EDGAR 10-K Filing

Company CIK: 858470
Filing Year: 2022
Filename: 858470_10-K_2022_0000858470-22-000009.json

---

ITEM 1. BUSINESS
ITEMS 1 and 2. BUSINESS AND PROPERTIES
Coterra Energy Inc. (“Coterra,” “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.
On October 1, 2021, we completed a merger transaction (the “Merger”) with Cimarex Energy Co. (“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.
As a result of the Merger, we added substantial assets and operations in the Permian Basin in Texas and New Mexico and the Anadarko Basin in Oklahoma. As of December 31, 2021, the proved reserves attributable to the Cimarex legacy operations represented 25 percent of our total proved reserves on a BOE basis. The Merger has provided us with geographic, commodity and asset diversification, with exposure to oil, natural gas and NGLs, which we believe will provide us with greater resiliency to market fluctuations and other factors impacting any single commodity, region or basin. We believe we have a multi-decade inventory of high-return development locations in each of our premier oil and natural gas basins in the U.S., with our approximately 177,000 net acres in the Marcellus Shale, approximately 306,000 net acres in the Permian Basin and approximately 182,000 net acres in the Anadarko Basin. We believe the Merger will generate long-term value for our stockholders and positions us to be a premier exploration and production company with the size, scale, inventory and financial strength to deliver sustainable returns through various commodity price cycles.
As of the effective time of the Merger, our Board of Directors was reconstituted to consist of ten members, with five of the directors being persons who previously served on our Board of Directors and five persons who previously served on the Cimarex Board of Directors. Also as of the effective time of the Merger, we made changes to our executive management team, including appointing Mr. Dan O. Dinges (our former President and Chief Executive Officer) as our Executive Chairman of the Board of Directors and appointing Mr. Thomas E. Jorden (Cimarex’s former Chief Executive Officer and President) as our Chief Executive Officer and President.
Certain 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.
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, our team members 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, disciplined capital investment and strong cash flow generation through the commodity price cycles give us the confidence to provide returns to our stockholders that we believe to be sustainable. Demonstrating our confidence in our business model, we increased our annual base dividend on our common stock to $0.50 per share following the consummation of the Merger and again in February 2022 to $0.60 per share. Since October 1, 2021, we have returned $652 million to stockholders through base-plus-variable and special dividends. Furthermore and consistent with our returns-focused strategy, in February 2022, our Board of Directors also approved a new $1.25 billion share repurchase program that replaced our previously announced share repurchase program. Together with our base-plus-variable dividend, we remain committed to returning at least 50 percent of our free cash flow to our stockholders, supplementing any of these returns periodically with our share repurchase program, all while staying focused on the 30 percent of cash flow from operations threshold, in all but the lowest commodity environments.
Disciplined Capital Allocation Across Top-Tier Position. We believe that we hold the ability to generate sustainable returns across our asset portfolio, which offers scale, capital optionality and low break-even investment options. We anticipate our drilling inventory will be developed over multiple decades, at the current run-rate. We are committed to maintaining a
disciplined capital investment strategy and using technology and innovation to maximize capital efficiency and operational execution. We believe that having three operating regions, the Marcellus Shale, Permian Basin and Anadarko Basin, offers diversity of geography and commodity and revenue streams, which should support strong and stable cash flow generation through commodity price cycles. In the fourth quarter of 2021, we invested 44 percent of our cash flow from operations in our drilling program and returned $0.80 per share to stockholders via dividend payments.
Maintain Financial Strength. We believe that maintaining an industry-leading balance sheet with significant financial flexibility is imperative in a cyclical industry exposed to commodity price volatility. We believe that our asset base, revenue diversity, low-cost structure and strong balance sheet provides us the flexibility we need to thrive across various commodity price environments. With no significant debt maturities until 2024, a year-end 2021 cash balance of $1.0 billion and $1.5 billion of unused commitments under our revolving credit facility, we believe we are well positioned to maintain our balance sheet strength.
Focus on Safe, Responsible and Sustainable Operations. We believe responsible development of oil and natural gas resources provides opportunity for a bright future, one built through technology and innovation that offers prosperity for both today and tomorrow. Our operational focus is based on making our operations more environmentally and socially sustainable by actively implementing technology across our operations from design phase to equipment improvements to limit and reduce our methane emissions and flaring activity. Our safety programs are built on a foundation that emphasizes personal responsibility and safety leadership. In addition, we focus on practical and sustainable environmental initiatives that promote efficient use of water and help to protect water quality, eliminate or mitigate releases, and minimize land surface impact. We are committed to being responsible stewards of our resources and implementing sustainable practices under the guidance of our management team and our diverse and experienced Board of Directors.
2022 OUTLOOK
Our 2022 capital program is expected to be approximately $1,400 million to $1,500 million, of which $1,225 million to $1,325 million is allocated to drilling and completion activities. We expect to turn-in-line 134 to 153 total net wells in 2022 across our three operating regions. Approximately 49 percent of drilling and completion capital will be invested in the Permian Basin, 44 percent in the Marcellus Shale and the balance in the Anadarko Basin. Midstream, saltwater disposal, electrification, infrastructure and other investments are expected to total approximately $175 million in the year.
DESCRIPTION OF PROPERTIES
Our operations are primarily concentrated in three operating areas-the Marcellus Shale in northeast Pennsylvania, the Permian Basin in west Texas and southeast New Mexico and the Anadarko Basin in the Mid-Continent region in Oklahoma.
Marcellus Shale
Our Marcellus Shale properties are principally located in Susquehanna County, Pennsylvania, where we currently hold approximately 177,000 net acres in the dry gas window in the Marcellus Shale. Our 2021 net production in the Marcellus was 389 MBOEPD, representing 85 percent of our total equivalent production for the year. As of December 31, 2021, we had a total of 954.0 net wells in the Marcellus Shale, of which approximately 99 percent are operated by us.
During 2021, we invested $594 million in the Marcellus where we exited 2021 with two drilling rigs operating in the play and plan to exit 2022 with two rigs operating.
Permian Basin
Our Permian Basin properties are principally located in the western half of the Permian Basin known as the Delaware Basin where we currently hold approximately 306,000 net acres in the play. Our development activities are primarily focused on the Wolfcamp Shale in Culberson and Reeves Counties in Texas and Lea and Eddy Counties in New Mexico. Our 2021 net production in the Permian Basin, which represents the production from this basin subsequent to the completion of the Merger on October 1, 2021, was 211 MBOEPD, representing 12 percent of our total equivalent production for the year. As of December 31, 2021, we had a total of 1,164.4 net wells in the Permian Basin, of which approximately 79 percent are operated by us.
During 2021, we invested $147 million in the Permian Basin, which represents the amount invested in the basin subsequent to the completion of the Merger. We exited 2021 with six drilling rigs operating in the play and plan to exit 2022 with six rigs operating.
Anadarko Basin
Our Anadarko Basin properties are principally located in Oklahoma where we currently hold approximately 182,000 net acres in the play. Our development activities are primarily focused on the Woodford Shale and the Meramec formation, both in Oklahoma. Our 2021 net production in the Anadarko Basin, which represents the production from this basin subsequent to the completion of the Merger on October 1, 2021, was 59 MBOEPD, representing three percent of our total equivalent production for the year. As of December 31, 2021, we had a total of 568.0 net wells in the Anadarko Basin, of which approximately 57 percent are operated by us.
During 2021, we invested $2 million in the Anadarko Basin, which represents the amount invested in the basin subsequent to the completion of the Merger. At the end of 2021, we had no rigs operating in the play but in the first half of 2022, subject to market conditions, we plan to have up to two rigs in the play.
Other Properties
Ancillary to our exploration, development and production operations, we operate a number of natural gas and saltwater disposal gathering systems. The majority of our gathering 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 pipelines, natural gas processing facilities and produced water disposal facilities. Control of our gathering pipeline systems also enables us to transport natural gas produced by third parties. In addition, we can engage in development drilling without relying on third parties to transport our natural gas or produced water and incur only the incremental costs of pipeline and compressor additions to our system.
MARKETING
Substantially all of our oil and natural gas production is sold at market sensitive prices under both long-term and short-term sales contracts. 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.
Demand for natural gas has historically been seasonal, with peak demand and typically higher prices occurring during the winter months.
We also incur transportation and gathering expenses to move our oil and natural gas production from the wellhead to our principal markets in the U.S. The majority of our Marcellus and Anadarko Basin natural gas production is gathered on third-party gathering systems, while the majority of our Permian Basin natural gas production is gathered on company-owned and operated gathering systems. Most of our natural gas is transported on interstate pipelines where we have long-term contractual capacity arrangements or use purchaser-owned capacity under both long-term and short-term sales contracts.
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 substantially all of our commitments, but 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, 2021 are set forth in the table below:
Natural Gas (in Bcf)
2022 652
2023 644
2024 601
2025 577
2026 572
We utilize a 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 which could require monetary shortfall penalties if our production is inadequate to meet the terms. However, we do not believe we will have any financial commitment due based on our current proved reserves and production levels from which we can fulfill these obligations.
RISK MANAGEMENT
From time to time, we use derivative financial instruments to manage price risk associated with our oil and natural gas production. Although there are many different types of derivatives available, we generally utilize collar, swap, roll differential swaps and basis swap agreements designed to assist us in managing price risk. The collar arrangements are a combination of put and call options used to establish floor and ceiling prices for a fixed volume of production during a certain time period. They provide for payments to counterparties if the index price exceeds the ceiling and payments from the counterparties if the index price falls below the floor. The swap agreements call for payments to, or receipts from, counterparties based on whether the index price for the period is greater or less than the fixed price established for the particular period under the swap agreement.
During 2021, oil collars with floor prices ranging from $29.00 to $40.00 per Bbl and ceiling prices ranging from $34.15 to $51.10 per Bbl covered 3.7 Mmbbls, or 45 percent, of oil production at a weighted-average price of $44.37 per Bbl. Oil basis swaps covered 3.2 Mmbbls, or 40 percent, of oil production at a weighted-average price of $(0.08) per Bbl. Oil roll differential swaps covered 1.6 Mmbbls, or 20 percent, of oil production at a weighted-average price of $(0.10) per Bbl.
During 2021, natural gas collars with floor prices ranging from $1.50 to $2.85 per Mmbtu and ceiling prices ranging from $1.75 to $3.94 per Mmbtu covered 193.2 Bcf, or 21 percent, of natural gas production at a weighted-average price of $2.85 per Mmbtu. Natural gas swaps covered 56.3 Bcf, or six percent, of natural gas production at a weighted-average price of $3.16 per Mmbtu.
As of December 31, 2021, we had the following outstanding financial commodity derivatives:
Collars Swaps
Floor Ceiling Basis Swaps Roll Swaps
Type of Contract Volume (Mbbl) Contract Period Range ($/Bbl) Weighted- Average ($/Bbl) Range ($/Bbl) Weighted- Average ($/Bbl) Weighted- Average ($/Bbl) Weighted- Average ($/Bbl)
Crude oil (WTI) 630 Jan. 2022-Mar. 2022 $ - $ 35.00 $45.15-$45.40
$ 45.28
Crude oil (WTI) 1,629 Jan. 2022-Jun. 2022 $35.00-$37.50
$ 36.11 $48.38-$51.10
$ 49.97
Crude oil (WTI) 2,730 Jan. 2022-Sep. 2022 $ - $ 40.00 $47.55-$50.89
$ 49.19
Crude oil (WTI) 2,920 Jan. 2022-Dec. 2022 $ - $ 57.00 $72.20-$72.80
$ 72.43
Crude oil (WTI Midland)(1)
630 Jan. 2022-Mar. 2022 $ 0.11
Crude oil (WTI Midland)(1)
1,448 Jan. 2022-Jun. 2022 $ 0.25
Crude oil (WTI Midland)(1)
1,911 Jan. 2022-Sep. 2022 $ 0.38
Crude oil (WTI Midland)(1)
2,920 Jan. 2022-Dec. 2022 $ 0.05
Crude oil (WTI) 630 Jan. 2022-Mar. 2022 $ (0.24)
Crude oil (WTI) 724 Jan. 2022-Jun. 2022 $ (0.20)
Crude oil (WTI) 1,911 Jan. 2022-Sep. 2022 $ 0.10
________________________________________________________
(1)The index price the Company pays under these basis swaps is WTI Midland, as quoted by Argus Americas Crude.
Collars
Floor Ceiling
Type of Contract Volume (Mmbtu) Contract Period Range
($/Mmbtu) Weighted-
Average
($/Mmbtu) Range
($/Mmbtu) Weighted-
Average
($/Mmbtu)
Natural gas (NYMEX) 36,000,000 Jan. 2022-Mar. 2022 $4.00 - $4.75
$ 4.38 $5.00 - $10.32
$ 6.97
Natural gas (NYMEX) 42,800,000 Apr. 2022 - Oct. 2022 $3.00 - $3.50
$ 3.19 $4.07 - $4.83
$ 4.30
Natural gas (Perm EP)(1)
1,800,000 Jan. 2022-Mar. 2022 $1.80 - $1.90
$ 1.85 $2.18 - $2.19
$ 2.18
Natural gas (Perm EP)(1)
3,620,000 Jan. 2022-Jun. 2022 $ - $ 2.40 $2.85 - $2.90
$ 2.88
Natural gas (Perm EP)(1)
7,300,000 Jan. 2022-Dec. 2022 $ - $ 2.50 $ - $ 3.15
Natural gas (PEPL)(2)
3,600,000 Jan. 2022-Mar. 2022 $1.90 - $2.10
$ 2.00 $2.35 - $2.44
$ 2.40
Natural gas (PEPL)(2)
3,620,000 Jan. 2022-Jun. 2022 $ - $ 2.40 $2.81 - $2.91
$ 2.86
Natural gas (PEPL)(2)
7,300,000 Jan. 2022-Dec. 2022 $ - $ 2.60 $ - $ 3.27
Natural gas (Waha)(3)
3,600,000 Jan. 2022-Mar. 2022 $1.70 - $1.84
$ 1.77 $2.10 - $2.20
$ 2.15
Natural gas (Waha)(3)
3,620,000 Jan. 2022-Jun. 2022 $ - $ 2.40 $2.82 - $2.89
$ 2.86
Natural gas (Waha)(3)
2,730,000 Jan. 2022-Sep. 2022 $ - $ 2.40 $ - $ 2.77
Natural gas (Waha)(3)
7,300,000 Jan. 2022-Dec. 2022 $ - $ 2.50 $ - $ 3.12
________________________________________________________
(1)The index price for these collars is El Paso Natural Gas Company, Permian Basin Index (“Perm EP”), as quoted in Platt’s Inside FERC.
(2)The index price for these collars is Panhandle Eastern Pipe Line, Tex/OK Mid-Continent Index (“PEPL”), as quoted in Platt’s Inside FERC.
(3)The index price for these collars is Waha West Texas Natural Gas Index (“Waha”), as quoted in Platt’s Inside FERC.
In early 2022, we entered into the following outstanding financial commodity derivatives:
Collars
Floor Ceiling
Type of Contract Volume (Mmbtu) Contract Period Range
($/Mmbtu) Weighted-
Average
($/Mmbtu) Range
($/Mmbtu) Weighted-
Average
($/Mmbtu)
Natural gas (NYMEX) 71,500,000 Apr. 2022-Dec. 2022 $3.50 - $4.25
$ 3.84 $4.75 - $6.65
$ 5.39
Natural gas (NYMEX) 10,700,000 Apr. 2022-Oct. 2022 $ - $ 4.00 $5.60 - $5.69 $ 5.63
Natural gas (NYMEX) 7,550,000 Nov. 2022-Mar. 2023 $ - $ 4.00 $7.06 - $7.10 $ 7.08
A significant portion of our expected oil and natural gas production for 2022 and beyond is currently unhedged and directly exposed to the volatility in oil and natural gas prices, whether favorable or unfavorable. We will continue to evaluate the benefit of using derivatives in the future. Please read “Management's Discussion and Analysis of Financial Condition and Results of Operations” and “Quantitative and Qualitative Disclosures about Market Risk” for further discussion related to our use of derivatives.
RESERVES
The following table presents our estimated proved reserves as of the dates indicated:
December 31,
2021 2020 2019
Oil (Mbbl)
Proved developed reserves 153,010 - -
Proved undeveloped reserves(1)
36,419 - -
189,429 - -
Natural Gas (Bcf)
Proved developed reserves 10,691 8,608 8,056
Proved undeveloped reserves(1)
4,204 5,064 4,847
14,895 13,672 12,903
NGLs (Mbbl)
Proved developed reserves 193,598 - -
Proved undeveloped reserves(1)
27,017 - -
220,615 - -
Oil equivalent (MBOE)
2,892,582 2,278,636 2,150,422
______________________________________________________________________________
(1)Proved undeveloped reserves for 2021, 2020 and 2019 include reserves drilled but uncompleted of 80 MMBOE, 40 MMBOE and 131 MMBOE, respectively.
Our proved reserves at December 31, 2021 increased 614 MMBOE, or 27 percent, from 2,279 MMBOE at December 31, 2020, primarily due to the Merger, which increased our proved reserves by 672 MMBOE. During 2021, we added 171 MMBOE of proved reserves through extensions, discoveries and other additions, primarily due to the results from our drilling and completion program in the Dimock field in northeast Pennsylvania. We had a net downward revision of 62 MMBOE, which was primarily due to a net downward performance revision of 97 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 the Marcellus Shale in Susquehanna County, Pennsylvania, contained approximately 75 percent of our total proved reserves.
Our reserves are sensitive to commodity prices and their effect on the economic productive life of producing properties. Our reserves are based on the 12-month average index price for the respective commodity, calculated as the unweighted arithmetic average for the first day of the month price for each month 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 audits of such estimates by Miller and Lents, Ltd. (“Miller and Lents”) and DeGolyer and MacNaughton and other information about our reserves, including the risks inherent in our estimates of proved reserves, refer to the Supplemental Oil and Gas Information to the Consolidated Financial Statements included in Item 8 and “Risk Factors-Business and Operational Risks-Our proved reserves are estimates. Any material inaccuracies in our reserve estimates or underlying assumptions could cause the quantities and net present value of our reserves to be overstated or understated” in Item 1A.
Technologies Used In Reserves Estimates
We utilize various traditional methods to estimate our reserves, including decline curve extrapolations, material balance calculations, volumetric calculations, 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.
Internal Control
Our Senior Vice President, Production and Operations is the technical person responsible for our internal reserves estimation process and provides oversight of our corporate reservoir engineering department, which consists of 10 engineers. He has a Bachelor of Science degree in Chemical Engineering, specializing in petroleum engineering, and over 39 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 30 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 independent audits of our estimated proved reserves. Upon completion of the process, the estimated reserves are presented to senior management and the Board of Directors.
Miller and Lents 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 its judgment, we have an effective system for gathering data and documenting information required to estimate our proved reserves and project our future revenues.
Copies of the audit letters by Miller and Lents dated January 31, 2022 and DeGolyer and MacNaughton dated January 17, 2022 have been filed as exhibits to this Annual Report on Form 10-K.
Qualifications of Third Party Engineers
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.
The technical person primarily responsible for the audit of our reserves estimates at DeGolyer and MacNaughton 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. DeGolyer and MacNaughton 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.
Proved Undeveloped Reserves
At December 31, 2021, we had future development costs of $2.1 billion associated with 764 MMBOE of PUD reserves, which represents a decrease of 80 MMBOE compared to December 31, 2020. By the end of 2022, we expect to complete substantially all the work necessary to convert our PUD reserves associated with wells that were drilled but uncompleted at December 31, 2021 to proved developed reserves. Future development plans are reflective of the current commodity price environment and have been established based on expected available cash flows from operations. As of December 31, 2021, all PUD reserves are expected to be drilled and completed within five years of initial disclosure of these reserves.
The following table is a reconciliation of the change in our PUD reserves (MMBOE):
Year Ended December 31, 2021
Balance at beginning of period 844
Transfers to proved developed (264)
Additions 131
Purchases of reserves in place 97
Revision of prior estimates (44)
Balance at end of period 764
Changes in PUD reserves that occurred during the year were due to:
•transfer of 264 MMBOE from PUD to proved developed reserves based on total capital expenditures of $565 million during 2021;
•new PUD reserve additions of 131 MMBOE in the Dimock field in northeast Pennsylvania;
•purchases of reserves in place of 97 MMBOE, which are primarily related to the Merger and are primarily located in the Permian Basin; and
•downward PUD reserve revisions of 44 MMBOE mainly due to performance revisions in the Marcellus Shale.
PRODUCTION, SALES PRICE AND PRODUCTION COSTS
The following table presents historical information about our total and average daily production volumes for oil, natural gas and NGLs; average oil, natural gas and NGL sales prices; and average production costs per equivalent:
Year Ended December 31,
2021(1)
2020 2019
Production Volumes
Oil (Mbbl) 8,150 - -
Natural gas (Bcf) 911 858 865
NGL (Mbbl) 7,104 - -
Equivalents (MBOE) 167,113 142,954 144,167
Average Daily Production Volumes
Oil (Mbbl) 89 - -
Natural gas (Mmcf) 2,966 2,344 2,371
NGL (Mbbl) 77 - -
Equivalents (MBOE) 660 391 395
Average Sales Price
Excluding Derivative Settlements
Oil ($/Bbl) $ 75.61 $ - $ -
Natural gas ($/Mcf) $ 3.07 $ 1.64 $ 2.29
NGL ($/Bbl) $ 34.18 $ - $ -
Including Derivative Settlements
Oil ($/Bbl) $ 60.35 $ - $ -
Natural gas ($/Mcf) $ 2.73 $ 1.68 $ 2.45
NGL ($/Bbl) $ 34.18 $ - $ -
Average Production Costs ($/BOE) $ 0.77 $ 0.36 $ 0.36
_______________________________________________________________________________
(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 and not Cimarex production for the entire year.
The following table presents historical information about our total and average daily natural gas production volumes associated with our interests in the Dimock field, which contains 15 percent or more of our total proved reserves. There was no oil or NGL production associated with our interests in the Dimock field:
Year Ended December 31,
2021 2020 2019
Production Volumes
Natural gas (Bcf) 853 858 865
Equivalents (MBOE) 142,223 142,954 144,167
Average Daily Production Volumes
Natural gas (Mmcf) 2,338 2,344 2,371
Equivalents (MBOE) 390 391 395
ACREAGE
Our interest in both developed and undeveloped properties is primarily in the form of leasehold interests held under customary mineral leases. These leases provide us the right to develop oil and/or natural gas on the properties. Their primary
terms generally range in length from approximately three to 10 years. These properties are held for longer periods if production is established.
The following table summarizes our gross and net developed and undeveloped leasehold acreage at December 31, 2021:
Acreage
Developed Undeveloped Total
Gross Net Gross Net Gross Net
Marcellus Shale
Pennsylvania 161,808 161,333 16,093 16,015 177,901 177,348
161,808 161,333 16,093 16,015 177,901 177,348
Permian Basin
New Mexico 144,942 104,470 65,533 46,099 210,475 150,569
Texas 196,848 130,070 31,697 25,562 228,545 155,632
341,790 234,540 97,230 71,661 439,020 306,201
Anadarko Basin
Oklahoma 305,621 140,347 87,100 41,993 392,721 182,340
305,621 140,347 87,100 41,993 392,721 182,340
Other
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
Colorado 3,832 1,363 25,743 19,057 29,575 20,420
Kentucky 122 92 53,237 47,303 53,359 47,395
Montana 7,397 1,606 25,020 7,307 32,417 8,913
Nevada 440 1 1,007,167 1,007,167 1,007,607 1,007,168
New Mexico 10,438 2,145 1,640,713 1,634,974 1,651,151 1,637,119
Offshore Gulf of Mexico 18,853 7,005 15,000 9,000 33,853 16,005
Pennsylvania - - 113,530 63,849 113,530 63,849
Texas 45,092 12,361 22,521 17,009 67,613 29,370
Utah 4,280 955 61,843 57,664 66,123 58,619
West Virginia - - 611,798 579,929 611,798 579,929
Wyoming 22,071 2,345 79,522 23,751 101,593 26,096
Other 5,430 867 65,511 35,005 70,941 35,872
135,162 45,947 6,202,933 5,983,343 6,338,095 6,029,290
944,381 582,167 6,403,356 6,113,012 7,347,737 6,695,179
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
2022 2023 2024
Gross Net Gross Net Gross Net
Marcellus Shale 2,701 2,701 3,020 2,933 2,048 1,888
Permian Basin 938 938 960 960 3 3
Anadarko Basin - - 4,097 934 700 134
Other 35,418 32,412 7,725 6,697 1,302 1,241
39,057 36,051 15,802 11,524 4,053 3,266
Percentage of total undeveloped acreage 1 % 1 % - % - % - % - %
At December 31, 2021, we had no proved undeveloped reserves recorded on undeveloped acreage that were scheduled for development beyond the expiration dates of the undeveloped acreage or outside of our primary operating area.
WELL SUMMARY
The following table presents our ownership in productive oil and natural gas wells at December 31, 2021. This summary includes crude oil and natural gas wells in which we have a working interest:
Gross Net
Natural Gas 3,401 1,797.0
Oil 4,960 893.4
Total(1)
8,361 2,690.4
_______________________________________________________________________________
(1)Total percentage of gross operated wells is 32 percent.
DRILLING ACTIVITY
We drilled and completed wells or participated in the drilling and completion of wells as indicated in the table below. During the years presented below, we did not drill and complete any exploration wells. The information below should not be considered indicative of future performance, nor should a correlation be assumed between the number of productive wells drilled, quantities of reserves found or economic value.
Year Ended December 31,
2021 2020 2019
Gross Net Gross Net Gross Net
Development Wells
Productive 114 99.9 74 64.3 96 94.0
Dry - - - - - -
Total 114 99.9 74 64.3 96 94.0
Acquired Wells 7,266 1,715.3 - - - -
During the year ended December 31, 2021, we completed 14 gross wells (13.0 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, 2021, which are not included in the above table:
Drilling In Progress Drilled But Uncompleted
Gross Net Gross Net
Development wells 23 14.7 66 39.7
OTHER BUSINESS MATTERS
Title to Properties
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 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 in our primary producing areas. We primarily compete with integrated, independent and other energy companies for the sale and transportation of our oil and
natural gas production to marketing companies and end users. Furthermore, the oil and gas industry competes with other energy industries that supply fuel and power to industrial, commercial and residential consumers. Many of these competitors have greater financial, technical and personnel resources. The effect of these competitive factors cannot be predicted.
Price, contract terms, availability of rigs and related equipment and quality of service, including pipeline connection times and distribution efficiencies affect competition. We believe that our concentrated acreage positions and our access to both third-party and company-owned gathering and pipeline infrastructure in 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.
Major Customers
During the year ended December 31, 2021, no customer accounted for more than 10 percent of our total sales. During the year ended December 31, 2020, three customers accounted for approximately 21 percent, 16 percent and 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 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. This regulation includes 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 in a given field 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 prohibiting the venting or flaring of natural gas and imposing certain requirements regarding the ratability of production. The effect of these regulations is to limit the amounts of oil and natural gas we can produce from our wells, and to limit the number of wells or the locations where we can drill. Because these statutes, rules and regulations undergo frequent review and often are 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 increases our cost of doing business and, consequently, affects our profitability. We do not believe, however, we are affected differently by these regulations 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. In addition, 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 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.
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, 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-Frank Act”) in July 2010, the Commodity Futures Trading Commission (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.
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, 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
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 pipeline’s rates or terms and conditions of service are unduly discriminatory or preferential. We are unable to predict with certainty the effect upon us of these periodic reviews by the FERC of the pipeline index, or any potential future challenges to pipelines' rates.
Environmental and Safety Regulations
General. Our operations are subject to extensive federal, state and local laws and regulations relating to the protection of the environment, public health, natural resources and wildlife, and relating to safety matters. 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. Government 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 significant costs and liabilities will not be incurred. 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.
U.S. laws and regulations applicable to our operations include those regulating emissions into the atmosphere, 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, and those relating to occupational health and safety.
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) or clean up property contamination (including groundwater contamination by prior owners or operators) or to perform plugging operations to prevent future contamination.
We generate some wastes that are hazardous wastes subject to the U.S. federal 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 U.S. 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 federal 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 Oil Pollution Act and related federal regulations to the extent applicable to our operations.
Endangered Species Act. The U.S. federal 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 U.S. federal Migratory Bird Treaty Act. 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 April 10, 2014, the FWS published a rule listing, as a threatened species under the ESA, the lesser prairie chicken, whose habitat is over a five-state region, including Texas, New Mexico and Oklahoma, where we conduct a substantial amount of our operations. Although the 2014 listing rule was vacated in July 2016, on June 1, 2021, the FWS proposed to list two distinct population segments (“DPS”) of the lesser prairie chicken under the ESA. The Southern DPS, located in eastern New Mexico and the southwest Texas panhandle was proposed to be listed as endangered and the Northern DPS, located in southeastern Colorado, southcentral to southwestern Kansas, western Oklahoma and the northeast Texas panhandle, was proposed to be listed as threatened. Listing of the lesser prairie chicken as a threatened or endangered species will impose restrictions on disturbances to critical habitat by landowners and drilling companies that would harass, harm or otherwise result in a “taking” of this species. Regulatory impacts on landowners and businesses from an ultimate decision to list the lesser prairie chicken could be limited for those landowners and businesses who have entered into certain range-wide conservation planning agreements, such as those developed by the Western Association of Fish and Wildlife Agencies (“WAFWA”), pursuant to which such parties agreed to take steps to protect the lesser prairie chicken’s habitat and to pay a mitigation fee if its actions harm the lesser prairie chicken’s habitat. We have entered into a voluntary Candidate Conservation Agreement (a “CCA”) with the WAFWA, whereby we agreed to take certain actions and limit certain activities, such as limiting drilling on certain portions of our acreage during nesting seasons, in an effort to protect the lesser prairie chicken.
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 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 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 could be impacted if the Peppered Chub is listed as endangered under the ESA or if the FWS declares the basins of the South Canadian river to be critical habitat. 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 U.S. 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 wastewaters 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 U.S. 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 could add costs and cause 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. 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 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 and/or criminal penalties for noncompliance. Obtaining permits may delay the development of our oil and natural gas projects, including the construction and operation of facilities.
Safe Drinking Water Act. The U.S. 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 emplacement of fluids (including disposal wells or enhanced oil recovery) is governed by U.S. 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. This technology involves the injection of fluids, usually consisting mostly of water but typically including small amounts of several chemical additives, as well as sand into a well under high pressure in order to create fractures in the formation that allow oil or natural gas to flow more freely to the wellbore. Most of our wells would not be economical without the use of hydraulic fracturing to stimulate production from the well. 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. For example, New York issued a statewide ban on hydraulic fracturing in June 2015. 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/or 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.
Water is an essential component of oil and natural gas production during the drilling process, and, in particular, we use a significant amount of water in the hydraulic fracturing process. Our inability to locate sufficient amounts of water, or 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, including as a result of potential regulatory and legislative changes due to the outcome of the 2020 U.S. congressional and presidential elections 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 flowback and produced water from well sites as a preferred alternative to disposal.
The adoption of U.S. federal, state or local laws or the implementation of regulations affecting our ability to conduct hydraulic fracturing could potentially cause a decrease in the completion of new oil and natural gas wells and increased compliance costs, which could increase costs of our operations and cause considerable delays in acquiring regulatory approvals to drill and complete wells. In addition, if existing laws and regulations with regard to hydraulic fracturing are revised or reinterpreted or if new laws and regulations become applicable to our operations through judicial or administrative actions, our business, financial condition, results of operations and cash flows could be adversely affected. For example, a Pennsylvania state appellate court in 2018 appeared to refuse to apply the established common law rule of capture in a case concerning claims of trespass by hydraulic fracturing. The Pennsylvania Supreme Court heard the appeal of this ruling and on January 22, 2020, in Briggs v. Southwestern Energy Production Co., 224 A.3d 334 (“Pa. 2020”), affirmed the rule of capture and remanded the case
to the Pennsylvania state appellate court for further proceedings. On December 8, 2020, the appellate court issued a non-precedential decision reversing its previous order vacating the trial court’s summary judgment in favor of Southwestern Energy Production Co. (Southwestern). The appellate court refuted the assumptions made by the Pennsylvania Supreme Court concerning the appellate court’s disregard of the established rule of capture and based its reversal on the failure of plaintiffs to “specifically allege that Southwestern engaged in horizontal drilling that extended onto their property, or that Southwestern propelled fracturing fluids and proppants across the property line,” leaving open the possibility that hydraulic fracturing can constitute a physical invasion, and thereby a trespass. Future developments in case law that expand the ability of adjacent property owners to prevail on trespass claims based on hydraulic fracturing could have a material impact on our operations.
Greenhouse Gas and Climate Change Laws and Regulations. In response to studies suggesting that emissions of carbon dioxide and certain other greenhouse gases (“GHGs”), 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. 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% 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. 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% clean energy” economy with net-zero GHG emissions.
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/or 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, the California 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.
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/or 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
We believe that our ability to attract, retain and develop the highest quality employees is a vital component of our success. In connection with the Merger, we developed an integration plan for every corporate functional organization and are in the process of completing staff reorganizations, relocations of key employees and hiring of new talent for our corporate headquarters in Houston, Texas. Staff reductions will occur primarily in our Denver, Colorado office (which will eventually be closed) and our Tulsa, Oklahoma office, which will be dedicated to management of our Anadarko Basin operations, with other corporate functions transferred to Houston. Detailed transition and knowledge transfer plans are intended to ensure that key aspects of ongoing operations are uninterrupted through this process. Our staff reorganization plans are intended to eliminate redundancy between the legacy company organizations, and our hiring plans aim to accelerate our ability to attract and develop a diverse workforce. We believe that the resulting employee levels from our integration plan are appropriate and that we will continue to have the human capital to operate our business and carry out our strategy as determined by management and our Board of Directors.
As of December 31, 2021, with the addition of employees as a result of the Merger, we had 936 total employees, 165 of whom were located in our headquarters in Houston, Texas and our corporate office in Denver, Colorado and 417 of whom were located in our regional offices in Midland, Texas, Tulsa Oklahoma and Pittsburgh, Pennsylvania. We had a total of 354 employees in production field locations across our regional offices. Of our total employee population, 611 were salaried and 325 were hourly. We also have 211 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, 15 were salaried and 196 were hourly. As a result of consistent communication and transparent management, we believe that our relations with our employees are favorable. None of our employees are represented pursuant to a collective bargaining agreement.
In managing our human capital resources, we seek to:
•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;
•offer highly competitive compensation and benefits packages; and
•promote a safe and healthy workplace.
We believe these practices, further described below, are the key drivers in our development of current and future talent and leadership as well as low voluntary turnover rates, which averaged less than five percent over the five-year period ended December 31, 2021.
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 in an effort to ensure 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 expand the role or
promote current 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 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 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 that 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 comprehensive environmental, health and safety (“EHS”) management system establishes a corporate governance framework for EHS compliance and performance and covers all elements of our operating lifecycle.
Our EHS management system provided the framework to implement immediate and comprehensive safety protocols in response to the COVID-19 pandemic that struck suddenly in early 2020. All of our employees are designated “critical infrastructure workers” under the Cybersecurity & Infrastructure Security Agency guidelines, and as a result, our field operations continued throughout 2020 and 2021. The actions taken to prevent the spread of infection on our worksites and promote the health and safety of our workforce include:
•implementing and providing training on a COVID-19 Safety Policy containing personal safety protocols, such as face coverings, social distancing requirements and personal hygiene measures;
•providing additional personal protective equipment;
•implementing rigorous COVID-19 self-assessment, contact tracing and quarantining protocols;
•increasing cleaning protocols at all locations;
•limiting business travel;
•providing additional paid leave to employees with actual or presumed COVID-19 cases; and
•encouraging our employees to obtain COVID-19 vaccinations and providing incentives to do so.
Due to these measures, all of our operations continued safely and uninterrupted through the onset of the pandemic in 2020 and throughout 2021. We also implemented appreciation award programs for many of our employees who have continued to work onsite during the pandemic.
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 is not a part of, and is not incorporated into, this report or any other report we may file with or furnish to the SEC, whether before or after the date of this report 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, Corporate Bylaws, Audit Committee Charter, Compensation Committee Charter, Governance and Social Responsibility Committee Charter, Code of Business Conduct and Environment, Health & Safety Committee Charter are available on our website at www.coterra.com, under the “Corporate Governance” section of “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.

