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 natural gas, oil and NGL from underground reservoirs. We own a large portfolio of onshore U.S. unconventional natural gas assets, including interests in approximately 5,000 gross natural gas wells.

On January 10, 2024, Chesapeake and Southwestern entered into an all-stock merger agreement. Southwestern is an independent energy company engaged in development, exploration and production activities, including related marketing activities, within its operating areas in the Marcellus and Haynesville shale plays. Pursuant to the terms of the merger agreement, at the effective time of the Southwestern Merger, each eligible share of Southwestern common stock issued and outstanding immediately prior to the effective time will be automatically converted into the right to receive 0.0867 of a share of Chesapeake’s common stock. Our Board of Directors and the Board of Directors of Southwestern both approved the merger agreement. Subject to the approval of our shareholders and Southwestern shareholders, regulatory approvals and the satisfaction or waiver of other customary closing conditions, the Southwestern Merger is targeted to close in the second quarter of 2024.

During 2023, we completed our exit from Eagle Ford through three separate divestiture transactions, with aggregate proceeds from these transactions exceeding $3.5 billion, subject to customary post-closing adjustments.

On March 25, 2022, we sold our Powder River Basin assets in Wyoming to Continental Resources, Inc. for approximately $450 million.

On March 9, 2022, we completed our acquisition of Chief, Radler and associated non-operated interests held by affiliates of Tug Hill. Chief, Radler and Tug Hill held producing assets and an inventory of premium drilling locations in the Marcellus Shale in Northeast Pennsylvania.

On November 1, 2021, we completed our acquisition of Vine, an energy company focused on the development of natural gas properties in stacked Haynesville and Mid-Bossier shale plays in Northwest Louisiana.

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. Upon emergence from bankruptcy, we adopted fresh start accounting, which resulted in us becoming a new entity for financial reporting purposes. Accordingly, the consolidated financial statements on or after February 9, 2021 are not comparable to the consolidated financial statements prior to that date. 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 and Note 3 of the notes to our consolidated financial statements included in Item 8 of Part II of this report for further discussion of our bankruptcy, the resulting reorganization and fresh start accounting.

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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 business strategy is to create shareholder value through the responsible development of our significant resource plays, while continuing to be a leading provider of affordable, reliable, lower carbon energy to markets in need.

Superior Capital Returns. We consistently focus on optimizing the development of our large resource base with a prioritization of generating high cash returns on capital invested. Our drive toward continuous improvement through engineering innovation and planning enhances margins for our shareholders.

Deep, Attractive Inventory. We hold leading positions in each of the two premier natural gas fields in the U.S. offering premium rock, returns and runway. Our prioritization of best-in-class execution further unlocks these resources to the benefit of our stakeholders.

Sustainability Leadership. We are committed to protecting our country’s natural resources and reducing our environmental footprint. We continue to foster a focus on environmental excellence through a culture of stewardship and sustainability 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.

Premier Balance Sheet. 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. We further de-risk our margins and cash flows with prudent natural gas hedging that aims to reduce the impact of volatility.

Operating Areas

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

Marcellus - Northern Appalachian Basin in Pennsylvania.

Haynesville - Haynesville/Bossier Shales in Northwestern Louisiana.

Well Data

As of December 31, 2023, we held an interest in approximately 5,000 gross productive gas wells, including 3,300 (1,900 net) wells in which we held a working interest and 1,700 wells in which we held an overriding or royalty interest. Of the 3,300 wells in which we held a working interest, we operated 2,800 gross wells and held a non-operating working interest in 500 gross wells. We also completed 166 gross (108 net) wells as operator and participated in another 28 gross (1 net) wells completed by other operators. We operate approximately 98% of our current daily production volumes.

