# EDGAR Filing Document

**Accession Number:** 0000893538
**File Stem:** 0000893538-26-000032
**Filing Date:** 2026-2
**Character Count:** 734453
**Document Hash:** 323001e1760a0aa483c5120a3cc3c1cb
**Contains OCR:** False
**Source Format:** 

## Filing Content

## Filing Summary
**0000893538-26-000032.hdr.sgml**: 20260226

**ACCESSION NUMBER**: 0000893538-26-000032

**CONFORMED SUBMISSION TYPE**: 10-K

**PUBLIC DOCUMENT COUNT**: 126

**CONFORMED PERIOD OF REPORT**: 20251231

**FILED AS OF DATE**: 20260226

**DATE AS OF CHANGE**: 20260226

**FILER**: 

**COMPANY DATA:**
- **COMPANY CONFORMED NAME:** SM Energy Co
- **CENTRAL INDEX KEY:** 0000893538
- **STANDARD INDUSTRIAL CLASSIFICATION:** CRUDE PETROLEUM & NATURAL GAS [1311]
- **ORGANIZATION NAME:** 01 Energy & Transportation
- **EIN:** 410518430
- **STATE OF INCORPORATION:** DE
- **FISCAL YEAR END:** 1231

**FILING VALUES:**
- **FORM TYPE:** 10-K
- **SEC ACT:** 1934 Act
- **SEC FILE NUMBER:** 001-31539
- **FILM NUMBER:** 26681959

**BUSINESS ADDRESS:**
- **STREET 1:** 1700 LINCOLN STREET
- **STREET 2:** SUITE 3200
- **CITY:** DENVER
- **STATE:** CO
- **ZIP:** 80203
- **BUSINESS PHONE:** 303-861-8140

**MAIL ADDRESS:**
- **STREET 1:** 1700 LINCOLN STREET
- **STREET 2:** SUITE 3200
- **CITY:** DENVER
- **STATE:** CO
- **ZIP:** 80203

**FORMER COMPANY:**
- **FORMER CONFORMED NAME:** ST MARY LAND & EXPLORATION CO
- **DATE OF NAME CHANGE:** 19940228

?xml version='1.0' encoding='ASCII'? sm-20251231

**UNITED STATES**

**SECURITIES AND EXCHANGE COMMISSION**

**Washington, D.C. 20549**

**FORM 10-K**

☑&nbsp;&nbsp;&nbsp;&nbsp;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

☐&nbsp;&nbsp;&nbsp;&nbsp;Transition Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

Commission file number 001-31539

**SM ENERGY COMPANY**

(Exact name of registrant as specified in its charter)

---

| | |
|:---|:---|
| **Delaware** | **41-0518430** |
| (State or other jurisdiction of incorporation or organization) | (I.R.S. Employer Identification No.) |

---

---

| | |
|:---|:---|
| **1700 Lincoln Street, Suite 3200, Denver, Colorado** | **80203** |
| (Address of principal executive offices) | (Zip Code) |

---

**(303) 861-8140**

(Registrant's telephone number, including area code)

Securities registered pursuant to Section 12(b) of the Act:

---

| | | |
|:---|:---|:---|
| Title of each class | Trading Symbol(s) | Name of each exchange on which registered |
| **Common stock, $0.01 par value** | **SM** | **New York Stock Exchange** |

---

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, a smaller reporting company, or 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. ☐ | 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. ☐ | 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. ☐ | 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. ☐ | 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 ☑

The aggregate market value of the 81,083,174 shares of voting stock held by non-affiliates of the registrant, based upon the closing sale price of the registrant's common stock on June 30, 2025, the last business day of the registrant's most recently completed second fiscal quarter, of $24.71 per share, as reported on the New York Stock Exchange, was $2,003,565,230. Shares of common stock held by each director and executive officer and by each person who owns 10 percent or more of the outstanding common stock or who is otherwise believed by the registrant to be in a control position have been excluded. This determination of affiliate status is not necessarily a conclusive determination for other purposes.

As of February 2, 2026, the registrant had 238,359,166 shares of common stock outstanding.

**DOCUMENTS INCORPORATED BY REFERENCE**

Certain information required by Items 10, 11, 12, 13, and 14 of Part III of this report is incorporated by reference from portions of the registrant's Definitive Proxy Statement on Schedule 14A relating to its 2026 annual meeting of stockholders, to be filed within 120 days after December 31, 2025.

------

---

| | | |
|:---|:---|:---|
| **<u>**TABLE OF CONTENTS**</u>** | **<u>**TABLE OF CONTENTS**</u>** | **<u>**TABLE OF CONTENTS**</u>** |
| **<u>Item</u>** | | **<u>Page</u>** |
| | <u>[Cautionary Information about Forward-Looking Statements](#i293a8c843fc7462dbf208500aa1f98b0_13)</u> | <u>[4](#i293a8c843fc7462dbf208500aa1f98b0_13)</u> |
| | <u>[Glossary](#i293a8c843fc7462dbf208500aa1f98b0_16)</u> | <u>[5](#i293a8c843fc7462dbf208500aa1f98b0_16)</u> |
| | **<u>[Part I](#i293a8c843fc7462dbf208500aa1f98b0_19)</u>** | <u>[8](#i293a8c843fc7462dbf208500aa1f98b0_19)</u> |
| <u>[Items 1. and 2.](#i293a8c843fc7462dbf208500aa1f98b0_22)</u> | <u>[Business and Properties](#i293a8c843fc7462dbf208500aa1f98b0_22)</u> | <u>[8](#i293a8c843fc7462dbf208500aa1f98b0_22)</u> |
| | &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;<u>[General](#i293a8c843fc7462dbf208500aa1f98b0_25)</u> | <u>[8](#i293a8c843fc7462dbf208500aa1f98b0_25)</u> |
| | &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;<u>[Strategy](#i293a8c843fc7462dbf208500aa1f98b0_28)</u> | <u>[8](#i293a8c843fc7462dbf208500aa1f98b0_28)</u> |
| | &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;<u>[Significant Developments in 2025](#i293a8c843fc7462dbf208500aa1f98b0_31)</u> | <u>[8](#i293a8c843fc7462dbf208500aa1f98b0_31)</u> |
| | &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;<u>[Outlook](#i293a8c843fc7462dbf208500aa1f98b0_34)</u> | <u>[9](#i293a8c843fc7462dbf208500aa1f98b0_34)</u> |
| | &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;<u>[Areas of Operation](#i293a8c843fc7462dbf208500aa1f98b0_37)</u> | <u>[10](#i293a8c843fc7462dbf208500aa1f98b0_37)</u> |
| | &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;<u>[Reserves](#i293a8c843fc7462dbf208500aa1f98b0_40)</u> | <u>[11](#i293a8c843fc7462dbf208500aa1f98b0_40)</u> |
| | &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;<u>[Production](#i293a8c843fc7462dbf208500aa1f98b0_43)</u> | <u>[16](#i293a8c843fc7462dbf208500aa1f98b0_43)</u> |
| | &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;<u>[Productive Wells](#i293a8c843fc7462dbf208500aa1f98b0_46)</u> | <u>[16](#i293a8c843fc7462dbf208500aa1f98b0_46)</u> |
| | &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;<u>[Drilling and Completion Activity](#i293a8c843fc7462dbf208500aa1f98b0_49)</u> | <u>[17](#i293a8c843fc7462dbf208500aa1f98b0_49)</u> |
| | &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;<u>[Title to Properties](#i293a8c843fc7462dbf208500aa1f98b0_52)</u> | <u>[17](#i293a8c843fc7462dbf208500aa1f98b0_52)</u> |
| | &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;<u>[Acreage](#i293a8c843fc7462dbf208500aa1f98b0_55)</u> | <u>[18](#i293a8c843fc7462dbf208500aa1f98b0_55)</u> |
| | &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;<u>[Delivery Commitments](#i293a8c843fc7462dbf208500aa1f98b0_58)</u> | <u>[18](#i293a8c843fc7462dbf208500aa1f98b0_58)</u> |
| | &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;<u>[Major Customers](#i293a8c843fc7462dbf208500aa1f98b0_61)</u> | <u>[18](#i293a8c843fc7462dbf208500aa1f98b0_61)</u> |
| | &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;<u>[Human Capital](#i293a8c843fc7462dbf208500aa1f98b0_64)</u> | <u>[18](#i293a8c843fc7462dbf208500aa1f98b0_64)</u> |
| | &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;<u>[Seasonality](#i293a8c843fc7462dbf208500aa1f98b0_70)</u> | <u>[19](#i293a8c843fc7462dbf208500aa1f98b0_70)</u> |
| | &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;<u>[Competition](#i293a8c843fc7462dbf208500aa1f98b0_73)</u> | <u>[19](#i293a8c843fc7462dbf208500aa1f98b0_73)</u> |
| | &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;<u>[Government Regulations](#i293a8c843fc7462dbf208500aa1f98b0_76)</u> | <u>[20](#i293a8c843fc7462dbf208500aa1f98b0_76)</u> |
| | &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;<u>[Available Information](#i293a8c843fc7462dbf208500aa1f98b0_82)</u> | <u>[24](#i293a8c843fc7462dbf208500aa1f98b0_82)</u> |
| <u>[Item 1A.](#i293a8c843fc7462dbf208500aa1f98b0_85)</u> | <u>[Risk Factors](#i293a8c843fc7462dbf208500aa1f98b0_85)</u> | <u>[24](#i293a8c843fc7462dbf208500aa1f98b0_85)</u> |
| <u>[Item 1B.](#i293a8c843fc7462dbf208500aa1f98b0_103)</u> | <u>[Unresolved Staff Comments](#i293a8c843fc7462dbf208500aa1f98b0_103)</u> | <u>[42](#i293a8c843fc7462dbf208500aa1f98b0_103)</u> |
| <u>[Item 1C.](#i293a8c843fc7462dbf208500aa1f98b0_106)</u> | <u>[Cybersecurity](#i293a8c843fc7462dbf208500aa1f98b0_106)</u> | <u>[42](#i293a8c843fc7462dbf208500aa1f98b0_106)</u> |
| <u>[Item 3.](#i293a8c843fc7462dbf208500aa1f98b0_109)</u> | <u>[Legal Proceedings](#i293a8c843fc7462dbf208500aa1f98b0_109)</u> | <u>[43](#i293a8c843fc7462dbf208500aa1f98b0_109)</u> |
| <u>[Item 4.](#i293a8c843fc7462dbf208500aa1f98b0_112)</u> | <u>[Mine Safety Disclosures](#i293a8c843fc7462dbf208500aa1f98b0_112)</u> | <u>[44](#i293a8c843fc7462dbf208500aa1f98b0_112)</u> |
| | **<u>[Part II](#i293a8c843fc7462dbf208500aa1f98b0_115)</u>** | <u>[45](#i293a8c843fc7462dbf208500aa1f98b0_115)</u> |
| <u>[Item 5.](#i293a8c843fc7462dbf208500aa1f98b0_118)</u> | <u>[Market For Registrant's Common Equity, Related Stockholder Matters, and Issuer Purchases of Equity Securities](#i293a8c843fc7462dbf208500aa1f98b0_118)</u> | <u>[45](#i293a8c843fc7462dbf208500aa1f98b0_118)</u> |
| <u>[Item 6.](#i293a8c843fc7462dbf208500aa1f98b0_124)</u> | <u>[\[Reserved\]](#i293a8c843fc7462dbf208500aa1f98b0_124)</u> | <u>[46](#i293a8c843fc7462dbf208500aa1f98b0_124)</u> |
| <u>[Item 7.](#i293a8c843fc7462dbf208500aa1f98b0_127)</u> | <u>[Management's Discussion and Analysis of Financial Condition and Results of Operations](#i293a8c843fc7462dbf208500aa1f98b0_127)</u> | <u>[47](#i293a8c843fc7462dbf208500aa1f98b0_127)</u> |
| | &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;<u>[Overview of the Company](#i293a8c843fc7462dbf208500aa1f98b0_130)</u> | <u>[47](#i293a8c843fc7462dbf208500aa1f98b0_130)</u> |
| | &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;<u>[Financial Results of Operations and Additional Comparative Data](#i293a8c843fc7462dbf208500aa1f98b0_136)</u> | <u>[52](#i293a8c843fc7462dbf208500aa1f98b0_136)</u> |
| | &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;<u>[Comparison of Financial Results and Trends Between 2025 and 2024](#i293a8c843fc7462dbf208500aa1f98b0_139)</u> | <u>[55](#i293a8c843fc7462dbf208500aa1f98b0_139)</u> |
| | &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;<u>[Overview of Liquidity and Capital Resources](#i293a8c843fc7462dbf208500aa1f98b0_145)</u> | <u>[57](#i293a8c843fc7462dbf208500aa1f98b0_145)</u> |
| | &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;<u>[Critical Accounting Estimates](#i293a8c843fc7462dbf208500aa1f98b0_148)</u> | <u>[61](#i293a8c843fc7462dbf208500aa1f98b0_148)</u> |
| | &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;<u>[Accounting Matters](#i293a8c843fc7462dbf208500aa1f98b0_154)</u> | <u>[63](#i293a8c843fc7462dbf208500aa1f98b0_154)</u> |
| | &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;<u>[Environmental](#i293a8c843fc7462dbf208500aa1f98b0_157)</u> | <u>[63](#i293a8c843fc7462dbf208500aa1f98b0_157)</u> |
| | &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;<u>[Non-GAAP Financial Measures](#i293a8c843fc7462dbf208500aa1f98b0_160)</u> | <u>[64](#i293a8c843fc7462dbf208500aa1f98b0_160)</u> |
| <u>[Item 7A.](#i293a8c843fc7462dbf208500aa1f98b0_163)</u> | <u>[Quantitative and Qualitative Disclosures About Market Risk](#i293a8c843fc7462dbf208500aa1f98b0_163)</u> | <u>[65](#i293a8c843fc7462dbf208500aa1f98b0_163)</u> |
| <u>[Item 8.](#i293a8c843fc7462dbf208500aa1f98b0_166)</u> | <u>[Consolidated Financial Statements and Supplementary Data](#i293a8c843fc7462dbf208500aa1f98b0_166)</u> | <u>[66](#i293a8c843fc7462dbf208500aa1f98b0_166)</u> |
| <u>[Item 9.](#i293a8c843fc7462dbf208500aa1f98b0_286)</u> | <u>[Changes In and Disagreements With Accountants on Accounting and Financial Disclosure](#i293a8c843fc7462dbf208500aa1f98b0_286)</u> | <u>[111](#i293a8c843fc7462dbf208500aa1f98b0_286)</u> |
| <u>[Item 9A.](#i293a8c843fc7462dbf208500aa1f98b0_289)</u> | <u>[Controls and Procedures](#i293a8c843fc7462dbf208500aa1f98b0_289)</u> | <u>[111](#i293a8c843fc7462dbf208500aa1f98b0_289)</u> |
| <u>[Item 9B.](#i293a8c843fc7462dbf208500aa1f98b0_295)</u> | <u>[Other Information](#i293a8c843fc7462dbf208500aa1f98b0_295)</u> | <u>[114](#i293a8c843fc7462dbf208500aa1f98b0_295)</u> |
| <u>[Item 9C.](#i293a8c843fc7462dbf208500aa1f98b0_301)</u> | <u>[Disclosure Regarding Foreign Jurisdictions that Prevent Inspections](#i293a8c843fc7462dbf208500aa1f98b0_301)</u> | <u>[114](#i293a8c843fc7462dbf208500aa1f98b0_301)</u> |

---

------

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| | | |
|:---|:---|:---|
| **<u>**TABLE OF CONTENTS**</u>** | **<u>**TABLE OF CONTENTS**</u>** | **<u>**TABLE OF CONTENTS**</u>** |
| **(Continued)** | **(Continued)** | **(Continued)** |
| **<u>Item</u>** | | **<u>Page</u>** |
| | **<u>[Part III](#i293a8c843fc7462dbf208500aa1f98b0_304)</u>** | <u>[114](#i293a8c843fc7462dbf208500aa1f98b0_304)</u> |
| <u>[Item 10.](#i293a8c843fc7462dbf208500aa1f98b0_307)</u> | <u>[Directors, Executive Officers, and Corporate Governance](#i293a8c843fc7462dbf208500aa1f98b0_307)</u> | <u>[114](#i293a8c843fc7462dbf208500aa1f98b0_307)</u> |
| <u>[Item 11.](#i293a8c843fc7462dbf208500aa1f98b0_310)</u> | <u>[Executive Compensation](#i293a8c843fc7462dbf208500aa1f98b0_310)</u> | <u>[114](#i293a8c843fc7462dbf208500aa1f98b0_310)</u> |
| <u>[Item 12.](#i293a8c843fc7462dbf208500aa1f98b0_313)</u> | <u>[Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters](#i293a8c843fc7462dbf208500aa1f98b0_313)</u> | <u>[114](#i293a8c843fc7462dbf208500aa1f98b0_313)</u> |
| <u>[Item 13.](#i293a8c843fc7462dbf208500aa1f98b0_316)</u> | <u>[Certain Relationships and Related Transactions, and Director Independence](#i293a8c843fc7462dbf208500aa1f98b0_316)</u> | <u>[115](#i293a8c843fc7462dbf208500aa1f98b0_316)</u> |
| <u>[Item 14.](#i293a8c843fc7462dbf208500aa1f98b0_319)</u> | <u>[Principal Accountant Fees and Services](#i293a8c843fc7462dbf208500aa1f98b0_319)</u> | <u>[115](#i293a8c843fc7462dbf208500aa1f98b0_319)</u> |
| | **<u>[Part IV](#i293a8c843fc7462dbf208500aa1f98b0_322)</u>** | <u>[116](#i293a8c843fc7462dbf208500aa1f98b0_322)</u> |
| <u>[Item 15.](#i293a8c843fc7462dbf208500aa1f98b0_325)</u> | <u>[Exhibits and Consolidated Financial Statement Schedules](#i293a8c843fc7462dbf208500aa1f98b0_325)</u> | <u>[116](#i293a8c843fc7462dbf208500aa1f98b0_325)</u> |
| <u>[Item 16.](#i293a8c843fc7462dbf208500aa1f98b0_331)</u> | <u>[Form 10-K Summary](#i293a8c843fc7462dbf208500aa1f98b0_331)</u> | <u>[119](#i293a8c843fc7462dbf208500aa1f98b0_331)</u> |
| | **<u>[Signatures](#i293a8c843fc7462dbf208500aa1f98b0_334)</u>** | <u>[120](#i293a8c843fc7462dbf208500aa1f98b0_334)</u> |

---

------

**Cautionary Information about Forward-Looking Statements**

This Annual Report on Form 10-K ("Form 10-K" or "this report") contains "forward-looking statements" within the meaning of Section 27A of the Securities Act of 1933, as amended ("Securities Act"), and Section 21E of the Securities Exchange Act of 1934, as amended ("Exchange Act"). All statements included in this report, other than statements of historical fact, that address activities, conditions, events, or developments with respect to our financial condition, results of operations, business prospects or economic performance that we expect, believe, or anticipate will or may occur in the future, or that address plans and objectives of management for future operations, are forward-looking statements. The words "anticipate," "assume," "believe," "budget," "could," "estimate," "expect," "forecast," "goal," "intend," "objective," "pending," "plan," "potential," "projected," "seek," "target," "will," and similar expressions are intended to identify forward-looking statements. Forward-looking statements appear throughout this report, and unless otherwise specifically noted, refer to the post-Merger entity following the Merger with Civitas Resources, Inc. ("Civitas"); see *Note 17 – Mergers, Acquisitions, and Divestitures* in Part II, Item 8 of this report and *Glossary* below for discussion and definition of the Civitas Merger. These statements include matters such as:

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;*•* the amount and nature of future capital expenditures, the resilience of our assets to declining commodity prices, the ability of our assets to generate returns in the current macroeconomic environment, and the availability of liquidity and capital resources to fund capital expenditures;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• our outlook on prices for future crude oil, natural gas, and natural gas liquids (also referred to throughout this report as "oil," "gas," and "NGLs," respectively), well costs, service costs, production costs, and general and administrative costs, and the effects of inflation, tariffs or trade restrictions on each of these;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• risks related to the Civitas Merger, including our ability to successfully integrate Civitas' business, operations, systems and personnel; potential disruptions to our business resulting from the transaction; and our ability to realize the anticipated benefits, synergies, efficiencies or cost savings from the Merger (including within expected timeframes, or at all);

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• changes in general economic and financial conditions, inflationary pressures, the potential for economic recession in the U.S., tariffs and trade restrictions, including the imposition of new and higher tariffs on imported goods, the uncertainty of evolving tariffs and retaliatory tariffs implemented by other countries on U.S. goods, any future U.S. federal government shutdown, and the potential effects on our financial condition or results of operations;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• business strategies and other plans and objectives for future operations, including plans for expansion and growth of operations or reallocation of capital, plans with respect to future dividend payments, debt repayments or redemptions, equity repurchases, capital markets activities, sustainability goals and initiatives, and our outlook on our future financial condition or results of operations;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• armed conflict, political instability, or civil unrest in oil and gas producing regions and shipping channels, including: recent U.S. military actions and heightened geopolitical tensions involving Venezuela; the war between Russia and Ukraine; instability in the Middle East including the war and armed conflicts between Israel and Hamas, Hezbollah, and Iran and its proxy forces; U.S. involvement in such matters; the possibility that any current or future ceasefires could fail, resulting in renewed or broader regional hostilities; and related potential effects on laws and regulations, or the imposition of economic or trade sanctions ("War and Geopolitical Instability");

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;*•* any changes to the borrowing base or aggregate revolving lender commitments under, or the maturity date of, our Seventh Amended and Restated Credit Agreement, as amended ("Credit Agreement");

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• cash flows, liquidity, interest and related debt service expenses, changes in our effective tax rate, and our ability to repay debt in the future;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• our drilling and completion activities and other exploration and development activities, each of which could be affected by supply chain disruptions, inflation, tariffs or trade restrictions, pipeline capacity, our ability to obtain permits and governmental approvals, and plans by us, our joint development partners, and/or other third-party operators;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• possible or expected acquisitions and divestitures, including our plans to execute on a divestiture target within the next year and our entry into a Purchase and Sale Agreement ("PSA") with Caturus Energy, LLC, a Delaware limited liability company ("Caturus") for the sale of certain of our South Texas assets, which is subject to customary closing conditions including regulatory approvals and certain required consents, and may not be completed on the anticipated timeline or at all, the possible divestiture or farm-out of, or farm-in or joint development of, certain properties;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• oil, gas, and NGL reserve estimates and estimates of both future net revenues and the present value of future net revenues associated with those reserve estimates, as well as the conversion of proved undeveloped reserves to proved developed reserves;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• our expected future production volumes, identified drilling locations, as well as drilling prospects, inventories, projects and programs;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• our expectations related to changes in proposed or final federal and state income tax laws and regulations, including the expected impacts of the One Big Beautiful Bill Act ("OBBBA"), enacted on July 4, 2025; and

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• other similar matters, such as those discussed in *Management's Discussion and Analysis of Financial Condition and Results of Operations* in Part II, Item 7 of this report.

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Our forward-looking statements are based on assumptions and analyses made by us in light of our experience and our perception of historical trends, current conditions, expected future developments, and other factors that we believe are appropriate under the circumstances. We caution you that forward-looking statements are not guarantees of future performance, and these statements are subject to known and unknown risks and uncertainties, which may cause our actual results or performance to be materially different from any future results or performance expressed or implied by the forward-looking statements. Factors that may cause our financial condition, results of operations, business prospects or economic performance to differ from expectations include, among others, commodity price volatility; changes in capital markets or access to liquidity; integration risks and the anticipated benefits of acquisitions or divestitures; operational, drilling, and production risks; regulatory or environmental developments; and other risks as discussed in Part I, Item 1A, *Risk Factors* below and elsewhere in this report.

The forward-looking statements in this report speak only as of the filing of this report. Although we may from time to time voluntarily update our prior forward-looking statements, we disclaim any commitment to do so except as required by applicable securities laws.

**Glossary**

The oil and gas terms and other terms defined in this section are used throughout this report. The definitions of the terms "developed reserves," "exploratory well," "field," "proved reserves," and "undeveloped reserves" have been abbreviated from the respective definitions under Rule 4-10(a) of Regulation S-X. The entire definitions of those terms under Rule 4-10(a) of Regulation S-X can be located on the Securities and Exchange Commission's ("SEC") website at www.sec.gov.

*Ad valorem tax.* A tax based on the value of real estate or personal property.

*ASC.* Accounting Standards Codification.

*ASU.* Accounting Standards Update.

*Basin.* A large depression on the earth's surface in which sediments are generally deposited.

*Bbl.* One stock tank barrel, or 42 U.S. gallons liquid volume, used in reference to oil, NGLs, water, or other liquid hydrocarbons.

*BBtu.* One billion British thermal units.

*Bcf*. One billion cubic feet, used in reference to gas.

*BOE.* Barrels of oil equivalent. Oil equivalents are determined using the ratio of six Mcf of gas to one Bbl of oil or NGLs.

*Btu.* One British thermal unit, the quantity of heat required to raise the temperature of a one-pound mass of water by one degree Fahrenheit.

*Civitas Merger.* On November 2, 2025, we entered into an Agreement and Plan of Merger (the "Merger Agreement") with Civitas. The Merger was completed on January 30, 2026 (the "Closing Date"). Refer to *Note 17 – Mergers, Acquisitions, and Divestitures* in Part II, Item 8 of this report for full definition and additional discussion. Referred to throughout as "Merger" or "Civitas Merger."

*Completion.* The installation of equipment for production of oil, gas, and/or NGLs, or in the case of a dry hole, the reporting to the applicable authority that the well has been abandoned.

*Conversion rate.* Current year conversions of proved undeveloped reserves to proved developed reserves, divided by beginning of the year proved undeveloped reserves (also commonly referred to in our industry as "*track record"*).

*Costs incurred.* Costs incurred in oil and gas property acquisition, exploration, and development activities, whether capitalized or expensed.

*Developed acreage.* The number of acres that are allocated or assignable to productive wells or wells capable of production.

*Developed reserves.* Reserves that can be expected to be recovered: (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 (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.

*Development well.* A well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive.

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*Dry hole.* An exploratory, development, or extension well that proves to be incapable of producing oil, gas, and/or NGLs in sufficient commercial quantities to justify completion, or upon completion, the economic operation of a well (also referred to as "*non-productive well"*).

*Exploratory well.* A well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir.

*Extension well*. A well drilled to extend the limits of a known reservoir.

*FASB.* Financial Accounting Standards Board.

*Fee properties.* The most extensive interest that can be owned in land, including surface and mineral (including oil and gas) rights.

*Field.* An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition.

*Formation.* A succession of sedimentary beds that were deposited under the same general geologic conditions.

*GAAP.* Accounting principles generally accepted in the United States.

*Gross acres or gross wells.* Acres or wells in which a working interest is owned.

*Horizontal wells.* Wells that are drilled at angles greater than 70 degrees from vertical.

*Lease operating expenses ("LOE*")*.* The expenses incurred in the lifting of oil, gas, and/or NGLs from a producing formation to the surface, constituting part of the current operating expenses of a working interest, and also including labor, superintendence, supplies, repairs, maintenance, allocated overhead costs, and other expenses incidental to production, but not including lease acquisition, drilling, or completion costs.

*MBbl.* One thousand barrels, used in reference to oil, NGLs, water, or other liquid hydrocarbons.

*MBOE.* One thousand barrels of oil equivalent.

*Mcf.* One thousand cubic feet, used in reference to gas.

*MMBbl.* One million barrels, used in reference to oil, NGLs, water, or other liquid hydrocarbons.

*MMBOE.* One million barrels of oil equivalent.

*MMBtu.* One million British thermal units.

*MMcf.* One million cubic feet, used in reference to gas.

*Net acres or net wells.* Sum of our fractional working interests owned in gross acres or gross wells.

*NGLs.* The combination of ethane, propane, isobutane, normal butane, and natural gasoline that when removed from gas become liquid under various levels of higher pressure and lower temperature.

*NYMEX WTI.* New York Mercantile Exchange West Texas Intermediate, a common industry benchmark price for oil.

*NYMEX Henry Hub ("HH").* New York Mercantile Exchange Henry Hub, a common industry benchmark price for gas.

*OPEC+.* The Organization of the Petroleum Exporting Countries ("*OPEC*") plus other non-OPEC oil producing countries.

*OPIS*. Oil Price Information Service, a common industry benchmark for NGL pricing at Mont Belvieu, Texas.

*PV-10.* PV-10 is a non-GAAP measure. The present value of estimated future revenue to be generated from the production of estimated proved reserves, net of estimated production and future development costs, based on prices used in estimating the proved reserves and costs in effect as of the date indicated (unless such costs are subject to change pursuant to contractual provisions), without giving effect to non-property related expenses such as general and administrative expenses, debt service, future income tax expenses, or depreciation, depletion, and amortization, discounted using an annual rate of 10 percent. While this measure does not include the effect of income taxes as it would in the use of the standardized measure of discounted future net cash flows calculation, it

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does provide an indicative representation of the relative value of the Company on a comparative basis to other companies and from period to period. This measure is presented because management believes it provides useful information to investors for analysis of the Company's fundamental business on a recurring basis.

*Productive well.* An exploratory, development, or extension well that is producing or is capable of commercial production of oil, gas, and/or NGLs.

*Proved reserves.* Those quantities of oil, gas, and NGLs that, 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. Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined, and the price to be used is 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.

*Recompletion.* The completion of an existing wellbore in a formation other than that in which the well has previously been completed.

*Reserve life index.* Expressed in years, represents the estimated proved reserves as of the end of the year divided by actual production for the preceding 12-month period.

*Reservoir.* A porous and permeable underground formation containing a natural accumulation of producible oil, gas, and/or associated liquid resources that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.

*Resource play.* A term used to describe an accumulation of oil, gas, and/or associated liquid resources known to exist over a large areal expanse, which when compared to a conventional play typically has lower expected geological risk.

*Royalty.* The amount or fee paid to the owner of mineral rights, expressed as a percentage or fraction of gross income from oil, gas, and NGLs produced and sold unencumbered by expenses relating to the drilling, completing, and operating of the affected well.

*Royalty interest.* An interest in an oil and gas property entitling the owner to shares of oil, gas, and NGL production free of costs of exploration, development, and production operations.

*Seismic.* The sending of energy waves or sound waves into the earth and analyzing the wave reflections to infer the type, size, shape, and depth of subsurface rock formations.

*Shale.* Fine-grained sedimentary rock composed mostly of consolidated clay or mud. Shale is the most frequently occurring sedimentary rock.

*SOFR.* Secured Overnight Financing Rate.

*Standardized measure of discounted future net cash flows.* The discounted future net cash flows related to estimated proved reserves based on prices used in estimating the reserves, year-end costs, and statutory tax rates, at a 10 percent annual discount rate. The information for this calculation is included in *Supplemental Oil and Gas Information (unaudited)* located in Part II, Item 8 of this report.

*Uinta Basin Acquisition.* On October 1, 2024, we completed the acquisition of assets in the Uinta Basin of northeastern Utah. Refer to *Note 17 – Mergers, Acquisitions, and Divestitures* in Part II, Item 8 of this report for full definition and additional discussion.

*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 oil, gas, and NGLs regardless of whether such acreage contains estimated proved reserves.

*Undeveloped reserves.* Reserves 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. The applicable SEC definition of undeveloped reserves provides that 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.

*Working interest.* The operating interest that gives the owner the right to drill, produce, and conduct operating activities on the property and to share in the production, sales, and costs.

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**PART I**

When we use the terms "SM Energy," the "Company," "we," "us," or "our," we are referring to SM Energy Company and its subsidiaries unless the context otherwise requires. We have included certain technical terms important to an understanding of our business in the *Glossary* section of this report. Throughout this document we make statements and projections that address future expectations, possibilities, or events, all of which may be classified as "forward-looking statements." Refer to the *Cautionary Information about Forward-Looking Statements* section of this report for an explanation of these types of statements and the associated risks and uncertainties.

**ITEMS 1. AND 2. BUSINESS AND PROPERTIES**

**General**

We are an independent energy company engaged in the acquisition, exploration, development, and production of oil, gas, and NGLs in Texas, Utah, and following the closing of the Civitas Merger on January 30, 2026, Colorado and New Mexico. SM Energy was founded in 1908, incorporated in Delaware in 1915, and our initial public offering of common stock was in 1992. Our common stock trades on the New York Stock Exchange under the ticker symbol "SM."

Our principal office is located at 1700 Lincoln Street, Suite 3200, Denver, Colorado 80203, and our telephone number is (303) 861-8140.

**Strategy**

Our purpose is to make people's lives better by responsibly producing energy supplies, contributing to domestic energy security and prosperity, and having a positive impact in the communities where we live and work. We are a premier operator of top-tier assets, utilizing state-of-the-art digital technology, data analytics, and artificial intelligence ("AI") in our operations, and continually seeking innovative ideas to optimize capital efficiency and well performance, while striving to reduce our impact on shared natural resources and operating in an efficient, safe, and responsible manner.

Following the Civitas Merger, our asset portfolio consists of high-quality assets in the Midland Basin and Delaware Basin, both of which are part of the larger Permian Basin of Texas and New Mexico, the Maverick Basin of South Texas, the Uinta Basin of northeast Utah, and the Denver-Julesburg Basin ("DJ Basin") of northeast Colorado. We believe our assets are capable of generating strong returns in the current macroeconomic environment and provide resilience to commodity price risk and volatility. Through disciplined capital spending, strategic acquisitions and divestitures, and continued development and optimization, we seek to maximize returns and increase the value of our top-tier asset base while maintaining financial flexibility and a sustainable approach to long-term value creation.

Our long-term vision and strategy are focused on sustainably growing value for all of our stakeholders by deploying technical excellence and exceptional execution to improve and optimize our high-quality asset portfolio, generate cash flows, and maintain a disciplined, strong balance sheet. Our team executes our strategy by prioritizing safety, technological innovation, and stewardship of natural resources, which are foundational to our corporate culture. Our near-term strategic focus is the successful integration of Civitas following the closing of the Merger on January 30, 2026. Integration is centered on maintaining safe operations, delivering consistent operational execution, and continuing to generate cash flows that enable us to return value to stockholders through fixed dividend payments, debt reduction, and share repurchases. Refer to *Outlook* for discussion of our 2026 capital program.

We are committed to exceptional safety, health, and environmental stewardship; supporting the professional development of a diverse and thriving team of employees; building and maintaining partnerships with our stakeholders by investing in and connecting with the communities where we live and work; and transparency in reporting our progress in these areas. We have prioritized sustainability initiatives by, among other things, integrating enhanced environmental and social programs throughout the organization and setting goals that include safety and spill metrics. Additionally, we have implemented systems and technologies to track sustainability metrics to improve future reporting and performance and to increase employee awareness. We continue to evaluate new technologies to support our sustainability initiatives. The Governance and Sustainability Committee of our Board of Directors oversees, among other things, the effectiveness of our sustainability policies, programs and initiatives, monitors and responds to emerging trends, issues, and associated risks, and, together with management, reports to our Board of Directors regarding such matters. Further demonstrating our commitment to sustainable operations and environmental stewardship, compensation for our executives and employees under certain aspects of our compensation plans is calculated based on Company-wide performance metrics that include key financial, operational, environmental, health, and safety measures.

**Significant Developments in 2025**

*Merger and Acquisition Activity*. On November 2, 2025, we entered into the Merger Agreement with Civitas. The Merger was completed on January 30, 2026, expanding our asset portfolio to include operations in the DJ Basin in Colorado and the Delaware Basin in New Mexico and Texas, while creating complementary development and exploration opportunities in the Midland Basin, where

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we already have a proven track record of successful operations. Combining our technical expertise and complementary asset programs expands our ability to responsibly produce energy in high-return basins while supporting the communities where we live and work.

Although this report is being filed following the closing of the Merger, unless otherwise specifically noted, information set forth herein only relates to the period as of and for the fiscal year ended December 31, 2025, and therefore does not include information relating to Civitas or its subsidiaries as of and for such period ended. Accordingly, unless otherwise specifically noted, references herein to "SM Energy" or the "Company" prior to the closing of the Merger do not include Civitas or the Civitas subsidiaries acquired in connection with the Civitas Merger.

The Civitas Merger will be accounted for as a business combination using the acquisition method of accounting with SM Energy treated as the accounting acquirer. Under the acquisition method of accounting, we will record all assets acquired and liabilities assumed from Civitas at their fair values as of the Closing Date. Following the closing of the Merger, Civitas' post-Merger results of operations will be consolidated into SM Energy's interim consolidated financial statements.

During the first quarter of 2025, we finalized post-closing adjustments related to the Uinta Basin Acquisition. The final adjusted purchase price was $2.1 billion. During the first half of 2025, we focused on the successful integration of our Uinta Basin assets, and during the second half of 2025, our focus shifted to optimizing operations and development to deliver sustained value from this core asset. The 2024 information presented in this report regarding our Uinta Basin assets pertains only to the fourth quarter of 2024 and does not represent the full-year 2024, as the assets were acquired on October 1, 2024.

Refer to *Note 17 – Mergers, Acquisitions, and Divestitures* in Part II, Item 8 of this report for additional discussion.

*Reserves and Capital Investment.* Our total estimated net proved reserves decreased slightly to 673.0 MMBOE as of December 31, 2025 from 678.3 MMBOE as of December 31, 2024. This decrease primarily related to 75.5 MMBOE produced during 2025, 40.7 MMBOE of revisions of previous estimates related to the removal of certain net proved undeveloped reserve cases that are no longer expected to be developed within the five-year period from initial booking, and 15.5 MMBOE of net negative performance and price revisions. These decreases were mostly offset by positive revisions of previous estimates of 87.0 MMBOE related to infill reserves, primarily related to our South Texas assets, and additions from extensions and discoveries of 39.7 MMBOE, primarily related to our Uinta Basin assets. Our proved reserve life index decreased to 8.9 years as of December 31, 2025, compared with 10.9 years as of December 31, 2024. Refer to *Areas of Operation* and *Reserves* below for additional discussion of changes in estimated net proved reserves. Costs incurred decreased 59 percent from 2024 to $1.4 billion in 2025, as 2024 included the acquisition of proved and unproved properties related to the Uinta Basin Acquisition. Refer to *Areas of Operation* below, and to *Supplemental Oil and Gas Information (unaudited)* in Part II, Item 8 of this report for additional discussion.

*Production, Pricing and Revenue, and Commodity Derivatives.* Our average net daily equivalent production in 2025 increased 21 percent compared with 2024 to 206.8 MBOE, consisting of 110.5 MBbl of oil, 412.3 MMcf of gas, and 27.6 MBbl of NGLs, resulting from a full year of production from our Uinta Basin assets and continued strong well performance. Oil production as a percentage of total production increased to 53 percent in 2025 from 47 percent in 2024, resulting from a full year of oil production from our Uinta Basin assets, which averaged 87 percent oil production.

Realized prices before the effect of net derivative settlements ("realized price" or "realized prices") for oil and NGLs decreased 15 percent and three percent, respectively, while realized gas prices increased 29 percent, for the year ended December 31, 2025, compared with 2024. Oil, gas, and NGL production revenue increased 17 percent to $3.1 billion for the year ended December 31, 2025, compared with $2.7 billion for 2024, primarily due to the addition of production from our Uinta Basin assets for full year 2025. Oil production revenue was 82 percent of total production revenue for each of the years ended December 31, 2025, and 2024.

We recorded net derivative gains of $178 million and $50 million for the years ended December 31, 2025, and 2024, respectively. These amounts include net derivative settlement gains of $132 million and $69 million for the years ended December 31, 2025, and 2024, respectively.

Refer to *Areas of Operation* below and *Overview of the Company* in Part II, Item 7 of this report for additional discussion.

**Outlook**

Our long-term vision and strategy is to sustainably grow value for all of our stakeholders as a premier operator of top-tier assets. Our 2026 strategy and operating plan seek to deliver long-term profitability and value creation through the following priorities:

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• Successfully integrating Civitas.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• Completing the divestiture of certain of our South Texas assets which will advance our deleveraging goals and position us to substantially achieve our commitment to complete at least $1.0 billion of divestitures within one year following the closing of the Civitas Merger.

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&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• Generating cash flows to support reducing debt and returning capital to stockholders through our increased annual base dividend of $0.88 per share and share repurchases.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• Executing operations with financial discipline by focusing on capital efficiency, and the development of low breakeven, high-return wells across our portfolio, while maintaining an emphasis on innovation and remaining a leader in stewardship.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• Capturing and maximizing synergies consisting of overhead and G&A, drilling and completion and operational costs, and cost of capital.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• Maintaining and expanding our portfolio of top-tier economic drilling inventory through exploration activities, the application of advanced analytics and new technologies, development optimization, and acquisitions.

We expect our total 2026 capital program to be approximately $2.65 billion to $2.85 billion, excluding acquisitions, which we expect to fund with cash flows from operations, with any remaining cash needs being funded by borrowings under our revolving credit facility. We plan to focus our 2026 capital program on highly economic oil development projects across our asset base.

Refer to *Overview of Liquidity and Capital Resources* in Part II, Item 7 of this report and *Note 17 – Mergers, Acquisitions, and Divestitures* in Part II, Item 8 of this report for additional discussion.

**Areas of Operation**

All of our operations are conducted in the United States, in the areas described below. The following table summarizes estimated net proved reserves, net production volumes, and costs incurred for these areas, for the year ended December 31, 2025:

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| | | | | |
|:---|:---|:---|:---|:---|
| | **Midland Basin** | **South Texas** | **Uinta Basin** | **Total** <sup>(1)</sup> |
| **Net proved reserves** | | | | |
| &nbsp;&nbsp;&nbsp;&nbsp;Oil (MMBbl) | 117.0 | 74.3 | 92.6 | 283.9 |
| &nbsp;&nbsp;&nbsp;&nbsp;Gas (Bcf) | 583.0 | 906.3 | 109.2 | 1598.5 |
| &nbsp;&nbsp;&nbsp;&nbsp;NGLs (MMBbl) | 0.1 | 122.5 |  | 122.6 |
| &nbsp;&nbsp;&nbsp;&nbsp;MMBOE <sup>(1)</sup> | 214.2 | 347.9 | 110.9 | 673.0 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Relative percentage | 32% | 52% | 16% | 100% |
| &nbsp;&nbsp;&nbsp;&nbsp;Proved developed % | 80% | 55% | 44% | 61% |
| **Net production volumes** |  |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Oil (MMBbl) | 19.2 | 7.3 | 13.9 | 40.3 |
| &nbsp;&nbsp;&nbsp;&nbsp;Gas (Bcf) | 66.3 | 71.7 | 12.5 | 150.5 |
| &nbsp;&nbsp;&nbsp;&nbsp;NGLs (MMBbl) |  | 10.1 |  | 10.1 |
| &nbsp;&nbsp;&nbsp;&nbsp;MMBOE <sup>(1)</sup> | 30.2 | 29.3 | 15.9 | 75.5 |
| &nbsp;&nbsp;&nbsp;&nbsp;Avg. daily equivalents (MBOE/d) <sup>(1)</sup> | 82.8 | 80.3 | 43.7 | 206.8 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Relative percentage | 40% | 39% | 21% | 100% |
| **Costs incurred (in millions)** <sup>(2)</sup> | $548 | $361 | $481 | $1448 |

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<sup>(1)</sup> Amounts may not calculate due to rounding.

<sup>(2)</sup> Asset costs incurred do not sum to total costs incurred primarily due to corporate charges incurred on exploration activities and costs related to exploration efforts outside of our core areas of operation that are excluded from this table. For total costs incurred, refer to *Costs Incurred* in *Supplemental Oil and Gas Information (unaudited)* in Part II, Item 8 of this report.

Total estimated net proved reserves at December 31, 2025, decreased one percent from December 31, 2024. Total net equivalent production increased 21 percent for the year ended December 31, 2025, compared with 2024. Costs incurred for the year ended December 31, 2025, decreased 59 percent compared with 2024, as 2024 included the acquisition of proved and unproved properties related to the Uinta Basin Acquisition.

*Midland Basin.* As of December 31, 2025, our Midland Basin assets, located in the Permian Basin in West Texas, comprised approximately 98,000 net acres and included our RockStar assets in Howard and Martin counties and our Sweetie Peck assets in Upton and Midland counties ("Midland Basin"). In 2025, our drilling and completion activities focused on development optimization of our RockStar assets and delineation and development of our Sweetie Peck assets. Following the closing of the Civitas Merger, we expanded our Permian Basin position, increased our Midland Basin footprint and established a new position in the Delaware Basin in West Texas and New Mexico. Our post-Merger position provides substantial future development opportunities within multiple oil-rich intervals. We expect our 2026 capital activity in the Permian Basin to be focused on highly economic oil development projects.

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In 2025, costs incurred totaled $548 million, and we averaged three drilling rigs and one completion crew. We drilled 47 gross (37 net) wells and completed 72 gross (53 net) wells, and as of December 31, 2025, 15 gross (12 net) wells had been drilled but not completed in our operated Midland Basin program. Net equivalent production for the year ended December 31, 2025, was 30.2 MMBOE, a three percent increase from 29.4 MMBOE for the year ended December 31, 2024. Estimated net proved reserves decreased seven percent to 214.2 MMBOE at December 31, 2025, from 230.5 MMBOE at December 31, 2024. This decrease primarily consisted of 30.2 MMBOE of production, partially offset by 10.6 MMBOE of positive revisions of previous estimates related to infill, and 6.2 MMBOE of additions from extensions and discoveries.

*South Texas.* Our South Texas assets comprise approximately 155,000 net acres located in Dimmit and Webb counties, Texas ("South Texas"). In 2025, our operations focused on development and further delineation of the Austin Chalk formation. Our overlapping acreage position in South Texas covers a significant portion of the western Eagle Ford shale and Austin Chalk formations ("Maverick Basin") and includes acreage across the oil, gas-condensate, and dry gas windows with gas composition amenable to processing for NGL extraction. We expect our 2026 capital activity in South Texas to be focused primarily on developing the Austin Chalk formation.

In 2025, costs incurred totaled $361 million, and we averaged one drilling rig and one completion crew. We drilled 30 gross (29 net) wells and completed 33 gross (33 net) wells, and as of December 31, 2025, 25 gross (24 net) wells had been drilled but not completed in our operated South Texas program. Net equivalent production for the year ended December 31, 2025, was 29.3 MMBOE, a one percent decrease from 29.6 MMBOE for the year ended December 31, 2024. Estimated net proved reserves remained flat at 347.9 MMBOE at each of December 31, 2025, and 2024. Positive revisions of previous estimates of 63.5 MMBOE of infill and 10.5 MMBOE of price revisions, and additions of 9.1 MMBOE from extensions and discoveries, were offset by 29.3 MMBOE of production, the removal of 27.5 MMBOE of net proved undeveloped reserves that are no longer expected to be developed within the five-year period from initial booking, and negative performance revisions of 26.3 MMBOE consisting of 12.3 MMBOE related to offset development activity, 7.5 MMBOE related to well performance, and 6.5 MMBOE related to type curve updates.

*Uinta Basin.* Our Uinta Basin assets comprise approximately 62,000 net acres located in northeastern Utah. In 2025, our operations focused on delineation and development. Our Uinta Basin position provides substantial future development and exploration opportunities within multiple oil-rich intervals in the Lower Green River and Wasatch formations, and includes acreage with waxy crude and gas composition amenable to processing for NGL extraction. We expect our 2026 capital activity in the Uinta Basin to be focused on highly economic oil development projects.

In 2025, costs incurred totaled $481 million, and we averaged three drilling rigs and one completion crew. We drilled 52 gross (38 net) wells and completed 62 gross (49 net) wells, and as of December 31, 2025, 38 gross (28 net) wells had been drilled but not completed in our operated Uinta Basin program. Net equivalent production for the year ended December 31, 2025, was 15.9 MMBOE, an increase from 3.3 MMBOE for the year ended December 31, 2024, which only included production during the fourth quarter of 2024. Estimated net proved reserves increased 11 percent to 110.9 MMBOE at December 31, 2025, from 99.9 MMBOE at December 31, 2024. The increase primarily related to 24.3 MMBOE of additions from extensions and discoveries and positive revisions of previous estimates of 13.0 MMBOE related to infill, partially offset by 15.9 MMBOE of production and the removal of 10.2 MMBOE of net proved undeveloped reserves that are no longer expected to be developed within the five-year period from initial booking.

*DJ Basin.* Following the closing of the Civitas Merger, our asset portfolio has expanded to include the DJ Basin of northeast Colorado. Our DJ Basin position provides substantial future development opportunities within multiple oil-rich intervals in the Niobrara and Codell formations. We expect our 2026 capital activity in the DJ Basin to be focused on highly economic oil development projects.

*Office Space.* As of December 31, 2025, we leased and owned office space as summarized in the table below:

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| | | |
|:---|:---|:---|
| | **Approximate Square Footage Leased** | **Approximate Square Footage Owned** |
| Corporate - Denver, CO | 74000 |  |
| Midland, TX | 59000 |  |
| Houston, TX and Catarina, TX, respectively | 41000 | 15000 |
| Roosevelt, UT |  | 7000 |
| Total | 174000 | 22000 |

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**Reserves**

Reserve estimates are inherently imprecise. Estimates for new discoveries and undeveloped locations are considered more imprecise than reserve estimates for producing oil and gas properties. Accordingly, we expect these estimates to change as new information becomes available. The table below presents the standardized measure of discounted future net cash flows and PV-10. PV-10 is a non-GAAP financial measure that is reconciled to the standardized measure of discounted future net cash flows, the most directly comparable GAAP financial measure. PV-10 does not include the effects of income taxes on future net revenues. Neither the standardized measure of discounted future net cash flows nor PV-10 represents the fair market value of our oil and gas properties. We

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and others in the oil and gas industry use PV-10 as a measure to compare the relative size and value of proved reserves held before consideration of tax characteristics specific to individual entities. Refer to the *Glossary* section of this report for additional information regarding these measures and refer to the reconciliation of the standardized measure of discounted future net cash flows to PV-10 set forth below. The actual quantities and present value of our estimated net proved reserves may be more or less than we have estimated. No estimates of our proved reserves have been filed with or included in reports to any federal authority or agency, other than the SEC, since the beginning of the last fiscal year. The table below should be read along with *Risk Factors* in Part I, Item 1A of this report.

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The following table summarizes estimated net proved reserves, the standardized measure of discounted future net cash flows (GAAP), PV-10 (non-GAAP), the prices used in the calculation of net proved reserves estimates, and reserve life index as of December 31, 2025, 2024, and 2023:

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| | | | |
|:---|:---|:---|:---|
| | **As of December 31,** | **As of December 31,** | **As of December 31,** |
| | **2025** | **2024** | **2023** |
| **Net reserve volumes:** |  |  |  |
| Proved developed |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Oil (MMBbl) | 163.7 | 160.3 | 118.5 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Gas (Bcf) | 1069.7 | 1031.3 | 948.5 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;NGLs (MMBbl) | 70.3 | 71.8 | 64.7 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;MMBOE | 412.3 | 404.0 | 341.2 |
| Proved undeveloped |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Oil (MMBbl) | 120.2 | 135.7 | 111.6 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Gas (Bcf) | 528.8 | 517.8 | 583.5 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;NGLs (MMBbl) | 52.3 | 52.4 | 54.8 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;MMBOE | 260.7 | 274.3 | 263.6 |
| Total proved |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Oil (MMBbl) | 283.9 | 296.0 | 230.1 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Gas (Bcf) | 1598.5 | 1549.1 | 1532.0 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;NGLs (MMBbl) | 122.6 | 124.1 | 119.5 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;MMBOE | 673.0 | 678.3 | 604.9 |
| Net proved developed reserves percentage | 61% | 60% | 56% |
| Net proved undeveloped reserves percentage | 39% | 40% | 44% |
| **Reserve data (in millions):** |  |  |  |
| Standardized measure of discounted future net cash flows (GAAP) | $5956 | $7268 | $6280 |
| PV-10 (non-GAAP): |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Proved developed PV-10 | $5130 | $5648 | $4965 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Proved undeveloped PV-10 | 1717 | 2708 | 2411 |
| Total proved PV-10 (non-GAAP) | $6847 | $8356 | $7377 |
| **12-month trailing average prices:** <sup>(1)</sup> |  |  |  |
| &nbsp;&nbsp;Oil (per Bbl) | $65.34 | $75.48 | $78.22 |
| &nbsp;&nbsp;Gas (per MMBtu) | $3.39 | $2.13 | $2.64 |
| &nbsp;&nbsp;NGLs (per Bbl) | $27.45 | $28.29 | $27.72 |
| Reserve life index (years) <sup>(2) (3)</sup> | 8.9 | 10.9 | 10.9 |

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____________________________________________

Note: Amounts may not calculate due to rounding.

<sup>(1)</sup> The prices used in the calculation of proved reserve estimates reflect the unweighted arithmetic average of the first-day-of-the-month price of each month within the trailing 12-month period in accordance with SEC rules. We then adjust these prices to reflect appropriate quality and location differentials over the period in estimating our net proved reserves.

<sup>(2)</sup> Refer to the reserve life index term in the *Glossary* section of this report for a description of how this metric is calculated.

<sup>(3)</sup> As of December 31, 2025, and 2024 the reserve life index includes production from our Uinta Basin assets and reflects activity occurring after the closing of the Uinta Basin Acquisition on October 1, 2024. Refer to *Note 17 – Mergers, Acquisitions, and Divestitures* in Part II, Item 8 of this report for additional discussion of the Uinta Basin Acquisition.

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The following table reconciles the standardized measure of discounted future net cash flows (GAAP) to the PV-10 (non-GAAP) of total estimated net proved reserves. Refer to the *Glossary* section of this report for the definitions of standardized measure of discounted future net cash flows and PV-10.

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| | | | |
|:---|:---|:---|:---|
| | **As of December 31,** | **As of December 31,** | **As of December 31,** |
| | **2025** | **2024** | **2023** |
| | **(in millions)** | **(in millions)** | **(in millions)** |
| Standardized measure of discounted future net cash flows (GAAP) | $5956 | $7268 | $6280 |
| Add: 10 percent annual discount, net of income taxes | 4318 | 5019 | 5295 |
| Add: future undiscounted income taxes | 1539 | 1796 | 2000 |
| Pre-tax undiscounted future net cash flows | 11813 | 14083 | 13575 |
| Less: 10 percent annual discount without tax effect | (4966) | (5727) | (6198) |
| PV-10 (non-GAAP) | $6847 | $8356 | $7377 |

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*Proved Undeveloped Reserves*

Proved undeveloped reserves include those reserves that are expected to be recovered from future wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Undeveloped reserves may be classified as proved reserves on undrilled acreage directly offsetting development areas that are reasonably certain of economic producibility when drilled or where reliable technology provides reasonable certainty of economic producibility. Undrilled locations may be classified as having proved undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless specific circumstances justify a longer time. As of December 31, 2025, we did not have any net proved undeveloped reserves that had been on our books in excess of five years, and substantially all of our net proved undeveloped reserves were on acreage that was not expected to expire, or that was expected to be held through renewal, before the targeted completion date.

For proved undeveloped locations that are more than one development spacing area from developed producing locations, we utilized reliable geologic and engineering technology when booking estimated net proved undeveloped reserves. Of the 260.7 MMBOE of total net proved undeveloped reserves as of December 31, 2025, approximately 20.9 MMBOE, 8.4 MMBOE, and 21.1 MMBOE of net proved undeveloped reserves in the Midland Basin, South Texas, and the Uinta Basin, respectively, were offset by more than one development spacing area from the nearest proved developed producing location. We incorporated public and proprietary data from multiple sources to establish geologic continuity of each formation and their producing properties. This included seismic data and interpretations (3-D and micro seismic), open hole log information (both vertically and horizontally collected) and petrophysical analysis of that log data, mud logs, gas sample analysis, measurements of total organic content, thermal maturity, test production, fluid properties, and core data as well as statistical performance data yielding predictable and repeatable reserve estimates within certain analogous areas. These locations were limited to only those areas where both established geologic consistency and sufficient statistical performance data could be demonstrated to provide reasonably certain results.

As of December 31, 2025, estimated net proved undeveloped reserves decreased 13.6 MMBOE, or five percent, compared with December 31, 2024. The following table provides a reconciliation of our net proved undeveloped reserves for the year ended December 31, 2025:

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| | |
|:---|:---|
| | **Total<br>(MMBOE)** |
| Total net proved undeveloped reserves: |  |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Beginning of year | 274.3 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Conversions to proved developed | (87.0) |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Revisions of previous estimates | 75.8 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Removed for five-year rule | (40.7) |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Additions from extensions and discoveries | 38.7 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Sales of reserves | (1.7) |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Purchases of minerals in place | 1.2 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;End of year <sup>(1)</sup> | 260.7 |

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____________________________________________

<sup>(1)</sup> Amount may not calculate due to rounding.

*Conversions to proved developed.* Our 2025 conversion rate was 32 percent and resulted primarily from the development of proved reserves in our Midland Basin program, our Austin Chalk assets in our South Texas program, and our Uinta Basin program.

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During 2025, we incurred $964 million on projects with reserves booked as proved undeveloped at the end of 2024, of which $796 million was spent on converting net proved undeveloped reserves to proved developed reserves by December 31, 2025. At December 31, 2025, operated drilled but not completed wells represented 51.9 MMBOE of total estimated net proved undeveloped reserves. We expect to incur $339 million of additional capital expenditures in completing these drilled but not completed wells, and we expect all estimated net proved undeveloped reserves to be converted to proved developed reserves within five years from their initial booking as net proved undeveloped reserves.

*Revisions of previous estimates*. During 2025, revisions of previous estimates totaled 75.8 MMBOE. Positive revisions consisted of 84.6 MMBOE of infill reserves, of which 62.7 MMBOE, 12.1 MMBOE, and 9.8 MMBOE of estimated net proved undeveloped reserves were attributable to our South Texas, Uinta Basin, and Midland Basin programs, respectively. Negative revisions consisted of 8.3 MMBOE that resulted from well performance related to infill development, and price revisions of 0.5 MMBOE that resulted from a decrease in oil prices.

*Removed for five-year rule.* As a result of our testing and delineation efforts in 2025, we revised certain aspects of our future development plan to focus on maximizing returns and the value of our assets. We removed 40.7 MMBOE of estimated net proved undeveloped reserves that are no longer expected to be developed within the five-year period from initial booking and reclassified these locations to unproved reserve categories, of which 27.5 MMBOE, 10.2 MMBOE, and 3.0 MMBOE related to our South Texas, Uinta Basin, and Midland Basin programs, respectively.

*Additions from extensions and discoveries.* During 2025, we added 38.7 MMBOE of estimated net proved undeveloped reserves, of which, 23.3 MMBOE were in the Uinta Basin resulting from delineation of our assets in the Lower Green River formation, 9.1 MMBOE were in South Texas resulting from extensions from our continued success in delineating the Austin Chalk formation, and 6.2 MMBOE were in the Midland Basin resulting from further development of our assets.

As of December 31, 2025, estimated future development costs relating to our net proved undeveloped reserves totaled $2.6 billion, and we expect to incur approximately $972 million, $624 million, and $634 million in 2026, 2027, and 2028, respectively.

*Internal Controls Over Proved Reserves Estimates*

Our internal controls over the recording of proved reserves are structured to objectively and accurately estimate our reserve quantities and values in compliance with the SEC's regulations. Our process for managing and monitoring our proved reserves is delegated to our Corporate Engineering group and is coordinated by our Corporate Engineering Manager, subject to the oversight of our management and the Audit Committee of our Board of Directors ("Audit Committee"), as discussed below. Our Corporate Engineering Manager has worked in the energy industry since 2008 and has been employed by the Company since 2010. He holds a Bachelor of Science degree in Petroleum Engineering from Montana Technological University and is a Registered Professional Petroleum Engineer in the states of Texas, Wyoming, and Montana. He is also a member of the Society of Petroleum Engineers. Technical, geological, and engineering reviews of our assets are performed throughout the year by our staff. Data obtained from these reviews, in conjunction with economic data and our ownership information, is used in making a determination of estimated net proved reserve quantities. Our asset teams' engineering technical staff do not report directly to our Corporate Engineering Manager; they report to either their respective asset technical managers or directly to the asset senior vice president. This design is intended to promote objective and independent analysis within our asset teams in the proved reserves estimation process.

*Third-party Reserves Audit*

Ryder Scott is an independent petroleum engineering consulting firm that has been providing petroleum engineering consulting services throughout the world since 1937. Ryder Scott performed an independent audit using its own engineering assumptions, but with economic and ownership data we provided. Ryder Scott audits a minimum of 80 percent of our total calculated proved reserve PV-10. In the aggregate, the proved reserve amounts of our audited properties determined by Ryder Scott are required, per our policy, to be within 10 percent of our proved reserve amounts for the total Company, as well as for each respective major asset. The technical person at Ryder Scott primarily responsible for overseeing our reserves audit is a Managing Senior Vice President who received a Bachelor of Science degree in Petroleum Engineering and a Business Foundations Certificate from The University of Texas at Austin in 2002. She is a registered Professional Engineer in the State of Texas and a member of the Society of Petroleum Engineers. The 2025 Ryder Scott audit report is included as Exhibit 99.1.

In addition to a third-party audit, our reserves are reviewed by our management with the Audit Committee. Our management, which includes our President and Chief Executive Officer, Executive Vice President and Chief Financial Officer, and Executive Vice President and Chief Operating Officer, is responsible for reviewing and verifying that the estimate of proved reserves is reasonable, complete, and accurate. The Audit Committee reviews a summary of the final reserves estimate in conjunction with Ryder Scott's results and also meets with Ryder Scott representatives, separate from our management, from time to time to discuss processes and findings.

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**Production**

The following table summarizes our net production volumes and realized prices for oil, gas, and NGLs produced and sold during the periods presented, and related production expense on a per BOE basis:

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| | | | |
|:---|:---|:---|:---|
| | **For the Years Ended December 31,** | **For the Years Ended December 31,** | **For the Years Ended December 31,** |
| | **2025** | **2024** | **2023** |
| Net production volumes |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Oil (MMBbl) | 40.3 | 29.4 | 23.8 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Gas (Bcf) | 150.5 | 137.0 | 132.4 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;NGLs (MMBbl) | 10.1 | 10.2 | 9.7 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Equivalent (MMBOE) <sup>(1)</sup> | 75.5 | 62.4 | 55.5 |
| Midland Basin net production volumes <sup>(2)</sup> |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Oil (MMBbl) | 19.2 | 19.1 | 17.5 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Gas (Bcf) | 66.3 | 62.0 | 59.8 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;NGLs (MMBbl) |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Equivalent (MMBOE) <sup>(1)</sup> | 30.2 | 29.4 | 27.5 |
| Maverick Basin net production volumes <sup>(2)</sup> |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Oil (MMBbl) | 7.3 | 7.4 | 6.2 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Gas (Bcf) | 71.6 | 72.2 | 72.5 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;NGLs (MMBbl) | 10.1 | 10.2 | 9.6 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Equivalent (MMBOE) <sup>(1)</sup> | 29.3 | 29.6 | 27.9 |
| Uinta Basin net production volumes <sup>(2)</sup> |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Oil (MMBbl) | 13.9 | 2.9 |  |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Gas (Bcf) | 12.5 | 2.7 |  |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;NGLs (MMBbl) |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Equivalent (MMBOE) <sup>(1)</sup> | 15.9 | 3.3 |  |
| Realized price |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Oil (per Bbl) | $63.52 | $74.49 | $76.28 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Gas (per Mcf) | $2.35 | $1.82 | $2.48 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;NGLs (per Bbl) | $22.22 | $23.01 | $23.02 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Per BOE | $41.58 | $42.81 | $42.60 |
| Production expense per BOE |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Lease operating expense | $5.71 | $5.11 | $5.13 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Transportation costs | $3.87 | $2.68 | $2.46 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Production taxes | $1.69 | $1.86 | $1.89 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Ad valorem tax expense | $0.46 | $0.56 | $0.67 |

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____________________________________________

<sup>(1)</sup> Amounts may not calculate due to rounding.

<sup>(2)</sup> For each of the years ended December 31, 2025, and 2024, total estimated net proved reserves attributed to our Midland Basin, Maverick Basin, and Uinta Basin fields each exceeded 15 percent of our total estimated net proved reserves expressed on an equivalent basis. For the year ended December 31, 2023, total estimated net proved reserves attributed to our Midland Basin and Maverick Basin fields each exceeded 15 percent of our total estimated net proved reserves expressed on an equivalent basis.

**Productive Wells**

As of December 31, 2025, we had working interests in 1,365 gross (1,023 net) productive oil wells and 586 gross (550 net) productive gas wells. Productive wells are wells producing in commercial quantities or wells capable of commercial production that are temporarily shut-in. Multiple completions in the same wellbore are counted as one well, and as of December 31, 2025, one of these wells had multiple completions. A well is categorized under state reporting regulations as an oil well or a gas well based on the ratio of gas to oil when it first commenced production, but such designation may not be indicative of current or future production composition.

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**Drilling and Completion Activity**

All of our drilling and completion activities are conducted by independent contractors using equipment they own and operate. The following table summarizes the number of operated and outside-operated wells drilled and completed or recompleted on our properties in 2025, 2024, and 2023, excluding non-consented projects, active injector wells, saltwater disposal wells, or wells in which we own only a royalty interest:

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| | | | | | | |
|:---|:---|:---|:---|:---|:---|:---|
| | **For the Years Ended December 31,** | **For the Years Ended December 31,** | **For the Years Ended December 31,** | **For the Years Ended December 31,** | **For the Years Ended December 31,** | **For the Years Ended December 31,** |
| | **2025** | **2025** | **2024** | **2024** | **2023** | **2023** |
| | **Gross** | **Net** | **Gross** | **Net** | **Gross** | **Net** |
| Development wells |  |  |  |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Oil | 149 | 111 | 115 | 97 | 74 | 62 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Gas | 25 | 25 | 21 | 21 | 21 | 21 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Non-productive |  |  |  |  |  |  |
|  | 174 | 136 | 136 | 118 | 95 | 83 |
| Exploratory wells |  |  |  |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Oil | 5 | 4 | 15 | 15 | 5 | 4 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Gas |  |  | 1 | 1 | 5 | 5 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Non-productive <sup>(1)</sup> |  |  | 1 | 1 | 1 | 1 |
|  | 5 | 4 | 17 | 17 | 11 | 10 |
| Total | 179 | 140 | 153 | 135 | 106 | 93 |

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____________________________________________

Note: The number of wells drilled refers to the number of wells completed at any time during the respective year, regardless of when drilling was initiated.

<sup>(1)</sup> &nbsp;&nbsp;&nbsp;&nbsp;For each of the years ended December 31, 2024, and 2023, one gross (one net) well was unsuccessful due to technical issues during the drilling phase and was not included in the drilled or completed well counts.

In addition to the wells completed in 2025 (included in the table above), excluding any wells related to the Civitas Merger, we were actively participating in the drilling of 22 gross (17 net) wells and had 84 gross (69 net) drilled but not completed wells as of January 31, 2026. Drilled but not completed wells as of January 31, 2026, represent wells that were being completed or were waiting on completion. The drilled but not completed well count as of January 31, 2026, includes two gross (two net) wells that were not included in our five-year development plan as of December 31, 2025, each of which are in the Eagle Ford shale.

**Title to Properties**

As of December 31, 2025, approximately 98 percent and 96 percent of our Texas and Utah operated oil and gas producing assets, respectively, were located on private lands, held pursuant to oil and gas leases from private mineral owners, and were not located on federal lands or leased from the federal government. The remainder of our operated oil and gas producing assets in Texas are located on state lands, and the remainder of our operated oil and gas producing assets in Utah are located on federal, state or tribal lands. We have obtained title opinions or have conducted other title review on substantially all of our producing properties and believe we have satisfactory title to such properties. We obtain new or updated title opinions prior to commencing initial drilling operations on the properties that we operate. Most of our producing properties are subject to mortgages securing indebtedness under our Credit Agreement, as defined in *Note 5 – Long-Term Debt* in Part II, Item 8 of this report, royalty and overriding royalty interests, liens for current taxes, and other ordinary course burdens that we believe do not materially interfere with the development of such properties. We typically perform title investigations in accordance with standards generally accepted in the oil and gas industry before acquiring developed and undeveloped leasehold acreage.

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**Acreage**

The following table sets forth the number of gross and net surface acres of developed and undeveloped oil and gas leasehold, fee properties, and mineral servitudes that we held as of December 31, 2025:

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| | | | | | | |
|:---|:---|:---|:---|:---|:---|:---|
| | **Developed Acres** <sup>(1)</sup> | **Developed Acres** <sup>(1)</sup> | **Undeveloped Acres** <sup>(2)(3)</sup> | **Undeveloped Acres** <sup>(2)(3)</sup> | **Total** | **Total** |
| | **Gross** | **Net** | **Gross** | **Net** | **Gross** | **Net** |
| Midland Basin | 98757 | 88291 | 14145 | 9543 | 112902 | 97834 |
| South Texas <sup>(4)</sup> | 95507 | 94443 | 63251 | 60534 | 158758 | 154977 |
| Uinta Basin | 86835 | 55414 | 14231 | 6682 | 101066 | 62096 |
| Other <sup>(5)</sup> | 10699 | 10524 | 126028 | 61939 | 136727 | 72463 |
| &nbsp;&nbsp;&nbsp;Total | 291798 | 248672 | 217655 | 138698 | 509453 | 387370 |

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<sup>(1)</sup> Developed acreage is acreage assigned to producing wells for the state approved spacing unit for the producing formation. Our developed acreage that includes multiple formations with different well spacing requirements may be considered undeveloped for certain formations but has been included only as developed acreage in the table above.

<sup>(2)</sup> Undeveloped acreage is acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil, gas, and/or NGLs regardless of whether such acreage contains estimated net proved reserves.

<sup>(3)</sup> As of February 2, 2026, 47,657, 7,511, and 3,852 net acres of our undeveloped acreage, inclusive of the acquired Civitas assets, is scheduled to expire by December 31, 2026, 2027, and 2028, respectively, unless production is established, or we take other action to extend the terms of the applicable leases (a majority of this acreage is included in Other). Certain of our acreage, primarily in South Texas, is subject to lease consolidation agreements containing drilling, completion, and other obligations that we currently expect to satisfy. Failure to meet these obligations results in payments to lessors, or termination of the lease consolidation agreements, which could result in additional future lease expirations if continuous development obligations required by individual leases are not met.

<sup>(4)</sup> On February 17, 2026, we entered into the PSA with Caturus to sell approximately 61,000 net acres located in South Texas, of which, approximately 49,000 are developed and approximately 12,000 are undeveloped. Refer to *Note 17 – Mergers, Acquisitions, and Divestitures* in Part II, Item 8 of this report for additional discussion.

<sup>(5)</sup> Includes other non-core acreage located in Colorado, Louisiana, Montana, North Dakota, Texas, Utah, and Wyoming.

**Delivery Commitments**

For information about delivery commitments, refer to *Commitments* within *Note 6 – Commitments and Contingencies* in Part II, Item 8 of this report.

**Major Customers**

For major customers and entities under common control that accounted for 10 percent or more of our total oil, gas, and NGL production revenue for at least one of the years ended December 31, 2025, 2024, and 2023, refer to *Concentration of Credit Risk and Major Customers* within *Note 1 – Summary of Significant Accounting Policies* in Part II, Item 8 of this report.

**Human Capital**

Our Company culture recognizes our employees as our most valuable assets, encourages personal and professional development, promotes innovation and leadership among all employees and, in turn, supports our efforts to attract and retain talent. Through our culture, we promote:

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• integrity and ethical behavior in the conduct of our business;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• environmental, health, and safety priorities;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• prioritizing the success of others and the team;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• collaboration and openness to new ideas and technologies that serve business improvement;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• support for team members' professional and personal development; and

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• support for the communities where we live and work.

