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 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 7,400 oil and natural gas wells. Our natural gas resource plays are the Marcellus Shale in the northern Appalachian Basin in Pennsylvania and the Haynesville/Bossier Shales in northwestern Louisiana. Our liquids-rich resource plays are the Eagle Ford Shale in South Texas and the stacked pay in the Powder River Basin in Wyoming.

On June 28, 2020, we and certain of our subsidiaries filed voluntary petitions for relief under chapter 11 of the Bankruptcy Code in the Bankruptcy Court. The Bankruptcy Court confirmed the Plan in a bench ruling on January 13, 2021 and entered the Confirmation Order on January 16, 2021. The Debtors emerged from bankruptcy on February 9, 2021. Upon emergence, all existing equity was canceled and new common stock was issued to the previous holders of our FLLO Term Loan Facility, Second Lien Notes, senior unsecured notes and certain general unsecured creditors whose claims were impaired as a result of our bankruptcy, as well as to other parties as set forth in the Plan, including to other parties participating in a $600 million rights offering. To facilitate our discussion in this report, we refer to the post-emergence reorganized company as the “Successor” and the pre-emergence company as the “Predecessor.” See Note 2 of the notes to our consolidated financial statements included in Item 8 of this report for further discussion of our bankruptcy and resulting reorganization.

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

Consistent Returns, Sustainable Future

Our strategy is to create shareholder value by generating cash flow from our oil and natural gas development and production activities. We focus on improving margins through operating efficiencies and financial discipline and further improving our Environmental, Social and Corporate Governance (ESG) performance. To accomplish these goals, we intend to allocate our human resources and capital expenditures to projects we believe offer the highest cash return on capital invested, to deploy leading drilling and completion technology throughout our portfolio, and to take advantage of acquisition and divestiture opportunities to strengthen our portfolio. We also intend to continue to dedicate capital to projects that reduce the environmental impact of our oil and natural gas producing activities. We continue to seek opportunities to reduce cash costs (production, gathering, processing and transportation and general and administrative) per barrel of oil equivalent production through operational efficiencies, including but not limited to improving our production volumes from existing wells. We believe that we have emerged from Chapter 11 bankruptcy as a fundamentally stronger company, built to generate sustainable free cash flow with a strengthened balance sheet, geographically diverse asset base and continuously improving ESG performance.

Maintain low leverage and strong liquidity. Now that we have emerged from Chapter 11 bankruptcy, we expect to target a net leverage ratio, which is measured as our net debt as a ratio of trailing 12-month EBITDAX, of less

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than 1x. We believe that maintaining low net leverage is integral to our business strategy and will allow us to maintain lower fixed costs, improve our margins and maintain the flexibility of our capital program.

Returns-focused capital reinvestment strategy. Our business focus will be on optimizing the development of our large, geographically diverse resource base with a prioritization of generating high cash returns on capital invested. As a result, we will target a long-term disciplined capital reinvestment rate, which we define as annual capital expenditures as a percentage of trailing 12-month EBITDAX, of 60% to 70%. We believe this level of reinvestment will be adequate to support our target long-term annual maintenance capital expenditure level, excluding capitalized interest, of $700 million to $750 million. We expect our maintenance capital program to yield in excess of annual production of 400 thousand barrels of oil equivalent per day and generate significant free cash flow at today’s prevailing commodity market prices.

Low-cost operator with expected top-quartile cash costs. We expect to continue to focus on our cost reduction initiatives, targeting a long-term annual free cash flow yield of 30% to 40% of annual EBITDAX. Since filing the Chapter 11 Cases in June 2020, we have successfully renegotiated or terminated certain of our midstream contracts and commitments, which resulted in significant reduction to our anticipated gathering, processing and transportation expenses, cumulatively achieving approximately $4 billion in expected lifetime contract savings (or $2 billion discounted to present value, assuming a 10% annual discount rate). For 2019, our total cash costs, inclusive of gathering, processing and transportation, operating, general and administrative and interest expenses were $2.8 billion. Now that we have emerged from Chapter 11 bankruptcy, based on the termination or successful renegotiation of many of our gathering, processing and transportation contracts, as well as reductions in expected interest, operating and general and administrative expenses, we expect our annualized cash costs for 2021 to be reduced by approximately $1 billion relative to 2019.