---

ITEM 1A. RISK FACTORS
ITEM 1A. RISK FACTORS
Business and Operational Risks
You should carefully consider the following risk factors in addition to the other information included in this report. Each of these risk factors could adversely affect our business, financial condition, results of operations and/or cash flows, as well as adversely affect the value of an investment in our common stock or debt securities.
Commodity prices fluctuate widely, and low prices for an extended period would likely have a material adverse impact on our business.
Our revenues, operating results, financial condition and ability to borrow funds or obtain additional capital depend substantially on prices we receive for the oil, natural gas and NGLs that we sell. Lower commodity prices may reduce the amount of oil, natural gas and NGLs that we can produce economically. Historically, commodity prices have been volatile, with prices fluctuating widely, and they are likely to continue to be volatile. For example, the WTI oil prices in 2021 ranged from a high of $84.65 to a low of $47.62 per Bbl and NYMEX natural gas prices in 2021 ranged from a high of $23.86 (during Winter Storm Uri) to a low of $2.43 per Mmbtu. Any substantial or extended decline in future commodity prices would have a material adverse effect on our future business, financial condition, results of operations, cash flows, liquidity or ability to finance planned capital expenditures and commitments. Furthermore, substantial, extended decreases in commodity prices may cause us to delay or postpone a significant portion of our exploration and development projects or may render such projects uneconomic, which may result in significant downward adjustments to our estimated proved reserves and could negatively impact our ability to borrow and cost of capital and our ability to access capital markets, increase our costs under our revolving credit facility and limit our ability to execute aspects of our business plans. Refer to “Future 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.”
Wide fluctuations in commodity prices may result from relatively minor changes in the supply of and demand for oil, natural gas and NGLs, market uncertainty and a variety of additional factors that are beyond our control. These factors include but are not limited to the following:
•the levels and location of oil, natural gas and NGLs supply and demand and expectations regarding supply and demand, including the potential long-term impact of an abundance of natural gas from shale (such as that produced from our Marcellus Shale properties) on the global natural gas supply;
•the level of consumer demand for oil, natural gas and NGLs, which has been significantly impacted by the COVID-19 pandemic, particularly during 2020;
•weather conditions and seasonal trends;
•political, economic or health conditions in oil, natural gas and NGL producing regions, including the Middle East, Africa, South America and the U.S., including for example, the impacts of local or international pandemics and disasters or events such as the global COVID-19 pandemic;
•the ability and willingness of the members of OPEC+ to agree to and maintain oil price and production controls;
•the price level and quantities of foreign imports;
•actions of governmental authorities;
•the availability, proximity and capacity of gathering, transportation, processing and/or refining facilities in regional or local areas;
•inventory storage levels and the cost and availability of storage and transportation of oil, natural gas and NGLs;
•the nature and extent of domestic and foreign governmental regulations and taxation, including environmental and climate change regulation;
•the price, availability and acceptance of alternative fuels;
•technological advances affecting energy consumption;
•speculation by investors in oil, natural gas and NGLs;
•variations between product prices at sales points and applicable index prices; and
•overall economic conditions, including the value of the U.S. dollar relative to other major currencies.
These factors and the volatile nature of the energy markets make it impossible to predict future commodity prices. If commodity prices decline significantly for a sustained period of time, the lower prices may cause us to reduce our planned drilling program or adversely affect our ability to make planned expenditures, raise additional capital or meet our financial obligations.
Drilling oil and natural gas wells is a high-risk activity.
Our growth is materially dependent upon the success of our drilling program. Drilling for oil and natural gas involves numerous risks, including the risk that no commercially productive reservoirs will be encountered. The cost of drilling, completing and operating wells is substantial and uncertain, and drilling operations may be curtailed, delayed or canceled as a result of a variety of factors beyond our control, including:
•decreases in commodity prices;
•unexpected drilling conditions, pressure or irregularities in formations;
•equipment failures or accidents, including blowouts, explosions and fires;
•adverse weather conditions;
•surface access restrictions;
•loss of title or other title related issues;
•lack of available gathering or processing facilities or delays in the construction thereof;
•compliance with, or changes in, governmental requirements and regulation, including with respect to wastewater disposal, discharge of greenhouse gases and fracturing;
•unusual or unexpected geological formations or pressure or irregularities in formations; and
•costs of shortages or delays in the availability of drilling rigs or crews and the delivery of equipment and materials.
Our future drilling activities may not be successful and, if unsuccessful, such failure will have an adverse effect on our future results of operations and financial condition. Our overall drilling success rate or our drilling success rate within a particular geographic area may decline. We may be unable to lease or drill identified or budgeted prospects within our expected time frame, or at all. We may be unable to lease or drill a particular prospect because, in some cases, we identify a prospect or drilling location before seeking an option or lease rights in the prospect or location. Similarly, our drilling schedule may vary from our capital budget. The final determination with respect to the drilling of any scheduled or budgeted wells will depend on a number of factors, including:
•the results of exploration efforts and the acquisition, review and analysis of seismic data;
•the availability of sufficient capital resources to us and the other participants for the drilling of the prospects;
•the approval of the prospects by other participants after additional data has been compiled;
•economic and industry conditions at the time of drilling, including prevailing and anticipated prices for oil and natural gas and the availability of drilling rigs and crews;
•our financial resources and results; and
•the availability of leases and permits on reasonable terms for the prospects and any delays in obtaining such permits.
These projects may not be successfully developed and the wells, if drilled, may not encounter reservoirs of commercially productive oil or natural gas.
Business disruptions from unexpected events, including pandemics, health crises and natural disasters, may disrupt our operations and adversely affect our business, financial condition and results of operations.
The occurrence of one or more unexpected events, including a public health crisis, pandemic and epidemic, war or civil unrest, a terrorist act, a cybersecurity incident resulting in unauthorized access to sensitive information or causing data or
systems to be unusable, a weather event, an earthquake or other catastrophe could cause instability in world financial markets and lead to increased volatility in prices for oil and natural gas, all of which could adversely affect our business, financial condition and results of operations. For example, the ongoing COVID-19 outbreak has resulted in widespread adverse impacts on the global economy. There is considerable uncertainty regarding the extent to which COVID-19 will continue to spread, including new strains of COVID-19 such as the Delta and Omicron variants, the global availability and efficacy of treatments and vaccines and boosters and the acceptance of such treatments and vaccines by a significant portion of the population, and the extent and duration of governmental and other measures implemented to try to slow the spread of the virus, such as quarantines, shelter-in-place orders and business and government shutdowns (whether through a continuation of existing measures or the re-imposition of prior measures). The worldwide vaccine rollouts in 2021 have allowed governments to ease COVID-19 restrictions and lockdown protocols; however, the recent increase in COVID-19 cases resulting from the Delta and Omicron variants has created questions about whether lockdown protocols must be adjusted and the ultimate impact of those variants is unknown. We have implemented preventative measures and developed response plans intended to minimize unnecessary risk of exposure to infection among our employees at our work sites, and we continue to assess and plan for various operational contingencies related to COVID-19. However, if a significant portion of our employees or contractors or the employees or contractors of the operators of pipelines, processing and other facilities we utilize or of our vendors or suppliers were unable to work due to illness or if our field operations were suspended or temporarily restricted due to control measures designed to contain the outbreak, that could adversely affect our business, financial condition and results of operations, and we cannot guarantee that any precautionary actions taken by us will be effective in preventing disruptions to our business. In the event of any significant resurgence in COVID-19 transmission and infection in the areas in which we operate, our non-operational employees may return to working remotely, which could increase the risk of security breaches or other cyber-incidents or attacks, loss of data, fraud and other disruptions as a consequence of more employees accessing sensitive and critical information from remote locations via network infrastructure and internet services not arranged, established or secured by us.
Additionally, vaccination and testing requirements related to COVID-19 could impact our business in the future. In September 2021, the OSHA was directed to implement an emergency temporary standard requiring employers with 100 or more employees to ensure their workforce is fully vaccinated or to require unvaccinated workers to produce a negative COVID-19 test result on at least a weekly basis. Although the U.S. Supreme Court recently blocked the implementation of the standard, the future implementation of similar mandatory vaccination and testing requirements could have a material adverse effect on our business, financial condition or results of operations in the event that, among other things, a significant portion of our workforce does not choose to become vaccinated, the costs related to mandatory testing for unvaccinated employees are significant or the time away from work for testing is disruptive to our operations.
Furthermore, the COVID-19 pandemic caused a significant reduction in demand for crude oil, and to a lesser extent, natural gas and NGLs during much of 2020. The supply/demand imbalance driven by the COVID-19 pandemic and production disagreements in March 2020 among members of OPEC+ led to a significant global economic contraction generally in 2020 and continued to have disruptive impacts on our industry in 2021. Although an agreement to cut production was subsequently announced by OPEC+, the situation, coupled with the impact of COVID-19 and storage and transportation capacity constraints, resulted in a significant downturn in the oil and gas industry. We cannot predict the full impact that COVID-19 and its variants or the significant disruption and volatility currently being experienced in the oil and natural gas markets will have on our business, financial condition and results of operations at this time due to numerous uncertainties. For example, the operations of our midstream service providers, on whom we rely for the transmission, gathering and processing of a significant portion of our produced oil, natural gas and NGLs, may be disrupted or suspended in response to containing outbreaks, and/or the economic challenges may lead to a reduction in capacity or closing of the facilities and infrastructure of our midstream service providers, which may result in substantial discounts in the prices we receive for our produced oil, natural gas or NGLs or result in the shut-in of producing wells or the delay or discontinuance of development plans for our properties. Although we have not received notices from our customers or counterparties regarding non-performance issues or delays resulting from the COVID-19 pandemic, to the extent we or any of our material suppliers or customers are unable to operate due to government restrictions or otherwise, we may have to temporarily shut down or reduce production, which could result in significant downtime and have significant adverse consequences for our business, financial condition and results of operations.
In addition, the COVID-19 pandemic has impacted supply chains, delaying deliveries of supplies and equipment and increasing costs. Our costs for services, labor and supplies increased during 2021 due to increased demand for those items and supply chain disruptions related to the COVID-19 pandemic. The ultimate impacts of the COVID-19 pandemic will depend on future developments, including, among others, the ultimate severity of the virus, any resurgence in COVID-19 transmission and infection in affected regions after they have begun to experience improvements, the consequences of governmental and other measures, the efficacy of treatments and vaccines and boosters and the success of vaccination programs, the duration of the outbreak, further actions taken by members of OPEC+, actions taken by governmental authorities, customers, suppliers and other third parties, workforce availability and the timing and extent to which normal economic and operating conditions resume.
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.
Reserve engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact manner. The process of estimating quantities of proved reserves is complex and inherently imprecise, and the reserve data included in this document are only estimates. The process relies on interpretations of available geologic, geophysical, engineering and production data. The extent, quality and reliability of this technical data can vary. The process also requires certain economic assumptions, some of which are mandated by the SEC, such as assumptions relating to commodity prices. Additional assumptions include drilling and operating expenses, capital expenditures, taxes and availability of funds. Furthermore, different reserve engineers may make different estimates of reserves and cash flows based on the same data.
Results of drilling, testing and production subsequent to the date of an estimate may justify revising the original estimate. Accordingly, initial reserve estimates often vary from the quantities of oil and natural gas that are ultimately recovered, and such variances may be material. Any significant variance could reduce the estimated quantities and present value of our reserves.
You should not assume that the present value of future net cash flows from our proved reserves is the current market value of our estimated reserves. In accordance with SEC requirements, we base the estimated discounted future net cash flows from our proved reserves on the 12-month average index price for the respective commodity, calculated as the unweighted arithmetic average for the first day of the month price for each month and costs in effect on the date of the estimate, holding the prices and costs constant throughout the life of the properties. Actual future prices and costs may differ materially from those used in the net present value estimate, and future net present value estimates using then current prices and costs may be significantly less than the current estimate. In addition, the 10 percent discount factor we use when calculating discounted future net cash flows for reporting requirements in compliance with the applicable accounting standards may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the oil and gas industry in general.
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.
The value of our oil and gas properties depends on commodity prices. Declines in these prices as well as increases in development costs, changes in well performance, delays in asset development or deterioration of drilling results may result in our having to make material downward adjustments to our estimated proved reserves, and could result in an impairment charge and a corresponding write-down of the carrying amount of our oil and gas properties.
We evaluate our oil and gas properties for impairment on a field-by-field basis whenever events or changes in circumstances indicate a property's carrying amount may not be recoverable. We compare expected undiscounted future cash flows to the net book value of the asset. If the future undiscounted expected cash flows, based on our estimate of future commodity prices, operating costs and anticipated production from proved reserves and risk-adjusted probable and possible reserves, are lower than the net book value of the asset, the capitalized cost is reduced to fair value. Commodity pricing is estimated by using a combination of assumptions management uses in its budgeting and forecasting process as well as historical and current prices adjusted for geographical location and quality differentials, as well as other factors that management believes will impact realizable prices. In the event that commodity prices decline, there could be a significant revision to the carrying amounts of oil and gas properties in the future.
Our future performance depends on our ability to find or acquire additional oil and natural gas reserves that are economically recoverable.
In general, the production rate of oil and gas properties declines as reserves are depleted, with the rate of decline depending on reservoir characteristics. Unless we successfully replace the reserves that we produce, our reserves will decline, eventually resulting in a decrease in oil and natural gas production and lower revenues and cash flow from operations. Our future production is, therefore, highly dependent on our level of success in finding or acquiring additional reserves. We may not be able to replace reserves through our exploration, development and exploitation activities or by acquiring properties at acceptable costs. Low commodity prices may further limit the kinds of reserves that we can develop and produce economically.
We estimate that production from our proved developed reserves as of December 31, 2021 will decrease at a rate of 24 percent, 17 percent and 13 percent during 2023, 2024 and 2025, respectively (although production from our proved developed reserves is expected to increase during 2022 due to the effects of the Merger, partially offset by natural decline rates). Future development of proved undeveloped and other reserves that we have not currently classified as proved developed producing will impact these rates of decline.
Exploration, development and exploitation activities involve numerous risks that may result in, among other things, dry holes, the failure to produce oil, natural gas and NGLs in commercial quantities and the inability to fully produce discovered reserves.
The development of our proved undeveloped reserves may take longer and may require higher levels of capital expenditures than we currently anticipate.
As of December 31, 2021, approximately 26 percent of our estimated proved reserves (by volume) were undeveloped. These reserve estimates reflect our plans to make capital expenditures for estimated future development costs of $2.1 billion to convert our PUD reserves into proved developed reserves. Developing PUD reserves requires significant capital expenditures, and the estimated future development costs associated with our PUD reserves may not equal our actual costs, development may not occur as scheduled and results of our development activities may not be as estimated. If we choose not to develop our PUD reserves, or if we are not otherwise able to develop them successfully, we will be required to remove them from our reported proved reserves. In addition, under the SEC’s reserve reporting rules, because PUD reserves generally may be recorded only if they relate to wells scheduled to be drilled within five years of the date of booking, we may be required to remove any PUD reserves that are no longer planned to be developed within this five-year time frame.
Strategic determinations, including the allocation of capital and other resources to strategic opportunities, are challenging, and our failure to appropriately allocate capital and resources among our strategic opportunities may adversely affect our financial condition and reduce our growth rate.
Our future growth prospects depend on our ability to identify optimal strategies for our business. In developing our business plans, we considered allocating capital and other resources to various aspects of our business including well-development (primarily drilling), reserve acquisitions, exploratory activity, corporate items and other alternatives. We also consider our likely sources of capital. Notwithstanding the determinations made in the development of our 2022 plan, business opportunities not previously identified periodically may come to our attention, including possible acquisitions and dispositions. If we fail to identify optimal business strategies, or fail to optimize our capital investment and capital raising opportunities and the use of our other resources in furtherance of our business strategies, our financial condition and growth rate may be adversely affected. Moreover, economic or other circumstances may change from those contemplated by our 2022 plan, and our failure to recognize or respond to those changes may limit our ability to achieve our objectives.
Our ability to sell our oil, natural gas and NGL production and/or the prices we receive for our production could be materially harmed if we fail to obtain adequate services such as transportation and processing.
The sale of our oil, natural gas and NGL production depends on a number of factors beyond our control, including the availability and capacity of transportation and processing facilities. We deliver the majority of our oil, natural gas and NGL production through gathering systems and pipelines that we do not own. The lack of available capacity on these systems and facilities could reduce the price offered for our production or result in the shut-in of producing wells or the delay or discontinuance of development plans for properties. Third-party systems and facilities may be unavailable due to market conditions or mechanical or other reasons, and in some cases the resulting curtailments of production could lead to payment being required where we fail to deliver oil, natural gas and NGLs to meet minimum volume commitments. In addition, construction of new pipelines and building of required infrastructure may be slow to build out. To the extent these services are unavailable, we would be unable to realize revenue from wells served by such facilities until suitable arrangements are made to market our production. Our failure to obtain these services on acceptable terms could materially harm our business.
Moreover, these availability and capacity issues are more likely to occur in remote areas with less established infrastructure, such as our Delaware Basin properties where we have significant oil and natural gas production. Any of these availability or capacity issues, whether resulting from the COVID-19 pandemic, construction delays, government restrictions, adverse weather conditions (such as the severe winter storm that impacted Texas and Oklahoma in February 2021), fire or other reasons, could negatively affect our operations, revenues and expenses. In addition, the Marcellus Shale wells we have drilled to date have generally reported very high initial production rates. The amount of natural gas being produced in the area from these new wells, as well as natural gas produced from other existing wells, may exceed the capacity of the various gathering and intrastate or interstate transportation pipelines currently available. In such an event, this could result in wells being shut in or awaiting a pipeline connection or capacity and/or natural gas being sold at much lower prices than those quoted on NYMEX or than we currently project, which would adversely affect our results of operations and cash flows.
Acquired properties may not be worth what we pay to acquire them, due to uncertainties in evaluating recoverable reserves and other expected benefits, as well as potential liabilities.
Successful property acquisitions require an assessment of a number of factors beyond our control. These factors include estimates of recoverable reserves, exploration potential, future commodity prices, operating costs, production taxes and
potential environmental and other liabilities. These assessments are complex and inherently imprecise. Our review of the properties we acquire may not reveal all existing or potential problems. In addition, our review may not allow us to assess fully the potential deficiencies of the properties. We do not inspect every well, and even when we inspect a well we may not discover structural, subsurface or environmental problems that may exist or arise.
There may be threatened or contemplated claims against the assets or businesses we acquire related to environmental, title, regulatory, tax, contract, litigation or other matters of which we are unaware, which could materially and adversely affect our production, revenues and results of operations. We often assume certain liabilities, and we may not be entitled to contractual indemnification for pre-closing liabilities, including environmental liabilities, and our contractual indemnification may not be effective. At times, we acquire interests in properties on an “as is” basis with limited representations and warranties and limited remedies for breaches of such representations and warranties. In addition, significant acquisitions can change the nature of our operations and business if the acquired properties have substantially different operating and geological characteristics or are in different geographic locations than our existing properties.
The integration of the businesses and properties we have acquired or may in the future acquire could be difficult, and may divert management's attention away from our existing operations.
The integration of the businesses and properties we have acquired, including via the Merger, or may in the future acquire could be difficult, and may divert management's attention and financial resources away from our existing operations. These difficulties include:
•the challenge of integrating the acquired businesses and properties while carrying on the ongoing operations of our business;
•the inability to retain key employees of the acquired business;
•the challenge of inconsistencies in standards, controls, procedures and policies of the acquired business;
•potential unknown liabilities, unforeseen expenses or higher-than-expected integration costs;
•an overall post-completion integration process that takes longer than originally anticipated;
•potential lack of operating experience in a geographic market of the acquired properties; and
•the possibility of faulty assumptions underlying our expectations.
If management is not able to effectively manage the integration process, or if any significant business activities are interrupted as a result of the integration process, our business could suffer. Our future success will depend, in part, on our ability to manage our expanded business, which may pose substantial challenges for management. We may also face increased scrutiny from governmental authorities as a result of the increase in the size of our business. There can be no assurances that we will be successful in our integration efforts.
We face a variety of hazards and risks that could cause substantial financial losses.
Our business involves a variety of operating risks, including:
•well site blowouts, cratering and explosions;
•equipment failures;
•pipe or cement failures and casing collapses, which can release oil, natural gas, drilling fluids or hydraulic fracturing fluids;
•uncontrolled flows of oil, natural gas or well fluids;
•pipeline ruptures;
•fires;
•formations with abnormal pressures;
•handling and disposal of materials, including drilling fluids and hydraulic fracturing fluids;
•release of toxic gas;
•buildup of naturally occurring radioactive materials;
•pollution and other environmental risks, including conditions caused by previous owners or operators of our properties; and
•natural disasters.
Any of these events could result in injury or loss of human life, loss of hydrocarbons, significant damage to or destruction of property, environmental pollution, natural resource damages, regulatory investigations and penalties, suspension or impairment of our operations and substantial losses to us.
Our utilization of oil and natural gas gathering and pipeline systems also involves various risks, including the risk of explosions and environmental hazards caused by pipeline leaks and ruptures. The location of pipelines near populated areas, including residential areas, commercial business centers and industrial sites, could increase these risks.
We have limited control over the activities on properties we do not operate.
Other companies operate some of the properties in which we have an interest. As of December 31, 2021, non-operated wells represented approximately 68 percent of our total owned gross wells, or 18 percent of our owned net wells. We have limited ability to influence or control the operation or future development of these non-operated properties and on properties we operate in joint ventures in which we may share control with third parties, including compliance with environmental, safety and other regulations or the amount of capital expenditures that we are required to fund with respect to them. The failure of an operator of our wells or joint venture participant to adequately perform operations, an operator's breach of the applicable agreements or an operator's failure to act in ways that are in our best interest could reduce our production and revenues. Our dependence on the operator and other working interest owners, including a joint venture participant, for these projects and our limited ability to influence or control the operation and future development of these properties could materially adversely affect the realization of our targeted returns on capital in drilling or acquisition activities and lead to unexpected future costs.
Many of our properties are in areas that may have been partially depleted or drained by offset wells and certain of our wells may be adversely affected by actions other operators may take when drilling, completing or operating wells that they own.
Many of our properties are in areas that may have been partially depleted or drained by earlier offset drilling. We have no control over offsetting operators, who could take actions, such as drilling and completing additional wells, which could adversely affect our operations. When a new well is completed and produced, the pressure differential in the vicinity of the wellbore causes the migration of reservoir fluids toward the new wellbore (and potentially away from existing wellbores), which could cause a depletion of our proved reserves and may inhibit our ability to further develop our proved reserves. The possibility for these impacts may increase with respect to wells that are shut in as a response to lower commodity prices or the lack of pipeline and storage capacity. In addition, completion operations and other activities conducted on other nearby wells could cause us, in order to protect our existing wells, to shut in production for indefinite periods of time. Shutting in our wells and damage to our wells from offset completions could result in increased costs and could adversely affect the reserves and re-commenced production from such shut in wells.
We may lose leases if production is not established within the time periods specified in the leases or if we do not maintain production in paying quantities.
We could lose leases under certain circumstances if we do not maintain production in paying quantities or meet other lease requirements, and the amounts we spent for those leases could be lost. If we shut in wells in response to lower commodity prices or a lack of pipeline and storage capacity, we may face claims that we are not complying with lease provisions. In addition, the Biden administration also may impose new restrictions and regulations affecting our ability to drill, conduct hydraulic fracturing operations, and obtain necessary rights-of-way on federal lands, which could, in turn, result in the loss of federal leases. The combined net acreage expiring over the next three years represents approximately one percent of our total net undeveloped acreage as of December 31, 2021. Our actual drilling activities may materially differ from those presently identified, which could adversely affect our business.
Cyber-attacks targeting our systems, the oil and gas industry systems and infrastructure or the systems of our third-party service providers could adversely affect our business.
Our business and the oil and gas industry in general have become increasingly dependent on digital data, computer networks and connected infrastructure, including technologies that are managed by third-party providers on whom we rely to help us collect, host or process information. We depend on this technology to record and store financial data, estimate quantities of oil and natural gas reserves, analyze and share operating data and communicate internally and externally. Computers control
nearly all of the oil and gas distribution systems in the U.S., which are necessary to transport our products to market. Computers also enable communications and provide a host of other support services for our business. In recent years (and, in large part, due to the COVID-19 pandemic), we have increased the use of remote networking and online conferencing services and technologies that enable employees to work outside of our corporate infrastructure, which exposes us to additional cybersecurity risks, including unauthorized access to sensitive information as a result of increased remote access and other cybersecurity related incidents.
Cyber-attacks are becoming more sophisticated and include, but are not limited to, malicious software, phishing, ransomware, attempts to gain unauthorized access to data and other electronic security breaches that could lead to disruptions in critical systems, unauthorized release of confidential or otherwise protected information and corruption of data. Unauthorized access to our seismic data, reserves information, customer or employee data or other proprietary or commercially sensitive information could lead to data corruption, communication interruption or other disruptions in our exploration or production operations or planned business transactions, any of which could have a material adverse impact on our business and operations. If our information technology systems cease to function properly or are breached, we could suffer disruptions to our normal operations, which may include drilling, completion, production and corporate functions. A cyber-attack involving our information systems and related infrastructure, or that of our business associates, could result in supply chain disruptions that delay or prevent the transportation and marketing of our production, non-compliance leading to regulatory fines or penalties, loss or disclosure of, or damage to, our or any of our customer’s or supplier’s data or confidential information that could harm our business by damaging our reputation, subjecting us to potential financial or legal liability and requiring us to incur significant costs, including costs to repair or restore our systems and data or to take other remedial steps.
In addition, certain cyber incidents, such as surveillance, may remain undetected for an extended period, and our systems and insurance coverage for protecting against such cybersecurity risks may be costly and may not be sufficient. As cyber-attackers become more sophisticated, we may be required to expend significant additional resources to continue to protect our business or remediate the damage from cyber-attacks. Furthermore, the continuing and evolving threat of cyber-attacks has resulted in increased regulatory focus on prevention, and we may be required to expend significant additional resources to continue to modify or enhance our protective measures or to investigate and remediate any information security vulnerabilities. To the extent we face increased regulatory requirements, we may be required to expend significant additional resources to meet such requirements.
Risks Related to our Indebtedness, Hedging Activities and Financial Position
We have substantial capital requirements, and we may not be able to obtain needed financing on satisfactory terms, if at all.
We make and expect to make substantial capital expenditures in connection with our development and production projects. We rely on access to both our revolving credit facility and longer-term capital markets as sources of liquidity for any capital requirements not satisfied by cash flow from operations or other sources. Future challenges in the global financial system, including the capital markets, may adversely affect our business, financial condition and access to capital. Our ability to access the capital markets may be restricted at a time when we desire, or need, to raise capital, which could have an impact on our flexibility to react to changing economic and business conditions. Adverse economic and market conditions could adversely affect the collectability of our trade receivables and cause our commodity hedging counterparties to be unable to perform their obligations or to seek bankruptcy protection. In addition, there have been efforts in recent years aimed at the investment community, including investment advisors, sovereign wealth funds, public pension funds, universities and other groups, promoting the divestment of fossil fuel equities as well as to pressure lenders and other financial services companies to limit or curtail activities with companies engaged in the extraction of fossil fuel reserves, which, if successful, could limit our ability to access capital markets. For example, in October 2020, JP Morgan Chase & Co. announced that it was adopting a financing commitment that is aligned to the goals of the Paris climate accord of 2015 (the “Paris Agreement”). Other banks have made climate-related pledges for various causes, such as stopping the financing of Arctic drilling and coal companies. These initiatives by activists and banks, including certain banks who are parties to the credit agreement providing for our revolving credit facility, could interfere with our business activities, operations and ability to access capital. Future challenges in the economy could also lead to reduced demand for oil and natural gas, which could have a negative impact on our revenues.
Risks associated with our debt and the provisions of our debt agreements could adversely affect our business, financial position and results of operations.
As of December 31, 2021, we had approximately $3.1 billion of debt outstanding (with a principal amount of $2.9 billion) and we may incur additional indebtedness in the future. Following the Merger, our legacy revolving credit facility and private placement senior notes remained outstanding. In addition, on October 7, 2021, we completed an exchange offer, whereby we issued $1.8 billion in aggregate principal amount of new senior notes in exchange for $1.8 billion in aggregate principal amount of previously outstanding Cimarex senior notes. Following completion of that exchange offer, approximately $200 million in aggregate principal amount of Cimarex senior notes remained outstanding. The increase in our indebtedness as a result of the Merger and related transactions could have adverse effects on our business, financial condition, results of operations and cash flows, including by:
•requiring us to use a substantial portion of our cash flow to make debt service payments, which will reduce the funds that would otherwise be available for operations, returning free cash flow to stockholders and future business opportunities;
•increasing the risk of default on debt obligations;
•limiting our ability to sell assets, engage in strategic transactions or obtain additional financing for working capital, capital expenditures, general corporate and other purposes;
•limiting our flexibility in planning for or reacting to changes in our business and the industry in which we operate, which could place us at a competitive disadvantage compared to our competitors with lower debt-service obligations;
•increasing our exposure to a rise in interest rates, which would generate greater interest expense to the extent we do not have applicable interest rate fluctuation hedges;
•depending on the levels of our outstanding debt, limit our ability to obtain additional financing for working capital, capital expenditures, general corporate and other purposes; and
•increasing our vulnerability to adverse changes in general economic and industry conditions, including declines in commodity prices, economic downturns and adverse developments in our business.
Our ability to make payments on and to refinance our indebtedness will depend on our ability to generate cash in the future from operations, financings or asset sales. Our ability to generate cash is subject to general economic, financial, competitive, legislative, regulatory and other factors that are beyond our control. In addition, our ability to withstand competitive pressures and to react to changes in the oil and gas industries could be impaired. If we fail to make required payments or otherwise default on our debt, the lenders who hold such debt also could accelerate amounts due, which could potentially trigger a default or acceleration of other debt.
In addition, the margins we pay under our revolving credit facility depend on (1) the credit rating of our debt, at times when our debt has an investment grade credit rating and (2) our leverage ratio, at times when our debt does not have an investment grade rating. Accordingly, adverse changes in our leverage ratio or the credit rating of our debt may result in an increase in our interest expense.
Our debt agreements also require compliance with covenants to maintain specified financial ratios. If commodity prices deteriorate from current levels, it could lead to reduced revenues, cash flow and earnings, which in turn could lead to a default due to lack of covenant compliance. Because the calculations of the financial ratios are made as of certain dates, the financial ratios can fluctuate significantly from period to period. A prolonged period of lower commodity prices could further increase the risk of our inability to comply with covenants to maintain specified financial ratios. In order to provide a margin of comfort with regard to these financial covenants, we may seek to reduce our capital expenditures, sell non-strategic assets or opportunistically modify or increase our derivative instruments to the extent permitted under our debt agreements. In addition, we may seek to refinance or restructure all or a portion of our indebtedness. We cannot provide assurance that we will be able to successfully execute any of these strategies, and such strategies may be unavailable on favorable terms or at all. For more information about our debt agreements, please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations-Financial Condition-Capital Resources and Liquidity.”
We may have hedging arrangements that expose us to risk of financial loss and limit the benefit to us of increases in prices for oil and natural gas.
From time to time, when we believe that market conditions are favorable, we use financial derivative instruments to manage price risk associated with our oil and natural gas production. While there are many different types of derivatives
available, we generally utilize collar, swap, roll differential swap and basis swap agreements to manage price risk more effectively. In addition, to mitigate a portion of its exposure to changes in commodity prices, Cimarex historically hedged oil and natural gas prices from time to time, primarily through the use of certain derivative instruments. Upon completion of the Merger, we assumed Cimarex’s existing hedges, such that we will now bear the economic impact of those hedges.
The collar arrangements are put and call options used to establish floor and ceiling prices for a fixed volume of production during a certain time period. They provide for payments to counterparties if the index price exceeds the ceiling and payments from the counterparties if the index price falls below the floor. The swap agreements call for payments to, or receipts from, counterparties based on whether the index price for the period is greater or less than the fixed price established for that period when the swap is put in place. These arrangements limit the benefit to us of increases in prices. In addition, these arrangements expose us to risks of financial loss in a variety of circumstances, including when:
•there is an adverse change in the expected differential between the underlying price in the derivative instrument and actual prices received for our production;
•production is less than expected; or
•a counterparty is unable to satisfy its obligations.
The CFTC has promulgated regulations to implement statutory requirements for swap transactions. These regulations are intended to implement a regulated market in which most swaps are executed on registered exchanges or swap execution facilities and cleared through central counterparties. Although we believe that our use of swap transactions exempt us from certain regulatory requirements, the changes to the swap market due to increased regulation 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 Wall Street Reform and Consumer Protection Act and implementing regulations thereunder, our results of operations may become more volatile and our cash flows may be less predictable.
In addition, the use of financial derivative instruments involves the risk that the counterparties will be unable to meet the financial terms of such transactions. We are unable to predict changes in a counterparty’s creditworthiness or ability to perform, and even if we could predict such changes accurately, our ability to negate such risk may be limited depending on market conditions and the contractual terms of the instruments. If any of our counterparties were to default on its obligations under our financial derivative instruments, such a default could (1) have a material adverse effect on our results of operations, (2) result in a larger percentage of our future production being subject to commodity price changes and (3) increase the likelihood that our financial derivative instruments may not achieve their intended strategic purposes.
We will continue to evaluate the benefit of utilizing derivatives in the future. Please read “Management's Discussion and Analysis of Financial Condition and Results of Operations” in Item 7 and “Quantitative and Qualitative Disclosures about Market Risk” in Item 7A for further discussion concerning our use of derivatives.
Legal, Regulatory and Governmental Risks
ESG concerns or negative public perception regarding us and/or our industry could have an adverse effect on our business operations and the price of our common stock.
Businesses across all industries are facing increasing scrutiny from investors, stockholders and the public related to their ESG practices. Failure, or a perceived failure, to adequately respond to or meet evolving investor, stockholder or public ESG expectations, concerns and standards may cause a business entity to suffer reputational damage and materially and adversely affect the entity’s business, financial condition, and/or stock price. In addition, organizations that provide ESG information to investors have developed ratings processes for evaluating a business entity’s approach to ESG matters. Although currently no universal rating standards exist, the importance of sustainability evaluations is becoming more broadly accepted by investors and stockholders, with some using these ratings to inform investment and voting decisions. Additionally, certain investors use these scores to benchmark businesses against their peers and, if a business entity is perceived as lagging, these investors may engage with the entity to require improved ESG disclosure or performance. Moreover, certain members of the broader investment community may consider a business entity's sustainability score as a reputational or other factor in making an investment decision. Consequently, a low sustainability score could result in exclusion of our common stock from consideration by certain investment funds, engagement by investors seeking to improve such scores and a negative perception of our operations by certain investors.
Further, negative public perception regarding us and/or our industry resulting from, among other things, concerns raised by advocacy groups about climate change impacts of methane and other greenhouse gas emissions, hydraulic fracturing, oil
spills, and pipeline explosions coupled with increasing societal expectations on businesses to address climate change and potential consumer use of substitutes to carbon-intensive energy commodities may result in increased costs, reduced demand for our oil, natural gas and NGL production, reduced profits, increased regulation, regulatory investigations and litigation, and negative impacts on our stock price and access to capital markets. These factors could also cause the permits we need to conduct our operations to be challenged, withheld, delayed, or burdened by requirements that restrict our ability to profitably conduct our business.
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.
Our operations are subject to extensive federal, state and local laws and regulations, including drilling and environmental and safety laws and regulations, which increase the cost of planning, designing, drilling, installing and operating oil and natural gas facilities. New laws and regulations or revisions or reinterpretations of existing laws and regulations could further increase these costs, could increase our liability risks, and could result in increased restrictions on oil and gas production activities, which could have a material adverse effect on us and the oil and gas industry as a whole. Risk of substantial costs and liabilities related to environmental and safety matters in particular, including compliance issues, environmental contamination and claims for damages to persons or property, are inherent in oil and natural gas operations. Failure to comply with applicable environmental and safety laws and regulations also may result in the suspension or termination of our operations and subject us to administrative, civil and criminal penalties as well as the imposition of corrective action requirements and orders. In addition, applicable laws and regulations require us to obtain many permits for the operation of various facilities. The issuance of required permits is not guaranteed and, once issued, permits are subject to revocation, modification and renewal. Failure to comply with applicable laws and regulations can result in fines and penalties or require us to incur substantial costs to remedy violations.
Most of our exploration and production operations depend on the use of hydraulic fracturing to enhance production from oil and gas wells. This technology involves the injection of fluids-usually consisting mostly of water but typically including small amounts of several chemical additives-as well as sand or other proppants into a well under high pressure in order to create fractures in the rock that allow oil or gas to flow more freely to the wellbore. Most of our wells would not be economical without the use of hydraulic fracturing to stimulate production from the well. If existing laws and regulations with regard to hydraulic fracturing are revised or reinterpreted or if new laws and regulations become applicable to our operations through judicial or administrative actions, our business, financial condition, results of operations and cash flows could be adversely affected. Further, state and federal regulatory agencies have focused on a possible connection between the operation of injection wells used for oil and gas waste disposal and seismic activity in recent years. Similar concerns have been raised that hydraulic fracturing may also contribute to seismic activity. When caused by human activity, such events are called induced seismicity. In March 2016, the U.S. Geological Survey identified six states with the most significant hazards from induced seismicity, including Oklahoma, Kansas, Texas, Colorado, New Mexico, and Arkansas. These concerns have further increased regulatory scrutiny on hydraulic fracturing as well as oil and gas waste injection wells and led to the adoption of state and local laws regulating such activities. We cannot predict whether additional federal, state or local laws or regulations applicable to hydraulic fracturing or oil and gas waste injection wells will be enacted in the future and, if so, what actions any such laws or regulations would require or prohibit. These concerns also could lead to greater opposition to, and litigation concerning, oil and gas activities utilizing hydraulic fracturing or injection wells for waste disposal, 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 from developing shale plays, or could make it more difficult to perform hydraulic fracturing. In addition, if existing laws and regulations with regard to hydraulic fracturing are revised or reinterpreted or if new laws and regulations become applicable to our operations through judicial or administrative actions, our business, financial condition, results of operations and cash flows could be adversely affected.
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 could result in more complex, costly, and time-consuming air permitting and cause delays in our operations. In August 2012 and June 2016, the EPA published rules establishing new air emission control requirements for the oil and natural gas sector, including NSPS to address emissions of sulfur dioxide and volatile organic compounds and to regulate methane emissions for new and modified sources in the oil and gas industry, and NESHAP to address hazardous air pollutants frequently associated with gas production and processing activities. Although these rules were stayed and ultimately carved back by a September 2020 EPA rule, on June 30, 2021, President Biden signed into law a joint Congressional resolution under the Congressional Review Act disapproving the September 2020 rule. On November 15, 2021, the EPA proposed rules to reduce methane emissions from both new and existing oil and natural gas
industry sources. Compliance with the 2012 and 2016 NSPS for the oil and gas sector and any additional requirements imposed by new EPA regulations, particularly a new methane regulation, may require modifications to certain of our operations or increase the cost of new or modified facilities, including the installation of new equipment to control emissions at the well site, which could result in significant costs, including increased capital expenditures and operating costs, and adversely impact our business.
For additional information, please read “Business and Properties-Other Business Matters-Regulation of Oil and Natural Gas Exploration and Production,” “-Regulation of Natural Gas Marketing, Gathering and Transportation,” and “-Environmental and Safety Regulations” in Items 1 and 2.
Oil and natural gas production operations, especially those using hydraulic fracturing, are substantially dependent on the availability of water. Our ability to produce oil and natural gas economically and in commercial quantities could be impaired if we are unable to acquire adequate supplies of water for our operations or are unable to dispose of or recycle the water we use economically and in an environmentally safe manner.
Water is an essential component of oil and natural gas production during the drilling process. In particular, we use a significant amount of water in the hydraulic fracturing process. Our inability to locate sufficient amounts of water, or dispose of or recycle water used in our exploration and production operations, could adversely impact our operations. For water sourcing, we first seek to use non-potable water supplies for our operational needs. In certain areas, there may be insufficient local aquifer capacity to provide a source of water for drilling activities. Water must then be obtained from other sources and transported to the drilling site. An inability to secure sufficient amounts of water or to dispose of or recycle the water used in our operations could adversely impact our operations in certain areas. 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.
For additional information, please read “Business and Properties-Other Business Matters-Environmental and Safety Regulations-Clean Water Act” in Items 1 and 2.
The adoption of climate change legislation or regulations restricting emission of greenhouse gases could result in increased operating costs and reduced demand for the oil and gas we produce.
Studies have found that emission of certain gases, commonly referred to as greenhouse gases (“GHG”), impact the earth’s climate. The U.S. Congress and various states have been evaluating, and in some cases implementing, climate-related legislation and other regulatory initiatives that restrict emissions of GHGs. In the absence of significant federal GHG legislation, a number of state and regional efforts have emerged, aimed at tracking and/or 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. On January 20, 2021, his first day in office, President Biden signed an executive order on climate action and reconvened an interagency working group to establish 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% clean energy” economy with net-zero GHG emissions. These actions as well as any future laws or regulations that regulate or 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, and monitor and report GHG emissions associated with our operations, any of which could increase our operating costs and could adversely affect demand for the oil and gas that we produce. At this time, it is not possible to quantify the impact of such future laws and regulations on our business.
For additional information, please read “Business and Properties-Other Business Matters-Environmental and Safety Regulations-Greenhouse Gas and Climate Change Laws and Regulations” in Items 1 and 2.
We are subject to various climate-related risks.
The following is a summary of potential climate-related risks that could adversely affect us:
Transition Risks. Transition risks are related to the transition to a lower-carbon economy and include policy and legal, technology, and market risks.
Policy and Legal Risks. Policy risks include actions that seek to lessen activities that contribute to adverse effects of climate change or to promote adaptation to climate change. These policy actions potentially could be accelerated with a
Democratic party in control of Congress and the Presidency. Examples of policy actions that would increase the costs of our operations or lower demand for our oil and gas include implementing carbon-pricing mechanisms, shifting energy use toward lower emission sources, adopting energy-efficiency solutions, encouraging greater water efficiency measures, and promoting more sustainable land-use practices. Policy actions also may include restrictions or bans on oil and gas activities, which could lead to write-downs or impairments of our assets. Legal risks include potential lawsuits claiming failure to mitigate impacts of climate change, failure to adapt to climate change, and the insufficiency of disclosure around material financial risks.
Furthermore, we also could also face an increased risk of climate-related litigation or “greenwashing” suits with respect to our operations, disclosures, or products. Claims have been made against certain energy companies alleging that GHG emissions from oil, gas and NGL operations constitute a public nuisance under federal and state law. Private individuals or public entities also could attempt to enforce environmental laws and regulations against us and could seek personal injury and property damages or other remedies. Additionally, governments and private parties are also increasingly filing suits, or initiating regulatory action, based on allegations that certain public statements regarding ESG-related matters by companies are false and misleading “greenwashing” campaigns that violate deceptive trade practices and consumer protection statutes or that climate-related disclosures made by companies are inadequate. Similar issues can also arise when aspirational statements such as net-zero or carbon neutrality targets are made without clear plans. Although we are not a party to any such climate-related or “greenwashing” litigation currently, unfavorable rulings against us in any such case brought against us in the future could significantly impact our operations and could have an adverse impact on our financial condition.
Technology Risks. Technological improvements or innovations that support the transition to a lower-carbon, more energy efficient economic system may have a significant impact on us. The development and use of emerging technologies in renewable energy, battery storage, and energy efficiency may lower demand for oil and gas, resulting in lower prices and revenues, and higher costs. In addition, many automobile manufacturers have announced plans to shift production from internal combustion engine to electric powered vehicles, and states and foreign countries have announced bans on sales of internal combustion engine vehicles beginning as early as 2025, which would reduce demand for oil.
Market Risks. Markets could be affected by climate change through shifts in supply and demand for certain commodities, especially carbon-intensive commodities such as oil and gas and other products dependent on oil and gas. Lower demand for our oil and gas production could result in lower prices and lower revenues. Market risk also may take the form of limited access to capital as investors shift investments to less carbon-intensive industries and alternative energy industries. In addition, investment advisers, banks, and certain sovereign wealth, pension, and endowment funds recently have been promoting divestment of investments in fossil fuel companies and pressuring lenders to limit funding to companies engaged in the extraction, production, and sale of oil and gas. For additional information, please read “-Risks Related to our Indebtedness, Hedging Activities and Financial Position-We have substantial capital requirements, and we may not be able to obtain needed financing on satisfactory terms, if at all” in this Item.
Reputation Risk. Climate change is a potential source of reputational risk, which is tied to changing customer or community perceptions of an organization’s contribution to, or detraction from, the transition to a lower-carbon economy. For additional information, please read “-ESG concerns or negative public perception regarding us and/or our industry could have an adverse effect on our business operations and the price of our common stock.”
Physical Risks. Potential physical risks resulting from climate change may be event driven (including increased severity of extreme weather events, such as hurricanes, droughts, or floods) or may be driven by longer-term shifts in climate patterns that may cause sea level rise or chronic heat waves. Potential physical risks may cause direct damage to assets and indirect impacts, such as supply chain disruption, and also could include changes in water availability, sourcing, and quality, which could impact drilling and completion operations. These physical risks could cause increased costs, production disruptions, lower revenues and substantially increase the cost or limit the availability of insurance.
We are subject to a number of privacy and data protection laws, rules and directives (collectively, data protection laws) relating to the processing of personal data.
The regulatory environment surrounding data protection laws is uncertain. Complying with varying jurisdictional requirements could increase the costs and complexity of compliance, and violations of applicable data protection laws can result in significant penalties. A determination that there have been violations of applicable data protection laws could expose us to significant damage awards, fines and other penalties that could materially harm our business and reputation.
Any failure, or perceived failure, by us to comply with applicable data protection laws could result in proceedings or actions against us by governmental entities or others, subject us to significant fines, penalties, judgments and negative publicity, require us to change our business practices, increase the costs and complexity of compliance and adversely affect our business. As noted above, we are also subject to the possibility of security and privacy breaches, which themselves may result in a
violation of these laws. Additionally, the acquisition of a company that is not in compliance with applicable data protection laws may result in a violation of these laws.
Tax law changes could have an adverse effect on our financial position, results of operations and cash flows.
Substantive changes to existing federal income tax laws have been proposed that, if adopted, would repeal many tax incentives and deductions that are currently used by U.S. oil and gas companies and would impose new taxes. The proposals include: repeal of the percentage depletion allowance for oil and gas properties; elimination of the ability to fully deduct intangible drilling costs in the year incurred; and increase in the geological and geophysical amortization period for independent producers. Additional proposed general tax law changes include raising tax rates on both domestic and foreign income and imposing a new alternative minimum tax on book income. Further, many states are currently in deficits, and have been enacting laws eliminating or limiting certain deductions, carryforwards and credits in order to increase tax revenue.
Should the U.S. or the states pass tax legislation limiting any currently allowed tax incentives and deductions, our taxes would increase, potentially significantly, which would have a negative impact on our net income and cash flows. This could also reduce our drilling activities in the U.S. Since future changes to federal and state tax legislation and regulations are unknown, we cannot predict the ultimate impact such changes may have on our business.
Additional Risks Related to the Merger
The Merger may result in a loss of customers, distributors, service providers, suppliers, vendors, joint venture participants and other business counterparties and may result in the termination of existing contracts.
As a result of the Merger, some of our and Cimarex's legacy customers, distributors, service providers, suppliers, vendors, joint venture participants and other business counterparties may terminate or scale back their current or prospective business relationships with the combined business. If relationships with customers, distributors, service providers, suppliers, vendors, joint venture participants and other business counterparties are adversely affected by the Merger, our business, financial condition, results of operations and cash flows could be materially and adversely affected.
We may fail to realize all of the anticipated benefits of the Merger.
The long-term success of the Merger will depend, in part, on our ability to realize the anticipated benefits and cost savings from combining our two businesses and operational synergies. The anticipated benefits and cost savings of the Merger may not be realized fully or at all, may take longer to realize than expected, may not be realized or could have other adverse effects that we do not currently foresee. Some of the assumptions that we have made, such as the achievement of the anticipated benefits related to the geographic, commodity and asset diversification and the expected size, scale, inventory and financial strength of the combined business, may not be realized. In addition, there could be potential unknown liabilities and unforeseen expenses associated with the Merger that could adversely impact us.
The market price of our common stock may fluctuate for various reasons and may decline if large amounts of our common stock are sold following the Merger.
The market price of our common stock may fluctuate significantly in the future and holders of our common stock could lose some or all of the value of their investment. As a result of the Merger, we issued approximately 408.2 million shares of our common stock to former Cimarex stockholders (excluding shares that were awarded in replacement of previously outstanding Cimarex restricted share awards). The Merger Agreement contained no restrictions on the ability of former Cimarex stockholders or our historic stockholders to sell or otherwise dispose of shares of our common stock. Former Cimarex stockholders may decide not to hold the shares of our common stock that they received in the Merger, and our historic stockholders may decide to reduce their investment in us as a result of the changes to our investment profile as a result of the Merger. These sales of our common stock (or the perception that these sales may occur) could have the effect of depressing the market price for our common stock. In addition, with the completion of the Merger, our financial position is different from our financial position before the completion of the Merger, and our future results of operations and cash flows will be affected by factors different from those that previously affected our results of operations and cash flows, all of which could adversely affect the market price of our common stock. Furthermore, the stock market has experienced significant price and volume fluctuations in recent times which, if they continue to occur, could have a material adverse effect on the market for, or liquidity of, our common stock, regardless of our actual operating performance.
Our ability to utilize Cimarex's historic net operating loss carryforwards and other tax attributes may be limited.
On October 1, 2021, we completed the Merger, and as a result, we acquired Cimarex’s U.S. federal net operating loss carryforwards (“NOLs”) and other tax attributes. Our ability to utilize these NOLs and other tax attributes to reduce future taxable income depends on many factors, including future income, which cannot be assured. Section 382 of the Internal
Revenue Code of 1986, as amended ("Section 382"), generally imposes an annual limitation on the amount of NOLs and other tax attributes that may be used to offset taxable income when a corporation has undergone an "ownership change" (as determined under Section 382). An ownership change generally occurs if one or more stockholders (or groups of stockholders) who are each deemed to own at least 5 percent of such corporation's stock increase their ownership by more than 50 percentage points over their lowest ownership percentage within a rolling three-year period.
As a result of the Merger, an ownership change occurred with respect to Cimarex under Section 382, which triggered a limitation on our ability to utilize Cimarex's historic NOLs and other tax attributes and could cause some of those NOLs and other tax attributes to expire unutilized. This annual limitation under Section 382 is determined by multiplying (1) the fair market value of Cimarex's stock at the time of the Merger by (2) the long-term tax exempt rate published by the Internal Revenue Service for the month in which the Merger occurred, subject to certain adjustments (provided that any unused annual limitation may be carried over to later years). In addition, the NOLs Cimarex acquired in 2019 as part of its acquisition of Resolute Energy Corporation are already subject to a Section 382 limitation.
See Note 10 of the Notes to Consolidated Financial Statements, “Income Taxes,” included in Item 8 for more information regarding Cimarex’s historic NOL carryforwards and the Section 382 limitation.
Risks Related to our Corporate Structure
Provisions of Delaware law and our bylaws and charter could discourage change-in-control transactions and prevent stockholders from receiving a premium on their investment.
Our charter authorizes our Board of Directors to set the terms of preferred stock. In addition, Delaware law contains provisions that impose restrictions on business combinations with interested parties. Our bylaws prohibit the calling of a special meeting by our stockholders and place procedural requirements and limitations on stockholder proposals at meetings of stockholders. Because of these provisions of our charter, bylaws and Delaware law, persons considering unsolicited tender offers or other unilateral takeover proposals may be more likely to negotiate with our Board of Directors rather than pursue non-negotiated takeover attempts. As a result, these provisions may make it more difficult for our stockholders to benefit from transactions that are opposed by an incumbent Board of Directors.
The personal liability of our directors for monetary damages for breach of their fiduciary duty of care is limited by the Delaware General Corporation Law and by our charter.
The Delaware General Corporation Law allows corporations to limit available relief for the breach of directors' duty of care to equitable remedies such as injunction or rescission. Our charter limits the liability of our directors to the fullest extent permitted by Delaware law. Specifically, our directors will not be personally liable for monetary damages for any breach of their fiduciary duty as a director, except for liability:
•for any breach of their duty of loyalty to the Company or our stockholders;
•for acts or omissions not in good faith or that involve intentional misconduct or a knowing violation of law;
•under provisions relating to unlawful payments of dividends or unlawful stock repurchases or redemptions; and
•for any transaction from which the director derived an improper personal benefit.
This limitation may have the effect of reducing the likelihood of derivative litigation against directors, and may discourage or deter stockholders or management from bringing a lawsuit against directors for breach of their duty of care, even though such an action, if successful, might otherwise have benefited our stockholders.
The exclusive-forum provision contained in our bylaws could limit our stockholders' ability to obtain a favorable judicial forum for disputes with us or our directors, officers or other employees.
Our bylaws provide that, unless we consent in writing to the selection of an alternative forum, the sole and exclusive forum for (1) any derivative action or proceeding brought on behalf of us, (2) any action asserting a claim of breach of a fiduciary duty owed by any current or former director, officer, other employee or agent of Coterra to Coterra or our stockholders, including a claim alleging the aiding and abetting of such a breach of fiduciary duty, (3) any action asserting a claim arising pursuant to any provision of the Delaware General Corporation Law or our bylaws or charter or (4) any action asserting a claim governed by the internal affairs doctrine or asserting an "internal corporate claim" shall, to the fullest extent permitted by law, be the Court of Chancery of the State of Delaware (or, if the Court of Chancery does not have jurisdiction, the U.S. federal district court for the District of Delaware).
To the fullest extent permitted by applicable law, this exclusive-forum provision applies to state and federal law claims, including claims under the federal securities laws, including the Securities Act of 1933, as amended (the “Securities Act”), and the Securities Exchange Act of 1934, as amended (the “Exchange Act”), although our stockholders will not be deemed to have waived our compliance with the federal securities laws and the rules and regulations thereunder. This exclusive-forum provision may limit the ability of a stockholder to bring a claim in a judicial forum of its choosing for disputes with us or our directors, officers or other employees, which may discourage lawsuits against us and our directors, officers and other employees. Alternatively, if a court were to find this exclusive-forum provision inapplicable to, or unenforceable in respect of, one or more of the specified types of actions or proceedings described above, we may incur additional costs associated with resolving such matters in other jurisdictions, which could negatively affect our business, results of operations and financial condition. In addition, stockholders who do bring a claim in a state or federal court located within the State of Delaware could face additional litigation costs in pursuing any such claim, particularly if they do not reside in or near Delaware. In addition, the court located in the State of Delaware may reach different judgments or results than would other courts, including courts where a stockholder would otherwise choose to bring the action, and such judgments or results may be more favorable to us than to our stockholders.
General Risk Factors
The loss of key personnel could adversely affect our ability to operate.
Our operations depend on a relatively small group of key management and technical personnel, and one or more of these individuals could leave our employment. The change in control and severance benefits triggered by the Merger may provide incentive for key management and technical personnel to leave our company. The unexpected loss of the services of one or more of these individuals could have a detrimental effect on us. In addition, our drilling success and the success of other activities integral to our operations will depend, in part, on our ability to attract and retain experienced geologists, engineers and other professionals. Competition for experienced geologists, engineers and some other professionals is extremely intense and can be exacerbated following a downturn in which talented professionals leave the industry or when potential new entrants to the industry decide not to undertake the professional training to enter the industry. This has occurred as a result of the downturn in commodity prices in 2020 and previous downturns and as a result of initiatives to move from oil and gas to alternative energy sources. If we cannot retain our technical personnel or attract additional experienced technical personnel, our ability to compete could be harmed.
We may not be insured against all of the operating risks to which we are exposed.
We maintain insurance against some, but not all, operating risks and losses. We do not carry business interruption insurance. In addition, pollution and environmental risks generally are not fully insurable. The occurrence of an event not fully covered by insurance could have a material adverse effect on our financial position, results of operations and cash flows. The cost of insurance may increase, and the availability of insurance may decrease, as a result of climate change or other factors.
Competition in our industry is intense, and many of our competitors have substantially greater financial and technological resources than we do, which could adversely affect our competitive position.
Competition in the oil and natural gas industry is intense. Major and independent oil and natural gas companies actively bid for desirable oil and gas properties, as well as for the capital, equipment, labor and infrastructure required to operate and develop these properties. Our competitive position is affected by price, contract terms and quality of service, including pipeline connection times, distribution efficiencies and reliable delivery record. Many of our competitors have financial and technological resources and exploration and development budgets that are substantially greater than ours. These companies may be able to pay more for exploratory projects and productive oil and gas properties and may be able to define, evaluate, bid for and purchase a greater number of properties and prospects than our financial or human resources permit. In addition, these companies may be able to expend greater resources on the existing and changing technologies that we believe will be increasingly important to attaining success in the industry. These companies may also have a greater ability to continue drilling activities during periods of low oil and natural gas prices and to absorb the burden of current and future governmental regulations and taxation.
Further, driven in part by reduced commodity prices related to the global COVID-19 pandemic, certain of our competitors may engage in bankruptcy proceedings, debt refinancing transactions, management changes or other strategic initiatives in an attempt to reduce operating costs to maintain a position in the market. This could result in such competitors emerging with stronger or healthier balance sheets and in turn an improved ability to compete with us in the future. We have seen and may continue to see corporate consolidations among our competitors, which could significantly alter industry conditions and competition within the industry.
Because our activity is concentrated in areas of heavy industry competition, there is heightened demand for equipment, power, services, facilities and resources, resulting in higher costs than in other areas. Such intense competition also could result in delays in securing, or the inability to secure, the equipment, power, services, resources or facilities necessary for our development activities, which could negatively impact our production volumes. In remote areas, vendors also can charge higher rates due to the inability to attract employees to those areas and the vendors’ ability to deploy their resources in easier-to-access areas.
The declaration, payment and amounts of future dividends distributed to our stockholders will be uncertain.
Although we have paid cash dividends on shares of common stock in the past, our Board of Directors may determine not to declare dividends in the future or may reduce the amount of dividends paid in the future. Decisions on whether, when and in which amounts to declare and pay any future dividends will remain in the discretion of our Board of Directors. Any dividend payment amounts will be determined by our Board of Directors on a quarterly basis, and it is possible that our Board of Directors may increase or decrease the amount of dividends paid in the future, or determine not to declare dividends in the future, at any time and for any reason. We expect that any such decisions will depend on our financial condition, results of operations, cash balances, cash requirements, future prospects, the outlook for commodity prices and other considerations that our Board of Directors deems relevant, including, but not limited to:
•whether we have enough cash to pay such dividends due to our cash requirements, capital spending plans, cash flows or financial position;
•our desire to maintain or improve the credit ratings on our debt; and
•applicable restrictions under Delaware law.
Our common stockholders should be aware that they have no contractual or other legal right to dividends that have not been declared.

