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:

		2017						2016						2015
		Gross Wells			Net Wells			Gross Wells			Net Wells			Gross Wells			Net Wells
Marcellus		43			21			19			9			44			22
Haynesville		37			34			41			34			68			49
Eagle Ford		180			106			199			116			244			138
Utica		69			56			34			17			178			114
Mid-Continent		114			58			135			62			212			63
Powder River Basin		25			21			1			1			41			34
Other		—			—			6			—			27			8
Total		468			296			435			239			814			428

As of December 31, 2017, we had 255 gross (148 net) wells in the process of being drilled or completed.

Production, Sales Prices, Production and Gathering, Processing and Transportation Expenses

The following table sets forth information regarding our net production volumes, average sales price received for our production, our average sales price of our production combined with our realized gains or losses from derivatives and gathering, processing and transportation expenses for the periods indicated:

		Years Ended December 31,
		2017				2016				2015
Net Production:
Oil (mmbbl)		33				33				42
Natural gas (bcf)		878				1,049				1,070
NGL (mmbbl)		21				24				28
Oil equivalent (mmboe)		200				233				248
Average Sales Price of Production:
Oil ($ per bbl)		$	51.03			$	40.65			$	45.77
Natural gas ($ per mcf)		$	2.76			$	2.05			$	2.31
NGL ($ per bbl)		$	23.18			$	14.76			$	14.06
Oil equivalent ($ per boe)		$	22.88			$	16.63			$	19.23
Average Sales Price (including realized gains (losses) on derivatives):
Oil ($ per bbl)		$	53.19			$	43.58			$	66.91
Natural gas ($ per mcf)		$	2.75			$	2.20			$	2.72
NGL ($ per bbl)		$	22.98			$	14.43			$	14.06
Oil equivalent ($ per boe)		$	23.17			$	17.66			$	24.54
Expenses ($ per boe):
Oil, natural gas and NGL production		$	2.81			$	3.05			$	4.22
Oil, natural gas and NGL gathering, processing and transportation		$	7.36			$	7.98			$	8.55

Oil, Natural Gas and NGL Reserves

The tables below set forth information as of December 31, 2017, with respect to our estimated proved reserves, the associated estimated future net revenue, the present value of estimated future net revenue (“PV-10”) and the standardized measure of discounted future net cash flows (“standardized measure”). Neither the estimated future net revenue, PV-10 nor the standardized measure is intended to represent the current market value of the estimated oil, natural gas and NGL reserves we own. All of our estimated reserves are located within the United States.

		December 31, 2017
		Oil			Natural Gas			NGL			Total
		(mmbbl)			(bcf)			(mmbbl)			(mmboe)
Proved developed		151			4,980			135			1,116
Proved undeveloped		109			3,620			84			796
Total proved(a)		260			8,600			219			1,912

		Proved Developed				Proved Undeveloped				Total Proved
		($ in millions)
Estimated future net revenue(b)		$	9,637			$	4,754			$	14,391
Present value of estimated future net revenue (PV-10)(b)		$	5,757			$	1,733			$	7,490
Standardized measure(b)										$	7,490

---

(a)	Utica, Marcellus, Haynesville and Eagle Ford accounted for approximately 25%, 24%, 21% and 19%, respectively, of our estimated proved reserves by volume as of December 31, 2017.

(b)

Estimated future net revenue represents the estimated future revenue to be generated from the production of proved reserves, net of estimated production and future development costs, using prices and costs under existing economic conditions as of December 31, 2017. For the purpose of determining prices used in our reserve reports, we used the unweighted arithmetic average of the prices on the first day of each month within the 12-month period ended December 31, 2017. The prices used in our PV-10 measure were $51.34 of oil and $2.98 of natural gas, before basis differential adjustments. These prices should not be interpreted as a prediction of future prices, nor do they reflect the value of our commodity derivative instruments in place as of December 31, 2017. The amounts shown do not give effect to non-property-related expenses, such as corporate general and administrative expenses and debt service, or to depreciation, depletion and amortization. The present value of estimated future net revenue typically differs from the standardized measure because the former does not include the effects of estimated future income tax expense. However, as we estimate no future income tax expense, the two measures are the same as of December 31, 2017.

Management uses PV-10, which is calculated without deducting estimated future income tax expenses, as a measure of the value of the Company's current proved reserves and to compare relative values among peer companies. We also understand that securities analysts and rating agencies use this measure in similar ways. While estimated future net revenue and the present value thereof are based on prices, costs and discount factors which may be consistent from company to company, the standardized measure of discounted future net cash flows is dependent on the unique tax situation of each individual company. PV-10 should not be considered in isolation or as a substitute for the standardized measure of discounted future net cash flows or any other measure of a company's financial or operating performance presented in accordance with GAAP.

