Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of "large“large accelerated filer," "accelerated” “accelerated filer," "smaller” “smaller reporting company,"” and "emerging“emerging growth company"company” in Rule 12b-2 of the Exchange Act.

The aggregate market value of Common Stock, par value $.10 per share ("(“Common Stock"Stock”), held by non-affiliates as of the last business day of registrant's most recently completed second fiscal quarter (based upon the closing sales price on the New York Stock Exchange on June 30, 2020)2021) was approximately $6.7$6.9 billion.

As of February 22, 2021,24, 2022, there were 399,419,748813,757,948 shares of Common Stock outstanding.

TheThis report includes forward-looking statements within the meaning of federal securities laws. All statements, other than statements of historical fact, included in this report are forward-looking statements. Such forward-looking statements include, but are not limited to, statements regarding future financial and operating performance and results, the anticipated effects of, and certain other matters related to, the merger involving Cimarex Energy Co. (“Cimarex”), strategic pursuits and goals, market prices, future hedging and risk management activities, and other statements that are not historical facts contained in this report are forward-looking statements.report. The words "expect," "project," "estimate," "believe," "anticipate," "intend," "budget," "plan," "forecast," "target," "predict," "may," "should," "could," "will"“expect,” “project,” “estimate,” “believe,” “anticipate,” “intend,” “budget,” “plan,” “forecast,” “target,” “predict,” “potential,” “possible,” “may,” “should,” “could,” “would,” “will,” “strategy,” “outlook” and similar expressions are also intended to identify forward-looking statements. SuchWe can provide no assurance that the forward-looking statements contained in this report will occur as expected, and actual results may differ materially from those included in this report. Forward-looking statements are based on current expectations and assumptions that involve a number of risks and uncertainties including, but not limitedthat could cause actual results to differ materially from those included in this report. These risks and uncertainties include, without limitation, the continuing effects of the COVID-19coronavirus (“COVID-19”) pandemic and the impact thereof on our business, financial condition and results of operations and the economy as a whole, the risk that our and Cimarex’s businesses will not be integrated successfully, the risk that the cost savings and any other synergies from the merger involving Cimarex may not be fully realized or may take longer to realize than expected, the availability of cash on hand and other sources of liquidity to fund our capital expenditures, actions by, or disputes among or between, members of the Organization of Petroleum Exporting Countries and other exporting nations, (OPEC+), market factors, market prices (including geographic basis differentials) of oil and natural gas, results of future drilling and marketing activity, future production and costs, legislative and regulatory initiatives, electronic, cyber or physical security breaches and other factors detailed herein and in our other Securities and Exchange Commission (“SEC”) filings. Refer toAdditional important risks, uncertainties and other factors are described in “Risk Factors” in Part I. Item 1A of this report. Forward-looking statements are based on the estimates and opinions of management at the time the statements are made. Except to the extent required by applicable law, we undertake no obligation to update or revise any forward-looking statement, whether as a result of new information, future events or otherwise. You are cautioned not to place undue reliance on these forward-looking statements, which speak only as of the date hereof.

The following are abbreviations and definitions of certain terms commonly used in the oil and gas industry and included within this Annual Report on Form 10-K:

Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the twelve-month12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based uponon future conditions.

Cabot Oil & Gas CorporationCoterra Energy Inc. (“Coterra,” “our,” “we” and “us”) is an independent oil and gas company engaged in the development, exploitation, exploration and production of oil, natural gas and gas properties.NGLs. Our assets are concentrated in areas with known hydrocarbon resources, which are conducive to multi-well, repeatable drillingdevelopment programs. We operate in one segment, oil and natural gas development, exploitation, exploration and production, in the continental United States. We have officesU.S.

Our headquarters is located in Houston, Texas. We also maintain regional offices in Pittsburgh, Pennsylvania, Midland, Texas and Pittsburgh, Pennsylvania.Tulsa, Oklahoma.

Our 20212022 capital program is expected to be approximately $530.0$1,400 million to $540.0$1,500 million, representing a six percent reduction, at the midpoint of the range, from our 2020 capital program of $569.8 million. We reduced our planned capital expenditures, which contemplates a maintenance capital program, as a result of the weaker natural gas price environment.$1,225 million to $1,325 million is allocated to drilling and completion activities. We expect to fund these expenditures withturn-in-line 134 to 153 total net wells in 2022 across our three operating cash flowregions. Approximately 49 percent of drilling and if required, cash on hand.

Our operations are primarily concentrated in one unconventional play—three operating areas—the Marcellus Shale in northeast Pennsylvania. Pennsylvania, the Permian Basin in west Texas and southeast New Mexico and the Anadarko Basin in the Mid-Continent region in Oklahoma.

Our Marcellus Shale properties represent our primary operating area and are principally located in Susquehanna County, Pennsylvania, where we currently hold approximately 175,000177,000 net acres in the dry gas window ofin the play.Marcellus Shale. Our 20202021 net production in the Marcellus Shale was 857 Bcfe,389 MBOEPD, representing substantially all85 percent of our total equivalent production for the year. As of December 31, 2020,2021, we had a total of 865.9954.0 net wells in the Marcellus Shale, of which approximately 99.599 percent are operated by us.

During 2020,2021, we invested $562.1$594 million in the Marcellus Shale and drilled or participated in drilling 64.3 net wells, completed 77.3 net wells and turned in line 69.2 net wells. As of December 31, 2020,where we had 13.0 net wells that were either in the completion stage or waiting on completion or connection to a pipeline. We exited 20202021 with threetwo drilling rigs operating in the play and plan to exit 20212022 with two rigs operating.

In July 2018, we sold certain proved and unproved oil and gasOur Permian Basin properties are principally located in the Haynesville Shale to a third party for $30.0 million and recognized a gain on salewestern half of oil and gas properties of $29.7 million.

During 2021, we invested $147 million in the fourth quarterPermian Basin, which represents the amount invested in the basin subsequent to the completion of 2017, we recorded an impairment chargethe Merger. We exited 2021 with six drilling rigs operating in the play and plan to exit 2022 with six rigs operating.

