Talos Energy Inc 8-K/A, filed Apr 12, 2023
Talos Energy Inc. (TALO)
About this 8-K/A
Talos Energy Inc filed this 8-K/A on April 12, 2023, reporting on events of February 13, 2023.
Items reported
- Item 9.01: Financial statements and exhibits
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM
(Amendment No. 1)
CURRENT REPORT
PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
Date of Report (Date of earliest event reported): April 12, 2023 (
(Exact name of registrant as specified in its charter)
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(Commission File Number) |
(I.R.S. Employer Identification No.) |
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(Registrant’s telephone number, including area code)
(Former name or former address, if changed since last report)
Check the appropriate box below if the Form 8-K is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions:
| Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425) |
| Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12) |
| Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b)) |
| Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c)) |
Securities registered pursuant to Section 12(b) of the Act:
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Name of Each Exchange on Which Registered | ||
Indicate by check mark whether the registrant is an emerging growth company as defined in Rule 405 of the Securities Act of 1933 (§230.405 of this chapter) or Rule 12b-2 of the Securities Exchange Act of 1934 (§240.12b-2 of this chapter).
Emerging growth company
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐
Introductory Note
As reported in a Current Report on Form 8-K filed with the U.S. Securities and Exchange Commission by Talos Energy Inc. (the “Company”) on February 14, 2023 (the “Original Form 8-K”), on February 13, 2023, the Company consummated the mergers (the “Mergers”) contemplated by the Agreement and Plan of Merger, dated as of September 21, 2022, by and among EnVen Energy Corporation (“EnVen”), Talos Production Inc., Tide Merger Sub I Inc., Tide Merger Sub II LLC, Tide Merger Sub III and BCC EnVen Investments, L.P., pursuant to which EnVen became a wholly owned subsidiary of the Company.
This Current Report on Form 8-K/A (this “Amendment”) amends and supplements the Original Form 8-K to provide the historical and pro forma financial statements described in Item 9.01 below. No other modifications to the Original Form 8-K are being made by this Amendment. This Amendment should be read in connection with the Original Form 8-K, which provides a more complete description of the Mergers.
| Item 9.01. | Financial Statements and Exhibits. |
| (a) | Financial Statements of Businesses Acquired |
| • | Audited consolidated financial statements of EnVen as of December 31, 2021 and 2020, and for the years ended December 31, 2021, 2020 and 2019 and the related notes to the consolidated financial statements, included in the Company’s proxy statement/consent solicitation statement/prospectus, beginning on page F-2, attached as Exhibit 99.1 hereto; |
| • | Unaudited condensed consolidated financial statements of EnVen as of September 30, 2022 and December 31, 2021 and for the nine months ended September 30, 2022 and 2021, and the related notes to the condensed consolidated financial statements, included in the Company’s proxy statement/consent solicitation statement/prospectus, beginning on page F-53, attached as Exhibit 99.2 hereto. |
| (b) | Pro Forma Financial Information |
The following unaudited pro forma condensed combined financial information of the Company, giving effect to the Mergers, attached as Exhibit 99.3 hereto:
| • | Unaudited Pro Forma Condensed Combined Balance Sheet as of September 30, 2022; |
| • | Unaudited Pro Forma Condensed Combined Statement of Operations for the nine months ended September 30, 2022; |
| • | Unaudited Pro Forma Condensed Combined Statement of Operations for the year ended December 31, 2021; and |
| • | Notes to the Unaudited Pro Forma Condensed Combined Financial Statements. |
(d) Exhibits
2
SIGNATURE
Pursuant to the requirements of the Securities Exchange Act of 1934, the Company has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized.
