TheThis report includes forward-looking statements within the meaning of federal securities laws. All statements, other than statements of historical fact, included in this report are forward-looking statements. Such forward-looking statements include, but are not limited to, statements regarding future financial and operating performance and results, the anticipated effects of, and certain other matters related to, the merger involving Cimarex Energy Co. (“Cimarex”), strategic pursuits and goals, market prices, future hedging and risk management activities, and other statements that are not historical facts contained in this report are forward-looking statements.report. The words "expect," "project," "estimate," "believe," "anticipate," "intend," "budget," "plan," "forecast," "target," "predict," "may," "should," "could," "will"“expect,” “project,” “estimate,” “believe,” “anticipate,” “intend,” “budget,” “plan,” “forecast,” “target,” “predict,” “potential,” “possible,” “may,” “should,” “could,” “would,” “will,” “strategy,” “outlook” and similar expressions are also intended to identify forward-looking statements. SuchWe can provide no assurance that the forward-looking statements contained in this report will occur as expected, and actual results may differ materially from those included in this report. Forward-looking statements are based on current expectations and assumptions that involve a number of risks and uncertainties including, but not limitedthat could cause actual results to 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 onof public health crises, including pandemics (such as the coronavirus (“COVID-19”) pandemic) and epidemics and any related company or governmental policies or actions, the risk that our business, financial condition and results of operations,Cimarex’s businesses will not be integrated successfully, the risk that the cost savings and any other synergies from the merger involving Cimarex may not be fully realized or may take longer to realize than expected, the availability of cash on hand and other sources of liquidity to fund our capital expenditures, actions by, or disputes among or between, members of the Organization of Petroleum Exporting Countries and other exporting nations (OPEC+)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 pandemics and geopolitical disruptions such as the war in Ukraine, 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,” “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 20212023 capital program is expected to be approximately $530.0 million$2.0 billion to $540.0 million, representing a six percent reduction, at the midpoint of the range, from our 2020 capital program of $569.8 million. We reduced our planned capital expenditures, which contemplates a maintenance capital program, as a result of the weaker natural gas price environment.$2.2 billion. We expect to fund these expenditures withturn-in-line 150 to 175 total net wells in 2023 across our three operating cash flowregions. Approximately 49 percent of our drilling and if required, cash on hand.

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

Our Marcellus Shale properties represent our primary operating area and are principally located in Susquehanna County, Pennsylvania, where we currently hold approximately 175,000183,000 net acres in the dry gas window ofin the play.Marcellus Shale. Our 20202022 net production in the Marcellus Shale was 857 Bcfe,367 MBoepd, representing substantially all58 percent of our total equivalent production for the year. As of December 31, 2020,2022, we had a total of 865.91,024.2 net wells in the Marcellus Shale, of which approximately 99.599 percent are operated by us.

During 2020,2022, we invested $562.1$813 million in the Marcellus Shale, and drilled or participated in drilling 64.3 net wells, completed 77.3 net wells and turned in line 69.2 net wells. As of December 31, 2020,where we had 13.0 net wells that were either in the completion stage or waiting on completion or connection to a pipeline. We exited 20202022 with threetwo drilling rigs operating in the play and plan to exit 20212023 with two rigs operating.

In July 2018,Our Anadarko Basin properties are principally located in Oklahoma where we sold certain provedcurrently hold approximately 182,000 net acres in the play. Our development activities are primarily focused on the Woodford Shale and unprovedthe Meramec formation, both in Oklahoma. Our 2022 net production in the Anadarko Basin was 55 MBoepd, representing nine percent of our total equivalent production for the year. As of December 31, 2022, we had a total of 511.4 net wells in the Anadarko Basin, of which approximately 60 percent are operated by us.

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

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

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

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

During 2020,2022, natural gas collars with floor prices ranging from $1.90$1.70 to $2.15$8.50 per MmbtuMMBtu and ceiling prices ranging from $2.10 to $2.38$13.08 per MmbtuMMBtu covered 92.3245.8 Bcf, or 1124 percent, of natural gas production at a weighted-average price of $2.09$4.94 per Mmbtu.MMBtu. Natural gas swaps covered 53.514.9 Bcf, or sixone percent, of natural gas production at a weighted-average price of $2.24$2.26 per Mmbtu.MMBtu.

As of December 31, 2020,2022, we had the following outstanding financial commodity derivatives:

A significant portion of our expected oil and natural gas production for 20212023 and beyond is currently unhedged and directly exposed to the volatility in oil and natural gas prices, whether favorable or unfavorable. We will continue to evaluate the benefit of using derivatives in the future. Please read "Management's“Management’s Discussion and Analysis of Financial Condition and Results of Operations"Operations” and "Quantitative“Quantitative and Qualitative Disclosures about Market Risk"Risk” for further discussion related to our use of derivatives.

