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 we may be required to purchase natural gas from third parties to satisfy shortfalls, should they occur.
|
| | | | | | | | |
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.
PROVED OIL AND GAS RESERVES
The following table presents our estimated proved reserves forby commodity as of the periodsdates indicated:
| | | | | | | | | | | | | | | | | |
| December 31, |
| 2023 | | 2022 | | 2021 |
Oil (MBbl) | | | | | |
Proved developed reserves | 173,392 | | | 168,649 | | | 153,010 | |
Proved undeveloped reserves | 75,821 | | | 71,107 | | | 36,419 | |
| 249,213 | | | 239,756 | | | 189,429 | |
Natural Gas (Bcf) | | | | | |
Proved developed reserves | 8,590 | | | 8,543 | | | 10,691 | |
Proved undeveloped reserves | 1,935 | | | 2,630 | | | 4,204 | |
| 10,525 | | | 11,173 | | | 14,895 | |
NGLs (MBbl) | | | | | |
Proved developed reserves | 234,306 | | | 224,706 | | | 193,598 | |
Proved undeveloped reserves | 83,150 | | | 72,059 | | | 27,017 | |
| 317,456 | | | 296,765 | | | 220,615 | |
| | | | | |
Oil equivalent (MBoe) | 2,320,757 | | | 2,398,666 | | | 2,892,582 | |
| | | | | |
| | | | | |
| | | | | |
|
| | | | | | | | |
| 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 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 atAt December 31, 2017, of which 96% were natural gas. This reserve level was up by 13% from 8,576 Bcfe at December 31, 2016. In 2017, we added 1,236.1 Bcfe of proved reserves through extensions, discoveries and other additions, primarily due to the positive results from2023, our drilling and completion programinterests in the Dimock field, which is primarily located in northeast Pennsylvania. We also had a net upward revisionSusquehanna County, Pennsylvania in the Marcellus Shale account for approximately 60 percent of 928.5 Bcfe,our total proved reserves. There are no other fields which was due to an upward performance revisionrepresent 15 percent or more of 863.8 Bcfe primarily associated with positive drilling results in our Dimock field in northeast Pennsylvania and 103.0 Bcfe associated with higher commodity prices, partially offset by a downward revision of 38.3 Bcfe associated withtotal proved undeveloped (PUD) reserves reclassifications as a result of the five year limitation. In 2017, we produced 685.3 Bcfe.
Our reserves are sensitive to natural gas and crude oil 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, 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.reserves.
For additional information regarding estimates of our net proved and proved undeveloped reserves, the auditqualifications of the preparers of our reserves estimates, the evaluation of such estimates by Millerour independent petroleum consultants, our processes and Lents, Ltd. (Miller and Lents)controls with respect to our reserves estimates 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 reservereserves 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, volumetric calculations and analogies, and in some cases a combination
Internal Control
Our Senior Vice President, South Region and Engineering 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. He has a Bachelor of Science degree in Chemical Engineering, specializing in petroleum engineering, and over 35 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 26 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, independent petroleum engineers, to perform an independent audit of our estimated proved reserves. Upon completion of the process, the estimated reserves are presented to senior management.
Miller and Lents made independent estimates for 100% of our proved reserves estimates and concluded, in their 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 of the audit letter by Miller and Lents dated January 26, 2018, has been filed as an exhibit to this 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.
Proved Undeveloped Reserves
At December 31, 2017 we had 3,538.7 Bcfe of PUD reserves associated with future development costs of $1.5 billion, which represents an increase of 585.4 Bcfe compared to December 31, 2016. Approximately 94% of our PUD reserves are located in Susquehanna County, Pennsylvania. We expect to complete approximately 100% of our PUD reserves associated with drilled but uncompleted wells by the end of 2018. Future development plans are reflective of the expected increase in commodity prices and have been established based on cash on hand, expected available cash flows from operations and availability under our revolving credit facility. As of December 31, 2017, 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):
|
| | |
| Year Ended
December 31, 2017 |
Balance at beginning of period | 2,953.3 |
|
Transfers to proved developed | (1,217.2 | ) |
Additions | 1,030.2 |
|
Revision of prior estimates | 772.4 |
|
Balance at end of period | 3,538.7 |
|
Changes in PUD reserves that occurred during the year were due to:
transfer of 1,217.2 Bcfe from PUD to proved developed reserves based on total capital expenditures of $382.4 million during 2017;
new PUD reserve additions of 1,030.2 Bcfe primarily in the Dimock field in northeast Pennsylvania; and
positive PUD reserve revisions of 772.4 Bcfe resulting from positive performance revisions of 809.8 Bcfe associated with the drilling of longer lateral wells and completing more frac stages in our Dimock field in northeast Pennsylvania and positive price revisions of 0.9 Bcfe, partially offset by downward revisions of 38.3 Bcfe associated with PUD reclassifications as a result of the five year limitation.
PRODUCTION, SALES PRICE AND PRODUCTION COSTS
The following table presents historical information about our total and average daily production volumes for oil, natural gas and NGLs; average oil, (including NGLs), average natural gas and crude oilNGL sales prices,prices; and average production costs per equivalent, including our Dimock field locatedequivalent:
| | | | | | | | | | | | | | | | | | | | |
| | Year Ended December 31, |
| | 2023 | | 2022 | | 2021 (1) |
Production Volumes | | | | | | |
Oil (MBbl) | | 35,110 | | 31,926 | | 8,150 | |
Natural gas (Bcf) | | 1,053 | | 1,024 | | 911 |
NGL (MBbl) | | 32,932 | | 28,697 | | 7,104 | |
Equivalents (MBoe) | | 243,497 | | 231,342 | | 167,113 |
| | | | | | |
Average Daily Production Volumes | | | | | | |
Oil (MBbl) | | 96 | | | 87 | | 89 | |
Natural gas (MMcf) | | 2,884 | | | 2,806 | | | 2,492 | |
NGL (MBbl) | | 90 | | 79 | | 77 |
Equivalents (MBoe) | | 667 | | | 634 | | 660 | |
| | | | | | |
Average Sales Price | | | | | | |
Excluding Derivative Settlements | | | | | | |
Oil ($/Bbl) | | $ | 75.97 | | | $ | 94.47 | | | $ | 75.61 | |
Natural gas ($/Mcf) | | $ | 2.18 | | | $ | 5.34 | | | $ | 3.07 | |
NGL ($/Bbl) | | $ | 19.56 | | | $ | 33.58 | | | $ | 34.18 | |
Including Derivative Settlements | | | | | | |
Oil ($/Bbl) | | $ | 76.07 | | | $ | 84.33 | | | $ | 60.35 | |
Natural gas ($/Mcf) | | $ | 2.44 | | | $ | 4.91 | | | $ | 2.73 | |
NGL ($/Bbl) | | $ | 19.56 | | | 33.58 | | $ | 34.18 | |
| | | | | | |
Average Production Costs ($/Boe) | | $ | 2.01 | | | $ | 1.84 | | | $ | 0.77 | |
(1)On October 1, 2021, we completed the Merger. The production information presented in northeast Pennsylvania, which represents more than 15% ofthis table includes Cimarex production for the period subsequent to that date.
The following table presents historical information about our total proved reserves:and average daily natural gas production volumes associated with our interests in the Dimock field. There was no oil or NGL production associated with our interests in the Dimock field. | | | | | | | | | | | | | | | | | | | | |
| | Year Ended December 31, |
| | 2023 | | 2022 | | 2021 |
Production Volumes | | | | | | |
| | | | | | |
Natural gas (Bcf) | | 826 | | | 805 | | | 853 | |
| | | | | | |
Equivalents (MBoe) | | 137,647 | | | 134,097 | | | 142,223 | |
| | | | | | |
Average Daily Production Volumes | | | | | | |
| | | | | | |
Natural gas (MMcf) | | 2,263 | | 2,204 | | | 2,338 | |
| | | | | | |
Equivalents (MBoe) | | 377 | | 367 | | | 390 | |
|
| | | | | | | | | | | |
| 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 customaryoil and gas mineral leases. These leases provide us the right to develop oil and/orand natural gas on the properties. Their primary terms generally range in length from approximately three to 10 years. These propertiesyears, and these leases generally are held for longer periods ifonce production is established.
The following table summarizes our gross and net developed and undeveloped leasehold and mineral fee acreage at December 31, 2017:2023: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Acreage |
| Developed | | Undeveloped | | Total |
| Gross | | Net | | Gross | | Net | | Gross | | Net |
Core Acreage | | | | | | | | | | | |
Permian Basin | | | | | | | | | | | |
New Mexico | 141,319 | | | 98,212 | | | 55,339 | | | 38,654 | | | 196,658 | | | 136,866 | |
Texas | 204,971 | | | 136,845 | | | 27,825 | | | 21,892 | | | 232,796 | | | 158,737 | |
| 346,290 | | | 235,057 | | | 83,164 | | | 60,546 | | | 429,454 | | | 295,603 | |
Marcellus Shale | | | | | | | | | | | |
Pennsylvania | 173,225 | | | 171,625 | | | 15,024 | | | 14,030 | | | 188,249 | | | 185,655 | |
| | | | | | | | | | | |
| | | | | | | | | | | |
Anadarko Basin | | | | | | | | | | | |
| | | | | | | | | | | |
Oklahoma | 320,080 | | | 146,987 | | | 69,123 | | | 34,526 | | | 389,203 | | | 181,513 | |
| | | | | | | | | | | |
| | | | | | | | | | | |
| | | | | | | | | | | |
Noncore Acreage | | | | | | | | | | | |
Arizona | 17,207 | | | 17,207 | | | 2,097,841 | | | 2,097,841 | | | 2,115,048 | | | 2,115,048 | |
California | — | | | — | | | 383,487 | | | 383,487 | | | 383,487 | | | 383,487 | |
| | | | | | | | | | | |
| | | | | | | | | | | |
| | | | | | | | | | | |
Nevada | 440 | | | 1 | | | 1,007,167 | | | 1,007,167 | | | 1,007,607 | | | 1,007,168 | |
New Mexico | 10,655 | | | 2,436 | | | 1,640,195 | | | 1,634,459 | | | 1,650,850 | | | 1,636,895 | |
| | | | | | | | | | | |
Pennsylvania | — | | | — | | | 114,199 | | | 64,044 | | | 114,199 | | | 64,044 | |
| | | | | | | | | | | |
| | | | | | | | | | | |
West Virginia | — | | | — | | | 607,347 | | | 575,691 | | | 607,347 | | | 575,691 | |
| | | | | | | | | | | |
Other | 128,713 | | | 45,069 | | | 298,421 | | | 172,990 | | | 427,134 | | | 218,059 | |
| 157,015 | | | 64,713 | | | 6,148,657 | | | 5,935,679 | | | 6,305,672 | | | 6,000,392 | |
| 996,610 | | | 618,382 | | | 6,315,968 | | | 6,044,781 | | | 7,312,578 | | | 6,663,163 | |
|
| | | | | | | | | | | | | | | | | |
| 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 or we take no action to extend or renewdrilling of a commercial well will hold the termsacreage beyond the expiration.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Acreage |
| | 2024 | | 2025 | | 2026 |
| | Gross | | Net | | Gross | | Net | | Gross | | Net |
Core Acreage | | | | | | | | | | | | |
Permian Basin | | 3 | | | 3 | | | — | | | — | | | 47 | | | 7 | |
Marcellus Shale | | 1,208 | | | 1,208 | | | 1,860 | | | 1,848 | | | 550 | | | 550 | |
Anadarko Basin | | 700 | | | 134 | | | 520 | | | 125 | | | 40 | | | 1 | |
Noncore Acreage | | 1,303 | | | 1,242 | | | — | | | — | | | — | | | — | |
| | 3,214 | | | 2,587 | | | 2,380 | | | 1,973 | | | 637 | | | 558 | |
| | | | | | | | | | | | |
| | | | | | | | | | | | |
Expiring acreage in our core operating areas in 2024, 2025 and 2026 represents less than one percent of our leases, our nettotal undeveloped acreage. At December 31, 2023, we had no PUD 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, renewalcore operating area.
WELL SUMMARY
The following table presents our ownership in productive oil and natural gas and crude oil wells at December 31, 2017.2023. This summary includes 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 | | 3,374 | | | 1,865.6 | |
Oil | | 2,523 | | | 837.0 | |
Total(1) | | 5,897 | | | 2,702.6 | |
(1)Total percentage of gross and net operated wells is 49 percent and 88 percent, respectively.
| |
(1) | Total percentage of gross operated wells is 85.3%. |
DRILLING ACTIVITY
WeThe table below presents wells that we drilled and completed wells or in which we participated in the drilling and completion of wells as indicated in the table below. Thecompletion. This information below should not be considered indicative of future performance, nor should a correlation be assumed betweenas a result of the number of productive wells drilled, the quantities of reserves found or the economic value. | | | Year Ended December 31, | | Year Ended December 31, |
| 2017 | | 2016 | | 2015 | | 2023 | | 2022 | | 2021 |
| Gross | | Net | | Gross | | Net | | Gross | | Net | | Gross | | Net | | Gross | | Net | | Gross | | Net |
Development Wells | | | | | | | | | | | |
Productive | 104 |
| | 93.2 |
| | 76 |
| | 76.0 |
| | 106 |
| | 97.9 |
|
Dry | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Exploratory Wells | | | | | | | | | | | |
Productive | |
Productive | — |
| | — |
| | — |
| | — |
| | 1 |
| | 1.0 |
|
Dry | 1 |
| | 1.0 |
| | — |
| | — |
| | — |
| | — |
|
| Total | |
| Total | |
| Total | 105 |
| | 94.2 |
| | 76 |
| | 76.0 |
| | 107 |
| | 98.9 |
|
| | | | | | | | | | | |
Acquired Wells | — |
| | — |
| | — |
| | — |
| | 1 |
| | 1.0 |
|
Acquired Wells | |
Acquired Wells | |
During the year ended December 31, 2017,2023, we completed 5098 gross wells (44.3(62.7 net) that werewere 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, 2017,2023, which are not included in the above table:
| | | | Drilling In Progress | | Drilled But Uncompleted |
| | Gross | | Net | | Gross | | Net |
| | Drilling In Progress | | | | Drilling In Progress | | Drilled But Uncompleted |
| | Gross | | | | Gross | | Net | | Gross | | Net |
Development wells | | 4 |
| | 4.0 |
| | 36 |
| | 32.6 |
|
Exploratory wells | | 3 |
| | 3.0 |
| | — |
| | — |
|
Total | | 7 |
| | 7.0 |
| | 36 |
| | 32.6 |
|
OTHER BUSINESS MATTERS
Title to Properties
We believe that we have satisfactory title to all of our producing properties and leases in accordance with generally accepted industry standards. Individual properties may be subject to burdens such as royalty, overriding royalty, carried, net profits, working and other outstanding interests customary in the industry. In addition, interests may be subject to obligations or duties under applicable laws or burdens such as production payments, ordinary course liens incidental to operating agreements and for current taxes or development obligations under oil and gas leases. As is customary in the industry in the case of undeveloped properties, we conduct preliminary investigations of record title 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.where we operate. We primarily compete with integrated, independent and other energy companies for the sale and transportation of our oil and natural gas
production to pipelines, marketing companies and end users. Furthermore, the oil and gas industry competes with other energy industries that supply fuel and power to industrial, commercial and residential consumers. Many of these competitors have greater financial, technical and personnel resources.resources than we have. The effect of these competitive factors cannot be predicted.
Price, contract terms, availability of rigs and related equipment and quality of service, including pipeline connection timesinfrastructure availability 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 core operating areas, along with our expected activity level and the related services and equipment that we have secured for the upcoming years, enhance our competitive position over other producers who do not have similar systems or services in place.position.
Major Customers
During the yearsyear ended December 31, 2017, 2016 and 2015,2023, two customers accounted for approximately 18%19 percent and 11%,17 percent of our total sales. During the year ended December 31, 2022, two customers accounted for approximately 19%13 percent and 10% and two customers accounted for approximately 16% and 14%, respectively,11 percent of our total sales.
If any one of our major customers were to stop purchasing our production, we believe there are other purchasers to whom we could sell our production. If multiple significant customers were to stop purchasing our production, we expect to have sufficient alternative markets to handle any sales disruptions despite any initial disruptions that may occur.
We 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 includesThese regulations include 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 prohibitingprohibit the venting or
flaring of natural gas and imposingimpose certain requirements regarding the ratability of production. The effect of theselaws and regulations is to limit the amounts of oil and natural gas we can produce from our wells and to limitas well as the number of wells, orand the locations where, we can drill. Because these statutes, ruleslaws and regulations undergo constant review andare 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 often increases itsthe cost of doing business and, consequently, affects itsour profitability. WeThese laws and regulations, however, do not believe, however, we are affectedaffect us 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, underUnder 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 approximately $1.5 million per day per violation. In 2010, the FERC issued Penalty Guidelines for the determination of civil penalties and procedure under its enforcement program.
