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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, 2023
OR
☐ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from ___________ to ___________
Commission File Number 001-31539
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 21, 2023, the registrant had 120,517,918 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 31, 2023, and December 31, 2022 | 4
| Condensed Consolidated Statements of Operations Three Months Ended March 31, 2023, and 2022 | 5
| Condensed Consolidated Statements of Comprehensive Income Three Months Ended March 31, 2023, and 2022 | 6
| Condensed Consolidated Statements of Stockholders’ Equity Three Months Ended March 31, 2023, and 2022 | 7
| Condensed Consolidated Statements of Cash Flows Three Months Ended March 31, 2023, and 2022 | 8
| Notes to Condensed Consolidated Financial Statements | 9
Item 2. | Management’s Discussion and Analysis of Financial Condition and Results of Operations | 18
Item 3. | Quantitative and Qualitative Disclosures About Market Risk | 32
Item 4. | Controls and Procedures | 32
| Part II | 33
Item 1. | Legal Proceedings | 33
Item 1A. | Risk Factors | 33
Item 2. | Unregistered Sales of Equity Securities and Use of Proceeds | 33
Item 6. | Exhibits | 34
| Signatures | 35

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,” “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 impacts of inflation on each of these;
•armed conflict, political instability, or civil unrest in oil and gas producing regions, including the ongoing conflict between Russia and Ukraine, 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 impacted 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, 2022 (“2022 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.
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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, 2023 |  | December 31, 2022
ASSETS |  |  |
Current assets: |  |  |
Cash and cash equivalents | $ | 477,869 |  |  | $ | 444,998 |
Accounts receivable | 187,810 |  |  | 233,297 |
Derivative assets | 81,062 |  |  | 48,677 |
Prepaid expenses and other | 9,535 |  |  | 10,231 |
Total current assets | 756,276 |  |  | 737,203 |
Property and equipment (successful efforts method): |  |  |
Proved oil and gas properties | 10,483,159 |  |  | 10,258,368 |
Accumulated depletion, depreciation, and amortization | (6,339,303) |  |  | (6,188,147) |
Unproved oil and gas properties, net of valuation allowance of $37,904 and $38,008, respectively | 497,127 |  |  | 487,192 |
Wells in progress | 342,875 |  |  | 287,267 |
Other property and equipment, net of accumulated depreciation of $57,338 and $56,512, respectively | 45,694 |  |  | 38,099 |
Total property and equipment, net | 5,029,552 |  |  | 4,882,779 |
Noncurrent assets: |  |  |
Derivative assets | 15,373 |  |  | 24,465 |
Other noncurrent assets | 68,957 |  |  | 71,592 |
Total noncurrent assets | 84,330 |  |  | 96,057 |
Total assets | $ | 5,870,158 |  |  | $ | 5,716,039 |
LIABILITIES AND STOCKHOLDERS’ EQUITY |  |  |
Current liabilities: |  |  |
Accounts payable and accrued expenses | $ | 522,279 |  |  | $ | 532,289 |
Derivative liabilities | 30,723 |  |  | 56,181 |
Other current liabilities | 10,144 |  |  | 10,114 |
Total current liabilities | 563,146 |  |  | 598,584 |
Noncurrent liabilities: |  |  |
Revolving credit facility | — |  |  | — |
Senior Notes, net | 1,572,991 |  |  | 1,572,210 |
Asset retirement obligations | 110,163 |  |  | 108,233 |
Deferred income taxes | 330,782 |  |  | 280,811 |
Derivative liabilities | 3,639 |  |  | 1,142 |
Other noncurrent liabilities | 59,642 |  |  | 69,601 |
Total noncurrent liabilities | 2,077,217 |  |  | 2,031,997 |
Commitments and contingencies (note 6) |  |  |
Stockholders’ equity: |  |  |
Common stock, $0.01 par value - authorized: 200,000,000 shares; issued and outstanding: 120,517,918 and 121,931,676 shares, respectively | 1,205 |  |  | 1,219 |
Additional paid-in capital | 1,743,567 |  |  | 1,779,703 |
Retained earnings | 1,489,032 |  |  | 1,308,558 |
Accumulated other comprehensive loss | (4,009) |  |  | (4,022) |
Total stockholders’ equity | 3,229,795 |  |  | 3,085,458 |
Total liabilities and stockholders’ equity | $ | 5,870,158 |  |  | $ | 5,716,039 |

The accompanying notes are an integral part of these condensed consolidated financial statements.
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SM ENERGY COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (UNAUDITED)
(in thousands, except per share data)

|  |  | For the Three Months Ended March 31,
|  |  |  |  | 2023 |  | 2022
Operating revenues and other income: |  |  |  |  |  |  |
Oil, gas, and NGL production revenue |  |  |  |  | $ | 570,778 |  |  | $ | 858,721 |
Other operating income |  |  |  |  | 2,727 |  |  | 1,055 |
Total operating revenues and other income |  |  |  |  | 573,505 |  |  | 859,776 |
Operating expenses: |  |  |  |  |  |  |
Oil, gas, and NGL production expense |  |  |  |  | 142,348 |  |  | 144,691 |
Depletion, depreciation, amortization, and asset retirement obligation liability accretion |  |  |  |  | 154,189 |  |  | 159,481 |
Exploration |  |  |  |  | 18,428 |  |  | 9,046 |
General and administrative |  |  |  |  | 27,669 |  |  | 24,996 |
Net derivative (gain) loss |  |  |  |  | (51,329) |  |  | 418,521 |
Other operating expense, net |  |  |  |  | 10,153 |  |  | 1,305 |
Total operating expenses |  |  |  |  | 301,458 |  |  | 758,040 |
Income from operations |  |  |  |  | 272,047 |  |  | 101,736 |
Interest expense |  |  |  |  | (22,459) |  |  | (39,387) |
Other non-operating income (expense), net |  |  |  |  | 4,470 |  |  | (724) |
Income before income taxes |  |  |  |  | 254,058 |  |  | 61,625 |
Income tax expense |  |  |  |  | (55,506) |  |  | (12,861) |
Net income |  |  |  |  | $ | 198,552 |  |  | $ | 48,764 |
Basic weighted-average common shares outstanding |  |  |  |  | 121,671 |  |  | 121,907 |
Diluted weighted-average common shares outstanding |  |  |  |  | 122,294 |  |  | 124,179 |
Basic net income per common share |  |  |  |  | $ | 1.63 |  |  | $ | 0.40 |
Diluted net income per common share |  |  |  |  | $ | 1.62 |  |  | $ | 0.39 |
Dividends per common share |  |  |  |  | $ | 0.15 |  |  | $ | 0.01 |

The accompanying notes are an integral part of these condensed consolidated financial statements.
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SM ENERGY COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)
(in thousands)

|  |  | For the Three Months Ended March 31,
|  |  |  |  | 2023 |  | 2022
Net income |  |  |  |  | $ | 198,552 |  |  | $ | 48,764 |
Other comprehensive income, net of tax: |  |  |  |  |  |  |
Pension liability adjustment |  |  |  |  | 13 |  |  | 182 |
Total other comprehensive income, net of tax |  |  |  |  | 13 |  |  | 182 |
Total comprehensive income |  |  |  |  | $ | 198,565 |  |  | $ | 48,946 |

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

|  |  | Additional Paid-in Capital |  |  |  | Accumulated Other Comprehensive Loss |  | Total Stockholders’ Equity
| Common Stock |  |  | Retained Earnings |  |
| Shares |  | Amount |  |  |  |
Balances, December 31, 2021 | 121,862,248 |  |  | $ | 1,219 |  |  | $ | 1,840,228 |  |  | $ | 234,533 |  |  | $ | (12,849) |  |  | $ | 2,063,131 |
Net income | — |  |  | — |  |  | — |  |  | 48,764 |  |  | — |  |  | 48,764 |
Other comprehensive income | — |  |  | — |  |  | — |  |  | — |  |  | 182 |  |  | 182 |
Cash dividends declared, $0.01 per share | — |  |  | — |  |  | — |  |  | (1,218) |  |  | — |  |  | (1,218) |
Issuance of common stock upon vesting of RSUs, net of shares used for tax withholdings | 1,929 |  |  | — |  |  | (24) |  |  | — |  |  | — |  |  | (24) |
Stock-based compensation expense | — |  |  | — |  |  | 4,274 |  |  | — |  |  | — |  |  | 4,274 |
Balances, March 31, 2022 | 121,864,177 |  |  | $ | 1,219 |  |  | $ | 1,844,478 |  |  | $ | 282,079 |  |  | $ | (12,667) |  |  | $ | 2,115,109 |

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,
| 2023 |  | 2022
Cash flows from operating activities: |  |  |
Net income | $ | 198,552 |  |  | $ | 48,764 |
Adjustments to reconcile net income to net cash provided by operating activities: |  |
Depletion, depreciation, amortization, and asset retirement obligation liability accretion | 154,189 |  |  | 159,481 |
Stock-based compensation expense | 4,318 |  |  | 4,274 |
Net derivative (gain) loss | (51,329) |  |  | 418,521 |
Derivative settlement gain (loss) | 5,076 |  |  | (168,183) |
Amortization of debt discount and deferred financing costs | 1,371 |  |  | 4,010 |
Deferred income taxes | 49,968 |  |  | 11,948 |
Other, net | (4,295) |  |  | 1,239 |
Net change in working capital | (26,216) |  |  | (137,962) |
Net cash provided by operating activities | 331,634 |  |  | 342,092 |
Cash flows from investing activities: |  |  |
Capital expenditures | (240,712) |  |  | (150,127) |
Other, net | 307 |  |  | — |
Net cash used in investing activities | (240,405) |  |  | (150,127) |
Cash flows from financing activities: |  |  |
Cash paid to repurchase Senior Notes | — |  |  | (104,770) |
Repurchase of common stock | (40,068) |  |  | — |
Dividends paid | (18,290) |  |  | — |
Other, net | — |  |  | (24) |
Net cash used in financing activities | (58,358) |  |  | (104,794) |
Net change in cash, cash equivalents, and restricted cash | 32,871 |  |  | 87,171 |
Cash, cash equivalents, and restricted cash at beginning of period | 444,998 |  |  | 332,716 |
Cash, cash equivalents, and restricted cash at end of period | $ | 477,869 |  |  | $ | 419,887 |
Supplemental schedule of additional cash flow information: |  |
Operating activities: |  |  |
Cash paid for interest, net of capitalized interest | $ | (33,882) |  |  | $ | (64,204) |
Investing activities: |  |  |
Increase in capital expenditure accruals and other | $ | 66,873 |  |  | $ | 15,627 |

