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 March 31, 2022
Commission File Number 1-8754
SILVERBOW RESOURCES, INC.
(Exact Name of Registrant as Specified in Its Charter)
| Delaware | 20-3940661 | ||||
(State of Incorporation) | (I.R.S. Employer Identification No.) | ||||
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 | ||||||
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.
| Yes | þ | No | o | ||||||||
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files).
| Yes | þ | No | o | ||||||||
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.
| Large Accelerated Filer | o | Accelerated Filer | þ | Non-Accelerated Filer | o | Smaller Reporting Company | þ | |||||||||||||||||||||||||
| 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.
| o | ||
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Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
| Yes | o | No | þ | ||||||||
Indicate by check mark whether the registrant has filed all documents and reports required to be filed by Sections 12, 13 or 15(d) of the Securities Exchange Act of 1934 subsequent to the distribution of securities under a plan confirmed by a court.
| Yes | þ | No | o | ||||||||
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) | 16,850,478 Shares outstanding at April 29, 2022 | ||||
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SILVERBOW RESOURCES, INC.
FORM 10-Q
FOR THE QUARTERLY PERIOD ENDED MARCH 31, 2022
INDEX
| Page | ||||||||
| Part I | FINANCIAL INFORMATION | |||||||
| Item 1. | Condensed Consolidated Financial Statements | |||||||
| Item 2. | ||||||||
| Item 3. | ||||||||
| Item 4. | ||||||||
| Part II | OTHER INFORMATION | |||||||
| 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” 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:
• the severity and duration of world health events, including the COVID-19 pandemic, related economic repercussions, including disruptions in the oil and gas industry;
• actions by the members of the Organization of the Petroleum Exporting Countries (“OPEC”) and Russia (together with OPEC and other allied producing countries) with respect to oil production levels and announcements of potential changes in such levels;
• the benefits of the recently announced Sundance and SandPoint transactions;
• risks related to the recently announced Sundance and SandPoint acquisitions, including the risk that the transactions will not be completed on the timeline or terms currently contemplated, that the benefits of the transactions may not be fully realized or may take longer to realize than expected, that the costs of the acquisitions will be significant and that management attention will be diverted to transaction-related issues;
• operational challenges relating to the COVID-19 pandemic and efforts to mitigate the spread of the virus, including logistical challenges, protecting the health and well-being of our employees, remote work arrangements, performance of contracts and supply chain disruptions;
• volatility in natural gas, oil and NGL prices;
• future cash flows and their adequacy to maintain our ongoing operations;
• liquidity, including our ability to satisfy our short- or long-term liquidity needs;
• our borrowing capacity, future covenant compliance, cash flow and liquidity;
• operating results;
• 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 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 political tensions and war;
• opportunities to monetize assets;
• our ability to execute on strategic initiatives;
• effectiveness of our risk management activities including hedging strategy;
• environmental liabilities;
• counterparty credit risk;
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• 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 and our Annual Report on Form 10-K for the year ended December 31, 2021.
Many of the foregoing risks and uncertainties, as well as risks and uncertainties that are currently unknown to us, are, and will be, exacerbated by the COVID-19 pandemic 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 annual report 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, 2021 and in subsequent Quarterly Reports on Form 10-Q and Current Reports on Form 8-K. 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.
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PART I. FINANCIAL INFORMATION
Condensed Consolidated Balance Sheets (Unaudited)
SilverBow Resources, Inc. and Subsidiary (in thousands, except share amounts)
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Condensed Consolidated Statements of Operations (Unaudited)
SilverBow Resources, Inc. and Subsidiary (in thousands, except per-share amounts)
| Three Months Ended March 31, 2022 | Three Months Ended March 31, 2021 | ||||||||||
| Revenues: | |||||||||||
| Oil and gas sales | $ | 129,656 | $ | 86,741 | |||||||
| Operating Expenses: | |||||||||||
| General and administrative, net | 4,786 | 4,782 | |||||||||
| Depreciation, depletion, and amortization | 21,154 | 13,393 | |||||||||
| Accretion of asset retirement obligations | 99 | 75 | |||||||||
| Lease operating expenses | 9,125 | 6,274 | |||||||||
| Workovers | 647 | 13 | |||||||||
| Transportation and gas processing | 6,352 | 5,056 | |||||||||
| Severance and other taxes | 7,764 | 3,489 | |||||||||
| Total Operating Expenses | 49,927 | 33,082 | |||||||||
| Operating Income | 79,729 | 53,659 | |||||||||
| Non-Operating Income (Expense) | |||||||||||
| Gain (loss) on commodity derivatives, net | (140,242) | (18,259) | |||||||||
| Interest expense, net | (6,557) | (7,019) | |||||||||
| Other income (expense), net | 61 | (1) | |||||||||
| Income (Loss) Before Income Taxes | (67,009) | 28,380 | |||||||||
| Provision (Benefit) for Income Taxes | (2,754) | — | |||||||||
| Net Income (Loss) | $ | (64,255) | $ | 28,380 | |||||||
| Per Share Amounts: | |||||||||||
| Basic Earnings (Loss) Per Share | $ | (3.84) | $ | 2.36 | |||||||
| Diluted Earnings (Loss) Per Share | $ | (3.84) | $ | 2.31 | |||||||
| Weighted-Average Shares Outstanding - Basic | 16,719 | 12,029 | |||||||||
| Weighted-Average Shares Outstanding - Diluted | 16,719 | 12,294 | |||||||||
| See accompanying Notes to Condensed Consolidated Financial Statements. | |||||||||||
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Condensed Consolidated Statements of Stockholders’ Equity (Unaudited)
SilverBow Resources, Inc. and Subsidiary (in thousands, except share amounts)
| Common Stock | Additional Paid-In Capital | Treasury Stock | Retained Earnings (Accumulated Deficit) | Total | |||||||||||||||||||||||||
| Balance, December 31, 2020 | $ | 121 | $ | 297,712 | $ | (2,372) | $ | (204,428) | $ | 91,033 | |||||||||||||||||||
Purchase of treasury shares (60,177 shares) | — | — | (488) | — | (488) | ||||||||||||||||||||||||
Vesting of share-based compensation (283,113 shares) | 2 | (2) | — | — | — | ||||||||||||||||||||||||
| Share-based compensation | — | 1,131 | — | — | 1,131 | ||||||||||||||||||||||||
| Net Income | — | — | — | 28,380 | 28,380 | ||||||||||||||||||||||||
| Balance, March 31, 2021 | $ | 123 | $ | 298,841 | $ | (2,860) | $ | (176,048) | $ | 120,056 | |||||||||||||||||||
| Balance, December 31, 2021 | $ | 168 | $ | 413,017 | $ | (2,984) | $ | (117,669) | $ | 292,532 | |||||||||||||||||||
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 | |||||||||||||||||||
| See accompanying Notes to Condensed Consolidated Financial Statements. | |||||||||||||||||||||||||||||
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Condensed Consolidated Statements of Cash Flows (Unaudited)
SilverBow Resources, Inc. and Subsidiary (in thousands)
| Three Months Ended March 31, 2022 | Three Months Ended March 31, 2021 | ||||||||||
| Cash Flows from Operating Activities: | |||||||||||
| Net income (loss) | $ | (64,255) | $ | 28,380 | |||||||
| Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities | |||||||||||
| Depreciation, depletion, and amortization | 21,154 | 13,393 | |||||||||
| Accretion of asset retirement obligations | 99 | 75 | |||||||||
| Deferred income taxes | (2,902) | — | |||||||||
| Share-based compensation | 1,047 | 1,070 | |||||||||
| (Gain) Loss on derivatives, net | 140,242 | 18,259 | |||||||||
| Cash settlement (paid) received on derivatives | (24,554) | (3,063) | |||||||||
| Settlements of asset retirement obligations | (38) | (104) | |||||||||
| Other | 1,138 | 344 | |||||||||
| Change in operating assets and liabilities: | |||||||||||
| (Increase) decrease in accounts receivable and other current assets | 2,794 | (878) | |||||||||
| Increase (decrease) in accounts payable and accrued liabilities | (10,144) | 10,301 | |||||||||
| Increase (decrease) in income taxes payable | 149 | — | |||||||||
| Increase (decrease) in accrued interest | 165 | 69 | |||||||||
| Net Cash Provided by (Used in) Operating Activities | 64,895 | 67,846 | |||||||||
| Cash Flows from Investing Activities: | |||||||||||
| Additions to property and equipment | (35,228) | (35,852) | |||||||||
| Acquisition of oil and gas properties, net of purchase price adjustments | 436 | (205) | |||||||||
| Net Cash Provided by (Used in) Investing Activities | (34,792) | (36,057) | |||||||||
| Cash Flows from Financing Activities: | |||||||||||
| Proceeds from bank borrowings | 122,000 | 57,000 | |||||||||
| Payments of bank borrowings | (149,000) | (87,000) | |||||||||
| Purchase of treasury shares | (2,462) | (488) | |||||||||
| Payments of debt issuance costs | (117) | — | |||||||||
| Net Cash Provided by (Used in) Financing Activities | (29,579) | (30,488) | |||||||||
| Net Increase (Decrease) in Cash and Cash Equivalents | 524 | 1,301 | |||||||||
| Cash and Cash Equivalents at Beginning of Period | 1,121 | 2,118 | |||||||||
| Cash and Cash Equivalents at End of Period | $ | 1,645 | $ | 3,419 | |||||||
| Supplemental Disclosures of Cash Flow Information: | |||||||||||
| Cash paid during period for interest, net of amounts capitalized | $ | 5,816 | $ | 6,424 | |||||||
| Non-cash Investing and Financing Activities: | |||||||||||
| Changes in capital accounts payable and capital accruals | $ | 5,037 | $ | (3,588) | |||||||
| Non-cash equity consideration for acquisitions | $ | 1,134 | $ | — | |||||||
| See accompanying Notes to Condensed Consolidated Financial Statements. | |||||||||||
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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, the Company possesses a significant understanding of the reservoirs in the region. We leverage this competitive understanding to assemble high quality drilling inventory while continuously enhancing our 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, 2021.