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 4NGPA and that our
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 gathering 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 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 ofThe Commodity Exchange Act provides the Dodd‑Frank Wall Street Reform and Consumer Protection Act (Dodd‑Frank Act) in July 2010, theU.S. Commodity Futures Trading Commission (CFTC) has promulgated regulations(the “CFTC”) with jurisdiction to implement statutory requirements for swapregulate the over-the-counter (“OTC”) derivatives market (which includes the sorts of financial instruments we use) and participants in that market. We endeavor to ensure that our OTC derivatives transactions including certain options. Thecomply with applicable 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. Weregulations. Although the CFTC does not currently require the clearing of OTC commodity derivatives transactions of the types that we use, we believe that our use of swaps to hedge against changes in commodity exposureprices qualifies us as ana commercial end‑user, exemptingwhich would exempt us from the requirementa future requirements to centrally clear our commodity swaps. Nevertheless, future changes to the swap market as a result of Dodd‑Frank implementationin CFTC regulations 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 reducederivative contracts, limit the availability of newderivatives to protect against risks that we encounter, reduce our ability to monetize or restructure our existing swaps.derivative contracts and increase our exposure to less creditworthy counterparties. 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.pipeline. Every five years, the FERC must examine the relationship between the annual change in the applicable index and the actual cost changes experienced in the oil pipeline industry. In December 2015, to implement this required five‑year re‑determination,redetermination, the FERC established an upward adjustment in the index to track oil pipeline cost changes and determined that the Producer Price Index for Finished Goods plus 1.23%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’spipelines’ rates or terms and conditions of service are unduly discriminatory or preferential. We are unable to predict with certainty the effect upon us of these periodic reviews by the FERC of the pipeline index or any potential future challenges to pipelines'pipelines’ rates.
Environmental and Safety Regulations
General.Our operations are subject to extensive and stringent federal, state and local laws and regulations relatinggoverning the protection of the environment. These laws and regulations can change, restrict or otherwise impact our business in many ways, including the handling or disposal of waste material, planning for future activities to avoid or mitigate harm to threatened or endangered species, and requiring the generation, storage, handling, emission, transportationinstallation and dischargeoperation of materials intoemissions or pollution control equipment. Failure to comply with these laws and regulations could result in the environment.assessment of administrative, civil and criminal penalties, the imposition of remedial requirements and the issuance of orders enjoining future operations. Permits are required for the operation of our various facilities. These permits can be revoked, modified or renewed by issuing authorities. Governmental authorities enforce compliance with their regulations through fines, injunctions or both. Government regulationsRegulations 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 we will not incur significant costs and liabilities will not be incurred.liabilities. Also, it is possible that other developments, such as stricter environmental laws and regulations and claims for damages to property or persons resulting from oil and natural gas production could result in substantial costs and liabilities to us.
U.S. laws and regulations applicable to our operations include those controlling the discharge of materials into the environment, requiring removal and cleanup of materials that may harm the environment or otherwise relating to the protection of the environment.
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 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 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 Federal 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 comply with the Oil Pollution Act and related federal regulations.
Endangered Species Act.The Endangered Species Act (ESA) restricts activities that may affect endangered or threatened species or their habitats. While some of our operations may be located in areas that are designated as habitats for endangered or threatened species, we believe that we are in substantial compliance with the ESA, nor are we aware of any proposed listings that will affectOPA and related federal regulations to the extent applicable to our operations. However,
Endangered Species Act. The Endangered Species Act (the “ESA”) was established to protect endangered and threatened species. Pursuant to the ESA, if a species is listed as threatened or endangered, restrictions may be imposed on activities adversely affecting that species’ habitat. The U.S. Fish and Wildlife Service (the “FWS”) may designate critical habitat and suitable habitat areas it believes are necessary for survival of a threatened or endangered species. A critical habitat or suitable habitat designation of previously unidentifiedcould result in further material restrictions to federal land use and may materially delay or prohibit land access for oil and gas development. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act, to bald and golden eagles under the Bald and Golden Eagle Protection Act, and to certain species under state law. We conduct operations in areas where certain species are currently listed as threatened or endangered, or could be listed as such, under the ESA. Operations in areas where threatened or endangered species or their habitat are known to exist may require us to incur increased costs to implement mitigation or protective measures and also may restrict or preclude our drilling activities in those areas or during certain seasons, such as breeding and nesting seasons.
On June 1, 2021, the FWS proposed to list two distinct population segments (“DPS”) of the lesser prairie-chicken (“LPC”) under the ESA. The Southern DPS, located in eastern New Mexico and the southwest Texas panhandle was proposed to be listed as endangered and the Northern DPS, located in southeastern Colorado, southcentral to southwestern Kansas, western Oklahoma and the northeast Texas panhandle, was proposed to be listed as threatened. On November 25, 2022, the FWS finalized the proposed rule, listing the southern DPS of the lesser prairie-chicken as endangered and the northern DPS of the lesser prairie-chicken as threatened. On July 27, 2023, the U.S. House of Representatives voted to use the Congressional Review Act to reverse the LPC listing. On September 26, 2023 President Biden vetoed Congress’ resolution to reverse the LPC listing. On September 28, 2023, the U.S. Senate voted and failed to override the President’s veto. On November 3, 2023, the U.S. House of Representatives passed an appropriations bill for the U.S. Department of Interior for fiscal year 2023, which provides, in part, that no funds may be used to implement, administer, or enforce the listing of the LPC. Listing of the LPC as a threatened or endangered species will impose restrictions on disturbances to critical habitat by landowners and drilling companies that would harass, harm or otherwise result in a “taking” of this species. Regulatory impacts on landowners and businesses from an ultimate decision to list the LPC could be limited for those landowners and businesses who have entered into certain range-wide conservation planning agreements, such as those developed by the Western Association of Fish and Wildlife Agencies (“WAFWA”), pursuant to which such parties agreed to take steps to protect the LPC’s habitat and to pay a mitigation fee if its actions harm the lesser prairie-chicken’s habitat. We have entered into a voluntary Candidate Conservation Agreement (a “CCA”) with the WAFWA, whereby we agreed to take certain actions and limit certain activities, such as limiting drilling on certain portions of our acreage during nesting seasons, in an effort to protect the LPC.
On February 9, 2018, the FWS announced the listing of the Texas Hornshell, a freshwater mussel species in areas where we operate in the Permian Basin, including New Mexico and Texas, as an endangered species. In March 2018, we entered into a CCA concerning voluntary conservation actions with respect to the Texas Hornshell.
Participating in CCAs could result in increased costs to us from species protection measures, time delays or limitations on drilling activities, which costs, delays or limitations may be significant. Listing petitions continue to be filed with the FWS which could impact our operations. Many non-governmental organizations (“NGOs”) work closely with the FWS regarding the listing of many species, including species with broad and even nationwide ranges. The listing of the Mexican Long Nosed Bat, whose habitat includes the Permian Basin where we operate, and the Dunes Sagebrush Lizard (proposed to be listed as endangered under the ESA on July 3, 2023) in the Permian Basin, are examples of the NGOs’ influence on ESA listing decisions.
On December 1, 2020, the FWS proposed to list the Peppered Chub as endangered under the ESA. The proposed listing was finalized and published on February 28, 2022. The Peppered Chub is a freshwater fish that historically was found in the South Canadian, Cimarron and Arkansas rivers within New Mexico, Texas, Oklahoma and Kansas. We have operations near the South Canadian River in Oklahoma that may be impacted by the listing of the Peppered Chub as endangered. The increase in endangered species listings, such as the Peppered Chub, may limit our ability to explore for or produce oil and gas in certain areas or cause us to incur additional costs or become subject to operating restrictions or bans in the affected areas.costs.
Clean Water Act.The 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 wastewaterswastewater 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 Federalfederal 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 has added costs and caused delays in operations.
In 2012, the EPA published final NSPS and NESHAP that amended the existing NSPS and NESHAP standards for oil and gas facilities and created new NSPS standards forthe oil and natural gas production, transmission and distribution facilities.sector. In June 2016, the EPA published a final rule that updatesupdated and expandsexpanded the NSPS by setting additional emissions limits for volatile organic compounds and regulating methane emissions for new and modified sources in the oil and gas industry. In addition, in June 2017, the EPA proposed a two yeartwo-year stay of certain requirements contained in the June 2016 rule and, in November 2017, issued a notice of data availability in support of the stay proposal and provided a 30-day comment period on the information provided. TheIn March 2018, the EPA also published a final rule that amended two narrow provisions of the NSPS, removing the requirement for completion of delayed repair during emergency or unscheduled vent blowdowns. In September 2020, the EPA published a final rule amending the 2012 and 2016 NSPS for the oil and natural gas sector that removed transmission and storage sources from the oil and natural gas industry source category and rescinded the methane requirements applicable to the production and processing sources. On June 30, 2021, President Biden signed into law a joint Congressional resolution under the Congressional Review Act disapproving the September 2020 rule amending the EPA’s 2012 and 2016 NSPS standards for the oil and natural gas sector. On November 15, 2021, the EPA proposed rules to reduce methane emissions from both new and existing oil and natural gas industry sources and published supplemental rules regarding the same on December 6, 2022. On December 2, 2023, during the United Nations Climate Change Conference in June 2016 concerning aggregation of sources that affects source determinations for air permitting inthe United Arab Emirates (“COP28”), the EPA announced its final methane rules, which impose several new methane emission requirements on the oil and gas industry. For additional information, please read “Risk Factors—Legal, Regulatory and Governmental Risks— Federal, state and local laws and regulations, judicial actions and regulatory initiatives related to oil and gas development and the use of hydraulic fracturing could result in increased costs and operating restrictions or delays and adversely affect our business, financial condition, results of operations and cash flows” in Item 1A.
In October 2015, the EPA adopted a lower national ambient air quality standard for ozone. The revised standard 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 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 emplacementplacement of fluids (including disposal wells or enhanced oil recovery) is governed by federal or state regulatory authorities that, in some cases, includes the state oil and gas regulatory authority or the state’s environmental authority. These regulations may increase the costs of compliance for some facilities.
Hydraulic Fracturing.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. 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 adoptionEPA released its final report in December 2016. It concluded that hydraulic fracturing activities can impact drinking water resources under some circumstances, including large volume spills and inadequate mechanical integrity of wells. This study and other studies that may be undertaken by the EPA or other federal agencies could spur initiatives to further regulate hydraulic fracturing under the Safe Drinking Water Act, the Toxic Substances Control Act, or other statutory and regulatory mechanisms. A number of federal stateagencies are analyzing, or local laws or the implementationhave been requested to review, a variety of regulations regardingenvironmental issues associated with hydraulic fracturing practices.
Our inability to locate sufficient amounts of water, or to dispose of or recycle water used or produced in our exploration and production operations, could potentially cause a decreaseadversely impact our operations. For water sourcing, we first seek to use non-potable water supplies, or recycled produced water for our operational needs. In certain areas, there may be insufficient water available for drilling and completion activities. Water must then be obtained from other sources and transported to the drilling site. Our operations in certain areas could be adversely impacted if we are unable to secure sufficient amounts of water or to dispose of or recycle the completionwater used in our operations. The imposition of new oilenvironmental and natural gasother regulations, as well as produced water disposal well limits or moratoriums in areas of seismicity, could further restrict our ability to conduct operations such as hydraulic fracturing by restricting the disposal of waste such as produced water and drilling fluids. Compliance with environmental regulations and permit requirements governing the withdrawal, storage and use of surface water or groundwater necessary for hydraulic fracturing of wells may increase our operating costs and increased compliance costs, which could
increase costscause delays, interruptions or termination of our operations, the extent of which cannot be predicted, all of which could have an adverse effect on our operations and cause considerable delays in acquiring regulatory approvalsfinancial condition. In June 2016, the EPA published final pretreatment standards for disposal of wastewater produced from shale gas operations to drill and complete wells. For additional information aboutpublicly owned treatment works. The regulations were developed under the EPA’s Effluent Guidelines Program under the authority of the Clean Water Act. In response to these actions, operators, including us, have begun to rely more on recycling of water that flows back from the wellbore following hydraulic fracturing (“flowback water”) and related environmental matters, please read “Risk Factors-Federalproduced water from well sites as a preferred alternative to disposal.
Greenhouse Gas and state legislationClimate Change Laws and regulatory initiatives related to oil and gas development, including hydraulic fracturing, could result in increased costs and operating restrictions or delays” in Item 1A.
Greenhouse Gas.Regulations.In response to studies suggesting that emissions of carbon dioxide and certain other gasesgreenhouse gas (“GHG”), including methane, may be contributing to global climate change, there is increasing focus by local, state, regional, national and international regulatory bodies as well as by investors and the public on GHG emissions and climate change issues. In December 2015, the U.S. joined the international community at the 21st Conference of the Parties of the United 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. In 2019, the U.S. withdrew from the Paris Agreement. The current Presidential
administration has made climate change a central priority. On January 20, 2021, his first day in office, President Biden took action to reverse the withdrawal of the previous administration from the Paris Agreement so that the U.S. could rejoin as a party to the agreement. The U.S. officially rejoined the Paris Agreement on February 19, 2021, and in April 2021 submitted its NDC. The U.S. NDC sets an economy-wide target of net GHG emissions reduction from 2005 levels of 50-52 percent by 2030. The specific measures to be taken in furtherance of achieving this target have not been established, but the NDC submission indicated that a “whole government approach” will be used to achieve this target, including regulatory, technology and policy initiatives designed to reduce the generation of GHG emissions and to incentivize the capture and geologic sequestration or utilization of carbon dioxide that would otherwise be emitted in the atmosphere. Also on his first day in office, President Biden signed an executive order on climate action and reconvened an interagency working group to establish interim and final social costs of three GHGs: carbon dioxide, nitrous oxide, and methane. Carbon dioxide is released during the combustion of fossil fuels, including oil, natural gas, and NGLs, and methane is a primary component of natural gas. The Biden administration stated it will use updated social cost figures to inform federal regulations and major agency actions and to justify aggressive climate action as the U.S. moves toward a “100 percent clean energy” economy with net-zero GHG emissions. Furthermore, at COP28 in December 2023, more than 190 governments reached a non-binding agreement to transition away from fossil fuels and encourage the growth and expansion of renewable energy.
Although the U.S. Congress has considered 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 reducing GHG emissions through cap-and-trade programs, which typically require major sources within the United States between 2012of GHG emissions, such as electric power plants, to acquire and 2050.surrender emission allowances in return for emitting GHGs. In addition, manya coalition of over 20 governors of U.S. states formed the U.S. Climate Alliance to advance the objectives of the Paris Agreement, and several U.S. cities have already taken legal measurescommitted to reduceadvance the objectives of the Paris Agreement at the state or local level as well. To this end, California’s governor issued an executive order on September 23, 2020 ordering actions to pursue GHG emissions reductions, including a direction to the California State Air Resources Board to develop and propose regulations to require increasing volumes of greenhouse gases, primarily throughnew zero-emission passenger vehicles and trucks sold in California over time, with a targeted ban of the planned developmentsale of greenhouse gas emission inventories and/or regional greenhouse gas cap and trade programs. Thenew gasoline vehicles by 2035.
At the federal level, the EPA has also begun to regulate carbon dioxide and other greenhouse gas emissionsGHGs under existing provisions of the Clean Air Act. ThisIn December 2009, the EPA published its findings that emissions of GHGs present an endangerment to public health and the environment because emissions of such gases are contributing to the warming of the earth’s atmosphere and other climatic changes. Based on these findings, the EPA adopted regulations under existing provisions of the federal Clean Air Act that establish Prevention of Significant Deterioration (“PSD”) and Title V permit reviews for GHG emissions from certain large 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 tosector and published proposed supplemental rules regarding the same on December 6, 2022. On December 2, 2023, during COP28, the EPA announced its final methane rules, which impose several new methane emission requirements on the oil and gas industry. The Inflation Reduction Act of 2022 (“IRA”) established the Methane Emissions Reduction Program, which imposes a charge on methane emissions from certain petroleum and natural gas facilities, by EPAwhich may apply to our operations in connection with its intention at the timefuture and may require us to regulate methane emissions from existing sources was withdrawn in March 2017. expend material sums.
If we are unable to recover or pass through a significant portion of our costs related to complying with current and future regulations relating to climate change and GHGs, it could materially affect our operations and financial condition. Any future laws or regulations that limit emissions of GHGs from our equipment and operations could require us to both develop and implement new practices aimed at reducing GHG emissions, such as emissions control technologies, which could increase our operating costs and could adversely affect demand for the oil and gas that we produce. To the extent financial markets view climate change and GHG emissions as a financial risk, this could negatively impact our cost of, and access to, capital. Future implementation or adoption of legislation or regulations adopted to address climate change could also make our products more or less desirable than competing sources of energy. 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/orand 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
As of December 31, 2017,2023, we had 308 employees. In addition,894 Coterra employees, 285 of whom were located in our headquarters in Houston, Texas and 227 of whom were located in our regional offices in Midland, Texas, Tulsa, Oklahoma and Pittsburgh, Pennsylvania. We had a total of 382 employees in production field locations across our regional offices. Of our total employee population, 564 were salaried and 330 were hourly. Additionally, we had 160have 189 employeesthat are employed by our wholly-owned subsidiary, GasSearch Drilling Services Corporation.Corporation (“GDS”), which is a service company engaged in water hauling and site preparation exclusively for our Marcellus Shale operations. Of our GDS employees, 16 were salaried and 173 were hourly. We recognize that our success is significantly influenced by the relationship we maintain with our employees. Overall, we believe that our relations with our employees are satisfactory. Ourfavorable. None of our employees are not represented bypursuant to a collective bargaining agreement.
