ITEMS 1 and 2. BUSINESS AND PROPERTIES
To date, we have not experienced significant difficulty in transporting or marketing our natural gas production as it becomes available; however, there is no assurance that we will always be able to transport and market all of our production.
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.
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 aany financial commitment due based on our current proved reserves and production levels from which we can fulfill these obligations.
From time to time, we use derivative financial instruments to manage price risk associated with our oil and natural gas and crude oil production. WhileAlthough there are many different types of derivatives available, we generally utilize collar, swap, roll differential swaps and basis swap agreements designed to manageassist us in managing price risk more effectively.risk. The collar arrangements are a combination of put and call options used to establish floor and ceiling prices for a fixed volume of natural gas or crude oil 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.
|
| | | | | | | | |
Type of Contract | | Volume | | Contract Period | | Weighted-Average Fixed Price |
Physical contracts | | | | | | | |
Natural gas purchase | | 81.2 |
| Bcf | | Jan. 2018 - Oct. 2018 | | $3.70 |
Natural gas sales | | 11.7 |
| Bcf | | Jan. 2018 - Feb. 2018 | | $4.71 |
In the table above, natural gas prices are stated per Mcf.
In January 2018, we terminated certain physical purchase contracts prior to their settlement date. The termination did not have a material impact on the Consolidated Financial Statements, as the contracts were previously recognized at fair value.
RESERVES
The following table presents our estimated proved reserves foras of the periodsdates 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 | |
| | | | | |
| | | | | |
| | | | | |
______________________________________________________________________________ |
| | | | | | | | |
| December 31, |
| 2017 | | 2016 | | 2015 |
Natural Gas (Bcf) | | | |
| | |
|
Proved developed reserves | 6,001 |
| | 5,500 |
| | 4,676 |
|
Proved undeveloped reserves(1) | 3,352 |
| | 2,781 |
| | 3,180 |
|
| 9,353 |
| | 8,281 |
| | 7,856 |
|
Crude Oil & NGLs (Mbbl)(2) | | | |
| | |
|
Proved developed reserves | 31,066 |
| | 20,442 |
| | 25,586 |
|
Proved undeveloped reserves(1) | 31,186 |
| | 28,730 |
| | 30,144 |
|
| 62,252 |
| | 49,172 |
| | 55,730 |
|
| | | | | |
Natural gas equivalent (Bcfe)(3) | 9,726 |
| | 8,576 |
| | 8,190 |
|
Reserve life index (in years)(4) | 14.2 |
| | 13.7 |
| | 13.6 |
|
(1)Proved undeveloped reserves for 2021, 2020 and 2019 include reserves drilled but uncompleted of 80 MMBOE, 40 MMBOE and 131 MMBOE, respectively. | |
(1) | Proved undeveloped reserves for 2017, 2016 and 2015 include reserves drilled but uncompleted of 807.4 Bcfe, 488.7 Bcfe and 937.4 Bcfe, respectively. |
| |
(2) | NGL reserves were less than 1.0% of our total proved equivalent reserves for 2017, 2016 and 2015, and 13.7%, 13.6% and 16.1% of our proved crude oil and NGL reserves for 2017, 2016 and 2015, respectively. |
| |
(3) | Natural gas equivalents are determined using a ratio of 6 Mcf of natural gas to 1 Bbl of crude oil, condensate or NGLs. |
| |
(4) | Reserve life index is equal to year-end proved reserves divided by annual production for the years ended December 31, 2017, 2016 and 2015, respectively. |
Our proved reserves totaled approximately 9,726 Bcfe at December 31, 2017, of which 96% were natural gas. This reserve level was up by 13%2021 increased 614 MMBOE, or 27 percent, from 8,576 Bcfe2,279 MMBOE at December 31, 2016. In 2017,2020, primarily due to the Merger, which increased our proved reserves by 672 MMBOE. During 2021, we added 1,236.1 Bcfe171 MMBOE of proved reserves through extensions, discoveries and other additions, primarily due to the positive results from our drilling and completion program in the Dimock field in northeast Pennsylvania. We also had a net upwarddownward revision of 928.5 Bcfe,62 MMBOE, which was primarily due to an upwarda net downward performance revision of 863.8 Bcfe primarily associated with positive drilling results in97 MMBOE, partially offset by an upward pricing revision of 34 MMBOE. During 2021, we produced 167 MMBOE.
At December 31, 2021, our Dimock field, which is located in northeastthe Marcellus Shale in Susquehanna County, Pennsylvania, and 103.0 Bcfe associated with higher commodity prices, partially offset by a downward revisioncontained approximately 75 percent of 38.3 Bcfe associated withour total proved undeveloped (PUD) reserves reclassifications as a result of the five year limitation. In 2017, we produced 685.3 Bcfe.reserves.
Our reserves are sensitive to natural gas and crude oilcommodity prices and their effect on the economic productive life of producing properties. Our reserves are based on the 12-month average natural gas, crude oil and NGL index prices,price for the respective commodity, calculated as the unweighted arithmetic average for the first day of the month price for each month during the year. Increases in commodity prices may result in a longer economic productive life of a property or result in more economically viable proved undeveloped reserves to be recognized. Decreases in prices may result in negative impacts of this nature.
For additional information regarding estimates of proved reserves, the auditaudits of such estimates by Miller and Lents, Ltd. (Miller(“Miller and Lents)Lents”) and DeGolyer and MacNaughton and other information about our reserves, including the risks inherent in our estimates of proved reserves, seerefer to the Supplemental Oil and Gas Information to the Consolidated Financial Statements included in Item 8 and “Risk Factors-OurFactors—Business and Operational Risks—Our proved reserves are estimates. Any material inaccuracies in our reserve estimates or underlying assumptions could cause the quantities and net present value of our reserves to be overstated or understated” in Item 1A.
Technologies Used In Reserves Estimates
We utilize various traditional methods to estimate our natural gas, crude oil and NGL reserves, including decline curve extrapolations, material balance calculations, volumetric calculations, and analogies and in some cases a combination of these methods. In addition, at times we may use seismic interpretations to confirm continuity of a formation in combination with traditional technologies; however, seismic interpretations are not used in the volumetric computation.
Internal Control
Our Senior Vice President, South RegionProduction and EngineeringOperations is the technical person responsible for our internal reserves estimation process and provides oversight of our corporate reservoir engineering department, which consists of three engineers, and the annual audit of our year-end reserves by Miller and Lents.10 engineers. He has a Bachelor of Science degree in Chemical Engineering, specializing in petroleum engineering, and over 3539 years of industry experience with positions of increasing responsibility in operations, engineering and evaluations. He has worked in the area of reserves and reservoir engineering for 2630 years and is a member of the Society of Petroleum Engineers.
Our reserves estimation process is coordinated by our corporate reservoir engineering department. Reserve information, including models and other technical data, are stored on secured databases on our network. Certain non-technical inputs used in the reserves estimation process, including commodity prices, production and development costs and ownership percentages, are obtained by other departments and are subject to testing as part of our annual internal control process. We also engage Miller and Lents and DeGolyer and MacNaughton, independent petroleum engineers, to perform an independent auditaudits of our estimated proved reserves. Upon completion of the process, the estimated reserves are presented to senior management.management and the Board of Directors.
Miller and Lents made independent estimates for 100%has audited 100 percent of our proved reserves estimates related to our Marcellus Shale properties, and DeGolyer and MacNaughton has performed an independent evaluation of estimated net reserves representing greater than 80 percent of the total future net revenue discounted at 10 percent attributable to our proved reserves estimates related to our Permian Basin, Anadarko Basin and other properties (excluding our Marcellus Shale properties). Each of Miller and Lents and DeGolyer and MacNaughton concluded, in theirits judgment, we have an effective system for gathering data and documenting information required to estimate our proved reserves and project our future revenues. Further, Miller and Lents has concluded (1) the reserves estimation methods employed by us were appropriate, and our classification of such reserves was appropriate to the relevant SEC reserve definitions, (2) our reserves estimation processes were comprehensive and of sufficient depth, (3) the data upon which we relied were adequate and of sufficient quality, and (4) the results of our estimates and projections are, in the aggregate, reasonable. A copy
Copies of the audit letterletters by Miller and Lents dated January 26, 2018, has31, 2022 and DeGolyer and MacNaughton dated January 17, 2022 have been filed as an exhibitexhibits to this Annual Report on Form 10-K.
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, 20172021, we had 3,538.7 Bcfe of PUD reserves associated with future development costs of $1.5$2.1 billion associated with 764 MMBOE of PUD reserves, which represents an increasea decrease of 585.4 Bcfe80 MMBOE compared to December 31, 2016. Approximately 94%2020. By the end of our PUD reserves are located in Susquehanna County, Pennsylvania. We2022, we expect to complete approximately 100% ofsubstantially all the work necessary to convert our PUD reserves associated with wells that were drilled but uncompleted wells by the end of 2018.at December 31, 2021 to proved developed reserves. Future development plans are reflective of the expected increase incurrent commodity pricesprice environment and have been established based on cash on hand, expected available cash flows from operations and availability under our revolving credit facility.operations. As of December 31, 2017,2021, all PUD reserves are expected to be drilled and completed within five years of initial disclosure of these reserves.
The following table is a reconciliation of the change in our PUD reserves (Bcfe)(MMBOE):
|
| | | | |
| Year Ended December 31, 20172021 |
Balance at beginning of period | 2,953.3844 |
|
Transfers to proved developed | (1,217.2(264) | ) |
Additions | 1,030.2131 |
|
Purchases of reserves in place | 97 | |
Revision of prior estimates | 772.4(44) |
|
| |
Balance at end of period | 3,538.7764 |
|
Changes in PUD reserves that occurred during the year were due to:
•transfer of 1,217.2 Bcfe264 MMBOE from PUD to proved developed reserves based on total capital expenditures of $382.4$565 million during 2017;2021;
•new PUD reserve additions of 1,030.2 Bcfe primarily131 MMBOE in the Dimock field in northeast Pennsylvania;
•purchases of reserves in place of 97 MMBOE, which are primarily related to the Merger and are primarily located in the Permian Basin; and
positive•downward PUD reserve revisions of 772.4 Bcfe resulting from positive44 MMBOE mainly due to performance revisions of 809.8 Bcfe associated within the drilling of longer lateral wells and completing more frac stages in our Dimock field in northeast Pennsylvania and positive price revisions of 0.9 Bcfe, partially offset by downward revisions of 38.3 Bcfe associated with PUD reclassifications as a result of the five year limitation.Marcellus Shale.
PRODUCTION, SALES PRICE AND PRODUCTION COSTS
The following table presents historical information about our total and average daily production volumes for oil, natural gas and NGLs; average oil, (including NGLs), average natural gas and crude oilNGL sales prices,prices; and average production costs per equivalent, includingequivalent:
| | | | | | | | | | | | | | | | | | | | |
| | Year Ended December 31, |
| | 2021(1) | | 2020 | | 2019 |
Production Volumes | | | | | | |
Oil (Mbbl) | | 8,150 | | | — | | | — | |
Natural gas (Bcf) | | 911 | | | 858 | | | 865 | |
NGL (Mbbl) | | 7,104 | | | — | | | — | |
Equivalents (MBOE) | | 167,113 | | | 142,954 | | | 144,167 | |
| | | | | | |
Average Daily Production Volumes | | | | | | |
Oil (Mbbl) | | 89 | | | — | | | — | |
Natural gas (Mmcf) | | 2,966 | | | 2,344 | | | 2,371 | |
NGL (Mbbl) | | 77 | | | — | | | — | |
Equivalents (MBOE) | | 660 | | | 391 | | | 395 | |
| | | | | | |
Average Sales Price | | | | | | |
Excluding Derivative Settlements | | | | | | |
Oil ($/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, located in northeast Pennsylvania, which representscontains 15 percent or more than 15% of our total proved reserves: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 | |
|
| | | | | | | | | | | |
| Year Ended December 31, |
| 2017 | | 2016 | | 2015 |
Production Volumes | |
| | |
| | |
|
Natural gas (Bcf) | |
| | |
| | |
|
Dimock field | 641.7 |
| | 581.9 |
| | 540.8 |
|
Total | 655.6 |
| | 600.4 |
| | 566.0 |
|
Oil (Mbbl)(1) | |
| | |
| | |
|
Total | 4,953 |
| | 4,454 |
| | 6,096 |
|
Equivalents (Bcfe) | |
| | |
| | |
|
Dimock field | 641.7 |
| | 581.9 |
| | 540.8 |
|
Total | 685.3 |
| | 627.1 |
| | 602.5 |
|
Natural Gas Average Sales Price ($/Mcf) | |
| | |
| | |
|
Dimock field | $ | 2.33 |
| | $ | 1.69 |
| | $ | 1.78 |
|
Total (excluding realized impact of derivative settlements) | $ | 2.30 |
| | $ | 1.70 |
| | $ | 1.81 |
|
Total (including realized impact of derivative settlements) | $ | 2.31 |
| | $ | 1.70 |
| | $ | 2.15 |
|
Oil Average Sales Price ($/Bbl) | |
| | |
| | |
|
Total (excluding realized impact of derivative settlements) | $ | 47.81 |
| | $ | 37.65 |
| | $ | 45.72 |
|
Total (including realized impact of derivative settlements) | $ | 48.16 |
| | $ | 37.30 |
| | $ | 45.72 |
|
Average Production Costs ($/Mcfe) | |
| | |
| | |
|
Dimock field | $ | 0.04 |
| | $ | 0.03 |
| | $ | 0.04 |
|
Total | $ | 0.11 |
| | $ | 0.11 |
| | $ | 0.18 |
|
| |
(1) | Includes NGLs which represent less than 1.0% of our equivalent production for all years presented and 10.3%, 9.9%, and 11.0% of our crude oil production for the years ended December 31, 2017, 2016 and 2015, respectively. |
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 and mineral fee acreage at December 31, 2017:2021: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| 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 | |
|
| | | | | | | | | | | | | | | | | |
| Developed | | Undeveloped (1) | | Total |
| Gross | | Net | | Gross | | Net | | Gross | | Net |
Leasehold acreage | 382,900 |
| | 301,230 |
| | 876,380 |
| | 780,960 |
| | 1,259,280 |
| | 1,082,190 |
|
Mineral fee acreage | 75 |
| | 19 |
| | 170,054 |
| | 148,120 |
| | 170,129 |
| | 148,139 |
|
Total | 382,975 |
| | 301,249 |
| | 1,046,434 |
| | 929,080 |
| | 1,429,409 |
| | 1,230,329 |
|
| |
(1) | Includes leasehold and mineral fee net acreage of 606,959 and 147,812, respectively, associated with deep formations located in West Virginia and Virginia that were retained as part of the divestiture that closed in the third quarter of 2017. All of this acreage is held by production from the shallow formations. |
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 event that production is not established ordrilling 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 takehad no action to extend or renew the terms of our leases, our netproved undeveloped reserves recorded on undeveloped acreage that will expire overwere scheduled for development beyond the next three years asexpiration dates of December 31, 2017 is 36,983, 10,880 and 34,380 for the years ending December 31, 2018, 2019 and 2020, respectively.
We expect to retain substantially allundeveloped acreage or outside of our expiring acreage either through drilling activities, renewal of the expiring leases or through the exercise of extension options. As of December 31, 2017, approximately 23% of our expiring acreage disclosed above is located in our primary areas of operation where we currently expect to continue development activities and/or extend the lease terms.operating area.
WELL SUMMARY
The following table presents our ownership in productive oil and natural gas and crude oil wells at December 31, 2017.2021. This summary includes crude oil and natural gas and crude oil wells in which we have a working interest:
|
| | | | | |
| Gross | | Net |
Natural gas | 803 |
| | 709.9 |
|
Crude oil | 309 |
| | 268.7 |
|
Total(1) | 1,112 |
| | 978.6 |
|
| | | | | | | | | | | | | | |
| | 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.
| |
(1) | Total percentage of gross operated wells is 85.3%. |
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, | | Year Ended December 31, |
| 2017 | | 2016 | | 2015 | | 2021 | | 2020 | | 2019 |
| Gross | | Net | | Gross | | Net | | Gross | | Net | | Gross | | Net | | Gross | | Net | | Gross | | Net |
Development Wells | | | | | | | | | | | | Development Wells | | | | | | | | | | | |
Productive | 104 |
| | 93.2 |
| | 76 |
| | 76.0 |
| | 106 |
| | 97.9 |
| Productive | 114 | | | 99.9 | | | 74 | | | 64.3 | | | 96 | | | 94.0 | |
Dry | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| Dry | — | | | — | | | — | | | — | | | — | | | — | |
Exploratory Wells | | | | | | | | | | | | |
Productive | — |
| | — |
| | — |
| | — |
| | 1 |
| | 1.0 |
| |
Dry | 1 |
| | 1.0 |
| | — |
| | — |
| | — |
| | — |
| |
| Total | 105 |
| | 94.2 |
| | 76 |
| | 76.0 |
| | 107 |
| | 98.9 |
| Total | 114 | | | 99.9 | | | 74 | | | 64.3 | | | 96 | | | 94.0 | |
| | | | | | | | | | | | | | | | | | | | | | | |
Acquired Wells | — |
| | — |
| | — |
| | — |
| | 1 |
| | 1.0 |
| Acquired Wells | 7,266 | | | 1,715.3 | | | — | | | — | | | — | | | — | |
During the year ended December 31, 2017,2021, we completed 5014 gross wells (44.3(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, 2017,2021, which are not included in the above table:
|
| | | | | | | | | | | | |
| | Drilling In Progress | | Drilled But Uncompleted |
| | Gross | | Net | | Gross | | Net |
Development wells | | 4 |
| | 4.0 |
| | 36 |
| | 32.6 |
|
Exploratory wells | | 3 |
| | 3.0 |
| | — |
| | — |
|
Total | | 7 |
| | 7.0 |
| | 36 |
| | 32.6 |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | 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 are made at the time of lease acquisition. CompleteWe conduct more complete investigations are made prior to the consummation of an acquisition of producing properties and before commencement of drilling operations on undeveloped properties.
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 extensiveconcentrated acreage positionpositions and our access to both third-party and company-owned gathering and pipeline infrastructure in Pennsylvania,our primary operating areas, along with our expected activity level and the related services and equipment that we have secured for the upcoming years, enhance our competitive position over other producers who do not have similar systems or services in place.
Major Customers
During the yearsyear ended December 31, 2017, 2016 and 2015, two2021, no customer accounted for more than 10 percent of our total sales. During the year ended December 31, 2020, three customers accounted for approximately 18%21 percent, 16 percent and 11%, two customers accounted for approximately 19% and 10% and two customers accounted for approximately 16% and 14%, respectively,12 percent of our total sales. If any one of our major customers were to stop purchasing our production, we believe there are a number of other purchasers to whom we could sell our production. If multiple significant customers were to stop purchasing our production, we believe there could be some initial challenges, but we have ample alternative markets to handle any sales disruptions.
We doregularly monitor the creditworthiness of our customers and may require parent company guarantees, letters of credit or prepayments when necessary. Historically, losses associated with uncollectible receivables have not believe that the loss of any of these customers would have a material adverse effect on us because alternative customers are readily available.been significant.
Seasonality
Demand for natural gas has historically been seasonal, with peak demand and typically higher prices occurring during the colder winter months.
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, and regulating the location of wells, the method of drilling and casing wells, the surface use and restoration of properties on which wells are drilled and the plugging and abandoning of wells. Our operations are also subject to various conservation laws and regulations. These include the regulation of the size of drilling and spacing units or proration units, the density of wells that may be drilled in a given field and the unitization or pooling of oil and natural gas properties. Some states allow the forced pooling or integration of tracts to facilitate exploration while other states rely on voluntary pooling of lands and leases. In addition, state conservation laws establish maximum rates of production from oil and natural gas wells, generally prohibiting the venting or
flaring of natural gas and imposing certain requirements regarding the ratability of production. The effect of these regulations is to limit the amounts of oil and natural gas we can produce from our wells, and to limit the number of wells or the locations where we can drill. Because these statutes, rules and regulations undergo constantfrequent 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 itsour cost of doing business and, consequently, affects itsour 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 (NGA)(the “NGA”), the U.S. Natural Gas Policy Act of 1978 (NGPA),(the “NGPA”) and the regulations promulgated under those statutes, the U.S. Federal Energy Regulatory Commission (FERC)(the “FERC”) regulates the interstate sale for resale of natural gas and the transportation of natural gas in interstate commerce, although facilities used in the production or gathering of natural gas in interstate commerce are generally exempted from FERC jurisdiction. Effective beginning in January 1993, the Natural Gas Wellhead Decontrol Act deregulated natural gas prices for all “first sales” of natural gas, which definition covers all sales of our own production. In addition, as part of the broad industry restructuring initiatives described below, the FERC granted to all producers such as us a “blanket certificate of public convenience and necessity” authorizing the sale of natural gas for resale without further FERC approvals. As a result of this policy, all of our produced natural gas is sold at market prices, subject to the terms of any private contracts that may be in effect. In addition, under the provisions of the Energy Policy Act of 2005 (2005 Act)(“2005 Act”), the NGA was amended to prohibit any forms of market manipulation in connection with the purchase or sale of natural gas. Pursuant to the 2005 Act, the FERC established regulations intended to increase natural gas pricing transparency by, among other things, requiring market participants to report their gas sales transactions annually to the FERC. The 2005 Act also significantly increased the penalties for violations of the NGA and NGPA and the FERC’s regulations thereunder up to $1,000,000$1 million per day per violation. This maximum penalty authority established by statute has been and will continue to be adjusted periodically for inflation. The current maximum penalty is over $1 million per day per violation. In 2010, the FERC issued Penalty Guidelines for the determination of civil penalties and procedure under its enforcement program.
Some of our pipelines were subject to regulation byUnder the FERC during 2017. Until September 29, 2017, we owned an intrastateNGPA, natural gas pipeline through our former wholly-owned subsidiary, Cranberry Pipeline Corporation, that provided interstate transportation and storage services pursuant to Section 311 ofgathering facilities are expressly exempt from FERC jurisdiction. What constitutes “gathering” under the NGPA as well as intrastate transportationhas evolved through FERC decisions and storage servicesjudicial review of such decisions. We believe that were regulated byour
gathering and production facilities meet the West Virginia Public Service Commission. We no longer own any interest in Cranberry Pipeline Corporation, and do not operate any natural gas pipelines subject to FERC's jurisdiction.
In 2012, we executed a precedent agreement with Constitution, at the time a wholly owned subsidiary of Williams Partners L.P.,test for 500,000 Dth per day of pipeline capacity and acquired a 25% equity interest in a pipeline to be constructed in the states of New York and Pennsylvania. On December 2, 2014, the FERC issued a certificate of public convenience and necessity, authorizing the construction and operation of the 124‑mile pipeline project that, once completed, will provide 650,000 Dth per day of pipeline capacity. While FERC has issued the certificate, the project scope or timeline for construction and eventual in-service date has been impacted by the public regulatory permitting process. Currently, the in-service date for Constitution cannot be reasonably estimated. If placed into service, the project pipeline will be an interstate pipeline subject to full regulation by FERCnon-jurisdictional “gathering” systems under the NGA. See Note 4 of the Notes to the Consolidated Financial Statements for more information about the legalNGPA and regulatory actions involving Constitution.
Additionally, in 2014 we executed a precedent agreement with Transcontinental Gas Pipe Line Company, LLC (Transco) for 850,000 Dth per day of pipeline capacity and acquired a 20% equity interest in Meade, which was formed to construct a pipeline with Transco from Susquehanna County, Pennsylvania to an interconnect with Transco's mainline in Lancaster County, Pennsylvania. The proposed pipeline will be an interstate pipeline subject to full regulation by the FERC under the NGA. Transco filed an application for a certificate of public convenience and necessity with the FERC on March 31, 2015. On February 3, 2017, the FERC issued a certificate of public convenience and necessity, authorizing the construction and operation of the pipeline project and the project is under construction, with a current expected in-service date of mid-2018.
Our production and gatheringthat our facilities are not subject to jurisdiction of the FERC; however,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 nevertheless continue to be affected by intrastate and interstate gas transportation regulation because the cost of transporting the natural gas once sold to the consuming market is a factor in the prices we receive. Beginning with Order No. 436 in 1985 and continuing through Order No. 636 in 1992 and Order No. 637 in 2000, the FERC has adopted a series of rulemakingsrule makings that have significantly altered the transportation and marketing of natural gas. These changes were intended by the FERC to foster competition by, among other things, requiring interstate pipeline companies to separate their wholesale gas marketing business from their gas transportation business and by increasing the transparency of pricing for pipeline services. The FERC has also established regulations governing the relationship of pipelines with their marketing affiliates, which essentially require that designated employees function independently of each other and that certain information not be shared. The FERC has also
implemented standards relating to the use of electronic data exchange by the pipelines to make transportation information available on a timely basis and to enable transactions to occur on a purely electronic basis.
In light of these statutory and regulatory changes, most pipelines have divested their natural gas sales functions to marketing affiliates, which operate separately from the transporter and in direct competition with all other merchants. Most pipelines have also implemented the large‑scale divestiture of their natural gas gathering facilities to affiliated or non‑affiliatednon-affiliated companies. Interstate pipelines are required to provide unbundled, open and nondiscriminatory transportation and transportation‑related services to producers, gas marketing companies, local distribution companies, industrial end users and other customers seeking such services. As a result of the FERC requiring natural gas pipeline companies to separate marketing and transportation services, sellers and buyers of natural gas have gained direct access to pipeline transportation services, and are better able to conduct business with a larger number of counterparties. We believe these changes generally have improved our access to markets while, at the same time, substantially increasing competition in the natural gas marketplace. We cannot predict what new or different regulations the FERC and other regulatory agencies may adopt, or what effect subsequent regulations may have on our activities. Similarly, we cannot predict what proposals, if any, that affect the oil and natural gas industry might actually be enacted by the U.S. Congress or the various state legislatures and what effect, if any, such proposals might have on us. Further, we cannot predict whether the recent trend toward federal deregulation of the natural gas industry will continue or what effect future policies will have on our sale of gas.