(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 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.
Subsequent Events. We have evaluated subsequent events requiring potential accrual or disclosure in our condensed consolidated financial statements. Effective April 12, 2022, the Company entered into the Ninth Amendment to its First Amended and Restated Senior Secured Revolving Credit Agreement (as defined below), in conjunction with our regularly scheduled borrowing base redetermination. The Ninth Amendment increased the borrowing base of our Credit Facility (as defined below) from $460.0 million to $525.0 million. See Note 6 for more information on the Ninth Amendment to the Credit Facility.
On April 13, 2022, SilverBow entered into a definitive agreement (the “Purchase Agreement”) with Sundance Energy, Inc. and certain affiliated entities (collectively, “Sundance”), to acquire oil and gas assets in the Eagle Ford (the “Sundance Transaction”). Consideration for the Sundance Transaction includes approximately $225 million in cash and 4.1 million shares of common stock of SilverBow. As part of the Purchase Agreement, the purchase price will be reduced by $16.5 million related to SilverBow assuming Sundance's outstanding commodity derivatives positions. The Sundance Transaction also includes up to two earn-out payments of $7.5 million per year for each of 2022 and 2023, 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 and $85 per barrel for 2023. The Sundance Transaction is expected to close in June or July 2022. The closing of the transaction is subject to SilverBow shareholder approval and satisfaction or waiver of customary closing conditions.
As provided for in the Purchase Agreement, if Sundance has the right to terminate the Purchase Agreement due to SilverBow’s material breach of its representations, warranties or covenants or failure to deliver closing deliverables then Sundance may (a) seek all remedies available at law, including specific performance, or (b) terminate the Purchase Agreement and collect the deposit as liquidated damages. If SilverBow has the right to terminate the Purchase Agreement due to Sundance’s material breach of their respective representations, warranties or covenants or failure to deliver closing deliverables, then SilverBow shall have the right, as its sole and exclusive remedy, to terminate the Purchase Agreement, receive the deposit back and collect a termination fee in the amount of $3.2 million as liquidated damages. If the Purchase Agreement is terminated by Sundance prior to the special meeting and shareholder approval in the event of a Change in Recommendation (as defined in the Purchase Agreement), then Sundance shall be entitled to collect $3.2 million from the deposit as liquidated damages. The
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remaining deposit will be returned to SilverBow. If the Purchase Agreement is terminated for any other reason, SilverBow will receive the deposit back
On April 13, 2022, the Company also entered into a definitive agreement to acquire oil and gas assets in the Eagle Ford from SandPoint Operating, LLC, a subsidiary of SandPoint Resources, LLC (collectively, “SandPoint,”) for a total purchase price consisting of $31 million in cash, subject to customary closing adjustments and 1.3 million shares of SilverBow common stock. The SandPoint acquisition is expected to close in May 2022.
Through April 30, 2022, 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 March 31, 2022:
| Oil Derivative Contracts (New York Mercantile Exchange (“NYMEX”) West Texas Intermediate (“WTI”) Settlements) | Total Volumes (Bbls) | Weighted-Average Price | ||||||||||||
| Swap Contracts | ||||||||||||||
| 2022 Contracts | ||||||||||||||
| 3Q22 | 46,000 | $ | 99.40 | |||||||||||
| 4Q22 | 76,500 | $ | 96.62 | |||||||||||
| 2023 Contracts | ||||||||||||||
| 1Q23 | 67,500 | $ | 93.13 | |||||||||||
| 2Q23 | 45,500 | $ | 90.05 | |||||||||||
| 3Q23 | 46,000 | $ | 87.60 | |||||||||||
| 4Q23 | 92,000 | $ | 85.73 | |||||||||||
| 2024 Contracts | ||||||||||||||
| 1Q24 | 91,000 | $ | 83.50 | |||||||||||
| 2Q24 | 113,750 | $ | 81.80 | |||||||||||
| 3Q24 | 115,000 | $ | 79.96 | |||||||||||
| 4Q24 | 115,000 | $ | 78.36 | |||||||||||
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| Natural Gas Derivative Contracts (NYMEX Henry Hub Settlements) | Total Volumes (MMBtu) | Weighted-Average Price | Weighted-Average Price | Weighted-Average Collar Call Price | ||||||||||||||||||||||
| Swap Contracts | ||||||||||||||||||||||||||
| 2022 Contracts | ||||||||||||||||||||||||||
| 3Q22 | 920,000 | $ | 7.19 | |||||||||||||||||||||||
| 4Q22 | 920,000 | $ | 7.30 | |||||||||||||||||||||||
| 2023 Contracts | ||||||||||||||||||||||||||
| 1Q23 | 900,000 | $ | 7.12 | |||||||||||||||||||||||
| 2Q23 | 1,820,000 | $ | 4.68 | |||||||||||||||||||||||
| 3Q23 | 2,760,000 | $ | 4.67 | |||||||||||||||||||||||
| 4Q23 | 3,680,000 | $ | 4.84 | |||||||||||||||||||||||
| 2024 Contracts | ||||||||||||||||||||||||||
| 1Q24 | 546,000 | $ | 4.95 | |||||||||||||||||||||||
| 2Q24 | 5,005,000 | $ | 3.87 | |||||||||||||||||||||||
| 3Q24 | 5,060,000 | $ | 3.94 | |||||||||||||||||||||||
| 4Q24 | 5,060,000 | $ | 4.21 | |||||||||||||||||||||||
| Collar Contracts | ||||||||||||||||||||||||||
| 2023 Contracts | ||||||||||||||||||||||||||
| 1Q23 | 900,000 | $ | 6.00 | $ | 13.85 | |||||||||||||||||||||
| 2Q23 | 1,820,000 | $ | 3.88 | $ | 4.75 | |||||||||||||||||||||
| 3Q23 | 1,840,000 | $ | 3.88 | $ | 4.77 | |||||||||||||||||||||
| 4Q23 | 1,840,000 | $ | 3.88 | $ | 5.28 | |||||||||||||||||||||
| 2024 Contracts | ||||||||||||||||||||||||||
| 1Q24 | 1,820,000 | $ | 4.00 | $ | 6.00 | |||||||||||||||||||||
| NGL Swaps (Mont Belvieu) | Total Volumes (Bbls) | Weighted-Average Price | ||||||||||||
| 2022 Contracts | ||||||||||||||
| 3Q22 | 76,500 | $ | 42.92 | |||||||||||
| 4Q22 | 92,000 | $ | 42.92 | |||||||||||
| 2023 Contracts | ||||||||||||||
| 1Q23 | 180,000 | $ | 34.99 | |||||||||||
| 2Q23 | 182,000 | $ | 34.99 | |||||||||||
| 3Q23 | 184,000 | $ | 34.99 | |||||||||||
| 4Q23 | 184,000 | $ | 34.99 | |||||||||||
| 2023 Contracts | ||||||||||||||
| 1Q24 | 127,400 | $ | 29.39 | |||||||||||
| 2Q24 | 127,400 | $ | 29.39 | |||||||||||
| 3Q24 | 128,800 | $ | 29.39 | |||||||||||
| 4Q24 | 128,800 | $ | 29.39 | |||||||||||
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
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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 March 31, 2022 and 2021, such internal costs when capitalized totaled $1.0 million and $1.1 million, respectively. Interest costs are also capitalized to unproved oil and natural gas properties. There was no capitalized interest on our unproved properties for either the three months ended March 31, 2022 and 2021.
