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) |
Securities Registered Pursuant to Section 12(b) of the Act: | ||
Title of Each Class | Name of Each Exchange on Which Registered | |
Common Stock, par value $0.01 | New York Stock Exchange | |
7.25% Senior Notes due 2018 | New York Stock Exchange | |
Floating Rate Senior Notes due 2019 | New York Stock Exchange | |
6.625% Senior Notes due 2020 | New York Stock Exchange | |
6.875% Senior Notes due 2020 | New York Stock Exchange | |
6.125% Senior Notes due 2021 | New York Stock Exchange | |
5.375% Senior Notes due 2021 | New York Stock Exchange | |
4.875% Senior Notes due 2022 | New York Stock Exchange | |
5.75% Senior Notes due 2023 | New York Stock Exchange | |
2.75% Contingent Convertible Senior Notes due 2035 | New York Stock Exchange | |
2.5% Contingent Convertible Senior Notes due 2037 | New York Stock Exchange | |
2.25% Contingent Convertible Senior Notes due 2038 | New York Stock Exchange | |
4.5% Cumulative Convertible Preferred Stock | New York Stock Exchange | |
Securities registered pursuant to Section 12(g) of the Act: | ||
None |
Page | ||
Item 1. | Business |
2016 | 2015 | 2014 | ||||||||||||||||||||||||||||||||||
Gross | % | Net | % | Gross | % | Net | % | Gross | % | Net | % | |||||||||||||||||||||||||
Development: | ||||||||||||||||||||||||||||||||||||
Productive | 431 | 99 | 236 | 99 | 806 | 99 | 423 | 100 | 1,784 | 99 | 629 | 99 | ||||||||||||||||||||||||
Dry | 1 | 1 | 1 | 1 | 1 | 1 | — | — | 3 | 1 | 1 | 1 | ||||||||||||||||||||||||
Total | 432 | 100 | 237 | 100 | 807 | 100 | 423 | 100 | 1,787 | 100 | 630 | 100 | ||||||||||||||||||||||||
Exploratory: | ||||||||||||||||||||||||||||||||||||
Productive | 3 | 100 | 2 | 100 | 7 | 100 | 5 | 100 | 145 | 95 | 46 | 88 | ||||||||||||||||||||||||
Dry | — | — | — | — | — | — | — | — | 8 | 5 | 6 | 12 | ||||||||||||||||||||||||
Total | 3 | 100 | 2 | 100 | 7 | 100 | 5 | 100 | 153 | 100 | 52 | 100 |
2016 | 2015 | 2014 | ||||||||||||||||
Gross Wells | Net Wells | Gross Wells | Net Wells | Gross Wells | Net Wells | |||||||||||||
Southern | 375 | 212 | 537 | 258 | 1,448 | 473 | ||||||||||||
Northern | 60 | 27 | 277 | 170 | 492 | 209 | ||||||||||||
Total | 435 | 239 | 814 | 428 | 1,940 | 682 |
Years Ended December 31, | ||||||||||||
2016 | 2015 | 2014 | ||||||||||
Net Production: | ||||||||||||
Oil (mmbbl) | 33 | 42 | 42 | |||||||||
Natural gas (bcf) | 1,049 | 1,070 | 1,095 | |||||||||
NGL (mmbbl) | 24 | 28 | 33 | |||||||||
Oil equivalent (mmboe)(a) | 233 | 248 | 258 | |||||||||
Average Sales Price (excluding gains (losses) on derivatives): | ||||||||||||
Oil ($ per bbl) | $ | 40.65 | $ | 45.77 | $ | 89.41 | ||||||
Natural gas ($ per mcf) | $ | 2.05 | $ | 2.31 | $ | 4.14 | ||||||
NGL ($ per bbl) | $ | 14.76 | $ | 14.06 | $ | 30.95 | ||||||
Oil equivalent ($ per boe) | $ | 16.63 | $ | 19.23 | $ | 36.21 | ||||||
Average Sales Price (including realized gains (losses) on derivatives): | ||||||||||||
Oil ($ per bbl) | $ | 43.58 | $ | 66.91 | $ | 85.04 | ||||||
Natural gas ($ per mcf) | $ | 2.20 | $ | 2.72 | $ | 3.97 | ||||||
NGL ($ per bbl) | $ | 14.43 | $ | 14.06 | $ | 30.95 | ||||||
Oil equivalent ($ per boe) | $ | 17.66 | $ | 24.54 | $ | 34.74 | ||||||
Expenses ($ per boe): | ||||||||||||
Oil, natural gas and NGL production | $ | 3.05 | $ | 4.22 | $ | 4.69 | ||||||
Oil, natural gas and NGL gathering, processing and transportation | $ | 7.98 | $ | 8.55 | $ | 8.43 |
(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. |
December 31, 2016 | |||||||||||||||
Oil | Natural Gas | NGL | Total | ||||||||||||
(mmbbl) | (bcf) | (mmbbl) | (mmboe) | ||||||||||||
Proved developed | 200 | 5,126 | 134 | 1,189 | |||||||||||
Proved undeveloped | 199 | 1,370 | 92 | 519 | |||||||||||
Total proved(a) | 399 | 6,496 | 226 | 1,708 | |||||||||||
Proved Developed | Proved Undeveloped | Total Proved | |||||||||||||
($ in millions) | |||||||||||||||
Estimated future net revenue(b) | $ | 6,415 | $ | 2,999 | $ | 9,414 | |||||||||
Present value of estimated future net revenue(b) | $ | 3,687 | $ | 718 | $ | 4,405 | |||||||||
Standardized measure(b)(c) | $ | 4,379 |
Operating Division | Oil | Natural Gas | NGL | Oil Equivalent | Proved Reserves | Present Value | ||||||||||||||
(mmbbl) | (bcf) | (mmbbl) | (mmboe) | % | ($ millions) | |||||||||||||||
Southern | 363 | 3,045 | 131 | 1,001 | 59 | $ | 3,279 | |||||||||||||
Northern | 36 | 3,451 | 95 | 707 | 41 | 1,126 | ||||||||||||||
Total | 399 | 6,496 | 226 | 1,708 | 100 | % | $ | 4,405 | (b) |
(a) | Includes 1 mmbbl of oil, 23 bcf of natural gas and 2 mmbbls of NGL reserves owned by the Chesapeake Granite Wash Trust, of which 1 mmbbl of oil, 12 bcf of natural gas and 1 mmbbl of NGL are attributable to noncontrolling interest holders. |
(b) | Estimated future net revenue represents the estimated future gross revenue to be generated from the production of proved reserves, net of estimated production and future development costs, using prices and costs under existing economic conditions as of December 31, 2016. For the purpose of determining prices used in our reserve reports, we used the unweighted arithmetic average of the prices on the first day of each month within the 12-month period ended December 31, 2016. The prices used in our reserve reports were $42.75 per bbl of oil and $2.49 per mcf of natural gas, before basis differential adjustments. These prices should not be interpreted as a prediction of future prices, nor do they reflect the value of our commodity derivative instruments in place as of December 31, 2016. The amounts shown do not give effect to non-property-related expenses, such as corporate general and administrative expenses and debt service, or to depreciation, depletion and amortization. The present value of estimated future net revenue differs from the standardized measure only because the former does not include the effects of estimated future income tax expenses ($26 million as of December 31, 2016). |
(c) | Additional information on the standardized measure is presented in Supplemental Disclosures About Oil, Natural Gas and NGL Producing Activities included in Item 8 of Part II of this report. |
Total | |||
(mmboe) | |||
Proved undeveloped reserves, beginning of period | 242 | ||
Extensions and discoveries | 477 | ||
Revisions of previous estimates | (78 | ) | |
Developed | (118 | ) | |
Sale of reserves-in-place | (4 | ) | |
Purchase of reserves-in-place | — | ||
Proved undeveloped reserves, end of period | 519 |
• | 26 years of practical experience working for major oil companies, including 18 years in reservoir engineering responsible for estimation and evaluation of reserves; |
• | Bachelor of Science degree in Petroleum Engineering; |
• | registered professional engineer in the state of Texas; and |
• | member in good standing of the Society of Petroleum Engineers. |
• | We follow comprehensive SEC-compliant internal policies to estimate and report proved reserves. Reserve estimates are made by experienced reservoir engineers or under their direct supervision. All material changes are reviewed and approved by Corporate Reserves Advisors. |
• | The Corporate Reserves Department reviews the Company's proved reserves at the close of each quarter. |
• | Each quarter, Corporate Reserves Department managers, the Director – Corporate Reserves, the Vice Presidents of our business units, the Director of Corporate and Strategic Planning and the Executive Vice President – Exploration and Production review all significant reserves changes and all new proved undeveloped reserves additions. |
• | The Corporate Reserves Department reports independently of our operating divisions. |
• | The five year PUD development plan is reviewed and approved annually by the Director of Corporate Reserves and the Director of Corporate and Strategic Planning. |
• | over 30 years of practical experience in the estimation and evaluation of reserves; |
• | registered professional geologist license in the Commonwealth of Pennsylvania; |
• | member in good standing of the Society of Petroleum Engineers and the Society of Petroleum Evaluation Engineers; and |
• | Bachelor of Science degree in Geological Sciences. |
Years Ended December 31, | ||||||||||||
2016 | 2015 | 2014 | ||||||||||
($ in millions) | ||||||||||||
Acquisition of Properties: | ||||||||||||
Proved properties | $ | 403 | $ | — | $ | 214 | ||||||
Unproved properties | 403 | 454 | 1,224 | |||||||||
Exploratory costs | 52 | 112 | 421 | |||||||||
Development costs | 1,312 | 2,941 | 4,204 | |||||||||
Costs incurred(a)(b) | $ | 2,170 | $ | 3,507 | $ | 6,063 |
(a) | Exploratory and development costs are net of joint venture drilling and completion cost carries of $51 million and $679 million in 2015 and 2014, respectively. |
(b) | Includes capitalized interest and asset retirement obligations as follows: |
Capitalized interest | $ | 242 | $ | 410 | $ | 604 | ||||||
Asset retirement obligations | $ | (57 | ) | $ | (15 | ) | $ | 39 |
Gross Wells Drilled | Net Wells Drilled | Exploration and Development | Acquisition of Unproved Properties | Acquisition of Proved Properties | Sales of Unproved Properties | Sales of Proved Properties(a) | Total(b) | |||||||||||||||||||||||
($ in millions) | ||||||||||||||||||||||||||||||
Southern | 375 | 212 | $ | 1,169 | $ | 252 | $ | 277 | $ | (432 | ) | $ | (849 | ) | $ | 417 | ||||||||||||||
Northern | 60 | 27 | 195 | 151 | 126 | (19 | ) | (258 | ) | 195 | ||||||||||||||||||||
Total | 435 | 239 | $ | 1,364 | $ | 403 | $ | 403 | $ | (451 | ) | $ | (1,107 | ) | $ | 612 |
(a) | Includes asset retirement disposal of $179 million related to divestitures. |
(b) | Includes capitalized internal costs of $148 million and related capitalized interest of $242 million. |
Developed Leasehold | Undeveloped Leasehold | Fee Minerals | Total | |||||||||||||||||||||
Gross Acres | Net Acres | Gross Acres | Net Acres | Gross Acres | Net Acres | Gross Acres | Net Acres | |||||||||||||||||
(in thousands) | ||||||||||||||||||||||||
Southern | 3,776 | 1,871 | 996 | 427 | 152 | 35 | 4,924 | 2,333 | ||||||||||||||||
Northern | 1,848 | 1,380 | 3,482 | 2,087 | 708 | 457 | 6,038 | 3,924 | ||||||||||||||||
Total | 5,624 | 3,251 | 4,478 | 2,514 | 860 | 492 | 10,962 | 6,257 |
Acres Expiring | ||||||
Gross Acres | Net Acres | |||||
(in thousands) | ||||||
Years Ending December 31: | ||||||
2017 | 1,126 | 660 | ||||
2018 | 462 | 192 | ||||
2019 | 243 | 157 | ||||
After 2019 | 2,647 | 1,505 | ||||
Total(a) | 4,478 | 2,514 |
(a) | Includes 2.5 million gross (1.4 million net) held-by-production acres that will remain in force as production continues on the subject leases, and other leasehold acreage where management anticipates the lease to remain in effect past the primary term of the agreement due to our contractual option to extend the lease term. |
• | seismic operations; |
• | the location of wells; |
• | construction and operations activities, including in sensitive areas, such as wetlands, coastal regions or areas that contain endangered or threatened species or their habitats; |
• | the method of drilling and completing wells; |
• | production operations, including the installation of flowlines and gathering systems; |
• | air emissions and hydraulic fracturing; |
• | the surface use and restoration of properties upon which oil and natural gas facilities are located, including the construction of well pads, pipelines, impoundments and associated access roads; |
• | water withdrawal; |
• | the plugging and abandoning of wells; |
• | the generation, storage, transportation treatment, recycling or disposal of hazardous waste, fluids or other substances in connection with operations; |
• | the construction and operation of underground injection wells to dispose of produced water and other liquid oilfield wastes; |
• | the construction and operation of surface pits to contain drilling muds and other fluids associated with drilling operations; |
• | the marketing, transportation and reporting of production; and |
• | the valuation and payment of royalties. |
• | requiring the installation of pollution-control equipment or otherwise restricting the way we can handle or dispose of wastes and other substances associated with operations; |
• | limiting or prohibiting construction activities in sensitive areas, such as wetlands, coastal regions or areas that contain endangered or threatened species and/or species of special statewide concern or their habitats; |
• | requiring investigatory and remedial actions to address pollution caused by our operations or attributable to former operations; |
• | requiring noise, lighting, visual impact, odor and/or dust mitigation, setbacks, landscaping, fencing, and other measures; |
• | restricting access to certain equipment or areas to a limited set of employees or contractors who have proper certification or permits to conduct work (e.g., confined space entry and process safety maintenance requirements); and |
• | restricting or even prohibiting water use based upon availability, impacts or other factors. |
ITEM 1A. | Risk Factors |
• | domestic and worldwide supplies of oil, natural gas and NGL, including U.S. inventories of oil and natural gas reserves; |
• | weather conditions; |
• | changes in the level of consumer and industrial demand; |
• | the price and availability of alternative fuels; |
• | the effectiveness of worldwide conservation measures; |
• | the availability, proximity and capacity of pipelines, other transportation facilities and processing facilities; |
• | the level and effect of trading in commodity futures markets, including by commodity price speculators and others; |
• | U.S. exports of oil and/or liquefied natural gas; |
• | the price and level of foreign imports; |
• | the nature and extent of domestic and foreign governmental regulations and taxes; |
• | the ability of the members of the Organization of Petroleum Exporting Countries to agree to and maintain oil price and production controls; |
• | political instability or armed conflict in oil and natural gas producing regions; |
• | acts of terrorism; and |
• | domestic and global economic conditions. |
• | require us to dedicate a substantial portion of our cash flow from operations to service our existing debt obligations and could limit our flexibility in planning for or reacting to changes in our business and the industry in which we operate; |
• | increase our vulnerability to economic downturns or adverse developments in our business; |
• | could limit our ability to access the capital markets to refinance our existing indebtedness, to raise capital on favorable terms or to obtain additional financing for working capital, capital expenditures, acquisitions, debt service requirements or execution of our business strategy or for other purposes; |
• | expose us to the risk of increased interest rates as certain of our borrowings, including borrowings under our credit facility, bear interest at floating rates; |
• | place restrictions on our ability to obtain additional financing, make investments, lease equipment, sell assets and engage in business combinations; |
• | place us at a competitive disadvantage relative to competitors with lower levels of indebtedness in relation to their overall size or that have less restrictive terms governing their indebtedness and, therefore, that may be able to take advantage of opportunities that our indebtedness prevents us from pursuing; |
• | limit management’s discretion in operating our business; and |
• | increase our cost of borrowing. |
• | refinancing or restructuring all or a portion of our debt; |
• | obtaining alternative financing; |
• | selling assets; |
• | reducing or delaying capital investments; |
• | seeking to raise additional capital; or |
• | revising or delaying our strategic plans. |
• | incur additional indebtedness; |
• | make investments or loans; |
• | create liens; |
• | consummate mergers and similar fundamental changes; |
• | make restricted payments; |
• | make investments in unrestricted subsidiaries; |
• | enter into transactions with affiliates; and |
• | use the proceeds of asset sales. |
• | limit our ability to plan for, or react to, market conditions, to meet capital needs or otherwise to restrict our activities or business plan; and |
• | adversely affect our ability to finance our operations, enter into acquisitions or to engage in other business activities that would be in our interest. |
• | injury or loss of life; |
• | severe damage to or destruction of property, natural resources or equipment; |
• | pollution or other environmental damage; |
• | clean-up responsibilities; |
• | regulatory investigations and administrative, civil and criminal penalties; and |
• | injunctions resulting in limitation or suspension of operations. |
• | conduct of our exploration, drilling, completion, production and midstream activities; |
• | amounts and types of emissions and discharges; |
• | generation, management, and disposition of hazardous substances and waste materials; |
• | reclamation and abandonment of wells and facility sites; and |
• | remediation of contaminated sites. |
ITEM 1B. | Unresolved Staff Comments |
ITEM 2. | Properties |
ITEM 3. | Legal Proceedings |
ITEM 4. | Mine Safety Disclosures |
ITEM 5. | Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities |
Common Stock | Dividend | |||||||||||
High | Low | Declared | ||||||||||
Year Ended December 31, 2016: | ||||||||||||
Fourth Quarter | $ | 8.20 | $ | 5.14 | $ | — | ||||||
Third Quarter | $ | 8.15 | $ | 4.13 | $ | — | ||||||
Second Quarter | $ | 7.59 | $ | 3.53 | $ | — | ||||||
First Quarter | $ | 5.76 | $ | 1.50 | $ | — | ||||||
Year Ended December 31, 2015: | ||||||||||||
Fourth Quarter | $ | 9.55 | $ | 3.56 | $ | — | ||||||
Third Quarter | $ | 11.90 | $ | 6.01 | $ | — | ||||||
Second Quarter | $ | 16.98 | $ | 10.94 | $ | — | ||||||
First Quarter | $ | 21.49 | $ | 13.38 | $ | 0.0875 |
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) | ||||||||||||||
October 1, 2016 through October 31, 2016 | 5,693 | $ | 6.12 | — | $ | 1,000 | ||||||||
November 1, 2016 through November 30, 2016 | 2,026 | $ | 6.80 | — | $ | 1,000 | ||||||||
December 1, 2016 through December 31, 2016 | 837 | $ | 7.06 | — | $ | 1,000 | ||||||||
Total | 8,556 | $ | 6.37 | — |
(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 $1 billion in value of its common stock from time to time. The repurchase program does not have an expiration date. As of December 31, 2016, no repurchases had been made under the program. |
ITEM 6. | Selected Financial Data |
Years Ended December 31, | ||||||||||||||||||||
2016 | 2015 | 2014 | 2013 | 2012 | ||||||||||||||||
($ in millions, except per share data) | ||||||||||||||||||||
STATEMENT OF OPERATIONS DATA: | ||||||||||||||||||||
Total revenues | $ | 7,872 | $ | 12,764 | $ | 23,125 | $ | 19,080 | $ | 13,422 | ||||||||||
Net income (loss) available to common stockholders(a) | $ | (4,926 | ) | $ | (14,856 | ) | $ | 1,273 | $ | 474 | $ | (940 | ) | |||||||
EARNINGS (LOSS) PER COMMON SHARE: | ||||||||||||||||||||
Basic | $ | (6.45 | ) | $ | (22.43 | ) | $ | 1.93 | $ | 0.73 | $ | (1.46 | ) | |||||||
Diluted | $ | (6.45 | ) | $ | (22.43 | ) | $ | 1.87 | $ | 0.73 | $ | (1.46 | ) | |||||||
CASH DIVIDEND DECLARED PER COMMON SHARE | $ | — | $ | 0.0875 | $ | 0.35 | $ | 0.35 | $ | 0.35 | ||||||||||
BALANCE SHEET DATA (AT END OF PERIOD): | ||||||||||||||||||||
Total assets | $ | 13,028 | $ | 17,314 | $ | 40,655 | $ | 41,663 | $ | 41,469 | ||||||||||
Long-term debt, net of current maturities | $ | 9,938 | $ | 10,311 | $ | 11,058 | $ | 12,767 | $ | 12,015 | ||||||||||
Total equity (deficit) | $ | (1,203 | ) | $ | 2,397 | $ | 18,205 | $ | 18,140 | $ | 17,896 |
(a) | Includes $2.564 billion, $18.238 billion and $3.315 billion of full cost ceiling test write-downs on our oil and natural gas properties for the years ended December 31, 2016, 2015 and December 2012, respectively. In 2014 and 2013, we did not have any ceiling test impairments for our oil and natural gas properties. |
ITEM 7. | Management’s Discussion and Analysis of Financial Condition and Results of Operations |
Years Ended December 31, | ||||||||||||
2016 | 2015 | 2014 | ||||||||||
Net Production: | ||||||||||||
Oil (mmbbl) | 33 | 42 | 42 | |||||||||
Natural gas (bcf) | 1,049 | 1,070 | 1,095 | |||||||||
NGL (mmbbl) | 24 | 28 | 33 | |||||||||
Oil equivalent (mmboe)(a) | 233 | 248 | 258 | |||||||||
Oil, Natural Gas and NGL Sales ($ in millions): | ||||||||||||
Oil sales | $ | 1,351 | $ | 1,904 | $ | 3,778 | ||||||
Oil derivatives – realized gains (losses)(b) | 97 | 880 | (185 | ) | ||||||||
Oil derivatives – unrealized gains (losses)(b) | (318 | ) | (536 | ) | 859 | |||||||
Total oil sales | 1,130 | 2,248 | 4,452 | |||||||||
Natural gas sales | 2,155 | 2,470 | 4,535 | |||||||||
Natural gas derivatives – realized gains (losses)(b) | 151 | 437 | (191 | ) | ||||||||
Natural gas derivatives – unrealized gains (losses)(b) | (500 | ) | (157 | ) | 535 | |||||||
Total natural gas sales | 1,806 | 2,750 | 4,879 | |||||||||
NGL sales | 360 | 393 | 1,023 | |||||||||
NGL derivatives – realized gains (losses)(b) | (8 | ) | — | — | ||||||||
NGL derivatives – unrealized gains (losses)(b) | — | — | — | |||||||||
Total NGL sales | 352 | 393 | 1,023 | |||||||||
Total oil, natural gas and NGL sales | $ | 3,288 | $ | 5,391 | $ | 10,354 | ||||||
Average Sales Price (excluding gains (losses) on derivatives): | ||||||||||||
Oil ($ per bbl) | $ | 40.65 | $ | 45.77 | $ | 89.41 | ||||||
Natural gas ($ per mcf) | $ | 2.05 | $ | 2.31 | $ | 4.14 | ||||||
NGL ($ per bbl) | $ | 14.76 | $ | 14.06 | $ | 30.95 | ||||||
Oil equivalent ($ per boe) | $ | 16.63 | $ | 19.23 | $ | 36.21 | ||||||
Average Sales Price (including realized gains (losses) on derivatives): | ||||||||||||
Oil ($ per bbl) | $ | 43.58 | $ | 66.91 | $ | 85.04 | ||||||
Natural gas ($ per mcf) | $ | 2.20 | $ | 2.72 | $ | 3.97 | ||||||
NGL ($ per bbl) | $ | 14.43 | $ | 14.06 | $ | 30.95 | ||||||
Oil equivalent ($ per boe) | $ | 17.66 | $ | 24.54 | $ | 34.74 | ||||||
Other Operating Income ($ in millions): | ||||||||||||
Marketing, gathering and compression net margin(c)(d) | $ | (194 | ) | $ | 243 | $ | (11 | ) | ||||
Oilfield services net margin | $ | — | $ | — | $ | 115 | ||||||
Years Ended December 31, | ||||||||||||
2016 | 2015 | 2014 | ||||||||||
Expenses ($ per boe): | ||||||||||||
Oil, natural gas and NGL production | $ | 3.05 | $ | 4.22 | $ | 4.69 | ||||||
Oil, natural gas and NGL gathering, processing and transportation | $ | 7.98 | $ | 8.55 | $ | 8.43 | ||||||
Production taxes | $ | 0.32 | $ | 0.40 | $ | 0.90 | ||||||
General and administrative(e) | $ | 1.03 | $ | 0.95 | $ | 1.25 | ||||||
Oil, natural gas and NGL depreciation, depletion and amortization | $ | 4.31 | $ | 8.47 | $ | 10.41 | ||||||
Depreciation and amortization of other assets | $ | 0.45 | $ | 0.53 | $ | 0.90 | ||||||
Interest expense(f) | $ | 1.18 | $ | 1.30 | $ | 0.63 | ||||||
Interest Expense ($ in millions): | ||||||||||||
Interest expense | $ | 286 | $ | 329 | $ | 173 | ||||||
Interest rate derivatives – realized (gains) losses(g) | (11 | ) | (6 | ) | (12 | ) | ||||||
Interest rate derivatives – unrealized (gains) losses(g) | 21 | (6 | ) | (72 | ) | |||||||
Total interest expense | $ | 296 | $ | 317 | $ | 89 |
(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) | For the years ended December 31, 2016 and 2015, we recorded unrealized losses of $297 million and unrealized gains of $296 million, respectively, on the fair value of our supply contract derivative. Additionally, in 2016, we sold the long-term natural gas supply contract to a third party for cash proceeds of $146 million. See Note 11 of the notes to our consolidated financial statements included in Item 8 of this report for discussion related to this instrument. |
(e) | Excludes restructuring and other termination costs. |
(f) | 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. |
(g) | 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. |
• | entered into a secured five-year term loan facility in aggregate principal amount of $1.5 billion; |
• | issued $1.25 billion principal amount of unsecured 5.5% Convertible Senior Notes due 2026; |
• | issued $1.0 billion principal amount of unsecured 8.00% Senior Notes due 2025; |
• | exchanged 109 million shares of common stock for $577 million principal amount of our outstanding senior notes and contingent convertible senior notes, including $373 million principal amount that was scheduled to mature or could be put to us in 2017 or 2018; |
• | retired $2.884 billion principal amount of our outstanding senior notes and contingent convertible notes through purchases in the open market, tender offers or repayment upon maturity for $2.734 billion, including $1.621 billion principal amount that was scheduled to mature or could be put to us in 2017 and 2018; |
• | exchanged 120.2 million shares of common stock for $1.3 billion liquidation value of our preferred stock, eliminating $74 million of annual dividend obligations; |
• | further amended our revolving credit agreement to reaffirm our borrowing base, postpone our next scheduled borrowing base redetermination date and modify or suspend certain credit agreement financial covenants; and |
• | mitigated a portion of our downside exposure to commodity prices through derivative contracts, suspended dividend payments on our convertible preferred stock and divested assets to increase our liquidity. |
Years Ended December 31, | ||||||||||||
2016 | 2015 | 2014 | ||||||||||
($ in millions) | ||||||||||||
Cash provided by (used in) operating activities | $ | (204 | ) | $ | 1,234 | $ | 4,634 | |||||
Proceeds from issuance of term loan | 1,476 | — | — | |||||||||
Proceeds from long-term debt, net | 2,210 | — | 2,966 | |||||||||
Proceeds from oilfield services long-term debt, net | — | — | 888 | |||||||||
Divestitures of proved and unproved properties | 1,406 | 189 | 5,813 | |||||||||
Sales of other property and equipment | 131 | 89 | 1,003 | |||||||||
Proceeds from sales of investments | — | — | 239 | |||||||||
Other | — | 52 | 37 | |||||||||
Total sources of cash and cash equivalents | $ | 5,019 | $ | 1,564 | $ | 15,580 |
Years Ended December 31, | ||||||||||||||||||||||||
2016 | 2015 | 2014 | ||||||||||||||||||||||
Principal Amount of Debt Issued | Net Proceeds | Principal Amount of Debt Issued | Net Proceeds | Principal Amount of Debt Issued | Net Proceeds | |||||||||||||||||||
($ in millions) | ||||||||||||||||||||||||
Convertible senior notes | $ | 1,250 | $ | 1,235 | $ | — | $ | — | $ | — | $ | — | ||||||||||||
Senior notes(a) | 1,000 | 975 | — | — | 3,500 | 3,460 | ||||||||||||||||||
Term loans(a) | 1,500 | 1,476 | — | — | 400 | 394 | ||||||||||||||||||
Total | $ | 3,750 | $ | 3,686 | $ | — | $ | — | $ | 3,900 | $ | 3,854 |
(a) | Our 2015 debt exchange of certain outstanding unsecured senior notes and contingent notes for Second Lien Notes did not result in any additional debt issued or proceeds received. The 2014 amounts include debt issued in connection with the spin-off of our oilfield services business. All deferred charges and debt balances related to the spin-off were removed from our consolidated balance sheet as of June 30, 2014. See Note 13 of the notes to our consolidated financial statements included in Item 8 of this report for further discussion of the spin-off. |
Years Ended December 31, | ||||||||||||
2016 | 2015 | 2014 | ||||||||||
($ in millions) | ||||||||||||
Oil and Natural Gas Expenditures: | ||||||||||||
Drilling and completion costs(a) | $ | 1,276 | $ | 3,083 | $ | 4,495 | ||||||
Acquisitions of proved and unproved properties | 571 | 135 | 793 | |||||||||
Interest capitalized on unproved leasehold | 236 | 410 | 604 | |||||||||
Total oil and natural gas expenditures | 2,083 | 3,628 | 5,892 | |||||||||
Other Uses of Cash and Cash Equivalents: | ||||||||||||
Cash paid to repurchase debt | 2,734 | 508 | 3,362 | |||||||||
Cash paid for title defects | 69 | — | — | |||||||||
Cash paid to repurchase noncontrolling interest of CHK C-T(b) | — | 143 | — | |||||||||
Cash paid to purchase leased rigs and compressors | — | — | 499 | |||||||||
Cash paid to repurchase CHK Utica preferred shares(b) | — | — | 1,254 | |||||||||
Cash paid on financing derivatives(c) | — | — | 53 | |||||||||
Payments on credit facility borrowings, net | — | — | 382 | |||||||||
Additions to other property and equipment | 37 | 143 | 227 | |||||||||
Dividends paid | — | 289 | 405 | |||||||||
Distributions to noncontrolling interest owners | 10 | 85 | 173 | |||||||||
Additions to investments | — | 1 | — | |||||||||
Other | 29 | 50 | 62 | |||||||||
Total other uses of cash and cash equivalents | 2,879 | 1,219 | 6,417 | |||||||||
Total uses of cash and cash equivalents | $ | 4,962 | $ | 4,847 | $ | 12,309 |
(a) | Net of $51 million and $679 million in drilling and completion carries received from our joint venture partners during 2015 and 2014, respectively. |
(b) | See Note 8 of the notes to our consolidated financial statements included in Item 8 of this report for discussion of these transactions. |
(c) | Reflects derivatives deemed to contain, for accounting purposes, a significant financing element at contract inception. |
December 31, 2016 | ||||||||
Principal Amount | Carrying Amount | |||||||
($ in millions) | ||||||||
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 | 64 | 64 | ||||||
Floating rate senior notes due 2019 | 380 | 380 | ||||||
6.625% senior notes due 2020 | 780 | 780 | ||||||
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(b) | 2,419 | 3,409 | ||||||
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(c)(d) | 1,250 | 811 | ||||||
2.75% contingent convertible senior notes due 2035(e) | 2 | 2 | ||||||
2.5% contingent convertible senior notes due 2037(d)(e) | 114 | 112 | ||||||
2.25% contingent convertible senior notes due 2038(d)(e) | 200 | 180 | ||||||
Debt issuance costs | — | (41 | ) | |||||
Discount on senior notes | — | (16 | ) | |||||
Interest rate derivatives(f) | — | 3 | ||||||
Total senior notes, net | 8,489 | 8,964 | ||||||
Less current maturities of senior notes, net(g) | (506 | ) | (503 | ) | ||||
Total long-term senior notes, net | $ | 7,983 | $ | 8,461 |
(a) | The principal amount shown is based on the exchange rate of $1.0517 to €1.00 as of December 31, 2016. See Note 11 of the notes to our consolidated financial statements included in Item 8 of this report for information on our related foreign currency derivatives. |
(b) | The carrying amount as of December 31, 2016, includes a premium of $990 million associated with a troubled debt restructuring. The premium is being amortized based on an effective yield method. |
(c) | 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. |
(d) | The carrying amount as of December 31, 2016, is reflected net of a discount associated with the equity component of our convertible and contingent convertible senior notes of $461 million. |
(e) | 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. |
(f) | See Note 11 of the notes to our consolidated financial statements included in Item 8 of this report for discussion related to these instruments. |
(g) | As of December 31, 2016, current maturities of long-term debt, net includes our 6.25% Euro-denominated Senior Notes due January 2017, 6.5% Senior Notes due 2017 and our 2037 Notes. As discussed in footnote (b) above and in Note 3 of the notes to our consolidated financial statements included in Item 8 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. As of December 31, 2016, there was $2 million of discount associated with the equity component of the 2037 Notes. |
Payments Due By Period | ||||||||||||||||||||
Total | Less Than 1 Year | 1-3 Years | 3-5 Years | More Than 5 Years | ||||||||||||||||
($ in millions) | ||||||||||||||||||||
Long-term debt: | ||||||||||||||||||||
Principal(a) | $ | 9,989 | $ | 506 | $ | 644 | $ | 3,381 | $ | 5,458 | ||||||||||
Interest | 3,969 | 664 | 1,300 | 1,101 | 904 | |||||||||||||||
Operating lease obligations(b) | 9 | 4 | 5 | — | — | |||||||||||||||
Operating commitments(c) | 11,269 | 1,578 | 2,421 | 2,045 | 5,225 | |||||||||||||||
Unrecognized tax benefits(d) | 97 | — | — | 97 | — | |||||||||||||||
Standby letters of credit | 1,036 | 1,036 | — | — | — | |||||||||||||||
Other | 29 | 6 | 8 | 9 | 6 | |||||||||||||||
Total contractual cash obligations(e) | $ | 26,398 | $ | 3,794 | $ | 4,378 | $ | 6,633 | $ | 11,593 |
(a) | Total principal amount of debt maturities, using the earliest demand repurchase date for contingent convertible senior notes. |
(b) | See Note 4 of the notes to our consolidated financial statements included in Item 8 of this report for a description of our operating lease obligations. |
(c) | See Note 4 of the notes to our consolidated financial statements included in Item 8 of this report for a description of gathering, processing and transportation agreements, drilling contracts and pressure pumping contracts. |
(d) | See Note 6 of the notes to our consolidated financial statements included in Item 8 of this report for a description of unrecognized tax benefits. |
(e) | This table does not include derivative liabilities or the estimated discounted liability for future dismantlement, abandonment and restoration costs of oil and natural gas properties. See Notes 11 and 20, respectively, of the notes to our consolidated financial statements included in Item 8 of this report for more information on our derivatives and asset retirement obligations. This table also does not include our costs to produce reserves attributable to non-expense-bearing royalty and other interests in our properties, including VPPs, which are discussed below. |
December 31, | ||||||||
2016 | 2015 | |||||||
($ in millions) | ||||||||
Derivative assets (liabilities): | ||||||||
Oil fixed-price swaps | $ | (140 | ) | $ | 144 | |||
Oil call options | (1 | ) | (7 | ) | ||||
Natural gas fixed-price swaps | (349 | ) | 229 | |||||
Natural gas collars | (9 | ) | — | |||||
Natural gas call options | — | (99 | ) | |||||
Natural gas basis protection swaps | (5 | ) | — | |||||
NGL fixed-price swaps | — | — | ||||||
Estimated fair value | $ | (504 | ) | $ | 267 |
2016 | |||||||||||||||||||||||||||
Oil | Natural Gas | NGL | Total | ||||||||||||||||||||||||
(mmbbl) | ($/bbl)(a) | (bcf) | ($/mcf)(a) | (mmbbl) | ($/bbl)(a) | (mmboe) | % | ($/boe)(a) | |||||||||||||||||||
Southern(b) | 26.4 | 41.84 | 537.1 | 2.20 | 11.3 | 14.77 | 127.3 | 55 | 19.29 | ||||||||||||||||||
Northern(c) | 6.8 | 36.01 | 512.4 | 1.90 | 13.1 | 14.75 | 105.3 | 45 | 13.40 | ||||||||||||||||||
Total | 33.2 | 40.65 | 1,049.5 | 2.05 | 24.4 | 14.76 | 232.6 | 100 | % | 16.63 | |||||||||||||||||
2015 | |||||||||||||||||||||||||||
Oil | Natural Gas | NGL | Total | ||||||||||||||||||||||||
(mmbbl) | ($/bbl)(a) | (bcf) | ($/mcf)(a) | (mmbbl) | ($/bbl)(a) | (mmboe) | % | ($/boe)(a) | |||||||||||||||||||
Southern(b) | 33.4 | 47.33 | 573.8 | 2.52 | 14.9 | 13.13 | 143.9 | 58 | 22.40 | ||||||||||||||||||
Northern(c) | 8.2 | 39.45 | 496.0 | 2.06 | 13.1 | 15.12 | 104.0 | 42 | 14.85 | ||||||||||||||||||