---

ITEM 1B. UNRESOLVED STAFF COMMENTS
ITEM 1B. UNRESOLVED STAFF COMMENTS
None.

---

ITEM 2. PROPERTIES

---

ITEM 3. LEGAL PROCEEDINGS
ITEM 3. LEGAL PROCEEDINGS
Legal Matters
We are involved in various legal proceedings incidental to our business. The information set forth under the heading “Legal Matters” in Note 8 of the Notes to Consolidated Financial Statements included in Item 8 of this Annual Report on Form 10-K is incorporated by reference in response to this item.
Governmental Proceedings
From time to time we receive notices of violation from governmental and regulatory authorities, including notices relating to alleged violations of environmental statutes or the rules and regulations promulgated thereunder. While we cannot predict with certainty whether these notices of violation will result in fines and/or penalties, if fines and/or penalties are imposed, they may result in monetary sanctions, individually or in the aggregate, in excess of $300,000.

---

ITEM 4. MINE SAFETY DISCLOSURE
ITEM 4. MINE SAFETY DISCLOSURES
Not applicable.
INFORMATION ABOUT OUR EXECUTIVE OFFICERS
The following table shows certain information as of February 28, 2022 about our executive officers, as such term is defined in Rule 3b-7 of the Securities Exchange Act of 1934.
Name Age Position Officer
Since
Dan O. Dinges 68 Executive Chairman, Board of Directors 2001
Thomas E. Jorden 64 Chief Executive Officer and President 2021
Scott C. Schroeder 59 Executive Vice President and Chief Financial Officer 1997
Stephen P. Bell 67 Executive Vice President, Business Development 2021
Francis B. Barron 59 Senior Vice President and General Counsel, and Assistant Corporate Secretary 2021
Christopher H. Clason 55 Senior Vice President and Chief Human Resources Officer 2021
Steven W. Lindeman 61 Senior Vice President, Production and Operations 2011
Phillip L. Stalnaker 62 Senior Vice President, Marcellus Business Unit 2009
Michael D. DeShazer 36 Vice President of Business Units 2021
Todd M. Roemer 51 Vice President and Chief Accounting Officer 2010
Kevin W. Smith 36 Vice President and Chief Technology Officer 2021
All officers are elected annually by our Board of Directors. All of the executive officers have been employed by Coterra Energy Inc. for at least the last five years, except for the following officers, each of whom previously served Cimarex as described below and began serving in his current role at the Company as of October 1, 2021, the effective date of the Merger:
Mr. Jorden previously served as the Chief Executive Officer and President of Cimarex since September 2011 and as Chairman of the Board of Directors of Cimarex since August 2012. At Cimarex, he began serving as Executive Vice President of Exploration when the company formed in 2002. Prior to the formation of Cimarex, Mr. Jorden held multiple leadership roles at Key Production Company, Inc. (“Key”), which was acquired by Cimarex in 2002. He joined Key in 1993 as Chief Geophysicist and subsequently became Executive Vice President of Exploration. Before joining Key, Mr. Jorden served at Union Pacific Resources and Superior Oil Company.
Mr. Bell was appointed Senior Vice President of Business Development and Land in September 2002 and was named Executive Vice President of Business Development in September 2012. Mr. Bell served at Key prior to its acquisition by Cimarex. He joined Key in 1994 as Vice President of Land and was appointed Senior Vice President of Business Development and Land in 1999.
Mr. Barron joined Cimarex as Senior Vice President and General Counsel in 2013. Prior to Cimarex, Mr. Barron served in various capacities at Bill Barrett Corporation between 2004 and 2013, including as Executive Vice President and General Counsel, Secretary, and Chief Financial Officer. Prior to Bill Barrett Corporation, Mr. Barron was a partner at the Denver, Colorado office of the law firm of Patton Boggs LLP, as well as a partner at Bearman Talesnick & Clowdus Professional Corporation.
Mr. Clason joined Cimarex as Vice President and Chief Human Resources Officer in 2019 and was named Senior Vice President and Chief Human Resources Officer in February 2020. Prior to Cimarex, Mr. Clason was Director of MBA Career Management and Employer Relations at the Marriott School of Business at Brigham Young University from 2016 to 2019. Prior to his work in higher education, he was Senior Vice President and Chief Human Resources Officer at ProBuild LLC, A Devonshire Investors Company. From 2001 until 2014, Mr. Clason held various global human resources executive leadership roles at Honeywell International, including Vice President Human Resources and Communications at Honeywell Aerospace. His background includes extensive international experience at Citigroup and early career work at Chevron.
Mr. DeShazer joined Cimarex in 2007, serving in various engineering and reservoir manager positions, as well as multiple leadership roles, including Technology Group Manager from 2016 to 2018 and Asset Evaluation Team Manager from 2018 to 2019. He was named Vice President of the Permian Business Unit in 2019.
Mr. Smith began his career with Cimarex in 2007, serving in a number of technical and leadership roles including Director of Technology and Anadarko Exploration Region Manager. In September 2020, Mr. Smith assumed the role of Chief Engineer for Cimarex.

---

ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
Our $0.10 par value common stock is listed and principally traded on the NYSE under the ticker symbol “CTRA.” Cash dividends were paid to our common stockholders in each quarter of 2021. Future dividend payments will depend on the company’s level of earnings, financial requirements and other factors considered relevant by our Board of Directors.
As of February 1, 2022, there were 771 registered holders of our common stock.
EQUITY COMPENSATION PLAN INFORMATION
In connection with the Merger, we assumed all rights and obligations under the Cimarex Energy Co. 2019 Equity Incentive Plan (the “2019 Cimarex Plan”) and will be entitled to grant equity or equity-based awards with respect to Coterra common stock under the plan to current or former employees of Cimarex, to the extent permissible under applicable law and NYSE listing rules. The 2019 Cimarex Plan provides for grants of options, stock appreciation rights, restricted stock, restricted stock units, performance stock units, cash awards and other stock-based awards.
The following table provides information as of December 31, 2021 regarding the number of shares of common stock that may be issued under our incentive plans, including the 2019 Cimarex Plan.
(a) (b) (c)
Plan Category Number of securities to be
issued upon exercise of
outstanding options, warrants
and rights Weighted-average exercise
price of outstanding options,
warrants and rights Number of securities
remaining available for
future issuance under equity
compensation plans
(excluding securities
reflected in column (a))
Equity compensation plans approved by security holders 4,745,825 (1)
n/a 49,430,179 (2)
Equity compensation plans not approved by security holders n/a n/a n/a
Total 4,745,825 n/a 49,430,179
_______________________________________________________________________________
(1)Includes 1,858,104 employee performance shares, the performance periods of which end on December 31, 2021, 2022, 2023, and September 30, 2024; 1,355,352 non-qualified stock options which expire in periods ranging from 2022 to 2027; 1,286,471 restricted stock units awarded to employees that vest in April 2022, December 2024 and various dates in 2022 and 2023 and 245,898 restricted stock units awarded to the non-employee directors, the restrictions on which would lapse upon a non-employee director's departure from our Board of Directors.
(2)Includes 3,019,183 shares of restricted stock, the restrictions on which lapse in 2022, 2023 and 2024, and 10,461,081 shares that are available for future grants under the Coterra Energy Inc. 2014 Incentive Plan; and 35,949,915 shares that are available for future grants to legacy Cimarex employees only under the 2019 Incentive Plan.
ISSUER PURCHASES OF EQUITY SECURITIES
Our Board of Directors previously authorized a share repurchase program under which we could purchase shares of our common stock in the open market or in negotiated transactions. No expiration date was associated with this prior authorization, and there were no repurchases under this authorized share repurchase program during the quarter ended December 31, 2021.
In February 2022, our Board of Directors terminated the previously authorized share repurchase program and authorized a new share repurchase program. This new share repurchase program authorizes the Company to purchase up to $1.25 billion of our common stock in the open market or in negotiated transactions.
The following table sets forth information regarding repurchases of our common stock during the quarter ended December 31, 2021.
Period Total number of shares purchased (1)
Average price paid per share Total number of shares purchased as part of publicly announced plans or programs Maximum number of shares that may yet be purchased under the plans or programs
October 2021 - - - -
November 2021 - - - -
December 2021 125,067 $ 19.74 - -
Total 125,067 $ 19.74 - -
_______________________________________________________________________________
(1)Reflects shares purchased from employees in order for employees to satisfy income tax withholding payments related to share-based awards that vested during the period.
PERFORMANCE GRAPH
The following graph compares our common stock performance (“CTRA”) with the performance of the Standard & Poor's 500 Stock Index, the Dow Jones U.S. Exploration & Production Index and the S&P Oil & Gas Exploration & Production Index for the period December 2016 through December 2021. The graph assumes that the value of the investment in our common stock and in each index was $100 on December 31, 2016 and that all dividends were reinvested.
December 31,
Calculated Values 2016 2017 2018 2019 2020 2021
CTRA $ 100.00 $ 123.26 $ 97.29 $ 77.07 $ 73.73 $ 91.05
S&P 500 $ 100.00 $ 121.83 $ 116.49 $ 153.17 $ 181.35 $ 233.41
Dow Jones U.S. Exploration & Production $ 100.00 $ 101.30 $ 83.30 $ 92.79 $ 61.57 $ 105.24
S&P Oil & Gas Exploration & Production $ 100.00 $ 93.69 $ 75.42 $ 84.49 $ 54.56 $ 102.08
The performance graph above is furnished and shall not be deemed to be filed for purposes of Section 18 of the Exchange Act, or otherwise subject to the liabilities of that section, nor shall it be deemed to be incorporated by reference into any registration statement or other filing under the Securities Act or the Exchange Act unless specifically identified therein as being incorporated therein by reference. The performance graph is not soliciting material subject to Regulation 14A of the Exchange Act.
PART II

---

ITEM 6. SELECTED FINANCIAL DATA
ITEM 6. [RESERVED]