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 2022 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, 2023, 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 2022 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 2022 Form 10-K.
Recently Issued Accounting Standards
As of March 31, 2023, and through the filing of this report, no Accounting Standards Updates have been issued and not yet adopted that are applicable to the Company and that would have a material effect on the Company’s unaudited condensed consolidated financial statements and related disclosures.
Note 2 - Revenue from Contracts with Customers
The Company recognizes its share of revenue from the sale of produced oil, gas, and NGLs from its Midland Basin and South Texas assets. Oil, gas, and NGL production revenue presented within the accompanying unaudited condensed consolidated statements of operations (“accompanying statements of operations”) is reflective of the 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 for the three months ended March 31, 2023, and 2022:

| Midland Basin |  | South Texas |  | Total
| Three Months Ended March 31, |  | Three Months Ended March 31, |  | Three Months Ended March 31,
| 2023 |  | 2022 |  | 2023 |  | 2022 |  | 2023 |  | 2022
| (in thousands)
Oil production revenue | $ | 320,135 |  | $ | 493,895 |  | $ | 100,703 |  | $ | 113,407 |  | $ | 420,838 |  | $ | 607,302
Gas production revenue | 49,789 |  | 102,273 |  | 43,942 |  | 67,776 |  | 93,731 |  | 170,049
NGL production revenue | 177 |  | 152 |  | 56,032 |  | 81,218 |  | 56,209 |  | 81,370
Total | $ | 370,101 |  | $ | 596,320 |  | $ | 200,677 |  | $ | 262,401 |  | $ | 570,778 |  | $ | 858,721
Relative percentage | 65 | % |  | 69 | % |  | 35 | % |  | 31 | % |  | 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 differs depending on the applicable contractual terms. Transfer of control drives the
9

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 control transfer 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 is impacted 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, 2023, and December 31, 2022, were $146.2 million and $184.5 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.
Please refer to Note 1 - Summary of Significant Accounting Policies and Note 2 - Revenue from Contracts with Customers in the 2022 Form 10-K for more information regarding the Company’s revenue recognition policy and the application of the guidance in Accounting Standards Codification Topic 606, Revenue from Contracts with Customers, and for more information regarding the types of contracts under which oil, gas, and NGL production revenue is generated.
Note 3 - Equity
Stock Repurchase Program
During 2022, the Company’s Board of Directors approved a stock repurchase program authorizing 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 2022 Form 10-K for additional information regarding the Company’s Stock Repurchase Program.
During the three months ended March 31, 2023, the Company utilized net cash provided by operating activities to repurchase and subsequently retire 1,413,758 shares of its common stock at a weighted-average share price of $28.32 for a total cost of $40.0 million, excluding taxes, commissions, and fees. As of March 31, 2023, $402.8 million remained available for repurchases of the Company’s outstanding common stock under the Stock Repurchase Program.
Note 4 - Income Taxes
The provision for income taxes for the three months ended March 31, 2023, and 2022, consists of the following:

|  |  | For the Three Months Ended March 31,
|  |  |  |  | 2023 |  | 2022
|  |  |  |  | (in thousands)
Current portion of income tax expense: |  |  |  |  |  |  |
Federal |  |  |  |  | $ | (4,998) |  | $ | (609)
State |  |  |  |  | (540) |  | (304)
Deferred portion of income tax expense |  |  |  |  | (49,968) |  | (11,948)
Income tax expense |  |  |  |  | $ | (55,506) |  | $ | (12,861)
Effective tax rate |  |  |  |  | 21.8 | % |  | 20.9 | %

Recorded income tax expense or benefit differs from the amount that would be provided 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 state income taxes, excess tax benefits and deficiencies from stock-based compensation awards, tax deduction limitations on the compensation of covered individuals, changes in valuation allowances, the cumulative effect of other smaller permanent differences, and can also reflect
10

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 Company commissioned a multi-year research and development (“R&D”) credit study in 2022, which is expected to be completed in late 2023, and is expected to favorably impact the Company’s effective tax rate and future tax obligations when the results are recorded. The Company’s policy is to not record an R&D credit until it is claimed on a filed tax return, which had not occurred as of the filing of this report.
For all years before 2019, the Company is generally no longer subject to United States federal or state income tax examinations by tax authorities.
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, 2023, the borrowing base and aggregate lender commitments under the Credit Agreement were $2.5 billion and $1.25 billion, respectively. Subsequent to March 31, 2023, 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, 2023. 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 2022 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 21, 2023, March 31, 2023, and December 31, 2022:

| As of April 21, 2023 |  | As of March 31, 2023 |  | As of December 31, 2022
| (in thousands)
Revolving credit facility (1) | $ | — |  |  | $ | — |  |  | $ | — |
Letters of credit (2) | 6,000 |  |  | 6,000 |  |  | 6,000 |
Available borrowing capacity | 1,244,000 |  |  | 1,244,000 |  |  | 1,244,000 |
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 $10.2 million and $10.8 million as of March 31, 2023, and December 31, 2022, 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.
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Senior Notes
The Company’s Senior Notes, net line item on the accompanying balance sheets as of March 31, 2023, and December 31, 2022, consists of the following (collectively referred to as “Senior Notes”):

| As of March 31, 2023 |  | As of December 31, 2022
| 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 |  |  | $ | 1,369 |  |  | $ | 347,749 |  |  | $ | 349,118 |  |  | $ | 1,528 |  |  | $ | 347,590 |
6.75% Senior Notes due 2026 | 419,235 |  |  | 2,394 |  |  | 416,841 |  |  | 419,235 |  |  | 2,569 |  | 416,666 |
6.625% Senior Notes due 2027 | 416,791 |  |  | 2,978 |  |  | 413,813 |  |  | 416,791 |  |  | 3,172 |  | 413,619 |
6.5% Senior Notes due 2028 | 400,000 |  |  | 5,412 |  |  | 394,588 |  |  | 400,000 |  |  | 5,665 |  |  | 394,335 |
Total | $ | 1,585,144 |  |  | $ | 12,153 |  |  | $ | 1,572,991 |  |  | $ | 1,585,144 |  |  | $ | 12,934 |  |  | $ | 1,572,210 |

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 based on a premium, plus accrued and unpaid interest as described in the indentures governing the Senior Notes.
On February 14, 2022, the Company redeemed the remaining $104.8 million of aggregate principal amount outstanding of its 5.0% Senior Notes due 2024 (“2024 Senior Notes”), with cash on hand, pursuant to the terms of the indenture governing the 2024 Senior Notes which provided for a redemption price equal to 100 percent of the principal amount of the 2024 Senior Notes on the date of redemption, plus accrued and unpaid interest. The Company canceled all redeemed 2024 Senior Notes upon settlement.
Please refer to Note 5 - Long-Term Debt in the 2022 Form 10-K for additional detail on the Company’s Senior Notes.
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, and merge or consolidate with other entities. The Company was in compliance with all financial and non-financial covenants as of March 31, 2023, and through the filing of this report. Please refer to Note 5 - Long-Term Debt in the 2022 Form 10-K for additional detail on the Company’s covenants under the Credit Agreement and indentures governing the Senior Notes.
Capitalized Interest
Capitalized interest costs for the three months ended March 31, 2023, and 2022, totaled $5.5 million and $3.0 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 2022 Form 10-K. Please refer to Note 6 - Commitments and Contingencies in the 2022 Form 10-K for additional discussion of the Company’s commitments.
Drilling Rig Service Contracts. During the three months ended March 31, 2023, and through the filing of this report, the Company amended certain of its drilling rig contracts resulting in the increase of day rates and potential early termination fees, and the extension of contract terms. As of the filing of this report, the Company’s drilling rig commitments totaled $30.3 million under contract terms extending through the second quarter of 2024. If all of these contracts were terminated as of the filing of this report, the Company would avoid a portion of the contractual service commitments; however, the Company would be required to pay $18.8 million in early termination fees. No early termination penalties or standby fees were incurred by the Company during the three months ended
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March 31, 2023, and the Company does not expect to incur material penalties with regard to its drilling rig contracts during the remainder of 2023.
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. 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 impact on cash flows. As of March 31, 2023, and through the filing of this report, all contracts were entered into 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, 2023, the Company had basis swap contracts with fixed price differentials between:
•NYMEX WTI and Argus WTI Midland for a portion of its Midland Basin oil production with sales contracts that settle at Argus WTI Midland prices;
•NYMEX WTI and Argus WTI Houston Magellan East Houston Terminal (“MEH”) for a portion of its South Texas oil production with sales contracts that settle at Argus WTI Houston MEH (“WTI Houston MEH”) prices;
•NYMEX HH and Inside FERC Houston Ship Channel (“IF HSC”) for a portion of its South Texas gas production with sales contracts that settle at IF HSC prices; 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.
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As of March 31, 2023, the Company had commodity derivative contracts outstanding through the fourth quarter of 2025 as summarized in the table below:

|  | Contract Period |  |  |  |  |  |
|  | Second Quarter 2023 |  | Third Quarter 2023 |  | Fourth Quarter 2023 |  | 2024 |  | 2025 |  |  |  |  |  |
Oil Derivatives (volumes in MBbl and prices in $ per Bbl): |  |  |  |
Swaps |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
NYMEX WTI Volumes |  | 333 |  |  | 607 |  |  | 546 |  |  | — |  |  | — |  |  |  |  |  |  |
Weighted-Average Contract Price |  | $ | 45.18 |  |  | $ | 59.77 |  |  | $ | 60.00 |  |  | $ | — |  |  | $ | — |  |  |  |  |  |  |
ICE Brent Volumes |  | 910 |  |  | 920 |  |  | 920 |  |  | 910 |  |  | — |  |  |  |  |  |  |
Weighted-Average Contract Price |  | $ | 86.50 |  |  | $ | 86.50 |  |  | $ | 86.50 |  |  | $ | 85.50 |  |  | $ | — |  |  |  |  |  |  |
Collars |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
NYMEX WTI Volumes |  | 464 |  |  | 291 |  |  | — |  |  | 919 |  |  | — |  |  |  |  |  |  |
Weighted-Average Floor Price |  | $ | 67.85 |  |  | $ | 75.00 |  |  | $ | — |  |  | $ | 75.00 |  |  | $ | — |  |  |  |  |  |  |
Weighted-Average Ceiling Price |  | $ | 81.53 |  |  | $ | 93.05 |  |  | $ | — |  |  | $ | 81.47 |  |  | $ | — |  |  |  |  |  |  |
Basis Swaps |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
WTI Midland-NYMEX WTI Volumes |  | 1,357 |  |  | 1,414 |  |  | 1,294 |  |  | 2,961 |  |  | — |  |  |  |  |  |  |
Weighted-Average Contract Price |  | $ | 0.99 |  |  | $ | 0.88 |  |  | $ | 0.88 |  |  | $ | 1.17 |  |  | $ | — |  |  |  |  |  |  |
WTI Houston MEH-NYMEX WTI Volumes |  | 431 |  |  | 361 |  |  | 296 |  |  | 877 |  |  | — |  |  |  |  |  |  |
Weighted-Average Contract Price |  | $ | 1.68 |  |  | $ | 1.59 |  |  | $ | 1.53 |  |  | $ | 1.85 |  |  | $ | — |  |  |  |  |  |  |
Roll Differential Swaps |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
NYMEX WTI Volumes |  | 1,243 |  |  | 1,304 |  |  | 1,201 |  |  | 2,188 |  |  | — |  |  |  |  |  |  |
Weighted-Average Contract Price |  | $ | 0.62 |  |  | $ | 0.64 |  |  | $ | 0.62 |  |  | $ | 0.42 |  |  | $ | — |  |  |  |  |  |  |
Gas Derivatives (volumes in BBtu and prices in $ per MMBtu): |  |  |  |
Swaps |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
NYMEX HH Volumes |  | 1,420 |  |  | 1,470 |  |  | — |  |  | — |  |  | — |  |  |  |  |  |  |
Weighted-Average Contract Price |  | $ | 5.05 |  |  | $ | 5.11 |  |  | $ | — |  |  | $ | — |  |  | $ | — |  |  |  |  |  |  |
Collars |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
NYMEX HH Volumes |  | 5,181 |  |  | 6,194 |  |  | 8,362 |  |  | 19,457 |  |  | — |  |  |  |  |  |  |
Weighted-Average Floor Price |  | $ | 3.83 |  |  | $ | 3.75 |  |  | $ | 3.90 |  |  | $ | 3.71 |  |  | $ | — |  |  |  |  |  |  |
Weighted-Average Ceiling Price |  | $ | 4.68 |  |  | $ | 4.62 |  |  | $ | 5.70 |  |  | $ | 5.89 |  |  | $ | — |  |  |  |  |  |  |
IF HSC Volumes |  | 1,345 |  |  | 1,389 |  |  | 1,451 |  |  | — |  |  | — |  |  |  |  |  |  |
Weighted-Average Floor Price |  | $ | 4.25 |  |  | $ | 4.25 |  |  | $ | 4.25 |  |  | $ | — |  |  | $ | — |  |  |  |  |  |  |
Weighted-Average Ceiling Price |  | $ | 5.00 |  |  | $ | 4.95 |  |  | $ | 5.55 |  |  | $ | — |  |  | $ | — |  |  |  |  |  |  |
Basis Swaps |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
IF Waha-NYMEX HH Volumes |  | 2,462 |  |  | 2,442 |  |  | 2,337 |  |  | 20,958 |  |  | 20,501 |  |  |  |  |  |  |
Weighted-Average Contract Price |  | $ | (1.93) |  |  | $ | (1.05) |  |  | $ | (1.01) |  |  | $ | (0.86) |  |  | $ | (0.66) |  |  |  |  |  |  |
IF HSC-NYMEX HH Volumes |  | 1,774 |  |  | 1,813 |  |  | 2,008 |  |  | 10,208 |  |  | — |  |  |  |  |  |  |
Weighted-Average Contract Price |  | $ | (0.25) |  |  | $ | (0.25) |  |  | $ | (0.25) |  |  | $ | (0.33) |  |  | $ | — |  |  |  |  |  |  |
NGL Derivatives (volumes in MBbl and prices in $ per Bbl): |  |  |  |
Swaps |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
OPIS Propane Mont Belvieu Non-TET Volumes |  | 182 |  |  | 181 |  |  | 187 |  |  | — |  |  | — |  |  |  |  |  |  |
Weighted-Average Contract Price |  | $ | 36.66 |  |  | $ | 36.67 |  |  | $ | 36.66 |  |  | $ | — |  |  | $ | — |  |  |  |  |  |  |

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Commodity Derivative Contracts Entered Into Subsequent to March 31, 2023
Subsequent to March 31, 2023, the Company entered into NYMEX WTI price swap contracts for the fourth quarter of 2023 for a total of 0.3 MMBbl of oil production at a contract price of $77.00 per Bbl and NYMEX HH price swap contracts for 2025 for a total of 5,891 BBtu of gas production at a weighted-average contract price of $4.20 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 the commodity derivative contracts was a net asset of $62.1 million and $15.8 million as of March 31, 2023, and December 31, 2022, respectively.
The following table details the fair value of commodity derivative contracts recorded in the accompanying balance sheets, by category:

| As of March 31, 2023 |  | As of December 31, 2022
| (in thousands)
Derivative assets: |  |  |
Current assets | $ | 81,062 |  |  | $ | 48,677 |
Noncurrent assets | 15,373 |  |  | 24,465 |
Total derivative assets | $ | 96,435 |  |  | $ | 73,142 |
Derivative liabilities: |  |  |
Current liabilities | $ | 30,723 |  |  | $ | 56,181 |
Noncurrent liabilities | 3,639 |  |  | 1,142 |
Total derivative liabilities | $ | 34,362 |  |  | $ | 57,323 |

Offsetting of Derivative Assets and Liabilities
As of March 31, 2023, and December 31, 2022, 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, 2023 |  | December 31, 2022 |  | March 31, 2023 |  | December 31, 2022
| (in thousands)
Gross amounts presented in the accompanying balance sheets | $ | 96,435 |  |  | $ | 73,142 |  |  | $ | (34,362) |  |  | $ | (57,323) |
Amounts not offset in the accompanying balance sheets | (25,293) |  |  | (26,136) |  |  | 25,293 |  |  | 26,136 |
Net amounts | $ | 71,142 |  |  | $ | 47,006 |  |  | $ | (9,069) |  |  | $ | (31,187) |

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The following table summarizes the commodity components of the derivative settlement (gain) loss, 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,
|  |  |  |  | 2023 |  | 2022
|  |  |  |  | (in thousands)
Derivative settlement (gain) loss: |  |  |  |  |  |  |
Oil contracts |  |  |  |  | $ | 6,226 |  |  | $ | 129,168 |
Gas contracts |  |  |  |  | (11,302) |  |  | 27,051 |
NGL contracts |  |  |  |  | — |  |  | 11,964 |
Total derivative settlement (gain) loss |  |  |  |  | $ | (5,076) |  |  | $ | 168,183 |
Net derivative (gain) loss: |  |  |  |  |  |  |
Oil contracts |  |  |  |  | $ | (29,167) |  |  | $ | 315,050 |
Gas contracts |  |  |  |  | (20,778) |  |  | 86,175 |
NGL contracts |  |  |  |  | (1,384) |  |  | 17,296 |
Total net derivative (gain) loss |  |  |  |  | $ | (51,329) |  |  | $ | 418,521 |

Credit Related Contingent Features
As of March 31, 2023, all of the Company’s derivative counterparties were members of the 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, 2023 |  | As of December 31, 2022
| Level 1 |  | Level 2 |  | Level 3 |  | Level 1 |  | Level 2 |  | Level 3
| (in thousands)
Assets: |  |  |  |  |  |  |  |  |  |  |
Derivatives (1) | $ | — |  |  | $ | 96,435 |  |  | $ | — |  |  | $ | — |  |  | $ | 73,142 |  |  | $ | — |
Liabilities: |  |  |  |  |  |  |  |  |  |  |
Derivatives (1) | $ | — |  |  | $ | 34,362 |  |  | $ | — |  |  | $ | — |  |  | $ | 57,323 |  |  | $ | — |

