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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-Q
☑ QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended March 31, 2024
OR
☐ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from ___________ to ___________
Commission File Number 001-31539
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

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 an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.

| Large accelerated filer | ☑ |  | Accelerated filer | ☐ |
| Non-accelerated filer | ☐ |  | Smaller reporting company | ☐ |
|  |  |  | Emerging growth company | ☐ |
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ☐ No ☑
Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date.
As of April 25, 2024, the registrant had 115,036,144 shares of common stock outstanding.

1

TABLE OF CONTENTS

Item |  |  | Page
| Cautionary Information about Forward-Looking Statements | 3
| Part I | 4
Item 1. | Financial Statements (unaudited) | 4
| Condensed Consolidated Balance Sheets March 3 1, 202 4, and December 31, 202 3 | 4
| Condensed Consolidated Statements of Operations Three M o n t h s Ended March 3 1, 202 4, and 202 3 | 5
| Condensed Consolidated Statements of Comprehensive Income Three Months Ended March 3 1, 202 4, and 202 3 | 6
| Condensed Consolidated Statements of Stockholders’ Equity Three Months Ended March 3 1, 202 4, and 202 3 | 7
| Condensed Consolidated Statements of Cash Flows Three Months Ended March 3 1, 202 4, and 202 3 | 8
| Notes to Condensed Consolidated Financial Statements | 9
Item 2. | Management’s Discussion and Analysis of Financial Condition and Results of Operations | 19
Item 3. | Quantitative and Qualitative Disclosures About Market Risk | 33
Item 4. | Controls and Procedures | 33
| Part II | 34
Item 1. | Legal Proceedings | 34
Item 1A. | Risk Factors | 34
Item 2. | Unregistered Sales of Equity Securities and Use of Proceeds | 34
Item 6. | Exhibits | 35
| Signatures | 36

2

Cautionary Information about Forward-Looking Statements
This Report on Form 10-Q (“Form 10-Q” 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,” “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 include statements about such matters as:
•business strategies and other plans and objectives for future operations, including plans for expansion and growth of operations or to defer capital investment, plans with respect to future dividend payments, debt redemptions or equity repurchases, capital markets activities, environmental, social, and governance (“ESG”) goals and initiatives, and our outlook on our future financial condition or results of operations;
•the amount and nature of future capital expenditures, the resilience of our assets to declining commodity prices, and the availability of liquidity and capital resources to fund capital expenditures;
•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 on each of these;
•armed conflict, political instability, or civil unrest in oil and gas producing regions and shipping channels, including instability in the Middle East, the wars between Russia and Ukraine and Israel and Hamas, and related potential effects on laws and regulations, or the imposition of economic or trade sanctions;
•any changes to the borrowing base or aggregate lender commitments under our Seventh Amended and Restated Credit Agreement (“Credit Agreement”);
•cash flows, liquidity, interest and related debt service expenses, changes in our effective tax rate, and our ability to repay debt in the future;
•our drilling and completion activities and other exploration and development activities, each of which could be affected by supply chain disruptions and inflation, our ability to obtain permits and governmental approvals, and plans by us, our joint development partners, and/or other third-party operators;
•possible or expected acquisitions and divestitures, including the possible divestiture or farm-out of, or farm-in or joint development of, certain properties;
•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;
•our expected future production volumes, identified drilling locations, as well as drilling prospects, inventories, projects and programs; and
•other similar matters, such as those discussed in Management’s Discussion and Analysis of Financial Condition and Results of Operations in Part I, Item 2 of this report.
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 the factors discussed in the Risk Factors section in Part I, Item 1A of our Annual Report on Form 10-K for the year ended December 31, 2023 (“2023 Form 10-K”).
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.
3

PART I. FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
SM ENERGY COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)
(in thousands, except share data)

| March 31, 2024 |  | December 31, 2023
ASSETS |  |  |
Current assets: |  |  |
Cash and cash equivalents | $ | 506,252 |  |  | $ | 616,164 |
Accounts receivable | 241,731 |  |  | 231,165 |
Derivative assets | 33,913 |  |  | 56,442 |
Prepaid expenses and other | 11,149 |  |  | 12,668 |
Total current assets | 793,045 |  |  | 916,439 |
Property and equipment (successful efforts method): |  |  |
Proved oil and gas properties | 11,756,523 |  |  | 11,477,358 |
Accumulated depletion, depreciation, and amortization | (6,994,005) |  |  | (6,830,253) |
Unproved oil and gas properties, net of valuation allowance of $34,934 and $35,362, respectively | 335,755 |  |  | 335,620 |
Wells in progress | 380,419 |  |  | 358,080 |
Other property and equipment, net of accumulated depreciation of $60,606 and $59,669, respectively | 34,905 |  |  | 35,615 |
Total property and equipment, net | 5,513,597 |  |  | 5,376,420 |
Noncurrent assets: |  |  |
Derivative assets | 7,198 |  |  | 8,672 |
Other noncurrent assets | 84,618 |  |  | 78,454 |
Total noncurrent assets | 91,816 |  |  | 87,126 |
Total assets | $ | 6,398,458 |  |  | $ | 6,379,985 |
LIABILITIES AND STOCKHOLDERS’ EQUITY |  |  |
Current liabilities: |  |  |
Accounts payable and accrued expenses | $ | 496,361 |  |  | $ | 611,598 |
Derivative liabilities | 24,108 |  |  | 6,789 |
Other current liabilities | 15,615 |  |  | 15,425 |
Total current liabilities | 536,084 |  |  | 633,812 |
Noncurrent liabilities: |  |  |
Revolving credit facility | — |  |  | — |
Senior Notes, net | 1,576,115 |  |  | 1,575,334 |
Asset retirement obligations | 124,085 |  |  | 118,774 |
Net deferred tax liabilities | 397,296 |  |  | 369,903 |
Derivative liabilities | 1,369 |  |  | 1,273 |
Other noncurrent liabilities | 65,258 |  |  | 65,039 |
Total noncurrent liabilities | 2,164,123 |  |  | 2,130,323 |
Commitments and contingencies (note 6) |  |  |
Stockholders’ equity: |  |  |
Common stock, $0.01 par value - authorized: 200,000,000 shares; issued and outstanding: 115,036,144 and 115,745,393 shares, respectively | 1,150 |  |  | 1,157 |
Additional paid-in capital | 1,536,929 |  |  | 1,565,021 |
Retained earnings | 2,162,771 |  |  | 2,052,279 |
Accumulated other comprehensive loss | (2,599) |  |  | (2,607) |
Total stockholders’ equity | 3,698,251 |  |  | 3,615,850 |
Total liabilities and stockholders’ equity | $ | 6,398,458 |  |  | $ | 6,379,985 |

The accompanying notes are an integral part of these condensed consolidated financial statements.
4

SM ENERGY COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (UNAUDITED)
(in thousands, except per share data)

|  |  | For the Three Months Ended March 31,
|  |  |  |  | 2024 |  | 2023
Operating revenues and other income: |  |  |  |  |  |  |
Oil, gas, and NGL production revenue |  |  |  |  | $ | 559,596 |  |  | $ | 570,778 |
Other operating income |  |  |  |  | 274 |  |  | 2,727 |
Total operating revenues and other income |  |  |  |  | 559,870 |  |  | 573,505 |
Operating expenses: |  |  |  |  |  |  |
Oil, gas, and NGL production expense |  |  |  |  | 137,375 |  |  | 142,348 |
Depletion, depreciation, amortization, and asset retirement obligation liability accretion |  |  |  |  | 166,188 |  |  | 154,189 |
Exploration |  |  |  |  | 18,581 |  |  | 18,428 |
General and administrative |  |  |  |  | 30,178 |  |  | 27,669 |
Net derivative (gain) loss |  |  |  |  | 28,145 |  |  | (51,329) |
Other operating expense, net |  |  |  |  | 1,008 |  |  | 10,153 |
Total operating expenses |  |  |  |  | 381,475 |  |  | 301,458 |
Income from operations |  |  |  |  | 178,395 |  |  | 272,047 |
Interest expense |  |  |  |  | (21,873) |  |  | (22,459) |
Interest income |  |  |  |  | 6,770 |  |  | 4,702 |
Other non-operating expense |  |  |  |  | (24) |  |  | (232) |
Income before income taxes |  |  |  |  | 163,268 |  |  | 254,058 |
Income tax expense |  |  |  |  | (32,069) |  |  | (55,506) |
Net income |  |  |  |  | $ | 131,199 |  |  | $ | 198,552 |
Basic weighted-average common shares outstanding |  |  |  |  | 115,642 |  |  | 121,671 |
Diluted weighted-average common shares outstanding |  |  |  |  | 116,456 |  |  | 122,294 |
Basic net income per common share |  |  |  |  | $ | 1.13 |  |  | $ | 1.63 |
Diluted net income per common share |  |  |  |  | $ | 1.13 |  |  | $ | 1.62 |
Net dividends declared per common share |  |  |  |  | $ | 0.18 |  |  | $ | 0.15 |

The accompanying notes are an integral part of these condensed consolidated financial statements.
5

SM ENERGY COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)
(in thousands)

|  |  | For the Three Months Ended March 31,
|  |  |  |  | 2024 |  | 2023
Net income |  |  |  |  | $ | 131,199 |  |  | $ | 198,552 |
Other comprehensive income, net of tax: |  |  |  |  |  |  |
Pension liability adjustment |  |  |  |  | 8 |  |  | 13 |
Total other comprehensive income, net of tax |  |  |  |  | 8 |  |  | 13 |
Total comprehensive income |  |  |  |  | $ | 131,207 |  |  | $ | 198,565 |

The accompanying notes are an integral part of these condensed consolidated financial statements.
6

SM ENERGY COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY (UNAUDITED)
(in thousands, except share data and dividends per share)

|  |  | Additional Paid-in Capital |  |  |  | Accumulated Other Comprehensive Loss |  | Total Stockholders’ Equity
| Common Stock |  |  | Retained Earnings |  |
| Shares |  | Amount |  |  |  |
Balances, December 31, 2023 | 115,745,393 |  |  | $ | 1,157 |  |  | $ | 1,565,021 |  |  | $ | 2,052,279 |  |  | $ | (2,607) |  |  | $ | 3,615,850 |
Net income | — |  |  | — |  |  | — |  |  | 131,199 |  |  | — |  |  | 131,199 |
Other comprehensive income | — |  |  | — |  |  | — |  |  | — |  |  | 8 |  |  | 8 |
Net cash dividends declared, $0.18 per share | — |  |  | — |  |  | — |  |  | (20,707) |  |  | — |  |  | (20,707) |
Issuance of common stock upon vesting of RSUs, net of shares used for tax withholdings | 1,147 |  |  | — |  |  | (22) |  |  | — |  |  | — |  |  | (22) |
Stock-based compensation expense | 1,839 |  |  | — |  |  | 5,018 |  |  | — |  |  | — |  |  | 5,018 |
Purchase of shares under Stock Repurchase Program | (712,235) |  |  | (7) |  |  | (33,088) |  |  | — |  |  | — |  |  | (33,095) |
Balances, March 31, 2024 | 115,036,144 |  |  | $ | 1,150 |  |  | $ | 1,536,929 |  |  | $ | 2,162,771 |  |  | $ | (2,599) |  |  | $ | 3,698,251 |

|  |  | Additional Paid-in Capital |  |  |  | Accumulated Other Comprehensive Loss |  | Total Stockholders’ Equity
| Common Stock |  |  | Retained Earnings |  |
| Shares |  | Amount |  |  |  |
Balances, December 31, 2022 | 121,931,676 |  |  | $ | 1,219 |  |  | $ | 1,779,703 |  |  | $ | 1,308,558 |  |  | $ | (4,022) |  |  | $ | 3,085,458 |
Net income | — |  |  | — |  |  | — |  |  | 198,552 |  |  | — |  |  | 198,552 |
Other comprehensive income | — |  |  | — |  |  | — |  |  | — |  |  | 13 |  |  | 13 |
Net cash dividends declared, $0.15 per share | — |  |  | — |  |  | — |  |  | (18,078) |  |  | — |  |  | (18,078) |
Stock-based compensation expense | — |  |  | — |  |  | 4,318 |  |  | — |  |  | — |  |  | 4,318 |
Purchase of shares under Stock Repurchase Program | (1,413,758) |  |  | (14) |  |  | (40,454) |  |  | — |  |  | — |  |  | (40,468) |
Balances, March 31, 2023 | 120,517,918 |  |  | $ | 1,205 |  |  | $ | 1,743,567 |  |  | $ | 1,489,032 |  |  | $ | (4,009) |  |  | $ | 3,229,795 |