Date: April 12, 2023
| TALOS ENERGY INC. | ||
| By: | /s/ William S. Moss III | |
| Name: | William S. Moss III | |
| Title: | Executive Vice President, General Counsel and Secretary | |
3
Exhibit 23.1
Consent of Independent Auditors
We consent to the incorporation by reference in Registration Statement Nos. 333-231925, 333-248754, 333-255489 and 333-265589 on Form S-3 and Registration Statement Nos. 333-225058 and 333-256554 on Form S-8 of Talos Energy Inc. of our report dated February 28, 2022, relating to the consolidated financial statements of EnVen Energy Corporation and subsidiaries as of December 31, 2021 and 2020 and for the years ended December 31, 2021, 2020 and 2019 appearing in this Current Report on Form 8-K/A of Talos Energy Inc.
| /s/ Ernst & Young LLP |
Houston, Texas
April 12, 2023
Exhibit 23.2
CONSENT OF INDEPENDENT PETROLEUM ENGINEERS AND GEOLOGISTS
As independent petroleum engineers, we hereby consent to the incorporation by reference into or inclusion in this Current Report on Form 8-K/A (including any amendments or supplements thereto, related appendices, and financial statements) (this “Current Report”) of Talos Energy Inc. (the “Company”) of our firm’s reserves report dated December 16, 2022, prepared for the Company as of December 16, 2022. The December 16 report sets forth the reserves and future revenue, as of December 31, 2021, to the EnVen Energy Ventures, LLC interest in certain oil and gas properties located in federal waters in the Gulf of Mexico. We hereby further consent to all references to our firm or such letters included in or incorporated by reference into this Current Report.
| NETHERLAND, SEWELL & ASSOCIATES, INC. | ||
| By: | /s/ Richard B. Talley, Jr. | |
| Richard B. Talley, Jr., P.E. Chief Executive Officer | ||
Houston, Texas
April 11, 2023
Exhibit 99.1
Report of Independent Auditors
To the Stockholders and the Board of Directors of EnVen Energy Corporation
Opinion
We have audited the consolidated financial statements of EnVen Energy Corporation and subsidiaries (the Company), which comprise the consolidated balance sheets as of December 31, 2021 and 2020, and the related consolidated statements of operations, comprehensive (loss) income, changes in equity and cash flows for the years ended December 31, 2021, 2020 and 2019, and the related notes (collectively referred to as the “financial statements”).
In our opinion, the accompanying financial statements present fairly, in all material respects, the financial position of the Company at December 31, 2021 and 2020, and the results of its operations and its cash flows for the years ended December 31, 2021, 2020 and 2019 in accordance with accounting principles generally accepted in the United States of America.
Basis for Opinion
We conducted our audits in accordance with auditing standards generally accepted in the United States of America (GAAS). Our responsibilities under those standards are further described in the Auditor’s Responsibilities for the Audit of the Financial Statements section of our report. We are required to be independent of the Company and to meet our other ethical responsibilities in accordance with the relevant ethical requirements relating to our audits. We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our audit opinion.
Adoption of Accounting Standards Update (ASU) 2020-06, Debt – Debt with Conversion and Other Options (Subtopic 470-20) and Derivatives and Hedging – Contracts in Entity’s Own Equity (Subtopic 815-40): Accounting for Convertible Instruments and Contracts in an Entity’s Own Equity (ASU 2020-06)
As discussed in Note 1 to the financial statements, in 2021 the Company adopted new accounting guidance, which revised the accounting for convertible debt and convertible preferred stock by removing the requirements to separately present certain conversion features in equity and eliminates the accounting model for beneficial conversion features, as a result of the adoption of the amendments to the Financial Accounting Standards Board (FASB) Accounting Standards Codification resulting from ASU 2020-06. Our opinion is not modified with respect to this matter.
Responsibilities of Management for the Financial Statements
Management is responsible for the preparation and fair presentation of the financial statements in accordance with accounting principles generally accepted in the United States of America, and for the design, implementation, and maintenance of internal control relevant to the preparation and fair presentation of financial statements that are free of material misstatement, whether due to fraud or error.
