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, seerefer to the Supplemental Oil and Gas Information to the Consolidated Financial Statements included in Item 8 and “Risk Factors-OurFactors—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.

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 extensiveconcentrated 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 yearsyear ended December 31, 2017, 2016 and 2015,2023, two customers accounted for approximately 18%19 percent and 11%,17 percent of our total sales. During the year ended December 31, 2022, two customers accounted for approximately 19%13 percent and 10% and two customers accounted for approximately 16% and 14%, respectively,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.been significant.

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

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 $1,000,000$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 approximately $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.

Some of our pipelines were subject to regulation byUnder the FERC during 2017. Until September 29, 2017, we owned an intrastateNGPA, natural gas pipeline through our former wholly-owned subsidiary, Cranberry Pipeline Corporation, that provided interstate transportation and storage services pursuant to Section 311 ofgathering facilities are expressly exempt from FERC jurisdiction. What constitutes “gathering” under the NGPA as well as intrastate transportationhas evolved through FERC decisions and storage servicesjudicial review of such decisions. We believe that were regulated byour gathering and production facilities meet the West Virginia Public Service Commission. We no longer own any interest in Cranberry Pipeline Corporation, and do not operate any natural gas pipelines subject to FERC's jurisdiction.

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 rulemakingsrule 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

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‑affiliatednon-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 swapregulate the over-the-counter (“OTC”) derivatives market (which includes the sorts of financial instruments we use) and participants in that market. We endeavor to ensure that our OTC derivatives transactions including certain options. Thecomply with applicable CFTC 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. In addition, all swap market participants are subject to new reporting and recordkeeping requirements related to their swap transactions. Weregulations. Although the CFTC does not currently require the clearing of OTC commodity derivatives transactions of the types that we use, we believe that our use of swaps to hedge against changes in commodity exposureprices qualifies us as ana commercial end‑user, exemptingwhich would exempt us from the requirementa future requirements to centrally clear our commodity swaps. Nevertheless, future changes to the swap market as a result of Dodd‑Frank implementationin CFTC regulations 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.

Our salesSales 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 re‑determination,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%1.23 percent should be the oil pricing index

We generate some hazardous wastes that are alreadyhazardous wastes subject to the Federal Resource Conservation and Recovery Act (RCRA)(the “RCRA”) and comparable state statutes.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 its RCRA Subtitle D criteria regulations exempting certainthe need to regulate exploration and production related oil and gas wastes exempt from regulation as hazardous wastes under RCRA.RCRA under Subtitle D applicable to non-hazardous solid waste. The consent decree requiresrequired 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. WeIn 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 therefore, be subject to more rigorous and costly disposal requirements in the future than we encounter today.

Some of our producing wells and associated facilities are subject to restrictive air emission limitations and permitting requirements. In 2012,Two examples are the EPA published finalEPA’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 may result in increased complexity and cost of, and time required for, air permitting. Particularly with respect to obtaining pre-construction permits, the final aggregation rule has added costs and caused delays in operations.

In 2012, the EPA published final NSPS and NESHAP that amended the existing NSPS and NESHAP standards for oil and gas facilities and created new NSPS standards forthe oil and natural gas production, transmission and distribution facilities.sector. In June 2016, the EPA published a final rule that updatesupdated and expandsexpanded 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 addition, 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. TheIn March 2018, the EPA also 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. On June 30, 2021, President Biden signed into law a joint Congressional resolution under the Congressional Review Act disapproving the September 2020 rule amending the EPA’s 2012 and 2016 NSPS standards for the oil and natural gas sector. On November 15, 2021, the EPA proposed rules to reduce methane emissions from both 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 June 2016 concerning aggregation of sources that affects source determinations for air permitting inthe 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 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 could resultresulted 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 anticipates promulgatingcompleted its final area designations under the new ozone standard in the first half ofJuly 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

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. The publicInformation 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 read and copy materials that we file with or furnish to the SEC at(and is not deemed filed herewith), whether before or after the SEC’s Public Reference Room located at 100 F Street, NE, Washington, DC 20549. Information regarding the operationdate of the Public Reference Room canthis Annual Report on Form 10-K and irrespective of any general incorporation language therein. Furthermore, references to our website URLs are intended to be obtained by calling the SEC at 1‑800‑SEC‑0330.inactive textual references only.

