ITEMS 1 and 2. BUSINESS AND PROPERTIES

Coterra Energy Inc. (“Coterra,” the “Company,” “our,” “we” and “us”) is an independent oil and gas company engaged in the development, exploration and production of oil, natural gas and NGLs. Our assets are concentrated in areas with known hydrocarbon resources, which are conducive to multi-well, repeatable development programs. We operate in one segment, oil and natural gas development, exploration and production, in the continental U.S.

Our headquarters is located in Houston, Texas. We also maintain regional offices in Pittsburgh, Pennsylvania, Midland, Texas, and Tulsa, Oklahoma, as well as field offices near our operations.

STRATEGY

Coterra is a premier U.S.-focused exploration and production company. We embrace innovation, technology and data, as we work to create value for our investors and the communities where we operate. We believe the following strategic priorities will help drive value creation and long-term success.

Generate Sustainable Returns. Our premier assets across multiple basins provide commodity diversification and strong cash flow generation through the commodity price cycles that, combined with our disciplined capital investment, give us confidence in our ability to provide returns to our stockholders that we believe to be sustainable. Demonstrating our continued confidence in our business model, since the consummation of the merger with Cimarex Energy Co. (“Cimarex”) through December 31, 2023, we have increased our annual base dividend $0.36 per share, or 82 percent, on our common stock to $0.80 per share and have returned over $3.5 billion to stockholders through dividends. In February 2024, our Board of Directors increased our annual base dividend to $0.84 per share. Since our initial share repurchase program, which began in early 2022, we have repurchased 65 million shares for $1.7 billion, at a weighted average share price of $25.75 per share. As of December 31, 2023, we had $1.6 billion remaining on our current $2.0 billion share repurchase program. In total, since the consummation of the merger with Cimarex, we have returned $5.2 billion to stockholders through dividends and share repurchases and have retired $874 million of debt. We remain committed to returning 50 percent or more of our annual free cash flow to our stockholders through dividends and our share repurchase program, while maintaining our industry-leading balance sheet.

Disciplined Capital Allocation Across Top-Tier Position. Our asset portfolio offers scale, capital optionality and low break-even investment options. We anticipate our drilling inventory will be developed over the next 15 to 20 years. We are committed to maintaining a disciplined capital investment strategy and using technology and innovation to maximize capital efficiency and create value for stockholders. With operations in the Permian Basin, Marcellus Shale, and Anadarko Basin, our asset portfolio is both commodity and geographically diversified, allowing for capital allocation flexibility that may prove opportunistic in navigating commodity price cycles. During 2023 and 2022, we invested 57 percent and 31 percent, respectively, of our cash flow from operations in our drilling program, and in 2024 we expect to invest approximately 50 percent of our estimated cash flow from operations, based on recent strip prices.

Maintain Financial Strength. Maintaining an industry-leading balance sheet with significant financial flexibility is imperative in a cyclical industry exposed to commodity price volatility. Our asset base, revenue diversity, low-cost structure and strong balance sheet provide us with the flexibility to thrive across various commodity price environments. With a year-end 2023 cash balance of $956 million and $1.5 billion of unused commitments under our revolving credit agreement, we believe we are well positioned to maintain our balance sheet strength.

Focus on Safe, Responsible and Sustainable Operations.Responsible development of oil and natural gas resources provides opportunity for a bright future, one built through technology and innovation that offers prosperity for communities around the world. Our focus on operational excellence is based on making our operations more environmentally and socially sustainable. We actively implement technology across our operations from the design phase to equipment improvements to limit our methane emissions and flaring activity. Safety of our employees and contractors is paramount. We empower all employees and contractors to utilize our Stop Work Authority program, which allows them to stop any work at any time if they are uncomfortable, discover a dangerous condition, or suspect any other EHS hazard. We also focus on practical and sustainable environmental initiatives that promote efficient use of fresh and produced water, eliminate or mitigate releases, and minimize land surface impact. We are committed to being responsible stewards of our resources and implementing sustainable practices. We have published our 2023 Sustainability Report, which includes more information related to our sustainability practices, on our website at www.coterra.com. The information on our website is not part of, and is not incorporated into, this Annual Report on Form 10-K or any other report we may file with or furnish to the SEC (and is not deemed filed herewith), whether before or after the date of this Annual Report on Form 10-K and irrespective of any general incorporation language therein.

2024 OUTLOOK

Our 2024 capital program is expected to be approximately $1.75 billion to $1.95 billion, a decrease of 12 percent (at the mid-point) from $2.1 billion in 2023. We expect to turn-in-line 132 to 158 total net wells in 2024 across our three core operating areas. Approximately 60 percent of our drilling and completion capital will be invested in the Permian Basin, 23 percent in the Marcellus Shale and 17 percent in the Anadarko Basin (at the mid-point).

DESCRIPTION OF PROPERTIES

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

Permian Basin

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

During 2023, we invested $970 million in the Permian Basin, and had seven drilling rigs operating at year end.

Marcellus Shale

Our properties are principally located in Susquehanna County, Pennsylvania, where we currently hold approximately 186,000 net acres in the dry gas window of the Marcellus Shale. Our 2023 net production in the Marcellus Shale was 377 MBoe per day, representing 57 percent of our total equivalent production for the year. Net natural gas production in 2023 averaged 2,263 MMcf per day, representing 78 percent of our total natural gas production. As of December 31, 2023, we had a total of 1,108.2 producing net wells in the Marcellus Shale, of which approximately 99 percent are operated by us.

During 2023, we invested $912 million in the Marcellus Shale, and had two drilling rigs operating at year end.

Anadarko Basin

Our properties are located in the Mid-Continent region in Oklahoma where we currently hold approximately 182,000 net acres. Our development activities are primarily focused on both the Woodford Shale and the Meramec formations. Our 2023 net production in the Anadarko Basin was 56 MBoe per day, representing eight percent of our total equivalent production for the year. As of December 31, 2023, we had a total of 509.9 producing net wells in the Anadarko Basin, of which approximately 61 percent are operated by us.