Total | 41.6 | 45.77 | 1,069.8 | 2.31 | 28.0 | 14.06 | 247.9 | 100 | % | 19.23 | |||||||||||||||||
2014 | |||||||||||||||||||||||||||
Oil | Natural Gas | NGL | Total | ||||||||||||||||||||||||
(mmbbl) | ($/bbl)(a) | (bcf) | ($/mcf)(a) | (mmbbl) | ($/bbl)(a) | (mmboe) | % | ($/boe)(a) | |||||||||||||||||||
Southern(b) | 35.3 | 91.15 | 580.7 | 4.20 | 16.9 | 32.18 | 148.9 | 58 | 41.62 | ||||||||||||||||||
Northern(c) | 7.0 | 80.15 | 514.3 | 4.08 | 16.2 | 29.56 | 108.9 | 42 | 28.81 | ||||||||||||||||||
Total | 42.3 | 89.41 | 1,095.0 | 4.14 | 33.1 | 30.95 | 257.8 | 100 | % | 36.21 |
(a) | Average sales prices exclude gains (losses) on derivatives. |
(b) | Our Southern Division includes the Eagle Ford and Anadarko Basin liquids plays and the Haynesville/Bossier and Barnett (prior to October 31, 2016) natural gas shale plays. The Eagle Ford Shale accounted for approximately 33% of our estimated proved reserves by volume as of December 31, 2016. Eagle Ford Shale production for 2016, 2015 and 2014 was 35.4 mmboe, 38.5 mmboe and 35.4 mmboe, respectively. |
(c) | Our Northern Division includes the Utica and Powder River liquids plays and the Marcellus natural gas play. The Utica Shale accounted for approximately 22% of our estimated proved reserves by volume as of December 31, 2016. Utica Shale production for 2016, 2015 and 2014 was 46.7 mmboe, 43.8 mmboe and 26.6 mmboe, respectively. The Marcellus Shale accounted for approximately 18% of our estimated proved reserves by volume as of December 31, 2016. Marcellus Shale production for 2016, 2015 and 2014 was 50.0 mmboe, 49.7 mmboe and 74.7 mmboe, respectively. |
Years Ended December 31, | |||||||||
2016 | 2015 | 2014 | |||||||
Oil | 35 | 40 | 40 | ||||||
Natural gas | 56 | 52 | 49 | ||||||
NGL | 9 | 8 | 11 | ||||||
Total | 100 | % | 100 | % | 100 | % |
2016 | 2015 | 2014 | |||||||||||||||||||
Production Expenses | $/boe | Production Expenses | $/boe | Production Expenses | $/boe | ||||||||||||||||
($ in millions, except per unit) | |||||||||||||||||||||
Southern | $ | 498 | 3.92 | $ | 771 | 5.36 | $ | 882 | 5.92 | ||||||||||||
Northern | 157 | 1.49 | 188 | 1.81 | 229 | 2.10 | |||||||||||||||
655 | 2.81 | 959 | 3.87 | 1,111 | 4.31 | ||||||||||||||||
Ad valorem tax | 55 | 0.24 | 87 | 0.35 | 97 | 0.38 | |||||||||||||||
Total | $ | 710 | 3.05 | $ | 1,046 | 4.22 | $ | 1,208 | 4.69 |
Years Ended December 31, | ||||||||||||
2016 | 2015 | 2014 | ||||||||||
Oil ($ per bbl) | $ | 3.61 | $ | 3.38 | $ | 2.86 | ||||||
Natural gas ($ per mcf) | $ | 1.47 | $ | 1.66 | $ | 1.68 | ||||||
NGL ($ per bbl) | $ | 7.83 | $ | 7.37 | $ | 6.59 |
Years Ended December 31, | Estimated Useful Life | |||||||||||||
2016 | 2015 | 2014 | ||||||||||||
($ in millions) | (in years) | |||||||||||||
Buildings and improvements | $ | 38 | $ | 39 | $ | 42 | 10 – 39 | |||||||
Natural gas compressors(a) | 24 | 38 | 37 | 3 – 20 | ||||||||||
Computers and office equipment | 20 | 22 | 32 | 3 – 7 | ||||||||||
Vehicles | 3 | 10 | 24 | 0 – 7 | ||||||||||
Natural gas gathering systems and treating plants(a) | 7 | 11 | 12 | 20 | ||||||||||
Oilfield services equipment(b) | — | — | 74 | 3 – 15 | ||||||||||
Other | 12 | 10 | 11 | 2 – 20 | ||||||||||
Total depreciation and amortization of other assets | $ | 104 | $ | 130 | $ | 232 |
(a) | Included in our marketing, gathering and compression operating segment. |
(b) | Included in our former oilfield services operating segment. |
Years Ended December 31, | ||||||||||||
2016 | 2015 | 2014 | ||||||||||
($ in millions) | ||||||||||||
Interest expense on senior notes | $ | 588 | $ | 682 | $ | 704 | ||||||
Interest expense on term loan | 46 | — | 36 | |||||||||
Amortization of loan discount, issuance costs and other | 33 | 62 | 42 | |||||||||
Amortization of premium associated with troubled debt restructuring | (165 | ) | (3 | ) | — | |||||||
Interest expense on revolving credit facilities | 35 | 12 | 28 | |||||||||
Realized gains on interest rate derivatives(a) | (11 | ) | (6 | ) | (12 | ) | ||||||
Unrealized (gains) losses on interest rate derivatives(b) | 21 | (6 | ) | (72 | ) | |||||||
Capitalized interest | (251 | ) | (424 | ) | (637 | ) | ||||||
Total interest expense | $ | 296 | $ | 317 | $ | 89 | ||||||
Average senior notes borrowings | $ | 8,749 | $ | 11,705 | 11,653 | |||||||
Average credit facilities borrowings | $ | 195 | $ | — | 306 | |||||||
Average term loan borrowings | $ | 537 | $ | — | 625 |
(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 open interest rate derivatives offset by amounts reclassified to realized (gains) losses during the period. |
• | taxable income projections in future years; |
• | reversal of existing deferred tax liabilities against deferred tax assets and whether the carryforward period is so brief that it would limit realization of the tax benefit; |
• | future sales and operating cost projections that will produce more than enough taxable income to realize the deferred tax asset based on existing sales prices and cost structures; and |
• | our earnings history exclusive of the loss that created the future deductible amount coupled with evidence indicating that the loss is an aberration rather than a continuing condition. |
• | 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; |
• | 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. |
ITEM 7A. | Quantitative and Qualitative Disclosures About Market Risk |
• | 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. |
Weighted Average Price | Fair Value | ||||||||||||||||||||||
Volume | Fixed | Call | Put | Differential | Asset (Liability) | ||||||||||||||||||
(mmbbl) | ($ per bbl) | ($ in millions) | |||||||||||||||||||||
Oil: | |||||||||||||||||||||||
Swaps: | |||||||||||||||||||||||
Short-term | 23 | $ | 50.19 | $ | — | $ | — | $ | — | $ | (140 | ) | |||||||||||
Call Options (sold): | |||||||||||||||||||||||
Short-term | 5 | $ | — | $ | 83.50 | $ | — | $ | — | (1 | ) | ||||||||||||
Total Oil | $ | (141 | ) | ||||||||||||||||||||
(tbtu) | ($ per mmbtu) | ||||||||||||||||||||||
Natural Gas: | |||||||||||||||||||||||
Swaps: | |||||||||||||||||||||||
Short-term | 599 | $ | 3.07 | $ | — | $ | — | $ | — | $ | (336 | ) | |||||||||||
Long-term | 120 | $ | 3.13 | $ | — | $ | — | $ | — | (13 | ) | ||||||||||||
Collars: | |||||||||||||||||||||||
Short-term | 23 | $ | — | $ | 3.48 | $ | 3.00 | $ | — | (8 | ) | ||||||||||||
Long-term | 37 | $ | — | $ | 3.25 | $ | 3.00 | $ | — | (1 | ) | ||||||||||||
Call Options (sold): | |||||||||||||||||||||||
Short-term | 48 | $ | — | $ | 9.43 | $ | — | $ | — | — | |||||||||||||
Long-term | 66 | $ | — | $ | 12.00 | $ | — | $ | — | — | |||||||||||||
Basis Protection Swaps: | |||||||||||||||||||||||
Short-term | 30 | $ | — | $ | — | $ | — | $ | (0.11 | ) | (4 | ) | |||||||||||
Long-term | 1 | $ | — | $ | — | $ | — | $ | (0.98 | ) | (1 | ) | |||||||||||
Total Natural Gas | $ | (363 | ) | ||||||||||||||||||||
(mmgal) | ($ per mgal) | ||||||||||||||||||||||
NGL: | |||||||||||||||||||||||
Ethane Swaps: | |||||||||||||||||||||||
Short-term | 53 | $ | 0.28 | $ | — | $ | — | $ | — | $ | — | ||||||||||||
Total NGL | $ | — | |||||||||||||||||||||
Total Oil, Natural Gas and NGL | $ | (504 | ) |
December 31, 2016 | ||||
($ in millions) | ||||
Short-term | $ | 82 | ||
Long-term | (82 | ) | ||
Total | $ | — |
December 31, 2016 | ||||
($ in millions) | ||||
Fair value of contracts outstanding, as of January 1, 2016 | $ | 267 | ||
Change in fair value of contracts | (546 | ) | ||
Contracts realized or otherwise settled | (230 | ) | ||
Fair value of contracts closed | 5 | |||
Fair value of contracts outstanding, as of December 31, 2016 | $ | (504 | ) |
Years of Maturity | |||||||||||||||||||||||||||
2017 | 2018 | 2019 | 2020 | 2021 | Thereafter | Total | |||||||||||||||||||||
($ in millions) | |||||||||||||||||||||||||||
Liabilities: | |||||||||||||||||||||||||||
Debt – fixed rate(a) | $ | 506 | $ | 264 | $ | — | $ | 1,061 | $ | 820 | $ | 5,458 | $ | 8,109 | |||||||||||||
Average interest rate | 5.47 | % | 3.46 | % | — | % | 6.68 | % | 5.88 | % | 7.03 | % | 6.66 | % | |||||||||||||
Debt – variable rate | $ | — | $ | — | $ | 380 | $ | — | $ | 1,500 | $ | — | $ | 1,880 | |||||||||||||
Average interest rate | — | % | — | % | 4.13 | % | — | % | 8.50 | % | — | % | 7.62 | % |
(a) | This amount does not include the premium, discount and deferred financing costs included in debt of $449 million and interest rate derivatives of $3 million. |
ITEM 8. | Financial Statements and Supplementary Data |
INDEX TO FINANCIAL STATEMENTS CHESAPEAKE ENERGY CORPORATION | ||||
Page | ||||
Consolidated Balance Sheets as of December 31, 2016 and 2015 | ||||
Consolidated Statements of Operations for the Years Ended December 31, 2016, 2015 and 2014 | ||||
Consolidated Statements of Comprehensive Income (Loss) for the Years Ended December 31, 2016, 2015 and 2014 | ||||
Consolidated Statements of Cash Flows for the Years Ended December 31, 2016, 2015 and 2014 | ||||
Consolidated Statements of Stockholders’ Equity for the Years Ended December 31, 2016, 2015 and 2014 | ||||
Notes to the Consolidated Financial Statements | ||||
/s/ ROBERT D. LAWLER | ||||
Robert D. Lawler | ||||
President and Chief Executive Officer | ||||
/s/ DOMENIC J. DELL'OSSO, JR. | ||||
Domenic J. Dell'Osso, Jr. | ||||
Executive Vice President and Chief Financial Officer | ||||
March 3, 2017 | ||||
December 31, | ||||||||
2016 | 2015 | |||||||
($ in millions) | ||||||||
CURRENT ASSETS: | ||||||||
Cash and cash equivalents ($1 and $1 attributable to our VIE) | $ | 882 | $ | 825 | ||||
Accounts receivable, net | 1,057 | 1,129 | ||||||
Short-term derivative assets | — | 366 | ||||||
Other current assets | 203 | 160 | ||||||
Total Current Assets | 2,142 | 2,480 | ||||||
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) | 66,451 | 63,843 | ||||||
Unproved properties | 4,802 | 6,798 | ||||||
Other property and equipment | 2,053 | 2,927 | ||||||
Total Property and Equipment, at Cost | 73,306 | 73,568 | ||||||
Less: accumulated depreciation, depletion and amortization (($458) and ($428) attributable to our VIE) | (62,726 | ) | (59,365 | ) | ||||
Property and equipment held for sale, net | 29 | 95 | ||||||
Total Property and Equipment, Net | 10,609 | 14,298 | ||||||
LONG-TERM ASSETS: | ||||||||
Long-term derivative assets | — | 246 | ||||||
Other long-term assets | 277 | 290 | ||||||
TOTAL ASSETS | $ | 13,028 | $ | 17,314 | ||||
December 31, | ||||||||
2016 | 2015 | |||||||
($ in millions) | ||||||||
CURRENT LIABILITIES: | ||||||||
Accounts payable | $ | 672 | $ | 944 | ||||
Current maturities of long-term debt, net | 503 | 381 | ||||||
Accrued interest | 113 | 101 | ||||||
Short-term derivative liabilities | 562 | 40 | ||||||
Other current liabilities ($3 and $8 attributable to our VIE) | 1,798 | 2,219 | ||||||
Total Current Liabilities | 3,648 | 3,685 | ||||||
LONG-TERM LIABILITIES: | ||||||||
Long-term debt, net | 9,938 | 10,311 | ||||||
Long-term derivative liabilities | 15 | 60 | ||||||
Asset retirement obligations, net of current portion | 247 | 452 | ||||||
Other long-term liabilities | 383 | 409 | ||||||
Total Long-Term Liabilities | 10,583 | 11,232 | ||||||
CONTINGENCIES AND COMMITMENTS (Note 4) | ||||||||
EQUITY: | ||||||||
Chesapeake Stockholders’ Equity: | ||||||||
Preferred stock, $0.01 par value, 20,000,000 shares authorized: 5,839,506 and 7,251,515 shares outstanding | 1,771 | 3,062 | ||||||
Common stock, $0.01 par value, 1,500,000,000 and 1,000,000,000 shares authorized: 896,279,353 and 664,795,509 shares issued | 9 | 7 | ||||||
Additional paid-in capital | 14,486 | 12,403 | ||||||
Accumulated deficit | (17,603 | ) | (13,202 | ) | ||||
Accumulated other comprehensive loss | (96 | ) | (99 | ) | ||||
Less: treasury stock, at cost; 1,220,504 and 1,437,724 common shares | (27 | ) | (33 | ) | ||||
Total Chesapeake Stockholders’ Equity (Deficit) | (1,460 | ) | 2,138 | |||||
Noncontrolling interests | 257 | 259 | ||||||
Total Equity (Deficit) | (1,203 | ) | 2,397 | |||||
TOTAL LIABILITIES AND EQUITY | $ | 13,028 | $ | 17,314 |
Years Ended December 31, | ||||||||||||
2016 | 2015 | 2014 | ||||||||||
($ in million except per share data) | ||||||||||||
REVENUES: | ||||||||||||
Oil, natural gas and NGL | $ | 3,288 | $ | 5,391 | $ | 10,354 | ||||||
Marketing, gathering and compression | 4,584 | 7,373 | 12,225 | |||||||||
Oilfield services | — | — | 546 | |||||||||
Total Revenues | 7,872 | 12,764 | 23,125 | |||||||||
OPERATING EXPENSES: | ||||||||||||
Oil, natural gas and NGL production | 710 | 1,046 | 1,208 | |||||||||
Oil, natural gas and NGL gathering, processing and transportation | 1,855 | 2,119 | 2,174 | |||||||||
Production taxes | 74 | 99 | 232 | |||||||||
Marketing, gathering and compression | 4,778 | 7,130 | 12,236 | |||||||||
Oilfield services | — | — | 431 | |||||||||
General and administrative | 240 | 235 | 322 | |||||||||
Restructuring and other termination costs | 6 | 36 | 7 | |||||||||
Provision for legal contingencies | 123 | 353 | 234 | |||||||||
Oil, natural gas and NGL depreciation, depletion and amortization | 1,003 | 2,099 | 2,683 | |||||||||
Depreciation and amortization of other assets | 104 | 130 | 232 | |||||||||
Impairment of oil and natural gas properties | 2,564 | 18,238 | — | |||||||||
Impairments of fixed assets and other | 838 | 194 | 88 | |||||||||
Net (gains) losses on sales of fixed assets | (12 | ) | 4 | (199 | ) | |||||||
Total Operating Expenses | 12,283 | 31,683 | 19,648 | |||||||||
INCOME (LOSS) FROM OPERATIONS | (4,411 | ) | (18,919 | ) | 3,477 | |||||||
OTHER INCOME (EXPENSE): | ||||||||||||
Interest expense | (296 | ) | (317 | ) | (89 | ) | ||||||
Losses on investments | (8 | ) | (96 | ) | (75 | ) | ||||||
Impairments of investments | (119 | ) | (53 | ) | (5 | ) | ||||||
Net gain (loss) on sales of investments | (10 | ) | — | 67 | ||||||||
Gains (losses) on purchases or exchanges of debt | 236 | 279 | (197 | ) | ||||||||
Other income | 19 | 8 | 22 | |||||||||
Total Other Expense | (178 | ) | (179 | ) | (277 | ) | ||||||
INCOME (LOSS) BEFORE INCOME TAXES | (4,589 | ) | (19,098 | ) | 3,200 | |||||||
INCOME TAX EXPENSE (BENEFIT): | ||||||||||||
Current income taxes | (19 | ) | (36 | ) | 47 | |||||||
Deferred income taxes | (171 | ) | (4,427 | ) | 1,097 | |||||||
Total Income Tax Expense (Benefit) | (190 | ) | (4,463 | ) | 1,144 | |||||||
NET INCOME (LOSS) | (4,399 | ) | (14,635 | ) | 2,056 | |||||||
Net income attributable to noncontrolling interests | (2 | ) | (50 | ) | (139 | ) | ||||||
NET INCOME (LOSS) ATTRIBUTABLE TO CHESAPEAKE | (4,401 | ) | (14,685 | ) | 1,917 | |||||||
Preferred stock dividends | (97 | ) | (171 | ) | (171 | ) | ||||||
Loss on exchange of preferred stock | (428 | ) | — | — | ||||||||
Repurchase of preferred shares of CHK Utica | — | — | (447 | ) | ||||||||
Earnings allocated to participating securities | — | — | (26 | ) | ||||||||
NET INCOME (LOSS) AVAILABLE TO COMMON STOCKHOLDERS | $ | (4,926 | ) | $ | (14,856 | ) | $ | 1,273 | ||||
EARNINGS (LOSS) PER COMMON SHARE: | ||||||||||||
Basic | $ | (6.45 | ) | $ | (22.43 | ) | $ | 1.93 | ||||
Diluted | $ | (6.45 | ) | $ | (22.43 | ) | $ | 1.87 | ||||
CASH DIVIDEND DECLARED PER COMMON SHARE | $ | — | $ | 0.0875 | $ | 0.35 | ||||||
WEIGHTED AVERAGE COMMON AND COMMON EQUIVALENT SHARES OUTSTANDING (in millions): | ||||||||||||
Basic | 764 | 662 | 659 | |||||||||
Diluted | 764 | 662 | 772 |
Years Ended December 31, | ||||||||||||
2016 | 2015 | 2014 | ||||||||||
($ in millions) | ||||||||||||
NET INCOME (LOSS) | $ | (4,399 | ) | $ | (14,635 | ) | $ | 2,056 | ||||
OTHER COMPREHENSIVE INCOME (LOSS), NET OF INCOME TAX: | ||||||||||||
Unrealized gains (losses) on derivative instruments, net of income tax expense (benefit) of ($14), $12 and $0 | (13 | ) | 20 | 1 | ||||||||
Reclassification of losses on settled derivative instruments, net of income tax expense of $18, $15 and $14 | 16 | 24 | 23 | |||||||||
Reclassification of (gains) losses on investment, net of income tax expense (benefit) of $0, $0 and ($3) | — | — | (5 | ) | ||||||||
Other Comprehensive Income (Loss) | 3 | 44 | 19 | |||||||||
COMPREHENSIVE INCOME (LOSS) | (4,396 | ) | (14,591 | ) | 2,075 | |||||||
COMPREHENSIVE INCOME ATTRIBUTABLE TO NONCONTROLLING INTERESTS | (2 | ) | (50 | ) | (139 | ) | ||||||
COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO CHESAPEAKE | $ | (4,398 | ) | $ | (14,641 | ) | $ | 1,936 |
Years Ended December 31, | ||||||||||||
2016 | 2015 | 2014 | ||||||||||
($ in millions) | ||||||||||||
CASH FLOWS FROM OPERATING ACTIVITIES: | ||||||||||||
NET (INCOME) LOSS | $ | (4,399 | ) | $ | (14,635 | ) | $ | 2,056 | ||||
ADJUSTMENTS TO RECONCILE NET LOSS TO CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES: | ||||||||||||
Depreciation, depletion and amortization | 1,107 | 2,229 | 2,915 | |||||||||
Deferred income tax expense (benefit) | (171 | ) | (4,427 | ) | 1,097 | |||||||
Derivative (gains) losses, net | 739 | (932 | ) | (1,102 | ) | |||||||
Cash receipts (payments) on derivative settlements, net | 448 | 1,123 | (253 | ) | ||||||||
Stock-based compensation | 52 | 78 | 59 | |||||||||
Impairment of oil and natural gas properties | 2,564 | 18,238 | — | |||||||||
Net (gains) losses on sales of fixed assets | (12 | ) | 4 | (199 | ) | |||||||
Renegotiation of natural gas gathering contracts | (115 | ) | — | — | ||||||||
Impairments of fixed assets and other | 467 | 175 | 58 | |||||||||
Losses on investments | 8 | 96 | 75 | |||||||||
Net (gain) loss on sales of investment | 10 | — | (67 | ) | ||||||||
Impairments of investments | 119 | 53 | 5 | |||||||||
(Gains) losses on purchases or exchanges of debt | (236 | ) | (304 | ) | 63 | |||||||
Restructuring and other termination costs | 3 | (14 | ) | (15 | ) | |||||||
Provision for legal contingencies | 87 | 340 | 234 | |||||||||
Other | (143 | ) | 244 | 220 | ||||||||
(Increase) decrease in accounts receivable and other assets | 21 | 1,186 | (21 | ) | ||||||||
Decrease in accounts payable, accrued liabilities and other | (753 | ) | (2,220 | ) | (491 | ) | ||||||
Net Cash Provided By (Used In) Operating Activities | (204 | ) | 1,234 | 4,634 | ||||||||
CASH FLOWS FROM INVESTING ACTIVITIES: | ||||||||||||
Drilling and completion costs | (1,295 | ) | (3,095 | ) | (4,581 | ) | ||||||
Acquisitions of proved and unproved properties | (788 | ) | (533 | ) | (1,311 | ) | ||||||
Proceeds from divestitures of proved and unproved properties | 1,406 | 189 | 5,813 | |||||||||
Additions to other property and equipment | (37 | ) | (143 | ) | (726 | ) | ||||||
Proceeds from sales of other property and equipment | 131 | 89 | 1,003 | |||||||||
Cash paid for title defects | (69 | ) | — | — | ||||||||
Additions to investments | — | (1 | ) | — | ||||||||
Proceeds from sales of investments | — | — | 239 | |||||||||
Decrease in restricted cash | — | 52 | 37 | |||||||||
Other | (8 | ) | (9 | ) | (20 | ) | ||||||
Net Cash Provided By (Used In) Investing Activities | (660 | ) | (3,451 | ) | 454 | |||||||
Years Ended December 31, | ||||||||||||
2016 | 2015 | 2014 | ||||||||||
($ in millions) | ||||||||||||
CASH FLOWS FROM FINANCING ACTIVITIES: | ||||||||||||
Cash paid to purchase debt | (2,734 | ) | (508 | ) | (3,362 | ) | ||||||
Proceeds from revolving credit facilities borrowings | 5,146 | — | 7,406 | |||||||||
Payments on revolving credit facilities borrowings | (5,146 | ) | — | (7,788 | ) | |||||||
Proceeds from issuance of senior notes, net of discount and offering costs | 2,210 | — | 2,966 | |||||||||
Proceeds from issuance of term loan, net of offering costs | 1,476 | — | — | |||||||||
Proceeds from issuance of oilfield services term loan, net of issuance costs | — | — | 394 | |||||||||
Proceeds from issuance of oilfield services senior notes, net of issuance costs | — | — | 494 | |||||||||
Cash held and retained by SSE at spin-off | — | — | (8 | ) | ||||||||
Cash paid for common stock dividends | — | (118 | ) | (234 | ) | |||||||
Cash paid for preferred stock dividends | — | (171 | ) | (171 | ) | |||||||
Cash paid on financing derivatives | — | — | (53 | ) | ||||||||
Cash paid to repurchase noncontrolling interest of CHK C-T | — | (143 | ) | — | ||||||||
Cash paid to repurchase preferred shares of CHK Utica | — | — | (1,254 | ) | ||||||||
Distributions to noncontrolling interest owners | (10 | ) | (85 | ) | (173 | ) | ||||||
Other | (21 | ) | (41 | ) | (34 | ) | ||||||
Net Cash Provided By (Used In) Financing Activities | 921 | (1,066 | ) | (1,817 | ) | |||||||
Net increase (decrease) in cash and cash equivalents | 57 | (3,283 | ) | 3,271 | ||||||||
Cash and cash equivalents, beginning of period | 825 | 4,108 | 837 | |||||||||
Cash and cash equivalents, end of period | $ | 882 | $ | 825 | $ | 4,108 | ||||||
Supplemental disclosures to the consolidated statements of cash flows are presented below: | ||||||||||||
Years Ended December 31, | ||||||||||||
2016 | 2015 | 2014 | ||||||||||
($ in millions) | ||||||||||||
SUPPLEMENTAL CASH FLOW INFORMATION: | ||||||||||||
Interest paid, net of capitalized interest | $ | 344 | $ | 235 | $ | 96 | ||||||
Income taxes paid, net of refunds received | $ | (27 | ) | $ | 44 | $ | 10 | |||||
SUPPLEMENTAL DISCLOSURE OF SIGNIFICANT NON-CASH INVESTING AND FINANCING ACTIVITIES: | ||||||||||||
Change in accrued drilling and completion costs | $ | (23 | ) | $ | (148 | ) | $ | (84 | ) | |||
Change in accrued acquisitions of proved and unproved properties | $ | (13 | ) | $ | 55 | $ | (74 | ) | ||||
Change in divested proved and unproved properties | $ | 52 | $ | 35 | $ | 38 | ||||||
Divestiture of proved and unproved CHK C-T properties | $ | — | $ | 1,024 | $ | — | ||||||
Debt exchanged for common stock | $ | 471 | $ | — | $ | — | ||||||
Repurchase of noncontrolling interest in CHK C-T | $ | — | $ | (872 | ) | $ | — |
Years Ended December 31, | ||||||||||||
2016 | 2015 | 2014 | ||||||||||
($ in millions) | ||||||||||||
PREFERRED STOCK: | ||||||||||||
Balance, beginning of period | $ | 3,062 | $ | 3,062 | $ | 3,062 | ||||||
Conversions of 1,412,009, 0 and 0 shares of preferred stock for common stock | (1,291 | ) | — | — | ||||||||
Balance, end of period | 1,771 | 3,062 | 3,062 | |||||||||
COMMON STOCK: | ||||||||||||
Balance, beginning of period | 7 | 7 | 7 | |||||||||
Exchange of senior notes and contingent convertible notes | 1 | — | — | |||||||||
Conversion of preferred stock | 1 | — | — | |||||||||
Balance, end of period | 9 | 7 | 7 | |||||||||
ADDITIONAL PAID-IN CAPITAL: | ||||||||||||
Balance, beginning of period | 12,403 | 12,531 | 12,446 | |||||||||
Stock-based compensation | 64 | 71 | 47 | |||||||||
Exchange of contingent convertible notes for 55,427,782, 0 and 0 shares of common stock | 241 | — | — | |||||||||
Exchange of senior notes for 53,923,925, 0 and 0 shares of common stock | 229 | — | — | |||||||||
Conversion of preferred stock for 120,186,195, 0 and 0 shares of common stock | 1,290 | — | — | |||||||||
Issuance of 5.5% convertible senior notes due 2026 | 445 | — | — | |||||||||
Tax effect on the issuance of 5.5% convertible senior notes due 2026 | (165 | ) | — | — | ||||||||
Equity component of contingent convertible notes repurchased, net of tax | (16 | ) | — | — | ||||||||
Exercise of stock options | — | — | 23 | |||||||||
Dividends on common stock | — | (59 | ) | — | ||||||||
Dividends on preferred stock | — | (128 | ) | — | ||||||||
Issuance costs | (5 | ) | — | — | ||||||||
Increase (decrease) in tax benefit from stock-based compensation | — | (12 | ) | 15 | ||||||||
Balance, end of period | 14,486 | 12,403 | 12,531 | |||||||||
RETAINED EARNINGS (ACCUMULATED DEFICIT): | ||||||||||||
Balance, beginning of period | (13,202 | ) | 1,483 | 688 | ||||||||
Net income (loss) attributable to Chesapeake | (4,401 | ) | (14,685 | ) | 1,917 | |||||||
Dividends on common stock | — | — | (234 | ) | ||||||||
Dividends on preferred stock | — | — | (171 | ) | ||||||||
Spin-off of oilfield services business | — | — | (270 | ) | ||||||||
Repurchase of preferred shares of CHK Utica | — | — | (447 | ) | ||||||||
Balance, end of period | (17,603 | ) | (13,202 | ) | 1,483 | |||||||
ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS): | ||||||||||||
Balance, beginning of period | (99 | ) | (143 | ) | (162 | ) | ||||||
Hedging activity | 3 | 44 | 24 | |||||||||
Investment activity | — | — | (5 | ) | ||||||||
Balance, end of period | (96 | ) | (99 | ) | (143 | ) | ||||||
Years Ended December 31, | ||||||||||||
2016 | 2015 | 2014 | ||||||||||
($ in millions) | ||||||||||||
TREASURY STOCK – COMMON: | ||||||||||||
Balance, beginning of period | (33 | ) | (37 | ) | (46 | ) | ||||||
Purchase of 37,871, 54,493 and 34,678 shares for company benefit plans | — | (1 | ) | (1 | ) | |||||||
Release of 255,091, 231,081 and 422,395 shares from company benefit plans | 6 | 5 | 10 | |||||||||
Balance, end of period | (27 | ) | (33 | ) | (37 | ) | ||||||
TOTAL CHESAPEAKE STOCKHOLDERS’ EQUITY (DEFICIT) | (1,460 | ) | 2,138 | 16,903 | ||||||||
NONCONTROLLING INTERESTS: | ||||||||||||
Balance, beginning of period | 259 | 1,302 | 2,145 | |||||||||
Net income attributable to noncontrolling interests | 2 | 50 | 139 | |||||||||
Distributions to noncontrolling interest owners | (4 | ) | (78 | ) | (169 | ) | ||||||
Repurchase of noncontrolling interest of CHK C-T | — | (1,015 | ) | — | ||||||||
Repurchase of preferred shares of CHK Utica | — | — | (807 | ) | ||||||||
Deconsolidation of investments, net | — | — | (6 | ) | ||||||||
Balance, end of period | 257 | 259 | 1,302 | |||||||||
TOTAL EQUITY (DEFICIT) | $ | (1,203 | ) | $ | 2,397 | $ | 18,205 |
1. | Basis of Presentation and Summary of Significant Accounting Policies |
December 31, | ||||||||
2016 | 2015 | |||||||
($ in millions) | ||||||||
Oil, natural gas and NGL sales | $ | 840 | $ | 696 | ||||
Joint interest | 156 | 230 | ||||||
Other | 93 | 226 | ||||||
Allowance for doubtful accounts | (32 | ) | (23 | ) | ||||
Total accounts receivable, net | $ | 1,057 | $ | 1,129 |
Year of Acquisition | ||||||||||||||||||||
2016 | 2015 | 2014 | Prior | Total | ||||||||||||||||
($ in millions) | ||||||||||||||||||||
Leasehold cost | $ | 109 | $ | 99 | $ | 507 | $ | 2,956 | $ | 3,671 | ||||||||||
Exploration cost | 24 | 36 | 13 | 34 | 107 | |||||||||||||||
Capitalized interest | 194 | 201 | 184 | 445 | 1,024 | |||||||||||||||
Total | $ | 327 | $ | 336 | $ | 704 | $ | 3,435 | $ | 4,802 |
As Previously Reported | December 31, 2015 Adjustment Effect | As Adjusted | ||||||||||
($ in millions) | ||||||||||||
Other long-term assets | $ | 333 | $ | (43 | ) | $ | 290 | |||||
Long-term debt, net | $ | 10,354 | $ | (43 | ) | $ | 10,311 |
As Previously Reported | December 31, 2015 Adjustment Effect | As Revised | ||||||||||||||||||||||
Carrying Amount | Estimated Fair Value | Carrying Amount | Estimated Fair Value | Carrying Amount | Estimated Fair Value | |||||||||||||||||||
($ in millions) | ||||||||||||||||||||||||
Short-term debt (Level 1) | $ | 381 | $ | 366 | $ | — | $ | — | $ | 381 | $ | 366 | ||||||||||||
Long-term debt (Level 1)(a) | $ | 10,347 | $ | 3,735 | $ | (3,627 | ) | $ | (1,189 | ) | $ | 6,720 | $ | 2,546 | ||||||||||
Long-term debt (Level 2) | $ | — | $ | — | $ | 3,584 | $ | 1,189 | $ | 3,584 | $ | 1,189 |
2. | Earnings Per Share |
Shares | |||
(in millions) | |||
Year Ended December 31, 2016 | |||
Common stock equivalent of our preferred stock outstanding: | |||
5.75% cumulative convertible preferred stock | 34 | ||
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 | 19 | ||
5.75% cumulative convertible preferred stock (series A) exchanged | 18 | ||
5.00% cumulative convertible preferred stock (series 2005B) exchanged | — | ||
Year Ended December 31, 2015 | |||
Common stock equivalent of our preferred stock outstanding: | |||
5.75% cumulative convertible preferred stock | 59 | ||
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 | ||
Year Ended December 31, 2014 | |||
Participating securities | 3 |
Income (Numerator) | Weighted Average Shares (Denominator) | Per Share Amount | |||||||||
(in millions, except per share data) | |||||||||||
For the Year Ended December 31, 2014: | |||||||||||
Basic EPS | $ | 1,273 | 659 | $ | 1.93 | ||||||
Effect of Dilutive Securities: | |||||||||||
Assumed conversion as of the beginning of the period of preferred shares outstanding during the period: | |||||||||||
Common shares assumed issued for 5.75% cumulative convertible preferred stock | 86 | 59 | |||||||||
Common shares assumed issued for 5.75% cumulative convertible preferred stock (series A) | 63 | 42 | |||||||||
Common shares assumed issued for 5.00% cumulative convertible preferred stock (series 2005B) | 10 | 6 | |||||||||
Common shares assumed issued for 4.50% cumulative convertible preferred stock | 12 | 6 | |||||||||
Diluted EPS | $ | 1,444 | 772 | $ | 1.87 |
3. | Debt |
December 31, 2016 | December 31, 2015 | |||||||||||||||
Principal Amount | Carrying Amount | Principal Amount | Carrying Amount | |||||||||||||
($ in millions) | ||||||||||||||||
Term loan due 2021 | $ | 1,500 | $ | 1,500 | $ | — | $ | — | ||||||||
3.25% senior notes due 2016 | — | — | 381 | 381 | ||||||||||||
6.25% euro-denominated senior notes due 2017(a) | 258 | 258 | 329 | 329 | ||||||||||||
6.5% senior notes due 2017 | 134 | 134 | 453 | 453 | ||||||||||||
7.25% senior notes due 2018 | 64 | 64 | 538 | 538 | ||||||||||||
Floating rate senior notes due 2019 | 380 | 380 | 1,104 | 1,104 | ||||||||||||
6.625% senior notes due 2020 | 780 | 780 | 822 | 822 | ||||||||||||
6.875% senior notes due 2020 | 279 | 279 | 304 | 304 | ||||||||||||
6.125% senior notes due 2021 | 550 | 550 | 589 | 589 | ||||||||||||
5.375% senior notes due 2021 | 270 | 270 | 286 | 286 | ||||||||||||
4.875% senior notes due 2022 | 451 | 451 | 639 | 639 | ||||||||||||
8.00% senior secured second lien notes due 2022(b) | 2,419 | 3,409 | 2,425 | 3,584 | ||||||||||||
5.75% senior notes due 2023 | 338 | 338 | 384 | 384 | ||||||||||||
8.00% senior notes due 2025 | 1,000 | 1,000 | — | — | ||||||||||||
5.5% convertible senior notes due 2026(c)(e) | 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) | 114 | 112 | 1,110 | 1,027 | ||||||||||||
2.25% contingent convertible senior notes due 2038(d)(e) | 200 | 180 | 340 | 290 | ||||||||||||
Revolving credit facility | — | — | — | — | ||||||||||||
Debt issuance costs | — | (64 | ) | — | (43 | ) | ||||||||||
Discount on senior notes | — | (16 | ) | — | (4 | ) | ||||||||||
Interest rate derivatives(f) | — | 3 | — | 7 | ||||||||||||
Total debt, net | 9,989 | 10,441 | 9,706 | 10,692 | ||||||||||||
Less current maturities of long-term debt, net(g) | (506 | ) | (503 | ) | (381 | ) | (381 | ) | ||||||||
Total long-term debt, net | $ | 9,483 | $ | 9,938 | $ | 9,325 | $ | 10,311 |
(a) | The principal and carrying amounts shown are based on the exchange rate of $1.0517 to €1.00 and $1.0862 to €1.00 as of December 31, 2016 and 2015, respectively. See Foreign Currency Derivatives in Note 11 for information on our related foreign currency derivatives. |
(b) | The carrying amounts as of December 31, 2016 and 2015, include premium amounts of $990 million and $1.159 billion, respectively, associated with a troubled debt restructuring. The premium is being amortized based on an effective yield method. |
(c) | The conversion and redemption provisions of our convertible senior notes are as follows: |
(d) | The repurchase, conversion, contingent interest and redemption provisions of our 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 |
(e) | The carrying amounts as of December 31, 2016 and 2015 are reflected net of discounts of $461 million and $133 million, respectively, associated with the equity component of our convertible and contingent convertible senior notes. This amount is being amortized based on an effective yield method through the first demand repurchase date as applicable. |
(f) | See Interest Rate Derivatives in Note 11 for further discussion related to these instruments. |
(g) | As of December 31, 2016, current maturities of long-term debt, net includes our 6.25% Euro-denominated Senior Notes due 2017, 6.5% Senior Notes due 2017 and our 2.5% Contingent Convertible Senior Notes due 2037 (2037 Notes). As discussed in footnote (b) 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. As of December 31, 2016, there was $2 million associated with the equity component of the 2037 Notes. |
Principal Amount of Debt Securities | ||||
($ in millions) | ||||
2017 | $ | 506 | ||
2018 | 264 | |||
2019 | 380 | |||
2020 | 1,061 | |||
2021 | 2,320 | |||
2022 and thereafter | 5,458 | |||
Total | $ | 9,989 |
December 31, 2016 | December 31, 2015 | |||||||||||||||
Carrying Amount | Estimated Fair Value | Carrying Amount | Estimated Fair Value | |||||||||||||
($ in millions) | ||||||||||||||||
Short-term debt (Level 1) | $ | 503 | $ | 511 | $ | 381 | $ | 366 | ||||||||
Long-term debt (Level 1) | $ | 3,271 | $ | 3,216 | $ | 6,720 | $ | 2,546 | ||||||||
Long-term debt (Level 2) | $ | 6,664 | $ | 6,654 | $ | 3,584 | $ | 1,189 |
4. | Contingencies and Commitments |
December 31, 2016 | ||||
($ in millions) | ||||
2017 | $ | 4 | ||
2018 | 3 | |||
2019 | 2 | |||
Total | $ | 9 |
December 31, 2016 | ||||
($ in millions) | ||||
2017 | $ | 1,434 | ||
2018 | 1,229 | |||
2019 | 1,178 | |||
2020 | 1,074 | |||
2021 | 970 | |||
2022 – 2099 | 5,225 | |||
Total | $ | 11,110 |
December 31, 2016 | ||||
($ in millions) | ||||
2017 | $ | 91 | ||
2018 | 14 | |||
Total | $ | 105 |
5. | Other Liabilities |
December 31, | ||||||||
2016 | 2015 | |||||||
($ in millions) | ||||||||
Revenues and royalties due others | $ | 543 | $ | 500 | ||||
Accrued drilling and production costs | 169 | 212 | ||||||
Joint interest prepayments received | 71 | 169 | ||||||
Accrued compensation and benefits | 239 | 264 | ||||||
Other accrued taxes | 32 | 37 | ||||||
Bank of New York Mellon legal accrual | 440 | 439 | ||||||
Minimum gathering volume commitment | — | 201 | ||||||
Other | 304 | 397 | ||||||
Total other current liabilities | $ | 1,798 | $ | 2,219 |
December 31, | ||||||||
2016 | 2015 | |||||||
($ in millions) | ||||||||
CHK Utica ORRI conveyance obligation(a) | $ | 160 | $ | 190 | ||||
Financing obligations | — | 29 | ||||||
Unrecognized tax benefits | 97 | 64 | ||||||
Other | 126 | 126 | ||||||
Total other long-term liabilities | $ | 383 | $ | 409 |
(a) | Approximately $43 million and $21 million of the total $203 million and $211 million obligations are recorded in other current liabilities as of December 31, 2016 and 2015, respectively. See Noncontrolling Interests in Note 8 for further discussion of the transaction. |
6. | Income Taxes |
Years Ended December 31, | ||||||||||||
2016 | 2015 | 2014 | ||||||||||
($ in millions) | ||||||||||||
Current | ||||||||||||
Federal | $ | (14 | ) | $ | — | $ | — | |||||
State | (5 | ) | (36 | ) | 47 | |||||||
Current Income Taxes | (19 | ) | (36 | ) | 47 | |||||||
Deferred | ||||||||||||
Federal | (147 | ) | (4,385 | ) | 1,115 | |||||||
State | (24 | ) | (42 | ) | (18 | ) | ||||||
Deferred Income Taxes | (171 | ) | (4,427 | ) | 1,097 | |||||||
Total | $ | (190 | ) | $ | (4,463 | ) | $ | 1,144 |
Years Ended December 31, | ||||||||||||
2016 | 2015 | 2014 | ||||||||||