Our Corporate Governance Guidelines, Corporate Bylaws,Code of Business Conduct and Ethics, Audit Committee Charter, Compensation Committee Charter, Corporate Governance and NominationsSocial Responsibility Committee Charter Code of Business Conduct and Environment, Health & Safety and Environmental Affairs 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 oilNGLs that we sell. Lower commodity prices may reduce the amount of oil, natural gas and oilNGLs that we can produce economically.economically, while higher commodity prices could cause us to experience periods of higher costs. Historically, natural gas and oilcommodity prices have been volatile, with prices fluctuating widely, and they are likely to continue to be volatile. Because our reserves are predominantlyWide fluctuations in commodity prices may result from relatively minor changes in the supply of and demand for oil, natural gas (approximately 96%and NGLs, market uncertainty and a variety of equivalent proved reserves), changesadditional 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 than oil prices.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 natural gas or crude oilcommodity prices would have a material adverse effect on our future business, financial condition, results of operations, cash flows, liquidity or ability to finance planned capital expenditures and commitments. Furthermore, substantial, extended decreases in natural gas and crude oilIf 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. See "Risk Factors-Future natural gas and oil 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 prices of natural gas and crude oil.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 our reserves are predominately natural gas (approximately 96% of equivalent proved reserves), changes in natural gas prices have a more significant impact on our financial results than oil prices.

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 natural gas and oilcommodity 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 properties are geographically concentrated ingrowth is materially dependent upon the Marcellus Shale in northeast Pennsylvania. At December 31, 2017, 97%success of our proved developed reservesdrilling program. Drilling for oil and 94%natural gas involves numerous risks, including the risk that no commercially productive reservoirs will be encountered. The cost of our total equivalent production were attributable our properties located in the Marcellus Shale,drilling, completing and we expect that concentration to increase slightly in 2018operating wells is substantial and uncertain, and drilling operations may be curtailed, delayed or canceled as a result of the expected salesa 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.

The scope and nature of our remaining Texas propertiesoperations present a variety of significant hazards and risks, including operational hazards and risks such as explosions, fires, product spills, and cybersecurity incidents, such as unauthorized access to data or systems, among other risks. Our operations are also subject to broader global events and conditions, including public health crises, pandemics, epidemics, war or civil unrest, acts of terror, weather events and natural disasters, including those that are related to

Reserves engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact manner. The process of estimating quantities of proved reserves is complex and inherently imprecise, and the reserves data included in this concentration, wedocument are only estimates. The process relies on interpretations of available geologic, geophysical, engineering and production data. The extent, quality and reliability of this technical data can vary. The process also requires certain economic assumptions, some of which are mandated by the SEC, such as assumptions relating to commodity prices. Additional assumptions include drilling and operating expenses, capital expenditures, taxes and availability of funds. Furthermore, different reserve engineers may make different estimates of reserves and cash flows based on the same data. For example, our total company proved reserves decreased by approximately 17 percent year over year at December 31, 2022. For more information on such revision, refer to the Supplemental Oil and Gas Information included in Item 8.

Results of drilling, testing and production subsequent to the date of a reserves estimate may justify revising the original estimate. Accordingly, initial reserves estimates often vary from the quantities of oil and natural gas that are ultimately recovered, and such variances may be disproportionately exposed tomaterial. Any significant variance could reduce the impactestimated quantities and present value of regional supply and demand factors, state and local  political forces and governmental regulation, processing or transportation capacity constraints,our reserves.

You should not assume that the present value of future net cash flows from our proved reserves is the current market limitations, severe weather events, water shortages or other conditions or interruptionvalue 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 processing or transportationmonth price for each month and costs in effect on the date of oil, natural gas or NGLsthe 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 region. 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.

In general, the production rate of natural gas and oil 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 and oil production and lower revenues and cash flow from operations. Our future natural gas and oil 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 natural gas and oilcommodity prices may further limit the kinds of reserves that we can develop and produce economically.

As of December 31, 2017, we had2023, approximately $1.5 billion of debt outstanding and we may incur additional indebtedness in the future. Increases in our level of indebtedness may:

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 20182024 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 20182024 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 oilNGL 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 oilNGL 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 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 natural gas and oilcommodity 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, 2017,2023, non-operated wells represented approximately 14.7%51 percent of our total owned gross wells, or approximately 3.8%12 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.

In addition, certain cyber incidents, such as reconnaissance campaigns, may remain undetected for desirable natural gasan extended period, and oil properties, as well asour systems and insurance coverage for the capital, equipmentprotecting against such cybersecurity risks may be costly and labormay not be sufficient. As cyber-attackers become more sophisticated, we may be required to operateexpend significant additional resources to continue to protect our business or remediate the damage from cyber-attacks. Furthermore, the continuing and develop these properties. Our competitive position is affected by price, contract termsevolving threat of cyber-attacks has resulted in increased regulatory focus on prevention, mitigation, and quality of service, including pipeline connection times, distribution efficienciesnotification, and reliable delivery record. Many ofwe may be required to expend significant additional resources to continue to modify or enhance our competitorsprotective measures or to investigate and remediate any information security vulnerabilities. To the extent we face increased regulatory requirements, we may be required to expend significant additional resources to meet such requirements.

We make and expect to make substantial capital expenditures in connection with our development and production projects. We rely on access to both our revolving credit agreement and longer-term capital markets as sources of liquidity for exploratory projectsany capital requirements not satisfied by cash flow from operations or other sources. Adverse economic and productive natural gasmarket conditions, could adversely affect our ability to access such sources of liquidity. Future challenges in the global financial system may adversely affect the terms on which we are able to obtain financing, which could impact our business, financial condition and oil propertiesaccess to capital. Our ability to access the capital markets may be restricted at a time when we want or need to raise capital, which could have an impact on our flexibility to react to changing economic and business conditions. Additionally, such adverse economic and market conditions could impact our counterparties, including our receivables and our hedging counterparties, who may, as a result of such conditions, be unable to perform their obligations.

Our debt agreements also require compliance with covenants to maintain specified financial ratios. If commodity prices deteriorate from current levels, 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 modify our capital program, sell non-strategic assets or opportunistically modify or increase our derivative 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 define, evaluate, bid forsuccessfully execute any of these strategies, and purchase a greater number of properties and prospects than our financial or human resources permit. In addition, these companiessuch strategies may be able to expend greater resourcesunavailable on the existingfavorable terms or at all. For more information about our debt agreements, please read “Management’s Discussion and changing technologies that we believe will be increasingly important to attaining success in the industry. These companies may also have a greater ability to continue drilling activities during periodsAnalysis of low natural gasFinancial Condition and oil pricesResults of Operations-Financial Condition-Liquidity and to absorb the burden of current and future governmental regulations and taxation.Capital 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 and crude oil 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 operate.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

Further, negative public perception regarding us and our industry resulting from, among other things, concerns raised by advocacy groups about climate change impacts of methane and other professionals. Competitiongreenhouse gas emissions, hydraulic fracturing, oil spills, 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 experienced geologists, engineersour oil, natural gas and some other professionals is extremely intense. IfNGL production, reduced profits, increased regulation, regulatory investigations and litigation, and negative impacts on our stock and debt prices and access to capital markets. These factors could also cause the permits we cannot retainneed to conduct our technical personneloperations to be challenged, withheld, delayed, or attract additional experienced technical personnel,burdened by requirements that restrict our ability to compete could be harmed.profitably conduct our business.

Most of our exploration and productionOur operations depend on the use of hydraulic fracturing to enhance production from oil and gas wells. This technology involves the injection of fluids—usually consisting mostly of water but typically including small amounts of several chemical additives—as well as sand or other proppants into a well under high pressure in order to create fractures in the rock that allow oil or gas to flow more freely to the wellbore. Most of our wells would not be economical without the use of hydraulic fracturing to stimulate production from the well. Hydraulic fracturing operations have historically been overseen by state regulators as part of their oil and gas regulatory programs; however, the EPA has asserted federal regulatory authority over certain hydraulic fracturing activities involving diesel under the Safe Drinking Water Act and has released permitting guidance for hydraulic fracturing activities that use diesel in fracturing fluids in those states where EPA is the permitting authority, including Pennsylvania. As a result, we may beare subject to additional permitting requirements for hydraulic fracturing operations as well as various restrictions on those operations. These permitting requirements and restrictions could result in delays in operations at well sites as well as increased costs to make wells productive. In addition, from time to time, legislation has been introduced, but not enacted, in Congress that would provide for federal regulation of hydraulic fracturing under the Safe Drinking Water Act and require the public disclosure of certain information regarding the chemical makeup of hydraulic fracturing fluids. If enacted, this legislation could establish an additional level of regulation and permitting at the federal, state or local levels, and could make it easier for third parties opposed to the hydraulic fracturing process to initiate legal proceedings based on allegations that specific chemicals used in the fracturing process could adversely affect the environment, including groundwater, soil or surface water. In March 2015, the Department of the Interior's Bureau of Land Management issued a final rule to regulate hydraulic fracturing on public and Indian land; however, these rules were rescinded by rule in December 2017. We voluntarily disclose on a well-by-well basis the chemicals we use in the hydraulic fracturing process at www.fracfocus.org.

Water is an essential component of oil and natural gas production activities, including operational delays or increased operating costs induring the production of oil and natural gas from developing shale plays, or could make it more difficult to perform hydraulic fracturing.

For example, in April 2011, 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 additional information, please read “Business and Properties—Other Business Matters—Environmental and Safety Regulations—Clean Water Act. In response to these actions, operators including us have begun to rely more on recyclingAct” in Items 1 and 2.

Studies have found that emission of certain gases, commonly referred to as GHGs impact the earth’s climate. The U.S. Congress and various states have been evaluating, and in some cases implementing, climate-related legislation and other regulatory initiatives that restrict GHG emissions. These actions as well as any future laws or regulations that regulate or limit GHG emissions from our equipment and operations could require us to develop and implement new practices aimed at reducing GHG emissions, such as emissions control technologies, and to monitor and report GHG emissions associated with our operations, any of which could increase our operating costs and could adversely affect demand for the oil and gas that we produce. At this time, it is not possible to quantify the impact of such future laws and regulations on our business.

For additional information, please read “Business and Properties—Other Business Matters—Environmental and Safety Regulations—Greenhouse Gas and Climate Change Laws and Regulations” in Items 1 and 2.

Furthermore, we could also face an increased risk of the regions in which we operate, all of which can create financial risks. In addition, legislative and regulatory responses 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 climate change may increase our operating costs. The United States Congress has previously considered legislation relatedNGL operations constitute a public nuisance under federal and state law. Private individuals or public entities also could attempt to GHG emissions. There haveenforce environmental laws and regulations against us and could seek personal injury and property damages or other remedies. Additionally, governments and private parties are also been international efforts seeking legally binding reductions in GHG emissions. The United States was actively involved in the negotiations at the 21st Conference of the Parties of the United Nations Framework Convention on Climate Change in Paris, which led to the creation of the Paris Agreement. The Paris Agreement requires countries to review and "represent a progression" in their nationally determined contributions, which set emissions reduction goals, every five years. The United States signed the Paris Agreement in April 2016. However, on August 4, 2017, the United States formally communicated to the United Nations its intent to withdraw from participation in the Paris Agreement, which entails a four-year process. In response to the announced withdrawal plan, a number of state and local governments in the United States have expressed intentions to take GHG-related actions. Increased public awareness and concern regarding climate change may result in more state, regional and/increasingly filing suits, or federal requirements to reduce or mitigate GHG emissions.

The threatregulatory environment surrounding data protection laws is uncertain. Complying with varying jurisdictional requirements could increase the costs and complexity of terrorismcompliance, and the impactviolations of militaryapplicable data protection laws can result in significant penalties. A determination that there have been violations of applicable data protection laws could expose us to significant damage awards, fines and other action have caused instabilitypenalties that could materially harm our business and reputation.

Any failure, or perceived failure, by us to comply with applicable data protection laws could result in world financial marketsproceedings or actions against us by governmental entities or others, subject us to significant fines, penalties, judgments and could leadnegative publicity, require us to increased volatility in prices for natural gaschange our business practices, increase the costs and oil, allcomplexity of which could adversely affect the markets for our operations. Acts of terrorism, including cybersecurity threats to gain unauthorized access to sensitive information or to render data or systems unusable, could be directed against companies operating in the United States. The U.S. government has issued public warnings that indicate energy assets might be specific targets of terrorist organizations. These developments have subjected our operations to increased riskcompliance and depending on their ultimate magnitude, could have a material adverse effect on our business.

On December 22, 2017, thePeriodically U.S. enacted legislation referredlegislators propose substantive changes to as the Tax Cuts and Jobs Act (the "Tax Act"). The Tax Act significantly changes U.S. corporateexisting federal income tax laws beginning, generally, in 2018. These changes include, among others, (i) a permanent reduction of the U.S. corporate income tax rate from a top marginal rate of 35% to a flat rate of 21%, (ii) elimination of the corporate alternative minimum tax, (iii) immediate deductions for certain new investments instead of deductions for depreciation expense over time, (iv) limitation on the tax deduction for interest expense to 30% of adjusted taxable income, (v) limitation of the deduction for net operating losses to 80% of current year taxable income and elimination of net operating loss carrybacks, and (vi) elimination ofthat would repeal many business deductions and credits, including the domestic production activities deduction, the deduction for entertainment expenditures, and the deduction for certain executive compensation in excess of $1 million. Refer to Note 10 of the Notes to the Consolidated Financial Statements, "Income Taxes" for additional discussion on the impact of the Tax Act on the Company. In the absence of guidance on various uncertainties and ambiguities in the application of certain provisions of the Tax Act, we will use what we believe are reasonable interpretations and assumptions in applying the Tax Act. Overall, we expect the provisions of the Tax Act to favorably impact the Company's future effective tax rate, after-tax earnings, and cash flows. However, it is possible that the Internal Revenue Service could issue subsequent guidance or take positions on audit that differ from our prior interpretations and assumptions, which could adversely impact our financial position, results of operations, and cash flows.

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 non-negotiated takeover attempts. As a result, these provisions may make it more difficult for our stockholders to benefit from transactions that are opposed by an incumbent Board of Directors.

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 $100,000.$300,000.

Not applicable.

The following table shows certain information as of February 22, 201823, 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, except for Mr. Charles E. Dyson IIRocky Mountain and Mr. Julius Leitner.

Mr. Roemer was appointed Vice President of Information Servicesand Chief Accounting Officer in February 2018.  Prior to joining the Company, heJuly 2019. Mr. Roemer previously served as the Director of Infrastructure and Support Services at Transocean Offshore Deepwater Drilling, Inc. Mr. Dyson holds a Bachelor of Business Administration degree in Finance from Texas A&M University. 

Mr. Smith was appointed Vice President and Chief Technology Officer following the Merger with Shell Energy North America (US) L.P.,Cimarex in October 2021. Mr. Smith began his career with Cimarex in 2007, serving in a number of technical and leadership roles, including Director of Northeast Trading, DirectorTechnology and Anadarko Exploration Region Manager. In September 2020, Mr. Smith assumed the role of Producer Services, and Senior Originator, from July 1996 through July 2017. Mr. Leitner holds a BachelorChief Engineer for Cimarex.