filings.toolsExpand Energy 10-K 2017-12-31
Filed 2018-02-22. 22 sections, 519K characters. Original on sec.gov · Markdown · JSON
Cover and table of contents
10-K 1 chk-20171231_10k.htm 10-K
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the Fiscal Year Ended December 31, 2017
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from to
Commission File No. 1-13726
CHESAPEAKE ENERGY CORPORATION
(Exact name of registrant as specified in its charter)
| Oklahoma | 73-1395733 | |
| (State or other jurisdiction of incorporation or organization) | (I.R.S. Employer Identification No.) | |
| 6100 North Western Avenue, Oklahoma City, Oklahoma | 73118 | |
| (Address of principal executive offices) | (Zip Code) | |
| (405) 848-8000 | ||
| (Registrant’s telephone number, including area code) |
| 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 | |
| 2.25% 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 |
| Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. YES [X] NO [ ] | ||||
| Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Exchange Act. YES [ ] NO [X] | ||||
| Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. YES [X] NO [ ] | ||||
| Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). YES [X] NO [ ] | ||||
| Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. [X] | ||||
| Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company or an emerging growth company. See the definitions of "large accelerated filer," "accelerated filer," "smaller reporting company" and “emerging growth company” in Rule 12b-2 of the Exchange Act. | ||||
| Large Accelerated Filer [X] Accelerated Filer [ ] Non-accelerated Filer [ ] Smaller Reporting Company [ ] Emerging Growth Company [ ] | ||||
| If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. [ ] | ||||
| Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). YES [ ] NO [X] |
The aggregate market value of our common stock held by non-affiliates on June 30, 2017, was approximately $4.5 billion. As of February 15, 2018, there were 909,242,558 shares of our $0.01 par value common stock outstanding.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the proxy statement for the 2018 Annual Meeting of Shareholders are incorporated by reference in Part III.
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
2017 ANNUAL REPORT ON FORM 10-K
TABLE OF CONTENTS
Glossary of Oil and Gas Terms
The terms defined in this section are used throughout this report.
Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume, used herein in reference to crude oil or other liquid hydrocarbons.
Bboe. One billion barrels of oil equivalent.
Bcf. Billion cubic feet of natural gas.
Bcfe. Billion cubic feet of natural gas equivalent.
Btu. British thermal unit, which is the heat required to raise the temperature of a one-pound mass of water from 58.5 to 59.5 degrees Fahrenheit.
Boe. Barrel of oil equivalent. 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. Despite holding this ratio constant at six mcf to one bbl, prices have historically often been higher or substantially higher for oil than natural gas on an energy equivalent basis, although there have been periods in which they have been lower or substantially lower.
Completion. The process of treating a drilled well followed by the installation of permanent equipment for the production of oil, natural gas or natural gas liquids, or in the case of a dry well, the reporting to the appropriate authority that the well has been abandoned.
Developed Acreage. The number of acres which are allocated or assignable to producing wells or wells capable of production.
Dry Well. A well found to be incapable of producing either oil or natural gas in sufficient quantities to justify completion as an oil or natural gas well.
Exploratory Well. A well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or natural gas in another reservoir.
Formation. A succession of sedimentary beds that were deposited under the same general geologic conditions.
Full Cost. The full cost method of accounting, as governed by SEC Regulation S-X 4-10(c), consists of capitalizing all costs associated with property acquisition, exploration and development activities into a full cost pool. The full cost pool is tested for impairment quarterly using the “ceiling test” described in Regulation S-X 4-10(c). Additionally, any internal costs that can be directly identified with acquisition, exploration and development activities are included. Any costs related to production, general corporate overhead or similar activities are not included.
GAAP. Generally Accepted Accounting Principles in the United States.
Gross Acres or Gross Wells. The total acres or wells, as the case may be, in which a working interest is owned.
Mboe. One thousand barrels of oil equivalent.
Mcf. One thousand cubic feet.
Mmbbl. One million barrels of crude oil or other liquid hydrocarbons.
Mmboe. One million barrels of oil equivalent.
Mmbtu. One million btus.
Mmcf. One million cubic feet.
Natural Gas Liquids (NGL). Hydrocarbons in natural gas that are separated from the gas as liquids through the process of absorption, condensation, adsorption or other methods in gas processing or cycling plants. Natural gas liquids primarily include ethane, propane, butane, isobutene, pentane, hexane and natural gasoline.
Net Acres or Net Wells. The sum of the fractional working interests owned in gross acres or gross wells.
NYMEX. New York Mercantile Exchange.
Play. A term applied to a portion of the exploration and production cycle following the identification by geologists and geophysicists of areas with potential oil, natural gas and NGL reserves.
Present Value of Estimated Future Net Revenues or PV-10 (non-GAAP). When used with respect to oil, natural gas and NGL reserves, present value of estimated future net revenues, or PV-10, means the estimated future gross revenue to be generated from the production of proved reserves, net of estimated production and future development costs, using prices calculated as the average oil and natural gas price during the preceding 12-month period prior to the end of the current reporting period, (determined as the unweighted arithmetic average of prices on the first day of each month within the 12-month period) and costs in effect at the determination date (unless such costs are subject to change pursuant to contractual provisions), without giving effect to non-property related expenses such as general and administrative expenses, debt service and future income tax expense or to depreciation, depletion and amortization, discounted using an annual discount rate of 10%.
Price Differential. The difference in the price of oil, natural gas or NGL received at the sales point and the NYMEX price.
Productive Well. A well that is not a dry well. Productive wells include producing wells and wells that are mechanically capable of production.
Proved Developed Reserves. Proved reserves that can be expected to be recovered through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well.
Proved Properties. Properties with proved reserves.
Proved Reserves. As used in this report, proved reserves has the meaning given to such term in Rule 4-10(a)(22) of Regulation S-X, which states in part proved oil and natural gas reserves are those quantities of oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible – from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations – prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation.
Proved Undeveloped Reserves (PUDs). Proved reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required. Reserves on undrilled acreage are limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.
Realized and Unrealized Gains and Losses on Oil, Natural Gas and NGL Derivatives. Realized gains and losses includes the following items:(i) settlements and accruals for settlements of non-designated derivatives related to current period notional production revenues, (ii) prior period settlements for option premiums and for early-terminated derivatives originally scheduled to settle against current period notional production revenues, and (iii) gains and losses related to de-designated cash flow hedges originally designated to settle against current period notional production revenues. Unrealized gains and losses include the change in fair value of open derivatives scheduled to settle against future period notional production revenues (including current period settlements for option premiums and early-terminated derivatives) offset by amounts reclassified as realized gains and losses during the period. Although we no longer designate our derivatives as cash flow hedges for accounting purposes, we believe these definitions are useful to management and investors in determining the effectiveness of our price risk management program.
Realized and Unrealized Gains and Losses on Interest Rate Derivatives. Realized gains and losses include interest rate derivative settlements related to current period interest and the effect of gains and losses on early-terminated trades. Settlements of early-terminated trades are reflected in realized gains and losses over the original life of the hedged item. Unrealized gains and losses include changes in the fair value of open interest rate derivatives offset by amounts reclassified to realized gains and losses during the period.
Reservoir. A porous and permeable underground formation containing a natural accumulation of producible oil and/or natural gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.
Royalty Interest. An interest in an oil and natural gas property entitling the owner to a share of oil, natural gas or NGL production free of costs of production.
Seismic. An exploration method of sending energy waves or sound waves into the earth and recording the wave reflections to indicate the type, size, shape and depth of subsurface rock formations.
Shale. Fine-grained sedimentary rock composed mostly of consolidated clay or mud. Shale is the most frequently occurring sedimentary rock.
SEC. The United States Securities and Exchange Commission.
Standardized Measure. The discounted future net cash flows relating to proved reserves based on the means of the estimated future gross revenue to be generated from the production of proved reserves, net of estimated production and future development costs, using prices calculated as the average oil and natural gas price during the preceding 12-month period prior to the end of the current reporting period (determined as the unweighted arithmetic average of prices on the first day of each month within the 12-month period). The standardized measure differs from the PV-10 measure only because the former includes the effects of estimated future income tax expenses.
Tbtu. One trillion British thermal units.
Undeveloped Acreage. Acreage on which wells have not been drilled or completed to a point that would permit the production of economic quantities of oil and natural gas regardless of whether the acreage contains proved reserves.
Unproved Properties. Properties with no proved reserves.
Volumetric Production Payment (VPP). As we use the term, a volumetric production payment represents 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 nonrecourse 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 the remaining reserves, if any, after the scheduled production volumes have been delivered.
Working Interest. The operating interest which gives the owner the right to drill, produce and conduct operating activities on the property and a share of production.
Forward-Looking Statements
This report includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934 (the “Exchange Act”). Forward-looking statements include our current expectations or forecasts of future events. In this context, forward-looking statements often address our expected future business and financial performance and financial condition, and often contain words such as "expect," “could,” “may,” "anticipate," "intend," "plan," “ability,” "believe," "seek," "see," "will," "would," “estimate,” “forecast,” "target," “guidance,” “outlook,” “opportunity” or “strategy.”
Although we believe the expectations and forecasts reflected in our forward-looking statements are reasonable, they are inherently subject to numerous risks and uncertainties, most of which are difficult to predict and many of which are beyond our control. No assurance can be given that such forward-looking statements will be correct or achieved or that the assumptions are accurate or will not change over time. Particular uncertainties that could cause our actual results to be materially different than those expressed in our forward-looking statements include:
| • | the volatility of oil, natural gas and NGL prices; |
| • | uncertainties inherent in estimating quantities of oil, natural gas and NGL reserves and projecting future rates of production and the amount and timing of development expenditures; |
| • | our ability to replace reserves and sustain production; |
| • | drilling and operating risks and resulting liabilities; |
| • | our ability to generate profits or achieve targeted results in drilling and well operations; |
| • | the limitations our level of indebtedness may have on our financial flexibility; |
| • | our inability to access the capital markets on favorable terms; |
| • | the availability of cash flows from operations and other funds to finance reserve replacement costs or satisfy our debt obligations; |
| • | adverse developments or losses from pending or future litigation and regulatory proceedings, including royalty claims; |
| • | effects of environmental protection laws and regulation on our business; |
| • | terrorist activities and/or cyber-attacks adversely impacting our operations; |
| • | effects of acquisitions and dispositions; and |
| • | other factors that are described under Risk Factors in Item 1A of this Form 10-K. |
We caution you not to place undue reliance on the forward-looking statements contained in this report, which speak only as of the filing date, and we undertake no obligation to update this information. We urge you to carefully review and consider the disclosures in this report and our other filings with the SEC that attempt to advise interested parties of the risks and factors that may affect our business.
PART I
Item 1. Business
Unless the context otherwise requires, references to “Chesapeake”, the “Company”, “us”, “we” and “our” in this report are to Chesapeake Energy Corporation together with its subsidiaries. Our principal executive offices are located at 6100 North Western Avenue, Oklahoma City, Oklahoma 73118, and our main telephone number at that location is (405) 848-8000.