Our Anadarko Basin properties and upon closing recognized a loss on sale of oil and gas properties of $45.4 million.

Ancillary to our exploration, development and production operations, we operate a number of natural gas and saltwater disposal gathering systems. The majority of our gathering infrastructure is located in Texas and directly supports our Permian Basin operations. Our gathering systems enable us to connect new wells quickly and to transport natural gas from the wellhead directly to interstate pipelines, natural gas processing facilities and produced water disposal facilities. Control of our gathering pipeline systems also enables us to transport natural gas produced by third quarterparties. In addition, we can engage in development drilling without relying on third parties to transport our natural gas or produced water and incur only the incremental costs of 2017, we recognized a loss on sale of oilpipeline and gas properties of $11.9 million.

Substantially all of our oil and natural gas production is sold at market sensitive prices under both long-term and short-term sales contracts and is subject to seasonal price swings. The principal markets for ourcontracts. We sell oil, natural gas are in the northeastern United States where we sell natural gasand NGLs to a broad portfolio of customers, including industrial customers, local distribution companies, oil and gas marketers, major energy companies, pipeline companies and power generation facilities.

We also incur transportation and gathering expenses to move our oil and natural gas production from the wellhead to our principal markets in the United States.U.S. The majority of our Marcellus and Anadarko Basin natural gas production is transportedgathered on third-party gathering systems, while the majority of our Permian Basin natural gas production is gathered on company-owned and operated gathering systems. Most of our natural gas is transported on interstate pipelines where we have long-term contractual capacity arrangements or use purchaser-owned capacity under both long-term and short-term sales contracts.

We have entered into various firm sales contracts to deliver and sell natural gas. We believe we will have sufficient production quantities to meet substantially all of our commitments, but may be required to purchase natural gas from third parties to satisfy shortfalls should they occur.

We utilize a part of our firm transportation capacity to deliver natural gas under the majority of these firm sales contracts and have entered into numerous agreements for transportation of our production. Some of these contracts have volumetric requirements which could require monetary shortfall penalties if our production is inadequate to meet the terms. However, we do not believe we will have aany financial commitment due based on our current proved reserves and production levels from which we can fulfill these obligations.

From time to time, we use derivative financial instruments to manage price risk associated with our oil and natural gas production. WhileAlthough there are many different types of derivatives available, we generally utilize collar, swap, roll differential swaps and basis swap agreements designed to manageassist us in managing price risk more effectively.risk. The collar arrangements are a combination of put and call options used to establish floor and ceiling prices for a fixed volume of natural gas production during a certain time period. They provide for payments to counterparties if the index price exceeds the ceiling and payments from the counterparties if the index price falls below the floor. The swap agreements call for payments to, or receipts from, counterparties based on whether the index price for the period is greater or less than the fixed price established for the particular period under the swap agreement.

During 2020,2021, oil collars with floor prices ranging from $29.00 to $40.00 per Bbl and ceiling prices ranging from $34.15 to $51.10 per Bbl covered 3.7 Mmbbls, or 45 percent, of oil production at a weighted-average price of $44.37 per Bbl. Oil basis swaps covered 3.2 Mmbbls, or 40 percent, of oil production at a weighted-average price of $(0.08) per Bbl. Oil roll differential swaps covered 1.6 Mmbbls, or 20 percent, of oil production at a weighted-average price of $(0.10) per Bbl.

During 2021, natural gas collars with floor prices ranging from $1.90$1.50 to $2.15$2.85 per Mmbtu and ceiling prices ranging from $2.10$1.75 to $2.38$3.94 per Mmbtu covered 92.3193.2 Bcf, or 1121 percent, of natural gas production at a weighted-average price of $2.09$2.85 per Mmbtu. Natural gas swaps covered 53.556.3 Bcf, or six percent, of natural gas production at a weighted-average price of $2.24$3.16 per Mmbtu.

As of December 31, 2020,2021, we had the following outstanding financial commodity derivatives:

A significant portion of our expected oil and natural gas production for 20212022 and beyond is currently unhedged and directly exposed to the volatility in oil and natural gas prices, whether favorable or unfavorable. We will continue to evaluate the benefit of using derivatives in the future. Please read "Management's“Management's Discussion and Analysis of Financial Condition and Results of Operations"Operations” and "Quantitative“Quantitative and Qualitative Disclosures about Market Risk"Risk” for further discussion related to our use of derivatives.

Our proved reserves at December 31, 20202021 increased 769 Bcfe614 MMBOE, or six27 percent, from 12,903 Bcfe2,279 MMBOE at December 31, 2019. In 2020, primarily due to the Merger, which increased our proved reserves by 672 MMBOE. During 2021, we added 1,974 Bcfe171 MMBOE of proved reserves through extensions, discoveries and other additions, primarily due to the results from our drilling and completion program in the Dimock field in northeast Pennsylvania. We also had a net downward revision of 347 Bcfe,62 MMBOE, which was primarily due to a net downward performance revision of 245 Bcfe and a downward revision of 66 Bcfe associated with proved undeveloped (PUD) reserves reclassifications as a result of the five-year limitation. The net downward performance revision of 245 Bcfe was primarily due to a downward performance revision of 368 Bcfe related to certain proved developed producing properties,97 MMBOE, partially offset by an upward pricing revision of 123 Bcfe associated with our PUD reserves due to performance revisions and the drilling of longer lateral length wells.34 MMBOE. During 2020,2021, we produced 858 Bcfe.167 MMBOE.

Since substantially allAt December 31, 2021, our Dimock field, which is located in the Marcellus Shale in Susquehanna County, Pennsylvania, contained approximately 75 percent of our total proved reserves.

Our reserves are natural gas, our reserves are significantly more sensitive to natural gascommodity prices and their effect on the economic productive life of producing properties. Our reserves are based on the 12-month average index price for the respective commodity, calculated as the unweighted arithmetic average for the first day of the month price for each month during the year. Increases in commodity prices may result in a longer economic productive life of a property or result in more economically viable proved undeveloped reserves to be recognized. Decreases in prices may result in negative impacts of this nature.