__________________________________________
(1) This represents a financial asset or liability that is measured at fair value on a recurring basis.
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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 derivatives. 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 in this report, and to Note 8 - Fair Value Measurements and Note 10 - Derivative Financial Instruments in the 2022 Form 10-K 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, 2023, or December 31, 2022, as they were recorded at carrying value, net of any unamortized deferred financing costs. Please refer to Note 5 - Long-Term Debt above for additional information.

| As of March 31, 2023 |  | As of December 31, 2022
| Principal Amount |  | Fair Value |  | Principal Amount |  | Fair Value
| (in thousands)
5.625% Senior Notes due 2025 | $ | 349,118 |  |  | $ | 339,207 |  |  | $ | 349,118 |  |  | $ | 337,821 |
6.75% Senior Notes due 2026 | $ | 419,235 |  |  | $ | 411,898 |  |  | $ | 419,235 |  |  | $ | 409,484 |
6.625% Senior Notes due 2027 | $ | 416,791 |  |  | $ | 404,466 |  |  | $ | 416,791 |  |  | $ | 402,120 |
6.5% Senior Notes due 2028 | $ | 400,000 |  |  | $ | 386,660 |  |  | $ | 400,000 |  |  | $ | 384,520 |

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 (“RSUs”) and contingent performance share units (“PSUs”), which were measured using the treasury stock method. Please refer to Note 7 - Compensation Plans and Note 9 - Earnings Per Share in the 2022 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,
|  |  |  |  | 2023 |  | 2022
|  |  |  |  | (in thousands, except per share data)
Net income |  |  |  |  | $ | 198,552 |  |  | $ | 48,764 |
Basic weighted-average common shares outstanding |  |  |  |  | 121,671 |  | 121,907
Dilutive effect of non-vested RSUs, contingent PSUs, and other |  |  |  |  | 623 |  | 2,272
Diluted weighted-average common shares outstanding |  |  |  |  | 122,294 |  | 124,179
Basic net income per common share |  |  |  |  | $ | 1.63 |  |  | $ | 0.40 |
Diluted net income per common share |  |  |  |  | $ | 1.62 |  |  | $ | 0.39 |

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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, 2023, and the three months ended December 31, 2022 (“sequential quarterly” or “sequentially”), as well as the year-to-date (“YTD”) change between the three months ended March 31, 2023, and the three months ended March 31, 2022 (“YTD 2023-over-YTD 2022”).
Overview of the Company
General Overview
Our strategy is to be a premier operator of top-tier oil and gas assets. 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 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 is to sustainably grow value for all of our stakeholders by maintaining and optimizing our high-quality asset portfolio, generating cash flows, and maintaining a strong balance sheet. Our near-term goals include returning value to stockholders through our Stock Repurchase Program and fixed dividend payments, and focusing on continued operational excellence.
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 are capable of generating strong returns in the current macroeconomic environment, and present resilience to commodity price risk and volatility. We remain focused on maximizing returns and increasing the value of our top-tier assets through continued development and optimization of our Midland Basin assets and through continued development and delineation of the Austin Chalk formation in South Texas. We believe that our high-quality asset base provides for a sustainable approach to prioritizing operational execution, maintaining a strong balance sheet, generating cash flows, returning capital to stockholders, and maintaining strong 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 development and implementation of the Company’s ESG policies, programs and initiatives, 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.
Global commodity and financial markets remain subject to heightened levels of uncertainty and volatility as a result of inflation, disruptions resulting from recent bank failures, and the ongoing conflict between Russia and Ukraine and associated economic and trade sanctions on Russia. These circumstances have driven commodity price volatility and have contributed to increased service provider and other costs, instances of supply chain disruptions, and a rise 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 2022 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 increased returns and cash flow generation.
Areas of Operations
Our Midland Basin assets are comprised of approximately 87,000 net acres located in the Permian Basin in West Texas (“Midland Basin”). In the first quarter of 2023, drilling and completion activities within our RockStar and Sweetie Peck positions continued to focus primarily on development optimization of our Midland Basin position. 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 the Maverick Basin in Dimmit and Webb Counties, Texas (“South Texas”). In the first quarter of 2023, our operations in South Texas were focused on production from both the Austin Chalk formation and Eagle Ford shale formation, development of the Eagle Ford shale formation, and development and further delineation of the Austin Chalk formation. Our overlapping acreage position in the Maverick Basin 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 2023 Overview and Outlook for the Remainder of 2023
During the first quarter of 2023, we remained focused on returning value to our stockholders through our Stock Repurchase Program and fixed quarterly dividend payments. During the three months ended March 31, 2023, we repurchased and subsequently retired 1,413,758 shares of our outstanding common stock at a cost of $40.0 million, excluding taxes, commissions, and fees. During the first quarter of 2023, we declared quarterly dividends of $0.15 per share totaling $18.1 million. Please refer to Note 3 - Equity in Part I, Item 1 of this report for additional discussion regarding our Stock Repurchase Program.
Our total 2023 capital program is expected to be approximately $1.1 billion, exclusive of acquisitions, and will remain focused on our highly economic oil development projects in both our Midland Basin and South Texas assets. During 2023, we expect to repeat our track record of inventory replacement and growth and to continue applying our strength in geosciences and development optimization. We believe that our high-quality asset portfolio is capable of generating strong returns in the current macroeconomic environment, which we expect will enable us to maintain cash flows and financial flexibility. Please refer to Overview of Liquidity and Capital Resources below for discussion of how we expect to fund the remainder of our 2023 capital program.
Financial and Operational Results. Average net daily equivalent production for the three months ended March 31, 2023, increased two percent sequentially to 146.4 MBOE, consisting of a 10 percent increase from our South Texas assets partially offset by a four percent decrease from our Midland Basin assets. These changes are a result of the timing of well completions.
Oil and gas realized prices, before the effect of derivative settlements (“realized price” or “realized prices”), decreased sequentially by 10 percent and 36 percent, respectively, as a result of decreases in benchmark commodity prices during the first quarter of 2023. Realized price for NGLs remained flat sequentially. Total realized price per BOE decreased 15 percent sequentially, resulting in a 15 percent decrease in oil, gas, and NGL production revenue, which was $570.8 million for the three months ended March 31, 2023, compared with $669.3 million for the three months ended December 31, 2022. Oil, gas, and NGL production expense of $10.80 per BOE for the three months ended March 31, 2023, decreased six percent sequentially, primarily as a result of decreases in production tax expense per BOE and ad valorem tax expense per BOE.
We recorded a net derivative gain of $51.3 million for the three months ended March 31, 2023, compared with a net derivative gain of $11.2 million for the three months ended December 31, 2022. Included within these amounts are a derivative settlement gain of $5.1 million for the three months ended March 31, 2023, and a derivative settlement loss of $115.6 million for the three months ended December 31, 2022.
Operational and financial activities during the three months ended March 31, 2023, resulted in the following:
•Net cash provided by operating activities of $331.6 million for the three months ended March 31, 2023, compared with $288.4 million for the three months ended December 31, 2022.
•Net income of $198.6 million, or $1.62 per diluted share, for the three months ended March 31, 2023, compared with net income of $258.5 million, or $2.09 per diluted share, for the three months ended December 31, 2022.
•Adjusted EBITDAX, a non-GAAP financial measure, for the three months ended March 31, 2023, of $401.4 million, compared with $373.9 million for the three months ended December 31, 2022. 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, 2023, and December 31, 2022, and Between the Three Months Ended March 31, 2023, and 2022 below for additional discussion.
Operational Activities. In our Midland Basin program, we operated three drilling rigs and averaged two completion crews, drilled eight gross (seven net) wells, and completed 12 gross (10 net) wells during the first quarter of 2023. Average net daily equivalent production volumes decreased sequentially by four percent to 74.0 MBOE. Costs incurred in our Midland Basin program during the three months ended March 31, 2023, totaled $174.0 million, or 56 percent of our total costs incurred for the period. During the remainder of 2023, we anticipate operating three drilling rigs and averaging one completion crew. We expect our activity to focus primarily on developing the Spraberry and Wolfcamp formations within our RockStar and Sweetie Peck positions.
In our South Texas program, we operated two drilling rigs and one completion crew, drilled seven gross (seven net) wells, and completed 17 gross (16 net) wells during the first quarter of 2023. Average net daily equivalent production volumes increased sequentially by 10 percent to 72.5 MBOE. Costs incurred in our South Texas program during the three months ended March 31, 2023, totaled $125.6 million, or 41 percent of our total costs incurred for the period. During the remainder of 2023, we anticipate operating two drilling rigs and one completion crew, 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, 2023:

| Midland Basin |  | South Texas (1) |  | Total
| Gross |  | Net |  | Gross |  | Net |  | Gross |  | Net
Wells drilled but not completed at December 31, 2022 (2) | 49 |  |  | 40 |  |  | 29 |  |  | 28 |  |  | 78 |  |  | 69 |
Wells drilled | 8 |  |  | 7 |  |  | 7 |  |  | 7 |  |  | 15 |  |  | 14 |
Wells completed | (12) |  |  | (10) |  |  | (17) |  |  | (16) |  |  | (29) |  |  | (26) |
Wells drilled but not completed at March 31, 2023 (2) | 45 |  |  | 37 |  |  | 19 |  |  | 19 |  |  | 64 |  |  | 56 |

