SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
_______________________________
FORM 10-K
(Mark One)
☒ | ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the fiscal year ended December 31, 2023 |
or
☐ | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the transition period from to |
Commission File Number: 001-32886
_______________________________
CONTINENTAL RESOURCES, INC.
(Exact name of registrant as specified in its charter)
_______________________________
Oklahoma | 73-0767549 | |||||||||||||||||||
(State or other |
| (I.R.S. Employer Identification No.) | ||||||||||||||||||
20 N. Broadway, | Oklahoma City, | Oklahoma | 73102 | |||||||||||||||||
(Address of principal executive offices) | (Zip Code) | |||||||||||||||||||
Registrant’s telephone number, including area code: (405) (405) 234-9000
Securities registered pursuant to Section 12(b) of the Act:
| None
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_______________________________
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes x¨ No ¨No
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ¨Yesx No x¨
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x¨ No ¨No
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes x No ¨
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.
Large accelerated filer |
| Accelerated filer | ☐ | |||||||||||||||||
Non-accelerated filer |
| Smaller reporting company | ☐ | |||||||||||||||||
Emerging growth company | ☐ | |||||||||||||||||||
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ¨
Indicate by check mark whether the registrant has filed a report on and attestation to its management's assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report. ☒
If securities are registered pursuant to Section 12(b) of the Act, indicate by check mark whether the financial statements of the registrant included in the filing reflect the correction of an error to previously issued financial statements. ☐
Indicate by check mark whether any of those error corrections are restatements that required a recovery analysis of incentive-based compensation received by any of the registrant’s executive officers during the relevant recovery period pursuant to §240.10D-1(b). ☐
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes ☐ No x
Effective November 22, 2022, Continental Resources, Inc. became a privately held corporation and has no publicly available common shares outstanding at the time of the voting and non-voting common equity held by non-affiliates of the registrant as of June 30, 2021 was approximately $2.5 billion, based upon the closing price of $38.03 per share as reported by the New York Stock Exchange on such date.
shares of our $0.01 par value common stock were outstanding on January 31, 2022.
None.
Table of Contents
PART I | ||||||||
Item 1. | ||||||||
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Item 1A. |
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Item 1B. |
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Item 1C. | 22 | |||||||
Item 2. |
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Item 3. |
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Item 4. |
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PART II | ||||||||
Item 5. |
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Item 6. |
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Item 7. |
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Item 7A. |
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Item 8. |
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Item 9. |
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Item 9A. |
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Item 9B. |
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Item 9C. |
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PART III | ||||||||
Item 10. |
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Item 11. |
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Item 12. |
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Item 13. |
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Item 14. |
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PART IV | ||||||||
Item 15. |
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Glossary of Crude Oil and Natural Gas Terms
The terms defined in this section may be used throughout this report:
“basin” A large natural depression on the earth’s surface in which sediments generally brought by water accumulate.
“Bbl” One stock tank barrel, of 42 U.S. gallons liquid volume, used herein in reference to crude oil, condensate or natural gas liquids.
“Bcf” One billion cubic feet of natural gas.
“Boe” Barrels of crude oil equivalent, with six thousand cubic feet of natural gas being equivalent to one barrel of crude oil based on the average equivalent energy content of the two commodities.
“Btu” British thermal unit, which represents the amount of energy needed to heat one pound of water by one degree Fahrenheit and can be used to describe the energy content of fuels.
“DD&A” Depreciation, depletion, amortization and accretion.
“developed acreage” The number of acres allocated or assignable to productive wells or wells capable of production.
“development well” A well drilled within the proved area of a crude oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive.
“dry hole” Exploratory or development well that does not produce crude oil and/or natural gas in economically producible quantities.
“exploratory well” A well drilled to find crude oil or natural gas in an unproved area, to find a new reservoir in an existing field previously found to be productive of crude oil or natural gas in another reservoir, or to extend a known reservoir beyond the proved area.
“field” An area consisting of a single reservoir or multiple reservoirs all grouped on, or related to, the same individual geological structural feature or stratigraphic condition. The field name refers to the surface area, although it may refer to both the surface and the underground productive formations.
“gross acres” or “gross wells” Refers to the total acres or wells in which a working interest is owned.
“MBbl” One thousand barrels of crude oil, condensate or natural gas liquids.
“MBoe” One thousand Boe.
“Mcf” One thousand cubic feet of natural gas.
“MMBo” One million barrels of crude oil.
“MMBoe” One million Boe.
“MMBtu” One million British thermal units.
“MMcf” One million cubic feet of natural gas.
“net acres” or “net wells” Refers to the sum of the fractional working interests owned in gross acres or gross wells.
“NGL” or "Net crude oilNGLs" Refers to natural gas liquids, which are hydrocarbon products that are separated during natural gas processing and include ethane, propane, isobutane, normal butane, and natural gas sales"gasoline. Represents total crude oil and natural gas sales less total transportation expenses. Net crude oil and natural gas sales presented herein is a non-GAAP measure. See Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Non-GAAP Financial Measures for a discussion and calculation of this measure.
“NYMEX” The New York Mercantile Exchange.
“proved reserves” The quantities of crude oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs and under existing economic conditions, operating methods, and government regulations prior to the time at which contracts providing the right to operate expire, unless evidence indicates renewal is reasonably certain.
“proved developed reserves” Reserves expected to be recovered through existing wells with existing equipment and operating methods.
i
“proved undeveloped reserves” or “PUD” Proved reserves expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for completion.
“residue gas” Refers to gas that has been processed to remove natural gas liquids.
“royalty interest” Refers to the ownership of a percentage of the resources or revenues produced from a crude oil or natural gas property. A royalty interest owner does not bear exploration, development, or operating expenses associated with drilling and producing a crude oil or natural gas property.
“undeveloped acreage” Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of crude oil and/or natural gas.
“working interest” The right granted to the lessee of a property to explore for and to produce and own crude oil, natural gas, or other minerals. The working interest owners bear the exploration, development, and operating costs on either a cash, penalty, or carried basis.
ii
Cautionary Statement for the Purpose of the “Safe Harbor” Provisions of the Private Securities Litigation Reform Act of 1995
This report and information incorporated by reference in this report include “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All statements other than statements of historical fact, including, but not limited to, forecasts or expectations regarding the Company’s business and statements or information concerning the Company’s future operations, performance, financial condition, production and reserves, schedules, plans, timing of development, rates of return, budgets, costs, business strategy, objectives, and cash flows, included in this report are forward-looking statements. The words “could,” “may,” “believe,” “anticipate,” “intend,” “estimate,” “expect,” “project,” “budget,” “target,” “plan,” “continue,” “potential,” “guidance,” “strategy” and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words.
Forward-looking statements may include, but are not limited to, statements about:
Forward-looking statements are based on the Company’s current expectations and assumptions about future events and currently available information as to the outcome and timing of future events. Although the Company believes these assumptions and expectations are reasonable, they are inherently subject to numerous business, economic, competitive, regulatory and other risks and uncertainties, most of which are difficult to predict and many of which are beyond the Company’s control. No assurance can be given that such expectations will be correct or achieved or that the assumptions are accurate or will not change over time. The risks and
iii
uncertainties that may affect the operations, performance and results of the business and forward-looking statements include, but are not limited to, those risk factors and other cautionary statements described under Part I, Item 1A. Risk Factors and elsewhere in this report registration statements we file from time to time with the Securities and Exchange Commission, and other disclosures or announcements we make from time to time.
Readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date on which such statement is made. Additionally, new factors emerge from time to time, and it is not possible for us to predict all such factors. Should one or more of the risks or uncertainties described in this report occur, or should underlying assumptions prove incorrect, the Company’sCompany's actual results and plans could differ materially from those
Except as expressly stated above or otherwise required by applicable law, the Company undertakes no obligation to publicly correct or update any forward-looking statement whether as a result of new information, future events or circumstances after the date of this report, or otherwise.
iv
Part I
You should read this entire report carefully, including the risks described under Part I, Item 1A. Risk Factors and our consolidated financial statements and the notes to those consolidated financial statements included elsewhere in this report. Unless the context otherwise requires, references in this report to “Continental Resources,” “Continental,” “we,” “us,” “our,” “ours” or “the Company” refer to Continental Resources, Inc. and its subsidiaries.
Item 1. Business
Nature of business
We are an independent crude oil and natural gas company formed in 1967 engaged in the exploration, development, management, and production of crude oil and natural gas and associated products with properties primarily located in four leading basins in the United States – the Bakken field of North SouthDakota and East regionsMontana, the Anadarko Basin of Oklahoma, the United States.Permian Basin of Texas, and the Powder River Basin of Wyoming. Additionally, we pursue the acquisition and management of perpetually owned minerals located in certain of our key operating areas.
We focus our activities in large crude oil and natural gas plays that provide us the opportunity to acquire undeveloped acreage positions and apply our geologic and operational expertise to drill and develop properties at attractive rates of return. We have been successful in targeting large repeatable resource plays where three dimensional seismic, horizontal drilling, geosteering technologies, advanced completion technologies, (e.g., fracture stimulation), pad/row development, and enhanced recovery technologies allow us to develop and produce crude oil and natural gas reserves from unconventional formations. As
Effective November 22, 2022, Continental Resources, Inc. became a result of these efforts, we have grown substantially throughprivately held corporation and has no publicly available common shares outstanding. We continue to furnish Quarterly Reports on Form 10-Q and Annual Reports on Form 10-K with the drill bit. We also grew in 2021 through the strategic acquisitions described below under Part I, Item 1. Business—Acquisition Activities. From January 1, 2019 through December 31, 2021, proved reserves added through extensions, discoveries and other additions totaled 828 MMBoe and proved reserves added through property acquisitions totaled 252 MMBoe.
| December 31, 2021 | Average daily production for fourth quarter 2021 (Boe per day) | |||||||||||||||||||||||||||||||||||||||||||
| Proved reserves (MBoe) | Percent of total | PV-10 (1) (In millions) | Net producing wells | Percent of total | ||||||||||||||||||||||||||||||||||||||||
| North Region: | ||||||||||||||||||||||||||||||||||||||||||||
| Bakken | 708,369 | 43.2 | % | $ | 9,659 | 1,997 | 175,585 | 51.6 | % | |||||||||||||||||||||||||||||||||||
| Powder River Basin | 31,901 | 1.9 | % | $ | 464 | 148 | 7,189 | 2.1 | % | |||||||||||||||||||||||||||||||||||
| Red River Units | 23,354 | 1.4 | % | $ | 396 | 251 | 6,212 | 1.8 | % | |||||||||||||||||||||||||||||||||||
| South Region: | ||||||||||||||||||||||||||||||||||||||||||||
| Oklahoma | 678,535 | 41.2 | % | $ | 7,027 | 825 | 146,131 | 43.0 | % | |||||||||||||||||||||||||||||||||||
| Permian Basin (2) | 203,103 | 12.3 | % | $ | 2,946 | 319 | 4,997 | 1.5 | % | |||||||||||||||||||||||||||||||||||
| Other | 48 | — | % | $ | 1 | 4 | 54 | — | % | |||||||||||||||||||||||||||||||||||
| Total | 1,645,310 | 100.0 | % | $ | 20,493 | 3,544 | 340,168 | 100.0 | % | |||||||||||||||||||||||||||||||||||
(2)The presentation of average daily 2021 fourth quarter production represents production during the period from the closing of our acquisition of Permian properties on December 21, 2021 through December 31, 2021 averaged over 92 days in the fourth quarter. At the time of closing, our Permian properties produced on average approximately 42,000 Boe per day based on two-stream reporting.
Our business strategies continue to be focused on generating significant shareholderincreasing enterprise value by finding and developing crude oil and natural gas reserves at low costs and attractive rates of return. For 2022,2024, our primary business strategies will include:
Proved Reserves
Proved reserves are those quantities of crude oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations prior to the time at which contracts providing the right to operate expire, unless evidence indicates renewal is reasonably certain. In connection with the estimation of proved reserves, the term “reasonable certainty” implies a high degree of confidence the quantities of crude oil and/or natural gas actually recovered will equal or exceed the estimate. To achieve reasonable certainty, our internal reserve engineers and Ryder Scott Company, L.P (“Ryder Scott”), our independent reserve engineers, employed technologies demonstrated to yield results with consistency and repeatability. The technologies and economic data used in the estimation of our proved reserves include, but are not limited to, well logs, geologic maps including isopach and structure maps, analogy and statistical analysis, and available downhole, production, seismic, and well test data.
The table below sets forth estimated proved crude oil and natural gas reserves information by reserve category as of December 31, 2021.2023. Proved reserves attributable to noncontrolling interests are not material relative to our consolidated reserves and are not separately presented herein. The standardized measure of our discounted future net cash flows totaled approximately $16.64 billion at December 31, 2021. Our reserve estimates as of December 31, 20212023 are based primarily on a reserve report prepared by Ryder Scott. In preparing its report, Ryder Scott evaluated properties representing approximately 98% of our PV-10 and 98%99% of our total proved reserves as of December 31, 2021.2023. Our internal technical staff evaluated the remaining properties. A copy of Ryder Scott’s summary report is included as an exhibit to this Annual Report on Form 10-K.
1
Our estimated proved reserves and related future net revenues Standardized Measure and PV-10 at December 31, 20212023 were determined using the 12-month unweighted arithmetic average of the first-day-of-the-month commodity prices for the period of January 20212023 through December 2021,2023, without giving effect to derivative transactions, and were held constant throughout the lives of the properties. These prices were $66.56$78.22 per Bbl for crude oil and $3.60$2.64 per MMBtu for natural gas ($62.1973.67 per Bbl for crude oil and $3.46$2.00 per Mcf for natural gas adjusted for location and quality differentials). These average prices are significantly higher than 2020 levels, which resulted in significant upward price-related revisions to proved reserves in 2021, as further discussed below.
The following table summarizes our estimated proved reserves by commodity and reserve classification as of December 31, 2021.
| Crude Oil (MBbls) | Natural Gas (MMcf) | Total (MBoe) | PV-10 (1) (in millions) | |||||||||||||||||||||||
| Proved developed producing | 415,861 | 2,853,980 | 891,524 | $ | 13,256.4 | |||||||||||||||||||||
| Proved developed non-producing | 8,292 | 47,167 | 16,154 | 230.5 | ||||||||||||||||||||||
| Proved undeveloped | 369,377 | 2,209,532 | 737,632 | 7,006.0 | ||||||||||||||||||||||
| Total proved reserves | 793,530 | 5,110,679 | 1,645,310 | $ | 20,492.9 | |||||||||||||||||||||
| Standardized Measure (1) | $ | 16,636.4 | ||||||||||||||||||||||||
for further discussion.
| Crude Oil |
|
| Natural Gas |
|
| Total |
|
| ||||
Proved developed producing |
|
| 394,532 |
|
|
| 3,186,722 |
|
|
| 925,653 |
|
|
Proved developed non-producing |
|
| 7,319 |
|
|
| 34,844 |
|
|
| 13,126 |
|
|
Proved undeveloped |
|
| 512,183 |
|
|
| 2,376,765 |
|
|
| 908,310 |
|
|
Total proved reserves |
|
| 914,034 |
|
|
| 5,598,331 |
|
|
| 1,847,089 |
|
|
The following table provides additional information regarding our estimated proved crude oil and natural gas reserves by region as of December 31, 2021.2023.
| Proved Developed | Proved Undeveloped | |||||||||||||||||||||||||||||||||||||
| Crude Oil (MBbls) | Natural Gas (MMcf) | Total (MBoe) | Crude Oil (MBbls) | Natural Gas (MMcf) | Total (MBoe) | |||||||||||||||||||||||||||||||||
| North Region: | ||||||||||||||||||||||||||||||||||||||
| Bakken | 222,986 | 856,607 | 365,754 | 241,364 | 607,509 | 342,615 | ||||||||||||||||||||||||||||||||
| Powder River Basin | 12,080 | 22,661 | 15,857 | 12,585 | 20,758 | 16,044 | ||||||||||||||||||||||||||||||||
| Red River Units | 23,354 | — | 23,354 | — | — | — | ||||||||||||||||||||||||||||||||
| South Region: | ||||||||||||||||||||||||||||||||||||||
| Oklahoma | 81,586 | 1,826,973 | 386,081 | 50,614 | 1,451,038 | 292,454 | ||||||||||||||||||||||||||||||||
| Permian Basin | 84,122 | 194,769 | 116,584 | 64,814 | 130,227 | 86,519 | ||||||||||||||||||||||||||||||||
| Other | 25 | 137 | 48 | — | — | — | ||||||||||||||||||||||||||||||||
| Total | 424,153 | 2,901,147 | 907,678 | 369,377 | 2,209,532 | 737,632 | ||||||||||||||||||||||||||||||||
| Proved Developed |
|
| Proved Undeveloped |
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| Crude Oil |
|
| Natural Gas |
|
| Total |
|
| Crude Oil |
|
| Natural Gas |
|
| Total |
| |||||||
Bakken |
|
| 187,125 |
|
|
| 916,570 |
|
|
| 339,887 |
|
|
| 201,766 |
|
|
| 630,987 |
|
|
| 306,931 |
|
Anadarko Basin |
|
| 80,047 |
|
|
| 1,933,019 |
|
|
| 402,216 |
|
|
| 77,239 |
|
|
| 1,042,211 |
|
|
| 250,941 |
|
Powder River Basin |
|
| 30,871 |
|
|
| 150,785 |
|
|
| 56,002 |
|
|
| 57,496 |
|
|
| 155,329 |
|
|
| 83,384 |
|
Permian Basin |
|
| 82,261 |
|
|
| 220,725 |
|
|
| 119,049 |
|
|
| 175,682 |
|
|
| 548,238 |
|
|
| 267,054 |
|
All other |
|
| 21,547 |
|
|
| 467 |
|
|
| 21,625 |
|
|
| — |
|
|
| — |
|
|
| — |
|
Total |
|
| 401,851 |
|
|
| 3,221,566 |
|
|
| 938,779 |
|
|
| 512,183 |
|
|
| 2,376,765 |
|
|
| 908,310 |
|
The following table provides information regarding changes in total estimated proved reserves for the periods presented.
| Year Ended December 31, | ||||||||||||||||||||
| MBoe | 2021 | 2020 | 2019 | |||||||||||||||||
| Proved reserves at beginning of year | 1,103,762 | 1,619,265 | 1,522,365 | |||||||||||||||||
| Revisions of previous estimates | 53,569 | (504,874) | (148,848) | |||||||||||||||||
| Extensions, discoveries and other additions | 371,105 | 91,387 | 365,034 | |||||||||||||||||
| Production | (120,321) | (109,833) | (124,244) | |||||||||||||||||
| Sales of minerals in place | (148) | — | (1,840) | |||||||||||||||||
| Purchases of minerals in place | 237,343 | 7,817 | 6,798 | |||||||||||||||||
| Proved reserves at end of year | 1,645,310 | 1,103,762 | 1,619,265 | |||||||||||||||||
| Year Ended December 31, |
| ||||||||||
MBoe |
| 2023 |
|
| 2022 |
|
| 2021 |
| |||
Proved reserves at beginning of year |
|
| 1,863,764 |
|
|
| 1,645,310 |
|
|
| 1,103,762 |
|
Revisions of previous estimates |
|
| (369,264 | ) |
|
| (133,061 | ) |
|
| 53,569 |
|
Extensions, discoveries and other additions |
|
| 438,367 |
|
|
| 395,490 |
|
|
| 371,105 |
|
Production |
|
| (160,660 | ) |
|
| (146,657 | ) |
|
| (120,321 | ) |
Sales of minerals in place |
|
| (15,594 | ) |
|
| (144 | ) |
|
| (148 | ) |
Purchases of minerals in place |
|
| 90,476 |
|
|
| 102,826 |
|
|
| 237,343 |
|
Proved reserves at end of year |
|
| 1,847,089 |
|
|
| 1,863,764 |
|
|
| 1,645,310 |
|
Revisions of previous estimates. Revisions for 20212023 are comprised of (i) upwarddownward price revisions of 9222 MMBo and 458344 Bcf (totaling 16879 MMBoe) due to the significant increasea decrease in average crude oil and natural gas prices in 20212023 compared to 2020 resulting from the lifting of COVID-19 restrictions, the resumption of normal economic activity, and the resulting improvement in supply and demand fundamentals,2022, (ii) the removal of 3114 MMBo and 155148 Bcf (totaling 5739 MMBoe) of PUD reserves no longer scheduled to be drilled within five years of initial booking due to continual refinement of our drilling and development programs and reallocation of capital to areas providing the best opportunities to improve efficiencies, recoveries, and rates of return, (iii) downward revisions of 1295 MMBo and 263446 Bcf (totaling 56170 MMBoe) from the removal of PUD reserves due to changes in anticipated well densities, economics, performance, and other factors, and (iv) downward revisions for oil reserves of 3557 MMBo and upward revisions for natural gas reserves of 195149 Bcf (netting to 2 MMBoe of downward revisions)(totaling 82 MMBoe) due to changes in ownership interests, operating costs, anticipated production, and other factors.
Extensions, discoveries and other additions. Extensions, discoveries and other additions for each of the three years reflected in the table above were due to successful drilling and completion activities and continual refinement of our drilling programs. ProvedFor 2023, proved reserve additions in the Bakken totaled 202 MMBoe, 41 MMBoe, and 160 MMBoe for 2021, 2020, and 2019, respectively, while reserve additions in Oklahoma totaled 169 MMBoe, 50 MMBoe, and 205 MMBoe for 2021, 2020, and 2019, respectively.438 MMBoe. See the subsequent section titled Summary of Crude Oil and Natural Gas Properties and Projects for a discussion of our 20212023 drilling activities.
Sales of minerals in place. We had no individually significant dispositions of proved reserves in the past three years.
Purchases of minerals in place. Purchases in 2023, 2022, and 2021 were primarily attributable to our acquisitions of properties as discussed in the Permian BasinPart II. Item 8. Notes to Consolidated Financial Statements—Note 2. Property Acquisitions and Powder River Basin described above. Proved reserves acquired in the Permian Basin totaled 149 MMBo and 326 Bcf (totaling 203 MMBoe) and proved reserves acquired in the Powder River Basin totaled 26 MMBo and 46 Bcf (totaling 34 MMBoe). We had no individually significant acquisitions of proved reserves in 2020 and 2019.Dispositions.
2
Proved Undeveloped Reserves
All of our PUD reserves at December 31, 20212023 are located in our most active development areas. The following table provides information regarding changes in our PUD reserves for the year ended December 31, 2021.2023. Our PUD reserves at December 31, 20212023 include 6849 MMBoe of reserves associated with wells where drilling has occurred but the wells have not been completed or are completed but not producing ("(“DUC wells"wells”). Our DUC wells are classified as PUD reserves when relatively major expenditures are required to complete and produce from the wells. Crude Oil
(MBbls)Natural Gas
(MMcf)Total
(MBoe)Proved undeveloped reserves at December 31, 2020 215,069 1,567,713 476,355 Revisions of previous estimates (45,340) (329,237) (100,214) Extensions, discoveries and other additions 157,384 1,183,484 354,631 Sales of minerals in place — — — Purchases of minerals in place 77,399 150,985 102,563 Conversion to proved developed reserves (35,135) (363,413) (95,703) Proved undeveloped reserves at December 31, 2021 369,377 2,209,532 737,632
| Crude Oil |
|
| Natural Gas |
|
| Total |
| ||||
Proved undeveloped reserves at December 31, 2022 |
|
| 435,240 |
|
|
| 2,358,578 |
|
|
| 828,336 |
|
Revisions of previous estimates |
|
| (147,483 | ) |
|
| (908,770 | ) |
|
| (298,945 | ) |
Extensions, discoveries and other additions |
|
| 230,136 |
|
|
| 979,737 |
|
|
| 393,426 |
|
Sales of minerals in place |
|
| (242 | ) |
|
| (673 | ) |
|
| (354 | ) |
Purchases of minerals in place |
|
| 52,043 |
|
|
| 192,274 |
|
|
| 84,088 |
|
Conversion to proved developed reserves |
|
| (57,511 | ) |
|
| (244,381 | ) |
|
| (98,241 | ) |
Proved undeveloped reserves at December 31, 2023 |
|
| 512,183 |
|
|
| 2,376,765 |
|
|
| 908,310 |
|
Revisions of previous estimates. As previously discussed, in 20212023 we removed 3114 MMBo and 155148 Bcf (totaling 5739 MMBoe) of PUD reserves no longer scheduled to be drilled within five years of initial booking due to continual refinement of our drilling and development programs and reallocation of capital to areas providing the best opportunities to improve efficiencies, recoveries, and rates of return. Of these removals, 25 MMBo and 53 Bcf (totaling 34 MMBoe) was related to Bakken properties and 6 MMBo and 102 Bcf (totaling 23 MMBoe) was related to Oklahoma properties. Additionally, changes in anticipated well densities, economics, performance, and other factors resulted in downward PUD reserve revisions of 1295 MMBo and 263446 Bcf (totaling 56170 MMBoe) in 2021.2023. The significant increasesdecreases in average crude oil and natural gas prices in 20212023 resulted in upwarddownward price revisions of 152 MMBo and 73135 Bcf (totaling 2725 MMBoe). Finally, changes in ownership interests, operating costs, anticipated production, and other factors resulted in downward revisions for oil PUD reserves of 1736 MMBo and net upward revisions for natural gas PUD reserves of 16180 Bcf (totaling a net downward revision of 1565 MMBoe) in 2021.2023.
Extensions, discoveries and other additions. Extensions, discoveries and other additions were due to successful drilling activities and continual refinement of our drilling and development programs. PUD reserve additions in the Bakken totaled 133230 MMBo and 359980 Bcf (totaling 193393 MMBoe) in 2021, while PUD reserve additions in Oklahoma totaled 24 MMBo and 824 Bcf (totaling 161 MMBoe).2023.
Sales of minerals in place. We had no individually significant dispositions of PUD reserves in 2021.2023.
Purchases of minerals in place. Purchases in 20212023 were primarily attributable to our acquisitions of properties as discussed in the Permian BasinPart II. Item 8. Notes to Consolidated Financial Statements—Note 2. Property Acquisitions and Powder River Basin described above. PUD reserves acquired in the Permian Basin totaled 65 MMBo and 130 Bcf (totaling 87 MMBoe) and PUD reserves acquired in the Powder River Basin totaled 12 MMBo and 21 Bcf (totaling 16 MMBoe).Dispositions.
Conversion to proved developed reserves. In 2021,2023, we developed approximately 24%20% of our PUD locations and 20%12% of our PUD reserves booked as of December 31, 20202022 through the drilling and completion of 269454 gross (137(213 net) development wells at an aggregate capital cost of approximately $508 million$1.2 billion incurred in 2021.2023.
Development plans. We have acquired substantial leasehold positions in our key operating areas. Our drilling programs to date in our historical operating areas have focused on proving our undeveloped leasehold acreage through strategic drilling, thereby increasing the amount of leasehold acreage in the secondary term of the lease with no further drilling obligations (i.e., categorized as held by production) and resulting in a reduced amount of leasehold acreage in the primary term of the lease. While we may opportunistically drill strategic exploratory wells, a substantial portion of our future capital expenditures will be focused on developing our PUD locations, including our drilled but not completed locations. Our inventory of DUC wells classified as PUDs total 259164 gross (83(65 net) operated and non-operated locations at December 31, 20212023 and represent 9%5% of our PUD reserves at that date. The costs to drill our uncompleted wells were incurred prior to December 31, 20212023 and only the remaining completion costs are included in future development plans.
Estimated future development costs relating to the development of PUD reserves at December 31, 20212023 are projected to be approximately $1.2 billion in 2022, $1.9 billion in 2023, $1.7$2.0 billion in 2024, $1.7$1.8 billion in 2025, and $1.2$2.6 billion in 2026.2026, $2.7 billion in 2027, and $2.3 billion in 2028. These capital expenditure projections have been established based on an expectation of drilling and completion costs, available cash flows, borrowing capacity, and the commodity price environment in effect at the time of preparing our reserve estimates and may be adjusted as market conditions evolve. Development of our existing PUD reserves at December 31, 20212023 is expected
3
Qualifications of Technical Persons and Internal Controls Over Reserves Estimation Process
Ryder Scott, our independent reserves evaluation consulting firm, estimated, in accordance with generally accepted petroleum engineering and evaluation principles and definitions and guidelines established by the SEC, 98% of our PV-10 and 98%99% of our total proved reserves as of December 31, 20212023 included in this Form 10-K. The Ryder Scott technical personnel responsible for preparing the reserve estimates presented herein meet 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. Refer to Exhibit 99 included with this Form 10-K for further discussion of the qualifications of Ryder Scott personnel.
We maintain an internal staff of petroleum engineers and geoscience professionals who work closely with our independent reserves engineers to ensure the integrity, accuracy and timeliness of data furnished to Ryder Scott in their reserves estimation process. Our technical team is in contact regularly with representatives of Ryder Scott to review properties and discuss methods and assumptions used in Ryder Scott’s preparation of the year-end reserves estimates. Proved reserves information is reviewed by our Audit Committee with representativescertain members of Ryder Scott and by our internal technical staffsenior management before the information is filed with the SEC on Form 10-K. Additionally, certain members of our senior management review and approve the Ryder Scott reserves report and on a semi-annual basis review any internal proved reserves estimates.
Our Vice President—Manager of Corporate Reserves is the technical person primarily responsible for overseeing the preparation of our reserve estimates. He has a Bachelor of Science degree in Petroleum Engineering, an MBA in Finance and 3739 years of industry experience with positions of increasing responsibility in operations, acquisitions, engineering and evaluations. He has worked in the area of reserves and reservoir engineering most of his career and is a member of the Society of Petroleum Engineers. The Vice President—Manager of Corporate Reserves reports directly to our Chief Financial Officer and Executive Vice ChairmanPresident of Strategic Growth Initiatives.Planning. The reserves estimates are reviewed and approved by certain members of the Company's executivesenior management.
The following table presents our total gross and net developed and undeveloped acres by region as of December 31, 2021:2023:
| Developed acres | Undeveloped acres | Total | ||||||||||||||||||||||||||||||||||||
| Gross | Net | Gross | Net | Gross | Net | |||||||||||||||||||||||||||||||||
| North Region: | ||||||||||||||||||||||||||||||||||||||
| Bakken | 1,125,023 | 702,709 | 116,922 | 69,175 | 1,241,945 | 771,884 | ||||||||||||||||||||||||||||||||
| Powder River Basin | 111,197 | 76,750 | 189,180 | 140,835 | 300,377 | 217,585 | ||||||||||||||||||||||||||||||||
| Red River Units | 154,643 | 139,363 | 19,891 | 10,186 | 174,534 | 149,549 | ||||||||||||||||||||||||||||||||
| Other | 80,287 | 54,113 | 29,040 | 25,654 | 109,327 | 79,767 | ||||||||||||||||||||||||||||||||
| South Region: | ||||||||||||||||||||||||||||||||||||||
| Oklahoma | 581,811 | 341,056 | 219,872 | 107,231 | 801,683 | 448,287 | ||||||||||||||||||||||||||||||||
| Permian Basin | 80,605 | 80,605 | 76,015 | 65,756 | 156,620 | 146,361 | ||||||||||||||||||||||||||||||||
| Other | 20,916 | 9,364 | 90,425 | 72,763 | 111,341 | 82,127 | ||||||||||||||||||||||||||||||||
| East Region | 734 | 661 | 52,929 | 46,815 | 53,663 | 47,476 | ||||||||||||||||||||||||||||||||
| Total | 2,155,216 | 1,404,621 | 794,274 | 538,415 | 2,949,490 | 1,943,036 | ||||||||||||||||||||||||||||||||
| Developed acres |
|
| Undeveloped acres |
|
| Total |
| ||||||||||||||||
| Gross |
|
| Net |
|
| Gross |
|
| Net |
|
| Gross |
|
| Net |
| |||||||
Bakken |
|
| 1,115,481 |
|
|
| 711,024 |
|
|
| 74,353 |
|
|
| 42,151 |
|
|
| 1,189,834 |
|
|
| 753,175 |
|
Anadarko Basin |
|
| 636,070 |
|
|
| 372,087 |
|
|
| 239,550 |
|
|
| 130,334 |
|
|
| 875,620 |
|
|
| 502,421 |
|
Powder River Basin |
|
| 247,057 |
|
|
| 181,250 |
|
|
| 279,382 |
|
|
| 194,793 |
|
|
| 526,439 |
|
|
| 376,043 |
|
Permian Basin |
|
| 118,803 |
|
|
| 105,930 |
|
|
| 108,950 |
|
|
| 87,345 |
|
|
| 227,753 |
|
|
| 193,275 |
|
All other |
|
| 186,906 |
|
|
| 152,037 |
|
|
| 234,150 |
|
|
| 147,973 |
|
|
| 421,056 |
|
|
| 300,010 |
|
Total |
|
| 2,304,317 |
|
|
| 1,522,328 |
|
|
| 936,385 |
|
|
| 602,596 |
|
|
| 3,240,702 |
|
|
| 2,124,924 |
|
The following table sets forth the number of gross and net undeveloped acres as of December 31, 20212023 scheduled to expire over the next three years by region unless production is established within the spacing units covering the acreage prior to the expiration dates or the leases are renewed.
| 2024 |
|
| 2025 |
|
| 2026 |
| ||||||||||||||||
| Gross |
|
| Net |
|
| Gross |
|
| Net |
|
| Gross |
|
| Net |
| |||||||
Bakken |
|
| 14,980 |
|
|
| 9,441 |
|
|
| 6,050 |
|
|
| 4,246 |
|
|
| 1,484 |
|
|
| 918 |
|
Anadarko Basin |
|
| 34,856 |
|
|
| 13,976 |
|
|
| 82,207 |
|
|
| 48,836 |
|
|
| 29,377 |
|
|
| 22,004 |
|
Powder River Basin |
|
| 8,715 |
|
|
| 4,050 |
|
|
| 2,707 |
|
|
| 2,378 |
|
|
| 10,258 |
|
|
| 7,392 |
|
Permian Basin |
|
| 41,758 |
|
|
| 33,594 |
|
|
| 24,713 |
|
|
| 18,181 |
|
|
| 11,486 |
|
|
| 11,159 |
|
All other |
|
| 31,803 |
|
|
| 14,260 |
|
|
| 16,843 |
|
|
| 11,392 |
|
|
| 23,285 |
|
|
| 15,844 |
|
Total |
|
| 132,112 |
|
|
| 75,321 |
|
|
| 132,520 |
|
|
| 85,033 |
|
|
| 75,890 |
|
|
| 57,317 |
|
| 2022 | 2023 | 2024 | ||||||||||||||||||||||||||||||||||||
| Gross | Net | Gross | Net | Gross | Net | |||||||||||||||||||||||||||||||||
| North Region: | ||||||||||||||||||||||||||||||||||||||
| Bakken | 47,272 | 29,243 | 9,779 | 7,639 | 10,467 | 6,986 | ||||||||||||||||||||||||||||||||
| Powder River Basin | 10,893 | 10,142 | 3,044 | 1,703 | 2,268 | 1,695 | ||||||||||||||||||||||||||||||||
| Other | — | — | 17,847 | 17,847 | — | — | ||||||||||||||||||||||||||||||||
| South Region: | ||||||||||||||||||||||||||||||||||||||
| Oklahoma | 54,083 | 29,789 | 35,837 | 16,704 | 26,109 | 13,426 | ||||||||||||||||||||||||||||||||
| Permian Basin | — | — | — | — | 26,347 | 16,285 | ||||||||||||||||||||||||||||||||
| Other | 14,660 | 11,031 | 13,436 | 13,086 | 37,399 | 9,985 | ||||||||||||||||||||||||||||||||
| East Region | 4,856 | 3,732 | 5,968 | 5,272 | 3,052 | 2,717 | ||||||||||||||||||||||||||||||||
| Total | 131,764 | 83,937 | 85,911 | 62,251 | 105,642 | 51,094 | ||||||||||||||||||||||||||||||||
4
Drilling Activity
During the three years ended December 31, 2021,2023, we participated in the drilling and completion of exploratory and development wells as set forth in the table below. 2021 2020 2019 Gross Net Gross Net Gross Net Exploratory wells: Crude oil 11 8.0 1 — 2 1.6 Natural gas 2 1.9 1 — 4 1.8 Dry holes — — 1 0.9 — — Total exploratory wells 13 9.9 3 0.9 6 3.4 Development wells: Crude oil 376 144.6 300 115.5 615 222.9 Natural gas 38 20.3 31 15.9 68 9.7 Dry holes — — — — — — Total development wells 414 164.9 331 131.4 683 232.6 Total wells 427 174.8 334 132.3 689 236.0
| 2023 |
|
| 2022 |
|
| 2021 |
| ||||||||||||||||
| Gross |
|
| Net |
|
| Gross |
|
| Net |
|
| Gross |
|
| Net |
| |||||||
Exploratory wells: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
Crude oil |
|
| 33 |
|
|
| 25.9 |
|
|
| 17 |
|
|
| 12.1 |
|
|
| 11 |
|
|
| 8.0 |
|
Natural gas |
|
| — |
|
|
| — |
|
|
| 2 |
|
|
| — |
|
|
| 2 |
|
|
| 1.9 |
|
Dry holes |
|
| — |
|
|
| — |
|
|
| 1 |
|
|
| 1 |
|
|
| — |
|
|
| — |
|
Total exploratory wells |
|
| 33 |
|
|
| 25.9 |
|
|
| 20 |
|
|
| 13.1 |
|
|
| 13 |
|
|
| 9.9 |
|
Development wells: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
Crude oil |
|
| 548 |
|
|
| 259.0 |
|
|
| 407 |
|
|
| 153.6 |
|
|
| 376 |
|
|
| 144.6 |
|
Natural gas |
|
| 27 |
|
|
| 7.6 |
|
|
| 65 |
|
|
| 28.8 |
|
|
| 38 |
|
|
| 20.3 |
|
Dry holes |
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
Total development wells |
|
| 575 |
|
|
| 266.6 |
|
|
| 472 |
|
|
| 182.4 |
|
|
| 414 |
|
|
| 164.9 |
|
Total wells |
|
| 608 |
|
|
| 292.5 |
|
|
| 492 |
|
|
| 195.5 |
|
|
| 427 |
|
|
| 174.8 |
|
As of December 31, 2021,2023, there were 393203 gross (153(113 net) operated and non-operated wells that have been spud and are in the process of drilling, completing or waiting on completion.
Summary of Crude Oil and Natural Gas Properties and Projects
Following is a discussion we review our budgeted number of wells and capital expenditures for 20222023 activities in our key operating areas.
Bakken Field
Our total Bakken production averaged 220,428 Boe per day for the fourth quarter of 2023, up 26% from the 2022 capital budget, based onfourth quarter. For the year ended December 31, 2023, our current expectations of commodity prices and costs, is expectedaverage daily Bakken production increased 18% compared to be funded from operating cash flows. Our2022. In 2023, we participated in the drilling and completion activities and the actual amount and timing of our capital expenditures may differ materially from our budget as a result of, among other things, available cash flows, unbudgeted acquisitions, actual drilling and completion results, the availability of drilling and completion rigs and other services and equipment, the availability of transportation and processing capacity, changes in commodity prices, and regulatory, technological and competitive developments. We monitor our capital spending closely based on actual and projected cash flows and may scale back our spending should commodity prices materially decrease from current levels.
| 2022 Plan | ||||||||||||||||||||
| Gross wells (1) | Net wells (1) | Capital expenditures (in millions) (2) | ||||||||||||||||||
| Bakken | 264 | 116 | $ | 800 | ||||||||||||||||
| Powder River Basin | 34 | 20 | 200 | |||||||||||||||||
| Oklahoma | 117 | 41 | 400 | |||||||||||||||||
| Permian Basin | 49 | 46 | 400 | |||||||||||||||||
| Total exploration and development | 464 | 223 | $ | 1,800 | ||||||||||||||||
| Land | 127 | |||||||||||||||||||
| Mineral acquisitions attributable to Continental (3) | 23 | |||||||||||||||||||
| Capital facilities, workovers, water infrastructure, and other | 344 | |||||||||||||||||||
| Seismic | 6 | |||||||||||||||||||
| 2022 capital budget attributable to Continental | $ | 2,300 | ||||||||||||||||||
| Mineral acquisitions attributable to Franco-Nevada (3) | 91 | |||||||||||||||||||
| Total 2022 capital budget (4) | $ | 2,391 | ||||||||||||||||||
. Continental holds a controlling financial interest in TMRC II and therefore consolidates the financial results and capital expenditures of the entity. With a carry structure in place, Continental will fund 20% of 2022 planned spending, or $23 million, and Franco-Nevada will fund the remaining 80%, or $91 million.
Anadarko Basin
Our properties in the South regionAnadarko Basin represented 54%35% of our total proved reserves as of December 31, 20212023 and 45%32% of our average daily Boe production for the fourth quarter of 2021. Our principal producing properties2023. Production in the South region are locatedAnadarko Basin averaged 144,158 Boe per day during the fourth quarter of 2023, down 13% compared to the 2022 fourth quarter. We participated in the SCOOPdrilling and STACK areascompletion of Oklahoma and our recently acquired properties120 gross (43 net) wells in the PermianAnadarko Basin of Texas.
Our proved reserves in the Anadarko Basin as of December 31, 2021, we controlled one2023 totaled 653 MMBoe, a decrease of 6% compared to December 31, 2022. Our inventory of proved undeveloped drilling locations in the largest leasehold positions in Oklahoma with approximately 801,700Anadarko Basin totaled 272 gross (448,300(161 net) acres under lease.
Our Powder River properties in Oklahoma represented 41%8% of our total proved reserves as ofat December 31, 20212023 and 43%6% of our average daily Boe production for the 2023 fourth quarter of 2021. Productionquarter. Our production in Oklahomathe Powder River Basin averaged 146,13125,577 Boe per day duringfor the fourth quarter of 2021, down 2%2023, a decrease of 9% compared to the 20202022 fourth quarter. For the year ended December 31, 2021, average daily production in Oklahoma increased 9% compared to 2020, reflecting the impact of voluntary production curtailments in 2020 and additional drilling and completion activities in 2021. WeDuring 2023, we participated in the drilling and completion of 16153 gross (63(17 net) wells in Oklahoma during 2021the play compared to 14531 gross (54(23 net) wells in 2020. 2022.
Our proved reserves in Oklahomathe Powder River Basin totaled 139 MMBoe as of December 31, 2021 totaled 679 MMBoe,2023, an increase of 18%34% compared to December 31, 2020 primarily due to reserves added from our drilling program and upward reserve revisions prompted by improved commodity prices.2022. Our inventory of proved undeveloped drilling locations in Oklahomathe play totaled 313136 gross (170(103 net) wells as of December 31, 2021.2023.
5
Table of return, and maximize cash flows.Contents
Permian Basin
Our Permian Basin properties acquired in late 2021 totaled 203 MMBoe, representing 12%represented 21% of our total proved reserves at December 31, 2023 and 13% of our average daily Boe production for the 2023 fourth quarter. Our production in the Permian Basin averaged 58,601 Boe per day for the fourth quarter of 2023, an increase of 30% compared to the 2022 fourth quarter. During 2023, we participated in the drilling and completion of 72 gross (66 net) wells in the play compared to 39 gross (35 net) wells in 2022.
Our proved reserves in the Permian Basin totaled 386 MMBoe as of December 31, 2021. Production from our Permian properties averaged approximately 42,000 Boe per day based on two-stream reporting during our short duration2023, an increase of ownership from December 21, 202127% compared to December 31, 2021.
The following table sets forth information concerning our production results, average sales prices and production costs for the years ended December 31, 2021, 20202023, 2022 and 20192021 in total and for each field containing 15 percent or more of our total proved reserves as of December 31, 2021.
| Year ended December 31, | ||||||||||||||||||||
| 2021 | 2020 | 2019 | ||||||||||||||||||
| Net production volumes: | ||||||||||||||||||||
| Crude oil (MBbls) | ||||||||||||||||||||
| North Dakota Bakken | 40,121 | 40,052 | 52,420 | |||||||||||||||||
| SCOOP | 11,318 | 12,585 | 11,679 | |||||||||||||||||
| Total Company | 58,636 | 58,745 | 72,267 | |||||||||||||||||
| Natural gas (MMcf) | ||||||||||||||||||||
| North Dakota Bakken | 120,517 | 97,532 | 98,186 | |||||||||||||||||
| SCOOP | 179,553 | 136,410 | 111,436 | |||||||||||||||||
| Total Company | 370,110 | 306,528 | 311,865 | |||||||||||||||||
| Crude oil equivalents (MBoe) | ||||||||||||||||||||
| North Dakota Bakken | 60,207 | 56,308 | 68,784 | |||||||||||||||||
| SCOOP | 41,244 | 35,320 | 30,252 | |||||||||||||||||
| Total Company | 120,321 | 109,833 | 124,244 | |||||||||||||||||
| Average net sales prices (1): | ||||||||||||||||||||
| Crude oil ($/Bbl) | ||||||||||||||||||||
| North Dakota Bakken | $ | 63.24 | $ | 33.53 | $ | 50.96 | ||||||||||||||
| SCOOP | 66.46 | 37.88 | 54.92 | |||||||||||||||||
| Total Company | 64.06 | 34.71 | 51.82 | |||||||||||||||||
| Natural gas ($/Mcf) | ||||||||||||||||||||
| North Dakota Bakken | $ | 4.52 | $ | 0.23 | $ | 1.28 | ||||||||||||||
| SCOOP | 5.33 | 1.64 | 2.36 | |||||||||||||||||
| Total Company | 4.88 | 1.04 | 1.77 | |||||||||||||||||
| Crude oil equivalents ($/Boe) | ||||||||||||||||||||
| North Dakota Bakken | $ | 51.21 | $ | 24.24 | $ | 40.66 | ||||||||||||||
| SCOOP | 41.44 | 19.90 | 29.80 | |||||||||||||||||
| Total Company | 46.24 | 21.47 | 34.56 | |||||||||||||||||
| Average costs per Boe: | ||||||||||||||||||||
| Production expenses ($/Boe) | ||||||||||||||||||||
| North Dakota Bakken | $ | 4.27 | $ | 4.35 | $ | 4.28 | ||||||||||||||
| SCOOP | 1.24 | 1.06 | 1.21 | |||||||||||||||||
| Total Company | 3.38 | 3.27 | 3.58 | |||||||||||||||||
| Production taxes ($/Boe) | $ | 3.36 | $ | 1.75 | $ | 2.88 | ||||||||||||||
| General and administrative expenses ($/Boe) | $ | 1.94 | $ | 1.79 | $ | 1.57 | ||||||||||||||
| DD&A expense ($/Boe) | $ | 15.76 | $ | 17.12 | $ | 16.25 | ||||||||||||||
for a discussion and calculation of net sales prices, which are non-GAAP measures.
| Year ended December 31, |
| ||||||||||
| 2023 |
|
| 2022 |
|
| 2021 |
| ||||
Net production volumes: |
|
|
|
|
|
|
|
|
| |||
Crude oil (MBbls) |
|
|
|
|
|
|
|
|
| |||
North Dakota Bakken |
|
| 48,032 |
|
|
| 39,917 |
|
|
| 40,121 |
|
SCOOP |
|
| 11,652 |
|
|
| 10,051 |
|
|
| 11,318 |
|
Permian Delaware |
|
| 14,762 |
|
|
| 11,832 |
|
|
| — |
|
Total Company |
|
| 84,710 |
|
|
| 72,827 |
|
|
| 58,636 |
|
Natural gas (MMcf) |
|
|
|
|
|
|
|
|
| |||
North Dakota Bakken |
|
| 146,026 |
|
|
| 124,411 |
|
|
| 120,517 |
|
SCOOP |
|
| 179,165 |
|
|
| 185,755 |
|
|
| 179,553 |
|
Permian Delaware |
|
| 27,980 |
|
|
| 20,804 |
|
|
| — |
|
Total Company |
|
| 455,698 |
|
|
| 442,980 |
|
|
| 370,110 |
|
Crude oil equivalents (MBoe) |
|
|
|
|
|
|
|
|
| |||
North Dakota Bakken |
|
| 72,370 |
|
|
| 60,652 |
|
|
| 60,207 |
|
SCOOP |
|
| 41,513 |
|
|
| 41,010 |
|
|
| 41,244 |
|
Permian Delaware |
|
| 19,425 |
|
|
| 15,300 |
|
|
| — |
|
Total Company |
|
| 160,660 |
|
|
| 146,657 |
|
|
| 120,321 |
|
Average sales prices: |
|
|
|
|
|
|
|
|
| |||
Crude oil ($/Bbl) |
|
|
|
|
|
|
|
|
| |||
North Dakota Bakken |
| $ | 76.41 |
|
| $ | 94.51 |
|
| $ | 67.08 |
|
SCOOP |
|
| 76.82 |
|
|
| 94.58 |
|
|
| 66.71 |
|
Permian Delaware |
|
| 76.21 |
|
|
| 95.14 |
|
|
| 69.54 |
|
Total Company |
|
| 76.89 |
|
|
| 94.95 |
|
|
| 67.21 |
|
Natural gas ($/Mcf) |
|
|
|
|
|
|
|
|
| |||
North Dakota Bakken |
| $ | 2.54 |
|
| $ | 8.30 |
|
| $ | 4.56 |
|
SCOOP |
|
| 2.93 |
|
|
| 7.00 |
|
|
| 5.46 |
|
Permian Delaware |
|
| 2.53 |
|
|
| 7.27 |
|
|
| 7.33 |
|
Total Company |
|
| 2.60 |
|
|
| 7.15 |
|
|
| 4.98 |
|
Average costs per Boe: |
|
|
|
|
|
|
|
|
| |||
Production expenses ($/Boe) |
|
|
|
|
|
|
|
|
| |||
North Dakota Bakken |
| $ | 5.23 |
|
| $ | 5.05 |
|
| $ | 4.27 |
|
SCOOP |
|
| 1.50 |
|
|
| 1.44 |
|
|
| 1.24 |
|
Permian Delaware |
|
| 5.72 |
|
|
| 7.27 |
|
|
| — |
|
Total Company |
|
| 4.47 |
|
|
| 4.24 |
|
|
| 3.38 |
|
Production and ad valorem taxes ($/Boe) |
| $ | 3.76 |
|
| $ | 4.98 |
|
| $ | 3.36 |
|
General and administrative expenses ($/Boe) |
| $ | 1.74 |
|
| $ | 2.74 |
|
| $ | 1.94 |
|
DD&A expense ($/Boe) |
| $ | 14.11 |
|
| $ | 12.86 |
|
| $ | 15.76 |
|
6
The following table sets forth information regarding our average daily production by region for the fourth quarter of 2021:2023:
| Fourth Quarter 2021 Daily Production | ||||||||||||||||||||
| Crude Oil (Bbls per day) | Natural Gas (Mcf per day) | Total (Boe per day) | ||||||||||||||||||
| North Region: | ||||||||||||||||||||
| Bakken | 116,548 | 354,222 | 175,585 | |||||||||||||||||
| Powder River Basin | 5,704 | 8,912 | 7,189 | |||||||||||||||||
| Red River Units | 6,212 | — | 6,212 | |||||||||||||||||
| South Region: | ||||||||||||||||||||
| Oklahoma | 34,314 | 670,904 | 146,131 | |||||||||||||||||
| Permian Basin (1) | 3,885 | 6,671 | 4,997 | |||||||||||||||||
| Other | 31 | 133 | 54 | |||||||||||||||||
| Total | 166,694 | 1,040,842 | 340,168 | |||||||||||||||||
| Fourth Quarter 2023 Daily Production |
| ||||||||||
| Crude Oil |
|
| Natural Gas |
|
| Total |
| ||||
Bakken |
|
| 146,841 |
|
|
| 441,521 |
|
|
| 220,428 |
|
Anadarko Basin |
|
| 33,979 |
|
|
| 661,075 |
|
|
| 144,158 |
|
Powder River Basin |
|
| 15,688 |
|
|
| 59,333 |
|
|
| 25,577 |
|
Permian Basin |
|
| 43,647 |
|
|
| 89,727 |
|
|
| 58,601 |
|
All other |
|
| 5,635 |
|
|
| 188 |
|
|
| 5,666 |
|
Total |
|
| 245,790 |
|
|
| 1,251,844 |
|
|
| 454,430 |
|
(1)The presentation of average daily 2021 fourth quarter production represents production during the period from the closing of our acquisition of Permian properties on December 21, 2021 through December 31, 2021 averaged over 92 days in the fourth quarter. At the time of closing, our Permian properties produced on average approximately 42,000 Boe per day (78% oil) based on two-stream reporting.