Our ability to attract, retain and develop the highest quality employees is a vital component of our success.
In managing our people, we seek to:
•promote a safe and healthy workplace;
•have a results-focused culture centered on transparency and open communication;
•attract, retain and develop a highly qualified, motivated and diverse workforce;
•maintain a conservatively managed headcount to minimize workforce fluctuations;
•provide opportunities for career growth, learning and development; and
•offer highly competitive compensation and benefits packages.
We believe these practices, further described below, are the key drivers in our development of current and future talent and leadership as well as employee engagement and retention.
Recruiting, Hiring and Advancement. Due to the cyclical nature of our business and the fluctuations in activity that can occur, we manage our headcount carefully. We provide employees with opportunities to learn new roles and develop the breadth and depth of their skills to ensure a collaborative environment, strong talent and future leadership. This also helps to minimize layoffs and overall staff fluctuations when downturns occur. When a position needs to be filled, we generally seek to promote current top-performing employees before going to outside sources for a new hire. We believe this practice helps to build future leadership and to reduce voluntary turnover among our workforce by providing employees with new challenges and opportunities throughout their careers.
When we hire from outside the Company, we identify qualified candidates by promoting the position internally for referrals, engaging in recruiting through our website and online platforms, utilizing recruiting services and attending job fairs. We also have a well-established internship program that feeds top talent into our technical functions. In our recruiting efforts, we foster a culture of mutual respect and compliance with all applicable federal, state and local laws governing nondiscrimination in employment. We seek to increase the diversity of our workforce in our external hiring practices. We ask our recruiting partners to provide diverse slates of candidates and we treat all applicants with the same high level of respect regardless of their gender, ethnicity, religion, national origin, age, marital status, political affiliation, sexual orientation, gender identity, disability or protected veteran status. This philosophy extends to all employees throughout the lifecycle of employment, including recruiting, hiring, placement, promotion, evaluation, leaves of absence, compensation and training.
Compensation and Benefits.Our focus on providing competitive total compensation and benefits to our employees is a core value and a key driver of our retention program. We design our compensation programs to provide compensation that is competitive with our industry peers and rewards superior performance and, for managers and executives, aligns compensation with our performance and incentivizes the achievement of superior operating results. We do this through a total rewards program that provides:
•base wages or salaries that are competitive for the position and considered for increases annually based on employee performance, business performance and industry outlook;
•incentives that reward individual and Company performance, such as performance bonuses, management discretionary bonuses, field operational bonuses and short-term and long-term incentive programs;
•retirement benefits, including dollar-for-dollar matching contributions and discretionary employer retirement contributions to a tax-qualified defined contribution savings plan for all employees and other non-qualified retirement programs;
•comprehensive health and welfare benefits, including medical insurance, prescription drug benefits, dental insurance, vision insurance, life insurance, accident insurance, short and long-term disability benefits, employee assistance program and health savings accounts;
•tuition reimbursement for eligible employees, scholarship program and matching charitable contributions program; and
•time off, sick time, parental leave and holiday time.
We believe our compensation and benefits package is a strong retention tool and promotes personal health and financial security within our workforce.
Health and Safety. The health and safety of our employees is one of our core values for sustainable operations. This value is reflected in our strong safety culture that emphasizes personal responsibility and safety leadership, both for our employees and our contractors that are on our worksites. Our safety programs are built on a foundation that emphasizes personal safety and includes a Stop Work Authority program that empowers employees and contractors to stop work if they discover a dangerous condition or other serious EHS hazard. Our comprehensive EHS management system establishes a corporate governance framework for EHS compliance and performance and covers all elements of our operating lifecycle.
Website Access to Company Reports
We make available free of charge through our website, www.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, including our 2023 Sustainability Report, is not a part of, and is not incorporated into, this Annual Report on Form 10-K or any other report we may read and copy materials that we file with or furnish to the SEC at(and is not deemed filed herewith), whether 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 Annual Report on Form 10-K 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,Code of Business Conduct and Ethics, Audit Committee Charter, Compensation Committee Charter, Corporate Governance and NominationsSocial Responsibility Committee Charter Code of Business Conduct and Environment, Health & Safety and Environmental Affairs Committee Charter are available on our website at www.cabotog.com, under the “Governance” sectionwww.coterra.com. Requests for copies of “About Cabot.” Requeststhese documents can also be made in writing to Investor RelationsCorporate Secretary 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 cash flows, as well as adversely affect the value of an investment in our common stock, debt securities, or preferred stock.
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.economically, while higher commodity prices could cause us to experience periods of higher costs. 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 predominantlyWide fluctuations in commodity prices may result from relatively minor changes in the supply of and demand for oil, natural gas (approximately 96%and NGLs, market uncertainty and a variety of equivalent proved reserves), changesadditional factors that are beyond our control, including global events or conditions that affect supply and demand, such as pandemics, the war in natural gas prices have a more significant impact on our financial results than oil prices.Ukraine, conflict in the Middle East and other geopolitical risks and sanctions, the actions of OPEC+ members and climate change. 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 oilIf commodity prices may cause us to delay or postpone a significant portion of our exploration, development and exploitation 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 oil 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 wide fluctuations in response to relatively minor changes in the supply of and demand for natural gas and oil, 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 natural gas and oil 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 natural gas and oil;
weather conditions;
political conditions or hostilities in natural gas and oil producing regions, including the Middle East, Africa and South America;
the ability and willingness of the members of the Organization of Petroleum Exporting Countries and other exporting nations 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 affect the realized price for natural gas and oil;
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 and natural gas;
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. If natural gas and oil 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 natural gas Furthermore, substantial, extended decreases in commodity prices may render certain projects uneconomic, which may result in significant downward adjustments to our estimated proved reserves and oil wells is a high-risk activity.
Our growth is materially dependent upon the successcould negatively impact our ability to borrow, our cost of capital and our ability to access capital markets, increase our costs under our revolving credit agreement and limit our ability to execute aspects of our drilling program. Drilling for 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 oil prices;
unexpected drilling conditions, pressure or irregularities in formations;
equipment failures or accidents;
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; 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 dependent 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 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 natural gas or oil.
Our proved reserves are estimates. Any material inaccuracies in our reserve estimates or underlying assumptions could cause the quantities and net present value of our reserves to be overstated or understated
Reserve engineering is a subjective process of estimating underground accumulations of 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 oil 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 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% 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.business plans.
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'sproperty’s carrying amount may not be recoverable. We compare expected undiscounted future cash flows to the net book value of the asset. If the future undiscounted expected cash flows, based on our estimate of future 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 to the carrying amounts of oil and gas properties in the future.
Our producing propertiesDrilling, completing and operating oil and natural gas wells are geographically concentrated in the Marcellus Shale in northeast Pennsylvania, making us vulnerable to risks associated with operating in one major geographic area.high-risk activities.
Our producing properties are geographically concentrated ingrowth is materially dependent upon the Marcellus Shale in northeast Pennsylvania. At December 31, 2017, 97%success of our proved developed reservesdrilling program. Drilling for oil and 94%natural gas involves numerous risks, including the risk that no commercially productive reservoirs will be encountered. The cost of our total equivalent production were attributable our properties located in the Marcellus Shale,drilling, completing and we expect that concentration to increase slightly in 2018operating wells is substantial and uncertain, and drilling operations may be curtailed, delayed or canceled as a result of the expected salesa variety of factors beyond our control. 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 operations present hazards and risks that require significant oversight and are subject to numerous possible disruptions from unexpected events.
The scope and nature of our remaining Texas propertiesoperations present a variety of significant hazards and risks, including operational hazards and risks such as explosions, fires, product spills, and cybersecurity incidents, such as unauthorized access to data or systems, among other risks. Our operations are also subject to broader global events and conditions, including public health crises, pandemics, epidemics, war or civil unrest, acts of terror, weather events and natural disasters, including those that are related to
or exacerbated by climate change. Such hazards and risks could impact our business in the first halfareas in which we operate, and our business and operations may be disrupted if we fail to respond in an appropriate manner to such hazards and risks or if we are unable to efficiently restore or replace affected operational components and capacity. Furthermore, our insurance may not cover such, or be adequate to compensate us for all resulting losses. The cost of 2018. Asinsurance may increase and the availability of insurance may decrease, as a result of climate change or other factors. The occurrence of any event not covered or fully covered by insurance could have a material adverse effect on our financial position, results of operations and cash flows.
Our proved reserves are estimates. Any material inaccuracies in our reserves estimates or underlying assumptions could cause the quantities and net present value of our reserves to be overstated or understated.
Reserves engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact manner. The process of estimating quantities of proved reserves is complex and inherently imprecise, and the reserves data included in this concentration, wedocument are only estimates. The process relies on interpretations of available geologic, geophysical, engineering and production data. The extent, quality and reliability of this technical data can vary. The process also requires certain economic assumptions, some of which are mandated by the SEC, such as assumptions relating to commodity prices. Additional assumptions include drilling and operating expenses, capital expenditures, taxes and availability of funds. Furthermore, different reserve engineers may make different estimates of reserves and cash flows based on the same data. For example, our total company proved reserves decreased by approximately 17 percent year over year at December 31, 2022. For more information on such revision, refer to the Supplemental Oil and Gas Information included in Item 8.
Results of drilling, testing and production subsequent to the date of a reserves estimate may justify revising the original estimate. Accordingly, initial reserves estimates often vary from the quantities of oil and natural gas that are ultimately recovered, and such variances may be disproportionately exposed tomaterial. Any significant variance could reduce the impactestimated quantities and present value of regional supply and demand factors, state and local political forces and governmental regulation, processing or transportation capacity constraints,our reserves.
You should not assume that the present value of future net cash flows from our proved reserves is the current market limitations, severe weather events, water shortages or other conditions or interruptionvalue of our estimated reserves. In accordance with SEC requirements, we base the estimated discounted future net cash flows from our proved reserves on the 12-month average index price for the respective commodity, calculated as the unweighted arithmetic average for the first day of the processing or transportationmonth price for each month and costs in effect on the date of oil, natural gas or NGLsthe estimate, holding the prices and costs constant throughout the life of the properties, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions. Actual future prices and costs may differ materially from those used in the region. net present value estimate, and future net present value estimates using then current prices and costs may be significantly less than the current estimate. In addition, the 10 percent discount factor we use when calculating discounted future net cash flows for reporting requirements in compliance with the applicable accounting standards may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the oil and gas industry in general.
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 natural 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 as reserves are depleted, 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. Additionally, there is no way to predict in advance of any exploration and development whether any particular location will yield sufficient quantities to recover drilling or completion costs or be economically viable. Low natural gas and oilcommodity prices may further limit the kinds of reserves that we can develop and produce economically.
Our reserve report estimates that If we are unable to replace our current and future production, from our proved developed reserves as of December 31, 2017revenues will decrease at a rate of 12%, 25%, 18% and 14% during 2018, 2019, 2020 and 2021, respectively. Future development of proved
undeveloped and other reserves currently not classified as proved developed producing will impact these rates of decline. Because of higher initial decline rates from newly developed reserves, we consider this pattern fairly typical.
Exploration, development and exploitation activities involve numerous risks that may result in, among other things, dry holes, the failure to produce natural gas and oil 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 collectability of our trade receivables 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 provisions of our debt agreements could adversely affect our business, financial positioncondition and results of operations.operations may be adversely affected.
The development of our proved undeveloped reserves may take longer and may require higher levels of capital expenditures than we currently anticipate.
As of December 31, 2017, we had2023, 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 portion21 percent of our cash flow to make debt service payments, which will reduceestimated proved reserves (by volume) were undeveloped. 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 reserves 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 Analysisrecorded only if they relate to wells scheduled to be drilled within five years of Financial Condition and Resultsthe date of Operations - Financial Condition - Capital Resources and Liquidity.”
The borrowing base under our revolving credit facilitybooking, we may be reduced, which could limit usrequired to remove any PUD reserves that are no longer planned to be developed within this five-year time frame. Delays in the future.
The borrowing base underdevelopment of 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 terms of the revolving credit facility on April 1. In addition, either 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 inPUD 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 declinesdecreases in commodity prices or otherwise, ourand increases in costs to drill and develop such reserves may also result in some projects becoming uneconomic.
ability to borrow under our revolving credit facility may be limited and we could be required to repay any indebtedness in excessStrategic 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)drilling and completion), 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 20182024 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 20182024 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/orand the prices we receive for our production could be materially harmed if we fail to obtain adequate services such as gathering, 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 gathering, 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 slower to build out.slow. 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, the Marcellus Shale wellsMoreover, these availability and capacity issues are likely to occur in remote areas with less established infrastructure, such as our Permian Basin properties where we have drilled to date have generally reported very high initial production rates. The amount ofsignificant oil and natural gas being produced in the area fromproduction. Any of these new wells, as well as natural gas produced from other existing wells, may exceed theavailability or capacity of the various gatheringissues could negatively affect our operations, revenues and intrastate or interstate transportation pipelines currently available. In such event, thisexpenses. 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 and development 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'smanagement’s attention away from our existing operations.
The integration of the businesses and properties we have acquired or may in the future acquire could be difficult, and may divert management'smanagement’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 varietyresult 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 natural gas, oil, drilling fluids or hydraulic fracturing fluids;
uncontrolled flows of natural gas, oil or well fluids;
pipeline ruptures;
fires;
formations with abnormal pressures;
handling and disposal of materials, including drilling fluids and hydraulic fracturing fluids;
release of toxic gas;
buildup of naturally occurring radioactive materials;
pollution and other environmental risks, including conditions caused by previous owners or operatorsthe increase in the size of our properties; and
natural disasters.
Any of these events could resultbusiness. There can be no assurances that we will be successful in injury or loss of human life, loss of hydrocarbons, significant damage to or destruction of property, environmental pollution, regulatory investigations and penalties, suspension or impairment of our operations and substantial losses to us.
Our utilization of natural gas gathering and pipeline systems also involves various risks, including the risk of explosions and environmental hazards caused by pipeline leaks and ruptures. The location of pipelines near populated areas, including residential areas, commercial business centers and industrial sites, could increase these risks. 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.integration efforts.
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, 2017,2023, non-operated wells represented approximately 14.7%51 percent of our total owned gross wells, or approximately 3.8%12 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 of 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 anAn operator of our wells toor a joint venture participant may not adequately perform operations, an operator'smay breach of the applicable agreements or an operator's failuremay fail to act in ways that are in our best interest, which could reduce our production and revenues.revenues and expose us to liabilities. Our dependence on the operator and other working interest owners for these projects and our limited ability to influence or control the operation and future development of these propertiesa joint venture participant could materially adversely affect the realization of our targeted returns on capital in drilling or acquisition activities and lead to unexpected future costs.
CompetitionMany of our properties are in areas that may have been partially depleted or drained by offset (i.e., neighboring) wells and certain of our wells may be adversely affected by actions other operators may take when drilling, completing or operating wells that they own.
Many of our properties are in areas that may have been partially depleted or drained by earlier drilled offset wells. We have no control over offsetting operators who could take actions such as drilling and completing nearby wells, that could adversely affect our operations. When a new offset 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 industrywells 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 intense,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 manythe 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 government 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. As of December 31, 2023, less than one percent of our competitors have substantially greater financial and technological resources than we do,net undeveloped acreage in our core operating areas will expire over the next three years. Our actual drilling activities may materially differ from those presently identified, which could adversely affect our competitive position.business.
CompetitionCyber-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, like the oil and gas industry in general, has become increasingly dependent on data, information systems, and digitally connected infrastructure, including technologies managed by third-party providers on whom we rely to help us
collect, host or process information. We depend on this technology to, for example, record and store information like financial data, estimate quantities of oil and natural gas reserves, analyze and share operating data, and communicate internally and externally. Information and operational technology systems control nearly all of the oil and gas distribution systems in the natural gasU.S., which are necessary to transport our products to market. These systems also enable communications and oil industry is intense. Majorprovide a host of other support services for our business. In recent years (and, in large part, due to the COVID-19 pandemic), we have increased the use of remote networking and independent natural gasonline conferencing services and oil companies actively bidtechnologies that enable employees to work outside of our corporate infrastructure, which exposes us to additional cybersecurity risks, including unauthorized access to proprietary, confidential, or other sensitive information.
Cyber-attacks are becoming more sophisticated and can include, but are not limited to, the use of malicious software, phishing scams, ransomware, attempts to gain unauthorized access to systems or data, or other electronic security breaches that could lead to disruptions in critical systems, unauthorized release of confidential or otherwise protected information, such as personal information of our employees, 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 integrity issues, 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 or operational 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 or operational technology systems and related infrastructure, or that of our business associates or partners, could result in supply chain disruptions that delay or prevent the transportation and marketing of our production, equipment damage, fires, explosions or environmental releases, 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 reconnaissance campaigns, may remain undetected for desirable natural gasan extended period, and oil properties, as well asour systems and insurance coverage for the capital, equipmentprotecting against such cybersecurity risks may be costly and labormay not be sufficient. As cyber-attackers become more sophisticated, we may be required to operateexpend significant additional resources to continue to protect our business or remediate the damage from cyber-attacks. Furthermore, the continuing and develop these properties. Our competitive position is affected by price, contract termsevolving threat of cyber-attacks has resulted in increased regulatory focus on prevention, mitigation, and quality of service, including pipeline connection times, distribution efficienciesnotification, and reliable delivery record. Many ofwe may be required to expend significant additional resources to continue to modify or enhance our competitorsprotective 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 financialsubstantial capital requirements, and technological resources and exploration and development budgets that are substantially greater than ours. These companieswe may not be able to pay moreobtain 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 agreement and longer-term capital markets as sources of liquidity for exploratory projectsany capital requirements not satisfied by cash flow from operations or other sources. Adverse economic and productive natural gasmarket conditions, could adversely affect our ability to access such sources of liquidity. Future challenges in the global financial system may adversely affect the terms on which we are able to obtain financing, which could impact our business, financial condition and oil propertiesaccess to capital. Our ability to access the capital markets may be restricted at a time when we want or need to raise capital, which could have an impact on our flexibility to react to changing economic and business conditions. Additionally, such adverse economic and market conditions could impact our counterparties, including our receivables and our hedging counterparties, who may, as a result of such conditions, be unable to perform their obligations.