During 2023, we invested $158 million in the Anadarko Basin and had one rig operating at year end.

Other Properties

Ancillary to our exploration, development and production operations, we operate a number of natural gas gathering and saltwater gathering and disposal systems. The majority of this infrastructure is located in Texas and directly supports our Permian Basin operations. Our gathering systems enable us to connect new wells quickly and to transport natural gas from the wellhead directly to interstate and intrastate pipelines and natural gas processing facilities and to transport produced water to new wells for re-use in completions activities and to disposal facilities. In addition, we can engage in development drilling without relying on third parties to transport our natural gas or produced water and while incurring only the incremental costs of pipeline and compressor additions to our system.

ACQUISITIONS

On October 1, 2021, we completed a merger transaction (the “Merger”) with Cimarex. Cimarex is an oil and gas exploration and production company with operations in Texas, New Mexico and Oklahoma. Under the terms of the merger agreement relating to the Merger (the “Merger Agreement”), and subject to certain exceptions specified in the Merger Agreement, each eligible share of Cimarex common stock was converted into the right to receive 4.0146 shares of our common stock at closing. As a result of the completion of the Merger, we issued approximately 408.2 million shares of common stock to Cimarex stockholders (excluding shares that were awarded in replacement of certain previously outstanding Cimarex restricted share awards). Additionally, on October 1, 2021, we changed our name to Coterra Energy Inc.

Operational information set forth in this Annual Report on Form 10-K does not include the activity of Cimarex for periods prior to the completion of the Merger.

MARKETING

Substantially all of our oil and natural gas production is sold under both long-term and short-term sales contracts at market-sensitive prices. We sell oil, natural gas and NGLs to a broad portfolio of customers, including industrial customers, local distribution companies, oil and gas marketers, major energy companies, pipeline companies and power generation facilities.

We also incur gathering and transportation expenses when we move our oil and natural gas production from wellhead markets to other downstream markets.

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

Delivery Commitments

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

A summary of our firm sales commitments as of December 31, 2023 are set forth in the table below:

						Natural Gas (in Bcf)
2024						601
2025						577
2026						572
2027						549
2028						526

We utilize part of our firm transportation capacity to deliver natural gas under the majority of these firm sales contracts and have entered into numerous agreements for transportation of our production. Some of these contracts have volumetric requirements that could result in monetary shortfall penalties if our production is inadequate to meet such requirements. However, we do not anticipate incurring any penalties based on our current proved reserves and production levels from which we can fulfill these obligations.

RISK MANAGEMENT

We use derivative financial instruments to manage price risk associated with our production. Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” “Quantitative and Qualitative Disclosures about Market Risk” and Note 5 of the Notes to the Consolidated Financial Statements, “Derivative Instruments” for further discussion related to our use of derivatives.

PROVED OIL AND GAS RESERVES

The following table presents our estimated proved reserves by commodity as of the dates indicated:

	December 31,
	2023	2022	2021
Oil (MBbl)
Proved developed reserves	173,392	168,649	153,010
Proved undeveloped reserves	75,821	71,107	36,419
	249,213	239,756	189,429
Natural Gas (Bcf)
Proved developed reserves	8,590	8,543	10,691
Proved undeveloped reserves	1,935	2,630	4,204
	10,525	11,173	14,895
NGLs (MBbl)
Proved developed reserves	234,306	224,706	193,598
Proved undeveloped reserves	83,150	72,059	27,017
	317,456	296,765	220,615

Oil equivalent (MBoe)	2,320,757	2,398,666	2,892,582

At December 31, 2023, our interests in the Dimock field, which is primarily located in Susquehanna County, Pennsylvania in the Marcellus Shale account for approximately 60 percent of our total proved reserves. There are no other fields which represent 15 percent or more of our total proved reserves.

For additional information regarding estimates of our net proved and proved undeveloped reserves, the qualifications of the preparers of our reserves estimates, the evaluation of such estimates by our independent petroleum consultants, our processes and controls with respect to our reserves estimates and other information about our reserves, including the risks inherent in our estimates of proved reserves, refer to the Supplemental Oil and Gas Information included in Item 8 and “Risk Factors—Business and Operational Risks—Our proved reserves are estimates. Any material inaccuracies in our reserves estimates or underlying assumptions could cause the quantities and net present value of our reserves to be overstated or understated” in Item 1A.

PRODUCTION, SALES PRICE AND PRODUCTION COSTS

The following table presents historical information about our total and average daily production volumes for oil, natural gas and NGLs; average oil, natural gas and NGL sales prices; and average production costs per equivalent:

	Year Ended December 31,
	2023		2022		2021 (1)
Production Volumes
Oil (MBbl)	35,110		31,926		8,150
Natural gas (Bcf)	1,053		1,024		911
NGL (MBbl)	32,932		28,697		7,104
Equivalents (MBoe)	243,497		231,342		167,113

Average Daily Production Volumes
Oil (MBbl)	96		87		89
Natural gas (MMcf)	2,884		2,806		2,492
NGL (MBbl)	90		79		77
Equivalents (MBoe)	667		634		660

Average Sales Price
Excluding Derivative Settlements
Oil ($/Bbl)	$	75.97	$	94.47	$	75.61
Natural gas ($/Mcf)	$	2.18	$	5.34	$	3.07
NGL ($/Bbl)	$	19.56	$	33.58	$	34.18
Including Derivative Settlements
Oil ($/Bbl)	$	76.07	$	84.33	$	60.35
Natural gas ($/Mcf)	$	2.44	$	4.91	$	2.73
NGL ($/Bbl)	$	19.56	33.58		$	34.18

Average Production Costs ($/Boe)	$	2.01	$	1.84	$	0.77

_______________________________________________________________________________

(1)On October 1, 2021, we completed the Merger. The production information presented in this table includes Cimarex production for the period subsequent to that date.

The following table presents historical information about our total and average daily natural gas production volumes associated with our interests in the Dimock field. There was no oil or NGL production associated with our interests in the Dimock field.