Gross wells represent the number of wells in which we own a working interest and net wells represent the total of our fractional working interests owned in gross wells. The following table presents the total gross and net productive wells by region and by crude oil or natural gas completion as of December 31, 2021.2023. One or more completions in the same well bore are counted as one well.
| Crude Oil Wells | Natural Gas Wells | Total Wells | ||||||||||||||||||||||||||||||||||||
| Gross | Net | Gross | Net | Gross | Net | |||||||||||||||||||||||||||||||||
| North Region: | ||||||||||||||||||||||||||||||||||||||
| Bakken | 5,610 | 1,997 | — | — | 5,610 | 1,997 | ||||||||||||||||||||||||||||||||
| Powder River Basin | 235 | 143 | 7 | 5 | 242 | 148 | ||||||||||||||||||||||||||||||||
| Red River Units | 267 | 251 | — | — | 267 | 251 | ||||||||||||||||||||||||||||||||
| South Region: | ||||||||||||||||||||||||||||||||||||||
| Oklahoma | 1,214 | 521 | 943 | 304 | 2,157 | 825 | ||||||||||||||||||||||||||||||||
| Permian Basin | 409 | 318 | 2 | 1 | 411 | 319 | ||||||||||||||||||||||||||||||||
| Other | 2 | 2 | 23 | 2 | 25 | 4 | ||||||||||||||||||||||||||||||||
| Total | 7,737 | 3,232 | 975 | 312 | 8,712 | 3,544 | ||||||||||||||||||||||||||||||||
| Crude Oil Wells |
|
| Natural Gas Wells |
|
| Total Wells |
| ||||||||||||||||
| Gross |
|
| Net |
|
| Gross |
|
| Net |
|
| Gross |
|
| Net |
| |||||||
Bakken |
|
| 6,127 |
|
|
| 2,236 |
|
|
| — |
|
|
| — |
|
|
| 6,127 |
|
|
| 2,236 |
|
Anadarko Basin |
|
| 1,184 |
|
|
| 525 |
|
|
| 974 |
|
|
| 321 |
|
|
| 2,158 |
|
|
| 846 |
|
Powder River Basin |
|
| 484 |
|
|
| 379 |
|
|
| 6 |
|
|
| 5 |
|
|
| 490 |
|
|
| 384 |
|
Permian Basin |
|
| 473 |
|
|
| 400 |
|
|
| 55 |
|
|
| 33 |
|
|
| 528 |
|
|
| 433 |
|
All other |
|
| 268 |
|
|
| 254 |
|
|
| 26 |
|
|
| 5 |
|
|
| 294 |
|
|
| 259 |
|
Total |
|
| 8,536 |
|
|
| 3,794 |
|
|
| 1,061 |
|
|
| 364 |
|
|
| 9,597 |
|
|
| 4,158 |
|
Title to Properties
As is customary in the crude oil and natural gas industry, upon initiation of acquiring oil and gas leases covering fee mineral interests on undeveloped lands which do not have associated proved reserves, contract landmen conduct a title examination of courthouse records and production databases to determine fee mineral ownership and availability. Title, lease forms and terms are reviewed and approved by Company landmen prior to consummation.
For acquisitions from third parties, whether lands are producing crude oil and natural gas or non-producing, Company and contract landmen perform title examinations at applicable courthouses, obtain physical well site inspections, and examine the seller’s internal records (land, legal, operational, production, environmental, well, marketing and accounting) upon execution of a mutually acceptable purchase and sale agreement. Company landmen may also procure an acquisition title opinion from outside legal counsel on higher value properties.
Prior to the commencement of drilling operations, Company landmen procure an original title opinion, or supplement an existing title opinion, from outside legal counsel and perform curative work to satisfy requirements pertaining to material title issues, if any. Company landmen will not approve commencement of drilling operations until material title defects pertaining to the Company’s interest are cured.
The Company has cured material title opinion issues as to Company interests on substantially all of its producing properties and believes it holds at least defensible title to its producing properties in accordance with standards generally accepted in the crude oil and natural gas industry. The Company’s crude oil and natural gas properties are subject to customary royalty and leasehold burdens which do not materially interfere with the Company’s interest in the properties or affect the Company’s carrying value of such properties.
Marketing
We sell most of our operated crude oil production to crude oil refining companies or midstream marketing companies at major market centers. In the Bakken, Powder River, Permian, SCOOP, and STACK areasAnadarko basins we have significant volumes of production directly connected to pipeline gathering systems, with the remaining production primarily transported by truck to a point on a pipeline system for further delivery. We do not transport any of our oil production prior to sale by rail, but several purchasers of our Bakken production are connected to rail delivery systems and may choose those methods to transport the oil they have purchased from us. We sell some operated crude oil production at the lease. Our share of crude oil production from non-operated properties is marketed at the discretion of the operators.
7
We sell most of our operated natural gas and natural gas liquids production to midstream customers at our lease locations based on market prices in the field where the sales occur, with the remaining production sold at centrally gathered locations or natural gas processing plants. These contracts include multi-year term agreements, many with acreage dedications. Under certain arrangements, we have the right to take a volume of processed residue gas and/or natural gas liquids ("NGLs") in-kind at the tailgate of the midstream customer's processing plant in lieu of a monetary settlement for the sale of our operated natural gas production. When we do take volumes in kind, we pay third parties to transport the residue gas volumes taken in kind to downstream delivery points, where we then sell to customers at prices applicable to those downstream markets. Sales at the downstream markets are mostly under daily and monthly packaged volumes deals, shorter term seasonal packages, and long term multi-year contracts. We continue to develop relationships and have the potential to enter into additional contracts with end-use customers, including utilities, industrial users, and liquefied natural gas exporters, for sale of products we elect to take in-kind in lieu of monetary settlement for our leasehold sales. Our share of natural gas and NGL production from non-operated properties is generally marketed at the discretion of the operators.
Competition
We operate in a highly competitive environment for acquiring properties, marketing crude oil and natural gas, and securing trained personnel. Also, there is substantial competition for capital available for investment in the crude oil and natural gas industry. Our competitors vary within the regions in which we operate, and some of our competitors may possess and employ financial, technical and personnel resources greater than ours. Those companies may be able to pay more for crude oil and
Regulation of the Crude Oil and Natural Gas Industry
All of our operations are conducted onshore in the United States. The crude oil and natural gas industry in the United States is subject to various types of regulation at the federal, state and local levels. Laws, rules, regulations, policies, and interpretations affecting our industry have been and are pervasive with the frequent imposition of new or increased requirements. These laws, regulations and other requirements often carry substantial penalties for failure to comply and may have a significant effect on our operations and may increase the cost of doing business and reduce our profitability. In addition, because public policy changes affecting the crude oil and natural gas industry are commonplace and because laws, rules and regulations may be enacted, amended or reinterpreted, we are unable to predict the future cost or impact of complying with such laws, rules and regulations. We do not expect future legislative or regulatory initiatives will affect us materially different than they will affect our similarly situated competitors.
The following is a discussionare significant areas of certain significant laws, rules and regulations, as amended from time to time,regulation that may affect us in the areas in which we operate.
Environmental, health, and transportation of crude oil and natural gas liquids
8
These laws, rules and regulations may restrict the level of substances generated by our operations that may be emitted into the air, discharged to surface water, and disposed or otherwise released to surface and below-ground soils and groundwater, and may also restrict the rate of our crude oil and natural gas production to a rate that is economically infeasible for continued production. The regulatory burden on the crude oil and natural gas industry increases the cost of doing business and affects profitability. Additionally, in the name of combatting climate change, President Biden has issued, and may continue to issue, executive orders that result in more stringent and costly requirements for the domestic crude oil and natural gas industry, or which restrict, delay or ban oil and gas permitting or leasing on federal lands. Any regulatory or executive changes that impose further requirements on domestic producers for emissions control, waste handling, disposal, cleanup and remediation could have a significant impact on our operating costs and production of oil and gas. For example, the U.S. Environmental Protection Agency finalized federal regulations in December 2023 regarding methane emissions for new and existing oil and gas sources. These rules require more stringent emissions controls for new sources and for the first time impose similar requirements on existing sources, and fines and penalties for violations of the rules can be substantial. Separately, the Inflation Reduction Act of 2022 (“IRA”) established a methane emissions charge, effective January 1, 2024, on specific types of oil and gas production facilities that report emissions in excess of applicable thresholds. Failure to comply with these and other laws, rules and regulations may result in the assessment of administrative, civil and criminal penalties, the imposition of corrective or remedial obligations or the incurrence of capital expenditures, the occurrence of restrictions, delays or cancellations in the permitting, development or expansion of projects, the issuance of orders enjoining performance of some or all of our operations, and potential litigation in a particular area. Additionally, certain of these environmental laws may result in imposition of joint and several or strict liability, which could cause us to become liable for the conduct of others or for consequences of our own actions. For instance, an accidental release from one of our wells could subject us to substantial liabilities arising from environmental cleanup and restoration costs, claims made by neighboring landowners or other third parties for personal injury and property damage and fines or penalties for related violations of environmental laws or regulations. Certain environmental laws also provide for certain citizen suits, which allow persons or organizations to act in place of the government and sue operators for alleged violations of environmental laws. We have incurred and will continue to incur operating and capital expenditures, some of which may be material, to comply with environmental, lawshealth, and regulations. The following is a description of some of the environmentalsafety laws, rules, and regulations, as amended from time to time, that apply to our operations.
Air emissions. Federal, state, and local laws, rules, and regulations have been and, in the future, will likely be enacted to address concerns about emissions of regulated air pollutants. These laws and regulations may require us to obtain pre-approval for the construction or modification of certain projects or facilities expected to produce or significantly increase air emissions, obtain and strictly comply with stringent air permit standards or utilize specific equipment or technologies to control emissions of certain pollutants. For example, in October 2021, the U.S. Environmental Protection Agency (“EPA”) announced its intention to initiate a rule-making to reassess and lower, by the end of 2023, the current National Ambient Air Quality Standard (“NAAQS”) for ground-level ozone, which was last set by the EPA under the Obama Administration in 2015. State implementation of a revised NAAQS for ground-level ozone could result in stricter permitting requirements, delay or prohibit our ability to obtain such permits, or result in increased expenditures for pollution control equipment, the costs of which could be significant.
The Company’s oil and gas operations are subject to a seriesvarious federal, state, and local laws and regulations that relate to matters including, among other things:
Our operations through limitations on venting and flaring andalso are subject to conservation regulations, including the implementation of enhanced emission leak detection and repair requirements. In recent years, there has been considerable uncertainty surrounding regulation of methane emissions. During 2020, the Trump Administration revised performance standards for methane establishedsize of drilling and spacing units or proration units; the number of wells that may be drilled in 2016 to lessena unit; the impactrate of those standards and remove the transmission and storage segmentsproduction allowable from the source category for certain regulations. However, shortly after taking office in 2021, President Biden issued an executive order calling on the EPA to revisit federal regulations regarding methane and establish new or more stringent standards for existing or new sources in the oil and gas sector, including the transmission and storage segments. The U.S. Congress also passed, and President Biden signed into law, a revocation of the 2020 rulemaking, effectively reinstating the 2016 standards. In response to President Biden’s executive order, in November 2021 the EPA issued a proposed rule that, if finalized, would establish Quad Ob new source and Quad Oc first-time existing source standards of performance for methane and volatile organic compound (VOC) emissions in the crude oil and natural gas source category. This proposed rule would apply to upstreamwells; and midstream facilities at oil and natural gas well sites, natural gas gathering and boosting compressor stations, natural gas processing plants, and transmission and storage facilities. Ownersthe unitization or operatorspooling of affected emission units or processes would have to comply with specific standards of performance that may include leak detection using optical gas imaging and subsequent repair requirements, reduction of emissions by 95% through capture and control systems, zero-emission requirements, operation and maintenance requirements, and so-called green well completion requirements. The EPA plans to issue a supplemental proposal enhancing this proposed rulemaking in 2022 that will contain additional requirements that were not included in the November 2021 proposed rule. The EPA anticipates issuing a final rule before end-of-year 2022. Additionally, the House of Representatives version of the Build Back Better Act included a fee on methane emissions, targeting industries that produce, transport, and store natural gas throughout the United States at $900 per ton in 2023, $1,200 per ton in 2024, and $1,500 per ton in 2025 and beyond. Congress could seek to include this or a similar fee in future legislation.
Certain of our leases are granted or approved by the costs associatedfederal government and administered by the Bureau of Land Management or Bureau of Indian Affairs of the Department of the Interior. Such leases require compliance with the disposaldetailed federal regulations and orders that regulate, among other matters, drilling and operations on lands covered by these leases and calculation and disbursement of produced water will have a material adverse effect on our operations to any greater degree than other similarly situated competitors. In recent years, we have increased our operation and use of water recycling and distribution facilities that economically reuse stimulation water for both operational efficiencies and environmental benefits.
9
Employee Healthroyalty payments to the federal government, tribes or tribal members. Moreover, the permitting process for oil and Safety. We are alsogas activities on federal and Indian lands can sometimes be subject to the requirementsdelay, including as a result of thechallenges to permits or other regulatory decisions brought by non-governmental organizations or other parties, which can hinder development activities or otherwise adversely impact operations. The federal Occupational Safetygovernment has, from time to time, evaluated and, Health Act and comparable state laws that regulate the protection of the health and safety of workers. In addition, the U.S. Occupational Safety and Health Administration hazard communication standard, the EPA community right-to-know regulation under Title III of the federal superfund Amendment and Reauthorization Act and similar state lawsin some cases, promulgated new rules and regulations requireregarding competitive lease bidding, venting and flaring, oil and gas measurement and royalty payment obligations for production from federal lands.
For additional information be maintained about hazardous materials used or produced in operationson the Company’s regulatory risks, see Part 1, Item 1A. Risk Factors—Legal and Regulatory Risks of this information be provided to employees, state and local governmental authorities and citizens.report.
Human Capital
As of December 31, 2021,2023, we employed 1,2541,457 people, all of which were employed in the United States, with 721818 employees being located at our corporate headquarters in Oklahoma City, Oklahoma and 533639 employees located in our field offices located in Oklahoma, North Dakota, South Dakota, Montana, Wyoming, and Texas. None of our employees are subject to collective bargaining agreements. We believe our overall relations with our workforce are good.
Because we operate in a highly competitive environment, we have designed our compensation program to attract, retain and motivate experienced, talented individuals. Our program is also designed to align employee’s interests with those of our shareholdersowners and to reward them for achieving the business and strategic objectives determined to be important to help the Company create and maintain advantage in a competitive environment. We align our employee’s interests with those of our shareholdersowners by making annual restricted stocklong-term incentive awards to virtually all of our salaried employees. We reward our employees for their performance in helping the Company achieve its annual business and strategic objectives through our bonus program, which is also available to virtually all of our employees. In order to ensure our compensation package remains competitive and fulfills our goal of recruiting and retaining talented employees, we consider competitive market compensation paid by other companies comparable to the Company in size, geographic location, and operations.
Safety is our highest priority and one of our core values. We promote safety with a robust health and safety program that includes employee orientation and training, contractor management, risk assessments, hazard identification and mitigation, audits, incident reporting and investigation, and corrective/preventative action development.
Through our “Brother’s Keeper” program, we encourage each of our employees to be a proactive participant in ensuring the safety of all of the Company’s personnel. We developed this program to leverage and continuously improve our ability to identify and prevent reoccurrence of unsafe behaviors and conditions. This program recognizes and rewards Company employees and contractors who observe and report outstanding safety and environmental behavior such as utilizing stop work authority, looking out for a co-worker, reporting incidents and near misses, or following proper safety procedures. This program positively impacts safety culture and performance and has contributed to a substantial increase in our reporting rates and to decreases in recordable incident and lost time incident rates. Our Total Recordable Incident Rate (TRIR), a commonly used safety metric that measures the number of recordable incidents per 100 full-time employees and contractors during a one year period,
has decreased sequentially in each of the past four years and measured 0.33 for 2021, a 61% decrease compared to 2017.
We are committed to the training and development of our employees. We believe that supporting our employees in achieving their career and development goals is a key element of our approach to attracting and retaining top talent. We have invested in a variety of resources to support employees in achieving their career and development goals, including developing learning paths for individual contributors and leaders, operating the Continental Leadership Learning Center which offers numerous instructor-led programs designed to foster employee development and maintaining a learning management system which provides access to numerous technical and soft skills online courses. We also invest time and resources in supporting the creation of individual development plans for our employees.
Health and Wellness
We offer various benefit programs designed to promote the health and well-being of our employees and their families. These benefits include medical, dental, and vision insurance plans; disability and life insurance plans; paid time off, for holidays, vacation, sick leave, and other personal leave; and healthcare flexible spending accounts, among other things. In addition to these programs, we have a number of other programs designed to further promote the health and wellness of our employees. For
10
access to our fitness center. Additionally, we have an employee assistance program that offers counseling and referral services for a broad range of personal and family situations. We also offer a wellness plan that includes annual biometric screenings, flu shots, smoking cessation programs, and healthy snack options in our break rooms to encourage total body wellness.
From the earliest days of the COVID-19 pandemic we have taken, and continue to take, proactive measures to protect the health and safety of our employees, both at work and at home. These measures have included offering free in-office testing, providing flexible work schedules for impacted employees, holding in-office vaccination clinics so that interested employees and household members could conveniently receive vaccinations as soon as possible, maintaining physical distancing policies, limiting the number of employees attending meetings, reducing the number of people at our sites, requiring the use of masks in certain circumstances, frequently and extensively disinfecting common areas, and implementing self-isolation and quarantine requirements, among other things. We are committed to maintaining best practices with our COVID-19 response protocols and will continue to work under the guidance of public health officials to ensure a safe workplace as long as COVID-19 remains a threat to our employees and communities.
We are committed to providing a diverse and inclusive workplace and career development opportunities to attract and retain talented employees. We prohibit discrimination and harassment of any type and afford equal employment opportunities to employees and applicants without regard to race, color, religion, sex, sexual orientation, gender identity, national origin, political affiliation, age, disability, genetic information, veteran status, or any other basis protected by local, state, or federal law. We also maintain a robust compliance program rooted in our Code of Business Conduct, and Ethics, which provides policies and guidance on non-discrimination, anti-harassment, and equal employment opportunities.
We believe embracing diversity and inclusion is more than a matter of compliance. We recognize and appreciate the importance of creating an environment in which all employees feel valued, included, and empowered to do their best work and bring great ideas to the table. We believe a diverse and inclusive workforce provides the best opportunity to obtain unique perspectives, experiences, ideas, and solutions to help sustain our business success; a diverse and inclusive culture is the high-performance fuel that enhances our ability to innovate, execute and grow. To that end, we have begun implementingimplemented a long-term initiative for enhancing awareness of, and continuously improving our approach to, building and sustaining a diverse and inclusive culture. We have chartered a Diversity and Inclusion Committee comprised of employees across all company functions. We have engaged external training resources for our entire workforce, including interview training for hiring managers focused on ensuring a fair and systematic approach for recruiting and selecting individuals from diverse backgrounds for competitive job openings. We are intentional about proactively conducting outreach and recruitment at job fairs and other events hosted by diverse organizations. We are working withThrough our newly formed Diversity and Inclusion Committee towe provide new opportunities for our leadership and all employees to hold targeted discussions on issues related to diversity and inclusion, such as unconscious bias, disability inclusion, and equality through inclusive interaction. We are committed to continuous improvement in this critical area, evaluating more ways to sustain and strengthen our diverse and inclusive workforce.
Company Contact Information
Our corporate internet website is www.clr.com. Through the investor relations“Stakeholders” section of our website, we make available free of charge our Annual Report on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, and any amendments to those reports as soon as reasonably practicable after the report is filed with or furnished to the SEC. For a current version of various corporate governance documents, including our Code of Business Conduct and Ethics, Corporate Governance Guidelines, and the charters for various committees of our Board of Directors, please see our website. We intend to disclose amendments to, or waivers from, our Code of Business Conduct and Ethics by posting to our website. Information contained on our website is not incorporated by reference into this report and you should not consider information contained on our website as part of this report.
We electronically file periodic reports and proxy statements with the SEC.SEC as required by our senior note indentures. The SEC maintains an internet website that contains reports proxy and information statements, and other information registrants file with the SEC. The address of the SEC’s website is www.sec.gov.
Our principal executive offices are located at 20 N. Broadway, Oklahoma City, Oklahoma 73102, and our telephone number at that address is (405) 234-9000.
11
Item 1A. Risk Factors
You should carefully consider each of the risks described below, together with all other information contained in this report in connection with an investment in our debt securities. If any of the following risks develop into actual events, our business, financial condition, results of operations, or cash flows could be materially adversely affected, the trading price of our securities could decline and you may lose all or part of your investment.
Business and Operating Risks
Substantial declines in commodity prices or extended periods of low commodity prices adversely affect our business, financial condition, results of operations and cash flows and our ability to meet our capital expenditure needs and financial commitments.
The prices we receive for sales of our crude oil and natural gas production impact our revenue, profitability, cash flows, access to capital, capital budget, rate of growth, and carrying value of our properties. Crude oil and natural gas are commodities and prices are subject to wide fluctuations in response to relatively minor changes in supply and demand. Historically, the markets for crude oil and natural gas have been volatile and unpredictable and commodity prices will likely remain volatile in the future. Our future crude oil production and a portion of our future natural gas production is unhedged as of the time of this filing and is exposed to continued volatility in market prices, whether favorable or unfavorable.
The prices we receive for sales of our production depend on numerous factors beyond our control. These factors include, but are not limited to, the following:
In addition to reducing our revenue, cash flows and earnings, depressed prices for crude oil and/or natural gas may adversely affect us in a variety of other ways. If commodity prices decrease substantially, some of our exploration and development projects could become uneconomic, and we may also have to make significant downward adjustments to our estimated proved reserves and our
12
estimates of the present value of those reserves. If these price effects occur, or if our estimates of production or economic factors change, accounting rules may require us to write down the carrying value of our crude oil and/or natural gas properties.
Lower commodity prices may also lead to reductions in our drilling and completion programs, which may result in insufficient production to satisfy our transportation and processing commitments. If production is not sufficient to meet our commitments we would incur deficiency fees that would need to be paid absent any cash inflows generated from the sale of production.
Lower commodity prices may also reduce our access to capital and lead to a downgrade or other negative rating action with respect to our credit rating. A downgrade of our credit rating could negatively impact our cost of capital, increase borrowing costs under our revolving credit facility and term loan, and limit our ability to access debt capital markets and execute aspects of our business plans. As a result, substantial declines in commodity prices or extended periods of low commodity prices may materially and adversely affect our future business, financial condition, results of operations, cash flows, liquidity and ability to meet our capital expenditure needs and commitments.
The ability or willingness of Saudi Arabia and other members of OPEC, and other oil exporting nations, including Russia, to set and maintain production levels has a significant impact on crude oil prices.
OPEC is an intergovernmental organization that seeks to manage the price and supply of crude oil on the global energy market. Actions taken by OPEC members, including those taken alongside other oil exporting nations such as Russia, may have a significant impact on global oil supply and pricing. There can be no assurance that OPEC members and other oil exporting nations will comply with agreed-upon production targets, agree to further production targets in the future, or utilize other actions to support and stabilize oil prices, nor can there be any assurance they will not increase production or deploy other actions aimed at reducing oil prices. Uncertainty regarding future actions to be taken by OPEC members or other oil exporting countries could lead to increased volatility in the price of oil, which could have a material adverse effect on our business, financial condition, results of operations, and cash flows.
•Limitations on storage and transportation capacity and an inability to market our production;
Our future financial condition and results of operations depend on the success of our exploration, development and production activities. Our crude oil and natural gas exploration and production activities are subject to numerous risks, including the risk that drilling will not result in commercially viable crude oil or natural gas production. Our decisions to purchase, explore, or develop prospects or properties will depend in part on the evaluation of data obtained through geophysical and geological analyses, production data, and engineering studies, the results of which are often inconclusive or subject to varying interpretations. Our cost of drilling, completing and operating wells may be uncertain before drilling commences.
Our management has specifically identified prospects and scheduled drilling locations as an estimation of our future multi-year drilling activities on our existing acreage. Our ability to drill and develop these locations is subject to a number of risks and uncertainties as described herein. If future drilling results do not establish sufficient reserves to achieve an economic return, we may curtail our drilling and completion activities. Prospects we decide to drill that do not produce crude oil or natural gas in expected quantities may adversely affect our results of operations, financial condition, and rates of return on capital employed. The use of seismic data and other technologies and the study of producing fields in the same area will not enable us to know conclusively prior to drilling whether crude oil or natural gas will be present in expected or economically producible quantities. We cannot assure you the wells we drill will be as productive as anticipated or whether the analogies we draw from other wells, more fully explored prospects, or producing fields will be applicable to our drilling prospects. Because of these uncertainties, we do not know if our potential drilling locations will ever be drilled or if we will be able to produce crude oil or natural gas from these or any other potential drilling locations in sufficient quantities to achieve an economic return.
Risks we face while drilling include, but are not limited to, failing to place our well bore in the desired target producing zone; not staying in the desired drilling zone while drilling horizontally through the formation; failing to run our casing the entire length of the well bore; and not being able to run tools and other equipment consistently through the horizontal well bore. Risks we face while completing our wells include, but are not limited to, not being able to fracture stimulate the planned number of stages; failing to run tools the entire length of the well bore during completion operations; not successfully cleaning out the well bore after completion of the final fracture stimulation stage; increased seismicity in areas near our completion activities; unintended interference of completion activities performed by us or by third parties with nearby operated or non-operated wells being drilled, completed, or producing; and failure of our optimized completion techniques to yield expected levels of production.
Further, many factors may occur that cause us to curtail, delay or cancel scheduled drilling and completion projects, including but not limited to:
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Any of the above risks could adversely affect our ability to conduct operations or result in substantial losses to us as a result of:
litigation.
Losses and liabilities arising from any of the above events could hinder our ability to conduct normal operations and could adversely affect our business, financial condition, results of operations and cash flows.
Reserve estimates depend on many assumptions that may turn out to be inaccurate. The present value of future net revenues from our proved reserves will not necessarily be the same as the current market value of our estimated crude oil and natural gas reserves. Any material inaccuracies in our reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves. The Company’sCompany's current estimates of reserves could change, potentially in material amounts, in the future due to changes in commodity prices, business strategies, and other factors. Additionally, unless we replace our crude oil and natural gas reserves, our total reserves and production will decline, which could adversely affect our cash flows and results of operations.
The process of estimating crude oil and natural gas reserves is complex and inherently imprecise. It requires interpretation of available technical data and many assumptions, including assumptions relating to current and future economic conditions, production rates, drilling and operating expenses, and commodity prices. Any significant inaccuracy in these interpretations or assumptions could materially affect our estimated quantities and present value of our reserves. See Part I, Item 1. Business—Crude Oil and Natural Gas Operations—Proved Reserves for information about our estimated crude oil and natural gas reserves standardized measure of discounted future net cash flows, and PV-10 as of December 31, 2021.2023.
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In order to prepare reserve estimates, we must project production rates and the amount and timing of development expenditures. We must also analyze available geological, geophysical, production and engineering data in preparing reserve estimates. The extent, quality and reliability of this data can vary which in turn can affect our ability to model the porosity, permeability and pressure relationships in unconventional resources. The process also requires economic assumptions, based on historical data projected into the future, about crude oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes, and availability of funds.
You should not assume the present value of future net revenues from our proved reserves is the current market value of our estimated crude oil and natural gas reserves. We base the estimated discounted future net revenues from proved reserves on the 12-month unweighted arithmetic average of the first-day-of-the-month commodity prices for the preceding twelve months. Actual future prices may be materially higher or lower than the average prices used in the calculations. In addition, the use of a 10% discount factor, which is required by the SEC to be used to calculate discounted future net revenues for reporting purposes, may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with our reserves or the crude oil and natural gas industry. For the year ended December 31, 2021, average prices used to calculate our estimated proved reserves were $66.56 per Bbl for crude oil and $3.60 per MMBtu for natural gas ($62.19 per Bbl for crude oil and $3.46 per Mcf for natural gas adjusted for location and quality differentials). NYMEX WTI crude oil and Henry Hub natural gas first-day-of-the-month commodity prices for January 1, 2022 and February 1, 2022 averaged $81.71 per barrel and $4.65 per MMBtu, respectively. See Part I, Item 1. Business—Crude Oil and Natural Gas Operations—Proved Reserves—Proved Reserves, Standardized Measure, and PV-10 Sensitivities for proved reserve sensitivities under certain increasing and decreasing commodity price scenarios.
Additionally, unless production is established within the spacing units covering the undeveloped acres on which some of the locations are identified, the leases for such acreage will expire. If we are not able to renew leases before they expire, any proved undeveloped reserves associated with such leases will be removed from our proved reserves. The combined net acreage expiring in the next three years represents 37%36% of our total net undeveloped acreage at December 31, 2021. At that date, we had leases representing 83,937 net acres expiring in 2022, 62,251 net acres expiring in 2023, and 51,094 net acres expiring in 2024.
Furthermore, unless we conduct successful exploration, development and exploitation activities or acquire properties containing proved reserves, our proved reserves will decline as those reserves are produced. Producing crude oil and natural gas reservoirs are generally characterized by declining production rates that vary depending upon reservoir characteristics and other factors. Our future crude oil and natural gas reserves and production, and therefore our cash flows and results of operations, are highly dependent on our success in efficiently developing our current reserves and economically finding or acquiring additional recoverable reserves. We may not be able to develop, find or acquire sufficient additional reserves to replace our current and future production. If we are unable to replace our current and future production, the value of our reserves will decrease, and our business, financial condition and results of operations could be materially adversely affected.
Our business depends on crude oil and natural gas transportation, processing, refining, and export facilities, most of which are owned by third parties.
The value we receive for our crude oil and natural gas production depends in part on the availability, proximity and capacity of gathering, pipeline and rail systems and processing, refining, and export facilities owned by third parties. The inadequacy or unavailability of capacity on these systems and facilities could result in the shut-in of producing wells, the delay or
The disruption of transportation, processing, refining, or export facilities due to contractual disputes or litigation, labor disputes, maintenance, civil disturbances, international trade disputes, public protests, terrorist attacks, cybercybersecurity attacks, adverse climatic events, natural disasters, seismic events, health epidemics and concerns, changes in tax and energy policies, federal, state and international regulatory developments, changes in supply and demand, equipment failures or accidents, including pipeline and gathering system ruptures or train derailments, and general economic conditions could negatively impact our ability to achieve the most favorable prices for our crude oil and natural gas production. We have no control over when or if access to such facilities would be restored or the impact on prices in the areas we operate. A significant shut-in of production in connection with any of the
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aforementioned items could materially affect our cash flows, and if a substantial portion of the impacted production fulfills transportation or processing commitments or is hedged at lower than market prices, those commitments or financial hedges would have to be paid from borrowings in the absence of sufficient operating cash flows.
Our operated crude oil and natural gas production is ultimately transported to downstream market centers in the United States primarily using transportation facilities and equipment owned and operated by third parties. See Part I, Item 1. Business—Regulation of the Crude Oil and Natural Gas Industry for a discussion of regulations impacting the transportation of crude oil and natural gas. From time to time we may sell our operated crude oil production at market centers in the United States to third parties who then subsequently export and sell the crude oil in international markets. We do not currently own or operate infrastructure used to facilitate the transportation and exportation of crude oil; however, third party compliance with regulations that impact the transportation or exportation of our production may increase our costs of doing business and inhibit a third party's ability to transport and sell our production, whether domestically or internationally, the consequences of which could have a material adverse effect on our business, financial condition, results of operations and cash flows.
In response to a July 2020 U.S. District Court decision vacating the U.S. Army Corps of Engineers (“Corps”) grant of an easement to the Dakota Access Pipeline (“DAPL”) and issuance of an order requiring the Corps to conduct an Environmental Impact Statement (“EIS”) for the pipeline, the Corps is currently conducting the court-ordered environmental review to determine the potential effects of the pipeline, including whether DAPL poses a threat to the drinking water supply of the Standing Rock Sioux Reservation. DAPL currently remainsThe Corps published a draft EIS on September 8, 2023 and anticipates issuing a final EIS in operation and, while the owners of DAPL appealed the District Court decision to the U.S. Supreme Court in September 2021, the Corps continues to conduct the review, which is estimated to be completed no later than November 2022.2024. Once the review is completed, the Corps will determine whether DAPL is safe to operate or must be shut down. There has not been any decision on whether the U.S. Supreme Court will hear the appeal andDAPL currently remains in operation, but we are unable to determine the outcome or the impact of these actions on DAPL in the future.
We utilize DAPL to transport a portion of our North regionBakken crude oil production to ultimate markets on the U.S. gulf coast. Our transportation commitment on the pipeline increased from 3,550 barrels per day tototals 30,000 barrels per day effective August 1, 2021 in conjunction with the completion of a DAPL expansion project. This commitmentwhich will continue through February 2026 at which time the commitment decreases to 26,450 barrels per day through July 2028.
If transportation capacity on DAPL becomes restricted or unavailable, we have the ability to utilize other third party pipelines or rail facilities to transport our Bakken crude oil production to market, although such alternatives may be more costly. A restriction of DAPL’sDAPL's takeaway capacity may have an impact on prices for Bakken-produced barrels and result in wider differentials relative to WTI benchmark prices in the future, the amount of which is uncertain.
Our exploration, development and exploitation projects require substantial capital expenditures. We may be unable to obtain needed capital or financing on acceptable terms, which could lead to a decline in our crude oil and natural gas reserves, production and revenues.
The crude oil and natural gas industry is capital intensive. We make and expect to continue to make substantial capital expenditures in our business for the exploration, development, exploitation, production and acquisition of crude oil and natural gas reserves. We have budgeted $2.30 billion for capital expenditures attributable to us in 2022, excluding acquisitions, of which approximately $1.80 billion is allocated to explorationmonitor and development activities. We may adjust our 2022 capital spending plans upward or downward depending on market conditions. Our 20222024 capital budget, based on our current expectations of commodity prices and costs, is expected to be funded from operating cash flows. However, the sufficiency of our cash flows from operations is subject to a number of variables, including but not limited to:
If oil and gas industry conditions weaken as a result of low commodity prices or other factors, we may not be able to generate sufficient cash flows and may have limited ability to obtain the capital necessary to sustain our operations at current or planned levels. A decline in cash flows from operations may require us to revise our capital program or alterseek financing in banking or increasedebt capital markets to fund our capitalization substantially through the issuance of debt or equity securities.
We have a revolving credit facility with lender commitments totaling $2.0$2.255 billion that matures in October 2026. In the future, we may not be able to access adequate funding under our revolving credit facility if our lenders are unwilling or unable to meet their funding obligations or increase their commitments under the credit facility. Our lenders could decline to increase their commitments based on our financial condition, the financial condition of our industry or the economy as a whole or for other reasons beyond our control. Due to these and other factors, we cannot be certain that funding, if needed, will be available to the extent required or on terms we find acceptable. If operating cash flows are insufficient and we are unable to access funding or execute debt capital transactions when needed on acceptable terms, we may not be able to fully implement our business plans, fund our capital program and commitments, complete new property acquisitions to replace reserves, take advantage of business opportunities, respond to
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competitive pressures, or refinance debt obligations as they come due. Should any of the above risks occur, they could have a material adverse effect on our business, financial condition, results of operations and cash flows.
The unavailability or high cost of drilling rigs, well completion crews, water, equipment, supplies, personnel and field services could adversely affect our ability to execute our exploration and development plans within budget and on a timely basis.
In the regions in which we operate, there have been shortages of drilling rigs, well completion crews, equipment, personnel, field services, and supplies, including key components used in fracture stimulation processes such as water and proppants, as well as high costs associated with these critical components of our operations. With current technology, water is an essential component of drilling and hydraulic fracturing processes. The availability of water sources and disposal facilities is becoming increasingly competitive, constrained, subject to social and regulatory scrutiny, and impacted by third-party supply chains over which we may have limited control. Limitations or restrictions on our ability to secure, transport, and use sufficient amounts of water, including limitations resulting from natural causes such as drought, could adversely impact our operations. In some cases, water may need to be obtained from new sources and transported to drilling or completion sites, resulting in increased costs.
The demand for qualified and experienced field service providers and associated equipment, supplies, and materials can fluctuate significantly, often in correlation with commodity prices or supply chain disruptions, causing periodic shortages and/or higher costs. For instance, recent supply chain disruptions stemming from the COVID-19 pandemic have led to shortages of certain materials and equipment and increased costs. While we have not yet experienced material shortages in supply as a resultAny of these disruptions, if they become prolonged or expand in scope the resulting shortages or higherfactors may cause costs could delay the execution of our drilling and development plans or cause us to incur expenditures not provided for in our capital budget or to not achieve the rates of return we are targeting for our development program, all ofrise which could have a material adverse effect on our business, financial condition, results of operations and cash flows.
We have been an early entrant into new or emerging plays. As a result, our drilling results in these areas are uncertain, and the value of our undeveloped acreage will decline if drilling results are unsuccessful.
While our costs to acquire undeveloped acreage in new or emerging plays have generally been less than those of later entrants into a developing play, our drilling results in new or emerging areas are more uncertain than drilling results in developed and producing areas. Since new or emerging plays have limited or no production history, we are unable to use past drilling results in those areas to help predict our future drilling results. As a result, our cost of drilling, completing and operating wells in these areas may be higher than initially expected, and the value of our undeveloped acreage in the emerging areas may decline if drilling results are unsuccessful.
We have limited control over the activities on properties we do not operate.
Some of the properties in which we have an ownership interest are operated by other companies and involve third-party working interest owners. As of December 31, 2021,2023, non-operated properties represented 14%13% of our estimated proved developed reserves, 7%8% of our estimated proved undeveloped reserves, and 11%10% of our estimated total proved reserves. We have limited ability to influence or control the operations or future development of non-operated properties, including the
We may be subject to risks in connection with acquisitions, divestitures, and joint development arrangements.
As part of our business strategy, we have made and expect to continue making acquisitions of oil and gas properties, divest assets, and enter into joint development arrangements. The successful acquisition of oil and gas properties requires an assessment of several factors, including but not limited to:
The accuracy of these acquisition assessments is inherently uncertain. In connection with these assessments, we perform a review, which we believe to be generally consistent with industry practices, of the subject properties. Our review will not reveal all existing or
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potential problems nor will it permit us to become sufficiently familiar with the properties to fully assess their deficiencies and capabilities prior to acquisition. Inspections may not always be performed on every property, and environmental problems are not necessarily observable even when an inspection is undertaken. Even when problems are identified, the seller of the subject properties may be unwilling or unable to provide effective contractual protection against all or part of the problems. We sometimes are not entitled to contractual indemnification for environmental liabilities and acquire properties on an “as is” basis. Significant acquisitions and other strategic transactions may involve other risks that may impact our business, including:
As a result of our 2021 propertystrategy of assessing and executing on accretive acquisitions, in the Permian Basin and Powder River Basin, the size and geographic footprint of our business has increased and may continue to do so, including into new jurisdictions. Our future success will depend, in part, on our ability to manage our expanded business, which may pose challenges including those related to the management and monitoring of new operations and basins and associated increased costs and complexity. We believe theseour acquisitions will complement our business strategies by delivering enhanced free cash flows and corporate returns, and shareholder value, among other things. However, the anticipated benefits of the transactions may be less significant than expected or may take longer to achieve than anticipated. If we are not able to achieve these objectives and realize the anticipated benefits within anticipated timing or at all, our business, financial condition and operating results may be adversely affected.
In addition, from time to time we may sell or otherwise dispose of certain assets as a result of an evaluation of our asset portfolio or to provide cash flow for use in reducing debt and enhancing liquidity. Such divestitures have inherent risks, including possible delays in closing, the risk of lower-than-expected sales proceeds for the disposed assets, and potential post-closing adjustments and claims for indemnification. Additionally, volatility and unpredictability in commodity prices may result in fewer potential bidders, unsuccessful sales efforts, and a higher risk that buyers may seek to terminate a transaction prior to
Volatility in the financial markets or in global economic conditions, including consequences resulting from domestic political uncertainty, geopolitical events, international trade disputes and tariffs, and health epidemics could adversely impact our business.
United States and global economies may experience periods of volatility and uncertainty from time to time, resulting in unstable consumer confidence, diminished consumer demand and spending, diminished liquidity and credit availability, and inability to access capital markets. In recent years, certain global economies have experienced periods of political uncertainty, slowing economic growth, rising interest rates, inflation, changing economic sanctions, health-related concerns, and currency volatility. These global macroeconomic conditions may have a negative impact on commodity prices and the availability and cost of materials used in our industry, which in turn could have a material adverse effect on our business, financial condition, results of operations and cash flows.
Trade restrictions or other governmental actions related to tariffs or trade policies have impacted in the past, and have the potential to further impact, our business and industry by increasing the cost of materials used in various aspects of upstream, midstream, and downstream oil and gas activities. Furthermore, tariffs and any quantitative import restrictions, particularly those impacting the cost and availability of steel and aluminum, may cause disruption in the energy industry’sindustry's supply chain, resulting in the delay or cessation of drilling and completion efforts or the postponement or cancellation of new pipeline transportation projects the U.S. industry is relying on to transport its onshore production to market, as well as endangering U.S. liquefied natural gas export projects resulting in negative impacts on natural gas production. Additionally, trade and/or tariff disputes have impacted in the past, and have the potential to further impact, domestic and global economies overall, which could result in reduced demand for crude oil and natural gas. Any of the above consequences could have a material adverse effect on our business, financial condition, results of operations and cash flows.
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A cybercybersecurity incident could result in information theft, data corruption, operational disruption, and/or financial loss.
Our business and industry has become increasingly dependent on digital technologies to conduct day-to-day operations including certain exploration, development and production activities. We rely heavily on digital technologies, including information and operational systems and related infrastructure as well as cloud applications and services, to process and record financial and operating data; analyze seismic, drilling, completion and production information; manage production equipment; conduct reservoir modeling and reserves estimation; communicate with employees and business associates; perform compliance reporting and many other activities. The availability and integrity of these systems are essential for us to conduct our operations. Our business associates, including employees, vendors, service providers, financial institutions, and transporters, processors, and purchasers of our production are also heavily dependent on digital technology.
As dependence on digital technologies has increased, cybercybersecurity incidents, including deliberate attacks or unintentional events, have also increased.evolved and increased in frequency. Cybersecurity attacks are becoming more sophisticated and include, but are not limited to, malicious software, surveillance, credential stuffing, spear phishing, social engineering, use of deepfakes (i.e., highly realistic synthetic media generated by artificial intelligence), ransomware attacks, attempts to gain unauthorized access to data, and other electronic security breaches. Our technologies, systems, networks, and those of our business associates have been and continue to be the target of cybercybersecurity attacks or information security breaches, which could lead to disruptions in critical systems, unauthorized release or theft of confidential or protected information, corruption of data, interruption of operating activities, challenges in maintaining our books and records, environmental damage, communication interruptions or other disruptions of our business operations. For example, there have been well-publicized cases in recent years involving cybercybersecurity attacks on software vendors utilized by the Company. In response to those incidents, we deployed our cybersecurity incidence response protocols and promptly took steps to contain and remediate potential vulnerabilities. We believe there have been noAs of the date of this report, we are not aware of any material compromises to our operations as a result of the attacks; however, other similar attacks in the future could have a significant negative impact on our systems and operations.
A cybercybersecurity attack involving our information or operational systems and related infrastructure, and/or that of our business associates and customers, could disrupt our business and negatively impact our operations in a variety of ways, including but not limited to unauthorized access to, or theft of, confidential, sensitive or proprietary information, and data corruption, interruption of operating activities, challenges in maintaining our books and records, environmental damage, communication interruptions or operational disruption that adversely affects our ability to carry on our business. Any such event could damage our reputation and lead to financial losses from remedial actions, loss of business, legal claims or proceedings, litigation costs, regulatory investigations and enforcement, penalties and fines, increased costs for compliance requirements or potential liability, which could have a material adverse effect on our business, financial condition, results of operations or cash flows. In addition, certain cybercybersecurity incidents such as reconnaissance of our
While the Company has well-established cyber securitymaintains cybersecurity systems and controls, disclosure controls and procedures and incident response protocols, these systems, controls, procedures and protocols may not identify all risks and threats we face, or may fail to protect data or mitigate the adverse effects of data loss.
As of the date of this report, we havedo not believe that the Company has experienced any material losses relating to cybercybersecurity attacks; however, there can be no assurance that we will not suffer material losses in the future either as a result of a breach of our systems or those of our business associates. As cybercybersecurity threats continue to evolve, we may be required to expend significant additional resources to continue to modify or enhance our protective measures or to investigate and remediate any information security vulnerabilities. Additionally, the growth of cybercybersecurity attacks has resulted in evolving legal and compliance matters which may impose significant costs that are likely to increase over time.
Competition in the crude oil and natural gas industry is intense, making it more difficult for us to acquire properties, market crude oil and natural gas and secure trained personnel.
Our ability to acquire additional prospects and find and develop reserves in the future will depend on our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment for acquiring properties, securing long-term transportation and processing capacity, marketing crude oil and natural gas, and securing trained personnel. Also, there is substantial competition for capital available for investment in the crude oil and natural gas industry. Our competitors may possess and employ financial, technical and personnel resources greater than ours. Those companies may be able to pay more for productive crude oil and natural gas properties and exploratory prospects and to evaluate, bid for and purchase a greater number of properties and prospects than our financial or personnel resources permit. Our inability to effectively compete in this environment could have a material adverse effect on our financial condition, results of operations and cash flows.