Our Business
We are an independent exploration and production company engaged in the acquisition, exploration and development of properties for the production of oil, natural gas and NGLs from underground reservoirs. We own a large and geographically diverse portfolio of onshore U.S. unconventional natural gas and liquids assets, including interests in approximately 17,300 oil and natural gas wells. We have leading positions in the liquids-rich resource plays of the Eagle Ford Shale in South Texas, the Anadarko Basin in northwestern Oklahoma and the stacked pay in the Powder River Basin in Wyoming. Our natural gas resource plays are the Marcellus Shale in the northern Appalachian Basin in Pennsylvania, the Haynesville/Bossier Shales in northwestern Louisiana and East Texas and the Utica Shale in Ohio.
Information About Us
We make available, free of charge on our website at chk.com, our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and any amendments to those reports as soon as reasonably practicable after we electronically file such material with, or furnish it to, the SEC. From time to time, we also post announcements, updates, events, investor information and presentations on our website in addition to copies of all recent news releases. Documents and information on our website are not incorporated by reference herein.
Business Strategy
Our strategy is to create shareholder value through the development of our significant resource plays. Our substantial inventory of hydrocarbon resources, including our undeveloped acreage position in each of our key basins, provides a strong foundation to create future value. Concentrated blocks of undeveloped acreage give us the opportunity to apply what we believe are best in class well spacing analysis, completion techniques and lateral lengths to maximize capital efficiency. We have greatly improved our capital and operating efficiency metrics over the last several years and today have what we believe is a leading cost structure in each of our major resource plays. We believe our cost structure provides a significant competitive advantage in the current commodity price environment and it is our strategy to continue to seek capital and operating efficiencies to grow this advantage.
We continue to focus on reducing debt, increasing cash provided by operating activities, and improving margins through financial discipline and operating efficiencies. To accomplish these goals, we intend to allocate our capital expenditures to projects we believe offer the highest return, deploy leading drilling and completion technology throughout our portfolio, and divest additional assets to strengthen our cost structure and our portfolio. Increasing our margins means not only increasing our absolute level of cash flow from operations, but also increasing our cash flow from operations generated per barrel of oil equivalent production. Our capital program is focused on investments that can improve our cash flow generating ability regardless of the commodity price environment. Although we expect our forecasted capital expenditures in 2018 to be lower compared to 2017, we anticipate modest production growth from both our oil-producing and natural gas-producing assets, adjusted for asset sales. Our ability to reduce capital expenditures while still growing production is primarily the result of improved operating efficiencies, including improved well performance. We continue to seek opportunities to reduce cash costs (production, general and administrative, gathering, processing and transportation and interest expenses) and improve our production volumes from existing wells.
We believe that our dedication to financial discipline, the flexibility and efficiency of our capital program and cost structure and our continued focus on safety and environmental stewardship will provide opportunities to create value for us and our shareholders.
Operating Areas
We focus our exploration, development, acquisition and production efforts in the six geographic operating areas described below.
Marcellus - Northern Appalachian Basin in Pennsylvania.
Haynesville - Northwestern Louisiana and East Texas (Gulf Coast).
Eagle Ford - South Texas.
Utica - Southern Appalachian Basin in Ohio.
Mid-Continent - Anadarko Basin in northwestern Oklahoma.
Powder River Basin - Stacked pay in Wyoming.
Well Data
As of December 31, 2017, we held an interest in approximately 17,300 gross (7,200 net) productive wells, including 14,000 properties in which we held a working interest and 3,300 properties in which we held an overriding or royalty interest. Of the wells in which we had a working interest, 9,400 gross (5,000 net) were classified as natural gas productive wells and 4,600 gross (2,200 net) were classified as oil productive wells. We operated approximately 9,500 of our 14,000 productive wells in which we had a working interest. During 2017, we drilled or participated in 401 gross (292 net) wells as operator and participated in another 67 gross (4 net) wells completed by other operators. We operate approximately 97% of our current daily production volumes.
Drilling Activity
The following table sets forth the wells we drilled or participated in during the periods indicated. In the table, "gross" refers to the total wells in which we had a working interest and "net" refers to gross wells multiplied by our working interest:
| 2017 | 2016 | 2015 | ||||||||||||||||||||||||||||||||||
| Gross | % | Net | % | Gross | % | Net | % | Gross | % | Net | % | |||||||||||||||||||||||||
| Development: | ||||||||||||||||||||||||||||||||||||
| Productive | 462 | 99 | 292 | 99 | 431 | 99 | 236 | 99 | 806 | 99 | 423 | 100 | ||||||||||||||||||||||||
| Dry | 4 | 1 | 2 | 1 | 1 | 1 | 1 | 1 | 1 | 1 | — | — | ||||||||||||||||||||||||
| Total | 466 | 100 | 294 | 100 | 432 | 100 | 237 | 100 | 807 | 100 | 423 | 100 | ||||||||||||||||||||||||
| Exploratory: | ||||||||||||||||||||||||||||||||||||
| Productive | 2 | 100 | 2 | 100 | 3 | 100 | 2 | 100 | 7 | 100 | 5 | 100 | ||||||||||||||||||||||||
| Dry | — | — | — | — | — | — | — | — | — | — | — | — | ||||||||||||||||||||||||
| Total | 2 | 100 | 2 | 100 | 3 | 100 | 2 | 100 | 7 | 100 | 5 | 100 |
The following table shows the wells we drilled or participated in by operating area:
| | | | | | | | | | | | | | | | | | | | | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | -
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Item 1A. Risk Factors
There are numerous factors that affect our business and operating results, many of which are beyond our control. The following is a description of significant factors that might cause our future results to differ materially from those currently expected. The risks described below are not the only risks facing our company. Additional risks and uncertainties not presently known to us or that we currently deem immaterial may also affect our business operations. If any of these risks actually occur, our business, financial position, operating results, cash flows, reserves and/or our ability to pay our debts and other liabilities could suffer, the trading price and liquidity of our securities could decline and you may lose all or part of your investment in our securities.
Oil, natural gas and NGL prices fluctuate widely, and lower prices for an extended period of time are likely to have a material adverse effect on our business.
Our revenues, operating results, profitability, liquidity and ability to grow depend primarily upon the prices we receive for the oil, natural gas and NGL we sell. We incur substantial expenditures to replace reserves, sustain production and fund our business plans. Low oil, natural gas and NGL prices can negatively affect the amount of cash available for capital expenditures, debt service and debt repayment and our ability to borrow money or raise additional capital and, as a result, could have a material adverse effect on our financial condition, results of operations, cash flows and reserves. In addition, low oil and natural gas prices, such as those experienced in 2015 and continuing into the first quarter of 2017, may result in ceiling test write-downs of our oil and natural gas properties.
Historically, the markets for oil, natural gas and NGL have been volatile, and they are likely to continue to be volatile. Wide fluctuations in oil, natural gas and NGL prices may result from factors that are beyond our control, including:
| • | 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, natural gas, liquefied natural gas and NGL; |
| • | 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. |
These factors and the volatility of the energy markets make it extremely difficult to predict future oil, natural gas and NGL price movements with any certainty. As of February 22, 2018, including January and February derivative contracts that have settled, approximately 74% and 68% of our forecasted 2018 oil production and natural gas production, respectively, was hedged through swaps and collars. Even with oil, natural gas and NGL derivatives currently in place to mitigate price risks associated with a portion of our 2018 cash flows, we have substantial exposure to oil, natural gas and NGL prices in 2019 and beyond. In addition, a prolonged extension of lower prices could reduce the quantities of reserves that we may economically produce.
We have a significant amount of indebtedness. Our leverage and debt service obligations may adversely affect our financial condition, results of operations and business prospects, and we may have difficulty paying our debts as they become due.
As of December 31, 2017, we had approximately $10.0 billion in principal amount of debt outstanding (including $52 million of current maturities and $781 million drawn under our senior secured revolving credit facility). We had approximately $116 million of letters of credit issued and borrowing capacity of approximately $2.9 billion under our $3.8 billion senior secured revolving credit facility.
The level of and terms and conditions governing our debt:
| • | 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 the cyclical nature of our business, economic downturns or other adverse developments in our business; |
| • | could limit our ability to access capital markets, refinance our existing indebtedness, raise capital on favorable terms, or obtain additional financing for working capital, capital expenditures, acquisitions, debt service requirements, 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 those that have less restrictive terms governing their indebtedness, thereby enabling competitors to take advantage of opportunities that our indebtedness may prevent us from pursuing; |
| • | limit management’s discretion in operating our business; and |
| • | increase our cost of borrowing. |
Any of the above listed factors could have a material adverse effect on our business, financial condition, cash flows and results of operations.
Our ability to pay our expenses and fund our working capital needs and debt obligations will depend on our future performance, which will be affected by financial, business, economic, regulatory and other factors. We will not be able to control many of these factors, such as commodity prices, other economic conditions and governmental regulation. We have drawn on our credit facility for liquidity, and the borrowing base under our credit facility is subject to redetermination on June 15, 2018. To the extent that the value of the collateral pledged under the credit facility declines as a result of lower oil and natural gas prices, asset dispositions or otherwise, we may be required to pledge additional collateral in order to maintain the current availability of the commitments thereunder, and we cannot assure you that we will be able to maintain a sufficiently high valuation to maintain the current commitments. In addition, we cannot be certain that our cash flow will be sufficient to allow us to pay the principal and interest on our debt and meet our other obligations. If we are unable to service our indebtedness and other obligations, we may be required to restructure or refinance all or part of our existing debt, sell assets, reduce capital expenditures, borrow more money or raise equity, some or all of which may not be available to us on terms acceptable to us, if at all, or such alternative strategies may yield insufficient funds to make required payments on our indebtedness. In addition, our ability to comply with the financial and other restrictive covenants in our indebtedness could be affected by our future performance and events or circumstances beyond our control. Failure to comply with these covenants would result in an event of default under such indebtedness, the potential acceleration of our obligation to repay outstanding debt and the potential foreclosure on the collateral securing such debt, and could cause a cross-default under our other outstanding indebtedness. Any of the above risks could materially adversely affect our business, financial condition, cash flows and results of operations.
We have significant capital needs, and our ability to access the capital and credit markets to raise capital on favorable terms is limited by our debt level and industry conditions.
Disruptions in the capital and credit markets, in particular with respect to the energy sector, could limit our ability to access these markets or may significantly increase our cost to borrow. Low commodity prices have caused and may continue to cause lenders to increase interest rates, enact tighter lending standards, refuse to refinance existing debt around maturity on favorable terms or at all and may reduce or cease to provide funding to borrowers. If we are unable to access the capital and credit markets on favorable terms, it could have a material adverse effect on our business, financial condition, results of operations, cash flows and liquidity and our ability to repay or refinance our debt.
If we are unable to generate enough cash flow from operations to service our indebtedness or are unable to use future borrowings to refinance our indebtedness or fund other capital needs, we may have to undertake alternative financing plans, which may have onerous terms or may be unavailable.
Our earnings and cash flow could vary significantly from year to year due to the cyclical nature of our industry. As a result, the amount of debt that we can manage in some periods may not be appropriate for us in other periods. Additionally, our future cash flow may be insufficient to meet our debt obligations and commitments. A range of economic, competitive, business and industry factors will affect our future financial performance and, as a result, our ability to generate cash flow from operations and service our debt. Factors that may cause us to generate cash flow that is insufficient to meet our debt obligations include the events and risks related to our business, many of which are beyond our control. Any cash flow insufficiency would have a material adverse impact on our business, financial condition, results of operations, cash flows and liquidity and our ability to repay or refinance our debt.