A reconciliation of the standardized measure of discounted future net cash flows to PV-10 is presented above. Neither PV-10 nor the standardized measure of discounted future net cash flows purport to represent the fair value of our proved oil and gas reserves.

As of December 31, 2017, our proved reserve estimates included 796 mmboe of reserves classified as proved undeveloped, compared to 519 mmboe as of December 31, 2016. Presented below is a summary of changes in our proved undeveloped reserves (PUDs) for 2017:

		Total
		(mmboe)
Proved undeveloped reserves, beginning of period		519
Extensions and discoveries		604
Revisions of previous estimates		(202	)
Developed		(125	)
Sale of reserves-in-place		—
Purchase of reserves-in-place		—
Proved undeveloped reserves, end of period		796

As of December 31, 2017, all PUDs were planned to be developed within a five-year period. In 2017, we invested approximately $793 million to convert 125 mmboe of PUDs to proved developed reserves. In 2018, we estimate that we will invest approximately $880 million for PUD conversion. Our proved undeveloped extensions and discoveries increased by 604 mmboe of reserves as a result of longer planned lateral lengths and additional allocated capital in our five-year development plan. We recorded a downward revision of 203 mmboe from previous estimates due to an updated development plan in the Eagle Ford aligning up-spacing and our activity schedule. Additionally, PUDs were removed from properties in the Mid-Continent in the process of being divested. In addition, approximately 1 mmboe of PUDs were added due to higher commodity prices.

The future net revenue attributable to our estimated PUDs was $4.8 billion and the present value was $1.7 billion as of December 31, 2017. These were calculated assuming that we will expend approximately $4.3 billion to develop these reserves ($880 million in 2018, $1.0 billion in 2019, $1.1 billion in 2020, $858 million in 2021 and $462 million in 2022). The amount and timing of these expenditures will depend on a number of factors, including actual drilling results, service costs, commodity prices and the availability of capital. Our developmental drilling schedules are subject to revision and reprioritization throughout the year resulting from unknowable factors such as unexpected developmental drilling results, title issues and infrastructure availability or constraints.

Our annual net decline rate on current proved producing properties is projected to be 35% in 2018, 23% in 2019, 18% in 2020, 15% in 2021 and 13% in 2022. Of our 1.116 bboe of proved developed reserves as of December 31, 2017, approximately 89 mmboe, or 8%, were non-producing.

Our ownership interest used for calculating proved reserves and the associated estimated future net revenue assumes maximum participation by other parties to our farm-out and participation agreements.

Our estimated proved reserves and the standardized measure of discounted future net cash flows of the proved reserves as of December 31, 2017, 2016 and 2015, along with the changes in quantities and standardized measure of the reserves for each of the three years then ended, are shown in Supplemental Disclosures About Oil, Natural Gas and NGL Producing Activities included in Item 8 of Part II of this report. No estimates of proved reserves comparable to those included herein have been included in reports to any federal agency other than the SEC.

There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting future rates of production and timing of development expenditures, including many factors beyond our control. The reserve data represents only estimates. Reserve engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be measured exactly, and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. As a result, estimates made by different engineers often vary. In addition, results of drilling, testing and production subsequent to the date of an estimate may justify revision of these estimates, and these revisions may be material. Accordingly, reserve estimates often differ from the actual quantities of oil, natural gas and NGL that are ultimately recovered. Furthermore, the estimated future net revenue from proved reserves and the associated present value are based upon certain assumptions, including prices, future production levels and costs that may not prove correct. Future prices and costs may be materially higher or lower than the prices and costs as of the date of any estimate.

Reserves Estimation

Our Corporate Reserves Department prepared approximately 17% by volume, and approximately 12% by value, of our estimated proved reserves disclosed in this report. Those estimates were based upon the best available production, engineering and geologic data.

Our Director – Corporate Reserves, is the technical person primarily responsible for overseeing the preparation of our reserve estimates and for coordinating any reserves work conducted by a third-party engineering firm. Her qualifications include the following:

•	Over 15 years of practical experience in the oil and gas industry, with 11 years in reservoir engineering;

•	Bachelor of Science degree in Geology and Environmental Sciences;

•	Master’s Degree in Petroleum and Natural Gas Engineering;

•	Executive MBA; and

•	Member in good standing of the Society of Petroleum Engineers.

We ensure that the key members of our Corporate Reserves Department have appropriate technical qualifications to oversee the preparation of reserves estimates. Each of our Corporate Reserves Advisors has significant engineering experience in reserve estimation. Our engineering technicians have a minimum of a four-year degree in mathematics, economics, finance or other technical/business/science field. We maintain a continuous education program for our engineers and technicians on new technologies and industry advancements as well as refresher training on basic skills and analytical techniques.