____________________________________________
(1) The South Texas drilled but not completed well count as of December 31, 2022, included nine gross (nine net) wells that were not included in our five-year development plan as of December 31, 2022, eight of which were in the Eagle Ford shale formation.
(2) Amounts may not calculate due to rounding.
Costs Incurred. Costs incurred in oil and gas property acquisition, exploration, and development activities, whether capitalized or expensed, totaled $308.7 million for the three months ended March 31, 2023, and were primarily incurred in our Midland Basin and South Texas programs as further detailed in Operational Activities above.
Production Results. The table below presents our production by product type for each of our assets for the three months ended March 31, 2023, December 31, 2022, and March 31, 2022:

| For the Three Months Ended
| March 31, 2023 |  | December 31, 2022 |  |  |  | March 31, 2022
Midland Basin Production: |  |  |  |  |  |  |
Oil (MMBbl) | 4.2 |  |  | 4.4 |  |  |  |  | 5.3 |
Gas (Bcf) | 14.5 |  |  | 15.9 |  |  |  |  | 15.5 |
NGLs (MMBbl) | — |  |  | — |  |  |  |  | — |
Equivalent (MMBOE) | 6.7 |  |  | 7.1 |  |  |  |  | 7.9 |
Average net daily equivalent (MBOE per day) | 74.0 |  |  | 77.0 |  |  |  |  | 87.4 |
Relative percentage | 51 | % |  | 54 | % |  |  |  | 57 | %
South Texas Production: |  |  |  |  |  |  |
Oil (MMBbl) | 1.4 |  |  | 1.3 |  |  |  |  | 1.2 |
Gas (Bcf) | 17.8 |  |  | 16.2 |  |  |  |  | 15.9 |
NGLs (MMBbl) | 2.1 |  |  | 2.1 |  |  |  |  | 2.1 |
Equivalent (MMBOE) | 6.5 |  |  | 6.1 |  |  |  |  | 5.9 |
Average net daily equivalent (MBOE per day) | 72.5 |  |  | 65.9 |  |  |  |  | 65.8 |
Relative percentage | 49 | % |  | 46 | % |  |  |  | 43 | %
Total Production: |  |  |  |  |  |  |
Oil (MMBbl) | 5.7 |  |  | 5.7 |  |  |  |  | 6.5 |
Gas (Bcf) | 32.2 |  |  | 32.1 |  |  |  |  | 31.4 |
NGLs (MMBbl) | 2.1 |  |  | 2.1 |  |  |  |  | 2.1 |
Equivalent (MMBOE) | 13.2 |  |  | 13.1 |  |  |  |  | 13.8 |
Average net daily equivalent (MBOE per day) | 146.4 |  |  | 142.9 |  |  |  |  | 153.3 |

____________________________________________
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, 2023, and December 31, 2022, and Between the Three Months Ended March 31, 2023, and 2022 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 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 derivative settlements, for the three months ended March 31, 2023, December 31, 2022, and March 31, 2022:

| For the Three Months Ended
| March 31, 2023 |  | December 31, 2022 |  | March 31, 2022
Oil (per Bbl): |  |  |  |  |
Average NYMEX contract monthly price | $ | 76.13 |  |  | $ | 82.64 |  |  | $ | 94.29 |
Realized price | $ | 74.31 |  |  | $ | 82.35 |  |  | $ | 94.03 |
Effect of oil derivative settlements | $ | (1.10) |  |  | $ | (15.04) |  |  | $ | (20.00) |
Gas: |  |  |  |  |
Average NYMEX monthly settle price (per MMBtu) | $ | 3.42 |  |  | $ | 6.26 |  |  | $ | 4.95 |
Realized price (per Mcf) | $ | 2.91 |  |  | $ | 4.52 |  |  | $ | 5.42 |
Effect of gas derivative settlements (per Mcf) | $ | 0.35 |  |  | $ | (0.91) |  |  | $ | (0.86) |
NGLs (per Bbl): |  |  |  |  |
Average OPIS price (1) | $ | 30.95 |  |  | $ | 33.03 |  |  | $ | 48.36 |
Realized price | $ | 26.24 |  |  | $ | 26.10 |  |  | $ | 38.56 |
Effect of NGL derivative settlements | $ | — |  |  | $ | (0.27) |  |  | $ | (5.67) |

____________________________________________
(1) Effective January 1, 2023, 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. For periods prior to 2023, average OPIS price per barrel of NGL, historical or strip, assumed a composite barrel product mix of 37% Ethane, 32% Propane, 6% Isobutane, 11% Normal Butane, and 14% Natural Gasoline. These product mixes represent the industry standard composite barrel for the respective periods presented and do not necessarily represent our product mix for NGL production. Realized prices reflect our actual product mix.
Given the uncertainty surrounding global financial markets, the ongoing conflict between Russia and Ukraine, the economic and trade sanctions that certain countries have imposed on Russia, production output from the Organization of the Petroleum Exporting Countries (“OPEC”) plus other non-OPEC oil producing countries (collectively referred to as “OPEC+”), 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, a continued rise 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 in the areas of our operations and beyond.
The following table summarizes 12-month strip prices for NYMEX WTI oil, NYMEX Henry Hub gas, and OPIS NGLs as of April 21, 2023, and March 31, 2023:

| As of April 21, 2023 |  | As of March 31, 2023
NYMEX WTI oil (per Bbl) | $ | 75.93 |  |  | $ | 74.45 |
NYMEX Henry Hub gas (per MMBtu) | $ | 3.03 |  |  | $ | 3.00 |
OPIS NGLs (per Bbl) | $ | 28.97 |  |  | $ | 28.73 |

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 of our 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
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exposure to volatility in commodity prices and basis differentials in the near term. Our use of costless collars for a portion of our derivatives allows us to participate in some of the upward movements in oil and gas prices while also setting a price floor below which we are insulated from further price decreases. 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, 2023, and the preceding three quarters:

| For the Three Months Ended
| March 31, |  | December 31, |  | September 30, |  | June 30,
| 2023 |  | 2022 |  | 2022 |  | 2022
| (in millions)
Production (MMBOE) | 13.2 |  |  | 13.1 |  |  | 12.7 |  |  | 13.3 |
Oil, gas, and NGL production revenue | $ | 570.8 |  |  | $ | 669.3 |  |  | $ | 827.6 |  |  | $ | 990.4 |
Oil, gas, and NGL production expense | $ | 142.3 |  |  | $ | 150.7 |  |  | $ | 160.0 |  |  | $ | 165.6 |
Depletion, depreciation, amortization, and asset retirement obligation liability accretion | $ | 154.2 |  |  | $ | 143.6 |  |  | $ | 145.9 |  |  | $ | 154.8 |
Exploration | $ | 18.4 |  |  | $ | 10.8 |  |  | $ | 14.2 |  |  | $ | 20.9 |
General and administrative | $ | 27.7 |  |  | $ | 32.8 |  |  | $ | 28.4 |  |  | $ | 28.3 |
Net income | $ | 198.6 |  |  | $ | 258.5 |  |  | $ | 481.2 |  |  | $ | 323.5 |

____________________________________________
Note: Amounts may not calculate due to rounding.
Selected Performance Metrics

| For the Three Months Ended
| March 31, |  | December 31, |  | September 30, |  | June 30,
| 2023 |  | 2022 |  | 2022 |  | 2022
Average net daily equivalent production (MBOE per day) | 146.4 |  |  | 142.9 |  |  | 137.8 |  |  | 146.6 |
Lease operating expense (per BOE) | $ | 5.16 |  |  | $ | 5.20 |  |  | $ | 5.64 |  |  | $ | 5.11 |
Transportation costs (per BOE) | $ | 2.81 |  |  | $ | 2.86 |  |  | $ | 2.87 |  |  | $ | 2.87 |
Production taxes as a percent of oil, gas, and NGL production revenue | 4.7 | % |  | 4.8 | % |  | 4.9 | % |  | 5.1 | %
Ad valorem tax expense (per BOE) | $ | 0.81 |  |  | $ | 0.97 |  |  | $ | 0.93 |  |  | $ | 0.69 |
Depletion, depreciation, amortization, and asset retirement obligation liability accretion (per BOE) | $ | 11.70 |  |  | $ | 10.93 |  |  | $ | 11.50 |  |  | $ | 11.60 |
General and administrative (per BOE) | $ | 2.10 |  |  | $ | 2.50 |  |  | $ | 2.24 |  |  | $ | 2.12 |