If we do not generate sufficient cash flow from operations to service our outstanding indebtedness, or if future borrowings are not available to us in an amount sufficient to enable us to pay or refinance our indebtedness, we may be required to undertake various alternative financing plans, which may include:
| • | refinancing or restructuring all or a portion of our debt; |
| • | seeking alternative financing or additional capital investment; |
| • | selling strategic assets; |
| • | reducing or delaying capital investments; or |
| • | revising or delaying our strategic plans. |
We cannot assure you that we would be able to implement any of the above alternative financing plans, if necessary, on commercially reasonable terms or at all. If we are unable to generate sufficient cash flow to satisfy our debt obligations or to obtain alternative financing, our business, financial condition, results of operations, cash flows and liquidity could be materially and adversely affected. Any failure to make scheduled payments of interest and principal on our outstanding indebtedness would likely result in a reduction of our credit rating, which could significantly harm our ability to incur additional indebtedness on acceptable terms. Further, if for any reason we are unable to meet our debt service and repayment obligations, we would be in default under the terms of the agreements governing our debt, which would allow our creditors under those agreements to declare all outstanding indebtedness thereunder to be due and payable (which would in turn trigger cross-acceleration or cross-default rights between the relevant agreements), the lenders under our credit facility could terminate their commitments to extend credit, and the lenders could foreclose against our assets securing their borrowings and we could be forced into bankruptcy or liquidation. In addition, the lenders under our credit facility could compel us to apply our available cash to repay our borrowings. If the amounts outstanding under the credit facility or any of our other significant indebtedness were to be accelerated, we cannot assure you that our assets would be sufficient to repay in full the amounts owed to the lenders or to our other debt holders.
Our variable rate indebtedness subjects us to interest rate risk, which could cause our debt service obligations to increase.
Borrowings under our revolving credit facility, term loan facility and floating rate senior notes due 2019 bear interest at variable rates and expose us to interest rate risk. If interest rates increase and we are unable to hedge our interest rate risk, our debt service obligations on the variable rate indebtedness would increase even though the amount borrowed remained the same.
Restrictive covenants in certain of our debt agreements could limit our growth and our ability to finance our operations, fund our capital needs, respond to changing conditions and engage in other business activities that may be in our best interests.
Certain of our debt agreements impose operating and financial restrictions on us. These restrictions limit our ability and that of our restricted subsidiaries to, among other things:
| • | 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. |
We may be prevented from taking advantage of business opportunities that arise because of the limitations imposed on us by the restrictive covenants under certain of our debt agreements. The restrictions contained in the covenants could:
| • | 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. |
Also, our credit facility requires us to maintain compliance with specified financial ratios and satisfy certain financial condition tests. Declines in oil, NGL and natural gas prices, or a prolonged period of low oil, NGL and natural gas prices and other events, some of which are beyond our control, could eventually result in our failing to meet one or more of the financial covenants under our credit facility, which could require us to refinance or amend such obligations resulting in the payment of consent fees or higher interest rates, or require us to raise additional capital at an inopportune time or on terms not favorable to us.
A breach of any of these covenants or our inability to comply with the required financial ratios or financial condition tests could result in a default under our credit facility that, if not cured or waived, could result in acceleration of all indebtedness outstanding thereunder and cross-default rights under our other debt. In addition, in the event of an event of default under the credit facility, term loan or second lien notes, the affected lenders could foreclose on the collateral securing the credit facility and require repayment of all borrowings outstanding thereunder. If the amounts outstanding under the credit facility or any of our other indebtedness were to be accelerated, our assets may not be sufficient to repay in full the amounts owed to the lenders or to our other debt holders.
Our credit rating could negatively impact our availability and cost of capital and could require us to post more collateral under certain commercial arrangements.
Some of our counterparties have requested or required us to post collateral as financial assurance of our performance under certain contractual arrangements, such as gathering, transportation, processing and hedging agreements. These collateral requirements depend, in part, on our credit ratings. As of February 20, 2018, we have received requests and posted approximately $151 million of collateral related to certain of our marketing and other contracts. We may be requested or required by other counterparties to post additional collateral in an aggregate amount of approximately $486 million, which may be in the form of additional letters of credit, cash or other acceptable collateral. Any downgrade to our credit ratings could impact the posting of collateral consisting of cash or letters of credit, which would reduce availability under our credit facility, and negatively impact our liquidity.
Declines in commodity prices could result in write downs of the carrying value of our oil and natural gas properties.
Under the full cost method of accounting for costs related to our oil and natural gas properties, we are required to write down the carrying value of our oil and natural gas assets if capitalized costs exceed the present value of future net revenues of our proved reserves, which is based on the average of commodity prices on the first day of the month
over the trailing 12-month period. Such write-downs could be material. As of December 31, 2017, the present value of estimated future net revenue of our proved reserves, discounted at an annual rate of 10%, was $7.5 billion, which exceeds the carrying value of our oil and natural gas properties.
Significant capital expenditures are required to replace our reserves and conduct our business.
Our exploration, development and acquisition activities require substantial capital expenditures. We intend to fund our capital expenditures through cash flows from operations, and to the extent that is not sufficient, borrowings under our revolving credit facility. Our ability to generate operating cash flow is subject to a number of risks and variables, such as the level of production from existing wells, prices of oil, natural gas and NGL, our success in developing and producing new reserves and the other risk factors discussed herein. If we are unable to fund our capital expenditures as planned, we could experience a curtailment of our exploration and development activity, a loss of properties and a decline in our oil, natural gas and NGL reserves.
If we are not able to replace reserves, we may not be able to sustain production.
Our future success depends largely upon our ability to find, develop or acquire additional oil and natural gas reserves that are economically recoverable. Unless we replace the reserves we produce through successful development, exploration or acquisition activities, our proved reserves and production will decline over time. Our reserve estimates as of December 31, 2017 reflect an expected decline in the production rate on our producing properties of approximately 35% in 2018 and 23% in 2019. Thus, our future oil and natural gas reserves and production, and therefore our cash flow and income, are highly dependent on our success in efficiently developing our current reserves and economically finding or acquiring additional recoverable reserves.
The actual quantities of and future net revenues from our proved reserves may be less than our estimates.
The estimates of our proved reserves and the estimated future net revenues from our proved reserves included in this report are based upon various assumptions, including assumptions required by the SEC relating to oil, natural gas and NGL prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. The process of estimating oil, natural gas and NGL reserves is complex and involves significant decisions and assumptions associated with geological, geophysical, engineering and economic data for each well. Therefore, these estimates are subject to future revisions.
Actual future production, oil, natural gas and NGL prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil, natural gas and NGL reserves most likely will vary from these estimates. Such variations may be significant and could materially affect the estimated quantities and present value of our proved reserves. In addition, we may adjust estimates of proved reserves to reflect production history, results of exploration and development drilling, prevailing oil and natural gas prices and other factors, many of which are beyond our control.
As of December 31, 2017, approximately 42% of our estimated proved reserves (by volume) were undeveloped. These reserve estimates reflect our plans to make significant capital expenditures to convert our PUDs into proved developed reserves, including approximately $4.3 billion during the next five years ending in 2022. You should be aware that the estimated development costs may not equal our actual costs, development may not occur as scheduled and results may not be as estimated. If we choose not to develop our PUDs, or if we are not otherwise able to successfully develop them, we will be required to remove them from our reported proved reserves. In addition, under the SEC's reserve reporting rules, because PUDs generally may be booked only if they relate to wells scheduled to be drilled within five years of the date of booking, we may be required to remove any PUDs that are not developed within this five-year time frame.
You should not assume that the present values included in this report represent the current market value of our estimated reserves. In accordance with SEC requirements, the estimates of our present values are based on prices and costs as of the date of the estimates. The price on the date of estimate is calculated as the average oil and natural gas price during the 12 months ending in the current reporting period, determined as the unweighted arithmetic average of prices on the first day of each month within the 12-month period. The December 31, 2017 present value is based on a $51.34 per bbl of oil price and a $2.98 per mcf of natural gas price, before considering basis differential adjustments. Actual future prices and costs may be materially higher or lower than the prices and costs as of the date of an estimate.
The timing of both the production and the expenses from the development and production of oil and natural gas properties will affect both the timing of future net cash flows from our proved reserves and their present value. Any changes in demand for oil and natural gas, governmental regulations or taxation will also affect the future net cash flows from our production. In addition, the 10% discount factor that is required by the SEC to be used in calculating
discounted future net cash flows for reporting purposes is not necessarily the most appropriate discount factor. Interest rates in effect from time to time and the risks associated with our business or the oil and gas industry in general will affect the appropriateness of the 10% discount factor.
Our development and exploratory drilling efforts and our well operations may not be profitable or achieve our targeted returns.
We have a substantial inventory of undeveloped properties. Development and exploratory drilling and production activities are subject to many risks, including the risk that commercially productive reservoirs will not be discovered. We have acquired undeveloped properties that we believe will enhance our growth potential and increase our earnings over time. However, we cannot assure you that all prospects will be economically viable or that we will not abandon our initial investments. Additionally, there can be no assurance that undeveloped properties acquired by us will be profitably developed, that new wells drilled by us in prospects that we pursue will be productive, or that we will recover all or any portion of our investment in such undeveloped properties or wells.
Drilling for oil and natural gas may involve unprofitable efforts, not only from dry wells but also from wells that are productive but do not produce sufficient commercial quantities to cover the drilling, operating and other costs. The cost of drilling, completing and operating a well is often uncertain, and many factors can adversely affect the economics of a well or property. Drilling and completion operations may be curtailed, delayed or canceled as a result of unexpected drilling conditions, title problems, equipment failures or accidents, shortages of midstream transportation, equipment or personnel, environmental issues, state or local bans or moratoriums on hydraulic fracturing and produced water disposal, and a decline in commodity prices, among others. The profitability of wells, particularly in certain of the areas in which we operate, will be reduced or eliminated as commodity prices decline. In addition, wells that are profitable may not meet our internal return targets, which are dependent upon the current and future market prices for oil, natural gas and NGL, costs associated with producing oil, natural gas and NGL and our ability to add reserves at an acceptable cost. All costs of development and exploratory drilling activities are capitalized under the full cost method, even if the activities do not result in commercially productive discoveries, which may result in a future impairment of our oil and natural gas properties if commodity prices decrease.
We rely to a significant extent on seismic data and other advanced technologies in evaluating undeveloped properties and in conducting our exploration activities. The seismic data and other technologies we use do not allow us to know conclusively, prior to acquisition of undeveloped properties, or drilling a well, whether oil or natural gas is present or may be produced economically. If we incur significant expense in acquiring or developing properties that do not produce as expected or at profitable levels, it could have a material adverse effect on our results of operations and financial condition.
Certain of our undeveloped properties are subject to leases that will expire over the next several years unless production is established on units containing the acreage or the leases are renewed.
Leases on oil and natural gas properties typically have a term of three to five years, after which they expire unless, prior to expiration, a well is drilled and production of hydrocarbons in paying quantities is established. If our leases on our undeveloped properties expire and we are unable to renew the leases, we will lose our right to develop the related properties. Although we seek to actively manage our undeveloped properties, our drilling plans for these areas are subject to change based upon various factors, including drilling results, oil and natural gas prices, the availability and cost of capital, drilling and production costs, availability of drilling services and equipment, gathering system and pipeline transportation constraints and regulatory approvals. Low commodity prices may cause us to delay our drilling plans and, as a result, lose our right to develop the related properties.
