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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, 2022
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.) |

| 1775 Sherman Street, Suite 1200, 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 20, 2022, the registrant had 121,864,177 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, 2022, and December 31, 2021 | 4
| Condensed Consolidated Statements of Operations Three Months Ended March 31, 2022, and 2021 | 5
| Condensed Consolidated Statements of Comprehensive Income (Loss) Three Months Ended March 31, 2022, and 2021 | 6
| Condensed Consolidated Statements of Stockholders’ Equity Three Months Ended March 31, 2022, and 2021 | 7
| Condensed Consolidated Statements of Cash Flows Three Months Ended March 31, 2022, and 2021 | 8
| Notes to Condensed Consolidated Financial Statements | 9
Item 2. | Management’s Discussion and Analysis of Financial Condition and Results of Operations | 21
Item 3. | Quantitative and Qualitative Disclosures About Market Risk | 37
Item 4. | Controls and Procedures | 37
| Part II | 38
Item 1. | Legal Proceedings | 38
Item 1A. | Risk Factors | 38
Item 2. | Unregistered Sales of Equity Securities and Use of Proceeds | 38
Item 6. | Exhibits | 39
| Signatures | 40

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 (the “Securities Act”), and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). All statements included in this report, other than statements of historical facts, 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,” “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:
•armed conflict, political instability, or civil unrest in crude oil and natural 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;
•the effects of the global COVID-19 pandemic (“Pandemic”) on us, our industry, our financial condition, and our results of operations;
•the amount and nature of future capital expenditures and the availability of liquidity and capital resources to fund capital expenditures;
•any changes to the borrowing base or aggregate lender commitments under our Sixth Amended and Restated Credit Agreement, as amended (“Credit Agreement”);
•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;
•our drilling and completion activities and other exploration and development activities, our ability to obtain permits and governmental approvals, and plans by us, our joint development partners, and/or other third-party operators;
•possible 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;
•cash flows, liquidity, interest and related debt service expenses, changes in our effective tax rate, and our ability to repay debt in the future;
•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; 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, 2021 (“2021 Form 10-K”).
The forward-looking statements in this report speak only as of the filing of this report. Although we may from time to time voluntarily update our prior forward-looking statements, we disclaim any commitment to do so except as required by applicable securities laws.
3

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

| March 31, 2022 |  | December 31, 2021
ASSETS |  |  |
Current assets: |  |  |
Cash and cash equivalents | $ | 419,887 |  |  | $ | 332,716 |
Accounts receivable | 321,076 |  |  | 247,201 |
Derivative assets | 9,649 |  |  | 24,095 |
Prepaid expenses and other | 8,223 |  |  | 9,175 |
Total current assets | 758,835 |  |  | 613,187 |
Property and equipment (successful efforts method): |  |  |
Proved oil and gas properties | 9,518,883 |  |  | 9,397,407 |
Accumulated depletion, depreciation, and amortization | (5,792,648) |  |  | (5,634,961) |
Unproved oil and gas properties | 628,250 |  |  | 629,098 |
Wells in progress | 192,821 |  |  | 148,394 |
Other property and equipment, net of accumulated depreciation of $62,845 and $62,359, respectively | 35,667 |  |  | 36,060 |
Total property and equipment, net | 4,582,973 |  |  | 4,575,998 |
Noncurrent assets: |  |  |
Derivative assets | 8,903 |  |  | 239 |
Other noncurrent assets | 45,070 |  |  | 44,553 |
Total noncurrent assets | 53,973 |  |  | 44,792 |
Total assets | $ | 5,395,781 |  |  | $ | 5,233,977 |
LIABILITIES AND STOCKHOLDERS’ EQUITY |  |  |
Current liabilities: |  |  |
Accounts payable and accrued expenses | $ | 514,558 |  |  | $ | 563,306 |
Derivative liabilities | 538,127 |  |  | 319,506 |
Other current liabilities | 6,036 |  |  | 6,515 |
Total current liabilities | 1,058,721 |  |  | 889,327 |
Noncurrent liabilities: |  |  |
Revolving credit facility | — |  |  | — |
Senior Notes, net | 1,980,392 |  |  | 2,081,164 |
Asset retirement obligations | 98,908 |  |  | 97,324 |
Deferred income taxes | 21,768 |  |  | 9,769 |
Derivative liabilities | 51,631 |  |  | 25,696 |
Other noncurrent liabilities | 69,252 |  |  | 67,566 |
Total noncurrent liabilities | 2,221,951 |  |  | 2,281,519 |
Commitments and contingencies (note 6) |  |  |
Stockholders’ equity: |  |  |
Common stock, $0.01 par value - authorized: 200,000,000 shares; issued and outstanding: 121,864,177 and 121,862,248 shares, respectively | 1,219 |  |  | 1,219 |
Additional paid-in capital | 1,844,478 |  |  | 1,840,228 |
Retained earnings | 282,079 |  |  | 234,533 |
Accumulated other comprehensive loss | (12,667) |  |  | (12,849) |
Total stockholders’ equity | 2,115,109 |  |  | 2,063,131 |
Total liabilities and stockholders’ equity | $ | 5,395,781 |  |  | $ | 5,233,977 |

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

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

|  |  | For the Three Months Ended March 31,
|  |  |  |  | 2022 |  | 2021
Operating revenues and other income: |  |  |  |  |  |  |
Oil, gas, and NGL production revenue |  |  |  |  | $ | 858,721 |  |  | $ | 423,165 |
Other operating income |  |  |  |  | 1,055 |  |  | 20,681 |
Total operating revenues and other income |  |  |  |  | 859,776 |  |  | 443,846 |
Operating expenses: |  |  |  |  |  |  |
Oil, gas, and NGL production expense |  |  |  |  | 144,691 |  |  | 100,930 |
Depletion, depreciation, amortization, and asset retirement obligation liability accretion |  |  |  |  | 159,481 |  |  | 166,960 |
Exploration |  |  |  |  | 9,046 |  |  | 9,323 |
Impairment |  |  |  |  | 1,000 |  |  | 8,750 |
General and administrative |  |  |  |  | 24,996 |  |  | 24,714 |
Net derivative loss |  |  |  |  | 418,521 |  |  | 344,689 |
Other operating expense, net |  |  |  |  | 305 |  |  | (599) |
Total operating expenses |  |  |  |  | 758,040 |  |  | 654,767 |
Income (loss) from operations |  |  |  |  | 101,736 |  |  | (210,921) |
Interest expense |  |  |  |  | (39,387) |  |  | (39,871) |
Other non-operating expense, net |  |  |  |  | (724) |  |  | (371) |
Income (loss) before income taxes |  |  |  |  | 61,625 |  |  | (251,163) |
Income tax expense |  |  |  |  | (12,861) |  |  | (106) |
Net income (loss) |  |  |  |  | $ | 48,764 |  |  | $ | (251,269) |
Basic weighted-average common shares outstanding |  |  |  |  | 121,907 |  |  | 114,759 |
Diluted weighted-average common shares outstanding |  |  |  |  | 124,179 |  |  | 114,759 |
Basic net income (loss) per common share |  |  |  |  | $ | 0.40 |  |  | $ | (2.19) |
Diluted net income (loss) per common share |  |  |  |  | $ | 0.39 |  |  | $ | (2.19) |
Dividends per common share |  |  |  |  | $ | 0.01 |  |  | $ | 0.01 |

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

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

|  |  | For the Three Months Ended March 31,
|  |  |  |  | 2022 |  | 2021
Net income (loss) |  |  |  |  | $ | 48,764 |  |  | $ | (251,269) |
Other comprehensive income, net of tax: |  |  |  |  |  |  |
Pension liability adjustment |  |  |  |  | 182 |  |  | 191 |
Total other comprehensive income, net of tax |  |  |  |  | 182 |  |  | 191 |
Total comprehensive income (loss) |  |  |  |  | $ | 48,946 |  |  | $ | (251,078) |

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

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

|  |  | Additional Paid-in Capital |  |  |  | Accumulated Other Comprehensive Loss |  | Total Stockholders’ Equity
| Common Stock |  |  | Retained Earnings |  |
| Shares |  | Amount |  |  |  |
Balances, December 31, 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 |

|  |  | Additional Paid-in Capital |  |  |  | Accumulated Other Comprehensive Loss |  | Total Stockholders’ Equity
| Common Stock |  |  | Retained Earnings (Deficit) |  |
| Shares |  | Amount |  |  |  |
Balances, December 31, 2020 | 114,742,304 |  |  | $ | 1,147 |  |  | $ | 1,827,914 |  |  | $ | 200,697 |  |  | $ | (13,598) |  |  | $ | 2,016,160 |
Net loss | — |  |  | — |  |  | — |  |  | (251,269) |  |  | — |  |  | (251,269) |
Other comprehensive income | — |  |  | — |  |  | — |  |  | — |  |  | 191 |  |  | 191 |
Cash dividends declared, $0.01 per share | — |  |  | — |  |  | — |  |  | (1,147) |  |  | — |  |  | (1,147) |
Stock-based compensation expense | — |  |  | — |  |  | 5,737 |  |  | — |  |  | — |  |  | 5,737 |
Balances, March 31, 2021 | 114,742,304 |  |  | $ | 1,147 |  |  | $ | 1,833,651 |  |  | $ | (51,719) |  |  | $ | (13,407) |  |  | $ | 1,769,672 |

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,
| 2022 |  | 2021
Cash flows from operating activities: |  |  |
Net income (loss) | $ | 48,764 |  |  | $ | (251,269) |
Adjustments to reconcile net income (loss) to net cash provided by operating activities: |  |
Depletion, depreciation, amortization, and asset retirement obligation liability accretion | 159,481 |  |  | 166,960 |
Impairment | 1,000 |  |  | 8,750 |
Stock-based compensation expense | 4,274 |  |  | 5,737 |
Net derivative loss | 418,521 |  |  | 344,689 |
Derivative settlement loss | (168,183) |  |  | (107,885) |
Amortization of debt discount and deferred financing costs | 4,010 |  |  | 4,723 |
Deferred income taxes | 11,948 |  |  | (52) |
Other, net | 239 |  |  | (14,592) |
Net change in working capital | (137,962) |  |  | (51,437) |
Net cash provided by operating activities | 342,092 |  |  | 105,624 |
Cash flows from investing activities: |  |  |
Capital expenditures | (150,127) |  |  | (147,563) |
Other, net | — |  |  | (71) |
Net cash used in investing activities | (150,127) |  |  | (147,634) |
Cash flows from financing activities: |  |  |
Proceeds from revolving credit facility | — |  |  | 440,000 |
Repayment of revolving credit facility | — |  |  | (398,000) |
Cash paid to repurchase Senior Notes | (104,770) |  |  | — |
Other, net | (24) |  |  | — |
Net cash provided by (used in) financing activities | (104,794) |  |  | 42,000 |
Net change in cash, cash equivalents, and restricted cash | 87,171 |  |  | (10) |
Cash, cash equivalents, and restricted cash at beginning of period | 332,716 |  |  | 10 |
Cash, cash equivalents, and restricted cash at end of period | $ | 419,887 |  |  | $ | — |
Supplemental schedule of additional cash flow information: |  |
Operating activities: |  |  |
Cash paid for interest, net of capitalized interest | $ | (64,204) |  |  | $ | (53,449) |
Investing activities: |  |  |
Increase in capital expenditure accruals and other | $ | 15,627 |  |  | $ | 37,409 |