We maintain internal controls such as the following to ensure the reliability of reserves estimations:

•	We follow comprehensive SEC-compliant internal policies to estimate and report proved reserves. Reserve estimates are made by experienced reservoir engineers or under their direct supervision. All material changes are reviewed and approved by Corporate Reserves Advisors.

•	The Corporate Reserves Department reviews our proved reserves at the close of each quarter.

•	Each quarter, Reservoir Managers, the Director – Corporate Reserves, the Vice Presidents of our business units, the Vice President of Corporate and Strategic Planning and the Executive Vice President – Exploration and Production review all significant reserves changes and all new proved undeveloped reserves additions.

•	The Corporate Reserves Department reports independently of our operations.

•	The five-year PUD development plan is reviewed and approved annually by the Director of Corporate Reserves and the Vice President of Corporate and Strategic Planning.

We engaged Software Integrated Solutions, Division of Schlumberger Technology Corporation, a third-party engineering firm, to prepare approximately 83% by volume, and approximately 88% by value, of our estimated proved reserves as of December 31, 2017. A copy of the report issued by the engineering firm is filed with this report as Exhibit 99.1. The qualifications of the technical person at the firm primarily responsible for overseeing the preparation of our reserve estimates are set forth below.

•	over 30 years of practical experience in the estimation and evaluation of reserves;

•	registered professional geologist license in the Commonwealth of Pennsylvania;

•	member in good standing of the Society of Petroleum Engineers and the Society of Petroleum Evaluation Engineers; and

•	Bachelor of Science degree in Geological Sciences.

Costs Incurred in Oil and Natural Gas Property Acquisition, Exploration and Development

The following table sets forth historical costs incurred in oil and natural gas property acquisition, exploration and development activities during the periods indicated:

		Years Ended December 31,
		2017				2016				2015
		($ in millions)
Acquisition of Properties:
Proved properties		$	23			$	403			$	—
Unproved properties		271				403				454
Exploratory costs		21				52				112
Development costs		2,146				1,312				2,941
Costs incurred(a)(b)		$	2,461			$	2,170			$	3,507

---

(a)	Exploratory and development costs are net of joint venture drilling and completion cost carries of $51 million in 2015.

(b)	Includes capitalized interest and asset retirement obligations as follows:

Capitalized interest		$	194			$	242			$	410
Asset retirement obligations(c)		$	(34	)		$	(57	)		$	(15	)

(c) Includes revisions as a result of lower plugging and abandonment costs in certain of our operating areas.

A summary of our exploration and development, acquisition and divestiture activities in 2017 by operating area is as follows:

		Gross Wells Drilled			Net Wells Drilled			Exploration and Development				Acquisition of Unproved Properties				Acquisition of Proved Properties				Sales of Unproved Properties				Sales of Proved Properties(a)				Total(b)
		($ in millions)
Marcellus		43			21			$	124			$	17			$	4			$	(13	)		$	(57	)		$	75
Haynesville		37			34			411				23				(3		)		(674		)		(241		)		(484		)
Eagle Ford		180			106			754				2				—				—				—				756
Utica		69			56			375				95				1				(91		)		(9		)		371
Mid-Continent		114			58			281				103				20				(88		)		(156		)		160
Powder River Basin		25			21			220				26				—				(5		)		—				241
Other		—			—			2				5				1				—				(38		)		(30		)
Total		468			296			$	2,167			$	271			$	23			$	(871	)		$	(501	)		$	1,089

---

(a)	Includes asset retirement disposal of $66 million related to divestitures.

(b)	Includes capitalized internal costs of $136 million and capitalized interest of $194 million.

Acreage

The following table sets forth our gross and net developed and undeveloped oil and natural gas leasehold and fee mineral acreage as of December 31, 2017. "Gross" acres are the total number of acres in which we own a working interest. "Net" acres refer to gross acres multiplied by our fractional working interest. Acreage numbers do not include our unexercised options to acquire additional acreage.

		Developed Leasehold						Undeveloped Leasehold						Fee Minerals						Total
		Gross Acres			Net Acres			Gross Acres			Net Acres			Gross Acres			Net Acres			Gross Acres			Net Acres
		(in thousands)
Marcellus		538			346			383			215			17			16			938			577
Haynesville		401			309			158			47			11			2			570			358
Eagle Ford		313			176			129			69			—			—			442			245
Utica		315			248			1,102			686			4			4			1,421			938
Mid-Continent		1,815			847			396			158			227			39			2,438			1,044
Powder River Basin		57			45			325			229			14			1			396			275
Other(a)		220			145			1,470			992			662			399			2,352			1,536
Total		3,659			2,116			3,963			2,396			935			461			8,557			4,973

---

(a)	Includes 1.6 million gross (1.3 million net) acres retained in the 2016 fourth quarter divestiture of our Devonian Shale assets, in which we retained all rights below the base of the Kope formation.