____________________________________________
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, 2023 |  | December 31, 2022 |  | March 31, 2022 |  | March 31, 2023 & December 31, 2022 |  | March 31, 2023 & 2022 |  | March 31, 2023 & December 31, 2022 |  | March 31, 2023 & 2022
Net production volumes: (1) |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Oil (MMBbl) |  |  |  |  |  |  |  |  | 5.7 |  |  | 5.7 |  |  | 6.5 |  |  | — |  |  | (0.8) |  |  | (1) | % |  | (12) | %
Gas (Bcf) |  |  |  |  |  |  |  |  | 32.2 |  |  | 32.1 |  |  | 31.4 |  |  | 0.1 |  |  | 0.9 |  |  | — | % |  | 3 | %
NGLs (MMBbl) |  |  |  |  |  |  |  |  | 2.1 |  |  | 2.1 |  |  | 2.1 |  |  | 0.1 |  |  | — |  |  | 3 | % |  | 2 | %
Equivalent (MMBOE) |  |  |  |  |  |  |  |  | 13.2 |  |  | 13.1 |  |  | 13.8 |  |  | — |  |  | (0.6) |  |  | — | % |  | (4) | %
Average net daily production: (1) |  |  |  |  |  |  |  |
Oil (MBbl per day) |  |  |  |  |  |  |  |  | 62.9 |  |  | 62.0 |  |  | 71.8 |  |  | 0.9 |  |  | (8.8) |  |  | 1 | % |  | (12) | %
Gas (MMcf per day) |  |  |  |  |  |  |  |  | 358.1 |  |  | 348.9 |  |  | 348.4 |  |  | 9.2 |  |  | 9.7 |  |  | 3 | % |  | 3 | %
NGLs (MBbl per day) |  |  |  |  |  |  |  |  | 23.8 |  |  | 22.7 |  |  | 23.4 |  |  | 1.1 |  |  | 0.4 |  |  | 5 | % |  | 2 | %
Equivalent (MBOE per day) |  |  |  |  |  |  |  |  | 146.4 |  |  | 142.9 |  |  | 153.3 |  |  | 3.6 |  |  | (6.9) |  |  | 2 | % |  | (4) | %
Oil, gas, and NGL production revenue (in millions): (1) |  |  |  |  |  |  |  |
Oil production revenue |  |  |  |  |  |  |  |  | $ | 420.8 |  |  | $ | 469.8 |  |  | $ | 607.3 |  |  | $ | (49.0) |  |  | $ | (186.5) |  |  | (10) | % |  | (31) | %
Gas production revenue |  |  |  |  |  |  |  |  | 93.7 |  |  | 145.0 |  |  | 170.0 |  |  | (51.2) |  |  | (76.3) |  |  | (35) | % |  | (45) | %
NGL production revenue |  |  |  |  |  |  |  |  | 56.2 |  |  | 54.5 |  |  | 81.4 |  |  | 1.7 |  |  | (25.2) |  |  | 3 | % |  | (31) | %
Total oil, gas, and NGL production revenue |  |  |  |  |  |  |  |  | $ | 570.8 |  |  | $ | 669.3 |  |  | $ | 858.7 |  |  | $ | (98.5) |  |  | $ | (287.9) |  |  | (15) | % |  | (34) | %
Oil, gas, and NGL production expense (in millions): (1) |  |  |  |  |  |  |  |
Lease operating expense |  |  |  |  |  |  |  |  | $ | 68.0 |  |  | $ | 68.4 |  |  | $ | 58.6 |  |  | $ | (0.3) |  |  | $ | 9.5 |  |  | — | % |  | 16 | %
Transportation costs |  |  |  |  |  |  |  |  | 37.0 |  |  | 37.6 |  |  | 37.7 |  |  | (0.6) |  |  | (0.7) |  |  | (2) | % |  | (2) | %
Production taxes |  |  |  |  |  |  |  |  | 26.7 |  |  | 32.0 |  |  | 40.4 |  |  | (5.3) |  |  | (13.8) |  |  | (17) | % |  | (34) | %
Ad valorem tax expense |  |  |  |  |  |  |  |  | 10.6 |  |  | 12.7 |  |  | 8.0 |  |  | (2.1) |  |  | 2.7 |  |  | (16) | % |  | 33 | %
Total oil, gas, and NGL production expense |  |  |  |  |  |  |  |  | $ | 142.3 |  |  | $ | 150.7 |  |  | $ | 144.7 |  |  | $ | (8.3) |  |  | $ | (2.3) |  |  | (6) | % |  | (2) | %
Realized price: |  |  |  |  |  |  |  |
Oil (per Bbl) |  |  |  |  |  |  |  |  | $ | 74.31 |  |  | $ | 82.35 |  |  | $ | 94.03 |  |  | $ | (8.04) |  |  | $ | (19.72) |  |  | (10) | % |  | (21) | %
Gas (per Mcf) |  |  |  |  |  |  |  |  | $ | 2.91 |  |  | $ | 4.52 |  |  | $ | 5.42 |  |  | $ | (1.61) |  |  | $ | (2.51) |  |  | (36) | % |  | (46) | %
NGLs (per Bbl) |  |  |  |  |  |  |  |  | $ | 26.24 |  |  | $ | 26.10 |  |  | $ | 38.56 |  |  | $ | 0.14 |  |  | $ | (12.32) |  |  | 1 | % |  | (32) | %
Per BOE |  |  |  |  |  |  |  |  | $ | 43.31 |  |  | $ | 50.92 |  |  | $ | 62.25 |  |  | $ | (7.61) |  |  | $ | (18.94) |  |  | (15) | % |  | (30) | %
Per BOE data: (1) |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Oil, gas, and NGL production expense: |  |  |  |  |  |  |  |  |  |  |  |
Lease operating expense |  |  |  |  |  |  |  |  | $ | 5.16 |  |  | $ | 5.20 |  |  | $ | 4.25 |  |  | $ | (0.04) |  |  | $ | 0.91 |  |  | (1) | % |  | 21 | %
Transportation costs |  |  |  |  |  |  |  |  | 2.81 |  |  | 2.86 |  |  | 2.74 |  |  | (0.05) |  |  | 0.07 |  |  | (2) | % |  | 3 | %
Production taxes |  |  |  |  |  |  |  |  | 2.02 |  |  | 2.43 |  |  | 2.93 |  |  | (0.41) |  |  | (0.91) |  |  | (17) | % |  | (31) | %
Ad valorem tax expense |  |  |  |  |  |  |  |  | 0.81 |  |  | 0.97 |  |  | 0.58 |  |  | (0.16) |  |  | 0.23 |  |  | (16) | % |  | 40 | %
Total oil, gas, and NGL production expense (1) |  |  |  |  |  |  |  |  | $ | 10.80 |  |  | $ | 11.46 |  |  | $ | 10.49 |  |  | $ | (0.66) |  |  | $ | 0.31 |  |  | (6) | % |  | 3 | %
Depletion, depreciation, amortization, and asset retirement obligation liability accretion |  |  |  |  |  |  |  |  | $ | 11.70 |  |  | $ | 10.93 |  |  | $ | 11.56 |  |  | $ | 0.77 |  |  | $ | 0.14 |  |  | 7 | % |  | 1 | %
General and administrative |  |  |  |  |  |  |  |  | $ | 2.10 |  |  | $ | 2.50 |  |  | $ | 1.81 |  |  | $ | (0.40) |  |  | $ | 0.29 |  |  | (16) | % |  | 16 | %
Derivative settlement gain (loss)(2) |  |  |  |  |  |  |  |  | $ | 0.39 |  |  | $ | (8.80) |  |  | $ | (12.19) |  |  | $ | 9.19 |  |  | $ | 12.58 |  |  | 104 | % |  | 103 | %
Earnings per share information (in thousands, except per share data): (3) |  |  |  |  |  |  |  |
Basic weighted-average common shares outstanding |  |  |  |  |  |  |  |  | 121,671 |  |  | 122,485 |  |  | 121,907 |  |  | (814) |  |  | (236) |  |  | (1) | % |  | — | %
Diluted weighted-average common shares outstanding |  |  |  |  |  |  |  |  | 122,294 |  |  | 123,399 |  |  | 124,179 |  |  | (1,105) |  |  | (1,885) |  |  | (1) | % |  | (2) | %
Basic net income per common share |  |  |  |  |  |  |  |  | $ | 1.63 |  |  | $ | 2.11 |  |  | $ | 0.40 |  |  | $ | (0.48) |  |  | $ | 1.23 |  |  | (23) | % |  | 308 | %
Diluted net income per common share |  |  |  |  |  |  |  |  | $ | 1.62 |  |  | $ | 2.09 |  |  | $ | 0.39 |  |  | $ | (0.47) |  |  | $ | 1.23 |  |  | (22) | % |  | 315 | %

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______________________________________
(1) Amounts and percentage changes may not calculate due to rounding.
(2) Derivative settlements for the three months ended March 31, 2023, and 2022, 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, 2023, increased two percent sequentially and decreased four percent compared with the same period in 2022. The YTD 2023-over-YTD 2022 decrease consisted of a 15 percent decrease from our Midland Basin assets, partially offset by a 10 percent increase from our South Texas assets as a result of a shift in capital allocation to our Austin Chalk assets.
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 $7.61 sequentially and $18.94 YTD 2023-over-YTD 2022, as a result of decreases in oil and gas benchmark prices. These decreases were slightly offset by a gain on the settlement of our commodity derivative contracts of $0.39 per BOE for the three months ended March 31, 2023. For the three months ended December 31, 2022, and March 31, 2022, we had losses on the settlement of our commodity derivative contracts of $8.80 per BOE and $12.19 per BOE, respectively.
Lease operating expense (“LOE”) on a per BOE basis remained flat sequentially and increased 21 percent YTD 2023-over-YTD 2022. The YTD 2023-over-YTD 2022 increase was a result of increased workover activity and the effects of inflation, both of which we expect will lead to an increase in LOE on a per BOE basis for the full-year 2023, compared with 2022. 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 decreased two percent sequentially and increased three percent YTD 2023-over-YTD 2022. 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 2023, we expect transportation costs on a per BOE basis to decrease compared with 2022, as a result of transportation cost reductions in the second half of 2023 resulting from the expiration of a long-term contract in South Texas.
Production tax expense on a per BOE basis decreased 17 percent sequentially and 31 percent YTD 2023-over-YTD 2022, as a result of decreases in realized prices. Our overall production tax rate for the three months ended March 31, 2023, and 2022, was 4.7 percent, compared with 4.8 percent for the three months ended December 31, 2022. 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 decreased 16 percent sequentially and increased 40 percent YTD 2023-over-YTD 2022 as a result of changes to the expected value assessments of our producing properties, which are driven by fluctuations in commodity prices. We anticipate volatility in ad valorem tax expense on a per BOE and absolute basis as the valuation of our producing properties changes.
Depletion, depreciation, amortization, and asset retirement obligation liability accretion (“DD&A”) expense on a per BOE basis increased seven percent sequentially and remained flat YTD 2023-over-YTD 2022. The sequential quarterly increase was a result of an increase in our DD&A rate due to inflation partially offset by a shift in our production mix resulting from increased activity in our South Texas assets which have a lower DD&A rate than our Midland Basin assets. Our DD&A rate fluctuates as a result of changes in our production mix, changes in our total estimated proved reserve volumes, changes in capital allocation, impairments, divestiture activity, and carrying cost funding and sharing arrangements with third parties. We expect DD&A expense per BOE and on an absolute basis to increase slightly in 2023, compared with 2022, primarily as a result of inflation, partially offset by increased activity in our Austin Chalk program.
General and administrative (“G&A”) expense on a per BOE basis decreased 16 percent sequentially primarily as a result of decreased compensation expense. G&A expense recorded during the three months ended December 31, 2022, 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 on a per BOE basis increased 16 percent YTD 2023-over-YTD 2022 as a result of increased compensation expense and inflationary impacts. We currently expect G&A expense to increase per BOE and on an absolute basis compared with 2022, primarily as a result of expected increases in compensation expense.
Please refer to Comparison of Financial Results and Trends Between the Three Months Ended March 31, 2023, and December 31, 2022, and Between the Three Months Ended March 31, 2023, and 2022 below for additional discussion of operating expenses.
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Comparison of Financial Results and Trends Between the Three Months Ended March 31, 2023, and December 31, 2022, and Between the Three Months Ended March 31, 2023, and 2022
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, 2023, and December 31, 2022:

| Net Equivalent Production Increase (Decrease) |  | Oil, Gas, and NGL Production Revenue Decrease |  | Oil, Gas, and NGL Production Expense Decrease
| (MBOE per day) |  | (in millions) |  | (in millions)
Midland Basin | (3.0) |  |  |  |  | $ | (66.3) |  |  |  |  | $ | (6.5) |  |  |
South Texas | 6.6 |  |  |  |  | (32.1) |  |  |  |  | (1.8) |  |  |
Total | 3.6 |  |  |  |  | $ | (98.5) |  |  |  |  | $ | (8.3) |  |  |

__________________________________________
Note: Amounts may not calculate due to rounding.
Average net daily equivalent production volumes increased two percent, consisting of a 10 percent increase from our South Texas assets, partially offset by a four percent decrease from our Midland Basin assets. Our realized oil and gas prices decreased 10 percent and 36 percent, respectively, and our realized price for NGLs remained flat. As a result of decreases in benchmark commodity prices for oil and gas, total realized price per BOE decreased 15 percent, resulting in a 15 percent decrease in oil, gas, and NGL production revenue. Oil, gas, and NGL production expense decreased six percent, primarily driven by decreases in production tax expense and ad valorem tax expense.
YTD 2023-over-YTD 2022 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, 2023, and 2022:

| Net Equivalent Production Increase (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 | (13.5) |  |  |  |  | $ | (226.2) |  |  |  |  | $ | (5.9) |  |  |
South Texas | 6.6 |  |  |  |  | (61.7) |  |  |  |  | 3.6 |  |  |
Total | (6.9) |  |  |  |  | $ | (287.9) |  |  |  |  | $ | (2.3) |  |  |

__________________________________________
Note: Amounts may not calculate due to rounding.
Average net daily equivalent production volumes decreased four percent, consisting of a 15 percent decrease from our Midland Basin assets, partially offset by a 10 percent increase from our South Texas assets. Realized prices for oil, gas, and NGLs decreased 21 percent, 46 percent, and 32 percent, respectively. As a result of decreases in benchmark commodity prices, total realized price per BOE decreased 30 percent, and combined with decreased average net daily equivalent production, resulted in a 34 percent decrease in oil, gas, and NGL production revenue. Oil, gas, and NGL production expense decreased two percent, primarily driven by a decrease in production tax expense which was mostly 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, 2023 |  | December 31, 2022 |  | March 31, 2022 |  |  |  |
| (in millions)
Depletion, depreciation, amortization, and asset retirement obligation liability accretion | $ | 154.2 |  |  | $ | 143.6 |  |  | $ | 159.5 |  |  |  |  |

DD&A expense increased seven percent sequentially and decreased three percent YTD 2023-over-YTD 2022. The sequential quarterly increase was a result of an increase to our DD&A rate due to inflation. This increase was partially offset by increased activity
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in our South Texas assets which have a lower DD&A rate than our Midland Basin 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, 2023 |  | December 31, 2022 |  | March 31, 2022 |  |  |  |
| (in millions)
Geological, geophysical, and other expenses | $ | 10.6 |  |  | $ | 2.9 |  |  | $ | 1.3 |  |  |  |  |
Overhead | 7.8 |  |  | 7.9 |  |  | 7.7 |  |  |  |  |
Total | $ | 18.4 |  |  | $ | 10.8 |  |  | $ | 9.0 |  |  |  |  |

__________________________________________
Note: Prior periods have been adjusted to conform to the current period presentation.
Exploration expense increased 70 percent sequentially and 104 percent YTD 2023-over-YTD 2022, primarily as a result of unsuccessful exploration activity related to one well that experienced technical issues during the drilling phase. 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, 2023 |  | December 31, 2022 |  | March 31, 2022 |  |  |  |
| (in millions)
General and administrative | $ | 27.7 |  |  | $ | 32.8 |  |  | $ | 25.0 |  |  |  |  |

G&A expense decreased 16 percent sequentially primarily as a result of decreased compensation expense. G&A expense recorded during the three months ended December 31, 2022, 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 11 percent YTD 2023-over-YTD 2022 as a result of increased compensation expense and inflationary impacts. 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, 2023 |  | December 31, 2022 |  | March 31, 2022 |  |  |  |
| (in millions)
Net derivative (gain) loss | $ | (51.3) |  |  | $ | (11.2) |  |  | $ | 418.5 |  |  |  |  |

Net derivative (gain) loss is a result of changes in derivative 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. The net derivative gains for the three months ended March 31, 2023, and December 31, 2022, resulted from decreases in benchmark commodity prices during those periods. The net derivative loss for the three months ended March 31, 2022, resulted from increases in benchmark commodity 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, 2023 |  | December 31, 2022 |  | March 31, 2022 |  |  |  |
| (in millions)
Interest expense | $ | (22.5) |  |  | $ | (22.6) |  |  | $ | (39.4) |  |  |  |  |

Interest expense remained flat sequentially and decreased 43 percent YTD 2023-over-YTD 2022 as a result of the reduction in the aggregate principal amount of our Senior Notes through various transactions in 2022, including the redemption of our 2024 Senior Notes on February 14, 2022, and the redemption of our 10.0% Senior Secured Notes due 2025 (“2025 Senior Secured Notes”) on June 17, 2022. As a result of these transactions, we expect interest expense to decrease for the full-year 2023, compared with 2022. Total
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interest expense can vary based on the timing and amount of borrowings under our revolving credit facility. Please refer to Note 5 - Long-Term Debt in Part I, Item 1 of this report and Overview of Liquidity and Capital Resources below for additional discussion.
Income tax expense

| For the Three Months Ended |  |
| March 31, 2023 |  | December 31, 2022 |  | March 31, 2022 |  |  |  |
| (in millions, except tax rate)
Income tax expense | $ | (55.5) |  |  | $ | (64.9) |  |  | $ | (12.9) |  |  |  |  |
Effective tax rate | 21.8 | % |  | 20.1 | % |  | 20.9 | % |  |  |  |

The sequential quarterly and YTD 2023-over-YTD 2022 increases in the effective tax rate are primarily due to a benefit recognized from the release of the valuation allowance during each of the three months ended December 31, 2022, and March 31, 2022, that lowered the effective tax rate for each of those periods.
The tax rates for each period presented 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 between eight percent and 10 percent of full-year 2023 income tax expense will be current, however, this could be impacted upon the resolution of the R&D credit study if we benefit from a carryover R&D credit amount.
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 impact on our effective tax rate and current tax expense. Please refer to the Risk Factors section in Part 1, Item 1A of our 2022 Form 10-K for additional discussion.
Please refer to Note 4 - Income Taxes in Part I, Item 1 of this report 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, 2023, our capital expenditure and return of capital programs were funded with cash flows from operating activities, and we expect that to continue for the remainder of 2023. As of March 31, 2023, our cash and cash equivalents balance was $477.9 million, which was an increase of $32.9 million from our cash and cash equivalents balance as of December 31, 2022. Although we expect cash flows from operations to be sufficient to fund our expected 2023 capital expenditure and return of capital programs, 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, and 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 commodity price 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, a borrowing base of $2.5 billion, and aggregate lender commitments totaling $1.25 billion. 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, 2023, the semi-annual
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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, 2023. 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, 2023, 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 of the outstanding balance, total amount of letters of credit, and available borrowing capacity under the Credit Agreement as of April 21, 2023, March 31, 2023, and December 31, 2022.
We had no revolving credit facility borrowings during the three months ended March 31, 2023, and 2022, or December 31, 2022. 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, 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, the non-cash amortization of deferred financing costs, and for the periods during which the 2025 Senior Secured Notes were outstanding, the non-cash amortization of the related discount. 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, 2023 |  | December 31, 2022 |  |  |  | March 31, 2022
Weighted-average interest rate | 7.2 | % |  | 7.0 | % |  |  |  | 8.2 | %
Weighted-average borrowing rate | 6.5 | % |  | 6.4 | % |  |  |  | 7.2 | %

