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, 2019 is 78,534, 13,747 and 3,998 for the years ending December 31, 2020, 2021 and 2022, respectively.

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 extensiveconcentrated 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, 2019, three customers accounted for approximately 17 percent, 16 percent and 16 percent of our total sales. During the year ended December 31, 2018,2022, two customers accounted for approximately 2013 percent and 11 percent of our total sales. During the year ended December 31, 2017, two customers2021, no customer accounted for approximately 18 percent and 11more than 10 percent of our total sales. If any one of our 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.been significant.

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 to limit the amounts of oil and natural gas we can produce from our wells, and to limit the number of wells or the locations

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 $1,000,000$1 million per day per violation. This maximum penalty authority established by statute has been and will continue to be adjusted periodically for inflation. As of December 31, 2019, theThe current maximum penalty amount was $1,269,500is over $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 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 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 transactions, including certain options. The CFTCthese reforms. While most of the regulations have been promulgated and are intended to implement a regulated marketalready in which most swaps are

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 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 percent should be the oil pricing index for the five‑year period beginning July 1, 2016. In 2020, the FERC 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.

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. 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. In March 2018, the EPA published a final rule that amended two narrow provisions of the NSPS, including removing the requirement for completion of delayed repair during emergency or unscheduled vent blowdowns. TheIn September 2020, the EPA also published a final rule in June 2016 concerning aggregation of sources that affects source determinations for air permitting in the oil and gas industry. In September 2019, the EPA published a proposal to rescindamending the 2012 and 2016 NSPS rules applicable to sources infor the oil and natural gas sector that removed transmission and storage segment ofsources from the oil and natural gas industry source category and to rescindrescinded the methane requirements applicable to sources in the production and processing segments. In itssources. On June 30, 2021, President Biden signed into law a joint Congressional resolution under the Congressional Review Act disapproving the September 2019 proposal, as an alternative,2020 rule amending the EPA proposedEPA’s 2012 and 2016 NSPS standards for the rescission of all of the new source performance standards applicable to all 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. 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 the source category without otherwise undoing the 2012increased costs and 2016 NSPS rules. 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 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 non-compliance.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 practices.

Our inability to locate sufficient amounts of water, or to dispose of or recycle water used or produced in our exploration and production operations, could potentially cause a decreaseadversely impact our operations. For water sourcing, we first seek to use non-potable water supplies, or recycled produced water for our operational needs. In certain areas, there may be insufficient water available for drilling and completion activities. Water must then be obtained from other sources and transported to the drilling site. Our operations in certain areas could be adversely impacted if we are unable to secure sufficient amounts of water or to dispose of or recycle the completionwater used in our operations. The imposition of new oilenvironmental and natural gasother regulations, as well as produced water disposal well limits or moratoriums in areas of seismicity, could further restrict our ability to conduct operations such as hydraulic fracturing by restricting the disposal of waste such as produced water and drilling fluids. Compliance with environmental regulations and permit requirements governing the withdrawal, storage and use of surface water or groundwater necessary for hydraulic fracturing of wells may increase our operating costs and increased compliance costs, which could increase costscause delays, interruptions or termination of our operations, the extent of which cannot be predicted, all of which could have an adverse effect on our operations and cause considerable delays in acquiring regulatory approvalsfinancial condition. In June 2016, the EPA published final pretreatment standards for disposal of wastewater produced from shale gas operations to drill and complete wells.publicly owned treatment works. The regulations were developed under the EPA’s Effluent Guidelines Program under the authority of the Clean Water Act. In addition, if existing laws and regulations with regardresponse to these actions, operators, including us, have begun to rely more on recycling of water that flows back from the wellbore following hydraulic fracturing are revised or reinterpreted or if new laws(“flowback water”) and regulations become applicableproduced water from well sites as a preferred alternative to our operations through judicial or administrative actions, our business, financial condition, results of operations and cash flows could be adversely affected.For additional information about hydraulic fracturing and related environmental matters, please read “Risk Factors-Federal and state legislation, judicial actions and regulatory initiatives related to oil and gas development, including 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.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

As of December 31, 2019,2022, we had 274981 total employees, associated with283 of whom were located in our upstream operations. In addition, weheadquarters in Houston, Texas and our corporate office in Denver, Colorado and 330 of whom were located in our regional offices in Midland, Texas, Tulsa Oklahoma and Pittsburgh, Pennsylvania. We had 273a total of 368 employees in production field locations across our regional offices. We had 132 employees that will exit as a result of our integration and transition plans. Of our total employee population, 606 were salaried and 375 were hourly. We also have 244 employees that are employed by our wholly-owned subsidiary, GasSearch Drilling Services Corporation.Corporation (“GDS”), which is a service company engaged in water hauling and site preparation exclusively for our Marcellus Shale operations. Of our GDS employees, 16 were salaried and 228 were hourly. We recognize that our success is significantly influenced by the relationship we maintain with our employees. Overall, we believe that our relations with our employees are satisfactory. Ourfavorable. None of our employees are not represented bypursuant to a collective bargaining agreement.

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, 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 Relations at our corporate headquarters at Three Memorial City Plaza, 840 Gessner Road, Suite 1400, Houston, Texas 77024.

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

Our future growth prospects depend on our ability to identify optimal strategies for our business. In developing our business plans, we considered allocating capital and other resources to various aspects of our business including well-development (primarily drilling), reserve reportacquisitions, exploratory activity, corporate items and other alternatives. We also consider our likely sources of capital. Notwithstanding the determinations made in the development of our 2023 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 2023 plan, and our failure to recognize or respond to those changes may limit our ability to achieve our objectives.

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 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.

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 operations. When a new 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 wells 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.

Our business and the oil and gas industry in general have become increasingly dependent on digital data, computer networks and connected infrastructure, including technologies that are managed 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 oil and natural gas reserves, analyze and share 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 ratehost of 13 percent, 26 percent, 18 percentother support services for our business. In recent years (and, in large part, due to the COVID-19 pandemic), we have increased the use of remote networking and 14 percent during 2020, 2021, 2022online conferencing services and 2023, respectively. Future developmenttechnologies that enable employees to work outside of proved undevelopedour 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 otherwise protected information and corruption of data. Unauthorized access to our seismic data, reserves currently not classified as proved developed producing willinformation, 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 material adverse impact these rateson 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 decline. Because of higher initial decline rates from newly developed reserves, we consider this pattern to be fairly typical.

In addition, certain cyber incidents, such as surveillance, may remain undetected for an extended period, and our systems 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 failuredamage from cyber-attacks. Furthermore, the continuing and evolving threat of cyber-attacks has resulted in increased regulatory focus on prevention, and we may be required to produce natural gasexpend significant additional resources to continue to modify or enhance our protective measures or to investigate and oil in commercial quantitiesremediate 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 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. Future challenges in the economy could also lead to reduced demand for natural gas which could have a negative impact on our revenues.obligations.

AsOur indebtedness as a result of December 31, 2019, we had approximately $1.2 billionthe Merger and related transactions could have adverse effects on our business, financial condition, results of debt outstandingoperations and we may incur additional indebtedness in the future. Increases in our level of indebtedness may:

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

From time to time, when we believe that market conditions are favorable, we use financial derivative instruments to manage price risk associated with our oil and natural gas properties. Our borrowing base may decrease as a resultproduction. While there are many different types of lower commodity prices, operating difficulties, declines in reserves, lending requirements or regulations,derivatives available, we generally utilize collar, swap and basis swap agreements to manage price risk more effectively.

While these derivatives reduce the issuanceimpact of new indebtedness or for any other reason. In the event of a decrease in our borrowing base due to declines in commodity prices, these derivatives conversely limit the benefit to us of increases in prices. In addition, these arrangements expose us to risks of financial loss in a variety of circumstances, including when:

The CFTC has promulgated regulations to implement statutory requirements for derivatives transactions, including swaps. Although we believe that our use of swap transactions exempts us from certain regulatory requirements, the changes to the derivatives market regulation affect us directly and indirectly. These changes, as in effect and as continuing to be implemented, could increase the cost of derivative contracts, limit the availability of derivatives to protect against risks that we encounter, reduce our ability to borrow undermonetize or restructure our revolving credit facilityexisting derivative contracts and increase our exposure to less creditworthy counterparties. If we reduce our use of swaps, our results of operations may become more volatile and our cash flows may be less predictable.

In addition, the use of financial derivative instruments involves the risk that the counterparties will be unable to meet the financial terms of such transactions. We are unable to predict changes in a counterparty’s creditworthiness or ability to perform, and even if we could predict such changes accurately, our ability to negate such risk may be limited depending on market conditions and we could be required to repay any indebtedness in excessthe contractual terms of the redetermined borrowing base. In addition, we may be unableinstruments. If any of our counterparties were to access the equity or debt capital markets, including the market for senior unsecured notes, to meet ourdefault on its obligations including any such debt repayment obligations.

We also considered our likely sourceswill continue to evaluate the benefit of capital. Notwithstanding the determinations madeutilizing derivatives in the developmentfuture. Please read “Management’s Discussion and Analysis of our 2020 plan, business opportunities not previously identified periodically come to our attention, including possible acquisitionsFinancial Condition and dispositions. If we fail to identify optimal business strategies, or fail to optimizeResults of Operations” in Item 7 and “Quantitative and Qualitative Disclosures about Market Risk” in Item 7A for further discussion concerning our capital investment and capital raising opportunities and the use of our other resources in furtherance of our business strategies, our financial conditionderivatives.

Businesses across all industries are facing increasing scrutiny from investors, governmental authorities, regulatory agencies and the public related to their ESG practices, including practices and disclosures related to climate change, sustainability, diversity, equity and inclusion initiatives, and heightened governance standards. Failure, or a perceived failure, to adequately respond to or meet evolving investor, stockholder or public ESG expectations, concerns and standards may cause a business entity to suffer reputational damage and materially and adversely affect the entity’s business, financial condition, or stock and/or 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 inform investment and voting decisions. Additionally, certain investors use these scores to benchmark businesses against their peers and, if a business entity is perceived as lagging, these investors may engage with the entity to require improved ESG disclosure or performance. Moreover, certain members of the broader investment community may consider a business entity’s sustainability score as a reputational or other factor in making an adverse effect oninvestment decision. Consequently, a low sustainability score could result in exclusion of our operations.securities from consideration by certain investment funds, engagement by investors seeking to improve such scores and a negative perception of our operations by certain investors. In addition, efforts in recent years aimed at the investment community to generally promote the divestment of fossil fuel equities and to limit or curtail activities with companies engaged in the extraction of fossil fuel reserves could limit our ability to access capital markets. These initiatives by activists and banks, including certain banks who are parties to the credit agreement providing for our revolving credit facility, could interfere with our business activities, operations and ability to access capital.

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

Our operations are subject to extensive federal, state and local laws and regulations, including drilling permittingand environmental and safety laws and regulations, and those relating towhich increase the generation, storage, handling, emission, transportation and discharge of materials into the environment. These laws and regulations can adversely affect the cost manner or feasibility of doing business. Many laws and regulations require permits for the operation of various facilities, and these permits are subject to revocation, modification and renewal. Governmental authorities have the power to enforce compliance with their regulations, and violations could subject us to fines, injunctions or both. These laws and regulations have increased the costs of planning, designing, drilling, installing and operating oil and natural gas and oil facilities, and newfacilities. New laws and regulations or revisions or reinterpretations of existing laws and regulations could further increase these costs. In addition, we may be liable for environmental damages caused by previous owners or operators of property we purchase or lease. Riskscosts, could increase our liability risks, and could result in increased restrictions on oil and gas exploration and production activities, which could have a material adverse effect on us and the oil and gas industry as a whole. Risk of substantial costs and liabilities related to environmental and safety matters in particular, including compliance issues, environmental contamination and claims for damages to persons or property, are inherent in oil and natural gas and oil operations. For example, we could be required to install expensive pollution control measures or limit or cease activities on lands located within wilderness, wetlands or other environmentally or politically sensitive areas. Failure to comply with theseapplicable environmental and safety laws and regulations also may result in the suspension or termination of our operations and subject us to administrative, civil and criminal penalties as well as the imposition of corrective action requirements and orders. It is possible that other developments, such as stricter environmentalIn addition, applicable laws and regulations require us to obtain many permits for the operation of various facilities. The issuance of required permits is not guaranteed and, claims for damagesonce issued, permits are subject to property or persons resulting from natural gasrevocation, modification and oil production, wouldrenewal. Failure to comply with applicable laws and regulations can result in fines and penalties or require us to incur substantial costs to remedy violations.