	Year Ended December 31,
	2023	2022	2021
Production Volumes

Natural gas (Bcf)	826	805	853

Equivalents (MBoe)	137,647	134,097	142,223

Average Daily Production Volumes

Natural gas (MMcf)	2,263	2,204	2,338

Equivalents (MBoe)	377	367	390

ACREAGE

Our interest in both developed and undeveloped properties is primarily in the form of leasehold interests held under oil and gas mineral leases. These leases provide us the right to develop oil and natural gas on the properties. Their primary terms generally range in length from approximately three to 10 years, and these leases generally are held for longer periods once production is established.

The following table summarizes our gross and net developed and undeveloped leasehold acreage at December 31, 2023:

	Acreage
	Developed		Undeveloped		Total
	Gross	Net	Gross	Net	Gross	Net
Core Acreage
Permian Basin
New Mexico	141,319	98,212	55,339	38,654	196,658	136,866
Texas	204,971	136,845	27,825	21,892	232,796	158,737
	346,290	235,057	83,164	60,546	429,454	295,603
Marcellus Shale
Pennsylvania	173,225	171,625	15,024	14,030	188,249	185,655


Anadarko Basin

Oklahoma	320,080	146,987	69,123	34,526	389,203	181,513



Noncore Acreage
Arizona	17,207	17,207	2,097,841	2,097,841	2,115,048	2,115,048
California	—	—	383,487	383,487	383,487	383,487



Nevada	440	1	1,007,167	1,007,167	1,007,607	1,007,168
New Mexico	10,655	2,436	1,640,195	1,634,459	1,650,850	1,636,895

Pennsylvania	—	—	114,199	64,044	114,199	64,044


West Virginia	—	—	607,347	575,691	607,347	575,691

Other	128,713	45,069	298,421	172,990	427,134	218,059
	157,015	64,713	6,148,657	5,935,679	6,305,672	6,000,392
	996,610	618,382	6,315,968	6,044,781	7,312,578	6,663,163

Total Net Undeveloped Acreage Expiration

The table below summarizes by year and operating area our undeveloped acreage expirations in the next three years. In most cases, the drilling of a commercial well will hold the acreage beyond the expiration.

	Acreage
	2024		2025		2026
	Gross	Net	Gross	Net	Gross	Net
Core Acreage
Permian Basin	3	3	—	—	47	7
Marcellus Shale	1,208	1,208	1,860	1,848	550	550
Anadarko Basin	700	134	520	125	40	1
Noncore Acreage	1,303	1,242	—	—	—	—
	3,214	2,587	2,380	1,973	637	558

Expiring acreage in our core operating areas in 2024, 2025 and 2026 represents less than one percent of our total undeveloped acreage. At December 31, 2023, we had no PUD reserves recorded on undeveloped acreage that were scheduled for development beyond the expiration dates of the undeveloped acreage or outside of our core operating area.

WELL SUMMARY

The following table presents our ownership in productive oil and natural gas wells at December 31, 2023. This summary includes oil and natural gas wells in which we have a working interest:

	Gross	Net
Natural Gas	3,374	1,865.6
Oil	2,523	837.0
Total(1)	5,897	2,702.6

_______________________________________________________________________________

(1)Total percentage of gross and net operated wells is 49 percent and 88 percent, respectively.

DRILLING ACTIVITY

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

	Year Ended December 31,
	2023		2022		2021
	Gross	Net	Gross	Net	Gross	Net
Development Wells
Productive	288	183.3	284	173.9	114	99.9
Dry	—	—	1	0.7	—	—



Total	288	183.3	285	174.6	114	99.9

Acquired Wells	—	—	—	—	7,266	1,715.3

During the year ended December 31, 2023, we completed 98 gross wells (62.7 net) that were drilled in prior years.

The following table sets forth information about wells for which drilling was in progress or which were drilled but uncompleted at December 31, 2023, which are not included in the above table:

	Drilling In Progress		Drilled But Uncompleted
	Gross	Net	Gross	Net
Development wells	31	19.9	72	48.4
Exploratory wells	1	0.5	—	—
Total	32	20.4	72	48.4

OTHER BUSINESS MATTERS

Title to Properties

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 at the time of lease acquisition. We conduct more complete investigations prior to the consummation of an acquisition of producing properties and before commencement of drilling operations on undeveloped properties.

Competition

The oil and gas industry is highly competitive, and we experience strong competition where we operate. 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. Many of these competitors have greater financial, technical and personnel 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 infrastructure availability and distribution efficiencies affect competition. We believe that our concentrated acreage positions and our access to both third-party and Company-owned gathering and pipeline infrastructure in 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.

Major Customers

During the year ended December 31, 2023, two customers accounted for approximately 19 percent and 17 percent of our total sales. During the year ended December 31, 2022, two customers accounted for approximately 13 percent and 11 percent of our total sales.

If any one of our major customers were to stop purchasing our production, we believe there are other purchasers to whom we could sell our production. If multiple significant customers were to stop purchasing our production, we expect to have sufficient alternative markets to handle any sales disruptions despite any initial disruptions that may occur.

We regularly 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 been significant.

Regulation of Oil and Natural Gas Exploration and Production

Exploration and production operations are subject to various types of regulation at the federal, state and local levels. These regulations include requiring permits to drill wells, maintaining bonding requirements to drill or operate wells, 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 and the unitization or pooling of oil and 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 prohibit the venting or flaring of natural gas and impose certain requirements regarding the ratability of production. The laws and regulations limit the amounts of oil and natural gas we can produce from our wells as well as the number of wells, and the locations where, we can drill. Because these laws and regulations are often amended, expanded and reinterpreted, we are unable to predict the future cost or impact of regulatory compliance. The regulatory burden on the oil and gas industry often increases the cost of doing business and, consequently, affects our profitability. These laws and regulations, however, do not affect us differently than others in the industry.