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 2021 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, 2022, 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 2021 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 2021 Form 10-K.
Recently Issued Accounting Standards
As of March 31, 2022, 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, 2022, and 2021:

| Midland Basin |  | South Texas |  | Total
| Three Months Ended March 31, |  | Three Months Ended March 31, |  | Three Months Ended March 31,
| 2022 |  | 2021 |  | 2022 |  | 2021 |  | 2022 |  | 2021
| (in thousands)
Oil production revenue | $ | 493,895 |  | $ | 286,105 |  | $ | 113,407 |  | $ | 19,672 |  | $ | 607,302 |  | $ | 305,777
Gas production revenue | 102,273 |  | 57,806 |  | 67,776 |  | 31,852 |  | 170,049 |  | 89,658
NGL production revenue | 152 |  | 100 |  | 81,218 |  | 27,630 |  | 81,370 |  | 27,730
Total | $ | 596,320 |  | $ | 344,011 |  | $ | 262,401 |  | $ | 79,154 |  | $ | 858,721 |  | $ | 423,165
Relative percentage | 69 | % |  | 81 | % |  | 31 | % |  | 19 | % |  | 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
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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. Please refer to Note 2 - Revenue from Contracts with Customers in the 2021 Form 10-K for more information regarding the types of contracts under which oil, gas, and NGL production revenue is generated.
Significant judgments made in applying the guidance in Accounting Standards Codification Topic 606, Revenue from Contracts with Customers, relate to the point in time when control transfers to purchasers in gas processing arrangements with midstream processors. The Company does not believe that significant judgments are required with respect to the determination of the transaction price, including amounts that represent variable consideration, as volume and price carry a low level of estimation uncertainty given the precision of volumetric measurements and the use of index pricing with generally predictable differentials. Accordingly, the Company does not consider estimates of variable consideration to be constrained.
The Company’s performance obligations arise upon the production of hydrocarbons from wells in which the Company has an ownership interest. The performance obligations are considered satisfied upon control transferring to a purchaser at the wellhead, inlet, or tailgate of the midstream processor’s processing facility, or other contractually specified delivery point. 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.
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, 2022, and December 31, 2021, were $291.7 million and $215.6 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.
Note 3 - Equity
On June 17, 2020, the Company issued warrants to purchase up to an aggregate of approximately 5.9 million shares, or approximately five percent of its then outstanding common stock, at an exercise price of $0.01 per share (“Warrants”). The Warrants became exercisable at the election of the holders on January 15, 2021, pursuant to the terms of the Warrant Agreement, dated as of June 17, 2020. The Warrants are indexed to the Company’s common stock and are required to be settled through physical settlement or net share settlement, if exercised.
Upon issuance, the $21.5 million fair value of the Warrants was recorded in additional paid-in capital on the accompanying balance sheets, and was determined using a stochastic Monte Carlo simulation using geometric Brownian motion (“GBM Model”). The Company evaluated the Warrants under authoritative accounting guidance and determined that they should be classified as equity instruments, with no recurring fair value measurement required. There have been no changes to the initial carrying amount of the Warrants since issuance.
No Warrants were exercised during the first quarter of 2022. As of March 31, 2022, 19,044 Warrants remain unexercised and such Warrants will remain exercisable in full or from time to time in part at the election of the holders until their expiration on June 30, 2023.
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Note 4 - Income Taxes
The provision for income taxes for the three months ended March 31, 2022, and 2021, consists of the following:

|  |  | For the Three Months Ended March 31,
|  |  |  |  | 2022 |  | 2021
|  |  |  |  | (in thousands)
Current portion of income tax expense: |  |  |  |  |  |  |
Federal |  |  |  |  | $ | (609) |  | $ | —
State |  |  |  |  | (304) |  | (158)
Deferred portion of income tax (expense) benefit |  |  |  |  | (11,948) |  | 52
Income tax expense |  |  |  |  | $ | (12,861) |  | $ | (106)
Effective tax rate |  |  |  |  | 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 limitations on the compensation of covered individuals, changes in valuation allowances, the cumulative effect of other smaller permanent differences, and can also reflect the cumulative effect of an enacted tax rate change, in the period of enactment, on the Company’s net deferred tax asset and liability balance. The quarterly rate and the resulting income tax (expense) benefit can also be affected by the proportional effects of forecasted net income or loss and the correlative effect on the valuation allowance for each period presented, as reflected in the table above. Forecasted net income had a larger impact on the effective tax rate for the three months ended March 31, 2022, compared with the same period in 2021, and valuation allowance adjustments had a larger impact on the effective tax rate for the three months ended March 31, 2021, compared with the same period in 2022.
For all years before 2018, the Company is generally no longer subject to United States federal or state income tax examinations by tax authorities.
Note 5 - Long-Term Debt
The following table summarizes the Company’s total outstanding balance on its Senior Secured Notes net of unamortized discount and deferred financing costs, and Senior Unsecured Notes net of unamortized deferred financing costs, as of March 31, 2022, and December 31, 2021:

|  |  | As of March 31, 2022 |  | As of December 31, 2021
|  |  | (in thousands)
Senior Secured Notes (1) |  |  | $ | 410,525 |  |  | $ | 407,712 |
Senior Unsecured Notes (1) |  |  | 1,569,867 |  |  | 1,673,452 |
Total |  |  | $ | 1,980,392 |  |  | $ | 2,081,164 |

____________________________________________
(1) Senior Secured Notes and Senior Unsecured Notes are defined below.
Credit Agreement
The Company’s Credit Agreement, which is scheduled to mature on September 28, 2023, provides for a senior secured revolving credit facility with a maximum loan amount of $2.5 billion. As of March 31, 2022, the borrowing base and aggregate lender commitments under the Credit Agreement were $1.1 billion. Subsequent to March 31, 2022, the semi-annual borrowing base redetermination was completed, which reaffirmed both the Company’s borrowing base and aggregate lender commitments at $1.1 billion. The next borrowing base redetermination date is scheduled for October 1, 2022.
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 2021 Form 10-K. At the Company’s election, borrowings under the Credit Agreement may be in the form of Eurodollar, Alternate Base Rate (“ABR”), or Swingline loans. Eurodollar loans accrue interest at the London Interbank Offered Rate (“LIBOR”), 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
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are accrued on the unused portion of the aggregate lender commitment amount at rates from the utilization grid and are included in the interest expense line item on the accompanying statements of operations.
LIBOR was discontinued as a global reference rate for new loans and contracts after December 31, 2021. The Credit Agreement specifies that if LIBOR is no longer a widely used benchmark rate, or if it is no longer used for determining interest rates for loans in the United States, a replacement interest rate that fairly reflects the cost to the lenders of funding loans shall be established by the Administrative Agent, as defined in the Credit Agreement, in consultation with the Company. In advance of the maturity date of the Company’s existing Credit Agreement, the Company expects to enter into a new credit agreement in 2022 that will, in addition to other negotiated terms, conditions, agreements, and other provisions, specify a new interest rate for Eurodollar loans. The Company does not expect to incur borrowings in the form of Eurodollar loans prior to that time.
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 20, 2022, March 31, 2022, and December 31, 2021:

| As of April 20, 2022 |  | As of March 31, 2022 |  | As of December 31, 2021
| (in thousands)
Revolving credit facility (1) | $ | — |  |  | $ | — |  |  | $ | — |
Letters of credit (2) | 6,000 |  |  | 6,000 |  |  | 2,500 |
Available borrowing capacity | 1,094,000 |  |  | 1,094,000 |  |  | 1,097,500 |
Total aggregate lender commitment amount | $ | 1,100,000 |  |  | $ | 1,100,000 |  |  | $ | 1,100,000 |

____________________________________________
(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 $2.3 million and $2.7 million as of March 31, 2022, and December 31, 2021, respectively. These costs are being amortized over the term of the revolving credit facility on a straight-line basis.
(2) Letters of credit outstanding reduce the amount available under the revolving credit facility on a dollar-for-dollar basis.
Senior Secured Notes
Senior Secured Notes, net of unamortized discount and deferred financing costs, included within the Senior Notes, net line item on the accompanying balance sheets as of March 31, 2022, and December 31, 2021, consist of the 10.0% Senior Secured Notes due 2025 (“2025 Senior Secured Notes” or “Senior Secured Notes”):

| As of March 31, 2022 |  | As of December 31, 2021
| (in thousands)
Principal amount of 10.0% Senior Secured Notes due 2025 | $ | 446,675 |  |  | $ | 446,675 |
Unamortized debt discount | 28,135 |  |  | 30,236 |
Unamortized deferred financing costs | 8,015 |  |  | 8,727 |
10.0% Senior Secured Notes due 2025, net of unamortized debt discount and deferred financing costs | $ | 410,525 |  |  | $ | 407,712 |

The 2025 Senior Secured Notes are senior obligations of the Company, secured on a second-priority basis, ranking junior to the Company’s obligations under the Credit Agreement. The 2025 Senior Secured Notes rank senior in right of payment with all of the Company’s existing and any future unsecured senior or subordinated debt.
The Company may redeem some or all of its 2025 Senior Secured Notes prior to their maturity at redemption prices based on a premium, plus accrued and unpaid interest, as described in the indenture governing the 2025 Senior Secured Notes.
On April 28, 2022, the Company issued a notice of redemption to the holders of the 2025 Senior Secured Notes notifying such holders that the Company intends to redeem the $446.7 million aggregate principal amount outstanding of its 2025 Senior Secured Notes on June 17, 2022 (“Redemption Date”). In accordance with the terms of the indenture governing the 2025 Senior Secured Notes, the redemption price will be equal to 107.5 percent of the principal amount of the 2025 Senior Secured Notes on the Redemption Date ($1,075 per $1,000 principal amount outstanding), plus accrued and unpaid interest.
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Senior Unsecured Notes
Senior Unsecured Notes, net of unamortized deferred financing costs, included within the Senior Notes, net line item on the accompanying balance sheets as of March 31, 2022, and December 31, 2021, consist of the following (collectively referred to as “Senior Unsecured Notes,” and together with the 2025 Senior Secured Notes, “Senior Notes”):

| As of March 31, 2022 |  | As of December 31, 2021
| Principal Amount |  | Unamortized Deferred Financing Costs |  | Principal Amount, Net |  | Principal Amount |  | Unamortized Deferred Financing Costs |  | Principal Amount, Net
| (in thousands)
5.0% Senior Notes due 2024 | $ | — |  |  | $ | — |  |  | $ | — |  |  | $ | 104,769 |  |  | $ | 403 |  |  | $ | 104,366 |
5.625% Senior Notes due 2025 | 349,118 |  |  | 2,001 |  |  | 347,117 |  |  | 349,118 |  |  | 2,160 |  | 346,958 |
6.75% Senior Notes due 2026 | 419,235 |  |  | 3,095 |  |  | 416,140 |  |  | 419,235 |  |  | 3,270 |  | 415,965 |
6.625% Senior Notes due 2027 | 416,791 |  |  | 3,755 |  |  | 413,036 |  |  | 416,791 |  |  | 3,949 |  | 412,842 |
6.5% Senior Notes due 2028 | 400,000 |  |  | 6,426 |  |  | 393,574 |  |  | 400,000 |  |  | 6,679 |  |  | 393,321 |
Total | $ | 1,585,144 |  |  | $ | 15,277 |  |  | $ | 1,569,867 |  |  | $ | 1,689,913 |  |  | $ | 16,461 |  |  | $ | 1,673,452 |

The Senior Unsecured 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 Unsecured 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 Unsecured Notes.
On February 14, 2022, the Company redeemed all of the $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. Upon redemption, the Company accelerated the amortization of all remaining previously unamortized deferred financing costs. The Company canceled all redeemed 2024 Senior Notes upon settlement.
Please refer to Note 5 - Long-Term Debt in the 2021 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, merge or consolidate with other entities, and with respect to the Company’s restricted subsidiaries, permit the consensual restriction on the ability of such restricted subsidiaries to pay dividends or indebtedness owing to the Company or to any other restricted subsidiaries. The Company was in compliance with all covenants under the Credit Agreement and the indentures governing the Senior Notes as of March 31, 2022, and through the filing of this report. Please refer to Note 5 - Long-Term Debt in the 2021 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, 2022, and 2021, totaled $3.0 million and $4.3 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 2021 Form 10-K. Please refer to Note 6 - Commitments and Contingencies in the 2021 Form 10-K for additional discussion of the Company’s commitments.
Drilling Rig Service Contracts. During the three months ended March 31, 2022, the Company amended certain of its drilling rig contracts resulting in the extension of contract terms. As of March 31, 2022, the Company’s drilling rig commitments totaled
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$27.1 million under contract terms extending through the second quarter of 2023. If all of these contracts were terminated as of March 31, 2022, the Company would avoid a portion of the contractual service commitments; however, the Company would be required to pay $17.3 million in early termination fees. No early termination penalties or standby fees were incurred by the Company during the three months ended March 31, 2022, and the Company does not expect to incur material penalties with regard to its drilling rig contracts during the remainder of 2022.
Drilling and Completion Commitments. During the three months ended March 31, 2022, the Company entered into an agreement that includes minimum drilling and completion footage requirements on certain existing leases. If these minimum requirements are not satisfied by March 31, 2024, the Company will be required to pay liquidated damages based on the difference between the actual footage drilled and completed and the minimum requirements. As of March 31, 2022, the liquidated damages could range from zero to a maximum of $96.0 million, with the maximum exposure assuming no additional development activity occurred prior to March 31, 2024. As of the filing of this report, the Company expects to meet its obligations under this agreement.
Contingencies
The Company is subject to litigation and claims arising in the ordinary course of business. The Company accrues for such items when a liability is both probable and the amount can be reasonably estimated. 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 - Compensation Plans
As of March 31, 2022, 4.9 million shares of common stock were available for grant under the Company’s Equity Incentive Compensation Plan (“Equity Plan”). The Company may also grant other types of long-term incentive-based awards, such as cash awards and performance-based cash awards, to eligible employees.
Performance Share Units
The Company has granted performance share units (“PSU” or “PSUs”) to eligible employees as part of its Equity Plan. The number of shares of the Company’s common stock issued to settle PSUs ranges from zero to two times the number of PSUs awarded and is determined based on certain criteria over a three-year performance period. PSUs generally vest on the third anniversary of the date of the grant or upon other triggering events as set forth in the Equity Plan.
For PSUs granted in 2019, which the Company determined to be equity awards, the settlement criteria include a combination of the Company’s Total Shareholder Return (“TSR”) relative to the TSR of certain peer companies and the Company’s cash return on total capital invested (“CRTCI”) relative to the CRTCI of certain peer companies over the associated three-year performance period. In addition to these performance criteria, the award agreements for these grants also stipulate that if the Company’s absolute TSR is negative over the three-year performance period, the maximum number of shares of common stock that can be issued to settle outstanding PSUs is capped at one times the number of PSUs granted on the award date, regardless of the Company’s TSR and CRTCI performance relative to its peer group. The fair value of the PSUs granted in 2019 was measured on the applicable grant date using the GBM Model, with the assumption that the associated CRTCI performance condition will be met at the target amount at the end of the respective performance period. Compensation expense for PSUs is recognized within general and administrative expense and exploration expense over the vesting periods of the respective awards. As these awards depend on a combination of performance-based settlement criteria and market-based settlement criteria, compensation expense may be adjusted in future periods as the number of units expected to vest increases or decreases based on the Company’s expected CRTCI performance relative to the applicable peer companies.
The Company records compensation expense associated with the issuance of PSUs based on the fair value of the awards as of the date of grant. Total compensation expense recorded for PSUs was $0.7 million and $3.2 million for the three months ended March 31, 2022, and 2021, respectively. As of March 31, 2022, there was $0.7 million of total unrecognized compensation expense related to non-vested PSUs, which is being amortized through mid-2022. There were no material changes to the outstanding and non-vested PSUs during the three months ended March 31, 2022.
Employee Restricted Stock Units
The Company has granted restricted stock units (“RSU” or “RSUs”) to eligible persons as part of its Equity Plan. Each RSU granted represents a right to receive one share of the Company’s common stock upon settlement of the award at the end of the specified vesting period. RSUs generally vest one-third of the total grant on each anniversary date of the grant over the applicable vesting period or upon other triggering events as set forth in the Equity Plan.
The Company records compensation expense associated with the issuance of RSUs based on the fair value of the awards as of the date of grant. The fair value of an RSU is equal to the closing price of the Company’s common stock on the date of the grant. Compensation expense for RSUs is recognized within general and administrative expense and exploration expense over the vesting
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periods of the respective awards. Total compensation expense recorded for employee RSUs was $3.3 million and $2.2 million for the three months ended March 31, 2022, and 2021, respectively. As of March 31, 2022, there was $17.2 million of total unrecognized compensation expense related to non-vested RSUs, which is being amortized through mid-2024. There were no material changes to the outstanding and non-vested RSUs during the three months ended March 31, 2022.
Please refer to Note 7 - Compensation Plans in the 2021 Form 10-K for additional detail on the Company’s Equity Plan.
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, 2022:

| Level 1 |  | Level 2 |  | Level 3
| (in thousands)
Assets: |  |  |  |  |
Derivatives (1) | $ | — |  |  | $ | 18,552 |  |  | $ | — |
Liabilities: |  |  |  |  |
Derivatives (1) | $ | — |  |  | $ | 589,758 |  |  | $ | — |

__________________________________________
(1) This represents a financial asset or liability that is measured at fair value on a recurring basis.
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 December 31, 2021:

| Level 1 |  | Level 2 |  | Level 3
| (in thousands)
Assets: |  |  |  |  |
Derivatives (1) | $ | — |  |  | $ | 24,334 |  |  | $ | — |
Liabilities: |  |  |  |  |
Derivatives (1) | $ | — |  |  | $ | 345,202 |  |  | $ | — |

____________________________________________
(1) This represents a financial asset or liability that is measured at fair value on a recurring basis.
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
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derivative markets are highly active. Please refer to Note 10 - Derivative Financial Instruments in this report, and to Note 10 - Derivative Financial Instruments and Note 8 - Fair Value Measurements in the 2021 Form 10-K for more information regarding the Company’s derivative instruments.
Oil and Gas Properties and Other Property and Equipment
The Company had no assets included in total property and equipment, net, measured at fair value as of March 31, 2022, or December 31, 2021.
No proved property impairment expense was recorded during the three months ended March 31, 2022, or 2021. For the three months ended March 31, 2022, and 2021, the Company recorded impairment expense related to the abandonment and impairment of unproved properties of $1.0 million, and $8.8 million, respectively. These impairments related to actual and anticipated lease expirations, as well as actual and anticipated losses on acreage due to title defects, changes in development plans, and other inherent acreage risks. The balances in the unproved oil and gas properties line item on the accompanying balance sheets as of March 31, 2022, and December 31, 2021, are recorded at carrying value.
Please refer to Note 1 - Summary of Significant Accounting Policies and Note 8 - Fair Value Measurements in the 2021 Form 10-K for more information about the Company’s policies for determining the fair value of its oil and gas producing properties and related impairment expense.
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, 2022, or December 31, 2021, as they were recorded at carrying value, net of any unamortized discounts and deferred financing costs. Please refer to Note 5 - Long-Term Debt above for additional information.

| As of March 31, 2022 |  | As of December 31, 2021
| Principal Amount |  | Fair Value |  | Principal Amount |  | Fair Value
| (in thousands)
10.0% Senior Secured Notes due 2025 | $ | 446,675 |  |  | $ | 486,760 |  |  | $ | 446,675 |  |  | $ | 491,628 |
5.0% Senior Notes due 2024 | $ | — |  |  | $ | — |  |  | $ | 104,769 |  |  | $ | 104,583 |
5.625% Senior Notes due 2025 | $ | 349,118 |  |  | $ | 349,715 |  |  | $ | 349,118 |  |  | $ | 353,091 |
6.75% Senior Notes due 2026 | $ | 419,235 |  |  | $ | 431,158 |  |  | $ | 419,235 |  |  | $ | 431,787 |
6.625% Senior Notes due 2027 | $ | 416,791 |  |  | $ | 428,253 |  |  | $ | 416,791 |  |  | $ | 432,783 |
6.5% Senior Notes due 2028 | $ | 400,000 |  |  | $ | 413,660 |  |  | $ | 400,000 |  |  | $ | 417,284 |

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 RSUs, contingent PSUs, and Warrants, all of which were measured using the treasury stock method. The Warrants became exercisable at the election of the holders on January 15, 2021, and as a result, they were included as potentially dilutive securities on an adjusted weighted-average basis for the portion of the three months ended March 31, 2021, for which they were outstanding. Please refer to Note 3 - Equity and Note 7 - Compensation Plans in this report, and Note 9 - Earnings Per Share in the 2021 Form 10-K for additional detail on these potentially dilutive securities.
When the Company recognizes a net loss from continuing operations, all potentially dilutive shares are anti-dilutive and are consequently excluded from the calculation of diluted net loss per common share. The following table details the weighted-average number of anti-dilutive securities for the periods presented:

|  |  | For the Three Months Ended March 31,
|  |  |  |  | 2022 |  | 2021
|  |  |  |  | (in thousands)
Anti-dilutive |  |  |  |  | — |  | 8,106

16

The following table sets forth the calculations of basic and diluted net income (loss) per common share:

|  |  | For the Three Months Ended March 31,
|  |  |  |  | 2022 |  | 2021
|  |  |  |  | (in thousands, except per share data)
Net income (loss) |  |  |  |  | $ | 48,764 |  |  | $ | (251,269) |
Basic weighted-average common shares outstanding |  |  |  |  | 121,907 |  | 114,759
Dilutive effect of non-vested RSUs and contingent PSUs |  |  |  |  | 2,253 |  | —
Dilutive effect of Warrants |  |  |  |  | 19 |  | —
Diluted weighted-average common shares outstanding |  |  |  |  | 124,179 |  | 114,759
Basic net income (loss) per common share |  |  |  |  | $ | 0.40 |  |  | $ | (2.19) |
Diluted net income (loss) per common share |  |  |  |  | $ | 0.39 |  |  | $ | (2.19) |

Note 10 - 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, 2022, all contracts were entered into for other-than-trading purposes. The Company’s commodity derivative contracts consist of swap and collar arrangements for oil, gas, and NGL production. In a typical commodity swap agreement, if the agreed upon published third-party index price (“index price”) is lower than the swap fixed price, the Company receives the difference between the index price and the agreed upon swap fixed price. If the index price is higher than the swap fixed 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 the filing of this report, the Company has basis swap contracts with fixed price differentials between:
•NYMEX WTI and WTI Midland for a portion of its Midland Basin oil production with sales contracts that settle at WTI Midland prices;
•NYMEX WTI and Intercontinental Exchange Brent Crude (“ICE Brent”) for a portion of its Midland Basin oil production with sales contracts that settle at ICE Brent 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 Henry Hub (“HH”) and Inside FERC Tennessee Texas, Zone 0 (“IF Tenn TX Z0”) for a portion of its South Texas gas production with sales contracts that settle at IF Tenn TX Z0 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 South Texas gas production with sales contracts that settle at IF WAHA prices.
The Company has also entered into crude 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, 2022, the Company had commodity derivative contracts outstanding through the fourth quarter of 2025 as summarized in the table below:

|  |  |  | Contract Period |  |  |  |  |  |
|  | Second Quarter 2022 |  | Third Quarter 2022 |  | Fourth Quarter 2022 |  | 2023 |  | 2024 |  | 2025 |  |  |  |
Oil Derivatives (volumes in MBbl and prices in $ per Bbl): |  |  |  |
Swaps |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
NYMEX WTI Volumes |  | 2,451 |  |  | 1,938 |  |  | 1,923 |  |  | 1,190 |  |  | — |  |  | — |  |  |  |  |
Weighted-Average Contract Price |  | $ | 52.71 |  |  | $ | 44.63 |  |  | $ | 44.58 |  |  | $ | 45.20 |  |  | $ | — |  |  | $ | — |  |  |  |  |
ICE Brent Volumes |  | — |  |  | — |  |  | — |  |  | 3,650 |  |  | 614 |  |  | — |  |  |  |  |
Weighted-Average Contract Price |  | $ | — |  |  | $ | — |  |  | $ | — |  |  | $ | 86.50 |  |  | $ | 85.26 |  |  | $ | — |  |  |  |  |
Collars |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
NYMEX WTI Volumes |  | 894 |  |  | 1,114 |  |  | 1,128 |  |  | 858 |  |  | — |  |  | — |  |  |  |  |
Weighted-Average Floor Price |  | $ | 56.94 |  |  | $ | 64.77 |  |  | $ | 63.74 |  |  | $ | 60.00 |  |  | $ | — |  |  | $ | — |  |  |  |  |
Weighted-Average Ceiling Price |  | $ | 64.93 |  |  | $ | 71.89 |  |  | $ | 75.48 |  |  | $ | 73.09 |  |  | $ | — |  |  | $ | — |  |  |  |  |
Basis Swaps |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
WTI Midland-NYMEX WTI Volumes |  | 2,374 |  |  | 2,442 |  |  | 2,462 |  |  | 885 |  |  | — |  |  | — |  |  |  |  |
Weighted-Average Contract Price |  | $ | 1.15 |  |  | $ | 1.15 |  |  | $ | 1.15 |  |  | $ | 0.60 |  |  | $ | — |  |  | $ | — |  |  |  |  |
NYMEX WTI-ICE Brent Volumes |  | 910 |  |  | 920 |  |  | 920 |  |  | — |  |  | — |  |  | — |  |  |  |  |
Weighted-Average Contract Price |  | $ | (7.78) |  |  | $ | (7.78) |  |  | $ | (7.78) |  |  | $ | — |  |  | $ | — |  |  | $ | — |  |  |  |  |
WTI Houston MEH-NYMEX WTI Volumes |  | 349 |  |  | 335 |  |  | 374 |  |  | 646 |  |  | — |  |  | — |  |  |  |  |
Weighted-Average Contract Price |  | $ | 1.25 |  |  | $ | 1.25 |  |  | $ | 1.25 |  |  | $ | 1.24 |  |  | $ | — |  |  | $ | — |  |  |  |  |
Roll Differential Swaps |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
NYMEX WTI Volumes |  | 3,359 |  |  | 3,288 |  |  | 3,248 |  |  | 4,968 |  |  | — |  |  | — |  |  |  |  |
Weighted-Average Contract Price |  | $ | 0.21 |  |  | $ | 0.22 |  |  | $ | 0.21 |  |  | $ | 0.62 |  |  | $ | — |  |  | $ | — |  |  |  |  |
Gas Derivatives (volumes in BBtu and prices in $ per MMBtu): |  |  |  |
Swaps |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
NYMEX HH volumes |  | 1,977 |  |  | 1,677 |  |  | 1,903 |  |  | — |  |  | — |  |  | — |  |  |  |  |
Weighted-Average Contract Price |  | $ | 3.95 |  |  | $ | 4.02 |  |  | $ | 4.25 |  |  | $ | — |  |  | $ | — |  |  | $ | — |  |  |  |  |
IF HSC Volumes |  | 6,808 |  |  | 6,934 |  |  | 6,982 |  |  | — |  |  | — |  |  | — |  |  |  |  |
Weighted-Average Contract Price |  | $ | 2.34 |  |  | $ | 2.37 |  |  | $ | 2.47 |  |  | $ | — |  |  | $ | — |  |  | $ | — |  |  |  |  |
IF WAHA Volumes |  | 3,079 |  |  | 3,085 |  |  | 3,067 |  |  | 900 |  |  | — |  |  | — |  |  |  |  |
Weighted-Average Contract Price |  | $ | 2.09 |  |  | $ | 2.19 |  |  | $ | 2.22 |  |  | $ | 3.98 |  |  | $ | — |  |  | $ | — |  |  |  |  |
Collars |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
NYMEX HH Volumes |  | 1,270 |  |  | 760 |  |  | 1,908 |  |  | 17,098 |  |  | — |  |  | — |  |  |  |  |
Weighted-Average Floor Price |  | $ | 3.00 |  |  | $ | 3.25 |  |  | $ | 3.50 |  |  | $ | 3.31 |  |  | $ | — |  |  | $ | — |  |  |  |  |
Weighted-Average Ceiling Price |  | $ | 4.48 |  |  | $ | 5.45 |  |  | $ | 4.44 |  |  | $ | 5.59 |  |  | $ | — |  |  | $ | — |  |  |  |  |
IF HSC Volumes |  | — |  |  | — |  |  | — |  |  | 900 |  |  | $ | — |  |  | $ | — |  |  |  |  |
Weighted-Average Floor Price |  | $ | — |  |  | $ | — |  |  | $ | — |  |  | $ | 3.38 |  |  | $ | — |  |  | $ | — |  |  |  |  |
Weighted-Average Ceiling Price |  | $ | — |  |  | $ | — |  |  | $ | — |  |  | $ | 7.75 |  |  | $ | — |  |  | $ | — |  |  |  |  |
Basis Swaps |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
IF Tenn TX Z0-NYMEX HH Volumes |  | 1,270 |  |  | 760 |  |  | — |  |  | — |  |  | — |  |  | — |  |  |  |  |
Weighted-Average Contract Price |  | $ | (0.14) |  |  | $ | (0.14) |  |  | $ | — |  |  | $ | — |  |  | $ | — |  |  | $ | — |  |  |  |  |
IF WAHA-NYMEX HH Volumes |  | — |  |  | — |  |  | — |  |  | 7,247 |  |  | 20,958 |  |  | 15,727 |  |  |  |  |
Weighted-Average Contract Price |  | $ | — |  |  | $ | — |  |  | $ | — |  |  | $ | (1.02) |  |  | $ | (0.86) |  |  | $ | (0.66) |  |  |  |  |

