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, strategic pursuits and goals, market prices, future hedging and risk management activities, timing and amount of capital expenditures 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 the continuing effects of the COVID-19 pandemicdiffer materially from those included in this report. These risks and uncertainties include, without limitation, the impact thereof on our business, financial conditionof public health crises, including pandemics (such as the coronavirus (“COVID-19”) pandemic) and results of operations,epidemics and any related company or governmental policies or actions, 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+)OPEC+, market factors, market prices (including geographic basis differentials) of oil and natural gas, impacts of inflation, labor shortages and economic disruption, including as a result of instability in the banking sector, geopolitical disruptions such as the war in Ukraine or the conflict in the Middle East, results of future drilling and marketing activity,activities, 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 for additionalof 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, aboutfuture events or otherwise. You are cautioned not to place undue reliance on these risksforward-looking statements, which speak only as of the date hereof.

Investors should note that we announce material financial information in SEC filings, press releases and uncertainties. Should one or morepublic conference calls. Based on guidance from the SEC, we may use the Investors section of these risks or uncertainties materialize, or should underlying assumptions prove incorrect, actual outcomes may vary materially from those indicated.our website (www.coterra.com) to communicate with investors. It is possible that the financial and other information posted there could be deemed to be material information. The information on our website is not part of, and is not incorporated into, this report.

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,” the “Company,” “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, as well as field offices near our operations.

Our 20212024 capital program is expected to be approximately $530.0 million$1.75 billion to $540.0 million, representing$1.95 billion, a sixdecrease of 12 percent reduction, at(at the midpoint of the range,mid-point) 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.$2.1 billion in 2023. We expect to fund these expenditures withturn-in-line 132 to 158 total net wells in 2024 across our three core operating cash flowareas. Approximately 60 percent of our drilling and if required, cash on hand.

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

Our Marcellus Shale properties representare principally located in the western half of the Permian Basin where we currently hold approximately 296,000 net acres in our primarycore operating area in the Delaware Basin. Our development activities are primarily focused on the Wolfcamp Shale and the Bone Spring formation in Culberson and Reeves Counties in Texas and Lea and Eddy Counties in New Mexico. Our 2023 net production from the Permian Basin was 233 MBoe per day, representing 35 percent of our total equivalent production for the year. Net oil production in 2023 averaged 90 MBbl per day, representing 93 percent of our total company oil production. As of December 31, 2023, we had a total of 1,083.0 producing net wells in the Permian Basin, of which approximately 89 percent are operated by us.

Our properties are principally located in Susquehanna County, Pennsylvania, where we currently hold approximately 175,000186,000 net acres in the dry gas window of the play.Marcellus Shale. Our 20202023 net production in the Marcellus Shale was 857 Bcfe,377 MBoe per day, representing substantially all57 percent of our total equivalent production for the year. Net natural gas production in 2023 averaged 2,263 MMcf per day, representing 78 percent of our total natural gas production. As of December 31, 2023, we had a total of 1,108.2 producing net wells in the Marcellus Shale, of which approximately 99 percent are operated by us.

Our properties are located in the Mid-Continent region in Oklahoma where we currently hold approximately 182,000 net acres. Our development activities are primarily focused on both the Woodford Shale and the Meramec formations. Our 2023 net production in the Anadarko Basin was 56 MBoe per day, representing eight percent of our total equivalent production for the year. As of December 31, 2020,2023, we had a total of 865.9509.9 producing net wells in the Marcellus Shale,Anadarko Basin, of which approximately 99.561 percent are operated by us.

During 2020,2023, we invested $562.1$158 million in the Marcellus ShaleAnadarko Basin and drilledhad one rig operating at year end.

Ancillary to our exploration, development and production operations, we operate a number of natural gas gathering and saltwater gathering and disposal systems. The majority of this 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 and intrastate pipelines and natural gas processing facilities and to transport produced water to new wells for re-use in completions activities and to disposal facilities. In addition, we can engage in development drilling without relying on third parties to transport our natural gas or participated in drilling 64.3 net wells,produced water and while incurring only the incremental costs of pipeline and compressor additions to our system.

On October 1, 2021, we completed 77.3 net wells and turned in line 69.2 net wells. As of December 31, 2020, we had 13.0 net wells that were either in the completion stage or waiting on completion or connection to a pipeline. We exited 2020merger transaction (the “Merger”) with three drilling rigs operating in the play and plan to exit 2021 with two rigs operating.

Operational information set forth in this Annual Report on Form 10-K does not include the activity of Cimarex for $30.0 million and recognized a gain on saleperiods prior to the completion of oil and gas properties of $29.7 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 ourat market-sensitive prices. 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 gathering and transportation and gathering expenses towhen we move our oil and natural gas production from the wellhead markets to our principal markets in the United States. The majority of our natural gas production is transported on third-party gathering systems and interstate pipelines where we have long-term contractual capacity arrangements or use purchaser-owned capacity under both long-term and short-term sales contracts.

To date, we have not experienced significant difficulty in transporting or marketing our natural gas production as it becomes available; however, there is no assurance that we will always be able to transport and market all of our production.

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 we may be required to purchase natural gas from third parties to satisfy shortfalls, should they occur.

From time to time, weWe use derivative financial instruments to manage price risk associated with our natural gas production. While there are many different types of derivatives available, we generally utilize collar, swap and basis swap agreements designed to manage price risk more effectively. 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.

