# EDGAR Filing Document

**Accession Number:** 0000732834
**File Stem:** 0001193125-26-064403
**Filing Date:** 2026-2
**Character Count:** 437341
**Document Hash:** ccd3285bfc46dfcbd5b7256e0ab7b6b6
**Contains OCR:** False
**Source Format:** 

## Filing Content

## Filing Summary
**0001193125-26-064403.hdr.sgml**: 20260223

**ACCESSION NUMBER**: 0001193125-26-064403

**CONFORMED SUBMISSION TYPE**: 10-K

**PUBLIC DOCUMENT COUNT**: 104

**CONFORMED PERIOD OF REPORT**: 20251231

**FILED AS OF DATE**: 20260223

**DATE AS OF CHANGE**: 20260223

**FILER**: 

**COMPANY DATA:**
- **COMPANY CONFORMED NAME:** CONTINENTAL RESOURCES, INC
- **CENTRAL INDEX KEY:** 0000732834
- **STANDARD INDUSTRIAL CLASSIFICATION:** CRUDE PETROLEUM & NATURAL GAS [1311]
- **ORGANIZATION NAME:** 01 Energy & Transportation
- **EIN:** 730767549
- **STATE OF INCORPORATION:** OK
- **FISCAL YEAR END:** 1231

**FILING VALUES:**
- **FORM TYPE:** 10-K
- **SEC ACT:** 1934 Act
- **SEC FILE NUMBER:** 001-32886
- **FILM NUMBER:** 26666632

**BUSINESS ADDRESS:**
- **STREET 1:** 20 NORTH BROADWAY
- **CITY:** OKLAHOMA CITY
- **STATE:** OK
- **ZIP:** 73102
- **BUSINESS PHONE:** 4052349000

**MAIL ADDRESS:**
- **STREET 1:** PO BOX 268836
- **CITY:** OKLAHOMA CITY
- **STATE:** OK
- **ZIP:** 73126

**FORMER COMPANY:**
- **FORMER CONFORMED NAME:** CONTINENTAL RESOURCES INC
- **DATE OF NAME CHANGE:** 19980811

?xml version='1.0' encoding='ASCII'? 10-K

[**<u>**Table of Contents**</u>**](#table_of_contents)

**UNITED STATES**

**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 **,** 2025

**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

**_______________________________**![img205445845_0.gif](img205445845_0.gif)

CONTINENTAL RESOURCES, INC.

**(Exact name of registrant as specified in its charter)**

**_______________________________** 

---

| | | | | | |
|:---|:---|:---|:---|:---|:---|
| Oklahoma |  |  |  |  | 73-0767549 |
| (State or other jurisdiction) |  |  |  |  | (I.R.S. Employer Identification No.) |
|  | 20 N. Broadway, | Oklahoma City, | Oklahoma | 73102 |  |
|  | (Address of principal executive offices) | (Address of principal executive offices) | (Address of principal executive offices) | (Zip Code) |  |

---

Registrant's telephone number, including area code: (405) 234-9000

Securities registered pursuant to Section 12(b) of the Act: None

Securities registered pursuant to Section 12(g) of the Act: None

**_______________________________** 

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ◻ 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 ⌧ No ◻

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 ◻ 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 ⌧ 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 ⌧

Effective November 22, 2022, Continental Resources, Inc. became a privately held corporation and has no publicly available common shares outstanding at the time of this filing.

DOCUMENTS INCORPORATED BY REFERENCE

None.

------

[**<u>**Table of Contents**</u>**](#table_of_contents)

**Table of Contents** 

---

| | | |
|:---|:---|:---|
| &nbsp;&nbsp;**<u>PART I</u>** |  |  |
| &nbsp;&nbsp;Item 1. | &nbsp;&nbsp;[<u>Business</u>](#section6) | &nbsp;&nbsp;<u>1</u> |
|  | &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;[<u>General</u>](#section7) | &nbsp;&nbsp;<u>1</u> |
|  | &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;[<u>Our Business Strategies</u>](#section8) | &nbsp;&nbsp;<u>1</u> |
|  | &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;[<u>Crude Oil and Natural Gas Operations</u>](#crude_oil_and_natural) | &nbsp;&nbsp;<u>1</u> |
|  | &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;[<u>Proved Reserves</u>](#section11) | &nbsp;&nbsp;<u>1</u> |
|  | &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;[<u>Developed and Undeveloped Acreage</u>](#section12) | &nbsp;&nbsp;<u>4</u> |
|  | &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;[<u>Drilling Activity</u>](#section13) | &nbsp;&nbsp;<u>4</u> |
|  | &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;[<u>Summary of Crude Oil and Natural Gas Properties and Projects</u>](#section14) | &nbsp;&nbsp;<u>5</u> |
|  | &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;[<u>Production and Price History</u>](#section15) | &nbsp;&nbsp;<u>6</u> |
|  | &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;[<u>Productive Wells</u>](#section16) | &nbsp;&nbsp;<u>7</u> |
|  | &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;[<u>Title to Properties</u>](#section17) | &nbsp;&nbsp;<u>7</u> |
|  | &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;[<u>Marketing</u>](#section18) | &nbsp;&nbsp;<u>7</u> |
|  | &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;[<u>Competition</u>](#section20) | &nbsp;&nbsp;<u>8</u> |
|  | &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;[<u>Regulation of the Crude Oil and Natural Gas Industry</u>](#section21) | &nbsp;&nbsp;<u>8</u> |
|  | &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;[<u>Human Capital</u>](#section22) | &nbsp;&nbsp;<u>10</u> |
|  | &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;[<u>Company Contact Information</u>](#section23) | &nbsp;&nbsp;<u>11</u> |
| &nbsp;&nbsp;Item 1A. | &nbsp;&nbsp;[<u>Risk Factors</u>](#section24) | &nbsp;&nbsp;<u>12</u> |
| &nbsp;&nbsp;Item 1B. | &nbsp;&nbsp;[<u>Unresolved Staff Comments</u>](#item_1b) | &nbsp;&nbsp;<u>23</u> |
| &nbsp;&nbsp;Item 1C. | &nbsp;&nbsp;[<u>Cybersecurity</u>](#item_cybersecurity) | &nbsp;&nbsp;<u>23</u> |
| &nbsp;&nbsp;Item 2. | &nbsp;&nbsp;[<u>Properties</u>](#item2) | &nbsp;&nbsp;<u>24</u> |
| &nbsp;&nbsp;Item 3. | &nbsp;&nbsp;[<u>Legal Proceedings</u>](#item3) | &nbsp;&nbsp;<u>24</u> |
| &nbsp;&nbsp;Item 4. | &nbsp;&nbsp;[<u>Mine Safety Disclosures</u>](#item4) | &nbsp;&nbsp;<u>24</u> |
| &nbsp;&nbsp;**<u>PART II</u>** |  |  |
| &nbsp;&nbsp;Item 5. | &nbsp;&nbsp;[<u>Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities</u>](#section30) | &nbsp;&nbsp;<u>25</u> |
| &nbsp;&nbsp;Item 6. | &nbsp;&nbsp;[<u>Reserved</u>](#section31) | &nbsp;&nbsp;<u>25</u> |
| &nbsp;&nbsp;Item 7. | &nbsp;&nbsp;[<u>Management's Discussion and Analysis of Financial Condition and Results of Operations</u>](#section32) | &nbsp;&nbsp;<u>26</u> |
| &nbsp;&nbsp;Item 7A. | &nbsp;&nbsp;[<u>Quantitative and Qualitative Disclosures About Market Risk</u>](#section44) | &nbsp;&nbsp;<u>37</u> |
| &nbsp;&nbsp;Item 8. | &nbsp;&nbsp;[<u>Financial Statements and Supplementary Data</u>](#section45) | &nbsp;&nbsp;<u>39</u> |
| &nbsp;&nbsp;Item 9. | &nbsp;&nbsp;[<u>Changes in and Disagreements with Accountants on Accounting and Financial Disclosure</u>](#section72) | &nbsp;&nbsp;<u>70</u> |
| &nbsp;&nbsp;Item 9A. | &nbsp;&nbsp;[<u>Controls and Procedures</u>](#section73) | &nbsp;&nbsp;<u>70</u> |
| &nbsp;&nbsp;Item 9B. | &nbsp;&nbsp;[<u>Other Information</u>](#section79) | &nbsp;&nbsp;<u>72</u> |
| &nbsp;&nbsp;Item 9C. | &nbsp;&nbsp;[<u>Disclosure Regarding Foreign Jurisdictions that Prevent Inspections</u>](#section80) | &nbsp;&nbsp;<u>72</u> |
| &nbsp;&nbsp;**<u>PART III</u>** | &nbsp;&nbsp;**<u>PART III</u>** |  |
| &nbsp;&nbsp;Item 10. | &nbsp;&nbsp;[<u>Directors, Executive Officers and Corporate Governance</u>](#section82) | &nbsp;&nbsp;<u>73</u> |
| &nbsp;&nbsp;Item 11. | &nbsp;&nbsp;[<u>Executive Compensation</u>](#section83) | &nbsp;&nbsp;<u>75</u> |
| &nbsp;&nbsp;Item 12. | &nbsp;&nbsp;<u>Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters</u> | &nbsp;&nbsp;<u>78</u> |
| &nbsp;&nbsp;Item 13. | &nbsp;&nbsp;[<u>Certain Relationships and Related Transactions, and Director Independence</u>](#section85) | &nbsp;&nbsp;<u>78</u> |
| &nbsp;&nbsp;Item 14. | &nbsp;&nbsp;[<u>Principal Accountant Fees and Services</u>](#section86) | &nbsp;&nbsp;<u>79</u> |
| &nbsp;&nbsp;**<u>PART IV</u>** | &nbsp;&nbsp;**<u>PART IV</u>** |  |
| &nbsp;&nbsp;Item 15. | &nbsp;&nbsp;[<u>Exhibits and Financial Statement Schedules</u>](#section88) | &nbsp;&nbsp;<u>80</u> |

---

------

[**<u>**Table of Contents**</u>**](#table_of_contents)

**Glossary of Crude Oil and Natural Gas Terms**

The terms defined in this section may be used throughout this report:

*"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.

*"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 *"NGLs"* 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 gasoline.

*"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.

*"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.

i

------

[**<u>**Table of Contents**</u>**](#table_of_contents)

*"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.

*"SCOOP"* Refers to the South Central Oklahoma Oil Province, a term used to describe properties located in the Anadarko basin of Oklahoma in which we operate.

*"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

------

[**<u>**Table of Contents**</u>**](#table_of_contents)

**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:

&nbsp;&nbsp;&nbsp;&nbsp;•our strategy;

&nbsp;&nbsp;&nbsp;&nbsp;•our business and financial plans;

&nbsp;&nbsp;&nbsp;&nbsp;•our future operations;

&nbsp;&nbsp;&nbsp;&nbsp;•our proved reserves and related development plans;

&nbsp;&nbsp;&nbsp;&nbsp;•technology;

&nbsp;&nbsp;&nbsp;&nbsp;•future crude oil, natural gas liquids, and natural gas prices and differentials;

&nbsp;&nbsp;&nbsp;&nbsp;•the timing and amount of future production of crude oil, natural gas liquids, and natural gas and flaring activities;

&nbsp;&nbsp;&nbsp;&nbsp;•the amount, nature and timing of capital expenditures;

&nbsp;&nbsp;&nbsp;&nbsp;•estimated revenues, expenses and results of operations;

&nbsp;&nbsp;&nbsp;&nbsp;•drilling and completing of wells;

&nbsp;&nbsp;&nbsp;&nbsp;•shutting in of production and the resumption of production activities;

&nbsp;&nbsp;&nbsp;&nbsp;•competition;

&nbsp;&nbsp;&nbsp;&nbsp;•marketing of crude oil, natural gas, and natural gas liquids;

&nbsp;&nbsp;&nbsp;&nbsp;•transportation of crude oil, natural gas, and natural gas liquids to markets;

&nbsp;&nbsp;&nbsp;&nbsp;•property exploitation, property acquisitions and dispositions, strategic investments, or joint domestic and foreign development opportunities;

&nbsp;&nbsp;&nbsp;&nbsp;•costs of exploiting and developing our properties and conducting other operations, including any impacts from inflation;

&nbsp;&nbsp;&nbsp;&nbsp;•our financial position;

&nbsp;&nbsp;&nbsp;&nbsp;•the timing and amount of debt borrowings or repayments;

&nbsp;&nbsp;&nbsp;&nbsp;•the timing and amount of income tax payments and payments the Company may be obligated to make pursuant to the stock redemption agreement described in *Note 13. Commitments and Contingencies*—*Stock Redemption Agreement*;

&nbsp;&nbsp;&nbsp;&nbsp;•current and potential litigation matters;

&nbsp;&nbsp;&nbsp;&nbsp;•geopolitical events and conditions in, or affecting other, crude oil-producing or natural gas-producing nations, including foreign jurisdictions where the Company may explore resource development opportunities;

&nbsp;&nbsp;&nbsp;&nbsp;•credit markets;

&nbsp;&nbsp;&nbsp;&nbsp;•our liquidity and access to capital;

&nbsp;&nbsp;&nbsp;&nbsp;•the impact of U.S. and foreign governmental policies, laws, regulations, tariffs in the U.S. and foreign jurisdictions, as well as regulatory and legal proceedings involving us and of scheduled or potential regulatory or legal changes in these areas;

&nbsp;&nbsp;&nbsp;&nbsp;•our future operating and financial results;

&nbsp;&nbsp;&nbsp;&nbsp;•our future commodity or other hedging arrangements; and

&nbsp;&nbsp;&nbsp;&nbsp;•the ability and willingness of current or potential lenders, hedging contract counterparties, customers, and working interest owners to fulfill their obligations to us or to enter into transactions with us in the future on terms that are acceptable to us.

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

iii

------

[**<u>**Table of Contents**</u>**](#table_of_contents)

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 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 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's actual results and plans could differ materially from those expressed in any forward-looking statements. All forward-looking statements are expressly qualified in their entirety by this cautionary statement.

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

------

[**<u>**Table of Contents**</u>**](#table_of_contents)

**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 Dakota and Montana, the Anadarko Basin of Oklahoma, the Permian Basin of Texas, and the Powder River Basin of Wyoming. As of December 31, 2025, all of our operations were conducted onshore in the United States. In the first quarter of 2026, we expanded our operations internationally via the acquisition of assets within the Vaca Muerta shale play in Argentina's Neuquén Basin. At the time of this filing, our 2026 activities in Argentina have no production or revenues and represent an immaterial portion of our consolidated assets. 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, pad/row development, and enhanced recovery technologies allow us to develop and produce crude oil and natural gas reserves from unconventional formations.

Effective November 22, 2022, Continental Resources, Inc. became a privately 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 SEC as required by our senior note indentures.

**Our Business Strategies**

Our business strategies continue to be focused on increasing enterprise value by finding and developing crude oil and natural gas reserves at low costs and attractive rates of return. For 2026, our primary business strategies will include:

&nbsp;&nbsp;&nbsp;&nbsp;•Continuing to evaluate world-class domestic and international resource opportunities that align well with our technical strengths and history of innovation;

&nbsp;&nbsp;&nbsp;&nbsp;•Continuing to exercise capital discipline and operational excellence to maximize cash flow generation;

&nbsp;&nbsp;&nbsp;&nbsp;•Reducing outstanding debt and strengthening our balance sheet to further enhance financial flexibility;

&nbsp;&nbsp;&nbsp;&nbsp;•Continuing to optimize the efficiency of our capital programs and production operations to further reduce costs and enhance returns; and

&nbsp;&nbsp;&nbsp;&nbsp;•Driving continued improvement in our health, safety, and environmental performance and governance programs.

**Crude Oil and Natural Gas Operations**

**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, performance-based methods, volumetric-based methods, geologic maps, seismic interpretation, well logs, well test data, and analogy and statistical analysis.

------

[**<u>**Table of Contents**</u>**](#table_of_contents)

The table below sets forth estimated proved crude oil and natural gas reserves information by reserve category as of December 31, 2025. Proved reserves attributable to noncontrolling interests are not material relative to our consolidated reserves and are not separately presented herein. Our reserve estimates as of December 31, 2025 are based primarily on a reserve report prepared by Ryder Scott. In preparing its report, Ryder Scott evaluated properties representing approximately 97% of our total proved reserves as of December 31, 2025. 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.

Our estimated proved reserves and related future net revenues at December 31, 2025 were determined using the 12-month unweighted arithmetic average of the first-day-of-the-month commodity prices for the period of January 2025 through December 2025, without giving effect to derivative transactions, and were held constant throughout the lives of the properties. These prices were $65.34 per Bbl for crude oil and $3.39 per MMBtu for natural gas ($61.92 per Bbl for crude oil and $2.75 per Mcf for natural gas adjusted for location and quality differentials).

The following table summarizes our estimated proved reserves by commodity and reserve classification as of December 31, 2025.

---

| | | | |
|:---|:---|:---|:---|
|  | **Crude Oil<br>(MBbls)** | **Natural Gas<br>(MMcf)** | **Total<br>(MBoe)** |
| Proved developed producing | 383371 | 3442905 | 957189 |
| Proved developed non-producing | 5296 | 42376 | 12359 |
| Proved undeveloped | 342365 | 2414070 | 744710 |
| &nbsp;&nbsp;&nbsp;&nbsp;Total proved reserves | 731032 | 5899351 | 1714258 |

---

The following table provides additional information regarding our estimated proved crude oil and natural gas reserves by region as of December 31, 2025.

---

| | | | | | | |
|:---|:---|:---|:---|:---|:---|:---|
|  | **Proved Developed** | **Proved Developed** | **Proved Developed** | **Proved Undeveloped** | **Proved Undeveloped** | **Proved Undeveloped** |
|  | **Crude Oil<br>(MBbls)** | **Natural Gas<br>(MMcf)** | **Total<br>(MBoe)** | **Crude Oil<br>(MBbls)** | **Natural Gas<br>(MMcf)** | **Total<br>(MBoe)** |
| Bakken | 155110 | 841588 | 295375 | 69894 | 214344 | 105618 |
| Anadarko Basin | 69511 | 1984039 | 400184 | 44116 | 1197530 | 243704 |
| Powder River Basin | 43453 | 151723 | 68740 | 37031 | 70781 | 48828 |
| Permian Basin | 99943 | 507819 | 184580 | 191324 | 931415 | 346560 |
| All other | 20650 | 112 | 20669 |  |  |  |
| Total | 388667 | 3485281 | 969548 | 342365 | 2414070 | 744710 |

---

The following table provides information regarding changes in total estimated proved reserves for the periods presented.

---

| | | | |
|:---|:---|:---|:---|
|  | **Year Ended December 31,** | **Year Ended December 31,** | **Year Ended December 31,** |
| ***MBoe*** | **2025** | **2024** | **2023** |
| Proved reserves at beginning of year | 1824810 | 1847089 | 1863764 |
| Revisions of previous estimates | (364218) | (276784) | (369264) |
| Extensions, discoveries and other additions | 418582 | 452530 | 438367 |
| Production | (166573) | (155914) | (160660) |
| Sales of minerals in place | (4769) | (42223) | (15594) |
| Purchases of minerals in place | 6426 | 112 | 90476 |
| Proved reserves at end of year | 1714258 | 1824810 | 1847089 |

---

*Revisions of previous estimates.* Revisions for 2025 are comprised of (i) downward price revisions of 6 MMBo and upward price revisions of 100 Bcf (totaling a net upward revision of 10 MMBoe) due to a decrease in average crude oil prices offset by an increase in average natural gas prices in 2025 compared to 2024, (ii) the removal of 81 MMBo and 339 Bcf (totaling 138 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 95 MMBo and 563 Bcf (totaling 189 MMBoe) from the removal of PUD reserves due to changes in anticipated well densities, economics, performance, and other factors, and (iv) downward revisions of 13 MMBo and 204 Bcf (totaling 47 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. For 2025, proved reserve additions totaled 419 MMBoe. See the subsequent section titled *Summary of Crude Oil and Natural Gas Properties and Projects* for a discussion of our 2025 drilling activities.

------

[**<u>**Table of Contents**</u>**](#table_of_contents)

*Sales and purchases of minerals in place.* Sales and purchases in 2025, 2024, and 2023 were attributable to the transactions discussed in *Part II. Item 8. Notes to Consolidated Financial Statements—Note 2. Property Acquisitions and Dispositions.* 

*Proved Undeveloped Reserves*

All of our PUD reserves at December 31, 2025 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, 2025. Our PUD reserves at December 31, 2025 include 64 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"). Our DUC wells are classified as PUD reserves when relatively major expenditures are required to complete and produce from the wells.

---

| | | | |
|:---|:---|:---|:---|
|  | **Crude Oil<br>(MBbls)** | **Natural Gas<br>(MMcf)** | **Total<br>(MBoe)** |
| Proved undeveloped reserves at December 31, 2024 | 430512 | 2607079 | 865025 |
| Revisions of previous estimates | (166385) | (922486) | (320133) |
| Extensions, discoveries and other additions | 152638 | 1280715 | 366091 |
| Sales of minerals in place | (977) | (6629) | (2082) |
| Conversion to proved developed reserves | (73423) | (544609) | (164191) |
| Proved undeveloped reserves at December 31, 2025 | 342365 | 2414070 | 744710 |

---

*Revisions of previous estimates.* As previously discussed, in 2025 we removed 81 MMBo and 339 Bcf (totaling 138 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. Additionally, changes in anticipated well densities, economics, performance, and other factors resulted in downward PUD reserve revisions of 95 MMBo and 563 Bcf (totaling 189 MMBoe) in 2025. Finally, changes in ownership interests, operating costs, anticipated production, and other factors resulted in upward revisions of 11 MMBo and downward revisions of 22 Bcf (totaling a net upward revision of 7 MMBoe) in 2025.

*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.

*Sales of minerals in place.* We had no individually significant dispositions of PUD reserves in 2025.

*Conversion to proved developed reserves.* In 2025, we developed approximately 19% of our PUD reserves booked as of December 31, 2024 through the drilling and completion of 311 gross (164 net) development wells at an aggregate capital cost of approximately $1.2 billion incurred in 2025.

*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 113 gross (56 net) operated and non-operated locations at December 31, 2025 and represent 9% of our PUD reserves at that date. The costs to drill our uncompleted wells were incurred prior to December 31, 2025 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, 2025 are projected to be approximately $1.9 billion in 2026, $1.5 billion in 2027, $1.7 billion in 2028, $1.5 billion in 2029, and $2.0 billion in 2030. 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, 2025 is expected to occur within five years of the date of initial booking of the PUDs. PUD reserves not expected to be drilled within five years of initial booking because of changes in business strategy or for other reasons have been removed from our reserves at December 31, 2025. We had no PUD reserves at December 31, 2025 that remain undrilled beyond five years from the date of initial booking.

------

[**<u>**Table of Contents**</u>**](#table_of_contents)

*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, 97% of our total proved reserves as of December 31, 2025 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 Manager of Corporate Resource Development is the technical person primarily responsible for overseeing the preparation of our reserve estimates. The Manager of Corporate Resource Development reports to our Chief Financial Officer and Executive Vice President of Strategic Planning. 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 certain members of senior management before the information is filed with the SEC on Form 10-K.

**Developed and Undeveloped Acreage**

The following table presents our total gross and net developed and undeveloped acres by region as of December 31, 2025:

---

| | | | | | | |
|:---|:---|:---|:---|:---|:---|:---|
|  | **Developed acres** | **Developed acres** | **Undeveloped acres** | **Undeveloped acres** | **Total** | **Total** |
|  | **Gross** | **Net** | **Gross** | **Net** | **Gross** | **Net** |
| Bakken | 1108293 | 713602 | 169113 | 100595 | 1277406 | 814197 |
| Anadarko Basin | 486714 | 293658 | 445595 | 220332 | 932309 | 513990 |
| Powder River Basin | 289917 | 222086 | 265941 | 192420 | 555858 | 414506 |
| Permian Basin | 149426 | 133379 | 187717 | 130184 | 337143 | 263563 |
| All other | 163248 | 141047 | 222708 | 137027 | 385956 | 278074 |
| Total | 2197598 | 1503772 | 1291074 | 780558 | 3488672 | 2284330 |

---

The following table sets forth the number of gross and net undeveloped acres as of December 31, 2025 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.

---

| | | | | | | |
|:---|:---|:---|:---|:---|:---|:---|
|  | **2026** | **2026** | **2027** | **2027** | **2028** | **2028** |
|  | **Gross** | **Net** | **Gross** | **Net** | **Gross** | **Net** |
| Bakken | 12250 | 7321 | 4397 | 1842 | 50226 | 34560 |
| Anadarko Basin | 55784 | 28628 | 75897 | 40289 | 69896 | 33897 |
| Powder River Basin | 10062 | 6227 | 2332 | 1200 | 4497 | 3779 |
| Permian Basin | 28367 | 19752 | 27988 | 11984 | 56030 | 43300 |
| All other | 14558 | 9602 | 6102 | 4253 | 10422 | 8218 |
| Total | 121021 | 71530 | 116716 | 59568 | 191071 | 123754 |

---

**Drilling Activity**

During the three years ended December 31, 2025, we participated in the drilling and completion of exploratory and development wells as set forth in the table below.

---

| | | | | | | |
|:---|:---|:---|:---|:---|:---|:---|
|  | **2025** | **2025** | **2024** | **2024** | **2023** | **2023** |
|  | **Gross** | **Net** | **Gross** | **Net** | **Gross** | **Net** |
| Exploratory wells: |  |  |  |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Crude oil | 58 | 40.0 | 47 | 39.3 | 33 | 25.9 |
| &nbsp;&nbsp;&nbsp;&nbsp;Natural gas | 9 | 9 |  |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Dry holes |  |  |  |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Total exploratory wells | 67 | 49.0 | 47 | 39.3 | 33 | 25.9 |
| Development wells: |  |  |  |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Crude oil | 281 | 164.0 | 417 | 194.5 | 548 | 259.0 |
| &nbsp;&nbsp;&nbsp;&nbsp;Natural gas | 12 | 6.0 | 2 | 0.1 | 27 | 7.6 |
| &nbsp;&nbsp;&nbsp;&nbsp;Dry holes |  |  |  |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Total development wells | 293 | 170.0 | 419 | 194.6 | 575 | 266.6 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Total wells | 360 | 219.0 | 466 | 233.9 | 608 | 292.5 |

---

------

[**<u>**Table of Contents**</u>**](#table_of_contents)

As of December 31, 2025, there were 212 gross (86 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 of 2025 activities in our key operating areas.

***Bakken Field***

Our total Bakken production averaged 204,524 Boe per day for the fourth quarter of 2025, up 8% from the 2024 fourth quarter. For the year ended December 31, 2025, our average daily Bakken production increased 2% compared to 2024. In 2025, we participated in the drilling and completion of 189 gross (99 net) wells in the Bakken compared to 242 gross (96 net) wells in 2024.

Our Bakken properties represented 23% of our total proved reserves at December 31, 2025 and 43% of our average daily Boe production for the 2025 fourth quarter. Our total proved Bakken field reserves as of December 31, 2025 were 401 MMBoe, a decrease of 28% compared to December 31, 2024. Our inventory of proved undeveloped drilling locations in the Bakken totaled 321 gross (162 net) wells as of December 31, 2025.

***Anadarko Basin***

Our properties in the Anadarko Basin represented 38% of our total proved reserves as of December 31, 2025 and 27% of our average daily Boe production for the fourth quarter of 2025. Production in the Anadarko Basin averaged 129,965 Boe per day during the fourth quarter of 2025, up 3% compared to the 2024 fourth quarter. We participated in the drilling and completion of 62 gross (40 net) wells in the Anadarko Basin during 2025 compared to 95 gross (45 net) wells in 2024.

Our proved reserves in the Anadarko Basin as of December 31, 2025 totaled 644 MMBoe, a decrease of 12% compared to December 31, 2024. Our inventory of proved undeveloped drilling locations in the Anadarko Basin totaled 208 gross (141 net) wells as of December 31, 2025.