---

ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following discussion and analysis is based on management’s perspective and is intended to assist you in understanding our results of operations and our present financial condition and outlook. Our Consolidated Financial Statements and the accompanying Notes to the Consolidated Financial Statements included elsewhere in this Annual Report on Form 10-K contain additional information that should be referred to when reviewing this material. This discussion and analysis also includes forward-looking statements. Readers are cautioned that such forward-looking statements are based on current expectations and assumptions that involve a number of risks and uncertainties that could cause actual results to differ materially from those included in this report, including those under “Forward-Looking Statements” in Part I of this report and “Risk Factors” in Part I, Item 1A of this report.
OVERVIEW
Cimarex Merger
On October 1, 2021, we and Cimarex completed the Merger. 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 and subject to certain exceptions specified therein, each eligible share of Cimarex common stock was converted into the right to receive 4.0146 shares of our common stock. 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 previously outstanding Cimarex restricted share awards). Additionally on October 1, 2021, we changed our name to Coterra Energy Inc.
Certain financial and operational information set forth herein does not include the activity of Cimarex for periods prior to the closing of the Merger.
Financial and Operating Overview
Financial and operating results for the year ended December 31, 2021 compared to the year ended December 31, 2020 are as follows:
•Natural gas production increased 53.4 Bcf, or six percent, from 857.7 Bcf in 2020 to 911.1 Bcf in 2021. The slight increase was attributable to production during the fourth quarter of 2021 from properties acquired in the Merger, which significantly expanded our operations, partially offset by the timing of our drilling and completion activities in the Marcellus Shale in 2021.
•Oil production increased 8 Mmbbl from prior year. The increase was attributable to production during the fourth quarter of 2021 from properties acquired in the Merger.
•NGL production increased 7 Mmbbl from prior year. The increase was attributable to production during the fourth quarter of 2021 from properties acquired in the Merger.
•Average realized natural gas price for 2021 was $2.73 per Mcf, 63 percent higher than the $1.68 per Mcf price realized in 2020.
•Average realized oil and NGL prices for 2021 were $60.35 and $34.18 per Bbl, respectively.
•Total capital expenditures were $725 million in 2021 compared to $570 million in 2020. The increase in capital expenditures was attributable to expanded drilling and completion activities during the fourth quarter of 2021 as a result of the Merger.
•Drilled 114 gross wells (99.9 net) with a success rate of 100 percent in 2021 compared to 74 gross wells (64.3 net) with a success rate of 100 percent in 2020.
•Completed 132 gross wells (108.3 net) in 2021 compared to 86 gross wells (77.3 net) in 2020.
•Average rig count during 2021 was approximately 2.5 rigs in the Marcellus compared to an average rig count of approximately 2.3 rigs during 2020. Rig count since the Merger averaged 5.3 and zero rigs in the Permian Basin and Anadarko Basin, respectively.
•Repaid $88 million of our 5.58% weighted-average private placement senior notes, which matured in January 2021, and $100 million of our 3.65% weighted-average private placement senior notes, which matured in September 2021.
•Paid dividends of $1.12 per share, including $0.445 per share for regular quarterly dividends, a special common stock dividend of $0.50 per share in October 2021 after the completion of the Merger and a variable common stock dividend of $0.175 per share in November 2021.
Impact of the COVID-19 Pandemic
The ongoing COVID-19 outbreak has caused widespread illness and significant loss of life, leading governments across the world to impose severely stringent limitations on movement and human interaction. We have implemented preventative measures and developed response plans intended to minimize unnecessary risk of exposure and prevent infection among our employees and the communities in which we operate. Beginning in March 2020, we modified certain business practices (including those related to nonoperational employee work locations and the cancellation of physical participation in a number of meetings, events and conferences) to conform to government restrictions and best practices encouraged by the Centers for Disease Control and Prevention, the WHO and other governmental and regulatory authorities. In addition, we implemented and provided training on a COVID-19 Safety Policy containing personal safety protocols; provided additional personal protective equipment to our workforce; implemented rigorous COVID-19 self-assessment, contact tracing and quarantine protocols; increased cleaning protocols at all of our employee work locations; and provided additional paid leave to employees with actual or presumed COVID-19 cases. We also collaborated, and continue to collaborate, with customers, suppliers and service providers to minimize potential impacts to or disruptions of our operations and to implement longer-term emergency response protocols. Although we returned to full in-person working in our Houston headquarters and other offices in July 2021, we intend to continue to monitor developments affecting our workforce, our customers, our suppliers, our service providers and the communities in which we operate, including any significant resurgence in COVID-19 transmission and infection. Should the need arise, we will take such precautions as we believe are warranted.
Our efforts to respond to the challenges presented by the ongoing pandemic, as well as certain operational decisions we previously implemented, such as our maintenance capital program, have helped to minimize the impact, and any resulting disruptions, of the pandemic to our business and operations.
The long-term impact that the COVID-19 pandemic will have on our business, cash flows, liquidity, financial condition and results of operations will depend on future developments, including, among others, the duration, ultimate geographic spread and severity of the virus and its variants (such as the Delta and Omicron variants), the global availability and efficacy of treatments and vaccines and boosters and the acceptance of such treatments and vaccines by a significant portion of the population, any significant resurgence in virus transmission and infection in regions that have experienced improvements, the extent and duration of governmental and other measures implemented to try to slow the spread of the virus (whether through a continuation of existing measures or the re-imposition of prior measures), and other actions by governmental authorities, customers, suppliers and other third parties.
Market Conditions and Commodity Prices
Our financial results depend on many factors, particularly commodity prices and our ability to market our production on economically attractive terms. Commodity prices are affected by many factors outside of our control, including changes in market supply and demand, which are impacted by pipeline capacity constraints, inventory storage levels, basis differentials, weather conditions and other factors. Our realized prices are also further impacted by our hedging activities.
Our revenues, operating results, financial condition and ability to borrow funds or obtain additional capital depend substantially on prevailing commodity prices, particularly oil and natural gas prices. Material declines in commodity prices could have a material adverse effect on our operating results, financial condition, liquidity and ability to obtain financing. Lower commodity prices also may reduce the amount of oil, natural gas, and NGLs that we can produce economically. In addition, in periods of low commodity prices, we may elect to curtail a portion of our production from time to time. Historically, commodity prices have been volatile, with prices sometimes fluctuating widely, and they may remain volatile. As a result, we cannot accurately predict future commodity prices and, therefore, cannot determine with any degree of certainty what effect increases or decreases in these prices will have on our capital program, production volumes or revenues. In addition to commodity prices and production volumes, finding and developing sufficient amounts of oil and natural gas reserves at economical costs are critical to our long-term success.
We account for our derivative instruments on a mark-to-market basis, with changes in fair value recognized in operating revenues in the Consolidated Statement of Operations. As a result of these mark-to-market adjustments associated with our derivative instruments, we will experience volatility in our earnings due to commodity price volatility. Refer to “Results of
Operations - Impact of Derivative Instruments on Operating Revenues” below and Note 5 of the Notes to the Consolidated Financial Statements, “Derivative Instruments,” for more information.
One of the impacts of the COVID-19 pandemic was a significant reduction in demand for crude oil, and to a lesser extent, natural gas. The supply/demand imbalance driven by the COVID-19 pandemic and production disagreements in March 2020 among members of OPEC+ led to a significant global economic contraction generally in 2020 and continued to have disruptive impacts on the oil and gas industry in 2021. Although the members of OPEC+ agreed in April 2020 to cut oil production and have subsequently taken actions that generally have supported commodity prices, and U.S. production has declined, oil prices and natural gas prices remained low, relative to pre-pandemic levels, through the first quarter of 2021, as the oversupply and lack of demand in the market persisted. Oil, natural gas and NGL prices increased during the second half of 2021 compared to 2020, in part due to greater demand and slightly decreasing production levels. In addition, our costs for services, labor and supplies increased during 2021 due to increased demand for those items and supply chain disruptions related to the COVID-19 pandemic.
Meanwhile, NYMEX oil and natural gas futures prices have strengthened since the reduction of pandemic-related restrictions and recent OPEC+ cooperation. Improving oil and natural gas futures prices in part reflect market expectations of limited U.S. supply growth from publicly traded companies as a result of capital investment discipline and a focus on delivering free cash flow returns to stockholders. In addition, natural gas prices have benefited from strong worldwide liquefied natural gas (“LNG”) demand and sustained higher U.S. exports, lower associated gas growth from oil drilling and improved U.S. economic activity. Oil price futures have improved coinciding with recovering global economic activity, lower supply from major oil producing countries, OPEC+ cooperation and moderating inventory levels.
Although the current outlook on oil and natural gas prices is generally favorable and our operations have not been significantly impacted in the short-term, in the event further disruptions occur and continue for an extended period of time, our operations could be adversely impacted, commodity prices could decline and our costs may increase further. Although we are unable to predict future commodity prices, at current oil, natural gas and NGL price levels, we do not believe that an impairment of our oil and gas properties is reasonably likely to occur in the near future; however, in the event that commodity prices significantly decline from current levels, our management would evaluate the recoverability of the carrying value of our oil and gas properties.
For information about the impact of realized commodity prices on our revenues, refer to “Results of Operations” below.
FINANCIAL CONDITION
Liquidity and Capital Resources
We strive to maintain an adequate liquidity level to address commodity price volatility and risk. Our primary sources of liquidity are (1) cash on hand, (2) net cash provided by operating activities and (3) available borrowing capacity under our revolving credit facility.
Our liquidity requirements consist primarily of (1) capital expenditures, (2) payment of contractual obligations, including debt maturity and interest payments, (3) working capital requirements, (4) dividend payments and (5) share repurchases. See below for additional discussion and analysis of our cash flows. We believe that, with operating cash flow, cash on hand and availability under our revolving credit facility, we have the ability to finance our spending plans over the next twelve months and, based on current expectations, for the long term.
We had $1.5 billion of capacity on our revolving credit facility at December 31, 2021. The revolving credit facility is scheduled to mature in April 2024, subject to extension up to one year if certain conditions are met.
At December 31, 2021, we had no borrowings outstanding under our revolving credit facility. We also had unrestricted cash on hand of $1.0 billion as of December 31, 2021.
Our revolving credit facility includes a covenant limiting our borrowing capacity based on our leverage ratio. Refer to Note 4 of the Notes to the Consolidated Financial Statements, “Debt and Credit Agreements,” for further details regarding our leverage ratio.
Immediately prior to the Merger, Cimarex had outstanding senior notes in the aggregate principal amount of $2.0 billion. On October 7, 2021 and after the completion of the Merger, we completed private offers to eligible holders to exchange $1.8 billion in aggregate principal of Cimarex senior notes (the “Existing Cimarex Notes”) for $1.8 billion in aggregate principal of new notes issued by us (the “New Coterra Notes”) and $2 million of cash consideration. In connection with the debt exchange, Cimarex obtained consents to adopt certain amendments to each of the indentures governing the Existing Cimarex Notes to eliminate certain of the covenants, restrictive provisions and events of default from such indentures. The New Coterra Notes are
general, unsecured, senior obligations of ours and have substantially identical terms and covenants to the Existing Cimarex Notes (before giving effect to the amendments referred to in the immediately preceding sentence), which we believe are customary for senior, unsecured notes issued by companies of similar size and credit quality as compared to us. The New Coterra Notes consist of $706 million aggregate principal amount of 4.375% Senior Notes due 2024, $687 million aggregate principal amount of 3.90% Senior Notes due 2027 and $433 million aggregate principal amount of 4.375% Senior Notes due 2029.
Our debt is currently rated as investment grade by the three leading rating agencies. In determining our debt ratings, the agencies consider a number of qualitative and quantitative items including, but not limited to, current commodity prices, our liquidity position, our asset quality and reserve mix, debt levels, cost structure and growth plans. Credit ratings are not recommendations to buy, sell, or hold securities and may be subject to revision or withdrawal at any time by the assigning rating agency. There are no “rating triggers” in any of our debt agreements that would accelerate the scheduled maturities should our debt rating fall below a certain level. However, a change in our debt rating could impact our interest rate on any borrowings under our revolving credit facility and our ability to economically access debt markets in the future and could trigger the requirement to post credit support under various agreements, which could reduce the borrowing capacity under our revolving credit facility.
At December 31, 2021, we were in compliance with all financial covenants for both our revolving credit facility and senior notes. Refer to Note 4 of the Notes to the Consolidated Financial Statements, “Debt and Credit Agreements,” for further details regarding financial covenants.
As market conditions warrant and subject to our contractual restrictions, liquidity position and other factors, we may from time to time seek to repurchase or retire our outstanding debt through cash purchases and/or exchanges for other debt or equity securities in open market transactions, privately negotiated transactions, by tender offer or otherwise. Any such cash repurchases by us may be funded by cash on hand or incurring new debt. The amounts involved in any such transactions, individually or in the aggregate, may be material.
Cash Flows
Our cash flows from operating activities, investing activities and financing activities are as follows:
Year Ended December 31,
(In millions) 2021 2020 2019
Cash flows provided by operating activities $ 1,667
$ 778
$ 1,445
Cash flows provided by (used in) investing activities
(584)
(543)
Cash flows used in financing activities (1,086)
(256)
(690)
Operating Activities. Operating cash flow fluctuations are substantially driven by changes in commodity prices, production volumes and operating expenses. Commodity prices have historically been volatile, primarily as a result of supply and demand for oil and natural gas, pipeline infrastructure constraints, basis differentials, inventory storage levels, seasonal influences and other factors. In addition, fluctuations in cash flow may result in an increase or decrease in our capital expenditures.
On October 1, 2021, we and Cimarex completed the Merger. Although we expect to achieve certain general and administrative expense synergies over the long-term through cost savings, in the near-term we will incur certain Merger-related restructuring cost cash outflows ranging from $100 million to $110 million. These payments will primarily relate to workforce reductions and the associated employee severance benefits, and the acceleration of employee benefits that were triggered by the Merger.
Our working capital is substantially influenced by the variables discussed above and fluctuates based on the timing and amount of borrowings and repayments under our revolving credit facility, repayments of debt, the timing of cash collections and payments on our trade accounts receivable and payable, respectively, payment of dividends, repurchases of our securities and changes in the fair value of our commodity derivative activity. From time to time, our working capital will reflect a deficit, while at other times it will reflect a surplus. This fluctuation is not unusual. At December 31, 2021 and 2020, we had a working capital surplus of $916 million and $26 million, respectively. We believe we have adequate liquidity and availability under our revolving credit facility to meet our working capital requirements over the next 12 months.
Net cash provided by operating activities in 2021 increased by $889 million compared to 2020. This increase was primarily due to higher natural gas, oil and NGL revenue, partially offset by higher operating expenses, higher cash paid on derivative settlements and unfavorable changes in working capital and other assets and liabilities. The increase in natural gas,
oil and NGL revenue was primarily due to the Merger, an increase in realized natural gas prices and moderately higher natural gas production in the Marcellus Shale. Average realized natural gas prices increased by 87 percent in 2021 compared to 2020.
Refer to “Results of Operations” for additional information relative to commodity price, production and operating expense fluctuations. We are unable to predict future commodity prices and, as a result, cannot provide any assurance about future levels of net cash provided by operating activities.
Investing Activities. Cash flows used in investing activities decreased by $897 million from 2020 compared to 2021. The decrease was primarily driven by $1.0 billion of cash acquired as a result of the Merger, partially offset by $152 million of higher capital expenditures which were primarily a result of the Merger.
Financing Activities. Cash flows used in financing activities increased by $830 million from 2020 compared to 2021. The increase was due to $621 million of higher dividend payments related to special and variable common stock dividends paid in 2021, $101 million higher net repayments of debt primarily related to maturities of certain of our senior notes and $104 million higher tax withholding payments related to share-based awards that vested as a result of the Merger.
2020 and 2019 Compared. For information on the comparison of operating, investing and financing cash flows for the year ended December 31, 2019 compared to the year ended December 31, 2020, refer to Financial Condition (Cash Flows) included in the Coterra Energy Inc. (formerly Cabot Oil & Gas Corporation) Annual Report on Form 10-K for the year ended December 31, 2020.
Capitalization
Information about our capitalization is as follows:
December 31,
(Dollars in millions) 2021 2020
Debt(1)
$ 3,125 $ 1,134
Stockholders' equity(2)
11,738 2,216
Total capitalization $ 14,863 $ 3,350
Debt to total capitalization 21% 34%
Cash and cash equivalents $ 1,036 $ 140
_______________________________________________________________________________
(1)Includes $188 million of current portion of long-term debt at December 31, 2020. There were no borrowings outstanding under our revolving credit facility as of December 31, 2021 and 2020, respectively.
(2)Includes consideration of $9.1 billion related to the issuance of our common stock in connection with the Merger.
On September 29, 2021, our stockholders approved an amendment to our certificate of incorporation to increase the number of authorized shares of our common stock from 960,000,000 shares to 1,800,000,000 shares. That amendment became effective on October 1, 2021.
On October 1, 2021 and following the effectiveness of the Merger, we issued approximately 408.2 million shares of common stock to Cimarex stockholders under the terms of the Merger Agreement (excluding shares that were awarded in replacement of previously outstanding Cimarex restricted share awards).
Share repurchases. We did not repurchase any shares of our common stock during 2021 and 2020 under our share repurchase program. As of December 31, 2021, 125,067 shares of common stock went into treasury stock that were retained from restricted stock award vestings for the withholding of taxes.
In February 2022, our Board of Directors terminated our previously authorized share repurchase program and authorized a new share repurchase program. This new share repurchase program authorizes the Company to purchase up to $1.25 billion of our common stock in the open market or in negotiated transactions.
Dividends. During 2021 and 2020, we paid dividends of $780 million ($1.12 per share) and $159 million ($0.40 per share) on our common stock, respectively.
In April 2021, our Board of Directors approved an increase in the quarterly dividend on our common stock from $0.10 per share to $0.11 per share. In November 2021, our Board of Directors also approved an increase in the base component of our quarterly dividend on our common stock from $0.11 per share to $0.125 per share. Also on that date, related to our dividend
strategy to return at least 50 percent of quarterly free cash flows to stockholders, our Board of Directors approved a variable dividend of $0.175 per share, resulting in a total base-plus-variable dividend of $0.30 per share on our common stock.
On October 4, 2021, and in connection with the completion of the Merger, our Board of Directors approved a special dividend of $0.50 per share payable on our common stock on October 22, 2021.
In February 2022, our Board of approved an additional increase in the quarterly dividend on our common stock from $0.125 per share to $0.15 per share. Also on that date, our Board of Directors approved a variable dividend of $0.41 per share, resulting in a quarterly base-plus-variable dividend of $0.56 per share on our common stock.
Capital and Exploration Expenditures
On an annual basis, we generally fund most of our capital expenditures, excluding any significant property acquisitions, with cash generated from operations and, if required, borrowings under our revolving credit facility. We budget these expenditures based on our projected cash flows for the year.
The following table presents major components of our capital and exploration expenditures:
Year Ended December 31,
(In millions) 2021 2020 2019
Acquisitions(1) :
Proved $ 7,472 $ - $ -
Unproved 5,381 - -
Total $ 12,853 $ - $ -
Capital expenditures
Drilling, completion and facilities $ 688 $ 547 $ 761
Leasehold acquisitions 5 6 6
Pipeline and gathering 9 - -
Other 23 17 16
725 570 783
Exploration expenditures(2)
18 15 21
Total $ 743 $ 585 $ 804
_______________________________________________________________________________
(1)These amounts represent the fair value of the proved and unproved properties recorded in the purchase price allocation with respect to the Merger. The purchase was funded through the issuance of our common stock.
(2)Exploration expenditures include $4 million and $2 million of exploratory dry-hole costs in 2020 and 2019, respectively. There were no exploratory dry-hole costs in 2021.
In 2021, we drilled 114 gross wells (99.9 net) and completed 132 gross wells (108.3 net), of which 14 gross wells (13.0 net) were drilled but uncompleted in prior years.
Our 2022 capital program is expected to be approximately $1,400 million to $1,500 million, of which $1,225 million to $1,325 million is allocated to drilling and completion activities. We expect to turn-in-line 134 to 153 total net wells in 2022 across our three operating regions. Approximately 49 percent of drilling and completion capital will be invested in the Permian Basin, 44 percent in the Marcellus Shale and the balance in the Anadarko Basin. Midstream, saltwater disposal, electrification, infrastructure and other investments are expected to total approximately $175 million in the year. We will continue to assess the commodity price environment and may increase or decrease our capital expenditures accordingly.
Contractual Obligations
We have various contractual obligations in the normal course of our operations. As of December 31, 2021, our material contractual obligations include debt and related interest expense, transportation and gathering agreements, lease obligations, operational agreements, drilling and completion obligations, derivative obligations and asset retirement obligations. Other joint owners in the properties operated by us could incur a portion of these costs. We expect that our sources of capital will be
adequate to fund these obligations. Refer to the Notes to the Consolidated Financial Statements included in Item 8 of this Annual Report for further details.
From time to time, we enter into arrangements that can give rise to material off-balance sheet obligations. As of December 31, 2021, the material off-balance sheet arrangements we had entered into included certain firm transportation and processing commitments and operating lease agreements with terms at commencement of less than 12 months for equipment used in our exploration and development activities. We have no other off-balance sheet debt or other similar unrecorded obligations.
Critical Accounting Estimates
In preparing financial statements, we follow GAAP. These principles require management to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities as of the date of the balance sheet, and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates, and changes in our estimates are recorded when known. We consider the following to be our most critical estimates that involve judgement of management.
Purchase Accounting
From time to time, we may acquire assets and assume liabilities in transactions accounted for as business combinations, such as the Merger. In connection with the Merger, we allocated the $9.1 billion of purchase price consideration to the assets acquired and liabilities assumed based on estimated fair values as of the effective date of the Merger. The purchase price allocation is substantially complete; however, it may be subject to change for up to one year after October 1, 2021, the effective date of the Merger.
We made a number of assumptions in estimating the fair value of assets acquired and liabilities assumed in the Merger. The most significant assumptions related to the fair value estimates of proved and unproved oil and gas properties, which were recorded at a fair value of $12.9 billion. Since sufficient market data was not available regarding the fair values of the acquired proved and unproved oil and gas properties, we prepared our estimates using discounted cash flows and engaged third party valuation experts. Significant judgments and assumptions are inherent in these estimates and include, among other things, estimates of reserve quantities and production volumes, future commodity prices and price differentials, expected development costs, lease operating costs, reserve risk adjustment factors and an estimate of an applicable market participant discount rate that reflects the risk of the underlying cash flow estimates.
Estimated fair values assigned to assets acquired can have a significant impact on future results of operations, as presented in our financial statements. Fair values are based on estimates of future commodity prices and price differentials, reserve quantities and production volumes, development costs and lease operating costs. In the event that future commodity prices or reserve quantities or production volumes are significantly lower than those used in the determination of fair value as of the effective date of the Merger, the likelihood increases that certain costs may be determined to be unrecoverable.
In addition to the fair value of proved and unproved oil and gas properties, other significant fair value assessments for the assets acquired and liabilities assumed in the Merger relate to long-term debt, fixed assets and derivative instruments. The fair value of the assumed Cimarex publicly traded debt was based on available third-party quoted prices. We prepared estimates and engaged third-party valuation experts to assist in the valuation of certain fixed assets, which required significant judgments and assumptions inherent in the estimates and included projected cash flows and comparable companies’ cash flow multiples. The fair value of assumed derivative instrument liabilities included significant judgments and assumptions related to estimates of future commodity prices and related differentials and estimates of volatility factors and interest rates.
Successful Efforts Method of Accounting
We follow the successful efforts method of accounting for our oil and gas producing activities. Acquisition costs for proved and unproved properties are capitalized when incurred. Judgment is required to determine the proper classification of wells designated as developmental or exploratory, which ultimately will determine the proper accounting treatment of costs incurred. Exploration costs, including geological and geophysical costs, the costs of carrying and retaining unproved properties and exploratory dry-hole costs are expensed. Development costs, including costs to drill and equip development wells and successful exploratory drilling costs to locate proved reserves, are capitalized.
Oil and Gas Reserves
The process of estimating quantities of proved reserves is inherently imprecise, and the reserves data included in this document is only an estimate. The process relies on interpretations and judgment of available geological, geophysical, engineering and production data. The extent, quality and reliability of this technical data can vary. The process also requires certain economic assumptions, some of which are mandated by the SEC, such as commodity prices. Additional assumptions
include drilling and operating expenses, capital expenditures, taxes and availability of funds. Any significant variance in the interpretations or assumptions could materially affect the estimated quantity and value of our reserves and can change substantially over time. Periodic revisions to the estimated reserves and future cash flows may be necessary as a result of reservoir performance, drilling activity, commodity prices, fluctuations in operating expenses, technological advances, new geological or geophysical data or other economic factors. Accordingly, reserve estimates are generally different from the quantities ultimately recovered. We cannot predict the amounts or timing of such future revisions.
The reserve quantity estimates of our oil and gas properties have been prepared by our petroleum engineering staff. Miller and Lents has audited 100 percent of the 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 the 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 their opinions, that our presented estimates are reasonable in the aggregate. For more information regarding reserve estimation, including historical reserve revisions, refer to the Supplemental Oil and Gas Information to the Consolidated Financial Statements included in Item 8.
Our rate of recording DD&A expense is dependent upon our estimate of proved and proved developed reserves, which are utilized in our unit-of-production calculation. If the estimates of proved reserves were to be reduced, the rate at which we record DD&A expense would increase, reducing net income. Such a reduction in reserves may result from lower market prices, which may make it uneconomic to drill and produce higher cost fields. A five percent positive or negative revision to proved reserves would result in a decrease of $0.29 per BOE and an increase of $0.32 per BOE, respectively, on our DD&A rate. This estimated impact is based on current data, and actual events could require different adjustments to our DD&A rate.
In addition, a decline in proved reserve estimates may impact the outcome of our impairment test under applicable accounting standards. Due to the inherent imprecision of the reserve estimation process, risks associated with the operations of proved producing properties and market sensitive commodity prices utilized in our impairment analysis, we cannot determine if an impairment is reasonably likely to occur in the future.
Oil and Gas Properties
We evaluate our proved oil and gas properties for impairment on a field-by-field basis whenever events or changes in circumstances indicate an asset's carrying amount may not be recoverable. We compare expected undiscounted future cash flows to the net book value of the asset. If the future undiscounted expected cash flows, based on our estimate of future commodity prices, operating costs and anticipated production from proved reserves and risk-adjusted probable and possible reserves, are lower than the net book value of the asset, the capitalized cost is reduced to fair value. Commodity pricing is estimated by using a combination of assumptions management uses in its budgeting and forecasting process, historical and current prices adjusted for geographical location and quality differentials, as well as other factors that we believe will impact realizable prices. In the event that commodity prices significantly decline, we would test the recoverability of the carrying value of our oil and gas properties and, if necessary, record an impairment charge. Fair value is calculated by discounting the future cash flows. The discount factor used is based on rates utilized by market participants that are commensurate with the risks inherent in the development and production of the underlying oil and natural gas.
Unproved oil and gas properties are assessed periodically for impairment on an aggregate basis through periodic updates to our undeveloped acreage amortization based on past drilling and exploration experience, our expectation of converting leases to held by production and average property lives. Average property lives are determined on a geographical basis and based on the estimated life of unproved property leasehold rights. Historically, the average property life in each of the geographical areas has not significantly changed and generally range from three to five years. The commodity price environment may impact the capital available for exploration projects as well as development drilling.
As these properties are developed and reserves are proved, the remaining capitalized costs are subject to depreciation and depletion. If the development of these properties is deemed unsuccessful and the properties are abandoned or surrendered, the capitalized costs related to the unsuccessful activity are expensed in the year the determination is made. The rate at which the unproved properties are written off depends on the timing and success of our future exploration and development program.
Derivative Instruments
Under applicable accounting standards, the fair value of each derivative instrument is recorded as either an asset or liability on the balance sheet. At the end of each quarterly period, these instruments are marked-to-market. The change in fair value of derivatives not designated as hedges are recorded as a component of operating revenues in gain (loss) on derivative instruments in the Consolidated Statement of Operations.
Our derivative contracts are measured based on quotes from our counterparties or internal models. Such quotes and models have been derived using an income approach that considers various inputs including current market and contractual prices for the underlying instruments, quoted forward commodity prices, basis differentials, volatility factors and interest rates for a similar length of time as the derivative contract term, as applicable. These estimates are derived from or verified using relevant NYMEX futures contracts or are compared to multiple quotes obtained from counterparties for reasonableness. The determination of fair value also incorporates a credit adjustment for non-performance risk. We measure the non-performance risk of our counterparties by reviewing credit default swap spreads for the various financial institutions with which we have derivative transactions, while our non-performance risk is evaluated using a market credit spread provided by one of our banks.
Our financial condition, results of operations and liquidity can be significantly impacted by changes in the market value of our derivative instruments due to volatility of commodity prices, both NYMEX and basis differentials.
Income Taxes
We make certain estimates and judgments in determining our income tax expense for financial reporting purposes. These estimates and judgments include the calculation of certain deferred tax assets and liabilities that arise from differences in the timing and recognition of revenue and expenses for tax and financial reporting purposes and estimating reserves for potential adverse outcomes regarding tax positions that we have taken. We account for the uncertainty in income taxes using a recognition and measurement threshold for tax positions taken or expected to be taken in a tax return. The tax benefit from an uncertain tax position is recognized when it is more likely than not that the position will be sustained upon examination by taxing authorities based on technical merits of the position. The amount of the tax benefit recognized is the largest amount of the benefit that has a greater than 50 percent likelihood of being realized upon ultimate settlement. The effective tax rate and the tax basis of assets and liabilities reflect management's estimates of the ultimate outcome of various tax uncertainties.
We believe all of our deferred tax assets, net of any valuation allowances, will ultimately be realized, taking into consideration our forecasted future taxable income, which includes consideration of future operating conditions specifically related to commodity prices. If our estimates and judgments change regarding our ability to realize our deferred tax assets, our tax provision could increase in the period it is determined that it is more likely than not it will not be realized.
Our effective tax rate is subject to variability as a result of factors other than changes in federal and state tax rates and/or changes in tax laws which could affect us. Our effective tax rate is affected by changes in the allocation of property, payroll and revenues among states in which we operate. A small change in our estimated future tax rate could have a material effect on current period earnings.
Contingency Reserves
A provision for contingencies is charged to expense when the loss is probable and the cost is estimable. The establishment of a reserve is based on an estimation process that includes the advice of legal counsel and subjective judgment of management. In certain cases, our judgment is based on the advice and opinions of legal counsel and other advisors, the interpretation of laws and regulations, which can be interpreted differently by regulators and courts of laws, our experience and the experiences of other companies dealing with similar matters, and our decision on how we intend to respond to a particular matter. Actual losses can differ from estimates for various reasons, including those noted above. We monitor known and potential legal, environmental and other contingencies and make our best estimate based on the information we have. Future changes in facts and circumstances not currently foreseeable could result in the actual liability exceeding the estimated ranges of loss and amounts accrued.
Stock-Based Compensation
We account for stock-based compensation under the fair value method of accounting in accordance with applicable accounting standards. Under the fair value method, compensation cost is measured at the grant date for equity-classified awards and remeasured each reporting period for liability-classified awards based on the fair value of an award and is recognized over the service period, which is generally the vesting period. To calculate fair value, we use various models, including both a Black Scholes or a Monte Carlo valuation model, as determined by the specific provisions of the award. The use of these models requires significant judgment with respect to expected life, volatility and other factors.
Recently Issued and Adopted Accounting Pronouncements
Refer to Note 1 of the Notes to the Consolidated Financial Statements, “Summary of Significant Accounting Policies,” for a discussion of recently issued and adopted accounting pronouncements.
OTHER ISSUES AND CONTINGENCIES
Regulations
Our operations are subject to various types of regulation by federal, state and local authorities. Refer to the “Other Business Matters” section of Item 1 for a discussion of these regulations.
Restrictive Covenants
Our ability to incur debt, incur liens, pay dividends, repurchase or redeem our equity interests, redeem our senior notes, make certain types of investments, enter into mergers, sell assets, enter into transactions with affiliates, and engage in certain other activities are subject to certain restrictive covenants in our various debt instruments. In addition, the senior note agreements governing various series of senior notes that were issued in separate private placements (the “private placement senior notes”) require us to maintain a minimum annual coverage ratio of consolidated cash flow to interest expense for the trailing four quarters of 2.8 to 1.0 and require a maximum ratio of total debt to consolidated EBITDA for the trailing four quarters of not more than 3.0 to 1.0. Our revolving credit agreement also requires us to maintain a leverage ratio of no more than 3.0 to 1.0 until such time as we have no other debt outstanding that has a financial maintenance covenant based on a leverage ratio, and thereafter requires us to maintain a ratio of total debt to total capitalization of no more than 65 percent.
At December 31, 2021, we were in compliance with all financial covenants in both our senior note agreements and our revolving credit agreement.
Operating Risks and Insurance Coverage
Our business involves a variety of operating risks. Refer to “Risk Factors-Business and Operational Risks-We face a variety of hazards and risks that could cause substantial financial losses” in Part I, Item 1A. In accordance with customary industry practice, we maintain insurance against some, but not all, of these hazards and risks and related losses. The occurrence of any loss events not fully covered by insurance could have a material adverse effect on our financial position, results of operations and cash flows. The costs of these insurance policies are somewhat dependent on our historical claims experience, the areas in which we operate and market conditions.
Commodity Pricing and Risk Management Activities
Our revenues, operating results, financial condition and ability to borrow funds or obtain additional capital depend substantially on prevailing commodity prices. Significant declines in commodity prices may have a material adverse effect on our financial condition, liquidity, ability to obtain financing and operating results. Lower commodity prices also may reduce the amount of oil and natural gas that we can produce economically. Historically, commodity prices have been volatile, with prices fluctuating widely, and they are likely to continue to be volatile. Depressed prices in the future would have a negative impact on our future financial results. In particular, substantially lower prices would significantly reduce revenue and could potentially trigger an impairment of our oil and gas properties or a violation of certain financial debt covenants.
The majority of our production is sold at market-sensitive prices. Generally, if the related commodity index declines, the price that we receive for our production will also decline. Therefore, the amount of revenue that we realize is determined by certain factors that are beyond our control. However, we may mitigate this price risk on a portion of our anticipated production with the use of financial commodity derivatives, including collars, swaps, roll differential swaps and basis swaps to reduce the impact of sustained lower pricing on our revenue. Under these arrangements, there is also a risk that the movement of index prices may result in our inability to realize the full benefit of an improvement in market conditions.
RESULTS OF OPERATIONS
2021 and 2020 Compared
Operating Revenues
Year Ended December 31, Variance
(In millions) 2021 2020 Amount Percent
Natural gas $ 2,798 $ 1,405 $ 1,393 99 %
Oil 616 - 616 N/A
NGL 243 - 243 N/A
(Loss) gain on derivative instruments (221) 61 (282) (462) %
Other 13 - 13 N/A
$ 3,449 $ 1,466 $ 1,983 135 %
Production Revenues
Our production revenues vary from year to year and are derived from sales of our oil, natural gas and NGL production. Our 2021 production revenues were substantially increased due to the Merger, which significantly expanded our operations to include the Permian and Anadarko Basins. Increases or decreases in our revenues, profitability and future production growth are highly dependent on the commodity prices we receive. Commodity prices are market driven and we expect future prices to be volatile due to supply and demand factors, pipeline capacity, seasonality and geopolitical, economic and other factors.
Below is a discussion of our production revenue, price and volume variances.
Natural Gas Revenues
Year Ended December 31, Variance Increase (Decrease) (In millions)
2021 2020 Amount Percent
Volume variance (Bcf) 911.1 857.7 53.4 6 % $ 164
Price variance ($/Mcf) $ 3.07 $ 1.64 $ 1.43 87 % 1,229
Total $ 1,393
Natural gas revenues increased $1.4 billion primarily due to significantly higher natural gas prices combined with higher production. The increase in production was primarily driven by an increase in fourth quarter production due to the Merger.
Oil Revenues
Oil revenues increased $616 million primarily due to the Merger.
NGL Revenues
NGL revenues increased $243 million primarily due to the Merger.
(Loss) Gain on Derivative Instruments
Net gains and losses on our derivative instruments are a function of fluctuations in the underlying commodity index prices as compared to the contracted prices and the monthly cash settlements (if any) of the instruments. We have elected not to designate our derivatives as hedging instruments for accounting purposes and, therefore, we do not apply hedge accounting treatment to our derivative instruments. Consequently, changes in the fair value of our derivative instruments and cash settlements on the instruments are included as a component of operating revenues as either a net gain or loss on derivative instruments. Cash settlements of our contracts are included in cash flows from operating activities in our statements of cash flows. The following table presents the components of “(Loss) gain on derivative instruments” for the years indicated:
Year Ended December 31,
(In millions) 2021 2020
Cash (paid) received on settlement of derivative instruments
Gas contracts $ (307) $ 35
Oil contracts (124) -
Non-cash (loss) gain on derivative instruments
Gas contracts 99 26
Oil contracts 111 -
$ (221) $ 61
Included in the table above are settlement losses of $194 million related to the derivative liabilities that we assumed in the Merger. Settlement losses realized in 2021 were primarily driven by significant price increases in the underlying commodity index prices that occurred during the fourth quarter of 2021.
Operating Costs and Expenses
Costs associated with producing oil and natural gas are substantial. Among other factors, some of these costs vary with commodity prices, some trend with the volume and commodity mix of production, some are a function of the number of wells we own, some depend on the prices charged by service companies, and some fluctuate based on a combination of the foregoing. Our operating costs and expenses in 2021 were substantially increased due to the Merger, which significantly expanded our operations to include the Permian and Anadarko Basins. In addition, our costs for services, labor and supplies have recently increased due to increased demand for those items and supply chain disruptions related to the COVID-19 pandemic.
The following table reflects our operating costs and expenses for the years indicated and a discussion of the operating costs and expenses follows.
Year Ended December 31, Variance Per BOE
(In millions, except per BOE) 2021 2020 Amount Percent 2021 2020
Operating Expenses
Direct operations $ 156 $ 73 $ 83 114 % $ 0.93 $ 0.51
Transportation, processing and gathering 663 571 92 16 % 3.97 3.99
Taxes other than income 83 14 69 493 % 0.50 0.10
Exploration 18 15 3 20 % 0.11 0.10
Depreciation, depletion and amortization 693 391 302 77 % 4.15 2.73
General and administrative 270 106 164 155 % 1.62 0.74
$ 1,883 $ 1,170 $ 713 61 %
Direct Operations
Direct operations expense generally consists of costs for labor, equipment, maintenance, saltwater disposal, compression, power, treating and miscellaneous other costs (lease operating expense). Direct operations expense also includes well workover activity necessary to maintain production from existing wells. Direct operations expense consisted of lease operating expense and workover expense as follows:
Year Ended December 31, Per BOE
(In millions, except per BOE) 2021 2020 Variance 2021 2020
Direct Operating Expense
Lease operating expense
$ 127 $ 58 $ 69 $ 0.76 $ 0.41
Workover expense
29 15 14 0.17 0.10
$ 156 $ 73 $ 83 $ 0.93 $ 0.51
Lease operating and workover expense increased due to our expanded operations due to the Merger.
Transportation, Processing and Gathering
Transportation, processing and gathering costs principally consist of expenditures to prepare and transport production from the wellhead, including gathering, fuel, compression and processing costs. Gathering costs also include costs associated with operating our gas gathering infrastructure, including operating and maintenance expenses. Costs vary by operating area and will fluctuate with increases or decreases in production volumes, contractual fees, and changes in fuel and compression costs.
Transportation, processing and gathering increased $92 million due to our expanded operations due to the Merger, offset by a decrease in costs due to lower production in the Marcellus Shale.
Taxes Other Than Income
Taxes other than income consist of production (or severance) taxes, drilling impact fees, ad valorem taxes and other taxes. State and local taxing authorities assess these taxes, with production taxes being based on the volume or value of production, drilling impact fees being based on drilling activities and prevailing natural gas prices and ad valorem taxes being based on the value of properties. The following table presents taxes other than income for the years indicated:
Year Ended December 31,
(In millions) 2021 2020 Variance
Taxes Other than Income
Production
$ 57 $ - $ 57
Drilling impact fees
22 14 8
Ad valorem
3 - 3
Other
1 - 1
$ 83 $ 14 $ 69
Taxes other than income as a percentage of production revenue
2.3 % 1.0 %
Taxes other than income increased $69 million. Production taxes represented the majority of our taxes other than income, which increased primarily due to the Merger and higher commodity prices. Drilling impact fees increased primarily due to higher natural gas prices.
Depreciation, Depletion and Amortization
DD&A expense consisted of the following for the periods indicated:
Year Ended December 31, Per BOE
(In millions, except per BOE) 2021 2020 Variance 2021 2020
DD&A Expense
Depletion
$ 663 $ 373 $ 290 $3.97 $2.61
Depreciation
23 6 17 $0.14 $0.04
Amortization of undeveloped properties 1 8 (7) $0.01 $0.06
Accretion of ARO
6 4 2 $0.04 $0.03
$ 693 $ 391 $ 302 $4.16 $0.00 $2.74
Depletion of our producing properties is computed on a field basis using the units-of-production method under the successful efforts method of accounting. The economic life of each producing property depends upon the estimated proved reserves for that property, which in turn depend upon the assumed realized sales price for future production. Therefore, fluctuations in oil and gas prices will impact the level of proved developed and proved reserves used in the calculation. Higher prices generally have the effect of increasing reserves, which reduces depletion expense. Conversely, lower prices generally have the effect of decreasing reserves, which increases depletion expense. The cost of replacing production also impacts our depletion expense. In addition, changes in estimates of reserve quantities, estimates of operating and future development costs, reclassifications of properties from unproved to proved and impairments of oil and gas properties will also impact depletion expense. Our depletion expense increased $290 million due to increased production and a higher depletion rate of $3.97 per MBOE for 2021, both of which are attributable to a significant increase in the value of the oil and gas properties acquired on the closing date of the Merger, compared to $2.61 per MBOE for 2020.
Fixed assets consist primarily of gas gathering facilities, water infrastructure, buildings, vehicles, aircraft, furniture and fixtures and computer equipment and software. These items are recorded at cost and are depreciated on the straight-line method based on expected lives of the individual assets, which range from three to 30 years. Also included in our depreciation expense is the depreciation of the right-of-use asset associated with our finance lease gathering system. The increase in depreciation expense during 2021 as compared to 2020 is primarily due to increased depreciation on our gathering and plant facilities acquired in the Merger.
General and Administrative
General and administrative (“G&A”) expense consists primarily of salaries and related benefits, stock-based compensation, office rent, legal and consulting fees, systems costs and other administrative costs incurred. Our G&A expense is reported net of amounts reimbursed to us by working interest owners of the oil and gas properties we operate. The table below reflects our G&A expense:
Year Ended December 31,
(In millions) 2021 2020 Variance
G&A Expense
General and administrative expense
$ 107 $ 63 $ 44
Stock-based compensation expense
57 43 14
Merger-related expense 106 - 106
$ 270 $ 106 $ 164
General and administrative increased $44 million primarily due to the Merger, which significantly expanded our headcount and office-related expenses.
Periodic stock-based compensation expense will fluctuate based on the grant date fair value of awards, the number of awards, the requisite service period of the awards, estimated employee forfeitures, and the timing of the awards. Stock-based compensation expense increased primarily due to the acceleration of vesting of certain stock-based awards on closing of the Merger of $10 million and an increase in compensation expense of $9 million related to replacement awards granted to Cimarex employees at the closing of the Merger. These increases were partially offset by lower stock-based compensation expense of $4 million related to the awards that vested at the closing of the Merger.
Merger-related expenses increased $106 million primarily due to $42 million of transaction-related costs (legal and financial advisor costs) associated with the Merger, $20 million of deferred compensation expense related to certain change-in-control payments and $44 million associated with the expected termination of certain Cimarex employees, which is being accrued over the expected transition period.
Other Expenses and Income
Year Ended December 31, Variance
(In millions) 2021 2020 Amount Percent
Other Expenses and Income
Loss on sale of assets
$ 2 $ - $ 2 N/A
Interest expense, net 62 54 8 15 %
$ 64 $ 54 $ 10 19 %
Interest Expense, net
Interest expense increased $8 million primarily due to the incremental interest expense, net of premium amortization associated with the debt related to the Merger of $2.2 billion, including the New Coterra Notes and Existing Cimarex Notes. This increase was partially offset by lower interest expense due to repayment of $87 million of our 6.51% weighted-average private placement senior notes, which matured in July 2020, the repayment of $88 million of our 5.58% weighted-average private placement senior notes, which matured in January 2021, and the repayment of $100 million of our 3.65% weighted-average private placement senior notes, which matured in September 2021.
Income Tax Expense
Year Ended December 31,
(In millions) 2021 2020 Variance
Income Tax Expense (Benefit)
Current tax expense (benefit)
$ 218 $ (31) $ 249
Deferred tax expense
126 72 54
$ 344 $ 41 $ 303
Combined federal and state effective income tax rate
23 % 17 %
Income tax expense increased $303 million due to higher pretax income attributable to increased commodity prices and the Merger.
2020 and 2019 Compared
For information on the comparison of the results of operations for the year ended December 31, 2020 compared to the year ended December 31, 2019, refer to Management's Discussion and Analysis included in the Coterra Energy Inc., formerly known as Cabot Oil & Gas Corporation, Annual Report on Form 10-K for the year ended December 31, 2020.