The core values of integrity and ethical behavior are the pillars of our culture, and all employees are responsible for upholding Company-wide standards and values. We have policies designed to promote ethical conduct and integrity, which employees are required to read and acknowledge on an annual basis. The health and safety of our employees and contractors is our highest priority.

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We strive to achieve performance excellence in environmental, health, and safety management, and compensation of all employees is tied to annual environmental, health, and safety performance goals.

Personal and professional development is an important part of our culture and is employee driven, manager facilitated, and organizationally supported. Employees are routinely provided training opportunities to develop skills in leadership, safety, and technical acumen, which help strengthen our efforts to conduct business with high ethical standards. During 2025, many of our employees participated in leadership and talent development programs that included industry, safety, and other specialized technical training.

We measure employee engagement and satisfaction through periodic surveys, administered by an independent third-party vendor.

We are proud of our many outstanding employees who invest their time, talents, and financial resources in their communities. Our annual charitable giving program includes a monetary match of our employees' personal contributions to qualified organizations and up to 12 hours per employee of Company-granted time to volunteer in the communities where we live and work.

We strive to provide competitive, performance-based compensation and benefits to our employees, including market-competitive pay, short-term and long-term incentive compensation plans, our Employee Stock Purchase Plan ("ESPP"), and various healthcare, retirement, and other benefit packages such as a hybrid work environment that is guided by each employee's job function and responsibilities. Compensation for our executives and employees under our short-term and long-term incentive plans is determined based on individual performance and Company performance with respect to qualitative and quantitative metrics that include environmental, health, and safety measures. The Compensation Committee of our Board of Directors oversees our compensation programs and regularly reviews program design to incentivize achievement of our corporate strategy and the matters of importance to our stakeholders. Significant planning for succession of key personnel is performed each year, or more frequently as deemed necessary by management.

As of February 2, 2026, we had 1,241 full-time employees, including former Civitas employees who became SM Energy employees upon the closing of the Merger on January 30, 2026. This headcount reflects the combined workforce immediately following the Merger and may change as the Company completes post-closing integration activities. None of these employees were subject to a collective bargaining agreement. We are committed to diversity at all levels of our organization, and we strive to provide equal employment opportunities to all employees and job applicants. We regularly perform internal analyses of our workforce demographics, and, at times, we retain a third party to conduct discrimination and pay equity testing. No discriminatory practices have been identified and no evidence of discrimination or pay inequity has been found. Additionally, we have established procedures and controls designed to support our objective of remaining, at all times, in material compliance with applicable federal, state, tribal, and local laws and governmental regulations.

**Seasonality**

The price of crude oil is primarily driven by global socioeconomic and geopolitical factors and is less affected by seasonal fluctuations; however, demand for energy is generally higher in the winter and in the summer driving season. The demand and price for gas generally increases during winter months and decreases during summer months. To lessen the effect of seasonal gas demand and price fluctuations, pipelines, utilities, local distribution companies, and industrial users regularly utilize gas storage facilities and forward purchase some of their anticipated winter requirements during the summer. However, increased summertime demand for electricity can divert gas that is traditionally placed into storage which, in turn, may increase the typical winter seasonal price. Seasonal anomalies, such as mild or extreme winters sometimes lessen or exacerbate these fluctuations.

Certain of our drilling, completion, and other operational activities are also subject to seasonal limitations. Seasonal weather conditions, government or tribal regulations, and lease stipulations could adversely affect our ability to conduct drilling activities in some of the areas where we operate. Refer to *Risk Factors* in Part I, Item 1A of this report for additional discussion.

**Competition**

The oil and gas industry is highly competitive, particularly with respect to acquiring prospective oil and gas properties. We believe our acreage positions provide a foundation for development activities that we expect to fuel our future growth. Our competitive position also depends on our geological, geophysical, and engineering expertise, as well as our financial resources. We believe the location of our acreage; our exploration, drilling, operational, and production expertise; available technologies; our financial resources and expertise; and the experience and knowledge of our management and technical teams enable us to compete in our core operating areas. However, we face competition from many major and independent oil and gas companies, which in some cases have larger technical teams and greater financial and operational resources than we do. Many of these companies not only engage in the acquisition, exploration, development, and production of oil and gas reserves, but also have gathering, processing or refining operations, market refined products, provide, dispose of and transport fresh and produced water, own drilling rigs or production equipment, or generate electricity, all of which, individually or in the aggregate, could provide such companies with a competitive advantage.

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We also compete with other oil and gas companies in securing drilling rigs and other equipment and services necessary for the drilling, completion, and maintenance of wells, as well as for the gathering, transporting, and processing of oil, gas, NGLs, and water. Consequently, we may face shortages, delays, or increased costs in securing these services from time to time. The oil and gas industry also faces competition from alternative fuel sources, including renewable energy sources such as solar and wind-generated energy, and other fossil fuels such as coal. Competitive conditions may be affected by future energy, environmental, climate-related, financial, or other policies, legislation, and regulations.

In addition, we compete for professionals in our workforce, including specialized roles in the oil and gas industry such as geologists, geophysicists, engineers, and others. Throughout the general labor market, the need to attract and retain talented people has grown at a time when the availability of individuals with these skills is becoming more limited due to the evolving demographics of our industry. The oil and gas industry is not insulated from the competition for qualified people, and we must compete effectively to be successful. Refer to *Human Capital* above and *Risk Factors* in Part I, Item 1A of this report for additional discussion.

**Government Regulations**

Our business is subject to federal, state, tribal, and local laws and governmental regulations. These laws and regulations frequently change in response to economic or political conditions, or other developments, and our regulatory burden may increase in the future. Laws and regulations have the potential to increase our cost of conducting business and consequently could affect our profitability.

*Energy Regulations*

*Production*. Our operations in Texas, Utah, Colorado, and New Mexico are subject to regulation under a wide range of local, state, and federal statutes, rules, orders and regulations. These laws and regulations govern the exploration for and production of oil, gas, and NGLs and may include, but are not limited to, laws and regulations: requiring permits for the drilling of wells; imposing bond requirements in order to drill or operate wells; and governing the timing of drilling and location of wells, the method of drilling and casing wells, the surface use and restoration of properties upon which wells are drilled, the plugging and abandonment of wells and pipelines, the production and operation of wells and other facilities, the size of drilling and spacing units or proration units, the number of wells that may be drilled in an area, the spacing of wells, the unitization or pooling of oil and gas properties, the maximum rates of production from oil and gas wells, limitations or prohibitions on the venting or flaring of gas, and the ratability or fair apportionment of production from fields and individual wells.

A portion of our acreage in the Uinta Basin is subject to tribal laws, ordinances, rules, and regulations. In addition to potential regulation by federal, state and local agencies and authorities, an entirely separate and distinct set of laws and regulations may apply to lessees, operators, third party contractors, and other parties on tribal or allotted Indian lands. These regulations include lease provisions, royalty matters, drilling and production requirements, environmental standards, and tribal employment and contractor preferences, among other matters. Further, lessees and operators on Indian lands may be subject to the jurisdiction of tribal courts, unless there is a specific waiver of sovereign immunity by the relevant tribe allowing resolution of disputes between the tribe and those lessees or operators to occur in federal or state court.

A portion of our acreage in the Uinta Basin is on federal lands subject to oil and gas leases administered by the Bureau of Land Management ("BLM"). These leases contain relatively standardized terms and require compliance with detailed regulations and orders that are subject to change. In addition to permits required from other regulatory agencies, lessees must obtain a permit from the BLM before drilling and must comply with regulations governing, among other things, engineering and construction specifications for production facilities, safety procedures, the valuation of production and payment of royalties, the removal of facilities, and the posting of bonds to ensure that lessee obligations are met. Under certain circumstances, the BLM may suspend or terminate our operations on federal leases.

*Regulation of transportation of oil*. Our sales of crude oil are affected by the availability, terms, and cost of transportation. Interstate transportation of oil by pipeline is regulated by the Federal Energy Regulatory Commission ("FERC") pursuant to the Interstate Commerce Act ("ICA"), the Energy Policy Act of 1992, and the rules and regulations promulgated under those laws. The ICA and its implementing regulations require that tariff rates for interstate service on oil pipelines, including interstate pipelines that transport crude oil and refined products (collectively referred to as "petroleum pipelines"), be just and reasonable and non-discriminatory and that such rates and terms and conditions of service be filed with FERC.

Intrastate oil pipeline transportation rates are generally subject to regulation by state regulatory commissions. The basis for intrastate oil pipeline regulation, and the degree of regulatory oversight and scrutiny given to intrastate oil pipeline rates, varies from state to state. Insofar as effective interstate and intrastate rates are equally applicable to all comparable shippers, we believe that the regulation of oil transportation rates will not affect our operations in any way that is materially different from how it affects operations of our competitors who are similarly situated.

*Regulation of transportation of natural gas.* Our sales of gas are affected by the availability, terms, and cost of gas pipeline transportation. FERC has jurisdiction over the transportation and sale for resale of gas in interstate commerce. FERC's current regulatory framework generally provides for a competitive and open access market for sales and transportation of gas. However, FERC

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regulations continue to affect the midstream and transportation segments of the industry, which affects the marketing of natural gas that we produce, as well as the revenues we receive for sales of our natural gas.

*Regulation of gathering activities*. Gathering service, which occurs upstream of jurisdictional transmission services, is regulated by the states onshore and in state waters. Section 1(b) of the Natural Gas Act ("NGA") exempts natural gas gathering facilities from regulation by FERC as a natural gas company under the NGA. Although its policy continues to evolve, FERC has reclassified certain jurisdictional transmission facilities as non-jurisdictional gathering facilities, which has the tendency to increase our costs of getting gas to point-of-sale locations. We believe that the natural gas pipelines in our gathering systems meet the traditional tests FERC has used to establish a pipeline's status as a gatherer not subject to regulation as a natural gas company. However, the classification and regulation of our gathering facilities could be subject to change based on future determinations by FERC, the courts, or Congress.

State regulation of natural gas gathering facilities generally includes various safety, environmental, and, in some circumstances, nondiscriminatory-take requirements. Although nondiscriminatory-take regulation has not generally been affirmatively applied by state agencies, natural gas gathering may receive greater regulatory scrutiny in the future.

Intrastate natural gas transportation is also subject to regulation by state regulatory agencies. The basis for intrastate regulation of natural gas transportation and the degree of regulatory oversight and scrutiny given to intrastate natural gas pipeline rates and services vary from state to state. Insofar as such regulation within a particular state will generally affect all intrastate natural gas shippers within the state on a comparable basis, we believe that the regulation of similarly situated intrastate natural gas transportation in the state in which we operate and ship natural gas on an intrastate basis will not affect our operations in any way that is materially different from how it affects operations of our competitors. Like the regulation of interstate transportation rates, the regulation of intrastate transportation rates affects the marketing of natural gas that we produce, as well as the revenues we receive for sales of our natural gas.

*Effects of Compliance with Regulations*. Changes in law and to FERC policies and regulations may adversely affect the availability and reliability of firm and/or interruptible transportation service on interstate pipelines. Changes in law and to FERC and state utility commission policies and regulations also may result in increased regulation of our business and operations, and we cannot predict what future action FERC or any state utility commission will take. We do not believe, however, that any regulatory changes will affect us in a way that materially differs from the way they will affect other natural gas producers, gatherers, and marketers with which we compete.

Failure to comply with applicable laws and regulations can result in substantial penalties and the suspension or cessation of operations. Our competitors in the oil and natural gas industry are subject to the same regulatory requirements and restrictions that affect our operations. The regulatory burden on the industry can increase the cost of doing business and negatively affect profitability. Because such laws and regulations are frequently revised and amended through various legislative actions and rulemakings, it is difficult to predict the future costs or impact of compliance. Additional rulemakings that affect the crude oil and natural gas industry are regularly considered at the federal, state, and various local government levels, including statutorily and through powers granted to various agencies that regulate our industry, and various court actions. We cannot predict when or whether any such future rulemakings may become effective or if the outcomes will negatively affect our operations.

We believe that continued substantial compliance with existing requirements will not have a material adverse effect on our financial position, cash flows, or results of operations. However, it is difficult to estimate the potential impact on our business from rules and regulations adopted by states in which we operate. Any new requirements or potential future rulemakings could make it more difficult and costly to develop new crude oil and natural gas wells and to continue to produce existing wells, increase our costs of compliance and doing business, and delay or prevent development in certain areas or under certain conditions. We cannot assure that the existing rules, as implemented, or any future rulemaking, will not have a material and adverse impact on our financial position, cash flows, or results of operations. In addition, the current regulatory requirements may change, currently unforeseen incidents may occur, or past noncompliance with laws or regulations may be discovered, any of which could likewise have a material adverse effect on our financial position, cash flows, or results of operations.

*Environmental, Health, and Safety Matters*

*General.* Our operations are subject to comprehensive and complex federal, state, tribal, and local laws and regulations governing protection of the environment and worker health and safety, as well as the discharge of materials and emissions into the environment. Various governmental agencies promulgate and enforce regulatory schemes to implement and enforce these laws, compliance with which can be complex and costly. These laws and regulations may, among other things:

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• require the acquisition of various permits before drilling commences;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• restrict the types, quantities, and concentration of various substances and emissions that may be released into the environment in connection with oil and gas drilling and production and saltwater disposal activities;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• limit or prohibit drilling activities on certain lands lying within wilderness, wetlands, and other protected areas, including areas containing certain wildlife or threatened and endangered plant and animal species;

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&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• impose stringent reporting requirements; and

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• require remedial measures to mitigate pollution from former and ongoing operations, such as closing pits and plugging abandoned wells.

These laws, rules, and regulations may also restrict the rate of oil and gas production below the rate that would otherwise be possible. The regulatory burden on the oil and gas industry increases the cost of conducting business and consequently affects profitability. Additionally, environmental laws and regulations are revised frequently, and any changes may result in more stringent, or different permitting, waste handling, disposal, and cleanup requirements for the oil and gas industry and could have a significant impact on our operating costs. Failure to comply with these laws or regulations or to obtain or comply with permits under such legal and regulatory schemes may result in the assessment of sanctions, including administrative penalties, civil penalties, criminal prosecution, imposition of investigatory, remedial or corrective actions, the required incurrence of capital expenditures, the occurrence of restrictions, delays or cancellations in the permitting, operation, development or expansion of projects, and the imposition of orders or injunctions to prohibit or restrict certain activities or force future compliance.

The following is a summary of some of the existing laws, rules, and regulations to which our business is subject.

*Waste handling.* The Resource Conservation and Recovery Act ("RCRA") and comparable state statutes regulate the generation, transportation, treatment, storage, disposal, and cleanup of hazardous and non-hazardous wastes. Under the auspices of the United States Environmental Protection Agency ("EPA"), individual states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent requirements. Drilling fluids, produced water, and most of the other wastes associated with the exploration, development, and production of oil or gas are currently regulated under RCRA's non-hazardous waste provisions. However, it is possible that certain oil and gas exploration and production wastes now classified as non-hazardous could be classified as hazardous wastes in the future. Any such change could result in an increase in our costs to manage and dispose of wastes, which could have a material adverse effect on our results of operations and financial position.

*Comprehensive Environmental Response, Compensation, and Liability Act.* The Comprehensive Environmental Response, Compensation, and Liability Act ("CERCLA"), also known as the Superfund law, imposes joint and several liability, without regard to fault or legality of conduct, on classes of persons who are considered to be responsible for the release or threatened release of a hazardous substance into the environment. These persons include the owner or operator of the site where the release occurred, and anyone who disposed or arranged for the disposal of, or transported, a hazardous substance released at the site. Under CERCLA, such persons may be subject to joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of environmental investigation and certain health studies. In addition, it is not uncommon for third-parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment.

We currently own, lease, or operate numerous properties that have been used for oil and gas exploration and production for many years. CERCLA excludes petroleum and natural gas from its definition of hazardous substances, and although we believe we have utilized operating and waste disposal practices that were standard in the industry at the time, hazardous substances or wastes may have been released on or under the properties owned or leased by us, or on or under other locations, including off-site locations, where such substances have been taken for disposal. In addition, some of our properties have been operated by third-parties or by previous owners or operators whose treatment and disposal of hazardous substances, wastes, or hydrocarbons were not under our control. These properties, and the substances disposed or released on them, may be subject to CERCLA, RCRA, and analogous state laws. Under such laws, we could be required to remove previously disposed substances and wastes, pay fines, remediate contaminated property, or perform remedial operations to prevent future contamination.

*Water discharges.* The federal Water Pollution Control Act ("Clean Water Act") and analogous state laws impose restrictions and strict controls with respect to the discharge of pollutants, including spills and leaks of oil and other substances, into waters of the United States and waters of the applicable states. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA, or analogous state agencies. This includes the discharge of certain storm water without a permit which requires periodic monitoring and sampling. In addition, the Clean Water Act regulates wastewater generated by unconventional oil and gas operations during the hydraulic fracturing process and discharged to publicly-owned wastewater treatment facilities. The Clean Water Act also prohibits discharge of dredged or fill material into waters of the United States, including wetlands, except in accordance with the terms of a permit issued by the United States Army Corps of Engineers, or a state, if the state has assumed authority to issue such permits. Federal and state regulatory agencies can impose administrative, civil, and criminal penalties for non-compliance with discharge permits or other requirements of the Clean Water Act and analogous state laws and regulations.

The Oil Pollution Act of 1990 ("OPA") addresses prevention, containment and cleanup, and liability associated with oil pollution. OPA applies to vessels, offshore platforms, and onshore facilities. OPA subjects owners of such facilities to strict liability for containment and removal costs, natural resource damages, and certain other consequences of oil spills into jurisdictional waters. Any unpermitted release of petroleum or other pollutants from our operations could result in governmental penalties and civil liability.

*Air emissions.* The federal Clean Air Act ("CAA") and comparable state laws and regulations regulate emissions of various air pollutants through air emissions permitting programs and the imposition of other requirements, such as requirements for emission reduction, capture and control. In addition, the EPA has developed, and continues to develop, stringent regulations governing

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emissions of hazardous air pollutants at specified sources. Federal and state regulatory agencies can impose administrative, civil, and criminal penalties for non-compliance with air permits or other requirements of the CAA and associated state laws and regulations. Refer to the *Environmental* section in Part II, Item 7 of this report for additional information about the regulation of air emissions from the oil and gas sector.

*Climate change.* In December 2009, the EPA determined that emissions of carbon dioxide, methane, and other greenhouse gases ("GHG" or "GHGs") endanger public health and welfare, and as a result, began adopting and implementing a comprehensive suite of regulations to restrict emissions of GHGs under existing provisions of the CAA. Current and future legislative and regulatory initiatives related to climate change and emissions of GHGs could have an adverse effect on our operations and the demand for oil and gas. For example, President Biden signed into law the Inflation Reduction Act ("IRA") in August 2022, which contained tax inducements and other provisions that incentivize investment, development, and deployment of alternative energy sources and technology, which could increase operating costs within the oil and gas industry and accelerate the transition away from fossil fuels. The Trump administration has diverged from the Biden administration's positions, and the passage of the One Big Beautiful Bill Act rescinded many IRA initiatives. In the absence of federal action regulating climate change or GHG, state and local regulators have and may continue to propose regulatory initiatives aimed at reducing GHG emissions. Refer to Risk Factors - Risks Related to Litigation and Government Regulations - Legislative and regulatory initiatives and litigation related to global warming and climate change could have an adverse effect on our operations and the demand for oil, gas, and NGLs, and could result in significant litigation, capital, and related expenses in Part I, Item 1A of this report. Meteorological or extreme weather events (whether or not related to climate change) pose additional risks to our operations, and in the past, have resulted in temporary shut-ins of certain wells and temporary capacity constraints at third-party purchasers impacting their ability to take delivery of our products.

*Endangered species.* The federal Endangered Species Act and analogous state laws regulate activities that could have an adverse effect on threatened or endangered species. Some of our operations are conducted in areas where protected species are known to exist. In these areas, we may be obligated to develop and implement plans to avoid potential adverse impacts on protected species, and we may be prohibited from conducting operations in certain locations or during certain seasons, such as breeding and nesting seasons, when our operations could have an adverse effect on these species. It is also possible that a federal or state agency could order a complete halt to activities in certain locations if it is determined that such activities may have a serious adverse effect on a protected species. The presence of a protected species in areas where we perform drilling, completion, and production activities could impair our ability to timely complete well drilling and development and could adversely affect our future production from those areas.

*OSHA and other laws and regulations.* We are subject to the requirements of the federal Occupational Safety and Health Act ("OSHA") and comparable state statutes. The OSHA hazard communication standard, the EPA community right-to-know regulations under Title III of CERCLA and similar state statutes require that we organize and/or disclose information about hazardous materials used or produced in our operations. Also, pursuant to OSHA, the Occupational Safety and Health Administration has established a variety of standards relating to workplace exposure to hazardous substances and employee health and safety. We believe we are in substantial compliance with the applicable requirements of OSHA and comparable laws.

*Hydraulic fracturing.* Hydraulic fracturing is an important and common practice used to stimulate production of hydrocarbons from tight shale formations. We routinely utilize hydraulic fracturing techniques in most of our drilling and completion programs. The process involves the injection of water, sand, and chemicals under pressure into the formation to fracture the surrounding rock and stimulate production. The process is typically regulated by state oil and gas commissions. However, even on private lands, the EPA has asserted federal regulatory authority over hydraulic fracturing involving diesel additives under the Safe Drinking Water Act's Underground Injection Control Program. The federal Safe Drinking Water Act protects the quality of the nation's public drinking water through the adoption of drinking water standards and controlling the injection of waste fluids, including saltwater disposal fluids, into below-ground formations that may adversely affect drinking water sources.

Increased regulation and scrutiny on oil and gas activities involving hydraulic fracturing techniques could potentially lead to a decrease in the completion of new oil and gas wells, an increase in compliance costs, delays, and changes in federal income tax laws, all of which could adversely affect our financial position, results of operations, and cash flows. As new laws or regulations that significantly restrict hydraulic fracturing are adopted at the state level, it could become more difficult or costly for us to perform fracturing to stimulate production from tight formations. These initiatives could subject our fracturing activities to additional permitting requirements, which could result in additional permitting delays and potential increases in costs. Restrictions on hydraulic fracturing could also reduce the amount of oil and gas that we are ultimately able to produce from our reserves.

We believe the trend in local and state environmental legislation and regulation may continue toward stricter standards, while the outlook regarding federal environmental legislation and regulation is more uncertain under the Trump administration. President Trump's administration will likely continue to withdraw from or otherwise roll back certain environmental commitments. Notably, on March 12, 2025, EPA Administrator Lee Zeldin announced initiatives to reconsider regulations addressing power plants, oil and gas, air pollution standards, GHG reporting, wastewater, endangerment findings, environmental justice, and other initiatives. While it is not possible at this time to predict how any such actions may impact our business, such actions, if undertaken, may prompt more activity from state, and local legislative bodies and administrative agencies to pass stricter GHG laws, regulations, and other binding commitments. While we believe we are in substantial compliance with existing environmental laws and regulations applicable to our current operations and that our continued compliance with existing requirements will not have a material adverse impact on our financial condition and results of operations, we cannot give any assurance that we will not be adversely affected in the future.

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*Environmental, Health, and Safety Initiatives.* We are committed to exceptional safety, health, and environmental stewardship; making a positive difference in the communities where we live and work; and transparency in reporting our progress in these areas. We set annual goals for our safety, health, and environmental program focused on minimizing the number of safety related incidents and the number and impact of spills of produced fluids. We also periodically conduct audits of our operations to ensure regulatory compliance, and we strive to provide appropriate training for our employees. Minimizing air emissions resulting from leaks, venting, or flaring of gas during operations has become a major focus area as we consider this a best practice and seek to comply with regulations. While flaring is sometimes necessary, minimizing these volumes is a priority for us. To avoid flaring when possible, we restrict testing periods and connect our production to gas pipeline infrastructure as quickly as possible after well completions. We have incurred in the past, and expect to incur in the future, capital costs related to environmental compliance. Such expenditures are included within our overall capital budget and are not separately itemized.

**Available Information**

Our internet website address is www.sm-energy.com. We routinely post important information for investors on our website. Within our website's investor relations section, we make available free of charge our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and amendments to those reports filed with or furnished to the SEC under applicable securities laws. These materials are made available as soon as reasonably practical after we electronically file such materials with or furnish such materials to the SEC, and can also be located at www.sec.gov. We also make available through our website our Corporate Governance Guidelines, Code of Business Conduct and Conflict of Interest Policy, Financial Code of Ethics Policy, Human Rights Policy, and the Charters of the Audit, Compensation, and Governance and Sustainability committees of our Board of Directors. Information on our website is not incorporated by reference into this report and should not be considered part of this document.

**ITEM 1A. RISK FACTORS**

In addition to the other information included in this report, the risk factors discussed below should be carefully considered when evaluating an investment in SM Energy. For the purposes of this section, "we," "our," "us," "Company" and "SM Energy" refer to the post-Merger company following the Civitas Merger**.** Our risk factors are summarized as follows:

**Risks Related to the Civitas Merger**

&nbsp;&nbsp;&nbsp;&nbsp;• We may be unable to successfully integrate Civitas' business into our business or achieve the anticipated benefits of the Merger, which may have a material adverse effect on our business, financial condition or results of operations.

&nbsp;&nbsp;&nbsp;&nbsp;• We have incurred additional costs in connection with the Merger, which will continue during a portion of 2026.

&nbsp;&nbsp;&nbsp;&nbsp;• Securities class action and derivative lawsuits may be brought against us in connection with the Merger, which could result in substantial costs.

&nbsp;&nbsp;&nbsp;&nbsp;*•* The market price for our common stock may be affected by factors different from those that historically have affected SM Energy common stock or Civitas common stock.

&nbsp;&nbsp;&nbsp;&nbsp;*•* Our ability to utilize certain tax attributes may be limited as a result of the Civitas Merger.

&nbsp;&nbsp;&nbsp;&nbsp;*•* The historical business relationships of SM Energy and Civitas may be subject to disruption due to uncertainty associated with the Merger, which could have a material adverse effect on our results of operations, cash flows and financial position.

&nbsp;&nbsp;&nbsp;&nbsp;*•* The synergies and other benefits attributable to the Merger may vary from expectations.

**Risks Related to Commodity Prices and Global Macroeconomics**

&nbsp;&nbsp;&nbsp;&nbsp;• Oil, gas, and NGL prices are volatile, and declines in prices may adversely affect our profitability, financial condition, cash flows, access to capital, and ability to grow.

&nbsp;&nbsp;&nbsp;&nbsp;*•* Future oil, gas, and NGL price declines or unsuccessful exploration efforts may result in write-downs of our asset carrying values.

&nbsp;&nbsp;&nbsp;&nbsp;*•* Weakness in economic conditions, inflation, or uncertainty in financial markets may have material adverse impacts on our business that we cannot predict.

&nbsp;&nbsp;&nbsp;&nbsp;• Global geopolitical tensions may create heightened volatility in oil, gas, and NGL prices and could adversely affect our business, financial condition and results of operations.

**Risks Related to Oil and Gas Operations and the Industry**

&nbsp;&nbsp;&nbsp;&nbsp;*•* The proposed divestiture of certain of our South Texas assets may not be completed on the anticipated terms or at all, which could adversely affect our ability to execute our publicly stated deleveraging objectives.

&nbsp;&nbsp;&nbsp;&nbsp;*•* The loss of personnel could adversely affect our business.

&nbsp;&nbsp;&nbsp;&nbsp;*•* Our increasing dependence on digital technologies puts us at risk for a cyber incident that could result in information theft, data corruption, operational disruptions or financial loss.

&nbsp;&nbsp;&nbsp;&nbsp;*•* We are incorporating artificial intelligence technologies into our processes and these technologies may present business, compliance, and reputational risks.

&nbsp;&nbsp;&nbsp;&nbsp;*•* Competition in our industry is intense, and many of our competitors have greater financial, technical, and human resources than we do.

&nbsp;&nbsp;&nbsp;&nbsp;*•* Our ability to sell oil, gas, and NGLs, and/or receive market prices for our production, may be adversely affected by constraints on gathering systems, processing facilities, pipelines, rail systems, and other transportation systems owned or operated by third-

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parties or by other interruptions beyond our control, which could obstruct, limit, or eliminate our access to oil, gas, and NGL markets.

&nbsp;&nbsp;&nbsp;&nbsp;*•* We have entered into firm transportation contracts that require us to pay fixed sums of money to our counterparties regardless of the quantities actually transported under these contracts. If we are unable to deliver the necessary quantities of oil, gas, NGL, or produced water to our counterparties, our results of operations, financial position, and liquidity could be adversely affected.

&nbsp;&nbsp;&nbsp;&nbsp;*•* We have limited control over the activities on properties we do not operate.

&nbsp;&nbsp;&nbsp;&nbsp;*•* We rely on third-party service providers to conduct drilling and completion and other related operations.

&nbsp;&nbsp;&nbsp;&nbsp;*•* The inability of customers or co-owners of assets to meet their obligations may adversely affect our financial results.

&nbsp;&nbsp;&nbsp;&nbsp;*•* Many of our properties are in areas that may have been partially depleted or drained by offset wells and certain of our wells or future locations may be adversely affected by actions other operators may take when drilling, completing, or operating wells that they own.

&nbsp;&nbsp;&nbsp;&nbsp;*•* Oil and gas drilling, completion, and production activities are subject to numerous risks, including the risk that no commercially producible oil, gas, or NGLs will be found.

&nbsp;&nbsp;&nbsp;&nbsp;*•* The development of our proved undeveloped reserves may take longer and may require higher levels of capital expenditures than we currently anticipate. Therefore, our undeveloped reserves may not be ultimately developed or produced.

&nbsp;&nbsp;&nbsp;&nbsp;*•* Our ability to produce oil, gas, and NGLs economically and in commercial quantities could be impaired if we are unable to acquire adequate supplies of water for our drilling and/or completions operations or are unable to dispose of or recycle the water we produce at a reasonable cost and in accordance with applicable environmental rules and regulations.

&nbsp;&nbsp;&nbsp;&nbsp;*•* If we are unable to replace reserves and increase our reserve life index, we will not be able to sustain production.

&nbsp;&nbsp;&nbsp;&nbsp;*•* The results of our operations are subject to drilling and completion technique risks, and results may not meet our expectations for reserves or production. As a result, we may incur material write-downs, and the value of our undeveloped acreage could decline if drilling and completion results are unsuccessful.

&nbsp;&nbsp;&nbsp;&nbsp;*•* The actual quantities and present value of our proved oil, gas, and NGL reserves may be less than we have estimated, and the cost to develop our reserves may be more than we have estimated.

&nbsp;&nbsp;&nbsp;&nbsp;*•* Our disposition activities may be subject to factors beyond our control, and in certain cases we may retain unforeseen liabilities for certain matters.

&nbsp;&nbsp;&nbsp;&nbsp;*•* Title to the properties in which we have an interest may be impaired by title defects.

&nbsp;&nbsp;&nbsp;&nbsp;• Our business could be negatively impacted by security threats, including cybersecurity threats, terrorism, armed conflict, and other disruptions.

&nbsp;&nbsp;&nbsp;&nbsp;*•* We are subject to operating and environmental risks and hazards that could result in substantial losses or liabilities that may not be fully insured.

&nbsp;&nbsp;&nbsp;&nbsp;*•* The impact of seasonal and extreme weather conditions and lease stipulations adversely affect our ability to conduct drilling activities in some of the areas where we operate.

**Risks Related to Litigation and Government Regulations**

&nbsp;&nbsp;&nbsp;&nbsp;*•* In the future, we may be subject to claims, litigation, administrative proceedings and regulatory actions that may not be resolved in our favor.

&nbsp;&nbsp;&nbsp;&nbsp;*•* Our operations are subject to complex laws and regulations, including environmental regulations, which result in substantial costs and other risks.

&nbsp;&nbsp;&nbsp;&nbsp;• Federal and state legislative and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays.

&nbsp;&nbsp;&nbsp;&nbsp;• Federal and state regulatory initiatives relating to air quality and greenhouse gas emissions could result in increased costs and additional operating restrictions or delays.

&nbsp;&nbsp;&nbsp;&nbsp;• Legislative and regulatory initiatives and litigation related to global warming and climate change could have an adverse effect on our operations and the demand for oil, gas, and NGLs, and could result in significant litigation, capital, and related expenses.

&nbsp;&nbsp;&nbsp;&nbsp;• Requirements to reduce gas flaring could have an adverse effect on our operations.

&nbsp;&nbsp;&nbsp;&nbsp;*•* Senate Bill 181's requirement, which applies to our Colorado operations, that we own or control more than 45 percent of the working or mineral interest in order to statutorily pool our applicable interest may make it much more difficult for us to develop such interests, which could have a material adverse effect on our business, financial condition, and results of operations.

**Risks Related to Debt, Liquidity, and Access to Capital**

&nbsp;&nbsp;&nbsp;&nbsp;*•* Commodity price declines could result in a decrease in the amount available to us under our Credit Agreement.

&nbsp;&nbsp;&nbsp;&nbsp;*•* Negative public perception and investor sentiment regarding our business and the oil and gas industry as a whole could adversely affect our business, operations, and our ability to attract capital.

&nbsp;&nbsp;&nbsp;&nbsp;*•* Substantial capital is required to develop and replace our reserves.

&nbsp;&nbsp;&nbsp;&nbsp;*•* Downgrades in our credit ratings by various credit rating agencies could impact our access to capital and have a material adverse effect on our business and financial condition.

&nbsp;&nbsp;&nbsp;&nbsp;*•* Our commodity derivative contract activities may result in financial losses or may limit the prices we receive for oil, gas, and NGL sales.

&nbsp;&nbsp;&nbsp;&nbsp;*•* The amount of our debt may limit our ability to obtain financing for acquisitions, make us more vulnerable to adverse economic conditions, and make it more difficult for us to make payments on our debt.

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&nbsp;&nbsp;&nbsp;&nbsp;*•* The agreements governing our debt arrangements contain various covenants that limit our discretion in the operation of our business, could prohibit us from engaging in transactions we believe to be beneficial, and could lead to the accelerated repayment of our debt.

**Risks Related to Corporate Governance and Ownership of Public Equity Securities**

&nbsp;&nbsp;&nbsp;&nbsp;*•* Our certificate of incorporation and by-laws have provisions that discourage corporate takeovers and could prevent stockholders from receiving a takeover premium on their investment, which could adversely affect the price of our common stock.

&nbsp;&nbsp;&nbsp;&nbsp;*•* The price of our common stock may fluctuate significantly, which may result in losses for investors.

&nbsp;&nbsp;&nbsp;&nbsp;*•* We may not always pay dividends on our common stock or repurchase common stock under our Stock Repurchase Program.

**Risks Related to the Civitas Merger**

*We may be unable to successfully integrate Civitas' business into our business or achieve the anticipated benefits of the Merger, which may have a material adverse effect on our business, financial condition or results of operations.*

The success of the Merger depends in part on whether we can complete the integration of the Civitas assets that we have not previously operated into our existing business in an efficient and effective manner, and there can be no assurance that we will be able to successfully integrate or otherwise realize the anticipated benefits of the Merger. The integration process may result in the disruption of ongoing business and there could be potential unknown liabilities and unforeseen expenses associated with the Merger that were not discovered in the course of performing due diligence. Integration may also require significant time and focus from management following the Merger that may disrupt our business and results of operations. Potential risks or difficulties include, among others:

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• complexities associated with integrating our existing complex systems, technologies and other workflows with new assets;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• the inability to retain the services of key management and personnel;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• the accuracy of our assessments of the assets acquired in the Merger, including recoverable reserves, transportation costs and availability, drilling and completion equipment cost and availability, regulatory, permitting, and related matters;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• establishing business relationships with new third party contractors and other service providers with whom we have no prior experience; and

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• potential unknown liabilities and unforeseen expenses, delays or regulatory conditions associated with the Merger.

Any of these issues could adversely affect our ability to maintain relationships with customers, suppliers, employees, and other constituencies. We may fail to realize the anticipated benefits expected from the Merger. The success of the Merger will depend, in significant part, on our ability to successfully complete the integration of the acquired assets and realize the anticipated strategic benefits from the Merger. The anticipated benefits of the Merger may not be realized fully or at all or may take longer to realize than expected. Actual operating, technological, strategic, and revenue opportunities, if achieved at all, may be less significant than expected or may take longer to achieve than anticipated. If we are not able to realize the anticipated benefits expected from the Merger within the anticipated timing or at all, our business, financial, and operating results may be adversely affected.

*We have incurred additional costs in connection with the Merger, which will continue during a portion of 2026.*

During the fiscal year ended December 31, 2025, we incurred non-recurring costs associated with the Merger, and we expect to continue to incur such costs during 2026. A substantial majority of non-recurring expenses consist of change in control payments and transaction costs which include, among others, fees paid to financial, legal, accounting, and other advisors.

*Securities class action and derivative lawsuits may be brought against us in connection with the Merger, which could result in substantial costs*.

Securities class action lawsuits and derivative lawsuits are often brought against public companies that have entered into acquisition, merger, or other business combination agreements. Even if such a lawsuit is without merit, defending against these claims can result in substantial costs and divert management time and resources. An adverse judgment could result in monetary damages, which could have a negative impact on our liquidity and financial condition.

*The market price for our common stock may be affected by factors different from those that historically have affected SM Energy common stock or Civitas common stock.*

Our financial position will differ from our financial position prior to the closing of the Merger, and our post-Merger results of operations may be affected by factors that are different from those that have historically affected the results of operations of SM Energy and of Civitas. Accordingly, the market price and performance of our common stock is likely to be different from the performance of the SM Energy and of Civitas common stock absent of the Merger. In addition, general fluctuations in trading activity and prices on the NYSE could have a material adverse effect on the market for, or liquidity of, our common stock, regardless of our actual operating performance.

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*Our ability to utilize certain tax attributes may be limited as a result of the Civitas Merger.*

Our ability to utilize the former SM Energy's carryover research and development credits and the former Civitas' net operating losses ("NOL" or "NOLs") and other tax attributes may be limited. The former Civitas had a material amount of federal tax NOLs that remained unutilized as of the Closing Date of the Merger.

Our ability to utilize these tax attributes to reduce future taxable income and reduce future tax liability depends on many factors, including our future income, which cannot be assured. Sections 382 and 383 of the Code ("Sections 382 and 383") generally impose an annual limitation on the amount of attributes that can be used when a corporation has undergone an "ownership change" (as determined under Sections 382 and 383). An ownership change generally occurs if one or more stockholders (or groups of stockholders) who are each deemed to own at least five percent of such corporation's stock has increased their ownership by more than 50 percentage points over their lowest ownership percentage within a rolling three-year period. In the event that an ownership change occurs, utilization of the relevant corporation's tax attributes would be subject to an annual limitation under Sections 382 and 383.

*The historical business relationships of SM Energy and Civitas may be subject to disruption due to uncertainty associated with the Merger, which could have a material adverse effect on our results of operations, cash flows and financial position.*

Parties with which the former SM Energy or the former Civitas do business may experience uncertainty associated with the Merger, including with respect to current or future business relationships with the Company. Our business relationships may be subject to disruption as customers, distributors, suppliers, vendors, landlords, joint venture partners and other business partners may attempt to delay or defer entering into new business relationships, negotiate changes in existing business relationships or consider entering into business relationships with parties other than us. These disruptions could have a material adverse effect on our results of operations, cash flows and our financial position, as well as a material adverse effect on the our ability to realize the expected cost savings and other benefits of the Merger.

*The synergies and other benefits attributable to the Merger may vary from expectations.*

We may fail to realize the anticipated synergies and other benefits expected from the Merger, which could adversely affect our business, financial condition and operating results. The success of the Merger will depend, in significant part, on our ability to successfully integrate the acquired business and realize the anticipated strategic benefits and synergies from the combination. The anticipated benefits of the transaction may not be realized fully or at all, or may take longer to realize than expected. Actual operating, technological, strategic and revenue opportunities, if achieved at all, 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 synergies and other benefits expected from the Merger within the anticipated timing or at all, our business, financial condition and operating results may be adversely affected.

**Risks Related to Commodity Prices and Global Macroeconomics**

*Oil, gas, and NGL prices are volatile, and declines in prices may adversely affect our profitability, financial condition, cash flows, access to capital, and ability to grow.*

Our revenues, operating results, profitability, future rate of growth, and the carrying value of our oil and gas properties depend heavily on the prices we receive for oil, gas, and NGL sales. Oil, gas, and NGL prices also affect our cash flows available for capital expenditures, debt reductions, return of capital, and other expenditures, our borrowing capacity, and the volume and value of our oil, gas, and NGL reserves. In addition, we may have oil and gas property impairments or downward revisions of estimates of proved reserves if prices fall significantly. Refer to *Significant Developments in 2025* and *Reserves* in Part I, Items 1 and 2, *Comparison of Financial Results and Trends Between 2025 and 2024* and *Overview of Liquidity and Capital Resources* in Part II, Item 7, and *Note 1 – Summary of Significant Accounting Policies*, *Note 8 – Fair Value Measurements*, and *Supplemental Oil and Gas Information (unaudited)* in Part II, Item 8 for specific discussion.

Historically, the markets for oil, gas, and NGLs have been volatile, and they are likely to continue to be volatile. Wide fluctuations in oil, gas, and NGL prices often result from relatively minor changes in the supply of and demand for oil, gas, and NGLs, market uncertainty, and other factors that are beyond our control, including:

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• global and domestic supplies of oil, gas, and NGLs, and the productive capacity of the industry as a whole;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• the level of consumer demand for oil, gas, and NGLs;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• overall global and domestic economic conditions;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• inflation and other economic factors that contribute to market volatility including tariffs and trade restrictions;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• weather conditions;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• the availability and capacity of gathering, transportation, processing, storage, and/or refining facilities in asset-specific or localized areas;

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&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• liquefied natural gas deliveries to and from the United States;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• the increased demand for, price, and availability of alternative fuels or sources of energy;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• technological advances in, and regulations affecting, energy consumption and conservation;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• the ability of the members of OPEC+ to maintain effective oil price and production controls;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• War and Geopolitical Instability;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• shipping channel constraints and disruptions to and from oil and gas producing countries or regions;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• actual or perceived epidemic or pandemic risks;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• strengthening and weakening of the United States dollar relative to other currencies;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• stockholder activism or activities by non-governmental organizations to limit sources of funding or restrict the exploration and production of oil, gas, and NGLs and related infrastructure; and

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• governmental regulations and taxes.

Declines in oil, gas, and NGL prices would reduce our revenues and could also reduce the amount of oil, gas, and NGLs that we can produce economically, which could have a material adverse effect on our business, financial condition, liquidity, results of operations, and prospects.

*Future oil, gas, and NGL price declines or unsuccessful exploration efforts may result in write-downs of our asset carrying values.*

We follow the successful efforts method of accounting for our oil and gas properties. All property acquisition costs and development costs are capitalized when incurred. Exploratory well costs are initially capitalized, pending the determination of whether proved reserves have been discovered. If commercial quantities of proved reserves are not discovered with an exploratory well, the costs initially capitalized are expensed as dry hole costs.

The capitalized costs of our oil and gas properties, on a depletion pool basis, cannot exceed the estimated undiscounted future net cash flows of that depletion pool. If net capitalized costs exceed undiscounted future net cash flows, we generally must write down the costs to the estimated discounted future net cash flows of that depletion pool. Write downs for unproved properties are also evaluated for carrying costs in excess of fair value. This evaluation considers the potential for abandonment due to actual and anticipated lease expirations, as well as actual and anticipated losses on acreage due to title defects, changes in development plans, and other inherent acreage risks. Declines in the prices of oil, gas, or NGLs, or unsuccessful exploration efforts, could cause proved and/or unproved property impairments in the future, which could have a material adverse effect on our business, financial condition, liquidity, and results of operations.

We review the carrying values of our properties for indicators of impairment on a quarterly basis using the prices in effect as of the end of each quarter. Once incurred, a write-down of oil and gas properties held for use cannot be reversed at a later date, even if oil, gas, or NGL prices increase.

*Weakness in economic conditions, inflation, or uncertainty in financial markets may have material adverse impacts on our business that we cannot predict.*

The United States and global economies and financial systems regularly experience turmoil and upheaval characterized by extreme volatility in prices of equity and debt securities, periods of diminished liquidity and credit availability, inability to access capital markets, the bankruptcy, failure, collapse, or sale of financial institutions, inflation, tariffs or trade restrictions, and heightened levels of intervention by the United States federal government and other governments. Weakness or uncertainty in the United States economy or other large economies could have a material adverse effect on our business and financial condition. For example:

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• market conditions, lack of buyer interest, regulatory delays or unforeseen economic issues could impede achieving our divestiture target of at least $1.0 billion and delay our ability to reach long term strategic goals;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• inflation has increased certain costs of our drilling and completion activities, and the costs of oilfield goods, services, personnel, equipment, and materials in recent years and could continue or worsen and further impact our financial condition, liquidity, and results of operations, and could limit our pool of economic development opportunities;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• economic recession could impact demand for oil, gas, and NGLs, and cause commodity price volatility;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• the tightening of credit or lack of credit availability to our customers could adversely affect our ability to collect our trade receivables;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• the liquidity available under our Credit Agreement could be reduced if any of our lenders is unable to fund its commitment;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• our ability, or the ability of our suppliers or contractors, to access the capital markets may be restricted or non-existent at a time when we or they would like, or need, to raise capital for our or their business, including for the exploration and/or development of reserves;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• our commodity derivative contracts could become economically ineffective if our counterparties are unable to perform their obligations or seek bankruptcy protection;

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&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• the Federal Reserve may change interest rates, as they have in recent years, which could impact borrowing costs and suppress economic growth;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• variable interest rate spread levels, including for SOFR and the prime rate, could increase significantly, resulting in higher interest costs for unhedged variable interest rate-based borrowings under our Credit Agreement; and

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• changes in tax laws and regulations could require us to adjust our business plan.

*Global geopolitical tensions may create heightened volatility in oil, gas, and NGL prices and could adversely affect our business, financial condition and results of operations.*

War and Geopolitical Instability could lead to significant market and other disruptions, including, but not limited to: significant volatility in commodity prices and supply of energy resources, instability in financial markets, supply chain interruptions, shipping channel constraints and disruptions, political and social instability, political and economic sanctions, geopolitical shifts, embargoes, changes in consumer or purchaser preferences, the potential destruction of critical oil-related infrastructure, as well as increases in cyberattacks and espionage. These factors could impact our operations and the financial condition of our business as well as the global economy.

**Risks Related to Oil and Gas Operations and the Industry**

*The proposed divestiture of certain of our South Texas assets may not be completed on the anticipated terms or at all, which could adversely affect our ability to execute our publicly stated deleveraging objectives.*

We have entered into the PSA with Caturus for the sale of certain of our South Texas assets as part of our previously announced plan to reduce debt and strengthen our capital structure. The completion of this Transaction, as defined in *Note 17 – Mergers, Acquisitions, and Divestitures* in Part II, Item 8 of this report, is subject to customary closing conditions including regulatory approvals and certain required consents, as well as the satisfaction of other contractual conditions. There can be no assurance that these conditions will be satisfied on the anticipated timeline or at all.

If the Transaction is delayed or not completed, we may not receive the anticipated proceeds within the expected timeframe, or at all, which could delay or prevent us from achieving our targeted leverage metrics or other strategic priorities. We may also incur Transaction-related costs, including advisory, legal and other expenses, regardless of whether the Transaction is completed, and management's attention may be diverted during the pendency of the Transaction.

*The loss of personnel could adversely affect our business.*

We depend to a large extent on the efforts and continued employment of our executive management team, other key personnel, and our general labor force. The loss of their services could adversely affect our business. Our success in drilling and completing new wells and the success of other activities integral to our operations will depend, in part, on our ability to attract and retain experienced geologists, engineers, landmen, and other professionals. Competition for many of these professionals can be intense. If we cannot retain our technical personnel or attract additional experienced technical personnel and professionals, our ability to compete could be harmed.

*Our increasing dependence on digital technologies puts us at risk for a cyber incident that could result in information theft, data corruption, operational disruptions or financial loss.*

We are subject to cybersecurity risks. The oil and gas industry, and our business, are increasingly dependent on digital technology. We use digital technology, including information technology ("IT") and operational technology ("OT"), to conduct certain aspects of our drilling development, production and gathering activities, manage drilling rigs and completion equipment, gather and interpret seismic data, conduct reservoir modeling, record financial and operating data, and maintain employee and other databases. Our service providers, including those who gather, process, and market our oil, gas, and NGLs, are also increasingly reliant on digital technology. Our and their reliance on this technology increasingly puts us at risk for technology system failures, data or network disruptions, cyberattacks and other breaches in cybersecurity. Power failures, telecommunication or other system failures due to hardware or software malfunctions, computer viruses, vandalism, terrorism, natural disasters, fire, flood, human error or other means could significantly impair our ability to conduct our business.

Cybersecurity attacks are evolving and include, but are not limited to, malware (including viruses), phishing, vulnerability exploitation, insider threats, and physical or electronic security breaches, which may result in operational disruption; unauthorized access to or exfiltration of data; and other impacts to the confidentiality, availability, and integrity of systems and information. Geopolitical tensions or conflicts may further heighten the risk of cyberattacks. In particular, sophisticated nation state actors have, and may continue to, target companies operating in industries providing critical infrastructure. Deliberate attacks on, or security breaches in our systems, infrastructure, the systems and infrastructure of third-parties, or cloud-based applications could lead to disclosure of confidential information, a corruption or loss of our proprietary data, delays in production or exploration activities, difficulty in completing or settling transactions, challenges in maintaining our books and records, environmental damage, communication or other operational disruptions, and liability to third parties. Any insurance we might obtain in the future may not provide adequate protection from these risks. Any such events could damage our reputation and lead to financial losses from remedial actions, loss of business or potential

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liability. As these cyber risks continue to evolve and our dependence on digital technologies grows, we may be required to expend significant additional resources to continue to modify or enhance our protective measures and remediate cyber vulnerabilities.

Refer to *Cybersecurity* in Part 1, Item 1C of this report for discussion of the Audit Committee's role in cybersecurity governance. We did not experience any material cybersecurity incidents during 2025, however there can be no assurance that the measures we have taken to address IT and cybersecurity risks will prove effective in the future.

*We are incorporating artificial intelligence technologies into our processes and these technologies may present business, compliance, and reputational risks.*

Our business increasingly utilizes AI, machine learning, and automated decision making to improve our processes. Issues in the development and use of AI, combined with an uncertain regulatory environment, may result in new or enhanced governmental or regulatory scrutiny, litigation, confidentiality or security risks, reputational harm, liability, or other adverse consequences to our business operations, all of which could adversely affect our business, results of operations, and financial condition.

In addition, it is possible that AI and machine learning-technology could, unbeknownst to us, be improperly utilized by employees while carrying out their responsibilities. The use of AI can lead to unintended consequences, including the unauthorized use or disclosure of confidential and proprietary information, or generating content that appears correct but is factually inaccurate, misleading, biased, or otherwise flawed, which could harm our reputation and business and expose us to risks related to inaccuracies or errors in the output of such technologies. As the use of AI in our business becomes more prominent, we may be required to expend additional resources to further enhance our digital security, and we may face challenges in fully anticipating or implementing adequate preventive measures or mitigating potential harm. These costs may include deploying additional personnel and protection technologies, training employees, and engaging third party experts and consultants.

It is not possible to predict all of the risks related to the use of AI, machine learning and automated decision making, and developments in the regulatory frameworks governing the use of such technologies and in related stakeholder expectations may adversely affect our ability to develop and use such technologies or subject us to liability. If we fail to successfully integrate AI into our business processes, or if we fail to keep pace with rapidly evolving AI technological developments, including attracting and retaining talented data scientists, data engineers, and programmers, we may face a competitive disadvantage.

*Competition in our industry is intense, and many of our competitors have greater financial, technical, and human resources than we do.*

We face intense competition from oil and gas exploration and production companies of all sizes for the capital, equipment, expertise, labor, and materials required to operate oil and gas properties. Many of our competitors have financial, technical, and other resources exceeding those available to us, and many oil and gas properties are sold in a competitive bidding process in which our competitors may be able and willing to pay more for exploratory and development prospects and producing properties, or in which our competitors have technological information or expertise that is not available to us to evaluate and successfully bid for properties. As a result, we may not be successful in acquiring and developing profitable properties. In addition, other companies may have a greater ability to continue drilling activities during periods of low oil or gas prices and to absorb the burden of current and future governmental regulations and taxation. In addition, shortages of equipment, labor, or materials resulting from intense competition may result in increased costs or the inability to obtain those resources as needed. Our inability to compete effectively with companies in any area of our business could have a material adverse impact on our business activities, financial condition, and results of operations.

*Our ability to sell oil, gas, and NGLs, and/or receive market prices for our production, may be adversely affected by constraints on gathering systems, processing facilities, pipelines, rail systems, and other transportation systems owned or operated by third-parties or by other interruptions beyond our control, which could obstruct, limit, or eliminate our access to oil, gas, and NGL markets.*

The marketability of our oil, gas, and NGL production depends in part on the availability, proximity, and capacity of gathering systems, processing facilities, pipelines, rail systems, and other transportation systems, which are generally owned or operated by third parties. Any significant interruption in service from, damage to, or lack of available capacity in these systems and facilities can result in the shutting-in of producing wells, the delay, or discontinuance of development plans for our properties, increases in costs, or lower price realizations. Although we have some influence over the processing and transportation of our operated production, material changes in these business relationships could materially affect our operations. Federal, state, and tribal regulation of oil, gas, and NGL production and transportation, tax and energy policies, changes in supply and demand, pipeline pressures, damage to or destruction of pipelines or processing facilities, infrastructure or capacity constraints, train derailments, and general economic conditions could adversely affect our ability to produce, gather, process, transport, or market oil, gas, and NGLs.

Production may be interrupted, or shut in, from time to time for numerous reasons, including weather conditions, accidents, loss of pipeline, gathering, processing or transportation system access or capacity, field labor issues or strikes, or we might voluntarily curtail production in response to market or other conditions. If a substantial amount of our production is interrupted at the same time, it could adversely affect our cash flows and results of operations.

Our Uinta Basin operations include the use of rail systems operated by third-parties to transport our crude oil to market which involves inherent risk, including the potential for accidents and derailments. In the event of a rail system accident or derailment, there

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could be significant delays in the delivery of oil to processing facilities, or impacts to rail system access or capacity, which may disrupt our business operations and could adversely affect our financial condition. Additionally, we could experience financial losses related to spills or damages to the oil in transit that we may not be able to recoup from the third-party rail operators. We continue to monitor our transportation arrangements and maintain contingency plans to mitigate potential impacts of transportation-related disruptions; however, we cannot guarantee that such measures will adequately reduce the risks associated with transportation by rail.

*We have entered into firm transportation contracts that require us to pay fixed sums of money to our counterparties regardless of the quantities actually transported under these contracts. If we are unable to deliver the necessary quantities of oil, gas, NGL, or produced water to our counterparties, our results of operations, financial position, and liquidity could be adversely affected.*

As of December 31, 2025, we were contractually committed to deliver a minimum of 49 MMBbl of oil through December of 2032. We may enter into additional firm transportation agreements as we expand the development of our resource plays. In the event we encounter delays in drilling and completing our wells or otherwise due to construction, interruptions of operations, or delays in connecting new volumes to rail systems, gathering systems, or pipelines for an extended period of time, or if we further limit our capital expenditures due to future commodity price declines or for other reasons, the requirements to pay for quantities not delivered could have a material impact on our results of operations, financial position, and liquidity.

*We have limited control over the activities on properties we do not operate.*

Some of our properties are operated by other companies and involve third-party working interest owners. As a result, we have limited ability to influence or control the operation or future development of such properties, including the nature and timing of drilling and operational activities, the operator's skill and expertise, compliance with environmental, safety and other regulations, the approval of other participants in such properties, the selection and application of suitable technology, or the amount of expenditures that we will be required to fund with respect to such properties. Moreover, we are dependent on the other working interest owners of such projects to fund their contractual share of the expenditures of such properties. These limitations and our dependence on the operator and other working interest owners in these projects could cause us to incur unexpected future costs.

*We rely on third-party service providers to conduct drilling and completion and other related operations.*

We rely on third-party service providers to perform necessary drilling and completion and other related operations. The ability of third-party service providers to perform such operations will depend on those service providers' ability to compete for and retain qualified personnel, financial condition, economic performance, and access to capital, which in turn will depend upon the supply and demand for oil, gas, and NGLs, prevailing economic conditions, and financial, business, and other factors. Future periods of sustained low commodity prices could occur and could cause third-party service providers to consolidate or declare bankruptcy, which could limit our options for engaging such providers. The failure of a third-party service provider to adequately perform operations could delay drilling or completion or reduce production from the property and adversely affect our financial condition and results of operations.

*The inability of customers or co-owners of assets to meet their obligations may adversely affect our financial results.*

Substantially all of our accounts receivable result from oil, gas, and NGL sales or joint interest billings to co-owners of oil and gas properties we operate. This concentration of customers and joint interest owners may impact our overall credit risk because these entities may be similarly affected by various economic and other market conditions, including declines in oil, gas, and NGL prices. The loss of one or more of these customers could reduce competition for our products and negatively impact the prices of commodities we sell. We do not believe the loss of any single purchaser would materially impact our operating results, as we have numerous options for purchasers in each of our operating areas for our oil, gas, and NGL production; however, if adverse market conditions or other economic decline affected a substantial number of our customers or joint interest owners, our operations and financial results could be impacted. Refer to *Concentration of Credit Risk and Major Customers* in *Note 1 – Summary of Significant Accounting Policies,* in Part II, Item 8 of this report for further discussion of our concentration of credit risk and major customers. Additionally, the inability of our co-owners, some of which have significant non-operated interests in a substantial portion of our oil and gas properties, to pay joint interest billings could negatively impact our cash flows and financial ability to drill and complete current and future wells.

*Many of our properties are in areas that may have been partially depleted or drained by offset wells and certain of our wells or future locations may be adversely affected by actions other operators may take when drilling, completing, or operating wells that they own.*

Many of our properties are in areas that may have already been partially depleted or drained by earlier offset drilling. The owners of leasehold interests adjoining any of our properties could take actions, such as drilling and completing additional wells, which could adversely affect our operations. When a new well is completed and produced, the pressure differential in the vicinity of the well causes the migration of reservoir fluids toward the new wellbore (and potentially away from existing wellbores). As a result, the drilling and production of these potential locations could cause a depletion of our proved reserves and may inhibit our ability to further develop our proved reserves. In addition, completion operations and other activities conducted on adjacent or nearby wells could cause production from our wells to be shut in for indefinite periods of time, result in increased lease operating expenses and adversely affect the production and reserves from our wells after they re-commence production. We have no control over the operations or activities of offsetting operators.

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*Oil and gas drilling, completion, and production activities are subject to numerous risks, including the risk that no commercially producible oil, gas, or NGLs will be found.*

The cost of drilling and completing wells is often uncertain, and oil, gas, or NGLs drilling and production activities may be shortened, delayed, or canceled as a result of a variety of factors, many of which are beyond our control. These factors may include, but are not limited to:

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• supply chain issues, including cost increases and availability of equipment or materials;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• unexpected adverse drilling or completion conditions;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• title problems;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• disputes with owners or holders of surface interests on or near areas where we operate;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• pressure or geologic irregularities in formations;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• engineering and construction delays;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• equipment failures or accidents;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• hurricanes, tornadoes, flooding, wildfires, seasonal weather, or other adverse weather conditions;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• operational restrictions resulting from seismicity concerns;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• compliance with and changes in federal, state, and local environmental and other governmental regulatory requirements;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• governmental permitting delays; and

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• shortages or delays in the availability of or increases in the cost of drilling rigs and crews, fracture stimulation crews and equipment, pipe, chemicals, water, sand, and other supplies.

The wells we drill may not be productive, and we may not recover all or any portion of our investment in such wells. The seismic data and other technologies we use do not allow us to know conclusively prior to drilling a well if oil, gas, or NGLs are present, or whether they can be produced economically. Drilling activities can result in dry holes or wells that are productive but do not produce sufficient net revenues after operating and other costs to cover drilling and completion costs. Even if sufficient amounts of oil, gas, or NGLs exist, we may damage a potentially productive hydrocarbon-bearing formation or experience mechanical difficulties while drilling or completing a well, which could result in reduced or no production from the well, significant expenditure to repair the well, and/or the loss and abandonment of the well.

Another significant risk inherent in our drilling plans is the need to obtain drilling permits from federal, state, tribal, local, and other governmental authorities. Delays in obtaining regulatory approvals and drilling permits, including delays that jeopardize our ability to realize the potential benefits from leased properties within the applicable lease periods, the failure to obtain a drilling permit for a well, or the receipt of a permit with unreasonable conditions or costs could have a material adverse effect on our ability to explore or develop our properties.

Results in newer resource plays may be more uncertain than results in resource plays that are more developed and have longer established production histories. We, and the industry, generally have less information with respect to the ultimate recoverability of reserves and the production decline rates in newer resource plays than other areas with longer histories of development and production. Drilling and completion techniques that have proven to be successful in other resource plays are being used in the early development of new plays; however, we can provide no assurance of the ultimate success of these drilling and completion techniques.

We may not be able to obtain any options or lease rights in potential drilling locations that we identify. While some expiring leases may contain predetermined extension payments, other expiring leases will require us to negotiate new leases at the time of lease expiration. Further, existing leases which are currently held by production may unexpectedly encounter operational, political, regulatory, or litigation challenges which could result in their termination. It is possible that market conditions at the time of negotiation could require us to agree to new leases on less favorable terms to us than the terms of the expired leases or cause us to lose the leases entirely. Unless production is established within the spacing units covering undeveloped acres on which our drilling locations are identified, the leases for such acreage will expire, and we will lose our right to develop the related properties. Our total net acreage as of February 2, 2026, that is scheduled to expire over the next three years, represents approximately 30 percent of our total net undeveloped acreage as of that date. Although we have identified numerous potential drilling locations, we may not be able to economically drill for and produce oil, gas, or NGLs from all of them, and our actual drilling activities may materially differ from those presently identified, which could adversely affect our financial condition, results of operations and operating cash flow.

*The development of our proved undeveloped reserves may take longer and may require higher levels of capital expenditures than we currently anticipate. Therefore, our undeveloped reserves may not be ultimately developed or produced.*

The development of our proved undeveloped reserves may take longer and require higher levels of capital expenditures than we currently anticipate or that may be available to us. Delays in the development of our reserves or increases in costs to drill and develop such reserves will reduce the value of our estimated proved undeveloped reserves and future net revenues estimated for such reserves and may result in some projects becoming uneconomic. In addition, delays in the development of reserves could require us to reclassify our proved reserves as unproved reserves.

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Our management has identified 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 uncertainties, including uncertainty in the level of reserves; the availability of capital to us and other participants; seasonal conditions; regulatory approvals; activist intervention; crude oil, natural gas, and NGL prices; availability of permits; costs; and well performance. Because of these uncertainties, we do not know if the numerous potential drilling locations we have identified 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. Pursuant to existing SEC rules and guidance, subject to limited exceptions, proved undeveloped reserves may only be booked if they relate to wells scheduled to be drilled within five years of the date of booking, and we may therefore be required to downgrade to probable or possible categories any proved undeveloped reserves that are not developed within this five-year time frame. These limitations may limit our potential to book additional proved undeveloped reserves as we pursue our drilling program.

*Our ability to produce oil, gas, and NGLs economically and in commercial quantities could be impaired if we are unable to acquire adequate supplies of water for our drilling and/or completions operations or are unable to dispose of or recycle the water we produce at a reasonable cost and in accordance with applicable environmental rules and regulations.*

The hydraulic fracturing process on which we and others in our industry depend to complete wells that will produce commercial quantities of oil, gas, and NGLs require the use and disposal of significant quantities of water. Our inability to secure sufficient amounts of water, or to dispose of, or recycle, the water produced from our wells, could adversely impact our operations. Moreover, the imposition of new federal, state, or local environmental initiatives and regulations could include restrictions on our ability to conduct certain operations such as hydraulic fracturing or disposal of wastes, including, but not limited to, produced water, drilling fluids, and other wastes associated with the exploration, development, or production of oil, gas, and NGLs.

Compliance with environmental regulations, oil and gas leases, surface use agreements, and permit requirements governing the withdrawal, storage, and use of surface water and disposal or recycling of produced water or groundwater necessary for hydraulic fracturing of wells may increase our operating costs and cause delays, interruptions, or termination of our operations. The extent of these impacts cannot be predicted, but they could have an adverse effect on our operations and financial condition.

*If we are unable to replace reserves and increase our reserve life index, we will not be able to sustain production.*

Our future operations depend on our ability to find or acquire and develop oil, gas, and NGL reserves that are economically producible. Our properties produce oil, gas, and NGLs at a declining rate over time. In order to maintain current production rates, we must locate or acquire and develop new oil, gas, and NGL reserves to replace those being depleted by production.

For future acquisitions we may complete, a successful outcome for our business will depend on a number of factors, many of which are beyond our control. These factors include the purchase price and transaction costs for the acquisition; future oil, gas, and NGL prices; the ability to reasonably estimate the recoverable volumes of reserves, rates of future production and future net revenues attainable from reserves; future operating and capital costs; results of future exploration, exploitation, and development activities on the acquired properties; future abandonment and possible future environmental or other liabilities; ability to attract and retain employees and contractors; success in transitioning ownership of the acquired properties; relationships with local regulatory authorities, landowners, and communities; and the ability to review and confirm the seller's title to the subject properties. There are numerous uncertainties inherent in estimating these variables with respect to prospective acquisition targets. Actual results may vary substantially from those assumed in the estimates. Our customary review in connection with acquisitions will not necessarily reveal, or allow us to fully assess, all existing or potential problems and deficiencies with such properties. We do not inspect every well, and even when we inspect a well, we may not discover structural, subsurface, or environmental problems that may exist or arise. We may not be entitled to contractual indemnification for pre-closing liabilities, including environmental liabilities, and we may not be able to obtain representation and warranty or similar insurance products on terms or at a price that efficiently manages the perceived or actual risk profile. We often acquire interests in properties on an "as-is" basis with limited remedies for breaches of representations and warranties.

Significant acquisitions can change the nature of our operations and business depending upon the character of the acquired properties. For example, newly acquired properties may have substantially different operating and geological characteristics or be in different geographic locations than our existing properties.

To the extent that acquired properties are substantially different than our existing properties, our ability to efficiently realize the expected economic benefits of such transactions may be limited. If we are unable to replace any significant volume declines with additional volumes from other sources, our results of operations and cash flows could be materially and adversely impacted.

*The results of our operations are subject to drilling and completion technique risks, and results may not meet our expectations for reserves or production. As a result, we may incur material write-downs, and the value of our undeveloped acreage could decline if drilling and completion results are unsuccessful.*

Many of our operations involve utilizing the latest drilling and completion techniques as developed by us, other operators and our service providers in order to maximize production and ultimate recoveries and therefore generate the highest possible returns. Risks we face while drilling include, but are not limited to, landing our well bore outside the desired drilling zone, deviating from the

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desired drilling zone while drilling horizontally through the formation, the inability to run our casing the entire length of the well bore, and the inability to run tools and recover equipment consistently through the horizontal well bore. Risks we face while completing our wells include, but are not limited to, the inability to fracture stimulate the planned number of stages, the inability to run tools and other equipment the entire length of the well bore during completion operations, the inability to recover such tools and other equipment, and the inability to successfully clean out the well bore after completion of the final fracture stimulation.

In addition, exploration and drilling technologies we currently use or implement in the future may become obsolete. If we are unable to maintain technological advancements consistent with industry standards, our operations and financial condition may be adversely affected. We cannot be certain we will be able to implement exploration and drilling technologies on a timely basis or at a cost that is acceptable to us.

Ultimately, the success of exploration, drilling, and completion technologies and techniques can only be evaluated over time as more wells are drilled and production profiles are established over a sufficiently long time period. If our drilling results are less than anticipated or we are unable to execute our drilling program because of capital constraints, lease expirations, limited access to gathering systems and takeaway capacity, and/or prices for oil, gas, and NGLs decline, then the return on our investment for a particular project may not be as attractive as we anticipated and we could incur material write-downs of oil and gas properties and the value of our undeveloped acreage could decline in the future.

*The actual quantities and present value of our proved oil, gas, and NGL reserves may be less than we have estimated, and the cost to develop our reserves may be more than we have estimated.*

This report and certain of our other SEC filings contain estimates of our proved oil, gas, and NGL reserves and the present value of estimated future net revenues from those reserves. The process of estimating reserves is complex and estimates are based on various assumptions, including geological and geophysical characteristics; future oil, gas, and NGL prices; drilling, completion and other capital expenditures; gathering and transportation costs; operating expenses; effects of governmental regulation; taxes; timing of operations; and availability of funds. Therefore, these estimates are inherently imprecise. In addition, our reserve estimates for properties with limited production history may be less reliable than estimates for properties with lengthy production histories.

Actual future production; prices for oil, gas, and NGLs; revenues; production taxes; development expenditures; operating expenses; and quantities of producible oil, gas, and NGL reserves will most likely vary from those estimated. Any significant variance could materially affect the estimated quantities of, and present value related to proved reserves disclosed by us, and the actual quantities and present value may be significantly less than we have previously estimated. Our properties may also be susceptible to hydrocarbon drainage from production on adjacent properties, which we may not control.

As of December 31, 2025, 39 percent, or 260.7 MMBOE, of our estimated proved reserves were proved undeveloped. In order to develop our net proved undeveloped reserves, as of December 31, 2025, we estimate approximately $2.6 billion of capital expenditures would be required. Although we have estimated our proved reserves and the costs associated with these proved reserves in accordance with industry standards, estimated costs may not be accurate, development may not occur as scheduled, and actual results may not occur as estimated.

One should not assume that the standardized measure of discounted future net cash flows or PV-10 included in this report represent the current market value of our estimated proved oil, gas, and NGL reserves. Management has based the estimated discounted future net cash flows from proved reserves on price and cost assumptions required by the SEC, whereas actual future prices and costs may be materially higher or lower. Refer to *Reserves* in Part I, Items 1 and 2 of this report for discussion regarding the prices used in estimating the present value of our proved reserves as of December 31, 2025, and to the caption *Oil and Gas Reserve Quantities* under *Critical Accounting Estimates* in Part II, Item 7 of this report for additional information.

The timing of production from oil and gas properties and of related expenses affects the timing of actual future net cash flows from proved reserves, and thus their actual present value. Our actual future net cash flows could be less than the estimated future net cash flows for purposes of computing PV-10. In addition, the 10 percent discount factor required by the SEC to calculate PV-10 for reporting purposes is not necessarily the most appropriate discount factor given actual interest rates, costs of capital, and other risks to which our business and the oil and gas industry in general are subject.

*Our disposition activities may be subject to factors beyond our control, and in certain cases we may retain unforeseen liabilities for certain matters*.

We periodically sell non-core assets in order to increase capital resources available for core assets and other purposes and to create organizational and operational efficiencies. We also occasionally sell interests in core assets for the purpose of accelerating the development and increasing efficiencies in other core assets. Various factors could materially affect our ability to dispose of such assets, including the approvals of governmental agencies or third parties, the availability of purchaser financing and purchasers willing to acquire the assets on terms we deem acceptable, or other matters or uncertainties that could impact such dispositions, including whether transactions could be consummated or completed in the form or timing and for the value that we anticipate. At times, we may be required to retain certain liabilities or agree to indemnify buyers in connection with such asset sales, or we may have to rely on third

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parties to perpetuate leases we intend to develop in the future. The magnitude of such retained liabilities or of the indemnification obligations may be difficult to quantify at the time of the transaction and ultimately could be material.

*Title to the properties in which we have an interest may be impaired by title defects.*

We generally rely on title due diligence reports when acquiring oil and gas leasehold interests, and we obtain title opinions prior to commencing initial drilling operations on the properties we operate. Title to the properties in which we have an interest may be impaired by title defects that may not be identified in the due diligence title reports or title opinions we obtain, or such defects may not be cured following identification. A material title defect can reduce the value of a property or render it worthless, thus adversely affecting our oil and gas reserves, financial condition, results of operations, and operating cash flow, and may also impair the value of or render adjacent properties uneconomic to develop. Undeveloped acreage has greater risk of title defects than developed acreage and title insurance is not generally available for oil and gas properties.