Our commodity price risk management activities may limit the benefit we would receive from increases in commodity prices, may require us to provide collateral for derivative liabilities and involve risk that our counterparties may be unable to satisfy their obligations to us.
In order to manage our exposure to price volatility, we enter into oil, natural gas and NGL price derivative contracts. Our oil, natural gas and NGL derivative arrangements may limit the benefit we would receive from increases in commodity prices. The fair value of our oil, natural gas and NGL derivative instruments can fluctuate significantly between periods. Our decision to mitigate cash flow volatility through derivative arrangements, if any, is based in part on our view of current and future market conditions and our desire to stabilize cash flows necessary for the development of our proved reserves. We may choose not to enter into derivatives if the pricing environment for certain time periods is not deemed to be favorable. Additionally, we may choose to liquidate existing derivative positions prior to the expiration of their contractual maturities to monetize gain positions for the purpose of funding our capital program.
Most of our oil, natural gas and NGL derivative contracts are with counterparties under bi-lateral hedging arrangements. Under a majority of our arrangements, the collateral provided for our obligations is secured by the same hydrocarbon interests that secure our senior secured revolving credit facility. Under other arrangements, our obligations under the bi-lateral hedging arrangements 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. Under certain circumstances, the cash collateral value posted could fall below the coverage designated, and we would be required to post additional cash or letter of credit collateral under our hedging arrangements. Our counterparties’ obligations under the arrangements must be secured by cash or letters of credit to the extent that any mark-to-market amounts owed to us exceed defined thresholds. Collateral requirements are dependent to a large extent on oil and natural gas prices.
Oil, natural gas and NGL derivative transactions expose us to the risk that our counterparties, which are generally financial institutions, may be unable to satisfy their obligations to us. During periods of declining commodity prices, the value of our commodity derivative asset positions increase, which increases our counterparty exposure. Although the counterparties to our hedging arrangements are required to secure their obligations to us under certain scenarios, if any of our counterparties were to default on its obligations to us under the derivative contracts or seek bankruptcy protection, it could have an adverse effect on our ability to fund our planned activities and could result in a larger percentage of our future cash flows being exposed to commodity price changes.
The ultimate outcome of pending legal and governmental proceedings is uncertain, and there are significant costs associated with these matters.
We are defending against claims by royalty owners alleging, among other things, that we used below-market prices, made improper deductions, used improper measurement techniques, entered into arrangements with affiliates that resulted in underpayment of royalties in connection with the production and sales of natural gas and NGL and similar theories. Numerous cases are pending. The resolution of disputes regarding past payments could cause our future obligations to royalty owners to increase and would negatively impact our future results of operations.
In addition, there are ongoing governmental regulatory investigations and inquiries into such matters as our royalty practices and possible antitrust violations. The outcome of any pending or future litigation or governmental regulatory matter is uncertain and may adversely affect our results of operations. In addition, we have incurred substantial legal expenses in the past three years, and such expenses may continue to be significant in the future. Further, attention to these matters by members of our senior management has been required, reducing the time they have available to devote to managing our business.
We may continue to incur cash and noncash charges that would negatively impact our future results of operations and liquidity.
While executing our strategic priorities to reduce financial leverage and complexity and to lower our capital expenditures in the face of lower commodity prices, we have incurred certain cash charges, including contract termination charges, restructuring and other termination costs, financing extinguishment costs and charges for unused natural gas transportation and gathering capacity. As we continue to focus on our strategic priorities, we may incur additional cash and noncash charges in 2018 and in future years. If incurred, these charges could materially adversely impact our future results of operations and liquidity.
Oil and natural gas drilling and producing operations can be hazardous and may expose us to liabilities.
Oil and natural gas operations are subject to many risks, including well blowouts, cratering, explosions, pipe failures, fires, formations with abnormal pressures, uncontrollable flows of oil, natural gas, brine or well fluids, oil spills, severe weather, natural disasters, groundwater contamination and other environmental hazards and risks. Some of these risks or hazards could materially and adversely affect our revenues and expenses by reducing or shutting in production from wells or otherwise negatively impacting the projected economic performance of our prospects. For our non-operated properties, we are dependent on the operator for operational and regulatory compliance. If any of these risks occurs, we could sustain substantial losses as a result of:
| • | 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. |
A material event such as those described above could expose us to liabilities, monetary penalties or interruptions in our business operations. While we may maintain insurance against some, but not all, of the risks described above, our insurance may not be adequate to cover casualty losses or liabilities, and our insurance does not cover penalties or fines that may be assessed by a governmental authority. For certain risks, such as political risk, business interruption, war, terrorism and piracy, we have limited or no insurance coverage. Also, in the future we may not be able to obtain insurance at premium levels that justify its purchase. The occurrence of a significant event against which we are not fully insured may expose us to liabilities.
We are subject to complex laws and regulations relating to environmental protection that can adversely affect the cost, manner and feasibility of doing business, and further regulation in the future could increase costs, impose additional operating restrictions and cause delays.
Our operations and properties are subject to numerous federal, regional, state and local laws and regulations governing the release of pollutants or otherwise relating to environmental protection. These laws and regulations govern the following, among other things:
| • | 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. |
In addition, these laws and regulations may impose substantial liabilities for our failure to comply or for any contamination resulting from our operations, including the assessment of administrative, civil and criminal penalties; the imposition of investigatory, remedial, and corrective action obligations or the incurrence of capital expenditures; the occurrence of delays in the development of projects; and the issuance of injunctions restricting or prohibiting some or all of our activities in a particular area. Future environmental laws and regulations imposing further restrictions on the emission of pollutants into the air, discharges into state or U.S. waters, wastewater disposal and hydraulic fracturing, or the designation of previously unprotected species as threatened or endangered in areas where we operate, may negatively impact our industry. We cannot predict the actions that future regulation will require or prohibit, but our business and operations could be subject to increased operating and compliance costs if certain regulatory proposals are adopted. In addition, such regulations may have an adverse impact on our ability to develop and produce our reserves.
Federal and state legislative and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays.
Several states have adopted or are considering adopting regulations that could impose more stringent permitting, public disclosure and/or well construction requirements on hydraulic fracturing operations. In addition to state laws, some local municipalities have adopted or are considering adopting land use restrictions, such as city ordinances, that may restrict or prohibit the performance of well drilling in general and/or hydraulic fracturing in particular. There have
also been certain governmental reviews that focus on deep shale and other formation completion and production practices, including hydraulic fracturing. These studies assess, among other things, the risks of groundwater contamination and earthquakes caused by hydraulic fracturing and other exploration and production activities. Based on the results of these studies, federal and state legislatures and agencies may seek to further regulate or even ban such activities, as some state and local governments have already done. In addition, a number of lawsuits have been filed in Oklahoma alleging damage from earthquakes relating to disposal well operations.
We cannot predict whether additional federal, state or local laws or regulations applicable to hydraulic fracturing will be enacted in the future and, if so, what actions any such laws or regulations would require or prohibit. If additional levels of regulation or permitting requirements were imposed on hydraulic fracturing operations, our business and operations could be subject to delays, increased operating and compliance costs and process prohibitions. Additional regulation could also lead to greater opposition to hydraulic fracturing, including litigation.
Our ability to produce oil, natural gas and NGL economically and in commercial quantities could be impaired if we are unable to acquire adequate supplies of water for our operations or are unable to dispose of or recycle the water we use economically and in an environmentally safe manner.
Development activities require the use of water. For example, hydraulic fracturing requires the use and disposal of significant quantities of water. In certain areas, there may be insufficient local aquifer capacity to provide a source of water for drilling activities. Water must be obtained from other sources and transported to the drilling site. Our inability to secure sufficient amounts of water, or to dispose of or recycle the water used in our operations, could adversely impact our operations in certain areas. The imposition of new environmental initiatives and regulations, such as the OCC’s volume reduction plans for oil and natural gas disposal wells injecting wastewater into the Arbuckle formation and the EPA’s June 2016 pretreatment standards for wastewater, could further restrict our ability to conduct certain operations such as hydraulic fracturing or disposal of waste, including, but not limited to, produced water, drilling fluids and other materials associated with the exploration, development or production of oil and natural gas.
Potential legislative and regulatory actions addressing climate change could significantly impact our industry and us, causing increased costs and reduced demand for oil and natural gas.
Various state governments and regional organizations are considering enacting new legislation and promulgating new regulations governing or restricting the emission of greenhouse gases from stationary sources such as our equipment and operations. At the federal level, the EPA has already made findings and issued regulations that require us to establish and report a prescribed inventory of greenhouse gas emissions. Additional legislative and/or regulatory proposals for restricting greenhouse gas emissions or otherwise addressing climate change could require us to incur additional operating costs and could adversely affect demand for the oil and natural gas that we sell. The potential increase in our operating costs could include new or increased costs to obtain permits, operate and maintain our equipment and facilities, install new emission controls on our equipment and facilities, acquire allowances to authorize our greenhouse gas emissions, pay taxes related to our greenhouse gas emissions and administer and manage a greenhouse gas emissions program. Even without federal legislation or regulation of greenhouse gas emissions, states may pursue the issue either directly or indirectly.
In addition, the United States was actively involved in the United Nations Conference on Climate Change in Paris, which led to the creation of the Paris Agreement. The Paris Agreement will require countries to review and “represent a progression” in their nationally determined contributions, which set emissions reduction goals, every five years. In August 2017, the United States informed the United Nations of its intent to withdraw from the Paris Agreement. The earliest possible effective withdrawal date from the Paris Agreement is November 2020. The Paris Agreement could further drive regulation in the United States. Restrictions on emissions of methane or carbon dioxide that have been or may be imposed in various states, or at the federal level could adversely affect the oil and gas industry. Moreover, incentives to conserve energy or use alternative energy sources as a means of addressing climate change could reduce demand for oil and natural gas. Finally, we note that some scientists have concluded that increasing concentrations of greenhouse gases in the Earth's atmosphere may produce climate changes that have significant physical effects, such as higher sea levels, increased frequency and severity of storms, droughts, floods, and other climatic events. If any such effects were to occur, they could have an adverse effect on our financial condition and results of operations.
The taxation of independent producers is subject to change, and changes in tax law could increase our cost of doing business.
We are subject to taxation by various taxing authorities at the federal, state and local levels where we do business. New legislation increasing our tax burden could be enacted by any of these governmental authorities. Recently, legislative changes imposing additional taxes or increases to existing taxes were considered in Louisiana, Ohio, Oklahoma, Pennsylvania and Wyoming. It is possible that any of these states could enact new tax legislation making it more costly for us to explore for oil and natural gas resources.
Additionally, on December 22, 2017, the President of the United States signed into law tax reform legislation informally known as the Tax Cuts and Jobs Act (the “Tax Act”) that substantially revised numerous areas of U.S. federal income tax law. Although we do not expect there to be an immediate adverse impact on our federal income taxes from the Tax Act, new restrictions on items such as the utilization of net operating loss (NOL) carryforwards and the deductibility of business interest could adversely impact our federal income taxes in future years. Furthermore, the extent to which state and local taxing authorities will adopt tax laws that conform with or differ from provisions of the Tax Act is unclear. Any change in state or local tax law in response to the Tax Act could affect our tax burden and make it more costly for us to explore for oil and natural gas resources.