Risks associated with our debt and the provisions of our debt agreements could adversely affect our business, financial position and results of operations.
Our indebtedness 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 would reduce the funds that would otherwise be available for operations, returning cash flow from operations to stockholders and future business opportunities. As a result, our ability to sell assets, engage in strategic transactions or obtain additional financing for working capital, capital expenditures, general corporate and other purposes may be adversely impacted. 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. 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.
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 under such agreements due to lack of covenant compliance. Because the calculations of the financial ratios are made as of certain dates, the financial ratios can fluctuate significantly from period to period. A prolonged period of lower commodity prices could further increase the risk of our inability to comply with covenants to maintain specified financial ratios. In order to provide a margin of comfort with regard to these financial covenants, we may seek to modify our capital program, sell non-strategic assets or opportunistically modify or increase our derivative instruments. 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 define, evaluate, bid forsuccessfully execute any of these strategies, and purchase a greater number of properties and prospects than our financial or human resources permit. In addition, these companiessuch strategies may be able to expend greater resourcesunavailable on the existingfavorable terms or at all. For more information about our debt agreements, please read “Management’s Discussion 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 periodsAnalysis of low natural gasFinancial Condition and oil pricesResults of Operations-Financial Condition-Liquidity and to absorb the burden of current and future governmental regulations and taxation.Capital Resources.”
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, weWe use financial derivative instruments to manage commodity price risk associated with our natural gas and crude oil production.risk. While there are many different types of derivatives available, we generally utilize collar, swap and basis swap agreements to manage price risk more effectively.
The collar arrangements are put and call options used to establish floor and ceilingWhile these derivatives reduce the impact of declines in commodity 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 arrangementsthese derivatives conversely limit the benefit to us of increases in prices. In addition, these arrangements expose us to risks of financial loss in a variety of circumstances, including when:
•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.
TheIn addition, 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. Whilederivatives transactions, including swaps. Although we believe that our use of swap transactions exemptexempts us from certain regulatory requirements, the changes to the swapderivatives market dueregulation affect us directly and indirectly. These changes, as in effect and as continuing to increased regulationbe implemented, as well as a reduced liquidity in oil and gas derivative market, 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 reducederivative contracts, limit the availability of newderivatives to protect against risks that we encounter, reduce our ability to monetize or restructure our existing swaps.derivative contracts and increase our exposure to less creditworthy counterparties. 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.
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 loss of key personnelLegal, Regulatory and Governmental Risks
ESG concerns and negative public perception regarding us and our industry could adversely affect our abilitybusiness operations and the price of our common stock, debt securities and preferred stock.
Businesses across all industries are facing increasing scrutiny from investors, governmental authorities, regulatory agencies and the public related to operate.their ESG practices, including practices and disclosures related to climate change, sustainability, diversity, equity and inclusion initiatives, and heightened governance standards. Failure, or a perceived failure, to adequately respond to or meet evolving investor, stockholder or public ESG expectations, concerns and standards may cause a business entity to suffer reputational damage and materially and adversely affect the entity’s business, financial condition, or stock and debt prices. In addition, organizations that provide ESG information to investors have developed ratings processes for evaluating a business entity’s approach to ESG matters. Although currently no universal rating standards exist, the importance of sustainability evaluations is becoming more broadly accepted by investors and stockholders, with some using these ratings to
Our operations are dependent upon
inform investment and voting decisions. Additionally, certain investors use these scores to benchmark businesses against their peers and, if a relatively small group of key management and technical personnel, and onebusiness entity is perceived as lagging, these investors may engage with the entity to demand improved ESG disclosure or more of these individuals could leave our employment. The unexpected lossperformance. Moreover, certain members of the servicesbroader investment community may consider a business entity’s sustainability score as a reputational or other factor in making an investment decision. Consequently, a low sustainability score could result in exclusion of one or moreour securities from consideration by certain investment funds, engagement by investors seeking to improve such scores and a negative perception of these individuals could have a detrimental effect on us.our operations by certain investors. In addition, our drilling successefforts in recent years aimed at the investment community to generally promote the divestment of fossil fuel equities and to limit or curtail activities with companies engaged in the successextraction of other activities integral to our operations will depend, in part, onfossil fuel reserves could limit our ability to attractaccess capital markets. These initiatives by activists and retain experienced geologists, engineersbanks, including certain banks who are parties to the credit agreement providing for our revolving credit agreement, could interfere with our business activities, operations and ability to access capital.
Further, negative public perception regarding us and our industry resulting from, among other things, concerns raised by advocacy groups about climate change impacts of methane and other professionals. Competitiongreenhouse 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 experienced geologists, engineersour oil, natural gas and some other professionals is extremely intense. IfNGL production, reduced profits, increased regulation, regulatory investigations and litigation, and negative impacts on our stock and debt prices and access to capital markets. These factors could also cause the permits we cannot retainneed to conduct our technical personneloperations to be challenged, withheld, delayed, or attract additional experienced technical personnel,burdened by requirements that restrict our ability to compete could be harmed.profitably conduct our 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.
Most of our exploration and productionOur 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 oil and gas regulatory programs; however, the EPA has asserted federal regulatory authority over certain hydraulic fracturing activities involving diesel under the Safe Drinking Water Act 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 may beare 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, 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. 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 States Geological Survey identified six states with the most significant hazards from induced seismicity, including Oklahoma, Kansas, Texas, Colorado, New Mexico, and Arkansas. In light 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 additionalextensive federal, state and local laws and regulations, may be needed to more closely regulateincluding drilling and environmental and safety laws and regulations, which increase the hydraulic fracturing process. We cannot predict whether additional federal, statecost of planning, designing, drilling, installing and operating oil and natural gas facilities. New laws and regulations or localrevisions or reinterpretations of existing laws orand regulations applicable to hydraulic fracturing will be enactedcould further increase these costs, could increase our liability risks, and could result in the future and, if so, what actions any such laws or regulations would require or prohibit. Increased regulation and attention given to induced seismicity could lead to greater opposition to, and litigation concerning,increased restrictions on oil and gas exploration and production activities, utilizing hydraulic fracturing or injection wells for waste disposal, which could have ana 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.
For additional information, please read “Business and Properties—Other Business Matters—Regulation of Oil and Natural Gas Exploration and Production,” “—Regulation of Natural Gas Marketing, Gathering and Transportation,” and “—Environmental and Safety Regulations” in Items 1 and 2.
Oil and natural gas production operations, especially those using hydraulic fracturing, are substantially dependent on the availability of water. Our ability to produce oil and natural gas economically and in commercial quantities could be impaired if we are unable to acquire adequate supplies of water for our operations or are unable to dispose of or recycle the water we use economically and in an environmentally safe manner.
Water is an essential component of oil and natural gas production activities, including operational delays or increased operating costs induring the production of oil and natural gas from developing shale plays, or could make it more difficult to perform hydraulic fracturing.
On August 16, 2012, the EPA published final rules that establish new air emission control requirements 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.drilling process. 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.
Compliance with these requirements, especially the 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 that could result in significant costs, including increased capital expenditures and operating costs, and could adversely impact our business. Similarly, aggregating our oil and gas facilities for permitting could result in more complex, costly, and time consuming air permitting. Particularly in regard 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 whichparticular, 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, withdrawal of water for use in high-volume hydraulic fracturing 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 gas preempt local zoning rules, this could lead to additional local restrictions on oil and gas activity in the state.
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 initiatives and regulations could include restrictions on our ability to conduct 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. 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.
A numberThe adoption 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 naturalgas we produce.
Studies have found that emission of certain gases, commonly referred to as GHGs impact the earth’s climate. The U.S. Congress and various states have been evaluating, and in some cases implementing, climate-related legislation and other regulatory initiatives that restrict GHG emissions. These actions as well as any future laws or regulations that regulate or limit GHG emissions from our equipment and operations could require us to develop and implement new practices aimed at reducing GHG emissions, such as emissions control technologies, and to monitor and report GHG emissions associated with our operations, any of which could increase our operating costs and could adversely affect demand for the oil and gas that we produce. At this time, it is not possible to quantify the impact of such future laws and regulations on our business.
For additional information, please read “Business and Properties—Other Business Matters—Environmental and Safety Regulations—Greenhouse Gas and Climate Change Laws and Regulations” in Items 1 and 2.
We are subject to various climate-related risks.
The following is a summary of potential climate-related risks that could adversely affect us:
Transition Risks. Transition risks are related to the transition to a lower-carbon economy and include policy and legal, technology, and market risks.
Policy and Legal Risks. Policy risks include actions that seek to lessen activities that contribute to adverse effects of climate change or to promote adaptation to climate change. 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 or may incentivize the use of alternative or renewable sources of energy that may be associated with its effects, and the regulation 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, reducingcould reduce the demand for our products. For example, the IRA contains tax inducements and consumptionother provisions that incentivize investment, development and deployment of our productsalternative energy sources and services (duetechnologies, and at COP28 in December 2023, more than 190 governments reached a non-binding agreement to transition away from fossil fuels and encourage the growth and expansion of renewable energy. Legal risks include potential lawsuits or regulations regarding the impacts of climate change, failure to adapt to climate change, and the insufficiency of disclosure around material financial risks. For example, the SEC in both2022 proposed rules on climate change disclosure requirements for public companies which, if adopted as proposed, could result in substantial compliance costs, and weather patterns), andin September of 2023, California passed climate-related disclosure mandates that are broader than the economic healthSEC’s proposed rules.
Furthermore, we could also face an increased risk of the regions in which we operate, all of which can create financial risks. In addition, legislative and regulatory responses climate‐related litigation or “greenwashing” suits with respect to our operations, disclosures, or products. Claims have been made against certain energy companies alleging that GHG emissions from oil, gas and climate change may increase our operating costs. The United States Congress has previously considered legislation relatedNGL operations constitute a public nuisance under federal and state law. Private individuals or public entities also could attempt to GHG emissions. There haveenforce environmental laws and regulations against us and could seek personal injury and property damages or other remedies. Additionally, governments and private parties are 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 States have expressed intentions to take GHG-related actions. Increased public awareness and concern regarding climate change may result in more state, regional and/increasingly filing suits, or federal requirements to reduce or mitigate GHG emissions.
In September 2009, the EPA finalized a mandatory GHG reporting rule that requires large sources of GHG emissions to monitor, maintain records on, and annually report their GHG emissions beginning January 1, 2010. The rule applies to large facilities emitting 25,000 metric tons or more of carbon dioxide-equivalent (CO2e) emissions per year and to most upstream suppliers of fossil fuels, as well as manufacturers of vehicles and engines. Subsequently, in November 2010, the EPA issued GHG monitoring and reporting regulations that went into effect on December 30, 2010, specifically for oil and natural gas facilities, including onshore and offshore oil and natural gas production facilities that emit 25,000 metric tons or more of CO2e per year. The rule required reporting of GHG emissions by regulated facilities to the EPA by March 2012 for emissions during 2011 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 permitsinitiating regulatory action, based on the emission of conventional pollutants. In October 2015, the EPA finalized rulesallegations that added new sourcescertain public statements regarding ESG-related matters by companies are false and misleading “greenwashing” campaigns that violate deceptive trade practices and consumer protection statutes or that climate-related disclosures made by companies are inadequate. Similar issues can also arise when aspirational statements such as net-zero or carbon neutrality targets are made without clear plans. Although we are not a party to 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,any such climate-related or “greenwashing” litigation currently, unfavorable rulings against us 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 calculate and report GHG emissions resulting from equipment leaks.
Federal and state regulatory agencies can impose administrative, civil and/or criminal penalties for non-compliance with air permits or other requirements of the CAA and associated state laws and regulations. In addition, the passage of any federal or state climate change laws or regulationssuch 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 costs to (i) operatelower prices and maintain our facilities, (ii) install new emission controls on our facilities and (iii) administer and manage any GHG emissions program. If we are unable to recover or pass through a significant levellower revenues. Market risk also may take the form of our costs related to complying with climate change regulatory requirements imposed on us, it could have a material adverse effect on our results of operations and financial condition. To the extent financial markets view climate change and GHG emissions as a financial risk, this could negatively impact our cost of andlimited access to capital. Legislation or regulations that may be adoptedcapital as investors shift investments to address climate change could also affect the markets for our products by making our products more or less desirable than competing sources of energy.
Moreover, some experts believe climate change poses potential physical risks, including an increase in sea levelcarbon-intensive industries and changes in weather conditions, such as an increase in changes in precipitation and extreme weather events.alternative energy industries. In addition, warmer winters asinvestment advisers, banks, and certain sovereign wealth, pension, and endowment funds recently have been promoting divestment of investments in fossil fuel companies and pressuring lenders to limit funding to companies engaged in the
extraction, production, and sale of oil and gas. For additional information, please read “—Risks Related to our Indebtedness, Hedging Activities and Financial Position—We have substantial capital requirements, and we may not be able to obtain needed financing on satisfactory terms, if at all” in this Item 1A.
Reputation Risk.Climate change is a resultpotential source of global warming could also decrease demand for natural gas. Toreputational risk, which is tied to changing customer or community perceptions of an organization’s contribution to, or detraction from, the extent that such unfavorable weather conditions are exacerbated by global climate change or otherwise, our operations may be adversely affectedtransition to a greater degree than we have previously experienced, including increased delayslower-carbon economy. For additional information, please read “—ESG concerns and costs. However, the uncertain nature of changes in extreme weather events (such as increased frequency, duration,negative public perception regarding us 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 caused by these potential physical risks of climate change unreliable.
Terrorist activities and the potential for military and other actionsindustry could adversely affect our business.business operations and the price of our common stock, debt securities and preferred stock.” in this Item 1A.
Physical Risks.Potential physical risks resulting from climate change may be event driven (including increased severity of extreme weather events, such as hurricanes, droughts, floods or freezes) or may be driven by longer-term shifts in climate patterns that may cause sea level rise or chronic heat waves. Potential physical risks may cause direct damage to assets and indirect impacts, such as supply chain disruption, changes in water availability, sourcing, and quality, which could impact drilling and completion operations. These physical risks could cause increased costs, production disruptions, lower revenues and substantially increase the cost or limit the availability of insurance.
We are subject to a number of privacy and data protection laws, rules and directives (collectively, “data protection laws”) relating to the processing of personal data.
The threatregulatory environment surrounding data protection laws is uncertain. Complying with varying jurisdictional requirements could increase the costs and complexity of terrorismcompliance, and the impactviolations of militaryapplicable 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 action have caused instabilitypenalties 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 world financial marketsproceedings or actions against us by governmental entities or others, subject us to significant fines, penalties, judgments and could leadnegative publicity, require us to increased volatility in prices for natural gaschange our business practices, increase the costs and oil, allcomplexity 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 riskcompliance 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 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 oil and gas industryacquisition of a company that is not in general have become increasingly dependent on digitalcompliance with applicable data computer networks and connected infrastructure. We depend on this technology to record and store financial data, estimate quantitiesprotection laws may result in a violation 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, thePeriodically U.S. enacted legislation referredlegislators propose substantive 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 ofthat 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. Past proposals have included 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. These proposals have also included general tax law is always subjectchanges to change. Periodically, legislation is proposed to repeal these industryraise tax incentivesrates on both domestic and deductions, and/or to impose new industry taxes. In addition, it is uncertain if and to what extent various states will conform to the Tax Act. 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.
foreign income.
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.
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'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 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. If we cannot retain our technical personnel or attract additional experienced technical personnel, our ability to compete could be harmed.
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, 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, water or other 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 and the repurchase of our common stock will be uncertain.
Although we have paid cash dividends on shares of our common stock and have conducted repurchases of our common stock in the past, our Board of Directors may determine not to take such actions in the future or may reduce the amount of dividends or repurchases made in the future. Decisions on whether, when and in which amounts to declare and pay any future dividends, or to authorize and make any repurchases of our common stock, will remain in the discretion of our Board of Directors. 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.
ITEM 1B. UNRESOLVED STAFF COMMENTS
None.
ITEM 1C. CYBERSECURITY
Governance
Our Board of Directors, with assistance from our Audit Committee, oversees our risk management program, which includes technology and cybersecurity risks. Our management team, including our Vice President - Information Technology (“VP - IT”), provides periodic updates on risk management to the Audit Committee and to the Board of Directors. Such periodic updates include presentations regarding cybersecurity matters, including any new cybersecurity threats, events, incidents, risks, risk management solutions, trainings or education, strategy pivots, or governance changes. The Audit Committee regularly reports its actions, findings and recommendations to the Board of Directors. The Audit Committee relies in large part on such periodic updates and presentations from our management team in developing its reports to the Board of Directors.