Regulation of Natural Gas Marketing, Gathering and Transportation

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 (the “NGA”), the U.S. Natural Gas Policy Act of 1978 (the “NGPA”) and the regulations promulgated under those statutes, the U.S. Federal Energy Regulatory Commission (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. Under the provisions of the Energy Policy Act of 2005 (“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 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.

Under 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 that our

facilities are not subject to federal regulations. Although exempt from FERC 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 continue to be affected by intrastate and interstate gas transportation regulation because the cost of transporting the natural gas once sold to the consuming market is a factor in the prices we receive. Beginning with Order No. 436 in 1985 and continuing through Order No. 636 in 1992 and Order No. 637 in 2000, the FERC has adopted a series of rule makings that have significantly altered the transportation and marketing of natural gas. These changes were intended by the FERC to foster competition by, among other things, requiring interstate pipeline companies to separate their wholesale gas marketing business from their gas transportation business and by increasing the transparency of pricing for pipeline services. The FERC has also established regulations governing the relationship of pipelines with their marketing affiliates, which essentially require that designated employees function independently of each other and that certain information not be shared. The FERC has also implemented standards relating to the use of electronic data exchange by the pipelines to make transportation information available on a timely basis and to enable transactions to occur on a purely electronic basis.

In light of these statutory and regulatory changes, most pipelines have divested their natural gas sales functions to marketing affiliates, which operate separately from the transporter and in direct competition with all other merchants. Most pipelines have also implemented the large‑scale divestiture of their natural gas gathering facilities to affiliated or non-affiliated companies. Interstate pipelines are required to provide unbundled, open and nondiscriminatory transportation and transportation‑related services to producers, gas marketing companies, local distribution companies, industrial end users and other customers seeking such services. As a result of the FERC requiring natural gas pipeline companies to separate marketing and transportation services, sellers and buyers of natural gas have gained direct access to pipeline transportation services, and are better able to conduct business with a larger number of counterparties. We believe these changes generally have improved our access to markets while, at the same time, substantially increasing competition in the natural gas marketplace. We cannot predict what new or different regulations the FERC and other regulatory agencies may adopt, or what effect subsequent regulations may have on our activities. Similarly, we cannot predict what proposals, if any, that affect the oil and natural gas industry might actually be enacted by the U.S. Congress or the various state legislatures and what effect, if any, such proposals might have on us. Further, we cannot predict whether the recent trend toward federal deregulation of the natural gas industry will continue or what effect future policies will have on our sale of gas.

Federal Regulation of Swap Transactions

We use derivative financial instruments such as collar, swap and basis swap agreements to attempt to manage price risk due to the impact of changes in commodity prices on our operating results and cash flows. The Commodity Exchange Act provides the U.S. Commodity Futures Trading Commission (the “CFTC”) with jurisdiction to regulate 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 comply with applicable CFTC regulations. 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 prices qualifies us as a commercial end‑user, which would exempt us from a future requirements to centrally clear our commodity swaps. Nevertheless, future changes in CFTC regulations could increase the cost of entering into derivative contracts, limit the availability of derivatives to protect against risks that we encounter, reduce our ability to monetize or restructure our existing 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.

Federal Regulation of Petroleum

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”). 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. Every five years, the FERC must examine the relationship between the annual change in the applicable index and the actual cost changes experienced in the oil pipeline industry. In December 2015, to implement this required five‑year redetermination, the FERC established an upward adjustment in the index to track oil pipeline cost changes and determined that the Producer Price Index for Finished Goods plus 1.23 percent should be the oil pricing index

for the five‑year period beginning July 1, 2016. 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 pipelines’ 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’ rates.

Environmental and Safety Regulations

General. Our operations are subject to extensive and stringent federal, state and local laws and regulations governing the protection of the environment. These laws and regulations can change, restrict or otherwise impact our business in many ways, including the handling or disposal of waste material, planning for future activities to avoid or mitigate harm to threatened or endangered species, and requiring the installation and operation of emissions or pollution control equipment. Failure to comply with these laws and regulations could result in the assessment of administrative, civil and criminal penalties, the imposition of remedial requirements and the issuance of orders enjoining future operations. Permits are required for the operation of our various facilities. These permits can be revoked, modified or renewed by issuing authorities. Governmental authorities enforce compliance with their regulations through fines, injunctions or both. Regulations can increase the cost of planning, designing, installing and operating, and can affect the timing of installing and operating, oil and natural gas facilities. Although we believe that compliance with environmental regulations will not have a material adverse effect on us, risks of substantial costs and liabilities and potential suspension or cessation of operations under certain conditions related to environmental considerations or compliance issues are part of oil and natural gas production operations. We can provide no assurance that we will not incur significant costs and liabilities. Also, it is possible that other developments, such as stricter environmental laws and regulations and claims for damages to property or persons resulting from oil and natural gas production could result in substantial costs and liabilities to us.

Solid and Hazardous Waste. We currently own or lease, and have in the past owned or leased, numerous properties that were used for the production of oil and natural gas for many years. Although operating and disposal practices that were standard in the industry at the time may have been utilized, it is possible that hydrocarbons or other wastes may have been disposed of or released on or under the properties currently owned or leased by us. State and federal laws applicable to oil and gas wastes and properties have become stricter over time. Under these increasingly stringent requirements, we could be required to remove or remediate previously disposed wastes (including wastes disposed or released by prior owners and operators), clean up contamination (including groundwater contamination by prior owners or operators) or perform plugging operations to prevent future contamination.

We generate some wastes that are hazardous wastes subject to the Resource Conservation and Recovery Act (the “RCRA”) and comparable state statutes, as well as wastes that are exempt from such regulation. The U.S. Environmental Protection Agency (the “EPA”) limits the disposal options for certain hazardous wastes. It is possible that certain wastes currently exempt from regulation as hazardous wastes may in the future be designated as hazardous wastes under RCRA or other applicable statutes. For example, in December 2016, the EPA and environmental groups entered into a consent decree to address the EPA’s alleged failure to timely assess the need to regulate exploration and production related oil and gas wastes exempt from regulation as hazardous wastes under RCRA under Subtitle D applicable to non-hazardous solid waste. The consent decree required the EPA to propose a rulemaking by March 2019 for revision of certain Subtitle D criteria regulations pertaining to oil and gas wastes or to sign a determination that revision of the regulations is not necessary. In April 2019, the EPA issued its determination that based on its review, including consideration of state regulatory programs, it was not necessary at the time to revise Subtitle D regulations to address the management of oil and gas wastes. In the future, we could be subject to more rigorous and costly disposal requirements than we encounter today.