In preparing the financial statements, management is required to evaluate whether there are conditions or events, considered in the aggregate, that raise substantial doubt about the Company’s ability to continue as a going concern for one year after the date that the financial statements are available to be issued.
F-1
Auditor’s Responsibilities for the Audit of the Financial Statements
Our objectives are to obtain reasonable assurance about whether the financial statements as a whole are free of material misstatement, whether due to fraud or error, and to issue an auditor’s report that includes our opinion. Reasonable assurance is a high level of assurance but is not absolute assurance and therefore is not a guarantee that an audit conducted in accordance with GAAS will always detect a material misstatement when it exists. The risk of not detecting a material misstatement resulting from fraud is higher than for one resulting from error, as fraud may involve collusion, forgery, intentional omissions, misrepresentations, or the override of internal control. Misstatements are considered material if there is a substantial likelihood that, individually or in the aggregate, they would influence the judgment made by a reasonable user based on the financial statements.
In performing an audit in accordance with GAAS, we:
| • | Exercise professional judgment and maintain professional skepticism throughout the audit. |
| • | Identify and assess the risks of material misstatement of the financial statements, whether due to fraud or error, and design and perform audit procedures responsive to those risks. Such procedures include examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. |
| • | Obtain an understanding of internal control relevant to the audit in order to design audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control. Accordingly, no such opinion is expressed. |
| • | Evaluate the appropriateness of accounting policies used and the reasonableness of significant accounting estimates made by management, as well as evaluate the overall presentation of the financial statements. |
| • | Conclude whether, in our judgment, there are conditions or events, considered in the aggregate, that raise substantial doubt about the Company’s ability to continue as a going concern for a reasonable period of time. |
We are required to communicate with those charged with governance regarding, among other matters, the planned scope and timing of the audit, significant audit findings, and certain internal control-related matters that we identified during the audit.
/s/ Ernst & Young LLP
Houston, Texas
February 28, 2022
F-2
ENVEN ENERGY CORPORATION AND SUBSIDIARIES
(In thousands, except share amounts)
| December 31, 2021 | December 31, 2020 | |||||||
| Assets: |
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| Current assets: |
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| Cash and cash equivalents |
$ | 88,930 | $ | 56,009 | ||||
| Accounts receivable: |
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| Oil, natural gas, and NGL revenue |
56,323 | 42,226 | ||||||
| Joint interest and other |
11,961 | 10,939 | ||||||
| Income tax receivable |
— | 5,612 | ||||||
| Prepaid expenses and other current assets |
11,426 | 15,452 | ||||||
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| Total current assets |
168,640 | 130,238 | ||||||
| Property and equipment: |
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| Oil and natural gas properties, full cost method, including $94,462 and $89,394 of unevaluated properties not being amortized as of December 31, 2021 and 2020, respectively |
1,832,679 | 1,718,345 | ||||||
| Other property and equipment |
8,545 | 8,414 | ||||||
| Less: accumulated depreciation, depletion, and amortization |
(1,074,368 | ) | (917,717 | ) | ||||
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| Property and equipment, net |
766,856 | 809,042 | ||||||
| Right-of-use assets |
21,662 | 23,987 | ||||||
| Restricted cash |
100,695 | 89,479 | ||||||
| Notes receivable, net |
65,089 | 62,512 | ||||||
| Other well equipment inventory |
11,408 | 5,738 | ||||||
| Income tax receivable |
— | 9,564 | ||||||
| Other non-current assets |
4,540 | 2,904 | ||||||