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):
| March 31, 2022 | December 31, 2021 | ||||||||||
| Property and Equipment | |||||||||||
| Proved oil and gas properties | $ | 1,621,948 | $ | 1,588,978 | |||||||
| Unproved oil and gas properties | 23,623 | 17,090 | |||||||||
| Furniture, fixtures and other equipment | 5,926 | 5,885 | |||||||||
| Less – Accumulated depreciation, depletion, amortization & impairment | (891,158) | (869,985) | |||||||||
| Property and Equipment, Net | $ | 760,339 | $ | 741,968 | |||||||
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
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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 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 impairment for the three months ended March 31, 2022 and 2021.
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, and based on our judgment, we accrue a reserve when we believe a receivable may not be collected. At both March 31, 2022 and December 31, 2021, we had an allowance for doubtful accounts of less than $0.1 million. The allowance for doubtful accounts has been deducted from the total “Accounts receivable, net” balance on the accompanying condensed consolidated balance sheets.
At March 31, 2022, our “Accounts receivable, net” balance included $43.0 million for oil and gas sales, $1.6 million due from joint interest owners, $1.0 million for severance tax credit receivables and $0.5 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
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administrative, net,” on the accompanying condensed consolidated statements of operations. The amount of supervision fees charged for each of the three months ended March 31, 2022 and 2021 did not exceed our actual costs incurred. The total amount of supervision fees charged to the wells we operated was $1.6 million and $1.2 million for the three months ended March 31, 2022 and 2021, 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. Management has determined that it was not more likely than not that the Company would realize future cash benefits from its remaining federal carryover items and other federal deferred tax assets and, accordingly, has recorded a full valuation allowance to offset its net federal deferred tax assets in excess of deferred tax liabilities. The Company maintains a full valuation allowance against its net federal deferred tax assets in excess of deferred tax liabilities, with the exception of a $5.5 million deferred tax liability that was recorded for the year ending December 31, 2021. We recorded an income tax benefit of $2.8 million for the three months ended March 31, 2022 which was primarily attributable to a deferred federal income tax benefit and state deferred income tax benefit. The benefit for the three months ended March 31, 2022 is a product of the overall forecasted annual effective tax rate applied to the year to date loss, and thus is a reduction of the deferred tax liability at December 31, 2021. There was no income tax expense or benefit for the three months ended March 31, 2021.
Our policy is to record interest and penalties relating to uncertain tax positions in income tax expense. At March 31, 2022 and December 31, 2021, 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.
On March 27, 2020, President Trump signed into law the Coronavirus Aid, Relief, and Economic Security Act (the “CARES Act”). The CARES Act, among other things, includes provisions relating to refundable payroll tax credits, deferment of employer-side Social Security payments, net operating loss carryback periods, alternative minimum tax credit refunds and modifications to the net interest deduction limitation. The CARES Act did not have a material impact on the Company's financial condition, results of operation, or liquidity.
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 March 31, 2022 and 2021 (in thousands):
| Three Months Ended March 31, 2022 | Three Months Ended March 31, 2021 | ||||||||||
| Oil, natural gas and NGLs sales: | |||||||||||
| Oil | $ | 39,741 | $ | 17,466 | |||||||
| Natural gas | 77,372 | 62,914 | |||||||||
| NGLs | 12,543 | 6,361 | |||||||||
| Total | $ | 129,656 | $ | 86,741 | |||||||
Accounts Payable and Accrued Liabilities. The “Accounts payable and accrued liabilities” balances on the accompanying condensed consolidated balance sheets are summarized below (in thousands):
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| March 31, 2022 | December 31, 2021 | ||||||||||
| Trade accounts payable | $ | 9,862 | $ | 9,688 | |||||||
| Accrued operating expenses | 4,261 | 4,192 | |||||||||
| Accrued compensation costs | 1,717 | 7,029 | |||||||||
| Asset retirement obligations – current portion | 526 | 524 | |||||||||
| Accrued non-income based taxes | 6,003 | 3,314 | |||||||||
| Accrued corporate and legal fees | 2,275 | 1,972 | |||||||||
| Payable for settled derivatives | 14,970 | 6,371 | |||||||||
| Other payables | 2,295 | 1,944 | |||||||||
| Total accounts payable and accrued liabilities | $ | 41,909 | $ | 35,034 | |||||||
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.
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 three months ended March 31, 2022, we purchased 96,012 treasury shares to satisfy withholding tax obligations arising upon the vesting of restricted shares and received 41,191 shares in conjunction with our post-closing settlement for a previously disclosed acquisition. For the three months ended March 31, 2021 we purchased 60,177 treasury shares to satisfy withholding tax obligations arising upon the vesting of restricted shares.
(3) Leases
The Company follows the Financial Accounting Standards Board's Accounting Standards Update 2016-02 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 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 March 31, 2022, 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.
Lease costs represent the straight-line lease expense of ROU assets and short-term leases. The components of lease cost are classified as follows (in thousands):
| Three Months Ended March 31, 2022 | Three Months Ended March 31, 2021 | ||||||||||
| Lease Costs Included in the Asset Additions in the Condensed Consolidated Balance Sheets | |||||||||||
| Property, plant and equipment acquisitions - short-term leases | $ | 1,755 | $ | 329 | |||||||
| Property, plant and equipment acquisitions - operating leases | — | — | |||||||||
| Total lease costs in property, plant and equipment additions | $ | 1,755 | $ | 329 | |||||||
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| Three Months Ended March 31, 2022 | Three Months Ended March 31, 2021 | ||||||||||
| Lease Costs Included in the Condensed Consolidated Statements of Operations | |||||||||||
| Lease operating expenses - short-term leases | $ | 932 | $ | 467 | |||||||
| Lease operating expenses - operating leases | 1,852 | 1,165 | |||||||||
| General and administrative, net - operating leases | 189 | 172 | |||||||||
| Total lease cost expensed | $ | 2,973 | $ | 1,804 | |||||||
The lease term and the discount rate related to the Company's leases are as follows:
| March 31, 2022 | |||||
| Weighted-average remaining lease term (in years) | 2.9 | ||||
| Weighted-average discount rate | 4.1 | % | |||
As of March 31, 2022, the Company's future undiscounted cash payment obligation for its operating lease liabilities are as follows (in thousands):
| As of March 31, 2022 | |||||
| 2022 (Remaining) | $ | 6,641 | |||
| 2023 | 7,578 | ||||
| 2024 | 1,302 | ||||
| 2025 | 781 | ||||
| 2026 | 660 | ||||
| Thereafter | 527 | ||||
| Total undiscounted lease payments | 17,489 | ||||
| Present value adjustment | (1,064) | ||||
| Net operating lease liabilities | $ | 16,425 | |||
Supplemental cash flow information related to leases was as follows (in thousands):
| Three Months Ended March 31, 2022 | Three Months Ended March 31, 2021 | ||||||||||
| Cash paid for amounts included in the measurement of lease liabilities; | |||||||||||
| Operating cash flows from operating leases | $ | 2,025 | $ | 1,335 | |||||||
| Non-cash Investing and Financing Activities | |||||||||||
| Additions to ROU assets obtained from new operating lease liabilities | $ | 1,187 | $ | 993 | |||||||
(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 $1.0 million and $1.1 million for the three months ended March 31, 2022 and 2021, respectively. Capitalized share-based compensation was less than $0.1 million for both the three months ended March 31, 2022 and 2021.
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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 to years). We use the Black-Scholes option pricing model to estimate the fair value of stock option awards.
At March 31, 2022, we had no unrecognized compensation cost related to stock option awards. The following table provides information regarding stock option award activity for the three months ended March 31, 2022:
| Shares | Wtd. Avg. Exer. Price | ||||||||||
| Options outstanding, beginning of period | 276,009 | $ | 28.12 | ||||||||
| Options expired | (64,263) | $ | 33.48 | ||||||||
| Options outstanding, end of period | 211,746 | $ | 26.50 | ||||||||
| Options exercisable, end of period | 211,746 | $ | 26.50 | ||||||||
Our outstanding stock option awards had $1.3 million measurable aggregate intrinsic value at March 31, 2022. At March 31, 2022, the weighted-average remaining contract life of stock option awards outstanding was 5.1 years and exercisable was 5.1 years. The total intrinsic value of stock option awards exercisable was $1.3 million as of March 31, 2022.