***Powder River Basin***

Our Powder River properties represented 7% of our total proved reserves as of December 31, 2025 and 5% of our average daily Boe production for the 2025 fourth quarter. Our production in the Powder River Basin averaged 25,420 Boe per day for the fourth quarter of 2025, a decrease of 7% compared to the 2024 fourth quarter. During 2025, we participated in the drilling and completion of 28 gross (11 net) wells in the play compared to 56 gross (25 net) wells in 2024.

Our proved reserves in the Powder River Basin totaled 118 MMBoe as of December 31, 2025, a decrease of 18% compared to December 31, 2024. Our inventory of proved undeveloped drilling locations in the play totaled 95 gross (70 net) wells as of December 31, 2025.

***Permian Basin***

Our Permian properties represented 31% of our total proved reserves at December 31, 2025 and 23% of our average daily Boe production for the 2025 fourth quarter. Our production in the Permian Basin averaged 110,487 Boe per day for the fourth quarter of 2025, an increase of 49% compared to the 2024 fourth quarter. During 2025, we participated in the drilling and completion of 80 gross (67 net) wells in the play compared to 73 gross (68 net) wells in 2024.

Our proved reserves in the Permian Basin totaled 531 MMBoe as of December 31, 2025, an increase of 46% compared to December 31, 2024. Our inventory of proved undeveloped drilling locations in the play totaled 444 gross (388 net) wells at year-end 2025.

------

[**<u>**Table of Contents**</u>**](#table_of_contents)

**Production and Price History**

The following table sets forth information concerning our production results, average sales prices and production costs for the years ended December 31, 2025, 2024 and 2023 in total and for each field containing 15 percent or more of our total proved reserves as of December 31, 2025.

---

| | | | |
|:---|:---|:---|:---|
|  | **Year ended December 31,** | **Year ended December 31,** | **Year ended December 31,** |
|  | **2025** | **2024** | **2023** |
| Net production volumes: |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Crude oil (MBbls) |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;North Dakota Bakken | 45508 | 44197 | 48032 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;SCOOP | 12525 | 12426 | 11652 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Permian Delaware | 20639 | 17343 | 14762 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Total Company | 90162 | 84139 | 84710 |
| &nbsp;&nbsp;&nbsp;&nbsp;Natural gas (MMcf) |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;North Dakota Bakken | 153676 | 153389 | 146026 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;SCOOP | 179306 | 169031 | 179165 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Permian Delaware | 70845 | 38414 | 27980 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Total Company | 458468 | 430649 | 455698 |
| &nbsp;&nbsp;&nbsp;&nbsp;Crude oil equivalents (MBoe) |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;North Dakota Bakken | 71121 | 69762 | 72370 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;SCOOP | 42409 | 40598 | 41513 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Permian Delaware | 32447 | 23745 | 19425 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Total Company | 166573 | 155914 | 160660 |
| Average sales prices: |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Crude oil ($/Bbl) |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;North Dakota Bakken | $63.19 | $75.01 | $76.41 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;SCOOP | 63.74 | 74.92 | 76.82 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Permian Delaware | 65.82 | 76.39 | 76.21 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Total Company | 63.88 | 75.18 | 76.89 |
| &nbsp;&nbsp;&nbsp;&nbsp;Natural gas ($/Mcf) |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;North Dakota Bakken | $2.19 | $1.80 | $2.54 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;SCOOP | 3.45 | 2.76 | 2.93 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Permian Delaware | 1.58 | 1.54 | 2.53 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Total Company | 2.63 | 2.16 | 2.60 |
| Average costs per Boe: |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Production expenses ($/Boe) |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;North Dakota Bakken | $5.98 | $5.82 | $5.23 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;SCOOP | 1.81 | 1.79 | 1.50 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Permian Delaware | 5.20 | 5.41 | 5.72 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Total Company | 4.95 | 4.94 | 4.47 |
| &nbsp;&nbsp;&nbsp;&nbsp;Production and ad valorem taxes ($/Boe) | $3.03 | $3.57 | $3.76 |
| &nbsp;&nbsp;&nbsp;&nbsp;General and administrative expenses ($/Boe) | $1.68 | $1.69 | $1.74 |
| &nbsp;&nbsp;&nbsp;&nbsp;DD&A expense ($/Boe) | $16.07 | $15.93 | $14.11 |

---

The following table sets forth information regarding our average daily production by region for the fourth quarter of 2025:

---

| | | | |
|:---|:---|:---|:---|
|  | **Fourth Quarter 2025 Daily Production** | **Fourth Quarter 2025 Daily Production** | **Fourth Quarter 2025 Daily Production** |
|  | **Crude Oil<br>(Bbls per day)** | **Natural Gas<br>(Mcf per day)** | **Total<br>(Boe per day)** |
| Bakken | 128961 | 453376 | 204524 |
| Anadarko Basin | 34058 | 575445 | 129965 |
| Powder River Basin | 16734 | 52118 | 25420 |
| Permian Basin | 67628 | 257152 | 110487 |
| All other | 4605 | 32 | 4610 |
| Total | 251986 | 1338123 | 475006 |

---

------

[**<u>**Table of Contents**</u>**](#table_of_contents)

**Productive Wells**

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, 2025. One or more completions in the same well bore are counted as one well.

---

| | | | | | | |
|:---|:---|:---|:---|:---|:---|:---|
|  | **Crude Oil Wells** | **Crude Oil Wells** | **Natural Gas Wells** | **Natural Gas Wells** | **Total Wells** | **Total Wells** |
|  | **Gross** | **Net** | **Gross** | **Net** | **Gross** | **Net** |
| Bakken | 6136 | 2276 |  |  | 6136 | 2276 |
| Anadarko Basin | 1031 | 476 | 748 | 256 | 1779 | 732 |
| Powder River Basin | 749 | 509 | 12 | 9 | 761 | 518 |
| Permian Basin | 670 | 567 | 55 | 32 | 725 | 599 |
| All other | 265 | 252 | 19 | 1 | 284 | 253 |
| Total | 8851 | 4080 | 834 | 298 | 9685 | 4378 |

---

**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, and Anadarko 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.

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 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.

------

[**<u>**Table of Contents**</u>**](#table_of_contents)

**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 natural gas properties, minerals, 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 ability to acquire additional prospects and to find and develop reserves in the future will depend on our ability to evaluate and select suitable properties and to consummate transactions economically in a highly competitive environment. In addition, supply chain disruptions in recent years have led to shortages of certain materials and equipment and increased costs. As a result, the likelihood of experiencing competition and shortages of materials and services may be further increased. Finally, the impact of climate change activism, fuel conservation measures, governmental requirements for renewable energy resources, increasing demand for alternative forms of energy, and technological advances in energy generation devices may result in reduced demand for the crude oil and natural gas we produce.

**Regulation of the Crude Oil and Natural Gas Industry**

As of December 31, 2025, all of our operations were conducted onshore in the United States. In the first quarter of 2026, we expanded our operations internationally via the acquisition of assets in Argentina and will be subject to the regulatory environment in that country going forward. The crude oil and natural gas industry in both the United States and Argentina is subject to various types of regulation at the federal, state, and local levels. These laws, rules, regulations, policies, and interpretations affecting our industry have been and are pervasive, with the frequent imposition of new or increased requirements. Non-compliance can result in substantial penalties that 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, repealed, 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 are significant areas of regulation that may affect us in the areas in which we operate.

***Environmental, health, and safety regulation***

We are subject to stringent, complex, and overlapping federal, state, and local laws, rules and regulations governing environmental compliance, and occupational safety and health, as well as the discharge of materials into, and the protection of, the environment and natural resources. Environmental, health, and safety laws, rules and regulations may relate to, among other things:

&nbsp;&nbsp;&nbsp;&nbsp;•the discharge or other release of pollutants into surface water, groundwater and ambient air; including compliance with all applicable quality standards and effluent thresholds established by federal and provincial authorities;

&nbsp;&nbsp;&nbsp;&nbsp;•assessing the environmental impact of seismic acquisition, drilling, and construction activities for any type of facilities, or their expansion or improvement;

&nbsp;&nbsp;&nbsp;&nbsp;•the generation, handling, storage, transportation, treatment and final disposal of waste materials, including hazardous substances;

&nbsp;&nbsp;&nbsp;&nbsp;•the emission of certain gases, including methane and other greenhouse gases, into the atmosphere;

&nbsp;&nbsp;&nbsp;&nbsp;•the acquisition, maintenance and renewal of various permits, authorizations and concessions required to conduct exploration, water abstraction, drilling, production and abandonment operations;

&nbsp;&nbsp;&nbsp;&nbsp;•the monitoring and maintenance of facilities and infrastructure, including the integrity and safety of hydrocarbon storage tanks among others;

&nbsp;&nbsp;&nbsp;&nbsp;•the restriction of types, quantities and concentrations of various substances that can be released into the environment in connection with drilling, production and transportation activities;

&nbsp;&nbsp;&nbsp;&nbsp;•the limitation or prohibition of drilling activities on certain lands lying within wilderness, wetlands and other protected areas including areas containing endangered species of plants and animals;

&nbsp;&nbsp;&nbsp;&nbsp;•the requirement of remedial measures to mitigate pollution from former and ongoing operations, such as requirements to close pits, plug abandoned wells, and restore affected land on which operations have ceased;

&nbsp;&nbsp;&nbsp;&nbsp;•the imposition of substantial liabilities for pollution resulting from drilling and production operations including liability for collective environmental harm and joint liability among responsible parties;

&nbsp;&nbsp;&nbsp;&nbsp;•the development of emergency response and spill contingency plans; and

------

[**<u>**Table of Contents**</u>**](#table_of_contents)

&nbsp;&nbsp;&nbsp;&nbsp;•worker protection.

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. Any regulatory 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. 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 in the United States, or in the defense of the environment that could be affected in Argentina, and bring claims against operators for alleged violations of environmental laws. This risk is particularly relevant in Argentina, where collective rights and broad standing in environmental matters are expressly recognized. We have incurred and will continue to incur operating and capital expenditures, some of which may be material, to comply with environmental, health, and safety laws, rules, and regulations.

In Argentina, this regulatory framework is governed by environmental public order laws that establish, among other principles, prevention, precaution, strict liability for collective environmental damage, the obligation to remediate, and potential criminal liability in the event of contamination of natural resources.

***Other regulation of the oil and gas industry***

The Company's oil and gas operations are subject to various federal, state, and local laws and regulations that relate to matters including, among other things:

&nbsp;&nbsp;&nbsp;&nbsp;•location, drilling and casing of wells;

&nbsp;&nbsp;&nbsp;&nbsp;•hydraulic fracturing;

&nbsp;&nbsp;&nbsp;&nbsp;•well production operations;

&nbsp;&nbsp;&nbsp;&nbsp;•disposal of produced water;

&nbsp;&nbsp;&nbsp;&nbsp;•regulation of transportation and sale of crude oil, natural gas, and natural gas liquids;

&nbsp;&nbsp;&nbsp;&nbsp;•surface usage;

&nbsp;&nbsp;&nbsp;&nbsp;•calculation and disbursement of royalty payments and production taxes; and

&nbsp;&nbsp;&nbsp;&nbsp;•restoration of properties used for oil and gas operations.

Our operations in the United States also are subject to conservation regulations, including the regulation of the size of drilling and spacing units or proration units; the number of wells that may be drilled in a unit; the rate of production allowable from crude oil and natural gas wells; and the unitization or pooling of oil and gas properties. Some states allow the forced pooling or unitization of tracts to facilitate exploration and development, while other states rely on voluntary pooling of lands and leases. Such rules often impact the ultimate timing of our exploration and development plans. In addition, federal and state conservation laws generally limit the venting or flaring of natural gas. These regulations limit the amounts of oil and gas we can produce from our wells and the number of wells or the locations at which we can drill.

In addition, our operations in Argentina are subject to federal and provincial regulations that govern, among other things: obtaining and maintaining state concessions, authorizations, or other operating rights, including the submission of and compliance with development plans for the granted areas; maintaining active registration in oil company registries, which requires meeting certain economic conditions and financial ratios; the potential conditioning of hydrocarbon exports on the satisfaction of domestic market needs; the imposition of export duties on hydrocarbons; preferential regimes for acquiring local goods and services; limits on the venting and flaring of natural gas; and the terms for compensating landowners for surface use.

Argentina has previously imposed limitations on producers' ability to increase local prices to reflect higher domestic taxes, increased production costs, or fluctuations in international commodity prices and exchange rates. Thus, the possibility that such measures could be enacted in the future cannot be ruled out.

------

[**<u>**Table of Contents**</u>**](#table_of_contents)

Certain of our leases in the United States are granted or approved by the federal 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 detailed federal regulations and orders that regulate, among other matters, drilling and operations on lands covered by these leases and calculation and disbursement of royalty payments to the federal government, tribes or tribal members. Moreover, the permitting process for oil and gas activities on federal and Indian lands can sometimes be subject to delay, including as a result of challenges 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 U.S. federal government has, from time to time, evaluated and, in some cases, promulgated new rules and regulations regarding competitive lease bidding, venting and flaring, oil and gas measurement and royalty payment obligations for production from federal lands.

For additional information on the Company's regulatory risks, see *Part 1, Item 1A. Risk Factors—Legal and Regulatory Risks* of this report.

**Human Capital**

***Employees and Labor Relations***

As of December 31, 2025, we employed 1,378 people, all of which were employed in the United States, with 789 employees being located at our corporate headquarters in Oklahoma City, Oklahoma and 589 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.

***Compensation***

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 owners 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 owners by making annual long-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***

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.

We encourage each of our employees to be a proactive participant in ensuring the safety of all of the Company's personnel. We've established programs to recognize and reward 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.

***Training and Development***

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 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 instance, employees at our corporate headquarters have

------

[**<u>**Table of Contents**</u>**](#table_of_contents)

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, and smoking cessation programs to encourage total body wellness.

***Diversity and Inclusion***

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, which provides policies and guidance on non-discrimination, anti-harassment, and equal employment opportunities.

**Company Contact Information**

Our corporate internet website is *www.clr.com.* Through the "Stakeholders" section of our website, we make available free of charge reports filed with or furnished to the SEC. 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 with the SEC as required by our senior note indentures. The SEC maintains an internet website that contains reports 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.

------

[**<u>**Table of Contents**</u>**](#table_of_contents)

**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.*

**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.

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:

&nbsp;&nbsp;&nbsp;&nbsp;•worldwide, domestic, and regional economic conditions impacting the supply of, and demand for, crude oil, natural gas, and natural gas liquids;

&nbsp;&nbsp;&nbsp;&nbsp;•the actions of the Organization of Petroleum Exporting Countries ("OPEC") and other petroleum producing nations;

&nbsp;&nbsp;&nbsp;&nbsp;•the nature, extent, and impact of domestic and foreign governmental laws, regulations, and taxation, including environmental laws as well as regulations governing the imposition of trade restrictions and foreign and domestic tariffs;

&nbsp;&nbsp;&nbsp;&nbsp;•executive, regulatory or legislative actions by Congress, the Presidential Office, states, or the governments of foreign countries in which we operate;

&nbsp;&nbsp;&nbsp;&nbsp;•geopolitical events and conditions, including political uncertainty in the United States or Argentina, or foreign regime changes that impact government energy policies;

&nbsp;&nbsp;&nbsp;&nbsp;•the level of global, national, and regional crude oil and natural gas exploration and production activities;

&nbsp;&nbsp;&nbsp;&nbsp;•the level of global, national, and regional crude oil and natural gas inventories, which may be impacted by economic sanctions applied to certain producing nations;

&nbsp;&nbsp;&nbsp;&nbsp;•the level and effect of speculative trading in commodity futures markets;

&nbsp;&nbsp;&nbsp;&nbsp;•the relative strength of the United States dollar compared to foreign currencies and foreign currency exchange rates relative to the United States dollar;

&nbsp;&nbsp;&nbsp;&nbsp;•the price and quantity of imports of foreign crude oil;

&nbsp;&nbsp;&nbsp;&nbsp;•the price and quantity of exports of crude oil or liquefied natural gas from the United States;

&nbsp;&nbsp;&nbsp;&nbsp;•military and political conditions in, or affecting other, crude oil-producing and natural gas-producing nations, including the continuation of, or any increase in the severity of, conflicts in Ukraine, the Middle East and the potential for conflict in South America;

&nbsp;&nbsp;&nbsp;&nbsp;•localized supply and demand fundamentals;

&nbsp;&nbsp;&nbsp;&nbsp;•the cost and availability, proximity and capacity of transportation, processing, storage and refining facilities for various quantities and grades of crude oil, natural gas, and natural gas liquids;

&nbsp;&nbsp;&nbsp;&nbsp;•adverse climatic conditions, natural disasters, and national and global health epidemics and concerns;

&nbsp;&nbsp;&nbsp;&nbsp;•technological advances affecting energy production and consumption;

&nbsp;&nbsp;&nbsp;&nbsp;•the effect of worldwide energy conservation and greenhouse gas emission limitations or other environmental protection efforts;

&nbsp;&nbsp;&nbsp;&nbsp;•the impact arising from increasing attention to environmental, social, and governance ("ESG") matters; and

&nbsp;&nbsp;&nbsp;&nbsp;•the price and availability of alternative fuels or other energy sources.

Sustained material declines in commodity prices reduce cash flows available for capital expenditures, repayment of indebtedness and other corporate purposes; may limit our ability to borrow money or raise additional capital; and may reduce our proved reserves and the amount of crude oil and natural gas we can economically produce.

------

[**<u>**Table of Contents**</u>**](#table_of_contents)

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 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 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, including the potential impact of military action or civil unrest in Venezuela, 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.

***Drilling for and producing crude oil and natural gas are high risk activities with many uncertainties that could adversely affect our business, financial condition or results of operations. We may not be insured for, or our insurance may be inadequate to protect us against, these risks.*** 

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.

------

[**<u>**Table of Contents**</u>**](#table_of_contents)

Further, many factors may occur that cause us to curtail, delay or cancel scheduled drilling and completion projects, including but not limited to:

&nbsp;&nbsp;&nbsp;&nbsp;•abnormal pressure or irregularities in geological formations;

&nbsp;&nbsp;&nbsp;&nbsp;•shortages of or delays in obtaining equipment or qualified personnel;

&nbsp;&nbsp;&nbsp;&nbsp;•shortages of or delays in obtaining components used in fracture stimulation processes such as water and proppants;

&nbsp;&nbsp;&nbsp;&nbsp;•delays associated with suspending our operations to accommodate nearby drilling or completion operations being conducted by other operators;

&nbsp;&nbsp;&nbsp;&nbsp;•mechanical difficulties, fires, explosions, equipment failures or accidents, including ruptures of pipelines or storage facilities, or train derailments;

&nbsp;&nbsp;&nbsp;&nbsp;•restrictions on the use of underground injection wells for disposing of waste water from oil and gas activities;

&nbsp;&nbsp;&nbsp;&nbsp;•political events, public protests, civil disturbances, terrorist acts or cybersecurity attacks;

&nbsp;&nbsp;&nbsp;&nbsp;•decreases in, or extended periods of low, crude oil and natural gas prices;

&nbsp;&nbsp;&nbsp;&nbsp;•title issues or issues with concessions granted by governments in foreign countries where we have operations;

&nbsp;&nbsp;&nbsp;&nbsp;•environmental hazards, such as uncontrollable flows of crude oil, natural gas, brine, well fluids, hydraulic fracturing fluids, toxic gas or other pollutants into the environment, including groundwater and shoreline contamination;

&nbsp;&nbsp;&nbsp;&nbsp;•adverse climatic conditions and natural disasters;

&nbsp;&nbsp;&nbsp;&nbsp;•spillage or mishandling of crude oil, natural gas, brine, well fluids, hydraulic fracturing fluids, toxic gas or other pollutants by us or by third party service providers;

&nbsp;&nbsp;&nbsp;&nbsp;•limitations in infrastructure, including transportation, processing, refining and exportation capacity, or markets for crude oil and natural gas; and

&nbsp;&nbsp;&nbsp;&nbsp;•delays imposed by or resulting from compliance with regulatory requirements including permitting.

Any of the above risks could adversely affect our ability to conduct operations or result in substantial losses to us as a result of:

&nbsp;&nbsp;&nbsp;&nbsp;•injury or loss of life;

&nbsp;&nbsp;&nbsp;&nbsp;•damage to or destruction of property, natural resources and equipment;

&nbsp;&nbsp;&nbsp;&nbsp;•pollution and other environmental damage;

&nbsp;&nbsp;&nbsp;&nbsp;•regulatory investigations and penalties;

&nbsp;&nbsp;&nbsp;&nbsp;•suspension of our operations;

&nbsp;&nbsp;&nbsp;&nbsp;•repair and remediation costs; and

&nbsp;&nbsp;&nbsp;&nbsp;•litigation.

We are not insured against all risks associated with our business. We may elect to not obtain insurance if we believe the cost of available insurance is excessive relative to the risks presented or for other reasons. In addition, pollution and environmental risks are generally not fully insurable.

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.

------

[**<u>**Table of Contents**</u>**](#table_of_contents)

***Reserve estimates depend on many assumptions that may turn out to be inaccurate. Any material inaccuracies in our reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves. The Company'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 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 as of December 31, 2025.

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.

Actual future production, crude oil and natural gas sales prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable crude oil and natural gas reserves will vary and could vary significantly from our estimates. Any significant variance could materially affect the estimated quantities and value of our reserves, which in turn could have an adverse effect on the value of our assets. In addition, we may remove or adjust estimates of proved reserves, potentially in material amounts, to reflect production history, results of exploration and development activities, changes in business strategies, prevailing crude oil and natural gas prices and other factors, some of which are beyond our control.

In addition, the development of our proved undeveloped reserves may take longer than anticipated and may not be ultimately developed or produced. At December 31, 2025, approximately 43% of our total estimated proved reserves (by volume) were undeveloped. Recovery of undeveloped reserves requires significant capital expenditures and successful drilling operations. Our reserve estimates assume we can and will make these expenditures and conduct these operations successfully. These assumptions may not prove to be accurate. Our reserve report at December 31, 2025 includes estimates of total future development costs over the next five years associated with our proved undeveloped reserves of approximately $8.6 billion. We cannot be certain the estimated costs of the development of these reserves are accurate, development will occur as scheduled, or the results of such development will be as estimated. If we choose not to spend the capital to develop these reserves, or if we are not otherwise able to successfully develop these reserves as a result of our inability to fund necessary capital expenditures or otherwise, we may be required to remove the associated volumes from our reported proved reserves. Proved undeveloped reserves generally must be drilled within five years from the date of initial booking under SEC reserve rules. Changes in the timing of development plans that impact our ability to develop such reserves in the required time frame have resulted, and may in the future result, in fluctuations in reserves between periods as reserves booked in one period may need to be removed in a subsequent period.

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 33% of our total net undeveloped acreage at December 31, 2025.

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

------

[**<u>**Table of Contents**</u>**](#table_of_contents)

unavailability of capacity on these systems and facilities could result in the shut-in of producing wells, the delay or discontinuance of development plans for properties, or higher operational costs associated with air quality compliance controls. Although we have some contractual control over the transportation of our products, changes in these business relationships or failure to obtain such services on acceptable terms could adversely affect our operations. If our production becomes shut-in for any of these or other reasons, we will be unable to realize revenue from those wells until other arrangements are made for the sale or delivery of our products and acreage lease terminations could result if production is shut-in for a prolonged period.

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, cybersecurity attacks, adverse climatic events, natural disasters, seismic events, health epidemics and concerns, changes in tax and energy policies or tariffs, federal, state and international regulatory developments, including such developments in foreign countries where we have operations, geopolitical conflicts, 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 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 primarily using transportation facilities and equipment owned and operated by third parties. From time to time we may sell our operated crude oil production at market centers 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.

***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 monitor and adjust our capital spending plans upward or downward depending on market conditions. Our 2026 capital budget, based on our current expectations of commodity prices, foreign currency exchange rates, 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:

&nbsp;&nbsp;&nbsp;&nbsp;•the prices at which crude oil and natural gas are sold;

&nbsp;&nbsp;&nbsp;&nbsp;•the volume of our proved reserves;

&nbsp;&nbsp;&nbsp;&nbsp;•the volume of crude oil and natural gas we are able to produce and sell from existing wells; and

&nbsp;&nbsp;&nbsp;&nbsp;•our ability to acquire, locate and produce new reserves;

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 seek financing in banking or debt capital markets to fund our operations.

We have a revolving credit facility with lender commitments totaling $1.80 billion that matures in October 2029, which date may be extended for up to two additional one-year periods subject to lender consent. 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 competitive pressures, or refinance debt

------

[**<u>**Table of Contents**</u>**](#table_of_contents)

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 may be 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. Any of these factors may cause costs to rise 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, 2025, non-operated properties represented 10% of our estimated proved developed reserves, 4% of our estimated proved undeveloped reserves, and 7% 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 marketing of oil and gas production, compliance with environmental, occupational safety and health and other regulations, or the amount of expenditures required to fund the development and operation of such properties. Moreover, we are dependent on other working interest owners on these projects to fund their contractual share of capital and operating expenditures. These limitations and our dependence on the operators and other working interest owners for these projects could cause us to incur unexpected future costs and could have a material adverse effect on our business, financial condition, results of operations and cash flows.

***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:

&nbsp;&nbsp;&nbsp;&nbsp;•reservoir modeling and evaluation of recoverable reserves;

&nbsp;&nbsp;&nbsp;&nbsp;•future crude oil and natural gas prices and location and quality differentials;

&nbsp;&nbsp;&nbsp;&nbsp;•the quality of the title or the concession granted with respect to acquired properties;

&nbsp;&nbsp;&nbsp;&nbsp;•the ability to access future drilling locations;

&nbsp;&nbsp;&nbsp;&nbsp;•availability and cost of gathering, processing, and transportation facilities;

&nbsp;&nbsp;&nbsp;&nbsp;•availability and cost of drilling and completion equipment and of skilled personnel;

&nbsp;&nbsp;&nbsp;&nbsp;•future development and operating costs and potential environmental and other liabilities;

&nbsp;&nbsp;&nbsp;&nbsp;•regulatory, permitting and similar matters; and

&nbsp;&nbsp;&nbsp;&nbsp;•with respect to foreign operations, the long-term stability of the government, legal and regulatory regimes within a given country.

------

[**<u>**Table of Contents**</u>**](#table_of_contents)

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 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:

&nbsp;&nbsp;&nbsp;&nbsp;•diversion of our management's attention to evaluating, negotiating and integrating significant acquisitions and strategic transactions;

&nbsp;&nbsp;&nbsp;&nbsp;•operating a larger organization in new geographic areas;

&nbsp;&nbsp;&nbsp;&nbsp;•the challenge and cost of integrating acquired assets and operations, including additional regulatory programs, with our preexisting assets and operations while carrying on our ongoing business; and

&nbsp;&nbsp;&nbsp;&nbsp;•the failure to realize the full benefit that we expect in estimated proved reserves, production volume, cost savings from operating synergies or other benefits anticipated from an acquisition, or to realize these benefits within the expected time frame.

As a result of our strategy of assessing and executing on accretive acquisitions, 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 our acquisitions will complement our business strategies by delivering enhanced cash flows and corporate returns, 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 closing. The occurrence of any of the matters described above could have an adverse impact on our business, financial condition, results of operations and cash flows.

***Volatility in the financial markets or in global economic conditions, including consequences resulting from domestic political uncertainty in the United States or countries where we operate, geopolitical events, international trade disputes and domestic and foreign 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 domestic and foreign 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, and certain manufactured production equipment, may cause disruption in the energy industry's supply chain, resulting in the delay or cessation of drilling and completion efforts or the postponement or cancellation of new pipeline transportation projects, 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.

------

[**<u>**Table of Contents**</u>**](#table_of_contents)

***A cybersecurity incident or events impacting our operational systems or other digital technology 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 artificial intelligence (AI), 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. The use of AI and machine-learning technologies by us and our business associates presents emerging risks that could adversely affect our business, financial condition, results of operations, and reputation. As with many technological innovations, there are significant risks and challenges involved in deploying AI and machine-learning technologies and there can be no assurance that the usage of such technologies will always enhance our operations or be beneficial to our business, including our efficiency or profitability. These technologies are rapidly evolving and may not perform as intended in our environments or under field conditions, and can produce outputs that are inaccurate, biased, incomplete, untimely, or otherwise unreliable.