For additional information regarding estimates of our net proved and proved undeveloped reserves, the auditqualifications of the preparers of our reserves estimates, the evaluation of such estimates by Millerour independent petroleum consultants, our processes and Lents, Ltd. (Miller and Lents)controls with respect to our reserves estimates 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 reservereserves estimates or underlying assumptions could cause the quantities and net present value of our reserves to be overstated or understated” in Item 1A.

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 customaryoil and gas mineral leases. These leases provide us the right to develop oil and/orand natural gas on the properties. Their primary terms generally range in length from approximately three to 10 years. These propertiesyears, and these leases generally are held for longer periods ifonce production is established.

In the event that production is not established or we take no action to extend or renew the terms ofThe table below summarizes by year and operating area our leases, our net undeveloped acreage that will expire overexpirations in the next three years asyears. In most cases, the drilling of December 31, 2020 is 13,515, 3,947a commercial well will hold the acreage beyond the expiration.

Expiring acreage in our core operating areas in 2024, 2025 and 4,371 for the years ending December 31, 2021, 2022 and 2023, respectively.

WeThe table below presents wells that we drilled and completed wells or in which we participated in the drilling and completion of wells as indicated in the table below. Thecompletion. This information below should not be considered indicative of future performance, nor should a correlation be assumed betweenas a result of the number of productive wells drilled, the quantities of reserves found or the economic value.

We believe that we have satisfactory title to all of our producing properties and leases 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.where we operate. We primarily compete with integrated, independent and other energy companies for the sale and transportation of our oil and natural gas

Price, contract terms, availability of rigs and related equipment and quality of service, including pipeline connection timesinfrastructure availability 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 core 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.position.

During the year ended December 31, 2020, three2023, two customers accounted for approximately 21 percent, 1619 percent and 1217 percent of our total sales. During the year ended December 31, 2019, three customers accounted for approximately 17 percent, 16 percent and 16 percent of our total sales. During the year ended December 31, 2018,2022, two customers accounted for approximately 2013 percent and 11 percent of our total sales.

We doregularly monitor the creditworthiness of our customers 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 includesThese regulations include 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 prohibitingprohibit the venting or flaring of natural gas and imposingimpose certain requirements regarding the ratability of production. The effect of theselaws and 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, underUnder 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 $1.3approximately $1.5 million per day per violation. In 2010, the FERC issued Penalty Guidelines for the determination of civil penalties and procedure under its enforcement program.

OurUnder the NGPA, natural gas gathering facilities are expressly exempt from FERC jurisdiction. What constitutes “gathering” under the NGPA has evolved through FERC decisions and judicial review of such decisions. We believe that our gathering and production facilities meet the test for non-jurisdictional “gathering” systems under the NGPA and gathering that our

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 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 ofThe Commodity Exchange Act provides the Dodd‑Frank Wall Street Reform and Consumer Protection Act (Dodd‑Frank Act) in July 2010, theU.S. Commodity Futures Trading Commission (CFTC) has promulgated regulations(the “CFTC”) with jurisdiction 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.pipeline. Every five years, the FERC must examine the relationship between the annual change in the applicable index and the actual cost changes experienced in the oil pipeline industry. In December 2015, to implement this required five‑year redetermination, the FERC established an upward adjustment in the index to track oil pipeline cost changes and determined that the Producer Price Index for Finished Goods plus 1.23 percent should be the oil pricing index

We generate some hazardous wastes that are hazardous wastes subject to the 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 June 1, 2021, the FWS proposed to list two distinct population segments (“DPS”) of the lesser prairie-chicken (“LPC”) 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. On November 25, 2022, the FWS finalized the proposed rule, listing the southern DPS of the lesser prairie-chicken as endangered and the northern DPS of the lesser prairie-chicken as threatened. On July 27, 2023, the U.S. House of Representatives voted to use the Congressional Review Act to reverse the LPC listing. On September 26, 2023 President Biden vetoed Congress’ resolution to reverse the LPC listing. On September 28, 2023, the U.S. Senate voted and failed to override the President’s veto. On November 3, 2023, the U.S. House of Representatives passed an appropriations bill for the U.S. Department of Interior for fiscal year 2023, which provides, in part, that no funds may be used to implement, administer, or enforce the listing of the LPC. Listing of the LPC 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 LPC 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 LPC’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 operationsacreage during nesting seasons, in an effort to protect the LPC.

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 (proposed to be listed as endangered under the ESA on July 3, 2023) 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 proposed listing was finalized and published on February 28, 2022. The Peppered Chub is a freshwater fish that historically was found in the South Canadian, Cimarron and Arkansas rivers within New Mexico, Texas, Oklahoma and Kansas. We have operations near the South Canadian River in Oklahoma that may be impacted by the listing of the Peppered Chub as endangered. The increase in endangered species listings, such as the Peppered Chub, may limit our ability to explore for or threatened species couldproduce oil and gas in certain areas or cause us to incur additional costs or become subject to operating restrictions or bans in the affected areas.costs.