The accompanying notes are an integral part of these condensed consolidated financial statements.
7

SM ENERGY COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)
(in thousands)

| For the Three Months Ended March 31,
| 2024 |  | 2023
Cash flows from operating activities: |  |  |
Net income | $ | 131,199 |  |  | $ | 198,552 |
Adjustments to reconcile net income to net cash provided by operating activities: |  |
Depletion, depreciation, amortization, and asset retirement obligation liability accretion | 166,188 |  |  | 154,189 |
Stock-based compensation expense | 5,018 |  |  | 4,318 |
Net derivative (gain) loss | 28,145 |  |  | (51,329) |
Net derivative settlement gain | 13,274 |  |  | 5,076 |
Amortization of deferred financing costs | 1,371 |  |  | 1,371 |
Deferred income taxes | 27,391 |  |  | 49,968 |
Other, net | 1,102 |  |  | (4,295) |
Net change in working capital | (97,688) |  |  | (26,216) |
Net cash provided by operating activities | 276,000 |  |  | 331,634 |
Cash flows from investing activities: |  |  |
Capital expenditures | (332,365) |  |  | (240,712) |
Other, net | 77 |  |  | 307 |
Net cash used in investing activities | (332,288) |  |  | (240,405) |
Cash flows from financing activities: |  |  |
Repurchase of common stock | (32,768) |  |  | (40,068) |
Dividends paid | (20,834) |  |  | (18,290) |
Net share settlement from issuance of stock awards | (22) |  |  | — |
Net cash used in financing activities | (53,624) |  |  | (58,358) |
Net change in cash, cash equivalents, and restricted cash | (109,912) |  |  | 32,871 |
Cash, cash equivalents, and restricted cash at beginning of period | 616,164 |  |  | 444,998 |
Cash, cash equivalents, and restricted cash at end of period | $ | 506,252 |  |  | $ | 477,869 |
Supplemental schedule of additional cash flow information: |  |
Operating activities: |  |  |
Cash paid for interest, net of capitalized interest | $ | (32,986) |  |  | $ | (33,882) |
Net cash refunded (paid) for income taxes | $ | 3,292 |  |  | $ | (50) |
Investing activities: |  |  |
Changes in capital expenditure accruals | $ | (26,569) |  |  | $ | 66,873 |

The accompanying notes are an integral part of these condensed consolidated financial statements.
8

SM ENERGY COMPANY AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)
Note 1 - Summary of Significant Accounting Policies
Description of Operations
SM Energy Company, together with its consolidated subsidiaries (“SM Energy” or the “Company”), is an independent energy company engaged in the acquisition, exploration, development, and production of oil, gas, and NGLs in the state of Texas.
Basis of Presentation
The accompanying unaudited condensed consolidated financial statements include the accounts of the Company and have been prepared in accordance with accounting principles generally accepted in the United States (“GAAP”) for interim financial information, the instructions to Quarterly Report on Form 10-Q, and Regulation S-X. These financial statements do not include all information and notes required by GAAP for annual financial statements. However, except as disclosed herein, there has been no material change in the information disclosed in the notes to the consolidated financial statements included in the 2023 Form 10-K. In the opinion of management, all adjustments, consisting of normal recurring adjustments considered necessary for a fair presentation of interim financial information, have been included. Operating results for the periods presented are not necessarily indicative of expected results for the full year. In connection with the preparation of the Company’s unaudited condensed consolidated financial statements, the Company evaluated events subsequent to the balance sheet date of March 31, 2024, and through the filing of this report. Additionally, certain prior period amounts have been reclassified to conform to current period presentation in the accompanying unaudited condensed consolidated financial statements.
Significant Accounting Policies
The significant accounting policies followed by the Company are set forth in Note 1 - Summary of Significant Accounting Policies in the 2023 Form 10-K and are supplemented by the notes to the unaudited condensed consolidated financial statements included in this report. These unaudited condensed consolidated financial statements should be read in conjunction with the 2023 Form 10-K.
Recently Issued Accounting Guidance
Accounting Standards Updates. In November 2023, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2023-07, Segment Reporting (Topic 280): Improvements to Reportable Segment Disclosures (“ASU 2023-07”). ASU 2023-07 was issued to improve the disclosures about a public entity’s reportable segments and to provide additional, more detailed information about a reportable segment’s expenses. ASU 2023-07 is effective for fiscal years beginning after December 15, 2023, and interim periods within fiscal years beginning after December 15, 2024, with early adoption permitted. The guidance is to be applied on a retrospective basis to all prior periods presented in the financial statements. The Company is within the scope of this ASU and expects to adopt ASU 2023-07 and related guidance on December 31, 2024. Adoption of ASU 2023-07 is not expected to have a material impact on the Company’s consolidated financial statements or related disclosures.
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 is 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 is within the scope of this ASU and expects to adopt ASU 2023-09 on January 1, 2025, on a prospective basis. Adoption of ASU 2023-09 is not expected to have a material impact on the Company’s consolidated financial statements or related disclosures.
SEC Final Rule to Enhance and Standardize Climate-Related Disclosures. On March 6, 2024, the Securities and Exchange Commission (“SEC”) adopted final rules to require registrants to disclose certain climate-related information in registration statements and annual reports. On April 4, 2024, the SEC issued an order staying the final rules pending completion of judicial review of the petitions challenging the final rules. The order does not amend the compliance dates contemplated by the final rules, which are applicable to the Company for fiscal years beginning with the Company’s annual report on Form 10-K for the fiscal year ended December 31, 2025. The Company is currently evaluating the potential impact of the final rules on its financial statements and related disclosures.
As of March 31, 2024, 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 unaudited condensed consolidated financial statements and related disclosures.
9

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 and South Texas assets. Oil, gas, and NGL production revenue presented within the accompanying unaudited condensed consolidated statements of operations (“accompanying statements of operations”) reflects revenue generated from contracts with customers.
The table below presents oil, gas, and NGL production revenue by product type for each of the Company’s operating areas:

| Midland Basin |  | South Texas |  | Total
| Three Months Ended March 31, |  | Three Months Ended March 31, |  | Three Months Ended March 31,
| 2024 |  | 2023 |  | 2024 |  | 2023 |  | 2024 |  | 2023
| (in thousands)
Oil production revenue | $ | 332,191 |  | $ | 320,135 |  | $ | 108,703 |  | $ | 100,703 |  | $ | 440,894 |  | $ | 420,838
Gas production revenue | 40,538 |  | 49,789 |  | 27,306 |  | 43,942 |  | 67,844 |  | 93,731
NGL production revenue | 84 |  | 177 |  | 50,774 |  | 56,032 |  | 50,858 |  | 56,209
Total | $ | 372,813 |  | $ | 370,101 |  | $ | 186,783 |  | $ | 200,677 |  | $ | 559,596 |  | $ | 570,778
Relative percentage | 67 | % |  | 65 | % |  | 33 | % |  | 35 | % |  | 100 | % |  | 100 | %

The Company recognizes oil, gas, and NGL production revenue 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 (“fees and other deductions”) within the accompanying statements of operations. Fees 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 at or near the wellhead, sales are based on a wellhead 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. Estimated revenue due to the Company is recorded within the accounts receivable line item on the accompanying unaudited condensed consolidated balance sheets (“accompanying balance sheets”) until payment is received. The accounts receivable balances from contracts with customers within the accompanying balance sheets as of March 31, 2024, and December 31, 2023, were $184.2 million and $175.3 million, respectively. To estimate accounts receivable from contracts with customers, the Company uses knowledge of its properties, historical performance, contractual arrangements, index pricing, quality and transportation differentials, and other factors as the basis for these estimates. Differences between estimates and actual amounts received for product sales are recorded in the month that payment is received from the purchaser. The time period between production and satisfaction of performance obligations is generally less than one day, therefore there are no material unsatisfied or partially unsatisfied performance obligations at the end of the reporting period.
Note 3 - Equity
Stock Repurchase Program
The Company’s current stock repurchase program authorizes the Company to repurchase up to $500.0 million in aggregate value of its common stock through December 31, 2024 (“Stock Repurchase Program”). 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. Please refer to Note 3 - Equity in the 2023 Form 10-K for additional information regarding the Company’s Stock Repurchase Program.
10

The following table presents activity under the Company’s Stock Repurchase Program during the three months ended March 31, 2024, and 2023:

|  |  | For the Three Months Ended March 31,
|  |  |  |  | 2024 |  | 2023
|  |  |  |  | (in thousands, except per share data)
Shares of common stock repurchased (1) |  |  |  |  | 712 |  |  | 1,414 |
Weighted-average price per share (2) |  |  |  |  | $ | 45.99 |  |  | $ | 28.32 |
Cost of shares of common stock repurchased (2) (3) |  |  |  |  | $ | 32,753 |  |  | $ | 40,040 |

____________________________________________
(1) All repurchased shares of the Company’s common stock were retired upon repurchase.
(2) Amounts exclude excise taxes, commissions, and fees.
(3) Amounts may not calculate due to rounding.
Since the inception of the Stock Repurchase Program in 2022, the Company has repurchased and subsequently retired approximately 9.0 million shares of the Company’s outstanding common stock at a cost of $317.9 million, excluding excise taxes, commissions, and fees. As of March 31, 2024, $182.1 million remained available for repurchases of the Company’s outstanding common stock through December 31, 2024, under the Stock Repurchase Program.
Note 4 - Income Taxes
The provision for income taxes consisted of the following:

|  |  | For the Three Months Ended March 31,
|  |  |  |  | 2024 |  | 2023
|  |  |  |  | (in thousands)
Current portion of income tax expense: |  |  |  |  |  |  |
Federal |  |  |  |  | $ | (4,254) |  | $ | (4,998)
State |  |  |  |  | (424) |  | (540)
Deferred portion of income tax expense |  |  |  |  | (27,391) |  | (49,968)
Income tax expense |  |  |  |  | $ | (32,069) |  | $ | (55,506)
Effective tax rate |  |  |  |  | 19.6 | % |  | 21.8 | %

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 tax credits, state income taxes, changes in valuation allowances, 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 effect of an enacted tax rate change, in the period of enactment, on the Company’s net deferred tax asset and liability balances. The quarterly effective tax rate and the resulting income tax expense or benefit can also be affected by the proportional effects of forecast net income or loss and the correlative effect on the valuation allowance for each of the periods presented in the table above.
The Company completed a multi-year research and development (“R&D”) credit study in 2023, which resulted in a favorable adjustment to the Company’s effective tax rate in both the third and fourth quarters of 2023 and a reduction of the Company’s tax obligation. Favorable adjustments to the Company’s effective tax rate are expected to continue in 2024 resulting from qualifying R&D activity and anticipated credit claims.
The Company complies with authoritative accounting guidance regarding uncertain tax positions. The entire amount of unrecognized tax benefit reported by the Company would affect its effective tax rate if recognized. The Company does not expect a significant change to the recorded unrecognized tax benefits in 2024, except for any potential changes related to the Company’s 2024 R&D credit claims.
For all years before 2020, the Company is generally no longer subject to United States federal or state income tax examinations by tax authorities.
11