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Drilling Activity

The following table sets forth the wells we completed 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:

						2023																								2022																								2021
						Gross						%						Net						%						Gross						%						Net						%						Gross						%						Net						%
Development:
Productive						194						100						109						100						237						100						151						100						137						100						74						100
Dry						—						—						—						—						—						—						—						—						—						—						—						—
Total						194						100						109						100						237						100						151						100						137						100						74						100
Exploratory:
Productive						—						—						—						—						—						—						—						—						2						100						1						100
Dry						—						—						—						—						1						100						1						100						—						—						—						—
Total						—						—						—						—						1						100						1						100						2						100						1						100

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

						2023												2022												2021
						Gross Wells						Net Wells						Gross Wells						Net Wells						Gross Wells						Net Wells
Marcellus						78						37						103						59						83						34
Haynesville						84						51						83						61						40						31
Eagle Ford						32						21						52						32						12						7
Powder River Basin						—						—						—						—						4						3
Total						194						109						238						152						139						75

As of December 31, 2023, we had 92 gross (58 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 tables present information regarding our net production volumes, average sales price received for our production, and production and gathering, processing and transportation expenses per Mcfe for the periods indicated for our significant fields:

						Production
						Natural Gas (Bcf)						Oil (MMBbl)						NGL (MMBbl)						Total (Bcfe)
2023 Successor Period
Marcellus						669						—						—						669
Haynesville						566						—						—						566
Eagle Ford						31						7.7						3.8						100
Total Production						1,266						7.7						3.8						1,335
2022 Successor Period
Marcellus						670						—						—						670
Haynesville						588						—						—						588
Eagle Ford						46						18.7						5.8						193
Total Production						1,308						19.4						6.0						1,461
2021 Successor Period
Marcellus						421						—						—						421
Haynesville						243						—						—						243
Eagle Ford						44						19.5						6.0						198
Total Production						727						22.5						7.1						905
2021 Predecessor Period
Marcellus						50						—						—						50
Haynesville						22						—						—						22
Eagle Ford						7						3.0						0.7						29
Total Production						80						3.4						0.9						105

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						Average Sales Price of Production**(a)**																								Expenses ($/Mcfe)
						Natural Gas ($/Mcf)						Oil ($/Bbl)						NGL ($/Bbl)						Total ($/Mcfe)						Production						GP&T
2023 Successor Period
Marcellus						$	2.22					$	—					$	—					$	2.22					$	0.12					$	0.65
Haynesville						$	2.30					$	—					$	—					$	2.30					$	0.33					$	0.46
Eagle Ford						$	2.25					$	77.80					$	25.62					$	7.64					$	0.91					$	1.57
Total						$	2.25					$	77.80					$	25.62					$	2.66					$	0.27					$	0.64
2022 Successor Period
Marcellus						$	6.03					$	—					$	—					$	6.03					$	0.11					$	0.57
Haynesville						$	5.92					$	—					$	—					$	5.92					$	0.26					$	0.53
Eagle Ford						$	5.64					$	96.10					$	36.76					$	11.76					$	1.22					$	1.78
Total						$	5.96					$	96.07					$	37.48					$	6.77					$	0.33					$	0.73
2021 Successor Period
Marcellus						$	3.25					$	—					$	—					$	3.25					$	0.08					$	0.68
Haynesville						$	4.10					$	—					$	—					$	4.10					$	0.24					$	0.49
Eagle Ford						$	4.02					$	69.25					$	29.76					$	8.65					$	0.88					$	1.46
Total						$	3.61					$	69.07					$	31.37					$	4.87					$	0.33					$	0.86
2021 Predecessor Period
Marcellus						$	2.42					$	—					$	—					$	2.42					$	0.08					$	0.70
Haynesville						$	2.44					$	—					$	—					$	2.44					$	0.19					$	0.49
Eagle Ford						$	2.57					$	53.37					$	23.94					$	6.71					$	0.71					$	1.55
Total						$	2.45					$	53.21					$	25.92					$	3.77					$	0.30					$	0.96

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(a) Excludes the effect of hedging.