Most of our leases have a three- to five-year primary term, and we manage lease expirations to ensure that we do not experience unintended material expirations. Our leasehold management efforts include scheduling our drilling to establish production in paying quantities in order to hold leases by production, timely exercising our contractual rights to pay delay rentals to extend the terms of leases we value, planning noncore divestitures to high-grade our lease inventory and letting some leases expire that are no longer part of our development plans. The following table sets forth the expiration periods of gross and net undeveloped leasehold acres as of December 31, 2017:

		Acres Expiring
		Gross Acres			Net Acres
		(in thousands)
Years Ending December 31:
2018		485			189
2019		259			145
2020		188			142
After 2020		155			112
Held-by-production(a)		2,876			1,808
Total		3,963			2,396

---

(a)	Held-by-production acres will remain in force as production continues on the subject leases.

Marketing, Gathering and Compression

Previously, we have presented two reportable operating segments: (i) exploration and production and (ii) marketing, gathering and compression. In the fourth quarter of 2017, we completed the realignment of our marketing, gathering and compression operations to serve as an ancillary service integral to our exploration and production activities. Our marketing, gathering and compression operations now principally operate to provide oil, natural gas and NGL marketing services, including commodity price structuring, securing and negotiating of gathering, hauling, processing and transportation services, contract administration and nomination services for us and other interest owners in Chesapeake-operated wells. The marketing, gathering, and compression operations also provide other services for our exploration and production activities, including services to enhance the value of oil and natural gas production by aggregating volumes sold to various intermediary markets, end markets and pipelines. This aggregation allows us to attract larger, more creditworthy customers that in turn assist in maximizing the prices received. In addition, we periodically enter into a variety of oil, natural gas and NGL purchase and sale contracts with third parties for various commercial purposes, including credit risk mitigation and satisfaction of our pipeline delivery commitments.

Following this realignment, we have a single, company-wide management team that administers all activities as a whole rather than through discrete operating units, with an emphasis on allocating capital focused on the expansion of our exploration and production assets. As a result, we have concluded that we have only one reportable operating segment, which is exploration and production. Prior year financial information for our previous Marketing, Gathering and Compression reportable segment has been eliminated. See further discussion in Note 1 of the notes to our consolidated financial statements included in Item 8 of Part II of this report.

Generally, our oil production is sold under market-sensitive short-term or spot price contracts. Natural gas and NGL production is sold to purchasers under percentage-of-proceeds contracts, percentage-of-index contracts or spot price contracts. Under the terms of our percentage-of-proceeds contracts, we receive a percentage of the resale price received from the ultimate purchaser. Under our percentage-of-index contracts, the price we receive is tied to published indices.

We have entered into long-term gathering, processing, and transportation contracts with various parties that require us to deliver fixed, determinable quantities of production over specified periods of time. Certain of our contracts require us to make payments for any shortfalls in delivering or transporting minimum volumes under these commitments.

Sales to Royal Dutch Shell PLC constituted approximately 10% of our total revenues (before the effects of hedging) for the year ended December 31, 2017. Sales to BP PLC constituted approximately 10% and 14% of our total revenues (before the effects of hedging) for the years ended December 31, 2016 and 2015, respectively.

Competition

We compete with both major integrated and other independent oil and natural gas companies in all aspects of our business to explore, develop and operate our properties and market our production. Some of our competitors may have larger financial and other resources than us. Competitive conditions may be affected by future legislation and regulations as the United States develops new energy and climate-related policies. In addition, some of our competitors may have a competitive advantage when responding to factors that affect demand for oil and natural gas production, such as changing prices, domestic and foreign political conditions, weather conditions, the price and availability of alternative fuels, the proximity and capacity of natural gas pipelines and other transportation facilities and overall economic conditions. We also face indirect competition from alternative energy sources, including wind, solar and electric power. We believe that our technological expertise, combined with our exploration, land, drilling and production capabilities and the experience of our management team, enables us to compete effectively.

Regulation – General

All of our operations are conducted onshore in the United States. The U.S. oil and natural gas industry is regulated at the federal, state and local levels, and some of the laws and regulations that govern our operations carry substantial administrative, civil and criminal penalties for non-compliance. Although we believe we are in material compliance with all applicable laws and regulations, and that the cost of compliance with existing requirements will not have a material adverse effect on our financial position, cash flows or results of operations, such laws and regulations could be, and frequently are, amended or reinterpreted. Additionally, currently unforeseen environmental incidents may occur or past non-compliance with environmental laws or regulations may be discovered. Therefore, we are unable to predict the future costs or impact of compliance or non-compliance. Additional proposals and proceedings that affect the oil and natural gas industry are regularly considered by Congress, state and local governments, the courts and federal agencies, such as the U.S. Environmental Protection Agency (EPA), the Federal Energy Regulatory Commission, the Department of Transportation, the Department of Interior and the U.S. Army Corps of Engineers (USACE). We actively monitor regulatory developments applicable to our industry in order to anticipate, design and implement required compliance activities and systems.