($ in millions) | ||||||||||||
Income tax expense (benefit) at the federal statutory rate (35%) | $ | (1,606 | ) | $ | (6,684 | ) | $ | 1,120 | ||||
State income taxes (net of federal income tax benefit) | (30 | ) | (406 | ) | 68 | |||||||
Remeasurement of state deferred tax liabilities | — | — | (114 | ) | ||||||||
Change in valuation allowance | 1,423 | 2,727 | 74 | |||||||||
Other | 23 | (100 | ) | (4 | ) | |||||||
Total | $ | (190 | ) | $ | (4,463 | ) | $ | 1,144 |
Years Ended December 31, | ||||||||
2016 | 2015 | |||||||
($ in millions) | ||||||||
Deferred tax liabilities: | ||||||||
Volumetric production payments | $ | (223 | ) | $ | (802 | ) | ||
Derivative instruments | — | (300 | ) | |||||
Other | (62 | ) | (71 | ) | ||||
Deferred tax liabilities | (285 | ) | (1,173 | ) | ||||
Deferred tax assets: | ||||||||
Property, plant and equipment | 593 | 1,144 | ||||||
Net operating loss carryforwards | 2,587 | 1,556 | ||||||
Carrying value of debt | 539 | 532 | ||||||
Asset retirement obligations | 98 | 174 | ||||||
Investments | 275 | 260 | ||||||
Derivative instruments | 161 | — | ||||||
Accrued liabilities | 319 | 333 | ||||||
Other | 118 | 123 | ||||||
Deferred tax assets | 4,690 | 4,122 | ||||||
Valuation allowance | (4,389 | ) | (2,949 | ) | ||||
Net deferred tax assets | 301 | 1,173 | ||||||
Net deferred tax assets(a) | $ | 16 | $ | — |
(a) | The net deferred tax assets are included in other long-term assets in the accompanying balance sheets. |
2016 | 2015 | 2014 | ||||||||||
($ in millions) | ||||||||||||
Unrecognized tax benefits at beginning of period | $ | 280 | $ | 303 | $ | 644 | ||||||
Additions based on tax positions related to the current year | — | 27 | 13 | |||||||||
Additions to tax positions of prior years | 33 | — | — | |||||||||
Settlements | (111 | ) | — | — | ||||||||
Reductions to tax positions of prior years | — | (50 | ) | (354 | ) | |||||||
Unrecognized tax benefits at end of period | $ | 202 | $ | 280 | $ | 303 |
7. | Related Party Transactions |
8. | Equity |
Years Ended December 31, | |||||||||
2016 | 2015 | 2014 | |||||||
(in thousands) | |||||||||
Shares issued as of January 1 | 664,796 | 664,944 | 666,192 | ||||||
Exchange of convertible notes | 55,428 | — | — | ||||||
Exchange of senior notes | 53,924 | — | — | ||||||
Conversion of preferred stock | 120,186 | — | — | ||||||
Restricted stock issuances (net of forfeitures and cancellations)(a) | 1,945 | (163 | ) | (2,529 | ) | ||||
Stock option exercises | — | 15 | 1,281 | ||||||
Shares issued as of December 31 | 896,279 | 664,796 | 664,944 |
(a) | The amount for 2014 reflects forfeitures upon the June 2014 spin-off of our oilfield services business. |
Preferred Stock Series | Issue Date | Liquidation Preference per Share | Holder's Conversion Right | Conversion Rate | Conversion Price | Company's Conversion Right From | Company's Market Conversion Trigger(a) | |||||||||||||
5.75% cumulative convertible non-voting | May and June 2010 | $ | 1,000 | Any time | 39.6858 | $ | 25.1979 | May 17, 2015 | $ | 32.7572 | ||||||||||
5.75% (series A) cumulative convertible non-voting | May 2010 | $ | 1,000 | Any time | 38.3508 | $ | 26.0751 | May 17, 2015 | $ | 33.8976 | ||||||||||
4.50% cumulative convertible | September 2005 | $ | 100 | Any time | 2.4561 | $ | 40.7152 | September 15, 2010 | $ | 52.9298 | ||||||||||
5.00% cumulative convertible (series 2005B) | November 2005 | $ | 100 | Any time | 2.7745 | $ | 36.0431 | November 15, 2010 | $ | 46.8560 |
(a) | Convertible at the Company's option if the trading price of the Company's common stock equals or exceeds the trigger price for a specified time period or after the applicable conversion date if there are less than 250,000 shares of 4.50% or 5.00% (Series 2005B) preferred stock outstanding or 25,000 shares of 5.75% or 5.75% (Series A) preferred stock outstanding. |
5.75% | 5.75% (A) | 4.50% | 5.00% (2005B) | |||||||||
(in thousands) | ||||||||||||
Shares outstanding as of January 1, 2016 | 1,497 | 1,100 | 2,559 | 2,096 | ||||||||
Preferred stock conversions/exchanges(a) | (654 | ) | (624 | ) | — | (134 | ) | |||||
Shares outstanding as of December 31, 2016 | 843 | 476 | 2,559 | 1,962 | ||||||||
Shares outstanding as of January 1, 2015 and December 31, 2015 | 1,497 | 1,100 | 2,559 | 2,096 | ||||||||
Shares outstanding as of January 1, 2014 and December 31, 2014 | 1,497 | 1,100 | 2,559 | 2,096 |
(a) | During 2016, holders of our 5.75% Cumulative Convertible Preferred Stock exchanged or converted 653,872 shares into 59,141,429 shares of common stock, holders of our 5.75% (Series A) Cumulative Convertible Preferred Stock exchanged or converted 624,137 shares into 60,032,734 shares of common stock and holders of our 5.00% (Series 2005B) Cumulative Convertible Preferred Stock exchanged or converted 134,000 shares into 1,012,032 shares of common stock. In connection with the exchanges noted above, 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 $428 million is reflected as a reduction to net income available to common stockholders for the purpose of calculating earnings per common share. |
5.75% | 5.75% (A) | 4.50% | 5.00% (2005B) | |||||||||||||
($ in millions) | ||||||||||||||||
Dividends in arrears | $ | 48 | $ | 27 | $ | 12 | $ | 10 |
Years Ended December 31, | ||||||||
2016 | 2015 | |||||||
($ in millions) | ||||||||
Balance, beginning of period | $ | (99 | ) | $ | (143 | ) | ||
Other comprehensive income before reclassifications | (13 | ) | 20 | |||||
Amounts reclassified from accumulated other comprehensive income | 16 | 24 | ||||||
Net other comprehensive income (loss) | 3 | 44 | ||||||
Balance, end of period | $ | (96 | ) | $ | (99 | ) |
Details About Accumulated Other Comprehensive Income (Loss) Components | Affected Line Item in the Statement Where Net Income is Presented | Amounts Reclassified | ||||
($ in millions) | ||||||
Year Ended December 31, 2016 | ||||||
Net losses on cash flow hedges: | ||||||
Commodity contracts | Oil, natural gas and NGL revenues | $ | 16 | |||
Foreign currency derivative | Gain (loss) on purchases or exchanges of debt | — | ||||
Total reclassifications for the period, net of tax | $ | 16 | ||||
Year Ended December 31, 2015 | ||||||
Net losses on cash flow hedges: | ||||||
Commodity contracts | Oil, natural gas and NGL revenues | $ | 23 | |||
Foreign currency derivative | Gain (loss) on purchases or exchanges of debt | 1 | ||||
Total reclassifications for the period, net of tax | $ | 24 |
Production Period | Distribution Date | Cash Distribution per Common Unit | Cash Distribution per Subordinated Unit | |||||||
June 2016 – August 2016 | December 1, 2016 | $ | 0.0857 | $ | — | |||||
March 2016 – May 2016 | August 29, 2016 | $ | 0.0734 | $ | — | |||||
December 2015 – February 2016 | May 31, 2016 | $ | 0.0403 | $ | — | |||||
September 2015 – November 2015 | March 1, 2016 | $ | 0.2195 | $ | — | |||||
June 2015 – August 2015 | November 30, 2015 | $ | 0.3232 | $ | — | |||||
March 2015 – May 2015 | August 31, 2015 | $ | 0.3579 | $ | — | |||||
December 2014 – February 2015 | June 1, 2015 | $ | 0.3899 | $ | — | |||||
September 2014 – November 2014 | March 2, 2015 | $ | 0.4496 | $ | — | |||||
June 2014 – August 2014 | December 1, 2014 | $ | 0.5079 | $ | — | |||||
March 2014 – May 2014 | August 29, 2014 | $ | 0.5796 | $ | — | |||||
December 2013 – February 2014 | May 30, 2014 | $ | 0.6454 | $ | — | |||||
September 2013 – November 2013 | March 3, 2014 | $ | 0.6624 | $ | — |
9. | Share-Based Compensation |
Shares of Unvested Restricted Stock | Weighted Average Grant Date Fair Value | ||||||
(in thousands) | |||||||
Unvested restricted stock as of January 1, 2016 | 10,455 | $ | 17.31 | ||||
Granted | 4,604 | $ | 4.58 | ||||
Vested | (4,692 | ) | $ | 17.23 | |||
Forfeited | (1,275 | ) | $ | 13.91 | |||
Unvested restricted stock as of December 31, 2016 | 9,092 | $ | 11.39 | ||||
Unvested restricted stock as of January 1, 2015 | 10,091 | $ | 21.20 | ||||
Granted | 7,095 | $ | 13.90 | ||||
Vested | (4,157 | ) | $ | 21.70 | |||
Forfeited | (2,574 | ) | $ | 16.98 | |||
Unvested restricted stock as of December 31, 2015 | 10,455 | $ | 17.31 | ||||
Unvested restricted stock as of January 1, 2014 | 13,400 | $ | 23.38 | ||||
Granted | 5,049 | $ | 25.92 | ||||
Vested | (4,803 | ) | $ | 27.17 | |||
Forfeited | (3,555 | ) | $ | 28.09 | |||
Unvested restricted stock as of December 31, 2014 | 10,091 | $ | 21.20 |
Expected option life – years | 6.0 | ||
Volatility | 46.07 | % | |
Risk-free interest rate | 1.70 | % | |
Dividend yield | — | % |
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, 2016 | 5,377 | $ | 19.37 | 5.80 | $ | — | |||||||
Granted | 4,932 | $ | 3.71 | ||||||||||
Exercised | — | $ | — | $ | — | ||||||||
Expired | (771 | ) | $ | 19.46 | |||||||||
Forfeited | (945 | ) | $ | 5.66 | |||||||||
Outstanding as of December 31, 2016 | 8,593 | $ | 11.88 | 7.22 | $ | 14 | |||||||
Exercisable as of December 31, 2016 | 2,844 | $ | 19.60 | 5.53 | $ | — | |||||||
Outstanding as of January 1, 2015 | 4,599 | $ | 19.55 | 7.03 | $ | 5 | |||||||
Granted | 1,208 | $ | 18.37 | ||||||||||
Exercised | (14 | ) | $ | 18.13 | $ | — | |||||||
Expired | (416 | ) | $ | 18.46 | |||||||||
Forfeited | — | $ | — | ||||||||||
Outstanding as of December 31, 2015 | 5,377 | $ | 19.37 | 5.80 | $ | — | |||||||
Exercisable as of December 31, 2015 | 2,045 | $ | 19.61 | 5.07 | $ | — | |||||||
Outstanding as of January 1, 2014 | 5,268 | $ | 19.28 | 6.66 | $ | 41 | |||||||
Granted | 994 | $ | 24.43 | ||||||||||
Exercised | (1,322 | ) | $ | 18.71 | $ | 11 | |||||||
Expired | (28 | ) | $ | 18.97 | |||||||||
Forfeited | (313 | ) | $ | 21.05 | |||||||||
Outstanding as of December 31, 2014 | 4,599 | $ | 19.55 | 7.03 | $ | 5 | |||||||
Exercisable as of December 31, 2014 | 1,304 | $ | 18.71 | 5.70 | $ | 1 |
(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. |
Years Ended December 31, | ||||||||||||
2016 | 2015 | 2014 | ||||||||||
($ in millions) | ||||||||||||
General and administrative expenses | $ | 38 | $ | 43 | $ | 46 | ||||||
Oil and natural gas properties | 16 | 23 | 29 | |||||||||
Oil, natural gas and NGL production expenses | 13 | 18 | 18 | |||||||||
Marketing, gathering and compression expenses | 1 | 5 | 6 | |||||||||
Oilfield services expenses | — | — | 5 | |||||||||
Total | $ | 68 | $ | 89 | $ | 104 |
Volatility | 91.19 | % | |
Risk-free interest rate | 1.20 | % | |
Dividend yield for value of awards | — | % |
Grant Date Fair Value | December 31, 2016 | ||||||||||||||
Units | Fair Value | Vested Liability | |||||||||||||
($ in millions) | |||||||||||||||
2016 Awards: | |||||||||||||||
Payable 2019 | 2,348,893 | $ | 10 | $ | 20 | $ | 12 | ||||||||
2015 Awards: | |||||||||||||||
Payable 2018 | 629,694 | $ | 13 | $ | 4 | $ | 3 | ||||||||
2014 Awards: | |||||||||||||||
Payable 2017 | 561,215 | $ | 16 | $ | — | $ | — |
Years Ended December 31, | ||||||||||||
2016 | 2015 | 2014 | ||||||||||
($ in millions) | ||||||||||||
General and administrative expenses | $ | 14 | $ | (19 | ) | $ | (4 | ) | ||||
Restructuring and other termination costs | 1 | (19 | ) | (19 | ) | |||||||
Marketing, gathering and compression | — | (1 | ) | — | ||||||||
Oil and natural gas properties | — | (2 | ) | 3 | ||||||||
Total | $ | 15 | $ | (41 | ) | $ | (20 | ) |
11. | Derivative and Hedging Activities |
• | Swaps: Chesapeake receives a fixed price and pays a floating market price to the counterparty for the hedged commodity. In exchange for higher fixed prices on certain of our swap trades, we granted options that allow the counterparty to double the notional amount. |
• | 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. |
December 31, 2016 | December 31, 2015 | |||||||||||||
Volume | Fair Value | Volume | Fair Value | |||||||||||
($ in millions) | ($ in millions) | |||||||||||||
Oil (mmbbl): | ||||||||||||||
Fixed-price swaps | 23 | $ | (140 | ) | 14 | $ | 144 | |||||||
Call options | 5 | (1 | ) | 19 | (7 | ) | ||||||||
Total oil | 28 | (141 | ) | 33 | 137 | |||||||||
Natural gas (tbtu): | ||||||||||||||
Fixed-price swaps | 719 | (349 | ) | 500 | 229 | |||||||||
Collars | 60 | (9 | ) | — | — | |||||||||
Call options | 114 | — | 295 | (99 | ) | |||||||||
Basis protection swaps | 31 | (5 | ) | 57 | — | |||||||||
Total natural gas | 924 | (363 | ) | 852 | 130 | |||||||||
NGL (mmgal): | ||||||||||||||
Fixed-price swaps | 53 | — | — | — | ||||||||||
Total estimated fair value | $ | (504 | ) | $ | 267 |
Balance Sheet Classification | Gross Fair Value | Amounts Netted in the Consolidated Balance Sheets | Net Fair Value Presented in Consolidated Balance Sheet | |||||||||
($ in millions) | ||||||||||||
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) | ||||||||||||
Short-term derivative liability | (73 | ) | — | (73 | ) | |||||||
Total foreign currency contracts | (73 | ) | — | (73 | ) | |||||||
Total derivatives | $ | (577 | ) | $ | — | $ | (577 | ) | ||||
As of December 31, 2015 | ||||||||||||
Commodity Contracts: | ||||||||||||
Short-term derivative asset | $ | 381 | $ | (66 | ) | $ | 315 | |||||
Short-term derivative liability | (106 | ) | 66 | (40 | ) | |||||||
Long-term derivative liability | (8 | ) | — | (8 | ) | |||||||
Total commodity contracts | 267 | — | 267 | |||||||||
Foreign Currency Contracts:(a) | ||||||||||||
Long-term derivative liability | (52 | ) | — | (52 | ) | |||||||
Total foreign currency contracts | (52 | ) | — | (52 | ) | |||||||
Supply Contracts: | ||||||||||||
Short-term derivative asset | 51 | — | 51 | |||||||||
Long-term derivative asset | 246 | — | 246 | |||||||||
Total supply contracts | 297 | — | 297 | |||||||||
Total derivatives | $ | 512 | $ | — | $ | 512 |
(a) | Designated as cash flow hedging instruments. |
Years Ended December 31, | ||||||||||||
2016 | 2015 | 2014 | ||||||||||
($ in millions) | ||||||||||||
Oil, natural gas and NGL revenues | $ | 3,866 | $ | 4,767 | $ | 9,336 | ||||||
Gains (losses) on undesignated oil, natural gas and NGL derivatives | (545 | ) | 661 | 1,055 | ||||||||
Losses on terminated cash flow hedges | (33 | ) | (37 | ) | (37 | ) | ||||||
Total oil, natural gas and NGL revenues | $ | 3,288 | $ | 5,391 | $ | 10,354 |
Years Ended December 31, | ||||||||||||
2016 | 2015 | 2014 | ||||||||||
($ in millions) | ||||||||||||
Marketing, gathering and compression revenues | $ | 4,881 | $ | 7,077 | $ | 12,224 | ||||||
Gains (losses) on undesignated supply contract derivatives | (297 | ) | 296 | 1 | ||||||||
Total marketing, gathering and compression revenues | $ | 4,584 | $ | 7,373 | $ | 12,225 |
Years Ended December 31, | ||||||||||||
2016 | 2015 | 2014 | ||||||||||
($ in millions) | ||||||||||||
Interest expense on senior notes | $ | 588 | $ | 682 | $ | 704 | ||||||
Interest expense on term loan | 46 | — | 36 | |||||||||
Amortization of loan discount, issuance costs and other | 33 | 62 | 42 | |||||||||
Amortization of premium associated with troubled debt restructuring | (165 | ) | (3 | ) | — | |||||||
Interest expense on revolving credit facilities | 35 | 12 | 28 | |||||||||
Gains on terminated fair value hedges | (2 | ) | (3 | ) | (3 | ) | ||||||
(Gains) losses on undesignated interest rate derivatives | 12 | (9 | ) | (81 | ) | |||||||
Capitalized interest | (251 | ) | (424 | ) | (637 | ) | ||||||
Total interest expense | $ | 296 | $ | 317 | $ | 89 |
Years Ended December 31, | ||||||||||||||||||||||||
2016 | 2015 | 2014 | ||||||||||||||||||||||
Before Tax | After Tax | Before Tax | After Tax | Before Tax | After Tax | |||||||||||||||||||
($ in millions) | ||||||||||||||||||||||||
Balance, beginning of period | $ | (160 | ) | $ | (99 | ) | $ | (231 | ) | $ | (143 | ) | $ | (269 | ) | $ | (167 | ) | ||||||
Net change in fair value | (27 | ) | (13 | ) | 32 | 20 | 1 | 1 | ||||||||||||||||
Losses reclassified to income | 34 | 16 | 39 | 24 | 37 | 23 | ||||||||||||||||||
Balance, end of period | $ | (153 | ) | $ | (96 | ) | $ | (160 | ) | $ | (99 | ) | $ | (231 | ) | $ | (143 | ) |
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 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 | ) | |||||
As of December 31, 2015 | ||||||||||||||||
Derivative Assets (Liabilities): | ||||||||||||||||
Commodity assets | $ | — | $ | 372 | $ | 9 | $ | 381 | ||||||||
Commodity liabilities | — | (14 | ) | (100 | ) | (114 | ) | |||||||||
Foreign currency liabilities | — | (52 | ) | — | (52 | ) | ||||||||||
Supply contract assets | — | — | 297 | 297 | ||||||||||||
Total derivatives | $ | — | $ | 306 | $ | 206 | $ | 512 |
Commodity Derivatives | Supply Contracts | |||||||
($ in millions) | ||||||||
Beginning balance as of December 31, 2015 | $ | (91 | ) | $ | 297 | |||
Total gains (losses) (realized/unrealized): | ||||||||
Included in earnings(a) | 6 | (118 | ) | |||||
Total purchases, issuances, sales and settlements: | ||||||||
Settlements | 75 | (33 | ) | |||||
Sales | — | (146 | ) | |||||
Ending balance as of December 31, 2016 | $ | (10 | ) | $ | — | |||
Beginning balance as of December 31, 2014 | $ | (54 | ) | $ | 1 | |||
Total gains (losses) (realized/unrealized): | ||||||||
Included in earnings(a) | 100 | 316 | ||||||
Total purchases, issuances, sales and settlements: | ||||||||
Settlements | (137 | ) | (20 | ) | ||||
Ending balance as of December 31, 2015 | $ | (91 | ) | $ | 297 |
(a) | Oil, Natural Gas and NGL Sales | Marketing, Gathering and Compression Revenue | ||||||||||||||
2016 | 2015 | 2016 | 2015 | |||||||||||||
($ in millions) | ||||||||||||||||
Total gains (losses) included in earnings for the period | $ | 6 | $ | 100 | $ | (118 | ) | $ | 316 | |||||||
Change in unrealized gains (losses) related to assets still held at reporting date | $ | (7 | ) | $ | 43 | $ | — | $ | 296 |
Instrument Type | Unobservable Input | Range | Weighted Average | Fair Value December 31, 2016 | ||||||
($ in millions) | ||||||||||
Oil trades | Oil price volatility curves | 17.32% - 25.95% | 23.95% | $ | (1 | ) | ||||
Natural gas trades | Natural gas price volatility curves | 19.72% – 68.72% | 30.71% | $ | (9 | ) |
12. | Oil and Natural Gas Property Transactions |
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 |
Year Ended December 31, 2016 | ||||||||||||
VPP # | Oil | Natural Gas | NGL | Total | ||||||||
(mbbl) | (bcf) | (mbbl) | (bcfe) | |||||||||
10(a) | 108.0 | 3.0 | 368.7 | 5.9 | ||||||||
9 | 152.4 | 12.9 | 347.1 | 15.9 | ||||||||
4(a) | 20.0 | 3.8 | — | 3.9 | ||||||||
3(a) | — | 2.4 | — | 2.4 | ||||||||
2(a) | — | 1.5 | — | 1.5 | ||||||||
1(a) | — | 11.1 | — | 11.1 | ||||||||
280.4 | 34.7 | 715.8 | 40.7 | |||||||||
Year Ended December 31, 2015 | ||||||||||||
VPP # | Oil | Natural Gas | NGL | Total | ||||||||
(mbbl) | (bcf) | (mbbl) | (bcfe) | |||||||||
10(a) | 310.0 | 8.5 | 1,043.9 | 16.6 | ||||||||
9 | 167.9 | 14.2 | 375.9 | 17.4 | ||||||||
8(b) | — | 36.5 | — | 36.5 | ||||||||
4(a) | 42.5 | 8.0 | — | 8.2 | ||||||||
3(a) | — | 6.4 | — | 6.4 | ||||||||
2(a) | — | 4.0 | — | 4.0 | ||||||||
1(a) | — | 13.3 | — | 13.3 | ||||||||
520.4 | 90.9 | 1,419.8 | 102.4 | |||||||||
Year Ended December 31, 2014 | ||||||||||||
VPP # | Oil | Natural Gas | NGL | Total | ||||||||
(mbbl) | (bcf) | (mbbl) | (bcfe) | |||||||||
10(a) | 403.0 | 10.6 | 1,296.5 | 20.7 | ||||||||
9 | 187.5 | 15.4 | 411.0 | 19.0 | ||||||||
8(b) | — | 60.1 | — | 60.1 | ||||||||
6(c) | 23.1 | 4.2 | — | 4.3 | ||||||||
5(c) | 16.5 | 4.6 | — | 4.7 | ||||||||
4(a) | 48.1 | 9.0 | — | 9.2 | ||||||||
3(a) | — | 7.2 | — | 7.2 | ||||||||
2(a) | — | 6.2 | — | 6.2 | ||||||||
1(a) | — | 13.8 | — | 13.8 | ||||||||
678.2 | 131.1 | 1,707.5 | 145.2 |
(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. |
(b) | VPP #8 expired in August 2015. |
(c) | We divested the properties associated with VPP #5 and VPP #6 in 2014. |
Volume Remaining as of December 31, 2016 | ||||||||||||||
VPP # | Term Remaining | Oil | Natural Gas | NGL | Total | |||||||||
(in months) | (mmbbl) | (bcf) | (mmbbl) | (bcfe) | ||||||||||
9 | 50 | 0.5 | 45.9 | 1.2 | 56.3 |
• | COO and certain of its subsidiaries entered into a $275 million senior secured revolving credit facility and a $400 million secured term loan, the proceeds of which were used to repay in full and terminate COO’s then-existing credit facility. |
• | COO distributed to us its compression unit manufacturing business, its geosteering business and the proceeds from the sale of substantially all of its crude oil hauling business. |
• | We transferred to a subsidiary of COO, at carrying value, certain of our buildings and land, most of which COO had been leasing from us prior to the spin-off. |
• | COO issued $500 million of 6.5% Senior Notes due 2022 in a private placement and used the net proceeds to make a cash distribution of approximately $391 million to us, to repay a portion of outstanding indebtedness under the new revolving credit facility and for general corporate purposes. |
14. | Investments |
Approximate Ownership % | Carrying Value | |||||||||||||
Accounting Method | December 31, 2016 | December 31, 2015 | December 31, 2016 | December 31, 2015 | ||||||||||
($ in millions) | ||||||||||||||
Sundrop Fuels, Inc. | Equity | 56% | 56% | $ | — | $ | 119 | |||||||
FTS International, Inc. | Equity | 30% | 30% | — | — | |||||||||
Other | — | —% | —% | 7 | 17 | |||||||||
Total investments(a) | $ | 7 | $ | 136 |
(a) | Balance is included in other long-term assets on our consolidated balance sheets. |
15. | Variable Interest Entities |
16. | Other Property and Equipment |
December 31, | Estimated Useful Life | |||||||||
2016 | 2015 | |||||||||
($ in millions) | (in years) | |||||||||
Buildings and improvements | $ | 1,119 | $ | 1,209 | 10 – 39 | |||||
Computer equipment | 337 | 318 | 5 | |||||||
Natural gas compressors(a) | 251 | 483 | 3 – 20 | |||||||
Land | 139 | 289 | ||||||||
Gathering systems and treating plants(a) | 2 | 214 | 20 | |||||||
Other | 205 | 414 | 2 – 20 | |||||||
Total other property and equipment, at cost | 2,053 | 2,927 | ||||||||
Less: accumulated depreciation | (632 | ) | (813 | ) | ||||||
Total other property and equipment, net | $ | 1,421 | $ | 2,114 |
(a) | Included in our marketing, gathering and compression operating segment. The decrease is primarily related to asset divestitures in 2016. |
Years Ended December 31, | ||||||||||||
2016 | 2015 | 2014 | ||||||||||
($ in millions) | ||||||||||||
Buildings and land | $ | (1 | ) | $ | 3 | $ | (2 | ) | ||||
Natural gas compressors | (10 | ) | — | (195 | ) | |||||||
Gathering systems and treating plants | — | 1 | 8 | |||||||||
Oilfield services equipment | — | — | (7 | ) | ||||||||
Other | (1 | ) | — | (3 | ) | |||||||
Total net (gains) losses on sales of fixed assets | $ | (12 | ) | $ | 4 | $ | (199 | ) |
17. | Impairments |
Years Ended December 31, | ||||||||||||
2016 | 2015 | 2014 | ||||||||||
($ in millions) | ||||||||||||
Barnett Shale exit costs | $ | 645 | $ | — | $ | — | ||||||
Devonian Shale exit costs | 142 | — | — | |||||||||
Gathering systems | 3 | — | 13 | |||||||||
Natural gas compressors | 21 | 21 | 11 | |||||||||
Buildings and land | 11 | — | 18 | |||||||||
Oilfield services equipment | — | — | 23 | |||||||||
Other | 16 | 173 | 23 | |||||||||
Total impairments of fixed assets and other | $ | 838 | $ | 194 | $ | 88 |
18. | Restructuring and Other Termination Costs |
19. | Fair Value Measurements |
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 December 31, 2016 | ||||||||||||||||
Financial Assets (Liabilities): | ||||||||||||||||
Other current assets | $ | 49 | $ | — | $ | — | $ | 49 | ||||||||
Other current liabilities | (51 | ) | — | — | (51 | ) | ||||||||||
Total | $ | (2 | ) | $ | — | $ | — | $ | (2 | ) | ||||||
As of December 31, 2015 | ||||||||||||||||
Financial Assets (Liabilities): | ||||||||||||||||
Other current assets | $ | 50 | $ | — | $ | — | $ | 50 | ||||||||
Other current liabilities | (51 | ) | — | — | (51 | ) | ||||||||||
Total | $ | (1 | ) | $ | — | $ | — | $ | (1 | ) |
20. | Asset Retirement Obligations |
Years Ended December 31, | ||||||||
2016 | 2015 | |||||||
($ in millions) | ||||||||
Asset retirement obligations, beginning of period | $ | 473 | $ | 465 | ||||
Additions | 4 | 6 | ||||||
Revisions(a) | (58 | ) | 13 | |||||
Settlements and disposals(b) | (182 | ) | (34 | ) | ||||
Accretion expense | 24 | 23 | ||||||
Asset retirement obligations, end of period | 261 | 473 | ||||||
Less current portion (c) | 14 | 21 | ||||||
Asset retirement obligation, long-term | $ | 247 | $ | 452 |
(a) | Revisions in estimated liabilities during the period relate primarily to changes in estimates of asset retirement costs and the expected timing of settlement. |
(b) | Settlements and disposals in 2016 relate primarily to wells divested in the Barnett and Devonian Shale areas. |
(c) | Balance is included in other current liabilities on our consolidated balance sheets. |
21. | Major Customers and Segment Information |
Exploration and Production | Marketing, Gathering and Compression | Former Oilfield Services | Other | Intercompany Eliminations | Consolidated Total | |||||||||||||||||||
($ in millions) | ||||||||||||||||||||||||
Year Ended December 31, 2016 | ||||||||||||||||||||||||
Revenues | $ | 3,288 | $ | 8,334 | $ | — | $ | — | $ | (3,750 | ) | $ | 7,872 | |||||||||||
Intersegment revenues | — | (3,750 | ) | — | — | 3,750 | — | |||||||||||||||||
Total revenues | $ | 3,288 | $ | 4,584 | $ | — | $ | — | $ | — | $ | 7,872 | ||||||||||||
Unrealized losses on commodity derivatives | $ | 819 | $ | — | $ | — | $ | — | $ | — | $ | 819 | ||||||||||||
Unrealized losses on marketing derivatives | $ | — | $ | 297 | $ | — | $ | — | $ | — | $ | 297 | ||||||||||||
Oil, natural gas, NGL and other depreciation, depletion and amortization | $ | 1,024 | $ | 45 | $ | — | $ | 38 | $ | — | $ | 1,107 | ||||||||||||
Impairment of oil and natural gas properties | $ | 2,564 | $ | — | $ | — | $ | — | $ | — | $ | 2,564 | ||||||||||||
Impairments of fixed assets and other | $ | 387 | $ | 220 | $ | — | $ | 231 | $ | — | $ | 838 | ||||||||||||
Net gain (loss) on sales of fixed assets | $ | (4 | ) | $ | (7 | ) | $ | — | $ | (1 | ) | $ | — | $ | (12 | ) | ||||||||
Interest expense | $ | (303 | ) | $ | — | $ | — | $ | 7 | $ | — | $ | (296 | ) | ||||||||||
Losses on investments | $ | — | $ | — | $ | — | $ | (8 | ) | $ | — | $ | (8 | ) | ||||||||||
Impairments of investments | $ | — | $ | — | $ | — | $ | (119 | ) | $ | — | $ | (119 | ) | ||||||||||
Gains on purchases or exchanges of debt | $ | 236 | $ | — | $ | — | $ | — | $ | — | $ | 236 | ||||||||||||
Income (Loss) Before Income Taxes | $ | (4,099 | ) | $ | (112 | ) | $ | — | $ | (378 | ) | $ | — | $ | (4,589 | ) | ||||||||
Total Assets | $ | 11,249 | $ | 1,118 | $ | — | $ | 1,059 | $ | (398 | ) | $ | 13,028 | |||||||||||
Capital Expenditures | $ | 1,439 | $ | 7 | $ | — | $ | — | $ | — | $ | 1,446 | ||||||||||||
Exploration and Production | Marketing, Gathering and Compression | Former Oilfield Services | Other | Intercompany Eliminations | Consolidated Total | |||||||||||||||||||
($ in millions) | ||||||||||||||||||||||||
Year Ended December 31, 2015 | ||||||||||||||||||||||||
Revenues | $ | 5,391 | $ | 11,745 | $ | — | $ | — | $ | (4,372 | ) | $ | 12,764 | |||||||||||
Intersegment revenues | — | (4,372 | ) | — | — | 4,372 | — | |||||||||||||||||
Total revenues | $ | 5,391 | $ | 7,373 | $ | — | $ | — | $ | — | $ | 12,764 | ||||||||||||
Unrealized losses on commodity derivatives | $ | 693 | $ | — | $ | — | $ | — | $ | — | $ | 693 | ||||||||||||
Unrealized gains on marketing derivatives | $ | — | $ | (295 | ) | $ | — | $ | — | $ | — | $ | (295 | ) | ||||||||||
Oil, natural gas, NGL and other depreciation, depletion and amortization | $ | 2,170 | $ | 20 | $ | — | $ | 39 | $ | — | $ | 2,229 | ||||||||||||
Impairment of oil and natural gas properties | $ | 18,238 | $ | — | $ | — | $ | — | $ | — | $ | 18,238 | ||||||||||||
Impairments of fixed assets and other | $ | 126 | $ | 68 | $ | — | $ | — | $ | — | $ | 194 | ||||||||||||
Net gain (loss) on sales of fixed assets | $ | 1 | $ | 1 | $ | — | $ | 2 | $ | — | $ | 4 | ||||||||||||
Interest expense | $ | (925 | ) | $ | (4 | ) | $ | — | $ | 6 | $ | 606 | $ | (317 | ) | |||||||||
Losses on investments | $ | (3 | ) | $ | — | $ | — | $ | (93 | ) | $ | — | $ | (96 | ) | |||||||||
Impairments of investments | $ | — | $ | — | $ | — | $ | (53 | ) | $ | — | $ | (53 | ) | ||||||||||
Gains on purchases or exchanges of debt | $ | 279 | $ | — | $ | — | $ | — | $ | — | $ | 279 | ||||||||||||
— | ||||||||||||||||||||||||
Income (Loss) Before Income Taxes | $ | (19,619 | ) | $ | 117 | $ | — | $ | (127 | ) | $ | 531 | $ | (19,098 | ) | |||||||||
Total Assets (as previously reported) | $ | 11,776 | $ | 1,524 | $ | — | $ | 4,325 | $ | (311 | ) | $ | 17,314 | |||||||||||
Total Assets (as revised) | $ | 14,610 | $ | 1,524 | $ | — | $ | 1,491 | $ | (311 | ) | $ | 17,314 | |||||||||||
Capital Expenditures | $ | 3,562 | $ | 42 | $ | — | $ | 10 | $ | — | $ | 3,614 | ||||||||||||
Exploration and Production | Marketing, Gathering and Compression | Former Oilfield Services | Other | Intercompany Eliminations | Consolidated Total | |||||||||||||||||||
($ in millions) | ||||||||||||||||||||||||
Year Ended December 31, 2014 | ||||||||||||||||||||||||
Revenues | $ | 10,354 | $ | 20,790 | $ | 1,060 | $ | 30 | $ | (9,109 | ) | $ | 23,125 | |||||||||||
Intersegment revenues | — | (8,565 | ) | (544 | ) | — | 9,109 | — | ||||||||||||||||
Total revenues | $ | 10,354 | $ | 12,225 | $ | 516 | $ | 30 | $ | — | $ | 23,125 | ||||||||||||
Unrealized losses on commodity derivatives | $ | (1,394 | ) | $ | — | $ | — | $ | — | $ | — | $ | (1,394 | ) | ||||||||||
Unrealized gains on marketing derivatives | $ | — | $ | (3 | ) | $ | — | $ | — | $ | — | $ | (3 | ) | ||||||||||
Oil, natural gas, NGL and other depreciation, depletion and amortization | $ | 2,756 | $ | 38 | $ | 145 | $ | 42 | $ | (66 | ) | $ | 2,915 | |||||||||||
Impairments of fixed assets and other | $ | 22 | $ | 24 | $ | 23 | $ | 19 | $ | — | $ | 88 | ||||||||||||
Net gain (loss) on sales of fixed assets | $ | (2 | ) | $ | (187 | ) | $ | (8 | ) | $ | (2 | ) | $ | — | $ | (199 | ) | |||||||
Interest expense | $ | (709 | ) | $ | (21 | ) | $ | (42 | ) | $ | 3 | $ | 680 | $ | (89 | ) | ||||||||
Losses on investments | $ | 2 | $ | — | $ | (1 | ) | $ | (76 | ) | $ | — | $ | (75 | ) | |||||||||
Impairments of investments | $ | — | $ | — | $ | (5 | ) | $ | — | $ | — | $ | (5 | ) | ||||||||||
Net loss on sales of investments | $ | (6 | ) | $ | — | $ | — | $ | 73 | $ | — | $ | 67 | |||||||||||
Gains on purchases or exchanges of debt | $ | (197 | ) | $ | — | $ | — | $ | — | $ | — | $ | (197 | ) | ||||||||||
Income (Loss) Before Income Taxes | $ | 2,874 | $ | 326 | $ | (16 | ) | $ | (30 | ) | $ | 46 | $ | 3,200 | ||||||||||
Total Assets (as previously reported) | $ | 35,285 | $ | 1,978 | $ | — | $ | 4,283 | $ | (891 | ) | $ | 40,655 | |||||||||||
Total Assets (as revised) | $ | 38,012 | $ | 1,978 | $ | — | $ | 1,556 | $ | (891 | ) | $ | 40,655 | |||||||||||
Capital Expenditures | $ | 6,173 | $ | 298 | $ | 158 | $ | 38 | $ | — | $ | 6,667 |
22. | Recently Issued Accounting Standards |
23. | Subsequent Events |
2016 First Quarter | As Previously Reported | Adjustment(b) | As Revised | |||||||||
($ in millions except per share data) | ||||||||||||
Total revenues | $ | 1,953 | $ | — | $ | 1,953 | ||||||
Gross profit(a) | $ | (952 | ) | $ | (147 | ) | $ | (1,099 | ) | |||
Net loss attributable to Chesapeake | $ | (921 | ) | $ | (147 | ) | $ | (1,068 | ) | |||
Net loss available to common stockholders | $ | (964 | ) | $ | (147 | ) | $ | (1,111 | ) | |||
Net loss per common share: | ||||||||||||
Basic | $ | (1.44 | ) | $ | (0.21 | ) | $ | (1.65 | ) | |||
Diluted | $ | (1.44 | ) | $ | (0.21 | ) | $ | (1.65 | ) |
2016 Second Quarter | As Previously Reported | Adjustment(b) | As Revised | |||||||||
($ in millions except per share data) | ||||||||||||
Total revenues | $ | 1,622 | $ | — | $ | 1,622 | ||||||
Gross profit(a) | $ | (1,757 | ) | $ | (26 | ) | $ | (1,783 | ) | |||
Net loss attributable to Chesapeake | $ | (1,750 | ) | $ | (26 | ) | $ | (1,776 | ) | |||
Net loss available to common stockholders | $ | (1,792 | ) | $ | (26 | ) | $ | (1,818 | ) | |||
Net loss per common share: | ||||||||||||
Basic | $ | (2.48 | ) | $ | (0.05 | ) | $ | (2.53 | ) | |||
Diluted | $ | (2.48 | ) | $ | (0.05 | ) | $ | (2.53 | ) |
2016 Third Quarter | As Previously Reported | Adjustment(b) | As Revised | |||||||||
($ in millions except per share data) | ||||||||||||
Total revenues | $ | 2,276 | $ | — | $ | 2,276 | ||||||
Gross profit(a) | $ | (1,174 | ) | $ | (60 | ) | $ | (1,234 | ) | |||
Net loss attributable to Chesapeake | $ | (1,155 | ) | $ | (60 | ) | $ | (1,215 | ) | |||
Net loss available to common stockholders | $ | (1,197 | ) | $ | (60 | ) | $ | (1,257 | ) | |||
Net loss per common share: | ||||||||||||
Basic | $ | (1.54 | ) | $ | (0.08 | ) | $ | (1.62 | ) | |||
Diluted | $ | (1.54 | ) | $ | (0.08 | ) | $ | (1.62 | ) |
2016 Fourth Quarter | ||||
($ in millions) | ||||
Total revenues | $ | 2,021 | ||
Gross profit(a) | $ | (295 | ) | |
Net loss attributable to Chesapeake | $ | (342 | ) | |
Net loss available to common stockholders | $ | (740 | ) | |
Net loss per common share: | ($ per share) | |||
Basic | $ | (0.83 | ) | |
Diluted | $ | (0.83 | ) |
2015 First Quarter | 2015 Second Quarter | 2015 Third Quarter | 2015 Fourth Quarter | |||||||||||||
($ in millions except per share data) | ||||||||||||||||
Total revenues | $ | 3,218 | $ | 3,521 | $ | 3,376 | $ | 2,649 | ||||||||
Gross profit(a) | $ | (5,040 | ) | $ | (5,507 | ) | $ | (5,453 | ) | $ | (2,919 | ) | ||||
Net loss attributable to Chesapeake | $ | (3,739 | ) | $ | (4,108 | ) | $ | (4,653 | ) | $ | (2,185 | ) | ||||
Net loss available to common stockholders | $ | (3,782 | ) | $ | (4,151 | ) | $ | (4,695 | ) | $ | (2,228 | ) | ||||
Net loss per common share: | ||||||||||||||||
Basic | $ | (5.72 | ) | $ | (6.27 | ) | $ | (7.08 | ) | $ | (3.36 | ) | ||||
Diluted | $ | (5.72 | ) | $ | (6.27 | ) | $ | (7.08 | ) | $ | (3.36 | ) |
(a) | Total revenue less operating expenses. Includes $2.564 billion and $18.238 billion in ceiling test write-downs on our oil and natural gas properties for the years ended December 31, 2016 and 2015, respectively. |
(b) | During our review of the full cost ceiling test calculation for 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. We determined that these errors do not relate to periods prior to January 1, 2016. |
The impact of the errors was an understatement in the impairment of oil and natural gas properties of $144 million for the quarter ended March 31, 2016, $24 million for the quarter ended June 30, 2016 and $64 million for the quarter ended September 30, 2016. The impact of the error was also an overstatement in the oil, natural gas and NGL depreciation, depletion and amortization of $8 million for the quarter ended March 31, 2016, an understatement of $13 million for the quarter ended June 30, 2016 and an overstatement of $4 million for the quarter ended September 30, 2016. In accordance with Staff Accounting Bulletin No. 99, Materiality, management evaluated the materiality of the errors from qualitative and quantitative perspectives and concluded that the errors are not material to our previously issued interim financial statements. Accordingly, the corrections for these errors and an other immaterial previously identified error is reflected in the table above. The corrections associated with these errors will also be reflected in our 2017 Form 10-Q filings. |