For additional information regarding estimates of proved reserves, the auditaudits of such estimates by Miller and Lents, Ltd. (Miller(“Miller and Lents)Lents”) and DeGolyer and MacNaughton and other information about our reserves, including the risks inherent in our estimates of proved reserves, refer to the Supplemental Oil and Gas Information to the Consolidated Financial Statements included in Item 8 and “Risk Factors—Business and Operational Risks—Our proved reserves are estimates. Any material inaccuracies in our reserve estimates or underlying assumptions could cause the quantities and net present value of our reserves to be overstated or understated” in Item 1A.

We utilize various traditional methods to estimate our reserves, including decline curve extrapolations, material balance calculations, volumetric calculations, analogies and in some cases a combination of these methods. In addition, at times we may use seismic interpretations to confirm continuity of a formation in combination with traditional technologies; however, seismic interpretations are not used in the volumetric computation.

Our Senior Vice President, EHSProduction and EngineeringOperations is the technical person responsible for our internal reserves estimation process and provides oversight of our corporate reservoir engineering department, which consists of two engineers, and the annual audit of our year-end reserves by Miller and Lents.10 engineers. He has a Bachelor of Science degree in Chemical Engineering, specializing in petroleum engineering, and over 3839 years of industry experience with positions of increasing responsibility in operations, engineering and evaluations. He has worked in the area of reserves and reservoir engineering for 2930 years and is a member of the Society of Petroleum Engineers.

Our reserves estimation process is coordinated by our corporate reservoir engineering department. Reserve information, including models and other technical data, are stored on secured databases on our network. Certain non-technical inputs used in the reserves estimation process, including commodity prices, production and development costs and ownership percentages, are obtained by other departments and are subject to testing as part of our annual internal control process. We also engage Miller and Lents and DeGolyer and MacNaughton, independent petroleum engineers, to perform an independent auditaudits of our estimated proved reserves. Upon completion of the process, the estimated reserves are presented to senior management.management and the Board of Directors.

Miller and Lents has audited 100 percent of our proved reserves estimates related to our Marcellus Shale properties, and DeGolyer and MacNaughton has performed an independent evaluation of estimated net reserves representing greater than 80 percent of the total future net revenue discounted at 10 percent attributable to our proved reserves estimates related to our Permian Basin, Anadarko Basin and other properties (excluding our Marcellus Shale properties). Each of Miller and Lents and DeGolyer and MacNaughton concluded, in theirits judgment, we have an effective system for gathering data and documenting information required to estimate our proved reserves and project our future revenues. Further, Miller and Lents has concluded (1) the reserves estimation methods employed by us were appropriate, and our classification of such reserves was appropriate to the relevant SEC reserve definitions, (2) our reserves estimation processes were comprehensive and of sufficient quality, (3) the data upon which we relied were adequate and of sufficient quality, and (4) the results of our estimates and projections are, in the aggregate, reasonable. A copy

Copies of the audit letterletters by Miller and Lents dated January 27, 2021, has31, 2022 and DeGolyer and MacNaughton dated January 17, 2022 have been filed as an exhibitexhibits to this Annual Report on Form 10-K.

The technical person primarily responsible for the audit of our reserves estimates at Miller and Lents meets the requirements regarding qualifications, independence, objectivity and confidentiality set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers. Miller and Lents is an independent firm of petroleum engineers, geologists, geophysicists and petro physicists; they do not own an interest in our properties and are not retained on a contingent fee basis.

At December 31, 2020,2021, we had 5,064 Bcfe of PUD reserves associated with future development costs of $1.4$2.1 billion associated with 764 MMBOE of PUD reserves, which represents an increasea decrease of 217 Bcfe80 MMBOE compared to December 31, 2019. All2020. By the end of our PUD reserves are located in Susquehanna County, Pennsylvania. We2022, we expect to complete substantially all ofthe work necessary to convert our PUD reserves associated with wells that were drilled but uncompleted wells by the end of 2021.at December 31, 2021 to proved developed reserves. Future development plans are reflective of the lowercurrent commodity price environment and have been established based on expected available cash flows from operations and availability under our revolving credit facility.operations. As of December 31, 2020,2021, all PUD reserves are expected to be drilled and completed within five years of initial disclosure of these reserves.

Changes in PUD reserves that occurred during the year were due to:

The following table presents historical information about our total and average daily production volumes for oil, natural gas and NGLs; average oil, (including NGLs), average natural gas and crude oilNGL sales prices,prices; and average production costs per equivalent. Substantially all of our total company historical operational information and proved reserves are derived from our Dimock field in northeast Pennsylvania:equivalent:

Our interest in both developed and undeveloped properties is primarily in the form of leasehold interests held under customary mineral leases. These leases provide us the right to develop oil and/or natural gas on the properties. Their primary

The table below summarizes by year and operating area our undeveloped acreage expirations in the next three years. In most cases, the event that production is not established ordrilling of a commercial well will hold the acreage beyond the expiration.

At December 31, 2021, we takehad no action to extend or renew the terms of our leases, our netproved undeveloped reserves recorded on undeveloped acreage that will expire overwere scheduled for development beyond the next three years asexpiration dates of December 31, 2020 is 13,515, 3,947 and 4,371 for the years ending December 31, 2021, 2022 and 2023, respectively.

We drilled and completed wells or participated in the drilling and completion of wells as indicated in the table below. During the years presented below, we did not drill and complete any exploration wells. The information below should not be considered indicative of future performance, nor should a correlation be assumed between the number of productive wells drilled, quantities of reserves found or economic value.

The following table sets forth information about wells for which drilling was in progress or which were drilled but uncompleted at December 31, 2020,2021, which are not included in the above table:

We believe that we have satisfactory title to all of our producing properties in accordance with generally accepted industry standards. Individual properties may be subject to burdens such as royalty, overriding royalty, carried, net profits, working and other outstanding interests customary in the industry. In addition, interests may be subject to obligations or duties under applicable laws or burdens such as production payments, ordinary course liens incidental to operating agreements and for current taxes or development obligations under oil and gas leases. As is customary in the industry in the case of undeveloped properties, we conduct preliminary investigations of record title are made at the time of lease acquisition. CompleteWe conduct more complete investigations are made prior to the consummation of an acquisition of producing properties and before commencement of drilling operations on undeveloped properties.