Further, our ability to utilize our federal NOL carryforwards to reduce future taxable income and federal income tax is subject to various limitations under the Internal Revenue Code of 1986, as amended (the “Code”). The utilization of such carryforwards may be limited upon the occurrence of certain ownership changes, including the acquisition or disposition of our stock by 5% shareholders and our offering of stock during any three-year period resulting in a cumulative shift of more than 50% in our beneficial ownership. In the event of an ownership change, Section 382 of the Code imposes an annual limitation on the amount of NOL carryforwards (accumulated prior to the change date) that can be used to offset our future taxable income. The limitation is generally equal to the product of (a) the fair market value of our equity multiplied by (b) the long-term tax-exempt rate in effect for the month in which the ownership change occurs. In addition, if we are in a net unrealized built-in gain position at the time of an ownership change then the limitation may be increased if there are recognized built-in gains during a certain recognition period following the ownership change. If we are in a net unrealized built-in loss position at the time of an ownership change then the limitation may apply to tax attributes other than just NOL carryforwards such as depreciable basis. Some states impose similar limitations on tax attribute utilization upon experiencing an ownership change. We do not believe that an ownership change has occurred as of December 31, 2017 that would limit future utilization of our NOL carryforwards or other tax attributes.
The oil and gas exploration and production industry is very competitive, and some of our competitors have greater financial and other resources than we do.
We face competition in every aspect of our business, including, but not limited to, buying and selling reserves and leases, obtaining goods and services needed to operate our business and marketing oil, natural gas or NGL. Competitors include multinational oil companies, independent production companies and individual producers and operators. Some of our competitors have greater financial and other resources than we do and, due to our debt levels and other factors, may have greater access to the capital and credit markets. As a result, these competitors may be able to address these competitive factors more effectively or weather industry downturns more easily than we can. We also face indirect competition from alternative energy sources, including wind, solar and electric power.
Our performance depends largely on the talents and efforts of highly skilled individuals and on our ability to attract new employees and to retain and motivate our existing employees. Competition in our industry for qualified employees is intense. If we are unsuccessful in attracting and retaining skilled employees and managerial talent, our ability to compete effectively will be diminished.
Risks related to potential acquisitions or dispositions may adversely affect our business.
From time to time, we evaluate acquisitions and dispositions of assets, businesses and other investments. These transactions may not result in the anticipated benefits or efficiencies. In addition, acquisitions may be financed by borrowings, requiring us to incur more debt, or by the issuance of our common stock. Any such acquisition or disposition involves risks and we cannot assure that:
| • | any acquisition would be successfully integrated into our operations and internal controls; |
| • | the due diligence conducted prior to an acquisition would uncover situations that could result in financial or legal exposure, such as title defects and potential environmental and other liabilities; |
| • | post-closing purchase price adjustments will be realized in our favor; |
| • | our assumptions about, among other things, reserves, estimated production, revenues, capital expenditures, operating, operating expenses and costs would be accurate; |
| • | any investment, acquisition, disposition or integration would not divert management resources from the operation of our business; and |
| • | any investment, acquisition, or disposition or integration would not have a material adverse effect on our financial condition, results of operations, cash flows or reserves. |
If any of these risks materialize, the benefits of such acquisition or disposition may not be fully realized, if at all, and our financial condition, results of operations, cash flows and reserves could be negatively impacted.
A deterioration in general economic, business or industry conditions would have a material adverse effect on our results of operations, liquidity and financial condition.
Historically, concerns about global economic growth have had a significant impact on global financial markets and commodity prices. If the economic climate in the United States or abroad deteriorates, worldwide demand for petroleum products could diminish, which could impact the price at which we can sell our production, affect the ability of our vendors, suppliers and customers to continue operations and materially adversely impact our results of operations, liquidity and financial condition.
Terrorist activities could materially and adversely affect our business and results of operations.
Terrorist attacks and the threat of terrorist attacks, whether domestic or foreign attacks, as well as military or other actions taken in response to these acts, could cause instability in the global financial and energy markets. Continued hostilities in the Middle East and the occurrence or threat of terrorist attacks in the United States or other countries could adversely affect the global economy in unpredictable ways, including the disruption of energy supplies and markets, increased volatility in commodity prices, or the possibility that the infrastructure on which we rely could be a direct target or an indirect casualty of an act of terrorism, and, in turn, could materially and adversely affect our business and results of operations.
Negative public perception regarding us and/or our industry could have an adverse effect on our operations.
Negative public perception regarding us and/or our industry resulting from, among other things, concerns raised by advocacy groups about hydraulic fracturing, waste disposal, oil spills, and explosions of natural gas transmission lines may lead to increased regulatory scrutiny, which may, in turn, lead to new state and federal safety and environmental laws, regulations, guidelines and enforcement interpretations. These actions may cause operational delays or restrictions, increased operating costs, additional regulatory burdens and increased risk of litigation. Moreover, governmental authorities exercise considerable discretion in the timing and scope of permit issuance and the public may engage in the permitting process, including through intervention in the courts. Negative public perception could cause the permits we require to conduct our operations to be withheld, delayed or burdened by requirements that restrict our ability to profitably conduct our business.
Our operations may be adversely affected by pipeline, trucking and gathering system capacity constraints and may be subject to interruptions that could adversely affect our cash flow.
In certain shale plays, the capacity of gathering and transportation systems is insufficient to accommodate potential production from existing and new wells. We rely heavily on third parties to meet our oil, natural gas and NGL gathering needs. Capital constraints could limit the construction of new pipelines and gathering systems and the providing or expansion of trucking services by third parties. Until this new capacity is available, we may experience delays in producing and selling our oil, natural gas and NGL. In such event, we might have to shut in our wells awaiting a pipeline connection or capacity and/or sell oil, natural gas or NGL production at significantly lower prices than those quoted on NYMEX or than we currently project, which would adversely affect our results of operations.
A portion of our oil, natural gas and NGL production in any region may be interrupted, or shut in, from time to time for numerous reasons, including weather conditions, accidents, loss of pipeline or gathering system access, field labor issues or strikes, or we might voluntarily curtail production in response to market conditions. If a substantial amount of our production is interrupted at the same time, it could materially adversely affect our cash flow.
Cyber-attacks targeting systems and infrastructure used by the oil and gas industry may adversely impact our operations.
Our business has become increasingly dependent on digital technologies to conduct certain exploration, development and production activities. We depend on digital technology to estimate quantities of oil, natural gas and NGL reserves, process and record financial and operating data, analyze seismic and drilling information, and communicate with our employees and third-party partners. We have been the subject of cyber-attacks on our internal systems and through those of third parties, but these incidents did not have a material adverse impact on our results of operations. Nevertheless, unauthorized access to our seismic data, reserves information or other proprietary or commercially sensitive information could lead to data corruption, communication interruption, or other disruptions in our exploration or production operations or planned business transactions, any of which could have a material adverse impact on our results of operations. Further, as cyber-attacks continue to evolve, we may be required to expend significant additional resources to continue to modify or enhance our protective measures or to investigate and remediate any vulnerabilities to cyber-attacks.
An interruption in operations at our headquarters could adversely affect our business.
Our headquarters are located in Oklahoma City, Oklahoma, an area that experiences severe weather events, including tornadoes and earthquakes. Our information systems and administrative and management processes are primarily provided to our various drilling projects and producing wells throughout the United States from this location, which could be disrupted if a catastrophic event, such as a tornado, power outage or act of terror, destroyed or severely damaged our headquarters. Any such catastrophic event could harm our ability to conduct normal operations and could adversely affect our business.
We do not anticipate paying dividends on our common stock in the near future.
In July 2015, our Board of Directors determined to eliminate quarterly cash dividends on our common stock. Accordingly, we do not intend to pay cash dividends on our common stock in the foreseeable future. We currently intend to retain any earnings for the future operation and development of our business, including exploration, development and acquisition activities or to retire outstanding debt and/or preferred stock. Any future dividend payments will require approval by the Board of Directors. In addition, dividends may be restricted by the terms of our debt agreements. Additionally, our Board of Directors may determine to suspend dividend payments on our preferred stock in the future. If we fail to pay dividends on our preferred stock with respect to six or more quarterly periods (whether or not consecutive), the holders of our preferred stock, voting as a single class, will be entitled at the next regular or special meeting of shareholders to elect two additional directors of the Company. We had previously failed to pay dividends on our outstanding preferred stock with respect to four quarterly periods during the fiscal year ended December 31, 2016, before resuming payment, in arrears, in the first quarter of 2017.
Certain anti-takeover and other provisions may affect your rights as a shareholder.
Our certificate of incorporation authorizes our Board of Directors to set the terms of and issue preferred stock without shareholder approval. Our Board of Directors could use the preferred stock as a means to delay, defer or prevent a takeover attempt that a shareholder might consider to be in our best interest. In addition, our revolving credit facility, term loan facility, preferred stock and certain of our notes contain terms that may restrict our ability to enter into change of control transactions, including requirements to repay borrowings under our revolving credit facility and to offer to purchase our term loan and to offer to repurchase such notes on a change in control. These provisions, along with specified provisions of the Oklahoma General Corporation Act and our certificate of incorporation and bylaws, may discourage or impede transactions involving actual or potential changes in our control, including transactions that otherwise could involve payment of a premium over prevailing market prices to holders of our common stock.
Item 1B. Unresolved Staff Comments
Not applicable.
Item 2. Properties
Information regarding our properties is included in Item 1 and in the Supplementary Information included in Item 8 of Part II of this report.
Item 3. Legal Proceedings
Litigation and Regulatory Proceedings
We are involved in a number of litigation and regulatory proceedings including those described below. Many of these proceedings are in early stages, and many of them seek or may seek damages and penalties, the amount of which is currently indeterminate. See Note 4 of the notes to our consolidated financial statements included in Item 8 of Part I of this report for information regarding our estimation and provision for potential losses related to litigation and regulatory proceedings.
Regulatory and Related Proceedings. We have received U.S. Postal Service and state subpoenas seeking information on our royalty payment practices. We have engaged in discussions with the U.S. Postal Service and state agency representatives and continue to respond to related subpoenas and demands.
Business Operations. We are involved in various other lawsuits and disputes incidental to our business operations, including commercial disputes, personal injury claims, royalty claims, property damage claims and contract actions.
Regarding royalty claims, we and other natural gas producers have been named in various lawsuits alleging royalty underpayments. The lawsuits against us allege, among other things, that we used below-market prices, made improper deductions, utilized improper measurement techniques, entered into arrangements with affiliates that resulted in underpayment of royalties in connection with the production and sale of natural gas and NGL, or similar theories. These lawsuits include cases filed by individual royalty owners and putative class actions, some of which seek to certify a statewide class. The lawsuits seek compensatory, consequential, treble, and punitive damages, restitution and disgorgement of profits, declaratory and injunctive relief regarding our royalty payment practices, pre-and post-judgment interest, and attorney’s fees and costs. 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. We have 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 numerous lawsuits seeking damages with respect to underpayment of royalties in multiple states where we have operated, including the matters set forth below.