December 31, | ||||||||
2016 | 2015 | |||||||
($ in millions) | ||||||||
Oil and oil and natural gas properties: | ||||||||
Proved | $ | 66,451 | $ | 63,843 | ||||
Unproved | 4,802 | 6,798 | ||||||
Total | 71,253 | 70,641 | ||||||
Less accumulated depreciation, depletion and amortization | (62,094 | ) | (58,552 | ) | ||||
Net capitalized costs | $ | 9,159 | $ | 12,089 |
Years Ended December 31, | ||||||||||||
2016 | 2015 | 2014 | ||||||||||
($ in millions) | ||||||||||||
Acquisition of Properties: | ||||||||||||
Proved properties | $ | 403 | $ | — | $ | 214 | ||||||
Unproved properties | 403 | 454 | 1,224 | |||||||||
Exploratory costs | 52 | 112 | 421 | |||||||||
Development costs | 1,312 | 2,941 | 4,204 | |||||||||
Costs incurred(a)(b) | $ | 2,170 | $ | 3,507 | $ | 6,063 |
(a) | Exploratory and development costs are net of $51 million and $679 million in drilling and completion carries received from our joint venture partners during 2015 and 2014, respectively. |
(b) | Includes capitalized interest and asset retirement obligations as follows: |
Capitalized interest | $ | 242 | $ | 410 | $ | 604 | ||||||
Asset retirement obligations | $ | (57 | ) | $ | (15 | ) | $ | 39 |
Years Ended December 31, | ||||||||||||
2016 | 2015 | 2014 | ||||||||||
($ in millions) | ||||||||||||
Oil, natural gas and NGL sales | $ | 3,288 | $ | 5,391 | $ | 10,354 | ||||||
Oil, natural gas and NGL production expenses | (710 | ) | (1,046 | ) | (1,208 | ) | ||||||
Oil, natural gas and NGL gathering, processing and transportation expenses | (1,855 | ) | (2,119 | ) | (2,174 | ) | ||||||
Production taxes | (74 | ) | (99 | ) | (232 | ) | ||||||
Impairment of oil and natural gas properties | (2,564 | ) | (18,238 | ) | — | |||||||
Depletion and depreciation | (1,003 | ) | (2,099 | ) | (2,683 | ) | ||||||
Imputed income tax provision(a) | 1,027 | 6,683 | (1,485 | ) | ||||||||
Results of operations from oil, natural gas and NGL producing activities | $ | (1,891 | ) | $ | (11,527 | ) | $ | 2,572 |
(a) | The imputed income tax provision is hypothetical (at the statutory tax rate) and determined without regard to our deduction for general and administrative expenses, interest costs and other income tax credits and deductions, nor whether the hypothetical tax provision (benefit) will be payable (receivable). |
December 31, | ||||||||
2016 | 2015 | 2014 | ||||||
Ryder Scott Company, L.P. | —% | 36 | % | 54 | % | |||
Software Integrated Solutions, Division of Schlumberger Technology Corporation | 70% | 23 | % | 25 | % |
Oil | Gas | NGL | Total | |||||||||
(mmbbl) | (bcf) | (mmbbl) | (mmboe) | |||||||||
December 31, 2016 | ||||||||||||
Proved reserves, beginning of period | 313.7 | 6,041 | 183.5 | 1,504 | ||||||||
Extensions, discoveries and other additions | 191.2 | 1,798 | 89.0 | 580 | ||||||||
Revisions of previous estimates | (58.9 | ) | 598 | 2.8 | 43 | |||||||
Production | (33.2 | ) | (1,050 | ) | (24.4 | ) | (233 | ) | ||||
Sale of reserves-in-place | (14.7 | ) | (1,190 | ) | (28.1 | ) | (241 | ) | ||||
Purchase of reserves-in-place | 1.0 | 299 | 3.6 | 55 | ||||||||
Proved reserves, end of period(a) | 399.1 | 6,496 | 226.4 | 1,708 | ||||||||
Proved developed reserves: | ||||||||||||
Beginning of period | 215.6 | 5,329 | 158.0 | 1,262 | ||||||||
End of period | 200.4 | 5,126 | 134.1 | 1,189 | ||||||||
Proved undeveloped reserves: | ||||||||||||
Beginning of period | 98.1 | 712 | 25.5 | 242 | ||||||||
End of period(b) | 198.7 | 1,370 | 92.2 | 519 | ||||||||
Oil | Gas | NGL | Total | |||||||||
(mmbbl) | (bcf) | (mmbbl) | (mmboe) | |||||||||
December 31, 2015 | ||||||||||||
Proved reserves, beginning of period | 420.8 | 10,692 | 266.3 | 2,469 | ||||||||
Extensions, discoveries and other additions | 61.1 | 805 | 35.3 | 231 | ||||||||
Revisions of previous estimates | (110.0 | ) | (4,191 | ) | (75.8 | ) | (885 | ) | ||||
Production | (41.6 | ) | (1,070 | ) | (28.0 | ) | (248 | ) | ||||
Sale of reserves-in-place | (16.6 | ) | (195 | ) | (14.3 | ) | (63 | ) | ||||
Purchase of reserves-in-place | — | — | — | — | ||||||||
Proved reserves, end of period(c) | 313.7 | 6,041 | 183.5 | 1,504 | ||||||||
Proved developed reserves: | ||||||||||||
Beginning of period | 229.3 | 8,615 | 198.5 | 1,864 | ||||||||
End of period | 215.6 | 5,329 | 158.0 | 1,262 | ||||||||
Proved undeveloped reserves: | ||||||||||||
Beginning of period | 191.5 | 2,077 | 67.8 | 605 | ||||||||
End of period(b) | 98.1 | 712 | 25.5 | 242 | ||||||||
December 31, 2014 | ||||||||||||
Proved reserves, beginning of period | 423.8 | 11,734 | 299.0 | 2,678 | ||||||||
Extensions, discoveries and other additions | 108.6 | 1,567 | 78.2 | 448 | ||||||||
Revisions of previous estimates | (51.1 | ) | (129 | ) | 21.3 | (51 | ) | |||||
Production | (42.3 | ) | (1,095 | ) | (33.1 | ) | (258 | ) | ||||
Sale of reserves-in-place | (23.3 | ) | (1,421 | ) | (101.7 | ) | (362 | ) | ||||
Purchase of reserves-in-place | 5.1 | 36 | 2.6 | 14 | ||||||||
Proved reserves, end of period(d) | 420.8 | 10,692 | 266.3 | 2,469 | ||||||||
Proved developed reserves: | ||||||||||||
Beginning of period | 201.3 | 8,584 | 177.1 | 1,809 | ||||||||
End of period | 229.3 | 8,615 | 198.5 | 1,864 | ||||||||
Proved undeveloped reserves: | ||||||||||||
Beginning of period | 222.5 | 3,150 | 121.9 | 869 | ||||||||
End of period(b) | 191.5 | 2,077 | 67.8 | 605 |
(a) | Includes 1 mmbbl of oil, 23 bcf of natural gas and 2 mmbbls of NGL reserves owned by the Chesapeake Granite Wash Trust, 1 mmbbl of oil, 12 bcf of natural gas and 1 mmbbl of NGL of which are attributable to the noncontrolling interest holders. |
(b) | As of December 31, 2016, 2015 and 2014, there were no PUDs that had remained undeveloped for five years or more. |
(c) | Includes 1 mmbbl of oil, 32 bcf of natural gas and 3 mmbbls of NGL reserves owned by the Chesapeake Granite Wash Trust, 1 mmbbl of oil, 16 bcf of natural gas and 2 mmbbls of NGL of which are attributable to the noncontrolling interest holders. |
(d) | Includes 2 mmbbls of oil, 46 bcf of natural gas and 5 mmbbls of NGL reserves owned by the Chesapeake Granite Wash Trust, 1 mmbbl of oil, 22 bcf of natural gas and 2 mmbbls of NGL of which are attributable to the noncontrolling interest holders. |
Years Ended December 31, | |||||||||||||
2016 | 2015 | 2014 | |||||||||||
($ in millions) | |||||||||||||
Future cash inflows | $ | 19,835 | (a) | $ | 20,247 | (b) | $ | 72,557 | (c) | ||||
Future production costs | (6,800 | ) | (7,391 | ) | (17,036 | ) | |||||||
Future development costs | (3,621 | ) | (1,518 | ) | (7,556 | ) | |||||||
Future income tax provisions | (79 | ) | (228 | ) | (12,494 | ) | |||||||
Future net cash flows | 9,335 | 11,110 | 35,471 | ||||||||||
Less effect of a 10% discount factor | (4,956 | ) | (6,417 | ) | (18,338 | ) | |||||||
Standardized measure of discounted future net cash flows(d) | $ | 4,379 | $ | 4,693 | $ | 17,133 |
(a) | Calculated using prices of $42.75 per bbl of oil and $2.49 per mcf of natural gas, before field differentials. |
(b) | Calculated using prices of $50.28 per bbl of oil and $2.58 per mcf of natural gas, before field differentials. |
(c) | Calculated using prices of $94.98 per bbl of oil and $4.35 per mcf of natural gas, before field differentials. |
(d) | Excludes future cash inflows attributable to production volumes sold to VPP buyers and includes future cash outflows attributable to the costs of production. See Note 12. |
Years Ended December 31, | ||||||||||||
2016 | 2015 | 2014 | ||||||||||
($ in millions) | ||||||||||||
Standardized measure, beginning of period(a) | $ | 4,693 | $ | 17,133 | $ | 17,390 | ||||||
Sales of oil and natural gas produced, net of production costs and gathering, processing and transportation(b) | (1,227 | ) | (1,503 | ) | (5,722 | ) | ||||||
Net changes in prices and production costs | (1,210 | ) | (18,070 | ) | (634 | ) | ||||||
Extensions and discoveries, net of production and development costs | 1,042 | 1,005 | 5,156 | |||||||||
Changes in estimated future development costs | 323 | 3,198 | 1,946 | |||||||||
Previously estimated development costs incurred during the period | 664 | 873 | 1,178 | |||||||||
Revisions of previous quantity estimates | 145 | (3,472 | ) | (715 | ) | |||||||
Purchase of reserves-in-place | 394 | 1 | 215 | |||||||||
Sales of reserves-in-place | 13 | (938 | ) | (1,788 | ) | |||||||
Accretion of discount | 473 | 2,201 | 2,168 | |||||||||
Net change in income taxes | (8 | ) | 4,845 | (593 | ) | |||||||
Changes in production rates and other | (923 | ) | (580 | ) | (1,468 | ) | ||||||
Standardized measure, end of period(a)(c)(d) | $ | 4,379 | $ | 4,693 | $ | 17,133 |
(a) | The impact of cash flow hedges has not been included in any of the periods presented. |
(b) | Excluding gains (losses) on derivatives. |
(c) | Effect of noncontrolling interest of the Chesapeake Granite Wash Trust is immaterial. |
(d) | The standardized measure of discounted future net cash flows does not include estimated future cash inflows attributable to future production of VPP volumes sold and does include estimated future cash outflows attributable to the costs of future production of VPP volumes sold. |
ITEM 9. | Changes In and Disagreements with Accountants on Accounting and Financial Disclosure |
ITEM 9A. | Controls and Procedures |
ITEM 9B. | Other Information |
ITEM 10. | Directors, Executive Officers and Corporate Governance |
ITEM 11. | Executive Compensation |
ITEM 12. | Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters |
ITEM 13. | Certain Relationships and Related Transactions and Director Independence |
ITEM 14. | Principal Accountant Fees and Services |
ITEM 15. | Exhibits and Financial Statement Schedules |
(a) | The following financial statements, financial statement schedules and exhibits are filed as a part of this report: |
1. | Financial Statements. Chesapeake's consolidated financial statements are included in Item 8 of Part II of this report. Reference is made to the accompanying Index to Financial Statements. |
2. | Financial Statement Schedules. No financial statement schedules are applicable or required. |
3. | 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. |
CHESAPEAKE ENERGY CORPORATION | |||
Date: March 3, 2017 | By: | /s/ ROBERT D. LAWLER | |
Robert D. Lawler | |||
President and Chief Executive Officer |
Signature | Capacity | Date | ||
/s/ ROBERT D. LAWLER | President and Chief Executive Officer (Principal Executive Officer) | March 3, 2017 | ||
Robert D. Lawler | ||||
/s/ DOMENIC J. DELL'OSSO, JR. | Executive Vice President and Chief Financial Officer (Principal Financial Officer) | March 3, 2017 | ||
Domenic J. Dell'Osso, Jr. | ||||
/s/ MICHAEL A. JOHNSON | Senior Vice President – Accounting, Controller and Chief Accounting Officer (Principal Accounting Officer) | March 3, 2017 | ||
Michael A. Johnson | ||||
/s/ R. BRAD MARTIN | Chairman of the Board | March 3, 2017 | ||
R. Brad Martin | ||||
/s/ ARCHIE W. DUNHAM | Director and Chairman Emeritus | March 3, 2017 | ||
Archie W. Dunham | ||||
/s/ GLORIA R. BOYLAND | Director | March 3, 2017 | ||
Gloria R. Boyland | ||||
/s/ LUKE R. CORBETT | Director | March 3, 2017 | ||
Luke R. Corbett | ||||
/s/ MERRILL A. MILLER, JR. | Director | March 3, 2017 | ||
Merrill A. Miller, Jr. | ||||
/s/ THOMAS L. RYAN | Director | March 3, 2017 | ||
Thomas L. Ryan |
Incorporated by Reference | ||||||||||||
Exhibit Number | Exhibit Description | Form | SEC File Number | Exhibit | Filing Date | Filed or Furnished Herewith | ||||||
2.1.1* | Purchase and Sale Agreement by and between Chesapeake Appalachia, L.L.C. and Southwestern Energy Production Company dated October 14, 2014. | 10-K | 001-13726 | 2.1.1 | 2/27/2015 | |||||||
2.1.2* | Amendment to Purchase and Sale Agreement by and between Chesapeake Appalachia, L.L.C. and SWN Production Company, LLC (formerly Southwestern Energy Production Company) dated December 22, 2014. | 10-K | 001-13726 | 2.1.2 | 2/27/2015 | |||||||
2.1.3 | Settlement Agreement by and between Chesapeake Appalachia, L.L.C. and SWN Production Company, LLC (formerly Southwestern Energy Production Company) dated December 22, 2014. | 10-K | 001-13726 | 2.1.3 | 2/27/2015 | |||||||
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 | 3.1.2 | 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 | |||||||
4.1** | Indenture dated as of November 8, 2005 among Chesapeake, as issuer, the subsidiaries signatory thereto, as Subsidiary Guarantors and The Bank of New York Mellon Trust Company, N.A., as Trustee, with respect to 6.875% Senior Notes due 2020. | 8-K | 001-13726 | 4.12.1 | 11/15/2005 | |||||||
4.2** | Indenture dated as of December 6, 2006 among Chesapeake, as issuer, the subsidiaries signatory thereto, as Subsidiary Guarantors, The Bank of New York Mellon Trust Company, N.A., as Trustee, AIB/BNY Fund Management (Ireland) Limited, as Irish Paying Agent and Transfer Agent, and The Bank of New York, London Branch, as Registrar, Transfer Agent and Paying Agent, with respect to 6.25% Senior Notes due 2017. | 8-K | 001-13726 | 4.1 | 12/6/2006 | |||||||
4.3** | Indenture dated as of May 15, 2007 among Chesapeake, as issuer, the subsidiaries signatory thereto, as Subsidiary Guarantors and The Bank of New York Mellon Trust Company, N.A., as Trustee, with respect to 2.5% Contingent Convertible Senior Notes due 2037. | 8-K | 001-13726 | 4.1 | 5/15/2007 | |||||||
4.4** | Indenture dated as of May 27, 2008 among Chesapeake, as issuer, the subsidiaries signatory thereto, as Subsidiary Guarantors and The Bank of New York Mellon Trust Company, N.A., as Trustee, with respect to 7.25% Senior Notes due 2018. | 8-K | 001-13726 | 4.1 | 5/29/2008 | |||||||
4.5** | Indenture dated as of May 27, 2008 among Chesapeake, as issuer, the subsidiaries signatory thereto, as Subsidiary Guarantors and The Bank of New York Mellon Trust Company, N.A., as Trustee, with respect to 2.25% Contingent Convertible Senior Notes due 2038. | 8-K | 001-13726 | 4.2 | 5/29/2008 | |||||||
4.6.1** | Indenture dated as of August 2, 2010 among Chesapeake, as issuer, the subsidiaries signatory thereto, as Subsidiary Guarantors, and the Bank of New York Mellon Trust Company, N.A., as Trustee. | S-3 | 333-168509 | 4.1 | 8/3/2010 | |||||||
4.6.2 | First Supplemental Indenture dated as of August 17, 2010 to Indenture dated as of August 2, 2010 with respect to 6.875% Senior Notes due 2018. | 8-A | 001-13726 | 4.2 | 9/24/2010 | |||||||
4.6.3 | Second Supplemental Indenture, dated as of August 17, 2010 to Indenture dated as of August 2, 2010 with respect to 6.625% Senior Notes due 2020. | 8-A | 001-13726 | 4.3 | 9/24/2010 | |||||||
4.6.4 | Fifth Supplemental Indenture dated February 11, 2011 to Indenture dated as of August 2, 2010 with respect to 6.125% Senior Notes due 2021. | 8-A | 001-13726 | 4.2 | 2/22/2011 | |||||||
4.6.5 | Fourteenth Supplemental Indenture dated March 18, 2013 among Chesapeake, as issuer, the subsidiaries signatory thereto, as Subsidiary Guarantors, and Deutsche Bank Trust Company Americas, as Trustee, to Indenture dated as of August 2, 2010. | S-3 | 333-168509 | 4.17 | 3/18/2013 | |||||||
4.6.6 | Sixteenth Supplemental Indenture dated April 1, 2013 to Indenture dated as of August 2, 2010 with respect to 5.375% Senior Notes due 2021. | 8-A | 001-13726 | 4.3 | 4/8/2013 | |||||||
4.6.7 | Seventeenth Supplemental Indenture dated April 1, 2013 to Indenture dated as of August 2, 2010 with respect to 5.75% Senior Notes due 2023. | 8-A | 001-13726 | 4.4 | 4/8/2013 | |||||||
4.7.1** | Indenture dated as of April 24, 2014 by and among Chesapeake, as Issuer, the subsidiaries signatory thereto, as Subsidiary Guarantors, and Deutsche Bank Trust Company Americas, as Trustee. | 8-K | 001-13726 | 4.1 | 4/29/2014 | |||||||
4.7.2 | First Supplemental Indenture dated as of April 24, 2014 to Indenture dated as of April 24, 2014 with respect to Floating Rate Senior Notes due 2019. | 8-K | 001-13726 | 4.2 | 4/29/2014 | |||||||
4.7.3 | Second Supplemental Indenture dated as of April 24, 2014 to Indenture dated as of April 24 2014 with respect to 4.875% Senior Notes due 2022. | 8-K | 001-13726 | 4.3 | 4/29/2014 | |||||||
4.8 | Indenture dated as of December 23, 2015 among Chesapeake, as Issuer, the subsidiaries signatory thereto, as Subsidiary Guarantors, and Deutsche Bank Trust Company Americas, as Trustee and Collateral Trustee with respect to 8.00% Senior Secured Second Lien Notes due 2022. | 8-K | 001-13726 | 4.1 | 12/23/2015 | |||||||
4.9.1 | Credit Agreement dated December 15, 2014 by and among: Chesapeake Energy Corporation, as borrower; MUFG Union Bank N.A., as administrative agent, co-syndication agent, a swingline lender and a letter of credit issuer; Wells Fargo Bank and National Association, as co-syndication agent, a swingline lender and a letter of credit issuer; Bank of America, N.A., Crédit Agricole Corporate and Investment Bank and JPMorgan Chase Bank, N.A., as co-documentation agents and letter of credit issuers; and certain other lenders named therein. | 10-Q | 001-13726 | 4.1 | 8/14/2016 | |||||||
4.9.2 | First Amendment to Credit Agreement dated September 30, 2015 among Chesapeake, as borrower, MUFG Union Bank N.A., as administrative agent, co-syndication agent, a swingline lender and a letter of credit issuer; Wells Fargo Bank, National Association, as co-syndication agent, a swingline lender and a letter of credit issuer; and certain other lenders named therein. | 10-Q | 001-13726 | 4.1 | 11/4/2015 | |||||||
4.9.3 | Second Amendment to Credit Agreement dated December 15, 2015 among Chesapeake, as borrower, MUFG Union Bank N.A., as administrative agent, co-syndication agent, a swingline lender and a letter of credit issuer; Wells Fargo Bank, National Association, as co-syndication agent, a swingline lender and a letter of credit issuer; and certain other lenders named therein. | 8-K | 001-13726 | 10.1 | 12/16/2015 | |||||||
4.9.4†† | Third Amendment to Credit Agreement dated April 8, 2016 among Chesapeake Energy Corporation, as borrower; MUFG Union Bank N.A., as administrative agent, a swingline lender and a letter of credit issuer; and certain other lenders named therein. | 10-Q | 001-13726 | 4.2 | 8/4/2016 | |||||||
4.10 | Intercreditor Agreement dated as of December 23, 2015 between MUFG Bank, N.A., as Priority Lien Agent, and Deutsche Bank Trust Company Americas, as Second Lien Collateral Trustee, and acknowledged by Chesapeake and certain of its subsidiaries. | 8-K | 001-13726 | 10.1 | 12/23/2015 | |||||||
4.11 | Collateral Trust Agreement, dated as of December 23, 2015, by and among Chesapeake, the guarantors named therein, and Deutsche Bank Trust Company Americas as the representative of the holders of the Second Lien Notes and as collateral trustee. | 8-K | 001-13726 | 10.2 | 12/23/2015 | |||||||
4.12 | Term Loan Agreement dated August 23, 2016 among Chesapeake Energy Corporation, the lenders party thereto and Deutsche Bank Trust Company Americas, as term agent. | 8-K | 001-13726 | 4.1 | 8/24/2016 | |||||||
4.13 | Class A Term Loan Supplement dated August 23, 2016 among Chesapeake Energy Corporation, the lenders party thereto and Deutsche Bank Trust Company Americas, as term agent. | 8-K | 001-13726 | 4.2 | 8/24/2016 | |||||||
4.14 | Indenture dated as of October 5, 2016, among Chesapeake Energy Corporation, the subsidiary guarantors named therein and Deutsche Bank Trust Company Americas, as trustee, with respect to the 5.5% Convertible Senior Notes due 2026. | 8-K | 001-13726 | 10.1 | 8/24/2016 | |||||||
4.15 | Collateral Trust Agreement, dated as of August 23, 2016 by and among MUFG Union Bank, N.A., as collateral trustee and revolver agent, and Deutsche Bank Trust Company Americas, as term loan agent, and acknowledged and agreed by Chesapeake Energy Corporation and certain of its subsidiaries. | 8-K | 001-13726 | 4.1 | 10/5/2016 | |||||||
4.16 | Sixth Supplemental indenture dated as of December 20, 2016 to indenture dated as of April 24, 2014 with respect to 8.00% Senior Notes due 2025. | 8-K | 001-13726 | 4.2 | 12/20/2016 | |||||||
4.17 | Registration Rights Agreement dated as of December 20, 2016, among Chesapeake Energy Corporation, the subsidiary guarantors named therein and Deutsche Bank Securities, Inc. | 8-K | 001-13726 | 4.4 | 12/20/2016 | |||||||
10.1.1† | Chesapeake's 2003 Stock Incentive Plan, as amended. | 10-Q | 001-13726 | 10.1.1 | 11/9/2009 | |||||||
10.1.2† | Form of 2013 Restricted Stock Award Agreement for Chesapeake's 2003 Stock Incentive Plan. | 10-K | 001-13726 | 10.1.3 | 3/1/2013 | |||||||
10.2.1† | Chesapeake's 2005 Amended and Restated Long Term Incentive Plan. | 8-K | 001-13726 | 10.1 | 6/20/2013 | |||||||
10.2.2† | Form of 2013 Restricted Stock Award Agreement for 2005 Amended and Restated Long Term Incentive Plan. | 8-K | 001-13726 | 10.3 | 2/4/2013 | |||||||
10.2.3† | Form of Nonqualified Stock Option Agreement for 2005 Amended and Restated Long Term Incentive Plan. | 8-K | 001-13726 | 10.1 | 2/4/2013 | |||||||
10.2.4† | Form of Retention Nonqualified Stock Option Agreement for 2005 Amended and Restated Long Term Incentive Plan. | 8-K | 001-13726 | 10.2 | 2/4/2013 | |||||||
10.2.5† | Form of 2013 Non-Employee Director Restricted Stock Award Agreement for 2005 Amended and Restated Long Term Incentive Plan. | 10-K | 001-13726 | 10.13.7 | 3/1/2013 | |||||||
10.2.6† | Form of 2013 Performance Share Unit Award Agreement for 2005 Amended and Restated Long Term Incentive Plan. | 10-K | 001-13726 | 10.13.9 | 3/1/2013 | |||||||
10.2.7† | Form of 2014 Performance Share Unit Award Agreement for 2005 Amended and Restated Long Term Incentive Plan. | 10-K | 001-13726 | 10.4.7 | 2/27/2014 | |||||||
10.2.8† | Form of Restricted Stock Unit Award Agreement for 2005 Amended and Restated Long Term Incentive Plan. | 10-Q | 001-13726 | 10.8 | 8/6/2013 | |||||||
10.2.9† | Form of Non-Employee Director Restricted Stock Unit Award Agreement for 2005 Amended and Restated Long Term Incentive Plan. | 10-Q | 001-13726 | 10.9 | 8/6/2013 | |||||||
10.2.10† | Form of Pension and Equity Makeup Restricted Stock Award Agreement for 2005 Amended and Restated Long Term Incentive Plan for Robert D. Lawler. | 10-Q | 001-13726 | 10.10 | 8/6/2013 | |||||||
10.3.1† | Chesapeake Energy Corporation Deferred Amended and Restated Deferred Compensation Plan, effective January 1, 2016. | 10-K | 001-13726 | 10.3 | 2/25/2016 | |||||||
Amendment to the Chesapeake Energy Corporation Deferred Compensation Plan for Non-Employee Directors, effective January 1, 2017. | X | |||||||||||
10.4† | Chesapeake Energy Corporation Deferred Compensation Plan for Non-Employee Directors. | 10-K | 001-13726 | 10.16 | 3/1/2013 | |||||||
10.5† | Employment Agreement dated as of May 20, 2013 between Robert D. Lawler and Chesapeake Energy Corporation. | 8-K | 001-13726 | 10.1 | 5/23/2013 | |||||||
10.6† | Employment Agreement dated as of January 1, 2016 between Domenic J. Dell'Osso, Jr. and Chesapeake Energy Corporation. | 8-K | 001-13726 | 10.1 | 1/6/2016 | |||||||
10.7† | Employment Agreement dated as of January 1, 2016 between James R. Webb and Chesapeake Energy Corporation. | 8-K | 001-13726 | 10.2 | 1/6/2016 | |||||||
10.8† | Employment Agreement dated as of January 1, 2016 between M. Christopher Doyle and Chesapeake Energy Corporation. | 8-K | 001-13726 | 10.3 | 1/6/2016 | |||||||
10.9† | Employment Agreement dated as of January 1, 2016 between Mikell Jason Pigott and Chesapeake Energy Corporation. | 8-K | 001-13726 | 10.4 | 1/6/2016 | |||||||
10.10† | Employment Agreement dated as of May 21, 2015 between Frank Patterson and Chesapeake Energy Corporation. | 10-Q | 001-13726 | 10.1 | 8/5/2015 | |||||||
10.11† | Form of Employment Agreement dated as of January 1, 2016 between Executive Vice President/Senior Vice President and Chesapeake Energy Corporation. | 8-K | 001-13726 | 10.5 | 1/6/2016 | |||||||
10.12† | Form of Indemnity Agreement for officers and directors of Chesapeake Energy Corporation and its subsidiaries. | 8-K | 001-13726 | 10.3 | 6/27/2012 | |||||||
10.13† | Chesapeake Energy Corporation 2013 Annual Incentive Plan. | DEF 14A | 001-13726 | Exhibit G | 5/3/2013 | |||||||
10.13.1† | Chesapeake Energy Corporation 2014 Long Term Incentive Plan. | DEF 14A | 001-13726 | Exhibit F | 4/30/2014 | |||||||
10.13.2† | Form of Restricted Stock Unit Award Agreement for 2014 Long Term Incentive Plan. | 10-Q | 001-13726 | 10.2 | 8/6/2014 | |||||||
10.13.3† | Form of Restricted Stock Award Agreement for 2014 Long Term Incentive Plan. | 10-Q | 001-13726 | 10.3 | 8/6/2014 | |||||||
10.13.4† | Form of Nonqualified Stock Option Agreement for 2014 Long Term Incentive Plan. | 10-Q | 001-13726 | 10.4 | 8/6/2014 | |||||||
10.13.5† | Form of Performance Share Unit Award Agreement for 2014 Long Term Incentive Plan. | 10-Q | 001-13726 | 10.5 | 8/6/2014 | |||||||
10.13.6† | Form of Director Restricted Stock Unit Award Agreement for 2014 Long Term Incentive Plan. | 10-Q | 001-13726 | 10.6 | 8/6/2014 | |||||||
Ratios of Earnings to Fixed Charges and Combined Fixed Charges and Preferred Dividends. | X | |||||||||||
Subsidiaries of Chesapeake Energy Corporation. | X | |||||||||||
Consent of PricewaterhouseCoopers LLP. | X | |||||||||||
Consent of Software Integrated Solutions, Division of Schlumberger Technology Corporation. | X | |||||||||||
Robert D. Lawler, President and Chief Executive Officer, Certification pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. | X | |||||||||||
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 | |||||||||||
Robert D. Lawler, President and Chief Executive Officer, Certification pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. | X | |||||||||||
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 | |||||||||||
Report of Software Integrated Solutions, Division of Schlumberger Technology Corporation. | 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 | ||||||||||
* | The Company agrees to furnish supplementally a copy of omitted exhibits and schedules to the Securities and Exchange Commission upon request. |
** | The Company agrees to furnish a copy of any of its unfiled long-term debt instruments to the Securities and Exchange Commission upon request. | |||||||||||
† | Management contract or compensatory plan or arrangement. | |||||||||||
†† | Confidential treatment has been requested for portions of this exhibit. These portions have been omitted and submitted separately to the Securities and Exchange Commission. | |||||||||||
PLEASE NOTE: Pursuant to the rules and regulations of the Securities and Exchange Commission, we have filed or incorporated by reference the agreements referenced above as exhibits to this Annual Report on Form 10-K. The agreements have been filed to provide investors with information regarding their respective terms. The agreements are not intended to provide any other factual information about Chesapeake Energy Corporation or its business or operations. In particular, the assertions embodied in any representations, warranties and covenants contained in the agreements may be subject to qualifications with respect to knowledge and materiality different from those applicable to investors and may be qualified by information in confidential disclosure schedules not included with the exhibits. These disclosure schedules may contain information that modifies, qualifies and creates exceptions to the representations, warranties and covenants set forth in the agreements. Moreover, certain representations, warranties and covenants in the agreements may have been used for the purpose of allocating risk between the parties, rather than establishing matters as facts. In addition, information concerning the subject matter of the representations, warranties and covenants may have changed after the date of the respective agreement, which subsequent information may or may not be fully reflected in our public disclosures. Accordingly, investors should not rely on the representations, warranties and covenants in the agreements as characterizations of the actual state of facts about Chesapeake Energy Corporation or its business or operations on the date hereof. |
“‘Eligible Compensation’ means the annual cash retainer and equity grants provided by the Company as compensation for services as a Non-Employee Director. In the event the Company pays Non‑Employee Directors cash or equity compensation for committee fees or meeting fees, Eligible Compensation shall also include these forms of compensation.” |
By: | /s/ James L. Hawkins | Date: | December 12, 2016 | |
James L. Hawkins | ||||
Its: | Vice President – Human Resources |
EXHIBIT 12 |
Years Ended December 31, | ||||||||||||||||||||
2012 | 2013 | 2014 | 2015 | 2016 | ||||||||||||||||
EARNINGS: | ||||||||||||||||||||
Income (loss) before income taxes and cumulative effect of accounting change | $ | (974 | ) | $ | 1,442 | $ | 3,200 | $ | (19,098 | ) | $ | (4,589 | ) | |||||||
Interest expense(a) | 142 | 207 | 172 | 322 | 275 | |||||||||||||||
(Gain)/loss on investment in equity investees in excess of distributed earnings | 108 | 219 | 75 | 96 | 8 | |||||||||||||||
Amortization of capitalized interest | 402 | 440 | 438 | 483 | 729 | |||||||||||||||
Loan cost amortization | 43 | 37 | 32 | 31 | 24 | |||||||||||||||
Earnings | $ | (279 | ) | $ | 2,345 | $ | 3,917 | $ | (18,166 | ) | $ | (3,553 | ) | |||||||
FIXED CHARGES: | ||||||||||||||||||||
Interest Expense | $ | 142 | $ | 207 | $ | 172 | $ | 322 | $ | 275 | ||||||||||
Capitalized interest | 976 | 815 | 604 | 410 | 242 | |||||||||||||||
Loan cost amortization | 43 | 37 | 32 | 31 | 24 | |||||||||||||||
Fixed Charges | $ | 1,161 | $ | 1,059 | $ | 808 | $ | 763 | $ | 541 | ||||||||||
PREFERRED STOCK DIVIDENDS: | ||||||||||||||||||||
Preferred dividend requirements | $ | 171 | $ | 171 | $ | 171 | $ | 171 | $ | 97 | ||||||||||
Ratio of income (loss) before provision for taxes to net income (loss)(b) | 1.64 | 1.61 | 1.56 | 1.30 | 1.04 | |||||||||||||||
Preferred Dividends | $ | 280 | $ | 275 | $ | 266 | $ | 222 | $ | 101 | ||||||||||
COMBINED FIXED CHARGES AND PREFERRED DIVIDENDS | $ | 1,441 | $ | 1,334 | $ | 1,074 | $ | 985 | $ | 642 | ||||||||||
RATIO OF EARNINGS TO FIXED CHARGES | (0.2 | ) | 2.2 | 4.8 | (23.8 | ) | (6.6 | ) | ||||||||||||
INSUFFICIENT COVERAGE | $ | 1,440 | $ | — | $ | — | $ | 18,929 | $ | 4,094 | ||||||||||
RATIO OF EARNINGS TO COMBINED FIXED CHARGES AND PREFERRED DIVIDENDS | (0.2 | ) | 1.8 | 3.6 | (18.4 | ) | (5.5 | ) | ||||||||||||
INSUFFICIENT COVERAGE | $ | 1,720 | $ | — | $ | — | $ | 19,151 | $ | 4,195 |
(a) | Excludes the effect of unrealized gains or losses on interest rate derivatives and includes amortization of bond discount. |
(b) | Amounts of income (loss) before provision for taxes and of net income (loss) exclude the cumulative effect of accounting change. |
Exhibit 21 |
Corporations | State of Organization | |
Chesapeake Energy Louisiana Corporation | Oklahoma | |
Limited Liability Companies | State of Organization | |
Chesapeake Appalachia, L.L.C. | Oklahoma | |
Chesapeake E&P Holding, L.L.C. | Oklahoma | |
Chesapeake Exploration, L.L.C. | Oklahoma | |
Chesapeake Land Development Company, L.L.C. | Oklahoma | |
Chesapeake Operating, L.L.C. | Oklahoma | |
Partnerships | State of Organization | |
Chesapeake Louisiana, L.P. | Oklahoma | |
* In accordance with Regulation S-K Item 601(b)(21), the names of particular subsidiaries that, considered in the aggregate as a single subsidiary, would not constitute a significant subsidiary (as that term is defined in Rule 1-02(w) of Regulation S-X) as of the end of the year covered by this report have been omitted. |
Exhibit 23.1 |
CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM | ||||
We hereby consent to the incorporation by reference in the Registration Statements on Form S-8 (File Nos. 333-109162, 333-126191, 333-135949, 333-143990, 333-151762, 333-160350, 333-171468, 333-178067, 333-187018, 333-189651, 333-192175 and 333-196977) of Chesapeake Energy Corporation of our report dated March 3, 2017 relating to the financial statements and the effectiveness of internal control over financial reporting, which appears in this Form 10-K. | ||||
/s/ PricewaterhouseCoopers LLP | ||||
Oklahoma City, Oklahoma | ||||
March 3, 2017 |
Software Integrated Solutions | |||||
Division of Schlumberger Technology Corporation | |||||
4600 J Barry Court | |||||
Suite 200 | |||||
Canonsburg, PA 15317 USA | |||||
Tel: 724-416-9700 | |||||
Fax: 724-416-9705 | |||||
Exhibit 23.2 | |||||
CONSENT OF SOFTWARE INTEGRATED SOLUTIONS | |||||
DIVISION OF SCHLUMBERGER TECHNOLOGY CORPORATION | |||||
As independent oil and gas consultants, Software Integrated Solutions, Division of Schlumberger Technology Corporation hereby consents to the incorporation by reference in the Registration Statements on Form S-8 (File Nos. 333-109162, 333-126191, 333-135949, 333- 143990, 333-151762, 333-160350, 333-171468, 333-178067, 333-187018, 333- 189651, 333-192175 and 333-196977) of Chesapeake Energy Corporation of all references to our firm and information from our reserves report dated 17 February 2017, included in or made a part of the Chesapeake Energy Corporation Annual Report on Form 10-K for the year ended 31 December 2016 to be filed with the Securities and Exchange Commission on or about 3 March 2017, and our summary report attached as Exhibit 99 to such Annual Report on Form 10-K. | |||||
Software Integrated Solutions | |||||
Division of Schlumberger Technology Corporation | |||||
By: | |||||
Charles M. Boyer II, PG, CPG | |||||
Advisor - Unconventional Reservoirs | |||||
Pittsburgh HUB Manager | |||||
Canonsburg, Pennsylvania | |||||
3 March 2017 |
Exhibit 31.1 |
1. | I have reviewed this Annual Report on Form 10-K of Chesapeake Energy Corporation; |
2. | Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; |
3. | Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report; |
4. | The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have: |
(a) | designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; |
(b) | designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles; |
(c) | evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and |
(d) | disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and |
5. | The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions): |
(a) | all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and |
(b) | any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting. |
March 3, 2017 | By: | /s/ ROBERT D. LAWLER |
Robert D. Lawler | ||
President and Chief Executive Officer |
Exhibit 31.2 |
1. | I have reviewed this Annual Report on Form 10-K of Chesapeake Energy Corporation; |
2. | Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; |
3. | Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report; |
4. | The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have: |