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 to five years).
As of March 31, 2022, we had $4.4 million unrecognized compensation expense related to our RSUs which is expected to be recognized over a weighted-average period of 2.5 years.
The following table provides information regarding RSU activity for the three months ended March 31, 2022:
| RSUs | Wtd. Avg. Grant Price | ||||||||||
| RSUs outstanding, beginning of period | 344,845 | $ | 8.60 | ||||||||
| RSUs granted | 170,866 | $ | 25.22 | ||||||||
| RSUs vested | (220,578) | $ | 9.94 | ||||||||
| RSUs outstanding, end of period | 295,133 | $ | 17.22 | ||||||||
Performance-Based Stock Units
On May 21, 2019, the Company granted 99,500 PSUs for which the number of shares earned is 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 contain market conditions which allow 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 have a cliff-vesting period of 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 years. All PSUs granted remain outstanding related to this award as of March 31, 2022.
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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 years. All PSUs granted remain outstanding related to this award as of March 31, 2022.
As of March 31, 2022, we had $5.2 million unrecognized compensation expense related to our PSUs based on the assumption of 100% target payout. The remaining weighted-average performance period is 2.3 years.
The following table provides information regarding performance-based stock unit activity for the three months ended March 31, 2022:
| PSUs | Wtd. Avg. Grant Price | ||||||||||
| Performance based stock units outstanding, beginning of period | 244,989 | $ | 18.84 | ||||||||
| Performance based stock units granted | 122,111 | $ | 24.16 | ||||||||
| Performance based stock units incremental shares granted | 14,212 | $ | 29.87 | ||||||||
| Performance based stock units vested | (97,812) | $ | 29.87 | ||||||||
| Performance based stock units outstanding, end of period | 283,500 | $ | 17.88 | ||||||||
(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 months ended March 31, 2022 and 2021 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 March 31, 2022 | Three Months Ended March 31, 2021 | ||||||||||||||||||||||||||||||||||
| Net Income (Loss) | Shares | Per Share Amount | Net Income (Loss) | Shares | Per Share Amount | ||||||||||||||||||||||||||||||
| Basic EPS: | |||||||||||||||||||||||||||||||||||
| Net Income (Loss) and Share Amounts | $ | (64,255) | 16,719 | $ | (3.84) | $ | 28,380 | 12,029 | $ | 2.36 | |||||||||||||||||||||||||
| Dilutive Securities: | |||||||||||||||||||||||||||||||||||
| RSU Awards | — | 265 | |||||||||||||||||||||||||||||||||
| Diluted EPS: | |||||||||||||||||||||||||||||||||||
| Net Income (Loss) and Assumed Share Conversions | $ | (64,255) | 16,719 | $ | (3.84) | $ | 28,380 | 12,294 | $ | 2.31 | |||||||||||||||||||||||||
Approximately 0.2 million stock options to purchase shares were not included in the computation of Diluted EPS for the three months ended March 31, 2022 because they were antidilutive due to the net loss while 0.3 million stock options to purchase shares were not included in the computation of Diluted EPS for the three months ended March 31, 2021 because they were antidilutive.
Less than 0.1 million antidilutive shares of RSUs that could be converted to common shares were not included in the computation of Diluted EPS for the three months ended March 31, 2022 because they were antidilutive due to the net loss,
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while approximately 0.2 million of RSUs that could be converted to common shares were not included in the computation of Diluted EPS for the three months ended March 31, 2021 because they were antidilutive.
There were no antidilutive shares of PSUs that could be converted to common shares for the three months ended March 31, 2022, while approximately 0.1 million shares of PSUs that could be converted to common shares were not included in the computation of Diluted EPS for the three months ended March 31, 2021 because they were antidilutive.
(6) Long-Term Debt
The Company's long-term debt consisted of the following (in thousands):
| March 31, 2022 | December 31, 2021 | ||||||||||
Credit Facility Borrowings (1) | $ | 200,000 | $ | 227,000 | |||||||
| Second Lien Notes due 2026 | 150,000 | 150,000 | |||||||||
| 350,000 | 377,000 | ||||||||||
| Unamortized discount on Second Lien Notes due 2026 | (1,016) | (1,061) | |||||||||
| Unamortized debt issuance cost on Second Lien Notes due 2026 | (2,981) | (3,114) | |||||||||
| Long-Term Debt, net | $ | 346,003 | $ | 372,825 | |||||||
(1) Unamortized debt issuance costs on our Credit Facility borrowings are included in “Other Long-Term Assets” in our consolidated balance sheet. As of March 31, 2022 and December 31, 2021, we had $3.3 million and $3.6 million, respectively, in unamortized debt issuance costs on our Credit Facility borrowings.
Revolving Credit Facility. Amounts outstanding under our Credit Facility (defined below) were $200.0 million and $227.0 million as of March 31, 2022 and December 31, 2021, 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”). Subsequent to the first quarter 2022 and in conjunction with its regularly scheduled semi-annual redetermination, the Company entered into the Ninth Amendment to the Credit Facility, effective April 12, 2022 (the “Ninth Amendment”), which increased the borrowing base under the Credit Facility to $525.0 million from $460.0 million.
The Credit Facility matures April 19, 2024 and provides for a maximum credit amount of $1.0 billion, subject to the current borrowing base of $525.0 million as of April 12, 2022. 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. 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 March 31, 2022 and December 31, 2021. 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”). Effective November 12, 2021, the applicable margin ranged from 2.25% to 3.25% for ABR Loans and 3.25% to 4.25% 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.
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 90% of estimated proved reserves of the Company and its subsidiary.
The Credit Agreement contains the following financial covenants:
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•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 (i) 3.25 to 1.00 as of the last day of each fiscal quarter for any fiscal quarter ending on or before December 31, 2021 and (ii) 3.00 to 1.00 as of the last day of each fiscal quarter, commencing with fiscal quarter ending March 31, 2022; 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 March 31, 2022, 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 $3.2 million and $2.5 million for the three months ended March 31, 2022 and 2021, respectively. The amount of commitment fee amortization included in interest expense, net was $0.3 million and $0.1 million for the three months ended March 31, 2022 and 2021, 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. The Company accounted for this paydown as a debt modification and incurred approximately $0.1 million in third party fees in connection with the amendment. The unamortized debt issuance cost and discount on the Second Lien Notes will be amortized through the new maturity date of December 15, 2026.
Interest on the Second Lien is payable quarterly and accrues at LIBOR plus 7.5%; provided that if LIBOR ceases to be available, the Second Lien provides for a mechanism to use ABR (an alternate base rate) plus 6.5% as the applicable interest rate. The definitions of LIBOR and ABR are set forth in the Note Purchase Agreement. To the extent that a payment, insolvency, or, at the holders’ election, another default exists and is continuing, all amounts outstanding under the Second Lien will bear interest at 2.0% per annum above the rate and margin otherwise applicable thereto. Additionally, to the extent the Company were to default on the Second Lien, this would potentially trigger a cross-default under our Credit Facility.
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, subject to a repayment fee of 1.0% of the principal amount of the Second Lien being prepaid through December 15, 2022; and thereafter, 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%.
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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 3.5 to 1.0 as of the last day of each fiscal quarter ending on or before December 31, 2021, (ii) and 3.25 to 1.0 as of the last day of each fiscal quarter, commencing with fiscal quarter ending March 31, 2022, and for any fiscal quarter thereafter. As of March 31, 2022, 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 March 31, 2022, total net amounts recorded for the Second Lien were $146.0 million, net of unamortized debt discount and debt issuance costs. Interest expense on the Second Lien totaled $3.4 million and $4.5 million for the three months ended March 31, 2022 and 2021, 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.
(7) Acquisitions and Dispositions
Bay De Chene Disposition
Effective December 22, 2017, the Company closed a purchase and sale contract to sell the Company's wellbores and facilities in the Bay De Chene field and recorded a $16.3 million obligation related to the funding of certain plugging and abandonment costs. Of the $16.3 million original obligation, no amount was paid during the three months ended March 31, 2022 and 2021. The remaining obligation under this contract is $0.5 million and is carried in the accompanying condensed consolidated balance sheet current liability in “Accounts payable and accrued liabilities” as of March 31, 2022.
