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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
(X) Quarterly Report Pursuant to Section 13 or 15(d)
of the Securities Exchange Act of 1934
For the quarterly period ended September 30, 2023
Commission File Number 1-8754
SILVERBOW RESOURCES, INC.
(Exact Name of Registrant as Specified in Its Charter)
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Delaware | 20-3940661 |
(State of Incorporation) | (I.R.S. Employer Identification No.) |
| |
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920 Memorial City Way, Suite 850
Houston, Texas 77024
(281) 874-2700
(Address and telephone number of principal executive offices)
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, par value $0.01 per share | SBOW | New York Stock Exchange |
Preferred Stock Purchase Rights | None | New York Stock Exchange |
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files).
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company or an emerging growth company. See definition of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.
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Large Accelerated Filer | o | | Accelerated Filer | þ | | Non-Accelerated Filer | o | | Smaller Reporting Company | o |
Emerging Growth Company | o | | | | | | | | | |
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
Indicate the number of shares outstanding of each of the issuer’s classes
of common stock, as of the latest practicable date.
| | | | | |
Common Stock ($.01 Par Value) (Class of Stock) | 25,429,610 Shares outstanding at October 27, 2023 |
SILVERBOW RESOURCES, INC.
FORM 10-Q
FOR THE QUARTERLY PERIOD ENDED SEPTEMBER 30, 2023
INDEX
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Part I | FINANCIAL INFORMATION | |
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Item 1. | Condensed Consolidated Financial Statements | |
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Item 2. | | |
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Item 3. | | |
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Item 4. | | |
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Part II | OTHER INFORMATION | |
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Item 1. | | |
Item 1A. | | |
Item 2. | | |
Item 3. | | |
Item 4. | | |
Item 5. | | |
Item 6. | | |
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Forward-Looking Statements
This report includes forward-looking statements intended to qualify for the safe harbors from liability established by the Private Securities Litigation Reform Act of 1995, Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). These forward-looking statements are based on current expectations and assumptions and are subject to a number of risks and uncertainties, many of which are beyond our control. All statements, other than statements of historical fact included in this report, including those regarding our strategy, future operations, financial position, well expectations and drilling plans, estimated production levels, expected oil and natural gas pricing, estimated oil and natural gas reserves or the present value thereof, reserve increases, service costs, impact of inflation, capital expenditures, budget, projected costs, prospects, plans and objectives of management are forward-looking statements. When used in this report, the words “will,” “could,” “believe,” “anticipate,” “intend,” “estimate,” “budgeted,” “guidance,” “expect,” “may,” “continue,” “predict,” “potential,” “plan,” “project,” “should” and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words.
Important factors that could cause actual results to differ materially from our expectations include, but are not limited to, the following risks and uncertainties:
• further actions by the members of the Organization of the Petroleum Exporting Countries (“OPEC”), Russia and other allied producing countries (together with OPEC, “OPEC+”) with respect to oil production levels and announcements of potential changes in such levels;
• risks related to the recently announced acquisition of oil and gas assets from Chesapeake Exploration, L.L.C., Chesapeake Operating, L.L.C., Chesapeake Energy Marketing, L.L.C. and Chesapeake Royalty, L.L.C. (collectively, the “Chesapeake Sellers”), including the risk that the transaction will not be completed on the timeline or terms currently contemplated, risks related to the ability to obtain any necessary consents or approvals, the risk that the benefits of the transaction may not be fully realized or may take longer to realize than expected, the risk that the costs of the acquisition will be significant and the risk that management attention will be diverted to transaction-related issues;
• risks related to recently completed acquisitions and integration of these acquisitions;
• volatility in natural gas, oil and natural gas liquids prices;
• ability to obtain permits and government approvals;
• our borrowing capacity, future covenant compliance, cash flow and liquidity, including our ability to satisfy our short or long-term liquidity needs;
• asset disposition efforts or the timing or outcome thereof;
• ongoing and prospective joint ventures, their structures and substance, and the likelihood of their finalization or the timing thereof;
• the amount, nature and timing of capital expenditures, including future development costs;
• timing, cost and amount of future production of oil and natural gas;
• availability of drilling and production equipment or availability of oil field labor;
• availability, cost and terms of capital;
• timing and successful drilling and completion of wells;
• availability and cost for transportation and storage capacity of oil and natural gas;
• costs of exploiting and developing our properties and conducting other operations;
• competition in the oil and natural gas industry;
• general economic and political conditions, including inflationary pressures, further increases in interest rates, a general economic slowdown or recession, instability in financial institutions, political tensions and war (including future developments in the ongoing conflicts in Ukraine and the Gaza Strip);
• the severity and duration of world health events, including health crises and pandemics, related economic repercussions, including disruptions in the oil and gas industry, supply chain disruptions, and operational challenges including remote work arrangements and protecting the health and well-being of our employees;
• opportunities to monetize assets;
• our ability to execute on strategic initiatives;
• effectiveness of our risk management activities including hedging strategy;
• counterparty and credit market risk;
• pending legal and environmental matters, including potential impacts on our business related to climate change and related regulations;
• actions by third parties, including customers, service providers and shareholders;
• current and future governmental regulation and taxation of the oil and natural gas industry;
• developments in world oil and natural gas markets and in oil and natural gas-producing countries;
• uncertainty regarding our future operating results; and
• other risks and uncertainties described in this Quarterly Report on Form 10-Q, our Annual Report on Form 10-K for the year ended December 31, 2022 and our other filings with the Securities and Exchange Commission (“SEC”).
Many of the foregoing risks and uncertainties, as well as risks and uncertainties that are currently unknown to us, are, and may be, exacerbated by geopolitical events and wars, increasing economic uncertainty, recessionary and inflationary pressures and any consequent worsening of the global business and economic environment. New factors emerge from time to time, and it is not possible for us to predict all such factors. Should one or more of the risks or uncertainties described in this Quarterly Report on Form 10-Q, our Annual Report on Form 10-K for the year ended December 31, 2022, subsequent Quarterly Reports on Form 10-Q, or other SEC filings occur, or should underlying assumptions prove incorrect, actual results and plans could differ materially from those expressed in any forward-looking statements.
All forward-looking statements speak only as of the date they are made. You should not place undue reliance on these forward-looking statements. Although we believe that our plans, intentions and expectations reflected in or suggested by the forward-looking statements we make in this report are reasonable, we can give no assurance that these plans, intentions or expectations will be achieved. We disclose important factors that could cause our actual results to differ materially from our expectations under “Risk Factors” in Item 1A of our Annual Report on Form 10-K for the year ended December 31, 2022 and in subsequent Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and our other filings with the SEC. These cautionary statements qualify all forward-looking statements attributable to us or persons acting on our behalf.
All subsequent written and oral forward-looking statements attributable to us or to persons acting on our behalf are expressly qualified in their entirety by the foregoing. We undertake no obligation to publicly release the results of any revisions to any such forward-looking statements that may be made to reflect events or circumstances after the date of this report or to reflect the occurrence of unanticipated events, except as required by law.
PART I. FINANCIAL INFORMATION
Condensed Consolidated Balance Sheets (Unaudited)
SilverBow Resources, Inc. and Subsidiary (in thousands, except share amounts)
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| September 30, 2023 | | December 31, 2022 |
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ASSETS | | | |
Current Assets: | | | |
Cash and cash equivalents | $ | 1,697 | | | $ | 792 | |
Accounts receivable, net | 80,202 | | | 89,714 | |
Fair value of commodity derivatives | 50,189 | | | 52,549 | |
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Other current assets | 3,825 | | | 2,671 | |
Total Current Assets | 135,913 | | | 145,726 | |
Property and Equipment: | | | |
Property and equipment, full cost method, including $27,821 and $16,272, respectively, of unproved property costs not being amortized at the end of each period | 2,861,267 | | | 2,529,223 | |
Less – Accumulated depreciation, depletion, amortization & impairment | (1,151,141) | | | (1,004,044) | |
Property and Equipment, Net | 1,710,126 | | | 1,525,179 | |
Right of use assets | 10,085 | | | 12,077 | |
Fair value of long-term commodity derivatives | 14,180 | | | 24,172 | |
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Deposit and other fees for oil and gas property transaction | 52,564 | | | — | |
Other long-term assets | 7,581 | | | 9,208 | |
Total Assets | $ | 1,930,449 | | | $ | 1,716,362 | |
LIABILITIES AND STOCKHOLDERS’ EQUITY | | | |
Current Liabilities: | | | |
Accounts payable and accrued liabilities | $ | 74,731 | | | $ | 60,200 | |
Fair value of commodity derivatives | 32,752 | | | 40,796 | |
Accrued capital costs | 56,424 | | | 56,465 | |
Accrued interest | 2,976 | | | 2,665 | |
Current lease liability | 5,507 | | | 8,553 | |
Undistributed oil and gas revenues | 22,462 | | | 27,160 | |
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Total Current Liabilities | 194,852 | | | 195,839 | |
Long-term debt, net | 645,096 | | | 688,531 | |
Non-current lease liability | 4,604 | | | 3,775 | |
Deferred tax liabilities | 49,033 | | | 16,141 | |
Asset retirement obligations | 9,840 | | | 9,171 | |
Fair value of long-term commodity derivatives | 21,560 | | | 7,738 | |
Other long-term liabilities | 922 | | | 3,588 | |
Commitments and Contingencies (Note 11) | | | |
Stockholders' Equity: | | | |
Preferred stock, $0.01 par value, 10,000,000 shares authorized, none issued | — | | | — | |
Common stock, $0.01 par value, 40,000,000 shares authorized, 25,914,823 and 22,663,135 shares issued, respectively, and 25,429,517 and 22,309,740 shares outstanding, respectively | 259 | | | 227 | |
Additional paid-in capital | 677,473 | | | 576,118 | |
Treasury stock, held at cost, 485,306 and 353,395 shares, respectively | (10,616) | | | (7,534) | |
Retained earnings | 337,426 | | | 222,768 | |
Total Stockholders’ Equity | 1,004,542 | | | 791,579 | |
Total Liabilities and Stockholders’ Equity | $ | 1,930,449 | | | $ | 1,716,362 | |
See accompanying Notes to Condensed Consolidated Financial Statements. |
Condensed Consolidated Statements of Operations (Unaudited)
SilverBow Resources, Inc. and Subsidiary (in thousands, except per-share amounts)
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| Three Months Ended September 30, 2023 | | Three Months Ended September 30, 2022 |
Revenues: | | | |
Oil and gas sales | $ | 173,963 | | | $ | 242,181 | |
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Operating Expenses: | | | |
General and administrative, net | 4,438 | | | 4,343 | |
Depreciation, depletion, and amortization | 53,186 | | | 41,501 | |
Accretion of asset retirement obligations | 254 | | | 166 | |
Lease operating expenses | 22,678 | | | 17,701 | |
Workovers | 672 | | | 284 | |
Transportation and gas processing | 13,710 | | | 9,662 | |
Severance and other taxes | 10,407 | | | 12,581 | |
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Total Operating Expenses | 105,345 | | | 86,238 | |
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Operating Income | 68,618 | | | 155,943 | |
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Non-Operating Income (Expense) | | | |
Gain (loss) on commodity derivatives, net | (54,639) | | | 4,832 | |
Interest expense, net | (19,811) | | | (12,173) | |
Other income (expense), net | 112 | | | 5 | |
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Income (Loss) Before Income Taxes | (5,720) | | | 148,607 | |
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Provision (Benefit) for Income Taxes | (949) | | | 6,066 | |
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Net Income (Loss) | $ | (4,771) | | | $ | 142,541 | |
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Per Share Amounts: | | | |
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Basic Earnings (Loss) Per Share | $ | (0.21) | | | $ | 6.39 | |
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Diluted Earnings (Loss) Per Share | $ | (0.21) | | | $ | 6.29 | |
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Weighted-Average Shares Outstanding - Basic | 22,985 | | | 22,308 | |
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Weighted-Average Shares Outstanding - Diluted | 22,985 | | | 22,669 | |
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See accompanying Notes to Condensed Consolidated Financial Statements. | | | |
Condensed Consolidated Statements of Operations (Unaudited)
SilverBow Resources, Inc. and Subsidiary (in thousands, except per-share amounts)
| | | | | | | | | | | |
| Nine Months Ended September 30, 2023 | | Nine Months Ended September 30, 2022 |
Revenues: | | | |
Oil and gas sales | $ | 440,317 | | | $ | 554,442 | |
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Operating Expenses: | | | |
General and administrative, net | 17,421 | | | 14,840 | |
Depreciation, depletion, and amortization | 147,037 | | | 89,096 | |
Accretion of asset retirement obligations | 718 | | | 366 | |
Lease operating expenses | 62,417 | | | 37,095 | |
Workovers | 2,263 | | | 933 | |
Transportation and gas processing | 37,001 | | | 22,784 | |
Severance and other taxes | 28,563 | | | 30,183 | |
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Total Operating Expenses | 295,420 | | | 195,297 | |
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Operating Income | 144,897 | | | 359,145 | |
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Non-Operating Income (Expense) | | | |
Gain (loss) on commodity derivatives, net | 57,604 | | | (157,816) | |
Interest expense, net | (54,746) | | | (26,632) | |
Other income (expense), net | 117 | | | 57 | |
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Income (Loss) Before Income Taxes | 147,872 | | | 174,754 | |
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Provision (Benefit) for Income Taxes | 33,214 | | | 7,678 | |
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Net Income (Loss) | $ | 114,658 | | | $ | 167,076 | |
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Per Share Amounts: | | | |
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Basic Earnings (Loss) Per Share | $ | 5.06 | | | $ | 8.85 | |
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Diluted Earnings (Loss) Per Share | $ | 5.02 | | | $ | 8.69 | |
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Weighted-Average Shares Outstanding - Basic | 22,677 | | | 18,885 | |
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Weighted-Average Shares Outstanding - Diluted | 22,852 | | | 19,237 | |
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See accompanying Notes to Condensed Consolidated Financial Statements. | | | |
Condensed Consolidated Statements of Stockholders’ Equity (Unaudited)
SilverBow Resources, Inc. and Subsidiary (in thousands, except share amounts)
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| Common Stock | | Additional Paid-In Capital | | Treasury Stock | | Retained Earnings (Accumulated Deficit) | | Total |
Balance, December 31, 2021 | $ | 168 | | | $ | 413,017 | | | $ | (2,984) | | | $ | (117,669) | | | $ | 292,532 | |
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Purchase of treasury shares (96,012 shares) | — | | | — | | | (2,462) | | | — | | | (2,462) | |
Treasury shares pursuant to purchase price adjustment (41,191 shares) | — | | | — | | | (1,146) | | | — | | | (1,146) | |
Vesting of share-based compensation (318,390 shares) | 3 | | | (3) | | | — | | | — | | | — | |
Issuance pursuant to acquisition (489 shares) | — | | | 12 | | | — | | | — | | | 12 | |
Share-based compensation | — | | | 1,101 | | | — | | | — | | | 1,101 | |
Net Loss | — | | | — | | | — | | | (64,255) | | | (64,255) | |
Balance, March 31, 2022 | $ | 171 | | | $ | 414,127 | | | $ | (6,592) | | | $ | (181,924) | | | $ | 225,782 | |
Stock options exercised (4,497 shares) | — | | | 39 | | | — | | | — | | | 39 | |
Purchase of treasury shares (16,485 shares) | — | | | — | | | (503) | | | — | | | (503) | |
Vesting of share-based compensation (57,355 shares) | 1 | | | (1) | | | — | | | — | | | — | |
Issuance pursuant to acquisition (5,448,472 shares) | 55 | | | 157,338 | | | — | | | — | | | 157,393 | |
Share-based compensation | — | | | 1,756 | | | — | | | — | | | 1,756 | |
Net Income | — | | | — | | | — | | | 88,790 | | | 88,790 | |
Balance, June 30, 2022 | $ | 227 | | | $ | 573,259 | | | $ | (7,095) | | | $ | (93,134) | | | $ | 473,257 | |
Stock options exercised (11,087 shares) | — | | | 387 | | | — | | | — | | | 387 | |
Purchase of treasury shares (7,853 shares) | — | | | — | | | (432) | | | — | | | (432) | |
Treasury shares pursuant to purchase price adjustment (184 shares) | — | | | — | | | (7) | | | — | | | (7) | |
Share-based compensation | — | | | 1,239 | | | — | | | — | | | 1,239 | |
Net income | — | | | — | | | — | | | 142,541 | | | 142,541 | |
Balance, September 30, 2022 | $ | 227 | | | $ | 574,885 | | | $ | (7,534) | | | $ | 49,407 | | | $ | 616,985 | |
| | | | | | | | | |
Balance, December 31, 2022 | $ | 227 | | | $ | 576,118 | | | $ | (7,534) | | | $ | 222,768 | | | $ | 791,579 | |
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Purchase of treasury shares (126,240 shares) | — | | | — | | | (2,945) | | | — | | | (2,945) | |
| | | | | | | | | |
Vesting of share-based compensation (418,518 shares) | 4 | | | (4) | | | — | | | — | | | — | |
| | | | | | | | | |
Share-based compensation | — | | | 1,179 | | | — | | | — | | | 1,179 | |
Net Income | — | | | — | | | — | | | 94,492 | | | 94,492 | |
Balance, March 31, 2023 | $ | 231 | | | $ | 577,293 | | | $ | (10,479) | | | $ | 317,260 | | | $ | 884,305 | |
Purchase of treasury shares (5,310 shares) | — | | | — | | | (121) | | | — | | | (121) | |
Vesting of share-based compensation (21,134 shares) | — | | | — | | | — | | | — | | | — | |
Share-based compensation | — | | | 1,524 | | | — | | | — | | | 1,524 | |
Net Income | — | | | — | | | — | | | 24,937 | | | 24,937 | |
Balance, June 30, 2023 | $ | 231 | | | $ | 578,817 | | | $ | (10,600) | | | $ | 342,197 | | | $ | 910,645 | |
Purchase of treasury shares (361 shares) | — | | | — | | | (16) | | | — | | | (16) | |
Vesting of share-based compensation (1,225 shares) | — | | | — | | | — | | | — | | | — | |
Issuance of common stock (2,810,811 shares) | 28 | | | 97,105 | | | — | | | — | | | 97,133 | |
Share-based compensation | — | | | 1,551 | | | — | | | — | | | 1,551 | |
Net Loss | — | | | — | | | — | | | (4,771) | | | (4,771) | |
Balance, September 30, 2023 | $ | 259 | | | $ | 677,473 | | | $ | (10,616) | | | $ | 337,426 | | | $ | 1,004,542 | |
See accompanying Notes to Condensed Consolidated Financial Statements. |
Condensed Consolidated Statements of Cash Flows (Unaudited)
SilverBow Resources, Inc. and Subsidiary (in thousands)
| | | | | | | | | | | |
| Nine Months Ended September 30, 2023 | | Nine Months Ended September 30, 2022 |
Cash Flows from Operating Activities: | | | |
Net income (loss) | $ | 114,658 | | | $ | 167,076 | |
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities | | | |
Depreciation, depletion, and amortization | 147,037 | | | 89,096 | |
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Accretion of asset retirement obligations | 718 | | | 366 | |
Deferred income taxes | 32,892 | | | 7,496 | |
Share-based compensation | 4,043 | | | 3,901 | |
(Gain) Loss on derivatives, net | (57,604) | | | 157,816 | |
Cash settlement (paid) received on derivatives | 70,670 | | | (182,058) | |
Settlements of asset retirement obligations | (481) | | | (47) | |
Write down of debt issuance cost | — | | | 350 | |
Other, net | 2,028 | | | (6,425) | |
Change in operating assets and liabilities: | | | |
(Increase) decrease in accounts receivable and other current assets | 9,129 | | | (47,320) | |
Increase (decrease) in accounts payable and accrued liabilities | (5,320) | | | 20,260 | |
Increase (decrease) in income taxes payable | 321 | | | (21) | |
Increase (decrease) in accrued interest | 311 | | | 1,688 | |
Net Cash Provided by (Used in) Operating Activities | 318,402 | | | 212,178 | |
Cash Flows from Investing Activities: | | | |
Additions to property and equipment | (316,003) | | | (163,567) | |
Acquisition of oil and gas properties, net of purchase price adjustments | (382) | | | (293,880) | |
Deposit and other fees for oil and gas property transaction | (51,163) | | | — | |
Proceeds from the sale of property and equipment | — | | | 4,415 | |
Payments on property sale obligations | — | | | (750) | |
| | | |
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Net Cash Provided by (Used in) Investing Activities | (367,548) | | | (453,782) | |
Cash Flows from Financing Activities: | | | |
| | | |
Proceeds from bank borrowings | 334,000 | | | 679,000 | |
Payments of bank borrowings | (378,000) | | | (426,000) | |
Net proceeds from issuances of common stock | 97,133 | | | — | |
Net proceeds from stock options exercised | — | | | 39 | |
Purchase of treasury shares | (3,082) | | | (3,404) | |
Payments of debt issuance costs | — | | | (7,228) | |
Net Cash Provided by (Used in) Financing Activities | 50,051 | | | 242,407 | |
Net Increase (Decrease) in Cash and Cash Equivalents | 905 | | | 803 | |
Cash and Cash Equivalents at Beginning of Period | 792 | | | 1,121 | |
Cash and Cash Equivalents at End of Period | $ | 1,697 | | | $ | 1,924 | |
Supplemental Disclosures of Cash Flow Information: | | | |
Cash paid during period for interest, net of amounts capitalized | $ | 52,170 | | | $ | 22,701 | |
| | | |
Non-cash Investing and Financing Activities: | | | |
Changes in capital accounts payable and capital accruals | $ | 13,363 | | | $ | 60,595 | |
Accrued other fees for oil and gas property transaction | $ | (1,401) | | | $ | — | |
Non-cash equity consideration for acquisitions | $ | — | | | $ | (156,259) | |
| | | |
See accompanying Notes to Condensed Consolidated Financial Statements. | | | |
Notes to Condensed Consolidated Financial Statements (Unaudited)
SilverBow Resources, Inc. and Subsidiary
(1) General Information
SilverBow Resources, Inc. (“SilverBow,” the “Company,” or “we”) is an independent oil and gas company headquartered in Houston, Texas. The Company's strategy is focused on acquiring and developing assets in the Eagle Ford and Austin Chalk located in South Texas.
Being a committed and long-term operator in South Texas, SilverBow possesses a significant understanding of the reservoir characteristics, geology, landowners and competitive landscape in the region. The Company leverages this in-depth knowledge to continue to assemble high quality drilling inventory while continuously enhancing its operations to maximize returns on capital invested.
The condensed consolidated financial statements included herein are unaudited and certain information and note disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States (“GAAP”) have been omitted pursuant to the rules and regulations of the Securities and Exchange Commission. We believe that the disclosures presented are adequate to allow the information presented not to be misleading. The condensed consolidated financial statements should be read in conjunction with the audited financial statements and the notes thereto included in our Annual Report on Form 10-K for the fiscal year ended December 31, 2022.
(2) Summary of Significant Accounting Policies
Basis of Presentation. The condensed consolidated financial statements included herein reflect necessary adjustments, all of which were of a recurring nature unless otherwise disclosed herein, and are in the opinion of our management necessary for a fair presentation.
Principles of Consolidation. The accompanying condensed consolidated financial statements include the accounts of SilverBow and its wholly owned subsidiary, SilverBow Resources Operating LLC, which are engaged in the exploration, development, acquisition, and operation of oil and gas properties, with a focus on oil and natural gas reserves in the Eagle Ford and Austin Chalk trend in Texas. Our undivided interests in oil and gas properties are accounted for using the proportionate consolidation method, whereby our proportionate share of the assets, liabilities, revenues, and expenses are included in the appropriate classifications in the accompanying condensed consolidated financial statements. Intercompany balances and transactions have been eliminated in preparing the accompanying condensed consolidated financial statements.
Stockholder Rights Agreement. On September 20, 2022, the Board adopted a stockholder rights agreement (the “Rights Agreement”) and declared a dividend distribution of one right (each, a “Right” and together with all such rights distributed or issued pursuant to the Rights Agreement, dated as of September 20, 2022, by and between the Company and American Stock Transfer & Trust Company, LLC, as rights agent, the “Rights”) for each outstanding share of Company common stock to holders of record on October 5, 2022. In the event that a person or group acquires beneficial ownership of 15% or more of the Company’s then-outstanding common stock, subject to certain exceptions, each Right would entitle its holder (other than such person or members of such group) to purchase additional shares of Company common stock at a substantial discount to the public market price. In addition, at any time after a person or group acquires beneficial ownership of 15% or more of the outstanding common stock, subject to certain exceptions, the Board may direct the Company to exchange the Rights (other than Rights owned by such person or certain related parties, which will have become null and void), in whole or in part, at an exchange ratio of one share of common stock per Right (subject to adjustment). While in effect, the Rights Agreement could make it more difficult for a third party to acquire control of the Company or a large block of the common stock of the Company without the approval of the Board. On May 16, 2023, the Company and the rights agent entered into an Amendment to the Rights Agreement (the “Amendment”) that amended the Rights Agreement to extend the expiration date until the close of business on the first day following the date of the Company’s first annual meeting of its stockholders that occurs after (but not on) the date of the Amendment. The Rights Agreement, as amended, will expire on the earliest of (a) 5:00 p.m., New York City time, on the first business day after the 2024 annual stockholders’ meeting, (b) the time at which the Rights are redeemed and (c) the time at which the Rights are exchanged in full.
Subsequent Events. We have evaluated subsequent events requiring potential accrual or disclosure in our condensed consolidated financial statements.
Through October 31, 2023, the Company entered into additional derivative contracts. The following tables summarize the weighted-average prices as well as future production volumes for our future derivative contracts entered into after September 30, 2023:
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Oil Derivative Contracts (NYMEX WTI Settlements) | | Total Volumes (Bbls) | | Weighted-Average Price |
Swap Contracts | | | | |
2024 Contracts | | | | |
1Q24 | | 91,000 | | | $ | 83.40 | |
2Q24 | | 91,000 | | | $ | 81.31 | |
3Q24 | | 92,000 | | | $ | 79.63 | |
4Q24 | | 92,000 | | | $ | 78.21 | |
2025 Contracts | | | | |
1Q25 | | 90,000 | | | $ | 76.52 | |
2Q25 | | 91,000 | | | $ | 75.38 | |
3Q25 | | 92,000 | | | $ | 74.56 | |
4Q25 | | 92,000 | | | $ | 73.58 | |
2026 Contracts | | | | |
1Q26 | | 157,500 | | | $ | 68.01 | |
2Q26 | | 136,500 | | | $ | 67.98 | |
3Q26 | | 110,400 | | | $ | 67.94 | |
4Q26 | | 156,150 | | | $ | 68.60 | |
| | | | | | | | | | | | | | |
Oil Basis Swaps (Argus Cushing (WTI) and Magellan East Houston) | | Total Volumes (MMBtu) | | Weighted-Average Price |
2023 Contracts | | | | |
4Q23 | | 61,000 | | | $ | 0.90 | |
2025 Contracts | | | | |
1Q25 | | 90,000 | | | $ | 1.75 | |
2Q25 | | 91,000 | | | $ | 1.75 | |
3Q25 | | 92,000 | | | $ | 1.75 | |
4Q25 | | 92,000 | | | $ | 1.75 | |
Calendar Monthly Roll Differential Swaps | | | | |
2023 Contracts | | | | |
4Q23 | | 61,000 | | | $ | 2.40 | |
2025 Contracts | | | | |
1Q25 | | 90,000 | | | $ | 0.50 | |
2Q25 | | 91,000 | | | $ | 0.50 | |
3Q25 | | 92,000 | | | $ | 0.50 | |
4Q25 | | 92,000 | | | $ | 0.50 | |
| | | | | | | | | | | | | | |
Natural Gas Derivative Contracts (NYMEX Henry Hub Settlements) | | Total Volumes (MMBtu) | | Weighted-Average Price |
Swap Contracts | | | | |
2024 Contracts | | | | |
1Q24 | | 1,820,000 | | | $ | 3.66 | |
2Q24 | | 2,430,000 | | | $ | 3.31 | |
3Q24 | | 2,760,000 | | | $ | 3.46 | |
4Q24 | | 2,760,000 | | | $ | 3.75 | |
2025 Contracts | | | | |
1Q25 | | 2,700,000 | | | $ | 4.20 | |
2Q25 | | 2,730,000 | | | $ | 3.75 | |
3Q25 | | 2,760,000 | | | $ | 3.89 | |
4Q25 | | 1,540,000 | | | $ | 4.11 | |
2026 Contracts | | | | |
1Q26 | | 900,000 | | | $ | 4.56 | |
2Q26 | | 910,000 | | | $ | 3.53 | |
3Q26 | | 920,000 | | | $ | 3.73 | |
4Q26 | | 920,000 | | | $ | 4.19 | |
| | | | | | | | | | | | | | |
Natural Gas Basis Derivative Swaps (East Texas Houston Ship Channel vs. NYMEX Settlements) | | Total Volumes (MMBtu) | | Weighted-Average Price |
2024 Contracts | | | | |
1Q24 | | 910,000 | | | $ | (0.21) | |
2Q24 | | 910,000 | | | $ | (0.21) | |
3Q24 | | 920,000 | | | $ | (0.21) | |
4Q24 | | 920,000 | | | $ | (0.21) | |
2025 Contracts | | | | |
1Q25 | | 900,000 | | | $ | (0.23) | |
2Q25 | | 910,000 | | | $ | (0.23) | |
3Q25 | | 920,000 | | | $ | (0.23) | |
4Q25 | | 920,000 | | | $ | (0.23) | |
| | | | | | | | | | | | | | |
NGL Swaps (Mont Belvieu) | | Total Volumes (Bbls) | | Weighted-Average Price |
2024 Contracts | | | | |
1Q24 | | 91,000 | | | $ | 24.25 | |
2Q24 | | 91,000 | | | $ | 24.25 | |
3Q24 | | 92,000 | | | $ | 24.25 | |
4Q24 | | 92,000 | | | $ | 24.25 | |
There were no other material subsequent events requiring additional disclosure in these condensed consolidated financial statements.
Use of Estimates. The preparation of financial statements in conformity with GAAP requires us to make estimates and assumptions that affect the reported amounts of certain assets and liabilities and the reported amounts of certain revenues and expenses during each reporting period. Such estimates and assumptions are subject to a number of risks and uncertainties that may cause actual results to differ materially from such estimates. Significant estimates and assumptions underlying these financial statements include:
•the estimated quantities of proved oil and natural gas reserves used to compute depletion of oil and natural gas properties, the related present value of estimated future net cash flows therefrom, and the Ceiling Test impairment calculation,
•estimates related to the collectability of accounts receivable and the creditworthiness of our customers,
•estimates of the counterparty bank risk related to letters of credit that our customers may have issued on our behalf,
•estimates of future costs to develop and produce reserves,
•accruals related to oil and gas sales, capital expenditures and lease operating expenses (“LOE”),
•estimates in the calculation of share-based compensation expense,
•estimates of our ownership in properties prior to final division of interest determination,
•the estimated future cost and timing of asset retirement obligations,
•estimates made in our income tax calculations, including the valuation of our deferred tax assets,
•estimates in the calculation of the fair value of commodity derivative assets and liabilities,
•estimates in the assessment of current litigation claims against the Company,
•estimates used in the assessment of business combinations and asset purchases,
•estimates in amounts due with respect to open state regulatory audits, and
•estimates on future lease obligations.
While we are not currently aware of any material revisions to any of our estimates, there will likely be future revisions to our estimates resulting from matters such as new accounting pronouncements, changes in ownership interests, payouts, joint venture audits, reallocations by purchasers or pipelines, or other corrections and adjustments common in the oil and gas industry, many of which relate to prior periods. These types of adjustments cannot be currently estimated and are expected to be recorded in the period during which the adjustments are known.
We are subject to legal proceedings, claims, liabilities and environmental matters that arise in the ordinary course of business. We accrue for losses when such losses are considered probable and the amounts can be reasonably estimated.
Property and Equipment. We follow the “full-cost” method of accounting for oil and natural gas property and equipment costs. Under this method of accounting, all productive and nonproductive costs incurred in the exploration, development, and acquisition of oil and natural gas reserves are capitalized. Such costs may be incurred both prior to and after the acquisition of a property and include lease acquisitions, geological and geophysical services, drilling, completion, and equipment. Internal costs incurred that are directly identified with exploration, development, and acquisition activities undertaken by us for our own account, and which are not related to production, general corporate overhead, or similar activities, are also capitalized. For the three months ended September 30, 2023 and 2022, such internal costs capitalized totaled $1.4 million and $1.1 million, respectively. For the nine months ended September 30, 2023 and 2022, such internal costs capitalized totaled $4.1 million and $3.3 million, respectively. Interest costs are also capitalized to unproved oil and natural gas properties. There was no capitalized interest on our unproved properties for both the three months ended September 30, 2023 and 2022 and the nine months ended September 30, 2023 and 2022.
The “Property and Equipment” balances on the accompanying condensed consolidated balance sheets are summarized for presentation purposes. The following is a detailed breakout of our “Property and Equipment” balances (in thousands):
| | | | | | | | | | | |
| September 30, 2023 | | December 31, 2022 |
Property and Equipment | | | |
Proved oil and gas properties | $ | 2,827,145 | | | $ | 2,506,853 | |
Unproved oil and gas properties | 27,821 | | | 16,272 | |
Furniture, fixtures and other equipment | 6,301 | | | 6,098 | |
Less – Accumulated depreciation, depletion, amortization & impairment | (1,151,141) | | | (1,004,044) | |
Property and Equipment, Net | $ | 1,710,126 | | | $ | 1,525,179 | |
No gains or losses are recognized upon the sale or disposition of oil and natural gas properties, except in transactions involving a significant amount of reserves or where the proceeds from the sale of oil and natural gas properties would significantly alter the relationship between capitalized costs and proved reserves of oil and natural gas attributable to a cost center. Internal costs associated with selling properties are expensed as incurred.
We compute the provision for depreciation, depletion and amortization (“DD&A”) of oil and natural gas properties using the unit-of-production method. Under this method, we compute the provision by multiplying the total unamortized costs of oil and natural gas properties, including future development costs, gas processing facilities, and both capitalized asset retirement obligations and undiscounted abandonment costs of wells to be drilled, net of salvage values, but excluding costs of unproved properties, by an overall rate determined by dividing the physical units of oil and natural gas produced (which excludes natural gas consumed in operations) during the period by the total estimated units of proved oil and natural gas reserves (which excludes natural gas consumed in operations) at the beginning of the period. Future development costs are estimated on a property-by-property basis based on current economic conditions. The period over which we will amortize these properties is dependent on our production from these properties in future years. Furniture, fixtures and other equipment are recorded at cost and are depreciated by the straight-line method at rates based on the estimated useful lives of the property, which range between two and 20 years. Repairs and maintenance are charged to expense as incurred.
Geological and geophysical (“G&G”) costs incurred on developed properties are recorded in “Proved oil and gas properties” and therefore subject to amortization. G&G costs incurred that are associated with unproved properties are capitalized in “Unproved oil and gas properties” and evaluated as part of the total capitalized costs associated with a prospect. The cost of unproved properties not being amortized is assessed quarterly, on a property-by-property basis, to determine whether such properties have been impaired. In determining whether such costs should be impaired, we evaluate current drilling results, lease expiration dates, current oil and gas industry conditions, economic conditions, capital availability and available geological and geophysical information. Any impairment assessed is added to the cost of proved properties being amortized.
Full-Cost Ceiling Test. At the end of each quarterly reporting period, the unamortized cost of oil and natural gas properties (including natural gas processing facilities, capitalized asset retirement obligations, net of related salvage values and deferred income taxes) is limited to the sum of the estimated future net revenues from proved properties (excluding cash outflows from recognized asset retirement obligations, including future development and abandonment costs of wells to be drilled, using the preceding 12-months’ average price based on closing prices on the first day of each month, adjusted for price differentials, discounted at 10% and the lower of cost or fair value of unproved properties) adjusted for related income tax effects (“Ceiling Test”).
The quarterly calculations of the Ceiling Test and provision for DD&A are based on estimates of proved reserves. There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting the future rates of production, timing and plan of development. The accuracy of any reserves estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Results of drilling, testing, and production subsequent to the date of the estimate may justify revision of such estimates. Accordingly, reserves estimates are often different from the quantities of oil and natural gas that are ultimately recovered. There was no ceiling test write-down for either of the three months ended September 30, 2023 and 2022 or the nine months ended September 30, 2023 and 2022.
If future capital expenditures outpace future discounted net cash flows in our reserve calculations, if we have significant declines in our oil and natural gas reserves volumes (which also reduces our estimate of discounted future net cash flows from proved oil and natural gas reserves) or if oil or natural gas prices decline, it is possible that non-cash write-downs of our oil and natural gas properties will occur again in the future. We cannot control and cannot predict what future prices for oil and natural gas will be; therefore, we cannot estimate the amount of any potential future non-cash write-down of our oil and natural gas properties due to decreases in oil or natural gas prices. However, it is reasonably possible that we will record additional Ceiling Test write-downs in future periods.
Accounts Receivable, Net. We assess the collectability of accounts receivable based on a broad range of reasonable and forward-looking information including historical losses, current economic conditions, future forecasts and contractual terms. The Company's credit losses based on these assessments are considered immaterial. At September 30, 2023, December 31, 2022 and December 31, 2021, we had an allowance of less than $0.1 million. The allowance has been deducted from the total “Accounts receivable, net” balance on the accompanying condensed consolidated balance sheets.
At September 30, 2023, our “Accounts receivable, net” balance included $60.4 million for oil and gas sales, $1.9 million due from joint interest owners, $9.1 million for severance tax credit receivables and $8.8 million for other receivables. At December 31, 2022, our “Accounts receivable, net” balance included $70.9 million for oil and gas sales, $5.6 million due from joint interest owners, $4.3 million for severance tax credit receivables and $8.9 million for other receivables. At December 31, 2021, our “Accounts receivable, net” balance included $45.3 million for oil and gas sales, $1.9 million due from joint interest owners, $1.0 million for severance tax credit receivables and $1.5 million for other receivables.
Supervision Fees. Consistent with industry practice, we charge a supervision fee to the wells we operate, including our wells, in which we own up to a 100% working interest. Supervision fees are recorded as a reduction to “General and
administrative, net,” on the accompanying condensed consolidated statements of operations. The amount of supervision fees charged for each of the nine months ended September 30, 2023 and 2022 did not exceed our actual costs incurred. The total amount of supervision fees charged to the wells we operated was $3.0 million and $2.8 million for the three months ended September 30, 2023 and 2022, respectively, and $8.6 million and $6.1 million for the nine months ended September 30, 2023 and 2022, respectively.
Income Taxes. Deferred taxes are determined based on the estimated future tax effects of differences between the financial statement and tax basis of assets and liabilities, given the provisions of the enacted tax laws. The Company's effective tax rate was approximately 17% and 4% for the three months ended September 30, 2023 and 2022, respectively, and 22% and 4% for the nine months ended September 30, 2023 and 2022, respectively. The Company recorded an income tax benefit of $0.9 million and income tax provision of $33.2 million for the three and nine months ended September 30, 2023, respectively, and an income tax provision of $6.1 million and $7.7 million for the three and nine months ended September 30, 2022, respectively. The tax impact for both periods was a product of the overall forecasted annual effective tax rate applied to the year to date income.
Section 382 of the Internal Revenue Code (“Section 382”) imposes limitations on a corporation’s ability to utilize its net operating losses (“NOLs”) if it experiences an ownership change. Generally, an “ownership change” occurs if one or more shareholders, each of whom is deemed to own five percent or more in value of a corporation’s stock, increase their aggregate percentage ownership by more than 50 percent over the lowest percentage of stock owned by those shareholders at any time during the preceding three-year period. In the event of an ownership change, utilization of the NOLs would be subject to an annual limitation under Section 382. We believe we had an ownership change in August 2022 and, therefore, are subject to an annual limitation on the usage of our NOLs generated prior to the ownership change. However, we do not expect to have any of our NOLs expire before becoming available to be utilized by the Company. Management will continue to monitor the potential impact of Section 382 with respect to our NOLs.
Our policy is to record interest and penalties relating to uncertain tax positions in income tax expense. At September 30, 2023 and December 31, 2022, we did not have any accrued liability for uncertain tax positions and do not anticipate recognition of any significant liabilities for uncertain tax positions during the next 12 months.
Revenue Recognition. Our reported oil and gas sales are comprised of revenues from oil, natural gas and natural gas liquids (“NGLs”) sales. Revenues from each product stream are recognized at the point when control of the product is transferred to the customer and collectability is reasonably assured. Prices for our products are either negotiated on a monthly basis or tied to market indices. The Company has determined that these contracts represent performance obligations which are satisfied when control of the commodity transfers to the customer, typically through the delivery of the specified commodity to a designated delivery point. Natural gas revenues are recognized based on the actual volume of natural gas sold to the purchasers.
The following table provides information regarding our oil and gas sales, by product, reported on the Condensed Consolidated Statements of Operations for the three months ended September 30, 2023 and 2022 and the nine months ended September 30, 2023 and 2022 (in thousands):
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Three Months Ended September 30, 2023 | | Three Months Ended September 30, 2022 | | Nine Months Ended September 30, 2023 | | Nine Months Ended September 30, 2022 | | | | |
Oil, natural gas and NGLs sales: | | | | | | | | | | | |
Oil | $ | 112,456 | | | $ | 71,811 | | | $ | 267,263 | | | $ | 155,566 | | | | | |
Natural gas | 46,075 | | | 150,958 | | | 132,802 | | | 351,626 | | | | | |
NGLs | 15,432 | | | 19,412 | | | 40,252 | | | 47,250 | | | | | |
Total | $ | 173,963 | | | $ | 242,181 | | | $ | 440,317 | | | $ | 554,442 | | | | | |
Accounts Payable and Accrued Liabilities. The “Accounts payable and accrued liabilities” balances on the accompanying condensed consolidated balance sheets are summarized below (in thousands):
| | | | | | | | | | | |
| September 30, 2023 | | December 31, 2022 |
Trade accounts payable | $ | 30,708 | | | $ | 23,660 | |
Accrued operating expenses | 11,266 | | | 10,572 | |
Accrued compensation costs | 3,267 | | | 4,814 | |
Asset retirement obligations – current portion | 1,578 | | | 1,284 | |
Accrued non-income based taxes | 13,303 | | | 4,849 | |
Accrued corporate and legal fees | 181 | | | 388 | |
WTI contingency payouts - current portion | 1,537 | | | 1,600 | |
Payable for settled derivatives | 3,549 | | | 6,026 | |
Other payables | 9,342 | | | 7,007 | |
Total accounts payable and accrued liabilities | $ | 74,731 | | | $ | 60,200 | |
Cash and Cash Equivalents. We consider all highly liquid instruments with an initial maturity of three months or less to be cash equivalents. These amounts do not include cash balances that are contractually restricted. The Company maintains cash and cash equivalent balances with major financial institutions, which at times exceed federally insured limits. The Company monitors the financial condition of the financial institutions and has experienced no losses associated with these accounts.
Treasury Stock. Our treasury stock repurchases are reported at cost and are included in “Treasury stock, held at cost” on the accompanying condensed consolidated balance sheets. For the nine months ended September 30, 2023, we purchased 131,911 treasury shares to satisfy withholding tax obligations arising upon the vesting of restricted shares. For the nine months ended September 30, 2022, we purchased 120,350 treasury shares to satisfy withholding tax obligations arising upon the vesting of restricted shares and received 41,375 shares in conjunction with our post-closing settlement for a previously disclosed acquisition.
New Accounting Pronouncements. In June 2016, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2016-13, Credit Losses - Measurement of Credit Losses on Financial Instruments. The standard changes how entities will measure credit losses for most financial assets, including accounts and notes receivables. The new standard replaces the existing incurred loss impairment methodology with a methodology that requires consideration of a broader range of reasonable and supportable forward-looking information to estimate all expected credit losses. The updated guidance is effective for the Company for annual and quarterly reporting periods beginning after December 15, 2022, and the Company adopted the guidance on January 1, 2023. The adoption of this guidance did not have a material impact on the Company’s consolidated financial statements or disclosures.
In March 2020, the FASB issued ASU No. 2020-04, Reference Rate Reform (Topic 848): Facilitation of the Effects of Reference Rate Reform on Financial Reporting followed by ASU No. 2021-01, Reference Rate Reform (Topic 848): Scope (“ASU 2021-01”), issued in January 2021, and ASU 2022-06, Reference Rate Reform (Topic 848): Deferral of the Sunset Date of Topic 848, issued in December 2022. The guidance provides and clarifies optional expedients and exceptions for applying generally accepted accounting principles to contract modifications, subject to meeting certain criteria, that reference LIBOR or another reference rate expected to be discontinued. The amendments within these ASUs were in effect beginning March 12, 2020, and an entity may elect to apply the amendments prospectively through December 31, 2024. This guidance provides an optional practical expedient that allows qualifying modifications to be accounted for as a debt modification rather than be analyzed under existing guidance to determine if the modification should be accounted for as a debt extinguishment. The Company adopted this accounting pronouncement in conjunction with the execution of the Third Amendment to the Note Purchase Agreement in June 2023 and elected to apply this optional expedient. See Note 6 – Long-Term Debt for further discussion of the Company’s accounting for its existing debt and related issuance costs. The adoption of this accounting standard did not have a material impact on the Company's condensed consolidated financial statements and related disclosures.
In August 2020, the FASB issued ASU No. 2020-06, Accounting for Convertible Instruments and Contracts in an Entity’s Own Equity. The guidance simplifies the accounting for certain financial instruments with characteristics of liabilities and equity, including convertible instruments and contracts in an entity’s own equity. Additionally, the amendment requires the application of the if-converted method to calculate the impact of convertible instruments on diluted earnings per share (EPS). The guidance is effective for the Company for fiscal years beginning after December 15, 2022, and the Company adopted the
guidance on January 1, 2023. The adoption of this guidance did not have a material impact on the Company’s consolidated financial statements or disclosures.
(3) Leases
The Company follows the FASB's Accounting Standards Codification Topic No. 842 and elected the package of practical expedients that allows an entity to carry forward historical accounting treatment relating to lease identification and classification for existing leases upon adoption and the practical expedient related to land easements that allows an entity to carry forward historical accounting treatment for land easements on existing agreements. The Company has made an accounting policy election to keep leases with an initial term of 12 months or less off the condensed consolidated balance sheets. We have elected to not account for lease and non-lease components separately.
The Company has contractual agreements for its corporate office lease, vehicle fleet, compressors, treating equipment, and for surface use rights. For leases with a primary term of more than 12 months, a right-of-use (“ROU”) asset and the corresponding lease liability is recorded. The Company determines at inception if an arrangement is an operating or financing lease. As of September 30, 2023, all of the Company’s leases were operating leases.
The initial asset and liability balances are recorded at the present value of the payment obligations over the lease term. If lease terms include options to extend the lease and it is reasonably certain that the Company will exercise that option, the lease term used for capitalization includes the expected renewal periods. Most leases do not provide an implicit interest rate. Unless the lease contract contains an implicit interest rate, the Company uses its incremental borrowing rate at the time of lease inception to compute the fair value of the lease payments. The ROU asset balance and current and non-current lease liabilities are reported separately on the accompanying condensed consolidated balance sheets. Certain leases have payment terms that vary based on the usage of the underlying assets. Variable lease payments are not included in ROU assets and lease liabilities. The Company recognizes lease expense on a straight-line basis over the lease term.
As of September 30, 2023, the Company's future cash payment obligation for its operating lease liabilities are as follows (in thousands):
| | | | | |
| As of September 30, 2023 |
2023 (Remaining) | $ | 2,667 | |
2024 | 4,166 | |
2025 | 2,427 | |
2026 | 1,194 | |
2027 | 61 | |
Thereafter | 475 | |
Total undiscounted lease payments | 10,990 | |
Present value adjustment | (879) | |
Net operating lease liabilities | $ | 10,111 | |
(4) Share-Based Compensation
Share-Based Compensation Plans
In 2016, the Company adopted the 2016 Equity Incentive Plan (as amended from time to time, the “2016 Plan”). The Company also adopted the Inducement Plan (as amended from time to time, the “Inducement Plan,” and, together with the 2016 Plan, the “Plans”) on December 15, 2016.
The Company computes a deferred tax benefit for restricted stock units (“RSUs”), performance-based stock units (“PSUs”) and stock options expected to generate future tax deductions by applying its effective tax rate to the expense recorded. For RSUs, the Company's actual tax deduction is based on the value of the units at the time of vesting.
The expense for awards issued to both employees and non-employees, which was recorded in “General and administrative, net” in the accompanying condensed consolidated statements of operations was $1.5 million and $1.2 million for the three months ended September 30, 2023 and 2022, respectively, and $4.0 million and $3.9 million for the nine months ended September 30, 2023 and 2022, respectively. Capitalized share-based compensation was less than $0.1 million for both
the three months ended September 30, 2023 and 2022, and $0.2 million for both the nine months ended September 30, 2023 and 2022.
We view stock option awards and RSUs with graded vesting as single awards with an expected life equal to the average expected life of component awards, and we amortize the awards on a straight-line basis over the life of the awards. The Company accounts for forfeitures in compensation cost when they occur.
Stock Option Awards
The compensation cost related to stock option awards is based on the grant date fair value and is typically expensed over the vesting period (generally one to five years). We use the Black-Scholes option pricing model to estimate the fair value of stock option awards.
At September 30, 2023, we had no unrecognized compensation cost related to stock option awards. The following table provides information regarding stock option award activity for the nine months ended September 30, 2023:
| | | | | | | | | | | |
| Shares | | Wtd. Avg. Exer. Price |
Options outstanding, beginning of period | 196,162 | | | $ | 26.46 | |
Options granted | — | | | $ | — | |
| | | |
| | | |
Options exercised | — | | | $ | — | |
Options outstanding, end of period | 196,162 | | | $ | 26.46 | |
Options exercisable, end of period | 196,162 | | | $ | 26.46 | |
Our outstanding stock option awards had $1.8 million aggregate intrinsic value at September 30, 2023. At September 30, 2023, the weighted-average remaining contract life of stock option awards outstanding was 3.6 years and exercisable was 3.6 years. The total intrinsic value of stock option awards exercisable was $1.8 million as of September 30, 2023.
Restricted Stock Units
The compensation cost related to restricted stock awards is based on the grant date fair value and is typically expensed over the requisite service period (generally one to five years).
As of September 30, 2023, we had $5.1 million unrecognized compensation expense related to our RSUs which is expected to be recognized over a weighted-average period of 2.0 years.
The following table provides information regarding RSU activity for the nine months ended September 30, 2023:
| | | | | | | | | | | |
| RSUs | | Wtd. Avg. Grant Price |
RSUs outstanding, beginning of period | 227,114 | | | $ | 21.18 | |
RSUs granted | 195,791 | | | $ | 23.75 | |
| | | |
| | | |
RSUs forfeited | (1,424) | | | $ | 25.44 | |
RSUs vested | (137,467) | | | $ | 17.78 | |
RSUs outstanding, end of period | 284,014 | | | $ | 24.58 | |
Performance-Based Stock Units
On May 21, 2019, the Company granted 99,500 PSUs for which the number of shares earned was based on the total shareholder return (“TSR”) of the Company's common stock relative to the TSR of its selected peers during the performance period from January 1, 2019 to December 31, 2021. The awards contained market conditions which allowed a payout ranging between 0% payout and 200% of the target payout. The fair value as of the grant date was $18.86 per unit or 112.9% of stock price. The awards had a cliff-vesting period of three years. In the first quarter of 2022, the Board and its Compensation Committee approved payout of these awards at 117% of target. Accordingly, 97,812 shares were issued on February 23, 2022.
On February 24, 2021, the Company granted 161,389 PSUs for which the number of shares earned is based on the TSR of the Company's common stock relative to the TSR of its selected peers during the performance period from January 1, 2021 to December 31, 2022. The awards contain market conditions which allow a payout ranging between 0% and 200% of the target payout. The fair value as of the grant date was $13.13 per unit or 157.6% of the stock price. The compensation expense for these awards is based on the per unit grant date valuation using a Monte Carlo simulation multiplied by the target payout level. The payout level is calculated based on actual stock price performance achieved during the performance period. The awards have a cliff-vesting period of two years. In the first quarter of 2023, the Board and its Compensation Committee approved payout of these awards at 188% of target. Accordingly, 303,410 shares were issued on February 22, 2023.
On February 23, 2022, the Company granted 122,111 PSUs for which the number of shares earned is based on the TSR of the Company's common stock relative to the TSR of its selected peers during the performance period from January 1, 2022 to December 31, 2024. The awards contain market conditions which allow a payout ranging between 0% and 200% of the target payout. The fair value as of the grant date was $36.47 per unit or 150.93% of the stock price. The compensation expense for these awards is based on the per unit grant date valuation using a Monte Carlo simulation multiplied by the target payout level. The payout level is calculated based on actual stock price performance achieved during the performance period. The awards have a cliff-vesting period of three years. All PSUs granted remain outstanding related to this award as of September 30, 2023.
On February 23, 2023, the Company granted 120,749 PSUs for which the number of shares earned is based on the TSR of the Company's common stock relative to the TSR of its selected peers during the performance period from January 1, 2023 to December 31, 2025. The awards contain market conditions which allow a payout ranging between 0% and 200% of the target payout. The fair value as of the grant date was $31.18 per unit or 136.28% of the stock price. The compensation expense for these awards is based on the per unit grant date valuation using a Monte Carlo simulation multiplied by the target payout level. The payout level is calculated based on actual stock price performance achieved during the performance period. The awards have a cliff-vesting period of three years. All PSUs granted remain outstanding related to this award as of September 30, 2023.
As of September 30, 2023, we had $4.9 million unrecognized compensation expense related to our PSUs based on the assumption of 100% target payout. The remaining weighted-average performance period is 1.9 years.
The following table provides information regarding performance-based stock unit activity for the nine months ended September 30, 2023:
| | | | | | | | | | | |
| PSUs | | Wtd. Avg. Grant Price |
Performance based stock units outstanding, beginning of period | 283,500 | | | $ | 23.18 | |
Performance based stock units granted | 120,749 | | | $ | 31.18 | |
Performance based stock units incremental shares granted | 142,021 | | | $ | 13.13 | |
Performance based stock units vested | (303,410) | | | $ | 13.13 | |
Performance based stock units outstanding, end of period | 242,860 | | | $ | 33.84 | |
(5) Earnings Per Share
Basic earnings per share (“Basic EPS”) has been computed using the weighted-average number of common shares outstanding during each period. Diluted earnings per share (“Diluted EPS”) assumes, as of the beginning of the period, exercise of stock options and RSU grants using the treasury stock method. Diluted EPS also assumes conversion of PSUs to common shares based on the number of shares (if any) that would be issuable, according to predetermined performance and market goals, if the end of the reporting period was the end of the performance period. Certain of our stock options and RSU grants that would potentially dilute Basic EPS in the future were also antidilutive for the three and nine months ended September 30, 2023 and 2022 are discussed below.
The following is a reconciliation of the numerators and denominators used in the calculation of Basic EPS and Diluted EPS for the periods indicated below (in thousands, except per share amounts):
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Three Months Ended September 30, 2023 | | Three Months Ended September 30, 2022 |
| Net Income (Loss) | | Shares | | Per Share Amount | | Net Income (Loss) | | Shares | | Per Share Amount |
Basic EPS: | | | | | | | | | | | |
Net Income (Loss) and Share Amounts | $ | (4,771) | | | 22,985 | | | $ | (0.21) | | | $ | 142,541 | | | 22,308 | | | $ | 6.39 | |
Dilutive Securities: | | | | | | | | | | | |
Performance Based Stock Unit Awards | | | — | | | | | | | 169 | | | |
RSU Awards | | | — | | | | | | | 137 | | | |
Stock Option Awards | | | — | | | | | | | 55 | | | |
Diluted EPS: | | | | | | | | | | | |
Net Income (Loss) and Assumed Share Conversions | $ | (4,771) | | | 22,985 | | | $ | (0.21) | | | $ | 142,541 | | | 22,669 | | | $ | 6.29 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Nine Months Ended September 30, 2023 | | Nine Months Ended September 30, 2022 |
| Net Income (Loss) | | Shares | | Per Share Amount | | Net Income (Loss) | | Shares | | Per Share Amount |
Basic EPS: | | | | | | | | | | | |
Net Income (Loss) and Share Amounts | $ | 114,658 | | | 22,677 | | | $ | 5.06 | | | $ | 167,076 | | | 18,885 | | | $ | 8.85 | |
Dilutive Securities: | | | | | | | | | | | |
Performance Based Stock Unit Awards | | | 67 | | | | | | | 141 | | | |
RSU Awards | | | 91 | | | | | | | 171 | | | |
Stock Option Awards | | | 17 | | | | | | | 40 | | | |
Diluted EPS: | | | | | | | | | | | |
Net Income (Loss) and Assumed Share Conversions | $ | 114,658 | | | 22,852 | | | $ | 5.02 | | | $ | 167,076 | | | 19,237 | | | $ | 8.69 | |
On September 18, 2023, the Company issued 2,810,811 shares of its common stock in a registered underwritten offering, for aggregate net proceeds, after offering expenses and fees, of approximately $97.1 million.
There were 0.2 million stock options that were not included in the computation of Diluted EPS for the three months ended September 30, 2023 because they were antidilutive due to the net loss, while there were no antidilutive stock options for the three months ended September 30, 2022. Additionally, there were less than 0.1 million stock options to purchase shares which were not included in the computation of Diluted EPS for both the nine months ended September 30, 2023 and 2022, because they were antidilutive.
There were 0.2 million shares of RSUs that were not included in the computation of Diluted EPS for the three months ended September 30, 2023 because they were antidilutive due to the net loss and less than 0.1 million shares of RSUs that were not included in the computation of Diluted EPS for the three months ended September 30, 2022 because they were antidilutive. Additionally, there were less than 0.1 million shares of RSUs which were not included in the computation of Diluted EPS for both the nine months ended September 30, 2023 and 2022 because they were antidilutive.
There were 0.1 million shares of PSUs that were not included in the computation of Diluted EPS for the three months ended September 30, 2023 because they were antidilutive due to the net loss and no antidilutive shares of PSUs for the three months ended September 30, 2022. Additionally, there were no antidilutive shares of PSUs for both the nine months ended September 30, 2023 and 2022.
(6) Long-Term Debt
The Company's long-term debt consisted of the following (in thousands):
| | | | | | | | | | | |
| September 30, 2023 | | December 31, 2022 |
Credit Facility Borrowings due 2026 (1) | $ | 498,000 | | | $ | 542,000 | |
Second Lien Notes due 2026 | 150,000 | | | 150,000 | |
| 648,000 | | | 692,000 | |
Unamortized discount on Second Lien Notes due 2026 | (738) | | | (882) | |
Unamortized debt issuance cost on Second Lien Notes due 2026 | (2,166) | | | (2,587) | |
Long-Term Debt, net | $ | 645,096 | | | $ | 688,531 | |
(1) Unamortized debt issuance costs on our Credit Facility borrowings are included in “Other Long-Term Assets” in our condensed consolidated balance sheet. As of September 30, 2023 and December 31, 2022, we had $7.0 million and $8.7 million, respectively, in unamortized debt issuance costs on our Credit Facility borrowings.
Revolving Credit Facility. Amounts outstanding under our Credit Facility (defined below) were $498.0 million and $542.0 million as of September 30, 2023 and December 31, 2022, respectively. The Company is a party to a First Amended and Restated Senior Secured Revolving Credit Agreement with JPMorgan Chase Bank, National Association, as administrative agent, and certain lenders party thereto, as amended (such agreement, the “Credit Agreement” and the borrowing facility provided thereby, the “Credit Facility”).
The Credit Facility matures October 19, 2026 (or to the extent earlier, the date that is 91 days prior to the scheduled maturity of the Company's Second Lien notes), and provides for a maximum credit amount of $2.0 billion, subject to the current borrowing base of $775.0 million. The borrowing base is regularly redetermined in or about May and November of each calendar year and is subject to additional adjustments from time to time, including for asset sales, elimination or reduction of hedge positions and incurrence of other debt. Additionally, the Company and the administrative agent may request an unscheduled redetermination of the borrowing base between scheduled redeterminations. The amount of the borrowing base is determined by the lenders, in their discretion, in accordance with their oil and gas lending criteria at the time of the relevant redetermination. In conjunction with its regularly scheduled semi-annual redeterminations, the Company reaffirmed the borrowing base and elected commitment amount under the Credit Facility at $775.0 million, effective November 22, 2022, and again on March 20, 2023. The Company may also request the issuance of letters of credit under the Credit Agreement in an aggregate amount up to $25.0 million, which reduces the amount of available borrowings under the borrowing base in the amount of such issued and outstanding letters of credit. There were no outstanding letters of credit as of September 30, 2023, and no outstanding letters of credit as of December 31, 2022. Maintaining or increasing our borrowing base under our Credit Facility is dependent on many factors, including commodity prices, our hedge positions, changes in our lenders' lending criteria and our ability to raise capital to drill wells to replace produced reserves.