(a) | designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; |
(b) | designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles; |
(c) | evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and |
(d) | disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and |
5. | The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions): |
(a) | all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and |
(b) | any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting. |
March 3, 2017 | By: | /s/ DOMENIC J. DELL’OSSO, JR. |
Domenic J. Dell’Osso, Jr. | ||
Executive Vice President and Chief Financial Officer |
Exhibit 32.1 |
1. | The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and |
2. | The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company. |
March 3, 2017 | By: | /s/ ROBERT D. LAWLER |
Robert D. Lawler President and Chief Executive Officer |
Exhibit 32.2 |
1. | The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and |
2. | The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company. |
March 3, 2017 | By: | /s/ DOMENIC J. DELL’OSSO, JR. |
Domenic J. Dell’Osso, Jr. | ||
Executive Vice President and Chief Financial Officer |
EXHIBIT 99 | ||
Software Integrated Solutions | ||
Division of Schlumberger Technology Corporation | ||
4600 J. Barry Court | ||
Suite 200 | ||
Canonsburg, Pennsylvania 15317 USA | ||
Tel: +1-724-416-9700 | ||
Fax: +1-724-416-9705 |
Proved Developed Reserves | Proved Undeveloped Reserves | Total Proved Reserves | |||||||
Remaining Net Reserves | |||||||||
Oil - Mbbls | 156,706.30 | 177,454.43 | 334,160.73 | ||||||
NGL - Mbbls | 112,918.56 | 67,234.38 | 180,152.94 | ||||||
Gas - MMscf | 3,343,768.56 | 738,597.54 | 4,082,366.11 | ||||||
Oil Equiv. - Mbbls | 826,919.62 | 367,788.40 | 1,194,708.02 | ||||||
Income Data (M$) | |||||||||
Future Net Revenue | 8,522,338.20 | 6,416,378.43 | 14,938,716.63 | ||||||
Deductions | |||||||||
Operating Expense | 2,346,596.66 | 1,164,648.06 | 3,511,244.73 | ||||||
Production Taxes | 640,067.40 | 477,874.41 | 1,117,941.81 | ||||||
Abandonment Expense | 100,046.89 | (31,668.46 | ) | 68,378.43 | |||||
Investment | 946.90 | 2,240,086.77 | 2,241,033.67 | ||||||
Future Net Cashflow (FNC) | 5,434,680.37 | 2,565,437.66 | 8,000,118.03 | ||||||
Discounted PV @ 10% (M$) | 3,030,808.91 | 636,879.84 | 3,667,688.75 |
Software Integrated Solutions | ||
Division of Schlumberger Technology Corporation | ||
February 17, 2017 | ||
Page 2 |
Proved Producing Reserves | Proved NonProducing Reserves | Proved Shut-In Reserves | Proved Undeveloped Reserves | Total Proved Reserves | ||||||
Remaining Net Reserves | ||||||||||
Oil - Mbbls | 156,430.79 | 275.51 | 0.00 | 177,454.43 | 334,160.73 | |||||
NGL - Mbbls | 112,821.83 | 96.73 | 0.00 | 67,234.38 | 180,152.94 | |||||
Gas - MMscf | 3,335,333.36 | 8,435.21 | 0.00 | 738,597.54 | 4,082,366.11 | |||||
Oil Equiv. - Mbbls | 825,141.52 | 1,778.10 | 0.00 | 367,788.40 | 1,194,708.02 | |||||
Income Data (M$) | ||||||||||
Future Net Revenue | 8,504,829.26 | 17,508.94 | 0.00 | 6,416,378.43 | 14,938,716.63 | |||||
Deductions | ||||||||||
Operating Expense | 2,338,226.57 | 8,354.96 | 15.14 | 1,164,648.06 | 3,511,244.73 | |||||
Production Taxes | 638,757.27 | 1,310.13 | 0.00 | 477,874.41 | 1,117,941.81 | |||||
Abandonment Expense | 98,982.25 | 687.53 | 377.11 | -31,668.46 | 68,378.43 | |||||
Investment | 0.00 | 946.90 | 0.00 | 2,240,086.77 | 2,241,033.67 | |||||
Future Net Cashflow (FNC) | 5,428,863.19 | 6,209.42 | (392.24) | 2,565,437.66 | 8,000,118.03 | |||||
Discounted PV @ 10% (M$) | 3,027,313.69 | 3,654.54 | (159.32) | 636,879.84 | 3,667,688.75 |
Software Integrated Solutions | ||
Division of Schlumberger Technology Corporation | ||
February 17, 2017 | ||
Page 3 |
Product | Reference Point | Year End 2016 Reference Price | Average Price |
Oil | West Texas Intermediate | $42.75/Bbl | $36.26/Bbl |
NGL | West Texas Intermediate | $42.75/Bbl | $7.73/Bbl |
Natural Gas | Henry Hub | $2.49/MMBtu | $0.35/Mscf |
Software Integrated Solutions | ||
Division of Schlumberger Technology Corporation | ||
February 17, 2017 | ||
Page 4 |
Sincerely yours, | ||
/s/ Denise L. Delozier | /s/ Charles M. Boyer II | |
Denise L. Delozier | Charles M. Boyer II, PG, CPG | |
Senior Engineer | Advisor - Unconventional Reservoirs | |
Pittsburgh HUB Manager |
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Document and Entity Information - USD ($) $ in Billions |
12 Months Ended | ||
---|---|---|---|
Dec. 31, 2016 |
Feb. 22, 2017 |
Jun. 30, 2016 |
|
Document and Entity Information [Abstract] | |||
Document Type | 10-K | ||
Amendment Flag | false | ||
Document Period End Date | Dec. 31, 2016 | ||
Document Fiscal Year Focus | 2016 | ||
Document Fiscal Period Focus | FY | ||
Trading Symbol | CHK | ||
Entity Registrant Name | Chesapeake Energy Corporation | ||
Entity Central Index Key | 0000895126 | ||
Current Fiscal Year End Date | --12-31 | ||
Entity Filer Category | Large Accelerated Filer | ||
Entity Common Stock, Shares Outstanding | 906,830,905 | ||
Entity Well-known Seasoned Issuer | Yes | ||
Entity Voluntary Filers | No | ||
Entity Current Reporting Status | Yes | ||
Entity Public Float | $ 3.3 |
CONSOLIDATED BALANCE SHEETS (Parenthetical) - USD ($) $ in Millions |
Dec. 31, 2016 |
Dec. 31, 2015 |
---|---|---|
Preferred stock, par value (usd per share) | $ 0.01 | $ 0.01 |
Preferred stock, shares authorized (shares) | 20,000,000 | 20,000,000 |
Preferred stock, shares outstanding (shares) | 5,839,506 | 7,251,515 |
Common stock, par value (usd per share) | $ 0.01 | $ 0.01 |
Common stock, shares authorized | 1,500,000,000 | 1,000,000,000 |
Common stock, shares issued | 896,279,353 | 664,795,509 |
Treasury stock, common shares | 1,220,504 | 1,437,724 |
VIE, cash and cash equivalents | $ 882 | $ 825 |
VIE. proved natural gas and oil properties | 66,451 | 63,843 |
VIE. accumulated depreciation, depletion and amortization | (62,726) | (59,365) |
VIE. other current liabilities | 1,798 | 2,219 |
Variable Interest Entities, Primary Beneficiary [Member] | ||
VIE, cash and cash equivalents | 1 | 1 |
VIE. proved natural gas and oil properties | 488 | 488 |
VIE. accumulated depreciation, depletion and amortization | (458) | (428) |
VIE. other current liabilities | $ 3 | $ 8 |
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) - USD ($) $ in Millions |
12 Months Ended | ||
---|---|---|---|
Dec. 31, 2016 |
Dec. 31, 2015 |
Dec. 31, 2014 |
|
NET INCOME (LOSS) | $ (4,399) | $ (14,635) | $ 2,056 |
OTHER COMPREHENSIVE INCOME (LOSS), NET OF INCOME TAX: | |||
Unrealized gains (losses) on derivative instruments, net of income tax expense (benefit) of ($14), $12 and $0 | (13) | 20 | 1 |
Reclassification of losses on settled derivative instruments, net of income tax expense of $18, $15 and $14 | 16 | 24 | 23 |
Reclassification of (gains) losses on investment, net of income tax expense (benefit) of $0, $0 and ($3) | 0 | 0 | (5) |
Other Comprehensive Income (Loss) | 3 | 44 | 19 |
COMPREHENSIVE INCOME (LOSS) | (4,396) | (14,591) | 2,075 |
COMPREHENSIVE INCOME ATTRIBUTABLE TO NONCONTROLLING INTERESTS | (2) | (50) | (139) |
COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO CHESAPEAKE | $ (4,398) | $ (14,641) | $ 1,936 |
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) (Parenthetical) - USD ($) $ in Millions |
12 Months Ended | ||
---|---|---|---|
Dec. 31, 2016 |
Dec. 31, 2015 |
Dec. 31, 2014 |
|
Income tax expense (benefit) of $0, $20 and $1 on unrealized gains (losses) on derivative instruments | $ (14) | $ 12 | $ 0 |
Income tax expense (benefit) of $0, and $4 on reclassification of (gains) losses on settled derivative instruments | 18 | 15 | 14 |
Income tax expense (benefit) of $0, $0 and ($3) on reclassification of (gains) losses on investment | $ 0 | $ 0 | $ (3) |
Basis of Presentation and Significant Accounting Policies (Notes) |
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Accounting Policies [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Organization, Consolidation, Basis of Presentation, Business Description and Accounting Policies Disclosure | Basis of Presentation and Summary of Significant Accounting Policies Description of Company Chesapeake Energy Corporation ("Chesapeake" or the "Company") is an oil and natural gas exploration and production company engaged in the acquisition, exploration and development of properties for the production of oil, natural gas and natural gas liquids (NGL) from underground reservoirs. We also own oil and natural gas marketing and compression businesses. As of December 31, 2016, we have sold substantially all of our assets associated with our natural gas gathering business, and prior to June 30, 2014, we owned an oilfield services business (see Note 13). Our operations are located onshore in the United States. Basis of Presentation The accompanying consolidated financial statements of Chesapeake 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. Accounting Estimates The preparation of financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the dates of the financial statements and the reported amounts of revenues and expenses during the reporting periods. Actual results could differ from those estimates. Estimates of oil and natural gas reserves and their values, future production rates and future costs and expenses are the most significant of our estimates. The accuracy of any reserve estimate is a function of the quality of data available and of engineering and geological interpretation and judgment. In addition, estimates of reserves may be revised based on actual production, results of subsequent exploration and development activities, recent commodity prices, operating costs and other factors. These revisions could materially affect our financial statements. The volatility of commodity prices results in increased uncertainty inherent in these estimates and assumptions. Changes in oil, natural gas or NGL prices could result in actual results differing significantly from our estimates. 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. Consolidation Chesapeake consolidates entities in which we have a controlling financial interest. We consolidate subsidiaries in which we hold, directly or indirectly, more than 50% of the voting rights and variable interest entities (VIEs) in which Chesapeake is the primary beneficiary. We use the equity method of accounting to record our net interests where Chesapeake has the ability to exercise significant influence through its investment. Under the equity method, our share of net income (loss) is included in our consolidated statements of operations according to our equity ownership or according to the terms of the applicable governing instrument. See Note 14 for further discussion of our investments. Undivided interests in oil and natural gas properties are consolidated on a proportionate basis. Noncontrolling Interests Noncontrolling interests represent third-party equity ownership in certain of our consolidated subsidiaries and are presented as a component of equity. See Note 8 for further discussion of noncontrolling interests. Variable Interest Entities VIEs are entities that, by design, either (i) lack sufficient equity to permit the entity to finance its activities independently, or (ii) have equity holders that do not have the power to direct the activities of the entity that most significantly impact its economic performance, the obligation to absorb the entity’s losses, or the right to receive the entity’s residual returns. We consolidate a VIE when we are the primary beneficiary, which is the party that has both (i) the power to direct the activities that most significantly impact the VIE’s economic performance and (ii) through its interests in the VIE, the obligation to absorb losses or the right to receive benefits from the VIE that could potentially be significant to the VIE. We continually monitor our consolidated VIE to determine if any events have occurred that could cause the primary beneficiary to change. See Note 15 for further discussion of VIEs. Cash and Cash Equivalents For purposes of the consolidated financial statements, Chesapeake considers investments in all highly liquid instruments with original maturities of three months or less at the date of purchase to be cash equivalents. Accounts Receivable Our accounts receivable are primarily from purchasers of oil, natural gas and NGL and from exploration and production companies that own interests in properties we operate. This industry concentration could affect our overall exposure to credit risk, either positively or negatively, because our purchasers and joint working interest owners may be similarly affected by changes in economic, industry or other conditions. We monitor the creditworthiness of all our counterparties and we generally require letters of credit or parent guarantees for receivables from parties which are judged to have sub-standard credit, unless the credit risk can otherwise be mitigated. We utilize an allowance method in accounting for bad debt based on historical trends in addition to specifically identifying receivables that we believe may be uncollectible. During 2016, 2015 and 2014, we recognized $10 million, $4 million and $2 million of bad debt expense related to potentially uncollectible receivables. Accounts receivable as of December 31, 2016 and 2015 are detailed below.
Oil and Natural Gas Properties Chesapeake follows the full cost method of accounting under which all costs associated with oil and natural gas property acquisition, exploration and development activities are capitalized. We capitalize internal costs that can be directly identified with these activities and do not capitalize any costs related to production, general corporate overhead or similar activities (see Supplementary Information – Supplemental Disclosures About Oil, Natural Gas and NGL Producing Activities). Capitalized costs are amortized on a composite unit-of-production method based on proved oil and natural gas reserves. Estimates of our proved reserves as of December 31, 2016 were prepared by an independent engineering firm and Chesapeake's internal staff. Approximately 70% by volume and 83% by value of these proved reserves estimates as of December 31, 2016 were prepared by an independent engineering firm. In addition, our internal engineers review and update our reserves on a quarterly basis. Proceeds from the sale of oil and natural gas properties are accounted for as reductions of capitalized costs unless these sales involve a significant change in proved reserves and significantly alter the relationship between costs and proved reserves, in which case a gain or loss is recognized. The costs of unproved properties are excluded from amortization until the properties are evaluated. We review all of our unproved properties quarterly to determine whether or not and to what extent proved reserves have been assigned to the properties and otherwise if impairment has occurred. Unproved properties are grouped by major prospect area in circumstances where individual property costs are not significant. In addition, we analyze our unproved leasehold and transfer to proved properties that portion of our leasehold that expired in the quarter, or leasehold that is no longer part of our development strategy and will be abandoned. The table below sets forth the cost of unproved properties excluded from the amortization base as of December 31, 2016 and the year in which the associated costs were incurred.
We also review, on a quarterly basis, the carrying value of our oil and natural gas properties under the full cost accounting rules of the Securities and Exchange Commission (SEC). This quarterly review is referred to as a ceiling test. 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 oil and natural gas derivatives designated as cash flow hedges) less estimated future expenditures to be incurred in developing and producing the proved reserves, less any related income tax effects. The ceiling test calculation uses costs as of the end of the applicable quarterly period and the unweighted arithmetic average of oil, natural gas and NGL prices on the first day of each month within the 12-month period prior to the ending date of the quarterly period. These prices are utilized except where different prices are fixed and determinable from applicable contracts for the remaining term of those contracts, including the effects of derivatives designated as cash flow hedges. As of December 31, 2016, none of our open derivative instruments were designated as cash flow hedges. Our oil and natural gas hedging activities are discussed in Note 11. Two primary factors impacting the ceiling test are reserves levels and oil, natural gas and NGL prices, and their associated impact on the present value of estimated future net revenues. Revisions to estimates of oil and natural gas reserves and/or an increase or decrease in prices can have a material impact on the present value of our estimated future net revenues. Any excess of the net book value over the ceiling is written off as an expense. We account for seismic costs as part of our oil and natural gas properties. Exploration costs may be incurred both before acquiring the related property and after acquiring the property. Further, exploration costs include, among other things, geological and geophysical studies and salaries and other expenses of geologists, geophysical crews and others conducting those studies. These costs are capitalized as incurred. The Company reviews its unproved properties and associated seismic costs quarterly to determine whether impairment has occurred. To the extent that seismic costs cannot be directly associated with specific unproved properties, they are included in the amortization base as incurred. Other Property and Equipment Other property and equipment consists primarily of natural gas compressors, buildings and improvements, land, vehicles, computers and office equipment. We have no remaining oilfield services equipment as a result of the spin-off of our oilfield services business in 2014, as discussed in Note 13. Major renewals and betterments are capitalized while the costs of repairs and maintenance are charged to expense as incurred. The costs of assets retired or otherwise disposed of and the applicable accumulated depreciation are removed from the accounts, and the resulting gain or loss is reflected in operating expenses. See Note 16 for further discussion of our gains and losses on the sales of other property and equipment for the years ended 2016, 2015 and 2014 and a summary of our other property and equipment held for sale as of December 31, 2016 and 2015. Other property and equipment costs, excluding land, are depreciated on a straight-line basis. Realization of the carrying value of other property and equipment is reviewed for possible impairment whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. Assets are determined to be impaired if a forecast of undiscounted estimated future net operating cash flows directly related to the asset, including any disposal value, is less than the carrying amount of the asset. If any asset is determined to be impaired, the loss is measured as the amount by which the carrying amount of the asset exceeds its fair value. An estimate of fair value is based on the best information available, including prices for similar assets and discounted cash flow. During 2016, 2015 and 2014, we determined that certain of our property and equipment was being carried at values that were not recoverable and in excess of fair value. See Note 17 for further discussion of these impairments. Capitalized Interest Interest from external borrowings is capitalized on significant investments in unproved properties and major development projects until the asset is ready for service using the weighted average borrowing rate of outstanding borrowings. Capitalized interest is determined by multiplying our weighted-average borrowing cost on debt by the average amount of qualifying costs incurred. Capitalized interest is depreciated over the useful lives of the assets in the same manner as the depreciation of the underlying asset. Accounts Payable Included in accounts payable as of December 31, 2016 and 2015 are liabilities of approximately $77 million and $60 million, respectively, representing the amount by which checks issued, but not yet presented to our banks for collection, exceeded balances in applicable bank accounts. Debt Issuance Costs Included in other long-term assets are costs associated with the issuance and amendments of our revolving credit facility. The remaining unamortized issuance costs as of December 31, 2016 and 2015, totaled $32 million and $31 million, respectively, and are being amortized over the life of credit facility using the effective interest method. Included in debt are costs associated with the issuance of our senior notes. The remaining unamortized issuance costs as of December 31, 2016 and 2015, totaled $64 million and $43 million, respectively, and are being amortized over the life of the senior notes using the effective interest method. Environmental Remediation Costs Chesapeake records environmental reserves for estimated remediation costs related to existing conditions from past operations when the responsibility to remediate is probable and the costs can be reasonably estimated. Expenditures that create future benefits or contribute to future revenue generation are capitalized. Asset Retirement Obligations We recognize liabilities for obligations associated with the retirement of tangible long-lived assets that result from the acquisition, construction and development of the assets. We recognize the fair value of a liability for a retirement obligation in the period in which the liability is incurred. For oil and natural gas properties, this is the period in which an oil or natural gas well is acquired or drilled. The liability is then accreted each period until the liability is settled or the well is sold, at which time the liability is removed. The related asset retirement cost is capitalized as part of the carrying amount of our oil and natural gas properties. See Note 20 for further discussion of asset retirement obligations. Revenue Recognition Oil, Natural Gas and NGL Sales. Revenue from the sale of oil, natural gas and NGL is recognized when title passes, net of royalties due to third parties. Natural Gas Imbalances. We follow the sales method of accounting for our natural gas revenue whereby we recognize sales revenue on all natural gas sold to our purchasers, regardless of whether the sales are proportionate to our ownership in the property. An asset or a liability is recognized to the extent that we have an imbalance in excess of the remaining estimated natural gas reserves on the underlying properties. The natural gas imbalance net liability position as of December 31, 2016 and 2015, was $9 million and $10 million, respectively. Marketing, Gathering and Compression Sales. Chesapeake takes title to the oil, natural gas and NGL it purchases from other interest owners at defined delivery points and delivers the product to third parties, at which time revenues are recorded. In addition, we periodically enter into a variety of oil, natural gas and NGL purchase and sale contracts with third parties for various commercial purposes, including credit risk mitigation and to help meet certain of our pipeline delivery commitments. In circumstances where we act as a principal rather than an agent, Chesapeake's results of operations related to its oil, natural gas and NGL marketing activities are presented on a gross basis. Gathering and compression revenues consist of fees billed to other interest owners in operated wells or third-party producers for the gathering, treating and compression of natural gas. Revenues are recognized when the service is performed and are based upon non-regulated rates and the related gathering, treating and compression volumes. All significant intercompany accounts and transactions have been eliminated. Oilfield Services Revenue. Prior to the spin-off of our oilfield services business in June 2014, we reported oilfield services revenue. Our former oilfield services operating segment was responsible for contract drilling, hydraulic fracturing, rentals, trucking and other oilfield services operations for both Chesapeake-operated wells and wells operated by third parties. Revenues were recognized upon completion stages for our contract drilling, hydraulic fracturing and other oilfield services. Revenue was recognized ratably over the term of the rental for our oilfield rental services. Oilfield trucking services revenue was recognized as services were performed. Fair Value Measurements Certain financial instruments are reported at fair value on our consolidated balance sheets. Under fair value measurement accounting guidance, fair value is defined as the amount that would be received from the sale of an asset or paid for the transfer of a liability in an orderly transaction between market participants (i.e., an exit price). To estimate an exit price, a three-level hierarchy is used. The fair value hierarchy prioritizes the inputs, which refer broadly to assumptions market participants would use in pricing an asset or a liability, into three levels. Level 1 inputs are unadjusted quoted prices in active markets for identical assets and liabilities and have the highest priority. Level 2 inputs are inputs other than quoted prices within Level 1 that are observable for the asset or liability, either directly or indirectly. Level 3 inputs are unobservable inputs for the asset or liability and have the lowest priority. The valuation techniques that may be used to measure fair value include a market approach, an income approach and a cost approach. A market approach uses prices and other relevant information generated by market transactions involving identical or comparable assets or liabilities. An income approach uses valuation techniques to convert future amounts to a single present amount based on current market expectations, including present value techniques, option-pricing models and the excess earnings method. The cost approach is based on the amount that currently would be required to replace the service capacity of an asset (replacement cost). The carrying values of financial instruments comprising cash and cash equivalents, accounts payable and accounts receivable approximate fair values due to the short-term maturities of these instruments. Derivatives Derivative instruments are recorded on our consolidated balance sheets as derivative assets or derivative liabilities at fair value, and changes in a derivative’s fair value are recognized currently in earnings unless specific hedge accounting criteria are followed. For qualifying commodity derivative instruments designated as cash flow hedges, changes in fair value, to the extent the hedge is effective, are recognized in other comprehensive income until the hedged item is recognized in earnings. Any change in fair value resulting from ineffectiveness is recognized immediately in earnings. Locked-in gains and losses of settled cash flow hedges are recorded in accumulated other comprehensive income and are transferred to earnings in the month of production. Changes in the fair value of interest rate derivative instruments designated as fair value hedges are recorded on the consolidated balance sheets as assets or liabilities, and the debt's carrying value amount is adjusted by the change in the fair value of the debt subsequent to the initiation of the derivative. Differences between the changes in the fair values of the hedged item and the derivative instrument, if any, represent hedge ineffectiveness and are recognized currently in earnings. Locked-in gains and losses related to settled fair value hedges are amortized as an adjustment to interest expense over the remaining term of the related debt instrument. We have elected not to designate any of our qualifying commodity and interest rate derivatives as cash flow or fair value hedges. Therefore, changes in fair value of these derivatives that occur prior to their maturity (i.e., temporary fluctuations in value) are recognized in our consolidated statements of operations within oil, natural gas and NGL sales and interest expense, respectively. 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 changes in fair value of the embedded derivative and the settlements are recognized in our consolidated statements of operations within marketing, gathering and compression sales. Derivative instruments reflected as current in the consolidated balance sheets represent the estimated fair value of derivatives scheduled to settle over the next twelve months based on market prices/rates as of the respective balance sheet dates. Cash settlements of our derivative instruments are generally classified as operating cash flows unless the derivatives are deemed to contain, for accounting purposes, a significant financing element at contract inception, in which case these cash settlements are classified as financing cash flows in the accompanying consolidated statement of cash flows. All of our derivative instruments are subject to master netting arrangements by contract type (i.e., commodity, interest rate and cross currency contracts) which provide for the offsetting of asset and liability positions within each contract type, as well as related cash collateral if applicable, by counterparty. Therefore, we net the value of our derivative instruments by contract type with the same counterparty in the accompanying consolidated balance sheets. We have established the fair value of our derivative instruments using established index prices, volatility curves and discount factors. These estimates are compared to our counterparty values for reasonableness. 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. Derivative transactions are 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. See Note 11 for further discussion of our derivative instruments. Share-Based Compensation Chesapeake’s share-based compensation program consists of restricted stock, stock options and performance share units granted to employees and restricted stock granted to non-employee directors under our Long Term Incentive Plan. We recognize in our financial statements the cost of employee services received in exchange for restricted stock and stock options based on the fair value of the equity instruments as of the grant date. For employees, this value is amortized over the vesting period, which is generally three or four years from the grant date. For directors, although restricted stock grants vest over three years, this value is recognized immediately as there is a non-substantive service condition for vesting. Because performance share units can only be settled in cash, they are classified as a liability in our consolidated financial statements and are measured at fair value as of the grant date and re-measured at fair value at the end of each reporting period. These fair value adjustments are recognized as general and administrative expense in the consolidated statements of operations. To the extent compensation expense relates to employees directly involved in the acquisition of oil and natural gas leasehold and exploration and development activities, these amounts are capitalized to oil and natural gas properties. Amounts not capitalized to oil and natural gas properties are recognized as general and administrative expenses, oil, natural gas and NGL production expenses, or marketing, gathering and compression expenses, based on the employees involved in those activities. See Note 9 for further discussion of share-based compensation. Reclassifications and Revisions In April 2015, the Financial Accounting Standards Board (FASB) issued guidance that requires debt issuance costs related to term debt to be presented in the balance sheet as a direct reduction from the associated debt liability. This standard requires retrospective application and is effective for annual reporting periods beginning after December 15, 2015. This change in accounting principle is preferable since it allows both debt issuance costs and debt discounts to be presented similarly in the consolidated balance sheets as a direct reduction from the face amount of our debt balances. A retrospective change to our consolidated balance sheet as of December 31, 2015, as previously presented, is required pursuant to the guidance. The retrospective adjustment to the December 31, 2015 consolidated balance sheet is shown below.
In addition, certain revisions have been made to the fair value of debt table included in Note 3 to conform to the presentation used for our 2016 disclosure. The 8.00% Senior Secured Second Lien Notes due 2022 were previously classified as Level 1 and should have been classified as Level 2, as these senior notes are not exchange-traded. The following table reflects the revisions made.
__________________________________________ (a) The difference in the carrying amount is due to the debt issuance costs retrospective change noted above. |
Earnings Per Share (Notes) |
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Earnings Per Share Disclosure | 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 years ended December 31, 2016, 2015 and 2014, 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 notes and contingent convertible senior notes. For the years ended December 31, 2016, 2015 and 2014, shares of common stock for the following dilutive securities were excluded from the calculation of diluted EPS as the effect was antidilutive.
For the year ended December 31, 2014, all outstanding equity securities convertible into common stock were included in the calculation of diluted EPS. A reconciliation of basic EPS and diluted EPS for the year ended December 31, 2014 is as follows:
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Debt (Notes) |
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Debt Disclosure [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Debt Disclosure | Debt Our long-term debt consisted of the following as of December 31, 2016 and 2015:
Optional Conversion by Holders. At the holder’s option, prior to maturity under certain circumstances, 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, beginning with the first quarter of 2017. Convertibility based on common stock price is measured quarterly. 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 year ended December 31, 2016. 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 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. 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 fourth quarter of 2016, 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 first 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 years ended December 31, 2016, 2015 and 2014. 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:
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.