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 March 31, 2024, the borrowing base and aggregate lender commitments under the Credit Agreement were $2.5 billion and $1.25 billion, respectively. Subsequent to March 31, 2024, the semi-annual borrowing base redetermination was completed, which reaffirmed both the Company’s borrowing base and aggregate lender commitments at existing amounts. The next scheduled borrowing base redetermination date is October 1, 2024. The Credit Agreement is scheduled to mature on the earlier of (a) August 2, 2027 (“Stated Maturity Date”), or (b) 91 days prior to the maturity date of any of the Company’s outstanding Senior Notes, as defined below, to the extent that, on or before such date, the respective Senior Notes have not been repaid, exchanged, repurchased, refinanced, or otherwise redeemed in full, and, if refinanced or exchanged, with a scheduled maturity date that is not earlier than at least 180 days after the Stated Maturity Date.
Interest and commitment fees associated with the revolving credit facility are accrued based on a borrowing base utilization grid set forth in the Credit Agreement, as presented in Note 5 - Long-Term Debt in the 2023 Form 10-K. At the Company’s election, borrowings under the Credit Agreement may be in the form of Secured Overnight Financing Rate (“SOFR”), Alternate Base Rate (“ABR”), or Swingline loans. SOFR loans accrue interest at SOFR plus the applicable margin from the utilization grid, and ABR 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 lender commitment amount at rates from the utilization grid.
The following table presents the outstanding balance, total amount of letters of credit outstanding, and available borrowing capacity under the Credit Agreement as of April 25, 2024, March 31, 2024, and December 31, 2023:

| As of April 25, 2024 |  | As of March 31, 2024 |  | As of December 31, 2023
| (in thousands)
Revolving credit facility (1) | $ | — |  |  | $ | — |  |  | $ | — |
Letters of credit (2) | 2,500 |  |  | 2,500 |  |  | 2,500 |
Available borrowing capacity | 1,247,500 |  |  | 1,247,500 |  |  | 1,247,500 |
Total aggregate lender commitment amount | $ | 1,250,000 |  |  | $ | 1,250,000 |  |  | $ | 1,250,000 |

____________________________________________
(1) 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 $7.9 million and $8.5 million as of March 31, 2024, and December 31, 2023, respectively. These costs are being amortized over the term of the revolving credit facility on a straight-line basis.
(2) 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 March 31, 2024, and December 31, 2023, consisted of the following (collectively referred to as “Senior Notes”):

| As of March 31, 2024 |  | As of December 31, 2023
| Principal Amount |  | Unamortized Deferred Financing Costs |  | Principal Amount, Net |  | Principal Amount |  | Unamortized Deferred Financing Costs |  | Principal Amount, Net
| (in thousands)
5.625% Senior Notes due 2025 | $ | 349,118 |  |  | $ | 738 |  |  | $ | 348,380 |  |  | $ | 349,118 |  |  | $ | 896 |  |  | $ | 348,222 |
6.75% Senior Notes due 2026 | 419,235 |  |  | 1,693 |  |  | 417,542 |  |  | 419,235 |  |  | 1,868 |  | 417,367 |
6.625% Senior Notes due 2027 | 416,791 |  |  | 2,201 |  |  | 414,590 |  |  | 416,791 |  |  | 2,395 |  | 414,396 |
6.5% Senior Notes due 2028 | 400,000 |  |  | 4,397 |  |  | 395,603 |  |  | 400,000 |  |  | 4,651 |  | 395,349 |
Total | $ | 1,585,144 |  |  | $ | 9,029 |  |  | $ | 1,576,115 |  |  | $ | 1,585,144 |  |  | $ | 9,810 |  |  | $ | 1,575,334 |

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.
12

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 Company was in compliance with all financial and non-financial covenants as of March 31, 2024, and through the filing of this report.
Capitalized Interest
Capitalized interest costs for the three months ended March 31, 2024, and 2023, totaled $6.1 million and $5.5 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.
Note 6 - Commitments and Contingencies
Commitments
Other than those items discussed below, there have been no changes in commitments through the filing of this report that differ materially from those disclosed in the 2023 Form 10-K.
Drilling Rig Service Contracts. During the three months ended March 31, 2024, the Company entered into new drilling rig contracts. As of March 31, 2024, the Company’s drilling rig commitments totaled $31.3 million under contract terms extending through the first quarter of 2025. If all of the drilling rig contracts were terminated as of March 31, 2024, the Company would avoid a portion of the contractual service commitments; however, the Company would be required to pay $19.6 million in early termination fees. No early termination penalties or standby fees were incurred by the Company during the three months ended March 31, 2024, and the Company does not expect to incur material penalties with regard to its drilling rig contracts during the remainder of 2024.
Drilling and Completion Commitments. During the three months ended March 31, 2024, the Company entered into an agreement that includes minimum drilling and completion footage requirements on certain existing leases. If these minimum requirements are not satisfied by March 31, 2026, the Company will be required to pay liquidated damages based on the difference between the actual footage drilled and completed and the minimum requirements. As of March 31, 2024, the liquidated damages could range from zero to a maximum of $96.0 million, with the maximum exposure assuming no additional development activity occurs prior to March 31, 2026. As of the filing of this report, the Company expects to meet its obligations under this agreement.
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 March 31, 2024, the Company had basis swap contracts with fixed price differentials between:
•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;
13

•NYMEX WTI and Argus WTI Houston Magellan East Houston Terminal (“WTI Houston MEH”) for a portion of its South Texas oil production with sales contracts that settle at WTI Houston MEH prices;
•NYMEX Henry Hub (“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; and
•NYMEX HH and Inside FERC West Texas (“IF Waha”) for a portion of its Midland Basin gas production with sales contracts that settle at IF Waha 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.
14

As of March 31, 2024, the Company had commodity derivative contracts outstanding through the fourth quarter of 2026 as summarized in the table below:

|  | Contract Period |  |  |  |  |  |
|  | Second Quarter 2024 |  | Third Quarter 2024 |  | Fourth Quarter 2024 |  | 2025 |  | 2026 |  |  |  |  |  |
Oil Derivatives (volumes in MBbl and prices in $ per Bbl): |  |  |  |
Swaps |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
NYMEX WTI Volumes |  | — |  |  | — |  |  | 780 |  |  | 323 |  |  | — |  |  |  |  |  |  |
Weighted-Average Contract Price |  | $ | — |  |  | $ | — |  |  | $ | 73.24 |  |  | $ | 75.00 |  |  | $ | — |  |  |  |  |  |  |
Collars |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
NYMEX WTI Volumes |  | 1,846 |  |  | 2,003 |  |  | 900 |  |  | 323 |  |  | — |  |  |  |  |  |  |
Weighted-Average Floor Price |  | $ | 67.46 |  |  | $ | 68.27 |  |  | $ | 69.85 |  |  | $ | 68.00 |  |  | $ | — |  |  |  |  |  |  |
Weighted-Average Ceiling Price |  | $ | 85.53 |  |  | $ | 83.10 |  |  | $ | 78.53 |  |  | $ | 79.93 |  |  | $ | — |  |  |  |  |  |  |
Basis Swaps |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
WTI Midland-NYMEX WTI Volumes |  | 1,193 |  |  | 1,235 |  |  | 1,230 |  |  | 2,748 |  |  | — |  |  |  |  |  |  |
Weighted-Average Contract Price |  | $ | 1.21 |  |  | $ | 1.21 |  |  | $ | 1.21 |  |  | $ | 1.15 |  |  | $ | — |  |  |  |  |  |  |
WTI Houston MEH-NYMEX WTI Volumes |  | 293 |  |  | 332 |  |  | 309 |  |  | 1,413 |  |  | 816 |  |  |  |  |  |  |
Weighted-Average Contract Price |  | $ | 1.82 |  |  | $ | 1.82 |  |  | $ | 1.82 |  |  | $ | 1.90 |  |  | $ | 2.10 |  |  |  |  |  |  |
Roll Differential Swaps |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
NYMEX WTI Volumes |  | 1,792 |  |  | 1,964 |  |  | 1,877 |  |  | — |  |  | — |  |  |  |  |  |  |
Weighted-Average Contract Price |  | $ | 0.57 |  |  | $ | 0.57 |  |  | $ | 0.57 |  |  | $ | — |  |  | $ | — |  |  |  |  |  |  |
Gas Derivatives (volumes in BBtu and prices in $ per MMBtu): |  |  |  |
Swaps |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
NYMEX HH Volumes |  | 4,186 |  |  | 2,923 |  |  | 1,569 |  |  | 5,891 |  |  | — |  |  |  |  |  |  |
Weighted-Average Contract Price |  | $ | 3.17 |  |  | $ | 3.18 |  |  | $ | 3.03 |  |  | $ | 4.20 |  |  | $ | — |  |  |  |  |  |  |
Collars |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
NYMEX HH Volumes |  | 4,432 |  |  | 4,612 |  |  | 7,328 |  |  | 25,434 |  |  | — |  |  |  |  |  |  |
Weighted-Average Floor Price |  | $ | 3.69 |  |  | $ | 3.68 |  |  | $ | 3.38 |  |  | $ | 3.23 |  |  | $ | — |  |  |  |  |  |  |
Weighted-Average Ceiling Price |  | $ | 4.00 |  |  | $ | 4.21 |  |  | $ | 4.97 |  |  | $ | 4.67 |  |  | $ | — |  |  |  |  |  |  |
Basis Swaps |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
IF Waha-NYMEX HH Volumes |  | 5,285 |  |  | 5,344 |  |  | 5,240 |  |  | 20,501 |  |  | — |  |  |  |  |  |  |
Weighted-Average Contract Price |  | $ | (1.09) |  |  | $ | (0.99) |  |  | $ | (0.73) |  |  | $ | (0.66) |  |  | $ | — |  |  |  |  |  |  |
IF HSC-NYMEX HH Volumes |  | 3,310 |  |  | 3,426 |  |  | 5,750 |  |  | 946 |  |  | — |  |  |  |  |  |  |
Weighted-Average Contract Price |  | $ | (0.34) |  |  | $ | (0.30) |  |  | $ | (0.38) |  |  | $ | 0.0025 |  |  | $ | — |  |  |  |  |  |  |
NGL Derivatives (volumes in MBbl and prices in $ per Bbl): |  |  |  |
Swaps |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
OPIS Propane Mont Belvieu Non-TET Volumes |  | 387 |  |  | 404 |  |  | 434 |  |  | 396 |  |  | — |  |  |  |  |  |  |
Weighted-Average Contract Price |  | $ | 31.90 |  |  | $ | 31.87 |  |  | $ | 31.85 |  |  | $ | 32.86 |  |  | $ | — |  |  |  |  |  |  |
OPIS Normal Butane Mont Belvieu Non-TET Volumes |  | 44 |  |  | 46 |  |  | 49 |  |  | 45 |  |  | — |  |  |  |  |  |  |
Weighted-Average Contract Price |  | $ | 39.48 |  |  | $ | 39.48 |  |  | $ | 39.48 |  |  | $ | 39.48 |  |  | $ | — |  |  |  |  |  |  |
OPIS Isobutane Mont Belvieu Non-TET Volumes |  | 24 |  |  | 25 |  |  | 28 |  |  | 25 |  |  | — |  |  |  |  |  |  |
Weighted-Average Contract Price |  | $ | 41.58 |  |  | $ | 41.58 |  |  | $ | 41.58 |  |  | $ | 41.58 |  |  | $ | — |  |  |  |  |  |  |