Risk Management and Strategy
We maintain a cybersecurity Incident Response Plan (“IRP”) designed to identify, assess, manage, mitigate, and respond to cybersecurity risks, threats and incidents. The IRP was developed in consultation with common cybersecurity frameworks, including NIST Cybersecurity Framework, to provide efficiency, familiarity and consistency in design. As part of our IRP, we have established a Cybersecurity Incident Management Team (“CIMT”), comprised of senior level executives and
management, that defines overall policy and strategy when faced with a cybersecurity incident. The CIMT provides cross-functional and geographical visibility, as well as executive leadership oversight, to address and mitigate associated risks. Among our CIMT, our VP - IT holds the highest level of executive responsibility for assessing and managing cybersecurity threats, incidents, and risks, as well as developing and implementing all cybersecurity risk management, strategy, and governance recommendations. Our VP - IT leads all components of our information technology functions and reports to our Executive Vice President and Chief Financial Officer.
The CIMT is supported by a dedicated Cybersecurity Incident Response Team (“CIRT”), comprised generally of security and networking team members with responsibilities to monitor and assess events, cybersecurity incidents, and technical activities throughout our organization. Our CIRT members possess critical skill sets, experience, and competencies related to the management of cybersecurity risks and matters. In particular, our VP - IT has over 28 years of experience in the field of information systems and cybersecurity and leads an experienced security and networking team with 67 years of additional combined experience in developing and executing cybersecurity strategies. Our CIRT members also hold over 29 certifications in risk and information security from organizations such as International Information System Security Certification Consortium (ISC2), The SANS Institute, Global Information Assurance Certification (GIAC), CompTIA and Cisco, including Certified Information Systems Security Professional (CISSP), GIAC, Certified Incident Handler Certification (GCIH), GIAC Critical Controls Certification (GCCC), GIAC Continuous Monitoring Certification (GMON), SANS Security Awareness Professional (SSAP), Certified Information Security Manager (CISM), Certified in Risk and Information Systems Control (CRISC), and Certified Information Systems Auditor (CISA).
Our CIRT is supported by dedicated Information Technology (“IT”) and Operational Technology (“OT”) security resources, and further supported by various external parties, including but not limited to, cybersecurity service providers, assessors, consultants, auditors, and other third parties engaged on an as-needed basis.
The CIRT determines whether a cybersecurity incident warrants escalation to the CIMT. In the event of a cybersecurity incident, the IRP describes processes to detect, analyze, contain, eradicate and remediate such incident. These processes include, but are not limited to:
•Maintaining an updated inventory and management of digital assets;
•Conducting risk assessments to validate our cybersecurity policies, practices, and tools;
•Employing appropriate next generation firewalls, endpoint detection and response (EDR) software, identity and access management (IAM), multifactor authentication (MFA), virtual private network (VPN), account change monitoring, encryption, patch management, web content filter, spam filter and reporting, and security information and event management (SIEM) software;
•Conducting regular vulnerability scans of our IT and OT infrastructure;
•Obtaining and applying vulnerability patches appropriately;
•Conducting penetration tests and assessing recommended corrective actions;
•Requiring employees to complete a security awareness training program;
•Conducting regular phishing simulations and tabletop exercises to test familiarity with cybersecurity policies and procedures; and
•Reviewing and evaluating developments in the cyber threat landscape.
Our IRP also describes processes to identify material risks from cybersecurity incidents associated with our use of third-party service providers.
Currently, we are not aware of any material risks from cybersecurity threats that have materially affected or are reasonably likely to materially affect our operations. However, the nature of potential cybersecurity risks and threats are uncertain, and any future incidents, outages or breaches could have a material adverse effect on our reputation, business strategy, results of operations or financial condition.
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 the 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/penalties or penalties,both, 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.
In June 2023, we received a Notice of Violation and Opportunity to Confer (“NOVOC”) from the U.S. EPA alleging violations of the Clean Air Act, the Texas State Implementation Plan, the New Mexico State Implementation Plan (“NMSIP”) and certain other state and federal regulations pertaining to facilities in Texas and New Mexico. Separately, in July 2023, we received a letter from the U.S. Department of Justice that the EPA has referred this NOVOC for civil enforcement proceedings. In August 2023, we received a second NOVOC from the EPA alleging violations of the Clean Air Act, the NMSIP, and certain other state and federal regulations pertaining to facilities in New Mexico. We have exchanged information with the EPA and continue to engage in discussions aimed at resolving the allegations. At this time we are unable to predict with certainty the financial impact of these NOVOCs or the timing of any resolution. However, any enforcement action related to these NOVOCs will likely result in fines or penalties, or both, and corrective actions, which may increase our development costs or operating costs. We believe that any fines, penalties, or corrective actions that may result from this matter will not have a material effect on our financial position, results of operations, or cash flows.
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, 201823, 2024 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.
|
| | | | | | | |
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 |
1934. All officers are elected annually by our Board of Directors. All
| | | | | | | | | | | | | | | | |
Name | | Age | | Position | | |
Thomas E. Jorden | | 66 | | | Chairman, Chief Executive Officer and President | | |
Shannon E. Young III | | 52 | | | Executive Vice President and Chief Financial Officer | | |
Stephen P. Bell | | 69 | | | Executive Vice President, Business Development | | |
Andrea M. Alexander | | 42 | | | Senior Vice President and Chief Human Resources Officer | | |
Blake Sirgo | | 41 | | | Senior Vice President, Operations | | |
Adam Vela | | 50 | | | Senior Vice President and General Counsel | | |
Michael D. DeShazer | | 38 | | | Vice President of Business Units | | |
Gary Hlavinka | | 62 | | | Vice President, Marcellus Business Unit | | |
Todd M. Roemer | | 53 | | | Vice President and Chief Accounting Officer | | |
Kevin W. Smith | | 38 | | | Vice President and Chief Technology Officer | | |
Mr. Jorden was appointed Chief Executive Officer and President of Coterra following the Merger with Cimarex in October 2021 and Chairman of the executive officers have been employedBoard of Coterra in November 2022. Mr. Jorden previously served as the Chief Executive Officer and President of Cimarex beginning September 2011 and as Chairman of the Board of Directors of Cimarex beginning August 2012. At Cimarex, he began serving as Executive Vice President of Exploration when the company formed in 2002. Prior to the formation of Cimarex, Mr. Jorden held multiple leadership roles at Key Production Company, Inc. (“Key”), which was acquired by Cimarex in 2002. He joined Key in 1993 as Chief Geophysicist and subsequently became Executive Vice President of Exploration. Before joining Key, Mr. Jorden served at Union Pacific Resources and Superior Oil Company.
Mr. Young was appointed Executive Vice President and Chief Financial Officer in July 2023. From 2019 to 2023, Mr. Young served as Executive Vice President and Chief Financial Officer of Talos Energy Inc. Prior to joining Talos Energy Inc.,
Mr. Young served in similar positions with Sheridan Production Company, LLC, Cobalt International Energy, Inc. and Talos Energy LLC. Mr. Young served as a Managing Director for the Global Energy Group at Goldman, Sachs & Co. from 2010 to 2014 and was an investment banker at Morgan Stanley from 1998 to 2010.
Mr. Bell was appointed Executive Vice President of Business Development following the Merger with Cimarex in October 2021. At Cimarex, Mr. Bell was appointed Senior Vice President of Business Development and Land in September 2002 and was named Executive Vice President of Business Development in September 2012. Mr. Bell served at Key prior to its acquisition by Cimarex. He joined Key in 1994 as Vice President of Land and was appointed Senior Vice President of Business Development and Land in 1999.
Ms. Alexander was appointed Senior Vice President and Chief Human Resources Officer in July 2023. Ms. Alexander served as Chief People Officer at Rent the Runway from June 2021 to July 2023. Ms. Alexander served in various roles of increasing responsibility, including Associate Partner and Professional Development Manager, at McKinsey & Company, a management consulting company, from 2009 to 2021.
Mr. Sirgo was appointed Senior Vice President of Operations in October 2022. Mr. Sirgo previously served as Vice President of Operations at Coterra from October 1, 2021 to October 1, 2022.Prior to the Merger with Cimarex in October 2021, Mr. Sirgo served in a number of technical and leadership roles since joining Cimarex in 2008, including Vice President of Operations from February 2020 to October 2021, Vice President of Operation Resources from November 2018 to February 2020, Permian Division Production Manager from June 2016 to November 2018, and in various engineering and production manager positions. Before joining Cimarex, Mr. Sirgo worked at Occidental Petroleum.
Mr. Vela was appointed Vice President and General Counsel in October 2022 and was promoted to Senior Vice President and General Counsel in August 2023. Mr. Vela previously served in various capacities at Coterra and Cimarex beginning in 2005, including Vice President, Assistant General Counsel, Chief Litigation Counsel and Corporate Counsel. Mr. Vela is a member of the Texas, Colorado, American and Houston Hispanic Bar associations, as well as the Foundation for Natural Resources and Energy Law.
Mr. DeShazer was appointed Vice President of Business Units following the Merger with Cimarex in October 2021. 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, Asset Evaluation Team Manager from 2018 to 2019 and Vice President of the Permian Business Unit in 2019.
Mr. Hlavinka was appointed Vice President of the Marcellus Business Unit in April 2022. Since joining Coterra, formerly Cabot Oil & Gas Corporation, in 1989, he has served in engineering and management roles across the Company’s operations, in multiple producing basins. Mr. Hlavinka worked initially as a Facility Engineer and District Superintendent in the Company’s West Virginia production operations, and subsequently as a Corporate Reservoir Engineer in Houston, Texas. In 2006 he was named West Region Engineering Manager for at least the last five years, except for Mr. Charles E. Dyson IIRocky Mountain and Mr. Julius Leitner.
Mr. Dyson joined the Company as the Director of Information ServicesMid-Continent operating areas, and in October 2015 and2009 he was promoted to Regional Operations Manager for the North Region, with responsibility for Appalachian Basin operations and engineering.
Mr. Roemer was appointed Vice President of Information Servicesand Chief Accounting Officer in February 2018. Prior to joining the Company, heJuly 2019. Mr. Roemer previously served as the Director of Infrastructure and Support Services at Transocean Offshore Deepwater Drilling, Inc. Mr. Dyson holds a Bachelor of Business Administration degree in Finance from Texas A&M University.
Mr. Leitner joined the Company as Vice President Marketing inand Controller from February 2017 to July 2019 and Controller from March 2010 to February 2017. Prior to joining Coterra in 2010, Mr. Roemer was a Senior Manager in the Company,energy practice of PricewaterhouseCoopers LLP. Mr. Leitner held various positionsRoemer is a Certified Public Accountant in the state of Texas.
Mr. Smith was appointed Vice President and Chief Technology Officer following the Merger with Shell Energy North America (US) L.P.,Cimarex in October 2021. Mr. Smith began his career with 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, and Senior Originator, from July 1996 through July 2017. Mr. Leitner holds a BachelorChief Engineer for Cimarex.
PART II
ITEM 5. MARKET FOR REGISTRANT'SREGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
Our $0.10 par value common stock is listed and principally traded on the New York Stock ExchangeNYSE under the ticker symbol "COG." The following table presents the high and low closing sales prices per share of“CTRA.” Cash dividends were paid to our common stock during certain periods, as reportedstockholders in each quarter of 2023. Future dividend payments will depend on the consolidated transaction reporting system. Cash dividends paid per shareCompany’s level 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 |
|
earnings, financial requirements and other factors considered relevant by our Board of Directors.As of February 1, 2018,6, 2024, there were 365858 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
OurIn February 2023, our Board of Directors hasterminated the previously authorized share repurchase plan and approved a new share repurchase program under which we maythat authorizes us to purchase sharesup to $2.0 billion of our common stock in the open market or in negotiated transactions. There is no expiration date associated withDuring the authorization. Thequarter ended December 31, 2023, we purchased 1 million shares includedof common stock for $29 million, bringing our total repurchases in the table below were repurchased on the open market and were held as treasury2023 to 17 million shares of common stock asat a total cost of $418 million. As of December 31, 2017.2023, we were authorized to repurchase up to approximately an additional $1.6 billion of our outstanding common stock.
The following table sets forth information regarding repurchases of our common stock during the quarter ended December 31, 2023. | | | | | | | | | | | | | | | | | | | | | | | | | | |
Period (1) | | Total Number of Shares Purchased (In thousands) | | Average Price Paid per Share | | Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs (In thousands) | | Maximum Approximate Dollar Value of Shares that May Yet Be Purchased Under the Plans or Programs (In millions) |
October 2023 | | 430 | | | $ | 26.90 | | | 430 | | | $ | 1,603 | |
November 2023 | | 307 | | | $ | 27.47 | | | 307 | | | $ | 1,595 | |
December 2023(2) | | 333 | | | $ | 26.14 | | | 333 | | | $ | 1,586 | |
Total | | 1,070 | | | | | 1,070 | | | |
_______________________________________________________________________________ |
| | | | | | | | | | | | | |
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,(1)All purchases during the covered periods were made under the new share repurchase program, which was approved by our Board of Directors in February 2023 and which authorized an increasethe repurchase of 25.0 million sharesup to $2.0 billion of our common stock. The new share repurchase program. After this authorization, the total numberprogram does not have an expiration date.
(2)In December 2023, we purchased 332,634 shares of shares available for repurchase is 30.1 million shares.
PERFORMANCE GRAPH
The following graph compares our common stock performance ("COG") withdelivered to us by employees to satisfy withholding taxes on the performancevesting 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 commonrestricted stock and in each index was $100 on December 31, 2012 and that all dividends were reinvested.awards.
|
| | | | | | | | | | | | | | | | | | | | | | | |
| 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'SMANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following discussion isand analysis are based on management’s perspective and are 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 toreferenced when reviewing this material. This discussion and analysis also include 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, including those described under “Forward-Looking Statements” in Part I of this report and “Risk Factors” in Part I, Item 1A of this report, which could cause actual results to differ materially from those included in this report.
OVERVIEW
Financial and Operating Overview
Financial and operating results for the year ended December 31, 20172023 compared to the year ended December 31, 20162022 are as follows:
•Net income decreased $2.4 billion from $4.1 billion, or $5.09 per share, in 2022 to $1.6 billion, or $2.14 per share, in 2023.
•Net cash provided by operating activities decreased $1.8 billion, from $5.5 billion, in 2022 to $3.7 billion in 2023.
•Equivalent production increased 58.2 Bcfe,12.2 MMBoe from 231.3 MMBoe, or 9%, from 627.1 Bcfe, or 1,713.4 Mmcfe633.8 MBoe per day, in 20162022 to 685.3 Bcfe,243.5 MMBoe, or 1,877.5 Mmcfe667.1 MBoe per day, in 2017.2023.
◦Natural gas production increased 55.228.4 Bcf from 1,024.3 Bcf, or 9%, from 600.42,806 MMcf per day, in 2022 to 1,052.7 Bcf, or 2,884 MMcf per day, in 2016 to 655.6 Bcf in 2017, as a result of drilling and completion activities in Pennsylvania.2023.
Crude oil/condensate/NGL◦Oil production increased 0.5 Mmbbls,3.2 MMBbl from 31.9 MMBbl, or 11%,87 MBbl per day, in 2022 to 35.1 MMBbl, or 96 MBbl per day, in 2023.
◦NGL volumes increased 4.2 MMBbl from 4.5 Mmbbls28.7 MMBbl, or 79 MBbl per day, in 20162022 to 5.0 Mmbbls32.9 MMBbl, or 90 MBbl per day, in 2017, as a result of an increase in drilling activities in south Texas, partially offset by a natural decline in production.2023.
•Average realized naturalprices:
◦Natural gas price for 2017 was $2.31$2.44 per Mcf 36% higherin 2023, 50 percent lower than the $1.70$4.91 per Mcf price realized in 2016.2022.
Average realized crude oil price for 2017◦Oil was $48.16$76.07 per Bbl 29% higherin 2023, 10 percent lower than the $37.30$84.33 per Bbl price realized in 2016.2022.
Drilled 91 gross wells (82.5 net) with a success rate of 98.9%◦NGL price for 2023 was $19.56 per Bbl, 42 percent lower than the $33.58 per Bbl price realized in 2017 compared to 40 gross wells (38.0 net) with a success rate of 100.0% in 2016.2022.
Completed 105 gross wells (94.2 net) in 2017 compared to 76 gross wells (76.0 net) in 2016.
•Total capital expenditures for drilling, completion and other fixed assets were $757.2 million$2.1 billion in 20172023 compared to $372.5 million$1.7 billion in 2016.2022. The increase was driven by higher planned completion activity levels across our operations and higher costs.
Average rig count during 2017 was approximately 2.0 rigs•Increased our quarterly base dividend from $0.15 per share for regular quarterly dividends in the Marcellus Shale, approximately 1.0 rig2022 to $0.20 per share 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 1.1 rigs and approximately 0.3 rigs in the Eagle Ford Shale during 2016.
In September 2017, we received proceeds of $32.7 million primarily related to the divestiture of certain oil 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 million2023 as a result of the remeasurementpart of our net deferred income tax liabilities based on the new lower corporate income tax rate associated with the enactment of the Tax Act.returns-focused strategy.