18

|  |  |  | Contract Period (continued) |  |  |  |  |  |
|  | Second Quarter 2022 |  | Third Quarter 2022 |  | Fourth Quarter 2022 |  | 2023 |  | 2024 |  | 2025 |  |  |  |
NGL Derivatives (volumes in MBbl and prices in $ per Bbl): |  |  |  |
Swaps |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
OPIS Propane Mont Belvieu Non-TET Volumes |  | 269 |  |  | 106 |  |  | 113 |  |  | — |  |  | — |  |  | — |  |  |  |  |
Weighted-Average Contract Price |  | $ | 41.69 |  |  | $ | 35.70 |  |  | $ | 35.91 |  |  | $ | — |  |  | $ | — |  |  | $ | — |  |  |  |  |
Collars |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
OPIS Propane Mont Belvieu Non-TET Volumes |  | 253 |  |  | 164 |  |  | 173 |  |  | — |  |  | — |  |  | — |  |  |  |  |
Weighted-Average Floor Price |  | $ | 25.94 |  |  | $ | 24.09 |  |  | $ | 24.11 |  |  | $ | — |  |  | $ | — |  |  | $ | — |  |  |  |  |
Weighted-Average Ceiling Price |  | $ | 31.69 |  |  | $ | 27.84 |  |  | $ | 28.13 |  |  | $ | — |  |  | $ | — |  |  | $ | — |  |  |  |  |

Commodity Derivative Contracts Entered Into Subsequent to March 31, 2022
Subsequent to March 31, 2022, the Company entered into the following commodity derivative contracts:
•fixed price ICE Brent oil swap contract for the first quarter of 2024 for a total of 0.3 MMBbl of oil production at a contract price of $86.00 per Bbl;
•NYMEX WTI oil collar contract for the fourth quarter of 2024 for a total of 0.1 MMBbl of oil production at a floor price of $75.00 per Bbl and a ceiling price of $78.20 per Bbl;
•IF HSC-NYMEX HH basis swap contract for the first quarter of 2023 for a total of 1,337 BBtu at a contract price of $0.005 per MMBtu; and
•IF WAHA-NYMEX HH basis swap contracts for 2025 for a total of 4,774 BBtu at a weighted-average contract price of $(0.64) 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 liability of $571.2 million and $320.9 million as of March 31, 2022, and December 31, 2021, respectively.
The following table details the fair value of commodity derivative contracts recorded in the accompanying balance sheets, by category:

| As of March 31, 2022 |  | As of December 31, 2021
| (in thousands)
Derivative assets: |  |  |
Current assets | $ | 9,649 |  |  | $ | 24,095 |
Noncurrent assets | 8,903 |  |  | 239 |
Total derivative assets | $ | 18,552 |  |  | $ | 24,334 |
Derivative liabilities: |  |  |
Current liabilities | $ | 538,127 |  |  | $ | 319,506 |
Noncurrent liabilities | 51,631 |  |  | 25,696 |
Total derivative liabilities | $ | 589,758 |  |  | $ | 345,202 |

Offsetting of Derivative Assets and Liabilities
As of March 31, 2022, and December 31, 2021, 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.
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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, 2022 |  | December 31, 2021 |  | March 31, 2022 |  | December 31, 2021
| (in thousands)
Gross amounts presented in the accompanying balance sheets | $ | 18,552 |  |  | $ | 24,334 |  |  | $ | (589,758) |  |  | $ | (345,202) |
Amounts not offset in the accompanying balance sheets | (18,262) |  |  | (22,862) |  |  | 18,262 |  |  | 22,862 |
Net amounts | $ | 290 |  |  | $ | 1,472 |  |  | $ | (571,496) |  |  | $ | (322,340) |

The following table summarizes the commodity components of the derivative settlement loss, and the net derivative 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,
|  |  |  |  | 2022 |  | 2021
|  |  |  |  | (in thousands)
Derivative settlement loss: |  |  |  |  |  |  |
Oil contracts |  |  |  |  | $ | 129,168 |  |  | $ | 56,329 |
Gas contracts |  |  |  |  | 27,051 |  |  | 40,448 |
NGL contracts |  |  |  |  | 11,964 |  |  | 11,108 |
Total derivative settlement loss |  |  |  |  | $ | 168,183 |  |  | $ | 107,885 |
Net derivative loss: |  |  |  |  |  |  |
Oil contracts |  |  |  |  | $ | 315,050 |  |  | $ | 265,815 |
Gas contracts |  |  |  |  | 86,175 |  |  | 48,922 |
NGL contracts |  |  |  |  | 17,296 |  |  | 29,952 |
Total net derivative loss |  |  |  |  | $ | 418,521 |  |  | $ | 344,689 |

Credit Related Contingent Features
As of March 31, 2022, and through the filing of this report, all of the Company’s derivative counterparties were members of the Company’s Credit Agreement 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.
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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, 2022, compared with the three months ended December 31, 2021 (“sequential quarterly” or “sequentially”), as well as the year-to-date (“YTD”) change between the three months ended March 31, 2022, compared with the three months ended March 31, 2021 (“YTD 2022-over-YTD 2021”).
Overview of the Company
General Overview
Our strategic objective is to be a premier operator of top-tier oil and gas assets. 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 short-term operational and financial goals include generating positive cash flows while strengthening our balance sheet through absolute debt reduction and improved leverage metrics, and increasing the value of our capital project inventory through exploration and development optimization. Our long-term vision is to sustainably grow value for all of our stakeholders. Our strategy for achieving our goals is to focus on high-quality economic drilling, completion, and production opportunities. Our investment portfolio is comprised of oil and gas producing assets in the state of Texas, specifically in the Midland Basin of West Texas and in the Maverick Basin of South Texas.
We are committed to exceptional safety, health, and environmental stewardship; supporting the professional development of a diverse and thriving team of employees; making a positive impact in the communities where we live and work; and transparency in reporting on our progress in these areas. We have prioritized ESG initiatives by, among other things, integrating enhanced environmental and social programs throughout the organization and setting near-term and medium-term goals that include reducing flaring and greenhouse gas emissions intensity and maintaining low methane emissions intensity. Additionally, we are putting systems in place to track additional ESG metrics to enable increased reporting in the future and to increase employee awareness. 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, and environmental, health, and safety measures.
Prices for the commodities produced by our industry remained strong during the first quarter of 2022 with benchmark oil prices increasing compared with the fourth quarter of 2021, in part due to the impact of the conflict between Russia and Ukraine on global commodity and financial markets, and in response to economic and trade sanctions that certain countries have imposed on Russia. Additionally, although the Pandemic remains a global health crisis and continues to evolve, consumer demand has strengthened as cases of the Omicron variant of COVID-19 have decreased from winter levels. Increased demand for oil and gas products has outpaced increased supply, resulting in strong commodity prices which, for 2021, rose to their highest average annual prices since 2014. However, global commodity and financial markets remain subject to heightened levels of uncertainty and volatility related to these events, and future disruptions and industry-specific impacts could result, which 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 2021 Form 10-K. Despite continuing impacts of geopolitical issues, the Pandemic, and future uncertainty, we expect to maintain our ability to sustain strong operational performance and financial stability while maximizing returns, improving leverage metrics, and increasing the value of our top-tier Midland Basin and South Texas assets.
Throughout the Pandemic, the safety of our employees, contractors, and the communities where we work has remained our first priority. While our core business operations required certain individuals to be physically present at well site locations, the majority of our office-based employees worked remotely from the onset of the Pandemic through February of 2022. We maintain and continually assess procedures designed to limit the spread of COVID-19, and we continue to communicate to and train all of our employees regarding best practices for maintaining a healthy and safe work environment. We believe that we meet or exceed Centers for Disease Control and Prevention and federal Occupational Safety and Health Act guidelines related to the prevention of the transmission of COVID-19. Throughout the Pandemic, we have operated without significant disruptions to our business, and we believe that our pre-existing control environment and internal controls continue to be effective.
Areas of Operations
Our Midland Basin assets are comprised of approximately 80,000 net acres located in the Permian Basin in West Texas (“Midland Basin”). In the first quarter of 2022, drilling and completion activities within our RockStar and Sweetie Peck positions continued to focus primarily on development optimization and further delineating our Midland Basin position. Our current Midland Basin position provides substantial future development opportunities within multiple oil-rich intervals, including the Spraberry and Wolfcamp formations.
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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 2022, our operations in South Texas were focused on production from both the Austin Chalk formation and Eagle Ford shale formation, and further development 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.
First Quarter 2022 Overview and Outlook for the Remainder of 2022
During the first quarter of 2022, we remained committed to our goal of reducing the principal balance of our outstanding debt through cash flow generation. For the three months ended March 31, 2022, net cash provided by operating activities exceeded net cash used in investing activities by $192.0 million, and we reduced the principal balance of our total outstanding long-term debt by $104.8 million. Further, cash and cash equivalents increased from $332.7 million at December 31, 2021, to $419.9 million at March 31, 2022. We executed on this goal through strong operational performance and a diligent focus on cost management, and we benefited from increased commodity pricing which has improved from historic lows experienced during the height of the Pandemic.
Our 2022 capital program is expected to be approximately $750.0 million. Our financial and operational flexibility allows us to continually monitor the economic environment and adjust our activity level as warranted. Our 2022 capital program remains focused on highly economic oil development projects in both our Midland Basin and South Texas assets. 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 grow cash flows, improve leverage metrics, and maintain strong financial flexibility. Please refer to Overview of Liquidity and Capital Resources below for discussion of how we expect to fund the remainder of our 2022 capital program.
Financial and Operational Results. Average net daily equivalent production for the three months ended March 31, 2022, decreased three percent sequentially to 153.3 MBOE, primarily driven by a decrease in oil volumes of 15 percent, or 12.7 MBbl per day, which was the result of timing of well completions. The decrease in oil volumes was partially offset by an increase of 37 percent, or 6.3 MBbl per day, in NGL volumes.
Increases in benchmark oil prices during the first quarter of 2022 resulted in an increased realized oil price, before the effect of derivative settlements, of 24 percent sequentially. Gas and NGL realized prices, before the effect of derivative settlements, decreased sequentially by 15 percent, and three percent, respectively. Total realized price before the effect of derivative settlements (“realized price” or “realized prices”) per BOE increased six percent sequentially. The increase in total realized price per BOE was partially offset by the decrease in total net equivalent production volumes, resulting in a one percent increase in oil, gas, and NGL production revenue, which was $858.7 million for the three months ended March 31, 2022, compared with $852.4 million for the three months ended December 31, 2021. Oil, gas, and NGL production expense per BOE of $10.49 for the three months ended March 31, 2022, increased seven percent sequentially, primarily as a result of increased ad valorem tax expense, production tax expense, and transportation costs per BOE.
We recorded a net derivative loss of $418.5 million for the three months ended March 31, 2022, compared to a net derivative gain of $22.5 million for the three months ended December 31, 2021. Included within these amounts are derivative settlement losses of $168.2 million and $268.7 million for the three months ended March 31, 2022, and December 31, 2021, respectively, resulting from increased benchmark commodity prices.
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, 2022, and December 31, 2021, and Between the Three Months Ended March 31, 2022, and 2021 below for additional discussion.
Operational and financial activities during the three months ended March 31, 2022, resulted in the following:
•Net cash provided by operating activities of $342.1 million for the three months ended March 31, 2022, compared with $429.6 million for the three months ended December 31, 2021.
•A cash and cash equivalents balance of $419.9 million and no outstanding balance on the revolving credit facility as of March 31, 2022, and a reduction of the principal balance of our total outstanding long-term debt of $104.8 million from December 31, 2021, to March 31, 2022.
•Net income of $48.8 million, or $0.39 per diluted share, for the three months ended March 31, 2022, compared with net income of $424.9 million, or $3.43 per diluted share, for the three months ended December 31, 2021. Net income for the three months ended March 31, 2022, was primarily a result of strong oil pricing partially offset by a net derivative loss of $418.5 million. Please refer to Comparison of Financial Results and Trends Between the Three Months Ended March 31, 2022, and December 31, 2021, and Between the Three Months Ended March 31, 2022, and 2021 below for additional discussion regarding the components of net income (loss) for the periods presented.
•Adjusted EBITDAX, a non-GAAP financial measure, for the three months ended March 31, 2022, was $524.6 million, compared with $406.9 million for the three months ended December 31, 2021. Please refer to the caption Non-GAAP
22