Interest under the Credit Facility accrues at the Company’s option either at an Alternate Base Rate plus the applicable margin (“ABR Loans”), the Adjusted Term Secured Overnight Financing Rate (“SOFR”) plus the applicable margin (“Term Benchmark Loans”) or Adjusted Daily Simple SOFR plus the applicable margin (“RFR Loans”). The applicable margin ranges from 1.75% to 2.75% based on borrowing base utilization for ABR Loans and 2.75% to 3.75% based on borrowing base utilization for Term Benchmark Loans and RFR Loans. The Alternate Base Rate and SOFR are defined, and the applicable margins are set forth, in the Credit Agreement. Undrawn amounts under the Credit Facility are subject to a 0.5% commitment fee. To the extent that a payment default exists and is continuing, all amounts outstanding under the Credit Facility will bear interest at 2.0% per annum above the rate and margin otherwise applicable thereto. As of September 30, 2023, the Company's weighted average interest rate on Credit Facility borrowings was 8.67%.
The obligations under the Credit Agreement are secured, subject to certain exceptions, by a first priority lien on substantially all assets of the Company and its subsidiary, including a first priority lien on properties attributed with at least 85% of estimated proved reserves of the Company and its subsidiary.
The Credit Agreement contains the following financial covenants:
•a ratio of total debt to earnings before interest, tax, depreciation and amortization (“EBITDA”), as defined in the Credit Agreement, for the most recently completed four fiscal quarters, not to exceed 3.00 to 1.00 as of the last day of each fiscal quarter; and
•a current ratio, as defined in the Credit Agreement, which includes in the numerator available borrowings undrawn under the borrowing base, of not less than 1.00 to 1.00 as of the last day of each fiscal quarter.
As of September 30, 2023, the Company was in compliance with all financial covenants under the Credit Agreement.
Additionally, the Credit Agreement contains certain representations, warranties and covenants, including but not limited to, limitations on incurring debt and liens, limitations on making certain restricted payments, limitations on investments, limitations on asset sales and hedge unwinds, limitations on transactions with affiliates and limitations on modifying organizational documents and material contracts. The Credit Agreement contains customary events of default. If an event of default occurs and is continuing, the lenders may declare all amounts outstanding under the Credit Facility to be immediately due and payable.
Total interest expense on the Credit Facility, which includes commitment fees and amortization of debt issuance costs, was $14.6 million and $8.3 million for the three months ended September 30, 2023 and 2022, respectively, and $39.8 million and $15.9 million for the nine months ended September 30, 2023 and 2022, respectively. The amount of commitment fee amortization included in interest expense, net was $0.2 million and $0.3 million for the three months ended September 30, 2023 and 2022, respectively, and $0.7 million and $0.9 million for the nine months ended September 30, 2023 and 2022, respectively.
Senior Secured Second Lien Notes. On December 15, 2017, the Company entered into a Note Purchase Agreement for Senior Secured Second Lien Notes (as amended, the “Note Purchase Agreement,” and such second lien facility the “Second Lien”) among the Company as issuer, U.S. Bank National Association as agent and collateral agent, and certain holders that are a party thereto, and issued notes in an initial principal amount of $200.0 million, with a $2.0 million discount, for net proceeds of $198.0 million.
Effective November 12, 2021, the Company entered into the Second Amendment to the Note Purchase Agreement, which extended the maturity date from December 15, 2024 to December 15, 2026 subject to paying down the principal amount of the Second Lien from $200.0 million to $150.0 million. The Company made the $50.0 million redemption of the Second Lien notes on November 29, 2021.
On June 14, 2023, the Company entered into the Third Amendment to the Note Purchase Agreement to effectuate the replacement of LIBOR with an adjusted term secured overnight financing rate plus a margin of 0.25% (“Term SOFR”). After the Third Amendment, interest under the Second Lien is payable quarterly and accrues, based on the Company's election at the time of the borrowing, either at Term SOFR plus a margin of 7.5% (“Second Lien Term SOFR Loans”) or at an Alternate Base Rate which is based on the greater of (i) the prime rate; (ii) the greater of the federal funds effective rate or overnight bank funding rate, plus 0.5%; or (iii) Term SOFR plus 1% (“Second Lien ABR Loans”) plus a margin of 6.5%. Additionally, to the extent the Company were to default on the Second Lien, this would potentially trigger a cross-default under our Credit Facility. As of September 30, 2023, the Company's interest rate on Second Lien borrowings was 13.16%.
The Company has the right, to the extent permitted under the Credit Facility and subject to the terms and conditions of the Second Lien, to optionally prepay the notes at no premium. Additionally, the Second Lien contains customary mandatory prepayment obligations upon asset sales (including hedge terminations), casualty events and incurrences of certain debt, subject to, in certain circumstances, reinvestment periods. Management believes the probability of mandatory prepayment due to default is remote.
The obligations under the Second Lien are secured, subject to certain exceptions and other permitted liens (including the liens created under the Credit Facility), by a perfected security interest, second in priority to the liens securing our Credit Facility, and mortgage lien on substantially all assets of the Company and its subsidiary, including a mortgage lien on oil and gas properties attributed with at least 90% of estimated PV-9 (defined below), of proved reserves of the Company and its subsidiary and 90% of the book value attributed to the PV-9 of the non-proved oil and gas properties of the Company. PV-9 is determined using commodity price assumptions by the administrative agent of the Credit Facility. PV-9 value is the estimated future net revenues to be generated from the production of proved reserves discounted to present value using an annual discount rate of 9%.
The Second Lien contains an Asset Coverage Ratio, which is only tested (i) as a condition to issuance of additional notes and (ii) in connection with certain asset sales in order to determine whether the proceeds of such asset sale must be applied as a prepayment of the notes and includes in the numerator of the PV-10 (defined below), based on forward strip pricing, plus the swap mark-to-market value of the commodity derivative contracts of the Company and its restricted subsidiary and in the denominator the total net indebtedness of the Company and its restricted subsidiary, of not less than 1.25 to 1.0 as of
each date of determination (the “Asset Coverage Ratio”). PV-10 value is the estimated future net revenues to be generated from the production of proved reserves discounted to present value using an annual discount rate of 10%.
The Second Lien also contains a financial covenant measuring the ratio of total net debt-to-EBITDA, as defined in the Note Purchase Agreement, for the most recently completed four fiscal quarters, not to exceed 3.25 to 1.0 as of the last day of each fiscal quarter. As of September 30, 2023, the Company was in compliance with all financial covenants under the Second Lien.
The Second Lien contains certain customary representations, warranties and covenants, including but not limited to, limitations on incurring debt and liens, limitations on making certain restricted payments, limitations on investments, limitations on asset sales and hedge unwinds, limitations on transactions with affiliates and limitations on modifying organizational documents and material contracts. The Second Lien contains customary events of default. If an event of default occurs and is continuing, the lenders may declare all amounts outstanding under the Second Lien to be immediately due and payable.
As of September 30, 2023, total net amounts recorded for the Second Lien were $147.1 million, net of unamortized debt discount and debt issuance costs. Interest expense on the Second Lien totaled $5.2 million and $3.8 million for the three months ended September 30, 2023 and 2022, respectively, and $14.9 million and $10.7 million for the nine months ended September 30, 2023 and 2022, respectively.
Debt Issuance Costs. Our policy is to capitalize upfront commitment fees and other direct expenses associated with our line of credit arrangement and then amortize such costs ratably over the term of the arrangement, regardless of whether there are any outstanding borrowings. During the nine months ended September 30, 2022, the Company capitalized $7.2 million for debt issuance costs incurred in connection with the amendments to our Credit Facility. There were no capitalized costs incurred during the nine months ended September 30, 2023.
(7) Acquisitions and Dispositions
November 2021 Acquisition
On November 19, 2021, the Company closed on an acquisition of oil-weighted assets in the Eagle Ford. The acquired assets included wells and acreage in La Salle, McMullen, DeWitt and Lavaca counties. After consideration of closing adjustments, total aggregate consideration was approximately $77.4 million, consisting of $37.6 million in cash, 1,351,961 shares of our common stock valued at approximately $37.9 million based on the Company's share price on the closing date, and contingent consideration with an estimated fair value of $1.9 million. The contingent consideration consists of up to three earn-out payments of $1.6 million per year for each of 2022, 2023 and 2024, contingent upon the average monthly settlement price of WTI exceeding $70 per barrel for such year (the “2021 WTI Contingency Payout”). During the three months ended September 30, 2023 and 2022, the Company recorded losses of $0.9 million and gains of $0.7 million, respectively, and losses of $1.0 million and $0.8 million, respectively, for the nine months ended September 30, 2023 and 2022 related to the 2021 WTI Contingency Payout which are recorded in “Gain (loss) on commodity derivatives, net” on the consolidated statements of operations. We also recorded $1.6 million in earn-out consideration payable to the seller related to the 2022 calendar year in “Accounts payable and accrued liabilities” on the condensed consolidated balance sheet as of December 31, 2022. For further discussion of the fair value related to the Company's contingent consideration, refer to Note 9 of these Notes to Consolidated Financial Statements. Management determined that substantially all the fair value of the gross assets acquired were concentrated in the proved oil and gas properties and have therefore accounted for this transaction as an asset acquisition and allocated the purchase price based on the relative fair value of the assets acquired and liabilities assumed.
May 2022 Acquisition
On May 10, 2022, the Company closed the acquisition of certain oil and gas assets located in La Salle and McMullen Counties, Texas, as well as assumed the seller's commodity derivative contracts in place at the closing date, from SandPoint Operating, LLC, a subsidiary of SandPoint Resources, LLC (collectively, “SandPoint”). After consideration of closing adjustments, total aggregate consideration was approximately $67.5 million, consisting of $27.7 million in cash and 1,300,000 shares of our common stock valued at approximately $39.8 million based on the Company's share price on the closing date. We incurred approximately $0.5 million in transaction costs during the year ended December 31, 2022 related to the acquisition. Management determined that substantially all the fair value of the gross assets acquired were concentrated in the proved oil and gas properties and have therefore accounted for this transaction as an asset acquisition and allocated the purchase price based on the relative fair value of the assets acquired and liabilities assumed.
The following table represents the allocation of the total cost of the acquisition to the assets acquired and liabilities assumed (in thousands):
| | | | | | | | |
Total Cost | | |
Cash consideration | | $ | 27,709 | |
Equity consideration | | 39,767 | |
Total Consideration | | 67,476 | |
| | |
Transaction costs | | 466 | |
| | |
Total Cost of Transaction | | $ | 67,942 | |
| | |
Allocation of Total Cost | | |
Assets | | |
Oil and gas properties | | $ | 84,810 | |
Total assets | | 84,810 | |
| | |
Liabilities | | |
Accounts payable and accrued liabilities | | 199 | |
Fair value of commodity derivatives | | 16,511 | |
Asset retirement obligations | | 158 | |
Total Liabilities | | $ | 16,868 | |
| | |
Net Assets Acquired | | $ | 67,942 | |
June 2022 Acquisition
On June 30, 2022, the Company closed the acquisition of certain oil and gas assets located in Atascosa, La Salle, Live Oak and McMullen Counties, Texas, as well as assumed the seller's commodity derivative contracts in place at the closing date, from Sundance Energy, Inc., and its affiliated entities Armadillo E&P, Inc. and SEA Eagle Ford, LLC (collectively, “Sundance”). After consideration of closing adjustments, total aggregate consideration was approximately $344.9 million, consisting of $220.9 million in cash, 4,148,472 shares of our common stock valued at approximately $117.7 million based on the Company's share price on the closing date, accrued purchase price adjustments receivable of $1.0 million and contingent consideration with an estimated fair value of $7.4 million. The contingent consideration consists of up to two earn-out payments of $7.5 million each, contingent upon the average monthly settlement price of NYMEX West Texas Intermediate crude oil exceeding $95 per barrel for the period from April 13, 2022 through December 31, 2022 which would trigger a payment of $7.5 million in 2023 and $85 per barrel for 2023 which would trigger a payment of $7.5 million in 2024 (the “2022 WTI Contingency Payout”). The contingent payout for the period of April 13, 2022 through December 31, 2022 did not materialize. During the nine months ended September 30, 2023, the Company recorded gains of $1.0 million related to valuation changes in the 2022 WTI Contingency Payout recorded in “Gain (loss) on commodity derivatives, net” on the accompanying condensed consolidated statements of operations. Additionally, as part of our post-close settlement we settled the 2022 WTI Contingency during the second quarter of 2023. As such, we recorded a non-cash gain of $1.1 million during the nine months ended September 30, 2023, and we are no longer required to make a contingency payment related to the 2022 WTI Contingency Payout. We incurred approximately $6.8 million in transaction costs during the year ended December 31, 2022 related to the acquisition. Management determined that substantially all the fair value of the gross assets acquired were concentrated in the proved oil and gas properties and have therefore accounted for this transaction as an asset acquisition and allocated the purchase price based on the relative fair value of the assets acquired and liabilities assumed.
The following table represents the allocation of the total cost of the acquisition to the assets acquired and liabilities assumed (in thousands):
| | | | | | | | |
Total Cost | | |
Cash consideration | | $ | 220,866 | |
Equity consideration | | 117,651 | |
Fair value of contingent consideration | | 7,422 | |
Accrued purchase price adjustments receivable | | (1,000) | |
Total Consideration | | 344,939 | |
| | |
Transaction costs | | 6,766 | |
| | |
Total Cost of Transaction | | $ | 351,705 | |
| | |
Allocation of Total Cost | | |
Assets | | |
Other current assets | | $ | 4,202 | |
Oil and gas properties | | 397,401 | |
Right of use assets | | 890 | |
Total assets | | 402,493 | |
| | |
Liabilities | | |
Accounts payable and accrued liabilities | | 13,687 | |
Fair value of commodity derivatives | | 33,767 | |
Non-current lease liability | | 890 | |
Asset retirement obligations | | 2,444 | |
Total Liabilities | | $ | 50,788 | |
| | |
Net Assets Acquired | | $ | 351,705 | |
August 2022 Acquisition
On August 15, 2022, the Company closed the acquisition of certain oil and gas assets in Webb County, Texas. After consideration of closing adjustments, total consideration was approximately $31.2 million. We did not incur any significant transaction costs during the year ended December 31, 2022 related to the acquisition. Management determined that substantially all the fair value of the gross assets acquired were concentrated in the proved oil and gas properties and have therefore accounted for this transaction as an asset acquisition and allocated the purchase price based on the relative fair value of the assets acquired and liabilities assumed.
October 2022 Acquisition
On October 31, 2022, the Company closed the acquisition of certain oil and gas assets in Dewitt and Gonzales Counties, Texas. After consideration of closing adjustments, total consideration was approximately $80.1 million. The acquisition is subject to further customary post-closing adjustments. We did not incur any significant transaction costs during the year ended December 31, 2022 related to the acquisition. Management determined that substantially all the fair value of the gross assets acquired were concentrated in the proved oil and gas properties and have therefore accounted for this transaction as an asset acquisition and allocated the purchase price based on the relative fair value of the assets acquired and liabilities assumed.
2022 Non-strategic Dispositions
During 2022, the Company closed on multiple dispositions of non-strategic oil and gas assets. After consideration of closing adjustments, total proceeds from the dispositions were approximately $4.4 million. The transactions are subject to further customary post-closing adjustments. There was no gain or loss recognized in connection with the dispositions.
2023 Chesapeake Acquisition
During the third quarter of 2023, SilverBow executed a purchase and sale agreement for the acquisition of certain oil and gas assets in South Texas from Chesapeake Energy Corporation (the “Chesapeake South Texas Rich Properties”) for a purchase price of $700 million, comprised of a $650 million cash payment at the closing date and a $50 million deferred cash payment due 12 months post-close, subject to customary purchase price adjustments (the “Chesapeake Transaction”) pursuant to the purchase and sale agreement, dated as of August 11, 2023, between SilverBow, SilverBow Resources Operating, LLC and the Chesapeake Sellers (the “Purchase Agreement”). Chesapeake may also receive up to $50 million in contingent cash consideration based on future commodity prices. SilverBow paid a $50 million cash deposit into escrow in conjunction with the Purchase Agreement recorded in “Deposit and other fees for oil and gas property transaction” on the accompanying condensed consolidated balance sheet.
The Purchase Agreement contains certain termination rights, including, but not limited to, each party’s right to terminate the Purchase Agreement in the event a material breach by the other party has occurred and is not waived on or before September 25, 2023, which date has passed, and in any event if the Chesapeake Transaction has not been consummated on or before November 24, 2023; provided that such date may be automatically extended for an additional 15 days to December 9, 2023, in the event certain approvals and consents have not been obtained by such date. The Chesapeake Transaction has an effective date of February 1, 2023, and is expected to close by year-end 2023, subject to satisfaction or waiver of certain customary closing conditions, including the accuracy of the representations and warranties of each party, compliance by each party in all material respects with its covenants and the satisfaction of certain consent requirements.
(8) Price-Risk Management Activities
Derivatives are recorded on the condensed consolidated balance sheet at fair value with changes in fair value recognized in earnings. The changes in the fair value of our derivatives are recognized in “Gain (loss) on commodity derivatives, net” on the accompanying condensed consolidated statements of operations. The Company's price-risk management policy is to use derivative instruments to protect against declines in oil and natural gas prices, primarily through the purchase of commodity price swaps and collars as well as basis swaps.
During the three months ended September 30, 2023 and 2022, the Company recorded losses of $53.7 million and losses of $1.3 million, respectively, on its commodity derivatives. During the nine months ended September 30, 2023 and 2022, the Company recorded gains of $56.5 million and losses of $162.5 million, respectively, on its commodity derivatives. During the three months ended September 30, 2023 and 2022, the Company recorded losses of $0.9 million and gains of $6.1 million, respectively, related to valuation changes on the 2021 WTI Contingency Payout and 2022 WTI Contingency Payout. During the nine months ended September 30, 2023 and 2022, the Company recorded gains of $1.1 million and gains of $4.7 million, respectively, related to valuation changes on the 2021 WTI Contingency Payout and 2022 WTI Contingency Payout. The Company collected cash payments of $70.7 million and made cash payments of $182.1 million for settled derivative contracts during the nine months ended September 30, 2023 and 2022, respectively.
At September 30, 2023 and December 31, 2022, there was $8.4 million and $6.9 million, respectively, in receivables for settled derivatives which were included on the accompanying condensed consolidated balance sheet in “Accounts receivable, net” and were subsequently collected in October 2023 and January 2023, respectively. At September 30, 2023 and December 31, 2022, we also had $3.5 million and $6.0 million, respectively, in payables for settled derivatives which were included on the accompanying condensed consolidated balance sheet in “Accounts payable and accrued liabilities” and were subsequently paid in October 2023 and January 2023, respectively.
The fair values of our swap contracts are computed using observable market data whereas our collar contracts are valued using a Black-Scholes pricing model. At September 30, 2023, there was $50.2 million and $14.2 million in current unsettled derivative assets and long-term unsettled derivative assets, respectively, and $32.8 million and $21.6 million in current and long-term unsettled derivative liabilities, respectively. At December 31, 2022, there was $52.5 million and $24.2 million in current and long-term unsettled derivative assets, respectively, and $40.8 million and $7.7 million in current and long-term unsettled derivative liabilities, respectively.
The Company uses an International Swap and Derivatives Association master agreement for our derivative contracts. This is an industry-standardized contract containing the general conditions of our derivative transactions including provisions relating to netting derivative settlement payments under certain circumstances (such as default). For reporting purposes, the Company has elected to not offset the asset and liability fair value amounts of its derivatives on the accompanying condensed consolidated balance sheet. Under the right of set-off, there was a $10.1 million net fair value asset at September 30, 2023, and a $28.2 million net fair value asset at December 31, 2022. For further discussion related to the fair value of the Company's derivatives, refer to Note 9 of these Notes to Condensed Consolidated Financial Statements.
The following tables summarize the weighted-average prices as well as future production volumes for our future derivative contracts in place as of September 30, 2023:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Oil Derivative Contracts (NYMEX WTI Settlements) | | Total Volumes (Bbls) | | Weighted-Average Price | | Weighted-Average Collar Sub Floor Price | | Weighted-Average Collar Floor Price | | Weighted-Average Collar Call Price |
Swap Contracts | | | | | | | | | | |
2023 Contracts | | | | | | | | | | |
4Q23 | | 707,300 | | | $ | 78.53 | | | | | | | |
2024 Contracts | | | | | | | | | | |
1Q24 | | 728,000 | | | $ | 77.67 | | | | | | | |
2Q24 | | 754,550 | | | $ | 77.59 | | | | | | | |
3Q24 | | 779,620 | | | $ | 76.48 | | | | | | | |
4Q24 | | 762,100 | | | $ | 76.16 | | | | | | | |
2025 Contracts | | | | | | | | | | |
1Q25 | | 666,000 | | | $ | 71.60 | | | | | | | |
2Q25 | | 673,400 | | | $ | 71.60 | | | | | | | |
3Q25 | | 680,800 | | | $ | 71.60 | | | | | | | |
4Q25 | | 588,800 | | | $ | 71.29 | | | | | | | |
2026 Contracts | | | | | | | | | | |
1Q26 | | 315,000 | | | $ | 69.40 | | | | | | | |
2Q26 | | 318,500 | | | $ | 69.40 | | | | | | | |
3Q26 | | 322,000 | | | $ | 69.40 | | | | | | | |
4Q26 | | 230,000 | | | $ | 69.42 | | | | | | | |
Collar Contracts | | | | | | | | | | |
2023 Contracts | | | | | | | | | | |
4Q23 | | 302,242 | | | | | | | $ | 65.89 | | | $ | 74.54 | |
2024 Contracts | | | | | | | | | | |
1Q24 | | 319,700 | | | | | | | $ | 58.95 | | | $ | 71.74 | |
2Q24 | | 215,000 | | | | | | | $ | 61.08 | | | $ | 73.57 | |
3Q24 | | 184,000 | | | | | | | $ | 63.50 | | | $ | 75.53 | |
4Q24 | | 184,000 | | | | | | | $ | 63.00 | | | $ | 75.35 | |
2025 Contracts | | | | | | | | | | |
1Q25 | | 238,500 | | | | | | | $ | 64.00 | | | $ | 74.62 | |
2Q25 | | 227,500 | | | | | | | $ | 60.80 | | | $ | 72.22 | |
2026 Contracts | | | | | | | | | | |
1Q26 | | 90,000 | | | | | | | $ | 64.00 | | | $ | 71.50 | |
2Q26 | | 91,000 | | | | | | | $ | 64.00 | | | $ | 71.50 | |
3Q26 | | 92,000 | | | | | | | $ | 64.00 | | | $ | 71.50 | |
3-Way Collar Contracts | | | | | | | | | | |
2023 Contracts | | | | | | | | | | |
4Q23 | | 8,970 | | | | | $ | 43.08 | | | $ | 53.38 | | | $ | 63.35 | |
2024 Contracts | | | | | | | | | | |
1Q24 | | 8,247 | | | | | $ | 45.00 | | | $ | 57.50 | | | $ | 67.85 | |
2Q24 | | 7,757 | | | | | $ | 45.00 | | | $ | 57.50 | | | $ | 67.85 | |
| | | | | | | | | | | | | | |
Oil Basis Swaps (Argus Cushing (WTI) and Magellan East Houston) | | Total Volumes (MMBtu) | | Weighted-Average Price |
2023 Contracts | | | | |
4Q23 | | 122,000 | | | $ | 0.80 | |
2024 Contracts | | | | |
1Q24 | | 364,000 | | | $ | 1.47 | |
2Q24 | | 364,000 | | | $ | 1.47 | |
3Q24 | | 368,000 | | | $ | 1.47 | |
4Q24 | | 368,000 | | | $ | 1.47 | |
2025 Contracts | | | | |
1Q25 | | 270,000 | | | $ | 1.75 | |
2Q25 | | 273,000 | | | $ | 1.75 | |
3Q25 | | 276,000 | | | $ | 1.75 | |
4Q25 | | 276,000 | | | $ | 1.75 | |
Calendar Monthly Roll Differential Swaps | | | | |
2023 Contracts | | | | |
4Q23 | | 122,000 | | | $ | 2.44 | |
2024 Contracts | | | | |
1Q24 | | 364,000 | | | $ | 0.69 | |
2Q24 | | 364,000 | | | $ | 0.69 | |
3Q24 | | 368,000 | | | $ | 0.69 | |
4Q24 | | 368,000 | | | $ | 0.69 | |
2025 Contracts | | | | |
1Q25 | | 270,000 | | | $ | 0.40 | |
2Q25 | | 273,000 | | | $ | 0.40 | |
3Q25 | | 276,000 | | | $ | 0.40 | |
4Q25 | | 276,000 | | | $ | 0.40 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Natural Gas Derivative Contracts (NYMEX Henry Hub Settlements) | | Total Volumes (MMBtu) | | Weighted-Average Price | | Weighted-Average Collar Sub Floor Price | | Weighted-Average Collar Floor Price | | Weighted-Average Collar Call Price |
Swap Contracts | | | | | | | | | | |
2023 Contracts | | | | | | | | | | |
4Q23 | | 5,727,000 | | | $ | 4.20 | | | | | | | |
2024 Contracts | | | | | | | | | | |
1Q24 | | 7,686,000 | | | $ | 4.12 | | | | | | | |
2Q24 | | 12,350,000 | | | $ | 3.67 | | | | | | | |
3Q24 | | 12,420,000 | | | $ | 3.78 | | | | | | | |
4Q24 | | 12,420,000 | | | $ | 4.12 | | | | | | | |
2025 Contracts | | | | | | | | | | |
1Q25 | | 9,450,000 | | | $ | 4.25 | | | | | | | |
2Q25 | | 9,555,000 | | | $ | 3.71 | | | | | | | |
3Q25 | | 11,960,000 | | | $ | 3.83 | | | | | | | |
4Q25 | | 8,740,000 | | | $ | 4.17 | | | | | | | |
2026 Contracts | | | | | | | | | | |
1Q26 | | 9,680,000 | | | $ | 4.48 | | | | | | | |
2Q26 | | 9,555,000 | | | $ | 3.56 | | | | | | | |
3Q26 | | 9,660,000 | | | $ | 3.74 | | | | | | | |
4Q26 | | 9,200,000 | | | $ | 4.13 | | | | | | | |
Collar Contracts | | | | | | | | | | |
2023 Contracts | | | | | | | | | | |
4Q23 | | 12,445,000 | | | | | | | $ | 3.87 | | | $ | 4.80 | |
2024 Contracts | | | | | | | | | | |
1Q24 | | 9,661,000 | | | | | | | $ | 3.94 | | | $ | 5.83 | |
2Q24 | | 4,643,000 | | | | | | | $ | 3.64 | | | $ | 4.28 | |
3Q24 | | 3,878,000 | | | | | | | $ | 3.77 | | | $ | 4.76 | |
4Q24 | | 3,865,000 | | | | | | | $ | 4.01 | | | $ | 5.34 | |
2025 Contracts | | | | | | | | | | |
1Q25 | | 5,130,000 | | | | | | | $ | 4.00 | | | $ | 5.32 | |
2Q25 | | 4,914,000 | | | | | | | $ | 3.25 | | | $ | 3.98 | |
3Q25 | | 920,000 | | | | | | | $ | 3.50 | | | $ | 3.99 | |
4Q25 | | 920,000 | | | | | | | $ | 3.75 | | | $ | 4.65 | |
3-Way Collar Contracts | | | | | | | | | | |
2023 Contracts | | | | | | | | | | |
4Q23 | | 219,200 | | | | | $ | 2.00 | | | $ | 2.50 | | | $ | 2.94 | |
2024 Contracts | | | | | | | | | | |
1Q24 | | 198,000 | | | | | $ | 2.00 | | | $ | 2.50 | | | $ | 3.37 | |
2Q24 | | 188,000 | | | | | $ | 2.00 | | | $ | 2.50 | | | $ | 3.37 | |
| | | | | | | | | | | | | | |
Natural Gas Basis Derivative Swaps (East Texas Houston Ship Channel vs. NYMEX Settlements) | | Total Volumes (MMBtu) | | Weighted-Average Price |
2023 Contracts | | | | |
4Q23 | | 13,800,000 | | | $ | (0.23) | |
2024 Contracts | | | | |
1Q24 | | 15,470,000 | | | $ | (0.02) | |
2Q24 | | 15,470,000 | | | $ | (0.29) | |
3Q24 | | 15,640,000 | | | $ | (0.26) | |
4Q24 | | 15,640,000 | | | $ | (0.28) | |
2025 Contracts | | | | |
1Q25 | | 5,400,000 | | | $ | (0.09) | |
2Q25 | | 5,460,000 | | | $ | (0.26) | |
3Q25 | | 5,520,000 | | | $ | (0.23) | |
4Q25 | | 5,520,000 | | | $ | (0.25) | |
| | | | | | | | | | | | | | |
NGL Swaps (Mont Belvieu) | | Total Volumes (Bbls) | | Weighted-Average Price |
2023 Contracts | | | | |
4Q23 | | 345,000 | | | $ | 32.87 | |
2024 Contracts | | | | |
1Q24 | | 400,400 | | | $ | 26.30 | |
2Q24 | | 400,400 | | | $ | 26.30 | |
3Q24 | | 404,800 | | | $ | 26.30 | |
4Q24 | | 404,800 | | | $ | 26.30 | |
2025 Contracts | | | | |
1Q25 | | 270,000 | | | $ | 24.17 | |
2Q25 | | 273,000 | | | $ | 24.17 | |
3Q25 | | 276,000 | | | $ | 24.17 | |
4Q25 | | 276,000 | | | $ | 24.17 | |
(9) Fair Value Measurements
Fair Value on a Recurring Basis. Our financial instruments consist of cash and cash equivalents, accounts receivable, accounts payable, derivatives, the Credit Facility and the Second Lien notes. The carrying amounts of cash and cash equivalents, accounts receivable, and accounts payable approximate fair value due to the highly liquid or short-term nature of these instruments.
The fair values of our derivative contracts are computed using observable market data whereas our derivative collar contracts are valued using a Black-Scholes pricing model. The fair value of the current and long-term 2021 WTI Contingency Payout and 2022 WTI Contingency Payout, included within “Accounts payable and accrued liabilities” and “Other long-term liabilities” on the condensed consolidated balance sheets, respectively, is estimated using observable market data and a Monte Carlo pricing model. These are considered Level 2 valuations (defined below).
The carrying value of our Credit Facility and Second Lien approximates fair value because the respective borrowing rates do not materially differ from market rates for similar borrowings. These are considered Level 3 valuations (defined below).
Fair Value on a Nonrecurring Basis. The Company applies the provisions of the fair value measurement standard on a non-recurring basis to its non-financial assets and liabilities, including oil and gas properties acquired and assessed for classification as a business or an asset and asset retirement obligations. These assets and liabilities are not measured at fair value on an ongoing basis but are subject to fair value estimation when acquisitions occur or asset retirement obligations are recorded. These are considered Level 3 valuations (defined below).
Asset retirement obligations. The initial measurement of asset retirement obligations (“ARO”) at fair value is recorded in the period in which the liability is incurred. Fair value is determined by calculating the present value of estimated future cash flows related to the liability. Estimating the future ARO requires management to make estimates and judgments regarding the timing and existence of a liability, as well as what constitutes adequate restoration when considering current regulatory requirements. Inherent in the fair value calculation are numerous assumptions and judgments, including the ultimate costs, inflation factors, credit-adjusted discount rates, timing of settlement and changes in the legal, regulatory, environmental and political environments.
Acquisitions. The Company recognized the assets acquired in our acquisitions at cost at a relative fair value basis (refer to Note 7 of these Notes to Consolidated Financial Statements). Fair value was determined using a discounted cash flow model. The underlying future commodity prices included in the Company’s estimated future cash flows of its proved oil and gas properties were determined using NYMEX forward strip prices as of the closing date of each acquisition. The estimated future cash flows also included management’s assumptions for the estimates of production from the crude oil and natural gas proved properties, future operating, development costs and income taxes of the acquired properties and risk adjusted discount rates.
The fair value hierarchy has three levels based on the reliability of the inputs used to determine the fair value:
Level 1 – Uses quoted prices in active markets for identical, unrestricted assets or liabilities. Instruments in this category have comparable fair values for identical instruments in active markets.
Level 2 – Uses quoted prices for similar assets or liabilities in active markets or observable inputs for assets or liabilities in non-active markets. Instruments in this category are periodically verified against quotes from brokers and include our commodity derivatives that we value using commonly accepted industry-standard models which contain inputs such as contract prices, risk-free rates, volatility measurements and other observable market data that are obtained from independent third-party sources.
Level 3 – Uses unobservable inputs for assets or liabilities that are in non-active markets.
The following table presents our assets and liabilities that are measured on a recurring basis at fair value as of each of September 30, 2023 and December 31, 2022, and are categorized using the fair value hierarchy. For additional discussion related to the fair value of the Company's derivatives, refer to Note 8 of these Notes to Condensed Consolidated Financial Statements.
| | | | | | | | | | | | | | | | | | | | | | | |
| Fair Value Measurements at |
(in thousands) | Total | | Quoted Prices in Active markets for Identical Assets (Level 1) | | Significant Other Observable Inputs (Level 2) | | Significant Unobservable Inputs (Level 3) |
September 30, 2023 | | | | | | | |
Assets | | | | | | | |
Natural Gas Derivatives | $ | 53,032 | | | $ | — | | | $ | 53,032 | | | $ | — | |
Natural Gas Basis Derivatives | 5,395 | | | — | | | 5,395 | | | — | |
Oil Derivatives | 418 | | | — | | | 418 | | | — | |
Oil Basis Derivatives | 254 | | | — | | | 254 | | | — | |
NGL Derivatives | 5,270 | | | — | | | 5,270 | | | — | |
Liabilities | | | | | | | |
Natural Gas Derivatives | 5,346 | | | — | | | 5,346 | | | — | |
Natural Gas Basis Derivatives | 5,415 | | | — | | | 5,415 | | | — | |
Oil Derivatives | 41,908 | | | — | | | 41,908 | | | — | |
Oil Basis Derivatives | 858 | | | — | | | 858 | | | — | |
NGL Derivatives | 785 | | | — | | | 785 | | | — | |
2021 WTI Contingency Payout | 2,459 | | | — | | | 2,459 | | | — | |
| | | | | | | |
December 31, 2022 | | | | | | | |
Assets | | | | | | | |
Natural Gas Derivatives | $ | 25,960 | | | $ | — | | | $ | 25,960 | | | $ | — | |
Natural Gas Basis Derivatives | 26,023 | | | — | | | 26,023 | | | — | |
Oil Derivatives | 14,604 | | | — | | | 14,604 | | | — | |
NGL Derivatives | 10,134 | | | — | | | 10,134 | | | — | |
Liabilities | | | | | | | |
Natural Gas Derivatives | 28,579 | | | — | | | 28,579 | | | — | |
Natural Gas Basis Derivatives | 409 | | | — | | | 409 | | | — | |
Oil Derivatives | 19,442 | | | — | | | 19,442 | | | — | |
NGL Derivatives | 104 | | | — | | | 104 | | | — | |
2022 WTI Contingency Payout | 2,135 | | | — | | | 2,135 | | | — | |
2021 WTI Contingency Payout | 1,453 | | | — | | | 1,453 | | | — | |
Our current and long-term unsettled derivative assets and liabilities in the table above are measured at gross fair value and are shown on the accompanying condensed consolidated balance sheets in “Fair value of commodity derivatives” and “Fair Value of Long-Term Commodity Derivatives,” respectively.
(10) Asset Retirement Obligations
Liabilities for legal obligations associated with the retirement obligations of tangible long-lived assets are initially recorded at fair value in the period in which they are incurred. Estimates for the initial recognition of asset retirement obligations are derived from historical costs as well as management's expectation of future cost environments and other unobservable inputs. As there is no corroborating market activity to support the assumptions used, the Company has designated these liabilities as Level 3 fair value measurements. When a liability is initially recorded, the carrying amount of the related asset is increased. The liability is discounted from the expected date of abandonment. Over time, accretion of the liability is recognized each period, and the capitalized cost is amortized on a unit-of-production basis as part of depreciation, depletion, and amortization expense for our oil and gas properties. Upon settlement of the liability, the Company either settles the
obligation for its recorded amount or incurs a gain or loss upon settlement which is included in the “Property and Equipment” balance on our accompanying condensed consolidated balance sheets.
The following provides a roll-forward of our asset retirement obligations for the year ended December 31, 2022 and the nine months ended September 30, 2023 (in thousands):
| | | | | |
Asset Retirement Obligations as of December 31, 2021 | $ | 6,050 | |
Accretion expense | 534 | |
Liabilities incurred for new wells, acquired wells and facilities construction | 3,032 | |
Reductions due to sold wells and facilities | (57) | |
Reductions due to plugged wells and facilities | (22) | |
Revisions in estimates | 919 | |
Asset Retirement Obligations as of December 31, 2022 | $ | 10,456 | |
Accretion expense | 718 | |
Liabilities incurred for new wells, acquired wells and facilities construction | 313 | |
| |
Reductions due to plugged wells and facilities | (603) | |
Revisions in estimates | 534 | |
Asset Retirement Obligations as of September 30, 2023 | $ | 11,418 | |
At September 30, 2023 and December 31, 2022, approximately $1.6 million and $1.3 million of our asset retirement obligations, respectively, were classified as a current liability in “Accounts payable and accrued liabilities” on the accompanying condensed consolidated balance sheets.
(11) Commitments and Contingencies
In the ordinary course of business, we are party to various legal actions, which arise primarily from our activities as an operator of oil and natural gas wells. In our management's opinion, the outcome of any such currently pending legal actions will not have a material adverse effect on our financial position or results of operations. During the second quarter of 2023, the Company entered into gas throughput agreements with separate parties in our Webb County gas area. The agreements provide for an annual average firm capacity of approximately 116,000 MMBtu/d over an eight-year term.
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations
You should read the following discussion and analysis in conjunction with the Company's financial information and its condensed consolidated financial statements and accompanying notes included in this report and its audited consolidated financial statements and accompanying notes included in its Annual Report on Form 10-K for the year ended December 31, 2022. The following information contains forward-looking statements; see “Forward-Looking Statements” in this report.
Company Overview
SilverBow is an independent oil and gas company headquartered in Houston, Texas. The Company's strategy is focused on acquiring and developing assets in the Eagle Ford and Austin Chalk located in South Texas where it has assembled approximately 180,000 net acres across five operating areas. SilverBow's acreage position in each of its operating areas is highly contiguous and designed for optimal and efficient horizontal well development. The Company has built a balanced portfolio of properties with a significant base of current production and reserves coupled with low-risk development drilling opportunities and meaningful upside from newer operating areas.
Being a committed and long-term operator in South Texas, SilverBow possesses a significant understanding of the reservoir characteristics, geology, landowners and competitive landscape in the region. The Company leverages this in-depth knowledge to continue to assemble high quality drilling inventory while continuously enhancing its operations to maximize returns on capital invested.
Operational Results and Strategy
Total production for the nine months ended September 30, 2023 increased 30% from the nine months ended September 30, 2022 to 330 million cubic feet of natural gas equivalent per day.
During the third quarter of 2023, SilverBow drilled 10 net wells, completed 9 net wells and brought online 9 net wells. The Company operated an average of two drilling rigs during the quarter, primarily on its Central Oil and Eastern Extension areas, which reflect its oil-focused development program year-to-date. SilverBow's team continues to increase operational efficiencies, completing 10% more stages per day year-to-date in 2023 as compared to similar jobs for full year 2022, and averaging pumping efficiencies 20% higher over the same time periods. Third quarter pumping efficiencies were the highest quarterly rate achieved year-to-date in 2023 due to decreases in downtime, leading to the increase in completed stages per day. Drilling costs continue to benefit from greater efficiencies from high-grading of rigs and ongoing cost deflation, particularly across casing costs and rig rates, resulting in drilling costs per lateral foot approximately 13% lower year-to-date in 2023 as compared to full year 2022.
In its Central Oil area, the Company recently brought online a four-well pad which produced a 30-day pad average of 4,349 Boe/d (82% oil) with average lateral lengths of 7,500 feet. Also in its Central Oil area, SilverBow brought online a two-well pad which produced a 30-day pad average of 2,140 Boe/d (82% oil) with average lateral lengths of 9,140 feet. Strong initial performance from these pads are in-line with expectations and support the Company's oil focused growth plans. Furthermore, SilverBow continues to test optimal spacing and co-development potential of the Eagle Ford and Austin Chalk formations across its oil assets.
For the remainder of 2023, the Company anticipates running one rig on its oil assets and one rig on its gas assets. SilverBow is re-iterating its full year 2023 capital budget guidance range of $400-$425 million. Given operational and cost efficiencies realized year-to-date, the Company may elect to complete several wells at the end of the year while remaining within its stated guidance range, which would be expected to contribute to higher production volumes into 2024. The Company aims to optimize its drilling schedule based on commodity prices, returns on investment and strategically proving up additional inventory within its portfolio.
Liquidity and Capital Resources
SilverBow's primary use of cash has been to fund capital expenditures to develop its oil and gas properties, fund acquisitions and to repay Credit Facility borrowings. The Company uses cash generated from operating activities and borrowings under its Credit Facility as its primary sources of liquidity.
During the third quarter, SilverBow executed a purchase and sale agreement for the acquisition of certain oil and gas assets in South Texas from Chesapeake Energy Corporation (the “Chesapeake South Texas Rich Properties”) for a purchase price of $700 million, comprised of a $650 million cash payment at the closing date and a $50 million deferred cash payment due 12 months post-close, subject to customary purchase price adjustments (the “Chesapeake Transaction”) pursuant to the purchase and sale agreement, dated as of August 11, 2023, between SilverBow, SilverBow Resources Operating, LLC and the Chesapeake Sellers (the “Purchase Agreement”). Chesapeake may also receive up to $50 million in contingent cash consideration based on future commodity prices. SilverBow paid a $50 million cash deposit into escrow in conjunction with the Purchase Agreement recorded in “Deposit and other fees for oil and gas property transaction” on the accompanying condensed consolidated balance sheet.
The Chesapeake Transaction is expected to be funded with cash on hand, borrowings under the Company’s First Amended and Restated Senior Secured Revolving Credit Agreement, dated as of April 19, 2017, and amended as of June 22, 2022 (the “Credit Facility”), among the Company, the lenders party thereto and JPMorgan Chase Bank, N.A., as administrative agent for the lenders, and the Company’s amended second lien notes (“Second Lien Notes”) led by EIG. In conjunction with the Chesapeake Transaction, the Company has secured $425 million of incremental commitments under its Credit Facility from existing and new lenders, which, subject to the closing of the Chesapeake Transaction, will increase lender commitments under the Credit Facility to $1.2 billion, and the Second Lien Notes will be upsized by $350 million, which, subject to the closing of the Chesapeake Transaction, will increase lender commitments under the Second Lien Notes to $500 million and extend the maturity date for the Second Lien Notes to December 15, 2028.
The Purchase Agreement contains certain termination rights, including, but not limited to, each party’s right to terminate the Purchase Agreement in the event a material breach by the other party has occurred and is not waived on or before September 25, 2023, which date has passed, and in any event if the Chesapeake Transaction has not been consummated on or before November 24, 2023; provided that such date may be automatically extended for an additional 15 days to December 9, 2023, in the event certain approvals and consents have not been obtained by such date. The Chesapeake Transaction has an effective date of February 1, 2023, and is expected to close by year-end 2023, subject to satisfaction or waiver of certain customary closing conditions, including the accuracy of the representations and warranties of each party, compliance by each party in all material respects with its covenants and the satisfaction of certain consent requirements.
On September 13, 2023, SilverBow priced a $148 million follow-on equity offering and used net proceeds to repay amounts outstanding on its Credit Facility. Strategic Value Partners, LLC participated in the follow-on as a selling shareholder. The base deal consisted of 4,000,000 shares of which approximately 70% were primary. As such, on September 18, 2023, the Company issued 2,810,811 shares of its common stock, for aggregate net proceeds, after expenses, of approximately $97 million, which was used to repay a portion of the amounts then outstanding under the Credit Facility. Borrowings under our Credit Facility decreased $44 million from December 31, 2022. As of September 30, 2023, the Company’s liquidity consisted of $1.7 million of cash-on-hand and $277 million in available borrowings on its Credit Facility, which had a $775 million borrowing base.
Management believes the Company has sufficient liquidity to meet all near-term obligations and execute its long-term development plans, including funding the Chesapeake Transaction. In the future, we may seek to access the debt and equity capital markets from time to time to raise additional capital, increase liquidity, fund acquisitions or refinance debt. For more information on its Credit Facility, see the Credit Facility section within Note 6 of our condensed consolidated financial statements included in Item 1 of this report.
Contractual Commitments and Obligations
Other than as discussed below, there were no other material changes in SilverBow's contractual commitments during the nine months ended September 30, 2023 from amounts referenced under “Contractual Commitments and Obligations” in Management's Discussion and Analysis of Financial Condition and Results of Operations in our Annual Report on Form 10-K for the year ended December 31, 2022. During the second quarter of 2023, the Company entered into gas throughput agreements with separate parties in our Webb County gas area. The agreements provide for an annual average firm capacity of approximately 116,000 MMBtu/d over an eight-year term.
Summary of 2023 Financial Results Through September 30, 2023
•Revenues and Net Income (Loss): The Company's oil and gas revenues were $440.3 million for the nine months ended September 30, 2023, compared to $554.4 million for the nine months ended September 30, 2022. Revenues were lower due to overall lower commodity pricing partially offset by increased production volumes. The Company's net income was $114.7 million for the nine months ended September 30, 2023, compared to net income of $167.1 million for the nine months ended September 30, 2022. The decrease in net income was primarily driven by lower commodity pricing.
•Capital Expenditures: The Company's capital expenditures on an accrual basis were $329.9 million for the nine months ended September 30, 2023 compared to $224.8 million for the nine months ended September 30, 2022. The expenditures for the nine months ended September 30, 2023 and 2022 were primarily attributable to drilling and completion activity.
•Working Capital: The Company had a working capital deficit of $58.9 million at September 30, 2023 and a working capital deficit of $50.1 million at December 31, 2022. Included in our working capital was a net asset of $17.4 million and $11.8 million at September 30, 2023 and December 31, 2022, respectively, related to the fair value of our current open derivative contracts. The working capital computation does not include available liquidity through our Credit Facility.
•Cash Flows: For the nine months ended September 30, 2023, the Company generated cash from operating activities of $318.4 million, of which $4.4 million was attributable to changes in working capital. Additionally, the Company collected cash settlements of $70.7 million on derivatives during the nine months ended September 30, 2023. Cash flows from operating activities also excluded $13.4 million attributable to a net increase of capital-related payables and accrued costs. Cash used for property additions was $316.0 million while acquisition costs related to our 2022 acquisitions totaled $0.4 million. The Company's deposit and other fees related to our oil and gas property transaction totaled $51.2 million during the nine months ended September 30, 2023. The Company’s net repayments on the Credit Facility were $44.0 million during the nine months ended September 30, 2023. The Company's aggregate net proceeds, after offering expenses, from issuance of common stock in a public underwritten offering was approximately $97.1 million during the nine months ended September 30, 2023.
For the nine months ended September 30, 2022, the Company generated cash from operating activities of $212.2 million which included negative impacts attributable to changes in working capital of $25.4 million. Cash used for property additions was $163.6 million while purchase price adjustments related to our 2021 acquisitions totaled $293.9 million. This excluded $60.6 million attributable to a net increase of capital-related payables and accrued costs. The Company’s net borrowings on the Credit Facility were $253.0 million during the nine months ended September 30, 2022 which were primarily used to fund acquisitions during the nine months ended September 30, 2022.
Results of Operations
Revenues — Three Months Ended September 30, 2023 and Three Months Ended September 30, 2022
Natural gas production was 61% and 70% of the Company's production volumes for the three months ended September 30, 2023 and 2022, respectively. Natural gas sales were 26% and 62% of oil and gas sales for the three months ended September 30, 2023 and 2022, respectively.
Crude oil production was 26% and 17% of the Company's production volumes for the three months ended September 30, 2023 and 2022, respectively. Crude oil sales were 65% and 30% of oil and gas sales for the three months ended September 30, 2023 and 2022, respectively.
NGL production was 13% of the Company's production volumes for both the three months ended September 30, 2023 and 2022. NGL sales were 9% and 8% of oil and gas sales for the three months ended September 30, 2023 and 2022.
The following table provides additional information regarding the Company's oil and gas sales, by area, excluding any effects of the Company's hedging activities, for the three months ended September 30, 2023 and 2022:
| | | | | | | | | | | | | | | | | | | | |
Fields | | Three Months Ended September 30, 2023 | | Three Months Ended September 30, 2022 |
| | Oil and Gas Sales (In Millions) | Net Oil and Gas Production Volumes (MMcfe) | | Oil and Gas Sales (In Millions) | Net Oil and Gas Production Volumes (MMcfe) |
Webb County Gas | | $ | 33.1 | | 14,445 | | | $ | 106.1 | | 13,514 | |
Western Condensate | | 26.9 | | 5,261 | | | 39.7 | | 4,623 | |
Southern Eagle Ford | | 7.3 | | 2,474 | | | 29.3 | | 3,913 | |
Central Oil | | 92.4 | | 8,968 | | | 59.6 | | 4,727 | |
Eastern Extension | | 13.6 | | 1,637 | | | 7.3 | | 682 | |
Non Core | | 0.7 | | 62 | | | 0.2 | | 46 | |
Total | | $ | 174.0 | | 32,847 | | | $ | 242.2 | | 27,505 | |
The sales volumes increase from 2022 to 2023 was primarily due to acquisitions in 2022, in addition to wells brought online as part of our full year 2022 and 2023 drilling programs.
In the third quarter of 2023, our $68.2 million, or 28%, decrease in oil, NGL and natural gas sales from the prior year period resulted from:
•Price variances that had an approximately $136.3 million unfavorable impact on sales due to overall lower commodity pricing; and
•Volume variances that had an approximately $68.1 million favorable impact on sales due to overall increased commodity production.
The following table provides additional information regarding our oil and gas sales, by commodity type, as well as the effects of our hedging activities for derivative contracts held to settlement, for the three months ended September 30, 2023 and 2022 (in thousands, except per-dollar amounts):
| | | | | | | | | | | |
| | Three Months Ended September 30, 2023 | Three Months Ended September 30, 2022 |
Production volumes: | | | |
Oil (MBbl) (1) | | 1,410 | | 781 | |
Natural gas (MMcf) | | 20,010 | | 19,324 | |
Natural gas liquids (MBbl) (1) | | 729 | | 582 | |
Total (MMcfe) | | 32,847 | | 27,505 | |
| | | |
Oil, natural gas and natural gas liquids sales: | | | |
Oil | | $ | 112,456 | | $ | 71,811 | |
Natural gas | | 46,075 | | 150,958 | |
Natural gas liquids | | 15,432 | | 19,412 | |
Total | | $ | 173,963 | | $ | 242,181 | |
| | | |
Average realized price before impact of cash-settled derivatives: | | | |
Oil (per Bbl) | | $ | 79.76 | | $ | 91.93 | |
Natural gas (per Mcf) | | 2.30 | | 7.81 | |
Natural gas liquids (per Bbl) | | 21.16 | | 33.34 | |
Average per Mcfe | | $ | 5.30 | | $ | 8.81 | |
| | | |
Price impact of cash-settled derivatives: | | | |
Oil (per Bbl) | | $ | (3.45) | | $ | (20.44) | |
Natural gas (per Mcf) | | 1.00 | | (3.47) | |
Natural gas liquids (per Bbl) | | 3.68 | | (1.86) | |
Average per Mcfe | | $ | 0.54 | | $ | (3.06) | |
| | | |
Average realized price including impact of cash-settled derivatives: | | | |
Oil (per Bbl) | | $ | 76.30 | | $ | 71.49 | |
Natural gas (per Mcf) | | 3.30 | | 4.34 | |
Natural gas liquids (per Bbl) | | 24.84 | | 31.48 | |
Average per Mcfe | | $ | 5.84 | | $ | 5.75 | |
(1) Oil and natural gas liquids are converted at the rate of one barrel to six Mcfe. Mcf refers to one thousand cubic feet, and MMcf refers to one million cubic feet. Bbl refers to one barrel of oil, and MBbl refers to one thousand barrels.
For the three months ended September 30, 2023 and 2022, the Company recorded net losses of $53.7 million and $1.3 million from our commodities derivatives activities, respectively. For the three months ended September 30, 2023 and 2022, we also recorded a net loss of $0.9 million and net gain $6.1 million, respectively, related to valuation changes from our 2021 and 2022 WTI Contingency Payouts. Hedging activity is recorded in “Gain (loss) on commodity derivatives, net” on the accompanying condensed consolidated statements of operations.
Costs and Expenses — Three Months Ended September 30, 2023 and Three Months Ended September 30, 2022
The following table provides additional information regarding our expenses for the three months ended September 30, 2023 and 2022 (in thousands):
| | | | | | | | |
Costs and Expenses | Three Months Ended September 30, 2023 | Three Months Ended September 30, 2022 |
General and administrative, net | $ | 4,438 | | $ | 4,343 | |
Depreciation, depletion, and amortization | 53,186 | | 41,501 | |
Accretion of asset retirement obligations | 254 | | 166 | |
Lease operating expenses | 22,678 | | 17,701 | |
Workovers | 672 | | 284 | |
Transportation and gas processing | 13,710 | | 9,662 | |
Severance and other taxes | 10,407 | | 12,581 | |
Interest expense, net | 19,811 | | 12,173 | |
Provision (benefit) for income taxes | (949) | | 6,066 | |
General and Administrative Expenses, Net. These expenses on a per-Mcfe basis were $0.14 and $0.16 for the three months ended September 30, 2023 and 2022, respectively. The decrease in per-Mcfe rate was due to an overall increase in production. Included in general and administrative expenses is $1.5 million and $1.2 million in share-based compensation for the three months ended September 30, 2023 and 2022, respectively.
Depreciation, Depletion and Amortization. These expenses on a per-Mcfe basis were $1.62 and $1.51 for the three months ended September 30, 2023 and 2022, respectively. The increase in our per-Mcfe depreciation, depletion and amortization rate was primarily related to the acquisitions in 2022 and inflation on future development costs. The increase in costs is related to the increase in the per-Mcfe rate, coupled with an overall increase in production.
Lease Operating Expenses and Workovers. These expenses on a per-Mcfe basis were $0.71 and $0.65 for the three months ended September 30, 2023 and 2022, respectively. The increase in costs was primarily due to higher labor, compression, salt water disposal and maintenance costs driven by our acquisitions in 2022.
Transportation and Gas Processing. These expenses are related to oil, natural gas and NGL sales. These expenses on a per-Mcfe basis were $0.42 and $0.35 for the three months ended September 30, 2023 and 2022, respectively. The increase in costs and in our per Mcfe rate was primarily attributable to additional transportation and processing agreements associated with our acquisitions in 2022 along with increased contractual fees across portions of our properties.
Severance and Other Taxes. These expenses on a per-Mcfe basis were $0.32 and $0.46 for the three months ended September 30, 2023 and 2022, respectively. Severance and other taxes, as a percentage of oil and gas sales, were approximately 6.0% and 5.2% for the three months ended September 30, 2023 and 2022, respectively.
Interest. Our interest cost was $19.8 million and $12.2 million for the three months ended September 30, 2023 and 2022, respectively. The increase in interest is primarily due to higher borrowings and higher interest rates. There were no capitalized interest costs for the three months ended September 30, 2023 and 2022.
Income Taxes. The Company recorded an income tax benefit of $0.9 million and an income tax provision of $6.1 million for the three months ended September 30, 2023 and 2022, respectively. The effective tax rate for the three months ended September 30, 2023 primarily related to the statutory federal tax rate plus the impact of the Texas Margin Tax. The tax impact for both periods was a product of the overall forecasted annual effective tax rate applied to the year to date income or loss.
Results of Operations
Revenues — Nine Months Ended September 30, 2023 and Nine Months Ended September 30, 2022
Natural gas production was 63% and 75% of the Company's production volumes for the nine months ended September 30, 2023 and 2022, respectively. Natural gas sales were 30% and 63% of oil and gas sales for the nine months ended September 30, 2023 and 2022, respectively.
Crude oil production was 24% and 14% of the Company's production volumes for the nine months ended September 30, 2023 and 2022, respectively. Crude oil sales were 61% and 28% of oil and gas sales for the nine months ended September 30, 2023 and 2022, respectively.
NGL production was 13% and 11% of the Company's production volumes for the nine months ended September 30, 2023 and 2022, respectively. NGL sales were 9% of oil and gas sales for both the nine months ended September 30, 2023 and 2022.
The following table provides additional information regarding the Company's oil and gas sales, by area, excluding any effects of the Company's hedging activities, for the nine months ended September 30, 2023 and 2022:
| | | | | | | | | | | | | | | | | | | | |
Fields | | Nine Months Ended September 30, 2023 | | Nine Months Ended September 30, 2022 |
| | Oil and Gas Sales (In Millions) | Net Oil and Gas Production Volumes (MMcfe) | | Oil and Gas Sales (In Millions) | Net Oil and Gas Production Volumes (MMcfe) |
Webb County Gas | | $ | 96.7 | | 41,425 | | | $ | 253.5 | | 37,386 | |
Western Condensate | | 82.5 | | 16,831 | | | 116.2 | | 13,096 | |
Southern Eagle Ford | | 17.6 | | 6,357 | | | 64.1 | | 9,236 | |
Central Oil | | 206.7 | | 20,826 | | | 94.6 | | 7,251 | |
Eastern Extension | | 35.4 | | 4,588 | | | 24.5 | | 2,242 | |
Non Core | | 1.4 | | 169 | | | 1.5 | | 256 | |
Total | | $ | 440.3 | | 90,196 | | | $ | 554.4 | | 69,467 | |
The sales volumes increase from 2022 to 2023 was primarily due to acquisitions in the second half of 2022, in addition to wells brought online as part of our full year 2022 and 2023 drilling programs.
In the first nine months of 2023, our $114.1 million, or 21%, decrease in oil, NGL and natural gas sales from the prior year period resulted from:
•Price variances that had an approximately $361.0 million unfavorable impact on sales due to overall lower commodity pricing; and
•Volume variances that had an approximately $246.9 million favorable impact on sales due to overall increased commodity production.
The following table provides additional information regarding our oil and gas sales, by commodity type, as well as the effects of our hedging activities for derivative contracts held to settlement, for the nine months ended September 30, 2023 and 2022 (in thousands, except per-dollar amounts):
| | | | | | | | | | | |
| | Nine Months Ended September 30, 2023 | Nine Months Ended September 30, 2022 |
Production volumes: | | | |
Oil (MBbl) (1) | | 3,569 | | 1,611 | |
Natural gas (MMcf) | | 57,109 | | 51,829 | |
Natural gas liquids (MBbl) (1) | | 1,945 | | 1,329 | |
Total (MMcfe) | | 90,196 | | 69,467 | |
| | | |
Oil, natural gas and natural gas liquids sales: | | | |
Oil | | $ | 267,263 | | $ | 155,566 | |
Natural gas | | 132,802 | | 351,626 | |
Natural gas liquids | | 40,252 | | 47,250 | |
Total | | $ | 440,317 | | $ | 554,442 | |
| | | |
Average realized price before impact of cash-settled derivatives: | | | |
Oil (per Bbl) | | $ | 74.88 | | $ | 96.58 | |
Natural gas (per Mcf) | | 2.33 | | 6.78 | |
Natural gas liquids (per Bbl) | | 20.69 | | 35.56 | |
Average per Mcfe | | $ | 4.88 | | $ | 7.98 | |
| | | |
Price impact of cash-settled derivatives: | | | |
Oil (per Bbl) | | $ | (0.59) | | $ | (28.60) | |
Natural gas (per Mcf) | | 1.07 | | (2.45) | |
Natural gas liquids (per Bbl) | | 4.28 | | (4.33) | |
Average per Mcfe | | $ | 0.75 | | $ | (2.57) | |
| | | |
Average realized price including impact of cash-settled derivatives: | | | |
Oil (per Bbl) | | $ | 74.29 | | $ | 67.98 | |
Natural gas (per Mcf) | | 3.40 | | 4.33 | |
Natural gas liquids (per Bbl) | | 24.97 | | 31.23 | |
Average per Mcfe | | $ | 5.63 | | $ | 5.41 | |
(1) Oil and natural gas liquids are converted at the rate of one barrel to six Mcfe. Mcf refers to one thousand cubic feet, and MMcf refers to one million cubic feet. Bbl refers to one barrel of oil, and MBbl refers to one thousand barrels.