Total principal amount of debt maturities, using the earliest demand repurchase date for contingent convertible senior notes, for the five years ended after December 31, 2016 and thereafter are as follows:
See Note 23 for discussion of debt that has been retired, repurchased and redeemed in 2017. Term Loan Facility In 2016, we entered into a secured five-year term loan facility in aggregate principal amount of $1.5 billion for net proceeds of approximately $1.476 billion. Our obligations under the new 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 loan was made at par without original discount. We used the net proceeds to finance tender offers for our unsecured notes. 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. The term loan contains covenants limiting our ability to incur additional indebtedness, incur liens, consummate mergers and similar fundamental changes, make restricted payments, sell collateral and use proceeds from such sales, make investments, repay certain subordinate, unsecured or junior lien indebtedness, and enter into transactions with affiliates. Events of default under the term loan include, among other things, nonpayment of principal, interest or other amounts; violation of covenants; incorrectness of representations and warranties in any material respect; cross-payment default and cross acceleration with respect to other indebtedness with an outstanding principal balance of $125 million or more; bankruptcy; judgments involving liability of $125 million or more that are not paid; and ERISA events. Many events of default are subject to customary notice and cure periods. Senior Secured Second Lien Notes In December 2015, we completed private offers to exchange newly issued 8.00% Senior Secured Second Lien Notes due 2022 (Second Lien Notes) for certain outstanding senior unsecured notes and contingent convertible senior notes (Existing Notes). The 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. 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. Accordingly, we recognized a gain of $304 million in our 2015 consolidated statement of operations, and the remaining reduction in principal amount of Existing Notes ($990 million as of December 31, 2016) is included in the carrying value of our Second Lien Notes. As a result, our reported interest expense will be significantly less than the contractual interest payments throughout the term of the Second Lien Notes. For the remaining TDR exchanges, where the future undiscounted cash flows are greater than the net carrying value of the original debt, no gain is recognized and a new effective interest rate is established. For the other Existing Notes that were exchanged that did not qualify as a TDR, we accounted for these exchanges as either a modification or extinguishment. Direct costs incurred of $30 million in 2015 related to the notes exchange were expensed and are included within gains (losses) on purchases or exchanges of debt in our consolidated statement of operations. Senior Notes, Contingent Convertible Senior Notes and Convertible Senior Notes The senior notes and the convertible senior notes are unsecured senior obligations of Chesapeake and rank equally in right of payment with all of our other existing and future senior unsecured indebtedness and rank senior in right of payment to all of our future subordinated indebtedness. Chesapeake’s obligations under the senior notes and the convertible senior notes are fully and unconditionally guaranteed, jointly and severally, by certain of our direct and indirect wholly owned subsidiaries. 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 consolidated financial statements. We may redeem the senior notes, other than the convertible senior notes, at any time at specified make-whole or redemption prices. Our senior notes are governed by indentures containing covenants that may limit our ability and our subsidiaries’ ability to incur certain secured indebtedness, enter into sale-leaseback transactions, and consolidate, merge or transfer assets. The indentures governing the senior notes and the convertible senior notes do not have any financial or restricted payment covenants. Indentures for the Second Lien Notes, senior notes and convertible senior notes have cross default provisions that apply to other indebtedness the Company or any guarantor subsidiary may have from time to time with an outstanding principal amount of at least $50 million or $75 million, depending on the indenture. 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. During 2016, we issued in a private placement $1.0 billion principal amount of unsecured 8.00% Senior Notes due 2025 at a discount for net proceeds of approximately $975 million. Some or all of the notes may be redeemed at any time prior to January 15, 2020, subject to a make-whole premium. In addition, we may redeem some or all of the notes at any time on or after January 15, 2020, at the applicable redemption price in accordance with the terms of the notes and the indenture and supplemental indenture governing the notes. In addition, subject to certain conditions, Chesapeake may redeem up to 35% of the aggregate principal amount of the notes at any time prior to January 15, 2020, at a price equal to 108% of the principal amount of the notes to be redeemed using the net proceeds of certain equity offerings by Chesapeake. During 2016, we issued in a private placement $1.25 billion principal amount of unsecured 5.5% Convertible Senior Notes due 2026 at par for net proceeds of approximately $1.235 billion. The notes are convertible, under certain specified circumstances, into cash, common stock, or a combination of cash and common stock, at our election. We accounted for the liability and equity components separately and reflected interest expense at the interest rate of similar nonconvertible debt at the time of issuance. The allocation to the equity component of the convertible notes was $445 million ($165 million tax expense). Additionally, debt issuance costs were allocated in proportion to the liability and equity components and accounted for as debt issuance costs and equity issuance costs, respectively. The accretion of the resulting discount on the debt is recognized through the convertible note’s maturity date as a component of interest expense, thereby increasing the amount of interest expense required to be recognized with respect to such instruments. During 2016, we used the net proceeds from our term loan and convertible and senior notes issuances discussed above, together with cash on hand, to purchase and retire $1.451 billion principal amount of our outstanding senior notes and $708 million principal amount of our outstanding contingent convertible senior notes for an aggregate $2.078 billion pursuant to tender offers. During 2016, in addition to the repayment upon maturity of $259 million principal amount of our 3.25% Senior Notes due 2016, we repurchased in the open market approximately $325 million principal amount of our outstanding senior notes for $300 million and $141 million principal amount of our outstanding contingent convertible senior notes for $86 million. Additionally, we privately negotiated exchanges of approximately $290 million principal amount of our outstanding senior notes for 53,923,925 shares of common stock and $287 million principal amount of our outstanding contingent convertible senior notes for 55,427,782 shares of common stock. For the year ended December 31, 2016, we recorded an aggregate net gain of approximately $236 million associated with the tender offers, debt repurchases and exchanges discussed above, which was net of $26 million ($10 million tax benefit) associated with the equity component of the retired contingent convertible senior notes. During 2015, as required by the terms of the indenture for our 2.75% Contingent Convertible Senior Notes due 2035 (the 2035 Notes), the holders were provided the option to require us to purchase on November 15, 2015, all or a portion of the holders’ 2035 Notes at par plus accrued and unpaid interest up to, but excluding, November 15, 2015. On November 16, 2015, we paid an aggregate of approximately $394 million to purchase all of the 2035 Notes that were tendered and not withdrawn. An aggregate of $2 million principal amount of the 2035 Notes remains outstanding as of December 31, 2016. During 2015, we repurchased in the open market approximately $119 million aggregate principal amount of our 3.25% Senior Notes due 2016 for cash. We recorded a gain of approximately $5 million associated with the repurchase. During 2014, we issued $3.0 billion in aggregate principal amount of senior notes at par. The offering included two series of notes: $1.5 billion in aggregate principal amount of Floating Rate Senior Notes due 2019 and $1.5 billion in aggregate principal amount of 4.875% Senior Notes due 2022. We used a portion of the net proceeds of $2.966 billion to repay the borrowings under, and terminate, our then-existing term loan credit facility. We used the remaining proceeds along with cash on hand to redeem the remaining $97 million principal amount of the 6.875% Senior Notes due 2018 and to purchase and redeem the remaining $1.265 billion principal amount of the 9.5% Senior Notes due 2015 for $1.454 billion. We recorded a loss of approximately $6 million associated with the redemption of the 6.875% Senior Notes due 2018, which consisted of $5 million in premiums and $1 million of unamortized deferred charges. We recorded a loss of approximately $99 million associated with the purchase and redemption of the 9.5% Senior Notes due 2015, which consisted of $87 million in premiums, $9 million of unamortized discount and $3 million of unamortized deferred charges. 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 December 31, 2016, we had no outstanding borrowings under the revolving credit facility and had used $1.036 billion 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). 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 December 31, 2016. 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. Our borrowing base may be reduced if we dispose of a certain percentage of the value of collateral securing the facility. As a result of certain asset sales discussed in Note 12 and certain other sales of collateral since the date of the most recent amendment, our borrowing base was reduced to $3.8 billion as of December 31, 2016. The amendment also provides 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 reduces 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 December 31, 2016, falls below 1.1 to 1.0, the $500 million minimum liquidity covenant increases to $750 million, and 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. 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. 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.
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Contingencies and Commitments (Notes) |
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Legal Matters and Contingencies | 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. 2016 Shareholder Litigation. On April 19, 2016, a shareholder lawsuit was filed in the U.S. District Court for the Western District of Oklahoma against the Company and current and former directors and officers of the Company alleging, among other things, violation of and conspiracy to violate the federal Racketeer Influenced and Corrupt Organizations Act, breach of fiduciary duties, waste of corporate assets, gross mismanagement and violations of Sections 10(b) and Rule 10b-5 of the Exchange Act related to actions allegedly taken by such persons since 2008. The lawsuit sought to assert derivative and direct claims, certification as a class action, damages, attorneys’ fees and other costs. The District Court dismissed the plaintiffs’ claims on August 30, 2016. 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 United States Court of Appeals for the Second Circuit affirmed the trial court’s ruling. On February 2, 2017, the Company filed a petition for writ of certiorari with the United States Supreme Court seeking review of the Court of Appeals’ decision. 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. With regard to contract actions, various mineral or leasehold owners have filed lawsuits against us seeking specific performance to require us to acquire their oil and natural gas interests and pay acreage bonus payments, damages based on breach of contract and/or, in certain cases, punitive damages based on alleged fraud. The Company has successfully defended a number of these failure-to-close cases in various courts and has settled and resolved other such cases and disputes. 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, through 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 United States District Court for the Western District of Oklahoma and in Oklahoma state courts, and an individual lawsuit was filed in the United States 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 which would restrain competition in a similar manner as alleged in the lawsuits. Other Matters In April 2016, a class action lawsuit on behalf of holders of the Company’s 6.875% Senior Notes due 2020 (the 2020 Notes) and 6.125% Senior Notes due 2021 (2021 Notes) was filed in the U.S. District Court for the Southern District of New York relating to the Company’s December 2015 debt exchange, whereby the Company privately exchanged newly issued 8.00% Senior Secured Second Lien Notes due 2022 (Second Lien Notes) for certain outstanding senior unsecured notes and contingent convertible notes. The lawsuit alleges that the Company violated the Trust Indenture Act of 1939 and the implied covenant of good faith and fair dealing by benefiting themselves and a minority of noteholders who are qualified institutional buyers (QIBs). According to the lawsuit, as a result of the Company’s private debt exchange in which only QIBs (and non-U.S. persons under Regulation S) were eligible to participate, the Company unjustly enriched itself at the expense of class members by reducing indebtedness and reducing the value of the 2020 Notes and the 2022 Notes. The lawsuit seeks damages and attorney’s fees, in addition to declaratory relief that the debt exchange and the liens created for the benefit of the Second Lien Notes are null and void and that the debt exchange effectively resulted in a default under the indentures for the 2020 Notes and the 2021 Notes. In June 2016, the lawsuit was transferred to the United States District Court for the Western District of Oklahoma, and in October 2016, the Company filed a motion to dismiss for failure to state a claim. The District Court dismissed the plaintiffs’ claims on February 8, 2017. 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 |
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Commitments Contingencies and Guarantees | Commitments Operating Leases Future operating lease commitments related to other property and equipment are not recorded as obligations in the accompanying consolidated balance sheets. The aggregate undiscounted minimum future lease payments are presented below.
Lease expense for the years ended December 31, 2016, 2015 and 2014, was $5 million, $7 million and $33 million, respectively. Lease expense decreased significantly in 2016 and 2015 compared to 2014 primarily due to the repurchase of all rigs and compressors previously sold under long-term sale-leaseback arrangements. Gathering, Processing and Transportation Agreements We have contractual commitments with midstream service companies and pipeline carriers for future gathering, processing and transportation of oil, natural gas and NGL to move certain of our production to market. Working interest owners and royalty interest owners, where appropriate, will be responsible for their proportionate share of these costs. Commitments related to gathering, processing and transportation agreements are not recorded as obligations in the accompanying consolidated balance sheets; however, they are reflected in our estimates of proved reserves. The aggregate undiscounted commitments under our gathering, processing and transportation agreements, excluding any proportionate share of these costs from working interest and royalty interest owners, credits for third-party volumes or future costs under cost-of-service agreements, are presented below.
In addition to the above commitments, 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. 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 consolidated balance sheets. As of December 31, 2016, the aggregate undiscounted minimum future payments under these drilling service commitments are detailed below.
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 consolidated balance sheets. As of December 31, 2016, the aggregate undiscounted minimum future payments under this agreement were approximately $53 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 12 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 required to extend, renew or replace 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 12 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. |
Other Liabilities (Notes) |
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Other Liabilities Disclosure [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Other Liabilities Disclosure | Other Liabilities Other current liabilities as of December 31, 2016 and 2015 are detailed below.
Other long-term liabilities as of December 31, 2016 and 2015 are detailed below.
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Income Taxes (Notes) |
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Income Tax Disclosure [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Income Tax Disclosure | Income Taxes The components of the income tax provision (benefit) for each of the periods presented below are as follows:
The effective income tax expense (benefit) differed from the computed "expected" federal income tax expense on earnings before income taxes for the following reasons:
In accordance with U.S. GAAP, intraperiod tax allocation provisions require allocation of $190 million of tax benefit to continuing operations. This tax benefit was partially offset by $165 million of tax expense and $10 million of tax benefit associated with the equity components of the debt transactions that occurred during the year. See Note 3 for further discussion of our debt transactions. Additionally, $4 million of tax expense was allocated to other comprehensive income. The result is a net tax benefit of $31 million which is primarily due to tax elections that allow for realization of deferred tax assets related to alternative minimum tax (AMT) credits. We reassessed the realizability of our deferred tax assets given the low commodity prices and recorded a $1.423 billion increase in our valuation allowance in our consolidated statement of operations for the year ended December 31, 2016. The increase in the valuation allowance is to offset the portion of the tax benefit at expected rates that we believe is more likely than not to not be realized. Deferred income taxes are provided to reflect temporary differences in the basis of net assets for income tax and financial reporting purposes. The tax-effected temporary differences and tax loss carryforwards which comprise deferred taxes are as follows:
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As of December 31, 2016, Chesapeake had federal income tax NOL carryforwards of approximately $6.2 billion and state NOL carryforwards of approximately $9.5 billion which excludes the NOL carryforwards related to unrecognized tax benefits. The associated deferred tax assets related to these NOL carryforwards were $2.161 billion and $426 million, respectively. The NOL carryforwards expire between 2031 and 2036. The value of these carryforwards depends on the ability of Chesapeake to generate taxable income. As of December 31, 2016 and 2015, we had deferred tax assets of $4.690 billion and $4.122 billion upon which we had a valuation allowance of $4.389 billion and $2.949 billion, respectively. Of the net change in the valuation allowance of $1.440 billion for both federal and state deferred tax assets, $1.423 billion is reflected as a component of income tax expense in the consolidated statement of operations and $17 million is reflected as a component of equity. 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 such taxable income is generated, to determine whether a valuation allowance is required. Such 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. As of December 31, 2016, 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 cumulative loss incurred over the three-year period ending December 31, 2016. Such 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 reduced or 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. The ability of Chesapeake to utilize NOL carryforwards to reduce future federal taxable income and federal income tax is subject to various limitations under the Internal Revenue Code of 1986, as amended. The utilization of these carryforwards may be limited upon the occurrence of certain ownership changes, including the issuance or exercise of rights to acquire stock, the purchase or sale of stock by 5% stockholders, as defined in the Treasury regulations, and the offering of stock by us during any three-year period resulting in an aggregate change of more than 50% in the beneficial ownership of Chesapeake. As of December 31, 2016, we do not believe that an ownership change has occurred that would limit our NOL carryforwards. Future equity transactions by Chesapeake or by 5% stockholders (including relatively small transactions and transactions beyond our control) could cause an ownership change and therefore a limitation on the annual utilization of NOLs. Accounting guidance for recognizing and measuring uncertain tax positions prescribes a threshold condition that a tax position must meet for any of the benefit of the uncertain tax position to be recognized in the financial statements. Guidance is also provided regarding de-recognition, classification and disclosure of these uncertain tax positions. As of December 31, 2016 and 2015, the amount of unrecognized tax benefits related to NOL carryforwards and state tax liabilities associated with uncertain tax positions was $202 million and $280 million, respectively. Of the 2016 amount, $76 million is related to state tax liabilities while the remainder is related to NOL carryforwards. Of the 2015 amount, $44 million is related to state tax liabilities while the remainder is related to NOL carryforwards. The uncertain tax positions identified would not have a material effect on the effective tax rate. No material changes to the current uncertain tax positions are expected within the next 12 months. As of both December 31, 2016 and 2015, we had accrued liabilities of $20 million for interest related to these uncertain tax positions. Chesapeake recognizes interest related to uncertain tax positions in interest expense. Penalties, if any, related to uncertain tax positions would be recorded in other expenses. A reconciliation of the beginning and ending balances of unrecognized tax benefits is as follows:
Chesapeake's federal and state income tax returns are routinely audited by federal and state fiscal authorities. The Internal Revenue Service (IRS) is currently auditing our federal income tax returns for 2010 through 2015. The 2010 through 2016 years and the 2007 through 2016 years remain open for all purposes of examination by the IRS and other taxing authorities in material jurisdictions, respectively. |
Related Party Transactions (Notes) |
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Related Party Transactions [Abstract] | |
Related Party Transactions Disclosure | Related Party Transactions Our equity method investees are considered related parties. Hydraulic fracturing and other services are provided to us in the ordinary course of business by our equity affiliate FTS International, Inc. (FTS). As well operators, we are reimbursed by other working interest owners through the joint interest billing process for their proportionate share of these costs. For the years ended December 31, 2016, 2015 and 2014, our expenditures for hydraulic fracturing services with FTS were $3 million, $65 million and $220 million, respectively. |
Equity (Notes) |
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Equity [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Stockholders' Equity Note Disclosure | Equity Common Stock A summary of the changes in our common shares issued for the years ended December 31, 2016, 2015 and 2014 is detailed below.
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During the year ended December 31, 2016, our shareholders approved an amendment to our certificate of incorporation to increase our authorized common stock from 1,000,000,000 shares to 1,500,000,000 shares, par value $0.01 per share. Preferred Stock Following is a summary of our preferred stock, including the primary conversion terms as of December 31, 2016:
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Outstanding shares of our preferred stock for the years ended December 31, 2016, 2015 and 2014 are detailed below.
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Dividends In January 2016, we announced that we were suspending dividend payments on each series of our outstanding convertible preferred stock. Suspension of the dividends did not constitute an event of default under our revolving credit facility or bond indentures. Our preferred stock dividends for the year ended December 31, 2016 (paid in arrears) are detailed below.
On February 15, 2017, 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 years ended December 31, 2016 and 2015, changes in accumulated other comprehensive income (loss) for cash flow hedges, net of tax, are detailed below.
For the years ended December 31, 2016 and 2015, amounts reclassified from accumulated other comprehensive income (loss), net of tax, into the consolidated statements of operations are detailed below.
Noncontrolling Interests Cleveland Tonkawa Financial Transaction. We formed CHK C-T in March 2012 to continue development of a portion of our oil and natural gas assets in our Cleveland and Tonkawa plays. In March 2012, in a private placement, third-party investors contributed $1.25 billion in cash to CHK C-T in exchange for (i) 1.25 million preferred shares, and (ii) our obligation to deliver a 3.75% overriding royalty interest (ORRI) in the existing wells and up to 1,000 future net wells to be drilled on the contributed play leasehold. We initially committed to drill and complete, for the benefit of CHK C-T in the area of mutual interest, a minimum cumulative total of 300 net wells. We ultimately drilled and completed 190 net wells, and the drilling commitment was suspended in January 2015. During 2015, CHK C-T sold all of its oil and natural gas properties to FourPoint Energy, LLC and immediately used the consideration received, plus other cash it had on hand, to repurchase and cancel all of the outstanding preferred shares in CHK C-T. In connection with the repurchase and cancellation of the CHK C-T preferred stock and related agreements with the CHK C-T investors, we eliminated quarterly preferred dividend payments and all related future drilling and ORRI commitments attributable to CHK C-T. The sale of the oil and natural gas properties was accounted for as a reduction of capitalized costs with no gain or loss recognized. For 2015 and 2014, income of $50 million and $75 million, respectively, was attributable to the noncontrolling interests of CHK C-T. Utica Financial Transaction. We formed CHK Utica, L.L.C. (CHK Utica) in October 2011 to develop a portion of our Utica Shale oil and natural gas assets. During November and December 2011, in private placements, third-party investors contributed $1.25 billion in cash to CHK Utica in exchange for (i) 1.25 million preferred shares, and (ii) our obligation to deliver a 3% ORRI in 1,500 net wells to be drilled on certain of our Utica Shale leasehold. In July 2014, we repurchased all of the outstanding preferred shares of CHK Utica from third-party preferred shareholders for approximately $1.254 billion, or approximately $1,189 per share including accrued dividends. The $447 million difference between the cash paid for the preferred shares and the carrying value of the noncontrolling interest acquired was reflected in retained earnings and as a reduction to net income available to common stockholders for purposes of our EPS computations. Pursuant to the transaction, our obligation to pay quarterly dividends to third-party preferred shareholders was eliminated. In addition, the development agreement was terminated pursuant to the transaction, which eliminated our obligation to drill and complete a minimum number of wells within a specified period for the benefit of CHK Utica. Our repurchase of the outstanding preferred shares in CHK Utica did not affect our obligation to deliver a 3% ORRI in 1,500 net wells on certain of our Utica Shale leasehold. The CHK Utica investors’ right to receive, proportionately, a 3% ORRI in the first 1,500 net wells drilled on certain of 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, which runs through 2023. However, in no event are we required to deliver to investors more than a total ORRI of 3% in 1,500 net wells. If at any time we hold fewer net acres than would enable us to drill all then-remaining net wells on 150-acre spacing, the investors have the right to require us to repurchase their right to receive ORRIs in the remaining net wells at the then-current fair market value of the remaining ORRIs. We retain the right to repurchase the investors’ right to receive ORRIs in the remaining net wells at the then-current fair market value of the remaining ORRIs once we have drilled a minimum of 1,300 net wells. As of December 31, 2016, we had drilled 508 net wells. The obligation to deliver future ORRIs has been recorded as a liability which will be settled through the future conveyance of the underlying ORRIs to the investors on a net-well basis, at which time the associated liability will be reversed and the sale of the ORRIs reflected as an adjustment to the capitalized cost of our oil and natural gas properties. We met our ORRI conveyance commitments as of December 31, 2014 and 2015 but did not meet our commitment in 2016. The ORRI will increase to 4% for wells drilled in 2017. In 2014, income of approximately $43 million was attributable to the noncontrolling interests of CHK Utica. Chesapeake Granite Wash Trust. In November 2011, Chesapeake Granite Wash Trust (the Trust) sold 23,000,000 common units representing beneficial interests in the Trust at a price of $19.00 per common unit in its initial public offering. The common units are listed on the New York Stock Exchange and trade under the symbol “CHKR”. We own 12,062,500 common units and 11,687,500 subordinated units, which in the aggregate represent an approximate 51% beneficial interest in the Trust. The Trust has a total of 46,750,000 units outstanding. The subordinated units we hold in the Trust are entitled to receive pro rata distributions from the Trust each quarter if and to the extent there is sufficient cash to provide a cash distribution on the common units that is not less than the applicable subordination threshold for the quarter. If there is not sufficient cash to fund a distribution on all of the Trust units, the distribution to be made with respect to the subordinated units is reduced or eliminated for the quarter in order to make a distribution, to the extent possible, of up to the subordination threshold amount on the common units. The distribution made with respect to the subordinated units to Chesapeake was either reduced or eliminated for each of the most recent 18 quarters. In exchange for agreeing to subordinate a portion of our Trust units, and in order to provide additional financial incentive to us to perform operations on the underlying properties in an efficient and cost-effective manner, Chesapeake is entitled to receive incentive distributions equal to 50% of the amount by which the cash available for distribution on the Trust units in any quarter exceeds the applicable incentive threshold for the quarter. The remaining 50% of cash available for distribution in excess of the applicable incentive threshold is to be paid to Trust unitholders, including Chesapeake, on a pro rata basis. Through December 31, 2016, no incentive distributions had been made. At the end of the 2017 second quarter, the subordinated units will automatically convert into common units on a one-for-one basis and our right to receive incentive distributions will terminate. After this time, the common units will no longer have the protection of the subordination threshold, and all Trust unitholders will share in the Trust’s distributions on a pro rata basis. For the years ended December 31, 2016, 2015 and 2014, the Trust declared and paid the following distributions:
We have determined that the Trust is a variable interest entity (VIE) and that Chesapeake is the primary beneficiary. As a result, the Trust is included in our consolidated financial statements. As of December 31, 2016 and 2015, we had $257 million and $259 million, respectively, of noncontrolling interests on our consolidated balance sheets attributable to the Trust. Net income attributable to the Trust’s noncontrolling interest is presented in our consolidated statements of operations as $2 million for the year ended December 31, 2016, a nominal amount for the year ended December 2015 and $24 million for the year ended December 31, 2014. See Note 15 for further discussion of VIEs. |
Share-Based Compensation (Notes) |
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Disclosure of Compensation Related Costs, Share-based Payments [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Disclosure of Compensation Related Costs, Share-based Payments | 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. In connection with the spin-off of our oilfield services business on June 30, 2014, and pursuant to the terms of our share-based compensation plans and the employee matters agreement between Chesapeake and Seventy Seven Energy Inc. (SSE), unexercised stock options and unvested restricted stock were modified as of the date of the spin-off. The modifications were designed to ensure that the value of each award of unexercised stock options and unvested restricted stock did not change as a result of the spin-off. The number of stock options and number of shares of restricted stock reported below have been adjusted to reflect modifications on the spin-off date. Share-Based Compensation Plans 2014 Long Term Incentive Plan. Our 2014 Long Term Incentive Plan (2014 LTIP), which is administered by the Compensation Committee of our Board of Directors, became effective on June 13, 2014 after it was approved by shareholders at our 2014 Annual Meeting. The 2014 LTIP replaced our Amended and Restated Long Term Incentive Plan which was adopted in 2005. The 2014 LTIP provides for up to 71,600,000 shares of common stock that may be issued as long-term incentive compensation to our employees and non-employee directors; provided, however, that the 2014 LTIP uses a fungible share pool under which (i) each share issued pursuant to a stock option or stock appreciation right (SAR) reduces the number of shares available under the 2014 LTIP by 1.0 share; (ii) each share issued pursuant to awards other than options and SARs reduces the number of shares available by 2.12 shares; (iii) if any awards of restricted stock under the 2014 LTIP, or its predecessor plan, are forfeited, expire, are settled for cash, or are tendered by the participant or withhold by us to satisfy any tax withholding obligation, then the shares subject to the award may be used again for awards; and (iv) PSUs and other performance awards which are payable solely in cash are not counted against the aggregate number of shares issuable. In addition, the 2014 LTIP prohibits the reuse of shares withheld or delivered to satisfy the exercise price of, or to satisfy tax withholding requirements for, an option or SAR. The 2014 LTIP also prohibits “net share counting” upon the exercise of options or SARs. The 2014 LTIP authorizes the issuance of the following types of awards: (i) nonqualified and incentive stock options; (ii) SARs; (iii) restricted stock; (iv) performance awards, including PSUs; and (v) other stock-based awards. For both stock options and SARs, the exercise price may not be less than the fair market value of our common stock on the date of grant and the maximum exercise period may not exceed ten years from the date of grant. Awards granted under the plan vest at specified dates and/or upon the satisfaction of certain performance or other criteria, as determined by the Compensation Committee. As of December 31, 2016, 61,856,065 shares of common stock remained issuable under the 2014 LTIP. Equity-Classified Awards Restricted Stock. We grant restricted stock units to employees and non-employee directors. Prior to 2014, we also granted restricted stock awards as equity compensation. We refer to both types of awards as restricted stock. A summary of the changes in unvested restricted stock during 2016, 2015 and 2014 is presented below.
The aggregate intrinsic value of restricted stock that vested during 2016 was approximately $21 million based on the stock price at the time of vesting. As of December 31, 2016, there was approximately $50 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 1.5 years. Stock Options. In 2016, 2015 and 2014, we granted members of senior 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 2016.
The following table provides information related to stock option activity for 2016, 2015 and 2014.
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As of December 31, 2016, there was $7 million of total unrecognized compensation expense related to stock options. The expense is expected to be recognized over a weighted average period of approximately 1.70 years. Restricted Stock and Stock Option Compensation. We recognized the following compensation costs related to restricted stock and stock options for the years ended December 31, 2016, 2015 and 2014.
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 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%. For PSUs granted in 2014, the TSR component can range from 0% to 200%, with no operational components. 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.
The following table presents a summary of our 2016, 2015 and 2014 PSU awards.
PSU Compensation. We recognized the following compensation costs (credits) related to PSUs for the years ended December 31, 2016, 2015 and 2016.
Effect of the Spin-off on Share-Based Compensation The employee matters agreement entered into in connection with the June 2014 spin-off of our oilfield services business (see Note 13) addresses the treatment of holders of Chesapeake stock options, restricted stock and PSUs that were impacted by the spin-off. Unvested equity-based compensation awards held by Chesapeake Oilfield Operating, L.L.C. (COO) employees were canceled and replaced with new awards of SSE, and unvested equity-based compensation awards held by Chesapeake employees were adjusted to account for the spin-off, each as of the spin-off date. The employee matters agreement provides that employees of SSE ceased to participate in benefit plans sponsored or maintained by Chesapeake as of the spin-off date. In addition, the employee matters agreement provides that as of the spin-off date, each party is responsible for the compensation of its current employees and for all liabilities relating to its former employees, as determined by their respective employer on the date of termination. |
Employee Benefit Plans (Notes) |
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Dec. 31, 2016 | |
Compensation and Retirement Disclosure [Abstract] | |
Pension and Other Postretirement Benefits Disclosure | Employee Benefit Plans Our qualified 401(k) profit sharing plan (401(k) Plan) is the Chesapeake Energy Corporation Savings and Incentive Stock Bonus Plan, which is open to employees of Chesapeake and all our subsidiaries. Eligible employees may elect to defer compensation through voluntary contributions to their 401(k) Plan accounts, subject to plan limits and those set by the IRS. Through December 31, 2014, Chesapeake matched employee contributions dollar for dollar (subject to a maximum contribution of 15% of an employee's base salary and performance bonus) with Chesapeake common stock purchased in the open market. Beginning January 1, 2015, Chesapeake matched employee contributions in cash. The Company contributed $39 million, $52 million and $61 million to the 401(k) Plan in 2016, 2015 and 2014, respectively. Chesapeake also maintains a nonqualified deferred compensation plan (DC Plan). To be eligible to participate in the DC Plan, an active employee must have a base salary of at least $150,000, have a hire date on or before December 1, immediately preceding the year in which the employee is able to participate, or be designated as eligible to participate. Only the top 10% of Company wage earners are eligible to participate. Additionally, the employee had to have made the maximum contribution allowable under the 401(k) Plan. Chesapeake matches 100% of employee contributions up to 15% of base salary and performance bonus in the aggregate for the DC Plan with Chesapeake common stock, and an employee who is at least age 55 may elect for the matching contributions to be made in any one of the DC Plan’s investment options. The maximum compensation that can be deferred by employees under all Company deferred compensation plans, including the Chesapeake 401(k) Plan, is a total of 75% of base salary and 100% of performance bonus. The Company contributed $9 million, $11 million and $7 million to the DC Plan during 2016, 2015 and 2014, respectively, to fund the match. Beginning in 2016, the DC Plan was no longer a spillover plan from the 401(k) Plan. The participant may choose separate deferral election percentages for both plans. The deferred compensation company match of 15% has a five-year vesting schedule based on years of service. Any participant who is active on December 31 of the plan year will receive the deferred compensation company match which will be awarded on an annual basis. Any assets placed in trust by Chesapeake to fund future obligations of the Company's nonqualified deferred compensation plan is subject to the claims of creditors in the event of insolvency or bankruptcy, and participants are general creditors of the Company as to their deferred compensation in the plan. |
Derivative and Hedging Activities (Notes) |
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Derivative Instruments and Hedging Activities Disclosure [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Derivative and Hedging Activities Disclosure | 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 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 December 31, 2016 and 2015, our oil, natural gas and NGL derivative instruments consisted of the following types of instruments:
The estimated fair values of our oil, natural gas and NGL derivative instrument assets (liabilities) as of December 31, 2016 and 2015 are provided below.
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 December 31, 2016 and 2015, 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 are party to cross currency swaps to mitigate our exposure to foreign currency exchange rate fluctuations. During 2016, in connection with debt repurchases, we retired €56 million in aggregate principal amount of our 6.25% Euro-denominated Senior Notes due 2017, and we simultaneously unwound the cross currency swaps for the same principal amount at a cost of $13 million. Under the terms of the remaining cross currency swaps, on each semi-annual interest payment date, the counterparties pay us €8 million and we pay the counterparties $12 million, which yields an annual dollar-equivalent interest rate of 7.491%. Upon maturity of the notes, the counterparties will pay us €246 million and we will pay 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 are designated as cash flow hedges and, because they are 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 do not impact earnings. The fair values of the cross currency swaps are recorded on the consolidated balance sheets as liabilities of $73 million and $52 million as of December 31, 2016 and 2015, respectively. The euro-denominated debt in long-term debt has been adjusted to $258 million as of December 31, 2016, using an exchange rate of $1.0517 to €1.00. 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. In one of these supply contracts, we were committed to supply a minimum of 90 bbtu per day of natural gas through March 2025. In 2016, we sold the long-term natural gas supply contract to a third party for cash proceeds of $146 million, which is included in marketing, gathering and compression revenues as a realized gain. Concurrent with this sale, we reversed the cumulative unrealized gains associated with this supply contract of $280 million. Effect of Derivative Instruments – Consolidated Balance Sheets The following table presents the fair value and location of each classification of derivative instrument included in the consolidated balance sheets as of December 31, 2016 and 2015 on a gross basis and after same-counterparty netting:
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As of December 31, 2016 and 2015, we did not have any cash collateral balances for these derivatives. Effect of Derivative Instruments – Consolidated Statements of Operations The components of oil, natural gas and NGL revenues for the years ended December 31, 2016, 2015 and 2014 are presented below.
The components of marketing, gathering and compression revenues for the years ended December 31, 2016, 2015 and 2014 are presented below.
The components of interest expense for the years ended December 31, 2016, 2015 and 2014 are presented below.
Effect of Derivative Instruments – Accumulated Other Comprehensive Income (Loss) A reconciliation of the changes in accumulated other comprehensive income (loss) in our consolidated statements of stockholders’ equity related to our cash flow hedges is presented below.
Approximately $97 million of the accumulated other comprehensive loss as of December 31, 2016 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 December 31, 2016, we expect to transfer approximately $22 million of net loss included in accumulated other comprehensive income to net income (loss) during the next 12 months. The remaining amounts will be transferred by December 31, 2022. Credit Risk Considerations Our derivative instruments expose us to our counterparties’ credit risk. To mitigate this risk, we enter into derivative contracts only with counterparties that are 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 December 31, 2016, our oil, natural gas and NGL and foreign currency derivative instruments were spread among 12 counterparties. Hedging Arrangements In 2015, we began entering 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. In 2016, certain of our counterparties that are also lenders (or affiliates of our lenders) under our revolving credit facility entered into derivative contracts to be secured by the same collateral that secures the revolving credit facility. This allows us to reduce any letters of credit posted as security with those counterparties. 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, interest rate 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 December 31, 2016 and 2015:
A summary of the changes in the fair values of Chesapeake’s financial assets (liabilities) classified as Level 3 during 2016 and 2015 is presented below.
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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 December 31, 2016:
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Oil and Natural Gas Property Transactions (Notes) |
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Property, Plant and Equipment [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Mergers, Acquisitions and Dispositions Disclosure | 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. 2016 Transactions We conveyed our interests in the Barnett Shale operating area located in north central Texas and received from the buyer aggregate net proceeds of approximately $218 million. We sold approximately 212,000 net developed and undeveloped acres along with other property and equipment. We simultaneously terminated most of our future commitments associated with this asset. In connection with this disposition, we paid $361 million to terminate certain natural gas gathering and transportation agreements and paid $58 million to restructure a long-term sales agreement. We recognized $361 million of expense for the termination of contracts and deferred charges of $58 million for the restructured contract. The deferred charges will be amortized to marketing, gathering and compression revenue over the life of the agreement. We may be required to pay additional amounts in respect of certain title and environmental contingencies. Additionally, we recognized a charge of $284 million in 2016 related to the impairment of other fixed assets sold in the divestiture. We sold the majority of our upstream and midstream assets in the Devonian Shale located in West Virginia, Kentucky and Virginia for proceeds of $140 million. We sold an interest in approximately 1.3 million net acres, retaining all rights below the base of the Kope formation, and approximately 5,300 wells along with related gathering assets, and other property and equipment. Additionally, we recognized an impairment charge of $142 million in 2016 related to other fixed assets sold in the divestiture. In connection with this divestiture, we purchased the underlying interests in one of our remaining VPP transactions for $127 million. All of the acquired interests were conveyed in our divestiture and we no longer have any future obligations related to this VPP. We acquired oil and natural gas properties in the Haynesville Shale for approximately $85 million. We sold certain of our other noncore oil and natural gas properties for net proceeds of approximately $1.048 billion, after post-closing adjustments. In conjunction with certain of these sales, we purchased oil and natural gas interests previously sold to third parties in connection with four of our VPP transactions for approximately $259 million. Substantially all of the acquired interests were part of the asset divestitures discussed above and we no longer have any further commitments or obligations related to these VPPs. The asset divestitures cover various operating areas. 2015 Transactions CHK Cleveland Tonkawa, L.L.C. (CHK C-T) sold all of its oil and natural gas properties to FourPoint Energy, LLC and immediately used the consideration, plus other cash it had on hand, to repurchase and cancel all of CHK C-T’s outstanding preferred shares. In a related transaction, we sold noncore properties adjacent to the CHK C-T properties to FourPoint Energy, LLC for approximately $90 million. Excluding proceeds received from selling additional interests in our joint venture leasehold described under Joint Ventures below, we received proceeds related to divestitures of other noncore oil and natural gas properties of approximately $66 million. 2014 Transactions We sold certain assets in the southern Marcellus Shale and a portion of the eastern Utica Shale to a subsidiary of Southwestern Energy Company for aggregate net proceeds of approximately $4.975 billion. We sold approximately 413,000 net acres and approximately 1,500 wells in northern West Virginia and southern Pennsylvania, of which 435 wells are in the Marcellus or Utica formations, along with related gathering assets and property, plant and equipment. We exchanged interests in approximately 440,000 gross acres in the Powder River Basin in southeastern Wyoming with RKI Exploration & Production, LLC (RKI). Under the agreement, we conveyed to RKI approximately 137,000 net acres and our interest in 67 gross wells with an average working interest of approximately 22% in the northern portion of the Powder River Basin, where RKI was the designated operator. In exchange, RKI conveyed to us approximately 203,000 net acres and its interest in 186 gross wells with an average working interest of 48% in the southern portion of the Powder River Basin, where we were the designated operator. In conjunction with the exchange, we paid RKI approximately $450 million in cash. We sold noncore leasehold interests in the Marcellus Shale to Rice Drilling B LLC, a wholly owned subsidiary of Rice Energy Inc. (NYSE:RICE), for net proceeds of $233 million. We sold noncore leasehold interests, producing properties and 61 wellhead compressor units in South Texas to Hilcorp Energy Company for net proceeds of $133 million. Operating obligations related to VPP #5 were also transferred. See Volumetric Production Payments below. We sold noncore leasehold interests and producing properties in East Texas and Louisiana for net proceeds of approximately $63 million. All commitments related to VPP #6 were also transferred. See Volumetric Production Payments below. Excluding proceeds received from selling additional interests in our joint venture leasehold described under Joint Ventures below, we received proceeds related to divestitures of other noncore oil and natural gas properties of approximately $379 million. Joint Ventures In 2016, 2015 and 2014, we sold interests in additional leasehold we acquired in the Marcellus, Barnett, Utica, Eagle Ford shales and Mid-Continent plays to our joint venture partners for approximately $7 million, $33 million and $33 million, respectively. 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 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. As of December 31, 2016, we had the following VPP outstanding:
The volumes produced on behalf of our VPP buyers during 2016, 2015 and 2014 were as follows:
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The volumes remaining to be delivered on behalf of our VPP buyers as of December 31, 2016 were as follows:
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Spin-Off of Oilfield Services Business (Notes) |
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Discontinued Operations and Disposal Groups [Abstract] | |||||||||||||||||
Disposal Groups, Including Discontinued Operations, Disclosure [Text Block] | Spin-Off of Oilfield Services Business On June 30, 2014, we completed the spin-off of our oilfield services business, which we previously conducted through our indirect, wholly owned subsidiary COO, into SSE, an independent, publicly traded company. Following the close of business on June 30, 2014, we distributed to Chesapeake shareholders one share of SSE common stock and cash in lieu of fractional shares for every 14 shares of Chesapeake common stock held on June 19, 2014, the record date for the distribution. Prior to the completion of the spin-off, we and COO and its affiliates engaged in the following series of transactions:
Following the spin-off, we have no ownership interest in SSE. Therefore, we ceased to consolidate SSE’s assets and liabilities as of the spin-off date. Because we expect to have significant continued involvement associated with SSE’s future operations through the various agreements we entered into in connection with the spin-off, our former oilfield services segment’s historical financial results for periods prior to the spin-off continue to be included in our historical financial results as a component of continuing operations. For segment disclosures, we have labeled our oilfield services segment as “Former Oilfield Services”. See Note 21 for additional information regarding our segments. In 2014, our stockholders’ equity decreased by $270 million, net of $151 million of associated deferred tax liabilities, as a result of the spin-off, and we recognized $15 million of charges associated with the spin-off that are included in restructuring and other termination costs on our consolidated statement of operations. |
Investments (Notes) |
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Equity Method Investments and Joint Ventures [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Equity Method Investments | Investments A summary of our investments, including our approximate ownership percentage and carrying value as of December 31, 2016 and 2015, is presented below.