---

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
In the normal course of business, we are subject to a variety of risks, including market risks associated with changes in commodity prices and interest rate movements on outstanding debt. The following quantitative and qualitative information is provided about financial instruments to which we were party to as of December 31, 2021 and from which we may incur future gains or losses from changes in commodity prices or interest rates.
Commodity Price Risk
Our most significant market risk exposure is pricing applicable to our oil, natural gas and NGL production. Realized prices are mainly driven by the worldwide price for oil and spot market prices for North American natural gas and NGL production. These prices have been volatile and unpredictable. To mitigate the volatility in commodity prices, we may enter into derivative instruments to hedge a portion of our production.
Derivative Instruments and Risk Management Activities
Our risk management strategy is designed to reduce the risk of commodity price volatility for our production in the oil and natural gas markets through the use of financial commodity derivatives. A committee that consists of members of senior management oversees our risk management activities. Our financial commodity derivatives generally cover a portion of our production and, while protecting us in the event of price declines, limit the benefit to us in the event of price increases. Further, if any of our counterparties defaulted, this protection might be limited as we might not receive the full benefit of our financial commodity derivatives. Please read the discussion below as well as Note 5 of the Notes to the Consolidated Financial Statements, “Derivative Instruments,” for a more detailed discussion of our derivatives.
Periodically, we enter into financial commodity derivatives, including collar, swap, roll differential swap and basis swap agreements, to protect against exposure to commodity price declines related to our oil and natural gas production. Our credit agreement restricts our ability to enter into financial commodity derivatives other than to hedge or mitigate risks to which we have actual or projected exposure or as permitted under our risk management policies and not subjecting us to material speculative risks. All of our financial derivatives are used for risk management purposes and are not held for trading purposes. Under the collar agreements, if the index price rises above the ceiling price, we pay the counterparty. If the index price falls below the floor price, the counterparty pays us. Under the swap agreements, we receive a fixed price on a notional quantity of natural gas in exchange for paying a variable price based on a market-based index.
As of December 31, 2021, we had the following outstanding financial commodity derivatives:
Collars Swaps Estimated Fair Value Asset (Liability)
(In millions)
Floor Ceiling Basis Swaps Roll Swaps
Type of Contract Volume (Mbbl) Contract Period Range ($/Bbl) Weighted- Average ($/Bbl) Range ($/Bbl) Weighted- Average ($/Bbl) Weighted- Average ($/Bbl) Weighted- Average ($/Bbl)
Crude oil (WTI) 630 Jan. 2022-Mar. 2022 $- $ 35.00 $45.15-$45.40
$ 45.28 $ (19)
Crude oil (WTI) 1,629 Jan. 2022-Jun. 2022 $35.00-$37.50
$ 36.11 $48.38-$51.10
$ 49.97 (40)
Crude oil (WTI) 2,730 Jan. 2022-Sep. 2022 $- $ 40.00 $47.55-$50.89
$ 49.19 (67)
Crude oil (WTI) 2,920 Jan. 2022-Dec. 2022 $- $ 57.00 $72.20-$72.80
$ 72.43 (12)
Crude oil (WTI Midland)(1)
630 Jan. 2022-Mar. 2022 $ 0.11 -
Crude oil (WTI Midland)(1)
1,448 Jan. 2022-Jun. 2022 $ 0.25 -
Crude oil (WTI Midland)(1)
1,911 Jan. 2022-Sep. 2022 $ 0.38 -
Crude oil (WTI Midland)(1)
2,920 Jan. 2022-Dec. 2022 $ 0.05 (2)
Crude oil (WTI) 630 Jan. 2022-Mar. 2022 $ (0.24) (1)
Crude oil (WTI) 724 Jan. 2022-Jun. 2022 $ (0.20) (1)
Crude oil (WTI) 1,911 Jan. 2022-Sep. 2022 $ 0.10 (1)
$ (143)
________________________________________________________
(1)The index price the Company pays under these basis swaps is WTI Midland as quoted by Argus Americas Crude.
Collars Estimated Fair Value Asset (Liability) (In millions)
Floor Ceiling
Type of Contract Volume (Mmbtu) Contract Period Range
($/Mmbtu) Weighted- Average
($/Mmbtu) Range
($/Mmbtu) Weighted- Average
($/Mmbtu)
Natural gas (NYMEX) 36,000,000 Jan. 2022-Mar. 2022 $4.00-$4.75
$ 4.38 $5.00-$10.32
$ 6.97 $ 24
Natural gas (NYMEX) 42,800,000 Apr. 2022 - Oct. 2022 $3.00-$3.50
$ 3.19 $4.07-$4.83
$ 4.30 -
Natural gas (Perm EP)(1)
1,800,000 Jan. 2022-Mar. 2022 $1.80-$1.90
$ 1.85 $2.18-$2.19
$ 2.18 (3)
Natural gas (Perm EP)(1)
3,620,000 Jan. 2022-Jun. 2022 $- $ 2.40 $2.85-$2.90
$ 2.88 (2)
Natural gas (Perm EP)(1)
7,300,000 Jan. 2022-Dec. 2022 $- $ 2.50 $- $ 3.15 (3)
Natural gas (PEPL)(2)
3,600,000 Jan. 2022-Mar. 2022 $1.90-$2.10
$ 2.00 $2.35-$2.44
$ 2.40 (7)
Natural gas (PEPL)(2)
3,620,000 Jan. 2022-Jun. 2022 $- $ 2.40 $2.81-$2.91
$ 2.86 (3)
Natural gas (PEPL)(2)
7,300,000 Jan. 2022-Dec. 2022 $- $ 2.60 $- $ 3.27 (4)
Natural gas (Waha)(3)
3,600,000 Jan. 2022-Mar. 2022 $1.70-$1.84
$ 1.77 $2.10-$2.20
$ 2.15 (6)
Natural gas (Waha)(3)
3,620,000 Jan. 2022-Jun. 2022 $- $ 2.40 $2.82-$2.89
$ 2.86 (2)
Natural gas (Waha)(3)
2,730,000 Jan. 2022-Sep. 2022 $- $ 2.40 $- $ 2.77 (1)
Natural gas (Waha)(3)
7,300,000 Jan. 2022-Dec. 2022 $- $ 2.50 $- $ 3.12 (3)
$ (10)
________________________________________________________
(1)The index price for these collars is El Paso Natural Gas Company, Permian Basin Index (“Perm EP”) as quoted in Platt’s Inside FERC.
(2)The index price for these collars is Panhandle Eastern Pipe Line, Tex/OK Mid-Continent Index (“PEPL”) as quoted in Platt’s Inside FERC.
(3)The index price for these collars is Waha West Texas Natural Gas Index (“Waha”) as quoted in Platt’s Inside FERC.
The estimated fair value amounts set forth in the table above represent our total unrealized derivative position at December 31, 2021 and exclude the impact of non-performance risk. Non-performance risk is considered in the fair value of our derivative instruments that are recorded in our Consolidated Financial Statements and is primarily evaluated by reviewing
credit default swap spreads for the various financial institutions with which we have derivative contracts, while our non-performance risk is evaluated using a market credit spread provided by several of our banks.
In early 2022, we entered into the following outstanding financial commodity derivatives:
Collars
Floor Ceiling
Type of Contract Volume (Mmbtu) Contract Period Range
($/Mmbtu) Weighted-
Average
($/Mmbtu) Range
($/Mmbtu) Weighted-
Average
($/Mmbtu)
Natural gas (NYMEX) 71,500,000 Apr. 2022-Dec. 2022 $3.50 - $4.25
$ 3.84 $4.75 - $6.65
$ 5.39
Natural gas (NYMEX) 10,700,000 Apr. 2022-Oct. 2022 $ - $ 4.00 $5.60 - $5.69 $ 5.63
Natural gas (NYMEX) 7,550,000 Nov. 2022-Mar. 2023 $ - $ 4.00 $7.06 - $7.10 $ 7.08
A significant portion of our expected oil and natural gas production for 2022 and beyond is currently unhedged and directly exposed to the volatility in commodity prices, whether favorable or unfavorable.
During 2021, oil collars with floor prices ranging from $29.00 to $40.00 per Bbl and ceiling prices ranging from $34.15 to $51.10 per Bbl covered 3.7 Mmbbls, or 45 percent, of oil production at a weighted-average price of $44.37 per Bbl. Oil basis swaps covered 3.2 Mmbbls, or 40 percent, of oil production at a weighted-average price of $(0.08) per Bbl. Oil roll differential swaps covered 1.6 Mmbbls, or 20 percent, of oil production at a weighted-average price of $(0.10) per Bbl.
During 2021, natural gas collars with floor prices ranging from $1.50 to $2.85 per Mmbtu and ceiling prices ranging from $1.75 to $3.94 per Mmbtu covered 193.2 Bcf, or 21 percent of natural gas production at a weighted-average price of $2.85 per Mmbtu. Natural gas swaps covered 56.3 Bcf, or six percent, of natural gas production at a weighted-average price of $3.16 per Mmbtu.
We are exposed to market risk on financial commodity derivative instruments to the extent of changes in market prices of oil and natural gas. However, the market risk exposure on these derivative contracts is generally offset by the gain or loss recognized upon the ultimate sale of the commodity. Although notional contract amounts are used to express the volume of oil and natural gas agreements, the amounts that can be subject to credit risk in the event of non-performance by third parties are substantially smaller. Our counterparties are primarily commercial banks and financial service institutions that management believes present minimal credit risk and our derivative contracts are with multiple counterparties to minimize our exposure to any individual counterparty. We perform both quantitative and qualitative assessments of these counterparties based on their credit ratings and credit default swap rates where applicable. We have not incurred any losses related to non-performance risk of our counterparties and we do not anticipate any material impact on our financial results due to non-performance by third parties. However, we cannot be certain that we will not experience such losses in the future.
Interest Rate Risk
At December 31, 2021, we had total debt of $3.1 billion (with a principal amount of $2.9 billion). All of our outstanding debt is based on fixed interest rates and, as a result, we do not have significant exposure to movements in market interest rates with respect to such debt. Our revolving credit facility provides for variable interest rate borrowings; however, we did not have any borrowings outstanding as of December 31, 2021 and, therefore, no related exposure to interest rate risk.
Fair Value of Other Financial Instruments
The estimated fair value of other financial instruments is the amount at which the instrument could be exchanged currently between willing parties. The carrying amounts reported in the Consolidated Balance Sheet for cash and cash equivalents and restricted cash approximate fair value due to the short-term maturities of these instruments.
The fair value of the New Coterra Notes and Existing Cimarex Notes is based on quoted market prices. We use available market data and valuation methodologies to estimate the fair value of our private placement senior notes. The fair value of the private placement senior notes is the estimated amount we would have to pay a third party to assume the debt, including a credit spread for the difference between the issue rate and the period end market rate. The credit spread is our default or repayment risk. The credit spread (premium or discount) is determined by comparing our senior notes and revolving credit facility to new issuances (secured and unsecured) and secondary trades of similar size and credit statistics for both public and private debt. The fair value of the private placement senior notes is based on interest rates currently available to us.
The carrying amount and fair value of debt is as follows:
December 31, 2021 December 31, 2020
(In millions) Carrying Amount Estimated Fair
Value Carrying Amount Estimated Fair
Value
Long-term debt $ 3,125 $ 3,163 $ 1,134 $ 1,214
Current maturities - - (188) (189)
Long-term debt, excluding current maturities $ 3,125 $ 3,163 $ 946 $ 1,025