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Natural Gas, Oil and NGL Reserves

The tables below set forth information as of December 31, 2023, with respect to our estimated proved reserves, the associated estimated future net revenue, the present value of estimated future net revenue and the standardized measure of discounted future net cash flows. None of the estimated future net revenue, PV-10 nor the standardized measure are intended to represent the current market value of the estimated natural gas, oil and NGL reserves we own. All of our estimated reserves are located within the United States.

						December 31, 2023
						Natural Gas						Oil						NGL						Total
						(Bcf)						(MMBbl)						(MMBbl)						(Bcfe)
Proved developed						6,363						—						—						6,363
Proved undeveloped						3,325						—						—						3,325
Total proved(a)						9,688						—						—						9,688

						Proved Developed						Proved Undeveloped						Total Proved
Standardized measure(b)																		$	4,477
Estimated future net revenue(b)						$	6,194					$	2,360					$	8,554
Present value of estimated future net revenue (PV-10)(b)						$	3,728					$	843					$	4,571

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(a) Marcellus and Haynesville accounted for approximately 73% and 27%, respectively, of our estimated proved reserves by volume as of December 31, 2023.

(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, 2023, 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, 2023. The price used in our PV-10 measure was $2.64 per Mcf of natural gas, before basis differential adjustments. This price should not be interpreted as a prediction of future prices, nor does it reflect the value of our commodity derivative instruments in place as of December 31, 2023. 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 $94 million as of December 31, 2023.

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 natural gas and oil reserves.

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As of December 31, 2023, our proved reserve estimates included 3,325 Bcfe of reserves classified as proved undeveloped, compared to 4,321 Bcfe as of December 31, 2022. Presented below is a summary of changes in our proved undeveloped reserves for 2023:

						Total
						(Bcfe)
Proved undeveloped reserves, beginning of period						4,321
Extensions and discoveries						301
Revisions of previous estimates						236
Conversion to proved developed reserves						(1,125)
Purchase of reserves-in-place						40
Sales of reserves-in-place						(448)
Proved undeveloped reserves, end of period						3,325

As of December 31, 2023, all PUDs were planned to be developed within five years of original recording. In 2023, we invested approximately $674 million to convert 1,125 Bcfe of PUDs to proved developed reserves. We added 301 Bcfe of PUD reserves through extensions and discoveries primarily due to new PUDs added in the Upper Marcellus. We had a net upward revision in previous estimates of 236 Bcfe. The net upward revision primarily consisted of 1,345 Bcfe from PUDs added in areas previously categorized as proved in both Marcellus and Haynesville, and 469 Bcfe of positive revisions on existing PUD locations primarily related to longer expected lateral lengths in both Marcellus and Haynesville, partially offset by 1,131 Bcfe of downward revisions due to lower natural gas, oil and NGL prices in 2023, and a downward revision of 447 Bcfe due to development plan and other changes in Marcellus and Haynesville. We added 40 Bcfe of PUDs through purchase of reserves-in-place in Haynesville. We divested 448 Bcfe of PUD reserves primarily related to our Eagle Ford divestitures.

The future net revenue attributable to our estimated PUDs was $2.36 billion, and the present value was $843 million as of December 31, 2023. These values were calculated assuming that we will expend approximately $2.0 billion to develop these reserves ($649 million in 2024, $326 million in 2025, $463 million in 2026, $292 million in 2027 and $221 million in 2028). 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 commodity prices, unexpected developmental drilling results, title issues and infrastructure availability or constraints.

As of December 31, 2023, approximately 222 Bcfe, or 2%, of our total proved reserves 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, 2023, 2022 and 2021, 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 Natural Gas, Oil 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 natural gas and oil 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 natural gas, oil 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 Natural Gas,

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Oil and NGL Producing Activities included in Item 8 of Part II of this report for further discussion of our reserve quantities.

Reserves Estimation

We engaged Netherland, Sewell & Associates, Inc., a third-party engineering firm, to audit our total proved reserves as of December 31, 2023. A copy of the audit letter issued by the engineering firm is filed with this report as Exhibit 99.1. The qualifications of the technical persons at the firm primarily responsible for overseeing the audit of our reserve estimates are set forth below.