Continue efforts to reduce greenhouse gas (GHG) emissions and operate in an environmentally responsible manner with a goal of net zero direct GHG emissions by 2035. We are committed to operating our business responsibly and protecting the environments in which we operate. We plan to eliminate routine flaring on all new wells completed in 2021 and beyond, and accomplish the same on all wells, enterprise-wide by 2025. We intend to reduce our methane loss rate to 0.09% and our GHG intensity to 5.5 by 2025, reductions of 47% and 33%, respectively, as compared to 2019.

Manage commodity price exposure and ensure stability through prudent hedging strategy. We employ a prudent hedging strategy, which is aligned with our capital expenditure program and is designed to manage our exposure to commodity price volatility, ensure the stability of our cash flows and mitigate our risks to realizing attractive cash returns on capital invested. As of February 25, 2021, and consistent with requirements of our DIP Credit Facility we have 19 mmbbls and 548 bcf of expected 2021, representing 77% and 74% of 2021 forecasted oil and natural gas production hedged at prices of $42.69/bbl and $2.67/mcf, respectively. Additionally, as of February 25, 2021, we have hedged 11 mmbbl and 273 bcf of expected 2022 oil and natural gas production at prices of $44.30/bbl and $2.53/mcf, respectively.

Operating Areas

We focus our acquisition, exploration, development and production efforts in the five geographic operating areas described below.

Marcellus - Northern Appalachian Basin in Pennsylvania.

Haynesville - Northwestern Louisiana (Gulf Coast).

Eagle Ford - South Texas.

Brazos Valley - Southeast Texas.

Powder River Basin - Stacked pay in Wyoming.

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Well Data

As of December 31, 2020, we held an interest in approximately 7,400 gross productive wells, including 5,900 properties in which we held a working interest and 1,500 properties in which we held an overriding or royalty interest. Of the 5,900 (3,700 net) properties in which we held a working interest, 2,500 (1,400 net) properties were classified as productive natural gas wells and 3,400 (2,300 net) properties were classified as productive oil wells. During 2020 excluding sold properties, we operated 5,200 gross wells and held a non-operating working interest in 700 gross wells. We also drilled or participated in 188 gross (128 net) wells as operator and participated in another 17 gross (nominal 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:

						2020																								2019																								2018
						Gross						%						Net						%						Gross						%						Net						%						Gross						%						Net						%
Development:
Productive						203						100						126						100						414						100						271						100						363						99						227						99
Dry						—						—						—						—						—						—						—						—						2						1						1						1
Total						203						100						126						100						414						100						271						100						365						100						228						100
Exploratory:
Productive						—						—						—						—						1						20						1						20						10						83						9						82
Dry						2						100						2						100						4						80						4						80						2						17						2						18
Total						2						100						2						100						5						100						5						100						12						100						11						100

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

						2020												2019												2018
						Gross Wells						Net Wells						Gross Wells						Net Wells						Gross Wells						Net Wells
Marcellus						79						33						44						22						52						23
Haynesville						21						19						22						16						30						21
Eagle Ford						55						36						150						85						162						98
Brazos Valley						31						29						83						79						—						—
Powder River Basin						12						9						75						57						41						34
Mid-Continent						5						—						40						12						52						32
Utica						—						—						—						—						40						31
Other						2						2						5						5						—						—
Total						205						128						419						276						377						239

As of December 31, 2020, we had 55 gross (32 net) wells in the process of being drilled or completed.

