Item 1. Business

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Item 1. Business

Unless the context otherwise requires, references to “Chesapeake,” the “Company,” “us,” “we” and “our” in this report are to Chesapeake Energy Corporation together with its subsidiaries. Our principal executive offices are located at 6100 North Western Avenue, Oklahoma City, Oklahoma 73118, and our main telephone number at that location is (405) 848-8000.


Our Business

We are an independent exploration and production company engaged in the acquisition, exploration and development of properties to produce oil, natural gas and NGL from underground reservoirs. We own a large and geographically diverse portfolio of onshore U.S. unconventional natural gas and liquids assets, including interests in approximately 8,200 gross oil and natural gas wells.

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.

On November 1, 2021, we completed our acquisition of Vine, an energy company focused on the development of natural gas properties in the over-pressured stacked Haynesville and Mid-Bossier shale plays in Northwest Louisiana. The Vine Acquisition strengthens Chesapeake’s competitive position, meaningfully increasing our Free Cash Flow outlook and deepening our inventory of premium natural gas locations, while preserving the strength of our balance sheet.

On January 24, 2022, we entered into a definitive agreement to acquire Chief and associated non-operated interests held by affiliates of Tug Hill, Inc. (“Tug Hill”), for $2.0 billion in cash and approximately 9.44 million common shares. Chief and Tug Hill hold producing assets and an inventory of premium drilling locations in the Marcellus Shale in Northeast Pennsylvania. The cash portion of the Chief Acquisition will be financed with cash on hand and the use of our Exit Credit Facility. The Chief Acquisition, which is subject to customary closing conditions, including certain regulatory approvals, is expected to close by the end of the first quarter of 2022.

On January 24, 2022, we entered into an agreement to sell our Powder River Basin assets in Wyoming to Continental Resources, Inc. for approximately $450 million in cash. The transaction, which is subject to certain customary closing conditions, is expected to close in the first quarter of 2022.

The completion of these transactions will clarify and strengthen our asset portfolio, concentrating on three operating areas and advancing our highest-return assets in the Marcellus and Haynesville gas basins.


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.

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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 sustainable Free Cash Flow from our oil and natural gas development and production activities. We continue to focus on improving margins through operating efficiencies and financial discipline and improving our Environmental, Social, and 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. Subsequent to our emergence from Chapter 11 bankruptcy, 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. We expect our maintenance capital program to yield in excess of annual production of 700 mboe 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 optimization initiatives.

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 eliminated routine flaring on all new wells completed in 2021, and plan to accomplish the same on all wells enterprise-wide by 2025. We reduced our methane loss rate to 0.08% and our GHG intensity to 5.0 as of December 31, 2021.

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 21, 2022, we have 11 mmbbls and 899 bcf of expected 2022 production, representing 58% and 68% of 2022 forecasted oil and natural gas production, hedged at prices of $44.30/bbl and $2.69/mcf, respectively, for swaps and $3.21/mcf to $4.26/mcf, respectively, for collars. Additionally, as of February 21, 2022, we have hedged 6 mmbbl and 467 bcf of expected 2023 oil and natural gas production at prices of $47.17/bbl and $2.69/mcf, respectively, for swaps and $65.00/bbl to $79.09/bbl and $3.03/mcf to $4.02/mcf, respectively, for collars. Metrics include hedges that are contingent upon the closing of the Chief Acquisition.


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.

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Eagle Ford - Eagle Ford Shale in South Texas.

Powder River Basin - Stacked pay in Wyoming (purchase and sale agreement to divest executed on January 24, 2022, and which, subject to the satisfaction or waiver of certain closing conditions, is expected to close in the first quarter of 2022).


Well Data

As of December 31, 2021, we held an interest in approximately 8,200 gross productive wells, including 6,500 wells in which we held a working interest and 1,700 wells in which we held an overriding or royalty interest. Of the 6,500 (4,100 net) wells in which we held a working interest, 3,000 (1,700 net) wells were classified as productive natural gas wells and 3,500 (2,400 net) wells were classified as productive oil wells. During 2021, excluding sold properties, we operated 5,700 gross wells and held a non-operating working interest in 800 gross wells. We also completed 126 gross (74 net) wells as operator and participated in another 13 gross (1 net) wells completed by other operators. We operate approximately 98% of our current daily production volumes.