Exploration and Production Operations

The laws and regulations applicable to our exploration and production operations include requirements for permits or approvals to drill and to conduct other operations and for provision of financial assurances (such as bonds) covering drilling and well operations. Other activities subject to such laws and regulations include, but are not limited to, the following:

•	seismic operations;

•	the location of wells;

•	construction and operations activities, including in sensitive areas, such as wetlands, coastal regions or areas that contain endangered or threatened species or their habitats;

•	the method of drilling and completing wells;

•	production operations, including the installation of flowlines and gathering systems;

•	air emissions and hydraulic fracturing;

•	the surface use and restoration of properties upon which oil and natural gas facilities are located, including the construction of well pads, pipelines, impoundments and associated access roads;

•	water withdrawal;

•	the plugging and abandoning of wells;

•	the generation, storage, transportation treatment, recycling or disposal of hazardous waste, fluids or other substances in connection with operations;

•	the construction and operation of underground injection wells to dispose of produced water and other liquid oilfield wastes;

•	the construction and operation of surface pits to contain drilling muds and other fluids associated with drilling operations;

•	the marketing, transportation and reporting of production; and

•	the valuation and payment of royalties.

Delays in obtaining permits or an inability to obtain new permits or permit renewals could inhibit our ability to execute our drilling and production plans. Failure to comply with applicable regulations or permit requirements could result in revocation of our permits, inability to obtain new permits and the imposition of fines and penalties.

Our exploration and production activities are also subject to various resource conservation regulations. These include the regulation of the size of drilling and spacing units (regarding the density of wells that may be drilled in a particular area) and the unitization or pooling of oil and natural gas properties. In this regard, some states, such as Oklahoma, allow the forced pooling or integration of tracts to facilitate exploration, while other states, such as Texas, West Virginia and Pennsylvania, rely on voluntary pooling of lands and leases. In areas where pooling is voluntary, it may be more difficult to form units and, therefore, more difficult to fully develop a project if the operator owns or controls less than 100% of the leasehold. In addition, some states’ resource conservation laws establish maximum rates of production from oil and natural gas wells, generally limit the venting or flaring of natural gas and impose certain

requirements regarding the ratability of production. The effect of these regulations is to limit the amount of oil and natural gas we can produce and to limit the number of wells and the locations at which we can drill.

Hydraulic Fracturing

Hydraulic fracturing is regulated by state and federal oil and gas regulatory authorities, including specifically the requirement to disclose certain information related to hydraulic fracturing operations. We follow applicable legal requirements for groundwater protection in our operations that are subject to supervision by state and federal regulators (including the Bureau of Land Management on federal acreage). Furthermore, our well construction practices require the installation of multiple layers of protective steel casing surrounded by cement that are specifically designed and installed to protect freshwater aquifers by preventing the migration of fracturing fluids into aquifers. Regulatory proposals in some states and local communities have been initiated to require or make more stringent the permitting and compliance requirements for hydraulic fracturing operations. Federal and state agencies have continued to assess the impacts of hydraulic fracturing, which could spur further action toward federal and/or state legislation and regulation of hydraulic fracturing activities. In addition, in light of concerns about seismic activity being triggered by the injection of produced waters into underground wells and hydraulic fracturing, certain regulators are also considering additional requirements related to seismic safety for hydraulic fracturing activities. For example, the Oklahoma Corporation Commission (OCC) has released guidance to operators in the SCOOP and STACK areas for management of certain seismic activity that may be related to hydraulic fracturing activities. Further restrictions on hydraulic fracturing could make it prohibitive to conduct our operations, and also reduce the amount of oil, natural gas and NGL that we are ultimately able to produce in commercial quantities from our properties. For further discussion, see Item 1A. Risk Factors – Federal and state legislative and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays.

Regulation – Environment, Health and Safety

Our operations are subject to stringent and complex federal, state and local laws and regulations relating to the protection of human health and safety, the environment and natural resources. These laws and regulations can restrict or impact our business activities in many ways, such as:

•	requiring the installation of pollution-control equipment or otherwise restricting the way we can handle or dispose of wastes and other substances associated with operations;

•	limiting or prohibiting construction activities in sensitive areas, such as wetlands, coastal regions or areas that contain endangered or threatened species and/or species of special statewide concern or their habitats;

•	requiring investigatory and remedial actions to address pollution caused by our operations or attributable to former operations;

•	requiring noise, lighting, visual impact, odor and/or dust mitigation, setbacks, landscaping, fencing, and other measures;

•	restricting access to certain equipment or areas to a limited set of employees or contractors who have proper certification or permits to conduct work (e.g., confined space entry and process safety maintenance requirements); and

•	restricting or even prohibiting water use based upon availability, impacts or other factors.