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‑(“Dodd‑Frank Act)Act”) in July 2010, the Commodity Futures Trading Commission (CFTC)(the “CFTC”) has promulgated regulations to implement statutory requirements for swap transactions, including certain options. The CFTC regulations are intended to implement a regulated market in which most swaps are executed on registered exchanges or swap execution facilities and cleared through central counterparties. In addition, all swap market participants are subject to new reporting and recordkeeping requirements related to their swap transactions. We believe that our use of swaps to hedge against commodity exposure qualifies us as an end‑user, exempting us from the requirement to centrally clear our swaps. Nevertheless, changes to the swap market as a result of Dodd‑Frank implementation could significantly increase the cost of entering into new swaps or maintaining existing swaps, materially alter the terms of new or existing swap transactions and/or reduce the availability of new or existing swaps. If we reduce our use of swaps as a result of the Dodd‑Frank Act and regulations, our results of operations may become more volatile and our cash flows may be less predictable.
Federal Regulation of Petroleum
Our salesSales of crude oil and NGLs are not regulated and are made at market prices. However, the price received from the sale of these products is affected by the cost of transporting the products to market. Much of that transportation is through interstate common carrier pipelines, which are regulated by the FERC under the Interstate Commerce Act (ICA)(“ICA”). The FERC requires that pipelines regulated under the ICA file tariffs setting forth the rates and terms and conditions of service and that such service not be unduly discriminatory or preferential.
Effective January 1, 1995, the FERC implemented regulations generally grandfathering all previously approved interstate transportation rates and establishing an indexing system for those rates by which adjustments are made annually based on the rate of inflation, subject to certain conditions and limitations. These regulations may increase or decrease the cost of transporting crude oil and NGLs by interstate pipeline, although the annual adjustments may result in decreased rates in a given year. Every five years, the FERC must examine the relationship between the annual change in the applicable index and the
actual cost changes experienced in the oil pipeline industry. In December 2015, to implement this required five‑year re‑determination,redetermination, the FERC established an upward adjustment in the index to track oil pipeline cost changes and determined that the Producer Price Index for Finished Goods plus 1.23%1.23 percent should be the oil pricing index 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 generation, storage, handling, emission, transportationprotection of the environment, public health, natural resources and discharge of materials into the environment.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. NoWe can provide no assurance can be given 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 controlling the discharge of materialsregulating emissions into the environment, requiringatmosphere, discharges of pollutants into waters, underground injection of wastewater, the generation, storage, transportation and disposal of waste materials and removal and cleanup of materials that may harm the environment, or otherwiseand those relating to the protection of the environment.occupational health and safety.
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 hazardous wastes that are alreadyhazardous wastes subject to the FederalU.S. federal Resource Conservation and Recovery Act (RCRA)(the “RCRA”) and comparable state statutes.statutes, as well as wastes that are exempt from such regulation. The U.S. Environmental Protection Agency (EPA) has limited(the “EPA”) limits the disposal options for certain hazardous wastes. It is possible that certain wastes currently exempt from treatmentregulation as hazardous wastes may in the future be designated as hazardous wastes under RCRA or other applicable statutes. For example, in December 2016, the EPA and environmental groups entered into a consent decree to address the EPA’s alleged failure to timely assess its RCRA Subtitle D criteria regulations exempting certainthe need to regulate exploration and production related oil and gas wastes exempt from regulation as hazardous wastes under RCRA.RCRA under Subtitle D applicable to non-hazardous solid waste. The consent decree requiresrequired the EPA to propose a rulemaking by March 2019 for revision of certain Subtitle D criteria regulations pertaining to oil and gas wastes or to sign a determination that revision of the regulations is not necessary. WeIn April 2019, the EPA issued its determination that based on its review, including consideration of state regulatory programs, it was not necessary at the time to revise Subtitle D regulations to address the management of oil and gas wastes. In the future, we could therefore, be subject to more rigorous and costly disposal requirements in the future than we encounter today.
Superfund.The U.S. Comprehensive Environmental Response, Compensation, and Liability Act (CERCLA)(“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 definition of hazardous substances.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 Federalfederal Oil Pollution Act of 1990 (OPA)(the “OPA”) and resultingimplementing 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 United States.U.S. The term “waters of the United States”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 substantially complyare in substantial compliance with the Oil Pollution Act and related federal regulations.regulations to the extent applicable to our operations.
Endangered Species Act.The U.S. federal Endangered Species Act (ESA) restricts(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 affectdesignate 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 habitats. While somehabitat 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 operationsoperations. 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 located in areas that are designated as habitats for endangered or threatened species, we believe that we are in substantial compliancesignificant. Listing petitions continue to be filed with the ESA, nor are we aware of any proposed listings that will affectFWS which could impact our operations. However,Many non-governmental organizations (“NGOs”) work closely with the designationFWS regarding the listing of previously unidentifiedmany species, including species with broad and even nationwide ranges. The listing of the Mexican Long Nosed Bat, whose habitat includes the Permian Basin where we operate, and the Dunes Sagebrush Lizard in the Permian Basin, are examples of the NGOs’ influence on ESA listing decisions.
On December 1, 2020, the FWS proposed to list the Peppered Chub as endangered under the ESA. The 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 threatenedif the FWS declares the basins of the South Canadian river to be critical habitat. The increase in endangered species couldlistings, 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 or become subject to operating restrictions or bans in the affected areas.costs.
Clean Water Act.The FederalU.S. federal Water Pollution Control Act (Clean(the “Clean Water Act)Act”) and resultingimplementing regulations, which are primarily implementedexecuted through a system of permits, also govern the discharge of certain contaminantspollutants into waters of the United States.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.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 FederalU.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 permits.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 penalties for failureany failures to comply strictly with air regulations or permits. RegulatoryHowever, 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 theapplicable 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. In 2012,Two examples are the EPA published finalEPA’s source aggregation rule and the EPA’s New Source Performance Standards (NSPS)(“NSPS”) and National Emission Standards for Hazardous Air Pollutants (NESHAP)(“NESHAP”). In June 2016, the EPA published a final rule concerning aggregation of sources that affects source determinations for air permitting in the oil and gas industry, and, as a result, aggregating our oil and gas facilities for permitting may result in increased complexity and cost of, and time required for, air permitting. Particularly with respect to obtaining pre-construction permits, the final aggregation rule could add costs and cause delays in operations.
In 2012, the EPA published final NSPS and NESHAP that amended the existing NSPS and NESHAP standards for oil and gas facilities and created new NSPS standards forthe oil and natural gas production, transmission and distribution facilities.sector. In June 2016, the EPA published a final rule that updatesupdated and expandsexpanded the NSPS by setting additional emissions limits for volatile organic compounds and regulating methane emissions for new and modified sources in the oil and gas industry. In addition, in June 2017, the EPA proposed a two yeartwo-year stay of certain requirements contained in the June 2016 rule and, in November 2017, issued a notice of data availability in support of the stay proposal and provided a 30-day comment period on the information provided. TheIn March 2018, the EPA also published a final rule in Junethat amended two narrow provisions of the NSPS, removing the requirement for completion of delayed repair during emergency or unscheduled vent blowdowns. In September 2020, the EPA published a final rule amending the 2012 and 2016 concerning aggregation of sources that affects source determinationsNSPS for air permitting in the oil and natural gas industry. sector that removed transmission and storage sources from the oil and natural gas industry source category and rescinded the methane requirements applicable to the production and processing sources. On June 30, 2021, President Biden signed into law a joint Congressional resolution under the Congressional Review Act disapproving the September 2020 rule amending the EPA’s 2012 and 2016 NSPS standards for the oil and natural gas sector. On November 15, 2021, the EPA proposed rules to reduce methane emissions from both new and existing oil and natural gas industry sources. For additional information, please read “Risk Factors—Legal, Regulatory and Governmental Risks— Federal and state legislation, judicial actions and regulatory initiatives related to oil and gas development and the use of hydraulic fracturing could result in increased costs and operating restrictions or delays and adversely affect our business, financial condition, results of operations and cash flows” in Item 1A.
In October 2015, the EPA adopted a lower national ambient air quality standard for ozone. The revised standard could resultresulted in additional areas being designated as ozone non-attainment, which could lead to requirements for additional emissions control equipment and the imposition of more stringent permit requirements on facilities in those areas. The EPA anticipates promulgatingcompleted its final area designations under the new ozone standard in the first half ofJuly 2018. If we are unable to comply with air pollution regulations or to obtain permits for emissions associated with our operations, we could be required to forego construction, modification or implement modifications to certain operations. These regulations may also increase compliance costs for some facilities we own or operate, and result in administrative, civil and/or criminal penalties for non-compliance.noncompliance. Obtaining permits may delay the development of our oil and natural gas projects, including the construction and operation of facilities.
Safe Drinking Water Act.The U.S. Safe Drinking Water Act (SDWA)(“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.Many 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, from the developing shale plays, 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 regardingaffecting 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. For additional information aboutIn addition, if existing laws and regulations with regard to hydraulic fracturing are revised or reinterpreted or if new laws and related environmental matters, please read “Risk Factors-Federalregulations 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 legislationappellate 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 regulatory initiatives related 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 oilthe 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 gas development, includingbased 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 result in increased costshave a material impact on our operations.
Greenhouse Gas and operating restrictions or delays” in Item 1A.
Greenhouse Gas.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 StatesNations 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 but not enacted, legislation designed to reduce emissions of greenhouse gases fromGHGs in recent years, it has not adopted any significant GHG legislation. However, the 2021 Infrastructure and Investment Jobs Act passed by Congress on November 6, 2021 included measures aimed at decarbonization to address climate change, including funding for replacing transit vehicles, including buses, with zero- and low-emission vehicles and for the deployment of an electric vehicle charging network nationwide. This legislation, and other future laws, that promote a shift toward electric vehicles could adversely affect the demand for our products. Moreover, in the absence of federal GHG legislation, a number of state and regional efforts have emerged. These include measures aimed at tracking and/or reducing GHG emissions through cap-and-trade programs, which typically require major sources within the United States between 2012of GHG emissions, such as electric power plants, to acquire and 2050.surrender emission allowances in return for emitting GHGs. In addition, manya coalition of over 20 governors of U.S. states formed the U.S. Climate Alliance to advance the objectives of the Paris Agreement, and several U.S. cities have already taken legal measurescommitted to reduceadvance the objectives of the Paris Agreement at the state or local level as well. To this end, 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 greenhouse gases, primarily throughnew zero-emission passenger vehicles and trucks sold in California over time, with a targeted ban of the planned developmentsale of greenhouse gas emission inventories and/or regional greenhouse gas cap and trade programs. Thenew gasoline vehicles by 2035.
At the federal level, the EPA has also begun to regulate carbon dioxide and other greenhouse gas emissionsGHGs under existing provisions of the Clean Air Act. ThisIn December 2009, the EPA published its findings that emissions of GHGs present an endangerment to public health and the environment because emissions of such gases are contributing to the warming of the earth’s atmosphere and other climatic changes. Based on these findings, the EPA adopted regulations under existing provisions of the federal Clean Air Act that establish Prevention of Significant Deterioration (“PSD”) and Title V permit reviews for GHG emissions from certain large 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 regulationcertain 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. A 2016 information collection request made to oil and natural gas facilities by EPA in connection with its intention at the time to regulate methane emissions from existing sources was withdrawn in March 2017.
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. Please read “Risk Factors-Climate changeAt this time, it is not possible to quantify the impact of any such future developments on our business.
Occupational Safety and climate change legislation and regulatory initiatives could result in increased operating costs and decreased demand for the oil and natural gas that we produce” in Item 1A.
OSHAHealth Act and Other Laws and Regulations.We are subject to the requirements of the U.S. federal Occupational Safety and Health Act (OSHA),(the “Occupational Safety and Health Act”) and comparable state laws. The OSHAOccupational 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 OSHA,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.
EmployeesHuman 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, 2017,2021, with the addition of employees as a result of the Merger, we had 308 employees. In addition, we936 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 160a 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-ownedwholly owned subsidiary, GasSearch Drilling Services Corporation. We recognize thatCorporation (“GDS”), which is a service company engaged in water hauling and site preparation exclusively for our success is significantly influenced by the relationship we maintain withMarcellus Shale operations. Of our employees. Overall,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 satisfactory. Ourfavorable. None of our employees are not represented bypursuant 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.cabotog.com,www.coterra.com, our annual reports on Form 10‑K, quarterly reports on Form 10‑Q, current reports on Form 8‑K and all amendments to those reports as soon as reasonably practicable after such material is electronically filed with or furnished to the Securities and Exchange Commission (SEC). Information on our website is not a part of this report.SEC. In addition, the SEC maintains an Internet site at www.sec.gov that contains reports, proxy and information statements and other information filed by us. The publicInformation on our website is not a part of, and is not incorporated into, this report or any other report we may read and copy materials that we file with or furnish to the SEC, atwhether before or after the SEC’s Public Reference Room located at 100 F Street, NE, Washington, DC 20549. Information regarding the operationdate of the Public Reference Room canthis report and irrespective of any general incorporation language therein. Furthermore, references to our website URLs are intended to be obtained by calling the SEC at 1‑800‑SEC‑0330.inactive textual references only.
Corporate Governance Matters
Our Corporate Governance Guidelines, Corporate Bylaws, Audit Committee Charter, Compensation Committee Charter, Corporate Governance and NominationsSocial Responsibility Committee Charter, Code of Business Conduct and Environment, Health & Safety and Environmental Affairs Committee Charter are available on our website at www.cabotog.com,www.coterra.com, under the “Governance”“Corporate Governance” section of “About Cabot.“Investors.” Requests for copies of these documents can also be made in writing to Investor Relations at our corporate headquarters at Three Memorial City Plaza, 840 Gessner Road, Suite 1400, Houston, Texas 77024.
ITEM 1A. RISK FACTORS
Natural gasBusiness and oilOperational 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 oilNGLs that we sell. Lower commodity prices may reduce the amount of oil, natural gas and oilNGLs that we can produce economically. Historically, natural gas and oilcommodity prices have been volatile, with prices fluctuating widely, and they are likely to continue to be volatile. Because our reserves are predominantly natural gas (approximately 96%For example, the WTI oil prices in 2021 ranged from a high of equivalent proved reserves), changes in$84.65 to a low of $47.62 per Bbl and NYMEX natural gas prices havein 2021 ranged from a more significant impact on our financial results than oil prices.high of $23.86 (during Winter Storm Uri) to a low of $2.43 per Mmbtu. Any substantial or extended decline in future natural gas or crude oilcommodity prices would have a material adverse effect on our future business, financial condition, results of operations, cash flows, liquidity or ability to finance planned capital expenditures and commitments. Furthermore, substantial, extended decreases in natural gas and crude oilcommodity prices may cause us to delay or postpone a significant portion of our exploration development and exploitationdevelopment projects or may render such projects uneconomic, which may result in significant downward adjustments to our estimated proved reserves and could negatively impact our ability to borrow and cost of capital and our ability to access capital markets, increase our costs under our revolving credit facility and limit our ability to execute aspects of our business plans. See "Risk Factors-Future natural gas and oilRefer to “Future commodity price declines may result in write-downs of the carrying amount of our oil and gas properties, which could materially and adversely affect our results of operations."”
Prices for natural gas and oil are subject to wideWide fluctuations in response tocommodity prices may result from relatively minor changes in the supply of and demand for oil, natural gas and oil,NGLs, market uncertainty and a variety of additional factors that are beyond our control. These factors include but are not limited to the following:
•the levels and location of oil, natural gas and oilNGLs 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 oil;NGLs, which has been significantly impacted by the COVID-19 pandemic, particularly during 2020;
•weather conditions;conditions and seasonal trends;
•political, economic or health conditions or hostilities in oil, natural gas and oilNGL producing regions, including the Middle East, Africa, South America and South America;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 the Organization of Petroleum Exporting Countries and other exporting nationsOPEC+ 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 localized areas that may affectlocal areas;
•inventory storage levels and the realized price forcost and availability of storage and transportation of oil, natural gas and oil;NGLs;
inventory storage levels;
•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 natural gas;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 the future prices of natural gas and oil.commodity prices. If natural gas and oilcommodity prices remain low or continue to 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 and oil wells is a high-risk activity.
Our growth is materially dependent upon the success of our drilling program. Drilling for oil and natural gas and oil involves numerous risks, including the risk that no commercially productive natural gas or oil 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 natural gas and oilcommodity prices;
•unexpected drilling conditions, pressure or irregularities in formations;
•equipment failures or accidents;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 be dependentdepend 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 oil 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 oil.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 understatedunderstated.
Reserve engineering is a subjective process of estimating underground accumulations of oil and natural gas and oil that cannot be measured in an exact manner. The process of estimating quantities of proved reserves is complex and inherently imprecise, and the 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 natural gas and oilassumptions 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 and oil that are ultimately recovered, and such variances may be material. Any significant variance could reduce the estimated quantities and present value of our reserves.
You should not assume that the present value of future net cash flows from our proved reserves is the current market value of our estimated natural gas and oil 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. The present value of future cash flows are based on $2.33 per Mcf of natural gas, $20.64 per Bbl of NGLs and $49.26 per Bbl of oil as of December 31, 2017. 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%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 natural gas and oilcommodity price declines may result in write-downs of the carrying amount of our oil and gas properties, which could materially and adversely affect our results of operations.
The value of our oil and gas properties depends on prices of natural gas and crude oil.commodity prices. Declines in these prices as well as increases in development costs, changes in well performance, delays in asset development or deterioration of drilling results may result in our having to make material downward adjustments to our estimated proved reserves, and could result in an impairment charge and a corresponding write-down of the carrying amount of our oil and natural gas properties. Because our reserves are predominately natural gas (approximately 96% of equivalent proved reserves), changes in natural gas prices have a more significant impact on our financial results than oil prices.
We evaluate our oil and gas properties for impairment on a field-by-field basis whenever events or changes in circumstances indicate a property's carrying amount may not be recoverable. We compare expected undiscounted future cash flows to the net book value of the asset. If the future undiscounted expected cash flows, based on our estimate of future natural gas and oilcommodity prices, operating costs and anticipated production from proved reserves and risk-adjusted probable and possible reserves, are lower than the net book value of the asset, the capitalized cost is reduced to fair value. Commodity pricing is estimated by using a combination of assumptions management uses in its budgeting and forecasting process as well as historical and current prices adjusted for geographical location and quality differentials, as well as other factors that management believes will impact realizable prices. In the event that commodity prices decline, there could be a significant revision into the future.
Our producing properties are geographically concentrated in the Marcellus Shale in northeast Pennsylvania, making us vulnerable to risks associated with operating in one major geographic area.
Our producing properties are geographically concentrated in the Marcellus Shale in northeast Pennsylvania. At December 31, 2017, 97%carrying amounts of our proved developed reservesoil and 94% of our total equivalent production were attributable our properties located in the Marcellus Shale, and we expect that concentration to increase slightly in 2018 as a result of the expected sales of our remaining Texasgas properties in the first half of 2018. As a result of this concentration, we may be disproportionately exposed to the impact of regional supply and demand factors, state and local political forces and governmental regulation, processing or transportation capacity constraints, market limitations, severe weather events, water shortages or other conditions or interruption of the processing or transportation of oil, natural gas or NGLs in the region. future.
Our future performance depends on our ability to find or acquire additional oil and natural gas and oil reserves that are economically recoverable.
In general, the production rate of naturaloil and gas and oil properties declines as reserves are depleted, with the rate of decline depending on reservoir characteristics. Unless we successfully replace the reserves that we produce, our reserves will decline, eventually resulting in a decrease in oil and natural gas and oil production and lower revenues and cash flow from operations. Our future natural gas and oil production is, therefore, highly dependent on our level of success in finding or acquiring additional reserves. We may not be able to replace reserves through our exploration, development and exploitation activities or by acquiring properties at acceptable costs. Low natural gas and oilcommodity prices may further limit the kinds of reserves that we can develop and produce economically.
Our reserve report estimatesWe estimate that production from our proved developed reserves as of December 31, 20172021 will decrease at a rate of 12%, 25%, 18%24 percent, 17 percent and 14%13 percent during 2018, 2019, 20202023, 2024 and 2021, respectively.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 not classified as proved developed producing will impact these rates of decline. Because
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 oilNGLs in commercial quantities and the inability to fully produce discovered reserves.
We have substantial capital requirements, and we may not be able to obtain needed financing on satisfactory terms, if at all.
We rely upon 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 and our financial condition. 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 collectabilityThe development of our trade receivablesproved undeveloped reserves may take longer and cause our commodity hedging counterparties to be unable to perform their obligations or to seek bankruptcy protection. Future challenges in the economy could also lead to reduced demand for natural gas which could have a negative impact on our revenues.
Risks associated with our debt and the provisionsmay require higher levels of our debt agreements could adversely affect our business, financial position and results of operations.capital expenditures than we currently anticipate.
As of December 31, 2017, we had2021, approximately $1.5 billion of debt outstanding and we may incur additional indebtedness in the future. Increases in our level of indebtedness may:
require us to use a substantial portion26 percent of our cash flowestimated proved reserves (by volume) were undeveloped. These reserve estimates reflect our plans to make debt service payments, which will reducecapital 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 funds that would otherwise be available for operationsestimated future development costs associated with our PUD reserves may not equal our actual costs, development may not occur as scheduled and future business opportunities;
limit our operating flexibility due to financial and other restrictive covenants, including restrictions on incurring additional debt, making certain investments, and paying dividends;
place us at a competitive disadvantage compared to our competitors with lower debt service obligations;
depending on the levelsresults of our outstanding debt, limitdevelopment activities may not be as estimated. If we choose not to develop our abilityPUD reserves, or if we are not otherwise able to obtain additional financing for working capital, capital expenditures, general corporate and other purposes; and
increase our vulnerability to downturns in our business or the economy, including declines in prices for natural gas and oil.
In addition, the margins we pay under our revolving credit facility depend on our leverage ratio. Accordingly, increases in the amount of our indebtedness without corresponding increases in our consolidated EBITDAX, or decreases in our EBITDAX without a corresponding decrease in our indebtedness, may result in an increase in our interest expense.
Our debt agreements also require compliance with covenants to maintain specified financial ratios. If the price that we receive for our natural gas and oil production deteriorates from current levels or continues for an extended period, 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 decreased natural gas and oil 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 assure you thatdevelop them successfully, we will be ablerequired to successfully execute any of these strategies, and such strategiesremove them from our reported proved reserves. In addition, under the SEC’s reserve reporting rules, because PUD reserves generally 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.”
The borrowing base under our revolving credit facility mayrecorded only if they relate to wells scheduled to be reduced, which could limit us in the future.
The borrowing base under our revolving credit facility is currently $3.2 billion, and lender commitments under our revolving credit facility are $1.7 billion. The borrowing base is redetermined annually under the termsdrilled within five years of the revolving credit facility on April 1. In addition, eitherdate of booking, we or the banks may request an interim redetermination twice a year or in conjunction with certain acquisitions or sales of oil and gas properties. Our borrowing base may decrease as a result of lower natural gas or oil prices, operating difficulties, declines in reserves, lending requirements or regulations, the issuance of new indebtedness or for any other reason. In the event of a decrease in our borrowing base due to declines in commodity prices or otherwise, our
ability to borrow under our revolving credit facility may be limited and we could be required to repayremove any indebtedness in excess of the redetermined borrowing base. In addition, we mayPUD reserves that are no longer planned to be unable to access the equity or debt capital markets, including the market for senior unsecured notes, to meet our obligations, including any such debt repayment obligations.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 are dependent upondepend on our ability to identify optimal strategies for our business. In developing our business plan,plans, we considered allocating capital and other resources to various aspects of our businessesbusiness including well-development (primarily drilling), reserve acquisitions, exploratory activity, corporate items and other alternatives. We also consideredconsider our likely sources of capital. Notwithstanding the determinations made in the development of our 20182022 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 20182022 plan, and our failure to recognize or respond to those changes may limit our ability to achieve our objectives.
Negative public perception regarding us and/or our industry could have an adverse effect on our operations.
Negative public perception regarding us and/or our industry resulting from, among other things, concerns raised by advocacy groups about hydraulic fracturing, oil spills, greenhouse gas or methane emissions and explosions of natural gas transmission lines, may lead to increased regulatory scrutiny, which may, in turn, lead to new state and federal safety and environmental laws, regulations, guidelines and enforcement interpretations. These actions may cause operational delays or restrictions, increased operating costs, additional regulatory burdens and increased risk of litigation. Moreover, governmental authorities exercise considerable discretion in the timing and scope of permit issuance and the public may engage in the permitting process, including through intervention in the courts. Negative public perception could cause the permits we need to conduct our operations to be withheld, delayed, or burdened by requirements that restrict our ability to profitably conduct our business.