*Our business could be negatively impacted by security threats, including cybersecurity threats, terrorism, armed conflict, and other disruptions.*

As an oil, gas, and NGL producer, we face various security threats, including cybersecurity threats to gain unauthorized access to sensitive information or to render data or systems unusable; threats to the safety of our employees; threats to the security of our facilities and infrastructure or third-party facilities and infrastructure, such as processing plants and pipelines; and threats from terrorist acts, including armed attacks on shipping channels. Although we utilize various procedures and controls to monitor these threats and mitigate our exposure to such threats, there can be no assurance that these procedures and controls will be sufficient in preventing security threats from materializing. If any of these events were to materialize, they could lead to losses of sensitive information, critical infrastructure, personnel, or capabilities essential to our operations and could have a material adverse effect on our reputation, financial position, results of operations, or cash flows. Further, our insurance may not protect against such occurrences.

The threat of terrorism and the impact of military and other actions have caused instability in world financial markets and could lead to increased volatility in prices for oil, gas, and NGLs, all of which could adversely affect the markets for our production. Energy assets might be specific targets of terrorist attacks. Depending on their occurrence and ultimate magnitude, terrorist threats or attacks could have a material adverse effect on our business, financial condition, or results of operations.

*We are subject to operating and environmental risks and hazards that could result in substantial losses or liabilities that may not be fully insured.*

Oil and gas operations are subject to many risks, including human error and accidents, that could cause personal injury, death, and property damage. These include well blowouts, craterings, explosions, and uncontrollable flows of oil, gas, NGLs, and well fluids. Risks also include releases or spills of completion fluids, spills or releases from facilities and equipment used to deliver or store these materials, and spills or releases of brine or other produced or flowback water. In addition, subsurface conditions may prevent us from stimulating the planned number of completion stages, accessing the entirety of the wellbore with our tools during completion, or removing materials from the wellbore to allow production to begin. Fires, adverse weather such as hurricanes or tornadoes, freezing conditions, wildfires, floods, droughts, formations with abnormal pressures, pipeline ruptures or spills, train derailments, pollution, seismic events, releases of toxic gas such as hydrogen sulfide, and other environmental risks and hazards may impact operations. If any of these types of events occur, we could sustain substantial losses.

In response to increased seismic activity in the Permian Basin in Texas, the Railroad Commission of Texas ("RRC") has developed a seismic review process for injection wells near qualifying seismic activity. As a result of the seismic review process, the RRC may declare an area to be a Seismic Response Area ("SRA") and may adjust limits for injection rates and pressure, require bottom-hole pressure tests, or modify, suspend, or terminate injection well permits within the SRA. If an SRA is declared within an area of our operations, our ability to dispose of produced water may be adversely affected, and as a result, we may be forced to shut-in injection wells or find alternate produced water disposal options which could affect production and therefore oil, gas, and NGL production revenue, and could cause us to incur additional capital or operating expense. The declaration of SRAs has required us to adjust the areas where we seek permits for injection wells to areas or formations that are less desirable, and could further restrict the areas where we are able to obtain and operate under such permits without restrictions. Additionally, we could be subject to third-party claims and liability based on allegations that our operations caused or contributed to seismic events that resulted in damage to property or personal injury, or that are otherwise related to seismic events.

If we experience any of the problems with well stimulation, completion activities, and disposal referenced above, our ability to explore for and produce oil, gas, and NGLs may be adversely affected. We could incur substantial losses or otherwise fail to realize reserves in particular formations resulting from the need to shut down, abandon, or relocate drilling operations, the need to modify drill sites to lessen the risk of spills or releases, the need to investigate and/or remediate any spills, releases or ground water contamination that might have occurred, and the need to suspend our operations.

There is an inherent risk of incurring significant environmental costs and liabilities in our operations due to our current and past generation, handling, and disposal of materials, including produced water, solid and hazardous wastes, and petroleum hydrocarbons. We may incur joint and several, and/or strict liability under applicable United States federal and state environmental laws in connection

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with releases of hazardous substances at, on, under, or from our leased or owned properties, some of which have been used for oil and gas exploration and production activities for a number of years, often by third-parties not under our control. For our outside-operated properties, we are dependent on the operator for operational and regulatory compliance and could be subject to liabilities in the event of non-compliance. These properties and the wastes disposed thereon or therefrom could be subject to stringent and costly investigatory or remedial requirements under applicable laws, some of which are strict liability laws without regard to fault or the legality of the original conduct, including CERCLA , RCRA, the Clean Water Act, the CAA, the OPA, and analogous state laws. Under various federal, state, and local regulations, we could be required to remove or remediate previously disposed wastes (including wastes disposed of or released by prior owners or operators) or property contamination (including groundwater contamination), to perform natural resource mitigation or restoration practices, or to perform remedial plugging or closure operations to prevent future contamination. In addition, it is not uncommon for neighboring landowners and other third-parties to file claims for personal injury or property damage, including induced seismicity damage, allegedly caused by the release of petroleum hydrocarbons or other hazardous substances into the environment. As a result, we may incur substantial liabilities to third-parties or governmental entities, which could reduce or eliminate funds available for exploration, development, or acquisitions, or cause us to incur losses.

We maintain insurance against some, but not all, of these potential risks and losses. We have significant but limited coverage for sudden environmental damage. We do not believe that insurance coverage for the full potential liability that could be caused by environmental damage that occurs gradually over time is appropriate for us at this time given the nature of our operations and the nature and cost of such coverage. Further, we may elect not to obtain insurance coverage under circumstances where we believe that the cost of available insurance is excessive relative to the risks to which we are subject. Accordingly, we may be subject to liability or may lose substantial assets in the event of environmental or other damages. If a significant accident or other event occurs and is not fully covered by insurance, we could suffer an uninsured material loss.

*The impact of seasonal and extreme weather conditions and lease stipulations adversely affect our ability to conduct drilling activities in some of the areas where we operate.*

Our operations have been in the past, and may continue to be, adversely affected by the impact of seasonal and extreme weather conditions. Additionally, lease stipulations designed to protect various wildlife or plant species may adversely impact our operations. In certain areas, drilling and other oil and gas activities can only be conducted during limited times of the year. This limits our ability to operate in those areas and can intensify competition during those times for drilling rigs and completion equipment, oil field equipment, services, supplies and qualified personnel, which may lead to periodic shortages. These constraints and the resulting shortages or high costs could delay our operations and materially increase our operating and capital costs.

**Risks Related to Litigation and Government Regulations**

*In the future, we may be subject to claims, litigation, administrative proceedings and regulatory actions that may not be resolved in our favor.*

In the future, we may be subject to claims, litigation, administrative proceedings and regulatory actions. The outcome of these matters may be difficult to assess or quantify, and there cannot be any assurance that such matters will be resolved in our favor. If we are unable to resolve such matters favorably, we or our directors, officers or employees may become involved in legal proceedings that could result in an onerous or unfavorable decision, including fines, sanctions, monetary damages or the inability to engage in certain operations or transactions. The defense of such matters may also be costly, time consuming and could divert the attention of management and key personnel away from our operations. We may also be subject to adverse publicity associated with such matters, regardless of whether such allegations are valid or whether we are ultimately found liable. As a result, such matters could have a material adverse effect on our business, reputation, financial condition, results of operations or liquidity.

*Our operations are subject to complex laws and regulations, including environmental regulations, which result in substantial costs and other risks.*

Federal, state, tribal, and local authorities extensively regulate the oil and gas industry. Legislation and regulations affecting the industry are under constant review for amendment or expansion, and subject to constantly changing or differing interpretations, raising the possibility of changes that may become more stringent and, as a result, may affect, among other things, the pricing, or marketing of oil, gas, and NGL production. Non-compliance with statutes and regulations and more vigorous enforcement of such statutes and regulations by regulatory agencies may lead to increased operational and compliance costs, substantial administrative penalties, civil penalties, and criminal prosecution. These may include the assessment of natural resource damages and the imposition of significant investigatory and remedial obligations, potentially resulting in the suspension or termination of our operations. The overall regulatory burden on the industry increases the cost to place, design, drill, complete, install, operate, and abandon wells and related facilities and, in turn, decreases profitability.

Governmental authorities regulate various aspects of drilling for and the production of oil, gas, and NGLs, including the permit and bonding requirements of drilling wells, the spacing of wells, the unitization or pooling of interests in oil and gas properties, rights-of-way and easements, disposal of produced water, environmental matters, occupational health and safety, the sharing of markets, production limitations, plugging, abandonment, restoration standards, and oil and gas operations. Public interest in environmental protection has increased over time, and environmental and other public interest organizations have opposed, with some success,

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certain projects. Under certain circumstances, regulatory authorities may deny a proposed permit or right-of-way grant or impose conditions of approval to mitigate potential environmental impacts, which could, in either case, negatively affect our ability to explore or develop certain properties. Any such delay, suspension, or termination could have a material adverse effect on our operations.

Our operations are also subject to complex and constantly changing environmental laws and regulations adopted by federal, state, tribal, and local governmental authorities in jurisdictions where we are engaged in exploration or production operations. New laws or regulations, or changes to current requirements, including, among other things, air quality and GHG emissions standards and the designation of previously unprotected wildlife or plant species as threatened or endangered in areas we operate in, could result in material costs or claims with respect to properties we own or have owned or limitations on exploration and production activities in certain locations. We will continue to be subject to uncertainty associated with new regulatory interpretations and inconsistent interpretations between state and federal agencies. Under existing or future environmental laws and regulations, we could incur significant liability, including joint and several, strict liability under federal, state, tribal, and local environmental laws for emissions and for discharges of oil, gas, and NGLs or other pollutants into the air, soil, surface water, or groundwater as described in *Government Regulations* in Part I, Items 1 and 2 of this report. Existing environmental laws or regulations, as currently interpreted or enforced, or as they may be interpreted, enforced, or altered in the future, may have a material adverse effect on us.

*Federal and state legislative and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays.*

Hydraulic fracturing is a common practice in the oil and gas industry used to stimulate the production of oil, gas, and NGLs from dense subsurface rock formations. We routinely apply hydraulic fracturing techniques to many of our oil and gas properties, including our unconventional resource plays. Hydraulic fracturing involves injecting water, sand, and certain chemicals under pressure to fracture the hydrocarbon-bearing rock formation to allow the flow of hydrocarbons into the wellbore. The process is typically regulated by state oil and gas commissions. However, the EPA and other federal agencies have asserted federal regulatory authority over certain aspects of hydraulic fracturing activities, as outlined below.

The EPA has authority to regulate underground injections that contain diesel in the fluid system under the Safe Drinking Water Act. The EPA also has authority under the Clean Water Act to regulate wastewater generated by unconventional oil and gas operations during the hydraulic fracturing process and discharged to publicly-owned wastewater treatment facilities. Although the Trump administration has signaled a desire for fewer environmental regulations, if the EPA were to implement further regulations of hydraulic fracturing, we may incur additional costs to comply with such requirements that may be significant in nature, experience delays or curtailment in the pursuit of exploration, development, or production activities, and could even be prohibited from drilling and/or completing certain wells.

A slowdown in federal regulation of hydraulic fracturing could encourage states, tribes, or localities to implement more or stricter regulations. Certain states have adopted or may adopt, regulations that could impose more stringent permitting, public disclosure, waste disposal, and well construction requirements on hydraulic fracturing operations or otherwise seek to ban fracturing activities altogether. The regulatory burden of each state's respective laws varies. For example, some counties in Colorado have amended their land use regulations to impose new siting and other requirements on oil and gas development, while other local governments have entered memoranda of agreement with oil and gas producers to accomplish the same or similar objectives. Under current Colorado law, local governments can regulate both facility siting and the surface impacts associated with oil and gas development, and local government regulations may be more protective or stricter than state requirements. Texas, Utah, and Colorado require disclosure of chemical ingredients used in hydraulic fracturing fluids. State initiatives relevant to fracturing are often changing and priorities across states differ. On May 14, 2025, the New Mexico Water Quality Control Commission adopted a rule that prohibits the discharge of produced water to New Mexico's ground and surface waters. Also in 2025, New Mexico lawmakers proposed a bill that would ban PFAS in fracking operations. In 2015, Texas Governor Greg Abbott signed a law which preempts municipal and county bans or limits on oil and gas operations, including drilling and hydraulic fracturing, and confirms that regulation of those activities is under the state of Texas' exclusive jurisdiction, while still allowing limited, commercially reasonable, surface-level regulation by local governments.

In addition to state laws, local land use restrictions, such as city ordinances or memoranda of understanding, may restrict, or prohibit the performance of drilling in general and/or hydraulic fracturing in particular. Recently, municipalities have passed or proposed zoning ordinances that ban or strictly regulate hydraulic fracturing within city boundaries, setting the stage for challenges by state regulators and third-parties. Similar events and processes are playing out in several cities, counties, and townships across the United States. In the event that tribal, state, local, or municipal legal restrictions are adopted in areas where we are currently conducting, or in the future plan to conduct, operations, we may incur additional costs to comply with such requirements that may be significant in nature, experience delays or curtailment in the pursuit of exploration, development, or production activities, and could even be prohibited from drilling and/or completing certain wells.

In the recent past, several federal governmental agencies were actively involved in studies or reviews that focus on environmental aspects and impacts of hydraulic fracturing practices. Increased regulation and attention given to the hydraulic fracturing process could lead to greater opposition, including litigation, to oil and gas production activities using hydraulic fracturing techniques. Disclosure of chemicals used in the hydraulic fracturing process could make it easier for third parties opposing such activities to pursue legal proceedings against producers and service providers based on allegations that specific chemicals used in the fracturing process could adversely affect human health or the environment, including groundwater. Litigation resulting in financial compensation for

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damages linked to hydraulic fracturing, including damages from induced seismicity, could spur future litigation and bring increased attention to the practice of hydraulic fracturing. Judicial decisions could also lead to increased regulation, permitting requirements, enforcement actions, and penalties. Additional legislation or regulation could also lead to operational delays or restrictions or increased costs in the exploration for, and production of, oil, gas, and NGLs, including from the development of shale plays, or could make it more difficult to perform hydraulic fracturing. The adoption of additional state or local laws, or the implementation of new regulations regarding hydraulic fracturing could potentially cause a decrease in the completion of new oil and gas wells, or an increase in compliance costs and delays, which could adversely affect our financial position, results of operations, and cash flows.

We will continue to be subject to uncertainty associated with new regulatory suspensions, revisions or rescissions and inconsistent state and federal regulatory mandates that could adversely affect our production.

*Federal and state regulatory initiatives relating to air quality and greenhouse gas emissions could result in increased costs and additional operating restrictions or delays.*

There has been a trend toward increased air quality and GHG regulation and reduced emissions from oil and gas sources. These regulations include the New Source Performance Standards ("NSPS"), the National Emission Standards for Hazardous Air Pollutants programs, and ozone standards set under the National Ambient Air Quality Standards ("NAAQS"), among others. Notwithstanding any reversal of this trend federally by the Trump administration, the adoption of additional state or local laws could adversely affect our financial position, results of operations, and cash flows. Refer to the *Environmental* section in Part II, Item 7 of this report for additional information about the regulation of air emissions, particularly methane emissions from the oil and gas sector.

Additionally, certain areas where we currently operate (such as the Uinta Basin in Utah) or may operate in the future are or may be designated as ozone non-attainment areas, and are subject to stricter emissions regulations and control measures. These increased regulations and controls, which may increase over time, result in certain restrictions or limitations to our operations, increase our costs and may cause delays, which could affect our financial position, results of operations, and cash flows.

*Legislative and regulatory initiatives and litigation related to global warming and climate change could have an adverse effect on our operations and the demand for oil, gas, and NGLs, and could result in significant litigation, capital, and related expenses.*

While courts have generally declined to assign direct liability for climate change to large sources of GHG emissions, some have required increased scrutiny of such emissions by federal agencies and permitting authorities. There is a continuing risk of claims being filed against companies that have significant GHG emissions, and new claims for damages and increased government scrutiny, especially from state and local governments, will likely continue.

The United States Congress has from time to time considered adopting legislation to reduce emissions of GHGs, and the majority of states have already taken measures to reduce emissions of GHGs through various measures, including, primarily through the planned development of GHG emission inventories, participation in and/or regional GHG "cap and trade" programs, and/or transition to clean energy. The focus on legislating and/or regulating methane could result in increased scrutiny for sources emitting high levels of methane, including during permitting processes, analysis, regulation and reduction of methane emissions as a requirement for project approval, and actions taken by one agency for a specific industry establishing precedents for other agencies and industry sectors. In 2021, the EPA proposed requirements for methane emission reductions from existing oil and gas equipment. In 2022, the EPA released a supplemental proposal expanding its initial requirements as well as updating requirements, and in 2023, proposed updates to GHG reporting requirements. In 2024, the EPA announced a final rule that facilitates the implementation of Congress's directive in the Inflation Reduction Act of 2022 ("IRA") to collect a waste emissions charge, but on March 14, 2025, President Trump signed a joint resolution of disapproval under the Congressional Review Act, voiding the EPA's final rule on methane waste emission.

Scientists have predicted that increasing concentrations of GHGs in the earth's atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, floods, and other climatic events. If such effects were to occur, our operations could be adversely affected. Potential adverse effects could include disruption of our drilling, completion, and production activities, including, for example, damages to our facilities from flooding or increases in our costs of operation or reductions in the efficiency of our operations. Significant physical effects of climate change could also have an indirect effect on our financing and operations by disrupting the transportation or process-related services provided by midstream companies, service companies, or suppliers with whom we have a business relationship. We may not be able to recover through insurance some or any of the damages, losses, or costs that may result from potential physical effects of climate change. Federal regulations or policy changes regarding climate change preparation requirements could also impact our costs and planning requirements because emissions of such gases contribute to warming of the earth's atmosphere and other climatic changes.

*Requirements to reduce gas flaring could have an adverse effect on our operations.*

In the areas where we have significant operations, there have been, and could be, in the future, constraints in gas takeaway capacity which has historically led to increased gas flaring. We are subject to laws established by state and other regulatory agencies that restrict the duration and amount of natural gas that can be legally flared. These laws and regulations, including potential future regulations that may impose further restrictions on flaring, could limit the amount of oil and gas we can produce from our wells or may

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limit the number of wells or the locations that we can drill. Any future laws or commitments may increase our operational costs, or restrict our production, which could have a material adverse effect on our financial condition, results of operations and cash flows.

*Senate Bill 181's requirement, which applies to our Colorado operations, that we own or control more than 45 percent of the working or mineral interest in order to statutorily pool our applicable interest may make it much more difficult for us to develop such interests, which could have a material adverse effect on our business, financial condition, and results of operations.*

With respect to our operations in the DJ Basin in Colorado, in some cases, we do not own more than 45 percent working interest or mineral interest in a prospective area of development, which is now required to statutorily pool our applicable working or mineral interests. In such cases, unless we can obtain the consent of more than 45 percent of all applicable working or mineral interest owners (who can be located through reasonable diligence) to pursue statutory pooling, or achieve a voluntary pooling agreement with 100 percent of the applicable interest owners, we may be prohibited from developing the resources in that area or having them be developed by other operators.

**Risks Related to Debt, Liquidity, and Access to Capital**

*Commodity price declines could result in a decrease in the amount available to us under our Credit Agreement.*

As of December 31, 2025, the borrowing base and aggregate revolving lender commitments under our Credit Agreement were $3.0 billion and $2.0 billion, respectively. The borrowing base is subject to semi-annual redetermination based on the bank group's assessment of the value of our proved reserves, which in turn is impacted by oil, gas, and NGL prices. On January 30, 2026, in connection with the closing of our acquisition of Civitas, we entered into a Fourth Amendment to our Credit Agreement, which increased the borrowing base to $5.0 billion, increased aggregate revolving lender commitments to $2.5 billion, and extended the scheduled maturity date to January 30, 2031. The next borrowing base redetermination date is scheduled to occur on April 1, 2026. Divestitures of properties, incurrence of additional debt, or declines in commodity prices could limit our borrowing base and reduce the amount we can borrow under our Credit Agreement, which could in turn impact, among other things, our ability to service our debt, fund our capital program, or compete for the acquisition of new properties.

*Negative public perception and investor sentiment regarding our business and the oil and gas industry as a whole could adversely affect our business, operations, and our ability to attract capital.*

Certain segments of the public as a whole, and the investment community in particular, have developed negative sentiment toward our industry. In recent years, equity returns in the sector versus other industry sectors have led to lower oil and gas representation in certain key equity market indices. In addition, some investors, including investment management firms, sovereign wealth and pension funds, university endowments and other investment advisors, have adopted policies to discontinue or reduce their investments in the oil and gas sector based on social and environmental considerations. Furthermore, other influential stakeholders have pressured commercial and investment banks and other service providers to reduce or cease financing of oil and gas companies and related infrastructure projects.

Such developments could result in downward pressure on the stock prices of oil and gas companies, including ours. This may also potentially result in a reduction of available capital funding for potential development projects, impacting our future financial results.

*Substantial capital is required to develop and replace our reserves.*

We must make substantial capital expenditures to find, acquire, develop, and produce oil, gas, and NGL reserves. Future cash flows and the availability of financing are subject to a number of factors, such as the level of production from existing wells, prices received for oil, gas, and NGL sales, our success in locating, acquiring, and developing new reserves, and the orderly functioning of credit and capital markets. If our cash flows from operations are less than expected, we may reduce our planned capital expenditures. If we cannot access sufficient liquidity under our Credit Agreement, or raise additional funds through debt or equity financing or the sale of assets, our ability to execute development plans, replace our reserves, maintain our acreage, or maintain production levels could be greatly limited.

*Downgrades in our credit ratings by various credit rating agencies could impact our access to capital and have a material adverse effect on our business and financial condition.*

Downgrades of our credit ratings could have material adverse consequences on our business and future prospects and could:

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• limit our ability to access capital markets, including for the purpose of refinancing our existing debt;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• cause us to refinance or issue debt with less favorable terms and conditions, which may restrict, among other things, our ability to make any dividend payments or repurchase shares;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;*•* negatively impact lenders' willingness to transact business with us, which could impact our ability to obtain favorable terms and conditions under our Credit Agreement;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• negatively impact current and prospective customers' willingness to transact business with us;

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&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• impose additional insurance, guarantee, bonding, and collateral requirements;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• limit our access to bank and third-party guarantees, surety bonds, and letters of credit; and

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• cause our suppliers and financial institutions to lower or eliminate the level of credit provided through payment terms or intraday funding when dealing with us, thereby increasing the need for higher levels of cash on hand, which would decrease our ability to repay outstanding indebtedness.

We cannot provide assurance that any of our current credit ratings will remain in effect for any given period of time or that a credit rating will not be lowered or withdrawn entirely by a rating agency if, in its judgment, circumstances warrant.

*Our commodity derivative contract activities may result in financial losses or may limit the prices we receive for oil, gas, and NGL sales.*

To mitigate a portion of the exposure to potentially adverse market changes in oil, gas, and NGL prices and the associated impact on cash flows, we regularly enter into commodity derivative contracts. Our commodity derivative contracts typically include price swaps and collar arrangements for oil, gas, and NGLs. These activities may expose us to the risk of financial loss in certain circumstances, including instances in which:

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• our production is less than expected;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• one or more counterparties to our commodity derivative contracts default on their contractual obligations; or

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• there is a widening of price differentials between delivery points for our production and the delivery point assumed in the commodity derivative contract arrangement.

In addition, commodity derivative contracts may limit the prices we receive for our oil, gas, and NGL sales if oil, gas, or NGL prices rise substantially over the price established by the commodity derivative contract. Refer to *Note 7 – Derivative Financial Instruments* in Part II, Item 8 of this report for additional detail regarding our commodity derivative contracts.

*The amount of our debt may limit our ability to obtain financing for acquisitions, make us more vulnerable to adverse economic conditions, and make it more difficult for us to make payments on our debt.*

As of December 31, 2025, we had $2.7 billion of aggregate principal amount outstanding of Senior Notes with maturities through 2032, as further discussed and defined in *Note 5 – Long-Term Debt* in Part II, Item 8 of this report. We had no outstanding balance on our revolving credit facility and we had $2.0 billion of available borrowing capacity under our Credit Agreement as of December 31, 2025. Our long-term debt represented 36 percent of our total book capitalization as of December 31, 2025.

In connection with the Civitas Merger on January 30, 2026, we assumed approximately $4.9 billion in aggregate principal amount of additional senior notes with maturities through 2033. Additionally, in connection with the closing of the Civitas Merger, the Company and its lenders entered into the Fourth Amendment to the Credit Agreement, which increased the aggregate revolving lender commitments available under our Credit Agreement to $2.5 billion and increased the borrowing base to $5.0 billion. As of February 2, 2026, we had no outstanding balance on our revolving credit facility and we had $2.5 billion of available borrowing capacity under our Credit Agreement. Refer to *Note 5 – Long-Term Debt* in Part II, Item 8 of this report for additional detail.

The amounts of our indebtedness could have important consequences for our operations, including:

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• making it more difficult for us to obtain additional financing in the future for our operations and potential acquisitions, working capital requirements, capital expenditures, debt service, or other general corporate requirements;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• requiring us to dedicate a substantial portion of our cash flows from operations to the repayment of our debt and the service of interest costs associated with our debt, rather than to capital investments;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• limiting our operating flexibility due to financial and other restrictive covenants, including restrictions on incurring additional debt, making acquisitions, and paying dividends or repurchasing shares of common stock;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• placing us at a competitive disadvantage compared to our competitors with less debt; and

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• making us more vulnerable in the event of adverse economic or industry conditions or a downturn in our business.

If our business does not generate sufficient cash flow from operations or future sufficient borrowings are not available to us under our Credit Agreement or from other sources, we might not be able to service our debt, issue additional debt, or fund our planned capital expenditures and other liquidity needs. If we are unable to service our debt due to inadequate liquidity or otherwise, we may have to delay or cancel acquisitions, defer capital expenditures, sell equity securities, divest assets, and/or restructure or refinance our debt. We might not be able to sell our equity, sell our assets, or restructure or refinance our debt on a timely basis or on satisfactory terms or at all. In addition, the terms of our existing or future debt agreements, including our Credit Agreement and any future credit agreements, may prohibit us from pursuing any of these alternatives.

As discussed above, our Credit Agreement is subject to periodic borrowing base redeterminations. At times when we have an outstanding balance, we could be forced to repay a portion of our bank borrowings in the event of a downward redetermination of our

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borrowing base, and we may not have sufficient funds to make such repayment at that time. If we do not have sufficient funds and are otherwise unable to negotiate adjustments to our borrowing base or arrange new financing, we may be forced to sell significant assets.

*The agreements governing our debt arrangements contain various covenants that limit our discretion in the operation of our business, could prohibit us from engaging in transactions we believe to be beneficial, and could lead to the accelerated repayment of our debt.*

Our debt agreements, including our Credit Agreement and the indentures governing our Senior Notes, contain restrictive covenants that limit our ability to engage in activities that may be in our long-term best interests, including restrictions on incurring debt, issuing dividends, repurchasing common stock, selling assets, creating liens, entering into transactions with affiliates, and merging, consolidating, or selling our assets. Our ability to borrow under our Credit Agreement is subject to compliance with certain financial and non-financial covenants, as outlined in the Credit Agreement. Refer to *Note 5 – Long-Term Debt* in Part II, Item 8 of this report for additional discussion. These restrictions on our ability to operate our business could significantly harm us by, among other things, limiting our ability to take advantage of financings, mergers and acquisitions, and other corporate opportunities.

Our failure to comply with these covenants could result in an event of default that, if not cured or waived, could result in the acceleration of all or a portion of our indebtedness. We do not have sufficient working capital to satisfy our debt obligations in the event of an acceleration of all or a significant portion of our outstanding indebtedness.

**Risks Related to Corporate Governance and Ownership of Public Equity Securities**

*Our certificate of incorporation and by-laws have provisions that discourage corporate takeovers and could prevent stockholders from receiving a takeover premium on their investment, which could adversely affect the price of our common stock.*

Delaware corporate law and our certificate of incorporation and by-laws contain provisions that may have the effect of delaying or preventing a change of control of us or our management. These provisions, among other things, provide for non-cumulative voting in the election of members of the Board of Directors and impose procedural requirements on stockholders who wish to make nominations for the election of directors or propose other actions at stockholder meetings. These provisions, alone or in combination with each other, may discourage transactions involving actual or potential changes of control, including transactions that otherwise could involve payment of a premium over prevailing market prices to stockholders for their common stock. As a result, these provisions could make it more difficult for a third party to acquire us, even if doing so would benefit our stockholders, which may limit the price investors are willing to pay in the future for shares of our common stock.

In addition, stockholder activism in our industry has been present in recent years, and if investors seek to exert influence or affect changes to our business that we do not believe are in the long-term best interests of our stockholders, such actions could adversely impact our business by, among other things, distracting our Board of Directors and management team, causing us to incur unexpected advisory fees and other related costs, impacting execution of our strategic objectives, and creating unnecessary market uncertainty.

*The price of our common stock may fluctuate significantly, which may result in losses for investors.*

From January 1, 2025, to February 2, 2026, the intraday trading prices per share of our common stock as reported by the New York Stock Exchange ranged from a low of $17.45 per share in January 2026 to a high of $44.95 per share in January 2025. We expect our stock to continue to be subject to fluctuations resulting from a variety of factors, including factors beyond our control. These factors include, in addition to the other risk factors set forth herein, the following:

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• changes in oil, gas, or NGL price;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• changes in the outlook for regional, national, or global commodity supply and demand;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• variations in drilling, recompletion, and operating activity;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• inflation;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• changes in financial estimates by securities analysts;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• changes in market valuations of comparable companies;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• additions or departures of key personnel;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• increased volatility due to the impacts of algorithmic trading practices;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• future sales of our common stock;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• negative public perception and investor sentiment regarding our business and the oil and gas industry as a whole;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• changes in the national and global economic outlook, including potential impacts from trade agreements or tariffs; and

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• international trade relationships, potentially including the effects of trade restrictions or tariffs affecting the raw materials we utilize and the commodities we produce in our business.

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We may not meet the expectations of our stockholders and/or of securities analysts at some time in the future, and our stock price could decline as a result.

*We may not always pay dividends on our common stock or repurchase common stock under our Stock Repurchase Program.*

Payment of future dividends remains at the discretion of our Board of Directors, and common stock repurchases under our Stock Repurchase Program remain at the discretion of our Board of Directors and certain authorized officers of the Company. Decisions regarding the payment of dividends and the repurchase of common stock will continue to depend on our earnings, capital requirements, financial condition, general market and economic conditions, applicable legal requirements, the market price of our common stock, and other factors. The payment of dividends and the repurchase of our common stock are each subject to covenants in our Credit Agreement and in the indentures governing our Senior Notes that could limit our ability to make certain restricted payments including dividends and common stock repurchases. Our Board of Directors may determine in the future to reduce the current annual dividend rate or discontinue the payment of dividends altogether. The value of shares authorized for repurchase by the Board of Directors does not require us to repurchase such shares or guarantee that such shares will be repurchased, and the Stock Repurchase Program may be suspended, modified, or discontinued at any time without prior notice. No assurance can be given that any particular number or dollar value of our shares will be repurchased. Refer to *Purchases of Equity Securities by Issuer and Affiliated Purchasers* in Part II, Item 5 of this report for discussion and definition of the Stock Repurchase Program.

**ITEM 1B. UNRESOLVED STAFF COMMENTS**

We have no unresolved comments from the SEC staff regarding our periodic or current reports under the Exchange Act.

**ITEM 1C. CYBERSECURITY**

**Governance**

Our Board of Directors, with assistance from the Audit Committee, oversees the Company's enterprise risk management process, including with respect to relevant IT matters affecting the Company and management of risks arising from cybersecurity threats. Our Board of Directors has delegated the primary responsibility to oversee relevant IT matters affecting the Company, including cybersecurity risks and mitigations strategies, to the Audit Committee. The Audit Committee receives cybersecurity reports and regular updates from our Vice President and Chief Information Officer and our Director of Cybersecurity Risk and Business Continuity ("IT Management"), which includes, among other information, the steps management has taken and the specific guidelines and policies that have been established to monitor, control, mitigate and report exposure to cybersecurity risk. The Audit Committee regularly reports to the Board of Directors on relevant IT matters affecting the Company, including cybersecurity risks and mitigation strategies.

IT Management is responsible for assessing and managing cybersecurity risks and leads a team of specialized technologists entrusted with ensuring the functionality, continuity, and security of our technology infrastructure and data. This team regularly reports to IT Management, and IT Management regularly reviews risk management measures implemented by the Company to identify and mitigate data protection and cybersecurity risks. IT Management works closely with our legal department to oversee compliance with legal, regulatory and contractual security requirements.

During 2025, our Vice President and Chief Information Officer was a seasoned IT professional with over 30 years of experience encompassing all facets of IT within the energy industry. His extensive background comprises managing IT service delivery, designing and administering secure solutions, establishing robust IT and Internet of Things infrastructures, and effectively managing technology-related risks. His skill set includes proficiency in threat mitigation, comprehensive risk assessment, and integration of cybersecurity strategies into business operations designed to safeguard critical assets and sensitive data. He reported to our Executive Vice President and Chief Financial Officer until his retirement in January 2026. Our Director of Cybersecurity Risk and Business Continuity has over 25 years of experience in the IT field with a majority of that time focused on designing, building and maintaining technology systems. His experience includes implementing security solutions and processes with a focus on adapting to the evolving cybersecurity threat landscape. He is a skilled leader and reports to our Executive Vice President and Chief Financial Officer.

In January 2026, upon his retirement, our Vice President and Chief Information Officer,'s role was been assumed by our new Vice President of Information Technology who has over 20 years of IT experience,12 of which have been at the Company in progressive leadership roles.

We have adopted a Cybersecurity Incident Response Plan that applies in the event of a cybersecurity threat or incident (the "IRP") to provide a standardized framework for responding to security incidents. The IRP outlines protocols by which certain cybersecurity incidents are escalated within the Company and, where appropriate, reported to executive management Audit Committee in a timely manner. We have also established a Cyber Incident Response Team ("CIRT") led by IT Management, to provide an efficient, effective, and orderly response to technology related incidents. The IRP applies to all Company personnel (including third-party contractors, vendors and partners) that perform functions or services require access to secure Company information, and to all devices and network services that are owned or managed by the Company.

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**Risk Management and Strategy**

We believe that mitigating cybersecurity risks is the responsibility of every employee. We are focused on building a resilient cybersecurity culture and strong IT and OT infrastructure. Our processes for assessing, identifying, and managing material risks from cybersecurity threats include:

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• monitoring the threat landscape and taking measures to enhance our cybersecurity program to adapt to new and developing risks;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• ongoing mandatory training and testing, and utilizing other forms of social engineering awareness and education for our employees;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• using cybersecurity tools to monitor endpoints and environment logs in a centralized security information and event management system with capabilities for detecting and alerting on known threats and anomalous behaviors;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• assessing the cybersecurity practices and external ratings and assessments of certain of our third-party technology and data vendors and service providers, and maintaining preventative controls and monitoring systems related to these partners;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• creating and testing various incident response plans to hypothetical cybersecurity attacks in order to quickly assess and respond to potential and actual threats;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• engaging third-party cybersecurity experts and consultants to perform penetration testing and scanning of our systems for vulnerabilities;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• obtaining third-party security maturity assessments, benchmarking, and security effectiveness ratings of our cybersecurity program; and

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• maintaining a retainer for incident response services with a trusted cybersecurity partner in order to quickly respond, investigate, contain, and recover in the event of a cybersecurity incident.

Our cybersecurity risk management program leverages the National Institute of Standards and Technology's Cybersecurity Framework. We strive to employ cybersecurity best practices, including implementing new technologies to proactively monitor new threats and vulnerabilities and reduce risk; maintaining a Cybersecurity Incident Response Plan, Disaster Recovery Plan, and Business Continuity Plan; and regularly updating our response planning and protocols. We have integrated our cybersecurity processes into our overall enterprise risk management program, thereby establishing a comprehensive approach by which we determine and implement strategies designed to manage external, strategic, operational and financial risks to our business, including cybersecurity threats.

We utilize a wide range of protective cybersecurity technologies and tools, including, but not limited to, encryption, firewalls, endpoint detection and response, security information and event management, multi-factor authentication, and threat intelligence feeds. In addition, we use an information security risk management approach that includes monitoring security threats and trends in the industry, analyzing potential security risks that could impact the business, partnering with industry recognized security organizations, and coordinating an appropriate response should the need arise.

Cybersecurity threats and incidents could have a material impact on our financial condition and results of operations. A successful cyber-attack could lead to operational disruptions, financial losses, regulatory penalties, reputational damage, and legal liabilities. In some cases, the costs associated with investigating and remediating a cybersecurity incident, as well as potential litigation and regulatory fines, could result in a material impact to our financial condition and results of operations. During 2025, 2024, and 2023, we did not experience any cybersecurity incidents that materially affected or are reasonably likely to materially affect us, including our business strategy, results of operations, or financial condition, however, there can be no assurance that the measures we have taken to address IT and cybersecurity risks will prove effective in the future. For additional discussion of the IT and cybersecurity risks facing our business, refer to *Risk Factors* in Part I, Item 1A of this report.

We prioritize investment in cybersecurity risk management and governance. We continually assess the adequacy of our resources and capabilities to address emerging threats, regulatory requirements, and changes in technology. As cybersecurity threats evolve, we may need to further enhance our processes and technologies, which could require additional financial resources.

**ITEM 3. LEGAL PROCEEDINGS**

At times, we may be involved in litigation relating to claims arising out of our business and operations in the normal course of business. As of the filing of this report, no legal proceedings are pending against us that we believe individually or collectively are likely to have a material adverse effect upon our financial condition, results of operations, or cash flows.

With respect to administrative or judicial proceedings involving the environment, we have determined that we will disclose any such proceeding if we reasonably believe such proceeding will result in monetary sanctions, exclusive of interest and costs, of $1 million or more.

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**ITEM 4. MINE SAFETY DISCLOSURES**

The required disclosure under Section 1503(a) of the Dodd-Frank Wall Street Reform and Consumer Protection Act and Item 104 of Regulation S-K is included in Exhibit 95.1 to this report.

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**PART II**

**ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS, AND ISSUER PURCHASES OF EQUITY SECURITIES**

Our common stock is currently traded on the New York Stock Exchange under the ticker symbol "SM." For dividend information, refer to the caption *Uses of Cash* in *Overview of Liquidity and Capital Resources* in Part II, Item 7 of this report. Information regarding our Equity Plans, and the securities authorized under the Equity Plans is included below. Refer to *Note 10 – Stock-Based Compensation* in Part II, Item 8 of this report for discussion and definitions of the Equity Plans.

**PERFORMANCE GRAPH**

The following performance graph compares the cumulative return on our common stock, for the period beginning December 31, 2020, and ending December 31, 2025, with the cumulative total returns of the Dow Jones Exploration and Production Index ("DJUSOS"), and the Standard & Poor's 500 Stock Index ("SPX").

**COMPARISON OF 5-YEAR CUMULATIVE TOTAL RETURNS**

![852](sm-20251231_g1.jpg)

The preceding information under the caption *Performance Graph* shall be deemed to be furnished, but not filed with the SEC.

*Holders.* As of February 2, 2026, the number of record holders of our common stock was 219. A substantially greater number of holders of our common stock are beneficial holders, whose shares of record are held by banks, brokers, and other financial institutions.

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*Purchases of Equity Securities by Issuer and Affiliated Purchasers.* The following table provides information about purchases made by us and any affiliated purchaser (as defined in Rule 10b-18(a)(3) under the Exchange Act) during the indicated quarters and months, and the year ended December 31, 2025, of shares of our common stock, which is the sole class of equity securities registered by us pursuant to Section 12 of the Exchange Act:

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| | | | | |
|:---|:---|:---|:---|:---|
| **PURCHASES OF EQUITY SECURITIES BY ISSUER AND AFFILIATED PURCHASERS** | **PURCHASES OF EQUITY SECURITIES BY ISSUER AND AFFILIATED PURCHASERS** | **PURCHASES OF EQUITY SECURITIES BY ISSUER AND AFFILIATED PURCHASERS** | **PURCHASES OF EQUITY SECURITIES BY ISSUER AND AFFILIATED PURCHASERS** | **PURCHASES OF EQUITY SECURITIES BY ISSUER AND AFFILIATED PURCHASERS** |
| **Period** | **Total Number of** <br>**Shares**<br> **Purchased** | **Weighted** <br>**Average Price** <br>**Paid per Share** | **Total Number of Shares Purchased as Part of Publicly Announced Program** <sup>(1)</sup> | **Approximate Dollar Value of Shares that May Yet Be Purchased Under the Program (as of the period end date)** <sup>(1)</sup> |
| 10/01/2025 - 10/31/2025 |  | $— |  | $487881090 |
| 11/01/2025 - 11/30/2025 |  | $— |  | $487881090 |
| 12/01/2025 - 12/31/2025 |  | $— |  | $487881090 |
| Total |  | $— |  |  |

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<sup>(1)&nbsp;&nbsp;&nbsp;&nbsp;</sup>Our Stock Repurchase Program, approved by the Board of Directors in September 2022 and reauthorized by the Board of Directors in June 2024, authorizes us to repurchase up to $500 million in aggregate value of our common stock through December 31, 2027 ("Stock Repurchase Program"), and permits us to repurchase our shares from time to time in open market transactions, through privately negotiated transactions or by other means in accordance with federal securities laws and subject to certain provisions of our Credit Agreement and the indentures governing our Senior Notes. The timing, as well as the number and value of shares repurchased under the Stock Repurchase Program, is determined by certain authorized officers of the Company at their discretion and depends on a variety of factors, including the market price of our common stock, general market and economic conditions and applicable legal requirements. The value of shares authorized for repurchase by our Board of Directors does not require us to repurchase such shares or guarantee that such shares will be repurchased, and the Stock Repurchase Program may be suspended, modified, or discontinued at any time without prior notice. No assurance can be given that any particular number or dollar value of our shares will be repurchased.

Our payment of cash dividends to our stockholders and repurchases of our common stock are each subject to certain covenants under the terms of our Credit Agreement and Senior Notes. Based on our current performance, we do not anticipate that any of these covenants will limit our potential repurchases of our common stock or our payment of dividends at our current rate for the foreseeable future if any dividends are declared by our Board of Directors.

During the year ended December 31, 2025, we paid $92 million in dividends to our stockholders reflecting $0.80 paid per share. We currently intend to continue paying dividends to our stockholders for the foreseeable future, subject to our future earnings, our financial condition, covenants under our Credit Agreement and indentures governing each series of our outstanding Senior Notes, and other factors that could arise. The payment and amount of future dividends remain at the discretion of our Board of Directors.

**ITEM 6. [RESERVED]**

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**ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS**

The following discussion includes forward-looking statements. Refer to the *Cautionary Information about Forward-Looking Statements* section of this report for important information about these types of statements. For discussion related to changes in financial condition and results of operations for the year ended December 31, 2024, compared with the year ended December 31, 2023, refer to "*Management's Discussion and Analysis of Financial Condition and Results of Operations*" in Part II, Item 7 of our Annual Report on Form 10-K for the year ended December 31, 2024, filed with the SEC on February 20, 2025.

**Overview of the Company**

*Merger with Civitas*

On November 2, 2025, we entered into the Merger Agreement with Civitas. On January 27, 2026, our stockholders voted in favor of both proposals necessary to complete the Civitas Merger, which included approval of (i) the issuance of shares of SM Energy common stock to Civitas stockholders as contemplated by the Merger Agreement, and (ii) an amendment of our Restated Certificate of Incorporation to increase the number of authorized shares of our common stock from 200 million shares to 400 million shares.

On January 30, 2026, we completed the Civitas Merger in accordance with the terms of the Merger Agreement. Civitas was an independent exploration and production company focused on the acquisition, development, and production of crude oil and associated liquids-rich natural gas in the DJ Basin in Colorado and the Permian Basin in Texas and New Mexico. We believe that the Merger will create a premier portfolio across the highest-return U.S. shale basins, driving significant free cash flow, enhancing stockholder value, and enabling the realization of significant operational and cost efficiencies.

Under the terms of the Merger Agreement, subject to certain exceptions, each share of Civitas common stock was converted into the right to receive 1.45 shares of SM Energy common stock, with cash paid in lieu of fractional shares. On January 30, 2026, we issued approximately 124 million shares to holders of Civitas common stock, representing 52 percent of the outstanding shares of SM Energy's common stock upon the closing of the Merger. Based on the closing price of SM Energy common stock on January 30, 2026, the total stock consideration was valued at $2.4 billion.

Refer to *Note 17 – Mergers, Acquisitions, and Divestitures* in Part II, Item 8 of this report for additional discussion.

*South Texas Asset Divestiture*

On February 17, 2026, we entered into the PSA with Caturus to sell certain of our South Texas assets for a Purchase Price of $950 million, subject to certain customary purchase price adjustments set forth in the PSA. This Transaction is expected to advance our deleveraging goals and position us to substantially achieve our commitment to complete at least $1.0 billion of divestitures within one year following the closing of the Civitas Merger. Refer to *Note 17 – Mergers, Acquisitions, and Divestitures* in Part II, Item 8 for additional discussion and the definitions of Purchase Price and Transaction.

*General Overview*

Our purpose is to make people's lives better by responsibly producing energy supplies, contributing to domestic energy security and prosperity, and having a positive impact in the communities where we live and work. We are a premier operator of top-tier assets in the Midland Basin, South Texas, and the Uinta Basin, utilizing state-of-the-art digital technology, data analytics, and AI in our operations, and continually seeking innovative ideas to help us optimize capital efficiency and well performance, while reducing our impact on shared natural resources and operating in an efficient, safe, and responsible manner.

Following the closing of the Civitas Merger, our asset portfolio consists of high-quality assets in the Midland Basin and Delaware Basin, both of which are part of the larger Permian Basin of Texas and New Mexico, the Maverick Basin of South Texas, the Uinta Basin of northeast Utah, and the DJ Basin of northeast Colorado. We believe our assets are capable of generating strong returns in the current macroeconomic environment and provide resilience to commodity price risk and volatility. Through disciplined capital spending, strategic acquisitions and divestitures, and continued development and optimization, we seek to maximize returns and increase the value of our top-tier asset base while maintaining financial flexibility and a sustainable approach to long-term value creation.

Our long-term vision and strategy are focused on sustainably growing value for all of our stakeholders by deploying our technical excellence and exceptional execution to improve and optimize our high-quality asset portfolio, generate cash flows, and maintain a disciplined, strong balance sheet. Our team executes our strategy by prioritizing safety, technological innovation, and stewardship of natural resources, which are foundational to our corporate culture. Our near-term strategic focus is the successful integration of Civitas following the closing of the Merger on January 30, 2026. Integration is centered on maintaining safe operations, delivering consistent operational execution, and continuing to generate cash flows that enable us to return value to stockholders through fixed dividend payments, debt reduction, and share repurchases. Refer to *Outlook* for discussion of our 2026 capital program.

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We are committed to exceptional safety, health, and environmental stewardship; supporting the professional development of a diverse and thriving team of employees; building and maintaining partnerships with our stakeholders by investing in and connecting with the communities where we live and work; and transparency in reporting our progress in these areas. The Governance and Sustainability Committee of our Board of Directors oversees, among other things, the effectiveness of our sustainability policies, programs and initiatives, monitors and responds to emerging trends, issues, and associated risks, and, together with management, reports to our Board of Directors regarding such matters. Further demonstrating our commitment to sustainable operations and environmental stewardship, compensation for our executives and employees under certain aspects of our compensation plans is calculated based on Company-wide performance metrics that include key financial, operational, environmental, health, and safety measures. Refer to our Definitive Proxy Statement on Schedule 14A for the 2026 annual meeting of stockholders to be filed within 120 days from December 31, 2025, for additional discussion of our compensation program.

*Market Trends and Uncertainties*

As global commodities, the prices of oil, gas, and NGLs, as well as broader financial markets, remain subject to heightened uncertainty and volatility. Market conditions are influenced by factors including real or perceived geopolitical risks, War and Geopolitical Instability, OPEC+ production decisions, fluctuations in global supply and demand (including demand from China), U.S. Federal Reserve monetary policy, movements in the strength of the U.S. dollar, shipping channel constraints and disruptions, tariffs or trade restrictions, and changes in global oil inventory in storage. These factors have resulted in commodity price volatility, contributed to instances of supply chain disruptions, inflation, and interest rate fluctuations, and could have further industry-specific impacts that may require us to adjust our business plan. The timing and magnitude of future effects are inherently unpredictable.

Historically, tariffs have led to increased costs for products exchanged in international trade, and have heightened global political tensions. Recent U.S. government policies, including new and higher tariffs on imported goods, have increased economic uncertainty. These tariffs, along with retaliatory tariffs from other countries, could lead to reduced trade resulting from increased costs for imported goods and decreased demand for U.S. exports, as well as reduced investment and technological exchange between major economies. These outcomes could negatively impact global economic conditions, financial market stability, and commodity prices. Volatility in political, trade, regulatory, and economic conditions could have a material adverse effect on our financial condition or results of operations. We are unable to reasonably estimate the period of time that these market conditions will exist or the extent to which they will impact our business, results of operations, and financial condition.

Continuing volatility in political, trade, regulatory and economic conditions could impact supply and demand fundamentals, and any related declines in oil, gas, and NGL prices could lead to proved and unproved property impairments in the future. Future impairments of proved and unproved properties are difficult to predict, especially in a volatile price environment.

*Outlook*

We expect our total 2026 capital program to be approximately $2.65 billion to $2.85 billion, excluding acquisitions, which we expect to fund with cash flows from operations, with any remaining cash needs being funded by borrowings under our revolving credit facility. We plan to focus our 2026 capital program on highly economic oil development projects in our Midland Basin, South Texas, Uinta Basin, and DJ Basin assets. Refer to *Outlook* in Part I, Items 1 and 2 of this report for additional discussion.

*2025 Financial and Operational Highlights*

During 2025:

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• We completed the integration of the Uinta Basin assets into our portfolio. Refer to *Note 17 – Mergers, Acquisitions, and Divestitures* in Part II, Item 8 of this report for additional discussion of the Uinta Basin Acquisition.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• Net equivalent production of 75.5 MMBOE drove net income of $648 million, net cash provided by operating activities of $2.0 billion, and Adjusted EBITDAX, a non-GAAP financial measure, of $2.3 billion. Refer to *Non-GAAP Financial Measures* below for additional discussion, including our definition of adjusted EBITDAX and reconciliations to net income and net cash provided by operating activities.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• Strong operating cash flow enabled us to reduce debt through $69 million in net repayments on our revolving credit facility, increase cash on hand to $368 million, and return capital to stockholders. We repurchased and subsequently retired 444,705 shares of our common stock at a cost of $12 million, excluding excise taxes, commissions, and fees, and paid $92 million in dividends.

*Financial and Operational Results.* Oil, gas, and NGL production revenue increased 17 percent to $3.1 billion for the year ended December 31, 2025, compared with $2.7 billion for 2024. This increase was primarily driven by a 21 percent increase in average net daily equivalent production to 206.8 MBOE, reflecting a full year of production from our Uinta Basin assets and continued strong well performance, partially offset by a three percent decrease in total realized price per BOE due to lower oil and NGL benchmark commodity prices. Oil, gas, and NGL production expense on a per BOE basis increased 15 percent to $11.72 per BOE for the year ended December 31, 2025, compared with 2024.

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We recorded net derivative gains of $178 million and $50 million for the years ended December 31, 2025, and 2024, respectively. These amounts include net derivative settlement gains of $132 million and $69 million for the years ended December 31, 2025, and 2024, respectively.

Operational activities during the year ended December 31, 2025, resulted in the following:

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• Net cash provided by operating activities of $2.0 billion, compared with $1.8 billion for 2024.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• Net income of $648 million, or $5.64 per diluted share, compared with net income of $770 million, or $6.67 per diluted share for 2024.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• Adjusted EBITDAX, a non-GAAP financial measure, of $2.3 billion, compared with $2.0 billion for 2024. Refer to *Non-GAAP Financial Measures* below for additional discussion, including our definition of adjusted EBITDAX and reconciliations to net income and net cash provided by operating activities.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• Estimated net proved reserves decreased slightly to 673.0 MMBOE as of December 31, 2025 from 678.3 MMBOE as of December 31, 2024. As of December 31, 2025, 60 percent of our net proved reserves were liquids (oil and NGLs), and 61 percent were proved developed reserves. The decrease primarily related to 75.5 MMBOE produced in 2025, the removal of 40.7 MMBOE of certain net proved undeveloped reserves that are no longer expected to be developed within the five-year period from initial booking resulting from testing and delineation efforts, and 15.5 MMBOE of net performance and price revisions. The decreases were mostly offset by revisions of previous estimates of 87.0 MMBOE related to infill reserves, primarily related to our South Texas assets, and additions from extensions and discoveries of 39.7 MMBOE, primarily related to our Uinta Basin assets. Our proved reserve life index decreased to 8.9 years as of December 31, 2025, compared with 10.9 years as of December 31, 2024. Refer to *Reserves* in Part I, Items 1 and 2 of this report for additional discussion. The standardized measure of discounted future net cash flows was $6.0 billion as of December 31, 2025, compared with $7.3 billion as of December 31, 2024. The year-over-year decrease of 18 percent was primarily due to decreases in oil and NGL benchmark commodity prices during 2025. Refer to *Supplemental Oil and Gas Information (unaudited)* in Part II, Item 8 of this report for additional discussion.

*Operational Activities.* During 2025, successful operational execution drove strong well performance and capital efficiency across our asset portfolio. Our continued success in our Midland Basin, South Texas, and Uinta Basin programs is attributable to our top-tier assets and technical teams, and our commitment to geoscience, technology, and innovation.

In our Midland Basin program, we averaged three drilling rigs and one completion crew during 2025. Average net daily equivalent production volumes increased year-over-year by three percent to 82.8 MBOE. Costs incurred during 2025 totaled $548 million, or 38 percent, of our total 2025 costs incurred. Drilling and completion activities focused on developing formations within our RockStar and Sweetie Peck assets.

In our South Texas program, we averaged one drilling rig and one completion crew during 2025. Average net daily equivalent production volumes decreased year-over-year by one percent to 80.3 MBOE. Costs incurred during 2025 totaled $361 million, or 25 percent, of our total 2025 costs incurred. Drilling and completion activities were primarily focused on delineating and developing the Austin Chalk formation.

In our Uinta Basin program, we averaged three drilling rigs and one completion crew during 2025. Average net daily equivalent production volumes increased to 43.7 MBOE for the full year 2025, compared to 36.1 MBOE for the fourth quarter of 2024. Costs incurred during 2025 totaled $481 million, or 33 percent, of our total 2025 costs incurred. Drilling and completion activities primarily focused on delineating and developing the Lower Green River and Wasatch formations.

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The table below provides a summary of changes in our drilled but not completed well count and current year drilling, completion, and acquisition activity in our operated programs for the year ended December 31, 2025:

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| | | | | | | | | |
|:---|:---|:---|:---|:---|:---|:---|:---|:---|
| | **Midland Basin** | **Midland Basin** | **South Texas** <sup>(1)</sup> | **South Texas** <sup>(1)</sup> | **Uinta Basin** | **Uinta Basin** | **Total** | **Total** |
| | **Gross** | **Net** | **Gross** | **Net** | **Gross** | **Net** | **Gross** | **Net** |
| Wells drilled but not completed at December 31, 2024 | 40 | 29 | 35 | 35 | 48 | 38 | 123 | 102 |
| &nbsp;&nbsp;&nbsp;&nbsp;Wells drilled | 47 | 37 | 30 | 29 | 52 | 38 | 129 | 104 |
| &nbsp;&nbsp;&nbsp;&nbsp;Wells completed | (72) | (53) | (33) | (33) | (62) | (49) | (167) | (135) |
| &nbsp;&nbsp;&nbsp;&nbsp;Other <sup>(2) (3)</sup> |  |  | (7) | (7) |  | 1 | (7) | (6) |
| Wells drilled but not completed at December 31, 2025 | 15 | 12 | 25 | 24 | 38 | 28 | 78 | 64 |

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Note: Amounts may not calculate due to rounding.

<sup>(1)</sup> &nbsp;&nbsp;&nbsp;&nbsp;As of December 31, 2024, the drilled but not completed well count included nine gross (nine net) wells that were not included in our five-year development plan, eight of which were in the Eagle Ford shale. As of December 31, 2025, the drilled but not completed well count included two gross (two net) wells that were not included in our five year development plan, each of which are in the Eagle Ford shale.

<sup>(2)</sup> &nbsp;&nbsp;&nbsp;&nbsp;The South Texas adjustments relate to previously drilled wells that we no longer intend to complete.

<sup>(3)</sup> &nbsp;&nbsp;&nbsp;&nbsp;The Uinta Basin adjustment relates to the acquisition of additional working interest in existing drilled but not completed wells.

*Costs Incurred.* Costs incurred in oil and gas property acquisition, exploration, and development activities, whether capitalized or expensed, are summarized as follows:

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| | |
|:---|:---|
| | **For the Year Ended**<br>**December 31, 2025** |
| | **(in millions)** |
| Development costs | $1333 |
| Exploration costs | 94 |
| Acquisitions |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Proved properties | (5) |
| &nbsp;&nbsp;&nbsp;&nbsp;Unproved properties | 26 |
| Total, including asset retirement obligations <sup>(1)</sup> | $1448 |

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<sup>(1)</sup> &nbsp;&nbsp;&nbsp;&nbsp;Refer to the caption *Costs Incurred* in *Supplemental Oil and Gas Information (unaudited)* in Part II, Item 8 of this report.

*Production Results.* The table below presents the disaggregation of our net production volumes by product type for each of our assets for the year ended December 31, 2025:

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| | | | | |
|:---|:---|:---|:---|:---|
| | **Midland Basin** | **South Texas** | **Uinta Basin** | **Total** |
| Net production volumes: |  |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Oil (MMBbl) | 19.2 | 7.3 | 13.9 | 40.3 |
| &nbsp;&nbsp;&nbsp;&nbsp;Gas (Bcf) | 66.3 | 71.7 | 12.5 | 150.5 |
| &nbsp;&nbsp;&nbsp;&nbsp;NGLs (MMBbl) |  | 10.1 |  | 10.1 |
| &nbsp;&nbsp;&nbsp;&nbsp;Equivalent (MMBOE) | 30.2 | 29.3 | 15.9 | 75.5 |
| Average net daily equivalent (MBOE per day) | 82.8 | 80.3 | 43.7 | 206.8 |
| Relative percentage | 40% | 39% | 21% | 100% |

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Note: Amounts may not calculate due to rounding.

Net equivalent production increased 21 percent for the year ended December 31, 2025, compared with 2024. The increase was a result of a three percent increase from our Midland Basin assets, a full year of production from our Uinta Basin assets, and continued strong well performance. Refer to *Overview of Selected Production and Financial Information, Including Trends* and *Comparison of Financial Results and Trends Between 2025 and 2024* below for additional discussion of production.

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*Oil, Gas, and NGL Prices*

Our financial condition and the results of our operations are significantly affected by the prices we receive for our oil, gas, and NGL production, which can fluctuate dramatically. When we refer to realized oil, gas, and NGL prices below, the disclosed price represents the average price for the respective period, before the effect of net derivative settlements. While quoted NYMEX oil and gas and OPIS NGL prices are generally used as a basis for comparison within our industry, the prices we receive are affected by quality, energy content, location and transportation differentials, and contracted pricing benchmarks for these products.

The following table summarizes commodity price data, as well as the effect of net derivative settlements, for the years ended December 31, 2025, and 2024:

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| | | |
|:---|:---|:---|
| | **For the Years Ended December 31,** | **For the Years Ended December 31,** |
| | **2025** | **2024** |
| Oil (per Bbl): |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Average NYMEX contract monthly price | $64.81 | $75.72 |
| &nbsp;&nbsp;&nbsp;&nbsp;Realized price <sup>(1)</sup> | $63.52 | $74.49 |
| &nbsp;&nbsp;&nbsp;&nbsp;Effect of oil net derivative settlements | $1.66 | $0.43 |
| Gas: |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Average NYMEX monthly settle price (per MMBtu) | $3.43 | $2.27 |
| &nbsp;&nbsp;&nbsp;&nbsp;Realized price (per Mcf) <sup>(1)</sup> | $2.35 | $1.82 |
| &nbsp;&nbsp;&nbsp;&nbsp;Effect of gas net derivative settlements (per Mcf) | $0.44 | $0.43 |
| NGLs (per Bbl): |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Average OPIS price <sup>(2)</sup> | $27.19 | $28.30 |
| &nbsp;&nbsp;&nbsp;&nbsp;Realized price <sup>(1)</sup> | $22.22 | $23.01 |
| &nbsp;&nbsp;&nbsp;&nbsp;Effect of NGL net derivative settlements | $(0.21) | $(0.25) |

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<sup>(1)&nbsp;&nbsp;&nbsp;&nbsp;</sup>Our realized prices at local sales points may be affected by infrastructure capacity in the areas of our operations and beyond.

<sup>(2)&nbsp;&nbsp;&nbsp;&nbsp;</sup>Average OPIS price per barrel of NGL, historical or strip, assumes a composite barrel product mix of 42% Ethane, 28% Propane, 6% Isobutane, 11% Normal Butane, and 13% Natural Gasoline. This product mix represents the industry standard composite barrel and does not necessarily represent our product mix for NGL production. Realized prices reflect our actual product mix.

The following table summarizes 12-month strip prices for NYMEX WTI oil, NYMEX Henry Hub gas, and OPIS NGLs as of February 2, 2026, and December 31, 2025:

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| | | |
|:---|:---|:---|
| | **As of February 2, 2026** | **As of December 31, 2025** |
| NYMEX WTI oil (per Bbl) | $60.38 | $57.08 |
| NYMEX Henry Hub gas (per MMBtu) | $3.76 | $3.72 |
| OPIS NGLs (per Bbl) | $24.77 | $23.46 |

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We use financial derivative instruments as part of our financial risk management program. We have a financial risk management policy governing our use of derivatives, and decisions regarding entering into commodity derivative contracts are overseen by a financial risk management committee consisting of certain senior executive officers and finance personnel. We make decisions about the amount of our expected production that we cover by derivatives based on the amount of debt on our balance sheet, the level of capital commitments and long-term obligations we have in place, and the terms and futures prices that are made available by our approved counterparties. With our current commodity derivative contracts, we believe we have partially reduced our exposure to volatility in commodity prices and basis differentials in the near term. Our use of costless collars for a portion of our derivatives allows us to participate in some of the upward movements in oil and gas prices while also setting a price floor below which we are insulated from further price decreases. Refer to *Note 7 – Derivative Financial Instruments* in Part II, Item 8 of this report and to *Commodity Price Risk* in *Overview of Liquidity and Capital Resources* below for additional information regarding our oil, gas, and NGL derivatives.

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**Financial Results of Operations and Additional Comparative Data**

The tables below provide information regarding selected production and financial information for the three months ended December 31, 2025, and the preceding three quarters:

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| | | | | |
|:---|:---|:---|:---|:---|
| | **For the Three Months Ended** | **For the Three Months Ended** | **For the Three Months Ended** | **For the Three Months Ended** |
| | **December 31,**<br>**2025** | **September 30,**<br>**2025** | **June 30,**<br>**2025** | **March 31,**<br>**2025** |
| | **(in millions)** | **(in millions)** | **(in millions)** | **(in millions)** |
| Production (MMBOE) | 19.0 | 19.7 | 19.0 | 17.8 |
| Oil, gas, and NGL production revenue | $703 | $811 | $785 | $840 |
| Oil, gas, and NGL production expense | $207 | $229 | $224 | $225 |
| Depletion, depreciation, and amortization | $319 | $325 | $293 | $270 |
| Exploration | $18 | $12 | $15 | $12 |
| General and administrative | $40 | $39 | $42 | $39 |
| Net income | $109 | $155 | $202 | $182 |

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Note: Amounts may not calculate due to rounding.

*Selected Performance Metrics*

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| | | | | |
|:---|:---|:---|:---|:---|
| | **For the Three Months Ended** | **For the Three Months Ended** | **For the Three Months Ended** | **For the Three Months Ended** |
| | **December 31,**<br>**2025** | **September 30,**<br>**2025** | **June 30,**<br>**2025** | **March 31,**<br>**2025** |
| Average net daily equivalent production (MBOE per day) | 206.9 | 213.8 | 209.1 | 197.3 |
| Lease operating expense (per BOE) | $5.55 | $5.67 | $5.52 | $6.13 |
| Transportation costs (per BOE) | $3.67 | $3.77 | $4.13 | $3.92 |
| Production taxes as a percent of oil, gas, and NGL production revenue | 3.8% | 4.1% | 3.9% | 4.4% |
| Ad valorem tax expense (per BOE) | $0.23 | $0.51 | $0.54 | $0.55 |
| Depletion, depreciation, and amortization (per BOE) | $16.73 | $16.54 | $15.40 | $15.20 |
| General and administrative (per BOE) | $2.10 | $2.00 | $2.21 | $2.22 |

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____________________________________________

Note: Amounts may not calculate due to rounding.

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*Overview of Selected Production and Financial Information, Including Trends*

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| | | | | |
|:---|:---|:---|:---|:---|
| | **For the Years Ended<br>December 31,** | **For the Years Ended<br>December 31,** | **Amount Change Between Periods** | **Percent Change Between Periods** |
| | **2025** | **2024** | **Amount Change Between Periods** | **Percent Change Between Periods** |
| Net production volumes: <sup>(1)</sup> |  |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Oil (MMBbl) | 40.3 | 29.4 | 11.0 | 37% |
| &nbsp;&nbsp;&nbsp;&nbsp;Gas (Bcf) | 150.5 | 137.0 | 13.5 | 10% |
| &nbsp;&nbsp;&nbsp;&nbsp;NGLs (MMBbl) | 10.1 | 10.2 | (0.1) | (1)% |
| &nbsp;&nbsp;&nbsp;&nbsp;Equivalent (MMBOE) | 75.5 | 62.4 | 13.1 | 21% |
| Average net daily production: <sup>(1)</sup> |  |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Oil (MBbl per day) | 110.5 | 80.2 | 30.2 | 38% |
| &nbsp;&nbsp;&nbsp;&nbsp;Gas (MMcf per day) | 412.3 | 374.3 | 38.1 | 10% |
| &nbsp;&nbsp;&nbsp;&nbsp;NGLs (MBbl per day) | 27.6 | 27.9 | (0.3) | (1)% |
| &nbsp;&nbsp;&nbsp;&nbsp;Equivalent (MBOE per day) | 206.8 | 170.5 | 36.3 | 21% |
| Oil, gas, and NGL production revenue (in millions): <sup>(1)</sup> | Oil, gas, and NGL production revenue (in millions): <sup>(1)</sup> | Oil, gas, and NGL production revenue (in millions): <sup>(1)</sup> |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Oil production revenue | $2561 | $2187 | $374 | 17% |
| &nbsp;&nbsp;&nbsp;&nbsp;Gas production revenue | 353 | 249 | 104 | 42% |
| &nbsp;&nbsp;&nbsp;&nbsp;NGL production revenue | 224 | 235 | (11) | (5)% |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Total oil, gas, and NGL production revenue | $3138 | $2671 | $467 | 17% |
| Oil, gas, and NGL production expense (in millions): <sup>(1)</sup> | Oil, gas, and NGL production expense (in millions): <sup>(1)</sup> | Oil, gas, and NGL production expense (in millions): <sup>(1)</sup> |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Lease operating expense | $431 | $319 | $112 | 35% |
| &nbsp;&nbsp;&nbsp;&nbsp;Transportation costs | 292 | 167 | 125 | 75% |
| &nbsp;&nbsp;&nbsp;&nbsp;Production taxes | 127 | 116 | 11 | 10% |
| &nbsp;&nbsp;&nbsp;&nbsp;Ad valorem tax expense | 35 | 35 |  | (1)% |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Total oil, gas, and NGL production expense | $885 | $637 | $248 | 39% |
| Realized price: | Realized price: | Realized price: |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Oil (per Bbl) | $63.52 | $74.49 | $(10.97) | (15)% |
| &nbsp;&nbsp;&nbsp;&nbsp;Gas (per Mcf) | $2.35 | $1.82 | $0.53 | 29% |
| &nbsp;&nbsp;&nbsp;&nbsp;NGLs (per Bbl) | $22.22 | $23.01 | $(0.79) | (3)% |
| &nbsp;&nbsp;&nbsp;&nbsp;Per BOE | $41.58 | $42.81 | $(1.23) | (3)% |
| Per BOE data: <sup>(1)</sup> |  |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Oil, gas, and NGL production expense: | &nbsp;&nbsp;&nbsp;&nbsp;Oil, gas, and NGL production expense: |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Lease operating expense | $5.71 | $5.11 | $0.60 | 12% |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Transportation costs | 3.87 | 2.68 | 1.19 | 44% |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Production taxes | 1.69 | 1.86 | (0.17) | (9)% |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Ad valorem tax expense | 0.46 | 0.56 | (0.10) | (18)% |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Total oil, gas, and NGL production expense <sup>(1)</sup> | $11.72 | $10.21 | $1.51 | 15% |
| &nbsp;&nbsp;&nbsp;&nbsp;Depletion, depreciation, and amortization | $15.99 | $12.97 | $3.02 | 23% |
| &nbsp;&nbsp;&nbsp;&nbsp;General and administrative | $2.13 | $2.22 | $(0.09) | (4)% |
| &nbsp;&nbsp;&nbsp;&nbsp;Net derivative settlement gain <sup>(2)</sup> | $1.75 | $1.10 | $0.65 | 59% |
| Earnings per share information (in millions, except per share data): <sup>(3)</sup> | Earnings per share information (in millions, except per share data): <sup>(3)</sup> | Earnings per share information (in millions, except per share data): <sup>(3)</sup> | Earnings per share information (in millions, except per share data): <sup>(3)</sup> | Earnings per share information (in millions, except per share data): <sup>(3)</sup> |
| &nbsp;&nbsp;&nbsp;&nbsp;Basic weighted-average common shares outstanding | 115 | 115 |  | —% |
| &nbsp;&nbsp;&nbsp;&nbsp;Diluted weighted-average common shares outstanding | 115 | 116 | (1) | (1)% |
| &nbsp;&nbsp;&nbsp;&nbsp;Basic net income per common share | $5.65 | $6.71 | $(1.06) | (16)% |
| &nbsp;&nbsp;&nbsp;&nbsp;Diluted net income per common share | $5.64 | $6.67 | $(1.03) | (15)% |

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____________________________________________

<sup>(1)</sup> &nbsp;&nbsp;&nbsp;&nbsp;Amounts and percentage changes may not calculate due to rounding.

<sup>(2)&nbsp;&nbsp;&nbsp;&nbsp;</sup>Net derivative settlements for the years ended December 31, 2025, and 2024, are included within the net derivative gain line item in the accompanying consolidated statements of operations ("accompanying statements of operations").

<sup>(3)</sup> &nbsp;&nbsp;&nbsp;&nbsp;Refer to *Note 9 – Earnings Per Share* in Part II, Item 8 of this report for additional discussion.

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The Civitas Merger, which closed on January 30, 2026, is expected to materially affect our future operating and financial results. The addition of Civitas' assets and operations is expected to increase production volumes and revenues and to impact oil, gas, and NGL production expense, general and administrative expense, and other expense categories. The magnitude and timing of these impacts will depend, in part, on integration activities, operating performance, commodity prices, and other factors and may not be directly comparable to the Company's historical results. Unless otherwise noted, the discussion below reflects the results of our legacy operations and historical trends prior to the Merger.