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| Total assets |
$ | 1,138,890 | $ | 1,133,464 | ||||
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| Liabilities and Stockholders’ Equity: |
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| Current liabilities: |
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| Accounts payable |
$ | 21,487 | $ | 45,334 | ||||
| Revenue and royalties payable |
17,508 | 9,708 | ||||||
| Accrued liabilities |
58,905 | 49,261 | ||||||
| Lease liabilities |
4,233 | 4,991 | ||||||
| Asset retirement obligations |
24,935 | 12,807 | ||||||
| Notes payable |
4,413 | 8,519 | ||||||
| 11.75% Senior Notes due 2026, net |
27,045 | — | ||||||
| Derivative liabilities |
77,551 | 15,253 | ||||||
| Income tax payable |
2,740 | — | ||||||
| Other current liabilities |
2,199 | — | ||||||
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| Total current liabilities |
241,016 | 145,873 | ||||||
| 11.00% Senior Notes due 2023, at fair value |
— | 262,646 | ||||||
| 11.75% Senior Notes due 2026, net, less current portion |
248,469 | — | ||||||
| Asset retirement obligations, less current portion |
323,351 | 286,867 | ||||||
| Lease liabilities, less current portion |
14,895 | 15,835 | ||||||
| Derivative liabilities |
2,391 | 4,034 | ||||||
| Notes payable, less current portion |
— | 4,413 | ||||||
| Deferred tax liability |
— | 9,648 | ||||||
| Other non-current liabilities |
15,344 | 3,494 | ||||||
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| Total liabilities |
845,466 | 732,810 | ||||||
F-3
| December 31, 2021 | December 31, 2020 | |||||||
| Commitments and contingencies (Note 14) |
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| Stockholders’ equity: |
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| Series A convertible perpetual preferred stock, $0.001 par value, 25,000,000 shares authorized and 14,949,771 and 14,409,417 shares issued and outstanding as of December 31, 2021 and 2020, respectively |
15 | 14 | ||||||
| Class A common stock, $0.001 par value, 200,000,000 shares authorized and 20,840,432 and 17,329,667 shares issued and outstanding as of December 31, 2021 and 2020, respectively |
21 | 17 | ||||||
| Class B common stock, $0.001 par value, 50,000,000 shares authorized and 0 and 3,333,333 shares issued and outstanding as of December 31, 2021 and 2020, respectively |
— | 3 | ||||||
| Additional paid-in capital |
394,474 | 382,819 | ||||||
| Accumulated other comprehensive income |
— | 23,011 | ||||||
| Accumulated deficit |
(101,086 | ) | (43,412 | ) | ||||
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| Total stockholders’ equity |
293,424 | 362,452 | ||||||
| Non-controlling interest |
— | 38,202 | ||||||
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| Total equity |
293,424 | 400,654 | ||||||
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| Total liabilities and equity |
$ | 1,138,890 | $ | 1,133,464 | ||||
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The accompanying notes are an integral part of these consolidated financial statements.
F-4
ENVEN ENERGY CORPORATION AND SUBSIDIARIES
Consolidated Statements of Operations
(In thousands)
| Year Ended December 31, | ||||||||||||
| 2021 | 2020 | 2019 | ||||||||||
| Revenues: |
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| Oil, natural gas, and NGL revenue |
$ | 508,901 | $ | 307,976 | $ | 481,454 | ||||||
| Production handling and other income |
21,390 | 21,655 | 19,080 | |||||||||
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| Total revenues |
530,291 | 329,631 | 500,534 | |||||||||
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| Operating expenses: |
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| Lease operating expenses |
79,789 | 77,249 | 84,829 | |||||||||
| Workover, repair, and maintenance expenses |
23,027 | 17,762 | 18,680 | |||||||||
| Transportation, gathering, and processing costs |
7,261 | 5,412 | 6,262 | |||||||||
| Depreciation, depletion, and amortization |
156,745 | 171,540 | 180,414 | |||||||||
| Accretion of asset retirement obligations |
27,541 | 28,996 | 37,881 | |||||||||
| General and administrative expenses |
75,601 | 43,830 | 57,852 | |||||||||
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| Total operating expenses |