Our weighted-average interest rate and our weighted-average borrowing rate each remained relatively flat sequentially, and decreased YTD 2023-over-YTD 2022, primarily due to the redemption of our 2024 Senior Notes and 2025 Senior Secured Notes during 2022. We expect our weighted-average interest rate and weighted-average borrowing rate to decrease for the full-year 2023 compared with 2022, primarily as a result of the redemption of our 2024 Senior Notes and 2025 Senior Secured Notes.
Our weighted-average interest rate and weighted-average borrowing rate are impacted 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 rates are impacted by the fees paid on the unused portion of our aggregate lender commitments. The rates disclosed in the above table do not reflect certain amounts associated with the repurchase or redemption of Senior Notes, such as the acceleration of unamortized deferred financing costs and unamortized discounts, as these amounts are netted against the associated gain or loss on extinguishment of debt. The 2024 Senior Notes were redeemed on February 14, 2022, and the 2025 Senior Secured Notes were redeemed on June 17, 2022. After these dates, the weighted-average interest rate was no longer impacted by the non-cash amortization of deferred financing costs or, for the 2025 Senior Secured Notes, the non-cash amortization of the discount.
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, dividends, debt obligations, including interest and early repayments or redemptions, and for repurchases of shares of our 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, 2023, we spent approximately $240.7 million on capital expenditures. This amount differs from the costs incurred amount of $308.7 million for the three months ended March 31, 2023, 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 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 2023 capital program, which we expect to fund with cash flows from operations, is expected to be approximately $1.1 billion, exclusive of acquisitions.
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
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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, 2023, we repurchased and subsequently retired 1,413,758 shares of our common stock at a cost of $40.0 million, excluding taxes, commission, and fees. As of March 31, 2023, $402.8 million remained available under the Stock Repurchase Program for repurchases of our common stock. Please refer to Note 3 - Equity in Part I, Item 1 of this report for additional discussion. On February 14, 2022, we redeemed all of the $104.8 million of aggregate principal amount outstanding of our 2024 Senior Notes and all redeemed 2024 Senior Notes were canceled upon settlement. Please refer to Note 5 - Long-Term Debt in Part I, Item 1 of this report for additional discussion.
Analysis of Cash Flow Changes Between the Three Months Ended March 31, 2023, and 2022
The following tables present changes in cash flows between the three months ended March 31, 2023, and 2022, 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 |  |
| 2023 |  | 2022 |  |
| (in millions) |  |
Net cash provided by operating activities | $ | 331.6 |  |  | $ | 342.1 |  |  | $ | (10.5) |  |  |

Net cash provided by operating activities decreased for the three months ended March 31, 2023, compared with the same period in 2022, primarily as a result of a $160.0 million decrease in cash received from oil, gas, and NGL production revenue net of transportation costs and production taxes and an increase of $33.7 million in cash paid for LOE and ad valorem taxes, mostly offset by a $149.2 million decrease in cash paid on settled derivative trades, a $26.8 million decrease in cash paid for interest, and a $16.1 million decrease in cash paid for G&A expense. 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 |  |
| 2023 |  | 2022 |  |
| (in millions) |  |
Net cash used in investing activities | $ | (240.4) |  |  | $ | (150.1) |  |  | $ | (90.3) |  |  |

Net cash used in investing activities increased for the three months ended March 31, 2023, compared with the same period in 2022, primarily as a result of a $90.6 million increase in capital expenditures. Net cash used in investing activities during the three months ended March 31, 2023, was funded by net cash provided by operating activities.
Financing activities

| For the Three Months Ended March 31, |  | Amount Change Between Periods |  |
| 2023 |  | 2022 |  |
| (in millions) |  |
Net cash used in financing activities | $ | (58.4) |  |  | $ | (104.8) |  |  | $ | 46.4 |  |  |

Net cash used in financing activities for the three months ended March 31, 2023, related to $40.1 million of cash paid to repurchase and subsequently retire 1,413,758 shares of our common stock under the Stock Repurchase Program and $18.3 million in dividends paid.
Net cash used in financing activities for the three months ended March 31, 2022, related to $104.8 million of cash paid to redeem our 2024 Senior Notes.
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
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credit facility’s fair value but will not impact 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 impact future results of operations and cash flows. Changes in interest rates do not impact the amount of interest we pay on our fixed-rate Senior Notes, but can impact their fair values. As of March 31, 2023, 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.
The Federal Reserve has continued to increase short-term interest rates in 2023. These increases, and any future increases, could impact the cost and our ability to borrow funds.
Commodity Price Risk
The prices we receive for our oil, gas, and NGL production directly impact our revenue, profitability, access to capital, ability to execute our Stock Repurchase Program and pay dividends, 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 the ongoing conflict between Russia and Ukraine, the economic and trade sanctions that certain countries have imposed on Russia, production output from OPEC+, and the associated potential impacts of these issues on global commodity and financial markets. These circumstances have contributed to inflation, instances of supply chain disruptions, and a rise 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, 2023, 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 $42.1 million, $9.4 million, and $5.6 million, respectively. If commodity prices had been 10 percent lower, our net derivative settlements for the three months ended March 31, 2023, would have offset the declines in oil, gas, and NGL production revenue by approximately $13.0 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, 2023, 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 $49.9 million, $1.9 million, and $1.8 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, 2023, 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 Accounting Policies included in Part II, Item 8 of our 2022 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.
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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 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 2022 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, 2023 |  | December 31, 2022 |  | March 31, 2022 |  |  |  |  |
| (in thousands)
Net income (GAAP) | $ | 198,552 |  |  | $ | 258,463 |  |  | $ | 48,764 |  |  |  |  |  |
Interest expense | 22,459 |  |  | 22,638 |  |  | 39,387 |  |  |  |  |  |
Income tax expense | 55,506 |  |  | 64,867 |  |  | 12,861 |  |  |  |  |  |
Depletion, depreciation, amortization, and asset retirement obligation liability accretion | 154,189 |  |  | 143,611 |  |  | 159,481 |  |  |  |  |  |
Exploration (1) | 17,477 |  |  | 9,826 |  |  | 8,055 |  |  |  |  |  |
Stock-based compensation expense | 4,318 |  |  | 4,914 |  |  | 4,274 |  |  |  |  |  |
Net derivative (gain) loss | (51,329) |  |  | (11,168) |  |  | 418,521 |  |  |  |  |  |
Derivative settlement gain (loss) | 5,076 |  |  | (115,620) |  |  | (168,183) |  |  |  |  |  |
Other, net | (4,854) |  |  | (3,677) |  |  | 1,404 |  |  |  |  |  |
Adjusted EBITDAX (non-GAAP) | 401,394 |  |  | 373,854 |  |  | 524,564 |  |  |  |  |  |
Interest expense | (22,459) |  |  | (22,638) |  |  | (39,387) |  |  |  |  |  |
Income tax expense | (55,506) |  |  | (64,867) |  |  | (12,861) |  |  |  |  |  |
Exploration (1)(2) | (8,181) |  |  | (8,851) |  |  | (8,055) |  |  |  |  |  |
Amortization of debt discount and deferred financing costs | 1,371 |  |  | 1,371 |  |  | 4,010 |  |  |  |  |  |
Deferred income taxes | 49,968 |  |  | 66,061 |  |  | 11,948 |  |  |  |  |  |
Other, net | (8,737) |  |  | 2,278 |  |  | (165) |  |  |  |  |  |
Net change in working capital | (26,216) |  |  | (58,833) |  |  | (137,962) |  |  |  |  |  |
Net cash provided by operating activities (GAAP) | $ | 331,634 |  |  | $ | 288,375 |  |  | $ | 342,092 |  |  |  |  |  |

____________________________________________
(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, 2023, amount excludes certain capital expenditures related to unsuccessful exploration activity for one well that experienced technical issues during the drilling phase. For the three months ended December 31, 2022, amount excludes certain capital expenditures related to unsuccessful exploration efforts outside of our core areas of operation.
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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 2022 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 Securities and Exchange Commission (“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 2023 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 other material changes to the risk factors as previously disclosed in our 2022 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, 2023, 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 | Weighted Average Price Paid per Share | Total Number of Shares Purchased as Part of Publicly Announced Program (1) | Approximate Dollar Value of Shares that May Yet Be Purchased Under the Program (as of period end date) (1)
01/01/2023 - 01/31/2023 | — |  | $ | — |  | — |  | $ | 442,820,671 |
02/01/2023 - 02/28/2023 | 100,000 |  | $ | 29.93 |  | 100,000 |  | $ | 439,827,521 |
03/01/2023 - 03/31/2023 | 1,313,758 |  | $ | 28.20 |  | 1,313,758 |  | $ | 402,780,476 |
Total: | 1,413,758 |  | $ | 28.32 |  | 1,413,758 |  |

___________________________________
(1) In September 2022, our Board of Directors approved the Stock Repurchase Program authorizing us to repurchase up to $500.0 million in aggregate value of our common stock through December 31, 2024. The Stock Repurchase Program 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. We intend to utilize net cash provided by operating activities to repurchase shares of our common stock. Stock repurchases may also be made with borrowings under our Credit Agreement. The timing, as well as the number and value of shares repurchased under the Stock Repurchase Program, will be determined by certain authorized officers of the Company at their discretion and will depend on a variety of factors, including the market price of 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, 2023, we repurchased and subsequently retired 1,413,758 shares of our common stock under the Stock Repurchase Program at a weighted-average share price of $28.32 for a total cost of $40.0 million, excluding 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 | 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
April 28, 2023 | By: | /s/ HERBERT S. VOGEL
|  | Herbert S. Vogel
|  | President and Chief Executive Officer
|  | (Principal Executive Officer)
April 28, 2023 | By: | /s/ A. WADE PURSELL
|  | A. Wade Pursell
|  | Executive Vice President and Chief Financial Officer
|  | (Principal Financial Officer)
April 28, 2023 | By: | /s/ PATRICK A. LYTLE
|  | Patrick A. Lytle
|  | Vice President - Chief Accounting Officer and Controller
|  | (Principal Accounting Officer)

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