Superfund. The Comprehensive Environmental Response, Compensation, and Liability Act (“CERCLA”), also known as the “Superfund” law, and comparable state laws and regulations impose liability, without regard to fault or the legality of the original conduct, on certain persons with respect to the release of hazardous substances into the environment. These persons include the current and past owners and operators of a site where the release occurred and any party that treated or disposed of or arranged for the treatment or disposal of hazardous substances found at a site. Under CERCLA, such persons may be subject to joint and several strict liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies. CERCLA also authorizes the EPA,

and in some cases, private parties, to undertake actions to clean up such hazardous substances, or to recover the costs of such actions from the responsible parties. In addition, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. In the course of business, we have used materials and generated wastes and will continue to use materials and generate wastes that may fall within CERCLA’s hazardous substances definition. We may also be an owner or operator of sites on which hazardous substances have been released. As a result, we may be responsible under CERCLA for all or part of the costs to clean up sites where such substances have been released.

Oil Pollution Act. The Oil Pollution Act of 1990 (the “OPA”) and implementing regulations impose a variety of obligations on responsible parties related to the prevention of oil spills and liability for damages resulting from such spills in waters of the U.S. The term “waters of the U.S.” has been broadly defined to include inland water bodies, including wetlands and intermittent streams. The OPA assigns joint and several strict liability to each responsible party for oil removal costs and a variety of public and private damages. The OPA also imposes ongoing requirements on operators, including the preparation of oil spill response plans and proof of financial responsibility to cover environmental cleanup and restoration costs that could be incurred in connection with an oil spill. We believe that we are in substantial compliance with the OPA and related federal regulations to the extent applicable to our operations.

Endangered Species Act. The Endangered Species Act (the “ESA”) was established to protect endangered and threatened species. Pursuant to the ESA, if a species is listed as threatened or endangered, restrictions may be imposed on activities adversely affecting that species’ habitat. The U.S. Fish and Wildlife Service (the “FWS”) may designate critical habitat and suitable habitat areas it believes are necessary for survival of a threatened or endangered species. A critical habitat or suitable habitat designation could result in further material restrictions to federal land use and may materially delay or prohibit land access for oil and gas development. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act, to bald and golden eagles under the Bald and Golden Eagle Protection Act, and to certain species under state law. We conduct operations in areas where certain species are currently listed as threatened or endangered, or could be listed as such, under the ESA. Operations in areas where threatened or endangered species or their habitat are known to exist may require us to incur increased costs to implement mitigation or protective measures and also may restrict or preclude our drilling activities in those areas or during certain seasons, such as breeding and nesting seasons.

On June 1, 2021, the FWS proposed to list two distinct population segments (“DPS”) of the lesser prairie-chicken (“LPC”) under the ESA. The Southern DPS, located in eastern New Mexico and the southwest Texas panhandle was proposed to be listed as endangered and the Northern DPS, located in southeastern Colorado, southcentral to southwestern Kansas, western Oklahoma and the northeast Texas panhandle, was proposed to be listed as threatened. On November 25, 2022, the FWS finalized the proposed rule, listing the southern DPS of the lesser prairie-chicken as endangered and the northern DPS of the lesser prairie-chicken as threatened. On July 27, 2023, the U.S. House of Representatives voted to use the Congressional Review Act to reverse the LPC listing. On September 26, 2023 President Biden vetoed Congress’ resolution to reverse the LPC listing. On September 28, 2023, the U.S. Senate voted and failed to override the President’s veto. On November 3, 2023, the U.S. House of Representatives passed an appropriations bill for the U.S. Department of Interior for fiscal year 2023, which provides, in part, that no funds may be used to implement, administer, or enforce the listing of the LPC. Listing of the LPC as a threatened or endangered species will impose restrictions on disturbances to critical habitat by landowners and drilling companies that would harass, harm or otherwise result in a “taking” of this species. Regulatory impacts on landowners and businesses from an ultimate decision to list the LPC could be limited for those landowners and businesses who have entered into certain range-wide conservation planning agreements, such as those developed by the Western Association of Fish and Wildlife Agencies (“WAFWA”), pursuant to which such parties agreed to take steps to protect the LPC’s habitat and to pay a mitigation fee if its actions harm the lesser prairie-chicken’s habitat. We have entered into a voluntary Candidate Conservation Agreement (a “CCA”) with the WAFWA, whereby we agreed to take certain actions and limit certain activities, such as limiting drilling on certain portions of our acreage during nesting seasons, in an effort to protect the LPC.

On February 9, 2018, the FWS announced the listing of the Texas Hornshell, a freshwater mussel species in areas where we operate in the Permian Basin, including New Mexico and Texas, as an endangered species. In March 2018, we entered into a CCA concerning voluntary conservation actions with respect to the Texas Hornshell.

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 significant. Listing petitions continue to be filed with the FWS which could impact our operations. Many non-governmental organizations (“NGOs”) work closely with the FWS regarding the listing of many species, including species with broad and even nationwide ranges. The listing of the Mexican Long Nosed Bat, whose habitat includes the Permian Basin where we operate, and the Dunes Sagebrush Lizard (proposed to be listed as endangered under the ESA on July 3, 2023) in the Permian Basin, are examples of the NGOs’ influence on ESA listing decisions.