August 2021 Acquisition
On August 3, 2021, the Company acquired the remaining working interest in 12 wells that SilverBow operates and additional acreage in Webb county. The total aggregate consideration was approximately $23.0 million, consisting of $13.0 million in cash and 516,675 shares of common stock valued at approximately $10.0 million based on the Company's share price on the closing date. 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. As a result, we allocated substantially all of the purchase price to proved oil and gas properties.
October 2021 Acquisition
On October 1, 2021, we closed on an all-stock transaction to acquire oil and gas assets in the Eagle Ford with three affiliated entities. The acquired assets include working interests in oil and gas properties across Atascosa, Fayette, Lavaca, McMullen and Live Oak counties. After consideration of closing adjustments, we issued 1,341,990 shares of our common stock valued at approximately $35.6 million, based on the Company's share price on the closing date. The acquisition was subject to further customary post-closing adjustments. We incurred approximately $0.6 million in transaction costs for the year ended December 31, 2021. 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. As a result, we allocated substantially all of the purchase price to proved oil and gas properties. As part of the post-closing settlement of this acquisition
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we received 41,191 shares back to our Treasury from two of the entities, and we issued 489 new shares to one of the entities during the three months ended March 31, 2022.
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 (“WTI Contingency Payout”). During the three months ended March 31, 2022, the Company recorded losses of $1.2 million related to the WTI Contingency Payout recorded in “Gain (loss) on commodity derivatives, net” on the accompanying condensed consolidated statements of operations. 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. The acquisition is subject to further customary post-closing adjustments. We incurred approximately $0.3 million in transaction costs for the year ended December 31, 2021. 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. As a result, we allocated the purchase price to proved oil and gas properties. We received $0.4 million in purchase price adjustments related to this acquisition during the three months ended March 31, 2022.
(8) Price-Risk Management Activities
Derivatives are recorded on the 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 March 31, 2022 and 2021, the Company recorded losses of $139.0 million and $18.3 million, respectively, on its commodity derivatives. The Company made cash payments of $24.6 million and $3.1 million for settled derivative contracts during the three months ended March 31, 2022 and 2021, respectively.
At March 31, 2022 and December 31, 2021, there was $0.3 million and $0.9 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 April 2022 and January 2022, respectively. At March 31, 2022 and December 31, 2021, we also had $15.0 million and $6.4 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 April 2022 and January 2022, 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 March 31, 2022, there was $1.7 million and less than $0.1 million in current unsettled derivative assets and long-term unsettled derivative assets, respectively, and $140.9 million and $19.1 million in current and long-term unsettled derivative liabilities, respectively. At December 31, 2021, there was $2.8 million and $0.2 million in current and long-term unsettled derivative assets, respectively, and $47.5 million and $8.6 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 $158.3 million net fair value liability at March 31, 2022, and a $53.0 million net fair value liability at December 31, 2021. 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.
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The following tables summarize the weighted-average prices as well as future production volumes for our future derivative contracts in place as of March 31, 2022:
| Oil Derivative Contracts (New York Mercantile Exchange (“NYMEX”) WTI Settlements) | Total Volumes (Bbls) | Weighted-Average Price | Weighted-Average Collar Floor Price | Weighted-Average Collar Call Price | ||||||||||||||||||||||
| Swap Contracts | ||||||||||||||||||||||||||
| 2022 Contracts | ||||||||||||||||||||||||||
| 2Q22 | 136,500 | $ | 56.66 | |||||||||||||||||||||||
| 3Q22 | 276,600 | $ | 53.27 | |||||||||||||||||||||||
| 4Q22 | 276,000 | $ | 63.97 | |||||||||||||||||||||||
| 2023 Contracts | ||||||||||||||||||||||||||
| 1Q23 | 194,675 | $ | 69.12 | |||||||||||||||||||||||
| 2Q23 | 114,325 | $ | 77.80 | |||||||||||||||||||||||
| 3Q23 | 122,980 | $ | 71.81 | |||||||||||||||||||||||
| 4Q23 | 117,300 | $ | 73.92 | |||||||||||||||||||||||
| Collar Contracts | ||||||||||||||||||||||||||
| 2022 Contracts | ||||||||||||||||||||||||||
| 2Q22 | 161,350 | $ | 48.21 | $ | 55.16 | |||||||||||||||||||||
| 3Q22 | 46,000 | $ | 70.00 | $ | 75.40 | |||||||||||||||||||||
| 4Q22 | 46,000 | $ | 68.00 | $ | 73.60 | |||||||||||||||||||||
| 2023 Contracts | ||||||||||||||||||||||||||
| 1Q23 | 45,000 | $ | 65.00 | $ | 72.80 | |||||||||||||||||||||
| 2Q23 | 111,475 | $ | 59.27 | $ | 66.32 | |||||||||||||||||||||
| 3Q23 | 46,000 | $ | 63.00 | $ | 69.10 | |||||||||||||||||||||
| 4Q23 | 46,000 | $ | 62.00 | $ | 67.55 | |||||||||||||||||||||
| 2024 Contracts | ||||||||||||||||||||||||||
| 1Q24 | 36,400 | $ | 70.00 | $ | 80.15 | |||||||||||||||||||||
| Natural Gas Derivative Contracts (NYMEX Henry Hub Settlements) | Total Volumes (MMBtu) | Weighted-Average Price | Weighted-Average Collar Floor Price | Weighted-Average Collar Call Price | ||||||||||||||||||||||
| Swap Contracts | ||||||||||||||||||||||||||
| 2022 Contracts | ||||||||||||||||||||||||||
| 2Q22 | 4,395,000 | $ | 3.20 | |||||||||||||||||||||||
| 3Q22 | 4,452,100 | $ | 3.13 | |||||||||||||||||||||||
| 4Q22 | 2,760,000 | $ | 3.14 | |||||||||||||||||||||||
| Collar Contracts | ||||||||||||||||||||||||||
| 2022 Contracts | ||||||||||||||||||||||||||
| 2Q22 | 6,156,500 | $ | 2.29 | $ | 2.74 | |||||||||||||||||||||
| 3Q22 | 7,659,000 | $ | 2.81 | $ | 3.23 | |||||||||||||||||||||
| 4Q22 | 8,685,076 | $ | 2.87 | $ | 3.43 | |||||||||||||||||||||
| 2023 Contracts | ||||||||||||||||||||||||||
| 1Q23 | 10,147,000 | $ | 3.21 | $ | 4.21 | |||||||||||||||||||||
| 2Q23 | 8,315,550 | $ | 2.89 | $ | 3.50 | |||||||||||||||||||||
| 3Q23 | 7,999,400 | $ | 3.10 | $ | 3.69 | |||||||||||||||||||||
| 4Q23 | 6,785,000 | $ | 3.37 | $ | 4.11 | |||||||||||||||||||||
| 2024 Contracts | ||||||||||||||||||||||||||
| 1Q24 | 3,185,000 | $ | 3.50 | $ | 5.34 | |||||||||||||||||||||
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| Natural Gas Basis Derivative Swaps (East Texas Houston Ship Channel vs. NYMEX Settlements) | Total Volumes (MMBtu) | Weighted-Average Price | ||||||||||||
| 2022 Contracts | ||||||||||||||
| 2Q22 | 3,640,000 | $ | (0.051) | |||||||||||
| 3Q22 | 3,680,000 | $ | (0.043) | |||||||||||
| 4Q22 | 3,680,000 | $ | (0.048) | |||||||||||
| Oil Basis Swaps (Argus Cushing (WTI) and Magellan East Houston) | Total Volumes (Bbls) | Weighted-Average Price | ||||||||||||
| Calendar Monthly Roll Differential Swaps | ||||||||||||||
| 2022 Contracts | ||||||||||||||
| 2Q22 | 309,400 | $ | 0.55 | |||||||||||
| 3Q22 | 312,800 | $ | 0.62 | |||||||||||
| 4Q22 | 266,800 | $ | 0.19 | |||||||||||
| NGL Swaps (Mont Belvieu) | Total Volumes (Bbls) | Weighted-Average Price | ||||||||||||
| 2022 Contracts | ||||||||||||||
| 2Q22 | 182,000 | $ | 30.49 | |||||||||||
| 3Q22 | 207,000 | $ | 30.79 | |||||||||||
| 4Q22 | 207,000 | $ | 30.74 | |||||||||||
| 2023 Contracts | ||||||||||||||
| 1Q23 | 22,500 | $ | 31.77 | |||||||||||
| 2Q23 | 22,750 | $ | 31.77 | |||||||||||
| 3Q23 | 23,000 | $ | 28.04 | |||||||||||
| 4Q23 | 23,000 | $ | 28.04 | |||||||||||
(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 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,
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inflation factors, credit-adjusted discount rates, timing of settlement and changes in the legal, regulatory, environmental and political environments.
