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 to produce oil, natural gas and NGL from underground reservoirs. We own a large and geographically diverse portfolio of onshore U.S. unconventional liquids and natural gas assets, including interests in approximately 13,200 oil and natural gas wells. We have leading positions in the liquids-rich resource plays of the Eagle Ford Shale in South Texas, the stacked pay in the Powder River Basin in Wyoming and the Anadarko Basin in northwestern Oklahoma. Our natural gas resource plays are the Marcellus Shale in the northern Appalachian Basin in Pennsylvania and the Haynesville/Bossier Shales in northwestern Louisiana.

In October 2018, we sold our interests in the Utica Shale operating area located in Ohio for approximately $1.9 billion to Encino Acquisition Partners (“Encino”), a private oil and gas company headquartered in Houston, Texas. We used the net proceeds to reduce debt.

In February 2019, we acquired WildHorse Resource Development Corporation, an oil and gas company with operations in the Eagle Ford Shale and Austin Chalk formations in southeast Texas, for approximately 717.3 million shares of our common stock and $381 million in cash, and the assumption of WildHorse’s debt of $1.4 billion as of the acquisition date of February 1, 2019. The acquisition of WildHorse expands our oil growth platform and accelerates our progress toward our strategic and financial goals of enhancing our margins, achieving sustainable free cash flow generation, and reducing our net debt to EBITDA ratio. In conjunction with the acquisition under terms of the merger agreement, David W. Hayes, partner for NGP Energy Capital Management, L.L.C. (“NGP”), has joined our board and another designee of NGP is expected to be appointed to fill the next vacancy on our board.

Because the acquisition of WildHorse occurred after December 31, 2018, Chesapeake’s consolidated financial statements and the notes thereto do not include or take into account the closing of the acquisition and its effects.

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.

The SEC maintains a website at www.sec.gov that contains reports, proxy and information statements, and other information regarding issuers, including Chesapeake, that file electronically with the SEC.

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, improving margins through financial discipline and operating efficiencies and improving environmental and safety performance. To accomplish these goals, we intend to allocate our capital expenditures to projects we believe offer the highest return

regardless of the commodity price environment, to deploy leading drilling and completion technology throughout our portfolio, and to take advantage of acquisition and divestiture opportunities 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. We continue to seek opportunities to reduce cash costs (production, gathering, processing and transportation, general and administrative and interest expenses) through operational efficiencies, including but not limited to improving 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 (Gulf Coast).

Eagle Ford - South Texas.

Brazos Valley - Southeast Texas assets acquired in our WildHorse acquisition on February 1, 2019.

Powder River Basin - Stacked pay in Wyoming.

Mid-Continent - Anadarko Basin in northwestern Oklahoma.

Well Data

As of December 31, 2018, we held an interest in approximately 13,200 gross (5,600 net) productive wells, including 10,200 properties in which we held a working interest and 3,000 properties in which we held an overriding or royalty interest. Of the 10,200 properties in which we had a working interest, we operated 7,200 wells, 6,800 gross (3,800 net), of which were classified as productive natural gas wells and 3,400 gross (1,800 net) were classified as productive oil wells. During 2018, we drilled or participated in 351 gross (238 net) wells as operator and participated in another 26 gross (1 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:

		2018												2017												2016
		Gross			%			Net			%			Gross			%			Net			%			Gross			%			Net			%
Development:
Productive		363			99			227			99			462			99			292			99			431			99			236			99
Dry		2			1			1			1			4			1			2			1			1			1			1			1
Total		365			100			228			100			466			100			294			100			432			100			237			100
Exploratory:
Productive		10			83			9			82			2			100			2			100			3			100			2			100
Dry		2			17			2			18			—			—			—			—			—			—			—			—
Total		12			100			11			100			2			100			2			100			3			100			2			100

The following table shows the wells we drilled or participated in by operating area:

		2018						2017						2016
		Gross Wells			Net Wells			Gross Wells			Net Wells			Gross Wells			Net Wells
Marcellus		52			23			43			21			19			9
Haynesville		30			21			37			34			41			34
Eagle Ford		162			98			180			106			199			116
Powder River Basin		41			34			25			21			1			1
Mid-Continent		52			32			114			58			135			62
Utica		40			31			69			56			34			17
Other		—			—			—			—			6			—
Total		377			239			468			296			435			239

As of December 31, 2018, we had 149 gross (82 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, average sales price of our production combined with our realized gains or losses on derivatives and production and gathering, processing and transportation expenses per boe for the periods indicated:

		Years Ended December 31,
		2018				2017				2016
Net Production:
Oil (mmbbl)		33				33				33
Natural gas (bcf)		832				878				1,049
NGL (mmbbl)		19				21				24
Oil equivalent (mmboe)		190				200				233
Average Sales Price of Production:
Oil ($ per bbl)		$	67.25			$	51.03			$	40.65
Natural gas ($ per mcf)		$	2.99			$	2.76			$	2.05
NGL ($ per bbl)		$	26.50			$	23.18			$	14.76
Oil equivalent ($ per boe)		$	27.27			$	22.88			$	16.63
Average Sales Price (including realized gains (losses) on derivatives):
Oil ($ per bbl)		$	57.42			$	53.19			$	43.58
Natural gas ($ per mcf)		$	3.00			$	2.75			$	2.20
NGL ($ per bbl)		$	25.84			$	22.98			$	14.43
Oil equivalent ($ per boe)		$	25.56			$	23.17			$	17.66
Expenses ($ per boe):
Oil, natural gas and NGL production		$	2.84			$	2.81			$	3.05
Oil, natural gas and NGL gathering, processing and transportation		$	7.35			$	7.36			$	7.98

Oil, Natural Gas and NGL Reserves

The tables below set forth information as of December 31, 2018, 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”). None of the estimated future net revenue, PV-10 nor the standardized measure are 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, 2018
		Oil			Natural Gas			NGL			Total
		(mmbbl)			(bcf)			(mmbbl)			(mmboe)
Proved developed		127.6			3,314			67.9			748
Proved undeveloped		87.9			3,463			35.4			700
Total proved(a)		215.5			6,777			103.3			1,448

		Proved Developed				Proved Undeveloped				Total Proved
		($ in millions)
Estimated future net revenue(b)		$	10,214			$	7,120			$	17,334
Present value of estimated future net revenue (PV-10)(b)		$	6,177			$	3,350			$	9,527
Standardized measure(b)										$	9,495

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(a)	Marcellus, Haynesville and Eagle Ford accounted for approximately 40%, 27%, and 22%, respectively, of our estimated proved reserves by volume as of December 31, 2018.

(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, 2018, and assuming commodity prices as set forth below. 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, 2018. The prices used in our PV-10 measure were $65.56 of oil and $3.10 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, 2018. 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 of $32 million as of December 31, 2018.

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, 2018, our proved reserve estimates included 700 mmboe of reserves classified as proved undeveloped, compared to 796 mmboe as of December 31, 2017. Presented below is a summary of changes in our proved undeveloped reserves (PUDs) for 2018:

		Total
		(mmboe)
Proved undeveloped reserves, beginning of period		796
Extensions and discoveries		236
Revisions of previous estimates		(27	)
Developed		(115	)
Sale of reserves-in-place		(190	)
Proved undeveloped reserves, end of period		700

As of December 31, 2018, all PUDs were planned to be developed within five years. In 2018, we invested approximately $807 million to convert 115 mmboe of PUDs to proved developed reserves. In 2019, we estimate that we will invest approximately $1.2 billion for PUD conversion. We added 236 mmboe of proved undeveloped reserves through extensions and discoveries primarily as a result of longer planned lateral lengths and additional allocated capital in our five-year development plan. We sold 190 mmboe of proved undeveloped reserves primarily in the divestiture of Utica Shale assets. We recorded a downward revision of 27 mmboe from previous estimates due to ongoing portfolio evaluation including longer lateral and spacing adjustments.