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Production Volumes, Sales Prices, Production Expenses 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,
						2020						2019						2018
Net Production:
Oil (mmbbl)						37						43						33
Natural gas (bcf)						685						728						832
NGL (mmbbl)						11						12						19
Oil equivalent (mmboe)						163						177						190
Average Sales Price of Production:
Oil ($ per bbl)						$	38.16					$	59.16					$	67.25
Natural gas ($ per mcf)						$	1.73					$	2.45					$	2.99
NGL ($ per bbl)						$	11.55					$	15.62					$	26.50
Oil equivalent ($ per boe)						$	16.84					$	25.57					$	27.27
Average Sales Price (including realized gains (losses) on derivatives):
Oil ($ per bbl)						$	56.74					$	60.00					$	57.42
Natural gas ($ per mcf)						$	1.97					$	2.60					$	3.00
NGL ($ per bbl)						$	11.55					$	15.62					$	25.84
Oil equivalent ($ per boe)						$	22.09					$	26.42					$	25.56
Expenses ($ per boe):
Oil, natural gas and NGL production						$	2.29					$	2.94					$	2.50
Oil, natural gas and NGL gathering, processing and transportation						$	6.64					$	6.13					$	7.35

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Oil, Natural Gas and NGL Reserves

The tables below set forth information as of December 31, 2020, 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, 2020
						Oil						Natural Gas						NGL						Total
						(mmbbl)						(bcf)						(mmbbl)						(mmboe)
Proved developed						158						3,196						51						742
Proved undeveloped						3						334						1						60
Total proved(a)						161						3,530						52						802

						Proved Developed						Proved Undeveloped						Total Proved
						($ in millions)
Estimated future net revenue(b)						$	4,519					$	202					$	4,721
Present value of estimated future net revenue (PV-10)(b)						$	2,976					$	111					$	3,087
Standardized measure(b)																		$	3,086

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(a) Marcellus, Eagle Ford, and Haynesville accounted for approximately 47%, 22%, and 18% respectively, of our estimated proved reserves by volume as of December 31, 2020.

(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 pricing differentials and costs under existing economic conditions as of December 31, 2020, 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, 2020. The prices used in our PV-10 measure were $39.57 of oil and $1.98 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, 2020. 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 $1 million as of December 31, 2020.

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, a non-GAAP measure, 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 comparison 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.

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As of December 31, 2020, our proved reserve estimates included 60 mmboe of reserves classified as proved undeveloped, compared to 726 mmboe as of December 31, 2019. Presented below is a summary of changes in our proved undeveloped reserves (PUDs) for 2020:

						Total
						(mmboe)
Proved undeveloped reserves, beginning of period						726
Extensions and discoveries						1
Revisions of previous estimates						(539)
Developed						(128)
Purchase of reserves-in-place						—
Proved undeveloped reserves, end of period						60

As of December 31, 2020, all PUDs were planned to be developed within five years of original recording. In 2020, we invested approximately $509 million to convert 128 mmboe of PUDs to proved developed reserves. During the first quarter of 2021, we estimate that we will invest approximately $126 million for PUD conversion. As a result of our entry into Chapter 11 bankruptcy and the limited duration of our DIP Credit Facility at December 31, 2020, we could not carry any PUD reserves past the maturity date of our DIP financing and we therefore recorded a downward revision of 539 mmboe of our previously reported PUD reserves. Given our liquidity and financial position post-emergence we expect to record more PUD reserves as of March 31, 2021.

The future net revenue attributable to our estimated PUDs was $202 million and the present value was $111 million as of December 31, 2020. These values were calculated assuming that we will expend approximately $126 million to develop these reserves during the first quarter of 2021.

Of our 742 mmboe of proved developed reserves as of December 31, 2020, approximately 6 mmboe, or 1%, 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, 2020, 2019 and 2018, 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 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. 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 this report for further discussion of our reserve quantities.

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Reserves Estimation

Our Corporate Reserves Department prepared approximately 13% by volume, and approximately 11% 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 18 years of practical experience in the oil and gas industry, with over 15 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 LaRoche Petroleum Consultants, Ltd., a third-party engineering firm, to prepare approximately 87% by volume, and approximately 89% by value, of our estimated proved reserves as of December 31, 2020. 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 40 years of practical experience in the estimation and evaluation of reserves;

• licensed professional engineer in the State of Texas; and

• Bachelor of Science and Master of Science degrees in Petroleum Engineering.