15

Commodity Derivative Contracts Entered Into Subsequent to March 31, 2024
Subsequent to March 31, 2024, and through the filing of this report, the Company entered into the following commodity derivative contracts:
•NYMEX WTI collar contracts for the fourth quarter of 2024 through the second quarter of 2025 for a total of 1.0 MMBbl of oil production at a weighted-average floor price of $71.77 per Bbl and a weighted-average ceiling price of $82.74 per Bbl;
•NYMEX WTI Roll Differential swap contract for the second through fourth quarters of 2024 for a total of 1.8 MMBbl of oil production at a weighted-average contract price of $1.02 per Bbl;
•NYMEX HH collar contracts for 2026 for a total of 13,438 BBtu of gas production at a weighted-average floor price of $3.25 per MMBtu and a weighted-average ceiling price of $4.90 per MMBtu; and
•IF Waha swap contracts for the first, third, and fourth quarters of 2026 for a total of 1,548 BBtu of gas production at a weighted-average contract price of $3.26 per MMBtu.
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 commodity derivative contracts at March 31, 2024, and December 31, 2023, was a net asset of $15.6 million and $57.1 million, respectively.
The following table details the fair value of commodity derivative contracts recorded in the accompanying balance sheets, by category:

| As of March 31, 2024 |  | As of December 31, 2023
| (in thousands)
Derivative assets: |  |  |
Current assets | $ | 33,913 |  |  | $ | 56,442 |
Noncurrent assets | 7,198 |  |  | 8,672 |
Total derivative assets | $ | 41,111 |  |  | $ | 65,114 |
Derivative liabilities: |  |  |
Current liabilities | $ | 24,108 |  |  | $ | 6,789 |
Noncurrent liabilities | 1,369 |  |  | 1,273 |
Total derivative liabilities | $ | 25,477 |  |  | $ | 8,062 |

Offsetting of Derivative Assets and Liabilities
As of March 31, 2024, and December 31, 2023, 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:

| Derivative Assets as of |  | Derivative Liabilities as of
| March 31, 2024 |  | December 31, 2023 |  | March 31, 2024 |  | December 31, 2023
| (in thousands)
Gross amounts presented in the accompanying balance sheets | $ | 41,111 |  |  | $ | 65,114 |  |  | $ | (25,477) |  |  | $ | (8,062) |
Amounts not offset in the accompanying balance sheets | (21,519) |  |  | (7,362) |  |  | 21,519 |  |  | 7,362 |
Net amounts | $ | 19,592 |  |  | $ | 57,752 |  |  | $ | (3,958) |  |  | $ | (700) |

16

The following table summarizes the commodity components of the net derivative settlement gain, and the net derivative (gain) loss line items presented within the accompanying unaudited condensed consolidated statements of cash flows (“accompanying statements of cash flows”) and the accompanying statements of operations, respectively:

|  |  | For the Three Months Ended March 31,
|  |  |  |  | 2024 |  | 2023
|  |  |  |  | (in thousands)
Net derivative settlement (gain) loss: |  |  |  |  |  |  |
Oil contracts |  |  |  |  | $ | (2,525) |  |  | $ | 6,226 |
Gas contracts |  |  |  |  | (12,220) |  |  | (11,302) |
NGL contracts |  |  |  |  | 1,471 |  |  | — |
Total net derivative settlement gain |  |  |  |  | $ | (13,274) |  |  | $ | (5,076) |
Net derivative (gain) loss: |  |  |  |  |  |  |
Oil contracts |  |  |  |  | $ | 37,099 |  |  | $ | (29,167) |
Gas contracts |  |  |  |  | (14,828) |  |  | (20,778) |
NGL contracts |  |  |  |  | 5,874 |  |  | (1,384) |
Total net derivative (gain) loss |  |  |  |  | $ | 28,145 |  |  | $ | (51,329) |

Credit Related Contingent Features
As of March 31, 2024, 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:
•Level 1 – quoted prices in active markets for identical assets or liabilities
•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
•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 in the accompanying balance sheets and where they are classified within the fair value hierarchy:

| As of March 31, 2024 |  | As of December 31, 2023
| Level 1 |  | Level 2 |  | Level 3 |  | Level 1 |  | Level 2 |  | Level 3
| (in thousands)
Assets: |  |  |  |  |  |  |  |  |  |  |
Derivatives (1) | $ | — |  |  | $ | 41,111 |  |  | $ | — |  |  | $ | — |  |  | $ | 65,114 |  |  | $ | — |
Liabilities: |  |  |  |  |  |  |  |  |  |  |
Derivatives (1) | $ | — |  |  | $ | 25,477 |  |  | $ | — |  |  | $ | — |  |  | $ | 8,062 |  |  | $ | — |

__________________________________________
(1) This represents a financial asset or liability that is measured at fair value on a recurring basis.
17

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.
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. Please 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 March 31, 2024, or December 31, 2023, as they were recorded at carrying value, net of any unamortized deferred financing costs. Please refer to Note 5 - Long-Term Debt for additional information.

| As of March 31, 2024 |  | As of December 31, 2023
| Principal Amount |  | Fair Value |  | Principal Amount |  | Fair Value
| (in thousands)
5.625% Senior Notes due 2025 | $ | 349,118 |  |  | $ | 348,025 |  |  | $ | 349,118 |  |  | $ | 348,189 |
6.75% Senior Notes due 2026 | $ | 419,235 |  |  | $ | 419,491 |  |  | $ | 419,235 |  |  | $ | 420,660 |
6.625% Senior Notes due 2027 | $ | 416,791 |  |  | $ | 417,458 |  |  | $ | 416,791 |  |  | $ | 416,549 |
6.5% Senior Notes due 2028 | $ | 400,000 |  |  | $ | 402,644 |  |  | $ | 400,000 |  |  | $ | 401,372 |

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. Potentially dilutive securities for this calculation consist primarily of non-vested restricted stock units (“RSU” or “RSUs”) and contingent performance share units (“PSU” or “PSUs”), which were measured using the treasury stock method. Please refer to Note 9 - Earnings Per Share and Note 10 - Compensation Plans in the 2023 Form 10-K for additional detail on these potentially dilutive securities.
The following table sets forth the calculations of basic and diluted net income per common share:

| For the Three Months Ended March 31, |  |
| 2024 |  | 2023 |  |  |  |
| (in thousands, except per share data)
Net income | $ | 131,199 |  |  | $ | 198,552 |  |  |  |  |
Basic weighted-average common shares outstanding | 115,642 |  | 121,671 |  |  |  |
Dilutive effect of non-vested RSUs, contingent PSUs, and other | 814 |  | 623 |  |  |  |
Diluted weighted-average common shares outstanding | 116,456 |  | 122,294 |  |  |  |
Basic net income per common share | $ | 1.13 |  |  | $ | 1.63 |  |  |  |  |
Diluted net income per common share | $ | 1.13 |  |  | $ | 1.62 |  |  |  |  |

18

ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following discussion includes forward-looking statements. Please refer to the Cautionary Information about Forward-Looking Statements section of this report for important information about these types of statements. Throughout the following discussion, we explain changes between the three months ended March 31, 2024, and the three months ended December 31, 2023 (“sequential quarterly” or “sequentially”), as well as the year-to-date (“YTD”) change between the three months ended March 31, 2024, and the three months ended March 31, 2023 (“YTD 2024-over-YTD 2023”).
Overview of the Company
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. Our long-term vision and strategy is to sustainably grow value for all of our stakeholders as a premier operator of top-tier assets by maintaining and optimizing our high-quality asset portfolio, generating cash flows, and maintaining a strong balance sheet. Our team executes this strategy by prioritizing safety, technological innovation, and stewardship of natural resources, all of which are integral to our corporate culture. Our near-term goals include focusing on continued operational excellence and continuing to return value to stockholders through our Stock Repurchase Program and fixed dividend payments.
Our asset portfolio is comprised of high-quality assets in the Midland Basin of West Texas and in the Maverick Basin of South Texas that we believe are capable of generating strong returns in the current macroeconomic environment and provide resilience to commodity price risk and volatility. We seek to maximize returns and increase the value of our top-tier assets through disciplined capital spending, strategic acquisitions, and continued development and optimization of our existing assets. We believe that our high-quality assets facilitate a sustainable approach to prioritizing operational execution, maintaining a strong balance sheet, generating cash flows, returning capital to stockholders, and maintaining financial flexibility.
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 on our progress in these areas. The Environmental, Social and Governance Committee of our Board of Directors oversees, among other things, the effectiveness of our ESG 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 eligible employees under our long-term incentive plan, and compensation for all employees under our short-term incentive plan is calculated based on, in part, certain Company-wide, performance-based metrics that include key financial, operational, environmental, health, and safety measures.
We are impacted by global commodity and financial markets that remain subject to heightened levels of uncertainty and volatility. While inflation continues to affect certain aspects of our business, the extent of its impact decreased in the first quarter of 2024 compared to 2023. Continued oil production curtailment agreements among the Organization of the Petroleum Exporting Countries (“OPEC”) plus other non-OPEC oil producing countries (collectively referred to as “OPEC+”), instability in the Middle East, economic and trade sanctions associated with the wars between Russia and Ukraine and Israel and Hamas, United States Federal Reserve monetary policy, shipping channel constraints and disruptions, and changes in global oil inventory in storage have driven commodity price volatility, contributed to 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. For additional detail, please refer to the Risk Factors section in Part I, Item 1A of our 2023 Form 10-K. Despite continuing uncertainty, we expect to maximize the value of our high-quality asset base and sustain strong operational performance and financial stability. We remain focused on returning capital to stockholders through cash flow generation.
Areas of Operations
Our Midland Basin assets are comprised of approximately 110,000 net acres located in the Permian Basin in West Texas (“Midland Basin”). In the first quarter of 2024, our drilling and completion activities focused on development optimization of our RockStar and Sweetie Peck assets, and delineation and development of our Klondike assets. Our Midland Basin position provides substantial future development opportunities within multiple oil-rich intervals, including the Spraberry and Wolfcamp formations.
Our South Texas assets are comprised of approximately 155,000 net acres located in Dimmit and Webb Counties, Texas (“South Texas”). In the first quarter of 2024, we focused our operations on development and further delineation of the Austin Chalk formation, and on production from both the Austin Chalk formation and Eagle Ford shale formation. Our overlapping acreage position in the Maverick Basin in South Texas covers a significant portion of the western Eagle Ford shale and Austin Chalk formations, and includes acreage across the oil, gas-condensate, and dry gas windows with gas composition amenable to processing for NGL extraction.
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First Quarter 2024 Overview and Outlook for the Remainder of 2024
During the first quarter of 2024, we continued to execute on our goal of sustainably returning capital to our stockholders through our Stock Repurchase Program and fixed quarterly dividend by repurchasing and subsequently retiring approximately 0.7 million shares of our outstanding common stock at a cost of $32.8 million, excluding excise taxes, commissions, and fees, and paying a quarterly dividend of $0.18 per share totaling $20.8 million. Please refer to Note 3 - Equity in Part I, Item 1 of this report for additional discussion of our Stock Repurchase Program.
Financial and Operational Results. Average net daily equivalent production for the three months ended March 31, 2024, decreased five percent sequentially to 145.1 MBOE, consisting of an eight percent decrease from our South Texas assets and a three percent decrease from our Midland Basin assets, resulting from the timing of well completions.
Realized price per BOE, before the effect of net derivative settlements (“realized price” or “realized prices”), remained flat sequentially. During the first quarter of 2024, oil and gas benchmark prices decreased and the NGL benchmark price increased. These changes resulted in sequential quarterly decreases in oil and gas realized prices of two percent and 12 percent, respectively, offset by an increase in NGL realized price of five percent.
As a result of the decrease in average net daily equivalent production volumes, oil, gas, and NGL production revenue decreased eight percent to $559.6 million for the three months ended March 31, 2024, from $606.9 million for the three months ended December 31, 2023. Oil, gas, and NGL production expense of $10.41 per BOE for the three months ended March 31, 2024, increased seven percent sequentially, primarily as a result of increases in ad valorem tax expense per BOE and lease operating expense (“LOE”) per BOE, partially offset by a decrease in production tax expense per BOE.
We recorded a net derivative loss of $28.1 million and a net derivative gain of $80.5 million for the three months ended March 31, 2024, and December 31, 2023, respectively. Included within these amounts are net derivative settlement gains of $13.3 million and $6.5 million for the three months ended March 31, 2024, and December 31, 2023, respectively.
Operational and financial activities during the three months ended March 31, 2024, resulted in the following:
•Net cash provided by operating activities of $276.0 million, compared with $476.5 million for the three months ended December 31, 2023.
•Net income of $131.2 million, or $1.13 per diluted share, compared with net income of $247.1 million, or $2.12 per diluted share, for the three months ended December 31, 2023.
•Adjusted EBITDAX, a non-GAAP financial measure, of $409.0 million, compared with $445.1 million for the three months ended December 31, 2023. Please refer to the caption Non-GAAP Financial Measures below for additional discussion and our definition of adjusted EBITDAX and reconciliations to net income and net cash provided by operating activities.
Please refer to Overview of Selected Production and Financial Information, Including Trends and Comparison of Financial Results and Trends Between the Three Months Ended March 31, 2024, and December 31, 2023, and Between the Three Months Ended March 31, 2024, and 2023 below for additional discussion.
Operational Activities. We expect our total 2024 capital program to be between $1.14 billion and $1.18 billion, excluding acquisitions. This reflects a decrease from our original expectation primarily as a result of capital efficiencies and lower-than-expected costs. Our capital program remains focused on highly economic oil development projects in both our Midland Basin and South Texas assets. During 2024, we expect to continue our focus on strategic inventory replacement and growth by applying our strength in geosciences and development optimization. Please refer to Overview of Liquidity and Capital Resources below for discussion of how we expect to fund the remainder of our 2024 capital program.
In our Midland Basin program, we operated four drilling rigs and two completion crews, drilled 19 gross (17 net) wells, and completed 16 gross (11 net) wells during the first quarter of 2024. Average net daily equivalent production volumes decreased sequentially by three percent to 74.5 MBOE. Costs incurred during the three months ended March 31, 2024, totaled $182.4 million, or 57 percent of our total costs incurred for the period. We anticipate operating four drilling rigs and between one and two completion crews for the remainder of 2024, focused on developing formations within our RockStar, Sweetie Peck, and Klondike assets.
In our South Texas program, we operated two drilling rigs and one completion crew, drilled 12 gross (12 net) wells, and completed 16 gross (16 net) wells during the first quarter of 2024. Average net daily equivalent production volumes decreased sequentially by eight percent to 70.6 MBOE. Costs incurred during the three months ended March 31, 2024, totaled $129.0 million, or 40 percent of our total costs incurred for the period. We anticipate operating two drilling rigs and averaging one completion crew for the remainder of 2024, focused primarily on developing the Austin Chalk formation.
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The table below provides a quarterly summary of changes in our drilled but not completed well count and current year drilling and completion activity in our operated programs for the three months ended March 31, 2024:

| Midland Basin |  | South Texas (1) |  | Total
| Gross |  | Net |  | Gross |  | Net |  | Gross |  | Net
Wells drilled but not completed at December 31, 2023 | 39 |  |  | 29 |  |  | 37 |  |  | 37 |  |  | 76 |  |  | 66 |
Wells drilled | 19 |  |  | 17 |  |  | 12 |  |  | 12 |  |  | 31 |  |  | 29 |
Wells completed | (16) |  |  | (11) |  |  | (16) |  |  | (16) |  |  | (32) |  |  | (27) |
Wells drilled but not completed at March 31, 2024 | 42 |  |  | 35 |  |  | 33 |  |  | 33 |  |  | 75 |  |  | 68 |

____________________________________________
(1) As of December 31, 2023, the drilled but not completed well count included nine gross (nine net) wells that were not included in our five-year development plan as of December 31, 2023, eight of which were in the Eagle Ford shale.
Costs Incurred. Costs incurred in oil and gas property acquisition, exploration, and development activities, whether capitalized or expensed, totaled $320.2 million for the three months ended March 31, 2024, and were primarily incurred in our Midland Basin and South Texas programs as discussed in Operational Activities above.
Production Results. The table below presents our net production by product type for each of our assets for the periods presented:

| For the Three Months Ended
| March 31, 2024 |  | December 31, 2023 |  |  |  | March 31, 2023
Midland Basin Net Production: |  |  |  |  |  |  |
Oil (MMBbl) | 4.4 |  |  | 4.6 |  |  |  |  | 4.2 |
Gas (Bcf) | 14.5 |  |  | 15.2 |  |  |  |  | 14.5 |
NGLs (MMBbl) | — |  |  | — |  |  |  |  | — |
Equivalent (MMBOE) | 6.8 |  |  | 7.1 |  |  |  |  | 6.7 |
Average net daily equivalent (MBOE per day) | 74.5 |  |  | 77.0 |  |  |  |  | 74.0 |
Relative percentage | 51 | % |  | 50 | % |  |  |  | 51 | %
South Texas Net Production: |  |  |  |  |  |  |
Oil (MMBbl) | 1.4 |  |  | 1.5 |  |  |  |  | 1.4 |
Gas (Bcf) | 16.7 |  |  | 18.3 |  |  |  |  | 17.8 |
NGLs (MMBbl) | 2.2 |  |  | 2.5 |  |  |  |  | 2.1 |
Equivalent (MMBOE) | 6.4 |  |  | 7.0 |  |  |  |  | 6.5 |
Average net daily equivalent (MBOE per day) | 70.6 |  |  | 76.4 |  |  |  |  | 72.5 |
Relative percentage | 49 | % |  | 50 | % |  |  |  | 49 | %
Total Net Production: |  |  |  |  |  |  |
Oil (MMBbl) | 5.8 |  |  | 6.1 |  |  |  |  | 5.7 |
Gas (Bcf) | 31.1 |  |  | 33.5 |  |  |  |  | 32.2 |
NGLs (MMBbl) | 2.2 |  |  | 2.5 |  |  |  |  | 2.1 |
Equivalent (MMBOE) | 13.2 |  |  | 14.1 |  |  |  |  | 13.2 |
Average net daily equivalent (MBOE per day) | 145.1 |  |  | 153.5 |  |  |  |  | 146.4 |

____________________________________________
Note: Amounts may not calculate due to rounding.
Please refer to Overview of Selected Production and Financial Information, Including Trends and Comparison of Financial Results and Trends Between the Three Months Ended March 31, 2024, and December 31, 2023, and Between the Three Months Ended March 31, 2024, and 2023 below for discussion on 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 three months ended March 31, 2024, December 31, 2023, and March 31, 2023:

| For the Three Months Ended
| March 31, 2024 |  | December 31, 2023 |  | March 31, 2023
Oil (per Bbl): |  |  |  |  |
Average NYMEX contract monthly price | $ | 76.96 |  |  | $ | 78.32 |  |  | $ | 76.13 |
Realized price | $ | 76.09 |  |  | $ | 77.41 |  |  | $ | 74.31 |
Effect of oil net derivative settlements | $ | 0.44 |  |  | $ | (1.11) |  |  | $ | (1.10) |
Gas: |  |  |  |  |
Average NYMEX monthly settle price (per MMBtu) | $ | 2.24 |  |  | $ | 2.88 |  |  | $ | 3.42 |
Realized price (per Mcf) | $ | 2.18 |  |  | $ | 2.47 |  |  | $ | 2.91 |
Effect of gas net derivative settlements (per Mcf) | $ | 0.39 |  |  | $ | 0.35 |  |  | $ | 0.35 |
NGLs (per Bbl): |  |  |  |  |
Average OPIS price (1) | $ | 29.28 |  |  | $ | 26.89 |  |  | $ | 30.95 |
Realized price | $ | 22.94 |  |  | $ | 21.92 |  |  | $ | 26.24 |
Effect of NGL net derivative settlements | $ | (0.66) |  |  | $ | 0.65 |  |  | $ | — |

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(1) 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.
Given the uncertainty surrounding global financial markets, production output from OPEC+, global shipping channel constraints and disruptions, instability in the Middle East, economic and trade sanctions associated with the wars between Russia and Ukraine and Israel and Hamas, changes in global oil inventory in storage, and the potential impacts of these issues on global commodity markets, we expect benchmark prices for oil, gas, and NGLs to remain volatile for the foreseeable future, and we cannot reasonably predict the timing or likelihood of any future impacts that may result, which could include further inflation, supply chain disruptions, fluctuations in interest rates, and industry-specific impacts. In addition to supply and demand fundamentals, as global commodities, the prices for oil, gas, and NGLs are affected by real or perceived geopolitical risks in various regions of the world as well as the relative strength of the United States dollar compared to other currencies. Our realized prices at local sales points may also be affected by infrastructure capacity or outages in the areas of our operations and beyond. We expect the realized price for our Midland Basin gas production during the second and third quarters of 2024 to be impacted by residue pipeline capacity constraints; however, a portion of any negative impact to the realized price would be mitigated by our commodity derivative contracts, which are discussed below.
The following table summarizes 12-month strip prices for NYMEX WTI oil, NYMEX Henry Hub gas, and OPIS NGLs as of April 25, 2024, and March 31, 2024:

| As of April 25, 2024 |  | As of March 31, 2024
NYMEX WTI oil (per Bbl) | $ | 80.03 |  |  | $ | 79.72 |
NYMEX Henry Hub gas (per MMBtu) | $ | 2.82 |  |  | $ | 2.66 |
OPIS NGLs (per Bbl) | $ | 28.51 |  |  | $ | 29.00 |

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
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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. Please refer to Note 7 - Derivative Financial Instruments in Part I, Item 1 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.
Financial Results of Operations and Additional Comparative Data
The tables below provide information regarding selected production and financial information for the three months ended March 31, 2024, and the preceding three quarters:

| For the Three Months Ended
| March 31, |  | December 31, |  | September 30, |  | June 30,
| 2024 |  | 2023 |  | 2023 |  | 2023
| (in millions)
Net production (MMBOE) | 13.2 |  |  | 14.1 |  |  | 14.1 |  |  | 14.1 |
Oil, gas, and NGL production revenue | $ | 559.6 |  |  | $ | 606.9 |  |  | $ | 639.7 |  |  | $ | 546.6 |
Oil, gas, and NGL production expense | $ | 137.4 |  |  | $ | 137.3 |  |  | $ | 138.3 |  |  | $ | 145.6 |
Depletion, depreciation, amortization, and asset retirement obligation liability accretion | $ | 166.2 |  |  | $ | 189.1 |  |  | $ | 189.4 |  |  | $ | 157.8 |
Exploration | $ | 18.6 |  |  | $ | 15.8 |  |  | $ | 10.2 |  |  | $ | 15.0 |
General and administrative | $ | 30.2 |  |  | $ | 36.6 |  |  | $ | 29.3 |  |  | $ | 27.5 |
Net income | $ | 131.2 |  |  | $ | 247.1 |  |  | $ | 222.3 |  |  | $ | 149.9 |

Selected Performance Metrics

| For the Three Months Ended
| March 31, |  | December 31, |  | September 30, |  | June 30,
| 2024 |  | 2023 |  | 2023 |  | 2023
Average net daily equivalent production (MBOE per day) | 145.1 |  |  | 153.5 |  |  | 153.7 |  |  | 154.4 |
Lease operating expense (per BOE) | $ | 5.54 |  |  | $ | 5.31 |  |  | $ | 5.08 |  |  | $ | 4.98 |
Transportation costs (per BOE) | $ | 2.07 |  |  | $ | 2.08 |  |  | $ | 2.07 |  |  | $ | 2.89 |
Production taxes as a percent of oil, gas, and NGL production revenue | 4.5 | % |  | 4.6 | % |  | 4.3 | % |  | 4.3 | %
Ad valorem tax expense (per BOE) | $ | 0.89 |  |  | $ | 0.37 |  |  | $ | 0.70 |  |  | $ | 0.83 |
Depletion, depreciation, amortization, and asset retirement obligation liability accretion (per BOE) | $ | 12.59 |  |  | $ | 13.39 |  |  | $ | 13.39 |  |  | $ | 11.23 |
General and administrative (per BOE) | $ | 2.29 |  |  | $ | 2.60 |  |  | $ | 2.07 |  |  | $ | 1.96 |