As dependence on digital technologies has increased, cybersecurity and data privacy incidents, including deliberate attacks or unintentional events, have also evolved and increased in frequency. Cybersecurity attacks are becoming more sophisticated and advancements in AI may also heighten our exposure to cybersecurity-related threats as malicious actors may use generative AI to improve or expand cybersecurity attack techniques and capabilities. Our technologies, systems, networks, and those of our business associates have been and continue to be the target of cybersecurity attacks that 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 AI), ransomware attacks, attempts to gain unauthorized access to data, and other information security breaches, and 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 cybersecurity attacks on software vendors utilized by the Company. In response to those incidents, we deployed our cybersecurity incidence response protocols and took steps to contain and remediate potential vulnerabilities. As 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 cybersecurity attack or other data privacy incident 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, 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 cybersecurity incidents such as reconnaissance of our systems and those of our business associates, may remain undetected for an extended period, which could result in significant consequences. We do not maintain specialized insurance for possible liability resulting from cybersecurity attacks due to lack of coverage for what we consider sensitive and proprietary data.

While the Company maintains 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. No security measure is infallible.

As of the date of this report, we do not believe that the Company has experienced any material losses relating to cybersecurity 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 cybersecurity threats continue to evolve, we may be required to expend significant additional resources to modify or enhance our protective measures or to investigate and remediate any information security vulnerabilities. Additionally, the growth of cybersecurity attacks and emerging digital technologies has resulted in evolving legal and compliance matters which may impose significant costs that may increase over time.

------

[**<u>**Table of Contents**</u>**](#table_of_contents)

***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.

***Severe weather events and natural disasters could have a material adverse effect on our business, financial condition, results of operations and cash flows.*** 

Severe weather events and natural disasters such as hurricanes, tornadoes, seismic events, floods, blizzards, extreme cold, drought, fires, 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' operations, which could have a material adverse effect on our business. 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 we consider these factors in our disaster preparedness and response and business continuity planning, we may not consider or prepare for every eventuality in such planning.

**Financial Risks**

***Our revolving credit facility and indentures for our senior notes contain certain covenants and restrictions, the violation of which could adversely affect our business, financial condition and results of operations.***

Our revolving credit facility contains restrictive covenants with which we must comply, including covenants that 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 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. Debt* for a discussion of how this ratio is calculated pursuant to our credit agreement. At December 31, 2025, we had $1.8 billion of available borrowing capacity with no outstanding borrowings under our credit facility and our consolidated net debt to total capitalization ratio, as defined, was 0.18.

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 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 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 ($1.02 billion in receivables at December 31, 2025) and our joint interest and other receivables $394.6 million at December 31, 2025). 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.

Additionally, we rely on field service companies and midstream companies for services associated with the drilling and completion of wells and for certain midstream services. A prolonged worsening of commodity prices may result in a material adverse impact on the liquidity and financial position of the parties with whom we do business, resulting in delays in payment of, or non-payment of,

------

[**<u>**Table of Contents**</u>**](#table_of_contents)

amounts owed to us, delays in operations, loss of access to equipment and facilities and similar impacts. These events could have an adverse impact on our business, financial condition, results of operations and cash flows.

**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.***

Our crude oil and natural gas exploration and production operations are subject to stringent federal, state, local and foreign government 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 summary of certain significant environmental and occupational safety and health legal requirements that govern us. 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; 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. 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, repealed, or reinterpreted, we are unable to predict the future cost or impact of complying with such laws, rules and regulations.

***We are subject to certain complex federal, state, local and foreign government 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, local and foreign government laws and regulations in areas other than environmental protection and occupational safety and health, including with respect to production, sales, cash transfers and distributions, and transport of crude oil, NGLs and natural gas, and employees and labor relations.

Failure to comply with 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 priorities could result in the imposition of new laws or regulations that adversely impact us or our industry. Any such changes could increase our operating costs, delay our operations or otherwise alter the way we conduct our business, which could have a material adverse effect on our financial condition, results of operations and cash flows.

***We operate assets outside of the United States, which exposes us to different legal and regulatory requirements and additional risk.***

Beginning in the first quarter of 2026, a portion of our assets are now located in Argentina. Our foreign operations are subject to various risks that could have a material adverse effect on our business, results of operations and financial condition, including political and economic instability from civil unrest; labor strikes; war and other armed conflict; inflation; currency fluctuations, devaluation and conversion restrictions or other factors. Any deterioration of social, political, labor or economic conditions, or affecting a customer with whom we do business, as well as difficulties in staffing, obtaining necessary equipment and supplies and managing foreign operations, may adversely affect our operations or financial results. We are also exposed to the risk of foreign and domestic governmental actions that may: impose additional costs on us; delay permits or otherwise impede our operations; limit or disrupt markets for our operations, restrict payments or limit the movement of funds; impose sanctions on or otherwise restrict our ability to conduct business with certain customers or persons or in certain countries; or result in the deprivation of contact rights. Our operations outside the United States may also be affected by changes in trade protection laws, policies and measures, and other regulatory requirements affecting trade and investment, including the Foreign Corrupt Practices Act and foreign laws prohibiting corrupt payments, as well as travel restrictions and import and export regulations.

------

[**<u>**Table of Contents**</u>**](#table_of_contents)

***Changes in tax laws or tax rulings could materially affect our financial position, results of operations, and cash flows.***

Rules and regulations governing U.S. federal, state, Argentine, and local income taxation are continually under review and subject to change. It cannot be predicted if changes to current U.S. or Argentine tax laws and regulations will be introduced as legislation or, if introduced, later enacted and, if enacted, what form such enacted legislation would take. While certain changes to tax laws and regulations may negatively impact our business, certain changes may be beneficial.

***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. One or more of these developments could have an adverse effect on our assets and operations.

***Increased attention to environmental, social, and corporate governance matters may impact our business.***

Companies across all industries are facing 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 or adequately (whether or not such perception is valid) to pursue, implement, or make progress against 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, could be materially and adversely affected. Attention to climate change, 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 ability to recruit necessary talent, and our access to debt capital markets.

Institutional lenders who provide financing for traditional energy companies may become more attentive to lending practices that favor power sources such as wind and solar and some of them may elect not to provide funding for traditional energy companies or impose certain ESG-related targets or goals as a condition to funding. While we cannot predict what polices may result from these developments, such efforts could make it more difficult for traditional companies to secure funding as well as negatively affect the cost of, and terms for, financings to fund growth projects or other aspects of our business.

------

[**<u>**Table of Contents**</u>**](#table_of_contents)

**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 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. Our CISO has received certifications relating to information security, security leadership, and forensics from the Global Information Assurance organization.

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.

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 independent 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 Executive Chairman; President and Chief Executive Officer; (both of whom are also members of the Company's Board of Directors); Chief Operating Officer; Chief Financial Officer and Executive Vice President of Strategic Planning; Executive Vice President, General Counsel and Chief Administrative Officer; CIO; and the Director of Corporate Security. 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.

------

[**<u>**Table of Contents**</u>**](#table_of_contents)

In addition, the CISO periodically briefs the Company's Audit Committee regarding cybersecurity matters at a regularly scheduled committee meeting and these briefings cover the same types of information as is presented to the Cybersecurity Executive Committee. The Audit Committee is composed of the two members of the Board of Directors who are also members of the Cybersecurity Executive Committee.

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 or events impacting our operational systems or other digital technology 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 our 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 adverse effect on our financial condition, results of operations or cash flows.

**Item 4. Mine Safety Disclosures**

Not applicable.

------

[**<u>**Table of Contents**</u>**](#table_of_contents)

**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 shares outstanding at the time of this filing.

The Company has no dividend policy and currently has no plans to pay cash dividends in the future year.

**Item 6. Reserved**

------

[**<u>**Table of Contents**</u>**](#table_of_contents)

**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 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. As of December 31, 2025, all of our operations were conducted onshore in the United States. In the first quarter of 2026, we expanded our operations internationally via the acquisition of assets within the Vaca Muerta shale play in Argentina's Neuquén Basin. At the time of this filing, our 2026 activities in Argentina have no production or revenues and represent an immaterial portion of our consolidated assets. 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. As discussed in *Part II. Item 8. Notes to Consolidated Financial Statements—Note 1. Organization and Summary of Significant Accounting Policies—Voluntary Filer,* effective November 22, 2022 Continental Resources, Inc. became a privately held corporation and has no publicly available common shares outstanding.

**Financial and Operating Metrics**

Commodity prices have remained volatile due to various factors, some of which include global supply and demand, global inventory levels, and regional conflicts. Average NYMEX crude oil prices per barrel for the years ended December 31, 2025, 2024, and 2023 were $65.39, $76.63, and $77.58, respectively. Average NYMEX natural gas prices per MMBtu for the years ended December 31, 2025, 2024, and 2023 were $3.52, $2.19, and $2.53, respectively. The following table contains financial and operating metrics for the periods presented. Average sales prices exclude any effect of derivative transactions. Per-unit expenses have been calculated using sales volumes.

---

| | | | |
|:---|:---|:---|:---|
|  | **Year ended December 31,** | **Year ended December 31,** | **Year ended December 31,** |
|  | **2025** | **2024** | **2023** |
| Average daily production: |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Crude oil (Bbl per day) | 247019 | 229889 | 232083 |
| &nbsp;&nbsp;&nbsp;&nbsp;Natural gas (Mcf per day) (1) | 1256076 | 1176638 | 1248488 |
| &nbsp;&nbsp;&nbsp;&nbsp;Crude oil equivalents (Boe per day) | 456365 | 425995 | 440164 |
| Average sales prices: |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Crude oil ($/Bbl) | $63.88 | $75.18 | $76.89 |
| &nbsp;&nbsp;&nbsp;&nbsp;Natural gas ($/Mcf) (1) | $2.63 | $2.16 | $2.60 |
| Production expenses ($/Boe) | $4.95 | $4.94 | $4.47 |
| Production and ad valorem taxes (% of net crude oil and natural gas sales) | 7.6% | 8.1% | 8.2% |
| DD&A ($/Boe) | $16.07 | $15.93 | $14.11 |
| Total general and administrative expenses ($/Boe) | $1.68 | $1.69 | $1.74 |

---

(1)Natural gas production volumes, sales volumes, and sales prices presented throughout management's discussion and analysis reflect the combined value for natural gas and natural gas liquids.

------

[**<u>**Table of Contents**</u>**](#table_of_contents)

**Results of Operations**

The following table presents selected financial and operating information for the periods presented.

---

| | | | |
|:---|:---|:---|:---|
|  | **Year Ended December 31,** | **Year Ended December 31,** | **Year Ended December 31,** |
| ***In thousands*** | **2025** | **2024** | **2023** |
| Crude oil, natural gas, and natural gas liquids sales | $6983581 | $7256685 | $7684263 |
| Gain (loss) on derivative instruments, net | 549378 | 27168 | 943768 |
| Crude oil and natural gas service operations | 160615 | 93776 | 103710 |
| Total revenues | 7693574 | 7377629 | 8731741 |
| Operating costs and expenses | (4830954) | (4623931) | (4419008) |
| Other expenses, net | (186083) | (265131) | (383786) |
| Income before income taxes | 2676537 | 2488567 | 3928947 |
| Provision for income taxes | (567891) | (471849) | (827630) |
| Income before equity in net loss of affiliate | 2108646 | 2016718 | 3101317 |
| Equity in net loss of affiliate | (18323) | (3653) | (3129) |
| Net income | 2090323 | 2013065 | 3098188 |
| Net income attributable to noncontrolling interests | 11882 | 1287 | 2361 |
| Net income attributable to Continental Resources | $2078441 | $2011778 | $3095827 |
| Production volumes: |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Crude oil (MBbl) | 90162 | 84139 | 84710 |
| &nbsp;&nbsp;&nbsp;&nbsp;Natural gas (MMcf) | 458468 | 430649 | 455698 |
| &nbsp;&nbsp;&nbsp;&nbsp;Crude oil equivalents (MBoe) | 166573 | 155914 | 160660 |
| Sales volumes: |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Crude oil (MBbl) | 90434 | 84167 | 84508 |
| &nbsp;&nbsp;&nbsp;&nbsp;Natural gas (MMcf) | 458468 | 430649 | 455698 |
| &nbsp;&nbsp;&nbsp;&nbsp;Crude oil equivalents (MBoe) | 166845 | 155942 | 160457 |

---

***Year ended December 31, 2025 compared to the year ended December 31, 2024*** 

Below is a discussion of changes in our results of operations for 2025 compared to 2024. A discussion of changes in our results of operations for 2024 compared to 2023 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, 2024 as filed with the SEC on February 24, 2025.

***Production***

The following table summarizes the changes in our average daily Boe production by major operating area for the periods presented.

---

| | | | | | | |
|:---|:---|:---|:---|:---|:---|:---|
|  | **Fourth Quarter** | **Fourth Quarter** | **Fourth Quarter** | **Year Ended December 31,** | **Year Ended December 31,** | **Year Ended December 31,** |
| ***Boe production per day*** | **2025** | **2024** | **% Change** | **2025** | **2024** | **% Change** |
| Bakken | 204524 | 189787 | 8% | 199425 | 194606 | 2% |
| Anadarko Basin | 129965 | 126068 | 3% | 128967 | 132558 | (3)% |
| Powder River Basin | 25420 | 27215 | (7)% | 26338 | 24979 | 5% |
| Permian Basin | 110487 | 74334 | 49% | 96813 | 68589 | 41% |
| All other | 4610 | 5061 | (9)% | 4822 | 5263 | (8)% |
| Total | 475006 | 422465 | 12% | 456365 | 425995 | 7% |

---

The following table summarizes the changes in our production by product for the periods presented.

---

| | | | | | | |
|:---|:---|:---|:---|:---|:---|:---|
|  | **Year Ended December 31,** | **Year Ended December 31,** | **Year Ended December 31,** | **Year Ended December 31,** |  | **Volume** |
|  | **2025** | **2025** | **2024** | **2024** | **Volume** | **percent** |
|  | **Volume** | **Percent** | **Volume** | **Percent** | **increase** | **increase** |
| Crude oil (MBbl) | 90162 | 54% | 84139 | 54% | 6023 | 7% |
| Natural gas (MMcf) | 458468 | 46% | 430649 | 46% | 27819 | 6% |
| Total (MBoe) | 166573 | 100% | 155914 | 100% | 10659 | 7% |

---

------

[**<u>**Table of Contents**</u>**](#table_of_contents)

The 7% increase in crude oil production and 6% increase in natural gas production in 2025 compared to 2024 were primarily driven by variation in the timing of new well completions between years and improvements in well productivity.

***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.

*Crude oil, natural gas, and natural gas liquids sales.* Sales for 2025 totaled $6.98 billion, a 4% decrease compared to sales of $7.26 billion for 2024 due to a decrease in crude oil sales prices, partially offset by increases in sales volumes and natural gas sales prices as discussed below.

Total sales volumes for 2025 increased 10,903 MBoe, or 7%, compared to 2024 primarily due to the previously described increases in crude oil and natural gas production volumes. For 2025, our crude oil sales volumes increased 7% and our natural gas sales volumes increased 6% compared to 2024.

Our crude oil sales prices averaged $63.88 per barrel for 2025, a decrease of 15% compared to $75.18 per barrel for 2024 due to a decrease in market prices resulting from changes in various macroeconomic conditions between periods. Our natural gas sales prices averaged $2.63 per Mcf for 2025, an increase of 22% compared to $2.16 per Mcf for 2024 due to an increase in market prices.

*Derivatives.* Changes in settled and future commodity prices in 2025 had a net favorable impact on the fair value of our derivatives, which resulted in positive revenue adjustments of $549.4 million for the year, representing $325.6 million of realized cash gains and $223.8 million of unsettled non-cash gains, compared to positive revenue adjustments totaling $27.2 million in 2024.

*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 $66.8 million, or 71%, from $93.8 million for 2024 to $160.6 million for 2025 primarily due to an increase in production volumes along with variation in the timing and magnitude of water handling projects compared to 2024.

***Operating Costs and Expenses***

*Production expenses*. Production expenses increased $55.4 million, or 7%, to $826.2 million for 2025 compared to $770.9 million for 2024 due to an increase in the number of producing wells from drilling and completion activities and higher workover-related activities aimed at enhancing production from producing properties. Production expenses on a per-Boe basis averaged $4.95 per Boe for 2025, consistent with $4.94 per Boe for 2024.

*Production and ad valorem taxes.* Production and ad valorem taxes decreased $50.3 million, or 9%, to $505.9 million for 2025 compared to $556.2 million for 2024 primarily due to a decrease in crude oil revenues. Our production taxes as a percentage of net sales averaged 7.6% for 2025 compared to 8.1% for 2024, the decrease of which resulted from changes in sales mix of crude oil and natural gas in our operating areas between periods.

*Transportation, gathering, processing, and compression.* These charges decreased $34.6 million, or 9%, to $332.7 million for 2025 compared to $367.2 million for 2024 due to changes in marketing terms and arrangements utilized between periods and changes in our working interest share of cost burdens in certain operating areas.

*Depreciation, depletion, amortization and accretion ("DD&A").* Total DD&A amounted to $2.68 billion for 2025, an increase of $198.4 million, or 8%, compared to $2.48 billion for 2024 primarily due to the previously described 7% increase in our total sales volumes. The following table shows the components of our DD&A on a unit of sales basis for the periods presented.

---

| | | |
|:---|:---|:---|
|  | **Year ended December 31,** | **Year ended December 31,** |
| ***$/Boe*** | **2025** | **2024** |
| Crude oil and natural gas properties | $15.36 | $15.26 |
| Other equipment | 0.56 | 0.53 |
| Asset retirement obligation accretion | 0.15 | 0.14 |
| Depreciation, depletion, amortization and accretion | $16.07 | $15.93 |

---

*Property impairments.* Property impairments increased $15.7 million to $58.9 million for 2025 compared to $43.2 million for 2024 due to higher impairments of unproved properties resulting from an increase in the amortization of undeveloped leasehold costs over the past year.

------

[**<u>**Table of Contents**</u>**](#table_of_contents)

*General and administrative ("G&A") expenses.* G&A expenses increased $16.7 million, or 6%, to $280.7 million for 2025 compared to $264.0 million for 2024. Total G&A expenses include charges for long-term incentive compensation awards of $76.9 million for 2025 compared to $83.7 million for 2024. This decrease was driven by changes in the remeasurement of outstanding award liabilities between periods. G&A expenses other than incentive compensation awards totaled $203.8 million for 2025, an increase of $23.5 million compared to $180.3 million for 2024 primarily due to the growth of our operations over the past year coupled with lower overhead and cost recoveries from joint interest owners compared to 2024.

The following table shows the components of G&A expenses on a unit of sales basis for the periods presented.

---

| | | |
|:---|:---|:---|
|  | **Year ended December 31,** | **Year ended December 31,** |
| ***$/Boe*** | **2025** | **2024** |
| General and administrative expenses | $1.22 | $1.15 |
| Long-term incentive compensation awards | 0.46 | 0.54 |
| Total general and administrative expenses | $1.68 | $1.69 |

---

*Interest expense.* Interest expense decreased $58.0 million, or 21%, to $217.8 million for 2025 compared to $275.7 million for 2024 due to a decrease in our annual weighted average outstanding debt balance from $5.8 billion in 2024 to $4.8 billion in 2025 driven by our debt reduction efforts throughout 2024 and 2025. Our outstanding debt totaled $4.8 billion at December 31, 2025.

*Income Taxes.* We provided for income taxes at a combined federal and state tax rate of 23.5% for both 2025 and 2024. We recorded income tax provisions of $567.9 million and $471.8 million for 2025 and 2024, respectively, which resulted in effective tax rates of 21.2% and 19.0%, respectively, after taking into account the application of statutory tax rates, permanent taxable differences, estimated tax 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 2025 and 2024.

**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.

At December 31, 2025, we had $1.8 billion of borrowing availability with no outstanding borrowings under our credit facility, along with $1.38 billion of cash on hand. Our credit facility, which is unsecured and has no borrowing base subject to redetermination, does not mature until October 2029. We have the option to extend the October 2029 maturity date by up to two additional one-year periods subject to lender consent.

The Company anticipates using a substantial majority of its current cash on hand to repay its senior notes maturing in November 2026 and to acquire additional operating assets.

Based on our planned capital spending, our forecasted cash flows, and projected levels of indebtedness, we expect to maintain compliance with the covenants under our credit facility 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 $222.6 million, or 5%, to $4.86 billion for 2025 compared to $4.64 billion for 2024. This increase was primarily driven by a $389.8 million decrease in cash payments for income taxes, a $64.3 million decrease in cash paid for interest, a $60 million decrease in cash payments for incentive compensation, a $50.3 million decrease in production and ad valorem taxes, and a $34.6 million decrease in transportation, gathering, processing and compression expenses. These improvements in operating cash flows were partially offset by a $273.1 million decrease in crude oil, natural gas, and NGL revenues, a $55.4 million increase in production expenses, and a $52.0 million decrease in realized cash settlements on matured commodity derivatives, along with changes in working capital items from period to period.

------

[**<u>**Table of Contents**</u>**](#table_of_contents)

***Cash flows used in investing activities***

Net cash used in investing activities totaled $3.47 billion for 2025 compared to $2.78 billion for 2024. Our investing cash flows for 2025 included $3.23 billion of exploration and development costs compared to $3.03 billion for 2024. In addition, proceeds from the sale of assets decreased $493.8 million for 2025 compared to 2024.

***Cash flows from financing activities***

Net cash used in financing activities for 2025 totaled $55.7 million, primarily consisting of $35.2 million of net repayments on outstanding debt and $19.7 million of net distributions to noncontrolling interests. Net cash used in financing activities for 2024 totaled $1.84 billion primarily due to $1.83 billion of net repayments on outstanding debt.

**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, and cash payments for income taxes 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 2026 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.

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.

*Credit facility*

We have an unsecured credit facility, maturing in October 2029, with aggregate lender commitments totaling $1.8 billion. We have the option to extend the October 2029 maturity date by up to two additional one-year periods subject to lender consent. The commitments are from a syndicate of 14 banks and financial institutions. We believe each member of the current syndicate has the capability to fund its commitment.

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.

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. 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, 2025 and expect to maintain compliance. At December 31, 2025, our consolidated net debt to total capitalization ratio was 0.18. 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.

------

[**<u>**Table of Contents**</u>**](#table_of_contents)

**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, 2025, 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 $4.8 billion at December 31, 2025, 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 $800 million of 2026 Notes due in November 2026, 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, 2025. We expect to fully redeem our 2026 Notes by the maturity date using available cash on hand. 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. Debt* in *Part II, Item 8. Notes to Consolidated Financial Statements*.

We were in compliance with our senior note covenants at December 31, 2025 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.

*Credit facility borrowings*

As of February 1, 2026, we continued to have no outstanding borrowings on our credit facility.

*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, 2025 under the arrangements amount to approximately $500 million. A portion of these future costs will be borne by other interest owners. See *Part II, Item 8. Notes to Consolidated Financial Statements—Note 13. Commitments and Contingencies* for additional information.

*Capital Expenditures*

For the year ended December 31, 2025, we invested $3.11 billion in our capital program excluding $193.2 million of unbudgeted acquisitions, excluding $10 million of mineral acquisitions attributable to Franco-Nevada, and excluding $124.6 million of capital costs associated with decreased accruals for capital expenditures as compared to December 31, 2024.

For 2026, our capital expenditures excluding acquisitions are forecasted to be approximately $2.5 billion.

Our 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, operational process improvements, the availability of drilling and completion rigs and other services and equipment, cost inflation, the impact of tariffs or trade restrictions, the availability of transportation, gathering 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 adjust our spending should commodity prices materially change from current levels. We expect to continue participating as a buyer of properties when and if we have the ability to increase our position in strategic plays at attractive terms.

*Stock Redemption Agreement*

See *Note 13. Commitments and Contingencies*—*Stock Redemption Agreement* in *Part II, Item 8. Notes to Consolidated Financial Statements.*

------

[**<u>**Table of Contents**</u>**](#table_of_contents)

*Delivery Commitments*

We have various natural gas volume delivery commitments that are related to our key 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, 2025, 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.

---

| | | | | |
|:---|:---|:---|:---|:---|
| Year Ending | Natural Gas | Natural Gas | Crude Oil | Crude Oil |
| December 31, | Bcf | Bcf | MMBo | MMBo |
| 2026 |  | 99 |  | 13 |
| 2027 |  | 77 |  | 3 |
| 2028 |  | 37 |  |  |
| 2029 |  | 17 |  |  |
| 2030 |  | 10 |  |  |
| 2031 |  | 8 |  |  |

---

**Senior note repurchases and redemptions**

In recent years we have redeemed or repurchased a portion of our outstanding senior notes. From time to time, we may execute additional redemptions or repurchases of our senior notes for cash in open market transactions, privately negotiated transactions, or otherwise. The timing and amount of any such redemptions or repurchases 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.

**Derivative Instruments**

The fair value of our derivative instruments at December 31, 2025 was a net asset of $381.3 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, 2025. 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, 2025. Between January 1, 2026 and February 14, 2026 we entered into additional derivative instruments as summarized below.

---

| | | | |
|:---|:---|:---|:---|
| ***Crude oil derivatives*** |  |  |  |
|  |  |  | **Weighted Average** |
| **Period and Type of Contract** | **Average Volumes Hedged** | **Average Volumes Hedged** | **Hedge Price ($/Bbl)** |
| February 2026 - December 2026 |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Fixed Swaps - WTI | 20000 | Bbls/day | $60.23 |
| January 2027 - December 2027 |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Fixed Swaps - WTI | 20000 | Bbls/day | $60.26 |

---

**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

------

[**<u>**Table of Contents**</u>**](#table_of_contents)

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*

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 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. 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.

Our DD&A calculations for oil and gas properties are performed on a field basis and revisions to proved reserves will not necessarily be applied ratably across all fields and may not be applied to some fields at all. Further, reserve revisions in significant fields may individually affect our DD&A rate. As a result, the impact on DD&A expense from revisions in reserves cannot be predicted with certainty and may result in changes in expense that are greater or less than the underlying changes in reserves.

*Revenue Recognition*

We derive substantially all of our revenues from the sale of crude oil, natural gas, and 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, 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 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, 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

------

[**<u>**Table of Contents**</u>**](#table_of_contents)

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 utilize derivative contracts to hedge against the variability in cash flows associated with the forecasted sale of future 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.

*Impairment of Assets*

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.

No impairments were recognized for our proved crude oil and natural gas properties for the year ended December 31, 2025 as estimated future cash flows were determined to be in excess of cost basis. Commodity price assumptions used for the year-end December 31, 2025 impairment calculations were based on publicly available average annual forward commodity strip prices through year-end 2030 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, 2025, the publicly available forward commodity strip prices for the year 2030 used in our fourth quarter impairment calculations averaged $60.85 per barrel for crude oil and $3.61 per Mcf for natural gas. 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.

Our equity method investment in Summit Carbon Solutions ("Summit") described in *Part II, Item 8. Notes to Consolidated Financial Statements—Note 18. Equity Investment* is reviewed for impairment whenever events or changes in circumstances indicate the carrying amount of the investment might not be recoverable. An impairment charge is recognized when a decline in value below the

------

[**<u>**Table of Contents**</u>**](#table_of_contents)

carrying amount is determined to be other than temporary. Our unit of account for evaluating impairment of equity method investments is the investment as a whole and we do not separately test the investee's underlying assets for impairment. Factors we consider in assessing whether a decline in value is other than temporary include the financial condition and future prospects for the investee, specific events that may influence the operations of the investee, and the intent and ability of investors to continue providing financial support to the investee, among others. Summit's carbon capture and sequestration project is in the design, permitting, and preliminary construction phases and has experienced permitting and regulatory delays that have impacted the scope and timing of the project's development. Our evaluation for the Summit investment is highly judgmental and may be subject to revision and impairment 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 a valuation allowance. We believe our deferred tax assets at December 31, 2025 will ultimately be realized. We will continue to evaluate both the positive and negative evidence on a quarterly basis in determining the need for a valuation allowance with respect to our deferred tax assets.

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.