Average net daily equivalent production for the year ended December 31, 2025, increased 21 percent compared with 2024, resulting from a full year of production from our Uinta Basin assets, and continued strong well performance. Oil production as a percentage of total production increased to 53 percent in 2025 from 47 percent in 2024, resulting from a full year of oil production from our Uinta Basin assets, which averaged 87 percent oil production in 2025. In 2026, we expect an increase in total production volumes due to the integration of assets from the Civitas Merger. Refer to *Comparison of Financial Results and Trends Between 2025 and 2024* below for additional discussion.

We present certain information on a per BOE basis in order to evaluate our performance relative to our peers and to identify and measure trends we believe may require additional analysis and discussion.

Our realized price on a per BOE basis decreased three percent for the year ended December 31, 2025, compared with 2024, primarily because of decreases in oil benchmark commodity prices partially offset by the increase in gas benchmark commodity prices. For the years ended December 31, 2025, and 2024, we recognized net gains on the settlement of our commodity derivative contracts of $1.75 per BOE and $1.10 per BOE, respectively.

LOE on a per BOE basis increased 12 percent for the year ended December 31, 2025, compared with 2024, driven by the increased percentage of oil in our total production mix, which has higher lifting costs per BOE, and increases in certain operating costs. We anticipate volatility in LOE on a per BOE basis resulting from changes in production, timing of workover projects, changes in service provider costs, and industry activity, all of which affect total LOE.

Transportation costs on a per BOE basis increased 44 percent for the year ended December 31, 2025, compared with 2024. This increase was primarily due to 15.9 MMBOE of full year production from our Uinta Basin assets, which incur higher transportation costs on a per BOE basis compared to our Midland Basin and South Texas assets. In general, we expect total transportation costs to fluctuate relative to changes in oil production from our Uinta Basin assets and gas and NGL production from our South Texas assets, where we incur a majority of our transportation costs. For 2026, we expect transportation costs on a per BOE basis to remain relatively flat compared with 2025.

Production tax expense on a per BOE basis for the year ended December 31, 2025, decreased nine percent compared with 2024, primarily resulting from a decrease in the realized price of oil, and full year operations for our Uinta Basin assets which incur a lower production tax rate compared to our Midland Basin and South Texas assets. Our overall production tax rate was 4.1 percent and 4.3 percent for the years ended December 31, 2025, and 2024, respectively. We generally expect production tax expense to correlate with oil, gas, and NGL production revenue on a per BOE and absolute basis. Product mix, the location of production, and incentives to encourage oil and gas development can also impact the amount of production tax expense that we recognize.

Ad valorem tax expense on a per BOE basis decreased 18 percent for the year ended December 31, 2025, compared with 2024, primarily due to increased net equivalent production and changes to the assessed values of our producing properties. We anticipate volatility in ad valorem tax expense on a per BOE and absolute basis as the valuation of our producing properties changes.

Depletion, depreciation, and amortization ("DD&A") expense on a per BOE basis increased 23 percent for the year ended December 31, 2025, compared with 2024, due to increased production from our Uinta Basin assets, which caused a shift in the production mix towards our higher rate Midland Basin and Uinta Basin assets. For 2026, we expect DD&A expense on an absolute basis to increase compared with 2025, primarily reflecting anticipated higher production volumes and our expanded asset base. Our DD&A expense on a per BOE and absolute basis may fluctuate as a result of changes in our production mix, changes in our total estimated proved reserve volumes, changes in capital allocation, impairments, acquisition and divestiture activity, and carrying cost funding and sharing arrangements with third parties.

General and administrative ("G&A") expense on a per BOE basis decreased four percent for the year ended December 31, 2025, compared with 2024, primarily driven by a higher rate of production growth relative to increases in G&A expense on an absolute basis. For 2026, we expect G&A expense on an absolute basis and on a per BOE basis to increase compared with 2025, primarily due to an increase in employee headcount as a result of the Civitas Merger, and expected increases in compensation expense and integration costs. Certain components of G&A expense, and G&A expense on a per BOE basis, are impacted by the Company's full year performance against performance targets established at the beginning of the year and, therefore, are subject to variability.

Refer to *Comparison of Financial Results and Trends Between 2025 and 2024* for additional discussion of operating expenses.

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**Comparison of Financial Results and Trends Between 2025 and 2024**

*Average net daily equivalent production, production revenue, and production expense*

The following table presents the changes in our average net daily equivalent production, oil, gas, and NGL production revenue, and oil, gas, and NGL production expense, by area, between the years ended December 31, 2025, and 2024:

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| | | | |
|:---|:---|:---|:---|
| | **Average Net Equivalent Production Increase (Decrease)** | **Oil, Gas, and NGL Production Revenue Increase (Decrease)** | **Oil, Gas, and NGL Production Expense Increase** |
| | **(MBOE per day)** | **(in millions)** | **(in millions)** |
| Midland Basin | 2.4 | $(194.8) | $9.2 |
| South Texas | (0.7) | (9.4) | 28.2 |
| Uinta Basin | 34.6 | 671.3 | 210.6 |
| Total | 36.3 | $467.1 | $247.9 |

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____________________________________________

Note: Amounts may not calculate due to rounding.

Average net daily equivalent production volumes for the year ended December 31, 2025, increased 21 percent compared with 2024, comprised of a three percent increase from our Midland Basin assets, and 43.7 MBOE of production from our Uinta Basin assets. As a result of decreases in benchmark oil and NGL prices, realized prices for oil and NGLs decreased 15 percent and three percent, respectively, while the realized price for gas increased 29 percent. Oil, gas, and NGL production revenue increased 17 percent, primarily resulting from a 21 percent increase in average net daily equivalent production volumes. Oil, gas, and NGL production expense for the year ended December 31, 2025, increased 39 percent compared with 2024, as activity related to our Uinta Basin assets contributed to increases in transportation costs, LOE, and production tax expense.

Refer to *Overview of Selected Production and Financial Information, Including Trends* above for additional discussion, including discussion of trends on a per BOE basis.

*Depletion, depreciation, and amortization*

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| | | |
|:---|:---|:---|
| | **For the Years Ended December 31,** | **For the Years Ended December 31,** |
| | **2025** | **2024** |
| | **(in millions)** | **(in millions)** |
| Depletion, depreciation, and amortization | $1207 | $809 |

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DD&A expense for the year ended December 31, 2025, increased 49 percent compared with 2024, primarily resulting from increased production from our Uinta Basin assets during 2025. Our Midland Basin and Uinta Basin assets have higher DD&A rates than our South Texas assets. Refer to *Overview of Selected Production and Financial Information, Including Trends* above for discussion of DD&A expense on a per BOE basis.

*Exploration*

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| | | |
|:---|:---|:---|
| | **For the Years Ended December 31,** | **For the Years Ended December 31,** |
| | **2025** | **2024** |
| | **(in millions)** | **(in millions)** |
| Geological, geophysical, and other expenses | $17 | $28 |
| Overhead | 40 | 36 |
| Total exploration | $57 | $64 |

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Exploration expense decreased 11 percent for the year ended December 31, 2025, compared with 2024, primarily resulting from a decrease in geological and geophysical and other expenses. Exploration expense fluctuates based on actual geological and geophysical studies we perform within an exploratory area, exploratory dry hole expense incurred, and changes in the amount of allocated overhead.

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*General and administrative*

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| | | |
|:---|:---|:---|
| | **For the Years Ended December 31,** | **For the Years Ended December 31,** |
| | **2025** | **2024** |
| | **(in millions)** | **(in millions)** |
| General and administrative | $161 | $138 |

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G&A expense increased 17 percent for the year ended December 31, 2025, compared with 2024, primarily due to increased compensation costs associated with additional headcount from the Uinta Basin Acquisition. Refer to *Overview of Selected Production and Financial Information, Including Trends* above for discussion of G&A expense, including G&A expense on a per BOE basis.

*Net derivative gain*

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| | | |
|:---|:---|:---|
| | **For the Years Ended December 31,** | **For the Years Ended December 31,** |
| | **2025** | **2024** |
| | **(in millions)** | **(in millions)** |
| Net derivative gain | $(178) | $(50) |

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Net derivative gain is a result of changes in fair values associated with fluctuations in the forward price curves for the commodities underlying our outstanding derivative contracts and the monthly cash settlements of our derivative positions during the period. We expect increases in benchmark commodity prices to result in net derivative losses, and decreases in benchmark commodity prices to result in net derivative gains, as measured against our derivative contract prices. Refer to *Note 7 – Derivative Financial Instruments* in Part II, Item 8 of this report for additional discussion.

*Interest expense*

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| | | |
|:---|:---|:---|
| | **For the Years Ended December 31,** | **For the Years Ended December 31,** |
| | **2025** | **2024** |
| | **(in millions)** | **(in millions)** |
| Interest expense | $(173) | $(141) |

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Interest expense increased 23 percent for the year ended December 31, 2025, compared with 2024, as a result of the issuance of our 2029 Senior Notes and 2032 Senior Notes during the third quarter of 2024 and an increase in interest expense associated with borrowings under our revolving credit facility. Total interest expense can vary based on the amount of our outstanding fixed-rate debt securities, fluctuations in the amount of capitalized interest resulting from the timing of the development of our wells in progress, and due to the timing and amount of borrowings under our revolving credit facility. Refer to *Overview of Liquidity and Capital Resources* below and to *Note 5 – Long-Term Debt* in Part II, Item 8 of this report for additional discussion and definitions.

*Income tax expense*

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| | | |
|:---|:---|:---|
| | **For the Years Ended December 31,** | **For the Years Ended December 31,** |
| | **2025** | **2024** |
| | **(in millions, except tax rate)** | **(in millions, except tax rate)** |
| Income tax expense | $(182) | $(196) |
| Effective tax rate | 22.0% | 20.3% |

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Our effective tax rate is impacted by changes in revenue affecting the apportionment of taxable income to states with higher statutory tax rates and proportional effects of net income on permanent items between periods and states. Our effective tax rate increased during 2025, primarily resulting from the impact of state income taxes and the decoupling of state income tax calculations from certain OBBBA provisions, partially offset by the Company's increasing research and development ("R&D") activities in new basins and additional credit claims. The increase also reflects the impact of excess tax deficiencies from stock-based compensation awards.

During 2025, we made estimated tax payments of $8 million and received a federal refund of $4 million during the fourth quarter of 2025.

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The effects of changes in tax laws are recognized in the period of enactment. On July 4, 2025, the OBBBA was enacted into law and includes, among other things, tax reform provisions that amend, eliminate, and extend tax rules under the Inflation Reduction Act and Tax Cuts and Jobs Act. During 2025, we recorded the impact of the OBBBA, which resulted in a decrease to our current portion of income tax expense. This change reflects the impacts of the reinstatement of 100 percent bonus depreciation on tangible assets; the immediate expensing of qualified R&D expenditures and the expensing of unamortized, previously capitalized, prior year qualified R&D expenditures; and a less restrictive limitation on the business interest expense deduction. Additionally, the OBBBA allows for the deduction of intangible drilling costs from Adjusted Financial Statement Income ("AFSI") when determining whether a company is subject to and liable for the Corporate Alternative Minimum Tax ("CAMT"). As a result, we do not expect to become subject to or liable for the CAMT for the foreseeable future, notwithstanding other factors that may impact our AFSI.

Refer to *Note 4 – Income Taxes* in Part II, Item 8 of this report for further discussion.

**Overview of Liquidity and Capital Resources**

Based on the current commodity price environment, we believe we have sufficient liquidity and capital resources to execute our business plan while continuing to meet our financial obligations, including near-term maturities of our outstanding Senior Notes. We continue to manage the duration and level of our drilling and completion service commitments in order to maintain flexibility with regard to our activity level and capital expenditures.

*Sources of Cash*

We expect to fund our 2026 capital expenditures and return of capital program with cash flows from operations, with any remaining cash needs being funded by borrowings under our revolving credit facility. Although we expect cash flows from these sources to be sufficient for 2026, we may also elect to raise funds through new debt or equity offerings or from other sources of financing. If we raise additional funds through the issuance of equity or convertible debt securities, the percentage ownership of our current stockholders could be diluted, and these newly issued securities may have rights, preferences, or privileges senior to those of existing stockholders and bondholders. Additionally, we may enter into carrying cost and sharing arrangements with third parties for certain exploration or development programs.

During 2024, we issued our 2029 Senior Notes and 2032 Senior Notes. See below for discussion on how the net proceeds received were used, and refer to *Note 5 – Long-Term Debt* in Part II, Item 8 of this report for additional discussion.

Our credit ratings affect the availability of, and cost for us to borrow, additional funds. Two major credit rating agencies upgraded our credit ratings following the close of the Civitas Merger on January 30, 2026, citing our increased size, scale and diversification, and enhanced and consistently positive free cash flow generation.

All of our sources of liquidity can be affected by the general conditions of the broader economy, force majeure events, fluctuations in commodity prices, operating costs, interest rate changes, tax law changes, and volumes produced, all of which affect us and our industry.

We have no control over the market prices for oil, gas, and NGLs, although we may be able to influence the amount of our realized revenues from our oil, gas, and NGL sales through the use of commodity derivative contracts as part of our financial risk management program. Commodity derivative contracts may limit the prices we receive for our oil, gas, and NGL sales if oil, gas, or NGL prices rise over the price established by the commodity derivative contract. Refer to *Note 7 – Derivative Financial Instruments* in Part II, Item 8 of this report for additional information about our commodity derivative contracts currently in place and the timing of settlement of those contracts*.*

*Credit Agreement*

Our Credit Agreement provides for a senior secured revolving credit facility with a maximum loan amount of $3.0 billion. As of December 31, 2025, the borrowing base and aggregate revolving lender commitments under our Credit Agreement were $3.0 billion and $2.0 billion, respectively. The borrowing base is subject to regular, semi-annual redetermination, and considers the value of both our proved oil and gas properties reflected in our most recent reserve report and commodity derivative contracts, each as determined by our lender group. The next borrowing base redetermination date is scheduled to occur on April 1, 2026. During, 2025 we entered into the Third Amendment with our lenders to amend the springing maturity provision of the Credit Agreement to provide a more flexible structure based on the amount of our short-term debt outstanding and our borrowing availability. No individual bank participating in our Credit Agreement represents more than 10 percent of the lender commitments under the Credit Agreement. We must comply with certain financial and non-financial covenants under the terms of the Credit Agreement, including covenants limiting dividend payments and requiring that we maintain certain financial ratios, as set forth in the Credit Agreement. We were in compliance with all financial and non-financial covenants as of December 31, 2025, and through the filing of this report. In connection with the closing of the Civitas Merger on January 30, 2026, the Company and its lenders entered into the Fourth Amendment to the Credit Agreement, which, among other things, increased the aggregate revolving lender commitments available under our Credit Agreement to $2.5 billion and increased the borrowing base to $5.0 billion. Refer to *Note 5 – Long-Term Debt* in Part II, Item 8 of this report for definitions of the Third

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Amendment and Fourth Amendment and additional discussion, as well as the presentation of the outstanding balance, total amount of letters of credit, and available borrowing capacity under the Credit Agreement as of February 2, 2026, December 31, 2025, and December 31, 2024.

The following table summarizes our daily weighted-average revolving credit facility balance during the periods presented:

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| | | |
|:---|:---|:---|
| | **For the Years Ended December 31,** | **For the Years Ended December 31,** |
| | **2025** | **2024** |
| | **(in millions)** | **(in millions)** |
| Daily weighted-average revolving credit facility balance | $50 | $57 |

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The amount we borrow under our revolving credit facility is impacted by cash flows provided by our operating activities, proceeds received from divestitures of properties, capital markets activities including open market debt repurchases, debt redemptions, and repayment of scheduled debt maturities, other financing activities, and our capital expenditures, including acquisitions.

*Weighted-Average Interest and Weighted-Average Borrowing Rates*

Our weighted-average interest rate includes paid and accrued interest, fees on the unused portion of the aggregate revolving lender commitment amount under the Credit Agreement, letter of credit fees, and the non-cash amortization of deferred financing costs. Our weighted-average borrowing rate includes paid and accrued interest only.

The following table presents our weighted-average interest rates and our weighted-average borrowing rates for the years ended December 31, 2025 and 2024:

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| | | |
|:---|:---|:---|
| | **For the Years Ended December 31,** | **For the Years Ended December 31,** |
| | **2025** | **2024** |
| Weighted-average interest rate | 7.4% | 7.6% |
| Weighted-average borrowing rate | 6.8% | 6.6% |

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Our weighted-average interest rate decreased for the year ended December 31, 2025, compared with 2024, primarily due to decreased borrowings under our revolving credit facility. Our weighted-average borrowing rate increased for the year ended December 31, 2025, compared with 2024, primarily as a result of the issuance of our 2029 Senior Notes and 2032 Senior Notes during 2024, which have greater outstanding aggregate principal balances and higher interest rates compared with our other outstanding Senior Notes and our 5.625% Senior Notes due June 1, 2025 ("2025 Senior Notes") that we redeemed during the third quarter of 2024. The rates disclosed in the table above for the year ended December 31, 2024, do not reflect the $9 million fee paid to secure firm commitments for senior unsecured bridge term loans in connection with the Uinta Basin Acquisition.

Our weighted-average interest rate and weighted-average borrowing rate are affected by the occurrence and timing of long-term debt issuances and redemptions and the average outstanding balance on our revolving credit facility. Additionally, our weighted-average interest rate is affected by the fees paid on the unused portion of our aggregate revolving lender commitments. The rates disclosed in the above table do not reflect certain amounts associated with the repurchase or redemption of Senior Notes, such as the accelerated expense recognition of the unamortized deferred financing costs and unamortized discounts, as these amounts are netted against the associated gain or loss on extinguishment of debt. The 2025 Senior Notes were redeemed at their par value on August 26, 2024 and after this date, the weighted-average interest rate was no longer affected by the non-cash amortization of deferred financing costs of the 2025 Senior Notes.

Refer to *Significant Developments in 2025* in Part I, Items 1 and 2 for the definitions of 2029 Senior Notes and 2032 Senior Notes, and to *Note 5 – Long-Term Debt* in Part II, Item 8 of this report for additional discussion and definitions.

*Uses of Cash*

We use cash for the development, exploration, and acquisition of oil and gas properties; for the payment of operating and general and administrative costs, income taxes, debt obligations, including interest and early repayments or redemptions, and dividends; and for repurchases of shares of our outstanding common stock under the Stock Repurchase Program. Expenditures for the development, exploration, and acquisition of oil and gas properties are the primary use of our capital resources. During 2025, we spent $1.5 billion on capital expenditures and on acquisitions of proved and unproved oil and gas properties. This amount differs from the costs incurred amount of $1.4 billion for the year ended December 31, 2025, as costs incurred is an accrual-based amount that also includes asset retirement obligations, geological and geophysical expenses, and exploration overhead amounts. Refer to *Costs Incurred* in *Supplemental Oil and Gas Information (unaudited)* in Part II, Item 8 of this report for additional discussion.

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The amount and allocation of our future capital expenditures will depend upon a number of factors, including our cash flows from operating, investing, and financing activities, our ability to execute our development program, inflation, and the number and size of acquisitions that we complete. In addition, the impact of oil, gas, and NGL prices on investment opportunities, the availability of capital, tax law and other regulatory changes, and the timing and results of our exploration and development activities may lead to changes in funding requirements for future development. We periodically review our capital expenditure budget and guidance to assess if changes are necessary based on current and projected cash flows, acquisition and divestiture activities, debt requirements, and other factors.

Changes to the Internal Revenue Code ("IRC") and federal income tax laws could increase our corporate income tax rate and eliminate or reduce current tax deductions, such as those for intangible drilling costs, depreciation of equipment costs, and other deductions which currently reduce our taxable income. The CAMT and other possible future legislation could reduce our net cash provided by operating activities resulting in a reduction of available funding. Refer to *Comparison of Financial Results and Trends Between 2025 and 2024* above for additional discussion.

We may from time to time repurchase shares of our common stock, or repurchase or redeem all or portions of our outstanding debt securities, for cash, through exchanges for other securities, or a combination of both. Such repurchases or redemptions may be made in open market transactions, privately negotiated transactions, tender offers, pursuant to contractual provisions, or otherwise. Any such repurchases or redemptions will depend on our business strategy, prevailing market conditions, our liquidity requirements, contractual restrictions or covenants, compliance with securities laws, and other factors. The amounts involved in any such transaction may be material.

During the years ended December 31, 2025, and 2024, we repurchased and subsequently retired 444,705 shares and 1,771,191 shares, respectively, of our common stock at a cost, excluding excise taxes, commissions, and fees, of $12 million and $84 million, respectively. As of December 31, 2025, $488 million remained available under the Stock Repurchase Program for repurchases of our common stock through December 31, 2027. Effective January 1, 2023, shares of common stock repurchased, net of shares of common stock issued, are subject to a one percent excise tax imposed by the IRA. We paid a minimal amount of excise tax related to common stock repurchases during 2025. Refer to *Note 3 – Equity* in Part II, Item 8 of this report for discussion of the Stock Repurchase Program.

During the years ended December 31, 2025, and 2024, we paid $92 million and $85 million, respectively, in dividends to our stockholders. Dividends paid were $0.80 and $0.74, per share during the years ended December 31, 2025, and 2024, respectively. Beginning in the first quarter of 2026, dividends are expected to be declared and paid within the same quarter, rather than being paid in the quarter subsequent to declaration. As a result of this timing change, cash dividend payments during 2026 are expected to include five payments, consisting of the fourth quarter 2025 dividend paid in the first quarter of 2026, plus the four quarterly dividends declared and paid during 2026. In February of 2026, our Board of Directors approved a 10 percent increase to our annual base dividend to $0.88 per share, payable quarterly, effective beginning with the March 2026 dividend. We currently intend to continue paying dividends to our stockholders for the foreseeable future, subject to our future earnings, our financial condition, covenants under our Credit Agreement and indentures governing each series of our outstanding Senior Notes, and other factors that could arise. The payment and amount of future dividends remain at the discretion of our Board of Directors.

During 2024, we redeemed all of the $349 million of aggregate principal amount outstanding of our 2025 Senior Notes. Additionally, we used a portion of the net proceeds from the 2029 Senior Notes and 2032 Senior Notes, cash on hand, and borrowings under our revolving credit facility to fund our proportionate share of the Uinta Basin Acquisition. Refer to *Significant Developments in 2025* in Part I, Items 1 and 2 for the definitions of 2029 Senior Notes and 2032 Senior Notes, and to *Note 5 – Long-Term Debt* and *Note 17 – Mergers, Acquisitions, and Divestitures* in Part II, Item 8 of this report for additional discussion and definitions.

*Analysis of Cash Flow Changes Between 2025 and 2024*

The following tables present changes in cash flows between the years ended December 31, 2025 and 2024, for our operating, investing, and financing activities. The analysis following each table should be read in conjunction with our accompanying consolidated statements of cash flows ("accompanying statements of cash flows") in Part II, Item 8 of this report.

*Operating Activities*

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| | | | |
|:---|:---|:---|:---|
| | **For the Years Ended December 31,** | **For the Years Ended December 31,** | **Amount Change Between Periods** |
| | **2025** | **2024** | **Amount Change Between Periods** |
| | **(in millions)** | **(in millions)** | **(in millions)** |
| Net cash provided by operating activities | $2011 | $1783 | $228 |

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Net cash provided by operating activities increased for the year ended December 31, 2025, compared with 2024, primarily resulting from a $474 million increase in cash received from oil, gas, and NGL production revenues, net of transportation costs and production taxes, and an increase of $60 million in cash received on settled derivative trades. These amounts were partially offset by an increase of $169 million in cash paid for LOE, ad valorem taxes, and certain G&A expenses, and an increase of $78 million in cash

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paid for interest. Net cash provided by operating activities was also affected by the timing of payments made between us and XCL Resources related to activity occurring after the closing date of the Uinta Basin Acquisition. Refer to *Note 17 – Mergers, Acquisitions, and Divestitures* in Part II, Item 8 of this report for additional discussion and definitions.

Net cash provided by operating activities is affected by working capital changes and the timing of cash receipts and disbursements.

*Investing Activities*

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| | | | |
|:---|:---|:---|:---|
| | **For the Years Ended December 31,** | **For the Years Ended December 31,** | **Amount Change Between Periods** |
| | **2025** | **2024** | **Amount Change Between Periods** |
| | **(in millions)** | **(in millions)** | **(in millions)** |
| Net cash used in investing activities | $(1468) | $(3407) | $1939 |

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Net cash used in investing activities decreased for the year ended December 31, 2025, compared with 2024, resulting from $2.1 billion of cash paid for the Uinta Basin Acquisition in 2024, partially offset by a $127 million increase in capital expenditures. Refer to *Note 17 – Mergers, Acquisitions, and Divestitures* in Part II, Item 8 of this report for additional discussion of the Uinta Basin Acquisition.

*Financing Activities*

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| | | | |
|:---|:---|:---|:---|
| | **For the Years Ended December 31,** | **For the Years Ended December 31,** | **Amount Change Between Periods** |
| | **2025** | **2024** | **Amount Change Between Periods** |
| | **(in millions)** | **(in millions)** | **(in millions)** |
| Net cash provided by (used in) financing activities | $(175) | $1008 | $(1183) |

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Net cash used in financing activities during the year ended December 31, 2025, primarily related to $92 million of dividends paid to our stockholders, net repayments under our revolving credit facility of $69 million, and $13 million, including commission and fees, paid to repurchase and subsequently retire 444,705 shares of our common stock under the Stock Repurchase Program.

Net cash provided by financing activities during the year ended December 31, 2024, primarily related to net cash proceeds of $1.5 billion from the issuance of our 2029 Senior Notes and 2032 Senior Notes, and net borrowings under our revolving credit facility of $69 million, partially offset by $349 million of cash paid to redeem our 2025 Senior Notes. Additionally, we paid $86 million, including commission and fees, to repurchase and subsequently retire 1,771,191 shares of our common stock under the Stock Repurchase Program, and paid $85 million of dividends to our stockholders.

Refer to *Note 3 – Equity* in Part II, Item 8 of this report for additional discussion of our Stock Repurchase Program and *Note 5 – Long-Term Debt* in Part II, Item 8 of this report for additional discussion and definitions related to our debt transactions.

*Interest Rate Risk*

We are exposed to market and credit risk due to the floating interest rate associated with any outstanding balance on our revolving credit facility. Our Credit Agreement allows us to fix the interest rate for all or a portion of the principal balance of our revolving credit facility for a period up to six months. To the extent that the interest rate is fixed, interest rate changes will affect the revolving credit facility's fair value but will not affect results of operations or cash flows. Conversely, for the portion of the revolving credit facility that has a floating interest rate, interest rate changes will not affect the fair value but will affect future results of operations and cash flows. Changes in interest rates do not affect the amount of interest we pay on our fixed-rate Senior Notes, but can affect their fair values. As of December 31, 2025, our outstanding principal amount of fixed-rate debt totaled $2.7 billion and we had no floating-rate debt outstanding. As of December 31, 2024, our outstanding principal amount of fixed-rate debt totaled $2.7 billion and our floating-rate debt outstanding totaled $69 million. Refer to *Note 8 – Fair Value Measurements* in Part II, Item 8 of this report for additional discussion on the fair values of our Senior Notes.

*Commodity Price Risk*

The prices we receive for our oil, gas, and NGL production directly affect our revenue, profitability, access to capital, ability to return capital to our stockholders, and future rate of growth. Oil, gas, and NGL prices are subject to unpredictable fluctuations resulting from a variety of factors that are typically beyond our control, including changes in supply and demand associated with the broader macroeconomic environment, constraints on gathering systems, processing facilities, pipelines, rail systems, and other transportation systems, and weather-related events. The markets for oil, gas, and NGLs have been volatile, especially over the last decade, and

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remain subject to high levels of uncertainty and volatility related to production output from OPEC+, fluctuations in oil and gas demand from China, global shipping channel constraints and disruptions, War and Geopolitical Instability, tariffs or trade restrictions, and the potential impacts of these issues on global commodity and financial markets. These circumstances have contributed to inflation, instances of supply chain disruptions, and fluctuations in interest rates, and could have further industry-specific impacts that may require us to adjust our business plan. The realized prices we receive for our production also depend on numerous factors that are typically beyond our control. Refer to *Risk Factors - Risks Related to Commodity Prices and Global Macroeconomics* in Part I, Item 1A of this report. Based on our production for 2025, and 2024, a 10 percent decrease in our average realized prices for oil, gas, and NGLs would have reduced our oil, gas, and NGL production revenues by approximately $256 million, $35 million, and $22 million, respectively, for 2025, and $219 million, $25 million and $24 million, respectively, for 2024. If commodity prices had been 10 percent lower, our net derivative settlements for the year ended December 31, 2025, would have offset the declines in oil, gas, and NGL production revenue by approximately $106 million.

We enter into commodity derivative contracts in order to reduce the risk of fluctuations in commodity prices. The fair value of our commodity derivative contracts is largely determined by estimates of the forward curves of the relevant price indices. As of December 31, 2025, and 2024, a 10 percent increase or decrease in the forward curves associated with our oil, gas, and NGL commodity derivative instruments would have changed our net derivative positions for these products by approximately $57 million, $36 million, and $1 million, respectively, for 2025, and $52 million, $23 million, and $2 million, respectively, for 2024.

*Off-Balance Sheet Arrangements*

We have not participated in transactions that generate relationships with unconsolidated entities or financial partnerships, such as entities often referred to as structured finance or special purpose entities ("SPE" or "SPEs"). Refer to *Off-Balance Sheet Arrangements* within *Note 1 – Summary of Significant Accounting Policies* in Part II, Item 8 of this report for additional discussion.

**Critical Accounting Estimates**

Our discussion of financial condition and results of operations is based upon the information reported in our consolidated financial statements. The preparation of these consolidated financial statements in conformity with GAAP requires us to make assumptions and estimates that affect the reported amounts of assets, liabilities, revenues, and expenses, as well as the disclosure of contingent assets and liabilities as of the date of our consolidated financial statements. We base our assumptions and estimates on historical experience and various other sources that we believe to be reasonable under the circumstances. Actual results may differ from the estimates we calculate as a result of changes in circumstances, global economics and politics, and general business conditions. A summary of our significant accounting policies is detailed in *Note 1 – Summary of Significant Accounting Policies* in Part II, Item 8 of this report. We have outlined below, those policies identified as being critical to the understanding of our business and results of operations and that require the application of significant management judgment.

*Successful Efforts Method of Accounting.* GAAP provides two alternative methods for the oil and gas industry to use in accounting for oil and gas producing activities. These two methods are generally known in our industry as the full cost method and the successful efforts method, and both methods are widely used. The methods are different enough that in many circumstances the same set of facts will provide materially different financial statement results within a given year. We have chosen the successful efforts method of accounting for our oil and gas producing activities. A more detailed description is included in *Note 1 – Summary of Significant Accounting Policies* of Part II, Item 8 of this report.

*Oil and Gas Reserve Quantities.* Our estimated proved reserve quantities and future net cash flows are critical to understanding the value of our business. They are used in comparative financial ratios and are the basis for significant accounting estimates in our consolidated financial statements, including the calculations of DD&A expense, impairment of proved and unproved oil and gas properties, asset retirement obligations, and purchase price allocations. Refer to *Oil and Gas Producing Activities* in *Note 1 – Summary of Significant Accounting Policies* of Part II, Item 8 of this report for additional discussion on our accounting policies impacted by estimated reserve quantities.

Future cash inflows and future production and development costs are determined by applying prices and costs, including transportation, quality differentials, and basis differentials, applicable to each period to our net share of estimated quantities of proved reserves remaining to be produced as of the end of that period. Expected cash flows are discounted to present value using an appropriate discount rate. For example, the standardized measure of discounted future net cash flows calculation requires that a 10 percent discount rate be applied. Although reserve estimates are inherently imprecise and estimates of new discoveries and undeveloped locations are more imprecise than those of established producing oil and gas properties, we make a considerable effort in estimating our reserves. We engage Ryder Scott, an independent reservoir evaluation consulting firm, to audit a minimum of 80 percent of our total calculated proved reserve PV-10. We expect proved reserve estimates will change as additional information becomes available and as commodity prices and operating and capital costs change. We evaluate and estimate our proved reserves each year end. It should not be assumed that the standardized measure of discounted future net cash flows (GAAP) or PV-10 (non-GAAP) as of December 31, 2025, is the current market value of our estimated proved reserves. In accordance with SEC requirements, we based these measures on the unweighted arithmetic average of the first-day-of-the-month price of each month within the trailing 12-month period ended December 31, 2025. Actual future prices and costs may be materially higher or lower than the prices and costs utilized in the estimates. Refer to *Risk Factors* in Part I, Item 1A of this report for additional discussion.

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If the estimates of proved reserves decline, the rate at which we record DD&A expense will increase, which would reduce future net income. Changes in DD&A rate calculations caused by changes in reserve quantities are made prospectively. In addition, a decline in reserve estimates may impact the outcome of our assessment of proved and unproved properties for impairment. Impairments are recorded in the period in which they are identified.

The following table presents information about proved reserve changes from period to period due to items we do not control, such as price, and from changes due to production history and well performance. These changes do not require a capital expenditure on our part, but may have resulted from capital expenditures we incurred to develop other estimated proved reserves.

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| | | |
|:---|:---|:---|
| | **For the Years Ended December 31,** | **For the Years Ended December 31,** |
| | **2025** | **2024** |
| | **MMBOE Change** | **MMBOE Change** |
| Revisions resulting from performance | (19.2) | (8.0) |
| Removal of net proved undeveloped reserves no longer in our five-year development plan | (40.7) | (30.5) |
| Revisions resulting from price changes | 3.7 | (13.4) |
| Total | (56.2) | (51.9) |

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____________________________________________

Note: Amounts may not calculate due to rounding.

As previously noted, commodity prices are volatile and estimates of reserves are inherently imprecise. Consequently, we expect to continue experiencing these types of changes.

We cannot reasonably predict future commodity prices, although we believe that together, the analyses below provide reasonable information regarding the impact of changes in pricing and trends on total estimated net proved reserves. The following table reflects the estimated MMBOE change and percentage change to our total reported estimated net proved reserve volumes from the described hypothetical changes:

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| | | |
|:---|:---|:---|
| | **For the year ended December 31, 2025** | **For the year ended December 31, 2025** |
| | **MMBOE Change** | **Percentage Change** |
| 10 percent decrease in SEC pricing <sup>(1)</sup> | (18.4) | (3)% |
| Average NYMEX strip pricing as of fiscal year end <sup>(2)</sup> | (9.0) | (1)% |
| 10 percent decrease in net proved undeveloped reserves <sup>(3)</sup> | (26.1) | (4)% |

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____________________________________________

<sup>(1)&nbsp;&nbsp;&nbsp;&nbsp;</sup>The change solely reflects the impact of a 10 percent decrease in SEC pricing to the total reported estimated net proved reserve volumes as of December 31, 2025, and does not include additional impacts to our estimated net proved reserves that may result from our internal intent to drill hurdles or changes in future service or equipment costs.

<sup>(2)&nbsp;&nbsp;&nbsp;&nbsp;</sup>The change solely reflects the impact of replacing SEC pricing with the five-year average NYMEX strip pricing as of December 31, 2025, and does not include additional impacts to our estimated net proved reserves that may result from our internal intent to drill hurdles or changes in future service or equipment costs. As of December 31, 2025, SEC pricing was $65.34 per Bbl for oil, $3.39 per MMBtu for gas, and $27.45 per Bbl for NGLs, and five-year average NYMEX strip pricing was $58.72 per Bbl for oil, $3.71 per MMBtu for gas, and $22.85 per Bbl for NGLs.

<sup>(3)&nbsp;&nbsp;&nbsp;&nbsp;</sup>The change solely reflects a 10 percent decrease in net proved undeveloped reserves as of December 31, 2025, and does not include any additional impacts to our estimated net proved reserves.

Additional reserve information can be found in *Reserves* in Part I, Items 1 and 2 of this report, and in *Supplemental Oil and Gas Information (unaudited)* in Part II, Item 8 of this report.

*Impairment of Proved Properties.* Proved oil and gas properties are evaluated for impairment on a depletion pool-by-pool basis and reduced to fair value when there is an indication that their carrying amount may not be recoverable. We estimate the expected future cash flows of our proved oil and gas properties and compare these undiscounted cash flows to the carrying amount to determine if the carrying amount is recoverable. If the carrying amount exceeds the estimated undiscounted future cash flows, we will write down the carrying amount of the proved oil and gas properties to fair value (or discounted future cash flows). Management estimates future cash flows from all proved reserves and risk adjusted probable and possible reserves using various factors, which are subject to our judgment and expertise, and include, but are not limited to, commodity price forecasts, estimated future operating and capital costs, development plans, and discount rates to incorporate the risk and current market conditions associated with realizing the expected cash flows. We cannot predict when or if future impairment charges will be recorded because of the uncertainty in the factors discussed above. Despite any amount of future impairment being difficult to predict, based on our commodity price assumptions as of

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February 2, 2026, we do not expect any material proved oil and gas property impairments in the first quarter of 2026 resulting from commodity price impacts.

**Accounting Matters**

Refer to *Recently Issued Accounting Guidance* in *Note 1 – Summary of Significant Accounting Policies* in Part II, Item 8 of this report for information on new authoritative accounting guidance.

**Environmental**

We believe we are in substantial compliance with environmental laws and regulations and do not currently anticipate that material future expenditures will be required under the existing regulatory framework. However, environmental laws and regulations are subject to frequent changes, and we are unable to predict the impact that compliance with future laws or regulations, such as those currently being considered as discussed below, may have on future capital expenditures, liquidity, and results of operations.

*Hydraulic Fracturing.* Hydraulic fracturing is an important and common practice that is used to stimulate production of hydrocarbons from tight formations. For additional information about hydraulic fracturing and related environmental matters, refer to *Risk Factors – Risks Related to Litigation and Government Regulations – Federal and state legislative and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays.*

*Climate Change and Air Quality.* In June 2013, President Obama announced a Climate Action Plan designed to further reduce GHG emissions and prepare the nation for the physical effects that may occur as a result of climate change. The Climate Action Plan targeted methane reductions from the oil and gas sector as part of a comprehensive interagency methane strategy. As part of the Climate Action Plan, on May 12, 2016, the EPA issued final regulations applicable to new, modified, or reconstructed sources that amended and expanded 2012 regulations for the oil and gas sector by, among other things, setting emission limits for volatile organic compounds ("VOCs" or "VOC") and methane, a GHG, and added requirements for previously unregulated sources. The 2016 NSPS requires reduction of methane and VOCs from certain activities in oil and gas production, processing, transmission and storage and applies to facilities constructed, modified, or reconstructed after September 18, 2015. The regulation requires, among other things, GHG and VOC emission limits for certain equipment, such as centrifugal compressors and reciprocating compressors; semi-annual leak detection and repair for well sites and quarterly for boosting and garnering compressor stations and gas transmission compressor stations; control requirements and emission limits for pneumatic pumps; and additional requirements for control of GHGs and VOCs from well completions. In September 2020, the EPA finalized amendments to the 2012 and 2016 NSPS that removed transmission and storage infrastructure from regulation of methane emissions and other VOCs, as well as removed methane control requirements. The portion of the 2020 amendments that removed the transmission and storage infrastructure from the regulations was disapproved by the Congressional Review Act in 2021. In November 2021, the EPA proposed to expand the requirements of the 2012 and 2016 NSPS and also include requirements for states to develop performance standards to control methane emissions from existing sources. In December 2022, the EPA issued a supplemental proposal to update, strengthen, and expand the 2021 proposed rules. The EPA finalized the rule in December 2023. In March 2024, the EPA announced a final rule that implemented a waste emissions charge and new reporting requirements for facilities and wells completed after May 7, 2024. On March 14, 2025, President Trump signed a joint resolution of disapproval under the Congressional Review Act, voiding the EPA's final rule on methane waste emission, and in July 2025, the EPA announced an interim final rule that extends deadlines for certain provisions related to facilities and wells.

States are also required to comply with the NAAQS. The oil and gas sector is often subjected to additional controls when areas within states are not attaining the ozone NAAQS as the VOCs emitted by the oil and gas sector are a precursor to ozone formation. The ozone NAAQS was set at 70 parts per billion ("ppb") in 2015. In 2023, the EPA announced its plan to perform a full and complete review of the ozone NAAQS. The results of this review could result in changes to the ozone NAAQS which, if lowered, may result in additional actions by states requiring further emission controls and associated costs. Oil and gas facilities operating in areas that are determined to be out of compliance with the 70 ppb requirement or a lowered ozone NAAQS may be subject to increased emission controls and associated costs of compliance. In March of 2025, the EPA announced it was revisiting the Biden PM2.5 NAAQS and that it was planning on releasing guidance to increase flexibility of NAAQS implementation, reforms to the New Source Review, and direction on permitting obligations.

The United States Congress has from time to time considered adopting legislation to reduce emissions of GHGs and many of the states have already taken legal measures to reduce emissions of GHGs primarily through the planned development of GHG emission inventories and/or regional GHG cap and trade programs. Most of these cap and trade programs work by requiring major sources of emissions, such as electric power plants, or major producers of fuels, such as refineries and gas processing plants, to acquire and surrender emission allowances. The number of allowances available for purchase is reduced each year in an effort to achieve the overall GHG emission reduction goal. In addition, certain international agreements seek to limit and reduce GHGs globally, including the Global Methane Pledge announced at the United Nations Climate Change Conference in Glasgow that aims to reduce methane emissions by 30 percent compared with 2020 levels.

The adoption of legislation or regulatory programs to reduce emissions of GHGs could require us to incur increased operating costs, such as costs to purchase and operate emissions control systems, to acquire emissions allowances, or comply with new regulatory or reporting requirements. Any such legislation or regulatory programs could also increase the cost of consuming, and

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thereby reduce demand for, the oil and gas we produce. Consequently, legislation and regulatory programs to reduce emissions of GHGs could have an adverse effect on our business, financial condition, and results of operations. Judicial challenges to new regulatory measures are likely and we cannot predict the outcome of such challenges. New regulatory suspensions, revisions, or rescissions and conflicting state and federal regulatory mandates may inhibit our ability to accurately forecast the costs associated with future regulatory compliance. Finally, scientists have concluded that increasing concentrations of GHGs in the earth's atmosphere produce climate changes that likely have significant physical effects, such as increased frequency and severity of storms, droughts, floods, and other climatic events. Such effects could have an adverse effect on our financial condition and results of operations.

In terms of opportunities, the regulation of GHG emissions and the introduction of alternative incentives, such as enhanced oil recovery, carbon sequestration, and low carbon fuel standards, could benefit us in a variety of ways. For example, although federal regulation and climate change legislation could reduce the overall demand for the oil and gas that we produce, the relative demand for gas may increase because the burning of gas produces lower levels of emissions than other readily available fossil fuels such as oil and coal. In addition, if renewable resources such as wind or solar power become more prevalent, gas-fired electric plants may provide an alternative backup to maintain consistent electricity supply. Also, if states adopt low-carbon fuel standards, gas may become a more attractive transportation fuel. For the years ended December 31, 2025, and 2024, approximately 33 percent and 37 percent, respectively, of our production on a per BOE basis was gas. Market-based incentives for the capture and storage of carbon dioxide in underground reservoirs, particularly in oil and gas reservoirs, could also benefit us through the potential to obtain GHG emission allowances or offsets from or government incentives for the sequestration of carbon dioxide. For additional information about climate change, air quality, and related environmental matters, refer to *Risk Factors – Risks Related to Litigation and Government Regulations – Legislative and regulatory initiatives and litigation related to global warming and climate change could have an adverse effect on our operations and the demand for oil, gas, and NGLs, and could result in significant litigation, capital, and related expenses* and *Federal and state regulatory initiatives relating to air quality and greenhouse gas emissions could result in increased costs and additional operating restrictions or delays.*

**Non-GAAP Financial Measures**

Adjusted EBITDAX represents net income (loss) before interest expense, interest income, income taxes, depletion, depreciation, and amortization expense, exploration expense, property abandonment and impairment expense, non-cash stock-based compensation expense, derivative gains and losses net of settlements, gains and losses on divestitures, gains and losses on extinguishment of debt, and certain other items. Adjusted EBITDAX excludes certain items that we believe affect the comparability of operating results and can exclude items that are generally non-recurring in nature or whose timing and/or amount cannot be reasonably estimated. Adjusted EBITDAX is a non-GAAP measure that we believe provides useful additional information to investors and analysts, as a performance measure, for analysis of our ability to internally generate funds for exploration, development, acquisitions, and to service debt. We are also subject to financial covenants under our Credit Agreement. In addition, adjusted EBITDAX is widely used by professional research analysts and others in the valuation, comparison, and investment recommendations of companies in the oil and gas exploration and production industry, and many investors use the published research of industry research analysts in making investment decisions. Adjusted EBITDAX should not be considered in isolation or as a substitute for net income (loss), income (loss) from operations, net cash provided by operating activities, or other profitability or liquidity measures prepared under GAAP. Because adjusted EBITDAX excludes some, but not all items that affect net income (loss) and may vary among companies, the adjusted EBITDAX amounts presented may not be comparable to similar metrics of other companies. Our revolving credit facility provides a material source of liquidity for us. Under the terms of our Credit Agreement, if we failed to comply with the covenants that establish a maximum permitted ratio of total funded debt, as defined in the Credit Agreement, to adjusted EBITDAX, we would be in default, an event that would prevent us from borrowing under our revolving credit facility and would therefore materially limit a significant source of our liquidity. In addition, if we are in default under our revolving credit facility and are unable to obtain a waiver of that default from our lenders, lenders under that facility and under the indentures governing each series of our outstanding Senior Notes would be entitled to exercise all of their remedies for default. Refer to *Note 5 – Long-Term Debt* in Part II, Item 8 of this report, for definition of and further detail about our Credit Agreement.

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The following table provides reconciliations of our net income (GAAP) and net cash provided by operating activities (GAAP) to adjusted EBITDAX (non-GAAP) for the periods presented:

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| | | |
|:---|:---|:---|
| | **For the Years Ended December 31,** | **For the Years Ended December 31,** |
| | **2025** | **2024** |
| | **(in millions)** | **(in millions)** |
| **Net income (GAAP)** | $648 | $770 |
| &nbsp;&nbsp;&nbsp;&nbsp;Interest expense | 173 | 141 |
| &nbsp;&nbsp;&nbsp;&nbsp;Interest income | (3) | (32) |
| &nbsp;&nbsp;&nbsp;&nbsp;Income tax expense | 182 | 196 |
| &nbsp;&nbsp;&nbsp;&nbsp;Depletion, depreciation, and amortization | 1207 | 809 |
| &nbsp;&nbsp;&nbsp;&nbsp;Exploration <sup>(1)</sup> | 51 | 59 |
| &nbsp;&nbsp;&nbsp;&nbsp;Stock-based compensation expense | 29 | 25 |
| &nbsp;&nbsp;&nbsp;&nbsp;Net derivative gain | (178) | (50) |
| &nbsp;&nbsp;&nbsp;&nbsp;Net derivative settlement gain | 132 | 69 |
| &nbsp;&nbsp;&nbsp;&nbsp;Other, net | 14 |  |
| **Adjusted EBITDAX (non-GAAP)** | **2255** | **1987** |
| &nbsp;&nbsp;&nbsp;&nbsp;Interest expense | (173) | (141) |
| &nbsp;&nbsp;&nbsp;&nbsp;Interest income | 3 | 32 |
| &nbsp;&nbsp;&nbsp;&nbsp;Income tax expense | (182) | (196) |
| &nbsp;&nbsp;&nbsp;&nbsp;Exploration <sup>(1) (2)</sup> | (51) | (50) |
| &nbsp;&nbsp;&nbsp;&nbsp;Amortization of deferred financing costs | 10 | 7 |
| &nbsp;&nbsp;&nbsp;&nbsp;Deferred income taxes | 178 | 175 |
| &nbsp;&nbsp;&nbsp;&nbsp;Other, net | (42) | (44) |
| &nbsp;&nbsp;&nbsp;&nbsp;Net change in working capital | 13 | 11 |
| **Net cash provided by operating activities (GAAP)** | $**2011** | $**1783** |

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Note: Prior year amounts may not calculate due to rounding.

<sup>(1)&nbsp;&nbsp;&nbsp;&nbsp;</sup>Stock-based compensation expense is a component of the exploration expense and general and administrative expense line items on the accompanying statements of operations. Therefore, the exploration line items shown in the reconciliation above will vary from the amount shown on the accompanying statements of operations for the component of stock-based compensation expense recorded to exploration expense.

<sup>(2)&nbsp;&nbsp;&nbsp;&nbsp;</sup>For the year ended December 31, 2024, amount excludes certain capital expenditures related to one well deemed non-commercial.

**ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK**

The information required by this Item is provided under the captions *Interest Rate Risk* and *Commodity Price Risk* in Item 7 above, as well as under the section entitled *Summary of Oil, Gas, and NGL Derivative Contracts in Place* in *Note 7 – Derivative Financial Instruments* in Part II, Item 8 of this report and is incorporated herein by reference.

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**ITEM 8. CONSOLIDATED FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA**

**Report of Independent Registered Public Accounting Firm**

To the Stockholders and the Board of Directors of SM Energy Company

**Opinion on the Financial Statements**

We have audited the accompanying consolidated balance sheets of SM Energy Company and subsidiaries (the Company) as of December 31, 2025 and 2024, the related consolidated statements of operations, comprehensive income, stockholders' 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 at 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 U.S. generally accepted accounting principles.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Company's internal control over financial reporting as of December 31, 2025, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework), and our report dated February 26, 2026 expressed an unqualified opinion thereon.

**Basis for Opinion**

These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the Company's financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.

**Critical Audit Matter**

The critical audit matter communicated below is a matter arising from the current period audit of the financial statements that was communicated or required to be communicated to the audit committee and that: (1) relates to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective or complex judgments. The communication of the critical audit matter does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.

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***Depletion, Depreciation and Amortization ("DD&A") of Proved Oil and Gas Properties***

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| | |
|:---|:---|
| *Description of the Matter* | At December 31, 2025, the net book value of the Company's proved oil and gas properties was $7.2 billion, and depletion, depreciation and amortization was $1.2 billion for the year then ended. As described in Note 1 to the consolidated financial statements, the Company follows the successful efforts method of accounting for its oil and gas properties. Under the successful efforts method of accounting, the capitalized costs of proved oil and gas properties are depleted using the units-of-production method based on proved oil and gas reserves, as estimated by the Company's engineers. Proved oil and gas reserve estimates are impacted by various inputs, including historical production, oil and gas price assumptions, and future operating and capital cost assumptions, among others, and requires the expertise of the Company's engineers in evaluating and interpreting the relevant data. Because of the complexity involved in estimating oil and gas reserves, management used independent petroleum engineers to audit the estimates prepared by the Company's engineers as of December 31, 2025.<br>Auditing the impact of proved oil and gas reserves on DD&A is especially complex because of the use of the work of the Company's engineers and the independent petroleum engineers and the evaluation of management's determination of the inputs described above used by the engineers in estimating proved oil and gas reserves. |
| *How We Addressed the Matter in Our Audit* | Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the consolidated financial statements. These procedures included testing the effectiveness of controls relating to management's estimates of proved oil and natural gas reserve volumes. The work of management's specialists was used in performing the procedures to evaluate the reasonableness of the proved oil and natural gas reserve volumes. As a basis for using this work, the specialists' qualifications were understood and the Company's relationship with the specialists was assessed. The procedures performed also included i) evaluating the methods and assumptions used by the specialists, ii) testing the completeness and accuracy of the data used by the specialists related to historical production volumes, iii) evaluating the specialists' findings related to estimated future production volumes by comparing the estimate to relevant historical and current period information, as applicable. |

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/s/ Ernst & Young LLP

We have served as the Company's auditor since 2012.

Denver, Colorado

February 26, 2026

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**SM ENERGY COMPANY AND SUBSIDIARIES**

**CONSOLIDATED BALANCE SHEETS**

**(in millions, except share data)**

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| | | |
|:---|:---|:---|
| | **December 31,** | **December 31,** |
| | **2025** | **2024** |
| **ASSETS** |  |  |
| Current assets: |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Cash and cash equivalents | $368 | $— |
| &nbsp;&nbsp;&nbsp;&nbsp;Accounts receivable | 331 | 361 |
| &nbsp;&nbsp;&nbsp;&nbsp;Derivative assets | 83 | 49 |
| &nbsp;&nbsp;&nbsp;&nbsp;Prepaid expenses and other | 29 | 25 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Total current assets | 811 | 435 |
| Property and equipment (successful efforts method): |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Proved oil and gas properties | 16012 | 14302 |
| &nbsp;&nbsp;&nbsp;&nbsp;Accumulated depletion, depreciation, and amortization | (8793) | (7603) |
| &nbsp;&nbsp;&nbsp;&nbsp;Unproved oil and gas properties, net of valuation allowance of $12 and $33, respectively | 460 | 765 |
| &nbsp;&nbsp;&nbsp;&nbsp;Wells in progress | 458 | 482 |
| &nbsp;&nbsp;&nbsp;&nbsp;Other property and equipment, net of accumulated depreciation of $63 and $62, respectively | 65 | 48 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Total property and equipment, net | 8202 | 7993 |
| Noncurrent assets: |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Derivative assets | 6 | 4 |
| &nbsp;&nbsp;&nbsp;&nbsp;Other noncurrent assets | 234 | 145 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Total noncurrent assets | 240 | 149 |
| **Total assets** | $**9253** | $**8577** |
| **LIABILITIES AND STOCKHOLDERS*'* EQUITY** |  |  |
| Current liabilities: |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Accounts payable and accrued expenses | $690 | $760 |
| &nbsp;&nbsp;&nbsp;&nbsp;Senior Notes, net | 419 |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Derivative liabilities | 2 | 7 |
| &nbsp;&nbsp;&nbsp;&nbsp;Other current liabilities | 58 | 22 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Total current liabilities | 1169 | 790 |
| Noncurrent liabilities: |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Revolving credit facility |  | 69 |
| &nbsp;&nbsp;&nbsp;&nbsp;Senior Notes, net | 2296 | 2708 |
| &nbsp;&nbsp;&nbsp;&nbsp;Asset retirement obligations | 150 | 145 |
| &nbsp;&nbsp;&nbsp;&nbsp;Net deferred tax liabilities | 724 | 545 |
| &nbsp;&nbsp;&nbsp;&nbsp;Derivative liabilities | 2 | 7 |
| &nbsp;&nbsp;&nbsp;&nbsp;Other noncurrent liabilities | 102 | 75 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Total noncurrent liabilities | 3274 | 3549 |
| Commitments and contingencies (note 6) |  |  |
| Stockholders' equity: |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Common stock, $0.01 par value - authorized: 200,000,000 shares; issued and outstanding: 114,630,905 and 114,461,934 shares, respectively | 1 | 1 |
| &nbsp;&nbsp;&nbsp;&nbsp;Additional paid-in capital | 1517 | 1502 |
| &nbsp;&nbsp;&nbsp;&nbsp;Retained earnings | 3291 | 2735 |
| &nbsp;&nbsp;&nbsp;&nbsp;Accumulated other comprehensive income (loss) | 1 | (1) |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Total stockholders' equity | 4810 | 4237 |
| **Total liabilities and stockholders' equity** | $**9253** | $**8577** |

---

____________________________________________

Note: Prior year amounts may not calculate due to rounding.

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

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**SM ENERGY COMPANY AND SUBSIDIARIES**

**CONSOLIDATED STATEMENTS OF OPERATIONS**

**(in millions, except per share data)**

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| | | | |
|:---|:---|:---|:---|
| | **For the Years Ended December 31,** | **For the Years Ended December 31,** | **For the Years Ended December 31,** |
| | **2025** | **2024** | **2023** |
| **Operating revenues and other income:** |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Oil, gas, and NGL production revenue | $3138 | $2671 | $2364 |
| &nbsp;&nbsp;&nbsp;&nbsp;Other operating income | 16 | 19 | 10 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Total operating revenues and other income | 3154 | 2690 | 2374 |
| **Operating expenses:** |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Oil, gas, and NGL production expense | 885 | 637 | 564 |
| &nbsp;&nbsp;&nbsp;&nbsp;Depletion, depreciation, and amortization | 1207 | 809 | 690 |
| &nbsp;&nbsp;&nbsp;&nbsp;Exploration | 57 | 64 | 59 |
| &nbsp;&nbsp;&nbsp;&nbsp;General and administrative | 161 | 138 | 121 |
| &nbsp;&nbsp;&nbsp;&nbsp;Net derivative gain | (178) | (50) | (68) |
| &nbsp;&nbsp;&nbsp;&nbsp;Other operating expense | 22 | 16 | 21 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Total operating expenses | 2154 | 1615 | 1387 |
| **Income from operations** | **1000** | **1076** | **987** |
| Interest expense | (173) | (141) | (92) |
| Interest income | 3 | 32 | 20 |
| Other non-operating expense |  | (1) | (1) |
| **Income before income taxes** | **830** | **966** | **914** |
| Income tax expense | (182) | (196) | (96) |
| **Net income** | $**648** | $**770** | $**818** |
| Basic weighted-average common shares outstanding | 115 | 115 | 119 |
| Diluted weighted-average common shares outstanding | 115 | 116 | 119 |
| Basic net income per common share | $5.65 | $6.71 | $6.89 |
| Diluted net income per common share | $5.64 | $6.67 | $6.86 |

---

____________________________________________

Note: Prior year amounts may not calculate due to rounding.

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

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**SM ENERGY COMPANY AND SUBSIDIARIES**

**CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME**

**(in millions)**

---

| | | | |
|:---|:---|:---|:---|
| | **For the Years Ended December 31,** | **For the Years Ended December 31,** | **For the Years Ended December 31,** |
| | **2025** | **2024** | **2023** |
| Net income | $648 | $770 | $818 |
| Other comprehensive income, net of tax: |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Pension liability adjustment <sup>(1)</sup> | 2 | 1 | 1 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Total other comprehensive income, net of tax | 2 | 1 | 1 |
| **Total comprehensive income** | $**650** | $**772** | $**819** |

---

____________________________________________

Note: Prior year amounts may not calculate due to rounding.

<sup>(1)&nbsp;&nbsp;&nbsp;&nbsp;</sup>Refer to *Note 12 – Pension Benefits* for discussion of the pension liability adjustment.

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

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**SM ENERGY COMPANY AND SUBSIDIARIES**

**CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY**

**(in millions, except share data and dividends per share)**

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| | | | | | | |
|:---|:---|:---|:---|:---|:---|:---|
| | | | **Additional Paid-in Capital** | | **Accumulated Other Comprehensive Income (Loss)** | **Total Stockholders' Equity** |
| | **Common Stock** | **Common Stock** | **Additional Paid-in Capital** | **Retained Earnings** | **Accumulated Other Comprehensive Income (Loss)** | **Total Stockholders' Equity** |
| | **Shares** | **Amount** | **Additional Paid-in Capital** | **Retained Earnings** | **Accumulated Other Comprehensive Income (Loss)** | **Total Stockholders' Equity** |
| **Balances, January 1, 2023** | **121931676** | $**1** | $**1780** | $**1309** | $**(4)** | $**3085** |
| Net income |  |  |  | 818 |  | 818 |
| Other comprehensive income |  |  |  |  | 1 | 1 |
| Net cash dividends declared, $0.63 per share |  |  |  | (74) |  | (74) |
| Issuance of common stock under Employee Stock Purchase Plan | 114427 |  | 3 |  |  | 3 |
| Issuance of common stock upon vesting of RSUs, net of shares used for tax withholdings | 554216 |  | (8) |  |  | (8) |
| Stock-based compensation expense | 56872 |  | 20 |  |  | 20 |
| Purchase of shares under Stock Repurchase Program | (6930835) |  | (230) |  |  | (230) |
| Other | 19037 |  |  |  |  |  |
| **Balances, December 31, 2023** | **115745393** | $**1** | $**1565** | $**2052** | $**(3)** | $**3616** |
| Net income |  |  |  | 770 |  | 770 |
| Other comprehensive income |  |  |  |  | 1 | 1 |
| Net cash dividends declared, $0.76 per share |  |  |  | (87) |  | (87) |
| Issuance of common stock under Employee Stock Purchase Plan | 97500 |  | 3 |  |  | 3 |
| Issuance of common stock upon vesting of RSUs, net of shares used for tax withholdings | 350675 |  | (7) |  |  | (7) |
| Stock-based compensation expense | 39557 |  | 25 |  |  | 25 |
| Purchase of shares under Stock Repurchase Program | (1771191) |  | (85) |  |  | (85) |
| **Balances, December 31, 2024** | **114461934** | $**1** | $**1502** | $**2735** | $**(1)** | $**4237** |
| Net income |  |  |  | 648 |  | 648 |
| Other comprehensive income |  |  |  |  | 2 | 2 |
| Net cash dividends declared, $0.80 per share |  |  |  | (92) |  | (92) |
| Issuance of common stock under Employee Stock Purchase Plan | 167027 |  | 3 |  |  | 3 |
| Issuance of common stock upon vesting of RSUs, and settlement of PSUs, net of shares used for tax withholdings | 364456 |  | (5) |  |  | (5) |
| Stock-based compensation expense | 82193 |  | 29 |  |  | 29 |
| Purchase of shares under Stock Repurchase Program | (444705) |  | (12) |  |  | (12) |
| **Balances, December 31, 2025** | **114630905** | $**1** | $**1517** | $**3291** | $**1** | $**4810** |

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____________________________________________

Note: Prior year amounts may not calculate due to rounding.

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

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**SM ENERGY COMPANY AND SUBSIDIARIES**

**CONSOLIDATED STATEMENTS OF CASH FLOWS**

**(in millions)**

---

| | | | |
|:---|:---|:---|:---|
| | **For the Years Ended December 31,** | **For the Years Ended December 31,** | **For the Years Ended December 31,** |
| | **2025** | **2024** | **2023** |
| Cash flows from operating activities: |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Net income | $648 | $770 | $818 |
| &nbsp;&nbsp;&nbsp;&nbsp;Adjustments to reconcile net income to net cash provided by operating activities: |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Depletion, depreciation, and amortization | 1207 | 809 | 690 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Stock-based compensation expense | 29 | 25 | 20 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Net derivative gain | (178) | (50) | (68) |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Net derivative settlement gain | 132 | 69 | 27 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Amortization of deferred financing costs | 10 | 7 | 5 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Deferred income taxes | 178 | 175 | 88 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Other, net | (29) | (35) | (2) |
| &nbsp;&nbsp;&nbsp;&nbsp;Changes in working capital: |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Accounts receivable | 30 | (86) | (10) |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Prepaid expenses and other | 1 | (13) | (2) |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Accounts payable and accrued expenses | (17) | 109 | 8 |
| **Net cash provided by operating activities** | **2011** | **1783** | **1574** |
| Cash flows from investing activities: |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Capital expenditures | (1438) | (1311) | (989) |
| &nbsp;&nbsp;&nbsp;&nbsp;Acquisition of proved and unproved oil and gas properties | (34) | (2104) | (110) |
| &nbsp;&nbsp;&nbsp;&nbsp;Other, net | 4 | 7 | 1 |
| **Net cash used in investing activities** | **(1468)** | **(3407)** | **(1099)** |
| Cash flows from financing activities: |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Proceeds from revolving credit facility | 1570 | 1019 |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Repayment of revolving credit facility | (1638) | (950) |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Net proceeds from Senior Notes |  | 1477 |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Cash paid to repurchase Senior Notes |  | (349) |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Repurchase of common stock | (13) | (86) | (228) |
| &nbsp;&nbsp;&nbsp;&nbsp;Dividends paid | (92) | (85) | (72) |
| &nbsp;&nbsp;&nbsp;&nbsp;Net proceeds from sale of common stock | 3 | 3 | 3 |
| &nbsp;&nbsp;&nbsp;&nbsp;Other, net | (5) | (20) | (8) |
| **Net cash provided by (used in) financing activities** | **(175)** | **1008** | **(305)** |
| Net change in cash, cash equivalents, and restricted cash | 368 | (616) | 171 |
| Cash, cash equivalents, and restricted cash at beginning of period |  | 616 | 445 |
| **Cash, cash equivalents, and restricted cash at end of period** | $**368** | $**—** | $**616** |

---

____________________________________________

Note: Prior year amounts may not calculate due to rounding.

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

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**SM ENERGY COMPANY AND SUBSIDIARIES**

**CONSOLIDATED STATEMENTS OF CASH FLOWS (Continued)**

**(in millions)**

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| | | | |
|:---|:---|:---|:---|
| | **For the Years Ended December 31,** | **For the Years Ended December 31,** | **For the Years Ended December 31,** |
| | **2025** | **2024** | **2023** |
| **Supplemental schedule of additional cash flow information and non-cash activities:** |  |  |  |
| Operating activities: |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Cash paid for interest, net of capitalized interest <sup>(1)</sup> | $(166) | $(88) | $(87) |
| Investing activities: |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Changes in capital expenditure accruals | $(39) | $(24) | $81 |

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____________________________________________

<sup>(1)</sup> &nbsp;&nbsp;&nbsp;&nbsp;Cash paid for interest, net of capitalized interest during the year ended December 31, 2024, does not include $9 million in fees paid to secure firm commitments for senior unsecured bridge term loans in connection with the Uinta Basin Acquisition.

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

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**SM ENERGY COMPANY AND SUBSIDIARIES**

**NOTES TO CONSOLIDATED FINANCIAL STATEMENTS**

**Note 1 – Summary of Significant Accounting Policies**

*Description of Operations*

SM Energy Company, together with its consolidated subsidiaries, is an independent energy company engaged in the acquisition, exploration, development, and production of oil, gas, and NGLs in Texas, Utah, and as of January 30, 2026, upon closing of the Civitas Merger, Colorado, and New Mexico.

*Basis of Presentation*

The accompanying consolidated financial statements include the accounts of the Company and have been prepared in accordance with GAAP and the instructions to Form 10-K and Regulation S-X. Intercompany accounts and transactions have been eliminated. Additionally, certain prior period amounts have been reclassified to conform to current period presentation in the accompanying consolidated financial statements.

*Use of Estimates in the Preparation of Financial Statements*

The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of proved oil and gas reserves, assets and liabilities, disclosure of contingent assets and liabilities as of the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. Estimates of proved oil and gas reserve quantities provide the basis for the calculation of DD&A expense, impairment of proved and unproved oil and gas properties, acquisitions of oil and gas properties, and asset retirement obligations, each of which represents a significant component of the accompanying consolidated financial statements.

*Cash and Cash Equivalents*

The Company considers all liquid investments purchased with an initial maturity of three months or less and deposits in money market mutual funds that are readily convertible into cash to be cash equivalents. The carrying value of cash and cash equivalents approximates fair value due to the short-term nature of these instruments.

*Accounts Receivable*

The Company's accounts receivable primarily consist of receivables due from oil, gas, and NGL purchasers and from joint interest owners on properties the Company operates. For receivables due from joint interest owners, the Company generally has the ability to withhold future revenue disbursements to recover non-payment of joint interest billings. Generally, the Company's oil, gas, and NGL receivables are collected within 30 to 90 days and the Company has had minimal bad debts. Although diversified among many companies, collectability is dependent upon the financial wherewithal of each individual company and is influenced by the general economic conditions of the industry. Receivables are not collateralized. Refer to *Note 14 – Accounts Receivable and Accounts Payable and Accrued Expenses* for additional disclosure.

*Concentration of Credit Risk and Major Customers*

The Company is exposed to credit risk in the event of nonpayment by counterparties, a significant portion of which are concentrated in energy-related industries. The creditworthiness of customers and other counterparties is regularly reviewed.

The Company does not believe the loss of any single purchaser of its production would materially affect its operating results, as oil, gas, and NGLs are products with well-established markets and numerous purchasers in the Company's operating areas.

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The following major customers and entities under common control accounted for 10 percent or more of the Company's total oil, gas, and NGL production revenue for at least one of the periods presented:

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| | | | | | | |
|:---|:---|:---|:---|:---|:---|:---|
| | **For the Years Ended December 31,** | **For the Years Ended December 31,** | **For the Years Ended December 31,** | **For the Years Ended December 31,** | **For the Years Ended December 31,** | **For the Years Ended December 31,** |
| | **2025** | **2025** | **2024** | **2024** | **2023** | **2023** |
| | **Amount** | **% of total** | **Amount** | **% of total** | **Amount** | **% of total** |
| | **(in millions)** | **(in millions)** | **(in millions)** | **(in millions)** | **(in millions)** | **(in millions)** |
| Major customer #1 | $931 | 28% | $900 | 34% | $581 | 24% |
| Major customer #2 | $212 | 6% | $248 | 9% | $261 | 11% |
| Group of entities under common control | $403 | 12% | $426 | 16% | $530 | 22% |

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For its commodity derivative instruments, the Company's policy is to only enter into contracts with affiliates of the lenders under its Credit Agreement as its derivative counterparties, and each counterparty must have certain minimum investment grade senior unsecured debt ratings.

The Company maintains its primary bank accounts with a large, multinational bank that has branch locations in the Company's areas of operation. The Company's policy is to diversify its concentration of cash and cash equivalent investments among multiple institutions and investment products to limit the amount of credit exposure to any single institution or investment.

*Oil and Gas Producing Activities*

*Proved properties*. The Company follows the successful efforts method of accounting for its oil and gas properties. Under this method, property acquisition costs and development costs are capitalized when incurred. Capitalized drilling and completion costs, including lease and well equipment, intangible development costs, and operational support facilities in the field, are depleted on a pool-by-pool basis (properties aggregated based on geographical and geological characteristics) using the units-of-production method based on estimated net proved developed oil and gas reserves. Similarly, proved leasehold costs are depleted on the same pool-by-pool basis; however, the units-of-production method is based on estimated total net proved oil and gas reserves. The computation of DD&A expense takes into consideration restoration, dismantlement, and abandonment costs as well as the anticipated proceeds from salvaging equipment.

Proved oil and gas properties are evaluated for impairment on a depletion pool-by-pool basis and reduced to fair value when there is an indication that their carrying amount may not be recoverable. The Company estimates future cash flows from all proved reserves and risk adjusted probable and possible reserves using various factors, which are subject to management's judgment and expertise, and include, but are not limited to, commodity price forecasts, estimated future operating and capital costs, development plans, and discount rates to incorporate the risk and current market conditions associated with realizing the expected cash flows. If the carrying amount exceeds the estimated undiscounted future cash flows, an impairment is indicated and the carrying amount is reduced to fair value.

If an impairment is indicated, the Company uses Level 3 inputs and the income valuation technique, which converts future cash flows to a single present value amount, to measure the fair value of proved properties using a discount rate, price and cost forecasts, and certain reserve risk-adjustment factors, as selected by the Company's management. The Company uses a discount rate that represents a current market-based weighted average cost of capital. The discount rate typically ranges from 10 percent to 15 percent. The prices for oil and gas are forecast based on NYMEX strip pricing, adjusted for basis differentials, for the first five years, after which a flat terminal price is used for each commodity stream. The prices for NGLs are forecast using OPIS Mont Belvieu pricing, adjusted for basis differentials, for as long as the market is actively trading, after which a flat terminal price is used. Future operating costs are also adjusted as deemed appropriate for these estimates. Certain undeveloped reserve estimates are also risk-adjusted given the risk to related projected cash flows due to performance and exploitation uncertainties.

The partial sale of a proved property within an existing asset group is accounted for as a normal retirement and no gain or loss on divestiture activity is recognized as long as the treatment does not significantly affect the units-of-production depletion rate. The sale of a partial interest in an individual proved property is accounted for as a recovery of cost. A gain or loss on divestiture activity is recognized in the accompanying statements of operations for all other sales of proved properties.