Financial Measures below for additional discussion and our definition of adjusted EBITDAX and reconciliations to net income (loss) and net cash provided by operating activities.
Operational Activities. In our Midland Basin program, we operated three drilling rigs and one completion crew, and drilled 16 gross (14 net) wells and completed six gross (five net) wells during the first quarter of 2022. Net equivalent production volumes decreased sequentially by 17 percent to 7.9 MMBOE. Costs incurred in our Midland Basin program during the three months ended March 31, 2022, totaled $84.4 million, or 48 percent of our total costs incurred for the period. During the remainder of 2022, we anticipate operating three drilling rigs and one completion crew, which will continue to utilize both zipper or simul-frac techniques, where two or more horizontal wells are stimulated at the same time using a single fleet. Activity will focus primarily on developing the Spraberry and Wolfcamp formations within our RockStar and Sweetie Peck positions in the Midland Basin.
In our South Texas program, we operated two drilling rigs and one completion crew, and drilled nine gross (nine net) wells and completed 13 gross (13 net) wells during the first quarter of 2022. Net equivalent production volumes increased sequentially by 16 percent to 5.9 MMBOE. Costs incurred in our South Texas program during the three months ended March 31, 2022, totaled $76.1 million, or 43 percent of our total costs incurred for the period. During the remainder of 2022, we anticipate operating two drilling rigs and one completion crew, focused primarily on developing the Austin Chalk formation.
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, 2022:

| Midland Basin |  | South Texas (1) |  | Total
| Gross |  | Net |  | Gross |  | Net |  | Gross |  | Net
Wells drilled but not completed at December 31, 2021 | 30 |  |  | 27 |  |  | 32 |  |  | 32 |  |  | 62 |  |  | 59 |
Wells drilled | 16 |  |  | 14 |  |  | 9 |  |  | 9 |  |  | 25 |  |  | 23 |
Wells completed | (6) |  |  | (5) |  |  | (13) |  |  | (13) |  |  | (19) |  |  | (18) |
Wells drilled but not completed at March 31, 2022 | 40 |  |  | 36 |  |  | 28 |  |  | 28 |  |  | 68 |  |  | 64 |

____________________________________________
(1) The South Texas drilled but not completed well count as of March 31, 2022, includes 11 gross (11 net) wells that are not included in our five-year development plan, 10 of which are in the Eagle Ford shale.
Costs Incurred. Costs incurred in oil and gas property acquisition, exploration, and development activities, whether capitalized or expensed, totaled $175.1 million for the three months ended March 31, 2022, and were primarily incurred in our Midland Basin and South Texas programs as further detailed in Operational Activities above.
23

Production Results. The table below presents our production by product type for each of our assets for the three months ended March 31, 2022, December 31, 2021, and March 31, 2021:

| For the Three Months Ended
| March 31, 2022 |  | December 31, 2021 |  |  |  | March 31, 2021
Midland Basin Production: |  |  |  |  |  |  |
Oil (MMBbl) | 5.3 |  |  | 6.7 |  |  |  |  | 5.1 |
Gas (Bcf) | 15.5 |  |  | 16.5 |  |  |  |  | 10.6 |
NGLs (MMBbl) | — |  |  | — |  |  |  |  | — |
Equivalent (MMBOE) | 7.9 |  |  | 9.4 |  |  |  |  | 6.9 |
Average net daily equivalent (MBOE per day) | 87.4 |  |  | 102.6 |  |  |  |  | 76.1 |
Relative percentage | 57 | % |  | 65 | % |  |  |  | 68 | %
South Texas Production: |  |  |  |  |  |  |
Oil (MMBbl) | 1.2 |  |  | 1.1 |  |  |  |  | 0.3 |
Gas (Bcf) | 15.9 |  |  | 14.7 |  |  |  |  | 11.0 |
NGLs (MMBbl) | 2.1 |  |  | 1.6 |  |  |  |  | 1.0 |
Equivalent (MMBOE) | 5.9 |  |  | 5.1 |  |  |  |  | 3.2 |
Average net daily equivalent (MBOE per day) | 65.8 |  |  | 55.7 |  |  |  |  | 35.5 |
Relative percentage | 43 | % |  | 35 | % |  |  |  | 32 | %
Total Production: |  |  |  |  |  |  |
Oil (MMBbl) | 6.5 |  |  | 7.8 |  |  |  |  | 5.4 |
Gas (Bcf) | 31.4 |  |  | 31.3 |  |  |  |  | 21.5 |
NGLs (MMBbl) | 2.1 |  |  | 1.6 |  |  |  |  | 1.0 |
Equivalent (MMBOE) | 13.8 |  |  | 14.6 |  |  |  |  | 10.0 |
Average net daily equivalent (MBOE per day) | 153.3 |  |  | 158.3 |  |  |  |  | 111.6 |

____________________________________________
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, 2022, and December 31, 2021, and Between the Three Months Ended March 31, 2022, and 2021 below for discussion on production.
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.
24

The following table summarizes commodity price data, as well as the effect of derivative settlements, for the three months ended March 31, 2022, December 31, 2021, and March 31, 2021:

| For the Three Months Ended
| March 31, 2022 |  | December 31, 2021 |  | March 31, 2021
Oil (per Bbl): |  |  |  |  |
Average NYMEX contract monthly price | $ | 94.29 |  |  | $ | 77.19 |  |  | $ | 57.84 |
Realized price | $ | 94.03 |  |  | $ | 76.08 |  |  | $ | 56.33 |
Effect of oil derivative settlements | $ | (20.00) |  |  | $ | (22.97) |  |  | $ | (10.38) |
Gas: |  |  |  |  |
Average NYMEX monthly settle price (per MMBtu) | $ | 4.95 |  |  | $ | 5.83 |  |  | $ | 2.69 |
Realized price (per Mcf) | $ | 5.42 |  |  | $ | 6.35 |  |  | $ | 4.16 |
Effect of gas derivative settlements (per Mcf) | $ | (0.86) |  |  | $ | (2.05) |  |  | $ | (1.88) |
NGLs (per Bbl): |  |  |  |  |
Average OPIS price (1) | $ | 48.36 |  |  | $ | 44.21 |  |  | $ | 30.47 |
Realized price | $ | 38.56 |  |  | $ | 39.63 |  |  | $ | 26.93 |
Effect of NGL derivative settlements | $ | (5.67) |  |  | $ | (16.64) |  |  | $ | (10.79) |

____________________________________________
(1) Average OPIS price per barrel of NGL, historical or strip, assumes a composite barrel product mix of 37% Ethane, 32% Propane, 6% Isobutane, 11% Normal Butane, and 14% Natural Gasoline for all periods presented. This product mix represents the industry standard composite barrel and does not necessarily represent our product mix for NGL production. Realized prices reflect our actual product mix.
Oil prices continued to increase during the first quarter of 2022, compared with 2021. However, given the uncertainty surrounding the ongoing conflict between Russia and Ukraine, the economic and trade sanctions that certain countries have imposed on Russia, the dynamic nature of the Pandemic, and the potential impacts to global commodity and financial markets, we expect future 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. In addition to supply and demand fundamentals, as a global commodity, the price of oil is 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 area of our operations and beyond. Please refer to First Quarter 2022 Overview and Outlook for the Remainder of 2022 above for additional discussion of factors impacting pricing.
The following table summarizes 12-month strip prices for NYMEX WTI oil, NYMEX Henry Hub gas, and OPIS NGLs as of April 20, 2022, and March 31, 2022:

| As of April 20, 2022 |  | As of March 31, 2022
NYMEX WTI oil (per Bbl) | $ | 96.54 |  |  | $ | 93.25 |
NYMEX Henry Hub gas (per MMBtu) | $ | 6.89 |  |  | $ | 5.72 |
OPIS NGLs (per Bbl) | $ | 47.89 |  |  | $ | 47.30 |

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 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 10 - 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.
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Financial Results of Operations and Additional Comparative Data
The tables below provide information regarding selected production and financial information for the three months ended March 31, 2022, and the preceding three quarters:

| For the Three Months Ended
| March 31, |  | December 31, |  | September 30, |  | June 30,
| 2022 |  | 2021 |  | 2021 |  | 2021
| (in millions)
Production (MMBOE) | 13.8 |  |  | 14.6 |  |  | 14.3 |  |  | 12.4 |
Oil, gas, and NGL production revenue | $ | 858.7 |  |  | $ | 852.4 |  |  | $ | 759.8 |  |  | $ | 562.6 |
Oil, gas, and NGL production expense | $ | 144.7 |  |  | $ | 143.3 |  |  | $ | 135.7 |  |  | $ | 125.5 |
Depletion, depreciation, amortization, and asset retirement obligation liability accretion | $ | 159.5 |  |  | $ | 200.0 |  |  | $ | 202.7 |  |  | $ | 204.7 |
Exploration | $ | 9.0 |  |  | $ | 12.6 |  |  | $ | 8.7 |  |  | $ | 8.7 |
General and administrative | $ | 25.0 |  |  | $ | 37.1 |  |  | $ | 25.5 |  |  | $ | 24.6 |
Net income (loss) | $ | 48.8 |  |  | $ | 424.9 |  |  | $ | 85.6 |  |  | $ | (223.0) |

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

| For the Three Months Ended
| March 31, |  | December 31, |  | September 30, |  | June 30,
| 2022 |  | 2021 |  | 2021 |  | 2021
Average net daily equivalent production (MBOE per day) | 153.3 |  |  | 158.3 |  |  | 155.8 |  |  | 136.5 |
Lease operating expense (per BOE) | $ | 4.25 |  |  | $ | 4.21 |  |  | $ | 4.20 |  |  | $ | 4.62 |
Transportation costs (per BOE) | $ | 2.74 |  |  | $ | 2.61 |  |  | $ | 2.41 |  |  | $ | 3.01 |
Production taxes as a percent of oil, gas, and NGL production revenue | 4.7 | % |  | 4.8 | % |  | 4.7 | % |  | 4.5 | %
Ad valorem tax expense (per BOE) | $ | 0.58 |  |  | $ | 0.22 |  |  | $ | 0.38 |  |  | $ | 0.45 |
Depletion, depreciation, amortization, and asset retirement obligation liability accretion (per BOE) | $ | 11.56 |  |  | $ | 13.74 |  |  | $ | 14.14 |  |  | $ | 16.48 |
General and administrative (per BOE) | $ | 1.81 |  |  | $ | 2.55 |  |  | $ | 1.78 |  |  | $ | 1.98 |