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 addhas added costs and causecaused 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 groupsboth new and existing oil and natural gas industry sources and published supplemental rules regarding the same on December 6, 2022. On December 2, 2023, during the United Nations Climate Change Conference in challenging the September 2020 rule.United Arab Emirates (“COP28”), the EPA announced its final methane rules, which impose several new methane emission requirements on the oil and gas industry. For additional information, please read “Risk Factors—Legal, Regulatory and Governmental Risks— Federal, state and state legislation,local laws and regulations, 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

At the federal level, the EPA conducted a study of the potential environmental effects of hydraulic fracturing on drinking water and groundwater. The adoptionEPA released its final report in December 2016. It concluded that hydraulic fracturing activities can impact drinking water resources under some circumstances, including large volume spills and inadequate mechanical integrity of wells. This study and other studies that may be undertaken by the EPA or other federal agencies could spur initiatives to further regulate hydraulic fracturing under the Safe Drinking Water Act, the Toxic Substances Control Act, or other statutory and regulatory mechanisms. A number of federal stateagencies are analyzing, or local laws or the implementationhave been requested to review, a variety of regulations regardingenvironmental issues associated with hydraulic fracturing practices.

Our inability to locate sufficient amounts of water, or to dispose of or recycle water used or produced in our exploration and production operations, could potentially cause a decreaseadversely impact our operations. For water sourcing, we first seek to use non-potable water supplies, or recycled produced water for our operational needs. In certain areas, there may be insufficient water available for drilling and completion activities. Water must then be obtained from other sources and transported to the drilling site. Our operations in certain areas could be adversely impacted if we are unable to secure sufficient amounts of water or to dispose of or recycle the completionwater used in our operations. The imposition of new oilenvironmental and natural gasother regulations, as well as produced water disposal well limits or moratoriums in areas of seismicity, could further restrict our ability to conduct operations such as hydraulic fracturing by restricting the disposal of waste such as produced water and drilling fluids. Compliance with environmental regulations and permit requirements governing the withdrawal, storage and use of surface water or groundwater necessary for hydraulic fracturing of wells may increase our operating costs and increased compliance costs, which could increase costscause delays, interruptions or termination of our operations, the extent of which cannot be predicted, all of which could have an adverse effect on our operations and cause considerable delays in acquiring regulatory approvalsfinancial condition. In June 2016, the EPA published final pretreatment standards for disposal of wastewater produced from shale gas operations to drill and complete wells.publicly owned treatment works. The regulations were developed under the EPA’s Effluent Guidelines Program under the authority of the Clean Water Act. 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 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, California’s 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. sector and published proposed supplemental rules regarding the same on December 6, 2022. On December 2, 2023, during COP28, the EPA announced its final methane rules, which impose several new methane emission requirements on the oil and gas industry. The Inflation Reduction Act of 2022 (“IRA”) established the Methane Emissions Reduction Program, which imposes a charge on methane emissions from certain petroleum and natural gas facilities, which may apply to our operations in the future and may require us to expend material sums.

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 personnel is an important component of our success. We believe our employee levels are appropriate and that we 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, 2020,2023, we had 503894 Coterra employees, 274285 of whom were associated withlocated in our upstream operations, of which 92 were located at our corporate headquarters in Houston, Texas 88 were located at our regional office in Pittsburgh, Pennsylvania, and 94227 of whom were located in our regional offices in Midland, Texas, Tulsa, Oklahoma and Pittsburgh, Pennsylvania. We had a total of 382 employees in production field operations in Susquehanna County, Pennsylvania.locations across our regional offices. Of these 274 upstream employees, 214our total employee population, 564 were salaried and 60330 were hourly. In addition to our upstream employees,Additionally, we had 229have 189 employees that are employed by our wholly ownedwholly-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, 1316 were salaried and 216173 were hourly. 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,people, we seek to:

We believe these practices, further described below, are the key drivers in our very low voluntary turnover rates, which averaged less than five percent over the five-year period ended December 31, 2020.development of current and future talent and leadership as well as employee engagement and retention.

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 ask our recruiting partners to provide diverse slates of candidates and 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.

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, including our 2023 Sustainability Report, is not a part of, and is not incorporated into, this Annual Report on Form 10-K or any other report we may file with or furnish to the SEC (and is not deemed filed herewith), whether before or after the date of this Annual Report on Form 10-K 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,Code of Business Conduct and Ethics, 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, under the “Governance” sectionwww.coterra.com. Requests for copies of “About Cabot.” Requeststhese documents can also be made in writing to Investor RelationsCorporate Secretary 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.economically, while higher commodity prices could cause us to experience periods of higher costs. Historically, commodity prices have been volatile, with prices fluctuating widely, and they are likely to continue to be volatile. Because substantially allWide fluctuations in commodity prices may result from relatively minor changes in the supply of our reserves areand demand for oil, natural gas changesand NGLs, market uncertainty and a variety of additional factors that are beyond our control, including global events or conditions that affect supply and demand, such as pandemics, the war in natural gas prices have a more significant impact on our financial results.Ukraine, conflict in the Middle East and other geopolitical risks and sanctions, the actions of OPEC+ members and climate change. 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. If commodity prices decline significantly for a sustained period of time, the lower prices may cause us to reduce our planned drilling program or adversely affect our ability to make planned expenditures, raise additional capital or meet our financial obligations. Furthermore, substantial, extended decreases in commodity prices may cause us to delay or postpone a significant portion of our exploration, development and exploitation projects or may render suchcertain projects uneconomic, which may result in significant downward adjustments to our estimated proved reserves and could negatively impact our ability to borrow, andour cost of capital and our ability to access capital markets, increase our costs under our revolving credit facility,agreement and limit our ability to execute aspects of our business plans. Refer to "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."

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'sproperty’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.

Our producing propertiesgrowth is materially dependent upon the success of our drilling program. Drilling for oil and natural gas 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. 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.

You should not assume that the present value of future net cash flows from our proved reserves is the current market value of our estimated reserves. In accordance with SEC requirements, we base the estimated discounted future net cash flows from our proved reserves 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 and costs in effect on the date of the estimate, holding the prices and costs constant throughout the life of the properties, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions. Actual future prices and costs may differ materially from those used in the net present value estimate, and future net present value estimates using then current prices and costs may be significantly less than the current estimate. In addition, the 10 percent discount factor we use when calculating discounted future net cash flows for reporting requirements in compliance with the applicable accounting standards may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with operatingus or the oil and gas industry in one major geographic area.

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 as reserves are depleted, 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. Additionally, there is no way to predict in advance of any exploration and development whether any particular location will yield sufficient quantities to recover drilling or completion costs or be economically viable. Low commodity prices may further limit the kinds of reserves that we can develop and produce economically. If we are unable to replace our current and future production, our revenues will decrease and our business, financial condition and results of operations may be adversely affected.

Our future growth prospects are dependent upondepend on our ability to identify optimal strategies for our business. In developing our business plan,plans, we considered allocating capital and other resources to various aspects of our businessesbusiness including well-development (primarily drilling)drilling and completion), reserve acquisitions, exploratory activity, corporate items and other alternatives. We also consideredconsider our likely sources of capital. Notwithstanding the determinations made in the development of our 20212024 plan, business opportunities not previously identified periodically may come to our attention, including possible acquisitions and dispositions. If we fail to identify optimal business strategies or fail to optimize our capital investment and capital raising opportunities and the use of our other resources in furtherance of our business strategies, our financial condition and growth rate may be adversely affected. Moreover, economic or other circumstances may change from those contemplated by our 20212024 plan, and our failure to recognize or respond to those changes may limit our ability to achieve our objectives.

The sale of our oil, natural gas and NGL production depends on a number of factors beyond our control, including the availability and capacity of gathering, transportation and processing facilities. We deliver the majority of our oil, natural gas and NGL production primarily through gathering systems and pipelines that we do not own. The lack of available capacity on these systems and facilities could reduce the price offered for our production or result in the shut-in of producing wells or the delay or discontinuance of development plans for properties. Third-party systems and facilities may be unavailable due to market conditions or mechanical or other reasons.reasons, and in some cases the resulting curtailments of production could lead to payment being required where we fail to deliver oil, natural gas and NGLs to meet minimum volume commitments. In addition, at current commodity prices, construction of new pipelines and building of suchrequired infrastructure may be slower to build out.slow. To the extent these services are unavailable, we would be unable to realize revenue from wells served by such facilities until suitable arrangements are made to market our production. Our failure to obtain these services on acceptable terms could materially harm our business.

For example, the Marcellus Shale wellsMoreover, these availability and capacity issues are likely to occur in remote areas with less established infrastructure, such as our Permian Basin properties where we have drilled to date have generally reported very high initial production rates. The amount ofsignificant oil and natural gas being produced in the area fromproduction. Any of these new wells, as well as natural gas produced from other existing wells, may exceed theavailability or capacity of the various gatheringissues could negatively affect our operations, revenues and intrastate or interstate transportation pipelines currently available. In such an event, thisexpenses. This could result in wells being shut in or awaiting a pipeline connection or capacity, and/or natural gas being sold at much lower prices than those quoted on NYMEX or than we currently project, which would adversely affect our results of operations and cash flows.

Successful property acquisitions require an assessment of a number of factors beyond our control. These factors include estimates of recoverable reserves, exploration and development potential, future commodity prices, operating costs, production taxes and potential environmental and other liabilities. These assessments are complex and inherently imprecise. Our review of the properties we acquire may not reveal all existing or potential problems. In addition, our review may not allow us to assess fully assess the potential deficiencies of the properties. We do not inspect every well, and even when we inspect a well we may not discover structural, subsurface or environmental problems that may exist or arise.

There may be threatened or contemplated claims against the assets or businesses we acquire related to environmental, title, regulatory, tax, contract, litigation or other matters of which we are unaware, which could materially and adversely affect our production, revenues and results of operations. We often assume certain liabilities, and we may not be entitled to contractual indemnification for pre-closing liabilities, including environmental liabilities, and our contractual indemnification may not be effective. At times, we acquire interests in properties on an "as is"“as is” basis with limited representations and warranties and limited remedies for breaches of such representations and warranties. In addition, significant acquisitions can change the nature of our operations and business if the acquired properties have substantially different operating and geological characteristics or are in different geographic locations than our existing properties.

The integration of the businesses and properties we have acquired or may in the future acquire could be difficult, and may divert management'smanagement’s attention and financial resources away from our existing operations. These difficulties include:

The process of integrating our operations could cause an interruption of, or loss of momentum in, the activities of our business. Members of our management may be required to devote considerable amounts of time to this integration process, which will decrease the time they will have to manage our existing business. If management is not able to effectively manage the integration process, or if any significant business activities are interrupted as a result of the integration process, our business could suffer.

Other companies operate some of the properties in which we have an interest. As of December 31, 2020,2023, non-operated wells represented approximately nine51 percent of our total owned gross wells, or less than one12 percent of our owned net wells. We have limited ability to influence or control the operation or future development of these non-operated properties and of properties we operate in joint ventures in which we may share control with third parties, including compliance with environmental, safety and other regulations or the amount of capital expenditures that we are required to fund with respect to them. The failure of anAn operator of our wells toor a joint venture participant may not adequately perform operations, an operator'smay breach of the applicable agreements or an operator's failuremay fail to act in ways that are in our best interest, which could reduce our production and revenues.revenues and expose us to liabilities. Our dependence on the operator and other working interest owners for these projects and our limited ability to influence or control the operation and future development of these propertiesa joint venture participant could materially adversely affect the realization of our targeted returns on capital in drilling or acquisition activities and lead to unexpected future costs.