The oil and gas industry is highly competitive, and we experience strong competition in our primary producing areas. We primarily compete with integrated, independent and other energy companies for the sale and transportation of our oil and

Price, contract terms, availability of rigs and related equipment and quality of service, including pipeline connection times and distribution efficiencies affect competition. We believe that our concentrated acreage positionpositions and our access to both third-party and company-owned gathering and pipeline infrastructure in Pennsylvania,our primary operating areas, along with our expected activity level and the related services and equipment that we have secured for the upcoming years, enhance our competitive position over other producers who do not have similar systems or services in place.

During the year ended December 31, 2021, no customer accounted for more than 10 percent of our total sales. During the year ended December 31, 2020, three customers accounted for approximately 21 percent, 16 percent and 12 percent of our total sales. During the year ended December 31, 2019, three customers accounted for approximately 17 percent, 16 percent and 16 percentIf any one of our total sales. Duringmajor customers were to stop purchasing our production, we believe there are a number of other purchasers to whom we could sell our production. If multiple significant customers were to stop purchasing our production, we believe there could be some initial challenges, but we have ample alternative markets to handle any sales disruptions.

We regularly monitor the year ended December 31, 2018, two customers accounted for approximately 20 percent and 11 percentcreditworthiness of our total sales. We docustomers and may require parent company guarantees, letters of credit or prepayments when necessary. Historically, losses associated with uncollectible receivables have not believe that the loss of any of these customers would have a material adverse effect on us because alternative customers are readily available.

Exploration and production operations are subject to various types of regulation at the federal, state and local levels. This regulation includes requiring permits to drill wells, maintaining bonding requirements to drill or operate wells, and regulating the location of wells, the method of drilling and casing wells, the surface use and restoration of properties on which wells are drilled and the plugging and abandoning of wells. Our operations are also subject to various conservation laws and regulations. These include the regulation of the size of drilling and spacing units or proration units, the density of wells that may be drilled in a given field and the unitization or pooling of oil and natural gas properties. Some states allow the forced pooling or integration of tracts to facilitate exploration while other states rely on voluntary pooling of lands and leases. In addition, state conservation laws establish maximum rates of production from oil and natural gas wells, generally prohibiting the venting or flaring of natural gas and imposing certain requirements regarding the ratability of production. The effect of these regulations is

Federal legislation and regulatory controls have historically affected the price of the natural gas we produce and the manner in which our production is transported and marketed. Under the U.S. Natural Gas Act of 1938 (NGA)(the “NGA”), the U.S. Natural Gas Policy Act of 1978 (NGPA),(the “NGPA”) and the regulations promulgated under those statutes, the U.S. Federal Energy Regulatory Commission (FERC)(the “FERC”) regulates the interstate sale for resale of natural gas and the transportation of natural gas in interstate commerce, although facilities used in the production or gathering of natural gas in interstate commerce are generally exempted from FERC jurisdiction. Effective beginning in January 1993, the Natural Gas Wellhead Decontrol Act deregulated natural gas prices for all “first sales” of natural gas, which definition covers all sales of our own production. In addition, as part of the broad industry restructuring initiatives described below, the FERC granted to all producers such as us a “blanket certificate of public convenience and necessity” authorizing the sale of natural gas for resale without further FERC approvals. As a result of this policy, all of our produced natural gas is sold at market prices, subject to the terms of any private contracts that may be in effect. In addition, under the provisions of the Energy Policy Act of 2005 (2005 Act)(“2005 Act”), the NGA was amended to prohibit any forms of market manipulation in connection with the purchase or sale of natural gas. Pursuant to the 2005 Act, the FERC established regulations intended to increase natural gas pricing transparency by, among other things, requiring market participants to report their gas sales transactions annually to the FERC. The 2005 Act also significantly increased the penalties for violations of the NGA and NGPA and the FERC’s regulations thereunder up to $1.0$1 million per day per violation. This maximum penalty authority established by statute has been and will continue to be adjusted periodically for inflation. The current maximum penalty is over $1.3$1 million per day per violation. In 2010, the FERC issued Penalty Guidelines for the determination of civil penalties and procedure under its enforcement program.

Our natural gas sales prices nevertheless continue to be affected by intrastate and interstate gas transportation regulation because the cost of transporting the natural gas once sold to the consuming market is a factor in the prices we receive. Beginning with Order No. 436 in 1985 and continuing through Order No. 636 in 1992 and Order No. 637 in 2000, the FERC has adopted a series of rule makings that have significantly altered the transportation and marketing of natural gas. These changes were intended by the FERC to foster competition by, among other things, requiring interstate pipeline companies to separate their wholesale gas marketing business from their gas transportation business and by increasing the transparency of pricing for pipeline services. The FERC has also established regulations governing the relationship of pipelines with their marketing affiliates, which essentially require that designated employees function independently of each other and that certain information not be shared. The FERC has also implemented standards relating to the use of electronic data exchange by the pipelines to make transportation information available on a timely basis and to enable transactions to occur on a purely electronic basis.

In light of these statutory and regulatory changes, most pipelines have divested their natural gas sales functions to marketing affiliates, which operate separately from the transporter and in direct competition with all other merchants. Most pipelines have also implemented the large‑scale divestiture of their natural gas gathering facilities to affiliated or non-affiliated companies. Interstate pipelines are required to provide unbundled, open and nondiscriminatory transportation and transportation‑related services to producers, gas marketing companies, local distribution companies, industrial end users and other customers seeking such services. As a result of the FERC requiring natural gas pipeline companies to separate marketing and transportation services, sellers and buyers of natural gas have gained direct access to pipeline transportation services, and are better able to conduct business with a larger number of counterparties. We believe these changes generally have improved our access to markets while, at the same time, substantially increasing competition in the natural gas marketplace. We cannot predict what new or different regulations the FERC and other regulatory agencies may adopt, or what effect subsequent regulations may have on our activities. Similarly, we cannot predict what proposals, if any, that affect the oil and natural gas industry might actually be enacted by the U.S. Congress or the various state legislatures and what effect, if any, such proposals might have on us. Further, we cannot predict whether the recent trend toward federal deregulation of the natural gas industry will continue or what effect future policies will have on our sale of gas.