• Over 43 combined years of practical experience in the estimation and evaluation of reserves;

• Licensed Professional Engineer in the State of Texas and Bachelor of Science degree in Chemical Engineering/Engineering and Public Policy;

• Licensed Professional Geoscientist in the State of Texas and Bachelor of Science and Master of Science degrees in Geology.

Our Corporate Reserves Department prepared our estimated proved reserves as of December 31, 2023 disclosed in this report. Those estimates were established utilizing standard geological and engineering technologies, which are generally accepted by the petroleum industry and were based upon the best available production, engineering and geologic data. These technologies, including computational methods, provide reasonable certainty in our reserves estimation and include technologies and inputs such as drilling results and well performance, decline curve analysis of wells in analogous reservoirs, material balance, volumetric calculation, statistical analysis, well logs, geologic maps and seismic data.

Our Manager – SEC Reserves Engineering, who is in charge of our Corporate Reserves Department, 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. His qualifications include the following:

• Over 16 years of practical experience in the oil and gas industry, with over 14 years in reservoir engineering;

• Licensed Professional Engineer (Petroleum) in the State of Oklahoma;

• Member in good standing of the Society of Petroleum Evaluation Engineers;

• Bachelor of Science in Mechanical Engineering; and

• Master’s of Business Administration.

We ensure that the key members of our Corporate Reserves Department have appropriate technical qualifications to oversee the preparation of reserve estimates. 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 the Manager – SEC Reserves Engineering.

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

• Each quarter, Reservoir Managers, the Manager – SEC Reserves Engineering, the Senior Resource Manager, the Vice Presidents of each operating area and the Vice President of Corporate and Strategic Planning 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 Manager – SEC Reserves Engineering, the Senior Resource Manager, and the Vice President of Corporate and Strategic Planning.

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Acreage

The following table sets forth our gross and net developed and undeveloped natural gas and oil leasehold and fee mineral acreage as of December 31, 2023. 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.

						Developed Leasehold												Undeveloped Leasehold												Total
						Gross Acres						Net Acres						Gross Acres						Net Acres						Gross Acres						Net Acres
						(in thousands)
Marcellus						576						337						182						152						758						489
Haynesville						354						322						100						59						454						381
Other(a)						313						293						1,351						1,276						1,664						1,569
Total						1,243						952						1,633						1,487						2,876						2,439

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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 non-core divestitures to high-grade our lease inventory and letting some leases expire that are no longer part of our development plans. We do not anticipate any material lease expirations within the next three years.

Marketing

The principal function of our marketing operations is to provide natural gas, oil 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 natural gas and oil 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 natural gas and NGL production are sold to purchasers under index contracts, percentage-of-index contracts, spot price contracts or percentage-of-proceeds contracts. Under our index and percentage-of-index contracts, the price we receive is tied to published indices. Under the terms of our percentage-of-proceeds contracts, we receive a percentage of the resale price received from the ultimate purchaser. Oil production is sold under short-to-long-term market-sensitive and spot price contracts.

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 7 of the notes to our consolidated financial statements included in Item 8 of Part II of this report for further discussion of commitments.

As of December 31, 2023, we had delivery commitments for a total of approximately 3,100 Bcf over the next 10 years. These delivery commitments vary each year, and we expect to fulfill these commitments primarily with production from our proved developed reserves.

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Major Customers

For the 2023 Successor Period, sales to Valero Energy Corporation and Shell Energy North America accounted for approximately 17% and 10%, respectively, of total revenues (before the effects of hedging). For the 2022 Successor Period, sales to Shell Energy North America and Valero Energy Corporation accounted for approximately 13% and 10%, respectively, of total revenues (before the effects of hedging). For the 2021 Successor Period, sales to Valero Energy Corporation and Energy Transfer Crude Marketing accounted for approximately 14% and 11%, respectively, of total revenues (before the effects of hedging). For the 2021 Predecessor Period, sales to Valero Energy Corporation accounted for approximately 19% of total revenues (before the effects of hedging). No other purchasers accounted for more than 10% of our total revenues during the 2023 Successor Period, 2022 Successor Period, 2021 Successor Period or 2021 Predecessor Period.