*Unproved properties*. The unproved oil and gas properties line item on the accompanying consolidated balance sheets ("accompanying balance sheets") consists of the costs incurred to acquire unproved leases. Leasehold costs allocated to those leases, or partial leases that have associated proved reserves recorded, are reclassified to proved properties and depleted on an asset group basis using the units-of-production method based on estimated total proved oil and gas reserves. Unproved oil and gas property costs are evaluated for impairment and reduced to fair value when there is an indication that the carrying costs may not be recoverable. Lease acquisition costs that are not individually significant are aggregated by asset group and the portion of such costs estimated to be nonproductive prior to lease expiration are recognized as a valuation allowance and amortized over the appropriate period. The

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estimate of what could be nonproductive is based on historical trends or other information, including current drilling plans and the Company's intent to renew leases. To measure the fair value of unproved properties, the Company uses an income approach, which takes into account the following significant assumptions: remaining lease terms, future development plans, risk-weighted potential resource recovery, estimated reserve values, and estimated acreage value based on price(s) received for similar, recent acreage transactions by the Company or other market participants.

For the sale of unproved properties where the original cost has been partially or fully amortized by providing a valuation allowance on an asset group basis, neither a gain nor loss is recognized unless the sales price exceeds the original cost of the property, in which case a gain shall be recognized in the accompanying statements of operations in the amount of such excess.

*Exploratory*. Exploratory geological and geophysical, including exploratory seismic studies, and the costs of carrying and retaining unproved acreage are expensed as incurred. Under the successful efforts method of accounting for oil and gas properties, exploratory well costs are initially capitalized pending the determination of whether proved reserves have been discovered. If proved reserves are discovered, exploratory well costs will be capitalized as proved properties and will be accounted for following the successful efforts method of accounting described above. If proved reserves are not found, exploratory well costs are expensed as dry holes. The application of the successful efforts method of accounting requires management's judgment to determine the proper designation of wells as either development or exploratory, which will ultimately determine the proper accounting treatment of costs of dry holes. Once a well is drilled, the determination that proved reserves have been discovered may take considerable time and judgment. Exploratory dry hole costs are included in the cash flows from investing activities section as part of capital expenditures within the accompanying statements of cash flows.

*Other Property and Equipment*

Other property and equipment such as facilities, equipment inventory, office furniture and equipment, buildings, and computer hardware and software, are recorded at cost. The Company capitalizes certain software costs incurred during the application development stage. The application development stage generally includes software design, configuration, testing, and installation activities. Costs of renewals and improvements that substantially extend the useful lives of the assets are capitalized. Maintenance and repair costs are expensed when incurred. Depreciation is calculated using either the straight-line method over the estimated useful lives of the assets, which range from three to 30 years, or the unit of output method when appropriate. When other property and equipment is sold or retired, the capitalized costs and related accumulated depreciation are removed from the Company's accounts.

Facilities and equipment inventory costs are evaluated for impairment and reduced to fair value when there is an indication the carrying costs may not be recoverable. To measure the fair value of facilities and equipment inventory, the Company uses an income valuation technique or market approach depending on the quality of information available to support management's assumptions and the circumstances. For facilities, the valuation includes consideration of the proved and unproved assets supported by the facilities, future cash flows associated with the assets, and fixed costs necessary to operate and maintain the assets.

*Acquisition of proved and unproved properties*

Assets acquired and liabilities assumed in transactions that meet the definition of a business combination under *ASC Topic 805, Business Combinations*, are accounted for using the acquisition method. Identifiable assets acquired and liabilities assumed are recognized separately from goodwill and measured at their estimated fair values as of the acquisition date, with any excess of consideration transferred over the net fair value of the identifiable assets acquired and liabilities assumed recorded as goodwill. The fair value measurements of assets acquired and liabilities assumed are based on inputs that are not observable in the market, and therefore represent Level 3 inputs. The fair values of oil and gas properties are measured using valuation techniques that convert future cash flows to a single discounted amount. Significant inputs to the valuation of oil and natural gas properties include estimates of reserves, future operating and development costs, future commodity prices, estimated future cash flows, reserve adjustment factors, and a market-based weighted average cost of capital. These inputs require significant judgments and estimates by management at the time of the valuation. Transaction and integration costs associated with a business combination are expensed as incurred.

Assets acquired and liabilities assumed under transactions that do not meet the criteria of a business combination under ASC Topic 805, *Business Combinations* are accounted for as an asset acquisition and are recorded based on the fair value of the total consideration transferred on the acquisition date using the lowest observable inputs available.

Refer to *Note 17 – Mergers, Acquisitions, and Divestitures* for additional discussion.

*Asset Retirement Obligations*

The Company recognizes an estimated liability for future costs associated with the abandonment of its oil and gas properties, including facilities requiring decommissioning. A liability for the fair value of an asset retirement obligation and corresponding increase to the carrying value of the related long-lived asset are recorded at the time a well is drilled or acquired, or a facility is constructed. The increase in carrying value is included in the proved oil and gas properties line item in the accompanying balance sheets. The Company depletes the amount added to proved oil and gas property costs and recognizes expense in connection with the accretion of the

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discounted liability over the remaining estimated lives of the respective long-lived assets. Asset retirement obligation accretion expense is included in the depletion, depreciation, and amortization line on the accompanying statements of operations. Cash paid to settle asset retirement obligations is included in the cash flows from operating activities section of the accompanying statements of cash flows.

The Company's estimated asset retirement obligation is based on historical experience in plugging and abandoning wells, estimated lives, estimated plugging and abandonment cost, and federal and state regulatory requirements. The liability is discounted using the credit-adjusted risk-free rate estimated at the time the liability is incurred or revised. The credit-adjusted risk-free rates used to discount the Company's plugging and abandonment liabilities range from 5.5 percent to 12 percent. In periods subsequent to initial measurement of the liability, the Company must recognize period-to-period changes in the liability resulting from the passage of time, revisions to either the amount of the original estimate of undiscounted cash flows or economic life, changes in inflation factors, or the Company's credit-adjusted risk-free rate as market conditions warrant. Refer to *Note 15 – Asset Retirement Obligations* for a reconciliation of the Company's total asset retirement obligation as of December 31, 2025, and 2024.

*Derivative Financial Instruments*

The Company regularly enters into commodity derivative contracts to mitigate a portion of its exposure to oil, gas, and NGL price volatility and location differentials for its expected future oil, gas, and NGL production, and the associated effect on cash flows. All commodity derivative contracts that the Company enters into are for other-than-trading purposes. The Company's commodity derivative contracts generally consist of price swap, collar, and basis swap arrangements. Commodity derivative instruments are measured at fair value and are included in the accompanying balance sheets as derivative assets and liabilities, with the exception of derivative instruments that meet the "normal purchase normal sale" exclusion. The fair value of the Company's commodity derivative contracts is measured based on, among other things, option pricing models, futures prices, volatility, time to maturity, and credit risk. The Company does not designate its commodity derivative contracts as hedging instruments. Accordingly, the Company reflects gains and losses from changes in the fair value of its commodity derivative contracts in the accompanying statements of operations as such changes occur, rather than deferring any such amounts in accumulated other comprehensive income (loss). Gains and losses on net derivative settlements are included within the cash flows from operating activities section of the accompanying statements of cash flows. Refer to *Note 7 – Derivative Financial Instruments* for additional discussion.

*Revenue Recognition*

The Company derives revenue predominately from the sale of produced oil, gas, and NGLs. Revenue reflects the Company's net revenue interest production, including both its working interests and royalty interests. Revenue is recognized at the point in time when custody and title ("control") of the product transfers to the purchaser, which may differ depending on the applicable contractual terms. Transfer of control determines the presentation of transportation, gathering, processing, and other post-production expenses ("costs and other deductions") within the accompanying statements of operations. Costs and other deductions incurred by the Company prior to transfer of control are recorded within the oil, gas, and NGL production expense line item on the accompanying statements of operations. When control is transferred, sales are based on a market price that may be affected by fees and other deductions incurred by the purchaser subsequent to the transfer of control.

Revenue is recorded in the month when performance obligations are satisfied. However, settlement statements from the purchasers of hydrocarbons and the related cash consideration are received 30 to 90 days after production has occurred. As a result, the Company must estimate the amount of production delivered to the customer and the consideration that will ultimately be received for sale of the product. Revenue accruals are recorded monthly as accounts receivable from contracts with customers within the accounts receivable line item on the accompanying balance sheets. The Company uses knowledge of its properties, contractual arrangements, quality and transportation differentials, historical performance, NYMEX, local spot market, and OPIS prices, and other factors as the basis of the accrual estimates. Differences between estimates and the actual amounts received for product sales are recorded in the month payment is received from the purchaser.

In general, the Company generates production revenue from a combination of the following types of contracts:

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• The Company sells oil and gas production at or near the wellhead and receives an agreed-upon market price from the purchaser. Under this type of arrangement, control transfers at or near the wellhead.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• The Company has certain processing arrangements that include the delivery of unprocessed gas to a midstream processor's facility for processing. Upon completion of processing, the midstream processor purchases the NGLs and redelivers residue gas back to the Company in-kind. For the NGLs extracted during processing, the midstream processor remits payment to the Company. For the residue gas taken in-kind, the Company has separate sales contracts where control transfers at points downstream of the processing facility. The Company also has certain oil sales that occur at market locations downstream of the production area. Given the structure of these arrangements and where control transfers, the Company separately recognizes costs and other deductions incurred prior to control transfer. These fees are recorded within the oil, gas, and NGL production expense line item on the accompanying statements of operations.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• The Company has certain arrangements where oil volumes are transported by railcar to purchasers. For these sales arrangements, the Company generally delivers produced oil to customers at defined locations, including domestic rail terminal

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facilities. Upon delivery, the Company is entitled to an agreed upon index price, net of pricing differentials for each barrel sold. The Company recognizes revenue when control transfers to the customer and the Company has no further contractual obligation to the customer. Costs associated with the transportation of these oil volumes are recorded within the oil, gas, and NGL production expense line item on the accompanying statements of operations.

The Company does not believe that significant judgments are required with respect to the determination of the transaction price, including amounts that represent variable consideration, as volume and price carry a low level of estimation uncertainty given the precision of volumetric measurements and the use of index pricing with generally predictable differentials. Accordingly, the Company does not consider estimates of variable consideration to be constrained.

The Company's performance obligations arise upon the production of hydrocarbons from wells in which the Company has an ownership interest. The performance obligations are considered satisfied upon control transferring to a purchaser at the wellhead, inlet, or tailgate of the midstream processor's processing facility, rail terminal, or other contractually specified delivery point. For volumes sold at, or in close proximity to the wellhead or to the inlet or tailgate of the midstream processing facility, the time period between production and satisfaction of performance obligations is generally less than one day. For volumes transported by rail, this period is generally less than two weeks.

Refer to *Note 2 – Revenue from Contracts with Customers* for additional information.

*Stock-Based Compensation*

At December 31, 2025, the Company had stock-based employee compensation plans that included Restricted Stock Units ("RSU" or "RSUs") and Performance Share Units ("PSU or "PSUs") issued to employees, RSUs and restricted stock issued to non-employee directors, and the Company's ESPP available to eligible employees. The Company records expense associated with the fair value of stock-based compensation in accordance with authoritative accounting guidance, which is based on the estimated fair value of these awards determined at the time of grant, and is included within the general and administrative and exploration expense line items in the accompanying statements of operations. For stock-based compensation awards containing non-market based performance conditions, the Company evaluates the probability of the number of shares that are expected to vest, and then adjusts the expense to reflect the number of shares expected to vest and the cumulative vesting period met to date. Further, the Company accounts for forfeitures of stock-based compensation awards as they occur. Refer to *Note 10 – Stock-Based Compensation* for additional discussion*.*

*Income Taxes*

The Company accounts for deferred income taxes whereby deferred tax assets and liabilities are recognized based on the tax effects of temporary differences between the carrying amounts on the accompanying consolidated financial statements and the tax basis of assets and liabilities, as measured using current enacted tax rates. These differences will result in taxable income or deductions in future years when the reported amounts of the assets or liabilities are recorded or settled, respectively. Judgment is required in predicting when these events may occur and whether recovery of an asset is more likely than not. The Company records deferred tax assets and associated valuation allowances, when appropriate, to reflect amounts more likely than not to be realized based upon Company analysis. The Company's federal and state income tax returns are not filed before the consolidated financial statements are prepared. Therefore, the Company estimates the tax basis of its assets and liabilities at the end of each period, as well as the effects of tax rate changes, tax credits, and net operating and capital loss carryforwards and carrybacks. Adjustments related to differences between the estimates used and actual amounts reported are recorded in the periods in which the income tax returns are filed. The cumulative effect of enacted tax rate changes on the net balance of reported amounts of assets and liabilities is recognized in the period of enactment. The Company's policy is to record interest related to income taxes in the interest expense line item in the accompanying statements of operations, and to record penalties related to income taxes in the other non-operating expense line item in the accompanying statements of operations. Refer to *Note 4 – Income Taxes* for additional discussion.

*Earnings per Share*

The Company uses the treasury stock method to determine the effect of potentially dilutive instruments. Refer to *Note 9 – Earnings Per Share* for additional discussion.

*Comprehensive Income (Loss)*

Comprehensive income (loss) is used to refer to net income (loss) plus other comprehensive income (loss). Other comprehensive income (loss) is comprised of revenues, expenses, gains, and losses that, under GAAP, are reported as separate components of stockholders' equity instead of net income (loss). Comprehensive income (loss) is presented net of income taxes in the accompanying consolidated statements of comprehensive income. The Company's policy for releasing income tax effects within accumulated other comprehensive income (loss) is an incremental, unit-of-account approach. Refer to *Note 12 – Pension Benefits* for detail on adjustments impacting other comprehensive income.

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*Fair Value of Financial Instruments*

The Company's financial instruments, including cash and cash equivalents, accounts receivable, and accounts payable are carried at cost, which approximates fair value due to the short-term maturity of these instruments. The Company's Senior Notes, as defined in *Note 5 – Long-Term Debt*, are recorded at cost, net of unamortized deferred financing costs, and their respective fair values are disclosed in *Note 8 – Fair Value Measurements.* Additionally, the Company has derivative financial instruments that are recorded at fair value. Considerable judgment is required to develop estimates of fair value. The estimates provided are not necessarily indicative of the amounts the Company would realize upon the sale or refinancing of such instruments.

*Leases*

The Company accounts for leases in accordance with ASC Topic 842, *Leases*, ("Topic 842"), which requires lessees to recognize operating and finance leases with terms greater than 12 months on the balance sheet. The Company evaluates a contractual arrangement at its inception to determine if it is a lease or contains an identifiable lease component. Certain leases may contain both lease and non-lease components. The Company's policy for all asset classes is to combine lease and non-lease components together and account for the arrangement as a single lease.

Certain assumptions and judgments made by the Company when evaluating a contract that meets the definition of a lease under Topic 842 include those to determine the discount rate and lease term. Unless implicitly defined, the Company determines the present value of future lease payments using an estimated incremental borrowing rate based on a yield curve analysis that factors in certain assumptions, including the term of the lease and credit rating of the Company at lease inception. The Company evaluates each contract containing a lease arrangement at inception to determine the length of the lease term when recognizing a right-of-use ("ROU") asset and corresponding lease liability. When determining the lease term, options available to extend or early terminate the arrangement are evaluated and included when it is reasonably certain an option will be exercised. Exercising an early termination option may result in an early termination penalty depending on the terms of the underlying agreement. The Company excludes from the balance sheet leases with terms that are less than one year.

An ROU asset represents a lessee's right to use an underlying asset for the lease term, while the associated lease liability represents the lessee's obligations to make lease payments. At the commencement date, which is the date on which a lessor makes an underlying asset available for use by a lessee, a lease ROU asset and corresponding lease liability is recognized based on the present value of the future lease payments. The initial measurement of lease payments may also be adjusted for certain items, including options that are reasonably certain to be exercised, such as options to purchase the asset at the end of the lease term, or options to extend or early terminate the lease. Excluded from the initial measurement of an ROU asset and corresponding lease liability are certain variable lease payments, such as payments made that vary depending on actual usage or performance.

Subsequent to initial measurement, costs associated with the Company's operating leases are either expensed or capitalized depending on how the underlying ROU asset is utilized and in accordance with GAAP requirements. When calculating the Company's ROU asset and liability for a contractual arrangement that qualifies as an operating lease, the Company considers all of the necessary payments made or that are expected to be made upon commencement of the lease. As discussed above, excluded from the initial measurement are certain variable lease payments, which for the Company's drilling rigs, completion crews, and midstream agreements, may be a significant component of the total lease costs. Refer to *Note 13 – Leases* for additional discussion.

*Industry, Geographic, and Segment Information*

The Company operates in the oil and gas extraction industry, focused on exploration and production activities, onshore in the United States. The Company has one reportable segment. Refer to *Note 11 – Segment Reporting* for additional discussion.

*Off-Balance Sheet Arrangements*

The Company has not participated in transactions that generate relationships with unconsolidated entities or financial partnerships, such as entities often referred to as structured finance or SPEs, which would have been established for the purpose of facilitating off-balance sheet arrangements or other contractually narrow or limited purposes.

The Company evaluates its transactions to determine if any variable interest entities exist. If it is determined that the Company is the primary beneficiary of a variable interest entity, that entity is consolidated into the Company's consolidated financial statements. The Company has not been involved in any unconsolidated SPE transactions during 2025 or 2024, or through the filing of this report.

*Recently Issued Accounting Guidance*

In November 2024, the FASB issued ASU No. 2024-03, *Income Statement - Reporting Comprehensive Income - Expense Disaggregation Disclosures (Subtopic 220-40): Disaggregation of Income Statement Expenses* ("ASU 2024-03"). ASU 2024-03 was issued to improve disclosures about a public business entity's expenses and address requests from investors for more detailed information about the types of expenses in commonly presented expense captions. ASU 2024-03 is effective for the fiscal years

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beginning after December 15, 2026, and interim reporting periods beginning after December 15, 2027, with early adoption permitted. The guidance is to be applied on a prospective basis; however, retrospective application is permitted. The Company is within the scope of this ASU and expects to adopt ASU 2024-03 on January 1, 2027, on a prospective basis, and adoption will result in new disclosures beginning with the 2027 Form 10-K, as prescribed by the guidance.

In December 2023, the FASB issued ASU No. 2023-09, *Income Taxes (Topic 740): Improvements to Income Tax Disclosures* ("ASU 2023-09")*.* ASU 2023-09 was issued to improve the disclosures related to rate reconciliations and income taxes paid. ASU 2023-09 was effective for annual periods beginning after December 15, 2024, with early adoption permitted. The guidance is to be applied on a prospective basis; however, retrospective application is permitted. The Company adopted ASU 2023-09 on January 1, 2025, on a prospective basis, and has included the required new disclosures in this report.

As of December 31, 2025, and through the filing of this report, no other accounting guidance has been issued and not yet adopted that is applicable to the Company and that would have a material effect on the Company's consolidated financial statements and related disclosures.

**Note 2 – Revenue from Contracts with Customers**

The Company recognizes its share of revenue from the sale of produced oil, gas, and NGLs from its Midland Basin, South Texas, and Uinta Basin assets. Oil, gas, and NGL production revenue presented within the accompanying statements of operations reflects revenue generated from contracts with customers.

The tables below present oil, gas, and NGL production revenue by product type for each of the Company's operating areas.

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| | | | | |
|:---|:---|:---|:---|:---|
| | **For the year ended December 31, 2025** | **For the year ended December 31, 2025** | **For the year ended December 31, 2025** | **For the year ended December 31, 2025** |
| | **Midland Basin** | **South Texas** | **Uinta Basin** | **Total** |
| | **(in millions)** | **(in millions)** | **(in millions)** | **(in millions)** |
| Oil production revenue | $1249 | $465 | $847 | $2561 |
| Gas production revenue | 122 | 203 | 28 | 353 |
| NGL production revenue | 1 | 223 |  | 224 |
| &nbsp;&nbsp;&nbsp;&nbsp;Total | $1372 | $891 | $875 | $3138 |
| Relative percentage | 44% | 28% | 28% | 100% |

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| | | | | |
|:---|:---|:---|:---|:---|
| | **For the year ended December 31, 2024** | **For the year ended December 31, 2024** | **For the year ended December 31, 2024** | **For the year ended December 31, 2024** |
| | **Midland Basin** | **South Texas** | **Uinta Basin** | **Total** |
| | **(in millions)** | **(in millions)** | **(in millions)** | **(in millions)** |
| Oil production revenue | $1448 | $543 | $197 | $2187 |
| Gas production revenue | 118 | 124 | 7 | 249 |
| NGL production revenue | 1 | 234 |  | 235 |
| &nbsp;&nbsp;&nbsp;&nbsp;Total | $1567 | $900 | $204 | $2671 |
| Relative percentage | 59% | 34% | 7% | 100% |

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____________________________________________

Note: Amounts may not calculate due to rounding.

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| | | | |
|:---|:---|:---|:---|
| | **For the year ended December 31, 2023** | **For the year ended December 31, 2023** | **For the year ended December 31, 2023** |
| | **Midland Basin** | **South Texas** | **Total** |
| | **(in millions)** | **(in millions)** | **(in millions)** |
| Oil production revenue | $1348 | $466 | $1814 |
| Gas production revenue | 175 | 153 | 328 |
| NGL production revenue | 1 | 222 | 222 |
| &nbsp;&nbsp;&nbsp;&nbsp;Total | $1524 | $840 | $2364 |
| Relative percentage | 64% | 36% | 100% |

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____________________________________________

Note: Amounts may not calculate due to rounding.

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As of December 31, 2025, there were no material unsatisfied or partially unsatisfied performance obligations.

The accounts receivable balances from contracts with customers within the accompanying balance sheets as of December 31, 2025, and 2024, were $193 million and $246 million, respectively.

**Note 3 – Equity**

*Stock Repurchase Program*

The Company's stock repurchase program permits the repurchase of up to $500 million in aggregate value of its common stock through December 31, 2027. The Stock Repurchase Program permits the Company to repurchase shares of its common stock from time to time in open market transactions, through privately negotiated transactions or by other means in accordance with federal securities laws and subject to certain provisions of the Credit Agreement and the indentures governing the Senior Notes, as defined in *Note 5 – Long-Term Debt*. The timing, as well as the number and value of shares repurchased under the Stock Repurchase Program, will be determined by certain authorized officers of the Company at their discretion and will depend on a variety of factors, including the market price of the Company's common stock, general market and economic conditions and applicable legal requirements. The value of shares authorized for repurchase by the Board of Directors does not require the Company to repurchase such shares or guarantee that such shares will be repurchased, and the Stock Repurchase Program may be suspended, modified, or discontinued at any time without prior notice. No assurance can be given that any particular number or dollar value of its shares will be repurchased by the Company.

The following table presents activity under the Company's Stock Repurchase Program:

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| | | | |
|:---|:---|:---|:---|
| | **For the Years Ended December 31,** | **For the Years Ended December 31,** | **For the Years Ended December 31,** |
| | **2025** | **2024** | **2023** |
| Shares of common stock repurchased <sup>(1)</sup> | 444705 | 1771191 | 6930835 |
| Weighted-average price per share <sup>(2)</sup> | $27.25 | $47.40 | $32.89 |
| Cost of shares of common stock repurchased (in millions) <sup>(2) (3)</sup> | $12 | $84 | $228 |

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____________________________________________

<sup>(1)&nbsp;&nbsp;&nbsp;&nbsp;</sup>All repurchased shares of the Company's common stock were retired upon repurchase.

<sup>(2)&nbsp;&nbsp;&nbsp;&nbsp;</sup>Amounts exclude excise taxes, commissions, and fees.

<sup>(3)&nbsp;&nbsp;&nbsp;&nbsp;</sup>Amounts may not calculate due to rounding.

As of December 31, 2025, $488 million remained available for repurchases of the Company's outstanding common stock through December 31, 2027, under the Stock Repurchase Program.

*Dividends*

During 2025, the Company had a fixed dividend of $0.80 per share annually, paid in quarterly increments of $0.20 per share. During the year ended December 31, 2025, net cash dividends declared totaled $92 million. In February of 2026, the Company's Board of Directors approved a 10 percent increase to the Company's annual base dividend to $0.88 per share, payable quarterly, effective beginning with the March 2026 dividend.

*Common Stock*

Refer to *Note 17 – Mergers, Acquisitions, and Divestitures* for discussion of the impact of the Civitas Merger on the Company's authorized, issued, and outstanding common stock.

**Note 4 – Income Taxes**

Effective January 1, 2025, the Company adopted ASU 2023-09, Income Taxes (Topic 740): Improvements to Income Tax Disclosures. The amendments were applied prospectively and primarily affect the Company's annual income tax disclosures, including enhanced effective tax rate reconciliation and income taxes paid information, as presented below.

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The provision for income taxes consisted of the following:

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| | | | |
|:---|:---|:---|:---|
| | **For the Years Ended December 31,** | **For the Years Ended December 31,** | **For the Years Ended December 31,** |
| | **2025** | **2024** | **2023** |
| | **(in millions)** | **(in millions)** | **(in millions)** |
| Current portion of income tax (expense) benefit |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Federal | $2 | $(18) | $(8) |
| &nbsp;&nbsp;&nbsp;&nbsp;State | (6) | (3) |  |
| Deferred portion of income tax expense | (178) | (175) | (88) |
| Income tax expense | $(182) | $(196) | $(96) |

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The components of the net deferred tax liabilities are as follows:

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| | | |
|:---|:---|:---|
| | **As of December 31,** | **As of December 31,** |
| | **2025** | **2024** |
| | **(in millions)** | **(in millions)** |
| &nbsp;&nbsp;Deferred tax liabilities: |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Oil and gas properties excluding asset retirement obligation | $792 | $596 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Derivative assets | 19 | 8 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Other | 8 | 6 |
| &nbsp;&nbsp;&nbsp;&nbsp;Total deferred tax liabilities | 819 | 611 |
| &nbsp;&nbsp;Deferred tax assets: |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Asset retirement obligation liabilities | 35 | 33 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Credit carryover, net | 44 | 19 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Lease liabilities | 6 | 4 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Legal liabilities | 3 | 3 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Federal and state tax net operating loss carryovers | 3 | 3 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Equity compensation | 3 | 2 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Other | 2 | 3 |
| &nbsp;&nbsp;&nbsp;&nbsp;Total deferred tax assets | 96 | 67 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Valuation allowance | (1) | (1) |
| &nbsp;&nbsp;&nbsp;&nbsp;Net deferred tax assets | 95 | 66 |
| Net deferred tax liabilities | $724 | $545 |
| Current federal income tax refundable (payable) | $— | $2 |
| Current state income tax refundable (payable) | $2 | $— |

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____________________________________________

Note: Amounts may not calculate due to rounding.

As of December 31, 2025, the Company had gross state NOL carryforwards of $67 million. Other than in states with no NOL carryforward expiration, the Company's state NOL carryforwards expire between 2035 and 2039. The Company's current valuation allowance includes an amount for state NOL carryforwards, which are expected to expire before they can be utilized.

Income tax expense or benefit differs from the amount that would be calculated by applying the statutory United States federal income tax rate to income or loss before income taxes. These differences primarily relate to the effect of federal and state tax credits, state income taxes, excess tax benefits and deficiencies from stock-based compensation awards, tax deduction limitations on compensation of covered individuals, the cumulative effect of other smaller permanent differences, and can also reflect the cumulative

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effect of an enacted tax rate change, in the period of enactment, on the Company's net deferred tax asset and liability balances. These differences for the years ended December 31, 2025, 2024, and 2023, are presented below:

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| | | | | | | |
|:---|:---|:---|:---|:---|:---|:---|
| | **For the Years Ended December 31,** | **For the Years Ended December 31,** | **For the Years Ended December 31,** | **For the Years Ended December 31,** | **For the Years Ended December 31,** | **For the Years Ended December 31,** |
| | **2025** | **2025** | **2024** | **2024** | **2023** | **2023** |
|  | **Amount** | **Percent** | **Amount** | **Percent** | **Amount** | **Percent** |
| | **(in millions)** | **(in millions)** | **(in millions)** | **(in millions)** | **(in millions)** | **(in millions)** |
| U.S. Federal statutory tax rate | $(174) | 21.0% | $(203) | 21.0% | $(192) | 21.0% |
| R&D and other tax credits | 18 | (2.1) | 17 | (1.8) | 92 | (10.1) |
| Change in valuation allowance |  |  | 1 | (0.1) |  |  |
| State tax (expense) benefit, net of federal effect <sup>(1)</sup> | (22) | 2.6 | (9) | 0.9 | 5 | (0.6) |
| Nontaxable and nondeductible Items | (4) | 0.5 |  |  |  |  |
| Other |  |  | (1) | 0.3 | (2) | 0.2 |
| Effective tax rate | $(182) | 22.0% | $(196) | 20.3% | $(96) | 10.5% |

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____________________________________________

Note: Amounts may not calculate due to rounding.

<sup>(1)&nbsp;&nbsp;&nbsp;&nbsp;</sup>For the year ended December 31, 2025, state taxes in Texas and Utah made up the majority (greater than 50 percent) of the tax effect in this category.

Acquisitions, divestitures, drilling activity, and basis differentials, which impact the prices received for oil, gas, and NGLs, impact the apportionment of taxable income to the states where the Company owns oil and gas properties. Transporting oil from the location where it is produced to the different markets where it may be sold affects the apportionment of income taxes. As these factors change, the Company's state income tax rate changes. This change, when applied to the Company's total temporary differences, impacts the total state income tax expense reported. Items affecting state apportionment factors are evaluated upon completion of the prior year income tax return, after significant acquisitions and divestitures, if there are significant changes in drilling activity, or if estimated state revenue changes occur during the year.

The Company completed a multi-year R&D credit study in 2023, which resulted in a favorable adjustment to the Company's effective tax rate for the year ended December 31, 2023, and a reduction of the Company's 2023 tax obligation. After utilizing a portion of the credits for the 2023 and 2024 tax years, the recorded net carryover R&D credit, as of December 31, 2025, expected to be utilized in future periods totaled $44 million. The R&D credits expire between 2042 and 2045.

On July 4, 2025, the OBBBA was enacted into law introducing changes to corporate tax provisions. The Company recorded the impact of this legislation on full-year income tax expense during the third quarter of 2025. As part of its evaluation of the OBBBA, and in accordance with ASC 740, the Company recorded increases to its deferred tax assets and liabilities. The adjustment to its deferred tax assets did not result in a change to the Company's valuation allowance. Additionally, the Company recorded decreases to its current portion of income tax expense and current income taxes payable. These decreases were primarily attributable to the following provisions of the OBBBA: (i) reinstatement of the immediate expensing of domestic research and development ("R&D") costs; (ii) allowance for the deduction of prior year capitalized and unamortized R&D costs; and (iii) the extension of 100 percent bonus depreciation for qualified property placed in service. The OBBBA also reinstated the option to elect a reduced R&D credit over capitalizing certain costs, which impacted the Company's effective tax rate for the twelve months ended December 31, 2025.

For all years before 2022, the Company is generally no longer subject to United States federal or state income tax examinations by tax authorities.

The Company complies with authoritative accounting guidance regarding uncertain tax provisions. The entire amount of unrecognized tax benefit reported by the Company would affect its effective tax rate if recognized.

The total amount recorded for unrecognized tax benefits is presented below:

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| | | | |
|:---|:---|:---|:---|
| | **For the Years Ended December 31,** | **For the Years Ended December 31,** | **For the Years Ended December 31,** |
| | **2025** | **2024** | **2023** |
| | **(in millions)** | **(in millions)** | **(in millions)** |
| Beginning balance | $29 | $24 | $— |
| Additions based on tax positions related to current year | 2 | 5 | 24 |
| Ending balance | $31 | $29 | $24 |

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Income taxes paid (net of refunds) were as follows:

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| | | | |
|:---|:---|:---|:---|
| | **For the Years Ended December 31,** | **For the Years Ended December 31,** | **For the Years Ended December 31,** |
| | **2025** | **2024** | **2023** |
| | **(in millions)** | **(in millions)** | **(in millions)** |
| Federal | $(4) | $26 | $3 |
| State | 8 | 1 | 6 |
| Total | $4 | $27 | $9 |

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Income taxes paid (net of refunds) exceeded five percent of total income taxes paid (net of refunds) in the following jurisdictions:

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| | |
|:---|:---|
| | **For the Year Ended December 31,** |
| | **2025** |
| | **(in millions)** |
| State |  |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Texas | $2 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Utah | 1 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Delaware | 2 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Oklahoma | 3 |

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**Note 5 – Long-Term Debt**

*Credit Agreement*

The Company's Credit Agreement provides for a senior secured revolving credit facility with a maximum loan amount of $3.0 billion. As of December 31, 2025, the borrowing base and aggregate revolving lender commitments under the Credit Agreement were $3.0 billion and $2.0 billion, respectively. The revolving credit facility is secured by substantially all of the Company's proved oil and gas properties. The borrowing base is subject to regular, semi-annual redetermination, and considers the value of both the Company's proved oil and gas properties reflected in the Company's most recent reserve report; and commodity derivative contracts, each as determined by the Company's lender group. The next borrowing base redetermination date is scheduled to occur on April 1, 2026.

*Third Amendment*. On October 13, 2025, the Company and its lenders entered into the Third Amendment to the Credit Agreement ("Third Amendment") to amend certain provisions related to the maturity date of the Credit Agreement. The Third Amendment amends the springing maturity provision of the Credit Agreement and provides that the maturity date of the Credit Agreement of October 1, 2029, can be accelerated in the event that (i) the outstanding balance of all Senior Notes and other unsecured indebtedness that matures within 91 days exceeds $50 million in the aggregate, and (ii) the Company's borrowing availability under the Credit Agreement, less the aggregate amount of outstanding Senior Notes and other unsecured indebtedness that matures within 91 days, is less than 20 percent of the current revolving loan commitment amount.

*Fourth Amendment*. On January 30, 2026, the Company and its lenders entered into the Fourth Amendment to the Credit Agreement ("Fourth Amendment") in connection with the closing of the Civitas Merger to, among other things: (i) permit the assumption of outstanding Civitas senior unsecured notes and add the subsidiaries of Civitas as guarantors under the Credit Agreement, (ii) extend the scheduled maturity date for elected revolving commitments to January 30, 2031, (iii) increase the aggregate revolving lender commitments available under the Credit Agreement from $2.0 billion to $2.5 billion and add three new lender counterparties, (iv) increase the borrowing base from $3.0 billion to $5.0 billion, (v) eliminate the credit spread adjustment applicable to term SOFR loans (as defined in the Credit Agreement), and (vi) make certain other amendments to the financial covenant definitions and provide additional flexibility under certain affirmative covenants, negative covenants and events of default.

Interest and commitment fees associated with the revolving credit facility are accrued based on a total revolving commitments utilization grid set forth in the Credit Agreement, and as presented in the table below. At the Company's election, borrowings under the Credit Agreement may be in the form of SOFR revolving loans, Alternate Base Rate ("ABR") revolving loans, or Swingline loans. SOFR revolving loans accrue interest at SOFR plus the applicable margin from the utilization grid, and ABR revolving loans and Swingline loans accrue interest at a market-based floating rate, plus the applicable margin from the utilization grid. Commitment fees are accrued on the unused portion of the aggregate revolving lender commitment amount at rates from the utilization grid.

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| | | | | | |
|:---|:---|:---|:---|:---|:---|
| **Total Revolving Commitments Utilization Percentage** | **<25%** | **≥25% <50%** | **≥50% <75%** | **≥75% <90%** | **≥90%** |
| SOFR Revolving Loans | 1.750% | 2.000% | 2.250% | 2.500% | 2.750% |
| ABR Revolving Loans or Swingline Loans | 0.750% | 1.000% | 1.250% | 1.500% | 1.750% |
| Commitment Fee Rate | 0.375% | 0.375% | 0.500% | 0.500% | 0.500% |

---

The following table presents the outstanding balance, total amount of letters of credit outstanding, and available borrowing capacity under the Credit Agreement:

---

| | | | |
|:---|:---|:---|:---|
| | **As of February 2, 2026** | **As of December 31, 2025** | **As of December 31, 2024** |
| | **(in millions)** | **(in millions)** | **(in millions)** |
| Revolving credit facility <sup>(1)</sup> | $— | $— | $69 |
| Letters of credit <sup>(2)</sup> | 4 | 2 | 2 |
| Available borrowing capacity | 2496 | 1999 | 1930 |
| Total aggregate revolving lender commitment amount | $2500 | $2000 | $2000 |

---

____________________________________________

Note: Amounts may not calculate due to rounding.

<sup>(1)&nbsp;&nbsp;&nbsp;&nbsp;</sup>Unamortized deferred financing costs attributable to the revolving credit facility are presented as a component of the other noncurrent assets line item on the accompanying balance sheets and totaled $15 million and $19 million as of December 31, 2025, and 2024, respectively. These costs are being amortized over the term of the Credit Agreement on a straight-line basis.

<sup>(2)&nbsp;&nbsp;&nbsp;&nbsp;</sup>Letters of credit outstanding reduce the amount available under the revolving credit facility on a dollar-for-dollar basis.

*Senior Notes*

The Company's Senior Notes, net line item on the accompanying balance sheets as of December 31, 2025, and 2024, consisted of the following (collectively referred to as "Senior Notes"):

---

| | | | | | | |
|:---|:---|:---|:---|:---|:---|:---|
| | **As of December 31, 2025** | **As of December 31, 2025** | **As of December 31, 2025** | **As of December 31, 2024** | **As of December 31, 2024** | **As of December 31, 2024** |
| | **Principal Amount** | **Unamortized Deferred Financing Costs** | **Principal Amount, Net** | **Principal Amount** | **Unamortized Deferred Financing Costs** | **Principal Amount, Net** |
| | **(in millions)** | **(in millions)** | **(in millions)** | **(in millions)** | **(in millions)** | **(in millions)** |
| 6.75% Senior Notes due 2026 <sup>(1)</sup> | $419 | $— | $419 | $419 | $1 | $418 |
| 6.625% Senior Notes due 2027 | 417 | 1 | 416 | 417 | 2 | 415 |
| 6.5% Senior Notes due 2028 | 400 | 3 | 397 | 400 | 4 | 396 |
| 6.75% Senior Notes due 2029 | 750 | 8 | 742 | 750 | 10 | 740 |
| 7.0% Senior Notes due 2032 | 750 | 10 | 740 | 750 | 11 | 739 |
| Total | $2736 | $22 | $2714 | $2736 | $28 | $2708 |

---

____________________________________________

<sup>(1)&nbsp;&nbsp;&nbsp;&nbsp;</sup>As of December 31, 2025, the 6.75% Senior Notes due 2026, as defined below, are presented in the current liabilities section of the accompanying balance sheets.

*2026 Senior Notes.* On September 12, 2016, the Company issued $500 million in aggregate principal amount of 6.75% Senior Notes due 2026, at par, which mature on September 15, 2026 ("2026 Senior Notes"). The Company received net proceeds of $492 million after deducting fees of $8 million.

*2027 Senior Notes.* On August 20, 2018, the Company issued $500 million in aggregate principal amount of 6.625% Senior Notes due 2027, at par, which mature on January 15, 2027 ("2027 Senior Notes"). The Company received net proceeds of $492 million after deducting fees of $8 million.

*2028 Senior Notes.* On June 23, 2021, the Company issued $400 million in aggregate principal amount of 6.5% Senior Notes due 2028, at par, which mature on July 15, 2028 ("2028 Senior Notes"). The Company received net proceeds of $393 million after deducting fees of $7 million.

------

*2029 Senior Notes*. On July 25, 2024, the Company issued $750 million in aggregate principal amount of 6.75% Senior Notes due 2029, at par, which mature on August 1, 2029 ("2029 Senior Notes"). The Company received net proceeds of $739 million after deducting fees of $12 million.

*2032 Senior Notes*. On July 25, 2024, the Company issued $750 million in aggregate principal amount of 7.0% Senior Notes due 2032, at par, which mature on August 1, 2032 ("2032 Senior Notes"). The Company received net proceeds of $739 million after deducting fees of $12 million.

*Civitas Senior Notes.* In connection with the Civitas Merger on January 30, 2026, the Company assumed approximately $4.9 billion in aggregate principal amount of additional senior notes with maturities through 2033.

*Senior Notes Activity*

On August 26, 2024, the Company redeemed the entirety of the $349 million of aggregate principal amount outstanding of its 2025 Senior Notes, pursuant to the terms of the indenture governing the 2025 Senior Notes, which provided for a redemption price equal to 100 percent of the principal amount outstanding of the 2025 Senior Notes on the date of redemption, plus accrued and unpaid interest. Upon redemption, the Company recorded an immaterial loss on extinguishment of debt related to the accelerated expense recognition of the remaining unamortized deferred financing costs. The Company canceled all redeemed 2025 Senior Notes upon settlement.

The Senior Notes are unsecured senior obligations and rank equal in right of payment with all of the Company's existing and any future unsecured senior debt and are senior in right of payment to any future subordinated debt. The Company may redeem some or all of its Senior Notes prior to their maturity at redemption prices that may include a premium, plus accrued and unpaid interest as described in the indentures governing the Senior Notes. Fees incurred upon issuance of each series of Senior Notes are being amortized as deferred financing costs over the life of the respective notes, unless earlier redeemed or retired, in which case amortization has been proportionately accelerated.

*Covenants*

The Company is subject to certain financial and non-financial covenants under the Credit Agreement and the indentures governing the Senior Notes that, among other terms, limit the Company's ability to incur additional indebtedness, make restricted payments including dividends, sell assets, create liens that secure debt, enter into transactions with affiliates, make certain investments, or merge or consolidate with other entities. The financial covenants under the Credit Agreement require that the Company's (a) total funded debt, as defined in the Credit Agreement, to 12-month trailing adjusted EBITDAX ratio cannot be greater than 3.50 to 1.00 on the last day of each fiscal quarter; and (b) adjusted current ratio, as defined in the Credit Agreement, cannot be less than 1.00 to 1.00 as of the last day of any fiscal quarter. The Company was in compliance with all covenants under the Credit Agreement and the indentures governing the Senior Notes as of December 31, 2025, and through the filing of this report.

*Capitalized Interest*

Capitalized interest costs for the years ended December 31, 2025, 2024, and 2023, totaled $34 million, $26 million, and $20 million, respectively. The amount of interest the Company capitalizes generally fluctuates based on the amount borrowed, the Company's capital program, and the timing and amount of costs associated with capital projects that are considered in progress. Capitalized interest costs are included in total costs incurred. Refer to *Costs Incurred* in *Supplemental Oil and Gas Information (unaudited)* in Part II, Item 8 of this report for additional information.

------

**Note 6 – Commitments and Contingencies**

*Commitments*

As of December 31, 2025, the Company had entered into various types of agreements as discussed below. The following table presents the annual minimum payments related to these agreements for the next five years, and the total minimum payments thereafter as of December 31, 2025:

---

| | | | | | | | |
|:---|:---|:---|:---|:---|:---|:---|:---|
| | **For the Years Ending December 31,** | **For the Years Ending December 31,** | **For the Years Ending December 31,** | **For the Years Ending December 31,** | **For the Years Ending December 31,** | **For the Years Ending December 31,** | **For the Years Ending December 31,** |
| | **2026** | **2027** | **2028** | **2029** | **2030** | **Thereafter** | **Total** |
| | **(in millions)** | **(in millions)** | **(in millions)** | **(in millions)** | **(in millions)** | **(in millions)** | **(in millions)** |
| Delivery commitments <sup>(1) (2)</sup> | $46 | $32 | $20 | $4 | $4 | $7 | $113 |
| Drilling rig contracts <sup>(3)</sup> | 29 |  |  |  |  |  | 29 |
| Office space leases <sup>(4)</sup> | 5 | 5 | 5 | 5 | 5 | 21 | 46 |
| Electrical power purchase contracts | 17 | 17 | 17 | 2 |  |  | 53 |
| Compression service contracts | 23 | 17 | 7 | 3 | 1 |  | 51 |
| Railcar agreements | 16 | 15 | 11 | 8 | 3 | 3 | 56 |
| Other <sup>(5)</sup> | 12 | 9 | 3 |  |  |  | 24 |
| Total | $148 | $95 | $63 | $22 | $13 | $31 | $372 |

---

____________________________________________

Note: The Company does not expect to incur material penalties or shortfalls with regard to its commitments.

<sup>(1)&nbsp;&nbsp;&nbsp;&nbsp;</sup>The Company has transportation throughput, terminal services, transloading, and delivery commitments with various third-parties that require delivery of a minimum amount of oil. As of December 31, 2025, the Company had commitments to deliver a minimum of 49 MMBbl of oil through December of 2032. Certain of these oil delivery commitments may be fulfilled with the same single barrel of oil. The Company would be required to make periodic deficiency payments for any shortfalls in delivering the minimum volume commitments under certain agreements.

<sup>(2)&nbsp;&nbsp;&nbsp;&nbsp;</sup>The Company expects to fulfill the delivery commitments from a combination of production from existing productive wells, future development of net proved undeveloped reserves, and future development of resources not yet characterized as proved reserves. Under certain of the Company's commitments, if the Company is unable to deliver the minimum quantity from its production, it may deliver production acquired from third-parties to satisfy its minimum volume commitments.

<sup>(3)&nbsp;&nbsp;&nbsp;&nbsp;</sup>As of December 31, 2025, the Company's drilling rig commitments had contract terms extending through the third quarter of 2026. If all of these contracts were terminated as of December 31, 2025, the Company would avoid a portion of the contractual service commitments; however, the Company would be required to pay $20 million in early termination fees. No material expenses related to early termination or standby fees were incurred by the Company during the year ended December 31, 2025.

<sup>(4)&nbsp;&nbsp;&nbsp;&nbsp;</sup>The Company leases office space under various operating leases, including maintenance, with certain terms extending into 2035. Rent expense was $3 million, $2 million, and $3 million for the years ended December 31, 2025, 2024, and 2023, respectively.

<sup>(5)&nbsp;&nbsp;&nbsp;&nbsp;</sup>Primarily consists of IT contracts, water purchase agreements, a sand purchase agreement, and vehicle leases.

*Contingencies*

The Company is subject to litigation and claims arising in the ordinary course of business. The Company accrues for such items when a liability is both probable and the amount can be reasonably estimated. As of the filing of this report, in the opinion of management, the anticipated results of any pending litigation and claims are not expected to have a material effect on the results of operations, the financial position, or the cash flows of the Company.

**Note 7 – Derivative Financial Instruments**

*Summary of Oil, Gas, and NGL Derivative Contracts in Place*

The Company regularly enters into commodity derivative contracts to mitigate a portion of its exposure to oil, gas, and NGL price volatility and location differentials, and the associated effect on cash flows. All commodity derivative contracts that the Company enters into are for other-than-trading purposes. The Company's commodity derivative contracts consist of price swap and collar arrangements for oil and gas production, and price swap arrangements for NGL production. In a typical commodity swap agreement, if the agreed upon published third-party index price ("index price") is lower than the swap price, the Company receives the difference between the index price and the agreed upon swap price. If the index price is higher than the swap price, the Company pays the difference. For collar arrangements, the Company receives the difference between an agreed upon index price and the floor price if the index price is below the floor price. The Company pays the difference between the agreed upon ceiling price and the index price if the index price is above the ceiling price. No amounts are paid or received if the index price is between the floor and ceiling prices.

------

The Company has entered into fixed price oil and gas basis swaps in order to mitigate exposure to adverse pricing differentials between certain industry benchmark prices and the actual physical pricing points where the Company's production is sold. As of December 31, 2025, the Company had basis swap contracts with fixed price differentials between:

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• NYMEX WTI and Argus WTI Midland ("WTI Midland") for a portion of its Midland Basin oil production with sales contracts that settle at WTI Midland prices;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• NYMEX WTI and Argus WTI Houston Magellan East Houston Terminal ("WTI Houston MEH") for a portion of its South Texas and Uinta Basin oil production with sales contracts that settle at WTI Houston MEH prices;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• NYMEX HH and Inside FERC ("IF") Waha hub in West Texas ("Waha") for a portion of its Midland Basin gas production with sales contracts that settle at IF Waha prices; and

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• NYMEX HH and Inside FERC Houston Ship Channel ("IF HSC") for a portion of its South Texas gas production with sales contracts that settle at IF HSC prices.

The Company has also entered into oil swap contracts to fix the differential in pricing between the NYMEX calendar month average and the physical crude oil delivery month ("Roll Differential") in which the Company pays the periodic variable Roll Differential and receives a weighted-average fixed price differential. The weighted-average fixed price differential represents the amount of net addition (reduction) to delivery month prices for the notional volumes covered by the swap contracts.

------

As of December 31, 2025, the Company had commodity derivative contracts outstanding through the fourth quarter of 2027 as summarized in the table below:

---

| | | | | | |
|:---|:---|:---|:---|:---|:---|
| | **Contract Period** | **Contract Period** | **Contract Period** | **Contract Period** | **Contract Period** |
| | **First Quarter**<br>**2026** | **Second Quarter**<br>**2026** | **Third Quarter**<br>**2026** | **Fourth Quarter**<br>**2026** | **2027** |
| **<u>Oil Derivatives (volumes in MBbl and prices in $ per Bbl):</u>** | **<u>Oil Derivatives (volumes in MBbl and prices in $ per Bbl):</u>** |  |  |  |  |
| &nbsp;&nbsp;**Swaps** |  |  |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;NYMEX WTI Volumes | 1744 | 1303 | 2014 | 876 |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Weighted-Average Contract Price | $63.03 | $62.04 | $63.00 | $59.78 | $— |
| &nbsp;&nbsp;**Collars** |  |  |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;NYMEX WTI Volumes | 2132 | 2213 | 1119 | 438 |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Weighted-Average Floor Price | $56.80 | $55.98 | $57.80 | $60.00 | $— |
| &nbsp;&nbsp;&nbsp;&nbsp;Weighted-Average Ceiling Price | $65.34 | $64.32 | $65.23 | $64.00 | $— |
| &nbsp;&nbsp;**Basis Swaps** |  |  |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;WTI Midland-NYMEX WTI Volumes | 1076 | 1086 | 975 | 1140 |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Weighted-Average Contract Price | $0.99 | $0.99 | $0.99 | $0.99 | $— |
| &nbsp;&nbsp;&nbsp;&nbsp;WTI Houston MEH-NYMEX WTI Volumes | 391 | 400 | 392 | 378 |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Weighted-Average Contract Price | $2.02 | $2.02 | $1.97 | $2.01 | $— |
| &nbsp;&nbsp;**Roll Differential Swaps** |  |  |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;NYMEX WTI Volumes | 1329 |  |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Weighted-Average Contract Price | $0.35 | $— | $— | $— | $— |
| **<u>Gas Derivatives (volumes in BBtu and prices in $ per MMBtu):</u>** | **<u>Gas Derivatives (volumes in BBtu and prices in $ per MMBtu):</u>** |  |  |  |  |
| &nbsp;&nbsp;**Swaps** |  |  |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;NYMEX HH Volumes | 5724 | 10194 | 11417 | 8176 | 17093 |
| &nbsp;&nbsp;&nbsp;&nbsp;Weighted-Average Contract Price | $4.41 | $3.55 | $3.90 | $4.22 | $4.12 |
| &nbsp;&nbsp;&nbsp;&nbsp;IF HSC Volumes | 957 |  |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Weighted-Average Contract Price | $4.07 | $— | $— | $— | $— |
| &nbsp;&nbsp;&nbsp;&nbsp;IF Waha Volumes | 3461 | 2232 | 3813 | 1067 | 4603 |
| &nbsp;&nbsp;&nbsp;&nbsp;Weighted-Average Contract Price | $2.93 | $1.21 | $2.35 | $3.13 | $3.64 |
| &nbsp;&nbsp;**Collars** |  |  |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;NYMEX HH Volumes | 6743 | 3398 | 3505 | 8952 | 2696 |
| &nbsp;&nbsp;&nbsp;&nbsp;Weighted-Average Floor Price | $3.65 | $3.25 | $3.25 | $3.56 | $4.00 |
| &nbsp;&nbsp;&nbsp;&nbsp;Weighted-Average Ceiling Price | $6.15 | $3.55 | $4.21 | $5.34 | $5.54 |
| &nbsp;&nbsp;**Basis Swaps** |  |  |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;IF Waha-NYMEX HH Volumes | 574 |  |  |  | 4495 |
| &nbsp;&nbsp;&nbsp;&nbsp;Weighted-Average Contract Price | $(1.75) | $— | $— | $— | $(0.70) |
| &nbsp;&nbsp;&nbsp;&nbsp;IF HSC-NYMEX HH Volumes | 973 |  |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Weighted-Average Contract Price | $(0.18) | $— | $— | $— | $— |
| **<u>NGL Derivatives (volumes in MBbl and prices in $ per Bbl):</u>** | **<u>NGL Derivatives (volumes in MBbl and prices in $ per Bbl):</u>** |  |  |  |  |
| &nbsp;&nbsp;**Swaps** |  |  |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;OPIS Ethane Mont Belvieu Non-TET Volumes | 259 | 137 | 137 | 141 |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Weighted-Average Contract Price | $12.57 | $11.71 | $11.71 | $11.71 | $— |

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*Derivative Assets and Liabilities Fair Value*

The Company's commodity derivatives are measured at fair value and are included in the accompanying balance sheets as derivative assets and liabilities, with the exception of derivative instruments that meet the "normal purchase normal sale" exclusion.

------

The Company does not designate its commodity derivative contracts as hedging instruments. The fair value of the commodity derivative contracts at December 31, 2025, and 2024, was a net asset of $85 million and $38 million, respectively.

The following table details the fair value of commodity derivative contracts recorded in the accompanying balance sheets, by category:

---

| | | |
|:---|:---|:---|
| | **As of December 31, 2025** | **As of December 31, 2024** |
| | **(in millions)** | **(in millions)** |
| Derivative assets: |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Current assets | $83 | $49 |
| &nbsp;&nbsp;&nbsp;&nbsp;Noncurrent assets | 6 | 4 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Total derivative assets | $89 | $52 |
| Derivative liabilities: |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Current liabilities | $2 | $7 |
| &nbsp;&nbsp;&nbsp;&nbsp;Noncurrent liabilities | 2 | 7 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Total derivative liabilities | $4 | $14 |

---

*Offsetting of Derivative Assets and Liabilities*

As of December 31, 2025, and 2024, all derivative instruments held by the Company were subject to master netting arrangements with various financial institutions. In general, the terms of the Company's agreements provide for offsetting of amounts payable or receivable between it and the counterparty, at the election of both parties, for transactions that settle on the same date and in the same currency. The Company's agreements also provide that in the event of an early termination, the counterparties have the right to offset amounts owed or owing under that and any other agreement with the same counterparty. The Company's accounting policy is to not offset these positions in its accompanying balance sheets.

The following table provides a reconciliation between the gross assets and liabilities reflected on the accompanying balance sheets and the potential effects of master netting arrangements on the fair value of the Company's commodity derivative contracts:

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| | | | | |
|:---|:---|:---|:---|:---|
| | **Derivative Assets as of** | **Derivative Assets as of** | **Derivative Liabilities as of** | **Derivative Liabilities as of** |
| | **December 31, <br>2025** | **December 31, <br>2024** | **December 31, <br>2025** | **December 31, <br>2024** |
| | **(in millions)** | **(in millions)** | **(in millions)** | **(in millions)** |
| Gross amounts presented in the accompanying balance sheets | $89 | $52 | $(4) | $(14) |
| Amounts not offset in the accompanying balance sheets | (4) | (13) | 4 | 13 |
| Net amounts | $85 | $40 | $— | $(1) |

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____________________________________________

Note: Amounts may not calculate due to rounding.

The Company recognizes all gains and losses from changes in commodity derivative fair values immediately in earnings rather than deferring such amounts in accumulated other comprehensive income (loss). The Company had no commodity derivative contracts designated as hedging instruments for the years ended December 31, 2025, 2024, and 2023. Refer to *Note 8 – Fair Value Measurements* for more information regarding the Company's derivative instruments, including its valuation techniques.

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The following table summarizes the commodity components of the net derivative settlement gain and the net derivative gain line items presented within the accompanying statements of cash flows and the accompanying statements of operations, respectively:

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| | | | |
|:---|:---|:---|:---|
| | **For the Years Ended December 31,** | **For the Years Ended December 31,** | **For the Years Ended December 31,** |
| | **2025** | **2024** | **2023** |
| | **(in millions)** | **(in millions)** | **(in millions)** |
| Net derivative settlement (gain) loss: |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Oil contracts | $(67) | $(13) | $27 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Gas contracts | (67) | (59) | (49) |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;NGL contracts | 2 | 3 | (5) |
| Total net derivative settlement gain: | $(132) | $(69) | $(27) |
| Net derivative (gain) loss: |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Oil contracts | $(98) | $(5) | $(21) |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Gas contracts | (80) | (49) | (43) |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;NGL contracts |  | 4 | (5) |
| Total net derivative gain: | $(178) | $(50) | $(68) |

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____________________________________________

Note: Amounts may not calculate due to rounding.

*Credit Related Contingent Features*

As of December 31, 2025, all of the Company's derivative counterparties were members of the Company's Credit Agreement lender group. The Company does not enter into derivative contracts with counterparties that are not part of the lender group. Under the Credit Agreement, the Company is required to provide mortgage liens on assets having a value equal to at least 85 percent of the total PV-9, as defined in the Credit Agreement, of the Company's proved oil and gas properties evaluated in the most recent reserve report. Collateral securing indebtedness under the Credit Agreement also secures the Company's derivative agreement obligations.

**Note 8 – Fair Value Measurements**

The Company follows fair value measurement accounting guidance for all assets and liabilities measured at fair value. This guidance defines fair value as the price that would be received to sell an asset or paid to transfer a liability (an exit price) in an orderly transaction between market participants at the measurement date. Market or observable inputs are the preferred sources of values, followed by assumptions based on hypothetical transactions in the absence of market inputs. The fair value hierarchy for grouping these assets and liabilities is based on the significance level of the following inputs:

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• Level 1 – quoted prices in active markets for identical assets or liabilities

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• Level 2 – quoted prices in active markets for similar assets or liabilities, quoted prices for identical or similar instruments in markets that are not active, and model-derived valuations whose inputs are observable or whose significant value drivers are observable

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• Level 3 – significant inputs to the valuation model are unobservable

The following table is a listing of the Company's assets and liabilities that are measured at fair value on a recurring basis in the accompanying balance sheets and where they are classified within the fair value hierarchy:

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| | | | | | | |
|:---|:---|:---|:---|:---|:---|:---|
| | **As of December 31, 2025** | **As of December 31, 2025** | **As of December 31, 2025** | **As of December 31, 2024** | **As of December 31, 2024** | **As of December 31, 2024** |
| | **Level 1** | **Level 2** | **Level 3** | **Level 1** | **Level 2** | **Level 3** |
| | **(in millions)** | **(in millions)** | **(in millions)** | **(in millions)** | **(in millions)** | **(in millions)** |
| Assets: |  |  |  |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Derivatives | $— | $89 | $— | $— | $52 | $— |
| Liabilities: |  |  |  |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Derivatives | $— | $4 | $— | $— | $14 | $— |

---

------

Both financial and non-financial assets and liabilities are categorized within the above fair value hierarchy based on the lowest level of input that is significant to the fair value measurement. The following is a description of the valuation methodologies used by the Company as well as the general classification of such instruments pursuant to the above fair value hierarchy. Refer to *Note 1 – Summary of Significant Accounting Policies* for additional information on the Company's policies for determining fair value for the categories discussed below.

*Derivatives*

The Company uses Level 2 inputs to measure the fair value of oil, gas, and NGL commodity derivative instruments. Fair values are based upon interpolated data. The Company derives internal valuation estimates taking into consideration forward commodity price curves, counterparties' credit ratings, the Company's credit rating, and the time value of money. These valuations are then compared to the respective counterparties' mark-to-market statements. The considered factors result in an estimated exit price that management believes provides a reasonable and consistent methodology for valuing derivative instruments. The commodity derivative instruments utilized by the Company are not considered by management to be complex, structured, or illiquid. The oil, gas, and NGL commodity derivative markets are highly active.

Generally, market quotes assume that all counterparties have near zero, or low, default rates and have equal credit quality. However, an adjustment may be necessary to reflect the credit quality of a specific counterparty to determine the fair value of the instrument. The Company monitors the credit ratings of its counterparties and may require counterparties to post collateral if their ratings deteriorate. In some instances, the Company will attempt to novate the trade to a more stable counterparty.

Valuation adjustments are necessary to reflect the effect of the Company's credit quality on the fair value of any commodity derivative liability position. This adjustment takes into account any credit enhancements, such as collateral margin that the Company may have posted with a counterparty, as well as any letters of credit between the parties. The methodology to determine this adjustment is consistent with how the Company evaluates counterparty credit risk, taking into account the Company's credit rating, current revolving credit facility margins, and any change in such margins since the last measurement date.

The methods described above may result in a fair value estimate that may not be indicative of net realizable value or may not be reflective of future fair values and cash flows. While the Company believes that the valuation methods utilized are appropriate and consistent with authoritative accounting guidance and other marketplace participants, the Company recognizes that third parties may use different methodologies or assumptions to determine the fair value of certain financial instruments that could result in a different estimate of fair value at the reporting date.

Refer to *Note 7 – Derivative Financial Instruments* for more information regarding the Company's derivative instruments.

*Long-Term Debt*

The following table reflects the fair value of the Company's Senior Notes obligations measured using Level 1 inputs based on quoted secondary market trading prices. These notes were not presented at fair value on the accompanying balance sheets as of December 31, 2025, or 2024, as they were recorded at carrying value, net of any unamortized deferred financing costs. Refer to *Note 5 – Long-Term Debt* for additional information.

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| | | | | |
|:---|:---|:---|:---|:---|
| | **As of December 31,** | **As of December 31,** | **As of December 31,** | **As of December 31,** |
| | **2025** | **2025** | **2024** | **2024** |
| | **Principal Amount** | **Fair Value** | **Principal Amount** | **Fair Value** |
| | **(in millions)** | **(in millions)** | **(in millions)** | **(in millions)** |
| 6.75% Senior Notes due 2026 <sup>(1)</sup> | $419 | $420 | $419 | $420 |
| 6.625% Senior Notes due 2027 | $417 | $419 | $417 | $416 |
| 6.5% Senior Notes due 2028 | $400 | $405 | $400 | $399 |
| 6.75% Senior Notes due 2029 | $750 | $756 | $750 | $742 |
| 7.0% Senior Notes due 2032 | $750 | $739 | $750 | $741 |

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____________________________________________

<sup>(1)&nbsp;&nbsp;&nbsp;&nbsp;</sup>As of December 31, 2025, the 2026 Senior Notes are presented in the current liabilities section of the accompanying balance sheets.

The carrying value of the Company's revolving credit facility approximates its fair value, as the applicable interest rates are floating, based on prevailing market rates.

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**Note 9 – Earnings Per Share**

Basic net income or loss per common share is calculated by dividing net income or loss available to common stockholders by the basic weighted-average number of common shares outstanding for the respective period. Diluted net income or loss per common share is calculated by dividing net income or loss available to common stockholders by the diluted weighted-average number of common shares outstanding, which includes the effect of potentially dilutive securities.

For the years ended December 31, 2025, 2024, and 2023, potentially dilutive securities for this calculation consisted primarily of non-vested RSUs and contingent PSUs, which were measured using the treasury stock method.

PSUs represent the right to receive, upon settlement of the PSUs after the completion of the three-year performance period, a number of shares of the Company's common stock that may range from zero to two times the number of PSUs granted on the award date. The number of potentially dilutive shares related to PSUs is based on the number of shares, if any, which would be issuable at the end of the respective reporting period, assuming that date was the end of the contingency period applicable to such PSUs.

Refer to *Note 10 – Stock-Based Compensation* for additional detail on RSUs and PSUs.

The following table sets forth the calculations of basic and diluted net income per common share:

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| | | | |
|:---|:---|:---|:---|
| | **For the Years Ended December 31,** | **For the Years Ended December 31,** | **For the Years Ended December 31,** |
| | **2025** | **2024** | **2023** |
| | **(in millions, except per share data)** | **(in millions, except per share data)** | **(in millions, except per share data)** |
| Net income | $648 | $770 | $818 |
| Basic weighted-average common shares outstanding | 115 | 115 | 119 |
| Dilutive effect of non-vested RSUs, contingent PSUs, and other |  | 1 | 1 |
| Diluted weighted-average common shares outstanding | 115 | 116 | 119 |
| Basic net income per common share | $5.65 | $6.71 | $6.89 |
| Diluted net income per common share | $5.64 | $6.67 | $6.86 |

---

____________________________________________

Note: Amounts may not calculate due to rounding.

**Note 10 – Stock-Based Compensation**

On May 22, 2025, the Company's stockholders approved the 2025 Equity Incentive Compensation Plan ("2025 Equity Plan"), which succeeded the SM Energy Company Equity Incentive Compensation Plan, as amended and restated effective as of May 22, 2018 ("Predecessor Equity Plan" and together with the 2025 Equity Plan, the "Equity Plans"). The Company ceased granting awards under the Predecessor Equity Plan following the approval of the 2025 Equity Plan, however, existing awards remain outstanding under the Predecessor Equity Plan. Among other items, the 2025 Equity Plan authorized an increase in the total number of shares of the Company's common stock available for grant of approximately 2.0 million shares. The 2025 Equity Plan is included as Exhibit 10.25 to this report.

As of December 31, 2025, approximately 2.5 million shares of common stock were available for grant under the 2025 Equity Plan. The issuance of a direct share benefit, such as a share of common stock, a stock option, a restricted share, an RSU or a PSU, counts as one share against the number of shares available to be granted under the Equity Plans. Each PSU has the potential to count as two shares against the number of shares available to be granted under the Equity Plans based on the final performance multiplier.

*Performance Share Units*

The Company has granted PSUs to eligible employees as part of its Equity Plans. The number of shares of the Company's common stock issued to settle PSUs ranges from zero to two times the number of PSUs awarded and is determined based on certain criteria over a three-year performance period. PSUs generally vest on the third anniversary of the grant date or upon other triggering events as set forth in the applicable Equity Plan. Employees who meet retirement eligibility criteria on the grant date of a PSU award (as determined by the applicable grant agreement) vest in pro-rata increments on a daily basis over the three-year performance period beginning at the grant date, and any non-vested portions of a PSU award will be forfeited if the employee leaves the Company.

The fair value of PSUs is measured at the grant date using a stochastic Monte Carlo simulation using geometric Brownian motion ("GBM Model"). A stochastic process is a mathematically defined equation that can create a series of outcomes over time.

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These outcomes are not deterministic in nature, which means that by iterating the equations multiple times, different results will be obtained for each iteration. In the case of the Company's PSUs, the Company cannot predict with certainty the path of its stock price or the stock prices of its peers over the three-year performance period. By using a stochastic simulation, the Company can create multiple prospective stock pathways, statistically analyze these simulations, and ultimately make inferences regarding the path the stock price may take. As such, because future stock prices are stochastic, or probabilistic with some direction in nature, the stochastic method, specifically the GBM Model, is deemed an appropriate method by which to determine the fair value of the PSUs. Significant assumptions used in this simulation include the Company's expected volatility, dividend yield, and risk-free interest rate based on U.S. Treasury yield curve rates with maturities consistent with a three-year vesting period, as well as the volatilities and dividend yield for each of the Company's peers.

For PSUs granted in 2025, settlement will be determined based on the Company's total shareholder return ("TSR") measured over the three-year performance period, including equally weighted absolute TSR and TSR relative to certain peer companies. For PSUs granted in 2024, and 2023, settlement will be determined based on a combination of the following criteria measured over the three-year performance period: relative TSR, absolute TSR, free cash flow ("FCF") generation, and the achievement of certain sustainability targets, in each case as defined by the award agreement. The relative and absolute TSR portions of the fair value of the PSUs granted in 2025, 2024, and 2023, were measured on the grant date using the GBM Model. The portion of the awards associated with FCF generation and sustainability performance conditions assumes that target amounts will be met at the end of the performance period. Because a portion of the 2024 and 2023 awards depends on performance-based settlement criteria, compensation expense may be adjusted in future periods as the expected number of shares of the Company's common stock issued to settle the units increases or decreases based on the Company's expected FCF generation and achievement of certain sustainability targets.

The Company initially records compensation expense associated with the issuance of PSUs based on the fair value of the awards as of the grant date and may adjust compensation expense in future periods as discussed above. Compensation expense for PSUs is recognized within general and administrative expense and exploration expense over the vesting periods of the respective awards. Total compensation expense recorded for PSUs was $7 million, $6 million, and $3 million for the years ended December 31, 2025, 2024, and 2023, respectively. As of December 31, 2025, there was $13 million of total unrecognized expense related to non-vested PSUs, which is being amortized through mid-2028.

The fair value of PSUs granted in each of 2025 and 2024 was $10 million, and in 2023, was $8 million.

A summary of activity is presented in the following table:

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| | | | | | | |
|:---|:---|:---|:---|:---|:---|:---|
| | **For the Years Ended December 31,** | **For the Years Ended December 31,** | **For the Years Ended December 31,** | **For the Years Ended December 31,** | **For the Years Ended December 31,** | **For the Years Ended December 31,** |
| | **2025** | **2025** | **2024** | **2024** | **2023** | **2023** |
| | **PSUs** <sup>(1)</sup> | **Weighted-Average Grant-Date Fair Value** <sup>(2)</sup> | **PSUs** <sup>(1)</sup> | **Weighted-Average Grant-Date Fair Value** <sup>(2)</sup> | **PSUs** <sup>(1)</sup> | **Weighted-Average Grant-Date Fair Value** <sup>(2)</sup> |
| Non-vested at beginning of year | 694366 | $32.99 | 469432 | $27.83 | 273258 | $26.67 |
| &nbsp;&nbsp;&nbsp;&nbsp;Granted | 374692 | $27.45 | 231120 | $42.76 | 256633 | $29.93 |
| &nbsp;&nbsp;&nbsp;&nbsp;Vested | (61343) | $26.67 |  | $— | (15950) | $25.50 |
| &nbsp;&nbsp;&nbsp;&nbsp;Forfeited | (188110) | $28.28 | (6186) | $25.87 | (44509) | $26.45 |
| Non-vested at end of year | 819605 | $32.18 | 694366 | $32.99 | 469432 | $27.83 |

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____________________________________________

<sup>(1)</sup> The number of PSUs presented assumes a multiplier of one. The actual final number of shares of common stock to be issued at the end of the three-year performance period will range from zero to two times the number of PSUs awarded depending on the three-year performance multiplier.

<sup>(2)</sup> Amounts represent price per unit.

During the year ended December 31, 2025, the Company settled PSUs that were granted in 2022, at a 0.28 times multiplier based on the same performance criteria utilized for PSUs granted in 2024 and 2023, as described above. The Company and all eligible recipients mutually agreed to net share settle a portion of the awards to cover income and payroll tax withholdings, as provided for in the Predecessor Equity Plan and applicable award agreements. After withholding 26,397 shares to satisfy income and payroll tax withholding obligations that occurred upon delivery of the shares underlying those PSUs, 39,475 shares of the Company's common stock were issued in accordance with the terms of the applicable award agreement. The fair value of PSUs that vested during the year ended December 31, 2025, was $2 million. No PSUs were settled during the years ended December 31, 2024 and 2023.

*Employee Restricted Stock Units*

The Company has granted RSUs to eligible employees as part of its Equity Plans. Each RSU represents a right to receive one share of the Company's common stock upon settlement of the award at the end of the specified vesting period. RSUs generally vest in

------

one-third increments on each anniversary of the applicable grant date over the applicable vesting period or upon other triggering events as set forth in the Equity Plans. Employees who meet retirement eligibility criteria at the time an RSU award is granted (as determined by the applicable grant agreement) generally vest in six-month increments over the applicable vesting period beginning at the grant date. Retirement eligible employees must stay with the Company through the entire six-month vesting period to receive that increment of vesting and any non-vested portions of an RSU award will be forfeited when the employee leaves the Company.

The Company records compensation expense associated with the issuance of RSUs based on the fair value of the awards as of the grant date. The fair value of an RSU is equal to the closing price of the Company's common stock on the grant date. Compensation expense for RSUs is recognized within general and administrative expense and exploration expense over the vesting periods of the respective awards. Total compensation expense recorded for RSUs for the years ended December 31, 2025, 2024, and 2023, was $19 million, $17 million, and $15 million, respectively. As of December 31, 2025, there was $33 million of total unrecognized compensation expense related to non-vested RSUs, which is being amortized through October 2028.