____________________________________________
Note: Amounts may not calculate due to rounding.
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Overview of Selected Production and Financial Information, Including Trends

|  |  |  |  |  |  | For the Three Months Ended |  | Amount Change Between the Three Months Ended |  | Percent Change Between the Three Months Ended
|  |  |  |  |  | March 31, 2024 |  | December 31, 2023 |  | March 31, 2023 |  | March 31, 2024 & December 31, 2023 |  | March 31, 2024 & 2023 |  | March 31, 2024 & December 31, 2023 |  | March 31, 2024 & 2023
Net production volumes: (1) |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Oil (MMBbl) |  |  |  |  |  |  |  |  | 5.8 |  |  | 6.1 |  |  | 5.7 |  |  | (0.3) |  |  | 0.1 |  |  | (5) | % |  | 2 | %
Gas (Bcf) |  |  |  |  |  |  |  |  | 31.1 |  |  | 33.5 |  |  | 32.2 |  |  | (2.4) |  |  | (1.1) |  |  | (7) | % |  | (3) | %
NGLs (MMBbl) |  |  |  |  |  |  |  |  | 2.2 |  |  | 2.5 |  |  | 2.1 |  |  | (0.2) |  |  | 0.1 |  |  | (10) | % |  | 3 | %
Equivalent (MMBOE) |  |  |  |  |  |  |  |  | 13.2 |  |  | 14.1 |  |  | 13.2 |  |  | (0.9) |  |  | — |  |  | (6) | % |  | — | %
Average net daily production: (1) |  |  |  |  |  |  |  |
Oil (MBbl per day) |  |  |  |  |  |  |  |  | 63.7 |  |  | 66.0 |  |  | 62.9 |  |  | (2.4) |  |  | 0.7 |  |  | (4) | % |  | 1 | %
Gas (MMcf per day) |  |  |  |  |  |  |  |  | 342.3 |  |  | 364.1 |  |  | 358.1 |  |  | (21.8) |  |  | (15.9) |  |  | (6) | % |  | (4) | %
NGLs (MBbl per day) |  |  |  |  |  |  |  |  | 24.4 |  |  | 26.7 |  |  | 23.8 |  |  | (2.4) |  |  | 0.6 |  |  | (9) | % |  | 2 | %
Equivalent (MBOE per day) |  |  |  |  |  |  |  |  | 145.1 |  |  | 153.5 |  |  | 146.4 |  |  | (8.4) |  |  | (1.3) |  |  | (5) | % |  | (1) | %
Oil, gas, and NGL production revenue (in millions): (1) |  |  |  |  |  |  |  |
Oil production revenue |  |  |  |  |  |  |  |  | $ | 440.9 |  |  | $ | 470.3 |  |  | $ | 420.8 |  |  | $ | (29.4) |  |  | $ | 20.1 |  |  | (6) | % |  | 5 | %
Gas production revenue |  |  |  |  |  |  |  |  | 67.8 |  |  | 82.6 |  |  | 93.7 |  |  | (14.8) |  |  | (25.9) |  |  | (18) | % |  | (28) | %
NGL production revenue |  |  |  |  |  |  |  |  | 50.9 |  |  | 53.9 |  |  | 56.2 |  |  | (3.1) |  |  | (5.3) |  |  | (6) | % |  | (10) | %
Total oil, gas, and NGL production revenue |  |  |  |  |  |  |  |  | $ | 559.6 |  |  | $ | 606.9 |  |  | $ | 570.8 |  |  | $ | (47.3) |  |  | $ | (11.2) |  |  | (8) | % |  | (2) | %
Oil, gas, and NGL production expense (in millions): (1) |  |  |  |  |  |  |  |
Lease operating expense |  |  |  |  |  |  |  |  | $ | 73.1 |  |  | $ | 74.9 |  |  | $ | 68.0 |  |  | $ | (1.8) |  |  | $ | 5.1 |  |  | (2) | % |  | 7 | %
Transportation costs |  |  |  |  |  |  |  |  | 27.3 |  |  | 29.4 |  |  | 37.0 |  |  | (2.1) |  |  | (9.7) |  |  | (7) | % |  | (26) | %
Production taxes |  |  |  |  |  |  |  |  | 25.1 |  |  | 27.8 |  |  | 26.7 |  |  | (2.6) |  |  | (1.5) |  |  | (9) | % |  | (6) | %
Ad valorem tax expense |  |  |  |  |  |  |  |  | 11.8 |  |  | 5.3 |  |  | 10.6 |  |  | 6.5 |  |  | 1.2 |  |  | 124 | % |  | 11 | %
Total oil, gas, and NGL production expense |  |  |  |  |  |  |  |  | $ | 137.4 |  |  | $ | 137.3 |  |  | $ | 142.3 |  |  | $ | — |  |  | $ | (5.0) |  |  | — | % |  | (3) | %
Realized price: |  |  |  |  |  |  |  |
Oil (per Bbl) |  |  |  |  |  |  |  |  | $ | 76.09 |  |  | $ | 77.41 |  |  | $ | 74.31 |  |  | $ | (1.32) |  |  | $ | 1.78 |  |  | (2) | % |  | 2 | %
Gas (per Mcf) |  |  |  |  |  |  |  |  | $ | 2.18 |  |  | $ | 2.47 |  |  | $ | 2.91 |  |  | $ | (0.29) |  |  | $ | (0.73) |  |  | (12) | % |  | (25) | %
NGLs (per Bbl) |  |  |  |  |  |  |  |  | $ | 22.94 |  |  | $ | 21.92 |  |  | $ | 26.24 |  |  | $ | 1.02 |  |  | $ | (3.30) |  |  | 5 | % |  | (13) | %
Per BOE |  |  |  |  |  |  |  |  | $ | 42.39 |  |  | $ | 42.99 |  |  | $ | 43.31 |  |  | $ | (0.60) |  |  | $ | (0.92) |  |  | (1) | % |  | (2) | %
Per BOE data: (1) |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Oil, gas, and NGL production expense: |  |  |  |  |  |  |  |  |  |  |  |
Lease operating expense |  |  |  |  |  |  |  |  | $ | 5.54 |  |  | $ | 5.31 |  |  | $ | 5.16 |  |  | $ | 0.23 |  |  | $ | 0.38 |  |  | 4 | % |  | 7 | %
Transportation costs |  |  |  |  |  |  |  |  | 2.07 |  |  | 2.08 |  |  | 2.81 |  |  | (0.01) |  |  | (0.74) |  |  | — | % |  | (26) | %
Production taxes |  |  |  |  |  |  |  |  | 1.90 |  |  | 1.97 |  |  | 2.02 |  |  | (0.07) |  |  | (0.12) |  |  | (4) | % |  | (6) | %
Ad valorem tax expense |  |  |  |  |  |  |  |  | 0.89 |  |  | 0.37 |  |  | 0.81 |  |  | 0.52 |  |  | 0.08 |  |  | 141 | % |  | 10 | %
Total oil, gas, and NGL production expense (1) |  |  |  |  |  |  |  |  | $ | 10.41 |  |  | $ | 9.73 |  |  | $ | 10.80 |  |  | $ | 0.68 |  |  | $ | (0.39) |  |  | 7 | % |  | (4) | %
Depletion, depreciation, amortization, and asset retirement obligation liability accretion |  |  |  |  |  |  |  |  | $ | 12.59 |  |  | $ | 13.39 |  |  | $ | 11.70 |  |  | $ | (0.80) |  |  | $ | 0.89 |  |  | (6) | % |  | 8 | %
General and administrative |  |  |  |  |  |  |  |  | $ | 2.29 |  |  | $ | 2.60 |  |  | $ | 2.10 |  |  | $ | (0.31) |  |  | $ | 0.19 |  |  | (12) | % |  | 9 | %
Net derivative settlement gain (2) |  |  |  |  |  |  |  |  | $ | 1.01 |  |  | $ | 0.46 |  |  | $ | 0.39 |  |  | $ | 0.55 |  |  | $ | 0.62 |  |  | 120 | % |  | 159 | %
Earnings per share information (in thousands, except per share data): (3) |  |  |  |  |  |  |  |
Basic weighted-average common shares outstanding |  |  |  |  |  |  |  |  | 115,642 |  |  | 115,971 |  |  | 121,671 |  |  | (329) |  |  | (6,029) |  |  | — | % |  | (5) | %
Diluted weighted-average common shares outstanding |  |  |  |  |  |  |  |  | 116,456 |  |  | 116,587 |  |  | 122,294 |  |  | (131) |  |  | (5,838) |  |  | — | % |  | (5) | %
Basic net income per common share |  |  |  |  |  |  |  |  | $ | 1.13 |  |  | $ | 2.13 |  |  | $ | 1.63 |  |  | $ | (1.00) |  |  | $ | (0.50) |  |  | (47) | % |  | (31) | %
Diluted net income per common share |  |  |  |  |  |  |  |  | $ | 1.13 |  |  | $ | 2.12 |  |  | $ | 1.62 |  |  | $ | (0.99) |  |  | $ | (0.49) |  |  | (47) | % |  | (30) | %

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______________________________________
(1) Amounts and percentage changes may not calculate due to rounding.
(2) Net derivative settlements for the three months ended March 31, 2024, and 2023, are included within the net derivative (gain) loss line item in the accompanying statements of operations.
(3) Please refer to Note 9 - Earnings Per Share in Part I, Item 1 of this report for additional discussion.
Average net daily equivalent production for the three months ended March 31, 2024, decreased five percent sequentially, consisting of an eight percent decrease from our South Texas assets and a three percent decrease from our Midland Basin assets, resulting from the timing of well completions. Average net daily equivalent production remained flat YTD 2024-over-YTD 2023.
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 $0.60 sequentially, primarily as a result of decreases in oil and gas benchmark prices, and decreased $0.92 YTD 2024-over-YTD 2023, primarily as a result of decreases in gas and NGL benchmark prices. For the three months ended March 31, 2024, December 31, 2023, and March 31, 2023, we recognized net gains on the settlement of our commodity derivative contracts of $1.01 per BOE, $0.46 per BOE, and $0.39 per BOE, respectively.
LOE on a per BOE basis increased four percent sequentially and seven percent YTD 2024-over-YTD 2023. The sequential quarterly increase was a result of decreased average net daily equivalent production and a slight shift in our production mix from our South Texas assets to our Midland Basin assets, which have higher unit operating costs. The YTD 2024-over-YTD 2023 increase was primarily driven by increases in labor costs. For the full-year 2024, we expect LOE on a per BOE basis to increase, compared with 2023, primarily as a result of expected increases in labor costs and certain other operating costs associated with both our Midland Basin and South Texas assets. We anticipate volatility in LOE on a per BOE basis as a result of changes in total production, changes in our overall production mix, timing of workover projects, and industry activity, all of which affect total LOE.
Transportation costs on a per BOE basis remained flat sequentially and decreased 26 percent YTD 2024-over-YTD 2023 as a result of the expiration of a long-term contract in South Texas on June 30, 2023. In general, we expect total transportation costs to fluctuate relative to changes in gas and NGL production from our South Texas assets, where we incur a majority of our transportation costs. For the full-year 2024, we expect transportation costs on a per BOE basis to decrease compared with 2023, as a result of the expiration of the long-term contract in South Texas previously discussed.
Production tax expense on a per BOE basis decreased four percent sequentially and six percent YTD 2024-over-YTD 2023, primarily as a result of decreases in total realized price per BOE. Our overall production tax rate for the three months ended March 31, 2024, December 31, 2023, and March 31, 2023, was 4.5 percent, 4.6 percent, and 4.7 percent, respectively. We generally expect production tax expense to correlate with oil, gas, and NGL production revenue on an absolute and per BOE 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 increased 141 percent sequentially as ad valorem tax expense recorded during the three months ended December 31, 2023, reflected the positive impact of a property tax relief bill that provided for a one-time benefit during 2023. Ad valorem tax expense on a per BOE basis increased 10 percent YTD 2024-over-YTD 2023 as a result of 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, which is generally driven by fluctuations in commodity prices.
Depletion, depreciation, amortization, and asset retirement obligation liability accretion (“DD&A”) expense on a per BOE basis decreased six percent sequentially primarily as a result of a decrease in our DD&A rate due to increased estimated net proved reserves at year-end 2023. DD&A expense on a per BOE basis increased eight percent YTD 2024-over-YTD 2023 due to inflation and a slight shift in production mix resulting from higher activity in our Midland Basin assets, which have a higher DD&A rate than our South Texas assets. Our DD&A rate fluctuates as a result of changes in our production mix, changes in our total estimated net proved reserve volumes, changes in capital allocation, impairments, acquisition and divestiture activity, and carrying cost funding and sharing arrangements with third parties. For the full-year 2024, we expect DD&A expense per BOE to remain flat and DD&A expense on an absolute basis to increase slightly, compared with 2023, primarily as a result of expected increased production.
General and administrative (“G&A”) expense on a per BOE basis decreased 12 percent sequentially primarily as a result of decreased compensation expense. G&A expense on a per BOE basis increased nine percent YTD 2024-over-YTD 2023 as a result of increased compensation expense due to inflation. For the full-year 2024, we expect G&A expense to remain relatively flat per BOE, and G&A expense on an absolute basis to increase compared with 2023, primarily as a result of increases in compensation expense due to inflation.
Please refer to Comparison of Financial Results and Trends Between the Three Months Ended March 31, 2024, and December 31, 2023, and Between the Three Months Ended March 31, 2024, and 2023 below for additional discussion of operating expenses.
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Comparison of Financial Results and Trends Between the Three Months Ended March 31, 2024, and December 31, 2023, and Between the Three Months Ended March 31, 2024, and 2023
Average net daily equivalent production, oil, gas, and NGL production revenue, and oil, gas, and NGL production expense
Sequential Quarterly Changes. The following table presents 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 three months ended March 31, 2024, and December 31, 2023:

| Average Net Equivalent Production Decrease |  | Oil, Gas, and NGL Production Revenue Decrease |  | Oil, Gas, and NGL Production Expense Increase (Decrease)
| (MBOE per day) |  | (in millions) |  | (in millions)
Midland Basin | (2.6) |  |  |  |  | $ | (25.6) |  |  |  |  | $ | 1.2 |  |  |
South Texas | (5.8) |  |  |  |  | (21.7) |  |  |  |  | (1.2) |  |  |
Total | (8.4) |  |  |  |  | $ | (47.3) |  |  |  |  | $ | — |  |  |

__________________________________________
Note: Amounts may not calculate due to rounding.
Average net daily equivalent production volumes decreased five percent, consisting of an eight percent decrease from our South Texas assets and a three percent decrease from our Midland Basin assets. Total realized price per BOE remained flat. As a result of the decrease in average net daily equivalent production volumes, oil, gas, and NGL production revenue decreased eight percent. Oil, gas, and NGL production expense remained flat, as an increase in ad valorem tax expense was offset by decreases in production tax expense, transportation costs, and LOE.
YTD 2024-over-YTD 2023 Changes. The following table presents 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 three months ended March 31, 2024, and 2023:

| Average Net Equivalent Production Increase (Decrease) |  | Oil, Gas, and NGL Production Revenue Increase (Decrease) |  | Oil, Gas, and NGL Production Expense Increase (Decrease)
| (MBOE per day) |  | (in millions) |  | (in millions)
Midland Basin | 0.5 |  |  |  |  | $ | 2.7 |  |  |  |  | $ | 3.4 |  |  |
South Texas | (1.9) |  |  |  |  | (13.9) |  |  |  |  | (8.4) |  |  |
Total | (1.3) |  |  |  |  | $ | (11.2) |  |  |  |  | $ | (5.0) |  |  |

__________________________________________
Note: Amounts may not calculate due to rounding.
Average net daily equivalent production volumes remained flat, as a three percent decrease from our South Texas assets was partially offset by a one percent increase from our Midland Basin assets. Total realized price per BOE decreased slightly, and combined with flat average net daily equivalent production volumes, resulted in oil, gas, and NGL production revenue remaining flat. Oil, gas, and NGL production expense decreased three percent, primarily driven by a decrease in transportation costs, partially offset by an increase in LOE.
Please 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, amortization, and asset retirement obligation liability accretion

| For the Three Months Ended |
| March 31, 2024 |  | December 31, 2023 |  | March 31, 2023 |  |  |
| (in millions)
Depletion, depreciation, amortization, and asset retirement obligation liability accretion | $ | 166.2 |  |  | $ | 189.1 |  |  | $ | 154.2 |  |  |  |

DD&A expense decreased 12 percent sequentially and increased eight percent YTD 2024-over-YTD 2023. The sequential quarterly decrease was primarily driven by a decrease in our DD&A rate and a decrease in average net daily equivalent production. The YTD 2024-over-YTD 2023 increase resulted from inflation and a slight shift in production mix resulting from higher activity in our
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Midland Basin assets, which have a higher DD&A rate than our South Texas assets. Please refer to Overview of Selected Production and Financial Information, Including Trends above for discussion of DD&A expense on a per BOE basis.
Exploration

| For the Three Months Ended |  |
| March 31, 2024 |  | December 31, 2023 |  | March 31, 2023 |  |  |  |
| (in millions)
Geological, geophysical, and other expenses | $ | 11.0 |  |  | $ | 5.7 |  |  | $ | 10.6 |  |  |  |  |
Overhead | 7.6 |  |  | 10.1 |  |  | 7.8 |  |  |  |  |
Total | $ | 18.6 |  |  | $ | 15.8 |  |  | $ | 18.4 |  |  |  |  |

Exploration expense increased 17 percent sequentially primarily as a result of expenses incurred related to one well deemed non-commercial, partially offset by a decrease in exploration overhead expense. Exploration expense remained flat YTD 2024-over-YTD 2023. 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.
General and administrative

| For the Three Months Ended |  |
| March 31, 2024 |  | December 31, 2023 |  | March 31, 2023 |  |  |  |
| (in millions)
General and administrative | $ | 30.2 |  |  | $ | 36.6 |  |  | $ | 27.7 |  |  |  |  |

G&A expense decreased 18 percent sequentially primarily as a result of decreased compensation expense. G&A expense recorded during the three months ended December 31, 2023, reflected an increase to compensation expense resulting from the Company’s full-year performance against targets established at the beginning of the year. G&A expense increased nine percent YTD 2024-over-YTD 2023 primarily as a result of increased compensation expense due to inflation. Please refer to the section Overview of Selected Production and Financial Information, Including Trends above for discussion of G&A expense on a per BOE basis.
Net derivative (gain) loss

| For the Three Months Ended |  |
| March 31, 2024 |  | December 31, 2023 |  | March 31, 2023 |  |  |  |
| (in millions)
Net derivative (gain) loss | $ | 28.1 |  |  | $ | (80.5) |  |  | $ | (51.3) |  |  |  |  |

Net derivative (gain) loss 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. Please refer to Note 7 - Derivative Financial Instruments in Part I, Item 1 of this report for additional discussion.
Interest expense

| For the Three Months Ended |  |
| March 31, 2024 |  | December 31, 2023 |  | March 31, 2023 |  |  |  |
| (in millions)
Interest expense | $ | (21.9) |  |  | $ | (23.9) |  |  | $ | (22.5) |  |  |  |  |

Interest expense decreased nine percent sequentially and three percent YTD 2024-over-YTD 2023 primarily driven by an increase in capitalized interest as a result of the timing of the development of our wells in progress. Total interest expense can vary based on the timing and amount of borrowings under our revolving credit facility. Please refer to Overview of Liquidity and Capital Resources below and to Note 5 - Long-Term Debt in Part I, Item 1 of this report for additional discussion.
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Income tax expense

| For the Three Months Ended |  |
| March 31, 2024 |  | December 31, 2023 |  | March 31, 2023 |  |  |  |
| (in millions, except tax rate)
Income tax expense | $ | (32.1) |  |  | $ | (44.7) |  |  | $ | (55.5) |  |  |  |  |
Effective tax rate | 19.6 | % |  | 15.3 | % |  | 21.8 | % |  |  |  |

Our effective tax rate increased sequentially as the positive impact of the R&D credit claimed during the three months ended December 31, 2023, was higher than for the three months ended March 31, 2024. Our effective tax rate decreased YTD 2024-over-YTD 2023 primarily due to the benefit recognized from anticipated qualified R&D credit claims in 2024.
The tax rates for each period presented also reflect the proportional effects of state income taxes, limits on expensing of certain covered individual’s compensation, and the cumulative effect of other small differences. Based on current projections, we estimate that after utilization of a portion of the R&D credits, between $15.0 million and $25.0 million of full-year 2024 income tax expense will be current. Please refer to Note 4 - Income Taxes in Part I, Item 1 of this report for additional discussion.
Changes in federal income tax laws or enactment of proposed legislation to increase the corporate tax rate and eliminate or reduce certain oil and gas industry deductions could have a material effect on our effective tax rate and current tax expense. Effective for tax years beginning after December 31, 2022, the Inflation Reduction Act of 2022 provides for a 15 percent corporate alternative minimum tax (“CAMT”) on corporations with average adjusted financial statement income over $1.0 billion for any three-year period preceding the tax year. Please refer to Overview of Liquidity and Capital Resources below and to the Risk Factors section in Part 1, Item 1A of our 2023 Form 10-K for additional 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 current financial obligations. 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
For the three months ended March 31, 2024, we funded our capital expenditures and return of capital program with cash flows from operating activities and cash on hand, and we expect that to continue for the remainder of 2024. However, we may also use borrowings under our revolving credit facility or 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 certain existing stockholders and bondholders. Additionally, we may enter into carrying cost and sharing arrangements with third parties for certain exploration or development programs. Our credit ratings affect the availability of, and cost for us to borrow, additional funds. Any future downgrades in our credit ratings could make it more difficult or expensive for us to borrow additional funds. 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, or 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 substantially over the price established by the commodity derivative contract. Please refer to Note 7 - Derivative Financial Instruments in Part I, Item 1 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 March 31, 2024, the borrowing base and aggregate lender commitments under our Credit Agreement were $2.5 billion and $1.25 billion, respectively. The borrowing base is subject to regular, semi-annual redetermination, which 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. Subsequent to March 31, 2024, the semi-annual borrowing base redetermination was completed, which reaffirmed both our borrowing base and aggregate lender commitments at existing amounts. The next scheduled borrowing base redetermination date is October 1, 2024. No individual bank participating in the Credit Agreement represents more than 10 percent of the aggregate lender commitment. We must comply with certain financial and non-financial covenants under the terms of the Credit Agreement. We were in compliance with all financial and non-financial covenants under the Credit Agreement as of March 31, 2024, and through the filing of this report. Please refer to Note 5 - Long-Term Debt in Part I, Item 1 of this report for additional discussion, as well as the presentation
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of the outstanding balance, total amount of letters of credit, and available borrowing capacity under the Credit Agreement as of April 25, 2024, March 31, 2024, and December 31, 2023.
We had no revolving credit facility borrowings during the three months ended March 31, 2024, or at any time during 2023. Cash flows provided by our operating activities, proceeds received from divestitures of properties, capital markets activities including open market debt repurchases, debt redemptions, repayment of scheduled debt maturities, other financing activities, and our capital expenditures, including acquisitions, all impact the amount we borrow under our revolving credit facility.
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 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 periods presented:

| For the Three Months Ended
| March 31, 2024 |  | December 31, 2023 |  |  |  | March 31, 2023
Weighted-average interest rate | 7.1 | % |  | 7.0 | % |  |  |  | 7.2 | %
Weighted-average borrowing rate | 6.4 | % |  | 6.4 | % |  |  |  | 6.5 | %