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Severe climaticweather events and natural disasters could have a material adverse effect on our business, financial condition, results of operations and cash flows.
Severe climaticweather events and natural disasters such as hurricanes, tornadoes, seismic events, floods, blizzards, extreme cold, drought, and ice storms affecting the areas in which we operate, including our corporate headquarters, could cause disruptions and in some cases suspension of our or our third party service providers’providers' operations, which could have a material adverse effect on our business. Climate changes could result in increased frequency and severity of these climatic events, as well as chronic shifts in temperature and precipitation patterns. The consequences of such events may include the evacuation of personnel; damage to and disruption of production equipment, drilling rigs, or gathering, transportation, processing, storage, refining, and export facilities; delivery stoppages by third party vendors upon whom we rely upon for goods and services; the shut-in of production resulting from an inability to transport crude oil or natural gas products to market centers and other factors; an inability to access well sites; destruction of information and communication systems; and the disruption of administrative and management processes, any of which could hinder our ability to conduct normal operations and could adversely affect our business, financial condition, results of operations or cash flows. Our planning for normal climatic variation, natural disasters, insurance programs and emergency recovery plans may inadequately mitigate the effects of such climatic conditions, and not all such effects can be predicted, eliminated or insured against. Longer term changes in temperature and precipitation patterns may result in changes to the amount, timing, or location of demand for energy or our production. While our consideration of changing climatic conditions and inclusion of safetywe consider these factors in design is intended to reduce the uncertainties that climate change and other events may potentially introduce, our ability to mitigate the adverse impacts of these events depends in part on the effectiveness of our facilities and our disaster preparedness and response and business continuity planning, whichwe may not have consideredconsider or be preparedprepare for every eventuality.
Financial Risks
Our revolving credit facility containsand term loan contain restrictive covenants with which we must comply, including covenants that may limit our ability to, among other things, incur additional indebtedness, incur liens, engage in sale and leaseback transactions, and merge, consolidate or sell all or substantially all of our assets. Our revolving credit facility and term loan also containscontain a requirement that we maintain a consolidated net debt to total capitalization ratio of no greater than 0.65 to 1.00. This ratio represents the ratio of net debt (calculated as total face value of debt plus outstanding letters of credit less cash and cash equivalents) divided by the sum of net debt plus total shareholders’shareholders' equity plus, to the extent resulting in a reduction of total shareholders’shareholders' equity, the amount of any non-cash impairment charges incurred, net of any tax effect, after June 30, 2014. At December 31, 2021,2023, we had $500$210 million of outstanding borrowings and $2.04 billion of available borrowing capacity on our credit facility and our consolidated net debt to total capitalization ratio, as defined, was 0.43.0.37.
The indentures governing our senior notes contain covenants that, among other things, limit our ability to create liens securing certain indebtedness, enter into certain sale and leaseback transactions, and consolidate, merge or transfer certain assets.
Our ability to comply with the provisions of our revolving credit facility, term loan or senior note indentures may be impacted by changes in economic or business conditions, results of operations, or events beyond our control. The breach of any covenant could result in a default under our revolving credit facility, term loan or senior note indentures, in which case, depending on the actions taken by the lenders or trustees thereunder or their successors or assignees, could result in all amounts outstanding thereunder, together with accrued interest, to be due and payable. If our indebtedness is accelerated, our assets may not be sufficient to repay in full such indebtedness, which would have a material adverse effect our business, financial condition, results of operations, and cash flows.
The inability of joint interest owners, significant customers, and service providers to meet their obligations to us may adversely affect our financial results.
Our principal exposure to credit risk is through the sale of our crude oil and natural gas production, which we market to energy marketing companies, crude oil refining companies, and natural gas gathering and processing companies ($1.11.2 billion in receivables at December 31, 2021)2023) and our joint interest and other receivables ($279351 million at December 31, 2021)2023). These counterparties may experience insolvency or liquidity issues and may not be able to meet their obligations and liabilities owed to us, particularly during a period of depressed commodity prices. Defaults by these counterparties could adversely impact our financial condition and results of operations.
Legal and Regulatory Risks
Laws, regulations, guidance, executive actions or other regulatory initiatives regarding environmental protection and occupational safety and health could increase our costs of doing business and result in operating restrictions, delays, or cancellations in the drilling and completion of crude oil and natural gas wells, which could have a material adverse effect on our business, results of operations, financial condition and cash flows.
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Our crude oil and natural gas exploration and production operations are subject to stringent federal, state and local legal requirements governing environmental protection and occupational safety and health. These requirements may take the form of laws, regulations, executive actions and various other legal initiatives. See Part I, Item 1. Business—Regulation of the Crude Oil and Natural Gas Industry for a discussionsummary of thosecertain significant environmental and occupational safety and health legal requirements that govern us, including with respectus. Such requirements include those pertaining to air emissions, including natural gas flaring limitations and ozone standards; climate change, including restriction of methane or other greenhouse gas emissions and suspensions of, or more stringent limitations upon, new leasing and permitting on federal lands and waters; hydraulic fracturing; waste water disposal regulatory developments;disposal; occupational safety standards, and other risks or regulations relating to environmental protection. One or more of these legal requirements could have a material adverse effect on our business, financial condition, results of operations, and cash flows.
We are subject to certain complex federal, state and local laws and regulations in areas other than environmental protection and occupational safety and health that could result in increased costs, operating restrictions or delays, limitations or prohibitions on our ability to develop and produce reserves, or expose us to significant liabilities.
Our crude oil and natural gas exploration and production operations are subject to complex and stringent federal, state and local laws and regulations in areas other than environmental protection and occupational safety and health, including with respect to production, sales and transport of crude oil, NGLs and natural gas, and employees and labor relations. Following is a discussion of certain significant laws, rulesrelations, and regulations that affect us in these areas in which we operate. See Part I, Item 1. Business—Regulation of the Crude Oil and Natural Gas Industry for further discussion of the regulations that affect us.
Additionally, in August 2022 President Biden signed the IRA into law, which provides various tax provisions, incentives, and tax credits aimed at curbing inflation by lowering prescription drug costs, health care costs, and energy costs. The passage of such legislation or any other similar change in U.S. federal income tax law could adversely affect our business, financial condition, results of operations and cash flows.
Failure to comply with the above and other laws and regulations, including those summarized in Part I, Item 1. Business—Regulation of the Crude Oil and Natural Gas Industry, may trigger a variety of administrative, civil and criminal enforcement investigations or actions, including investigatory actions, the assessment of monetary penalties, the imposition of remedial requirements, the issuance of orders or judgments limiting or enjoining future operations, criminal sanctions, or litigation. Moreover, changes to existing laws or regulations or changes in interpretations of laws and regulations may unfavorably impact us or the infrastructure used for transporting our products. Similarly, changes in regulatory policies and
Our operations and the operations of our customers are subject to a number of risks arising out of the threat of climate change, energy conservation measures, or initiatives that stimulate demand for alternative forms of energy that could result in increased operating costs, limit the areas in which oil and natural gas production may occur, and reduce the demand for the crude oil and natural gas we produce.
Risks arising out of the threat of climate change, fuel conservation measures, governmental requirements for renewable energy resources, increasing consumer demand for alternative forms of energy, and technological advances in fuel economy and energy generation devices may create new competitive conditions that result in reduced demand for the crude oil and natural gas we produce. The potential impact of changing demand for crude oil and natural gas services and products may have a material adverse effect on our business, financial condition, results of operations and cash flows. Additionally, variability in power generation output from alternative energy facilities that are dependent on weather conditions, such as wind and solar, may result in intermittent changes in demand for the commodities we produce which could lead to increased volatility in commodity prices. See Part I, Item 1. Business—Regulation of the Crude Oil and Natural Gas Industry for further discussion relating to risks arising out of the threat of climate change and emission of greenhouse gases, climate change activism, energy conservation measures, initiatives that stimulate demand for alternative forms of energy, and physical effects of climate change. One or more of these developments could have an adverse effect on our assets and operations.
Increasing scrutiny on environmental, social, and corporate governance matters may impact our business.
Companies across all industries are facing increasing scrutiny from a wide array of stakeholders related to their ESG practices. ESG standards are evolving and if we are perceived to have not responded appropriately to certain standards, regardless of whether there is a legal requirement to do so, we may suffer from reputational damage and our business or financial condition, and/or stock price could be materially and
21
adversely affected. Increasing attention to climate change, increasing societal expectations on companies to address climate change, and potential consumer use of alternative forms of energy may result in increased costs, reduced demand for hydrocarbon products, reduced profits, increased investigations and litigation, and negative impacts on our stock price, our ability to recruit necessary talent, and our access to debt capital markets.
Institutional lenders who provide financing for fossil fuel energy companies also have become more attentive to sustainable lending practices that favor “clean” power sources such as wind and solar, making those sources more attractive for investment, and some of them may elect not to provide informationfunding for fossil fuel energy companies or impose certain ESG-related targets or goals as a condition to investors on corporate governance and related matters have developed ratings processes for evaluating companies on their approach to ESG matters. Currently, there are no universal standards for such scores or ratings and, in fact, different standards focus, to varying degrees, on different attributes of environmental, social, and corporate governance matters. This disparity between the “standards”funding. While we cannot predict what polices may result in investors focusing on inadequate or improper metrics which may lead to a misperception of a company and its ESG practices. Conversely, pressures to createfrom these developments, such efforts could make it more uniformity among these “standards” may result in a skewed and potentially misplaced focus on certain factors over other, equally valuable factors. For example, of the 17 United Nations Sustainability Goals, the vast majority fall within the societal component, but many sustainability “standards” provide little weight to these goals, instead emphasizing the environmental component. Nonetheless, the importance of sustainability evaluations is becoming more broadly accepted by investors and shareholders. ESG ratings are used by some investors to inform their investment and voting decisions. Additionally, certain investors use these scores to benchmark companies against their peers, and if a company is perceived as lagging, these investors may engage withdifficult for fossil fuel companies to require improved ESG disclosure or performance. Moreover, certain memberssecure funding as well as negatively affect the cost of, the broader investment community may consider a company’s sustainability score as a reputationaland terms for, financings to fund growth projects or other factor in making an investment decision. Consequently, a low sustainability score could result in exclusionaspects of our stock from consideration by certain investment funds, engagement by investors seeking to improve such scores, and a negative perception of our operations by certain investors.
Item 1B. Unresolved Staff Comments
Not applicable.
Item 1C. Cybersecurity
Our business and industry has become increasingly dependent upon digital technologies, including information and operational systems and related infrastructure as well as cloud applications and services, to process and record financial and operating data; analyze seismic, drilling, completion and production information; manage production equipment; conduct reservoir modeling and reserves estimation; communicate with employees and business associates; perform compliance reporting and many other activities. We recognize the importance of developing, implementing, and maintaining effective cybersecurity measures to safeguard our information systems and protect the confidentiality, integrity, and availability of our data. The Company has an Insider Threat and Data Loss Prevention program that is designed to protect the confidentiality, integrity and availability of such data, and we maintain processes designed to assess, identify, and manage material risks from cybersecurity threats.
The Company has a cybersecurity team with relevant subject-matter expertise that is part of the Company’s Information Technology department (the “Cybersecurity Team”). This team reports to the Company’s Vice President and Chief Information Officer (“CIO”) and is led by the Company’s Chief Information Security Officer (“CISO”), who has primary responsibility for oversight of the Company’s assessment, identification, and management of cybersecurity risks. The CISO has 27 years of cybersecurity experience, 17 of which are in the oil and gas industry. The Company’s CISO is certified in strategic planning, policy and leadership, and is one of less than 400 CISOs globally that has graduated from the FBI’s CISO Academy in Quantico, Virginia. The CIO and CISO jointly determine whether a given cybersecurity matter is sufficiently important to warrant elevating it to the attention of the Company’s Cybersecurity Executive Committee (defined below) and/or Board of Directors.
The Cybersecurity Team monitors the cybersecurity environment for threats and indicators of compromise. It also considers the risks attendant to the Company’s business operations and strategy and develops solutions and mitigation measures for the risks identified, including risks arising in connection with third-party interactions and the integration of newly acquired assets. In addition, the Company invests in Security Awareness training to help promote employee awareness of cybersecurity.
The Company’s internal cybersecurity efforts are supported by a team of outside consultants, assessors, and third-party vendors who assist with identifying and monitoring risks and indications of compromise.
The Cybersecurity Team regularly engages third-party assessors to conduct evaluations of the Company’s cybersecurity risk mitigation efforts and strategy. The Company also engages a third-party auditing firm to periodically assess our information security program. Audits are also conducted from time-to-time by other third parties, such as insurance adjusters and regulators.
The Cybersecurity Team engages third-party vendors to assist with managing endpoint security, managing the Company’s security operations center, providing threat detection and response capabilities, monitoring certain operational technology and control system environments, and providing threat detection and vulnerability identification and remediation services. Additionally, the Company is a member of the Oil and Natural Gas Information and Analysis Center. This center provides the Company with information regarding threats to the oil and gas industry and threats reported by other industry participants. Finally, the Cybersecurity Team periodically engages with the cybersecurity-related guidance of other third parties such as law enforcement, industry trade groups and vendors.
The Cybersecurity Team reviews the integrity of services provided by vendors engaged to support the Company’s cybersecurity efforts using the same methods as are used to evaluate the services provided by other vendors engaged to support the Company’s regular business operations.
22
The above cybersecurity risk management processes are integrated into the Company’s overall enterprise risk management program. Cybersecurity risks are understood to be significant business risks, and as such, are considered an important component of our enterprise-wide risk management approach.
Since the Company is private, it has no unresolved Securitiesindependent members of its Board of Directors. All of the Company’s directors are also executive officers. The body primarily responsible for oversight of the Cybersecurity Team is the Cybersecurity Executive Committee, which is composed of the Company’s President and Exchange Commission staff commentsChief Executive Officer; Executive Vice President, Chief Culture Officer and Administrative Officer (both of whom are also members of the Company’s Board of Directors); Chief Financial Officer and Executive Vice President of Strategic Planning; Senior Vice President, General Counsel and Secretary; CIO; Director of Corporate Security; and the Information Security Manager. The Cybersecurity Executive Committee meets regularly and during these meetings its members review and discuss cybersecurity information provided by the CISO, which may include: (i) metrics relevant to cybersecurity issues; (ii) summaries of changes or proposed changes to the Company’s cybersecurity program; and (iii) cybersecurity risk and threat updates. Information regarding any critical cybersecurity-related matter is communicated to the Cybersecurity Executive Committee as soon as practicable.
In addition, the CISO annually briefs the Company's Audit Committee regarding cybersecurity matters at December 31, 2021.
The Company has developed a Cybersecurity Incident Response Plan (the “Response Plan”), which is based upon NASA’s mission control incident response procedures to address and manage certain cybersecurity incidents. If an incident meets certain criteria, the incident response plan is invoked by the CISO and General Counsel. Once the plan is invoked, an impact assessment is conducted and a remediation plan is developed, if needed. The plan also sets forth procedures for monitoring incidents and post-incident follow-up so that any lessons learned can be discussed. Where appropriate, the post-incident follow up identifies measures that can be implemented to aid with future incident prevention and detection. Under the Response Plan any incident-related information is communicated using the channels outlined in the Response Plan.
As of the date of this report, though the Company and our service providers have experienced certain cybersecurity incidents, the Company does not believe any prior cybersecurity threat or incident has materially affected or are reasonably likely to materially affect the Company, including its business operations or prospects. However, the Company acknowledges that cybersecurity threats are continually evolving and the possibility of future cybersecurity incidents remains. Despite the implementation of our cybersecurity processes, our security measures cannot guarantee that a significant cyberattack will not occur. A successful attack on our information technology systems could have significant consequences for the business. While we devote resources to our security measures to protect our systems and information, these measures cannot provide absolute security. No security measure is infallible. For additional information about the risks to our business associated with cybersecurity incidents, please see “A cybersecurity incident could result in information theft, data corruption, operational disruption, and/or financial loss” under Part I, Item IA. Risk Factors.
Item 2. Properties
The information required by Item 2 is contained in Part I, Item 1. Business—Crude Oil and Natural Gas Operations and Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Delivery Commitments and is incorporated herein by reference.
Item 3. Legal Proceedings
We are involved in various legal proceedings including, but not limited to, commercial disputes, claims from royalty and surface owners, property damage claims, claims made by former shareholders in connection with the take-private transaction, antitrust claims related to the market price of hydrocarbons, personal injury claims, regulatory compliance matters, disputes with tax authorities and other matters. While the outcome of these legal matters cannot be predicted with certainty, we do not expect them to have a material effect on our financial condition, results of operations or cash flows.
Item 4. Mine Safety Disclosures
Not applicable.
23
Part II
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
Effective November 22, 2022, Continental Resources, Inc. became a privately held corporation and has no publicly available common stock is listed onshares outstanding at the New York Stock Exchange and trades under the symbol “CLR.” Astime of February 2, 2022, the number of record holders of our common stock was 1,269. On February 2, 2022, after inquiry, management believes that the number of beneficial owners of our common stock is 79,854. On February 2, 2022, the last reported sales price of our common stock, as reported on the New York Stock Exchange, was $55.08 per share.
The Company intendshas no dividend policy and currently has no plans to continue paying a quarterly dividend; however, any payment of futurepay cash dividends will be at the discretion of our Board of Directors and will depend on, among other things, our future earnings, financial condition, cash flows, capital requirements, levels of indebtedness, prevailing business conditions and other considerations our Board of Directors may deem relevant.
| Period | Total number of shares purchased | Average price paid per share | Total number of shares purchased as part of publicly announced plans or programs (1) | Maximum dollar value of shares that may yet be purchased under the plans or programs (in millions) (1) | ||||||||||||||||||||||
| October 1, 2021 to October 31, 2021 | ||||||||||||||||||||||||||
| Repurchases for tax withholdings (2) | 11,288 | $ | 52.13 | — | $ | — | ||||||||||||||||||||
| November 1, 2021 to November 30, 2021 | ||||||||||||||||||||||||||
| Repurchases for tax withholdings (2) | 41,154 | $ | 49.36 | — | $ | — | ||||||||||||||||||||
| Share repurchase program (1) | 1,102,682 | $ | 46.30 | 1,102,682 | $ | 566.5 | ||||||||||||||||||||
| Purchases by principal shareholder (3) | 108,500 | $ | 47.69 | — | $ | — | ||||||||||||||||||||
| December 1, 2021 to December 31, 2021 | ||||||||||||||||||||||||||
| Share repurchase program (1) | 179,820 | $ | 42.33 | 179,820 | $ | 558.9 | ||||||||||||||||||||
| Purchases by principal shareholder (3) | 367,020 | $ | 43.82 | — | $ | — | ||||||||||||||||||||
| Total for the quarter | 1,810,464 | $ | 45.59 | 1,282,502 | ||||||||||||||||||||||
| Exercise Price of Outstanding Options | Available for Future Issuance Under Equity Compensation Plans (1) | ||||||||||||||||||
ITEM 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
The following discussion and analysis should be read in conjunction with our consolidated financial statements and notes included elsewhere in this report. Results attributable to noncontrolling interests are not material relative to consolidated results and are not separately presented or discussed below.
The following discussion and analysis includes forward-looking statements and should be read in conjunction with Part I, Item 1A. Risk Factors in this report, along with Cautionary Statement for the Purpose of the “Safe Harbor” Provisions of the Private Securities Litigation Reform Act of 1995 at the beginning of this report, for information about the risks and uncertainties that could cause our actual results to be materially different than our forward-looking statements.
Overview
We are an independent crude oil and natural gas company engaged in the exploration, development, management, and production of crude oil and natural gas and associated products.products with properties primarily located in four leading basins in the United States – the Bakken field of North Dakota and Montana, the Anadarko Basin of Oklahoma, the Permian Basin of Texas, and the Powder River Basin of Wyoming. Additionally, we pursue the acquisition and management of perpetually owned minerals located in certain of our key operating areas. We derive the majority of our operating income and cash flows from the sale of crude oil, natural gas, and natural gas liquids and expect this to continue in the future.We are the largest leaseholder and the largest producer in the Bakken field of North Dakota and Montana. We also have significant positions in the SCOOP and STACK plays in Oklahoma and recently acquired positions in the Permian Basin of Texas and Powder River Basin of Wyoming.Our common stock trades on the New York Stock Exchange under the symbol “CLR” and our corporate internet website is www.clr.com.
Financial and Operating Metrics
Commodity prices have increased significantly in 2021 comparedremained volatile due to 2020 levels in response to the liftingvarious factors, some of COVID-19 restrictions, the resumption of normal economic activity, and the resulting improvement inwhich include global supply and demand, fundamentals. The increase in commodityglobal inventory levels, and regional conflicts. Average NYMEX oil prices for the years ended December 31, 2023, 2022, and resumption of our operations resulted in significantly improved operating results in 2021 compared to 2020 as further described below.
| Year ended December 31, |
| ||||||||||
| 2023 |
|
| 2022 |
|
| 2021 |
| ||||
Average daily production: |
|
|
|
|
|
|
|
|
| |||
Crude oil (Bbl per day) |
|
| 232,083 |
|
|
| 199,526 |
|
|
| 160,647 |
|
Natural gas (Mcf per day) (1) |
|
| 1,248,488 |
|
|
| 1,213,643 |
|
|
| 1,014,000 |
|
Crude oil equivalents (Boe per day) |
|
| 440,164 |
|
|
| 401,800 |
|
|
| 329,647 |
|
Average sales prices: |
|
|
|
|
|
|
|
|
| |||
Crude oil ($/Bbl) |
| $ | 76.89 |
|
| $ | 94.95 |
|
| $ | 67.21 |
|
Natural gas ($/Mcf) (1) |
| $ | 2.60 |
|
| $ | 7.15 |
|
| $ | 4.98 |
|
Production expenses ($/Boe) |
| $ | 4.47 |
|
| $ | 4.24 |
|
| $ | 3.38 |
|
Production and ad valorem taxes (% of net crude oil and natural gas sales) |
|
| 8.2 | % |
|
| 7.5 | % |
|
| 7.3 | % |
DD&A ($/Boe) |
| $ | 14.11 |
|
| $ | 12.86 |
|
| $ | 15.76 |
|
Total general and administrative expenses ($/Boe) |
| $ | 1.74 |
|
| $ | 2.74 |
|
| $ | 1.94 |
|
| Year ended December 31, | ||||||||||||||||||||
| 2021 | 2020 | 2019 | ||||||||||||||||||
| Average daily production: | ||||||||||||||||||||
| Crude oil (Bbl per day) | 160,647 | 160,505 | 197,991 | |||||||||||||||||
| Natural gas (Mcf per day) | 1,014,000 | 837,509 | 854,424 | |||||||||||||||||
| Crude oil equivalents (Boe per day) | 329,647 | 300,090 | 340,395 | |||||||||||||||||
| Average net sales prices: (1) | ||||||||||||||||||||
| Crude oil ($/Bbl) | $ | 64.06 | $ | 34.71 | $ | 51.82 | ||||||||||||||
| Natural gas ($/Mcf) | $ | 4.88 | $ | 1.04 | $ | 1.77 | ||||||||||||||
| Crude oil equivalents ($/Boe) | $ | 46.24 | $ | 21.47 | $ | 34.56 | ||||||||||||||
| Crude oil net sales price discount to NYMEX ($/Bbl) | $ | (4.00) | $ | (5.80) | $ | (5.15) | ||||||||||||||
| Natural gas net sales price premium (discount) to NYMEX ($/Mcf) | $ | 1.00 | $ | (1.10) | $ | (0.86) | ||||||||||||||
| Production expenses ($/Boe) | $ | 3.38 | $ | 3.27 | $ | 3.58 | ||||||||||||||
| Production taxes (% of net crude oil and natural gas sales) | 7.3 | % | 8.2 | % | 8.3 | % | ||||||||||||||
| DD&A ($/Boe) | $ | 15.76 | $ | 17.12 | $ | 16.25 | ||||||||||||||
| Total general and administrative expenses ($/Boe) | $ | 1.94 | $ | 1.79 | $ | 1.57 | ||||||||||||||
25
Results of Operations
The following table presents selected financial and operating information for the periods presented.
| Year Ended December 31, | ||||||||||||||||||||
| In thousands, except sales price data | 2021 | 2020 | 2019 | |||||||||||||||||
| Crude oil and natural gas sales | $ | 5,793,741 | $ | 2,555,434 | $ | 4,514,389 | ||||||||||||||
| Gain (loss) on derivative instruments, net | (128,864) | (14,658) | 49,083 | |||||||||||||||||
| Crude oil and natural gas service operations | 54,441 | 45,694 | 68,475 | |||||||||||||||||
| Total revenues | 5,719,318 | 2,586,470 | 4,631,947 | |||||||||||||||||
| Operating costs and expenses | (3,257,638) | (3,140,362) | (3,374,535) | |||||||||||||||||
| Other expenses, net | (275,542) | (220,859) | (270,250) | |||||||||||||||||
| Income (loss) before income taxes | 2,186,138 | (774,751) | 987,162 | |||||||||||||||||
| (Provision) benefit for income taxes | (519,730) | 169,190 | (212,689) | |||||||||||||||||
| Net income (loss) | 1,666,408 | (605,561) | 774,473 | |||||||||||||||||
| Net income (loss) attributable to noncontrolling interests | 5,440 | (8,692) | (1,168) | |||||||||||||||||
| Net income (loss) attributable to Continental Resources | $ | 1,660,968 | $ | (596,869) | $ | 775,641 | ||||||||||||||
| Diluted net income (loss) per share attributable to Continental Resources | $ | 4.56 | $ | (1.65) | $ | 2.08 | ||||||||||||||
| Production volumes: | ||||||||||||||||||||
| Crude oil (MBbl) | 58,636 | 58,745 | 72,267 | |||||||||||||||||
| Natural gas (MMcf) | 370,110 | 306,528 | 311,865 | |||||||||||||||||
| Crude oil equivalents (MBoe) | 120,321 | 109,833 | 124,244 | |||||||||||||||||
| Sales volumes: | ||||||||||||||||||||
| Crude oil (MBbl) | 58,757 | 58,793 | 72,136 | |||||||||||||||||
| Natural gas (MMcf) | 370,110 | 306,528 | 311,865 | |||||||||||||||||
| Crude oil equivalents (MBoe) | 120,442 | 109,881 | 124,113 | |||||||||||||||||
| Year Ended December 31, |
| ||||||||||
In thousands |
| 2023 |
|
| 2022 |
|
| 2021 |
| |||
Crude oil, natural gas, and natural gas liquids sales |
| $ | 7,684,263 |
|
| $ | 10,074,675 |
|
| $ | 5,793,741 |
|
Gain (loss) on derivative instruments, net |
|
| 943,768 |
|
|
| (671,095 | ) |
|
| (128,864 | ) |
Crude oil and natural gas service operations |
|
| 103,710 |
|
|
| 70,128 |
|
|
| 54,441 |
|
Total revenues |
|
| 8,731,741 |
|
|
| 9,473,708 |
|
|
| 5,719,318 |
|
Operating costs and expenses |
|
| (4,419,008 | ) |
|
| (4,120,028 | ) |
|
| (3,257,638 | ) |
Other expenses, net |
|
| (383,786 | ) |
|
| (285,267 | ) |
|
| (275,542 | ) |
Income before income taxes |
|
| 3,928,947 |
|
|
| 5,068,413 |
|
|
| 2,186,138 |
|
Provision for income taxes |
|
| (827,630 | ) |
|
| (1,020,804 | ) |
|
| (519,730 | ) |
Income before equity in net loss of affiliate |
|
| 3,101,317 |
|
|
| 4,047,609 |
|
|
| 1,666,408 |
|
Equity in net loss of affiliate |
|
| (3,129 | ) |
|
| (1,489 | ) |
|
| — |
|
Net income |
|
| 3,098,188 |
|
|
| 4,046,120 |
|
|
| 1,666,408 |
|
Net income attributable to noncontrolling interests |
|
| 2,361 |
|
|
| 21,562 |
|
|
| 5,440 |
|
Net income attributable to Continental Resources |
| $ | 3,095,827 |
|
| $ | 4,024,558 |
|
| $ | 1,660,968 |
|
|
|
|
|
|
|
|
|
| ||||
Production volumes: |
|
|
|
|
|
|
|
|
| |||
Crude oil (MBbl) |
|
| 84,710 |
|
|
| 72,827 |
|
|
| 58,636 |
|
Natural gas (MMcf) |
|
| 455,698 |
|
|
| 442,980 |
|
|
| 370,110 |
|
Crude oil equivalents (MBoe) |
|
| 160,660 |
|
|
| 146,657 |
|
|
| 120,321 |
|
Sales volumes: |
|
|
|
|
|
|
|
|
| |||
Crude oil (MBbl) |
|
| 84,508 |
|
|
| 72,732 |
|
|
| 58,757 |
|
Natural gas (MMcf) |
|
| 455,698 |
|
|
| 442,980 |
|
|
| 370,110 |
|
Crude oil equivalents (MBoe) |
|
| 160,457 |
|
|
| 146,562 |
|
|
| 120,442 |
|
Year ended December 31, 20212023 compared to the year ended December 31, 2020
Below is a discussion of changes in our results of operations for 20212023 compared to 2020.2022. A discussion of changes in our results of operations for 20202022 compared to 20192021 has been omitted from this Form 10-K, but may be found in Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations of our Form 10-K for the year ended December 31, 20202022 as filed with the SEC on February 16, 2021.22, 2023.
Production
The following table summarizes the changes in our average daily Boe production by major operating area for the periods presented.
| Fourth Quarter | Year Ended December 31, | |||||||||||||||||||||||||||||||||||||
| Boe production per day | 2021 | 2020 | % Change | 2021 | 2020 | % Change | ||||||||||||||||||||||||||||||||
| Bakken | 175,585 | 183,141 | (4 | %) | 169,636 | 158,604 | 7 | % | ||||||||||||||||||||||||||||||
| Oklahoma | 146,131 | 149,341 | (2 | %) | 147,249 | 134,506 | 9 | % | ||||||||||||||||||||||||||||||
| Powder River Basin | 7,189 | — | — | % | 5,161 | — | — | % | ||||||||||||||||||||||||||||||
| Permian Basin (1) | 4,997 | — | — | % | 1,260 | — | — | % | ||||||||||||||||||||||||||||||
| All other | 6,266 | 6,825 | (8 | %) | 6,341 | 6,980 | (9 | %) | ||||||||||||||||||||||||||||||
| Total | 340,168 | 339,307 | — | % | 329,647 | 300,090 | 10 | % | ||||||||||||||||||||||||||||||
(1)
| Fourth Quarter |
|
| Year Ended December 31, |
| |||||||||||||||||||
Boe production per day |
| 2023 |
|
| 2022 |
|
| % Change |
|
| 2023 |
|
| 2022 |
|
| % Change |
| ||||||
Bakken |
|
| 220,428 |
|
|
| 174,397 |
|
|
| 26 | % |
|
| 202,610 |
|
|
| 171,025 |
|
|
| 18 | % |
Anadarko Basin |
|
| 144,158 |
|
|
| 165,225 |
|
|
| (13 | )% |
|
| 153,426 |
|
|
| 158,221 |
|
|
| (3 | )% |
Powder River Basin |
|
| 25,577 |
|
|
| 28,057 |
|
|
| (9 | )% |
|
| 23,757 |
|
|
| 24,602 |
|
|
| (3 | )% |
Permian Basin |
|
| 58,601 |
|
|
| 44,925 |
|
|
| 30 | % |
|
| 54,651 |
|
|
| 41,917 |
|
|
| 30 | % |
All other |
|
| 5,666 |
|
|
| 5,552 |
|
|
| 2 | % |
|
| 5,720 |
|
|
| 6,035 |
|
|
| (5 | )% |
Total |
|
| 454,430 |
|
|
| 418,156 |
|
|
| 9 | % |
|
| 440,164 |
|
|
| 401,800 |
|
|
| 10 | % |
The presentation of average daily production represents production during the period from the closing of our acquisition of Permian properties on December 21, 2021 through December 31, 2021 averaged over the respective fourth quarter and full year periods. At the time of closing, our Permian properties produced on average approximately 42,000 Boe per day based on two-stream reporting.
The following tables reflecttable summarizes the changes in our production by product and region for the periods presented.
| Year Ended December 31, |
|
|
|
|
| Volume |
| ||||||||||||||||
| 2023 |
|
| 2022 |
|
| Volume |
|
| percent |
| |||||||||||||
| Volume |
|
| Percent |
|
| Volume |
|
| Percent |
|
| increase |
|
| increase |
| |||||||
Crude oil (MBbl) |
|
| 84,710 |
|
|
| 53 | % |
|
| 72,827 |
|
|
| 50 | % |
|
| 11,883 |
|
|
| 16 | % |
Natural gas (MMcf) |
|
| 455,698 |
|
|
| 47 | % |
|
| 442,980 |
|
|
| 50 | % |
|
| 12,718 |
|
|
| 3 | % |
Total (MBoe) |
|
| 160,660 |
|
|
| 100 | % |
|
| 146,657 |
|
|
| 100 | % |
|
| 14,003 |
|
|
| 10 | % |
26
| Year Ended December 31, | Volume increase (decrease) | Volume percent increase (decrease) | ||||||||||||||||||||||||||||||||||||
| 2021 | 2020 | |||||||||||||||||||||||||||||||||||||
| Volume | Percent | Volume | Percent | |||||||||||||||||||||||||||||||||||
| Crude oil (MBbl) | 58,636 | 49 | % | 58,745 | 53 | % | (109) | — | % | |||||||||||||||||||||||||||||
| Natural gas (MMcf) | 370,110 | 51 | % | 306,528 | 47 | % | 63,582 | 21 | % | |||||||||||||||||||||||||||||
| Total (MBoe) | 120,321 | 100 | % | 109,833 | 100 | % | 10,488 | 10 | % | |||||||||||||||||||||||||||||
| Year Ended December 31, | Volume increase | Volume percent increase | ||||||||||||||||||||||||||||||||||||
| 2021 | 2020 | |||||||||||||||||||||||||||||||||||||
| MBoe | Percent | MBoe | Percent | |||||||||||||||||||||||||||||||||||
| North Region | 66,105 | 55 | % | 60,591 | 55 | % | 5,514 | 9 | % | |||||||||||||||||||||||||||||
| South Region | 54,216 | 45 | % | 49,242 | 45 | % | 4,974 | 10 | % | |||||||||||||||||||||||||||||
| Total | 120,321 | 100 | % | 109,833 | 100 | % | 10,488 | 10 | % | |||||||||||||||||||||||||||||
The 16% increase in crude oil production in 2023 compared to 2022 was primarily driven by new well completions in the Bakken field over the past year, we increasedwhich led to an increase of 7,939 MBbls, or 19%, compared to 2022. The increase was also driven by our allocation of capital to gas-weighted projects to capitalize on improvementsproperty acquisitions and subsequent new well completions in market prices for natural gas and natural gas liquids. These actionsthe Permian Basin over the past year, which contributed to an increase in our natural gas2023 production by 3,275 MBbls, or 28%, compared to 2022. Additionally, as a percentageresult of totalnew well completions over the past year our crude oil production and ledincreased 1,240 MBbls, or 11%, in the Anadarko Basin in 2023 compared to 2022. These increases were partially offset by a 21%467 MBbls, or 8%, decrease in crude oil production in the Powder River Basin due to variation in the timing of new well completions between years.
The 3% increase in natural gas production in 20212023 compared to 2020. Natural gas production2022 was primarily driven by new well completions in Oklahoma increased 37,345the Bakken field over the past year, which led to an increase of 21,534 MMcf, or 18%17%, compared to 2022. The increase was also driven by our property acquisitions and subsequent new well completions in the Permian Basin over the past year, which contributed to an increase in our 2023 production by 8,240 MMcf, or 40%, compared to 2022. These increases were partially offset by a 17,943 MMcf, or 6%, decrease in natural gas production in the Bakken increased 23,122 MMcf, or 23%, over the prior year. Additionally, properties acquired in the Powder RiverAnadarko Basin in March and November 2021 added 2,517 MMcfdue to our natural gas production, while properties acquired in the Permian Basin added 614 MMcf during the short duration of our ownership of the properties in late 2021.
Revenues
Our revenues consist of sales of crude oil, natural gas, and natural gas liquids, gains and losses resulting from changes in the fair value of our derivative instruments, and revenues associated with crude oil and natural gas service operations.
Net crudeCrude oil, natural gas, and natural gas liquids sales. Sales for 2023 totaled $7.68 billion, a 24% decrease compared to sales and related netof $10.07 billion for 2022 due to decreases in sales prices, presented below are non-GAAP measures. See the subsequent section titled Non-GAAP Financial Measures for discussion and calculation of these measures.
Total sales volumes for 20212023 increased 10,56113,895 MBoe, or 10%9%, compared to 2020, reflecting reduced sales in2022 due to additional drilling and completion activities and new wells added from our property acquisitions over the prior period from the previously described production curtailments in the second and third quarters of 2020 and our subsequent resumption of usual operations.past year. For 2021,2023, our crude oil sales volumes were flatincreased 16% compared to 2020, while2022 and our natural gas sales volumes increased 21% driven by our increased allocation of capital toward gas-weighted projects over the past year.
Our crude oil net sales prices averaged $64.06$76.89 per barrel for 2021, an increase2023, a decrease of 85%19% compared to $34.71$94.95 per barrel for 20202022 due to a significant increasedecrease in market prices driven by improved supply and demand fundamentals along with improved price differentials. The differentialresulting from changes in various macroeconomic conditions between NYMEX West Texas Intermediate calendar month crude oil prices and our realized crude oil netperiods.
Our natural gas sales prices averaged $4.00 per barrel in 2021 compared to $5.80 per barrel in 2020. Crude oil prices for 2020 were severely impacted by adverse changes in supply and demand fundamentals from the economic effects of the COVID-19 pandemic, which negatively impacted location differentials and price realizations in the 2020 period with no similar impacts in 2021.
Derivatives. The significant improvement inReduced commodity prices in 20212023 had an overall unfavorablefavorable impact on the fair value of our derivatives, which resulted in negativepositive revenue adjustments of $128.9$943.8 million for the year, representing $149.7$257.2 million of realized cash losses partially offset by $20.8gains and $686.6 million of unsettled non-cash gains. For 2020, we recognizedgains, compared to negative revenue adjustments of $14.7totaling $671.1 million resulting from changes in market prices that had an unfavorable impact on the fair value of our derivatives. 2022.
Crude oil and natural gas service operations. Our crude oil and natural gas service operations consist primarily of revenues associated with water gathering, recycling, delivery, and disposal activities, which are impacted by our production volumes and the timing and extent of our drilling and completion projects. Revenues associated with such activities increased $8.7$33.6 million, or 19%48%, from $45.7$70.1 million for 20202022 to $54.4$103.7 million for 20212023 due to increased water handling activities resulting from increases in completion activities and production volumes compared to 2020.2022, which also contributed to an increase in service-related operating expenses in the current year.
Operating Costs and Expenses
Production expenses. Production expenses increased $47.6$95.6 million, or 13%15%, to $406.9$717.5 million for 20212023 compared to $359.3$621.9 million for 2020 primarily2022 due to the previously described 10%an increase in total sales volumes.the number of producing wells from drilling activities and property acquisitions, cost inflation for services and materials, and higher workover-related activities aimed at enhancing production from producing properties. Production expenses on a per-Boe basis averaged $3.38$4.47 per Boe for 2021, consistent with $3.272023 compared to $4.24 per Boe for 2020.2022, the increase of which reflects higher workover-related activities, cost inflation, and a higher proportion of production coming from oil-weighted properties over the past year which typically have higher per-unit operating costs compared to gas-weighted properties.
Production and ad valorem taxes. Production and ad valorem taxes increased $211.6decreased $126.6 million, or 110%17%, to $404.4$603.5 million for 20212023 compared to $192.7$730.1 million for 20202022 due to the previously described increasedecrease in crude oil, and natural gas, sales partially offset by a decrease in our average production tax rate.and NGL sales. Our production taxes as a percentage of net sales averaged 8.2% for 2023 compared to 7.5% for 2022. This increase was the result of changes in sales mix of crude oil and natural gas sales decreasedin the Company's operating areas between periods.
Transportation, gathering, processing, and compression. These charges increased $21.8 million, or 7%, to 7.3%$338.2 million for 20212023 compared to 8.2%$316.4 million for 20202022 primarily resulting from andue to our 9% increase in the proportiontotal sales volumes.
27
Depreciation, depletion, amortization and accretion (“DD&A”). Total DD&A amounted to $1.90$2.26 billion for 2021, consistent with $1.882023, an increase of $378.9 million, or 20%, compared to $1.89 billion for 2020,2022, reflecting a 10%9% increase in total sales volumes the impact of which was nearly offset by a decreaseas well as an increase in our DD&A rate per Boe as further discussed below. The following table shows the components of our DD&A on a unit of sales basis for the periods presented.
| Year ended December 31, | ||||||||||||||
| $/Boe | 2021 | 2020 | ||||||||||||
| Crude oil and natural gas properties | $ | 15.45 | $ | 16.84 | ||||||||||
| Other equipment | 0.22 | 0.19 | ||||||||||||
| Asset retirement obligation accretion | 0.09 | 0.09 | ||||||||||||
| Depreciation, depletion, amortization and accretion | $ | 15.76 | $ | 17.12 | ||||||||||
| Year ended December 31, |
| ||||||
$/Boe |
| 2023 |
|
| 2022 |
| ||
Crude oil and natural gas properties |
| $ | 13.58 |
|
| $ | 12.57 |
|
Other equipment |
|
| 0.44 |
|
|
| 0.20 |
|
Asset retirement obligation accretion |
|
| 0.09 |
|
|
| 0.09 |
|
Depreciation, depletion, amortization and accretion |
| $ | 14.11 |
|
| $ | 12.86 |
|
Estimated proved reserves are a key component in our computation of DD&A expense. Proved reserves are determined using the unweighted arithmetic average of the first-day-of-the-month commodity prices for the preceding twelve months as required by SEC rules. Holding all other factors constant, if proved reserves are revised downward due to commodity price declines or other reasons, the rate at which we record DD&A expense increases. Conversely, if proved reserves are revised upward, the rate at which we record DD&A expense decreases.
Our proved reserves werehave been revised upward in 2021downward over the past year prompted by significant increasesdecreases in first-day-of-the-month commodity prices and other factors, which resulted in a decreasean increase in our DD&A rate for crude oil and natural gas properties in the current period. As a result of these upward revisions, our2023 compared to 2022. Our DD&A rate decreased to $14.34totaled $15.76 per Boe for the 20212023 fourth quarter compared to $19.01 per Boe for the 2020 fourth quarter, the impact of which helped offset higher DD&A recognized in 2021 from increased sales volumes.
Property impairments. Property impairments decreased $239.6$3.6 million to $38.4$66.8 million for 20212023 compared to $277.9$70.4 million for 2020, primarily reflecting lower2022 due in part to $17.5 million of proved property impairments recognized in the current period. No2022 compared to $15.5 million of proved property impairments werebeing recognized in 2021 as estimated future net cash flows were determined to be in excess of cost basis due to improved commodity prices, while proved property impairments totaled $207.1 million in 2020.2023. Additionally, impairments of unproved properties decreased $32.5$1.6 million in 20212023 compared to 20202022 reflecting a decrease in the amortization of undeveloped leasehold costs from changes in management's estimates of properties not expected to be developed before lease expiration in response to significantly improved commodity prices compared toover the priorpast year. Our unamortized balance of unproved properties increased significantly in late 2021 in connection with our 2021 fourth quarter property acquisitions and now totals $1.36 billion at December 31, 2021. Accordingly, our amortized impairments of unproved property costs are expected to increase in 2022 relative to 2021 levels, the amount of which is uncertain.
General and administrative ("(“G&A"&A”) expenses. G&A expenses increased $37.0decreased $122.3 million, or 19%30%, to $233.6$279.3 million for 20212023 compared to $196.6$401.6 million for 2020.2022.
Total G&A expenses include non-cash charges for incentive compensation/prior equity compensationawards of $63.2$91.3 million and $64.6$217.7 million for 20212023 and 2020,2022, respectively. This decrease was primarily driven by the prior year remeasurement of cumulative compensation expense on restricted stock awards that were replaced with new liability-classified awards in conjunction with the Hamm Family’s take-private transaction. The remeasurement in 2022 resulted in the recognition of additional non-cash equity/incentive compensation expense totaling $136 million ($0.93 per Boe), reflecting the increase in the value of the awards from the original grant date to the November 2022 modification date.
G&A expenses other than incentive compensation/prior equity compensationawards totaled $170.4$188.0 million for 2021,2023, an increase of $38.4$4.2 million, or 29%2%, compared to $132.0$183.8 million for 20202022 primarily due to an increasethe growth of our operations and increases in payroll costs and employee benefits, partially offset by higher overhead recoveries from joint interest owners driven by increased drilling, completion, and production activities compared to 2020.
The following table shows the components of G&A expenses on a unit of sales basis for the periods presented.
| Year ended December 31, | ||||||||||||||
| $/Boe | 2021 | 2020 | ||||||||||||
| General and administrative expenses | $ | 1.42 | $ | 1.20 | ||||||||||
| Non-cash equity compensation | 0.52 | 0.59 | ||||||||||||
| Total general and administrative expenses | $ | 1.94 | $ | 1.79 | ||||||||||
| Year ended December 31, |
| ||||||
$/Boe |
| 2023 |
|
| 2022 |
| ||
General and administrative expenses |
| $ | 1.17 |
|
| $ | 1.25 |
|
Incentive compensation/prior equity awards |
|
| 0.57 |
|
|
| 1.49 |
|
Total general and administrative expenses |
| $ | 1.74 |
|
| $ | 2.74 |
|
Transaction costs. WeIn 2022, we incurred $13.9$32 million of expenses in connection with our December 2021 acquisition of properties inlegal and advisory fees related to the Permian Basin,Hamm Family's take-private transaction, which are reflectedincluded in the caption “Acquisition costs”"Transaction costs" in the consolidated statements of comprehensive income (loss) for 2021.2022, with no similar charges being incurred in 2023.
Interest expense. Interest expense decreased $6.6increased $95.1 million, or 3%32%, to $251.6$395.8 million for 20212023 compared to $258.2$300.7 million for 20202022 due to a decreasean increase in our annual weighted average outstanding debt balance from $5.8$6.8 billion in 20202022 to $5.6$7.9 billion in 2021.2023 coupled with an increase in the variable interest rates incurred on outstanding credit facility and term loan borrowings. Our outstanding debt totaled $6.8$6.6 billion at December 31, 2021, reflecting an increase of $2.1 billion in the 2021 fourth quarter due to credit facility and senior note borrowings incurred to fund a portion of our December 2021 acquisition of properties in the Permian Basin.2023.
Income Taxes. For 2021 and 2020 weWe provided for income taxes at a combined federal and state tax rate of 24.5% of pre-tax income/loss.23.5% for both 2023 and 2022. We recorded an income tax provisionprovisions of $519.7$827.6 million and an income tax benefit of $169.2 million$1.02 billion for 20212023 and 2020,2022, respectively, which resulted in effective tax rates of 23.8%
28
21.1% and 21.8%20.1%, respectively, after taking into account the application of statutory tax rates, permanent taxable differences, estimated tax effects from equity compensation, changes in valuation allowances,credits, and other items. See Part II, Item 8. Notes to Consolidated Financial Statements—Note 11. Income Taxes for a summary of the sources and tax effects of items comprising our income tax provision and resulting effective tax rates for 20212023 and 2020.2022.
Liquidity and Capital Resources
Our primary sources of liquidity have historically been cash flows generated from operating activities, financing provided by our credit facility and the issuance of debt securities. Additionally, asset dispositions and joint development arrangements have provided a source of cash flow for use in reducing debt and enhancing liquidity. We are committed to operating in a responsible manner to preserve financial flexibility, liquidity, and the strength of our balance sheet.
At January 31, 2022,February 1, 2024, we had approximately $1.76$2.2 billion of borrowing availability under our credit facility after considering outstanding borrowings and letters of credit, which represents a $260 million increase in availability compared to year-end 2021.credit. Our credit facility, which is unsecured and has no borrowing base subject to redetermination, does not mature until October 2026.
Based on our planned capital spending, including our pending property acquisition described below, our forecasted cash flows, and projected levels of indebtedness, we expect to maintain compliance with the covenants under our credit facility, term loan, and senior note indentures. Further, based on current market indications, we expect to meet our contractual cash commitments to third parties subsequently described under the heading Future Capital Requirements, recognizing we may be required to meet such commitments even if our business plan assumptions were to change. We monitor our capital spending closely based on actual and projected cash flows and have the ability to reduce spending or dispose of assets if needed to preserve liquidity and financial flexibility to fund our operations.