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 customary mineral leases. These leases provide us the right to develop oil and/or natural gas on the properties. Their primary terms generally range in length from approximately three to 10 years. These properties are held for longer periods if 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 a commercial well will hold the acreage beyond the expiration.

At December 31, 2020 is 13,515, 3,947 and 4,371 for the years ending December 31, 2021, 2022, and 2023, respectively.

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

The following table sets forth information about wells for which drilling was in progress or which were drilled but uncompleted at December 31, 2020,2022, which are not included in the above table:

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

The oil and gas industry is highly competitive, and we experience strong competition in our primary producing areas. We primarily compete with integrated, independent and other energy companies for the sale and transportation of our oil and natural gas production to pipelines, marketing companies and end users. Furthermore, the oil and gas industry competes with other energy industries that supply fuel and power to industrial, commercial and residential consumers. Many of these competitors have greater financial, technical and personnel resources.resources than we have. The effect of these competitive factors cannot be predicted.

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

During the year ended December 31, 2020, three2022, two customers accounted for approximately 21 percent, 1613 percent and 1211 percent of our total sales. During the year ended December 31, 2019, three customers2021, no customer accounted for approximately 17 percent, 16 percent and 16more than 10 percent of our total sales. During the year ended December 31, 2018, two customers accounted for approximately 20 percent and 11 percentIf any one of our total sales. major customers were to stop purchasing our production, we believe there are a number of other purchasers to whom we could sell our production. If multiple significant customers were to stop purchasing our production, we believe there could be some initial challenges, but we have sufficient alternative markets to handle any sales disruptions.

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

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

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 gatheringthat our facilities are not subject to federal regulations. Although exempt from FERC jurisdiction; however,oversight, our natural gas gathering systems and services may receive regulatory scrutiny by state and federal agencies regarding the safety and operating aspects of the transportation and storage activities of these facilities.

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 of theThe Dodd‑Frank Wall Street Reform and Consumer Protection Act (Dodd‑(“Dodd‑Frank Act)Act”) enacted comprehensive financial reform, establishing federal oversight over and regulation of the over-the-counter derivatives market (which includes the sorts of financial instruments we use) and participants in July 2010, the market. The Commodity Futures Trading Commission (CFTC)(the “CFTC”) has promulgated regulations to implement statutory requirements for swap

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

Effective January 1, 1995, the FERC implemented regulations generally grandfathering all previously approved interstate transportation rates and establishing an indexing system for those rates by which adjustments are made annually based on the rate of inflation, subject to certain conditions and limitations. These regulations may increase or decrease the cost of transporting crude oil and NGLs by interstate pipeline, although the annual adjustments may result in decreased rates in a given year.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 for the five‑year period beginning July 1, 2016. TheIn 2020, the FERC recently concluded its five-year index review to establish the new adder for crude oil and liquids pipeline rates subject to indexing. The FERC issued an order on December 17, 2020 establishing an index level of Producer Price Index for Finished Goods plus 0.78 percent for the five-year period commencing July 1, 2021. The result of indexing is a “ceiling rate” for each rate, which is the maximum at which the pipeline may set its interstate transportation rates. A pipeline may also file cost‑of‑service based rates if rate indexing will be insufficient to allow the pipeline to recover its costs. Rates are subject to challenge by protest when they are filed or changed. For indexed rates, complaints alleging that the rates are unjust and unreasonable may only be pursued if the complainant can show that a substantial change has occurred since the enactment of Energy Policy Act of 1992 in either the economic circumstances of the pipeline or in the nature of the services provided that were a basis for the rate. There is no such limitation on complaints alleging that the pipeline’s rates or terms and conditions of service are unduly discriminatory or preferential. We are unable to predict with certainty the effect upon us of these periodic reviews by the FERC of the pipeline index, or any potential future challenges to pipelines'pipelines’ rates.

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 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. Listing of the lesser prairie-chicken as a threatened or endangered species will impose restrictions on disturbances to critical habitat by landowners and drilling companies that would harass, harm or otherwise result in a “taking” of this species. Regulatory impacts on landowners and businesses from an ultimate decision to list the lesser prairie-chicken could be limited for those landowners and businesses who have entered into certain range-wide conservation planning agreements, such as those developed by the Western Association of Fish and Wildlife Agencies (“WAFWA”), pursuant to which such parties agreed to take steps to protect the lesser prairie-chicken’s habitat and to pay a mitigation fee if its actions harm the lesser prairie-chicken’s habitat. We have entered into a voluntary Candidate Conservation Agreement (a “CCA”) with the WAFWA, whereby we agreed to take certain actions and limit certain activities, such as limiting drilling on certain portions of our operationsacreage during nesting seasons, in an effort to protect the lesser prairie-chicken.