For the nine months ended September 30, 2023 and 2022, the Company recorded net gains of $56.5 million and net losses of $162.5 million from our commodities derivatives activities, respectively. For the nine months ended September 30, 2023 and 2022, we also recorded a net gain of $1.1 million and net gain of $4.7 million, respectively, related to valuation changes from our 2021 and 2022 WTI Contingency Payouts. Additionally, we settled the final post-close adjustment related to the Sundance acquisition during the second quarter of 2023. As part of the settlement, SilverBow is no longer required to make any contingency payments related to the 2022 WTI Contingency Payout. As such, we recorded a non-cash gain of $1.1 million during the nine months ended September 30, 2023. Hedging activity is recorded in “Gain (loss) on commodity derivatives, net” on the accompanying condensed consolidated statements of operations.
Costs and Expenses — Nine Months Ended September 30, 2023 and Nine Months Ended September 30, 2022
The following table provides additional information regarding our expenses for the nine months ended September 30, 2023 and 2022 (in thousands):
| | | | | | | | |
Costs and Expenses | Nine Months Ended September 30, 2023 | Nine Months Ended September 30, 2022 |
General and administrative, net | $ | 17,421 | | $ | 14,840 | |
Depreciation, depletion, and amortization | 147,037 | | 89,096 | |
Accretion of asset retirement obligations | 718 | | 366 | |
Lease operating expenses | 62,417 | | 37,095 | |
Workovers | 2,263 | | 933 | |
Transportation and gas processing | 37,001 | | 22,784 | |
Severance and other taxes | 28,563 | | 30,183 | |
Interest expense, net | 54,746 | | 26,632 | |
Provision (benefit) for income taxes | 33,214 | | 7,678 | |
General and Administrative Expenses, Net. These expenses on a per-Mcfe basis were $0.19 and $0.21 for the nine months ended September 30, 2023 and 2022, respectively. The increase in costs was primarily due to higher legal and professional fees while the decrease in per-Mcfe rate was due to an overall increase in production. Included in general and administrative expenses is $4.0 million and $3.9 million in share-based compensation for the nine months ended September 30, 2023 and 2022, respectively.
Depreciation, Depletion and Amortization. These expenses on a per-Mcfe basis were $1.63 and $1.28 for the nine months ended September 30, 2023 and 2022, respectively. The increase in our per-Mcfe depreciation, depletion and amortization rate was primarily related to the acquisitions in 2022 and inflation on future development costs. The increase in costs is related to the increase in the per-Mcfe rate, coupled with an overall increase in production.
Lease Operating Expenses and Workovers. These expenses on a per-Mcfe basis were $0.72 and $0.55 for the nine months ended September 30, 2023 and 2022, respectively. The increase in costs was primarily due to higher labor, compression, salt water disposal, maintenance and chemical costs driven by our acquisitions in 2022.
Transportation and Gas Processing. These expenses are related to oil, natural gas and NGL sales. These expenses on a per-Mcfe basis were $0.41 and $0.33 for the nine months ended September 30, 2023 and 2022, respectively. The increase in costs and in our per Mcfe rate was primarily attributable to additional transportation and processing agreements associated with our acquisitions in 2022 along with increased contractual fees across portions of our properties.
Severance and Other Taxes. These expenses on a per-Mcfe basis were $0.32 and $0.43 for the nine months ended September 30, 2023 and 2022, respectively. Severance and other taxes, as a percentage of oil and gas sales, were approximately 6.5% and 5.4% for the nine months ended September 30, 2023 and 2022, respectively.
Interest. Our interest cost was $54.7 million and $26.6 million for the nine months ended September 30, 2023 and 2022, respectively. The increase in interest is primarily due to higher borrowings and higher interest rates. There were no capitalized interest costs for the nine months ended September 30, 2023 and 2022.
Income Taxes. The Company recorded an income tax provision of $33.2 million and an income tax provision of $7.7 million for the nine months ended September 30, 2023 and 2022, respectively. The effective tax rate for the nine months ended September 30, 2023 primarily related to the statutory federal tax rate plus the impact of the Texas Margin Tax The tax impact for both periods was a product of the overall forecasted annual effective tax rate applied to the year to date income.
Critical Accounting Policies and New Accounting Pronouncements
There have been no changes in the critical accounting policies disclosed in our 2022 Annual Report on Form 10-K.
Item 3. Quantitative and Qualitative Disclosures About Market Risk
Commodity Risk. Our major market risk exposure is the commodity pricing applicable to our oil and natural gas production. Realized commodity prices received for such production are primarily driven by the prevailing worldwide price for crude oil and spot prices applicable to natural gas. This commodity pricing volatility has continued with unpredictable price swings in recent periods.
Our price risk management policy permits the utilization of agreements and financial instruments (such as futures, forward contracts, swaps and options contracts) to mitigate price risk associated with fluctuations in oil and natural gas prices. We do not utilize these agreements and financial instruments for trading and only enter into derivative agreements with banks in our Credit Facility. For additional discussion related to our price risk management policy, refer to Note 8 of our condensed consolidated financial statements included in Item 1 of this report.
Customer Credit Risk. We are exposed to the risk of financial non-performance by customers. Our ability to collect on sales to our customers is dependent on the liquidity of our customer base. Continued volatility in both credit and commodity markets may reduce the liquidity of our customer base. To manage customer credit risk, we monitor credit ratings of customers and, when considered necessary, we also obtain letters of credit from certain customers, parent company guarantees, if applicable, and other collateral as considered necessary to reduce risk of loss. Due to availability of other purchasers, we do not believe the loss of any single oil or natural gas customer would have a material adverse effect on our results of operations.
Concentration of Sales Risk. A large portion of our oil and gas sales are made to Kinder Morgan, Inc. and its affiliates and we expect to continue this relationship in the future. We believe that the business risk of this relationship is mitigated by the reputation and nature of their business and the availability of other purchasers.
Interest Rate Risk. At September 30, 2023, we had a combined $648.0 million drawn under our Credit Facility and our Second Lien, which bear floating rates of interest and therefore are susceptible to interest rate fluctuations. These variable interest rate borrowings are also impacted by changes in short-term interest rates. A hypothetical one percentage point increase in interest rates on our borrowings outstanding under our Credit Facility and Second Lien at September 30, 2023 would increase our annual interest expense by $6.5 million.
Item 4. Controls and Procedures
Disclosure Controls and Procedures
We maintain disclosure controls and procedures, as defined in Rules 13a-15(e) and 15d-15(e) of the Exchange Act, consisting of controls and other procedures designed to give reasonable assurance that information we are required to disclose in the reports we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission’s rules and forms and that such information is accumulated and communicated to management, including our Chief Executive Officer and our Chief Financial Officer, to allow timely decisions regarding such required disclosure. Our Chief Executive Officer and Chief Financial Officer have evaluated such disclosure controls and procedures as of the end of the period covered by this quarterly report on Form 10-Q and have determined that such disclosure controls and procedures are effective.
Changes in Internal Control Over Financial Reporting
There was no change in our internal control over financial reporting during the three months ended September 30, 2023 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.
PART II. OTHER INFORMATION
Item 1. Legal Proceedings.
No material legal proceedings are pending other than ordinary, routine litigation incidental to the Company’s business.
Item 1A. Risk Factors.
A description of our risk factors can be found in “Part I, Item 1A. Risk Factors” included in our Annual Report on Form 10-K for the fiscal year ended December 31, 2022. Other than as described below, there have been no material changes in our risk factors disclosed in the 2022 Annual Report on Form 10-K.
Risks Related to the Chesapeake Transaction
We may not consummate the Chesapeake Transaction.
The completion of the Chesapeake Transaction is subject to a number of closing conditions, some of which are out of our control, including the material performance by the other party of all of the obligations, agreements and covenants of the transaction agreement to be performed at or prior to the closing of the Chesapeake Transaction, including the receipt of any necessary consents or approvals. Additionally, although we have committed financing through our Credit Facility and Second Lien Notes for the purchase price, the completion of the Chesapeake Transaction is subject to our ability to secure this financing.
We also cannot be certain when SilverBow and the Chesapeake Sellers will be able to satisfy the other closing conditions or whether those closing conditions will be satisfied, including consent from certain significant landowners. If any of these conditions are not satisfied, including the failure to obtain certain consents, and in any event if the Chesapeake Transaction has not been consummated on or before November 24, 2023; provided that such date may be automatically extended for an additional 15 days to December 9, 2023, in the event certain approvals and consents have not been obtained by such date, it is possible that the Purchase Agreement may be terminated. Although the parties have agreed in the Purchase Agreement to use commercially reasonable efforts, subject to certain limitations, in regards to certain closing conditions, these and other conditions to the completion of the Chesapeake Transaction may fail to be satisfied.
If the Chesapeake Transaction is delayed, not consummated or consummated on terms different from those currently contemplated, the market price of our common stock may decline. Further, a failed transaction may result in negative publicity or a negative impression of us in the investment community and may affect our relationships with our business partners. Failure to complete the Chesapeake Transaction could cause us to be in breach of the Purchase Agreement, could result in litigation and other losses to us and a decline in the market price of our common stock.
We may not be able to achieve the expected benefits of the Chesapeake Transaction and may have difficulty integrating the Chesapeake Transaction.
Even if we consummate the Chesapeake Transaction, we may not be able to achieve the expected benefits of the Chesapeake Transaction. There can be no assurance that the Chesapeake Transaction will be beneficial to us. We may not be able to integrate and develop the Chesapeake South Texas Rich Properties without increases in costs, losses in revenues or other difficulties. Any unexpected costs or delays, including inability to reconcile post-acquisition adjustments, incurred in connection with the integration and development of the Chesapeake South Texas Rich Properties could have an adverse effect on our business, results of operations, financial condition and prospects, as well as the market price of our common stock.
Our assessment of the Chesapeake South Texas Rich Properties to date has been limited; and, even by the time of closing, it will not reveal all existing or potential problems, nor will it permit us to become familiar enough with the properties to assess fully their capabilities and deficiencies. In the course of our assessment, we will not receive an independent reserve engineer report related to the Chesapeake South Texas Rich Properties. We may incur costs or experience problems related to the Chesapeake South Texas Rich Properties in the Chesapeake Transaction, and we may not have adequate recourse against the Chesapeake Sellers. Although we have and will inspect the properties being sold to us, inspections may not reveal all title, structural or environmental problems. We may be required to assume the risk of the physical condition of the properties in addition to the risk that the properties may not perform in accordance with our expectations. Our ability to make specified claims against the Chesapeake Sellers in the Chesapeake Transaction generally expires over time and we may be left with no recourse for liabilities and other problems associated with the Chesapeake Transaction that we do not discover prior to the expiration date related to such matters under the Purchase Agreement.
The market price of our common stock may decline as a result of the Chesapeake Transaction if, among other things, the integration and development of the Chesapeake South Texas Rich Properties is unsuccessful or if the liabilities, expenses, title, environmental and other defects, or transaction costs related to the Chesapeake Transaction are greater than expected or the Chesapeake South Texas Rich Properties do not yield the anticipated returns. The market price of our common stock may decline if we do not achieve the perceived benefits of the Chesapeake Transaction as rapidly or to the extent anticipated by us or by securities market participants or if the effect of the Chesapeake Transaction, including the obligations incurred to finance the Chesapeake Transaction, on our business results of operations or financial condition or prospects is not consistent with our expectations or those of securities market participants.
Upon consummation of the Chesapeake Transaction, our overall level of debt obligations will increase, which could adversely affect us.
Upon consummation of the Chesapeake Transaction, our overall long-term debt will increase, and our level of debt obligations after completion of the Chesapeake Transaction could have adverse consequences on our business and future prospects, including the following:
•we may not be able to obtain financing in the future on acceptable terms or at all for working capital, capital expenditures, acquisitions, debt service requirements or other purposes;
•less-levered competitors could have a competitive advantage because they have lower debt service requirements;
•credit rating agencies could downgrade our credit ratings following the Chesapeake Transaction below currently expected levels; and
•we may be less able to take advantage of significant business opportunities and to react to changes in market or industry conditions than our competitors.
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds.
None.
Item 3. Defaults Upon Senior Securities.
None.
Item 4. Mine Safety Disclosures.
Not applicable.
Item 5. Other Information.
(c) Trading Plans
During the quarter ended September 30, 2023, no director or Section 16 officer adopted or terminated any Rule 10b5-1 trading arrangements or non-Rule 10b5-1 trading arrangements (in each case, as defined in Item 408 of Regulation S-K).
Item 6. Exhibits.
The following exhibits in this index are required by Item 601 of Regulation S-K and are filed herewith or are incorporated herein by reference:
| | | | | |
3.1 | |
3.2 | |
3.3 | |
3.4 | |
10.1 | Purchase and Sale Agreement, dated August 11, 2023, between SilverBow Resources Operating, LLC and Chesapeake Exploration, L.L.C., Chesapeake Operating, L.L.C., Chesapeake Energy Marketing, L.L.C. and Chesapeake Royalty, L.L.C. (incorporated by reference as Exhibit 10.1 to SilverBow Resources, Inc.’s Current Report on Form 8-K filed August 14, 2023, File No. 001-08754). |
31.1* | |
31.2* | |
32.1# | |
101* | The following materials from SilverBow Resources, Inc.'s Quarterly Report on Form 10-Q for the quarter ended September 30, 2023 formatted in iXBRL (Inline eXtensible Business Reporting Language): (i) the Condensed Consolidated Balance Sheets (Unaudited), (ii) the Condensed Consolidated Statements of Operations (Unaudited), (iii) the Consolidated Statements of Stockholders Equity (Unaudited), (iv) the Condensed Consolidated Statements of Cash Flows (Unaudited), and (v) Notes to the Condensed Consolidated Financial Statements. |
104 | Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101). |
*Filed herewith
# Furnished herewith. Not considered to be “filed” for the purposes of Section 18 of the Securities Exchange Act of 1934 or otherwise subject to the liabilities of that section.
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.
| | | | | | | | | | | | | | |
| | | SILVERBOW RESOURCES, INC. (Registrant) |
Date: | November 2, 2023 | | By: | /s/ Christopher M. Abundis |
| | | | Christopher M. Abundis Executive Vice President, Chief Financial Officer and General Counsel |
| | | | |
Date: | November 2, 2023 | | By: | /s/ W. Eric Schultz |
| | | | W. Eric Schultz Vice President of Accounting and Controller |
Exhibit 31.1
CERTIFICATION OF CHIEF EXECUTIVE OFFICER
PURSUANT TO RULE 13A-14(A)
OF THE SECURITIES EXCHANGE ACT OF 1934, AS AMENDED
I, Sean C. Woolverton, certify that:
1.I have reviewed this Quarterly Report on Form 10-Q for the period ended September 30, 2023, of SilverBow Resources, Inc. (the “registrant”);
2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15(d)-15(f)) for the registrant and have:
(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting, to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
(c) Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
(d) Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and
5. The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):
(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and
(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.
| | | | | | | | | | | |
Date: | November 2, 2023 | | /s/ Sean C. Woolverton |
| | | Sean C. Woolverton Chief Executive Officer |
Exhibit 31.2
CERTIFICATION OF CHIEF FINANCIAL OFFICER
PURSUANT TO RULE 13A-14(A)
OF THE SECURITIES EXCHANGE ACT OF 1934, AS AMENDED
I, Christopher M. Abundis, certify that:
1.I have reviewed this Quarterly Report on Form 10-Q for the period ended September 30, 2023, of SilverBow Resources, Inc. (the “registrant”);
2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15(d)-15(f)) for the registrant and have:
(a)Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
(b)Designed such internal control over financial reporting, or caused such internal control over financial reporting, to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
(c)Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
(d)Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and
5.The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):
(a)All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and
(b)Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.
| | | | | | | | | | | |
Date: | November 2, 2023 | | /s/ Christopher M. Abundis |
| | | Christopher M. Abundis Executive Vice President, Chief Financial Officer and General Counsel |
Exhibit 32.1
Certification of the Chief Executive Officer and Chief Financial Officer
Pursuant to 18 U.S.C. Section 1350
In connection with the Quarterly Report on Form 10-Q for the period ended September 30, 2023 of SilverBow Resources, Inc. (the “Company”) as filed with the Securities and Exchange Commission on the date hereof (the “Report”), Sean C. Woolverton, the Chief Executive Officer of the Company, and Christopher M. Abundis, the Executive Vice President, Chief Financial Officer and General Counsel of the Company, each certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that to his knowledge:
1.The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and
2.The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.
| | | | | | | | | | | |
Date: | November 2, 2023 | | /s/ Sean C. Woolverton |
| | | Sean C. Woolverton Chief Executive Officer |
| | | |
Date: | November 2, 2023 | | /s/ Christopher M. Abundis |
| | | Christopher M. Abundis Executive Vice President, Chief Financial Officer and General Counsel |
v3.23.3
Document and Entity Information - shares
|
9 Months Ended |
|
Sep. 30, 2023 |
Oct. 27, 2023 |
Document and Entity Information [Abstract] |
|
|
Document Type |
10-Q
|
|
Document Period End Date |
Sep. 30, 2023
|
|
Entity File Number |
1-8754
|
|
Entity Registrant Name |
SILVERBOW RESOURCES, INC.
|
|
Entity Incorporation, State or Country Code |
DE
|
|
Entity Tax Identification Number |
20-3940661
|
|
Entity Address, Address Line One |
920 Memorial City Way
|
|
Entity Address, Address Line Two |
Suite 850
|
|
Entity Address, City or Town |
Houston
|
|
Entity Address, State or Province |
TX
|
|
Entity Address, Postal Zip Code |
77024
|
|
City Area Code |
281
|
|
Local Phone Number |
874-2700
|
|
Title of 12(b) Security |
Common Stock, par value $0.01 per share
|
|
Trading Symbol |
SBOW
|
|
Security Exchange Name |
NYSE
|
|
Entity Filer Category |
Accelerated Filer
|
|
Document Quarterly Report |
true
|
|
Document Transition Report |
false
|
|
Entity Emerging Growth Company |
false
|
|
Entity Small Business |
false
|
|
Entity Shell Company |
false
|
|
Entity Current Reporting Status |
Yes
|
|
Entity Interactive Data Current |
Yes
|
|
Entity Central Index Key |
0000351817
|
|
Current Fiscal Year End Date |
--12-31
|
|
Amendment Flag |
false
|
|
Document Fiscal Year Focus |
2023
|
|
Document Fiscal Period Focus |
Q3
|
|
Entity Common Stock, Shares Outstanding |
|
25,429,610
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v3.23.3
Condensed Consolidated Balance Sheets - USD ($) $ in Thousands |
Sep. 30, 2023 |
Dec. 31, 2022 |
Current Assets: |
|
|
Cash and cash equivalents |
$ 1,697
|
$ 792
|
Accounts receivable, net |
80,202
|
89,714
|
Fair value of commodity derivatives |
50,189
|
52,549
|
Other current assets |
3,825
|
2,671
|
Total Current Assets |
135,913
|
145,726
|
Property and Equipment: |
|
|
Property and Equipment, full cost method |
2,861,267
|
2,529,223
|
Less - Accumulated depreciation, depletion, and amortization |
(1,151,141)
|
(1,004,044)
|
Net Furniture, Fixtures and other equipment |
1,710,126
|
1,525,179
|
Capitalized Costs, unproved property balance |
27,821
|
16,272
|
Right of Use Assets |
10,085
|
12,077
|
Fair value of long-term commodity derivatives |
14,180
|
24,172
|
Deposit and other fees for oil and gas property transaction |
52,564
|
0
|
Other Long-Term Assets |
7,581
|
9,208
|
Total Assets |
1,930,449
|
1,716,362
|
Current Liabilities: |
|
|
Accounts payable and accrued liabilities |
74,731
|
60,200
|
Fair value of commodity derivatives |
32,752
|
40,796
|
Accrued capital costs |
56,424
|
56,465
|
Accrued interest |
2,976
|
2,665
|
Current lease liability |
5,507
|
8,553
|
Undistributed oil and gas revenues |
22,462
|
27,160
|
Total Current Liabilities |
194,852
|
195,839
|
Long-Term Debt |
645,096
|
688,531
|
Non-current Lease Liability |
4,604
|
3,775
|
Deferred Tax Liabilities |
49,033
|
16,141
|
Asset Retirement Obligation |
9,840
|
9,171
|
Fair value of long-term commodity derivatives |
21,560
|
7,738
|
Other Long-Term Liabilities |
922
|
3,588
|
Stockholders' Equity: |
|
|
Preferred Stock, Value, Outstanding |
0
|
0
|
Common stock, $0.01 par value |
259
|
227
|
Additional paid-in capital |
677,473
|
576,118
|
Treasury stock held, at cost |
(10,616)
|
(7,534)
|
Retained earnings (Accumulated deficit) |
337,426
|
222,768
|
Total Stockholders' Equity (Deficit) |
1,004,542
|
791,579
|
Total Liabilities and Stockholders' Equity |
$ 1,930,449
|
$ 1,716,362
|
Preferred Stock, Par or Stated Value Per Share |
$ 0.01
|
$ 0.01
|
Preferred Stock, Shares Authorized |
10,000,000
|
10,000,000
|
Preferred Stock, Shares Outstanding |
0
|
0
|
Common Stock, Par or Stated Value Per Share |
$ 0.01
|
$ 0.01
|
Common Stock, Shares Authorized |
40,000,000
|
40,000,000
|
Common Stock, Shares, Issued |
25,914,823
|
22,663,135
|
Common Stock, Shares, Outstanding |
25,429,517
|
22,309,740
|
Treasury Stock, Shares |
485,306
|
353,395
|
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v3.23.3
Condensed Consolidated Balance Sheets (Parenthetical) - $ / shares
|
Sep. 30, 2023 |
Dec. 31, 2022 |
Statement of Financial Position [Abstract] |
|
|
Preferred stock, par value (in dollars per share) |
$ 0.01
|
$ 0.01
|
Preferred stock, shares authorized |
10,000,000
|
10,000,000
|
Preferred Stock, Shares Outstanding |
0
|
0
|
Common Stock, Par or Stated Value Per Share |
$ 0.01
|
$ 0.01
|
Common Stock, Shares Authorized |
40,000,000
|
40,000,000
|
X |
- DefinitionFace amount or stated value per share of common stock.
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v3.23.3
Condensed Consolidated Statements of Operations (Unaudited) - USD ($) shares in Thousands, $ in Thousands |
3 Months Ended |
9 Months Ended |
Sep. 30, 2023 |
Sep. 30, 2022 |
Sep. 30, 2023 |
Sep. 30, 2022 |
Income Statement [Abstract] |
|
|
|
|
Oil and gas sales |
$ 173,963
|
$ 242,181
|
$ 440,317
|
$ 554,442
|
Costs and Expenses [Abstract] |
|
|
|
|
General and administrative, net |
4,438
|
4,343
|
17,421
|
14,840
|
Depreciation, depletion, and amortization |
53,186
|
41,501
|
147,037
|
89,096
|
Accretion of asset retirement obligation |
254
|
166
|
718
|
366
|
Lease operating costs |
22,678
|
17,701
|
62,417
|
37,095
|
Workovers |
672
|
284
|
2,263
|
933
|
Transportation and gas processing |
13,710
|
9,662
|
37,001
|
22,784
|
Severance and other taxes |
10,407
|
12,581
|
28,563
|
30,183
|
Operating Expenses |
105,345
|
86,238
|
295,420
|
195,297
|
Operating Income (Loss) |
68,618
|
155,943
|
144,897
|
359,145
|
Net gain (loss) on commodity derivatives |
(54,639)
|
4,832
|
57,604
|
(157,816)
|
Interest expense, net |
(19,811)
|
(12,173)
|
(54,746)
|
(26,632)
|
Other Nonoperating Income (Expense) |
112
|
5
|
117
|
57
|
Income (Loss) from Continuing Operations before Income Taxes, Noncontrolling Interest |
(5,720)
|
148,607
|
147,872
|
174,754
|
Provision (Benefit) for Income Taxes |
(949)
|
6,066
|
33,214
|
7,678
|
Net Income (Loss) |
$ (4,771)
|
$ 142,541
|
$ 114,658
|
$ 167,076
|
Per Share Amounts- |
|
|
|
|
Earnings Per Share, Basic |
$ (0.21)
|
$ 6.39
|
$ 5.06
|
$ 8.85
|
Earnings Per Share, Diluted |
$ (0.21)
|
$ 6.29
|
$ 5.02
|
$ 8.69
|
Weighted Average Shares Outstanding - Basic |
22,985
|
22,308
|
22,677
|
18,885
|
Weighted Average Shares Outstanding - Diluted |
22,985
|
22,669
|
22,852
|
19,237
|
X |
- DefinitionAmount of accretion expense recognized during the period that is associated with an asset retirement obligation. Accretion expense measures and incorporates changes due to the passage of time into the carrying amount of the liability.
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v3.23.3
Condensed Consolidated Statements of Stockholders' Equity - USD ($) $ in Thousands |
Total |
Common Stock |
Additional Paid-in Capital |
Treasury Stock |
Retained Earnings (Accumulated Deficit) |
Beginning Balance at Dec. 31, 2021 |
$ 292,532
|
$ 168
|
$ 413,017
|
$ (2,984)
|
$ (117,669)
|
Purchase of treasury shares |
(2,462)
|
0
|
0
|
(2,462)
|
0
|
Treasury Stock, Value, Acquired Pursuant to Purchase Price Adjustment |
(1,146)
|
0
|
0
|
(1,146)
|
0
|
Vesting of share-based compensation |
0
|
3
|
(3)
|
0
|
0
|
Issuance pursuant to acquisition |
12
|
0
|
12
|
0
|
0
|
Amortization of share-based compensation |
1,101
|
0
|
1,101
|
0
|
0
|
Net Income (Loss) |
(64,255)
|
0
|
0
|
0
|
(64,255)
|
Ending Balance at Mar. 31, 2022 |
$ 225,782
|
171
|
414,127
|
(6,592)
|
(181,924)
|
Purchase of treasury stock (shares) |
96,012
|
|
|
|
|
Vesting of share-based compensation (shares) |
318,390
|
|
|
|
|
Treasury Shares Pursuant to Purchase Price Adjustment (shares) |
41,191
|
|
|
|
|
Issuance pursuant to acquisition (shares) |
489
|
|
|
|
|
Beginning Balance at Dec. 31, 2021 |
$ 292,532
|
168
|
413,017
|
(2,984)
|
(117,669)
|
Net Income (Loss) |
167,076
|
|
|
|
|
Ending Balance at Sep. 30, 2022 |
$ 616,985
|
227
|
574,885
|
(7,534)
|
49,407
|
Purchase of treasury stock (shares) |
120,350
|
|
|
|
|
Treasury Shares Pursuant to Purchase Price Adjustment (shares) |
41,375
|
|
|
|
|
Beginning Balance at Mar. 31, 2022 |
$ 225,782
|
171
|
414,127
|
(6,592)
|
(181,924)
|
Purchase of treasury shares |
(503)
|
0
|
0
|
(503)
|
0
|
Stock options exercised |
(39)
|
0
|
(39)
|
0
|
0
|
Vesting of share-based compensation |
0
|
1
|
(1)
|
0
|
0
|
Issuance pursuant to acquisition |
157,393
|
55
|
157,338
|
0
|
0
|
Amortization of share-based compensation |
1,756
|
0
|
1,756
|
0
|
0
|
Net Income (Loss) |
88,790
|
0
|
0
|
0
|
88,790
|
Ending Balance at Jun. 30, 2022 |
$ 473,257
|
227
|
573,259
|
(7,095)
|
(93,134)
|
Purchase of treasury stock (shares) |
16,485
|
|
|
|
|
Options, Exercises in Period |
4,497
|
|
|
|
|
Vesting of share-based compensation (shares) |
57,355
|
|
|
|
|
Issuance pursuant to acquisition (shares) |
5,448,472
|
|
|
|
|
Purchase of treasury shares |
$ (432)
|
0
|
0
|
(432)
|
0
|
Stock options exercised |
(387)
|
0
|
(387)
|
0
|
0
|
Treasury Stock, Value, Acquired Pursuant to Purchase Price Adjustment |
(7)
|
0
|
0
|
(7)
|
0
|
Amortization of share-based compensation |
1,239
|
0
|
1,239
|
0
|
0
|
Net Income (Loss) |
142,541
|
0
|
0
|
0
|
142,541
|
Ending Balance at Sep. 30, 2022 |
$ 616,985
|
227
|
574,885
|
(7,534)
|
49,407
|
Purchase of treasury stock (shares) |
7,853
|
|
|
|
|
Options, Exercises in Period |
11,087
|
|
|
|
|
Treasury Shares Pursuant to Purchase Price Adjustment (shares) |
184
|
|
|
|
|
Beginning Balance at Dec. 31, 2022 |
$ 791,579
|
227
|
576,118
|
(7,534)
|
222,768
|
Purchase of treasury shares |
(2,945)
|
0
|
0
|
(2,945)
|
0
|
Vesting of share-based compensation |
0
|
4
|
(4)
|
0
|
0
|
Amortization of share-based compensation |
1,179
|
0
|
1,179
|
0
|
0
|
Net Income (Loss) |
94,492
|
0
|
0
|
0
|
94,492
|
Ending Balance at Mar. 31, 2023 |
$ 884,305
|
231
|
577,293
|
(10,479)
|
317,260
|
Purchase of treasury stock (shares) |
126,240
|
|
|
|
|
Vesting of share-based compensation (shares) |
418,518
|
|
|
|
|
Beginning Balance at Dec. 31, 2022 |
$ 791,579
|
227
|
576,118
|
(7,534)
|
222,768
|
Net Income (Loss) |
114,658
|
|
|
|
|
Ending Balance at Sep. 30, 2023 |
$ 1,004,542
|
259
|
677,473
|
(10,616)
|
337,426
|
Purchase of treasury stock (shares) |
131,911
|
|
|
|
|
Beginning Balance at Mar. 31, 2023 |
$ 884,305
|
231
|
577,293
|
(10,479)
|
317,260
|
Purchase of treasury shares |
(121)
|
0
|
0
|
(121)
|
0
|
Vesting of share-based compensation |
0
|
0
|
0
|
0
|
0
|
Amortization of share-based compensation |
1,524
|
0
|
1,524
|
0
|
0
|
Net Income (Loss) |
24,937
|
0
|
0
|
0
|
24,937
|
Ending Balance at Jun. 30, 2023 |
$ 910,645
|
231
|
578,817
|
(10,600)
|
342,197
|
Purchase of treasury stock (shares) |
5,310
|
|
|
|
|
Vesting of share-based compensation (shares) |
21,134
|
|
|
|
|
Purchase of treasury shares |
$ (16)
|
0
|
0
|
(16)
|
0
|
Vesting of share-based compensation |
0
|
0
|
0
|
0
|
0
|
Amortization of share-based compensation |
1,551
|
0
|
1,551
|
0
|
0
|
Net Income (Loss) |
(4,771)
|
0
|
0
|
0
|
(4,771)
|
Ending Balance at Sep. 30, 2023 |
$ 1,004,542
|
259
|
677,473
|
(10,616)
|
337,426
|
Purchase of treasury stock (shares) |
361
|
|
|
|
|
Vesting of share-based compensation (shares) |
1,225
|
|
|
|
|
Issuance of common stock (shares) |
2,810,811
|
|
|
|
|
Issuance of common stock |
$ 97,133
|
$ 28
|
$ 97,105
|
$ 0
|
$ 0
|
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v3.23.3
Condensed Consolidated Statements of Cash Flows (Unaudited) - USD ($) $ in Thousands |
3 Months Ended |
9 Months Ended |
12 Months Ended |
|
Sep. 30, 2023 |
Sep. 30, 2022 |
Sep. 30, 2023 |
Sep. 30, 2022 |
Dec. 31, 2022 |
Dec. 31, 2021 |
Cash Flows from Operating Activities: |
|
|
|
|
|
|
Net Income (Loss) |
$ (4,771)
|
$ 142,541
|
$ 114,658
|
$ 167,076
|
|
|
Adjustments to reconcile net income to net cash provided by operating activities - |
|
|
|
|
|
|
Depreciation, depletion, and amortization |
53,186
|
41,501
|
147,037
|
89,096
|
|
|
Accretion of asset retirement obligation |
254
|
166
|
718
|
366
|
$ 534
|
|
Deferred income taxes |
|
|
32,892
|
7,496
|
|
|
Stock-based compensation expenses |
|
|
4,043
|
3,901
|
|
|
Loss (gain) on derivatives |
|
|
(57,604)
|
157,816
|
|
|
Cash Received (Paid) On Settlements of Derivative Contracts |
|
|
70,670
|
(182,058)
|
|
|
Settlements of asset retirement obligations |
|
|
(481)
|
(47)
|
|
|
Write off of Debt Issuance Cost |
|
|
0
|
350
|
|
|
Other Noncash Income (Expense) |
|
|
2,028
|
(6,425)
|
|
|
(Increase) decrease in accounts receivable and other current assets |
|
|
9,129
|
(47,320)
|
|
|
Increase (decrease) in accounts payable and accrued liabilities |
|
|
(5,320)
|
20,260
|
|
|
Increase (Decrease) in Income Taxes Payable |
|
|
(321)
|
21
|
|
|
Increase (decrease) in accrued interest |
|
|
311
|
1,688
|
|
|
Net Cash Provided by (Used in) Operating Activities |
|
|
318,402
|
212,178
|
|
|
Cash Flows from Investing Activities: |
|
|
|
|
|
|
Additions to property and equipment |
|
|
(316,003)
|
(163,567)
|
|
|
Acquisition of oil and gas properties |
|
|
(382)
|
(293,880)
|
|
|
Other Payments to Acquire Businesses |
|
|
(51,163)
|
0
|
|
|
Proceeds from the sale of property and equipment |
|
|
0
|
4,415
|
4,400
|
|
Payments on property sale obligations |
|
|
0
|
(750)
|
|
|
Net Cash Provided by (Used in) Investing Activities |
|
|
(367,548)
|
(453,782)
|
|
|
Cash Flows from Financing Activities: |
|
|
|
|
|
|
Proceeds from bank borrowings |
|
|
334,000
|
679,000
|
|
|
Payments of bank borrowings |
|
|
(378,000)
|
(426,000)
|
|
|
Proceeds from Issuance of Common Stock |
|
|
97,133
|
0
|
|
|
Net proceeds from stock options exercised |
|
|
0
|
39
|
|
|
Purchase of treasury shares |
|
|
(3,082)
|
(3,404)
|
|
|
Payments of Debt Issuance Costs |
|
|
0
|
(7,228)
|
|
|
Net Cash Provided by (Used in) Financing Activities |
|
|
50,051
|
242,407
|
|
|
Net increase (decrease) in Cash, Cash Equivalents and Restricted Cash |
|
|
905
|
803
|
|
|
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents |
$ 1,697
|
$ 1,924
|
1,697
|
1,924
|
$ 792
|
$ 1,121
|
Supplemental Disclosures of Cash Flows Information: |
|
|
|
|
|
|
Cash paid during period for interest, net of amounts capitalized |
|
|
52,170
|
22,701
|
|
|
Changes in capital accounts payable and capital accruals |
|
|
13,363
|
60,595
|
|
|
Accrued other fees for oil and gas property transaction |
|
|
(1,401)
|
0
|
|
|
Non-cash equity consideration for acquisitions |
|
|
$ 0
|
$ (156,259)
|
|
|
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v3.23.3
General Information
|
9 Months Ended |
Sep. 30, 2023 |
Organization, Consolidation and Presentation of Financial Statements [Abstract] |
|
General Information |
(1) General Information
SilverBow Resources, Inc. (“SilverBow,” the “Company,” or “we”) is an independent oil and gas company headquartered in Houston, Texas. The Company's strategy is focused on acquiring and developing assets in the Eagle Ford and Austin Chalk located in South Texas.
Being a committed and long-term operator in South Texas, SilverBow possesses a significant understanding of the reservoir characteristics, geology, landowners and competitive landscape in the region. The Company leverages this in-depth knowledge to continue to assemble high quality drilling inventory while continuously enhancing its operations to maximize returns on capital invested.
The condensed consolidated financial statements included herein are unaudited and certain information and note disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States (“GAAP”) have been omitted pursuant to the rules and regulations of the Securities and Exchange Commission. We believe that the disclosures presented are adequate to allow the information presented not to be misleading. The condensed consolidated financial statements should be read in conjunction with the audited financial statements and the notes thereto included in our Annual Report on Form 10-K for the fiscal year ended December 31, 2022.
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v3.23.3
Summary of Significant Accounting Policies
|
9 Months Ended |
Sep. 30, 2023 |
Accounting Policies [Abstract] |
|
Summary of Significant Accounting Policies |
(2) Summary of Significant Accounting Policies
Basis of Presentation. The condensed consolidated financial statements included herein reflect necessary adjustments, all of which were of a recurring nature unless otherwise disclosed herein, and are in the opinion of our management necessary for a fair presentation.
Principles of Consolidation. The accompanying condensed consolidated financial statements include the accounts of SilverBow and its wholly owned subsidiary, SilverBow Resources Operating LLC, which are engaged in the exploration, development, acquisition, and operation of oil and gas properties, with a focus on oil and natural gas reserves in the Eagle Ford and Austin Chalk trend in Texas. Our undivided interests in oil and gas properties are accounted for using the proportionate consolidation method, whereby our proportionate share of the assets, liabilities, revenues, and expenses are included in the appropriate classifications in the accompanying condensed consolidated financial statements. Intercompany balances and transactions have been eliminated in preparing the accompanying condensed consolidated financial statements.
Stockholder Rights Agreement. On September 20, 2022, the Board adopted a stockholder rights agreement (the “Rights Agreement”) and declared a dividend distribution of one right (each, a “Right” and together with all such rights distributed or issued pursuant to the Rights Agreement, dated as of September 20, 2022, by and between the Company and American Stock Transfer & Trust Company, LLC, as rights agent, the “Rights”) for each outstanding share of Company common stock to holders of record on October 5, 2022. In the event that a person or group acquires beneficial ownership of 15% or more of the Company’s then-outstanding common stock, subject to certain exceptions, each Right would entitle its holder (other than such person or members of such group) to purchase additional shares of Company common stock at a substantial discount to the public market price. In addition, at any time after a person or group acquires beneficial ownership of 15% or more of the outstanding common stock, subject to certain exceptions, the Board may direct the Company to exchange the Rights (other than Rights owned by such person or certain related parties, which will have become null and void), in whole or in part, at an exchange ratio of one share of common stock per Right (subject to adjustment). While in effect, the Rights Agreement could make it more difficult for a third party to acquire control of the Company or a large block of the common stock of the Company without the approval of the Board. On May 16, 2023, the Company and the rights agent entered into an Amendment to the Rights Agreement (the “Amendment”) that amended the Rights Agreement to extend the expiration date until the close of business on the first day following the date of the Company’s first annual meeting of its stockholders that occurs after (but not on) the date of the Amendment. The Rights Agreement, as amended, will expire on the earliest of (a) 5:00 p.m., New York City time, on the first business day after the 2024 annual stockholders’ meeting, (b) the time at which the Rights are redeemed and (c) the time at which the Rights are exchanged in full. Subsequent Events. We have evaluated subsequent events requiring potential accrual or disclosure in our condensed consolidated financial statements.
Through October 31, 2023, the Company entered into additional derivative contracts. The following tables summarize the weighted-average prices as well as future production volumes for our future derivative contracts entered into after September 30, 2023: | | | | | | | | | | | | | | | Oil Derivative Contracts (NYMEX WTI Settlements) | | Total Volumes (Bbls) | | Weighted-Average Price | Swap Contracts | | | | | 2024 Contracts | | | | | 1Q24 | | 91,000 | | | $ | 83.40 | | 2Q24 | | 91,000 | | | $ | 81.31 | | 3Q24 | | 92,000 | | | $ | 79.63 | | 4Q24 | | 92,000 | | | $ | 78.21 | | 2025 Contracts | | | | | 1Q25 | | 90,000 | | | $ | 76.52 | | 2Q25 | | 91,000 | | | $ | 75.38 | | 3Q25 | | 92,000 | | | $ | 74.56 | | 4Q25 | | 92,000 | | | $ | 73.58 | | 2026 Contracts | | | | | 1Q26 | | 157,500 | | | $ | 68.01 | | 2Q26 | | 136,500 | | | $ | 67.98 | | 3Q26 | | 110,400 | | | $ | 67.94 | | 4Q26 | | 156,150 | | | $ | 68.60 | |
| | | | | | | | | | | | | | | Oil Basis Swaps (Argus Cushing (WTI) and Magellan East Houston) | | Total Volumes (MMBtu) | | Weighted-Average Price | 2023 Contracts | | | | | 4Q23 | | 61,000 | | | $ | 0.90 | | 2025 Contracts | | | | | 1Q25 | | 90,000 | | | $ | 1.75 | | 2Q25 | | 91,000 | | | $ | 1.75 | | 3Q25 | | 92,000 | | | $ | 1.75 | | 4Q25 | | 92,000 | | | $ | 1.75 | | Calendar Monthly Roll Differential Swaps | | | | | 2023 Contracts | | | | | 4Q23 | | 61,000 | | | $ | 2.40 | | 2025 Contracts | | | | | 1Q25 | | 90,000 | | | $ | 0.50 | | 2Q25 | | 91,000 | | | $ | 0.50 | | 3Q25 | | 92,000 | | | $ | 0.50 | | 4Q25 | | 92,000 | | | $ | 0.50 | |
| | | | | | | | | | | | | | | Natural Gas Derivative Contracts (NYMEX Henry Hub Settlements) | | Total Volumes (MMBtu) | | Weighted-Average Price | Swap Contracts | | | | | 2024 Contracts | | | | | 1Q24 | | 1,820,000 | | | $ | 3.66 | | 2Q24 | | 2,430,000 | | | $ | 3.31 | | 3Q24 | | 2,760,000 | | | $ | 3.46 | | 4Q24 | | 2,760,000 | | | $ | 3.75 | | 2025 Contracts | | | | | 1Q25 | | 2,700,000 | | | $ | 4.20 | | 2Q25 | | 2,730,000 | | | $ | 3.75 | | 3Q25 | | 2,760,000 | | | $ | 3.89 | | 4Q25 | | 1,540,000 | | | $ | 4.11 | | 2026 Contracts | | | | | 1Q26 | | 900,000 | | | $ | 4.56 | | 2Q26 | | 910,000 | | | $ | 3.53 | | 3Q26 | | 920,000 | | | $ | 3.73 | | 4Q26 | | 920,000 | | | $ | 4.19 | |
| | | | | | | | | | | | | | | Natural Gas Basis Derivative Swaps (East Texas Houston Ship Channel vs. NYMEX Settlements) | | Total Volumes (MMBtu) | | Weighted-Average Price | 2024 Contracts | | | | | 1Q24 | | 910,000 | | | $ | (0.21) | | 2Q24 | | 910,000 | | | $ | (0.21) | | 3Q24 | | 920,000 | | | $ | (0.21) | | 4Q24 | | 920,000 | | | $ | (0.21) | | 2025 Contracts | | | | | 1Q25 | | 900,000 | | | $ | (0.23) | | 2Q25 | | 910,000 | | | $ | (0.23) | | 3Q25 | | 920,000 | | | $ | (0.23) | | 4Q25 | | 920,000 | | | $ | (0.23) | |
| | | | | | | | | | | | | | | NGL Swaps (Mont Belvieu) | | Total Volumes (Bbls) | | Weighted-Average Price | 2024 Contracts | | | | | 1Q24 | | 91,000 | | | $ | 24.25 | | 2Q24 | | 91,000 | | | $ | 24.25 | | 3Q24 | | 92,000 | | | $ | 24.25 | | 4Q24 | | 92,000 | | | $ | 24.25 | |
There were no other material subsequent events requiring additional disclosure in these condensed consolidated financial statements.
Use of Estimates. The preparation of financial statements in conformity with GAAP requires us to make estimates and assumptions that affect the reported amounts of certain assets and liabilities and the reported amounts of certain revenues and expenses during each reporting period. Such estimates and assumptions are subject to a number of risks and uncertainties that may cause actual results to differ materially from such estimates. Significant estimates and assumptions underlying these financial statements include: •the estimated quantities of proved oil and natural gas reserves used to compute depletion of oil and natural gas properties, the related present value of estimated future net cash flows therefrom, and the Ceiling Test impairment calculation, •estimates related to the collectability of accounts receivable and the creditworthiness of our customers, •estimates of the counterparty bank risk related to letters of credit that our customers may have issued on our behalf, •estimates of future costs to develop and produce reserves, •accruals related to oil and gas sales, capital expenditures and lease operating expenses (“LOE”), •estimates in the calculation of share-based compensation expense, •estimates of our ownership in properties prior to final division of interest determination, •the estimated future cost and timing of asset retirement obligations, •estimates made in our income tax calculations, including the valuation of our deferred tax assets, •estimates in the calculation of the fair value of commodity derivative assets and liabilities, •estimates in the assessment of current litigation claims against the Company, •estimates used in the assessment of business combinations and asset purchases, •estimates in amounts due with respect to open state regulatory audits, and •estimates on future lease obligations.
While we are not currently aware of any material revisions to any of our estimates, there will likely be future revisions to our estimates resulting from matters such as new accounting pronouncements, changes in ownership interests, payouts, joint venture audits, reallocations by purchasers or pipelines, or other corrections and adjustments common in the oil and gas industry, many of which relate to prior periods. These types of adjustments cannot be currently estimated and are expected to be recorded in the period during which the adjustments are known.
We are subject to legal proceedings, claims, liabilities and environmental matters that arise in the ordinary course of business. We accrue for losses when such losses are considered probable and the amounts can be reasonably estimated.
Property and Equipment. We follow the “full-cost” method of accounting for oil and natural gas property and equipment costs. Under this method of accounting, all productive and nonproductive costs incurred in the exploration, development, and acquisition of oil and natural gas reserves are capitalized. Such costs may be incurred both prior to and after the acquisition of a property and include lease acquisitions, geological and geophysical services, drilling, completion, and equipment. Internal costs incurred that are directly identified with exploration, development, and acquisition activities undertaken by us for our own account, and which are not related to production, general corporate overhead, or similar activities, are also capitalized. For the three months ended September 30, 2023 and 2022, such internal costs capitalized totaled $1.4 million and $1.1 million, respectively. For the nine months ended September 30, 2023 and 2022, such internal costs capitalized totaled $4.1 million and $3.3 million, respectively. Interest costs are also capitalized to unproved oil and natural gas properties. There was no capitalized interest on our unproved properties for both the three months ended September 30, 2023 and 2022 and the nine months ended September 30, 2023 and 2022.
The “Property and Equipment” balances on the accompanying condensed consolidated balance sheets are summarized for presentation purposes. The following is a detailed breakout of our “Property and Equipment” balances (in thousands): | | | | | | | | | | | | | September 30, 2023 | | December 31, 2022 | Property and Equipment | | | | Proved oil and gas properties | $ | 2,827,145 | | | $ | 2,506,853 | | Unproved oil and gas properties | 27,821 | | | 16,272 | | Furniture, fixtures and other equipment | 6,301 | | | 6,098 | | Less – Accumulated depreciation, depletion, amortization & impairment | (1,151,141) | | | (1,004,044) | | Property and Equipment, Net | $ | 1,710,126 | | | $ | 1,525,179 | |
No gains or losses are recognized upon the sale or disposition of oil and natural gas properties, except in transactions involving a significant amount of reserves or where the proceeds from the sale of oil and natural gas properties would significantly alter the relationship between capitalized costs and proved reserves of oil and natural gas attributable to a cost center. Internal costs associated with selling properties are expensed as incurred. We compute the provision for depreciation, depletion and amortization (“DD&A”) of oil and natural gas properties using the unit-of-production method. Under this method, we compute the provision by multiplying the total unamortized costs of oil and natural gas properties, including future development costs, gas processing facilities, and both capitalized asset retirement obligations and undiscounted abandonment costs of wells to be drilled, net of salvage values, but excluding costs of unproved properties, by an overall rate determined by dividing the physical units of oil and natural gas produced (which excludes natural gas consumed in operations) during the period by the total estimated units of proved oil and natural gas reserves (which excludes natural gas consumed in operations) at the beginning of the period. Future development costs are estimated on a property-by-property basis based on current economic conditions. The period over which we will amortize these properties is dependent on our production from these properties in future years. Furniture, fixtures and other equipment are recorded at cost and are depreciated by the straight-line method at rates based on the estimated useful lives of the property, which range between two and 20 years. Repairs and maintenance are charged to expense as incurred.
Geological and geophysical (“G&G”) costs incurred on developed properties are recorded in “Proved oil and gas properties” and therefore subject to amortization. G&G costs incurred that are associated with unproved properties are capitalized in “Unproved oil and gas properties” and evaluated as part of the total capitalized costs associated with a prospect. The cost of unproved properties not being amortized is assessed quarterly, on a property-by-property basis, to determine whether such properties have been impaired. In determining whether such costs should be impaired, we evaluate current drilling results, lease expiration dates, current oil and gas industry conditions, economic conditions, capital availability and available geological and geophysical information. Any impairment assessed is added to the cost of proved properties being amortized.
Full-Cost Ceiling Test. At the end of each quarterly reporting period, the unamortized cost of oil and natural gas properties (including natural gas processing facilities, capitalized asset retirement obligations, net of related salvage values and deferred income taxes) is limited to the sum of the estimated future net revenues from proved properties (excluding cash outflows from recognized asset retirement obligations, including future development and abandonment costs of wells to be drilled, using the preceding 12-months’ average price based on closing prices on the first day of each month, adjusted for price differentials, discounted at 10% and the lower of cost or fair value of unproved properties) adjusted for related income tax effects (“Ceiling Test”).
The quarterly calculations of the Ceiling Test and provision for DD&A are based on estimates of proved reserves. There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting the future rates of production, timing and plan of development. The accuracy of any reserves estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Results of drilling, testing, and production subsequent to the date of the estimate may justify revision of such estimates. Accordingly, reserves estimates are often different from the quantities of oil and natural gas that are ultimately recovered. There was no ceiling test write-down for either of the three months ended September 30, 2023 and 2022 or the nine months ended September 30, 2023 and 2022.
If future capital expenditures outpace future discounted net cash flows in our reserve calculations, if we have significant declines in our oil and natural gas reserves volumes (which also reduces our estimate of discounted future net cash flows from proved oil and natural gas reserves) or if oil or natural gas prices decline, it is possible that non-cash write-downs of our oil and natural gas properties will occur again in the future. We cannot control and cannot predict what future prices for oil and natural gas will be; therefore, we cannot estimate the amount of any potential future non-cash write-down of our oil and natural gas properties due to decreases in oil or natural gas prices. However, it is reasonably possible that we will record additional Ceiling Test write-downs in future periods.
Accounts Receivable, Net. We assess the collectability of accounts receivable based on a broad range of reasonable and forward-looking information including historical losses, current economic conditions, future forecasts and contractual terms. The Company's credit losses based on these assessments are considered immaterial. At September 30, 2023, December 31, 2022 and December 31, 2021, we had an allowance of less than $0.1 million. The allowance has been deducted from the total “Accounts receivable, net” balance on the accompanying condensed consolidated balance sheets.
At September 30, 2023, our “Accounts receivable, net” balance included $60.4 million for oil and gas sales, $1.9 million due from joint interest owners, $9.1 million for severance tax credit receivables and $8.8 million for other receivables. At December 31, 2022, our “Accounts receivable, net” balance included $70.9 million for oil and gas sales, $5.6 million due from joint interest owners, $4.3 million for severance tax credit receivables and $8.9 million for other receivables. At December 31, 2021, our “Accounts receivable, net” balance included $45.3 million for oil and gas sales, $1.9 million due from joint interest owners, $1.0 million for severance tax credit receivables and $1.5 million for other receivables.
Supervision Fees. Consistent with industry practice, we charge a supervision fee to the wells we operate, including our wells, in which we own up to a 100% working interest. Supervision fees are recorded as a reduction to “General and administrative, net,” on the accompanying condensed consolidated statements of operations. The amount of supervision fees charged for each of the nine months ended September 30, 2023 and 2022 did not exceed our actual costs incurred. The total amount of supervision fees charged to the wells we operated was $3.0 million and $2.8 million for the three months ended September 30, 2023 and 2022, respectively, and $8.6 million and $6.1 million for the nine months ended September 30, 2023 and 2022, respectively.
Income Taxes. Deferred taxes are determined based on the estimated future tax effects of differences between the financial statement and tax basis of assets and liabilities, given the provisions of the enacted tax laws. The Company's effective tax rate was approximately 17% and 4% for the three months ended September 30, 2023 and 2022, respectively, and 22% and 4% for the nine months ended September 30, 2023 and 2022, respectively. The Company recorded an income tax benefit of $0.9 million and income tax provision of $33.2 million for the three and nine months ended September 30, 2023, respectively, and an income tax provision of $6.1 million and $7.7 million for the three and nine months ended September 30, 2022, respectively. The tax impact for both periods was a product of the overall forecasted annual effective tax rate applied to the year to date income.
Section 382 of the Internal Revenue Code (“Section 382”) imposes limitations on a corporation’s ability to utilize its net operating losses (“NOLs”) if it experiences an ownership change. Generally, an “ownership change” occurs if one or more shareholders, each of whom is deemed to own five percent or more in value of a corporation’s stock, increase their aggregate percentage ownership by more than 50 percent over the lowest percentage of stock owned by those shareholders at any time during the preceding three-year period. In the event of an ownership change, utilization of the NOLs would be subject to an annual limitation under Section 382. We believe we had an ownership change in August 2022 and, therefore, are subject to an annual limitation on the usage of our NOLs generated prior to the ownership change. However, we do not expect to have any of our NOLs expire before becoming available to be utilized by the Company. Management will continue to monitor the potential impact of Section 382 with respect to our NOLs.
Our policy is to record interest and penalties relating to uncertain tax positions in income tax expense. At September 30, 2023 and December 31, 2022, we did not have any accrued liability for uncertain tax positions and do not anticipate recognition of any significant liabilities for uncertain tax positions during the next 12 months.
Revenue Recognition. Our reported oil and gas sales are comprised of revenues from oil, natural gas and natural gas liquids (“NGLs”) sales. Revenues from each product stream are recognized at the point when control of the product is transferred to the customer and collectability is reasonably assured. Prices for our products are either negotiated on a monthly basis or tied to market indices. The Company has determined that these contracts represent performance obligations which are satisfied when control of the commodity transfers to the customer, typically through the delivery of the specified commodity to a designated delivery point. Natural gas revenues are recognized based on the actual volume of natural gas sold to the purchasers.
The following table provides information regarding our oil and gas sales, by product, reported on the Condensed Consolidated Statements of Operations for the three months ended September 30, 2023 and 2022 and the nine months ended September 30, 2023 and 2022 (in thousands): | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Three Months Ended September 30, 2023 | | Three Months Ended September 30, 2022 | | Nine Months Ended September 30, 2023 | | Nine Months Ended September 30, 2022 | | | | | Oil, natural gas and NGLs sales: | | | | | | | | | | | | Oil | $ | 112,456 | | | $ | 71,811 | | | $ | 267,263 | | | $ | 155,566 | | | | | | Natural gas | 46,075 | | | 150,958 | | | 132,802 | | | 351,626 | | | | | | NGLs | 15,432 | | | 19,412 | | | 40,252 | | | 47,250 | | | | | | Total | $ | 173,963 | | | $ | 242,181 | | | $ | 440,317 | | | $ | 554,442 | | | | | |
Accounts Payable and Accrued Liabilities. The “Accounts payable and accrued liabilities” balances on the accompanying condensed consolidated balance sheets are summarized below (in thousands): | | | | | | | | | | | | | September 30, 2023 | | December 31, 2022 | Trade accounts payable | $ | 30,708 | | | $ | 23,660 | | Accrued operating expenses | 11,266 | | | 10,572 | | Accrued compensation costs | 3,267 | | | 4,814 | | Asset retirement obligations – current portion | 1,578 | | | 1,284 | | Accrued non-income based taxes | 13,303 | | | 4,849 | | Accrued corporate and legal fees | 181 | | | 388 | | WTI contingency payouts - current portion | 1,537 | | | 1,600 | | Payable for settled derivatives | 3,549 | | | 6,026 | | Other payables | 9,342 | | | 7,007 | | Total accounts payable and accrued liabilities | $ | 74,731 | | | $ | 60,200 | |
Cash and Cash Equivalents. We consider all highly liquid instruments with an initial maturity of three months or less to be cash equivalents. These amounts do not include cash balances that are contractually restricted. The Company maintains cash and cash equivalent balances with major financial institutions, which at times exceed federally insured limits. The Company monitors the financial condition of the financial institutions and has experienced no losses associated with these accounts.
Treasury Stock. Our treasury stock repurchases are reported at cost and are included in “Treasury stock, held at cost” on the accompanying condensed consolidated balance sheets. For the nine months ended September 30, 2023, we purchased 131,911 treasury shares to satisfy withholding tax obligations arising upon the vesting of restricted shares. For the nine months ended September 30, 2022, we purchased 120,350 treasury shares to satisfy withholding tax obligations arising upon the vesting of restricted shares and received 41,375 shares in conjunction with our post-closing settlement for a previously disclosed acquisition.
New Accounting Pronouncements. In June 2016, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2016-13, Credit Losses - Measurement of Credit Losses on Financial Instruments. The standard changes how entities will measure credit losses for most financial assets, including accounts and notes receivables. The new standard replaces the existing incurred loss impairment methodology with a methodology that requires consideration of a broader range of reasonable and supportable forward-looking information to estimate all expected credit losses. The updated guidance is effective for the Company for annual and quarterly reporting periods beginning after December 15, 2022, and the Company adopted the guidance on January 1, 2023. The adoption of this guidance did not have a material impact on the Company’s consolidated financial statements or disclosures.
In March 2020, the FASB issued ASU No. 2020-04, Reference Rate Reform (Topic 848): Facilitation of the Effects of Reference Rate Reform on Financial Reporting followed by ASU No. 2021-01, Reference Rate Reform (Topic 848): Scope (“ASU 2021-01”), issued in January 2021, and ASU 2022-06, Reference Rate Reform (Topic 848): Deferral of the Sunset Date of Topic 848, issued in December 2022. The guidance provides and clarifies optional expedients and exceptions for applying generally accepted accounting principles to contract modifications, subject to meeting certain criteria, that reference LIBOR or another reference rate expected to be discontinued. The amendments within these ASUs were in effect beginning March 12, 2020, and an entity may elect to apply the amendments prospectively through December 31, 2024. This guidance provides an optional practical expedient that allows qualifying modifications to be accounted for as a debt modification rather than be analyzed under existing guidance to determine if the modification should be accounted for as a debt extinguishment. The Company adopted this accounting pronouncement in conjunction with the execution of the Third Amendment to the Note Purchase Agreement in June 2023 and elected to apply this optional expedient. See Note 6 – Long-Term Debt for further discussion of the Company’s accounting for its existing debt and related issuance costs. The adoption of this accounting standard did not have a material impact on the Company's condensed consolidated financial statements and related disclosures.
In August 2020, the FASB issued ASU No. 2020-06, Accounting for Convertible Instruments and Contracts in an Entity’s Own Equity. The guidance simplifies the accounting for certain financial instruments with characteristics of liabilities and equity, including convertible instruments and contracts in an entity’s own equity. Additionally, the amendment requires the application of the if-converted method to calculate the impact of convertible instruments on diluted earnings per share (EPS). The guidance is effective for the Company for fiscal years beginning after December 15, 2022, and the Company adopted the guidance on January 1, 2023. The adoption of this guidance did not have a material impact on the Company’s consolidated financial statements or disclosures.
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- DefinitionThe entire disclosure for all significant accounting policies of the reporting entity.
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v3.23.3
Leases Leases (Notes)
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9 Months Ended |
Sep. 30, 2023 |
Leases [Abstract] |
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Lessee, Operating Leases |
(3) Leases The Company follows the FASB's Accounting Standards Codification Topic No. 842 and elected the package of practical expedients that allows an entity to carry forward historical accounting treatment relating to lease identification and classification for existing leases upon adoption and the practical expedient related to land easements that allows an entity to carry forward historical accounting treatment for land easements on existing agreements. The Company has made an accounting policy election to keep leases with an initial term of 12 months or less off the condensed consolidated balance sheets. We have elected to not account for lease and non-lease components separately. The Company has contractual agreements for its corporate office lease, vehicle fleet, compressors, treating equipment, and for surface use rights. For leases with a primary term of more than 12 months, a right-of-use (“ROU”) asset and the corresponding lease liability is recorded. The Company determines at inception if an arrangement is an operating or financing lease. As of September 30, 2023, all of the Company’s leases were operating leases.