Competition

We compete with both major integrated and other independent natural gas and oil 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 natural gas and oil 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. 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;

• 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;

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• 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 natural gas and oil 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.

In November 2021, the Environmental Protection Agency (the “EPA”) proposed new regulations to establish comprehensive standards of performance and emission guidelines for methane and volatile organic compound emissions from existing operations in the oil and gas sector, including the exploration and production, transmission, processing, and storage segments. The EPA issued a supplemental proposed rule in November 2022 to update, strengthen and expand its November 2021 proposed rule. In December 2023, the EPA issued the final rule, which imposes more stringent requirements on the natural gas and oil industry, requiring all well sites and compressor stations to be routinely monitored for leaks and eliminating or minimizing emissions from common pieces of equipment used in oil and gas operations, such as process controllers, pumps, and storage tanks. Further, in May 2023, the Department of Transportation’s Pipeline and Hazardous Materials Safety Administration (the “PHMSA”) issued a proposed rule that would require pipelines, underground natural gas storage facilities, and liquefied natural gas facilities to update leak detection and repair programs to require companies to use commercially available technologies to find and fix methane leaks from pipelines and other facilities. These rules and policy priorities may result in the development of additional regulations or changes to existing regulations, certain of which could negatively impact our financial position, results of operations and cash flows. President Biden has recommitted the United States to the Paris Agreement and, in April 2021, announced a goal of reducing the United States’ emissions by 50-52% below 2005 levels by 2030. Although the national commitments in the Paris Agreement create no binding requirements on individual companies or facilities, they do provide indications of the current administration’s policy direction and the types of legislative and regulatory requirements—such as the EPA’s final methane and volatile organic compound rule—that may be needed to achieve those commitments. In November 2021, the international community gathered again in Glasgow at the 26th Conference to the Parties on the UN Framework Convention on Climate Change (“COP26”), during which multiple announcements were made, including a call for parties to eliminate certain fossil fuel subsidies and pursue further action on non-carbon dioxide GHGs. While there were limited announcements at COP27, which took place in November 2022 in Sharm-El Sheik, with respect to the reduction of fossil fuel use, there were negotiations on emissions reduction targets and reduction of fossil fuel use amongst the international community. Relatedly, the United States and European Union jointly announced the launch of the “Global Methane Pledge,” which aims to cut global methane pollution at least 30% by 2030 relative to 2020 levels, including “all feasible reductions” in the energy sector. Such discussions continued at COP28 in Dubai, which resulted in an agreement among 200 nations to take more decisive climate action, including commitments to reduce reliance on fossil fuels.

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In January 2024, the Biden administration announced a temporary pause on the U.S. Department of Energy’s (“DOE”) review of pending applications for authorization to export LNG to non-Free Trade Agreement countries until the DOE updates its underlying analyses for such decisions using more current data to account for considerations like potential energy cost increases for consumers and manufacturers or the latest assessment of the impact of GHG emissions. The temporary pause is not expected to affect LNG exports that have already been authorized. While this pause may not directly impact our exploration, production, and development activities, it may affect the demand for our products, which could have a material adverse effect on our business and financial position and impact our future business strategy.