---

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
Page
Report of Independent Registered Public Accounting Firm (PCAOB ID: 238)
Consolidated Balance Sheet at December 31, 2021 and 2020
Consolidated Statement of Operations for the Years Ended December 31, 2021, 2020 and 2019
Consolidated Statement of Comprehensive Income for the Years Ended December 31, 2021, 2020 and 2019
Consolidated Statement of Cash Flows for the Years Ended December 31, 2021, 2020 and 2019
Consolidated Statement of Stockholders' Equity for the Years Ended December 31, 2021, 2020 and 2019
Notes to the Consolidated Financial Statements
Supplemental Oil and Gas Information (Unaudited)
Report of Independent Registered Public Accounting Firm
To the Board of Directors and Stockholders of Coterra Energy Inc.
Opinions on the Financial Statements and Internal Control over Financial Reporting
We have audited the accompanying consolidated balance sheet of Coterra Energy Inc. and its subsidiaries (the “Company”) as of December 31, 2021 and 2020, and the related consolidated statements of operations, of comprehensive income, of stockholders’ equity and of cash flows for each of the three years in the period ended December 31, 2021, including the related notes (collectively referred to as the “consolidated financial statements”). We also have audited the Company’s internal control over financial reporting as of December 31, 2021, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31, 2021 and 2020, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2021 in conformity with accounting principles generally accepted in the United States of America. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2021, based on criteria established in Internal Control - Integrated Framework (2013) issued by the COSO.
Basis for Opinions
The Company's management is responsible for these consolidated financial statements, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in Management’s Report on Internal Control over Financial Reporting appearing under Item 9A. Our responsibility is to express opinions on the Company’s consolidated financial statements and on the Company's internal control over financial reporting based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud, and whether effective internal control over financial reporting was maintained in all material respects.
Our audits of the consolidated financial statements included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.
As described in Management’s Report on Internal Control over Financial Reporting, management has excluded Cimarex Energy Co. from its assessment of internal control over financial reporting as of December 31, 2021 because it was acquired by the Company in a purchase business combination during 2021. We have also excluded Cimarex Energy Co. from our audit of internal control over financial reporting. Cimarex Energy Co. is a wholly-owned subsidiary whose total assets and total revenues excluded from management’s assessment and our audit of internal control over financial reporting represent approximately 75% and 33%, respectively, of the related consolidated financial statement amounts as of and for the year ended December 31, 2021.
Definition and Limitations of Internal Control over Financial Reporting
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and
expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
Critical Audit Matters
The critical audit matters communicated below are matters arising from the current period audit of the consolidated financial statements that were communicated or required to be communicated to the audit committee and that (i) relate to accounts or disclosures that are material to the consolidated financial statements and (ii) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matters below, providing separate opinions on the critical audit matters or on the accounts or disclosures to which they relate.
The Impact of Proved Oil and Gas Reserves on Proved Oil and Gas Properties, Net
As described in Notes 1 and 3 to the consolidated financial statements, a significant portion of the Company’s properties and equipment, net balance of $17,375 million as of December 31, 2021 and depreciation, depletion and amortization (DD&A) expense of $693 million for the year ended December 31, 2021 relate to proved oil and gas properties. The Company uses the successful efforts method of accounting for its oil and gas producing activities. As disclosed by management, the Company’s rate of recording DD&A expense is dependent upon the estimate of proved and proved developed reserves, which are utilized in the unit-of-production calculation. In estimating proved oil and natural gas reserves, management relies on interpretations and judgment of available geological, geophysical, engineering and production data, as well as the use of certain economic assumptions such as commodity prices. Additional assumptions include drilling and operating expenses, capital expenditures, taxes and availability of funds. The estimates of oil and natural gas reserves have been developed by specialists, specifically petroleum engineers.
The principal considerations for our determination that performing procedures relating to the impact of proved oil and natural gas reserves on proved oil and gas properties is a critical audit matter are (i) the significant judgment by management, including the use of specialists, when developing the estimates of proved oil and natural gas reserves, which in turn led to (ii) a high degree of auditor judgment and effort in performing procedures and evaluating the audit evidence related to the data, methods, and assumptions used by management and its specialists in developing the estimates of proved oil and natural gas reserves.
Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the consolidated financial statements. These procedures included testing the effectiveness of controls relating to management’s estimates of proved oil and natural gas reserves. The work of management’s specialists was used in performing the procedures to evaluate the reasonableness of the proved oil and natural gas reserves. As a basis for using this work, the specialists’ qualifications were understood and the Company’s relationship with the specialists was assessed. The procedures performed also included evaluation of the methods and assumptions used by the specialists, tests of the completeness and accuracy of the data used by the specialists, and an evaluation of the specialist’s findings.
Merger with Cimarex Energy Co. - Valuation of oil and gas properties
As described in Note 2 to the consolidated financial statements, on October 1, 2021 the Company completed a merger with Cimarex Energy Co. for approximately $9.1 billion. The transaction was accounted for using the acquisition method of accounting, under which the assets, liabilities, and mezzanine equity will be recorded at their respective fair values. Determining the fair value of the assets and liabilities requires judgment and certain assumptions to be made, the most significant of these being related to the valuation of oil and gas properties, which were recorded at a fair value of $12.9 billion. As disclosed by management, since sufficient market data was not available regarding the fair values of the acquired oil and gas properties, management prepared the estimates using discounted cash flows and engaged third party valuation experts. Significant judgments and assumptions are inherent in these estimates and include, among other things, estimates of reserve quantities and production volumes, future commodity prices and price differentials, expected development costs, lease operating costs, reserve risk adjustment factors and an estimate of an applicable market participant discount rates that reflects the risk of the underlying cash flow estimates.
The principal considerations for our determination that performing procedures relating to the valuation of oil and gas properties from the merger with Cimarex Energy Co. is a critical audit matter are (i) the significant judgment by management,
including the use of specialists, when determining the fair value of the acquired oil and gas properties, which in turn led to (ii) a high degree of auditor judgment, subjectivity, and effort in performing procedures and evaluating management’s significant assumptions related to production volumes, future commodity prices and price differentials, lease operating costs, reserve risk adjustment factors, and the market participant discount rates; and (iii) the audit effort involved the use of professionals with specialized skill and knowledge.
Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the consolidated financial statements. These procedures included testing the effectiveness of controls relating to acquisition accounting, including controls over the fair value estimate of oil and gas properties. These procedures also included, among others (i) testing management’s process for developing the fair value of the acquired oil and gas properties; (ii) evaluating the appropriateness of the discounted cash flow models; (iii) testing the completeness and accuracy of underlying data used in the discounted cash flow modes; and (iv) evaluating the reasonableness of the significant assumptions used by management related to production volumes, future commodity prices and price differentials, lease operating costs, reserve risk adjustment factors, and the market participant discount rates. The work of management’s specialists was used in performing the procedures to evaluate the reasonableness of the oil and natural gas reserves as stated in the Critical Audit Matter titled “The Impact of Proved Oil and Natural Gas Reserves on Proved Oil and Gas Properties” and the reasonableness of the production volumes used in the discounted cash flows. As a basis for using this work, management’s specialists’ qualifications were understood and the Company’s relationship with the specialists was assessed. The procedures performed also included evaluation of the methods and assumptions used by the specialists, tests of the completeness and accuracy of data used by the specialists, and an evaluation of the specialists’ findings. Evaluating the reasonableness of management’s assumptions relating to future commodity prices and price differentials and lease operating costs involved evaluating whether the assumptions used by management were reasonable considering the past performance of Cimarex Energy Co., the consistency with external market and industry data, and whether the assumptions were consistent with evidence obtained in other areas of the audit. Professionals with specialized skill and knowledge were used to assist in the evaluation of the reasonableness of the significant assumptions related to the market participant discount rates and reserve risk adjustment factors.
/s/ PricewaterhouseCoopers LLP
Houston, Texas
March 1, 2022
We have served as the Company’s auditor since 1989.
COTERRA ENERGY INC.
CONSOLIDATED BALANCE SHEET
December 31,
(In millions, except share amounts) 2021 2020
ASSETS
Current assets
Cash and cash equivalents $ 1,036 $ 140
Restricted cash 10 12
Accounts receivable, net 1,037 215
Income taxes receivable - 6
Inventories 39 15
Derivative instruments 7 26
Other current assets 7 2
Total current assets 2,136 416
Properties and equipment, net (Successful efforts method) 17,375 4,045
Other assets 389 63
$ 19,900 $ 4,524
LIABILITIES, REDEEMABLE PREFERRED STOCK AND STOCKHOLDERS' EQUITY
Current liabilities
Accounts payable $ 747 $ 162
Current portion of long-term debt - 188
Accrued liabilities 260 22
Interest payable 25 18
Income taxes payable 29 -
Derivative instruments 159 -
Total current liabilities 1,220 390
Long-term debt, net 3,125 946
Deferred income taxes 3,101 774
Asset retirement obligations 259 85
Postretirement benefits 33 31
Other liabilities 374 82
Total liabilities 8,112 2,308
Commitments and contingencies
Cimarex redeemable preferred stock 50 -
Stockholders' equity
Common stock:
Authorized - 1,800,000,000 shares and 960,000,000 shares of $0.10 par value in 2021 and 2020, respectively
Issued - 892,612,010 shares and 477,828,813 shares in 2021 and 2020, respectively
89 48
Additional paid-in capital 10,911 1,804
Retained earnings 2,563 2,185
Accumulated other comprehensive income 1 2
Less treasury stock, at cost:
79,082,385 shares and 78,957,318 shares in 2021 and 2020, respectively
(1,826) (1,823)
Total stockholders' equity 11,738 2,216
$ 19,900 $ 4,524
The accompanying notes are an integral part of these consolidated financial statements.
COTERRA ENERGY INC.
CONSOLIDATED STATEMENT OF OPERATIONS
Year Ended December 31,
(In millions, except per share amounts) 2021 2020 2019
OPERATING REVENUES
Natural gas $ 2,798 $ 1,405 $ 1,985
Oil 616 - -
NGL 243 - -
(Loss) gain on derivative instruments (221) 61 81
Other 13 - -
3,449 1,466 2,066
OPERATING EXPENSES
Direct operations 156 73 77
Transportation, processing and gathering 663 571 575
Taxes other than income 83 14 17
Exploration 18 15 20
Depreciation, depletion and amortization 693 391 406
General and administrative 270 106 95
1,883 1,170 1,190
Earnings on equity method investments - - 81
Loss on sale of assets (2) - (1)
INCOME FROM OPERATIONS 1,564 296 956
Interest expense, net 62 54 55
Other expense - - 1
Income before income taxes 1,502 242 900
Income tax expense 344 41 219
NET INCOME $ 1,158 $ 201 $ 681
Earnings per share
Basic $ 2.30 $ 0.50 $ 1.64
Diluted $ 2.29 $ 0.50 $ 1.63
Weighted-average common shares outstanding
Basic 503 399 416
Diluted 504 401 418
The accompanying notes are an integral part of these consolidated financial statements.
COTERRA ENERGY INC.
CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME
Year Ended December 31,
(In millions) 2021 2020 2019
Net income
$ 1,158 $ 201 $ 681
Postretirement benefits:
Net actuarial gain (loss)(1)
- 1 (2)
Amortization of prior service cost(2)
(1) (1) (1)
Total other comprehensive income (1) - (3)
Comprehensive income $ 1,157 $ 201 $ 678
_______________________________________________________________________________
(1)Net of income taxes of less than $1 million for each of the years ended December 31, 2021, 2020 and 2019.
(2)Net of income taxes of less than $1 million for each of the years ended December 31, 2021, 2020 and 2019.
The accompanying notes are an integral part of these consolidated financial statements.
COTERRA ENERGY INC.
CONSOLIDATED STATEMENT OF CASH FLOWS
Year Ended December 31,
(In millions) 2021 2020 2019
CASH FLOWS FROM OPERATING ACTIVITIES
Net income $ 1,158 $ 201 $ 681
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization 693 391 406
Deferred income tax expense 126 72 244
Loss on sale of assets 2 - 1
Exploratory dry hole cost - 4 2
Loss (gain) on derivative instruments 221 (61) (81)
Net cash (paid) received in settlement of derivative instruments (431) 35 139
Earnings on equity method investments - - (81)
Distribution of earnings from equity method investments - - 16
Amortization of premium and debt issuance costs (10) 3 4
Stock-based compensation and other 52 40 30
Changes in assets and liabilities:
Accounts receivable, net (229) (6) 153
Income taxes 34 124 (14)
Inventories 5 (2) (3)
Other current assets (4) - -
Accounts payable and accrued liabilities 47 (30) (30)
Interest payable 6 (2) -
Other assets and liabilities (3) 9 (22)
Net cash provided by operating activities 1,667 778 1,445
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures (728) (576) (788)
Proceeds from sale of assets 8 1 3
Investment in equity method investments - - (9)
Distribution of investment from equity method investments - - 2
Cash received from Merger 1,033 - -
Proceeds from sale of equity method investments - (9) 249
Net cash provided by (used in) investing activities 313 (584) (543)
CASH FLOWS FROM FINANCING ACTIVITIES
Borrowings from debt 100 196 95
Repayments of debt (288) (283) (102)
Repayment of finance leases (2) - -
Treasury stock repurchases - - (520)
Dividends paid (780) (159) (146)
Tax withholding on vesting of stock awards (114) (10) (11)
Capitalized debt issuance costs (4) - (6)
Cash received for stock option exercises 2 - -
Net cash used in financing activities (1,086) (256) (690)
Net increase (decrease) in cash, cash equivalents and restricted
cash
894 (62) 212
Cash, cash equivalents and restricted cash, beginning of period 152 214 2
Cash, cash equivalents and restricted cash, end of period $ 1,046 $ 152 $ 214
The accompanying notes are an integral part of these consolidated financial statements.
COTERRA ENERGY INC.
CONSOLIDATED STATEMENT OF STOCKHOLDERS' EQUITY
(In millions, except per
share amounts) Common
Shares Common Stock
Par Treasury
Shares Treasury
Stock Paid-In
Capital Accumulated
Other
Comprehensive
Income (Loss) Retained
Earnings Total
Balance at December 31, 2018 476 $ 48 53 $ (1,335) $ 1,763 $ 4 $ 1,608 $ 2,088
Net income - - - - - - 681 681
Stock amortization and vesting 1 - - - 19 - - 19
Purchase of treasury stock - - 26 (488) - - - (488)
Cash dividends at $0.35 per share
- - - - - - (146) (146)
Other comprehensive income - - - - - (3) - (3)
Balance at December 31, 2019 477 $ 48 79 $ (1,823) $ 1,782 $ 1 $ 2,143 $ 2,151
Net income - - - - - - 201 201
Stock amortization and vesting 1 - - - 22 - - 22
Cash dividends at $0.40 per share
- - - - - - (159) (159)
Other comprehensive income - - - - - 1 - 1
Balance at December 31, 2020 478 $ 48 79 $ (1,823) $ 1,804 $ 2 $ 2,185 $ 2,216
Net income - - - - - - 1,158 1,158
Issuance of common stock for merger 408 41 - - 9,042 - - 9,083
Issuance of replacement awards and options for merger consideration 4 - - - 37 - - 37
Exercise of stock options - - - - 2 - - 2
Stock amortization and vesting 3 - - (3) 26 - - 23
Cash dividends
Common stock at $1.12 per share
- - - - - - (779) (779)
Preferred stock at $20.3125 per share
- - - - - - (1) (1)
Other comprehensive income - - - - - (1) - (1)
Balance at December 31, 2021 893 $ 89 79 $ (1,826) $ 10,911 $ 1 $ 2,563 $ 11,738
The accompanying notes are an integral part of these consolidated financial statements.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
1. Summary of Significant Accounting Policies
Basis of Presentation and Nature of Operations
Coterra Energy Inc. and its subsidiaries (“Coterra” or the “Company”) are engaged in the development, exploration and production of oil, natural gas and NGLs exclusively within the continental U.S. The Company's exploration and development activities are concentrated in areas with known hydrocarbon resources, which are conducive to multi-well, repeatable drilling programs.
The Company operates in one segment, oil and natural gas development, exploration and production. The Company's oil and gas properties are managed as a whole rather than through discrete operating segments. Operational information is tracked by geographic area; however, financial performance is assessed as a single enterprise and not on a geographic basis. Allocation of resources is made on a project basis across the Company's entire portfolio without regard to geographic areas.
The consolidated financial statements include the accounts of the Company and its subsidiaries after eliminating all significant intercompany balances and transactions. Certain reclassifications have been made to prior year statements to conform with the current year presentation. These reclassifications have no impact on previously reported stockholders' equity, net income or cash flows.
The Company (formerly known as Cabot Oil & Gas Corporation) and Cimarex Energy Co. (“Cimarex”) completed a merger transaction on October 1, 2021 (the “Merger”), pursuant to an agreement entered into by the Company and Cimarex (the “Merger Agreement”). Upon the effectiveness of the Merger, each eligible share of Cimarex common stock was automatically converted into the right to receive 4.0146 shares of the Company’s common stock. The transaction has been accounted for using the acquisition method of accounting, with the Company being treated as the accounting acquirer. Refer to Note 2, “Acquisitions,” for further information. Additionally, on October 1, 2021, Cabot Oil & Gas Corporation changed its name to Coterra Energy Inc.
Recently Issued and Adopted Accounting Pronouncements
Convertible Instruments. In August 2020, the Financial Accounting Standards Board (the “FASB”) issued Accounting Standards Update (“ASU”) No. 2020-06, Debt-Debt with Conversion and Other Options (Subtopic 470-20) and Derivatives and Hedging-Contracts in Entity’s Own Equity (Subtopic 815-40): Accounting for Convertible Instruments and Contracts in an Entity’s Own Equity ("ASU 2020-06"), which simplifies the accounting for convertible instruments by removing the separation models for (1) convertible debt with a cash conversion feature and (2) convertible instruments with a beneficial conversion feature. As a result, a convertible debt instrument will be accounted for as a single liability measured at its amortized cost. ASU 2020-06 also requires the application of the if-converted method for calculating diluted earnings per share for all convertible instruments and the treasury stock method will no longer be available. For public companies, the guidance is effective for fiscal years beginning after December 15, 2021, and interim periods within those fiscal years. Early adoption is permitted in the first quarter of 2021. The Company elected to adopt the guidance in ASU 2020-06 as of October 1, 2021. The adoption of ASU 2020-06 did not have any effect on the Company’s financial positions, results of operations or cash flows; however, it modified certain disclosures, which were not material.
Significant Accounting Policies
Cash and Cash Equivalents
The Company considers all highly liquid short-term investments with a maturity of three months or less and deposits in money market funds that are readily convertible to cash to be cash equivalents. Cash and cash equivalents were primarily concentrated in four financial institutions at December 31, 2021. The Company periodically assesses the financial condition of its financial institutions and considers any possible credit risk to be minimal.
From time to time, the Company may be in the position of a book overdraft in which outstanding checks exceed cash and cash equivalents. The Company classifies book overdrafts in accounts payable in the Consolidated Balance Sheet, and classifies the change in accounts payable associated with book overdrafts as an operating activity in the Consolidated Statement of Cash Flows. There was no book overdraft within accounts payable as of December 31, 2021 and 2020.
Restricted Cash
Restricted cash includes cash that is legally or contractually restricted as to withdrawal or usage. As of December 31, 2021 and 2020, the restricted cash balance of $10 million and $12 million, respectively, includes cash deposited in escrow accounts that are restricted for use.
Allowance for Doubtful Accounts
The Company records an allowance for doubtful accounts based on the Company's estimate of future expected credit losses on outstanding receivables.
Inventories
Inventories are comprised of tubular goods and well equipment and are carried at average cost. Inventories are assessed periodically for obsolescence.
Properties and Equipment
Oil and Gas Properties
The Company uses the successful efforts method of accounting for oil and gas producing activities. Under this method, acquisition costs for proved and unproved properties are capitalized when incurred. Exploration costs, including geological and geophysical costs, the costs of carrying and retaining unproved properties and exploratory dry-hole drilling costs, are expensed. Development costs, including the costs to drill and equip development wells and successful exploratory drilling costs to locate proved reserves are capitalized.
Exploratory drilling costs are capitalized when incurred pending the determination of whether a well has found proved reserves. The determination is based on a process which relies on interpretations of available geologic, geophysical and engineering data. If a well is determined to be successful, the capitalized drilling costs will be reclassified as part of the cost of the well. If a well is determined to be unsuccessful, the capitalized drilling costs will be charged to exploration expense in the Consolidated Statement of Operations in the period the determination is made. If an exploratory well requires a major capital expenditure before production can begin, the cost of drilling the exploratory well will continue to be carried as an asset pending determination of whether reserves have been found only as long as: (1) the well has found a sufficient quantity of reserves to justify its completion as a producing well if the required capital expenditure is made and (2) drilling of an additional exploratory well is under way or firmly planned for the near future. If drilling in the area is not under way or firmly planned or if the well has not found a commercially producible quantity of reserves, the exploratory well is assumed to be impaired and its costs are charged to exploration expense.
Development costs of proved oil and gas properties, including estimated dismantlement, restoration and abandonment costs and acquisition costs, are depreciated and depleted on a field basis by the units-of-production method using proved developed and proved reserves, respectively.
Costs of sold or abandoned properties that make up a part of an amortization base (partial field) remain in the amortization base if the units-of-production rate is not significantly affected. If significant, a gain or loss, if any, is recognized and the sold or abandoned properties are retired. A gain or loss, if any, is also recognized when a group of proved properties (entire field) that make up the amortization base has been retired, abandoned or sold.
The Company evaluates its proved oil and gas properties for impairment whenever events or changes in circumstances indicate an asset's carrying amount may not be recoverable. The Company compares expected undiscounted future cash flows to the net book value of the asset. If the future undiscounted expected cash flows, based on estimates of future commodity prices, operating costs and anticipated production from proved reserves and risk-adjusted probable and possible reserves, are lower than the net book value of the asset, the capitalized cost is reduced to fair value. Commodity pricing is estimated by using a combination of assumptions management uses in its budgeting and forecasting process as well as historical and current prices adjusted for geographical location and quality differentials, as well as other factors that management believes will impact realizable prices. Fair value is calculated by discounting the future cash flows. The discount factor used is based on rates utilized by market participants that are commensurate with the risks inherent in the development and production of the underlying natural gas and oil.
Unproved oil and gas properties are assessed periodically for impairment on an aggregate basis through periodic updates to the Company's undeveloped acreage amortization based on past drilling and exploration experience, the Company's expectation of converting leases to held by production and average property lives. Average property lives are determined on a geographical basis and based on the estimated life of unproved property leasehold rights.
Fixed Assets
Fixed assets consist primarily of gas gathering systems, water infrastructure, buildings, vehicles, aircraft, furniture and fixtures, and computer equipment and software. These items are recorded at cost and are depreciated on the straight-line method based on expected lives of the individual assets, which range from three to 30 years.
Asset Retirement Obligations
The Company records the fair value of a liability for an asset retirement obligation in the period in which it is incurred if a reasonable estimate of fair value can be made. The associated asset retirement cost is capitalized as part of the carrying amount of the long-lived asset. Asset retirement costs for oil and gas properties are depreciated using the units-of-production method, while asset retirement costs for other assets are depreciated using the straight-line method over estimated useful lives.
Additional retirement obligations increase the liability associated with new oil and gas wells and other facilities as these obligations are incurred. Accretion expense is included in depreciation, depletion and amortization expense in the Consolidated Statement of Operations.
Derivative Instruments
The Company enters into financial derivative contracts, primarily collars, swaps, roll differential swaps and basis swaps, to manage its exposure to price fluctuations on a portion of its anticipated future production volumes. The Company’s credit agreement restricts the ability of the Company to enter into financial commodity derivatives other than to hedge or mitigate risks to which the Company has actual or projected exposure or as permitted under the Company’s risk management policies and where such derivatives do not subject the Company to material speculative risks. All of the Company’s derivatives are used for risk management purposes and are not held for trading purposes. The Company has elected not to designate its financial derivative instruments as accounting hedges under the accounting guidance.
The Company evaluates all of its physical purchase and sale contracts to determine if they meet the definition of a derivative. For contracts that meet the definition of a derivative, the Company may elect the normal purchase normal sale (“NPNS”) exception provided under the applicable accounting guidance and account for the contract using the accrual method of accounting. Contracts that do not qualify for or for which the Company elects not to apply the NPNS exception are accounted for at fair value.
All derivatives, except for derivatives that qualify for the NPNS exception, are recognized on the balance sheet and are measured at fair value. At the end of each quarterly period, these derivatives are marked to market. As a result, changes in the fair value of derivatives are recognized in operating revenues in gain (loss) on derivative instruments. The resulting cash flows are reported as cash flows from operating activities.
Leases
The Company determines if an arrangement is, or contains, a lease at inception based on whether that contract conveys the right to control the use of an identified asset in exchange for consideration for a period of time. Operating leases are included in operating lease right-of-use assets (“ROU assets”) and operating and financing lease liabilities (current and non-current) in the Consolidated Balance Sheet.
ROU assets represent the Company’s right to use an underlying asset for the lease term and lease liabilities represent the Company’s obligation to make lease payments arising from the leases. ROU assets and lease liabilities are recognized at the lease commencement date based on the present value of minimum lease payments over the lease term. Most leases do not provide an implicit interest rate; therefore, the Company uses its incremental borrowing rate based on the information available at the inception date to determine the present value of the lease payments. Lease terms include options to extend the lease when it is reasonably certain that the Company will exercise that option. Lease cost for lease payments is recognized on a straight-line basis over the lease term. Certain leases have payment terms that vary based on the usage of the underlying assets. Variable lease payments are not included in ROU assets and lease liabilities.
The Company has elected the following practical expedients in applying authoritative guidance on lease accounting:
•For all operating leases, lease and non-lease components are accounted for as a single lease component.
•Short-term leases (a lease that, at commencement, has a lease term of one year or less and does not contain a purchase option that the Company is reasonably certain to exercise) are not recognized in ROU assets and lease liabilities.
•Certain land easements in existence prior to January 1, 2019 were not reassessed under new accounting guidance.
Fair Value of Assets and Liabilities
The Company follows the authoritative accounting guidance for measuring fair value of assets and liabilities in its financial statements. Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). The Company utilizes market data or assumptions that market participants who are independent, knowledgeable and willing and able to transact would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. The Company is able to classify fair value balances based on the observability of these inputs. The authoritative guidance for fair value measurements establishes three levels of the fair value hierarchy, defined as follows:
•Level 1: Unadjusted, quoted prices for identical assets or liabilities in active markets.
•Level 2: Quoted prices in markets that are not considered to be active or financial instruments for which all significant inputs are observable, either directly or indirectly for substantially the full term of the asset or liability.
•Level 3: Significant, unobservable inputs for use when little or no market data exists, requiring a significant degree of judgment.
The hierarchy gives the highest priority to Level 1 measurements and the lowest priority to Level 3 measurements. Depending on the particular asset or liability, input availability can vary depending on factors such as product type, longevity of a product in the market and other particular transaction conditions. In some cases, certain inputs used to measure fair value may be categorized into different levels of the fair value hierarchy. For disclosure purposes under the accounting guidance, the lowest level that contains significant inputs used in the valuation should be chosen.
Revenue Recognition
The Company’s revenue is typically generated from contracts to sell oil, natural gas and NGLs produced from interests in oil and gas properties owned by the Company. These contracts generally require the Company to deliver a specific amount of a commodity per day for a specified number of days at a price that is either fixed or variable. The contracts specify a delivery point which represents the point at which control of the product is transferred to the customer. These contracts frequently meet the definition of a derivative under Accounting Standards Codification (“ASC”) 815, and are accounted for as derivatives unless the Company elects to treat them as normal sales as permitted under that guidance. The Company typically elects to treat contracts to sell oil, natural gas and NGL production as normal sales, which are then accounted for as contracts with customers. The Company has determined that these contracts represent multiple performance obligations which are satisfied when control of the commodity transfers to the customer, typically through the delivery of the specified commodity to a designated delivery point.
Revenue is measured based on consideration specified in the contract with the customer, and excludes any amounts collected on behalf of third parties. The Company recognizes revenue in the amount that reflects the consideration it expects to be entitled to in exchange for transferring control of those goods to the customer. The contract consideration in the Company’s variable price contracts are typically allocated to specific performance obligations in the contract according to the price stated in the contract. Amounts allocated in the Company’s fixed price contracts are based on the standalone selling price of those products in the context of long-term, fixed price contracts, which generally approximates the contract price. Payment is generally received one or two months after the sale has occurred.
Gain or loss on derivative instruments is outside the scope of the revenue recognition standard and is not considered revenue from contracts with customers under that guidance. The Company may use financial or physical contracts accounted for as derivatives as economic hedges to manage price risk associated with normal sales, or in limited cases may use them for contracts the Company intends to physically settle but do not meet all of the criteria to be treated as normal sales.
Taxes assessed by a governmental authority that are both imposed on and concurrent with a specific revenue-producing transaction, and that are collected by the Company from a customer, are excluded from revenue.
Producer Gas Imbalances. The Company applies the sales method of accounting for natural gas revenue. Under this method, revenues are recognized based on the actual volume of natural gas sold to purchasers. Natural gas production operations may include joint owners who take more or less than the production volumes entitled to them on certain properties. Production volume is monitored to minimize these natural gas imbalances. Under this method, a natural gas imbalance liability is recorded if the Company's excess takes of natural gas exceed its estimated remaining proved developed reserves for these properties at the actual price realized upon the gas sale. A receivable is recognized only to the extent an imbalance cannot be recouped from the reserves in the underlying properties. The Company’s aggregate imbalance positions at December 31, 2021 and 2020 were not material.
Practical Expedients. The Company makes use of certain practical expedients provided under the revenue standard, including the value of unsatisfied performance obligations are not disclosed for (1) contracts with an original expected length of one year or less, (2) contracts for which the Company recognizes revenue at the amount to which the Company has the right to invoice, (3) contracts with variable consideration which is allocated entirely to a wholly unsatisfied performance obligation and meets the variable allocation criteria in the standard and (4) contracts that were not completed at transition.
The Company has not adjusted the promised amount of consideration for the effects of a significant financing component if the Company expects, at contract inception, that the period between when the Company transfers a promised good or service to the customer and when the customer pays for that good or service will be one year or less.
Income Taxes
The Company follows the asset and liability method of accounting for income taxes. Under this method, deferred tax assets and liabilities are recorded for the estimated future tax consequences attributable to the differences between the financial carrying amounts of existing assets and liabilities and their respective tax basis. Deferred tax assets and liabilities are measured using the tax rate in effect for the year in which those temporary differences are expected to reverse. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in the year of the enacted rate change. A valuation allowance is established to reduce deferred tax assets if it is more likely than not that the related tax benefits will not be realized.
The Company follows the “equity first” approach when applying the limitation for certain executive compensation in excess of $1 million to future compensation. The limitation is first applied to stock-based compensation that vests in future tax years before considering cash compensation paid in a future period. Accordingly, the Company records a deferred tax asset for stock-based compensation expense recorded in the current period, and reverses the temporary difference in the future period, during which the stock-based compensation becomes deductible for tax purposes.
The Company is required to make judgments, including estimating reserves for potential adverse outcomes regarding tax positions that the Company has taken. The Company accounts for uncertainty in income taxes using a recognition and measurement threshold for tax positions taken or expected to be taken in a tax return. The tax benefit from an uncertain tax position is recognized when it is more likely than not that the position will be sustained upon examination by taxing authorities based on technical merits of the position. The amount of the tax benefit recognized is the largest amount of the benefit that has a greater than 50 percent likelihood of being realized upon ultimate settlement. The effective tax rate and the tax basis of assets and liabilities reflect management's estimates of the ultimate outcome of various tax uncertainties.
The Company recognizes accrued interest related to uncertain tax positions in interest expense and accrued penalties related to such positions in general and administrative expense in the Consolidated Statement of Operations.
Stock-Based Compensation
The Company accounts for stock-based compensation under the fair value method of accounting. Under this method, compensation cost is measured at the grant date for equity-classified awards and remeasured each reporting period for liability-classified awards based on the fair value of an award and is recognized over the service period, which is generally the vesting period. To calculate fair value, the Company uses a Black Scholes or Monte Carlo valuation model based on the specific provisions of the award. Stock-based compensation cost for all types of awards is included in general and administrative expense in the Consolidated Statement of Operations.
The Company records excess tax benefits and tax deficiencies on stock-based compensation in the income statement upon vesting of the respective awards. Excess tax benefits and tax deficiencies are included in cash flows from operating activities in the Consolidated Statement of Cash Flow.
Cash paid by the Company when directly withholding shares from employee stock-based compensation awards for tax-withholding purposes are classified as financing activities in the Consolidated Statement of Cash Flow.
Earnings per Share
The Company calculates earnings per share recognizing that unvested share-based payment awards that contain non-forfeitable rights to dividends or dividend equivalents are “participating securities” and, therefore, should be included in computing earnings per share using the two-class earnings allocation method. The two-class method is an earnings allocation formula that determines earnings per share for each class of common stock and participating security according to dividends declared (or accumulated) and participation rights in undistributed earnings. Certain of the Company’s unvested share-based payment awards, consisting of restricted stock, qualify as participating securities. The Company’s participating securities do not have a contractual obligation to share in the losses of the entity and, therefore, net losses are not allocated to them.
Environmental Matters
Environmental expenditures are expensed or capitalized, as appropriate, depending on their future economic benefit. Expenditures that relate to an existing condition caused by past operations, and that do not have future economic benefit are expensed. Liabilities related to future costs are recorded on an undiscounted basis when environmental assessments and/or remediation activities are probable and the costs can be reasonably estimated. Any insurance recoveries are recorded as assets when received.
Credit and Concentration Risk
Substantially all of the Company's accounts receivable result from the sale of oil, natural gas and NGLs to third parties in the oil and gas industry and joint interest billings with other participants in joint operations. This concentration of purchasers and joint owners may impact the Company's overall credit risk, either positively or negatively, in that these entities may be similarly affected by changes in economic or other conditions. The Company does not anticipate any material impact on its financial results due to non-performance by the third parties.
During the year ended December 31, 2021, no customer accounted for more than 10 percent of the Company’s total sales. During the year ended December 31, 2020, three customers accounted for approximately 21 percent, 16 percent and 12 percent of the Company's total sales. During the year ended December 31, 2019, three customers accounted for approximately 17 percent, 16 percent and 16 percent of the Company's total sales. The Company does not believe that the loss of any of these customers would have a material adverse effect on it because alternative customers are readily available. If any one of the Company’s major customers were to stop purchasing the Company’s production, the Company believes there are a number of other purchasers to whom it could sell its production. If multiple significant customers were to stop purchasing the Company’s production, the Company believes there could be some initial challenges, but the Company believes it has ample alternative markets to handle any sales disruptions.
The Company regularly monitors the creditworthiness of its customers and may require parent company guarantees, letters of credit or prepayments when necessary. Historically, losses associated with uncollectible receivables have been insignificant.
Use of Estimates
In preparing financial statements, the Company follows GAAP. These principles require management to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. The most significant estimates pertain to proved oil and natural gas reserves and related cash flow estimates which are used to compute depreciation, depletion and amortization, impairments of proved oil and gas properties and the fair value of oil and gas properties in purchase accounting. Other estimates include oil, natural gas and NGLs revenues and expenses, fair value of derivative instruments, estimates of expenses related to legal, environmental and other contingencies, asset retirement obligations, postretirement obligations, stock-based compensation and deferred income taxes. Actual results could differ from those estimates.
2. Acquisitions
Cimarex Energy Co.
On October 1, 2021, Coterra and Cimarex completed the Merger. Cimarex is an oil and gas exploration and production company with operations in Texas, New Mexico and Oklahoma. Upon the effectiveness of the Merger, each eligible share of Cimarex common stock was converted into the right to receive 4.0146 shares of common stock of the Company. Based on the closing price of Coterra's common stock on October 1, 2021, the total value of such shares of Coterra common stock was approximately $9.1 billion. Coterra and Cimarex intended for the Merger to qualify as a tax-free reorganization for U.S. federal income tax purposes.
Also in accordance with the Merger Agreement with Cimarex and included as merger consideration, the Company issued 3.4 million shares of restricted stock to replace Cimarex restricted stock awards granted to certain employees. Because these restricted shares have non-forfeitable rights to dividends or dividend equivalents, the Company considers these shares as issued and outstanding shares of common stock.
Purchase Price Allocation
The transaction is being accounted for using the acquisition method of accounting, with the Company being treated as the accounting acquirer. Under the acquisition method of accounting, the assets, liabilities and mezzanine equity of Cimarex and its
subsidiaries will be recorded at their respective fair values as of the effective date of the Merger. The purchase price allocation is substantially complete; however, it may be subject to change for up to one year after October 1, 2021, the effective date of the Merger. Determining the fair value of the assets and liabilities of Cimarex requires judgment and certain assumptions to be made. The most significant fair value estimates related to the valuation of Cimarex's oil and gas properties and certain other fixed assets, long-term debt and derivative instruments. Oil and gas properties and certain fixed assets were valued using an income and market approach utilizing Level 3 inputs including internally generated production and development data and estimated price and cost estimates. Long-term debt was valued using a market approach utilizing Level 1 inputs including observable market prices on the underlying debt instruments. Derivative liabilities were based on Level 3 inputs consistent with the Company’s other commodity derivative instruments. Refer to Note 6, “Fair Value Measurements,” for additional information.
The following table represents the preliminary allocation of the total purchase price of Cimarex to the identifiable assets acquired and the liabilities assumed based on the fair values as of the effective date of the Merger.
(In millions, except share price and exchange ratio) Preliminary Purchase Price Allocation
Consideration:
Cimarex common stock issued as of October 1, 2021 103
Less unvested common stock (3)
Total Cimarex common stock to be converted 100
Exchange ratio 4.0146
Coterra common stock issued in exchange for Cimarex common stock 403
Coterra common stock issued for Cimarex share awards vested on October 1, 2021 5
Total shares of Coterra common stock issued 408
Coterra common stock closing price on October 1, 2021 $ 22.25
Total value of Coterra common stock issued $ 9,083
Total value of Coterra stock options issued 15
Total value of Coterra restricted stock awards issued 22
Total consideration $ 9,120
Assets acquired:
Cash and cash equivalents $ 1,033
Accounts receivable 598
Other current assets 31
Properties and equipment 13,300
Other assets 324
Total assets acquired $ 15,286
Liabilities and Mezzanine Equity assumed:
Accounts payable $ 528
Accrued liabilities 258
Derivative instruments, current 382
Other current liabilities 83
Long-term debt 2,196
Deferred income taxes 2,201
Asset retirement obligation 162
Derivative instruments, noncurrent 7
Other liabilities 299
Cimarex redeemable preferred stock 50
Total liabilities and mezzanine equity assumed $ 6,166
Net assets acquired $ 9,120
Post-Acquisition Operating Results
Cimarex contributed the following to the Company’s consolidated operating results.
(in millions) October 1, 2021 through December 31, 2021
Revenue $ 1,129
Net income 394
Unaudited Pro Forma Financial Information
The results of Cimarex’s operations have been included in the Company’s consolidated financial statements since October 1, 2021, the effective date of the Merger. The following supplemental pro forma information for the years ended December 31, 2021 and 2020 has been prepared to give effect to the Cimarex acquisition as if it had occurred on January 1, 2020. The information below reflects pro forma adjustments based on available information and certain assumptions that Coterra believes are factual and supportable. The pro forma results of operations do not include any cost savings or other synergies that may result from the acquisition or any estimated costs that have been or will be incurred by Coterra to integrate the Cimarex assets.
The pro forma information is not necessarily indicative of the results that might have occurred had the transaction actually taken place on January 1, 2020 and is not intended to be a projection of future results. Future results may vary significantly from the results reflected in the following pro forma information because of normal production declines, changes in commodity prices, future acquisitions and divestitures, future development and exploration activities and other factors.
Year Ended December 31,
(in millions, except per share information) 2021 2020
Pro forma revenue $ 5,236 $ 2,990
Pro forma net income 1,205 (2,189)
Pro forma basic earnings per share $ 1.49 $ (2.71)
Pro forma diluted earnings per share $ 1.48 $ (2.71)
Other Information
In connection with the Merger, the Company incurred certain merger-related restructuring and related transaction costs. The costs relate to workforce reductions and the associated employee severance benefits and the acceleration of employee benefits that were triggered by the Merger. For the year ended December 31, 2021, the Company recognized $44 million of restructuring expense related to the accrual of employee severance and termination benefits. Additionally, in conjunction with the Merger, the Company recognized $42 million of transaction costs for the year ended December 31, 2021. These fees primarily related to bank, legal and accounting fees and are included in general and administrative expenses in the Consolidated Statement of Operations.
3. Properties and Equipment, Net
Properties and equipment, net are comprised of the following:
December 31,
(In millions) 2021 2020
Proved oil and gas properties $ 15,340 $ 7,069
Unproved oil and gas properties 5,316 50
Pipelines and gathering
395 -
Land, buildings and other equipment 140 92
Finance lease right-of-use asset
20 -
21,211 7,211
Accumulated depreciation, depletion and amortization (3,836) (3,166)
$ 17,375 $ 4,045
Capitalized Exploratory Well Costs
As of and for the years ended December 31, 2021, 2020 and 2019, the Company did not have any projects with exploratory well costs capitalized for a period of greater than one year after drilling.
4. Debt and Credit Agreements
The Company's debt and credit agreements consisted of the following:
December 31,
(In millions) 2021 2020
Total debt
6.51% weighted-average private placement senior notes
$ 37 $ 37
5.58% weighted-average private placement senior notes (1)
87 175
3.65% weighted-average private placement senior notes (2)
825 925
4.375% senior notes due June 1, 2024
750 -
3.90% senior notes due May 15, 2027
750 -
4.375% senior notes due March 15, 2029
500 -
Revolving credit facility - -
Net premium (discount) 185 -
Unamortized debt issuance costs (9) (3)
$ 3,125 $ 1,134
_______________________________________________________________________________
(1)Includes $88 million of current portion of long-term debt at December 31, 2020, which the Company repaid in January 2021.
(2)Includes $100 million of current portion of long-term debt at December 31, 2020, which the Company repaid in September 2021.
The Company has debt maturities in the next five years as follows:
(in millions) 2022 2023 2024 2025 2026 Thereafter
Debt maturities $ - $ 62 $ 1,325 $ - $ 312 $ 1,250
At December 31, 2021, the Company was in compliance with all financial covenants for both its revolving credit facility and senior notes.
Private Placement Senior Notes
The Company has various issuances of senior notes that were issued in separate private placements (the “private placement senior notes”). Interest on each of such series of private placement senior notes is payable semi-annually. Under the terms of the various note purchase agreements, the Company may prepay all or any portion of the notes of each series on any date at a price equal to the principal amount thereof plus accrued and unpaid interest plus a make-whole premium.
The note purchase agreements provide that the Company must maintain a minimum annual coverage ratio of consolidated cash flow to interest expense for the trailing four quarters of 2.8 to 1.0 and require a maximum ratio of total debt to consolidated EBITDA for the trailing four quarters of not more than 3.0 to 1.0. There are also various other covenants and events of default customarily found in such debt instruments.
6.51% Weighted-Average Senior Notes
In July 2008, the Company issued $425 million of senior unsecured notes to a group of 41 institutional investors in a private placement. The notes have bullet maturities and were issued in three separate tranches as follows:
Principal (In millions) Term Maturity Date Coupon
Tranche 1 $ 245 10 years July 2018 6.44 %
Tranche 2 $ 100 12 years July 2020 6.54 %
Tranche 3 $ 80 15 years July 2023 6.69 %
In May 2016, the Company repurchased $8 million of Tranche 1, $13 million of Tranche 2 and $43 million of Tranche 3 for a total of $64 million for $68 million.
As of December 31, 2021, the Company has repaid $388 million of aggregate principal amount associated with the 6.51% weighted-average private placement senior notes.
5.58% Weighted-Average Senior Notes
In December 2010, the Company issued $175 million of senior unsecured notes to a group of eight institutional investors in a private placement. The notes have bullet maturities and were issued in three separate tranches as follows:
Principal (In millions) Term Maturity Date Coupon
Tranche 1 $ 88 10 years January 2021 5.42 %
Tranche 2 $ 25 12 years January 2023 5.59 %
Tranche 3 $ 62 15 years January 2026 5.80 %
As of December 31, 2021, the Company has repaid $88 million of aggregate principal amount associated with the 5.58% weighted-average private placement senior notes.
3.65% Weighted-Average Senior Notes
In September 2014, the Company issued $925 million of senior unsecured notes to a group of 24 institutional investors in a private placement. The notes have bullet maturities and were issued in three separate tranches as follows:
Principal (In millions) Term Maturity Date
Coupon
Tranche 1 $ 100 7 years September 2021 3.24 %
Tranche 2 $ 575 10 years September 2024 3.67 %
Tranche 3 $ 250 12 years September 2026 3.77 %
As of December 31, 2021, the Company has repaid $100 million of aggregate principal amount associated with the 3.65% weighted-average private placement senior notes.
Cimarex Senior Notes
The following table includes the summary of the Cimarex debt that was outstanding as of the consummation of the Merger on October 1, 2021 (the “Existing Cimarex Notes”):
(In millions) Face Value Fair Value
4.375% senior notes due June 1, 2024
$ 750 $ 809
3.90% senior notes due May 15, 2027
750 823
4.375% senior notes due March 15, 2029
500 564
$ 2,000 $ 2,196
Exchange Offers
On October 7, 2021 and after the completion of the Merger, the Company completed private offers to eligible holders to exchange (collectively, the “Exchange Offers”) $1.8 billion in aggregate principal of Existing Cimarex Notes for $1.8 billion in aggregate principal of new notes issued by Coterra (the “New Coterra Notes”) and $2 million of cash consideration. In connection with the Exchange Offers, Cimarex obtained consents to adopt certain amendments to each of the indentures governing the Existing Cimarex Notes to eliminate certain of the covenants, restrictive provisions and events of default from such indentures. The New Coterra Notes are general, unsecured, senior obligations of the Company and have substantially identical terms and covenants to the Existing Cimarex Notes (before giving effect to the amendments referred to in the immediately preceding sentence). The aggregate principal amount of Existing Cimarex Notes not exchanged, approximately $174 million, remained outstanding across the three series of Existing Cimarex Notes. The New Coterra Notes consist of $706 million aggregate principal amount of 4.375% Senior Notes due 2024, $687 million aggregate principal amount of 3.90% Senior Notes due 2027 and $433 million aggregate principal amount of 4.375% Senior Notes due 2029.
Revolving Credit Agreement
On April 22, 2019, the Company entered into a second amended and restated credit agreement (the “revolving credit agreement”). The revolving credit agreement is unsecured. The revolving credit agreement was subsequently amended on July 17, 2021 to address certain matters precedent to the Merger with Cimarex and on September 16, 2021 to among other things: (1) remove the provisions which limited borrowings thereunder to an amount not to exceed the borrowing base and certain related provisions; (2) replace the then-existing financial maintenance covenants with a covenant requiring maintenance of a leverage ratio not more than 3.0 to 1.0; (3) provide that if, in the future, the Company no longer has any other indebtedness subject to a leverage-based financial maintenance covenant, then the leverage covenant shall be replaced by a covenant requiring maintenance of a ratio of total debt to total capitalization not to exceed 65 percent at any time; and (4) provide for changes to certain exceptions to the negative covenants to reflect the completion of the Merger. This amendment became effective upon completion of the Merger and closing of the debt exchange described above. The Company's revolving credit facility matures in April 2024 and can be extended by one year upon the agreement of the Company and lenders holding at least 50 percent of the commitments under the revolving credit facility.
Interest rates under the revolving credit facility are based on LIBOR or ABR indications, plus a margin which ranges from 112.5 to 175 basis points for LIBOR loans and from 12.5 to 75 basis points for ABR loans. The revolving credit facility also provides for a commitment fee on the unused available balance and is calculated at annual rates ranging from 12.5 to 27.5 basis points.
From time to time, the Company uses the LIBOR benchmark rate for borrowings under its revolving credit facility. In July 2017, the U.K. Financial Conduct Authority (“FCA”) announced that it will no longer compel banks to submit rates that are currently used to calculate LIBOR after 2021. Subsequently in March 2021, the FCA announced some U.S. Dollar LIBOR tenors (overnight, 1 month, 3 month, 6 month and 12 month) will continue to be published until June 30, 2023. Regulators in the U.S. and other jurisdictions have been working to replace these rates with alternative reference interest rates that are supported by transactions in liquid and observable markets, such as the Secured Overnight Financing Rate (SOFR) for U.S. Dollar LIBOR. The Company’s revolving credit facility has a term that extends beyond June 30, 2023. The Company’s revolving credit facility also provides that in the event that the LIBOR benchmark rate is no longer available, the Company and its lenders will endeavor to establish an alternative interest rate based on the then prevailing market convention for purposes of LIBOR borrowings. The Company currently has no borrowings outstanding under its revolving credit facility and does not expect the transition to an alternative rate to have a material impact on its results of operations or cash flows.
At December 31, 2021, there were no borrowings outstanding under the Company's revolving credit facility and unused commitments were $1.5 billion.
5. Derivative Instruments
As of December 31, 2021, the Company had the following outstanding financial commodity derivatives:
Collars Swaps
Floor Ceiling Basis Swaps Roll Swaps
Type of Contract Volume (Mbbl) Contract Period Range ($/Bbl) Weighted- Average ($/Bbl) Range ($/Bbl) Weighted- Average ($/Bbl) Weighted- Average ($/Bbl) Weighted- Average ($/Bbl)
Crude oil (WTI) 630 Jan. 2022-Mar. 2022 $- $ 35.00 $45.15-$45.40
$ 45.28
Crude oil (WTI) 1,629 Jan. 2022-Jun. 2022 $35.00-$37.50
$ 36.11 $48.38-$51.10
$ 49.97
Crude oil (WTI) 2,730 Jan. 2022-Sep. 2022 $- $ 40.00 $47.55-$50.89
$ 49.19
Crude oil (WTI) 2,920 Jan. 2022-Dec. 2022 $- $ 57.00 $72.20-$72.80
$ 72.43
Crude oil (WTI Midland)(1)
630 Jan. 2022-Mar. 2022 $ 0.11
Crude oil (WTI Midland)(1)
1,448 Jan. 2022-Jun. 2022 $ 0.25
Crude oil (WTI Midland)(1)
1,911 Jan. 2022-Sep. 2022 $ 0.38
Crude oil (WTI Midland)(1)
2,920 Jan. 2022-Dec. 2022 $ 0.05
Crude oil (WTI) 630 Jan. 2022-Mar. 2022 $ (0.24)
Crude oil (WTI) 724 Jan. 2022-Jun. 2022 $ (0.20)
Crude oil (WTI) 1,911 Jan. 2022-Sep. 2022 $ 0.10
________________________________________________________
(1)The index price the Company pays under these basis swaps is WTI Midland, as quoted by Argus Americas Crude.
Collars
Floor Ceiling
Type of Contract Volume (Mmbtu) Contract Period Range
($/Mmbtu) Weighted-Average
($/Mmbtu) Range
($/Mmbtu) Weighted- Average
($/Mmbtu)
Natural gas (NYMEX) 36,000,000 Jan. 2022-Mar. 2022 $4.00 - $4.75
$ 4.38 $5.00 - $10.32
$ 6.97
Natural gas (NYMEX) 42,800,000 Apr. 2022 - Oct. 2022 $3.00 - $3.50
$ 3.19 $4.07 - $4.83
$ 4.30
Natural gas (Perm EP)(1)
1,800,000 Jan. 2022-Mar. 2022 $1.80 - $1.90
$ 1.85 $2.18 - $2.19
$ 2.18
Natural gas (Perm EP)(1)
3,620,000 Jan. 2022-Jun. 2022 $ - $ 2.40 $2.85 - $2.90
$ 2.88
Natural gas (Perm EP)(1)
7,300,000 Jan. 2022-Dec. 2022 $ - $ 2.50 $ - $ 3.15
Natural gas (PEPL)(2)
3,600,000 Jan. 2022-Mar. 2022 $1.90 - $2.10
$ 2.00 $2.35 - $2.44
$ 2.40
Natural gas (PEPL)(2)
3,620,000 Jan. 2022-Jun. 2022 $ - $ 2.40 $2.81 - $2.91
$ 2.86
Natural gas (PEPL)(2)
7,300,000 Jan. 2022-Dec. 2022 $ - $ 2.60 $ - $ 3.27
Natural gas (Waha)(3)
3,600,000 Jan. 2022-Mar. 2022 $1.70 - $1.84
$ 1.77 $2.10 - $2.20
$ 2.15
Natural gas (Waha)(3)
3,620,000 Jan. 2022-Jun. 2022 $ - $ 2.40 $2.82 - $2.89
$ 2.86
Natural gas (Waha)(3)
2,730,000 Jan. 2022-Sep. 2022 $ - $ 2.40 $ - $ 2.77
Natural gas (Waha)(3)
7,300,000 Jan. 2022-Dec. 2022 $ - $ 2.50 $ - $ 3.12
________________________________________________________
(1)The index price for these collars is El Paso Natural Gas Company, Permian Basin Index (“Perm EP”), as quoted in Platt’s Inside FERC.
(2)The index price for these collars is Panhandle Eastern Pipe Line, Tex/OK Mid-Continent Index (“PEPL”), as quoted in Platt’s Inside FERC.
(3)The index price for these collars is Waha West Texas Natural Gas Index (“Waha”), as quoted in Platt’s Inside FERC.
In early 2022, the Company entered into the following outstanding financial commodity derivatives:
Collars
Floor Ceiling
Type of Contract Volume (Mmbtu) Contract Period Range
($/Mmbtu) Weighted-
Average
($/Mmbtu) Range
($/Mmbtu) Weighted-
Average
($/Mmbtu)
Natural gas (NYMEX) 71,500,000 Apr. 2022-Dec. 2022 $3.50 - $4.25
$ 3.84 $4.75 - $6.65
$ 5.39
Natural gas (NYMEX) 10,700,000 Apr. 2022-Oct. 2022 $ - $ 4.00 $5.60 - $5.69
$ 5.63
Natural gas (NYMEX) 7,550,000 Nov. 2022-Mar. 2023 $ - $ 4.00 $7.06 - $7.10
$ 7.08
Effect of Derivative Instruments on the Consolidated Balance Sheet
Fair Values of Derivative Instruments
Derivative Assets Derivative Liabilities
December 31, December 31,
(In millions) Balance Sheet Location 2021 2020 2021 2020
Commodity contracts Derivative instruments (current) $ 7 $ 26 $ 159 $ -
Offsetting of Derivative Assets and Liabilities in the Consolidated Balance Sheet
December 31,
(In millions) 2021 2020
Derivative assets
Gross amounts of recognized assets $ 27 $ 26
Gross amounts offset in the consolidated balance sheet (20) -
Net amounts of assets presented in the consolidated balance sheet 7 26
Gross amounts of financial instruments not offset in the consolidated balance sheet - -
Net amount $ 7 $ 26
Derivative liabilities
Gross amounts of recognized liabilities $ 179 $ -
Gross amounts offset in the consolidated balance sheet (20) -
Net amounts of liabilities presented in the consolidated balance sheet 159 -
Gross amounts of financial instruments not offset in the consolidated balance sheet 35 -
Net amount $ 194 $ -
Effect of Derivative Instruments on the Consolidated Statement of Operations
Year Ended December 31,
(In millions) 2021 2020 2019
Cash (paid) received on settlement of derivative instruments
Gas contracts $ (307) $ 35 $ 139
Oil contracts (124) - -
Non-cash (loss) gain on derivative instruments
Gas contracts 99 26 (58)
Oil contracts 111 - -
$ (221) $ 61 $ 81
Additional Disclosures about Derivative Instruments
The use of derivative instruments involves the risk that the counterparties will be unable to meet their obligations under the agreements. The Company's counterparties are primarily commercial banks and financial service institutions that management believes present minimal credit risk and its derivative contracts are with multiple counterparties to minimize its exposure to any individual counterparty. The Company performs both quantitative and qualitative assessments of these counterparties based on their credit ratings and credit default swap rates where applicable.
Certain counterparties to the Company's derivative instruments are also lenders under its revolving credit facility. The Company's revolving credit facility and derivative instruments contain certain cross default and acceleration provisions that may require immediate payment of the Company’s liabilities thereunder if the Company defaults on other material indebtedness. The Company also has netting arrangements with each of its counterparties that allow it to offset assets and liabilities from separate derivative contracts with that counterparty.
6. Fair Value Measurements
Financial Assets and Liabilities
The following fair value hierarchy table presents information about the Company's financial assets and liabilities measured at fair value on a recurring basis:
(In millions) Quoted Prices in
Active Markets for
Identical Assets
(Level 1) Significant Other
Observable Inputs
(Level 2) Significant
Unobservable
Inputs
(Level 3) Balance at
December 31,
Assets
Deferred compensation plan $ 47 $ - $ - $ 47
Derivative instruments - - 27 27
Total assets $ 47 $ - $ 27 $ 74
Liabilities
Deferred compensation plan $ 56 $ - $ - $ 56
Derivative instruments - - 179 179
Total liabilities $ 56 $ - $ 179 $ 235
(In millions) Quoted Prices in
Active Markets for
Identical Assets
(Level 1) Significant Other
Observable Inputs
(Level 2) Significant
Unobservable
Inputs
(Level 3) Balance at
December 31,
Assets
Deferred compensation plan $ 22 $ - $ - $ 22
Derivative instruments - 2 24 26
Total assets $ 22 $ 2 $ 24 $ 48
Liabilities
Deferred compensation plan $ 31 $ - $ - $ 31
Derivative instruments - - - -
Total liabilities $ 31 $ - $ - $ 31
The Company's investments associated with its deferred compensation plan consist of mutual funds and deferred shares of the Company's common stock that are publicly traded and for which market prices are readily available.
The derivative instruments were measured based on quotes from the Company's counterparties or internal models. Such quotes and models have been derived using an income approach that considers various inputs, including current market and contractual prices for the underlying instruments, quoted forward commodity prices, basis differentials, volatility factors and interest rates for a similar length of time as the derivative contract term as applicable. Estimates are derived from or verified using relevant NYMEX futures contracts and/or are compared to multiple quotes obtained from counterparties for reasonableness. The determination of the fair values presented above also incorporates a credit adjustment for non-performance risk. The Company measured the non-performance risk of its counterparties by reviewing credit default swap spreads for the
various financial institutions with which it has derivative contracts while non-performance risk of the Company is evaluated using a market credit spread provided by several of the Company's banks. The Company has not incurred any losses related to non-performance risk of its counterparties and does not anticipate any material impact on its financial results due to non-performance by third parties.
The most significant unobservable inputs relative to the Company's Level 3 derivative contracts are basis differentials and volatility factors. An increase (decrease) in these unobservable inputs would result in an increase (decrease) in fair value, respectively. The Company does not have access to the specific assumptions used in its counterparties' valuation models. Consequently, additional disclosures regarding significant Level 3 unobservable inputs were not provided.
The following table sets forth a reconciliation of changes in the fair value of financial assets and liabilities classified as Level 3 in the fair value hierarchy:
Year Ended December 31,
(In millions) 2021 2020 2019
Balance at beginning of period $ 24 $ - $ 22
Total gain (loss) included in earnings (532) 41 25
Settlement (gain) loss 356 (17) (47)
Transfers in and/or out of Level 3 - - -
Balance at end of period $ (152) $ 24 $ -
Change in unrealized gains (losses) relating to assets and liabilities still held at the end of the period $ (154) $ 24 $ -
Non-Financial Assets and Liabilities
The Company discloses or recognizes its non-financial assets and liabilities, such as impairments of oil and gas properties or acquisitions, at fair value on a nonrecurring basis. On October 1, 2021, the Company and Cimarex completed the Merger. In connection with the Merger, the assets acquired and liabilities assumed were recorded at fair value. The most significant fair value determinations for non-financial assets and liabilities related to oil and gas properties acquired. Refer to Note 2, “Acquisitions,” for additional information. As none of the Company's other non-financial assets and liabilities were measured at fair value as of December 31, 2021, 2020 and 2019, additional disclosures were not required.
The estimated fair value of the Company's asset retirement obligations at inception is determined by utilizing the income approach by applying a credit-adjusted risk-free rate, which takes into account the Company's credit risk, the time value of money, and the current economic state to the undiscounted expected abandonment cash flows. Given the unobservable nature of the inputs, the measurement of the asset retirement obligations was classified as Level 3 in the fair value hierarchy.
Fair Value of Other Financial Instruments
The estimated fair value of other financial instruments is the amount at which the instrument could be exchanged currently between willing parties. The carrying amounts reported in the Consolidated Balance Sheet for cash and cash equivalents and restricted cash approximate fair value due to the short-term maturities of these instruments. Cash and cash equivalents and restricted cash are classified as Level 1 in the fair value hierarchy and the remaining financial instruments are classified as Level 2.
The fair value of the New Coterra Notes and Existing Cimarex Notes is based on quoted market prices, which is classified as Level 1 in the fair value hierarchy. We use available market data and valuation methodologies to estimate the fair value of our private placement senior notes. The fair value of the private placement senior notes is the estimated amount we would have to pay a third party to assume the debt, including a credit spread for the difference between the issue rate and the period end market rate. The credit spread is our default or repayment risk. The credit spread (premium or discount) is determined by comparing our senior notes and revolving credit facility to new issuances (secured and unsecured) and secondary trades of similar size and credit statistics for both public and private debt. The fair value of the private placement senior notes is based on interest rates currently available to us. The Company’s private placement senior notes are valued using an income approach and are classified as Level 3 in the fair value hierarchy.
The carrying amount and fair value of debt is as follows:
December 31, 2021 December 31, 2020
(In millions) Carrying
Amount Estimated
Fair Value Carrying
Amount Estimated
Fair Value
Long-term debt $ 3,125 $ 3,163 $ 1,134 $ 1,214
Current maturities - - (188) (189)
Long-term debt, excluding current maturities $ 3,125 $ 3,163 $ 946 $ 1,025
7. Asset Retirement Obligations
Activity related to the Company's asset retirement obligations is as follows:
Year Ended December 31,
(In millions) 2021 2020
Balance at beginning of period $ 86 $ 72
Liabilities assumed in Merger 175 -
Liabilities incurred 6 10
Liabilities settled (10) -
Accretion expense 6 4
Balance at end of period 263 86
Less: current asset retirement obligation (4) (1)
Noncurrent asset retirement obligation $ 259 $ 85
8. Commitments and Contingencies
Transportation, Processing and Gathering Agreements
Transportation, Processing and Gathering Commitments
The Company has entered into certain transportation and gathering agreements with various pipeline carriers. Under certain of these agreements, the Company is obligated to ship minimum daily quantities, or pay for any deficiencies at a specified rate. The Company's forecasted production to be shipped on these pipelines is expected to exceed minimum daily quantities provided in the agreements. The Company is also obligated under certain of these arrangements to pay a demand charge for firm capacity rights on pipeline systems regardless of the amount of pipeline capacity utilized by the Company. If the Company does not utilize the capacity, it can release it to others, thus reducing its potential liability.
As of December 31, 2021, the Company's future minimum obligations under transportation and gathering agreements are as follows:
(In millions)
2022 $ 101
2023 138
2024 156
2025 159
2026 143
Thereafter 1,047
$ 1,744
Other Gathering and Processing Volume Commitments
The Company has entered into certain gas processing agreements. Under certain of these agreements, the Company is obligated to process minimum daily quantities, or pay for any deficiencies at a specified rate. The Company's forecasted production to be processed under most of these agreements is expected to exceed minimum daily quantities provided in the agreements.
As of December 31, 2021, the Company's future minimum obligations under gas processing agreements are as follows:
(In millions)
2022 $ 88
2023 93
2024 96
2025 95
2026 84
Thereafter 231
$ 687
As of December 31, 2021, the Company had accrued $9 million in other non-current liabilities associated with these commitments, representing the present value of estimated amounts payable due to insufficient forecasted delivery volumes.
The Company also has minimum volume delivery commitments associated with agreements to reimburse connection costs to various pipelines. Under certain of these agreements, the Company is obligated to deliver minimum daily quantities, or pay for any deficiencies at a specified rate. The Company's forecasted production to be delivered under most of these agreements is expected to exceed minimum daily quantities provided in the agreements.