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:


	2021				2020				2019
	Gross	%	Net	%	Gross	%	Net	%	Gross	%	Net	%
Development:
Productive	137	100	74	100	203	100	126	100	414	100	271	100
Dry	—	—	—	—	—	—	—	—	—	—	—	—
Total	137	100	74	100	203	100	126	100	414	100	271	100

Exploratory:
Productive	2	100	1	100	—	—	—	—	1	20	1	20
Dry	—	—	—	—	2	100	2	100	4	80	4	80
Total	2	100	1	100	2	100	2	100	5	100	5	100

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


	2021		2020		2019
	Gross Wells	Net Wells	Gross Wells	Net Wells	Gross Wells	Net Wells
Marcellus	83	34	79	33	44	22
Haynesville	40	31	21	19	22	16
Eagle Ford	12	7	86	65	233	164
Powder River Basin	4	3	12	9	75	57
Mid-Continent	—	—	5	—	40	12
Other	—	—	2	2	5	5
Total	139	75	205	128	419	276

As of December 31, 2021, 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:


	Successor		Predecessor
	Period from February 10, 2021 through December 31, 2021		Period from January 1, 2021 through February 9, 2021		Year Ended December 31, 2020		Year Ended December 31, 2019
Net Production:
Oil (mmbbl)	23		3		37		43
Natural gas (bcf)	727		80		685		728
NGL (mmbbl)	7		1		11		12
Oil equivalent (mmboe)	150		18		163		177

Average Sales Price of Production:
Oil ($ per bbl)	$	69.07	$	53.21	$	38.16	$	59.16
Natural gas ($ per mcf)	$	3.61	$	2.45	$	1.73	$	2.45
NGL ($ per bbl)	$	31.37	$	25.92	$	11.55	$	15.62
Oil equivalent ($ per boe)	$	29.19	$	22.63	$	16.84	$	25.57

Average Sales Price (including realized gains (losses) on derivatives):
Oil ($ per bbl)	$	49.06	$	46.85	$	56.74	$	60.00
Natural gas ($ per mcf)	$	2.62	$	2.52	$	1.97	$	2.60
NGL ($ per bbl)	$	31.42	$	25.55	$	11.55	$	15.62
Oil equivalent ($ per boe)	$	21.46	$	21.72	$	22.09	$	26.42

Expenses ($ per boe):
Production	$	1.97	$	1.80	$	2.29	$	2.94
Gathering, processing and transportation	$	5.17	$	5.78	$	6.64	$	6.13

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Oil, Natural Gas and NGL Reserves

The tables below set forth information as of December 31, 2021, 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, 2021
	Oil	Natural Gas	NGL	Total
	(mmbbl)	(bcf)	(mmbbl)	(mmboe)
Proved developed	166	4,246	62	935
Proved undeveloped	44	3,578	20	661
Total proved(a)	210	7,824	82	1,596


	Proved Developed		Proved Undeveloped		Total Proved
Estimated future net revenue(b)	$	14,502	$	8,776	$	23,278
Present value of estimated future net revenue (PV-10)(b)	$	8,654	$	5,057	$	13,711
Standardized measure(b)					$	12,287

(a) Haynesville, Marcellus, and Eagle Ford accounted for approximately 39%, 36%, and 23% respectively, of our estimated proved reserves by volume as of December 31, 2021.

(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, 2021, 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, 2021. The prices used in our PV-10 measure were $66.56 per bbl of oil and $3.60 per mcf 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, 2021. 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 $1.424 billion as of December 31, 2021.