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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, 2020. 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						555						353						245						168						16						16						816						537
Haynesville						230						203						30						22						1						1						261						226
Eagle Ford						316						188						45						31						—						—						361						219
Brazos Valley						360						298						222						126						—						—						582						424
Powder River Basin						105						85						137						104						1						1						243						190
Other(a)						157						126						918						868						431						427						1,506						1,421
Total						1,723						1,253						1,597						1,319						449						445						3,769						3,017

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(a) Includes 1.2 million net acres retained in the 2016 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, 2020:

						Acres Expiring
						Gross Acres						Net Acres
						(in thousands)
Years Ending December 31:
2021						60						52
2022						30						30
2023						12						11
After 2023						83						82
Held-by-production(a)						1,412						1,144
Total						1,597						1,319

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

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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.

Generally, our oil production is sold under market-sensitive short-term or spot price contracts. Natural gas and NGL production are 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 6 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 17%, 12% and 10% of total revenues (before the effects of hedging) for the years ended December 31, 2020, 2019 and 2018, respectively. No other purchasers accounted for more than 10% of our total revenues in 2020, 2019 or 2018.

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 that 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.

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;

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• 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/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 well completion and hydraulic fracturing;

• water withdrawal;

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

• emergency response, contingency plans and spill prevention plans;

• emissions and discharges permitting;

• 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.

Shortly after taking office in January 2021, President Biden issued a series of executive orders designed to address climate change and requiring agencies to review environmental actions taken by the Trump administration, as well as a memorandum to departments and agencies to refrain from proposing or issuing rules until a departmental or agency head appointed or designated by the Biden administration has reviewed and approved the rule. These executive orders may result in the development of additional regulations or changes to existing regulations. Failure to comply with these laws and regulations can lead to the imposition of remedial liabilities, administrative, civil or criminal fines or penalties or 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 safety and health compliance fundamental, 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 the protection of the environment and safety and health compliance 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.

Our operations also are 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, while 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. For further discussion, see Item 1A. Risk Factors - We are subject to extensive governmental regulation, which can change and could adversely impact our business.

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

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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 make it difficult or impossible to conduct our drilling and completion operations, and thereby reduce the amount of oil, natural gas and NGL that we are ultimately able to produce from our properties.

Certain of our U.S. natural gas and oil leases, primarily in our Powder River Basin operating area, 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, on January 20, 2021, the Acting Secretary for the Department of the Interior signed an order effectively suspending new fossil fuel leasing and permitting on federal lands for 60 days. Then on January 27, 2021, President Biden issued an executive order indefinitely suspending new oil and natural gas leases on public lands or in offshore waters pending completion of a comprehensive review and reconsideration of federal oil and gas permitting and leasing practices. To the extent that the review results in the development of additional restrictions on drilling, limitations on the availability of leases, or restrictions on the ability to obtain required permits, it could have a material adverse impact on our operations.

Permitting activities on federal lands are also 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.

For further discussion, see Item 1A. Risk Factors - Oil and natural gas drilling and producing operations can be hazardous and may expose us to liabilities.

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 $50 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

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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, 54, 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., 44, 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. Before joining Chesapeake, Mr. Dell’Osso was an energy investment banker with Jefferies & Co. from 2006 to 2008 and Banc of America Securities from 2004 to 2006.

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

Frank J. Patterson, 62, 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.

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

James R. Webb, 53, 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, 48, 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.

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Human Capital

One Team. One Chesapeake.

Our “One CHK” culture and company core values promote an inclusive, diverse and productive workplace. Working as One CHK defines Chesapeake’s culture. It is a culture that engages the power of our people, working cooperatively to put Chesapeake first and perform our best for the company. We had approximately 1,300 employees as of February 25, 2021.

Our Culture, Our Core Values

At Chesapeake, our employees are driven to create value every day in a safe and responsible manner. Our core values are the foundation of our culture and the driving force behind our goal to achieve ESG excellence. Serving as the lens through which we evaluate every business decision, our commitment to these values, in both words and actions builds a stronger, healthier Chesapeake, benefiting all our stakeholders. Our core values are:

• Integrity and Trust

• Respect

• Transparency and Open Communication

• Commercial Focus

• Change Leadership

Celebrating Inclusion and Diversity

We are committed to inclusion and diversity. We proactively embrace our diversity of people, thoughts and talents, and combine these strengths to pursue results and meaningful change for our company, employees and stakeholders, and we provide education and training for our employees on topics related to inclusion and diversity.