Failure to comply with these laws and regulations may trigger a variety of administrative, civil and criminal enforcement measures, including the assessment of monetary penalties, the imposition of remedial or restoration obligations, and the issuance of orders enjoining future operations or imposing additional compliance requirements. Certain environmental statutes impose strict, joint and several liability for costs required to clean up and restore sites where hazardous substances, hydrocarbons or wastes have been disposed or otherwise released. Moreover, local restrictions, such as state or local moratoria, city ordinances, zoning laws and traffic regulations, may restrict or prohibit the execution of our drilling and production plans. In addition, third parties, such as neighboring landowners, may file claims alleging property damage, nuisance or personal injury arising from our operations or from the release of hazardous substances, hydrocarbons or other waste products into the environment.

We monitor developments at the federal, state and local levels to inform our actions pertaining to future regulatory requirements that might be imposed to mitigate the costs of compliance with any such requirements. We also participate in industry groups that help formulate recommendations for addressing existing or future regulations and that share best practices and lessons learned in relation to pollution prevention and incident investigations.

Below is a discussion of the major environmental, health and safety laws and regulations that relate to our business. We believe we are in material compliance with these laws and regulations. We do not believe compliance with existing environmental, health and safety laws or regulations will have a material adverse effect on our financial condition, results of operations or cash flow. At this point, however, we cannot reasonably predict what applicable laws, regulations or guidance may eventually be adopted with respect to our operations or the ultimate cost to comply with such requirements.

Hazardous Substances and Waste

Federal and state laws, in particular the federal Resource Conservation and Recovery Act (RCRA) regulate hazardous and non-hazardous wastes. In the course of our operations, we generate petroleum hydrocarbon wastes, such as drill cuttings, produced water and ordinary industrial wastes. Under a longstanding legal framework, certain of these wastes are currently not subject to federal regulations governing hazardous wastes, although they are regulated under other federal and state waste laws. At various times in the past, most recently in December 2016, proposals have been made to amend RCRA or otherwise eliminate the exemption applicable to crude oil and natural gas exploration and production wastes. Repeal or modifications of this exemption by administrative, legislative or judicial process, or through changes in applicable state statutes, would increase the volume of hazardous waste we are required to manage and dispose and would cause us, as well as our competitors, to incur significantly increased operating expenses.

Federal, state and local laws may also require us to remove or remediate wastes or hazardous substances that have been previously disposed or released into the environment. This can include removing or remediating wastes or hazardous substances disposed or released by us (or prior owners or operators) in accordance with then current laws, suspending or ceasing operations at contaminated areas, or performing remedial well plugging operations or response actions to reduce the risk of future contamination. Federal laws, including the Comprehensive Environmental Response, Compensation, and Liability Act (CERCLA) and analogous state laws impose joint and several liability, without regard to fault or legality of the original conduct, on classes of persons who are considered legally responsible for releases of a hazardous substance into the environment. These persons include the owner or operator of the site where the release occurred, persons who disposed or arranged for the disposal of hazardous substances at the site, and any person who accepted hazardous substances for transportation to the site. CERCLA and analogous state laws also authorize the EPA, state environmental agencies and, in some cases, third parties to take action to prevent or respond to threats to human health or the environment and/or seek recovery of the costs of such actions from responsible classes of persons.

The Underground Injection Control (UIC) Program authorized by the Safe Drinking Water Act prohibits any underground injection unless authorized by a permit. We recycle and reuse some produced water and we also dispose of produced water in Class II UIC wells, which are designed and permitted to place the water into deep geologic formations, isolated from fresh water sources. Permits for Class II UIC wells may be issued by the EPA or by a state regulatory agency if EPA has delegated its UIC Program authority. Because some states have become concerned that the disposal of produced water could under certain circumstances contribute to seismicity, they have adopted or are considering adopting additional regulations governing such disposal.

Air Emissions

Our operations are subject to the federal Clean Air Act (CAA) and comparable state laws and regulations. Among other things, these laws and regulations regulate emissions of air pollutants from various industrial sources, including compressor stations and production equipment, and impose various control, monitoring and reporting requirements. Permits and related compliance obligations under the CAA, each state's development and promulgation of regulatory programs to comport with federal requirements, as well as changes to state implementation plans for controlling air emissions in regional non-attainment or near-non-attainment areas, may require oil and gas exploration and production operators to incur future capital expenditures in connection with the addition or modification of existing air emission control equipment and strategies.