As of December 31, 2021, the Company's future minimum obligations under these delivery commitments are as follows:
(In millions)
2022 $ 3
2023 13
2024 12
2025 7
2026 14
Thereafter 15
$ 64
As of December 31, 2021, the Company had accrued $10 million in other non-current liabilities associated with these commitments, representing the present value of estimated amounts payable due to insufficient forecasted delivery volumes.
Water Delivery Commitments
The Company has minimum volume water delivery commitments associated with a water services agreement that expires in 2030. The Company is obligated to deliver minimum daily quantities, or pay for any deficiencies at a specified rate.
As of December 31, 2021, the Company's future minimum obligations under this water delivery commitment are as follows:
(In millions)
2022 $ 7
2023 7
2024 7
2025 6
2026 6
Thereafter 25
$ 58
As of December 31, 2021, the Company had accrued $21 million in other non-current liabilities associated with this commitment, representing the present value of estimated amounts payable due to insufficient forecasted delivery volumes.
Lease Commitments
The Company has operating leases for office space, surface use agreements, compressor services and other leases. The leases have remaining terms ranging from one month to 24 years, including options to extend leases that the Company is
reasonably certain to exercise. During the year ended December 31, 2021, the Company recognized operating lease cost and variable lease cost of $23 million and $6 million, respectively. During the year ended December 31, 2020, the Company recognized operating lease cost and variable lease cost of $5 million and $1 million, respectively.
Short-term leases. The Company leases drilling rigs, fracturing and other equipment under lease terms ranging from 30 days to one year. Lease cost of $113 million and $26 million was recognized on short-term leases during the year ended December 31, 2021 and 2020, respectively. Certain lease costs are capitalized and included in Properties and equipment, net in the Consolidated Balance Sheet because they relate to drilling and completion activities, while other costs are expensed because they relate to production and administrative activities.
As of December 31, 2021, the Company’s future undiscounted minimum cash payment obligations for its operating lease liabilities are as follows:
(In millions) Year Ending December 31,
2022 $ 75
2023 75
2024 72
2025 58
2026 14
Thereafter 50
Total undiscounted future lease payments 344
Present value adjustment (27)
Net operating lease liabilities $ 317
As of December 31, 2021, the Company’s future undiscounted minimum cash payment obligations for its financing lease liabilities are as follows:
(In millions) Year Ending December 31,
2022 $ 6
2023 6
2024 6
2025 4
2026 -
Thereafter -
Total undiscounted future lease payments 22
Present value adjustment (1)
Net financing lease liabilities $ 21
Supplemental cash flow information related to leases was as follows:
Year Ended December 31,
(In millions) 2021 2020
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows from operating leases $ 23 $ 5
Financing cash flows from financing leases $ 2 $ -
Information regarding the weighted-average remaining lease term and the weighted-average discount rate for operating leases is summarized below:
December 31,
2021 2020
Weighted-average remaining lease term (in years)
Operating leases 5.7 11.1
Financing leases 3.7 -
Weighted-average discount rate
Operating leases 2.4 % 5.0 %
Financing leases 2.1 % - %
In May 2021, the Company entered in a lease for the use of an electric hydraulic fracturing fleet, pursuant to which the Company must use such hydraulic fracturing fleet and the personnel and other equipment required to use the fleet for a period of four years. The lessor is constructing the fleet and the lease will commence on the earlier of the commencement of field activity or June 30, 2022. Upon commencement of the lease, the Company expects to record a lease liability and right-of-use asset of between $150 million and $160 million.
Legal Matters
Pennsylvania Office of Attorney General Matter
In June 2020, the Office of Attorney General of the Commonwealth of Pennsylvania informed the Company that it will pursue certain misdemeanor and felony charges in a Susquehanna County Magisterial District Court against the Company related to alleged violations of the Pennsylvania Clean Streams Law, which prohibits discharge of industrial wastes. The Company is vigorously defending itself against such charges; however, the proceedings could result in fines or penalties against the Company. At this time, it is not possible to estimate the amount of any fines or penalties, or the range of such fines or penalties, that are reasonably possible in this case.
Securities Litigation
In October 2020, a class action lawsuit styled Delaware County Emp. Ret. Sys. v. Cabot Oil and Gas Corp., et. al. (U.S. District Court, Middle District of Pennsylvania), was filed against the Company, Dan O. Dinges, its then Chief Executive Officer, and Scott C. Schroeder, its Chief Financial Officer, alleging that the Company made misleading statements in its periodic filings with the SEC in violation of Section 10(b) and Section 20 of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). The plaintiffs allege misstatements in the Company’s public filings and disclosures over a number of years relating to its potential liability for alleged environmental violations in Pennsylvania. The plaintiffs allege that such misstatements caused a decline in the price of the Company’s common stock when it disclosed in its Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2019 two notices of violations from the Pennsylvania Department of Environmental Protection and an additional decline when it disclosed on June 15, 2020 the criminal charges brought by the Office of the Attorney General of the Commonwealth of Pennsylvania related to alleged violations of the Pennsylvania Clean Streams Law, which prohibits discharge of industrial wastes. The court appointed Delaware County Employees Retirement System to represent the purported class on February 3, 2021. In April 2021, the complaint was amended to include Phillip L. Stalnaker, the Company’s then Senior Vice President of Operations, as a defendant. The plaintiffs seek monetary damages, interest and attorney’s fees.
Also in October 2020, a stockholder derivative action styled Ezell v. Dinges, et. al. (U.S. District Court, Middle District of Pennsylvania), was filed against the Company, Messrs. Dinges and Schroeder and the Board of Directors of the Company serving at that time, for alleged securities violations under Section 10(b) and Section 21D of the Exchange Act arising from the same alleged misleading statements that form the basis of the class action lawsuit described above. In addition to the Exchange Act claims, the derivative actions also allege claims based on breaches of fiduciary duty and statutory contribution theories. On December 9, 2020, the Ezell case was consolidated with a second derivative case with similar allegations. In January 2021, a third derivative case was filed with substantially similar allegations and it too was consolidated with the Ezell case in February 2021.
On February 25, 2021, the Company filed a motion to transfer the class action lawsuit to the U.S. District Court for the Southern District of Texas, in Houston, Texas, where its headquarters are located. On June 11, 2021, the Company filed a motion to dismiss the class action lawsuit on the basis that the plaintiffs’ allegations do not meet the requirements for pleading a claim under Section 10(b) or Section 20 of the Exchange Act. On June 22, 2021, the motion to transfer the class action lawsuit
to the Southern District of Texas was granted. Pursuant to the prior agreement of the parties, the consolidated derivative case discussed in the preceding paragraph was also transferred to the Southern District of Texas on July 12, 2021. Subsequently, an additional stockholder derivative action styled Treppel Family Trust U/A 08/18/18 Lawrence A. Treppel and Geri D. Treppel for the benefit of Geri D. Treppel and Larry A. Treppel v. Dinges, et al. (U.S. District Court, Southern District of Texas, Houston Division), asserting substantially similar Delaware common law claims as in the existing derivative cases, was filed in the Southern District of Texas and consolidated with the existing consolidated derivative cases. On January 12, 2022, the U.S. District Court for the Southern District of Texas granted the Company’s motion to dismiss the class action lawsuit but has allowed the plaintiffs to file an amended complaint. The class action plaintiffs filed their amended complaint on February 11, 2022. The Company anticipates filing a motion to dismiss the amended complaint. The motion to dismiss the derivative actions remain pending. The Company intends to vigorously defend the class action and derivative lawsuits.
In November 2020, the Company received a stockholder demand for inspection of books and records under Section 220 of the General Corporation Law of the State of Delaware (“Section 220 Demand”). The Section 220 Demand seeks broad categories of documents reviewed by the Board of Directors and minutes of meetings of the Board of Directors pertaining to alleged environmental violations in Pennsylvania, as well as documents relating to any Board of Directors conflicts of interest, dating back to January 1, 2015. The Company also received three other similar requests from other stockholders in February and June 2021. On May 17, 2021, the Company was served with a complaint filed in the Court of Chancery of the State of Delaware by the stockholder making the February 2021 Section 220 Demand to compel the production of books and records requested. After making an agreed books and records production, the Section 220 complaint was voluntarily dismissed effective September 21, 2021. The Company also provided substantially the same books and records production in response to the other three Section 220 requests described above. It is possible that one or more additional stockholder suits could be filed pertaining to the subject matter of the Section 220 Demands and the class and derivative actions described above.
Other
The Company is a defendant in various other legal proceedings arising in the normal course of business. All known liabilities are accrued when management determines they are probable based on its best estimate of the potential loss. While the outcome and impact of these legal proceedings on the Company cannot be predicted with certainty, management believes that the resolution of these proceedings will not have a material effect on the Company's financial position, results of operations or cash flows.
Contingency Reserves
When deemed necessary, the Company establishes reserves for certain legal proceedings. The establishment of a reserve is based on an estimation process that includes the advice of legal counsel and subjective judgment of management. While management believes these reserves to be adequate, it is reasonably possible that the Company could incur additional losses with respect to those matters for which reserves have been established. The Company believes that any such amount above the amounts accrued would not be material to the Consolidated Financial Statements. Future changes in facts and circumstances not currently foreseeable could result in the actual liability exceeding the estimated ranges of loss and amounts accrued.
9. Revenue Recognition
Disaggregation of Revenue
The following table presents revenues from contracts with customers disaggregated by product:
Year Ended December 31,
(In millions) 2021 2020 2019
OPERATING REVENUES
Natural gas $ 2,798 $ 1,405 $ 1,985
Oil 616 - -
NGL 243 - -
Other 13 - -
Total revenues from contracts with customers $ 3,670 $ 1,405 $ 1,985
All of the Company’s revenues from contracts with customers represent products transferred at a point in time as control is transferred to the customer and generated in the U.S.
Transaction Price Allocated to Remaining Performance Obligations
A significant number of the Company’s product sales contracts are short-term in nature with a contract term of one year or less. For those contracts, the Company has utilized the practical expedient exempting the Company from disclosure of the transaction price allocated to remaining performance obligations if the performance obligation is part of a contract that has an original expected duration of one year or less.
As of December 31, 2021, the Company has $7.7 billion of unsatisfied performance obligations related to natural gas sales that have a fixed pricing component and a contract term greater than one year. The Company expects to recognize these obligations over periods ranging from two to 17 years.
Contract Balances
Receivables from contracts with customers are recorded when the right to consideration becomes unconditional, generally when control of the product has been transferred to the customer. Receivables from contracts with customers were $922 million and $216 million as of December 31, 2021 and 2020, respectively, and are reported in accounts receivable, net in the Consolidated Balance Sheet. As of December 31, 2021 and 2020, the Company had no assets or liabilities related to its revenue contracts, including no upfront payments or rights to deficiency payments.
10. Income Taxes
Income tax expense is summarized as follows:
Year Ended December 31,
(In millions) 2021 2020 2019
Current
Federal $ 207 $ (32) $ (29)
State 11 1 4
218 (31) (25)
Deferred
Federal 119 68 233
State 7 4 11
126 72 244
Income tax expense $ 344 $ 41 $ 219
Income tax expense was different than the amounts computed by applying the statutory federal income tax rate as follows:
Year Ended December 31,
2021 2020 2019
(In millions, except rates) Amount Rate Amount Rate Amount Rate
Computed “expected” federal income tax $ 315 21.00 % $ 51 21.00 % $ 189 21.00 %
State income tax, net of federal income tax benefit 24 1.59 % 5 1.86 % 15 1.64 %
Deferred tax adjustment related to change in overall state tax rate (7) (0.46) % 1 0.50 % (1) (0.07) %
Valuation allowance 3 0.22 % (4) (1.58) % 18 1.96 %
Excess executive compensation 15 1.03 % 5 2.18 % 2 0.21 %
Reserve on uncertain tax positions 1 0.05 % 6 2.47 % - - %
Tax credits generated (6) (0.39) % (23) (9.63) % - - %
Other, net (1) (0.14) % - 0.04 % (4) (0.40) %
Income tax expense $ 344 22.90 % $ 41 16.84 % $ 219 24.34 %
In 2021, the Company's overall effective tax rate increased compared to 2020, primarily due to lower research and development tax credit benefits recorded in 2021 compared to 2020. The overall effective tax rate decreased in 2020 compared to 2019, primarily due to research and development tax credit benefits recorded in 2020 related to amended prior-year returns.
The composition of net deferred tax liabilities is as follows:
December 31,
(In millions) 2021 2020
Deferred Tax Assets
Net operating losses $ 388 $ 22
Incentive compensation 23 16
Deferred compensation 22 6
Post-retirement benefits 8 7
Capital loss carryforward 30 17
Other credit carryforwards 10 -
Leases 11 8
Derivative instruments 35 -
Other 18 3
Less: valuation allowance (177) (28)
Total 368 51
Deferred Tax Liabilities
Properties and equipment 3,459 810
Equity method investments 1 1
Leases 9 8
Derivative instruments - 6
Total 3,469 825
Net deferred tax liabilities $ 3,101 $ 774
On October 1, 2021, Coterra and Cimarex completed the Merger. For U.S. federal income tax purposes, Coterra and Cimarex intended for the Merger to qualify as a tax-free reorganization, whereby Coterra acquired the common stock of Cimarex and Cimarex retained a carryover tax basis in Cimarex’s assets and liabilities. As of December 31, 2021, the Company recorded a net deferred tax liability of $2.2 billion to reflect the difference between the fair value of Cimarex’s assets and liabilities recorded in the acquisition and the income tax basis of the assets and liabilities assumed. See Note 2 “Acquisitions” for more information regarding the preliminary purchase price allocation. The deferred tax liability includes certain deferred tax assets net of valuation allowances.
Because the Merger resulted in an “ownership change” with respect to Cimarex, the Company’s ability to utilize Cimarex’s federal tax attributes will be limited pursuant to Section 382 of the Internal Revenue Code. In particular, the Company’s ability to use the Cimarex net operating losses (“NOLs”) and credits is limited to an annual amount (determined by multiplying (1) the fair market value of Cimarex’s stock at the effective time of the Merger by (2) the long-term tax exempt rate published by the Internal Revenue Service for the month in which the Merger occurred) plus any built-in gains recognized within five years after the ownership change (but only to the extent of the net unrealized built-in gain that existed at the time of the ownership change). The annual limitation amount is $130 million and the net unrealized built-in gain is projected to be $2.8 billion. The Cimarex federal NOLs were approximately $1.3 billion at the date of the Merger and do not begin to expire until 2034. Even with the Section 382 limitation, the Company expects to be able to fully utilize the Cimarex NOLs prior to their expiration. Accordingly, no additional valuation allowance has been recorded on these acquired tax attributes.
At December 31, 2021, the Company had federal NOL carryforwards of approximately $1.1 billion, $875 million of which is subject to expiration in years 2034 through 2037, and $224 million of which is not subject to expiration. The Company believes that the carryforward, net of valuation allowance, will be utilized before it expires. The Company had gross state NOL carryforwards of $3.0 billion at December 31, 2021, primarily expiring between 2022 and 2041, with all but $69 million covered by a valuation allowance. The Company had capital loss carryforwards of $135 million, which can only be used to offset future capital gains, of which $64 million expires in 2022 and $71 million expires in 2025. The Company also had enhanced oil recovery and marginal well credits of $10 million at December 31, 2021.
As of December 31, 2021, the Company had $136 million of valuation allowances on the deferred tax benefits related to state NOLs, $29 million of valuation allowances on the deferred tax benefits related to the capital loss carryforwards, and $4 million of valuation allowances on the deferred tax benefits related to enhanced oil recovery credits. The Company believes it is more likely than not that the remainder of its deferred tax benefits will be utilized prior to their expiration.
Unrecognized Tax Benefits
A reconciliation of unrecognized tax benefits is as follows:
Year Ended December 31,
(In millions) 2021 2020 2019
Balance at beginning of period $ 6 $ 1 $ 17
Additions for tax positions of current period 1 - -
Additions for tax positions of prior periods
- 5 -
Reductions for tax positions of prior periods
- - (16)
Balance at end of period $ 7 $ 6 $ 1
During 2021, the Company recorded a $1 million reserve for unrecognized tax benefits related to estimated current year research and development tax credits. As of December 31, 2021, the Company's overall net reserve for unrecognized tax positions was $7 million, with a $1 million liability for accrued interest on the uncertain tax positions. If recognized, the net tax benefit of $7 million would not have a material effect on the Company's effective tax rate.
The Company files income tax returns in the U.S. federal, various states and other jurisdictions. The Company is no longer subject to examinations by state authorities before 2012 or by federal authorities before 2017. The Company believes that appropriate provisions have been made for all jurisdictions and all open years, and that any assessment on these filings will not have a material impact on the Company's financial position, results of operations or cash flows.
11. Employee Benefit Plans
Postretirement Benefits
The Company provides certain health care benefits for legacy retired employees of Cabot Oil & Gas Corporation, including their spouses, eligible dependents and surviving spouses (retirees). These benefits are commonly called postretirement benefits. The health care plans are contributory, with participants' contributions adjusted annually. Most legacy employees of Cabot Oil & Gas Corporation become eligible for these benefits if they meet certain age and service requirements at retirement.
The Company provided postretirement benefits to 364 retirees and their dependents at the end of 2021 and 337 retirees and their dependents at the end of 2020.
Obligations and Funded Status
The funded status represents the difference between the accumulated benefit obligation of the Company's postretirement plan and the fair value of plan assets at December 31. The postretirement plan does not have any plan assets; therefore, the unfunded status is equal to the amount of the December 31 accumulated benefit obligation.
The change in the Company's postretirement benefit obligation is as follows:
Year Ended December 31,
(In millions) 2021 2020 2019
Change in Benefit Obligation
Benefit obligation at beginning of period
$ 33 $ 34 $ 30
Service cost 2 2 2
Interest cost 1 1 1
Actuarial (gain) loss 1 (2) 3
Benefits paid (2) (2) (2)
Benefit obligation at end of period
$ 35 $ 33 $ 34
Change in Plan Assets
Fair value of plan assets at end of period
- - -
Funded status at end of period
$ (35) $ (33) $ (34)
Amounts Recognized in the Balance Sheet
Amounts recognized in the balance sheet consist of the following:
December 31,
(In millions) 2021 2020 2019
Current liabilities $ 2 $ 2 $ 2
Non-current liabilities 33 31 32
$ 35 $ 33 $ 34
Amounts Recognized in Accumulated Other Comprehensive Income (Loss)
Amounts recognized in accumulated other comprehensive income (loss) consist of the following:
December 31,
(In millions) 2021 2020 2019
Net actuarial (gain) loss $ - $ - $ 2
Prior service cost (2) (3) (4)
$ (2) $ (3) $ (2)
Components of Net Periodic Benefit Cost and Other Amounts Recognized in Other Comprehensive Income (Loss)
Year Ended December 31,
(In millions) 2021 2020 2019
Components of Net Periodic Postretirement Benefit Cost
Service cost $ 2 $ 2 $ 2
Interest cost 1 1 1
Amortization of prior service cost (1) (1) (1)
Net periodic postretirement cost $ 2 $ 2 $ 2
Other Changes in Benefit Obligations Recognized in Other Comprehensive Income (Loss)
Net (gain) loss $ - $ (2) $ 3
Amortization of prior service cost 1 1 1
Total recognized in other comprehensive income 1 (1) 4
Total recognized in net periodic benefit cost (income) and other comprehensive income $ 3 $ 1 $ 6
Assumptions
Assumptions used to determine projected postretirement benefit obligations and postretirement costs are as follows:
December 31,
2021 2020 2019
Discount rate(1)
2.85 % 2.65 % 3.50 %
Health care cost trend rate for medical benefits assumed for next year (pre-65) 6.50 % 6.75 % 7.00 %
Health care cost trend rate for medical benefits assumed for next year (post-65) 4.75 % 5.00 % 5.25 %
Ultimate trend rate (pre-65) 4.50 % 4.50 % 4.50 %
Ultimate trend rate (post-65) 4.50 % 4.50 % 4.50 %
Year that the rate reaches the ultimate trend rate (pre-65) 2030 2030 2030
Year that the rate reaches the ultimate trend rate (post-65) 2023 2023 2023
_______________________________________________________________________________
(1)Represents the year end rates used to determine the projected benefit obligation. To compute postretirement cost in 2021, 2020 and 2019, respectively, the beginning of year discount rates of 2.65 percent, 3.50 percent and 4.45 percent were used.
Coverage provided to participants age 65 and older is under a fully-insured arrangement. The Company subsidy is limited to 60 percent of the expected annual fully-insured premium for participants age 65 and older. For all participants under age 65, the Company subsidy for all retiree medical and prescription drug benefits, beginning January 1, 2006, was limited to an aggregate annual amount not to exceed $648,000. This limit increases by 3.5 percent annually thereafter.
Cash Flows
Contributions. The Company expects to contribute approximately $2 million to the postretirement benefit plan in 2022.
Estimated Future Benefit Payments. The following estimated benefit payments under the Company's postretirement plans, which reflect expected future service, are expected to be paid as follows:
(In millions)
2022 $ 2
2023 2
2024 2
2025 2
2026 2
Years 2027 - 2031 7
Savings Investment Plan
The Company has a Savings Investment Plan (“SIP”), which is a defined contribution plan. The Company matches a portion of employees' contributions in cash. Participation in the SIP is voluntary and all regular employees of the Company are eligible to participate. The Company matches employee contributions dollar-for-dollar, up to the maximum Internal Revenue Service (“IRS”) limit, on the first six percent of an employee's pretax earnings. The SIP also provides for discretionary profit sharing contributions in an amount equal to 10 percent of an eligible plan participant's salary and bonus.
In connection with the Merger, the Company assumed the Cimarex Energy Co. 401(k) Plan (the “401(k) Plan”) with respect to Cimarex employees. The Company expects to maintain this plan throughout the integration process. Participation in the 401(k) Plan is voluntary and all regular Cimarex employees are eligible to participate. The Company matches employee contributions dollar-for-dollar, up to the maximum IRS limit, on the first seven percent of an employee's pretax earnings. The 401(k) Plan also provides for certain discretionary contributions. No such employer discretionary contributions were made in 2021.
During the years ended December 31, 2021, 2020 and 2019, the Company made contributions of $7 million, $6 million and $6 million, respectively, which are included in general and administrative expense in the Consolidated Statement of Operations. The Company's common stock is an investment option within the SIP and the 401(k) Plan.
Deferred Compensation Plans
The Company has a deferred compensation plan which is available to officers and certain members of the Company's management group and acts as a supplement to the SIP. The Internal Revenue Code does not cap the amount of compensation that may be taken into account for purposes of determining contributions to the deferred compensation plan and does not impose limitations on the amount of contributions to the deferred compensation plan. At the present time, the Company anticipates making a contribution to the deferred compensation plan on behalf of a participant in the event that Internal Revenue Code limitations cause a participant to receive less than the Company matching contribution under the SIP.
The assets of the deferred compensation plan are held in a rabbi trust and are subject to additional risk of loss in the event of bankruptcy or insolvency of the Company.
Under the deferred compensation plan, the participants direct the deemed investment of amounts credited to their accounts. The trust assets are invested in either mutual funds that cover the investment spectrum from equity to money market, or may include holdings of the Company's common stock, which is funded by the issuance of shares to the trust. The mutual funds are publicly traded and have market prices that are readily available. The Company's common stock is not currently an investment option in the deferred compensation plan. Shares of the Company's stock currently held in the deferred compensation plan represent vested performance share awards that were previously deferred into the rabbi trust. Settlement payments are made to participants in cash, either in a lump sum or in periodic installments. The market value of the trust assets, excluding the Company's common stock, was $47 million and $22 million at December 31, 2021 and 2020, respectively, and is included in other assets in the Consolidated Balance Sheet. Related liabilities, including the Company's common stock, totaled $56 million and $31 million at December 31, 2021 and 2020, respectively, and are included in other liabilities in the Consolidated Balance Sheet. With the exception of the Company's common stock, there is no impact on earnings or earnings per share from the changes in market value of the deferred compensation plan assets because the changes in market value of the trust assets are offset completely by changes in the value of the liability, which represents trust assets belonging to plan participants.
As of December 31, 2021 and 2020, 495,774 shares of the Company's common stock were held in the rabbi trust, respectively. These shares were recorded at the market value on the date of deferral, which totaled $5 million and $5 million at December 31, 2021 and 2020, respectively, and is included in additional paid-in capital in stockholders' equity in the Consolidated Balance Sheet. The Company recognized compensation expense (benefit) of $1 million, $(1) million and $(2) million in 2021, 2020 and 2019, respectively, which is included in general and administrative expense in the Consolidated Statement of Operations representing the increase (decrease) in the closing price of the Company's shares held in the trust. The Company's common stock issued to the trust is not considered outstanding for purposes of calculating basic earnings per share, but is considered a common stock equivalent in the calculation of diluted earnings per share.
On September 30, 2021, certain executives of the Company entered into letter agreements whereby, in exchange for the cancellation of their rights under their change-in-control agreements and the non-competition and non-solicitation provisions contained in the letter agreements, each such executive would receive a contribution into his or her deferred compensation account at the effective time of the Merger. On October 1, 2021, the Company made deferred contribution payments totaling approximately $19 million into such executives’ deferred compensation accounts. All of such contributions are fully vested.
In connection with the Merger, the Company assumed the Cimarex deferred compensation plan. The market value of the trust assets and related liabilities was $27 million at the effective date of the Merger, October 1, 2021. Subsequent to the completion of the Merger, in October 2021, the Company distributed $27 million to the plan participants as a result of the change-in-control provision under the plan.
The Company made contributions to the deferred compensation plans of $20 million, $1 million and $1 million in 2021, 2020 and 2019, respectively, which are included in general and administrative expense in the Consolidated Statement of Operations.
12. Capital Stock
Issuance of Common Stock
Following the effectiveness of the Merger, the Company issued approximately 408.2 million shares of its common stock to Cimarex stockholders under the terms of the Merger Agreement.
In October 2021, in accordance with the Merger Agreement, the Company issued 3.4 million shares of restricted stock to replace Cimarex restricted stock awards granted to certain employees. Because these awards have non-forfeitable rights to dividends or dividend equivalents, the Company considers these shares as issued and outstanding common stock.
Increase in Number of Authorized Shares
On September 29, 2021, the Company's stockholders approved an amendment to the Company's certificate of incorporation to increase the number of authorized shares of Company common stock from 960,000,000 shares to 1,800,000,000 shares. That amendment became effective on October 1, 2021.
Dividends
Common Stock
In April 2021, the Company’s Board of Directors approved an increase in the quarterly dividend on the Company's common stock from $0.10 per share to $0.11 per share. In November 2021, the Company’s Board of Directors also approved an increase in the quarterly dividend on the Company's common stock from $0.11 per share to $0.125 per share.
On October 4, 2021, and in connection with the completion of the Merger, the Company’s Board of Directors approved a special dividend of $0.50 per share payable on the Company’s common stock on October 22, 2021.
On November 3, 2021, consistent with the Company's dividend strategy to return at least 50 percent of quarterly free cash flows to stockholders, the Company’s Board of Directors approved a base-plus-variable dividend of $0.30 per share, payable on the Company’s common stock on November 24, 2021.
Subsequent Event. In February 2022, the Company’s Board of Directors of approved an additional increase in the quarterly dividend on the Company’s common stock from $0.125 per share to $0.15 per share. Also on that date, the Board of Directors approved a variable dividend of $0.41 per share, resulting in a base-plus-variable dividend of $0.56 per share on the Company’s common stock.
Cimarex Redeemable Preferred Stock
In the fourth quarter of 2021 and after the Merger with Cimarex, a cash dividend of $20.3125 per share was declared on the outstanding shares of Preferred Stock (as defined below) issued by Cimarex. Dividends are paid in the quarter following the quarter of declaration. At December 31, 2021, dividends payable to preferred stockholders of $1 million were included in accounts payable in the Consolidated Balance Sheet.
Incentive Plans
Coterra Energy Inc. 2014 Incentive Plan
On May 1, 2014, the Company’s stockholders approved the Coterra Energy Inc. 2014 Incentive Plan (the “2014 Coterra Plan”). Under the 2014 Coterra Plan, incentive and non-statutory stock options, stock appreciation rights (“SAR’s”), stock awards, cash awards and performance share awards may be granted to key employees, consultants and officers of the Company. Non-employee directors of the Company may be granted discretionary awards under the 2014 Coterra Plan consisting of stock options or stock awards. A total of 18.0 million shares of common stock may be issued under the 2014 Coterra Plan. Under the 2014 Coterra Plan, no more than 10.0 million shares may be issued pursuant to incentive stock options. No additional awards may be granted under the 2014 Coterra Plan on or after May 1, 2024. At December 31, 2021, approximately 10.5 million shares are available for issuance under the 2014 Coterra Plan.
Cimarex Energy Co. 2019 Equity Incentive Plan
In connection with the Merger, the Company assumed all rights and obligations under the Cimarex Energy Co. 2019 Equity Incentive Plan (the “2019 Cimarex Plan”) and the Company will be entitled to grant equity or equity-based awards with respect to Coterra common stock under the Plan to current or former employees of Cimarex, to the extent permissible under applicable law and NYSE listing rules. The 2019 Cimarex Plan provides for grants of stock options, SARs, restricted stock, restricted stock units, performance stock units, cash awards and other stock-based awards. As of December 31, 2021, approximately 35.9 million shares of Coterra common stock are available for issuance under the 2019 Cimarex Plan, subject to certain limitations.
Treasury Stock
In August 1998, the Company’s Board of Directors authorized a share repurchase program under which the Company could purchase shares of common stock in the open market or in negotiated transactions. The timing and amount of these stock purchases was determined at the discretion of management. The Company could use the repurchased shares to fund stock compensation programs presently in existence, or for other corporate purposes. All purchases executed under the share repurchase program were through open market transactions. There was no expiration date associated with the authorization to repurchase shares of the Company.
During 2021 and 2020, there were no share repurchases under the share repurchase program. During the years ended December 31, 2019, the Company repurchased 25.5 million shares for a total cost of $488 million. Since the authorization date and subsequent authorizations, the Company repurchased 99.0 million shares, of which 20.0 million shares have been retired, for a total cost of approximately $1.9 billion. No treasury shares have been delivered or sold by the Company subsequent to the repurchase.
During 2021, the Company withheld 125,067 shares of common stock valued at $3 million related to shares withheld for taxes upon the vesting of certain restricted stock awards. The shares withheld are included in treasury stock in the Consolidated Balance Sheet.
As of December 31, 2021, 79.1 million shares were held as treasury stock and the remaining number of shares authorized for repurchase under the share repurchase plan was 11.0 million.
Subsequent Event. In February 2022, our Board of Directors terminated the previously authorized share repurchase program and authorized a new share repurchase program. This new share repurchase program authorizes the Company to purchase up to $1.25 billion of the Company’s common stock in the open market or in negotiated transactions.
Dividend Restrictions
The Board of Directors of the Company determines the amount of future cash dividends, if any, to be declared and paid on the common stock depending on, among other things, the Company's financial condition, funds from operations, the level of its capital and exploration expenditures and its future business prospects. None of the senior note or credit agreements in place have restricted payment provisions or other provisions which currently limit the Company’s ability to pay dividends.
Cimarex Redeemable Preferred Stock
In October 2021, in connection with the Merger, the Company effectively assumed the obligations associated with Cimarex’s preferred stock, par value $0.01 per share, designated as 8 1/8% Series A Cumulative Perpetual Convertible Preferred Stock (the “Preferred Stock”). The Preferred Stock was originally issued by Cimarex and remains on the Cimarex balance sheet after the Merger. The fair value of the Preferred Stock as of the effective date of the Merger was $50 million. The Company accounts for the Preferred Stock as a non-controlling interest, which is immaterial for reporting purposes.
Holders of the Preferred Stock are entitled to receive, when, as, and if declared by the Cimarex board of directors out of funds of Cimarex legally available for payment, cumulative cash dividends at the annual rate of 8.125% of each share’s liquidation preference of $1,000. Dividends on the Preferred Stock are payable quarterly in arrears and accumulate from the most recent date as to which dividends have been paid. In the event of any liquidation, winding up or dissolution of Cimarex, whether voluntary or involuntary, each holder will be entitled to receive in respect of its shares and to be paid out of the assets of Cimarex legally available for distribution to its stockholders, after satisfaction of liabilities to Cimarex’s creditors and any senior stock (of which there is currently none) and before any payment or distribution is made to holders of junior stock (including Cimarex’s common stock), the liquidation preference of $1,000 per share, with the total liquidation preference at December 31, 2021 being $28 million in the aggregate. Each holder has the right at any time, at its option, to convert any or all of such holder’s shares of Preferred Stock at an initial conversion rate of 34.1008 shares of fully paid and nonassessable shares of the Company’s common stock and $471.3975 in cash per share of Preferred Stock. The initial conversion rate of 34.1008 adjusts upon the occurrence of certain events, including the payment of cash dividends to common stockholders of Coterra, and is 35.38530 as of December 31, 2021. As a result of the cash redemption features included in the Preferred Stock conversion option granted to each holder, with such conversion not solely within Cimarex’s control, the instruments are classified as “Cimarex redeemable preferred stock” in temporary equity ion the Consolidated Balance Sheet.
Additionally, beginning on and continuing after October 15, 2021, Cimarex has the right, at its option, if the closing sale price of Coterra common stock meets certain criteria, to elect to cause all, and not part, of the outstanding shares of Preferred Stock to be converted into that number of shares of Coterra common stock for each eligible share of Preferred Stock equal to the conversion rate in effect on the mandatory conversion date as such terms are defined in the Certificate of Designations for
the Preferred Stock and $471.3975 in cash per share of Preferred Stock. The Company and Cimarex also have the right at any time to repurchase shares of Preferred Stock through privately negotiated transactions.
13. Stock-Based Compensation
General
Stock-based compensation expense for the years ended December 31, 2021, 2020 and 2019 was $57 million, $43 million and $31 million, respectively, and is included in general and administrative expense in the Consolidated Statement of Operations. The related income tax benefit for the years ended December 31, 2021, 2020 and 2019 was $24 million, $10 million and $7 million, respectively.
Restricted Stock Units - Employees
Restricted stock units are granted from time to time to employees of the Company. The fair value of restricted stock unit grants is based on the closing stock price on the grant date. Restricted stock units generally vest either at the end of a three year service period or on a graded or graduated vesting basis at each anniversary date over a three or four year service period.
For awards that vest at the end of the service period, expense is recognized ratably using a straight-line approach over the service period. Under the graded or graduated approach, the Company recognizes compensation cost ratably over the requisite service period, as applicable, for each separately vesting tranche as though the awards are, in substance, multiple awards. For most restricted stock units, vesting is dependent upon the employees' continued service with the Company, with the exception of employment termination due to death, disability or, if applicable, retirement. If retirement protection is included in the grant award, the Company accelerates the vesting period for retirement-eligible employees for purposes of recognizing compensation expense in accordance with the vesting provisions of the Company's stock-based compensation programs.
The Company used an annual forfeiture rate assumption ranging from zero to five percent for purposes of recognizing stock-based compensation expense for restricted stock units. The annual forfeiture rates were based on the Company's actual forfeiture history or expectations for this type of award to various employee groups.
The following table is a summary of restricted stock unit award activity:
Year Ended December 31,
2021 2020 2019
Shares Weighted-
Average Grant
Date Fair Value
per Share Shares Weighted-
Average Grant
Date Fair Value
per Share Shares Weighted-
Average Grant
Date Fair Value
per Share
Outstanding at beginning of period 50,500 $ 25.29 58,834 $ 25.19 150,293 $ 28.12
Granted 1,236,971 20.83 - - 55,500 25.29
Vested - - (6,334) 24.39 (143,959) 28.29
Forfeited (1,000) 25.29 (2,000) 25.29 (3,000) 25.29
Outstanding at end of period(1)(2)
1,286,471 $ 21.00 50,500 $ 25.29 58,834 $ 25.19
__________________________________________________________________
(1)As of December 31, 2021, the aggregate intrinsic value was $24 million and was calculated by multiplying the closing market price of the Company's common stock on December 31, 2021 by the number of non-vested restricted stock units outstanding.
(2)As of December 31, 2021, the weighted average remaining contractual term of non-vested restricted stock units outstanding was 2.3 years.
On September 30, 2021, certain executives of the Company entered into letter agreements whereby, in exchange for the cancellation of their rights under their change-in-control agreements and the non-competition and non-solicitation provisions contained in the letter agreements, each such executive would receive a grant of restricted stock units at the effective time of the Merger. On October 1, 2021, the Company granted 258,252 shares of restricted stock units, with a grant date value of $22.25 per unit to each such executive. The fair value of these units is measured based on the closing stock price on the October 1, 2021 grant date and will fully vest over a six-month vesting period.
Compensation expense recorded for all employee restricted stock units for the years ended December 31, 2021, 2020 and 2019 was $4 million, $- million and $1 million, respectively. Unamortized expense as of December 31, 2021 for all outstanding restricted stock units was $23 million and will be recognized over the next 2.3 years.
The total fair value of restricted stock units that vested during 2021, 2020 and 2019 was $- million, $- million and $4 million, respectively.
Restricted Stock Units - Non-Employee Directors
Restricted stock units are granted from time to time to non-employee directors of the Company. The fair value of the restricted stock units is based on the closing stock price on the grant date. These units vest immediately and compensation expense is recorded immediately. Shares of Company common stock are issued when the director ceases to be a director of the Company.
The following table is a summary of restricted stock unit award activity:
Year Ended December 31,
2021 2020 2019
Shares Weighted-
Average Grant
Date Fair Value
per Share Shares Weighted-
Average Grant
Date Fair Value
per Share Shares Weighted-
Average Grant
Date Fair Value
per Share
Outstanding at beginning of period 704,284 $ 17.99 574,219 $ 18.47 490,415 $ 17.41
Granted and fully vested 107,710 18.51 130,065 15.88 83,804 24.70
Issued (566,096) 17.04 - - - -
Forfeited - - - - - -
Outstanding at end of period(1)(2)
245,898 $ 20.41 704,284 $ 17.99 574,219 $ 18.47
_______________________________________________________________________________
(1)As of December 31, 2021, the aggregate intrinsic value was $5 million and was calculated by multiplying the closing market price of the Company's stock on December 31, 2021 by the number of outstanding restricted stock units.
(2)Due to the immediate vesting of the units and the unknown term of each director, the weighted-average remaining contractual term in years has not been provided.
Compensation expense recorded for all non-employee director restricted stock units for the year ended December 31, 2021, 2020 and 2019 was $2 million, $2 million and $2 million, respectively, which reflects the total fair value of these units.
Restricted Stock Awards
Restricted stock awards are granted from time to time to employees of the Company. The fair value of restricted stock grants is based on the closing stock price on the grant date. Restricted stock awards generally vest either at the end of a three year service period or on a graded or graduated vesting basis at each anniversary date over a three or four year service period.
For awards that vest at the end of the service period, expense is recognized ratably using a straight-line approach over the service period. Under the graded or graduated approach, the Company recognizes compensation cost ratably over the requisite service period, as applicable, for each separately vesting tranche as though the awards are, in substance, multiple awards. For most restricted stock awards, vesting is dependent upon the employees' continued service with the Company, with the exception of employment termination due to death, disability or, if applicable, retirement. If retirement protection is included in the grant award, the Company accelerates the vesting period for retirement-eligible employees for purposes of recognizing compensation expense in accordance with the vesting provisions of the Company's stock-based compensation programs.
The Company used an annual forfeiture rate assumption of ranging from zero to 15 percent for purposes of recognizing stock-based compensation expense for restricted stock awards. The annual forfeiture rates were based on the Company's actual forfeiture history for this type of award to various employee groups.
The following table is a summary of restricted stock award activity:
Year Ended December 31,
2021 2020 2019
Shares Weighted-
Average Grant
Date Fair Value
per Share Shares Weighted-
Average Grant
Date Fair Value
per Share Shares Weighted-
Average Grant
Date Fair Value
per Share
Outstanding at beginning of period - $ - - $ - - $ -
Granted 3,364,354 22.25 - - - -
Vested (337,142) 22.25 - - - -
Forfeited (8,029) 22.25 - - - -
Outstanding at end of period(1)(2)
3,019,183 $ 22.25 - $ - - $ -
_______________________________________________________________________________
(1)As of December 31, 2021, the aggregate intrinsic value was $57 million and was calculated by multiplying the closing market price of the Company's stock on December 31, 2021 by the number of non-vested restricted stock awards outstanding.
(2)As of December 31, 2021, the weighted average remaining contractual term of non-vested restricted stock awards outstanding was 2.0 years.
On October 1, 2021, the Company granted 3,364,354 shares of restricted stock, with a grant date value of $22.25 per share. These awards are replacement awards granted to Cimarex employees as provided under the Merger Agreement. The fair value of these awards is measured based on the closing stock price on the closing date of the Merger (grant date). The awards will vest over periods ranging from two months to three years. Approximately $22 million of the grant date value was recognized as merger consideration and the remaining fair value will be recognized as stock-based compensation expense over the respective vesting periods.
Compensation expense recorded for all restricted stock awards for the year ended December 31, 2021was $5 million and unamortized expense as of December 31, 2021 was $41 million and will be recognized over the next 2.0 years.
The total fair value of restricted stock awards that vested during 2021 was $7 million.
Performance Share Awards
The Company grants three types of performance share awards: two based on performance conditions measured against the Company's internal performance metrics (“Employee Performance Share Awards” and “Hybrid Performance Share Awards”) and one based on market conditions measured based on the Company's performance relative to a predetermined peer group (“TSR Performance Share Awards”). The performance period for these awards commences on January 1 of the respective year in which the award was granted and extends over a three-year performance period. For all performance share awards, the Company used an annual forfeiture rate assumption ranging from zero percent to seven percent for purposes of recognizing stock-based compensation expense for its performance share awards.
Performance Share Awards Based on Internal Performance Metrics
The fair value of performance share award grants based on internal performance metrics is based on the closing stock price on the grant date. Each performance share award represents the right to receive up to 100 percent of the award in shares of common stock.
Employee Performance Share Awards. The Employee Performance Share Awards vest at the end of the three-year performance period and the performance metrics are set by the Company's Compensation Committee. For the awards granted in 2021 and 2020, an employee will earn 100 percent of the award on the third anniversary, provided that the Company averages $100 million or more of operating cash flow during the three-year performance period. For awards granted in 2019, an employee will earn one-third of the award for each of the three performance metrics. The three performance metrics are based on the Company's average production, average finding costs and average reserve replacement over a three-year performance period. Based on the Company's probability assessment at December 31, 2021, it is considered probable that all of the criteria for these awards will be met.
The following table is a summary of activity for Employee Performance Share Awards:
Year Ended December 31,
2021 2020 2019
Shares Weighted-
Average Grant
Date Fair Value
per Share Shares Weighted-
Average Grant
Date Fair Value
per Share Shares Weighted-
Average Grant
Date Fair Value
per Share
Outstanding at beginning of period 1,610,124 $ 20.31 1,259,287 $ 23.64 1,280,021 $ 22.22
Granted 769,594 18.76 722,500 15.60 526,730 24.95
Issued and fully vested (481,784) 23.25 (334,640) 22.60 (388,370) 20.49
Forfeited (39,830) 18.94 (37,023) 20.38 (159,094) 24.29
Outstanding at end of period 1,858,104 $ 18.93 1,610,124 $ 20.31 1,259,287 $ 23.64
On September 29, 2021, in accordance with the Merger Agreement, the compensation committee of the Board of Directors of the Company certified that the performance conditions of the Employee Performance Share Awards which were granted in 2019 had been met. In the first quarter of 2022, 407,540 shares with a grant date fair value of $10 million are expected to be issued and fully vested.
Hybrid Performance Share Awards. The Hybrid Performance Share Awards have a three-year graded performance period. The awards vest 25 percent on each of the first and second anniversary dates and 50 percent on the third anniversary provided that the Company has $100 million or more of operating cash flow for the year preceding the vesting date, as set by the Company's Compensation Committee. If the Company does not meet the performance metric for the applicable period, then the portion of the performance shares that would have been issued on that anniversary date will be forfeited.
The following table is a summary of activity for the Hybrid Performance Share Awards:
Year Ended December 31,
2021 2020 2019
Shares Weighted-
Average Grant
Date Fair Value
per Share Shares Weighted-
Average Grant
Date Fair Value
per Share Shares Weighted-
Average Grant
Date Fair Value
per Share
Outstanding at beginning of period 903,551 $ 19.41 692,788 $ 23.90 662,388 $ 22.48
Granted 423,171 18.58 506,412 15.60 315,029 24.95
Issued and fully vested (1,326,722) 19.14 (295,649) 23.40 (284,629) 21.78
Forfeited - - - - - -
Outstanding at end of period - $ - 903,551 $ 19.41 692,788 $ 23.90
On October 1, 2021, in accordance with the Merger Agreement, the Company vested 960,497 shares of common stock in connection with the accelerated vesting of all outstanding Hybrid Performance Share Awards upon the completion of the Merger. The Company recognized approximately $8 million of stock-based compensation expense in the fourth quarter of 2021 associated with the accelerated vesting of these awards. As of December 31, 2021, there were no Hybrid Awards outstanding.
Performance Share Awards Based on Market Conditions
These awards have both an equity and liability component, with the right to receive up to the first 100 percent of the award in shares of common stock and the right to receive up to an additional 100 percent of the value of the award in excess of the equity component in cash. The equity portion of these awards is valued on the grant date and is not marked to market, while the liability portion of the awards is valued as of the end of each reporting period on a mark-to-market basis. The Company calculates the fair value of the equity and liability portions of the awards using a Monte Carlo simulation model.
TSR Performance Share Awards. The TSR Performance Share Awards granted are earned, or not earned, based on the comparative performance of the Company's common stock measured against a predetermined group of companies in the Company's peer group over a three-year performance period. The Company incorporated a new feature in the 2021 TSR awards that will reduce the potential cash component of the award if the actual performance is negative over the three-year period and the base calculation indicates an above-target payout.
The following table is a summary of activity for the TSR Performance Share Awards:
Year Ended December 31,
2021 2020 2019
Shares Weighted-
Average Grant
Date Fair Value
per Share(1)
Shares Weighted-
Average Grant
Date Fair Value
per Share(1)
Shares Weighted-
Average Grant
Date Fair Value
per Share(1)
Outstanding at beginning of period 1,398,853 $ 16.41 1,428,634 $ 20.17 1,299,868 $ 19.47
Granted 723,224 16.07 862,180 13.79 536,673 20.63
Issued and fully vested (2,122,077) 16.30 (891,961) 19.89 (407,907) 18.57
Forfeited - - - - - -
Outstanding at end of period - $ - 1,398,853 $ 16.41 1,428,634 $ 20.17
_______________________________________________________________________________
(1)The grant date fair value figures in this table represent the fair value of the equity component of the performance share awards.
On October 1, 2021, in accordance with the Merger Agreement, the Company vested 2,122,077 shares of common stock in connection with the accelerated vesting of all outstanding TSR Performance Share Awards upon the completion of the Merger. Under the terms of the Merger Agreement, all TSR Performance Share Awards were vested at target, resulting in a 100 percent payout of equity, with no cash payments earned under the awards. The Company recognized approximately $10 million of stock-based compensation expense in the fourth quarter of 2021 associated with the acceleration of vesting of these awards.
The following table reflects certain balance sheet information of outstanding TSR Awards:
December 31,
(In millions) 2021 2020
Other current liabilities $ - $ -
Other non-current liabilities - 7
The following table reflects certain cash payments related to the vesting of TSR Awards:
Year Ended December 31,
(In millions) 2021 2020 2019
Cash payments for TSR awards $ - $ 14 $ 5
The following assumptions were used to determine the grant date fair value of the equity component of the TSR Performance Share Awards for the respective periods:
Year Ended December 31,
2021 2020 2019
Fair value per performance share award granted during the period $ 16.07 $ 13.79 $ 20.63
Assumptions
Stock price volatility 39.8 % 29.5 % 31.3 %
Risk free rate of return 0.2 % 1.4 % 2.5 %
The following assumptions were used to determine the fair value of the liability component of the TSR Performance Share Awards for the respective periods:
December 31,
2021 2020 2019
Fair value per performance share award at the end of the period $-
$10.37 - $10.81
$6.18 - $14.80
Assumptions
Stock price volatility -%
42.4% - 52.4%
29.8% - 30.4%
Risk free rate of return -% 0.1% 1.6%
The stock price volatility was calculated using historical closing stock price data for the Company for the period associated with the expected term through the grant date of each award. The risk free rate of return percentages are based on the continuously compounded equivalent of the U.S. Treasury within the expected term as measured on the grant date.
Performance Share Awards - Other Information
Compensation expense recorded for both the equity and liability components of all performance share awards for the years ended December 31, 2021, 2020 and 2019 was $41 million, $40 million and $29 million, respectively. Total unamortized compensation expense related to the equity component of performance shares at December 31, 2021 was $13 million and will be recognized over the next 1.3 years.
As of December 31, 2021, the aggregate intrinsic value for all performance share awards was $34 million and was calculated by multiplying the closing market price of the Company's stock on December 31, 2021 by the number of unvested performance share awards outstanding. As of December 31, 2021, the weighted average remaining contractual term of unvested performance share awards outstanding was approximately 1.3 years.
Stock Option Awards
On October 1, 2021, the Company granted stock option awards to purchase 1,577,554 shares of the Company’s common stock with exercise prices ranging from $8.47 to $28.72 per share. These awards are replacement awards granted to Cimarex employees and former employees as provided under the Merger Agreement and were fully vested on the closing date of the Merger. The grant date fair value of approximately $14 million was recognized as merger consideration and, accordingly, no compensation expense will be recognized by the Company related to these awards, as there is no future service requirement for the holders of these awards.
The following table is a summary of activity for the Stock Option Awards:
Year Ended December 31,
2021 2020 2019
Shares Weighted-
Average Strike Price Shares Weighted-
Average Strike Price Shares Weighted-
Average Strike Price
Outstanding at beginning of period - $ - - $ - - $ -
Granted 1,577,554 16.19 - - - -
Exercised
(222,202) 9.15 - - - -
Forfeited or Expired
- - - - - -
Outstanding at end of period(1)
1,355,352 $ 17.35 - $ - - $ -
Exercisable at end of period(1)
1,355,352 $ 17.35 - $ - - $ -
_______________________________________________________________________________
(1)The intrinsic value of a stock option is the amount by which the current market value of the underlying stock exceeds the exercise price of the stock option. The aggregate intrinsic value of stock options outstanding and exercisable at December 31, 2021 was $6 million and $6 million, respectively. The weighted-average remaining contractual term is 3.5 years.
Deferred Performance Shares
As of December 31, 2021, 495,774 shares of the Company's common stock representing vested performance share awards were deferred into the deferred compensation plan. During 2021, no shares were sold out of the plan. During 2021, an increase
to the deferred compensation liability of $1 million was recognized, which represents the increase in the closing price of the Company's shares held in the trust during the period. The increase in compensation expense was included in general and administrative expense in the Consolidated Statement of Operations.
14. Earnings per Common Share
Basic earnings per share (“EPS”) is computed by dividing net income available to common stockholders by the weighted-average number of common shares outstanding for the period. Diluted EPS is similarly calculated except that the common shares outstanding for the period is increased using the treasury stock and as-if-converted methods to reflect the potential dilution that could occur if outstanding stock awards were vested or exercised at the end of the applicable period. Anti-dilutive shares represent potentially dilutive securities that are excluded from the computation of diluted income or loss per share as their impact would be anti-dilutive.
The following is a calculation of basic and diluted net earnings per common share under the two-class method:
Year Ended December 31,
(In millions except per share amounts) 2021 2020 2019
Income (Numerator)
Net income $ 1,158 $ 201 $ 681
Less: dividends attributable to participating securities (2) (2) - -
Less: Cimarex redeemable preferred stock dividends (1) - -
Net income available to common stockholders $ 1,155 $ 201 $ 681
Shares (Denominator)
Weighted average shares - Basic 503 399 416
Dilution effect of stock awards at end of period 1 2 2
Weighted average shares - Diluted 504 401 418
Earnings per share:
Basic $ 2.30 $ 0.50 $ 1.64
Diluted $ 2.29 $ 0.50 $ 1.63
The following is a calculation of weighted-average shares excluded from diluted EPS due to the anti-dilutive effect:
Year Ended December 31,
(In millions) 2021 2020 2019
Weighted-average stock awards excluded from diluted EPS due to the anti-dilutive effect calculated using the treasury stock method 1 - 1
15. Related Party Transactions
On October 1, 2021 and in connection with the Merger, Hans Helmerich was appointed a director of Coterra. Mr. Helmerich is also the Chairman of the Board of Directors of Helmerich & Payne, Inc. (“H&P”). From time to time, H&P provides contract drilling services to the Company. The Company incurred drilling costs of approximately $3 million related to these services subsequent to the effective date of the Merger.
16. Restructuring Costs
In connection with the Merger, the Company recognized $44 million of restructuring expenses during 2021 related to the accrual of employee-related severance and termination benefits associated with the expected termination of certain Cimarex employees.
The following table summarizes the Company’s restructuring liabilities:
(In millions) Year Ended December 31, 2021
Balance at beginning of period $ -
Additions related to merger integration 44
Reductions related to merger integration payments (1)
Balance at end of period $ 43
17. Additional Balance Sheet Information
Certain balance sheet amounts are comprised of the following:
December 31,
(In millions) 2021 2020
Accounts receivable, net
Trade accounts $ 922 $ 216
Joint interest accounts $ 83 $ -
Other accounts 34 -
1,039 216
Allowance for doubtful accounts (2) (1)
$ 1,037 $ 215
Other assets
Deferred compensation plan $ 47 $ 22
Debt issuance cost 5 7
Operating lease right-of-use assets 317 34
Other accounts 20 -
$ 389 $ 63
Accounts payable
Trade accounts $ 94 $ 11
Royalty and other owners 315 37
Accrued transportation 96 52
Accrued capital costs 88 38
Accrued lease operating costs 29 2
Taxes other than income 60 14
Other accounts 65 8
$ 747 $ 162
Accrued liabilities
Employee benefits $ 124 $ 14
Taxes other than income 13 3
Operating lease liabilities 69 4
Financing lease liabilities 14 -
Other accounts 40 1
$ 260 $ 22
Other liabilities
Deferred compensation plan $ 56 $ 31
Operating lease liabilities 248 30
Financing lease liabilities 7 -
Other accounts 63 21
$ 374 $ 82
18. Supplemental Cash Flow Information
Year Ended December 31,
(In millions) 2021 2020 2019
Cash paid for interest and income taxes
Interest $ 81 $ 57 $ 57
Income taxes 184 11 8
Non-cash activity
Equity and replacement stock awards issued as consideration in the Merger
$ 9,120 $ - $ -
Cash, cash equivalents and restricted cash, included in the Consolidated Statement of Cash Flow, is comprised of the following:
December 31,
(In millions) 2021 2019
Cash and cash equivalents $ 1,036 $ 140
Restricted cash 10 12
$ 1,046 $ 152
COTERRA ENERGY INC.
SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED)
Oil and Gas Reserves
Users of this information should be aware that the process of estimating quantities of “proved” and “proved developed” natural gas and crude oil reserves is very complex, requiring significant subjective decisions in the evaluation of all available geological, engineering and economic data for each reservoir. The data for a given reservoir may also change substantially over time as a result of numerous factors including, but not limited to, additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. As a result, revisions to existing reserve estimates may occur from time to time. Although every reasonable effort is made to ensure that reserve estimates reported represent the most accurate assessments possible, the subjective decisions and variances in available data for various reservoirs make these estimates generally less precise than other estimates included in the financial statement disclosures.
Estimates of total proved reserves at December 31, 2021, 2020 and 2019 were based on studies performed by the Company's petroleum engineering staff. The estimates were computed using the 12-month average index price for the respective commodity, calculated as the unweighted arithmetic average for the first day of the month price for each month during the respective year. Estimates with respect to the Company’s Marcellus Shale reserves were audited by Miller and Lents, Ltd. and estimates of the net reserves representing greater than 80 percent of the total future net revenue discounted at 10 percent attributable to the Company’s remaining reserves were subject to an independent evaluation performed by DeGolyer and MacNaughton. Miller and Lents and DeGolyer and MacNaughton each indicated that based on their investigations and subject to the limitations described in their audit letters, they believe the Company’s estimates were, in the aggregate, reasonable.
No major discovery or other favorable or unfavorable event after December 31, 2021, is believed to have caused a material change in the estimates of proved or proved developed reserves as of that date.
The following tables illustrate the Company's net proved reserves, including changes, and proved developed and proved undeveloped reserves for the periods indicated, as estimated by the Company's engineering staff. All reserves are located within the continental U.S.
Oil (Mbbl) Natural Gas
(Bcf) NGLs
(Mbbl) Total
(MBOE)
December 31, 2018 120 11,604 - 1,934,136
Revision of prior estimates(1)
(48) 48 - 7,834
Extensions, discoveries and other additions(2)
- 2,116 - 352,731
Production - (865) - (144,229)
Sales of reserves in place (50) - - (50)
December 31, 2019 22 12,903 - 2,150,422
Revision of prior estimates(3)
(3) (347) - (57,808)
Extensions, discoveries and other additions(2)
- 1,974 - 328,976
Production (4) (858) - (142,954)
December 31, 2020 15 13,672 - 2,278,636
Revision of prior estimates(4)
10,837 (538) 16,797 (61,967)
Extensions, discoveries and other additions(2)
2,633 973 6,100 170,988
Production (8,150) (911) (7,104) (167,113)
Purchases of reserves in place(5)
184,094 1,699 204,822 672,038
December 31, 2021 189,429 14,895 220,615 2,892,582
Proved Developed Reserves
December 31, 2018 107 7,402 - 1,233,790
December 31, 2019 22 8,056 - 1,342,589
December 31, 2020 15 8,608 - 1,434,714
December 31, 2021 153,010 10,691 193,598 2,128,439
Proved Undeveloped Reserves
December 31, 2018 13 4,202 - 700,346
December 31, 2019 - 4,847 - 807,833
December 31, 2020 - 5,064 - 843,922
December 31, 2021 36,419 4,204 27,017 764,143
_______________________________________________________________________________
(1)The net upward revision of 8 MMBOE was primarily due to a net upward performance revision of 11 MMBOE, partially offset by a downward revision of 3 MMBOE associated with PUD reclassifications as a result of the five-year limitation. The net upward performance revision of 11 MMBOE was primarily due to an upward revision of 69 MMBOE associated with the Company's PUD reserves due to performance revisions and the drilling of longer lateral length wells, partially offset by a downward performance revision of 58 MMBOE related to certain proved developed producing properties.
(2)Extensions, discoveries and other additions were primarily related to drilling activity in the Dimock field located in northeast Pennsylvania. The Company added 152 MMBOE, 329 MMBOE and 353 MMBOE of proved reserves in this field in 2021, 2020 and 2019, respectively.
(3)The net downward revision of 58 MMBOE was primarily due to a net downward performance revision of 41 MMBOE and a downward revision of 11 MMBOE associated with PUD reclassifications as a result of the five-year limitation. The net downward performance revision of 41 MMBOE was primarily due to a downward performance revision of 61 MMBOE related to certain proved developed producing properties, partially offset by an upward revision of 21 MMBOE associated with the Company’s PUD reserves due to performance revisions and the drilling of longer lateral length wells.
(4)The net downward revision of 62 MMBOE was primarily related to 97 MMBOE downward performance revision coupled with a 6 MMBOE downward revision associated with PUD reclassifications as a result of the 5 year rule
which was partially offset by a 42 MMBOE positive pricing and cost revision. The net downward performance revision of 97 MMBOE, was primarily due to 57 MMBOE performance revision related to certain proved developed reserves and a 40 MMBOE downward performance revision associate with proved undeveloped reserves.
(5)Purchases of reserves in place were primarily related to the acquisition of Cimarex’s oil and gas properties in connection with the Merger. The reserves are primarily related to the Wolfcamp Shale in the Permian Basin and Woodford Shale in the Anadarko Basin.
Capitalized Costs Relating to Oil and Gas Producing Activities
Capitalized costs relating to oil and gas producing activities and related accumulated depreciation, depletion and amortization were as follows:
December 31,
(In millions) 2021 2020 2019
Aggregate capitalized costs relating to oil and gas producing activities $ 20,655 $ 7,154 $ 6,676
Aggregate accumulated depreciation, depletion and amortization (3,775) (3,149) (2,861)
Net capitalized costs $ 16,880 $ 4,005 $ 3,815
Costs Incurred in Oil and Gas Property Acquisition, Exploration and Development Activities
Costs incurred in property acquisition, exploration and development activities were as follows:
Year Ended December 31,
(In millions) 2021(1)
2020 2019
Property acquisition costs, proved $ 7,472 $ - $ -
Property acquisition costs, unproved 5,386 6 6
Exploration costs 18 15 20
Development costs 688 547 761
Total costs $ 13,564 $ 568 $ 787
_______________________________________________________________________________
(1)These amounts include the fair value of the proved and unproved properties recorded in the purchase price allocation with respect to the Merger. The purchase was funded through the issuance of the Company’s common stock.
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves
The following information has been developed based on natural gas and crude oil reserve and production volumes estimated by the Company's engineering staff. It can be used for some comparisons, but should not be the only method used to evaluate the Company or its performance. Further, the information in the following table may not represent realistic assessments of future cash flows, nor should the Standardized Measure of Discounted Future Net Cash Flows (“Standardized Measure”) be viewed as representative of the current value of the Company.
The Company believes that the following factors should be taken into account when reviewing the following information:
•Future costs and selling prices will differ from those required to be used in these calculations.
•Due to future market conditions and governmental regulations, actual rates of production in future years may vary significantly from the rate of production assumed in the calculations.
•Selection of a 10 percent discount rate is arbitrary and may not be a reasonable measure of the relative risk that is part of realizing future net oil and gas revenues.
•Future net revenues may be subject to different rates of income taxation.
Under the Standardized Measure, future cash inflows were estimated by using the 12-month average index price for the respective commodity, calculated as the unweighted arithmetic average for the first day of the month price for each month during the year.
The average prices (adjusted for basis and quality differentials) related to proved reserves are as follows:
Year Ended December 31,
2021 2020 2019
Natural gas $ 2.93 $ 1.64 $ 2.35
Oil
$ 65.40 $ 32.53 $ 55.80
NGLs $ 25.74 $ - $ -
In the above table, natural gas prices are stated per Mcf and oil and NGL prices are stated per barrel.
Future cash inflows were reduced by estimated future development and production costs based on year end costs to arrive at net cash flow before tax. Future income tax expense was computed by applying year end statutory tax rates to future pretax net cash flows, less the tax basis of the properties involved and utilization of available tax carryforwards related to oil and gas operations. The applicable accounting standards require the use of a 10 percent discount rate.
Management does not solely use the following information when making investment and operating decisions. These decisions are based on a number of factors, including estimates of proved reserves and varying price and cost assumptions considered more representative of a range of anticipated economic conditions.
Standardized Measure is as follows:
Year Ended December 31,
(In millions) 2021 2020 2019
Future cash inflows $ 60,908 $ 22,385 $ 30,302
Future production costs (18,241) (10,784) (10,039)
Future development costs(1)
(2,449) (1,612) (2,006)
Future income tax expenses (8,535) (2,176) (4,043)
Future net cash flows 31,683 7,813 14,214
10% annual discount for estimated timing of cash flows (18,399) (4,751) (8,353)
Standardized measure of discounted future net cash flows $ 13,284 $ 3,062 $ 5,861
______________________________________________________________________________
(1)Includes $390 million, $224 million and $213 million in plugging and abandonment costs for the years ended December 31, 2021, 2020 and 2019, respectively.
Changes in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves
The following is an analysis of the changes in the Standardized Measure:
Year Ended December 31,
(In millions) 2021 2020 2019
Beginning of year $ 3,062 $ 5,861 $ 6,483
Discoveries and extensions, net of related future costs 800 311 1,076
Net changes in prices and production costs 9,573 (4,326) (1,510)
Accretion of discount 551 750 813
Revisions of previous quantity estimates 467 (108) 28
Timing and other (161) 6 (192)
Changes in estimated future development costs (103) - -
Development costs incurred 497 501 469
Sales and transfers, net of production costs (2,801) (746) (1,317)
Sales of reserves in place (1) - (1)
Purchases of reserves in place 6,477 - -
Net change in income taxes (5,077) 813 12
End of year $ 13,284 $ 3,062 $ 5,861