During 2017, we repurchased 5.0 million shares of•Increased our common stock for a total cost of $123.7 million.
In May 2017, the Board of Directors approved an increase in the quarterly base dividend on our common stock from $0.02$0.20 per share to $0.05 per share.
In January 2018, the Board of Directors approved an increase in the quarterly dividend on our common stock from $0.05$0.21 per share to $0.06 per share.in February 2024.
In February 2018, the Board of Directors authorized an increase of 25.0•Implemented our new $2.0 billion share repurchase program and repurchased 17 million shares tofor $418 million during the year ended December 31, 2023. Under our previous share repurchase program.program, we repurchased 48 million shares for $1.25 billion during the year ended December 31, 2022.
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 find, develop and 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 geopolitical, economic and other factors. In addition,
Oil prices have recovered in recent years from previous pandemic related market weakness, particularly on the demand side. Global conflict and supply chain disruptions drove high oil prices in 2022, which then moderated throughout 2023. OPEC+ reacted with supply reductions, helping to stabilize oil price levels during 2023. Oil and gas companies in the U.S. have largely refrained from expanding their existing production, which has contributed to steadier oil prices in 2023 as compared to recent years and to improved oil futures prices in early 2024.
Natural gas prices trended down year-over-year but strengthened in fourth quarter due to increased power demand. However, natural gas futures prices have declined in the first part of 2024 as the domestic market appears oversupplied.
Although the current outlook on oil and natural gas prices is generally favorable and our realizedoperations 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. Oil and natural gas prices
have fallen significantly since their peak in 2022, and we expect commodity price volatility to continue driven by further geopolitical disruptions, including conflicts in the Middle East and actions of OPEC+, and swift near and medium term fluctuations in supply and demand. Although we are further impacted by our hedging activities. As a result, we cannot accuratelyunable to 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 expectat current oil, natural gas and crudeNGL price levels, we do not believe that an impairment of our oil and gas properties is reasonably likely to occur in the near future. However, in the event that commodity prices to remain volatile. significantly decline or costs increase significantly from current levels, our management would evaluate the recoverability of the carrying value of our oil and gas properties.
In addition, the issue of, and increasing political and social attention on, climate change has resulted in both existing and pending national, regional and local legislation and regulatory measures, such as mandates for renewable energy and emissions reductions targeted at limiting or reducing emissions of GHGs. Changes in these laws or regulations may result in delays or restrictions in permitting and the development of projects, may result in increased costs and may impair our ability to production volumesmove forward with our construction, completions, drilling, water management, waste handling, storage, transport and commodity prices, finding and developing sufficient amountsremediation activities, any of natural gas and crude oil reserves at economical costs are critical towhich could have an adverse effect on our long-term success. financial results.
For information about the impact of realized commodity prices on our natural gas and crude oil and condensate revenues, refer to "Results“Results of Operations"Operations” below. See "Risk Factors—Natural gas
FINANCIAL CONDITION
Liquidity 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.Capital Resources
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 duestrive to maintain an adequate liquidity level to address commodity price volatility. Refervolatility and risk. Our liquidity requirements consist primarily of our planned capital expenditures, payment of contractual obligations (including debt maturities and interest payments), working capital requirements, dividend payments and share repurchases. Although we have no obligation to “Impactdo so, we may also from time-to-time refinance or retire our outstanding debt through privately negotiated transactions, open market repurchases, redemptions, exchanges, tender offers or otherwise.
Our primary sources of Derivative Instrumentsliquidity are cash on Operating Revenues” belowhand, net cash provided by operating activities and Note 6 of the Notes to the Consolidated Financial Statements for more information.
Commodity prices have remained volatile but have improved during 2017 compared to the fourth quarter of 2016. In the event that commodity prices significantly decline, management would test the recoverability of the carrying value of its oil and gas properties and, if necessary, record an impairment charge.
We believe that weavailable borrowing capacity under our revolving credit agreement. Our liquidity requirements 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 programgenerally funded with the expectation of funding our capital expenditurescash flows provided by operating activities, together with cash on hand, operating cash flows,hand. However, from time to time, our investments may be funded by bank borrowings (including draws under our revolving credit agreement), sales of non-strategic assets, and if required,private or public financing based on our monitoring of capital markets and our balance sheet. Our debt is currently rated as investment grade by the three leading rating agencies, and 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. 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 debt levels and leverage ratios, the size and mix of our production and proved reserves, and our cost structure. 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. A change in our debt rating could impact our interest rate on any borrowings under our revolving credit facility.
Continuingagreement and our ability to optimize our drilling, completioneconomically access debt markets in the future and operational efficiencies, resulting in lower operating costs per unit of production.
Continuingcould trigger the requirement to manage our balance sheet,post credit support under various agreements, which we believe provides sufficient availabilitycould reduce the borrowing capacity under our revolving credit facility and existing cash balances to meet our capital requirements 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. See below for additional discussion and analysis of 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.agreement. We believe that, with the existingoperating cash flow, cash on hand internally generated cash flow and availability under our revolving credit facility,agreement, we have the capacityability to finance our spending plans.
At December 31, 2017, we were in compliance with all restrictive financial covenants for bothplans over the revolving credit facilitynext twelve months and, senior notes. As of December 31, 2017, based on our asset coverage and leverage ratios, there were no interest rate adjustments requiredcurrent expectations, for our senior notes. See Note 5 of the Notes to the Consolidated Financial Statements for further details regarding our debt.
Cash Flows
Our cash flows from operating activities, investing activities and financing activities are as follows:
|
| | | | | | | | | | | |
| 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 our production volumes and operating expenses. Prices for natural gas and crude oil have historically been volatile, primarily as a result of supply and demand for natural gas and crude oil, pipeline infrastructure constraints, basis differentials, inventory storage levels and seasonal influences. In addition, fluctuations in cash flow may result in an increase or decrease in our capital expenditures. See "Results of Operations" for a review of the impact of prices and volumes on revenues.longer term.
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,agreement, 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, 20172023 and 2016,2022, we had a working capital surplus of $134.9$355 million and $458.1$1.0 billion, respectively. The decrease in our working capital surplus is primarily due to the reclassification during 2023 of $575 million respectively.of long-term debt scheduled to mature in September 2024 to current liabilities. We believe we have adequate liquidity and availability under our revolving credit facility availableagreement as outlined above to meet our working capital requirements over the next twelve12 months.
As of December 31, 2023, we had no borrowings outstanding under our revolving credit agreement, our unused commitments were $1.5 billion, and we had unrestricted cash on hand of $956 million.
Cash Flows
Our cash flows from operating activities, investing activities and financing activities are as follows: | | | | | | | | | | | | | | | | | |
| Year Ended December 31, |
(In millions) | 2023 | | 2022 | | 2021 |
Cash flows provided by operating activities | $ | 3,658 | |
| $ | 5,456 | |
| $ | 1,667 | |
Cash flows (used in) provided by investing activities | (2,059) | |
| (1,674) | |
| 313 | |
Cash flows used in financing activities | (1,317) | |
| (4,145) | |
| (1,086) | |
| | | | | |
Operating Activities. Operating cash flow fluctuations are substantially driven by changes in commodity prices, production volumes and operating expenses. Commodity prices have historically been volatile, primarily as a result of supply and demand for oil and natural gas, pipeline infrastructure constraints, basis differentials, inventory storage levels, seasonal influences and geopolitical, economic and other factors. In addition, fluctuations in cash flow may result in an increase or decrease in our capital expenditures.
Net cash provided by operating activities in 2017 increased2023 decreased by $500.7 million when$1.8 billion compared to 2016.2022. This increasedecrease was primarily due to higher operating revenues,lower net income as a result of lower natural gas, oil and NGL revenue due to lower commodity prices, partially offset by higher production. This decrease was partially offset by lower operating expenses (excluding non-cash expenses)costs, higher cash received on derivative settlements and unfavorablea larger contribution from changes in working capital and other assets and liabilities. The increase in operating revenues was primarily due
Refer to 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“Results of 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 decreased by 21% and 18%, respectively, for 2016 compared to 2015. Equivalent production increased by 4% for 2016 over 2015 as a result 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$385 million from 20162022 to 20172023. The increase was primarily due to an increase$389 million of $389.4 million inhigher capital expenditures and $28.6 million higherdue to our increased capital contributions associated with our equity method investments, partially offset by $65.0 million higher proceeds from the sale of assets.budget for 2023 compared to 2022 .
Financing Activities.Cash flows used in investing activities decreased by $640.1 million from 2015 to 2016 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$2.8 billion from 20162022 to 20172023. The decrease was primarily due to $995.3$1.1 billion of lower dividend payments and $845 million of lower net proceeds from the issuance of common stock in 2016, $123.7repurchases during 2023, and $874 million of repurchases of our common stock in 2017 and $42.7 million of higher dividend payments related to an increase in the dividend rate in 2017 and the issuance of common stock in 2016. These decreases were partially offset by $497.0 million of lower net repayments of debt duein 2022.
2022 and 2021 Compared. For information on the comparison of operating, investing, and financing cash flows for the year ended December 31, 2022 compared to the repaymentyear ended December 31, 2021, refer to Financial Condition (Cash Flows) included in the Coterra Energy Inc. Annual Report on Form 10-K for the year ended December 31, 2022, which information in incorporated by reference herein.
Revolving Credit Agreement
We had $1.5 billion of the outstanding balance onborrowing capacity under our revolving credit facilityagreement at December 31, 2023. The revolving credit agreement is scheduled to mature in March 2028 and certaincan be extended for additional one-year periods on up to two occasions upon the agreement of our senior notes withlenders holding at least 50 percent of the proceeds fromcommitments under the issuance of common stock in 2016.
Cash flows provided by financing activities increased by $230.5 million from 2015 to 2016 due to $995.3 million of net proceeds related to the issuance of common stockcredit agreement and lower capitalized debt issuance costs of $4.6 million related to the amendment ofus. Borrowings under our revolving credit facilityagreement bear interest at a rate per annum equal to, at our option, (i) either a term secured overnight financing rate (“SOFR”) plus a 0.10 percent credit spread adjustment for all tenors or (ii) a base rate, in each case plus an interest rate margin which ranges from 0 to 75 basis points for base rate loans and senior notes in December 2015. These increases were partially offset by $770.0 million100 to 175 basis points for term SOFR loans based on our credit rating. Our revolving credit agreement includes certain customary covenants, including the maintenance of higher net repaymentsa maximum leverage ratio of debt dueno more than 3.0 to the repayment1.0 as of the last day of any fiscal quarter. At such time as we have no other debt in a principal amount in excess of $75 million outstanding balancethat has a financial maintenance covenant based on a substantially similar leverage ratio, in lieu of such maximum leverage ratio covenant, the revolving credit agreement will instead require us to maintain a ratio of total debt to total capitalization of no more than 65 percent. At December 31, 2023, we were in compliance with all financial covenants for our revolving credit facilityagreement. Refer to Note 4 of the Notes to the Consolidated Financial Statements, “Long-Term Debt and Credit Agreements,” for further details regarding the interest rate on future borrowings under the revolving credit agreement and our leverage ratio.
Certain Restrictive Covenants
Our ability to incur debt, incur liens, enter into mergers, sell assets, enter into transactions with affiliates, and engage in certain other activities are subject to certain restrictive covenants in our various debt instruments. In addition, the senior note agreement governing various series of our senior notes that were issued in a private placement (the “private placement senior notes”) requires us to maintain a minimum annual coverage ratio of consolidated cash flow to interest expense for the trailing
four quarters of not less than 2.8 to 1.0 and requires us to maintain, as of the last day of any fiscal quarter, a maximum ratio of total debt to consolidated EBITDAX for the trailing four quarters of not more than 3.0 to 1.0. At December 31, 2023, we were in compliance with all financial covenants in our private placement senior notes. Refer to Note 4 of the proceeds fromNotes to the issuance of common stockConsolidated Financial Statements, “Long-Term Debt and $3.1 million of higher dividend payments.Credit Agreements,” for further details regarding the restrictive covenants contained in our various debt instruments.
Capitalization
Information about our capitalization is as follows: | | | | | | | | | | | |
| December 31, |
(Dollars in millions) | 2023 | | 2022 |
Total debt | $ | 2,161 | | $ | 2,181 |
Stockholders' equity | 13,039 | | 12,659 |
Total capitalization | $ | 15,200 | | $ | 14,840 |
Debt to total capitalization | 14% | | 15% |
Cash and cash equivalents | $ | 956 | | $ | 673 |
|
| | | | | | | |
| 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 |
|
Share repurchases. In February 2023, our Board of Directors approved a new share repurchase program which authorizes the purchase of up to $2.0 billion of our common stock in the open market or in negotiated transactions. | |
(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 2017,2023, we repurchased 5.0and retired 17 million shares of our common stock for $123.7 million.$418 million under our authorized share repurchase program. During 20172022, the Company repurchased 48 million shares of common stock for $1.25 billion under the February 2022 share repurchase program. During the years ended December 31, 2023 and 2016, we paid dividends2022, 332,634 and 320,236 shares of $78.8 million ($0.17 per share)common stock, respectively, were recorded as treasury stock and $36.2 million ($0.08 per share) onretired related to common shares that were retained from vested restricted stock awards for withholding of taxes.
In December 2022, our Board of Directors authorized the retirement of our common stock respectively. held in treasury as of December 31, 2022 and provided that prospectively, share repurchases and shares withheld for the vesting of stock awards will be retired in the period in which they are repurchased or withheld. Accordingly, as of December 31, 2023 and 2022, there were no common shares held in Treasury Stock on the Consolidated Balance Sheet.
Dividends. In May 2017, theFebruary 2023, our Board of Directors approved an increase in the base quarterly dividend from $0.15 per share to $0.20 per share.
The following table presents our dividends paid on our common stock from $0.02 per share to $0.05 per share.for the year ended December 31, 2023 and 2022.
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Rate per share | | |
| | Base | | Variable | | Total | | Total Dividends Paid (In millions) |
2023 | | $ | 0.80 | | | $ | 0.37 | | | $ | 1.17 | | | $ | 895 | |
2022 | | $ | 0.60 | | | $ | 1.89 | | | $ | 2.49 | | | $ | 1,991 | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
In January 2018, theFebruary 2024, our Board of Directors approved an increase in theour base quarterly dividend on our common stock from $0.05$0.20 per share to $0.06$0.21 per share beginning in the first quarter of 2024, and approved a quarterly base dividend of $0.21 per share.
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.agreement. 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 thousands) | 2017 | | 2016 | | 2015 |
Capital expenditures | |
| | |
| | |
|
Drilling and facilities | $ | 637,207 |
| | $ | 359,479 |
| | $ | 729,994 |
|
Leasehold acquisitions | 102,265 |
| | 2,703 |
| | 20,097 |
|
Property acquisitions | — |
| | — |
| | 16,312 |
|
Pipeline and gathering | 716 |
| | 1,909 |
| | 2,373 |
|
Other | 17,034 |
| | 8,386 |
| | 4,739 |
|
| 757,222 |
| | 372,477 |
| | 773,515 |
|
Exploration expenditures(1) | 21,526 |
| | 27,662 |
| | 27,460 |
|
Total | $ | 778,748 |
| | $ | 400,139 |
| | $ | 800,975 |
|
| | | | | | | | | | | | | | | | | |
| Year Ended December 31, |
(In millions) | 2023 | | 2022 | | 2021 |
Acquisitions(1) : | | | | | |
Proved | $ | — | | | $ | — | | | $ | 7,472 | |
Unproved | — | | | — | | | 5,381 | |
Total | $ | — | | | $ | — | | | $ | 12,853 | |
| | | | | |
Capital expenditures | | | | | |
Drilling and completion | $ | 1,979 | | | $ | 1,617 | | | $ | 688 | |
| | | | | |
Pipeline and gathering | 91 | | | 56 | | | 9 | |
Other | 34 | | | 54 | | | 23 | |
Capital expenditures for drilling, completion and other fixed asset additions | 2,104 | | | 1,727 | | | 720 | |
Capital expenditures for leasehold and property acquisitions | 10 | | | 10 | | | 5 | |
Exploration expenditures(2) | 20 | | | 29 | | | 18 | |
Total | $ | 2,134 | | | $ | 1,766 | | | $ | 743 | |
(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)Exploration expenditures include$3.8 million, $10.1 million and $3.3 million of(2)There were no exploratory dry hole expenditurescosts in 2017, 20162023, 2022 and 2015, respectively.2021.
In 2017,2023, we drilled 91264 gross wells (82.5(169.4 net) and completed 105288 gross wells (94.2(183.3 net), of which 5098 gross wells (44.3(62.7 net) were drilled but uncompleted in prior years. In 2018, we plan
Our 2024 capital program is expected to allocate the majoritybe approximately $1.75 billion to $1.95 billion. We expect to turn-in-line 132 to 158 total net wells in 2024 across our three core operating areas. Approximately 60 percent of our drilling and completion capital towill be invested in the Permian Basin, 23 percent in the Marcellus Shale where we expect to drill 85 gross wells (85.0 net) and complete 95 gross wells (95.0 net)17 percent in the Anadarko Basin (at the mid-point). Our 2018 drilling program includes approximately $890.0 millionThe decrease in totalour year-over-year capital expenditures.expenditures is primarily driven by lower planned spending in the Marcellus Shale, partially offset by modest increases in the Permian Basin and Anadarko Basin. 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 forth2023, our material contractual obligations include debt and related interest expense, gathering, processing and transportation agreements, lease obligations, operational agreements, drilling and completion obligations, derivative obligations and asset retirement obligations. Other joint owners in the following table:
|
| | | | | | | | | | | | | | | | | | | |
|
|
| 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 |
|
| |
(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 Notesproperties operated by us could incur a portion of these costs. We expect that our sources of capital will be adequate to fund these obligations. Refer to the Consolidated Financial Statements. |
| |
(3) | For further information on our equity investment contribution commitments, see Note 4 of the Notes to the Consolidated Financial Statements. |
Amounts related 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 of the Notes to the Consolidated Financial Statements included in Item 8 of this Annual Report for further details.