Our ability to sell our oil, natural gas and oilNGL 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 oilNGL 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 oilNGL production primarily through gathering systems and pipelines that we do not own. The lack of available capacity on these systems and facilities could reduce the price offered for our production or result in the shut-in of producing wells or the delay or discontinuance of development plans for properties. Third-party systems and facilities may be unavailable due to market conditions or mechanical or other reasons.reasons, and in some cases the resulting curtailments of production could lead to payment being required where we fail to deliver oil, natural gas and NGLs to meet minimum volume commitments. In addition, at current commodity prices, construction of new pipelines and building of suchrequired infrastructure may be slowerslow 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.
For example,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.
We are subject to complex laws and regulations, including environmental and safety regulations, which can adversely affect the cost, manner or feasibility of doing business.
Our operations are subject to extensive federal, state and local laws and regulations, including drilling, permitting and safety laws and regulations and those relating to the generation, storage, handling, emission, transportation and discharge of materials into the environment. These laws and regulations can adversely affect the cost, manner or feasibility of doing business. Many laws and regulations require permits for the operation of various facilities, and these permits are subject to revocation, modification and renewal. Governmental authorities have the power to enforce compliance with their regulations, and violations could subject us to fines, injunctions or both. These laws and regulations have increased the costs of planning, designing, drilling, installing and operating natural gas and oil facilities, and new laws and regulations or revisions or reinterpretations of existing laws and regulations could further increase these costs. In addition, we may be liable for
environmental damages caused by previous owners or operators of property we purchase or lease. Risks of substantial costs and liabilities related to environmental compliance issues are inherent in natural gas and oil operations. For example, we could be required to install expensive pollution control measures or limit or cease activities on lands located within wilderness, wetlands or other environmentally or politically sensitive areas. Failure to comply with these laws 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 orders. It is possible that other developments, such as stricter environmental laws and regulations, and claims for damages to property or persons resulting from natural gas and oil production, would result in substantial costs and liabilities.
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 natural gas and oilcommodity prices, operating costs, production taxes and
potential environmental and other liabilities. These assessments are complex and inherently imprecise. Our review of the properties we acquire may not reveal all existing or potential problems. In addition, our review may not allow us to assess fully assess the potential deficiencies of the properties. We do not inspect every well, and even when we inspect a well we may not discover structural, subsurface or environmental problems that may exist or arise.
There may be threatened or contemplated claims against the assets or businesses we acquire related to environmental, title, regulatory, tax, contract, litigation or other matters of which we are unaware, which could materially and adversely affect our production, revenues and results of operations. We often assume certain liabilities, and we may not be entitled to contractual indemnification for pre-closing liabilities, including environmental liabilities, and our contractual indemnification may not be effective. At times, we acquire interests in properties on an "as is"“as is” basis with limited representations and warranties and limited remedies for breaches of such representations and warranties. In addition, significant acquisitions can change the nature of our operations and business if the acquired properties have substantially different operating and geological characteristics or are in different geographic locations than our existing properties.
The integration of the businesses and properties we have acquired or may in the future acquire could be difficult, and may divert management'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.
The process of integrating our operations could cause an interruption of, or loss of momentum in, the activities of our business. Members of our management may be required to devote considerable amounts of time to this integration process, which will decrease the time they will have to manage our existing business. If management is not able to effectively manage the integration process, or if any significant business activities are interrupted as a result of the integration process, our business could suffer. 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, oil, drilling fluids or hydraulic fracturing fluids;
•uncontrolled flows of oil, natural gas oil or well fluids;
•pipeline ruptures;
•fires;
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 environmentalenvironmental 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. In addition, certain segments of our pipelines will periodically require repair, replacement or maintenance, which may be costly.
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.
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, 2017,2021, non-operated wells represented approximately 14.7%68 percent of our total owned gross wells, or approximately 3.8%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.
Competition in our industry is intense, and manyMany of our competitorsproperties are in areas that may have substantially greater financialbeen partially depleted or drained by offset wells and technological resources than we do,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 competitive position.
Competitionoperations. 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 industry is intense. Major and independent natural gas distribution systems in the U.S., which are necessary to transport our products to market. Computers also enable communications and oil companies actively bidprovide a host of other support services for desirable natural gasour business. In recent years (and, in large part, due to the COVID-19 pandemic), we have increased the use of remote networking and oil properties,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 capital, equipmentfinancing of Arctic drilling and labor requiredcoal companies. These initiatives by activists and banks, including certain banks who are parties to operatethe credit agreement providing for our revolving credit facility, could interfere with our business activities, operations and develop these properties. Our competitive position is affected by price, contract termsability to access capital. Future challenges in the economy could also lead to reduced demand for oil and qualitynatural gas, which could have a negative impact on our revenues.
Risks associated with our debt and reliable delivery record. Manythe 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 technological resources and exploration and development budgetsother factors that are substantially greater than ours. These companiesbeyond 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 pay more for exploratory projectssuccessfully execute any of these strategies, and productive natural gas and oil properties andsuch strategies may be able to define, evaluate, bid forunavailable on favorable terms or at all. For more information about our debt agreements, please read “Management’s Discussion and purchase a greater numberAnalysis of propertiesFinancial Condition and prospects than our financial or human resources permit. In addition, these companies may be able to expend greater resources on the existingResults of Operations-Financial Condition-Capital Resources 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 natural gas and oil prices and to absorb the burden of current and future governmental regulations and taxation.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 and oil.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 and crude oil 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. WhileAlthough 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“Management's Discussion and Analysis of Financial Condition and Results of Operations"Operations” in Item 7 and "Quantitative“Quantitative and Qualitative Disclosures about Market Risk"Risk” in Item 7A for further discussion concerning our use of derivatives.
The lossLegal, 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 key personnelour 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 adversely affectresult 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 operate.
Our operations are dependent upon a relatively small group of key management and technical personnel, and one or more of these individuals could leaveprofitably conduct our employment. 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. If we cannot retain our technical personnel or attract additional experienced technical personnel, our ability to compete could be harmed.business.
Federal, state and state legislationlocal laws and regulations, judicial actions and regulatory initiatives related to oil and gas development includingand the use of hydraulic fracturing could result in increased costs and operating restrictions or delays.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. Hydraulic fracturing operations have historically been overseen by state regulators as part of their oilIf existing laws and gas regulatory programs; however, the EPA has asserted federal regulatory authority over certainregulations with regard to hydraulic fracturing activities involving diesel under the Safe Drinking Water Actare revised or reinterpreted or if new laws and has released permitting guidance for hydraulic fracturing activities that use diesel in fracturing fluids in those states where EPA is the permitting authority, including Pennsylvania. As a result, we mayregulations become applicable to our operations through judicial or administrative actions, our business, financial condition, results of operations and cash flows could be subject to additional permitting requirements for hydraulic fracturing operations as well as various restrictions on those operations. These permitting requirements and restrictions could result in delays in operations at well sites as well as increased costs to make wells productive. In addition, from time to time, legislation has been introduced, but not enacted, in Congress that would provide for federal regulation of hydraulic fracturing under the Safe Drinking Water Act and require the public disclosure of certain information regarding the chemical makeup of hydraulic fracturing fluids. If enacted, this legislation could establish an additional level of regulation and permitting at the federal, state or local levels, and could make it easier for third parties opposed to the hydraulic fracturing process to initiate legal proceedings based on allegations that specific chemicals used in the fracturing process could adversely affect the environment, including groundwater, soil or surface water. In March 2015, the Department of the Interior's Bureau of Land Management issued a final rule to regulate hydraulic fracturing on public and Indian land; however, these rules were rescinded by rule in December 2017. We voluntarily disclose on a well-by-well basis the chemicals we use in the hydraulic fracturing process at www.fracfocus.org.
In addition,affected. Further, state and federal regulatory agencies recently have focused on a possible connection between the operation of injection wells used for oil and gas waste disposal and seismic activity.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 United StatesU.S. Geological Survey identified six states with the most significant hazards from induced seismicity, including Oklahoma, Kansas, Texas, Colorado, New Mexico, and Arkansas. In lightThese concerns have further increased regulatory scrutiny on hydraulic fracturing as well as oil and gas waste injection wells and led to the adoption of these concerns, some state regulatory agencies have modified their regulations or issued orders to address induced seismicity. Certain environmental and other groups have also suggested that additional federal, state and local laws and regulations may be needed to more closely regulate the hydraulic fracturing process.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. Increased regulation and attention given to induced seismicityThese 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.
On August 16, 2012, the EPA published final rules that establish newSome of our producing wells and associated facilities are subject to restrictive air emission control requirementslimitations 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 natural gas and NGL production, processing and transportation activities, including NSPS to address emissions of sulfur dioxide and volatile organic compounds, and NESHAPS to address hazardous air pollutants frequently associated with gas production and processing activities.Hazardous Air Pollutants (“NESHAP”). In June 2016, the EPA published a final rule that updates and expands 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. A 2016 information collection request made to oil and natural gas facilities by EPA in connection with its intention at the time to regulate methane emissions from existing sources were withdrawn in March 2017. The EPA also published a final rule in June 2016 concerning aggregation of sources that affects source determinations for air permitting in the oil and gas industry.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 thesethe 2012 and 2016 NSPS for the oil and gas sector and any additional requirements especially theimposed 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, thatwhich could result in significant costs, including increased capital expenditures and operating costs, and could adversely impact our business. Similarly, aggregating our
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 facilities for permittingeconomically and in commercial quantities could result in more complex, costly, and time consuming air permitting. Particularly in regardbe impaired if we are unable to obtaining pre-construction permits, the final aggregation rule could add costs and cause delays in our operations.
In addition to these federal legislative and regulatory proposals, some states in which we operate, such as Pennsylvania and Texas, and certain local governments have adopted, and others are considering adopting, regulations that could restrict hydraulic fracturing in certain circumstances, including requirements regarding chemical disclosure, casing and cementing of wells, withdrawalacquire adequate supplies of water for our operations or are unable to dispose of or recycle the water we use economically and in high-volume hydraulic fracturingan environmentally safe manner.
Water is an essential component of horizontal wells, baseline testing of nearby water wells, and restrictions on the type of additives that may be used in hydraulic fracturing operations. For example, the City of Denton, Texas adopted a moratorium on hydraulic fracturing in November 2014, though it was later lifted in 2015, and New York issued a statewide ban on hydraulic fracturing in June 2015. In addition, Pennsylvania's Act 13 of 2012 became law on February 14, 2012 and amended the state's Oil and Gas Act to, among other things, increase civil penalties and strengthen the Pennsylvania Department of Environmental Protection's (PaDEP) authority over the issuance of drilling permits. Although the Pennsylvania Supreme Court struck down portions of Act 13 that made statewide rules on oil and natural gas preempt local zoning rules, this could lead to additional local restrictions on oil and gas activity inproduction during the state.
Wedrilling process. In particular, we use a significant amount of water in ourthe hydraulic fracturing operations.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. Moreover, new environmental initiativesFor 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 regulationstransported 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 include restrictions onadversely impact our ability to conductoperations in certain operations such as hydraulic fracturing or disposal of waste, including, but not limited to, produced water, drilling fluids and other wastes associated with the exploration, development or production of natural gas.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 example, in April 2011, PaDEP called on all Marcellus Shale natural gas drilling operators to voluntarily cease by May 19, 2011 delivering wastewater to those centralized treatment facilities that were grandfathered from the application of PaDEP's Total Dissolved Solids regulations. In June 2016, the EPA published final pretreatment standards for disposal of wastewater produced from shale gas operations to publicly owned treatment works. The regulations were developed under the EPA's Effluent Guidelines Program under the authority of the additional information, please read “Business and Properties—Other Business Matters—Environmental and Safety Regulations—Clean Water Act. In response to these actions, operators including us have begun to rely more on recyclingAct” in Items 1 and 2.
The adoption of flowback and produced water from well sites as a preferred alternative to disposal.
A number of federal agencies are analyzing, or have been requested to review, a variety of environmental issues associated with hydraulic fracturing practices. For example, 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 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.
Climate change and climate change legislation and regulatory initiativesor regulations restricting emission of greenhouse gases could result in increased operating costs and decreasedreduced demand for the oil and natural gas that we produce.
Climate change,Studies have found that emission of certain gases, commonly referred to as greenhouse gases (“GHG”), impact the costsearth’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 may be associated with its effects, andrestrict emissions of GHGs. In the regulationabsence of greenhouse gas (GHG) emissions have the potential to affect our business in many ways, including increasing the costs to provide our products and services, reducing the demand for and consumption of our products and services (due to change in both costs and weather patterns), and the economic health of the regions in which we operate, all of which can create financial risks. In addition, legislative and regulatory responses related tosignificant federal GHG emissions and climate change may increase our operating costs. The United States Congress has previously considered legislation, related to GHG emissions. There have also been international efforts seeking legally binding reductions in GHG emissions. The United States was actively involved in the negotiations at the 21st Conference of the Parties of the United Nations Framework Convention on Climate Change in Paris, which led to the creation of the Paris Agreement. The Paris Agreement requires countries to review and "represent a progression" in their nationally determined contributions, which set emissions reduction goals, every five years. The United States signed the Paris Agreement in April 2016. However, on August 4, 2017, the United States formally communicated to the United Nations its intent to withdraw from participation in the Paris Agreement, which entails a four-year process. In response to the announced withdrawal plan, a number of state and local governments in the United Statesregional efforts have expressed intentions to take GHG-related actions. Increased public awareness and concern regarding climate change may result in more state, regionalemerged, aimed at tracking and/or federal requirements to reduce or mitigatereducing GHG emissions.
In September 2009, the EPA finalized a mandatory GHG reporting rule that requires largeemissions through cap-and-trade programs, which typically require major sources of GHG emissions, such as electric power plants, to monitor, maintain recordsacquire 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 annually report their GHG emissions beginning January 1, 2010. The rule appliesreconvened an interagency working group to large facilities emitting 25,000 metric tons or moreestablish social costs of three GHGs: carbon dioxide-equivalent (CO2e) emissions per yeardioxide, nitrous oxide, and to most upstream suppliersmethane. 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 manufacturers of vehicles and engines. Subsequently, in November 2010, the EPA issued GHG monitoring and reportingany future laws or regulations that went into effect on December 30, 2010, specifically for oilregulate or limit emissions of GHGs from our equipment and natural gas facilities, including onshoreoperations could require us to both develop and offshore oil and natural gas production facilities that emit 25,000 metric tons or more of CO2e per year. The rule required reporting ofimplement new practices aimed at reducing GHG emissions, by regulated facilities to the EPA by March 2012 forsuch as emissions during 2011control technologies, and annually thereafter. We are required to report our GHG emissions to the EPA each year in March under this rule and have submitted our annual reports in compliance with the deadline. The EPA also issued a final rule that makes certain stationary sources and newer modification projects subject to permitting requirements for GHG emissions, beginning in 2011, under the CAA. However, in June 2014, the U.S. Supreme Court, in UARG v. EPA, limited the application of the GHG permitting requirements under the Prevention of Significant Deterioration and Title V permitting programs to sources that would otherwise need permits based on the emission of conventional pollutants. In October 2015, the EPA finalized rules that added new sources to the scope of the GHG monitoring and reporting requirements. These new sources include gathering and boosting facilities as well as completions and workovers from hydraulically fractured oil wells. The revisions also include the addition of well identification reporting requirements for certain facilities. Also, in November 2016, the EPA published a final rule adding monitoring methods for detecting leaks from oil and gas equipment and emission factors for leaking equipment to be used to calculatemonitor and report GHG emissions resultingassociated 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 equipment leaks.
Federaloil, gas and NGL operations constitute a public nuisance under federal and state regulatory agencies can impose administrative, civil and/law. Private individuals or criminal penalties for non-compliance with air permitspublic entities also could attempt to enforce environmental laws and regulations against us and could seek personal injury and property damages or other requirements of the CAAremedies. Additionally, governments and associated state lawsprivate 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 regulations. In addition, the passage ofmisleading “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 federalsuch climate-related or state climate change laws or regulations“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 increased costslower prices and lower revenues. Market risk also may take the form of limited access to (i) operatecapital as investors shift investments to less carbon-intensive industries and maintainalternative 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 facilities, (ii) install new emission controlsIndebtedness, 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 facilities and (iii) administer and manage any GHG emissions program. If we are unable to recover or pass through a significant level of our costs related to complying with climate change regulatory requirements imposed on us, itindustry could have a materialan adverse effect on our results ofbusiness operations and financial condition. To the extent financial markets viewprice of our common stock.”
Physical Risks.Potential physical risks resulting from climate change and GHG emissions as a financial risk, this could negatively impact our cost of and access to capital. Legislation or regulations that may be adopted to address climate change could also affect the markets for our products by making our products more or less desirable than competing sourcesevent driven (including increased severity of energy.
Moreover, some experts believe climate change poses potential physical risks, including an increase in sea level and changes in weather conditions, such as an increase in changes in precipitation and extreme weather events. In addition, warmer winters as a result of global warming could also decrease demand for natural gas. To the extent that such unfavorable weather conditions are exacerbated by global climate change or otherwise, our operations may be adversely affected to a greater degree than we have previously experienced, including increased delays and costs. However, the uncertain nature of changes in extreme weather events, (suchsuch as increased frequency, duration, and severity) and the long period of time over which any
changes would take place make any estimations of future financial risk to our operations causedhurricanes, droughts, or floods) or may be driven by these potentiallonger-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 climate change unreliable.insurance.
Terrorist activitiesWe are subject to a number of privacy and data protection laws, rules and directives (collectively, data protection laws) relating to the potential for militaryprocessing 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 couldagainst 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 impactacquisition of military and other action have caused instabilitya company that is not in world financial markets and could lead to increased volatilitycompliance with applicable data protection laws may result in prices for natural gas and oil, alla violation of which could adversely affect the markets for our operations. Acts of terrorism, including cybersecurity threats to gain unauthorized access to sensitive information or to render data or systems unusable, could be directed against companies operating in the United States. The U.S. government has issued public warnings that indicate energy assets might be specific targets of terrorist organizations. These developments have subjected our operations to increased risk and, depending on their ultimate magnitude, could have a material adverse effect on our business.
Cyber-attacks targeting our systems or the oil and gas industry systems and infrastructure 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. We depend on this technology to record and store financial data, estimate quantities of natural gas and crude oil reserves, analyze and share operating data and communicate internally and externally. Computers control nearly all of the oil and gas distribution systems in the United States, which are necessary to transport our products to market.
A cyber-attack may involve a hacker, a virus, malware, phishing or other actions for the purposes of misappropriating assets or sensitive information, corrupting data or causing operational disruption. Unauthorized access to our proprietary information could lead to data corruption or communication or operational disruptions. A cyber-attack directed at oil and gas distribution systems could damage those assets or the environment, delay or prevent delivery of production to markets and make it difficult or impossible to accurately account for transported products.
We can provide no assurance that we will not suffer such attacks in the future. 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. To the extent we face increased regulatory requirements, we may be required to expend significant additional resources to meet such requirements.these laws.
Tax law changes could have an adverse effect on our financial position, results of operations and cash flows.
On December 22, 2017, the U.S. enacted legislation referredSubstantive changes to as the Tax Cuts and Jobs Act (the "Tax Act"). The Tax Act significantly changes U.S. corporateexisting federal income tax laws beginning, generally, in 2018. These changes include, among others, (i) a permanent reduction of the U.S. corporate income tax rate from a top marginal rate of 35% to a flat rate of 21%, (ii) elimination of the corporate alternative minimum tax, (iii) immediate deductions for certain new investments instead of deductions for depreciation expense over time, (iv) limitation on the tax deduction for interest expense to 30% of adjusted taxable income, (v) limitation of the deduction for net operating losses to 80% of current year taxable income and elimination of net operating loss carrybacks, and (vi) elimination ofhave been proposed that, if adopted, would repeal many business deductions and credits, including the domestic production activities deduction, the deduction for entertainment expenditures, and the deduction for certain executive compensation in excess of $1 million. Refer to Note 10 of the Notes to the Consolidated Financial Statements, "Income Taxes" for additional discussion on the impact of the Tax Act on the Company. In the absence of guidance on various uncertainties and ambiguities in the application of certain provisions of the Tax Act, we will use what we believe are reasonable interpretations and assumptions in applying the Tax Act. Overall, we expect the provisions of the Tax Act to favorably impact the Company's future effective tax rate, after-tax earnings, and cash flows. However, it is possible that the Internal Revenue Service could issue subsequent guidance or take positions on audit that differ from our prior interpretations and assumptions, which could adversely impact our financial position, results of operations, and cash flows.
While the Tax Act maintains many of the tax incentives and deductions that are currently used by U.S. oil and gas companies includingand would impose new taxes. The proposals include: repeal of the percentage depletion allowance for oil and natural gas companies,properties; elimination of the ability to fully deduct intangible drilling costs in the year incurred,incurred; and increase in the current amortization period of geological and geophysical expendituresamortization period for independent producers, the U.S.producers. Additional proposed general tax law is always subject to change. Periodically, legislation is proposed to repeal these industrychanges include raising tax incentivesrates on both domestic and deductions, and/or to imposeforeign income and imposing a new industry taxes. In addition, it is uncertain if and to what extent various states will conform to the Tax Act.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 knowpredict 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 controlchange-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
None.
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"“Legal Matters” in Note 98 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.
Environmental MattersGovernmental Proceedings
From time to time we receive notices of violation from governmental and regulatory authorities, in areas in which we operateincluding notices relating to alleged violations of environmental statutes or the rules and regulations promulgated thereunder. While we cannot predict with certainty whether these notices of violation will result in fines and/or penalties, if fines and/or penalties are imposed, they may result in monetary sanctions, individually or in the aggregate, in excess of $100,000.$300,000.
ITEM 4. MINE SAFETY DISCLOSURES
Not applicable.
INFORMATION ABOUT OUR EXECUTIVE OFFICERS OF THE REGISTRANT
The following table shows certain information as of February 22, 201828, 2022 about our executive officers, as such term is defined in Rule 3b-7 of the Securities Exchange Act of 1934, and certain of our other officers.1934.
|
| | | | | | | |
Name | | Age | | Position | | Officer Since |
Dan O. Dinges | | 64 |
| | Chairman, President and Chief Executive Officer | | 2001 |
Scott C. Schroeder | | 55 |
| | Executive Vice President and Chief Financial Officer | | 1997 |
Jeffrey W. Hutton | | 62 |
| | Senior Vice President, Marketing | | 1995 |
Todd L. Liebl | | 60 |
| | Senior Vice President, Land and Business Development | | 2012 |
Steven W. Lindeman | | 57 |
| | Senior Vice President, South Region and Engineering | | 2011 |
Phillip L. Stalnaker | | 58 |
| | Senior Vice President, North Region | | 2009 |
G. Kevin Cunningham | | 64 |
| | Vice President and General Counsel | | 2010 |
Charles E. Dyson II | | 46 |
| | Vice President, Information Services | | 2018 |
Matthew P. Kerin | | 37 |
| | Vice President and Treasurer | | 2014 |
Julius Leitner | | 55 |
| | Vice President, Marketing | | 2017 |
Todd M. Roemer | | 47 |
| | Vice President and Controller | | 2010 |
Deidre L. Shearer | | 50 |
| | Vice President and Corporate Secretary | | 2012 |
| | | | | | | | | | | | | | | | | | | | |
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 Cabot Oil & Gas CorporationCoterra Energy Inc. for at least the last five years, except for Mr. Charles E. Dyson IIthe following officers, each of whom previously served Cimarex as described below and Mr. Julius Leitner.
Mr. Dyson joinedbegan serving in his current role at the Company as of October 1, 2021, the Directoreffective date of Information Services in October 2015the Merger:
Mr. Jorden previously served as the Chief Executive Officer and was promoted toPresident 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 Information ServicesExploration when the company formed in February 2018.2002. 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 the Company, heKey, Mr. Jorden served as the Director of Infrastructureat Union Pacific Resources and Support Services at Transocean Offshore Deepwater Drilling, Inc. Superior Oil Company.
Mr. Dyson holds a BachelorBell was appointed Senior Vice President of Business Administration degreeDevelopment and Land in Finance from Texas A&M University.
September 2002 and was named Executive Vice President of Business Development in September 2012. Mr. LeitnerBell served at Key prior to its acquisition by Cimarex. He joined the CompanyKey in 1994 as Vice President Marketingof Land and was appointed Senior Vice President of Business Development and Land in July 2017.1999.
Mr. Barron joined Cimarex as Senior Vice President and General Counsel in 2013. Prior to joiningCimarex, 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 Company, Denver, Colorado office of the law firm of Patton Boggs LLP, as well as a partner at Bearman Talesnick & Clowdus Professional Corporation.
Mr. LeitnerClason 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 Shell Energy North America (US) L.P.,Cimarex in 2007, serving in a number of technical and leadership roles including Director of Northeast Trading, DirectorTechnology and Anadarko Exploration Region Manager. In September 2020, Mr. Smith assumed the role of Producer Services,Chief Engineer for Cimarex.