**Legislative and Regulatory Developments**

The crude oil and natural gas industry is subject to various types of regulation at the federal, state and local levels that result in stringent and costly requirements for our business. See *Part I, Item 1. Business—Regulation of the Crude Oil and Natural Gas Industry* for a summary of significant laws and regulations that may affect us in the areas in which we operate. There is the potential for the revision or repeal of existing laws and regulations or the adoption of new legislation that could affect our industry.

------

[**<u>**Table of Contents**</u>**](#table_of_contents)

**Inflation**

Inflationary pressures experienced in recent years may persist or worsen in 2026. Some of the underlying factors impacting inflation may include, but are not limited to, global supply chain disruptions, the imposition of trade restrictions or other governmental actions related to tariffs or trade policies, shipping bottlenecks, labor market constraints, increased competition for goods and services, and side effects from monetary and fiscal policies. It is uncertain at this time to what extent ongoing changes in trade restrictions and tariffs will have on our business. Tariffs on foreign goods and services could result in reciprocal tariffs on U.S. goods and services, which could impact the demand for and price of crude oil, natural gas, and natural gas liquids and increase inflationary pressures on, or impact the availability of, certain supplies, equipment and materials that we use to conduct our business. If inflationary pressures persist or worsen, we may incur additional costs for equipment and materials and from service providers. Our budgeted expenditures include an estimate for the potential impact of cost inflation and increased costs resulting from tariffs and, despite inflationary pressures, we expect to continue generating significant amounts of free cash flow at current commodity price levels.

------

[**<u>**Table of Contents**</u>**](#table_of_contents)

**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, interest rate risk, and foreign currency exchange 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 liquids. Realized pricing is primarily driven by the prevailing worldwide price for crude oil and spot market prices applicable to our natural gas 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, 2025, and excluding any effect of our derivative instruments in place, our annual revenue would increase or decrease by approximately $920 million for each $10.00 per barrel change in crude oil prices at December 31, 2025 and $488 million for each $1.00 per Mcf change in natural gas prices at December 31, 2025.

To reduce price risk caused by market fluctuations in commodity prices, from time to time we economically hedge a portion of our anticipated 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, 2025 was a net asset of $381.3 million, which is comprised of a $206.7 million net asset associated with our crude oil derivatives and a $174.6 million net asset associated with our natural gas 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, 2025.

---

| | | |
|:---|:---|:---|
|  |  | **Hypothetical Fair Value** |
| ***In thousands*** | **Change in Forward Price** | **Asset (Liability)** |
| Crude Oil | -10% | $411763 |
| Crude Oil | +10% | $9061 |
| Natural Gas | -10% | $344441 |
| Natural Gas | +10% | $5342 |

---

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 ($1.0 billion in receivables at December 31, 2025) and our joint interest and other receivables ($394.6 million at December 31, 2025).

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 $30 million at December 31, 2025, 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 to variable-rate borrowings we may have outstanding from time to time on our credit facility. Such borrowings bear interest at market-based interest rates plus a margin based on the terms of the

------

[**<u>**Table of Contents**</u>**](#table_of_contents)

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 no variable rate borrowings outstanding on our credit facility at February 1, 2026.

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, 2025:

---

| | | | | | | | |
|:---|:---|:---|:---|:---|:---|:---|:---|
| ***In thousands*** | **2026** | **2027** | **2028** | **2029** | **2030** | **Thereafter** | **Total** |
| Fixed rate debt: |  |  |  |  |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Senior Notes: |  |  |  |  |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Principal amount (1) | $800000 | $— | $1000000 | $— | $— | $3000000 | $4800000 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Weighted-average interest rate | 2.3% |  | 4.4% |  |  | 4.8% | 4.2% |

---

(1)Amounts represent scheduled maturities and do not reflect any discount or premium at which the notes were issued or any debt issuance costs.

*Foreign Currency Exchange Risk*. We expect to be exposed to foreign currency exchange risk in the future associated with our emerging international operations in Argentina. We currently have no foreign currency derivative instruments in place to manage foreign currency risk. However, we may enter into such instruments in the future as our international operations increase in size and scope.

------

[**<u>**Table of Contents**</u>**](#table_of_contents)

**Item 8. Financial Statements and Supplementary Data**

**Index to Consolidated Financial Statements**

---

| | | |
|:---|:---|:---|
| [<u>Report of Independent Registered Public Accounting Firm</u>](#section46) | (PCAOB ID Number 248) | <u>40</u> |
| [<u>Consolidated Balance Sheets as of December 31, 2025 and 2024</u>](#consolidatedbalancesheets) | [<u>Consolidated Balance Sheets as of December 31, 2025 and 2024</u>](#consolidatedbalancesheets) | <u>42</u> |
| [<u>Consolidated Statements of Income for the Years Ended December 31, 2025, 2024 and 2023</u>](#consolstatementsofincome) | [<u>Consolidated Statements of Income for the Years Ended December 31, 2025, 2024 and 2023</u>](#consolstatementsofincome) | <u>43</u> |
| [<u>Consolidated Statements of Equity for the Years Ended December 31, 2025, 2024 and 2023</u>](#consolstatementsofequity) | [<u>Consolidated Statements of Equity for the Years Ended December 31, 2025, 2024 and 2023</u>](#consolstatementsofequity) | <u>44</u> |
| [<u>Consolidated Statements of Cash Flows for the Years Ended December 31, 2025, 2024 and 2023</u>](#consolsocf) | [<u>Consolidated Statements of Cash Flows for the Years Ended December 31, 2025, 2024 and 2023</u>](#consolsocf) | <u>45</u> |
| [<u>Notes to Consolidated Financial Statements</u>](#section52) |  | <u>46</u> |

---

------

[**<u>**Table of Contents**</u>**](#table_of_contents)

**REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM**

Board of Directors

Continental Resources, Inc.

***Opinion on the financial statements*** 

We have audited the accompanying consolidated balance sheets of Continental Resources, Inc. (an Oklahoma corporation) and subsidiaries (the "Company") as of December 31, 2025 and 2024, the related consolidated statements of income, equity, and cash flows for each of the three years in the period ended December 31, 2025, and the related notes (collectively referred to as the "consolidated financial statements"). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2025 and 2024, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2025, in conformity with accounting principles generally accepted in the United States of America.

***Basis for opinion*** 

These consolidated financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the Company's consolidated financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) ("PCAOB") and are required to be independent with respect to the Company in accordance with 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 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) relate 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 oil and gas 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 and proved and unproved crude oil and natural gas reserves to assess its proved crude oil and natural gas properties for impairment. To estimate the crude oil and natural gas reserves and future cash flows, management makes significant estimates and assumptions including forecasting the production decline rate of proved crude oil and natural gas properties and forecasting the timing and volume of production associated with the Company's development plan for proved undeveloped properties and unproved properties. In addition, the estimation of the crude oil and natural gas reserves is also impacted by management's judgments and estimates regarding the financial performance of wells associated with the crude oil and natural gas reserves to determine if wells are expected with reasonable certainty to be economical under the appropriate pricing assumptions required in the estimation of depletion expense and impairment assessments/measurements. We identified 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

------

[**<u>**Table of Contents**</u>**](#table_of_contents)

natural gas reserves for the assessment/measurement of impairment of proved crude oil and natural gas properties as a critical audit matter.

The principle consideration for our determination that 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 proved crude oil and natural gas properties is a critical audit matter is that relatively minor changes in certain highly subjective inputs and assumptions that are necessary to estimate the volumes of future cash flows of the Company's crude oil and natural gas reserves could have a significant impact on the measurement of depletion expense or the assessment/measurement of proved impairment expense of 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 of proved crude oil and natural gas properties, included the following, among others:

• We assessed the independence, objectivity, and professional qualifications of the Company's reservoir engineer specialists, made inquiries of these specialists (internal and external) regarding the process followed and judgments used to make significant estimates, including but not limited to crude oil and natural gas reserve volumes, decline rates, and economically recoverable crude oil and natural gas reserves and reviewed the reserve estimates prepared by the Company's specialists.

• To the extent key inputs and assumptions used to determine crude oil and natural gas reserve volumes and other cash flow inputs and assumptions are derived from the Company's accounting records, including, but not limited to: historical pricing differentials, operating costs, estimated capital costs, discount rates, and ownership interests, we tested management's process for determining the assumptions, including examining underlying support on a sample basis. Specifically, our audit procedures involved testing management's assumptions as follows:

&nbsp;&nbsp;&nbsp;&nbsp;◦We compared the estimated pricing differentials used in the reserve report to realized prices related to revenue transactions recorded in the current year and examined contractual support for the pricing differentials.

&nbsp;&nbsp;&nbsp;&nbsp;◦We evaluated the models used to estimate the operating costs at year end and compared to historical operating costs.

&nbsp;&nbsp;&nbsp;&nbsp;◦We compared the estimates of future capital expenditures in the reserve reports to management's forecasts and amounts expended for recently drilled and completed wells.

&nbsp;&nbsp;&nbsp;&nbsp;◦We evaluated the working and net revenue interests used in the reserve report by inspecting land and division order records.

&nbsp;&nbsp;&nbsp;&nbsp;◦We evaluated the Company's evidence supporting the amount of proved undeveloped properties reflected in the reserve report by examining historical conversion rates and support for the Company's ability to fund and intent to develop the proved undeveloped properties.

&nbsp;&nbsp;&nbsp;&nbsp;◦We applied analytical procedures to the reserve report by comparing to historical actual results and to the prior year reserve report.

&nbsp;&nbsp;&nbsp;&nbsp;◦We evaluated the reasonableness of the Company's classification of reserves as proved or unproved.

&nbsp;&nbsp;&nbsp;&nbsp;◦We evaluated the reasonableness of risk-adjustment factors applied to unproved crude oil and natural gas reserves that were taken into consideration to determine estimated future net cash flows used to evaluate impairment of proved crude oil and natural gas properties.

/s/ GRANT THORNTON LLP

We have served as the Company's auditor since 2004.

Oklahoma City, Oklahoma

February 23, 2026

------

[**<u>**Table of Contents**</u>**](#table_of_contents)

**Continental Resources, Inc. and Subsidiaries**

**Consolidated Balance Sheets**

---

| | | |
|:---|:---|:---|
|  | **December 31,** | **December 31,** |
| ***In thousands, except par values and share data*** | **2025** | **2024** |
| **Assets** |  |  |
| Current assets: |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Cash and cash equivalents | $1375861 | $39064 |
| &nbsp;&nbsp;&nbsp;&nbsp;Accounts receivable, net | 1406796 | 1553919 |
| &nbsp;&nbsp;&nbsp;&nbsp;Derivative assets | 324706 | 95227 |
| &nbsp;&nbsp;&nbsp;&nbsp;Inventories | 227407 | 184251 |
| &nbsp;&nbsp;&nbsp;&nbsp;Prepaid expenses and other | 98396 | 32648 |
| Total current assets | 3433166 | 1905109 |
| Net property and equipment, based on successful efforts method of accounting | 20656908 | 20037922 |
| Investment in unconsolidated affiliates | 261333 | 258359 |
| Operating lease right-of-use assets | 29891 | 20933 |
| Derivative assets, noncurrent | 61528 | 62426 |
| Other noncurrent assets | 79336 | 20832 |
| Total assets | $24522162 | $22305581 |
| **Liabilities and equity** |  |  |
| Current liabilities: |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Accounts payable trade | $700669 | $845160 |
| &nbsp;&nbsp;&nbsp;&nbsp;Revenues and royalties payable | 718631 | 682461 |
| &nbsp;&nbsp;&nbsp;&nbsp;Accrued liabilities and other | 317819 | 413036 |
| &nbsp;&nbsp;&nbsp;&nbsp;Current portion of incentive compensation liability | 82510 | 74494 |
| &nbsp;&nbsp;&nbsp;&nbsp;Current portion of income tax liabilities | 519 | 21659 |
| &nbsp;&nbsp;&nbsp;&nbsp;Current portion of operating lease liabilities | 10225 | 4046 |
| &nbsp;&nbsp;&nbsp;&nbsp;Current portion of long-term debt | 798609 | 2587 |
| Total current liabilities | 2628982 | 2043443 |
| Long-term debt, net of current portion | 3973437 | 4798860 |
| Other noncurrent liabilities: |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Deferred income tax liabilities, net | 3046707 | 2704069 |
| &nbsp;&nbsp;&nbsp;&nbsp;Incentive compensation liability, noncurrent | 19976 | 36468 |
| &nbsp;&nbsp;&nbsp;&nbsp;Asset retirement obligations, noncurrent | 505382 | 432495 |
| &nbsp;&nbsp;&nbsp;&nbsp;Derivative liabilities, noncurrent | 4905 | 143 |
| &nbsp;&nbsp;&nbsp;&nbsp;Operating lease liabilities, noncurrent | 18701 | 15823 |
| &nbsp;&nbsp;&nbsp;&nbsp;Other noncurrent liabilities | 29020 | 48783 |
| Total other noncurrent liabilities | 3624691 | 3237781 |
| Commitments and contingencies (Note 13) |  |  |
| Equity: |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Preferred stock, $0.01 par value: 25,000,000 shares authorized; no shares issued and outstanding |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Common stock (Note 16) | 2996 | 2996 |
| &nbsp;&nbsp;&nbsp;&nbsp;Retained earnings | 13940956 | 11862515 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Total shareholders' equity attributable to Continental Resources | 13943952 | 11865511 |
| &nbsp;&nbsp;&nbsp;&nbsp;Noncontrolling interests | 351100 | 359986 |
| Total equity | 14295052 | 12225497 |
| Total liabilities and equity | $24522162 | $22305581 |

---

*The accompanying notes are an integral part of these consolidated financial statements.*

------

[**<u>**Table of Contents**</u>**](#table_of_contents)

**Continental Resources, Inc. and Subsidiaries**

**Consolidated Statements of Income**

---

| | | | |
|:---|:---|:---|:---|
|  | **Year Ended December 31,** | **Year Ended December 31,** | **Year Ended December 31,** |
| ***In thousands*** | **2025** | **2024** | **2023** |
| Revenues: |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Crude oil, natural gas, and natural gas liquids sales | $6983581 | $7256685 | $7684263 |
| &nbsp;&nbsp;&nbsp;&nbsp;Gain on derivative instruments, net | 549378 | 27168 | 943768 |
| &nbsp;&nbsp;&nbsp;&nbsp;Crude oil and natural gas service operations | 160615 | 93776 | 103710 |
| Total revenues | 7693574 | 7377629 | 8731741 |
| Operating costs and expenses: |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Production expenses | 826240 | 770875 | 717478 |
| &nbsp;&nbsp;&nbsp;&nbsp;Production and ad valorem taxes | 505903 | 556174 | 603534 |
| &nbsp;&nbsp;&nbsp;&nbsp;Transportation, gathering, processing, and compression | 332675 | 367247 | 338217 |
| &nbsp;&nbsp;&nbsp;&nbsp;Exploration expenses | 19890 | 12369 | 16368 |
| &nbsp;&nbsp;&nbsp;&nbsp;Crude oil and natural gas service operations | 117265 | 88078 | 82392 |
| &nbsp;&nbsp;&nbsp;&nbsp;Depreciation, depletion, amortization and accretion | 2681843 | 2483444 | 2264334 |
| &nbsp;&nbsp;&nbsp;&nbsp;Property impairments | 58895 | 43199 | 66798 |
| &nbsp;&nbsp;&nbsp;&nbsp;General and administrative expenses | 280747 | 264029 | 279306 |
| &nbsp;&nbsp;&nbsp;&nbsp;Net loss on sale of assets and other | 7496 | 38516 | 50581 |
| Total operating costs and expenses | 4830954 | 4623931 | 4419008 |
| Income from operations | 2862620 | 2753698 | 4312733 |
| Other income (expense): |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Interest expense | (217774) | (275748) | (395765) |
| &nbsp;&nbsp;&nbsp;&nbsp;Loss on extinguishment of debt | (57) | (1600) |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Other | 31748 | 12217 | 11979 |
|  | (186083) | (265131) | (383786) |
| Income before income taxes | 2676537 | 2488567 | 3928947 |
| Provision for income taxes | (567891) | (471849) | (827630) |
| Income before equity in net loss of affiliate | 2108646 | 2016718 | 3101317 |
| Equity in net loss of affiliate | (18323) | (3653) | (3129) |
| Net income | 2090323 | 2013065 | 3098188 |
| Net income attributable to noncontrolling interests | 11882 | 1287 | 2361 |
| Net income attributable to Continental Resources | $2078441 | $2011778 | $3095827 |

---

*The accompanying notes are an integral part of these consolidated financial statements.*

------

[**<u>**Table of Contents**</u>**](#table_of_contents)

**Continental Resources, Inc. and Subsidiaries**

**Consolidated Statements of Equity**

---

| | | | | | | |
|:---|:---|:---|:---|:---|:---|:---|
|  | **Shareholders' equity attributable to Continental Resources** | **Shareholders' equity attributable to Continental Resources** | **Shareholders' equity attributable to Continental Resources** | **Shareholders' equity attributable to Continental Resources** |  |  |
| ***In thousands, except share data*** | **Shares<br>outstanding** | **Common<br>stock** | **Retained<br>earnings** | **Total** | **Noncontrolling<br>interests** | **Total equity** |
| Balance at December 31, 2022 | 299610267 | $2996 | $6754174 | $6757170 | $372438 | $7129608 |
| &nbsp;&nbsp;&nbsp;&nbsp;Net income |  |  | 3095827 | 3095827 | 2361 | 3098188 |
| &nbsp;&nbsp;&nbsp;&nbsp;Change in dividends payable |  |  | 686 | 686 |  | 686 |
| &nbsp;&nbsp;&nbsp;&nbsp;Contributions from noncontrolling interests |  |  |  |  | 10188 | 10188 |
| &nbsp;&nbsp;&nbsp;&nbsp;Distributions to noncontrolling interests |  |  |  |  | (28883) | (28883) |
| Balance at December 31, 2023 | 299610267 | $2996 | $9850687 | $9853683 | $356104 | $10209787 |
| &nbsp;&nbsp;&nbsp;&nbsp;Net income |  |  | 2011778 | 2011778 | 1287 | 2013065 |
| &nbsp;&nbsp;&nbsp;&nbsp;Change in dividends payable |  |  | 50 | 50 |  | 50 |
| &nbsp;&nbsp;&nbsp;&nbsp;Contributions from noncontrolling interests |  |  |  |  | 24459 | 24459 |
| &nbsp;&nbsp;&nbsp;&nbsp;Distributions to noncontrolling interests |  |  |  |  | (21864) | (21864) |
| Balance at December 31, 2024 | 299610267 | $2996 | $11862515 | $11865511 | $359986 | $12225497 |
| &nbsp;&nbsp;&nbsp;&nbsp;Net income |  |  | 2078441 | 2078441 | 11882 | 2090323 |
| &nbsp;&nbsp;&nbsp;&nbsp;Contributions from noncontrolling interests |  |  |  |  | 10596 | 10596 |
| &nbsp;&nbsp;&nbsp;&nbsp;Distributions to noncontrolling interests |  |  |  |  | (31364) | (31364) |
| Balance at December 31, 2025 | 299610267 | $2996 | $13940956 | $13943952 | $351100 | $14295052 |

---

*The accompanying notes are an integral part of these consolidated financial statements.*

------

[**<u>**Table of Contents**</u>**](#table_of_contents)

**Continental Resources, Inc. and Subsidiaries**

**Consolidated Statements of Cash Flows**

---

| | | | |
|:---|:---|:---|:---|
|  | **Year Ended December 31,** | **Year Ended December 31,** | **Year Ended December 31,** |
| ***In thousands*** | **2025** | **2024** | **2023** |
| **Cash flows from operating activities:** |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Net income | $2090323 | $2013065 | $3098188 |
| &nbsp;&nbsp;&nbsp;&nbsp;Adjustments to reconcile net income to cash provided by operating activities: |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Depreciation, depletion, amortization and accretion | 2677619 | 2485265 | 2265948 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Property impairments | 58895 | 43199 | 66798 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Non-cash (gain) loss on derivatives, net | (223819) | 350417 | (686598) |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Provision (benefit) for deferred income taxes | 342638 | (163214) | 328970 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Equity in net loss of affiliate | 18323 | 3653 | 3129 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Net loss on sale of assets and other | 3886 | 36791 | 50581 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Loss on extinguishment of debt | 57 | 1600 |  |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Other, net | 15569 | 56612 | 21594 |
| &nbsp;&nbsp;&nbsp;&nbsp;Changes in assets and liabilities: |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Accounts receivable | 146612 | (11468) | 222091 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Inventories | (48836) | 5589 | (17600) |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Other current assets | (68896) | 623 | (6118) |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Accounts payable trade | (33667) | 2622 | (38740) |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Revenues and royalties payable | 35632 | (85351) | (111738) |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Accrued liabilities and other | (101211) | 54698 | 2940 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Incentive compensation liability | (8476) | (61329) | (53429) |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Current income taxes liability | (21140) | (62897) | (67593) |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Other noncurrent assets and liabilities | (22088) | (31044) | (17436) |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Net cash provided by operating activities | 4861421 | 4638831 | 5060987 |
| **Cash flows from investing activities:** |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Exploration and development | (3227878) | (3030955) | (3550502) |
| &nbsp;&nbsp;&nbsp;&nbsp;Purchase of producing crude oil and natural gas properties | (108739) | (8557) | (161408) |
| &nbsp;&nbsp;&nbsp;&nbsp;Purchase of other property and equipment | (163251) | (268437) | (205356) |
| &nbsp;&nbsp;&nbsp;&nbsp;Proceeds from sale of assets | 52277 | 546109 | 390034 |
| &nbsp;&nbsp;&nbsp;&nbsp;Contributions to unconsolidated affiliates | (21297) | (21527) | (33862) |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Net cash used in investing activities | (3468888) | (2783367) | (3561094) |
| **Cash flows from financing activities:** |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Credit facility borrowings | 440000 | 3932000 | 4792000 |
| &nbsp;&nbsp;&nbsp;&nbsp;Repayment of credit facility | (460000) | (4122000) | (5742000) |
| &nbsp;&nbsp;&nbsp;&nbsp;Redemption and repurchase of Senior Notes |  | (893126) | (636000) |
| &nbsp;&nbsp;&nbsp;&nbsp;Repayment of other debt | (15220) | (752495) | (2410) |
| &nbsp;&nbsp;&nbsp;&nbsp;Debt issuance costs | (140) | (5359) | (242) |
| &nbsp;&nbsp;&nbsp;&nbsp;Contributions from noncontrolling interests | 11335 | 22953 | 10580 |
| &nbsp;&nbsp;&nbsp;&nbsp;Distributions to noncontrolling interests | (31083) | (22428) | (31156) |
| &nbsp;&nbsp;&nbsp;&nbsp;Dividends paid on common stock | (628) | (2342) | (2056) |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Net cash used in financing activities | (55736) | (1842797) | (1611284) |
| Net change in cash and cash equivalents | 1336797 | 12667 | (111391) |
| Cash and cash equivalents at beginning of period | 39064 | 26397 | 137788 |
| Cash and cash equivalents at end of period | $1375861 | $39064 | $26397 |

---

*The accompanying notes are an integral part of these consolidated financial statements.*

------

[**<u>**Table of Contents**</u>**](#table_of_contents)

**Continental Resources, Inc. and Subsidiaries**

**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 and associated 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. As of December 31, 2025, all of the Company's operations were conducted onshore in the United States. Additionally, the Company pursues the acquisition and management of perpetually owned minerals located in certain of its key operating areas.

*Voluntary Filer*

The Company is privately owned by its founder, Harold G. Hamm, certain members of his family and their affiliated entities (the "Hamm Family"). As of December 31, 2025, the Hamm Family holds approximately 299.6 million shares of common stock of the Company. As a privately held company, certain of the corporate governance, disclosure, and other provisions applicable to a company with listed equity securities and reporting obligations under the Securities Exchange Act of 1934 do not apply to us. We continue to furnish Quarterly Reports on Form 10-Q and Annual Reports on Form 10-K with the 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 and equity attributable to the noncontrolling interests are presented separately in the Company's financial statements.

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 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. The Company's President and CEO is the chief operating decision maker and he reviews consolidated net income to assess performance and determine how to allocate resources. The measure of segment assets is reported on the consolidated balance sheets as total assets. As a single reportable segment entity, the financial information is contained in *Part II. Item 8. Consolidated Financial Statements.*

*Subsequent events*

The Company evaluated its December 31, 2025 financial statements for subsequent events through February 23, 2026, the date the financial statements were available to be issued.

Subsequent to December 31, 2025, the Company completed its first international acquisition of oil and gas properties located in the Vaca Muerta shale play in Argentina's Neuquén Basin. The transaction closed after year-end and, accordingly, has not been reflected in the accompanying consolidated financial statements as of December 31, 2025. The acquired properties include undeveloped acreage with no production or revenues as of the closing date and currently represent an immaterial portion of the Company's consolidated assets. The acquisition represents the Company's initial entry into Argentina and is expected to generate future development opportunities that expand the geographic scope of the Company's operations.

*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.

------

[**<u>**Table of Contents**</u>**](#table_of_contents)

**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, 2025, the Company had cash deposits in excess of federally insured amounts of approximately $1.37 billion. 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 $4.0 million and $4.1 million as of December 31, 2025 and 2024, 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, 2025, sales to the Company's largest purchaser accounted for approximately 13% of the Company's total crude oil and natural gas sales. No other purchaser accounted for more than 10% of the Company's total crude oil, natural gas, and natural gas liquids sales for 2025. 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.

*Inventories*

Inventory is comprised of crude oil held in storage or as line fill in pipelines, pipeline imbalances, and tubular goods, equipment, and materials to be used in the Company's exploration and development activities. Crude oil inventories are valued at the lower of cost or net realizable value primarily using the first-in, first-out inventory method. Tubular goods and equipment are valued primarily using a weighted average cost method applied to specific classes of inventory items.

The components of inventory as of December 31, 2025 and 2024 consisted of the following:

---

| | | |
|:---|:---|:---|
|  | **December 31,** | **December 31,** |
| ***In thousands*** | **2025** | **2024** |
| Tubular goods, equipment, and materials | $109478 | $61502 |
| Crude oil | 117732 | 122608 |
| Natural gas | 197 | 141 |
| Total | $227407 | $184251 |

---

*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.

------

[**<u>**Table of Contents**</u>**](#table_of_contents)

**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<br>In Years** |
| Automobiles and aircraft | 5-15 |
| 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 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.

------

[**<u>**Table of Contents**</u>**](#table_of_contents)

**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, 2023 through December 31, 2025:

---

| | | | |
|:---|:---|:---|:---|
| ***In thousands*** | **2025** | **2024** | **2023** |
| Asset retirement obligations at January 1 | $440816 | $401928 | $261087 |
| Accretion expense | 25853 | 22239 | 14818 |
| Revisions (1) | 31396 | 15352 | 112803 |
| Plus: Additions for new assets | 18984 | 18720 | 18929 |
| Less: Plugging costs and sold assets | (4287) | (17423) | (5709) |
| &nbsp;&nbsp;&nbsp;&nbsp;Total asset retirement obligations at December 31 | $512762 | $440816 | $401928 |
| Less: Current portion of asset retirement obligations at December 31 (2) | 7380 | 8321 | 9971 |
| &nbsp;&nbsp;&nbsp;&nbsp;Non-current portion of asset retirement obligations at December 31 | $505382 | $432495 | $391957 |

---

(1)Revisions primarily represent changes in the present value of liabilities resulting from changes in estimated costs and economic lives of producing properties.

(2)Balance is included in the caption "Accrued liabilities and other" in the consolidated balance sheets.

As of December 31, 2025 and 2024, net property and equipment on the consolidated balance sheets included $214.6 million and $200.3 million, respectively, of net asset retirement costs.

*Asset impairment*

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.

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 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 $33.0 million and $40.5 million (net of accumulated amortization of $44.0 million and $36.6 million) relating to its long-term debt at December 31, 2025 and 2024, respectively.

Unamortized capitalized costs associated with the Company's Notes and note payable totaled $26.0 million and $31.7 million at December 31, 2025 and 2024, 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 $7.0 million and $8.7 million at December 31, 2025 and 2024, respectively, and are reflected in "Other noncurrent assets" on the consolidated balance sheets.