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

On December 1, 2020, the FWS proposed to list the Peppered Chub as endangered under the ESA. The 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 groups in challengingboth new and existing oil and natural gas industry sources and published supplemental rules regarding the September 2020 rule.same on December 6, 2022. 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 administrative, civil and/or criminal penalties for noncompliance. Obtaining permits may delay the development of our oil and natural gas projects, including the construction and operation of facilities.

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/or 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 could potentially cause a decrease in the completion of new oil and natural gas wells and increased compliance costs, which could increase costs of our operations and cause considerable delays in acquiring regulatory approvals to drill and complete wells. Inpractices.

addition, if existing lawsOur inability to locate sufficient amounts of water, or to dispose of or recycle water used or produced in our exploration and regulations with regardproduction operations, could adversely impact our operations. For water sourcing, we first seek to hydraulic fracturing are reviseduse non-potable water supplies, or reinterpreted or if new lawsrecycled produced water for our operational needs. In certain areas, there may be insufficient water available for drilling and regulations become applicablecompletion activities. Water must then be obtained from other sources and transported to ourthe drilling site. Our operations through judicial or administrative actions, our business, financial condition, results of operations and cash flowsin certain areas could be adversely affected. For additional information aboutimpacted if we are unable to secure sufficient amounts of water or to dispose of or recycle the water used in our operations. The imposition of new environmental and other 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 relateddrilling fluids. Compliance with environmental matters, please read “Risk Factors—Legal, Regulatoryregulations and Governmental Risks—Federalpermit requirements governing the withdrawal, storage and state legislation, judicial actions and regulatory initiatives related to oil and gas development and the use of surface water or groundwater necessary for hydraulic fracturing could result in increasedof wells may increase our operating costs and operating restrictionscause delays, interruptions or delays and adversely affecttermination of our business, financial condition, resultsoperations, the extent of which cannot be predicted, all of which could have an adverse effect on our operations and cash flows” in Item 1A.financial condition. 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 Clean Water Act. In response to these actions, operators, including us, have begun to rely more on recycling of water that flows back from the wellbore following hydraulic fracturing (“flowback water”) and produced water from well sites as a preferred alternative to disposal.

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

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 ourOur ability to attract, retain and develop the highest quality personnelemployees is an importanta vital component of our success. In connection with the Merger, we developed integration plans for every organization and are in the final stages of staff reorganizations, relocations of key employees and hiring of new talent for our corporate headquarters in Houston, Texas. Staff reductions are occurring primarily in our Denver, Colorado office (which will close in 2023) and our Tulsa, Oklahoma office, which will be dedicated to management of our Anadarko Basin operations, with other corporate functions transferred to Houston, Texas. Detailed transition, staffing and knowledge transfer plans have ensured that key aspects of ongoing operations continue uninterrupted through this process. Our staff reorganization plans have eliminated redundancy between the legacy company organizations, and our hiring plans have accelerated our ability to attract and develop a diverse workforce. We believe ourthat the resulting employee levels from our integration plan are appropriate and that we will continue to have the human capital to operate our business and carry out our strategy as determined by management and our Board of Directors.

As of December 31, 2020,2022, we had 503981 total employees, 274283 of whom were associated withlocated in our upstream operations, of which 92 were located at our corporate headquarters in Houston, Texas 88 were located atand our regionalcorporate office in Pittsburgh, Pennsylvania,Denver, Colorado and 94330 of whom were located in our regional offices in Midland, Texas, Tulsa Oklahoma and Pittsburgh, Pennsylvania. We had a total of 368 employees in production field operations in Susquehanna County, Pennsylvania.locations across our regional offices. We had 132 employees that will exit as a result of our integration and transition plans. Of these 274 upstream employees, 214our total employee population, 606 were salaried and 60375 were hourly. In addition to our upstream employees, we had 229We also have 244 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 216228 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:

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 2022 Sustainability Report, is not a part of, and is not incorporated into, this 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 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 Relations at our corporate headquarters at Three Memorial City Plaza, 840 Gessner Road, Suite 1400, Houston, Texas 77024.