We use derivative financial instruments such as collar, swap, roll differential swap and basis swap agreements to attempt to more effectively manage price risk due to the impact of changes in commodity prices on our operating results and cash flows. Following enactment of the Dodd‑Frank Wall Street Reform and Consumer Protection Act (Dodd‑(“Dodd‑Frank Act)Act”) in July 2010, the Commodity Futures Trading Commission (CFTC)(the “CFTC”) has promulgated regulations to implement statutory requirements for swap

Sales of crude oil and NGLs are not regulated and are made at market prices. However, the price received from the sale of these products is affected by the cost of transporting the products to market. Much of that transportation is through interstate common carrier pipelines, which are regulated by the FERC under the Interstate Commerce Act (ICA)(“ICA”). The FERC requires that pipelines regulated under the ICA file tariffs setting forth the rates and terms and conditions of service and that such service not be unduly discriminatory or preferential.

Effective January 1, 1995, the FERC implemented regulations generally grandfathering all previously approved interstate transportation rates and establishing an indexing system for those rates by which adjustments are made annually based on the rate of inflation, subject to certain conditions and limitations. These regulations may increase or decrease the cost of transporting crude oil and NGLs by interstate pipeline, although the annual adjustments may result in decreased rates in a given year. Every five years, the FERC must examine the relationship between the annual change in the applicable index and the

U.S. laws and regulations applicable to our operations include those controlling the discharge of materialsregulating emissions into the environment, requiringatmosphere, discharges of pollutants into waters, underground injection of wastewater, the generation, storage, transportation and disposal of waste materials and removal and cleanup of materials that may harm the environment, and those regulating the emission of air contaminants and laws and regulations otherwise relating to the protection of the environment, or to occupational health and safety.

We generate some hazardous wastes that are hazardous wastes subject to the FederalU.S. federal Resource Conservation and Recovery Act (RCRA)(the “RCRA”) and comparable state statutes, as well as wastes that are exempt from such regulation. The U.S. Environmental Protection Agency (EPA) has limited(the “EPA”) limits the disposal options for certain hazardous wastes. It is possible that certain wastes currently exempt from treatmentregulation as hazardous wastes may in the future be designated as hazardous wastes under RCRA or other applicable statutes. For example, in December 2016, the EPA and environmental groups entered into a consent decree to address the EPA’s alleged failure to timely assess the need to regulate exploration and production related oil and gas wastes exempt from regulation as hazardous wastes under RCRA under Subtitle D applicable to non-hazardous solid waste. The consent decree required the EPA to propose a rulemaking by March 2019 for revision of certain Subtitle D criteria regulations pertaining to oil and gas wastes or to sign a determination that revision of the regulations is not necessary. In April 2019, the EPA issued its determination that based on its review, including consideration of state regulatory programs, it was not necessary at the time to revise Subtitle D regulations to address the management of oil and gas wastes. In the future, we could be subject to more rigorous and costly disposal requirements than we encounter today.

On April 10, 2014, the FWS published a rule listing, as a threatened species under the ESA, the lesser prairie chicken, whose habitat is over a five-state region, including Texas, New Mexico and Oklahoma, where we conduct a substantial amount of our operationsoperations. Although the 2014 listing rule was vacated in July 2016, on June 1, 2021, the FWS proposed to list two distinct population segments (“DPS”) of the lesser prairie chicken under the ESA. The Southern DPS, located in eastern New Mexico and the southwest Texas panhandle was proposed to be listed as endangered and the Northern DPS, located in southeastern Colorado, southcentral to southwestern Kansas, western Oklahoma and the northeast Texas panhandle, was proposed to be listed as threatened. Listing of the lesser prairie chicken as a threatened or endangered species will impose restrictions on disturbances to critical habitat by landowners and drilling companies that would harass, harm or otherwise result in a “taking” of this species. Regulatory impacts on landowners and businesses from an ultimate decision to list the lesser prairie chicken could be limited for those landowners and businesses who have entered into certain range-wide conservation planning agreements, such as those developed by the Western Association of Fish and Wildlife Agencies (“WAFWA”), pursuant to which such parties agreed to take steps to protect the lesser prairie chicken’s habitat and to pay a mitigation fee if its actions harm the lesser prairie chicken’s habitat. We have entered into a voluntary Candidate Conservation Agreement (a “CCA”) with the WAFWA, whereby we agreed to take certain actions and limit certain activities, such as limiting drilling on certain portions of our acreage during nesting seasons, in an effort to protect the lesser prairie chicken.

Participating in CCAs could result in increased costs to us from species protection measures, time delays or limitations on drilling activities, which costs, delays or limitations may be located in areas that are designated as habitats for endangered or threatened species, we believe that we are in substantial compliancesignificant. Listing petitions continue to be filed with the ESA, nor are we aware of any proposed listings that will affectFWS which could impact our operations. However,Many non-governmental organizations (“NGOs”) work closely with the designationFWS regarding the listing of previously unidentifiedmany species, including species with broad and even nationwide ranges. The listing of the Mexican Long Nosed Bat, whose habitat includes the Permian Basin where we operate, and the Dunes Sagebrush Lizard in the Permian Basin, are examples of the NGOs’ influence on ESA listing decisions.

On December 1, 2020, the FWS proposed to list the Peppered Chub as endangered under the ESA. The Peppered Chub is a freshwater fish that historically was found in the South Canadian, Cimarron and Arkansas rivers within New Mexico, Texas,

Some of our producing wells and associated facilities are subject to restrictive air emission limitations and permitting requirements. Two examples are the EPA’s source aggregation rule and the EPA’s New Source Performance Standards (NSPS)(“NSPS”) and National Emission Standards for Hazardous Air Pollutants (NESHAP)(“NESHAP”). In June 2016, the EPA published a final rule concerning aggregation of sources that affects source determinations for air permitting in the oil and gas industry, and, as a result, aggregating our oil and gas facilities for permitting couldmay result in more complex, costly,increased complexity and time-consumingcost of, and time required for, air permitting. Particularly with respect to obtaining pre-construction permits, the final aggregation rule could add costs and cause delays in operations.

In 2012, the EPA published final NSPS and NESHAP that amended the existing NSPS and NESHAP for the oil and natural gas sector. In June 2016, the EPA published a final rule that updated and expanded the NSPS by setting additional emissions limits for volatile organic compounds and regulating methane emissions for new and modified sources in the oil and gas industry. In June 2017, the EPA proposed a two yeartwo-year stay of certain requirements contained in the June 2016 rule and, in November 2017, issued a notice of data availability in support of the stay proposal and provided a 30-day comment period on the information provided. In March 2018, the EPA published a final rule that amended two narrow provisions of the NSPS, removing the requirement for completion of delayed repair during emergency or unscheduled vent blowdowns. In September 2020, the EPA published a final rule amending the 2012 and 2016 NSPS for the oil and natural gas sector that removed transmission and storage sources from the oil and natural gas industry source category and rescinded the methane requirements applicable to the production and processing sources. The same day asOn June 30, 2021, President Biden signed into law a joint Congressional resolution under the publication ofCongressional Review Act disapproving the September 2020 rule 20 states and three municipalities filed a petition for review ofamending the EPA’s final rule in the D.C. Circuit Court of Appeals. In October 2020, the D.C. Circuit Court of Appeals denied emergency motions2012 and 2016 NSPS standards for a stay of the oil and natural gas sector NSPS amendmentssector. On November 15, 2021, the EPA proposed rules to reduce methane emissions from taking effect pending review. The original petitioners have been joined by a number of environmental groups in challenging the September 2020 rule.both new and existing oil and natural gas industry sources. For additional information, please read “Risk Factors—Legal, Regulatory and Governmental Risks— Federal and state legislation, judicial actions and regulatory initiatives related to oil and gas development and the use of hydraulic fracturing could result in increased costs and operating restrictions or delays and adversely affect our business, financial condition, results of operations and cash flows” in Item 1A.

In October 2015, the EPA adopted a lower national ambient air quality standard for ozone. The revised standard resulted in additional areas being designated as ozone non-attainment, which could lead to requirements for additional emissions control equipment and the imposition of more stringent permit requirements on facilities in those areas. The EPA completed its final area designations under the new ozone standard in July 2018. If we are unable to comply with air pollution regulations or to obtain permits for emissions associated with our operations, we could be required to forego construction, modification or implement modifications to certain operations. These regulations may also increase compliance costs for some facilities we own or operate, and result in administrative, civil and/or criminal penalties for noncompliance. Obtaining permits may delay the development of our oil and natural gas projects, including the construction and operation of facilities.

The adoption of U.S. federal, state or local laws or the implementation of regulations regardingaffecting our ability to conduct hydraulic fracturing could potentially cause a decrease in the completion of new oil and natural gas wells and increased compliance costs, which could increase costs of our operations and cause considerable delays in acquiring regulatory approvals to drill and complete wells. In

Although the U.S. Congress has considered but not enacted, legislation designed to reduce emissions of greenhouse gases fromGHGs in recent years, it has not adopted any significant GHG legislation. However, the 2021 Infrastructure and Investment Jobs Act passed by Congress on November 6, 2021 included measures aimed at decarbonization to address climate change, including funding for replacing transit vehicles, including buses, with zero- and low-emission vehicles and for the deployment of an electric vehicle charging network nationwide. This legislation, and other future laws, that promote a shift toward electric vehicles could adversely affect the demand for our products. Moreover, in the absence of federal GHG legislation, a number of state and regional efforts have emerged. These include measures aimed at tracking and/or reducing GHG emissions through cap-and-trade programs, which typically require major sources within the United States between 2012of GHG emissions, such as electric power plants, to acquire and 2050.surrender emission allowances in return for emitting GHGs. In addition, manya coalition of over 20 governors of U.S. states formed the U.S. Climate Alliance to advance the objectives of the Paris Agreement, and several U.S. cities have already taken legal measurescommitted to reduceadvance the objectives of the Paris Agreement at the state or local level as well. To this end, the California governor issued an executive order on September 23, 2020 ordering actions to pursue GHG emissions reductions, including a direction to the California State Air Resources Board to develop and propose regulations to require increasing volumes of greenhouse gases, primarily throughnew zero-emission passenger vehicles and trucks sold in California over time, with a targeted ban of the planned developmentsale of greenhouse gas emission inventories and/or regional greenhouse gas cap and trade programs. Thenew gasoline vehicles by 2035.

At the federal level, the EPA has also begun to regulate carbon dioxide and other greenhouse gas emissionsGHGs under existing provisions of the Clean Air Act. ThisIn December 2009, the EPA published its findings that emissions of GHGs present an endangerment to public health and the environment because emissions of such gases are contributing to the warming of the earth’s atmosphere and other climatic changes. Based on these findings, the EPA adopted regulations under existing provisions of the federal Clean Air Act that establish Prevention of Significant Deterioration (“PSD”) and Title V permit reviews for GHG emissions from certain large stationary sources that are otherwise subject to PSD and Title V permitting requirements. The EPA has also adopted rules requiring the monitoring and reporting of GHG emissions from specified sources in the U.S., including, among others, certain oil and gas production facilities on an annual basis, which includes potential regulationcertain of our operations. The EPA widened the scope of annual GHG reporting to include, not only activities associated with completion and workover of gas wells with hydraulic fracturing and activities associated with oil and gas production operations, but also completions and workovers of oil wells with hydraulic fracturing, gathering and boosting systems, and transmission pipelines. More recently, on November 15, 2021, the EPA proposed rules to reduce methane emissions from new and modified sources in the oil and gas sector.