Many of our properties are in areas that may have been partially depleted or drained by earlier drilled offset wells. We have no control over offsetting operators who could take actions such as drilling and completing nearby wells, that could adversely affect our operations. When a new offset well is completed and produced, the pressure differential in the vicinity of the wellbore causes the migration of reservoir fluids toward the new wellbore (and potentially away from existing wellbores), which could cause a depletion of our proved reserves and may inhibit our ability to further develop our proved reserves. The possibility for these impacts may increase with respect to wells that are shut in as a response to lower commodity prices or the lack of pipeline and storage capacity. In addition, completion operations and other activities conducted on other nearby wells could cause us, in order to protect our existing wells, to shut in production for indefinite periods of time. Shutting in our industrywells and damage to our wells from offset completions could result in increased costs and could adversely affect the reserves and re-commenced production from such shut in wells.

We could lose leases under certain circumstances if we do not maintain production in paying quantities or meet other lease requirements, and manythe amounts we spent for those leases could be lost. If we shut in wells in response to lower commodity prices or a lack of pipeline and storage capacity, we may face claims that we are not complying with lease provisions. In addition, the government also may impose new restrictions and regulations affecting our ability to drill, conduct hydraulic fracturing operations, and obtain necessary rights-of-way on federal lands, which could, in turn, result in the loss of federal leases. As of December 31, 2023, less than one percent of our competitors have substantially greater financial and technological resources than we do,net undeveloped acreage in our core operating areas will expire over the next three years. Our actual drilling activities may materially differ from those presently identified, which could adversely affect our competitive position.business.

Our operations arebusiness, like the oil and gas industry in general, has become increasingly dependent upon a relatively small groupon data, information systems, and digitally connected infrastructure, including technologies managed by third-party providers on whom we rely to help us

Cyber-attacks are becoming more sophisticated and can include, but are not limited to, the use of these individualsmalicious software, phishing scams, ransomware, attempts to gain unauthorized access to systems or data, or other electronic security breaches that could lead to disruptions in critical systems, unauthorized release of confidential or otherwise protected information, such as personal information of our employees, and corruption of data. Unauthorized access to our seismic data, reserves information, customer or employee data or other proprietary or commercially sensitive information could lead to data integrity issues, communication interruption or other disruptions in our exploration or production operations or planned business transactions, any of which could have a detrimental effectmaterial adverse impact on us. our business and operations. If our information or operational technology systems cease to function properly or are breached, we could suffer disruptions to our normal operations, which may include drilling, completion, production and corporate functions. A cyber-attack involving our information or operational technology systems and related infrastructure, or that of our business associates or partners, could result in supply chain disruptions that delay or prevent the transportation and marketing of our production, equipment damage, fires, explosions or environmental releases, non-compliance leading to regulatory fines or penalties, loss or disclosure of, or damage to, our or any of our customer’s or supplier’s data or confidential information that could harm our business by damaging our reputation, subjecting us to potential financial or legal liability and requiring us to incur significant costs, including costs to repair or restore our systems and data or to take other remedial steps.

In addition, certain cyber incidents, such as reconnaissance campaigns, may remain undetected for an extended period, and our drilling successsystems and insurance coverage for protecting against such cybersecurity risks may be costly and may not be sufficient. As cyber-attackers become more sophisticated, we may be required to expend significant additional resources to continue to protect our business or remediate the successdamage from cyber-attacks. Furthermore, the continuing and evolving threat of other activities integralcyber-attacks has resulted in increased regulatory focus on prevention, mitigation, and notification, and we may be required to expend significant additional resources to continue to modify or enhance our operations will depend, in part, on our abilityprotective measures or to attractinvestigate and retain experienced geologists, engineers and other professionals. Competition for experienced geologists, engineers and some other professionals is extremely intense and canremediate any information security vulnerabilities. To the extent we face increased regulatory requirements, we may be exacerbated following a downturn in which talented professionals leave the industry. If we cannot retain our technical personnel or attractrequired to expend significant additional experienced technical personnel, our abilityresources to compete could be harmed.meet such requirements.

We make and expect to make substantial capital expenditures in connection with our development and production projects. We rely uponon access to both our revolving credit facilityagreement and longer-term capital markets as sources of liquidity for any capital requirements not satisfied by cash flow from operations or other sources. Adverse economic and market conditions, could adversely affect our ability to access such sources of liquidity. Future challenges in the global financial system including the capital markets, may adversely affect the terms on which we are able to obtain financing, which could impact our business, financial condition and our financial condition.access to capital. Our ability to access the capital markets may be restricted at a time when we desire,want or need to raise capital, which could have an impact on our flexibility to react to changing economic and business conditions. AdverseAdditionally, such adverse economic and market conditions could adversely affect the collectability ofimpact our tradecounterparties, including our receivables and cause our commodity hedging counterparties, towho may, as a result of such conditions, be unable to perform their obligations or to seek bankruptcy protection. In addition, there have been efforts in recent years aimed at the investment community, including investment advisors, sovereign wealth funds, public pension funds, universities and other groups, promoting the divestment of fossil fuel equities as well as to pressure lenders and other financial services companies to limit or curtail activities with companies engaged in the extraction of fossil fuel reserves, which, if successful, could limit our ability to access capital markets. Future challenges in the economy could also lead to reduced demand for natural gas which could have a negative impact on our revenues.