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 Senior Originator,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 July 19962022 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 July 2017. Mr. Leitner holds a BachelorDecember 2021. The graph assumes that the value of Science degreethe investment in Biology from Boston Collegeour common stock and a Mastersin 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 Business Administration fromSection 18 of the Mays Business SchoolExchange Act, or otherwise subject to the liabilities of Texas A&M University.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 5. MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
Our common stock is listed and principally traded on the New York Stock Exchange under the ticker symbol "COG." The following table presents the high and low closing sales prices per share of our common stock during certain periods, as reported in the consolidated transaction reporting system. Cash dividends paid per share of the common stock are also shown.
|
| | | | | | | | | | | |
| High | | Low | | Dividends |
2017 | |
| | |
| | |
|
First Quarter | $ | 24.10 |
| | $ | 20.65 |
| | $ | 0.02 |
|
Second Quarter | $ | 24.99 |
| | $ | 21.42 |
| | $ | 0.05 |
|
Third Quarter | $ | 26.91 |
| | $ | 24.17 |
| | $ | 0.05 |
|
Fourth Quarter | $ | 29.44 |
| | $ | 24.38 |
| | $ | 0.05 |
|
2016 | |
| | |
| | |
|
First Quarter | $ | 22.88 |
| | $ | 15.42 |
| | $ | 0.02 |
|
Second Quarter | $ | 25.94 |
| | $ | 22.23 |
| | $ | 0.02 |
|
Third Quarter | $ | 26.47 |
| | $ | 23.52 |
| | $ | 0.02 |
|
Fourth Quarter | $ | 25.69 |
| | $ | 20.03 |
| | $ | 0.02 |
|
As of February 1, 2018, there were 365 registered holders of our common stock.
In January 2018, the Board of Directors approved an increase in the quarterly dividend on our common stock from $0.05 per share to $0.06 per share.
EQUITY COMPENSATION PLAN INFORMATION
The following table provides information as of December 31, 2017 regarding the number of shares of common stock that may be issued under our 2014 and 2004 incentive plans.
|
| | | | | | | | | | |
| (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 | 3,244,739 |
| (1) | $ | 17.59 |
| (2) | 14,935,363 |
| (3) |
Equity compensation plans not approved by security holders | n/a |
| | n/a |
| | n/a |
| |
Total | 3,244,739 |
| | $ | 17.59 |
| | 14,935,363 |
| |
| |
(1) | Includes 57,144 SARs to be settled in common stock, which are fully vested; 1,095,970 employee performance shares, the performance periods of which end on December 31, 2017, 2018 and 2019; 1,109,708 TSR performance shares, the performance periods of which end on December 31, 2017, 2018 and 2019; 574,354 hybrid performance shares, which vest, if at all, in 2018, 2019, and 2020; and 407,563 restricted stock units awarded to the non-employee directors, the restrictions on which lapse upon a non-employee director's departure from the Board of Directors. |
| |
(2) | Price is only with respect to the 57,144 SARs outstanding because all other outstanding awards are issued without an exercise price. |
| |
(3) | Includes 161,450 shares of restricted stock, the restrictions on which lapse on various dates in 2018, 2019 and 2020; and 14,773,913 shares that are available for future grants under the 2014 Incentive Plan. |
ISSUER PURCHASES OF EQUITY SECURITIES
Our Board of Directors has authorized a share repurchase program under which we may purchase shares of common stock in the open market or in negotiated transactions. There is no expiration date associated with the authorization. The shares included in the table below were repurchased on the open market and were held as treasury stock as of December 31, 2017.
|
| | | | | | | | | | | | | |
Period | | Total Number of Shares Purchased | | 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 2017 | | — |
| | — |
| | — |
| | 7,054,074 |
|
November 2017 | | 177,900 |
| | $ | 27.81 |
| | 177,900 |
| | 6,876,174 |
|
December 2017 | | 1,822,100 |
| | $ | 27.71 |
| | 1,822,100 |
| | 5,054,074 |
|
Total | | 2,000,000 |
| | | | 2,000,000 |
| | |
In February 2018, the Board of Directors authorized an increase of 25.0 million shares to our share repurchase program. After this authorization, the total number of shares available for repurchase is 30.1 million shares.
PERFORMANCE GRAPH
The following graph compares our common stock performance ("COG") with the performance of the Standard & Poor's 500 Stock Index and the Dow Jones U.S. Exploration & Production Index for the period December 2012 through December 2017. The graph assumes that the value of the investment in our common stock and in each index was $100 on December 31, 2012 and that all dividends were reinvested.
|
| | | | | | | | | | | | | | | | | | | | | | | |
| December 31, |
Calculated Values | 2012 | | 2013 | | 2014 | | 2015 | | 2016 | | 2017 |
COG | $ | 100.00 |
| | $ | 156.13 |
| | $ | 119.54 |
| | $ | 71.63 |
| | $ | 94.94 |
| | $ | 117.02 |
|
S&P 500 | $ | 100.00 |
| | $ | 132.39 |
| | $ | 150.51 |
| | $ | 152.59 |
| | $ | 170.84 |
| | $ | 208.14 |
|
Dow Jones U.S. Exploration & Production | $ | 100.00 |
| | $ | 131.84 |
| | $ | 117.64 |
| | $ | 89.72 |
| | $ | 111.69 |
| | $ | 113.14 |
|
The performance graph above is furnished and not filed for purposes of Section 18 of the Securities Exchange Act of 1934 and will not be incorporated by reference into any registration statement filed under the Securities Act of 1933 unless specifically identified therein as being incorporated therein by reference. The performance graph is not soliciting material subject to Regulation 14A.
ITEM 6. SELECTED FINANCIAL DATA[RESERVED]
The following table summarizes our selected consolidated financial data for the periods indicated. This information should be read in conjunction with Management's Discussion and Analysis of Financial Condition and Results of Operations in Item 7, and the Consolidated Financial Statements and related Notes in Item 8.
|
| | | | | | | | | | | | | | | | | | | |
| Year Ended December 31, |
(In thousands, except per share amounts) | 2017 | | 2016 | | 2015 | | 2014 | | 2013 |
Statement of Operations Data | |
| | |
| | |
| | |
| | |
|
Operating revenues | $ | 1,764,219 |
| | $ | 1,155,677 |
| | $ | 1,357,150 |
| | $ | 2,173,011 |
| | $ | 1,746,278 |
|
Impairment of oil and gas properties and other assets(1) | 482,811 |
| | 435,619 |
| | 114,875 |
| | 771,037 |
| | — |
|
Earnings (loss) on equity method investments(2) | (100,486 | ) | | (2,477 | ) | | 6,415 |
| | 3,080 |
| | 1,102 |
|
Gain (loss) on sale of assets(3) | (11,565 | ) | | (1,857 | ) | | 3,866 |
| | 17,120 |
| | 21,351 |
|
Income (loss) from operations | (151,260 | ) | | (564,945 | ) | | (88,914 | ) | | 106,186 |
| | 551,582 |
|
Net income (loss)(4) | 100,393 |
| | (417,124 | ) | | (113,891 | ) | | 104,468 |
| | 279,773 |
|
Basic earnings (loss) per share | $ | 0.22 |
| | $ | (0.91 | ) | | $ | (0.28 | ) | | $ | 0.25 |
| | $ | 0.67 |
|
Diluted earnings (loss) per share | $ | 0.22 |
| | $ | (0.91 | ) | | $ | (0.28 | ) | | $ | 0.25 |
| | $ | 0.66 |
|
Dividends per common share | $ | 0.17 |
| | $ | 0.08 |
| | $ | 0.08 |
| | $ | 0.08 |
| | $ | 0.06 |
|
|
| | | | | | | | | | | | | | | | | | | |
| December 31, |
(In thousands) | 2017 | | 2016 | | 2015 | | 2014 | | 2013 |
Balance Sheet Data | |
| | |
| | |
| | |
| | |
|
Properties and equipment, net | $ | 3,072,204 |
| | $ | 4,250,125 |
| | $ | 4,976,879 |
| | $ | 4,925,711 |
| | $ | 4,546,227 |
|
Total assets(5) | 4,727,344 |
| | 5,122,569 |
| | 5,253,038 |
| | 5,429,705 |
| | 4,978,038 |
|
Current portion of long-term debt | 304,000 |
| | — |
| | 20,000 |
| | — |
| | — |
|
Long-term debt(5) | 1,217,891 |
| | 1,520,530 |
| | 1,996,139 |
| | 1,743,989 |
| | 1,143,958 |
|
Stockholders' equity | 2,523,905 |
| | 2,567,667 |
| | 2,009,188 |
| | 2,142,733 |
| | 2,204,602 |
|
| |
(1) | For discussion of impairment of oil and gas properties and other assets, refer to Note 3 of the Notes to the Consolidated Financial Statements. |
| |
(2) | Earnings (loss) on equity method investments in 2017 includes an other than temporary impairment of $95.9 million associated with our investment in Constitution. Refer to Note 4 of the Notes to the Consolidated Financial Statements. |
| |
(3) | Loss on sale of assets in 2017 includes an $11.9 million loss from the sale of certain proved and unproved oil and gas properties located in West Virginia, Virginia and Ohio. Gain on sale of assets in 2014 includes a $19.9 million gain from the sale of certain proved and unproved oil and gas properties located in east Texas. Gain on sale of assets in 2013 includes a $19.4 million gain from the sale of certain proved and unproved oil and gas properties located in the Oklahoma and Texas panhandles, and a $17.5 million loss from the sale of certain proved and unproved oil and gas properties located in Oklahoma, Texas and Kansas and an aggregate net gain of $19.5 million from the sale of various other oil and gas properties during the year. |
| |
(4) | Net income (loss) includes an income tax benefit of $242.9 million as a result of the remeasurement of our net deferred income tax liabilities based on the new lower corporate income tax rate associated with the Tax Act enacted in December 2017. |
| |
(5) | Effective January 1, 2016, the Company adopted Accounting Standards Update No. 2015-03 as a change in accounting principle. The Consolidated Balance Sheet as of December 31, 2015, 2014 and 2013 has been retrospectively adjusted to reflect the adoption of this guidance, resulting in a decrease of $8.9 million, $8.0 million, and $3.0 million, respectively, in both total assets and long-term debt related to the debt issuance costs on the Company's senior notes. |
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.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, 20172021 compared to the year ended December 31, 20162020 are as follows:
Equivalent production increased 58.2 Bcfe, or 9%, from 627.1 Bcfe, or 1,713.4 Mmcfe per day, in 2016 to 685.3 Bcfe, or 1,877.5 Mmcfe per day, in 2017.
•Natural gas production increased 55.253.4 Bcf, or 9%,six percent, from 600.4857.7 Bcf in 20162020 to 655.6911.1 Bcf in 2017, as a result2021. 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 Pennsylvania.the Marcellus Shale in 2021.
Crude oil/condensate/•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 0.5 Mmbbls, or 11%,7 Mmbbl from 4.5 Mmbblsprior year. The increase was attributable to production during the fourth quarter of 2021 from properties acquired in 2016 to 5.0 Mmbbls in 2017, as a result of an increase in drilling activities in south Texas, partially offset by a natural decline in production.the Merger.
•Average realized natural gas price for 20172021 was $2.31$2.73 per Mcf, 36%63 percent higher than the $1.70$1.68 per Mcf price realized in 2016.2020.
•Average realized crude oil priceand NGL prices for 2017 was $48.162021 were $60.35 and $34.18 per Bbl, 29% higher thanrespectively.
•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 $37.30 per Bbl price realized in 2016.fourth quarter of 2021 as a result of the Merger.
•Drilled 91114 gross wells (82.5(99.9 net) with a success rate of 98.9%100 percent in 20172021 compared to 4074 gross wells (38.0(64.3 net) with a success rate of 100.0%100 percent in 2016.2020.
•Completed 105132 gross wells (94.2(108.3 net) in 20172021 compared to 7686 gross wells (76.0(77.3 net) in 2016.2020.
Total capital expenditures were $757.2 million in 2017 compared to $372.5 million in 2016.
•Average rig count during 20172021 was approximately 2.02.5 rigs in the Marcellus Shale, approximately 1.0 rig in the Eagle Ford Shale and approximately 0.4 rigs in other areas, compared to an average rig count in the Marcellus Shale of approximately 1.12.3 rigs during 2020. Rig count since the Merger averaged 5.3 and approximately 0.3zero rigs in the Eagle Ford Shale during 2016.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 2017,2021.
•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 received proceeds of $32.7 million primarilyoperate. Beginning in March 2020, we modified certain business practices (including those related to nonoperational employee work locations and the divestiturecancellation 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 oiloperational decisions we previously implemented, such as our maintenance capital program, have helped to minimize the impact, and gas properties and related pipeline assets in West Virginia, Virginia and Ohio.
In December 2017, we recognized an impairment loss of $414.3 million associated with our Eagle Ford shale oil and gas properties in south Texas and an other than temporary impairment of $95.9 million associated with our equity method investment in Constitution.
In December 2017, we recognized an income tax benefit of $242.9 million as a resultany resulting disruptions, of the remeasurementpandemic 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 our net deferred income tax liabilities basedoperations will depend on future developments, including, among others, the new lower corporate income tax rate associated with the enactmentduration, ultimate geographic spread and severity of the Tax Act.
During 2017, we repurchased 5.0 million sharesvirus and its variants (such as the Delta and Omicron variants), the global availability and efficacy of our common stock fortreatments and vaccines and boosters and the acceptance of such treatments and vaccines by a total costsignificant portion of $123.7 million.
In May 2017, the Boardpopulation, any significant resurgence in virus transmission and infection in regions that have experienced improvements, the extent and duration of Directors approved an increase ingovernmental and other measures implemented to try to slow the quarterly dividend on our common stock from $0.02 per share to $0.05 per share.
In January 2018,spread of the Boardvirus (whether through a continuation of Directors approved an increase inexisting measures or the quarterly dividend on our common stock from $0.05 per share to $0.06 per share.
In February 2018, the Boardre-imposition of Directors authorized an increase of 25.0 million shares to our share repurchase program.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 the price of natural gas and crude oilcommodity 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. In addition, ourOur 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, we 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. Location differentials have increased in certain regions, such as in the Appalachian region, resulting in further declines in natural gas prices. We expect natural gas and crude oil prices to remain volatile. In addition to commodity prices and production volumes, and commodity prices, finding and developing sufficient amounts of oil and natural gas and crude oil reserves at economical costs are critical to our long-term success. For information about the impact of realized commodity prices on our natural gas and crude oil and condensate revenues, refer to "Results of Operations" below. See "Risk Factors—Natural gas and oil prices fluctuate widely, and low prices for an extended period would likely have a material adverse impact on our business" and "Risk Factors—Our future performance depends on our ability to find or acquire additional natural gas and oil reserves that are economically recoverable" in Item 1A.
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 “Impact“Results of
Operations — Impact of Derivative Instruments on Operating Revenues” below and Note 65 of the Notes to the Consolidated Financial Statements, “Derivative Instruments,” for more information.
CommodityOne 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 remained volatile butstrengthened 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 during 2017 comparedcoinciding 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 fourth quarter of 2016. Innear future; however, in the event that commodity prices significantly decline from current levels, our management would testevaluate the recoverability of the carrying value of itsour oil and gas propertiesproperties.
For information about the impact of realized commodity prices on our revenues, refer to “Results of Operations” below.
FINANCIAL CONDITION
Liquidity and if necessary, record an impairment charge.Capital Resources
We believe that westrive to maintain an adequate liquidity level to address commodity price volatility and risk. Our primary sources of liquidity are well-positioned to manage the challenges presented in depressed commodity pricing environment, and that we can endure the continued volatility in current and future commodity prices by:
Continuing to exercise discipline in our capital program with the expectation of funding our capital expenditures with(1) cash on hand, (2) net cash provided by operating cash flows,activities and if required, borrowings(3) available borrowing capacity under our revolving credit facility.
Continuing to optimize our drilling, completionOur liquidity requirements consist primarily of (1) capital expenditures, (2) payment of contractual obligations, including debt maturity and operational efficiencies, resulting in lower operating costs per unit of production.
Continuing to manage our balance sheet, which we believe provides sufficient availability under our revolving credit facility and existing cash balances to meet ourinterest payments, (3) working capital requirements, (4) dividend payments and maintain compliance with our debt covenants.
Continuing to manage price risk by strategically hedging our natural gas and crude oil production.
FINANCIAL CONDITION
Capital Resources and Liquidity
Our primary sources of cash in 2017 were from the sale of natural gas and crude oil production and proceeds from the sale of assets. These cash flows were primarily used to fund our capital expenditures (including contributions to our equity method investments), repurchase of shares of our common stock and payment of dividends.(5) share repurchases. See below for additional discussion and analysis of our cash flow.
The borrowing base under the terms of our revolving credit facility is redetermined annually in April. In addition, either we or the banks may request an interim redetermination twice a year or in connection with certain acquisitions or divestitures of oil and gas properties. Effective April 11, 2017, the borrowing base and available commitments were reaffirmed at $3.2 billion and $1.7 billion, respectively. As of December 31, 2017, we had no borrowings outstanding and unused commitments of $1.7 billion under our revolving credit facility.
In December 2017, we entered into an agreement to sell certain of our Eagle Ford Shale assets for $765.0 million and expect to close on the sale in the first quarter of 2018. The lenders under our revolving credit facility have agreed to waive the requirement that the borrowing base be reduced upon closing of the Eagle Ford sale provided that the sale of these assets is considered in our upcoming annual borrowing base redetermination on April 1, 2018.
A decline in commodity prices could result in the future reduction of our borrowing base and related commitments under the revolving credit facility. Unless commodity prices decline significantly from current levels, we do not believe that any such reductions would have a significant impact on our ability to service our debt and fund our drilling program and related operations.
We strive to manage our debt at a level below the available credit line in order to maintain borrowing capacity. Our revolving credit facility includes a covenant limiting our total debt.flows. We believe that, with the existingoperating cash flow, cash on hand internally generated cash flow and availability under our revolving credit facility, we have the capacityability to finance our spending plans.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, 2017,2021, we were in compliance with all restrictive financial covenants for both thehad 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 and senior notes. As of December 31, 2017,includes a covenant limiting our borrowing capacity based on our asset coverage and leverage ratios, there were no interest rate adjustments required for our senior notes. Seeratio. Refer to Note 54 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 | 313 | |
| (584) | |
| (543) | |
Cash flows used in financing activities | (1,086) | |
| (256) | |
| (690) | |
| | | | | |
|
| | | | | | | | | | | |
| Year Ended December 31, |
(In thousands) | 2017 |
| 2016 |
| 2015 |
Cash flows provided by operating activities | $ | 898,160 |
|
| $ | 397,441 |
|
| $ | 749,598 |
|
Cash flows used in investing activities | (706,153 | ) |
| (353,218 | ) |
| (993,334 | ) |
Cash flows provided by (used in) financing activities | (210,502 | ) |
| 453,805 |
|
| 223,296 |
|
Net increase (decrease) in cash and cash equivalents | $ | (18,495 | ) |
| $ | 498,028 |
|
| $ | (20,440 | ) |
Operating Activities.Operating cash flow fluctuations are substantially driven by commodity prices, changes in ourcommodity prices, production volumes and operating expenses. Prices for natural gas and crude oilCommodity prices have historically been volatile, primarily as a result of supply and demand for oil and natural gas, and crude oil, pipeline infrastructure constraints, basis differentials, inventory storage levels, seasonal influences and seasonal influences.other factors. In addition, fluctuations in cash flow may result in an increase or decrease in our capital expenditures. See "Results
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 Operations" for a review ofemployee benefits that were triggered by the impact of prices and volumes on revenues.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, sales andpayment 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, 20172021 and 2016,2020, we had a working capital surplus of $134.9$916 million and $458.1$26 million, respectively. We believe we have adequate liquidity and availability under our revolving credit facility available to meet our working capital requirements over the next twelve12 months.
Net cash provided by operating activities in 20172021 increased by $500.7$889 million when compared to 2016.2020. This increase was primarily due to higher operating revenues,natural gas, oil and NGL revenue, partially offset by higher operating expenses, (excluding non-cash expenses)higher cash paid on derivative settlements and unfavorable changes in working capital and other assets and liabilities. The increase in operating revenuesnatural gas,
oil and NGL revenue was primarily due to the Merger, an increase in realized natural gas and crude oil prices and higher equivalent production. Average realized natural gas and crude oil prices increased by 36% and 29%, respectively, for 2017 compared to 2016. Equivalent production increased by 9% for 2017 over 2016 as a result ofmoderately higher natural gas production in the Marcellus Shale.
Net cash provided by operating activities in 2016 decreased by $352.2 million when compared to 2015. This decrease was primarily due to unfavorable changes in working capital and other assets and liabilities and lower operating revenues, partially offset by lower operating expenses (excluding non-cash expenses). The decrease in operating revenues was primarily due to a decrease in realized natural gas and crude oil prices, partially offset by an increase in equivalent production. Average realized natural gas and crude oil prices decreasedincreased by 21% and 18%, respectively, for 201687 percent in 2021 compared to 2015. Equivalent production increased by 4% for 2016 over 2015 as a result2020.
Refer to “Results of higher natural gas production in the Marcellus Shale, partially offset by lower crude oil production in the Eagle Ford Shale.
See "Results of Operations"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 increased by $352.9 million from 2016 to 2017 due to an increase of $389.4 million in capital expenditures and $28.6 million higher capital contributions associated with our equity method investments, partially offset by $65.0 million higher proceeds from the sale of assets.
Cash flows used in investing activities decreased by $640.1$897 million from 20152020 compared to 20162021. 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 a decrease of $580.4 million in capital expenditures, $16.3 million lower acquisition costs and $42.8 million higher proceeds from the sale of assets.
Financing Activities. Cash flows provided by financing activities decreased by $664.3 million from 2016 to 2017 due to $995.3 million lower net proceeds from the issuance of common stock in 2016, $123.7 million of repurchases of our common stock in 2017 and $42.7$621 million of higher dividend payments related to an increase in the dividend rate in 2017special and the issuance ofvariable common stock dividends paid in 2016. These decreases were partially offset by $497.02021, $101 million of lowerhigher net repayments of debt dueprimarily related to the repaymentmaturities of the outstanding balance on our revolving credit facility and certain of our senior notes with the proceeds from the issuance of common stock in 2016.
Cash flows provided by financing activities increased by $230.5and $104 million from 2015 to 2016 due to $995.3 million of net proceedshigher tax withholding payments related to share-based awards that vested as a result of the issuanceMerger.
2020 and 2019 Compared. For information on the comparison of common stockoperating, investing and lower capitalized debt issuance costs of $4.6 million relatedfinancing cash flows for the year ended December 31, 2019 compared to the amendment of our revolving credit facility and senior notesyear 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 2015. These increases were partially offset by $770.0 million of higher net repayments of debt due to the repayment of the outstanding balance on our revolving credit facility and certain of our senior notes with the proceeds from the issuance of common stock and $3.1 million of higher dividend payments.31, 2020.
Capitalization
Information about our capitalization is as follows:
|
| | | | | | | |
| December 31, |
(Dollars in thousands) | 2017 | | 2016 |
Debt(1) | $ | 1,521,891 |
| | $ | 1,520,530 |
|
Stockholders' equity | 2,523,905 |
| | 2,567,667 |
|
Total capitalization | $ | 4,045,796 |
| | $ | 4,088,197 |
|
Debt to total capitalization | 38 | % | | 37 | % |
Cash and cash equivalents | $ | 480,047 |
| | $ | 498,542 |
|
| | | | | | | | | | | |
| 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.
| |
(1) | Includes $304.0 million of current portion of long-term debt at December 31, 2017. There were no borrowings outstanding under our revolving credit facility as of December 31, 2017 and 2016, respectively. |
During 2017, we repurchased 5.0 million(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 $123.7 million. 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 20172021 and 2016,2020, we paid dividends of $78.8$780 million ($0.171.12 per share) and $36.2$159 million ($0.080.40 per share) on our common stock, respectively.
In May 2017, theApril 2021, our Board of Directors approved an increase in the quarterly dividend on our common stock from $0.02$0.10 per share to $0.05$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 $0.05$0.125 per share to $0.06$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) | | (In millions) | 2021 | | 2020 | | 2019 |
Acquisitions(1) : | | Acquisitions(1) : | | | | | |
Proved | | Proved | $ | 7,472 | | | $ | — | | | $ | — | |
Unproved | | Unproved | 5,381 | | | — | | | — | |
Total | | Total | $ | 12,853 | | | $ | — | | | $ | — | |
| Year Ended December 31, | | | | | | |
(In thousands) | 2017 | | 2016 | | 2015 | |
Capital expenditures | |
| | |
| | |
| Capital expenditures | | | | | |
Drilling and facilities | $ | 637,207 |
| | $ | 359,479 |
| | $ | 729,994 |
| |
Drilling, completion and facilities | | Drilling, completion and facilities | $ | 688 | | | $ | 547 | | | $ | 761 | |
Leasehold acquisitions | 102,265 |
| | 2,703 |
| | 20,097 |
| Leasehold acquisitions | 5 | | | 6 | | | 6 | |
Property acquisitions | — |
| | — |
| | 16,312 |
| |
| Pipeline and gathering | 716 |
| | 1,909 |
| | 2,373 |
| Pipeline and gathering | 9 | | | — | | | — | |
Other | 17,034 |
| | 8,386 |
| | 4,739 |
| Other | 23 | | | 17 | | | 16 | |
| 757,222 |
| | 372,477 |
| | 773,515 |
| | 725 | | | 570 | | | 783 | |
Exploration expenditures(1) | 21,526 |
| | 27,662 |
| | 27,460 |
| |
Exploration expenditures(2) | | Exploration expenditures(2) | 18 | | | 15 | | | 21 | |
Total | $ | 778,748 |
| | $ | 400,139 |
| | $ | 800,975 |
| 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.
(1)(2)Exploration expenditures include$3.8 million, $10.1 $4 million and $3.3$2 million of exploratory dry hole expendituresdry-hole costs in 2017, 20162020 and 2015,2019, respectively. There were no exploratory dry-hole costs in 2021.