If we are unable to recover or pass through a significant portion of our costs related to complying with current and future regulations relating to climate change and GHGs, it could materially affect our operations and financial condition. Any future laws or regulations that limit emissions of GHGs from our equipment and operations could require us to both develop and implement new practices aimed at reducing GHG emissions, such as emissions control technologies, which could increase our operating costs and could adversely affect demand for the oil and gas that we produce. To the extent financial markets view climate change and GHG emissions as a financial risk, this could negatively impact our cost of, and access to, capital. Future implementation or adoption of legislation or regulations adopted to address climate change could also make our products more or less desirable than competing sources of energy. Please read “Risk Factors—Legal, RegulatoryAt this time, it is not possible to quantify the impact of any such future developments on our business.

We believe that our ability to attract, retain and develop the highest quality personnelemployees is an importanta vital component of our success. In connection with the Merger, we developed an integration plan for every corporate functional organization and are in the process of completing staff reorganizations, relocations of key employees and hiring of new talent for our corporate headquarters in Houston, Texas. Staff reductions will occur primarily in our Denver, Colorado office (which will eventually be closed) and our Tulsa, Oklahoma office, which will be dedicated to management of our Anadarko Basin operations, with other corporate functions transferred to Houston. Detailed transition and knowledge transfer plans are intended to ensure that key aspects of ongoing operations are uninterrupted through this process. Our staff reorganization plans are intended to eliminate redundancy between the legacy company organizations, and our hiring plans aim to accelerate our ability to attract and develop a diverse workforce. We believe ourthat the resulting employee levels from our integration plan are appropriate and that we will continue to have the human capital to operate our business and carry out our strategy as determined by management and our Board of Directors.

As of December 31, 2020,2021, with the addition of employees as a result of the Merger, we had 503936 total employees, 274165 of whom were associated withlocated in our upstream operations, of which 92 were located at our corporate headquarters in Houston, Texas 88 were located atand our regionalcorporate office in Pittsburgh, Pennsylvania,Denver, Colorado and 94417 of whom were located in our regional offices in Midland, Texas, Tulsa Oklahoma and Pittsburgh, Pennsylvania. We had a total of 354 employees in production field operations in Susquehanna County, Pennsylvania.locations across our regional offices. Of these 274 upstream employees, 214our total employee population, 611 were salaried and 60325 were hourly. In addition to our upstream employees, we had 229We also have 211 employees that are employed by our wholly owned subsidiary, GasSearch Drilling Services Corporation (GDS)(“GDS”), which is a service company engaged in water hauling and site preparation exclusively for our fieldMarcellus Shale operations. Of these 229our GDS employees, 1315 were salaried and 216196 were hourly. WeAs a result of consistent communication and transparent management, we believe that our relations with our employees are favorable. None of our employees isare represented bypursuant to a collective bargaining agreement.

In managing our human capital resources, we seek to:

We believe these practices, further described below, are the key drivers in our verydevelopment of current and future talent and leadership as well as low voluntary turnover rates, which averaged less than five percent over the five-year period ended December 31, 2020.2021.

WeWhen we hire from outside the company, we identify qualified candidates by promoting the position internally for referrals, engaging in recruiting through our website and online platforms, conducting campus outreach, filling internshipsutilizing recruiting services and attending job fairs. We also have a well-established internship program that feeds top talent into our technical functions. In our recruiting and hiring efforts, we seek to foster a culture of mutual respect and strictly complycompliance with all applicable federal, state and local laws governing nondiscrimination in employment. We seek to increase the diversity of our workforce in our external hiring practices. We treat all applicants with the same high level of respect regardless of their gender, ethnicity, religion, national origin, age, marital status, political affiliation, sexual orientation, gender identity, disability or protected veteran status. This philosophy extends to all employees throughout the lifecycle of employment, including recruiting, hiring, placement, promotion, evaluation, leaves of absence, compensation and training.

We believe that our compensation and benefits package is a strong retention tool and promotes personal health and financial security within our workforce.

Our EHS management system provided the framework to implement immediate and comprehensive safety protocols in response to the COVID-19 pandemic that struck suddenly in the first quarter ofearly 2020. All of our employees are designated “critical infrastructure workers” under the Cybersecurity & Infrastructure Security Agency guidelines, and as a result, our field operations continued throughout 2020.2020 and 2021. The actions taken to prevent the spread of infection on our worksites and promote the health and safety of our workforce include:

Due to these measures, all of our operations continued safely and uninterrupted duringthrough the onset of the pandemic in 2020.2020 and throughout 2021. We also implemented appreciation award programs for many of our employees who have continued to work onsite during the pandemic.

We make available free of charge through our website, www.cabotog.com,www.coterra.com, our annual reports on Form 10‑K, quarterly reports on Form 10‑Q, current reports on Form 8‑K and all amendments to those reports as soon as reasonably practicable after such material is electronically filed with or furnished to the Securities and Exchange Commission (SEC). Information on our website is not a part of this report.SEC. In addition, the SEC maintains an Internet site at www.sec.gov that contains reports, proxy and information statements and other information filed by us. Information on our website is not a part of, and is not incorporated into, this report or any other report we may file with or furnish to the SEC, whether before or after the date of this report and irrespective of any general incorporation language therein. Furthermore, references to our website URLs are intended to be inactive textual references only.

Our Corporate Governance Guidelines, Corporate Bylaws, Audit Committee Charter, Compensation Committee Charter, Governance and Social Responsibility Committee Charter, Code of Business Conduct and Environment, Health & Safety Committee Charter are available on our website at www.cabotog.com,www.coterra.com, under the “Governance”“Corporate Governance” section of “About Cabot.“Investors.” Requests for copies of these documents can also be made in writing to Investor Relations at our corporate headquarters at Three Memorial City Plaza, 840 Gessner Road, Suite 1400, Houston, Texas 77024.