Cash Flows
Cash flows from operating activities
Net cash provided by operating activities increased $2.55decreased $2.0 billion, or 179%28%, to $3.97$5.06 billion for 20212023 compared to $1.42$7.04 billion for 2020 primarily due to2022. The decrease was driven by a $3.24$2.39 billion increasedecrease in crude oil, and natural gas, and NGL revenues due to the previously described increasesdecrease in commodity prices and natural gas sales volumesincreases in the current period. This increase was partially offset by a $211.6 million increase in production taxes associated with higher crude oil and natural gas revenues and a $121.5 million increase in realized cash losses on matured commodity derivatives in the current period. Additionally, we experienced an increase in certain other cash operating expenses primarily due to an increase in totalassociated with increased sales volumes whichand the growth of our Company over the past year. Increased cash operating expenses included a $47.6$96 million increase in production expenses, and a $28.3$22 million increase in transportation, expenses.
Cash flows used in investing activities
Net cash used in investing activities totaled $4.99 billion and $1.51$3.56 billion for 20212023, consistent with $3.53 billion for 2022. Our investing cash flows for 2023 included $3.55 billion of exploration and 2020, respectively,development costs compared to $2.84 billion of exploration and development costs for 2022, reflecting a planned increase in budgeted spending. This increase in spending was partially offset by lower acquisitions of producing crude oil and natural gas properties, with $161 million acquired in 2023 compared to $422 million acquired in 2022, as well as increased proceeds from the $3.48 billion increasesale of which reflects our 2021 property acquisition activities discussedassets with $390 million of proceeds received in Part II, Item 8. Notes2023 compared to Consolidated Financial Statements—Note 2. Property Acquisitions and Dispositions.$6 million of proceeds received in 2022. Additionally, contributions to unconsolidated affiliates decreased $178 million from $212 million in 2022 to $34 million in 2023.
Cash flows from financing activities
Net cash provided byused in financing activities for 20212023 totaled $989.1 million,$1.61 billion, primarily consisting of $1.59 billion$950 million of net proceeds received fromrepayments on our November 2021 issuancescredit facility, $636 million of cash used to redeem senior notes and $340$31 million of net credit facility borrowings incurredcash distributed to noncontrolling interests.
Net cash used in financing activities for 2022 totaled $3.39 billion, primarily consisting of $4.3 billion of cash used to fund a portion of our December 2021 Permian Basin acquisition. These increases were partially offset by $630.8the Hamm Family's take-private transaction, $284 million of senior note redemptions during the year, $123.9cash dividends paid on common stock, $100 million of cash used to repurchase shares of our common stock prior to the take-private transaction, and $165.9 million of cash dividends paid on common stock.
29
Future Sources of Financing
Although we cannot provide any assurance, we believe funds from operating cash flows, our cash balance, and availability under our credit facility should be sufficient to meet our normal operating needs, debt service obligations, budgeted capital expenditures, the pending property acquisition described below,and cash payments for income taxes and dividend payments for at least the next 12 months and to meet our contractual cash commitments to third parties described under the heading Future Capital Requirements beyond 12 months.
Based on current market indications supported by cash flow protection provided by our hedge portfolio against commodity price declines, our budgeted capital spending plans for 20222024 are expected to be funded from operating cash flows. Any deficiencies in operating cash flows relative to budgeted spending are expected to be funded by borrowings under our credit facility. If cash flows are materially impacted by declines in commodity prices, we have the ability to reduce our capital expenditures or utilize the availability of our credit facility if needed to fund our operations and business plans.
We may choose to access banking or debt capital markets for additional financing or capital to fund our operations or take advantage of business opportunities that may arise. Further, we may sell assets or enter into strategic joint development opportunities in order to obtain funding if such transactions can be executed on satisfactory terms. However, no assurance can be given that such transactions will occur.
We have an unsecured credit facility, maturing in October 2026, with aggregate lender commitments totaling $2.0$2.255 billion. The commitments are from a syndicate of 1213 banks and financial institutions. We believe each member of the current syndicate has the capability to fund its commitment. As of January 31, 2022, we had $1.76 billion of borrowing availability on our credit facility after considering outstanding borrowings and letters of credit.
The commitments under our credit facility are not dependent on a borrowing base calculation subject to periodic redetermination based on changes in commodity prices and proved reserves. Additionally, downgrades or other negative rating actions with respect to our credit rating do not trigger a reduction in our current credit facility commitments, nor do such actions trigger a security requirement or change in covenants. Downgrades of our credit rating will, however, trigger increases in our credit facility's interest rates and commitment fees paid on unused borrowing availability under certain circumstances.
Our credit facility contains restrictive covenants that may limit our ability to, among other things, incur additional indebtedness, incur liens, engage in sale and leaseback transactions, or merge, consolidate or sell all or substantially all of our assets. Our credit facility also contains a requirement that we maintain a consolidated net debt to total capitalization ratio of no greater than 0.65 to 1.00. See Part II, Item 8. Notes to Consolidated Financial Statements—Note 8. Long-Term Debt for a discussion of how this ratio is calculated pursuant to our credit agreement.
We were in compliance with our credit facility covenants at December 31, 20212023 and expect to maintain compliance. At December 31, 2021,2023, our consolidated net debt to total capitalization ratio was 0.43.0.37. We do not believe the credit facility covenants are reasonably likely to limit our ability to undertake additional debt financing if needed to support our business.
Future Capital Requirements
Our material future cash requirements are summarized below. Based on current market indications, we expect to meet our contractual cash commitments to third parties as of December 31, 2021,2023, recognizing we may be required to meet such commitments even if our business plan assumptions were to change.
Senior notes
Our debt includes outstanding senior note obligations totaling $6.36$5.7 billion at December 31, 2021,2023, exclusive of interest payment obligations thereon. Our senior notes are not subject to any mandatory redemption or sinking fund requirements. The earliest scheduled senior note maturity is our $649.6$893 million of 20232024 Notes due in AprilJune 2024, which is reflected as a current liability in the caption “Current portion of long-term debt” in the consolidated balance sheets as of December 31, 2023. We expect to fully redeem our 2024 Notes by the maturity date using a combination of available cash flows and utilization of credit facility borrowing capacity if necessary. For further information on the face values, maturity dates, semi-annual interest payment dates, optional redemption periods and covenant restrictions related to our senior notes, refer to Note 8. Long-Term Debt in Part II, Item 8. Notes to Consolidated Financial Statements.
We were in compliance with our senior note covenants at December 31, 20212023 and expect to maintain compliance. We do not believe the senior note covenants will materially limit our ability to undertake additional debt financing. Downgrades or other negative rating actions with respect to the credit ratings assigned to our senior unsecured debt do not trigger additional senior note covenants.
30
Credit facility borrowings
As of January 31, 2022,February 1, 2024, we had $240$10 million of outstanding borrowings on our credit facility, which represents a decrease of $260 million compared to $500 million outstanding at year-end 2021.facility. Our credit facility matures in October 2026.
Term loan
We have a $750 million term loan that matures in November 2025. The covenant requirements in the term loan are consistent with the covenants in our revolving credit facility, including the requirement that we maintain a consolidated net debt to total capitalization ratio of no greater than 0.65 to 1.0. We were in compliance with the term loan covenants at December 31, 2023 and expect to maintain compliance. Downgrades or other negative rating actions with respect to the credit ratings assigned to our senior unsecured debt do not trigger a security requirement or change in covenants for the term loan.
Transportation, gathering, and processing commitments
We have entered into transportation, gathering, and processing commitments to guarantee capacity on crude oil and natural gas pipelines and natural gas processing facilities that require us to pay per-unit charges regardless of the amount of capacity used. Future commitments remaining as of December 31, 20212023 under the arrangements amount to approximately $1.31 billion.$824 million. See Part II, Item 8. Notes to Consolidated Financial Statements—Note 13. Commitments and Contingencies for additional information.
Capital Expenditures
2023 Capital Spending
For the year ended December 31, 2021,2023, we invested $1.54$3.25 billion in our capital program excluding $3.58 billion$681.2 million of unbudgeted acquisitions, excluding $21.3$9.7 million of mineral acquisitions attributable to Franco-Nevada, and including $114.1$22.3 million of capital costs associated with increased accruals for capital expenditures as compared to December 31, 2020.2022. Our 20212023 capital
In millions |
| 2023 |
| |
Exploration and development drilling |
| $ | 2,734.9 |
|
Land costs |
|
| 134.6 |
|
Mineral acquisitions attributable to Continental |
|
| 2.4 |
|
Capital facilities, workovers, water infrastructure, and other corporate assets |
|
| 381.5 |
|
Capital expenditures attributable to Continental, excluding unbudgeted acquisitions |
| $ | 3,253.4 |
|
Unbudgeted acquisitions |
|
| 681.2 |
|
Total capital expenditures attributable to Continental |
| $ | 3,934.6 |
|
Mineral acquisitions attributable to Franco-Nevada |
|
| 9.7 |
|
Total capital expenditures |
| $ | 3,944.3 |
|
2024 Capital Expenditures Budget
For 2024, our capital expenditures budget attributable to us is $3.4 billion. Costs of acquisitions and investments, such as those described in Note 18. Equity Investment in Part II, Item 8. Notes to Consolidated Financial Statements—Note 2. Property Acquisitions and DispositionsStatements, for discussion of our notable property acquisitions executed in 2021.
| In millions | 1Q 2021 | 2Q 2021 | 3Q 2021 | 4Q 2021 | Total 2021 | ||||||||||||
| Exploration and development drilling | $ | 255.6 | $ | 216.2 | $ | 312.3 | $ | 382.6 | $ | 1,166.7 | |||||||
| Land costs | 7.5 | 14.5 | 18.5 | 111.1 | 151.6 | ||||||||||||
| Mineral acquisitions attributable to Continental | 0.2 | 1.3 | 1.5 | 2.9 | 5.9 | ||||||||||||
| Capital facilities, workovers, water infrastructure, and other corporate assets | 27.4 | 57.3 | 51.0 | 68.4 | 204.1 | ||||||||||||
| Seismic | 2.7 | 0.2 | 0.4 | 9.2 | 12.5 | ||||||||||||
| Capital expenditures attributable to Continental, excluding unbudgeted acquisitions | $ | 293.4 | $ | 289.5 | $ | 383.7 | $ | 574.2 | $ | 1,540.8 | |||||||
| Acquisitions of producing properties (1) | 183.3 | (5.4) | 0.3 | 2,390.3 | 2,568.5 | ||||||||||||
| Acquisitions of non-producing properties (1) | 24.3 | 18.7 | 3.0 | 967.5 | 1,013.5 | ||||||||||||
| Total unbudgeted acquisitions | 207.6 | 13.3 | 3.3 | 3,357.8 | 3,582.0 | ||||||||||||
| Total capital expenditures attributable to Continental | 501.0 | 302.8 | 387.0 | 3,932.0 | 5,122.8 | ||||||||||||
| Mineral acquisitions attributable to Franco-Nevada | 0.9 | 2.8 | 6.0 | 11.6 | 21.3 | ||||||||||||
| Total capital expenditures | 501.9 | 305.6 | 393.0 | 3,943.6 | 5,144.1 | ||||||||||||
.
Cash Payments for Income Taxes
For the year ended December 31, 2023, we made cash payments for federal and state income taxes totaling $566 million, representing payments associated with 2022 tax return filing extensions and estimated quarterly payments for 2023 federal and state income taxes based on estimates of February 10, 2022, the publicly available forwardtaxable income for 2023. Significant judgment is involved in estimating future taxable income as we are required to make assumptions about future commodity strip prices, for the remainderprojected production, development activities, capital spending, profitability, and general economic conditions, all of 2022 averaged $83.38 per barrel for crude oil and $4.09 per Mcf for natural gas.which are subject to material revision in future periods as better information
31
becomes available. If commodity prices remain at thesecurrent levels, for the year, we could potentially utilize the full amount of our federal net operating loss carryforwards and certain state net operating loss carryforwards and generateexpect to continue generating significant taxable income in 2022,through at least year-end 2024, which couldwould result in us making cashcontinuing to make estimated tax payments for income taxeson a quarterly basis in 2024 that could approximate the upcoming year.payments made in 2023. Because of the significant uncertainty inherent in numerous factors utilized in projecting taxable income, including future commodity prices, production levels, development activities, capital spending, profitability, and general economic conditions, we cannot predict the amount of future income tax payments with certainty, but suchcertainty.
Long-term incentive compensation awards
As discussed in Note 15. Incentive Compensation in Part II, Item 8. Notes to Consolidated Financial Statements we have recognized a current liability of $130.6 million and a non-current liability of $41.7 million in the consolidated balance sheets associated with unvested incentive compensation awards granted to employees that are scheduled to vest in 2024, 2025, and 2026. We intend to settle these awards in cash at the time vesting occurs. Our recognized liabilities will be remeasured each reporting period leading up to the applicable award vesting dates to reflect additional service rendered by employees and to reflect changes in expected cash payments could be significant.
Delivery Commitments
We have various natural gas volume delivery commitments that are related to our North and Southkey operating areas. We expect to primarily fulfill our contractual natural gas obligations with production from our proved reserves. However, we may purchase third-party volumes to satisfy our commitments. Additionally, in the Permian Basin certain of our firm sales contracts for crude oil include delivery commitments that specify the delivery of a fixed and determinable quantity. We expect to primarily fulfill our contractual crude oil obligations with production from our proved reserves. As of December 31, 2023, we were committed to deliver the following fixed quantities of natural gas and crude oil production. The volumes disclosed herein represent gross production associated with properties operated by us and do not reflect our net proportionate share of such amounts. Additionally, in the South region certain of our firm sales contracts for oil include delivery commitments that specify the delivery of a fixed and determinable quantity. We expect to primarily fulfill our contractual obligations with production from our proved reserves. As of December 31, 2021, we were committed to deliver the following fixed quantities of natural gas production.
| Year Ending | Natural Gas | Crude Oil | ||||||||||||
| December 31, | Bcf | MMBo | ||||||||||||
| 2022 | 146 | 13 | ||||||||||||
| 2023 | 84 | 13 | ||||||||||||
| 2024 | 73 | 3 | ||||||||||||
| 2025 | 18 | — | ||||||||||||
| 2026 | 15 | — | ||||||||||||
in
Year Ending |
| Natural Gas |
|
| Crude Oil |
| ||
December 31, |
| Bcf |
|
| MMBo |
| ||
2024 |
|
| 126 |
|
|
| 13 |
|
2025 |
|
| 74 |
|
|
| 3 |
|
2026 |
|
| 38 |
|
|
| — |
|
2027 |
|
| 4 |
|
|
| — |
|
Part II, Item 8. Notes to Consolidated Financial Statements
for discussion of our hedging activities, including a summary of derivative contracts in place as of December 31, 2021. Between January 1, 2022 and February 10, 2022 we entered into additional derivative instruments as summarized in the tables below.
| Natural gas derivatives | |||||||||||||||||||||||||||||
| Weighted Average Hedge Price ($/MMBtu) | |||||||||||||||||||||||||||||
| Period and Type of Contract | Average Volumes Hedged | Swaps | Floor | Ceiling | |||||||||||||||||||||||||
| April 2022 - September 2022 | |||||||||||||||||||||||||||||
| Swaps - Henry Hub | 200,000 | MMBtus/day | $ | 4.03 | |||||||||||||||||||||||||
| April 2022 - September 2022 | |||||||||||||||||||||||||||||
| Collars - Henry Hub | 110,000 | MMBtus/day | $ | 4.50 | $ | 6.00 | |||||||||||||||||||||||
| July 2022 - December 2022 | |||||||||||||||||||||||||||||
| Swaps - WAHA | 45,000 | MMBtus/day | $ | 3.41 | |||||||||||||||||||||||||
| October 2022 - March 2023 | |||||||||||||||||||||||||||||
| Collars - Henry Hub | 210,000 | MMBtus/day | $ | 4.12 | $ | 5.52 | |||||||||||||||||||||||
| January 2023 - December 2023 | |||||||||||||||||||||||||||||
| Swaps - WAHA | 40,000 | MMBtus/day | $ | 2.69 | |||||||||||||||||||||||||
| April 2023 - September 2023 | |||||||||||||||||||||||||||||
| Swaps - Henry Hub | 100,000 | MMBtus/day | $ | 3.25 | |||||||||||||||||||||||||
| October 2023 - March 2024 | |||||||||||||||||||||||||||||
| Collars - Henry Hub | 100,000 | MMBtus/day | $ | 3.14 | $ | 4.00 | |||||||||||||||||||||||
| April 2024 - December 2024 | |||||||||||||||||||||||||||||
| Swaps - Henry Hub | 100,000 | MMBtus/day | $ | 3.11 | |||||||||||||||||||||||||
| Crude oil derivatives | |||||||||||||||||||||||||||||||||||
| Period and Type of Contract | Average Volumes Hedged | Weighted Average Hedge Price ($/Bbl) | |||||||||||||||||||||||||||||||||
| March 2022 - December 2022 | |||||||||||||||||||||||||||||||||||
| NYMEX Roll Swaps | 24,000 | Bbls/day | $ | 1.10 | |||||||||||||||||||||||||||||||
As discussed in Note 8. Long-Term Debt in Part II, Item 8. Notes to Consolidated Financial Statements, inIn recent yearsperiods we have repurchasedredeemed or redeemedrepurchased a portion of our outstanding senior notes. From time to time, we may seek to execute additional repurchasesredemptions or redemptionsrepurchases of our senior notes for cash in open market transactions, privately negotiated transactions, or otherwise. SuchThe timing and amount of any such redemptions or repurchases or redemptions will depend on prevailing market conditions, our liquidity and prospects for future access to capital, and other factors. The amounts involved in any such transactions, individually or in the aggregate, may be material. Our $893 million of 2024 Notes is due in June 2024. We expect to fully redeem our 2024 Notes by the maturity date using a combination of available cash flows and utilization of credit facility borrowing capacity if necessary.
Derivative Instruments
The fair value of our derivative instruments at December 31, 2023 was a net asset of $508 million. See Note 6. Derivative Instruments in Part II, Item 8. Notes to Consolidated Financial Statements for further discussion of our hedging activities, including a summary of derivative contracts in place as of December 31, 2023. The estimated fair value of our derivatives is highly sensitive to market price volatility and therefore subject to significant fluctuations from period to period. See Item 7A. Quantitative and Qualitative Disclosures About Market Risk for information on how hypothetical changes in commodity prices would impact the fair value of our derivatives as of December 31, 2023.
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Critical Accounting Policies and Estimates
Our consolidated financial statements and related footnotes contain information that is pertinent to our management’s discussion and analysis of financial condition and results of operations. The preparation of financial statements in conformity with generally accepted accounting principles requires management to select appropriate accounting policies and to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues, expenses, and the disclosure and estimation of contingent assets and liabilities. See Part II, Item 8. Notes to Consolidated Financial Statements—Note 1. Organization and Summary of Significant Accounting Policies and Note 9. Revenues for descriptions of our major accounting policies. Certain of these accounting policies involve judgments and uncertainties to such an extent that there is a reasonable likelihood that materially different amounts could have been reported under different conditions or if different assumptions had been used.
In management’s opinion, the most significant reporting areas impacted by management’s judgments and estimates are crude oil and natural gas reserve estimations, revenue recognition, the choice of accounting method for crude oil and natural gas activities and derivatives, impairment of assets, income taxes and contingent liabilities. These areas are discussed below. Management’s judgments and estimates in these areas are based on information available from both internal and external sources, including engineers, geologists and historical experience in similar matters and are believed to be reasonable under the circumstances. We evaluate our estimates and assumptions on a regular basis. Actual results could differ from the estimates as additional information becomes known.
Crude Oil and Natural Gas Reserves Estimation and Standardized Measure of Future Cash Flows
Our external independent reserve engineers, Ryder Scott, and internal technical staff prepare the estimates of our crude oil and natural gas reserves and associated future net cash flows. Even though Ryder Scott and our internal technical staff are knowledgeable and follow authoritative guidelines for estimating reserves, they must make a number of subjective assumptions based on professional judgments in developing the reserve estimates. Estimates of reserves and their values, future production rates, and future costs and expenses are inherently uncertain for various reasons, including many factors beyond the Company’s control. Reserve estimates are updated by us at least semi-annually and take into account recent production levels and other technical information about each of our properties.
Crude oil and natural gas reserve engineering is a subjective process of estimating underground accumulations of crude oil and natural gas that cannot be precisely measured. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Periodic revisions or removals of estimated reserves and future cash flows may be necessary as a result of a number of factors, including reservoir performance, new drilling, crude oil and natural gas prices, changes in costs, technological advances, new geological or geophysical data, changes in business strategies, or other economic factors. Accordingly, reserve estimates may differ significantly from the quantities of crude oil and natural gas ultimately recovered. For the years ended December 31, 2021, 2020, and 2019, net upward (downward) revisions of our proved reserves totaled approximately 54 MMBoe, (505) MMBoe, and (149) MMBoe, respectively. We cannot predict the amounts or timing of future reserve revisions or removals.
Estimates of proved reserves are key components of the Company’s most significant financial estimates including the computation of depreciation, depletion, amortization and impairment of proved crude oil and natural gas properties. Holding all other factors constant, if proved reserves are revised downward, the rate at which we record DD&A expense would increase, reducing net income. Conversely, if proved reserves are revised upward, the rate at which we record DD&A expense would decrease. Future revisions of reserves may be material and could significantly alter future depreciation, depletion, and amortization expense and may result in material impairments of assets.
for additional proved reserve sensitivities under certain increasing and decreasing commodity price scenarios for crude oil and natural gas.
We derive substantially all of our revenues from the sale of crude oil, natural gas, and natural gas.NGLs. See Part II, Item 8. Notes to Consolidated Financial Statements—Note 9. Revenues for discussion of our accounting policies governing the recognition and presentation of revenues.
Operated crude oil, and natural gas, and NGL revenues are recognized during the month in which control transfers to the customer and it is probable the Company will collect the consideration it is entitled to receive. For non-operated properties, the Company's proportionate share of production is generally marketed at the discretion of the operators. Non-operated revenues are recognized by the Company during the month in which production occurs and it is probable the Company will collect the consideration it is entitled to receive.
At the end of each month, to record revenues we estimate the amount of production delivered and sold to customers and the prices at which they were sold. Variances between estimated revenues and actual amounts received for all prior months are recorded in the
33
month payment is received and are reflected in our financial statements as crude oil and natural gas sales. These variances have historically not been material.
For the sale of crude oil, and natural gas, and NGLs we evaluate whether we are the principal, and report revenues on a gross basis (revenues presented separately from associated expenses), or an agent, and report revenues on a net basis. In this assessment, we consider if we obtain control of the products before they are transferred to the customer as well as other indicators. Judgment may be required in determining the point in time when control of products transfers to customers.
Successful Efforts Method of Accounting
Our business is subject to accounting rules that are unique to the crude oil and natural gas industry. Two generally accepted methods of accounting for oil and gas activities are available—the successful efforts method and the full cost method. The most significant differences between these two methods are the treatment of exploration costs and the manner in which the carrying value of oil and gas properties are amortized and evaluated for impairment. We use the successful efforts method of accounting for our oil and gas properties. See Part II, Item 8. Notes to Consolidated Financial Statements—Note 1. Organization and Summary of Significant Accounting Policies for further discussion of the accounting policies applicable to the successful efforts method of accounting.
Derivative Activities
From time to time we may utilize derivative contracts to hedge against the variability in cash flows associated with the forecasted sale of future crude oil and natural gas production and for other purposes. We have elected not to designate any of our price risk management activities as cash flow hedges. As a result, we mark our derivative instruments to fair value and recognize the changes in fair value in current earnings.
In determining the amounts to be recorded for outstanding derivative contracts, we are required to estimate the fair value of the derivatives. We use an independent third party to provide our derivative valuations. The third party’s valuation models for derivative contracts are industry-standard models that consider various inputs including quoted forward prices for commodities, time value, volatility factors, and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. The fair value calculations for collars requires the use of an option-pricing model. The estimated future prices are compared to the prices fixed by the derivative agreements and the resulting estimated future cash inflows or outflows over the lives of the derivatives are discounted to calculate the fair value of the derivative contracts. These pricing and discounting variables are sensitive to market volatility as well as changes in future price forecasts and interest rates.
We validate our derivative valuations through management review and by comparison to our counterparties’ valuations for reasonableness. Differences between our fair value calculations and counterparty valuations have historically not been material.
All of our long-lived assets are monitored for potential impairment when circumstances indicate the carrying value of an asset may be greater than its future net cash flows, including cash flows from risk-adjusted proved reserves. Risk-adjusted probable and possible reserves may be taken into consideration when determining estimated future net cash flows and fair value when such reserves exist and are economically recoverable.
Proved crude oil and natural gas properties are reviewed for impairment on a field-by-field basis. If the carrying amount of a field exceeds its estimated undiscounted future cash flows, the carrying amount of the field is reduced to its estimated fair value using a discounted cash flow model. For producing properties, the impairment evaluations involve a significant amount of judgment since the results are based on estimated future events, such as future sales prices for crude oil and natural gas, future costs to produce those products, estimates of future crude oil and natural gas reserves to be recovered and the timing thereof, the economic and regulatory climates and other factors. The need to test a field for impairment may result from significant declines in sales prices or downward revisions or removals of crude oil and natural gas reserves. Estimates of anticipated sales prices and recoverable reserves are highly judgmental and are subject to material revision in future periods.
Impairment provisions for our proved crude oil and natural gas properties totaled $15.5 million for the year ended December 31, 2021 as estimated future net cash flows were determined to be in excess of cost basis.2023. Commodity price assumptions used for the year-end December 31, 20212023 impairment calculations were based on publicly available average annual forward commodity strip prices through year-end 20262028 and were then escalated at 3% per year thereafter. Holding all other factors constant, as forward commodity prices decrease, our probability for recognizing producing property impairments may increase, or the magnitude of impairments to be recognized may increase. Conversely, as forward commodity prices increase, our probability for recognizing producing property impairments may decrease, or the magnitude of impairments to be recognized may decrease or be eliminated. As of December 31, 2021,2023 , the publicly available forward commodity strip prices for the year 20262028 used in our fourth quarter impairment calculations averaged $58.42$61.94 per barrel for crude oil and $3.03$3.80 per Mcf for natural gas. If forward commodity prices materially decrease from current levels for an extended period, impairments of producing properties may be recognized in the
34
future. Because of the uncertainty inherent in the numerous factors utilized in determining the fair value of producing properties, we cannot predict the timing and amount of future impairment charges, if any.
Impairment losses for unproved properties are generally recognized by amortizing the portion of the properties’ costs which management estimates will not be transferred to proved properties over the lives of the leases based on drilling plans, experience of successful drilling, and the average holding period. The impairment assessments are affected by economic factors such as the results of exploration activities, commodity price outlooks, anticipated drilling programs, remaining lease terms, and potential shifts in business strategy employed by management. The estimated timing and rate of successful drilling is highly judgmental and is subject to material revision in future periods as better information becomes available.
Income Taxes
Income taxes are accounted for using the asset and liability method. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date.
In assessing the realizability of deferred tax assets, management must consider whether it is more likely than not that some portion or all of the deferred tax assets will not be realized. We apply judgment to determine the weight of both positive and negative evidence in order to conclude whether a valuation allowance is necessary for our deferred tax assets. In determining whether a valuation allowance is required, we consider, among other factors, our financial position, results of operations, projected future taxable income, reversal of existing deferred tax liabilities against deferred tax assets, and tax planning strategies. Significant judgment is involved in this determination as we are required to make assumptions about future commodity prices, projected production, development activities, profitability of future business strategies and forecasted economics in the oil and gas industry. Additionally, changes in the effective tax rate resulting from changes in tax law and our level of earnings may limit utilization of deferred tax assets and may affect the valuation of deferred tax balances in the future. Changes in judgment regarding future realization of deferred tax assets may result in a reversal of all or a portion of thea valuation allowance.
We make certain estimates and judgments in determining our income tax expense for financial reporting purposes. Our federal and state income tax returns are generally not prepared or filed before our consolidated financial statements are prepared; therefore, we estimate the tax basis of our assets and liabilities at the end of each period as well as the effects of tax rate changes, tax credits, and net operating loss carryforwards, among other things. Adjustments related to these estimates are recorded in our tax provision in the period in which we file our income tax returns. Accordingly, our effective tax rate is subject to variability from period to period as a result of factors other than changes in federal and state tax rates and/or changes in tax laws which can affect tax-paying companies. For instance, our effective tax rate is affected by, among other things, permanent taxable differences, tax credits, valuation allowances, and changes in the apportionment of property, revenues, and payroll between states in which we own property as rates vary from state to state, all of which could have a material effect on current period earnings.
Contingent Liabilities
A provision for legal, environmental and other contingencies is charged to expense when a loss is probable and the loss or range of loss can be reasonably estimated. Determining when liabilities and expenses should be recorded for these contingencies and the appropriate amounts of accruals is subject to an estimation process that requires subjective judgment of management. In certain cases, management’s judgment is based on the advice and opinions of legal counsel and other advisers, the interpretation of laws and regulations which can be interpreted differently by regulators and/or courts of law, the experience of the Company and other companies dealing with similar matters, and management’s decision on how it intends to respond to a particular matter; for example, a decision to contest it vigorously or a decision to seek a negotiated settlement. Actual losses can differ from estimates for various reasons, including differing interpretations of laws and opinions and assessments on the amount of damages. We closely monitor known and potential legal, environmental and other contingencies and make our best estimate of when or if to record liabilities and losses for matters based on available information.
See Part II, Item 8. Notes to Consolidated Financial Statements—Note 1. Organization and Summary of Significant Accounting Policies—Adoption of new accounting pronouncement for a discussion of the new income tax accounting standard adopted on January 1, 2021, which did not have a material impact on our financial position, results of operations, or cash flows.
The crude oil and natural gas industry in the United States is subject to various types of regulation at the federal, state and local levels. In January 2021, President Biden, issued executive orders that, among other things, establish new greenhouse gas emission standards for the oil and gas sector. Additionally, the Biden Administration is pursuing legislative changes to eliminate or defer certain key U.S. federal income tax deductions historically available to oil and gas exploration and production companies, as well as other tax policy changes including a proposed increase in the U.S. corporate income tax rate, among other things. These changes, if enacted, could have a material adverse effect on our results of operations and cash flows. President Biden may continue to issue additional executive orders in pursuit of his regulatory agenda, has issued, and may continue to issue, executive orders that result in more stringent and costly requirements for the domestic crude oil and natural gas industry and there is the potential for the revision of existing laws and regulations or the adoption of new legislation that could adversely affect the oil and gas industry. Such changes, if enacted, could have a material adverse effect on our results of operations and cash flows. See Part I, Item 1. Business—Regulation of
35
the Crude Oil and Natural Gas Industry for further discussiona summary of significant laws and regulations that have been enacted or are currently being considered by regulatory bodies that may affect us in the areas in which we operate.
Inflation
Inflationary pressures experienced in recent years may continue in 2024. Some of the underlying factors impacting inflation may include, but are not limited to, global supply chain disruptions, shipping bottlenecks, labor market constraints, and completionside effects from monetary and fiscal expansions. If these inflationary pressures persist or worsen, we may incur additional costs and costs of oilfield services,for equipment and materials, decreased in recent years asand from service providers reduced their costs in response to reduced demand arising from historically low crude oil prices. However,providers. Our budgeted expenditures include an estimate for the impact of cost inflation and, despite inflationary pressures, returned in 2021 and are expectedwe expect to continue in 2022 in conjunction with thegenerating significant improvement inamounts of free cash flow at current commodity prices over the past year in response to the liftingprice levels.
36
. For non-operated properties, we receive a net payment from the operator for our share of sales proceeds which is net of costs incurred by the operator, if any. Such non-operated revenues are recognized at the net amount of proceeds received. As a result, the separate presentation of revenues and transportation expenses from our operated properties differs from the net presentation from non-operated properties. This impacts the comparability of certain operating metrics, such as per-unit sales prices, when such metrics are prepared in accordance with U.S. GAAP using gross presentation for some revenues and net presentation for others.
| Total Company | Year Ended December 31, 2021 | Year Ended December 31, 2020 | Year Ended December 31, 2019 | |||||||||||||||||||||||||||||||||||||||||||||||||||||
| In thousands | Crude oil | Natural gas | Total | Crude oil | Natural gas | Total | Crude oil | Natural gas | Total | |||||||||||||||||||||||||||||||||||||||||||||||
| Crude oil and natural gas sales (GAAP) | $ | 3,949,294 | $ | 1,844,447 | $ | 5,793,741 | $ | 2,199,976 | $ | 355,458 | $ | 2,555,434 | $ | 3,929,994 | $ | 584,395 | $ | 4,514,389 | ||||||||||||||||||||||||||||||||||||||
| Less: Transportation expenses | (185,130) | (39,859) | (224,989) | (158,989) | (37,703) | (196,692) | (191,998) | (33,651) | (225,649) | |||||||||||||||||||||||||||||||||||||||||||||||
| Net crude oil and natural gas sales (non-GAAP) | $ | 3,764,164 | $ | 1,804,588 | $ | 5,568,752 | $ | 2,040,987 | $ | 317,755 | $ | 2,358,742 | $ | 3,737,996 | $ | 550,744 | $ | 4,288,740 | ||||||||||||||||||||||||||||||||||||||
| Sales volumes (MBbl/MMcf/MBoe) | 58,757 | 370,110 | 120,442 | 58,793 | 306,528 | 109,881 | 72,136 | 311,865 | 124,113 | |||||||||||||||||||||||||||||||||||||||||||||||
| Net sales price (non-GAAP) | $ | 64.06 | $ | 4.88 | $ | 46.24 | $ | 34.71 | $ | 1.04 | $ | 21.47 | $ | 51.82 | $ | 1.77 | $ | 34.56 | ||||||||||||||||||||||||||||||||||||||
| North Dakota Bakken | Year Ended December 31, 2021 | Year Ended December 31, 2020 | Year Ended December 31, 2019 | |||||||||||||||||||||||||||||||||||||||||||||||||||||
| In thousands | Crude oil | Natural gas | Total | Crude oil | Natural gas | Total | Crude oil | Natural gas | Total | |||||||||||||||||||||||||||||||||||||||||||||||
| Crude oil and natural gas sales (GAAP) | $ | 2,695,738 | $ | 549,932 | $ | 3,245,670 | $ | 1,469,450 | $ | 24,714 | $ | 1,494,164 | $ | 2,826,136 | $ | 128,426 | $ | 2,954,562 | ||||||||||||||||||||||||||||||||||||||
| Less: Transportation expenses | (154,359) | (4,831) | (159,190) | (127,036) | (2,580) | (129,616) | (157,076) | (2,530) | (159,606) | |||||||||||||||||||||||||||||||||||||||||||||||
| Net crude oil and natural gas sales (non-GAAP) | $ | 2,541,379 | $ | 545,101 | $ | 3,086,480 | $ | 1,342,414 | $ | 22,134 | $ | 1,364,548 | $ | 2,669,060 | $ | 125,896 | $ | 2,794,956 | ||||||||||||||||||||||||||||||||||||||
| Sales volumes (MBbl/MMcf/MBoe) | 40,186 | 120,517 | 60,272 | 40,040 | 97,532 | 56,295 | 52,374 | 98,186 | 68,738 | |||||||||||||||||||||||||||||||||||||||||||||||
| Net sales price (non-GAAP) | $ | 63.24 | $ | 4.52 | $ | 51.21 | $ | 33.53 | $ | 0.23 | $ | 24.24 | $ | 50.96 | $ | 1.28 | $ | 40.66 | ||||||||||||||||||||||||||||||||||||||
| SCOOP | Year Ended December 31, 2021 | Year Ended December 31, 2020 | Year Ended December 31, 2019 | |||||||||||||||||||||||||||||||||||||||||||||||||||||
| In thousands | Crude oil | Natural gas | Total | Crude oil | Natural gas | Total | Crude oil | Natural gas | Total | |||||||||||||||||||||||||||||||||||||||||||||||
| Crude oil and natural gas sales (GAAP) | $ | 756,596 | $ | 980,323 | $ | 1,736,919 | $ | 486,076 | $ | 246,125 | $ | 732,201 | $ | 640,097 | $ | 277,230 | $ | 917,327 | ||||||||||||||||||||||||||||||||||||||
| Less: Transportation expenses | (2,854) | (23,808) | (26,662) | (5,275) | (21,909) | (27,184) | (3,539) | (14,795) | (18,334) | |||||||||||||||||||||||||||||||||||||||||||||||
| Net crude oil and natural gas sales (non-GAAP) | $ | 753,742 | $ | 956,515 | $ | 1,710,257 | $ | 480,801 | $ | 224,216 | $ | 705,017 | $ | 636,558 | $ | 262,435 | $ | 898,993 | ||||||||||||||||||||||||||||||||||||||
| Sales volumes (MBbl/MMcf/MBoe) | 11,341 | 179,553 | 41,267 | 12,694 | 136,410 | 35,429 | 11,592 | 111,436 | 30,164 | |||||||||||||||||||||||||||||||||||||||||||||||
| Net sales price (non-GAAP) | $ | 66.46 | $ | 5.33 | $ | 41.44 | $ | 37.88 | $ | 1.64 | $ | 19.90 | $ | 54.92 | $ | 2.36 | $ | 29.80 | ||||||||||||||||||||||||||||||||||||||
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
General. We are exposed to a variety of market risks including commodity price risk, credit risk, and interest rate risk. We seek to address these risks through a program of risk management which may include the use of derivative instruments.
Commodity Price Risk. Our primary market risk exposure is in the prices we receive from sales of our crude oil, natural gas, and natural gas.gas liquids. Realized pricing is primarily driven by the prevailing worldwide price for crude oil and spot market prices applicable to our natural gas production. Prices for crude oil and natural gas liquids production. Commodity prices have been volatile and unpredictable for several years, and we expect this volatility to continue in the future. The prices we receive for production depend on many factors outside of our control, including volatility in the differences between product prices at sales points and the applicable index prices. Based on our average daily production for the quarter ended December 31, 2021,2023, and excluding any effect of our derivative instruments in place, our annual revenue would increase or decrease by approximately $608$897 million for each $10.00 per barrel change in crude oil prices at December 31, 20212023 and $380$457 million for each $1.00 per Mcf change in natural gas prices at December 31, 2021.2023.
To reduce price risk caused by market fluctuations in crude oil and natural gascommodity prices, from time to time we may economically hedge a portion of our anticipated crude oil and natural gas production as part of our risk management program. In addition, we may utilize basis contracts to hedge the differential between derivative contract index prices and those of our physical pricing points. Reducing our exposure to price volatility helps secure funds to be used for our capital program and for general corporate purposes. Our decision on the quantity and price at which we choose to hedge our production is based in part on our view of current and future market conditions. We may choose not to hedge future production if the price environment for certain time periods is deemed to be unfavorable. Additionally, we may choose to settle existing derivative positions prior to the expiration of their contractual maturities. While hedging, if utilized, may limit the downside risk of adverse price movements, it also may limit future revenues from upward price movements.
The fair value of our derivative instruments at December 31, 20212023 was a net asset of $34.3$508 million, which is comprised of a $33.3$355 million net asset associated with our natural gas derivatives and a $1.0$153 million net asset associated with our crude oil derivatives. The following table shows how a hypothetical +/- 10% change in the underlying forward prices used to calculate the fair value of our derivatives would impact the fair value estimates as of December 31, 2021.2023.Hypothetical Fair Value In thousands Change in Forward Price Asset (Liability) Crude Oil -10% $1,273 Crude Oil +10% $641 Natural Gas -10% $99,641 Natural Gas +10% ($33,074)
|
|
| Hypothetical Fair Value |
| ||
In thousands |
| Change in Forward Price |
| Asset (Liability) |
| |
Crude Oil |
| -10% |
| $ | 347,530 |
|
Crude Oil |
| +10% |
| $ | (41,267 | ) |
Natural Gas |
| -10% |
| $ | 578,959 |
|
Natural Gas |
| +10% |
| $ | 130,894 |
|
Changes in the fair value of our derivatives from the above price sensitivities would produce a corresponding change in our total revenues.
Credit Risk. We monitor our risk of loss due to non-performance by counterparties of their contractual obligations. Our principal exposure to credit risk is through the sale of our crude oil and natural gas production, which we market to energy marketing companies, crude oil refining companies, and natural gas gathering and processing companies ($1.11.2 billion in receivables at December 31, 2021)2023) and our joint interest and other receivables ($279351 million at December 31, 2021)2023).
We monitor our exposure to counterparties on crude oil and natural gas sales primarily by reviewing credit ratings, financial statements and payment history. We extend credit terms based on our evaluation of each counterparty’s credit worthiness. We have not generally required our counterparties to provide collateral to secure crude oil and natural gas sales receivables owed to us. Historically, our credit losses on crude oil and natural gas sales receivables have been immaterial.
Joint interest receivables arise from billing the individuals and entities who own a partial interest in the wells we operate. These individuals and entities participate in our wells primarily based on their ownership in leases included in units on which we wish to drill. We can do very little to choose who participates in our wells. In order to minimize our exposure to this credit risk we generally request prepayment of drilling costs where it is allowed by contract or state law. For such prepayments, a liability is recorded and subsequently reduced as the associated work is performed. This liability was $19$37 million at December 31, 2021,2023, which will be used to offset future capital costs when billed. In this manner, we reduce credit risk. We may have the right to place a lien on a co-owner’s interest in the well, to net production proceeds against amounts owed in order to secure payment or, if necessary, foreclose on the interest. Historically, our credit losses on joint interest receivables have been immaterial.
Interest Rate Risk. Our exposure to changes in interest rates relates primarily to variable-rate borrowings we may have outstanding from time to time under our credit facility.facility and our $750 million term loan. Such borrowings bear interest at market-based interest rates plus a margin based on the terms
37
of the borrowing and the credit ratings assigned to our senior, unsecured, long-term indebtedness. All of our other long-term indebtedness is fixed rate and does not expose us to the risk of cash flow loss due to changes in market interest rates.
We had $240$10 million of variable rate borrowings outstanding on our credit facility and $750 million of variable rate borrowings on our term loan at January 31, 2022.February 1, 2024. The impact of a 0.25% increase in interest rates on this amount of debt would result in increased interest expense and reduced income before income taxes of approximately $0.6$1.9 million per year.
We manage our interest rate exposure by monitoring both the effects of market changes in interest rates and the proportion of our debt portfolio that is variable-rate versus fixed-rate debt. We may utilize interest rate derivatives to alter interest rate exposure in an attempt to reduce interest rate expense related to existing debt issues. Interest rate derivatives may be used solely to modify interest rate exposure and not to modify the overall leverage of the debt portfolio. We currently have no interest rate derivatives.
The following table presents our debt maturities and the weighted average interest rates by expected maturity date as of December 31, 2021:2023:
| In thousands | 2022 | 2023 | 2024 | 2025 | 2026 | Thereafter | Total | |||||||||||||||||||||||||||||||||||||
| Fixed rate debt: | ||||||||||||||||||||||||||||||||||||||||||||
| Senior Notes: | ||||||||||||||||||||||||||||||||||||||||||||
| Principal amount (1) | $ | — | $ | 649,625 | $ | 911,000 | $ | — | $ | 800,000 | $ | 4,000,000 | $ | 6,360,625 | ||||||||||||||||||||||||||||||
| Weighted-average interest rate | — | 4.5% | 3.8% | — | 2.3 | % | 4.7 | % | 4.2 | % | ||||||||||||||||||||||||||||||||||
| Notes payable: | ||||||||||||||||||||||||||||||||||||||||||||
| Principal amount (1) | $ | 2,326 | $ | 2,410 | $ | 2,495 | $ | 2,587 | $ | 2,681 | $ | 9,952 | $ | 22,451 | ||||||||||||||||||||||||||||||
| Interest rate | 3.5 | % | 3.5 | % | 3.5 | % | 3.5 | % | 3.5 | % | 3.5 | % | 3.5 | % | ||||||||||||||||||||||||||||||
| Variable rate debt: | ||||||||||||||||||||||||||||||||||||||||||||
| Credit facility: | ||||||||||||||||||||||||||||||||||||||||||||
| Principal amount | $ | — | $ | — | $ | — | $ | — | $ | 500,000 | $ | — | $ | 500,000 | ||||||||||||||||||||||||||||||
| Weighted-average interest rate | — | — | — | — | 1.6 | % | — | 1.6 | % | |||||||||||||||||||||||||||||||||||
In thousands |
| 2024 |
|
| 2025 |
|
| 2026 |
|
| 2027 |
|
| 2028 |
|
| Thereafter |
|
| Total |
| |||||||
Fixed rate debt: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||
Senior Notes: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||
Principal amount (1) |
| $ | 893,126 |
|
| $ | — |
|
| $ | 800,000 |
|
| $ | — |
|
| $ | 1,000,000 |
|
| $ | 3,000,000 |
|
| $ | 5,693,126 |
|
Weighted-average interest rate |
|
| 3.8 | % |
|
| — |
|
|
| 2.3 | % |
|
| — |
|
|
| 4.4 | % |
|
| 4.8 | % |
|
| 4.2 | % |
Notes payable: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||
Principal amount (1) |
| $ | 2,495 |
|
| $ | 2,587 |
|
| $ | 2,681 |
|
| $ | 2,777 |
|
| $ | 2,876 |
|
| $ | 4,299 |
|
| $ | 17,715 |
|
Interest rate |
|
| 3.5 | % |
|
| 3.5 | % |
|
| 3.5 | % |
|
| 3.5 | % |
|
| 3.5 | % |
|
| 3.5 | % |
|
| 3.5 | % |
Variable rate debt: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||
Credit facility: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||
Principal amount |
| $ | — |
|
| $ | — |
|
| $ | 210,000 |
|
| $ | — |
|
| $ | — |
|
| $ | — |
|
| $ | 210,000 |
|
Weighted-average interest rate |
|
| — |
|
|
| — |
|
|
| 7.0 | % |
|
| — |
|
|
| — |
|
|
| — |
|
|
| 7.0 | % |
Term loan: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||
Principal amount |
| $ | — |
|
| $ | 750,000 |
|
| $ | — |
|
| $ | — |
|
| $ | — |
|
| $ | — |
|
| $ | 750,000 |
|
Weighted-average interest rate |
|
| — |
|
|
| 7.0 | % |
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| 7.0 | % |
38
Item 8. Financial Statements and Supplementary Data
Index to Consolidated Financial Statements
39
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
Board of Directors and Shareholders
Continental Resources, Inc.
We have audited the accompanying consolidated balance sheets of Continental Resources, Inc. (an Oklahoma corporation) and subsidiaries (the “Company”) as of December 31, 20212023 and 2020,2022, the related consolidated statements of comprehensive income, (loss), equity, and cash flows for each of the three years in the period ended December 31, 2021,2023, and the related notes (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 20212023 and 2020,2022, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2021,2023, in conformity with accounting principles generally accepted in the United States of America.
issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”), and our report datedFebruary 14, 2022expressed an unqualified opinion.
These financial statements are the responsibility of the Company’sCompany's management. Our responsibility is to express an opinion on the Company’s financial statements based on our audits. We are a public accounting firm registered with the PCAOBPublic Company Accounting Oversight Board (United States) (“PCAOB”) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB.PCAOB and in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion.
Our audits included performing procedures to assess the risks of material misstatement of the 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 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 financial statements. We believe that our audits provide a reasonable basis for our opinion.
Critical audit matter
The critical audit matter communicated below is a matter arising from the current period audit of the financial statements that was communicated or required to be communicated to the audit committee and that: (1) relates to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the 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.
Estimation of proved crude oil and natural gas reserves as it relates to the recognition of depletion expense, proved and unproved crude oil and natural gas reserves used in the assessment and measurement of impairment, of proved crude oil and natural gas properties, and recording of the fair valuevaluation of crude oil and natural gas properties in the Permian Basin Acquisitionfrom certain 2023 executed acquisitions of proved oil and Powder River Basin Acquisitionsgas properties (herein referred to as “the crude oil and natural gas reserves”).
As described in Note 1 to the consolidated financial statements, the Company accounts for its crude oil and natural gas properties using the successful efforts method of accounting, which requires management to make estimates of proved crude oil and natural gas reserve volumes and future cash flows to record depletion expense
40
expense and impairment assessments / assessments/measurements. We identified the estimation of proved crude oil and natural gas reserves as it relates to the recognition of depletion expense and the recording of fair values of properties acquired in the 2023 acquisitions, and proved and unproved crude oil and natural gas reserves for the assessment / assessment/measurement of impairment of crude oil and natural gas properties as a critical audit matter.
The principal considerationsconsideration for our determination that the estimation of proved crude oil and natural gas reserves as it relates to the recognition of depletion expense and proved and unproved crude oil and natural gas reserves for the assessment / measurement of impairment of crude oil and natural gas properties and the recording of oil and natural gas propertiesproperty values in the Permian Basin Acquisition and Powder River Basin Acquisitions2023 acquisitions is a critical audit matter is that relatively minor changes in certain highly subjective inputs and assumptions which require a high degree of subjectivity,that are necessary to estimate the volume and future cash flows of the Company’sCompany's crude oil and natural gas reserves could have a significant impact on the measurement of depletion expense or assessment / measurement of impairment expense and the acquisition date values of crude oil and natural gas properties.