The fair value of RSUs granted to eligible employees in 2025, 2024 and 2023, was $26 million, $22 million, and $20 million, respectively, and the fair value of RSUs that vested during the years ended December 31, 2025, 2024, and 2023, was $18 million, $15 million, and $14 million, respectively.

A summary of activity is presented in the following table:

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| | | | | | | |
|:---|:---|:---|:---|:---|:---|:---|
| | **For the Years Ended December 31,** | **For the Years Ended December 31,** | **For the Years Ended December 31,** | **For the Years Ended December 31,** | **For the Years Ended December 31,** | **For the Years Ended December 31,** |
| | **2025** | **2025** | **2024** | **2024** | **2023** | **2023** |
| | **RSUs** | **Weighted-**<br>**Average**<br>**Grant-Date**<br>**Fair Value** <sup>(1)</sup> | **RSUs** | **Weighted-**<br>**Average**<br>**Grant-Date**<br>**Fair Value** <sup>(1)</sup> | **RSUs** | **Weighted-**<br>**Average**<br>**Grant-Date**<br>**Fair Value** <sup>(1)</sup> |
| Non-vested at beginning of year | 1039837 | $37.87 | 1080544 | $31.49 | 1375052 | $22.42 |
| &nbsp;&nbsp;&nbsp;&nbsp;Granted | 1009505 | $26.22 | 504010 | $43.44 | 630474 | $32.03 |
| &nbsp;&nbsp;&nbsp;&nbsp;Vested | (486768) | $36.39 | (507171) | $30.18 | (805205) | $16.75 |
| &nbsp;&nbsp;&nbsp;&nbsp;Forfeited | (114649) | $34.00 | (37546) | $32.96 | (119777) | $29.26 |
| Non-vested at end of year | 1447925 | $30.55 | 1039837 | $37.87 | 1080544 | $31.49 |

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____________________________________________

<sup>(1)</sup> Amounts represent price per unit.

A summary of the shares of common stock issued to settle RSUs is presented in the table below:

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| | | | |
|:---|:---|:---|:---|
| | **For the Years Ended December 31,** | **For the Years Ended December 31,** | **For the Years Ended December 31,** |
| | **2025** | **2024** | **2023** |
| Shares of common stock issued to settle RSUs <sup>(1)</sup> | 486768 | 508927 | 803449 |
| Less: shares of common stock withheld for income and payroll taxes | (161787) | (158252) | (249233) |
| Net shares of common stock issued | 324981 | 350675 | 554216 |

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____________________________________________

<sup>(1)&nbsp;&nbsp;&nbsp;&nbsp;</sup>During the years ended December 31, 2025, 2024, and 2023, the Company issued shares of common stock to settle RSUs that related to awards granted in prior years. The Company and a majority of eligible recipients in 2025 and 2023, and all eligible recipients in 2024, mutually agreed to net share settle a portion of the awards to cover income and payroll tax withholdings in accordance with the Company's Equity Plans and individual award agreements.

**Note 11 – Segment Reporting**

The Company's operations are all related to the exploration, development, and production of oil, gas, and NGLs in the United States, from which the Company derives all of its revenue. The nature of the production process, the types of purchasers, and the regulatory environment under which the Company operates are consistent across the Company. Additionally, for financial reporting purposes related to oil and gas extraction activities, the United States is considered to be one geographic area. As a result of these factors, the Company has one reportable segment: the oil, gas, and NGL exploration and production segment ("E&P Segment"). The E&P Segment constitutes all of the consolidated entity and the accompanying consolidated financial statements and the notes to the accompanying consolidated financial statements are representative of such amounts for the E&P Segment. The accounting policies of the E&P Segment are the same as those described in *Note 1 – Summary of Significant Accounting Policies.*

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The Company's Chief Operating Decision Maker ("CODM") is the President and Chief Executive Officer. The CODM uses net income as presented on the accompanying statements of operations to measure E&P Segment profit or loss, and to evaluate income generated from E&P Segment assets in deciding whether to reinvest profits into operational activities or to use profits for other purposes, such as debt reduction, acquisitions, or the Company's Stock Repurchase Program. Additionally, net income is used in assessing budget versus actual results and in benchmarking to the Company's competitors.

*Segment Revenue, Significant Expenses, and Net Income*

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| | | | |
|:---|:---|:---|:---|
| | **For the Years Ended December 31,** | **For the Years Ended December 31,** | **For the Years Ended December 31,** |
| | **2025** | **2024** | **2023** |
| | **(in millions)** | **(in millions)** | **(in millions)** |
| Total operating revenues and other income | $3154 | $2690 | $2374 |
| &nbsp;&nbsp;&nbsp;&nbsp;Less: |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Lease operating expense | 431 | 319 | 285 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Transportation costs | 292 | 167 | 136 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Production taxes | 127 | 116 | 105 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Ad valorem tax expense | 35 | 35 | 37 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Depletion, depreciation, and amortization | 1207 | 809 | 690 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Exploration | 57 | 64 | 59 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;General and administrative | 161 | 138 | 121 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Net derivative gain | (178) | (50) | (68) |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Other operating expense, net | 22 | 16 | 21 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Interest expense | 173 | 141 | 92 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Interest income | (3) | (32) | (20) |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Other non-operating income |  | 1 | 1 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Income tax expense | 182 | 196 | 96 |
| E&P Segment net income | $648 | $770 | $818 |

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___________________________________________

Note: Amounts may not recalculate due to rounding.

There are no reconciling items between net income presented on the accompanying statements of operations and E&P Segment net income.

**Note 12 – Pension Benefits**

The Company has a non-contributory defined benefit pension plan covering employees who met age and service requirements and began employment with the Company prior to January 1, 2016 ("Qualified Pension Plan"). The Company also has a supplemental non-contributory pension plan covering certain management employees ("Nonqualified Pension Plan" and together with the Qualified Pension Plan, "Pension Plans"). The Company froze the Pension Plans to new participants, effective January 1, 2016. Employees participating in the Pension Plans prior to the plans being frozen continue to earn benefits.

*Obligations and Funded Status for the Pension Plans*

The Company recognizes the funded status (*i.e*., the difference between the fair value of plan assets and the projected benefit obligation) of the Company's Pension Plans in the accompanying balance sheets as either an asset or a liability and recognizes a corresponding adjustment within the other comprehensive income, net of tax, line item in the accompanying consolidated statements of comprehensive income. The projected benefit obligation is the actuarial present value of the benefits earned to date by plan participants based on employee service and compensation including the effect of assumed future salary increases. The accumulated benefit obligation uses the same factors as the projected benefit obligation, but excludes the effects of assumed future salary increases. The Company's measurement date for plan assets and obligations is December 31.

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| | | |
|:---|:---|:---|
| | **For the Years Ended December 31,** | **For the Years Ended December 31,** |
| | **2025** | **2024** |
| | **(in millions)** | **(in millions)** |
| Change in benefit obligation: |  |  |
| Projected benefit obligation at beginning of year | $70 | $67 |
| &nbsp;&nbsp;&nbsp;&nbsp;Service cost | 3 | 4 |
| &nbsp;&nbsp;&nbsp;&nbsp;Interest cost | 4 | 3 |
| &nbsp;&nbsp;&nbsp;&nbsp;Actuarial (gain) loss | 2 | (1) |
| &nbsp;&nbsp;&nbsp;&nbsp;Benefits paid | (4) | (2) |
| &nbsp;&nbsp;&nbsp;&nbsp;Settlements |  |  |
| Projected benefit obligation at end of year | 75 | 70 |
| Change in plan assets: |  |  |
| Fair value of plan assets at beginning of year | 57 | 46 |
| &nbsp;&nbsp;&nbsp;&nbsp;Actual return on plan assets | 8 | 4 |
| &nbsp;&nbsp;&nbsp;&nbsp;Employer contribution | 6 | 10 |
| &nbsp;&nbsp;&nbsp;&nbsp;Benefits paid | (4) | (2) |
| &nbsp;&nbsp;&nbsp;&nbsp;Settlements |  |  |
| Fair value of plan assets at end of year | 67 | 57 |
| Funded status at end of year | $(8) | $(13) |

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____________________________________________

Note: Amounts may not calculate due to rounding.

The Company's underfunded status for the Pension Plans as of December 31, 2025, and 2024, was $8 million and $13 million, respectively, and is recognized in the accompanying balance sheets within the other noncurrent liabilities line item. There are no plan assets in the Nonqualified Pension Plan.

*Accumulated Benefit Obligation Compared to Plan Assets for the Pension Plans*

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| | | |
|:---|:---|:---|
| | **As of December 31,** | **As of December 31,** |
| | **2025** | **2024** |
| | **(in millions)** | **(in millions)** |
| Projected benefit obligation | $75 | $70 |
| Accumulated benefit obligation | $65 | $59 |
| Less: fair value of plan assets | (67) | (57) |
| &nbsp;&nbsp;&nbsp;&nbsp;(Funded) underfunded accumulated benefit obligation | $(2) | $2 |

---

Pension expense is determined based upon the annual service cost of benefits (the actuarial cost of benefits earned during a period) and the interest cost on those liabilities, less the expected return on plan assets. The expected long-term rate of return on plan assets is applied to a calculated value of plan assets that recognizes changes in fair value over a five-year period. This practice is intended to reduce year-to-year volatility in pension expense, but it can have the effect of delaying recognition of differences between actual returns on assets and expected returns based on long-term rate of return assumptions. Amortization of the unrecognized net gain or loss resulting from actual experience different from that assumed and from changes in assumptions (excluding asset gains and losses not yet reflected in market-related value) is included as a component of net periodic benefit cost for the year. If, as of the beginning of the year, the unrecognized net gain or loss exceeds 10 percent of the greater of the projected benefit obligation and the market-related value of plan assets, then the amortization is the excess divided by the average remaining service period of participating employees expected to receive benefits under the plan.

The pre-tax amounts not yet recognized in net periodic pension costs, but rather recognized in the accumulated other comprehensive income (loss) line item within the accompanying balance sheets was a gain of $1 million as of December 31, 2025, and a loss of $2 million as of December 31, 2024, related to unrecognized actuarial activity.

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The pension liability adjustments recognized in other comprehensive income during 2025, 2024, and 2023, were as follows:

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| | | | |
|:---|:---|:---|:---|
| | **For the Years Ended December 31,** | **For the Years Ended December 31,** | **For the Years Ended December 31,** |
| | **2025** | **2024** | **2023** |
| | **(in millions)** | **(in millions)** | **(in millions)** |
| Net actuarial gain | $3 | $2 | $2 |
| Amortization of net actuarial loss |  |  |  |
| Settlements |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Total pension liability adjustment, pre-tax | 3 | 2 | 2 |
| Tax expense | (1) |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Total pension liability adjustment, net | $2 | $1 | $1 |

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____________________________________________

Note: Amounts may not calculate due to rounding.

*Components of Net Periodic Benefit Cost for the Pension Plans*

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| | | | |
|:---|:---|:---|:---|
| | **For the Years Ended December 31,** | **For the Years Ended December 31,** | **For the Years Ended December 31,** |
| | **2025** | **2024** | **2023** |
| | **(in millions)** | **(in millions)** | **(in millions)** |
| Components of net periodic benefit cost: |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Service cost | $3 | $4 | $4 |
| &nbsp;&nbsp;&nbsp;&nbsp;Interest cost | 4 | 3 | 3 |
| &nbsp;&nbsp;&nbsp;&nbsp;Expected return on plan assets that reduces periodic pension benefit cost | (3) | (3) | (2) |
| &nbsp;&nbsp;&nbsp;&nbsp;Amortization of net actuarial loss |  |  |  |
| Net periodic benefit cost | 4 | 4 | 5 |
| &nbsp;&nbsp;&nbsp;&nbsp;Settlements |  |  |  |
| Total net benefit cost | $4 | $4 | $5 |

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*Pension Plan Assumptions*

The weighted-average assumptions used to measure the Company's projected benefit obligation are as follows:

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| | | |
|:---|:---|:---|
| | **As of December 31,** | **As of December 31,** |
| | **2025** | **2024** |
| Projected benefit obligation: |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Discount rate | 5.5% | 5.6% |
| &nbsp;&nbsp;&nbsp;&nbsp;Rate of compensation increase | 3.5% | 3.5% |

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The weighted-average assumptions used to measure the Company's net periodic benefit cost are as follows:

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| | | | |
|:---|:---|:---|:---|
| | **For the Years Ended December 31,** | **For the Years Ended December 31,** | **For the Years Ended December 31,** |
| | **2025** | **2024** | **2023** |
| Net periodic benefit cost: |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Discount rate | 5.6% | 5.1% | 5.2% |
| &nbsp;&nbsp;&nbsp;&nbsp;Expected return on plan assets <sup>(1)</sup> | 6.3% | 6.5% | 6.3% |
| &nbsp;&nbsp;&nbsp;&nbsp;Rate of compensation increase | 3.5% | 3.5% | 3.5% |

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____________________________________________

<sup>(1)</sup> There is no assumed expected return on plan assets for the Nonqualified Pension Plan because there are no plan assets in the Nonqualified Pension Plan.

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The Company's pension investment policy includes various guidelines and procedures designed to ensure that assets are prudently invested in a manner necessary to meet the future benefit obligation of the Pension Plans. The policy prohibits the direct investment of plan assets in the Company's securities. The Qualified Pension Plan's investment horizon is long-term and accordingly the target asset allocations encompass a strategic, long-term perspective of capital markets, expected risk and return behavior and perceived future economic conditions. The key investment principles of diversification, assessment of risk, and targeting of expected returns for given levels of risk are applied.

The Qualified Pension Plan's investment portfolio contains a diversified blend of investments, which may reflect varying rates of return. The investments are further diversified within each asset classification. This portfolio diversification provides protection against a single security or class of securities having a disproportionate impact on aggregate investment performance. The actual asset allocations are reviewed and rebalanced on a periodic basis to maintain the target allocations.

The weighted-average asset allocation of the Qualified Pension Plan is as follows:

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| | | | |
|:---|:---|:---|:---|
| | | **As of December 31,** | **As of December 31,** |
|<br>&nbsp;&nbsp;**Asset Category** | **Target**<br>**2026** | **2025** | **2024** |
| Equity securities | 35.0% | 37.9% | 41.0% |
| Fixed income securities | 50.0% | 49.2% | 40.3% |
| Other securities | 15.0% | 12.9% | 18.7% |
| &nbsp;&nbsp;&nbsp;&nbsp;Total | 100.0% | 100.0% | 100.0% |

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There is no asset allocation of the Nonqualified Pension Plan since there are no plan assets in the plan. The assumption of the expected long-term rate of return on plan assets of the Qualified Pension Plan is based upon the target asset allocation and is determined using forward-looking assumptions in the context of historical returns and volatilities for each asset class, as well as correlations among asset classes. The Company evaluates the expected rate of return on plan assets assumption on an annual basis.

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*Pension Plan Assets*

The fair values of the Company's Qualified Pension Plan assets utilizing the fair value hierarchy discussed in *Note 8 – Fair Value Measurements* are as follows:

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| | | | | | |
|:---|:---|:---|:---|:---|:---|
| | | | **Fair Value Measurements Using:** | **Fair Value Measurements Using:** | **Fair Value Measurements Using:** |
| |<br>**Actual Asset Allocation** <sup>(1)</sup> |<br>**Total** | **Level 1 Inputs** | **Level 2 Inputs** | **Level 3 Inputs** <sup>(2)</sup> |
| | | **(in millions)** | **(in millions)** | **(in millions)** | **(in millions)** |
| **As of December 31, 2025** | | | | | |
| Equity securities: |  |  |  |  |  |
| &nbsp;&nbsp;Domestic <sup>(3)</sup> | 19.1% | $12 | $8 | $4 | $— |
| &nbsp;&nbsp;International <sup>(4)</sup> | 18.8% | 13 | 13 |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Total equity securities | 37.9% | 25 | 21 | 4 |  |
| Fixed income securities: |  |  |  |  |  |
| &nbsp;&nbsp;Core fixed income <sup>(5)</sup> | 49.2% | 33 | 1 | 32 |  |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Total fixed income securities | 49.2% | 33 | 1 | 32 |  |
| Other securities: |  |  |  |  |  |
| Real estate <sup>(6)</sup> | 2.9% | 2 |  |  | 2 |
| Collective investment trusts <sup>(7)</sup> | 1.3% | 1 |  | 1 |  |
| Hedge fund <sup>(8)</sup> | 8.7% | 6 | 2 |  | 4 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Total other securities | 12.9% | 9 | 2 | 1 | 6 |
| Total investments | 100.0% | $67 | $24 | $37 | $6 |
| **As of December 31, 2024** |  |  |  |  |  |
| Equity securities: |  |  |  |  |  |
| &nbsp;&nbsp;Domestic <sup>(3)</sup> | 19.5% | $11 | $7 | $4 | $— |
| &nbsp;&nbsp;International <sup>(4)</sup> | 21.5% | 12 | 12 |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Total equity securities | 41.0% | 23 | 19 | 4 |  |
| Fixed income securities: |  |  |  |  |  |
| &nbsp;&nbsp;Core fixed income <sup>(5)</sup> | 40.3% | 23 | 23 |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Total fixed income securities | 40.3% | 23 | 23 |  |  |
| Other securities: |  |  |  |  |  |
| Real estate <sup>(6)</sup> | 3.3% | 2 |  |  | 2 |
| Collective investment trusts <sup>(7)</sup> | 6.1% | 4 |  | 4 |  |
| Hedge fund <sup>(8)</sup> | 9.3% | 5 | 2 |  | 4 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Total other securities | 18.7% | 11 | 2 | 4 | 5 |
| Total investments <sup>(1)</sup> | 100.0% | $57 | $44 | $7 | $5 |

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____________________________________________

<sup>(1)</sup> Amounts may not calculate due to rounding.

<sup>(2)</sup> During the years ended December 31, 2025, and 2024, there were no material changes in Level 3 plan assets.

<sup>(3)</sup> Level 1 equity securities consist of United States large and small capitalization companies, which are actively traded securities that can be sold on demand. Level 2 equity securities are investments in collective investment funds that are valued at net asset value based on the value of the underlying investments and total units outstanding on a daily basis. The objective of these funds is to approximate the S&P 500 by investing in one or more collective investment funds.

<sup>(4)</sup> International equity securities consist of a well-diversified portfolio of holdings of mostly large issuers organized in developed countries with liquid markets, commingled with investments in equity securities of issuers located in emerging markets that are believed to have strong sustainable financial productivity at attractive valuations.

<sup>(5)</sup> The objective of core fixed income investments is to generate income through diversified, investment-grade fixed income securities while managing exposure to credit and interest rate risk.

<sup>(6)</sup> The investment objective of direct real estate is to provide current income with the potential for long-term capital appreciation. Ownership in real estate entails a long-term time horizon, periodic valuations, and potentially low liquidity.

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<sup>(7)</sup> Collective investment trusts invest in short-term investments and are valued at the net asset value of the collective investment trust. The net asset value, as provided by the trustee, is used as a practical expedient to estimate fair value. The net asset value is based on the fair value of the underlying investments held by the fund less its liabilities.

<sup>(8)</sup> The hedge fund portfolio includes investments in actively traded global mutual funds that focus on alternative investments and a hedge fund of funds that invests both long and short using a variety of investment strategies.

*Contributions*

The Company contributed $6 million to the Pension Plans during the year ended December 31, 2025, and $10 million during each of the years ended December 31, 2024 and 2023. The Company expects to make a $4 million contribution to the Pension Plans in 2026.

*Benefit Payments*

The Pension Plans made actual benefit payments of $4 million, $3 million, and $5 million during the years ended December 31, 2025, 2024, and 2023, respectively. Expected benefit payments over the next 10 years are as follows:

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| | |
|:---|:---|
| **For the Years Ending December 31,** | **Amount** |
| | **(in millions)** |
| 2026 | $12 |
| 2027 | $5 |
| 2028 | $5 |
| 2029 | $5 |
| 2030 | $6 |
| 2031 through 2035 | $28 |

---

**Note 13 – Leases**

As of December 31, 2025, and 2024, the Company had operating leases for asset classes that include office space, office equipment, drilling rigs, completion crews, midstream agreements, vehicles, railcars, and equipment rentals used in field operations. For operating leases recorded on the accompanying balance sheets, the remaining lease terms range from less than one year to approximately 10 years. Certain leases contain optional extension periods that allow for terms to be extended for up to an additional 10 years; however, in order to maintain financial and operational flexibility, there are no available options to extend that the Company is reasonably certain it will exercise. An early termination option exists for certain leases, some of which allow the Company to terminate a lease within one year; however, there are no leases in which material early termination options are reasonably certain to be exercised by the Company. As of December 31, 2025, and 2024, the Company did not have any agreements in place that were classified as finance leases under Topic 842. As of December 31, 2025, and through the filing of this report, the Company has no material lease arrangements which are scheduled to commence in the future. Refer to *Note 1 – Summary of Significant Accounting Policies* for additional information on the Company's policies for lease determination and classification.

------

The following table reflects the components of the Company's total lease costs, whether capitalized or expensed, related to operating leases, including short-term leases, and variable lease costs for both short-term and long-term leases for the years ended December 31, 2025, 2024, and 2023. This total does not reflect amounts that may be reimbursed by other third parties in the normal course of business, such as non-operating working interest owners.

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| | | | |
|:---|:---|:---|:---|
| | **For the Years Ended December 31,** | **For the Years Ended December 31,** | **For the Years Ended December 31,** |
| | **2025** | **2024** | **2023** |
| | **(in millions)** | **(in millions)** | **(in millions)** |
| Operating lease cost | $44 | $27 | $16 |
| Short-term lease cost <sup>(1)</sup> | 140 | 86 | 252 |
| Variable lease cost <sup>(2)</sup> | 289 | 387 | 12 |
| Total lease cost | $473 | $499 | $279 |

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____________________________________________

Note: Amounts may not calculate due to rounding.

<sup>(1)</sup> &nbsp;&nbsp;&nbsp;&nbsp;Costs associated with short-term lease agreements relate primarily to operational activities where underlying lease terms are less than one year. This amount includes drilling and completion activities, most of which are contracted for 12 months or less. It is expected that this amount will fluctuate primarily with the number of drilling rigs and completion crews the Company is operating under short-term agreements.

<sup>(2)</sup> &nbsp;&nbsp;&nbsp;&nbsp;Variable lease payments relate to the actual volumes delivered under certain midstream agreements, actual usage associated with drilling rigs, completion crews, and vehicles, and variable utility costs associated with the Company's leased office space. Fluctuations in variable lease payments are primarily driven by actual volumes delivered and the number of drilling rigs and completion crews operating.

Cash paid for amounts included in the measurement of lease liabilities were as follows:

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| | | | |
|:---|:---|:---|:---|
| | **For the Years Ended December 31,** | **For the Years Ended December 31,** | **For the Years Ended December 31,** |
| | **2025** | **2024** | **2023** |
| | **(in millions)** | **(in millions)** | **(in millions)** |
| Operating cash flows related to operating leases | $48 | $11 | $4 |
| Investing cash flows related to operating leases | $19 | $16 | $11 |

---

Maturities for the Company's operating lease liabilities included on the accompanying balance sheets as of December 31, 2025, were as follows:

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| | |
|:---|:---|
| | **As of December 31, 2025** |
| | **(in millions)** |
| 2026 | $69 |
| 2027 | 37 |
| 2028 | 22 |
| 2029 | 14 |
| 2030 | 7 |
| Thereafter | 16 |
| &nbsp;&nbsp;&nbsp;&nbsp;Total Lease payments | $165 |
| Less: Imputed interest <sup>(1)</sup> | (27) |
| &nbsp;&nbsp;&nbsp;&nbsp;Total | $138 |

---

____________________________________________

<sup>(1)&nbsp;&nbsp;&nbsp;&nbsp;</sup>The weighted-average discount rate used to determine the operating lease liability as of December 31, 2025, was 5.7 percent.

------

The following table presents supplemental accompanying balance sheet information for operating leases:

---

| | | | | |
|:---|:---|:---|:---|:---|
| | **As of December 31,** | **As of December 31,** | **As of December 31,** | **As of December 31,** |
| | **2025** | **2025** | **2024** | **2024** |
| | **(in millions, except discount rate and lease term)** | **(in millions, except discount rate and lease term)** | **(in millions, except discount rate and lease term)** | **(in millions, except discount rate and lease term)** |
| Balance sheet classifications of operating leases: |  |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Other noncurrent assets | $| 210 | $| 112 |
| &nbsp;&nbsp;&nbsp;&nbsp;Other current liabilities | $| 58 | $| 22 |
| &nbsp;&nbsp;&nbsp;&nbsp;Other noncurrent liabilities | $| 80 | $| 43 |
| ROU assets obtained in exchange for operating lease liabilities | $| 77 | $| 27 |
| Weighted-average discount rate | 5.7% | 5.7% | 5.5% | 5.5% |
| Weighted-average remaining lease term (years) | 4 | 4 | 4 | 4 |

---

**Note 14 – Accounts Receivable and Accounts Payable and Accrued Expenses**

The components of accounts receivable are as follows:

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| | | |
|:---|:---|:---|
| | **As of December 31,** | **As of December 31,** |
| | **2025** | **2024** |
| | **(in millions)** | **(in millions)** |
| Oil, gas, and NGL production revenue | $193 | $246 |
| Amounts due from joint interest owners | 119 | 98 |
| Other | 19 | 16 |
| Total accounts receivable | $331 | $361 |

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____________________________________________

Note: Amounts may not calculate due to rounding.

The components of accounts payable and accrued expenses are as follows:

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| | | |
|:---|:---|:---|
| | **As of December 31,** | **As of December 31,** |
| | **2025** | **2024** |
| | **(in millions)** | **(in millions)** |
| Drilling and lease operating cost accruals | $167 | $200 |
| Trade accounts payable | 77 | 83 |
| Revenue and severance tax payable | 221 | 246 |
| Property taxes | 48 | 41 |
| Compensation | 49 | 46 |
| Interest | 78 | 80 |
| Dividends payable | 23 | 23 |
| Other | 27 | 42 |
| Total accounts payable and accrued expenses | $690 | $760 |

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____________________________________________

Note: Amounts may not calculate due to rounding.

**Note 15 – Asset Retirement Obligations**

Refer to *Asset Retirement Obligations* in *Note 1 – Summary of Significant Accounting Policies* for a discussion of the initial and subsequent measurements of asset retirement obligation liabilities and the significant assumptions used in the estimates.

------

The following is a reconciliation of the Company's total asset retirement obligation:

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| | | |
|:---|:---|:---|
| | **As of December 31,** | **As of December 31,** |
| | **2025** | **2024** |
| | **(in millions)** | **(in millions)** |
| Beginning asset retirement obligations | $149 | $123 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Liabilities incurred <sup>(1)</sup> | 3 | 21 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Liabilities settled <sup>(2)</sup> | (4) | (27) |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Accretion expense | 9 | 5 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Revision to estimated cash flows |  | 26 |
| Ending asset retirement obligations <sup>(3)</sup> | $157 | $149 |

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____________________________________________

Note: Amounts may not calculate due to rounding.

<sup>(1)</sup> Reflects liabilities incurred through drilling activities and acquisitions of drilled wells.

<sup>(2)</sup> Reflects liabilities settled through plugging and abandonment activities and divestitures of properties.

<sup>(3)</sup> Balances as of December 31, 2025, and 2024, included $7 million and $4 million, respectively, related to the Company's current asset retirement obligation, which is recorded in the accounts payable and accrued expenses line item on the accompanying balance sheets.

**Note 16 – Suspended Well Costs**

The following table reflects the net changes in capitalized exploratory well costs during the periods presented. The table does not include amounts that were capitalized and either subsequently expensed or reclassified to producing well costs in the same year:

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| | | | |
|:---|:---|:---|:---|
| | **For the Years Ended December 31,** | **For the Years Ended December 31,** | **For the Years Ended December 31,** |
| | **2025** | **2024** | **2023** |
| | **(in millions)** | **(in millions)** | **(in millions)** |
| Beginning balance | $33 | $71 | $49 |
| &nbsp;&nbsp;&nbsp;&nbsp;Additions to capitalized exploratory well costs pending the determination of net proved reserves | 22 | 33 | 71 |
| &nbsp;&nbsp;&nbsp;&nbsp;Reclassifications based on the determination of net proved reserves | (33) | (67) | (48) |
| &nbsp;&nbsp;&nbsp;&nbsp;Capitalized exploratory well costs charged to expense <sup>(1)</sup> |  | (4) |  |
| Ending balance | $22 | $33 | $71 |

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____________________________________________

Note: Amounts may not calculate due to rounding.

<sup>(1)</sup> For the year ended December 31, 2024, amount relates to one well deemed non-commercial.

As of December 31, 2025, there were no exploratory well costs that were capitalized for more than one year.

**Note 17 – Mergers, Acquisitions, and Divestitures**

*Civitas Merger*

On November 2, 2025, the Company entered into the Merger Agreement with Civitas. On January 27, 2026, the Company's stockholders voted in favor of both proposals necessary to complete the Civitas Merger, which included approval of (i) the issuance of shares of SM Energy common stock to Civitas stockholders as contemplated by the Merger Agreement, and (ii) an amendment of the Company's Restated Certificate of Incorporation to increase the number of authorized shares of the Company's common stock from 200 million shares to 400 million.

On January 30, 2026, SM Energy completed the Civitas Merger in accordance with the terms of the Merger Agreement, through which SM Energy acquired 100 percent of the outstanding voting equity interests of Civitas. Civitas was an independent exploration and production company focused on the acquisition, development, and production of crude oil and associated liquids-rich natural gas primarily in the DJ Basin in Colorado and the Permian Basin in Texas and New Mexico. The Company believes that the Merger will create a premier portfolio across high-return U.S. shale basins, driving free cash flow, enhancing stockholder value, and enabling the realization of operational and cost efficiencies.

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Under the terms of the Merger Agreement, subject to certain exceptions, each share of Civitas common stock was converted into the right to receive 1.45 shares of SM Energy common stock with cash paid in lieu of fractional shares. On January 30, 2026, the Company issued approximately 124 million shares to holders of Civitas common stock, representing 52 percent of the outstanding shares of SM Energy's common stock upon the closing of the Merger. Based on the closing price of SM Energy common stock on January 30, 2026, the total stock consideration was valued at $2.4 billion.

The Civitas Merger will be accounted for as a business combination using the acquisition method of accounting under ASC Topic 805, *Business Combinations,* with SM Energy treated as the accounting acquirer. Under the acquisition method of accounting, SM Energy will record all assets acquired and liabilities assumed from Civitas at their fair values as of the January 30, 2026 Closing Date of the Merger. The preliminary purchase price assessment is not complete as of the date of this report due to limited time since the Closing Date. The Company will include any required disclosures and information related to the Merger in its Quarterly Report on Form 10-Q for the quarter ended March 31, 2026 or earlier filed Current Reports on Form 8-K, as applicable, pursuant to the rules and regulations of the SEC and authoritative accounting guidance. The Merger was structured as a tax-free reorganization for United States federal income tax purposes.

Following the closing of the Merger, Civitas' post-Merger results of operations will be consolidated into SM Energy's interim consolidated financial statements.

During the year ended December 31, 2025, the Company incurred approximately $7 million of transaction related costs in connection with the Merger. These costs primarily consist of legal, advisory, accounting and valuation fees and have been expensed as incurred and are included in other operating expense on the accompanying statements of operations. Integration and restructuring costs incurred after the Closing Date will be included in general and administrative expense on the accompanying statements of operations.

*South Texas Asset Divestiture*

On February 17, 2026, the Company entered into the PSA with Caturus, pursuant to which the Company agreed to sell all of its rights, titles and interests in certain producing and non-producing assets encompassing approximately 61,000 net acres located in the Company's southern Maverick Basin position in Webb County, Texas (the "Assets"). Upon the closing of the transaction contemplated by the PSA (the "Transaction"), the Company will receive aggregate cash consideration of $950 million (the "Purchase Price"), subject to certain customary purchase price adjustments set forth in the PSA. Upon execution of the PSA, Caturus deposited cash with an escrow agent equal to 7.5 percent of the unadjusted Purchase Price pursuant to an escrow agreement among the Company, Caturus and the escrow agent.

The PSA includes customary representations, warranties, covenants and agreements. The obligations of the parties to complete the Transaction, which is expected to close during the second quarter of 2026, are subject to the satisfaction or waiver of customary closing conditions set forth in the PSA, including the expiration or termination of the applicable waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended, and certain required consents. Upon the closing of the Transaction, the deposit will be applied as a credit toward the Purchase Price.

*2024 Acquisition Activity*

On October 1, 2024, the Company completed the acquisition of an undivided 80 percent interest in both the oil and gas assets of XCL Resources, LLC and certain of its subsidiaries ("XCL Assets") and certain adjacent assets (the "Altamont Option Assets") in the Uinta Basin of northeastern Utah (collectively the "Uinta Basin Acquisition"). The Altamont Option Assets refer to specific oil and gas properties and related interests adjacent to the XCL Assets, acquired pursuant to an exercised purchase option. The Company's undivided 80 percent interest in the assets acquired in the Uinta Basin Acquisition consisted of approximately 63,300 net acres.

In accordance with GAAP, this transaction was considered to be an asset acquisition as substantially all the gross assets acquired were concentrated in a group of similar identifiable assets. Therefore, the properties were recorded based on the total consideration paid after purchase price adjustments and the transaction costs were capitalized as a component of the cost of the assets acquired. The adjusted purchase price was allocated to the assets and liabilities acquired based on their estimated fair value as of the acquisition date using certain assumptions including: (i) estimated net proved and unproved reserves; (ii) production rates; (iii) future operating and development costs; (iv) future commodity prices, including price differentials; (v) risk adjusted future cash flows; and (vi) a market participant-based weighted average cost of capital rate. These inputs required significant judgment by management at the time of the valuation.

On the closing date of October 1, 2024, the unadjusted purchase price, net to the Company's 80 percent undivided interest in the Uinta Basin Acquisition, was approximately $2.1 billion, with approximately $1.9 billion paid in cash using a portion of the net proceeds from the issuance of the 2029 Senior Notes and 2032 Senior Notes discussed in *Note 5 – Long-Term Debt*, cash on hand, and borrowings under the Company's revolving credit facility. The adjusted purchase price was $2.0 billion and was allocated to the assets acquired and liabilities assumed based on the relative fair values on the closing date as follows: (i) $1.6 billion to proved oil and gas properties, (ii) $495 million to unproved oil and gas properties, (iii) $16 million to both operating lease right-of-use assets and

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operating liabilities, (iv) $58 million to revenue and royalties payable and other liabilities, net, and (v) $15 million to asset retirement obligations.

During the first quarter of 2025, the Company finalized post-closing adjustments related to the Uinta Basin Acquisition. The final adjusted purchase price was $2.1 billion.

*2023 Acquisition Activity*

On June 30, 2023, the Company acquired approximately 20,000 net acres of oil and gas properties in Dawson and northern Martin counties, Texas. In accordance with GAAP, this transaction was considered to be an asset acquisition. During the third quarter of 2023, the Company acquired additional working interests in certain wells located in the Midland Basin. Total consideration paid for these transactions, after purchase price adjustments, was $110 million.

**Supplemental Oil and Gas Information (unaudited)**

*Costs Incurred*

Costs incurred in oil and gas property acquisition, exploration, and development activities, whether capitalized or expensed, are summarized as follows:

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| | | | |
|:---|:---|:---|:---|
| | **For the Years Ended December 31,** | **For the Years Ended December 31,** | **For the Years Ended December 31,** |
| | **2025** | **2024** | **2023** |
| | **(in millions)** | **(in millions)** | **(in millions)** |
| Development costs <sup>(1)</sup> | $1333 | $1197 | $932 |
| Exploration costs | 94 | 170 | 173 |
| Acquisitions |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Proved properties | (5) | 1622 | 65 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Unproved properties <sup>(2)</sup> | 26 | 515 | 66 |
| Total, including asset retirement obligations <sup>(3)(4)</sup> | $1448 | $3504 | $1235 |

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____________________________________________

Note: Amounts may not calculate due to rounding.

<sup>(1)</sup> Includes facility costs of $88 million, $42 million, and $24 million for the years ended December 31, 2025, 2024, and 2023, respectively.

<sup>(2)</sup> Includes amounts related to leasing activity and acquiring surface rights outside of acquisitions of proved and unproved properties totaling $7 million, $3 million, and $18 million for the years ended December 31, 2025, 2024, and 2023, respectively.

<sup>(3)</sup> Includes amounts related to estimated asset retirement obligations of $3 million, $48 million, and $6 million for the years ended December 31, 2025, 2024, and 2023, respectively.

<sup>(4)</sup> Includes capitalized interest of $34 million, $26 million, and $20 million for the years ended December 31, 2025, 2024, and 2023, respectively.

*Oil and Gas Reserve Quantities*

The reserve estimates presented below were made in accordance with GAAP requirements for disclosures about oil and gas producing activities and SEC rules for oil and gas reporting of reserve estimation and disclosure.

Proved reserves are the estimated quantities of oil, gas, and NGLs that, 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. Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined, and the price to be used is 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. All of the Company's estimated net proved reserves are located in the United States.

The tables below present a summary of changes in the Company's estimated net proved reserves for each of the years ended December 31, 2025, 2024, and 2023. The Company engaged Ryder Scott to audit internal engineering estimates for at least 80 percent of the Company's total calculated proved reserve PV-10 for each year presented. The Company emphasizes that reserve estimates are inherently imprecise and that estimates of new discoveries and undeveloped locations are more imprecise than estimates

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of established producing oil and gas properties. Accordingly, these estimates are expected to change as future information becomes available.

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| | | | | |
|:---|:---|:---|:---|:---|
| | **For the Year Ended December 31, 2025** | **For the Year Ended December 31, 2025** | **For the Year Ended December 31, 2025** | **For the Year Ended December 31, 2025** |
| | **Oil** | **Gas** | **NGLs** | **Total** |
| | **(MMBbl)** | **(Bcf)** | **(MMBbl)** | **(MMBOE)** |
| **Total net proved reserves:** | **Total net proved reserves:** | | | |
| Beginning of year | 296.0 | 1549.1 | 124.1 | 678.3 |
| &nbsp;&nbsp;Revisions of previous estimates <sup>(1)</sup> | (0.2) | 150.5 | 6.0 | 30.9 |
| &nbsp;&nbsp;&nbsp;Discoveries and extensions | 28.7 | 50.2 | 2.6 | 39.7 |
| &nbsp;&nbsp;&nbsp;Sales of reserves | (1.2) | (3.2) |  | (1.8) |
| &nbsp;&nbsp;Purchases of minerals in place  | 1.0 | 2.4 |  | 1.4 |
| &nbsp;&nbsp;&nbsp;Production | (40.3) | (150.5) | (10.1) | (75.5) |
| End of year | 283.9 | 1598.5 | 122.6 | 673.0 |
| **Net proved developed reserves:** | **Net proved developed reserves:** | **Net proved developed reserves:** |  |  |
| Beginning of year | 160.3 | 1031.3 | 71.8 | 404.0 |
| End of year | 163.7 | 1069.7 | 70.3 | 412.3 |
| **Net proved undeveloped reserves:** | **Net proved undeveloped reserves:** | **Net proved undeveloped reserves:** |  |  |
| Beginning of year | 135.7 | 517.8 | 52.4 | 274.3 |
| End of year | 120.2 | 528.8 | 52.3 | 260.7 |

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____________________________________________

Note: Amounts may not calculate due to rounding.

<sup>(1)&nbsp;&nbsp;&nbsp;&nbsp;</sup>Revisions of previous estimates consist of:

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• 87.0 MMBOE of infill reserves additions;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• 40.7 MMBOE removal of certain net proved undeveloped reserves that are no longer expected to be developed within five years as a result of revisions to the Company's future development plans that have been reclassified to unproved reserve categories;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• 3.7 MMBOE of negative price revisions resulting primarily from decreases in gas prices; and

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• 19.2 MMBOE of negative performance revisions related to well performance.

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Refer to *Areas of Operation* in Part I, Items 1 and 2 of this report, and to *Oil and Gas Reserve Quantities* in *Critical Accounting Estimates* in Part II, Item 7 of this report for additional information.

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| | | | | |
|:---|:---|:---|:---|:---|
| | **For the Year Ended December 31, 2024** | **For the Year Ended December 31, 2024** | **For the Year Ended December 31, 2024** | **For the Year Ended December 31, 2024** |
| | **Oil** | **Gas** | **NGLs** | **Total** |
| | **(MMBbl)** | **(Bcf)** | **(MMBbl)** | **(MMBOE)** |
| **Total net proved reserves:** | | | | |
| Beginning of year | 230.1 | 1532.0 | 119.5 | 604.9 |
| &nbsp;&nbsp;Revisions of previous estimates <sup>(1)</sup> | 3.5 | 30.7 | 14.1 | 22.7 |
| &nbsp;&nbsp;&nbsp;Discoveries and extensions | 7.2 | 19.4 | 0.7 | 11.1 |
| &nbsp;&nbsp;&nbsp;Sales of reserves | (0.7) | (3.3) |  | (1.2) |
| &nbsp;&nbsp;Purchases of minerals in place <sup>(2)</sup> | 85.3 | 107.3 |  | 103.2 |
| &nbsp;&nbsp;&nbsp;Production | (29.3) | (137.0) | (10.2) | (62.4) |
| End of year | 296.0 | 1549.1 | 124.1 | 678.3 |
| **Net proved developed reserves:** |  |  |  |  |
| Beginning of year | 118.5 | 948.5 | 64.7 | 341.2 |
| End of year | 160.3 | 1031.3 | 71.8 | 404.0 |
| **Net proved undeveloped reserves:** |  |  |  |  |
| Beginning of year | 111.6 | 583.5 | 54.8 | 263.6 |
| End of year | 135.7 | 517.8 | 52.4 | 274.3 |

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____________________________________________

Note: Amounts may not calculate due to rounding.

<sup>(1)&nbsp;&nbsp;&nbsp;&nbsp;</sup>Revisions of previous estimates consist of:

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• 74.7 MMBOE of infill additions;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• 30.5 MMBOE removal of certain net proved undeveloped reserves cases that are no longer expected to be developed within the five-year period from initial booking as a result of the reallocation of capital to include the Company's Uinta Basin assets, and certain lease obligations;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• 13.4 MMBOE of negative price revisions resulting primarily from decreases in gas prices; and

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• 8.0 MMBOE of negative performance revisions related to well performance.

<sup>(2)&nbsp;&nbsp;&nbsp;&nbsp;</sup>Purchases of minerals in place consist of 103.2 MMBOE acquired as part of the Uinta Basin Acquisition. Refer to *Note 17 – Mergers, Acquisitions, and Divestitures* for additional information.

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| | | | | |
|:---|:---|:---|:---|:---|
| | **For the Year Ended December 31, 2023** | **For the Year Ended December 31, 2023** | **For the Year Ended December 31, 2023** | **For the Year Ended December 31, 2023** |
| | **Oil** | **Gas** | **NGLs** | **Total** |
| | **(MMBbl)** | **(Bcf)** | **(MMBbl)** | **(MMBOE)** |
| **Total net proved reserves:** | | | | |
| Beginning of year | 205.8 | 1402.9 | 97.8 | 537.4 |
| &nbsp;&nbsp;Revisions of previous estimates <sup>(1)</sup> | 38.7 | 194.2 | 20.8 | 91.9 |
| &nbsp;&nbsp;&nbsp;Discoveries and extensions | 8.9 | 69.1 | 10.5 | 30.9 |
| &nbsp;&nbsp;&nbsp;Sales of reserves | (3.2) | (13.1) |  | (5.4) |
| &nbsp;&nbsp;&nbsp;Purchases of minerals in place | 3.6 | 11.2 |  | 5.5 |
| &nbsp;&nbsp;&nbsp;Production | (23.8) | (132.4) | (9.7) | (55.5) |
| End of year | 230.1 | 1532.0 | 119.5 | 604.9 |
| **Net proved developed reserves:** |  |  |  |  |
| Beginning of year | 110.4 | 902.1 | 57.1 | 317.8 |
| End of year | 118.5 | 948.5 | 64.7 | 341.2 |
| **Net proved undeveloped reserves:** |  |  |  |  |
| Beginning of year | 95.4 | 500.8 | 40.7 | 219.6 |
| End of year | 111.6 | 583.5 | 54.8 | 263.6 |

---

____________________________________________

Note: Amounts may not calculate due to rounding.

<sup>(1)</sup> Revisions of previous estimates consist of:

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• 113.9 MMBOE of infill reserves additions;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• 65.3 MMBOE of positive price revisions resulting from changes to decline curve estimates based on reservoir engineering analysis;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• 28.0 MMBOE of negative performance revisions related to well performance;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• 30.8 MMBOE of estimated net proved undeveloped reserves reclassified to unproved reserves categories resulting from revising certain aspects of the Company's future development plans, and due to certain lease obligations; and

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• 28.4 MMBOE of negative price revisions resulting primarily from decreases in gas and NGL prices.

*Standardized Measure of Discounted Future Net Cash Flows*

The Company computes a standardized measure of discounted future net cash flows and changes therein relating to estimated proved reserves in accordance with authoritative accounting guidance. Future cash inflows and production and development costs are determined by applying prices and costs, including transportation, quality, and basis differentials, to the year-end estimated future reserve quantities. Each property the Company operates is also charged with field-level overhead in the estimated reserve calculation. Estimated future income taxes are computed using the current statutory income tax rates, including consideration for estimated future statutory depletion. The resulting future net cash flows are reduced to present value amounts by applying a 10 percent annual discount factor.

Future operating costs are determined based on estimates of expenditures to be incurred in developing and producing the estimated proved reserves in place at the end of the period using year end costs and assuming continuation of existing economic conditions, plus Company overhead incurred by the central administrative office attributable to operating activities and estimated abandonment costs.

The assumptions used to compute the standardized measure of discounted future net cash flows are those prescribed by the FASB and the SEC. These assumptions do not necessarily reflect the Company's expectations of actual revenues to be derived from those reserves, nor their present value amount. The limitations inherent in the reserve quantity estimation process, as discussed previously, are equally applicable to the standardized measure of discounted future net cash flows computations since these reserve quantity estimates are the basis for the valuation process. The following prices as adjusted for transportation, quality, and basis differentials were used in the calculation of the standardized measure of discounted future net cash flows:

---

| | | | |
|:---|:---|:---|:---|
| | **For the Years Ended December 31,** | **For the Years Ended December 31,** | **For the Years Ended December 31,** |
| | **2025** | **2024** | **2023** |
| Oil (per Bbl) | $64.05 | $74.75 | $77.96 |
| Gas (per Mcf) | $2.45 | $1.86 | $2.52 |
| NGLs (per Bbl) | $21.64 | $22.45 | $22.35 |

---

------

The following summary sets forth the Company's future net cash flows relating to proved oil, gas, and NGL reserves based on the standardized measure of discounted future net cash flows:

---

| | | | |
|:---|:---|:---|:---|
| | **As of December 31,** | **As of December 31,** | **As of December 31,** |
| | **2025** | **2024** | **2023** |
| | **(in millions)** | **(in millions)** | **(in millions)** |
| Future cash inflows | $24750 | $27798 | $24466 |
| &nbsp;&nbsp;&nbsp;&nbsp;Future production costs | (10060) | (10480) | (7894) |
| &nbsp;&nbsp;&nbsp;&nbsp;Future development costs | (2877) | (3235) | (2998) |
| &nbsp;&nbsp;&nbsp;&nbsp;Future income taxes | (1539) | (1796) | (2000) |
| Future net cash flows | 10274 | 12286 | 11575 |
| &nbsp;&nbsp;&nbsp;&nbsp;10 percent annual discount | (4318) | (5019) | (5295) |
| Standardized measure of discounted future net cash flows | $5956 | $7268 | $6280 |

---

____________________________________________

Note: Amounts may not calculate due to rounding.

The principal sources of changes in the standardized measure of discounted future net cash flows were:

---

| | | | |
|:---|:---|:---|:---|
| | **For the Years Ended December 31,** | **For the Years Ended December 31,** | **For the Years Ended December 31,** |
| | **2025** | **2024** | **2023** |
| | **(in millions)** | **(in millions)** | **(in millions)** |
| Standardized measure of discounted future net cash flows, beginning of year | $7268 | $6280 | $9962 |
| &nbsp;&nbsp;&nbsp;&nbsp;Sales of oil, gas, and NGLs produced, net of production costs | (2253) | (2034) | (1800) |
| &nbsp;&nbsp;&nbsp;&nbsp;Net changes in prices and production costs | (1281) | (922) | (5650) |
| &nbsp;&nbsp;&nbsp;&nbsp;Extensions and discoveries, net of related costs | 338 | 183 | 281 |
| &nbsp;&nbsp;&nbsp;&nbsp;Sales of reserves in place | (22) | (14) | (84) |
| &nbsp;&nbsp;&nbsp;&nbsp;Purchase of reserves in place | 14 | 1655 | 151 |
| &nbsp;&nbsp;&nbsp;&nbsp;Previously estimated development costs incurred during the period | 987 | 1022 | 773 |
| &nbsp;&nbsp;&nbsp;&nbsp;Changes in estimated future development costs | (57) | 59 | 100 |
| &nbsp;&nbsp;&nbsp;&nbsp;Revisions of previous quantity estimates | 146 | 467 | 538 |
| &nbsp;&nbsp;&nbsp;&nbsp;Accretion of discount | 835 | 738 | 1215 |
| &nbsp;&nbsp;&nbsp;&nbsp;Net change in income taxes | 197 | 9 | 1096 |
| &nbsp;&nbsp;&nbsp;&nbsp;Changes in timing and other | (216) | (173) | (302) |
| Standardized measure of discounted future net cash flows, end of year | $5956 | $7268 | $6280 |

---

____________________________________________

Note: Amounts may not calculate due to rounding.

------

**ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE**

None.

**ITEM 9A. CONTROLS AND PROCEDURES**

**Evaluation of Disclosure Controls and Procedures**

We maintain a system of disclosure controls and procedures that are designed to reasonably ensure that information required to be disclosed in our SEC reports is recorded, processed, summarized, and reported within the time periods specified in the SEC's rules and forms, and to reasonably ensure that such information is accumulated and communicated to our management, including our Chief Executive Officer (Principal Executive Officer) and our Chief Financial Officer (Principal Financial Officer), as appropriate, to allow for timely decisions regarding required disclosure.

Our management, including our Chief Executive Officer and our Chief Financial Officer, does not expect that our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) of the Exchange Act) ("Disclosure Controls") will prevent all errors and all fraud. A control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Further, the design of a control system must reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs. Because of the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, within our company have been detected. These inherent limitations include the realities that judgments in decision-making can be faulty, and that breakdowns can occur because of simple error or mistake. Additionally, controls can be circumvented by the individual acts of some persons, by collusion of two or more people, or by management override of the control. The design of any system of controls also is based in part upon certain assumptions about the likelihood of future events, and there can be no assurance that any design will succeed in achieving its stated goals under all potential future conditions. Because of the inherent limitations in a cost-effective control system, misstatements due to error or fraud may occur and not be detected. We monitor our Disclosure Controls and make modifications as necessary; our intent in this regard is that the Disclosure Controls will be modified as systems change and conditions warrant.

An evaluation of the effectiveness of the design and operation of our Disclosure Controls was performed as of the end of the period covered by this report. This evaluation was performed under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer. Based upon that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our Disclosure Controls are effective at a reasonable assurance level.

**Changes in Internal Control Over Financial Reporting**

There have been no changes to our internal control over financial reporting (as defined in Rule 13a-15(f) under the Exchange Act) that occurred during the fourth quarter of 2025 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

------

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

Management of the Company is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act. The Company's internal control over financial reporting is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. The Company's internal control over financial reporting includes those policies and procedures that:

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(i)pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the Company;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(ii)provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the Company are being made only in accordance with authorizations of management and directors of the Company; and

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(iii)provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the Company's assets that have a material effect on the financial statements.

Because of the inherent limitations, internal controls over financial reporting may not prevent or detect misstatements. Even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of the changes in conditions, or that the degree of compliance with the policies and procedures may deteriorate.

Management assessed the effectiveness of the Company's internal control over financial reporting as of December 31, 2025. In making this assessment, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission in *Internal Control-Integrated Framework* (2013 framework)*.*

Based on management's assessment and those criteria, management concluded that the Company maintained effective internal control over financial reporting as of December 31, 2025.

The Company's independent registered public accounting firm has issued an attestation report on the Company's internal control over financial reporting. That report immediately follows this report.

------

**Report of Independent Registered Public Accounting Firm**

To the Stockholders and the Board of Directors of SM Energy Company

**Opinion on Internal Control Over Financial Reporting**

We have audited SM Energy Company and subsidiaries' internal control over financial reporting as of December 31, 2025, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) (the COSO criteria). In our opinion, SM Energy Company and subsidiaries (the Company) maintained, in all material respects, effective internal control over financial reporting as of December 31, 2025, based on the COSO criteria.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the 2025 consolidated financial statements of the Company and our report dated February 26, 2026 expressed an unqualified opinion thereon.

**Basis for Opinion**

The Company's management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management's Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company's internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects.

Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

**Definition and Limitations of Internal Control Over Financial Reporting**

A company's internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

/s/ Ernst & Young LLP

Denver, Colorado

February 26, 2026

------

**ITEM 9B. OTHER INFORMATION**

During the three months ended December 31, 2025, none of our directors or Section 16 officers adopted or terminated a "Rule 10b5-1 trading arrangement" or "non-Rule 10b5-1 trading arrangement," as each term is defined in Item 408 of Regulation S-K.

**ITEM 9C. DISCLOSURE REGARDING FOREIGN JURISDICTIONS THAT PREVENT INSPECTIONS**

These disclosures are not applicable to the Company.

**PART III**

**ITEM 10. DIRECTORS, EXECUTIVE OFFICERS, AND CORPORATE GOVERNANCE**

The information required by this Item is incorporated by reference to the information provided under the captions "*Corporate Governance," "Proposal 1 - Election of Directors," and "Information about our Executive Officers"* in the Company's Definitive Proxy Statement on Schedule 14A for the 2026 annual meeting of stockholders, to be filed within 120 days from December 31, 2025.

The Company has adopted insider trading policies and procedures governing the purchase, sale, and/or other dispositions of the registrant's securities by directors, officers, and employees. This policy is filed as Exhibit 19.1 to this report.

**ITEM 11. EXECUTIVE COMPENSATION**

The information required by this Item is incorporated by reference to the information provided under the captions "*Compensation Discussion and Analysis,*" "*Executive Compensation Tables*," "*Director Compensation*" and "*Certain Relationships and Related Transactions – Compensation Committee Interlocks and Insider Participation*" in the Company's Definitive Proxy Statement on Schedule 14A for the 2026 annual meeting of stockholders, to be filed within 120 days from December 31, 2025.

**ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS**

The information required by this Item concerning security ownership of certain beneficial owners and management is incorporated by reference to the information provided under the caption "*Security Ownership of Certain Beneficial Owners and Management"* in the Company's Definitive Proxy Statement on Schedule 14A for the 2026 annual meeting of stockholders, to be filed within 120 days from December 31, 2025.

------

*Securities Authorized for Issuance Under Equity Compensation Plans.* The Company has equity compensation plans under which options and shares of the Company's common stock are authorized for grant or issuance as compensation to eligible employees, consultants, and members of the Board of Directors. The Company's stockholders have approved these plans. Refer to *Note 10 – Stock-Based Compensation* in Part II, Item 8 of this report for further information about the material terms of the Company's equity compensation plans. The following table is a summary of the shares of common stock authorized for issuance under equity compensation plans as of December 31, 2025:

---

| | | | |
|:---|:---|:---|:---|
|<br>**Plan category** | **(a)**<br>**Number of securities to be issued upon exercise of outstanding options, warrants, and rights** | **(b)**<br>**Weighted-average exercise price of outstanding options, warrants, and rights** | **(c)**<br>**Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a))** |
| Equity compensation plans approved by security holders: |  |  |  |
| Equity Incentive Compensation Plan <sup>(1)</sup> |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Restricted stock units <sup>(2)</sup> | 1447925 | N/A |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Performance share units <sup>(2) (3)</sup> | 819605 | N/A |  |
| Total for Equity Incentive Compensation Plan | 2267530 | $— | 2532469 |
| Employee Stock Purchase Plan <sup>(4)</sup> |  |  |  |
| Equity compensation plans not approved by security holders |  |  |  |
| Total for all plans | 2267530 | $— | 2532469 |

---

____________________________________________

<sup>(1)</sup> On May 22, 2025, the Company's stockholders approved the 2025 Equity Plan, which succeeded the Predecessor Equity Plan. The Company ceased granting awards under the Predecessor Equity Plan following the approval of the 2025 Equity Plan, however, existing awards remain outstanding under the Predecessor Equity Plan. The 2025 Equity Plan authorizes the issuance of restricted stock, restricted stock units, nonqualified stock options, incentive stock options, stock appreciation rights, performance share units, and stock-based awards to key employees, consultants, and members of the Board of Directors of the Company or any affiliate of the Company. The total number of shares of the Company's common stock underlying awards granted in 2025, 2024, and 2023 under the Equity Plans were 1,466,390, 774,687, and 943,979, respectively.

<sup>(2)</sup> RSUs and PSUs do not have exercise prices associated with them, but rather a weighted-average per unit fair value, which is presented in order to provide additional information regarding the potential dilutive effect of the awards. The weighted-average grant date per unit fair value for the outstanding RSUs and PSUs was $30.55 and $32.18, respectively. Refer to *Note 10 – Stock-Based Compensation* in Part II, Item 8 of this report for additional discussion.

<sup>(3)</sup> The number of shares of common stock assumes a multiplier of one. The actual final number of shares of common stock to be issued will range from zero to two times the number of PSUs awarded depending on the three-year performance multiplier.

<sup>(4)</sup> Under the Company's ESPP, eligible employees may purchase shares of the Company's common stock through payroll deductions of up to 15 percent of their eligible compensation, subject to certain limitations as set forth in the Equity Plans. The purchase price of the common stock is 85 percent of the lower of the trading price of the common stock on either the first or last day of the six-month offering period. The ESPP is intended to qualify under Section 423 of the IRC. The total number of shares of the Company's common stock issued in 2025, 2024, and 2023 under the ESPP were 167,027, 97,500, and 114,427, respectively.

**ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE**

The information required by this Item is incorporated by reference to the information provided under the captions "*Corporate Governance - Board and Committee Independence*" and "*Certain Relationships and Related Transactions*" in the Company's Definitive Proxy Statement on Schedule 14A for the 2026 annual meeting of stockholders, to be filed within 120 days from December 31, 2025.

**ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES**

The information required by this Item is incorporated by reference to the information provided under the caption "*Independent Registered Accounting Firm*" in the Company's Definitive Proxy Statement on Schedule 14A for the 2026 annual meeting of stockholders, to be filed within 120 days from December 31, 2025.

------

**PART IV**

**ITEM 15. EXHIBITS AND CONSOLIDATED FINANCIAL STATEMENT SCHEDULES**

*(a)(1) and (a)(2) Consolidated Financial Statements and Financial Statement Schedules:*

---

| | |
|:---|:---|
| Report of Independent Registered Public Accounting Firm (PCAOB ID 42) | <u>[66](#i293a8c843fc7462dbf208500aa1f98b0_169)</u> |
| Consolidated Balance Sheets | <u>[68](#i293a8c843fc7462dbf208500aa1f98b0_172)</u> |
| Consolidated Statements of Operations | <u>[69](#i293a8c843fc7462dbf208500aa1f98b0_175)</u> |
| Consolidated Statements of Comprehensive Income | <u>[70](#i293a8c843fc7462dbf208500aa1f98b0_178)</u> |
| Consolidated Statements of Stockholders' Equity | <u>[71](#i293a8c843fc7462dbf208500aa1f98b0_181)</u> |
| Consolidated Statements of Cash Flows | <u>[72](#i293a8c843fc7462dbf208500aa1f98b0_184)</u> |
| Notes to Consolidated Financial Statements | <u>[74](#i293a8c843fc7462dbf208500aa1f98b0_187)</u> |

---

All schedules are omitted because the required information is not applicable or is not present in amounts sufficient to require submission of the schedule or because the information required is included in the Consolidated Financial Statements and Notes thereto.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;*(b) Exhibits.* The following exhibits are filed or furnished with or incorporated by reference into this report on Form 10-K:

---

| | |
|:---|:---|
| **Exhibit**<br>**<u>Number</u>** | **<u>Description</u>** |
| <u>[2.1](https://www.sec.gov/Archives/edgar/data/893538/000089353825000144/exhibit21agreementandplano.htm)</u> | <u>[Agreement and Plan of Merger among SM Energy Company, Cars Merger Sub, Inc., and Civitas Resources, Inc., dated as of November 2, 2025 (filed as Exhibit 2.1 to the registrant's Current Report on Form 8-K filed November 3, 2025, and incorporated herein by reference)](https://www.sec.gov/Archives/edgar/data/893538/000089353825000144/exhibit21agreementandplano.htm)</u> |
| <u>[3.1](https://www.sec.gov/Archives/edgar/data/893538/000110465910041421/a10-13039_1ex3d1.htm)</u> | <u>[Restated Certificate of Incorporation of SM Energy Company, as amended through June 1, 2010 (filed as Exhibit 3.1 to the registrant's Quarterly Report on Form 10-Q for the quarter ended June 30, 2010, and incorporated herein by reference)](https://www.sec.gov/Archives/edgar/data/893538/000110465910041421/a10-13039_1ex3d1.htm)</u> |
| <u>[3.2](https://www.sec.gov/Archives/edgar/data/893538/000089353823000040/exhibit31-certificateofame.htm)</u> | <u>[Certificate of Amendment of Restated Certificate of Incorporation of SM Energy Company, as amended through June 1, 2010, dated May 25, 2023 (filed as Exhibit 3.1 to the registrant's Current Report on Form 8-K filed on May 30, 2023, and incorporated herein by reference)](https://www.sec.gov/Archives/edgar/data/893538/000089353823000040/exhibit31-certificateofame.htm)</u> |
| <u>[3.3](https://www.sec.gov/Archives/edgar/data/893538/000110465926008380/tm264415d2_ex3-1.htm)</u> | <u>[Certificate of Amendment to the Restated Certificate of Incorporation of SM Energy Company, dated January 30, 2026](https://www.sec.gov/Archives/edgar/data/893538/000110465926008380/tm264415d2_ex3-1.htm)[(file](https://www.sec.gov/Archives/edgar/data/893538/000110465926008380/tm264415d2_ex3-1.htm)[d as Exhibit 3.1 to the registrant](https://www.sec.gov/Archives/edgar/data/893538/000110465926008380/tm264415d2_ex3-1.htm)['](https://www.sec.gov/Archives/edgar/data/893538/000110465926008380/tm264415d2_ex3-1.htm)[s Current Report on For](https://www.sec.gov/Archives/edgar/data/893538/000110465926008380/tm264415d2_ex3-1.htm)[m 8-K filed January 30, 2026, and incorporated herein by referen](https://www.sec.gov/Archives/edgar/data/893538/000110465926008380/tm264415d2_ex3-1.htm)[ce)](https://www.sec.gov/Archives/edgar/data/893538/000110465926008380/tm264415d2_ex3-1.htm)</u> |
| <u>[3.](https://www.sec.gov/Archives/edgar/data/893538/000089353817000013/exhibit32-amendedandrestat.htm)[4](https://www.sec.gov/Archives/edgar/data/893538/000089353817000013/exhibit32-amendedandrestat.htm)</u> | <u>[Amended and Restated By-Laws of SM Energy Company, effective as of February 21, 2017 (filed as Exhibit 3.2 to the registrant's Annual Report on Form 10-K for the year ended December 31, 2016, and incorporated herein by reference)](https://www.sec.gov/Archives/edgar/data/893538/000089353817000013/exhibit32-amendedandrestat.htm)</u> |
| <u>[4.](https://www.sec.gov/Archives/edgar/data/893538/000110465916139281/a16-16325_11ex4d1.htm)[1](https://www.sec.gov/Archives/edgar/data/893538/000110465916139281/a16-16325_11ex4d1.htm)</u> | <u>[Base Indenture, dated as of May 21, 2015, by and between SM Energy Company and U.S. Bank National Association, as trustee (filed as Exhibit 4.1 to the registrant's Current Report on Form 8-K filed on August 12, 2016, and incorporated herein by reference)](https://www.sec.gov/Archives/edgar/data/893538/000110465916139281/a16-16325_11ex4d1.htm)</u> |
| <u>[4.](https://www.sec.gov/Archives/edgar/data/893538/000110465916144202/a16-17878_4ex4d2.htm)[2](https://www.sec.gov/Archives/edgar/data/893538/000110465916144202/a16-17878_4ex4d2.htm)</u> | <u>[Third Supplemental Indenture, dated September 12, 2016 by and between SM Energy Company and U.S. Bank National Association, as trustee (filed as Exhibit 4.2 to the registrant's Current Report on Form 8-K filed on September 12, 2016, and incorporated herein by reference)](https://www.sec.gov/Archives/edgar/data/893538/000110465916144202/a16-17878_4ex4d2.htm)</u> |
| <u>[4.](https://www.sec.gov/Archives/edgar/data/893538/000110465918052819/a18-19088_1ex4d2.htm#Exhibit4_2_034244)[3](https://www.sec.gov/Archives/edgar/data/893538/000110465918052819/a18-19088_1ex4d2.htm#Exhibit4_2_034244)</u> | <u>[Fourth Supplemental Indenture, dated as of August 20, 2018, by and between SM Energy Company and U.S. Bank National Association, as trustee (filed as Exhibit 4.2 to the registrant's Current Report on Form 8-K filed on August 20, 2018, and incorporated herein by reference)](https://www.sec.gov/Archives/edgar/data/893538/000110465918052819/a18-19088_1ex4d2.htm#Exhibit4_2_034244)</u> |
| <u>[4.](https://www.sec.gov/Archives/edgar/data/893538/000110465921084648/tm2120478d1_ex4-2.htm)[4](https://www.sec.gov/Archives/edgar/data/893538/000110465921084648/tm2120478d1_ex4-2.htm)</u> | <u>[Fifth Supplemental Indenture, dated as of June 23, 2021, by and between SM Energy Company and U.S. Bank National Association, as trustee (filed as Exhibit 4.2 to the registrant's Current Report on Form 8-K filed on June 23, 2021, and incorporated herein by reference)](https://www.sec.gov/Archives/edgar/data/893538/000110465921084648/tm2120478d1_ex4-2.htm)</u> |
| <u>[4.](https://www.sec.gov/Archives/edgar/data/893538/000089353824000085/exhibit41indenture.htm)[5](https://www.sec.gov/Archives/edgar/data/893538/000089353824000085/exhibit41indenture.htm)</u> | <u>[Indenture, dated as of July 25, 2024, by and between SM Energy Company and U.S. Bank Trust Company, National Association, as trustee (filed as Exhibit 4.1 to the registrant's Current Report on Form 8-K filed on July 25, 2024, and incorporated herein by reference)](https://www.sec.gov/Archives/edgar/data/893538/000089353824000085/exhibit41indenture.htm)</u> |
| <u>[4.](https://www.sec.gov/Archives/edgar/data/1509589/000110465921126831/tm2129993d1_ex4-1.htm)[6](https://www.sec.gov/Archives/edgar/data/1509589/000110465921126831/tm2129993d1_ex4-1.htm)</u> | <u>[Indenture, dated as of October 13, 2021, by and among Bonanza Creek Energy, Inc., the guarantors party thereto and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 4.1 to Bonanza Creek Energy, Inc.'s Current Report on Form 8-K filed on October 15, 2021, file no. 001-35371)](https://www.sec.gov/Archives/edgar/data/1509589/000110465921126831/tm2129993d1_ex4-1.htm)</u> |
| <u>[4.](https://www.sec.gov/Archives/edgar/data/1509589/000119312521318493/d205905dex41.htm)[7](https://www.sec.gov/Archives/edgar/data/1509589/000119312521318493/d205905dex41.htm)</u> | <u>[First Supplemental Indenture, dated as of November 1, 2021, by and among Civitas Resources, Inc., Computershare Trust Company, N.A., as trustee, and certain guarantor parties thereto (incorporated by reference to Exhibit 4.1 to Civitas Resources, Inc.'s Current Report on Form 8-K filed on November 3, 2021, file no. 001-35371)](https://www.sec.gov/Archives/edgar/data/1509589/000119312521318493/d205905dex41.htm)</u> |
| <u>[4.](https://www.sec.gov/Archives/edgar/data/1509589/000150958923000106/ex43thirdsupplementalinden.htm)[8](https://www.sec.gov/Archives/edgar/data/1509589/000150958923000106/ex43thirdsupplementalinden.htm)</u> | <u>[Third Supplemental Indenture, dated August 2, 2023, by and among Civitas Resources, Inc., as issuer, the guarantors party thereto and Computershare Trust Company, N.A., as trustee (incorporated by reference to Exhibit 4.3 to Civitas Resources, Inc.'s Quarterly Report on Form 10-Q filed on November 7, 2023, file no. 001-35371)](https://www.sec.gov/Archives/edgar/data/1509589/000150958923000106/ex43thirdsupplementalinden.htm)</u> |