On December 1, 2020, the FWS proposed to list the Peppered Chub as endangered under the ESA. The proposed listing was finalized and published on February 28, 2022. The Peppered Chub is a freshwater fish that historically was found in the South Canadian, Cimarron and Arkansas rivers within New Mexico, Texas, Oklahoma and Kansas. We have operations near the South Canadian River in Oklahoma that may be impacted by the listing of the Peppered Chub as endangered. The increase in endangered species listings, such as the Peppered Chub, may limit our ability to explore for or produce oil and gas in certain areas or cause us to incur additional costs.

Clean Water Act. The Federal Water Pollution Control Act (the “Clean Water Act”) and implementing regulations, which are primarily executed through a system of permits, also govern the discharge of certain pollutants into waters of the U.S. Sanctions for failure to comply strictly with the Clean Water Act are generally resolved by payment of fines and correction of any identified deficiencies. However, regulatory agencies could require us to cease construction or operation of certain facilities or to cease hauling wastewater to facilities owned by others that are the source of water discharges to resolve non-compliance. We believe that we substantially comply with the applicable provisions of the Clean Water Act and related federal and state regulations.

Clean Air Act. Our operations are subject to the federal Clean Air Act (the “Clean Air Act”) and comparable local and state laws and regulations to control emissions from sources of air pollution. Federal and state laws require new and modified sources of air pollutants to obtain permits prior to commencing construction. Major sources of air pollutants are subject to more stringent, federally imposed requirements including additional permitting requirements. Federal and state laws designed to control toxic air pollutants and greenhouse gases might require installation of additional controls. Payment of fines and correction of any identified deficiencies generally resolve any failures to comply strictly with air regulations or permits. However, in the event of non-compliance, regulatory agencies could also require us to cease construction or operation of certain facilities or to install additional controls on certain facilities that are air emission sources. We believe that we substantially comply with applicable emission standards and permitting requirements under local, state and federal laws and regulations.

Some of our producing wells and associated facilities are subject to restrictive air emission limitations and permitting requirements. Two examples are the EPA’s source aggregation rule and the EPA’s New Source Performance Standards (“NSPS”) and National Emission Standards for Hazardous Air Pollutants (“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 for the oil and natural gas sector. In June 2016, the EPA published a final rule that updated and expanded the NSPS by setting additional emissions limits for volatile organic compounds and regulating methane emissions for new and modified sources in the oil and gas industry. In June 2017, the EPA proposed a two-year stay of certain requirements contained in the June 2016 rule and, in November 2017, issued a notice of data availability in support of the stay proposal and provided a 30-day comment period on the information provided. In March 2018, the EPA published a final rule that amended two narrow provisions of the NSPS, removing the requirement for completion of delayed repair during emergency or unscheduled vent blowdowns. In September 2020, the EPA published a final rule amending the 2012 and 2016 NSPS for the oil and natural gas sector that removed transmission and storage sources from the oil and natural gas industry source category and rescinded the methane requirements applicable to the production and processing sources. 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 the 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 resulted in additional areas being designated as ozone non-attainment, which could lead to requirements for additional emissions control equipment and the imposition of more stringent permit requirements on facilities in those areas. The EPA completed its final area designations under the new ozone standard in July 2018. If we are unable to comply with air pollution regulations or to obtain permits for emissions associated with our operations, we could be required to forego 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 or criminal penalties for noncompliance. Obtaining permits may delay the development of our oil and natural gas projects, including the construction and operation of facilities.

Safe Drinking Water Act. The Safe Drinking Water Act (“SDWA”) and comparable local and state provisions restrict the disposal, treatment or release of water produced or used during oil and gas development. Subsurface placement of fluids (including disposal wells or enhanced oil recovery) is governed by federal or state regulatory authorities that, in some cases, includes the state oil and gas regulatory authority or the state’s environmental authority. These regulations may increase the costs of compliance for some facilities.

Hydraulic Fracturing. Substantially all of our exploration and production operations depend on the use of hydraulic fracturing to enhance production from oil and natural gas wells. Most of our wells would not be economical without the use of hydraulic fracturing to stimulate production from the well. Due to concerns raised relating to potential impacts of hydraulic fracturing on groundwater quality, legislative and regulatory efforts at the U.S. federal, state and local levels have been initiated to render permitting and compliance requirements more stringent for hydraulic fracturing or to restrict or prohibit the activity altogether. States in which we operate also have adopted, or have stated intentions to adopt, laws or regulations that mandate further restrictions on hydraulic fracturing, such as imposing more stringent permitting, disclosure and well-construction requirements on hydraulic fracturing operations and establishing standards for the capture of air emissions released during hydraulic fracturing. In addition to state measures, local land use restrictions, such as city ordinances, may restrict drilling in general or hydraulic fracturing in particular. Increased regulation and attention given to the hydraulic fracturing process could lead to greater opposition to oil and natural gas production activities using hydraulic fracturing techniques, which could have an adverse effect on oil and natural gas production activities, including operational delays or increased operating costs in the production of oil and natural gas, or could make it more difficult to perform hydraulic fracturing. For example, Pennsylvania’s Act 13 of 2012 amended the state’s Oil and Gas Act to, among other things, increase civil penalties and strengthen the authority of the Pennsylvania Department of Environmental Protection over the issuance of drilling permits. Although the Pennsylvania Supreme Court struck down portions of Act 13 that made statewide rules on oil and gas preempt local zoning rules, this could lead to additional local restrictions on oil and gas activity in the state.