The future net revenue attributable to our estimated PUDs was $7.1 billion and the present value was $3.3 billion as of December 31, 2018. These values were calculated assuming that we will expend approximately $3.6 billion to develop these reserves ($1.2 billion in 2019, $984 million in 2020, $901 million in 2021, $337 million in 2022 and $166 million in 2023). 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.

Of our 748 mmboe of proved developed reserves as of December 31, 2018, approximately 20 mmboe, or 3%, 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, 2018, 2017 and 2016, 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. See Supplemental Disclosures About Oil, Natural Gas and NGL Producing Activities included in Item 8 of Part II of this report for further discussion of our reserve quantities.

Reserves Estimation

Our Corporate Reserves Department prepared approximately 20% by volume, and approximately 18% 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 12 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 Engineers 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 Engineers.

•	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 – 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 80% by volume, and approximately 82% by value, of our estimated proved reserves as of December 31, 2018. 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,
		2018				2017				2016
		($ in millions)
Acquisition of Properties:
Proved properties		$	80			$	23			$	403
Unproved properties		216				271				403
Exploratory costs		132				21				52
Development costs		2,009				2,146				1,312
Costs incurred(a)		$	2,437			$	2,461			$	2,170

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

Capitalized interest		$	162			$	194			$	242
Asset retirement obligations(b)		$	8			$	(34	)		$	(57	)

(b)	Activity in 2017 and 2016 primarily reflects revisions as the result of decreased plugging and abandonment costs in certain of our operating areas.

A summary of our exploration and development, acquisition and divestiture activities in 2018 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		52			23			$	170			$	5			$	1			$	(2	)		$	—			$	174
Haynesville		30			21			346				6				—				(5		)		(8		)		339
Eagle Ford		162			98			696				14				—				(2		)		—				708
Powder River Basin		41			34			395				73				—				(28		)		—				440
Mid-Continent		52			32			201				19				1				(123		)		(262		)		(164		)
Utica		40			31			301				90				77				(325		)		(2,039		)		(1,896		)
Other		—			—			32				9				1				—				(6		)		36
Total		377			239			$	2,141			$	216			$	80			$	(485	)		$	(2,315	)		$	(363	)

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(a)	Includes asset retirement disposal of $28 million related to divestitures.

(b)	Includes capitalized internal costs of $121 million and capitalized interest of $162 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, 2018. 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		541			347			265			177			16			16			822			540
Haynesville		302			270			99			67			—			—			401			337
Eagle Ford		308			183			77			52			—			—			385			235
Powder River Basin		73			58			244			189			1			1			318			248
Mid-Continent		926			602			200			132			38			34			1,164			768
Other(a)		184			146			1,066			983			435			431			1,685			1,560
Total		2,334			1,606			1,951			1,600			490			482			4,775			3,688

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(a)	Includes 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, 2018:

		Acres Expiring
		Gross Acres			Net Acres
		(in thousands)
Years Ending December 31:
2019		108			87
2020		49			44
2021		37			27
After 2021		53			51
Held-by-production(a)		1,704			1,391
Total		1,951			1,600

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

Marketing

The principal function of our marketing operations is 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 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.

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. See Note 4 of the notes to our consolidated financial statements included in Item 8 of this report for further discussion of commitments.

Major Customers

Sales to Valero Energy Corporation constituted approximately 10% of our total revenues (before the effects of hedging) for the year ended December 31, 2018. No other purchasers accounted for more than 10% of our total revenues for 2018. 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% of our total revenues (before the effects of hedging) for the year ended December 31, 2016.

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.

Public Policy and Government Regulation

All of our operations are conducted onshore in the United States. Our industry is subject to a wide range of regulations, laws, rules, taxes, fees and other policy implementation actions that have been pervasive and are under constant review for amendment or expansion. Numerous government agencies have issued extensive regulations which are binding on our industry, some of which carry substantial penalties for failure to comply. These laws and regulations increase the cost of doing business and consequently affect profitability. Additionally, currently unforeseen environmental incidents may occur or past non-compliance with environmental laws or regulations may be discovered. We actively monitor regulatory developments applicable to our industry in order to anticipate, design and implement required compliance activities and systems. The following are significant areas of government control and regulation affecting our operations.