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| | |
|:---|:---|
| <u>[4.](https://www.sec.gov/Archives/edgar/data/1509589/000110465923076340/tm2320046d1_ex4-1.htm)[9](https://www.sec.gov/Archives/edgar/data/1509589/000110465923076340/tm2320046d1_ex4-1.htm)</u> | <u>[Indenture, dated June 29, 2023, by and among Civitas Resources, Inc., as issuer, the guarantors party thereto and Computershare Trust Company, N.A., as trustee (incorporated by reference to Exhibit 4.1 to Civitas Resources, Inc.'s Current Report on Form 8-K filed on June 29, 2023, file no. 001-35371)](https://www.sec.gov/Archives/edgar/data/1509589/000110465923076340/tm2320046d1_ex4-1.htm)</u> |
| <u>[4.1](https://www.sec.gov/Archives/edgar/data/1509589/000150958923000106/ex41firstsupplementalinden.htm)[0](https://www.sec.gov/Archives/edgar/data/1509589/000150958923000106/ex41firstsupplementalinden.htm)</u> | <u>[First Supplemental Indenture, dated August 2, 2023, by and among Civitas Resources, Inc., as issuer, the guarantors party thereto and Computershare Trust Company, N.A., as trustee (incorporated by reference to Exhibit 4.1 to Civitas Resources, Inc.'s Quarterly Report on Form 10-Q filed on November 7, 2023, file no. 001-35371)](https://www.sec.gov/Archives/edgar/data/1509589/000150958923000106/ex41firstsupplementalinden.htm)</u> |
| <u>[4.1](https://www.sec.gov/Archives/edgar/data/1509589/000110465923076340/tm2320046d1_ex4-3.htm)[1](https://www.sec.gov/Archives/edgar/data/1509589/000110465923076340/tm2320046d1_ex4-3.htm)</u> | <u>[Indenture, dated June 29, 2023, by and among Civitas Resources, Inc., as issuer, the guarantors party thereto and Computershare Trust Company, N.A., as trustee (incorporated by reference to Exhibit 4.3 to Civitas Resources, Inc.'s Current Report on Form 8-K filed on June 29, 2023, file no. 001-35371)](https://www.sec.gov/Archives/edgar/data/1509589/000110465923076340/tm2320046d1_ex4-3.htm)</u> |
| <u>[4.1](https://www.sec.gov/Archives/edgar/data/1509589/000150958923000106/ex42firstsupplementalinden.htm)[2](https://www.sec.gov/Archives/edgar/data/1509589/000150958923000106/ex42firstsupplementalinden.htm)</u> | <u>[First Supplemental Indenture, dated August 2, 2023, by and among Civitas Resources, Inc., as issuer, the guarantors party thereto and Computershare Trust Company, N.A., as trustee (incorporated by reference to Exhibit 4.2 to Civitas Resources, Inc.'s Quarterly Report on Form 10-Q filed on November 7, 2023, file no. 001-35371)](https://www.sec.gov/Archives/edgar/data/1509589/000150958923000106/ex42firstsupplementalinden.htm)</u> |
| <u>[4.1](https://www.sec.gov/Archives/edgar/data/1509589/000110465923109865/tm2320652d13_ex4-1.htm)[3](https://www.sec.gov/Archives/edgar/data/1509589/000110465923109865/tm2320652d13_ex4-1.htm)</u> | <u>[Indenture, dated October 17, 2023, by and among Civitas Resources, Inc., as issuer, the guarantors party thereto and Computershare Trust Company, N.A., as trustee (incorporated by reference to Exhibit 4.1 to Civitas Resources, Inc.'s Current Report on Form 8-K filed on October 18, 2023, file no. 001-35371)](https://www.sec.gov/Archives/edgar/data/1509589/000110465923109865/tm2320652d13_ex4-1.htm)</u> |
| <u>[4.1](https://www.sec.gov/Archives/edgar/data/1509589/000110465925055975/tm2516904d1_ex4-1.htm)[4](https://www.sec.gov/Archives/edgar/data/1509589/000110465925055975/tm2516904d1_ex4-1.htm)</u> | <u>[Indenture, dated June 3, 2025, by and among Civitas Resources, Inc., as issuer, the guarantors party thereto and Computershare Trust Company, N.A., as trustee, pursuant to which the 2033 Senior Notes were issued (incorporated by reference to Exhibit 4.1 to Civitas Resources, Inc.'s Current Report on Form 8-K filed on June 3, 2025, file no. 001-35371)](https://www.sec.gov/Archives/edgar/data/1509589/000110465925055975/tm2516904d1_ex4-1.htm)</u> |
| <u>[4.15](exhibit415-civitasindentur.htm)[\*](exhibit415-civitasindentur.htm)</u> | <u>[Fourth Supplemental Indenture, dated as of January 30, 2026, by and among SM Energy Company, the guarantors party thereto and Computershare Trust Company, N.A. (as successor trustee to Wells Fargo Bank, National Association), supplementing the Indenture dated as of October 13, 2021](exhibit415-civitasindentur.htm)</u> |
| <u>[4.16](exhibit416-civitasindentur.htm)[\*](exhibit416-civitasindentur.htm)</u> | <u>[Second Supplemental Indenture, dated as of January 30, 2026, by and among SM Energy Company, the guarantors party thereto and Computershare Trust Company, N.A., as trustee, supplementing the Indenture dated as of June 29, 2023](exhibit416-civitasindentur.htm)</u> |
| <u>[4.17](exhibit417-civitasindentur.htm)[\*](exhibit417-civitasindentur.htm)</u> | <u>[Second Supplemental Indenture, dated as of January 30, 2026, by and among SM Energy Company, the guarantors party thereto and Computershare Trust Company, N.A., as trustee, supplementing the Indenture dated as of June 29, 2023](exhibit417-civitasindentur.htm)</u> |
| <u>[4.18](exhibit418-civitasindentur.htm)[\*](exhibit418-civitasindentur.htm)</u> | <u>[First Supplemental Indenture, dated as of January 30, 2026, by and among SM Energy Company, the guarantors party thereto and Computershare Trust Company, N.A., as trustee, supplementing the Indenture dated as of October 17, 2023](exhibit418-civitasindentur.htm)</u> |
| <u>[4.19](exhibit419-civitasindentur.htm)[\*](exhibit419-civitasindentur.htm)</u> | <u>[First Supplemental Indenture, dated as of January 30, 2026, by and among SM Energy Company, the guarantors party thereto and Computershare Trust Company, N.A., as trustee, supplementing the Indenture dated as of June 3, 2025](exhibit419-civitasindentur.htm)</u> |
| <u>[4.2](exhibit420-smindenturexgua.htm)[0\*](exhibit420-smindenturexgua.htm)</u> | <u>[First Supplemental Indenture, dated as of January 30, 2026, by and among SM Energy Company, the guarantors party thereto and U.S. Bank Trust Company, National Association, as trustee, supplementing the Indenture dated as of July 25, 2024](exhibit420-smindenturexgua.htm)</u> |
| <u>[4.21](exhibit421-smindenturexgua.htm)[\*](exhibit421-smindenturexgua.htm)</u> | <u>[Sixth Supplemental Indenture, dated as of January 30, 2026, by and among SM Energy Company, the guarantors party thereto and U.S. Bank Trust Company, National Association (as successor in interest to U.S. Bank, National Association), as trustee, supplementing the Indenture dated as of May 21, 2015](exhibit421-smindenturexgua.htm)</u> |
| <u>[4.](exhibit422-descriptionofse.htm)[22](exhibit422-descriptionofse.htm)[\*](exhibit422-descriptionofse.htm)</u> | <u>[Description of Securities](exhibit422-descriptionofse.htm)</u> |
| <u>[10.1](https://www.sec.gov/Archives/edgar/data/893538/000089353809000021/exhibit102.htm)</u> | <u>[Deed of Trust to Wachovia Bank, National Association, as Administrative Agent, dated effective as of April 14, 2009 (filed as Exhibit 10.2 to the registrant's Current Report on Form 8-K filed on April 20, 2009, and incorporated herein by reference)](https://www.sec.gov/Archives/edgar/data/893538/000089353809000021/exhibit102.htm)</u> |
| <u>[10.2](https://www.sec.gov/Archives/edgar/data/893538/000089353809000021/exhibit103.htm)</u> | <u>[Supplement and Amendment to Deed of Trust, Mortgage, Line of Credit Mortgage, Assignment, Security Agreement, Fixture Filing and Financing Statement for the benefit of Wachovia Bank, National Association, as Administrative Agent, dated effective as of April 14, 2009 (filed as Exhibit 10.3 to the registrant's Current Report on Form 8-K filed on April 20, 2009, and incorporated herein by reference)](https://www.sec.gov/Archives/edgar/data/893538/000089353809000021/exhibit103.htm)</u> |
| <u>[10.3](https://www.sec.gov/Archives/edgar/data/893538/000089353822000112/exhibit101seventhamendedan.htm)</u> | <u>[Seventh Amended and Restated Credit Agreement dated as of August 2, 2022, among SM Energy Company, Wells Fargo Bank, National Association, as Administrative Agent and Swingline Lender, and the Lenders party thereto (filed as Exhibit 10.1 to the registrant's Quarterly Report on Form 10-Q for the quarter ended June 30, 2022, and incorporated herein by reference)](https://www.sec.gov/Archives/edgar/data/893538/000089353822000112/exhibit101seventhamendedan.htm)</u> |
| <u>[10.4](https://www.sec.gov/Archives/edgar/data/893538/000089353824000076/exhibit101-firstamendmentt.htm)</u> | <u>[First Amendment to Seventh Amended and Restated Credit Agreement, dated as of July 2, 2024, by and among SM Energy Company, a Delaware corporation, each of the Lenders that is a party thereto; and Wells Fargo Bank, National Association, as administrative agent for the Lenders, the Issuing Banks and the Swingline Lender (filed as Exhibit 10.1 to the registrant's Current Report on Form 8-K filed on July 8, 2024, and incorporated herein by reference)](https://www.sec.gov/Archives/edgar/data/893538/000089353824000076/exhibit101-firstamendmentt.htm)</u> |
| <u>[10.5](https://www.sec.gov/Archives/edgar/data/893538/000089353824000130/exhibit101secondamendment.htm)</u> | <u>[Second Amendment to Seventh Amended and Restated Credit Agreement, dated as of October 1, 2024, by and among SM Energy Company, a Delaware corporation, each of the Lenders that is a party thereto; and Wells Fargo Bank, National Association, as administrative agent for the Lenders, the Issuing Banks and the Swingline Lender (filed as Exhibit 10.1 to the registrant's Current Report on Form 8-K filed on October 2, 2024, and incorporated herein by reference)](https://www.sec.gov/Archives/edgar/data/893538/000089353824000130/exhibit101secondamendment.htm)</u> |
| <u>[1](https://www.sec.gov/Archives/edgar/data/893538/000089353825000126/exhibit101thirdamendment.htm)[0.6](https://www.sec.gov/Archives/edgar/data/893538/000089353825000126/exhibit101thirdamendment.htm)</u> | <u>[Third Amendment to Seventh Amended and Restated Credit Agreement, dated as of October 13, 2025, by and among SM Energy Company, a Delaware corporation, each of the Lenders that is a party thereto, and Wells Fargo Bank, National Association, as administrative agent for the Lenders, the Issuing Banks and the Swingline Lender (filed as Exhibit 10.1 to the registrant's Current Report on Form 8-K filed on October 16, 2025, and incorporated herein by reference](https://www.sec.gov/Archives/edgar/data/893538/000089353825000126/exhibit101thirdamendment.htm)</u>) |

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| | |
|:---|:---|
| <u>[1](https://www.sec.gov/Archives/edgar/data/893538/000110465926008380/tm264415d2_ex10-1.htm)[0.](https://www.sec.gov/Archives/edgar/data/893538/000110465926008380/tm264415d2_ex10-1.htm)[7](https://www.sec.gov/Archives/edgar/data/893538/000110465926008380/tm264415d2_ex10-1.htm)</u> | <u>[Fourth](https://www.sec.gov/Archives/edgar/data/893538/000110465926008380/tm264415d2_ex10-1.htm)[Amendment to Seventh Amended and Restated Credit Agreement, dated as of](https://www.sec.gov/Archives/edgar/data/893538/000110465926008380/tm264415d2_ex10-1.htm)[January](https://www.sec.gov/Archives/edgar/data/893538/000110465926008380/tm264415d2_ex10-1.htm)[3](https://www.sec.gov/Archives/edgar/data/893538/000110465926008380/tm264415d2_ex10-1.htm)[0](https://www.sec.gov/Archives/edgar/data/893538/000110465926008380/tm264415d2_ex10-1.htm)[, 202](https://www.sec.gov/Archives/edgar/data/893538/000110465926008380/tm264415d2_ex10-1.htm)[6](https://www.sec.gov/Archives/edgar/data/893538/000110465926008380/tm264415d2_ex10-1.htm)[, by and among SM Energy Company,](https://www.sec.gov/Archives/edgar/data/893538/000110465926008380/tm264415d2_ex10-1.htm)[a Delaware corporation,](https://www.sec.gov/Archives/edgar/data/893538/000110465926008380/tm264415d2_ex10-1.htm)[each of the Lenders that is a party thereto, and Wells Fargo Bank, National Association, as administrative agent for the Lenders, the Issuing Banks and the Swingline Lender](https://www.sec.gov/Archives/edgar/data/893538/000110465926008380/tm264415d2_ex10-1.htm)[(filed as Exhibit 1](https://www.sec.gov/Archives/edgar/data/893538/000110465926008380/tm264415d2_ex10-1.htm)[0.1 to the registrant](https://www.sec.gov/Archives/edgar/data/893538/000110465926008380/tm264415d2_ex10-1.htm)['](https://www.sec.gov/Archives/edgar/data/893538/000110465926008380/tm264415d2_ex10-1.htm)[s Curr](https://www.sec.gov/Archives/edgar/data/893538/000110465926008380/tm264415d2_ex10-1.htm)[ent Report on Form 8-K file](https://www.sec.gov/Archives/edgar/data/893538/000110465926008380/tm264415d2_ex10-1.htm)[d on January 30, 2026, and incor](https://www.sec.gov/Archives/edgar/data/893538/000110465926008380/tm264415d2_ex10-1.htm)[porated herein by reference)](https://www.sec.gov/Archives/edgar/data/893538/000110465926008380/tm264415d2_ex10-1.htm)</u> |
| <u>[10.](https://www.sec.gov/Archives/edgar/data/893538/000089353824000059/exhibit101-xclpurchaseands.htm)[8](https://www.sec.gov/Archives/edgar/data/893538/000089353824000059/exhibit101-xclpurchaseands.htm)</u> | <u>[Purchase and Sale Agreement dated as of June 27, 2024 by and among XCL AssetCo, LLC, XCL Marketing, LLC, Wasatch Water Logistics, LLC, XCL Resources, LLC and XCL SandCo, LLC, as Seller, and SM Energy Company, as Purchaser, and solely for the limited purposes as set forth therein, Northern Oil and Gas, Inc.(filed as Exhibit 10.1 to the registrant's Current Report on Form 8-K filed on June 28, 2024, and incorporated herein by reference)](https://www.sec.gov/Archives/edgar/data/893538/000089353824000059/exhibit101-xclpurchaseands.htm)</u> |
| <u>[10.](https://www.sec.gov/Archives/edgar/data/893538/000089353824000059/exhibit102-smxnogxacquisit.htm)[9](https://www.sec.gov/Archives/edgar/data/893538/000089353824000059/exhibit102-smxnogxacquisit.htm)</u> | <u>[Acquisition and Cooperation Agreement dated as of June 27, 2024 by and between SM Energy Company and Northern Oil and Gas, Inc. (filed as Exhibit 10.2 to the registrant's Current Report on Form 8-K filed on June 28, 2024, and incorporated herein by reference)](https://www.sec.gov/Archives/edgar/data/893538/000089353824000059/exhibit102-smxnogxacquisit.htm)</u> |
| <u>[10.](https://www.sec.gov/Archives/edgar/data/893538/000110465910055533/a10-17647_1ex10d6.htm)[10](https://www.sec.gov/Archives/edgar/data/893538/000110465910055533/a10-17647_1ex10d6.htm)[††](https://www.sec.gov/Archives/edgar/data/893538/000110465910055533/a10-17647_1ex10d6.htm)</u> | <u>[Net Profits Interest Bonus Plan, As Amended by the Board of Directors on July 30, 2010 (filed as Exhibit 10.6 to the registrant's Quarterly Report on Form 10-Q for the quarter ended September 30, 2010 and incorporated herein by reference)](https://www.sec.gov/Archives/edgar/data/893538/000110465910055533/a10-17647_1ex10d6.htm)</u> |
| <u>[10.](https://www.sec.gov/Archives/edgar/data/893538/000110465911010268/a11-3036_1ex10d30.htm)[11](https://www.sec.gov/Archives/edgar/data/893538/000110465911010268/a11-3036_1ex10d30.htm)[†](https://www.sec.gov/Archives/edgar/data/893538/000110465911010268/a11-3036_1ex10d30.htm)</u> | <u>[Pension Plan for Employees of SM Energy Company as Amended and Restated as of January 1, 2010 (filed as Exhibit 10.30 to the registrant's Annual Report on Form 10-K filed for the year ended December 31, 2010, and incorporated herein by reference)](https://www.sec.gov/Archives/edgar/data/893538/000110465911010268/a11-3036_1ex10d30.htm)</u> |
| <u>[10.1](https://www.sec.gov/Archives/edgar/data/893538/000089353812000012/exhibit1041-amendmentno1pe.htm)[2](https://www.sec.gov/Archives/edgar/data/893538/000089353812000012/exhibit1041-amendmentno1pe.htm)[†](https://www.sec.gov/Archives/edgar/data/893538/000089353812000012/exhibit1041-amendmentno1pe.htm)</u> | <u>[Amendment No. 1 to the Pension Plan for Employees of SM Energy Company amended as of January 1, 2011 (filed as Exhibit 10.41 to the registrant's Annual Report on Form 10-K filed for the year ended December 31, 2011, and incorporated herein by reference)](https://www.sec.gov/Archives/edgar/data/893538/000089353812000012/exhibit1041-amendmentno1pe.htm)</u> |
| <u>[10.1](https://www.sec.gov/Archives/edgar/data/893538/000089353812000012/exhibit1042-amendmentno2pe.htm)[3](https://www.sec.gov/Archives/edgar/data/893538/000089353812000012/exhibit1042-amendmentno2pe.htm)[†](https://www.sec.gov/Archives/edgar/data/893538/000089353812000012/exhibit1042-amendmentno2pe.htm)</u> | <u>[Amendment No. 2 to the Pension Plan for Employees of SM Energy Company amended as of January 1, 2012 (filed as Exhibit 10.42 to the registrant's Annual Report on Form 10-K filed for the year ended December 31, 2011, and incorporated herein by reference)](https://www.sec.gov/Archives/edgar/data/893538/000089353812000012/exhibit1042-amendmentno2pe.htm)</u> |
| <u>[10.1](https://www.sec.gov/Archives/edgar/data/893538/000089353816000122/exhibit1029-amendmentno3to.htm)[4](https://www.sec.gov/Archives/edgar/data/893538/000089353816000122/exhibit1029-amendmentno3to.htm)[†](https://www.sec.gov/Archives/edgar/data/893538/000089353816000122/exhibit1029-amendmentno3to.htm)</u> | <u>[Amendment No. 3 to the Pension Plan for Employees of SM Energy Company amended as of January 1, 2016 (filed as Exhibit 10.29 to the registrant's Annual Report on Form 10-K filed for the year ended December 31, 2015, and incorporated herein by reference)](https://www.sec.gov/Archives/edgar/data/893538/000089353816000122/exhibit1029-amendmentno3to.htm)</u> |
| <u>[10.1](https://www.sec.gov/Archives/edgar/data/893538/000110465911010268/a11-3036_1ex10d31.htm)[5](https://www.sec.gov/Archives/edgar/data/893538/000110465911010268/a11-3036_1ex10d31.htm)[+](https://www.sec.gov/Archives/edgar/data/893538/000110465911010268/a11-3036_1ex10d31.htm)</u> | <u>[SM Energy Company Non-Qualified Unfunded Supplemental Retirement Plan as Amended as of December 31, 2010 (filed as Exhibit 10.31 to the registrant's Annual Report on Form 10-K filed for the year ended December 31, 2010, and incorporated herein by reference)](https://www.sec.gov/Archives/edgar/data/893538/000110465911010268/a11-3036_1ex10d31.htm)</u> |
| <u>[10.1](https://www.sec.gov/Archives/edgar/data/893538/000089353814000005/exhibit101012414.htm)[6](https://www.sec.gov/Archives/edgar/data/893538/000089353814000005/exhibit101012414.htm)[†](https://www.sec.gov/Archives/edgar/data/893538/000089353814000005/exhibit101012414.htm)</u> | <u>[SM Energy Company Non-Qualified Deferred Compensation Plan as of March 10, 2014 (filed as Exhibit 10.1 to the registrant's Current Report on Form 8-K filed on January 24, 2014, and incorporated herein by reference)](https://www.sec.gov/Archives/edgar/data/893538/000089353814000005/exhibit101012414.htm)</u> |
| <u>[10.1](https://www.sec.gov/Archives/edgar/data/893538/000089353814000010/exhibit1041-cashbonusplan.htm)[7](https://www.sec.gov/Archives/edgar/data/893538/000089353814000010/exhibit1041-cashbonusplan.htm)[†](https://www.sec.gov/Archives/edgar/data/893538/000089353814000010/exhibit1041-cashbonusplan.htm)</u> | <u>[Cash Bonus Plan, As Amended and Restated as of February 1, 2014 (filed as Exhibit 10.41 to the registrant's Annual Report on Form 10-K filed for the year ended December 31, 2013, and incorporated herein by reference)](https://www.sec.gov/Archives/edgar/data/893538/000089353814000010/exhibit1041-cashbonusplan.htm)</u> |
| <u>[10.1](https://www.sec.gov/Archives/edgar/data/893538/000089353821000022/def14a-proxystatementforth.htm#icd257dce987f4796bd529c2d0a9ecaa3_208)[8](https://www.sec.gov/Archives/edgar/data/893538/000089353821000022/def14a-proxystatementforth.htm#icd257dce987f4796bd529c2d0a9ecaa3_208)[†](https://www.sec.gov/Archives/edgar/data/893538/000089353821000022/def14a-proxystatementforth.htm#icd257dce987f4796bd529c2d0a9ecaa3_208)</u> | <u>[SM Energy Company Employee Stock Purchase Plan, amended and restated effective as of April 5, 2021 (filed as Annex A in the registrant's Definitive Proxy Statement on Schedule 14A, filed on April 16, 2021, and incorporated herein by reference)](https://www.sec.gov/Archives/edgar/data/893538/000089353821000022/def14a-proxystatementforth.htm#icd257dce987f4796bd529c2d0a9ecaa3_208)</u> |
| <u>[10.1](https://www.sec.gov/Archives/edgar/data/893538/000110465910041421/a10-13039_1ex10d5.htm)[9](https://www.sec.gov/Archives/edgar/data/893538/000110465910041421/a10-13039_1ex10d5.htm)[†](https://www.sec.gov/Archives/edgar/data/893538/000110465910041421/a10-13039_1ex10d5.htm)</u> | <u>[Form of Non-Employee Director Restricted Stock Award Agreement as of May 27, 2010 (filed as Exhibit 10.5 to the registrant's Quarterly Report on Form 10-Q for the quarter ended June 30, 2010, and incorporated herein by reference)](https://www.sec.gov/Archives/edgar/data/893538/000110465910041421/a10-13039_1ex10d5.htm)</u> |
| <u>[10.](https://www.sec.gov/Archives/edgar/data/893538/000089353824000009/exhibit1022-psuawardagreem.htm)[20](https://www.sec.gov/Archives/edgar/data/893538/000089353824000009/exhibit1022-psuawardagreem.htm)[†](https://www.sec.gov/Archives/edgar/data/893538/000089353824000009/exhibit1022-psuawardagreem.htm)</u> | <u>[Form of Performance Share Unit Award Agreement as of July 1, 2023 (filed as Exhibit 10.22 to the registrant's Annual Report on Form 10-K for the year ended December 31, 2023, and incorporated herein by reference)](https://www.sec.gov/Archives/edgar/data/893538/000089353824000009/exhibit1022-psuawardagreem.htm)</u> |
| <u>[10.2](https://www.sec.gov/Archives/edgar/data/893538/000089353824000009/exhibit1023-rsuawardagreem.htm)[1](https://www.sec.gov/Archives/edgar/data/893538/000089353824000009/exhibit1023-rsuawardagreem.htm)[†](https://www.sec.gov/Archives/edgar/data/893538/000089353824000009/exhibit1023-rsuawardagreem.htm)</u> | <u>[Form of Restricted Stock Unit Award Agreement as of July 1, 2023 (filed as Exhibit 10.23 to the registrant's Annual Report on Form 10-K for the year ended December 31, 2023, and incorporated herein by reference)](https://www.sec.gov/Archives/edgar/data/893538/000089353824000009/exhibit1023-rsuawardagreem.htm)</u> |
| <u>[10.2](https://www.sec.gov/ix?doc=/Archives/edgar/data/0000893538/000089353825000032/sm-20250404.htm#i6676a5ea6b8a44de8ed6162bd47f250e_229)[2](https://www.sec.gov/ix?doc=/Archives/edgar/data/0000893538/000089353825000032/sm-20250404.htm#i6676a5ea6b8a44de8ed6162bd47f250e_229)[†](https://www.sec.gov/ix?doc=/Archives/edgar/data/0000893538/000089353825000032/sm-20250404.htm#i6676a5ea6b8a44de8ed6162bd47f250e_229)</u> | <u>[SM Energy Company Equity Incentive Compensation Plan, amended and restated effective as of May 22, 2025 (filed as Annex A in the registrant's Definitive Proxy Statement on Schedule 14A, filed on April 7 2025, and incorporated herein by reference)](https://www.sec.gov/ix?doc=/Archives/edgar/data/0000893538/000089353825000032/sm-20250404.htm#i6676a5ea6b8a44de8ed6162bd47f250e_229)</u> |
| <u>[10.2](https://www.sec.gov/Archives/edgar/data/893538/000089353825000113/exhibit102-2025rsuawardagr.htm)[3](https://www.sec.gov/Archives/edgar/data/893538/000089353825000113/exhibit102-2025rsuawardagr.htm)[†](https://www.sec.gov/Archives/edgar/data/893538/000089353825000113/exhibit102-2025rsuawardagr.htm)</u> | <u>[Form of Restricted Stock Unit Award Agreement dated as of July 1, 2025 (filed as Exhibit 10.2 to the registrant's Quarterly Report on Form 10-Q for the quarter ended June 30, 2025, and incorporated herein by reference)](https://www.sec.gov/Archives/edgar/data/893538/000089353825000113/exhibit102-2025rsuawardagr.htm)</u> |
| <u>[10.](https://www.sec.gov/Archives/edgar/data/893538/000089353825000113/exhibit103-2025psuawardagr.htm)[24](https://www.sec.gov/Archives/edgar/data/893538/000089353825000113/exhibit103-2025psuawardagr.htm)[†](https://www.sec.gov/Archives/edgar/data/893538/000089353825000113/exhibit103-2025psuawardagr.htm)</u> | <u>[Form of Performance Share Unit Award Agreement dated as of July 1, 2025 (filed as Exhibit 10.3 to the registrant's Quarterly Report on Form 10-Q for the quarter ended June 30, 2025, and incorporated herein by reference)](https://www.sec.gov/Archives/edgar/data/893538/000089353825000113/exhibit103-2025psuawardagr.htm)</u> |
| <u>[10.](exhibit1025-directorcompen.htm)[25](exhibit1025-directorcompen.htm)[\*†](exhibit1025-directorcompen.htm)</u> | <u>[Summary of Compensation Arrangements for Non-Employee Directors](exhibit1025-directorcompen.htm)</u> |
| <u>[10.2](https://www.sec.gov/Archives/edgar/data/893538/000089353824000009/exhibit1016changeofcontrol.htm)[6](https://www.sec.gov/Archives/edgar/data/893538/000089353824000009/exhibit1016changeofcontrol.htm)[†](https://www.sec.gov/Archives/edgar/data/893538/000089353824000009/exhibit1016changeofcontrol.htm)</u> | <u>[Change of Control Executive Severance Agreement (filed as Exhibit 10.16 to the registrant's Annual Report on Form 10-K for the year ended December 31, 2023, and incorporated herein by reference)](https://www.sec.gov/Archives/edgar/data/893538/000089353824000009/exhibit1016changeofcontrol.htm)</u> |
| <u>[10.2](https://www.sec.gov/Archives/edgar/data/1509589/000110465924070027/tm2416440d1_ex4-1.htm)[7](https://www.sec.gov/Archives/edgar/data/1509589/000110465924070027/tm2416440d1_ex4-1.htm)[†](https://www.sec.gov/Archives/edgar/data/1509589/000110465924070027/tm2416440d1_ex4-1.htm)</u> | <u>[Civitas Resources, Inc. 2024 Long Term Incentive Plan (incorporated by reference to Exhibit 4.1 to Civitas Resources, Inc.'s Registration Statement on Form S-8 filed on June 10, 2024](https://www.sec.gov/Archives/edgar/data/1509589/000110465924070027/tm2416440d1_ex4-1.htm)[, file no. 001-35371](https://www.sec.gov/Archives/edgar/data/1509589/000110465924070027/tm2416440d1_ex4-1.htm)[)](https://www.sec.gov/Archives/edgar/data/1509589/000110465924070027/tm2416440d1_ex4-1.htm)</u> |
| <u>[10.2](https://www.sec.gov/Archives/edgar/data/1509589/000150958921000134/ex1062021ltip.htm)[8](https://www.sec.gov/Archives/edgar/data/1509589/000150958921000134/ex1062021ltip.htm)[†](https://www.sec.gov/Archives/edgar/data/1509589/000150958921000134/ex1062021ltip.htm)</u> | <u>[Bonanza Creek Energy, Inc. 2021 Long Term Incentive Plan (incorporated by reference to Exhibit 10.6 to Bonanza Creek Energy, Inc.'s Quarterly Report on Form 10-Q filed on August 9, 2021](https://www.sec.gov/Archives/edgar/data/1509589/000150958921000134/ex1062021ltip.htm)[, file no. 001-35371](https://www.sec.gov/Archives/edgar/data/1509589/000150958921000134/ex1062021ltip.htm)[)](https://www.sec.gov/Archives/edgar/data/1509589/000150958921000134/ex1062021ltip.htm)</u> |
| <u>[10.2](https://www.sec.gov/Archives/edgar/data/1655020/000165502021000039/ex-1062021longxtermincenti.htm)[9](https://www.sec.gov/Archives/edgar/data/1655020/000165502021000039/ex-1062021longxtermincenti.htm)[†](https://www.sec.gov/Archives/edgar/data/1655020/000165502021000039/ex-1062021longxtermincenti.htm)</u> | <u>[Extraction Oil & Gas, Inc. 2021 Long Term Incentive Plan (incorporated by reference to Exhibit 10.6 to Extraction's Current Report on Form 8-K (File No. 001-37907) filed with the Commission on January 20, 202](https://www.sec.gov/Archives/edgar/data/1655020/000165502021000039/ex-1062021longxtermincenti.htm)[1,](https://www.sec.gov/Archives/edgar/data/1655020/000165502021000039/ex-1062021longxtermincenti.htm)[file no. 001-35371](https://www.sec.gov/Archives/edgar/data/1655020/000165502021000039/ex-1062021longxtermincenti.htm)[)](https://www.sec.gov/Archives/edgar/data/1655020/000165502021000039/ex-1062021longxtermincenti.htm)</u> |

---

------

---

| | |
|:---|:---|
| <u>[10.](https://www.sec.gov/Archives/edgar/data/1509589/000095010317004047/dp75602_ex1003.htm)[30](https://www.sec.gov/Archives/edgar/data/1509589/000095010317004047/dp75602_ex1003.htm)[†](https://www.sec.gov/Archives/edgar/data/1509589/000095010317004047/dp75602_ex1003.htm)</u> | <u>[Bonanza Creek Energy, Inc. 2017 Long Term Incentive Plan (incorporated by reference to Exhibit 10.3 to Bonanza Creek Energy, Inc.'s Current Report on Form 8-K filed on April 28, 2017](https://www.sec.gov/Archives/edgar/data/1509589/000095010317004047/dp75602_ex1003.htm)[, file no. 001-35371](https://www.sec.gov/Archives/edgar/data/1509589/000095010317004047/dp75602_ex1003.htm)[)](https://www.sec.gov/Archives/edgar/data/1509589/000095010317004047/dp75602_ex1003.htm)</u> |
| <u>[10.31](https://www.sec.gov/Archives/edgar/data/893538/000110465926017062/tm266202d1_ex10-1.htm)</u> | <u>[Purchase and Sale Agreement, dated as of February 17, 2026, by and between SM Energy Company, a Delaware corporation, as Seller, and (i) Caturus Energy, LLC, a Delaware limited liability company, as Purchaser, and (ii) solely for purposes of Section 7.8 thereof, Caturus Holdco, LLC, a Delaware limited liability company](https://www.sec.gov/Archives/edgar/data/893538/000110465926017062/tm266202d1_ex10-1.htm)[(filed as Exhibit 10.1 to the registrant's Current Report on Form 8-K filed on](https://www.sec.gov/Archives/edgar/data/893538/000110465926017062/tm266202d1_ex10-1.htm)[February](https://www.sec.gov/Archives/edgar/data/893538/000110465926017062/tm266202d1_ex10-1.htm)[1](https://www.sec.gov/Archives/edgar/data/893538/000110465926017062/tm266202d1_ex10-1.htm)[8, 202](https://www.sec.gov/Archives/edgar/data/893538/000110465926017062/tm266202d1_ex10-1.htm)[6](https://www.sec.gov/Archives/edgar/data/893538/000110465926017062/tm266202d1_ex10-1.htm)[, and incorporated herein by reference)](https://www.sec.gov/Archives/edgar/data/893538/000110465926017062/tm266202d1_ex10-1.htm)</u> |
| <u>[19.1](https://www.sec.gov/Archives/edgar/data/893538/000089353825000008/exhibit191-securitiestradi.htm)</u> | <u>[Insider Trading Policy and Procedure](https://www.sec.gov/Archives/edgar/data/893538/000089353825000008/exhibit191-securitiestradi.htm)[s](https://www.sec.gov/Archives/edgar/data/893538/000089353825000008/exhibit191-securitiestradi.htm)[(filed as Exhibit](https://www.sec.gov/Archives/edgar/data/893538/000089353825000008/exhibit191-securitiestradi.htm)[19.1](https://www.sec.gov/Archives/edgar/data/893538/000089353825000008/exhibit191-securitiestradi.htm)[to the registrant's Annual Report on Form 10-K for the year ended December 31, 20](https://www.sec.gov/Archives/edgar/data/893538/000089353825000008/exhibit191-securitiestradi.htm)[24](https://www.sec.gov/Archives/edgar/data/893538/000089353825000008/exhibit191-securitiestradi.htm)[, and incorporated herein by reference)](https://www.sec.gov/Archives/edgar/data/893538/000089353825000008/exhibit191-securitiestradi.htm)</u> |
| <u>[21.1\*](exhibit211-subsidiaries123.htm)</u> | <u>[Subsidiaries of Registrant](exhibit211-subsidiaries123.htm)</u> |
| <u>[23.1\*](exhibit231-consentofpublic.htm)</u> | <u>[Consent of Ernst & Young LLP](exhibit231-consentofpublic.htm)</u> |
| <u>[23.2\*](exhibit232-consentofindepe.htm)</u> | <u>[Consent of Ryder Scott Company L.P.](exhibit232-consentofindepe.htm)</u> |
| <u>[24.1\*](#i293a8c843fc7462dbf208500aa1f98b0_334)</u> | <u>[Power of Attorney](#i293a8c843fc7462dbf208500aa1f98b0_334)</u> |
| <u>[31.1\*](exhibit311-certificationem.htm)</u> | <u>[Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes – Oxley Act of 2002](exhibit311-certificationem.htm)</u> |
| <u>[31.2\*](exhibit312-certificationwp.htm)</u> | <u>[Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes – Oxley Act of 2002](exhibit312-certificationwp.htm)</u> |
| <u>[32.1\*\*](exhibit321-906certificatio.htm)</u> | <u>[Certification pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes - Oxley Act of 2002](exhibit321-906certificatio.htm)</u> |
| <u>[95.1\*](exhibit951-minesafetydiscl.htm)</u> | <u>[Mine Safety Disclosures](exhibit951-minesafetydiscl.htm)</u> |
| <u>[97.1†](https://www.sec.gov/Archives/edgar/data/893538/000089353824000009/exhibit971-compensationcla.htm)</u> | <u>[Policy Relating to Recovery of Erroneously Awarded Compensation (filed as Exhibit 97.1 to the registrant's Annual Report on Form 10-K for the year ended December 31, 2023, and incorporated herein by reference)](https://www.sec.gov/Archives/edgar/data/893538/000089353824000009/exhibit971-compensationcla.htm)</u> |
| <u>[99.1\*](exhibit991-ryderscottlette.htm)</u> | <u>[Ryder Scott Audit Letter](exhibit991-ryderscottlette.htm)</u> |
| 101.INS | Inline XBRL Instance Document - The instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document. |
| 101.SCH\* | Inline XBRL Schema Document |
| 101.CAL\* | Inline XBRL Calculation Linkbase Document |
| 101.LAB\* | Inline XBRL Label Linkbase Document |
| 101.PRE\* | Inline XBRL Presentation Linkbase Document |
| 101.DEF\* | Inline XBRL Taxonomy Extension Definition Linkbase Document |
| 104 | Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101.INS) |

---

_____________________________________

---

| | |
|:---|:---|
| \* | Filed with this report. |
| \*\* | Furnished with this report. |
| † | Exhibit constitutes a management contract or compensatory plan or agreement. |
| †† | Exhibit constitutes a management contract or compensatory plan or agreement. This document was amended on July 30, 2010 primarily to reflect the change in the name of the registrant from St. Mary Land & Exploration Company to SM Energy Company. There were no material changes to the substantive terms and conditions in this document. |
| + | Exhibit constitutes a management contract or compensatory plan or agreement. This document was amended on November 9, 2010, in order to make technical revisions to ensure compliance with Section 409A of the Internal Revenue Code. There were no material changes to the substantive terms and conditions in this document. |

---

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;*(c) Financial Statement Schedules.* Refer to Item 15(a) above.

**ITEM 16. FORM 10-K SUMMARY**

None.

------

**SIGNATURES**

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

---

| | | | |
|:---|:---|:---|:---|
| | | **<u>SM ENERGY COMPANY</u>** | **<u>SM ENERGY COMPANY</u>** |
| | | (Registrant) | (Registrant) |
| Date: | February 26, 2026 | By: | <u>/s/ ELIZABETH A. MCDONALD</u> |
|  |  |  | Elizabeth A. McDonald |
|  |  |  | President and Chief Executive Officer |
|  |  |  | (Principal Executive Officer) |

---

**GENERAL POWER OF ATTORNEY**

KNOW ALL PERSONS BY THESE PRESENTS, that each person whose signature appears below constitutes and appoints each of Elizabeth A. McDonald and A. Wade Pursell his or her true and lawful attorney-in-fact and agent with full power of substitution and resubstitution, and each with full power to act alone, for the undersigned and in his or her name, place and stead, in any and all capacities, to sign any amendments to this Annual Report on Form 10-K for the fiscal year ended December 31, 2025, and to file the same, with exhibits thereto and other documents in connection therewith, with the Securities and Exchange Commission, hereby ratifying and confirming all that each of said attorney-in-fact, or his substitute or substitutes, may do or cause to be done by virtue hereof.

Pursuant to the requirements of the Exchange Act, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

---

| | | |
|:---|:---|:---|
| **Signature** | **Title** | **Date** |
| <u>/s/ ELIZABETH A. MCDONALD</u> | President and Chief Executive Officer | February 26, 2026 |
| Elizabeth A. McDonald | (Principal Executive Officer) |  |
| <u>/s/ A. WADE PURSELL</u> | Executive Vice President and Chief Financial Officer | February 26, 2026 |
| A. Wade Pursell | (Principal Financial Officer) |  |
| <u>/s/ ALAN D. BENNETT</u> | Vice President - Controller | February 26, 2026 |
| Alan D. Bennett | (Principal Accounting Officer) |  |

---

------

---

| | | |
|:---|:---|:---|
| **Signature** | **Title** | **Date** |
| <u>/s/ JULIO M. QUINTANA</u> | Chairman of the Board of Directors | February 26, 2026 |
| Julio M. Quintana |  |  |
| <u>/s/ BARTON R. BROOKMAN</u> | Director | February 26, 2026 |
| Barton R. Brookman |  |  |
| <u>/s/ MORRIS R. CLARK</u> | Director | February 26, 2026 |
| Morris R. Clark |  |  |
| <u>/s/ CARRIE M. FOX</u> | Director | February 26, 2026 |
| Carrie M. Fox |  |  |
| <u>/s/ LLOYD W. "BILLY" HELMS JR.</u> | Director | February 26, 2026 |
| Lloyd W. "Billy" Helms Jr.  |  |  |
| <u>/s/ RAMIRO G. PERU</u> | Director | February 26, 2026 |
| Ramiro G. Peru |  |  |
| <u>/s/ ROSE M. ROBESON</u> | Director | February 26, 2026 |
| Rose M. Robeson |  |  |
| <u>/s/ WOUTER VAN KEMPEN</u> | Director | February 26, 2026 |
| Wouter van Kempen |  |  |
| <u>/s/ ASHWIN VENKATRAMAN</u> | Director | February 26, 2026 |
| Ashwin Venkatraman |  |  |
| <u>/s/ HOWARD A. WILLARD, III</u> | Director | February 26, 2026 |
| Howard A. Willard, III |  |  |

---

## Exhibit 4.15

**EXHIBIT 4.15**

**FOURTH SUPPLEMENTAL INDENTURE** 

FOURTH SUPPLEMENTAL INDENTURE (this "*Supplemental Indenture*"), dated as of January 30, 2026, among SM Energy Company, a Delaware corporation, (the "*Parent*") and the Guarantors (as defined in the Indenture referred to herein) and Computershare Trust Company, N.A., as successor trustee (the "*Trustee*") to Wells Fargo Bank, National Association under the Indenture referred to below.

**W I T N E S S E T H**

WHEREAS, Civitas Resources, Inc. (f/k/a Bonanza Creek Energy, Inc.), a Delaware corporation (the "*Company*") and the guarantors party thereto and the Trustee entered into an indenture (as amended and supplemented from time to time, the "*Indenture*"), dated as of October 13, 2021, providing for the issuance of the Company's 5.000% Senior Notes due 2026 (the "*Notes*");

WHEREAS, the Parent and the Company are party to the Agreement and Plan of Merger, dated November 2, 2025, by and among the Parent, the Company, and Cars Merger Sub, Inc., a Delaware corporation and a direct wholly-owned subsidiary of the Parent ("*Merger Sub*") (the "*Merger Agreement*");

WHEREAS, the Merger Agreement provides for, among other things, the merger of Merger Sub with and into the Company, with the Company continuing as the surviving entity (the "*First Company Merger*");

WHEREAS, immediately following the First Company Merger, the Company will merge with and into the Parent, with the Parent continuing as the surviving entity (the "*Second Company Merger*" and, the time the Second Company Merger becomes effective being the "*Second Effective Time*");

WHEREAS, pursuant to Section 5. 01(a) of the Indenture, the Parent is required to enter into a supplemental indenture in connection with the Second Company Merger to assume all of the obligations of the Company under the Notes and the Indenture; and

WHEREAS, pursuant to Section 9.01 of the Indenture, the Trustee is authorized to execute and deliver this Supplemental Indenture without the consent of Holders of the Notes.

NOW, THEREFORE, in consideration of the foregoing and for other good and valuable consideration, the receipt of which is hereby acknowledged, the Parent, the Guarantors, and the Trustee mutually covenant and agree for the equal and ratable benefit of the Holders of the Notes as follows:

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;1. CAPITALIZED TERMS. Capitalized terms used herein without definition shall have the meanings assigned to them in the Indenture.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;2. AGREEMENT TO ASSUME. The Parent hereby agrees to assume all the obligations of the Company under the Notes and the Indenture effective as of the Second Effective Time.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;3. NO RECOURSE AGAINST OTHERS. No director, manager, officer, member, employee, incorporator or other owner of Capital Stock of the Parent or any Guarantor, as such, will have any liability for any obligations of the Parent or the Guarantors under the Notes, the Indenture or the Note Guarantees or for any claim based on, in respect of, or by reason of, such obligations or their creation. Each Holder of Notes by accepting a Note waives and releases all such liability. The waiver and release are part of the consideration for issuance of the Notes.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;4. NEW YORK LAW TO GOVERN. THE LAW OF THE STATE OF NEW YORK SHALL GOVERN AND BE USED TO CONSTRUE THIS SUPPLEMENTAL INDENTURE.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;5. COUNTERPARTS. This Supplemental Indenture shall be valid, binding, and enforceable against a party only when executed and delivered by an authorized individual on behalf of the party by means of (i) any electronic signature permitted by the federal Electronic Signatures in Global and National Commerce Act, state enactments of the Uniform Electronic Transactions Act, and/or any other relevant electronic signatures law, including relevant provisions of the Uniform Commercial Code (collectively, "Signature Law"); (ii) an original manual

------

signature; or (iii) a faxed, scanned, or photocopied manual signature. Each electronic signature or faxed, scanned, or photocopied manual signature shall for all purposes have the same validity, legal effect, and admissibility in evidence as an original manual signature. Each party hereto shall be entitled to conclusively rely upon, and shall have no liability with respect to, any faxed, scanned, or photocopied manual signature, or other electronic signature, of any party and shall have no duty to investigate, confirm or otherwise verify the validity or authenticity thereof. This Supplemental Indenture may be executed in any number of counterparts, each of which shall be deemed to be an original, but such counterparts shall, together, constitute one and the same instrument. For avoidance of doubt, original manual signatures shall be used for execution or indorsement of writings when required under the Uniform Commercial Code or other Signature Law due to the character or intended character of the writings.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;6. EFFECT OF HEADINGS. The headings of the Sections of this Supplemental Indenture have been inserted for convenience of reference only, are not to be considered a part of this Supplemental Indenture and will in no way modify or restrict any of the terms or provisions hereof.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;7. THE TRUSTEE. The Trustee shall not be responsible in any manner whatsoever for or in respect of the validity or sufficiency of this Supplemental Indenture or for or in respect of the recitals contained herein, all of which recitals are made solely by the Parent and the Guarantors.

------

IN WITNESS WHEREOF, the parties hereto have caused this Supplemental Indenture to be duly executed and attested, all as of the date first above written.

---

| | |
|:---|:---|
| Dated: | January 30, 2026 |

---

---

| | |
|:---|:---|
| SM ENERGY COMPANY | SM ENERGY COMPANY |
| By: | /s/ A. WADE PURSELL |
|  | Name: A. Wade Pursell |
|  | Title: Executive Vice President, Chief Financial |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Officer and Treasurer | &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Officer and Treasurer |

---

*Signature Page to Fourth Supplemental Indenture (2026 Notes)*

------

---

| | |
|:---|:---|
| 7N, LLC<br>8 NORTH, LLC<br>COLLEGIATE HOLDINGS LLC<br>AXIS EXPLORATION, LLC<br>BONANZA CREEK ENERGY OPERATING COMPANY, LLC<br>CIVITAS DE BASIN HOLDINGS, LLC<br>CIVITAS DE BASIN HOLDINGS II, LLC<br>CIVITAS DE BASIN MIDSTREAM, LLC<br>CIVITAS DE BASIN MINERALS, LP<br>CIVITAS DE BASIN MINERALS II, LLC<br>CIVITAS DE BASIN NM HOLDINGS, LLC<br>CIVITAS DE BASIN NM MINERALS, LLC<br>CIVITAS DE BASIN RESOURCES, LLC<br>CIVITAS DE BASIN RESOURCES II, LLC<br>CIVITAS MID BASIN ENERGY, LLC<br>CIVITAS MID BASIN ENERGY B, LLC<br>CIVITAS PERMIAN OPERATING, LLC<br>CIVITAS NORTH, LLC<br>CRESTONE PEAK RESOURCES ACQUISITION COMPANY I LLC<br>CRESTONE PEAK RESOURCES GP INC.<br>CRESTONE PEAK RESOURCES LLC<br>CRESTONE PEAK RESOURCES HOLDINGS LLC<br>CRESTONE PEAK RESOURCES LP<br>CRESTONE PEAK RESOURCES MIDSTREAM LLC<br>CRESTONE PEAK RESOURCES OPERATING LLC<br>CRESTONE PEAK RESOURCES WATKINS HOLDINGS LLC<br>CRESTONE PEAK RESOURCES WATKINS MIDSTREAM LLC<br>EXTRACTION FINANCE CORP.<br>EXTRACTION OIL & GAS, INC.<br>FIFTH POCKET PRODUCTION, LLC<br>HIGHPOINT OPERATING CORPORATION<br>HIGHPOINT RESOURCES CORPORATION<br>HOLMES EASTERN COMPANY, LLC<br>MOUNTAINTOP MINERALS, LLC<br>NORTHWEST CORRIDOR HOLDINGS, LLC<br>RAPTOR CONDOR MERGER SUB 2, LLC<br>ROCKY MOUNTAIN INFRASTRUCTURE, LLC<br>TABLE MOUNTAIN RESOURCES, LLC<br>XOG SERVICES, LLC<br>XTR MIDSTREAM, LLC | 7N, LLC<br>8 NORTH, LLC<br>COLLEGIATE HOLDINGS LLC<br>AXIS EXPLORATION, LLC<br>BONANZA CREEK ENERGY OPERATING COMPANY, LLC<br>CIVITAS DE BASIN HOLDINGS, LLC<br>CIVITAS DE BASIN HOLDINGS II, LLC<br>CIVITAS DE BASIN MIDSTREAM, LLC<br>CIVITAS DE BASIN MINERALS, LP<br>CIVITAS DE BASIN MINERALS II, LLC<br>CIVITAS DE BASIN NM HOLDINGS, LLC<br>CIVITAS DE BASIN NM MINERALS, LLC<br>CIVITAS DE BASIN RESOURCES, LLC<br>CIVITAS DE BASIN RESOURCES II, LLC<br>CIVITAS MID BASIN ENERGY, LLC<br>CIVITAS MID BASIN ENERGY B, LLC<br>CIVITAS PERMIAN OPERATING, LLC<br>CIVITAS NORTH, LLC<br>CRESTONE PEAK RESOURCES ACQUISITION COMPANY I LLC<br>CRESTONE PEAK RESOURCES GP INC.<br>CRESTONE PEAK RESOURCES LLC<br>CRESTONE PEAK RESOURCES HOLDINGS LLC<br>CRESTONE PEAK RESOURCES LP<br>CRESTONE PEAK RESOURCES MIDSTREAM LLC<br>CRESTONE PEAK RESOURCES OPERATING LLC<br>CRESTONE PEAK RESOURCES WATKINS HOLDINGS LLC<br>CRESTONE PEAK RESOURCES WATKINS MIDSTREAM LLC<br>EXTRACTION FINANCE CORP.<br>EXTRACTION OIL & GAS, INC.<br>FIFTH POCKET PRODUCTION, LLC<br>HIGHPOINT OPERATING CORPORATION<br>HIGHPOINT RESOURCES CORPORATION<br>HOLMES EASTERN COMPANY, LLC<br>MOUNTAINTOP MINERALS, LLC<br>NORTHWEST CORRIDOR HOLDINGS, LLC<br>RAPTOR CONDOR MERGER SUB 2, LLC<br>ROCKY MOUNTAIN INFRASTRUCTURE, LLC<br>TABLE MOUNTAIN RESOURCES, LLC<br>XOG SERVICES, LLC<br>XTR MIDSTREAM, LLC |
| By: | /s/ A. WADE PURSELL |
|  | Name: A. Wade Pursell |
|  | Title: Executive Vice President, Chief Financial |
| &nbsp;&nbsp;&nbsp;&nbsp; Officer and Treasurer | &nbsp;&nbsp;&nbsp;&nbsp; Officer and Treasurer |

---

*Signature Page to Fourth Supplemental Indenture (2026 Notes)*

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| | |
|:---|:---|
| <br>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;COMPUTERSHARE TRUST COMPANY, N.A., | <br>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;COMPUTERSHARE TRUST COMPANY, N.A., |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;As Trustee | &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;As Trustee |
| By: | /s/ SCOTT LITTLE |
|  | Name: Scott Little |
|  | Title: Vice President |

---

*Signature Page to Fourth Supplemental Indenture (2026 Notes)*

## Exhibit 4.16

**EXHIBIT 4.16**

**SECOND SUPPLEMENTAL INDENTURE** 

SECOND SUPPLEMENTAL INDENTURE (this "*Supplemental Indenture*"), dated as of January 30, 2026, among SM Energy Company, a Delaware corporation (the "*Parent*"), the Guarantors (as defined in the Indenture referred to herein) and Computershare Trust Company, N.A., as trustee (the "*Trustee*") under the Indenture referred to below.

**W I T N E S S E T H**

WHEREAS, Civitas Resources, Inc. (f/k/a Bonanza Creek Energy, Inc.), a Delaware corporation (the "*Company*") and the guarantors party thereto and the Trustee entered into an indenture (as amended and supplemented from time to time, the "*Indenture*"), dated as of June 29, 2023, providing for the issuance of the Company's 8.375% Senior Notes due 2028 (the "*Notes*");

WHEREAS, the Parent and the Company are party to the Agreement and Plan of Merger, dated November 2, 2025, by and among the Parent, the Company, and Cars Merger Sub, Inc., a Delaware corporation and a direct wholly-owned subsidiary of the Parent ("*Merger Sub*") (the "*Merger Agreement*");

WHEREAS, the Merger Agreement provides for, among other things, the merger of Merger Sub with and into the Company, with the Company continuing as the surviving entity (the "*First Company Merger*");

WHEREAS, immediately following the First Company Merger, the Company will merge with and into the Parent, with the Parent continuing as the surviving entity (the "*Second Company Merger*" and, the time the Second Company Merger becomes effective being the "*Second Effective Time*");

WHEREAS, pursuant to Section 5. 01(a) of the Indenture, the Parent is required to enter into a supplemental indenture in connection with the Second Company Merger to assume all of the obligations of the Company under the Notes and the Indenture; and

WHEREAS, pursuant to Section 9.01 of the Indenture, the Trustee is authorized to execute and deliver this Supplemental Indenture without the consent of Holders of the Notes.

NOW, THEREFORE, in consideration of the foregoing and for other good and valuable consideration, the receipt of which is hereby acknowledged, the Parent, the Guarantors, and the Trustee mutually covenant and agree for the equal and ratable benefit of the Holders of the Notes as follows:

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;1. CAPITALIZED TERMS. Capitalized terms used herein without definition shall have the meanings assigned to them in the Indenture.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;2. AGREEMENT TO ASSUME. The Parent hereby agrees to assume all the obligations of the Company under the Notes and the Indenture effective as of the Second Effective Time.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;3. NO RECOURSE AGAINST OTHERS. No director, manager, officer, member, employee, incorporator or other owner of Capital Stock of the Parent or any Guarantor, as such, will have any liability for any obligations of the Parent or the Guarantors under the Notes, the Indenture or the Note Guarantees or for any claim based on, in respect of, or by reason of, such obligations or their creation. Each Holder of Notes by accepting a Note waives and releases all such liability. The waiver and release are part of the consideration for issuance of the Notes.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;4. NEW YORK LAW TO GOVERN. THE LAW OF THE STATE OF NEW YORK SHALL GOVERN AND BE USED TO CONSTRUE THIS SUPPLEMENTAL INDENTURE.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;5. COUNTERPARTS. This Supplemental Indenture shall be valid, binding, and enforceable against a party only when executed and delivered by an authorized individual on behalf of the party by means of (i) any electronic signature permitted by the federal Electronic Signatures in Global and National Commerce Act, state enactments of the Uniform Electronic Transactions Act, and/or any other relevant electronic signatures law, including relevant provisions of the Uniform Commercial Code (collectively, "Signature Law"); (ii) an original

------

manual signature; or (iii) a faxed, scanned, or photocopied manual signature. Each electronic signature or faxed, scanned, or photocopied manual signature shall for all purposes have the same validity, legal effect, and admissibility in evidence as an original manual signature. Each party hereto shall be entitled to conclusively rely upon, and shall have no liability with respect to, any faxed, scanned, or photocopied manual signature, or other electronic signature, of any party and shall have no duty to investigate, confirm or otherwise verify the validity or authenticity thereof. This Supplemental Indenture may be executed in any number of counterparts, each of which shall be deemed to be an original, but such counterparts shall, together, constitute one and the same instrument. For avoidance of doubt, original manual signatures shall be used for execution or indorsement of writings when required under the Uniform Commercial Code or other Signature Law due to the character or intended character of the writings.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;6. EFFECT OF HEADINGS. The headings of the Sections of this Supplemental Indenture have been inserted for convenience of reference only, are not to be considered a part of this Supplemental Indenture and will in no way modify or restrict any of the terms or provisions hereof.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;7. THE TRUSTEE. The Trustee shall not be responsible in any manner whatsoever for or in respect of the validity or sufficiency of this Supplemental Indenture or for or in respect of the recitals contained herein, all of which recitals are made solely by the Parent and the Guarantors.

------

IN WITNESS WHEREOF, the parties hereto have caused this Supplemental Indenture to be duly executed and attested, all as of the date first above written.

---

| | |
|:---|:---|
| Dated: | January 30, 2026 |

---

---

| | |
|:---|:---|
| SM ENERGY COMPANY | SM ENERGY COMPANY |
| By: | /s/ A. WADE PURSELL |
|  | Name: A. Wade Pursell |
|  | Title: Executive Vice President, Chief Financial |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Officer and Treasurer | &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Officer and Treasurer |

---

*Signature Page to Second Supplemental Indenture (2028 Notes)*

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| | |
|:---|:---|
| 7N, LLC<br>8 NORTH, LLC<br>COLLEGIATE HOLDINGS LLC<br>AXIS EXPLORATION, LLC<br>BONANZA CREEK ENERGY OPERATING COMPANY, LLC<br>CIVITAS DE BASIN HOLDINGS, LLC<br>CIVITAS DE BASIN HOLDINGS II, LLC<br>CIVITAS DE BASIN MIDSTREAM, LLC<br>CIVITAS DE BASIN MINERALS, LP<br>CIVITAS DE BASIN MINERALS II, LLC<br>CIVITAS DE BASIN NM HOLDINGS, LLC<br>CIVITAS DE BASIN NM MINERALS, LLC<br>CIVITAS DE BASIN RESOURCES, LLC<br>CIVITAS DE BASIN RESOURCES II, LLC<br>CIVITAS MID BASIN ENERGY, LLC<br>CIVITAS MID BASIN ENERGY B, LLC<br>CIVITAS PERMIAN OPERATING, LLC<br>CIVITAS NORTH, LLC<br>CRESTONE PEAK RESOURCES ACQUISITION COMPANY I LLC<br>CRESTONE PEAK RESOURCES GP INC.<br>CRESTONE PEAK RESOURCES LLC<br>CRESTONE PEAK RESOURCES HOLDINGS LLC<br>CRESTONE PEAK RESOURCES LP<br>CRESTONE PEAK RESOURCES MIDSTREAM LLC<br>CRESTONE PEAK RESOURCES OPERATING LLC<br>CRESTONE PEAK RESOURCES WATKINS HOLDINGS LLC<br>CRESTONE PEAK RESOURCES WATKINS MIDSTREAM LLC<br>EXTRACTION FINANCE CORP.<br>EXTRACTION OIL & GAS, INC.<br>FIFTH POCKET PRODUCTION, LLC<br>HIGHPOINT OPERATING CORPORATION<br>HIGHPOINT RESOURCES CORPORATION<br>HOLMES EASTERN COMPANY, LLC<br>MOUNTAINTOP MINERALS, LLC<br>NORTHWEST CORRIDOR HOLDINGS, LLC<br>RAPTOR CONDOR MERGER SUB 2, LLC<br>ROCKY MOUNTAIN INFRASTRUCTURE, LLC<br>TABLE MOUNTAIN RESOURCES, LLC<br>XOG SERVICES, LLC<br>XTR MIDSTREAM, LLC | 7N, LLC<br>8 NORTH, LLC<br>COLLEGIATE HOLDINGS LLC<br>AXIS EXPLORATION, LLC<br>BONANZA CREEK ENERGY OPERATING COMPANY, LLC<br>CIVITAS DE BASIN HOLDINGS, LLC<br>CIVITAS DE BASIN HOLDINGS II, LLC<br>CIVITAS DE BASIN MIDSTREAM, LLC<br>CIVITAS DE BASIN MINERALS, LP<br>CIVITAS DE BASIN MINERALS II, LLC<br>CIVITAS DE BASIN NM HOLDINGS, LLC<br>CIVITAS DE BASIN NM MINERALS, LLC<br>CIVITAS DE BASIN RESOURCES, LLC<br>CIVITAS DE BASIN RESOURCES II, LLC<br>CIVITAS MID BASIN ENERGY, LLC<br>CIVITAS MID BASIN ENERGY B, LLC<br>CIVITAS PERMIAN OPERATING, LLC<br>CIVITAS NORTH, LLC<br>CRESTONE PEAK RESOURCES ACQUISITION COMPANY I LLC<br>CRESTONE PEAK RESOURCES GP INC.<br>CRESTONE PEAK RESOURCES LLC<br>CRESTONE PEAK RESOURCES HOLDINGS LLC<br>CRESTONE PEAK RESOURCES LP<br>CRESTONE PEAK RESOURCES MIDSTREAM LLC<br>CRESTONE PEAK RESOURCES OPERATING LLC<br>CRESTONE PEAK RESOURCES WATKINS HOLDINGS LLC<br>CRESTONE PEAK RESOURCES WATKINS MIDSTREAM LLC<br>EXTRACTION FINANCE CORP.<br>EXTRACTION OIL & GAS, INC.<br>FIFTH POCKET PRODUCTION, LLC<br>HIGHPOINT OPERATING CORPORATION<br>HIGHPOINT RESOURCES CORPORATION<br>HOLMES EASTERN COMPANY, LLC<br>MOUNTAINTOP MINERALS, LLC<br>NORTHWEST CORRIDOR HOLDINGS, LLC<br>RAPTOR CONDOR MERGER SUB 2, LLC<br>ROCKY MOUNTAIN INFRASTRUCTURE, LLC<br>TABLE MOUNTAIN RESOURCES, LLC<br>XOG SERVICES, LLC<br>XTR MIDSTREAM, LLC |
| By: | /s/ A. WADE PURSELL |
|  | Name: A. Wade Pursell |
|  | Title: Executive Vice President, Chief Financial |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Officer and Treasurer | &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Officer and Treasurer |

---

*Signature Page to Second Supplemental Indenture (2028 Notes)*

------

---

| | |
|:---|:---|
|  | COMPUTERSHARE TRUST COMPANY, N.A., |
|  | As Trustee |
| By: | /s/ SCOTT LITTLE |
|  | Name: Scott Little |
|  | Title: Vice President |

---

*Signature Page to Second Supplemental Indenture (2028 Notes)*

## Exhibit 4.17

**EXHIBIT 4.17**

**SECOND SUPPLEMENTAL INDENTURE** 

SECOND SUPPLEMENTAL INDENTURE (this "*Supplemental Indenture*"), dated as of January 30, 2026, among SM Energy Company, a Delaware corporation (the "*Parent*"), the Guarantors (as defined in the Indenture referred to herein) and Computershare Trust Company, N.A., as trustee (the "*Trustee*") under the Indenture referred to below.

**W I T N E S S E T H**

WHEREAS, Civitas Resources, Inc. (f/k/a Bonanza Creek Energy, Inc.), a Delaware corporation (the "*Company*") and the guarantors party thereto and the Trustee entered into an indenture (as amended and supplemented from time to time, the "*Indenture*"), dated as of June 29, 2023, providing for the issuance of the Company's 8.750% Senior Notes due 2031 (the "*Notes*");

WHEREAS, the Parent and the Company are party to the Agreement and Plan of Merger, dated November 2, 2025, by and among the Parent, the Company, and Cars Merger Sub, Inc., a Delaware corporation and a direct wholly-owned subsidiary of the Parent ("*Merger Sub*") (the "*Merger Agreement*");

WHEREAS, the Merger Agreement provides for, among other things, the merger of Merger Sub with and into the Company, with the Company continuing as the surviving entity (the "*First Company Merger*");

WHEREAS, immediately following the First Company Merger, the Company will merge with and into the Parent, with the Parent continuing as the surviving entity (the "*Second Company Merger*" and, the time the Second Company Merger becomes effective being the "*Second Effective Time*");

WHEREAS, pursuant to Section 5. 01(a) of the Indenture, the Parent is required to enter into a supplemental indenture in connection with the Second Company Merger to assume all of the obligations of the Company under the Notes and the Indenture; and

WHEREAS, pursuant to Section 9.01 of the Indenture, the Trustee is authorized to execute and deliver this Supplemental Indenture without the consent of Holders of the Notes.

NOW, THEREFORE, in consideration of the foregoing and for other good and valuable consideration, the receipt of which is hereby acknowledged, the Parent, the Guarantors, and the Trustee mutually covenant and agree for the equal and ratable benefit of the Holders of the Notes as follows:

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;1. CAPITALIZED TERMS. Capitalized terms used herein without definition shall have the meanings assigned to them in the Indenture.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;2.&nbsp;&nbsp;&nbsp;&nbsp;AGREEMENT TO ASSUME. The Parent hereby agrees to assume all the obligations of the Company under the Notes and the Indenture effective as of the Second Effective Time.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;3.&nbsp;&nbsp;&nbsp;&nbsp;NO RECOURSE AGAINST OTHERS. No director, manager, officer, member, employee, incorporator or other owner of Capital Stock of the Parent or any Guarantor, as such, will have any liability for any obligations of the Parent or the Guarantors under the Notes, the Indenture or the Note Guarantees or for any claim based on, in respect of, or by reason of, such obligations or their creation. Each Holder of Notes by accepting a Note waives and releases all such liability. The waiver and release are part of the consideration for issuance of the Notes.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;4.&nbsp;&nbsp;&nbsp;&nbsp;NEW YORK LAW TO GOVERN. THE LAW OF THE STATE OF NEW YORK SHALL GOVERN AND BE USED TO CONSTRUE THIS SUPPLEMENTAL INDENTURE.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;5. COUNTERPARTS. This Supplemental Indenture shall be valid, binding, and enforceable against a party only when executed and delivered by an authorized individual on behalf of the party by means of (i) any electronic signature permitted by the federal Electronic Signatures in Global and National Commerce Act, state

------

enactments of the Uniform Electronic Transactions Act, and/or any other relevant electronic signatures law, including relevant provisions of the Uniform Commercial Code (collectively, "Signature Law"); (ii) an original manual signature; or (iii) a faxed, scanned, or photocopied manual signature. Each electronic signature or faxed, scanned, or photocopied manual signature shall for all purposes have the same validity, legal effect, and admissibility in evidence as an original manual signature. Each party hereto shall be entitled to conclusively rely upon, and shall have no liability with respect to, any faxed, scanned, or photocopied manual signature, or other electronic signature, of any party and shall have no duty to investigate, confirm or otherwise verify the validity or authenticity thereof. This Supplemental Indenture may be executed in any number of counterparts, each of which shall be deemed to be an original, but such counterparts shall, together, constitute one and the same instrument. For avoidance of doubt, original manual signatures shall be used for execution or indorsement of writings when required under the Uniform Commercial Code or other Signature Law due to the character or intended character of the writings.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;6. EFFECT OF HEADINGS. The headings of the Sections of this Supplemental Indenture have been inserted for convenience of reference only, are not to be considered a part of this Supplemental Indenture and will in no way modify or restrict any of the terms or provisions hereof.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;7. THE TRUSTEE. The Trustee shall not be responsible in any manner whatsoever for or in respect of the validity or sufficiency of this Supplemental Indenture or for or in respect of the recitals contained herein, all of which recitals are made solely by the Parent and the Guarantors.

------

IN WITNESS WHEREOF, the parties hereto have caused this Supplemental Indenture to be duly executed and attested, all as of the date first above written.

---

| | |
|:---|:---|
| Dated: | January 30, 2026 |

---

---

| | |
|:---|:---|
| SM ENERGY COMPANY | SM ENERGY COMPANY |
| By: | /s/ A. WADE PURSELL |
|  | Name: A. Wade Pursell |
|  | Title: Executive Vice President, Chief Financial |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Officer and Treasurer | &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Officer and Treasurer |

---

*Signature Page to Second Supplemental Indenture (2031 Notes)*

------

---

| | |
|:---|:---|
| 7N, LLC<br>8 NORTH, LLC<br>COLLEGIATE HOLDINGS LLC<br>AXIS EXPLORATION, LLC<br>BONANZA CREEK ENERGY OPERATING COMPANY, LLC<br>CIVITAS DE BASIN HOLDINGS, LLC<br>CIVITAS DE BASIN HOLDINGS II, LLC<br>CIVITAS DE BASIN MIDSTREAM, LLC<br>CIVITAS DE BASIN MINERALS, LP<br>CIVITAS DE BASIN MINERALS II, LLC<br>CIVITAS DE BASIN NM HOLDINGS, LLC<br>CIVITAS DE BASIN NM MINERALS, LLC<br>CIVITAS DE BASIN RESOURCES, LLC<br>CIVITAS DE BASIN RESOURCES II, LLC<br>CIVITAS MID BASIN ENERGY, LLC<br>CIVITAS MID BASIN ENERGY B, LLC<br>CIVITAS PERMIAN OPERATING, LLC<br>CIVITAS NORTH, LLC<br>CRESTONE PEAK RESOURCES ACQUISITION COMPANY I LLC<br>CRESTONE PEAK RESOURCES GP INC.<br>CRESTONE PEAK RESOURCES LLC<br>CRESTONE PEAK RESOURCES HOLDINGS LLC<br>CRESTONE PEAK RESOURCES LP<br>CRESTONE PEAK RESOURCES MIDSTREAM LLC<br>CRESTONE PEAK RESOURCES OPERATING LLC<br>CRESTONE PEAK RESOURCES WATKINS HOLDINGS LLC<br>CRESTONE PEAK RESOURCES WATKINS MIDSTREAM LLC<br>EXTRACTION FINANCE CORP.<br>EXTRACTION OIL & GAS, INC.<br>FIFTH POCKET PRODUCTION, LLC<br>HIGHPOINT OPERATING CORPORATION<br>HIGHPOINT RESOURCES CORPORATION<br>HOLMES EASTERN COMPANY, LLC<br>MOUNTAINTOP MINERALS, LLC<br>NORTHWEST CORRIDOR HOLDINGS, LLC<br>RAPTOR CONDOR MERGER SUB 2, LLC<br>ROCKY MOUNTAIN INFRASTRUCTURE, LLC<br>TABLE MOUNTAIN RESOURCES, LLC<br>XOG SERVICES, LLC<br>XTR MIDSTREAM, LLC | 7N, LLC<br>8 NORTH, LLC<br>COLLEGIATE HOLDINGS LLC<br>AXIS EXPLORATION, LLC<br>BONANZA CREEK ENERGY OPERATING COMPANY, LLC<br>CIVITAS DE BASIN HOLDINGS, LLC<br>CIVITAS DE BASIN HOLDINGS II, LLC<br>CIVITAS DE BASIN MIDSTREAM, LLC<br>CIVITAS DE BASIN MINERALS, LP<br>CIVITAS DE BASIN MINERALS II, LLC<br>CIVITAS DE BASIN NM HOLDINGS, LLC<br>CIVITAS DE BASIN NM MINERALS, LLC<br>CIVITAS DE BASIN RESOURCES, LLC<br>CIVITAS DE BASIN RESOURCES II, LLC<br>CIVITAS MID BASIN ENERGY, LLC<br>CIVITAS MID BASIN ENERGY B, LLC<br>CIVITAS PERMIAN OPERATING, LLC<br>CIVITAS NORTH, LLC<br>CRESTONE PEAK RESOURCES ACQUISITION COMPANY I LLC<br>CRESTONE PEAK RESOURCES GP INC.<br>CRESTONE PEAK RESOURCES LLC<br>CRESTONE PEAK RESOURCES HOLDINGS LLC<br>CRESTONE PEAK RESOURCES LP<br>CRESTONE PEAK RESOURCES MIDSTREAM LLC<br>CRESTONE PEAK RESOURCES OPERATING LLC<br>CRESTONE PEAK RESOURCES WATKINS HOLDINGS LLC<br>CRESTONE PEAK RESOURCES WATKINS MIDSTREAM LLC<br>EXTRACTION FINANCE CORP.<br>EXTRACTION OIL & GAS, INC.<br>FIFTH POCKET PRODUCTION, LLC<br>HIGHPOINT OPERATING CORPORATION<br>HIGHPOINT RESOURCES CORPORATION<br>HOLMES EASTERN COMPANY, LLC<br>MOUNTAINTOP MINERALS, LLC<br>NORTHWEST CORRIDOR HOLDINGS, LLC<br>RAPTOR CONDOR MERGER SUB 2, LLC<br>ROCKY MOUNTAIN INFRASTRUCTURE, LLC<br>TABLE MOUNTAIN RESOURCES, LLC<br>XOG SERVICES, LLC<br>XTR MIDSTREAM, LLC |
| By: | /s/ A. WADE PURSELL |
|  | Name: A. Wade Pursell |
|  | Title: Executive Vice President, Chief Financial |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Officer and Treasurer | &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Officer and Treasurer |

---

*Signature Page to Second Supplemental Indenture (2031 Notes)*

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---

| | |
|:---|:---|
|  | <br>COMPUTERSHARE TRUST COMPANY, N.A., |
|  | As Trustee |
| By: | /s/ SCOTT LITTLE |
|  | Name: Scott Little |
|  | Title: Vice President |

---

*Signature Page to Second Supplemental Indenture (2031 Notes)*

## Exhibit 4.18

**EXHIBIT 4.18**

**FIRST SUPPLEMENTAL INDENTURE** 

FIRST SUPPLEMENTAL INDENTURE (this "*Supplemental Indenture*"), dated as of January 30, 2026, among SM Energy Company, a Delaware corporation (the "*Parent*"), the Guarantors (as defined in the Indenture referred to herein) and Computershare Trust Company, N.A., as trustee (the "*Trustee*") under the Indenture referred to below.