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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The following table presents our assets and liabilities that are measured on a recurring basis at fair value as of each of March 31, 2022 and December 31, 2021, 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) | |||||||||||||||||||
| March 31, 2022 | |||||||||||||||||||||||
| Assets | |||||||||||||||||||||||
| Natural Gas Derivatives | $ | 170 | $ | — | $ | 170 | $ | — | |||||||||||||||
| Natural Gas Basis Derivatives | 1,530 | — | 1,530 | — | |||||||||||||||||||
| Oil Basis Derivatives | 48 | — | 48 | — | |||||||||||||||||||
| NGL Derivatives | 7 | — | 7 | — | |||||||||||||||||||
| Liabilities | |||||||||||||||||||||||
| Natural Gas Derivatives | 110,720 | — | 110,720 | — | |||||||||||||||||||
| Natural Gas Basis Derivatives | 27 | — | 27 | — | |||||||||||||||||||
| Oil Derivatives | 41,754 | — | 41,754 | — | |||||||||||||||||||
| Oil Basis Derivatives | 1,313 | — | 1,313 | — | |||||||||||||||||||
| NGL Derivatives | 6,216 | — | 6,216 | — | |||||||||||||||||||
| WTI Contingency Payout | $ | 3,088 | $ | — | $ | 3,088 | $ | — | |||||||||||||||
| December 31, 2021 | |||||||||||||||||||||||
| Assets | |||||||||||||||||||||||
| Natural Gas Derivatives | $ | 1,159 | $ | — | $ | 1,159 | $ | — | |||||||||||||||
| Natural Gas Basis Derivatives | 1,025 | — | 1,025 | — | |||||||||||||||||||
| Oil Derivatives | 371 | — | 371 | — | |||||||||||||||||||
| Oil Basis Derivatives | 3 | — | 3 | — | |||||||||||||||||||
| NGL Derivatives | 449 | — | 449 | — | |||||||||||||||||||
| Liabilities | |||||||||||||||||||||||
| Natural Gas Derivatives | 31,801 | — | 31,801 | — | |||||||||||||||||||
| Natural Gas Basis Derivatives | 452 | — | 452 | — | |||||||||||||||||||
| Oil Derivatives | 21,330 | — | 21,330 | — | |||||||||||||||||||
| Oil Basis Derivatives | 514 | — | 514 | — | |||||||||||||||||||
| NGL Derivatives | 1,941 | — | 1,941 | — | |||||||||||||||||||
| WTI Contingency Payout | $ | 1,841 | $ | — | $ | 1,841 | $ | — | |||||||||||||||
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
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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, 2021 and the three months ended March 31, 2022 (in thousands):
| Asset Retirement Obligations as of December 31, 2020 | $ | 4,974 | |||
| Accretion expense | 306 | ||||
| Liabilities incurred for new wells, acquired wells and facilities construction | 1,120 | ||||
| Reductions due to plugged wells and facilities | (192) | ||||
| Revisions in estimates | (158) | ||||
| Asset Retirement Obligations as of December 31, 2021 | $ | 6,050 | |||
| Accretion expense | 99 | ||||
| Liabilities incurred for new wells and facilities construction | 29 | ||||
| Reductions due to plugged wells and facilities | (9) | ||||
| Asset Retirement Obligations as of March 31, 2022 | $ | 6,169 | |||
At both March 31, 2022 and December 31, 2021, approximately $0.5 million of our asset retirement obligations were classified as a current liability in “Accounts payable and accrued liabilities” on the accompanying 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.
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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, 2021. 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 153,000 net acres across six 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
Total production for the three months ended March 31, 2022 increased 25% from the three months ended March 31, 2021 to 226 million cubic feet of natural gas equivalent per day as SilverBow pursued a moderated growth strategy and did not have any curtailed production impacting results.
During the first quarter of 2022, SilverBow drilled nine net wells, completed one well and brought one well online. The Company's first quarter activity focused primarily on its La Mesa area, where one Austin Chalk well drilled to a lateral length of approximately 9,800 feet was brought online, representing the longest lateral SilverBow has drilled in the Austin Chalk to date. Additionally, SilverBow drilled an eight-well La Mesa pad, the largest pad in the Company’s history. The eight wells were co-developed using a wine-rack configuration, of which three targeted the Lower Eagle Ford, three targeted the Upper Eagle Ford and two targeted the Austin Chalk. First production from this pad is expected towards the end of the second quarter of 2022.
SilverBow's drilling rig will shift its focus from our Webb County Gas and Austin Chalk assets in the first quarter towards our La Salle and McMullen oil assets in the second quarter. In the back half of the year, the Company anticipates drilling a mix of Webb County Gas wells and locations acquired in 2021. SilverBow anticipates adding a second rig upon closing the Sundance acquisition. The Company continues to optimize its drilling schedule based on commodity prices and first production timing.
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. As of March 31, 2022, the Company’s liquidity consisted of $1.6 million of cash-on-hand and $260.0 million in available borrowings on its Credit Facility, which had a $460 million borrowing base. Effective April 12, 2022, SilverBow entered into the Ninth Amendment to its First Amended and Restated Senior Secured Revolving Credit Agreement governing its Credit Facility, in conjunction with its regularly scheduled borrowing base redetermination. The Ninth Amendment (i) increased the borrowing base of SilverBow's Credit Facility from $460 million to $525 million, (ii) added two new lenders as parties to the Credit Agreement, and (iii) added an investment bucket allowing the Company to make deposits to third party sellers up to the lesser of $50 million and 10% of the borrowing base. Management believes the Company has sufficient liquidity to meet its obligations through the second quarter of 2023 and execute its long-term development plans. For more information on its Credit Facility, see the Credit Facility section within Note 6 to SilverBow's condensed consolidated financial statements.
Contractual Commitments and Obligations
Other than as discussed below, there were no other material changes in SilverBow's contractual commitments during the three months ended March 31, 2022 from amounts referenced under “Contractual Commitments and Obligations” in
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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, 2021.
On April 13, 2022, SilverBow entered into a definitive agreement to acquire substantially all of the assets of Sundance Energy, Inc. and certain affiliated entities (the “Sundance Sellers”) for a total purchase price of $354 million consisting of $225 million in cash, subject to customary closing adjustments, 4.1 million shares of SilverBow common stock valued at $129 million based on our 30-day volume weighted average price as of April 8, 2022, and up to $15 million of contingent payments in cash based on future commodity prices. The Sundance transaction, which is expected to close in June or July of 2022, has been unanimously approved by the Boards of Directors of both companies. The closing of the transaction is subject to SilverBow shareholder approval and satisfaction or waiver of customary closing conditions. The Company and the Sundance Sellers made customary representations and warranties in the purchase agreement. Subject to certain limitations on liability contained in the purchase agreement, the Company agreed to indemnify the Sundance Sellers for breaches of representations and warranties, covenants and certain liabilities. The purchase agreement contains certain termination rights for both the Company and the Sundance Sellers, including, but not limited to, the right to terminate the purchase agreement in the event that the transaction has not been approved by shareholders and consummated on or before September 2, 2022, or under certain conditions, if there has been a breach of certain representations and warranties or a failure by the other party to perform a covenant. In connection with the purchase agreement, on April 13, 2022, SilverBow entered into an agreement with SVMF 71 LLC (“SVMF 71”), an entity indirectly managed by Strategic Value Partners, LLC (“SVP”), pursuant to which SVMF 71 agreed to vote its shares of common stock in favor of the issuance of the common stock in the transaction in any shareholder vote thereon, subject to specified conditions. Each of the Sundance Sellers is a third party beneficiary of the voting agreement with respect to SVMF 71's performance thereunder. SilverBow agreed to provide customary registration rights with respect to the resale of the common stock issued to the Sundance Sellers as consideration in the transaction.
On April 13, 2022, SilverBow also announced it entered into a definitive agreement to acquire certain assets from SandPoint Operating, LLC, a subsidiary of SandPoint Resources, LLC, (“SandPoint”) for a total purchase price of $71 million consisting of $31 million in cash, subject to customary closing adjustments and 1.3 million shares of SilverBow common stock valued at $40 million based on our 30-day volume weighted average price as of April 8, 2022. The oil and gas assets target the Eagle Ford and Olmos formations in La Salle and McMullen counties. The SandPoint transaction has been unanimously approved by the Boards of Directors of both companies and is expected to close in May of 2022, subject to customary closing conditions. SilverBow agreed to provide customary registration rights with respect to the resale of the common stock issued to the SandPoint as consideration in the transaction.