The initial asset and liability balances are recorded at the present value of the payment obligations over the lease term. If lease terms include options to extend the lease and it is reasonably certain that the Company will exercise that option, the lease term used for capitalization includes the expected renewal periods. Most leases do not provide an implicit interest rate. Unless the lease contract contains an implicit interest rate, the Company uses its incremental borrowing rate at the time of lease inception to compute the fair value of the lease payments. The ROU asset balance and current and non-current lease liabilities are reported separately on the accompanying condensed consolidated balance sheets. Certain leases have payment terms that vary based on the usage of the underlying assets. Variable lease payments are not included in ROU assets and lease liabilities. The Company recognizes lease expense on a straight-line basis over the lease term. As of September 30, 2023, the Company's future cash payment obligation for its operating lease liabilities are as follows (in thousands): | | | | | | | As of September 30, 2023 | 2023 (Remaining) | $ | 2,667 | | 2024 | 4,166 | | 2025 | 2,427 | | 2026 | 1,194 | | 2027 | 61 | | Thereafter | 475 | | Total undiscounted lease payments | 10,990 | | Present value adjustment | (879) | | Net operating lease liabilities | $ | 10,111 | |
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- DefinitionThe entire disclosure for operating leases of lessee. Includes, but is not limited to, description of operating lease and maturity analysis of operating lease liability.
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v3.23.3
Share-Based Compensation
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9 Months Ended |
Sep. 30, 2023 |
Share-Based Payment Arrangement [Abstract] |
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Share-Based Compensation |
(4) Share-Based Compensation
Share-Based Compensation Plans
In 2016, the Company adopted the 2016 Equity Incentive Plan (as amended from time to time, the “2016 Plan”). The Company also adopted the Inducement Plan (as amended from time to time, the “Inducement Plan,” and, together with the 2016 Plan, the “Plans”) on December 15, 2016.
The Company computes a deferred tax benefit for restricted stock units (“RSUs”), performance-based stock units (“PSUs”) and stock options expected to generate future tax deductions by applying its effective tax rate to the expense recorded. For RSUs, the Company's actual tax deduction is based on the value of the units at the time of vesting.
The expense for awards issued to both employees and non-employees, which was recorded in “General and administrative, net” in the accompanying condensed consolidated statements of operations was $1.5 million and $1.2 million for the three months ended September 30, 2023 and 2022, respectively, and $4.0 million and $3.9 million for the nine months ended September 30, 2023 and 2022, respectively. Capitalized share-based compensation was less than $0.1 million for both the three months ended September 30, 2023 and 2022, and $0.2 million for both the nine months ended September 30, 2023 and 2022.
We view stock option awards and RSUs with graded vesting as single awards with an expected life equal to the average expected life of component awards, and we amortize the awards on a straight-line basis over the life of the awards. The Company accounts for forfeitures in compensation cost when they occur.
Stock Option Awards
The compensation cost related to stock option awards is based on the grant date fair value and is typically expensed over the vesting period (generally one to five years). We use the Black-Scholes option pricing model to estimate the fair value of stock option awards.
At September 30, 2023, we had no unrecognized compensation cost related to stock option awards. The following table provides information regarding stock option award activity for the nine months ended September 30, 2023: | | | | | | | | | | | | | Shares | | Wtd. Avg. Exer. Price | Options outstanding, beginning of period | 196,162 | | | $ | 26.46 | | Options granted | — | | | $ | — | | | | | | | | | | Options exercised | — | | | $ | — | | Options outstanding, end of period | 196,162 | | | $ | 26.46 | | Options exercisable, end of period | 196,162 | | | $ | 26.46 | |
Our outstanding stock option awards had $1.8 million aggregate intrinsic value at September 30, 2023. At September 30, 2023, the weighted-average remaining contract life of stock option awards outstanding was 3.6 years and exercisable was 3.6 years. The total intrinsic value of stock option awards exercisable was $1.8 million as of September 30, 2023.
Restricted Stock Units
The compensation cost related to restricted stock awards is based on the grant date fair value and is typically expensed over the requisite service period (generally one to five years).
As of September 30, 2023, we had $5.1 million unrecognized compensation expense related to our RSUs which is expected to be recognized over a weighted-average period of 2.0 years.
The following table provides information regarding RSU activity for the nine months ended September 30, 2023: | | | | | | | | | | | | | RSUs | | Wtd. Avg. Grant Price | RSUs outstanding, beginning of period | 227,114 | | | $ | 21.18 | | RSUs granted | 195,791 | | | $ | 23.75 | | | | | | | | | | RSUs forfeited | (1,424) | | | $ | 25.44 | | RSUs vested | (137,467) | | | $ | 17.78 | | RSUs outstanding, end of period | 284,014 | | | $ | 24.58 | |
Performance-Based Stock Units
On May 21, 2019, the Company granted 99,500 PSUs for which the number of shares earned was based on the total shareholder return (“TSR”) of the Company's common stock relative to the TSR of its selected peers during the performance period from January 1, 2019 to December 31, 2021. The awards contained market conditions which allowed a payout ranging between 0% payout and 200% of the target payout. The fair value as of the grant date was $18.86 per unit or 112.9% of stock price. The awards had a cliff-vesting period of three years. In the first quarter of 2022, the Board and its Compensation Committee approved payout of these awards at 117% of target. Accordingly, 97,812 shares were issued on February 23, 2022. On February 24, 2021, the Company granted 161,389 PSUs for which the number of shares earned is based on the TSR of the Company's common stock relative to the TSR of its selected peers during the performance period from January 1, 2021 to December 31, 2022. The awards contain market conditions which allow a payout ranging between 0% and 200% of the target payout. The fair value as of the grant date was $13.13 per unit or 157.6% of the stock price. The compensation expense for these awards is based on the per unit grant date valuation using a Monte Carlo simulation multiplied by the target payout level. The payout level is calculated based on actual stock price performance achieved during the performance period. The awards have a cliff-vesting period of two years. In the first quarter of 2023, the Board and its Compensation Committee approved payout of these awards at 188% of target. Accordingly, 303,410 shares were issued on February 22, 2023.
On February 23, 2022, the Company granted 122,111 PSUs for which the number of shares earned is based on the TSR of the Company's common stock relative to the TSR of its selected peers during the performance period from January 1, 2022 to December 31, 2024. The awards contain market conditions which allow a payout ranging between 0% and 200% of the target payout. The fair value as of the grant date was $36.47 per unit or 150.93% of the stock price. The compensation expense for these awards is based on the per unit grant date valuation using a Monte Carlo simulation multiplied by the target payout level. The payout level is calculated based on actual stock price performance achieved during the performance period. The awards have a cliff-vesting period of three years. All PSUs granted remain outstanding related to this award as of September 30, 2023.
On February 23, 2023, the Company granted 120,749 PSUs for which the number of shares earned is based on the TSR of the Company's common stock relative to the TSR of its selected peers during the performance period from January 1, 2023 to December 31, 2025. The awards contain market conditions which allow a payout ranging between 0% and 200% of the target payout. The fair value as of the grant date was $31.18 per unit or 136.28% of the stock price. The compensation expense for these awards is based on the per unit grant date valuation using a Monte Carlo simulation multiplied by the target payout level. The payout level is calculated based on actual stock price performance achieved during the performance period. The awards have a cliff-vesting period of three years. All PSUs granted remain outstanding related to this award as of September 30, 2023.
As of September 30, 2023, we had $4.9 million unrecognized compensation expense related to our PSUs based on the assumption of 100% target payout. The remaining weighted-average performance period is 1.9 years.
The following table provides information regarding performance-based stock unit activity for the nine months ended September 30, 2023: | | | | | | | | | | | | | PSUs | | Wtd. Avg. Grant Price | Performance based stock units outstanding, beginning of period | 283,500 | | | $ | 23.18 | | Performance based stock units granted | 120,749 | | | $ | 31.18 | | Performance based stock units incremental shares granted | 142,021 | | | $ | 13.13 | | Performance based stock units vested | (303,410) | | | $ | 13.13 | | Performance based stock units outstanding, end of period | 242,860 | | | $ | 33.84 | |
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- DefinitionThe entire disclosure for share-based payment arrangement.
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v3.23.3
Earnings Per Share
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9 Months Ended |
Sep. 30, 2023 |
Earnings Per Share [Abstract] |
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Earnings Per Share |
(5) Earnings Per Share
Basic earnings per share (“Basic EPS”) has been computed using the weighted-average number of common shares outstanding during each period. Diluted earnings per share (“Diluted EPS”) assumes, as of the beginning of the period, exercise of stock options and RSU grants using the treasury stock method. Diluted EPS also assumes conversion of PSUs to common shares based on the number of shares (if any) that would be issuable, according to predetermined performance and market goals, if the end of the reporting period was the end of the performance period. Certain of our stock options and RSU grants that would potentially dilute Basic EPS in the future were also antidilutive for the three and nine months ended September 30, 2023 and 2022 are discussed below. The following is a reconciliation of the numerators and denominators used in the calculation of Basic EPS and Diluted EPS for the periods indicated below (in thousands, except per share amounts): | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Three Months Ended September 30, 2023 | | Three Months Ended September 30, 2022 | | Net Income (Loss) | | Shares | | Per Share Amount | | Net Income (Loss) | | Shares | | Per Share Amount | Basic EPS: | | | | | | | | | | | | Net Income (Loss) and Share Amounts | $ | (4,771) | | | 22,985 | | | $ | (0.21) | | | $ | 142,541 | | | 22,308 | | | $ | 6.39 | | Dilutive Securities: | | | | | | | | | | | | Performance Based Stock Unit Awards | | | — | | | | | | | 169 | | | | RSU Awards | | | — | | | | | | | 137 | | | | Stock Option Awards | | | — | | | | | | | 55 | | | | Diluted EPS: | | | | | | | | | | | | Net Income (Loss) and Assumed Share Conversions | $ | (4,771) | | | 22,985 | | | $ | (0.21) | | | $ | 142,541 | | | 22,669 | | | $ | 6.29 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Nine Months Ended September 30, 2023 | | Nine Months Ended September 30, 2022 | | Net Income (Loss) | | Shares | | Per Share Amount | | Net Income (Loss) | | Shares | | Per Share Amount | Basic EPS: | | | | | | | | | | | | Net Income (Loss) and Share Amounts | $ | 114,658 | | | 22,677 | | | $ | 5.06 | | | $ | 167,076 | | | 18,885 | | | $ | 8.85 | | Dilutive Securities: | | | | | | | | | | | | Performance Based Stock Unit Awards | | | 67 | | | | | | | 141 | | | | RSU Awards | | | 91 | | | | | | | 171 | | | | Stock Option Awards | | | 17 | | | | | | | 40 | | | | Diluted EPS: | | | | | | | | | | | | Net Income (Loss) and Assumed Share Conversions | $ | 114,658 | | | 22,852 | | | $ | 5.02 | | | $ | 167,076 | | | 19,237 | | | $ | 8.69 | |
On September 18, 2023, the Company issued 2,810,811 shares of its common stock in a registered underwritten offering, for aggregate net proceeds, after offering expenses and fees, of approximately $97.1 million.
There were 0.2 million stock options that were not included in the computation of Diluted EPS for the three months ended September 30, 2023 because they were antidilutive due to the net loss, while there were no antidilutive stock options for the three months ended September 30, 2022. Additionally, there were less than 0.1 million stock options to purchase shares which were not included in the computation of Diluted EPS for both the nine months ended September 30, 2023 and 2022, because they were antidilutive.
There were 0.2 million shares of RSUs that were not included in the computation of Diluted EPS for the three months ended September 30, 2023 because they were antidilutive due to the net loss and less than 0.1 million shares of RSUs that were not included in the computation of Diluted EPS for the three months ended September 30, 2022 because they were antidilutive. Additionally, there were less than 0.1 million shares of RSUs which were not included in the computation of Diluted EPS for both the nine months ended September 30, 2023 and 2022 because they were antidilutive.
There were 0.1 million shares of PSUs that were not included in the computation of Diluted EPS for the three months ended September 30, 2023 because they were antidilutive due to the net loss and no antidilutive shares of PSUs for the three months ended September 30, 2022. Additionally, there were no antidilutive shares of PSUs for both the nine months ended September 30, 2023 and 2022.
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- DefinitionThe entire disclosure for earnings per share.
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v3.23.3
Long-Term Debt
|
9 Months Ended |
Sep. 30, 2023 |
Debt Disclosure [Abstract] |
|
Long-Term Debt |
(6) Long-Term Debt
The Company's long-term debt consisted of the following (in thousands): | | | | | | | | | | | | | September 30, 2023 | | December 31, 2022 | Credit Facility Borrowings due 2026 (1) | $ | 498,000 | | | $ | 542,000 | | Second Lien Notes due 2026 | 150,000 | | | 150,000 | | | 648,000 | | | 692,000 | | Unamortized discount on Second Lien Notes due 2026 | (738) | | | (882) | | Unamortized debt issuance cost on Second Lien Notes due 2026 | (2,166) | | | (2,587) | | Long-Term Debt, net | $ | 645,096 | | | $ | 688,531 | |
(1) Unamortized debt issuance costs on our Credit Facility borrowings are included in “Other Long-Term Assets” in our condensed consolidated balance sheet. As of September 30, 2023 and December 31, 2022, we had $7.0 million and $8.7 million, respectively, in unamortized debt issuance costs on our Credit Facility borrowings.
Revolving Credit Facility. Amounts outstanding under our Credit Facility (defined below) were $498.0 million and $542.0 million as of September 30, 2023 and December 31, 2022, respectively. The Company is a party to a First Amended and Restated Senior Secured Revolving Credit Agreement with JPMorgan Chase Bank, National Association, as administrative agent, and certain lenders party thereto, as amended (such agreement, the “Credit Agreement” and the borrowing facility provided thereby, the “Credit Facility”).
The Credit Facility matures October 19, 2026 (or to the extent earlier, the date that is 91 days prior to the scheduled maturity of the Company's Second Lien notes), and provides for a maximum credit amount of $2.0 billion, subject to the current borrowing base of $775.0 million. The borrowing base is regularly redetermined in or about May and November of each calendar year and is subject to additional adjustments from time to time, including for asset sales, elimination or reduction of hedge positions and incurrence of other debt. Additionally, the Company and the administrative agent may request an unscheduled redetermination of the borrowing base between scheduled redeterminations. The amount of the borrowing base is determined by the lenders, in their discretion, in accordance with their oil and gas lending criteria at the time of the relevant redetermination. In conjunction with its regularly scheduled semi-annual redeterminations, the Company reaffirmed the borrowing base and elected commitment amount under the Credit Facility at $775.0 million, effective November 22, 2022, and again on March 20, 2023. The Company may also request the issuance of letters of credit under the Credit Agreement in an aggregate amount up to $25.0 million, which reduces the amount of available borrowings under the borrowing base in the amount of such issued and outstanding letters of credit. There were no outstanding letters of credit as of September 30, 2023, and no outstanding letters of credit as of December 31, 2022. Maintaining or increasing our borrowing base under our Credit Facility is dependent on many factors, including commodity prices, our hedge positions, changes in our lenders' lending criteria and our ability to raise capital to drill wells to replace produced reserves.
Interest under the Credit Facility accrues at the Company’s option either at an Alternate Base Rate plus the applicable margin (“ABR Loans”), the Adjusted Term Secured Overnight Financing Rate (“SOFR”) plus the applicable margin (“Term Benchmark Loans”) or Adjusted Daily Simple SOFR plus the applicable margin (“RFR Loans”). The applicable margin ranges from 1.75% to 2.75% based on borrowing base utilization for ABR Loans and 2.75% to 3.75% based on borrowing base utilization for Term Benchmark Loans and RFR Loans. The Alternate Base Rate and SOFR are defined, and the applicable margins are set forth, in the Credit Agreement. Undrawn amounts under the Credit Facility are subject to a 0.5% commitment fee. To the extent that a payment default exists and is continuing, all amounts outstanding under the Credit Facility will bear interest at 2.0% per annum above the rate and margin otherwise applicable thereto. As of September 30, 2023, the Company's weighted average interest rate on Credit Facility borrowings was 8.67%.
The obligations under the Credit Agreement are secured, subject to certain exceptions, by a first priority lien on substantially all assets of the Company and its subsidiary, including a first priority lien on properties attributed with at least 85% of estimated proved reserves of the Company and its subsidiary.
The Credit Agreement contains the following financial covenants:
•a ratio of total debt to earnings before interest, tax, depreciation and amortization (“EBITDA”), as defined in the Credit Agreement, for the most recently completed four fiscal quarters, not to exceed 3.00 to 1.00 as of the last day of each fiscal quarter; and •a current ratio, as defined in the Credit Agreement, which includes in the numerator available borrowings undrawn under the borrowing base, of not less than 1.00 to 1.00 as of the last day of each fiscal quarter.
As of September 30, 2023, the Company was in compliance with all financial covenants under the Credit Agreement.
Additionally, the Credit Agreement contains certain representations, warranties and covenants, including but not limited to, limitations on incurring debt and liens, limitations on making certain restricted payments, limitations on investments, limitations on asset sales and hedge unwinds, limitations on transactions with affiliates and limitations on modifying organizational documents and material contracts. The Credit Agreement contains customary events of default. If an event of default occurs and is continuing, the lenders may declare all amounts outstanding under the Credit Facility to be immediately due and payable.
Total interest expense on the Credit Facility, which includes commitment fees and amortization of debt issuance costs, was $14.6 million and $8.3 million for the three months ended September 30, 2023 and 2022, respectively, and $39.8 million and $15.9 million for the nine months ended September 30, 2023 and 2022, respectively. The amount of commitment fee amortization included in interest expense, net was $0.2 million and $0.3 million for the three months ended September 30, 2023 and 2022, respectively, and $0.7 million and $0.9 million for the nine months ended September 30, 2023 and 2022, respectively.
Senior Secured Second Lien Notes. On December 15, 2017, the Company entered into a Note Purchase Agreement for Senior Secured Second Lien Notes (as amended, the “Note Purchase Agreement,” and such second lien facility the “Second Lien”) among the Company as issuer, U.S. Bank National Association as agent and collateral agent, and certain holders that are a party thereto, and issued notes in an initial principal amount of $200.0 million, with a $2.0 million discount, for net proceeds of $198.0 million.
Effective November 12, 2021, the Company entered into the Second Amendment to the Note Purchase Agreement, which extended the maturity date from December 15, 2024 to December 15, 2026 subject to paying down the principal amount of the Second Lien from $200.0 million to $150.0 million. The Company made the $50.0 million redemption of the Second Lien notes on November 29, 2021.
On June 14, 2023, the Company entered into the Third Amendment to the Note Purchase Agreement to effectuate the replacement of LIBOR with an adjusted term secured overnight financing rate plus a margin of 0.25% (“Term SOFR”). After the Third Amendment, interest under the Second Lien is payable quarterly and accrues, based on the Company's election at the time of the borrowing, either at Term SOFR plus a margin of 7.5% (“Second Lien Term SOFR Loans”) or at an Alternate Base Rate which is based on the greater of (i) the prime rate; (ii) the greater of the federal funds effective rate or overnight bank funding rate, plus 0.5%; or (iii) Term SOFR plus 1% (“Second Lien ABR Loans”) plus a margin of 6.5%. Additionally, to the extent the Company were to default on the Second Lien, this would potentially trigger a cross-default under our Credit Facility. As of September 30, 2023, the Company's interest rate on Second Lien borrowings was 13.16%.
The Company has the right, to the extent permitted under the Credit Facility and subject to the terms and conditions of the Second Lien, to optionally prepay the notes at no premium. Additionally, the Second Lien contains customary mandatory prepayment obligations upon asset sales (including hedge terminations), casualty events and incurrences of certain debt, subject to, in certain circumstances, reinvestment periods. Management believes the probability of mandatory prepayment due to default is remote.
The obligations under the Second Lien are secured, subject to certain exceptions and other permitted liens (including the liens created under the Credit Facility), by a perfected security interest, second in priority to the liens securing our Credit Facility, and mortgage lien on substantially all assets of the Company and its subsidiary, including a mortgage lien on oil and gas properties attributed with at least 90% of estimated PV-9 (defined below), of proved reserves of the Company and its subsidiary and 90% of the book value attributed to the PV-9 of the non-proved oil and gas properties of the Company. PV-9 is determined using commodity price assumptions by the administrative agent of the Credit Facility. PV-9 value is the estimated future net revenues to be generated from the production of proved reserves discounted to present value using an annual discount rate of 9%.
The Second Lien contains an Asset Coverage Ratio, which is only tested (i) as a condition to issuance of additional notes and (ii) in connection with certain asset sales in order to determine whether the proceeds of such asset sale must be applied as a prepayment of the notes and includes in the numerator of the PV-10 (defined below), based on forward strip pricing, plus the swap mark-to-market value of the commodity derivative contracts of the Company and its restricted subsidiary and in the denominator the total net indebtedness of the Company and its restricted subsidiary, of not less than 1.25 to 1.0 as of each date of determination (the “Asset Coverage Ratio”). PV-10 value is the estimated future net revenues to be generated from the production of proved reserves discounted to present value using an annual discount rate of 10%.
The Second Lien also contains a financial covenant measuring the ratio of total net debt-to-EBITDA, as defined in the Note Purchase Agreement, for the most recently completed four fiscal quarters, not to exceed 3.25 to 1.0 as of the last day of each fiscal quarter. As of September 30, 2023, the Company was in compliance with all financial covenants under the Second Lien.
The Second Lien contains certain customary representations, warranties and covenants, including but not limited to, limitations on incurring debt and liens, limitations on making certain restricted payments, limitations on investments, limitations on asset sales and hedge unwinds, limitations on transactions with affiliates and limitations on modifying organizational documents and material contracts. The Second Lien contains customary events of default. If an event of default occurs and is continuing, the lenders may declare all amounts outstanding under the Second Lien to be immediately due and payable.
As of September 30, 2023, total net amounts recorded for the Second Lien were $147.1 million, net of unamortized debt discount and debt issuance costs. Interest expense on the Second Lien totaled $5.2 million and $3.8 million for the three months ended September 30, 2023 and 2022, respectively, and $14.9 million and $10.7 million for the nine months ended September 30, 2023 and 2022, respectively.
Debt Issuance Costs. Our policy is to capitalize upfront commitment fees and other direct expenses associated with our line of credit arrangement and then amortize such costs ratably over the term of the arrangement, regardless of whether there are any outstanding borrowings. During the nine months ended September 30, 2022, the Company capitalized $7.2 million for debt issuance costs incurred in connection with the amendments to our Credit Facility. There were no capitalized costs incurred during the nine months ended September 30, 2023.
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- DefinitionThe entire disclosure for information about short-term and long-term debt arrangements, which includes amounts of borrowings under each line of credit, note payable, commercial paper issue, bonds indenture, debenture issue, own-share lending arrangements and any other contractual agreement to repay funds, and about the underlying arrangements, rationale for a classification as long-term, including repayment terms, interest rates, collateral provided, restrictions on use of assets and activities, whether or not in compliance with debt covenants, and other matters important to users of the financial statements, such as the effects of refinancing and noncompliance with debt covenants.
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v3.23.3
Acquisitions and Dispositions Acquisitions and Dispostions
|
9 Months Ended |
Sep. 30, 2023 |
Discontinued Operations and Disposal Groups [Abstract] |
|
Acquisitions and Dispositions |
(7) Acquisitions and Dispositions
November 2021 Acquisition On November 19, 2021, the Company closed on an acquisition of oil-weighted assets in the Eagle Ford. The acquired assets included wells and acreage in La Salle, McMullen, DeWitt and Lavaca counties. After consideration of closing adjustments, total aggregate consideration was approximately $77.4 million, consisting of $37.6 million in cash, 1,351,961 shares of our common stock valued at approximately $37.9 million based on the Company's share price on the closing date, and contingent consideration with an estimated fair value of $1.9 million. The contingent consideration consists of up to three earn-out payments of $1.6 million per year for each of 2022, 2023 and 2024, contingent upon the average monthly settlement price of WTI exceeding $70 per barrel for such year (the “2021 WTI Contingency Payout”). During the three months ended September 30, 2023 and 2022, the Company recorded losses of $0.9 million and gains of $0.7 million, respectively, and losses of $1.0 million and $0.8 million, respectively, for the nine months ended September 30, 2023 and 2022 related to the 2021 WTI Contingency Payout which are recorded in “Gain (loss) on commodity derivatives, net” on the consolidated statements of operations. We also recorded $1.6 million in earn-out consideration payable to the seller related to the 2022 calendar year in “Accounts payable and accrued liabilities” on the condensed consolidated balance sheet as of December 31, 2022. For further discussion of the fair value related to the Company's contingent consideration, refer to Note 9 of these Notes to Consolidated Financial Statements. Management determined that substantially all the fair value of the gross assets acquired were concentrated in the proved oil and gas properties and have therefore accounted for this transaction as an asset acquisition and allocated the purchase price based on the relative fair value of the assets acquired and liabilities assumed.
May 2022 Acquisition On May 10, 2022, the Company closed the acquisition of certain oil and gas assets located in La Salle and McMullen Counties, Texas, as well as assumed the seller's commodity derivative contracts in place at the closing date, from SandPoint Operating, LLC, a subsidiary of SandPoint Resources, LLC (collectively, “SandPoint”). After consideration of closing adjustments, total aggregate consideration was approximately $67.5 million, consisting of $27.7 million in cash and 1,300,000 shares of our common stock valued at approximately $39.8 million based on the Company's share price on the closing date. We incurred approximately $0.5 million in transaction costs during the year ended December 31, 2022 related to the acquisition. Management determined that substantially all the fair value of the gross assets acquired were concentrated in the proved oil and gas properties and have therefore accounted for this transaction as an asset acquisition and allocated the purchase price based on the relative fair value of the assets acquired and liabilities assumed. The following table represents the allocation of the total cost of the acquisition to the assets acquired and liabilities assumed (in thousands): | | | | | | | | | Total Cost | | | Cash consideration | | $ | 27,709 | | Equity consideration | | 39,767 | | Total Consideration | | 67,476 | | | | | Transaction costs | | 466 | | | | | Total Cost of Transaction | | $ | 67,942 | | | | | Allocation of Total Cost | | | Assets | | | Oil and gas properties | | $ | 84,810 | | Total assets | | 84,810 | | | | | Liabilities | | | Accounts payable and accrued liabilities | | 199 | | Fair value of commodity derivatives | | 16,511 | | Asset retirement obligations | | 158 | | Total Liabilities | | $ | 16,868 | | | | | Net Assets Acquired | | $ | 67,942 | |
June 2022 Acquisition On June 30, 2022, the Company closed the acquisition of certain oil and gas assets located in Atascosa, La Salle, Live Oak and McMullen Counties, Texas, as well as assumed the seller's commodity derivative contracts in place at the closing date, from Sundance Energy, Inc., and its affiliated entities Armadillo E&P, Inc. and SEA Eagle Ford, LLC (collectively, “Sundance”). After consideration of closing adjustments, total aggregate consideration was approximately $344.9 million, consisting of $220.9 million in cash, 4,148,472 shares of our common stock valued at approximately $117.7 million based on the Company's share price on the closing date, accrued purchase price adjustments receivable of $1.0 million and contingent consideration with an estimated fair value of $7.4 million. The contingent consideration consists of up to two earn-out payments of $7.5 million each, contingent upon the average monthly settlement price of NYMEX West Texas Intermediate crude oil exceeding $95 per barrel for the period from April 13, 2022 through December 31, 2022 which would trigger a payment of $7.5 million in 2023 and $85 per barrel for 2023 which would trigger a payment of $7.5 million in 2024 (the “2022 WTI Contingency Payout”). The contingent payout for the period of April 13, 2022 through December 31, 2022 did not materialize. During the nine months ended September 30, 2023, the Company recorded gains of $1.0 million related to valuation changes in the 2022 WTI Contingency Payout recorded in “Gain (loss) on commodity derivatives, net” on the accompanying condensed consolidated statements of operations. Additionally, as part of our post-close settlement we settled the 2022 WTI Contingency during the second quarter of 2023. As such, we recorded a non-cash gain of $1.1 million during the nine months ended September 30, 2023, and we are no longer required to make a contingency payment related to the 2022 WTI Contingency Payout. We incurred approximately $6.8 million in transaction costs during the year ended December 31, 2022 related to the acquisition. Management determined that substantially all the fair value of the gross assets acquired were concentrated in the proved oil and gas properties and have therefore accounted for this transaction as an asset acquisition and allocated the purchase price based on the relative fair value of the assets acquired and liabilities assumed. The following table represents the allocation of the total cost of the acquisition to the assets acquired and liabilities assumed (in thousands): | | | | | | | | | Total Cost | | | Cash consideration | | $ | 220,866 | | Equity consideration | | 117,651 | | Fair value of contingent consideration | | 7,422 | | Accrued purchase price adjustments receivable | | (1,000) | | Total Consideration | | 344,939 | | | | | Transaction costs | | 6,766 | | | | | Total Cost of Transaction | | $ | 351,705 | | | | | Allocation of Total Cost | | | Assets | | | Other current assets | | $ | 4,202 | | Oil and gas properties | | 397,401 | | Right of use assets | | 890 | | Total assets | | 402,493 | | | | | Liabilities | | | Accounts payable and accrued liabilities | | 13,687 | | Fair value of commodity derivatives | | 33,767 | | Non-current lease liability | | 890 | | Asset retirement obligations | | 2,444 | | Total Liabilities | | $ | 50,788 | | | | | Net Assets Acquired | | $ | 351,705 | |
August 2022 Acquisition On August 15, 2022, the Company closed the acquisition of certain oil and gas assets in Webb County, Texas. After consideration of closing adjustments, total consideration was approximately $31.2 million. We did not incur any significant transaction costs during the year ended December 31, 2022 related to the acquisition. Management determined that substantially all the fair value of the gross assets acquired were concentrated in the proved oil and gas properties and have therefore accounted for this transaction as an asset acquisition and allocated the purchase price based on the relative fair value of the assets acquired and liabilities assumed.
October 2022 Acquisition On October 31, 2022, the Company closed the acquisition of certain oil and gas assets in Dewitt and Gonzales Counties, Texas. After consideration of closing adjustments, total consideration was approximately $80.1 million. The acquisition is subject to further customary post-closing adjustments. We did not incur any significant transaction costs during the year ended December 31, 2022 related to the acquisition. Management determined that substantially all the fair value of the gross assets acquired were concentrated in the proved oil and gas properties and have therefore accounted for this transaction as an asset acquisition and allocated the purchase price based on the relative fair value of the assets acquired and liabilities assumed.
2022 Non-strategic Dispositions During 2022, the Company closed on multiple dispositions of non-strategic oil and gas assets. After consideration of closing adjustments, total proceeds from the dispositions were approximately $4.4 million. The transactions are subject to further customary post-closing adjustments. There was no gain or loss recognized in connection with the dispositions. 2023 Chesapeake Acquisition During the third quarter of 2023, SilverBow executed a purchase and sale agreement for the acquisition of certain oil and gas assets in South Texas from Chesapeake Energy Corporation (the “Chesapeake South Texas Rich Properties”) for a purchase price of $700 million, comprised of a $650 million cash payment at the closing date and a $50 million deferred cash payment due 12 months post-close, subject to customary purchase price adjustments (the “Chesapeake Transaction”) pursuant to the purchase and sale agreement, dated as of August 11, 2023, between SilverBow, SilverBow Resources Operating, LLC and the Chesapeake Sellers (the “Purchase Agreement”). Chesapeake may also receive up to $50 million in contingent cash consideration based on future commodity prices. SilverBow paid a $50 million cash deposit into escrow in conjunction with the Purchase Agreement recorded in “Deposit and other fees for oil and gas property transaction” on the accompanying condensed consolidated balance sheet.
The Purchase Agreement contains certain termination rights, including, but not limited to, each party’s right to terminate the Purchase Agreement in the event a material breach by the other party has occurred and is not waived on or before September 25, 2023, which date has passed, and in any event if the Chesapeake Transaction has not been consummated on or before November 24, 2023; provided that such date may be automatically extended for an additional 15 days to December 9, 2023, in the event certain approvals and consents have not been obtained by such date. The Chesapeake Transaction has an effective date of February 1, 2023, and is expected to close by year-end 2023, subject to satisfaction or waiver of certain customary closing conditions, including the accuracy of the representations and warranties of each party, compliance by each party in all material respects with its covenants and the satisfaction of certain consent requirements.
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- DefinitionThe entire disclosure for business combinations, including leverage buyout transactions (as applicable), and divestitures. This may include a description of a business combination or divestiture (or series of individually immaterial business combinations or divestitures) completed during the period, including background, timing, and assets and liabilities recognized and reclassified or sold. This element does not include fixed asset sales and plant closings.
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v3.23.3
Price-Risk Management Price-Risk Management (Notes)
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9 Months Ended |
Sep. 30, 2023 |
Derivative Instruments and Hedging Activities Disclosure [Abstract] |
|
Price-Risk Management Activities |
(8) Price-Risk Management Activities
Derivatives are recorded on the condensed consolidated balance sheet at fair value with changes in fair value recognized in earnings. The changes in the fair value of our derivatives are recognized in “Gain (loss) on commodity derivatives, net” on the accompanying condensed consolidated statements of operations. The Company's price-risk management policy is to use derivative instruments to protect against declines in oil and natural gas prices, primarily through the purchase of commodity price swaps and collars as well as basis swaps.
During the three months ended September 30, 2023 and 2022, the Company recorded losses of $53.7 million and losses of $1.3 million, respectively, on its commodity derivatives. During the nine months ended September 30, 2023 and 2022, the Company recorded gains of $56.5 million and losses of $162.5 million, respectively, on its commodity derivatives. During the three months ended September 30, 2023 and 2022, the Company recorded losses of $0.9 million and gains of $6.1 million, respectively, related to valuation changes on the 2021 WTI Contingency Payout and 2022 WTI Contingency Payout. During the nine months ended September 30, 2023 and 2022, the Company recorded gains of $1.1 million and gains of $4.7 million, respectively, related to valuation changes on the 2021 WTI Contingency Payout and 2022 WTI Contingency Payout. The Company collected cash payments of $70.7 million and made cash payments of $182.1 million for settled derivative contracts during the nine months ended September 30, 2023 and 2022, respectively.
At September 30, 2023 and December 31, 2022, there was $8.4 million and $6.9 million, respectively, in receivables for settled derivatives which were included on the accompanying condensed consolidated balance sheet in “Accounts receivable, net” and were subsequently collected in October 2023 and January 2023, respectively. At September 30, 2023 and December 31, 2022, we also had $3.5 million and $6.0 million, respectively, in payables for settled derivatives which were included on the accompanying condensed consolidated balance sheet in “Accounts payable and accrued liabilities” and were subsequently paid in October 2023 and January 2023, respectively.
The fair values of our swap contracts are computed using observable market data whereas our collar contracts are valued using a Black-Scholes pricing model. At September 30, 2023, there was $50.2 million and $14.2 million in current unsettled derivative assets and long-term unsettled derivative assets, respectively, and $32.8 million and $21.6 million in current and long-term unsettled derivative liabilities, respectively. At December 31, 2022, there was $52.5 million and $24.2 million in current and long-term unsettled derivative assets, respectively, and $40.8 million and $7.7 million in current and long-term unsettled derivative liabilities, respectively.
The Company uses an International Swap and Derivatives Association master agreement for our derivative contracts. This is an industry-standardized contract containing the general conditions of our derivative transactions including provisions relating to netting derivative settlement payments under certain circumstances (such as default). For reporting purposes, the Company has elected to not offset the asset and liability fair value amounts of its derivatives on the accompanying condensed consolidated balance sheet. Under the right of set-off, there was a $10.1 million net fair value asset at September 30, 2023, and a $28.2 million net fair value asset at December 31, 2022. For further discussion related to the fair value of the Company's derivatives, refer to Note 9 of these Notes to Condensed Consolidated Financial Statements. The following tables summarize the weighted-average prices as well as future production volumes for our future derivative contracts in place as of September 30, 2023: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Oil Derivative Contracts (NYMEX WTI Settlements) | | Total Volumes (Bbls) | | Weighted-Average Price | | Weighted-Average Collar Sub Floor Price | | Weighted-Average Collar Floor Price | | Weighted-Average Collar Call Price | Swap Contracts | | | | | | | | | | | 2023 Contracts | | | | | | | | | | | 4Q23 | | 707,300 | | | $ | 78.53 | | | | | | | | 2024 Contracts | | | | | | | | | | | 1Q24 | | 728,000 | | | $ | 77.67 | | | | | | | | 2Q24 | | 754,550 | | | $ | 77.59 | | | | | | | | 3Q24 | | 779,620 | | | $ | 76.48 | | | | | | | | 4Q24 | | 762,100 | | | $ | 76.16 | | | | | | | | 2025 Contracts | | | | | | | | | | | 1Q25 | | 666,000 | | | $ | 71.60 | | | | | | | | 2Q25 | | 673,400 | | | $ | 71.60 | | | | | | | | 3Q25 | | 680,800 | | | $ | 71.60 | | | | | | | | 4Q25 | | 588,800 | | | $ | 71.29 | | | | | | | | 2026 Contracts | | | | | | | | | | | 1Q26 | | 315,000 | | | $ | 69.40 | | | | | | | | 2Q26 | | 318,500 | | | $ | 69.40 | | | | | | | | 3Q26 | | 322,000 | | | $ | 69.40 | | | | | | | | 4Q26 | | 230,000 | | | $ | 69.42 | | | | | | | | Collar Contracts | | | | | | | | | | | 2023 Contracts | | | | | | | | | | | 4Q23 | | 302,242 | | | | | | | $ | 65.89 | | | $ | 74.54 | | 2024 Contracts | | | | | | | | | | | 1Q24 | | 319,700 | | | | | | | $ | 58.95 | | | $ | 71.74 | | 2Q24 | | 215,000 | | | | | | | $ | 61.08 | | | $ | 73.57 | | 3Q24 | | 184,000 | | | | | | | $ | 63.50 | | | $ | 75.53 | | 4Q24 | | 184,000 | | | | | | | $ | 63.00 | | | $ | 75.35 | | 2025 Contracts | | | | | | | | | | | 1Q25 | | 238,500 | | | | | | | $ | 64.00 | | | $ | 74.62 | | 2Q25 | | 227,500 | | | | | | | $ | 60.80 | | | $ | 72.22 | | 2026 Contracts | | | | | | | | | | | 1Q26 | | 90,000 | | | | | | | $ | 64.00 | | | $ | 71.50 | | 2Q26 | | 91,000 | | | | | | | $ | 64.00 | | | $ | 71.50 | | 3Q26 | | 92,000 | | | | | | | $ | 64.00 | | | $ | 71.50 | | 3-Way Collar Contracts | | | | | | | | | | | 2023 Contracts | | | | | | | | | | | 4Q23 | | 8,970 | | | | | $ | 43.08 | | | $ | 53.38 | | | $ | 63.35 | | 2024 Contracts | | | | | | | | | | | 1Q24 | | 8,247 | | | | | $ | 45.00 | | | $ | 57.50 | | | $ | 67.85 | | 2Q24 | | 7,757 | | | | | $ | 45.00 | | | $ | 57.50 | | | $ | 67.85 | |
| | | | | | | | | | | | | | | Oil Basis Swaps (Argus Cushing (WTI) and Magellan East Houston) | | Total Volumes (MMBtu) | | Weighted-Average Price | 2023 Contracts | | | | | 4Q23 | | 122,000 | | | $ | 0.80 | | 2024 Contracts | | | | | 1Q24 | | 364,000 | | | $ | 1.47 | | 2Q24 | | 364,000 | | | $ | 1.47 | | 3Q24 | | 368,000 | | | $ | 1.47 | | 4Q24 | | 368,000 | | | $ | 1.47 | | 2025 Contracts | | | | | 1Q25 | | 270,000 | | | $ | 1.75 | | 2Q25 | | 273,000 | | | $ | 1.75 | | 3Q25 | | 276,000 | | | $ | 1.75 | | 4Q25 | | 276,000 | | | $ | 1.75 | | Calendar Monthly Roll Differential Swaps | | | | | 2023 Contracts | | | | | 4Q23 | | 122,000 | | | $ | 2.44 | | 2024 Contracts | | | | | 1Q24 | | 364,000 | | | $ | 0.69 | | 2Q24 | | 364,000 | | | $ | 0.69 | | 3Q24 | | 368,000 | | | $ | 0.69 | | 4Q24 | | 368,000 | | | $ | 0.69 | | 2025 Contracts | | | | | 1Q25 | | 270,000 | | | $ | 0.40 | | 2Q25 | | 273,000 | | | $ | 0.40 | | 3Q25 | | 276,000 | | | $ | 0.40 | | 4Q25 | | 276,000 | | | $ | 0.40 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Natural Gas Derivative Contracts (NYMEX Henry Hub Settlements) | | Total Volumes (MMBtu) | | Weighted-Average Price | | Weighted-Average Collar Sub Floor Price | | Weighted-Average Collar Floor Price | | Weighted-Average Collar Call Price | Swap Contracts | | | | | | | | | | | 2023 Contracts | | | | | | | | | | | 4Q23 | | 5,727,000 | | | $ | 4.20 | | | | | | | | 2024 Contracts | | | | | | | | | | | 1Q24 | | 7,686,000 | | | $ | 4.12 | | | | | | | | 2Q24 | | 12,350,000 | | | $ | 3.67 | | | | | | | | 3Q24 | | 12,420,000 | | | $ | 3.78 | | | | | | | | 4Q24 | | 12,420,000 | | | $ | 4.12 | | | | | | | | 2025 Contracts | | | | | | | | | | | 1Q25 | | 9,450,000 | | | $ | 4.25 | | | | | | | | 2Q25 | | 9,555,000 | | | $ | 3.71 | | | | | | | | 3Q25 | | 11,960,000 | | | $ | 3.83 | | | | | | | | 4Q25 | | 8,740,000 | | | $ | 4.17 | | | | | | | | 2026 Contracts | | | | | | | | | | | 1Q26 | | 9,680,000 | | | $ | 4.48 | | | | | | | | 2Q26 | | 9,555,000 | | | $ | 3.56 | | | | | | | | 3Q26 | | 9,660,000 | | | $ | 3.74 | | | | | | | | 4Q26 | | 9,200,000 | | | $ | 4.13 | | | | | | | | Collar Contracts | | | | | | | | | | | 2023 Contracts | | | | | | | | | | | 4Q23 | | 12,445,000 | | | | | | | $ | 3.87 | | | $ | 4.80 | | 2024 Contracts | | | | | | | | | | | 1Q24 | | 9,661,000 | | | | | | | $ | 3.94 | | | $ | 5.83 | | 2Q24 | | 4,643,000 | | | | | | | $ | 3.64 | | | $ | 4.28 | | 3Q24 | | 3,878,000 | | | | | | | $ | 3.77 | | | $ | 4.76 | | 4Q24 | | 3,865,000 | | | | | | | $ | 4.01 | | | $ | 5.34 | | 2025 Contracts | | | | | | | | | | | 1Q25 | | 5,130,000 | | | | | | | $ | 4.00 | | | $ | 5.32 | | 2Q25 | | 4,914,000 | | | | | | | $ | 3.25 | | | $ | 3.98 | | 3Q25 | | 920,000 | | | | | | | $ | 3.50 | | | $ | 3.99 | | 4Q25 | | 920,000 | | | | | | | $ | 3.75 | | | $ | 4.65 | | 3-Way Collar Contracts | | | | | | | | | | | 2023 Contracts | | | | | | | | | | | 4Q23 | | 219,200 | | | | | $ | 2.00 | | | $ | 2.50 | | | $ | 2.94 | | 2024 Contracts | | | | | | | | | | | 1Q24 | | 198,000 | | | | | $ | 2.00 | | | $ | 2.50 | | | $ | 3.37 | | 2Q24 | | 188,000 | | | | | $ | 2.00 | | | $ | 2.50 | | | $ | 3.37 | |
| | | | | | | | | | | | | | | Natural Gas Basis Derivative Swaps (East Texas Houston Ship Channel vs. NYMEX Settlements) | | Total Volumes (MMBtu) | | Weighted-Average Price | 2023 Contracts | | | | | 4Q23 | | 13,800,000 | | | $ | (0.23) | | 2024 Contracts | | | | | 1Q24 | | 15,470,000 | | | $ | (0.02) | | 2Q24 | | 15,470,000 | | | $ | (0.29) | | 3Q24 | | 15,640,000 | | | $ | (0.26) | | 4Q24 | | 15,640,000 | | | $ | (0.28) | | 2025 Contracts | | | | | 1Q25 | | 5,400,000 | | | $ | (0.09) | | 2Q25 | | 5,460,000 | | | $ | (0.26) | | 3Q25 | | 5,520,000 | | | $ | (0.23) | | 4Q25 | | 5,520,000 | | | $ | (0.25) | |
| | | | | | | | | | | | | | | NGL Swaps (Mont Belvieu) | | Total Volumes (Bbls) | | Weighted-Average Price | 2023 Contracts | | | | | 4Q23 | | 345,000 | | | $ | 32.87 | | 2024 Contracts | | | | | 1Q24 | | 400,400 | | | $ | 26.30 | | 2Q24 | | 400,400 | | | $ | 26.30 | | 3Q24 | | 404,800 | | | $ | 26.30 | | 4Q24 | | 404,800 | | | $ | 26.30 | | 2025 Contracts | | | | | 1Q25 | | 270,000 | | | $ | 24.17 | | 2Q25 | | 273,000 | | | $ | 24.17 | | 3Q25 | | 276,000 | | | $ | 24.17 | | 4Q25 | | 276,000 | | | $ | 24.17 | |
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- DefinitionThe entire disclosure for derivatives and fair value of assets and liabilities.
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v3.23.3
Fair Value Measurements
|
9 Months Ended |
Sep. 30, 2023 |
Fair Value Disclosures [Abstract] |
|
Fair Value Measurements |
(9) Fair Value Measurements
Fair Value on a Recurring Basis. Our financial instruments consist of cash and cash equivalents, accounts receivable, accounts payable, derivatives, the Credit Facility and the Second Lien notes. The carrying amounts of cash and cash equivalents, accounts receivable, and accounts payable approximate fair value due to the highly liquid or short-term nature of these instruments.
The fair values of our derivative contracts are computed using observable market data whereas our derivative collar contracts are valued using a Black-Scholes pricing model. The fair value of the current and long-term 2021 WTI Contingency Payout and 2022 WTI Contingency Payout, included within “Accounts payable and accrued liabilities” and “Other long-term liabilities” on the condensed consolidated balance sheets, respectively, is estimated using observable market data and a Monte Carlo pricing model. These are considered Level 2 valuations (defined below).
The carrying value of our Credit Facility and Second Lien approximates fair value because the respective borrowing rates do not materially differ from market rates for similar borrowings. These are considered Level 3 valuations (defined below).
Fair Value on a Nonrecurring Basis. The Company applies the provisions of the fair value measurement standard on a non-recurring basis to its non-financial assets and liabilities, including oil and gas properties acquired and assessed for classification as a business or an asset and asset retirement obligations. These assets and liabilities are not measured at fair value on an ongoing basis but are subject to fair value estimation when acquisitions occur or asset retirement obligations are recorded. These are considered Level 3 valuations (defined below). Asset retirement obligations. The initial measurement of asset retirement obligations (“ARO”) at fair value is recorded in the period in which the liability is incurred. Fair value is determined by calculating the present value of estimated future cash flows related to the liability. Estimating the future ARO requires management to make estimates and judgments regarding the timing and existence of a liability, as well as what constitutes adequate restoration when considering current regulatory requirements. Inherent in the fair value calculation are numerous assumptions and judgments, including the ultimate costs, inflation factors, credit-adjusted discount rates, timing of settlement and changes in the legal, regulatory, environmental and political environments.
Acquisitions. The Company recognized the assets acquired in our acquisitions at cost at a relative fair value basis (refer to Note 7 of these Notes to Consolidated Financial Statements). Fair value was determined using a discounted cash flow model. The underlying future commodity prices included in the Company’s estimated future cash flows of its proved oil and gas properties were determined using NYMEX forward strip prices as of the closing date of each acquisition. The estimated future cash flows also included management’s assumptions for the estimates of production from the crude oil and natural gas proved properties, future operating, development costs and income taxes of the acquired properties and risk adjusted discount rates.
The fair value hierarchy has three levels based on the reliability of the inputs used to determine the fair value:
Level 1 – Uses quoted prices in active markets for identical, unrestricted assets or liabilities. Instruments in this category have comparable fair values for identical instruments in active markets.
Level 2 – Uses quoted prices for similar assets or liabilities in active markets or observable inputs for assets or liabilities in non-active markets. Instruments in this category are periodically verified against quotes from brokers and include our commodity derivatives that we value using commonly accepted industry-standard models which contain inputs such as contract prices, risk-free rates, volatility measurements and other observable market data that are obtained from independent third-party sources.
Level 3 – Uses unobservable inputs for assets or liabilities that are in non-active markets. The following table presents our assets and liabilities that are measured on a recurring basis at fair value as of each of September 30, 2023 and December 31, 2022, and are categorized using the fair value hierarchy. For additional discussion related to the fair value of the Company's derivatives, refer to Note 8 of these Notes to Condensed Consolidated Financial Statements.
| | | | | | | | | | | | | | | | | | | | | | | | | Fair Value Measurements at | (in thousands) | Total | | Quoted Prices in Active markets for Identical Assets (Level 1) | | Significant Other Observable Inputs (Level 2) | | Significant Unobservable Inputs (Level 3) | September 30, 2023 | | | | | | | | Assets | | | | | | | | Natural Gas Derivatives | $ | 53,032 | | | $ | — | | | $ | 53,032 | | | $ | — | | Natural Gas Basis Derivatives | 5,395 | | | — | | | 5,395 | | | — | | Oil Derivatives | 418 | | | — | | | 418 | | | — | | Oil Basis Derivatives | 254 | | | — | | | 254 | | | — | | NGL Derivatives | 5,270 | | | — | | | 5,270 | | | — | | Liabilities | | | | | | | | Natural Gas Derivatives | 5,346 | | | — | | | 5,346 | | | — | | Natural Gas Basis Derivatives | 5,415 | | | — | | | 5,415 | | | — | | Oil Derivatives | 41,908 | | | — | | | 41,908 | | | — | | Oil Basis Derivatives | 858 | | | — | | | 858 | | | — | | NGL Derivatives | 785 | | | — | | | 785 | | | — | | 2021 WTI Contingency Payout | 2,459 | | | — | | | 2,459 | | | — | | | | | | | | | | December 31, 2022 | | | | | | | | Assets | | | | | | | | Natural Gas Derivatives | $ | 25,960 | | | $ | — | | | $ | 25,960 | | | $ | — | | Natural Gas Basis Derivatives | 26,023 | | | — | | | 26,023 | | | — | | Oil Derivatives | 14,604 | | | — | | | 14,604 | | | — | | NGL Derivatives | 10,134 | | | — | | | 10,134 | | | — | | Liabilities | | | | | | | | Natural Gas Derivatives | 28,579 | | | — | | | 28,579 | | | — | | Natural Gas Basis Derivatives | 409 | | | — | | | 409 | | | — | | Oil Derivatives | 19,442 | | | — | | | 19,442 | | | — | | NGL Derivatives | 104 | | | — | | | 104 | | | — | | 2022 WTI Contingency Payout | 2,135 | | | — | | | 2,135 | | | — | | 2021 WTI Contingency Payout | 1,453 | | | — | | | 1,453 | | | — | |
Our current and long-term unsettled derivative assets and liabilities in the table above are measured at gross fair value and are shown on the accompanying condensed consolidated balance sheets in “Fair value of commodity derivatives” and “Fair Value of Long-Term Commodity Derivatives,” respectively.
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v3.23.3
Asset Retirement Obligations Asset Retirement Obligations (Notes)
|
9 Months Ended |
Sep. 30, 2023 |
Asset Retirement Obligation Disclosure [Abstract] |
|
Asset Retirement Obligations |
(10) Asset Retirement Obligations
Liabilities for legal obligations associated with the retirement obligations of tangible long-lived assets are initially recorded at fair value in the period in which they are incurred. Estimates for the initial recognition of asset retirement obligations are derived from historical costs as well as management's expectation of future cost environments and other unobservable inputs. As there is no corroborating market activity to support the assumptions used, the Company has designated these liabilities as Level 3 fair value measurements. When a liability is initially recorded, the carrying amount of the related asset is increased. The liability is discounted from the expected date of abandonment. Over time, accretion of the liability is recognized each period, and the capitalized cost is amortized on a unit-of-production basis as part of depreciation, depletion, and amortization expense for our oil and gas properties. Upon settlement of the liability, the Company either settles the obligation for its recorded amount or incurs a gain or loss upon settlement which is included in the “Property and Equipment” balance on our accompanying condensed consolidated balance sheets.
The following provides a roll-forward of our asset retirement obligations for the year ended December 31, 2022 and the nine months ended September 30, 2023 (in thousands): | | | | | | Asset Retirement Obligations as of December 31, 2021 | $ | 6,050 | | Accretion expense | 534 | | Liabilities incurred for new wells, acquired wells and facilities construction | 3,032 | | Reductions due to sold wells and facilities | (57) | | Reductions due to plugged wells and facilities | (22) | | Revisions in estimates | 919 | | Asset Retirement Obligations as of December 31, 2022 | $ | 10,456 | | Accretion expense | 718 | | Liabilities incurred for new wells, acquired wells and facilities construction | 313 | | | | Reductions due to plugged wells and facilities | (603) | | Revisions in estimates | 534 | | Asset Retirement Obligations as of September 30, 2023 | $ | 11,418 | |
At September 30, 2023 and December 31, 2022, approximately $1.6 million and $1.3 million of our asset retirement obligations, respectively, were classified as a current liability in “Accounts payable and accrued liabilities” on the accompanying condensed consolidated balance sheets.
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- DefinitionThe entire disclosure for an asset retirement obligation and the associated long-lived asset. An asset retirement obligation is a legal obligation associated with the disposal or retirement from service of a tangible long-lived asset that results from the acquisition, construction or development, or the normal operations of a long-lived asset, except for certain obligations of lessees.
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v3.23.3
Commitments and Contingencies Commitments and Contingencies
|
9 Months Ended |
Sep. 30, 2023 |
Commitments and Contingencies Disclosure [Abstract] |
|
Commitments and Contingencies |
(11) Commitments and Contingencies
In the ordinary course of business, we are party to various legal actions, which arise primarily from our activities as an operator of oil and natural gas wells. In our management's opinion, the outcome of any such currently pending legal actions will not have a material adverse effect on our financial position or results of operations. During the second quarter of 2023, the Company entered into gas throughput agreements with separate parties in our Webb County gas area. The agreements provide for an annual average firm capacity of approximately 116,000 MMBtu/d over an eight-year term.
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- DefinitionThe entire disclosure for commitments and contingencies.
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v3.23.3
Summary of Significant Accounting Policies (Policies)
|
9 Months Ended |
Sep. 30, 2023 |
Accounting Policies [Abstract] |
|
Principles of Consolidation |
Principles of Consolidation. The accompanying condensed consolidated financial statements include the accounts of SilverBow and its wholly owned subsidiary, SilverBow Resources Operating LLC, which are engaged in the exploration, development, acquisition, and operation of oil and gas properties, with a focus on oil and natural gas reserves in the Eagle Ford and Austin Chalk trend in Texas. Our undivided interests in oil and gas properties are accounted for using the proportionate consolidation method, whereby our proportionate share of the assets, liabilities, revenues, and expenses are included in the appropriate classifications in the accompanying condensed consolidated financial statements. Intercompany balances and transactions have been eliminated in preparing the accompanying condensed consolidated financial statements.
|
Use of Estimates |
Use of Estimates. The preparation of financial statements in conformity with GAAP requires us to make estimates and assumptions that affect the reported amounts of certain assets and liabilities and the reported amounts of certain revenues and expenses during each reporting period. Such estimates and assumptions are subject to a number of risks and uncertainties that may cause actual results to differ materially from such estimates. Significant estimates and assumptions underlying these financial statements include: •the estimated quantities of proved oil and natural gas reserves used to compute depletion of oil and natural gas properties, the related present value of estimated future net cash flows therefrom, and the Ceiling Test impairment calculation, •estimates related to the collectability of accounts receivable and the creditworthiness of our customers, •estimates of the counterparty bank risk related to letters of credit that our customers may have issued on our behalf, •estimates of future costs to develop and produce reserves, •accruals related to oil and gas sales, capital expenditures and lease operating expenses (“LOE”), •estimates in the calculation of share-based compensation expense, •estimates of our ownership in properties prior to final division of interest determination, •the estimated future cost and timing of asset retirement obligations, •estimates made in our income tax calculations, including the valuation of our deferred tax assets, •estimates in the calculation of the fair value of commodity derivative assets and liabilities, •estimates in the assessment of current litigation claims against the Company, •estimates used in the assessment of business combinations and asset purchases, •estimates in amounts due with respect to open state regulatory audits, and •estimates on future lease obligations.
While we are not currently aware of any material revisions to any of our estimates, there will likely be future revisions to our estimates resulting from matters such as new accounting pronouncements, changes in ownership interests, payouts, joint venture audits, reallocations by purchasers or pipelines, or other corrections and adjustments common in the oil and gas industry, many of which relate to prior periods. These types of adjustments cannot be currently estimated and are expected to be recorded in the period during which the adjustments are known.
We are subject to legal proceedings, claims, liabilities and environmental matters that arise in the ordinary course of business. We accrue for losses when such losses are considered probable and the amounts can be reasonably estimated.
|
Property and Equipment |
Property and Equipment. We follow the “full-cost” method of accounting for oil and natural gas property and equipment costs. Under this method of accounting, all productive and nonproductive costs incurred in the exploration, development, and acquisition of oil and natural gas reserves are capitalized. Such costs may be incurred both prior to and after the acquisition of a property and include lease acquisitions, geological and geophysical services, drilling, completion, and equipment. Internal costs incurred that are directly identified with exploration, development, and acquisition activities undertaken by us for our own account, and which are not related to production, general corporate overhead, or similar activities, are also capitalized. For the three months ended September 30, 2023 and 2022, such internal costs capitalized totaled $1.4 million and $1.1 million, respectively. For the nine months ended September 30, 2023 and 2022, such internal costs capitalized totaled $4.1 million and $3.3 million, respectively. Interest costs are also capitalized to unproved oil and natural gas properties. There was no capitalized interest on our unproved properties for both the three months ended September 30, 2023 and 2022 and the nine months ended September 30, 2023 and 2022.
The “Property and Equipment” balances on the accompanying condensed consolidated balance sheets are summarized for presentation purposes. The following is a detailed breakout of our “Property and Equipment” balances (in thousands): | | | | | | | | | | | | | September 30, 2023 | | December 31, 2022 | Property and Equipment | | | | Proved oil and gas properties | $ | 2,827,145 | | | $ | 2,506,853 | | Unproved oil and gas properties | 27,821 | | | 16,272 | | Furniture, fixtures and other equipment | 6,301 | | | 6,098 | | Less – Accumulated depreciation, depletion, amortization & impairment | (1,151,141) | | | (1,004,044) | | Property and Equipment, Net | $ | 1,710,126 | | | $ | 1,525,179 | |
No gains or losses are recognized upon the sale or disposition of oil and natural gas properties, except in transactions involving a significant amount of reserves or where the proceeds from the sale of oil and natural gas properties would significantly alter the relationship between capitalized costs and proved reserves of oil and natural gas attributable to a cost center. Internal costs associated with selling properties are expensed as incurred. We compute the provision for depreciation, depletion and amortization (“DD&A”) of oil and natural gas properties using the unit-of-production method. Under this method, we compute the provision by multiplying the total unamortized costs of oil and natural gas properties, including future development costs, gas processing facilities, and both capitalized asset retirement obligations and undiscounted abandonment costs of wells to be drilled, net of salvage values, but excluding costs of unproved properties, by an overall rate determined by dividing the physical units of oil and natural gas produced (which excludes natural gas consumed in operations) during the period by the total estimated units of proved oil and natural gas reserves (which excludes natural gas consumed in operations) at the beginning of the period. Future development costs are estimated on a property-by-property basis based on current economic conditions. The period over which we will amortize these properties is dependent on our production from these properties in future years. Furniture, fixtures and other equipment are recorded at cost and are depreciated by the straight-line method at rates based on the estimated useful lives of the property, which range between two and 20 years. Repairs and maintenance are charged to expense as incurred.