____________________________________________
Note: Amounts may not calculate due to rounding.
26

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, 2022 |  | December 31, 2021 |  | March 31, 2021 |  | March 31, 2022 & December 31, 2021 |  | March 31, 2022 & 2021 |  | March 31, 2022 & December 31, 2021 |  | March 31, 2022 & 2021
Net production volumes: (1) |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Oil (MMBbl) |  |  |  |  |  |  |  |  | 6.5 |  |  | 7.8 |  |  | 5.4 |  |  | (1.3) |  |  | 1.0 |  |  | (17) | % |  | 19 | %
Gas (Bcf) |  |  |  |  |  |  |  |  | 31.4 |  |  | 31.3 |  |  | 21.5 |  |  | 0.1 |  |  | 9.8 |  |  | — | % |  | 46 | %
NGLs (MMBbl) |  |  |  |  |  |  |  |  | 2.1 |  |  | 1.6 |  |  | 1.0 |  |  | 0.5 |  |  | 1.1 |  |  | 34 | % |  | 105 | %
Equivalent (MMBOE) |  |  |  |  |  |  |  |  | 13.8 |  |  | 14.6 |  |  | 10.0 |  |  | (0.8) |  |  | 3.7 |  |  | (5) | % |  | 37 | %
Average net daily production: (1) |  |  |  |  |  |  |  |
Oil (MBbl per day) |  |  |  |  |  |  |  |  | 71.8 |  |  | 84.5 |  |  | 60.3 |  |  | (12.7) |  |  | 11.4 |  |  | (15) | % |  | 19 | %
Gas (MMcf per day) |  |  |  |  |  |  |  |  | 348.4 |  |  | 339.7 |  |  | 239.4 |  |  | 8.7 |  |  | 109.1 |  |  | 3 | % |  | 46 | %
NGLs (MBbl per day) |  |  |  |  |  |  |  |  | 23.4 |  |  | 17.2 |  |  | 11.4 |  |  | 6.3 |  |  | 12.0 |  |  | 37 | % |  | 105 | %
Equivalent (MBOE per day) |  |  |  |  |  |  |  |  | 153.3 |  |  | 158.3 |  |  | 111.6 |  |  | (5.0) |  |  | 41.6 |  |  | (3) | % |  | 37 | %
Oil, gas, and NGL production revenue (in millions): (1) |  |  |  |  |  |  |  |
Oil production revenue |  |  |  |  |  |  |  |  | $ | 607.3 |  |  | $ | 591.3 |  |  | $ | 305.8 |  |  | $ | 16.0 |  |  | $ | 301.5 |  |  | 3 | % |  | 99 | %
Gas production revenue |  |  |  |  |  |  |  |  | 170.0 |  |  | 198.5 |  |  | 89.7 |  |  | (28.5) |  |  | 80.4 |  |  | (14) | % |  | 90 | %
NGL production revenue |  |  |  |  |  |  |  |  | 81.4 |  |  | 62.6 |  |  | 27.7 |  |  | 18.8 |  |  | 53.6 |  |  | 30 | % |  | 193 | %
Total oil, gas, and NGL production revenue |  |  |  |  |  |  |  |  | $ | 858.7 |  |  | $ | 852.4 |  |  | $ | 423.2 |  |  | $ | 6.4 |  |  | $ | 435.6 |  |  | 1 | % |  | 103 | %
Oil, gas, and NGL production expense (in millions): (1) |  |  |  |  |  |  |  |
Lease operating expense |  |  |  |  |  |  |  |  | $ | 58.6 |  |  | $ | 61.3 |  |  | $ | 46.7 |  |  | $ | (2.8) |  |  | $ | 11.9 |  |  | (5) | % |  | 26 | %
Transportation costs |  |  |  |  |  |  |  |  | 37.7 |  |  | 38.1 |  |  | 29.6 |  |  | (0.3) |  |  | 8.2 |  |  | (1) | % |  | 28 | %
Production taxes |  |  |  |  |  |  |  |  | 40.4 |  |  | 40.7 |  |  | 19.5 |  |  | (0.3) |  |  | 20.9 |  |  | (1) | % |  | 107 | %
Ad valorem tax expense |  |  |  |  |  |  |  |  | 8.0 |  |  | 3.2 |  |  | 5.2 |  |  | 4.8 |  |  | 2.8 |  |  | 150 | % |  | 53 | %
Total oil, gas, and NGL production expense |  |  |  |  |  |  |  |  | $ | 144.7 |  |  | $ | 143.3 |  |  | $ | 100.9 |  |  | $ | 1.4 |  |  | $ | 43.8 |  |  | 1 | % |  | 43 | %
Realized price: |  |  |  |  |  |  |  |
Oil (per Bbl) |  |  |  |  |  |  |  |  | $ | 94.03 |  |  | $ | 76.08 |  |  | $ | 56.33 |  |  | $ | 17.95 |  |  | $ | 37.70 |  |  | 24 | % |  | 67 | %
Gas (per Mcf) |  |  |  |  |  |  |  |  | $ | 5.42 |  |  | $ | 6.35 |  |  | $ | 4.16 |  |  | $ | (0.93) |  |  | $ | 1.26 |  |  | (15) | % |  | 30 | %
NGLs (per Bbl) |  |  |  |  |  |  |  |  | $ | 38.56 |  |  | $ | 39.63 |  |  | $ | 26.93 |  |  | $ | (1.07) |  |  | $ | 11.63 |  |  | (3) | % |  | 43 | %
Per BOE |  |  |  |  |  |  |  |  | $ | 62.25 |  |  | $ | 58.54 |  |  | $ | 42.11 |  |  | $ | 3.71 |  |  | $ | 20.14 |  |  | 6 | % |  | 48 | %
Per BOE data: (1) |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Oil, gas, and NGL production expense: |  |  |  |  |  |  |  |  |  |  |  |
Lease operating expense |  |  |  |  |  |  |  |  | $ | 4.25 |  |  | $ | 4.21 |  |  | $ | 4.64 |  |  | $ | 0.04 |  |  | $ | (0.39) |  |  | 1 | % |  | (8) | %
Transportation costs |  |  |  |  |  |  |  |  | 2.74 |  |  | 2.61 |  |  | 2.94 |  |  | 0.13 |  |  | (0.20) |  |  | 5 | % |  | (7) | %
Production taxes |  |  |  |  |  |  |  |  | 2.93 |  |  | 2.80 |  |  | 1.94 |  |  | 0.13 |  |  | 0.99 |  |  | 5 | % |  | 51 | %
Ad valorem tax expense |  |  |  |  |  |  |  |  | 0.58 |  |  | 0.22 |  |  | 0.52 |  |  | 0.36 |  |  | 0.06 |  |  | 164 | % |  | 12 | %
Total oil, gas, and NGL production expense |  |  |  |  |  |  |  |  | $ | 10.49 |  |  | $ | 9.84 |  |  | $ | 10.04 |  |  | $ | 0.65 |  |  | $ | 0.45 |  |  | 7 | % |  | 4 | %
Depletion, depreciation, amortization, and asset retirement obligation liability accretion |  |  |  |  |  |  |  |  | $ | 11.56 |  |  | $ | 13.74 |  |  | $ | 16.62 |  |  | $ | (2.18) |  |  | $ | (5.06) |  |  | (16) | % |  | (30) | %
General and administrative |  |  |  |  |  |  |  |  | $ | 1.81 |  |  | $ | 2.55 |  |  | $ | 2.46 |  |  | $ | (0.74) |  |  | $ | (0.65) |  |  | (29) | % |  | (26) | %
Derivative settlement loss (2) |  |  |  |  |  |  |  |  | $ | (12.19) |  |  | $ | (18.45) |  |  | $ | (10.74) |  |  | $ | 6.26 |  |  | $ | (1.45) |  |  | 34 | % |  | (14) | %
Earnings per share information (in thousands, except per share data): (3) |  |  |  |  |  |  |  |
Basic weighted-average common shares outstanding |  |  |  |  |  |  |  |  | 121,907 |  |  | 121,535 |  |  | 114,759 |  |  | 372 |  |  | 7,148 |  |  | — | % |  | 6 | %
Diluted weighted-average common shares outstanding |  |  |  |  |  |  |  |  | 124,179 |  |  | 124,019 |  |  | 114,759 |  |  | 160 |  |  | 9,420 |  |  | — | % |  | 8 | %
Basic net income (loss) per common share |  |  |  |  |  |  |  |  | $ | 0.40 |  |  | $ | 3.50 |  |  | $ | (2.19) |  |  | $ | (3.10) |  |  | $ | 2.59 |  |  | (89) | % |  | 118 | %
Diluted net income (loss) per common share |  |  |  |  |  |  |  |  | $ | 0.39 |  |  | $ | 3.43 |  |  | $ | (2.19) |  |  | $ | (3.04) |  |  | $ | 2.58 |  |  | (89) | % |  | 118 | %

27

______________________________________
(1) Amounts and percentage changes may not calculate due to rounding.
(2) Derivative settlements for the three months ended March 31, 2022, and 2021, are included within the net derivative 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, 2022, decreased three percent sequentially consisting of a 15 percent decrease from our Midland Basin assets due to the timing of well completions, partially offset by an 18 percent increase from our South Texas assets. Average net daily equivalent production for the three months ended March 31, 2022, increased 37 percent compared with the same period in 2021, consisting of an increase of 85 percent from our South Texas assets as a result of increased capital allocation to our Austin Chalk assets and strong well performance, and an increase of 15 percent from our Midland Basin assets as a result of strong well performance. Average net daily equivalent production for the three months ended March 31, 2021, was negatively impacted by a significant cold weather event in the state of Texas which resulted in reduced production for approximately 14 days in February 2021.
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 increased $3.71 sequentially as a result of strengthening benchmark oil prices. The loss on the settlement of our derivative contracts decreased $6.26 per BOE as a result of a lower percentage of volumes covered by commodity derivative contracts settled during the first quarter of 2022, compared with the fourth quarter of 2021. Our realized price on a per BOE basis increased $20.14 YTD 2022-over-YTD 2021, primarily as a result of higher benchmark commodity prices, which increased throughout 2021 in response to global macroeconomic events. The positive impact on oil, gas, and NGL production revenues resulting from the YTD 2022-over-YTD 2021 realized price increase was slightly offset by an increase in the loss on the settlement of our derivative contracts of $1.45 per BOE.
LOE on a per BOE basis remained flat sequentially and decreased eight percent YTD 2022-over-YTD 2021. The YTD 2022-over-YTD 2021 decrease was driven by the decreased percentage of oil in our total product mix, which has higher lifting costs per BOE. For the full year 2022, we expect LOE on a per BOE basis to slightly increase, compared with 2021, due to anticipated increases in service provider costs and workover activity, which we expect to be partially offset by increasing activity in the Austin Chalk. 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 impact total LOE.
Transportation costs on a per BOE basis increased five percent sequentially and decreased seven percent YTD 2022-over-YTD 2021. The sequential quarterly increase was the result of a 16 percent increase in net equivalent production volumes from our South Texas assets, which incur the majority of our transportation costs. The YTD 2022-over-YTD 2021 decrease was the result of increased net equivalent production volumes outpacing increased transportation expense on an absolute basis as we benefited from transportation contract cost reductions during the second half of 2021. In general, we expect total transportation costs to fluctuate relative to changes in gas and NGL production from our South Texas assets. For the full year 2022, we expect transportation costs on a per BOE basis to increase compared with 2021.
Production tax expense on a per BOE basis increased five percent sequentially, and 51 percent YTD 2022-over-YTD 2021, primarily driven by increases in realized prices. Our overall production tax rate for the three months ended March 31, 2022, was 4.7 percent compared with 4.8 percent and 4.6 percent for the three months ended December 31, 2021, and March 31, 2021, respectively. We generally expect production tax expense to correlate with oil, gas, and NGL production revenue on an absolute and per BOE basis. Product mix, the location of production, and incentives to encourage oil and gas development can also impact the amount of production tax expense that we recognize.
Ad valorem tax expense on a per BOE basis increased 164 percent sequentially and 12 percent YTD 2022-over-YTD 2021 as a result of changes to the expected value assessments of our producing properties, which are driven by increases 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 decreased 16 percent sequentially and 30 percent YTD 2022-over-YTD 2021 as a result of increased estimated proved reserves and increased activity in our Austin Chalk program, which has lower DD&A rates compared with our Midland Basin assets. Our DD&A rate fluctuates as a result of impairments, divestiture activity, carrying cost funding and sharing arrangements with third parties, changes in our production mix, and changes in our total estimated proved reserve volumes. We expect DD&A expense per BOE and DD&A expense on an absolute basis to decrease in 2022, compared with 2021, primarily as a result of increased estimated proved reserves and increased activity in our Austin Chalk program, as these assets have a lower DD&A rate than our Midland Basin assets.
General and administrative (“G&A”) expense on a per BOE basis decreased 29 percent sequentially as a result of decreased compensation expense. G&A expense recorded during the three months ended December 31, 2021, reflected an increase to full-year 2021 compensation expense resulting from the Company’s full-year performance against performance targets established at the
28

beginning of the year. G&A expense on a per BOE basis decreased 26 percent YTD 2022-over-YTD 2021 as a result of a 37 percent increase in net equivalent production volumes. Despite inflationary pressures, for the full year 2022 we currently expect G&A expense to slightly decrease on an absolute basis and to decrease on a per BOE basis, compared with 2021.
Please refer to Comparison of Financial Results and Trends Between the Three Months Ended March 31, 2022, and December 31, 2021, and Between the Three Months Ended March 31, 2022, and 2021 below for additional discussion on operating expenses.
Comparison of Financial Results and Trends Between the Three Months Ended March 31, 2022, and December 31, 2021, and Between the Three Months Ended March 31, 2022, and 2021
Average net daily equivalent production, production revenue, and production expense
Sequential Quarterly Changes. The following table presents the changes in our average net daily equivalent production, production revenue, and production expense, by area, between the three months ended March 31, 2022, and December 31, 2021:

| Net Equivalent Production Increase (Decrease) |  | Production Revenue Increase (Decrease) |  | Production Expense Increase (Decrease)
| (MBOE per day) |  | (in millions) |  | (in millions)
Midland Basin | (15.1) |  |  |  |  | $ | (34.8) |  |  |  |  | $ | (2.6) |  |  |
South Texas | 10.2 |  |  |  |  | 41.1 |  |  |  |  | 4.0 |  |  |
Total | (5.0) |  |  |  |  | $ | 6.4 |  |  |  |  | $ | 1.4 |  |  |