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Summary of 2022 Financial Results Through March 31, 2022
•Revenues and Net Income (Loss): The Company's oil and gas revenues were $129.7 million for the three months ended March 31, 2022, compared to $86.7 million for the three months ended March 31, 2021. Revenues were higher due to increased production volumes and higher oil and NGL pricing. The Company's net loss was $64.3 million for the three months ended March 31, 2022, compared to net income of $28.4 million for the three months ended March 31, 2021. The net loss was primarily due to mark-to-market loss on our commodity derivatives, partially offset by higher revenues due to increased production volumes and higher oil and NGL pricing.
•Capital Expenditures: The Company's capital expenditures on an accrual basis were $40.4 million for the three months ended March 31, 2022 compared to $33.0 million for the three months ended March 31, 2021. The expenditures for the three months ended March 31, 2022 and 2021 were primarily attributable to drilling and completion activity.
•Working Capital: The Company had a working capital deficit of $170.0 million at March 31, 2022 and a working capital deficit of $65.8 million at December 31, 2021. Included in our working capital deficit was a net unrealized loss of $139.3 million and $44.6 million at March 31, 2022 and December 31, 2021, respectively, related to the fair value of our current derivative contracts. The working capital computation does not include available liquidity through our Credit Facility.
•Cash Flows: For the three months ended March 31, 2022, the Company generated cash from operating activities of $64.9 million during which we had a decrease of working capital of $7.0 million. Cash used for property additions was $35.2 million while cash received in property acquisitions, including purchase price adjustments was $0.4 million. This excluded $5.0 million attributable to a net increase of capital-related payables and accrued costs. The Company’s net repayments on the Credit Facility were $27.0 million during the three months ended March 31, 2022.
For the three months ended March 31, 2021, the Company generated cash from operating activities of $67.8 million, of which $9.5 million was attributable to changes in working capital. Cash used for property additions was $35.9 million. This included $3.6 million attributable to a net decrease of capital-related payables and accrued costs. The Company’s net repayments on the Credit Facility were $30.0 million during the three months ended March 31, 2021.
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Results of Operations
Revenues — Three Months Ended March 31, 2022 and Three Months Ended March 31, 2021
Natural gas production was 77% and 78% of the Company's production volumes for the three months ended March 31, 2022 and 2021, respectively. Natural gas sales were 60% and 73% of oil and gas sales for the three months ended March 31, 2022 and 2021, respectively.
Crude oil production was 13% and 12% of the Company's production volumes for the three months ended March 31, 2022 and 2021, respectively. Crude oil sales were 31% and 20% of oil and gas sales for the three months ended March 31, 2022 and 2021, respectively.
NGL production was 10% of the Company's production volumes for both the three months ended March 31, 2022 and 2021. NGL sales were 9% and 7% of oil and gas sales for the three months ended March 31, 2022 and 2021, respectively.
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 March 31, 2022 and 2021:
| Fields | Three Months Ended March 31, 2022 | Three Months Ended March 31, 2021 | ||||||||||||||||||
| 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) | |||||||||||||||||
| Artesia | $ | 37.3 | 4,477 | $ | 14.5 | 3,252 | ||||||||||||||
| AWP | 16.1 | 1,696 | 17.0 | 2,715 | ||||||||||||||||
| Fasken | 54.6 | 10,971 | 47.4 | 8,407 | ||||||||||||||||
| Atascosa | 3.0 | 215 | — | — | ||||||||||||||||
| Eastern Eagle Ford | 8.1 | 797 | — | — | ||||||||||||||||
| Southern Eagle Ford Gas | 7.4 | 1,542 | 7.4 | 1,747 | ||||||||||||||||
| Other | 3.2 | 621 | 0.4 | 103 | ||||||||||||||||
| Total | $ | 129.7 | 20,319 | $ | 86.7 | 16,224 | ||||||||||||||
The sales volumes increase from 2021 to 2022 was primarily due to acquisitions in the second half of 2021, in addition to wells brought online as part of our full year 2021 capital program.
In the first quarter of 2022, our $42.9 million, or 49%, increase in oil, NGL and natural gas sales from the prior year period resulted from:
•Price variances that had an approximately $20.1 million favorable impact on sales due to higher oil and NGL pricing; and
•Volume variances that had an approximately $22.8 million favorable impact on sales due to overall increased commodity production.
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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 March 31, 2022 and 2021 (in thousands, except per-dollar amounts):
| Three Months Ended March 31, 2022 | Three Months Ended March 31, 2021 | ||||||||||
| Production volumes: | |||||||||||
Oil (MBbl) (1) | 429 | 315 | |||||||||
| Natural gas (MMcf) | 15,587 | 12,624 | |||||||||
Natural gas liquids (MBbl) (1) | 359 | 285 | |||||||||
| Total (MMcfe) | 20,319 | 16,224 | |||||||||
| Oil, natural gas and natural gas liquids sales: | |||||||||||
| Oil | $ | 39,741 | $ | 17,466 | |||||||
| Natural gas | 77,372 | 62,914 | |||||||||
| Natural gas liquids | 12,543 | 6,361 | |||||||||
| Total | $ | 129,656 | $ | 86,741 | |||||||
| Average realized price: | |||||||||||
| Oil (per Bbl) | $ | 92.59 | $ | 55.49 | |||||||
| Natural gas (per Mcf) | 4.96 | 4.98 | |||||||||
| Natural gas liquids (per Bbl) | 34.89 | 22.30 | |||||||||
| Average per Mcfe | $ | 6.38 | $ | 5.35 | |||||||
| Price impact of cash-settled derivatives: | |||||||||||
| Oil (per Bbl) | $ | (30.04) | $ | (12.75) | |||||||
| Natural gas (per Mcf) | (0.84) | (0.01) | |||||||||
| Natural gas liquids (per Bbl) | (6.11) | (2.07) | |||||||||
| Average per Mcfe | $ | (1.39) | $ | (0.29) | |||||||
| Average realized price including impact of cash-settled derivatives: | |||||||||||
| Oil (per Bbl) | $ | 62.55 | $ | 42.74 | |||||||
| Natural gas (per Mcf) | 4.12 | 4.97 | |||||||||
| Natural gas liquids (per Bbl) | 28.78 | 20.23 | |||||||||
| Average per Mcfe | $ | 4.99 | $ | 5.06 | |||||||
(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 March 31, 2022 and 2021, the Company recorded net losses of $139.0 million and $18.3 million from our derivatives activities, respectively. Hedging activity is recorded in “Gain (loss) on commodity derivatives, net” on the accompanying condensed consolidated statements of operations.
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Costs and Expenses — Three Months Ended March 31, 2022 and Three Months Ended March 31, 2021
The following table provides additional information regarding our expenses for the three months ended March 31, 2022 and 2021 (in thousands):
| Costs and Expenses | Three Months Ended March 31, 2022 | Three Months Ended March 31, 2021 | ||||||
| General and administrative, net | $ | 4,786 | $ | 4,782 | ||||
| Depreciation, depletion, and amortization | 21,154 | 13,393 | ||||||
| Accretion of asset retirement obligations | 99 | 75 | ||||||
| Lease operating expenses | 9,125 | 6,274 | ||||||
| Workovers | 647 | 13 | ||||||
| Transportation and gas processing | 6,352 | 5,056 | ||||||
| Severance and other taxes | 7,764 | 3,489 | ||||||
| Interest expense, net | 6,557 | 7,019 | ||||||
General and Administrative Expenses, Net. These expenses on a per-Mcfe basis were $0.24 and $0.29 for the three months ended March 31, 2022 and 2021, respectively. The decrease per Mcfe was due to higher production. Included in general and administrative expenses is $1.0 million and $1.1 million in share-based compensation for the three months ended March 31, 2022 and 2021, respectively.
Depreciation, Depletion and Amortization. These expenses on a per-Mcfe basis were $1.04 and $0.83 for the three months ended March 31, 2022 and 2021, respectively. The increase in our per-Mcfe depreciation, depletion and amortization rate was primarily related to the acquisitions in the fourth quarter of 2021. 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 $0.48 and $0.39 for the three months ended March 31, 2022 and 2021, respectively. The increase in costs was due to higher compression, salt water disposal, chemicals and dehydration and treating costs.
Transportation and Gas Processing. These expenses are related to natural gas and NGL sales. These expenses on a per-Mcfe basis were $0.31 for both the three months ended March 31, 2022 and 2021.