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, 2021, our proved reserve estimates included 661 mmboe of reserves classified as proved undeveloped, compared to 60 mmboe as of December 31, 2020. Presented below is a summary of changes in our proved undeveloped reserves (“PUDs”) for 2021:


						Total
						(mmboe)
Proved undeveloped reserves, beginning of period (Predecessor)						60
Extensions and discoveries						321
Revisions of previous estimates						145
Conversion to proved developed reserves						(60)
Purchase of reserves-in-place						195
Proved undeveloped reserves, end of period (Successor)						661

As of December 31, 2021, all PUDs were planned to be developed within five years of original recording. In 2021, we invested approximately $97 million to convert 60 mmboe of PUDs to proved developed reserves. In 2022, we estimate that we will invest approximately $794 million for PUD conversion. We added 321 mmboe of proved undeveloped reserves through extensions and discoveries following our emergence from bankruptcy on February 9, 2021 and certainty regarding our ability to finance the development of our proved reserves over a five-year period. In addition, during 2021, we recorded an upward revision of 145 mmboe from previous estimates due to lateral length adjustments, performance and updates to our five-year development plan. We also added 195 mmboe of proved undeveloped reserves through purchase of reserves-in-place related to the Vine Acquisition.

The future net revenue attributable to our estimated PUDs was $8.776 billion and the present value was $5.057 billion as of December 31, 2021. These values were calculated assuming that we will expend approximately $2.7 billion to develop these reserves ($794 million in 2022, $814 million in 2023, $539 million in 2024, $378 million in 2025 and $217 million in 2026). The amount and timing of these expenditures will depend on a number of factors, including actual drilling results, service costs, commodity prices and the availability of capital. Our developmental drilling schedules are subject to revision and reprioritization throughout the year resulting from unknowable factors such as unexpected developmental drilling results, title issues and infrastructure availability or constraints.

Of our 1,596 mmboe of proved developed reserves as of December 31, 2021, approximately 20 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, 2021, 2020 and 2019, along with the changes in quantities and standardized measure of the reserves for each of the three years then ended, are shown in Supplemental Disclosures About Oil, Natural Gas and NGL Producing Activities included in Item 8 of Part II of this report. No estimates of proved reserves comparable to those included herein have been included in reports to any federal agency other than the SEC.

There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting future rates of production and timing of development expenditures, including many factors beyond our control. The reserve data represents only estimates. Reserve engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be measured exactly, and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. As a result, estimates made by different engineers often vary. Accordingly, reserve estimates often differ from the actual quantities of oil, natural gas and NGL that are ultimately recovered. Furthermore, the estimated future net revenue from proved reserves and the associated present value are based upon certain assumptions, including prices, future production levels and costs that may not prove correct. Future prices and costs may be materially higher or lower than the prices and costs as of the date of any estimate. See Supplemental Disclosures About Oil, Natural Gas and NGL Producing Activities included in Item 8 of Part II of this report for further discussion of our reserve quantities.

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Reserves Estimation

Our Corporate Reserves Department prepared approximately 9% by volume, and approximately 4% by value, of our estimated proved reserves as of December 31, 2021, 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 19 years of practical experience in the oil and gas industry, with over 16 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 reserve 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 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 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 91% by volume, and approximately 96% by value, of our estimated proved reserves as of December 31, 2021. 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, 2021. 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		Total
	Gross Acres	Net Acres	Gross Acres	Net Acres	Gross Acres	Net Acres
	(in thousands)
Marcellus	556	339	216	172	772	511
Haynesville	359	323	33	23	392	346
Eagle Ford	678	478	235	133	913	611
Powder River Basin	106	86	126	95	232	181
Other(a)	231	212	1,256	1,195	1,487	1,407
Total	1,930	1,438	1,866	1,618	3,796	3,056

(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. The acreage in the table above includes a total of 0.1 million net acres subject to expiration in the next three years.


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


Major Customers

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). For the 2020 and 2019 Predecessor Periods, sales to Valero Corporation constituted 17% and 12% of total revenues (before the effects of hedging). No other purchasers accounted for more than 10% of our total revenues during the 2021 Successor Period or 2021, 2020 or 2019 Predecessor Periods.