In 2019, Chesapeake joined a coalition of companies pledging to advance diversity and inclusion in the workplace. Through the Chief Executive Officer Action for Diversity & Inclusion™, Chief Executive Officer Doug Lawler committed himself and Chesapeake to cultivate a workplace in which diverse perspectives and experiences are welcomed and respected and where employees feel encouraged to discuss diversity and inclusion. As the first E&P Chief Executive Officer to sign the pledge, Mr. Lawler joins more than 550 signatories who are sharing best practices and learning opportunities to initiate real change within their organizations. On February 9, 2021, we formed a board committee dedicated to ESG oversight, including our inclusion and diversity efforts. Two of our seven directors are considered diverse, including one female and one “underrepresented minority” (as defined in Nasdaq’s newly proposed listing rule).

Stewards of Our Environment

Chesapeake is committed to protecting our country’s natural resources and reducing our environmental footprint. We have strict standards for environmental stewardship and a culture of environmental excellence among our employees and business partners. We recognize that ownership and accountability are key to helping ensure our work sites are safe and protective of the environment.

Our path to leading a responsible energy future begins with our goal to achieve net-zero direct greenhouse gas emissions by 2035. To meet this challenge, we have set meaningful initial steps including:

• Eliminating routine flaring from all new wells completed from 2021 forward, and enterprise-wide by 2025

• Reducing our methane intensity to 0.09% by 2025

• Reducing our GHG intensity to 5.5 by 2025

Safety First Every Day

Safety is more than a company metric, it is a value that drives our commitment to responsible operations. We set and deliver on strict safety standards, prioritizing safety for everyone every day. Our safety culture is modeled first by Mr. Lawler, with guidance and leadership from our Health, Safety, Environmental and Regulatory (HSER) team. Maintaining a safe work environment and promoting safe behaviors is a commitment that each of our

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employees own together. We hold each other accountable to keeping our sites, our co-workers and our contractors safe.

One program that reinforces this philosophy of personal responsibility is Stop Work Authority. Through Stop Work Authority, every employee and contractor has the right and responsibility to stop work if conditions are unsafe or could cause harm to the environment. Creating an incident-free work environment starts with setting clear expectations among employees, contractors and suppliers regarding our safety standards, and working to equip these individuals with the skills necessary to promote safety in their areas of work. The foundation of our safety training efforts is our Stay Accident Free Every Day (S.A.F.E.) program, which encourages all workers on our locations to take personal responsibility for their safety and the safety of those around them. This behavior-based program addresses the activities that can often lead to safety incidents and encourages actions that create safe work sites and a safe corporate campus.

Ethical Business Conduct

Chesapeake works hard to maintain the confidence of our stakeholders. We earn this trust by acting in an ethical manner to protect our people, the environment and the communities where we operate. This starts by driving accountability through all levels of the company and having systems in place to uphold our high standards for conduct. Strong governance practices begin at the top providing our organization with clear guidelines to define standards for ethical behavior at every level. Each Chesapeake director or employee, regardless of position, must abide by Chesapeake’s Code of Business Conduct (the "Code"), which is structured around our core values. Each year all employees must sign a Code certification confirming they have reviewed the Code and related policies, understand the high standards expected of them and will report actual or potential ethics concerns or Code violations.

Employee Wellness and Benefits

Supporting the individual well-being of our employees is foundational to our safety culture and success as a company. We champion healthy lifestyles and offer health resources. Across the company, employees are offered preventive programs and are encouraged to complete an annual screening for common health-related issues. We support our employees’ and their families’ health by offering full medical, dental, vision, prescription drug insurance for employees and their families, life insurance, short- and long-term disability coverage, and health savings and dependent care flexible spending accounts. We offer parental leave for the birth or adoption of a child, an adoption assistance program, alternate work schedules, a 401(k) savings plan with company match, flexible work hours, tuition reimbursement and access to a child development center and fitness center at market rates. Additionally, Chesapeake provides employees and their families access to a confidential Employee Assistance Program (EAP) which connects employees with trained counselors and other support professionals.

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