Our weighted-average interest rate and our weighted-average borrowing rate each remained flat both sequentially and YTD 2024-over-YTD 2023. We expect our weighted-average interest rate and weighted-average borrowing rate to remain relatively flat for the full-year 2024 compared with 2023.
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 lender commitments.
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, 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 the three months ended March 31, 2024, we spent $332.4 million on capital expenditures. This amount differs from the costs incurred amount of $320.2 million for the three months ended March 31, 2024, as costs incurred is an accrual-based amount that also includes asset retirement obligations, geological and geophysical expenses, acquisitions of oil and gas properties, and exploration overhead amounts.
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. Our total 2024 capital program, which we expect to fund with cash flows from operations, is expected to be between $1.14 billion and $1.18 billion, excluding acquisitions. This reflects a decrease from our original expectation primarily as a result of capital efficiencies and lower-than-expected costs.
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 three months ended March 31, 2024, and 2023, we repurchased and subsequently retired 0.7 million and 1.4 million shares, respectively, of our common stock at a cost of $32.8 million and $40.0 million, respectively, excluding excise taxes, commissions, and fees. As of March 31, 2024, $182.1 million remained available under the Stock Repurchase Program for repurchases of our common stock through December 31, 2024. Please refer to Note 3 - Equity in Part I, Item 1 of this report for additional discussion.
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During the three months ended March 31, 2024, and 2023, we paid $20.8 million and $18.3 million, respectively, in dividends to our stockholders. 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.
Changes in federal income tax laws, specifically the CAMT, could increase our corporate income tax rate and could eliminate or reduce current tax deductions. While the CAMT is not currently applicable to us, it and other possible future legislation could reduce our net cash provided by operating activities over time, which could result in a reduction of available funding. Please refer to Comparison of Financial Results and Trends Between the Three Months Ended March 31, 2024, and December 31, 2023, and Between the Three Months Ended March 31, 2024, and 2023 above for additional discussion.
Analysis of Cash Flow Changes Between the Three Months Ended March 31, 2024, and 2023
The following tables present changes in cash flows between the three months ended March 31, 2024, and 2023, for our operating, investing, and financing activities. The analysis following each table should be read in conjunction with our accompanying statements of cash flows in Part I, Item 1 of this report.
Operating activities

| For the Three Months Ended March 31, |  | Amount Change Between Periods |  |
| 2024 |  | 2023 |  |
| (in millions) |  |
Net cash provided by operating activities | $ | 276.0 |  |  | $ | 331.6 |  |  | $ | (55.6) |  |  |

Net cash provided by operating activities decreased for the three months ended March 31, 2024, compared with the same period in 2023, primarily as a result of a $46.8 million decrease in cash received from oil, gas, and NGL production revenue net of transportation costs and production taxes and an increase of $17.5 million in cash paid for G&A expense, partially offset by a $31.3 million decrease in cash paid on settled derivative trades. Net cash provided by operating activities is also affected by working capital changes and the timing of cash receipts and disbursements.
Investing activities

| For the Three Months Ended March 31, |  | Amount Change Between Periods |  |
| 2024 |  | 2023 |  |
| (in millions) |  |
Net cash used in investing activities | $ | (332.3) |  |  | $ | (240.4) |  |  | $ | (91.9) |  |  |

Net cash used in investing activities increased for the three months ended March 31, 2024, compared with the same period in 2023, as a result of a $91.7 million increase in capital expenditures. Net cash used in investing activities during the three months ended March 31, 2024, was funded by net cash provided by operating activities and cash on hand.
Financing activities

| For the Three Months Ended March 31, |  | Amount Change Between Periods |  |
| 2024 |  | 2023 |  |
| (in millions) |  |
Net cash used in financing activities | $ | (53.6) |  |  | $ | (58.4) |  |  | $ | 4.8 |  |  |

Net cash used in financing activities for the three months ended March 31, 2024, primarily related to $32.8 million of cash paid, including commissions and fees, to repurchase and subsequently retire 0.7 million shares of our common stock under the Stock Repurchase Program and $20.8 million of dividends paid to our stockholders.
Net cash used in financing activities for the three months ended March 31, 2023, related to $40.1 million of cash paid, including commissions and fees, to repurchase and subsequently retire 1.4 million shares of our common stock under the Stock Repurchase Program and $18.3 million of dividends paid to our stockholders.
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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 March 31, 2024, our outstanding principal amount of fixed-rate debt totaled $1.6 billion, and we had no floating-rate debt outstanding. Please refer to Note 8 - Fair Value Measurements in Part I, Item 1 of this report for additional discussion on the fair values of our Senior Notes.
As a result of the United States Federal Reserve’s current monetary policy, short-term interest rates could remain elevated longer than expected, which could increase the cost of and affect our ability to borrow funds.
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, and other transportation systems, and weather-related events. The markets for oil, gas, and NGLs have been volatile, especially over the last decade, and remain subject to high levels of uncertainty and volatility related to production output from OPEC+, global shipping channel constraints and disruptions, instability in the Middle East, economic and trade sanctions associated with the wars between Russia and Ukraine and Israel and Hamas, 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. Based on our production for the three months ended March 31, 2024, a 10 percent decrease in our average realized oil, gas, and NGL prices would have reduced our oil, gas, and NGL production revenue by approximately $44.1 million, $6.8 million, and $5.1 million, respectively. If commodity prices had been 10 percent lower, our net derivative settlements for the three months ended March 31, 2024, would have offset the declines in oil, gas, and NGL production revenue by approximately $11.9 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 March 31, 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 $34.4 million, $6.4 million, and $6.6 million, respectively.
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”), which would have been established for the purpose of facilitating off-balance sheet arrangements or other contractually narrow or limited purposes.
We evaluate our transactions to determine if any variable interest entities exist. If we determine that we are the primary beneficiary of a variable interest entity, that entity is consolidated into our consolidated financial statements. We have not been involved in any unconsolidated SPE transactions during the three months ended March 31, 2024, or through the filing of this report.
Critical Accounting Estimates
Please refer to the corresponding section in Part II, Item 7 and to Note 1 - Summary of Significant Accounting Policies included in Part II, Item 8 of our 2023 Form 10-K for discussion of our accounting estimates.
Accounting Matters
Please refer to Note 1 - Summary of Significant Accounting Policies in Part I, Item 1 of this report for information on new authoritative accounting guidance.
Non-GAAP Financial Measures
Adjusted EBITDAX represents net income (loss) before interest expense, interest income, income taxes, depletion, depreciation, amortization and asset retirement obligation liability accretion expense, exploration expense, property abandonment and
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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 based on adjusted EBITDAX ratios as further described in Note 5 - Long-Term Debt in the 2023 Form 10-K. 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.
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:

| For the Three Months Ended |  |
| March 31, 2024 |  | December 31, 2023 |  | March 31, 2023 |  |  |  |  |
| (in thousands)
Net income (GAAP) | $ | 131,199 |  |  | $ | 247,111 |  |  | $ | 198,552 |  |  |  |  |  |
Interest expense | 21,873 |  |  | 23,917 |  |  | 22,459 |  |  |  |  |  |
Interest income | (6,770) |  |  | (6,052) |  |  | (4,702) |  |  |  |  |  |
Income tax expense | 32,069 |  |  | 44,703 |  |  | 55,506 |  |  |  |  |  |
Depletion, depreciation, amortization, and asset retirement obligation liability accretion | 166,188 |  |  | 189,107 |  |  | 154,189 |  |  |  |  |  |
Exploration (1) | 17,456 |  |  | 14,721 |  |  | 17,477 |  |  |  |  |  |
Stock-based compensation expense | 5,018 |  |  | 5,731 |  |  | 4,318 |  |  |  |  |  |
Net derivative (gain) loss | 28,145 |  |  | (80,506) |  |  | (51,329) |  |  |  |  |  |
Net derivative settlement gain | 13,274 |  |  | 6,523 |  |  | 5,076 |  |  |  |  |  |
Other, net | 597 |  |  | (128) |  |  | (152) |  |  |  |  |  |
Adjusted EBITDAX (non-GAAP) | 409,049 |  |  | 445,127 |  |  | 401,394 |  |  |  |  |  |
Interest expense | (21,873) |  |  | (23,917) |  |  | (22,459) |  |  |  |  |  |
Interest income | 6,770 |  |  | 6,052 |  |  | 4,702 |  |  |  |  |  |
Income tax expense | (32,069) |  |  | (44,703) |  |  | (55,506) |  |  |  |  |  |
Exploration (1) (2) | (9,539) |  |  | (14,901) |  |  | (8,181) |  |  |  |  |  |
Amortization of deferred financing costs | 1,371 |  |  | 1,372 |  |  | 1,371 |  |  |  |  |  |
Deferred income taxes | 27,391 |  |  | 45,085 |  |  | 49,968 |  |  |  |  |  |
Other, net | (7,412) |  |  | 9,622 |  |  | (13,439) |  |  |  |  |  |
Net change in working capital | (97,688) |  |  | 52,778 |  |  | (26,216) |  |  |  |  |  |
Net cash provided by operating activities (GAAP) | $ | 276,000 |  |  | $ | 476,515 |  |  | $ | 331,634 |  |  |  |  |  |

____________________________________________
(1) 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.
(2) For the three months ended March 31, 2024, amount excludes certain capital expenditures primarily related to one well deemed non-commercial. For three months ended December 31, 2023, amount excludes immaterial non-cash adjustments. For the three months ended March 31, 2023, amount excludes certain capital expenditures primarily related to unsuccessful exploration activity for one well that experienced technical issues during the drilling phase.
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ITEM 3. 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 2 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 I, Item 1 of this report and is incorporated herein by reference. Please also refer to the information under Interest Rate Risk and Commodity Price Risk in Management’s Discussion and Analysis of Financial Condition and Results of Operations in Part II, Item 7 of our 2023 Form 10-K.
ITEM 4. 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 during the first quarter of 2024 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
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PART II. OTHER INFORMATION
ITEM 1. 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 materially adverse effect upon our financial condition, results of operations, or cash flows.
ITEM 1A. RISK FACTORS
There have been no material changes to the risk factors as previously disclosed in our 2023 Form 10-K.
ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS
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 three months ended March 31, 2024, 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:

PURCHASES OF EQUITY SECURITIES BY ISSUER AND AFFILIATED PURCHASES
Period | Total Number of Shares Purchased (1) | Weighted Average Price Paid per Share | Total Number of Shares Purchased as Part of Publicly Announced Program (2) | Maximum Number or Approximate Dollar Value of Shares that May Yet Be Purchased Under the Program (as of the period end date) (2)
01/01/2024 - 01/31/2024 | 609 |  | $ | 35.68 |  | — |  | $ | 214,854,687 |
02/01/2024 - 02/29/2024 | 26,942 |  | $ | 42.88 |  | 26,942 |  | $ | 213,699,355 |
03/01/2024 - 03/31/2024 | 685,293 |  | $ | 46.11 |  | 685,293 |  | $ | 182,101,195 |
Total: | 712,844 |  | $ | 45.98 |  | 712,235 |  |

___________________________________
(1) 609 shares purchased by us in the first quarter of 2024 were to offset tax withholding obligations that occurred upon the delivery of outstanding shares underlying RSUs issued under the terms of award agreements granted under the Equity Plan.
(2) Our Stock Repurchase Program, which authorizes us to repurchase up to $500.0 million in aggregate value of our common stock through December 31, 2024, 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. During the three months ended March 31, 2024, we repurchased and subsequently retired 712,235 shares of our common stock under the Stock Repurchase Program at a weighted-average share price of $45.99 for a total cost of $32.8 million, excluding excise taxes, commissions, and fees.
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.
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ITEM 6. EXHIBITS
The following exhibits are filed or furnished with, or incorporated by reference into this report:

Exhibit Number | Description
3.1 | 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)
3.2 | 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)
3.3 | 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)
31.1* | Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes - Oxley Act of 2002
31.2* | Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes - Oxley Act of 2002
32.1** | Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes - Oxley Act of 2002
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.

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SIGNATURES
Pursuant to the requirements 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.

| SM ENERGY COMPANY
May 3, 2024 | By: | /s/ HERBERT S. VOGEL
|  | Herbert S. Vogel
|  | President and Chief Executive Officer
|  | (Principal Executive Officer)
May 3, 2024 | By: | /s/ A. WADE PURSELL
|  | A. Wade Pursell
|  | Executive Vice President and Chief Financial Officer
|  | (Principal Financial Officer)
May 3, 2024 | By: | /s/ PATRICK A. LYTLE
|  | Patrick A. Lytle
|  | Vice President - Chief Accounting Officer and Controller
|  | (Principal Accounting Officer)

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