Our revenues, operating results, financial condition and ability to borrow funds or obtain additional capital depend substantially on prices we receive for the oil, natural gas and NGLs that we sell. Lower commodity prices may reduce the amount of oil, natural gas and NGLs that we can produce economically. Historically, commodity prices have been volatile, with prices fluctuating widely, and they are likely to continue to be volatile. Because substantially allFor example, the WTI oil prices in 2021 ranged from a high of our reserves are natural gas, changes in$84.65 to a low of $47.62 per Bbl and NYMEX natural gas prices havein 2021 ranged from a more significant impact on our financial results.high of $23.86 (during Winter Storm Uri) to a low of $2.43 per Mmbtu. Any substantial or extended decline in future commodity prices would have a material adverse effect on our future business, financial condition, results of operations, cash flows, liquidity or ability to finance planned capital expenditures and commitments. Furthermore, substantial, extended decreases in commodity prices may cause us to delay or postpone a significant portion of our exploration development and exploitationdevelopment projects or may render such projects uneconomic, which may result in significant downward adjustments to our estimated proved reserves and could negatively impact our ability to borrow and cost of capital and our ability to access capital markets, increase our costs under our revolving credit facility and limit our ability to execute aspects of our business plans. Refer to "Future“Future commodity price declines may result in write-downs of the carrying amount of our oil and gas properties, which could materially and adversely affect our results of operations."”

Wide fluctuations in commodity prices may result from relatively minor changes in the supply of and demand for oil, natural gas and oil,NGLs, market uncertainty and a variety of additional factors that are beyond our control. These factors include but are not limited to the following:

These factors and the volatile nature of the energy markets make it impossible to predict the future commodity prices. If commodity prices remain low or continue to decline significantly for a sustained period of time, the lower prices may cause us

Our growth is materially dependent upon the success of our drilling program. Drilling for oil and natural gas and oil involves numerous risks, including the risk that no commercially productive reservoirs will be encountered. The cost of drilling, completing and operating wells is substantial and uncertain, and drilling operations may be curtailed, delayed or canceled as a result of a variety of factors beyond our control, including:

Our future drilling activities may not be successful and, if unsuccessful, such failure will have an adverse effect on our future results of operations and financial condition. Our overall drilling success rate or our drilling success rate within a particular geographic area may decline. We may be unable to lease or drill identified or budgeted prospects within our expected time frame, or at all. We may be unable to lease or drill a particular prospect because, in some cases, we identify a prospect or drilling location before seeking an option or lease rights in the prospect or location. Similarly, our drilling schedule may vary from our capital budget. The final determination with respect to the drilling of any scheduled or budgeted wells will be dependentdepend on a number of factors, including:

These projects may not be successfully developed and the wells, if drilled, may not encounter reservoirs of commercially productive oil or natural gas.

Furthermore, the COVID-19 pandemic caused a significant reduction in demand for crude oil, and to a lesser extent, natural gas and NGLs during much of 2020. The supply/demand imbalance driven by the COVID-19 pandemic and production disagreements in March 2020 among members of OPEC+ led to a significant global economic contraction generally in 2020 and continued to have disruptive impacts on our industry in 2021. Although an agreement to cut production was subsequently announced by OPEC+, the situation, coupled with the impact of COVID-19 and storage and transportation capacity constraints, resulted in a significant downturn in the oil and gas industry. We cannot predict the full impact that COVID-19 and its variants or the significant disruption and volatility currently being experienced in the oil and natural gas markets will have on our business, financial condition and results of operations at this time due to numerous uncertainties. For example, the operations of our midstream service providers, on whom we rely for the transmission, gathering and processing of a significant portion of our produced oil, natural gas and NGLs, may be disrupted or suspended in response to containing outbreaks, and/or the economic challenges may lead to a reduction in capacity or closing of the facilities and infrastructure of our midstream service providers, which may result in substantial discounts in the prices we receive for our produced oil, natural gas or oil.NGLs or result in the shut-in of producing wells or the delay or discontinuance of development plans for our properties. Although we have not received notices from our customers or counterparties regarding non-performance issues or delays resulting from the COVID-19 pandemic, to the extent we or any of our material suppliers or customers are unable to operate due to government restrictions or otherwise, we may have to temporarily shut down or reduce production, which could result in significant downtime and have significant adverse consequences for our business, financial condition and results of operations.

Reserve engineering is a subjective process of estimating underground accumulations of oil and natural gas and oil that cannot be measured in an exact manner. The process of estimating quantities of proved reserves is complex and inherently imprecise, and the reserve data included in this document are only estimates. The process relies on interpretations of available geologic, geophysical, engineering and production data. The extent, quality and reliability of this technical data can vary. The process also requires certain economic assumptions, some of which are mandated by the SEC, such as assumptions relating to commodity prices. Additional assumptions include drilling and operating expenses, capital expenditures, taxes and availability of funds. Furthermore, different reserve engineers may make different estimates of reserves and cash flows based on the same data.

The value of our oil and gas properties depends on commodity prices. Declines in these prices as well as increases in development costs, changes in well performance, delays in asset development or deterioration of drilling results may result in our having to make material downward adjustments to our estimated proved reserves, and could result in an impairment charge and a corresponding write-down of the carrying amount of our oil and natural gas properties. Because substantially all of our reserves are natural gas, changes in natural gas prices have a more significant impact on our financial results.

We evaluate our oil and gas properties for impairment on a field-by-field basis whenever events or changes in circumstances indicate a property's carrying amount may not be recoverable. We compare expected undiscounted future cash flows to the net book value of the asset. If the future undiscounted expected cash flows, based on our estimate of future commodity prices, operating costs and anticipated production from proved reserves and risk-adjusted probable and possible reserves, are lower than the net book value of the asset, the capitalized cost is reduced to fair value. Commodity pricing is estimated by using a combination of assumptions management uses in its budgeting and forecasting process as well as historical and current prices adjusted for geographical location and quality differentials, as well as other factors that management believes will impact realizable prices. In the event that commodity prices decline, there could be a significant revision to the carrying amounts of oil and gas properties in the future.

In general, the production rate of oil and gas properties declines as reserves are depleted, with the rate of decline depending on reservoir characteristics. Unless we successfully replace the reserves that we produce, our reserves will decline, eventually resulting in a decrease in oil and natural gas production and lower revenues and cash flow from operations. Our future production is, therefore, highly dependent on our level of success in finding or acquiring additional reserves. We may not be able to replace reserves through our exploration, development and exploitation activities or by acquiring properties at acceptable costs. Low commodity prices may further limit the kinds of reserves that we can develop and produce economically.