For the years ended December 31, 2025, 2024 and 2023, the Company recognized amortization expense associated with capitalized debt issuance costs of $7.5 million, $8.5 million, and $10.0 million, respectively, which are reflected in "Interest expense" on the consolidated statements of income.

------

[**<u>**Table of Contents**</u>**](#table_of_contents)

**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 income under the caption "Gain 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, stock redemption option, 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 at December 31, 2025 and 2024.

*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.

*Adoption of new accounting pronouncement*

In December 2023, the Financial Accounting Standards Board issued Accounting Standards Update ("ASU") 2023-09, *Income Taxes (Topic 740): Improvements to Income Tax Disclosures*. This ASU requires public business entities on an annual basis to disclose specific categories in a tabular rate reconciliation and provide additional information for reconciling items that meet a five percent quantitative threshold. Additionally, the ASU requires all entities to disclose the amount of income taxes paid disaggregated by federal, state, and foreign taxes, as well as individual jurisdictions where income taxes paid are equal to or greater than five percent of total income taxes paid. ASU 2023-09 became effective for annual periods beginning after December 15, 2024. The Company adopted this guidance in the financial statements for the year ending December 31, 2025, applying it retrospectively to the prior periods presented. See *Note 11. Income Taxes* for additional information.

*Recently issued accounting pronouncements not yet adopted*

In November 2024, the Financial Accounting Standards Board issued ASU 2024-03, *Income Statement – Reporting Comprehensive Income – Expense Disaggregation Disclosures (Subtopic 220-40): Disaggregation of Income Statement Expenses.* This ASU requires entities to disclose certain additional expense information including, among other items, purchases of inventory, employee compensation, depreciation and intangible asset amortization included within each consolidated statements of income expense caption. ASU 2024-03 is effective for annual reporting periods beginning after December 15, 2026, and interim reporting periods beginning after December 15, 2027. Early adoption is permitted and the update should be applied on a prospective basis, with a retrospective application permitted in the financial statements. The Company is currently evaluating the impact of the new standard on our consolidated financial statements and related disclosures.

------

[**<u>**Table of Contents**</u>**](#table_of_contents)

**Continental Resources, Inc. and Subsidiaries**

**Notes to Consolidated Financial Statements**

**Note 2. Property Acquisitions and Dispositions**

***2025***

In 2025, the Company executed acquisitions of oil and gas properties in various areas for cash consideration totaling $193 million. The Company accounted for each acquisition as an asset acquisition under ASC Topic 805—Business Combinations. Of the purchase prices, a total of $109 million was allocated to proved properties and a total of $84 million was allocated to unproved properties.

In 2025, the Company executed sales of oil and gas properties in various areas for cash proceeds totaling $52 million and recognized pre-tax net losses on the transactions totaling $2 million. The disposed properties represented an immaterial portion of the Company's production and proved reserves.

***2024***

In 2024, the Company executed acquisitions of oil and gas properties in various areas for cash consideration totaling $24 million. The Company accounted for each acquisition as an asset acquisition under ASC Topic 805—Business Combinations. Of the purchase prices, a total of $8 million was allocated to proved properties and a total of $16 million was allocated to unproved properties.

In 2024, the Company executed sales of oil and gas properties in various areas for cash proceeds totaling $546 million and recognized pre-tax net losses on the transactions totaling $31 million. The disposed properties represented an immaterial portion of the Company's production and proved reserves.

***2023***

In 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.

In 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.

**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,** | **Year ended December 31,** | **Year ended December 31,** |
| ***In thousands*** | **2025** | **2024** | **2023** |
| Supplemental cash flow information: |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Cash paid for interest | $206657 | $270934 | $387686 |
| &nbsp;&nbsp;&nbsp;&nbsp;Cash paid for income taxes | 315605 | 705405 | 566253 |
| &nbsp;&nbsp;&nbsp;&nbsp;Cash received for income tax refunds | 14768 | 3266 | 2 |
| Non-cash investing activities: |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Asset retirement obligation additions and revisions, net | 50380 | 34072 | 131732 |

---

As of December 31, 2025 and 2024, the Company had $251.8 million and $376.4 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.

------

[**<u>**Table of Contents**</u>**](#table_of_contents)

**Continental Resources, Inc. and Subsidiaries**

**Notes to Consolidated Financial Statements**

**Note 4. Net Property and Equipment**

Net property and equipment includes the following at December 31, 2025 and 2024.

---

| | | |
|:---|:---|:---|
|  | **December 31,** | **December 31,** |
| ***In thousands*** | **2025** | **2024** |
| Proved crude oil and natural gas properties | $41245944 | $38176634 |
| Unproved crude oil and natural gas properties | 1715566 | 1674548 |
| Service properties, equipment and other | 1386576 | 1265908 |
| Total property and equipment | 44348086 | 41117090 |
| Accumulated depreciation, depletion and amortization | (23691178) | (21079168) |
| Net property and equipment | $20656908 | $20037922 |

---

**Note 5. Accrued Liabilities and Other**

Accrued liabilities and other includes the following at December 31, 2025 and 2024:

---

| | | |
|:---|:---|:---|
|  | **December 31,** | **December 31,** |
| ***In thousands*** | **2025** | **2024** |
| Prepaid advances from joint interest owners | $29725 | $65495 |
| Accrued compensation | 96100 | 87331 |
| Accrued production taxes, ad valorem taxes and other non-income taxes | 109006 | 125574 |
| Accrued interest | 70476 | 70581 |
| Current portion of asset retirement obligations | 7380 | 8321 |
| Other | 5132 | 55734 |
| Accrued liabilities and other | $317819 | $413036 |

---

**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*.

At December 31, 2025 the Company had outstanding derivative contracts as set forth in the tables below.

---

| | | | | | | |
|:---|:---|:---|:---|:---|:---|:---|
| ***Natural gas derivatives*** |  |  |  |  |  |  |
|  |  |  | **Weighted Average Hedge Price ($/MMBtu)** | **Weighted Average Hedge Price ($/MMBtu)** | **Weighted Average Hedge Price ($/MMBtu)** | **Weighted Average Hedge Price ($/MMBtu)** |
| **Period and Type of Contract** | **Average Volumes Hedged** | **Average Volumes Hedged** | **Basis Swaps** | **Fixed Swaps** | **Floor** | **Ceiling** |
| January 2026 - March 2026 |  |  |  |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Collars - Henry Hub | 304000 | MMBtus/day |  |  | $4.25 | $5.99 |
| January 2026 - December 2026 |  |  |  |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Swaps - Henry Hub | 737000 | MMBtus/day |  | $4.13 |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Basis Swaps - WAHA | 113000 | MMBtus/day | $(1.80) |  |  |  |
| January 2027 - March 2027 |  |  |  |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Basis Swaps - WAHA | 120000 | MMBtus/day | $(0.90) |  |  |  |
| January 2027 - December 2027 |  |  |  |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Swaps - Henry Hub | 647000 | MMBtus/day |  | $3.94 |  |  |

---

------

[**<u>**Table of Contents**</u>**](#table_of_contents)

**Continental Resources, Inc. and Subsidiaries**

**Notes to Consolidated Financial Statements**

---

| | | | | | |
|:---|:---|:---|:---|:---|:---|
| ***Crude oil derivatives*** |  |  |  |  |  |
|  |  |  | **Weighted Average Hedge Price ($/Bbl)** | **Weighted Average Hedge Price ($/Bbl)** | **Weighted Average Hedge Price ($/Bbl)** |
| **Period and Type of Contract** | **Average Volumes Hedged** | **Average Volumes Hedged** | **Fixed Swaps** | **Floor** | **Ceiling** |
| January 2026 - December 2026 |  |  |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Fixed Swaps - WTI | 55000 | Bbls/day | $62.17 |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Collars - WTI | 33000 | Bbls/day |  | $60.00 | $69.38 |
| January 2027 - December 2027 |  |  |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Fixed Swaps - WTI | 19000 | Bbls/day | $64.52 |  |  |

---

***Derivative gains and losses***

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") 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,** | **Year ended December 31,** | **Year ended December 31,** |
| ***In thousands*** | **2025** | **2024** | **2023** |
| Cash received (paid) on derivatives: |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Crude oil fixed price swaps | $138693 | $58950 | $17989 |
| &nbsp;&nbsp;&nbsp;&nbsp;Crude oil collars | 4464 |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Crude oil NYMEX roll swaps | 2774 | (12) | 3519 |
| &nbsp;&nbsp;&nbsp;&nbsp;Natural gas fixed price swaps | 102919 | 262394 | 178529 |
| &nbsp;&nbsp;&nbsp;&nbsp;Natural gas basis swaps |  |  | 4818 |
| &nbsp;&nbsp;&nbsp;&nbsp;Natural gas collars | 76709 | 16069 | 29139 |
| &nbsp;&nbsp;&nbsp;&nbsp;Natural gas three-way collars |  |  | 3741 |
| &nbsp;&nbsp;&nbsp;&nbsp;Natural gas WAHA fixed price swaps |  | 40184 | 19435 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Cash received on derivatives, net | 325559 | 377585 | 257170 |
| Non-cash gain (loss) on derivatives: |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Crude oil fixed price swaps | 135410 | (133711) | 134548 |
| &nbsp;&nbsp;&nbsp;&nbsp;Crude oil collars | 58815 |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Crude oil NYMEX roll swaps |  | (6888) | 4051 |
| &nbsp;&nbsp;&nbsp;&nbsp;Natural gas fixed price swaps | (24224) | (176372) | 513129 |
| &nbsp;&nbsp;&nbsp;&nbsp;Natural gas basis swaps |  |  | (8910) |
| &nbsp;&nbsp;&nbsp;&nbsp;Natural gas collars | 16702 | (11923) | 42240 |
| &nbsp;&nbsp;&nbsp;&nbsp;Natural gas three-way collars |  |  | (598) |
| &nbsp;&nbsp;&nbsp;&nbsp;Natural gas WAHA fixed price swaps |  | (21523) | 2138 |
| &nbsp;&nbsp;&nbsp;&nbsp;Natural gas WAHA basis swaps | 37116 |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Non-cash gain (loss) on derivatives, net | 223819 | (350417) | 686598 |
| Gain on derivative instruments, net | $549378 | $27168 | $943768 |

---

***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.

------

[**<u>**Table of Contents**</u>**](#table_of_contents)

**Continental Resources, Inc. and Subsidiaries**

**Notes to Consolidated Financial Statements**

The following table presents the gross amounts of recognized derivative assets and liabilities, the amounts offset under netting arrangements with counterparties, and the resulting net amounts presented in the consolidated balance sheets at December 31, 2025 and 2024, all at fair value.

---

| | | |
|:---|:---|:---|
|  | **December 31,** | **December 31,** |
| ***In thousands*** | **2025** | **2024** |
| Commodity derivative assets: |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Gross amounts of recognized assets | $392348 | $168023 |
| &nbsp;&nbsp;&nbsp;&nbsp;Gross amounts offset on balance sheet | (6114) | (10370) |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Net amounts of assets on balance sheet | 386234 | 157653 |
| Commodity derivative liabilities: |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Gross amounts of recognized liabilities | (11019) | (10513) |
| &nbsp;&nbsp;&nbsp;&nbsp;Gross amounts offset on balance sheet | 6114 | 10370 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Net amounts of liabilities on balance sheet | $(4905) | $(143) |

---

The following table reconciles the net amounts disclosed above to the individual financial statement line items in the consolidated balance sheets.

---

| | | |
|:---|:---|:---|
|  | **December 31,** | **December 31,** |
| ***In thousands*** | **2025** | **2024** |
| Derivative assets | $324706 | $95227 |
| Derivative assets, noncurrent | 61528 | 62426 |
| &nbsp;&nbsp;&nbsp;&nbsp;Net amounts of assets on balance sheet | 386234 | 157653 |
| Derivative liabilities, noncurrent | (4905) | (143) |
| Total derivative assets, net | $381329 | $157510 |

---

**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:

&nbsp;&nbsp;&nbsp;&nbsp;•Level 1: Observable inputs that reflect unadjusted quoted prices for identical assets or liabilities in active markets as of the reporting date.

&nbsp;&nbsp;&nbsp;&nbsp;•Level 2: Observable market-based inputs or unobservable inputs corroborated by market data. These are inputs other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reporting date.

&nbsp;&nbsp;&nbsp;&nbsp;•Level 3: Unobservable inputs not corroborated by market data and may be used with internally developed methodologies that result in management's best estimate of fair value.

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.

*Assets and Liabilities Measured at Fair Value on a Recurring Basis*

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.

------

[**<u>**Table of Contents**</u>**](#table_of_contents)

**Continental Resources, Inc. and Subsidiaries**

**Notes to Consolidated Financial Statements**

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, 2025 and 2024.

---

| | | | | |
|:---|:---|:---|:---|:---|
|  | **Fair value measurements at December 31, 2025 using:** | **Fair value measurements at December 31, 2025 using:** | **Fair value measurements at December 31, 2025 using:** |  |
| ***In thousands*** | **Level 1** | **Level 2** | **Level 3** | **Total** |
| Derivative assets: |  |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Crude oil fixed price swaps | $— | $147943 | $— | $147943 |
| &nbsp;&nbsp;&nbsp;&nbsp;Crude oil collars |  | 58815 |  | 58815 |
| &nbsp;&nbsp;&nbsp;&nbsp;Natural gas fixed price swaps |  | 120753 |  | 120753 |
| &nbsp;&nbsp;&nbsp;&nbsp;Natural gas collars |  | 16702 |  | 16702 |
| &nbsp;&nbsp;&nbsp;&nbsp;Natural gas WAHA basis swaps |  | 37116 |  | 37116 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Total | $— | $381329 | $— | $381329 |

---

---

| | | | | |
|:---|:---|:---|:---|:---|
|  | **Fair value measurements at December 31, 2024 using:** | **Fair value measurements at December 31, 2024 using:** | **Fair value measurements at December 31, 2024 using:** |  |
| ***In thousands*** | **Level 1** | **Level 2** | **Level 3** | **Total** |
| Derivative assets: |  |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Crude oil fixed price swaps | $— | $12533 | $— | $12533 |
| &nbsp;&nbsp;&nbsp;&nbsp;Natural gas fixed price swaps |  | 144977 |  | 144977 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Total | $— | $157510 | $— | $157510 |

---

*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% discount rate. At December 31, 2025, the Company's commodity price assumptions were based on forward NYMEX strip prices through year-end 2030 and were then escalated at 3% per year thereafter. Operating cost assumptions were based on current costs escalated at 3% per year beginning in 2027.

Unobservable inputs to the Company'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.

For the years ended December 31, 2025 and 2024, estimated future net cash flows were determined to be in excess of cost basis, and therefore no impairments were recorded for the Company's proved crude oil and natural gas properties. For the year ended December 31, 2023, the Company determined the carrying amounts of certain proved properties were not recoverable from future cash flows, and therefore, were impaired. Such impairments totaled $15.5 million for 2023.

Certain unproved crude oil and natural gas properties were impaired during the years ended December 31, 2025, 2024, and 2023, 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.

------

[**<u>**Table of Contents**</u>**](#table_of_contents)

**Continental Resources, Inc. and Subsidiaries**

**Notes to Consolidated Financial Statements**

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 income.

---

| | | | |
|:---|:---|:---|:---|
|  | **Year ended December 31,** | **Year ended December 31,** | **Year ended December 31,** |
| ***In thousands*** | **2025** | **2024** | **2023** |
| Proved property impairments | $— | $— | $15455 |
| Unproved property impairments | 58895 | 43199 | 51343 |
| Total | $58895 | $43199 | $66798 |

---

*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.

---

| | | | | |
|:---|:---|:---|:---|:---|
|  | **December 31, 2025** | **December 31, 2025** | **December 31, 2024** | **December 31, 2024** |
| ***In thousands*** | **Carrying Amount** | **Estimated Fair Value** | **Carrying Amount** | **Estimated Fair Value** |
| Debt: |  |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Credit facility | $— | $— | $20000 | $20000 |
| &nbsp;&nbsp;&nbsp;&nbsp;Notes payable |  |  | 15159 | 13900 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;2.268% Senior Notes due 2026 | 798609 | 784400 | 797056 | 758400 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;4.375% Senior Notes due 2028 | 997005 | 997700 | 995635 | 972200 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;5.75% Senior Notes due 2031 | 1488995 | 1539100 | 1487175 | 1481700 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;2.875% Senior Notes due 2032 | 794525 | 697600 | 793740 | 655500 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;4.9% Senior Notes due 2044 | 692912 | 557400 | 692682 | 564800 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Total debt | $4772046 | $4576200 | $4801447 | $4466500 |

---

The fair value of credit facility borrowings, if any, 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 fair values of the Company's senior notes are based on quoted market prices and, accordingly, are classified as Level 1 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.

------

[**<u>**Table of Contents**</u>**](#table_of_contents)

**Continental Resources, Inc. and Subsidiaries**

**Notes to Consolidated Financial Statements**

**Note 8. Debt**

The Company's debt, net of unamortized discounts, premiums, and debt issuance costs totaling $28.0 million and $33.8 million at December 31, 2025 and 2024, respectively, consists of the following.

---

| | | |
|:---|:---|:---|
|  | **December 31,** | **December 31,** |
| ***In thousands*** | **2025** | **2024** |
| Credit facility | $— | $20000 |
| Notes payable |  | 15159 |
| 2.268% Senior Notes due 2026 (1) | 798609 | 797056 |
| 4.375% Senior Notes due 2028 | 997005 | 995635 |
| 5.75% Senior Notes due 2031 | 1488995 | 1487175 |
| 2.875% Senior Notes due 2032 | 794525 | 793740 |
| 4.9% Senior Notes due 2044 | 692912 | 692682 |
| &nbsp;&nbsp;&nbsp;&nbsp;Total debt | 4772046 | 4801447 |
| Less: Current portion of long-term debt | 798609 | 2587 |
| Long-term debt, net of current portion | $3973437 | $4798860 |

---

(1) The Company's 2026 Notes, which have a face value of $800 million at December 31, 2025, are scheduled to mature on November 15, 2026 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, 2025.

***Credit Facility***

The Company has a credit facility, maturing in October 2029, with aggregate lender commitments totaling $1.8 billion. The Company has the option to extend the October 2029 maturity date by up to two additional one-year periods subject to lender consent. The credit facility is unsecured and has no borrowing base requirement subject to redetermination.

The Company had no outstanding borrowings on its credit facility at December 31, 2025*.* The Company incurs commitment fees based on currently assigned credit ratings of 0.20% per annum on the daily average amount of unused borrowing availability. 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's senior, unsecured, long-term indebtedness.

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 (a) net debt (calculated as total face value of debt plus outstanding letters of credit less cash and cash equivalents) divided by (b) the sum of net debt plus total shareholders' equity (i) 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 and (ii) plus (to the extent resulting in a reduction of total shareholders' equity) or minus (to the extent resulting in an increase of total shareholders' equity), as applicable, the amount of the non-cash impact of the accounting treatment for the Redemption Agreement, which amount shall be further adjusted, (x) if the Redemption Agreement is amended without the lenders consent and has the effect of materially increasing the scope of the Company's obligations beyond the last form of the Redemption Agreement that was approved by the lenders and (y) to reflect the impact of any cash payments actually made under the agreement. The Company was in compliance with the credit facility covenants at December 31, 2025.

***Senior Notes*** 

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, 2025.

---

| | | | | | |
|:---|:---|:---|:---|:---|:---|
|  | **2026 Notes** | **2028 Notes** | **2031 Notes** | **2032 Notes** | **2044 Notes** |
| Face value (in thousands) | $800000 | $1000000 | $1500000 | $800000 | $700000 |
| Maturity date | November 15, 2026 | January 15, 2028 | January 15, 2031 | April 1, 2032 | June 1, 2044 |
| Interest payment dates | 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) | Nov 15, 2023 | Oct 15, 2027 | Jul 15, 2030 | January 1. 2032 | Dec 1, 2043 |

---

------

[**<u>**Table of Contents**</u>**](#table_of_contents)

**Continental Resources, Inc. and Subsidiaries**

**Notes to Consolidated Financial Statements**

(1)At any time prior to the indicated dates, the Company has the option to redeem all or a portion of its senior notes of the applicable series at the "make-whole" redemption amounts specified in the respective senior note indentures plus any accrued and unpaid interest to the date of redemption. On or after the indicated dates, the Company may redeem all or a portion of its senior notes at a redemption amount equal to 100% of the principal amount of the senior notes being redeemed plus any accrued and unpaid interest to the date of redemption.

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, 2025.

The senior notes are obligations of Continental Resources, Inc. Additionally, certain of the Company's wholly-owned consolidated subsidiaries (Banner Pipeline Company, L.L.C., CLR Asset Holdings, LLC, The Mineral Resources Company, LLC, SCS1 Holdings LLC, Continental Innovations LLC, Jagged Peak Energy LLC, and Parsley SoDe Water LLC) fully and unconditionally guarantee the senior notes on a joint and several basis. The Company's subsidiaries formed under the laws of foreign jurisdictions (Continental Resources Argentina S.A.U. and Continental Resources Turkey Petrol Arama ve Üretim Limited Şirketi) are not currently required to guarantee the senior notes under the terms of the indentures governing such notes. The financial information of the guarantor group is not materially different from the consolidated financial statements of the Company. The Company's other subsidiaries, whose assets, equity, and results of operations attributable to the Company are not material, do not guarantee the senior notes.

***Retirement of Senior Notes***

*2024*

In June 2024, the Company repaid its outstanding $893.1 million of 2024 Notes that were scheduled to mature on June 1, 2024. The redemption price was equal to 100% of the principal amount plus accrued and unpaid interest to the redemption date. The aggregate of the principal amount and accrued interest paid upon redemption was $910.1 million.

*2023*

In April 2023, the Company fully 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 the principal amount and accrued interest paid upon redemption was $650.3 million.

***Repayment of Term Loan***

In November 2022, the Company borrowed $750 million under a three-year term loan agreement that was scheduled to mature in November 2025. The Company repaid $100 million of the term loan during the three months ended March 31, 2024 and repaid the remaining $650 million during the three months ended June 30, 2024. The Company recognized a pre-tax loss on extinguishment of debt totaling $1.6 million related to the repayments.

***Repayment of Notes Payable***

In June 2020, the Company borrowed an aggregate of $26.0 million under two 10-year amortizing term loans secured by the Company's corporate office building and its interest in parking facilities in Oklahoma City, Oklahoma. The Company repaid the outstanding $14.4 million principal balance of its term loans during the three months ended June 30, 2025. The loans were scheduled to mature in May 2030.

**Note 9. Revenues**

Below is a discussion of the nature, timing, and presentation of revenues arising from the Company'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'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

------

[**<u>**Table of Contents**</u>**](#table_of_contents)

**Continental Resources, Inc. and Subsidiaries**

**Notes to Consolidated Financial Statements**

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's operated crude oil production totaled $298.0 million, $317.8 million, and $284.2 million for the years ended December 31, 2025, 2024, and 2023, respectively.

*Operated natural gas revenues –* The Company sells a 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'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 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 may elect to take a volume of processed residue gas and/or NGLs in-kind at the tailgate of the midstream customer's processing plant in lieu of a monetary settlement for the sale of the Company's operated 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 products 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'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 $34.7 million, $49.5 million, and $54.0 million for the years ended December 31, 2025, 2024, and 2023, respectively.

*Non-operated crude oil, natural gas, and NGL revenues –* The Company'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's accounting for its derivative instruments.

*Revenues from service operations –* Revenues from the Company's crude oil and natural gas service operations consist primarily of revenues associated with water gathering, recycling, delivery, and disposal 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.

------

[**<u>**Table of Contents**</u>**](#table_of_contents)

**Continental Resources, Inc. and Subsidiaries**

**Notes to Consolidated Financial Statements**

***Disaggregation of revenues***

The following table presents the disaggregation of the Company's crude oil and natural gas revenues for the periods presented. Sales of natural gas and NGLs are combined, as a substantial majority of the Company's natural gas sales contracts represent wellhead sales of unprocessed gas.

---

| | | | | | | | | | |
|:---|:---|:---|:---|:---|:---|:---|:---|:---|:---|
|  | **Year ended December 31,** | **Year ended December 31,** | **Year ended December 31,** | **Year ended December 31,** | **Year ended December 31,** | **Year ended December 31,** | **Year ended December 31,** | **Year ended December 31,** | **Year ended December 31,** |
|  | **2025** | **2025** | **2025** | **2024** | **2024** | **2024** | **2023** | **2023** | **2023** |
| ***In thousands*** | **Crude Oil** | **Natural Gas and NGLs** | **Total** | **Crude Oil** | **Natural Gas and NGLs** | **Total** | **Crude Oil** | **Natural Gas and NGLs** | **Total** |
| Bakken | $2960045 | $343982 | $3304027 | $3386418 | $283248 | $3669666 | $3777412 | $380359 | $4157771 |
| Anadarko Basin | 801496 | 684091 | 1485587 | 968795 | 532747 | 1501542 | 999009 | 687687 | 1686696 |
| Powder River Basin | 401457 | 54574 | 456031 | 428667 | 46412 | 475079 | 410963 | 43968 | 454931 |
| Permian Basin | 1501974 | 123529 | 1625503 | 1394808 | 66135 | 1460943 | 1135421 | 74133 | 1209554 |
| All other | 112394 | 39 | 112433 | 149361 | 94 | 149455 | 175118 | 193 | 175311 |
| Crude oil, natural gas, and natural gas liquids sales | $5777366 | $1206215 | $6983581 | $6328049 | $928636 | $7256685 | $6497923 | $1186340 | $7684263 |

---

***Performance obligations***

The Company satisfies the performance obligations under its commodity 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, 2025 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") 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'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, 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.

***Contract balances***

Under the Company's commodity 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's unconditional rights to receive consideration are presented as a receivable within "Accounts receivable, net" 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 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 oil, natural gas, and natural gas liquids sales". Revenues recognized during the years ended December 31, 2025, 2024, and 2023 related to performance obligations satisfied in prior reporting periods were not material.

------

[**<u>**Table of Contents**</u>**](#table_of_contents)

**Continental Resources, Inc. and Subsidiaries**

**Notes to Consolidated Financial Statements**

**Note 10. Allowance for Credit Losses**

The Company's principal exposure to credit risk is through the sale of its crude oil, 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 discussed below, the balances of which are combined to form the caption "Accounts receivable, net" in the consolidated balance sheets.

Historically, the Company's credit losses on receivables have been immaterial. The Company's aggregate allowance for credit losses totaled $4.0 million and $4.1 million at December 31, 2025 and 2024, respectively, which is netted within the caption "Accounts receivable, net" in the consolidated balance sheets. Aggregate credit loss expenses totaled $0.1 million, $1.4 million, and $0.1 million for the years ended December 31, 2025, 2024, and 2023, respectively, which are included in "General and administrative expenses" in the consolidated statements of income.

*Receivables—Crude oil, natural gas, and natural gas liquids sales*

The Company's crude oil, 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, natural gas, and NGL sales receivables.

Receivables associated with crude oil, natural gas, and NGL sales, which totaled $1.0 billion, $1.2 billion, and 1.2 billion at December 31, 2025, 2024, and 2023 respectively, are short term in nature. Receivables from the sale of crude oil, 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, natural gas, and NGL sales was negligible at both December 31, 2025 and December 31, 2024. 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, 2025, 2024, and 2023.

*Receivables—Joint interest and other*

Joint interest and other receivables, which totaled $394.6 million, $381.8 million, $350.9 million at December 31, 2025, 2024, and 2023 respectively, 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'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's interest.

The Company's allowance for credit losses on joint interest receivables totaled $4.0 million and $4.1 million at December 31, 2025 and 2024, respectively. 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, the ability to recoup amounts owed through netting of production proceeds, the balance of co-owner prepayments if any, and the co-owner'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, 2025, 2024, and 2023.

**Note 11. Income Taxes**

In July 2025, the One Big Beautiful Bill Act (the "Act") was enacted, which included a broad range of tax reform provisions affecting businesses. Below is a summary of notable changes included in the Act.

*Bonus depreciation* – the Act permanently restored 100% immediate expensing for qualifying tangible property placed into service after January 19, 2025.