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Sundrop Fuels, Inc. Sundrop Fuels, Inc. (Sundrop), based in Longmont, Colorado, is a privately held cellulosic biofuels company that is constructing a nonfood biomass-based “green gasoline” plant. Based on our review of the investment in Sundrop, we recognized an other-than-temporary impairment of $119 million in 2016. In 2015, we recorded a $20 million charge related to our share of Sundrop's net loss and $9 million of capitalized interest associated with the construction of Sundrop’s plant. FTS International, Inc. FTS International, Inc. (FTS), based in Fort Worth, Texas, is a privately held company that, through its subsidiaries, provides hydraulic fracturing and other services to oil and gas companies. In 2015, we recorded our equity in FTS’ net losses and other adjustments, prior to intercompany profit eliminations, of $107 million and an accretion adjustment of $44 million related to the excess of our underlying equity in net assets of FTS over our carrying value. Due to the decrease in the oil and natural gas pricing environment, we recognized an other-than-temporary impairment on our investment in FTS of $53 million during 2015. Sold Investments Chaparral Energy, Inc. Chaparral Energy, Inc. (Chaparral), based in Oklahoma City, Oklahoma, is a private independent oil and natural gas company engaged in the production, acquisition and exploitation of oil and natural gas properties. In 2014, we sold all of our interest in Chaparral for net cash proceeds of $209 million. We recorded a $73 million gain related to the sale. Other. In 2014, we sold an equity investment in a natural gas trading and management firm for cash proceeds of $30 million and recorded a loss of $6 million associated with the transaction. |
Variable Interest Entities (Notes) |
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Dec. 31, 2016 | |
Variable Interest Entity, Not Primary Beneficiary, Disclosures [Abstract] | |
Variable Interest Entities Disclosure | 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 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. 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 December 31, 2016, $1 million of cash and cash equivalents, $488 million of proved oil and natural gas properties, $458 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 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. Unconsolidated VIE Mineral Acquisition Company I, L.P. In 2012, MAC-LP, L.L.C., a wholly owned non-guarantor unrestricted subsidiary of Chesapeake, entered into a partnership agreement with KKR Royalty Aggregator LLC (KKR) to form Mineral Acquisition Company I, L.P. The purpose of the partnership was to acquire mineral interests, or royalty interests carved out of mineral interests, in oil and natural gas basins in the continental United States. The partnership was an unconsolidated VIE and the carrying value of our equity investment was $10 million as of December 31, 2015. During 2016, we sold certain mineral interests held outside the partnership for approximately $9 million, and assigned our interest in the partnership to KKR, which eliminated our future commitments to acquire additional mineral interests. As a result of the transaction, we wrote off our equity investment and recognized a $10 million loss which is included in net gain (loss) on sales of investments in our consolidated statements of operations. |
Other Property and Equipment (Notes) |
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Property, Plant and Equipment [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Other Property and Equipment Disclosure | Other Property and Equipment Other Property and Equipment A summary of other property and equipment held for use and the estimated useful lives thereof is as follows:
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Net (Gains) Losses on Sales of Fixed Assets A summary by asset class of (gains) or losses on sales of fixed assets for the years ended December 31, 2016, 2015 and 2014 is as follows:
Natural Gas Compressors. In 2014, we sold 703 compressors to various parties for $693 million and recorded an aggregate gain of $195 million on the sales. Assets Held for Sale We are continuing to pursue the sale of buildings and land located primarily in Oklahoma and West Virginia. Buildings and land are recorded within our other segment. These assets are being actively marketed, and we believe it is probable they will be sold over the next 12 months. As a result, these assets are reflected as held for sale as of December 31, 2016. Oil and natural gas properties that we intend to sell are not presented as held for sale pursuant to the rules governing full cost accounting for oil and gas properties. As of December 31, 2016 and 2015, we had $29 million and $95 million, respectively, of buildings and land, net of accumulated depreciation, classified as assets held for sale on our consolidated balance sheets. |
Impairments (Notes) |
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Asset Impairment Charges Disclosure | 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 2016 and 2015, capitalized costs of oil and natural gas properties exceeded the ceiling, resulting in impairments in the carrying value of our oil and natural gas properties of $2.564 billion and $18.238 billion, respectively. In 2014, we did not have an impairment for our oil and natural gas properties. Cash flow hedges which relate to future periods increased the ceiling test impairment by $176 million in 2015. 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 years ended December 31, 2016, 2015 and 2014 is as follows:
Barnett Shale Exit Costs. In 2016, we conveyed our interests in the Barnett Shale operating area located in north central Texas and simultaneously terminated most of our future commitments associated with this asset. As a result of this transaction, we recognized $361 million of charges related to the termination of natural gas gathering and transportation agreements. We also recognized an impairment charge of $284 million in 2016 related to other fixed assets sold in the divestiture. Devonian Shale Exit Costs. In 2016, we sold the majority of our upstream and midstream assets in the Devonian Shale located in West Virginia and Kentucky. We recognized an impairment charge of $142 million in 2016 related to other fixed assets sold in the divestiture. Natural Gas Compressors. In 2016, we recorded a $13 million impairment related to obsolescence of 205 compressors. Additionally, we recorded an $8 million impairment related to 155 compressors for the difference between the aggregate sales price and carrying value. Oilfield Services Equipment. In 2014, we purchased 31 leased rigs and equipment from various lessors for an aggregate purchase price of $140 million. In connection with these purchases, we paid $8 million in early lease termination costs, which are included in impairments of fixed assets and other in the consolidated statement of operations. In addition, we recognized an impairment loss of approximately $15 million related to leasehold improvements associated with these assets. The drilling rigs and equipment are included in our former oilfield services operating segment. Other. In 2015, we recorded a $47 million loss contingency related to contract disputes. In 2015, we recorded a $22 million impairment of a note receivable as a result of the increased credit risk associated with declining commodity prices. In addition, under the terms of our joint venture agreements (see Note 12), we are required to extend, renew or replace certain expiring joint leasehold, at our cost, to ensure that the net acreage is maintained in certain designated areas. In 2015, we entered into a settlement with Total regarding our acreage maintenance commitment in our Barnett Shale joint venture and accrued a $70 million charge. In 2015, as a result of reductions in our planned drilling activity in response to declines in oil and natural gas prices, we terminated contracts with drilling contractors and incurred charges of $18 million. The contract termination charges are included in our exploration and production operating segment. In 2014, we revised our estimate of our net acreage shortfall with Total under the terms of our Barnett Shale joint venture agreement and recorded a $22 million charge. See Note 4 for additional discussion regarding our net acreage maintenance commitments. Nonrecurring Fair Value Measurements. Fair value measurements for certain of the impairments discussed above 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. |
Restructuring and Other Termination Costs (Notes) |
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Restructuring and Related Activities [Abstract] | |
Restructuring and Related Activities Disclosure | Restructuring and Other Termination Costs Workforce Reductions In 2016, we recognized $6 million of charges related to a reduction of workforce in connection with the restructuring of our compressor manufacturing subsidiary and the reductions of workforce resulting from the conveyance of our interests in the Barnett Shale and Devonian Shale operating areas. On September 29, 2015, we reduced our workforce by approximately 15% as part of an overall plan to reduce costs and better align our workforce with the needs of our business and current oil and natural gas commodity prices. In connection with the reduction, we incurred a total charge of approximately $55 million in 2015 for one-time termination benefits. This charge consisted of $47 million in salary expense and $8 million in other termination benefits. Oilfield Services Spin-Off On June 30, 2014, we completed the spin-off of our oilfield services business through a pro rata distribution of SSE common stock to holders of Chesapeake common stock. In connection with the spin-off, in 2014, we incurred restructuring charges of $15 million, including transaction costs of $17 million, stock-based compensation adjustments of $5 million for Chesapeake employees, credits of $10 million of forfeitures for Seventy Seven Energy employees and $3 million in debt extinguishment costs. See Note 13 for further discussion of the spin-off. Other We recognized credits of $19 million and $8 million in 2015 and 2014, respectively, related to negative fair value adjustments to PSUs granted to former executives of the Company which corresponded to a decrease in the trading price of our common stock. For further discussion of our PSUs, see Note 9. |
Fair Value Measurements (Notes) |
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Fair Value Measurements Disclosure | 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 December 31, 2016 and 2015:
See Note 3 for information regarding fair value measurement of our debt instruments. See Note 11 for information regarding fair value measurement of our derivatives. Nonrecurring Fair Value Measurements See Note 17 regarding nonrecurring fair value measurements. |
Asset Retirement Obligations (Notes) |
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Asset Retirement Obligation Disclosure | Asset Retirement Obligations The components of the change in our asset retirement obligations are shown below.
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Segment Information (Notes) |
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Segment Reporting, Disclosure of Entity's Reportable Segments [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Segment Information Disclosure | Major Customers and Segment Information Sales to BP PLC constituted approximately 10% and 14% of our total revenues (before the effects of hedging) for the years ended December 31, 2016 and 2015, respectively. Sales to Exxon Mobil Corporation constituted approximately 12% of our total revenues (before the effects of hedging) for the year ended December 31, 2014. As of December 31, 2016, 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. In addition, prior to the spin-off of our oilfield services business in June 2014, our former oilfield services operating segment was responsible for drilling, oilfield trucking, oilfield rentals, hydraulic fracturing and other oilfield services for both Chesapeake-operated wells and wells operated by third parties. Our former oilfield services segment’s historical financial results for periods prior to the spin-off continue to be included in our historical financial results as a component of continuing operations, as reflected in the table below. 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 $3.750 billion, $4.372 billion and $8.565 billion for the years ended December 31, 2016, 2015 and 2014, respectively. Revenues generated by our former oilfield services operating segment for work performed for Chesapeake’s exploration and production operating segment were reclassified to the full cost pool based on Chesapeake’s ownership interest. Revenues reclassified totaled $544 million for year ended December 31, 2014. No income was recognized in our consolidated statements of operations related to oilfield services performed for Chesapeake-operated wells. During the 2016 first quarter, we changed the structure of our internal organization to include certain assets in our Exploration and Production reportable segment instead of our Other segment. Accordingly, this change has been reflected through retroactive revision of the segment information as of December 31, 2015 and 2014, as shown in the tables below. The following table presents selected financial information for Chesapeake’s operating segments:
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Recently Issued Accounting Standards (Notes) |
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Dec. 31, 2016 | |
New Accounting Pronouncements and Changes in Accounting Principles [Abstract] | |
Schedule of Adoption of New Accounting Pronouncements | 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, 2016, with early application not permitted. In July 2015, the FASB approved a one-year deferral of the effective date as well as permission to early adopt the new revenue recognition standard as of the original effective date. 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 evaluating the impact of this guidance on our consolidated financial statements and related disclosures. In August 2014, the FASB issued updated guidance that requires management, for each annual and interim reporting period, to evaluate whether there are conditions or events, considered in the aggregate, that raise substantial doubt about the entity’s ability to continue as a going concern within one year after the date that the consolidated financial statements are issued. If management concludes that conditions or events raise substantial doubt about the entity’s ability to continue as a going concern, certain disclosures are required to be made within the footnotes to the consolidated financial statements. The amendments in this update are effective for annual periods ending after December 15, 2016, and interim periods thereafter, with early adoption permitted. We adopted this guidance as of December 31, 2016, and it had no impact on our 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 guidance for improvements to employee share-based payment accounting to simplify the accounting for share-based compensation. The new standard requires all excess tax benefits and reductions from differences between the deduction for tax purposes and the compensation cost recorded for financial reporting purposes be recognized as income tax expense or benefit in the income statement and not recognized as additional paid-in capital. The new standard also requires all excess tax benefits and deficiencies to be classified as operating activity within the statement of cash flows. For public business entities, the amendments are effective for annual periods, including interim periods within those annual periods, beginning after December 15, 2016. Early adoption is permitted in any interim or annual period, with any adjustments reflected as of the beginning of the fiscal year of adoption. We have elected to early adopt the amendments effective January 1, 2016. The cumulative-effect adjustment to retained earnings for all excess tax benefits not previously recognized as of the beginning period is fully offset by a corresponding change in the valuation allowance resulting in no change to our consolidated financial statements. The implementation of this guidance did not have a material impact 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. We are evaluating the impact of this guidance on our consolidated financial statements and related disclosures. |
Subsequent Events Subsequent Events (Notes) |
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Dec. 31, 2016 | |
Subsequent Events [Abstract] | |
Subsequent Events [Text Block] | Subsequent Events In January 2017, we purchased and retired approximately $287 million principal amount of our outstanding contingent convertible senior notes and $2 million principal amount of our outstanding senior notes for an aggregate of $286 million pursuant to tender offers. In January 2017, we completed private exchanges of an aggregate of approximately 10.0 million shares of our common stock for (i) 150,948 shares of 5.00% Cumulative Convertible Preferred Stock (Series 2005B), (ii) 72,600 shares of 5.75% Cumulative Convertible Preferred Stock and (iii) 12,500 shares of 5.75% Cumulative Convertible Preferred Stock (Series A). In January 2017, we sold a portion of our acreage and producing properties in our Haynesville Shale operating area in northern Louisiana for approximately $450 million, subject to certain customary post-closing adjustments. Included in the sale were approximately 78,000 net acres. The sale also included 250 wells currently producing approximately 30 mmcf of gas per day. In January 2017, we redeemed our $133 million principal amount of outstanding 6.5% Senior Notes due 2017. In January 2017, we repurchased in the open market approximately $221 million principal amount of our outstanding debt scheduled to mature or that could be put to us in 2018 and 2020 for $224 million. In February 2017, we reinstated the payment of dividends on each series of our outstanding convertible preferred stock and paid our dividends in arrears. In February 2017, we sold a portion of our acreage and producing properties in our Haynesville Shale operating area in northern Louisiana for approximately $465 million, subject to certain customary post-closing adjustments. Included in the sale were approximately 41,500 net acres. The sale also included 326 operated and non-operated wells currently producing approximately 50 mmcf of gas per day. In February 2017, we paid $290 million to assign an oil transportation agreement. This assignment is expected to reduce our future oil transportation commitments by approximately $450 million. The assignment is effective April 1, 2017. In addition, we terminated future natural gas transportation commitments related to divested assets of approximately $110 million for a cash payment of approximately $100 million. This termination was effective March 1, 2017. |
Basis of Presentation and Significant Accounting Policies (Policies) |
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Accounting Policies [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Basis of Accounting, Policy | Basis of Presentation The accompanying consolidated financial statements of Chesapeake 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. |
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Accounting Estimates, Policy | Accounting Estimates The preparation of financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the dates of the financial statements and the reported amounts of revenues and expenses during the reporting periods. Actual results could differ from those estimates. Estimates of oil and natural gas reserves and their values, future production rates and future costs and expenses are the most significant of our estimates. The accuracy of any reserve estimate is a function of the quality of data available and of engineering and geological interpretation and judgment. In addition, estimates of reserves may be revised based on actual production, results of subsequent exploration and development activities, recent commodity prices, operating costs and other factors. These revisions could materially affect our financial statements. The volatility of commodity prices results in increased uncertainty inherent in these estimates and assumptions. Changes in oil, natural gas or NGL prices could result in actual results differing significantly from our estimates. |
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Consolidation, Policy | Consolidation Chesapeake consolidates entities in which we have a controlling financial interest. We consolidate subsidiaries in which we hold, directly or indirectly, more than 50% of the voting rights and variable interest entities (VIEs) in which Chesapeake is the primary beneficiary. We use the equity method of accounting to record our net interests where Chesapeake has the ability to exercise significant influence through its investment. Under the equity method, our share of net income (loss) is included in our consolidated statements of operations according to our equity ownership or according to the terms of the applicable governing instrument. See Note 14 for further discussion of our investments. Undivided interests in oil and natural gas properties are consolidated on a proportionate basis. Noncontrolling Interests Noncontrolling interests represent third-party equity ownership in certain of our consolidated subsidiaries and are presented as a component of equity. See Note 8 for further discussion of noncontrolling interests. |
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Noncontrolling Interests, Policy | Consolidation Chesapeake consolidates entities in which we have a controlling financial interest. We consolidate subsidiaries in which we hold, directly or indirectly, more than 50% of the voting rights and variable interest entities (VIEs) in which Chesapeake is the primary beneficiary. We use the equity method of accounting to record our net interests where Chesapeake has the ability to exercise significant influence through its investment. Under the equity method, our share of net income (loss) is included in our consolidated statements of operations according to our equity ownership or according to the terms of the applicable governing instrument. See Note 14 for further discussion of our investments. Undivided interests in oil and natural gas properties are consolidated on a proportionate basis. Noncontrolling Interests Noncontrolling interests represent third-party equity ownership in certain of our consolidated subsidiaries and are presented as a component of equity. See Note 8 for further discussion of noncontrolling interests. |
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Variable Interest Entity, Policy | Variable Interest Entities VIEs are entities that, by design, either (i) lack sufficient equity to permit the entity to finance its activities independently, or (ii) have equity holders that do not have the power to direct the activities of the entity that most significantly impact its economic performance, the obligation to absorb the entity’s losses, or the right to receive the entity’s residual returns. We consolidate a VIE when we are the primary beneficiary, which is the party that has both (i) the power to direct the activities that most significantly impact the VIE’s economic performance and (ii) through its interests in the VIE, the obligation to absorb losses or the right to receive benefits from the VIE that could potentially be significant to the VIE. We continually monitor our consolidated VIE to determine if any events have occurred that could cause the primary beneficiary to change. See Note 15 for further discussion of VIEs. 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 qualitative analysis of the entity’s design, organizational structure, primary decision makers and relevant agreements. |
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Cash and Cash Equivalents, Policy | Cash and Cash Equivalents For purposes of the consolidated financial statements, Chesapeake considers investments in all highly liquid instruments with original maturities of three months or less at the date of purchase to be cash equivalents. Accounts Payable Included in accounts payable as of December 31, 2016 and 2015 are liabilities of approximately $77 million and $60 million, respectively, representing the amount by which checks issued, but not yet presented to our banks for collection, exceeded balances in applicable bank accounts. |
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Accounts Receivable, Policy | Accounts Receivable Our accounts receivable are primarily from purchasers of oil, natural gas and NGL and from exploration and production companies that own interests in properties we operate. This industry concentration could affect our overall exposure to credit risk, either positively or negatively, because our purchasers and joint working interest owners may be similarly affected by changes in economic, industry or other conditions. We monitor the creditworthiness of all our counterparties and we generally require letters of credit or parent guarantees for receivables from parties which are judged to have sub-standard credit, unless the credit risk can otherwise be mitigated. We utilize an allowance method in accounting for bad debt based on historical trends in addition to specifically identifying receivables that we believe may be uncollectible. During 2016, 2015 and 2014, we recognized $10 million, $4 million and $2 million of bad debt expense related to potentially uncollectible receivables. Accounts receivable as of December 31, 2016 and 2015 are detailed below.
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Oil and Natural Gas Properties, Policy | Oil and Natural Gas Properties Chesapeake follows the full cost method of accounting under which all costs associated with oil and natural gas property acquisition, exploration and development activities are capitalized. We capitalize internal costs that can be directly identified with these activities and do not capitalize any costs related to production, general corporate overhead or similar activities (see Supplementary Information – Supplemental Disclosures About Oil, Natural Gas and NGL Producing Activities). Capitalized costs are amortized on a composite unit-of-production method based on proved oil and natural gas reserves. Estimates of our proved reserves as of December 31, 2016 were prepared by an independent engineering firm and Chesapeake's internal staff. Approximately 70% by volume and 83% by value of these proved reserves estimates as of December 31, 2016 were prepared by an independent engineering firm. In addition, our internal engineers review and update our reserves on a quarterly basis. Proceeds from the sale of oil and natural gas properties are accounted for as reductions of capitalized costs unless these sales involve a significant change in proved reserves and significantly alter the relationship between costs and proved reserves, in which case a gain or loss is recognized. The costs of unproved properties are excluded from amortization until the properties are evaluated. We review all of our unproved properties quarterly to determine whether or not and to what extent proved reserves have been assigned to the properties and otherwise if impairment has occurred. Unproved properties are grouped by major prospect area in circumstances where individual property costs are not significant. In addition, we analyze our unproved leasehold and transfer to proved properties that portion of our leasehold that expired in the quarter, or leasehold that is no longer part of our development strategy and will be abandoned. The table below sets forth the cost of unproved properties excluded from the amortization base as of December 31, 2016 and the year in which the associated costs were incurred.
We also review, on a quarterly basis, the carrying value of our oil and natural gas properties under the full cost accounting rules of the Securities and Exchange Commission (SEC). This quarterly review is referred to as a ceiling test. 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 oil and natural gas derivatives designated as cash flow hedges) less estimated future expenditures to be incurred in developing and producing the proved reserves, less any related income tax effects. The ceiling test calculation uses costs as of the end of the applicable quarterly period and the unweighted arithmetic average of oil, natural gas and NGL prices on the first day of each month within the 12-month period prior to the ending date of the quarterly period. These prices are utilized except where different prices are fixed and determinable from applicable contracts for the remaining term of those contracts, including the effects of derivatives designated as cash flow hedges. As of December 31, 2016, none of our open derivative instruments were designated as cash flow hedges. Our oil and natural gas hedging activities are discussed in Note 11. Two primary factors impacting the ceiling test are reserves levels and oil, natural gas and NGL prices, and their associated impact on the present value of estimated future net revenues. Revisions to estimates of oil and natural gas reserves and/or an increase or decrease in prices can have a material impact on the present value of our estimated future net revenues. Any excess of the net book value over the ceiling is written off as an expense. We account for seismic costs as part of our oil and natural gas properties. Exploration costs may be incurred both before acquiring the related property and after acquiring the property. Further, exploration costs include, among other things, geological and geophysical studies and salaries and other expenses of geologists, geophysical crews and others conducting those studies. These costs are capitalized as incurred. The Company reviews its unproved properties and associated seismic costs quarterly to determine whether impairment has occurred. To the extent that seismic costs cannot be directly associated with specific unproved properties, they are included in the amortization base as incurred. |
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Other Property and Equipment, Policy | Other Property and Equipment Other property and equipment consists primarily of natural gas compressors, buildings and improvements, land, vehicles, computers and office equipment. We have no remaining oilfield services equipment as a result of the spin-off of our oilfield services business in 2014, as discussed in Note 13. Major renewals and betterments are capitalized while the costs of repairs and maintenance are charged to expense as incurred. The costs of assets retired or otherwise disposed of and the applicable accumulated depreciation are removed from the accounts, and the resulting gain or loss is reflected in operating expenses. See Note 16 for further discussion of our gains and losses on the sales of other property and equipment for the years ended 2016, 2015 and 2014 and a summary of our other property and equipment held for sale as of December 31, 2016 and 2015. Other property and equipment costs, excluding land, are depreciated on a straight-line basis. Realization of the carrying value of other property and equipment is reviewed for possible impairment whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. Assets are determined to be impaired if a forecast of undiscounted estimated future net operating cash flows directly related to the asset, including any disposal value, is less than the carrying amount of the asset. If any asset is determined to be impaired, the loss is measured as the amount by which the carrying amount of the asset exceeds its fair value. An estimate of fair value is based on the best information available, including prices for similar assets and discounted cash flow. During 2016, 2015 and 2014, we determined that certain of our property and equipment was being carried at values that were not recoverable and in excess of fair value. See Note 17 for further discussion of these impairments. |
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Capitalized Interest, Policy | Capitalized Interest Interest from external borrowings is capitalized on significant investments in unproved properties and major development projects until the asset is ready for service using the weighted average borrowing rate of outstanding borrowings. Capitalized interest is determined by multiplying our weighted-average borrowing cost on debt by the average amount of qualifying costs incurred. Capitalized interest is depreciated over the useful lives of the assets in the same manner as the depreciation of the underlying asset. |
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Accounts Payable, Policy | Cash and Cash Equivalents For purposes of the consolidated financial statements, Chesapeake considers investments in all highly liquid instruments with original maturities of three months or less at the date of purchase to be cash equivalents. Accounts Payable Included in accounts payable as of December 31, 2016 and 2015 are liabilities of approximately $77 million and $60 million, respectively, representing the amount by which checks issued, but not yet presented to our banks for collection, exceeded balances in applicable bank accounts. |
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Debt Issuance Costs, Policy | Debt Issuance Costs Included in other long-term assets are costs associated with the issuance and amendments of our revolving credit facility. The remaining unamortized issuance costs as of December 31, 2016 and 2015, totaled $32 million and $31 million, respectively, and are being amortized over the life of credit facility using the effective interest method. Included in debt are costs associated with the issuance of our senior notes. The remaining unamortized issuance costs as of December 31, 2016 and 2015, totaled $64 million and $43 million, respectively, and are being amortized over the life of the senior notes using the effective interest method. |
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Environmental Remediation Costs, Policy | Environmental Remediation Costs Chesapeake records environmental reserves for estimated remediation costs related to existing conditions from past operations when the responsibility to remediate is probable and the costs can be reasonably estimated. Expenditures that create future benefits or contribute to future revenue generation are capitalized. |
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Asset Retirement Obligations, Policy | Asset Retirement Obligations We recognize liabilities for obligations associated with the retirement of tangible long-lived assets that result from the acquisition, construction and development of the assets. We recognize the fair value of a liability for a retirement obligation in the period in which the liability is incurred. For oil and natural gas properties, this is the period in which an oil or natural gas well is acquired or drilled. The liability is then accreted each period until the liability is settled or the well is sold, at which time the liability is removed. The related asset retirement cost is capitalized as part of the carrying amount of our oil and natural gas properties. See Note 20 for further discussion of asset retirement obligations. |
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Revenue Recognition, Policy | Revenue Recognition Oil, Natural Gas and NGL Sales. Revenue from the sale of oil, natural gas and NGL is recognized when title passes, net of royalties due to third parties. Natural Gas Imbalances. We follow the sales method of accounting for our natural gas revenue whereby we recognize sales revenue on all natural gas sold to our purchasers, regardless of whether the sales are proportionate to our ownership in the property. An asset or a liability is recognized to the extent that we have an imbalance in excess of the remaining estimated natural gas reserves on the underlying properties. The natural gas imbalance net liability position as of December 31, 2016 and 2015, was $9 million and $10 million, respectively. Marketing, Gathering and Compression Sales. Chesapeake takes title to the oil, natural gas and NGL it purchases from other interest owners at defined delivery points and delivers the product to third parties, at which time revenues are recorded. In addition, we periodically enter into a variety of oil, natural gas and NGL purchase and sale contracts with third parties for various commercial purposes, including credit risk mitigation and to help meet certain of our pipeline delivery commitments. In circumstances where we act as a principal rather than an agent, Chesapeake's results of operations related to its oil, natural gas and NGL marketing activities are presented on a gross basis. Gathering and compression revenues consist of fees billed to other interest owners in operated wells or third-party producers for the gathering, treating and compression of natural gas. Revenues are recognized when the service is performed and are based upon non-regulated rates and the related gathering, treating and compression volumes. All significant intercompany accounts and transactions have been eliminated. Oilfield Services Revenue. Prior to the spin-off of our oilfield services business in June 2014, we reported oilfield services revenue. Our former oilfield services operating segment was responsible for contract drilling, hydraulic fracturing, rentals, trucking and other oilfield services operations for both Chesapeake-operated wells and wells operated by third parties. Revenues were recognized upon completion stages for our contract drilling, hydraulic fracturing and other oilfield services. Revenue was recognized ratably over the term of the rental for our oilfield rental services. Oilfield trucking services revenue was recognized as services were performed. |
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Fair Value Measurements, Policy | Fair Value Measurements Certain financial instruments are reported at fair value on our consolidated balance sheets. Under fair value measurement accounting guidance, fair value is defined as the amount that would be received from the sale of an asset or paid for the transfer of a liability in an orderly transaction between market participants (i.e., an exit price). To estimate an exit price, a three-level hierarchy is used. The fair value hierarchy prioritizes the inputs, which refer broadly to assumptions market participants would use in pricing an asset or a liability, into three levels. Level 1 inputs are unadjusted quoted prices in active markets for identical assets and liabilities and have the highest priority. Level 2 inputs are inputs other than quoted prices within Level 1 that are observable for the asset or liability, either directly or indirectly. Level 3 inputs are unobservable inputs for the asset or liability and have the lowest priority. The valuation techniques that may be used to measure fair value include a market approach, an income approach and a cost approach. A market approach uses prices and other relevant information generated by market transactions involving identical or comparable assets or liabilities. An income approach uses valuation techniques to convert future amounts to a single present amount based on current market expectations, including present value techniques, option-pricing models and the excess earnings method. The cost approach is based on the amount that currently would be required to replace the service capacity of an asset (replacement cost). The carrying values of financial instruments comprising cash and cash equivalents, accounts payable and accounts receivable approximate fair values due to the short-term maturities of these instruments. |
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Derivatives, Policy | Derivatives Derivative instruments are recorded on our consolidated balance sheets as derivative assets or derivative liabilities at fair value, and changes in a derivative’s fair value are recognized currently in earnings unless specific hedge accounting criteria are followed. For qualifying commodity derivative instruments designated as cash flow hedges, changes in fair value, to the extent the hedge is effective, are recognized in other comprehensive income until the hedged item is recognized in earnings. Any change in fair value resulting from ineffectiveness is recognized immediately in earnings. Locked-in gains and losses of settled cash flow hedges are recorded in accumulated other comprehensive income and are transferred to earnings in the month of production. Changes in the fair value of interest rate derivative instruments designated as fair value hedges are recorded on the consolidated balance sheets as assets or liabilities, and the debt's carrying value amount is adjusted by the change in the fair value of the debt subsequent to the initiation of the derivative. Differences between the changes in the fair values of the hedged item and the derivative instrument, if any, represent hedge ineffectiveness and are recognized currently in earnings. Locked-in gains and losses related to settled fair value hedges are amortized as an adjustment to interest expense over the remaining term of the related debt instrument. We have elected not to designate any of our qualifying commodity and interest rate derivatives as cash flow or fair value hedges. Therefore, changes in fair value of these derivatives that occur prior to their maturity (i.e., temporary fluctuations in value) are recognized in our consolidated statements of operations within oil, natural gas and NGL sales and interest expense, respectively. 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 changes in fair value of the embedded derivative and the settlements are recognized in our consolidated statements of operations within marketing, gathering and compression sales. Derivative instruments reflected as current in the consolidated balance sheets represent the estimated fair value of derivatives scheduled to settle over the next twelve months based on market prices/rates as of the respective balance sheet dates. Cash settlements of our derivative instruments are generally classified as operating cash flows unless the derivatives are deemed to contain, for accounting purposes, a significant financing element at contract inception, in which case these cash settlements are classified as financing cash flows in the accompanying consolidated statement of cash flows. All of our derivative instruments are subject to master netting arrangements by contract type (i.e., commodity, interest rate and cross currency contracts) which provide for the offsetting of asset and liability positions within each contract type, as well as related cash collateral if applicable, by counterparty. Therefore, we net the value of our derivative instruments by contract type with the same counterparty in the accompanying consolidated balance sheets. We have established the fair value of our derivative instruments using established index prices, volatility curves and discount factors. These estimates are compared to our counterparty values for reasonableness. 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. Derivative transactions are 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. See Note 11 for further discussion of our derivative instruments. |
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Share-Based Compensation, Policy | Share-Based Compensation Chesapeake’s share-based compensation program consists of restricted stock, stock options and performance share units granted to employees and restricted stock granted to non-employee directors under our Long Term Incentive Plan. We recognize in our financial statements the cost of employee services received in exchange for restricted stock and stock options based on the fair value of the equity instruments as of the grant date. For employees, this value is amortized over the vesting period, which is generally three or four years from the grant date. For directors, although restricted stock grants vest over three years, this value is recognized immediately as there is a non-substantive service condition for vesting. Because performance share units can only be settled in cash, they are classified as a liability in our consolidated financial statements and are measured at fair value as of the grant date and re-measured at fair value at the end of each reporting period. These fair value adjustments are recognized as general and administrative expense in the consolidated statements of operations. To the extent compensation expense relates to employees directly involved in the acquisition of oil and natural gas leasehold and exploration and development activities, these amounts are capitalized to oil and natural gas properties. Amounts not capitalized to oil and natural gas properties are recognized as general and administrative expenses, oil, natural gas and NGL production expenses, or marketing, gathering and compression expenses, based on the employees involved in those activities. See Note 9 for further discussion of share-based compensation. |
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Reclassifications and Revisions, Policy | Reclassifications and Revisions In April 2015, the Financial Accounting Standards Board (FASB) issued guidance that requires debt issuance costs related to term debt to be presented in the balance sheet as a direct reduction from the associated debt liability. This standard requires retrospective application and is effective for annual reporting periods beginning after December 15, 2015. This change in accounting principle is preferable since it allows both debt issuance costs and debt discounts to be presented similarly in the consolidated balance sheets as a direct reduction from the face amount of our debt balances. A retrospective change to our consolidated balance sheet as of December 31, 2015, as previously presented, is required pursuant to the guidance. The retrospective adjustment to the December 31, 2015 consolidated balance sheet is shown below.
In addition, certain revisions have been made to the fair value of debt table included in Note 3 to conform to the presentation used for our 2016 disclosure. The 8.00% Senior Secured Second Lien Notes due 2022 were previously classified as Level 1 and should have been classified as Level 2, as these senior notes are not exchange-traded. The following table reflects the revisions made.
__________________________________________ (a) The difference in the carrying amount is due to the debt issuance costs retrospective change noted above. |
Variable Interest Entities Variable Interest Entities (Policies) |
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Dec. 31, 2016 | |
Variable Interest Entity, Not Primary Beneficiary, Disclosures [Abstract] | |
Variable Interest Entity, Policy | Variable Interest Entities VIEs are entities that, by design, either (i) lack sufficient equity to permit the entity to finance its activities independently, or (ii) have equity holders that do not have the power to direct the activities of the entity that most significantly impact its economic performance, the obligation to absorb the entity’s losses, or the right to receive the entity’s residual returns. We consolidate a VIE when we are the primary beneficiary, which is the party that has both (i) the power to direct the activities that most significantly impact the VIE’s economic performance and (ii) through its interests in the VIE, the obligation to absorb losses or the right to receive benefits from the VIE that could potentially be significant to the VIE. We continually monitor our consolidated VIE to determine if any events have occurred that could cause the primary beneficiary to change. See Note 15 for further discussion of VIEs. 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 qualitative analysis of the entity’s design, organizational structure, primary decision makers and relevant agreements. |
Recently Issued Accounting Standards (Policies) |
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New Accounting Pronouncements and Changes in Accounting Principles [Abstract] | |
New Accounting Pronouncements, Policy | 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, 2016, with early application not permitted. In July 2015, the FASB approved a one-year deferral of the effective date as well as permission to early adopt the new revenue recognition standard as of the original effective date. 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 evaluating the impact of this guidance on our consolidated financial statements and related disclosures. In August 2014, the FASB issued updated guidance that requires management, for each annual and interim reporting period, to evaluate whether there are conditions or events, considered in the aggregate, that raise substantial doubt about the entity’s ability to continue as a going concern within one year after the date that the consolidated financial statements are issued. If management concludes that conditions or events raise substantial doubt about the entity’s ability to continue as a going concern, certain disclosures are required to be made within the footnotes to the consolidated financial statements. The amendments in this update are effective for annual periods ending after December 15, 2016, and interim periods thereafter, with early adoption permitted. We adopted this guidance as of December 31, 2016, and it had no impact on our 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 guidance for improvements to employee share-based payment accounting to simplify the accounting for share-based compensation. The new standard requires all excess tax benefits and reductions from differences between the deduction for tax purposes and the compensation cost recorded for financial reporting purposes be recognized as income tax expense or benefit in the income statement and not recognized as additional paid-in capital. The new standard also requires all excess tax benefits and deficiencies to be classified as operating activity within the statement of cash flows. For public business entities, the amendments are effective for annual periods, including interim periods within those annual periods, beginning after December 15, 2016. Early adoption is permitted in any interim or annual period, with any adjustments reflected as of the beginning of the fiscal year of adoption. We have elected to early adopt the amendments effective January 1, 2016. The cumulative-effect adjustment to retained earnings for all excess tax benefits not previously recognized as of the beginning period is fully offset by a corresponding change in the valuation allowance resulting in no change to our consolidated financial statements. The implementation of this guidance did not have a material impact 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. We are evaluating the impact of this guidance on our consolidated financial statements and related disclosures. |
Basis of Presentation and Significant Accounting Policies (Tables) |
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Schedule of Accounts, Notes, Loans and Financing Receivable | Accounts receivable as of December 31, 2016 and 2015 are detailed below.
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Schedule of Capitalized Costs of Unproved Properties Excluded from Amortization | The table below sets forth the cost of unproved properties excluded from the amortization base as of December 31, 2016 and the year in which the associated costs were incurred.
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Schedule of Adoption of New Accounting Pronouncements, Debt Issuance Costs | The retrospective adjustment to the December 31, 2015 consolidated balance sheet is shown below.
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Schedule of Revisions to Fair Value of Debt | The following table reflects the revisions made.
__________________________________________ (a) The difference in the carrying amount is due to the debt issuance costs retrospective change noted above. |
Earnings Per Share (Tables) |
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Earnings Per Share, Basic and Diluted, Other Disclosures [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Antidilutive Securities Excluded From Computation Of Earnings Per Share | For the years ended December 31, 2016, 2015 and 2014, shares of common stock for the following dilutive securities were excluded from the calculation of diluted EPS as the effect was antidilutive.