We enter into arrangements that can give rise to material off-balance sheet obligations. As of December 31, 2023, the material off-balance sheet arrangements we had entered into included certain firm gathering, processing and transportation 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
RESULTS OF OPERATIONS
2023 and 2022 Compared
Operating Revenues
| | | | | | | | | | | | | | | | | | | | | | | |
| Year Ended December 31, | | Variance |
(In millions) | 2023 | | 2022 | | Amount | | Percent |
Natural gas | $ | 2,292 | | | $ | 5,469 | | | $ | (3,177) | | | (58) | % |
Oil | 2,667 | | | 3,016 | | | (349) | | | (12) | % |
NGL | 644 | | | 964 | | | (320) | | | (33) | % |
Gain (loss) on derivative instruments | 230 | | | (463) | | | 693 | | | (150) | % |
Other | 81 | | | 65 | | | 16 | | | 25 | % |
| $ | 5,914 | | | $ | 9,051 | | | $ | (3,137) | | | (35) | % |
Production Revenues
Our production revenues are derived from sales of our oil, natural gas and NGL production. Increases or decreases in our revenues, profitability and future production growth are highly dependent on the commodity prices we receive, which we expect to fluctuate due to supply and demand factors, and the availability of transportation, seasonality and geopolitical, economic and other factors.
Natural Gas Revenues
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Year Ended December 31, | | Variance | Increase (Decrease) (In millions) |
| 2023 | | 2022 | | Amount | | Percent |
Volume variance (Bcf) | 1,052.7 | | | 1,024.3 | | | 28.4 | | | 3 | % | | $ | 152 | |
Price variance ($/Mcf) | $ | 2.18 | | | $ | 5.34 | | | $ | (3.16) | | | (59) | % | | (3,329) | |
Total | | | | | | | | | $ | (3,177) | |
Natural gas revenues decreased $3.2 billion primarily due to significantly lower natural gas prices, partially offset by higher production. The increase in production was related to higher production in the Marcellus Shale, Permian Basin and Anadarko Basin.
Oil Revenues | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Year Ended December 31, | | Variance | Increase (Decrease) (In millions) |
| 2023 | | 2022 | | Amount | | Percent |
Volume variance (MMBbl) | 35.1 | | 31.9 | | 3.2 | | 10% | | $ | 302 | |
Price variance ($/Bbl) | $ | 75.97 | | | $ | 94.47 | | | $ | (18.50) | | | (20)% | | (651) | |
Total | | | | | | | | | $ | (349) | |
Oil revenues decreased $349 million primarily due to lower oil prices, offset by higher production mainly in the Permian Basin.
NGL Revenues
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Year Ended December 31, | | Variance | Increase (Decrease) (In millions) |
| 2023 | | 2022 | | Amount | | Percent |
Volume variance (MMBbl) | 32.9 | | 28.7 | | 4.2 | | | 15 | % | | $ | 141 | |
Price variance ($/Bbl) | $ | 19.56 | | | $ | 33.58 | | | $ | (14.02) | | | (42) | % | | (461) | |
Total | | | | | | | | | $ | (320) | |
NGL revenues decreased $320 million primarily due significantly lower NGL prices, partially offset by higher NGL volumes, particularly in the Permian Basin.
Gain (Loss) on Derivative Instruments
Net gains and losses on our derivative instruments are a function of fluctuations in the underlying commodity index prices as compared to the contracted prices and the monthly cash settlements (if any) of the derivative instruments. We have elected not to designate our derivatives as hedging instruments for accounting purposes and, therefore, we do not apply hedge accounting treatment to our derivative instruments. Consequently, changes in the fair value of our derivative instruments and cash settlements are included as a component of operating revenues as either a net gain or loss on derivative instruments. Cash settlements of our contracts are included in cash flows from operating activities in our statement of cash flows.
The following table presents the components of “Gain (loss) on derivative instruments” for the years indicated:
| | | | | | | | | | | |
| Year Ended December 31, |
(In millions) | 2023 | | 2022 |
Cash received (paid) on settlement of derivative instruments | | | |
Gas contracts | $ | 280 | | | $ | (438) | |
Oil contracts | 4 | | | (324) | |
Non-cash gain (loss) on derivative instruments | | | |
Gas contracts | (72) | | | 149 | |
Oil contracts | 18 | | | 150 | |
| $ | 230 | | | $ | (463) | |
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 volume and commodity mix, some are a function of the number of wells we own and operate, some depend on the prices charged by service companies, and some fluctuate based on a combination of the foregoing. Our costs for services, labor and supplies have remained high due to on-going demand for those items, and to a lesser extent rising inflation and supply chain disruptions, all of which affected the cost of our operations throughout 2022. During 2023, these costs have begun to stabilize.
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) | 2023 | | 2022 | | Amount | | Percent | | 2023 | | 2022 |
Operating Expenses | | | | | | | | | | | |
Direct operations | $ | 562 | | | $ | 460 | | | $ | 102 | | | 22 | % | | $ | 2.31 | | | $ | 1.99 | |
Gathering, processing and transportation | 975 | | | 955 | | | 20 | | | 2 | % | | 4.00 | | | 4.13 | |
Taxes other than income | 283 | | | 366 | | | (83) | | | (23) | % | | 1.16 | | | 1.58 | |
Exploration | 20 | | | 29 | | | (9) | | | (31) | % | | 0.08 | | | 0.13 | |
Depreciation, depletion and amortization | 1,641 | | | 1,635 | | | 6 | | | — | % | | 6.74 | | | 7.07 | |
| | | | | | | | | | | |
| | | | | | | | | | | |
General and administrative | 291 | | | 396 | | | (105) | | | (27) | % | | 1.20 | | | 1.70 | |
| $ | 3,772 | | | $ | 3,841 | | | $ | (69) | | | (2) | % | | | | |
Direct Operations
Direct operations generally consist of costs for labor, equipment, maintenance, saltwater disposal, compression, power, treating and miscellaneous other costs (collectively, “lease operating expense”). Direct operations also include well workover activity necessary to maintain production from existing wells.
Direct operations consisted of lease operating expense and workover expense as follows:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Year Ended December 31, | | | | Per Boe |
(In millions, except per Boe) | 2023 | | 2022 | | Variance | | 2023 | | 2022 |
Direct Operations | | | | | | | | | |
Lease operating expense | $ | 472 | | | $ | 370 | | | $ | 102 | | | $ | 1.94 | | | $ | 1.60 | |
Workover expense | 90 | | | 90 | | | — | | | 0.37 | | | 0.39 | |
| $ | 562 | | | $ | 460 | | | $ | 102 | | | $ | 2.31 | | | $ | 1.99 | |
Lease operating expense increased primarily due to higher production levels. Additionally, lease operating expense on a per Boe basis generally increased due to increasing costs of equipment and field services, which began to stabilize in late 2023, and higher contract labor and employee-related costs.
Gathering, Processing and Transportation
Gathering, processing and transportation costs principally consist of expenditures to treat and transport production downstream from the wellhead, including gathering, fuel, and compression and processing costs, the last of which are incurred to extract NGLs from the raw natural gas stream. 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.
Gathering, processing and transportation increased $20 million primarily due to higher production levels, partially offset by lower costs in the Permian Basin and Anadarko Basin due to lower gathering and transportation rates which were driven by lower commodity prices during 2023 compared to the same period in 2022.
Taxes Other Than Income
Taxes other than income consist of production (or severance) taxes, drilling impact fees, ad valorem taxes and other taxes. State and local taxing authorities assess these taxes, with production taxes being based on the volume or value of production, drilling impact fees being based on drilling activities and prevailing natural gas prices and ad valorem taxes being based on the value of properties.
The following table presents taxes other than income for the years indicated: | | | | | | | | | | | | | | | | | |
| Year Ended December 31, | | |
(In millions) | 2023 | | 2022 | | Variance |
Taxes Other than Income | | | | | |
Production | $ | 205 | | $ | 282 | | | $ | (77) | |
Drilling impact fees | 23 | | | 31 | | | (8) | |
Ad valorem | 53 | | | 53 | | | — | |
Other | 2 | | | — | | | 2 | |
| $ | 283 | | | $ | 366 | | | $ | (83) | |
Production taxes as a percentage of revenue (Permian and Anadarko Basins) | 5.6 | % | | 5.5 | % | | |
Taxes other than income decreased $83 million. Production taxes represented the majority of our taxes other than income, which decreased primarily due to lower oil, natural gas and NGL revenues. Drilling impact fees decreased primarily due to the timing of wells drilled in the Marcellus Shale and lower natural gas prices, which drive the fees assessed on our drilling activities.
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) | 2023 | | 2022 | | Variance | | 2023 | | 2022 |
DD&A Expense | | | | | | | | | |
Depletion | $ | 1,509 | | | $ | 1,474 | | | $ | 35 | | | $ | 6.20 | | | $ | 6.37 | |
Depreciation | 74 | | 91 | | (17) | | | 0.30 | | 0.40 |
Amortization of unproved properties | 48 | | 61 | | (13) | | | 0.20 | | 0.26 |
Accretion of ARO | 10 | | 9 | | | 1 | | | 0.04 | | 0.04 |
| $ | 1,641 | | | $ | 1,635 | | | $ | 6 | | | $ | 6.74 | | | $ | 7.07 | |
Depletion of our producing properties is computed on a field basis using the unit-of-production method under the successful efforts method of accounting. The economic life of each producing property depends upon the estimated proved reserves for that property, which in turn depend upon the assumed realized sales price for future production. Therefore, fluctuations in oil and gas prices will impact the level of proved developed and proved reserves used in the calculation. Higher prices generally have the effect of increasing reserves, which reduces depletion expense. Conversely, lower prices generally have the effect of decreasing reserves, which increases depletion expense. The cost of replacing production also impacts our depletion expense. In addition, changes in estimates of reserve quantities, estimates of operating and future development costs, reclassifications of properties from unproved to proved and impairments of oil and gas properties will also impact depletion expense. Our depletion expense increased $35 million primarily due to increased production partially offset by a lower depletion rate of $6.20 per Boe for 2023 compared to $6.37 per Boe for 2022.
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. Depreciation expense decreased $17 million primarily due to a non-recurring impairment charge related to certain right-of-use assets (building leases) recorded in late 2022.
Unproved oil and gas properties are amortized based on our drilling experience and our expectation of converting our unproved leaseholds to proved properties. The rate of amortization depends on the timing and success of our exploration and development program. If development of unproved properties is deemed unsuccessful and the properties are abandoned or surrendered, the capitalized costs are expensed in the period the determination is made. Amortization of unproved properties decreased $13 million primarily due to a non-recurring charge related to the release of certain leaseholds that occurred in 2022.
General and Administrative
G&A expense consists primarily of salaries and related benefits, stock-based compensation, office rent, legal and consulting fees, systems costs and other administrative costs incurred.
The table below reflects our G&A expense for the periods identified:
| | | | | | | | | | | | | | | | | |
| Year Ended December 31, | | |
(In millions) | 2023 | | 2022 | | Variance |
G&A Expense | | | | | |
General and administrative expense | $ | 220 | | | $ | 241 | | | $ | (21) | |
Stock-based compensation expense | 59 | | | 86 | | | (27) | |
Merger-related expense | 12 | | | 69 | | | (57) | |
| $ | 291 | | | $ | 396 | | | $ | (105) | |
G&A expense, excluding stock-based compensation and merger-related expenses, decreased $21 million primarily due to lower legal costs incurred in 2023 compared to 2022, and lower compensation and benefit costs due to the reduction in transition personnel throughout 2023.
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 decreased $27 million primarily due to higher stock-based compensation costs during 2022 related to the accelerated vesting of employee performance shares and vesting of certain other awards, and a gain related to our deferred compensation plan associated with the liquidation of the Coterra stock in the plan in 2023. These decreases were partially offset by higher stock-based compensation costs related to new shares granted during 2023.
Merger-related expenses decreased $57 million primarily due to lower employee-related severance and termination benefits associated with the termination of transition employees. We accrued for these costs over the transition period during 2022 and early 2023, with substantially all of our expected severance costs being fully accrued over that time period. Merger-related expenses also decreased due to $7 million of transaction-related costs associated with the merger that were incurred in 2022.
Gain (Loss) on Sale of Assets
The increase in gain (loss) on sale of assets is due to the sale of certain non-core oil and gas properties and other equipment.
Interest Expense
The table below reflects our interest expense, net for the periods indicated:
| | | | | | | | | | | | | | | | | |
| Year Ended December 31, | | |
(In millions) | 2023 | | 2022 | | Variance |
Interest Expense | | | | | |
Interest expense | $ | 82 | | | $ | 110 | | | $ | (28) | |
Debt premium amortization | (21) | | | (37) | | | 16 | |
Debt issuance cost amortization | 3 | | | 4 | | | (1) | |
Other | 9 | | | 3 | | | 6 | |
| $ | 73 | | | $ | 80 | | | $ | (7) | |
Interest expense decreased $28 million primarily due to the repayment of our 6.51% and 5.58% weighted-average private placement senior notes in August 2022 and the redemption of $750 million of the 4.375% senior notes in late 2022.
Debt premium amortization decreased $16 million primarily due to the redemption of $750 million of the 4.375% senior notes in late 2022.
Interest Income
Interest income increased $37 million primarily due to higher interest rates on higher cash balances.
Gain on Debt Extinguishment
In 2022, we paid down $874 million of our debt for $880 million and recognized a net gain on debt extinguishment of $28 million primarily due to the write off of related debt premiums and debt issuance costs.
Income Tax Expense | | | | | | | | | | | | | | | | | |
| Year Ended December 31, | | |
(In millions) | 2023 | | 2022 | | Variance |
Income Tax Expense | | | | | |
Current tax expense | $ | 429 | | | $ | 869 | | | $ | (440) | |
Deferred tax expense | 74 | | | 235 | | | (161) | |
| $ | 503 | | | $ | 1,104 | | | $ | (601) | |
Combined federal and state effective income tax rate | 24 | % | | 21 | % | | |
Income tax expense decreased $601 million primarily due to lower pre-tax income in 2023 compared to 2022, partially offset by a higher effective tax rate. The effective tax rate was higher for 2023 compared to 2022 due to differences in the non-recurring discrete items recorded during 2023 versus 2022.
2022 and 2021 Compared
For information on the comparison of the results of operations for the year ended December 31, 2022 compared to the year ended December 31, 2021, refer to Management’s Discussion and Analysis of Financial Condition and Results of Operations included in the Coterra Energy Inc. Annual Report on Form 10-K for the year ended December 31, 2022, which information is incorporated by reference herein.
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 isfinancial statements in accordanceconformity with accounting principles generally accepted in the United States,GAAP requires 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.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.
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 are 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, reservereserves estimates are generally different from the quantities ultimately recovered. We cannot predict the amounts or timing
The reserves estimates of such future revisions.
Our reservesour oil and gas properties have been prepared by our petroleumreservoir engineering staff and auditedcertain of our reserves are subject to an evaluation performed by Miller and Lents,an independent third-party petroleum engineers, who in their opinion determinedconsulting firm. In 2023, greater than 90 percent of the estimates presentedtotal future net revenue discounted at 10 percent attributable to be reasonable in the aggregate.our proved reserves were subject to this evaluation. For more information regarding reservereserves estimation, including historical reservereserves 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 and proved developed 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$0.31 per McfeBoe and an increase of $0.04$0.35 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 reservereserves estimates may impact the outcome of our impairment test under applicable accounting standards. Due to the inherent imprecision of the reservereserves 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'sasset’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, then 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. Given the significant volatility in oil, natural gas and NGLs prices, estimates of such future prices are inherently imprecise. 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 undevelopedunproved 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 rangeranges from three to five years. The commodity price environment may impact the capital available for exploration projects as well as development drilling.our drilling activities. We have considered these impacts when determining the amortization rate of our undeveloped acreage, especially in exploratory areas.unproved acreage. If the average unproved property life decreases or increases by one year, the amortization would increase by approximately $11.7$12 million or decrease by approximately $9.6$8 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 areis 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 by using a market credit spread provided by one ofdefault swap spreads for various similarly rated companies in our banks.sector.
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, including changes in both NYMEXindex prices (such as 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'smanagement’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/orand 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,law, 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 remeasuredre-measured 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 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 of Significant Accounting Policies," for a discussion of recently adopted accounting pronouncements.
Recently Issued Accounting Pronouncements
Refer to Note 1 of the Notes to the Consolidated Financial Statements, "Summary“Summary of Significant Accounting Policies,"” for a discussion of new accounting pronouncements that affect us.