In addition, several states and geographic regions in the United States have also adopted legislation and regulations regarding climate change-related matters, and additional legislation or regulation by these states and regions, U.S. federal agencies, including the EPA, and/or international agreements to which the United States may become a party could result in increased compliance costs for us and our customers. 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 responsibility and costs of environmental protection and safety and health compliance fundamental parts of our business. To date, 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, as well as the increasing number of climate-related commitments by capital providers, 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. For example, in addition to existing regulations from the EPA and similar agencies, the SEC has issued proposed rules that would mandate extensive disclosure of climate-related risks and other information. Additionally, in August 2023, the EPA issued a proposed rule that would amend the Petroleum and Natural Gas Systems source category of the EPA’s Greenhouse Gas Reporting Program to include new requirements for certain types of methane release events and bring the EPA’s Greenhouse Gas Reporting Program’s requirements into alignment with the Methane Emissions and Waste Reduction Incentive Program. For more information, see Item 1A. Risk Factors - “We are subject to extensive governmental regulation, which can change and could adversely impact our business.” The SEC has also indicated plans to propose various other disclosure regulations, including regarding human capital and other ESG matters. 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 gas and oil wells, and the unitization or pooling of gas and oil properties. In the United States, some states allow the statutory 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 gas and oil 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 gas and oil 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 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 natural gas, oil and NGL that we are ultimately able to produce 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 U.S. 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 increased its review in recent years in evaluating and, in some cases, promulgating new rules and regulations regarding competitive lease bidding, venting and flaring, gas and oil measurement and royalty

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payment obligations for production from federal lands. On November 30, 2022, the BLM issued a proposed rule to reduce the release of methane from venting, flaring, and leaks during gas and oil production activities on Federal and Indian leases, exemplifying the Biden Administration’s increased focus on the climate change impacts of federal projects, which could result in further changes to the federal gas and oil leasing program in the future. Restrictions surrounding onshore drilling and restrictions on the ability to obtain required permits could have a material adverse impact on our operations.

Permitting activities 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 - Natural gas and oil operations are uncertain and involve substantial costs and risks.

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 natural gas and oil 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 natural gas and oil industry. Nevertheless, we are involved in title disputes from time to time that may result in litigation.

Operating Hazards and Insurance

The natural gas and oil 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 $300 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 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.

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Executive Officers

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

Domenic J. (“Nick”) Dell'Osso, Jr., 47, has served as President and Chief Executive Officer since October 2021. Prior to being named as CEO, Mr. Dell’Osso served as our 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. Mr. Dell’Osso graduated from Boston College in 1998 and from the University of Texas at Austin in 2003.

Mohit Singh, Executive Vice President and Chief Financial Officer

Mohit Singh, 47, has served as Executive Vice President and Chief Financial Officer since December 2021. Prior to joining Chesapeake, Mr. Singh served for six years on the executive leadership team at BPX Energy, the United States onshore subsidiary of BP (NYSE: BP). He most recently led the M&A, corporate land and reserves functions, having previously served as Head of Business Development and Exploration and as Senior Vice President – North Business Unit. Prior to joining BPX, Mr. Singh worked as an investment banker focused on oil and gas transactions for RBC Capital Markets and Goldman Sachs. A chemical engineer by training, he began his career at Shell Exploration & Production Company where he held business planning, reservoir engineering and research engineering roles of increasing importance. Mr. Singh earned a PhD in Chemical Engineering from the University of Houston, an MBA from the University of Texas and a BTech in Chemical Engineering from the Indian Institute of Technology.

Joshua J. Viets, Executive Vice President and Chief Operating Officer

Joshua J. (“Josh”) Viets, 45, has served as Executive Vice President and Chief Operating Officer since February 2022. Prior to joining Chesapeake, Mr. Viets worked for 20 years in operational positions of increasing importance at ConocoPhillips Company (NYSE: COP). He most recently served as Vice President, Delaware Basin and previously held leadership positions in operations, engineering, subsurface, and capital project across the ConocoPhillips portfolio. Mr. Viets earned a Bachelor of Science in Petroleum Engineering from Colorado School of Mines in 2001.