Our audit procedures related to the estimation of proved crude oil and natural gas reserves as it relates to the recognition of depletion expense and proved and unproved crude oil and natural gas reserves for the assessment and measurement of impairment and the amount of crude oil and natural gas properties recorded from acquisitions and business combinations included the following, among others.
/s/ GRANT THORNTON LLP
We have served as the Company’s auditor since 2004.
Oklahoma City, Oklahoma
February 14, 2022
Continental Resources, Inc. and Subsidiaries
Consolidated Balance Sheets
| December 31, |
| ||||||
In thousands, except par values and share data |
| 2023 |
|
| 2022 |
| ||
Assets |
|
|
|
|
|
| ||
Current assets: |
|
|
|
|
|
| ||
Cash and cash equivalents |
| $ | 26,397 |
|
| $ | 137,788 |
|
Receivables: |
|
|
|
|
|
| ||
Crude oil, natural gas, and natural gas liquids sales |
|
| 1,196,262 |
|
|
| 1,313,538 |
|
Joint interest and other |
|
| 350,907 |
|
|
| 458,391 |
|
Allowance for credit losses |
|
| (3,172 | ) |
|
| (5,514 | ) |
Receivables, net |
|
| 1,543,997 |
|
|
| 1,766,415 |
|
Derivative assets |
|
| 353,261 |
|
|
| 39,280 |
|
Inventories |
|
| 190,762 |
|
|
| 173,264 |
|
Prepaid expenses and other |
|
| 33,450 |
|
|
| 27,508 |
|
Total current assets |
|
| 2,147,867 |
|
|
| 2,144,255 |
|
Net property and equipment, based on successful efforts method of accounting |
|
| 19,786,889 |
|
|
| 18,471,914 |
|
Investment in unconsolidated affiliates |
|
| 240,484 |
|
|
| 210,805 |
|
Operating lease right-of-use assets |
|
| 38,656 |
|
|
| 25,158 |
|
Derivative assets, noncurrent |
|
| 155,252 |
|
|
| 3,548 |
|
Other noncurrent assets |
|
| 18,293 |
|
|
| 22,670 |
|
Total assets |
| $ | 22,387,441 |
|
| $ | 20,878,350 |
|
Liabilities and equity |
|
|
|
|
|
| ||
Current liabilities: |
|
|
|
|
|
| ||
Accounts payable trade |
| $ | 835,012 |
|
| $ | 850,547 |
|
Revenues and royalties payable |
|
| 768,381 |
|
|
| 882,256 |
|
Accrued liabilities and other |
|
| 354,537 |
|
|
| 343,777 |
|
Current portion of incentive compensation liability |
|
| 130,583 |
|
|
| 125,653 |
|
Current portion of income tax liabilities |
|
| 84,556 |
|
|
| 152,149 |
|
Derivative liabilities |
|
| — |
|
|
| 88,136 |
|
Current portion of operating lease liabilities |
|
| 18,112 |
|
|
| 4,086 |
|
Current portion of long-term debt |
|
| 895,105 |
|
|
| 638,058 |
|
Total current liabilities |
|
| 3,086,286 |
|
|
| 3,084,662 |
|
Long-term debt, net of current portion |
|
| 5,734,007 |
|
|
| 7,571,582 |
|
Other noncurrent liabilities: |
|
|
|
|
|
| ||
Deferred income tax liabilities, net |
|
| 2,867,283 |
|
|
| 2,538,312 |
|
Incentive compensation liability, noncurrent |
|
| 41,707 |
|
|
| 100,066 |
|
Asset retirement obligations, noncurrent |
|
| 391,957 |
|
|
| 257,152 |
|
Derivative liabilities, noncurrent |
|
| 586 |
|
|
| 133,363 |
|
Operating lease liabilities, noncurrent |
|
| 19,482 |
|
|
| 20,055 |
|
Other noncurrent liabilities |
|
| 36,346 |
|
|
| 43,550 |
|
Total other noncurrent liabilities |
|
| 3,357,361 |
|
|
| 3,092,498 |
|
Commitments and contingencies (Note 13) |
|
|
|
|
|
| ||
Equity: |
|
|
|
|
|
| ||
Preferred stock, $0.01 par value; 25,000,000 shares authorized; no shares issued and outstanding |
|
| — |
|
|
| — |
|
Common stock, $0.01 par value; 1,000,000,000 shares authorized; |
|
|
|
|
|
| ||
299,610,267 shares issued and outstanding at December 31, 2023 and 2022; |
|
| 2,996 |
|
|
| 2,996 |
|
Retained earnings |
|
| 9,850,687 |
|
|
| 6,754,174 |
|
Total shareholders’ equity attributable to Continental Resources |
|
| 9,853,683 |
|
|
| 6,757,170 |
|
Noncontrolling interests |
|
| 356,104 |
|
|
| 372,438 |
|
Total equity |
|
| 10,209,787 |
|
|
| 7,129,608 |
|
Total liabilities and equity |
| $ | 22,387,441 |
|
| $ | 20,878,350 |
|
| December 31, | ||||||||||||||
| In thousands, except par values and share data | 2021 | 2020 | ||||||||||||
| Assets | ||||||||||||||
| Current assets: | ||||||||||||||
| Cash and cash equivalents | $ | 20,868 | $ | 47,470 | ||||||||||
| Receivables: | ||||||||||||||
| Crude oil and natural gas sales | 1,122,415 | 561,127 | ||||||||||||
| Joint interest and other | 278,753 | 143,829 | ||||||||||||
| Allowance for credit losses | (2,814) | (2,462) | ||||||||||||
| Receivables, net | 1,398,354 | 702,494 | ||||||||||||
| Derivative assets | 22,334 | 15,303 | ||||||||||||
| Inventories | 105,568 | 72,157 | ||||||||||||
| Prepaid expenses and other | 17,266 | 15,121 | ||||||||||||
| Total current assets | 1,564,390 | 852,545 | ||||||||||||
| Net property and equipment, based on successful efforts method of accounting | 16,975,465 | 13,737,292 | ||||||||||||
| Derivative assets, noncurrent | 13,188 | — | ||||||||||||
| Operating lease right-of-use assets | 16,370 | 8,557 | ||||||||||||
| Other noncurrent assets | 21,698 | 34,704 | ||||||||||||
| Total assets | $ | 18,591,111 | $ | 14,633,098 | ||||||||||
| Liabilities and equity | ||||||||||||||
| Current liabilities: | ||||||||||||||
| Accounts payable trade | $ | 582,317 | $ | 361,704 | ||||||||||
| Revenues and royalties payable | 627,171 | 327,029 | ||||||||||||
| Accrued liabilities and other | 285,740 | 167,013 | ||||||||||||
| Derivative liabilities | 899 | 227 | ||||||||||||
| Current portion of operating lease liabilities | 1,674 | 2,588 | ||||||||||||
| Current portion of long-term debt | 2,326 | 2,245 | ||||||||||||
| Total current liabilities | 1,500,127 | 860,806 | ||||||||||||
| Long-term debt, net of current portion | 6,826,566 | 5,530,173 | ||||||||||||
| Other noncurrent liabilities: | ||||||||||||||
| Deferred income tax liabilities, net | 2,139,884 | 1,620,154 | ||||||||||||
| Asset retirement obligations, net of current portion | 215,701 | 177,194 | ||||||||||||
| Derivative liabilities, noncurrent | 318 | 1,584 | ||||||||||||
| Operating lease liabilities, net of current portion | 13,800 | 5,839 | ||||||||||||
| Other noncurrent liabilities | 38,390 | 14,623 | ||||||||||||
| Total other noncurrent liabilities | 2,408,093 | 1,819,394 | ||||||||||||
| Commitments and contingencies (Note 13) | 0 | 0 | ||||||||||||
| Equity: | ||||||||||||||
| Preferred stock, $0.01 par value; 25,000,000 shares authorized; no shares issued and outstanding | — | — | ||||||||||||
| Common stock, $0.01 par value; 1,000,000,000 shares authorized; | ||||||||||||||
| 364,297,520 shares issued and outstanding at December 31, 2021; | ||||||||||||||
| 365,220,435 shares issued and outstanding at December 31, 2020; | 3,643 | 3,652 | ||||||||||||
| Additional paid-in capital | 1,131,602 | 1,205,148 | ||||||||||||
| Retained earnings | 6,340,211 | 4,847,646 | ||||||||||||
| Total shareholders’ equity attributable to Continental Resources | 7,475,456 | 6,056,446 | ||||||||||||
| Noncontrolling interests | 380,869 | 366,279 | ||||||||||||
| Total equity | 7,856,325 | 6,422,725 | ||||||||||||
| Total liabilities and equity | $ | 18,591,111 | $ | 14,633,098 | ||||||||||
42
Continental Resources, Inc. and Subsidiaries
Consolidated Statements of Comprehensive Income (Loss)
| Year Ended December 31, |
| ||||||||||
In thousands, except per share data |
| 2023 |
|
| 2022 |
|
| 2021 |
| |||
Revenues: |
|
|
|
|
|
|
|
|
| |||
Crude oil, natural gas, and natural gas liquids sales |
| $ | 7,684,263 |
|
| $ | 10,074,675 |
|
| $ | 5,793,741 |
|
Gain (loss) on derivative instruments, net |
|
| 943,768 |
|
|
| (671,095 | ) |
|
| (128,864 | ) |
Crude oil and natural gas service operations |
|
| 103,710 |
|
|
| 70,128 |
|
|
| 54,441 |
|
Total revenues |
|
| 8,731,741 |
|
|
| 9,473,708 |
|
|
| 5,719,318 |
|
|
|
|
|
|
|
|
|
|
| |||
Operating costs and expenses: |
|
|
|
|
|
|
|
|
| |||
Production expenses |
|
| 717,478 |
|
|
| 621,921 |
|
|
| 406,906 |
|
Production and ad valorem taxes |
|
| 603,534 |
|
|
| 730,132 |
|
|
| 404,362 |
|
Transportation, gathering, processing, and compression |
|
| 338,217 |
|
|
| 316,414 |
|
|
| 224,989 |
|
Exploration expenses |
|
| 16,368 |
|
|
| 23,068 |
|
|
| 21,047 |
|
Crude oil and natural gas service operations |
|
| 82,392 |
|
|
| 37,002 |
|
|
| 21,480 |
|
Depreciation, depletion, amortization and accretion |
|
| 2,264,334 |
|
|
| 1,885,465 |
|
|
| 1,898,082 |
|
Property impairments |
|
| 66,798 |
|
|
| 70,417 |
|
|
| 38,370 |
|
Transaction costs |
|
| — |
|
|
| 33,796 |
|
|
| 13,920 |
|
General and administrative expenses |
|
| 279,306 |
|
|
| 401,551 |
|
|
| 233,628 |
|
Net (gain) loss on sale of assets and other |
|
| 50,581 |
|
|
| 262 |
|
|
| (5,146 | ) |
Total operating costs and expenses |
|
| 4,419,008 |
|
|
| 4,120,028 |
|
|
| 3,257,638 |
|
Income from operations |
|
| 4,312,733 |
|
|
| 5,353,680 |
|
|
| 2,461,680 |
|
Other income (expense): |
|
|
|
|
|
|
|
|
| |||
Interest expense |
|
| (395,765 | ) |
|
| (300,662 | ) |
|
| (251,598 | ) |
Loss on extinguishment of debt |
|
| — |
|
|
| (403 | ) |
|
| (290 | ) |
Other |
|
| 11,979 |
|
|
| 15,798 |
|
|
| (23,654 | ) |
|
| (383,786 | ) |
|
| (285,267 | ) |
|
| (275,542 | ) | |
Income before income taxes |
|
| 3,928,947 |
|
|
| 5,068,413 |
|
|
| 2,186,138 |
|
Provision for income taxes |
|
| (827,630 | ) |
|
| (1,020,804 | ) |
|
| (519,730 | ) |
Income before equity in net loss of affiliate |
|
| 3,101,317 |
|
|
| 4,047,609 |
|
|
| 1,666,408 |
|
Equity in net loss of affiliate |
|
| (3,129 | ) |
|
| (1,489 | ) |
|
| — |
|
Net income |
|
| 3,098,188 |
|
|
| 4,046,120 |
|
|
| 1,666,408 |
|
Net income attributable to noncontrolling interests |
|
| 2,361 |
|
|
| 21,562 |
|
|
| 5,440 |
|
Net income attributable to Continental Resources |
| $ | 3,095,827 |
|
| $ | 4,024,558 |
|
| $ | 1,660,968 |
|
|
|
|
|
|
|
|
|
|
| |||
Net income per share attributable to Continental Resources: |
|
|
|
|
|
|
|
|
| |||
Basic |
| $ | 10.33 |
|
| $ | 11.45 |
|
| $ | 4.61 |
|
Diluted |
| $ | 10.33 |
|
| $ | 11.45 |
|
| $ | 4.56 |
|
| Year Ended December 31, | ||||||||||||||||||||
| In thousands, except per share data | 2021 | 2020 | 2019 | |||||||||||||||||
| Revenues: | ||||||||||||||||||||
| Crude oil and natural gas sales | $ | 5,793,741 | $ | 2,555,434 | $ | 4,514,389 | ||||||||||||||
| Gain (loss) on derivative instruments, net | (128,864) | (14,658) | 49,083 | |||||||||||||||||
| Crude oil and natural gas service operations | 54,441 | 45,694 | 68,475 | |||||||||||||||||
| Total revenues | 5,719,318 | 2,586,470 | 4,631,947 | |||||||||||||||||
| Operating costs and expenses: | ||||||||||||||||||||
| Production expenses | 406,906 | 359,267 | 444,649 | |||||||||||||||||
| Production taxes | 404,362 | 192,718 | 357,988 | |||||||||||||||||
| Transportation expenses | 224,989 | 196,692 | 225,649 | |||||||||||||||||
| Exploration expenses | 21,047 | 17,732 | 14,667 | |||||||||||||||||
| Crude oil and natural gas service operations | 21,480 | 18,294 | 33,230 | |||||||||||||||||
| Depreciation, depletion, amortization and accretion | 1,898,082 | 1,880,959 | 2,017,383 | |||||||||||||||||
| Property impairments | 38,370 | 277,941 | 86,202 | |||||||||||||||||
| Acquisition costs | 13,920 | — | — | |||||||||||||||||
| General and administrative expenses | 233,628 | 196,572 | 195,302 | |||||||||||||||||
| Net (gain) loss on sale of assets and other | (5,146) | 187 | (535) | |||||||||||||||||
| Total operating costs and expenses | 3,257,638 | 3,140,362 | 3,374,535 | |||||||||||||||||
| Income (loss) from operations | 2,461,680 | (553,892) | 1,257,412 | |||||||||||||||||
| Other income (expense): | ||||||||||||||||||||
| Interest expense | (251,598) | (258,240) | (269,379) | |||||||||||||||||
| Gain (loss) on extinguishment of debt | (290) | 35,719 | (4,584) | |||||||||||||||||
| Other | (23,654) | 1,662 | 3,713 | |||||||||||||||||
| (275,542) | (220,859) | (270,250) | ||||||||||||||||||
| Income (loss) before income taxes | 2,186,138 | (774,751) | 987,162 | |||||||||||||||||
| (Provision) benefit for income taxes | (519,730) | 169,190 | (212,689) | |||||||||||||||||
| Net income (loss) | 1,666,408 | (605,561) | 774,473 | |||||||||||||||||
| Net income (loss) attributable to noncontrolling interests | 5,440 | (8,692) | (1,168) | |||||||||||||||||
| Net income (loss) attributable to Continental Resources | $ | 1,660,968 | $ | (596,869) | $ | 775,641 | ||||||||||||||
| Net income (loss) per share attributable to Continental Resources: | ||||||||||||||||||||
| Basic | $ | 4.61 | $ | (1.65) | $ | 2.09 | ||||||||||||||
| Diluted | $ | 4.56 | $ | (1.65) | $ | 2.08 | ||||||||||||||
| Comprehensive income (loss): | ||||||||||||||||||||
| Net income (loss) | $ | 1,666,408 | $ | (605,561) | $ | 774,473 | ||||||||||||||
| Other comprehensive income (loss), net of tax: | ||||||||||||||||||||
| Foreign currency translation adjustments | — | — | 140 | |||||||||||||||||
| Release of cumulative translation adjustments | — | — | (555) | |||||||||||||||||
| Total other comprehensive income (loss), net of tax | — | — | (415) | |||||||||||||||||
| Comprehensive income (loss) | 1,666,408 | (605,561) | 774,058 | |||||||||||||||||
| Comprehensive income (loss) attributable to noncontrolling interests | 5,440 | (8,692) | (1,168) | |||||||||||||||||
| Comprehensive income (loss) attributable to Continental Resources | $ | 1,660,968 | $ | (596,869) | $ | 775,226 | ||||||||||||||
The accompanying notes are an integral part of these consolidated financial statements.
43
Continental Resources, Inc. and Subsidiaries
Consolidated Statements of Equity
| Shareholders’ equity attributable to Continental Resources |
|
|
|
|
|
|
| ||||||||||||||||||||||||
In thousands, except share data |
| Shares |
|
| Common |
|
| Additional |
|
| Treasury |
|
| Retained |
|
| Total shareholders’ equity of Continental Resources |
|
| Noncontrolling |
|
| Total |
| ||||||||
Balance at December 31, 2020 |
|
| 365,220,435 |
|
| $ | 3,652 |
|
| $ | 1,205,148 |
|
| $ | — |
|
| $ | 4,847,646 |
|
| $ | 6,056,446 |
|
| $ | 366,279 |
|
| $ | 6,422,725 |
|
Net income |
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| 1,660,968 |
|
|
| 1,660,968 |
|
|
| 5,440 |
|
|
| 1,666,408 |
|
Cash dividends declared |
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| (168,536 | ) |
|
| (168,536 | ) |
|
| — |
|
|
| (168,536 | ) |
Change in dividends payable |
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| 133 |
|
|
| 133 |
|
|
| — |
|
|
| 133 |
|
Common stock repurchased |
|
| — |
|
|
| — |
|
|
| — |
|
|
| (123,924 | ) |
|
| — |
|
|
| (123,924 | ) |
|
| — |
|
|
| (123,924 | ) |
Common stock retired |
|
| (3,198,571 | ) |
|
| (32 | ) |
|
| (123,892 | ) |
|
| 123,924 |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
Stock-based compensation |
|
| — |
|
|
| — |
|
|
| 63,145 |
|
|
| — |
|
|
| — |
|
|
| 63,145 |
|
|
| — |
|
|
| 63,145 |
|
Restricted stock: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||
Granted |
|
| 3,050,491 |
|
|
| 31 |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| 31 |
|
|
| — |
|
|
| 31 |
|
Repurchased and canceled |
|
| (478,697 | ) |
|
| (5 | ) |
|
| (12,799 | ) |
|
| — |
|
|
|
|
|
| (12,804 | ) |
|
| — |
|
|
| (12,804 | ) | |
Forfeited |
|
| (296,138 | ) |
|
| (3 | ) |
|
| — |
|
|
| — |
|
|
| — |
|
|
| (3 | ) |
|
| — |
|
|
| (3 | ) |
Contributions from noncontrolling interests |
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| 33,086 |
|
|
| 33,086 |
|
Distributions to noncontrolling interests |
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| (23,936 | ) |
|
| (23,936 | ) |
Balance at December 31, 2021 |
|
| 364,297,520 |
|
| $ | 3,643 |
|
| $ | 1,131,602 |
|
| $ | — |
|
| $ | 6,340,211 |
|
| $ | 7,475,456 |
|
| $ | 380,869 |
|
| $ | 7,856,325 |
|
Net income |
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| 4,024,558 |
|
|
| 4,024,558 |
|
|
| 21,562 |
|
|
| 4,046,120 |
|
Cash dividends declared |
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| (287,035 | ) |
|
| (287,035 | ) |
|
| — |
|
|
| (287,035 | ) |
Change in dividends payable |
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| 205 |
|
|
| 205 |
|
|
| — |
|
|
| 205 |
|
Common stock repurchased prior to take-private transaction |
|
| — |
|
|
| — |
|
|
| — |
|
|
| (99,855 | ) |
|
| — |
|
|
| (99,855 | ) |
|
| — |
|
|
| (99,855 | ) |
Common stock retired prior to take-private transaction |
|
| (1,842,422 | ) |
|
| (18 | ) |
|
| (99,837 | ) |
|
| 99,855 |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
Stock-based compensation |
|
| — |
|
|
| — |
|
|
| (8,085 | ) |
|
| — |
|
|
| — |
|
|
| (8,085 | ) |
|
| — |
|
|
| (8,085 | ) |
Restricted stock: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||
Granted |
|
| 1,575,847 |
|
|
| 16 |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| 16 |
|
|
| — |
|
|
| 16 |
|
Repurchased and canceled |
|
| (627,742 | ) |
|
| (7 | ) |
|
| (35,438 | ) |
|
| — |
|
|
|
|
|
| (35,445 | ) |
|
| — |
|
|
| (35,445 | ) | |
Forfeited |
|
| (384,536 | ) |
|
| (4 | ) |
|
| — |
|
|
| — |
|
|
| — |
|
|
| (4 | ) |
|
| — |
|
|
| (4 | ) |
Restricted stock canceled from take-private transaction (see Note 15) |
|
| (5,349,141 | ) |
|
| (53 | ) |
|
|
|
|
|
|
|
|
|
|
| (53 | ) |
|
|
|
|
| (53 | ) | ||||
Take-private transaction (see Note 1) |
|
| (58,059,259 | ) |
|
| (581 | ) |
|
| (988,242 | ) |
|
|
|
|
| (3,323,765 | ) |
|
| (4,312,588 | ) |
|
| — |
|
|
| (4,312,588 | ) | |
Contributions from noncontrolling interests |
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| 12,498 |
|
|
| 12,498 |
|
Distributions to noncontrolling interests |
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| (42,491 | ) |
|
| (42,491 | ) |
Balance at December 31, 2022 |
|
| 299,610,267 |
|
| $ | 2,996 |
|
| $ | — |
|
| $ | — |
|
| $ | 6,754,174 |
|
| $ | 6,757,170 |
|
| $ | 372,438 |
|
| $ | 7,129,608 |
|
Net income |
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| 3,095,827 |
|
|
| 3,095,827 |
|
|
| 2,361 |
|
|
| 3,098,188 |
|
Change in dividends payable |
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| 686 |
|
|
| 686 |
|
|
| — |
|
|
| 686 |
|
Contributions from noncontrolling interests |
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| 10,188 |
|
|
| 10,188 |
|
Distributions to noncontrolling interests |
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| (28,883 | ) |
|
| (28,883 | ) |
Balance at December 31, 2023 |
|
| 299,610,267 |
|
| $ | 2,996 |
|
| $ | — |
|
| $ | — |
|
| $ | 9,850,687 |
|
| $ | 9,853,683 |
|
| $ | 356,104 |
|
| $ | 10,209,787 |
|
| Shareholders’ equity attributable to Continental Resources | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| In thousands, except share data | Shares outstanding | Common stock | Additional paid-in capital | Accumulated other comprehensive income | Treasury stock | Retained earnings | Total shareholders’ equity of Continental Resources | Noncontrolling interests | Total equity | |||||||||||||||||||||||||||||||||||||||||||||||
| Balance at December 31, 2018 | 376,021,575 | $ | 3,760 | $ | 1,434,823 | $ | 415 | $ | — | $ | 4,706,135 | $ | 6,145,133 | $ | 276,728 | $ | 6,421,861 | |||||||||||||||||||||||||||||||||||||||
| Net income (loss) | — | — | — | — | — | 775,641 | 775,641 | (1,168) | 774,473 | |||||||||||||||||||||||||||||||||||||||||||||||
| Cash dividends declared | — | — | — | — | — | (18,747) | (18,747) | — | (18,747) | |||||||||||||||||||||||||||||||||||||||||||||||
| Change in dividends payable | — | — | — | — | — | 195 | 195 | — | 195 | |||||||||||||||||||||||||||||||||||||||||||||||
| Common stock repurchased | — | — | — | — | (190,239) | — | (190,239) | — | (190,239) | |||||||||||||||||||||||||||||||||||||||||||||||
| Common stock retired | (5,646,553) | (56) | (190,183) | — | 190,239 | — | — | — | — | |||||||||||||||||||||||||||||||||||||||||||||||
| Other comprehensive loss, net of tax | — | — | — | (415) | — | — | (415) | — | (415) | |||||||||||||||||||||||||||||||||||||||||||||||
| Stock-based compensation | — | — | 52,030 | — | — | — | 52,030 | — | 52,030 | |||||||||||||||||||||||||||||||||||||||||||||||
| Restricted stock: | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Granted | 1,526,825 | 15 | — | — | — | — | 15 | — | 15 | |||||||||||||||||||||||||||||||||||||||||||||||
| Repurchased and canceled | (477,789) | (5) | (21,938) | — | — | — | (21,943) | — | (21,943) | |||||||||||||||||||||||||||||||||||||||||||||||
| Forfeited | (350,022) | (3) | — | — | — | — | (3) | — | (3) | |||||||||||||||||||||||||||||||||||||||||||||||
| Contributions from noncontrolling interests | — | — | — | — | — | — | — | 105,528 | 105,528 | |||||||||||||||||||||||||||||||||||||||||||||||
| Distributions to noncontrolling interests | — | — | — | — | — | — | — | (14,404) | (14,404) | |||||||||||||||||||||||||||||||||||||||||||||||
| Balance at December 31, 2019 | 371,074,036 | $ | 3,711 | $ | 1,274,732 | $ | — | $ | — | $ | 5,463,224 | $ | 6,741,667 | $ | 366,684 | $ | 7,108,351 | |||||||||||||||||||||||||||||||||||||||
| Net loss | — | — | — | — | — | (596,869) | (596,869) | (8,692) | (605,561) | |||||||||||||||||||||||||||||||||||||||||||||||
| Cumulative effect adjustment from adoption of ASU 2016-13 | — | — | — | — | — | (137) | (137) | — | (137) | |||||||||||||||||||||||||||||||||||||||||||||||
| Cash dividends declared | — | — | — | — | — | (18,580) | (18,580) | — | (18,580) | |||||||||||||||||||||||||||||||||||||||||||||||
| Change in dividends payable | — | — | — | — | — | 8 | 8 | — | 8 | |||||||||||||||||||||||||||||||||||||||||||||||
| Common stock repurchased | — | — | — | — | (126,906) | — | (126,906) | — | (126,906) | |||||||||||||||||||||||||||||||||||||||||||||||
| Common stock retired | (8,122,104) | (81) | (126,825) | — | 126,906 | — | — | — | — | |||||||||||||||||||||||||||||||||||||||||||||||
| Stock-based compensation | — | — | 64,585 | — | — | — | 64,585 | — | 64,585 | |||||||||||||||||||||||||||||||||||||||||||||||
| Restricted stock: | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Granted | 2,738,625 | 27 | — | — | — | — | 27 | — | 27 | |||||||||||||||||||||||||||||||||||||||||||||||
| Repurchased and canceled | (306,845) | (3) | (7,344) | — | — | (7,347) | — | (7,347) | ||||||||||||||||||||||||||||||||||||||||||||||||
| Forfeited | (163,277) | (2) | — | — | — | — | (2) | — | (2) | |||||||||||||||||||||||||||||||||||||||||||||||
| Contributions from noncontrolling interests | — | — | — | — | — | — | — | 21,557 | 21,557 | |||||||||||||||||||||||||||||||||||||||||||||||
| Distributions to noncontrolling interests | — | — | — | — | — | — | — | (13,270) | (13,270) | |||||||||||||||||||||||||||||||||||||||||||||||
| Balance at December 31, 2020 | 365,220,435 | $ | 3,652 | $ | 1,205,148 | $ | — | $ | — | $ | 4,847,646 | $ | 6,056,446 | $ | 366,279 | $ | 6,422,725 | |||||||||||||||||||||||||||||||||||||||
| Net income | — | — | — | — | — | 1,660,968 | 1,660,968 | 5,440 | 1,666,408 | |||||||||||||||||||||||||||||||||||||||||||||||
| Cash dividends declared | — | — | — | — | — | (168,536) | (168,536) | — | (168,536) | |||||||||||||||||||||||||||||||||||||||||||||||
| Change in dividends payable | — | — | — | — | — | 133 | 133 | — | 133 | |||||||||||||||||||||||||||||||||||||||||||||||
| Common stock repurchased | — | — | — | — | (123,924) | — | (123,924) | — | (123,924) | |||||||||||||||||||||||||||||||||||||||||||||||
| Common stock retired | (3,198,571) | (32) | (123,892) | — | 123,924 | — | — | — | — | |||||||||||||||||||||||||||||||||||||||||||||||
| Stock-based compensation | — | — | 63,145 | — | — | — | 63,145 | — | 63,145 | |||||||||||||||||||||||||||||||||||||||||||||||
44
Continental Resources, Inc. and Subsidiaries
Consolidated Statements of Equity
| Year Ended December 31, |
| ||||||||||
In thousands |
| 2023 |
|
| 2022 |
|
| 2021 |
| |||
Cash flows from operating activities: |
|
|
|
|
|
|
|
|
| |||
Net income |
| $ | 3,098,188 |
|
| $ | 4,046,120 |
|
| $ | 1,666,408 |
|
Adjustments to reconcile net income to cash provided by operating activities: |
|
|
|
|
|
|
|
|
| |||
Depreciation, depletion, amortization and accretion |
|
| 2,265,948 |
|
|
| 1,886,491 |
|
|
| 1,893,106 |
|
Property impairments |
|
| 66,798 |
|
|
| 70,417 |
|
|
| 38,370 |
|
Non-cash (gain) loss on derivatives, net |
|
| (686,598 | ) |
|
| 212,976 |
|
|
| (20,814 | ) |
Stock-based compensation |
|
| — |
|
|
| 217,650 |
|
|
| 63,173 |
|
Provision for deferred income taxes |
|
| 328,970 |
|
|
| 398,429 |
|
|
| 519,730 |
|
Equity in net loss of affiliate |
|
| 3,129 |
|
|
| 1,489 |
|
|
| — |
|
Dry hole costs |
|
| — |
|
|
| 12,305 |
|
|
| — |
|
Net (gain) loss on sale of assets and other |
|
| 50,581 |
|
|
| 262 |
|
|
| (5,146 | ) |
Loss on extinguishment of debt |
|
| — |
|
|
| 403 |
|
|
| 290 |
|
Other, net |
|
| 21,594 |
|
|
| 27,294 |
|
|
| 35,614 |
|
Changes in assets and liabilities: |
|
|
|
|
|
|
|
|
| |||
Accounts receivable |
|
| 222,091 |
|
|
| (372,529 | ) |
|
| (694,981 | ) |
Inventories |
|
| (17,600 | ) |
|
| (67,478 | ) |
|
| (33,411 | ) |
Other current assets |
|
| (6,118 | ) |
|
| (10,242 | ) |
|
| (2,144 | ) |
Accounts payable trade |
|
| (38,740 | ) |
|
| 164,071 |
|
|
| 106,367 |
|
Revenues and royalties payable |
|
| (111,738 | ) |
|
| 253,286 |
|
|
| 298,552 |
|
Accrued liabilities and other |
|
| 2,940 |
|
|
| 51,222 |
|
|
| 109,540 |
|
Incentive compensation liability |
|
| (53,429 | ) |
|
| — |
|
|
| — |
|
Current income taxes liability |
|
| (67,593 | ) |
|
| 152,149 |
|
|
| — |
|
Other noncurrent assets and liabilities |
|
| (17,436 | ) |
|
| (4,625 | ) |
|
| (803 | ) |
Net cash provided by operating activities |
|
| 5,060,987 |
|
|
| 7,039,690 |
|
|
| 3,973,851 |
|
Cash flows from investing activities: |
|
|
|
|
|
|
|
|
| |||
Exploration and development |
|
| (3,550,502 | ) |
|
| (2,838,075 | ) |
|
| (2,382,413 | ) |
Purchase of producing crude oil and natural gas properties |
|
| (161,408 | ) |
|
| (421,850 | ) |
|
| (2,548,575 | ) |
Purchase of other property and equipment |
|
| (205,356 | ) |
|
| (68,189 | ) |
|
| (66,598 | ) |
Proceeds from sale of assets |
|
| 390,034 |
|
|
| 5,740 |
|
|
| 8,041 |
|
Contributions to unconsolidated affiliates |
|
| (33,862 | ) |
|
| (212,294 | ) |
|
| — |
|
Net cash used in investing activities |
|
| (3,561,094 | ) |
|
| (3,534,668 | ) |
|
| (4,989,545 | ) |
Cash flows from financing activities: |
|
|
|
|
|
|
|
|
| |||
Credit facility borrowings |
|
| 4,792,000 |
|
|
| 3,886,000 |
|
|
| 1,663,000 |
|
Repayment of credit facility |
|
| (5,742,000 | ) |
|
| (3,226,000 | ) |
|
| (1,323,000 | ) |
Proceeds from issuance of Senior Notes |
|
| — |
|
|
| — |
|
|
| 1,587,776 |
|
Redemption and repurchase of Senior Notes |
|
| (636,000 | ) |
|
| (31,829 | ) |
|
| (630,782 | ) |
Proceeds from other debt |
|
| — |
|
|
| 750,000 |
|
|
| — |
|
Repayment of other debt |
|
| (2,410 | ) |
|
| (2,326 | ) |
|
| (2,243 | ) |
Debt issuance costs |
|
| (242 | ) |
|
| (5,148 | ) |
|
| (12,082 | ) |
Contributions from noncontrolling interests |
|
| 10,580 |
|
|
| 13,665 |
|
|
| 31,493 |
|
Distributions to noncontrolling interests |
|
| (31,156 | ) |
|
| (40,685 | ) |
|
| (22,447 | ) |
Repurchase of common stock prior to take-private transaction |
|
| — |
|
|
| (99,855 | ) |
|
| (123,924 | ) |
Take-private transaction (see Note 1) |
|
| — |
|
|
| (4,312,642 | ) |
|
| — |
|
Repurchase of restricted stock for tax withholdings |
|
| — |
|
|
| (35,444 | ) |
|
| (12,804 | ) |
Dividends paid on common stock |
|
| (2,056 | ) |
|
| (283,838 | ) |
|
| (165,895 | ) |
Net cash provided by (used in) financing activities |
|
| (1,611,284 | ) |
|
| (3,388,102 | ) |
|
| 989,092 |
|
Net change in cash and cash equivalents |
|
| (111,391 | ) |
|
| 116,920 |
|
|
| (26,602 | ) |
Cash and cash equivalents at beginning of period |
|
| 137,788 |
|
|
| 20,868 |
|
|
| 47,470 |
|
Cash and cash equivalents at end of period |
| $ | 26,397 |
|
| $ | 137,788 |
|
| $ | 20,868 |
|
| Restricted stock: | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Granted | 3,050,491 | 31 | — | — | — | — | 31 | — | 31 | |||||||||||||||||||||||||||||||||||||||||||||||
| Repurchased and canceled | (478,697) | (5) | (12,799) | — | — | (12,804) | — | (12,804) | ||||||||||||||||||||||||||||||||||||||||||||||||
| Forfeited | (296,138) | (3) | — | — | — | — | (3) | — | (3) | |||||||||||||||||||||||||||||||||||||||||||||||
| Contributions from noncontrolling interests | — | — | — | — | — | — | — | 33,086 | 33,086 | |||||||||||||||||||||||||||||||||||||||||||||||
| Distributions to noncontrolling interests | — | — | — | — | — | — | — | (23,936) | (23,936) | |||||||||||||||||||||||||||||||||||||||||||||||
| Balance at December 31, 2021 | 364,297,520 | $ | 3,643 | $ | 1,131,602 | $ | — | $ | — | $ | 6,340,211 | $ | 7,475,456 | $ | 380,869 | $ | 7,856,325 | |||||||||||||||||||||||||||||||||||||||
45
Continental Resources, Inc. and Subsidiaries
| Year Ended December 31, | ||||||||||||||||||||
| In thousands | 2021 | 2020 | 2019 | |||||||||||||||||
| Cash flows from operating activities: | ||||||||||||||||||||
| Net income (loss) | $ | 1,666,408 | $ | (605,561) | $ | 774,473 | ||||||||||||||
| Adjustments to reconcile net income (loss) to cash provided by operating activities: | ||||||||||||||||||||
| Depreciation, depletion, amortization and accretion | 1,893,106 | 1,882,458 | 2,019,704 | |||||||||||||||||
| Property impairments | 38,370 | 277,941 | 86,202 | |||||||||||||||||
| Non-cash (gain) loss on derivatives, net | (20,814) | (13,492) | 15,612 | |||||||||||||||||
| Stock-based compensation | 63,173 | 64,613 | 52,044 | |||||||||||||||||
| Provision (benefit) for deferred income taxes | 519,730 | (166,971) | 212,689 | |||||||||||||||||
| Net (gain) loss on sale of assets and other | (5,146) | 187 | (535) | |||||||||||||||||
| (Gain) loss on extinguishment of debt | 290 | (35,719) | 4,584 | |||||||||||||||||
| Other, net | 35,614 | 16,970 | 10,408 | |||||||||||||||||
| Changes in assets and liabilities: | ||||||||||||||||||||
| Accounts receivable | (694,981) | 332,128 | (33,619) | |||||||||||||||||
| Inventories | (33,411) | 12,859 | (21,204) | |||||||||||||||||
| Other current assets | (2,144) | 1,471 | (4,459) | |||||||||||||||||
| Accounts payable trade | 106,367 | (133,977) | (36,359) | |||||||||||||||||
| Revenues and royalties payable | 298,552 | (143,260) | 69,195 | |||||||||||||||||
| Accrued liabilities and other | 109,540 | (66,071) | (36,467) | |||||||||||||||||
| Other noncurrent assets and liabilities | (803) | (1,272) | 3,420 | |||||||||||||||||
| Net cash provided by operating activities | 3,973,851 | 1,422,304 | 3,115,688 | |||||||||||||||||
| Cash flows from investing activities: | ||||||||||||||||||||
| Exploration and development | (2,382,413) | (1,408,149) | (2,783,149) | |||||||||||||||||
| Purchase of producing crude oil and natural gas properties | (2,548,575) | (81,994) | (51,558) | |||||||||||||||||
| Purchase of other property and equipment | (66,598) | (23,994) | (25,983) | |||||||||||||||||
| Proceeds from sale of assets | 8,041 | 2,779 | 88,734 | |||||||||||||||||
| Net cash used in investing activities | (4,989,545) | (1,511,358) | (2,771,956) | |||||||||||||||||
| Cash flows from financing activities: | ||||||||||||||||||||
| Credit facility borrowings | 1,663,000 | 2,052,000 | 1,216,000 | |||||||||||||||||
| Repayment of credit facility | (1,323,000) | (1,947,000) | (1,161,000) | |||||||||||||||||
| Proceeds from issuance of Senior Notes | 1,587,776 | 1,485,000 | — | |||||||||||||||||
| Redemption and repurchase of Senior Notes | (630,782) | (1,343,250) | (500,000) | |||||||||||||||||
| Premium and costs on redemption of Senior Notes | — | (25,173) | (4,167) | |||||||||||||||||
| Proceeds from other debt | — | 26,000 | — | |||||||||||||||||
| Repayment of other debt | (2,243) | (6,679) | (2,352) | |||||||||||||||||
| Debt issuance costs | (12,082) | (4,368) | — | |||||||||||||||||
| Contributions from noncontrolling interests | 31,493 | 27,116 | 109,137 | |||||||||||||||||
| Distributions to noncontrolling interests | (22,447) | (13,809) | (14,164) | |||||||||||||||||
| Repurchase of common stock | (123,924) | (126,906) | (190,239) | |||||||||||||||||
| Repurchase of restricted stock for tax withholdings | (12,804) | (7,347) | (21,943) | |||||||||||||||||
| Dividends paid on common stock | (165,895) | (18,460) | (18,380) | |||||||||||||||||
| Net cash provided by (used in) financing activities | 989,092 | 97,124 | (587,108) | |||||||||||||||||
| Effect of exchange rate changes on cash | — | — | 27 | |||||||||||||||||
| Net change in cash and cash equivalents | (26,602) | 8,070 | (243,349) | |||||||||||||||||
| Cash and cash equivalents at beginning of period | 47,470 | 39,400 | 282,749 | |||||||||||||||||
| Cash and cash equivalents at end of period | $ | 20,868 | $ | 47,470 | $ | 39,400 | ||||||||||||||
Notes to Consolidated Financial Statements
Note 1. Organization and Summary of Significant Accounting Policies
Description of the Company
Continental Resources, Inc. (the “Company”) was formed in 1967 and is incorporated under the laws of the State of Oklahoma. The Company’s principal business is the exploration, development, management, and production of crude oil and natural gas exploration, development, management, and productionassociated products with properties primarily located in the North, South, and East regions offour leading basins in the United States.States – the Bakken field of North Dakota and Montana, the Anadarko Basin of Oklahoma, the Permian Basin of Texas, and the Powder River Basin of Wyoming. Additionally, the Company pursues the acquisition and management of perpetually owned minerals located in certain of its key operating areas.
2022 Take-Private Transaction
In 2021On November 22, 2022, the Company executed strategic acquisitionscompleted a series of take-private transactions with Omega Acquisition, Inc, an entity owned by the Company’s founder, Harold G. Hamm, pursuant to expand its operations intowhich the Permian BasinCompany became wholly owned by Mr. Hamm, certain members of Texashis family and their affiliated entities (the “Hamm Family”). A total of approximately 58.1 million shares of Continental’s common stock were purchased pursuant to the take-private transaction for total cash consideration of approximately $4.31 billion. The 2022 purchase of outstanding shares was funded by Continental through the use of approximately $2.2 billion of cash on hand, $1.3 billion of credit facility borrowings, and the Powder River Basinexecution of Wyoming.a $750 million three-year term loan. See Note 2. Property Acquisitions and Dispositionsthe Consolidated Statements of Equity for additional informationthe year ended December 31, 2022 for the impact on the acquisitions.components of Shareholders’ Equity resulting from the take-private transaction. The Company's North region consistsCompany incurred $32 million of properties northlegal and advisory fees in 2022 in connection with the take-private transaction which are included in the caption “Transaction costs” in the Consolidated Statements of Kansas and westIncome for the year ended December 31, 2022.
Following the consummation of the Mississippi River and includes North Dakota Bakken, Montana Bakken, Powder River Basin, andtransactions in November 2022: (i) our common stock ceased to be listed on the Red River units. The South region includes all properties south of Nebraska and westNew York Stock Exchange, (ii) our common stock was deregistered under Section 12(b) of the Mississippi RiverSecurities Exchange Act of 1934 as amended (the “Exchange Act”), and includes the SCOOP and STACK areas of Oklahoma and the Permian Basin of Texas. The East region is primarily comprised of undeveloped leasehold acreage east(iii) we suspended our reporting obligations under Section 15(d) of the Mississippi RiverExchange Act. As a result, certain of the corporate governance, disclosure, and other provisions applicable to a company with listed equity securities and reporting obligations under the Exchange Act no significant drilling or production operations. For financial reporting purposes,longer apply to us. We will continue to furnish Quarterly Reports on Form 10-Q and Annual Reports on Form 10-K with the Company has one reportable segment due to the similar nature of its business, which is the exploration, development, and production of crude oil and natural gas in the United States.SEC as required by our senior note indentures.
Basis of presentation of consolidated financial statements
The consolidated financial statements include the accounts of the Company, its wholly-owned subsidiaries, and entities in which the Company has a controlling financial interest. Intercompany accounts and transactions have been eliminated upon consolidation. Noncontrolling interests reflected herein represent third party ownership in the net assets of consolidated subsidiaries. The portions of consolidated net income (loss) and equity attributable to the noncontrolling interests are presented separately in the Company’s financial statements. For financial reporting purposes, the Company has one reportable segment due to the similar nature of its business, which is the exploration, development, and production of crude oil, natural gas, and natural gas liquids in the United States.
Investments in entities in which the Company has the ability to exercise significant influence, but does not control, are accounted for using the equity method of accounting. In applying the equity method, the investments are initially recognized at cost and are subsequently adjusted for the Company’s proportionate share of earnings, losses, contributions, and distributions as applicable.
The Company evaluated its December 31, 2023 financial statements for subsequent events through February 22, 2024, the date the financial statements were available to be issued.
Use of estimates
The preparation of financial statements in conformity with accounting principles generally accepted in the United States (“U.S. GAAP”) requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure and estimation of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting periods. Actual results may differ from those estimates. The most significant estimates and assumptions impacting reported results are estimates of the Company’s crude oil and natural gas reserves, which are used to compute depreciation, depletion, amortization and impairment of proved crude oil and natural gas properties.
Continental Resources, Inc. and Subsidiaries
Notes to Consolidated Financial Statements
Cash and cash equivalents
The Company considers all highly liquid investments with original maturities of three months or less to be cash equivalents. The Company maintains its cash and cash equivalents in accounts that may not be federally insured. As of December 31, 2021,2023, the Company had cash deposits in excess of federally insured amounts of approximately $19.4$24.7 million. The Company has not experienced any losses in such accounts and believes it is not exposed to significant credit risk in this area.
Accounts receivable
Receivables arising from crude oil and natural gas sales and joint interest receivables are generally unsecured. Accounts receivable are due within 30 days and are considered delinquent after 60 days. The Company writes off specific receivables when they become noncollectable and any payments subsequently received on those receivables are credited to the allowance for credit losses. Write-offs of noncollectable receivables have historically not been material. The Company’s allowance for credit losses totaled $2.8$3.2 million and $2.5$5.5 million as of December 31, 20212023 and 2020,2022, respectively. See Note 10. Allowance for Credit Losses for additional information.
Concentration of credit risk
The Company is subject to credit risk resulting from the concentration of its crude oil and natural gas receivables with significant purchasers. For the year ended December 31, 2021, sales to the Company’s largest2023, no purchaser accounted for approximately 10%more than 10% of the Company’s total crude oil, natural gas, and natural gas sales. No other purchaser accounted for more than 10% of the Company’s total crude oil and natural gasliquids sales for 2021.2023. The Company generally does not require collateral and does not believe the loss of any single purchaser would materially impact its operating results, as crude oil and natural gas are fungible products with well-established markets and numerous purchasers in various regions.
Table of ContentsInventories
The components of inventory as of December 31, 20212023 and 20202022 consisted of the following:
| December 31, |
| ||||||
In thousands |
| 2023 |
|
| 2022 |
| ||
Tubular goods and equipment |
| $ | 65,205 |
|
| $ | 38,636 |
|
Crude oil |
|
| 125,557 |
|
|
| 130,192 |
|
Natural gas |
|
| — |
|
|
| 4,436 |
|
Total |
| $ | 190,762 |
|
| $ | 173,264 |
|
| December 31, | ||||||||||||||
| In thousands | 2021 | 2020 | ||||||||||||
| Tubular goods and equipment | $ | 12,506 | $ | 13,671 | ||||||||||
| Crude oil | 93,062 | 58,486 | ||||||||||||
| Total | $ | 105,568 | $ | 72,157 | ||||||||||
Crude oil and natural gas properties
The Company uses the successful efforts method of accounting for crude oil and natural gas properties whereby costs incurred to acquire interests in crude oil and natural gas properties, to drill and equip exploratory wells that find proved reserves, to drill and equip development wells, and expenditures for enhanced recovery operations are capitalized. Geological and geophysical costs, seismic costs incurred for exploratory projects, lease rentals and costs associated with unsuccessful exploratory wells or projects are expensed as incurred. Costs of seismic studies that are utilized in development drilling within an area of proved reserves are capitalized as development costs. To the extent a seismic project covers areas of both developmental and exploratory drilling, those seismic costs are proportionately allocated between capitalized development costs and exploration expense. Maintenance and repairs are expensed as incurred.
Under the successful efforts method of accounting, the Company capitalizes exploratory drilling costs on the balance sheet pending determination of whether the well has found proved reserves in economically producible quantities. The Company capitalizes costs associated with the acquisition or construction of support equipment and facilities with the drilling and development costs to which they relate. If proved reserves are found by an exploratory well, the associated capitalized costs become part of well equipment and facilities. However, if proved reserves are not found, the capitalized costs associated with the well are expensed, net of any salvage value.
47
Continental Resources, Inc. and Subsidiaries
Notes to Consolidated Financial Statements
Production expenses are those costs incurred by the Company to operate and maintain its crude oil and natural gas properties and associated equipment and facilities. Production expenses include but are not limited to labor costs to operate the Company’s properties, repairs and maintenance, certain waste water disposal costs, utility costs, certain workover-related costs, and materials and supplies utilized in the Company’s operations.
Service property and equipment
Service property and equipment consist primarily of automobiles and aircraft; machinery and equipment; gathering and recycling systems; storage tanks; office and computer equipment, software, furniture and fixtures; and buildings and improvements. Major renewals and replacements are capitalized and stated at cost, while maintenance and repairs are expensed as incurred.