Severance and Other Taxes. These expenses on a per-Mcfe basis were $0.38 and $0.22 for the three months ended March 31, 2022 and 2021, respectively. Severance and other taxes, as a percentage of oil and gas sales, were approximately 6.0% and 4.0% for the three months ended March 31, 2022 and 2021, respectively.
Interest. Our gross interest cost was $6.6 million and $7.0 million for the three months ended March 31, 2022 and 2021, respectively. The decrease in gross interest is primarily due lower borrowing. There were no capitalized interest costs for the three months ended March 31, 2022 and 2021.
Income Taxes. The Company recorded an income tax benefit of $2.8 million for the three months ended March 31, 2022 primarily attributable to a deferred federal income tax benefit and state deferred income tax benefit. The benefit is a product of the overall forecasted annual effective tax rate applied to the year to date loss, and thus is a reduction of our deferred tax liability at December 31, 2021. There was no income tax expense or benefit for the three months ended March 31, 2021.
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Critical Accounting Policies and New Accounting Pronouncements
There have been no changes in the critical accounting policies disclosed in our 2021 Annual Report on Form 10-K.
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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 March 31, 2022, we had a combined $350.0 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 March 31, 2022 would increase our annual interest expense by $3.5 million.
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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 March 31, 2022 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.
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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 “Item 1A. Risk Factors” included in our Annual Report on Form 10-K for the fiscal year ended December 31, 2021. There have been no material changes in our risk factors disclosed in the 2021 Annual Report on Form 10-K, except as set forth below:
There is no assurance as to when or if the Sundance transaction will be completed. Failure to obtain required approvals necessary to satisfy closing conditions may delay or prevent completion of the Sundance transaction.
The completion of the Sundance transaction is subject to a number of closing conditions, some of which are out of SilverBow’s control, including the following:
•approval of the issuance of shares of common stock of SilverBow (the “Common Shares”) by SilverBow shareholders;
•the aggregate value of any title and environmental defects, and the allocated value attributable to assets subject to unobtained preferential purchase rights and certain consents related to the assets being transferred being less than $48 million;
•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 Sundance transaction; and
•the accuracy of representations and warranties made by the other party in the transaction agreement (subject generally to a material adverse effect standard, with different standards applicable to certain representations and warranties).
SilverBow cannot be certain that its shareholders will approve the issuance of shares in connection with the Sundance transaction. SilverBow also cannot be certain when it and Sundance will be able to satisfy the other closing conditions or whether those closing conditions will be satisfied. If any of these conditions are not satisfied or waived prior to September 2, 2022, it is possible that the transaction agreement may be terminated. Although the parties have agreed in the transaction agreement to use commercially reasonable efforts, subject to certain limitations, to complete the Sundance transaction, these and other conditions to the completion of the Sundance transaction may fail to be satisfied.
Current SilverBow shareholders will have a reduced ownership and voting interest in SilverBow after the Sundance transaction and will exercise less influence over management.
The consideration for the Sundance transaction payable at closing will include 4,148,472 Common Shares. After closing of the Sundance transaction, current SilverBow shareholders (after giving effect to the shares issued in the SandPoint acquisition) will own approximately 81.4% of the outstanding Common Shares and former shareholders of Sundance will own approximately 18.6% of the outstanding Common Shares. Accordingly, the issuance of SilverBow shares to Sundance’s shareholders in the Sundance transaction will reduce the relative voting power of current SilverBow shareholders. Consequently, current SilverBow shareholders as a group will have less influence over the management and policies of SilverBow after the Sundance transaction than prior to the transaction.
The pendency of the Sundance transaction could have an adverse effect on the trading price of the Common Shares and the business, financial condition, results of operations or business prospects for SilverBow and/or Sundance.
The pendency of the Sundance transaction could disrupt SilverBow’s business, including in the following ways:
•third parties may seek to terminate or renegotiate their relationships with SilverBow or Sundance, or may delay or defer certain business decisions, as a result of the Sundance transaction, whether pursuant to the terms of their existing agreements with SilverBow or Sundance or otherwise;
•the attention of the SilverBow and Sundance’s management may be directed toward completion of the Sundance transaction and related matters and may be diverted from the day-to-day business operations of their respective companies, including from other opportunities that otherwise might be beneficial to SilverBow and Sundance ; and
•the transaction agreement restricts SilverBow and Sundance from taking certain specified actions while the Sundance transaction is pending without first obtaining written consent of the other party, which may restrict SilverBow or
38
Sundance from pursuing otherwise attractive business opportunities and making other changes to their businesses before completion of the Sundance transaction or termination of the transaction agreement.
Should they occur, any of these matters could adversely affect the trading price of the Common Shares or harm the financial condition, results of operations or business prospects of SilverBow and/or Sundance.
Failure to complete the Sundance transaction could negatively impact SilverBow’s share price and future business and financial results.
If the Sundance transaction is not completed, SilverBow’s ongoing business may be adversely affected, and SilverBow may be subject to several risks, including the following:
•having to pay certain costs relating to the Sundance transaction, such as legal, accounting, financial advisor and other fees and expenses and, in certain circumstances, liquidated damages;
•a potential decline in the price of the Common Shares to the extent that the current market price reflects a market assumption that the Sundance transaction will be completed;
•reputational harm due to the adverse perception of any failure to successfully complete the Sundance transaction; and
•having had the focus of SilverBow’s management on the Sundance transaction instead of on pursuing other opportunities that could have been beneficial to SilverBow.
SilverBow has incurred and will continue to incur significant transaction costs in connection with the Sundance transaction.
SilverBow expects to incur a number of non-recurring transaction-related costs associated with completing the Sundance transaction, combining the operations of the two organizations and achieving desired synergies. These fees and costs will be substantial. Non-recurring transaction costs include, but are not limited to, fees paid to financial, legal and accounting advisors, filing fees, printing costs, and costs of future resales of the Common Shares. Additional unanticipated costs may be incurred in the integration of the Sundance’s and SilverBow’s businesses. There can be no assurance that the elimination of certain duplicative costs, as well as the realization of other efficiencies related to the integration of the two businesses, will offset the incremental transaction-related costs over time.
The failure to integrate successfully the assets acquired in the Sundance transaction into SilverBow’s business in the expected timeframe would adversely affect SilverBow’s future results following the completion of the Sundance transaction.
The success of the Sundance transaction will depend, in large part, on the ability of SilverBow following the completion of the transaction to realize the anticipated benefits, including operating synergies, from the acquired assets. SilverBow must successfully integrate the properties and assets into SilverBow’s business. This integration will be complex and time-consuming, and significant management attention and resources will be required to integrate the property and assets. Delays in this process could adversely affect SilverBow’s business, financial results, financial condition and share price following the Sundance transaction.
Potential difficulties that may be encountered in the integration process include potential unknown liabilities and unforeseen expenses, delays or regulatory conditions associated with the Sundance transaction and performance shortfalls at one or both of the companies as a result of the diversion of management’s attention caused by completing the Sundance transaction . Even if SilverBow was able to integrate the assets successfully, there can be no assurance that this integration will result in the realization of the full benefits of synergies and operational efficiencies that may be possible from this integration and that these benefits will be achieved within a reasonable period of time.
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds.
The issuance of the Common Shares in connection with the Sundance and SandPoint acquisitions will be completed in reliance upon the exemption from the registration requirements of the Securities Act of 1933, as amended (the “Securities Act”), provided by Section 4(a)(2) thereof as transactions by an issuer not involving any public offering. SilverBow has agreed to use reasonable efforts to prepare and file a registration statement under the Securities Act to permit resale of the Common Shares.
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Item 3. Defaults Upon Senior Securities.
Not applicable.
Item 4. Mine Safety Disclosures.
Not applicable.
Item 5. Other Information.
Not applicable.
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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 | |||||
10.1*+ | |||||
10.2*+ | |||||
10.3*+ | |||||
| 10.4 | |||||
| 10.5 | |||||
| 10.6 | |||||
| 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 March 31, 2022 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.
+ Management contract or compensatory plan or arrangement.
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SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
| SILVERBOW RESOURCES, INC. (Registrant) | ||||||||||||||
| Date: | May 5, 2022 | By: | /s/ Christopher M. Abundis | |||||||||||
| Christopher M. Abundis Executive Vice President, Chief Financial Officer, General Counsel and Secretary | ||||||||||||||
| Date: | May 5, 2022 | By: | /s/ W. Eric Schultz | |||||||||||
| W. Eric Schultz Controller | ||||||||||||||
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