On December 9, 2015, the Commonwealth of Pennsylvania, by the Office of Attorney General, filed a lawsuit in the Bradford County Court of Common Pleas related to royalty underpayment and lease acquisition and accounting practices with respect to properties in Pennsylvania. The lawsuit, which primarily relates to the Marcellus Shale and Utica Shale, alleges that we 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 we are a party established unlawful market allocation for the acquisition of leases. The lawsuit seeks statutory restitution, civil penalties and costs, as well as a temporary injunction from exploration and drilling activities in Pennsylvania until restitution, penalties and costs have been paid, and a permanent injunction from further violations of the UTPCPL.
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 our divestiture of substantially all of our midstream business and most of our 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, intentional interference with contractual relations, and violations of antitrust laws related to purported markets for gas mineral rights, operating rights and gas gathering sources. These lawsuits seek in aggregate compensatory, consequential, treble, and punitive damages, restitution and disgorgement of profits, declaratory and injunctive relief regarding our royalty payment practices, pre-and post-judgment interest, and attorney’s fees and costs. On December 20, 2017, we reached a tentative settlement to resolve substantially all Pennsylvania civil royalty cases for approximately $30 million.
We are also defending lawsuits alleging various violations of the Sherman Antitrust Act and state antitrust laws. In 2016, putative class action lawsuits were filed in the U.S. District Court for the Western District of Oklahoma and in Oklahoma state courts, and an individual lawsuit was filed in the U.S. District Court of Kansas, in each case against us and other defendants. The lawsuits generally allege that, since 2007 and continuing through April 2013, the defendants conspired to rig bids and depress the market for the purchases of oil and natural gas leasehold interests and properties in the Anadarko Basin containing producing oil and natural gas wells. The lawsuits seek damages, attorney’s fees, costs and interest, as well as enjoinment from adopting practices or plans that would restrain competition in a similar manner as alleged in the lawsuits.
Environmental Proceedings
Our subsidiary Chesapeake Appalachia, LLC (CALLC) is engaged in discussions with the EPA, the USACE and the Pennsylvania Department of Environmental Protection (PADEP) regarding potential violations of the permitting requirements of the federal CWA, the Pennsylvania Clean Streams Law and the Pennsylvania Dam Safety and Encroachments Act in connection with the placement of dredge and fill material during construction of certain sites in Pennsylvania. CALLC identified the potential violations in connection with an internal review of its facilities siting and construction processes and voluntarily reported them to the regulatory agencies. Resolution of the matter may result in monetary sanctions of more than $100,000.
We are also in discussions with PADEP regarding gas migration in the vicinity of certain of our wells in Bradford County, Pennsylvania. We believe we are close to identifying agreed-upon steps to resolve PADEP’s concerns regarding the issue. In addition to these steps, we anticipate making a donation of $300,000 to the PADEP’s well plugging fund.
On December 27, 2016, we received a Finding of Violation from the EPA alleging violations of the CAA at a number of locations in Ohio. We have exchanged information with the EPA and are engaged in discussions aimed at resolving the allegations. Resolution of the matter may result in monetary sanctions of more than $100,000.
We are named as a defendant in numerous lawsuits and putative class actions in Oklahoma alleging that we and other companies have engaged in activities that have caused earthquakes. These lawsuits seek compensation for injury to real and personal property, diminution of property value, economic losses due to business interruption, interference with the use and enjoyment of property, annoyance and inconvenience, personal injury and emotional distress. In addition, they seek the reimbursement of insurance premiums and the award of punitive damages, attorneys’ fees, costs, expenses and interest.
Item 4. Mine Safety Disclosures
Not applicable.
PART II
Item 5. Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
Price Range of Common Stock
Our common stock trades on the New York Stock Exchange under the symbol "CHK". The following table sets forth, for the periods indicated, the high and low sales prices per share of our common stock as reported by the New York Stock Exchange:
| Common Stock | ||||||||
| High | Low | |||||||
| Year Ended December 31, 2017: | ||||||||
| Fourth Quarter | $ | 4.38 | $ | 3.41 | ||||
| Third Quarter | $ | 5.20 | $ | 3.55 | ||||
| Second Quarter | $ | 6.59 | $ | 4.38 | ||||
| First Quarter | $ | 7.32 | $ | 4.88 | ||||
| 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 |
Shareholders
As of February 20, 2018, there were approximately 1,850 holders of record of our common stock and approximately 595,000 beneficial owners.
Dividends
We ceased paying dividends on our common stock in the 2015 third quarter and do not anticipate paying any dividends on our common stock in the foreseeable future. Our revolving credit facility, our term loan facility and the certificates of designation for our preferred stock contain restrictions on our ability to declare and pay cash dividends on our common or preferred stock if an event of default has occurred. The certificates of designation for our preferred stock prohibit payment of cash dividends on our common stock unless we have declared and paid (or set apart for payment) full accumulated dividends on the preferred stock. After suspending the payment of dividends on our outstanding convertible preferred stock during fiscal year 2016, we reinstated the payment of dividends on each series of our outstanding convertible preferred stock beginning with the dividends payable in the 2017 first quarter and paid all dividends in arrears.
Unregistered Sales of Equity Securities and Use of Proceeds
The following table presents information about repurchases of our common stock during the quarter ended December 31, 2017:
| Period | Total Number of Shares Purchased(a) | Average Price Paid Per Share(a) | Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs | Maximum Approximate Dollar Value of Shares That May Yet Be Purchased Under the Plans or Programs(b) | ||||||||||
| ($ in millions) | ||||||||||||||
| October 1, 2017 through October 31, 2017 | 11,666 | $ | 4.36 | — | $ | 1,000 | ||||||||
| November 1, 2017 through November 30, 2017 | — | $ | — | — | $ | 1,000 | ||||||||
| December 1, 2017 through December 31, 2017 | — | $ | — | — | $ | 1,000 | ||||||||
| Total | 11,666 | $ | 4.36 | — |
| (a) | Includes shares of common stock purchased on behalf of our deferred compensation plan related to participant deferrals and Company matching contributions. |
| (b) | In December 2014, our Board of Directors authorized the repurchase of up to $1 billion of our common stock from time to time. The repurchase program does not have an expiration date. As of December 31, 2017, there have been no repurchases under the program. |
Item 6. Selected Financial Data
The following table sets forth selected consolidated financial data of Chesapeake as of and for the years ended December 31, 2017, 2016, 2015, 2014 and 2013. The data are derived from our audited consolidated financial statements. The table below should be read in conjunction with Management's Discussion and Analysis of Financial Condition and Results of Operations and our consolidated financial statements, including the notes thereto, appearing in Items 7 and 8, respectively, of this report.
| Years Ended December 31, | ||||||||||||||||||||
| 2017 | 2016 | 2015 | 2014 | 2013 | ||||||||||||||||
| ($ in millions, except per share data) | ||||||||||||||||||||
| STATEMENT OF OPERATIONS DATA: | ||||||||||||||||||||
| Total revenues | $ | 9,496 | $ | 7,872 | $ | 12,764 | $ | 23,125 | $ | 19,080 | ||||||||||
| Net income (loss) available to common stockholders(a) | $ | 813 | $ | (4,915 | ) | $ | (14,738 | ) | $ | 1,273 | $ | 474 | ||||||||
| EARNINGS (LOSS) PER COMMON SHARE: | ||||||||||||||||||||
| Basic | $ | 0.90 | $ | (6.43 | ) | $ | (22.26 | ) | $ | 1.93 | $ | 0.73 | ||||||||
| Diluted | $ | 0.90 | $ | (6.43 | ) | $ | (22.26 | ) | $ | 1.87 | $ | 0.73 | ||||||||
| CASH DIVIDEND DECLARED PER COMMON SHARE | $ | — | $ | — | $ | 0.0875 | $ | 0.35 | $ | 0.35 | ||||||||||
| BALANCE SHEET DATA (AT END OF PERIOD): | ||||||||||||||||||||
| Total assets | $ | 12,425 | $ | 13,028 | $ | 17,314 | $ | 40,655 | $ | 41,663 | ||||||||||
| Long-term debt, net of current maturities | $ | 9,921 | $ | 9,938 | $ | 10,311 | $ | 11,058 | $ | 12,767 | ||||||||||
| Total equity (deficit) | $ | (372 | ) | $ | (1,203 | ) | $ | 2,397 | $ | 18,205 | $ | 18,140 |
| (a) | Includes $2.564 billion and $18.238 billion of full cost ceiling test write-downs on our oil and natural gas properties for the years ended December 31, 2016 and 2015, respectively. In 2017, 2014 and 2013, we did not have any ceiling test impairments on our oil and natural gas properties. |
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
Overview
Introduction
The following discussion and analysis presents management’s perspective of our business, financial condition and overall performance. This information is intended to provide investors with an understanding of our past performance, current financial condition and outlook for the future and should be read in conjunction with “Item 8. Financial Statements and Supplementary Data” of this report.
Overview of 2017 Results
The transformation of Chesapeake over the past four years has been significant and our progress continued in 2017. Our progress has been guided by our strategies of financial discipline, pursuing profitable and efficient growth from our captured resources, leveraging technology and our operational expertise to unlock additional domestic resources through exploration and development and optimizing our portfolio through business development. Our strategies have not changed through the price cycles of the past several years, and we believe our recent accomplishments and achievements in 2017 have made our company stronger. Highlights include the following:
| • | grew estimated proved reserves volumes by 16% in 2017, net of divestitures; |
| • | improved cash flow from operations by $949 million; |
| • | grew production by 3%, adjusted for asset sales, and met our targeted goal of reaching 100,000 barrels of average net oil production per day in the fourth quarter of 2017, a significant accomplishment representing 11% growth from our 2016 fourth quarter oil volumes; |
| • | improved our cost structure by reducing our production, general and administrative, and gathering, processing and transportation expenses by $510 million, or 18%; |
| • | generated approximately $1.3 billion in net proceeds from the disposition of certain non-core assets and other property sales; |
| • | reduced outstanding secured term debt by approximately $1.3 billion, or 32%; |
| • | continued to reduce legal obligations; |
| • | exchanged approximately 10.0 million shares of common stock for approximately $100 million of liquidation value of our preferred stock, eliminating approximately $6 million of annual dividend obligations; and |
| • | achieved company record health, safety and environmental performance by lowering total recordable incident rates to 0.045 and reducing reportable spills by 15% compared to 2016. |
| Years Ended December 31, | ||||||||||||||||||
| 2017 | change | 2016 | change | 2015 | ||||||||||||||
| ($ in millions) | ||||||||||||||||||
| Net income (loss) available to common stockholders | $ | 813 | n/m | $ | (4,915 | ) | 67 | % | $ | (14,738 | ) | |||||||
| Net earnings (loss) per diluted common share | $ | 0.90 | n/m | $ | (6.43 | ) | 71 | % | $ | (22.26 | ) | |||||||
| Adjusted production(a) (mboe per day) | 541 | 3 | % | 525 | 3 | % | 511 | |||||||||||
| Total production (mboe per day) | 548 | (14 | )% | 635 | (6 | )% | 679 | |||||||||||
| Average sales price (per boe) | $ | 22.88 | 38 | % | $ | 16.63 | (14 | )% | $ | 19.23 | ||||||||
| Oil, natural gas and NGL production expenses | $ | 562 | (21 | )% | $ | 710 | (32 | )% | $ | 1,046 | ||||||||
| Oil, natural gas and NGL gathering, processing and transportation expenses | $ | 1,471 | (21 | )% | $ | 1,855 | (12 | )% | $ | 2,119 | ||||||||
| General and administrative expenses | $ | 262 | 9 | % | $ | 240 | 2 | % | $ | 235 | ||||||||
| Total debt (principal amount) | $ | 9,981 | — | % | $ | 9,989 | 3 | % | $ | 9,706 | ||||||||
| Estimated proved reserves (mmboe) | 1,912 | 12 | % | 1,708 | 14 | % | 1,504 |
| (a) | Adjusted for assets sold. |
Business and Industry Outlook
Over the past decade, the landscape of energy production has changed dramatically in the United States. Domestic energy production capabilities have increased the nation’s supply of both crude oil and natural gas, primarily driven by advances in technology, horizontal drilling and hydraulic fracture stimulation techniques. As a result of this increase in domestic supply of crude oil and natural gas, commodity prices for these products are meaningfully lower than they were a decade ago, but may remain volatile for the foreseeable future. To this end, we will always strive to protect a portion of our projected cash flow through our commodity hedging program as we see appropriate.