Depreciation and amortization of service property and equipment are provided in amounts sufficient to expense the cost of depreciable assets to operations over their estimated useful lives using the straight-line method. The estimated useful lives of service property and equipment are as follows:
Service property and equipment | Useful Lives | ||||
Automobiles and aircraft |
| 5-10 | |||
Machinery and equipment |
| 6-30 | |||
Gathering and recycling systems |
| 15-30 | |||
Storage tanks |
| 10-30 | |||
Office and computer equipment, software, furniture and fixtures |
| 3-25 | |||
Buildings and improvements |
| 4-40 |
Depreciation, depletion and amortization
Depreciation, depletion and amortization of capitalized drilling and development costs of producing crude oil and natural gas properties, including related support equipment and facilities, are computed using the unit-of-production method on a field basis based on total estimated proved developed reserves. Amortization of producing leaseholds is based on the unit-of-production method using total estimated proved reserves. In arriving at rates under the unit-of-production method, the quantities of recoverable crude oil and natural gas reserves are established based on estimates made by the Company’s internal geologists and engineers and external independent reserve engineers. Upon sale or retirement of properties, the cost and related accumulated depreciation, depletion and amortization are eliminated from the accounts and the resulting gain or loss, if any, is recognized. Sales of proved properties constituting a part of an amortization base are accounted for as normal retirements with no gain or loss recognized if doing so does not significantly affect the unit-of-production amortization rate. Unit-of-production rates are revised whenever there is an indication of a need, but at least in conjunction with semi-annual reserve reports. Revisions are accounted for prospectively as changes in accounting estimates.
Asset retirement obligations
The Company accounts for its asset retirement obligations by recording the fair value of a liability for an asset retirement obligation in the period in which a legal obligation is incurred and a corresponding increase in the carrying amount of the related long-lived asset. Subsequently, the capitalized asset retirement costs are charged to expense through the depreciation, depletion and amortization of crude oil and natural gas properties and the liability is accreted to the expected future abandonment cost ratably over the related asset’s life.
48
Continental Resources, Inc. and Subsidiaries
Notes to Consolidated Financial Statements
The Company’s primary asset retirement obligations relate to future plugging and abandonment costs and related disposal of facilities on its crude oil and natural gas properties.The following table summarizes the changes in the Company’s future abandonment liabilities from January 1, 20192021 through December 31, 2021:2023:
In thousands |
| 2023 |
|
| 2022 |
|
| 2021 |
| |||
Asset retirement obligations at January 1 |
| $ | 261,087 |
|
| $ | 219,824 |
|
| $ | 179,676 |
|
Accretion expense |
|
| 14,818 |
|
|
| 12,857 |
|
|
| 11,125 |
|
Revisions (1) |
|
| 112,803 |
|
|
| (6,672 | ) |
|
| (1,291 | ) |
Plus: Additions for new assets |
|
| 18,929 |
|
|
| 37,413 |
|
|
| 32,351 |
|
Less: Plugging costs and sold assets |
|
| (5,709 | ) |
|
| (2,335 | ) |
|
| (2,037 | ) |
Total asset retirement obligations at December 31 |
| $ | 401,928 |
|
| $ | 261,087 |
|
| $ | 219,824 |
|
Less: Current portion of asset retirement obligations at December 31 (2) |
|
| 9,971 |
|
|
| 3,935 |
|
|
| 4,123 |
|
Non-current portion of asset retirement obligations at December 31 |
| $ | 391,957 |
|
| $ | 257,152 |
|
| $ | 215,701 |
|
| In thousands | 2021 | 2020 | 2019 | |||||||||||||||||
| Asset retirement obligations at January 1 | $ | 179,676 | $ | 153,673 | $ | 141,360 | ||||||||||||||
| Accretion expense | 11,125 | 9,393 | 8,443 | |||||||||||||||||
| Revisions (1) | (1,291) | 10,743 | (1,762) | |||||||||||||||||
| Plus: Additions for new assets (2) | 32,351 | 7,048 | 8,392 | |||||||||||||||||
| Less: Plugging costs and sold assets | (2,037) | (1,181) | (2,760) | |||||||||||||||||
| Total asset retirement obligations at December 31 | $ | 219,824 | $ | 179,676 | $ | 153,673 | ||||||||||||||
| Less: Current portion of asset retirement obligations at December 31 (3) | 4,123 | 2,482 | 1,899 | |||||||||||||||||
| Non-current portion of asset retirement obligations at December 31 | $ | 215,701 | $ | 177,194 | $ | 151,774 | ||||||||||||||
As of December 31, 20212023 and 2020,2022, net property and equipment on the consolidated balance sheets included $72.8$204.2 million and $56.1$96.5 million, respectively, of net asset retirement costs.
Asset impairment
Impairment losses for unproved properties are generally recognized by amortizing the portion of the properties’ costs which management estimates will not be transferred to proved properties over the lives of the leases based on drilling plans, experience of successful drilling, and the average holding period. The Company’s impairment assessments are affected by economic factors such as the results of exploration activities, commodity price outlooks, anticipated drilling programs, remaining lease terms, and potential shifts in business strategy employed by management.
Debt issuance costs
Costs incurred in connection with the execution of the Company’s notes payable, and revolving credit facility, term loan and any amendments thereto are capitalized and amortized over the terms of the arrangements on a straight-line basis, the use of which approximates the effective interest method. Costs incurred upon the issuances of the Company’s various senior notes (collectively, the “Notes”) were capitalized and are being amortized over the terms of the Notes using the effective interest method.
The Company had aggregate capitalized costs of $60.6$46.5 million and $45.8$56.3 million (net of accumulated amortization of $36.9$37.3 million and $30.5$46.3 million) relating to its long-term debt at December 31, 20212023 and 2020,2022, respectively. The increase in 2021 resulted from the capitalization of costs incurred in connection with the amendment of the Company’s credit facility and the issuance of new senior notes as discussed in Note 8. Long-Term Debt.
Unamortized capitalized costs associated with the Company’s Notes, and note payable, and term loan totaled $50.9 million$39.4 million and $and $42.546.8 million at December 31, 20212023 and 2020,2022, respectively, and are reflected as a reduction of “Long-term debt, net of current portion” on the consolidated balance sheets.
Unamortized capitalized costs associated with the Company’s revolving credit facility totaled $9.7 million$7.1 million and $and $3.39.4 million at December 31, 20212023 and 2020,2022, respectively, and are reflected in “Other noncurrent assets” on the consolidated balance sheets.
For the years ended December 31, 2021, 20202023, 2022 and 2019,2021, the Company recognized amortization expense associated with capitalized debt issuance costs of $7.2$10.0 million, $7.8$9.3 million, and $8.3$7.2 million, respectively, which are reflected in “Interest expense” on the consolidated statements of comprehensive income (loss).income.
49
Continental Resources, Inc. and Subsidiaries
Notes to Consolidated Financial Statements
Derivative instruments
The Company recognizes its derivative instruments on the balance sheet as either assets or liabilities measured at fair value with such amounts classified as current or long-term based on contractual settlement dates. The accounting for the changes in fair value of a derivative depends on the intended use of the derivative and resulting designation. The Company has not designated its derivative instruments as hedges for accounting purposes and, as a result, marks its derivative instruments to fair value and recognizes the changes in fair value in the consolidated statements of comprehensive income (loss) under the caption “Gain (loss) on derivative instruments, net.” See Note 6. Derivative Instruments for additional information.
Fair value of financial instruments
The Company’s financial instruments consist primarily of cash, trade receivables, trade payables, derivative instruments and long-term debt. See Note 7. Fair Value Measurements for a discussion of the methods used to determine fair value for the Company’s financial instruments and the quantification of fair value for its derivatives and long-term debt obligations at December 31, 20212023 and 2020.2022.
Income taxes
Income taxes are accounted for using the asset and liability method under which deferred income taxes are recognized for the future tax effects of temporary differences between financial statement carrying amounts and the tax basis of existing assets and liabilities using the enacted statutory tax rates in effect at period-end. The effect on deferred taxes for a change in tax rates is recognized in income in the period that includes the enactment date. The Company’s policy is to recognize penalties and interest related to unrecognized tax benefits, if any, in income tax expense.
The Company establishes a valuation allowance if it believes it is more likely than not that some or all of its deferred tax assets will not be realized. Significant judgment is applied in evaluating the need for and the magnitude of appropriate valuation allowances against deferred tax assets. See Note 11. Income Taxes for additional information.
Basic net income (loss) per share is computed by dividing net income (loss) attributable to the Company by the weighted-average number of shares outstanding for the period. InPrior to the Hamm Family’s take-private transaction, in periods where the Company hashad net income, diluted earnings per share reflectsreflected the potential dilution of non-vested restricted stock awards, which arewas calculated using the treasury stock method.The following table presents the calculation of basic and diluted weighted average shares outstanding and net income (loss) per share attributable to the Company for the years ended December 31, 2021, 20202023, 2022, and 2019.
| Year ended December 31, | ||||||||||||||||||||
| In thousands, except per share data | 2021 | 2020 | 2019 | |||||||||||||||||
| Net income (loss) attributable to Continental Resources (numerator) | $ | 1,660,968 | $ | (596,869) | $ | 775,641 | ||||||||||||||
| Weighted average shares (denominator): | ||||||||||||||||||||
| Weighted average shares - basic | 360,434 | 361,538 | 370,699 | |||||||||||||||||
| Non-vested restricted stock (1) | 4,019 | — | 1,839 | |||||||||||||||||
| Weighted average shares - diluted | 364,453 | 361,538 | 372,538 | |||||||||||||||||
| Net income (loss) per share attributable to Continental Resources: | ||||||||||||||||||||
| Basic | $ | 4.61 | $ | (1.65) | $ | 2.09 | ||||||||||||||
| Diluted | $ | 4.56 | $ | (1.65) | $ | 2.08 | ||||||||||||||
| Year ended December 31, |
| ||||||||||
In thousands, except per share data |
| 2023 |
|
| 2022 |
|
| 2021 |
| |||
Net income attributable to Continental Resources (numerator) |
| $ | 3,095,827 |
|
| $ | 4,024,558 |
|
| $ | 1,660,968 |
|
Weighted average shares (denominator): |
|
|
|
|
|
|
|
|
| |||
Weighted average shares - basic |
|
| 299,610 |
|
|
| 351,392 |
|
|
| 360,434 |
|
Non-vested restricted stock and restricted stock units (1) |
|
| — |
|
|
| — |
|
|
| 4,019 |
|
Weighted average shares - diluted |
|
| 299,610 |
|
|
| 351,392 |
|
|
| 364,453 |
|
Net income per share attributable to Continental Resources: |
|
|
|
|
|
|
|
|
| |||
Basic |
| $ | 10.33 |
|
| $ | 11.45 |
|
| $ | 4.61 |
|
Diluted |
| $ | 10.33 |
|
| $ | 11.45 |
|
| $ | 4.56 |
|
Note 2. Property Acquisitions and Dispositions
2023
During the year ended December 31, 2023, the Company executed acquisitions of oil and gas properties in various areas for cash consideration totaling $681 million. The Company accounted for each acquisition as an asset acquisition under ASC Topic 805—Business Combinations. Of the purchase prices, a total of $161 million was allocated to proved properties and a total of $520 million was allocated to unproved properties.
50
Continental Resources, Inc. and Subsidiaries
Notes to Consolidated Financial Statements
During the year ended December 31, 2023, the Company executed sales of oil and gas properties in various areas for cash proceeds totaling $390 million and recognized pre-tax net losses on the transactions totaling $51 million. The disposed properties represented an immaterial portion of the Company's production and proved reserves.
2022
During the year ended December 31, 2022, the Company executed acquisitions of oil and gas properties in various areas for cash consideration totaling $714 million. The Company accounted for each acquisition as an asset acquisition under ASC Topic 805—Business Combinations. Of the purchase prices, a total of $422 million was allocated to proved properties and a total of $292 million was allocated to unproved properties.
2021
Permian Basin Acquisition
In December 21, 2021, the Company acquired oil and gas assets and properties from certain subsidiaries of Pioneer Natural Resources Company pursuant to a purchase and sale agreement in which the Company purchased: (a) 100% of the issued and outstanding limited liability company interests of Jagged Peak Energy LLC, which in turn owns 100% of the issued and outstanding limited liability company interests of Parsley SoDe Water LLC; and (b) certain oil and gas assets and properties in the Permian Basin of Texas (collectively, the “Pioneer Acquisition”). The properties included approximately 92,000 net leasehold acres, approximately 50,000 net royalty acres in the same area normalized to a 1/8th royalty, production totaling approximately 42,000 net barrels of oil equivalent per day (78% oil) based on two-stream reporting at the time of closing, and extensive water infrastructure.
The Pioneer Acquisitionacquisition contributed $29.4$29.4 million of revenues and $14.1$14.1 million ($0.04 per basic and diluted share)of net income to the Company's consolidated results during the period of ownership from December 21, 2021 to December 31, 2021, excluding transaction expenses. The Company incurred $13.9$13.9 million of expenses in connection with the transaction which are reflected in the caption “Acquisition“Transaction costs” in the consolidated statements of comprehensive income (loss) for the year ended December 31, 2021.
The table below summarizes the Company'sCompany’s pro forma results as if the Pioneer Acquisition and associated increase in debt described in Note 8. Long-Term Debt had been completed on January 1, 2020 and were combined with the Company's historical results. The following pro forma information is unaudited, is provided for informational purposes only, and does not represent actual results that would have occurred if the Pioneer Acquisition was completed on January 1, 2020, nor are they indicative of future results.
| Year Ended December 31, |
| ||
In millions |
| 2021 |
| |
Pro forma combined total revenues |
| $ | 6,657 |
|
Pro forma combined net income attributable to Continental |
| $ | 2,097 |
|
| Year Ended December 31, | ||||||||||||||
| In millions | 2021 | 2020 | ||||||||||||
| Pro forma combined total revenues | $ | 6,657 | $ | 3,174 | ||||||||||
| Pro forma combined net income (loss) attributable to Continental | $ | 2,097 | $ | (481) | ||||||||||
Powder River Basin Acquisitions
During the year ended December 31, 2021, the Company acquired undeveloped leaseholdcompleted acquisitions of oil and producinggas properties in the Powder River Basin of Wyoming for $206.6 million, consisting of a $21.5 million escrow deposit paid in December 2020 upon execution of a definitive purchase agreement and a $185.1 million payment made at closing in March 2021.cash consideration totaling $453 million. The acquisition wasCompany accounted for each acquisition as an asset acquisition under ASC Topic 805 and included approximately 130,000 net acres and producing properties with production totaling approximately 7,200 net barrels of oil equivalent per day at the time of closing.805—Business Combinations. Of the purchase price, $183prices, a total of $210 million was allocated to proved properties and $24a total of $243 million was allocated to unproved properties. The $21.5 million escrow deposit paid in December 2020 is included in the caption "Other noncurrent assets" on the Company's balance sheet at December 31, 2020, which was subsequently reclassified to "Net property and equipment" on the closing date. The Company recognized approximately $4.9 million of asset retirement obligations and $8.2 million of right-of-use assets and corresponding lease liabilities associated with the acquired properties.
Note 3. Supplemental Cash Flow Information
The following table discloses supplemental cash flow information about cash paid for interest and income tax payments and refunds. Also disclosed is information about investing activities that affects recognized assets and liabilities but does not result in cash receipts or payments.
| Year ended December 31, |
| ||||||||||
In thousands |
| 2023 |
|
| 2022 |
|
| 2021 |
| |||
Supplemental cash flow information: |
|
|
|
|
|
|
|
|
| |||
Cash paid for interest |
| $ | 387,686 |
|
| $ | 279,571 |
|
| $ | 214,727 |
|
Cash paid for income taxes (1) |
|
| 566,253 |
|
|
| 470,147 |
|
|
| 3 |
|
Cash received for income tax refunds |
|
| 2 |
|
|
| 16 |
|
|
| 58 |
|
Non-cash investing activities: |
|
|
|
|
|
|
|
|
| |||
Asset retirement obligation additions and revisions, net |
|
| 131,732 |
|
|
| 30,741 |
|
|
| 31,060 |
|
| Year ended December 31, | ||||||||||||||||||||
| In thousands | 2021 | 2020 | 2019 | |||||||||||||||||
| Supplemental cash flow information: | ||||||||||||||||||||
| Cash paid for interest | $ | 214,727 | $ | 256,633 | $ | 267,421 | ||||||||||||||
| Cash paid for income taxes | 3 | 4 | 229 | |||||||||||||||||
| Cash received for income tax refunds (1) | 58 | 9,600 | 107 | |||||||||||||||||
| Non-cash investing activities: | ||||||||||||||||||||
| Asset retirement obligation additions and revisions, net | 31,060 | 17,791 | 6,630 | |||||||||||||||||
51
Continental Resources, Inc. and Subsidiaries
Notes to Consolidated Financial Statements
As of December 31, 20212023 and 2020,2022, the Company had $242.9$367.2 million and $128.8$344.9 million, respectively, of accrued capital expenditures included in “Net property and equipment” with an offsetting amount in “Accounts payable trade” in the consolidated balance sheets.
Note 4. Net Property and Equipment
Net property and equipment includes the following at December 31, 20212023 and 2020. See 2022.Note 2. Property Acquisitions and Dispositions
for discussion of certain acquisitions executed in 2021 that contributed to the increase in net property and equipment in 2021.December 31, In thousands 2021 2020 Proved crude oil and natural gas properties $ 31,613,656 $ 27,726,954 Unproved crude oil and natural gas properties 1,358,673 368,256 Service properties, equipment and other 484,989 414,066 Total property and equipment 33,457,318 28,509,276 Accumulated depreciation, depletion and amortization (16,481,853) (14,771,984) Net property and equipment $ 16,975,465 $ 13,737,292
| December 31, |
| ||||||
In thousands |
| 2023 |
|
| 2022 |
| ||
Proved crude oil and natural gas properties |
| $ | 37,400,304 |
|
| $ | 34,741,054 |
|
Unproved crude oil and natural gas properties |
|
| 1,775,662 |
|
|
| 1,513,627 |
|
Service properties, equipment and other |
|
| 1,014,093 |
|
|
| 549,528 |
|
Total property and equipment |
|
| 40,190,059 |
|
|
| 36,804,209 |
|
Accumulated depreciation, depletion and amortization |
|
| (20,403,170 | ) |
|
| (18,332,295 | ) |
Net property and equipment |
| $ | 19,786,889 |
|
| $ | 18,471,914 |
|
Note 5. Accrued Liabilities and Other
Accrued liabilities and other includes the following at December 31, 20212023 and 2020:2022:
| December 31, |
| ||||||
In thousands |
| 2023 |
|
| 2022 |
| ||
Prepaid advances from joint interest owners |
| $ | 36,923 |
|
| $ | 15,575 |
|
Accrued compensation |
|
| 88,644 |
|
|
| 81,646 |
|
Accrued production taxes, ad valorem taxes and other non-income taxes |
|
| 133,456 |
|
|
| 145,436 |
|
Accrued interest |
|
| 79,640 |
|
|
| 83,724 |
|
Current portion of asset retirement obligations |
|
| 9,971 |
|
|
| 3,935 |
|
Other |
|
| 5,903 |
|
|
| 13,461 |
|
Accrued liabilities and other |
| $ | 354,537 |
|
| $ | 343,777 |
|
| December 31, | ||||||||||||||
| In thousands | 2021 | 2020 | ||||||||||||
| Prepaid advances from joint interest owners | $ | 18,964 | $ | 25,209 | ||||||||||
| Accrued compensation | 82,844 | 47,985 | ||||||||||||
| Accrued production taxes, ad valorem taxes and other non-income taxes | 90,597 | 40,818 | ||||||||||||
| Accrued interest | 75,983 | 50,009 | ||||||||||||
| Current portion of asset retirement obligations | 4,123 | 2,482 | ||||||||||||
| Other | 13,229 | 510 | ||||||||||||
| Accrued liabilities and other | $ | 285,740 | $ | 167,013 | ||||||||||
Note 6. Derivative Instruments
From time to time the Company enters into derivative contracts to economically hedge against the variability in cash flows associated with future sales of production. The Company recognizes its derivative instruments on the balance sheet as either assets or liabilities measured at fair value. The estimated fair value is based upon various factors, including commodity exchange prices, over-the-counter quotations, and, in the case of collars, volatility, the risk-free interest rate, and the time to expiration. The calculation of the fair value of collars requires the use of an option-pricing model. See Note 7. Fair Value Measurements.
Natural gas derivatives |
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||
|
|
|
|
|
|
| Weighted Average Hedge Price ($/MMBtu) |
| ||||||||||
Period and Type of Contract |
| Average Volumes Hedged |
| Swaps |
|
| Floor |
|
| Ceiling |
| |||||||
January 2024 - December 2024 |
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||
Swaps - Henry Hub |
|
| 618,000 |
|
| MMBtus/day |
| $ | 3.44 |
|
|
|
|
|
|
| ||
Collars - Henry Hub |
|
| 50,000 |
|
| MMBtus/day |
|
|
|
| $ | 3.12 |
|
| $ | 4.09 |
| |
Swaps - WAHA |
|
| 42,000 |
|
| MMBtus/day |
| $ | 3.08 |
|
|
|
|
|
|
| ||
January 2025 - December 2025 |
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||
Swaps - Henry Hub |
|
| 575,000 |
|
| MMBtus/day |
| $ | 3.93 |
|
|
|
|
|
|
| ||
January 2026 - December 2026 |
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||
Swaps - Henry Hub |
|
| 635,000 |
|
| MMBtus/day |
| $ | 4.11 |
|
|
|
|
|
|
| ||
January 2027 - December 2027 |
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||
Swaps - Henry Hub |
|
| 123,000 |
|
| MMBtus/day |
| $ | 4.01 |
|
|
|
|
|
|
| ||
| Natural gas derivatives | Weighted Average Hedge Price ($/MMBtu) | ||||||||||||||||||||||||||||||||||||||||
| Period and Type of Contract | Average Volumes Hedged | Basis Swaps | Swaps | Sold Put | Floor | Ceiling | |||||||||||||||||||||||||||||||||||
| January 2022 - December 2023 | |||||||||||||||||||||||||||||||||||||||||
| Basis Swaps - NGPL TXOK | 75,000 | MMBtus/day | $ | (0.17) | |||||||||||||||||||||||||||||||||||||
| January 2022 - March 2022 | |||||||||||||||||||||||||||||||||||||||||
| Collars - Henry Hub | 90,000 | MMBtus/day | $ | 3.00 | $ | 6.33 | |||||||||||||||||||||||||||||||||||
| Three-way collars - Henry Hub | 280,000 | MMBtus/day | $ | 2.33 | $ | 3.02 | $ | 4.46 | |||||||||||||||||||||||||||||||||
| Swaps - Henry Hub | 45,000 | MMBtus/day | $ | 3.86 | |||||||||||||||||||||||||||||||||||||
| April 2022 - September 2022 | |||||||||||||||||||||||||||||||||||||||||
| Swaps - Henry Hub | 190,000 | MMBtus/day | $ | 4.02 | |||||||||||||||||||||||||||||||||||||
| October 2022 - December 2022 | |||||||||||||||||||||||||||||||||||||||||
| Collars - Henry Hub | 150,000 | MMBtus/day | $ | 3.54 | $ | 5.34 | |||||||||||||||||||||||||||||||||||
| Three-way collars - Henry Hub | 50,000 | MMBtus/day | $ | 3.00 | $ | 4.07 | $ | 5.00 | |||||||||||||||||||||||||||||||||
| Swaps - Henry Hub | 50,000 | MMBtus/day | $ | 4.20 | |||||||||||||||||||||||||||||||||||||
| January 2023 - December 2023 | |||||||||||||||||||||||||||||||||||||||||
| Collars - Henry Hub | 62,500 | MMBtus/day | $ | 3.41 | $ | 4.87 | |||||||||||||||||||||||||||||||||||
| Three-way collars - Henry Hub | 12,500 | MMBtus/day | $ | 3.00 | $ | 4.32 | $ | 5.00 | |||||||||||||||||||||||||||||||||
| Swaps - Henry Hub | 175,000 | MMBtus/day | $ | 3.38 | |||||||||||||||||||||||||||||||||||||
| January 2024 - December 2024 | |||||||||||||||||||||||||||||||||||||||||
| Swaps - Henry Hub | 125,000 | MMBtus/day | $ | 3.12 | |||||||||||||||||||||||||||||||||||||
| Collars - Henry Hub | 25,000 | MMBtus/day | $ | 3.10 | $ | 4.18 | |||||||||||||||||||||||||||||||||||
| January 2025 - December 2025 | |||||||||||||||||||||||||||||||||||||||||
| Swaps - Henry Hub | 10,000 | MMBtus/day | $ | 3.08 | |||||||||||||||||||||||||||||||||||||
52
Continental Resources, Inc. and Subsidiaries
Notes to Consolidated Financial Statements
Crude oil derivatives |
|
|
|
|
|
|
|
|
|
|
| |||
|
|
|
|
|
|
| Weighted Average |
| ||||||
Period and Type of Contract |
| Average Volumes Hedged |
| Roll Swaps |
|
| Fixed Swaps |
| ||||||
January 2024 - December 2024 |
|
|
|
|
|
|
|
|
|
|
| |||
Fixed Swaps - WTI |
|
| 76,000 |
|
| Bbls/day |
|
|
|
| $ | 76.84 |
| |
January 2024 - December 2024 |
|
|
|
|
|
|
|
|
|
|
| |||
Roll Swaps - NYMEX |
|
| 36,000 |
|
| Bbls/day |
| $ | 0.71 |
|
|
|
| |
| Crude oil derivatives | |||||||||||||||||
| Period and Type of Contract | Average Volumes Hedged | Weighted Average Hedge Price ($/Bbl) | |||||||||||||||
| January 2022 - March 2022 | |||||||||||||||||
| NYMEX Roll Swaps | 32,500 | Bbls/day | $ | 0.71 | |||||||||||||
| April 2022 - June 2022 | |||||||||||||||||
| NYMEX Roll Swaps | 15,000 | Bbls/day | $ | 0.85 | |||||||||||||
| July 2022 - December 2022 | |||||||||||||||||
| NYMEX Roll Swaps | 7,500 | Bbls/day | $ | 0.90 | |||||||||||||
Cash receipts and payments in the following table reflect the gains or losses on derivative contracts which matured during the applicable period, calculated as the difference between the contract price and the market settlement price of matured contracts. The Company's derivative contracts are settled based upon reported settlement prices on commodity exchanges, with crude oil derivative settlements based on NYMEX West Texas Intermediate ("WTI"(“WTI”) pricing and natural gas derivative settlements based primarily on NYMEX Henry Hub pricing. Non-cash gains and losses below represent the change in fair value of derivative instruments which continued to be held at period end and the reversal of previously recognized non-cash gains or losses on derivative contracts that matured during the period.
| Year ended December 31, |
| ||||||||||
In thousands |
| 2023 |
|
| 2022 |
|
| 2021 |
| |||
Cash received (paid) on derivatives: |
|
|
|
|
|
|
|
|
| |||
Crude oil fixed price swaps |
| $ | 17,989 |
|
| $ | — |
|
| $ | (44,463 | ) |
Crude oil collars |
|
| — |
|
|
| — |
|
|
| (9,365 | ) |
Crude oil NYMEX roll swaps |
|
| 3,519 |
|
|
| (9,234 | ) |
|
| (163 | ) |
Natural gas basis swaps |
|
| 4,818 |
|
|
| 9,674 |
|
|
| — |
|
Natural gas WAHA swaps |
|
| 19,435 |
|
|
| (16,350 | ) |
|
| — |
|
Natural gas fixed price swaps |
|
| 178,529 |
|
|
| (353,326 | ) |
|
| (84,141 | ) |
Natural gas collars |
|
| 29,139 |
|
|
| (66,596 | ) |
|
| (11,546 | ) |
Natural gas three-way collars |
|
| 3,741 |
|
|
| (22,287 | ) |
|
| — |
|
Cash received (paid) on derivatives, net |
|
| 257,170 |
|
|
| (458,119 | ) |
|
| (149,678 | ) |
Non-cash gain (loss) on derivatives: |
|
|
|
|
|
|
|
|
| |||
Crude oil collars |
|
| — |
|
|
| — |
|
|
| 227 |
|
Crude oil fixed price swaps |
|
| 134,548 |
|
|
| 11,696 |
|
|
| — |
|
Crude oil NYMEX roll swaps |
|
| 4,051 |
|
|
| 1,879 |
|
|
| 957 |
|
Natural gas basis swaps |
|
| (8,910 | ) |
|
| 9,088 |
|
|
| (177 | ) |
Natural gas WAHA swaps |
|
| 2,138 |
|
|
| 19,386 |
|
|
| — |
|
Natural gas fixed price swaps |
|
| 513,129 |
|
|
| (219,388 | ) |
|
| 25,565 |
|
Natural gas collars |
|
| 42,240 |
|
|
| (34,303 | ) |
|
| (7,690 | ) |
Natural gas three-way collars |
|
| (598 | ) |
|
| (1,334 | ) |
|
| 1,932 |
|
Non-cash gain (loss) on derivatives, net |
|
| 686,598 |
|
|
| (212,976 | ) |
|
| 20,814 |
|
Gain (loss) on derivative instruments, net |
| $ | 943,768 |
|
| $ | (671,095 | ) |
| $ | (128,864 | ) |
| Year ended December 31, | ||||||||||||||||||||
| In thousands | 2021 | 2020 | 2019 | |||||||||||||||||
| Cash received (paid) on derivatives: | ||||||||||||||||||||
| Crude oil fixed price swaps | $ | (44,463) | $ | (31,179) | $ | — | ||||||||||||||
| Crude oil collars | (9,365) | — | — | |||||||||||||||||
| Crude oil NYMEX roll swaps | (163) | — | — | |||||||||||||||||
| Natural gas fixed price swaps | (84,141) | 1,071 | 58,836 | |||||||||||||||||
| Natural gas collars | (11,546) | 1,958 | 5,859 | |||||||||||||||||
| Cash received (paid) on derivatives, net | (149,678) | (28,150) | 64,695 | |||||||||||||||||
| Non-cash gain (loss) on derivatives: | ||||||||||||||||||||
| Crude oil collars | 227 | (227) | — | |||||||||||||||||
| Crude oil NYMEX roll swaps | 957 | — | — | |||||||||||||||||
| Natural gas fixed price swaps | 25,565 | 2,043 | (10,130) | |||||||||||||||||
| Natural gas basis swaps | (177) | — | — | |||||||||||||||||
| Natural gas collars | (7,690) | 11,676 | (5,482) | |||||||||||||||||
| Natural gas three-way collars | 1,932 | — | — | |||||||||||||||||
| Non-cash gain (loss) on derivatives, net | 20,814 | 13,492 | (15,612) | |||||||||||||||||
| Gain (loss) on derivative instruments, net | $ | (128,864) | $ | (14,658) | $ | 49,083 | ||||||||||||||
Balance sheet offsetting of derivative assets and liabilities
The Company’s derivative contracts are recorded at fair value in the consolidated balance sheets under the captions “Derivative assets,” “Derivative assets, noncurrent,” “Derivative liabilities,” and “Derivative liabilities, noncurrent,” as applicable. Derivative assets and liabilities with the same counterparty that are subject to contractual terms which provide for net settlement are reported on a net basis in the consolidated balance sheets.
53
Continental Resources, Inc. and Subsidiaries
Notes to Consolidated Financial Statements
| December 31, |
| ||||||
In thousands |
| 2023 |
|
| 2022 |
| ||
Commodity derivative assets: |
|
|
|
|
|
| ||
Gross amounts of recognized assets |
| $ | 510,375 |
|
| $ | 50,559 |
|
Gross amounts offset on balance sheet |
|
| (1,862 | ) |
|
| (7,731 | ) |
Net amounts of assets on balance sheet |
|
| 508,513 |
|
|
| 42,828 |
|
Commodity derivative liabilities: |
|
|
|
|
|
| ||
Gross amounts of recognized liabilities |
|
| (2,448 | ) |
|
| (229,230 | ) |
Gross amounts offset on balance sheet |
|
| 1,862 |
|
|
| 7,731 |
|
Net amounts of liabilities on balance sheet |
| $ | (586 | ) |
| $ | (221,499 | ) |
| December 31, | ||||||||||||||
| In thousands | 2021 | 2020 | ||||||||||||
| Commodity derivative assets: | ||||||||||||||
| Gross amounts of recognized assets | $ | 42,903 | $ | 15,900 | ||||||||||
| Gross amounts offset on balance sheet | (7,381) | (597) | ||||||||||||
| Net amounts of assets on balance sheet | 35,522 | 15,303 | ||||||||||||
| Commodity derivative liabilities: | ||||||||||||||
| Gross amounts of recognized liabilities | (8,598) | (2,408) | ||||||||||||
| Gross amounts offset on balance sheet | 7,381 | 597 | ||||||||||||
| Net amounts of liabilities on balance sheet | $ | (1,217) | $ | (1,811) | ||||||||||
The following table reconciles the net amounts disclosed above to the individual financial statement line items in the consolidated balance sheets.
| December 31, |
| ||||||
In thousands |
| 2023 |
|
| 2022 |
| ||
Derivative assets |
| $ | 353,261 |
|
| $ | 39,280 |
|
Derivative assets, noncurrent |
|
| 155,252 |
|
|
| 3,548 |
|
Net amounts of assets on balance sheet |
|
| 508,513 |
|
|
| 42,828 |
|
Derivative liabilities |
|
| — |
|
|
| (88,136 | ) |
Derivative liabilities, noncurrent |
|
| (586 | ) |
|
| (133,363 | ) |
Net amounts of liabilities on balance sheet |
|
| (586 | ) |
|
| (221,499 | ) |
Total derivative assets (liabilities), net |
| $ | 507,927 |
|
| $ | (178,671 | ) |
| December 31, | ||||||||||||||
| In thousands | 2021 | 2020 | ||||||||||||
| Derivative assets | $ | 22,334 | $ | 15,303 | ||||||||||
| Derivative assets, noncurrent | 13,188 | — | ||||||||||||
| Net amounts of assets on balance sheet | 35,522 | 15,303 | ||||||||||||
| Derivative liabilities | (899) | (227) | ||||||||||||
| Derivative liabilities, noncurrent | (318) | (1,584) | ||||||||||||
| Net amounts of liabilities on balance sheet | (1,217) | (1,811) | ||||||||||||
| Total derivative assets, net | $ | 34,305 | $ | 13,492 | ||||||||||
Note 7. Fair Value Measurements
The Company follows a three-level valuation hierarchy for disclosure of fair value measurements. The valuation hierarchy categorizes assets and liabilities measured at fair value into one of three different levels depending on the observability of the inputs employed in the measurement. The three levels are defined as follows:
A financial instrument’s categorization within the hierarchy is based upon the lowest level of input that is significant to the fair value measurement. Level 1 inputs are given the highest priority in the fair value hierarchy while Level 3 inputs are given the lowest priority. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the placement of assets and liabilities within the levels of the hierarchy. As Level 1 inputs generally provide the most reliable evidence of fair value, the Company uses Level 1 inputs when available.
54
Continental Resources, Inc. and Subsidiaries
Notes to Consolidated Financial Statements
The Company’s derivative instruments are reported at fair value on a recurring basis. In determining the fair values of swap contracts, a discounted cash flow method is used due to the unavailability of relevant comparable market data for the Company’s exact contracts. The discounted cash flow method estimates future cash flows based on quoted market prices for forward commodity prices and a risk-adjusted discount rate. The fair values of swap contracts are calculated mainly using significant observable inputs (Level 2). Calculation of the fair values of collars requires the use of an industry-standard option pricing model that considers various inputs including quoted forward prices for commodities, time value, volatility factors, and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. These assumptions are observable in the marketplace or can be corroborated by active markets or broker quotes and are therefore designated as Level 2 within the valuation hierarchy. The Company’s calculation of fair value for each of its derivative positions is compared to the counterparty valuation for reasonableness.
The following tables summarize the valuation of derivative instruments by pricing levels that were accounted for at fair value on a recurring basis as of December 31, 20212023 and 2020.2022.
| Fair value measurements at December 31, 2023 using: |
|
|
|
| |||||||||||
In thousands |
| Level 1 |
|
| Level 2 |
|
| Level 3 |
|
| Total |
| ||||
Derivative assets (liabilities): |
|
|
|
|
|
|
|
|
|
|
|
| ||||
Crude oil fixed price swaps |
| $ | — |
|
| $ | 146,243 |
|
| $ | — |
|
| $ | 146,243 |
|
Crude oil NYMEX roll swaps |
|
| — |
|
|
| 6,888 |
|
|
| — |
|
|
| 6,888 |
|
Natural gas WAHA swaps |
|
| — |
|
|
| 21,523 |
|
|
| — |
|
|
| 21,523 |
|
Natural gas fixed price swaps |
|
| — |
|
|
| 321,350 |
|
|
| — |
|
|
| 321,350 |
|
Natural gas collars |
|
| — |
|
|
| 11,923 |
|
|
| — |
|
|
| 11,923 |
|
Total |
| $ | — |
|
| $ | 507,927 |
|
| $ | — |
|
| $ | 507,927 |
|
| Fair value measurements at December 31, 2022 using: |
|
|
|
| |||||||||||
In thousands |
| Level 1 |
|
| Level 2 |
|
| Level 3 |
|
| Total |
| ||||
Derivative assets (liabilities): |
|
|
|
|
|
|
|
|
|
|
|
| ||||
Crude oil fixed price swaps |
| $ | — |
|
| $ | 11,696 |
|
| $ | — |
|
| $ | 11,696 |
|
Crude oil NYMEX roll swaps |
|
| — |
|
|
| 2,836 |
|
|
| — |
|
|
| 2,836 |
|
Natural gas basis swaps |
|
| — |
|
|
| 8,910 |
|
|
| — |
|
|
| 8,910 |
|
Natural gas WAHA swaps |
|
| — |
|
|
| 19,386 |
|
|
| — |
|
|
| 19,386 |
|
Natural gas fixed price swaps |
|
| — |
|
|
| (191,779 | ) |
|
| — |
|
|
| (191,779 | ) |
Natural gas collars |
|
| — |
|
|
| (30,318 | ) |
|
| — |
|
|
| (30,318 | ) |
Natural gas three-way collars |
|
| — |
|
|
| 598 |
|
|
| — |
|
|
| 598 |
|
Total |
| $ | — |
|
| $ | (178,671 | ) |
| $ | — |
|
| $ | (178,671 | ) |
| Fair value measurements at December 31, 2021 using: | ||||||||||||||||||||||||||
| In thousands | Level 1 | Level 2 | Level 3 | Total | ||||||||||||||||||||||
| Derivative assets (liabilities): | ||||||||||||||||||||||||||
| Fixed price swaps | $ | — | $ | 27,608 | $ | — | $ | 27,608 | ||||||||||||||||||
| Basis swaps | — | (177) | — | (177) | ||||||||||||||||||||||
| Collars | — | 3,986 | — | 3,986 | ||||||||||||||||||||||
| Three-way collars | — | 1,931 | — | 1,931 | ||||||||||||||||||||||
| NYMEX roll swaps | — | 957 | — | 957 | ||||||||||||||||||||||
| Total | $ | — | $ | 34,305 | $ | — | $ | 34,305 | ||||||||||||||||||
| Fair value measurements at December 31, 2020 using: | ||||||||||||||||||||||||||
| In thousands | Level 1 | Level 2 | Level 3 | Total | ||||||||||||||||||||||
| Derivative assets (liabilities): | ||||||||||||||||||||||||||
| Swaps | — | $ | 2,043 | — | 2,043 | |||||||||||||||||||||
| Collars | — | 11,449 | — | 11,449 | ||||||||||||||||||||||
| Total | $ | — | $ | 13,492 | $ | — | $ | 13,492 | ||||||||||||||||||
Assets Measured at Fair Value on a Nonrecurring Basis
Certain assets are reported at fair value on a nonrecurring basis in the consolidated financial statements. The following methods and assumptions were used to estimate the fair values for those assets.
Asset impairments – Proved crude oil and natural gas properties are reviewed for impairment on a field-by-field basis each quarter. The estimated future cash flows expected in connection with the field are compared to the carrying amount of the field to determine if the carrying amount is recoverable. If the carrying amount of the field exceeds its estimated undiscounted future cash flows, the carrying amount of the field is reduced to its estimated fair value. Risk-adjusted probable and possible reserves may be taken into consideration when determining estimated future net cash flows and fair value when such reserves exist and are economically recoverable. Due to the unavailability of relevant comparable market data, a discounted cash flow method is used to determine the fair value of proved properties. Significant unobservable inputs (Level 3) utilized in the determination of discounted future net cash flows include future commodity prices adjusted for differentials, forecasted production based on decline curve analysis, estimated future operating and development costs, property ownership interests, and a 10%10% discount rate. At December 31, 2021,2023, the Company'sCompany’s commodity price assumptions were based on forward NYMEX strip prices through year-end 20262028 and were then escalated at 3%3% per year thereafter. Operating cost assumptions were based on current costs escalated at 3%3% per year beginning in 2023.2025.
55
Continental Resources, Inc. and Subsidiaries
Notes to Consolidated Financial Statements
Unobservable inputs to the Company'sCompany’s fair value assessments are reviewed and revised as warranted based on a number of factors, including reservoir performance, new drilling, crude oil and natural gas prices, changes in costs, technological advances, new geological or geophysical data, or other economic factors. Fair value measurements of proved properties are reviewed and approved by certain members of the Company’s management.
Certain unproved crude oil and natural gas properties were impaired during the years ended December 31, 2021, 2020,2023, 2022, and 2019,2021, reflecting recurring amortization of undeveloped leasehold costs on properties the Company expects will not be transferred to proved properties over the lives of the leases based on drilling plans, experience of successful drilling, and the average holding period.
The following table sets forth the non-cash impairments of both proved and unproved properties for the indicated periods. Proved and unproved property impairments are recorded under the caption “Property impairments” in the consolidated statements of comprehensive income (loss).income.
| Year ended December 31, |
| ||||||||||
In thousands |
| 2023 |
|
| 2022 |
|
| 2021 |
| |||
Proved property impairments |
| $ | 15,455 |
|
| $ | 17,520 |
|
| $ | — |
|
Unproved property impairments |
|
| 51,343 |
|
|
| 52,897 |
|
|
| 38,370 |
|
Total |
| $ | 66,798 |
|
| $ | 70,417 |
|
| $ | 38,370 |
|
| Year ended December 31, | ||||||||||||||||||||
| In thousands | 2021 | 2020 | 2019 | |||||||||||||||||
| Proved property and inventory impairments | $ | — | $ | 207,119 | $ | 3,745 | ||||||||||||||
| Unproved property impairments | 38,370 | 70,822 | 82,457 | |||||||||||||||||
| Total | $ | 38,370 | $ | 277,941 | $ | 86,202 | ||||||||||||||
Financial Instruments Not Recorded at Fair Value
The following table sets forth the estimated fair values of financial instruments that are not recorded at fair value in the consolidated financial statements. See Note 8. Long-Term Debt for discussion of the changes in the Company'sCompany’s outstanding debt during the year ended December 31, 2021.in 2023 and 2022.
| December 31, 2023 |
|
| December 31, 2022 |
| |||||||||||
In thousands |
| Carrying Amount |
|
| Estimated Fair Value |
|
| Carrying Amount |
|
| Estimated Fair Value |
| ||||
Debt: |
|
|
|
|
|
|
|
|
|
|
|
| ||||
Credit facility |
| $ | 210,000 |
|
| $ | 210,000 |
|
| $ | 1,160,000 |
|
| $ | 1,160,000 |
|
Term Loan |
|
| 748,092 |
|
|
| 748,092 |
|
|
| 747,073 |
|
|
| 747,073 |
|
Notes payable |
|
| 17,642 |
|
|
| 16,300 |
|
|
| 20,041 |
|
|
| 18,300 |
|
4.5% Senior Notes due 2023 |
|
| — |
|
|
| — |
|
|
| 635,648 |
|
|
| 633,600 |
|
3.8% Senior Notes due 2024 |
|
| 892,610 |
|
|
| 886,400 |
|
|
| 891,404 |
|
|
| 867,400 |
|
2.268% Senior Notes due 2026 |
|
| 795,541 |
|
|
| 736,400 |
|
|
| 794,062 |
|
|
| 693,100 |
|
4.375% Senior Notes due 2028 |
|
| 994,327 |
|
|
| 968,000 |
|
|
| 993,076 |
|
|
| 917,200 |
|
5.75% Senior Notes due 2031 |
|
| 1,485,460 |
|
|
| 1,490,900 |
|
|
| 1,483,843 |
|
|
| 1,412,300 |
|
2.875% Senior Notes due 2032 |
|
| 792,977 |
|
|
| 647,100 |
|
|
| 792,238 |
|
|
| 600,900 |
|
4.9% Senior Notes due 2044 |
|
| 692,463 |
|
|
| 556,400 |
|
|
| 692,255 |
|
|
| 527,900 |
|
Total debt |
| $ | 6,629,112 |
|
| $ | 6,259,592 |
|
| $ | 8,209,640 |
|
| $ | 7,577,773 |
|
| December 31, 2021 | December 31, 2020 | |||||||||||||||||||||||||
| In thousands | Carrying Amount | Estimated Fair Value | Carrying Amount | Estimated Fair Value | ||||||||||||||||||||||
| Debt: | ||||||||||||||||||||||||||
| Credit facility | $ | 500,000 | $ | 500,000 | $ | 160,000 | $ | 160,000 | ||||||||||||||||||
| Notes payable | 22,356 | 22,000 | 24,590 | 24,700 | ||||||||||||||||||||||
| 5% Senior Notes due 2022 | — | — | 630,470 | 632,900 | ||||||||||||||||||||||
| 4.5% Senior Notes due 2023 | 648,078 | 670,200 | 646,943 | 669,900 | ||||||||||||||||||||||
| 3.8% Senior Notes due 2024 | 908,061 | 950,000 | 906,922 | 939,500 | ||||||||||||||||||||||
| 2.268% Senior Notes due 2026 | 792,621 | 795,200 | — | — | ||||||||||||||||||||||
| 4.375% Senior Notes due 2028 | 991,880 | 1,082,100 | 990,746 | 1,024,400 | ||||||||||||||||||||||
| 5.75% Senior Notes due 2031 | 1,482,319 | 1,769,600 | 1,480,879 | 1,651,900 | ||||||||||||||||||||||
| 2.875% Senior Notes due 2032 | 791,521 | 780,500 | — | — | ||||||||||||||||||||||
| 4.9% Senior Notes due 2044 | 692,056 | 781,500 | 691,868 | 689,600 | ||||||||||||||||||||||
| Total debt | $ | 6,828,892 | $ | 7,351,100 | $ | 5,532,418 | $ | 5,792,900 | ||||||||||||||||||
The fair value of credit facility and term loan borrowings approximate carrying value based on borrowing rates available to the Company for bank loans with similar terms and maturities and are classified as Level 2 in the fair value hierarchy.
The fair value of notes payable is determined using a discounted cash flow approach based on the interest rate and payment terms of the notes payable and an assumed discount rate. The fair value of notes payable is significantly influenced by the discount rate assumption, which is derived by the Company and is unobservable. Accordingly, the fair value of notes payable is classified as Level 3 in the fair value hierarchy.
The carrying values of all classes of cash and cash equivalents, trade receivables, and trade payables are considered to be representative of their respective fair values due to the short term maturities of those instruments.