AsOur indebtedness could have adverse effects on our business, financial condition, results of December 31, 2020, we had approximately $1.1 billion of debt outstandingoperations and we may incur additional indebtedness in the future. Increases in our level of indebtedness may:

Our debt agreements also require compliance with covenants to maintain specified financial ratios. If commodity prices deteriorate from current levels, or continue for an extended period, it could lead to reduced revenues, cash flow and earnings, which in turn could lead to a default under such agreements due to lack of covenant compliance. Because the calculations of the financial ratios are made as of certain dates, the financial ratios can fluctuate significantly from period to period. A prolonged period of lower commodity prices could further increase the risk of our inability to comply with covenants to maintain specified financial ratios. In order to provide a margin of comfort with regard to these financial covenants, we may seek to reducemodify our capital expenditures,program, sell non-strategic assets or opportunistically modify or increase our derivative instruments to the extent permitted under our debt agreements.instruments. In addition, we may seek to refinance or restructure all or a portion of our indebtedness. We cannot provide assurance that we will be able to successfully execute any of these strategies, and such strategies may be unavailable on favorable terms or at all. For more information about our debt agreements, please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations - Financial Condition -Operations-Financial Condition-Liquidity and Capital Resources and Liquidity.Resources.”

From time to time, when we believe that market conditions are favorable, weWe use financial derivative instruments to manage commodity price risk associated with our natural gas production.risk. While there are many different types of derivatives available, we generally utilize collar, swap and basis swap agreements to manage price risk more effectively.

TheIn addition, the CFTC has promulgated regulations to implement statutory requirements for swap transactions. These regulations are intended to implement a regulated market in which most swaps are executed on registered exchanges or swap execution facilities and cleared through central counterparties. Whilederivatives transactions, including swaps. Although we believe that our use of swap transactions exemptexempts us from certain regulatory requirements, the changes to the swapderivatives market dueregulation affect us directly and indirectly. These changes, as in effect and as continuing to increased regulationbe implemented, as well as a reduced liquidity in oil and gas derivative market, could significantly increase the cost of entering into new swaps or maintaining existing swaps, materially alter the terms of new or existing swap transactions and/or reducederivative contracts, limit the availability of newderivatives to protect against risks that we encounter, reduce our ability to monetize or restructure our existing swaps.derivative contracts and increase our exposure to less creditworthy counterparties. If we reduce our use of swaps, as a result of the Dodd-Frank Act and regulations, our results of operations may become more volatile, and our cash flows may be less predictable.

We will continue to evaluate the benefit of utilizing derivatives in the future. Please read "Management's“Management’s Discussion and Analysis of Financial Condition and Results of Operations"Operations” in Item 7 and "Quantitative“Quantitative and Qualitative Disclosures about Market Risk"Risk” in Item 7A for further discussion concerning our use of derivatives.

Businesses across all industries are facing increasing scrutiny from investors, governmental authorities, regulatory agencies and the public related to their ESG practices, including practices and disclosures related to climate change, sustainability, diversity, equity and inclusion initiatives, and heightened governance standards. Failure, or a perceived failure, to adequately respond to or meet evolving investor, stockholder or public ESG expectations, concerns and standards may cause a business entity to suffer reputational damage and materially and adversely affect the entity’s business, financial condition, or stock and debt prices. In addition, organizations that provide ESG information to investors have developed ratings processes for evaluating a business entity’s approach to ESG matters. Although currently no universal rating standards exist, the importance of sustainability evaluations is becoming more broadly accepted by investors and stockholders, with some using these ratings to

NegativeFurther, negative public perception regarding us and/orand our industry resulting from, among other things, concerns raised by advocacy groups about climate change impacts of methane and other greenhouse gas emissions, hydraulic fracturing, oil spills, greenhouse gas or methane emissions and pipeline explosions coupled with increasing societal expectations on businesses to address climate change and potential consumer use of substitutes to carbon-intensive energy commodities may result in increased costs, reduced demand for our oil, natural gas transmission lines, may leadand NGL production, reduced profits, increased regulation, regulatory investigations and litigation, and negative impacts on our stock and debt prices and access to increased regulatory scrutiny, which may, in turn, lead to new state and federal safety and environmental laws, regulations, guidelines and enforcement interpretations.capital markets. These actions may cause operational delays or restrictions, increased operating costs, additional regulatory burdens and increased risk of litigation. Moreover, governmental authorities exercise considerable discretion in the timing and scope of permit issuance and the public may engage in the permitting process, including through intervention in the courts. Negative public perceptionfactors could also cause the permits we need to conduct our operations to be challenged, withheld, delayed, or burdened by requirements that restrict our ability to profitably conduct our business.