**W I T N E S S E T H**

WHEREAS, Civitas Resources, Inc. (f/k/a Bonanza Creek Energy, Inc.), a Delaware corporation (the "*Company*") and the guarantors party thereto and the Trustee entered into an indenture (as amended and supplemented from time to time, the "*Indenture*"), dated as of October 17, 2023, providing for the issuance of the Company's 8.625% Senior Notes due 2030 (the "*Notes*");

WHEREAS, the Parent and the Company are party to the Agreement and Plan of Merger, dated November 2, 2025, by and among the Parent, the Company, and Cars Merger Sub, Inc., a Delaware corporation and a direct wholly-owned subsidiary of the Parent ("*Merger Sub*") (the "*Merger Agreement*");

WHEREAS, the Merger Agreement provides for, among other things, the merger of Merger Sub with and into the Company, with the Company continuing as the surviving entity (the "*First Company Merger*");

WHEREAS, immediately following the First Company Merger, the Company will merge with and into the Parent, with the Parent continuing as the surviving entity (the "*Second Company Merger*" and, the time the Second Company Merger becomes effective being the "*Second Effective Time*");

WHEREAS, pursuant to Section 5. 01(a) of the Indenture, the Parent is required to enter into a supplemental indenture in connection with the Second Company Merger to assume all of the obligations of the Company under the Notes and the Indenture; and

WHEREAS, pursuant to Section 9.01 of the Indenture, the Trustee is authorized to execute and deliver this Supplemental Indenture without the consent of Holders of the Notes.

NOW, THEREFORE, in consideration of the foregoing and for other good and valuable consideration, the receipt of which is hereby acknowledged, the Parent, the Guarantors, and the Trustee mutually covenant and agree for the equal and ratable benefit of the Holders of the Notes as follows:

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;1. CAPITALIZED TERMS. Capitalized terms used herein without definition shall have the meanings assigned to them in the Indenture.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;2.&nbsp;&nbsp;&nbsp;&nbsp;AGREEMENT TO ASSUME. The Parent hereby agrees to assume all the obligations of the Company under the Notes and the Indenture effective as of the Second Effective Time.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;3.&nbsp;&nbsp;&nbsp;&nbsp;NO RECOURSE AGAINST OTHERS. No director, manager, officer, member, employee, incorporator or other owner of Capital Stock of the Parent or any Guarantor, as such, will have any liability for any obligations of the Parent or the Guarantors under the Notes, the Indenture or the Note Guarantees or for any claim based on, in respect of, or by reason of, such obligations or their creation. Each Holder of Notes by accepting a Note waives and releases all such liability. The waiver and release are part of the consideration for issuance of the Notes.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;4. NEW YORK LAW TO GOVERN. THE LAW OF THE STATE OF NEW YORK SHALL GOVERN AND BE USED TO CONSTRUE THIS SUPPLEMENTAL INDENTURE.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;5. COUNTERPARTS. This Supplemental Indenture shall be valid, binding, and enforceable against a party only when executed and delivered by an authorized individual on behalf of the party by means of (i) any electronic signature permitted by the federal Electronic Signatures in Global and National Commerce Act, state enactments of the Uniform Electronic Transactions Act, and/or any other relevant electronic signatures law,

------

including relevant provisions of the Uniform Commercial Code (collectively, "Signature Law"); (ii) an original manual signature; or (iii) a faxed, scanned, or photocopied manual signature. Each electronic signature or faxed, scanned, or photocopied manual signature shall for all purposes have the same validity, legal effect, and admissibility in evidence as an original manual signature. Each party hereto shall be entitled to conclusively rely upon, and shall have no liability with respect to, any faxed, scanned, or photocopied manual signature, or other electronic signature, of any party and shall have no duty to investigate, confirm or otherwise verify the validity or authenticity thereof. This Supplemental Indenture may be executed in any number of counterparts, each of which shall be deemed to be an original, but such counterparts shall, together, constitute one and the same instrument. For avoidance of doubt, original manual signatures shall be used for execution or indorsement of writings when required under the Uniform Commercial Code or other Signature Law due to the character or intended character of the writings.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;6. EFFECT OF HEADINGS. The headings of the Sections of this Supplemental Indenture have been inserted for convenience of reference only, are not to be considered a part of this Supplemental Indenture and will in no way modify or restrict any of the terms or provisions hereof.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;7. THE TRUSTEE. The Trustee shall not be responsible in any manner whatsoever for or in respect of the validity or sufficiency of this Supplemental Indenture or for or in respect of the recitals contained herein, all of which recitals are made solely by the Parent and the Guarantors.

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IN WITNESS WHEREOF, the parties hereto have caused this Supplemental Indenture to be duly executed and attested, all as of the date first above written.

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| | |
|:---|:---|
| Dated: | January 30, 2026 |

---

---

| | |
|:---|:---|
| SM ENERGY COMPANY | SM ENERGY COMPANY |
| By: | /s/ A. WADE PURSELL |
|  | Name: A. Wade Pursell |
|  | Title: Executive Vice President, Chief Financial |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Officer and Treasurer | &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Officer and Treasurer |

---

*Signature Page to First Supplemental Indenture (2030 Notes)*

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| | |
|:---|:---|
| 7N, LLC<br>8 NORTH, LLC<br>COLLEGIATE HOLDINGS LLC<br>AXIS EXPLORATION, LLC<br>BONANZA CREEK ENERGY OPERATING COMPANY, LLC<br>CIVITAS DE BASIN HOLDINGS, LLC<br>CIVITAS DE BASIN HOLDINGS II, LLC<br>CIVITAS DE BASIN MIDSTREAM, LLC<br>CIVITAS DE BASIN MINERALS, LP<br>CIVITAS DE BASIN MINERALS II, LLC<br>CIVITAS DE BASIN NM HOLDINGS, LLC<br>CIVITAS DE BASIN NM MINERALS, LLC<br>CIVITAS DE BASIN RESOURCES, LLC<br>CIVITAS DE BASIN RESOURCES II, LLC<br>CIVITAS MID BASIN ENERGY, LLC<br>CIVITAS MID BASIN ENERGY B, LLC<br>CIVITAS PERMIAN OPERATING, LLC<br>CIVITAS NORTH, LLC<br>CRESTONE PEAK RESOURCES ACQUISITION COMPANY I LLC<br>CRESTONE PEAK RESOURCES GP INC.<br>CRESTONE PEAK RESOURCES LLC<br>CRESTONE PEAK RESOURCES HOLDINGS LLC<br>CRESTONE PEAK RESOURCES LP<br>CRESTONE PEAK RESOURCES MIDSTREAM LLC<br>CRESTONE PEAK RESOURCES OPERATING LLC<br>CRESTONE PEAK RESOURCES WATKINS HOLDINGS LLC<br>CRESTONE PEAK RESOURCES WATKINS MIDSTREAM LLC<br>EXTRACTION FINANCE CORP.<br>EXTRACTION OIL & GAS, INC.<br>FIFTH POCKET PRODUCTION, LLC<br>HIGHPOINT OPERATING CORPORATION<br>HIGHPOINT RESOURCES CORPORATION<br>HOLMES EASTERN COMPANY, LLC<br>MOUNTAINTOP MINERALS, LLC<br>NORTHWEST CORRIDOR HOLDINGS, LLC<br>RAPTOR CONDOR MERGER SUB 2, LLC<br>ROCKY MOUNTAIN INFRASTRUCTURE, LLC<br>TABLE MOUNTAIN RESOURCES, LLC<br>XOG SERVICES, LLC<br>XTR MIDSTREAM, LLC | 7N, LLC<br>8 NORTH, LLC<br>COLLEGIATE HOLDINGS LLC<br>AXIS EXPLORATION, LLC<br>BONANZA CREEK ENERGY OPERATING COMPANY, LLC<br>CIVITAS DE BASIN HOLDINGS, LLC<br>CIVITAS DE BASIN HOLDINGS II, LLC<br>CIVITAS DE BASIN MIDSTREAM, LLC<br>CIVITAS DE BASIN MINERALS, LP<br>CIVITAS DE BASIN MINERALS II, LLC<br>CIVITAS DE BASIN NM HOLDINGS, LLC<br>CIVITAS DE BASIN NM MINERALS, LLC<br>CIVITAS DE BASIN RESOURCES, LLC<br>CIVITAS DE BASIN RESOURCES II, LLC<br>CIVITAS MID BASIN ENERGY, LLC<br>CIVITAS MID BASIN ENERGY B, LLC<br>CIVITAS PERMIAN OPERATING, LLC<br>CIVITAS NORTH, LLC<br>CRESTONE PEAK RESOURCES ACQUISITION COMPANY I LLC<br>CRESTONE PEAK RESOURCES GP INC.<br>CRESTONE PEAK RESOURCES LLC<br>CRESTONE PEAK RESOURCES HOLDINGS LLC<br>CRESTONE PEAK RESOURCES LP<br>CRESTONE PEAK RESOURCES MIDSTREAM LLC<br>CRESTONE PEAK RESOURCES OPERATING LLC<br>CRESTONE PEAK RESOURCES WATKINS HOLDINGS LLC<br>CRESTONE PEAK RESOURCES WATKINS MIDSTREAM LLC<br>EXTRACTION FINANCE CORP.<br>EXTRACTION OIL & GAS, INC.<br>FIFTH POCKET PRODUCTION, LLC<br>HIGHPOINT OPERATING CORPORATION<br>HIGHPOINT RESOURCES CORPORATION<br>HOLMES EASTERN COMPANY, LLC<br>MOUNTAINTOP MINERALS, LLC<br>NORTHWEST CORRIDOR HOLDINGS, LLC<br>RAPTOR CONDOR MERGER SUB 2, LLC<br>ROCKY MOUNTAIN INFRASTRUCTURE, LLC<br>TABLE MOUNTAIN RESOURCES, LLC<br>XOG SERVICES, LLC<br>XTR MIDSTREAM, LLC |
| By: | /s/ A. WADE PURSELL |
|  | Name: A. Wade Pursell |
|  | Title: Executive Vice President, Chief Financial |
| &nbsp;&nbsp;&nbsp;&nbsp; Officer and Treasurer | &nbsp;&nbsp;&nbsp;&nbsp; Officer and Treasurer |

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*Signature Page to First Supplemental Indenture (2030 Notes)*

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| | |
|:---|:---|
|  | <br>COMPUTERSHARE TRUST COMPANY, N.A., |
|  | As Trustee |
| By: | /s/ SCOTT LITTLE |
|  | Name: Scott Little |
|  | Title: Vice President |

---

*Signature Page to First Supplemental Indenture (2030 Notes)*

## Exhibit 4.19

**EXHIBIT 4.19**

**FIRST SUPPLEMENTAL INDENTURE** 

FIRST SUPPLEMENTAL INDENTURE (this "*Supplemental Indenture*"), dated as of January 30, 2026, among SM Energy Company, a Delaware corporation (the "*Parent*"), the Guarantors (as defined in the Indenture referred to herein) and Computershare Trust Company, N.A., as trustee (the "*Trustee*") under the Indenture referred to below.

**W I T N E S S E T H**

WHEREAS, Civitas Resources, Inc. (f/k/a Bonanza Creek Energy, Inc.), a Delaware corporation (the "*Company*") and the guarantors party thereto and the Trustee entered into an indenture (as amended and supplemented from time to time, the "*Indenture*"), dated as of June 3, 2025, providing for the issuance of the Company's 9.625% Senior Notes due 2033 (the "*Notes*");

WHEREAS, the Parent and the Company are party to the Agreement and Plan of Merger, dated November 2, 2025, by and among the Parent, the Company, and Cars Merger Sub, Inc., a Delaware corporation and a direct wholly-owned subsidiary of the Parent ("*Merger Sub*") (the "*Merger Agreement*");

WHEREAS, the Merger Agreement provides for, among other things, the merger of Merger Sub with and into the Company, with the Company continuing as the surviving entity (the "*First Company Merger*");

WHEREAS, immediately following the First Company Merger, the Company will merge with and into the Parent, with the Parent continuing as the surviving entity (the "*Second Company Merger*" and, the time the Second Company Merger becomes effective being the "*Second Effective Time*");

WHEREAS, pursuant to Section 5. 01(a) of the Indenture, the Parent is required to enter into a supplemental indenture in connection with the Second Company Merger to assume all of the obligations of the Company under the Notes and the Indenture; and

WHEREAS, pursuant to Section 9.01 of the Indenture, the Trustee is authorized to execute and deliver this Supplemental Indenture without the consent of Holders of the Notes.

NOW, THEREFORE, in consideration of the foregoing and for other good and valuable consideration, the receipt of which is hereby acknowledged, the Parent, the Guarantors, and the Trustee mutually covenant and agree for the equal and ratable benefit of the Holders of the Notes as follows:

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;1. CAPITALIZED TERMS. Capitalized terms used herein without definition shall have the meanings assigned to them in the Indenture.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;2. AGREEMENT TO ASSUME. The Parent hereby agrees to assume all the obligations of the Company under the Notes and the Indenture effective as of the Second Effective Time.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;3.&nbsp;&nbsp;&nbsp;&nbsp;NO RECOURSE AGAINST OTHERS. No director, manager, officer, member, employee, incorporator or other owner of Capital Stock of the Parent or any Guarantor, as such, will have any liability for any obligations of the Parent or the Guarantors under the Notes, the Indenture or the Note Guarantees or for any claim based on, in respect of, or by reason of, such obligations or their creation. Each Holder of Notes by accepting a Note waives and releases all such liability. The waiver and release are part of the consideration for issuance of the Notes.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;4.&nbsp;&nbsp;&nbsp;&nbsp;NEW YORK LAW TO GOVERN. THE LAW OF THE STATE OF NEW YORK SHALL GOVERN AND BE USED TO CONSTRUE THIS SUPPLEMENTAL INDENTURE.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;5. COUNTERPARTS. This Supplemental Indenture shall be valid, binding, and enforceable against a party only when executed and delivered by an authorized individual on behalf of the party by means of (i) any electronic signature permitted by the federal Electronic Signatures in Global and National Commerce Act, state enactments of the Uniform Electronic Transactions Act, and/or any other relevant electronic signatures law,

------

including relevant provisions of the Uniform Commercial Code (collectively, "Signature Law"); (ii) an original manual signature; or (iii) a faxed, scanned, or photocopied manual signature. Each electronic signature or faxed, scanned, or photocopied manual signature shall for all purposes have the same validity, legal effect, and admissibility in evidence as an original manual signature. Each party hereto shall be entitled to conclusively rely upon, and shall have no liability with respect to, any faxed, scanned, or photocopied manual signature, or other electronic signature, of any party and shall have no duty to investigate, confirm or otherwise verify the validity or authenticity thereof. This Supplemental Indenture may be executed in any number of counterparts, each of which shall be deemed to be an original, but such counterparts shall, together, constitute one and the same instrument. For avoidance of doubt, original manual signatures shall be used for execution or indorsement of writings when required under the Uniform Commercial Code or other Signature Law due to the character or intended character of the writings.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;6. EFFECT OF HEADINGS. The headings of the Sections of this Supplemental Indenture have been inserted for convenience of reference only, are not to be considered a part of this Supplemental Indenture and will in no way modify or restrict any of the terms or provisions hereof.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;7. THE TRUSTEE. The Trustee shall not be responsible in any manner whatsoever for or in respect of the validity or sufficiency of this Supplemental Indenture or for or in respect of the recitals contained herein, all of which recitals are made solely by the Parent and the Guarantors.

------

IN WITNESS WHEREOF, the parties hereto have caused this Supplemental Indenture to be duly executed and attested, all as of the date first above written.

---

| | |
|:---|:---|
| Dated: | January 30, 2026 |

---

---

| | |
|:---|:---|
| SM ENERGY COMPANY | SM ENERGY COMPANY |
| By: | /s/ A. WADE PURSELL |
|  | Name: A. Wade Pursell |
|  | Title: Executive Vice President, Chief Financial |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Officer and Treasurer | &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Officer and Treasurer |

---

*Signature Page to First Supplemental Indenture (2033 Notes)*

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---

| | |
|:---|:---|
| 7N, LLC<br>8 NORTH, LLC<br>COLLEGIATE HOLDINGS LLC<br>AXIS EXPLORATION, LLC<br>BONANZA CREEK ENERGY OPERATING COMPANY, LLC<br>CIVITAS DE BASIN HOLDINGS, LLC<br>CIVITAS DE BASIN HOLDINGS II, LLC<br>CIVITAS DE BASIN MIDSTREAM, LLC<br>CIVITAS DE BASIN MINERALS, LP<br>CIVITAS DE BASIN MINERALS II, LLC<br>CIVITAS DE BASIN NM HOLDINGS, LLC<br>CIVITAS DE BASIN NM MINERALS, LLC<br>CIVITAS DE BASIN RESOURCES, LLC<br>CIVITAS DE BASIN RESOURCES II, LLC<br>CIVITAS MID BASIN ENERGY, LLC<br>CIVITAS MID BASIN ENERGY B, LLC<br>CIVITAS PERMIAN OPERATING, LLC<br>CIVITAS NORTH, LLC<br>CRESTONE PEAK RESOURCES ACQUISITION COMPANY I LLC<br>CRESTONE PEAK RESOURCES GP INC.<br>CRESTONE PEAK RESOURCES LLC<br>CRESTONE PEAK RESOURCES HOLDINGS LLC<br>CRESTONE PEAK RESOURCES LP<br>CRESTONE PEAK RESOURCES MIDSTREAM LLC<br>CRESTONE PEAK RESOURCES OPERATING LLC<br>CRESTONE PEAK RESOURCES WATKINS HOLDINGS LLC<br>CRESTONE PEAK RESOURCES WATKINS MIDSTREAM LLC<br>EXTRACTION FINANCE CORP.<br>EXTRACTION OIL & GAS, INC.<br>FIFTH POCKET PRODUCTION, LLC<br>HIGHPOINT OPERATING CORPORATION<br>HIGHPOINT RESOURCES CORPORATION<br>HOLMES EASTERN COMPANY, LLC<br>MOUNTAINTOP MINERALS, LLC<br>NORTHWEST CORRIDOR HOLDINGS, LLC<br>RAPTOR CONDOR MERGER SUB 2, LLC<br>ROCKY MOUNTAIN INFRASTRUCTURE, LLC<br>TABLE MOUNTAIN RESOURCES, LLC<br>XOG SERVICES, LLC<br>XTR MIDSTREAM, LLC | 7N, LLC<br>8 NORTH, LLC<br>COLLEGIATE HOLDINGS LLC<br>AXIS EXPLORATION, LLC<br>BONANZA CREEK ENERGY OPERATING COMPANY, LLC<br>CIVITAS DE BASIN HOLDINGS, LLC<br>CIVITAS DE BASIN HOLDINGS II, LLC<br>CIVITAS DE BASIN MIDSTREAM, LLC<br>CIVITAS DE BASIN MINERALS, LP<br>CIVITAS DE BASIN MINERALS II, LLC<br>CIVITAS DE BASIN NM HOLDINGS, LLC<br>CIVITAS DE BASIN NM MINERALS, LLC<br>CIVITAS DE BASIN RESOURCES, LLC<br>CIVITAS DE BASIN RESOURCES II, LLC<br>CIVITAS MID BASIN ENERGY, LLC<br>CIVITAS MID BASIN ENERGY B, LLC<br>CIVITAS PERMIAN OPERATING, LLC<br>CIVITAS NORTH, LLC<br>CRESTONE PEAK RESOURCES ACQUISITION COMPANY I LLC<br>CRESTONE PEAK RESOURCES GP INC.<br>CRESTONE PEAK RESOURCES LLC<br>CRESTONE PEAK RESOURCES HOLDINGS LLC<br>CRESTONE PEAK RESOURCES LP<br>CRESTONE PEAK RESOURCES MIDSTREAM LLC<br>CRESTONE PEAK RESOURCES OPERATING LLC<br>CRESTONE PEAK RESOURCES WATKINS HOLDINGS LLC<br>CRESTONE PEAK RESOURCES WATKINS MIDSTREAM LLC<br>EXTRACTION FINANCE CORP.<br>EXTRACTION OIL & GAS, INC.<br>FIFTH POCKET PRODUCTION, LLC<br>HIGHPOINT OPERATING CORPORATION<br>HIGHPOINT RESOURCES CORPORATION<br>HOLMES EASTERN COMPANY, LLC<br>MOUNTAINTOP MINERALS, LLC<br>NORTHWEST CORRIDOR HOLDINGS, LLC<br>RAPTOR CONDOR MERGER SUB 2, LLC<br>ROCKY MOUNTAIN INFRASTRUCTURE, LLC<br>TABLE MOUNTAIN RESOURCES, LLC<br>XOG SERVICES, LLC<br>XTR MIDSTREAM, LLC |
| By: | /s/ A. WADE PURSELL |
|  | Name: A. Wade Pursell |
|  | Title: Executive Vice President, Chief Financial |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Officer and Treasurer | &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Officer and Treasurer |

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*Signature Page to First Supplemental Indenture (2033 Notes)*

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| | |
|:---|:---|
|  | <br>COMPUTERSHARE TRUST COMPANY, N.A., |
|  | As Trustee |
| By: | /s/ SCOTT LITTLE |
|  | Name: Scott Little |
|  | Title: Vice President |

---

*Signature Page to First Supplemental Indenture (2033 Notes)*

## Exhibit 4.20

**EXHIBIT 4.20**

***FIRST SUPPLEMENTAL INDENTURE***

FIRST SUPPLEMENTAL INDENTURE (this "<u>Guarantor Supplemental Indenture</u>"), dated as of January 30, 2026, among SM Energy Company (the "<u>Company</u>"), the Company's Subsidiaries listed on Schedule A hereto (each, a "<u>New Guarantor</u>") and U.S. Bank Trust Company, National Association, as trustee under the Indenture referred to below (the "<u>Trustee</u>").

WITNESSETH

WHEREAS, the Company and the Trustee are parties to an Indenture dated as of July 25, 2024 (as amended or supplemented, the "<u>Indenture</u>") by and between the Company and the Trustee, providing for the issuance of the Company's 6.750% Senior Notes due 2029 and 7.000% Senior Notes due 2032 (collectively, the "<u>Notes</u>");

WHEREAS, Section 9.01 of the Indenture provides that, without the consent of any Holders, the Company and the Trustee, at any time and from time to time, may modify, supplement or amend the Indenture to add a Guarantor or additional obligor under the Indenture or permit any Person to guarantee the Notes and/or obligations under the Indenture;

WHEREAS, each New Guarantor wishes to guarantee the Notes pursuant to the Indenture;

WHEREAS, pursuant to the Indenture, the Company, the New Guarantors and the Trustee have agreed to enter into this Guarantor Supplemental Indenture for the purposes stated herein; and

WHEREAS, all things necessary have been done to make this Guarantor Supplemental Indenture, when executed and delivered by the Company and each New Guarantor, the legal, valid and binding agreement of the Company and each New Guarantor, in accordance with its terms.

NOW THEREFORE, in consideration of the foregoing and for other good and valuable consideration, the receipt of which is hereby acknowledged, the Company, each New Guarantor and the Trustee mutually covenant and agree for the equal and ratable benefit of the Holders of the Notes as follows:

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(1) <u>Capitalized Terms</u>. Capitalized terms used herein without definition shall have the meanings assigned to them in the Indenture.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(2) <u>Guarantee</u>. Each New Guarantor hereby guarantees the obligations of the Company under the Indenture and the Notes related thereto pursuant to the terms and conditions of Article Ten of the Indenture, such Article Ten being incorporated by reference herein as if set forth at length herein (each such guarantee, a "<u>Guarantee</u>") and such New Guarantor agrees to be bound as a Subsidiary Guarantor under the Indenture as if it had been an initial signatory thereto; *provided,* that the New Guarantor can be released from its Guarantee to the same extent as any other Subsidiary Guarantor under the Indenture.

------

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(3) <u>GOVERNING LAW</u>. THIS GUARANTOR SUPPLEMENTAL INDENTURE SHALL BE GOVERNED BY, AND CONSTRUED IN ACCORDANCE WITH, THE LAWS OF THE STATE OF NEW YORK.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(4) <u>Counterparts</u>. The parties may sign any number of copies of this Guarantor Supplemental Indenture. Each signed copy shall be an original, but all of them together represent the same agreement.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(5) <u>Effect of Headings</u>. The section headings herein are for convenience only and shall not affect the construction hereof.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(6) <u>The Trustee</u>. The Trustee shall not be responsible in any manner whatsoever for or in respect of the validity or sufficiency of this Guarantor Supplemental Indenture or for or in respect of the recitals contained herein, all of which recitals are made solely by the Company and the New Guarantors.

------

IN WITNESS WHEREOF, the parties hereto have caused this Guarantor Supplemental Indenture to be duly executed and attested, all as of the date first above written.

<br>Dated: &nbsp;&nbsp;&nbsp;&nbsp;January 30, 2026

SM ENERGY COMPANY,

a Delaware corporation

---

| | |
|:---|:---|
| By: | /s/ A. WADE PURSELL |
|  | Name: A. Wade Pursell |
|  | Title: Executive Vice President, Chief |
|  | &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp; Financial Officer and Treasurer |

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EACH GUARANTOR LISTED ON

SCHEDULE A HERETO

---

| | |
|:---|:---|
| By: | /s/ A. WADE PURSELL |
|  | Name: A. Wade Pursell |
|  | Title: Executive Vice President, Chief |
|  | &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp; Financial Officer and Treasurer |

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U.S. Bank Trust Company, National Association, as Trustee

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| | |
|:---|:---|
| By: | /s/ MICHAEL MCGUIRE |
|  | Authorized Signatory |

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*Signature Page to First Supplemental Indenture (2029, 2032 Notes)*

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SCHEDULE A

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;1.Extraction Oil & Gas, Inc., a Delaware corporation

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;2.HighPoint Resources Corporation, a Delaware corporation

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;3.Raptor Condor Merger Sub 2, LLC, a Delaware limited liability company

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;4.Civitas North, LLC, a Colorado limited liability company

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;5.Civitas MID Basin Energy, LLC, a Delaware limited liability company

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;6.Civitas MID Basin Energy B, LLC, a Delaware limited liability company

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;7.Bonanza Creek Energy Operating Company, LLC, a Delaware limited liability company

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;8.Civitas DE Basin NM Holdings, LLC, a Delaware limited liability company

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;9.Civitas DE Basin Resources, LLC, a Delaware limited liability company

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;10.Civitas DE Basin Resources II, LLC, a Delaware limited liability company

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;11.Extraction Finance Corp., a Delaware corporation

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;12.HighPoint Operating Corporation, a Delaware corporation

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;13.Fifth Pocket Production, LLC, a Colorado limited liability company

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;14.Mountaintop Minerals, LLC, a Delaware limited liability company

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;15.Table Mountain Resources, LLC, a Delaware limited liability company

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;16.Axis Exploration, LLC, a Delaware limited liability company

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;17.Northwest Corridor Holdings, LLC, a Delaware limited liability company

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;18.XOG Services, LLC, a Delaware limited liability company

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;19.XTR Midstream, LLC, a Delaware limited liability company

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;20.7N, LLC, a Delaware limited liability company

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;21.8 North, LLC, a Delaware limited liability company

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;22.Crestone Peak Resources GP Inc., a Delaware corporation

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;23.Crestone Peak Resources LP, a Delaware limited partnership

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;24.Civitas Permian Operating, LLC, a Delaware limited liability company

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;25.Crestone Peak Resources LLC, a Delaware limited liability company

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;26.Crestone Peak Resources Holdings LLC, a Delaware limited liability company

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&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;27.Crestone Peak Resources Operating LLC, a Delaware limited liability

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;28.Crestone Peak Resources Midstream LLC, a Delaware limited liability company

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;29.Crestone Peak Resources Acquisition Company I LLC, a Delaware limited liability company

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;30.Collegiate Holdings LLC, a Delaware limited liability company

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;31.Crestone Peak Resources Watkins Midstream LLC, a Delaware limited liability company

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;32.Crestone Peak Resources Watkins Holdings LLC, a Delaware limited liability company

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;33.Civitas DE Basin NM Minerals, LLC, a Delaware limited liability company

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;34.Civitas DE Basin Holdings, LLC, a Delaware limited liability company

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;35.Civitas DE Basin Minerals, LP, a Delaware limited partnership

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;36.Civitas DE Basin Midstream, LLC, a Delaware limited liability company

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;37.Civitas DE Basin Holdings II, LLC, a Delaware limited liability company

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;38.Civitas DE Basin Minerals II, LLC, a Delaware limited liability company

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;39.Holmes Eastern Company, LLC, a Delaware limited liability company

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;40.Rocky Mountain Infrastructure, LLC, a Delaware limited liability company

## Exhibit 4.21

**EXHIBIT 4.21**

***SIXTH SUPPLEMENTAL INDENTURE***

SIXTH SUPPLEMENTAL INDENTURE (this "<u>Guarantor Supplemental Indenture</u>"), dated as of January 30, 2026, among SM Energy Company (the "<u>Company</u>"), the Company's Subsidiaries listed on Schedule A hereto (each, a "<u>New Guarantor</u>") and U.S. Bank Trust Company, National Association (as successor in interest to U.S. Bank, National Association), as trustee under the Indenture referred to below (the "<u>Trustee</u>").

WITNESSETH

WHEREAS, the Company and the Trustee are parties to an Indenture dated as of May 21, 2015 (the "<u>Base Indenture</u>") by and between the Company and the Trustee, as amended and supplemented by the Third Supplemental Indenture dated as of September 12, 2016 (the "<u>Third Supplemental Indenture</u>"), providing for the issuance of the Company's 6.750% Senior Notes due 2026 (the "<u>2026 Notes</u>"), the Fourth Supplemental Indenture dated as of August 20, 2018 (the "<u>Fourth Supplemental Indenture</u>"), providing for the issuance of the Company's 6.625% Senior Notes due 2027 (the "<u>2027 Notes</u>") and the Fifth Supplemental Indenture dated as of June 23, 2021 (the "<u>Fifth Supplemental Indenture</u>") (the Base Indenture, as so amended and supplemented by the Third Supplemental Indenture, the Fourth Supplemental Indenture and the Fifth Supplemental Indenture, being called the "<u>Indenture</u>"), providing for the issuance of the Company's 6.500% Senior Notes due 2028 (the "<u>2028 Notes</u>" and, together with the 2026 Notes and the 2027 Notes, the "<u>Notes</u>");

WHEREAS, Section 10.01 of the Indenture provides that, without the consent of any Holders, the Company and the Trustee, at any time and from time to time, may modify, supplement or amend the Indenture to add a Guarantor or additional obligor under the Indenture or permit any Person to guarantee the Notes and/or obligations under the Indenture;

WHEREAS, each New Guarantor wishes to guarantee the Notes pursuant to the Indenture;

WHEREAS, pursuant to the Indenture, the Company, the New Guarantors and the Trustee have agreed to enter into this Guarantor Supplemental Indenture for the purposes stated herein; and

WHEREAS, all things necessary have been done to make this Guarantor Supplemental Indenture, when executed and delivered by the Company and each New Guarantor, the legal, valid and binding agreement of the Company and each New Guarantor, in accordance with its terms.

NOW THEREFORE, in consideration of the foregoing and for other good and valuable consideration, the receipt of which is hereby acknowledged, the Company, each New Guarantor and the Trustee mutually covenant and agree for the equal and ratable benefit of the Holders of the Notes as follows:

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(1) <u>Capitalized Terms</u>. Capitalized terms used herein without definition shall have the meanings assigned to them in the Indenture.

------

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(2) <u>Guarantee</u>. Each New Guarantor hereby guarantees (i) the obligations of the Company under the Third Supplemental Indenture and the 2026 Notes related thereto pursuant to the terms and conditions of Article Eleven of the Third Supplemental Indenture, such Article Eleven being incorporated by reference herein as if set forth at length herein, (ii) the obligations of the Company under the Fourth Supplemental Indenture and the 2027 Notes related thereto pursuant to the terms and conditions of Article Eleven of the Fourth Supplemental Indenture, such Article Eleven being incorporated by reference herein as if set forth at length herein and (iii) the obligations of the Company under the Fifth Supplemental Indenture and the 2028 Notes related thereto pursuant to the terms and conditions of Article Eleven of the Fifth Supplemental Indenture, such Article Eleven being incorporated by reference herein as if set forth at length herein (each such guarantee, a "<u>Guarantee</u>") and such New Guarantor agrees to be bound as a Subsidiary Guarantor under the Indenture as if it had been an initial signatory thereto; *provided,* that the New Guarantor can be released from its Guarantee to the same extent as any other Subsidiary Guarantor under the Indenture.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(3) <u>GOVERNING LAW</u>. THIS GUARANTOR SUPPLEMENTAL INDENTURE SHALL BE GOVERNED BY, AND CONSTRUED IN ACCORDANCE WITH, THE LAWS OF THE STATE OF NEW YORK.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(4) <u>Counterparts</u>. The parties may sign any number of copies of this Guarantor Supplemental Indenture. Each signed copy shall be an original, but all of them together represent the same agreement.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(5) <u>Effect of Headings</u>. The section headings herein are for convenience only and shall not affect the construction hereof.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(6) <u>The Trustee</u>. The Trustee shall not be responsible in any manner whatsoever for or in respect of the validity or sufficiency of this Guarantor Supplemental Indenture or for or in respect of the recitals contained herein, all of which recitals are made solely by the Company and the New Guarantors.

&nbsp;&nbsp;&nbsp;&nbsp;

&nbsp;&nbsp;&nbsp;&nbsp;

------

IN WITNESS WHEREOF, the parties hereto have caused this Guarantor Supplemental Indenture to be duly executed and attested, all as of the date first above written.

<br>Dated: January 30, 2026

SM ENERGY COMPANY,

a Delaware corporation

---

| | |
|:---|:---|
| By: | /s/ A. WADE PURSELL |
|  | Name: A. Wade Pursell |
|  | Title: Executive Vice President, Chief |
|  | &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp; Financial Officer and Treasurer |

---

EACH GUARANTOR LISTED ON

SCHEDULE A HERETO

---

| | |
|:---|:---|
| By: | /s/ A. WADE PURSELL |
|  | Name: A. Wade Pursell |
|  | Title: Executive Vice President, Chief |
|  | Financial Officer and Treasurer |

---

U.S. Bank Trust Company, National Association, as Trustee

---

| | |
|:---|:---|
| By: | /s/ MICHAEL MCGUIRE |
|  | Authorized Signatory |

---

*Signature Page to Sixth Supplemental Indenture (2026, 2027, 2028 Notes)*

------

SCHEDULE A

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;1.Extraction Oil & Gas, Inc., a Delaware corporation

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;2.HighPoint Resources Corporation, a Delaware corporation

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;3.Raptor Condor Merger Sub 2, LLC, a Delaware limited liability company

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;4.Civitas North, LLC, a Colorado limited liability company

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;5.Civitas MID Basin Energy, LLC, a Delaware limited liability company

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;6.Civitas MID Basin Energy B, LLC, a Delaware limited liability company

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;7.Bonanza Creek Energy Operating Company, LLC, a Delaware limited liability company

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;8.Civitas DE Basin NM Holdings, LLC, a Delaware limited liability company

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;9.Civitas DE Basin Resources, LLC, a Delaware limited liability company

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;10.Civitas DE Basin Resources II, LLC, a Delaware limited liability company

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;11.Extraction Finance Corp., a Delaware corporation

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;12.HighPoint Operating Corporation, a Delaware corporation

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;13.Fifth Pocket Production, LLC, a Colorado limited liability company

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;14.Mountaintop Minerals, LLC, a Delaware limited liability company

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;15.Table Mountain Resources, LLC, a Delaware limited liability company

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;16.Axis Exploration, LLC, a Delaware limited liability company

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;17.Northwest Corridor Holdings, LLC, a Delaware limited liability company

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;18.XOG Services, LLC, a Delaware limited liability company

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;19.XTR Midstream, LLC, a Delaware limited liability company

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;20.7N, LLC, a Delaware limited liability company

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;21.8 North, LLC, a Delaware limited liability company

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;22.Crestone Peak Resources GP Inc., a Delaware corporation

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;23.Crestone Peak Resources LP, a Delaware limited partnership

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;24.Civitas Permian Operating, LLC, a Delaware limited liability company

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;25.Crestone Peak Resources LLC, a Delaware limited liability company

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;26.Crestone Peak Resources Holdings LLC, a Delaware limited liability company

------

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;27.Crestone Peak Resources Operating LLC, a Delaware limited liability

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;28.Crestone Peak Resources Midstream LLC, a Delaware limited liability company

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;29.Crestone Peak Resources Acquisition Company I LLC, a Delaware limited liability company

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;30.Collegiate Holdings LLC, a Delaware limited liability company

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;31.Crestone Peak Resources Watkins Midstream LLC, a Delaware limited liability company

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;32.Crestone Peak Resources Watkins Holdings LLC, a Delaware limited liability company

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;33.Civitas DE Basin NM Minerals, LLC, a Delaware limited liability company

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;34.Civitas DE Basin Holdings, LLC, a Delaware limited liability company

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;35.Civitas DE Basin Minerals, LP, a Delaware limited partnership

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;36.Civitas DE Basin Midstream, LLC, a Delaware limited liability company

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;37.Civitas DE Basin Holdings II, LLC, a Delaware limited liability company

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;38.Civitas DE Basin Minerals II, LLC, a Delaware limited liability company

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;39.Holmes Eastern Company, LLC, a Delaware limited liability company

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;40.Rocky Mountain Infrastructure, LLC, a Delaware limited liability company

## Exhibit 4.22

**EXHIBIT 4.22**

**<u>DESCRIPTION OF SECURITIES</u>**

As of the filing of this report, SM Energy Company has registered one class of securities under Section 12 of the Securities Exchange Act of 1934, as amended (the "**<u>Exchange Act</u>**").

**Description of Common Stock**

The following description of our Common Stock is a summary and does not purport to be complete. It is subject to, and qualified in its entirety by, reference to our Restated Certificate of Incorporation (the "**<u>Certificate of Incorporation</u>**") and our Amended and Restated By-laws (the "**<u>Bylaws</u>**"), each of which are incorporated by reference as an exhibit to the Annual Report on Form 10-K of which this Exhibit is a part. We encourage you to read our Certificate of Incorporation, our Bylaws and the applicable provisions of the Delaware General Corporate Law, for additional information.

***Authorized Capital Shares***

Our authorized capital shares consist of 400,000,000 shares of capital stock, $0.01 par value per share. We have outstanding shares of common stock ("**<u>Common Stock</u>**"). The outstanding shares of our Common Stock are fully paid and non-assessable. This means the full purchase price for the outstanding shares of Common Stock has been paid and the holders of such shares will not be assessed any additional amounts for such shares. Any additional shares of Common Stock that the Company may issue in the future will also be fully paid and non-assessable.

The Certificate of Incorporation provides that authorized but unissued shares of Common Stock are available for future issuance without stockholder approval, subject to various limitations imposed by the New York Stock Exchange ("**<u>NYSE</u>**"). These additional shares of Common Stock may be utilized for a variety of corporate purposes, including future public offerings to raise additional capital, corporate acquisitions and employee benefit plans. The existence of authorized but unissued shares of Common Stock could make it more difficult or discourage an attempt to obtain control of the Company by means of a proxy contest, tender offer, merger or otherwise.

***Voting Rights***

Each share of Common Stock is entitled to one vote on all matters submitted to a vote of the stockholders, including the election of directors. Our Common Stock does not have cumulative voting rights. This means a holder of a single share of Common Stock cannot cast more than one vote for each position to be filled on the Board of Directors. It also means the holders of a majority of the shares of Common Stock entitled to vote in the election of directors can elect all directors standing for election and the holders of the remaining shares will not be able to elect any directors.

***Dividend Rights***

The holders of Common Stock are entitled to receive ratably such dividends, if any, as may be declared from time to time by the Board of Directors in its discretion out of funds legally available for the payment of dividends. Delaware law allows a corporation to pay dividends only out of surplus, as determined under Delaware law.

***Liquidation Rights***

Upon the liquidation, dissolution or winding up of the Company, the holders of Common Stock are entitled to receive ratably the net assets of the Company legally available for distribution.

***Other Rights and Preferences***

Our Common Stock has no sinking fund provision or preemptive, subscription or conversion rights. The holders of Common Stock may act by unanimous written consent.

***Listing***

Our Common Stock is traded on the NYSE under the trading symbol "SM."

## Exhibit 10.25

**EXHIBIT 10.25**

**SUMMARY OF COMPENSATION ARRANGEMENTS FOR NON-EMPLOYEE DIRECTORS**

The following is a description of the standard arrangements pursuant to which members of the Board of Directors (a "Director" or the "Board") of SM Energy Company (the "Company") are compensated for their services:

**DIRECTOR COMPENSATION**

Employee directors do not receive compensation for their service on the Board or any committee of the Board (each a "Committee").

Directors are generally elected by the Company's stockholders at their annual meeting in late May of each year to serve a one-year term through the subsequent year's annual meeting of stockholders. For service during the 2025 - 2026 term, target base compensation for each member of the Board of Directors was set at $280,000 annually, and was split between (i) an equity grant comprised of the Company's common stock valued at $185,000 at the time of election; and (ii) a cash retainer of $95,000, paid in lieu of Board and Committee meeting attendance fees.

With respect to the annual equity grant component of a Director's compensation, the number of shares issued to each Director was determined based on the closing price of the Company's common stock on the date of election to the Board and resulted in the grant of 7,982 shares to each non-employee Director, which shares were restricted upon issuance until they vested on December 31, 2025.

With respect to the cash retainer component of a Director's compensation, Directors may elect to receive shares of the Company's common stock in lieu of, and of a value equal to, the amount of the annual cash retainer. Further, if any non-employee Director attends more than 30 Board and Committee meetings in the aggregate during the one-year term, such Director is entitled to $1,500 per meeting for each meeting in excess of 30. No Director attended more than 30 Board and Committee meetings during the trailing one-year term.

In addition, each Director is reimbursed for expenses incurred in attending Board and Committee meetings and director education programs.

In addition to the base Director compensation structure described above, the non-executive chairman of the Board and the chair of each Committee received compensation in the amounts set forth below in recognition of the additional workload of their respective assignments. With the exception of the non-executive chairman payment, these amounts were paid in cash at the beginning of the annual service period.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• Non-executive Chairman - $140,000 (equity compensation paid in the form of 6,040 shares of the Company's common stock based on the closing price on the date of the Company's annual meeting); these shares were restricted upon issuance until they vested on December 31, 2025.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• Audit Committee - $25,000

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• Compensation Committee - $20,000

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• Governance and Sustainability Committee - $20,000

For their 2025 - 2026 term of service, Barton Brookman, Anita Powers, and William Sullivan elected to receive their retainer in the form of shares of the Company's common stock, which resulted in a grant of 4,099 additional shares of SM Energy common stock. These shares were restricted upon issuance until they vested on December 31, 2025. Carla Bailo, Ramiro Peru, Julio Quintana, Rose Robeson and Ashwin Venkatraman each elected to receive the $95,000 cash payment for their retainer.

All shares issued to Directors as compensation for their Board service are issued under SM Energy's Equity Incentive Compensation Plan.

## Exhibit 21.1

**EXHIBIT 21.1**

**SUBSIDIARIES**

**OF**

**SM ENERGY COMPANY**

None. Pursuant to Securities and Exchange Commission ("SEC") Regulation S-K, Item 601(b)(21), no subsidiaries or aggregation of subsidiaries constitute a significant subsidiary, as defined under SEC Regulation S-X, Rule 1-02(w), as of December 31, 2025.

## Exhibit 23.1

**EXHIBIT 23.1**

Consent of Independent Registered Public Accounting Firm

We consent to the incorporation by reference in the following Registration Statements:

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(1)Registration Statement (Form S-4 No. 333-291956) of SM Energy Company,

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(2)Registration Statements (Form S-8 Nos. 333-134221, 333-151779, 333-165740, 333-170351, 333-194305, 333-212359, and 333-226660) pertaining to the Equity Incentive Compensation Plan of SM Energy Company,

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(3)Registration Statement (Form S-8 No. 333-288917) pertaining to the SM Energy Company 2025 Equity Incentive Compensation Plan,

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(4)Registration Statement (Form S-8 Nos. 333-219719 and 333-257005) pertaining to the SM Energy Company Employee Stock Purchase Plan, and

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(5)Registration Statement (Form S-8 No. 333-293103) pertaining to the Civitas Resources, Inc. 2024 Long Term Incentive Plan, Civitas Resources, Inc. 2021 Long Term Incentive Plan, Extraction Oil & Gas, Inc. 2021 Long Term Incentive Plan, and Bonanza Creek Energy, Inc. 2017 Long Term Incentive Plan;

of our reports dated February 26, 2026, with respect to the consolidated financial statements of SM Energy Company and subsidiaries and the effectiveness of internal control over financial reporting of SM Energy Company and subsidiaries, included in this Annual Report (Form 10-K) of SM Energy Company for the year ended December 31, 2025.

/s/ Ernst & Young LLP

Denver, Colorado

February 26, 2026

## Exhibit 23.2

![ryderscottheaderb.jpg](ryderscottheaderb.jpg)

**EXHIBIT 23.2**

CONSENT OF INDEPENDENT PETROLEUM ENGINEERS AND GEOLOGISTS

The undersigned hereby consents to the references to our firm in the form and context in which they appear in the Annual Report on Form 10-K of SM Energy Company for the year ended December 31, 2025. We hereby further consent to the use of information contained in our reports, and the use of our audit letter, as of December 31, 2025, relating to estimates of SM Energy Company's oil, gas, and NGL reserves. We further consent to the incorporation by reference thereof into SM Energy Company's Registration Statement Nos. 333-134221, 333-151779, 333-165740, 333-170351, 333-194305, 333-212359, 333-219719, 333-226660, 333-257005, 333-288917, and 333-293103 on Form S-8, and Registration Statement No. 333-291956 on Form S-4.

<u>/s/ RYDER SCOTT COMPANY, L.P.</u>

RYDER SCOTT COMPANY, L.P.

TBPELS Firm Registration No. F-1580

Houston, Texas

February 26, 2026

![imageb.jpg](imageb.jpg)

## Exhibit 31.1

**EXHIBIT 31.1**

**CERTIFICATION** 

I, Elizabeth A. McDonald, certify that:

1.&nbsp;&nbsp;&nbsp;&nbsp;I have reviewed this annual report on Form 10-K of SM Energy Company;

2.&nbsp;&nbsp;&nbsp;&nbsp;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.&nbsp;&nbsp;&nbsp;&nbsp;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.&nbsp;&nbsp;&nbsp;&nbsp;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)&nbsp;&nbsp;&nbsp;&nbsp;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)&nbsp;&nbsp;&nbsp;&nbsp;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)&nbsp;&nbsp;&nbsp;&nbsp;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)&nbsp;&nbsp;&nbsp;&nbsp;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.&nbsp;&nbsp;&nbsp;&nbsp;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 (or persons performing the equivalent functions):

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(a)&nbsp;&nbsp;&nbsp;&nbsp;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)&nbsp;&nbsp;&nbsp;&nbsp;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 26, 2026

<u>/s/ ELIZABETH A. MCDONALD</u>

Elizabeth A. McDonald

President and Chief Executive Officer

## Exhibit 31.2

**EXHIBIT 31.2**

**CERTIFICATION**

I, A. Wade Pursell, certify that:

1.&nbsp;&nbsp;&nbsp;&nbsp;I have reviewed this annual report on Form 10-K of SM Energy Company;

2.&nbsp;&nbsp;&nbsp;&nbsp;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.&nbsp;&nbsp;&nbsp;&nbsp;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.&nbsp;&nbsp;&nbsp;&nbsp;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)&nbsp;&nbsp;&nbsp;&nbsp;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)&nbsp;&nbsp;&nbsp;&nbsp;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)&nbsp;&nbsp;&nbsp;&nbsp;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)&nbsp;&nbsp;&nbsp;&nbsp;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.&nbsp;&nbsp;&nbsp;&nbsp;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 (or persons performing the equivalent functions):

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(a)&nbsp;&nbsp;&nbsp;&nbsp;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)&nbsp;&nbsp;&nbsp;&nbsp;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 26, 2026

<u>/s/ A. WADE PURSELL</u>

A. Wade Pursell

Executive Vice President and Chief Financial Officer

## Exhibit 32.1

**EXHIBIT 32.1**

**CERTIFICATION**

**PURSUANT TO**

**18 U.S.C. SECTION 1350, AS ADOPTED PURSUANT TO**

**SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002**

In connection with the Annual Report on Form 10-K of SM Energy Company (the "Company") for the fiscal year ended December 31, 2025, as filed with the Securities and Exchange Commission on the date hereof (the "Report"), Elizabeth A. McDonald, as President and Chief Executive Officer of the Company, and A. Wade Pursell, as Executive Vice President and Chief Financial Officer of the Company, each hereby certifies, pursuant to and solely for the purpose of 18 U.S.C. § 1350, as adopted pursuant to § 906 of the Sarbanes-Oxley Act of 2002, to the best of his knowledge and belief, that:

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(1)&nbsp;&nbsp;&nbsp;&nbsp;The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934 (15 U.S.C. 78m or 78o(d)); and

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(2)&nbsp;&nbsp;&nbsp;&nbsp;The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

<u>/s/ ELIZABETH A. MCDONALD</u>

Elizabeth A. McDonald

President and Chief Executive Officer

February 26, 2026

<u>/s/ A. WADE PURSELL</u>

A. Wade Pursell

Executive Vice President and Chief Financial Officer

February 26, 2026

## Exhibit 95.1

**EXHIBIT 95.1**

**Mine Safety Disclosures**

Section 1503(a) of the Dodd-Frank Wall Street Reform and Consumer Protection Act ("Dodd-Frank Act") and Item 104 of Regulation S-K (17 CFR 229.104) ("Item 104") require certain disclosures by companies required to file periodic reports under the Securities Exchange Act of 1934, as amended, that operate mines regulated under the Federal Mine Safety and Health Act of 1977, as amended by the Mine Improvement and New Emergency Response Act of 2006 ("Mine Act").

The Company owns a sand mine that is subject to regulation by the U.S. Federal Mine Safety and Health Administration ("MSHA"). The sand mine is listed under MSHA Mine ID No. 42-02760 and is located in Duchesne County, Utah ("Bundick Sand Mine"). Operations at the Bundick Sand Mine are conducted by a third party.

*Mine Safety Information*

The following provides additional information about references used in the table below to describe the categories of violations, orders or citations issued by MSHA under the Mine Act:

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• *Section 104(a) Significant and Substantial ("S&S") Citations:* Citations for violations of mandatory health or safety standards that could significantly and substantially contribute to the cause and effect of a mine safety or health hazard.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• *Section 104(b) Orders*: Orders which represent a failure to abate a citation under section 104(a) within the period of time prescribed by MSHA. This results in an order of immediate withdrawal from the area of the mine affected by the condition until MSHA determines that the violation has been abated.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• *Section 104(d) Citations and Orders*: Citations and orders for an unwarrantable failure to comply with mandatory health or safety standards.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• *Section 110(b) Violations*: Flagrant violations.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• *Section 107(a) Orders*: Orders for situations in which MSHA determined an "imminent danger" (as defined by MSHA) existed.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• *Notice of Pattern of Violations*: Notice of a pattern of violations of mandatory health or safety standards that are of such nature as could have significantly and substantially contributed to the cause and effect of mine health or safety hazards under section 104(e) of the Mine Act.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• *Notice of Potential Pattern of Violations*: Notice of the potential to have a pattern of violations under section 104(e).

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• *Pending Legal Actions*: Legal actions before the Federal Mine Safety and Health Review Commission initiated.

---

| | |
|:---|:---|
| **For the year ended December 31, 2025** | **For the year ended December 31, 2025** |
| **Citation, Order, Violation or Action** | &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;**Bundick Sand Mine** |
| Section 104(a) *S&S* citations (#) |  |
| Section 104(b) orders (#) |  |
| Section 104(d) citations and orders (#) |  |
| Section 110(b)(2) violations (#) |  |
| Section 107(a) orders (#) |  |
| Proposed assessments under MSHA ($) <sup>(1)</sup> | $302 |
| Mining-related fatalities (#) |  |
| Notice of pattern of violations (yes/no) | No |
| Notice of potential pattern of violations (yes/no) | No |
| Pending legal actions (#) |  |

---

____________________________________________

<sup>(1)&nbsp;&nbsp;&nbsp;&nbsp;</sup>Amounts shown include assessments proposed by MSHA during the year ended December 31, 2025 on all citations and orders, including those citations and orders that are not required to be included within the above table. This number may differ from actual assessments paid to MSHA as the Company may contest any proposed penalty.

## Exhibit 99.1

January 10, 2025

**EXHIBIT 99.1**

**SM ENERGY COMPANY**

**Estimated**

**Future Reserves**

**Attributable to Certain**

**Leasehold Interests**

**SEC Parameters**

**As of**

**December 31, 2025**

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| | |
|:---|:---|
| /s/ MARSHA E. WELLMAN | /s/ ERIC A. SEPOLIO |
| Marsha E. Wellmann, P.E. | Eric A. Sepolio, P.E. |
| TBPELS License No. 116149 | TBPELS License No. 128738 |
| Managing Senior Vice President | Vice President |

---

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| |
|:---|
| ![mwseala.jpg](mwseala.jpg) |
| ![mwseala.jpg](mwseala.jpg) |

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| |
|:---|
| /s/ JAMES WELLS |
| James Wells |
| Senior Petroleum Engineer |

---

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;

---

| |
|:---|
| ![imagea.jpg](imagea.jpg) |
| ![imagea.jpg](imagea.jpg) |

---

**RYDER SCOTT COMPANY, L.P.**<br>TBPELS Firm Registration No. F-1580<br>

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

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![ryderscottheadera.jpg](ryderscottheadera.jpg)

January 9, 2026

Mr. Levi Briese

Corporate Engineering Manager

SM Energy Company

1700 Lincoln Street, Suite 3200<br>Denver, CO 80203

&nbsp;&nbsp;&nbsp;&nbsp;

Dear Mr. Briese,

At the request of SM Energy Company (SM Energy), Ryder Scott Company, L.P. (Ryder Scott) has conducted a reserves audit of the estimates of the proved reserves as of December 31, 2025 prepared by SM Energy's engineering and geological staff 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 reserves audit, completed on January 5, 2026 and presented herein, was prepared for public disclosure by SM Energy in filings made with the SEC in accordance with the disclosure requirements set forth in the SEC regulations. The estimated reserves shown herein represent SM Energy's estimated net reserves attributable to the leasehold interests in certain properties owned by SM Energy and the portion of those reserves reviewed by Ryder Scott, as of December 31, 2025. The properties reviewed by Ryder Scott incorporate SM Energy reserves determinations and are located in the states of Texas and Utah.

The properties reviewed by Ryder Scott account for a portion of SM Energy's total net proved liquid hydrocarbon and gas reserves as of December 31, 2025. Based on the estimates of total net proved reserves prepared by SM Energy, the reserves audit conducted by Ryder Scott addresses approximately 87 percent of the total proved net reserves of SM Energy on a barrel of oil equivalent (BOE) basis as of December 31, 2025.

As prescribed by the Society of Petroleum Engineers in Paragraph 2.2(f) of the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information (SPE auditing standards), a reserves audit is defined as "the process of reviewing certain of the pertinent facts interpreted and assumptions made that have resulted in an estimate of reserves and/or Reserves Information prepared by others and the rendering of an opinion about (1) the appropriateness of the methodologies employed; (2) the adequacy and quality of the data relied upon; (3) the depth and thoroughness of the reserves estimation process; (4) the classification of reserves appropriate to the relevant definitions used; and (5) the reasonableness of the estimated reserves quantities and/or Reserves Information." Reserves Information may consist of various estimates pertaining to the extent and value of petroleum properties.

Based on our review, including the data, technical processes and interpretations presented by SM Energy, it is our opinion that the overall procedures and methodologies utilized by SM Energy in

preparing their estimates of the proved reserves as of December 31, 2025 comply with the current SEC regulations and that the overall proved reserves for the reviewed properties as estimated by SM Energy are, in the aggregate, reasonable within the established audit tolerance guidelines of 10 percent as set forth in the SPE auditing standards.

SUITE 2800, 350 7TH AVENUE, S.W. CALGARY, ALBERTA T2P 3N9 TEL (403) 262-2799 <br> 555 17TH STREET, SUITE 985 DENVER, COLORADO 80202 TEL (303) 339-8110

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SM Energy Company

January 9, 2026

The estimated reserves presented in this report are related to hydrocarbon prices. SM Energy has informed us that in the preparation of their reserves and income projections, as of December 31, 2025, they used 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 may differ significantly from the estimated quantities presented in this report. The net reserves as estimated by SM Energy attributable to SM Energy's interest in properties that we reviewed and for those that we did not review are summarized as follows:

---

| | | | | |
|:---|:---|:---|:---|:---|
| **SEC PARAMETERS** | **SEC PARAMETERS** | **SEC PARAMETERS** | **SEC PARAMETERS** | **SEC PARAMETERS** |
| Estimated Net Reserves | Estimated Net Reserves | Estimated Net Reserves | Estimated Net Reserves | Estimated Net Reserves |
| Certain Leasehold Interests of | Certain Leasehold Interests of | Certain Leasehold Interests of | Certain Leasehold Interests of | Certain Leasehold Interests of |
| **SM Energy Company** | **SM Energy Company** | **SM Energy Company** | **SM Energy Company** | **SM Energy Company** |
| As of December 31, 2025 | 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>Audited by Ryder Scott</u>***<br>***<u>Net Reserves</u>*** |  |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Oil/Condensate – MBBLS | 149340 | 3736 | 108659 | 261734 |
| &nbsp;&nbsp;&nbsp;&nbsp;Plant Products – MBBLS | 62522 | 606 | 33876 | 97003 |
| &nbsp;&nbsp;&nbsp;&nbsp;Gas – MMCF | 979441 | 9210 | 371435 | 1360086 |
| &nbsp;&nbsp;&nbsp;&nbsp;MBOE  | 375102 | 5877 | 204440 | 585419 |
| <br>***<u>Not Audited by Ryder Scott</u>***<br>***<u>Net Reserves</u>*** |  |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Oil/Condensate – MBBLS | 10532 | 96 | 11577 | 22206 |
| &nbsp;&nbsp;&nbsp;&nbsp;Plant Products – MBBLS | 6374 | 798 | 18460 | 25633 |
| &nbsp;&nbsp;&nbsp;&nbsp;Gas – MMCF | 74675 | 6351 | 157384 | 238409 |
| &nbsp;&nbsp;&nbsp;&nbsp;MBOE  | 29353 | 1952 | 56268 | 87573 |
| <br>***<u>Total Net Reserves</u>*** |  |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Oil/Condensate – MBBLS | 159872 | 3832 | 120236 | 283940 |
| &nbsp;&nbsp;&nbsp;&nbsp;Plant Products – MBBLS | 68896 | 1404 | 52336 | 122636 |
| &nbsp;&nbsp;&nbsp;&nbsp;Gas – MMCF | 1054116 | 15561 | 528819 | 1598495 |
| &nbsp;&nbsp;&nbsp;&nbsp;MBOE  | 404455 | 7829 | 260708 | 672992 |

---

***Values may not sum to total due to rounding*.**

Liquid hydrocarbons are expressed in standard 42 U.S. gallon barrels and shown herein as thousands of barrels (MBBLS). 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

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

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SM Energy Company

January 9, 2026

gas reserves are located. The net reserves are also shown herein on an equivalent unit basis wherein natural gas is converted to oil equivalent using a factor of 6,000 cubic feet of natural gas per one barrel of oil equivalent. MBOE means thousand barrels of oil equivalent.

***Reserves Included in This Report***

In our opinion, the proved reserves presented in this report 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 proved 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 shut-in status category.

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 SM Energy's request, this report addresses only the proved reserves attributable to the properties reviewed 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. They may or may not be actually recovered.

***Audit Data, Methodology, Procedure and Assumptions***

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

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

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SM Energy Company

January 9, 2026

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 reserves prepared by SM Energy for the properties that we reviewed were estimated by performance methods, analogy, or a combination of methods. In general, the 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, which utilized extrapolations of historical production and pressure data available through November 2025 in those cases where such data were considered to be definitive. The data used in these analyses were furnished to Ryder Scott by SM Energy or obtained from public data sources and were considered sufficient for the purpose thereof. In certain cases, producing reserves were estimated analogy. This method was used where there were inadequate historical performance data to establish a definitive trend and where the use of production performance data as a basis for the estimates was considered to be inappropriate.

The reserves prepared by SM Energy attributable to the undeveloped status categories that we reviewed were estimated by analogy. The data utilized from the analogues were considered sufficient for the purpose thereof.

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SM Energy Company

January 9, 2026

To estimate economically producible proved oil and gas reserves, many factors and assumptions are considered 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 conducting this review.

As stated previously, 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. To confirm that the proved reserves reviewed by us meet the SEC requirements to be economically producible, we have reviewed certain primary economic data utilized by SM Energy relating to hydrocarbon prices and costs as noted herein.

The hydrocarbon prices furnished by SM Energy for the properties reviewed by us 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.

The initial SEC hydrocarbon benchmark prices in effect on December 31, 2025 for the properties reviewed by us 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 by SM Energy for the geographic area reviewed by us. In certain geographic areas, the price reference and benchmark prices may be defined by contractual arrangements.

The product prices that were actually used by SM Energy to determine the future gross revenue for each property reviewed by us reflect adjustments to the benchmark prices for gravity, quality, local conditions, and/or distance from market, referred to herein as "differentials." The differentials used by SM Energy 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 SM Energy.

The table below summarizes SM Energy's net volume weighted benchmark prices adjusted for differentials for the properties reviewed by us and referred to herein as SM Energy's "average realized prices." The average realized prices shown in the table below were determined from SM Energy's estimate of the total future gross revenue before production taxes for the properties reviewed by us and SM Energy's estimate of the total net reserves for the properties reviewed by us for the geographic area. The data shown in the table below is presented in accordance with SEC disclosure requirements for each of the geographic areas reviewed by us.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

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SM Energy Company

January 9, 2026

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| | | | | |
|:---|:---|:---|:---|:---|
| Geographic Area | Product | Price<br>Reference | Average<br>Benchmark<br>Prices | Average Realized<br>Prices |
| &nbsp;&nbsp;&nbsp;&nbsp;North America |  |  |  |  |
|  | Oil/Condensate | WTI Cushing | $65.34/BBL | $64.00/BBL |
| &nbsp;&nbsp;&nbsp;&nbsp;United States | NGLs | NGL Basket OPIS Mont Belvieu Non-TET<sup>(1)</sup> | $27.45/BBL | $21.72/BBL |
|  | Gas | Henry Hub | $3.387/MMBTU | $2.41/MCF |

---

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;*(1)&nbsp;&nbsp;&nbsp;&nbsp;Price reflects composition of ethane, butanes, propanes and natural gasoline.*

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

Accumulated gas production imbalances, if any, were not taken into account in the proved gas reserves estimates reviewed. The proved gas volumes presented herein do not include volumes of gas consumed in operations as reserves.

Operating costs furnished by SM Energy are based on the operating expense reports of SM Energy and include only those costs directly applicable to the leases or wells for the properties reviewed by us. The operating costs include a portion of general and administrative costs allocated directly to the leases and wells. For operated properties, the operating costs include an appropriate level of corporate general administrative and overhead costs. The operating costs for non-operated properties include the COPAS overhead costs that are allocated directly to the leases and wells under terms of operating agreements**.** The operating costs furnished by SM Energy 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 SM Energy. 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 furnished by SM Energy are based on authorizations for expenditure for the proposed work or actual costs for similar projects. The development costs furnished by SM Energy 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 SM Energy. The estimated net cost of abandonment after salvage was included by SM Energy for properties where abandonment costs net of salvage were material. SM Energy's estimates of the net abandonment costs were accepted without independent verification.

The estimated net cost of abandonment after salvage was included by SM Energy for properties where certain abandonment costs net of salvage were provided by SM Energy and for which they requested be included in our report. SM Energy's estimates of the net abandonment costs were accepted without independent verification. We have made no inspections to determine if any additional abandonment, decommissioning, and /or restoration costs may be necessary in addition to the costs provided by SM Energy and included herein.

The proved developed non-producing and undeveloped reserves for the properties reviewed by us have been incorporated herein in accordance with SM Energy's plans to develop these reserves as of December 31, 2025. The implementation of SM Energy's development plans as presented to us is subject to the approval process adopted by SM Energy's management. As the result of our inquiries

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

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SM Energy Company

January 9, 2026

during the course of our review, SM Energy has informed us that the development activities for the properties reviewed by us have been subjected to and received the internal approvals required by SM Energy'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 SM Energy. SM Energy has provided written documentation supporting their commitment to proceed with the development activities as presented to us**.** Additionally, SM Energy 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 SM Energy were held constant throughout the life of the properties.

SM Energy's forecasts of future production rates are based on historical performance from wells currently on production. 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 by SM Energy 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 SM Energy. Wells or locations that are not currently producing may start producing earlier or later than anticipated in SM Energy's 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.

SM Energy'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 review of the properties in which SM Energy 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 by SM Energy for potential liabilities to restore and clean up damages, if any, caused by past operating practices.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

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SM Energy Company

January 9, 2026

Certain technical personnel of SM Energy are responsible for the preparation of reserves estimates on new properties and for the preparation of revised estimates, when necessary, on old properties. These personnel assembled the necessary data and maintained the data and workpapers in an orderly manner. We consulted with these technical personnel and had access to their workpapers and supporting data in the course of our audit.

SM Energy 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 performing our audit of SM Energy's forecast of future proved production, we have relied upon data furnished by SM Energy 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, ad valorem and production taxes, recompletion and development costs, development plans, certain abandonment costs after salvage, 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 SM Energy. The data described herein were accepted as authentic and sufficient for determining the reserves unless, during the course of our examination, a matter of question came to our attention in which case the data were not accepted until all questions were satisfactorily resolved. We consider the factual data furnished to us by SM Energy to be appropriate and sufficient for the purpose of our review of SM Energy's estimates of reserves. In summary, we consider the assumptions, data, methods and analytical procedures used by SM Energy and as reviewed by us appropriate for the purpose hereof, and we have used all such methods and procedures that we consider necessary and appropriate under the circumstances to render the conclusions set forth herein.

***Audit Opinion***

Based on our review, including the data, technical processes and interpretations presented by SM Energy, it is our opinion that the overall procedures and methodologies utilized by SM Energy in preparing their estimates of the proved reserves as of December 31, 2025 comply with the current SEC regulations and that the overall proved reserves for the reviewed properties as estimated by SM Energy are, in the aggregate, reasonable within the established audit tolerance guidelines of 10 percent as set forth in the SPE auditing standards. Ryder Scott found the processes and controls used by SM Energy in their estimation of proved reserves to be effective and, in the aggregate, we found no bias in the utilization and analysis of data in estimates for these properties.

We were in reasonable agreement with SM Energy's estimates of proved reserves for the properties which we reviewed; although in certain cases there was more than an acceptable variance between SM Energy's estimates and our estimates due to a difference in interpretation of data or due to our having access to data which were not available to SM Energy when its reserves estimates were prepared. However notwithstanding, it is our opinion that on an aggregate basis the data presented herein for the properties that we reviewed fairly reflects the estimated net reserves owned by SM Energy.

***Other Properties***

Other properties, as used herein, are those properties of SM Energy which we did not review. The proved net reserves attributable to the other properties account for approximately 13 percent of the

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SM Energy Company

January 9, 2026

total proved net liquid hydrocarbon and gas reserves of SM Energy on a barrel of oil equivalent, BOE basis, based on estimates prepared by SM Energy as of December 31, 2025.

The same technical personnel of SM Energy were responsible for the preparation of the reserves estimates for the properties that we reviewed as well as for the properties not reviewed by Ryder Scott.

***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 SM Energy. 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 audit, 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 review 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 audit, 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 SM Energy.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

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SM Energy Company

January 9, 2026

SM Energy makes periodic filings on Form 10-K with the SEC under the 1934 Exchange Act. Furthermore, SM Energy has certain registration statements filed with the SEC under the 1933 Securities Act into which any subsequently filed Form 10-K is incorporated by reference. We have consented to the incorporation by reference in the registration statements on Form S-8 of SM Energy, of the references to our name, as well as to the references to our third-party report for SM Energy, which appears in the December 31, 2025 annual report on Form 10-K of SM Energy. Our written consent for such use is included as a separate exhibit to the filings made with the SEC by SM Energy.

We have provided SM Energy 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 SM Energy and the original signed report letter, the original signed report letter shall control and supersede the digital version.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

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SM Energy Company

January 9, 2026

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.

&nbsp;&nbsp;&nbsp;&nbsp; Very truly yours,

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| | |
|:---|:---|
| **RYDER SCOTT COMPANY, L.P.**<br>TBPELS Firm Registration No. F-1580 | |
| /s/ Marsha E. Wellmann | ![mwseala.jpg](mwseala.jpg) |
| Marsha E. Wellmann, P.E. | ![mwseala.jpg](mwseala.jpg) |
| TBPELS License No. 116149 | ![mwseala.jpg](mwseala.jpg) |
| Senior Vice President | ![mwseala.jpg](mwseala.jpg) |
| /s/ Eric A. Sepolio | ![imagea.jpg](imagea.jpg) |
| Eric A. Sepolio, P.E. | ![imagea.jpg](imagea.jpg) |
| TBPELS License No. 128738 | ![imagea.jpg](imagea.jpg) |
| Vice President&nbsp;&nbsp;&nbsp;&nbsp; | ![imagea.jpg](imagea.jpg) |
| /s/ James Wells |  |
| James Wells |  |
| Senior Petroleum Engineer |  |

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MEW-EAS-JW (DRO)/pl

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

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**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. Ms. Marsha E. Wellmann was the primary technical person responsible for overseeing the estimate of the reserves, future production and income prepared by Ryder Scott presented herein.

Ms. Wellmann, an employee of Ryder Scott Company L.P. (Ryder Scott) since 2012, is a Managing Senior Vice President responsible for coordinating and supervising staff and consulting engineers of the company in ongoing reservoir evaluation studies throughout North America and the Gulf of Mexico. Before joining Ryder Scott, Ms. Wellmann served in a number of engineering positions. For more information regarding Ms. Wellmann geographic and job specific experience, please refer to the Ryder Scott Company website at <u>www.ryderscott.com/Company/Employees</u>.

Ms. Wellmann earned a Bachelor of Science degree in Petroleum Engineering and a Business Foundations Certificate from The University of Texas at Austin in 2002 and is a registered Professional Engineer in the State of Texas. She is also a member of the Society of Petroleum Engineers.

In addition to gaining experience and competency through prior work experience, the Texas Board of Professional Engineers requires a minimum of fifteen hours of continuing education annually, including at least one hour in the area of professional ethics, which Ms. Wellmann fulfills. As part of her 2025 continuing education hours, Ms. Wellmann attended 32 hours of formalized training including various professional society presentations covering such topics as 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, Final Rule released January 14, 2009 in the Federal Register, the SPE/WPC/AAPG/SPEE Petroleum Resources Management System, reservoir engineering, geoscience and petroleum economics evaluation methods, procedures and software and ethics for consultants.

Based on her educational background, professional training and more than 15 years of practical experience in the estimation and evaluation of petroleum reserves, Ms. Wellmann 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.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

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**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 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. 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.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

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PETROLEUM RESERVES DEFINITIONS

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.* 

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

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PETROLEUM RESERVES DEFINITIONS

&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.* 

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;*(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.* 

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

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**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.* 

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

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PETROLEUM RESERVES STATUS DEFINITIONS AND GUIDELINES

*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;&nbsp;&nbsp;&nbsp;&nbsp;*(1)&nbsp;&nbsp;&nbsp;&nbsp;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;&nbsp;&nbsp;&nbsp;&nbsp;*(2)&nbsp;&nbsp;&nbsp;&nbsp;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;&nbsp;&nbsp;&nbsp;&nbsp;*(3)&nbsp;&nbsp;&nbsp;&nbsp;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)&nbsp;&nbsp;&nbsp;&nbsp;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.*

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS