Our proved reserves totaled approximately 9,726 Bcfe at December 31, 2017, of which 96% were natural gas. This reserve level was up by 13%2021 increased 614 MMBOE, or 27 percent, from 8,576 Bcfe2,279 MMBOE at December 31, 2016. In 2017,2020, primarily due to the Merger, which increased our proved reserves by 672 MMBOE. During 2021, we added 1,236.1 Bcfe171 MMBOE of proved reserves through extensions, discoveries and other additions, primarily due to the positive results from our drilling and completion program in the Dimock field in northeast Pennsylvania. We also had a net upwarddownward revision of 928.5 Bcfe,62 MMBOE, which was primarily due to an upwarda net downward performance revision of 863.8 Bcfe primarily associated with positive drilling results in97 MMBOE, partially offset by an upward pricing revision of 34 MMBOE. During 2021, we produced 167 MMBOE.

At December 31, 2021, our Dimock field, which is located in northeastthe Marcellus Shale in Susquehanna County, Pennsylvania, and 103.0 Bcfe associated with higher commodity prices, partially offset by a downward revisioncontained approximately 75 percent of 38.3 Bcfe associated withour total proved undeveloped (PUD) reserves reclassifications as a result of the five year limitation. In 2017, we produced 685.3 Bcfe.reserves.

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

For additional information regarding estimates of proved reserves, the auditaudits of such estimates by Miller and Lents, Ltd. (Miller(“Miller and Lents)Lents”) and DeGolyer and MacNaughton and other information about our reserves, including the risks inherent in our estimates of proved reserves, 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 reserve estimates or underlying assumptions could cause the quantities and net present value of our reserves to be overstated or understated” in Item 1A.

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

Our Senior Vice President, South RegionProduction and EngineeringOperations is the technical person responsible for our internal reserves estimation process and provides oversight of our corporate reservoir engineering department, which consists of three engineers, and the annual audit of our year-end reserves by Miller and Lents.10 engineers. He has a Bachelor of Science degree in Chemical Engineering, specializing in petroleum engineering, and over 3539 years of industry experience with positions of increasing responsibility in operations, engineering and evaluations. He has worked in the area of reserves and reservoir engineering for 2630 years and is a member of the Society of Petroleum Engineers.

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

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

Copies of the audit letterletters by Miller and Lents dated January 26, 2018, has31, 2022 and DeGolyer and MacNaughton dated January 17, 2022 have been filed as an exhibitexhibits to this Annual Report on Form 10-K.

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

At December 31, 20172021, we had 3,538.7 Bcfe of PUD reserves associated with future development costs of $1.5$2.1 billion associated with 764 MMBOE of PUD reserves, which represents an increasea decrease of 585.4 Bcfe80 MMBOE compared to December 31, 2016. Approximately 94%2020. By the end of our PUD reserves are located in Susquehanna County, Pennsylvania. We2022, we expect to complete approximately 100% ofsubstantially all the work necessary to convert our PUD reserves associated with wells that were drilled but uncompleted wells by the end of 2018.at December 31, 2021 to proved developed reserves. Future development plans are reflective of the expected increase incurrent commodity pricesprice environment and have been established based on cash on hand, expected available cash flows from operations and availability under our revolving credit facility.operations. As of December 31, 2017,2021, all PUD reserves are expected to be drilled and completed within five years of initial disclosure of these reserves.

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

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

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

At December 31, 2021, we takehad no action to extend or renew the terms of our leases, our netproved undeveloped reserves recorded on undeveloped acreage that will expire overwere scheduled for development beyond the next three years asexpiration dates of December 31, 2017 is 36,983, 10,880 and 34,380 for the years ending December 31, 2018, 2019 and 2020, respectively.

The following table sets forth information about wells for which drilling was in progress or which were drilled but uncompleted at December 31, 2017,2021, which are not included in the above table:

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

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

Price, contract terms, availability of rigs and related equipment and quality of service, including pipeline connection times and distribution efficiencies affect competition. We believe that our 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 over other producers who do not have similar systems or services in place.

During the yearsyear ended December 31, 2017, 2016 and 2015, two2021, no customer accounted for more than 10 percent of our total sales. During the year ended December 31, 2020, three customers accounted for approximately 18%21 percent, 16 percent and 11%, two customers accounted for approximately 19% and 10% and two customers accounted for approximately 16% and 14%, respectively,12 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 ample 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

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. The current maximum penalty is 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.

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

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, roll differential swap and basis swap agreements to attempt to more effectively manage price risk due to the impact of changes in commodity prices on our operating results and cash flows. Following enactment of the Dodd‑Frank Wall Street Reform and Consumer Protection Act (Dodd‑(“Dodd‑Frank Act)Act”) in July 2010, the Commodity Futures Trading Commission (CFTC)(the “CFTC”) has promulgated regulations to implement statutory requirements for swap transactions, including certain options. The 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. We believe that our use of swaps to hedge against commodity exposure qualifies us as an end‑user, exempting us from the requirement to centrally clear our swaps. Nevertheless, changes to the swap market as a result of Dodd‑Frank implementation 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 reduce the availability of new or existing swaps. 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. Every five years, the FERC must examine the relationship between the annual change in the applicable index and the

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

We generate some hazardous wastes that are alreadyhazardous wastes subject to the FederalU.S. 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 could add costs and cause 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 in Junethat 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 concerning aggregation of sources that affects source determinationsNSPS for air permitting in the oil and natural gas industry. 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. For additional information, please read “Risk Factors—Legal, Regulatory and Governmental Risks— Federal and state legislation, judicial actions and regulatory initiatives related to oil and gas development and the use of hydraulic fracturing could result in increased costs and operating restrictions or delays and adversely affect our business, financial condition, results of operations and cash flows” in Item 1A.

In October 2015, the EPA adopted a lower national ambient air quality standard for ozone. The revised standard 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 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.

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 is not a part of, and is not incorporated into, this report or any other report we may read and copy materials that we file with or furnish to the SEC, atwhether 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 report 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, 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,www.coterra.com, under the “Governance”“Corporate Governance” section of “About Cabot.“Investors.” Requests for copies of these documents can also be made in writing to Investor Relations at our corporate headquarters at Three Memorial City Plaza, 840 Gessner Road, Suite 1400, Houston, Texas 77024.

Our revenues, operating results, financial condition and ability to borrow funds or obtain additional capital depend substantially on prices we receive for the oil, natural gas and oilNGLs that we sell. Lower commodity prices may reduce the amount of oil, natural gas and oilNGLs that we can produce economically. 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 predominantly natural gas (approximately 96%For example, the WTI oil prices in 2021 ranged from a high of equivalent proved reserves), changes in$84.65 to a low of $47.62 per Bbl and NYMEX natural gas prices havein 2021 ranged from a more significant impact on our financial results than oil prices.high of $23.86 (during Winter Storm Uri) to a low of $2.43 per Mmbtu. 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 oilcommodity prices may cause us to delay or postpone a significant portion of our exploration development and exploitationdevelopment projects or may render such projects uneconomic, which may result in significant downward adjustments to our estimated proved reserves and could negatively impact our ability to borrow and cost of capital and our ability to access capital markets, increase our costs under our revolving credit facility and limit our ability to execute aspects of our business plans. See "Risk Factors-Future natural gas and oilRefer to “Future commodity price declines may result in write-downs of the carrying amount of our oil and gas properties, which could materially and adversely affect our results of operations."”

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