Geological and geophysical (“G&G”) costs incurred on developed properties are recorded in “Proved oil and gas properties” and therefore subject to amortization. G&G costs incurred that are associated with unproved properties are capitalized in “Unproved oil and gas properties” and evaluated as part of the total capitalized costs associated with a prospect. The cost of unproved properties not being amortized is assessed quarterly, on a property-by-property basis, to determine whether such properties have been impaired. In determining whether such costs should be impaired, we evaluate current drilling results, lease expiration dates, current oil and gas industry conditions, economic conditions, capital availability and available geological and geophysical information. Any impairment assessed is added to the cost of proved properties being amortized.
|
Full-Cost Ceiling Test |
Full-Cost Ceiling Test. At the end of each quarterly reporting period, the unamortized cost of oil and natural gas properties (including natural gas processing facilities, capitalized asset retirement obligations, net of related salvage values and deferred income taxes) is limited to the sum of the estimated future net revenues from proved properties (excluding cash outflows from recognized asset retirement obligations, including future development and abandonment costs of wells to be drilled, using the preceding 12-months’ average price based on closing prices on the first day of each month, adjusted for price differentials, discounted at 10% and the lower of cost or fair value of unproved properties) adjusted for related income tax effects (“Ceiling Test”).The quarterly calculations of the Ceiling Test and provision for DD&A are based on estimates of proved reserves. There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting the future rates of production, timing and plan of development. The accuracy of any reserves estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Results of drilling, testing, and production subsequent to the date of the estimate may justify revision of such estimates. Accordingly, reserves estimates are often different from the quantities of oil and natural gas that are ultimately recovered.
|
Accounts Receivable, Net |
Accounts Receivable, Net. We assess the collectability of accounts receivable based on a broad range of reasonable and forward-looking information including historical losses, current economic conditions, future forecasts and contractual terms. The Company's credit losses based on these assessments are considered immaterial. At September 30, 2023, December 31, 2022 and December 31, 2021, we had an allowance of less than $0.1 million. The allowance has been deducted from the total “Accounts receivable, net” balance on the accompanying condensed consolidated balance sheets.
|
Supervision Fees |
Supervision Fees. Consistent with industry practice, we charge a supervision fee to the wells we operate, including our wells, in which we own up to a 100% working interest. Supervision fees are recorded as a reduction to “General and administrative, net,” on the accompanying condensed consolidated statements of operations.
|
Income Taxes |
Income Taxes. Deferred taxes are determined based on the estimated future tax effects of differences between the financial statement and tax basis of assets and liabilities, given the provisions of the enacted tax laws. The Company's effective tax rate was approximately 17% and 4% for the three months ended September 30, 2023 and 2022, respectively, and 22% and 4% for the nine months ended September 30, 2023 and 2022, respectively. The Company recorded an income tax benefit of $0.9 million and income tax provision of $33.2 million for the three and nine months ended September 30, 2023, respectively, and an income tax provision of $6.1 million and $7.7 million for the three and nine months ended September 30, 2022, respectively. The tax impact for both periods was a product of the overall forecasted annual effective tax rate applied to the year to date income.
Section 382 of the Internal Revenue Code (“Section 382”) imposes limitations on a corporation’s ability to utilize its net operating losses (“NOLs”) if it experiences an ownership change. Generally, an “ownership change” occurs if one or more shareholders, each of whom is deemed to own five percent or more in value of a corporation’s stock, increase their aggregate percentage ownership by more than 50 percent over the lowest percentage of stock owned by those shareholders at any time during the preceding three-year period. In the event of an ownership change, utilization of the NOLs would be subject to an annual limitation under Section 382. We believe we had an ownership change in August 2022 and, therefore, are subject to an annual limitation on the usage of our NOLs generated prior to the ownership change. However, we do not expect to have any of our NOLs expire before becoming available to be utilized by the Company. Management will continue to monitor the potential impact of Section 382 with respect to our NOLs.
Our policy is to record interest and penalties relating to uncertain tax positions in income tax expense. At September 30, 2023 and December 31, 2022, we did not have any accrued liability for uncertain tax positions and do not anticipate recognition of any significant liabilities for uncertain tax positions during the next 12 months.
|
Revenue Recognition |
Revenue Recognition. Our reported oil and gas sales are comprised of revenues from oil, natural gas and natural gas liquids (“NGLs”) sales. Revenues from each product stream are recognized at the point when control of the product is transferred to the customer and collectability is reasonably assured. Prices for our products are either negotiated on a monthly basis or tied to market indices. The Company has determined that these contracts represent performance obligations which are satisfied when control of the commodity transfers to the customer, typically through the delivery of the specified commodity to a designated delivery point. Natural gas revenues are recognized based on the actual volume of natural gas sold to the purchasers.
|
Accounts Payable and Accrued Liabilities |
Accounts Payable and Accrued Liabilities. The “Accounts payable and accrued liabilities” balances on the accompanying condensed consolidated balance sheets are summarized below (in thousands): | | | | | | | | | | | | | September 30, 2023 | | December 31, 2022 | Trade accounts payable | $ | 30,708 | | | $ | 23,660 | | Accrued operating expenses | 11,266 | | | 10,572 | | Accrued compensation costs | 3,267 | | | 4,814 | | Asset retirement obligations – current portion | 1,578 | | | 1,284 | | Accrued non-income based taxes | 13,303 | | | 4,849 | | Accrued corporate and legal fees | 181 | | | 388 | | WTI contingency payouts - current portion | 1,537 | | | 1,600 | | Payable for settled derivatives | 3,549 | | | 6,026 | | Other payables | 9,342 | | | 7,007 | | Total accounts payable and accrued liabilities | $ | 74,731 | | | $ | 60,200 | |
|
Cash and Cash Equivalents, Restricted Cash and Cash Equivalents, Policy |
Cash and Cash Equivalents. We consider all highly liquid instruments with an initial maturity of three months or less to be cash equivalents. These amounts do not include cash balances that are contractually restricted. The Company maintains cash and cash equivalent balances with major financial institutions, which at times exceed federally insured limits. The Company monitors the financial condition of the financial institutions and has experienced no losses associated with these accounts.
|
Treasury Stock |
Treasury Stock. Our treasury stock repurchases are reported at cost and are included in “Treasury stock, held at cost” on the accompanying condensed consolidated balance sheets.
|
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v3.23.3
Leases Leases (Policies)
|
9 Months Ended |
Sep. 30, 2023 |
Leases [Abstract] |
|
Lessee, Leases [Policy Text Block] |
Leases The Company follows the FASB's Accounting Standards Codification Topic No. 842 and elected the package of practical expedients that allows an entity to carry forward historical accounting treatment relating to lease identification and classification for existing leases upon adoption and the practical expedient related to land easements that allows an entity to carry forward historical accounting treatment for land easements on existing agreements. The Company has made an accounting policy election to keep leases with an initial term of 12 months or less off the condensed consolidated balance sheets. We have elected to not account for lease and non-lease components separately. The Company has contractual agreements for its corporate office lease, vehicle fleet, compressors, treating equipment, and for surface use rights. For leases with a primary term of more than 12 months, a right-of-use (“ROU”) asset and the corresponding lease liability is recorded. The Company determines at inception if an arrangement is an operating or financing lease. As of September 30, 2023, all of the Company’s leases were operating leases.
The initial asset and liability balances are recorded at the present value of the payment obligations over the lease term. If lease terms include options to extend the lease and it is reasonably certain that the Company will exercise that option, the lease term used for capitalization includes the expected renewal periods. Most leases do not provide an implicit interest rate. Unless the lease contract contains an implicit interest rate, the Company uses its incremental borrowing rate at the time of lease inception to compute the fair value of the lease payments. The ROU asset balance and current and non-current lease liabilities are reported separately on the accompanying condensed consolidated balance sheets. Certain leases have payment terms that vary based on the usage of the underlying assets. Variable lease payments are not included in ROU assets and lease liabilities. The Company recognizes lease expense on a straight-line basis over the lease term.
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v3.23.3
Share-Based Compensation Share-Based Compensation (Policies)
|
9 Months Ended |
Sep. 30, 2023 |
Share-Based Payment Arrangement [Abstract] |
|
Share-based Compensation, Option and Incentive Plans Policy |
Share-Based Compensation Share-Based Compensation Plans
In 2016, the Company adopted the 2016 Equity Incentive Plan (as amended from time to time, the “2016 Plan”). The Company also adopted the Inducement Plan (as amended from time to time, the “Inducement Plan,” and, together with the 2016 Plan, the “Plans”) on December 15, 2016. The Company computes a deferred tax benefit for restricted stock units (“RSUs”), performance-based stock units (“PSUs”) and stock options expected to generate future tax deductions by applying its effective tax rate to the expense recorded. For RSUs, the Company's actual tax deduction is based on the value of the units at the time of vesting.
|
X |
- DefinitionDisclosure of accounting policy for award under share-based payment arrangement. Includes, but is not limited to, methodology and assumption used in measuring cost.
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v3.23.3
Earnings Per Share Earnings Per Share (Policies)
|
9 Months Ended |
Sep. 30, 2023 |
Earnings Per Share [Abstract] |
|
Earnings Per Share, Policy |
Earnings Per ShareBasic earnings per share (“Basic EPS”) has been computed using the weighted-average number of common shares outstanding during each period. Diluted earnings per share (“Diluted EPS”) assumes, as of the beginning of the period, exercise of stock options and RSU grants using the treasury stock method. Diluted EPS also assumes conversion of PSUs to common shares based on the number of shares (if any) that would be issuable, according to predetermined performance and market goals, if the end of the reporting period was the end of the performance period. Certain of our stock options and RSU grants that would potentially dilute Basic EPS in the future were also antidilutive for the three and nine months ended September 30, 2023 and 2022 are discussed below.
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v3.23.3
Long-Term Debt Long-Term Debt (Policies)
|
9 Months Ended |
Sep. 30, 2023 |
Debt Disclosure [Abstract] |
|
Debt Issuance Costs, Policy |
Debt Issuance Costs. Our policy is to capitalize upfront commitment fees and other direct expenses associated with our line of credit arrangement and then amortize such costs ratably over the term of the arrangement, regardless of whether there are any outstanding borrowings.
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v3.23.3
Price-Risk Management Price-Risk Management (Policies)
|
9 Months Ended |
Sep. 30, 2023 |
Derivative Instruments and Hedging Activities Disclosure [Abstract] |
|
Price-Risk Management Activities, Policy |
Price-Risk Management ActivitiesDerivatives are recorded on the condensed consolidated balance sheet at fair value with changes in fair value recognized in earnings. The changes in the fair value of our derivatives are recognized in “Gain (loss) on commodity derivatives, net” on the accompanying condensed consolidated statements of operations. The Company's price-risk management policy is to use derivative instruments to protect against declines in oil and natural gas prices, primarily through the purchase of commodity price swaps and collars as well as basis swaps.
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v3.23.3
Fair Value Measurements Fair Value Disclosures (Policies)
|
9 Months Ended |
Sep. 30, 2023 |
Fair Value Disclosures [Abstract] |
|
Fair Value of Financial Instruments, Policy |
Fair Value Measurements Fair Value on a Recurring Basis. Our financial instruments consist of cash and cash equivalents, accounts receivable, accounts payable, derivatives, the Credit Facility and the Second Lien notes. The carrying amounts of cash and cash equivalents, accounts receivable, and accounts payable approximate fair value due to the highly liquid or short-term nature of these instruments.
The fair values of our derivative contracts are computed using observable market data whereas our derivative collar contracts are valued using a Black-Scholes pricing model. The fair value of the current and long-term 2021 WTI Contingency Payout and 2022 WTI Contingency Payout, included within “Accounts payable and accrued liabilities” and “Other long-term liabilities” on the condensed consolidated balance sheets, respectively, is estimated using observable market data and a Monte Carlo pricing model. These are considered Level 2 valuations (defined below).
The carrying value of our Credit Facility and Second Lien approximates fair value because the respective borrowing rates do not materially differ from market rates for similar borrowings. These are considered Level 3 valuations (defined below).
Fair Value on a Nonrecurring Basis. The Company applies the provisions of the fair value measurement standard on a non-recurring basis to its non-financial assets and liabilities, including oil and gas properties acquired and assessed for classification as a business or an asset and asset retirement obligations. These assets and liabilities are not measured at fair value on an ongoing basis but are subject to fair value estimation when acquisitions occur or asset retirement obligations are recorded. These are considered Level 3 valuations (defined below). Asset retirement obligations. The initial measurement of asset retirement obligations (“ARO”) at fair value is recorded in the period in which the liability is incurred. Fair value is determined by calculating the present value of estimated future cash flows related to the liability. Estimating the future ARO requires management to make estimates and judgments regarding the timing and existence of a liability, as well as what constitutes adequate restoration when considering current regulatory requirements. Inherent in the fair value calculation are numerous assumptions and judgments, including the ultimate costs, inflation factors, credit-adjusted discount rates, timing of settlement and changes in the legal, regulatory, environmental and political environments.
Acquisitions. The Company recognized the assets acquired in our acquisitions at cost at a relative fair value basis (refer to Note 7 of these Notes to Consolidated Financial Statements). Fair value was determined using a discounted cash flow model. The underlying future commodity prices included in the Company’s estimated future cash flows of its proved oil and gas properties were determined using NYMEX forward strip prices as of the closing date of each acquisition. The estimated future cash flows also included management’s assumptions for the estimates of production from the crude oil and natural gas proved properties, future operating, development costs and income taxes of the acquired properties and risk adjusted discount rates.
The fair value hierarchy has three levels based on the reliability of the inputs used to determine the fair value:
Level 1 – Uses quoted prices in active markets for identical, unrestricted assets or liabilities. Instruments in this category have comparable fair values for identical instruments in active markets.
Level 2 – Uses quoted prices for similar assets or liabilities in active markets or observable inputs for assets or liabilities in non-active markets. Instruments in this category are periodically verified against quotes from brokers and include our commodity derivatives that we value using commonly accepted industry-standard models which contain inputs such as contract prices, risk-free rates, volatility measurements and other observable market data that are obtained from independent third-party sources.
Level 3 – Uses unobservable inputs for assets or liabilities that are in non-active markets.
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v3.23.3
Asset Retirement Obligations Asset Retirement Obligations (Policies)
|
9 Months Ended |
Sep. 30, 2023 |
Asset Retirement Obligation Disclosure [Abstract] |
|
Asset Retirement Obligations, Policy |
Asset Retirement ObligationsLiabilities for legal obligations associated with the retirement obligations of tangible long-lived assets are initially recorded at fair value in the period in which they are incurred. Estimates for the initial recognition of asset retirement obligations are derived from historical costs as well as management's expectation of future cost environments and other unobservable inputs. As there is no corroborating market activity to support the assumptions used, the Company has designated these liabilities as Level 3 fair value measurements. When a liability is initially recorded, the carrying amount of the related asset is increased. The liability is discounted from the expected date of abandonment. Over time, accretion of the liability is recognized each period, and the capitalized cost is amortized on a unit-of-production basis as part of depreciation, depletion, and amortization expense for our oil and gas properties. Upon settlement of the liability, the Company either settles the obligation for its recorded amount or incurs a gain or loss upon settlement which is included in the “Property and Equipment” balance on our accompanying condensed consolidated balance sheets.
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v3.23.3
Commitments and Contingencies Commitments and Contingencies (Policies)
|
9 Months Ended |
Sep. 30, 2023 |
Commitments and Contingencies Disclosure [Abstract] |
|
Commitments and Contingencies, Policy |
Commitments and Contingencies In the ordinary course of business, we are party to various legal actions, which arise primarily from our activities as an operator of oil and natural gas wells. In our management's opinion, the outcome of any such currently pending legal actions will not have a material adverse effect on our financial position or results of operations.
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v3.23.3
Summary of Significant Accounting Policies (Tables)
|
9 Months Ended |
Sep. 30, 2023 |
Accounting Policies [Abstract] |
|
Schedule of Subsequent Events |
Subsequent Events. We have evaluated subsequent events requiring potential accrual or disclosure in our condensed consolidated financial statements.
Through October 31, 2023, the Company entered into additional derivative contracts. The following tables summarize the weighted-average prices as well as future production volumes for our future derivative contracts entered into after September 30, 2023: | | | | | | | | | | | | | | | Oil Derivative Contracts (NYMEX WTI Settlements) | | Total Volumes (Bbls) | | Weighted-Average Price | Swap Contracts | | | | | 2024 Contracts | | | | | 1Q24 | | 91,000 | | | $ | 83.40 | | 2Q24 | | 91,000 | | | $ | 81.31 | | 3Q24 | | 92,000 | | | $ | 79.63 | | 4Q24 | | 92,000 | | | $ | 78.21 | | 2025 Contracts | | | | | 1Q25 | | 90,000 | | | $ | 76.52 | | 2Q25 | | 91,000 | | | $ | 75.38 | | 3Q25 | | 92,000 | | | $ | 74.56 | | 4Q25 | | 92,000 | | | $ | 73.58 | | 2026 Contracts | | | | | 1Q26 | | 157,500 | | | $ | 68.01 | | 2Q26 | | 136,500 | | | $ | 67.98 | | 3Q26 | | 110,400 | | | $ | 67.94 | | 4Q26 | | 156,150 | | | $ | 68.60 | |
| | | | | | | | | | | | | | | Oil Basis Swaps (Argus Cushing (WTI) and Magellan East Houston) | | Total Volumes (MMBtu) | | Weighted-Average Price | 2023 Contracts | | | | | 4Q23 | | 61,000 | | | $ | 0.90 | | 2025 Contracts | | | | | 1Q25 | | 90,000 | | | $ | 1.75 | | 2Q25 | | 91,000 | | | $ | 1.75 | | 3Q25 | | 92,000 | | | $ | 1.75 | | 4Q25 | | 92,000 | | | $ | 1.75 | | Calendar Monthly Roll Differential Swaps | | | | | 2023 Contracts | | | | | 4Q23 | | 61,000 | | | $ | 2.40 | | 2025 Contracts | | | | | 1Q25 | | 90,000 | | | $ | 0.50 | | 2Q25 | | 91,000 | | | $ | 0.50 | | 3Q25 | | 92,000 | | | $ | 0.50 | | 4Q25 | | 92,000 | | | $ | 0.50 | |
| | | | | | | | | | | | | | | Natural Gas Derivative Contracts (NYMEX Henry Hub Settlements) | | Total Volumes (MMBtu) | | Weighted-Average Price | Swap Contracts | | | | | 2024 Contracts | | | | | 1Q24 | | 1,820,000 | | | $ | 3.66 | | 2Q24 | | 2,430,000 | | | $ | 3.31 | | 3Q24 | | 2,760,000 | | | $ | 3.46 | | 4Q24 | | 2,760,000 | | | $ | 3.75 | | 2025 Contracts | | | | | 1Q25 | | 2,700,000 | | | $ | 4.20 | | 2Q25 | | 2,730,000 | | | $ | 3.75 | | 3Q25 | | 2,760,000 | | | $ | 3.89 | | 4Q25 | | 1,540,000 | | | $ | 4.11 | | 2026 Contracts | | | | | 1Q26 | | 900,000 | | | $ | 4.56 | | 2Q26 | | 910,000 | | | $ | 3.53 | | 3Q26 | | 920,000 | | | $ | 3.73 | | 4Q26 | | 920,000 | | | $ | 4.19 | |
| | | | | | | | | | | | | | | Natural Gas Basis Derivative Swaps (East Texas Houston Ship Channel vs. NYMEX Settlements) | | Total Volumes (MMBtu) | | Weighted-Average Price | 2024 Contracts | | | | | 1Q24 | | 910,000 | | | $ | (0.21) | | 2Q24 | | 910,000 | | | $ | (0.21) | | 3Q24 | | 920,000 | | | $ | (0.21) | | 4Q24 | | 920,000 | | | $ | (0.21) | | 2025 Contracts | | | | | 1Q25 | | 900,000 | | | $ | (0.23) | | 2Q25 | | 910,000 | | | $ | (0.23) | | 3Q25 | | 920,000 | | | $ | (0.23) | | 4Q25 | | 920,000 | | | $ | (0.23) | |
| | | | | | | | | | | | | | | NGL Swaps (Mont Belvieu) | | Total Volumes (Bbls) | | Weighted-Average Price | 2024 Contracts | | | | | 1Q24 | | 91,000 | | | $ | 24.25 | | 2Q24 | | 91,000 | | | $ | 24.25 | | 3Q24 | | 92,000 | | | $ | 24.25 | | 4Q24 | | 92,000 | | | $ | 24.25 | |
There were no other material subsequent events requiring additional disclosure in these condensed consolidated financial statements.
|
Property and Equipment |
The “Property and Equipment” balances on the accompanying condensed consolidated balance sheets are summarized for presentation purposes. The following is a detailed breakout of our “Property and Equipment” balances (in thousands): | | | | | | | | | | | | | September 30, 2023 | | December 31, 2022 | Property and Equipment | | | | Proved oil and gas properties | $ | 2,827,145 | | | $ | 2,506,853 | | Unproved oil and gas properties | 27,821 | | | 16,272 | | Furniture, fixtures and other equipment | 6,301 | | | 6,098 | | Less – Accumulated depreciation, depletion, amortization & impairment | (1,151,141) | | | (1,004,044) | | Property and Equipment, Net | $ | 1,710,126 | | | $ | 1,525,179 | |
|
Disaggregation of Revenue |
The following table provides information regarding our oil and gas sales, by product, reported on the Condensed Consolidated Statements of Operations for the three months ended September 30, 2023 and 2022 and the nine months ended September 30, 2023 and 2022 (in thousands): | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Three Months Ended September 30, 2023 | | Three Months Ended September 30, 2022 | | Nine Months Ended September 30, 2023 | | Nine Months Ended September 30, 2022 | | | | | Oil, natural gas and NGLs sales: | | | | | | | | | | | | Oil | $ | 112,456 | | | $ | 71,811 | | | $ | 267,263 | | | $ | 155,566 | | | | | | Natural gas | 46,075 | | | 150,958 | | | 132,802 | | | 351,626 | | | | | | NGLs | 15,432 | | | 19,412 | | | 40,252 | | | 47,250 | | | | | | Total | $ | 173,963 | | | $ | 242,181 | | | $ | 440,317 | | | $ | 554,442 | | | | | |
|
Accounts Payable and Accrued Liabilities |
The “Accounts payable and accrued liabilities” balances on the accompanying condensed consolidated balance sheets are summarized below (in thousands): | | | | | | | | | | | | | September 30, 2023 | | December 31, 2022 | Trade accounts payable | $ | 30,708 | | | $ | 23,660 | | Accrued operating expenses | 11,266 | | | 10,572 | | Accrued compensation costs | 3,267 | | | 4,814 | | Asset retirement obligations – current portion | 1,578 | | | 1,284 | | Accrued non-income based taxes | 13,303 | | | 4,849 | | Accrued corporate and legal fees | 181 | | | 388 | | WTI contingency payouts - current portion | 1,537 | | | 1,600 | | Payable for settled derivatives | 3,549 | | | 6,026 | | Other payables | 9,342 | | | 7,007 | | Total accounts payable and accrued liabilities | $ | 74,731 | | | $ | 60,200 | |
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v3.23.3
Leases Leases (Tables)
|
9 Months Ended |
Sep. 30, 2023 |
Leases [Abstract] |
|
Lessee, Operating Lease, Liability, Maturity [Table Text Block] |
As of September 30, 2023, the Company's future cash payment obligation for its operating lease liabilities are as follows (in thousands): | | | | | | | As of September 30, 2023 | 2023 (Remaining) | $ | 2,667 | | 2024 | 4,166 | | 2025 | 2,427 | | 2026 | 1,194 | | 2027 | 61 | | Thereafter | 475 | | Total undiscounted lease payments | 10,990 | | Present value adjustment | (879) | | Net operating lease liabilities | $ | 10,111 | |
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v3.23.3
Share-Based Compensation (Tables)
|
9 Months Ended |
Sep. 30, 2023 |
Share-Based Payment Arrangement [Abstract] |
|
Stock option activity |
The following table provides information regarding stock option award activity for the nine months ended September 30, 2023: | | | | | | | | | | | | | Shares | | Wtd. Avg. Exer. Price | Options outstanding, beginning of period | 196,162 | | | $ | 26.46 | | Options granted | — | | | $ | — | | | | | | | | | | Options exercised | — | | | $ | — | | Options outstanding, end of period | 196,162 | | | $ | 26.46 | | Options exercisable, end of period | 196,162 | | | $ | 26.46 | |
|
Restricted stock activity |
The following table provides information regarding RSU activity for the nine months ended September 30, 2023: | | | | | | | | | | | | | RSUs | | Wtd. Avg. Grant Price | RSUs outstanding, beginning of period | 227,114 | | | $ | 21.18 | | RSUs granted | 195,791 | | | $ | 23.75 | | | | | | | | | | RSUs forfeited | (1,424) | | | $ | 25.44 | | RSUs vested | (137,467) | | | $ | 17.78 | | RSUs outstanding, end of period | 284,014 | | | $ | 24.58 | |
|
Performance-Based Stock Units Activity |
The following table provides information regarding performance-based stock unit activity for the nine months ended September 30, 2023: | | | | | | | | | | | | | PSUs | | Wtd. Avg. Grant Price | Performance based stock units outstanding, beginning of period | 283,500 | | | $ | 23.18 | | Performance based stock units granted | 120,749 | | | $ | 31.18 | | Performance based stock units incremental shares granted | 142,021 | | | $ | 13.13 | | Performance based stock units vested | (303,410) | | | $ | 13.13 | | Performance based stock units outstanding, end of period | 242,860 | | | $ | 33.84 | |
|
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v3.23.3
Earnings Per Share (Tables)
|
9 Months Ended |
Sep. 30, 2023 |
Earnings Per Share [Abstract] |
|
Reconciliation of the numerators and denominators used in the calculation of Basic and Diluted EPS |
The following is a reconciliation of the numerators and denominators used in the calculation of Basic EPS and Diluted EPS for the periods indicated below (in thousands, except per share amounts): | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Three Months Ended September 30, 2023 | | Three Months Ended September 30, 2022 | | Net Income (Loss) | | Shares | | Per Share Amount | | Net Income (Loss) | | Shares | | Per Share Amount | Basic EPS: | | | | | | | | | | | | Net Income (Loss) and Share Amounts | $ | (4,771) | | | 22,985 | | | $ | (0.21) | | | $ | 142,541 | | | 22,308 | | | $ | 6.39 | | Dilutive Securities: | | | | | | | | | | | | Performance Based Stock Unit Awards | | | — | | | | | | | 169 | | | | RSU Awards | | | — | | | | | | | 137 | | | | Stock Option Awards | | | — | | | | | | | 55 | | | | Diluted EPS: | | | | | | | | | | | | Net Income (Loss) and Assumed Share Conversions | $ | (4,771) | | | 22,985 | | | $ | (0.21) | | | $ | 142,541 | | | 22,669 | | | $ | 6.29 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Nine Months Ended September 30, 2023 | | Nine Months Ended September 30, 2022 | | Net Income (Loss) | | Shares | | Per Share Amount | | Net Income (Loss) | | Shares | | Per Share Amount | Basic EPS: | | | | | | | | | | | | Net Income (Loss) and Share Amounts | $ | 114,658 | | | 22,677 | | | $ | 5.06 | | | $ | 167,076 | | | 18,885 | | | $ | 8.85 | | Dilutive Securities: | | | | | | | | | | | | Performance Based Stock Unit Awards | | | 67 | | | | | | | 141 | | | | RSU Awards | | | 91 | | | | | | | 171 | | | | Stock Option Awards | | | 17 | | | | | | | 40 | | | | Diluted EPS: | | | | | | | | | | | | Net Income (Loss) and Assumed Share Conversions | $ | 114,658 | | | 22,852 | | | $ | 5.02 | | | $ | 167,076 | | | 19,237 | | | $ | 8.69 | |
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v3.23.3
Long-Term Debt (Tables)
|
9 Months Ended |
Sep. 30, 2023 |
Debt Disclosure [Abstract] |
|
Schedule of Long-term Debt Instruments |
The Company's long-term debt consisted of the following (in thousands): | | | | | | | | | | | | | September 30, 2023 | | December 31, 2022 | Credit Facility Borrowings due 2026 (1) | $ | 498,000 | | | $ | 542,000 | | Second Lien Notes due 2026 | 150,000 | | | 150,000 | | | 648,000 | | | 692,000 | | Unamortized discount on Second Lien Notes due 2026 | (738) | | | (882) | | Unamortized debt issuance cost on Second Lien Notes due 2026 | (2,166) | | | (2,587) | | Long-Term Debt, net | $ | 645,096 | | | $ | 688,531 | |
(1) Unamortized debt issuance costs on our Credit Facility borrowings are included in “Other Long-Term Assets” in our condensed consolidated balance sheet. As of September 30, 2023 and December 31, 2022, we had $7.0 million and $8.7 million, respectively, in unamortized debt issuance costs on our Credit Facility borrowings.
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v3.23.3
Business Combinations and Asset Acquisitions (Tables)
|
Jun. 30, 2022 |
May 10, 2022 |
Business Combination and Asset Acquisition [Abstract] |
|
|
Schedule of Recognized Identified Assets Acquired and Liabilities Assumed |
The following table represents the allocation of the total cost of the acquisition to the assets acquired and liabilities assumed (in thousands): | | | | | | | | | Total Cost | | | Cash consideration | | $ | 220,866 | | Equity consideration | | 117,651 | | Fair value of contingent consideration | | 7,422 | | Accrued purchase price adjustments receivable | | (1,000) | | Total Consideration | | 344,939 | | | | | Transaction costs | | 6,766 | | | | | Total Cost of Transaction | | $ | 351,705 | | | | | Allocation of Total Cost | | | Assets | | | Other current assets | | $ | 4,202 | | Oil and gas properties | | 397,401 | | Right of use assets | | 890 | | Total assets | | 402,493 | | | | | Liabilities | | | Accounts payable and accrued liabilities | | 13,687 | | Fair value of commodity derivatives | | 33,767 | | Non-current lease liability | | 890 | | Asset retirement obligations | | 2,444 | | Total Liabilities | | $ | 50,788 | | | | | Net Assets Acquired | | $ | 351,705 | |
|
The following table represents the allocation of the total cost of the acquisition to the assets acquired and liabilities assumed (in thousands): | | | | | | | | | Total Cost | | | Cash consideration | | $ | 27,709 | | Equity consideration | | 39,767 | | Total Consideration | | 67,476 | | | | | Transaction costs | | 466 | | | | | Total Cost of Transaction | | $ | 67,942 | | | | | Allocation of Total Cost | | | Assets | | | Oil and gas properties | | $ | 84,810 | | Total assets | | 84,810 | | | | | Liabilities | | | Accounts payable and accrued liabilities | | 199 | | Fair value of commodity derivatives | | 16,511 | | Asset retirement obligations | | 158 | | Total Liabilities | | $ | 16,868 | | | | | Net Assets Acquired | | $ | 67,942 | |
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v3.23.3
Price-Risk Management Price-Risk Management (Tables)
|
9 Months Ended |
Sep. 30, 2023 |
Derivative Instruments and Hedging Activities Disclosure [Abstract] |
|
Schedule of Derivative Instruments [Table Text Block] |
The following tables summarize the weighted-average prices as well as future production volumes for our future derivative contracts in place as of September 30, 2023: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Oil Derivative Contracts (NYMEX WTI Settlements) | | Total Volumes (Bbls) | | Weighted-Average Price | | Weighted-Average Collar Sub Floor Price | | Weighted-Average Collar Floor Price | | Weighted-Average Collar Call Price | Swap Contracts | | | | | | | | | | | 2023 Contracts | | | | | | | | | | | 4Q23 | | 707,300 | | | $ | 78.53 | | | | | | | | 2024 Contracts | | | | | | | | | | | 1Q24 | | 728,000 | | | $ | 77.67 | | | | | | | | 2Q24 | | 754,550 | | | $ | 77.59 | | | | | | | | 3Q24 | | 779,620 | | | $ | 76.48 | | | | | | | | 4Q24 | | 762,100 | | | $ | 76.16 | | | | | | | | 2025 Contracts | | | | | | | | | | | 1Q25 | | 666,000 | | | $ | 71.60 | | | | | | | | 2Q25 | | 673,400 | | | $ | 71.60 | | | | | | | | 3Q25 | | 680,800 | | | $ | 71.60 | | | | | | | | 4Q25 | | 588,800 | | | $ | 71.29 | | | | | | | | 2026 Contracts | | | | | | | | | | | 1Q26 | | 315,000 | | | $ | 69.40 | | | | | | | | 2Q26 | | 318,500 | | | $ | 69.40 | | | | | | | | 3Q26 | | 322,000 | | | $ | 69.40 | | | | | | | | 4Q26 | | 230,000 | | | $ | 69.42 | | | | | | | | Collar Contracts | | | | | | | | | | | 2023 Contracts | | | | | | | | | | | 4Q23 | | 302,242 | | | | | | | $ | 65.89 | | | $ | 74.54 | | 2024 Contracts | | | | | | | | | | | 1Q24 | | 319,700 | | | | | | | $ | 58.95 | | | $ | 71.74 | | 2Q24 | | 215,000 | | | | | | | $ | 61.08 | | | $ | 73.57 | | 3Q24 | | 184,000 | | | | | | | $ | 63.50 | | | $ | 75.53 | | 4Q24 | | 184,000 | | | | | | | $ | 63.00 | | | $ | 75.35 | | 2025 Contracts | | | | | | | | | | | 1Q25 | | 238,500 | | | | | | | $ | 64.00 | | | $ | 74.62 | | 2Q25 | | 227,500 | | | | | | | $ | 60.80 | | | $ | 72.22 | | 2026 Contracts | | | | | | | | | | | 1Q26 | | 90,000 | | | | | | | $ | 64.00 | | | $ | 71.50 | | 2Q26 | | 91,000 | | | | | | | $ | 64.00 | | | $ | 71.50 | | 3Q26 | | 92,000 | | | | | | | $ | 64.00 | | | $ | 71.50 | | 3-Way Collar Contracts | | | | | | | | | | | 2023 Contracts | | | | | | | | | | | 4Q23 | | 8,970 | | | | | $ | 43.08 | | | $ | 53.38 | | | $ | 63.35 | | 2024 Contracts | | | | | | | | | | | 1Q24 | | 8,247 | | | | | $ | 45.00 | | | $ | 57.50 | | | $ | 67.85 | | 2Q24 | | 7,757 | | | | | $ | 45.00 | | | $ | 57.50 | | | $ | 67.85 | |
| | | | | | | | | | | | | | | Oil Basis Swaps (Argus Cushing (WTI) and Magellan East Houston) | | Total Volumes (MMBtu) | | Weighted-Average Price | 2023 Contracts | | | | | 4Q23 | | 122,000 | | | $ | 0.80 | | 2024 Contracts | | | | | 1Q24 | | 364,000 | | | $ | 1.47 | | 2Q24 | | 364,000 | | | $ | 1.47 | | 3Q24 | | 368,000 | | | $ | 1.47 | | 4Q24 | | 368,000 | | | $ | 1.47 | | 2025 Contracts | | | | | 1Q25 | | 270,000 | | | $ | 1.75 | | 2Q25 | | 273,000 | | | $ | 1.75 | | 3Q25 | | 276,000 | | | $ | 1.75 | | 4Q25 | | 276,000 | | | $ | 1.75 | | Calendar Monthly Roll Differential Swaps | | | | | 2023 Contracts | | | | | 4Q23 | | 122,000 | | | $ | 2.44 | | 2024 Contracts | | | | | 1Q24 | | 364,000 | | | $ | 0.69 | | 2Q24 | | 364,000 | | | $ | 0.69 | | 3Q24 | | 368,000 | | | $ | 0.69 | | 4Q24 | | 368,000 | | | $ | 0.69 | | 2025 Contracts | | | | | 1Q25 | | 270,000 | | | $ | 0.40 | | 2Q25 | | 273,000 | | | $ | 0.40 | | 3Q25 | | 276,000 | | | $ | 0.40 | | 4Q25 | | 276,000 | | | $ | 0.40 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Natural Gas Derivative Contracts (NYMEX Henry Hub Settlements) | | Total Volumes (MMBtu) | | Weighted-Average Price | | Weighted-Average Collar Sub Floor Price | | Weighted-Average Collar Floor Price | | Weighted-Average Collar Call Price | Swap Contracts | | | | | | | | | | | 2023 Contracts | | | | | | | | | | | 4Q23 | | 5,727,000 | | | $ | 4.20 | | | | | | | | 2024 Contracts | | | | | | | | | | | 1Q24 | | 7,686,000 | | | $ | 4.12 | | | | | | | | 2Q24 | | 12,350,000 | | | $ | 3.67 | | | | | | | | 3Q24 | | 12,420,000 | | | $ | 3.78 | | | | | | | | 4Q24 | | 12,420,000 | | | $ | 4.12 | | | | | | | | 2025 Contracts | | | | | | | | | | | 1Q25 | | 9,450,000 | | | $ | 4.25 | | | | | | | | 2Q25 | | 9,555,000 | | | $ | 3.71 | | | | | | | | 3Q25 | | 11,960,000 | | | $ | 3.83 | | | | | | | | 4Q25 | | 8,740,000 | | | $ | 4.17 | | | | | | | | 2026 Contracts | | | | | | | | | | | 1Q26 | | 9,680,000 | | | $ | 4.48 | | | | | | | | 2Q26 | | 9,555,000 | | | $ | 3.56 | | | | | | | | 3Q26 | | 9,660,000 | | | $ | 3.74 | | | | | | | | 4Q26 | | 9,200,000 | | | $ | 4.13 | | | | | | | | Collar Contracts | | | | | | | | | | | 2023 Contracts | | | | | | | | | | | 4Q23 | | 12,445,000 | | | | | | | $ | 3.87 | | | $ | 4.80 | | 2024 Contracts | | | | | | | | | | | 1Q24 | | 9,661,000 | | | | | | | $ | 3.94 | | | $ | 5.83 | | 2Q24 | | 4,643,000 | | | | | | | $ | 3.64 | | | $ | 4.28 | | 3Q24 | | 3,878,000 | | | | | | | $ | 3.77 | | | $ | 4.76 | | 4Q24 | | 3,865,000 | | | | | | | $ | 4.01 | | | $ | 5.34 | | 2025 Contracts | | | | | | | | | | | 1Q25 | | 5,130,000 | | | | | | | $ | 4.00 | | | $ | 5.32 | | 2Q25 | | 4,914,000 | | | | | | | $ | 3.25 | | | $ | 3.98 | | 3Q25 | | 920,000 | | | | | | | $ | 3.50 | | | $ | 3.99 | | 4Q25 | | 920,000 | | | | | | | $ | 3.75 | | | $ | 4.65 | | 3-Way Collar Contracts | | | | | | | | | | | 2023 Contracts | | | | | | | | | | | 4Q23 | | 219,200 | | | | | $ | 2.00 | | | $ | 2.50 | | | $ | 2.94 | | 2024 Contracts | | | | | | | | | | | 1Q24 | | 198,000 | | | | | $ | 2.00 | | | $ | 2.50 | | | $ | 3.37 | | 2Q24 | | 188,000 | | | | | $ | 2.00 | | | $ | 2.50 | | | $ | 3.37 | |
| | | | | | | | | | | | | | | Natural Gas Basis Derivative Swaps (East Texas Houston Ship Channel vs. NYMEX Settlements) | | Total Volumes (MMBtu) | | Weighted-Average Price | 2023 Contracts | | | | | 4Q23 | | 13,800,000 | | | $ | (0.23) | | 2024 Contracts | | | | | 1Q24 | | 15,470,000 | | | $ | (0.02) | | 2Q24 | | 15,470,000 | | | $ | (0.29) | | 3Q24 | | 15,640,000 | | | $ | (0.26) | | 4Q24 | | 15,640,000 | | | $ | (0.28) | | 2025 Contracts | | | | | 1Q25 | | 5,400,000 | | | $ | (0.09) | | 2Q25 | | 5,460,000 | | | $ | (0.26) | | 3Q25 | | 5,520,000 | | | $ | (0.23) | | 4Q25 | | 5,520,000 | | | $ | (0.25) | |
| | | | | | | | | | | | | | | NGL Swaps (Mont Belvieu) | | Total Volumes (Bbls) | | Weighted-Average Price | 2023 Contracts | | | | | 4Q23 | | 345,000 | | | $ | 32.87 | | 2024 Contracts | | | | | 1Q24 | | 400,400 | | | $ | 26.30 | | 2Q24 | | 400,400 | | | $ | 26.30 | | 3Q24 | | 404,800 | | | $ | 26.30 | | 4Q24 | | 404,800 | | | $ | 26.30 | | 2025 Contracts | | | | | 1Q25 | | 270,000 | | | $ | 24.17 | | 2Q25 | | 273,000 | | | $ | 24.17 | | 3Q25 | | 276,000 | | | $ | 24.17 | | 4Q25 | | 276,000 | | | $ | 24.17 | |
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- DefinitionTabular disclosure of pertinent information about a derivative or group of derivatives on a disaggregated basis, such as for individual instruments, or small groups of similar instruments. May include a combination of the type of instrument, risks being hedged, notional amount, hedge designation, related hedged item, inception date, maturity date, or other relevant item.
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v3.23.3
Fair Value Measurements (Tables)
|
9 Months Ended |
Sep. 30, 2023 |
Fair Value Disclosures [Abstract] |
|
Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis [Table Text Block] |
The following table presents our assets and liabilities that are measured on a recurring basis at fair value as of each of September 30, 2023 and December 31, 2022, and are categorized using the fair value hierarchy. For additional discussion related to the fair value of the Company's derivatives, refer to Note 8 of these Notes to Condensed Consolidated Financial Statements.
| | | | | | | | | | | | | | | | | | | | | | | | | Fair Value Measurements at | (in thousands) | Total | | Quoted Prices in Active markets for Identical Assets (Level 1) | | Significant Other Observable Inputs (Level 2) | | Significant Unobservable Inputs (Level 3) | September 30, 2023 | | | | | | | | Assets | | | | | | | | Natural Gas Derivatives | $ | 53,032 | | | $ | — | | | $ | 53,032 | | | $ | — | | Natural Gas Basis Derivatives | 5,395 | | | — | | | 5,395 | | | — | | Oil Derivatives | 418 | | | — | | | 418 | | | — | | Oil Basis Derivatives | 254 | | | — | | | 254 | | | — | | NGL Derivatives | 5,270 | | | — | | | 5,270 | | | — | | Liabilities | | | | | | | | Natural Gas Derivatives | 5,346 | | | — | | | 5,346 | | | — | | Natural Gas Basis Derivatives | 5,415 | | | — | | | 5,415 | | | — | | Oil Derivatives | 41,908 | | | — | | | 41,908 | | | — | | Oil Basis Derivatives | 858 | | | — | | | 858 | | | — | | NGL Derivatives | 785 | | | — | | | 785 | | | — | | 2021 WTI Contingency Payout | 2,459 | | | — | | | 2,459 | | | — | | | | | | | | | | December 31, 2022 | | | | | | | | Assets | | | | | | | | Natural Gas Derivatives | $ | 25,960 | | | $ | — | | | $ | 25,960 | | | $ | — | | Natural Gas Basis Derivatives | 26,023 | | | — | | | 26,023 | | | — | | Oil Derivatives | 14,604 | | | — | | | 14,604 | | | — | | NGL Derivatives | 10,134 | | | — | | | 10,134 | | | — | | Liabilities | | | | | | | | Natural Gas Derivatives | 28,579 | | | — | | | 28,579 | | | — | | Natural Gas Basis Derivatives | 409 | | | — | | | 409 | | | — | | Oil Derivatives | 19,442 | | | — | | | 19,442 | | | — | | NGL Derivatives | 104 | | | — | | | 104 | | | — | | 2022 WTI Contingency Payout | 2,135 | | | — | | | 2,135 | | | — | | 2021 WTI Contingency Payout | 1,453 | | | — | | | 1,453 | | | — | |
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- DefinitionTabular disclosure of assets and liabilities, including [financial] instruments measured at fair value that are classified in stockholders' equity, if any, that are measured at fair value on a recurring basis. The disclosures contemplated herein include the fair value measurements at the reporting date by the level within the fair value hierarchy in which the fair value measurements in their entirety fall, segregating fair value measurements using quoted prices in active markets for identical assets (Level 1), significant other observable inputs (Level 2), and significant unobservable inputs (Level 3).