---

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.

---

ITEM 9A. CONTROLS AND PROCEDURES
ITEM 9A. CONTROLS AND PROCEDURES
Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures and Changes in Internal Control over Financial Reporting
As of December 31, 2021, the Company carried out an evaluation, under the supervision and with the participation of the Company's management, including the Company's Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of the Company's disclosure controls and procedures pursuant to Rules 13a-15 and 15d-15 of the Exchange Act. Based upon that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that the Company's disclosure controls and procedures are effective to provide reasonable assurance with respect to the recording, processing, summarizing and reporting, within the time periods specified in the SEC’s rules and forms, of information required to be disclosed by the Company in the reports that it files or submits under the Exchange Act.
During the quarter ended December 31, 2021, the Company completed its Merger with Cimarex. As part of the ongoing integration of the acquired business, the Company is in the process of incorporating the controls and related procedures of Cimarex. Other than incorporating Cimarex’s controls, there were no changes in internal control over financial reporting that occurred during the fourth quarter of 2021 that have materially affected, or are reasonably likely to have a material effect on, the Company's internal control over financial reporting.
Management's Report on Internal Control over Financial Reporting
The management of Coterra Energy Inc. is responsible for establishing and maintaining adequate internal control over financial reporting. Coterra Energy Inc.'s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
Coterra Energy Inc.'s management assessed the effectiveness of the Company's internal control over financial reporting as of December 31, 2021. In making this assessment, it used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”) in Internal Control-Integrated Framework (2013). Based on this assessment management has concluded that, as of December 31, 2021, the Company's internal control over financial reporting is effective at a reasonable assurance level based on those criteria.
Management’s assessment and conclusion on the effectiveness of the Company’s internal control over financial reporting as of December 31, 2021 excludes an assessment of the internal control over financial reporting of Cimarex, which was acquired in a business combination on October 1, 2021. The total assets and total revenues of Cimarex represent approximately 75 percent and 33 percent, respectively, of the related consolidated financial statement amounts as of and for the year ended December 31, 2021.
The effectiveness of Coterra Energy Inc.'s internal control over financial reporting as of December 31, 2021, has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which appears herein.

---

ITEM 9B. OTHER INFORMATION
ITEM 9B. OTHER INFORMATION
None.

---

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
The information required by this Item is incorporated by reference to the Company's definitive Proxy Statement in connection with the 2022 annual stockholders' meeting. In addition, the information set forth under the caption “Business-Other Business Matters-Corporate Governance Matters” in Item 1 regarding our Code of Business Conduct is incorporated by reference in response to this Item.

---

ITEM 11. EXECUTIVE COMPENSATION
ITEM 11. EXECUTIVE COMPENSATION
The information required by this Item is incorporated by reference to the Company's definitive Proxy Statement in connection with the 2022 annual stockholders' meeting.

---

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS
The information required by this Item is incorporated by reference to the Company's definitive Proxy Statement in connection with the 2022 annual stockholders' meeting.

---

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE
The information required by this Item is incorporated by reference to the Company's definitive Proxy Statement in connection with the 2022 annual stockholders' meeting.

---

ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES
ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES
The information required by this Item is incorporated by reference to the Company's definitive Proxy Statement in connection with the 2022 annual stockholders' meeting.
PART IV

---

ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES
ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
A. INDEX
1. Consolidated Financial Statements
See Index on page 66
2. Financial Statement Schedules
Financial statement schedules listed under SEC rules but not included in this report are omitted because they are not applicable or the required information is provided in the notes to our consolidated financial statements.
3. Exhibits
The following instruments are included as exhibits to this report. Those exhibits below incorporated by reference herein are indicated as such by the information supplied in the parenthetical thereafter. If no parenthetical appears after an exhibit, copies of the instrument have been included herewith. The Company's file number with the SEC is 1-10447.
Exhibit
Number Description
2.1
Agreement and Plan of Merger, dated as of May 23, 2021, by and among Cabot Oil & Gas Corporation, Double C Merger Sub, Inc. and Cimarex Energy Co. (incorporated herein by reference to Exhibit 2.1 of Coterra’s Current Report on Form 8-K filed with the SEC on May 24, 2021).
2.2
Amendment No. 1 to Agreement and Plan of Merger, dated as of June 29, 2021, by and among Cabot Oil & Gas Corporation, Double C Merger Sub, Inc. and Cimarex Energy Co. (incorporated herein by reference to Annex A to the Joint Proxy Statement/Prospectus included in Coterra’s Registration Statement on Form S-4 (Reg. No. 333-257534) filed with the SEC on June 30, 2021).
3.1
Restated Certificate of Incorporation of Coterra Energy Inc. (incorporated herein by reference to Exhibit 3.3 of Coterra’s Current Report on Form 8-K filed with the SEC on October 1, 2021).
3.2
Amended and Restated Bylaws of Coterra Energy Inc. (incorporated herein by reference to Exhibit 3.4 of Coterra’s Current Report on Form 8-K filed with the SEC on October 1, 2021).
4.1
Description of Securities Registered Pursuant to Section 12 of the Securities Exchange Act or 1934
4.2
Form of Common Stock Certificate of Coterra Energy Inc. (incorporated herein by reference to Exhibit 4.3 of Coterra’s Registration Statement on Form S-8 (Reg. No. 333-260035 ) filed with the SEC on October 5, 2021).
4.3
Certificate of Designations to 8 1⁄8% Series A Cumulative Perpetual Convertible Preferred Stock of Cimarex Energy Co.
4.4
Amendment to Certificate of Designations to 8 1⁄8% Series A Cumulative Perpetual Convertible Preferred Stock of Cimarex Energy Co.
4.5
Note Purchase Agreement dated as of July 16, 2008 among Cabot Oil & Gas Corporation and the Purchasers named therein (incorporated herein by reference to Exhibit 4.1 of Coterra’s Current Report on Form 8-K filed with the SEC on July 22, 2008).
(a) Amendment No. 1 to Note Purchase Agreement, dated as of June 30, 2010 (incorporated herein by reference to Exhibit 4.2 of Coterra’s Quarterly Report on Form 10-Q for the fiscal quarter ended June 30, 2010.
(b) Amendment No. 2 to Note Purchase Agreement, dated as of December 31, 2015 (incorporated herein by reference to Exhibit 4.2 of Coterra’s Current Report on Form 8-K filed with the SEC on February 9, 2016).
(c) Amendment No. 3 to Note Purchase Agreement, dated as of April 8, 2016 (incorporated herein by reference to Exhibit 4.1(c) of Coterra’s Quarterly Report on Form 10-Q for the fiscal quarter ended March 31, 2016).
4.6
Note Purchase Agreement dated as of December 30, 2010 among Cabot Oil & Gas Corporation and the Purchasers named therein (incorporated herein by reference to Exhibit 4.5 of Coterra’s Annual Report on Form 10-K for the fiscal year ended December 31, 2010).
(a) Amendment No. 1 to Note Purchase Agreement, dated as of December 31, 2015 (incorporated herein by reference to Exhibit 4.4 of Coterra’s Current Report on Form 8-K filed with the SEC on February 9, 2016).
(b) Amendment No. 2 to Note Purchase Agreement, dated as of April 8, 2016 (incorporated herein by reference to Exhibit 4.3(b) of Coterra’s Quarterly Report on Form 10-Q for the fiscal quarter ended March 31, 2016).
4.7
Note Purchase Agreement dated as of September 18, 2014 among Cabot Oil & Gas Corporation and the Purchasers named therein (incorporated herein by reference to Exhibit 4.1 of Coterra’s Current Report on Form 8-K filed with the SEC on September 24, 2014).
(a) Amendment No. 1 to Note Purchase Agreement, dated as of December 31, 2015 (incorporated herein by reference to Exhibit 4.5 of Coterra’s Current Report on Form 8-K filed with the SEC on February 9, 2016).
(b) Amendment No. 2 to Note Purchase Agreement, dated as of April 8, 2016 (incorporated herein by reference to Exhibit 4.4(b) of Coterra’s Quarterly Report on Form 10-Q for the fiscal quarter ended March 31, 2016).
4.8
Indenture, dated as of October 7, 2021, by and between Coterra Energy Inc. and U.S. Bank National Association, as Trustee (incorporated herein by reference to Exhibit 4.1 of Coterra’s Current Report on Form 8-K filed with the SEC on October 7, 2021).
4.9
First Supplemental Indenture, dated as of October 7, 2021, by and between Coterra Energy Inc. and U.S. Bank National Association, as Trustee (incorporated herein by reference to Exhibit 4.2 of Coterra’s Current Report on Form 8-K filed with the SEC on October 7, 2021).
4.10
Form of 4.375% Senior Notes due 2024 (incorporated herein by reference to Exhibit A-1 to the First Supplemental Indenture filed as Exhibit 4.2 of Coterra’s Current Report on Form 8-K filed with the SEC on October 7, 2021).
4.11
Form of 3.90% Senior Notes due 2027 (incorporated herein by reference to Exhibit A-2 to the First Supplemental Indenture filed as Exhibit 4.2 of Coterra’s Current Report on Form 8-K filed with the SEC on October 7, 2021).
4.12
Form of 4.375% Senior Notes due 2029 (incorporated herein by reference to Exhibit A-3 to the First Supplemental Indenture filed as Exhibit 4.2 of Coterra’s Current Report on Form 8-K filed with the SEC on October 7, 2021).
4.13
Registration Rights Agreement, dated as of October, 7 2021, by and among Coterra Energy Inc., J.P. Morgan Securities LLC, BofA Securities, Inc., Citigroup Global Markets Inc., PNC Capital Markets LLC, Scotia Capital (USA) Inc., TD Securities (USA) LLC, U.S. Bancorp Investments, Inc., Wells Fargo Securities, LLC, Capital One Securities, Inc., CIBC World Markets Corp., KeyBanc Capital Markets Inc., RBC Capital Markets, LLC, SMBC Nikko Securities America, Inc., Truist Securities, Inc. and MUFG Securities Americas Inc. (incorporated herein by reference to Exhibit 4.6 of Coterra’s Current Report on Form 8-K filed with the SEC on October 7, 2021).
Coterra or certain of its consolidated subsidiaries are parties to other debt instruments under which the total amount of securities authorized does not exceed 10% of Coterra’s total consolidated assets. Pursuant to paragraph (4)(iii)(A) of Item 601(b) of Regulation S-K, Coterra agrees to furnish a copy of any of those instruments to the SEC upon its request.
*10.1
Form of Change in Control Agreement between Cabot Oil & Gas Corporation and Certain Officers (incorporated herein by reference to Exhibit 10.1 of Coterra’s Annual Report on Form 10-K for the fiscal year ended December 31, 2008).
(a) Form of Change in Control Agreement between Cabot Oil & Gas Corporation and Certain Officers (Confirmation that Certain Benefits no Longer Apply) (incorporated herein by reference to Exhibit 10.1(a) of Coterra’s Annual Report on Form 10-K for the fiscal year ended December 31, 2010).
(b) Form of Amendment to Change in Control Agreement (incorporated herein by reference to Exhibit 10.4 of Coterra’s Registration Statement on Form S-4 (Reg. No. 333-257534) filed with the SEC on June 30, 2021).
(c) Form of Letter Agreement with respect to Change-in-Control Arrangements (incorporated herein by reference to Exhibit 10.1 of Coterra’s Current Report on Form 8-K filed with the SEC on October 1, 2021).
*10.2
Form of Indemnity Agreement between Cabot Oil & Gas Corporation and Certain Officers (incorporated herein by reference to Exhibit 10.2 of Coterra’s Annual Report on Form 10-K for the fiscal year ended December 31, 2012).
*10.3
Form of Indemnification Agreement (incorporated herein by reference to Exhibit 10.3 of Coterra’s Current Report on Form 8-K filed with the SEC on October 1, 2021).
*10.4
Deferred Compensation Plan of Cabot Oil & Gas Corporation, as Amended and Restated, Effective January 1, 2011 (incorporated herein by reference to Exhibit 10.1 of Coterra’s Quarterly Report on Form 10-Q for the fiscal quarter ended June 30, 2011).
*10.5
Deferred Compensation Letter Agreement, dated as of September 30, 2021, between Cabot Oil & Gas Corporation and Phillip L. Stalnaker (incorporated herein by reference to Exhibit 10.2 of Coterra’s Current Report on Form 8-K filed with the SEC on October 1, 2021).
*10.6
Employment Letter Agreement, dated as of May 23, 2021, between Cabot Oil & Gas Corporation and Dan O. Dinges (incorporated herein by reference to Exhibit 10.1 of Coterra’s Registration Statement on Form S-4 (Reg. No. 333-257534) filed with the SEC on June 30, 2021).
*10.7
Employment Letter Agreement, dated as of May 23, 2021, between Cabot Oil & Gas Corporation and Thomas E. Jorden (incorporated herein by reference to Exhibit 10.2 of Coterra’s Registration Statement on Form S-4 (Reg. No. 333-257534) filed with the SEC on June 30, 2021).
*10.8
Side Letter Agreement, dated as of June 29, 2021, by and among Cabot Oil and Gas Corporation and Thomas E. Jorden (incorporated herein by reference to Exhibit 10.3 of Coterra’s Registration Statement on Form S-4 (Reg. No. 333-257534) filed with the SEC on June 30, 2021).
*10.9
Cabot Oil & Gas Corporation 2014 Incentive Plan (incorporated herein by reference to Exhibit 10.1 of Coterra’s Quarterly Report on Form 10-Q for the fiscal quarter ended June 30, 2014).
(a) Form of Non-Employee Director Restricted Unit Award Agreement (incorporated herein by reference to Exhibit 10.2 of Coterra’s Quarterly Report on Form 10-Q for the fiscal quarter ended June 30, 2014).
(b) Form of Restricted Stock Award Agreement (3 year graded) (incorporated herein by reference to Exhibit 10.2(a) of Coterra’s Quarterly Report on Form 10-Q for the fiscal quarter ended March 31, 2015).
(c) Form of Restricted Stock Award Agreement (3 year cliff) (incorporated herein by reference to Exhibit 10.2(b) of Coterra’s Quarterly Report on Form 10-Q for the fiscal quarter ended March 31, 2015).
(d) Form of Performance Share Award Agreement (Officers) (incorporated herein by reference to Exhibit 10.2(c) of Coterra’s Quarterly Report on Form 10-Q for the fiscal quarter ended March 31, 2015).
(e) Form of Hybrid Performance Share Award Agreement (incorporate herein by reference to Exhibit 10.2(d) of Coterra’s Quarterly Report on Form 10-Q for the fiscal quarter ended March 31, 2015)..
(f) Form of Performance Share Award Agreement (Employees) (incorporated herein by reference to Exhibit 10.2(e) of Coterra’s Quarterly Report on Form 10-Q for the fiscal quarter ended March 31, 2015).
(g) Form of Performance Share Award Agreement (Employees) (incorporated herein by reference to Exhibit 10.5(g) of Coterra’s Annual Report on Form 10-K for the fiscal year ended December 31, 2020).
*10.10
Cimarex Energy Co. Amended and Restated 2019 Equity Incentive Plan (incorporated herein by reference to Exhibit 4.4 of Coterra’s Registration Statement on Form S-8 (Reg. No. 333-260230) filed with the SEC on October 14, 2021).
(a) Form of Notice of Grant of Restricted Stock and Award Agreement.
(b) Form of Notice of Grant of Performance Stock Units and Award Agreement (Performance Award).
(c) Form of Notice of Grant of Performance Stock Units and Award Agreement (Performance Award).
(d) Form of Restricted Share Award Agreement (Continuing Employees).
(e) Form of Restricted Share Award Agreement (Transitioning Employees).
*10.11
Form of Severance Compensation Agreement of certain executive officers of Cimarex Energy Co. (incorporated herein by reference to Exhibit 10.1 of Cimarex’s Current Report on Form 8-K filed with the SEC on March 13, 2020).
(a) Form of Amendment to Severance Compensation Agreements of certain executive officers of Cimarex Energy Co. (incorporated herein by reference to Exhibit 10.11 of Coterra’s Quarterly Report on Form 10-Q for the fiscal quarter ended September 30, 2021).
*10.12
Nonemployee Director Deferred Compensation Plan effective December 21, 2012 (incorporated herein by reference to Exhibit 10.10 of Coterra’s Annual Report on Form 10-K for the fiscal year ended December 31, 2012).
10.13
Second Amended and Restated Credit Agreement dated as of April 22, 2019, among Cabot Oil & Gas Corporation, as Borrower, JPMorgan Chase Bank, N.A., as Administrative Agent and Joint Lead Arranger, Merrill Lynch, Pierce, Fenner & Smith, Incorporated, as Syndication Agent and Joint Lead Arranger, Bank of Montreal, The Bank of Nova Scotia, Houston Branch, Citibank N.A., Compass Bank, Toronto Dominion (New York) LLC, U.S. Bank National Association and Wells Fargo, N.A. as Co-Documentation Agent, and the Lenders party thereto (incorporated herein by reference to Exhibit 10.1 of Coterra’s Quarterly Report on Form 10-Q for the fiscal quarter ended March 31, 2019).
10.14
First Amendment to Second Amended and Restated Credit Agreement, dated as of June 17, 2021, by and among Cabot Oil & Gas Corporation, the Lenders party thereto and JPMorgan Chase Bank, N.A., as Administrative Agent (incorporated herein by reference to Exhibit 10.1 of Coterra’s Current Report on Form 8-K filed with the SEC on June 17, 2021).
10.15
Second Amendment to Second Amended and Restated Credit Agreement, dated as of September 16, 2021, by and among Cabot Oil & Gas Corporation, the Lenders party thereto and JPMorgan Chase Bank, N.A., as Administrative Agent (incorporated herein by reference to Exhibit 10.1 of Coterra’s Current Report on Form 8-K filed with the SEC on September 17, 2021).
21.1
Subsidiaries of Coterra Energy Inc.
23.1
Consent of PricewaterhouseCoopers LLP.
23.2
Consent of Miller and Lents, Ltd.
23.3
Consent of DeGolyer and MacNaughton.
31.1
302 Certification-Chairman, President and Chief Executive Officer.
31.2
302 Certification-Vice President and Chief Financial Officer.
32.1
906 Certification.
99.1
Miller and Lents, Ltd. Audit Letter.
99.2
DeGolyer and MacNaughton Audit Letter.
101.INS Inline XBRL Instance Document. The instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document.
101.SCH Inline XBRL Taxonomy Extension Schema Document.
101.CAL Inline XBRL Taxonomy Extension Calculation Linkbase Document.
101.LAB Inline XBRL Taxonomy Extension Label Linkbase Document.
101.PRE Inline XBRL Taxonomy Extension Presentation Linkbase Document.
101.DEF Inline XBRL Taxonomy Extension Definition Linkbase Document.
104 Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101).
______________________________________________________________________________
*Compensatory plan, contract or arrangement.