As of February 22, 2018, including January and February derivative contracts that are settled, approximately 74% of our projected full year 2018 crude oil production was hedged through swaps and open collars at an average of $52.41 per barrel and approximately 68% of our projected full year 2018 natural gas production was hedged through swaps and collars at an average of $3.10 per mcf. Our crude oil hedges are below current 2018 NYMEX crude oil strip prices of approximately $60.00 per barrel, and our natural gas hedges currently sit in a profitable position, above current 2018 NYMEX natural gas strip prices of approximately $2.80 per mcf. While we cannot predict the future movements of commodity prices with complete accuracy, we believe it is prudent to protect a portion of our projected cash flow through hedging and plan to continue to do so in the future.
In 2018, our focus is concentrated on three strategic priorities:
| • | reduce total debt by $2 - $3 billion; |
| • | increase net cash provided by operating activities to fund capital expenditures; and |
| • | improve margins through financial discipline and operating efficiencies. |
With regard to our debt, we are committed to decreasing the amount of debt outstanding. To accomplish this objective, we intend to allocate our capital expenditures to the highest-return projects, deploy leading drilling and completion technology throughout our portfolio to profitably and efficiently grow, and divest additional large assets to strengthen our cost structure and our portfolio. Increasing our margins means not only increasing our level of cash flow from operations, but also increasing our cash flow from operations generated per barrel of equivalent production. We are seeking to reduce cash costs (production, general and administrative and gathering, processing and transportation expenses), improve our production volumes from existing wells, and achieve additional operating and capital efficiencies with a focus on growing our oil volumes. Finally, we seek to maintain our high level of health, safety, and environmental performance and stewardship.
We have already made significant progress towards achieving our strategic priorities to date in 2018. So far we have:
| • | signed agreements for the sale of properties in the Mid-Continent, including our Mississippian Lime assets, for an expected aggregate amount of approximately $500 million in proceeds that we expect to close by the end of the 2018 second quarter; and |
| • | received net proceeds of approximately $74 million from the sale of approximately 4.3 million shares of FTS International, Inc. (NYSE: FTSI). After the sale, we own approximately 22 million shares of FTSI. |
The proceeds from these divestitures will be used to repay debt and fun
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Item 7A. Quantitative and Qualitative Disclosures About Market Risk
Oil, Natural Gas and NGL Derivatives
Our results of operations and cash flows are impacted by changes in market prices for oil, natural gas and NGL. To mitigate a portion of our exposure to adverse price changes, we have entered into various derivative instruments. Our oil, natural gas and NGL derivative activities, when combined with our sales of oil, natural gas and NGLs, allow us to predict with greater certainty the revenue we will receive. We believe our derivative instruments continue to be highly effective in achieving our risk management objectives.
Our general strategy for protecting short-term cash flow and attempting to mitigate exposure to adverse oil, natural gas and NGL price changes is to hedge into strengthening oil and natural gas futures markets when prices reach levels that management believes are unsustainable for the long term, have material downside risk in the short term or provide reasonable rates of return on our invested capital. Information we consider in forming an opinion about future prices includes general economic conditions, industrial output levels and expectations, producer breakeven cost structures, liquefied natural gas trends, oil and natural gas storage inventory levels, industry decline rates for base production and weather trends. Executive management is involved in all risk management activities and the Board of Directors reviews our derivative program at its quarterly board meetings. We believe we have sufficient internal controls to prevent unauthorized trading.
We use derivative instruments to achieve our risk management objectives, including swaps, collars and options. All of these are described in more detail below. We typically use swaps and collars for a large portion of the oil and natural gas price risk we hedge. We have also sold calls, taking advantage of premiums associated with market price volatility.
We determine the notional volume potentially subject to derivative contracts by reviewing our overall estimated future production levels, which are derived from extensive examination of existing producing reserve estimates and estimates of likely production from new drilling. Production forecasts are updated at least monthly and adjusted if necessary to actual results and activity levels. We do not enter into derivative contracts for volumes in excess of our share of forecasted production, and if production estimates were lowered for future periods and derivative instruments are already executed for some volume above the new production forecasts, the positions would be reversed. The actual fixed price on our derivative instruments is derived from the reference NYMEX price, as reflected in current NYMEX trading. The pricing dates of our derivative contracts follow NYMEX futures. All of our commodity derivative instruments are net settled based on the difference between the fixed price as stated in the contract and the floating-price, resulting in a net amount due to or from the counterparty.
We review our derivative positions continuously and if future market conditions change and prices are at levels we believe could jeopardize the effectiveness of a position, we will mitigate this risk by either negotiating a cash settlement with our counterparty, restructuring the position or entering into a new trade that effectively reverses the current position. The factors we consider in closing or restructuring a position before the settlement date are identical to those we review when deciding to enter into the original derivative position. Gains or losses related to closed positions will be recognized in the month specified in the original contract.
We have determined the fair value of our derivative instruments utilizing established index prices, volatility curves and discount factors. These estimates are compared to counterparty valuations for reasonableness. Derivative transactions are also subject to the risk that counterparties will be unable to meet their obligations. This non-performance risk is considered in the valuation of our derivative instruments, but to date has not had a material impact on the values of our derivatives. Future risk related to counterparties not being able to meet their obligations has been partially mitigated under our commodity hedging arrangements that require counterparties to post collateral if their obligations to us are in excess of defined thresholds. The values we report in our financial statements are as of a point in time and subsequently change as these estimates are revised to reflect actual results, changes in market conditions and other factors. See Note 11 of the notes to our consolidated financial statements included in Item 8 of this report for further discussion of the fair value measurements associated with our derivatives.
As of December 31, 2017, our oil, natural gas and NGL derivative instruments consisted of the following types of instruments:
| • | Swaps: We receive a fixed price and 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 may sell call options and call swaptions. |
| • | Options: We sell, and occasionally buy, call options in exchange for a premium. At the time of settlement, if the market price exceeds the fixed price of the call option, we pay the counterparty the excess on sold call options, and we receive the excess on bought call options. If the market price settles below the fixed price of the call option, no payment is due from either party. |
| • | Call Swaptions: We sell call swaptions to counterparties that allow the counterparty, on a specific date, to extend an existing fixed-price swap for a certain period of time |
| • | Collars: These instruments contain a fixed floor price (put) and ceiling price (call). If the market price exceeds the call strike price or falls below the put strike price, we receive the fixed price and pays the market price. If the market price is between the put and the call strike prices, no payments are due from either party. Three-way collars include the sale by us of an additional put option in exchange for a more favorable strike price on the call option. This eliminates the counterparty’s downside exposure below the second put option strike price. |
| • | Basis Protection Swaps: These instruments are arrangements that guarantee a fixed price differential to NYMEX from a specified delivery point. We receive the fixed price differential and pays the floating market price differential to the counterparty for the hedged commodity. |
As of December 31, 2017, we had the following open oil, natural gas and NGL derivative instruments:
| Weighted Average Price | Fair Value | ||||||||||||||||||||||
| Volume | Fixed | Call | Put | Differential | Asset (Liability) | ||||||||||||||||||
| (mmbbl) | ($ per bbl) | ($ in millions) | |||||||||||||||||||||
| Oil: | |||||||||||||||||||||||
| Swaps: | |||||||||||||||||||||||
| Short-term | 20 | $ | 51.99 | $ | — | $ | — | $ | — | $ | (147 | ) | |||||||||||
| Long-term | 1 | $ | 53.60 | $ | — | $ | — | $ | — | (4 | ) | ||||||||||||
| Three Way Collars: | |||||||||||||||||||||||
| Short-term | 2 | $ | — | $ | 55.00 | $39.15 / $47.00 | $ | — | $ | (10 | ) | ||||||||||||
| Call Swaptions: | |||||||||||||||||||||||
| Short-term | 2 | $ | 52.87 | $ | — | $ | — | $ | — | $ | (13 | ) | |||||||||||
| Basis Protection Swaps: | |||||||||||||||||||||||
| Short-term | 11 | $ | — | $ | — | $ | — | $ | 3.32 | (9 | ) | ||||||||||||
| Total Oil | (183 | ) | |||||||||||||||||||||
| (bcf) | ($ per mcf) | ||||||||||||||||||||||
| Natural Gas: | |||||||||||||||||||||||
| Swaps(a): | |||||||||||||||||||||||
| Short-term | 532 | $ | 3.11 | $ | — | $ | — | $ | — | 149 | |||||||||||||
| Collars: | |||||||||||||||||||||||
| Short-term | 47 | $ | — | $ | 3.25 | $ | 3.00 | $ | — | 11 | |||||||||||||
| Call Options (sold): | |||||||||||||||||||||||
| Short-term | 66 | $ | — | $ | 6.27 | $ | — | $ | — | (3 | ) | ||||||||||||
| Long-term | 44 | $ | — | $ | 12.00 | $ | — | $ | — | — | |||||||||||||
| Basis Protection Swaps: | |||||||||||||||||||||||
| Short-term | 65 | $ | — | $ | — | $ | — | $ | (0.52 | ) | (7 | ) | |||||||||||
| Total Natural Gas | 150 | ||||||||||||||||||||||
| (mmgal) | ($ per gal) | ||||||||||||||||||||||
| NGL: | |||||||||||||||||||||||
| Propane Swaps | |||||||||||||||||||||||
| Short-term | 15 | $ | 0.73 | $ | — | $ | — | $ | — | (2 | ) | ||||||||||||
| Butane Swaps | |||||||||||||||||||||||
| Short-term | 5 | $ | 0.88 | $ | — | $ | — | $ | — | — | |||||||||||||
| Short-term % of WTI | 5 | 70.5% | $ | — | $ | — | $ | — | — | ||||||||||||||
| Ethane Swaps | |||||||||||||||||||||||
| Short-term | 8 | $ | 0.28 | $ | — | $ | — | $ | — | — | |||||||||||||
| Total NGL | (2 | ) | |||||||||||||||||||||
| Total Estimated Fair Value | $ | (35 | ) |
| (a) | This amount includes a sold option to enhance the swap price at an average price of $3.40/mmbtu covering 44 tbtu, included in the sold call options. |
In addition to the open derivative positions disclosed above, as of December 31, 2017, we had $81 million of net derivative losses related to settled contracts for future periods that will be recorded within oil, natural gas and NGL revenues as realized gains (losses) on derivatives once they are transferred from either accumulated other comprehensive income or unrealized gains (losses) on derivatives in the month of related production, based on the terms specified in the original contract as noted below:
| December 31, 2017 | ||||
| ($ in millions) | ||||
| Short-term | $ | (24 | ) | |
| Long-term | (57 | ) | ||
| Total | $ | (81 | ) |
The table below reconciles the changes in fair value of our oil and natural gas derivatives during 2017. Of the $35 million fair value liability as of December 31, 2017, a $31 million liability relates to contracts maturing in the next 12 months and a $4 million liability relates to contracts maturing after 12 months. All open derivative instruments as of December 31, 2017 are expected to mature by December 31, 2020.