In 2017,2021, we drilled 91114 gross wells (82.5(99.9 net) and completed 105132 gross wells (94.2(108.3 net), of which 5014 gross wells (44.3(13.0 net) were drilled but uncompleted in prior years. In 2018, we plan
Our 2022 capital program is expected to allocatebe 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 majority of our capital toPermian Basin, 44 percent in the Marcellus Shale where we expectand the balance in the Anadarko Basin. Midstream, saltwater disposal, electrification, infrastructure and other investments are expected to drill 85 gross wells (85.0 net) and complete 95 gross wells (95.0 net). Our 2018 drilling program includestotal approximately $890.0$175 million in total capital expenditures.the year. We will continue to assess the natural gascommodity price environment along with our liquidity position and may increase or decrease our capital expenditures accordingly.
Contractual Obligations
We have various contractual obligations in the normal course of our operations. A summary of our contractual obligations asAs of December 31, 2017 are set forth2021, 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 following table:properties operated by us could incur a portion of these costs. We expect that our sources of capital will be
|
| | | | | | | | | | | | | | | | | | | |
|
|
| Payments Due by Year |
(In thousands) | Total |
| 2018 |
| 2019 to 2020 |
| 2021 to 2022 |
| 2023 & Beyond |
Debt | $ | 1,528,000 |
|
| $ | 304,000 |
|
| $ | 87,000 |
|
| $ | 188,000 |
|
| $ | 949,000 |
|
Interest on debt(1) | 340,278 |
|
| 65,947 |
|
| 100,780 |
|
| 84,002 |
|
| 89,549 |
|
Transportation and gathering agreements(2) | 1,744,684 |
|
| 105,478 |
|
| 320,671 |
|
| 314,448 |
|
| 1,004,087 |
|
Operating leases(2) | 30,005 |
|
| 6,541 |
|
| 12,298 |
|
| 6,623 |
|
| 4,543 |
|
Equity investment contribution commitments(3) | 75,000 |
|
| 60,000 |
|
| 15,000 |
|
| — |
|
| — |
|
Total contractual obligations | $ | 3,717,967 |
|
| $ | 541,966 |
|
| $ | 535,749 |
|
| $ | 593,073 |
|
| $ | 2,047,179 |
|
53
| |
(1) | Interest payments have been calculated utilizing the rates associated with our senior notes outstanding at December 31, 2017, assuming that our senior notes will remain outstanding through their respective maturity dates. |
| |
(2) | For further information on our obligations under transportation and gathering agreements and operating leases, see Note 9 of the Notes to the Consolidated Financial Statements. |
| |
(3) | For further information on our equity investment contribution commitments, see Note 4 of the Notes to the Consolidated Financial Statements. |
adequate to our asset retirement obligation are not included in the above table given the uncertainty regarding the actual timing of such expenditures. The total amount of our asset retirement obligation at December 31, 2017 was $64.3 million, of which $15.7 million was classified as liabilities held for sale. See Note 8 offund 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.
Potential Impact of Our Critical Accounting PoliciesEstimates
Our significant accounting policies are described in Note 1 of the Notes to the Consolidated Financial Statements. The preparation of the Consolidated Financial Statements, which is in accordance with accountingIn preparing financial statements, we follow GAAP. These principles generally accepted in the United States, requiresrequire management to make certain estimates and judgmentsassumptions that affect the amounts reported in our financial statements and the related disclosuresamounts of assets and liabilities. The following accounting policies are our most critical policies requiring more significant judgmentsliabilities, the disclosure of contingent assets and estimates. We evaluate our estimatesliabilities as of the date of the balance sheet, and assumptions on a regular basis.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 ultimately 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 holedry-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 reservereserves data included in this document areis only estimates.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 natural gas and crude oilcommodity 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.
Our reservesThe reserve quantity estimates of our oil and gas properties have been prepared by our petroleum engineering staff and audited bystaff. 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 petroleum engineers, whoevaluation 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 opinion determined theopinions, that our presented estimates presented to beare 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 depreciation, depletion and amortization (DD&A)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 5%five percent positive or negative revision to proved reserves would result in a decrease of $0.03$0.29 per McfeBOE and an increase of $0.04$0.32 per Mcfe,BOE, respectively, on our DD&A rate. Revisions in significant fields may individually affect our DD&A rate. ItThis estimated impact is estimated that a positive or negative reserve revision of 10% in one of our most productive fields would result in a decrease of $0.04 per Mcfe and an increase of $0.05 per Mcfe, respectively, on our total DD&A rate. These estimated impacts are 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, managementwe cannot determine if an impairment is reasonably likely to occur in the future.
Carrying Value of 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 natural gas and crude oilcommodity prices, operating costs and anticipated production from proved reserves and risk-adjusted probable and possible reserves, are lower than the net book value of the asset, the capitalized cost is reduced to fair value. Commodity pricing is estimated by using a combination of assumptions management uses in its budgeting and forecasting process, historical and current prices adjusted for geographical location and quality differentials, as well as other factors that management believeswe believe will impact realizable prices. In the event that commodity prices significantly decline, management
we would test the recoverability of the carrying value of itsour 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 and oil.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. We have considered these impacts when determining the amortization rate of our undeveloped acreage, especially in exploratory areas. If the average unproved property life decreases or increases by one year, the amortization would increase by approximately $11.7 million or decrease by approximately $9.6 million, respectively, per year.
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 isare 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.
Asset Retirement Obligations
The majority of our asset retirement obligations (ARO) relates to the plugging and abandonment of oil and gas wells. We record the fair value of a liability for an asset retirement obligation in the period in which it is incurred, with the associated asset retirement cost capitalized as part of the carrying amount of the related long-lived asset. The recognition of an asset retirement obligation requires management to make assumptions that include estimated plugging and abandonment costs, timing of settlements, inflation rates and discount rate. In periods subsequent to initial measurement, the asset retirement cost is depreciated using the units-of-production method, while increases in the discounted ARO liability resulting from the passage of time (accretion expense) are reflected as depreciation, depletion and amortization expense.
Accounting for Derivative Instruments and Hedging Activities
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 and the ineffective portion of the change in the fair value of derivatives designated as cash flow hedges and 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, for natural gas and crude oil, basis differentials, volatility factors and interest rates such as a LIBOR curve 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 inwith 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 natural gas and crude oilcommodity 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%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, management'sour 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 eithervarious models, including both a Black Scholes or a Monte Carlo or Black-Scholes 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. Stock-based compensation cost for all types of awards is included in general
Recently Issued and administrative expense in the Consolidated Statement of Operations. See Note 13 of the Notes to the Consolidated Financial Statements for a full discussion of our stock-based compensation.
Recently Adopted Accounting Pronouncements
Refer to Note 1 of the Notes to the Consolidated Financial Statements, "Summary“Summary of Significant Accounting Policies,"” for a discussion of recently issued and adopted accounting pronouncements.
Recently Issued Accounting PronouncementsRefer to Note 1
OTHER ISSUES AND CONTINGENCIES
Regulations.Regulations
Our operations are subject to various types of regulation by federal, state and local authorities. SeeRefer to the "Other“Other Business Matters"Matters” section of Item 1 for a discussion of these regulations.
Restrictive Covenants. Covenants
Our ability to incur debt, and toincur liens, pay dividends, repurchase or redeem our equity interests, redeem our senior notes, make certain types of investments, isenter 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. Among other requirements, ourIn addition, the senior note agreements and our revolving credit agreement specifygoverning 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 minimum asset coveragemaximum ratio of total debt to consolidated EBITDA for the present valuetrailing four quarters of proved reserves before income taxes plus adjusted cashnot more than 3.0 to indebtedness and other liabilities of 1.25 to 1.0, which increases to a ratio of 1.75 to 1.0 beginning on January 1, 2018 and thereafter.1.0. Our revolving credit agreement also requires us to maintain a minimum currentleverage 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 1.0. maintain a ratio of total debt to total capitalization of no more than 65 percent.
At December 31, 2017,2021, we were in compliance with all restrictive financial covenants in both our senior note agreements and our revolving credit agreement.
Operating Risks and Insurance Coverage.Coverage
Our business involves a variety of operating risks. See "RiskRefer to “Risk Factors—Business and Operational Risks—We face a variety of hazards and risks that could cause substantial financial losses"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 of theseloss 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. Activities
Our revenues, operating results, financial condition and ability to borrow funds or obtain additional capital depend substantially on prevailing prices for natural gas and crude oil. Furthercommodity prices. Significant declines in natural gas and crude oilcommodity prices may have a material adverse effect on our financial condition, liquidity, ability to obtain financing and operating results. Lower natural gas and crude oilcommodity prices also may reduce the amount of oil and natural gas and crude oil that we can produce economically. Historically, natural gas and crude oilcommodity 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. Because our reserves are predominantly natural gas (approximately 96% of equivalent proved reserves), changes in natural gas prices may have a more significant impact on our financial results than oil prices.
The majority of our production is sold at market responsivemarket-sensitive prices. Generally, if the related commodity index declines, the price that we receive for our production will also decline. Furthermore, we have experienced widening basis differentials in certain regions, such as in the Appalachian region, resulting in further declines in natural gas prices. Therefore, the amount of revenue that we realize is determined by certain factors that are beyond our control. However, managementwe may mitigate this price risk on a portion of our anticipated production with the use of commodity derivatives. Most recently, we have usedfinancial commodity derivatives, such as collar, swapincluding collars, swaps, roll differential swaps and basis swap arrangementsswaps to reduce the impact of sustained lower pricing on our revenue. Under boththese 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
20172021 and 20162020 Compared
We reported net income for 2017 of $100.4 million, or $0.22 per share, compared to net loss for 2016 of $417.1 million, or $0.91 per share. The increase in net income was primarily due to higher operating revenues and higher income tax benefit, partially offset by higher operating expenses and loss on sale of assets.Operating Revenues
Revenue, Price and Volume Variances | | | | | | | | | | | | | | | | | | | | | | | |
| 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 as a resultand are derived from sales of changesour 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 production volumes. 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.
|
| | | | | | | | | | | | | | |
| Year Ended December 31, | | Variance |
Revenue Variances (In thousands) | 2017 | | 2016 | | Amount | | Percent |
Natural gas | $ | 1,506,078 |
| | $ | 1,022,590 |
| | $ | 483,488 |
| | 47 | % |
Crude oil and condensate | 212,338 |
| | 151,106 |
| | 61,232 |
| | 41 | % |
Gain (loss) on derivative instruments | 16,926 |
| | (38,950 | ) | | 55,876 |
| | 143 | % |
Brokered natural gas | 17,217 |
| | 13,569 |
| | 3,648 |
| | 27 | % |
Other | 11,660 |
| | 7,362 |
| | 4,298 |
| | 58 | % |
| $ | 1,764,219 |
| | $ | 1,155,677 |
| | $ | 608,542 |
| | 53 | % |
|
| | | | | | | | | | | | | | | | | | |
| Year Ended December 31, | | Variance | Increase (Decrease) (In thousands) |
| 2017 | | 2016 | | Amount | | Percent |
Price Variances | |
| | |
| | |
| | |
| | |
|
Natural gas | $ | 2.30 |
| | $ | 1.70 |
| | $ | 0.60 |
| | 35 | % | | $ | 389,648 |
|
Crude oil and condensate | $ | 47.81 |
| | $ | 37.65 |
| | $ | 10.16 |
| | 27 | % | | 45,118 |
|
Total | |
| | |
| | |
| | |
| | $ | 434,766 |
|
Volume Variances | |
| | |
| | |
| | |
| | |
|
Natural gas (Bcf) | 655.6 |
| | 600.4 |
| | 55.2 |
| | 9 | % | | $ | 93,840 |
|
Crude oil and condensate (Mbbl) | 4,441 |
| | 4,013 |
| | 428 |
| | 11 | % | | 16,114 |
|
Total | |
| | |
| | |
| | |
| | $ | 109,954 |
|
Natural Gas Revenues
The increase in natural | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| 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 of $483.5 million wasincreased $1.4 billion primarily due to significantly higher natural gas prices and production. The increase in production was a result of an increase in our drilling and completion activities in Pennsylvania.
Crude Oil and Condensate Revenues
The increase in crude oil and condensate revenues of $61.2 million was due to higher production and crude oil prices.
Impact of Derivative Instruments on Operating Revenues |
| | | | | | | |
| Year Ended December 31, |
(In thousands) | 2017 | | 2016 |
Cash received (paid) on settlement of derivative instruments | |
| | |
|
Gain (loss) on derivative instruments | $ | 8,056 |
| | $ | (1,682 | ) |
Non-cash gain (loss) on derivative instruments | |
| | |
|
Gain (loss) on derivative instruments | 8,870 |
| | (37,268 | ) |
| $ | 16,926 |
| | $ | (38,950 | ) |
|
| | | | | | | | | | | | | | | | | | |
| Year Ended December 31, | | Variance | | Price and Volume Variances (In thousands) |
| 2017 | | 2016 | | Amount | | Percent | |
Brokered Natural Gas Sales | | |
| | | |
| | |
| | |
| | |
|
Sales price ($/Mcf) | $ | 3.14 |
| | $ | 2.55 |
| | $ | 0.59 |
| | 23 | % | | $ | 3,236 |
|
Volume brokered (Mmcf) | x | 5,485 |
| | x | 5,321 |
| | 164 |
| | 3 | % | | 412 |
|
Brokered natural gas (In thousands) | $ | 17,217 |
| | $ | 13,569 |
| | |
| | |
| | $ | 3,648 |
|
| | | | | | | | | | | |
Brokered Natural Gas Purchases | | |
| | | |
| | |
| | |
| | |
|
Purchase price ($/Mcf) | $ | 2.78 |
| | $ | 2.03 |
| | $ | 0.75 |
| | 37 | % | | $ | 4,114 |
|
Volume brokered (Mmcf) | x | 5,485 |
| | x | 5,321 |
| | 164 |
| | 3 | % | | 353 |
|
Brokered natural gas (In thousands) | $ | 15,252 |
| | $ | 10,785 |
| | |
| | |
| | $ | 4,467 |
|
| | | | | | | | | | | |
Brokered natural gas margin (In thousands) | $ | 1,965 |
| | $ | 2,784 |
| | |
| | |
| | $ | (819 | ) |
The $0.8 million decrease in brokered natural gas margin is a result of an increase in purchase price that outpaced the increase in sales price and higher brokered volumes.
Operating and Other Expenses
|
| | | | | | | | | | | | | | |
| Year Ended December 31, | | Variance |
(In thousands) | 2017 | | 2016 | | Amount | | Percent |
Operating and Other Expenses | |
| | |
| | |
| | |
|
Direct operations | $ | 102,310 |
| | $ | 100,696 |
| | $ | 1,614 |
| | 2 | % |
Transportation and gathering | 481,439 |
| | 436,542 |
| | 44,897 |
| | 10 | % |
Brokered natural gas | 15,252 |
| | 10,785 |
| | 4,467 |
| | 41 | % |
Taxes other than income | 33,487 |
| | 29,223 |
| | 4,264 |
| | 15 | % |
Exploration | 21,526 |
| | 27,662 |
| | (6,136 | ) | | (22 | )% |
Depreciation, depletion and amortization | 568,817 |
| | 590,128 |
| | (21,311 | ) | | (4 | )% |
Impairment of oil and gas properties and other assets | 482,811 |
| | 435,619 |
| | 47,192 |
| | 11 | % |
General and administrative | 97,786 |
| | 85,633 |
| | 12,153 |
| | 14 | % |
| $ | 1,803,428 |
| | $ | 1,716,288 |
| | $ | 87,140 |
| | 5 | % |
| | | | | | | |
Earnings (loss) on equity method investments | $ | (100,486 | ) | | $ | (2,477 | ) | | $ | (98,009 | ) | | 3,957 | % |
Loss on sale of assets | (11,565 | ) | | (1,857 | ) | | (9,708 | ) | | 523 | % |
Interest expense, net | 82,130 |
| | 88,336 |
| | (6,206 | ) | | (7 | )% |
Loss on debt extinguishment | — |
| | 4,709 |
| | (4,709 | ) | | (100 | )% |
Other expense (income) | (4,955 | ) | | 1,609 |
| | 6,564 |
| | (408 | )% |
Income tax benefit | (328,828 | ) | | (242,475 | ) | | 86,353 |
| | (36 | )% |
Total costs and expenses from operations increased by $87.1 million from 2016 to 2017. The primary reasons for this fluctuation are as follows:
Direct operations increased $1.6 million largely due to an increase in operating costs primarily driven by higher production, partially offset by improved operational efficiencies in 2017 compared to 2016 and the sale of our operations in West Virginia, Virginia and Ohio in the third quarter of 2017.
Transportation and gathering increased $44.9 million due to higher throughput as a result of higher Marcellus Shale production.
Brokered natural gas increased $4.5 million from 2016 to 2017. See the preceding table titled "Brokered Natural Gas" for further analysis.
Taxes other than income increased $4.3 million due to $4.5 million higher production taxes in Texas primarily resulting from higher natural gas and crude oil prices and $2.5 million higher drilling impact fees due to an increase in drilling activity in Pennsylvania. These increases were offset by $2.9 million lower ad valorem taxes as a result of lower property values primarily in south Texas.
Exploration decreased $6.1 million as a result of a $6.3 million decrease in exploratory dry hole expense and lower charges related to the release of certain drilling rig contracts in south Texas. These decreases were partially offset by an increase of $3.0 million in geological and geophysical costs associatedcombined with our new exploratory areas. During 2017, we recorded no rig termination charges, compared to $1.7 million during 2016.
Depreciation, depletion and amortization decreased $21.3 million, of which $92.8 million was due to a lower DD&A rate of $0.73 per Mcfe for 2017 compared to $0.87 per Mcfe for 2016, partially offset by a $50.6 million increase due to higher equivalent production volumes.The lower DD&A rate was primarily due to lower cost reserve additions and the impairment charge recorded in the second quarter of 2016 associated with higher DD&A rate fields. In addition, amortization of unproved properties increased $27.8 million in 2017 as a result of higher lease acquisition costs and amortization rates.
Impairment of oil and gas properties and other assets was $482.8 million in 2017 due to the $414.3 million impairment of oil and gas properties located in south Texas and $68.6 million impairment of oil and gas properties and related pipeline assets in West Virginia, Virginia and Ohio. In 2016, we recognized an impairment of oil and gas properties
and other assets of $435.6 million due to the impairment of oil and gas properties and related pipeline assets in West Virginia and Virginia.
General and administrative increased $12.2 million due to higher stock-based compensation expense of $8.1 million associated with certain of our market-based performance share awards, $3.8 million higher employee-related expenses and $3.2 million of severance costs for employees terminated as a result of its sale of oil and gas properties located in West Virginia, Virginia and Ohio. These increases were partially offset by $5.5 million lower professional services. The remaining changes were not individually significant.
Earnings (Loss) on Equity Method Investments
The increase in loss on equity method investments is due to an other than temporary impairment of $95.9 million associated with our equity method investment in Constitution and recording our proportionate share of net losses from our equity method investments which increased in 2017 compared to 2016.
Loss on Sale of Assets
Loss on sale of assets increased $9.7 million due to the Company's sale of certain oil and gas properties and related pipeline assets located in West Virginia, Virginia and Ohio. During 2016, we recognized a net aggregate loss of $1.9 million primarily due to the sale of certain of our oil and gas properties in Texas.
Interest Expense, net
Interest expense decreased $6.2 million primarily due to a $1.8 million increase in interest income and a $2.1 million decrease in interest expense resulting from the repayment of the outstanding borrowings under our revolving credit facility in March 2016, which has remained undrawn through December 31, 2017. Interest expense also decreased $2.4 million resulting from the repurchase of $64.0 million of our 6.51% weighted-average senior notes in May 2016 and the repayment of $20.0 million of our 7.33% weighted-average senior notes in July 2016.
Loss on Debt Extinguishment
A $4.7 million debt extinguishment loss was recognized in the second quarter of 2016 related to the premium paid for the repurchase of a portion of our 6.51% weighted-average senior notes in May 2016 and the write-off of a portion of the associated deferred financing costs due to early repayment.
Other Expense (Income)
Other income increased $6.6 million primarily due to a curtailment gain of $4.9 million on postretirement benefits as a result of the termination of approximately 100 employees in West Virginia.
Income Tax Benefit
Income tax benefit increased $86.4 million due to a higher effective tax rate, partially offset by a lower pretax loss. The effective tax rates for 2017 and 2016 were 143.9% and 36.8%, respectively. The increase in the effective tax rate is primarily due to the impact of the tax legislation referred to as the Tax Cuts and Jobs Act (the "Tax Act") that was enacted in December 2017. The Tax Act significantly changes U.S. corporate income tax laws by, among other things, reducing the U.S. corporate income tax rate to 21% starting in 2018. Refer to Note 10 of the Notes to the Consolidated Financial Statements for additional discussion on the impact of the Tax Act on our financial results.
Excluding the impact of any discrete items, the provisions of the Tax Act are expected to reduce our 2018 effective income tax rate to approximately 24.0% to 26.0%. However, this rate may fluctuate based on a number of factors, including but not limited to changes in enacted federal and/or state rates that occur during the year, changes in our executive compensation, the amount of excess tax benefits on stock based compensation, as well as changes in the composition and location of our asset base, our employees and our customers.
2016 and 2015 Compared
We reported a net loss for 2016 of $417.1 million, or $0.91 per share, compared to net loss for 2015 of $113.9 million, or $0.28 per share. The increase in net loss was primarily due to lower operating revenues and higher operating expenses, partially offset by a higher income tax benefit.
Revenue, Price and Volume Variances
Our revenues vary from year to year as a result of changes in commodity prices and production volumes. Below is a discussion of revenue, price and volume variances.
|
| | | | | | | | | | | | | | |
| Year Ended December 31, | | Variance |
Revenue Variances (In thousands) | 2016 | | 2015 | | Amount | | Percent |
Natural gas | $ | 1,022,590 |
| | $ | 1,025,044 |
| | $ | (2,454 | ) | | — | % |
Crude oil and condensate | 151,106 |
| | 248,211 |
| | (97,105 | ) | | (39 | )% |
Gain (loss) on derivative instruments | (38,950 | ) | | 56,686 |
| | (95,636 | ) | | (169 | )% |
Brokered natural gas | 13,569 |
| | 16,383 |
| | (2,814 | ) | | (17 | )% |
Other | 7,362 |
| | 10,826 |
| | (3,464 | ) | | (32 | )% |
| $ | 1,155,677 |
| | $ | 1,357,150 |
| | $ | (201,473 | ) | | (15 | )% |
|
| | | | | | | | | | | | | | | | | | |
| Year Ended December 31, | | Variance | | Increase (Decrease) (In thousands) |
| 2016 | | 2015 | | Amount | | Percent | |
Price Variances | |
| | |
| | |
| | |
| | |
|
Natural gas | $ | 1.70 |
| | $ | 1.81 |
| | $ | (0.11 | ) | | (6 | )% | | $ | (64,718 | ) |
Crude oil and condensate | $ | 37.65 |
| | $ | 45.72 |
| | $ | (8.07 | ) | | (18 | )% | | (32,365 | ) |
Total | |
| | |
| | |
| | |
| | $ | (97,083 | ) |
Volume Variances | |
| | |
| | |
| | |
| | |
|
Natural gas (Bcf) | 600.4 |
| | 566.0 |
| | 34.4 |
| | 6 | % | | $ | 62,264 |
|
Crude oil and condensate (Mbbl) | 4,013 |
| | 5,429 |
| | (1,416 | ) | | (26 | )% | | (64,740 | ) |
Total | |
| | |
| | |
| | |
| | $ | (2,476 | ) |
Natural Gas Revenues
The decrease in natural gas revenues of $2.5 million was due to lower natural gas prices, partially offset by 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 resultfunction 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 drillingderivative instruments and completioncash 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 Pennsylvania, partiallyour 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 OperationsDirect 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 the divestiture of certain oil and gas properties in east Texas in early 2016.
Crude Oil and Condensate Revenues
Thea decrease in crude oil and condensate revenues of $97.1 million wascosts due to lower production and crude oil prices. The decrease in production was a result of a decrease in drilling and completion activities in south Texas.
Impact of Derivative Instruments on Operating Revenues |
| | | | | | | |
| Year Ended December 31, |
(In thousands) | 2016 | | 2015 |
Cash received (paid) on settlement of derivative instruments | |
| | |
|
Gain (loss) on derivative instruments | (1,682 | ) | | 194,289 |
|
Non-cash gain (loss) on derivative instruments | |
| | |
|
Gain (loss) on derivative instruments | (37,268 | ) | | (137,603 | ) |
| $ | (38,950 | ) | | $ | 56,686 |
|
|
| | | | | | | | | | | | | | | | | | |
| Year Ended December 31, | | Variance | | Price and Volume Variances (In thousands) |
| 2016 | | 2015 | | Amount | | Percent | |
Brokered Natural Gas Sales | | |
| | | |
| | |
| | |
| | |
|
Sales price ($/Mcf) | $ | 2.55 |
| | $ | 2.83 |
| | $ | (0.28 | ) | | (10 | )% | | $ | (1,490 | ) |
Volume brokered (Mmcf) | x | 5,321 |
| | x | 5,784 |
| | (463 | ) | | (8 | )% | | (1,324 | ) |
Brokered natural gas (In thousands) | $ | 13,569 |
| | $ | 16,383 |
| | |
| | |
| | $ | (2,814 | ) |
| | | | | | | | | | | |
Brokered Natural Gas Purchases | | |
| | | |
| | |
| | |
| | |
|
Purchase price ($/Mcf) | $ | 2.03 |
| | $ | 2.18 |
| | $ | (0.15 | ) | | (7 | )% | | $ | (798 | ) |
Volume brokered (Mmcf) | x | 5,321 |
| | x | 5,784 |
| | (463 | ) | | (8 | )% | | (1,009 | ) |
Brokered natural gas (In thousands) | $ | 10,785 |
| | $ | 12,592 |
| | |
| | |
| | $ | (1,807 | ) |
| | | | | | | | | | | |
Brokered natural gas margin (In thousands) | $ | 2,784 |
| | $ | 3,791 |
| | |
| | |
| | $ | (1,007 | ) |
The $1.0 million decrease in brokered natural gas margin is a result of a decrease in sales price that outpaced the decrease in purchase price and lower brokered volumes.
Operating and Other Expenses |
| | | | | | | | | | | | | | |
| Year Ended December 31, | | Variance |
(In thousands) | 2016 | | 2015 | | Amount | | Percent |
Operating and Other Expenses | |
| | |
| | |
| | |
|
Direct operations | $ | 100,696 |
| | $ | 140,814 |
| | $ | (40,118 | ) | | (28 | )% |
Transportation and gathering | 436,542 |
| | 427,588 |
| | 8,954 |
| | 2 | % |
Brokered natural gas | 10,785 |
| | 12,592 |
| | (1,807 | ) | | (14 | )% |
Taxes other than income | 29,223 |
| | 42,809 |
| | (13,586 | ) | | (32 | )% |
Exploration | 27,662 |
| | 27,460 |
| | 202 |
| | 1 | % |
Depreciation, depletion and amortization | 590,128 |
| | 622,211 |
| | (32,083 | ) | | (5 | )% |
Impairment of oil and gas properties and other assets | 435,619 |
| | 114,875 |
| | 320,744 |
| | 279 | % |
General and administrative | 85,633 |
| | 67,996 |
| | 17,637 |
| | 26 | % |
| $ | 1,716,288 |
| | $ | 1,456,345 |
| | $ | 259,943 |
| | 18 | % |
| | | | | | | |
Earnings (loss) on equity method investments | $ | (2,477 | ) | | $ | 6,415 |
| | $ | (8,892 | ) | | (139 | )% |
Gain (loss) on sale of assets | (1,857 | ) | | 3,866 |
| | (5,723 | ) | | (148 | )% |
Loss on debt extinguishment | 4,709 |
| | — |
| | 4,709 |
| | 100 | % |
Interest expense, net | 88,336 |
| | 96,911 |
| | (8,575 | ) | | (9 | )% |
Other expense (income) | 1,609 |
| | 1,448 |
| | 161 |
| | 11 | % |
Income tax benefit | (242,475 | ) | | (73,382 | ) | | 169,093 |
| | 230 | % |
Total costs and expenses from operations increased by $259.9 million from 2015 to 2016. The primary reasons for this fluctuation are as follows:
Direct operations decreased $40.1 million largely due to improved operational efficiencies, cost reductions from service providers and suppliers in 2016 compared to 2015 and divestiture of certain oil and gas properties in east Texas in February 2016.
Transportation and gathering increased $9.0 million due to higher throughput as a result of higher Marcellus Shale production and the commencement of various transportation and gathering agreements in the Marcellus Shale throughout 2015.Shale.
BrokeredTaxes 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 decreased $1.8 million from 2015 to 2016. Seeprices and ad valorem taxes being based on the precedingvalue of properties. The following table titled “Brokered Natural Gas”presents taxes other than income for further analysis.
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 decreased $13.6 millionincreased $69 million. Production taxes represented the majority of our taxes other than income, which increased primarily due to $7.2 million lower production taxes resulting from lower crude oil pricesthe Merger and production in south Texas and the receipt of a production tax refund of $1.9 million in February 2016. Additionally, drillinghigher commodity prices. Drilling impact fees decreased $1.5 million as a result of drilling fewer wells in Pennsylvania during 2016 compared to 2015 and ad valorem taxes decreased $3.8 million as a result of lower property valuesincreased primarily in south Texas. The remaining changes were not individually significant.
Exploration increased $0.2 million as a result of a $6.7 million increase in exploratory dry hole expense, partially offset by lower charges related to the release of certain drilling rig contracts in south Texas and $2.7 million lower geophysical and geological costs and other exploration expenses. During 2016, we recorded rig termination charges of $1.7 million, compared to $5.1 million during 2015.
Depreciation, depletion and amortization decreased $32.1 million, of which $41.2 million was due to a lower DD&A rate of $0.87 per Mcfe for 2016 compared to $0.93 per Mcfe for 2015, partially offset by a $23.0 million increase due to higher equivalent production volumes.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 lower DD&A rate was primarily due to lower cost reserve additionseconomic 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 impairment charge recordedlevel of proved developed and proved reserves used in the fourth quartercalculation. Higher prices generally have the effect of 2015 associated with higher DD&A rate fields.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, amortizationchanges in estimates of reserve quantities, estimates of operating and future development costs, reclassifications of properties from unproved properties decreased $16.4 million in 2016 as a result of lower lease acquisition coststo proved and lower amortization rates.
Impairmentimpairments of oil and gas properties and other assets was $435.6will also impact depletion expense. Our depletion expense increased $290 million in 2016 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 impairmentvalue 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 pipeline assets in West Virginiabenefits, stock-based compensation, office rent, legal and Virginia. In 2015, we recognized an impairmentconsulting 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 of $114.9 million related to certain fields in south Texas, east Texas and Louisiana.we operate. The impairment of these fields was due to a significant decline in commodity prices in late 2015.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 $17.6 million due to higher stock-based compensation expense of $12.3 million primarily the result of an increase in the Company's stock price during 2016 compared to 2015 and $2.7 million higher professional services. The remaining changes were not individually significant.
Earnings (Loss) on Equity Method Investments
The increase in loss on equity method investments is due to recording our proportionate share of net losses from our equity method investments which increased in 2016 compared to 2015.
Gain (Loss) on Sale of Assets
During 2016, we recognized a net aggregate loss of $1.9$44 million primarily due to the saleMerger, 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 our oilthe Merger of $10 million and gas propertiesan increase in eastcompensation 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 south Texas. During 2015, we recognized afinancial 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 aggregate gain of $3.9
Interest expense increased $8 million primarily due to the saleincremental interest expense, net of certain unproved oil and gas properties in east Texas.
Loss on Debt Extinguishment
A $4.7 million extinguishment loss was recognized inpremium amortization associated with the second quarter of 2016debt related to the premium paid forMerger of $2.2 billion, including the repurchaseNew Coterra Notes and Existing Cimarex Notes. This increase was partially offset by lower interest expense due to repayment of a portion$87 million of our 6.51% weighted-average private placement senior notes, which matured in May 2016 and the write-off of a portion of the associated deferred financing costs due to early repayment.
Interest Expense, net
Interest expense decreased $8.6 million due to a $5.5 million decrease resulting fromJuly 2020, the repayment of the outstanding borrowings under our revolving credit facility in March 2016, which remained undrawn through December 31, 2016. Interest expense also decreased $3.4$88 million resulting from the repurchase of a portion of our 6.51%5.58% weighted-average private placement senior notes, which matured in May 2016January 2021, and the repayment of $100 million of our 7.33%3.65% weighted-average private placement senior notes, at maturity. These decreases were offset by a $0.6 million increasewhich matured in commitment fees as a resultSeptember 2021.
Income Tax BenefitExpense | | | | | | | | | | | | | | | | | |
| 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 benefitexpense increased $169.1$303 million due to a higher pretax loss, partially offset by a lower effective tax rate. The effective tax ratesincome attributable to increased commodity prices and the Merger.
2020 and 2019 Compared
For information on the comparison of the results of operations for 2016the year ended December 31, 2020 compared to the year ended December 31, 2019, refer to Management's Discussion and 2015 were 36.8% and 39.2%, respectively. The decreaseAnalysis included in the effective tax rate is primarily due toCoterra Energy Inc., formerly known as Cabot Oil & Gas Corporation, Annual Report on Form 10-K for the impact of non-recurring discrete items recorded during 2016 compared to 2015.year ended December 31, 2020.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
MarketIn 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 primarymost significant market risk exposure is exposurepricing applicable to our oil, natural gas and crude oil prices.NGL production. Realized prices are mainly driven by the worldwide pricesprice for crude oil and spot market prices for North American natural gas and NGL production. CommodityThese prices can behave 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 and crude oil 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, provide only partial price protection by limiting the benefit to us of increases in prices, while protecting us in the event of price declines.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 65 of the Notes to the Consolidated Financial Statements, “Derivative Instruments,” for a more detailed discussion of our derivative and risk management activities.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 and crude oil 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 or crude oil in exchange for paying a variable price based on a market-based index, such as the NYMEX gas and crude oil futures.index.
As of December 31, 2017,2021, 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) | |
________________________________________________________ |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | Collars | | | | |
| | | | | | | Floor | | Ceiling | | Basis Swaps | | Asset |
Type of Contract | | Volume | | Contract Period | | Range | | Weighted- Average | | Range | | Weighted- Average | | Weighted- Average | | (Liability) (In thousands) |
Financial contracts | | |
| | | | | | | | | | | |
|
Natural gas (Leidy) | | 17.7 |
| Bcf | | Jan. 2018 - Dec. 2018 | |
| |
| |
| |
| | $ | (0.71 | ) | | (1,168 | ) |
Natural gas (Transco) | | 21.3 |
| Bcf | | Jan. 2018 - Dec. 2019 | |
| |
| |
| |
| | $ | 0.42 |
| | 1,097 |
|
Crude oil (WTI/LLS) | | 2.9 |
| Mmbbl | | Jan. 2018 - Dec. 2018 | | $ | — |
| | $ | 55.00 |
| | $63.35-$63.80 | | $ | 63.62 |
| | | | (6,121 | ) |
| | | | | | | | | | | | | | | | | $ | (6,192 | ) |
In January 2018, we entered into the following financial commodity derivative contracts:
|
| | | | | | | | | | | |
| | | | | | | | Swaps | | Basis Swaps |
Type of Contract | | Volume | | Contract Period | | Weighted- Average | | Weighted- Average |
Financial contracts | | | | | | | | | | |
Natural gas (NYMEX) | | 84.4 |
| | Bcf | | Feb. 2018 - Dec. 2018 | | $2.93 | | |
Natural gas (NYMEX) | | 13.3 |
| | Bcf | | Feb. 2018 - Oct. 2018 | | $3.10 | | |
Natural gas (Leidy) | | 16.2 |
| | Bcf | | Feb. 2018 - Dec. 2018 | | | | $(0.68) |
In the above tables, natural gas prices are stated per Mcf and crude oil prices are stated per barrel.
As of December 31, 2017, we had the following outstanding physical commodity derivatives:
|
| | | | | | | | | | | | | |
Type of Contract | | Volume | | Contract Period | | Weighted-Average Fixed Price | | Asset (Liability) (In thousands) |
Physical contracts | | | | | | | | | | |
Natural gas purchase | | 81.2 |
| | Bcf | | Jan. 2018 - Oct. 2018 | | $3.70 | | (12,745 | ) |
Natural gas sales | | 11.7 |
| | Bcf | | Jan. 2018 - Feb. 2018 | | $4.71 | | (9,471 | ) |
| | | | | | | | | | $ | (22,216 | ) |
In the table above, natural gas prices are stated per Mcf.
In January 2018,(1)The index price the Company terminated certain physical purchase contracts prior to their settlement date. 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 termination did not have a material impact on the Consolidated Financial Statements,index price for these collars is El Paso Natural Gas Company, Permian Basin Index (“Perm EP”) as the contracts were previously recognized at fair value.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 tablestable above represent our total unrealized derivative position at December 31, 20172021 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 inwith which we have derivative transactions,contracts, while our non-performance risk is evaluated using a market credit spread provided by oneseveral 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 and crude oil production for 20182022 and beyond is currently unhedged and directly exposed to the volatility in natural gas and crude oil marketcommodity prices, whether favorable or unfavorable.
During 2017,2021, 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 of $3.09ranging from $1.50 to $2.85 per McfMmbtu and ceiling prices ranging from $3.42$1.75 to $3.45$3.94 per McfMmbtu covered 35.5193.2 Bcf, or 5% of natural gas production at an average price of $3.20 per Mcf. Natural gas swaps covered 51.7 Bcf, or 8%,21 percent of natural gas production at a weighted-average price of $3.23$2.85 per Mcf. Crude oil collars with floor pricesMmbtu. Natural gas swaps covered 56.3 Bcf, or six percent, of $50.00 per Bbl and ceiling prices ranging from $56.25 to $56.50 per Bbl covered 1.8 Mmbbl, or 41%, of crude oilnatural gas production at a weighted-average price of $51.78$3.16 per Bbl.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 and crude oil.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.
The preceding paragraphs contain forward-looking information concerning future productionInterest 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, projected gainsas 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, losses, which may be impacted both by production and by changes in the future commodity prices. See “Forward-Looking Information” for further details.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 amountamounts reported in the Consolidated Balance Sheet for cash and cash equivalents approximatesand restricted cash approximate fair value due to the short-term maturities of these instruments. Cash and cash equivalents are classified as Level 1 in the
The fair value hierarchy.
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 debt.our private placement senior notes. The fair value of debtthe 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 allthe private placement senior notes and the revolving credit facility 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 | |
|
| | | | | | | | | | | | | | | |
| December 31, 2017 | | December 31, 2016 |
(In thousands) | Carrying Amount | | Estimated Fair Value | | Carrying Amount | | Estimated Fair Value |
Long-term debt | $ | 1,521,891 |
| | $ | 1,527,624 |
| | $ | 1,520,530 |
| | $ | 1,463,643 |
|
Current maturities | (304,000 | ) | | (312,055 | ) | | — |
| | — |
|
Long-term debt, excluding current maturities | $ | 1,217,891 |
| | $ | 1,215,569 |
| | $ | 1,520,530 |
| | $ | 1,463,643 |
|
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
Report of Independent Registered Public Accounting Firm
To theBoard of Directors and Stockholders of Cabot Oil & Gas Corporation:Coterra Energy Inc.
Opinions on the Financial Statements and Internal Control over Financial Reporting
We have audited the accompanying consolidated balance sheetssheet of Cabot Oil & Gas CorporationCoterra Energy Inc. and its subsidiaries (the “Company”) as of December 31, 20172021 and 2016,2020, 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, 2017,2021, including the related notes (collectively referred to as the “consolidated financial statements”). We also have audited the Company'sCompany’s internal control over financial reporting as of December 31, 2017,2021, 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, 20172021 and 2016,2020, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 20172021 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, 2017,2021, 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'sManagement’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")(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
February 27, 2018March 1, 2022
We have served as the Company’s auditor since 1989.
CABOT OIL & GAS CORPORATION
COTERRA ENERGY INC.
CONSOLIDATED BALANCE SHEET
| | | | | December 31, |
(In millions, except share amounts) | | (In millions, except share amounts) | | 2021 | | 2020 |
ASSETS | | ASSETS | | | | |
Current assets | | Current assets | | | | |
Cash and cash equivalents | | Cash and cash equivalents | | $ | 1,036 | | | $ | 140 | |
Restricted cash | | Restricted cash | | 10 | | | 12 | |
Accounts receivable, net | | Accounts receivable, net | | 1,037 | | | 215 | |
Income taxes receivable | | Income taxes receivable | | — | | | 6 | |
Inventories | | Inventories | | 39 | | | 15 | |
Derivative instruments | | Derivative instruments | | 7 | | | 26 | |
| Other current assets | | Other current assets | | 7 | | | 2 | |
Total current assets | | Total current assets | | 2,136 | | | 416 | |
Properties and equipment, net (Successful efforts method) | | Properties and equipment, net (Successful efforts method) | | 17,375 | | | 4,045 | |
| | | | December 31, | |
(In thousands, except share amounts) | | 2017 | | 2016 | |
ASSETS | | |
| | |
| |
Current assets | | |
| | |
| |
Cash and cash equivalents | | $ | 480,047 |
| | $ | 498,542 |
| |
Accounts receivable, net | | 216,004 |
| | 191,045 |
| |
Income taxes receivable | | 56,666 |
| | 10,298 |
| |
Inventories | | 8,006 |
| | 13,304 |
| |
Current assets held for sale | | 1,440 |
| | — |
| |
Other current assets | | 2,794 |
| | 2,692 |
| |
Total current assets | | 764,957 |
| | 715,881 |
| |
Properties and equipment, net (Successful efforts method) | | 3,072,204 |
| | 4,250,125 |
| |
Equity method investments | | 86,077 |
| | 129,524 |
| |
Assets held for sale | | 778,855 |
| | — |
| |
Other assets | | 25,251 |
| | 27,039 |
| Other assets | | 389 | | | 63 | |
| | $ | 4,727,344 |
| | $ | 5,122,569 |
| | $ | 19,900 | | | $ | 4,524 | |
LIABILITIES AND STOCKHOLDERS' EQUITY | | |
| | |
| |
LIABILITIES, REDEEMABLE PREFERRED STOCK AND STOCKHOLDERS' EQUITY | | LIABILITIES, REDEEMABLE PREFERRED STOCK AND STOCKHOLDERS' EQUITY | | | | |
Current liabilities | | |
| | |
| Current liabilities | | | | |
Accounts payable | | $ | 238,045 |
| | $ | 168,411 |
| Accounts payable | | $ | 747 | | | $ | 162 | |
Current portion of long-term debt | | 304,000 |
| | — |
| Current portion of long-term debt | | — | | | 188 | |
Accrued liabilities | | 27,441 |
| | 21,492 |
| Accrued liabilities | | 260 | | | 22 | |
Interest payable | | 27,575 |
| | 27,650 |
| Interest payable | | 25 | | | 18 | |
Income taxes payable | | Income taxes payable | | 29 | | | — | |
| Derivative instruments | | 30,637 |
| | 40,259 |
| Derivative instruments | | 159 | | | — | |
Current liabilities held for sale | | 2,352 |
| | — |
| |
| Total current liabilities | | 630,050 |
| | 257,812 |
| Total current liabilities | | 1,220 | | | 390 | |
Long-term debt, net | | 1,217,891 |
| | 1,520,530 |
| Long-term debt, net | | 3,125 | | | 946 | |
Deferred income taxes | | 227,030 |
| | 579,447 |
| Deferred income taxes | | 3,101 | | | 774 | |
Asset retirement obligations | | 43,601 |
| | 131,733 |
| Asset retirement obligations | | 259 | | | 85 | |
Liabilities held for sale | | 15,748 |
| | — |
| |
| Postretirement benefits | | 29,396 |
| | 36,259 |
| Postretirement benefits | | 33 | | | 31 | |
Other liabilities | | 39,723 |
| | 29,121 |
| Other liabilities | | 374 | | | 82 | |
Total liabilities | | 2,203,439 |
| | 2,554,902 |
| Total liabilities | | 8,112 | | | 2,308 | |
| | | | | |
| | Commitments and contingencies | |
|
| |
|
| Commitments and contingencies | | 0 | |
|
| 0Cimarex redeemable preferred stock | | 0Cimarex redeemable preferred stock | | 50 | | | — | |
| | | | | |
Stockholders' equity | | |
| | |
| Stockholders' equity | | | | |
Common stock: | | |
| | |
| Common stock: | | | | |
Authorized — 960,000,000 shares of $0.10 par value in 2017 and 2016, respectively | | |
| | |
| |
Issued — 475,547,419 shares and 475,042,692 shares in 2017 and 2016, respectively | | 47,555 |
| | 47,504 |
| |
Authorized — 1,800,000,000 shares and 960,000,000 shares of $0.10 par value in 2021 and 2020, respectively | | 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 | | Issued — 892,612,010 shares and 477,828,813 shares in 2021 and 2020, respectively | | 89 | | | 48 | |
Additional paid-in capital | | 1,742,419 |
| | 1,727,310 |
| Additional paid-in capital | | 10,911 | | | 1,804 | |
Retained earnings | | 1,162,430 |
| | 1,098,703 |
| Retained earnings | | 2,563 | | | 2,185 | |
Accumulated other comprehensive income | | 2,077 |
| | 985 |
| Accumulated other comprehensive income | | 1 | | | 2 | |
Less treasury stock, at cost: | | | | | Less treasury stock, at cost: | |
14,935,926 shares and 9,892,680 shares in 2017 and 2016, respectively | | (430,576 | ) | | (306,835 | ) | |
79,082,385 shares and 78,957,318 shares in 2021 and 2020, respectively | | 79,082,385 shares and 78,957,318 shares in 2021 and 2020, respectively | | (1,826) | | | (1,823) | |
Total stockholders' equity | | 2,523,905 |
| | 2,567,667 |
| Total stockholders' equity | | 11,738 | | | 2,216 | |
| | $ | 4,727,344 |
| | $ | 5,122,569 |
| | $ | 19,900 | | | $ | 4,524 | |
The accompanying notes are an integral part of these consolidated financial statements.
CABOT OIL & GAS CORPORATION
COTERRA ENERGY INC.
CONSOLIDATED STATEMENT OF OPERATIONS
|
| | | | | | | | | | | |
| Year Ended December 31, |
(In thousands, except per share amounts) | 2017 | | 2016 | | 2015 |
OPERATING REVENUES | |
| | |
| | |
|
Natural gas | $ | 1,506,078 |
| | $ | 1,022,590 |
| | $ | 1,025,044 |
|
Crude oil and condensate | 212,338 |
| | 151,106 |
| | 248,211 |
|
Gain (loss) on derivative instruments | 16,926 |
| | (38,950 | ) | | 56,686 |
|
Brokered natural gas | 17,217 |
| | 13,569 |
| | 16,383 |
|
Other | 11,660 |
| | 7,362 |
| | 10,826 |
|
| 1,764,219 |
| | 1,155,677 |
| | 1,357,150 |
|
OPERATING EXPENSES | |
| | |
| | |
|
Direct operations | 102,310 |
| | 100,696 |
| | 140,814 |
|
Transportation and gathering | 481,439 |
| | 436,542 |
| | 427,588 |
|
Brokered natural gas | 15,252 |
| | 10,785 |
| | 12,592 |
|
Taxes other than income | 33,487 |
| | 29,223 |
| | 42,809 |
|
Exploration | 21,526 |
| | 27,662 |
| | 27,460 |
|
Depreciation, depletion and amortization | 568,817 |
| | 590,128 |
| | 622,211 |
|
Impairment of oil and gas properties and other assets | 482,811 |
| | 435,619 |
| | 114,875 |
|
General and administrative | 97,786 |
| | 85,633 |
| | 67,996 |
|
| 1,803,428 |
| | 1,716,288 |
| | 1,456,345 |
|
Earnings (loss) on equity method investments | (100,486 | ) | | (2,477 | ) | | 6,415 |
|
Gain (loss) on sale of assets | (11,565 | ) | | (1,857 | ) | | 3,866 |
|
LOSS FROM OPERATIONS | (151,260 | ) | | (564,945 | ) | | (88,914 | ) |
Interest expense, net | 82,130 |
| | 88,336 |
| | 96,911 |
|
Loss on debt extinguishment | — |
| | 4,709 |
| | — |
|
Other expense (income) | (4,955 | ) | | 1,609 |
| | 1,448 |
|
Loss before income taxes | (228,435 | ) | | (659,599 | ) | | (187,273 | ) |
Income tax benefit | (328,828 | ) | | (242,475 | ) | | (73,382 | ) |
NET INCOME (LOSS) | $ | 100,393 |
| | $ | (417,124 | ) | | $ | (113,891 | ) |
| | | | | |
Earnings (loss) per share | |
| | |
| | |
|
Basic | $ | 0.22 |
| | $ | (0.91 | ) | | $ | (0.28 | ) |
Diluted | $ | 0.22 |
| | $ | (0.91 | ) | | $ | (0.28 | ) |
| | | | | |
Weighted-average common shares outstanding | |
| | |
| | |
|
Basic | 463,735 |
| | 456,847 |
| | 413,696 |
|
Diluted | 465,551 |
| | 456,847 |
| | 413,696 |
|
| | | | | |
Dividends per common share | $ | 0.17 |
| | $ | 0.08 |
| | $ | 0.08 |
|
| | | | | | | | | | | | | | | | | |
| 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.
CABOT OIL & GAS CORPORATION
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 | |
| | | | | |
| | | | | |
_______________________________________________________________________________ |
| | | | | | | | | | | |
| Year Ended December 31, |
(In thousands) | 2017 | | 2016 | | 2015 |
Net income (loss) | $ | 100,393 |
| | $ | (417,124 | ) | | $ | (113,891 | ) |
Postretirement benefits: | |
| | |
| | |
|
Net gain (loss)(1) | (2,634 | ) | | 1,794 |
| | 1,786 |
|
Prior service credit (cost)(2) | 5,449 |
| | (514 | ) | | — |
|
Amortization of prior service cost(3) | (1,723 | ) | | 70 |
| | — |
|
Total other comprehensive income | 1,092 |
| | 1,350 |
| | 1,786 |
|
Comprehensive income (loss) | $ | 101,485 |
| | $ | (415,774 | ) | | $ | (112,105 | ) |
(1)Net of income taxes of less than $1 million for each of the years ended December 31, 2021, 2020 and 2019. | |
(1) | Net of income taxes of $1,544, $(1,052) and $(1,043) for the year ended December 31, 2017, 2016 and 2015, respectively.
|
| |
(2) | Net of income taxes of $(3,194) and $301 for the year ended December 31, 2017 and 2016, respectively. |
| |
(3) | Net of income taxes of $1,010 and $(41) for the year ended December 31, 2017 and 2016, respectively. |
(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.