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Schedule of Earnings Per Share, Basic and Diluted | A reconciliation of basic EPS and diluted EPS for the year ended December 31, 2014 is as follows:
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Debt (Tables) |
12 Months Ended | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Debt Disclosure [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Schedule of Debt | Our long-term debt consisted of the following as of December 31, 2016 and 2015:
Optional Conversion by Holders. At the holder’s option, prior to maturity under certain circumstances, 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, beginning with the first quarter of 2017. Convertibility based on common stock price is measured quarterly. 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 year ended December 31, 2016. 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 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. 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 fourth quarter of 2016, 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 first 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 years ended December 31, 2016, 2015 and 2014. 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:
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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Schedule of Maturities of Long-term Debt | Total principal amount of debt maturities, using the earliest demand repurchase date for contingent convertible senior notes, for the five years ended after December 31, 2016 and thereafter are as follows:
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Schedule of Carrying Values and Estimated Fair Values of Debt Instruments | Fair value is compared to the carrying value, excluding the impact of interest rate derivatives, in the table below.
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Contingencies and Commitments (Tables) |
12 Months Ended | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Dec. 31, 2016 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Commitments and Contingencies Disclosure [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Operating Leases | As of December 31, 2016, the aggregate undiscounted minimum future payments under these drilling service commitments are detailed below.
The aggregate undiscounted commitments under our gathering, processing and transportation agreements, excluding any proportionate share of these costs from working interest and royalty interest owners, credits for third-party volumes or future costs under cost-of-service agreements, are presented below.
The aggregate undiscounted minimum future lease payments are presented below.
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Gathering, Processing and Transportation Commitments | As of December 31, 2016, the aggregate undiscounted minimum future payments under these drilling service commitments are detailed below.
The aggregate undiscounted commitments under our gathering, processing and transportation agreements, excluding any proportionate share of these costs from working interest and royalty interest owners, credits for third-party volumes or future costs under cost-of-service agreements, are presented below.
The aggregate undiscounted minimum future lease payments are presented below.
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Drilling Contracts | As of December 31, 2016, the aggregate undiscounted minimum future payments under these drilling service commitments are detailed below.
The aggregate undiscounted commitments under our gathering, processing and transportation agreements, excluding any proportionate share of these costs from working interest and royalty interest owners, credits for third-party volumes or future costs under cost-of-service agreements, are presented below.
The aggregate undiscounted minimum future lease payments are presented below.
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Other Liabilities (Tables) |
12 Months Ended | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Dec. 31, 2016 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Other Liabilities Disclosure [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Other Current Liabilities | Other current liabilities as of December 31, 2016 and 2015 are detailed below.
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Other Long-Term Liabilities | Other long-term liabilities as of December 31, 2016 and 2015 are detailed below.
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Income Taxes Income Taxes (Tables) |
12 Months Ended | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Income Tax Disclosure [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Schedule of Components of Income Tax Expense (Benefit) [Table Text Block] | The components of the income tax provision (benefit) for each of the periods presented below are as follows:
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Schedule of Effective Income Tax Rate Reconciliation [Table Text Block] | The effective income tax expense (benefit) differed from the computed "expected" federal income tax expense on earnings before income taxes for the following reasons:
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Schedule of Deferred Tax Assets and Liabilities [Table Text Block] | The tax-effected temporary differences and tax loss carryforwards which comprise deferred taxes are as follows:
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Schedule of Unrecognized Tax Benefits Roll Forward [Table Text Block] | A reconciliation of the beginning and ending balances of unrecognized tax benefits is as follows:
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Equity (Tables) |
12 Months Ended | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Equity [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Schedule of Common Stock Outstanding Roll Forward | A summary of the changes in our common shares issued for the years ended December 31, 2016, 2015 and 2014 is detailed below.
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Schedule of Stock by Class,Preferred Stock Conversion Terms | Following is a summary of our preferred stock, including the primary conversion terms as of December 31, 2016:
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Outstanding shares of our preferred stock for the years ended December 31, 2016, 2015 and 2014 are detailed below.
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Schedule of Stock by Class,Preferred Stock Shares Outstanding | Following is a summary of our preferred stock, including the primary conversion terms as of December 31, 2016:
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Outstanding shares of our preferred stock for the years ended December 31, 2016, 2015 and 2014 are detailed below.
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Schedule of Dividends Payable | Our preferred stock dividends for the year ended December 31, 2016 (paid in arrears) are detailed below.
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Schedule of Accumulated Other Comprehensive Income (Loss) | For the years ended December 31, 2016 and 2015, changes in accumulated other comprehensive income (loss) for cash flow hedges, net of tax, are detailed below.
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Reclassification out of Accumulated Other Comprehensive Income | For the years ended December 31, 2016 and 2015, amounts reclassified from accumulated other comprehensive income (loss), net of tax, into the consolidated statements of operations are detailed below.
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Distributions Made to Limited Partner, by Distribution [Table Text Block] | For the years ended December 31, 2016, 2015 and 2014, the Trust declared and paid the following distributions:
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Share-Based Compensation (Tables) |
12 Months Ended | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Disclosure of Compensation Related Costs, Share-based Payments [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Schedule of Share-Based Compensation, Restricted Stock and Restricted Stock Units Activity | A summary of the changes in unvested restricted stock during 2016, 2015 and 2014 is presented below.
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Equity-Classified Share-Based Payment Award Valuation Assumptions | The Company used the following weighted average assumptions to estimate the grant date fair value of the stock options granted in 2016.
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.
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Schedule of Share-Based Compensation, Stock Options, Activity | The following table provides information related to stock option activity for 2016, 2015 and 2014.
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Equity-Classified Stock-Based Compensation | We recognized the following compensation costs (credits) related to PSUs for the years ended December 31, 2016, 2015 and 2016.
We recognized the following compensation costs related to restricted stock and stock options for the years ended December 31, 2016, 2015 and 2014.
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Liability-Classified Share-Based Payment Award Valuation Assumptions | The Company used the following weighted average assumptions to estimate the grant date fair value of the stock options granted in 2016.
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.
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Schedule of Nonvested Performance-based Units Activity | The following table presents a summary of our 2016, 2015 and 2014 PSU awards.
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Liability-Classified Stock-Based Compensation | We recognized the following compensation costs (credits) related to PSUs for the years ended December 31, 2016, 2015 and 2016.
We recognized the following compensation costs related to restricted stock and stock options for the years ended December 31, 2016, 2015 and 2014.
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Derivative and Hedging Activities (Tables) |
12 Months Ended | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Derivative Instruments and Hedging Activities Disclosure [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Schedule of Notional Amounts of Outstanding Derivative Positions | The estimated fair values of our oil, natural gas and NGL derivative instrument assets (liabilities) as of December 31, 2016 and 2015 are provided below.
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Schedule Of Derivative Instruments In Condensed Consolidated Balance Sheets | The following table presents the fair value and location of each classification of derivative instrument included in the consolidated balance sheets as of December 31, 2016 and 2015 on a gross basis and after same-counterparty netting:
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Schedule of Derivative Instruments, Natural Gas and Oil Sales | The components of marketing, gathering and compression revenues for the years ended December 31, 2016, 2015 and 2014 are presented below.
The components of oil, natural gas and NGL revenues for the years ended December 31, 2016, 2015 and 2014 are presented below.
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Schedule of Derivative Instruments, Marketing, Gathering and Compression Sales | The components of marketing, gathering and compression revenues for the years ended December 31, 2016, 2015 and 2014 are presented below.
The components of oil, natural gas and NGL revenues for the years ended December 31, 2016, 2015 and 2014 are presented below.
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Interest Income And Interest Expense Disclosure | The components of interest expense for the years ended December 31, 2016, 2015 and 2014 are presented below.
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Schedule of Cash Flow Hedges Included in Accumulated Other Comprehensive Income (Loss) | A reconciliation of the changes in accumulated other comprehensive income (loss) in our consolidated statements of stockholders’ equity related to our cash flow hedges is presented below.
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Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis | The following table provides information for financial assets (liabilities) measured at fair value on a recurring basis as of December 31, 2016 and 2015:
A summary of the changes in the fair values of Chesapeake’s financial assets (liabilities) classified as Level 3 during 2016 and 2015 is presented below.
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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 December 31, 2016 and 2015:
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Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation | The following table provides information for financial assets (liabilities) measured at fair value on a recurring basis as of December 31, 2016 and 2015:
A summary of the changes in the fair values of Chesapeake’s financial assets (liabilities) classified as Level 3 during 2016 and 2015 is presented below.
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Fair Value Inputs, Assets, Quantitative Information | 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 December 31, 2016:
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Oil and Natural Gas Property Transactions (Tables) |
12 Months Ended | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Dec. 31, 2016 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Property, Plant and Equipment [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
VPP Transactions | As of December 31, 2016, we had the following VPP outstanding:
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VPP Volumes Produced During Period | The volumes produced on behalf of our VPP buyers during 2016, 2015 and 2014 were as follows:
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VPP Volumes Remaining to Be Delivered | The volumes remaining to be delivered on behalf of our VPP buyers as of December 31, 2016 were as follows:
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Investments Investments (Tables) |
12 Months Ended | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Dec. 31, 2016 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Equity Method Investments and Joint Ventures [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Equity Method Investments | A summary of our investments, including our approximate ownership percentage and carrying value as of December 31, 2016 and 2015, is presented below.
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Other Property and Equipment Other Property and Equipment (Tables) |
12 Months Ended | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Dec. 31, 2016 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Property, Plant and Equipment [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Other Property and Equipment - Held for Use and Useful Life | A summary of other property and equipment held for use and the estimated useful lives thereof is as follows:
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A summary by asset class of (gains) or losses on sales of fixed assets for the years ended December 31, 2016, 2015 and 2014 is as follows:
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Other Property and Equipment - Net (Gains) Losses on Sales of Fixed Assets | A summary of other property and equipment held for use and the estimated useful lives thereof is as follows:
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A summary by asset class of (gains) or losses on sales of fixed assets for the years ended December 31, 2016, 2015 and 2014 is as follows:
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Impairments (Tables) |
12 Months Ended | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Dec. 31, 2016 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Asset Impairment Charges [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Details of Impairment of Long-Lived Assets Held and Used by Asset | A summary of our impairments of fixed assets by asset class and other charges for the years ended December 31, 2016, 2015 and 2014 is as follows:
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Fair Value Measurements (Tables) |
12 Months Ended | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Dec. 31, 2016 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Fair Value Disclosures [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis | The following table provides information for financial assets (liabilities) measured at fair value on a recurring basis as of December 31, 2016 and 2015:
A summary of the changes in the fair values of Chesapeake’s financial assets (liabilities) classified as Level 3 during 2016 and 2015 is presented below.
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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 December 31, 2016 and 2015:
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Asset Retirement Obligations (Tables) |
12 Months Ended | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Dec. 31, 2016 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Asset Retirement Obligation Disclosure [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Schedule of Asset Retirement Obligations | The components of the change in our asset retirement obligations are shown below.
_________________________________________
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Segment Information (Tables) |
12 Months Ended | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Segment Reporting, Disclosure of Entity's Reportable Segments [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Schedule of Segment Reporting Information, by Segment | The following table presents selected financial information for Chesapeake’s operating segments:
|
Basis of Presentation and Significant Accounting Policies Basis of Presentation and Significant Accounting Policies - Accounts Receivable Table (Details) - USD ($) $ in Millions |
Dec. 31, 2016 |
Dec. 31, 2015 |
---|---|---|
Accounting Policies [Abstract] | ||
Oil, Natural Gas and NGL Sales Receivables | $ 840 | $ 696 |
Oil and Gas Joint Interest Billing Receivables, Current | 156 | 230 |
Other Receivables | 93 | 226 |
Allowance for Doubtful Accounts Receivable | (32) | (23) |
Accounts receivable, net | $ 1,057 | $ 1,129 |
Basis of Presentation and Significant Accounting Policies Basis of Presentation and Significant Accounting Policies - Capitalized Costs of Unproved Properties Table (Details) - USD ($) $ in Millions |
12 Months Ended | |||
---|---|---|---|---|
Dec. 31, 2016 |
Dec. 31, 2015 |
Dec. 31, 2014 |
Dec. 31, 2013 |
|
Accounting Policies [Abstract] | ||||
Acquisition Costs, Period Cost | $ 109 | $ 99 | $ 507 | $ 2,956 |
Acquisition Costs, Cumulative | 3,671 | |||
Exploration Costs, Period Cost | 24 | 36 | 13 | 34 |
Exploration Costs, Cumulative | 107 | |||
Capitalized Interest of Unproved Properties Excluded from Amortization, Period Cost | 194 | 201 | 184 | 445 |
Capitalized Interest Of Unproved Properties Excluded From Amortization Cumulative | 1,024 | |||
Capitalized Costs of Unproved Properties Excluded from Amortization, Period Cost | 327 | 336 | $ 704 | $ 3,435 |
Unproved properties | $ 4,802 | $ 6,798 |
Debt Debt - Maturities of Long-Term Debt Table (Details) - USD ($) $ in Millions |
Dec. 31, 2016 |
Dec. 31, 2015 |
---|---|---|
Debt Disclosure [Abstract] | ||
Long-term Debt, Maturities, Repayments of Principal in Next Twelve Months | $ 506 | |
Long-term Debt, Maturities, Repayments of Principal in Year Two | 264 | |
Long-term Debt, Maturities, Repayments of Principal in Year Three | 380 | |
Long-term Debt, Maturities, Repayments of Principal in Year Four | 1,061 | |
Long-term Debt, Maturities, Repayments of Principal in Year Five | 2,320 | |
Long-term Debt, Maturities, Repayments of Principal after Year Five | 5,458 | |
Debt Instrument, Face Amount | $ 9,989 | $ 9,706 |
Debt Debt - Term Loan (Details) - USD ($) $ in Millions |
12 Months Ended | |||||
---|---|---|---|---|---|---|
Aug. 22, 2020 |
Aug. 22, 2019 |
Aug. 22, 2018 |
Aug. 22, 2017 |
Dec. 31, 2016 |
Dec. 31, 2015 |
|
Debt Instrument, Term Loan [Line Items] | ||||||
Debt Instrument, Face Amount | $ 9,989 | $ 9,706 | ||||
Term Loan [Member] | ||||||
Debt Instrument, Term Loan [Line Items] | ||||||
Debt Instrument, Term | 5 years | |||||
Debt Instrument, Face Amount | $ 1,500 | $ 0 | ||||
Proceeds from Issuance of Secured Debt | $ 1,476 | |||||
Debt Instrument, Description of Variable Rate Basis | 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 loan was made at par without original discount. We used the net proceeds to finance tender offers for our unsecured notes. | |||||
Debt Instrument, Description | 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. | |||||
Debt Instrument, Covenant Description | The term loan contains covenants limiting our ability to incur additional indebtedness, incur liens, consummate mergers and similar fundamental changes, make restricted payments, sell collateral and use proceeds from such sales, make investments, repay certain subordinate, unsecured or junior lien indebtedness, and enter into transactions with affiliates. | |||||
Debt Instrument, Debt Default, Description of Violation or Event of Default | Events of default under the term loan include, among other things, nonpayment of principal, interest or other amounts; violation of covenants; incorrectness of representations and warranties in any material respect; cross-payment default and cross acceleration with respect to other indebtedness with an outstanding principal balance of $125 million or more; bankruptcy; judgments involving liability of $125 million or more that are not paid; and ERISA events. Many events of default are subject to customary notice and cure periods. | |||||
Term Loan [Member] | Minimum [Member] | ||||||
Debt Instrument, Term Loan [Line Items] | ||||||
Debt Instrument, Event of Default, Cross-Payment Default and Cross Acceleration with Respect to Other Indebtedness, Outstanding Principal Balance | $ 125 | |||||
Debt Instrument, Event of Default, Judgments Involving Liability | $ 125 | |||||
Term Loan [Member] | Scenario, Forecast [Member] | ||||||
Debt Instrument, Term Loan [Line Items] | ||||||
Make Whole Premium Percentage Prior to 2nd Anniversary | 100.00% | |||||
Premium to Par Percentage, Prior to 3rd Anniversary | 4.25% | |||||
Premium to Par Percentage Prior to 4th Anniversary | 2.125% | |||||
Premium to Par Percentage at 4th Anniversary | 100.00% | |||||
Term Loan [Member] | London Interbank Offered Rate (LIBOR) [Member] | ||||||
Debt Instrument, Term Loan [Line Items] | ||||||
Debt Instrument, Basis Spread on Variable Rate | 7.50% | |||||
Debt Instrument, Floor Rate | 1.00% | |||||
Term Loan [Member] | Alternative Base Rate (ABR) [Member] | ||||||
Debt Instrument, Term Loan [Line Items] | ||||||
Debt Instrument, Basis Spread on Variable Rate | 6.50% | |||||
Debt Instrument, Floor Rate | 2.00% |
Debt - Revolving Credit Facility Narrative (Details) - USD ($) $ in Millions |
3 Months Ended | 12 Months Ended | |||||||
---|---|---|---|---|---|---|---|---|---|
Mar. 31, 2017 |
Dec. 31, 2016 |
Dec. 31, 2017 |
Sep. 30, 2017 |
Jun. 30, 2017 |
Mar. 31, 2017 |
Dec. 31, 2016 |
Dec. 31, 2015 |
Dec. 31, 2014 |
|
Long-Term Debt Instrument [Line Items] | |||||||||
Debt Instrument, Face Amount | $ 9,989 | $ 9,989 | $ 9,706 | ||||||
Senior Notes [Member] | |||||||||
Long-Term Debt Instrument [Line Items] | |||||||||
Debt Instrument, Face Amount | $ 3,000 | ||||||||
Redemption of 2019 Notes [Member] | 6.75% Senior Notes Due 2019 [Member] | Senior Notes [Member] | |||||||||
Long-Term Debt Instrument [Line Items] | |||||||||
Supersedeas Bond | 461 | ||||||||
Revolving Credit Facility [Member] | |||||||||
Long-Term Debt Instrument [Line Items] | |||||||||
Borrowing capacity | 4,000 | 4,000 | |||||||
Letters of Credit Outstanding, Amount | 1,036 | 1,036 | |||||||
Line of Credit Facility, Current Borrowing Capacity | $ 3,800 | $ 3,800 | |||||||
Line of Credit Facility, Description | The amendment reduces 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 December 31, 2016, falls below 1.1 to 1.0, the $500 million minimum liquidity covenant increases to $750 million, and 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. 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 $1.0 billion. | ||||||||
Interest Coverage Ratio | 1.1 to 1.0 | ||||||||
Minimum Liquidity Requirement ($ in millions) When Covenant Ratio Is At Or Above 1.1 to 1.0 | $ 500 | ||||||||
Revolving Credit Facility [Member] | Minimum [Member] | |||||||||
Long-Term Debt Instrument [Line Items] | |||||||||
Collateral Value Coverage Ratio | 1.1 to 1.0 | ||||||||
Revolving Credit Facility [Member] | Scenario, Forecast [Member] | |||||||||
Long-Term Debt Instrument [Line Items] | |||||||||
Interest Coverage Ratio | 1.25 to 1.0 | 1.2 to 1.0 | 0.70 to 1.0 | 0.65 to 1.0 | |||||
Minimum Liquidity Requirement ($ in millions) If Covenant Ratio Is Below 1.25 to 1.0 | $ 750 | ||||||||
Revolving Credit Facility [Member] | Scenario, Forecast [Member] | Minimum [Member] | |||||||||
Long-Term Debt Instrument [Line Items] | |||||||||
Collateral Value Coverage Ratio | 1.25 to 1.0 | ||||||||
Revolving Credit Facility [Member] | First Lien [Member] | Maximum [Member] | |||||||||
Long-Term Debt Instrument [Line Items] | |||||||||
Additional Indebtedness | $ 2,500 | 2,500 | |||||||
Additional Indebtedness, After Term Loan | 1,000 | ||||||||
Revolving Credit Facility [Member] | Line of Credit [Member] | |||||||||
Long-Term Debt Instrument [Line Items] | |||||||||
Debt Instrument, Face Amount | $ 0 | $ 0 | $ 0 |
Contingencies - Narrative (Details) - USD ($) $ in Millions |
12 Months Ended | |||
---|---|---|---|---|
Jul. 17, 2015 |
Dec. 31, 2016 |
Dec. 31, 2015 |
Dec. 31, 2014 |
|
Loss Contingencies [Line Items] | ||||
Provision for legal contingencies | $ 123 | $ 353 | $ 234 | |
6.875% Senior Notes Due 2020 [Member] | Senior Notes [Member] | ||||
Loss Contingencies [Line Items] | ||||
Debt Instrument, Interest Rate, Stated Percentage | 6.875% | |||
6.125% Senior Notes Due 2021 [Member] | Senior Notes [Member] | ||||
Loss Contingencies [Line Items] | ||||
Debt Instrument, Interest Rate, Stated Percentage | 6.125% | |||
8.00% Senior Secured Second Lien Notes Due 2022 [Member] | Senior Notes [Member] | ||||
Loss Contingencies [Line Items] | ||||
Debt Instrument, Interest Rate, Stated Percentage | 8.00% | 8.00% | ||
Redemption of 2019 Notes [Member] | 6.75% Senior Notes Due 2019 [Member] | Senior Notes [Member] | ||||
Loss Contingencies [Line Items] | ||||
Loss Contingency, Damages Awarded, Value | $ 380 | |||
Loss Contingency, Prejudgment Interest Awarded | $ 59 | |||
Supersedeas Bond | $ 461 | |||
Provision for legal contingencies | $ 339 | $ 100 |
Contingencies and Commitments Commitments - Operating Leases Table (Details) $ in Millions |
Dec. 31, 2016
USD ($)
|
---|---|
Commitments and Contingencies Disclosure [Abstract] | |
Operating Leases, Future Minimum Payments Due, Next Twelve Months | $ 4 |
Operating Leases, Future Minimum Payments, Due in Two Years | 3 |
Operating Leases, Future Minimum Payments, Due in Three Years | 2 |
Operating Leases Commitment | $ 9 |
Commitments - Undiscounted Gathering Processing and Transportation Agreements Commitments Table (Details) - Gas Gathering and Processing Equipment [Member] $ in Millions |
Dec. 31, 2016
USD ($)
|
---|---|
Other Commitments [Line Items] | |
Gathering, Processing and Transportation Commitment, Due in First Year | $ 1,434 |
Gathering, Processing and Transportation Commitment, Due in Second Year | 1,229 |
Gathering, Processing and Transportation Commitment, Due in Third Year | 1,178 |
Gathering, Processing and Transportation Commitment, Due in Fourth Year | 1,074 |
Gathering, Processing and Transportation Commitment, Due in Fifth Year | 970 |
Gathering, Processing and Transportation Commitment, Due after Fifth Year | 5,225 |
Gathering, Processing and Transportation Commitment | $ 11,110 |
Contingencies and Commitments Contingencies - Drilling Contracts (Details) - Drilling Rig Leases [Member] $ in Millions |
Dec. 31, 2016
USD ($)
|
---|---|
Other Commitments [Line Items] | |
Contractual Obligation, Due in Next Fiscal Year | $ 91 |
Contractual Obligation, Due in Second Year | 14 |
Contractual Obligation | $ 105 |
Commitments - Narrative (Details) $ in Millions |
12 Months Ended | ||
---|---|---|---|
Dec. 31, 2016
USD ($)
Crew
|
Dec. 31, 2015
USD ($)
|
Dec. 31, 2014
USD ($)
|
|
Long-term Purchase Commitment [Line Items] | |||
Operating Leases, Rent Expense | $ 5 | $ 7 | $ 33 |
Operating Leases Commitment | $ 9 | ||
Pressure Pumping Leases [Member] | Discontinued Operations, Disposed of by Means Other than Sale, Spinoff [Member] | Seven Seven Energy Inc. [Member] | |||
Long-term Purchase Commitment [Line Items] | |||
Number of Crews | Crew | 3 | ||
Percent of Total | 50.00% | ||
Operating Leases Commitment | $ 53 |
Other Liabilities - Current Table (Details) - USD ($) $ in Millions |
Dec. 31, 2016 |
Dec. 31, 2015 |
---|---|---|
Other Liabilities Disclosure [Abstract] | ||
Revenues and royalties due others | $ 543 | $ 500 |
Accrued drilling and production costs | 169 | 212 |
Joint interest prepayments received | 71 | 169 |
Accrued compensation and benefits | 239 | 264 |
Other accrued taxes | 32 | 37 |
Bank of New York Mellon legal accrual | 440 | 439 |
Minimum gathering volume commitment | 0 | 201 |
Other | 304 | 397 |
Total other current liabilities | $ 1,798 | $ 2,219 |
Other Liabilities - Long-Term Table (Details) - USD ($) $ in Millions |
Dec. 31, 2016 |
Dec. 31, 2015 |
---|---|---|
Other Long-Term Liabilities [Line Items] | ||
CHK Utica ORRI conveyance obligation(a) | $ 160 | $ 190 |
Financing obligations | 0 | 29 |
Unrecognized tax benefits | 97 | 64 |
Other | 126 | 126 |
Total other long-term liabilities | 383 | 409 |
Total other current liabilities | 1,798 | 2,219 |
Noncontrolling Interest, Chesapeake Utica L L C [Member] | ||
Other Long-Term Liabilities [Line Items] | ||
Total other long-term liabilities | 203 | 211 |
Total other current liabilities | $ 43 | $ 21 |
Income Taxes Income Taxes - Income Tax Provision (Benefit) Table (Details) - USD ($) $ in Millions |
12 Months Ended | ||
---|---|---|---|
Dec. 31, 2016 |
Dec. 31, 2015 |
Dec. 31, 2014 |
|
Income Tax Disclosure [Abstract] | |||
Current Federal Tax Expense (Benefit) | $ (14) | $ 0 | $ 0 |
Current State and Local Tax Expense (Benefit) | (5) | (36) | 47 |
Current Income Tax Expense (Benefit) | (19) | (36) | 47 |
Deferred Federal Income Tax Expense (Benefit) | (147) | (4,385) | 1,115 |
Deferred State and Local Income Tax Expense (Benefit) | (24) | (42) | (18) |
Deferred Income Tax Expense (Benefit) | (171) | (4,427) | 1,097 |
Total Income Tax Expense (Benefit) | $ (190) | $ (4,463) | $ 1,144 |
Income Taxes Income Taxes - Effective Income Tax Expense Table (Details) - USD ($) $ in Millions |
12 Months Ended | ||
---|---|---|---|
Dec. 31, 2016 |
Dec. 31, 2015 |
Dec. 31, 2014 |
|
Income Tax Disclosure [Abstract] | |||
Effective Income Tax Rate Reconciliation, at Federal Statutory Income Tax Rate, Percent | 35.00% | ||
Effective Income Tax Rate Reconciliation at Federal Statutory Income Tax Rate, Amount | $ (1,606) | $ (6,684) | $ 1,120 |
Effective Income Tax Rate Reconciliation, State and Local Income Taxes, Amount | (30) | (406) | 68 |
Effective Income Tax Rate Reconciliation, Tax Contingency, State and Local, Amount | 0 | 0 | (114) |
Effective Income Tax Rate Reconciliation, Change in Deferred Tax Assets Valuation Allowance, Amount | 1,423 | 2,727 | 74 |
Effective Income Tax Rate Reconciliation, Other Adjustments, Amount | 23 | (100) | (4) |
Total Income Tax Expense (Benefit) | $ (190) | $ (4,463) | $ 1,144 |
Income Taxes Income Taxes - Reconciliation of Unrecognized Tax Benefits Table (Details) - USD ($) $ in Millions |
12 Months Ended | ||
---|---|---|---|
Dec. 31, 2016 |
Dec. 31, 2015 |
Dec. 31, 2014 |
|
Income Tax Disclosure [Abstract] | |||
Unrecognized tax benefits at beginning of period | $ 280 | $ 303 | $ 644 |
Additions based on tax positions related to the current year | 0 | 27 | 13 |
Additions to tax positions of prior years | 33 | 0 | 0 |
Unrecognized Tax Benefits, Decrease Resulting from Settlements with Taxing Authorities | (111) | 0 | 0 |
Reductions to tax positions of prior years | 0 | (50) | (354) |
Unrecognized tax benefits at end of period | $ 202 | $ 280 | $ 303 |
Related Party Transactions Related Party Transactions - Narrative (Details) - USD ($) $ in Millions |
12 Months Ended | ||
---|---|---|---|
Dec. 31, 2016 |
Dec. 31, 2015 |
Dec. 31, 2014 |
|
FTS International, Inc. [Member] | |||
Related Party Transaction [Line Items] | |||
Related Party Transaction, Expenses from Transactions with Related Party | $ 3 | $ 65 | $ 220 |
Equity - Narrative (Details) - $ / shares |
Dec. 31, 2016 |
Dec. 31, 2015 |
---|---|---|
Equity [Abstract] | ||
Common stock, shares authorized | 1,500,000,000 | 1,000,000,000 |
Common stock, par value (usd per share) | $ 0.01 | $ 0.01 |
Equity Equity - Distributions Declared and Paid by Noncontrolling Interest Chesapeake Granite Wash Trust (Details) - Noncontrolling Interest, Chesapeake Granite Wash Trust [Member] - $ / shares |
3 Months Ended | |||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|
Aug. 31, 2016 |
May 31, 2016 |
Feb. 29, 2016 |
Nov. 30, 2015 |
Aug. 31, 2015 |
May 31, 2015 |
Feb. 28, 2015 |
Nov. 30, 2014 |
Aug. 31, 2014 |
May 31, 2014 |
Feb. 28, 2014 |
Nov. 30, 2013 |
|
Noncontrolling Interest [Line Items] | ||||||||||||
Distribution Made to Limited Partner, Distribution Date | Dec. 01, 2016 | Aug. 29, 2016 | May 31, 2016 | Mar. 01, 2016 | Nov. 30, 2015 | Aug. 31, 2015 | Jun. 01, 2015 | Mar. 02, 2015 | Dec. 01, 2014 | Aug. 29, 2014 | May 30, 2014 | Mar. 03, 2014 |
Unit Distribution, Common Unit [Member] | ||||||||||||
Noncontrolling Interest [Line Items] | ||||||||||||
Distribution Made to Limited Partner, Distributions Declared, Per Unit | $ 0.0857 | $ 0.0734 | $ 0.0403 | $ 0.2195 | $ 0.3232 | $ 0.3579 | $ 0.3899 | $ 0.4496 | $ 0.5079 | $ 0.5796 | $ 0.6454 | $ 0.6624 |
Unit Distribution, Subordinated Units [Member] | ||||||||||||
Noncontrolling Interest [Line Items] | ||||||||||||
Distribution Made to Limited Partner, Distributions Declared, Per Unit | $ 0.0000 | $ 0.0000 | $ 0.0000 | $ 0.0000 | $ 0.0000 | $ 0.0000 | $ 0.0000 | $ 0.0000 | $ 0.0000 | $ 0.0000 | $ 0.0000 | $ 0.0000 |
Share-Based Compensation - Equity-Classified Valuation Table (Details) - Employee Stock Option [Member] |
12 Months Ended |
---|---|
Dec. 31, 2016 | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Expected Term | 6 years |
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Expected Volatility Rate | 46.07% |
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Risk Free Interest Rate | 1.70% |
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Expected Dividend Rate | 0.00% |
Share-Based Compensation - Liability Classified Valuation Table (Details) - Performance Shares [Member] |
12 Months Ended |
---|---|
Dec. 31, 2016 | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Expected Volatility Rate | 91.19% |
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Risk Free Interest Rate | 1.20% |
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Expected Dividend Rate | 0.00% |
Derivative and Hedging Activities - Natural Gas and Oil Sales Table (Details) - USD ($) $ in Millions |
12 Months Ended | ||
---|---|---|---|
Dec. 31, 2016 |
Dec. 31, 2015 |
Dec. 31, 2014 |
|
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |||
Oil, natural gas and NGL revenues | $ 3,866 | $ 4,767 | $ 9,336 |
Gains (losses) on undesignated oil, natural gas and NGL derivatives | (545) | 661 | 1,055 |
Gains (losses) on terminated cash flow hedges - oil, natural gas and NGL | (33) | (37) | (37) |
Total oil, natural gas and NGL revenues | $ 3,288 | $ 5,391 | $ 10,354 |
Derivative and Hedging Activities Derivative and Hedging Activities - Marketing, Gathering and Compression Sales (Details) - USD ($) $ in Millions |
12 Months Ended | ||
---|---|---|---|
Dec. 31, 2016 |
Dec. 31, 2015 |
Dec. 31, 2014 |
|
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |||
Marketing, gathering and compression revenues | $ 4,881 | $ 7,077 | $ 12,224 |
Gains (losses) on undesignated supply contract derivatives | (297) | 296 | 1 |
Total marketing, gathering and compression revenues | $ 4,584 | $ 7,373 | $ 12,225 |
Derivative and Hedging Activities - Components of Interest Income and Interest Expense Table (Details) - USD ($) $ in Millions |
12 Months Ended | ||
---|---|---|---|
Dec. 31, 2016 |
Dec. 31, 2015 |
Dec. 31, 2014 |
|
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |||
Interest expense on senior notes | $ 588 | $ 682 | $ 704 |
Interest expense on term loan | 46 | 0 | 36 |
Amortization of loan discount, issuance costs and other | 33 | 62 | 42 |
Amortization of premium associated with troubled debt restructuring | (165) | (3) | 0 |
Interest expense on revolving credit facilities | 35 | 12 | 28 |
Gains on terminated fair value hedges | (2) | (3) | (3) |
(Gains) losses on undesignated interest rate derivatives | 12 | (9) | (81) |
Capitalized interest | (251) | (424) | (637) |
Total interest expense | $ 296 | $ 317 | $ 89 |
Oil and Natural Gas Property Transactions - VPP Transactions Table (Details) - VPP 9 Mid-Continent [Member] MBbls in Millions, $ in Millions, Mcfe in Billions, Mcf in Billions |
May 31, 2011
USD ($)
Mcfe
MBbls
Mcf
|
---|---|
VPP Transactions [Line Items] | |
Cash Proceeds from Volumetric Production Payment (VPP) | $ | $ 853 |
Proved Developed Reserves (Energy) | Mcfe | 177 |
Oil [Member] | |
VPP Transactions [Line Items] | |
Proved Developed Reserves (Volume) | 1.7 |
Natural Gas [Member] | |
VPP Transactions [Line Items] | |
Proved Developed Reserves (Volume) | Mcf | 138 |
Natural Gas Liquids [Member] | |
VPP Transactions [Line Items] | |
Proved Developed Reserves (Volume) | 4.8 |
Investments Investments - Equity Method Investments Table (Details) - USD ($) $ in Millions |
Dec. 31, 2016 |
Dec. 31, 2015 |
---|---|---|
Schedule of Equity Method Investments [Line Items] | ||
Equity Method Investments | $ 7 | $ 136 |
Sundrop Fuels Inc [Member] | ||
Schedule of Equity Method Investments [Line Items] | ||
Equity Method Investment, Ownership Percentage | 56.00% | 56.00% |
Equity Method Investments | $ 0 | $ 119 |
FTS International, Inc. [Member] | ||
Schedule of Equity Method Investments [Line Items] | ||
Equity Method Investment, Ownership Percentage | 30.00% | 30.00% |
Equity Method Investments | $ 0 | $ 0 |
Other Chesapeake Investments [Member] | ||
Schedule of Equity Method Investments [Line Items] | ||
Equity Method Investment, Ownership Percentage | 0.00% | 0.00% |
Equity Method Investments | $ 7 | $ 17 |
Other Property and Equipment Other Property and Equipment - Net (Gains) Losses on Sales of Fixed Assets Table (Details) - USD ($) $ in Millions |
12 Months Ended | ||
---|---|---|---|
Dec. 31, 2016 |
Dec. 31, 2015 |
Dec. 31, 2014 |
|
Property, Plant and Equipment [Line Items] | |||
Net (gains) losses on sales of fixed assets | $ (12) | $ 4 | $ (199) |
Buildings and land [Member] | |||
Property, Plant and Equipment [Line Items] | |||
Net (gains) losses on sales of fixed assets | (1) | 3 | (2) |
Natural Gas Compressor [Member] | |||
Property, Plant and Equipment [Line Items] | |||
Net (gains) losses on sales of fixed assets | (10) | 0 | (195) |
Gas Gathering and Processing Equipment [Member] | |||
Property, Plant and Equipment [Line Items] | |||
Net (gains) losses on sales of fixed assets | 0 | 1 | 8 |
Exploration and Production Equipment [Member] | |||
Property, Plant and Equipment [Line Items] | |||
Net (gains) losses on sales of fixed assets | 0 | 0 | (7) |
Other Assets [Member] | |||
Property, Plant and Equipment [Line Items] | |||
Net (gains) losses on sales of fixed assets | $ (1) | $ 0 | $ (3) |
Other Property and Equipment Other Property and Equipment - Narrative (Details) $ in Millions |
12 Months Ended | ||
---|---|---|---|
Dec. 31, 2016
USD ($)
|
Dec. 31, 2015
USD ($)
|
Dec. 31, 2014
USD ($)
Compressor
|
|
Property, Plant and Equipment [Line Items] | |||
Gain (Loss) on Disposition of Property Plant Equipment | $ 12 | $ (4) | $ 199 |
Property and equipment held for sale, net | 29 | 95 | |
Natural Gas Compressor [Member] | |||
Property, Plant and Equipment [Line Items] | |||
Equipment, Number of Units | Compressor | 703 | ||
Proceeds from Sale of Property, Plant, and Equipment | $ 693 | ||
Gain (Loss) on Disposition of Property Plant Equipment | 10 | 0 | 195 |
Buildings and land [Member] | |||
Property, Plant and Equipment [Line Items] | |||
Gain (Loss) on Disposition of Property Plant Equipment | 1 | (3) | $ 2 |
Buildings and land [Member] | Disposal Group, Held-for-sale, Not Discontinued Operations [Member] | |||
Property, Plant and Equipment [Line Items] | |||
Property and equipment held for sale, net | $ 29 | $ 95 |
Asset Retirement Obligations Table (Details) - USD ($) $ in Millions |
12 Months Ended | |
---|---|---|
Dec. 31, 2016 |
Dec. 31, 2015 |
|
Asset Retirement Obligation Disclosure [Abstract] | ||
Asset Retirement Obligation, Beginning of Period | $ 473 | $ 465 |
Asset Retirement Obligation, Liabilities Incurred | 4 | 6 |
Asset Retirement Obligation, Revision of Estimate | (58) | 13 |
Asset Retirement Obligation, Liabilities Settled | (182) | (34) |
Asset Retirement Obligation, Accretion Expense | 24 | 23 |
Asset Retirement Obligation, End of Period | 261 | 473 |
Asset Retirement Obligation, Current | 14 | 21 |
Asset retirement obligations, long-term | $ 247 | $ 452 |
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