------

[**<u>**Table of Contents**</u>**](#table_of_contents)

**Continental Resources, Inc. and Subsidiaries**

**Notes to Consolidated Financial Statements**

*Research and development (R&D) costs* – the Act repealed a provision that required domestic R&D costs to be capitalized and amortized over five years. Companies can now immediately expense R&D costs incurred in tax years beginning after December 31, 2024. In addition, companies are permitted to make an election to accelerate the deductions for unamortized R&D costs that were previously capitalized from 2022 to 2024 effective for tax years beginning after December 31, 2024.

*Intangible drilling and development costs* – the Act introduced a new adjustment for intangible drilling and development costs that will be included in the computation of adjusted financial statement income to determine liability for the corporate alternative minimum tax ("CAMT") effective for tax years beginning after December 31, 2025.

In accordance with US GAAP, the Company recognized the tax effects from the Act in the third quarter of 2025, the reporting period that included the enactment date. As a result of the Act, the Company became subject to CAMT for the 2025 tax year and recorded CAMT credit carryforwards of $285 million at December 31, 2025. These CAMT credit carryforwards do not expire and may be used to offset future regular U.S. federal income tax liabilities. Given the Company's future taxable income projections, CAMT did not impact the Company's quarterly or annual effective tax rates during 2025.

As discussed in *Note 1. Organization and Summary of Significant Accounting Policies*, at December 31, 2025 the Company adopted ASU 2023-09, *Income Taxes (Topic 740): Improvements to Income Tax Disclosures*. The disclosures required by the new standard are presented below as applicable. The standard was adopted on a retrospective basis and, accordingly, information for prior periods has been adjusted to conform to the new presentation.

The items comprising the Company's provision for income taxes are as follows for the periods presented:

---

| | | | |
|:---|:---|:---|:---|
|  | **Year ended December 31,** | **Year ended December 31,** | **Year ended December 31,** |
| ***In thousands*** | **2025** | **2024** | **2023** |
| Current income tax provision: |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;United States federal | $224711 | $591706 | $461487 |
| &nbsp;&nbsp;&nbsp;&nbsp;State and local | 542 | 43357 | 37173 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Total current income tax provision | 225253 | 635063 | 498660 |
| Deferred income tax provision (benefit): |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;United States federal | 321298 | (148273) | 318484 |
| &nbsp;&nbsp;&nbsp;&nbsp;State and local | 21340 | (14941) | 10486 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Total deferred income tax provision (benefit) | 342638 | (163214) | 328970 |
| Provision for income taxes | $567891 | $471849 | $827630 |
| Effective tax rate | 21.2% | 19.0% | 21.1% |

---

The Company's effective tax rate differs from the United States federal statutory tax rate due to the effect of state income taxes, permanent taxable differences, tax credits, and other tax items as reflected in the table below.

---

| | | | | | | |
|:---|:---|:---|:---|:---|:---|:---|
|  | **Year ended December 31,** | **Year ended December 31,** | **Year ended December 31,** | **Year ended December 31,** | **Year ended December 31,** | **Year ended December 31,** |
|  | **2025** | **2025** | **2024** | **2024** | **2023** | **2023** |
| ***In thousands, except tax rates*** | **Amount** | **Percent** | **Amount** | **Percent** | **Amount** | **Percent** |
| Income before income taxes | $2676537 |  | $2488567 |  | $3928947 |  |
| U.S. federal statutory tax expense and rate | 562073 | 21.0% | 522599 | 21.0% | 825079 | 21.0% |
| State taxes, net of federal income tax effect (1) | 21882 | 0.8% | 28416 | 1.2% | 47659 | 1.2% |
| Federal tax credits |  |  |  |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Research and development tax credits | (11890) | (0.4)% | (82014) | (3.3)% | (45082) | (1.1)% |
| &nbsp;&nbsp;&nbsp;&nbsp;Other | (1500) | (0.1)% | (1662) | (0.1)% |  | —% |
| Nontaxable or nondeductible items |  |  |  |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Other | (2674) | (0.1)% | 4510 | 0.2% | (26) | (0.0)% |
| Income tax expense and effective tax rate | $567891 | 21.2% | $471849 | 19.0% | $827630 | 21.1% |

---

(1) State taxes in North Dakota during the years ended December 31, 2025, 2024, and 2023 made up the majority (greater than 50%) of the tax effect in this category.

Federal and state income taxes paid by the Company are as follows for the periods presented:

------

[**<u>**Table of Contents**</u>**](#table_of_contents)

**Continental Resources, Inc. and Subsidiaries**

**Notes to Consolidated Financial Statements**

---

| | | | |
|:---|:---|:---|:---|
|  | **December 31,** | **December 31,** | **December 31,** |
| ***In thousands*** | **2025** | **2024** | **2023** |
| Cash paid for federal income taxes | $295000 | $644000 | $458000 |
| Cash paid for state income taxes, net of refunds: |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;North Dakota | 1641 | 52000 | 102000 |
| &nbsp;&nbsp;&nbsp;&nbsp;Other | 4196 | 6139 | 6251 |
| Total cash paid for state income taxes, net of refunds | 5837 | 58139 | 108251 |
| Total cash paid for income taxes, net of refunds | $300837 | $702139 | $566251 |

---

The components of the Company's deferred tax assets and deferred tax liabilities as of December 31, 2025 and 2024 are reflected in the table below.

---

| | | |
|:---|:---|:---|
|  | **December 31,** | **December 31,** |
| ***In thousands*** | **2025** | **2024** |
| Deferred tax assets |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Net operating loss carryforwards | $65277 | $30298 |
| &nbsp;&nbsp;&nbsp;&nbsp;Corporate alternative minimum tax carryforward | 284954 |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Incentive compensation | 23922 | 26224 |
| &nbsp;&nbsp;&nbsp;&nbsp;Other | 53229 | 34343 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Total deferred tax assets | 427382 | 90865 |
| Deferred tax liabilities |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Property and equipment | (3381439) | (2755011) |
| &nbsp;&nbsp;&nbsp;&nbsp;Net deferred hedge gains | (89010) | (37226) |
| &nbsp;&nbsp;&nbsp;&nbsp;Other | (3640) | (2697) |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Total deferred tax liabilities | (3474089) | (2794934) |
| Deferred income tax liabilities, net | $(3046707) | $(2704069) |

---

In assessing the realizability of deferred tax assets the Company must consider whether it is more likely than not that some portion or all of the deferred tax assets will not be realized. The Company applies judgment to determine the weight of both positive and negative evidence in order to conclude whether a valuation allowance is necessary for its deferred tax assets. In determining whether a valuation allowance is required, the Company considers, among other factors, the Company's financial position, results of operations, projected future taxable income, reversal of existing deferred tax liabilities against deferred tax assets, and tax planning strategies. No valuation allowances were recognized during the years ended December 31, 2025, 2024, and 2023.

The Company will continue to evaluate both the positive and negative evidence on a periodic 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.

As of December 31, 2025, the Company had federal, North Dakota and Oklahoma net operating loss ("NOL") carryforwards of $122 million, $45 million, and $1.2 billion respectively that have an indefinite life. As of December 31, 2025, the Company had North Dakota and Texas research and development tax credit carryforwards of $3 million and $6 million, respectively, that carryforward 15 years and 20 years, respectively. As of December 31, 2025, the Company had a CAMT carryforward of $285 million that has an indefinite life. The Company files income tax returns in U.S. federal and various other state and foreign jurisdictions where it operates. With few exceptions, the Company is no longer subject to U.S. federal or various other state and foreign income tax examinations by tax authorities for years prior to 2022.

**Note 12. Leases**

The Company's lease liabilities recognized on the balance sheet as a lessee totaled $28.9 million and $19.9 million as of December 31, 2025 and 2024, respectively, at discounted present value, which is comprised of the asset classes reflected in the table below. The amounts disclosed herein primarily represent costs associated with properties operated by the Company that are presented on a gross basis and do not represent the Company's net proportionate share of such amounts. A portion of these costs have been or will be billed to other working interest owners. Once paid, the Company's share of these costs are included in property and equipment, production expenses, or general and administrative expenses, as applicable.

------

[**<u>**Table of Contents**</u>**](#table_of_contents)

**Continental Resources, Inc. and Subsidiaries**

**Notes to Consolidated Financial Statements**

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's leasing activities as a lessor are negligible.

---

| | | |
|:---|:---|:---|
|  | **December 31,** | **December 31,** |
| ***In thousands*** | **2025** | **2024** |
| Surface use agreements | $15332 | $16370 |
| Field equipment | 13223 | 3034 |
| Other | 371 | 465 |
| Total | $28926 | $19869 |

---

Minimum future commitments by year for the Company's operating leases as of December 31, 2025 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** |
| 2026 | 11451 |
| 2027 | 5858 |
| 2028 | 1746 |
| 2029 | 1749 |
| 2030 | 1749 |
| Thereafter | 12984 |
| Total operating lease liabilities, at undiscounted value | $35537 |
| Less: Imputed interest | (6611) |
| Total operating lease liabilities, at discounted present value | $28926 |
| Less: Current portion of operating lease liabilities | (10225) |
| Operating lease liabilities, noncurrent | $18701 |

---

Additional information for the Company'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 any 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,** | **Year ended December 31,** | **Year ended December 31,** |
| ***In thousands, except weighted average data*** | **2025** | **2024** | **2023** |
| Lease costs: |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Operating lease costs | $14185 | $20073 | $13121 |
| &nbsp;&nbsp;&nbsp;&nbsp;Variable lease costs | 2698 | 1174 | 896 |
| &nbsp;&nbsp;&nbsp;&nbsp;Short-term lease costs | 166886 | 180830 | 168680 |
| Total lease costs | $183769 | $202077 | $182697 |
| Other information: |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Right-of-use assets obtained in exchange for new operating lease liabilities | $21147 | $1097 | $24949 |
| &nbsp;&nbsp;&nbsp;&nbsp;Operating cash flows from operating leases included in lease liabilities | 14087 | 20076 | 13166 |
| &nbsp;&nbsp;&nbsp;&nbsp;Weighted average remaining lease term as of December 31 (in years) | 7.4 | 11.1 | 6.9 |
| &nbsp;&nbsp;&nbsp;&nbsp;Weighted average discount rate as of December 31 | 4.7% | 4.8% | 4.7% |

---

**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, 2025 under the arrangements amount to approximately $500 million, of which $219 million is expected to be incurred in 2026, $204 million in 2027, $68 million in

------

[**<u>**Table of Contents**</u>**](#table_of_contents)

**Continental Resources, Inc. and Subsidiaries**

**Notes to Consolidated Financial Statements**

2028, $3 million in 2029, $3 million in 2030, and $3 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 routine operations*

The Company is involved in various legal proceedings including, but not limited to, commercial disputes, claims from royalty and surface owners, property damage claims, 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, the Company does not expect them to have a material adverse effect on its financial condition, results of operations or cash flows. As of December 31, 2025 and 2024, the Company had recognized a liability within "Other noncurrent liabilities" of $1.4 million and $15.9 million, respectively, for various matters, none of which are believed to be individually significant.

*Litigation pertaining to 2022 take-private transaction*

In April 2023, three separate putative class action lawsuits were consolidated under the caption *In re Continental Resources, Inc. Shareholder Litigation*, Case No. CJ-2022-4162, in the District Court of Oklahoma County, Oklahoma (the "Consolidated Action"). In the Consolidated Action, the plaintiffs, on behalf of themselves and all other similarly situated former shareholders of the Company, allege that Mr. Hamm, certain trusts established for the benefit of Mr. Hamm and/or his family members, and certain other directors of the Company breached their fiduciary duties in connection with the 2022 take-private transaction and seek: (i) monetary damages; (ii) the costs and expenses associated with the lawsuits; and (iii) other equitable relief. This matter is currently set for trial in May 2026. The defendants continue to vigorously defend themselves against these claims.

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 2022 take-private transaction. In April 2024, Quadre Investments, L.P. filed a voluntary dismissal with prejudice. The Company continues to vigorously defend itself against these claims.

*Stock Redemption Agreement –* In 2024, Continental entered into a Redemption Agreement with Mr. Hamm and certain members of his family whereby, following Mr. Hamm's passing, his estate may, but is not obligated to, elect from time-to-time to require Continental to redeem sufficient shares to enable the estate to fund the payment of estate taxes and interest as they become due. Mr. Hamm's potential estate tax liability is expected to be primarily based on the fair market value his estate assigns to his Continental stock at the time of passing. The agreement contemplates that the estate will defer and pay the potential estate taxes and related interest in installments over a period of up to 14 years as permitted by the Internal Revenue Code. Assuming the estate elects to exercise its redemption rights, Continental's potential obligations are expected to occur over the same 14 year period in conjunction with the estate's installment payments. The future value of Continental, the future tax laws and resulting estate tax liability, the timing of any redemptions, and the potential number and value of shares Continental may be required to redeem under the agreement are unknown and subject to numerous uncertainties and cannot be reasonably quantified. There have been no share repurchases or settlements under the agreement since its inception.

**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 $0.2 million, $0.3 million, and $0.4 million and received payments from these affiliates of $0.1 million, $0.1 million, and $0.1 million during the years ended December 31, 2025, 2024, and 2023, respectively, relating to the operations of the respective properties. In connection with such interest, we also paid these affiliates $0.1 million for their share of interests in certain wells divested by the Company for the year ended December 31, 2024. At December 31, 2025 and 2024, approximately $21,000 and $18,000, respectively, was due from these affiliates relating to these transactions, which is included in "Accounts receivable, net" on the consolidated balance sheets. At December 31, 2025 and 2024, approximately $17,000

------

[**<u>**Table of Contents**</u>**](#table_of_contents)

**Continental Resources, Inc. and Subsidiaries**

**Notes to Consolidated Financial Statements**

and $21,000, 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 2025, 2024, and 2023, the Company charged affiliates approximately $25,000, $8,500, and $28,100, respectively, for use of its corporate aircraft crews, fuel, and reimbursement of expenses and received approximately $22,000, $14,100, and $31,000 from affiliates in 2025, 2024, and 2023, respectively, in connection with such items. The Company was charged approximately $603,000, $404,000, and $312,000, respectively, by affiliates for use of their aircraft and reimbursement of expenses during 2025, 2024, and 2023 and paid $684,000, $271,000, and $299,000 to the affiliates in 2025, 2024, and 2023, respectively. At December 31, 2025 and 2024, approximately $4,000 and $1,000, respectively, was due from an affiliate relating to these transactions, which is included in "Accounts receivable, net" on the consolidated balance sheets. At December 31, 2025 and 2024, approximately $51,000 and $133,000, respectively, was due to an affiliate relating to these transactions, which is included in "Accounts payable trade" on the consolidated balance sheets.

*See Note 13. Commitments and Contingencies—Stock Redemption Agreement* for discussion of the redemption agreement entered into between the Company, Mr. Hamm, and certain members of his family in 2024.

*See Note 16. Shareholders' Equity Attributable to Continental Resources—Common Stock* for discussion of the share exchange agreement entered into between the Company, Mr. Hamm, and certain members of his family in 2024.

**Note 15. Incentive Compensation**

The Company has granted incentive compensation awards to employees pursuant to the Continental Resources, Inc. 2022 Long-Term Incentive Plan ("2022 Plan"). Awards granted prior to 2024 generally vest after three years of employee service. Awards granted in 2024 and thereafter generally vest annually in one-third increments, over three years of employee service. The Company intends to settle all outstanding incentive awards vesting in the future in cash and, thus, the awards are classified as liability awards pursuant to ASC Topic 718, Compensation—Stock Compensation.

At December 31, 2025, the Company had recorded a current liability of $82.5 million and a non-current liability of $20.0 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 reflect 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, 2025. The Company's compensation expense associated with such awards during the years ended December 31, 2025, 2024, and 2023 which is included in the caption "General and administrative expenses" in the consolidated statements of income, was $76.9 million, $83.7 million and $93.1 million, respectively. As of December 31, 2025, there was approximately $48.6 million of unrecognized liabilities and compensation expense related to unvested awards, which are expected to be recognized over a weighted average period of 1.2 years. The current liability at December 31, 2025 was paid in cash to employees in February 2026 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.

------

[**<u>**Table of Contents**</u>**](#table_of_contents)

**Continental Resources, Inc. and Subsidiaries**

**Notes to Consolidated Financial Statements**

**Note 16. Shareholders' Equity Attributable to Continental Resources**

***Common Stock***

As of December 31, 2023, the Company had one class of common stock, $0.01 par value, with 1,000,000,000 shares authorized and 299,610,267 shares issued and outstanding. As of December 31, 2023 all shares of common stock were held by the Hamm Family.

In December 2024, the Company amended its Certificate of Incorporation to create Class A Common Stock and Class B Common Stock. The Class A Common Stock has a par value of $0.01 per share, with 400,000 shares authorized and includes voting rights. The Class B Common Stock has a par value of $0.01 per share, with 400,000,000 shares authorized and does not include voting rights. Except for the difference in voting rights, the Class A and Class B shares have the same rights and privileges, rank equally, and are identical in all respects. In December 2024, the Company entered into a share exchange agreement with shareholders of the Hamm Family to exchange their existing common shares into the newly designated Class A voting shares and Class B non-voting shares. The voting control and total equity ownership percentages of each individual shareholder remained the same before and after the share exchange.

As of December 31, 2025 and 2024 all shares of Class A and Class B Common Stock were held by the Hamm Family. As of December 31, 2025 and 2024, the Company had 187,256 shares issued and outstanding of Class A Common Stock and 299,423,011 shares issued and outstanding of Class B Common Stock.

***Dividend Payments***

During the years ended December 31, 2025, 2024, and 2023 the Company paid $0.6 million, $2.3 million, and $2.1 million of dividends, respectively, to employees upon vesting of long-term incentive units which had accumulated dividends declared in periods prior to the take-private transaction.

**Note 17. Noncontrolling Interests**

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"). Under the arrangement, Continental funds 20% of 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 $339.8 million and $348.8 million at December 31, 2025 and 2024, respectively.

**Note 18. Equity Investment**

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 United States. The project is in the design, permitting, and preliminary construction phases.

During the years ended December 31, 2025, 2024, and 2023 the Company contributed $21.3 million, $21.5 million, and $32.8 million, respectively, and continues to provide additional funding to Summit from time to time. The Company's investment in Summit had a carrying value of $258.9 million and $256.0 million at December 31, 2025 and 2024, respectively, which is included in the caption "Investment in unconsolidated affiliates" in the consolidated balance sheets.

The Company has board representation and holds an approximate 22% non-controlling ownership interest in the equity of Summit Carbon Holdings, the parent company of Summit Carbon Solutions, and thus has significant influence over the entity. The Company is not the primary beneficiary of Summit and accounts for its investment under the equity method of accounting. The Company's share of earnings/losses from its investment was immaterial for the years ended December 31, 2025, 2024, and 2023.

------

[**<u>**Table of Contents**</u>**](#table_of_contents)

**Continental Resources, Inc. and Subsidiaries**

**Notes to Consolidated Financial Statements**

**Note 19. Capitalized Exploratory Well Costs** 

Under the successful efforts method of accounting, the costs of drilling an exploratory well are capitalized pending determination of whether proved reserves can be attributed to the discovery. When initial drilling and completion operations are complete, management attempts to determine whether the well has discovered crude oil and natural gas reserves and, if so, whether those reserves can be classified as proved reserves. Often, the determination of whether proved reserves can be recorded under SEC guidelines cannot be made when drilling is completed. In those situations where management believes that economically producible hydrocarbons have not been discovered, the exploratory drilling costs are reflected on the consolidated statements of income as dry hole costs, a component of "Exploration expenses." Where sufficient hydrocarbons have been discovered to justify further exploration or appraisal activities, exploratory drilling costs are deferred under the caption "Net property and equipment" on the consolidated balance sheets pending the outcome of those activities.

On a periodic 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,** | **Year ended December 31,** | **Year ended December 31,** |
| ***In thousands*** | **2025** | **2024** | **2023** |
| Balance at January 1 | $173446 | $159734 | $84822 |
| Additions to capitalized exploratory well costs pending determination of proved reserves | 638686 | 449747 | 345434 |
| Reclassification to proved crude oil and natural gas properties based on the determination of proved reserves | (627257) | (435333) | (270490) |
| Capitalized exploratory well costs charged to expense | (689) | (702) | (32) |
| Balance at December 31 | $184186 | $173446 | $159734 |
| Number of gross wells | 34 | 42 | 34 |

---

As of December 31, 2025, the Company had no significant exploratory well costs that were suspended one year beyond the completion of drilling.

**Note 20. Supplemental Crude Oil and Natural Gas Information (Unaudited)**

The table below provides 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 97%, 97%, and 99% of the Company's total proved reserves as of December 31, 2025, 2024, and 2023, respectively. Remaining reserve estimates were prepared by the Company's internal technical staff.

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, 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. There are numerous uncertainties inherent in estimating quantities of proved crude oil and natural gas reserves. 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, and estimates of engineers other than the Company's might differ materially from the estimates set forth herein. 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.

Reserves at December 31, 2025, 2024, and 2023 were computed using the 12-month unweighted average of the first-day-of-the-month commodity prices as required by SEC rules. All proved reserves stated herein are located in the United States. Proved reserves attributable to noncontrolling interests are not material relative to the Company's consolidated reserves and are not separately

------

[**<u>**Table of Contents**</u>**](#table_of_contents)

**Continental Resources, Inc. and Subsidiaries**

**Notes to Consolidated Financial Statements**

presented. Natural gas imbalance receivables and payables for each of the three years ended December 31, 2025, 2024, and 2023 were not material and have not been included in the reserve estimates.

*Proved crude oil and natural gas reserves*

The following information sets forth the estimated quantities of proved developed and proved undeveloped crude oil and natural gas reserves of the Company as of December 31, 2025, 2024, and 2023.

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 reserves 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,** | **December 31,** | **December 31,** |
|  | **2025** | **2024** | **2023** |
| Proved Developed Reserves |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Crude oil (MBbl) | 388667 | 408394 | 401851 |
| &nbsp;&nbsp;&nbsp;&nbsp;Natural Gas (MMcf) | 3485281 | 3308345 | 3221566 |
| &nbsp;&nbsp;&nbsp;&nbsp;Total (MBoe) | 969548 | 959785 | 938779 |
| Proved Undeveloped Reserves |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Crude oil (MBbl) | 342365 | 430512 | 512183 |
| &nbsp;&nbsp;&nbsp;&nbsp;Natural Gas (MMcf) | 2414070 | 2607079 | 2376765 |
| &nbsp;&nbsp;&nbsp;&nbsp;Total (MBoe) | 744710 | 865025 | 908310 |
| Total Proved Reserves |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Crude oil (MBbl) | 731032 | 838906 | 914034 |
| &nbsp;&nbsp;&nbsp;&nbsp;Natural Gas (MMcf) | 5899351 | 5915424 | 5598331 |
| &nbsp;&nbsp;&nbsp;&nbsp;Total (MBoe) | 1714258 | 1824810 | 1847089 |

---

------

[**<u>**Table of Contents**</u>**](#table_of_contents)

**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, 2025 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.

**Changes in Internal Control over Financial Reporting**

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 2025 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 2025 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

------

[**<u>**Table of Contents**</u>**](#table_of_contents)

**Management's Report on Internal Control Over Financial Reporting**

**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, 2025.

/s/ Robert D. Lawler

President and Chief Executive Officer

/s/ John D. Hart

Chief Financial Officer and Executive Vice President of Strategic Planning

February 23, 2026

------

[**<u>**Table of Contents**</u>**](#table_of_contents)

**Item 9B. Other Information**

Not applicable.

**Item 9C. Disclosure Regarding Foreign Jurisdictions that Prevent Inspections**

Not applicable.

------

[**<u>**Table of Contents**</u>**](#table_of_contents)

**PART III**

**Item 10. Directors, Executive Officers and Corporate Governance Information About Our Executive Officers**

Our current executive officers are named below:

---

| | | |
|:---|:---|:---|
| Name | Age | Position |
| Harold G. Hamm | 80 | Chairman Emeritus |
| Shelly Lambertz  | 59 | Executive Chairman |
| Robert D. ("Doug") Lawler  | 59 | President and Chief Executive Officer and Director  |
| John D. Hart  | 58 | Chief Financial Officer and Executive Vice President of Strategic Planning  |
| Michael Aaron Chang | 38 | Chief Operating Officer |
| Jeffrey B. Hume  | 74 | Vice-Chairman, Corporate Strategic Growth  |
| James R. Webb  | 58 | Executive Vice President, General Counsel, Chief Administrative Officer and Secretary |
| Robert Hagens  | 67 | Senior Vice President, Commercial Development |

---

**Harold G. Hamm** is our Chairman Emeritus, a position he has held since August 19, 2025. Prior to then, he served as Executive Chairman, a position he held from November 2022 to August 19, 2025. Mr. Hamm served as our 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 board 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.

**Shelly Lambertz** is our Executive Chairman, a position she has held since August 19, 2025. Prior to this, she served as our Executive Vice President, Chief Culture and Administrative Officer, a position she held from January 12, 2022 to August 19, 2025. Ms. Lambertz 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 began her career working for the U.S. House of Representatives 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.

**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

------

[**<u>**Table of Contents**</u>**](#table_of_contents)

Oklahoma City Chamber of Commerce and serves as Chairman of the Casady School Board of Trustees. 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.

**Michael Aaron Chang** is our Chief Operating Officer, a position he has held since March 31, 2025. Prior to this, he served as Vice President, Anadarko Basin from July 2022 to March 31, 2025. From June 2020 to July 2022, he served as Vice President of Oil & Gas Marketing. Mr. Chang joined the company in April 2017 as part of our Marketing department until he returned to operations in 2022. Mr. Chang has extensive experience in the oil and gas industry, spanning both the midstream and upstream sectors in engineering, commercial, and operational roles. Mr. Chang graduated from Oklahoma State University with a Bachelor of Science in Chemical Engineering.

**Jeffrey B. Hume** is our Vice Chairman, Corporate Strategic Growth, a position he has held since March 19, 2025. Prior to this, he served as our Vice Chairman of Strategic Growth Initiatives, a position he held from June 2012 to March 19, 2025. 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 our Executive Vice President, General Counsel, Chief Administrative Officer and Secretary, a position he has held since August 19, 2025. Prior to this, he served as our Senior Vice President, General Counsel, and Secretary, a position he held from November 2022 to August 19, 2025. 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, a 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 and Insider Trading Policy**

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 adopted the current version of our Code of Business Conduct in January 2026. The Code of Business Conduct is reviewed annually in order to evaluate whether further revisions are necessary or desirable. The Code of Business Conduct is applicable to all employees, officers, and directors, including our principal executive, financial, and accounting officers.

The Company has an Insider Trading Policy governing the purchase, sale and other dispositions of its securities by directors, officers, employees, and contractors that is reasonably designed to promote compliance with insider trading laws, rules and regulations. The Insider Trading Policy is filed with this Form 10-K as Exhibit 19.

**Material Changes to Procedures for Nominating Directors** 

Not Applicable.

------

[**<u>**Table of Contents**</u>**](#table_of_contents)

**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 listed on the NYSE, our Audit Committee is not required to have an Audit Committee financial expert.

**Item 11. Executive Compensation**

**2025 Compensation Discussion and Analysis and Executive Officer Compensation** 

*<u>Introduction</u>*

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 2025. These individuals are identified below and are referred to collectively in the discussion below as the "NEOs" for 2025. The discussion summarizes our compensation philosophy and the different components of our compensation program and provides information regarding the financial statement impact for 2025 associated with the compensation program for our NEOs.

Our NEOs for 2025 (determined in accordance with the requirements of Item 402 of Regulation S-K) are:

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•Shelly Lambertz, Executive Chairman;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•Robert D. ("Doug") Lawler, President and Chief Executive Officer;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•John D. Hart, Chief Financial Officer and Executive Vice President of Strategic Planning;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•James R. Webb, Executive Vice President, General Counsel, Chief Administrative Officer and Secretary; and

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;•Michael Aaron Chang, Chief Operating Officer.

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.

*<u>Executive Compensation Philosophy</u>*

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 2025, our Chairman Emeritus, Executive Chairman, and President and Chief Executive 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 the Management Compensation Group. The Management Compensation Group's analysis consisted of comparing the market data of base salary, cash bonus, long-term incentive awards, and total compensation 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.