Our revenues, operating results, financial condition and ability to borrow funds or obtain additional capital depend substantially on prices we receive for the oil, natural gas and NGLs that we sell. Lower commodity prices may reduce the amount of oil, natural gas and NGLs that we can produce economically.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 the COVID-19 pandemic, the war in natural gas prices have a more significant impact on our financial results.Ukraine 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 such projects uneconomic, which may result in significant downward adjustments to our estimated proved reserves and could negatively impact our ability to borrow and cost of capital and our ability to access capital markets, increase our costs under our revolving credit facility and limit our ability to execute aspects of our business plans. Refer to "Future“Future commodity price declines may result in write-downs of the carrying amount of our oil and gas properties, which could materially and adversely affect our results of operations."”

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

The scope and nature of our operations present a variety of significant hazards and risks, including operational hazards and risks such as explosions, fires, product spills, and cybersecurity incidents and unauthorized access to data or systems, among other risks. Our operations are also subject to broader global events and conditions, including public health crises, pandemic or epidemic, war or civil unrest, acts of terror, weather events and natural disasters, including weather events or natural disasters that are related to or exacerbated by climate change. Such hazards and risks could impact our drilling success rate within a particular geographic area may decline. Webusiness in the areas in which we operate, and our business and operations may be disrupted if we fail to respond in an appropriate manner to such hazards and risks or if we are unable to leaseefficiently restore or drill identified or budgeted prospects withinreplace affected operational components and capacity. Furthermore, our expected time frame, or at all. Weinsurance may not be unableadequate to lease or drill a particular prospect because, in some cases, we identify a prospect or drilling location before seeking an option or lease rights in the prospect or location. Similarly, our drilling schedulecompensate us for all resulting losses. The cost of insurance may vary from our capital budget. The final determination with respect to the drilling of any scheduled or budgeted wells will be dependent on a number of factors, including:

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

Results of drilling, testing and production subsequent to the date of ana reserves estimate may justify revising the original estimate. Accordingly, initial reservereserves estimates often vary from the quantities of oil and natural gas and oil that are ultimately recovered, and such variances may be material. Any significant variance could reduce the estimated quantities and present value of our reserves.

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.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 us or the oil and gas industry in general.

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.

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), 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 20212023 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 20212023 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 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,Moreover, 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 significant oil and natural gas production. Any of these availability or capacity issues could negatively affect our operations, revenues and expenses. In addition, the Marcellus Shale wells we have drilled to date have generally reported very high initial production rates. The amount of natural gas being produced in the area from these new wells, as well as natural gas produced from other existing wells, may exceed the capacity of the various gathering and intrastate or interstate transportation pipelines currently available. In such an event, thisThis 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 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, including via the Merger, 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, 2020,2022, non-operated wells represented approximately nine51 percent of our total owned gross wells, or less than one13 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 on 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 an operator of our wells or joint venture participant to adequately perform operations, an operator'soperator’s breach of the applicable agreements or an operator'soperator’s failure to act in ways that are in our best interest could reduce our production and revenues. Our dependence on the operator and other working interest owners, including a joint venture participant, for these projects and our limited ability to influence or control the operation and future development of these properties 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 offset drilling. We have no control over offsetting operators, who could take actions, such as drilling and completing additional wells, which could adversely affect our competitive position.

We could lose leases under certain circumstances if we do not maintain production in paying quantities or meet other lease requirements, and the 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 stronger or healthier balance sheetslease provisions. In

Our operationsbusiness and the oil and gas industry in general have become increasingly dependent on digital data, computer networks and connected infrastructure, including technologies that are dependent upon a relatively small groupmanaged by third-party providers on whom we rely to help us collect, host or process information. We depend on this technology to record and store financial data, estimate quantities of key managementoil and technical personnel,natural gas reserves, analyze and one or more of these individuals could leave our employment. The unexpected lossshare operating data and communicate internally and externally. Computers control nearly all of the oil and gas distribution systems in the U.S., which are necessary to transport our products to market. Computers also enable communications and provide a host of other support services for our business. In recent years (and, in large part, due to the COVID-19 pandemic), we have increased the use of oneremote networking and online conferencing services and technologies that enable employees to work outside of our corporate infrastructure, which exposes us to additional cybersecurity risks, including unauthorized access to sensitive information as a result of increased remote access and other cybersecurity related incidents.

Cyber-attacks are becoming more sophisticated and include, but are not limited to, malicious software, phishing, ransomware, attempts to gain unauthorized access to data and other electronic security breaches that could lead to disruptions in critical systems, unauthorized release of confidential or moreotherwise protected information and corruption of these individualsdata. Unauthorized access to our seismic data, reserves information, customer or employee data or other proprietary or commercially sensitive information could lead to data corruption, 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 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 systems and related infrastructure, or that of our business associates, 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 surveillance, 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, 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 facility 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, such as actions of the Federal Reserve to raise the target federal funds rate, 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, 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.obligations.