CABOT OIL & GAS CORPORATION
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. |
| | | | | | | | | | | |
| Year Ended December 31, |
(In thousands) | 2017 | | 2016 | | 2015 |
CASH FLOWS FROM OPERATING ACTIVITIES | |
| | |
| | |
|
Net income (loss) | $ | 100,393 |
| | $ | (417,124 | ) | | $ | (113,891 | ) |
Adjustments to reconcile net income (loss) to cash provided by operating activities: | |
| | |
| | |
|
Depreciation, depletion and amortization | 568,817 |
| | 590,128 |
| | 622,211 |
|
Impairment of oil and gas properties and other assets | 482,811 |
| | 435,619 |
| | 114,875 |
|
Deferred income tax benefit | (321,113 | ) | | (230,707 | ) | | (72,968 | ) |
(Gain) loss on sale of assets | 11,565 |
| | 1,857 |
| | (3,866 | ) |
Exploratory dry hole cost | 3,820 |
| | 10,120 |
| | 3,452 |
|
(Gain) loss on derivative instruments | (16,926 | ) | | 38,950 |
| | (56,686 | ) |
Net cash received (paid) in settlement of derivative instruments | 8,056 |
| | (1,682 | ) | | 194,289 |
|
(Earnings) loss on equity method investments | 100,486 |
| | 2,477 |
| | (6,415 | ) |
Amortization of debt issuance costs | 4,774 |
| | 5,083 |
| | 4,454 |
|
Stock-based compensation and other | 33,419 |
| | 25,982 |
| | 13,645 |
|
Changes in assets and liabilities: | |
| | |
| | |
|
Accounts receivable, net | (25,036 | ) | | (71,060 | ) | | 112,406 |
|
Income taxes | (46,368 | ) | | (5,975 | ) | | (711 | ) |
Inventories | 1,334 |
| | 3,044 |
| | (3,023 | ) |
Other current assets | (104 | ) | | (21 | ) | | (817 | ) |
Accounts payable and accrued liabilities | (2,552 | ) | | 10,858 |
| | (55,217 | ) |
Interest payable | (75 | ) | | (2,573 | ) | | (455 | ) |
Other assets and liabilities | (5,141 | ) | | 2,465 |
| | (1,685 | ) |
Net cash provided by operating activities | 898,160 |
| | 397,441 |
| | 749,598 |
|
CASH FLOWS FROM INVESTING ACTIVITIES | |
| | |
| | |
|
Capital expenditures | (764,558 | ) | | (375,153 | ) | | (955,602 | ) |
Acquisitions | — |
| | — |
| | (16,312 | ) |
Proceeds from sale of assets | 115,444 |
| | 50,419 |
| | 7,653 |
|
Investment in equity method investments | (57,039 | ) | | (28,484 | ) | | (29,073 | ) |
Net cash used in investing activities | (706,153 | ) | | (353,218 | ) | | (993,334 | ) |
CASH FLOWS FROM FINANCING ACTIVITIES | |
| | |
| | |
|
Borrowings from debt | — |
| | 90,000 |
| | 877,000 |
|
Repayments of debt | — |
| | (587,000 | ) | | (604,000 | ) |
Treasury stock repurchases | (123,741 | ) | | — |
| | — |
|
Sale of common stock, net | — |
| | 995,279 |
| | — |
|
Dividends paid | (78,838 | ) | | (36,187 | ) | | (33,090 | ) |
Tax withholding on vesting of stock awards | (7,973 | ) | | (5,064 | ) | | (8,861 | ) |
Capitalized debt issuance costs | — |
| | (3,223 | ) | | (7,838 | ) |
Other | 50 |
| | — |
| | 85 |
|
Net cash (used in) provided by financing activities | (210,502 | ) | | 453,805 |
| | 223,296 |
|
Net (decrease) increase in cash and cash equivalents | (18,495 | ) | | 498,028 |
| | (20,440 | ) |
Cash and cash equivalents, beginning of period | 498,542 |
| | 514 |
| | 20,954 |
|
Cash and cash equivalents, end of period | $ | 480,047 |
| | $ | 498,542 |
| | $ | 514 |
|
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.
CABOT OIL & GAS CORPORATION
CONSOLIDATED STATEMENT OF STOCKHOLDERS' EQUITY
The accompanying notes are an integral part
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
1. Summary of Significant Accounting Policies
Basis of Presentation and Nature of Operations
Cabot Oil & Gas CorporationCoterra Energy Inc. and its subsidiaries (the Company)(“Coterra” or the “Company”) are engaged in the development, exploitation, exploration and production and marketing of oil, natural gas oil and NGLs exclusively within the continental United States.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 one1 segment, oil and natural gas development, exploration and oil development, exploitation and exploration.production. The Company's oil and gas properties are managed as a whole rather than through discrete operating segments or business units.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 (loss) 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 four4 financial institutions at December 31, 2017.2021. 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 for receivables that the Company determines to be uncollectible based on the specific identification method.Company's estimate of future expected credit losses on outstanding receivables.
Inventories
Inventories are comprised of tubular goods and well equipment and pipeline imbalances. Tubular goods and well equipment balances are carried at average cost.
Natural gas gathering and pipeline operations normally include imbalance arrangements with the pipeline. The volumes of natural gas due to or from the Company under imbalance arrangements Inventories are recorded at actual selling or purchase prices, as the case may be, and are adjusted monthly to market prices.
Equity Method Investments
The Company accountsassessed periodically for its investments in entities over which the Company has significant influence, but not control, using the equity method of accounting. Under the equity method of accounting, the Company increases its investment for contributions made and records its proportionate share of net earnings, declared dividends and partnership distributions based on the most recently available financial statements of the investee. The Company records the activity for its equity method investments on a one month lag. In addition, the Company evaluates its equity method investments for potential impairment whenever events or changes in circumstances indicate that there is an other than temporary decline in the value of the investment.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 holedry-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: (i)(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 (ii)(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. Properties related to gathering and pipeline systems and equipment are depreciated using the straight-line method based on estimated useful lives ranging from 10 to 25 years. Buildings are depreciated on a straight-line basis over 25 to 40 years. Certain other assets are depreciated on a straight-line basis over 3 to 10 years.
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 natural gas and crude oilcommodity prices, operating costs and anticipated production from proved reserves and risk-adjusted probable and possible reserves, are lower than the net book value of the asset, the capitalized cost is reduced to fair value. Commodity pricing is estimated by using a combination of assumptions management uses in its budgeting and forecasting process as well as historical and current prices adjusted for geographical location and quality differentials, as well as other factors that management believes will impact realizable prices. 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. During 2017, 2016
Fixed Assets
Fixed assets consist primarily of gas gathering systems, water infrastructure, buildings, vehicles, aircraft, furniture and 2015, amortization associated withfixtures, and computer equipment and software. These items are recorded at cost and are depreciated on the Company's unproved properties was $52.8 million, $25.0 million and $41.4 million, respectively, and is included in depreciation, depletion, and amortization instraight-line method based on expected lives of the Consolidated Statement of Operations.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. The assetAsset retirement costs for oil and gas properties are depreciated using the units-of-production method. At December 31, 2017, there were no assets legally restricted for purposes of settlingmethod, while asset retirement obligations.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 and Hedging Activities
The Company enters into financial derivative contracts, primarily collars, swaps, collarsroll differential swaps and basis swaps, to manage its exposure to price fluctuations on a portion of its anticipated future natural gas and crude oil production.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. We haveThe Company has elected not to designate ourits financial derivative instruments as accounting hedges under the accounting guidance.
The Company evaluates all of its physical oil and gas 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)(“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
NaturalThe Company’s revenue is typically generated from contracts to sell oil, natural gas and oil sales resultNGLs produced from interests in oil and gas properties owned by the Company. SalesThese 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 oilNGL production as normal sales, which are recognizedthen accounted for as contracts with customers. The Company has determined that these contracts represent multiple performance obligations which are satisfied when control of the product is delivered and titlecommodity transfers to the purchaser.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 to threeor 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, 20172021 and 20162020 were not material.
Brokered Natural Gas.Revenues and expenses related to brokered natural gas activity are reported gross as part
Practical Expedients. The Company buys and sells natural gas utilizing separate purchase and sale transactions, typicallymakes use of certain practical expedients provided under the revenue standard, including the value of unsatisfied performance obligations are not disclosed for (1) contracts with separate counterparties, wherebyan original expected length of one year or less, (2) contracts for which the Company and/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 the counterparty takes titleservice to the natural gas purchasedcustomer and when the customer pays for that good or sold.
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%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 either a Black Scholes or Monte Carlo or Black-Scholes valuation model dependingbased 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.
Effective January 1, 2017, theThe Company adopted Accounting Standards Update (ASU) No. 2016-09, Improvements to Employee Share-Based Payment Accounting, which requires the Company to recordrecords excess tax benefits and tax deficiencies on stock-based compensation in the income statement upon vesting of the respective awards. Prior to the adoption of ASU 2016-09, excess benefits were recorded in additional paid-in capital in the Consolidated Balance Sheet and tax deficiencies reduced additional paid-in capital to the extent they offset previously recorded tax benefits. As a result of the adoption of ASU 2016-09, excessExcess tax benefits and tax deficiencies are included in cash flows from operating activities.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.
ReferEarnings per Share
The Company calculates earnings per share recognizing that unvested share-based payment awards that contain non-forfeitable rights to Recently Adopted Accounting Pronouncementsdividends 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 followdetermines earnings per share for further information with respecteach class of common stock and participating security according to dividends declared (or accumulated) and participation rights in undistributed earnings. Certain of the adoptionCompany’s unvested share-based payment awards, consisting of ASU 2016-09.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 oil and joint interest billingsNGLs to third parties in the oil and gas industry.industry and joint interest billings with other participants in joint operations. This concentration of purchasers and joint interest 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 yearsyear ended December 31, 2017, 2016 and 2015, two2021, 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 18%21 percent, 16 percent and 11%, two12 percent of the Company's total sales. During the year ended December 31, 2019, three customers accounted for approximately 19%17 percent, 16 percent and 10% and two customers accounted for approximately 16% and 14%, respectively,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 accounting principles generally accepted in the United States.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 and oil reserves and related cash flow estimates which are used to compute depreciation, depletion and amortization, and impairments of proved oil and gas properties.properties and the fair value of oil and gas properties in purchase accounting. Other significant estimates include oil, natural gas and oilNGLs 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.
Recently Adopted Accounting Pronouncements
Stock-Based Compensation.In March 2016,2. Acquisitions
Cimarex Energy Co.
On October 1, 2021, Coterra and Cimarex completed the Financial Accounting Standards Board (FASB) issued ASU No. 2016-09, Improvements to Employee Share-Based Payment Accounting, asMerger. Cimarex is an amendment to ASC Topic 718. The areas for simplificationoil and gas exploration and production company with operations in this update involve several aspectsTexas, New Mexico and Oklahoma. Upon the effectiveness of the accountingMerger, 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 share-based payment transactions, including the Merger to qualify as a tax-free reorganization for U.S. federal income tax consequences, forfeitures, classificationpurposes.
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 either equity orissued 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 classification onmezzanine equity of Cimarex and its
subsidiaries will be recorded at their respective fair values as of the statementeffective date of cash flows.the Merger. The guidancepurchase price allocation is substantially complete; however, it may be subject to change for up to one year after October 1, 2021, the effective for interimdate of the Merger. Determining the fair value of the assets and annual periods beginning after December 15, 2016. Amendmentsliabilities of Cimarex requires judgment and certain assumptions to be made. The most significant fair value estimates related to the timingvaluation of when excess tax benefits are recognized, minimum statutory withholding requirements, forfeitures,Cimarex's oil and intrinsic value should be appliedgas 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 modified retrospective transition method by meansmarket 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 a cumulative-effect adjustmentthe total purchase price of Cimarex to equitythe identifiable assets acquired and the liabilities assumed based on the fair values as of the beginningeffective date of the period in whichMerger.
| | | | | | | | |
(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 guidance is adopted. Amendments relatedfollowing to the presentationCompany’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 employee taxes paid on the statement of cash flows when an employer withholds shares to meet the minimum statutory withholding requirement should be applied retrospectively. Amendments requiring recognition of excess tax benefits and tax deficienciesCimarex’s operations have been included in the income statement and the practical expedient for estimating expected term should be applied prospectively. An entity may elect to apply the amendments related to the presentation of excess tax benefits on the statement of cash flows using either a prospective transition method or a retrospective transition method. The Company elected to apply this guidance on a prospective basis.
The Company adopted this guidance effective JanuaryCompany’s consolidated financial statements since October 1, 2017. The recognition of previously unrecognized windfall tax benefits resulted in a cumulative-effect adjustment of $42.2 million, which increased retained earnings and decreased net deferred tax liabilities by the same amount as of the beginning of 2017. Effective January 1, 2017, cash paid by the Company when directly withholding shares from employee awards for tax-withholding purposes was classified as a financing activity. This change was recognized retrospectively beginning January 1, 2015. Prior periods have been adjusted as follows:
|
| | | | | | | | | | | | | | | | |
| | Net Cash Provided by Operating Activities | | Net Cash Provided by Financing Activities |
(In thousands) | | As Reported | | As Adjusted | | As Reported | | As Adjusted |
Year ended December 31, 2015 | | $ | 740,737 |
| | $ | 749,598 |
| | $ | 232,157 |
| | $ | 223,296 |
|
Year ended December 31, 2016 | | 392,377 |
| | 397,441 |
| | 458,869 |
| | 453,805 |
|
The remaining provisions of this amendment did not have a material effect on the Company's financial position, results of operations or cash flows.
Accounting Changes and Error Corrections.In January 2017, the FASB issued ASU No. 2017-03, Accounting Changes and Error Corrections (Topic 250) and Investments - Equity Method and Joint Venture (Topic 323), which states that registrants should consider additional qualitative disclosures if the impact of an issued but not yet adopted ASU is unknown or cannot be reasonably estimated and to include a description of the effect of the accounting policies that the registrant expects to apply, if determined. Transition guidance in certain issued but not yet adopted ASUs, including Leases and Revenue Recognition, was also updated to reflect this amendment. This guidance was effective immediately. The adoption of this guidance impacted the Company’s disclosures but had no effect on its financial position, results of operations or cash flows.
Retirement Benefits.In March 2017, the FASB issued ASU No. 2017-07, Compensation - Retirement Benefits (Topic 715). The amendments in this update require that an employer report the service cost component of postretirement benefits in the same line item as other compensation costs arising from services rendered by the pertinent employees during the period. The other components of net benefit cost are required to be presented in the income statement separately from the service cost component and outside a subtotal of income from operations. The amendments in this update also allow only the service cost component to be eligible for capitalization when applicable. The amendments in this update should be applied retrospectively for the presentation of the service cost component and the other components of net periodic postretirement benefit cost in the
income statement and prospectively, on and after2021, the effective date for the capitalization of the service cost component of net periodic benefit cost in assets.
Merger. The guidance is effective for annual periods beginning after December 15, 2017, including interim periods within those annual periods. Early adoption is permitted as of the beginning of an annual period for which financial statements have not been issued or made available for issuance. The Company elected to early adopt this guidance effective January 1, 2017. The reclassification of interest and amortization of prior service cost resulted in an increase in operating income and an increase in other expense (non-operating expense) of $1.6 million and $1.4 millionfollowing supplemental pro forma information for the years ended December 31, 20162021 and 2015, respectively.
Recently Issued Accounting Pronouncements
Financial Instruments.In January 2016,2020 has been prepared to give effect to the FASB issued ASU 2016-01, Financial Instruments - Overall,Cimarex acquisition as an amendment to ASC Subtopic 825-10. The amendments in this update address certain aspects of recognition, measurement, presentation and disclosure of financial instruments. Among other items, this update will simplify the impairment assessment of equity investments without readily determinable fair values by requiring a qualitative assessment to identify impairment. When a qualitative assessment indicates that impairment exists, an entity is required to measure the investment at fair value. This impairment assessment reduces the complexity of the other than temporary impairment guidance that entities follow currently. The guidance is effective for annual periods beginning after December 15, 2018, including interim periods within those annual periods. Early adoption of this amendment is not permitted. The adoption of this guidance will change the methodology that the Company uses to evaluate its equity method investments for impairment. The Company is currently evaluating the effect that adopting this guidance will haveif it had occurred on its financial position, results of operation or cash flows.
Leases.In February 2016, the FASB issued ASU No. 2016-02, Leases, as a new Topic, ASC Topic 842. The new lease guidance supersedes Topic 840. The core principle of the guidance is that a company should recognize the assets and liabilities that arise from leases. This ASU does not apply to leases to explore for or use minerals, oil, natural gas and similar nonregenerative resources, including the intangible right to explore for those natural resources and rights to use the land in which those natural resources are contained. The guidance is effective for interim and annual periods beginning after December 15, 2018. This ASU is to be adopted using a modified retrospective approach. The Companyplans to adopt this guidance effective January 1, 2019. To date the Company has determined2020. The information below reflects pro forma adjustments based on available information and certain assumptions that right to use assetsCoterra believes are factual and related liabilities will increase as a result of the adoption of this guidance; however, the extent to which this increase impacts the financial position,supportable. The pro forma results of operations do not include any cost savings or cash flows hasother 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 yet been determined.
Revenue Recognition.In May 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers, as a new Topic, ASC Topic 606. The new revenue recognition standard provides a five-step analysis of transactions to determine when and how revenue is recognized. The core principlenecessarily indicative of the guidanceresults that might have occurred had the transaction actually taken place on January 1, 2020 and is that a company should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expectsnot intended to be entitled in exchange for those goods or services. In August 2015,a projection of future results. Future results may vary significantly from the FASB issued ASU No. 2015-14, Revenue from Contracts with Customers (Topic 606), which deferred the effective date of ASU No. 2014-09 by one year, making the new standard effective for interim and annual periods beginning after December 15, 2017. This ASU can be adopted either retrospectively or as a cumulative-effect adjustment as of the date of adoption.
Additionally, in March 2016, the FASB issued ASU No. 2016-08, Revenue from Contracts with Customers (Topic 606): Principal versus agent considerations (reporting revenue gross versus net), which clarifies the implementation guidance on principal versus agent considerations on such matters. In April 2016, the FASB issued ASU No. 2016-10, Revenue from Contracts with Customers (Topic 606): Identifying performance obligations and licensing, which clarifies guidance related to identifying performance obligations and licensing implementation guidance containedresults reflected in the new revenue recognition standard. 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 May 2016,connection with the FASB issued ASU No. 2016-12, Revenue from Contracts with Customers (Topic 606): Narrow-scope improvementsMerger, the Company incurred certain merger-related restructuring and practical expedients, which addresses narrow-scope improvementsrelated transaction costs. The costs relate to workforce reductions and the guidance on collectibility, non-cash consideration,associated employee severance benefits and completed contracts at transition. Additionally, the amendments in this update provide a practical expedient for contract modifications at transition and an accounting policy electionacceleration 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 presentationaccrual of sales taxesemployee severance and other similar taxes collected from customers. In December 2016,termination benefits. Additionally, in conjunction with the FASB issued ASU No. 2016-20, Technical Corrections and Improvements to Topic 606, Revenue from Contracts with Customers, which clarifies the guidance or corrects unintended application of guidance.
The Company plans to adopt this guidance effective January 1, 2018 using the modified retrospective method applied to contracts that are not completed as of that date. The Company has not identified changes to its revenue recognition policies that would result in a material adjustment to the opening balance of retained earnings on January 1, 2018. The Company has also evaluated its agreements with royalty and nonoperated partners for principal versus agent consideration and determined that there are no changes to its existing policies regarding these transactions. Adopting this guidance will result in increased
disclosures related to revenue recognition policies and disaggregation of revenue in future disclosures in the Company’s Consolidated Financial Statements. As allowed by the practical expedients under Topic 606,Merger, the Company does not plan to provide expanded disclosures with respect to the valuerecognized $42 million of unsatisfied performance obligations for contracts with variable consideration or with an original term of one year or less.
Statement of Cash Flows.In August 2016, the FASB issued ASU No. 2016-15, Statement of Cash Flows (Topic 230), which is intended to reduce diversity in practice in how certain transactions are classified in the statement of cash flows. The guidance addresses eight specific cash flow issues for which current GAAP is either unclear or does not include specific guidance. The guidance is effective for annual periods beginning after December 15, 2017 and interim periods within those annual periods. Early adoption is permitted, provided that all of the amendments are adopted in the same period. This ASU must be adopted using a retrospective transition method.
The Company expects to classify distributions it receives from its equity method investees based on the nature of distributions approach in which distributions received are classified on the basis of the nature of the activity that generated the distribution as either a return on investment (cash inflows from operating activities) or a return of investment (cash inflows from investing activities). The Company is not currently receiving any distributions from its equity method investees; however, if material distributions are received in the future, the impact on its cash flows could be material. The Company plans to adopt this guidance effective January 1, 2018. The Company has not identified any changes to the remaining areas of this guidance that upon adoption will have a material effect on its cash flows.
2. Divestitures
The Company recognized an aggregate net gain (loss) on sale of assets of $(11.6) million, $(1.9) million and $3.9 milliontransaction costs for the yearsyear ended December 31, 2017, 20162021. These fees primarily related to bank, legal and 2015, respectively.
In September 2017, the Company sold certain provedaccounting fees and unproved oilare included in general and gas properties and related pipeline assets located in West Virginia, Virginia and Ohio for $41.3 million, and recognized an $11.9 million loss on sale of assets. During the second quarter of 2017, the Company had classified these assets as held for sale and recorded an impairment charge of $68.6 million associated with the proposed sale of these properties.
In February 2016, the Company completed the divestiture of certain proved and unproved oil and gas properties in east Texas for $56.4 million and recognized a $0.5 million gain on sale of assets. The purchase price included a $6.3 million deposit that was receivedadministrative expenses in the fourth quarterConsolidated Statement of 2015.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 | |
|
| | | | | | | |
| December 31, |
(In thousands) | 2017 | | 2016 |
Proved oil and gas properties | $ | 4,932,512 |
| | $ | 7,437,604 |
|
Unproved oil and gas properties | 190,474 |
| | 260,543 |
|
Gathering and pipeline systems | 1,569 |
| | 187,846 |
|
Land, building and other equipment | 82,670 |
| | 84,462 |
|
| 5,207,225 |
| | 7,970,455 |
|
Accumulated depreciation, depletion and amortization | (2,135,021 | ) | | (3,720,330 | ) |
| $ | 3,072,204 |
| | $ | 4,250,125 |
|
Assets Held for Sale
On December 11, 2017, the Company entered into an agreement to sell its operated and non-operated Haynesville Shale assets to an undisclosed buyer for $30.0 million, subject to customary purchase price adjustments, and classified these assets as held for sale. The Company expects to close this transaction in the first half of 2018.
On December 19, 2017, the Company entered into an agreement to sell its operated and non-operated Eagle Ford Shale assets to an affiliate of Venado Oil & Gas LLC for $765.0 million, subject to customary closing conditions and purchase price adjustments, and classified these assets as held for sale. The Company expects to close this transaction in the first quarter of 2018.
Balance sheet data related to the assets held for sale is as follows:
|
| | | | |
(In thousands) | | December 31, 2017 |
ASSETS | | |
Inventories | | $ | 1,440 |
|
Properties and equipment, net | | 778,855 |
|
| | 780,295 |
|
LIABILITIES | | |
Accounts payable | | 2,352 |
|
Asset retirement obligations | | 15,748 |
|
| | 18,100 |
|
Net assets held for sale | | $ | 762,195 |
|
The assets held for sale as of December 31, 2017 do not qualify for discontinued operations as they do not represent a strategic shift that will have a major effect of the Company's operations or financial results.
Impairment of Oil and Gas Properties and Other Assets
In December 2017, the Company recorded an impairment of $414.3 million associated with its Eagle Ford Shale oil and gas properties located in south Texas. The impairment of these properties was due to the anticipated sale of these assets, as demonstrated by the execution of a purchase and sale agreement with a third party on December 19, 2017. These assets were designated as held for sale and were reduced to fair value of approximately $765.6 million.
In June 2017, the Company recorded an impairment of $68.6 million associated with its proposed sale of oil and gas properties and related pipeline assets located in West Virginia, Virginia and Ohio. These assets were designated as held for sale as of June 30, 2017 and were reduced to fair value of approximately $37.9 million.
In December 2016, the Company recorded an impairment of $435.6 million associated with oil and gas properties and related pipeline assets located in West Virginia and Virginia. In the fourth quarter of 2016, although oil and natural gas prices had improved since late 2015, the Company performed an impairment test of its West Virginia and Virginia fields because it had then determined that it was more likely than not that we would dispose of these assets significantly earlier than their remaining expected useful life. As a result of its step one assessment, which was based on a probability weighted assessment that considered the anticipated disposition of these assets earlier than their remaining expected useful life, the Company determined that these assets were impaired which resulted in an impairment charge of $435.6 million. These assets were reduced to fair value of approximately $89.2 million. The fair value of these assets was based on a market approach that considered the preliminary price contained in a draft purchase and sale agreement that was under negotiation with a potential buyer as of December 31, 2016.
In December 2015, the Company recorded an impairment of $114.9 million associated with oil and gas properties in certain fields in south Texas, east Texas and Louisiana. The impairment of these fields was due to a significant decline in commodity prices in late 2015. These fields were reduced to fair value of approximately $89.9 million using discounted future cash flows.
The fair value of the impaired assets in 2017 was determined using a market approach that took into consideration the expected sales price included in the respective purchase and sale agreements the Company executed in June and December 2017. Accordingly, the inputs associated with the fair value of these assets were considered Level 3 in the fair value hierarchy. Refer to Note 1 for a description of fair value hierarchy.