At the federal level, the EPA conducted a study of the potential environmental effects of hydraulic fracturing on drinking water and groundwater. The EPA released its final report in December 2016. It concluded that hydraulic fracturing activities can impact drinking water resources under some circumstances, including large volume spills and inadequate mechanical integrity of wells. This study and other studies that may be undertaken by the EPA or other federal agencies could spur initiatives to further regulate hydraulic fracturing under the Safe Drinking Water Act, the Toxic Substances Control Act, or other statutory and regulatory mechanisms. A number of federal agencies are analyzing, or have been requested to review, a variety of environmental 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 adversely 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 water used in our operations. The imposition of new environmental and other regulations, as well as produced water disposal well limits or moratoriums in areas of seismicity, could further restrict our ability to conduct operations such as hydraulic fracturing by restricting the disposal of waste such as produced water and drilling fluids. Compliance with environmental regulations and permit requirements governing the withdrawal, storage and use of surface water or groundwater necessary for hydraulic fracturing of wells may increase our operating costs and cause delays, interruptions or termination of our operations, the extent of which cannot be predicted, all of which could have an adverse effect on our operations and financial condition. In June 2016, the EPA published final pretreatment standards for disposal of wastewater produced from shale gas operations to publicly owned treatment works. The regulations were developed under the EPA’s Effluent Guidelines Program under the authority of the Clean Water Act. In response to these actions, operators, including us, have begun to rely more on recycling of water that flows back from the wellbore following hydraulic fracturing (“flowback water”) and produced water from well sites as a preferred alternative to disposal.

Greenhouse Gas and Climate Change Laws and Regulations. In response to studies suggesting that emissions of carbon dioxide and certain other greenhouse gas (“GHG”), including methane, may be contributing to global climate change, there is increasing focus by local, state, regional, national and international regulatory bodies as well as by investors and the public on GHG emissions and climate change issues. In December 2015, the U.S. joined the international community at the 21st Conference of the Parties of the United Nations Framework Convention on Climate Change (the “UNFCCC”) in Paris, France in creating an agreement (the “Paris Agreement”) that requires member countries to review and “represent a progression” in their intended nationally determined contributions (“NDC”) of GHGs, which set GHG emission reduction goals every five years beginning in 2020. In 2019, the U.S. withdrew from the Paris Agreement. The current Presidential

administration has made climate change a central priority. On January 20, 2021, his first day in office, President Biden took action to reverse the withdrawal of the previous administration from the Paris Agreement so that the U.S. could rejoin as a party to the agreement. The U.S. officially rejoined the Paris Agreement on February 19, 2021, and in April 2021 submitted its NDC. The U.S. NDC sets an economy-wide target of net GHG emissions reduction from 2005 levels of 50-52 percent by 2030. The specific measures to be taken in furtherance of achieving this target have not been established, but the NDC submission indicated that a “whole government approach” will be used to achieve this target, including regulatory, technology and policy initiatives designed to reduce the generation of GHG emissions and to incentivize the capture and geologic sequestration or utilization of carbon dioxide that would otherwise be emitted in the atmosphere. Also on his first day in office, President Biden signed an executive order on climate action and reconvened an interagency working group to establish interim and final social costs of three GHGs: carbon dioxide, nitrous oxide, and methane. Carbon dioxide is released during the combustion of fossil fuels, including oil, natural gas, and NGLs, and methane is a primary component of natural gas. The Biden administration stated it will use updated social cost figures to inform federal regulations and major agency actions and to justify aggressive climate action as the U.S. moves toward a “100 percent clean energy” economy with net-zero GHG emissions. Furthermore, at COP28 in December 2023, more than 190 governments reached a non-binding agreement to transition away from fossil fuels and encourage the growth and expansion of renewable energy.

Although the U.S. Congress has considered legislation designed to reduce emissions of GHGs in recent years, it has not adopted any significant GHG legislation. However, the 2021 Infrastructure and Investment Jobs Act passed by Congress on November 6, 2021 included measures aimed at decarbonization to address climate change, including funding for replacing transit vehicles, including buses, with zero- and low-emission vehicles and for the deployment of an electric vehicle charging network nationwide. This legislation, and other future laws, that promote a shift toward electric vehicles could adversely affect the demand for our products. Moreover, in the absence of federal GHG legislation, a number of state and regional efforts have emerged. These include measures aimed at tracking and reducing GHG emissions through cap-and-trade programs, which typically require major sources of GHG emissions, such as electric power plants, to acquire and surrender emission allowances in return for emitting GHGs. In addition, a 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 committed to advance 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 new zero-emission passenger vehicles and trucks sold in California over time, with a targeted ban of the sale of new gasoline vehicles by 2035.

At the federal level, the EPA has begun to regulate carbon dioxide and other GHGs under existing provisions of the Clean Air Act. In December 2009, the EPA published its findings that emissions of GHGs present an endangerment to public health and the environment because emissions of such gases are contributing to the warming of the earth’s atmosphere and other climatic changes. Based on these findings, the EPA adopted regulations under existing provisions of the federal Clean Air Act that establish Prevention of Significant Deterioration (“PSD”) and Title V permit reviews for GHG emissions from certain large stationary sources that are otherwise subject to PSD and Title V permitting requirements. The EPA has also adopted rules requiring the monitoring and reporting of GHG emissions from specified sources in the U.S., including, among others, certain oil and gas production facilities on an annual basis, which includes certain of our operations. The EPA widened the scope of annual GHG reporting to include, not only activities associated with completion and workover of gas wells with hydraulic fracturing and activities associated with oil and gas production operations, but also completions and workovers of oil wells with hydraulic fracturing, gathering and boosting systems, and transmission pipelines. More recently, on November 15, 2021, the EPA proposed rules to reduce methane emissions from new and modified sources in the oil and gas sector and published proposed supplemental rules regarding the same on December 6, 2022. On December 2, 2023, during COP28, the EPA announced its final methane rules, which impose several new methane emission requirements on the oil and gas industry. The Inflation Reduction Act of 2022 (“IRA”) established the Methane Emissions Reduction Program, which imposes a charge on methane emissions from certain petroleum and natural gas facilities, which may apply to our operations in the future and may require us to expend material sums.

If we are unable to recover or pass through a significant portion of our costs related to complying with current and future regulations relating to climate change and GHGs, it could materially affect our operations and financial condition. Any future laws or regulations that limit emissions of GHGs from our equipment and operations could require us to both develop and implement new practices aimed at reducing GHG emissions, such as emissions control technologies, which could increase our operating costs and could adversely affect demand for the oil and gas that we produce. To the extent financial markets view climate change and GHG emissions as a financial risk, this could negatively impact our cost of, and access to, capital. Future implementation or adoption of legislation or regulations adopted to address climate change could also make our products more or less desirable than competing sources of energy. At this time, it is not possible to quantify the impact of any such future developments on our business.