*<u>Role of Management</u>*

The Management Compensation Group is responsible for overseeing all aspects of our benefit and compensation plans and programs for our executive officers. For 2025, 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 change in control or severance obligations that are out of line with market norms. Mr. Lawler does have an agreement on market terms specifying what Mr. Lawler will receive in the event he is terminated: (x) for reasons other than cause, disability, or death; (y) for good reason during a transition period following customary specified events; and (z) for

------

[**<u>**Table of Contents**</u>**](#table_of_contents)

cause, death, or disability. Given Mr. Lawler's key role within the Company's business, the Company determined it was important for retention purposes to provide Mr. Lawler with customary market protection in relation to these types of events.

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.

*<u>Role of Compensation Consultants</u>*

For 2025, 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 2025, Meridian was consulted on select compensation questions, but did not have the level of involvement in providing benchmarking, market data and compensation structure recommendations as it had in prior years. Instead, the Company's human resources team used various paid and publicly available resources to provide this type of information to the Management Compensation Group. During 2025, 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.

*<u>Description of Executive Officer Compensation Program</u>*

*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.<br>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.<br>Allows the Management Compensation Group to evaluate both objective and subjective considerations when exercising discretion to determine final payout amounts.<br>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 | 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 and/or providing an incentive for an executive to stay with the Company over the long-term.<br>Important to the Company's ability to attract, motivate, and retain the Company's executive officers. |

---

------

[**<u>**Table of Contents**</u>**](#table_of_contents)

*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 2025 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 2025, 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 2025, the Company match was in effect the entire year.

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 the overall performance 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 discourage 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 best 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 long-term performance of our Company.

The aggregate total amount of annual compensation-related expenses recognized in the Company's financial statements related to the 2025 compensation of the NEOs as a group represented less than 2% of our total income from operations, our total operating cash flows and our total liabilities as of and for the year ended December 31, 2025.

------

[**<u>**Table of Contents**</u>**](#table_of_contents)

**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 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/ Shelly Lambertz | /s/ Harold G. Hamm | /s/ Robert D. Lawler |
| Shelly Lambertz<br>Executive Chairman and Director | Harold G. Hamm<br>Chairman Emeritus and Director | Robert D. Lawler<br>President, Chief Executive Officer and Director |

---

**Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters**

As a result of the completion of the take-private transaction, the Company is 100% owned by the Hamm Family. As a result, none of our directors and/or executive officers who are not members of the Hamm Family have any security ownership reportable to this item.

**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 the 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. The standard for review and approval of related party transactions under our current structure is substantially the same as applied prior to the take private transaction. None of the transactions reviewed by the full Audit Committee since December 31, 2022 are transactions in which the related party had a direct or indirect material interest, and so are not discussed in detail in this filing. The stock redemption agreement described in *Note 13. Commitments and Contingencies*—*Stock Redemption Agreement* was approved by the sole disinterested member of the Audit Committee.

------

[**<u>**Table of Contents**</u>**](#table_of_contents)

**Item 14. Principal Accountant Fees and Services**

Grant Thornton served as our independent registered public accounting firm during 2025 and 2024. The aggregate fees for various services performed by Grant Thornton for the years ended December 31, 2025 and 2024 are set forth below:

---

| | | |
|:---|:---|:---|
|  | 2025 | 2024 |
| Audit Fees | $1090000 | $1011000 |
| Audit-Related Fees |  |  |
| Tax Fees |  |  |
| All Other Fees |  |  |
| Total Fees | $1090000 | $1011000 |

---

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 Audit 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 Audit Committee to approve services and fees in advance and requires documentation regarding the specific services to be performed. All 2025 audit fees were approved in advance in accordance with the Audit Committee's policies.

------

[**<u>**Table of Contents**</u>**](#table_of_contents)

**PART IV**

**Item 15. Exhibits and Financial Statement Schedules**

*(1) Financial Statements*

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.

*(2) Financial Statement Schedules*

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.

*(3) Index to Exhibits* 

The exhibits required to be filed or furnished pursuant to Item 601 of Regulation S-K are set forth below.

---

| | |
|:---|:---|
| &nbsp;&nbsp;3.1 | &nbsp;&nbsp;[<u>Conformed version of Seventh Amended and Restated Certificate of Incorporation of Continental Resources, Inc. filed as Exhibit 3.1 to the Company's Form 10-K for the year ended December 31, 2024 (Commission File No. 001-32886) filed February 23, 2025 and incorporated herein by reference.</u>](https://www.sec.gov/Archives/edgar/data/732834/000095017025025741/ck0000732834-ex3_1.htm) |
| &nbsp;&nbsp;3.2 | &nbsp;&nbsp;[<u>Sixth Amended and Restated Bylaws of Continental Resources, Inc. filed as Exhibit 3.2 to the Company's Form 10-Q for the quarter ended September 30, 2024 (Commission File No. 001-32886) filed November 12, 2024 and incorporated herein by reference.</u>](https://www.sec.gov/Archives/edgar/data/732834/000095017024124720/ck0000732834-ex3_2.htm) |
| &nbsp;&nbsp;4.1 | &nbsp;&nbsp;[<u>Indenture dated as of May 19, 2014 among Continental Resources, Inc., Banner Pipeline Company, L.L.C., CLR Asset Holdings, LLC and Wilmington Trust, National Association, as trustee, filed as Exhibit 4.1 to the Company's Current Report on Form 8-K (Commission File No. 001-32886) filed May 22, 2014 and incorporated herein by reference.</u>](https://www.sec.gov/Archives/edgar/data/732834/000119312514209880/d730049dex41.htm) |
| &nbsp;&nbsp;4.2 | &nbsp;&nbsp;[<u>Indenture dated as of December 8, 2017 among Continental Resources, Inc., Banner Pipeline Company, L.L.C., CLR Asset Holdings, LLC, The Mineral Resources Company and Wilmington Trust, National Association, as trustee, filed as Exhibit 4.1 to the Company's Current Report on Form 8-K (Commission File No. 001-32886) filed December 12, 2017 and incorporated herein by reference.</u>](https://www.sec.gov/Archives/edgar/data/732834/000119312517367465/d470946dex41.htm) |
| &nbsp;&nbsp;4.3 | &nbsp;&nbsp;[<u>Indenture dated as of November 25, 2020 among Continental Resources, Inc., Banner Pipeline Company, L.L.C., CLR Asset Holdings, LLC, The Mineral Resources Company and Wilmington Trust, National Association, as trustee, filed as Exhibit 4.1 to the Company's Current Report on Form 8-K (Commission File No. 001-32886) filed November 25, 2020 and incorporated herein by reference.</u>](https://www.sec.gov/Archives/edgar/data/732834/000119312520303612/d41194dex41.htm) |
| &nbsp;&nbsp;4.4 | &nbsp;&nbsp;[<u>Indenture dated as of November 22, 2021 among Continental Resources, Inc., Banner Pipeline Company, L.L.C., CLR Asset Holdings, LLC, The Mineral Resources Company and Wilmington Trust, National Association, as trustee, filed as Exhibit 4.1 to the Company's Current Report on Form 8-K (Commission File No. 001-32886) filed November 22, 2021 and incorporated herein by reference.</u>](https://www.sec.gov/Archives/edgar/data/732834/000119312521336930/d214782dex41.htm) |
| &nbsp;&nbsp;10.1 | &nbsp;&nbsp;[<u>Revolving Credit Agreement dated as of October 29, 2024 by and among (i) Continental Resources, Inc. as borrower, (ii) Banner Pipeline Company, L.L.C., CLR Asset Holdings, LLC, The Mineral Resources Company, Continental Innovations LLC, SCS1 Holdings LLC, Jagged Peak Energy LLC and Parsley SoDe Water LLC, as guarantors, (iii) MUFG Bank, LTD., as administrative agent, and (iv) the banks and other financial institutions party thereto as lenders filed as Exhibit 10.1 to the Company's Form 10-Q for the quarter ended September 30, 2024 (Commission File No. 001-32886) filed November 12, 2024 and incorporated herein by reference.</u>](https://www.sec.gov/Archives/edgar/data/732834/000095017024124720/ck0000732834-ex10_1.htm) |
| &nbsp;&nbsp;10.2†<br>| &nbsp;&nbsp;[<u>Continental Resources, Inc. Deferred Compensation Plan filed as Exhibit 10.2 to the Company's Form 10-Q for the quarter ended September 30, 2018 (Commission File No. 001-32886) filed October 29, 2018 and incorporated herein by reference.</u>](https://www.sec.gov/Archives/edgar/data/732834/000073283418000012/clr3q2018-ex10ii.htm) |

---

------

[**<u>**Table of Contents**</u>**](#table_of_contents)

---

| | |
|:---|:---|
| &nbsp;&nbsp;10.3†<br>| &nbsp;&nbsp;[<u>First Amendment to the Continental Resources, Inc. Deferred Compensation Plan filed as Exhibit 10.1 to the Company's Form 10-Q for the quarter ended March 31, 2014 (Commission File No. 001-32886) filed May 8, 2014 and incorporated herein by reference.</u>](https://www.sec.gov/Archives/edgar/data/732834/000073283414000006/ex101fy2014q1.htm) |
| &nbsp;&nbsp;10.4†<br>| &nbsp;&nbsp;[<u>Second Amendment to the Continental Resources, Inc. Deferred Compensation Plan adopted and effective as of May 23, 2014 filed as Exhibit 10.15 to the Company's Registration Statement on Form S-4 (Commission File No. 333-196944) filed June 20, 2014 and incorporated herein by reference.</u>](https://www.sec.gov/Archives/edgar/data/732834/000119312514243931/d731079dex1015.htm) |
| &nbsp;&nbsp;10.5†<br>| &nbsp;&nbsp;[<u>Continental Resources, Inc. Second Amended and Restated 2022 Long-Term Incentive Plan filed as Exhibit 10.10 to the Company's Form 10-K for the year ended December 31, 2022 (Commission File No. 001-32886) filed February 22, 2023 and incorporated herein by reference.</u>](https://www.sec.gov/Archives/edgar/data/732834/000095017023003794/ck0000732834-ex10_10.htm) |
| &nbsp;&nbsp;10.6†<br>| &nbsp;&nbsp;[<u>Cash Award Agreement – Continental Resources, Inc. Second Amended and Restated 2022 Long-Term Incentive Plan filed as Exhibit 10.12 to the Company's Form 10-K for the year ended December 31, 2022 (Commission File No. 001-32886) filed February 22, 2023 and incorporated herein by reference.</u>](https://www.sec.gov/Archives/edgar/data/732834/000095017023003794/ck0000732834-ex10_12.htm) |
| &nbsp;&nbsp;19\* | &nbsp;&nbsp;[<u>Insider Trading Policy of Continental Resources, Inc.</u>](ck0000732834-ex19.htm) |
| &nbsp;&nbsp;21\* | &nbsp;&nbsp;[<u>Subsidiaries of Continental Resources, Inc.</u>](ck0000732834-ex21.htm) |
| &nbsp;&nbsp;31.1\* | &nbsp;&nbsp;[<u>Certification of the Company's Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (15 U.S.C. Section 7241)</u>](ck0000732834-ex31_1.htm) |
| &nbsp;&nbsp;31.2\* | &nbsp;&nbsp;[<u>Certification of the Company's Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (15 U.S.C. Section 7241)</u>](ck0000732834-ex31_2.htm) |
| &nbsp;&nbsp;99\* | &nbsp;&nbsp;[<u>Report of Ryder Scott Company, L.P., Independent Petroleum Engineers and Geologists</u>](ck0000732834-ex99.htm) |
| &nbsp;&nbsp;101.INS\* | &nbsp;&nbsp;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 |
| &nbsp;&nbsp;101.SCH\* | &nbsp;&nbsp;Inline XBRL Taxonomy Extension Schema With Embedded Linkbases Document |
| &nbsp;&nbsp;104 | &nbsp;&nbsp;Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101)<br>|

---

\* Filed herewith

† Management contracts or compensatory plans or arrangements filed pursuant to Item 601(b)(10)(iii) of Regulation S-K.

------

[**<u>**Table of Contents**</u>**](#table_of_contents)

**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. | CONTINENTAL RESOURCES, INC. |
| **By:** | /S/ ROBERT D. LAWLER |
| **Name:** | **Robert D. Lawler** |
| **Title:** | **President, Chief Executive Officer, and Director** |
| **Date:** | **February 23, 2026** |

---

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.

---

| | | |
|:---|:---|:---|
| &nbsp;&nbsp;**<u>Signature</u>** | &nbsp;&nbsp;**<u>Title</u>** | &nbsp;&nbsp;**<u>Date</u>** |
| &nbsp;&nbsp;/s/ HAROLD G. HAMM | &nbsp;&nbsp;Chairman Emeritus and Director | &nbsp;&nbsp;February 23, 2026 |
| &nbsp;&nbsp;**Harold G. Hamm** |  |  |
| &nbsp;&nbsp;/s/ SHELLY LAMBERTZ | &nbsp;&nbsp;Executive Chairman and Director | &nbsp;&nbsp;February 23, 2026 |
| &nbsp;&nbsp;**Shelly Lambertz** |  |  |
| &nbsp;&nbsp;/s/ ROBERT D. LAWLER | &nbsp;&nbsp;President, Chief Executive Officer, and Director<br>(principal executive officer) | &nbsp;&nbsp;February 23, 2026 |
| &nbsp;&nbsp;**Robert D. Lawler** |  |  |
| &nbsp;&nbsp;/s/ JOHN D. HART | &nbsp;&nbsp;Chief Financial Officer and Executive Vice President of Strategic Planning<br>(principal financial and accounting officer) | &nbsp;&nbsp;February 23, 2026 |
| &nbsp;&nbsp;**John D. Hart** |  |  |

---

------

## Ex-19

**Exhibit 19**

**Insider Trading Policy** 

Securities laws make it illegal for you to trade in a company's securities when you have access to "material, nonpublic information" relating to a company. This conduct is referred to as "insider trading" and may result in civil or criminal penalties.

**<u>Trading Restrictions</u>**

If a Continental director, officer, employee, or contractor has material, non-public information related to Continental, that person is an "insider" as to that information, and that person must not trade in Continental debt securities until the information is generally publicly available. Insiders must also avoid "tipping." If you share material, non-public information with someone else, or recommend they trade in Continental debt securities while you have such information, and they trade on your information or recommendation, then both you and they can be held liable for insider trading.

Trading restrictions also apply if you obtain material, non-public information or analyses relating to any other company (including but not limited to vendors, suppliers, partners, other oil and gas companies, and customers). You must not trade in that company's securities while possessing information that is material and non-public with respect to that other company.

Continental maintains additional restrictions on trading Continental debt securities by directors, officers, and certain other employees who are presumed to have material, non-public information at certain times (Covered Employees), regardless of whether they possess such information. Those additional restrictions are outlined below.

**<u>Key Terms</u>**

&nbsp;&nbsp;&nbsp;&nbsp;•**Who is an "Insider"?**

Any person who possesses material, non-public information is considered an "insider" as to that information.

&nbsp;&nbsp;&nbsp;&nbsp;•**What is "Material Information"?**

Information is material if there is a substantial likelihood that a reasonable investor would consider it important in making a decision to buy, sell, or hold a security, or where the information is likely to affect the market price of the security. Material information can be positive or negative. It can relate to virtually any aspect of a company's business or to any type of security (e.g., debt or equity).

Some examples of potentially material information include:

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;▪Unpublished financial or operational results or projections, including earnings information;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;▪Pending, evaluated or proposed mergers, acquisitions, divestitures, tender offers, or other transactions;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;▪Significant changes in corporate objectives, debt ratings, dividend or stock repurchase policies; and

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;▪Significant changes in financial liquidity.

This list is only illustrative. Whether information is material depends upon the circumstances. If you are unsure whether particular non-public information is material, you should consult with the Legal Department before disclosing that information or trading in a company's securities.

**1**

------

**Insider Trading Policy**

&nbsp;&nbsp;&nbsp;&nbsp;•**What is "Non-public Information"?**

Information is non-public if it has not been disclosed generally to the public. Information becomes public only after it is disclosed in a press release, in a company's public filings with the Securities and Exchange Commission, or otherwise widely disseminated in a manner making it generally available to investors through media. In addition, reasonable time must pass to allow the market to absorb the information.

&nbsp;&nbsp;&nbsp;&nbsp;•**What are "Securities"?**

Securities include shares of stock and derivative securities (such as futures, calls, options, puts, warrants), debt securities, and any other rights to exchange or acquire stock.

&nbsp;&nbsp;&nbsp;&nbsp;•**What does it mean to "trade"?**

Trading not only includes purchases and sales, but any agreement to acquire or dispose of a security, such as conversions and the exercise of warrants or puts, calls or other options related to a security, with or without the assistance of a broker.

&nbsp;&nbsp;&nbsp;&nbsp;•**What is "tipping"?**

Tipping involves sharing material non-public information, or making trading recommendations while possessing such information, to someone who then trades on that information or recommendation.

**<u>Guidelines for All Employees</u>**

&nbsp;&nbsp;&nbsp;&nbsp;•Do not trade in Continental debt securities if you have material, non-public information about Continental. This includes trades on your own account, through a broker, or through another person's account (such as a family or household member).

&nbsp;&nbsp;&nbsp;&nbsp;•Do not make trading recommendations or act as a "tipper" while you possess material, non-public information.

&nbsp;&nbsp;&nbsp;&nbsp;•Do not trade in the securities of a Continental business associate or another company if you gain access to material non-public information related to that company or its securities.

&nbsp;&nbsp;&nbsp;&nbsp;•Remember that separation of employment does not end your legal responsibilities. If your employment or other relationship with Continental terminates at a time when you have material non-public information regarding Continental or its business associates, the law still prohibits you from trading until the information becomes public.

&nbsp;&nbsp;&nbsp;&nbsp;•Warn consultants and advisors you engage for Continental. If you engage a third-party consultant for Continental, you should warn them about the potential for them to gain access to material non-public information that would prohibit them from trading.

&nbsp;&nbsp;&nbsp;&nbsp;•Warn your broker or investment manager. Similarly, if you work with a broker or other investment manager, you should warn them there can be no trading on your personal account without first getting your permission to ensure you avoid a trade occurring on your behalf while you have insider information.

&nbsp;&nbsp;&nbsp;&nbsp;•Do not share confidential information outside the company. If you have material, non-public information about Continental, or about other individuals or companies with which Continental has an existing or contemplated business relationship, don't share it outside the company, even with your family and members of your household.

**2**

------

**Insider Trading Policy**

&nbsp;&nbsp;&nbsp;&nbsp;•Make sure a business need exists before disclosing any material, non-public information. If you believe disclosure is necessary to perform your job duties, make sure a confidentiality agreement exists before disclosure. Ask the Legal Department if you are unsure whether disclosure is necessary.

## <u>Additional Restrictions on Covered Employees</u> 
&nbsp;&nbsp;&nbsp;&nbsp;•**Who are Covered Employees?**

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;▪Members of our Board of Directors;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;▪Executive Vice Presidents, Senior Vice Presidents, Vice Presidents, and their assistants;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;▪Members of the Legal Department;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;▪Designated employees in departments with routine access to material, non-public information about Continental as part of their day-to-day responsibilities; and

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;▪Other employees identified from time to time by the Legal Department.

Covered Employees also include such employees' family and household members, trusts of which a Covered Employee is a trustee or beneficiary, estates of which a Covered Employee is an executor, and entities owned or controlled by a Covered Employee. If a description of your role doesn't appear above, the Legal Department will notify you if you are a Covered Employee. If your role is described above, you should assume you are a Covered Employee as long as you remain in that role. Even if you stop serving in a role identified above, you should observe the restrictions described below as long as you continue to possess material, non-public information gained while serving in that capacity.

&nbsp;&nbsp;&nbsp;&nbsp;•**Blackout Periods for Covered Employees**

In addition to being prohibited from trading while in possession of material, non-public information, Covered Employees are also prohibited from conducting certain trades in Continental debt securities during any "Blackout Period." Blackout Periods commence the last three (3) business days of the last month of a fiscal calendar quarter and continue until twenty-four (24) hours after the release of quarterly or annual financial information, as applicable. During a Blackout Period, Covered Employees must not buy, sell, or otherwise trade in Continental's debt securities or change their investment decisions regarding Continental's debt securities.

&nbsp;&nbsp;&nbsp;&nbsp;•**Mandatory Pre-Clearance Procedures for Covered Employees**

Outside of Blackout Periods, Covered Employees who wish to trade Continental debt securities must first obtain pre-approval to trade from the Legal Department.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;▪A pre-clearance request should be submitted to the Legal Department using the Pre-clearance Request Form located on the company's intranet.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;▪After receiving a pre-clearance request, the Legal Department will determine whether to approve the proposed transaction and will promptly notify the Covered Employee of the determination.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;▪To comply with the law and/or Continental policy, the Legal Department, in its discretion, may withhold approval for a Covered Employee's proposed transaction.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;▪When given, clearance to trade will be only for a specified time period, and any trades must take place within that time period.

**3**

------

**Insider Trading Policy**

&nbsp;&nbsp;&nbsp;&nbsp;•**Rule 10b5-1 Trading Plans**

Any Covered Employee who wishes to implement a Rule 10b5-1 Plan (in order to obtain an affirmative defense to insider trading) must obtain pre-approval from the Legal Department.

&nbsp;&nbsp;&nbsp;&nbsp;•**Speculative Trading Prohibited by Covered Employees**

Covered Employees are prohibited from engaging in any speculative transactions involving Continental debt securities, including: (1) buying or selling puts or calls or otherwise hedging against changes in the value of company securities; and (2) short sales of company securities.

**4**

------

## Ex-21

**Exhibit 21**

SUBSIDIARIES OF CONTINENTAL RESOURCES, INC.

20 Broadway Associates LLC, an Oklahoma limited liability company

Banner Pipeline Company, L.L.C., an Oklahoma limited liability company

CLR Asset Holdings, LLC, an Oklahoma limited liability company

SFPG, LLC, an Oklahoma limited liability company\*

The Mineral Resources Company LLC, an Oklahoma limited liability company

The Mineral Resources Company II, LLC, a Delaware limited liability company\*

Jagged Peak Energy LLC, a Delaware limited liability company

Parsley SoDe Water LLC, a Delaware limited liability company

Continental Innovations LLC, an Oklahoma limited liability company

SCS1 Holdings LLC, an Oklahoma limited liability company

Continental Resources Argentina S.A.U, a sociedad anónima unipersonal organized and validly existing under the laws of the Republic of Argentina

Continental Resources Turkey Petrol Arama ve Üretim Limited Şirketi

\* Ownership is less than 100%.

------

## Exhibit 31.1

**Exhibit 31.1**

**Certification of the Company's Chief Executive Officer Pursuant to**

**Section 302 of the Sarbanes-Oxley Act of 2002 (15 U.S.C. Section 7241)**

I, Robert D. Lawler, certify that:

1. I have reviewed this report on Form 10-K for the period ended December 31, 2025 of Continental Resources, Inc. ("Registrant");

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the Registrant as of, and for, the periods presented in this report;

4. The Registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the Registrant and have:

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(a)Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the Registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(b)Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(c)Evaluated the effectiveness of the Registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(d)Disclosed in this report any change in the Registrant's internal control over financial reporting that occurred during the Registrant's most recent fiscal quarter (the Registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the Registrant's internal control over financial reporting; and

5. The Registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the Registrant's auditors and the audit committee of the Registrant's board of directors:

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(a)All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the Registrant's ability to record, process, summarize and report financial information; and

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(b)Any fraud, whether or not material, that involves management or other employees who have a significant role in the Registrant's internal control over financial reporting.

Date: February 23, 2026

---

| |
|:---|
| /s/ Robert D. Lawler |
| **Robert D. Lawler** |
| **President and Chief Executive Officer** |

---

------

## Exhibit 31.2

**Exhibit 31.2**

**Certification of the Company's Chief Financial Officer Pursuant to**

**Section 302 of the Sarbanes-Oxley Act of 2002 (15 U.S.C. Section 7241)**

I, John D. Hart, certify that:

1. I have reviewed this report on Form 10-K for the period ended December 31, 2025 of Continental Resources, Inc. ("Registrant");

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the Registrant as of, and for, the periods presented in this report;

4. The Registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the Registrant and have:

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(a)Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the Registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(b)Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(c)Evaluated the effectiveness of the Registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(d)Disclosed in this report any change in the Registrant's internal control over financial reporting that occurred during the Registrant's most recent fiscal quarter (the Registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the Registrant's internal control over financial reporting; and

5. The Registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the Registrant's auditors and the audit committee of the Registrant's board of directors:

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(a)All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the Registrant's ability to record, process, summarize and report financial information; and

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(b)Any fraud, whether or not material, that involves management or other employees who have a significant role in the Registrant's internal control over financial reporting.

Date: February 23, 2026

---

| |
|:---|
| /s/ John D. Hart |
| **John D. Hart** |
| **Chief Financial Officer and Executive Vice President of Strategic Planning** |

---

------

## Ex-99

**Exhibit 99**

---

| | |
|:---|:---|
| ![img215251112_0.jpg](img215251112_0.jpg) | ![img215251112_1.jpg](img215251112_1.jpg) |
|  | TBPELS REGISTERED ENGINEERING FIRM F-1580 |
|  | 633 17TH STREET SUITE 1700 DENVER, COLORADO 80202 TELEPHONE (303) 339-8110<br>|

---

January 8, 2026

Continental Resources, Inc.

20 North Broadway

Oklahoma City, Oklahoma 73102

Ladies and Gentlemen:

At your request, Ryder Scott Company, L.P. (Ryder Scott) has prepared an estimate of the proved reserves, future production, and income attributable to certain leasehold and royalty interests of Continental Resources, Inc. (Continental) as of December 31, 2025. The subject properties are located in the states of Louisiana, Montana, North Dakota, New Mexico, Oklahoma, South Dakota, Texas, and Wyoming. The reserves and income data were estimated based on the definitions and disclosure guidelines of the United States Securities and Exchange Commission (SEC) contained in Title 17, Code of Federal Regulations, Modernization of Oil and Gas Reporting, Final Rule released January 14, 2009 in the Federal Register (SEC regulations). Our third party study, completed on January 8, 2026 and presented herein, was prepared for public disclosure by Continental in filings made with the SEC in accordance with the disclosure requirements set forth in the SEC regulations.

The properties evaluated by Ryder Scott account for a portion of Continental's total net proved reserves as of December 31, 2025. Based on information provided by Continental, the third party estimate conducted by Ryder Scott addresses approximately 92 percent of the total proved developed net liquid hydrocarbon reserves, 94 percent of the total proved developed net gas reserves, 100 percent of the total proved undeveloped net liquid hydrocarbon reserves, and 100 percent of the total proved undeveloped net gas reserves of Continental. When put in discounted cash flow terms, the reserves values evaluated represent 97 percent of Continental's total proved FNI discounted at 10 percent.

The estimated reserves and future net income amounts presented in this report, as of December 31, 2025, are related to hydrocarbon prices. The hydrocarbon prices used in the preparation of this report are based on the average prices during the 12-month period prior to the "as of date" of this report, determined as the unweighted arithmetic averages of the prices in effect on the first-day-of-the-month for each month within such period, unless prices were defined by contractual arrangements, as required by the SEC regulations. Actual future prices may vary considerably from the prices required by SEC regulations. The reserves volumes and the income attributable thereto have a direct relationship to the hydrocarbon prices actually received; therefore, volumes of reserves actually recovered and the amounts of income actually received may differ significantly from the estimated quantities presented in this report. The results of this study are summarized as follows.