The fair value of the impaired assets in 2016 was determined using a market approach that took into consideration the preliminary purchase price included in a draft purchase and sale agreement that was under negotiation with a potential buyer as of December 31, 2016. Accordingly, the inputs associated with the fair value of these assets were considered Level 3 in the fair value hierarchy. Refer to Note 1 for a description of fair value hierarchy.
The fair value of the impaired properties in 2015 was determined using an income approach that was based on significant inputs that were not observable in the market and are considered to be Level 3 inputs as defined by ASC 820. Refer to Note 1 for a description of fair value hierarchy. Key assumptions included (i) reserves, including risk adjustments for probable and possible reserves; (ii) production rates based on the Company's experience with similar properties in which it operates; (iii)
estimated future operating and development costs; (iv) future commodity prices; (v) future cash flows; and (vi) a market-based weighted average cost of capital rate of 10%.
Capitalized Exploratory Well Costs
The following table reflectsAs of and for the net changes in capitalized exploratory well costs:
|
| | | | | | | | | | | |
| Year Ended December 31, |
(In thousands) | 2017 | | 2016 | | 2015 |
Balance at beginning of period | $ | — |
| | $ | — |
| | $ | 10,557 |
|
Additions to capitalized exploratory well costs pending the determination of proved reserves | 19,511 |
| | — |
| | — |
|
Reclassifications to wells, facilities, and equipment based on the determination of proved reserves | — |
| | — |
| | (10,557 | ) |
Capitalized exploratory well costs charged to expense | — |
| | — |
| | — |
|
Balance at end of period | $ | 19,511 |
| | $ | — |
| | $ | — |
|
The following table provides an aging of capitalizedyears ended December 31, 2021, 2020 and 2019, the Company did not have any projects with exploratory well costs based on the date the drilling was completed:
|
| | | | | | | | | | | |
| December 31, |
(In thousands) | 2017 | | 2016 | | 2015 |
Capitalized exploratory well costs that have been capitalized for a period of one year or less | $ | 19,511 |
| | $ | — |
| | $ | — |
|
Capitalized exploratory well costs that have been capitalized for a period greater than one year | — |
| | — |
| | — |
|
| $ | 19,511 |
| | $ | — |
| | $ | — |
|
4. Equity Method Investments
The Company has two equity method investments, Constitution Pipeline Company, LLC (Constitution) and Meade Pipeline Co LLC (Meade), which are further described below. Activity related to these equity method investments is as follows:
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Constitution | | Meade | | Total |
| | Year Ended December 31, | | Year Ended December 31, | | Year Ended December 31, |
(In thousands) | | 2017 | | 2016 | | 2015 | | 2017 | | 2016 | | 2015 | | 2017 | | 2016 | | 2015 |
Balance at beginning of period | | $ | 96,850 |
| | $ | 90,345 |
| | $ | 64,268 |
| | $ | 32,674 |
| | $ | 13,172 |
| | $ | 3,761 |
| | $ | 129,524 |
| | $ | 103,517 |
| | $ | 68,029 |
|
Contributions | | 4,350 |
| | 8,975 |
| | 19,625 |
| | 52,689 |
| | 19,509 |
| | 9,448 |
| | 57,039 |
| | 28,484 |
| | 29,073 |
|
Earnings (loss) on equity method investments | | (100,468 | ) | | (2,470 | ) | | 6,452 |
| | (18 | ) | | (7 | ) | | (37 | ) | | (100,486 | ) | | (2,477 | ) | | 6,415 |
|
Balance at end of period | | $ | 732 |
| | $ | 96,850 |
| | $ | 90,345 |
| | $ | 85,345 |
| | $ | 32,674 |
| | $ | 13,172 |
| | $ | 86,077 |
| | $ | 129,524 |
| | $ | 103,517 |
|
Constitution Pipeline Company, LLC
In April 2012, the Company acquired a 25% equity interest in Constitution, which was formed to develop, construct and operate a 124-mile large diameter pipeline to transport natural gas from northeast Pennsylvania to both the New England and New York markets. Under the terms of the agreement, the Company agreed to invest its proportionate share of costs associated with the development and construction of the pipeline and related facilities, subject to a contribution cap of $250 million.
On April 22, 2016, Constitution announced that the New York State Department of Environmental Conservation (NYSDEC) denied Constitution's applicationcapitalized for a Section 401 Water Quality Certification (Certification) for the New York State portion of its proposed 124-mile route. In early 2016, Constitution filed legal actions in the U.S. Court of Appeals for the Second Circuit and the U.S. District Court for the Northern District of New York challenging the legality and appropriateness of the NYSDEC’s decision. On March 16, 2017, the U.S. District Court for the Northern District of New York issued an order
ruling, without prejudice, that it lacked subject matter jurisdiction to hear Constitution’s complaint. On August 18, 2017, the Second Circuit issued a decision denying in part and dismissing in part Constitution’s appeal. The Second Circuit determined that it lacked jurisdiction to address Constitution’s argument that the NYSDEC waived its ability to issue a Certification by unreasonably delaying action on Constitution's application. Instead, the Second Circuit found that jurisdiction over the waiver issue lies exclusively with the United States Court of Appeals for the District of Columbia Circuit. The Second Circuit, however, rejected Constitution’s assertion that the denial of the Certification by the NYSDEC was “arbitrary and capricious” and denied Constitution’s complaint in that regard. On October 11, 2017, Constitution filed a petition for a declaratory order requesting the Federal Energy Regulatory Commission (FERC) to find that, by operation of law, the Section 401 Water Quality Certification requirement for the New York State portion of the pipeline project was waived due to the failure of the NYSDEC to act on Constitution’s application within a reasonable period of time, as required by the Clean Water Act. On January 11, 2018, the FERC denied Constitution’s petition. On January 16, 2018, Constitution petitioned the U.S. Supreme Court to review the judgment of the U.S. Court of Appeals for the Second Circuit, asserting that the Second Circuit’s decision conflicts with the decisions of the U.S. Supreme Court and federal Courts of Appeals on an important question of federal law. The U.S. Supreme Court has not yet determined if it will hear the case. On February 12, 2018, Constitution filed a rehearing request with the FERC of its findings that the NYSDEC did not waive the Section 401 Water Quality Certification requirement. The FERC has not yet ruled on the rehearing.greater than one year after drilling.
Constitution stated that it remains committed to pursuing the project and that it intends to pursue all available options to challenge the NYSDEC’s decision. In light of thecurrent status of the remaining litigation and regulatory challenges, Constitution is unable to reasonably estimate its target in-service date.
The Company evaluated its investment in Constitution for other than temporary impairment (OTTI) as of December 31, 2017. The Company’s evaluation considered various factors, including but not limited to prior FERC approval and the related economic viability of the project, the other members’ continued commitment to the project and the recent legal and regulatory actions. In light of the recent actions taken by the courts and regulators to uphold the NYDEC’s denial of the certification and the Company's estimation of the likelihood of an unfavorable outcome associated with the remaining legal and regulatory challenges, the Company recorded an OTTI of $95.9 million in December 2017, reducing its investment in Constitution to its estimated fair value. Fair value was determined using a market approach. The Company will continue to monitor the carrying value of its investment as required. As of December 31, 2017, the Company’s carrying value of its investment in Constitution is less than its proportionate share of Constitution’s net assets by $95.9 million. This basis difference is due to the Company’s recent impairment recorded in the fourth quarter of 2017 and relates entirely to the pipeline assets of Constitution. The Company expects to amortize this basis difference once the related assets of Constitution are placed in service, which may or may not occur, depending on the outcome of the legal and regulatory process.
At this time, the Company remains committed to funding the project in an amount in proportion to its ownership interest for the duration of the remaining legal and regulatory challenges and if successful, the development and construction of the new pipeline.
Meade Pipeline Co LLC
In February 2014, the Company acquired a 20% equity interest in Meade, which was formed to participate in the development and construction of a 177-mile pipeline (Central Penn Line) that will transport natural gas from Susquehanna County, Pennsylvania to an interconnect with Transcontinental Gas Pipe Line Company, LLC’s (Transco) mainline in Lancaster County, Pennsylvania. The new pipeline will be constructed and operated by Transco and will be owned by Transco and Meade in proportion to their respective ownership percentages of approximately 61% and 39%, respectively. Under the terms of the Meade LLC agreement, the Company agreed to invest its proportionate share of Meade’s anticipated costs associated with the new pipeline. The Company expects to contribute approximately $75.0 million over the next two years. By order issued on February 3, 2017, the FERC issued Transco a certificate of public convenience and necessity authorizing the construction of the new pipeline. The in-service date for the new pipeline is expected to be mid-2018.
5.4. 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 | |
_______________________________________________________________________________ |
| | | | | | | |
| December 31, |
(In thousands) | 2017 | | 2016 |
Total debt | | | |
6.51% weighted-average senior notes (1) | $ | 361,000 |
| | $ | 361,000 |
|
9.78% senior notes (2) | 67,000 |
| | 67,000 |
|
5.58% weighted-average senior notes | 175,000 |
| | 175,000 |
|
3.65% weighted-average senior notes | 925,000 |
| | 925,000 |
|
Revolving credit facility | — |
| | — |
|
Unamortized debt issuance costs | (6,109 | ) | | (7,470 | ) |
| $ | 1,521,891 |
| | $ | 1,520,530 |
|
(1)Includes $237.0$88 million of current portion of long-term debt at December 31, 2017.2020, which the Company repaid in January 2021.
(2)Includes $67.0$100 million of current portion of long-term debt at December 31, 2017.2020, which the Company repaid in September 2021.
The Company has debt maturities of $304.0 million due in 2018, $87.0 million due in 2020 and $188.0 million due in 2021. In addition, the revolving credit facility matures in 2020. No other tranches of debt are due within the next five years.years as follows: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
(in millions) | | 2022 | | 2023 | | 2024 | | 2025 | | 2026 | | Thereafter |
Debt maturities | | $ | — | | | $ | 62 | | | $ | 1,325 | | | $ | — | | | $ | 312 | | | $ | 1,250 | |
At December 31, 2017,2021, the Company was in compliance with all restrictive financial covenants as amended, for both its revolving credit facility and senior notes.
Private Placement Senior Notes
The Company has various issuances of senior notes.notes that were issued in separate private placements (the “private placement senior notes”). Interest on each of thesuch series of private placement senior notes is payable semi-annually. Under the terms of the various senior 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 Company'snote purchase agreements (as amended) provide that the Company must maintain a minimum asset coverage ratio of 1.25 to 1.0 through and including December 31, 2017 and 1.75 to 1.0 beginning on January 1, 2018 and thereafter. The amended agreements also introduced a leverage ratio covenant, which was defined in the agreement as the ratio of debt to consolidated EBITDAX and provided for potential increases to the original coupon rates ranging from 0 to 125 basis points depending on the asset coverage and leverage ratios at the end of the respective quarterly period, as defined in the note agreements. These covenants and the potential coupon rate increases were to remain in effect until the Company maintained a leverage ratio below 3.0 to 1.0 for two consecutive fiscal quarters ending on or after December 31, 2017, or received an investment grade rating by Standard & Poor's Ratings Services (S&P) or Moody’s Investor Service, Inc (Moody's). As of December 31, 2017, the Company had maintained a leverage ratio below 3.0 to 1.0 for two consecutive fiscal quarters and is no longer subject to this financial covenant or potential coupon rate increases. As of December 31, 2017, 2016 and 2015, there were no interest rate adjustments required for the Company's senior notes.
The note agreements also include a minimum annual coverage ratio of consolidated cash flow to interest expense for the trailing four4 quarters of 2.8 to 1.0 which was unchanged byand require a maximum ratio of total debt to consolidated EBITDA for the amendments.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.
In conjunction with the execution of the amendments, the Company incurred approximately $1.9 million of debt issuance costs, which were capitalized and are being amortized over the term of the respective amended agreements.
6.51% Weighted-Average Senior Notes
In July 2008, the Company issued $425.0$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 three3 separate tranches as follows:
|
| | | | | | | | | | |
| Principal | | Term | | Maturity Date | | Coupon |
Tranche 1 | $ | 245,000,000 |
| | 10 years | | July 2018 | | 6.44 | % |
Tranche 2 | $ | 100,000,000 |
| | 12 years | | July 2020 | | 6.54 | % |
Tranche 3 | $ | 80,000,000 |
| | 15 years | | July 2023 | | 6.69 | % |
| | | | | | | | | | | | | | | | | | | | | | | |
| 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 $8.0$8 million of Tranche 1, $13.0$13 million of Tranche 2 and $43.0$43 million of Tranche 3 for a total of $64.0$64 million for $68.3$68 million. The
As of December 31, 2021, the Company recognized a $4.7has repaid $388 million extinguishment lossof aggregate principal amount associated with the premium paid and the write-off of a portion of the related deferred financing costs due to early repayment.
9.78% Senior Notes
In December 2008, the Company issued $67.0 million aggregate principal amount of 10 year 9.78%6.51% weighted-average private placement senior unsecured notes to a group of four institutional investors in a private placement.notes.
5.58% Weighted-Average Senior Notes
In December 2010, the Company issued $175.0$175 million of senior unsecured notes to a group of eight8 institutional investors in a private placement. The notes have bullet maturities and were issued in three3 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 | % |
|
| | | | | | | | | | |
| Principal | | Term | | Maturity Date | | Coupon |
Tranche 1 | $ | 88,000,000 |
| | 10 years | | January 2021 | | 5.42 | % |
Tranche 2 | $ | 25,000,000 |
| | 12 years | | January 2023 | | 5.59 | % |
Tranche 3 | $ | 62,000,000 |
| | 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 $925.0$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 three3 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.
|
| | | | | | | | | | |
| Principal | | Term | | Maturity Date | | Coupon |
Tranche 1 | $ | 100,000,000 |
| | 7 years | | September 2021 | | 3.24 | % |
Tranche 2 | $ | 575,000,000 |
| | 10 years | | September 2024 | | 3.67 | % |
Tranche 3 | $ | 250,000,000 |
| | 12 years | | September 2026 | | 3.77 | % |
Cimarex Senior NotesThe 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 Company's revolving credit facilityagreement 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 is redetermined annually underand certain related provisions; (2) replace the termsthen-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 revolving credit facility on April 1. In addition, eitherMerger. This amendment became effective upon completion of the Company orMerger and closing of the banks may request an interim redetermination twice a year or in conjunction with certain acquisitions or sales of oil and gas properties. Effective April 11, 2017, the Company’s borrowing baseand available commitments were reaffirmed at$3.2 billion and $1.7 billion, respectively.debt exchange described above. The Company's revolving credit facility matures in April 2020.
In December 2017,2024 and can be extended by one year upon the agreement of the Company entered into an agreement to sell certainand lenders holding at least 50 percent of its Eagle Ford Shale assets for $765.0 million and expects to close on the sale in the first quarter of 2018. The lenderscommitments under the Company's revolving credit facility have agreed to waive the requirement that the borrowing base be reduced upon closing of the Eagle Ford sale provided that the sale of these assets is considered in the Company’s upcoming annual borrowing base redetermination on April 1, 2018.facility.
The Company's revolving credit agreement (as amended) provides that the Company maintain a minimum asset coverage ratio of 1.25 to 1.0 through and including December 31, 2017 and 1.75 to 1.0 beginning on January 1, 2018 and thereafter. The amended agreement also introduced a leverage ratio covenant, which was defined in the agreement as the ratio of debt to consolidated EBITDAX and increased the maximum leverage ratio and associated margins. Interest rates under the amended revolving credit facility are based onLIBORorABRindications, plus a margin which ranges from50 112.5 to300 175 basis points as defined in the amended agreement. These covenantsfor LIBOR loans and the and the associated margin adjustments werefrom 12.5 to remain in effect until the Company maintained a leverage ratio below 3.0 to 1.075 basis points for two consecutive fiscal quarters ending on or after December 31, 2017, or received an investment grade rating by Standard & Poor's Ratings Services (S&P) or Moody’s Investor Service, Inc (Moody's). As of December 31, 2017, the Company had maintained a leverage ratio below 3.0 to 1.0 for two consecutive fiscal quarters and is no longer subject to this financial covenant and the associated margins reverted back to the pre-amendment levels of 50 to 225 basis points.
The revolving credit facility also contains various other customary covenants that remained unchanged as a result of the amendment, which include the following (with all calculations based on definitions contained in the agreement):
| |
(a) | Maintenance of a minimum annual coverage ratio of consolidated cash flow to interest expense for the trailing four quarters of 2.8 to 1.0. |
| |
(b) | Maintenance of a minimum current ratio of 1.0 to 1.0. |
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 0.30%12.5 to 0.50%.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 other terms and conditions of the amended facility are generally consistent with the terms and conditions of theCompany’s revolving credit facility prior to its amendment.
At December 31, 2017,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 hadand 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 had unused commitmentsdoes not expect the transition to an alternative rate to have a material impact on its results of $1.7 billion. Theoperations or cash flows.
At December 31, 2021, there were no borrowings outstanding under the Company's weighted-average effective interest rates for the revolving credit facility during the years ended December 31, 2016 and 2015unused commitments were approximately 2.3% and 2.2%, respectively.$1.5 billion.
6.
5. Derivative Instruments and Hedging Activities
As of December 31, 2017,2021, the Company had the following outstanding financial commodity derivatives:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | Collars | | Swaps |
| | | | | | Floor | | Ceiling | | Basis Swaps | | Roll Swaps |
Type of Contract | | Volume (Mbbl) | | Contract Period | | Range ($/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.
|
| | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | Collars | | |
| | | | | | | Floor | | Ceiling | | Basis Swaps |
Type of Contract | | Volume | | Contract Period | | Range | | Weighted-Average | | Range | | Weighted- Average | | Weighted- Average |
Financial contracts | |
|
|
| |
| | | | | | | | | | |
Natural gas (Leidy) | | 17.7 |
| Bcf | | Jan. 2018 - Dec. 2018 | |
| |
|
| |
| |
|
| | $ | (0.71 | ) |
Natural gas (Transco) | | 21.3 |
| Bcf | | Jan. 2018 - Dec. 2019 | |
| |
|
| |
| |
|
| | $ | 0.42 |
|
Crude oil (WTI/LLS) | | 2.9 |
| Mmbbl | | Jan. 2018 - Dec. 2018 | | $— | | $ | 55.00 |
| | $63.35-$63.80 | | $ | 63.62 |
| | |
In January 2018, weearly 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 | |
|
| | | | | | | | | | |
| | | | | | | Swaps | | Basis Swaps |
Type of Contract | Volume | | Contract Period | | Weighted- Average | | Weighted- Average |
Financial contracts | | | | | | | | | |
Natural gas (NYMEX) | 84.4 |
| | Bcf | | Feb. 2018 - Dec. 2018 | | $2.93 | | |
Natural gas (NYMEX) | 13.3 |
| | Bcf | | Feb. 2018 - Oct. 2018 | | $3.10 | | |
Natural gas (Leidy) | 16.2 |
| | Bcf | | Feb. 2018 - Dec. 2018 | | | | $(0.68) |
In the tables above, natural gas prices are stated per Mcf and crude oil prices are stated per barrel.
As of December 31, 2017, the Company had the following outstanding physical commodity derivatives:
|
| | | | | | | | | |
Type of Contract | | Volume | | Contract Period | | Weighted-Average Fixed Price |
Physical contracts | | | | | | | | |
Natural gas purchase | | 81.2 |
| | Bcf | | Jan. 2018 - Oct. 2018 | | $3.70 |
Natural gas sales | | 11.7 |
| | Bcf | | Jan. 2018 - Feb. 2018 | | $4.71 |
In the table above, natural gas prices are stated per Mcf.
In January 2018, the Company terminated certain physical purchase contracts prior to their settlement date. The termination did not have a material impact on the Consolidated Financial Statements, as the contracts were previously recognized at fair value.
Effect of Derivative Instruments on the Consolidated Balance Sheet |
| | | | | | | | | | | | | | | | | | |
| | | | Fair Values of Derivative Instruments |
| | | | Derivative Assets | | Derivative Liabilities |
| | | | December 31, | | December 31, |
(In thousands) | | Balance Sheet Location | | 2017 | | 2016 | | 2017 | | 2016 |
Commodity contracts | | Other assets (non-current) | | $ | 2,239 |
| | $ | 2,991 |
| | $ | — |
| | $ | — |
|
Commodity contracts | | Derivative instruments (current) | | — |
| | — |
| | 30,637 |
| | 40,259 |
|
| | | | $ | 2,239 |
| | $ | 2,991 |
| | $ | 30,637 |
| | $ | 40,259 |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | 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 | | | $ | — | |
|
| | | | | | | | |
| | December 31, |
(In thousands) | | 2017 | | 2016 |
Derivative assets | | |
| | |
|
Gross amounts of recognized assets | | $ | 2,239 |
| | $ | 2,991 |
|
Gross amounts offset in the statement of financial position | | — |
| | — |
|
Net amounts of assets presented in the statement of financial position | | 2,239 |
| | 2,991 |
|
Gross amounts of financial instruments not offset in the statement of financial position | | — |
| | — |
|
Net amount | | $ | 2,239 |
| | $ | 2,991 |
|
| | | | |
Derivative liabilities | | | | |
Gross amounts of recognized liabilities | | $ | 30,637 |
| | $ | 40,259 |
|
Gross amounts offset in the statement of financial position | | — |
| | — |
|
Net amounts of liabilities presented in the statement of financial position | | 30,637 |
| | 40,259 |
|
Gross amounts of financial instruments not offset in the statement of financial position | | 241 |
| | 757 |
|
Net amount | | $ | 30,878 |
| | $ | 41,016 |
|
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 | |
|
| | | | | | | | | | | | |
| | Year Ended December 31, |
(In thousands) | | 2017 | | 2016 | | 2015 |
Cash received (paid) on settlement of derivative instruments | | | | | | |
Gain (loss) on derivative instruments | | $ | 8,056 |
| | $ | (1,682 | ) | | $ | 194,289 |
|
Non-cash gain (loss) on derivative instruments | | | | | | |
Gain (loss) on derivative instruments | | 8,870 |
| | (37,268 | ) | | (137,603 | ) |
| | $ | 16,926 |
| | $ | (38,950 | ) | | $ | 56,686 |
|
Additional Disclosures about Derivative Instruments and Hedging Activities
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 its derivativethe Company’s liabilities in certain situations.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.
7.6. 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, 2021 |
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 thousands) | 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, 2017 |
Assets | |
| | |
| | |
| | |
|
Deferred compensation plan | $ | 14,966 |
| | $ | — |
| | $ | — |
| | $ | 14,966 |
|
Derivative instruments | — |
| | — |
| | 2,239 |
| | 2,239 |
|
Total assets | $ | 14,966 |
| | $ | — |
| | $ | 2,239 |
| | $ | 17,205 |
|
Liabilities | |
| | |
| | |
| | |
|
Deferred compensation plan | $ | 29,145 |
| | $ | — |
| | $ | — |
| | $ | 29,145 |
|
Derivative instruments | — |
| | — |
| | 30,637 |
| | 30,637 |
|
Total liabilities | $ | 29,145 |
| | $ | — |
| | $ | 30,637 |
| | $ | 59,782 |
|
| | (In thousands) | 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, 2016 | |
(In millions) | | (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, 2020 |
Assets | |
| | |
| | |
| | |
| Assets | | | | | | | |
Deferred compensation plan | $ | 12,587 |
| | $ | — |
| | $ | — |
| | $ | 12,587 |
| Deferred compensation plan | $ | 22 | | | $ | — | | | $ | — | | | $ | 22 | |
Derivative instruments | — |
| | — |
| | 2,991 |
| | 2,991 |
| Derivative instruments | — | | | 2 | | | 24 | | | 26 | |
Total assets | $ | 12,587 |
| | $ | — |
| | $ | 2,991 |
| | $ | 15,578 |
| Total assets | $ | 22 | | | $ | 2 | | | $ | 24 | | | $ | 48 | |
Liabilities | |
| | |
| | |
| | |
| Liabilities | | | | | | | |
Deferred compensation plan | $ | 24,169 |
| | $ | — |
| | $ | — |
| | $ | 24,169 |
| Deferred compensation plan | $ | 31 | | | $ | — | | | $ | — | | | $ | 31 | |
Derivative instruments | — |
| | 21,400 |
| | 18,859 |
| | 40,259 |
| Derivative instruments | — | | | — | | | — | | | — | |
Total liabilities | $ | 24,169 |
| | $ | 21,400 |
| | $ | 18,859 |
| | $ | 64,428 |
| 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, for natural gas and crude oil, basis differentials, volatility factors and interest rates such as a LIBOR curve 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
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:
The Company discloses or recognizes its non-financial assets and liabilities, such as impairments of oil and gas properties or other than temporary impairments of equity method investments,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 Company recorded an impairment chargemost significant fair value determinations for non-financial assets and liabilities related to certain oil and gas properties and other assets during the years ended December 31, 2017, 2016 and 2015. The Company also recorded an other than temporary impairment of its equity method investment in Constitution during the year ended December 31, 2017.acquired. Refer to Notes 3 and 4Note 2, “Acquisitions,” for additional disclosures related to fair value associated with the impaired assets.information. As none of the Company’sCompany's other non-financial assets and liabilities were measured at fair value as of December 31, 2017, 20162021, 2020 and 2015,2019, additional disclosures were not required.
The estimated fair value of other financial instruments is the amount at which the instrument could be exchanged currently between willing parties. The carrying amountamounts reported in the Consolidated Balance Sheet for cash and cash equivalents approximatesand 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.