56
Continental Resources, Inc. and Subsidiaries
Notes to Consolidated Financial Statements
Note 8. Long-Term Debt
The Company's debt, net of unamortized discounts, premiums, and debt issuance costs totaling $54.2$41.7 million and $43.7$49.6 million at December 31, 20212023 and 2020,2022, respectively, consists of the following.
| December 31, |
| ||||||
In thousands |
| 2023 |
|
| 2022 |
| ||
Credit facility |
| $ | 210,000 |
|
| $ | 1,160,000 |
|
Term loan |
|
| 748,092 |
|
|
| 747,073 |
|
Notes payable |
|
| 17,642 |
|
|
| 20,041 |
|
4.5% Senior Notes due 2023 |
|
| — |
|
|
| 635,648 |
|
3.8% Senior Notes due 2024 (1) |
|
| 892,610 |
|
|
| 891,404 |
|
2.268% Senior Notes due 2026 |
|
| 795,541 |
|
|
| 794,062 |
|
4.375% Senior Notes due 2028 |
|
| 994,327 |
|
|
| 993,076 |
|
5.75% Senior Notes due 2031 |
|
| 1,485,460 |
|
|
| 1,483,843 |
|
2.875% Senior Notes due 2032 |
|
| 792,977 |
|
|
| 792,238 |
|
4.9% Senior Notes due 2044 |
|
| 692,463 |
|
|
| 692,255 |
|
Total debt |
|
| 6,629,112 |
|
|
| 8,209,640 |
|
Less: Current portion of long-term debt |
|
| 895,105 |
|
|
| 638,058 |
|
Long-term debt, net of current portion |
| $ | 5,734,007 |
|
| $ | 7,571,582 |
|
(1) The Company’s 2024 Notes, which have a face value of $893.1 million at December 31, 2023, are scheduled to mature on June 1, 2024 and, accordingly, are included as a current liability in the caption “Current portion of long-term debt” in the consolidated balance sheets as of December 31, 2023 along with the current portion of the Company's notes payable.
| December 31, | ||||||||||||||
| In thousands | 2021 | 2020 | ||||||||||||
| Credit facility | $ | 500,000 | $ | 160,000 | ||||||||||
| Notes payable | 22,356 | 24,590 | ||||||||||||
| 5% Senior Notes due 2022 | — | 630,470 | ||||||||||||
| 4.5% Senior Notes due 2023 | 648,078 | 646,943 | ||||||||||||
| 3.8% Senior Notes due 2024 | 908,061 | 906,922 | ||||||||||||
| 2.268% Senior Notes due 2026 | 792,621 | — | ||||||||||||
| 4.375% Senior Notes due 2028 | 991,880 | 990,746 | ||||||||||||
| 5.75% Senior Notes due 2031 | 1,482,319 | 1,480,879 | ||||||||||||
| 2.875% Senior Notes due 2032 | 791,521 | — | ||||||||||||
| 4.9% Senior Notes due 2044 | 692,056 | 691,868 | ||||||||||||
| Total debt | 6,828,892 | 5,532,418 | ||||||||||||
| Less: Current portion of long-term debt | 2,326 | 2,245 | ||||||||||||
| Long-term debt, net of current portion | $ | 6,826,566 | $ | 5,530,173 | ||||||||||
Credit Facility
The Company replaced itshas a credit facility, which resultedmaturing in an increase inOctober 2026, with aggregate lender commitments from $1.5 billion to $1.7 billion and an extension of the maturity date from April 2023 to October 2026. On November 22, 2021, the Company incrementally increased the amount of aggregate credit facility commitments from $1.7 billion to $2.0totaling $2.255 billion. The new credit facility provides for benchmark replacement mechanics to address the transition from LIBOR, while all other terms, conditions, and covenants remain substantially unchanged from the prior credit facility. The Company's credit facility is unsecured and has no borrowing base requirement subject to redetermination.
The Company had $500$210 million of outstanding borrowings on its credit facility at December 31, 2021, which were incurred to fund a portion of the Company's December 2021 acquisition of properties in the Permian Basin of Texas as discussed in 2023Note 2. Property Acquisitions and Dispositions.. Credit facility borrowings bear interest at market-based interest rates plus a margin based on the terms of the borrowing and the credit ratings assigned to the Company'sCompany’s senior, unsecured, long-term indebtedness. The weighted-average interest rate on outstanding credit facility borrowings at December 31, 20212023 was 1.6%6.95%.
The Company had approximately $1.50$2.04 billion of borrowing availability on its credit facility at December 31, 20212023 after considering outstanding borrowings and letters of credit. The Company incurs commitment fees based on currently assigned credit ratings of 0.20%0.20% per annum on the daily average amount of unused borrowing availability.
The credit facility contains certain restrictive covenants including a requirement that the Company maintain a consolidated net debt to total capitalization ratio of no greater than 0.65 to 1.00. This ratio represents the ratio of net debt (calculated as total face value of debt plus outstanding letters of credit less cash and cash equivalents) divided by the sum of net debt plus total shareholders’ equity plus, to the extent resulting in a reduction of total shareholders’ equity, the amount of any non-cash impairment charges incurred, net of any tax effect, after June 30, 2014. The Company was in compliance with the credit facility covenants at December 31, 2021.
The following table summarizes the face values, maturity dates, semi-annual interest payment dates, and optional redemption periods related to the Company’s outstanding senior note obligations at December 31, 2021.2023.
| 2024 Notes |
|
| 2026 Notes |
|
| 2028 Notes |
|
| 2031 Notes |
|
| 2032 Notes |
|
| 2044 Notes |
| |||||||
Face value (in thousands) |
| $ | 893,126 |
|
| $ | 800,000 |
|
| $ | 1,000,000 |
|
| $ | 1,500,000 |
|
| $ | 800,000 |
|
| $ | 700,000 |
|
Maturity date |
| June 1, 2024 |
|
| November 15, 2026 |
|
| January 15, 2028 |
|
| January 15, 2031 |
|
| April 1, 2032 |
|
| June 1, 2044 |
| ||||||
Interest payment dates |
| June 1, Dec 1 |
|
| May 15, Nov 15 |
|
| Jan 15, July 15 |
|
| Jan 15, Jul 15 |
|
| April 1, Oct 1 |
|
| June 1, Dec 1 |
| ||||||
Make-whole redemption period (1) |
| Mar 1, 2024 |
|
| Nov 15, 2023 |
|
| Oct 15, 2027 |
|
| Jul 15, 2030 |
|
| January 1. 2032 |
|
| Dec 1, 2043 |
| ||||||
57
| 2023 Notes | 2024 Notes | 2026 Notes | 2028 Notes | 2031 Notes | 2032 Notes | 2044 Notes | ||||||||||||||||||||||||||||||||||||||
| Face value (in thousands) | $649,625 | $911,000 | $800,000 | $1,000,000 | $1,500,000 | $800,000 | $700,000 | |||||||||||||||||||||||||||||||||||||
| Maturity date | April 15, 2023 | June 1, 2024 | November 15, 2026 | January 15, 2028 | January 15, 2031 | April 1, 2032 | June 1, 2044 | |||||||||||||||||||||||||||||||||||||
| Interest payment dates | April 15, Oct 15 | June 1, Dec 1 | May 15, Nov 15 | Jan 15, July 15 | Jan 15, Jul 15 | April 1, Oct 1 | June 1, Dec 1 | |||||||||||||||||||||||||||||||||||||
| Make-whole redemption period (1) | Jan 15, 2023 | Mar 1, 2024 | Nov 15, 2023 | Oct 15, 2027 | Jul 15, 2030 | January 1. 2032 | Dec 1, 2043 | |||||||||||||||||||||||||||||||||||||
Continental Resources, Inc. and Subsidiaries
Notes to Consolidated Financial Statements
The Company’s senior notes are not subject to any mandatory redemption or sinking fund requirements.
The indentures governing the Company’s senior notes contain covenants that, among other things, limit the Company’s ability to create liens securing certain indebtedness, enter into certain sale-leaseback transactions, or consolidate, merge or transfer certain assets. These covenants are subject to a number of important exceptions and qualifications. The Company was in compliance with these covenants at December 31, 2021.
The senior notes are obligations of Continental Resources, Inc. Additionally, as of December 31, 2021 threecertain of the Company’s wholly-owned consolidated subsidiaries Banner(Banner Pipeline Company, L.L.C., CLR Asset Holdings, LLC, and The Mineral Resources Company, whose assets, equity,SCS1 Holdings LLC, Continental Innovations LLC, Jagged Peak Energy LLC, and results of operations are not material,Parsley SoDe Water LLC) fully and unconditionally guarantee the senior notes on a joint and several basis. The Company plans to designate Jagged Peak Energy LLC and Parsley SoDe Water LLC, its recently acquiredfinancial information of the guarantor group is not materially different from the consolidated subsidiaries discussed in Note 2. Property Acquisitions and Dispositions, as restricted subsidiaries underfinancial statements of the Company’s senior note indentures. As a result, such entities will fully and unconditionally guarantee the senior notes on a joint and several basis along with the Company’s other subsidiary guarantors.Company. The Company’s other subsidiaries, existing at December 31, 2021, whose assets, equity, and results of operations attributable to the Company are not material, do not guarantee the senior notes.
Issuance of Senior Notes
2021
In November 2021, the Company issued $800 million of 2.268% Senior Notes due 2026 and $800 million of 2.875% Senior Notes due 2032 and received combined total net proceeds from the offerings of $1.59 billion after deducting the initial purchasers' fees and original issuance discount. The Company used the net proceeds from the offerings to finance a portion of its December 2021 acquisition of properties in the Permian Basin as discussed in Note 2. Property Acquisitions and Dispositions.
Retirement of Senior Notes
2023
In January 2021,April 2023, the Company redeemed $400.0fully repaid its outstanding $636 million of 2023 Notes that were scheduled to mature on April 15, 2023. The redemption price was equal to 100% of the principal amount plus accrued and unpaid interest to the redemption date. The aggregate of its outstanding 2022 Notes and subsequently redeemed the remaining $230.8 million principal amount of its 2022 Notes in April 2021. The Company recognized pre-tax losses on extinguishment of debt totaling $0.3 million related to the redemptions, which included the pro-rata write-off of deferred financing costs and unamortized debt premium associated with the redeemed notes. The losses are reflected in the caption “Gain (loss) on extinguishment of debt” in the consolidated statements of comprehensive income (loss).
2022
In March and April 2020,2022, the Company repurchased a portion of its 2023 Notes and 2024 Notes in open market transactions, at a substantial discount to the face value of the notes, including $50.4$13.6 million face value of its 2023 Notes at an aggregate cost of $29.3$13.9 million and $89.0$17.9 million face value of its 2024 Notes at an aggregate cost of $46.9$18.3 million, in each case, including accrued and unpaid interest to the repurchase dates. The Company recognized pre-tax gainslosses on extinguishment of debt totaling
2021
In November 2020,2021, the Company repurchased $469.2fully repaid the $630.8 million principal amount of its outstanding 2022 Notes and $800.0 million of its 2023 Notes using proceeds from its November 2020 issuance of $1.5 billion of 5.75% Senior Notes due 2031. For the 2022 Notes, the purchase price was equal to 100.250% of the principal amount repurchased plus accrued and unpaid interest to the repurchase date. The aggregate of the principal amount, premium, and accrued interest paid upon repurchase of the 2022 Notes was $475.0 million. For the 2023 Notes, the purchase price was equal to 103.000% of the principal amount repurchased plus accrued and unpaid interest to the repurchase date. The aggregate of the principal amount, premium, and accrued interest paid upon repurchase of the 2023 Notes was $828.0 million. The Company recorded pre-tax losses on extinguishment of debt related to these repurchases totaling $28.9 million, which included the premium and pro-rata write-off of deferred financing costs and unamortized debt premium associated with the notes.
Term Loan
In November 2022, the Company borrowed $750 million under a three-year term loan agreement, the proceeds of $4.6 million, which includedwere used to fund a portion of the redemption premiumHamm Family’s November 2022 take-private transaction. The term loan matures in November 2025 and pro-rata write-offbears interest at market-based interest rates plus a margin based on the terms of deferred financing coststhe borrowing and unamortizedthe credit ratings assigned to the Company’s senior, unsecured, long-term indebtedness. The interest rate on the term loan was 6.98% at December 31, 2023.
The term loan contains certain restrictive covenants including a requirement that the Company maintain a consolidated net debt premium associatedto total capitalization ratio of no greater than 0.65 to 1.0, consistent with the notes.covenant requirement in the Company’s revolving credit facility. The Company was in compliance with the term loan covenants at December 31, 2023.
58
Continental Resources, Inc. and Subsidiaries
Notes payableto Consolidated Financial Statements
Notes Payable
In June 2020, the Company borrowed an aggregate of $26.0$26.0 million under two 10-year10-year amortizing term loans secured by the Company’s corporate office building and its interest in parking facilities in Oklahoma City, Oklahoma. The loans mature in May 2030 and bear interest at a fixed rate of 3.50%3.50% per annum through June 9, 2025, at which time the interest rate will be reset and fixed through the maturity date. Principal and interest are payable monthly through the maturity date and, accordingly, $2.3$2.5 million is reflectedincluded as a current liability underin the caption “Current portion of long-term debt” in the consolidated balance sheets as of December 31, 20212023 associated with the loans. A portion of the proceeds from the new loans was used to fully repay the Company's previous note payable that was set to mature in February 2022, which had a balance at pay-off of $4.4 million.
Note 9. Revenues
Below is a discussion of the nature, timing, and presentation of revenues arising from the Company'sCompany’s major revenue-generating arrangements.
Operated crude oil revenues – The Company pays third parties to transport the majority of its operated crude oil production from lease locations to downstream market centers, at which time the Company'sCompany’s customers take title and custody of the product in exchange for prices based on the particular market where the product was delivered. Operated crude oil revenues are recognized during the month in which control transfers to the customer and it is probable the Company will collect the consideration it is entitled to receive. Crude oil sales proceeds from operated properties are generally received by the Company within one month after the month in which a sale has occurred. Operated crude oil revenues are presented separately from transportation expenses, as the Company controls the operated production prior to its transfer to customers. Transportation expenses associated with the Company'sCompany’s operated crude oil production totaled $185.1$284.2 million, $159.0$254.0 million, and $192.0$185.1 million for the years ended December 31, 2021, 2020,2023, 2022, and 2019,2021, respectively.
Operated natural gas revenues – The Company sells thea substantial majority of its operated natural gas production to midstream customers at its lease locations based on market prices in the field where the sales occur. Under these arrangements, the midstream customers obtain control of the unprocessed gas stream inclusive of natural gas liquids (“NGLs”) at the lease location and the Company'sCompany’s revenues from each sale are determined using contractually agreed pricing formulas which contain multiple components, including the volume and Btu content of the natural gas sold, the midstream customer's proceeds from the sale of residue gas and natural gas liquids ("NGLs")NGLs at secondary downstream markets, and contractual pricing adjustments reflecting the midstream customer's estimated recoupment of its investment over time. Such revenues are recognized net of pricing adjustments applied by the midstream customer during the month in which control transfers to the customer at the delivery point and it is probable the Company will collect the consideration it is entitled to receive. Natural gas and NGL sales proceeds from operated properties are generally received by the Company within one month after the month in which a sale has occurred.
Under certain arrangements, the Company has the rightmay elect to take a volume of processed residue gas and/or NGLs in-kind at the tailgate of the midstream customer'scustomer’s processing plant in lieu of a monetary settlement for the sale of the Company's operated natural gas production. When the Company elects to take volumes in kind, it takes possession of the processed products at the tailgate of the processing facility and either sells them at the tailgate or pays third parties to transport the processed products it took in-kind to downstream delivery points, where it then sells to customers at prices applicable to those downstream markets. In such situations, operated revenues are recognized during the month in which control transfers to the customer at the delivery point and it is probable the Company will collect the consideration it is entitled to receive. Operated sales proceeds are generally received by the Company within one month after the month in which a sale has occurred. In these scenarios, the Company'sCompany’s revenues include the pricing adjustments applied by the midstream processing entity according to the applicable contractual pricing formula, but exclude the transportation expenses the Company incurs to transport the processed products to downstream customers. Transportation expenses associated with these arrangements totaled $39.9$54.0 million, $37.7$62.4 million, and $33.7$39.9 million for the years ended December 31, 2021, 2020,2023, 2022, and 2019,2021, respectively.
Non-operated crude oil, and natural gas, and NGL revenues – The Company'sCompany’s proportionate share of production from non-operated properties is generally marketed at the discretion of the operators. For non-operated properties, the Company receives a net payment from the operator representing its proportionate share of sales proceeds which is net of costs incurred by the operator, if any. Such non-operated revenues are recognized at the net amount of proceeds to be received by the Company during the month in which production occurs and it is probable the Company will collect the consideration it is entitled to receive. Proceeds are generally received by the Company within two to three months after the month in which production occurs.
Revenues from derivative instruments – See Note 6. Derivative Instruments for discussion of the Company'sCompany’s accounting for its derivative instruments.
59
Continental Resources, Inc. and Subsidiaries
Notes to Consolidated Financial Statements
Revenues from service operations – Revenues from the Company'sCompany’s crude oil and natural gas service operations consist primarily of revenues associated with water gathering, recycling, delivery, and disposal activities and the treatment and sale of crude oil reclaimed from waste products.activities. Revenues associated with such activities, which are derived using market-based rates or rates commensurate with industry guidelines, are recognized during the month in which services are performed, the Company has an unconditional right to receive payment, and collectability is probable. Payment is generally received by the Company within one month after the month in which services are provided.
The following table presents the disaggregation of the Company'sCompany’s crude oil and natural gas revenues for the periods presented.
| Year ended December 31, | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| 2021 | 2020 | 2019 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||
| In thousands | North Region | South Region | Total | North Region | South Region | Total | North Region | South Region | Total | |||||||||||||||||||||||||||||||||||||||||||||||
| Crude oil revenues: | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Operated properties | $ | 2,392,465 | $ | 838,129 | $ | 3,230,594 | $ | 1,264,149 | $ | 537,961 | $ | 1,802,110 | $ | 2,365,574 | $ | 786,652 | $ | 3,152,226 | ||||||||||||||||||||||||||||||||||||||
| Non-operated properties | 656,727 | 61,973 | 718,700 | 362,952 | 34,914 | 397,866 | 727,068 | 50,700 | 777,768 | |||||||||||||||||||||||||||||||||||||||||||||||
| Total crude oil revenues | 3,049,192 | 900,102 | 3,949,294 | 1,627,101 | 572,875 | 2,199,976 | 3,092,642 | 837,352 | 3,929,994 | |||||||||||||||||||||||||||||||||||||||||||||||
| Natural gas revenues: | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Operated properties (1) | 460,376 | 1,186,937 | 1,647,313 | 28,086 | 301,486 | 329,572 | 109,668 | 411,464 | 521,132 | |||||||||||||||||||||||||||||||||||||||||||||||
| Non-operated properties (2) | 115,420 | 81,714 | 197,134 | 720 | 25,166 | 25,886 | 25,188 | 38,075 | 63,263 | |||||||||||||||||||||||||||||||||||||||||||||||
| Total natural gas revenues | 575,796 | 1,268,651 | 1,844,447 | 28,806 | 326,652 | 355,458 | 134,856 | 449,539 | 584,395 | |||||||||||||||||||||||||||||||||||||||||||||||
| Crude oil and natural gas sales | $ | 3,624,988 | $ | 2,168,753 | $ | 5,793,741 | $ | 1,655,907 | $ | 899,527 | $ | 2,555,434 | $ | 3,227,498 | $ | 1,286,891 | $ | 4,514,389 | ||||||||||||||||||||||||||||||||||||||
| Timing of revenue recognition | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Goods transferred at a point in time | $ | 3,624,988 | $ | 2,168,753 | $ | 5,793,741 | $ | 1,655,907 | $ | 899,527 | $ | 2,555,434 | $ | 3,227,498 | $ | 1,286,891 | $ | 4,514,389 | ||||||||||||||||||||||||||||||||||||||
| Goods transferred over time | — | — | — | — | — | — | — | — | — | |||||||||||||||||||||||||||||||||||||||||||||||
| $ | 3,624,988 | $ | 2,168,753 | $ | 5,793,741 | $ | 1,655,907 | $ | 899,527 | $ | 2,555,434 | $ | 3,227,498 | $ | 1,286,891 | $ | 4,514,389 | |||||||||||||||||||||||||||||||||||||||
| Year ended December 31, |
| ||||||||||||||||||||||||||||||||||
| 2023 |
|
| 2022 |
|
| 2021 |
| ||||||||||||||||||||||||||||
In thousands |
| Crude Oil |
|
| Natural Gas and NGLs |
|
| Total |
|
| Crude Oil |
|
| Natural Gas and NGLs |
|
| Total |
|
| Crude Oil |
|
| Natural Gas and NGLs |
|
| Total |
| |||||||||
Bakken |
| $ | 3,777,412 |
|
| $ | 380,359 |
|
| $ | 4,157,771 |
|
| $ | 3,899,749 |
|
| $ | 1,051,870 |
|
| $ | 4,951,619 |
|
| $ | 2,786,320 |
|
| $ | 562,695 |
|
| $ | 3,349,015 |
|
Anadarko Basin |
|
| 999,009 |
|
|
| 687,687 |
|
|
| 1,686,696 |
|
|
| 1,109,405 |
|
|
| 1,839,473 |
|
|
| 2,948,878 |
|
|
| 874,752 |
|
|
| 1,264,069 |
|
|
| 2,138,821 |
|
Powder River Basin |
|
| 410,963 |
|
|
| 43,968 |
|
|
| 454,931 |
|
|
| 557,943 |
|
|
| 125,065 |
|
|
| 683,008 |
|
|
| 101,705 |
|
|
| 13,110 |
|
|
| 114,815 |
|
Permian Basin |
|
| 1,135,421 |
|
|
| 74,133 |
|
|
| 1,209,554 |
|
|
| 1,122,290 |
|
|
| 151,217 |
|
|
| 1,273,507 |
|
|
| 24,857 |
|
|
| 4,499 |
|
|
| 29,356 |
|
All other |
|
| 175,118 |
|
|
| 193 |
|
|
| 175,311 |
|
|
| 216,616 |
|
|
| 1,047 |
|
|
| 217,663 |
|
|
| 161,660 |
|
|
| 74 |
|
|
| 161,734 |
|
Crude oil, natural gas, and natural gas liquids sales |
| $ | 6,497,923 |
|
| $ | 1,186,340 |
|
| $ | 7,684,263 |
|
| $ | 6,906,003 |
|
| $ | 3,168,672 |
|
| $ | 10,074,675 |
|
| $ | 3,949,294 |
|
| $ | 1,844,447 |
|
| $ | 5,793,741 |
|
The Company satisfies the performance obligations under its crude oil and natural gascommodity sales contracts upon delivery of its production and related transfer of control to customers. Judgment may be required in determining the point in time when control transfers to customers. Upon delivery of production, the Company has a right to receive consideration from its customers in amounts determined by the sales contracts.
The Company's outstanding crude oil sales contracts at December 31, 20212023 are primarily short-term in nature with contract terms of less than one year. For such contracts, the Company has utilized the practical expedient in Accounting Standards Codification ("ASC"(“ASC”) 606-10-50-14 exempting the Company from disclosure of the transaction price allocated to remaining performance obligations, if any, if the performance obligation is part of a contract that has an original expected duration of one year or less.
The substantial majority of the Company'sCompany’s operated natural gas production is sold at lease locations to midstream customers under multi-year term contracts. For such contracts having a term greater than one year, the Company has utilized the practical expedient in ASC 606-10-50-14A which indicates an entity is not required to disclose the transaction price allocated to remaining performance obligations, if any, if variable consideration is allocated entirely to a wholly unsatisfied performance obligation. Under the Company’s commodity sales contracts, whether for crude oil or natural gas, each unit of production delivered to a customer represents a separate performance obligation; therefore, future volumes to be delivered are wholly unsatisfied at period-end and disclosure of the transaction price allocated to remaining performance obligations is not applicable.
Under the Company’s crude oil and natural gascommodity sales contracts or activities that give rise to service revenues, the Company recognizes revenue after its performance obligations have been satisfied, at which point the Company has an unconditional right to receive payment. Accordingly, the Company’s commodity sales contracts and service activities generally do not give rise to contract assets or contract liabilities under ASC Topic 606. Instead, the Company'sCompany’s unconditional rights to receive consideration are presented as a receivable within "Receivables“Receivables–Crude oil, natural gas, and natural gas sales"liquids sales” or "Receivables“Receivables–Joint interest and other,"” as applicable, in its consolidated balance sheets.
Revenues from previously satisfied performance obligations
To record revenues for commodity sales, at the end of each month the Company estimates the amount of production delivered and sold to customers and the prices to be received for such sales. Differences between estimated revenues and actual amounts received
60
Continental Resources, Inc. and Subsidiaries
Notes to Consolidated Financial Statements
for all prior months are recorded in the month payment is received from the customer and are reflected in the financial statements within the caption "Crude“Crude oil, natural gas, and natural gas sales"liquids sales”. Revenues recognized during the years ended December 31, 2021, 2020,2023, 2022, and 20192021 related to performance obligations satisfied in prior reporting periods were not material.
Note 10. Allowance for Credit Losses
The Company'sCompany’s principal exposure to credit risk is through the sale of its crude oil, and natural gas, and NGL production and its receivables associated with billings to joint interest owners. Accordingly, the Company classifies its receivables into two portfolio segments as depicted on the consolidated balance sheets as "Receivables“Receivables—Crude oil, natural gas, and natural gas liquids sales” and "Receivables“Receivables—Joint interest and other.”
Receivables—Crude oil, natural gas, and natural gas liquids sales
The Company'sCompany’s crude oil, and natural gas, and NGL production from operated properties is generally sold to energy marketing companies, crude oil refining companies, and natural gas gathering and processing companies. The Company monitors its credit loss exposure to these counterparties primarily by reviewing credit ratings, financial statements, and payment history. Credit terms are extended based on an evaluation of each counterparty’s credit worthiness. The Company has not generally required its counterparties to provide collateral to secure its crude oil, and natural gas, and NGL sales receivables.
Receivables associated with crude oil, and natural gas, and NGL sales are short term in nature. Receivables from the sale of crude oil, and natural gas, and NGLs from operated properties are generally collected within one month after the month in which a sale has occurred, while receivables associated with non-operated properties are generally collected within two to three months after the month in which production occurs.
The Company’s allowance for credit losses on crude oil, and natural gas, and NGL sales was negligible at both December 31, 20212023 and December 31, 2020.2022. The allowance was determined by considering a number of factors, primarily including the Company’s history of credit losses with adjustment as needed to reflect current conditions, the length of time accounts are past due, whether amounts relate to operated properties or non-operated properties, and the counterparty's ability to pay. There were no significant write-offs, recoveries, or changes in the provision for credit losses on this portfolio segment during the years ended December 31, 2021, 2020,2023, 2022, and 2019.
Receivables—Joint interest and other
Joint interest and other receivables primarily arise from billing the individuals and entities who own a partial interest in the wells we operate. Joint interest receivables are due within 30 days and are considered delinquent after 60 days. In order to minimize our exposure to credit risk with these counterparties we generally request prepayment of drilling costs where it is allowed by contract or state law. Such prepayments are used to offset future capital costs when billed, thereby reducing the Company'sCompany’s credit risk. We may have the right to place a lien on a co-owner's interest in the well, to net production proceeds against amounts owed in order to secure payment or, if necessary, foreclose on the co-owner'sco-owner’s interest.
61
Continental Resources, Inc. and Subsidiaries
Notes to Consolidated Financial Statements
Note 11. Income Taxes
The items comprising the Company'sCompany’s provision (benefit) for income taxes are as follows for the periods presented:
| Year ended December 31, |
| ||||||||||
In thousands |
| 2023 |
|
| 2022 |
|
| 2021 |
| |||
Current income tax provision: |
|
|
|
|
|
|
|
|
| |||
United States federal |
| $ | 461,487 |
|
| $ | 538,704 |
|
| $ | — |
|
Various states |
|
| 37,173 |
|
|
| 83,671 |
|
|
| — |
|
Total current income tax provision |
|
| 498,660 |
|
|
| 622,375 |
|
|
| — |
|
Deferred income tax provision: |
|
|
|
|
|
|
|
|
| |||
United States federal |
|
| 318,484 |
|
|
| 374,802 |
|
|
| 467,051 |
|
Various states |
|
| 10,486 |
|
|
| 23,627 |
|
|
| 52,679 |
|
Total deferred income tax provision |
|
| 328,970 |
|
|
| 398,429 |
|
|
| 519,730 |
|
Provision for income taxes |
| $ | 827,630 |
|
| $ | 1,020,804 |
|
| $ | 519,730 |
|
Effective tax rate |
|
| 21.1 | % |
|
| 20.1 | % |
|
| 23.8 | % |
| Year ended December 31, | ||||||||||||||||||||
| In thousands | 2021 | 2020 | 2019 | |||||||||||||||||
| Current income tax provision (benefit): | ||||||||||||||||||||
| United States federal | $ | — | $ | (2,248) | $ | — | ||||||||||||||
| Various states | — | 29 | — | |||||||||||||||||
| Total current income tax provision (benefit) | — | (2,219) | — | |||||||||||||||||
| Deferred income tax provision (benefit): | ||||||||||||||||||||
| United States federal | 467,051 | (148,828) | 191,328 | |||||||||||||||||
| Various states | 52,679 | (18,143) | 21,361 | |||||||||||||||||
| Total deferred income tax provision (benefit) | 519,730 | (166,971) | 212,689 | |||||||||||||||||
| Provision (benefit) for income taxes | $ | 519,730 | $ | (169,190) | $ | 212,689 | ||||||||||||||
| Effective tax rate | 23.8 | % | 21.8 | % | 21.5 | % | ||||||||||||||
The Company'sCompany’s effective tax rate differs from the United States federal statutory tax rate due to the effect of state income taxes, equityequity/incentive compensation, tax credits, changes in valuation allowances, and other tax items as reflected in the table below.
| Year ended December 31, |
| ||||||||||
In thousands, except tax rates |
| 2023 |
|
| 2022 |
|
| 2021 |
| |||
Income before income taxes |
| $ | 3,928,947 |
|
| $ | 5,068,413 |
|
| $ | 2,186,138 |
|
U.S. federal statutory tax rate |
|
| 21.0 | % |
|
| 21.0 | % |
|
| 21.0 | % |
Expected income tax provision based on U.S. federal statutory tax rate |
|
| 825,079 |
|
|
| 1,064,367 |
|
|
| 459,089 |
|
Items impacting the effective tax rate: |
|
|
|
|
|
|
|
|
| |||
State and local income taxes, net of federal benefit |
|
| 98,257 |
|
|
| 126,932 |
|
|
| 77,979 |
|
Tax (benefit) deficiency from stock-based compensation |
|
| — |
|
|
| (5,282 | ) |
|
| 5,869 |
|
Change in valuation allowance |
|
| — |
|
|
| — |
|
|
| (14,474 | ) |
Tax credits for increasing research activities |
|
| (67,039 | ) |
|
| (151,913 | ) |
|
| — |
|
Other, net |
|
| (28,667 | ) |
|
| (13,300 | ) |
|
| (8,733 | ) |
Provision for income taxes |
| $ | 827,630 |
|
| $ | 1,020,804 |
|
| $ | 519,730 |
|
Effective tax rate |
|
| 21.1 | % |
|
| 20.1 | % |
|
| 23.8 | % |
| Year ended December 31, | ||||||||||||||||||||
| In thousands, except tax rates | 2021 | 2020 | 2019 | |||||||||||||||||
| Income (loss) before income taxes | $ | 2,186,138 | $ | (774,751) | $ | 987,162 | ||||||||||||||
| U.S. federal statutory tax rate | 21.0 | % | 21.0 | % | 21.0 | % | ||||||||||||||
| Expected income tax provision (benefit) based on U.S. federal statutory tax rate | 459,089 | (162,698) | 207,304 | |||||||||||||||||
| Items impacting the effective tax rate: | ||||||||||||||||||||
| State and local income taxes, net of federal benefit | 77,979 | (24,808) | 31,967 | |||||||||||||||||
| Tax (benefit) deficiency from stock-based compensation | 5,869 | 4,927 | (7,971) | |||||||||||||||||
| Sale of Canadian subsidiary and assets | — | — | (16,860) | |||||||||||||||||
| Other, net | (8,733) | (1,085) | (1,751) | |||||||||||||||||
| Change in valuation allowance | (14,474) | 14,474 | — | |||||||||||||||||
| Provision (benefit) for income taxes | $ | 519,730 | $ | (169,190) | $ | 212,689 | ||||||||||||||
| Effective tax rate | 23.8 | % | 21.8 | % | 21.5 | % | ||||||||||||||
The Company will continue to evaluate both the positive and negative evidence on a quarterlyperiodic basis in determining the need for a valuation allowance with respect to its deferred tax assets. Changes in positive and negative evidence, including differences between estimated and actual results, could result in changes in the valuation of our deferred tax assets that could have a material impact on our consolidated financial statements. Changes in existing tax laws could also affect actual tax results and the realization of deferred tax assets over time.
62
Continental Resources, Inc. and Subsidiaries
Notes to Consolidated Financial Statements
The components of the Company’s deferred tax assets and deferred tax liabilities as of December 31, 20212023 and 20202022 are reflected in the table below.
| December 31, |
| ||||||
In thousands |
| 2023 |
|
| 2022 |
| ||
Deferred tax assets |
|
|
|
|
|
| ||
United States net operating loss carryforwards |
| $ | 56,377 |
|
| $ | 63,128 |
|
Incentive/equity compensation |
|
| 40,929 |
|
|
| 34,987 |
|
Net deferred hedge losses |
|
| — |
|
|
| 42,898 |
|
Other |
|
| 28,080 |
|
|
| 31,324 |
|
Total deferred tax assets |
|
| 125,386 |
|
|
| 172,337 |
|
Valuation allowance |
|
| — |
|
|
| — |
|
Total deferred tax assets, net of valuation allowance |
|
| 125,386 |
|
|
| 172,337 |
|
Deferred tax liabilities |
|
|
|
|
|
| ||
Property and equipment |
|
| (2,870,259 | ) |
|
| (2,708,641 | ) |
Net deferred hedge gains |
|
| (120,662 | ) |
|
| — |
|
Other |
|
| (1,748 | ) |
|
| (2,008 | ) |
Total deferred tax liabilities |
|
| (2,992,669 | ) |
|
| (2,710,649 | ) |
Deferred income tax liabilities, net |
| $ | (2,867,283 | ) |
| $ | (2,538,312 | ) |
| December 31, | ||||||||||||||
| In thousands | 2021 | 2020 | ||||||||||||
| Deferred tax assets | ||||||||||||||
| United States net operating loss carryforwards | $ | 365,602 | $ | 579,781 | ||||||||||
| Equity compensation | 12,751 | 12,900 | ||||||||||||
| Other | 29,421 | 10,691 | ||||||||||||
| Total deferred tax assets | 407,774 | 603,372 | ||||||||||||
| Valuation allowance | — | (14,474) | ||||||||||||
| Total deferred tax assets, net of valuation allowance | 407,774 | 588,898 | ||||||||||||
| Deferred tax liabilities | ||||||||||||||
| Property and equipment | (2,536,938) | (2,204,378) | ||||||||||||
| Other | (10,720) | (4,674) | ||||||||||||
| Total deferred tax liabilities | (2,547,658) | (2,209,052) | ||||||||||||
| Deferred income tax liabilities, net | $ | (2,139,884) | $ | (1,620,154) | ||||||||||
As of December 31, 2021,2023, the Company had federal and state net operating loss (“NOL”) carryforwards of $1.17 billion and $3.63 billion, respectively. Approximately $283 million of the Company's federal net operating loss carryforwards were generated in tax years prior to 2018 and expire in 2037, with the remaining $887 million having an indefinite life. The Company’s net operating loss carryforward in Oklahoma totaled $3.07totaling $1.8 billion, at December 31, 2021, of which $1.96 billion$673 million expires between 20302035 and 2037, and the remaining $1.11$1.1 billion has an indefinite life. The Company’s net operating loss carryforward in North Dakota totaled $457 million at December 31, 2021 and has an indefinite life. Any available statutory depletion carryforwards will be recognized when realized. The Company files income tax returns in U.S. federal and state jurisdictions. With few exceptions, the Company is no longer subject to U.S. federal or state income tax examinations by tax authorities for years prior to 2018.2020.
Note 12. Leases
The Company’s lease liabilities recognized on the balance sheet as a lessee totaled $15.5$37.6 million and $8.4$24.1 million as of December 31, 20212023 and 2020,2022, respectively, at discounted present value, which is comprised of the asset classes reflected in the table below. All leases recognized on the Company'sCompany’s balance sheet are classified as operating leases. The amounts disclosed
The Company accounts for lease and non-lease components in its contracts as a single lease component for all asset classes. Additionally, the Company does not apply the recognition requirements of ASC Topic 842 to leases with durations of twelve months or less and uses hindsight in determining the lease term for all leases. The Company'sCompany’s leasing activities as a lessor are negligible.
| December 31, |
| ||||||
In thousands |
| 2023 |
|
| 2022 |
| ||
Surface use agreements |
| $ | 17,263 |
|
| $ | 18,136 |
|
Field equipment |
|
| 19,713 |
|
|
| 5,224 |
|
Other |
|
| 618 |
|
|
| 781 |
|
Total |
| $ | 37,594 |
|
| $ | 24,141 |
|
63
Continental Resources, Inc. and Subsidiaries
Notes to Consolidated Financial Statements
| December 31, | ||||||||||||||
| In thousands | 2021 | 2020 | ||||||||||||
| Drilling rig commitments | $ | — | $ | 2,025 | ||||||||||
| Surface use agreements | 12,354 | 4,928 | ||||||||||||
| Field equipment | 2,095 | 928 | ||||||||||||
| Other | 1,025 | 546 | ||||||||||||
| Total | $ | 15,474 | $ | 8,427 | ||||||||||
Minimum future commitments by year for the Company'sCompany’s operating leases as of December 31, 20212023 are presented in the table below. Such commitments are reflected at undiscounted values and are reconciled to the discounted present value recognized on the balance sheet.
In thousands |
| Amount |
| |
2024 |
| $ | 19,603 |
|
2025 |
|
| 4,571 |
|
2026 |
|
| 1,848 |
|
2027 |
|
| 1,827 |
|
2028 |
|
| 1,765 |
|
Thereafter |
|
| 16,586 |
|
Total operating lease liabilities, at undiscounted value |
| $ | 46,200 |
|
Less: Imputed interest |
|
| (8,606 | ) |
Total operating lease liabilities, at discounted present value |
| $ | 37,594 |
|
Less: Current portion of operating lease liabilities |
|
| (18,112 | ) |
Operating lease liabilities, noncurrent |
| $ | 19,482 |
|
| In thousands | Amount | |||||||
| 2022 | $ | 2,369 | ||||||
| 2023 | 2,263 | |||||||
| 2024 | 1,831 | |||||||
| 2025 | 1,295 | |||||||
| 2026 | 1,258 | |||||||
| Thereafter | 13,084 | |||||||
| Total operating lease liabilities, at undiscounted value | $ | 22,100 | ||||||
| Less: Imputed interest | (6,626) | |||||||
| Total operating lease liabilities, at discounted present value | $ | 15,474 | ||||||
| Less: Current portion of operating lease liabilities | (1,674) | |||||||
| Operating lease liabilities, net of current portion | $ | 13,800 | ||||||
Additional information for the Company'sCompany’s operating leases is presented below. Lease costs primarily represent costs incurred for drilling rigs, most of which are short term contracts that are not recognized as right-of-use assets and lease liabilities on the balance sheet. Variable lease costs primarily represent differences between minimum payment obligations and actual operating day-rate charges incurred by the Company for its long term drilling rig contracts. Short-term lease costs primarily represent operating day-rate charges for drilling rig contracts with durations of one year or less and month-to-month field equipment rentals. A portion of such lease costs are borne by other interest owners.
| Year ended December 31, |
| ||||||||||
In thousands, except weighted average data |
| 2023 |
|
| 2022 |
|
| 2021 |
| |||
Lease costs: |
|
|
|
|
|
|
|
|
| |||
Operating lease costs |
| $ | 13,121 |
|
| $ | 3,484 |
|
| $ | 6,653 |
|
Variable lease costs |
|
| 896 |
|
|
| 650 |
|
|
| 3,271 |
|
Short-term lease costs |
|
| 168,680 |
|
|
| 124,535 |
|
|
| 77,551 |
|
Total lease costs |
| $ | 182,697 |
|
| $ | 128,669 |
|
| $ | 87,475 |
|
|
|
|
|
|
|
|
|
|
| |||
Other information: |
|
|
|
|
|
|
|
|
| |||
Right-of-use assets obtained in exchange for new operating lease liabilities |
| $ | 24,949 |
|
| $ | 19,944 |
|
| $ | 10,481 |
|
Operating cash flows from operating leases included in lease liabilities |
|
| 13,166 |
|
|
| 4,370 |
|
|
| 1,731 |
|
Weighted average remaining lease term as of December 31 (in years) |
|
| 6.9 |
|
|
| 12.0 |
|
|
| 14.4 |
|
Weighted average discount rate as of December 31 |
|
| 4.7 | % |
|
| 4.8 | % |
|
| 5.0 | % |
| Year ended December 31, | ||||||||||||||||||||
| In thousands, except weighted average data | 2021 | 2020 | 2019 | |||||||||||||||||
| Lease costs: | ||||||||||||||||||||
| Operating lease costs | $ | 6,653 | $ | 6,444 | $ | 11,130 | ||||||||||||||
| Variable lease costs | 3,271 | 4,956 | 11,930 | |||||||||||||||||
| Short-term lease costs | 77,551 | 107,984 | 176,586 | |||||||||||||||||
| Total lease costs | $ | 87,475 | $ | 119,384 | $ | 199,646 | ||||||||||||||
| Other information: | ||||||||||||||||||||
| Right-of-use assets obtained in exchange for new operating lease liabilities (1) | $ | 10,481 | $ | 7,377 | $ | 1,208 | ||||||||||||||
| Operating cash flows from operating leases included in lease liabilities | 1,731 | 890 | 804 | |||||||||||||||||
| Weighted average remaining lease term as of December 31 (in years) | 14.4 | 13.2 | 11.5 | |||||||||||||||||
| Weighted average discount rate as of December 31 | 5.0 | % | 4.8 | % | 4.9 | % | ||||||||||||||
Note 13. Commitments and Contingencies
Transportation, gathering, and processing commitments – The Company has entered into transportation, gathering, and processing commitments to guarantee capacity on crude oil and natural gas pipelines and natural gas processing facilities. The commitments, which have varying terms extending as far as 2031, require the Company to pay per-unit transportation, gathering, or processing charges regardless of the amount of capacity used. Future commitments remaining as of December 31, 20212023 under the arrangements amount to approximately $1.31 billion,$824 million, of which $275$307 million is expected to be incurred in 2022, $270 million in 2023, $251 million in 2024, $164$164 million in 2025, $139$139 million in 2026, $136 million in 2027, $70 million in 2028, and $214$8 million thereafter. A portion of these future costs will be borne by other interest owners. The Company is not committed under the above contracts to deliver fixed and determinable quantities of crude oil or natural gas in the future. These commitments do not qualify as leases under ASC Topic 842 and are not recognized on the Company’s balance sheet.
Lease commitments – The Company has various lease commitments primarily associated with surface use agreements and field equipment. See Note 12. Leases for additional information.
Litigation pertaining to the Company's routine operations
64
Pledge commitmentTable of Contents
Continental Resources, Inc. and Subsidiaries
Notes to Consolidated Financial Statements
– The Company entered into a $25.0 million ten-year irrevocable pledge agreement with Oklahoma State University in December 2021. The pledge agreement provides for ten equal payments of $2.5 million to be paid annually on or before December 31 of each year until the pledge is paid in full on December 31, 2030. In connection with the pledge, the Company recognized a $25.0 million charge to earnings which is reflected in the caption “Other income (expense)—Other” in the consolidated statements of comprehensive income (loss) for the year ended December 31, 2021.
Environmental risk –Litigation pertaining to take-private transaction Due to– Transactions such as the natureHamm Family’s take-private transaction described in Note 1. Organization and Nature of Business—2022 Take-Private Transaction often attract litigation and demands from minority shareholders.
In April 2023, three separate putative class action lawsuits were consolidated under the crude oil and natural gas business, the Company is exposed to possible environmental risks. The Company is not aware of any material environmental issues or claims.caption
In January 2023, FourWorld Deep Value Opportunities Fund I, LLC, FourWorld Event Opportunities, LP, FW Deep Value Opportunities I, LLC, FourWorld Global Opportunities Fund, Ltd., FourWorld Special Opportunities Fund, LLC, Corbin ERISA Opportunity Fund Ltd., and Quadre Investments, L.P. (collectively, “FourWorld”), all former shareholders of the Company, filed a petition in the District Court of Oklahoma County, Oklahoma, seeking appraisal of their respective shares of the Company’s common stock in connection with the take-private transaction. The Company continues to vigorously defend itself against these claims.
Note 14. Related Party Transactions
Certain officers of the Company own or control entities that own working and royalty interests in wells operated by the Company. The Company paid revenues to these affiliates, including royalties, of $0.4$0.4 million, $0.2$0.5 million, and $0.4$0.4 million and received payments from these affiliates of $0.1$0.1 million, $0.3$0.2 million, and $0.3$0.1 million during the years ended December 31, 2021, 2020,2023, 2022, and 2019,2021, respectively, relating to the operations of the respective properties. At December 31, 20212023 and 2020,2022, approximately $39,000$35,000 and $18,000,$6,000, respectively, was due from these affiliates relating to these transactions, which is included in “Receivables—Joint interest and other” on the consolidated balance sheets. At December 31, 20212023 and 2020,2022, approximately $37,000$31,000 and $18,000,$36,000, respectively, was due to these affiliates relating to these transactions, which is included in “Revenues and royalties payable” on the consolidated balance sheets.
The Company allows certain affiliates to use its corporate aircraft and crews and has used the aircraft of those same affiliates from time to time in order to facilitate efficient transportation of Company personnel. The rates charged between the parties vary by type of aircraft used. For usage during 2021, 2020,2023, 2022, and 2019,2021, the Company charged affiliates approximately $11,300, $8,100,$28,100, $16,400, and $17,600,$11,300, respectively, for use of its corporate aircraft crews, fuel, and reimbursement of expenses and received approximately $5,000, $9,500,$31,000, $13,000, and $18,900$5,000 from affiliates in 2021, 2020,2023, 2022, and 2019,2021, respectively, in connection with such items. The Company was charged approximately $117,000, $120,000,$312,000, $235,000, and $303,000,$117,000, respectively, by affiliates for use of their aircraft and reimbursement of expenses during 2021, 2020,2023, 2022, and 20192021 and paid $84,000, $158,000,$299,000, $219,000, and $426,000$84,000 to the affiliates in 2021, 2020,2023, 2022, and 2019,2021, respectively. At December 31, 2021,2023 and 2022, approximately $6,300$7,000 and $9,800, respectively, was due from an affiliate relating to these transactions, which is included in “Receivables—Joint interest and other” on the consolidated balance sheets. At December 31, 2021,2023 and 2022, approximately $33,000$63,000 and $49,000, respectively, was due to an affiliate relating to these transactions, which is included in “Accounts payable trade” on the consolidated balance sheets. No
Note 15. Incentive Compensation
Long-term Incentive Compensation
The Company has granted long-term incentive compensation awards to employees pursuant to the Continental Resources, Inc. 2022 Long-Term Incentive Plan (“2022 Plan”). Such awards generally vest after three years of employee service. The Company intends to settle all outstanding awards vesting in the future in cash and, thus, the awards are classified as liability awards pursuant to ASC Topic 718, Compensation—Stock Compensation.
65
Continental Resources, Inc. and Subsidiaries
Notes to Consolidated Financial Statements
At December 31, 2023, the Company had recorded a current liability of $130.6 million and a non-current liability of $41.7 million in the captions “Current portion of incentive compensation liability” and “Incentive compensation liability, noncurrent,” respectively, in the consolidated balance sheets associated with the awards. Such amounts were duereflect the Company’s estimate of expected future cash payments multiplied by the percentage of requisite service periods that employees have completed as of December 31, 2023. The Company’s compensation expense associated with such awards, which is included in the caption “General and administrative expenses” in the consolidated statements of income, was $91.3 million for the year ended December 31, 2023. As of December 31, 2023, there was approximately $90.4 million of unrecognized liabilities and compensation expense related to or from the affiliateunvested awards, which are expected to be recognized over a weighted average period of 1.5 years. The current liability at December 31, 2020.2023 was paid in cash to employees in February 2024 upon the scheduled vesting of awards.
The Company’s incentive compensation liability will be remeasured each reporting period leading up to the applicable award vesting dates to reflect additional service rendered by employees and to reflect changes in expected cash payments arising from underlying changes in the value of the Company based on independent third party appraisals. Changes in the liability will be recorded as increases or decreases to compensation expense. The Company has estimated the number of forfeitures expected to occur in determining the amount of liability and expense to recognize.
Stock-based Compensation
Prior to the Hamm Family’s take-private transaction described in Note 1. Organization and Summary of Significant Accounting Policies—2022 Take-Private Transaction, the Company granted restricted stock to employees and directors pursuant to the Continental Resources, Inc. 2013 Long-Term Incentive Plan as amended (“2013 Plan”). and 2022 Plan. The Company’s associated compensation expense associated with such awards, which is included in the caption “General and administrative expenses” in the consolidated statements of comprehensive income, (loss), was $63.2 million, $64.6$217.8 million and $52.0$63.2 million for the years ended December 31, 2022, and 2021, 2020, and 2019, respectively.
In March 2019,As of the Company amended and restated itsNovember 22, 2022 effective time of the Hamm Family’s take-private transaction, each unvested restricted stock award previously issued under the Company’s 2013 Plan and specified 12,983,543 shares2022 Plan that was outstanding immediately prior to the effective time was replaced with a restricted stock unit award (the “Rollover Shares”) issued by the Company that provides the holder of commonsuch previous award with the right to receive, on the date that such restricted stock may be issuedaward otherwise would have been settled, and at the Company’s sole discretion, either a share of the Company, a cash award designed to provide substantially equivalent value, or any combination of the two. Upon this event, the Company remeasured the cumulative compensation expense recognized on the modified awards pursuant to ASC Topic 718, Compensation—Stock Compensation, which resulted in the amended plan. Subjectrecognition of additional non-cash compensation expense in 2022 within “General and administrative expenses” totaling approximately $136 million, reflecting the increase in the value of the awards from the original grant date to limited exceptions, the 2013 Plan allows previously issued shares to be reissued if such shares are subsequently forfeited or withheld to satisfy tax withholdings. subsequent modification date.