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v3.23.3
Asset Retirement Obligations Asset Retirement Obligations (Tables)
|
9 Months Ended |
Sep. 30, 2023 |
Asset Retirement Obligation Disclosure [Abstract] |
|
Roll-forward of our asset retirement obligations |
The following provides a roll-forward of our asset retirement obligations for the year ended December 31, 2022 and the nine months ended September 30, 2023 (in thousands): | | | | | | Asset Retirement Obligations as of December 31, 2021 | $ | 6,050 | | Accretion expense | 534 | | Liabilities incurred for new wells, acquired wells and facilities construction | 3,032 | | Reductions due to sold wells and facilities | (57) | | Reductions due to plugged wells and facilities | (22) | | Revisions in estimates | 919 | | Asset Retirement Obligations as of December 31, 2022 | $ | 10,456 | | Accretion expense | 718 | | Liabilities incurred for new wells, acquired wells and facilities construction | 313 | | | | Reductions due to plugged wells and facilities | (603) | | Revisions in estimates | 534 | | Asset Retirement Obligations as of September 30, 2023 | $ | 11,418 | |
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v3.23.3
Summary of Significant Accounting Policies (Details) $ in Thousands |
3 Months Ended |
9 Months Ended |
|
|
Sep. 30, 2023
USD ($)
bbl
MMBTU
$ / Boe
$ / MMBTU
|
Sep. 30, 2022
USD ($)
|
Sep. 30, 2023
USD ($)
bbl
MMBTU
$ / Boe
$ / MMBTU
|
Sep. 30, 2022
USD ($)
|
Oct. 31, 2023
bbl
MMBTU
$ / MMBTU
$ / Boe
|
Dec. 31, 2022
USD ($)
|
Property and Equipment |
|
|
|
|
|
|
Proved oil and gas properties | $ |
$ 2,827,145
|
|
$ 2,827,145
|
|
|
$ 2,506,853
|
Unproved oil and gas properties | $ |
27,821
|
|
27,821
|
|
|
16,272
|
Furniture, fixtures, and other equipment | $ |
6,301
|
|
6,301
|
|
|
6,098
|
Less - Accumulated depreciation, depletion, and amortization | $ |
(1,151,141)
|
|
(1,151,141)
|
|
|
(1,004,044)
|
Net Furniture, Fixtures and other equipment | $ |
1,710,126
|
|
1,710,126
|
|
|
1,525,179
|
Disaggregation of Revenue [Line Items] |
|
|
|
|
|
|
Oil and gas sales | $ |
173,963
|
$ 242,181
|
440,317
|
$ 554,442
|
|
|
Accounts Payable and Accrued Liabilities |
|
|
|
|
|
|
Trade accounts payable | $ |
30,708
|
|
30,708
|
|
|
23,660
|
Accrued operating expenses | $ |
11,266
|
|
11,266
|
|
|
10,572
|
Accrued compensation costs | $ |
3,267
|
|
3,267
|
|
|
4,814
|
Asset retirement obligation - current portion | $ |
1,578
|
|
1,578
|
|
|
1,284
|
Accrued non-income based taxes | $ |
13,303
|
|
13,303
|
|
|
4,849
|
Accrued corporate and legal fees | $ |
181
|
|
181
|
|
|
388
|
WTI contingency payouts - current portion | $ |
1,537
|
|
1,537
|
|
|
1,600
|
Payables for Settled Derivatives | $ |
3,549
|
|
3,549
|
|
|
6,026
|
Other payables | $ |
9,342
|
|
9,342
|
|
|
7,007
|
Total Accounts payable and accrued liabilities | $ |
74,731
|
|
74,731
|
|
|
$ 60,200
|
Oil sales [Member] |
|
|
|
|
|
|
Disaggregation of Revenue [Line Items] |
|
|
|
|
|
|
Oil and gas sales | $ |
112,456
|
71,811
|
267,263
|
155,566
|
|
|
Natural gas sales [Member] |
|
|
|
|
|
|
Disaggregation of Revenue [Line Items] |
|
|
|
|
|
|
Oil and gas sales | $ |
46,075
|
150,958
|
132,802
|
351,626
|
|
|
NGL sales [Member] |
|
|
|
|
|
|
Disaggregation of Revenue [Line Items] |
|
|
|
|
|
|
Oil and gas sales | $ |
$ 15,432
|
$ 19,412
|
$ 40,252
|
$ 47,250
|
|
|
Swap [Member] | Fourth Quarter 2023 | Oil Derivative Swaps |
|
|
|
|
|
|
Derivative Instruments and Hedging Activities Disclosures [Line Items] |
|
|
|
|
|
|
Oil and Gas Production Hedged Volumes |
707,300
|
|
707,300
|
|
|
|
Derivative, Swap Type, Fixed Price | $ / Boe |
78.53
|
|
78.53
|
|
|
|
Swap [Member] | Fourth Quarter 2023 | Natural Gas Derivative Swaps |
|
|
|
|
|
|
Derivative Instruments and Hedging Activities Disclosures [Line Items] |
|
|
|
|
|
|
Oil and Gas Production Hedged Volumes | MMBTU |
5,727,000
|
|
5,727,000
|
|
|
|
Derivative, Swap Type, Fixed Price | $ / MMBTU |
4.20
|
|
4.20
|
|
|
|
Swap [Member] | Fourth Quarter 2023 | NGL Derivative |
|
|
|
|
|
|
Derivative Instruments and Hedging Activities Disclosures [Line Items] |
|
|
|
|
|
|
Oil and Gas Production Hedged Volumes |
345,000
|
|
345,000
|
|
|
|
Derivative, Swap Type, Fixed Price | $ / MMBTU |
32.87
|
|
32.87
|
|
|
|
Swap [Member] | First Quarter 2024 | Oil Derivative Swaps |
|
|
|
|
|
|
Derivative Instruments and Hedging Activities Disclosures [Line Items] |
|
|
|
|
|
|
Oil and Gas Production Hedged Volumes |
728,000
|
|
728,000
|
|
|
|
Derivative, Swap Type, Fixed Price | $ / Boe |
77.67
|
|
77.67
|
|
|
|
Swap [Member] | First Quarter 2024 | Oil Derivative Swaps | Subsequent Event [Member] |
|
|
|
|
|
|
Derivative Instruments and Hedging Activities Disclosures [Line Items] |
|
|
|
|
|
|
Oil and Gas Production Hedged Volumes |
|
|
|
|
91,000
|
|
Derivative, Swap Type, Fixed Price | $ / Boe |
|
|
|
|
83.40
|
|
Swap [Member] | First Quarter 2024 | Natural Gas Derivative Swaps |
|
|
|
|
|
|
Derivative Instruments and Hedging Activities Disclosures [Line Items] |
|
|
|
|
|
|
Oil and Gas Production Hedged Volumes | MMBTU |
7,686,000
|
|
7,686,000
|
|
|
|
Derivative, Swap Type, Fixed Price | $ / MMBTU |
4.12
|
|
4.12
|
|
|
|
Swap [Member] | First Quarter 2024 | Natural Gas Derivative Swaps | Subsequent Event [Member] |
|
|
|
|
|
|
Derivative Instruments and Hedging Activities Disclosures [Line Items] |
|
|
|
|
|
|
Oil and Gas Production Hedged Volumes | MMBTU |
|
|
|
|
1,820,000
|
|
Derivative, Swap Type, Fixed Price | $ / MMBTU |
|
|
|
|
3.66
|
|
Swap [Member] | First Quarter 2024 | NGL Derivative |
|
|
|
|
|
|
Derivative Instruments and Hedging Activities Disclosures [Line Items] |
|
|
|
|
|
|
Oil and Gas Production Hedged Volumes |
400,400
|
|
400,400
|
|
|
|
Derivative, Swap Type, Fixed Price | $ / MMBTU |
26.30
|
|
26.30
|
|
|
|
Swap [Member] | First Quarter 2024 | NGL Derivative | Subsequent Event [Member] |
|
|
|
|
|
|
Derivative Instruments and Hedging Activities Disclosures [Line Items] |
|
|
|
|
|
|
Oil and Gas Production Hedged Volumes |
|
|
|
|
91,000
|
|
Derivative, Swap Type, Fixed Price | $ / MMBTU |
|
|
|
|
24.25
|
|
Swap [Member] | Second Quarter 2024 | Oil Derivative Swaps |
|
|
|
|
|
|
Derivative Instruments and Hedging Activities Disclosures [Line Items] |
|
|
|
|
|
|
Oil and Gas Production Hedged Volumes |
754,550
|
|
754,550
|
|
|
|
Derivative, Swap Type, Fixed Price | $ / Boe |
77.59
|
|
77.59
|
|
|
|
Swap [Member] | Second Quarter 2024 | Oil Derivative Swaps | Subsequent Event [Member] |
|
|
|
|
|
|
Derivative Instruments and Hedging Activities Disclosures [Line Items] |
|
|
|
|
|
|
Oil and Gas Production Hedged Volumes |
|
|
|
|
91,000
|
|
Derivative, Swap Type, Fixed Price | $ / Boe |
|
|
|
|
81.31
|
|
Swap [Member] | Second Quarter 2024 | Natural Gas Derivative Swaps |
|
|
|
|
|
|
Derivative Instruments and Hedging Activities Disclosures [Line Items] |
|
|
|
|
|
|
Oil and Gas Production Hedged Volumes | MMBTU |
12,350,000
|
|
12,350,000
|
|
|
|
Derivative, Swap Type, Fixed Price | $ / MMBTU |
3.67
|
|
3.67
|
|
|
|
Swap [Member] | Second Quarter 2024 | Natural Gas Derivative Swaps | Subsequent Event [Member] |
|
|
|
|
|
|
Derivative Instruments and Hedging Activities Disclosures [Line Items] |
|
|
|
|
|
|
Oil and Gas Production Hedged Volumes | MMBTU |
|
|
|
|
2,430,000
|
|
Derivative, Swap Type, Fixed Price | $ / MMBTU |
|
|
|
|
3.31
|
|
Swap [Member] | Second Quarter 2024 | NGL Derivative |
|
|
|
|
|
|
Derivative Instruments and Hedging Activities Disclosures [Line Items] |
|
|
|
|
|
|
Oil and Gas Production Hedged Volumes |
400,400
|
|
400,400
|
|
|
|
Derivative, Swap Type, Fixed Price | $ / MMBTU |
26.30
|
|
26.30
|
|
|
|
Swap [Member] | Second Quarter 2024 | NGL Derivative | Subsequent Event [Member] |
|
|
|
|
|
|
Derivative Instruments and Hedging Activities Disclosures [Line Items] |
|
|
|
|
|
|
Oil and Gas Production Hedged Volumes |
|
|
|
|
91,000
|
|
Derivative, Swap Type, Fixed Price | $ / MMBTU |
|
|
|
|
24.25
|
|
Swap [Member] | Third Quarter 2024 | Oil Derivative Swaps |
|
|
|
|
|
|
Derivative Instruments and Hedging Activities Disclosures [Line Items] |
|
|
|
|
|
|
Oil and Gas Production Hedged Volumes |
779,620
|
|
779,620
|
|
|
|
Derivative, Swap Type, Fixed Price | $ / Boe |
76.48
|
|
76.48
|
|
|
|
Swap [Member] | Third Quarter 2024 | Oil Derivative Swaps | Subsequent Event [Member] |
|
|
|
|
|
|
Derivative Instruments and Hedging Activities Disclosures [Line Items] |
|
|
|
|
|
|
Oil and Gas Production Hedged Volumes |
|
|
|
|
92,000
|
|
Derivative, Swap Type, Fixed Price | $ / Boe |
|
|
|
|
79.63
|
|
Swap [Member] | Third Quarter 2024 | Natural Gas Derivative Swaps |
|
|
|
|
|
|
Derivative Instruments and Hedging Activities Disclosures [Line Items] |
|
|
|
|
|
|
Oil and Gas Production Hedged Volumes | MMBTU |
12,420,000
|
|
12,420,000
|
|
|
|
Derivative, Swap Type, Fixed Price | $ / MMBTU |
3.78
|
|
3.78
|
|
|
|
Swap [Member] | Third Quarter 2024 | Natural Gas Derivative Swaps | Subsequent Event [Member] |
|
|
|
|
|
|
Derivative Instruments and Hedging Activities Disclosures [Line Items] |
|
|
|
|
|
|
Oil and Gas Production Hedged Volumes | MMBTU |
|
|
|
|
2,760,000
|
|
Derivative, Swap Type, Fixed Price | $ / MMBTU |
|
|
|
|
3.46
|
|
Swap [Member] | Third Quarter 2024 | NGL Derivative |
|
|
|
|
|
|
Derivative Instruments and Hedging Activities Disclosures [Line Items] |
|
|
|
|
|
|
Oil and Gas Production Hedged Volumes |
404,800
|
|
404,800
|
|
|
|
Derivative, Swap Type, Fixed Price | $ / MMBTU |
26.30
|
|
26.30
|
|
|
|
Swap [Member] | Third Quarter 2024 | NGL Derivative | Subsequent Event [Member] |
|
|
|
|
|
|
Derivative Instruments and Hedging Activities Disclosures [Line Items] |
|
|
|
|
|
|
Oil and Gas Production Hedged Volumes |
|
|
|
|
92,000
|
|
Derivative, Swap Type, Fixed Price | $ / MMBTU |
|
|
|
|
24.25
|
|
Swap [Member] | Fourth Quarter 2024 | Oil Derivative Swaps |
|
|
|
|
|
|
Derivative Instruments and Hedging Activities Disclosures [Line Items] |
|
|
|
|
|
|
Oil and Gas Production Hedged Volumes |
762,100
|
|
762,100
|
|
|
|
Derivative, Swap Type, Fixed Price | $ / Boe |
76.16
|
|
76.16
|
|
|
|
Swap [Member] | Fourth Quarter 2024 | Oil Derivative Swaps | Subsequent Event [Member] |
|
|
|
|
|
|
Derivative Instruments and Hedging Activities Disclosures [Line Items] |
|
|
|
|
|
|
Oil and Gas Production Hedged Volumes |
|
|
|
|
92,000
|
|
Derivative, Swap Type, Fixed Price | $ / Boe |
|
|
|
|
78.21
|
|
Swap [Member] | Fourth Quarter 2024 | Natural Gas Derivative Swaps |
|
|
|
|
|
|
Derivative Instruments and Hedging Activities Disclosures [Line Items] |
|
|
|
|
|
|
Oil and Gas Production Hedged Volumes | MMBTU |
12,420,000
|
|
12,420,000
|
|
|
|
Derivative, Swap Type, Fixed Price | $ / MMBTU |
4.12
|
|
4.12
|
|
|
|
Swap [Member] | Fourth Quarter 2024 | Natural Gas Derivative Swaps | Subsequent Event [Member] |
|
|
|
|
|
|
Derivative Instruments and Hedging Activities Disclosures [Line Items] |
|
|
|
|
|
|
Oil and Gas Production Hedged Volumes | MMBTU |
|
|
|
|
2,760,000
|
|
Derivative, Swap Type, Fixed Price | $ / MMBTU |
|
|
|
|
3.75
|
|
Swap [Member] | Fourth Quarter 2024 | NGL Derivative |
|
|
|
|
|
|
Derivative Instruments and Hedging Activities Disclosures [Line Items] |
|
|
|
|
|
|
Oil and Gas Production Hedged Volumes |
404,800
|
|
404,800
|
|
|
|
Derivative, Swap Type, Fixed Price | $ / MMBTU |
26.30
|
|
26.30
|
|
|
|
Swap [Member] | Fourth Quarter 2024 | NGL Derivative | Subsequent Event [Member] |
|
|
|
|
|
|
Derivative Instruments and Hedging Activities Disclosures [Line Items] |
|
|
|
|
|
|
Oil and Gas Production Hedged Volumes |
|
|
|
|
92,000
|
|
Derivative, Swap Type, Fixed Price | $ / MMBTU |
|
|
|
|
24.25
|
|
Swap [Member] | First Quarter 2025 | Oil Derivative Swaps |
|
|
|
|
|
|
Derivative Instruments and Hedging Activities Disclosures [Line Items] |
|
|
|
|
|
|
Oil and Gas Production Hedged Volumes |
666,000
|
|
666,000
|
|
|
|
Derivative, Swap Type, Fixed Price | $ / Boe |
71.60
|
|
71.60
|
|
|
|
Swap [Member] | First Quarter 2025 | Oil Derivative Swaps | Subsequent Event [Member] |
|
|
|
|
|
|
Derivative Instruments and Hedging Activities Disclosures [Line Items] |
|
|
|
|
|
|
Oil and Gas Production Hedged Volumes |
|
|
|
|
90,000
|
|
Derivative, Swap Type, Fixed Price | $ / Boe |
|
|
|
|
76.52
|
|
Swap [Member] | First Quarter 2025 | Natural Gas Derivative Swaps |
|
|
|
|
|
|
Derivative Instruments and Hedging Activities Disclosures [Line Items] |
|
|
|
|
|
|
Oil and Gas Production Hedged Volumes | MMBTU |
9,450,000
|
|
9,450,000
|
|
|
|
Derivative, Swap Type, Fixed Price | $ / MMBTU |
4.25
|
|
4.25
|
|
|
|
Swap [Member] | First Quarter 2025 | Natural Gas Derivative Swaps | Subsequent Event [Member] |
|
|
|
|
|
|
Derivative Instruments and Hedging Activities Disclosures [Line Items] |
|
|
|
|
|
|
Oil and Gas Production Hedged Volumes | MMBTU |
|
|
|
|
2,700,000
|
|
Derivative, Swap Type, Fixed Price | $ / MMBTU |
|
|
|
|
4.20
|
|
Swap [Member] | First Quarter 2025 | NGL Derivative |
|
|
|
|
|
|
Derivative Instruments and Hedging Activities Disclosures [Line Items] |
|
|
|
|
|
|
Oil and Gas Production Hedged Volumes |
270,000
|
|
270,000
|
|
|
|
Derivative, Swap Type, Fixed Price | $ / MMBTU |
24.17
|
|
24.17
|
|
|
|
Swap [Member] | Second Quarter 2025 | Oil Derivative Swaps |
|
|
|
|
|
|
Derivative Instruments and Hedging Activities Disclosures [Line Items] |
|
|
|
|
|
|
Oil and Gas Production Hedged Volumes |
673,400
|
|
673,400
|
|
|
|
Derivative, Swap Type, Fixed Price | $ / Boe |
71.60
|
|
71.60
|
|
|
|
Swap [Member] | Second Quarter 2025 | Oil Derivative Swaps | Subsequent Event [Member] |
|
|
|
|
|
|
Derivative Instruments and Hedging Activities Disclosures [Line Items] |
|
|
|
|
|
|
Oil and Gas Production Hedged Volumes |
|
|
|
|
91,000
|
|
Derivative, Swap Type, Fixed Price | $ / Boe |
|
|
|
|
75.38
|
|
Swap [Member] | Second Quarter 2025 | Natural Gas Derivative Swaps |
|
|
|
|
|
|
Derivative Instruments and Hedging Activities Disclosures [Line Items] |
|
|
|
|
|
|
Oil and Gas Production Hedged Volumes | MMBTU |
9,555,000
|
|
9,555,000
|
|
|
|
Derivative, Swap Type, Fixed Price | $ / MMBTU |
3.71
|
|
3.71
|
|
|
|
Swap [Member] | Second Quarter 2025 | Natural Gas Derivative Swaps | Subsequent Event [Member] |
|
|
|
|
|
|
Derivative Instruments and Hedging Activities Disclosures [Line Items] |
|
|
|
|
|
|
Oil and Gas Production Hedged Volumes | MMBTU |
|
|
|
|
2,730,000
|
|
Derivative, Swap Type, Fixed Price | $ / MMBTU |
|
|
|
|
3.75
|
|
Swap [Member] | Second Quarter 2025 | NGL Derivative |
|
|
|
|
|
|
Derivative Instruments and Hedging Activities Disclosures [Line Items] |
|
|
|
|
|
|
Oil and Gas Production Hedged Volumes |
273,000
|
|
273,000
|
|
|
|
Derivative, Swap Type, Fixed Price | $ / MMBTU |
24.17
|
|
24.17
|
|
|
|
Swap [Member] | Third Quarter 2025 | Oil Derivative Swaps |
|
|
|
|
|
|
Derivative Instruments and Hedging Activities Disclosures [Line Items] |
|
|
|
|
|
|
Oil and Gas Production Hedged Volumes |
680,800
|
|
680,800
|
|
|
|
Derivative, Swap Type, Fixed Price | $ / Boe |
71.60
|
|
71.60
|
|
|
|
Swap [Member] | Third Quarter 2025 | Oil Derivative Swaps | Subsequent Event [Member] |
|
|
|
|
|
|
Derivative Instruments and Hedging Activities Disclosures [Line Items] |
|
|
|
|
|
|
Oil and Gas Production Hedged Volumes |
|
|
|
|
92,000
|
|
Derivative, Swap Type, Fixed Price | $ / Boe |
|
|
|
|
74.56
|
|
Swap [Member] | Third Quarter 2025 | Natural Gas Derivative Swaps |
|
|
|
|
|
|
Derivative Instruments and Hedging Activities Disclosures [Line Items] |
|
|
|
|
|
|
Oil and Gas Production Hedged Volumes | MMBTU |
11,960,000
|
|
11,960,000
|
|
|
|
Derivative, Swap Type, Fixed Price | $ / MMBTU |
3.83
|
|
3.83
|
|
|
|
Swap [Member] | Third Quarter 2025 | Natural Gas Derivative Swaps | Subsequent Event [Member] |
|
|
|
|
|
|
Derivative Instruments and Hedging Activities Disclosures [Line Items] |
|
|
|
|
|
|
Oil and Gas Production Hedged Volumes | MMBTU |
|
|
|
|
2,760,000
|
|
Derivative, Swap Type, Fixed Price | $ / MMBTU |
|
|
|
|
3.89
|
|
Swap [Member] | Third Quarter 2025 | NGL Derivative |
|
|
|
|
|
|
Derivative Instruments and Hedging Activities Disclosures [Line Items] |
|
|
|
|
|
|
Oil and Gas Production Hedged Volumes |
276,000
|
|
276,000
|
|
|
|
Derivative, Swap Type, Fixed Price | $ / MMBTU |
24.17
|
|
24.17
|
|
|
|
Swap [Member] | Fourth Quarter 2025 | Oil Derivative Swaps |
|
|
|
|
|
|
Derivative Instruments and Hedging Activities Disclosures [Line Items] |
|
|
|
|
|
|
Oil and Gas Production Hedged Volumes |
588,800
|
|
588,800
|
|
|
|
Derivative, Swap Type, Fixed Price | $ / Boe |
71.29
|
|
71.29
|
|
|
|
Swap [Member] | Fourth Quarter 2025 | Oil Derivative Swaps | Subsequent Event [Member] |
|
|
|
|
|
|
Derivative Instruments and Hedging Activities Disclosures [Line Items] |
|
|
|
|
|
|
Oil and Gas Production Hedged Volumes |
|
|
|
|
92,000
|
|
Derivative, Swap Type, Fixed Price | $ / Boe |
|
|
|
|
73.58
|
|
Swap [Member] | Fourth Quarter 2025 | Natural Gas Derivative Swaps |
|
|
|
|
|
|
Derivative Instruments and Hedging Activities Disclosures [Line Items] |
|
|
|
|
|
|
Oil and Gas Production Hedged Volumes | MMBTU |
8,740,000
|
|
8,740,000
|
|
|
|
Derivative, Swap Type, Fixed Price | $ / MMBTU |
4.17
|
|
4.17
|
|
|
|
Swap [Member] | Fourth Quarter 2025 | Natural Gas Derivative Swaps | Subsequent Event [Member] |
|
|
|
|
|
|
Derivative Instruments and Hedging Activities Disclosures [Line Items] |
|
|
|
|
|
|
Oil and Gas Production Hedged Volumes | MMBTU |
|
|
|
|
1,540,000
|
|
Derivative, Swap Type, Fixed Price | $ / MMBTU |
|
|
|
|
4.11
|
|
Swap [Member] | Fourth Quarter 2025 | NGL Derivative |
|
|
|
|
|
|
Derivative Instruments and Hedging Activities Disclosures [Line Items] |
|
|
|
|
|
|
Oil and Gas Production Hedged Volumes |
276,000
|
|
276,000
|
|
|
|
Swap [Member] | First Quarter 2026 | Oil Derivative Swaps |
|
|
|
|
|
|
Derivative Instruments and Hedging Activities Disclosures [Line Items] |
|
|
|
|
|
|
Oil and Gas Production Hedged Volumes |
315,000
|
|
315,000
|
|
|
|
Derivative, Swap Type, Fixed Price | $ / Boe |
69.40
|
|
69.40
|
|
|
|
Swap [Member] | First Quarter 2026 | Oil Derivative Swaps | Subsequent Event [Member] |
|
|
|
|
|
|
Derivative Instruments and Hedging Activities Disclosures [Line Items] |
|
|
|
|
|
|
Oil and Gas Production Hedged Volumes |
|
|
|
|
157,500
|
|
Derivative, Swap Type, Fixed Price | $ / Boe |
|
|
|
|
68.01
|
|
Swap [Member] | First Quarter 2026 | Natural Gas Derivative Swaps |
|
|
|
|
|
|
Derivative Instruments and Hedging Activities Disclosures [Line Items] |
|
|
|
|
|
|
Oil and Gas Production Hedged Volumes | MMBTU |
9,680,000
|
|
9,680,000
|
|
|
|
Derivative, Swap Type, Fixed Price | $ / MMBTU |
4.48
|
|
4.48
|
|
|
|
Swap [Member] | First Quarter 2026 | Natural Gas Derivative Swaps | Subsequent Event [Member] |
|
|
|
|
|
|
Derivative Instruments and Hedging Activities Disclosures [Line Items] |
|
|
|
|
|
|
Oil and Gas Production Hedged Volumes | MMBTU |
|
|
|
|
900,000
|
|
Derivative, Swap Type, Fixed Price | $ / MMBTU |
|
|
|
|
4.56
|
|
Swap [Member] | Second Quarter 2026 | Oil Derivative Swaps |
|
|
|
|
|
|
Derivative Instruments and Hedging Activities Disclosures [Line Items] |
|
|
|
|
|
|
Oil and Gas Production Hedged Volumes |
318,500
|
|
318,500
|
|
|
|
Derivative, Swap Type, Fixed Price | $ / Boe |
69.40
|
|
69.40
|
|
|
|
Swap [Member] | Second Quarter 2026 | Oil Derivative Swaps | Subsequent Event [Member] |
|
|
|
|
|
|
Derivative Instruments and Hedging Activities Disclosures [Line Items] |
|
|
|
|
|
|
Oil and Gas Production Hedged Volumes |
|
|
|
|
136,500
|
|
Derivative, Swap Type, Fixed Price | $ / Boe |
|
|
|
|
67.98
|
|
Swap [Member] | Second Quarter 2026 | Natural Gas Derivative Swaps |
|
|
|
|
|
|
Derivative Instruments and Hedging Activities Disclosures [Line Items] |
|
|
|
|
|
|
Oil and Gas Production Hedged Volumes | MMBTU |
9,555,000
|
|
9,555,000
|
|
|
|
Derivative, Swap Type, Fixed Price | $ / MMBTU |
3.56
|
|
3.56
|
|
|
|
Swap [Member] | Second Quarter 2026 | Natural Gas Derivative Swaps | Subsequent Event [Member] |
|
|
|
|
|
|
Derivative Instruments and Hedging Activities Disclosures [Line Items] |
|
|
|
|
|
|
Oil and Gas Production Hedged Volumes | MMBTU |
|
|
|
|
910,000
|
|
Derivative, Swap Type, Fixed Price | $ / MMBTU |
|
|
|
|
3.53
|
|
Swap [Member] | Third Quarter 2026 | Oil Derivative Swaps |
|
|
|
|
|
|
Derivative Instruments and Hedging Activities Disclosures [Line Items] |
|
|
|
|
|
|
Oil and Gas Production Hedged Volumes |
322,000
|
|
322,000
|
|
|
|
Derivative, Swap Type, Fixed Price | $ / Boe |
69.40
|
|
69.40
|
|
|
|
Swap [Member] | Third Quarter 2026 | Oil Derivative Swaps | Subsequent Event [Member] |
|
|
|
|
|
|
Derivative Instruments and Hedging Activities Disclosures [Line Items] |
|
|
|
|
|
|
Oil and Gas Production Hedged Volumes |
|
|
|
|
110,400
|
|
Derivative, Swap Type, Fixed Price | $ / Boe |
|
|
|
|
67.94
|
|
Swap [Member] | Third Quarter 2026 | Natural Gas Derivative Swaps |
|
|
|
|
|
|
Derivative Instruments and Hedging Activities Disclosures [Line Items] |
|
|
|
|
|
|
Oil and Gas Production Hedged Volumes | MMBTU |
9,660,000
|
|
9,660,000
|
|
|
|
Derivative, Swap Type, Fixed Price | $ / MMBTU |
3.74
|
|
3.74
|
|
|
|
Swap [Member] | Third Quarter 2026 | Natural Gas Derivative Swaps | Subsequent Event [Member] |
|
|
|
|
|
|
Derivative Instruments and Hedging Activities Disclosures [Line Items] |
|
|
|
|
|
|
Oil and Gas Production Hedged Volumes | MMBTU |
|
|
|
|
920,000
|
|
Derivative, Swap Type, Fixed Price | $ / MMBTU |
|
|
|
|
3.73
|
|
Swap [Member] | Fourth Quarter 2026 | Oil Derivative Swaps |
|
|
|
|
|
|
Derivative Instruments and Hedging Activities Disclosures [Line Items] |
|
|
|
|
|
|
Oil and Gas Production Hedged Volumes |
230,000
|
|
230,000
|
|
|
|
Derivative, Swap Type, Fixed Price | $ / Boe |
69.42
|
|
69.42
|
|
|
|
Swap [Member] | Fourth Quarter 2026 | Oil Derivative Swaps | Subsequent Event [Member] |
|
|
|
|
|
|
Derivative Instruments and Hedging Activities Disclosures [Line Items] |
|
|
|
|
|
|
Oil and Gas Production Hedged Volumes |
|
|
|
|
156,150
|
|
Derivative, Swap Type, Fixed Price | $ / Boe |
|
|
|
|
68.60
|
|
Swap [Member] | Fourth Quarter 2026 | Natural Gas Derivative Swaps |
|
|
|
|
|
|
Derivative Instruments and Hedging Activities Disclosures [Line Items] |
|
|
|
|
|
|
Oil and Gas Production Hedged Volumes | MMBTU |
9,200,000
|
|
9,200,000
|
|
|
|
Derivative, Swap Type, Fixed Price | $ / MMBTU |
4.13
|
|
4.13
|
|
|
|
Swap [Member] | Fourth Quarter 2026 | Natural Gas Derivative Swaps | Subsequent Event [Member] |
|
|
|
|
|
|
Derivative Instruments and Hedging Activities Disclosures [Line Items] |
|
|
|
|
|
|
Oil and Gas Production Hedged Volumes | MMBTU |
|
|
|
|
920,000
|
|
Derivative, Swap Type, Fixed Price | $ / MMBTU |
|
|
|
|
4.19
|
|
Basis Swap [Member] | Fourth Quarter 2023 | Natural Gas Basis Derivative Swaps [Member] |
|
|
|
|
|
|
Derivative Instruments and Hedging Activities Disclosures [Line Items] |
|
|
|
|
|
|
Oil and Gas Production Hedged Volumes | MMBTU |
13,800,000
|
|
13,800,000
|
|
|
|
Derivative, Swap Type, Fixed Price | $ / MMBTU |
(0.23)
|
|
(0.23)
|
|
|
|
Basis Swap [Member] | Fourth Quarter 2023 | Oil Basis Derivative |
|
|
|
|
|
|
Derivative Instruments and Hedging Activities Disclosures [Line Items] |
|
|
|
|
|
|
Oil and Gas Production Hedged Volumes |
122,000
|
|
122,000
|
|
|
|
Derivative, Swap Type, Fixed Price | $ / Boe |
0.80
|
|
0.80
|
|
|
|
Basis Swap [Member] | Fourth Quarter 2023 | Oil Basis Derivative | Subsequent Event [Member] |
|
|
|
|
|
|
Derivative Instruments and Hedging Activities Disclosures [Line Items] |
|
|
|
|
|
|
Oil and Gas Production Hedged Volumes |
|
|
|
|
61,000
|
|
Derivative, Swap Type, Fixed Price | $ / Boe |
|
|
|
|
0.90
|
|
Basis Swap [Member] | Fourth Quarter 2023 | Oil Basis Calendar Monthly Roll Differential Swap |
|
|
|
|
|
|
Derivative Instruments and Hedging Activities Disclosures [Line Items] |
|
|
|
|
|
|
Oil and Gas Production Hedged Volumes |
122,000
|
|
122,000
|
|
|
|
Derivative, Swap Type, Fixed Price | $ / Boe |
2.44
|
|
2.44
|
|
|
|
Basis Swap [Member] | Fourth Quarter 2023 | Oil Basis Calendar Monthly Roll Differential Swap | Subsequent Event [Member] |
|
|
|
|
|
|
Derivative Instruments and Hedging Activities Disclosures [Line Items] |
|
|
|
|
|
|
Oil and Gas Production Hedged Volumes |
|
|
|
|
61,000
|
|
Derivative, Swap Type, Fixed Price | $ / Boe |
|
|
|
|
2.40
|
|
Basis Swap [Member] | First Quarter 2024 | Natural Gas Basis Derivative Swaps [Member] |
|
|
|
|
|
|
Derivative Instruments and Hedging Activities Disclosures [Line Items] |
|
|
|
|
|
|
Oil and Gas Production Hedged Volumes | MMBTU |
15,470,000
|
|
15,470,000
|
|
|
|
Derivative, Swap Type, Fixed Price | $ / MMBTU |
(0.02)
|
|
(0.02)
|
|
|
|
Basis Swap [Member] | First Quarter 2024 | Natural Gas Basis Derivative Swaps [Member] | Subsequent Event [Member] |
|
|
|
|
|
|
Derivative Instruments and Hedging Activities Disclosures [Line Items] |
|
|
|
|
|
|
Oil and Gas Production Hedged Volumes | MMBTU |
|
|
|
|
910,000
|
|
Derivative, Swap Type, Fixed Price | $ / MMBTU |
|
|
|
|
(0.21)
|
|
Basis Swap [Member] | First Quarter 2024 | Oil Basis Derivative |
|
|
|
|
|
|
Derivative Instruments and Hedging Activities Disclosures [Line Items] |
|
|
|
|
|
|
Oil and Gas Production Hedged Volumes |
364,000
|
|
364,000
|
|
|
|
Derivative, Swap Type, Fixed Price | $ / Boe |
1.47
|
|
1.47
|
|
|
|
Basis Swap [Member] | First Quarter 2024 | Oil Basis Calendar Monthly Roll Differential Swap |
|
|
|
|
|
|
Derivative Instruments and Hedging Activities Disclosures [Line Items] |
|
|
|
|
|
|
Oil and Gas Production Hedged Volumes |
364,000
|
|
364,000
|
|
|
|
Derivative, Swap Type, Fixed Price | $ / Boe |
0.69
|
|
0.69
|
|
|
|
Basis Swap [Member] | Second Quarter 2024 | Natural Gas Basis Derivative Swaps [Member] |
|
|
|
|
|
|
Derivative Instruments and Hedging Activities Disclosures [Line Items] |
|
|
|
|
|
|
Oil and Gas Production Hedged Volumes | MMBTU |
15,470,000
|
|
15,470,000
|
|
|
|
Derivative, Swap Type, Fixed Price | $ / MMBTU |
(0.29)
|
|
(0.29)
|
|
|
|
Basis Swap [Member] | Second Quarter 2024 | Natural Gas Basis Derivative Swaps [Member] | Subsequent Event [Member] |
|
|
|
|
|
|
Derivative Instruments and Hedging Activities Disclosures [Line Items] |
|
|
|
|
|
|
Oil and Gas Production Hedged Volumes | MMBTU |
|
|
|
|
910,000
|
|
Derivative, Swap Type, Fixed Price | $ / MMBTU |
|
|
|
|
(0.21)
|
|
Basis Swap [Member] | Second Quarter 2024 | Oil Basis Derivative |
|
|
|
|
|
|
Derivative Instruments and Hedging Activities Disclosures [Line Items] |
|
|
|
|
|
|
Oil and Gas Production Hedged Volumes |
364,000
|
|
364,000
|
|
|
|
Derivative, Swap Type, Fixed Price | $ / Boe |
1.47
|
|
1.47
|
|
|
|
Basis Swap [Member] | Second Quarter 2024 | Oil Basis Calendar Monthly Roll Differential Swap |
|
|
|
|
|
|
Derivative Instruments and Hedging Activities Disclosures [Line Items] |
|
|
|
|
|
|
Oil and Gas Production Hedged Volumes |
364,000
|
|
364,000
|
|
|
|
Derivative, Swap Type, Fixed Price | $ / Boe |
0.69
|
|
0.69
|
|
|
|
Basis Swap [Member] | Third Quarter 2024 | Natural Gas Basis Derivative Swaps [Member] |
|
|
|
|
|
|
Derivative Instruments and Hedging Activities Disclosures [Line Items] |
|
|
|
|
|
|
Oil and Gas Production Hedged Volumes | MMBTU |
15,640,000
|
|
15,640,000
|
|
|
|
Derivative, Swap Type, Fixed Price | $ / MMBTU |
(0.26)
|
|
(0.26)
|
|
|
|
Basis Swap [Member] | Third Quarter 2024 | Natural Gas Basis Derivative Swaps [Member] | Subsequent Event [Member] |
|
|
|
|
|
|
Derivative Instruments and Hedging Activities Disclosures [Line Items] |
|
|
|
|
|
|
Oil and Gas Production Hedged Volumes | MMBTU |
|
|
|
|
920,000
|
|
Derivative, Swap Type, Fixed Price | $ / MMBTU |
|
|
|
|
(0.21)
|
|
Basis Swap [Member] | Third Quarter 2024 | Oil Basis Derivative |
|
|
|
|
|
|
Derivative Instruments and Hedging Activities Disclosures [Line Items] |
|
|
|
|
|
|
Oil and Gas Production Hedged Volumes |
368,000
|
|
368,000
|
|
|
|
Derivative, Swap Type, Fixed Price | $ / Boe |
1.47
|
|
1.47
|
|
|
|
Basis Swap [Member] | Third Quarter 2024 | Oil Basis Calendar Monthly Roll Differential Swap |
|
|
|
|
|
|
Derivative Instruments and Hedging Activities Disclosures [Line Items] |
|
|
|
|
|
|
Oil and Gas Production Hedged Volumes |
368,000
|
|
368,000
|
|
|
|
Derivative, Swap Type, Fixed Price | $ / Boe |
0.69
|
|
0.69
|
|
|
|
Basis Swap [Member] | Fourth Quarter 2024 | Natural Gas Basis Derivative Swaps [Member] |
|
|
|
|
|
|
Derivative Instruments and Hedging Activities Disclosures [Line Items] |
|
|
|
|
|
|
Oil and Gas Production Hedged Volumes | MMBTU |
15,640,000
|
|
15,640,000
|
|
|
|
Derivative, Swap Type, Fixed Price | $ / MMBTU |
(0.28)
|
|
(0.28)
|
|
|
|
Basis Swap [Member] | Fourth Quarter 2024 | Natural Gas Basis Derivative Swaps [Member] | Subsequent Event [Member] |
|
|
|
|
|
|
Derivative Instruments and Hedging Activities Disclosures [Line Items] |
|
|
|
|
|
|
Oil and Gas Production Hedged Volumes | MMBTU |
|
|
|
|
920,000
|
|
Derivative, Swap Type, Fixed Price | $ / MMBTU |
|
|
|
|
(0.21)
|
|
Basis Swap [Member] | Fourth Quarter 2024 | Oil Basis Derivative |
|
|
|
|
|
|
Derivative Instruments and Hedging Activities Disclosures [Line Items] |
|
|
|
|
|
|
Oil and Gas Production Hedged Volumes |
368,000
|
|
368,000
|
|
|
|
Derivative, Swap Type, Fixed Price | $ / Boe |
1.47
|
|
1.47
|
|
|
|
Basis Swap [Member] | Fourth Quarter 2024 | Oil Basis Calendar Monthly Roll Differential Swap |
|
|
|
|
|
|
Derivative Instruments and Hedging Activities Disclosures [Line Items] |
|
|
|
|
|
|
Oil and Gas Production Hedged Volumes |
368,000
|
|
368,000
|
|
|
|
Derivative, Swap Type, Fixed Price | $ / Boe |
0.69
|
|
0.69
|
|
|
|
Basis Swap [Member] | First Quarter 2025 | Natural Gas Basis Derivative Swaps [Member] |
|
|
|
|
|
|
Derivative Instruments and Hedging Activities Disclosures [Line Items] |
|
|
|
|
|
|
Oil and Gas Production Hedged Volumes | MMBTU |
5,400,000
|
|
5,400,000
|
|
|
|
Derivative, Swap Type, Fixed Price | $ / MMBTU |
(0.09)
|
|
(0.09)
|
|
|
|
Basis Swap [Member] | First Quarter 2025 | Natural Gas Basis Derivative Swaps [Member] | Subsequent Event [Member] |
|
|
|
|
|
|
Derivative Instruments and Hedging Activities Disclosures [Line Items] |
|
|
|
|
|
|
Oil and Gas Production Hedged Volumes | MMBTU |
|
|
|
|
900,000
|
|
Derivative, Swap Type, Fixed Price | $ / MMBTU |
|
|
|
|
(0.23)
|
|
Basis Swap [Member] | First Quarter 2025 | Oil Basis Derivative |
|
|
|
|
|
|
Derivative Instruments and Hedging Activities Disclosures [Line Items] |
|
|
|
|
|
|
Oil and Gas Production Hedged Volumes |
270,000
|
|
270,000
|
|
|
|
Derivative, Swap Type, Fixed Price | $ / Boe |
1.75
|
|
1.75
|
|
|
|
Basis Swap [Member] | First Quarter 2025 | Oil Basis Derivative | Subsequent Event [Member] |
|
|
|
|
|
|
Derivative Instruments and Hedging Activities Disclosures [Line Items] |
|
|
|
|
|
|
Oil and Gas Production Hedged Volumes |
|
|
|
|
90,000
|
|
Derivative, Swap Type, Fixed Price | $ / Boe |
|
|
|
|
1.75
|
|
Basis Swap [Member] | First Quarter 2025 | Oil Basis Calendar Monthly Roll Differential Swap |
|
|
|
|
|
|
Derivative Instruments and Hedging Activities Disclosures [Line Items] |
|
|
|
|
|
|
Oil and Gas Production Hedged Volumes |
270,000
|
|
270,000
|
|
|
|
Derivative, Swap Type, Fixed Price | $ / Boe |
0.40
|
|
0.40
|
|
|
|
Basis Swap [Member] | First Quarter 2025 | Oil Basis Calendar Monthly Roll Differential Swap | Subsequent Event [Member] |
|
|
|
|
|
|
Derivative Instruments and Hedging Activities Disclosures [Line Items] |
|
|
|
|
|
|
Oil and Gas Production Hedged Volumes |
|
|
|
|
90,000
|
|
Derivative, Swap Type, Fixed Price | $ / Boe |
|
|
|
|
0.50
|
|
Basis Swap [Member] | Second Quarter 2025 | Natural Gas Basis Derivative Swaps [Member] |
|
|
|
|
|
|
Derivative Instruments and Hedging Activities Disclosures [Line Items] |
|
|
|
|
|
|
Oil and Gas Production Hedged Volumes | MMBTU |
5,460,000
|
|
5,460,000
|
|
|
|
Derivative, Swap Type, Fixed Price | $ / MMBTU |
(0.26)
|
|
(0.26)
|
|
|
|
Basis Swap [Member] | Second Quarter 2025 | Natural Gas Basis Derivative Swaps [Member] | Subsequent Event [Member] |
|
|
|
|
|
|
Derivative Instruments and Hedging Activities Disclosures [Line Items] |
|
|
|
|
|
|
Oil and Gas Production Hedged Volumes | MMBTU |
|
|
|
|
910,000
|
|
Derivative, Swap Type, Fixed Price | $ / MMBTU |
|
|
|
|
(0.23)
|
|
Basis Swap [Member] | Second Quarter 2025 | Oil Basis Derivative |
|
|
|
|
|
|
Derivative Instruments and Hedging Activities Disclosures [Line Items] |
|
|
|
|
|
|
Oil and Gas Production Hedged Volumes |
273,000
|
|
273,000
|
|
|
|
Derivative, Swap Type, Fixed Price | $ / Boe |
1.75
|
|
1.75
|
|
|
|
Basis Swap [Member] | Second Quarter 2025 | Oil Basis Derivative | Subsequent Event [Member] |
|
|
|
|
|
|
Derivative Instruments and Hedging Activities Disclosures [Line Items] |
|
|
|
|
|
|
Oil and Gas Production Hedged Volumes |
|
|
|
|
91,000
|
|
Derivative, Swap Type, Fixed Price | $ / Boe |
|
|
|
|
1.75
|
|
Basis Swap [Member] | Second Quarter 2025 | Oil Basis Calendar Monthly Roll Differential Swap |
|
|
|
|
|
|
Derivative Instruments and Hedging Activities Disclosures [Line Items] |
|
|
|
|
|
|
Oil and Gas Production Hedged Volumes |
273,000
|
|
273,000
|
|
|
|
Derivative, Swap Type, Fixed Price | $ / Boe |
0.40
|
|
0.40
|
|
|
|
Basis Swap [Member] | Second Quarter 2025 | Oil Basis Calendar Monthly Roll Differential Swap | Subsequent Event [Member] |
|
|
|
|
|
|
Derivative Instruments and Hedging Activities Disclosures [Line Items] |
|
|
|
|
|
|
Oil and Gas Production Hedged Volumes |
|
|
|
|
91,000
|
|
Derivative, Swap Type, Fixed Price | $ / Boe |
|
|
|
|
0.50
|
|
Basis Swap [Member] | Third Quarter 2025 | Natural Gas Basis Derivative Swaps [Member] |
|
|
|
|
|
|
Derivative Instruments and Hedging Activities Disclosures [Line Items] |
|
|
|
|
|
|
Oil and Gas Production Hedged Volumes | MMBTU |
5,520,000
|
|
5,520,000
|
|
|
|
Derivative, Swap Type, Fixed Price | $ / MMBTU |
(0.23)
|
|
(0.23)
|
|
|
|
Basis Swap [Member] | Third Quarter 2025 | Natural Gas Basis Derivative Swaps [Member] | Subsequent Event [Member] |
|
|
|
|
|
|
Derivative Instruments and Hedging Activities Disclosures [Line Items] |
|
|
|
|
|
|
Oil and Gas Production Hedged Volumes | MMBTU |
|
|
|
|
920,000
|
|
Derivative, Swap Type, Fixed Price | $ / MMBTU |
|
|
|
|
(0.23)
|
|
Basis Swap [Member] | Third Quarter 2025 | Oil Basis Derivative |
|
|
|
|
|
|
Derivative Instruments and Hedging Activities Disclosures [Line Items] |
|
|
|
|
|
|
Oil and Gas Production Hedged Volumes |
276,000
|
|
276,000
|
|
|
|
Derivative, Swap Type, Fixed Price | $ / Boe |
1.75
|
|
1.75
|
|
|
|
Basis Swap [Member] | Third Quarter 2025 | Oil Basis Derivative | Subsequent Event [Member] |
|
|
|
|
|
|
Derivative Instruments and Hedging Activities Disclosures [Line Items] |
|
|
|
|
|
|
Oil and Gas Production Hedged Volumes |
|
|
|
|
92,000
|
|
Derivative, Swap Type, Fixed Price | $ / Boe |
|
|
|
|
1.75
|
|
Basis Swap [Member] | Third Quarter 2025 | Oil Basis Calendar Monthly Roll Differential Swap |
|
|
|
|
|
|
Derivative Instruments and Hedging Activities Disclosures [Line Items] |
|
|
|
|
|
|
Oil and Gas Production Hedged Volumes |
276,000
|
|
276,000
|
|
|
|
Derivative, Swap Type, Fixed Price | $ / Boe |
0.40
|
|
0.40
|
|
|
|
Basis Swap [Member] | Third Quarter 2025 | Oil Basis Calendar Monthly Roll Differential Swap | Subsequent Event [Member] |
|
|
|
|
|
|
Derivative Instruments and Hedging Activities Disclosures [Line Items] |
|
|
|
|
|
|
Oil and Gas Production Hedged Volumes |
|
|
|
|
92,000
|
|
Derivative, Swap Type, Fixed Price | $ / Boe |
|
|
|
|
0.50
|
|
Basis Swap [Member] | Fourth Quarter 2025 | Natural Gas Basis Derivative Swaps [Member] |
|
|
|
|
|
|
Derivative Instruments and Hedging Activities Disclosures [Line Items] |
|
|
|
|
|
|
Oil and Gas Production Hedged Volumes | MMBTU |
5,520,000
|
|
5,520,000
|
|
|
|
Derivative, Swap Type, Fixed Price | $ / MMBTU |
(0.25)
|
|
(0.25)
|
|
|
|
Basis Swap [Member] | Fourth Quarter 2025 | Natural Gas Basis Derivative Swaps [Member] | Subsequent Event [Member] |
|
|
|
|
|
|
Derivative Instruments and Hedging Activities Disclosures [Line Items] |
|
|
|
|
|
|
Oil and Gas Production Hedged Volumes | MMBTU |
|
|
|
|
920,000
|
|
Derivative, Swap Type, Fixed Price | $ / MMBTU |
|
|
|
|
(0.23)
|
|
Basis Swap [Member] | Fourth Quarter 2025 | Oil Basis Derivative |
|
|
|
|
|
|
Derivative Instruments and Hedging Activities Disclosures [Line Items] |
|
|
|
|
|
|
Oil and Gas Production Hedged Volumes |
276,000
|
|
276,000
|
|
|
|
Derivative, Swap Type, Fixed Price | $ / Boe |
1.75
|
|
1.75
|
|
|
|
Basis Swap [Member] | Fourth Quarter 2025 | Oil Basis Derivative | Subsequent Event [Member] |
|
|
|
|
|
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92,000
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|
|
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1.75
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276,000
|
|
276,000
|
|
|
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0.40
|
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0.40
|
|
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92,000
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|
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0.50
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v3.23.3
Summary of Significant Accounting Policies (Details Textual) $ in Thousands |
3 Months Ended |
9 Months Ended |
|
|
|
|
Sep. 30, 2023
USD ($)
MMBTU
bbl
$ / Boe
$ / MMBTU
shares
|
Jun. 30, 2023
shares
|
Mar. 31, 2023
shares
|
Sep. 30, 2022
USD ($)
shares
|
Jun. 30, 2022
shares
|
Mar. 31, 2022
shares
|
Sep. 30, 2023
USD ($)
MMBTU
bbl
$ / Boe
$ / MMBTU
shares
|
Sep. 30, 2022
USD ($)
shares
|
Oct. 31, 2023
bbl
MMBTU
$ / MMBTU
$ / Boe
|
Dec. 31, 2022
USD ($)
|
Sep. 20, 2022 |
Dec. 31, 2021
USD ($)
|
Summary of Significant Accounting Policies |
|
|
|
|
|
|
|
|
|
|
|
|
Capitalized Costs Oil and Gas Producing Activities | $ |
$ 1,400
|
|
|
$ 1,100
|
|
|
$ 4,100
|
$ 3,300
|
|
|
|
|
Proved oil and gas properties | $ |
2,827,145
|
|
|
|
|
|
2,827,145
|
|
|
$ 2,506,853
|
|
|
Unproved oil and gas properties | $ |
27,821
|
|
|
|
|
|
27,821
|
|
|
16,272
|
|
|
Furniture, fixtures, and other equipment | $ |
6,301
|
|
|
|
|
|
6,301
|
|
|
6,098
|
|
|
Less - Accumulated depreciation, depletion, and amortization | $ |
(1,151,141)
|
|
|
|
|
|
(1,151,141)
|
|
|
(1,004,044)
|
|
|
Net Furniture, Fixtures and other equipment | $ |
$ 1,710,126
|
|
|
|
|
|
1,710,126
|
|
|
1,525,179
|
|
|
Discount rate for estimated future net revenues from proved properties |
10.00%
|
|
|
|
|
|
|
|
|
|
|
|
Write-down of oil and gas properties | $ |
$ 0
|
|
|
0
|
|
|
0
|
0
|
|
|
|
|
Allowance for doubtful accounts receivable, current | $ |
100
|
|
|
|
|
|
100
|
|
|
100
|
|
$ 100
|
Accounts receivable, gross | $ |
60,400
|
|
|
|
|
|
60,400
|
|
|
70,900
|
|
45,300
|
Accounts receivable related to joint interest owners | $ |
1,900
|
|
|
|
|
|
1,900
|
|
|
5,600
|
|
1,900
|
Severance tax receivable | $ |
9,100
|
|
|
|
|
|
9,100
|
|
|
4,300
|
|
1,000
|
Other receivables | $ |
8,800
|
|
|
|
|
|
$ 8,800
|
|
|
8,900
|
|
$ 1,500
|
Percentage of working interest in wells |
|
|
|
|
|
|
100.00%
|
|
|
|
|
|
Total amount of supervision fees charged to wells | $ |
$ 3,000
|
|
|
$ 2,800
|
|
|
$ 8,600
|
$ 6,100
|
|
|
|
|
Effective Income Tax Rate Reconciliation, Percent |
17.00%
|
|
|
4.00%
|
|
|
22.00%
|
4.00%
|
|
|
|
|
Provision (Benefit) for Income Taxes | $ |
$ (949)
|
|
|
$ 6,066
|
|
|
$ 33,214
|
$ 7,678
|
|
|
|
|
Oil and gas sales | $ |
173,963
|
|
|
$ 242,181
|
|
|
440,317
|
$ 554,442
|
|
|
|
|
Trade accounts payable | $ |
30,708
|
|
|
|
|
|
30,708
|
|
|
23,660
|
|
|
Accrued operating expenses | $ |
11,266
|
|
|
|
|
|
11,266
|
|
|
10,572
|
|
|
Accrued payroll costs | $ |
3,267
|
|
|
|
|
|
3,267
|
|
|
4,814
|
|
|
Asset retirement obligation - current portion | $ |
1,578
|
|
|
|
|
|
1,578
|
|
|
1,284
|
|
|
Accrued non-income based taxes | $ |
13,303
|
|
|
|
|
|
13,303
|
|
|
4,849
|
|
|
Accrued corporate and legal fees | $ |
181
|
|
|
|
|
|
181
|
|
|
388
|
|
|
WTI contingency payouts - current portion | $ |
1,537
|
|
|
|
|
|
1,537
|
|
|
1,600
|
|
|
Payables for Settled Derivatives | $ |
3,549
|
|
|
|
|
|
3,549
|
|
|
6,026
|
|
|
Other payables | $ |
9,342
|
|
|
|
|
|
9,342
|
|
|
7,007
|
|
|
Accounts payable and accrued liabilities | $ |
$ 74,731
|
|
|
|
|
|
$ 74,731
|
|
|
$ 60,200
|
|
|
Purchase of treasury stock (shares) | shares |
361
|
5,310
|
126,240
|
7,853
|
16,485
|
96,012
|
131,911
|
120,350
|
|
|
|
|
Treasury Shares Pursuant to Purchase Price Adjustment (shares) | shares |
|
|
|
184
|
|
41,191
|
|
41,375
|
|
|
|
|
Stockholders Rights Agreement, Percentage of Common Stock Threshold |
|
|
|
|
|
|
|
|
|
|
0.15
|
|
Oil sales [Member] |
|
|
|
|
|
|
|
|
|
|
|
|
Summary of Significant Accounting Policies |
|
|
|
|
|
|
|
|
|
|
|
|
Oil and gas sales | $ |
$ 112,456
|
|
|
$ 71,811
|
|
|
$ 267,263
|
$ 155,566
|
|
|
|
|
Natural gas sales [Member] |
|
|
|
|
|
|
|
|
|
|
|
|
Summary of Significant Accounting Policies |
|
|
|
|
|
|
|
|
|
|
|
|
Oil and gas sales | $ |
46,075
|
|
|
150,958
|
|
|
132,802
|
351,626
|
|
|
|
|
NGL sales [Member] |
|
|
|
|
|
|
|
|
|
|
|
|
Summary of Significant Accounting Policies |
|
|
|
|
|
|
|
|
|
|
|
|
Oil and gas sales | $ |
$ 15,432
|
|
|
$ 19,412
|
|
|
$ 40,252
|
$ 47,250
|
|
|
|
|
Collar Contracts [Member] | Fourth Quarter 2023 | Oil Derivative Swaps |
|
|
|
|
|
|
|
|
|
|
|
|
Summary of Significant Accounting Policies |
|
|
|
|
|
|
|
|
|
|
|
|
Oil and Gas Production Hedged Volumes | MMBTU |
302,242
|
|
|
|
|
|
302,242
|
|
|
|
|
|
Collar Contracts [Member] | Fourth Quarter 2023 | Natural Gas Derivative Swaps |
|
|
|
|
|
|
|
|
|
|
|
|
Summary of Significant Accounting Policies |
|
|
|
|
|
|
|
|
|
|
|
|
Oil and Gas Production Hedged Volumes | MMBTU |
12,445,000
|
|
|
|
|
|
12,445,000
|
|
|
|
|
|
Collar Contracts [Member] | First Quarter 2024 | Oil Derivative Swaps |
|
|
|
|
|
|
|
|
|
|
|
|
Summary of Significant Accounting Policies |
|
|
|
|
|
|
|
|
|
|
|
|
Oil and Gas Production Hedged Volumes | MMBTU |
319,700
|
|
|
|
|
|
319,700
|
|
|
|
|
|
Collar Contracts [Member] | First Quarter 2024 | Natural Gas Derivative Swaps |
|
|
|
|
|
|
|
|
|
|
|
|
Summary of Significant Accounting Policies |
|
|
|
|
|
|
|
|
|
|
|
|
Oil and Gas Production Hedged Volumes | MMBTU |
9,661,000
|
|
|
|
|
|
9,661,000
|
|
|
|
|
|
Collar Contracts [Member] | Second Quarter 2024 | Oil Derivative Swaps |
|
|
|
|
|
|
|
|
|
|
|
|
Summary of Significant Accounting Policies |
|
|
|
|
|
|
|
|
|
|
|
|
Oil and Gas Production Hedged Volumes | MMBTU |
215,000
|
|
|
|
|
|
215,000
|
|
|
|
|
|
Collar Contracts [Member] | Second Quarter 2024 | Natural Gas Derivative Swaps |
|
|
|
|
|
|
|
|
|
|
|
|
Summary of Significant Accounting Policies |
|
|
|
|
|
|
|
|
|
|
|
|
Oil and Gas Production Hedged Volumes | MMBTU |
4,643,000
|
|
|
|
|
|
4,643,000
|
|
|
|
|
|
Collar Contracts [Member] | Third Quarter 2024 | Oil Derivative Swaps |
|
|
|
|
|
|
|
|
|
|
|
|
Summary of Significant Accounting Policies |
|
|
|
|
|
|
|
|
|
|
|
|
Oil and Gas Production Hedged Volumes | MMBTU |
184,000
|
|
|
|
|
|
184,000
|
|
|
|
|
|
Collar Contracts [Member] | Third Quarter 2024 | Natural Gas Derivative Swaps |
|
|
|
|
|
|
|
|
|
|
|
|
Summary of Significant Accounting Policies |
|
|
|
|
|
|
|
|
|
|
|
|
Oil and Gas Production Hedged Volumes | MMBTU |
3,878,000
|
|
|
|
|
|
3,878,000
|
|
|
|
|
|
Collar Contracts [Member] | Fourth Quarter 2024 | Oil Derivative Swaps |
|
|
|
|
|
|
|
|
|
|
|
|
Summary of Significant Accounting Policies |
|
|
|
|
|
|
|
|
|
|
|
|
Oil and Gas Production Hedged Volumes | MMBTU |
184,000
|
|
|
|
|
|
184,000
|
|
|
|
|
|
Collar Contracts [Member] | Fourth Quarter 2024 | Natural Gas Derivative Swaps |
|
|
|
|
|
|
|
|
|
|
|
|
Summary of Significant Accounting Policies |
|
|
|
|
|
|
|
|
|
|
|
|
Oil and Gas Production Hedged Volumes | MMBTU |
3,865,000
|
|
|
|
|
|
3,865,000
|
|
|
|
|
|
Collar Contracts [Member] | First Quarter 2025 | Oil Derivative Swaps |
|
|
|
|
|
|
|
|
|
|
|
|
Summary of Significant Accounting Policies |
|
|
|
|
|
|
|
|
|
|
|
|
Oil and Gas Production Hedged Volumes | MMBTU |
238,500
|
|
|
|
|
|
238,500
|
|
|
|
|
|
Collar Contracts [Member] | First Quarter 2025 | Natural Gas Derivative Swaps |
|
|
|
|
|
|
|
|
|
|
|
|
Summary of Significant Accounting Policies |
|
|
|
|
|
|
|
|
|
|
|
|
Oil and Gas Production Hedged Volumes | MMBTU |
5,130,000
|
|
|
|
|
|
5,130,000
|
|
|
|
|
|
Collar Contracts [Member] | Second Quarter 2025 | Oil Derivative Swaps |
|
|
|
|
|
|
|
|
|
|
|
|
Summary of Significant Accounting Policies |
|
|
|
|
|
|
|
|
|
|
|
|
Oil and Gas Production Hedged Volumes | MMBTU |
227,500
|
|
|
|
|
|
227,500
|
|
|
|
|
|
Collar Contracts [Member] | Second Quarter 2025 | Natural Gas Derivative Swaps |
|
|
|
|
|
|
|
|
|
|
|
|
Summary of Significant Accounting Policies |
|
|
|
|
|
|
|
|
|
|
|
|
Oil and Gas Production Hedged Volumes | MMBTU |
4,914,000
|
|
|
|
|
|
4,914,000
|
|
|
|
|
|
Collar Contracts [Member] | Third Quarter 2025 | Natural Gas Derivative Swaps |
|
|
|
|
|
|
|
|
|
|
|
|
Summary of Significant Accounting Policies |
|
|
|
|
|
|
|
|
|
|
|
|
Oil and Gas Production Hedged Volumes | MMBTU |
920,000
|
|
|
|
|
|
920,000
|
|
|
|
|
|
Collar Contracts [Member] | Fourth Quarter 2025 | Natural Gas Derivative Swaps |
|
|
|
|
|
|
|
|
|
|
|
|
Summary of Significant Accounting Policies |
|
|
|
|
|
|
|
|
|
|
|
|
Oil and Gas Production Hedged Volumes | MMBTU |
920,000
|
|
|
|
|
|
920,000
|
|
|
|
|
|
Collar Contracts [Member] | First Quarter 2026 | Oil Derivative Swaps |
|
|
|
|
|
|
|
|
|
|
|
|
Summary of Significant Accounting Policies |
|
|
|
|
|
|
|
|
|
|
|
|
Oil and Gas Production Hedged Volumes | MMBTU |
90,000
|
|
|