Benjamin E. Russ, Executive Vice President - General Counsel and Corporate Secretary

Benjamin E. (“Ben”) Russ, 49, has served as Executive Vice President – General Counsel and Corporate Secretary since June 2021. Prior to that time, he served as Associate General Counsel – Corporate from May 2014 to June 2021; Division Counsel/Senior Division Counsel managing day-to-day legal matters in the Barnett, East Texas and Louisiana from July 2010 to May 2014; and Attorney/Senior Attorney managing litigation in Louisiana from September 2008 to July 2010. Before joining Chesapeake, Mr. Russ worked at Gulfport Energy Corporation serving as Assistant General Counsel from 2005 to 2006 and General Counsel from 2006 to 2008. Prior to Gulfport, he was an associate at the McKinney & Stringer, P.C. Mr. Russ received a B.S. in Finance from Oklahoma State University in 1996 and a J.D. from Oklahoma City University in 2004.

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Human Capital Resources

One Team. One Chesapeake.

Our “One CHK” culture and company core values are aimed at promoting an inclusive, diverse and productive workplace. Working as One CHK defines Chesapeake’s culture and unites our team to achieve shared goals for the benefit of our stakeholders. It is a culture of accountability where innovation, collaboration and calculated risk-taking help us achieve sustainable operational success. We had approximately 1,000 employees as of December 31, 2023. None of our employees were covered by collective bargaining agreements, and our management works to maintain good relations with our employees.

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 Diversity, Equity and Inclusion

We are committed to inclusion and diversity. Building a diverse workforce and equitable and inclusive work culture is an important factor in contributing to Chesapeake’s sustainable success. 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. On February 9, 2021, we formed a board committee dedicated to ESG oversight, including our inclusion and diversity efforts. Two of the seven members of our Board of Directors are considered to come from underrepresented backgrounds, including one woman and one “underrepresented minority” (as defined in Nasdaq’s board diversity rule). Chesapeake cultivates a workplace in which diverse perspectives are welcomed and respected and where employees feel encouraged to discuss diversity and inclusion.

In 2022, we further advanced our DEI program by nominating an executive sponsor from the Company’s senior management team, along with our inaugural advisory board and council teams. Each of these branches of our DEI program take part in determining strategic priorities, advancing our culture and supporting internal activities that invite all employees to participate in achieving our DEI vision.

For all these reasons, we believe our DEI program helps contribute to our corporate culture and business performance. We also recognize the importance of these efforts being compliant with applicable laws. DEI efforts are part of our legal compliance considerations, and we are committed to not making employment decisions, including decisions regarding hiring, promotion, and compensation, on the basis of any legally protected characteristic, such as race or gender.

Stay Accident Free Everyday (S.A.F.E.)

Safety is more than a company metric. It is core to our commitment to leading a responsible energy future. We set and deliver robust safety standards, prioritizing the well-being of our employees and contractors. Our safety culture is championed by our Board of Directors and executive leadership team, owned by every employee and contractor and managed by our Health, Safety, Environmental and Regulatory (HSER) team. Maintaining a safe work environment and promoting safe behaviors is a commitment that each of our employees and contractors own together. We hold each other accountable to keeping our sites, our co-workers and our contractors safe.

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One program that reinforces this philosophy of personal responsibility is Stop Work Authority. Through Stop Work Authority, every employee and contractor has the right, responsibility and authority 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 and contractors regarding our Safe and Compliant Operations Policy, safety standards, and working to empower and equip 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.

Every year our HSER team provides targeted trainings based on safety performance analysis, job functions and location specific factors. Our training program includes a mix of in-person and virtual training, with greater emphasis on in-person instruction and includes all employees. Job-specific learning paths aim to exceed regulatory requirements and ensure employees are holistically prepared to execute their job functions safely and responsibly.

Chesapeake’s training philosophy values contractor training in the same manner as employees. We design contractor training to align as much as possible with employee training, encouraging synchronized knowledge sharing and understanding, critical to decreasing our cumulative incidents.

Ethical Business Conduct

Chesapeake works hard to maintain the confidence of our stakeholders. We earn this trust by striving to act 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 and discretionary contributions, flexible work hours, generous paid time off, including a well-being day, where each employee is encouraged to relax and recharge for a day once per calendar year and 12 company-paid holidays, 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, which connects employees with trained counselors and other support professionals.

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