As of December 31, 2021,2022, the Company had5.3 million Rollover Shares which are classified as liability awards under ASC 718. As of December 31, 2022, the Company had recorded a current liability of $8,492,645 shares125.7 million and a non-current liability of common stock available for long-term incentive awards$100.1 million in the consolidated balance sheets associated with the Rollover Shares. The current liability at December 31, 2022 was paid in cash to employees and directors under the 2013 Plan.
| Number of |
|
| Weighted |
| |||
Non-vested restricted shares at December 31, 2020 |
|
| 4,890,638 |
|
| $ | 36.26 |
|
Granted |
|
| 3,050,491 |
|
|
| 24.73 |
|
Vested |
|
| (1,750,483 | ) |
|
| 44.36 |
|
Forfeited |
|
| (296,138 | ) |
|
| 26.61 |
|
Non-vested restricted shares at December 31, 2021 |
|
| 5,894,508 |
|
| $ | 28.38 |
|
Granted |
|
| 1,575,847 |
|
|
| 56.52 |
|
Vested |
|
| (1,736,678 | ) |
|
| 36.04 |
|
Forfeited |
|
| (384,536 | ) |
|
| 27.82 |
|
Canceled shares due to take-private transaction |
|
| (5,349,141 | ) |
|
| 34.22 |
|
Non-vested restricted shares at December 31, 2022 |
|
| — |
|
| $ | — |
|
66
| Number of non-vested shares | Weighted average grant-date fair value | |||||||||||||
| Non-vested restricted shares at December 31, 2018 | 4,022,409 | $ | 38.44 | |||||||||||
| Granted | 1,526,825 | 43.21 | ||||||||||||
| Vested | (1,737,304) | 24.19 | ||||||||||||
| Forfeited | (350,022) | 47.13 | ||||||||||||
| Non-vested restricted shares at December 31, 2019 | 3,461,908 | $ | 46.82 | |||||||||||
| Granted | 2,738,625 | 26.93 | ||||||||||||
| Vested | (1,146,618) | 45.78 | ||||||||||||
| Forfeited | (163,277) | 36.69 | ||||||||||||
| Non-vested restricted shares at December 31, 2020 | 4,890,638 | $ | 36.26 | |||||||||||
| Granted | 3,050,491 | 24.73 | ||||||||||||
| Vested | (1,750,483) | 44.36 | ||||||||||||
| Forfeited | (296,138) | 26.61 | ||||||||||||
| Non-vested restricted shares at December 31, 2021 | 5,894,508 | $ | 28.38 | |||||||||||
Continental Resources, Inc. and Subsidiaries
Notes to Consolidated Financial Statements
The grant date fair value of restricted stock representsgranted prior to the Hamm Family’s take-private transaction represented the closing market price of the Company’s common stock on the date of grant. Compensation expense for a restricted stock grant iswas determined at the grant date fair value and iswas recognized over the vesting period as services arewere rendered by employees and directors. The Company estimatesestimated the number of forfeitures expected to occur in determining the amount of stock-based compensation expense to recognize. There arewere no post-vesting restrictions related to the Company’s restricted stock. The fair value at the vesting date of restricted stock that vested during 2022 and 2021 2020, and 2019 was approximately $46.7 million, $27.5$98.4 million and $79.7$46.7 million, respectively. As of December 31, 2021, there was approximately $70 million of unrecognized compensation expense related to non-vested restricted stock. This expense is expected to be recognized over a weighted average period of 1.4 years.
Note 16. Shareholders'Shareholders’ Equity Attributable to Continental Resources
See the Consolidated Statements of Equity for the year ended December 31, 2022 for the impact on Shareholders’ Equity resulting from the Hamm Family’s take-private transaction consummated on November 22, 2022.
Share Repurchases
In May 2019 the Company's Board of Directors approved the initiation of a share repurchase program to acquire up to $1 billion of the Company's common stock beginning in June 2019. See Note 20. Subsequent Events for discussion of an increase in the authorized amount ofShare repurchases made under the Company's share repurchase program made subsequentprior to December 31, 2021. As of December 31, 2021, the Company has repurchased and retired a cumulative total of approximately 17.0 million shares under the program at an aggregate cost of $441.1 million asHamm Family’s take-private transaction are reflected in the table below by year.Number of
sharesAggregate cost (in thousands) 2019 Share Repurchases 5,646,553 $ 190,239 2020 Share Repurchases 8,122,104 126,906 2021 Share Repurchases 3,198,571 123,924 Total 16,967,228 $ 441,069
| Number of |
|
| Aggregate cost (in thousands) |
| |||
2021 Share Repurchases |
|
| 3,198,571 |
|
| $ | 123,924 |
|
2022 Share Repurchases |
|
| 1,842,422 |
|
|
| 99,855 |
|
Total |
|
| 5,040,993 |
|
| $ | 223,779 |
|
As of December 31, 2023 and 2022, the Hamm Family holds approximately 299.6 million shares of capital stock, and such shares are the only remaining capital stock of the Company following the take-private transaction.
Dividend Payments
During the years ended December 31, 2022 and 2021, 2020,the Company paid dividends of $283.8 million and 2019.$Amount (in thousands) Dividend per share Year Ended December 31, 2019 Fourth quarter $ 18,747 $ 0.05 Total $ 18,747 Year Ended December 31, 2020 First quarter $ 18,580 $ 0.05 Total $ 18,580 Year Ended December 31, 2021 Second quarter $ 40,429 $ 0.11 Third quarter 55,132 $ 0.15 Fourth quarter 72,975 $ 0.20 Total $ 168,536
Note 2. Property Acquisitions and Dispositions for further information.
Note 17. Noncontrolling Interests
Strategic mineral relationship
In October 2018, Continental entered into a strategic relationship with Franco-Nevada Corporation to acquire oil and gas mineral interests within an area of mutual interest through a minerals subsidiary named The Mineral Resources Company II, LLC (“TMRC II”). At closing in October 2018, Continental contributed most of its previously acquired mineral interests to TMRC II in exchange for a 50.1% ownership interest in the entity and Franco-Nevada paid $214.8 million to Continental for a 49.9% ownership interest in TMRC II and for funding of its share of certain mineral acquisition costs. Under the arrangement, Continental is to fundfunds 20% of future mineral acquisitions and will be entitled to receive between 25% and 50% of total revenues generated by TMRC II based upon performance relative to certain predetermined production targets.
Continental holds a controlling financial interest in TMRC II and manages its operations. Accordingly, Continental consolidates the financial results of the entity and presents the portion of TMRC II’s results attributable to Franco-Nevada as a noncontrolling interest in its consolidated financial statements. Periodically, Franco-Nevada makes capital contributions to, and receives revenue distributions from, TMRC II and the portion of Continental’s consolidated net assets attributable to Franco-Nevada totaled $369.8$345.1 million and $355.1$361.4 million at December 31, 20212023 and 2020,2022, respectively.
Joint ownership arrangement
67
Continental Resources, Inc. and Subsidiaries
Notes to Consolidated Financial Statements
Note 18. Crude Oil and Natural Gas Property Information
In 2022 the Company began investing in an affiliate of Summit Carbon Solutions (“Summit”) to develop carbon capture and sequestration infrastructure. Summit was founded in 2020 with the goal of decarbonizing the biofuel and agriculture industries and seeks to lower greenhouse gas emissions by connecting industrial facilities via strategic infrastructure to capture, transport, and store carbon dioxide in the Midwestern United States. The Company committed to invest a total of $250 million with Summit to fund a portion of its subsidiaries. In 2014,development and construction activities.
During the years ended December 31, 2023 and 2022, the Company initiated operations in Canadacontributed $33 million and $210 million, respectively, toward its $250 million commitment to Summit, which were soldis included in the fourth quarter of 2019. The Company's Canadian operations have not had a material impact on historical capital expenditures, production, and revenues. Accordingly, the results of operations, costs incurred, and capitalized costs associated with the Canadian operations have not been shown separately fromcaption “Investment in unconsolidated affiliates” in the consolidated figuresbalance sheets. Upon completion of Summit’s equity raises, the Company expects to hold an approximate 22% non-controlling ownership interest in the tables below. Additionally, results attributable to noncontrolling interests areequity of Summit Carbon Holdings, the parent company of Summit Carbon Solutions. The Company is not material relative to the Company's consolidated resultsprimary beneficiary of Summit and are not separately presented below.
| Year ended December 31, | ||||||||||||||||||||
| In thousands | 2021 | 2020 | 2019 | |||||||||||||||||
| Crude oil and natural gas sales | $ | 5,793,741 | $ | 2,555,434 | $ | 4,514,389 | ||||||||||||||
| Production expenses | (406,906) | (359,267) | (444,649) | |||||||||||||||||
| Production taxes | (404,362) | (192,718) | (357,988) | |||||||||||||||||
| Transportation expenses | (224,989) | (196,692) | (225,649) | |||||||||||||||||
| Exploration expenses | (21,047) | (17,732) | (14,667) | |||||||||||||||||
| Depreciation, depletion, amortization and accretion | (1,872,075) | (1,859,893) | (1,997,854) | |||||||||||||||||
| Property impairments | (38,370) | (277,941) | (86,202) | |||||||||||||||||
| Income tax (provision) benefit (1) | (690,902) | 83,427 | (323,025) | |||||||||||||||||
| Results from crude oil and natural gas producing activities | $ | 2,135,090 | $ | (265,382) | $ | 1,064,355 | ||||||||||||||
(1) Income taxes reflect the application of a combined federal and state tax rate of 24.5% on pre-tax income/loss generated by our operations in the United States. Additionally, the 2019 period includes the $16.9 million income tax benefit recognized upon the Company's sale of its Canadian operations during that year.Note 19. Capitalized Exploratory Well Costs
Costs incurred, both capitalized and expensed, in connection with the Company’s consolidated crude oil and natural gas acquisition, exploration and development activities for the years ended December 31, 2021, 2020 and 2019 are presented below. See Note 2. Property Acquisitions and Dispositions for discussion of notable property acquisitions executed in 2021 that gave rise to the significant increase in costs incurred and aggregate capitalized costs in the current year.
| Year ended December 31, | ||||||||||||||||||||
| In thousands | 2021 | 2020 | 2019 | |||||||||||||||||
| Property acquisition costs: | ||||||||||||||||||||
| Proved | $ | 2,580,271 | $ | 60,494 | $ | 51,558 | ||||||||||||||
| Unproved | 1,197,507 | 201,919 | 312,680 | |||||||||||||||||
| Total property acquisition costs | 3,777,778 | 262,413 | 364,238 | |||||||||||||||||
| Exploration Costs | 171,549 | 48,282 | 50,143 | |||||||||||||||||
| Development Costs | 1,174,828 | 1,053,532 | 2,388,582 | |||||||||||||||||
| Total | $ | 5,124,155 | $ | 1,364,227 | $ | 2,802,963 | ||||||||||||||
| December 31, | ||||||||||||||
| In thousands | 2021 | 2020 | ||||||||||||
| Proved crude oil and natural gas properties | $ | 31,613,656 | $ | 27,726,954 | ||||||||||
| Unproved crude oil and natural gas properties | 1,358,673 | 368,256 | ||||||||||||
| Total | 32,972,329 | 28,095,210 | ||||||||||||
| Less accumulated depreciation, depletion and amortization | (16,310,054) | (14,622,376) | ||||||||||||
| Net capitalized costs | $ | 16,662,275 | $ | 13,472,834 | ||||||||||
On at least a quarterlyperiodic basis, operating and financial management review the status of all deferred exploratory drilling costs in light of ongoing exploration activities—in particular, whether the Company is making sufficient progress in its ongoing exploration and appraisal efforts. If management determines that future appraisal drilling or development activities are not likely to occur, any associated exploratory well costs are expensed in that period of determination.
The following table presents the amount of capitalized exploratory well costs pending evaluation at December 31 for each of the last three years and changes in those amounts during the years then ended:
| Year ended December 31, |
| ||||||||||
In thousands |
| 2023 |
|
| 2022 |
|
| 2021 |
| |||
Balance at January 1 |
| $ | 84,822 |
|
| $ | 37,673 |
|
| $ | 32,737 |
|
Additions to capitalized exploratory well costs pending determination of proved reserves |
|
| 345,434 |
|
|
| 286,059 |
|
|
| 122,068 |
|
Reclassification to proved crude oil and natural gas properties based on the determination of proved reserves |
|
| (270,490 | ) |
|
| (229,348 | ) |
|
| (117,131 | ) |
Capitalized exploratory well costs charged to expense |
|
| (32 | ) |
|
| (9,562 | ) |
|
| (1 | ) |
Balance at December 31 |
| $ | 159,734 |
|
| $ | 84,822 |
|
| $ | 37,673 |
|
Number of gross wells |
|
| 34 |
|
|
| 36 |
|
|
| 17 |
|
| Year ended December 31, | ||||||||||||||||||||
| In thousands | 2021 | 2020 | 2019 | |||||||||||||||||
| Balance at January 1 | $ | 32,737 | $ | 6,257 | $ | 3,959 | ||||||||||||||
| Additions to capitalized exploratory well costs pending determination of proved reserves | 122,068 | 32,880 | 28,280 | |||||||||||||||||
| Reclassification to proved crude oil and natural gas properties based on the determination of proved reserves | (117,131) | (72) | (23,200) | |||||||||||||||||
| Capitalized exploratory well costs charged to expense | (1) | (6,328) | (2,782) | |||||||||||||||||
| Balance at December 31 | $ | 37,673 | $ | 32,737 | $ | 6,257 | ||||||||||||||
| Number of gross wells | 17 | 16 | 11 | |||||||||||||||||
As of December 31, 2021,2023, the Company had no significant exploratory well costs that were suspended one year beyond the completion of drilling.
Note 19.20. Supplemental Crude Oil and Natural Gas Information (Unaudited)
The table below showsprovides estimates of proved reserves prepared by the Company’s internal technical staff and independent external reserve engineers in accordance with SEC definitions. Ryder Scott Company, L.P. prepared reserve estimates for properties comprising approximately 98%99%, 95%98%, and 91%98% of the Company'sCompany’s total proved reserves as of December 31, 2021, 2020,2023, 2022, and 2019,2021, respectively. Remaining reserve estimates were prepared by the Company’s internal technical staff. All proved reserves stated herein are located in the United States. No proved reserves have been included for the Company’s Canadian operations for the periods presented. Proved reserves attributable to noncontrolling interests are not material relative to the Company's consolidated reserves and are not separately presented in the tables below.
Proved reserves are estimated quantities of crude oil and natural gas which geological and engineering data demonstrate with reasonable certainty to be economically producible in future periods from known reservoirs under existing economic conditions,
68
Continental Resources, Inc. and Subsidiaries
Notes to Consolidated Financial Statements
operating methods, and government regulations prior to the time at which contracts providing the right to operate
Reserves at December 31, 2021, 2020,2023, 2022, and 20192021 were computed using the 12-month unweighted average of the first-day-of-the-month commodity prices as required by SEC rules.
Proved crude oil and natural gas reserves
| Crude Oil (MBbls) | Natural Gas (MMcf) | Total (MBoe) | ||||||||||||||||||
| Proved reserves as of December 31, 2018 | 757,096 | 4,591,614 | 1,522,365 | |||||||||||||||||
| Revisions of previous estimates | (88,307) | (363,239) | (148,848) | |||||||||||||||||
| Extensions, discoveries and other additions | 162,710 | 1,213,947 | 365,034 | |||||||||||||||||
| Production | (72,267) | (311,865) | (124,244) | |||||||||||||||||
| Sales of minerals in place | (803) | (6,224) | (1,840) | |||||||||||||||||
| Purchases of minerals in place | 1,758 | 30,238 | 6,798 | |||||||||||||||||
| Proved reserves as of December 31, 2019 | 760,187 | 5,154,471 | 1,619,265 | |||||||||||||||||
| Revisions of previous estimates | (249,845) | (1,530,174) | (504,874) | |||||||||||||||||
| Extensions, discoveries and other additions | 42,106 | 295,686 | 91,387 | |||||||||||||||||
| Production | (58,745) | (306,528) | (109,833) | |||||||||||||||||
| Sales of minerals in place | — | — | — | |||||||||||||||||
| Purchases of minerals in place | 3,272 | 27,269 | 7,817 | |||||||||||||||||
| Proved reserves as of December 31, 2020 | 496,975 | 3,640,724 | 1,103,762 | |||||||||||||||||
| Revisions of previous estimates | 14,574 | 233,966 | 53,569 | |||||||||||||||||
| Extensions, discoveries and other additions | 165,268 | 1,235,022 | 371,105 | |||||||||||||||||
| Production | (58,636) | (370,110) | (120,321) | |||||||||||||||||
| Sales of minerals in place | (70) | (469) | (148) | |||||||||||||||||
| Purchases of minerals in place | 175,419 | 371,546 | 237,343 | |||||||||||||||||
| Proved reserves as of December 31, 2021 | 793,530 | 5,110,679 | 1,645,310 | |||||||||||||||||
Revisions of previous estimates. Revisions for 2021 are comprised of (i) upward price revisions of 92 MMBo and 458 Bcf (totaling 168 MMBoe) due to the significant increase in average crude oil and natural gas prices in 2021 compared to 2020 resulting from the lifting of COVID-19 restrictions, the resumption of normal economic activity, and the resulting improvement in supply and demand fundamentals, (ii) the removal of 31 MMBo and 155 Bcf (totaling 57 MMBoe) of PUD reserves no longer scheduled to be drilled within five years of initial booking due continual refinement of our drilling and development programs and reallocation of capital to areas providing the best opportunities to improve efficiencies, recoveries, and rates of return, (iii) downward revisions of 12 MMBo and 263 Bcf (totaling 56 MMBoe) from the removal of PUD reserves due to changes in anticipated well densities, economics, performance, and other factors, and (iv) downward revisions for oil reserves of 35 MMBo and upward revisions for natural gas reserves of 195 Bcf (netting to 2 MMBoe of downward revisions) due to changes in ownership interests, operating costs, anticipated production, and other factors.
| December 31, | ||||||||||||||||||||
| 2021 | 2020 | 2019 | ||||||||||||||||||
| Proved Developed Reserves | ||||||||||||||||||||
| Crude oil (MBbl) | 424,153 | 281,906 | 336,405 | |||||||||||||||||
| Natural Gas (MMcf) | 2,901,147 | 2,073,011 | 2,226,117 | |||||||||||||||||
| Total (MBoe) | 907,678 | 627,407 | 707,424 | |||||||||||||||||
| Proved Undeveloped Reserves | ||||||||||||||||||||
| Crude oil (MBbl) | 369,377 | 215,069 | 423,782 | |||||||||||||||||
| Natural Gas (MMcf) | 2,209,532 | 1,567,713 | 2,928,354 | |||||||||||||||||
| Total (MBoe) | 737,632 | 476,355 | 911,841 | |||||||||||||||||
| Total Proved Reserves | ||||||||||||||||||||
| Crude oil (MBbl) | 793,530 | 496,975 | 760,187 | |||||||||||||||||
| Natural Gas (MMcf) | 5,110,679 | 3,640,724 | 5,154,471 | |||||||||||||||||
| Total (MBoe) | 1,645,310 | 1,103,762 | 1,619,265 | |||||||||||||||||
Proved developed reserves are reserves expected to be recovered through existing wells with existing equipment and operating methods. Proved undeveloped reserves are reserves expected to be recovered from new wells on undrilled acreage or from existing wells that require relatively major capital expenditures to recover, including most wells where drilling has occurred but the wells have not been completed. Natural gas isreserves are converted to barrels of crude oil equivalent using a conversion factor of six thousand cubic feet per barrel of crude oil based on the average equivalent energy content of natural gas compared to crude oil.
| December 31, |
| ||||||||||
| 2023 |
|
| 2022 |
|
| 2021 |
| ||||
Proved Developed Reserves |
|
|
|
|
|
|
|
|
| |||
Crude oil (MBbl) |
|
| 401,851 |
|
|
| 454,299 |
|
|
| 424,153 |
|
Natural Gas (MMcf) |
|
| 3,221,566 |
|
|
| 3,486,774 |
|
|
| 2,901,147 |
|
Total (MBoe) |
|
| 938,779 |
|
|
| 1,035,428 |
|
|
| 907,678 |
|
Proved Undeveloped Reserves |
|
|
|
|
|
|
|
|
| |||
Crude oil (MBbl) |
|
| 512,183 |
|
|
| 435,240 |
|
|
| 369,377 |
|
Natural Gas (MMcf) |
|
| 2,376,765 |
|
|
| 2,358,578 |
|
|
| 2,209,532 |
|
Total (MBoe) |
|
| 908,310 |
|
|
| 828,336 |
|
|
| 737,632 |
|
Total Proved Reserves |
|
|
|
|
|
|
|
|
| |||
Crude oil (MBbl) |
|
| 914,034 |
|
|
| 889,539 |
|
|
| 793,530 |
|
Natural Gas (MMcf) |
|
| 5,598,331 |
|
|
| 5,845,352 |
|
|
| 5,110,679 |
|
Total (MBoe) |
|
| 1,847,089 |
|
|
| 1,863,764 |
|
|
| 1,645,310 |
|
69
| December 31, | ||||||||||||||||||||
| In thousands | 2021 | 2020 | 2019 | |||||||||||||||||
| Future cash inflows | $ | 67,034,046 | $ | 21,334,235 | $ | 49,893,470 | ||||||||||||||
| Future production costs | (18,837,000) | (7,750,834) | (15,309,672) | |||||||||||||||||
| Future development and abandonment costs | (7,751,678) | (3,950,752) | (10,033,887) | |||||||||||||||||
| Future income taxes (1) | (7,862,849) | (724,569) | (3,351,657) | |||||||||||||||||
| Future net cash flows | 32,582,519 | 8,908,080 | 21,198,254 | |||||||||||||||||
| 10% annual discount for estimated timing of cash flows | (15,946,126) | (4,254,515) | (10,736,613) | |||||||||||||||||
| Standardized measure of discounted future net cash flows | $ | 16,636,393 | $ | 4,653,565 | $ | 10,461,641 | ||||||||||||||
| December 31, | ||||||||||||||||||||
| In thousands | 2021 | 2020 | 2019 | |||||||||||||||||
| Standardized measure of discounted future net cash flows at January 1 | $ | 4,653,565 | $ | 10,461,641 | $ | 15,684,817 | ||||||||||||||
| Extensions, discoveries and improved recoveries, less related costs | 2,985,056 | 187,981 | 1,649,322 | |||||||||||||||||
| Revisions of previous quantity estimates | 816,674 | (2,952,489) | (1,564,503) | |||||||||||||||||
| Changes in estimated future development and abandonment costs | 706,168 | 4,760,286 | 1,401,513 | |||||||||||||||||
| Purchases (sales) of minerals in place, net | 3,408,365 | 53,742 | 49,330 | |||||||||||||||||
| Net change in prices and production costs | 9,396,945 | (6,912,031) | (6,591,347) | |||||||||||||||||
| Accretion of discount | 489,273 | 1,183,993 | 1,865,034 | |||||||||||||||||
| Sales of crude oil and natural gas produced, net of production costs | (4,757,483) | (1,806,758) | (3,486,103) | |||||||||||||||||
| Development costs incurred during the period | 683,212 | 863,101 | 1,557,121 | |||||||||||||||||
| Change in timing of estimated future production and other | 1,871,903 | (2,325,024) | (1,690,779) | |||||||||||||||||
| Change in income taxes | (3,617,285) | 1,139,123 | 1,587,236 | |||||||||||||||||
| Net change | 11,982,828 | (5,808,076) | (5,223,176) | |||||||||||||||||
| Standardized measure of discounted future net cash flows at December 31 | $ | 16,636,393 | $ | 4,653,565 | $ | 10,461,641 | ||||||||||||||
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
There have been no changes in accountants or any disagreements with accountants.
Item 9A. Controls and Procedures
Evaluation of Disclosure Controls and Procedures
As of the end of the period covered by this report, an evaluation of the effectiveness of the design and operation of the Company’s disclosure controls and procedures (as defined in Rule 13a-15(e) under the Securities Exchange Act of 1934, as amended (the “Exchange Act”)) was performed under the supervision and with the participation of the Company’s management, including its Chief Executive Officer and Chief Financial Officer. Based on that evaluation, our Chief Executive Officer and Chief Financial Officer concluded the Company’s disclosure controls and procedures were effective as of December 31, 20212023 to ensure information required to be disclosed in the reports it files and submits under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and information required to be disclosed under the Exchange Act is accumulated and communicated to the Company’s management, including its Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure.
As of the end of the period covered by this report, we carried out an evaluation, under the supervision and with the participation of our Chief Executive Officer and Chief Financial Officer, of our internal control over financial reporting to determine whether any changes occurred during the fourth quarter of 20212023 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting. Based on that evaluation, there were no changes in our internal control over financial reporting or in other factors during the fourth quarter of 20212023 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
70
Management’s Report on Internal Control Over Financial Reporting
Our Company’s management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rule 13a-15(f). Internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of our consolidated financial statements for external purposes in accordance with generally accepted accounting principles. Under the supervision and with the participation of our Company’s management, including the Chief Executive Officer and Chief Financial Officer, we conducted an evaluation of the effectiveness of our internal control over financial reporting based on the framework in Internal Control—Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission.
Our internal control over financial reporting includes those policies and procedures that: (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of our assets; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of our consolidated financial statements in accordance with generally accepted accounting principles, and that our receipts and expenditures are being made only in accordance with authorizations of our management and directors; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of our assets that could have a material effect on our consolidated 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.
Based on our evaluation under the framework in Internal Control—Integrated Framework (2013), the management of our Company concluded that our internal control over financial reporting was effective as of December 31, 2021.2023.
President and Chief Executive Officer
/s/ John D. Hart
Chief Financial Officer and Executive Vice President of Strategic Planning
February 14, 2022
71
Item 9B. Other Information
Item 9C. Disclosure Regarding Foreign Jurisdictions that Prevent Inspections
Not applicable.
72
Item 10. Directors, Executive Officers and Corporate Governance
Our current executive officers are named below:
Name | Age | Position |
Harold G. Hamm | 78 | Executive Chairman |
Robert D. (“Doug”) Lawler | 57 | President and Chief Executive Officer and Director |
John D. Hart | 56 | Chief Financial Officer and Executive Vice President of Strategic Planning |
Shelly Lambertz | 57 | Executive Vice President, Chief Culture and Administrative Officer and Director |
Jeffrey B. Hume | 72 | Vice-Chairman, Strategic Growth Initiatives |
James R. Webb | 56 | Senior Vice President, General Counsel, and Secretary |
Robert Hagens | 65 | Senior Vice President, Commercial Development |
Harold G. Hamm serves as Executive Chairman, a position he has held since November 2022. Prior to Item 10 will be set forththis, he served as non-employee Chairman from May 19, 2021, to November 22, 2022. Prior to assuming the role of Chairman, he served as Executive Chairman of the Board from January 1, 2020, to May 19, 2021, and as employee Chairman prior to that. He has served as a director since our inception in 1967 and served as our Chief Executive Officer from 1967 to December 31, 2019. In addition, Mr. Hamm served as our President from October 31, 2008 to November 3, 2009. He served as Chairman of the Proxy Statementboard of directors of the publicly traded general partners of Hiland Partners, LP (“Hiland”) and Hiland Holdings GP, LP (“Hiland Holdings”), former affiliates of ours through February 13, 2015. From September 2005 through February 2012, Mr. Hamm served as a director of Complete Production Services, Inc., an oil and gas service company publicly traded on the New York Stock Exchange (“NYSE”). Mr. Hamm is Chairman of Domestic Energy Producers Alliance and served as Chairman of the Oklahoma Independent Petroleum Association from June 2005 to June 2007 (currently known as the Petroleum Alliance of Oklahoma). He was President of the National Stripper Well Association, founder and Chairman of Save Domestic Oil, Inc., served on the board of directors of the Oklahoma Energy Explorers, Oklahoma Independent Petroleum Association and is co-chairman of the Council for a Secure America.
Robert D. (“Doug”) Lawler is our President and Chief Executive Officer, a position he has held since January 1, 2023. Prior to then, he served as our Chief Operating Officer and Executive Vice President from February 1, 2022 through August 17, 2022. From August 17, 2022 through December 31, 2022, Mr. Lawler served as our President and Chief Operating Officer. On January 22, 2023, Mr. Lawler was appointed to serve as a director. Prior to joining the Company, he served as the President and Chief Executive Officer of Chesapeake Energy Corporation (“Chesapeake”) from June 2013 to April 2021. Chesapeake voluntarily filed for Chapter 11 bankruptcy protection in June of 2020 and emerged from bankruptcy in February of 2021. Mr. Lawler has served as a director of Pilot Travel Centers LLC (dba Pilot/Flying J) since 2016. Mr. Lawler holds a degree in petroleum engineering from the Colorado School of Mines and an M.B.A. from Rice University.
John D. Hart joined us as Vice President, Chief Financial Officer, and Treasurer in November 2005. He was promoted to Senior Vice President in May 2009 and served in that capacity to mid-March 2021. In March 2021, his title was changed to Senior Vice President, Chief Financial Officer and Chief Strategy Officer and he served in that capacity through January 11, 2022. On January 12, 2022, Mr. Hart was promoted to his current position as our Chief Financial Officer and Executive Vice President of Strategic Planning. Prior to joining us, he was a Senior Audit Manager with Ernst & Young LLP. Mr. Hart was employed by Ernst & Young LLP from April 1998 to November 2005 and by Arthur Andersen LLP from December 1991 to April 1998, working with numerous public companies in a wide variety of securities and exchange matters and capital markets activities. He is a member of the American Institute of Certified Public Accountants and The Petroleum Alliance of Oklahoma. Mr. Hart serves on the executive board of the Greater Oklahoma City Chamber of Commerce, and the board of directors of the Myriad Gardens Foundation. Additionally, he serves as Chairman of the Casady School Board of Trustees and serves on the Oklahoma State University Foundation Board of Governors. Mr. Hart is a Certified Public Accountant and received a Bachelor of Science in Accounting and Finance and a Master of Science in Accounting from Oklahoma State University.
Shelly Lambertz serves as Executive Vice President, Chief Culture and Administrative Officer, a position she has held since January 12, 2022. Prior to this she served as our Chief Culture Officer and Senior Vice President, Human Resources from February 2020 to January 12, 2022, and as the Company’s Vice President, Human Resources from October 2018 to February 2020. Ms. Lambertz served as a director from May 2018 to November 2022, and on January 22, 2023, she was again appointed to serve as a director. Before joining the Company as an employee, she served as the Chief Operating Officer at Hamm Capital, a family investment and advisory firm based in Oklahoma City, from August 2011 to October 2018. Ms. Lambertz also serves as Director of the Harold Hamm Foundation. From 1999 to 2005, Ms. Lambertz was the Executive Director of the YWCA in Enid, Oklahoma. From 1996 to 1998, Ms. Lambertz was Director of Human Resources and Business Development Advisor for Hamm & Phillips Service Company. She
73
began her career working for the Annual MeetingU.S. House of ShareholdersRepresentatives in Washington, D.C. Positions there included Office Manager for Congressman Mickey Edwards (OK), Legislative Assistant for the Leadership Office of Minority Leader Bob Michel (IL), and Deputy Chief of Staff for Frank Lucas (OK). Ms. Lambertz holds a bachelor’s degree in business administration from Oklahoma State University.
Jeffrey B. Hume became our Vice Chairman of Strategic Growth Initiatives in June 2012. He previously served as our President from November 3, 2009 until June 2012. From November 2008 to June 2012, Mr. Hume also served as our Chief Operating Officer after serving as our Senior Vice President of Operations since November 2006. He was previously appointed as Senior Vice President of Resource and Business Development in October 2005, Senior Vice President of Resource Development in July 2002, and served as Vice President of Drilling Operations from 1996 to 2002. Prior to joining us in May 1983 as Vice President of Engineering and Operations, Mr. Hume held various engineering positions with Sun Oil Company, Monsanto Company, and FCD Oil Corporation. Mr. Hume is a Registered Professional Engineer and member of the Society of Petroleum Engineers, The Petroleum Alliance of Oklahoma, and the Oklahoma and National Professional Engineering Societies. Mr. Hume graduated from Oklahoma State University with a Bachelor of Science in Petroleum Engineering Technology.
James R. Webb is Senior Vice President, General Counsel, and Secretary, a position he has held since November 2022. From September 2021 to November 2022, Mr. Webb served as Senior Vice President, General Counsel, Chief Risk Officer, and Secretary. Prior to joining the Company, Mr. Webb served in various executive roles at Chesapeake from 2012 to 2021, most recently as Executive Vice President – General Counsel and Corporate Secretary from January 2014 to June 2021. Chesapeake voluntarily filed for Chapter 11 bankruptcy protection in June of 2020 and emerged from bankruptcy in February of 2021. Immediately prior to joining Chesapeake, Mr. Webb was an attorney with the law firm of McAfee & Taft from 1995 to October 2012.
Robert Hagens is our Senior Vice President, Commercial Development, as position he has held since December 12, 2023. Prior to this, he served as our Senior Vice President, Land, a position he held from October 2020 (when he joined the Company) to December 12, 2023. Over the years, he has engaged in all levels of leadership within land, land administration and regulatory. Mr. Hagens started his career as a Landman with Atlantic Richfield Company (“ARCO”) in Midland, Texas and has held positions of increasing responsibility across multiple offices within the lower 48 and Alaska with ARCO and its subsidiaries. Shortly following the merger with BP plc (“BP”) in 2000, Mr. Hagens assumed the position of U.S. Onshore Land Manager with BP. Prior to joining the Company, he spent the previous 15 years as Vice President and Senior Vice President of Land for Pioneer Natural Resources Company. Mr. Hagens holds a degree in Petroleum Land Management from the University of Texas at Austin.
Information About Our Board of Directors
For information about our directors, please see the information pertaining to Mr. Hamm, Mr. Lawler, and Ms. Lambertz above. Since all directors are also executive officers, we do not have any independent directors and our directors do not receive any compensation outside their compensation for serving as executive officers.
Code of Business Conduct
We have adopted a Code of Business Conduct as a matter of sound corporate governance to promote honest and ethical conduct, consistent with our core values. We last amended our Code of Business Conduct in November 2022 by making non-substantive language changes to reflect our private company status. The Code of Business Conduct is applicable to all employees, officers, and directors, including our principal executive, financial, and accounting officers.
Material Changes to Procedures for Nominating Directors
Not Applicable.
Audit Committee Financial Experts
Our Board has an Audit Committee, and Mr. Lawler and Ms. Lambertz are currently serving as members of this committee. Our Board has not determined that either Mr. Lawler or Ms. Lambertz are Audit Committee financial experts for purposes of serving on this committee. As a result of our common stock ceasing to be held in May 2022 (the “Annual Meeting”) andlisted on the NYSE, our Audit Committee is incorporated herein by reference.
Item 11. Executive Compensation
2023 Compensation Discussion and Analysis and Executive Officer Compensation
Introduction
74
The discussion below summarizes the approach taken with respect to the compensation of our Principal Executive Officer, Principal Financial Officer, and the three other most highly compensated executive officers during 2023. These individuals are identified below and are referred to collectively in the discussion below as the “NEOs” for 2023. The discussion summarizes our compensation philosophy, the different components of our compensation program, the mix of compensation paid to our NEOs, and provides information regarding the financial statement impact for 2023 associated with the compensation program for our NEOs.
Our NEOs for 2023 (determined in accordance with the requirements of Item 402 of Regulation S-K) are:
As a result of the take-private transaction, the only group with an interest in any Company issued securities outside of Mr. Hamm, certain members of his family, and entities under their control (referred to collectively herein as the “Hamm Family”) are the holders of our outstanding bonds. As a result of the take-private transaction, we are now a voluntary filer.
Executive Compensation Philosophy
Because we operate in a highly competitive environment, we have designed our executive compensation program to attract, retain, and motivate experienced, talented individuals. We also designed our executive compensation program to reward our executives for achieving the strategic and business objectives determined to be important to help the Company create and maintain advantage in a competitive environment.
In determining individual compensation, we consider the performance of the Company against specific operational and financial factors determined to be relevant for the period in question. We also consider competitive market compensation paid by other companies comparable to us in size, geographic location, and operations. We maintain and incorporate flexibility into our compensation programs and in the assessment process, which we believe is particularly important in a changing commodity price environment. As such, we do not apply rigid formulas in determining the amount and mix of compensation elements.
For 2023, our Executive Chairman, President and Chief Executive Officer and Executive Vice President, Chief Culture and Administrative Officer (collectively, referred to herein as the “Management Compensation Group”) evaluated how the following elements (collectively, the “Primary Compensation Elements”) of our compensation program compared to the compensation awarded by the members of the then current compensation survey group (as identified by our compensation consultant firm, discussed further below). The Management Compensation Group’s analysis consisted of comparing the market data of base salary, cash bonus, long-term incentive awards, and total compensation at the 25th, 50th, and 75th percentiles of the then current compensation survey group to the compensation of each of our NEOs. Total compensation for each NEO is structured to target compensation levels near the 50th percentile, taking into account responsibilities and duties, experience, individual performance, and time in position.
Role of Management
The Management Compensation Group is responsible for overseeing all aspects of our benefit and compensation plans and programs for our executive officers. For 2023, the Management Compensation Group reviewed and determined the individual elements of total compensation of the NEOs listed above, as well as our other executive officers. Since our compensation programs are relatively simple, we do not have complex equity plans or significant change in control or severance obligations. As a result, the Management Compensation Group did not use tally sheets in analyzing the compensation of our NEOs, but instead reviewed each element of compensation, as described below, in evaluating and approving the total compensation of each of our NEOs. When making decisions with respect to each element of our compensation program, the Management Compensation Group considered how the terms of that particular element may impact the overall compensation package awarded to each NEO. As a result, any decision made with respect to each element of our compensation program was influenced by the decisions made with respect to the other elements of our compensation program.
The Management Compensation Group believed targeting near the 50th percentile for base salary, cash bonus, and long-term incentive awards resulted in competitive compensation and aligned overall pay with shareholder interests, while preserving considerable upside potential should Company and individual executive performance merit higher compensation. As the Management Compensation Group worked to achieve alignment close to the 50th percentile, it also considered an individual executive officer’s performance and the external business environment, and any final compensation decision ultimately reflected the Management Compensation Group’s discretion, which can be a significant factor in its final compensation decisions.
75
Role of Compensation Consultants
For 2023, the Management Compensation Group retained the services of an independent compensation consulting firm, Meridian Compensation Partners (“Meridian”). Meridian reported directly to the Management Compensation Group. During late 2022, Meridian provided an analysis of market compensation for our executive officers, based upon its review of compensation paid by exploration and production companies comparable to us in terms of revenues, total assets, geographic location, and market capitalization. This analysis was contained in a report used as a reference by the Management Compensation Group, and certain other members of our management team in recommending and setting compensation for 2023. During 2023, Meridian provided no other services, resulting in total fees of less than $120,000.
As a result of the take-private transaction, we have not formally assessed the independence of Meridian in connection with the preparation of this filing. However, the relationship with Meridian has not changed in any substantial respect versus prior years when it was determined Meridian was independent under New York Stock Exchange and Securities and Exchange Commission rules.
Description of Executive Officer Compensation Program
Primary Compensation Elements. The table below describes each of our Primary Compensation Elements, the purpose of each element, and how each element fits within the Company’s compensation philosophy and objectives.
Compensation Element | Description | Purpose and Philosophy |
Base Salary | Fixed cash compensation | Provides a stable, fixed element of cash compensation. Attract and retain executive officers by paying a wage commensurate with such officer’s experience, skills, and responsibilities. It also recognizes and considers the internal value of the position within the Company, the officer’s leadership potential and demonstrated performance. |
Annual Cash Bonus | Annual cash bonus related to individual contribution toward achievement of annual financial and operating results | Rewards executives for the achievement of specific annual financial, operating, and strategic goals and individual performance. Allows the Management Compensation Group to evaluate both objective and subjective considerations when exercising discretion to determine final payout amounts. Important to the Company’s ability to attract, motivate, and retain the Company’s executive officers. |
Long-term Incentive Awards | Long-term cash-based awards and restricted stock units (which are held by executive officers, but which haven’t been awarded since 2022 and are not expected to be awarded in the future) | Aligns the executive’s long-term interests with those of shareholders. Long-term incentive awards align executive’s interests with those of shareholders by increasing or decreasing in value based on changes in the overall value of the Company. Important to the Company’s ability to attract, motivate, and retain the Company’s executive officers. |
Role of Discretion in Determining Primary Compensation Elements. All base salary adjustments, cash bonuses, and long-term incentive awards for NEOs have been determined on a discretionary basis. While not linked to specific corporate goals or objectives, the overall performance of the Company and individual performance were considered in determining pay generally, including target award amounts. The Management Compensation Group retained discretion over all aspects of the annual cash bonus plan and the awards made for 2023 under that plan.
Other Compensation. Compensation and benefits that are outside of our three main compensation elements are designed to attract and retain employees by enhancing our overall compensation package. During 2023, we provided fuel cards to certain NEOs and automobiles to certain other employees for business and/or personal use. The personal use is valued according to IRS guidelines and reported as taxable income to the individuals.
We have a defined contribution retirement plan (“401(k)”) covering all full-time employees. Our contributions to the plan are discretionary and based on a percentage of eligible compensation. The 401(k) provides for Company dollar for dollar matching of up to a maximum of 10% of a covered employee’s eligible compensation, depending on the employee’s level of contribution into the employee’s account and subject to IRS limits. During 2023, the Company match was in effect the entire year.
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All full-time employees may participate in our health and welfare benefit programs, including medical, dental, vision care, life insurance, and disability insurance. We provide all full-time employees with life insurance coverage of the lesser of two times base salary or $1,000,000 and allow them to purchase supplemental coverage. We do not sponsor any qualified or non-qualified defined benefit plans.
Risk Assessment Related to our Compensation Structure. We believe our executive compensation program is appropriately structured and not reasonably likely to result in risks that could have a material adverse effect on us. We believe our approach of subjectively evaluating performance results of each executive assists in mitigating excessive risk-taking that could harm our value or reward poor judgment by our executives. Several features of our programs reflect sound risk management practices. We believe we have allocated our compensation among base salary and short and long-term compensation opportunities in such a way as to Item 11 will be set forthdiscourage excessive risk-taking. Further, one of the primary factors we take into consideration in setting compensation is the performance of the Company as a whole. This is based on our belief that applying Company-wide metrics encourages decision-making that is in the Proxy Statementbest long-term interests of the Company and our shareholders as a whole. Metrics used may include financial and operating metrics pertaining to production volumes, capital spending, cash flows, return on capital employed, resource replacement, and health, safety, and environmental performance. Finally, the time-based vesting over a multi-year period for our long-term incentive awards ensures our employees’ interests align with those of our shareholders for the Annual Meetinglong-term performance of our Company.
The following charts illustrate the various components of total annual compensation for our Chief Executive Officer and the other NEOs as a group, and reflect the following: (i) base salary received by the NEO during 2023; (ii) the cash bonus for 2023 paid in February 2024; (iii) the grant date target value of the long-term incentive awards granted to the NEOs in 2023 (which is incorporated hereinthe target value of the awards on the date of grant, and not necessarily reflective of the amounts the NEOs may receive at the time of settlement); and (iv) the other compensation for each NEO during 2023.
The aggregate total amount of annual compensation-related expenses recognized in the Company’s financial statements related to the 2023 compensation of the NEOs as a group represented less than 0.5% of our total income from operations, our total operating cash flows and our total liabilities as of and for the year ended December 31, 2023.
Management Compensation Group Report (in lieu of a Compensation Committee Report)
As a result of the take-private transaction, the Compensation Committee was eliminated by reference.the Board and ceased to function. As a result, it is not possible to provide a report of the Compensation Committee at the time of the filing of this report. The Management Compensation Group (which is composed of the same individuals as currently comprise our Board and has assumed many of the duties previously performed by the Compensation Committee) has reviewed and discussed the Compensation Discussion and Analysis (“CD&A”) above with other members of management. Based on this review and discussion, the Management Compensation Group has determined that it is appropriate to include this CD&A in this filing.
/s/ Harold G. Hamm | /s/ Robert D. Lawler | /s/ Shelly Lambertz | ||
Harold G. Hamm Executive Chairman and Director | Robert D. Lawler President, Chief Executive Officer and Director | Shelly Lambertz Executive Vice President, Chief Culture and Administrative Officer and Director |
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Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
Information requiredAs a result of the completion of the take-private transaction, the Company is 100% owned by Item 201(d)the Hamm Family. As a result, none of Regulation S-K with respectour directors and/or executive officers who are not members of the Hamm Family have any security ownership reportable to securities authorized for issuance under equity compensation plans is disclosed in this item.Part II, Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities—Equity Compensation Plan Information and is incorporated herein by reference. Other applicable information required as to Item 12 will be set forth in the Proxy Statement for the Annual Meeting and is incorporated herein by reference.
Item 13. Certain Relationships and Related Transactions, and Director Independence
Prior to the completion of the take-private transaction, our Audit Committee (then composed of independent directors meeting applicable NYSE and SEC requirements) reviewed related party transactions, as required by the terms of the Audit Committee charter then in place, and recommended approval or disapproval to Item 13 will bethe Board of any such transaction. During this time, the Audit Committee recommended for approval only those related party transactions that were, in its business judgment, in our best interests and on terms no less favorable to us than we could have achieved with an unaffiliated party. Following the completion of the take-private transaction, an Audit Committee composed of Mr. Lawler and Ms. Lambertz was voluntarily established for the purpose of reviewing related party transactions as a matter of sound corporate governance and to provide oversight to ensure that any transactions with related parties meet existing covenant requirements pertaining to affiliate transactions set forth in our senior credit facility and term loan agreements. The standard for review and approval of related party transactions under our current structure is substantially the Proxy Statement forsame as applied prior to the Annual Meetingtake private transaction. None of transactions reviewed by the Audit Committee since December 31, 2022 are transactions in which the related party had a direct or indirect material interest, and is incorporated herein by reference.
Item 14. Principal Accountant Fees and Services
Grant Thornton served as to Item 14 will beour independent registered public accounting firm during 2023 and 2022. The aggregate fees for various services performed by Grant Thornton for the years ended December 31, 2023, and 2022 are set forth below:
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| 2023 | 2022 |
Audit Fees | $994,000 | $1,107,000 |
Audit-Related Fees | — | — |
Tax Fees | — | — |
All Other Fees | — | — |
Total Fees | $994,000 | $1,107,000 |
Fees for audit services include fees associated with our annual consolidated and subsidiary audits, the review of our quarterly reports on Form 10-Q, Sarbanes Oxley Act compliance review, accounting consultations, and services normally provided by the accounting firm in connection with statutory or regulatory filings.
As necessary, the Proxy StatementAudit Committee considers whether the provision of non-audit services by Grant Thornton is compatible with maintaining auditor independence and has adopted a policy that requires pre-approval of all audit and non-audit services for Grant Thornton. Such policy requires the Annual MeetingAudit Committee to approve services and is incorporated herein by reference.
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PART IV
Item 15. Exhibits and Financial Statement Schedules
The consolidated financial statements of Continental Resources, Inc. and Subsidiaries and the Report of Independent Registered Public Accounting Firm are included in Part II, Item 8 of this report. Reference is made to the accompanying Index to Consolidated Financial Statements.
All financial statement schedules have been omitted because they are not applicable or the required information is presented in the financial statements or the notes thereto.
The exhibits required to be filed or furnished pursuant to Item 601 of Regulation S-K are set forth below.
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31.1* | ||||||||
31.2* | ||||||||
99* | ||||||||
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101.INS* | Inline XBRL Instance Document - the Inline XBRL Instance Document does not appear in the Interactive Data file because its XBRL tags are embedded within the Inline XBRL document | |||||||
101.SCH* | Inline XBRL Taxonomy Extension Schema With Embedded Linkbases Document | |||||||
104 | Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101) | |||||||
* Filed herewith
† Management contracts or compensatory plans or arrangements filed pursuant to Item 601(b)(10)(iii) of Regulation S-K.
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Signatures
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, Continental Resources, Inc. has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
CONTINENTAL RESOURCES, INC. | ||||||||
By: | /S/ ROBERT D. LAWLER | |||||||
Name: |
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Title: | President, | |||||||
Date: | February | |||||||
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of Continental Resources, Inc. and in the capacities and on the dates indicated.
Signature | Title | Date | ||||||||||||
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/s/ HAROLD G. HAMM | Executive Chairman | February | ||||||||||||
Harold G. Hamm | ||||||||||||||
/s/ | President, Chief Executive Officer, and Director (principal executive officer) | February | ||||||||||||
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(principal financial and accounting officer) | ||||||||||||||
/s/ SHELLY LAMBERTZ | Executive Vice President, Chief Culture and Administrative Officer and Director | February | ||||||||||||
Shelly Lambertz | ||||||||||||||
/s/ JOHN |
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(principal financial and accounting officer) |
| February | ||||||||||
John | ||||||||||||||
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