OTHER ISSUES AND CONTINGENCIES
Regulations.Our operations are subject to various types of regulation by federal, state and local authorities. See the "Other Business Matters" section of Item 1 for a discussion of these regulations.
Restrictive Covenants. Our ability to incur debt and to make certain types of investments is subject to certain restrictive covenants in our various debt instruments. Among other requirements, our senior note agreements and our revolving credit agreement specify a minimum annual coverage ratio of consolidated cash flow to interest expense for the trailing four quarters of 2.8 to 1.0 and a minimum asset coverage ratio of the present value of proved reserves before income taxes plus adjusted cash 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. Our revolving credit agreement also requires us to maintain a minimum current ratio of 1.0 to 1.0. At December 31, 2017, 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.Our business involves a variety of operating risks. See "Risk Factors—We face a variety of hazards and risks that could cause substantial financial losses" in Item 1A. In accordance with customary
industry practice, we maintain insurance against some, but not all, of these risks and losses. The occurrence of any of these events not fully covered by insurance could have a material adverse effect on our financial position, results of operations and cash flows. The costs of these insurance policies are somewhat dependent on our historical claims experience, the areas in which we operate and market conditions.
Commodity Pricing and Risk Management Activities. Our revenues, operating results, financial condition and ability to borrow funds or obtain additional capital depend substantially on prevailing prices for natural gas and crude oil. Further declines in natural gas and crude oil prices may have a material adverse effect on our financial condition, liquidity, ability to obtain financing and operating results. Lower natural gas and crude oil prices also may reduce the amount of natural gas and crude oil that we can produce economically. Historically, natural gas and crude oil 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 responsive 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, management may mitigate this price risk on a portion of our anticipated production with the use of commodity derivatives. Most recently, we have used commodity derivatives such as collar, swap and basis swap arrangements to reduce the impact of sustained lower pricing on our revenue. Under both 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
2017 and 2016 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.
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) | 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 gas revenues of $483.5 million was due to 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 associated 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 a result of our drilling and completion activities in Pennsylvania, partially offset by the divestiture of certain oil and gas properties in east Texas in early 2016.
Crude Oil and Condensate Revenues
The decrease in crude oil and condensate revenues of $97.1 million was 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.
Brokered natural gas decreased $1.8 million from 2015 to 2016. See the preceding table titled “Brokered Natural Gas” for further analysis.
Taxes other than income decreased $13.6 million due to $7.2 million lower production taxes resulting from lower crude oil prices and production in south Texas and the receipt of a production tax refund of $1.9 million in February 2016. Additionally, 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 values 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. The lower DD&A rate was primarily due to lower cost reserve additions and the impairment charge recorded in the fourth quarter of 2015 associated with higher DD&A rate fields. In addition, amortization of unproved properties decreased $16.4 million in 2016 as a result of lower lease acquisition costs and lower amortization rates.
Impairment of oil and gas properties and other assets was $435.6 million in 2016 due to the impairment of oil and gas properties and related pipeline assets in West Virginia and Virginia. In 2015, we recognized an impairment of oil and gas properties of $114.9 million related to 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.
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 million primarily due to the sale of certain of our oil and gas properties in east and south Texas. During 2015, we recognized a net aggregate gain of $3.9 million primarily due to the sale of certain unproved oil and gas properties in east Texas.
Loss on Debt Extinguishment
A $4.7 million 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.
Interest Expense, net
Interest expense decreased $8.6 million due to a $5.5 million decrease resulting from 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 million resulting from the repurchase of a portion of our 6.51% weighted-average senior notes in May 2016 and the repayment of our 7.33% weighted-average senior notes at maturity. These decreases were offset by a $0.6 million increase in commitment fees as a result of an increase in the unused portion of the commitments under our revolving credit facility.
Income Tax Benefit
Income tax benefit increased $169.1 million due to a higher pretax loss, partially offset by a lower effective tax rate. The effective tax rates for 2016 and 2015 were 36.8% and 39.2%, respectively. The decrease in the effective tax rate is primarily due to the impact of non-recurring discrete items recorded during 2016 compared to 2015.
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 for financial instruments to which we were party to as of December 31, 2023 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,” in Item 8 for a more detailed discussion of our derivative and risk management activities.derivatives.
Periodically, we enter into financial commodity derivatives, including collar, swap, and basis swap agreements, to protect against exposure to commodity price declines related to our natural gas and crude oil production. Our credit agreement restricts our ability to enter into 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.declines. 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, 2017,2023, we had the following outstanding financial commodity derivatives:
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| | 2024 | | 2025 | | Fair Value Asset (Liability) (In millions) | | | | |
Natural Gas | | First Quarter | | Second Quarter | | Third Quarter | | Fourth Quarter | | First Quarter | | Second Quarter | | Third Quarter | | Fourth Quarter | | | | | |
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NYMEX collars | | | | | | | | | | | | | | | | | | $ | 67 | | | | | |
Volume (MMBtu) | | 35,490,000 | | | 44,590,000 | | | 45,080,000 | | | 16,690,000 | | | 9,000,000 | | | 9,100,000 | | | 9,200,000 | | | 9,200,000 | | | | | | | |
Weighted average floor ($/MMBtu) | | $ | 3.00 | | | $ | 2.70 | | | $ | 2.75 | | | $ | 2.75 | | | $ | 3.25 | | | $ | 3.25 | | | $ | 3.25 | | | $ | 3.25 | | | | | | | |
Weighted average ceiling ($/MMBtu) | | $ | 5.38 | | | $ | 3.87 | | | $ | 3.94 | | | $ | 4.23 | | | $ | 4.79 | | | $ | 4.79 | | | $ | 4.79 | | | $ | 4.79 | | | | | | | |
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| | | | | | | 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 | ) |
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| | 2024 | | Fair Value Asset (Liability) (In millions) |
Oil | | First Quarter | | Second Quarter | | Third Quarter | | Fourth Quarter | |
WTI oil collars | | | | | | | | | | $ | 26 | |
Volume (MBbl) | | 2,730 | | | 2,730 | | | 1,840 | | | 1,840 | | | |
Weighted average floor ($/Bbl) | | $ | 68.00 | | | $ | 68.00 | | | $ | 65.00 | | | $ | 65.00 | | | |
Weighted average ceiling ($/Bbl) | | $ | 91.37 | | | $ | 91.37 | | | $ | 90.01 | | | $ | 90.01 | | | |
| | | | | | | | | | |
WTI Midland oil basis swaps | | | | | | | | | | (1) | |
Volume (MBbl) | | 2,730 | | | 2,730 | | | 1,840 | | | 1,840 | | | |
Weighted average differential ($/Bbl) | | $ | 1.16 | | | $ | 1.16 | | | $ | 1.17 | | | $ | 1.17 | | | |
| | | | | | | | | | $ | 25 | |
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In January 2018, we2024, the Company entered into the following financial commodity derivative contracts:
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| | | | | | | | 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 | | | | $(0.68) |
In the above tables, natural gas prices are stated per Mcf and crude oil prices are stated per barrel.
As of December 31, 2017, we had the following outstanding physical commodity derivatives:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | |
| | 2024 | | | | |
Oil | | First Quarter | | Second Quarter | | Third Quarter | | Fourth Quarter | | | | |
WTI oil collars | | | | | | | | | | | | |
Volume (MBbl) | | 300 | | | 455 | | | 920 | | | 920 | | | | | |
Weighted average floor ($/Bbl) | | $ | 65.00 | | | $ | 65.00 | | | $ | 65.00 | | | $ | 65.00 | | | | | |
Weighted average ceiling ($/Bbl) | | $ | 85.02 | | | $ | 85.02 | | | $ | 81.49 | | | $ | 81.49 | | | | | |
| | | | | | | | | | | | |
WTI Midland oil basis swaps | | | | | | | | | | | | |
Volume (MBbl) | | 300 | | | 455 | | | 920 | | | 920 | | | | | |
Weighted average differential ($/Bbl) | | $ | 1.10 | | | $ | 1.10 | | | $ | 1.10 | | | $ | 1.10 | | | | | |
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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, 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.
The amounts set forth in the tables above represent our total unrealized derivative position at December 31, 2017 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 in which we have derivative transactions, while our non-performance risk is evaluated using a market credit spread provided by one of our banks.
A significant portion of our expected natural gas and crude oil production for 20182024 and beyond is currently unhedged and directly exposed to the volatility in natural gas and crude oil marketcommodity prices, whether favorable or unfavorable.
During 2017,2023, natural gas collars with floor prices of $3.09ranging from $3.00 to $7.50 per McfMMBtu and ceiling prices ranging from $3.42$4.55 to $3.45$13.08 per McfMMBtu covered 35.5174.9 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%,17 percent of natural gas production at a weighted-average price of $3.23$4.23 per Mcf. CrudeMMBtu.
During 2023, oil collars with floor prices of $50.00ranging from $65.00 to $80.00 per Bbl and ceiling prices ranging from $56.25$89.00 to $56.50$118.30 per Bbl covered 1.8 Mmbbl,7.1 MMBbls, or 41%,20 percent, of crude oil production at a weighted-average price of $51.78$68.75 per Bbl. Oil basis swaps covered 7.6 MMBbls, or 22 percent, of oil production at a weighted-average price of $0.92 per Bbl.
We are exposed to market risk on financial commodity derivative instruments to the extent of changes in market prices of natural gas and crude oil.the related commodity. 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, 2023, we had total debt of $2.2 billion (with a principal amount of $2.1 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 agreement provides for variable interest rate borrowings; however, we did not have any borrowings outstanding as of December 31, 2023 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 fair value hierarchy.
We use available market data and valuation methodologies to estimate the fair value of debt. The fair value of debtour senior notes is the estimated amount we would have to pay a third party to assume the debt, including abased on quoted market prices. The fair value of our private placement senior notes is based on third-party quotes which are derived from credit spreadspreads 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 notesrate 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 all senior notes and the revolving credit facility is based on interest rates currently available to us.
other unobservable inputs.
The carrying amount and estimated fair value of debt is as follows:
| | | | | | | | | | | | | | | | | | | | | | | |
| December 31, 2023 | | December 31, 2022 |
(In millions) | Carrying Amount | | Estimated Fair Value | | Carrying Amount | | Estimated Fair Value |
Total debt | $ | 2,161 | | | $ | 2,015 | | | $ | 2,181 | | | $ | 1,955 | |
Current maturities | (575) | | | (565) | | | — | | | — | |
Long-term debt, excluding current maturities | $ | 1,586 | | | $ | 1,450 | | | $ | 2,181 | | | $ | 1,955 | |
|
| | | | | | | | | | | | | | | |
| 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 |
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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
Report of Independent Registered Public Accounting Firm
To the Board 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, 20172023 and 2016,2022, 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, 2017,2023, including the related notes (collectively referred to as the “consolidated financial statements”). We also have audited the Company's internal control over financial reporting as of December 31, 2017,2023, 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, 20172023 and 2016,2022, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 20172023 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, 2017,2023, 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.
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 matter communicated below is a matter arising from the current period audit of the consolidated financial statements that was communicated or required to be communicated to the audit committee and that (i) relates 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 matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.
The Impact of Proved Developed Oil and Natural 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 $12,835 million as of December 31, 2023 and depreciation, depletion and amortization (DD&A) expense of $1,635 million for the year ended December 31, 2023 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 reserves 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 developed oil and natural gas reserves on proved oil and gas properties, net is a critical audit matter are (i) the significant judgment by management, including the use of specialists, when developing the estimates of proved developed oil and natural gas reserves, which in turn led to (ii) a high degree of auditor judgment, subjectivity, and effort in performing procedures and evaluating audit evidence related to the data, methods, and assumptions used by management and its specialists in developing the estimates of proved developed 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 developed oil and natural gas reserves. The work of management’s specialists was used in performing the procedures to evaluate the reasonableness of the proved developed 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 evaluating the methods and assumptions used by the specialists, testing the completeness and accuracy of data used by the specialists, and evaluating the specialists’ findings.
/s/ PricewaterhouseCoopers LLP
Houston, Texas
February 27, 201823, 2024
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 per share amounts) | | (In millions, except per share amounts) | | 2023 | | 2022 |
ASSETS | | ASSETS | | |
Current assets | | Current assets | | |
Cash and cash equivalents | |
Restricted cash | |
Accounts receivable, net | |
Income taxes receivable | |
Inventories | |
Derivative instruments | |
| Other current assets | |
Other current assets | |
Other current assets | |
Total current assets | |
Properties and equipment, net (Successful efforts method) | |
| | | | 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 |
|
| | $ | 4,727,344 |
| | $ | 5,122,569 |
|
LIABILITIES AND STOCKHOLDERS' EQUITY | | |
| | |
|
| Other assets | |
| Other assets | |
| | $ | |
LIABILITIES, REDEEMABLE PREFERRED STOCK AND STOCKHOLDERS' EQUITY | | LIABILITIES, REDEEMABLE PREFERRED STOCK AND STOCKHOLDERS' EQUITY | | |
Current liabilities | | |
| | |
| Current liabilities | | |
Accounts payable | | $ | 238,045 |
| | $ | 168,411 |
|
Current portion of long-term debt | | 304,000 |
| | — |
|
Accrued liabilities | | 27,441 |
| | 21,492 |
|
| Interest payable | | 27,575 |
| | 27,650 |
|
Derivative instruments | | 30,637 |
| | 40,259 |
|
Current liabilities held for sale | | 2,352 |
| | — |
|
Interest payable | |
Interest payable | |
| Total current liabilities | | 630,050 |
| | 257,812 |
|
Long-term debt, net | | 1,217,891 |
| | 1,520,530 |
|
| Total current liabilities | |
| Total current liabilities | |
Long-term debt | |
Deferred income taxes | | 227,030 |
| | 579,447 |
|
Asset retirement obligations | | 43,601 |
| | 131,733 |
|
Liabilities held for sale | | 15,748 |
| | — |
|
Postretirement benefits | | 29,396 |
| | 36,259 |
|
| Other liabilities | |
| Other liabilities | |
| Other liabilities | | 39,723 |
| | 29,121 |
|
Total liabilities | | 2,203,439 |
| | 2,554,902 |
|
| | | | |
Commitments and contingencies | |
|
| |
|
|
| Commitments and contingencies (Note 8) | |
| Commitments and contingencies (Note 8) | |
| Commitments and contingencies (Note 8) | | | | |
|
| | | |
Cimarex redeemable preferred stock | |
Cimarex redeemable preferred stock | |
Cimarex redeemable preferred stock | |
| | | | |
Stockholders' equity | | |
| | |
|
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 shares of $0.10 par value in 2023 and 2022 | | Authorized — 1,800 shares of $0.10 par value in 2023 and 2022 | | | | |
Issued — 751 shares and 768 shares in 2023 and 2022, respectively | |
Additional paid-in capital | | 1,742,419 |
| | 1,727,310 |
|
Retained earnings | | 1,162,430 |
| | 1,098,703 |
|
Accumulated other comprehensive income | | 2,077 |
| | 985 |
|
Less treasury stock, at cost: | | | | |
14,935,926 shares and 9,892,680 shares in 2017 and 2016, respectively | | (430,576 | ) | | (306,835 | ) |
| Total stockholders' equity | | 2,523,905 |
| | 2,567,667 |
|
| | $ | 4,727,344 |
| | $ | 5,122,569 |
|
Total stockholders' equity | |
| Total stockholders' equity | |
| | $ | |
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 millions, except per share amounts) | | (In millions, except per share amounts) | 2023 | | 2022 | | 2021 |
OPERATING REVENUES | | OPERATING REVENUES | | | |
Natural gas | |
Oil | |
NGL | |
Gain (loss) on derivative instruments | |
Other | |
| 5,914 | |
OPERATING EXPENSES | | OPERATING EXPENSES | | | |
Direct operations | |
Gathering, processing and transportation | |
Taxes other than income | |
Exploration | |
Depreciation, depletion and amortization | |
| General and administrative | |
| General and administrative | |
| General and administrative | |
| 3,772 | |
| Gain (loss) on sale of assets | |
Gain (loss) on sale of assets | |
Gain (loss) on sale of assets | |
INCOME FROM OPERATIONS | |
Interest expense | |
Interest income | |
Gain on debt extinguishment | |
Other income | |
Income before income taxes | |
Income tax expense | |
NET INCOME | |
| | | 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 per share | |
| | | | | |
Earnings (loss) per share | |
| | |
| | |
|
| Earnings per share | |
| Earnings per share | | | | |
Basic | $ | 0.22 |
| | $ | (0.91 | ) | | $ | (0.28 | ) |
Diluted | $ | 0.22 |
| | $ | (0.91 | ) | | $ | (0.28 | ) |
| | | | | |
Weighted-average common shares outstanding | |
| | |
| | |
|
Weighted-average common shares outstanding | |
Weighted-average common shares outstanding | | | | |
Basic | 463,735 |
| | 456,847 |
| | 413,696 |
| Basic | 756 | | | 796 | | 796 | | 503 |
Diluted | 465,551 |
| | 456,847 |
| | 413,696 |
| Diluted | 760 | | | 799 | | 799 | | 504 |
| | | | | |
Dividends per common share | $ | 0.17 |
| | $ | 0.08 |
| | $ | 0.08 |
|
|
The accompanying notes are an integral part of these consolidated financial statements.
The accompanying notes are an integral part of these consolidated financial statements.