|
|
|
90,000
|
|
|
|
|
|
Collar Contracts [Member] | Second Quarter 2026 | Oil Derivative Swaps |
|
|
|
|
|
|
|
|
|
|
|
|
Summary of Significant Accounting Policies |
|
|
|
|
|
|
|
|
|
|
|
|
Oil and Gas Production Hedged Volumes | MMBTU |
91,000
|
|
|
|
|
|
91,000
|
|
|
|
|
|
Collar Contracts [Member] | Third Quarter 2026 | Oil Derivative Swaps |
|
|
|
|
|
|
|
|
|
|
|
|
Summary of Significant Accounting Policies |
|
|
|
|
|
|
|
|
|
|
|
|
Oil and Gas Production Hedged Volumes | MMBTU |
92,000
|
|
|
|
|
|
92,000
|
|
|
|
|
|
Swap [Member] | Fourth Quarter 2023 | Oil Derivative Swaps |
|
|
|
|
|
|
|
|
|
|
|
|
Summary of Significant Accounting Policies |
|
|
|
|
|
|
|
|
|
|
|
|
Oil and Gas Production Hedged Volumes |
707,300
|
|
|
|
|
|
707,300
|
|
|
|
|
|
Derivative, Swap Type, Fixed Price | $ / Boe |
78.53
|
|
|
|
|
|
78.53
|
|
|
|
|
|
Swap [Member] | Fourth Quarter 2023 | Natural Gas Derivative Swaps |
|
|
|
|
|
|
|
|
|
|
|
|
Summary of Significant Accounting Policies |
|
|
|
|
|
|
|
|
|
|
|
|
Oil and Gas Production Hedged Volumes | MMBTU |
5,727,000
|
|
|
|
|
|
5,727,000
|
|
|
|
|
|
Derivative, Swap Type, Fixed Price | $ / MMBTU |
4.20
|
|
|
|
|
|
4.20
|
|
|
|
|
|
Swap [Member] | Fourth Quarter 2023 | NGL Derivative |
|
|
|
|
|
|
|
|
|
|
|
|
Summary of Significant Accounting Policies |
|
|
|
|
|
|
|
|
|
|
|
|
Oil and Gas Production Hedged Volumes |
345,000
|
|
|
|
|
|
345,000
|
|
|
|
|
|
Derivative, Swap Type, Fixed Price | $ / MMBTU |
32.87
|
|
|
|
|
|
32.87
|
|
|
|
|
|
Swap [Member] | First Quarter 2024 | Oil Derivative Swaps |
|
|
|
|
|
|
|
|
|
|
|
|
Summary of Significant Accounting Policies |
|
|
|
|
|
|
|
|
|
|
|
|
Oil and Gas Production Hedged Volumes |
728,000
|
|
|
|
|
|
728,000
|
|
|
|
|
|
Derivative, Swap Type, Fixed Price | $ / Boe |
77.67
|
|
|
|
|
|
77.67
|
|
|
|
|
|
Swap [Member] | First Quarter 2024 | Oil Derivative Swaps | Subsequent Event [Member] |
|
|
|
|
|
|
|
|
|
|
|
|
Summary of Significant Accounting Policies |
|
|
|
|
|
|
|
|
|
|
|
|
Oil and Gas Production Hedged Volumes |
|
|
|
|
|
|
|
|
91,000
|
|
|
|
Derivative, Swap Type, Fixed Price | $ / Boe |
|
|
|
|
|
|
|
|
83.40
|
|
|
|
Swap [Member] | First Quarter 2024 | Natural Gas Derivative Swaps |
|
|
|
|
|
|
|
|
|
|
|
|
Summary of Significant Accounting Policies |
|
|
|
|
|
|
|
|
|
|
|
|
Oil and Gas Production Hedged Volumes | MMBTU |
7,686,000
|
|
|
|
|
|
7,686,000
|
|
|
|
|
|
Derivative, Swap Type, Fixed Price | $ / MMBTU |
4.12
|
|
|
|
|
|
4.12
|
|
|
|
|
|
Swap [Member] | First Quarter 2024 | Natural Gas Derivative Swaps | Subsequent Event [Member] |
|
|
|
|
|
|
|
|
|
|
|
|
Summary of Significant Accounting Policies |
|
|
|
|
|
|
|
|
|
|
|
|
Oil and Gas Production Hedged Volumes | MMBTU |
|
|
|
|
|
|
|
|
1,820,000
|
|
|
|
Derivative, Swap Type, Fixed Price | $ / MMBTU |
|
|
|
|
|
|
|
|
3.66
|
|
|
|
Swap [Member] | First Quarter 2024 | NGL Derivative |
|
|
|
|
|
|
|
|
|
|
|
|
Summary of Significant Accounting Policies |
|
|
|
|
|
|
|
|
|
|
|
|
Oil and Gas Production Hedged Volumes |
400,400
|
|
|
|
|
|
400,400
|
|
|
|
|
|
Derivative, Swap Type, Fixed Price | $ / MMBTU |
26.30
|
|
|
|
|
|
26.30
|
|
|
|
|
|
Swap [Member] | First Quarter 2024 | NGL Derivative | Subsequent Event [Member] |
|
|
|
|
|
|
|
|
|
|
|
|
Summary of Significant Accounting Policies |
|
|
|
|
|
|
|
|
|
|
|
|
Oil and Gas Production Hedged Volumes |
|
|
|
|
|
|
|
|
91,000
|
|
|
|
Derivative, Swap Type, Fixed Price | $ / MMBTU |
|
|
|
|
|
|
|
|
24.25
|
|
|
|
Swap [Member] | Second Quarter 2024 | Oil Derivative Swaps |
|
|
|
|
|
|
|
|
|
|
|
|
Summary of Significant Accounting Policies |
|
|
|
|
|
|
|
|
|
|
|
|
Oil and Gas Production Hedged Volumes |
754,550
|
|
|
|
|
|
754,550
|
|
|
|
|
|
Derivative, Swap Type, Fixed Price | $ / Boe |
77.59
|
|
|
|
|
|
77.59
|
|
|
|
|
|
Swap [Member] | Second Quarter 2024 | Oil Derivative Swaps | Subsequent Event [Member] |
|
|
|
|
|
|
|
|
|
|
|
|
Summary of Significant Accounting Policies |
|
|
|
|
|
|
|
|
|
|
|
|
Oil and Gas Production Hedged Volumes |
|
|
|
|
|
|
|
|
91,000
|
|
|
|
Derivative, Swap Type, Fixed Price | $ / Boe |
|
|
|
|
|
|
|
|
81.31
|
|
|
|
Swap [Member] | Second Quarter 2024 | Natural Gas Derivative Swaps |
|
|
|
|
|
|
|
|
|
|
|
|
Summary of Significant Accounting Policies |
|
|
|
|
|
|
|
|
|
|
|
|
Oil and Gas Production Hedged Volumes | MMBTU |
12,350,000
|
|
|
|
|
|
12,350,000
|
|
|
|
|
|
Derivative, Swap Type, Fixed Price | $ / MMBTU |
3.67
|
|
|
|
|
|
3.67
|
|
|
|
|
|
Swap [Member] | Second Quarter 2024 | Natural Gas Derivative Swaps | Subsequent Event [Member] |
|
|
|
|
|
|
|
|
|
|
|
|
Summary of Significant Accounting Policies |
|
|
|
|
|
|
|
|
|
|
|
|
Oil and Gas Production Hedged Volumes | MMBTU |
|
|
|
|
|
|
|
|
2,430,000
|
|
|
|
Derivative, Swap Type, Fixed Price | $ / MMBTU |
|
|
|
|
|
|
|
|
3.31
|
|
|
|
Swap [Member] | Second Quarter 2024 | NGL Derivative |
|
|
|
|
|
|
|
|
|
|
|
|
Summary of Significant Accounting Policies |
|
|
|
|
|
|
|
|
|
|
|
|
Oil and Gas Production Hedged Volumes |
400,400
|
|
|
|
|
|
400,400
|
|
|
|
|
|
Derivative, Swap Type, Fixed Price | $ / MMBTU |
26.30
|
|
|
|
|
|
26.30
|
|
|
|
|
|
Swap [Member] | Second Quarter 2024 | NGL Derivative | Subsequent Event [Member] |
|
|
|
|
|
|
|
|
|
|
|
|
Summary of Significant Accounting Policies |
|
|
|
|
|
|
|
|
|
|
|
|
Oil and Gas Production Hedged Volumes |
|
|
|
|
|
|
|
|
91,000
|
|
|
|
Derivative, Swap Type, Fixed Price | $ / MMBTU |
|
|
|
|
|
|
|
|
24.25
|
|
|
|
Swap [Member] | Third Quarter 2024 | Oil Derivative Swaps |
|
|
|
|
|
|
|
|
|
|
|
|
Summary of Significant Accounting Policies |
|
|
|
|
|
|
|
|
|
|
|
|
Oil and Gas Production Hedged Volumes |
779,620
|
|
|
|
|
|
779,620
|
|
|
|
|
|
Derivative, Swap Type, Fixed Price | $ / Boe |
76.48
|
|
|
|
|
|
76.48
|
|
|
|
|
|
Swap [Member] | Third Quarter 2024 | Oil Derivative Swaps | Subsequent Event [Member] |
|
|
|
|
|
|
|
|
|
|
|
|
Summary of Significant Accounting Policies |
|
|
|
|
|
|
|
|
|
|
|
|
Oil and Gas Production Hedged Volumes |
|
|
|
|
|
|
|
|
92,000
|
|
|
|
Derivative, Swap Type, Fixed Price | $ / Boe |
|
|
|
|
|
|
|
|
79.63
|
|
|
|
Swap [Member] | Third Quarter 2024 | Natural Gas Derivative Swaps |
|
|
|
|
|
|
|
|
|
|
|
|
Summary of Significant Accounting Policies |
|
|
|
|
|
|
|
|
|
|
|
|
Oil and Gas Production Hedged Volumes | MMBTU |
12,420,000
|
|
|
|
|
|
12,420,000
|
|
|
|
|
|
Derivative, Swap Type, Fixed Price | $ / MMBTU |
3.78
|
|
|
|
|
|
3.78
|
|
|
|
|
|
Swap [Member] | Third Quarter 2024 | Natural Gas Derivative Swaps | Subsequent Event [Member] |
|
|
|
|
|
|
|
|
|
|
|
|
Summary of Significant Accounting Policies |
|
|
|
|
|
|
|
|
|
|
|
|
Oil and Gas Production Hedged Volumes | MMBTU |
|
|
|
|
|
|
|
|
2,760,000
|
|
|
|
Derivative, Swap Type, Fixed Price | $ / MMBTU |
|
|
|
|
|
|
|
|
3.46
|
|
|
|
Swap [Member] | Third Quarter 2024 | NGL Derivative |
|
|
|
|
|
|
|
|
|
|
|
|
Summary of Significant Accounting Policies |
|
|
|
|
|
|
|
|
|
|
|
|
Oil and Gas Production Hedged Volumes |
404,800
|
|
|
|
|
|
404,800
|
|
|
|
|
|
Derivative, Swap Type, Fixed Price | $ / MMBTU |
26.30
|
|
|
|
|
|
26.30
|
|
|
|
|
|
Swap [Member] | Third Quarter 2024 | NGL Derivative | Subsequent Event [Member] |
|
|
|
|
|
|
|
|
|
|
|
|
Summary of Significant Accounting Policies |
|
|
|
|
|
|
|
|
|
|
|
|
Oil and Gas Production Hedged Volumes |
|
|
|
|
|
|
|
|
92,000
|
|
|
|
Derivative, Swap Type, Fixed Price | $ / MMBTU |
|
|
|
|
|
|
|
|
24.25
|
|
|
|
Swap [Member] | Fourth Quarter 2024 | Oil Derivative Swaps |
|
|
|
|
|
|
|
|
|
|
|
|
Summary of Significant Accounting Policies |
|
|
|
|
|
|
|
|
|
|
|
|
Oil and Gas Production Hedged Volumes |
762,100
|
|
|
|
|
|
762,100
|
|
|
|
|
|
Derivative, Swap Type, Fixed Price | $ / Boe |
76.16
|
|
|
|
|
|
76.16
|
|
|
|
|
|
Swap [Member] | Fourth Quarter 2024 | Oil Derivative Swaps | Subsequent Event [Member] |
|
|
|
|
|
|
|
|
|
|
|
|
Summary of Significant Accounting Policies |
|
|
|
|
|
|
|
|
|
|
|
|
Oil and Gas Production Hedged Volumes |
|
|
|
|
|
|
|
|
92,000
|
|
|
|
Derivative, Swap Type, Fixed Price | $ / Boe |
|
|
|
|
|
|
|
|
78.21
|
|
|
|
Swap [Member] | Fourth Quarter 2024 | Natural Gas Derivative Swaps |
|
|
|
|
|
|
|
|
|
|
|
|
Summary of Significant Accounting Policies |
|
|
|
|
|
|
|
|
|
|
|
|
Oil and Gas Production Hedged Volumes | MMBTU |
12,420,000
|
|
|
|
|
|
12,420,000
|
|
|
|
|
|
Derivative, Swap Type, Fixed Price | $ / MMBTU |
4.12
|
|
|
|
|
|
4.12
|
|
|
|
|
|
Swap [Member] | Fourth Quarter 2024 | Natural Gas Derivative Swaps | Subsequent Event [Member] |
|
|
|
|
|
|
|
|
|
|
|
|
Summary of Significant Accounting Policies |
|
|
|
|
|
|
|
|
|
|
|
|
Oil and Gas Production Hedged Volumes | MMBTU |
|
|
|
|
|
|
|
|
2,760,000
|
|
|
|
Derivative, Swap Type, Fixed Price | $ / MMBTU |
|
|
|
|
|
|
|
|
3.75
|
|
|
|
Swap [Member] | Fourth Quarter 2024 | NGL Derivative |
|
|
|
|
|
|
|
|
|
|
|
|
Summary of Significant Accounting Policies |
|
|
|
|
|
|
|
|
|
|
|
|
Oil and Gas Production Hedged Volumes |
404,800
|
|
|
|
|
|
404,800
|
|
|
|
|
|
Derivative, Swap Type, Fixed Price | $ / MMBTU |
26.30
|
|
|
|
|
|
26.30
|
|
|
|
|
|
Swap [Member] | Fourth Quarter 2024 | NGL Derivative | Subsequent Event [Member] |
|
|
|
|
|
|
|
|
|
|
|
|
Summary of Significant Accounting Policies |
|
|
|
|
|
|
|
|
|
|
|
|
Oil and Gas Production Hedged Volumes |
|
|
|
|
|
|
|
|
92,000
|
|
|
|
Derivative, Swap Type, Fixed Price | $ / MMBTU |
|
|
|
|
|
|
|
|
24.25
|
|
|
|
Swap [Member] | First Quarter 2025 | Oil Derivative Swaps |
|
|
|
|
|
|
|
|
|
|
|
|
Summary of Significant Accounting Policies |
|
|
|
|
|
|
|
|
|
|
|
|
Oil and Gas Production Hedged Volumes |
666,000
|
|
|
|
|
|
666,000
|
|
|
|
|
|
Derivative, Swap Type, Fixed Price | $ / Boe |
71.60
|
|
|
|
|
|
71.60
|
|
|
|
|
|
Swap [Member] | First Quarter 2025 | Oil Derivative Swaps | Subsequent Event [Member] |
|
|
|
|
|
|
|
|
|
|
|
|
Summary of Significant Accounting Policies |
|
|
|
|
|
|
|
|
|
|
|
|
Oil and Gas Production Hedged Volumes |
|
|
|
|
|
|
|
|
90,000
|
|
|
|
Derivative, Swap Type, Fixed Price | $ / Boe |
|
|
|
|
|
|
|
|
76.52
|
|
|
|
Swap [Member] | First Quarter 2025 | Natural Gas Derivative Swaps |
|
|
|
|
|
|
|
|
|
|
|
|
Summary of Significant Accounting Policies |
|
|
|
|
|
|
|
|
|
|
|
|
Oil and Gas Production Hedged Volumes | MMBTU |
9,450,000
|
|
|
|
|
|
9,450,000
|
|
|
|
|
|
Derivative, Swap Type, Fixed Price | $ / MMBTU |
4.25
|
|
|
|
|
|
4.25
|
|
|
|
|
|
Swap [Member] | First Quarter 2025 | Natural Gas Derivative Swaps | Subsequent Event [Member] |
|
|
|
|
|
|
|
|
|
|
|
|
Summary of Significant Accounting Policies |
|
|
|
|
|
|
|
|
|
|
|
|
Oil and Gas Production Hedged Volumes | MMBTU |
|
|
|
|
|
|
|
|
2,700,000
|
|
|
|
Derivative, Swap Type, Fixed Price | $ / MMBTU |
|
|
|
|
|
|
|
|
4.20
|
|
|
|
Swap [Member] | First Quarter 2025 | NGL Derivative |
|
|
|
|
|
|
|
|
|
|
|
|
Summary of Significant Accounting Policies |
|
|
|
|
|
|
|
|
|
|
|
|
Oil and Gas Production Hedged Volumes |
270,000
|
|
|
|
|
|
270,000
|
|
|
|
|
|
Derivative, Swap Type, Fixed Price | $ / MMBTU |
24.17
|
|
|
|
|
|
24.17
|
|
|
|
|
|
Swap [Member] | Second Quarter 2025 | Oil Derivative Swaps |
|
|
|
|
|
|
|
|
|
|
|
|
Summary of Significant Accounting Policies |
|
|
|
|
|
|
|
|
|
|
|
|
Oil and Gas Production Hedged Volumes |
673,400
|
|
|
|
|
|
673,400
|
|
|
|
|
|
Derivative, Swap Type, Fixed Price | $ / Boe |
71.60
|
|
|
|
|
|
71.60
|
|
|
|
|
|
Swap [Member] | Second Quarter 2025 | Oil Derivative Swaps | Subsequent Event [Member] |
|
|
|
|
|
|
|
|
|
|
|
|
Summary of Significant Accounting Policies |
|
|
|
|
|
|
|
|
|
|
|
|
Oil and Gas Production Hedged Volumes |
|
|
|
|
|
|
|
|
91,000
|
|
|
|
Derivative, Swap Type, Fixed Price | $ / Boe |
|
|
|
|
|
|
|
|
75.38
|
|
|
|
Swap [Member] | Second Quarter 2025 | Natural Gas Derivative Swaps |
|
|
|
|
|
|
|
|
|
|
|
|
Summary of Significant Accounting Policies |
|
|
|
|
|
|
|
|
|
|
|
|
Oil and Gas Production Hedged Volumes | MMBTU |
9,555,000
|
|
|
|
|
|
9,555,000
|
|
|
|
|
|
Derivative, Swap Type, Fixed Price | $ / MMBTU |
3.71
|
|
|
|
|
|
3.71
|
|
|
|
|
|
Swap [Member] | Second Quarter 2025 | Natural Gas Derivative Swaps | Subsequent Event [Member] |
|
|
|
|
|
|
|
|
|
|
|
|
Summary of Significant Accounting Policies |
|
|
|
|
|
|
|
|
|
|
|
|
Oil and Gas Production Hedged Volumes | MMBTU |
|
|
|
|
|
|
|
|
2,730,000
|
|
|
|
Derivative, Swap Type, Fixed Price | $ / MMBTU |
|
|
|
|
|
|
|
|
3.75
|
|
|
|
Swap [Member] | Second Quarter 2025 | NGL Derivative |
|
|
|
|
|
|
|
|
|
|
|
|
Summary of Significant Accounting Policies |
|
|
|
|
|
|
|
|
|
|
|
|
Oil and Gas Production Hedged Volumes |
273,000
|
|
|
|
|
|
273,000
|
|
|
|
|
|
Derivative, Swap Type, Fixed Price | $ / MMBTU |
24.17
|
|
|
|
|
|
24.17
|
|
|
|
|
|
Swap [Member] | Third Quarter 2025 | Oil Derivative Swaps |
|
|
|
|
|
|
|
|
|
|
|
|
Summary of Significant Accounting Policies |
|
|
|
|
|
|
|
|
|
|
|
|
Oil and Gas Production Hedged Volumes |
680,800
|
|
|
|
|
|
680,800
|
|
|
|
|
|
Derivative, Swap Type, Fixed Price | $ / Boe |
71.60
|
|
|
|
|
|
71.60
|
|
|
|
|
|
Swap [Member] | Third Quarter 2025 | Oil Derivative Swaps | Subsequent Event [Member] |
|
|
|
|
|
|
|
|
|
|
|
|
Summary of Significant Accounting Policies |
|
|
|
|
|
|
|
|
|
|
|
|
Oil and Gas Production Hedged Volumes |
|
|
|
|
|
|
|
|
92,000
|
|
|
|
Derivative, Swap Type, Fixed Price | $ / Boe |
|
|
|
|
|
|
|
|
74.56
|
|
|
|
Swap [Member] | Third Quarter 2025 | Natural Gas Derivative Swaps |
|
|
|
|
|
|
|
|
|
|
|
|
Summary of Significant Accounting Policies |
|
|
|
|
|
|
|
|
|
|
|
|
Oil and Gas Production Hedged Volumes | MMBTU |
11,960,000
|
|
|
|
|
|
11,960,000
|
|
|
|
|
|
Derivative, Swap Type, Fixed Price | $ / MMBTU |
3.83
|
|
|
|
|
|
3.83
|
|
|
|
|
|
Swap [Member] | Third Quarter 2025 | Natural Gas Derivative Swaps | Subsequent Event [Member] |
|
|
|
|
|
|
|
|
|
|
|
|
Summary of Significant Accounting Policies |
|
|
|
|
|
|
|
|
|
|
|
|
Oil and Gas Production Hedged Volumes | MMBTU |
|
|
|
|
|
|
|
|
2,760,000
|
|
|
|
Derivative, Swap Type, Fixed Price | $ / MMBTU |
|
|
|
|
|
|
|
|
3.89
|
|
|
|
Swap [Member] | Third Quarter 2025 | NGL Derivative |
|
|
|
|
|
|
|
|
|
|
|
|
Summary of Significant Accounting Policies |
|
|
|
|
|
|
|
|
|
|
|
|
Oil and Gas Production Hedged Volumes |
276,000
|
|
|
|
|
|
276,000
|
|
|
|
|
|
Derivative, Swap Type, Fixed Price | $ / MMBTU |
24.17
|
|
|
|
|
|
24.17
|
|
|
|
|
|
Swap [Member] | Fourth Quarter 2025 | Oil Derivative Swaps |
|
|
|
|
|
|
|
|
|
|
|
|
Summary of Significant Accounting Policies |
|
|
|
|
|
|
|
|
|
|
|
|
Oil and Gas Production Hedged Volumes |
588,800
|
|
|
|
|
|
588,800
|
|
|
|
|
|
Derivative, Swap Type, Fixed Price | $ / Boe |
71.29
|
|
|
|
|
|
71.29
|
|
|
|
|
|
Swap [Member] | Fourth Quarter 2025 | Oil Derivative Swaps | Subsequent Event [Member] |
|
|
|
|
|
|
|
|
|
|
|
|
Summary of Significant Accounting Policies |
|
|
|
|
|
|
|
|
|
|
|
|
Oil and Gas Production Hedged Volumes |
|
|
|
|
|
|
|
|
92,000
|
|
|
|
Derivative, Swap Type, Fixed Price | $ / Boe |
|
|
|
|
|
|
|
|
73.58
|
|
|
|
Swap [Member] | Fourth Quarter 2025 | Natural Gas Derivative Swaps |
|
|
|
|
|
|
|
|
|
|
|
|
Summary of Significant Accounting Policies |
|
|
|
|
|
|
|
|
|
|
|
|
Oil and Gas Production Hedged Volumes | MMBTU |
8,740,000
|
|
|
|
|
|
8,740,000
|
|
|
|
|
|
Derivative, Swap Type, Fixed Price | $ / MMBTU |
4.17
|
|
|
|
|
|
4.17
|
|
|
|
|
|
Swap [Member] | Fourth Quarter 2025 | Natural Gas Derivative Swaps | Subsequent Event [Member] |
|
|
|
|
|
|
|
|
|
|
|
|
Summary of Significant Accounting Policies |
|
|
|
|
|
|
|
|
|
|
|
|
Oil and Gas Production Hedged Volumes | MMBTU |
|
|
|
|
|
|
|
|
1,540,000
|
|
|
|
Derivative, Swap Type, Fixed Price | $ / MMBTU |
|
|
|
|
|
|
|
|
4.11
|
|
|
|
Swap [Member] | Fourth Quarter 2025 | NGL Derivative |
|
|
|
|
|
|
|
|
|
|
|
|
Summary of Significant Accounting Policies |
|
|
|
|
|
|
|
|
|
|
|
|
Oil and Gas Production Hedged Volumes |
276,000
|
|
|
|
|
|
276,000
|
|
|
|
|
|
Swap [Member] | First Quarter 2026 | Oil Derivative Swaps |
|
|
|
|
|
|
|
|
|
|
|
|
Summary of Significant Accounting Policies |
|
|
|
|
|
|
|
|
|
|
|
|
Oil and Gas Production Hedged Volumes |
315,000
|
|
|
|
|
|
315,000
|
|
|
|
|
|
Derivative, Swap Type, Fixed Price | $ / Boe |
69.40
|
|
|
|
|
|
69.40
|
|
|
|
|
|
Swap [Member] | First Quarter 2026 | Oil Derivative Swaps | Subsequent Event [Member] |
|
|
|
|
|
|
|
|
|
|
|
|
Summary of Significant Accounting Policies |
|
|
|
|
|
|
|
|
|
|
|
|
Oil and Gas Production Hedged Volumes |
|
|
|
|
|
|
|
|
157,500
|
|
|
|
Derivative, Swap Type, Fixed Price | $ / Boe |
|
|
|
|
|
|
|
|
68.01
|
|
|
|
Swap [Member] | First Quarter 2026 | Natural Gas Derivative Swaps |
|
|
|
|
|
|
|
|
|
|
|
|
Summary of Significant Accounting Policies |
|
|
|
|
|
|
|
|
|
|
|
|
Oil and Gas Production Hedged Volumes | MMBTU |
9,680,000
|
|
|
|
|
|
9,680,000
|
|
|
|
|
|
Derivative, Swap Type, Fixed Price | $ / MMBTU |
4.48
|
|
|
|
|
|
4.48
|
|
|
|
|
|
Swap [Member] | First Quarter 2026 | Natural Gas Derivative Swaps | Subsequent Event [Member] |
|
|
|
|
|
|
|
|
|
|
|
|
Summary of Significant Accounting Policies |
|
|
|
|
|
|
|
|
|
|
|
|
Oil and Gas Production Hedged Volumes | MMBTU |
|
|
|
|
|
|
|
|
900,000
|
|
|
|
Derivative, Swap Type, Fixed Price | $ / MMBTU |
|
|
|
|
|
|
|
|
4.56
|
|
|
|
Swap [Member] | Second Quarter 2026 | Oil Derivative Swaps |
|
|
|
|
|
|
|
|
|
|
|
|
Summary of Significant Accounting Policies |
|
|
|
|
|
|
|
|
|
|
|
|
Oil and Gas Production Hedged Volumes |
318,500
|
|
|
|
|
|
318,500
|
|
|
|
|
|
Derivative, Swap Type, Fixed Price | $ / Boe |
69.40
|
|
|
|
|
|
69.40
|
|
|
|
|
|
Swap [Member] | Second Quarter 2026 | Oil Derivative Swaps | Subsequent Event [Member] |
|
|
|
|
|
|
|
|
|
|
|
|
Summary of Significant Accounting Policies |
|
|
|
|
|
|
|
|
|
|
|
|
Oil and Gas Production Hedged Volumes |
|
|
|
|
|
|
|
|
136,500
|
|
|
|
Derivative, Swap Type, Fixed Price | $ / Boe |
|
|
|
|
|
|
|
|
67.98
|
|
|
|
Swap [Member] | Second Quarter 2026 | Natural Gas Derivative Swaps |
|
|
|
|
|
|
|
|
|
|
|
|
Summary of Significant Accounting Policies |
|
|
|
|
|
|
|
|
|
|
|
|
Oil and Gas Production Hedged Volumes | MMBTU |
9,555,000
|
|
|
|
|
|
9,555,000
|
|
|
|
|
|
Derivative, Swap Type, Fixed Price | $ / MMBTU |
3.56
|
|
|
|
|
|
3.56
|
|
|
|
|
|
Swap [Member] | Second Quarter 2026 | Natural Gas Derivative Swaps | Subsequent Event [Member] |
|
|
|
|
|
|
|
|
|
|
|
|
Summary of Significant Accounting Policies |
|
|
|
|
|
|
|
|
|
|
|
|
Oil and Gas Production Hedged Volumes | MMBTU |
|
|
|
|
|
|
|
|
910,000
|
|
|
|
Derivative, Swap Type, Fixed Price | $ / MMBTU |
|
|
|
|
|
|
|
|
3.53
|
|
|
|
Swap [Member] | Third Quarter 2026 | Oil Derivative Swaps |
|
|
|
|
|
|
|
|
|
|
|
|
Summary of Significant Accounting Policies |
|
|
|
|
|
|
|
|
|
|
|
|
Oil and Gas Production Hedged Volumes |
322,000
|
|
|
|
|
|
322,000
|
|
|
|
|
|
Derivative, Swap Type, Fixed Price | $ / Boe |
69.40
|
|
|
|
|
|
69.40
|
|
|
|
|
|
Swap [Member] | Third Quarter 2026 | Oil Derivative Swaps | Subsequent Event [Member] |
|
|
|
|
|
|
|
|
|
|
|
|
Summary of Significant Accounting Policies |
|
|
|
|
|
|
|
|
|
|
|
|
Oil and Gas Production Hedged Volumes |
|
|
|
|
|
|
|
|
110,400
|
|
|
|
Derivative, Swap Type, Fixed Price | $ / Boe |
|
|
|
|
|
|
|
|
67.94
|
|
|
|
Swap [Member] | Third Quarter 2026 | Natural Gas Derivative Swaps |
|
|
|
|
|
|
|
|
|
|
|
|
Summary of Significant Accounting Policies |
|
|
|
|
|
|
|
|
|
|
|
|
Oil and Gas Production Hedged Volumes | MMBTU |
9,660,000
|
|
|
|
|
|
9,660,000
|
|
|
|
|
|
Derivative, Swap Type, Fixed Price | $ / MMBTU |
3.74
|
|
|
|
|
|
3.74
|
|
|
|
|
|
Swap [Member] | Third Quarter 2026 | Natural Gas Derivative Swaps | Subsequent Event [Member] |
|
|
|
|
|
|
|
|
|
|
|
|
Summary of Significant Accounting Policies |
|
|
|
|
|
|
|
|
|
|
|
|
Oil and Gas Production Hedged Volumes | MMBTU |
|
|
|
|
|
|
|
|
920,000
|
|
|
|
Derivative, Swap Type, Fixed Price | $ / MMBTU |
|
|
|
|
|
|
|
|
3.73
|
|
|
|
Swap [Member] | Fourth Quarter 2026 | Oil Derivative Swaps |
|
|
|
|
|
|
|
|
|
|
|
|
Summary of Significant Accounting Policies |
|
|
|
|
|
|
|
|
|
|
|
|
Oil and Gas Production Hedged Volumes |
230,000
|
|
|
|
|
|
230,000
|
|
|
|
|
|
Derivative, Swap Type, Fixed Price | $ / Boe |
69.42
|
|
|
|
|
|
69.42
|
|
|
|
|
|
Swap [Member] | Fourth Quarter 2026 | Oil Derivative Swaps | Subsequent Event [Member] |
|
|
|
|
|
|
|
|
|
|
|
|
Summary of Significant Accounting Policies |
|
|
|
|
|
|
|
|
|
|
|
|
Oil and Gas Production Hedged Volumes |
|
|
|
|
|
|
|
|
156,150
|
|
|
|
Derivative, Swap Type, Fixed Price | $ / Boe |
|
|
|
|
|
|
|
|
68.60
|
|
|
|
Swap [Member] | Fourth Quarter 2026 | Natural Gas Derivative Swaps |
|
|
|
|
|
|
|
|
|
|
|
|
Summary of Significant Accounting Policies |
|
|
|
|
|
|
|
|
|
|
|
|
Oil and Gas Production Hedged Volumes | MMBTU |
9,200,000
|
|
|
|
|
|
9,200,000
|
|
|
|
|
|
Derivative, Swap Type, Fixed Price | $ / MMBTU |
4.13
|
|
|
|
|
|
4.13
|
|
|
|
|
|
Swap [Member] | Fourth Quarter 2026 | Natural Gas Derivative Swaps | Subsequent Event [Member] |
|
|
|
|
|
|
|
|
|
|
|
|
Summary of Significant Accounting Policies |
|
|
|
|
|
|
|
|
|
|
|
|
Oil and Gas Production Hedged Volumes | MMBTU |
|
|
|
|
|
|
|
|
920,000
|
|
|
|
Derivative, Swap Type, Fixed Price | $ / MMBTU |
|
|
|
|
|
|
|
|
4.19
|
|
|
|
Basis Swap [Member] | Fourth Quarter 2023 | Natural Gas Basis Derivative Swaps [Member] |
|
|
|
|
|
|
|
|
|
|
|
|
Summary of Significant Accounting Policies |
|
|
|
|
|
|
|
|
|
|
|
|
Oil and Gas Production Hedged Volumes | MMBTU |
13,800,000
|
|
|
|
|
|
13,800,000
|
|
|
|
|
|
Derivative, Swap Type, Fixed Price | $ / MMBTU |
(0.23)
|
|
|
|
|
|
(0.23)
|
|
|
|
|
|
Basis Swap [Member] | Fourth Quarter 2023 | Oil Basis Derivative |
|
|
|
|
|
|
|
|
|
|
|
|
Summary of Significant Accounting Policies |
|
|
|
|
|
|
|
|
|
|
|
|
Oil and Gas Production Hedged Volumes |
122,000
|
|
|
|
|
|
122,000
|
|
|
|
|
|
Derivative, Swap Type, Fixed Price | $ / Boe |
0.80
|
|
|
|
|
|
0.80
|
|
|
|
|
|
Basis Swap [Member] | Fourth Quarter 2023 | Oil Basis Derivative | Subsequent Event [Member] |
|
|
|
|
|
|
|
|
|
|
|
|
Summary of Significant Accounting Policies |
|
|
|
|
|
|
|
|
|
|
|
|
Oil and Gas Production Hedged Volumes |
|
|
|
|
|
|
|
|
61,000
|
|
|
|
Derivative, Swap Type, Fixed Price | $ / Boe |
|
|
|
|
|
|
|
|
0.90
|
|
|
|
Basis Swap [Member] | Fourth Quarter 2023 | Oil Basis Calendar Monthly Roll Differential Swap |
|
|
|
|
|
|
|
|
|
|
|
|
Summary of Significant Accounting Policies |
|
|
|
|
|
|
|
|
|
|
|
|
Oil and Gas Production Hedged Volumes |
122,000
|
|
|
|
|
|
122,000
|
|
|
|
|
|
Derivative, Swap Type, Fixed Price | $ / Boe |
2.44
|
|
|
|
|
|
2.44
|
|
|
|
|
|
Basis Swap [Member] | Fourth Quarter 2023 | Oil Basis Calendar Monthly Roll Differential Swap | Subsequent Event [Member] |
|
|
|
|
|
|
|
|
|
|
|
|
Summary of Significant Accounting Policies |
|
|
|
|
|
|
|
|
|
|
|
|
Oil and Gas Production Hedged Volumes |
|
|
|
|
|
|
|
|
61,000
|
|
|
|
Derivative, Swap Type, Fixed Price | $ / Boe |
|
|
|
|
|
|
|
|
2.40
|
|
|
|
Basis Swap [Member] | First Quarter 2024 | Natural Gas Basis Derivative Swaps [Member] |
|
|
|
|
|
|
|
|
|
|
|
|
Summary of Significant Accounting Policies |
|
|
|
|
|
|
|
|
|
|
|
|
Oil and Gas Production Hedged Volumes | MMBTU |
15,470,000
|
|
|
|
|
|
15,470,000
|
|
|
|
|
|
Derivative, Swap Type, Fixed Price | $ / MMBTU |
(0.02)
|
|
|
|
|
|
(0.02)
|
|
|
|
|
|
Basis Swap [Member] | First Quarter 2024 | Natural Gas Basis Derivative Swaps [Member] | Subsequent Event [Member] |
|
|
|
|
|
|
|
|
|
|
|
|
Summary of Significant Accounting Policies |
|
|
|
|
|
|
|
|
|
|
|
|
Oil and Gas Production Hedged Volumes | MMBTU |
|
|
|
|
|
|
|
|
910,000
|
|
|
|
Derivative, Swap Type, Fixed Price | $ / MMBTU |
|
|
|
|
|
|
|
|
(0.21)
|
|
|
|
Basis Swap [Member] | First Quarter 2024 | Oil Basis Derivative |
|
|
|
|
|
|
|
|
|
|
|
|
Summary of Significant Accounting Policies |
|
|
|
|
|
|
|
|
|
|
|
|
Oil and Gas Production Hedged Volumes |
364,000
|
|
|
|
|
|
364,000
|
|
|
|
|
|
Derivative, Swap Type, Fixed Price | $ / Boe |
1.47
|
|
|
|
|
|
1.47
|
|
|
|
|
|
Basis Swap [Member] | First Quarter 2024 | Oil Basis Calendar Monthly Roll Differential Swap |
|
|
|
|
|
|
|
|
|
|
|
|
Summary of Significant Accounting Policies |
|
|
|
|
|
|
|
|
|
|
|
|
Oil and Gas Production Hedged Volumes |
364,000
|
|
|
|
|
|
364,000
|
|
|
|
|
|
Derivative, Swap Type, Fixed Price | $ / Boe |
0.69
|
|
|
|
|
|
0.69
|
|
|
|
|
|
Basis Swap [Member] | Second Quarter 2024 | Natural Gas Basis Derivative Swaps [Member] |
|
|
|
|
|
|
|
|
|
|
|
|
Summary of Significant Accounting Policies |
|
|
|
|
|
|
|
|
|
|
|
|
Oil and Gas Production Hedged Volumes | MMBTU |
15,470,000
|
|
|
|
|
|
15,470,000
|
|
|
|
|
|
Derivative, Swap Type, Fixed Price | $ / MMBTU |
(0.29)
|
|
|
|
|
|
(0.29)
|
|
|
|
|
|
Basis Swap [Member] | Second Quarter 2024 | Natural Gas Basis Derivative Swaps [Member] | Subsequent Event [Member] |
|
|
|
|
|
|
|
|
|
|
|
|
Summary of Significant Accounting Policies |
|
|
|
|
|
|
|
|
|
|
|
|
Oil and Gas Production Hedged Volumes | MMBTU |
|
|
|
|
|
|
|
|
910,000
|
|
|
|
Derivative, Swap Type, Fixed Price | $ / MMBTU |
|
|
|
|
|
|
|
|
(0.21)
|
|
|
|
Basis Swap [Member] | Second Quarter 2024 | Oil Basis Derivative |
|
|
|
|
|
|
|
|
|
|
|
|
Summary of Significant Accounting Policies |
|
|
|
|
|
|
|
|
|
|
|
|
Oil and Gas Production Hedged Volumes |
364,000
|
|
|
|
|
|
364,000
|
|
|
|
|
|
Derivative, Swap Type, Fixed Price | $ / Boe |
1.47
|
|
|
|
|
|
1.47
|
|
|
|
|
|
Basis Swap [Member] | Second Quarter 2024 | Oil Basis Calendar Monthly Roll Differential Swap |
|
|
|
|
|
|
|
|
|
|
|
|
Summary of Significant Accounting Policies |
|
|
|
|
|
|
|
|
|
|
|
|
Oil and Gas Production Hedged Volumes |
364,000
|
|
|
|
|
|
364,000
|
|
|
|
|
|
Derivative, Swap Type, Fixed Price | $ / Boe |
0.69
|
|
|
|
|
|
0.69
|
|
|
|
|
|
Basis Swap [Member] | Third Quarter 2024 | Natural Gas Basis Derivative Swaps [Member] |
|
|
|
|
|
|
|
|
|
|
|
|
Summary of Significant Accounting Policies |
|
|
|
|
|
|
|
|
|
|
|
|
Oil and Gas Production Hedged Volumes | MMBTU |
15,640,000
|
|
|
|
|
|
15,640,000
|
|
|
|
|
|
Derivative, Swap Type, Fixed Price | $ / MMBTU |
(0.26)
|
|
|
|
|
|
(0.26)
|
|
|
|
|
|
Basis Swap [Member] | Third Quarter 2024 | Natural Gas Basis Derivative Swaps [Member] | Subsequent Event [Member] |
|
|
|
|
|
|
|
|
|
|
|
|
Summary of Significant Accounting Policies |
|
|
|
|
|
|
|
|
|
|
|
|
Oil and Gas Production Hedged Volumes | MMBTU |
|
|
|
|
|
|
|
|
920,000
|
|
|
|
Derivative, Swap Type, Fixed Price | $ / MMBTU |
|
|
|
|
|
|
|
|
(0.21)
|
|
|
|
Basis Swap [Member] | Third Quarter 2024 | Oil Basis Derivative |
|
|
|
|
|
|
|
|
|
|
|
|
Summary of Significant Accounting Policies |
|
|
|
|
|
|
|
|
|
|
|
|
Oil and Gas Production Hedged Volumes |
368,000
|
|
|
|
|
|
368,000
|
|
|
|
|
|
Derivative, Swap Type, Fixed Price | $ / Boe |
1.47
|
|
|
|
|
|
1.47
|
|
|
|
|
|
Basis Swap [Member] | Third Quarter 2024 | Oil Basis Calendar Monthly Roll Differential Swap |
|
|
|
|
|
|
|
|
|
|
|
|
Summary of Significant Accounting Policies |
|
|
|
|
|
|
|
|
|
|
|
|
Oil and Gas Production Hedged Volumes |
368,000
|
|
|
|
|
|
368,000
|
|
|
|
|
|
Derivative, Swap Type, Fixed Price | $ / Boe |
0.69
|
|
|
|
|
|
0.69
|
|
|
|
|
|
Basis Swap [Member] | Fourth Quarter 2024 | Natural Gas Basis Derivative Swaps [Member] |
|
|
|
|
|
|
|
|
|
|
|
|
Summary of Significant Accounting Policies |
|
|
|
|
|
|
|
|
|
|
|
|
Oil and Gas Production Hedged Volumes | MMBTU |
15,640,000
|
|
|
|
|
|
15,640,000
|
|
|
|
|
|
Derivative, Swap Type, Fixed Price | $ / MMBTU |
(0.28)
|
|
|
|
|
|
(0.28)
|
|
|
|
|
|
Basis Swap [Member] | Fourth Quarter 2024 | Natural Gas Basis Derivative Swaps [Member] | Subsequent Event [Member] |
|
|
|
|
|
|
|
|
|
|
|
|
Summary of Significant Accounting Policies |
|
|
|
|
|
|
|
|
|
|
|
|
Oil and Gas Production Hedged Volumes | MMBTU |
|
|
|
|
|
|
|
|
920,000
|
|
|
|
Derivative, Swap Type, Fixed Price | $ / MMBTU |
|
|
|
|
|
|
|
|
(0.21)
|
|
|
|
Basis Swap [Member] | Fourth Quarter 2024 | Oil Basis Derivative |
|
|
|
|
|
|
|
|
|
|
|
|
Summary of Significant Accounting Policies |
|
|
|
|
|
|
|
|
|
|
|
|
Oil and Gas Production Hedged Volumes |
368,000
|
|
|
|
|
|
368,000
|
|
|
|
|
|
Derivative, Swap Type, Fixed Price | $ / Boe |
1.47
|
|
|
|
|
|
1.47
|
|
|
|
|
|
Basis Swap [Member] | Fourth Quarter 2024 | Oil Basis Calendar Monthly Roll Differential Swap |
|
|
|
|
|
|
|
|
|
|
|
|
Summary of Significant Accounting Policies |
|
|
|
|
|
|
|
|
|
|
|
|
Oil and Gas Production Hedged Volumes |
368,000
|
|
|
|
|
|
368,000
|
|
|
|
|
|
Derivative, Swap Type, Fixed Price | $ / Boe |
0.69
|
|
|
|
|
|
0.69
|
|
|
|
|
|
Basis Swap [Member] | First Quarter 2025 | Natural Gas Basis Derivative Swaps [Member] |
|
|
|
|
|
|
|
|
|
|
|
|
Summary of Significant Accounting Policies |
|
|
|
|
|
|
|
|
|
|
|
|
Oil and Gas Production Hedged Volumes | MMBTU |
5,400,000
|
|
|
|
|
|
5,400,000
|
|
|
|
|
|
Derivative, Swap Type, Fixed Price | $ / MMBTU |
(0.09)
|
|
|
|
|
|
(0.09)
|
|
|
|
|
|
Basis Swap [Member] | First Quarter 2025 | Natural Gas Basis Derivative Swaps [Member] | Subsequent Event [Member] |
|
|
|
|
|
|
|
|
|
|
|
|
Summary of Significant Accounting Policies |
|
|
|
|
|
|
|
|
|
|
|
|
Oil and Gas Production Hedged Volumes | MMBTU |
|
|
|
|
|
|
|
|
900,000
|
|
|
|
Derivative, Swap Type, Fixed Price | $ / MMBTU |
|
|
|
|
|
|
|
|
(0.23)
|
|
|
|
Basis Swap [Member] | First Quarter 2025 | Oil Basis Derivative |
|
|
|
|
|
|
|
|
|
|
|
|
Summary of Significant Accounting Policies |
|
|
|
|
|
|
|
|
|
|
|
|
Oil and Gas Production Hedged Volumes |
270,000
|
|
|
|
|
|
270,000
|
|
|
|
|
|
Derivative, Swap Type, Fixed Price | $ / Boe |
1.75
|
|
|
|
|
|
1.75
|
|
|
|
|
|
Basis Swap [Member] | First Quarter 2025 | Oil Basis Derivative | Subsequent Event [Member] |
|
|
|
|
|
|
|
|
|
|
|
|
Summary of Significant Accounting Policies |
|
|
|
|
|
|
|
|
|
|
|
|
Oil and Gas Production Hedged Volumes |
|
|
|
|
|
|
|
|
90,000
|
|
|
|
Derivative, Swap Type, Fixed Price | $ / Boe |
|
|
|
|
|
|
|
|
1.75
|
|
|
|
Basis Swap [Member] | First Quarter 2025 | Oil Basis Calendar Monthly Roll Differential Swap |
|
|
|
|
|
|
|
|
|
|
|
|
Summary of Significant Accounting Policies |
|
|
|
|
|
|
|
|
|
|
|
|
Oil and Gas Production Hedged Volumes |
270,000
|
|
|
|
|
|
270,000
|
|
|
|
|
|
Derivative, Swap Type, Fixed Price | $ / Boe |
0.40
|
|
|
|
|
|
0.40
|
|
|
|
|
|
Basis Swap [Member] | First Quarter 2025 | Oil Basis Calendar Monthly Roll Differential Swap | Subsequent Event [Member] |
|
|
|
|
|
|
|
|
|
|
|
|
Summary of Significant Accounting Policies |
|
|
|
|
|
|
|
|
|
|
|
|
Oil and Gas Production Hedged Volumes |
|
|
|
|
|
|
|
|
90,000
|
|
|
|
Derivative, Swap Type, Fixed Price | $ / Boe |
|
|
|
|
|
|
|
|
0.50
|
|
|
|
Basis Swap [Member] | Second Quarter 2025 | Natural Gas Basis Derivative Swaps [Member] |
|
|
|
|
|
|
|
|
|
|
|
|
Summary of Significant Accounting Policies |
|
|
|
|
|
|
|
|
|
|
|
|
Oil and Gas Production Hedged Volumes | MMBTU |
5,460,000
|
|
|
|
|
|
5,460,000
|
|
|
|
|
|
Derivative, Swap Type, Fixed Price | $ / MMBTU |
(0.26)
|
|
|
|
|
|
(0.26)
|
|
|
|
|
|
Basis Swap [Member] | Second Quarter 2025 | Natural Gas Basis Derivative Swaps [Member] | Subsequent Event [Member] |
|
|
|
|
|
|
|
|
|
|
|
|
Summary of Significant Accounting Policies |
|
|
|
|
|
|
|
|
|
|
|
|
Oil and Gas Production Hedged Volumes | MMBTU |
|
|
|
|
|
|
|
|
910,000
|
|
|
|
Derivative, Swap Type, Fixed Price | $ / MMBTU |
|
|
|
|
|
|
|
|
(0.23)
|
|
|
|
Basis Swap [Member] | Second Quarter 2025 | Oil Basis Derivative |
|
|
|
|
|
|
|
|
|
|
|
|
Summary of Significant Accounting Policies |
|
|
|
|
|
|
|
|
|
|
|
|
Oil and Gas Production Hedged Volumes |
273,000
|
|
|
|
|
|
273,000
|
|
|
|
|
|
Derivative, Swap Type, Fixed Price | $ / Boe |
1.75
|
|
|
|
|
|
1.75
|
|
|
|
|
|
Basis Swap [Member] | Second Quarter 2025 | Oil Basis Derivative | Subsequent Event [Member] |
|
|
|
|
|
|
|
|
|
|
|
|
Summary of Significant Accounting Policies |
|
|
|
|
|
|
|
|
|
|
|
|
Oil and Gas Production Hedged Volumes |
|
|
|
|
|
|
|
|
91,000
|
|
|
|
Derivative, Swap Type, Fixed Price | $ / Boe |
|
|
|
|
|
|
|
|
1.75
|
|
|
|
Basis Swap [Member] | Second Quarter 2025 | Oil Basis Calendar Monthly Roll Differential Swap |
|
|
|
|
|
|
|
|
|
|
|
|
Summary of Significant Accounting Policies |
|
|
|
|
|
|
|
|
|
|
|
|
Oil and Gas Production Hedged Volumes |
273,000
|
|
|
|
|
|
273,000
|
|
|
|
|
|
Derivative, Swap Type, Fixed Price | $ / Boe |
0.40
|
|
|
|
|
|
0.40
|
|
|
|
|
|
Basis Swap [Member] | Second Quarter 2025 | Oil Basis Calendar Monthly Roll Differential Swap | Subsequent Event [Member] |
|
|
|
|
|
|
|
|
|
|
|
|
Summary of Significant Accounting Policies |
|
|
|
|
|
|
|
|
|
|
|
|
Oil and Gas Production Hedged Volumes |
|
|
|
|
|
|
|
|
91,000
|
|
|
|
Derivative, Swap Type, Fixed Price | $ / Boe |
|
|
|
|
|
|
|
|
0.50
|
|
|
|
Basis Swap [Member] | Third Quarter 2025 | Natural Gas Basis Derivative Swaps [Member] |
|
|
|
|
|
|
|
|
|
|
|
|
Summary of Significant Accounting Policies |
|
|
|
|
|
|
|
|
|
|
|
|
Oil and Gas Production Hedged Volumes | MMBTU |
5,520,000
|
|
|
|
|
|
5,520,000
|
|
|
|
|
|
Derivative, Swap Type, Fixed Price | $ / MMBTU |
(0.23)
|
|
|
|
|
|
(0.23)
|
|
|
|
|
|
Basis Swap [Member] | Third Quarter 2025 | Natural Gas Basis Derivative Swaps [Member] | Subsequent Event [Member] |
|
|
|
|
|
|
|
|
|
|
|
|
Summary of Significant Accounting Policies |
|
|
|
|
|
|
|
|
|
|
|
|
Oil and Gas Production Hedged Volumes | MMBTU |
|
|
|
|
|
|
|
|
920,000
|
|
|
|
Derivative, Swap Type, Fixed Price | $ / MMBTU |
|
|
|
|
|
|
|
|
(0.23)
|
|
|
|
Basis Swap [Member] | Third Quarter 2025 | Oil Basis Derivative |
|
|
|
|
|
|
|
|
|
|
|
|
Summary of Significant Accounting Policies |
|
|
|
|
|
|
|
|
|
|
|
|
Oil and Gas Production Hedged Volumes |
276,000
|
|
|
|
|
|
276,000
|
|
|
|
|
|
Derivative, Swap Type, Fixed Price | $ / Boe |
1.75
|
|
|
|
|
|
1.75
|
|
|
|
|
|
Basis Swap [Member] | Third Quarter 2025 | Oil Basis Derivative | Subsequent Event [Member] |
|
|
|
|
|
|
|
|
|
|
|
|
Summary of Significant Accounting Policies |
|
|
|
|
|
|
|
|
|
|
|
|
Oil and Gas Production Hedged Volumes |
|
|
|
|
|
|
|
|
92,000
|
|
|
|
Derivative, Swap Type, Fixed Price | $ / Boe |
|
|
|
|
|
|
|
|
1.75
|
|
|
|
Basis Swap [Member] | Third Quarter 2025 | Oil Basis Calendar Monthly Roll Differential Swap |
|
|
|
|
|
|
|
|
|
|
|
|
Summary of Significant Accounting Policies |
|
|
|
|
|
|
|
|
|
|
|
|
Oil and Gas Production Hedged Volumes |
276,000
|
|
|
|
|
|
276,000
|
|
|
|
|
|
Derivative, Swap Type, Fixed Price | $ / Boe |
0.40
|
|
|
|
|
|
0.40
|
|
|
|
|
|
Basis Swap [Member] | Third Quarter 2025 | Oil Basis Calendar Monthly Roll Differential Swap | Subsequent Event [Member] |
|
|
|
|
|
|
|
|
|
|
|
|
Summary of Significant Accounting Policies |
|
|
|
|
|
|
|
|
|
|
|
|
Oil and Gas Production Hedged Volumes |
|
|
|
|
|
|
|
|
92,000
|
|
|
|
Derivative, Swap Type, Fixed Price | $ / Boe |
|
|
|
|
|
|
|
|
0.50
|
|
|
|
Basis Swap [Member] | Fourth Quarter 2025 | Natural Gas Basis Derivative Swaps [Member] |
|
|
|
|
|
|
|
|
|
|
|
|
Summary of Significant Accounting Policies |
|
|
|
|
|
|
|
|
|
|
|
|
Oil and Gas Production Hedged Volumes | MMBTU |
5,520,000
|
|
|
|
|
|
5,520,000
|
|
|
|
|
|
Derivative, Swap Type, Fixed Price | $ / MMBTU |
(0.25)
|
|
|
|
|
|
(0.25)
|
|
|
|
|
|
Basis Swap [Member] | Fourth Quarter 2025 | Natural Gas Basis Derivative Swaps [Member] | Subsequent Event [Member] |
|
|
|
|
|
|
|
|
|
|
|
|
Summary of Significant Accounting Policies |
|
|
|
|
|
|
|
|
|
|
|
|
Oil and Gas Production Hedged Volumes | MMBTU |
|
|
|
|
|
|
|
|
920,000
|
|
|
|
Derivative, Swap Type, Fixed Price | $ / MMBTU |
|
|
|
|
|
|
|
|
(0.23)
|
|
|
|
Basis Swap [Member] | Fourth Quarter 2025 | Oil Basis Derivative |
|
|
|
|
|
|
|
|
|
|
|
|
Summary of Significant Accounting Policies |
|
|
|
|
|
|
|
|
|
|
|
|
Oil and Gas Production Hedged Volumes |
276,000
|
|
|
|
|
|
276,000
|
|
|
|
|
|
Derivative, Swap Type, Fixed Price | $ / Boe |
1.75
|
|
|
|
|
|
1.75
|
|
|
|
|
|
Basis Swap [Member] | Fourth Quarter 2025 | Oil Basis Derivative | Subsequent Event [Member] |
|
|
|
|
|
|
|
|
|
|
|
|
Summary of Significant Accounting Policies |
|
|
|
|
|
|
|
|
|
|
|
|
Oil and Gas Production Hedged Volumes |
|
|
|
|
|
|
|
|
92,000
|
|
|
|
Derivative, Swap Type, Fixed Price | $ / Boe |
|
|
|
|
|
|
|
|
1.75
|
|
|
|
Basis Swap [Member] | Fourth Quarter 2025 | Oil Basis Calendar Monthly Roll Differential Swap |
|
|
|
|
|
|
|
|
|
|
|
|
Summary of Significant Accounting Policies |
|
|
|
|
|
|
|
|
|
|
|
|
Oil and Gas Production Hedged Volumes |
276,000
|
|
|
|
|
|
276,000
|
|
|
|
|
|
Derivative, Swap Type, Fixed Price | $ / Boe |
0.40
|
|
|
|
|
|
0.40
|
|
|
|
|
|
Basis Swap [Member] | Fourth Quarter 2025 | Oil Basis Calendar Monthly Roll Differential Swap | Subsequent Event [Member] |
|
|
|
|
|
|
|
|
|
|
|
|
Summary of Significant Accounting Policies |
|
|
|
|
|
|
|
|
|
|
|
|
Oil and Gas Production Hedged Volumes |
|
|
|
|
|
|
|
|
92,000
|
|
|
|
Derivative, Swap Type, Fixed Price | $ / Boe |
|
|
|
|
|
|
|
|
0.50
|
|
|
|
Minimum [Member] |
|
|
|
|
|
|
|
|
|
|
|
|
Summary of Significant Accounting Policies |
|
|
|
|
|
|
|
|
|
|
|
|
Estimated useful lives of property |
2 years
|
|
|
|
|
|
2 years
|
|
|
|
|
|
Maximum [Member] |
|
|
|
|
|
|
|
|
|
|
|
|
Summary of Significant Accounting Policies |
|
|
|
|
|
|
|
|
|
|
|
|
Estimated useful lives of property |
20 years
|
|
|
|
|
|
20 years
|
|
|
|
|
|
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- DefinitionCapitalized costs oil and gas producing activities, total.
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+ ReferencesReference 1: http://www.xbrl.org/2003/role/exampleRef -Topic 852 -SubTopic 10 -Name Accounting Standards Codification -Section 55 -Paragraph 10 -Publisher FASB -URI https://asc.fasb.org//1943274/2147481372/852-10-55-10
Reference 2: http://fasb.org/us-gaap/role/ref/legacyRef -Name Accounting Standards Codification -Topic 210 -SubTopic 10 -Section S99 -Paragraph 1 -Subparagraph (SX 210.5-02.19(a)) -Publisher FASB -URI https://asc.fasb.org//1943274/2147480566/210-10-S99-1
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v3.23.3
Leases Leases (Details) $ in Thousands |
Sep. 30, 2023
USD ($)
|
Leases [Abstract] |
|
Lessee, Operating Lease, Liability, Payments, Remainder of Fiscal Year |
$ 2,667
|
Lessee, Operating Lease, Liability, Payments, Due Year Two |
4,166
|
Lessee, Operating Lease, Liability, Payments, Due Year Three |
2,427
|
Lessee, Operating Lease, Liability, Payments, Due Year Four |
1,194
|
Lessee, Operating Lease, Liability, Payments, Due Year Five |
61
|
Lessee, Operating Lease, Liability, Payments, Due after Year Five |
475
|
Lessee, Operating Lease, Liability, Payments, Due |
10,990
|
Lessee, Operating Lease, Liability, Undiscounted Excess Amount |
(879)
|
Operating Lease, Liability |
$ 10,111
|
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v3.23.3
Share-Based Compensation (Details Textual) - USD ($) $ / shares in Units, $ in Thousands |
|
|
|
|
|
|
3 Months Ended |
9 Months Ended |
|
Sep. 30, 2023 |
Feb. 23, 2023 |
Feb. 22, 2023 |
Feb. 23, 2022 |
Feb. 24, 2021 |
May 21, 2019 |
Sep. 30, 2023 |
Sep. 30, 2022 |
Jun. 30, 2022 |
Sep. 30, 2023 |
Sep. 30, 2022 |
Dec. 31, 2022 |
Share-based Compensation (Details Textual) |
|
|
|
|
|
|
|
|
|
|
|
|
Share-based Payment Arrangement, Noncash Expense |
|
|
|
|
|
|
|
|
|
$ 4,043
|
$ 3,901
|
|
Share-based compensation (capitalized) |
|
|
|
|
|
|
$ 100
|
$ 100
|
|
200
|
200
|
|
Stock Option Activity |
|
|
|
|
|
|
|
|
|
|
|
|
Options, Exercises in Period |
|
|
|
|
|
|
|
(11,087)
|
(4,497)
|
|
|
|
General and Administrative Expense [Member] |
|
|
|
|
|
|
|
|
|
|
|
|
Share-based Compensation (Details Textual) |
|
|
|
|
|
|
|
|
|
|
|
|
Share-based Payment Arrangement, Noncash Expense |
|
|
|
|
|
|
1,500
|
$ 1,200
|
|
4,000
|
$ 3,900
|
|
Share-based Payment Arrangement, Option [Member] |
|
|
|
|
|
|
|
|
|
|
|
|
Share-based Compensation (Details Textual) |
|
|
|
|
|
|
|
|
|
|
|
|
Stock option award unrecognized compensation |
$ 0
|
|
|
|
|
|
0
|
|
|
0
|
|
|
Stock option award outstanding aggregate intrinsic value |
$ 1,800
|
|
|
|
|
|
$ 1,800
|
|
|
1,800
|
|
|
Remaining contract life of outstanding stock options. |
3 years 7 months 6 days
|
|
|
|
|
|
|
|
|
|
|
|
Remaining contract life of exercisable stock option |
3 years 7 months 6 days
|
|
|
|
|
|
|
|
|
|
|
|
Stock option award exercisable aggregate intrinsic value |
|
|
|
|
|
|
|
|
|
$ 1,800
|
|
|
Stock Option Activity |
|
|
|
|
|
|
|
|
|
|
|
|
Options outstanding, beginning of period, shares |
196,162
|
|
|
|
|
|
196,162
|
|
|
196,162
|
|
196,162
|
Options outstanding, beginning of period, weighted average price |
$ 26.46
|
|
|
|
|
|
$ 26.46
|
|
|
$ 26.46
|
|
$ 26.46
|
Options, Grants in Period |
|
|
|
|
|
|
|
|
|
0
|
|
|
Options, Grants in Period, Weighted Average Grant Date Fair Value |
|
|
|
|
|
|
|
|
|
$ 0
|
|
|
Options, Exercises in Period |
|
|
|
|
|
|
|
|
|
0
|
|
|
Options, Exercises in Period, Weighted Average Exercise Price |
|
|
|
|
|
|
|
|
|
$ 0
|
|
|
Options exercisable, end of period, shares |
196,162
|
|
|
|
|
|
196,162
|
|
|
196,162
|
|
|
Options exercisable, end of period, weighted average price |
$ 26.46
|
|
|
|
|
|
$ 26.46
|
|
|
$ 26.46
|
|
|
Restricted Stock Units (RSUs) [Member] |
|
|
|
|
|
|
|
|
|
|
|
|
Share-based Compensation (Details Textual) |
|
|
|
|
|
|
|
|
|
|
|
|
Stock option award unrecognized compensation |
$ 5,100
|
|
|
|
|
|
$ 5,100
|
|
|
$ 5,100
|
|
|
Unrecognized compensation expense weighted-average period |
|
|
|
|
|
|
|
|
|
2 years
|
|
|
Restricted stock activity |
|
|
|
|
|
|
|
|
|
|
|
|
Restricted shares outstanding, beginning of period, shares |
|
|
|
|
|
|
|
|
|
227,114
|
|
|
Restricted shares outstanding, beginning of period, weighted average price |
|
|
|
|
|
|
|
|
|
$ 21.18
|
|
|
Restricted shares granted, shares |
|
|
|
|
|
|
|
|
|
195,791
|
|
|
Restricted shares granted, weighted average price |
|
|
|
|
|
|
|
|
|
$ 23.75
|
|
|
Restricted shares forfeited |
|
|
|
|
|
|
|
|
|
(1,424)
|
|
|
Restricted shares forfeited, weighted average price |
|
|
|
|
|
|
|
|
|
$ 25.44
|
|
|
Restricted shares vested, shares |
|
|
|
|
|
|
|
|
|
(137,467)
|
|
|
Restricted shares vested, weighted average price |
|
|
|
|
|
|
|
|
|
$ 17.78
|
|
|
Restricted shares outstanding, end of period, shares |
284,014
|
|
|
|
|
|
284,014
|
|
|
284,014
|
|
|
Restricted shares outstanding, end of period, weighted average price |
$ 24.58
|
|
|
|
|
|
$ 24.58
|
|
|
$ 24.58
|
|
|
Performance Shares [Member] |
|
|
|
|
|
|
|
|
|
|
|
|
Share-based Compensation (Details Textual) |
|
|
|
|
|
|
|
|
|
|
|
|
Stock option award unrecognized compensation |
$ 4,900
|
|
|
|
|
|
$ 4,900
|
|
|
$ 4,900
|
|
|
Unrecognized compensation expense weighted-average period |
1 year 10 months 24 days
|
|
|
|
|
|
|
|
|
|
|
|
Share-based Compensation, Expected Term |
|
3 years
|
|
3 years
|
2 years
|
3 years
|
|
|
|
|
|
|
Restricted stock activity |
|
|
|
|
|
|
|
|
|
|
|
|
Restricted shares outstanding, beginning of period, shares |
|
|
|
|
|
|
|
|
|
283,500
|
|
|
Restricted shares outstanding, beginning of period, weighted average price |
|
|
|
|
|
|
|
|
|
$ 23.18
|
|
|
Restricted shares granted, shares |
|
120,749
|
|
122,111
|
161,389
|
99,500
|
|
|
|
|
|
|
Restricted shares granted, weighted average price |
|
$ 31.18
|
|
$ 36.47
|
$ 13.13
|
$ 18.86
|
|
|
|
|
|
|
Performance based stock units, incremental shares vested |
|
|
|
142,021
|
|
|
|
|
|
|
|
|
Performance based stock units, incremental shares vested, Weighted Average Grant Date Fair Value |
|
|
|
$ 13.13
|
|
|
|
|
|
|
|
|
Restricted shares vested, shares |
|
|
(303,410)
|
(97,812)
|
|
|
|
|
|
(303,410)
|
|
|
Restricted shares vested, weighted average price |
|
|
|
|
|
|
|
|
|
$ 13.13
|
|
|
Restricted shares outstanding, end of period, shares |
242,860
|
|
|
|
|
|
242,860
|
|
|
242,860
|
|
|
Restricted shares outstanding, end of period, weighted average price |
$ 33.84
|
|
|
|
|
|
$ 33.84
|
|
|
$ 33.84
|
|
|
Percent of payout for performance based stock units |
100.00%
|
136.28%
|
|
150.93%
|
157.60%
|
112.90%
|
100.00%
|
|
|
100.00%
|
|
|
Approved payout for performance based stock units |
|
|
188.00%
|
117.00%
|
|
|
|
|
|
|
|
|
Minimum [Member] | Share-based Payment Arrangement, Option [Member] |
|
|
|
|
|
|
|
|
|
|
|
|
Share-based Compensation (Details Textual) |
|
|
|
|
|
|
|
|
|
|
|
|
Stock option award vesting period |
|
|
|
|
|
|
|
|
|
1 year
|
|
|
Minimum [Member] | Restricted Stock Units (RSUs) [Member] |
|
|
|
|
|
|
|
|
|
|
|
|
Share-based Compensation (Details Textual) |
|
|
|
|
|
|
|
|
|
|
|
|
Stock option award vesting period |
|
|
|
|
|
|
|
|
|
1 year
|
|
|
Minimum [Member] | Performance Shares [Member] |
|
|
|
|
|
|
|
|
|
|
|
|
Restricted stock activity |
|
|
|
|
|
|
|
|
|
|
|
|
Percent of payout for performance based stock units |
|
0.00%
|
|
0.00%
|
0.00%
|
0.00%
|
|
|
|
|
|
|
Maximum [Member] | Share-based Payment Arrangement, Option [Member] |
|
|
|
|
|
|
|
|
|
|
|
|
Share-based Compensation (Details Textual) |
|
|
|
|
|
|
|
|
|
|
|
|
Stock option award vesting period |
|
|
|
|
|
|
|
|
|
5 years
|
|
|
Maximum [Member] | Restricted Stock Units (RSUs) [Member] |
|
|
|
|
|
|
|
|
|
|
|
|
Share-based Compensation (Details Textual) |
|
|
|
|
|
|
|
|
|
|
|
|
Stock option award vesting period |
|
|
|
|
|
|
|
|
|
5 years
|
|
|
Maximum [Member] | Performance Shares [Member] |
|
|
|
|
|
|
|
|
|
|
|
|
Restricted stock activity |
|
|
|
|
|
|
|
|
|
|
|
|
Percent of payout for performance based stock units |
|
200.00%
|
|
200.00%
|
200.00%
|
200.00%
|
|
|
|
|
|
|
X |
- DefinitionRemaining contract life of exercisable stock option.
+ References
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Period Type: |
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|
X |
- DefinitionRemaining contract life of outstanding stock options.