__________________________________________
Note: Amounts may not calculate due to rounding.
Average net daily equivalent production volumes decreased three percent, consisting of a 15 percent decrease from our Midland Basin assets, partially offset by an 18 percent increase from our South Texas assets. Our realized oil price increased 24 percent, while our realized gas and NGL prices decreased 15 percent and three percent, respectively. The six percent increase in total realized price per BOE was mostly offset by the decrease in average net daily equivalent production volumes, resulting in a slight increase in oil, gas, and NGL production revenue. Total production expense remained flat.
YTD 2022-over-YTD 2021. The following table presents the changes in our average net daily equivalent production, production revenue, and production expense, by area, between the three months ended March 31, 2022, and 2021:

| Net Equivalent Production Increase |  | Production Revenue Increase |  | Production Expense Increase
| (MBOE per day) |  | (in millions) |  | (in millions)
Midland Basin | 11.3 |  |  |  |  | $ | 252.3 |  |  |  |  | $ | 23.7 |  |  |
South Texas | 30.3 |  |  |  |  | 183.2 |  |  |  |  | 20.1 |  |  |
Total | 41.6 |  |  |  |  | $ | 435.6 |  |  |  |  | $ | 43.8 |  |  |

__________________________________________
Note: Amounts may not calculate due to rounding.
Average net daily equivalent production volumes increased 37 percent, consisting of increases of 85 percent and 15 percent from our South Texas assets and our Midland Basin assets, respectively. Realized prices for oil, gas, and NGLs increased 67 percent, 30 percent, and 43 percent, respectively. As a result of increases in benchmark commodity prices and an increase in production volumes, oil, gas, and NGL production revenue increased 103 percent. Total production expense increased 43 percent, primarily as a result of increased production taxes and 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, 2022 |  | December 31, 2021 |  | March 31, 2021 |  |  |  |
| (in millions)
Depletion, depreciation, amortization, and asset retirement obligation liability accretion | $ | 159.5 |  |  | $ | 200.0 |  |  | $ | 167.0 |  |  |  |  |

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DD&A expense decreased 20 percent sequentially and four percent YTD 2022-over-YTD 2021. These decreases were driven by increased estimated proved reserves and increased activity in our Austin Chalk program, which has lower DD&A rates compared with our Midland Basin assets. Please refer to Overview of Selected Production and Financial Information, Including Trends above for additional discussion of DD&A expense on a per BOE basis.
Exploration

| For the Three Months Ended |  |
| March 31, 2022 |  | December 31, 2021 |  | March 31, 2021 |  |  |  |
| (in millions)
Geological and geophysical expenses | $ | — |  |  | $ | 0.2 |  |  | $ | 0.3 |  |  |  |  |
Overhead and other expenses | 9.0 |  |  | 12.4 |  |  | 9.0 |  |  |  |  |
Total | $ | 9.0 |  |  | $ | 12.6 |  |  | $ | 9.3 |  |  |  |  |

Exploration expense decreased 28 percent sequentially and three percent YTD 2022-over-YTD 2021. The sequential quarterly decrease was primarily a result of decreases in overhead and other expenses. Exploration expense is impacted by actual geological and geophysical studies we perform within an exploratory area and unsuccessful exploration activities, if any.
Impairment

| For the Three Months Ended |  |
| March 31, 2022 |  | December 31, 2021 |  | March 31, 2021 |  |  |  |
| (in millions)
Impairment | $ | 1.0 |  |  | $ | 8.8 |  |  | $ | 8.8 |  |  |  |  |

Impairment expense recorded during the periods presented consists entirely of unproved property abandonments and impairments related to actual and anticipated lease expirations, as well as actual and anticipated losses of acreage due to title defects, changes in development plans, and other inherent acreage risks. Impairment expense decreased both sequentially and YTD 2022-over-YTD 2021, as a result of fewer actual and anticipated lease expirations and title defects.
We expect proved property impairments to occur more frequently in periods of declining or depressed commodity prices, and that the frequency of unproved property abandonments and impairments will fluctuate with the timing of lease expirations or title defects, and changing economics associated with decreases in commodity prices. Additionally, changes in drilling plans, unsuccessful exploration activities, and downward engineering revisions may result in proved and unproved property impairments.
Future impairments of proved and unproved properties are difficult to predict; however, based on our commodity price assumptions as of April 20, 2022, we do not expect any material oil and gas property impairments in the second quarter of 2022 resulting from commodity price impacts. We expect abandonment and impairment expense related to unproved properties to decrease for the full year 2022 compared with 2021.
Please refer to Note 8 - Fair Value Measurements in Part I, Item 1 of this report for additional discussion of impairment expense.
General and administrative

| For the Three Months Ended |  |
| March 31, 2022 |  | December 31, 2021 |  | March 31, 2021 |  |  |  |
| (in millions)
General and administrative | $ | 25.0 |  |  | $ | 37.1 |  |  | $ | 24.7 |  |  |  |  |

G&A expense decreased 33 percent sequentially and remained flat YTD 2022-over-YTD 2021. G&A expense recorded during the three months ended December 31, 2021, reflected an increase to full-year 2021 compensation expense resulting from the Company’s full-year performance against performance targets established at the beginning of the year. Please refer to the section Overview of Selected Production and Financial Information, Including Trends above for additional discussion of G&A expense in total and on a per BOE basis.
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Net derivative (gain) loss

| For the Three Months Ended |  |
| March 31, 2022 |  | December 31, 2021 |  | March 31, 2021 |  |  |  |
| (in millions)
Net derivative (gain) loss | $ | 418.5 |  |  | $ | (22.5) |  |  | $ | 344.7 |  |  |  |  |

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 losses for the three months ended March 31, 2022, and 2021, resulted from increases in benchmark commodity prices. The net derivative gain for the three months ended December 31, 2021, was the result of decreases in the forward price curves for gas and NGLs, partially offset by an increase in the forward price curve for oil. Please refer to Note 10 - Derivative Financial Instruments in Part I, Item 1 of this report for additional discussion.
Interest expense

| For the Three Months Ended |  |
| March 31, 2022 |  | December 31, 2021 |  | March 31, 2021 |  |  |  |
| (in millions)
Interest expense | $ | (39.4) |  |  | $ | (40.1) |  |  | $ | (39.9) |  |  |  |  |

Interest expense remained relatively flat for the periods presented. We expect interest expense related to our Senior Notes to continue to decrease during 2022 compared with 2021 primarily as a result of the reduction in aggregate principal amount of Senior Notes through various transactions in 2021 and 2022, including the redemption of our 2024 Senior Notes on February 14, 2022, and the announced redemption of our 2025 Senior Secured Notes, which will be redeemed on June 17, 2022. Total interest expense is impacted by, and 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, 2022 |  | December 31, 2021 |  | March 31, 2021 |  |  |  |
| (in millions, except tax rate)
Income tax expense | $ | (12.9) |  |  | $ | (10.0) |  |  | $ | (0.1) |  |  |  |  |
Effective tax rate | 20.9 | % |  | 2.3 | % |  | — | % |  |  |  |

The sequential quarterly increase in the effective tax rate was primarily due to the effect of increased forecasted net income for the full-year 2022, compared with 2021. Additionally, as a result of commodity price increases discussed in Overview of the Company above, we anticipate that a significant portion of the valuation allowance recorded against the derivative deferred tax asset as of December 31, 2021, could be reversed during 2022. The effect of this anticipated reversal is included in the effective tax rate for the three months ended March 31, 2022. Please refer to Note 4 - Income Taxes included in Part II, Item 8 of our 2021 Form 10-K for discussion of the valuation allowance recorded as of December 31, 2021.
The YTD 2022-over-YTD 2021 increase in the effective tax rate was primarily due to the effect of higher full-year 2022 forecasted net income as of March 31, 2022, compared with the amount of forecasted net income for the full-year 2021 as of March 31, 2021.
The tax rates for each period presented reflect the effect of valuation allowance adjustments against the statutory rate, the proportional effects of excess tax deficiencies from stock-based compensation awards, and limits on expensing of certain covered individual’s compensation. Based on current projections, we estimate that between six percent and eight percent of full-year 2022 income tax expense will be current.
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 I, Item 1A of our 2021 Form 10-K for additional discussion.
Please refer to Note 4 - Income Taxes in Part I, Item 1 of this report for additional discussion.
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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, 2022, our capital program was funded with cash flows from operating activities and we expect that to continue for the remainder of 2022. Although we expect cash flows from operations to be sufficient to fund our expected 2022 capital program, 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. 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, tax law changes, and volumes produced, all of which affect us and our industry.
Our credit ratings impact the availability of and cost for us to borrow additional funds. Three major credit rating agencies have upgraded our credit ratings during 2022, reflecting our top-tier assets and operational performance, the redemption of our 2024 Senior Notes, and our strong liquidity profile, among other factors. The credit rating agencies also cited our priorities of continuing to reduce debt and improve our leverage metrics, and our expected ability to generate meaningful cash flows, among other reasons for the rating upgrades.
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 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 10 - Derivative Financial Instruments in Part I, Item 1 of this report for additional information about our oil, gas, and NGL 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 $2.5 billion, and a borrowing base and aggregate lender commitments of $1.1 billion. The borrowing base under the Credit Agreement is subject to regular, semi-annual redetermination, and considers the value of both our (a) proved oil and gas properties reflected in the most recent reserve report provided to our lenders under the Credit Agreement; and (b) commodity derivative contracts, each as determined by our lender group. Subsequent to March 31, 2022, the semi-annual borrowing base redetermination was completed, which reaffirmed both our borrowing base and aggregate lender commitments at $1.1 billion. The next borrowing base redetermination date is scheduled for October 1, 2022. Our borrowing base can be adjusted as a result of changes in commodity prices, acquisitions or divestitures of proved properties, or financing activities, all as provided for in the Credit Agreement. No individual bank participating in our Credit Agreement represents more than 10 percent of the lender commitments under the Credit Agreement. 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 our Credit Agreement as of April 20, 2022, March 31, 2022, and December 31, 2021.
We must comply with certain financial and non-financial covenants under the terms of the Credit Agreement, including covenants limiting dividend payments and requiring that we maintain certain financial ratios, as set forth in the Credit Agreement. We were in compliance with all financial and non-financial covenants as of March 31, 2022, 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.
We had no revolving credit facility borrowings during the three months ended March 31, 2022, due to our cash and cash equivalents balance resulting from cash flows from operating activities exceeding cash flows from investing and financing activities. Our daily weighted-average revolving credit facility debt balance for the three months ended December 31, 2021, and March 31, 2021, was $21.0 million and $134.2 million, respectively. 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.
Under our Credit Agreement, borrowings in the form of Eurodollar loans accrue interest based on LIBOR which was discontinued as a global reference rate for new loans and contracts after December 31, 2021. Our Credit Agreement specifies that if LIBOR is no longer a widely used benchmark rate, or if it is no longer used for determining interest rates for loans in the United States, a replacement interest rate that fairly reflects the cost to the lenders of funding loans shall be established by the Administrative Agent, as defined in the Credit Agreement, in consultation with us. In advance of the maturity date of our existing Credit Agreement, we expect to enter into a new credit agreement during 2022 that will, in addition to other negotiated terms, conditions, agreements, and other provisions, specify a new interest rate for Eurodollar loans. We currently do not expect to incur borrowings in the form of Eurodollar
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loans prior to that time, and we currently do not expect the transition from LIBOR to have a material impact on interest expense or borrowing activities under the Credit Agreement, or to otherwise have a material adverse impact on our business.
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, the non-cash amortization of the discount related to the 2025 Senior Secured Notes, and for the three months ended March 31, 2021, the non-cash amortization of the discount related to the 1.50% 2021 Senior Secured Convertible Notes due July 1, 2021 (“2021 Senior Secured Convertible Notes”). 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, 2022 |  | December 31, 2021 |  |  |  | March 31, 2021
Weighted-average interest rate | 8.2 | % |  | 7.9 | % |  |  |  | 7.7 | %
Weighted-average borrowing rate | 7.2 | % |  | 7.0 | % |  |  |  | 6.7 | %