Discharges into Waters

The federal Water Pollution Control Act, or the Clean Water Act (CWA), and analogous state laws impose restrictions and strict controls regarding the discharge of pollutants into state waters as well as waters of the United States. Spill prevention, control and countermeasure regulations require appropriate containment berms and similar structures to help prevent the contamination of regulated waters in the event of a release of hydrocarbons. In addition,

the CWA and analogous state laws require individual permits or coverage under general permits for discharges of storm water runoff from certain types of facilities and construction activities.

The Oil Pollution Act of 1990 (OPA) establishes strict liability for owners and operators of facilities that release oil into waters of the United States. The OPA and its associated regulations impose a variety of requirements on responsible parties related to the prevention of oil spills and liability for damages resulting from such spills. A ''responsible party'' under the OPA includes owners and operators of certain onshore facilities from which a release may affect waters of the United States.

Health and Safety

The Occupational Safety and Health Act (OSHA) and comparable state laws regulate the protection of the health and safety of our employees. The federal Occupational Safety and Health Administration has established workplace safety standards that provide guidelines for maintaining a safe workplace in light of potential hazards, such as employee exposure to hazardous substances. OSHA also requires employee training and maintenance of records, and the OSHA hazard communication standard and EPA community right-to-know regulations under the Emergency Planning and Community Right-to-Know Act of 1986 require that we organize and/or disclose information about hazardous materials used or produced in our operations.

Endangered Species

The Endangered Species Act (ESA) prohibits the taking of endangered or threatened species or their habitats. While some of our assets and lease acreage may be located in areas that are designated as habitats for endangered or threatened species, we believe that we are in material compliance with the ESA. However, the designation of previously unidentified endangered or threatened species in areas where we intend to conduct construction activity or the imposition of seasonal restrictions on our construction or operational activities could materially limit or delay our plans.

Global Warming and Climate Change

At the federal level, EPA regulations require us to establish and report a prescribed inventory of greenhouse gas emissions. Legislative and 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. In recent years, the EPA has considered additional standards of performance to limit methane emissions from oil and gas sources. In 2017, the EPA announced that it is reconsidering these standards and has proposed to stay their requirements. However, the standards currently remain in effect. The potential increase in our operating costs could include new or increased costs to (i) obtain permits, (ii) operate and maintain our equipment and facilities (through the reduction or elimination of venting and flaring of methane), (iii) install new emission controls on our equipment and facilities, (iv) acquire allowances authorizing our greenhouse gas emissions, (v) pay taxes related to our greenhouse gas emissions, and (vi) administer and manage a greenhouse gas emissions program. In addition to these federal actions, state governments and/or regional agencies are considering enacting new legislation and/or promulgating new regulations governing or restricting the emission of greenhouse gases from stationary sources such as our equipment and operations.

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 requires countries to review and “represent a progression” in their nationally determined contributions, which set emissions reduction goals, every five years. In August of 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. For further discussion, see Item 1A. Risk Factors - Potential legislative and regulatory actions addressing climate change could significantly impact our industry and the Company, causing increased costs and reduced demand for oil and natural gas.

Title to Properties

Our title to properties is subject to royalty, overriding royalty, carried, net profits, working and other similar interests and contractual arrangements customary in the oil and natural gas industry, to liens for current taxes not yet due and to other encumbrances. As is customary in the industry in the case of undeveloped properties, only cursory investigation of record title is made at the time of acquisition. Drilling title opinions are usually prepared before commencement of drilling operations. We believe we have satisfactory title to substantially all of our active properties in accordance with standards generally accepted in the oil and natural gas industry. Nevertheless, we are involved in title disputes from time to time that may result in litigation.

Operating Hazards and Insurance

The oil and natural gas business involves a variety of operating risks, including the risk of fire, explosions, blow-outs, pipe failure, abnormally pressured formations and environmental hazards such as oil spills, natural gas leaks, ruptures or discharges of toxic gases. If any of these should occur, we could incur legal defense costs and could suffer substantial losses due to injury or loss of life, severe damage to or destruction of property, natural resources and equipment, pollution or other environmental damage, clean-up responsibilities, regulatory investigation and penalties, and suspension of operations. Our horizontal and deep drilling activities involve greater risk of mechanical problems than vertical and shallow drilling operations.