Our operations are subject to extensive federal, state and local laws and regulations, including drilling permittingand environmental and safety laws and regulations, and those relating towhich increase the generation, storage, handling, emission, transportation and discharge of materials into the environment. These laws and regulations can adversely affect the cost manner or feasibility of doing business. Many laws and regulations require permits for the operation of various facilities, and these permits are subject to revocation, modification and renewal. Governmental authorities have the power to enforce compliance with their regulations, and violations could subject us to fines, injunctions or both. These laws and regulations have increased the costs of planning, designing, drilling, installing and operating oil and natural gas and oil facilities, and newfacilities. New laws and regulations or revisions or reinterpretations of existing laws and regulations could further increase these costs. In addition, we may be liable for environmental damages caused by previous owners or operators of property we purchase or lease. Riskscosts, could increase our liability risks, and could result in increased restrictions on oil and gas exploration and production activities, which could have a material adverse effect on us and the oil and gas industry as a whole. Risk of substantial costs and liabilities related to environmental and safety matters in particular, including compliance issues, environmental contamination and claims for damages to persons or property, are inherent in oil and natural gas and oil operations. For example, we could be required to install expensive pollution control measures or limit or cease activities on lands located within wilderness, wetlands or other environmentally or politically sensitive areas. Failure to comply with applicable environmental and safety laws and regulations also may result in the suspension or termination of our operations and subject us to administrative, civil and criminal penalties as well as the imposition of corrective action requirements and orders. Furthermore, due to the outcome of the 2020 U.S. congressional and presidential elections, potential increased restrictions on oil and gas production activities may result, which could have a material adverse effect on the oil and gas industry as a whole. For example, in January 2021, the Biden administration issued an executive order directing all federal agencies to review and take action to address any federal regulations, orders, guidance documents, policies and any similar agency promulgated during the prior administration that may

For additional information, please read “Business and liabilities.Properties—Other Business Matters—Regulation of Oil and Natural Gas Exploration and Production,” “—Regulation of Natural Gas Marketing, Gathering and Transportation,” and “—Environmental and Safety Regulations” in Items 1 and 2.

Water is an essential component of oil and natural gas production during the drilling process. In particular, we use a significant amount of water in the hydraulic fracturing process. Our inability to locate sufficient amounts of water, or dispose of or recycle water used in our exploration and production operations, could adversely impact our operations. For water sourcing, we first seek to use non-potable water supplies for our operational needs. In certain areas, there may be insufficient local aquifer capacity to provide a source of water for drilling activities. Water must then be obtained from other sources and transported to the drilling site. An inability to secure sufficient amounts of water or to dispose of or recycle the water used in our operations could adversely impact our operations in certain areas. The imposition of new environmental regulations, including as a result of potential regulatory and legislative changes due to the outcome of the 2020 U.S. congressional and presidential elections, could further restrict our ability to conduct operations such as hydraulic fracturing by restricting the disposal of waste such as produced water and drilling fluids. Compliance with environmental regulations and permit requirements governing the withdrawal, storage and use of surface water or groundwater necessary for hydraulic fracturing of wells may increase our operating costs and cause delays, interruptions or termination of our operations, the extent of which cannot be predicted, all of which could have an adverse effect on our operations and financial condition.

For example, in April 2011, the Pennsylvania Department of additional information, please read “Business and Properties—Other Business Matters—Environmental Protection (the PaDEP) called on all Marcellus Shale natural gas drilling operators to voluntarily cease by May 19, 2011 delivering wastewater to those centralized treatment facilities that were grandfathered from the application of PaDEP's Total Dissolved Solids regulations. In June 2016, the EPA published final pretreatment standards for disposal of wastewater produced from shale gas operations to publicly owned treatment works. The regulations were developed under the EPA's Effluent Guidelines Program under the authority of the and Safety Regulations—Clean Water Act. In response to these actions, operators including us have begun to rely more on recycling of flowbackAct” in Items 1 and produced water from well sites as a preferred alternative to disposal.

Studies have found that emission of certain gases, commonly referred to as GHGs impact the earth’s climate. The U.S. Congress and seismic activity in recent years. Similar concernsvarious states have been raised that hydraulic fracturing may also contribute to seismic activity. When caused by human activity, such events are called induced seismicity. In March 2016, the United States Geological Survey identified six states with the most significant hazards from induced seismicity, including Oklahoma, Kansas, Texas, Colorado, New Mexico,evaluating, and Arkansas. In light of these concerns,in some state regulatory agencies have modified their regulations or issued orders to address induced seismicity. Certain environmentalcases implementing, climate-related legislation and other groups have also suggestedregulatory initiatives that additional federal, state and local laws and regulations may be needed to more closely regulate the hydraulic fracturing process. We cannot predict whether additional federal, state or localrestrict GHG emissions. These actions as well as any future laws or regulations applicablethat regulate or limit GHG emissions from our equipment and operations could require us to hydraulic fracturing will be enacted in the futuredevelop and if so, what actions any such laws or regulations would require or prohibit. Increased regulation and attention given to induced seismicity could lead to greater opposition to, and litigation concerning, oil and gas activities utilizing hydraulic fracturing or injection wells for waste disposal, which could have an adverse effect on oil and natural gas production activities, including operational delays or increased operating costs in the production of oil and natural gas from developing shale plays, or could make it more difficult to perform hydraulic fracturing.

Furthermore, we could also face an increased risk of climate‐related litigation or “greenwashing” suits with respect to our operations, disclosures, or products. Claims have been made against certain energy companies alleging that GHG emissions from oil, gas and NGL operations constitute a public nuisance under federal and state law. Private individuals or public entities also could attempt to enforce environmental laws and regulations against us and could seek personal injury and property damages or other remedies. Additionally, governments and private parties are also increasingly filing suits, or initiating regulatory action, based on allegations that certain public statements regarding ESG-related matters by companies are false and misleading “greenwashing” campaigns that violate deceptive trade practices and consumer protection statutes or that climate-related disclosures made by companies are inadequate. Similar issues can also arise when aspirational statements such as net-zero or carbon neutrality targets are made without clear plans. Although we are not a party to any such climate-related or “greenwashing” litigation currently, unfavorable rulings against us in any such case brought against us in the future could significantly impact our operations and could have an adverse effectimpact on our operationsfinancial condition.