+ References
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Period Type: |
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|
X |
- DefinitionShare-Based Compensation Arrangement by Share-Based Payment Award, Equity Instruments Other than Options, Incremental Grants in Period, Weighted Average Grant Date Fair Value
+ References
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v3.23.3
Earnings Per Share (Details) - USD ($) $ / shares in Units, $ in Thousands |
3 Months Ended |
9 Months Ended |
Sep. 30, 2023 |
Jun. 30, 2023 |
Mar. 31, 2023 |
Sep. 30, 2022 |
Jun. 30, 2022 |
Mar. 31, 2022 |
Sep. 30, 2023 |
Sep. 30, 2022 |
Basic EPS: |
|
|
|
|
|
|
|
|
Net Income (Loss) |
$ (4,771)
|
$ 24,937
|
$ 94,492
|
$ 142,541
|
$ 88,790
|
$ (64,255)
|
$ 114,658
|
$ 167,076
|
Income, share amounts |
22,985,000
|
|
|
22,308,000
|
|
|
22,677,000
|
18,885,000
|
Earnings Per Share, Basic |
$ (0.21)
|
|
|
$ 6.39
|
|
|
$ 5.06
|
$ 8.85
|
Diluted EPS: |
|
|
|
|
|
|
|
|
Net Income (Loss) Available to Common Stockholders, Diluted |
$ (4,771)
|
|
|
$ 142,541
|
|
|
$ 114,658
|
$ 167,076
|
Weighted Average Shares Outstanding - Diluted |
22,985,000
|
|
|
22,669,000
|
|
|
22,852,000
|
19,237,000
|
Earnings Per Share, Diluted |
$ (0.21)
|
|
|
$ 6.29
|
|
|
$ 5.02
|
$ 8.69
|
Issuance of common stock (shares) |
2,810,811
|
|
|
|
|
|
|
|
Proceeds from Issuance of Common Stock |
|
|
|
|
|
|
$ 97,133
|
$ 0
|
Share-based Payment Arrangement, Option [Member] |
|
|
|
|
|
|
|
|
Dilutive Securities: |
|
|
|
|
|
|
|
|
Dilutive Securities |
0
|
|
|
55,000
|
|
|
17,000
|
40,000
|
Diluted EPS: |
|
|
|
|
|
|
|
|
Antidilutive shares excluded from EPS, shares |
200,000
|
|
|
0
|
|
|
100,000
|
100,000
|
Restricted Stock Units (RSUs) [Member] |
|
|
|
|
|
|
|
|
Dilutive Securities: |
|
|
|
|
|
|
|
|
Dilutive Securities |
0
|
|
|
137,000
|
|
|
91,000
|
171,000
|
Diluted EPS: |
|
|
|
|
|
|
|
|
Antidilutive shares excluded from EPS, shares |
200,000
|
|
|
100,000
|
|
|
100,000
|
100,000
|
Performance Shares [Member] |
|
|
|
|
|
|
|
|
Dilutive Securities: |
|
|
|
|
|
|
|
|
Dilutive Securities |
0
|
|
|
169,000
|
|
|
67,000
|
141,000
|
Diluted EPS: |
|
|
|
|
|
|
|
|
Antidilutive shares excluded from EPS, shares |
100,000
|
|
|
0
|
|
|
0
|
0
|
X |
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v3.23.3
Long-Term Debt (Details) $ in Thousands |
|
|
|
|
3 Months Ended |
9 Months Ended |
|
|
Jun. 14, 2023 |
Mar. 20, 2023
USD ($)
|
Nov. 29, 2021
USD ($)
|
Nov. 12, 2021
USD ($)
|
Sep. 30, 2023
USD ($)
|
Sep. 30, 2022
USD ($)
|
Sep. 30, 2023
USD ($)
|
Sep. 30, 2022
USD ($)
|
Dec. 31, 2022
USD ($)
|
Dec. 15, 2017
USD ($)
|
Bank Borrowings |
|
|
|
|
|
|
|
|
|
|
Long-term Debt, excluding current maturities |
|
|
|
|
$ 645,096
|
|
$ 645,096
|
|
$ 688,531
|
|
Payments of Debt Issuance Costs |
|
|
|
|
|
|
0
|
$ 7,228
|
|
|
Second Lien [Abstract] |
|
|
|
|
|
|
|
|
|
|
Long-term debt, gross |
|
|
|
|
$ 648,000
|
|
648,000
|
|
692,000
|
|
Discount Rate for Estimated Future Net Revenues from Proved Properties |
|
|
|
|
10.00%
|
|
|
|
|
|
Gross interest expense including amortization of debt issuance costs |
|
|
|
|
$ 19,811
|
$ 12,173
|
54,746
|
26,632
|
|
|
New Credit Facility [Member] |
|
|
|
|
|
|
|
|
|
|
Bank Borrowings |
|
|
|
|
|
|
|
|
|
|
Debt Issuance Costs, Net |
|
|
|
|
7,000
|
|
7,000
|
|
8,700
|
|
Second Lien Notes [Member] |
|
|
|
|
|
|
|
|
|
|
Bank Borrowings |
|
|
|
|
|
|
|
|
|
|
Debt Issuance Costs, Net |
|
|
|
|
2,166
|
|
2,166
|
|
2,587
|
|
Long-term Debt, excluding current maturities |
|
|
|
|
150,000
|
|
150,000
|
|
150,000
|
$ 198,000
|
Second Lien [Abstract] |
|
|
|
|
|
|
|
|
|
|
Long-term debt, gross |
|
|
|
$ 150,000
|
|
|
|
|
|
200,000
|
Debt Instrument, Unamortized Discount |
|
|
|
|
$ (738)
|
|
$ (738)
|
|
(882)
|
$ (2,000)
|
Repayments of Long-Term Debt |
|
|
$ 50,000
|
|
|
|
|
|
|
|
Debt Instrument, Interest Rate, Stated Percentage |
|
|
|
|
13.16%
|
|
13.16%
|
|
|
|
Second Lien, Required Security Interest on Proved Reserves |
|
|
|
90.00%
|
|
|
|
|
|
|
Second Lien, Required Security Interest on Oil and Gas Properties |
|
|
|
90.00%
|
|
|
|
|
|
|
Discount Rate for Estimated Future Net Revenues for Proved Properties at 9% |
|
|
|
9.00%
|
|
|
|
|
|
|
Second Lien, Asset Coverage Ratio, Minimum |
|
|
|
1.25
|
|
|
|
|
|
|
Second Lien, Debt to EBITDA Ratio, after March 31, 2022 |
|
|
|
3.25
|
|
|
|
|
|
|
Long-term debt, net |
|
|
|
|
$ 147,100
|
|
$ 147,100
|
|
|
|
Gross interest expense including amortization of debt issuance costs |
|
|
|
|
5,200
|
3,800
|
14,900
|
10,700
|
|
|
Second Lien Notes [Member] | Alternative Base Interest Rate [Member] |
|
|
|
|
|
|
|
|
|
|
Second Lien [Abstract] |
|
|
|
|
|
|
|
|
|
|
Debt Instrument, Minimum Margin on SOFR |
1.00%
|
|
|
|
|
|
|
|
|
|
Debt Instrument, Basis Spread on Variable Rate |
6.50%
|
|
|
|
|
|
|
|
|
|
Second Lien Notes [Member] | Secured Overnight Financing Rate (SOFR) Overnight Index Swap Rate |
|
|
|
|
|
|
|
|
|
|
Second Lien [Abstract] |
|
|
|
|
|
|
|
|
|
|
Debt Instrument, Minimum Margin on SOFR |
0.25%
|
|
|
|
|
|
|
|
|
|
Debt Instrument, Basis Spread on Variable Rate |
7.50%
|
|
|
|
|
|
|
|
|
|
Second Lien Notes [Member] | Fed Funds Effective Rate Overnight Index Swap Rate |
|
|
|
|
|
|
|
|
|
|
Second Lien [Abstract] |
|
|
|
|
|
|
|
|
|
|
Debt Instrument, Basis Spread on Variable Rate |
0.50%
|
|
|
|
|
|
|
|
|
|
Line of Credit [Member] | New Credit Facility [Member] |
|
|
|
|
|
|
|
|
|
|
Bank Borrowings |
|
|
|
|
|
|
|
|
|
|
Long-term Debt, excluding current maturities |
|
|
|
|
498,000
|
|
498,000
|
|
542,000
|
|
Line of Credit Facility, Maximum Borrowing Capacity |
|
$ 2,000,000
|
|
|
|
|
|
|
|
|
Line of Credit Facility, Current Borrowing Capacity |
|
775,000
|
|
|
|
|
|
|
|
|
Line of Credit, Letters of Credit Issuable |
|
$ 25,000
|
|
|
|
|
|
|
|
|
Letters of Credit Outstanding, Amount |
|
|
|
|
$ 0
|
|
$ 0
|
|
$ 0
|
|
Commitment fee basis points for the credit facility |
|
0.50%
|
|
|
|
|
|
|
|
|
Line of Credit, Additional Interest Due to Payment Default |
|
2.00%
|
|
|
|
|
|
|
|
|
Debt, Weighted Average Interest Rate |
|
|
|
|
8.67%
|
|
8.67%
|
|
|
|
Line of Credit, Required Security Interest on Oil and Gas Properties |
|
85.00%
|
|
|
|
|
|
|
|
|
Line of Credit, Covenant, Debt to EBITDA Ratio |
|
3.00
|
|
|
|
|
|
|
|
|
Line of Credit, Covenant, Current Ratio, Minimum |
|
1.00
|
|
|
|
|
|
|
|
|
Line of Credit Facility, Commitment Fee Amount |
|
|
|
|
$ 200
|
300
|
$ 700
|
900
|
|
|
Payments of Debt Issuance Costs |
|
|
|
|
|
|
0
|
7,200
|
|
|
Second Lien [Abstract] |
|
|
|
|
|
|
|
|
|
|
Gross interest expense including amortization of debt issuance costs |
|
|
|
|
$ 14,600
|
$ 8,300
|
$ 39,800
|
$ 15,900
|
|
|
Line of Credit [Member] | New Credit Facility [Member] | Minimum [Member] | Secured Overnight Financing Rate (SOFR) Overnight Index Swap Rate |
|
|
|
|
|
|
|
|
|
|
Bank Borrowings |
|
|
|
|
|
|
|
|
|
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Debt instrument escalating basis spread on base rate |
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0.0175
|
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|
|
|
|
|
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|
0.0275
|
|
|
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|
|
|
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|
|
|
|
Bank Borrowings |
|
|
|
|
|
|
|
|
|
|
Debt instrument escalating basis spread on base rate |
|
0.0275
|
|
|
|
|
|
|
|
|
Debt Instrument Escalating Rates for Eurodollar Rate Loans |
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0.0375
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v3.23.3
Acquisitions and Dispositions Acquisitions and Dispositions (Details) $ in Thousands |
|
|
|
|
|
|
3 Months Ended |
9 Months Ended |
12 Months Ended |
Aug. 11, 2023
USD ($)
|
Oct. 31, 2022
USD ($)
|
Aug. 15, 2022
USD ($)
|
Jun. 30, 2022
USD ($)
shares
|
May 10, 2022
USD ($)
shares
|
Nov. 19, 2021
USD ($)
shares
|
Sep. 30, 2023
USD ($)
|
Sep. 30, 2022
USD ($)
|
Jun. 30, 2022
USD ($)
shares
|
Mar. 31, 2022
shares
|
Sep. 30, 2023
USD ($)
|
Sep. 30, 2022
USD ($)
|
Dec. 31, 2022
USD ($)
|
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] |
|
|
|
|
|
|
|
|
|
|
|
|
|
Stock Issued During Period, Shares, Acquisitions | shares |
|
|
|
|
|
|
|
|
5,448,472
|
489
|
|
|
|
Other current assets |
|
|
|
|
|
|
$ 3,825
|
|
|
|
$ 3,825
|
|
$ 2,671
|
Right of Use Assets |
|
|
|
|
|
|
10,085
|
|
|
|
10,085
|
|
12,077
|
Derivative, Fair Value, Net |
|
|
|
|
|
|
10,100
|
|
|
|
10,100
|
|
28,200
|
Non-current Lease Liability |
|
|
|
|
|
|
4,604
|
|
|
|
4,604
|
|
3,775
|
Asset Retirement Obligations, Noncurrent |
|
|
|
|
|
|
9,840
|
|
|
|
9,840
|
|
9,171
|
WTI Contingency Payout Fair Value |
|
|
|
|
|
$ 1,900
|
|
|
|
|
|
|
|
Proceeds from the sale of property and equipment |
|
|
|
|
|
|
|
|
|
|
0
|
$ 4,415
|
4,400
|
Gain (Loss) on WTI Contingency Payout |
|
|
|
|
|
|
(900)
|
$ 6,100
|
|
|
1,100
|
4,700
|
|
Teal Acquisition |
|
|
|
|
|
|
|
|
|
|
|
|
|
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] |
|
|
|
|
|
|
|
|
|
|
|
|
|
Acquisition of oil and gas properties |
|
|
|
|
|
37,600
|
|
|
|
|
|
|
|
Asset Acquisition, Consideration Transferred |
|
|
|
|
|
77,400
|
|
|
|
|
|
|
|
Asset Acquisition, Consideration Transferred, Equity Interest Issued and Issuable |
|
|
|
|
|
37,900
|
|
|
|
|
|
|
|
WTI Annual Earn Out Payment |
|
|
|
|
|
$ 1,600
|
|
|
|
|
|
|
|
WTI Annual Earn Out, Average Monthly Settlement Price |
|
|
|
|
|
70
|
|
|
|
|
|
|
|
2021 WTI Contingency Payable |
|
|
|
|
|
|
|
|
|
|
|
|
1,600
|
Gain (Loss) on WTI Contingency Payout |
|
|
|
|
|
|
$ 900
|
$ 700
|
|
|
1,000
|
$ 800
|
|
Teal Acquisition | Asset Acquisition, Shares Issuable |
|
|
|
|
|
|
|
|
|
|
|
|
|
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] |
|
|
|
|
|
|
|
|
|
|
|
|
|
Stock Issued During Period, Shares, Acquisitions | shares |
|
|
|
|
|
1,351,961
|
|
|
|
|
|
|
|
SandPoint Acquisition |
|
|
|
|
|
|
|
|
|
|
|
|
|
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] |
|
|
|
|
|
|
|
|
|
|
|
|
|
Acquisition of oil and gas properties |
|
|
|
|
$ 27,709
|
|
|
|
|
|
|
|
|
Asset Acquisition, Consideration Transferred |
|
|
|
|
67,476
|
|
|
|
|
|
|
|
|
Asset Acquisition, Consideration Transferred, Equity Interest Issued and Issuable |
|
|
|
|
$ 39,767
|
|
|
|
|
|
|
|
|
Asset Acquisition, Transaction Costs |
|
|
|
|
|
|
|
|
|
|
|
|
466
|
Asset Acquisition, Total Cost of Transaction |
|
|
|
|
|
|
|
|
|
|
|
|
67,942
|
Allocation of Total Cost, Oil and gas properties |
|
|
|
|
|
|
|
|
|
|
|
|
84,810
|
Allocation of Total cost, Total assets |
|
|
|
|
|
|
|
|
|
|
|
|
84,810
|
Accounts Payable and Accrued Liabilities, Current |
|
|
|
|
|
|
|
|
|
|
|
|
199
|
Derivative, Fair Value, Net |
|
|
|
|
|
|
|
|
|
|
|
|
16,511
|
Asset Retirement Obligations, Noncurrent |
|
|
|
|
|
|
|
|
|
|
|
|
158
|
Allocation of Total Cost, Total Liabilities |
|
|
|
|
|
|
|
|
|
|
|
|
16,868
|
SandPoint Acquisition | Asset Acquisition, Shares Issuable |
|
|
|
|
|
|
|
|
|
|
|
|
|
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] |
|
|
|
|
|
|
|
|
|
|
|
|
|
Stock Issued During Period, Shares, Acquisitions | shares |
|
|
|
|
1,300,000
|
|
|
|
|
|
|
|
|
Sundance Acquisition |
|
|
|
|
|
|
|
|
|
|
|
|
|
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] |
|
|
|
|
|
|
|
|
|
|
|
|
|
Acquisition of oil and gas properties |
|
|
|
$ 220,866
|
|
|
|
|
|
|
|
|
|
Asset Acquisition, Consideration Transferred |
|
|
|
344,939
|
|
|
|
|
|
|
|
|
|
Asset Acquisition, Consideration Transferred, Equity Interest Issued and Issuable |
|
|
|
117,651
|
|
|
|
|
|
|
|
|
|
Asset Acquisition, Transaction Costs |
|
|
|
6,766
|
|
|
|
|
$ 6,766
|
|
|
|
6,800
|
Asset Acquisition, Total Cost of Transaction |
|
|
|
351,705
|
|
|
|
|
|
|
|
|
|
Other current assets |
|
|
|
4,202
|
|
|
|
|
4,202
|
|
|
|
|
Allocation of Total Cost, Oil and gas properties |
|
|
|
397,401
|
|
|
|
|
|
|
|
|
|
Right of Use Assets |
|
|
|
890
|
|
|
|
|
890
|
|
|
|
|
Allocation of Total cost, Total assets |
|
|
|
402,493
|
|
|
|
|
|
|
|
|
|
Accounts Payable and Accrued Liabilities, Current |
|
|
|
13,687
|
|
|
|
|
13,687
|
|
|
|
|
Derivative, Fair Value, Net |
|
|
|
33,767
|
|
|
|
|
33,767
|
|
|
|
|
Non-current Lease Liability |
|
|
|
890
|
|
|
|
|
890
|
|
|
|
|
Asset Retirement Obligations, Noncurrent |
|
|
|
2,444
|
|
|
|
|
2,444
|
|
|
|
|
Allocation of Total Cost, Total Liabilities |
|
|
|
50,788
|
|
|
|
|
|
|
|
|
|
2022 WTI Contingency Payout Fair Value |
|
|
|
7,422
|
|
|
|
|
7,422
|
|
|
|
|
WTI Annual Earn Out Payment |
|
|
|
7,500
|
|
|
|
|
7,500
|
|
|
|
|
Account Receivable for purchase price adjustments |
|
|
|
$ (1,000)
|
|
|
|
|
$ (1,000)
|
|
|
|
|
WTI Annual Earn Out, Average Monthly Settlement 2022 |
|
|
|
95
|
|
|
|
|
95
|
|
|
|
|
2023 WTI Annual Earn Out Payment |
|
|
|
|
|
|
|
|
|
|
|
|
$ 7,500
|
WTI Annual Earn Out, Average Monthly Settlement Price 2023 |
|
|
|
85
|
|
|
|
|
85
|
|
|
|
|
2024 WTI Annual Earn Out Payment |
|
|
|
$ 7,500
|
|
|
|
|
$ 7,500
|
|
|
|
|
Gain (Loss) on WTI Contingency Payout |
|
|
|
|
|
|
|
|
|
|
1,000
|
|
|
Non-Cash Gain on WTI Contingency |
|
|
|
|
|
|
|
|
|
|
$ 1,100
|
|
|
Sundance Acquisition | Asset Acquisition, Shares Issuable |
|
|
|
|
|
|
|
|
|
|
|
|
|
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] |
|
|
|
|
|
|
|
|
|
|
|
|
|
Stock Issued During Period, Shares, Acquisitions | shares |
|
|
|
4,148,472
|
|
|
|
|
|
|
|
|
|
Arkoma Acquisition |
|
|
|
|
|
|
|
|
|
|
|
|
|
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] |
|
|
|
|
|
|
|
|
|
|
|
|
|
Asset Acquisition, Consideration Transferred |
|
|
$ 31,200
|
|
|
|
|
|
|
|
|
|
|
Dewitt and Gonzalez Counties Acquisition |
|
|
|
|
|
|
|
|
|
|
|
|
|
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] |
|
|
|
|
|
|
|
|
|
|
|
|
|
Asset Acquisition, Consideration Transferred |
|
$ 80,100
|
|
|
|
|
|
|
|
|
|
|
|
Chesapeake South Texas Rich Acquisition |
|
|
|
|
|
|
|
|
|
|
|
|
|
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] |
|
|
|
|
|
|
|
|
|
|
|
|
|
WTI Annual Earn Out Payment |
$ 50,000
|
|
|
|
|
|
|
|
|
|
|
|
|
Asset Acquisition, Price of Acquisition, Expected |
700,000
|
|
|
|
|
|
|
|
|
|
|
|
|
Asset Acquisition, Cash Price to be Paid for Acquisition |
650,000
|
|
|
|
|
|
|
|
|
|
|
|
|
Asset Acquisition, Deferred Cash Payment |
50,000
|
|
|
|
|
|
|
|
|
|
|
|
|
Asset Acquisition, Cash Deposit in Escrow |
$ 50,000
|
|
|
|
|
|
|
|
|
|
|
|
|
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v3.23.3
Price-Risk Management Price-Risk Management (Details) $ in Thousands |
3 Months Ended |
9 Months Ended |
|
Sep. 30, 2023
USD ($)
MMBTU
bbl
$ / MMBTU
$ / Boe
|
Sep. 30, 2022
USD ($)
|
Sep. 30, 2023
USD ($)
MMBTU
bbl
$ / MMBTU
$ / Boe
|
Sep. 30, 2022
USD ($)
|
Dec. 31, 2022
USD ($)
|
Derivative Instruments and Hedging Activities Disclosures [Line Items] |
|
|
|
|
|
Gain (Loss) on Price Risk Derivatives, Net | $ |
$ (53,700)
|
$ (1,300)
|
$ 56,500
|
$ (162,500)
|
|
Gain (Loss) on WTI Contingency Payout | $ |
(900)
|
$ 6,100
|
1,100
|
4,700
|
|
Cash Received (Paid) On Settlements of Derivative Contracts | $ |
|
|
70,670
|
$ (182,058)
|
|
Receivables for Settled Derivatives | $ |
8,400
|
|
8,400
|
|
$ 6,900
|
Payables for Settled Derivatives | $ |
3,549
|
|
3,549
|
|
6,026
|
Derivative, Fair Value, Net | $ |
10,100
|
|
10,100
|
|
28,200
|
Other Current Assets [Member] |
|
|
|
|
|
Derivative Instruments and Hedging Activities Disclosures [Line Items] |
|
|
|
|
|
Derivative Asset, Fair Value, Gross Asset | $ |
50,200
|
|
50,200
|
|
52,500
|
Other Noncurrent Assets [Member] |
|
|
|
|
|
Derivative Instruments and Hedging Activities Disclosures [Line Items] |
|
|
|
|
|
Derivative Asset, Fair Value, Gross Asset | $ |
14,200
|
|
14,200
|
|
24,200
|
Other Current Liabilities [Member] |
|
|
|
|
|
Derivative Instruments and Hedging Activities Disclosures [Line Items] |
|
|
|
|
|
Derivative Liability, Fair Value, Gross Liability | $ |
32,800
|
|
32,800
|
|
40,800
|
Other Noncurrent Liabilities [Member] |
|
|
|
|
|
Derivative Instruments and Hedging Activities Disclosures [Line Items] |
|
|
|
|
|
Derivative Liability, Fair Value, Gross Liability | $ |
$ 21,600
|
|
$ 21,600
|
|
$ 7,700
|
Swap [Member] | Oil Derivative Swaps | Fourth Quarter 2023 |
|
|
|
|
|
Derivative Instruments and Hedging Activities Disclosures [Line Items] |
|
|
|
|
|
Oil and Gas Production Hedged Volumes | bbl |
707,300
|
|
707,300
|
|
|
Derivative, Swap Type, Fixed Price | $ / Boe |
78.53
|
|
78.53
|
|
|
Swap [Member] | Oil Derivative Swaps | First Quarter 2024 |
|
|
|
|
|
Derivative Instruments and Hedging Activities Disclosures [Line Items] |
|
|
|
|
|
Oil and Gas Production Hedged Volumes | bbl |
728,000
|
|
728,000
|
|
|
Derivative, Swap Type, Fixed Price | $ / Boe |
77.67
|
|
77.67
|
|
|
Swap [Member] | Oil Derivative Swaps | Second Quarter 2024 |
|
|
|
|
|
Derivative Instruments and Hedging Activities Disclosures [Line Items] |
|
|
|
|
|
Oil and Gas Production Hedged Volumes | bbl |
754,550
|
|
754,550
|
|
|
Derivative, Swap Type, Fixed Price | $ / Boe |
77.59
|
|
77.59
|
|
|
Swap [Member] | Oil Derivative Swaps | Third Quarter 2024 |
|
|
|
|
|
Derivative Instruments and Hedging Activities Disclosures [Line Items] |
|
|
|
|
|
Oil and Gas Production Hedged Volumes | bbl |
779,620
|
|
779,620
|
|
|
Derivative, Swap Type, Fixed Price | $ / Boe |
76.48
|
|
76.48
|
|
|
Swap [Member] | Oil Derivative Swaps | Fourth Quarter 2024 |
|
|
|
|
|
Derivative Instruments and Hedging Activities Disclosures [Line Items] |
|
|
|
|
|
Oil and Gas Production Hedged Volumes | bbl |
762,100
|
|
762,100
|
|
|
Derivative, Swap Type, Fixed Price | $ / Boe |
76.16
|
|
76.16
|
|
|
Swap [Member] | Oil Derivative Swaps | First Quarter 2025 |
|
|
|
|
|
Derivative Instruments and Hedging Activities Disclosures [Line Items] |
|
|
|
|
|
Oil and Gas Production Hedged Volumes | bbl |
666,000
|
|
666,000
|
|
|
Derivative, Swap Type, Fixed Price | $ / Boe |
71.60
|
|
71.60
|
|
|
Swap [Member] | Oil Derivative Swaps | Second Quarter 2025 |
|
|
|
|
|
Derivative Instruments and Hedging Activities Disclosures [Line Items] |
|
|
|
|
|
Oil and Gas Production Hedged Volumes | bbl |
673,400
|
|
673,400
|
|
|
Derivative, Swap Type, Fixed Price | $ / Boe |
71.60
|
|
71.60
|
|
|
Swap [Member] | Oil Derivative Swaps | Third Quarter 2025 |
|
|
|
|
|
Derivative Instruments and Hedging Activities Disclosures [Line Items] |
|
|
|
|
|
Oil and Gas Production Hedged Volumes | bbl |
680,800
|
|
680,800
|
|
|
Derivative, Swap Type, Fixed Price | $ / Boe |
71.60
|
|
71.60
|
|
|
Swap [Member] | Oil Derivative Swaps | Fourth Quarter 2025 |
|
|
|
|
|
Derivative Instruments and Hedging Activities Disclosures [Line Items] |
|
|
|
|
|
Oil and Gas Production Hedged Volumes | bbl |
588,800
|
|
588,800
|
|
|
Derivative, Swap Type, Fixed Price | $ / Boe |
71.29
|
|
71.29
|
|
|
Swap [Member] | Oil Derivative Swaps | First Quarter 2026 |
|
|
|
|
|
Derivative Instruments and Hedging Activities Disclosures [Line Items] |
|
|
|
|
|
Oil and Gas Production Hedged Volumes | bbl |
315,000
|
|
315,000
|
|
|
Derivative, Swap Type, Fixed Price | $ / Boe |
69.40
|
|
69.40
|
|
|
Swap [Member] | Oil Derivative Swaps | Second Quarter 2026 |
|
|
|
|
|
Derivative Instruments and Hedging Activities Disclosures [Line Items] |
|
|
|
|
|
Oil and Gas Production Hedged Volumes | bbl |
318,500
|
|
318,500
|
|
|
Derivative, Swap Type, Fixed Price | $ / Boe |
69.40
|
|
69.40
|
|
|
Swap [Member] | Oil Derivative Swaps | Third Quarter 2026 |
|
|
|
|
|
Derivative Instruments and Hedging Activities Disclosures [Line Items] |
|
|
|
|
|
Oil and Gas Production Hedged Volumes | bbl |
322,000
|
|
322,000
|
|
|
Derivative, Swap Type, Fixed Price | $ / Boe |
69.40
|
|
69.40
|
|
|
Swap [Member] | Oil Derivative Swaps | Fourth Quarter 2026 |
|
|
|
|
|
Derivative Instruments and Hedging Activities Disclosures [Line Items] |
|
|
|
|
|
Oil and Gas Production Hedged Volumes | bbl |
230,000
|
|
230,000
|
|
|
Derivative, Swap Type, Fixed Price | $ / Boe |
69.42
|
|
69.42
|
|
|
Swap [Member] | Natural Gas Derivative Swaps | Fourth Quarter 2023 |
|
|
|
|
|
Derivative Instruments and Hedging Activities Disclosures [Line Items] |
|
|
|
|
|
Oil and Gas Production Hedged Volumes | MMBTU |
5,727,000
|
|
5,727,000
|
|
|
Derivative, Swap Type, Fixed Price |
4.20
|
|
4.20
|
|
|
Swap [Member] | Natural Gas Derivative Swaps | First Quarter 2024 |
|
|
|
|
|
Derivative Instruments and Hedging Activities Disclosures [Line Items] |
|
|
|
|
|
Oil and Gas Production Hedged Volumes | MMBTU |
7,686,000
|
|
7,686,000
|
|
|
Derivative, Swap Type, Fixed Price |
4.12
|
|
4.12
|
|
|
Swap [Member] | Natural Gas Derivative Swaps | Second Quarter 2024 |
|
|
|
|
|
Derivative Instruments and Hedging Activities Disclosures [Line Items] |
|
|
|
|
|
Oil and Gas Production Hedged Volumes | MMBTU |
12,350,000
|
|
12,350,000
|
|
|
Derivative, Swap Type, Fixed Price |
3.67
|
|
3.67
|
|
|
Swap [Member] | Natural Gas Derivative Swaps | Third Quarter 2024 |
|
|
|
|
|
Derivative Instruments and Hedging Activities Disclosures [Line Items] |
|
|
|
|
|
Oil and Gas Production Hedged Volumes | MMBTU |
12,420,000
|
|
12,420,000
|
|
|
Derivative, Swap Type, Fixed Price |
3.78
|
|
3.78
|
|
|
Swap [Member] | Natural Gas Derivative Swaps | Fourth Quarter 2024 |
|
|
|
|
|
Derivative Instruments and Hedging Activities Disclosures [Line Items] |
|
|
|
|
|
Oil and Gas Production Hedged Volumes | MMBTU |
12,420,000
|
|
12,420,000
|
|
|
Derivative, Swap Type, Fixed Price |
4.12
|
|
4.12
|
|
|
Swap [Member] | Natural Gas Derivative Swaps | First Quarter 2025 |
|
|
|
|
|
Derivative Instruments and Hedging Activities Disclosures [Line Items] |
|
|
|
|
|
Oil and Gas Production Hedged Volumes | MMBTU |
9,450,000
|
|
9,450,000
|
|
|
Derivative, Swap Type, Fixed Price |
4.25
|
|
4.25
|
|
|
Swap [Member] | Natural Gas Derivative Swaps | Second Quarter 2025 |
|
|
|
|
|
Derivative Instruments and Hedging Activities Disclosures [Line Items] |
|
|
|
|
|
Oil and Gas Production Hedged Volumes | MMBTU |
9,555,000
|
|
9,555,000
|
|
|
Derivative, Swap Type, Fixed Price |
3.71
|
|
3.71
|
|
|
Swap [Member] | Natural Gas Derivative Swaps | Third Quarter 2025 |
|
|
|
|
|
Derivative Instruments and Hedging Activities Disclosures [Line Items] |
|
|
|
|
|
Oil and Gas Production Hedged Volumes | MMBTU |
11,960,000
|
|
11,960,000
|
|
|
Derivative, Swap Type, Fixed Price |
3.83
|
|
3.83
|
|
|
Swap [Member] | Natural Gas Derivative Swaps | Fourth Quarter 2025 |
|
|
|
|
|
Derivative Instruments and Hedging Activities Disclosures [Line Items] |
|
|
|
|
|
Oil and Gas Production Hedged Volumes | MMBTU |
8,740,000
|
|
8,740,000
|
|
|
Derivative, Swap Type, Fixed Price |
4.17
|
|
4.17
|
|
|
Swap [Member] | Natural Gas Derivative Swaps | First Quarter 2026 |
|
|
|
|
|
Derivative Instruments and Hedging Activities Disclosures [Line Items] |
|
|
|
|
|
Oil and Gas Production Hedged Volumes | MMBTU |
9,680,000
|
|
9,680,000
|
|
|
Derivative, Swap Type, Fixed Price |
4.48
|
|
4.48
|
|
|
Swap [Member] | Natural Gas Derivative Swaps | Second Quarter 2026 |
|
|
|
|
|
Derivative Instruments and Hedging Activities Disclosures [Line Items] |
|
|
|
|
|
Oil and Gas Production Hedged Volumes | MMBTU |
9,555,000
|
|
9,555,000
|
|
|
Derivative, Swap Type, Fixed Price |
3.56
|
|
3.56
|
|
|
Swap [Member] | Natural Gas Derivative Swaps | Third Quarter 2026 |
|
|
|
|
|
Derivative Instruments and Hedging Activities Disclosures [Line Items] |
|
|
|
|
|
Oil and Gas Production Hedged Volumes | MMBTU |
9,660,000
|
|
9,660,000
|
|
|
Derivative, Swap Type, Fixed Price |
3.74
|
|
3.74
|
|
|
Swap [Member] | Natural Gas Derivative Swaps | Fourth Quarter 2026 |
|
|
|
|
|
Derivative Instruments and Hedging Activities Disclosures [Line Items] |
|
|
|
|
|
Oil and Gas Production Hedged Volumes | MMBTU |
9,200,000
|
|
9,200,000
|
|
|
Derivative, Swap Type, Fixed Price |
4.13
|
|
4.13
|
|
|
Swap [Member] | NGL Derivative | Fourth Quarter 2023 |
|
|
|
|
|
Derivative Instruments and Hedging Activities Disclosures [Line Items] |
|
|
|
|
|
Oil and Gas Production Hedged Volumes | bbl |
345,000
|
|
345,000
|
|
|
Derivative, Swap Type, Fixed Price |
32.87
|
|
32.87
|
|
|
Swap [Member] | NGL Derivative | First Quarter 2024 |
|
|
|
|
|
Derivative Instruments and Hedging Activities Disclosures [Line Items] |
|
|
|
|
|
Oil and Gas Production Hedged Volumes | bbl |
400,400
|
|
400,400
|
|
|
Derivative, Swap Type, Fixed Price |
26.30
|
|
26.30
|
|
|
Swap [Member] | NGL Derivative | Second Quarter 2024 |
|
|
|
|
|
Derivative Instruments and Hedging Activities Disclosures [Line Items] |
|
|
|
|
|
Oil and Gas Production Hedged Volumes | bbl |
400,400
|
|
400,400
|
|
|
Derivative, Swap Type, Fixed Price |
26.30
|
|
26.30
|
|
|
Swap [Member] | NGL Derivative | Third Quarter 2024 |
|
|
|
|
|
Derivative Instruments and Hedging Activities Disclosures [Line Items] |
|
|
|
|
|
Oil and Gas Production Hedged Volumes | bbl |
404,800
|
|
404,800
|
|
|
Derivative, Swap Type, Fixed Price |
26.30
|
|
26.30
|
|
|
Swap [Member] | NGL Derivative | Fourth Quarter 2024 |
|
|
|
|
|
Derivative Instruments and Hedging Activities Disclosures [Line Items] |
|
|
|
|
|
Oil and Gas Production Hedged Volumes | bbl |
404,800
|
|
404,800
|
|
|
Derivative, Swap Type, Fixed Price |
26.30
|
|
26.30
|
|
|
Swap [Member] | NGL Derivative | First Quarter 2025 |
|
|
|
|
|
Derivative Instruments and Hedging Activities Disclosures [Line Items] |
|
|
|
|
|
Oil and Gas Production Hedged Volumes | bbl |
270,000
|
|
270,000
|
|
|
Derivative, Swap Type, Fixed Price |
24.17
|
|
24.17
|
|
|
Swap [Member] | NGL Derivative | Second Quarter 2025 |
|
|
|
|
|
Derivative Instruments and Hedging Activities Disclosures [Line Items] |
|
|
|
|
|
Oil and Gas Production Hedged Volumes | bbl |
273,000
|
|
273,000
|
|
|
Derivative, Swap Type, Fixed Price |
24.17
|
|
24.17
|
|
|
Swap [Member] | NGL Derivative | Third Quarter 2025 |
|
|
|
|
|
Derivative Instruments and Hedging Activities Disclosures [Line Items] |
|
|
|
|
|
Oil and Gas Production Hedged Volumes | bbl |
276,000
|
|
276,000
|
|
|
Derivative, Swap Type, Fixed Price |
24.17
|
|
24.17
|
|
|
Swap [Member] | NGL Derivative | Fourth Quarter 2025 |
|
|
|
|
|
Derivative Instruments and Hedging Activities Disclosures [Line Items] |
|
|
|
|
|
Oil and Gas Production Hedged Volumes | bbl |
276,000
|
|
276,000
|
|
|
Collar Contracts [Member] | Oil Derivative Swaps | Fourth Quarter 2023 |
|
|
|
|
|
Derivative Instruments and Hedging Activities Disclosures [Line Items] |
|
|
|
|
|
Oil and Gas Production Hedged Volumes | MMBTU |
302,242
|
|
302,242
|
|
|
Derivative, Average Floor Price |
65.89
|
|
65.89
|
|
|
Derivative, Average Cap Price |
74.54
|
|
74.54
|
|
|
Collar Contracts [Member] | Oil Derivative Swaps | First Quarter 2024 |
|
|
|
|
|
Derivative Instruments and Hedging Activities Disclosures [Line Items] |
|
|
|
|
|
Oil and Gas Production Hedged Volumes | MMBTU |
319,700
|
|
319,700
|
|
|
Derivative, Average Floor Price |
58.95
|
|
58.95
|
|
|
Derivative, Average Cap Price |
71.74
|
|
71.74
|
|
|
Collar Contracts [Member] | Oil Derivative Swaps | Second Quarter 2024 |
|
|
|
|
|
Derivative Instruments and Hedging Activities Disclosures [Line Items] |
|
|
|
|
|
Oil and Gas Production Hedged Volumes | MMBTU |
215,000
|
|
215,000
|
|
|
Derivative, Average Floor Price |
61.08
|
|
61.08
|
|
|
Derivative, Average Cap Price |
73.57
|
|
73.57
|
|
|
Collar Contracts [Member] | Oil Derivative Swaps | Third Quarter 2024 |
|
|
|
|
|
Derivative Instruments and Hedging Activities Disclosures [Line Items] |
|
|
|
|
|
Oil and Gas Production Hedged Volumes | MMBTU |
184,000
|
|
184,000
|
|
|
Derivative, Average Floor Price |
63.50
|
|
63.50
|
|
|
Derivative, Average Cap Price |
75.53
|
|
75.53
|
|
|
Collar Contracts [Member] | Oil Derivative Swaps | Fourth Quarter 2024 |
|
|
|
|
|
Derivative Instruments and Hedging Activities Disclosures [Line Items] |
|
|
|
|
|
Oil and Gas Production Hedged Volumes | MMBTU |
184,000
|
|
184,000
|
|
|
Derivative, Average Floor Price |
63.00
|
|
63.00
|
|
|
Derivative, Average Cap Price |
75.35
|
|
75.35
|
|
|
Collar Contracts [Member] | Oil Derivative Swaps | First Quarter 2025 |
|
|
|
|
|
Derivative Instruments and Hedging Activities Disclosures [Line Items] |
|
|
|
|
|
Oil and Gas Production Hedged Volumes | MMBTU |
238,500
|
|
238,500
|
|
|
Derivative, Average Floor Price |
64.00
|
|
64.00
|
|
|
Derivative, Average Cap Price |
74.62
|
|
74.62
|
|
|
Collar Contracts [Member] | Oil Derivative Swaps | Second Quarter 2025 |
|
|
|
|
|
Derivative Instruments and Hedging Activities Disclosures [Line Items] |
|
|
|
|
|
Oil and Gas Production Hedged Volumes | MMBTU |
227,500
|
|
227,500
|
|
|
Derivative, Average Floor Price |
60.80
|
|
60.80
|
|
|
Derivative, Average Cap Price |
72.22
|
|
72.22
|
|
|
Collar Contracts [Member] | Oil Derivative Swaps | First Quarter 2026 |
|
|
|
|
|
Derivative Instruments and Hedging Activities Disclosures [Line Items] |
|
|
|
|
|
Oil and Gas Production Hedged Volumes | MMBTU |
90,000
|
|
90,000
|
|
|
Derivative, Average Floor Price |
64.00
|
|
64.00
|
|
|
Derivative, Average Cap Price |
71.50
|
|
71.50
|
|
|
Collar Contracts [Member] | Oil Derivative Swaps | Second Quarter 2026 |
|
|
|
|
|
Derivative Instruments and Hedging Activities Disclosures [Line Items] |
|
|
|
|
|
Oil and Gas Production Hedged Volumes | MMBTU |
91,000
|
|
91,000
|
|
|
Derivative, Average Floor Price |
64.00
|
|
64.00
|
|
|
Derivative, Average Cap Price |
71.50
|
|
71.50
|
|
|
Collar Contracts [Member] | Oil Derivative Swaps | Third Quarter 2026 |
|
|
|
|
|
Derivative Instruments and Hedging Activities Disclosures [Line Items] |
|
|
|
|
|
Oil and Gas Production Hedged Volumes | MMBTU |
92,000
|
|
92,000
|
|
|
Derivative, Average Floor Price |
64.00
|
|
64.00
|
|
|
Derivative, Average Cap Price |
71.50
|
|
71.50
|
|
|
Collar Contracts [Member] | Natural Gas Derivative Swaps | Fourth Quarter 2023 |
|
|
|
|
|
Derivative Instruments and Hedging Activities Disclosures [Line Items] |
|
|
|
|
|
Oil and Gas Production Hedged Volumes | MMBTU |
12,445,000
|
|
12,445,000
|
|
|
Derivative, Average Floor Price |
3.87
|
|
3.87
|
|
|
Derivative, Average Cap Price |
4.80
|
|
4.80
|
|
|
Collar Contracts [Member] | Natural Gas Derivative Swaps | First Quarter 2024 |
|
|
|
|
|
Derivative Instruments and Hedging Activities Disclosures [Line Items] |
|
|
|
|
|
Oil and Gas Production Hedged Volumes | MMBTU |
9,661,000
|
|
9,661,000
|
|
|
Derivative, Average Floor Price |
3.94
|
|
3.94
|
|
|
Derivative, Average Cap Price |
5.83
|
|
5.83
|
|
|
Collar Contracts [Member] | Natural Gas Derivative Swaps | Second Quarter 2024 |
|
|
|
|
|
Derivative Instruments and Hedging Activities Disclosures [Line Items] |
|
|
|
|
|
Oil and Gas Production Hedged Volumes | MMBTU |
4,643,000
|
|
4,643,000
|
|
|
Derivative, Average Floor Price |
3.64
|
|
3.64
|
|
|
Derivative, Average Cap Price |
4.28
|
|
4.28
|
|
|
Collar Contracts [Member] | Natural Gas Derivative Swaps | Third Quarter 2024 |
|
|
|
|
|
Derivative Instruments and Hedging Activities Disclosures [Line Items] |
|
|
|
|
|
Oil and Gas Production Hedged Volumes | MMBTU |
3,878,000
|
|
3,878,000
|
|
|
Derivative, Average Floor Price |
3.77
|
|
3.77
|
|
|
Derivative, Average Cap Price |
4.76
|
|
4.76
|
|
|
Collar Contracts [Member] | Natural Gas Derivative Swaps | Fourth Quarter 2024 |
|
|
|
|
|
Derivative Instruments and Hedging Activities Disclosures [Line Items] |
|
|
|
|
|
Oil and Gas Production Hedged Volumes | MMBTU |
3,865,000
|
|
3,865,000
|
|
|
Derivative, Average Floor Price |
4.01
|
|
4.01
|
|
|
Derivative, Average Cap Price |
5.34
|
|
5.34
|
|
|
Collar Contracts [Member] | Natural Gas Derivative Swaps | First Quarter 2025 |
|
|
|
|
|
Derivative Instruments and Hedging Activities Disclosures [Line Items] |
|
|
|
|
|
Oil and Gas Production Hedged Volumes | MMBTU |
5,130,000
|
|
5,130,000
|
|
|
Derivative, Average Floor Price |
4.00
|
|
4.00
|
|
|
Derivative, Average Cap Price |
5.32
|
|
5.32
|
|
|
Collar Contracts [Member] | Natural Gas Derivative Swaps | Second Quarter 2025 |
|
|
|
|
|
Derivative Instruments and Hedging Activities Disclosures [Line Items] |
|
|
|
|
|
Oil and Gas Production Hedged Volumes | MMBTU |
4,914,000
|
|
4,914,000
|
|
|
Derivative, Average Floor Price |
3.25
|
|
3.25
|
|
|
Derivative, Average Cap Price |
3.98
|
|
3.98
|
|
|
Collar Contracts [Member] | Natural Gas Derivative Swaps | Third Quarter 2025 |
|
|
|
|
|
Derivative Instruments and Hedging Activities Disclosures [Line Items] |
|
|
|
|
|
Oil and Gas Production Hedged Volumes | MMBTU |
920,000
|
|
920,000
|
|
|
Derivative, Average Floor Price |
3.50
|
|
3.50
|
|
|
Derivative, Average Cap Price |
3.99
|
|
3.99
|
|
|
Collar Contracts [Member] | Natural Gas Derivative Swaps | Fourth Quarter 2025 |
|
|
|
|
|
Derivative Instruments and Hedging Activities Disclosures [Line Items] |
|
|
|
|
|
Oil and Gas Production Hedged Volumes | MMBTU |
920,000
|
|
920,000
|
|
|
Derivative, Average Floor Price |
3.75
|
|
3.75
|
|
|
Derivative, Average Cap Price |
4.65
|
|
4.65
|
|
|
3-Way Collar | Oil Derivative Swaps | Fourth Quarter 2023 |
|
|
|
|
|
Derivative Instruments and Hedging Activities Disclosures [Line Items] |
|
|
|
|
|
Oil and Gas Production Hedged Volumes | MMBTU |
8,970
|
|
8,970
|
|
|
Derivative, Average Sub Floor Price |
43.08
|
|
43.08
|
|
|
Derivative, Average Floor Price |
53.38
|
|
53.38
|
|
|
Derivative, Average Cap Price |
63.35
|
|
63.35
|
|
|
3-Way Collar | Oil Derivative Swaps | First Quarter 2024 |
|
|
|
|
|
Derivative Instruments and Hedging Activities Disclosures [Line Items] |
|
|
|
|
|
Oil and Gas Production Hedged Volumes | MMBTU |
8,247
|
|
8,247
|
|
|
Derivative, Average Sub Floor Price |
45.00
|
|
45.00
|
|
|
Derivative, Average Floor Price |
57.50
|
|
57.50
|
|
|
Derivative, Average Cap Price |
67.85
|
|
67.85
|
|
|
3-Way Collar | Oil Derivative Swaps | Second Quarter 2024 |
|
|
|
|
|
Derivative Instruments and Hedging Activities Disclosures [Line Items] |
|
|
|
|
|
Oil and Gas Production Hedged Volumes | MMBTU |
7,757
|
|
7,757
|
|
|
Derivative, Average Sub Floor Price |
45.00
|
|
45.00
|
|
|
Derivative, Average Floor Price |
57.50
|
|
57.50
|
|
|
Derivative, Average Cap Price |
67.85
|
|
67.85
|
|
|
3-Way Collar | Natural Gas Derivative Swaps | Fourth Quarter 2023 |
|
|
|
|
|
Derivative Instruments and Hedging Activities Disclosures [Line Items] |
|
|
|
|
|
Oil and Gas Production Hedged Volumes | MMBTU |
219,200
|
|
219,200
|
|
|
Derivative, Average Sub Floor Price |
2.00
|
|
2.00
|
|
|
Derivative, Average Floor Price |
2.50
|
|
2.50
|
|
|
Derivative, Average Cap Price |
2.94
|
|
2.94
|
|
|
3-Way Collar | Natural Gas Derivative Swaps | First Quarter 2024 |
|
|
|
|
|
Derivative Instruments and Hedging Activities Disclosures [Line Items] |
|
|
|
|
|
Oil and Gas Production Hedged Volumes | MMBTU |
198,000
|
|
198,000
|
|
|
Derivative, Average Sub Floor Price |
2.00
|
|
2.00
|
|
|
Derivative, Average Floor Price |
2.50
|
|
2.50
|
|
|
Derivative, Average Cap Price |
3.37
|
|
3.37
|
|
|
3-Way Collar | Natural Gas Derivative Swaps | Second Quarter 2024 |
|
|
|
|
|
Derivative Instruments and Hedging Activities Disclosures [Line Items] |
|
|
|
|
|
Oil and Gas Production Hedged Volumes | MMBTU |
188,000
|
|
188,000
|
|
|
Derivative, Average Sub Floor Price |
2.00
|
|
2.00
|
|
|
Derivative, Average Floor Price |
2.50
|
|
2.50
|
|
|
Derivative, Average Cap Price |
3.37
|
|
3.37
|
|
|
Basis Swap [Member] | Natural Gas Basis Derivative Swaps [Member] | Fourth Quarter 2023 |
|
|
|
|
|
Derivative Instruments and Hedging Activities Disclosures [Line Items] |
|
|
|
|
|
Oil and Gas Production Hedged Volumes | MMBTU |
13,800,000
|
|
13,800,000
|
|
|
Derivative, Swap Type, Fixed Price |
(0.23)
|
|
(0.23)
|
|
|
Basis Swap [Member] | Natural Gas Basis Derivative Swaps [Member] | First Quarter 2024 |
|
|
|
|
|
Derivative Instruments and Hedging Activities Disclosures [Line Items] |
|
|
|
|
|
Oil and Gas Production Hedged Volumes | MMBTU |
15,470,000
|
|
15,470,000
|
|
|
Derivative, Swap Type, Fixed Price |
(0.02)
|
|
(0.02)
|
|
|
Basis Swap [Member] | Natural Gas Basis Derivative Swaps [Member] | Second Quarter 2024 |
|
|
|
|
|
Derivative Instruments and Hedging Activities Disclosures [Line Items] |
|
|
|
|
|
Oil and Gas Production Hedged Volumes | MMBTU |
15,470,000
|
|
15,470,000
|
|
|
Derivative, Swap Type, Fixed Price |
(0.29)
|
|
(0.29)
|
|
|
Basis Swap [Member] | Natural Gas Basis Derivative Swaps [Member] | Third Quarter 2024 |
|
|
|
|
|
Derivative Instruments and Hedging Activities Disclosures [Line Items] |
|
|
|
|
|
Oil and Gas Production Hedged Volumes | MMBTU |
15,640,000
|
|
15,640,000
|
|
|
Derivative, Swap Type, Fixed Price |
(0.26)
|
|
(0.26)
|
|
|
Basis Swap [Member] | Natural Gas Basis Derivative Swaps [Member] | Fourth Quarter 2024 |
|
|
|
|
|
Derivative Instruments and Hedging Activities Disclosures [Line Items] |
|
|
|
|
|
Oil and Gas Production Hedged Volumes | MMBTU |
15,640,000
|
|
15,640,000
|
|
|
Derivative, Swap Type, Fixed Price |
(0.28)
|
|
(0.28)
|
|
|
Basis Swap [Member] | Natural Gas Basis Derivative Swaps [Member] | First Quarter 2025 |
|
|
|
|
|
Derivative Instruments and Hedging Activities Disclosures [Line Items] |
|
|
|
|
|
Oil and Gas Production Hedged Volumes | MMBTU |
5,400,000
|
|
5,400,000
|
|
|
Derivative, Swap Type, Fixed Price |
(0.09)
|
|
(0.09)
|
|
|
Basis Swap [Member] | Natural Gas Basis Derivative Swaps [Member] | Second Quarter 2025 |
|
|
|
|
|
Derivative Instruments and Hedging Activities Disclosures [Line Items] |
|
|
|
|
|
Oil and Gas Production Hedged Volumes | MMBTU |
5,460,000
|
|
5,460,000
|
|
|
Derivative, Swap Type, Fixed Price |
(0.26)
|
|
(0.26)
|
|
|
Basis Swap [Member] | Natural Gas Basis Derivative Swaps [Member] | Third Quarter 2025 |
|
|
|
|
|
Derivative Instruments and Hedging Activities Disclosures [Line Items] |
|
|
|
|
|
Oil and Gas Production Hedged Volumes | MMBTU |
5,520,000
|
|
5,520,000
|
|
|
Derivative, Swap Type, Fixed Price |
(0.23)
|
|
(0.23)
|
|
|
Basis Swap [Member] | Natural Gas Basis Derivative Swaps [Member] | Fourth Quarter 2025 |
|
|
|
|
|
Derivative Instruments and Hedging Activities Disclosures [Line Items] |
|
|
|
|
|
Oil and Gas Production Hedged Volumes | MMBTU |
5,520,000
|
|
5,520,000
|
|
|
Derivative, Swap Type, Fixed Price |
(0.25)
|
|
(0.25)
|
|
|
Basis Swap [Member] | Oil Basis Derivative | Fourth Quarter 2023 |
|
|
|
|
|
Derivative Instruments and Hedging Activities Disclosures [Line Items] |
|
|
|
|
|
Oil and Gas Production Hedged Volumes | bbl |
122,000
|
|
122,000
|
|
|
Derivative, Swap Type, Fixed Price | $ / Boe |
0.80
|
|
0.80
|
|
|
Basis Swap [Member] | Oil Basis Derivative | First Quarter 2024 |
|
|
|
|
|
Derivative Instruments and Hedging Activities Disclosures [Line Items] |
|
|
|
|
|
Oil and Gas Production Hedged Volumes | bbl |
364,000
|
|
364,000
|
|
|
Derivative, Swap Type, Fixed Price | $ / Boe |
1.47
|
|
1.47
|
|
|
Basis Swap [Member] | Oil Basis Derivative | Second Quarter 2024 |
|
|
|
|
|
Derivative Instruments and Hedging Activities Disclosures [Line Items] |
|
|
|
|
|
Oil and Gas Production Hedged Volumes | bbl |
364,000
|
|
364,000
|
|
|
Derivative, Swap Type, Fixed Price | $ / Boe |
1.47
|
|
1.47
|
|
|
Basis Swap [Member] | Oil Basis Derivative | Third Quarter 2024 |
|
|
|
|
|
Derivative Instruments and Hedging Activities Disclosures [Line Items] |
|
|
|
|
|
Oil and Gas Production Hedged Volumes | bbl |
368,000
|
|
368,000
|
|
|
Derivative, Swap Type, Fixed Price | $ / Boe |
1.47
|
|
1.47
|
|
|
Basis Swap [Member] | Oil Basis Derivative | Fourth Quarter 2024 |
|
|
|
|
|
Derivative Instruments and Hedging Activities Disclosures [Line Items] |
|
|
|
|
|
Oil and Gas Production Hedged Volumes | bbl |
368,000
|
|
368,000
|
|
|
Derivative, Swap Type, Fixed Price | $ / Boe |
1.47
|
|
1.47
|
|
|
Basis Swap [Member] | Oil Basis Derivative | First Quarter 2025 |
|
|
|
|
|
Derivative Instruments and Hedging Activities Disclosures [Line Items] |
|
|
|
|
|
Oil and Gas Production Hedged Volumes | bbl |
270,000
|
|
270,000
|
|
|
Derivative, Swap Type, Fixed Price | $ / Boe |
1.75
|
|
1.75
|
|
|
Basis Swap [Member] | Oil Basis Derivative | Second Quarter 2025 |
|
|
|
|
|
Derivative Instruments and Hedging Activities Disclosures [Line Items] |
|
|
|
|
|
Oil and Gas Production Hedged Volumes | bbl |
273,000
|
|
273,000
|
|
|
Derivative, Swap Type, Fixed Price | $ / Boe |
1.75
|
|
1.75
|
|
|
Basis Swap [Member] | Oil Basis Derivative | Third Quarter 2025 |
|
|
|
|
|
Derivative Instruments and Hedging Activities Disclosures [Line Items] |
|
|
|
|
|
Oil and Gas Production Hedged Volumes | bbl |
276,000
|
|
276,000
|
|
|
Derivative, Swap Type, Fixed Price | $ / Boe |
1.75
|
|
1.75
|
|
|
Basis Swap [Member] | Oil Basis Derivative | Fourth Quarter 2025 |
|
|
|
|
|
Derivative Instruments and Hedging Activities Disclosures [Line Items] |
|
|
|
|
|
Oil and Gas Production Hedged Volumes | bbl |
276,000
|
|
276,000
|
|
|
Derivative, Swap Type, Fixed Price | $ / Boe |
1.75
|
|
1.75
|
|
|
Basis Swap [Member] | Oil Basis Calendar Monthly Roll Differential Swap | Fourth Quarter 2023 |
|
|
|
|
|
Derivative Instruments and Hedging Activities Disclosures [Line Items] |
|
|
|
|
|
Oil and Gas Production Hedged Volumes | bbl |
122,000
|
|
122,000
|
|
|
Derivative, Swap Type, Fixed Price | $ / Boe |
2.44
|
|
2.44
|
|
|
Basis Swap [Member] | Oil Basis Calendar Monthly Roll Differential Swap | First Quarter 2024 |
|
|
|
|
|
Derivative Instruments and Hedging Activities Disclosures [Line Items] |
|
|
|
|
|
Oil and Gas Production Hedged Volumes | bbl |
364,000
|
|
364,000
|
|
|
Derivative, Swap Type, Fixed Price | $ / Boe |
0.69
|
|
0.69
|
|
|
Basis Swap [Member] | Oil Basis Calendar Monthly Roll Differential Swap | Second Quarter 2024 |
|
|
|
|
|
Derivative Instruments and Hedging Activities Disclosures [Line Items] |
|
|
|
|
|
Oil and Gas Production Hedged Volumes | bbl |
364,000
|
|
364,000
|
|
|
Derivative, Swap Type, Fixed Price | $ / Boe |
0.69
|
|
0.69
|
|
|
Basis Swap [Member] | Oil Basis Calendar Monthly Roll Differential Swap | Third Quarter 2024 |
|
|
|
|
|
Derivative Instruments and Hedging Activities Disclosures [Line Items] |
|
|
|
|
|
Oil and Gas Production Hedged Volumes | bbl |
368,000
|
|
368,000
|
|
|
Derivative, Swap Type, Fixed Price | $ / Boe |
0.69
|
|
0.69
|
|
|
Basis Swap [Member] | Oil Basis Calendar Monthly Roll Differential Swap | Fourth Quarter 2024 |
|
|
|
|
|
Derivative Instruments and Hedging Activities Disclosures [Line Items] |
|
|
|
|
|
Oil and Gas Production Hedged Volumes | bbl |
368,000
|
|
368,000
|
|
|
Derivative, Swap Type, Fixed Price | $ / Boe |
0.69
|
|
0.69
|
|
|
Basis Swap [Member] | Oil Basis Calendar Monthly Roll Differential Swap | First Quarter 2025 |
|
|
|
|
|
Derivative Instruments and Hedging Activities Disclosures [Line Items] |
|
|
|
|
|
Oil and Gas Production Hedged Volumes | bbl |
270,000
|
|
270,000
|
|
|
Derivative, Swap Type, Fixed Price | $ / Boe |
0.40
|
|
0.40
|
|
|
Basis Swap [Member] | Oil Basis Calendar Monthly Roll Differential Swap | Second Quarter 2025 |
|
|
|
|
|
Derivative Instruments and Hedging Activities Disclosures [Line Items] |
|
|
|
|
|
Oil and Gas Production Hedged Volumes | bbl |
273,000
|
|
273,000
|
|
|
Derivative, Swap Type, Fixed Price | $ / Boe |
0.40
|
|
0.40
|
|
|
Basis Swap [Member] | Oil Basis Calendar Monthly Roll Differential Swap | Third Quarter 2025 |
|
|
|
|
|
Derivative Instruments and Hedging Activities Disclosures [Line Items] |
|
|
|
|
|
Oil and Gas Production Hedged Volumes | bbl |
276,000
|
|
276,000
|
|
|
Derivative, Swap Type, Fixed Price | $ / Boe |
0.40
|
|
0.40
|
|
|
Basis Swap [Member] | Oil Basis Calendar Monthly Roll Differential Swap | Fourth Quarter 2025 |
|
|
|
|
|
Derivative Instruments and Hedging Activities Disclosures [Line Items] |
|
|
|
|
|
Oil and Gas Production Hedged Volumes | bbl |
276,000
|
|
276,000
|
|
|
Derivative, Swap Type, Fixed Price | $ / Boe |
0.40
|
|
0.40
|
|
|
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v3.23.3
Fair Value Measurements (Details) - Fair Value, Recurring [Member] - USD ($) $ in Thousands |
Sep. 30, 2023 |
Dec. 31, 2022 |
Natural Gas Contract [Member] |
|
|
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] |
|
|
Derivative Asset |
$ 53,032
|
$ 25,960
|
Derivative Liability |
5,346
|
28,579
|
Natural Gas Basis Contract [Member] |
|
|
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] |
|
|
Derivative Asset |
5,395
|
26,023
|
Derivative Liability |
5,415
|
409
|
Oil Contract [Member] |
|
|
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] |
|
|
Derivative Asset |
418
|
14,604
|
Derivative Liability |
41,908
|
19,442
|
2022 WTI Contingency Payout Fair Value |
|
2,135
|
2021 WTI Contingency Payout |
2,459
|
1,453
|
Oil Basis Derivative |
|
|
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] |
|
|
Derivative Asset |
254
|
|
Derivative Liability |
858
|
|
NGL Derivative |
|
|
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] |
|
|
Derivative Asset |
5,270
|
10,134
|
Derivative Liability |
785
|
104
|
Fair Value, Inputs, Level 1 [Member] | Natural Gas Contract [Member] |
|
|
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] |
|
|
Derivative Asset |
0
|
0
|
Derivative Liability |
0
|
0
|
Fair Value, Inputs, Level 1 [Member] | Natural Gas Basis Contract [Member] |
|
|
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] |
|
|
Derivative Asset |
0
|
0
|
Derivative Liability |
0
|
0
|
Fair Value, Inputs, Level 1 [Member] | Oil Contract [Member] |
|
|
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] |
|
|
Derivative Asset |
0
|
0
|
Derivative Liability |
0
|
0
|
2022 WTI Contingency Payout Fair Value |
|
0
|
2021 WTI Contingency Payout |
0
|
0
|
Fair Value, Inputs, Level 1 [Member] | Oil Basis Derivative |
|
|
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] |
|
|
Derivative Asset |
0
|
|
Derivative Liability |
0
|
|
Fair Value, Inputs, Level 1 [Member] | NGL Derivative |
|
|
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] |
|
|
Derivative Asset |
0
|
0
|
Derivative Liability |
0
|
0
|
Fair Value, Inputs, Level 2 [Member] | Natural Gas Contract [Member] |
|
|
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] |
|
|
Derivative Asset |
53,032
|
25,960
|
Derivative Liability |
5,346
|
28,579
|
Fair Value, Inputs, Level 2 [Member] | Natural Gas Basis Contract [Member] |
|
|
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] |
|
|
Derivative Asset |
5,395
|
26,023
|
Derivative Liability |
5,415
|
409
|
Fair Value, Inputs, Level 2 [Member] | Oil Contract [Member] |
|
|
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] |
|
|
Derivative Asset |
418
|
14,604
|
Derivative Liability |
41,908
|
19,442
|
2022 WTI Contingency Payout Fair Value |
|
2,135
|
2021 WTI Contingency Payout |
2,459
|
1,453
|
Fair Value, Inputs, Level 2 [Member] | Oil Basis Derivative |
|
|
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] |
|
|
Derivative Asset |
254
|
|
Derivative Liability |
858
|
|
Fair Value, Inputs, Level 2 [Member] | NGL Derivative |
|
|
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] |
|
|
Derivative Asset |
5,270
|
10,134
|
Derivative Liability |
785
|
104
|
Fair Value, Inputs, Level 3 [Member] | Natural Gas Contract [Member] |
|
|
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] |
|
|
Derivative Asset |
0
|
0
|
Derivative Liability |
0
|
0
|
Fair Value, Inputs, Level 3 [Member] | Natural Gas Basis Contract [Member] |
|
|
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] |
|
|
Derivative Asset |
0
|
0
|
Derivative Liability |
0
|
0
|
Fair Value, Inputs, Level 3 [Member] | Oil Contract [Member] |
|
|
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] |
|
|
Derivative Asset |
0
|
0
|
Derivative Liability |
0
|
0
|
2022 WTI Contingency Payout Fair Value |
|
0
|
2021 WTI Contingency Payout |
0
|
0
|
Fair Value, Inputs, Level 3 [Member] | Oil Basis Derivative |
|
|
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] |
|
|
Derivative Asset |
0
|
|
Derivative Liability |
0
|
|
Fair Value, Inputs, Level 3 [Member] | NGL Derivative |
|
|
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] |
|
|
Derivative Asset |
0
|
0
|
Derivative Liability |
$ 0
|
$ 0
|
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v3.23.3
Asset Retirement Obligations Asset Retirement Obligations (Details) - USD ($) $ in Thousands |
3 Months Ended |
9 Months Ended |
12 Months Ended |
|
Sep. 30, 2023 |
Sep. 30, 2022 |
Sep. 30, 2023 |
Sep. 30, 2022 |
Dec. 31, 2022 |
Dec. 31, 2021 |
Asset Retirement Obligation Disclosure [Abstract] |
|
|
|
|
|
|
Asset Retirement Obligation |
$ 11,418
|
|
$ 11,418
|
|
$ 10,456
|
$ 6,050
|
Accretion expense |
254
|
$ 166
|
718
|
$ 366
|
534
|
|
Liabilities incurred for new wells and facilities construction |
|
|
313
|
|
3,032
|
|
Reduction due to sold wells and facilities |
|
|
|
|
(57)
|
|
Reductions due to plugged wells and facilities |
|
|
(603)
|
|
(22)
|
|
Revisions in estimates |
|
|
534
|
|
919
|
|
Asset retirement obligation - current portion |
$ 1,578
|
|
$ 1,578
|
|
$ 1,284
|
|
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v3.23.3
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