------

**SEC PARAMETERS**

Estimated Net Reserves and Income Data

Certain Leasehold and Royalty Interests of

**Continental Resources, Inc.**

---

| | | | | |
|:---|:---|:---|:---|:---|
|  | As of December 31, 2025 | As of December 31, 2025 | As of December 31, 2025 | As of December 31, 2025 |
|  | Proved | Proved | Proved | Proved |
|  | Developed | Developed |  | Total |
|  | Producing | Non-Producing | Undeveloped | Proved |
| *<u>Net Reserves</u>* |  |  |  |  |
| Oil/Condensate – MBarrels | 353668 | 3257 | 341827 | 698752 |
| Gas - MMCF | 3232699 | 26057 | 2411346 | 5670102 |
| *<u>Income Data ($M)</u>* |  |  |  |  |
| Future Gross Revenue | $28317045 | $243063 | $26589446 | $55149552 |
| Deductions | 9169154 | 93385 | 13181336 | 22443878 |
| Future Net Income (FNI) | $19147891 | $149678 | $13408111 | $32705673 |
| Discounted FNI @ 10% | $11509842 | $80951 | $5669180 | $17259973 |

---

Liquid hydrocarbons are expressed in standard 42 U.S. gallon barrels and shown herein as thousands of barrels (MBarrels). All gas volumes are reported on an "as sold basis" expressed in millions of cubic feet (MMCF) at the official temperature and pressure bases of the areas in which the gas reserves are located. In this report, the revenues, deductions, and income data are expressed as thousands of U.S. dollars ($M).

The estimates of the reserves, future production, and income attributable to properties in this report were prepared using the economic software package ARIESTM Petroleum Economics and Reserves Software, a copyrighted program of Halliburton. The program was used at the request of Continental. Ryder Scott has found this program to be generally acceptable, but notes that certain summaries and calculations may vary due to rounding and may not exactly match the sum of the properties being summarized. Furthermore, one line economic summaries may vary slightly from the more detailed cash flow projections of the same properties, also due to rounding. The rounding differences are not material.

The future gross revenue is after the deduction of production taxes. The deductions incorporate the normal direct costs of operating the wells, recompletion costs, and development costs. The future net income is before the deduction of state and federal income taxes and general administrative overhead, and has not been adjusted for outstanding loans that may exist, nor does it include any adjustment for cash on hand or undistributed income.

Liquid hydrocarbon reserves account for approximately 73 percent and gas reserves account for the remaining 27 percent of total future gross revenue from proved reserves.

The discounted future net income shown above was calculated using a discount rate of 10 percent per annum compounded monthly. Future net income was discounted at four other discount rates which were also compounded monthly. These results are shown in summary form as follows.

---

| | |
|:---|:---|
|  | Discounted Future Net Income ($M) |
|  | As of December 31, 2025 |
| Discount Rate | Total |
| Percent | Proved |
| 5 | $22600100 |
| 15 | $13980800 |
| 20 | $11768867 |
| 25 | $10180068 |

---

The results shown above are presented for your information and should not be construed as our estimate of fair market value.

***Reserves Included in This Report***

The proved reserves included herein conform to the definition as set forth in the Securities and Exchange Commission's Regulations Part 210.4-10(a). An abridged version of the SEC reserves definitions from 210.4-10(a) entitled "PETROLEUM RESERVES DEFINITIONS" is included as an attachment to this report.

The various reserves status categories are defined in the attachment entitled "PETROLEUM RESERVES STATUS DEFINITIONS AND GUIDELINES" in this report. The proved developed non-producing reserves included herein consist of the behind pipe and shut-in status categories.

No attempt was made to quantify or otherwise account for any accumulated gas production imbalances that may exist. The proved gas volumes presented herein do not include volumes of gas consumed in operations as reserves.

------

Reserves are "estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations." All reserves estimates involve an assessment of the uncertainty relating the likelihood that the actual remaining quantities recovered will be greater or less than the estimated quantities determined as of the date the estimate is made. The uncertainty depends primarily on the amount of reliable geologic and engineering data available at the time of the estimate and the interpretation of these data. The relative degree of uncertainty may be conveyed by placing reserves into one of two principal categories, either proved or unproved. Unproved reserves are less certain to be recovered than proved reserves, and may be further sub-categorized as probable and possible reserves to denote progressively increasing uncertainty in their recoverability. At Continental's request, this report addresses only the proved reserves attributable to the properties evaluated herein.

Proved oil and gas reserves are "those quantities of oil and gas which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward." The proved reserves included herein were estimated using deterministic methods. The SEC has defined reasonable certainty for proved reserves, when based on deterministic methods, as a "high degree of confidence that the quantities will be recovered."

Proved reserves estimates will generally be revised only as additional geologic or engineering data become available or as economic conditions change. For proved reserves, the SEC states that "as changes due to increased availability of geoscience (geological, geophysical, and geochemical), engineering, and economic data are made to the estimated ultimate recovery (EUR) with time, reasonably certain EUR is much more likely to increase or remain constant than to decrease." Moreover, estimates of proved reserves may be revised as a result of future operations, effects of regulation by governmental agencies or geopolitical or economic risks. Therefore, the proved reserves included in this report are estimates only and should not be construed as being exact quantities, and if recovered, the revenues therefrom, and the actual costs related thereto, could be more or less than the estimated amounts.

Continental's operations may be subject to various levels of governmental controls and regulations. These controls and regulations may include, but may not be limited to, matters relating to land tenure and leasing, the legal rights to produce hydrocarbons, drilling and production practices, environmental protection, marketing and pricing policies, royalties, various taxes and levies including income tax and are subject to change from time to time. Such changes in governmental regulations and policies may cause volumes of proved reserves actually recovered and amounts of proved income actually received to differ significantly from the estimated quantities.

The estimates of proved reserves presented herein were based upon a detailed study of the properties in which Continental owns an interest; however, we have not made any field examination of the properties. No consideration was given in this report to potential environmental liabilities that may exist nor were any costs included for potential liabilities to restore and clean up damages, if any, caused by past operating practices.

***Estimates of Reserves***

The estimation of reserves involves two distinct determinations. The first determination results in the estimation of the quantities of recoverable oil and gas and the second determination results in the estimation of the uncertainty associated with those estimated quantities in accordance with the definitions set forth by the Securities and Exchange Commission's Regulations Part 210.4-10(a). The process of estimating the quantities of recoverable oil and gas reserves relies on the use of certain generally accepted analytical procedures. These analytical procedures fall into three broad categories or methods: (1) performance-based methods; (2) volumetric-based methods; and (3) analogy. These methods may be used individually or in combination by the reserves evaluator in the process of estimating the quantities of reserves. Reserves evaluators must select the method or combination of methods, which in their professional judgment is most appropriate given the nature and amount of reliable geoscience and engineering data available at the time of the estimate, the established or anticipated performance characteristics of the reservoir being evaluated, and the stage of development or producing maturity of the property.

In many cases, the analysis of the available geoscience and engineering data and the subsequent interpretation of this data may indicate a range of possible outcomes in an estimate, irrespective of the method selected by the evaluator. When a range in the quantity of reserves is identified, the evaluator must determine the uncertainty associated with the incremental quantities of the reserves. If the reserves quantities are estimated using the deterministic incremental approach, the uncertainty for each discrete incremental quantity of the reserves is addressed by the reserves category assigned by the evaluator. Therefore, it is the categorization of reserves quantities as proved, probable and/or possible that addresses the inherent uncertainty in the estimated quantities reported. For proved reserves, uncertainty is defined by the SEC as reasonable certainty wherein the "quantities actually recovered are much more likely to be achieved than not." The SEC states that "probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered." The SEC states that "possible reserves are those additional reserves that are less certain to be recovered than probable reserves and the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves." All quantities of reserves within the same reserves category must meet the SEC definitions as noted above.

Estimates of reserves quantities and their associated reserves categories may be revised in the future as additional geoscience or engineering data become available. Furthermore, estimates of reserves quantities and their associated reserves categories may also be revised due to other factors such as changes in economic conditions, results of future operations, effects of regulation by governmental agencies or geopolitical or economic risks as previously noted herein.

------

The proved reserves for the properties included herein were estimated by performance methods, the volumetric method, analogy, or a combination of methods. All of the proved producing reserves attributable to producing wells and/or reservoirs were estimated by performance methods. These performance methods include, but may not be limited to, decline curve analysis, material balance and/or reservoir simulation which utilized extrapolations of historical production and pressure data available through October 2025 in those cases where such data were considered to be definitive. The data utilized in this analysis were furnished to Ryder Scott by Continental or obtained from public data sources and were considered sufficient for the purpose thereof.

All of the proved developed non-producing and undeveloped reserves included herein were estimated by the volumetric method, analogy, or a combination of methods. The volumetric analysis utilized pertinent well and seismic data furnished to Ryder Scott by Continental or which we have obtained from public data sources that were available through October 2025. The data utilized from the analogues were considered sufficient for the purpose thereof.

To estimate economically producible proved oil and gas reserves and related future net cash flows, we consider many factors and assumptions including, but not limited to, the use of reservoir parameters derived from geological, geophysical and engineering data which cannot be measured directly, economic criteria based on current costs and SEC pricing requirements, and forecasts of future production rates. Under the SEC regulations 210.4-10(a)(22)(v) and (26), proved reserves must be anticipated to be economically producible from a given date forward based on existing economic conditions including the prices and costs at which economic producibility from a reservoir is to be determined. While it may reasonably be anticipated that the future prices received for the sale of production and the operating costs and other costs relating to such production may increase or decrease from those under existing economic conditions, such changes were, in accordance with rules adopted by the SEC, omitted from consideration in making this evaluation.

Continental has informed us that they have furnished us all of the material accounts, records, geological and engineering data, and reports and other data required for this investigation. In preparing our forecast of future proved production and income, we have relied upon data furnished by Continental with respect to property interests owned, production and well tests from examined wells, normal direct costs of operating the wells or leases, other costs such as transportation and/or processing fees, production and ad valorem taxes, recompletion and development costs, development plans, product prices based on the SEC regulations, adjustments or differentials to product prices, geological structural and isochore maps, well logs, core analyses, and pressure measurements. Ryder Scott reviewed such factual data for its reasonableness; however, we have not conducted an independent verification of the data furnished by Continental. We consider the factual data used in this report appropriate and sufficient for the purpose of preparing the estimates of reserves and future net revenues herein.

In summary, we consider the assumptions, data, methods and analytical procedures used in this report appropriate for the purpose hereof, and we have used all such methods and procedures that we consider necessary and appropriate to prepare the estimates of reserves herein. The proved reserves included herein were determined in conformance with the United States Securities and Exchange Commission (SEC) Modernization of Oil and Gas Reporting; Final Rule, including all references to Regulation S-X and Regulation S-K, referred to herein collectively as the "SEC Regulations." In our opinion, the proved reserves presented in this report comply with the definitions, guidelines and disclosure requirements as required by the SEC regulations.

***Future Production Rates***

For wells currently on production, our forecasts of future production rates are based on historical performance data. If no production decline trend has been established, future production rates were held constant, or adjusted for the effects of curtailment where appropriate, until a decline in ability to produce was anticipated. An estimated rate of decline was then applied until depletion of the reserves. If a decline trend has been established, this trend was used as the basis for estimating future production rates.

Test data and other related information were used to estimate the anticipated initial production rates for those wells or locations that are not currently producing. For reserves not yet on production, sales were estimated to commence at an anticipated date furnished by Continental. Wells or locations that are not currently producing may start producing earlier or later than anticipated in our estimates due to unforeseen factors causing a change in the timing to initiate production. Such factors may include delays due to weather, the availability of rigs, the sequence of drilling, completing and/or recompleting wells and/or constraints set by regulatory bodies.

The future production rates from wells currently on production or wells or locations that are not currently producing may be more or less than estimated because of changes including, but not limited to, reservoir performance, operating conditions related to surface facilities, compression and artificial lift, pipeline capacity and/or operating conditions, producing market demand and/or allowables or other constraints set by regulatory bodies.

***Hydrocarbon Prices***

The hydrocarbon prices used herein are based on SEC price parameters using the average prices during the 12-month period prior to the "as of date" of this report, determined as the unweighted arithmetic averages of the prices in effect on the first-day-of-the-month for each month within such period, unless prices were defined by contractual arrangements. For hydrocarbon products sold under contract, the contract prices, including fixed and determinable escalations, exclusive of inflation adjustments, were used until expiration of the contract. Upon contract expiration, the prices were adjusted to the 12-month unweighted arithmetic average as previously described.

------

Continental furnished us with the above mentioned average benchmark prices in effect on December 31, 2025. These initial SEC hydrocarbon prices were determined using the 12-month average first-day-of-the-month benchmark prices appropriate to the geographic area where the hydrocarbons are sold. These benchmark prices are prior to the adjustments for differentials as described herein. The table below summarizes the "benchmark prices" and "price reference" used for the geographic area included in the report. In certain geographic areas, the price reference and benchmark prices may be defined by contractual arrangements.

The product prices that were actually used to determine the future gross revenue for each property reflect adjustments to the benchmark prices for gravity, quality, local conditions, gathering and transportation fees and/or distance from market, referred to herein as "differentials." The differentials used in the preparation of this report were furnished to us by Continental. The differentials furnished to us were accepted as factual data and reviewed by us for their reasonableness; however, we have not conducted an independent verification of the data used by Continental to determine these differentials.

In addition, the table below summarizes the net volume weighted benchmark prices adjusted for differentials and referred to herein as the "average realized prices." The average realized prices shown in the table below were determined from the total future gross revenue before production taxes and the total net reserves for the geographic area and presented in accordance with SEC disclosure requirements for the geographic area included in the report.

---

| | | | | |
|:---|:---|:---|:---|:---|
| Geographic Area | Product | Price<br>Reference | Average<br>Benchmark<br>Prices | Average<br>Realized<br>Prices |
| &nbsp;&nbsp;&nbsp;&nbsp;North America | Oil/Condensate | WTI Cushing | $65.34/BBL | $62.03/BBL |
|  | Gas | Henry Hub | $3.39/MMBTU | $2.77/MCF |

---

The effects of derivative instruments designated as price hedges of oil and gas quantities are not reflected in our individual property evaluations.

***Costs***

Operating costs for the leases and wells in this report were furnished by Continental and are based on the operating expense reports of Continental and include only those costs directly applicable to the leases or wells. The operating costs furnished to us were accepted as factual data and reviewed by us for their reasonableness; however, we have not conducted an independent verification of the operating cost data used by Continental. No deduction was made for loan repayments, interest expenses, or exploration and development prepayments that were not charged directly to the leases or wells.

Development costs were furnished to us by Continental and are based on authorizations for expenditure for the proposed work or actual costs for similar projects. The development costs furnished to us were accepted as factual data and reviewed by us for their reasonableness; however, we have not conducted an independent verification of these costs. Continental's estimates of zero abandonment costs after salvage value for the properties included in this report were used at Continental's request. Ryder Scott has not performed a detailed study of the abandonment costs or the salvage value and makes no warranty for Continental's estimates.

The proved developed non-producing and undeveloped reserves in this report have been incorporated herein in accordance with Continental's plans to develop these reserves as of December 31, 2025. The implementation of Continental's development plans as presented to us and incorporated herein is subject to the approval process adopted by Continental's management. As the result of our inquiries during the course of preparing this report, Continental has informed us that the development activities included herein have been subjected to and received the internal approvals required by Continental's management at the appropriate local, regional and/or corporate level. In addition to the internal approvals as noted, certain development activities may still be subject to specific partner AFE processes, Joint Operating Agreement (JOA) requirements or other administrative approvals external to Continental. Continental has provided written documentation supporting their commitment to proceed with the development activities as presented to us. Additionally, Continental has informed us that they are not aware of any legal, regulatory, or political obstacles that would significantly alter their plans. While these plans could change from those under existing economic conditions as of December 31, 2025, such changes were, in accordance with rules adopted by the SEC, omitted from consideration in making this evaluation.

Current costs used by Continental were held constant throughout the life of the properties.

***Standards of Independence and Professional Qualification***

Ryder Scott is an independent petroleum engineering consulting firm that has been providing petroleum consulting services throughout the world since 1937. Ryder Scott is employee-owned and maintains offices in Houston, Texas; Denver, Colorado; and Calgary, Alberta, Canada. We have approximately eighty engineers and geoscientists on our permanent staff. By virtue of the size of our firm and the large number of clients for which we provide services, no single client or job represents a material portion of our annual revenue. We do not serve as officers or directors of any privately-owned or publicly-traded oil and gas company and are separate and independent from the operating and investment decision-making process of our clients. This allows us to bring the highest level of independence and objectivity to each engagement for our services.

Ryder Scott actively participates in industry-related professional societies and organizes an annual public forum focused on the subject of reserves evaluations and SEC regulations. Many of our staff have authored or co-authored technical papers on the subject of reserves related topics. We encourage our staff to maintain and enhance their professional skills by actively participating in ongoing continuing education.

------

Prior to becoming an officer of the Company, Ryder Scott requires that staff engineers and geoscientists receive professional accreditation in the form of a registered or certified professional engineer's license or a registered or certified professional geoscientist's license, or the equivalent thereof, from an appropriate governmental authority or a recognized self-regulating professional organization. Regulating agencies require that, in order to maintain active status, a certain amount of continuing education hours be completed annually, including an hour of ethics training. Ryder Scott fully supports this technical and ethics training with our internal requirement mentioned above.

We are independent petroleum engineers with respect to Continental. Neither we nor any of our employees have any financial interest in the subject properties and neither the employment to do this work nor the compensation is contingent on our estimates of reserves for the properties which were reviewed.

The results of this study, presented herein, are based on technical analyses conducted by teams of geoscientists and engineers from Ryder Scott. The professional qualifications of the undersigned, the technical person primarily responsible for overseeing the evaluation of the reserves information discussed in this report, are included as an attachment to this letter.

***Terms of Usage***

The results of our third party study, presented in report form herein, were prepared in accordance with the disclosure requirements set forth in the SEC regulations and intended for public disclosure as an exhibit in filings made with the SEC by Continental.

We have provided Continental with a digital version of the original signed copy of this report letter. In the event there are any differences between the digital version included in filings made by Continental and the original signed report letter, the original signed report letter shall control and supersede the digital version.

The data and work papers used in the preparation of this report are available for examination by authorized parties in our offices. Please contact us if we can be of further service.

---

| |
|:---|
| Very truly yours, |
| **RYDER SCOTT COMPANY, L.P.** |
| TBPELS Firm Registration No. F-1580 |
| /s/ Scott J. Wilson |
| Scott J. Wilson, P.E., MBA |
| Colorado License No. 36112 |
| Senior Vice President |

---

------

 **Professional Qualifications of Primary Technical Person**

The conclusions presented in this report are the result of technical analysis conducted by teams of geoscientists and engineers from Ryder Scott Company, L.P. Mr. Scott James Wilson was the primary technical person responsible for the estimate of the reserves, future production, and income presented herein.

Mr. Wilson, an employee of Ryder Scott Company L.P. (Ryder Scott) since 2000, is a Senior Vice President responsible for coordinating and supervising staff and consulting engineers of the company in ongoing reservoir evaluation studies worldwide. Before joining Ryder Scott, Mr. Wilson served in a number of engineering positions with Atlantic Richfield Company. For more information regarding Mr. Wilson's geographic and job specific experience, please refer to the Ryder Scott Company website at https://www.ryderscott.com/company/employees/denver-employees.

Mr. Wilson earned a Bachelor of Science degree in Petroleum Engineering from the Colorado School of Mines in 1983 and an MBA in Finance from the University of Colorado in 1985, graduating from both with High Honors. He is a registered Professional Engineer by exam in the States of Alaska, Colorado, Texas, and Wyoming. He is also an active member of the Society of Petroleum Engineers; serving as co-Chairman of the SPE Reserves and Economics Technology Interest Group, and Gas Technology Editor for SPE's Journal of Petroleum Technology. He is a member and past chairman of the Denver section of the Society of Petroleum Evaluation Engineers. Mr. Wilson has published several technical papers, one chapter in Marine and Petroleum Geology and two in SPEE monograph 4, which was published in 2016. He is the primary inventor on four US patents and won the 2017 Reservoir Description and Dynamics award for the SPE Rocky Mountain Region.

In addition to gaining experience and competency through prior work experience, several state Boards of Professional Engineers require a minimum number of hours of continuing education annually, including at least one hour in the area of professional ethics, which Mr. Wilson fulfills as part of his registration in four states. As part of his continuing education, Mr. Wilson attends internally presented training as well as public forums relating to the definitions and disclosure guidelines contained in the United States Securities and Exchange Commission Title 17, Code of Federal Regulations, Modernization of Oil and Gas Reporting, and Final Rule released January 14, 2009 in the Federal Register. Mr. Wilson attends additional hours of formalized external training covering such topics as the SPE/WPC/AAPG/SPEE Petroleum Resources Management System, reservoir engineering and petroleum economics evaluation methods, procedures and software and ethics for consultants.

Based on his educational background, professional training and more than 35 years of practical experience in the estimation and evaluation of petroleum reserves, Mr. Wilson has attained the professional qualifications as a Reserves Estimator and Reserves Auditor set forth in Article III of the "Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information" promulgated by the Society of Petroleum Engineers as of June 2019.

------

**PETROLEUM RESERVES DEFINITIONS**

**As Adapted From:**

**RULE 4-10(a) of REGULATION S-X PART 210**

**UNITED STATES SECURITIES AND EXCHANGE COMMISSION (SEC)**

***PREAMBLE***

On January 14, 2009, the United States Securities and Exchange Commission (SEC) published the "Modernization of Oil and Gas Reporting; Final Rule" in the Federal Register of National Archives and Records Administration (NARA). The "Modernization of Oil and Gas Reporting; Final Rule" includes revisions and additions to the definition section in Rule 4-10 of Regulation S-X, revisions and additions to the oil and gas reporting requirements in Regulation S-K, and amends and codifies Industry Guide 2 in Regulation S-K. The "Modernization of Oil and Gas Reporting; Final Rule", including all references to Regulation S-X and Regulation S-K, shall be referred to herein collectively as the "SEC regulations". The SEC regulations take effect for all filings made with the United States Securities and Exchange Commission as of December 31, 2009, or after January 1, 2010. Reference should be made to the full text under Title 17, Code of Federal Regulations, Regulation S-X Part 210, Rule 4-10(a) for the complete definitions (direct passages excerpted in part or wholly from the aforementioned SEC document are denoted in italics herein).

*Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations.* All reserve estimates involve an assessment of the uncertainty relating the likelihood that the actual remaining quantities recovered will be greater or less than the estimated quantities determined as of the date the estimate is made. The uncertainty depends chiefly on the amount of reliable geologic and engineering data available at the time of the estimate and the interpretation of these data. The relative degree of uncertainty may be conveyed by placing reserves into one of two principal classifications, either proved or unproved. Unproved reserves are less certain to be recovered than proved reserves and may be further sub-classified as probable and possible reserves to denote progressively increasing uncertainty in their recoverability. Under the SEC regulations as of December 31, 2009, or after January 1, 2010, a company may optionally disclose estimated quantities of probable or possible oil and gas reserves in documents publicly filed with the SEC. The SEC regulations continue to prohibit disclosure of estimates of oil and gas resources other than reserves and any estimated values of such resources in any document publicly filed with the SEC unless such information is required to be disclosed in the document by foreign or state law as noted in §229.1202 Instruction to Item 1202.

Reserves estimates will generally be revised only as additional geologic or engineering data become available or as economic conditions change.

Reserves may be attributed to either natural energy or improved recovery methods. Improved recovery methods include all methods for supplementing natural energy or altering natural forces in the reservoir to increase ultimate recovery. Examples of such methods are pressure maintenance, natural gas cycling, waterflooding, thermal methods, chemical flooding, and the use of miscible and immiscible displacement fluids. Other improved recovery methods may be developed in the future as petroleum technology continues to evolve.

Reserves may be attributed to either conventional or unconventional petroleum accumulations. Petroleum accumulations are considered as either conventional or unconventional based on the nature of their in-place characteristics, extraction method applied, or degree of processing prior to sale. Examples of unconventional petroleum accumulations include coalbed or coalseam methane (CBM/CSM), basin-centered gas, shale gas, gas hydrates, natural bitumen and oil shale deposits. These unconventional accumulations may require specialized extraction technology and/or significant processing prior to sale.

Reserves do not include quantities of petroleum being held in inventory.

Because of the differences in uncertainty, caution should be exercised when aggregating quantities of petroleum from different reserves categories.

**<u>RESERVES (SEC DEFINITIONS)</u>**

Securities and Exchange Commission Regulation S-X §210.4-10(a)(26) defines reserves as follows:

***Reserves.*** *Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project.*

*<u>Note to paragraph (a)(26):</u> Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (<u>i.e.</u>, absence of reservoir, structurally low reservoir, or negative test results). Such areas may contain prospective resources (<u>i.e.</u>, potentially recoverable resources from undiscovered accumulations).*

------

**<u>PROVED RESERVES (SEC DEFINITIONS)</u>**

Securities and Exchange Commission Regulation S-X §210.4-10(a)(22) defines proved oil and gas reserves as follows:

***Proved oil and gas reserves.*** *Proved oil and gas reserves are those quantities of oil and 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 that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.*

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;*(i) The area of the reservoir considered as proved includes:*

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;*(A) The area identified by drilling and limited by fluid contacts, if any, and*

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;*(B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.*

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;*(ii) In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.*

*(iii)Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.*

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;*(iv) Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when:*

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;*(A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and*

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;*(B) The project has been approved for development by all necessary parties and entities, including governmental entities.*

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;*(v) Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.*

------

**PETROLEUM RESERVES STATUS DEFINITIONS AND GUIDELINES**

**As Adapted From:**

**RULE 4-10(a) of REGULATION S-X PART 210**

**UNITED STATES SECURITIES AND EXCHANGE COMMISSION (SEC)**

**and**

**2018 PETROLEUM RESOURCES MANAGEMENT SYSTEM (SPE-PRMS)**

**Sponsored and Approved by:**

**SOCIETY OF PETROLEUM ENGINEERS (SPE)**

**WORLD PETROLEUM COUNCIL (WPC)**

**AMERICAN ASSOCIATION OF PETROLEUM GEOLOGISTS (AAPG)**

**SOCIETY OF PETROLEUM EVALUATION ENGINEERS (SPEE)**

**SOCIETY OF EXPLORATION GEOPHYSICISTS (SEG)**

**SOCIETY OF PETROPHYSICISTS AND WELL LOG ANALYSTS (SPWLA)**

**EUROPEAN ASSOCIATION OF GEOSCIENTISTS & ENGINEERS (EAGE)**

Reserves status categories define the development and producing status of wells and reservoirs. Reference should be made to Title 17, Code of Federal Regulations, Regulation S-X Part 210, Rule 4-10(a) and the SPE-PRMS as the following reserves status definitions are based on excerpts from the original documents (direct passages excerpted from the aforementioned SEC and SPE-PRMS documents are denoted in italics herein).

**<u>DEVELOPED RESERVES (SEC DEFINITIONS)</u>**

Securities and Exchange Commission Regulation S-X §210.4-10(a)(6) defines developed oil and gas reserves as follows:

*Developed oil and gas reserves are reserves of any category that can be expected to be recovered:*

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;*(i) Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and*

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;*(ii) Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.*

**<u>Developed Producing (SPE-PRMS Definitions)</u>**

While not a requirement for disclosure under the SEC regulations, developed oil and gas reserves may be further sub-classified according to the guidance contained in the SPE-PRMS as Producing or Non-Producing.

***<u>Developed Producing Reserves</u>***

*Developed Producing Reserves are expected quantities to be recovered from completion intervals that are open and producing at the effective date of the estimate.*

*Improved recovery reserves are considered producing only after the improved recovery project is in operation.*

***<u>Developed Non-Producing</u>***

*Developed Non-Producing Reserves include shut-in and behind-pipe Reserves.*

***<u>Shut-In</u>***

*Shut-in Reserves are expected to be recovered from:*

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;*(1) completion intervals that are open at the time of the estimate but which have not yet started producing;*

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;*(2) wells which were shut-in for market conditions or pipeline connections; or*

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;*(3) wells not capable of production for mechanical reasons.*

***<u>Behind-Pipe</u>***

*Behind-pipe Reserves are expected to be recovered from zones in existing wells that will require additional completion work or future re-completion before start of production with minor cost to access these reserves.*

*In all cases, production can be initiated or restored with relatively low expenditure compared to the cost of drilling a new well.*

------

**<u>UNDEVELOPED RESERVES (SEC DEFINITIONS)</u>**

Securities and Exchange Commission Regulation S-X §210.4-10(a)(31) defines undeveloped oil and gas reserves as follows:

*Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.*

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;*(i) Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.*

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;*(ii) Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time.*

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;*(iii) Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, as defined in paragraph (a)(2) of this section, or by other evidence using reliable technology establishing reasonable certainty.*

------