Regulation – Environment, Health and Safety

Exploration and Production, Environmental, Health and Safety, and Occupational Laws and Regulations

Our operations are subject to federal, tribal, state, and local laws and regulations. These laws and regulations relate to matters that include, but are not limited to, the following:

•	reporting of workplace injuries and illnesses;

•	industrial hygiene monitoring;

•	worker protection and workplace safety;

•	approval or permits to drill and to conduct operations;

•	provision of financial assurances (such as bonds) covering drilling and well operations;

•	calculation and disbursement of royalty payments and production taxes;

•	seismic operations and data;

•	location, drilling, cementing and casing of wells;

•	well design and construction of pad and equipment;

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

•	method of completing wells;

•	hydraulic fracturing;

•	water withdrawal;

•	well production and operations, including processing and gathering systems;

•	emergency response, contingency plans and spill prevention plans;

•	air emissions and fluid discharges;

•	climate change;

•	use, transportation, storage and disposal of fluids and materials incidental to oil and gas operations;

•	surface usage, maintenance, monitoring and the restoration of properties associated with well pads, pipelines, impoundments and access roads;

•	plugging and abandoning of wells; and

•	transportation of production.

Failure to comply with these laws and regulations can lead to the imposition of remedial liabilities, fines, or criminal penalties or to injunctions limiting our operations in affected areas. Moreover, multiple environmental laws provide for citizen suits which allow environmental organizations to act in the place of the government and sue operators for alleged violations of environmental law. We consider the costs of environmental protection and of safety and health compliance to be necessary, manageable parts of our business. We have been able to plan for and comply with environmental, safety and health laws and regulations without materially altering our operating strategy or incurring significant unreimbursed expenditures. However, based on regulatory trends and increasingly stringent laws, our capital expenditures and operating expenses related to compliance with the protection of the environment, safety and health have increased over the years and may continue to increase. We cannot predict with any reasonable degree of certainty our future exposure concerning such matters. See the Risk Factors described in Item 1A of this report for further discussion of governmental regulation and ongoing regulatory changes, including with respect to environmental matters,

Our operations are also subject to conservation regulations, including the regulation of the size of drilling and spacing units or proration units, the number of wells that may be drilled in a unit, the rate of production allowable from oil and gas wells, and the unitization or pooling of oil and gas properties. In the United States, some states allow the forced pooling or integration of tracts to facilitate exploration. Other states rely on voluntary pooling of lands and leases which may make it more difficult to develop oil and gas properties. In addition, federal and state conservation laws generally limit the venting or flaring of natural gas, and state conservation laws impose certain requirements regarding the ratable purchase of production. These regulations limit the amounts of oil and gas we can produce from our wells and the number of wells or the locations at which we can drill.

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 potential impacts of hydraulic fracturing, which could spur further action toward federal, state and/or local legislation and regulation. Further restrictions of hydraulic fracturing could reduce the amount of oil, natural gas and NGL that we are ultimately able to produce in commercial quantities from our properties.

Certain of our U.S. natural gas and oil leases are granted or approved by the federal government and administered by the Bureau of Land Management (BLM) or Bureau of Indian Affairs (BIA) of the Department of the Interior. Such leases require compliance with detailed federal regulations and orders that regulate, among other matters, drilling and operations on lands covered by these leases and calculation and disbursement of royalty payments to the federal government, tribes or tribal members. The federal government has been particularly active in recent years in evaluating and, in some cases, promulgating new rules and regulations regarding competitive lease bidding, venting and flaring, oil and gas measurement and royalty payment obligations for production from federal lands. In addition, permitting activities on federal lands are subject to frequent delays.

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.

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 $75 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, 52, 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., 42, 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 J. Patterson, 60, 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, 45, 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, 51, 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, 46, 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.

Employees

We had approximately 2,350 employees as of December 31, 2018.