The regulatory environment surrounding data protection laws is uncertain. Complying with varying jurisdictional requirements could increase the costs and complexity of compliance, and violations of applicable data protection laws can result

Any failure, or perceived failure, by us to comply with applicable data protection laws could result in proceedings or actions against us by governmental entities or others, subject us to significant fines, penalties, judgments and negative publicity, require us to change our business practices, increase the costs and complexity of compliance and adversely affect our business. As noted above, we are also subject to the possibility of security and privacy breaches, which themselves may result in a violation of these laws. Additionally, the acquisition of a company that is not in compliance with applicable data protection laws may result in a violation of these laws.

SubstantivePeriodically U.S. legislators propose substantive changes to existing federal income tax laws have been proposed that if adopted, would repeal many tax incentives and deductions that are currently used by U.S. oil and gas companies and would impose new taxes. ThePast proposals include:have included repeal of the percentage depletion allowance for oil and natural gas properties; elimination of the ability to fully deduct intangible drilling costs in the year incurred; and increase in the geological and geophysical amortization period for independent producers. The Biden administration hasThese proposals have also previously provided informal guidance on certainincluded general tax law changes that it would support, which includes, among other things, raisingto raise tax rates on both domestic and foreign income and imposing a new alternative minimum tax on book income. Further, many states are currently in deficits, and have been enacting laws eliminating or limiting certain deductions, carryforwards, and credits in order to increase tax revenue.

Should the U.S. or the states pass tax legislation limiting any currently allowed tax incentives and deductions, our taxes would increase, potentially significantly, which would have a negative impact on our net income and cash flows. This could also reduce our drilling activities in the U.S. Since future changes to federal and state tax legislation and regulations are unknown, we cannot knowpredict the ultimate impact such changes may have on our business.

Our charter authorizes our Board of Directors to set the terms of preferred stock. In addition, Delaware law contains provisions that impose restrictions on business combinations with interested parties. Our bylaws prohibit the calling of a special meeting by our stockholders and place procedural requirements and limitations on stockholder proposals at meetings of stockholders. Because of these provisions of our charter, bylaws and Delaware law, persons considering unsolicited tender offers or other unilateral takeover proposals may be more likely to negotiate with our Board of Directors rather than pursue

The Delaware General Corporation Law allows corporations to limit available relief for the breach of directors'directors’ duty of care to equitable remedies such as injunction or rescission. Our charter limits the liability of our directors to the fullest extent permitted by Delaware law. Specifically, our directors will not be personally liable for monetary damages for any breach of their fiduciary duty as a director, except for liability:

This limitation may have the effect of reducing the likelihood of derivative litigation against directors and may discourage or deter stockholders or management from bringing a lawsuit against directors for breach of their duty of care, even though such an action, if successful, might otherwise have benefited our stockholders.

None.

We are involved in various legal proceedings incidental to our business. The information set forth under the heading "Legal Matters"“Legal Matters” in Note 98 of the Notes to the Consolidated Financial Statements included in Item 8 of this Annual Report on Form 10-K is incorporated by reference in response to this item.

From time to time we receive notices of violation from governmental and regulatory authorities, in areas in which we operateincluding notices relating to alleged violations of environmental statutes or the rules and regulations promulgated thereunder. While we cannot predict with certainty whether these notices of violation will result in fines, and/penalties or penalties,both, if fines and/or penalties are imposed, they may result in monetary sanctions, individually or in the aggregate, in excess of $300,000.

Not applicable.

The following table shows certain information as of February 17, 202123, 2024 about our executive officers, as such term is defined in Rule 3b-7 of the Securities Exchange Act of 1934, and certain of our other officers.

Mr. Jorden was appointed Chief Executive Officer and President of Coterra following the Merger with Cimarex in October 2021 and Chairman of the executive officers have been employedBoard of Coterra in November 2022. Mr. Jorden previously served as the Chief Executive Officer and President of Cimarex beginning September 2011 and as Chairman of the Board of Directors of Cimarex beginning August 2012. At Cimarex, he began serving as Executive Vice President of Exploration when the company formed in 2002. Prior to the formation of Cimarex, Mr. Jorden held multiple leadership roles at Key Production Company, Inc. (“Key”), which was acquired by Cimarex in 2002. He joined Key in 1993 as Chief Geophysicist and subsequently became Executive Vice President of Exploration. Before joining Key, Mr. Jorden served at Union Pacific Resources and Superior Oil Company.

Mr. Hlavinka was appointed Vice President of the Marcellus Business Unit in April 2022. Since joining Coterra, formerly Cabot Oil & Gas Corporation, in 1989, he has served in engineering and management roles across the Company’s operations, in multiple producing basins. Mr. Hlavinka worked initially as a Facility Engineer and District Superintendent in the Company’s West Virginia production operations, and subsequently as a Corporate Reservoir Engineer in Houston, Texas. In 2006 he was named West Region Engineering Manager for at least the last five years, exceptRocky Mountain and Mid-Continent operating areas, and in 2009 he was promoted to Regional Operations Manager for Mr. Julius Leitner.the North Region, with responsibility for Appalachian Basin operations and engineering.