We maintain a control of well insurance policy with a $50 million single well limit and a $100 million multiple wells limit that insures against certain sudden and accidental risks associated with drilling, completing and operating our wells. This insurance may not be adequate to cover all losses or exposure to liability. We also carry a $250 million comprehensive general liability umbrella insurance policy. In addition, we maintain a $100 million pollution liability insurance policy providing coverage for gradual pollution related risks and in excess of the general liability policy for sudden and accidental pollution risks. We provide workers' compensation insurance coverage to employees in all states in which we operate. While we believe these policies are customary in the industry, they do not provide complete coverage against all operating risks, and policy limits scale to our working interest percentage in certain situations. In addition, our insurance does not cover penalties or fines that may be assessed by a governmental authority. A loss not fully covered by insurance could have a material adverse effect on our financial position, results of operations and cash flows. Our insurance coverage may not be sufficient to cover every claim made against us or may not be commercially available for purchase in the future.

Facilities

We own an office complex in Oklahoma City and we own or lease various field offices in cities or towns in the areas where we conduct our operations.

Executive Officers

Robert D. Lawler, President, Chief Executive Officer and Director

Robert D. (“Doug”) Lawler, 51, has served as President and Chief Executive Officer since June 2013. Prior to joining Chesapeake, Mr. Lawler served in multiple engineering and leadership positions at Anadarko Petroleum Corporation. His positions at Anadarko included Senior Vice President, International and Deepwater Operations and member of Anadarko’s Executive Committee from July 2012 to May 2013; Vice President, International Operations from December 2011 to July 2012; Vice President, Operations for the Southern and Appalachia Region from March 2009 to July 2012; and Vice President, Corporate Planning from August 2008 to March 2009. Mr. Lawler began his career with Kerr-McGee Corporation in 1988 and joined Anadarko following its acquisition of Kerr-McGee in 2006.

Domenic J. Dell'Osso, Jr., Executive Vice President and Chief Financial Officer

Domenic J. (“Nick”) Dell'Osso, Jr., 41, has served as Executive Vice President and Chief Financial Officer since November 2010. Mr. Dell'Osso served as our Vice President – Finance and Chief Financial Officer of our wholly owned midstream subsidiary, Chesapeake Midstream Development, L.P., from August 2008 to November 2010.

Frank J. Patterson, Executive Vice President – Exploration and Production

Frank Patterson, 59, has served as Executive Vice President - Exploration and Production since August 2016. Previously, he served as Executive Vice President – Exploration and Northern Division since April 2016 and as Executive Vice President – Exploration, Technology & Land since May 2015. Before joining Chesapeake, Mr. Patterson served in various roles at Anadarko from 2006 to 2015, most recently as Senior Vice President – International Exploration. Prior to that he was Vice President – Deepwater Exploration at Kerr-McGee and Manager – Geology at Sun E&P/Oryx Energy.

M. Jason Pigott, Executive Vice President – Operations and Technical Services

M. Jason Pigott, 44, has served as Executive Vice President – Operations and Technical Services since August 2016. Previously, he served as Executive Vice President – Operations, Southern Division since January 2015 and Senior Vice President – Operations, Southern Division since August 2013. Before joining Chesapeake, Mr. Pigott served in various positions at Anadarko and focused on all aspects of developing unconventional resources. His positions at Anadarko included General Manager Eagle Ford from June to August 2013; General Manager East Texas and North Louisiana from October 2010 to June 2013; Southern & Appalachia Planning Manager from October 2009 to October 2010; Reservoir Engineering Manager East Texas and North Louisiana from July to October 2009; and Reservoir Engineering Manager Bossier from 2007 to July 2009.

James R. Webb, Executive Vice President – General Counsel and Corporate Secretary

James R. Webb, 50, has served as Executive Vice President – General Counsel and Corporate Secretary since January 2014. Previously, he served as Senior Vice President – Legal and General Counsel since October 2012 and as Corporate Secretary since August 2013. Mr. Webb first joined Chesapeake in May 2012 on a contract basis as Chief Legal Counsel. Prior to joining Chesapeake, Mr. Webb was an attorney with the law firm of McAfee & Taft from 1995 to October 2012.

William M. Buergler – Senior Vice President and Chief Accounting Officer

William Buergler, 45, has served as Senior Vice President and Chief Accounting Officer since August 2017. Previously, he served as Vice President - Tax since July 2014. Before joining Chesapeake, he worked for Ernst & Young LLP, where he served as a Partner since 2009.

Other Senior Officer

Cathlyn L. Tompkins, Senior Vice President – Information Technology and Chief Information Officer

Cathlyn L. Tompkins, 57, has served as Senior Vice President – Information Technology and Chief Information Officer since 2006. Ms. Tompkins served as Vice President – Information Technology from 2005 to 2006.

Employees

We had approximately 3,200 employees as of December 31, 2017. Subsequent to December 31, 2017, we underwent a reduction in workforce that affected approximately 13% of our employees across all functions, primarily at our Oklahoma City campus.