Occupational Safety and Health Act and Other Laws and Regulations. We are subject to the requirements of the U.S. federal Occupational Safety and Health Act (the “Occupational Safety and Health Act”) and comparable state laws. The Occupational Safety and Health Act hazard communication standard, the EPA community right‑to‑know regulations under the Title III of CERCLA and similar state laws require that we organize and disclose information about hazardous materials used or produced in our operations. Also, pursuant to the Occupational Safety and Health Act, the Occupational Safety and Health Administration (the “OSHA”) has established a variety of standards related to workplace exposure to hazardous substances and employee health and safety.

Human Capital Resources

As of December 31, 2023, we had 894 Coterra employees, 285 of whom were located in our headquarters in Houston, Texas and 227 of whom were located in our regional offices in Midland, Texas, Tulsa, Oklahoma and Pittsburgh, Pennsylvania. We had a total of 382 employees in production field locations across our regional offices. Of our total employee population, 564 were salaried and 330 were hourly. Additionally, we have 189 employees that are employed by our wholly-owned subsidiary, GasSearch Drilling Services 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 173 were hourly. We believe that our relations with our employees are favorable. None of our employees are represented pursuant to a collective bargaining agreement.

Our ability to attract, retain and develop the highest quality employees is a vital component of our success.

In managing our people, we seek to:

• promote a safe and healthy workplace;

• have a results-focused culture centered on transparency and open communication;

• attract, retain and develop a highly qualified, motivated and diverse workforce;

• maintain a conservatively managed headcount to minimize workforce fluctuations;

• provide opportunities for career growth, learning and development; and

• offer highly competitive compensation and benefits packages.

We believe these practices, further described below, are the key drivers in our development of current and future talent and leadership as well as employee engagement and retention.

Recruiting, Hiring and Advancement. Due to the cyclical nature of our business and the fluctuations in activity that can occur, we manage our headcount carefully. We provide employees with opportunities to learn new roles and develop the breadth and depth of their skills to ensure a collaborative environment, strong talent and future leadership. This also helps to minimize layoffs and overall staff fluctuations when downturns occur. When a position needs to be filled, we generally seek to promote current top-performing employees before going to outside sources for a new hire. We believe this practice helps to build future leadership and to reduce voluntary turnover among our workforce by providing employees with new challenges and opportunities throughout their careers.

When we hire from outside the Company, we identify qualified candidates by promoting the position internally for referrals, engaging in recruiting through our website and online platforms, utilizing recruiting services and attending job fairs. We also have a well-established internship program that feeds top talent into our technical functions. In our recruiting efforts, we foster a culture of mutual respect and compliance with all applicable federal, state and local laws governing nondiscrimination in employment. We seek to increase the diversity of our workforce in our external hiring practices. We ask our recruiting partners to provide diverse slates of candidates and we treat all applicants with the same high level of respect regardless of their gender, ethnicity, religion, national origin, age, marital status, political affiliation, sexual orientation, gender identity, disability or protected veteran status. This philosophy extends to all employees throughout the lifecycle of employment, including recruiting, hiring, placement, promotion, evaluation, leaves of absence, compensation and training.

Compensation and Benefits.Our focus on providing competitive total compensation and benefits to our employees is a core value and a key driver of our retention program. We design our compensation programs to provide compensation that is competitive with our industry peers and rewards superior performance and, for managers and executives, aligns compensation with our performance and incentivizes the achievement of superior operating results. We do this through a total rewards program that provides:

• base wages or salaries that are competitive for the position and considered for increases annually based on employee performance, business performance and industry outlook;

• incentives that reward individual and Company performance, such as performance bonuses, management discretionary bonuses, field operational bonuses and short-term and long-term incentive programs;

• retirement benefits, including dollar-for-dollar matching contributions and discretionary employer retirement contributions to a tax-qualified defined contribution savings plan for all employees and other non-qualified retirement programs;

• comprehensive health and welfare benefits, including medical insurance, prescription drug benefits, dental insurance, vision insurance, life insurance, accident insurance, short and long-term disability benefits, employee assistance program and health savings accounts;

• tuition reimbursement for eligible employees, scholarship program and matching charitable contributions program; and

• time off, sick time, parental leave and holiday time.

We believe our compensation and benefits package is a strong retention tool and promotes personal health and financial security within our workforce.

Health and Safety. The health and safety of our employees is one of our core values for sustainable operations. This value is reflected in our strong safety culture that emphasizes personal responsibility and safety leadership, both for our employees and our contractors that are on our worksites. Our safety programs are built on a foundation that emphasizes personal safety and includes a Stop Work Authority program that empowers employees and contractors to stop work if they discover a dangerous condition or other serious EHS hazard. Our comprehensive EHS management system establishes a corporate governance framework for EHS compliance and performance and covers all elements of our operating lifecycle.

Website Access to Company Reports

We make available free of charge through our website, 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 SEC. In addition, the SEC maintains an Internet site at www.sec.gov that contains reports, proxy and information statements and other information filed by us. Information on our website, including our 2023 Sustainability Report, is not a part of, and is not incorporated into, this Annual Report on Form 10-K or any other report we may file with or furnish to the SEC (and is not deemed filed herewith), whether before or after the date of this Annual Report on Form 10-K and irrespective of any general incorporation language therein. Furthermore, references to our website URLs are intended to be inactive textual references only.

Corporate Governance Matters

Our Corporate Governance Guidelines, Code of Business Conduct and Ethics, Audit Committee Charter, Compensation Committee Charter, Governance and Social Responsibility Committee Charter and Environment, Health & Safety Committee Charter are available on our website at www.coterra.com. Requests for copies of these documents can also be made in writing to Corporate Secretary at our corporate headquarters at Three Memorial City Plaza, 840 Gessner Road, Suite 1400, Houston, Texas 77024.

CTRA - Coterra Energy Inc.

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