Our weighted-average interest rates and our weighted-average borrowing rates increased both sequentially and YTD 2022-over-YTD 2021, as the remaining Senior Notes outstanding as of March 31, 2022 have higher interest rates than the Senior Notes redeemed during 2021 and during the first quarter of 2022.
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, as these amounts are netted against the associated gain or loss on extinguishment of debt. The 2021 Senior Secured Convertible Notes were retired upon maturity on July 1, 2021. After this date, the weighted-average interest rate was no longer impacted by the non-cash amortization of deferred financing costs or the non-cash amortization of the discount related to the 2021 Senior Secured Convertible Notes.
Uses of Cash
We use cash for the development, exploration, and acquisition of oil and gas properties and for the payment of operating and general and administrative costs, income taxes, dividends, and debt obligations, including interest. 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, 2022, we spent approximately $150.1 million on capital expenditures. This amount differs from the costs incurred amount of $175.1 million for the three months ended March 31, 2022, 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, 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 2022 capital program is expected to be approximately $750.0 million. We will continue to monitor the economic environment through the remainder of the year and adjust our activity level as warranted.
We may from time to time repurchase or redeem all or portions of our outstanding debt securities for cash, through exchanges for other securities, or a combination of both. Such repurchases or redemptions may be made in open market transactions, privately negotiated transactions, tender offers, pursuant to contractual provisions, or otherwise. Any such repurchases or redemptions will depend on prevailing market conditions, our liquidity requirements, contractual restrictions, compliance with securities laws, and other factors. The amounts involved in any such transaction may be material. On February 14, 2022, we redeemed all of the $104.8 million of aggregate principal amount outstanding of our 2024 Senior Notes. On April 28, 2022, we issued a notice of redemption to the holders of our 2025 Senior Secured Notes notifying such holders that we intend to redeem the $446.7 million aggregate principal amount outstanding of our 2025 Senior Secured Notes on June 17, 2022 (“Redemption Date”). In accordance with the terms of the indenture governing the 2025 Senior Secured Notes, the redemption price will be equal to 107.5 percent of the principal amount of the 2025 Senior Secured Notes on the Redemption Date ($1,075 per $1,000 principal amount outstanding), plus accrued and unpaid interest. Please refer to Note 5 - Long-Term Debt in Part I, Item 1 of this report for additional discussion. As part of our strategy for 2022, we continue to focus on reducing absolute debt and improving our debt metrics.
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As of the filing of this report, we could repurchase up to 3,072,184 shares of our common stock under our stock repurchase program, subject to the approval of our Board of Directors. Shares may be repurchased from time to time in the open market, or in privately negotiated transactions, subject to market conditions and other factors, including certain provisions of our Credit Agreement, the indentures governing each series of our outstanding Senior Notes, compliance with securities laws, and the terms and provisions of our stock repurchase program. Our Board of Directors periodically reviews this program as part of the allocation of our capital. During the three months ended March 31, 2022, we did not repurchase any shares of our common stock.
Analysis of Cash Flow Changes Between the Three Months Ended March 31, 2022, and 2021
The following tables present changes in cash flows between the three months ended March 31, 2022, and 2021, 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 |  |
| 2022 |  | 2021 |  |
| (in millions) |  |
Net cash provided by operating activities | $ | 342.1 |  |  | $ | 105.6 |  |  | $ | 236.5 |  |  |

Net cash provided by operating activities increased for the three months ended March 31, 2022, compared with the same period in 2021, primarily due to a $371.9 million increase in cash received from oil, gas, and NGL production revenues, net of transportation costs and production taxes partially offset by a $104.5 million increase in cash paid on settled derivative trades. Net cash provided by operating activities is also affected by working capital changes and the timing of cash receipts and disbursements.
Investing activities

| For the Three Months Ended March 31, |  | Amount Change Between Periods |  |
| 2022 |  | 2021 |  |
| (in millions) |  |
Net cash used in investing activities | $ | (150.1) |  |  | $ | (147.6) |  |  | $ | (2.5) |  |  |

Net cash used in investing activities slightly increased for the three months ended March 31, 2022, compared with the same period in 2021, primarily due to increased capital expenditures of $2.6 million.
Financing activities

| For the Three Months Ended March 31, |  | Amount Change Between Periods |  |
| 2022 |  | 2021 |  |
| (in millions) |  |
Net cash provided by (used in) financing activities | $ | (104.8) |  |  | $ | 42.0 |  |  | $ | (146.8) |  |  |

During the three months ended March 31, 2022, we redeemed the $104.8 million of aggregate principal amount outstanding of our 2024 Senior Notes using cash on hand.
For the three months ended March 31, 2021, net borrowings under our revolving credit facility increased $42.0 million.
Interest Rate Risk
We are exposed to market risk due to the floating interest rate associated with any outstanding balance on our revolving credit facility. As of March 31, 2022, we had no outstanding balance on our revolving credit facility. Our Credit Agreement allows us to fix the interest rate for all or a portion of the principal balance of our revolving credit facility for a period up to six months. To the extent that the interest rate is fixed, interest rate changes will affect the revolving credit facility’s fair value but will not 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 Unsecured Notes or fixed-rate Senior Secured Notes, but can impact their fair values. As of March 31, 2022, our outstanding principal amount of fixed-rate debt totaled $2.0 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.
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Commodity Price Risk
The prices we receive for our oil, gas, and NGL production directly impact our revenue, profitability, access to capital, 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, and weather-related events. The markets for oil, gas, and NGLs have been volatile, especially over the last several years. Oil prices continued to increase during the first quarter of 2022. However, commodity prices remain subject to heightened 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, the dynamic nature of the Pandemic, and the potential impacts to global commodity and financial markets. 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, 2022, a 10 percent decrease in our average realized oil, gas, and NGL prices, before the effects of derivative settlements, would have reduced our oil, gas, and NGL production revenues by approximately $60.7 million, $17.0 million, and $8.1 million, respectively. If commodity prices had been 10 percent lower, our net derivative settlements for the three months ended March 31, 2022, would have offset the declines in oil, gas, and NGL production revenue by approximately $38.0 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, 2022, 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 $144.3 million, $18.5 million, and $5.9 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 (“SPEs”), 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, 2022, or through the filing of this report.
Critical Accounting Policies and Estimates
Please refer to the corresponding section in Part II, Item 7 and to Note 1 - Summary of Significant Accounting Policies included in Part II, Item 8 of our 2021 Form 10-K for discussion of our accounting policies and 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 2021 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 (loss) (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,
|  |  |  |  | 2022 |  |  |  | 2021
|  |  |  |  | (in thousands)
Net income (loss) (GAAP) |  |  |  |  | $ | 48,764 |  |  |  |  | $ | (251,269) |
Interest expense |  |  |  |  | 39,387 |  |  |  |  | 39,871 |
Income tax expense |  |  |  |  | 12,861 |  |  |  |  | 106 |
Depletion, depreciation, amortization, and asset retirement obligation liability accretion |  |  |  |  | 159,481 |  |  |  |  | 166,960 |
Exploration (1) |  |  |  |  | 8,055 |  |  |  |  | 8,039 |
Impairment |  |  |  |  | 1,000 |  |  |  |  | 8,750 |
Stock-based compensation expense |  |  |  |  | 4,274 |  |  |  |  | 5,737 |
Net derivative loss |  |  |  |  | 418,521 |  |  |  |  | 344,689 |
Derivative settlement loss |  |  |  |  | (168,183) |  |  |  |  | (107,885) |
Other, net |  |  |  |  | 404 |  |  |  |  | (10) |
Adjusted EBITDAX (non-GAAP) |  |  |  |  | 524,564 |  |  |  |  | 214,988 |
Interest expense |  |  |  |  | (39,387) |  |  |  |  | (39,871) |
Income tax expense |  |  |  |  | (12,861) |  |  |  |  | (106) |
Exploration (1) |  |  |  |  | (8,055) |  |  |  |  | (8,039) |
Amortization of debt discount and deferred financing costs |  |  |  |  | 4,010 |  |  |  |  | 4,723 |
Deferred income taxes |  |  |  |  | 11,948 |  |  |  |  | (52) |
Other, net |  |  |  |  | (165) |  |  |  |  | (14,582) |
Net change in working capital |  |  |  |  | (137,962) |  |  |  |  | (51,437) |
Net cash provided by operating activities (GAAP) |  |  |  |  | $ | 342,092 |  |  |  |  | $ | 105,624 |

____________________________________________
(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.
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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 10 - 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 2021 Form 10-K.
ITEM 4. CONTROLS AND PROCEDURES
Evaluation of Disclosure Controls and Procedures
We maintain a system of disclosure controls and procedures that are designed to reasonably ensure that information required to be disclosed in our SEC reports is recorded, processed, summarized, and reported within the time periods specified in the SEC’s rules and forms, and to reasonably ensure that such information is accumulated and communicated to our management, including our Chief Executive Officer (Principal Executive Officer) and our Chief Financial Officer (Principal Financial Officer), as appropriate, to allow for timely decisions regarding required disclosure.
Our management, including our Chief Executive Officer and our Chief Financial Officer, does not expect that our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) of the Exchange Act) (“Disclosure Controls”) will prevent all errors and all fraud. A control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Further, the design of a control system must reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs. Because of the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, within our company have been detected. These inherent limitations include the realities that judgments in decision-making can be faulty, and that breakdowns can occur because of simple error or mistake. Additionally, controls can be circumvented by the individual acts of some persons, by collusion of two or more people, or by management override of the control. The design of any system of controls also is based in part upon certain assumptions about the likelihood of future events, and there can be no assurance that any design will succeed in achieving its stated goals under all potential future conditions. Because of the inherent limitations in a cost-effective control system, misstatements due to error or fraud may occur and not be detected. We monitor our Disclosure Controls and make modifications as necessary; our intent in this regard is that the Disclosure Controls will be modified as systems change and conditions warrant.
An evaluation of the effectiveness of the design and operation of our Disclosure Controls was performed as of the end of the period covered by this report. This evaluation was performed under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer. Based upon that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our Disclosure Controls are effective at a reasonable assurance level.
Changes in Internal Control Over Financial Reporting
There have been no changes during the first quarter of 2022 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
Global geopolitical tensions, specifically including the ongoing conflict between Russia and Ukraine, may create heightened volatility in oil, gas, and NGL prices and could adversely affect our business, financial condition and results of operations.
On February 24, 2022, Russian military forces commenced a military operation in Ukraine, and sustained conflict and disruption in the region is likely. Although the length, impact, and outcome of the ongoing military conflict in Ukraine is highly unpredictable, this conflict could lead to significant market and other disruptions, including significant volatility in commodity prices and supply of energy resources, instability in financial markets, supply chain interruptions, political and social instability, changes in consumer or purchaser preferences, as well as increases in cyberattacks and espionage.
While it is not possible at this time to predict or determine the ultimate consequences of the conflict in Ukraine, which could include, among other things, additional sanctions, greater regional instability, embargoes, geopolitical shifts and other material and adverse effects on macroeconomic conditions, supply chains, financial markets, and hydrocarbon price volatility in particular is likely to continue for the foreseeable future. To the extent negotiations of a cease fire between Russia and Ukraine are unsuccessful, the potential destruction of critical oil-related infrastructure in Ukraine, and the implementation of further sanctions and other measures taken by governmental bodies and private actors, could have a lasting impact in the short- and long-term on the operations and financial condition of our business and the global economy.
There have been no other material changes to the risk factors as previously disclosed in our 2021 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, 2022, of shares of our common stock, which is the sole class of equity securities registered by us pursuant to Section 12 of the Exchange Act:

PURCHASES OF EQUITY SECURITIES BY ISSUER AND AFFILIATED PURCHASES
Period | Total Number of Shares Purchased (1) | Weighted Average Price Paid per Share | Total Number of Shares Purchased as Part of Publicly Announced Program | Maximum Number of Shares that May Yet Be Purchased Under the Program (2)
01/01/2022 - 01/31/2022 | — |  | $ | — |  | — |  | 3,072,184 |
02/01/2022 - 02/28/2022 | — |  | $ | — |  | — |  | 3,072,184 |
03/01/2022 - 03/31/2022 | 623 |  | $ | 38.02 |  | — |  | 3,072,184 |
Total: | 623 |  | $ | 38.02 |  | — |  | 3,072,184 |

___________________________________
(1) All shares purchased by us in the first quarter of 2022 were to offset tax withholding obligations that occurred upon the delivery of outstanding shares underlying RSUs issued under the terms of award agreements granted under the Equity Plan.
(2) In July 2006, our Board of Directors approved an increase in the number of shares of our common stock that may be repurchased under the original August 1998 authorization to 6,000,000 as of the effective date of the resolution. Accordingly, as of the filing of this report, subject to the approval of our Board of Directors, we may repurchase up to 3,072,184 shares of common stock on a prospective basis. The shares may be repurchased from time to time in open market transactions or privately negotiated transactions, subject to market conditions and other factors, including certain provisions of our Credit Agreement, the indentures governing our Senior Notes, and compliance with securities laws. Stock repurchases may be funded with existing cash balances, internal cash flows, or borrowings under our Credit Agreement. The stock repurchase program may be suspended or discontinued at any time. During the three months ended March 31, 2022, we did not repurchase any shares of our common stock.
Our payment of cash dividends to our stockholders is 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 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 29, 2022 | By: | /s/ HERBERT S. VOGEL
|  | Herbert S. Vogel
|  | President and Chief Executive Officer
|  | (Principal Executive Officer)
April 29, 2022 | By: | /s/ A. WADE PURSELL
|  | A. Wade Pursell
|  | Executive Vice President and Chief Financial Officer
|  | (Principal Financial Officer)
April 29, 2022 | By: | /s/ PATRICK A. LYTLE
|  | Patrick A. Lytle
|  | Vice President - Chief Accounting Officer and Controller
|  | (Principal Accounting Officer)

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