| December 31, 2017 | ||||
| ($ in millions) | ||||
| Fair value of contracts outstanding, as of January 1, 2017 | $ | (504 | ) | |
| Change in fair value of contracts | 445 | |||
| Contracts realized or otherwise settled | 24 | |||
| Fair value of contracts outstanding, as of December 31, 2017 | $ | (35 | ) |
Interest Rate Risk
The table below presents principal cash flows and related weighted average interest rates by expected maturity dates, using the earliest demand repurchase date for contingent convertible senior notes. As of December 31, 2017, we had total debt of $9.981 billion, including $7.588 billion of fixed rate debt at interest rates averaging 6.95% and $2.393 billion of floating rate debt at an interest rate of 6.53%.
| Years of Maturity | |||||||||||||||||||||||||||
| 2018 | 2019 | 2020 | 2021 | 2022 | Thereafter | Total | |||||||||||||||||||||
| ($ in millions) | |||||||||||||||||||||||||||
| Liabilities: | |||||||||||||||||||||||||||
| Debt – fixed rate(a) | $ | 53 | $ | — | $ | 665 | $ | 814 | $ | 1,868 | $ | 4,188 | $ | 7,588 | |||||||||||||
| Average interest rate | 6.42 | % | — | % | 6.71 | % | 5.88 | % | 7.25 | % | 7.07 | % | 6.95 | % | |||||||||||||
| Debt – variable rate | $ | — | $ | 1,160 | $ | — | $ | 1,233 | $ | — | $ | — | $ | 2,393 | |||||||||||||
| Average interest rate | — | % | 4.10 | % | — | % | 8.81 | % | — | % | — | % | 6.53 | % |
| (a) | This amount excludes $9 million of premium, discount and deferred financing costs included in debt and $2 million of interest rate derivatives. |
Changes in interest rates affect the amount of interest we earn on our cash, cash equivalents and short-term investments and the interest rate we pay on borrowings under our revolving credit facility, term loan and our floating rate senior notes. All of our other indebtedness is fixed rate and, therefore, does not expose us to the risk of fluctuations in earnings or cash flow due to changes in market interest rates. However, changes in interest rates do affect the fair value of our fixed-rate debt.
From time to time, we enter into interest rate derivatives, including fixed-to-floating interest rate swaps (we receive a fixed interest rate and pay a floating market rate) to mitigate our exposure to changes in the fair value of our senior notes and floating-to-fixed interest rate swaps (we receive a floating market rate and pay a fixed interest rate) to manage our interest rate exposure related to our revolving credit facility borrowings. As of December 31, 2017, we had no interest rate derivatives outstanding.
As of December 31, 2017, we had $7 million of net gains related to settled derivative contracts that will be recorded within interest expense as realized gains or losses once they are transferred from our senior note liability or within interest expense as unrealized gains or losses over the remaining six-year term of our related senior notes.
Realized and unrealized (gains) or losses from interest rate derivative transactions are reflected as adjustments to interest expense on the consolidated statements of operations.
Item 8. Financial Statements and Supplementary Data
MANAGEMENT'S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
It is the responsibility of the management of Chesapeake Energy Corporation to establish and maintain adequate internal control over financial reporting (as defined in Rule 13a-15(f) under the Securities Exchange Act of 1934). Management utilized the Committee of Sponsoring Organizations of the Treadway Commission's Internal Control-Integrated Framework (2013) in conducting the required assessment of effectiveness of the Company's internal control over financial reporting.
Management has performed an assessment of the effectiveness of the Company's internal control over financial reporting and has determined the Company’s internal control over financial reporting was effective as of December 31, 2017.
The effectiveness of the Company's internal control over financial reporting, as of December 31, 2017, has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in its report, which appears herein.
| /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 | ||||
| February 22, 2018 | ||||
Report of Independent Registered Public Accounting Firm
To the Board of Directors and Shareholders of Chesapeake Energy Corporation
Opinions on the Financial Statements and Internal Control over Financial Reporting
We have audited the consolidated financial statements, including the related notes of Chesapeake Energy Corporation and its subsidiaries as listed in the accompanying index (collectively referred to as the “consolidated financial statements”). We also have audited the Company's internal control over financial reporting as of December 31, 2017, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31, 2017 and 2016, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2017 in conformity with accounting principles generally accepted in the United States of America. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2017, based on criteria established in Internal Control - Integrated Framework (2013) issued by the COSO.
Basis for Opinions
The Company's management is responsible for these consolidated financial statements, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control Over Financial Reporting. Our responsibility is to express opinions on the Company’s consolidated financial statements and on the Company's internal control over financial reporting based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) ("PCAOB") and are required to be i
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Item 9. Changes In and Disagreements with Accountants on Accounting and Financial Disclosure
Not applicable.
Item 9A. Controls and Procedures
Evaluation of Disclosure Controls and Procedures
We maintain disclosure controls and procedures designed to ensure that information required to be disclosed in reports we file or submit under the Securities Exchange Act of 1934, as amended (the “Exchange Act”), is recorded, processed, summarized and reported within the time periods specified in SEC rules and forms, and that such information is accumulated and communicated to management, including our principal executive and principal financial officers, as appropriate, to allow timely decisions regarding required disclosure.
As of the end of the period covered by this report, we carried out an evaluation, under the supervision and with the participation of management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Exchange Act Rule 13a-15(b). Based on that evaluation, our Chief Executive Officer and Chief Financial Officer concluded as of December 31, 2017 that our disclosure controls and procedures were effective.
Remediation of Previously Identified Material Weakness
As disclosed in our Annual Report on Form 10-K for the year ended December 31, 2016, our management determined that a material weakness existed in our internal control over financial reporting over the review of the valuation of proved oil and natural gas properties and the accuracy of impairment of oil and natural gas properties. Specifically, the review of the initial configuration of a newly implemented tool used to calculate basis price differentials did not detect an error in the calculation formula and the manual interface control that compared the data used in the tool to the general ledger was not designed at an appropriately disaggregated level.
We have taken the necessary steps to enhance the underlying control activities, which now include restricted access within the tool to maintain and control changes to the formulaic calculations, a manual interface control to validate that the automated interface configuration and calculation formulas are accurate, and a manual recalculation of the basis price differentials.
Based on the results of management’s evaluation, we have concluded that the controls are designed and operating effectively as of December 31, 2017 and, therefore, the previously disclosed material weakness has been remediated.
Changes in Internal Control Over Financial Reporting
There were no changes in our internal control over financial reporting that occurred during the quarter ended December 31, 2017 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
Management’s Report on Internal Control Over Financial Reporting
Management’s Report on Internal Control Over Financial Reporting is set forth in Item 8 of this Annual Report on Form 10-K.
Item 9B. Other Information
Not applicable.
PART III
Item 10. Directors, Executive Officers and Corporate Governance
The names of executive officers and certain other senior officers of the Company and their ages, titles and biographies as of the date hereof are incorporated by reference from Item 1 of Part I of this report. The other information called for by this Item 10 is incorporated herein by reference to the definitive proxy statement to be filed by Chesapeake pursuant to Regulation 14A of the General Rules and Regulations under the Securities Exchange Act of 1934 not later than April 30, 2018 (the 2018 Proxy Statement).
Item 11. Executive Compensation
The information called for by this Item 11 is incorporated herein by reference to the 2018 Proxy Statement.
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
The information called for by this Item 12 is incorporated herein by reference to the 2018 Proxy Statement.
Item 13. Certain Relationships and Related Transactions and Director Independence
The information called for by this Item 13 is incorporated herein by reference to the 2018 Proxy Statement.
Item 14. Principal Accountant Fees and Services
The information called for by this Item 14 is incorporated herein by reference to the 2018 Proxy Statement.
PART IV
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 are filed, furnished or incorporated by reference pursuant to the requirements of Item 601 of Regulation S-K. |
INDEX OF EXHIBITS
| 99 | 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 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. |
Item 16. Form 10-K Summary
Not applicable.
Signatures
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
| CHESAPEAKE ENERGY CORPORATION | |||
| Date: February 22, 2018 | By: | /s/ ROBERT D. LAWLER | |
| Robert D. Lawler | |||
| President and Chief Executive Officer |
POWER OF ATTORNEY
Each person whose signature appears below constitutes and appoints Robert D. Lawler and Domenic J. Dell'Osso, Jr., and each of them, either one of whom may act without joinder of the other, his true and lawful attorneys-in-fact and agents, with full power of substitution and resubstitution, for him and in his name, place and stead, in any and all capacities, to sign any or all amendments to this Annual Report on Form 10-K, and to file the same, with all, exhibits thereto and other documents in connection therewith, with the Securities and Exchange Commission, granting unto said attorneys-in-fact and agents, and each of them, full power and authority to do and perform each, and every act and thing requisite and necessary to be done in and about the premises, as fully to all intents and purposes as he might or could do in person, hereby ratifying and confirming all that said attorneys-in-fact and agents, and each of them, or the substitute or substitutes of any or all of them, may lawfully do or cause to be done by virtue hereof.
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.
| Signature | Capacity | Date | ||
| /s/ ROBERT D. LAWLER | President and Chief Executive Officer (Principal Executive Officer) | February 22, 2018 | ||
| Robert D. Lawler | ||||
| /s/ DOMENIC J. DELL'OSSO, JR. | Executive Vice President and Chief Financial Officer (Principal Financial Officer) | February 22, 2018 | ||
| Domenic J. Dell'Osso, Jr. | ||||
| /s/ WILLIAM M. BUERGLER | Senior Vice President and Chief Accounting Officer (Principal Accounting Officer) | February 22, 2018 | ||
| William M. Buergler | ||||
| /s/ R. BRAD MARTIN | Chairman of the Board | February 22, 2018 | ||
| R. Brad Martin | ||||
| /s/ ARCHIE W. DUNHAM | Director and Chairman Emeritus | February 22, 2018 | ||
| Archie W. Dunham | ||||
| /s/ GLORIA R. BOYLAND | Director | February 22, 2018 | ||
| Gloria R. Boyland | ||||
| /s/ LUKE R. CORBETT | Director | February 22, 2018 | ||
| Luke R. Corbett | ||||
| /s/ LESLIE S. KEATING | Director | February 22, 2018 | ||
| Leslie S. Keating | ||||
| /s/ MERRILL A. MILLER, JR. | Director | February 22, 2018 | ||
| Merrill A. Miller, Jr. | ||||
| /s/ THOMAS L. RYAN | Director | February 22, 2018 | ||
| Thomas L. Ryan |