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;
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;

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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. In November 2021, the Biden Administration released “The Long-Term Strategy of the United States: Pathways to Net-Zero Greenhouse Gas Emissions by 2050,” which establishes a roadmap to net zero emissions in the United States by 2050 through, among other things, improving energy efficiency; decarbonizing energy sources via electricity, hydrogen, and sustainable biofuels; and reducing non-carbon dioxide GHG emissions, such as methane and nitrous oxide. These executive orders 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. In addition, the United States is one of almost 200 nations that, in December 2015, agreed to the Paris Agreement, an international climate change agreement in Paris, France that calls for countries to set their own GHG emissions targets and be transparent about the measures each country will take to achieve its GHG emissions targets. 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. 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. 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. 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 Environmental Protection Agency (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, manageable 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. 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 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 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

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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 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. 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. A federal district court judge in Louisiana issued a nationwide preliminary injunction on June 15, 2021, effectively preventing the Biden Administration from implementing the pause of new oil and natural gas leases on federal lands and waters and forcing the lease sale. On November 26, 2021, the U.S. Department of the Interior released its “Report On The Federal Oil And Gas Leasing Program,” which assessed the current state of oil and gas leasing on federal lands and proposed several reforms, including raising royalty rates and implementing stricter standards for entities seeking to purchase oil and gas leases. Recently, on January 27, 2022, a federal district court judge in Washington, DC vacated the results of the federal government’s Lease Sale 257, effectively canceling the sale, on the grounds that the federal government failed to consider foreign consumption of oil and natural gas from its greenhouse gas emissions analysis. These recent developments and the Biden Administration’s and certain federal courts’ focus on the climate change impacts of federal projects could result in significant changes to the federal oil and gas leasing program in the future. Restrictions surrounding onshore drilling, onshore federal lease availability, and restrictions on the ability to obtain required permits 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 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 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.

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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 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

Michael A. Wichterich, Executive Chairman and Director

Michael A. (“Mike”) Wichterich, 53, has served as Executive Chair of Chesapeake's Board of Directors since October 2021. He previously served as Chair of the Board of Directors since February 2021, and as the Company's Interim Chief Executive Officer from April 2021 to October 2021. Mr. Wichterich is Founder and Chief Executive Officer of Three Rivers Operating Company LLC, a private exploration and production company with a focus in the Permian Basin. Prior to founding Three Rivers Operating, Mr. Wichterich served as the Chief Financial Officer of Texas American Resources, New Braunfels Utilities and Mariner Energy. Additionally, Mr. Wichterich began his career with PricewaterhouseCoopers in its energy auditing practice. Mr. Wichterich also serves as a board member of Grizzly Energy. He earned a B.B.A. from the University of Texas.

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

Domenic J. (“Nick”) Dell'Osso, Jr., 45, 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.

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Mohit Singh, Executive Vice President and Chief Financial Officer

Mohit Singh, 44, was appointed Executive Vice President and Chief Financial Officer in December 2021. For the last six years, Mr. Singh has served 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.

Josh Viets, Executive Vice President and Chief Operating Officer

Josh Viets, 43, was appointed Executive Vice President and Chief Operating Officer in February 2022. For the last 20 years, Mr. Viets has worked 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, 47, was appointed Executive Vice President – General Counsel and Corporate Secretary in 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 promote 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 and collaboration help us achieve sustainable operational success. We had approximately 1,300 employees as of February 21, 2022.

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. 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 diverse, including one female and one “underrepresented minority” (as defined in Nasdaq’s newly proposed listing rule). Chesapeake cultivates a workplace in which diverse perspectives are welcomed and respected and where employees feel encouraged to discuss diversity and inclusion.

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 (achieved 0.08% in 2021); and
Reducing our GHG intensity to 5.5 by 2025 (achieved 5.0 in 2021).

Safety First Every Day

Safety is more than a company metric, it is core to our commitment to leading a responsible energy future. We set and deliver strict safety standards, prioritizing the well-being of our employees and partners. 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 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, contractors and suppliers regarding our 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 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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