369,964 | 344,789 | 385,918 | |||||||||
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| Operating income (loss) |
160,327 | (15,158 | ) | 114,616 | ||||||||
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| Other (expenses) income: |
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| (Loss) gain on derivatives, net |
(171,917 | ) | 22,716 | (42,855 | ) | |||||||
| Interest expense |
(47,165 | ) | (47,628 | ) | (51,533 | ) | ||||||
| (Loss) gain on extinguishment of long-term debt |
(11,419 | ) | 8,167 | — | ||||||||
| Gain (loss) on fair value of 11.00% Senior Notes due 2023 |
16,589 | (3,242 | ) | (9,169 | ) | |||||||
| Interest income and other |
2,790 | 5,914 | 6,392 | |||||||||
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| Total other expenses |
(211,122 | ) | (14,073 | ) | (97,165 | ) | ||||||
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| (Loss) income before income taxes |
(50,795 | ) | (29,231 | ) | 17,451 | |||||||
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| Income tax expense (benefit) |
11,307 | (18,334 | ) | (485 | ) | |||||||
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| Net (loss) income |
(62,102 | ) | (10,897 | ) | 17,936 | |||||||
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| Net (loss) income attributable to non-controlling interest |
(4,744 | ) | (2,720 | ) | 1,778 | |||||||
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| Net (loss) income attributable to EnVen Energy Corporation |
(57,358 | ) | (8,177 | ) | 16,158 | |||||||
| Series A preferred stock dividends |
(28,583 | ) | (23,709 | ) | (30,670 | ) | ||||||
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| Net loss attributable to EnVen Energy Corporation Class A common stockholders |
$ | (85,941 | ) | $ | (31,886 | ) | $ | (14,512 | ) | |||
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The accompanying notes are an integral part of these consolidated financial statements.
F-5
ENVEN ENERGY CORPORATION AND SUBSIDIARIES
Consolidated Statements of Comprehensive (Loss) Income
(In thousands)
| Year Ended December 31, | ||||||||||||
| 2021 | 2020 | 2019 | ||||||||||
| Net (loss) income |
$ | (62,102 | ) | $ | (10,897 | ) | $ | 17,936 | ||||
| Other comprehensive (loss) income, net: |
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| Credit risk adjustment on 11.00% Senior Notes due 2023 before reclassification, net of deferred income tax (benefit) expense of $(2.2) million, $4.5 million and $0 million for the years ended December 31, 2021, 2020 and 2019, respectively |
(23,571 | ) | 18,286 | 39,957 | ||||||||
| Amounts reclassified from accumulated other comprehensive (loss) income, net of deferred income tax expense of $0 million, $2.3 million and $0 million for the years ended December 31, 2021, 2020 and 2019, respectively |
(5,035 | ) | (8,716 | ) | — | |||||||
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| Total comprehensive (loss) income, net |
(90,708 | ) | (1,327 | ) | 57,893 | |||||||
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| Less: comprehensive (loss) income attributable to non-controlling interest |
(10,339 | ) | (1,256 | ) | 5,906 | |||||||
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| Comprehensive (loss) income attributable to EnVen Energy Corporation |
$ | (80,369 | ) | $ | (71 | ) | $ | 51,987 | ||||
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The accompanying notes are an integral part of these consolidated financial statements.
F-6
ENVEN ENERGY CORPORATION AND SUBSIDIARIES
Consolidated Statement of Changes in Equity
(In thousands, except share amounts)
| Series A preferred | Class A common stock | Class B common stock | ||||||||||||||||||||||||||||||||||||||||||||||
| Shares | Amount | Shares | Amount | Shares | Amount | Additional paid-in capital |
Accumulated other comprehensive income |
Accumulated deficit |
Total stockholders’ equity |
Non- controlling interest |
Total equity |
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| January 1, 2019 balance |
10,762,683 | $ | 11 | 16,307,443 | $ | 16 | 3,333,333 | $ | 3 | $ | 320,411 | $ | — | $ | (17,375 | ) | $ | 303,066 | $ | 39,805 | $ | 342,871 | ||||||||||||||||||||||||||
| Issuance of Class A common stock related to stock-based compensation |
— | — | 1,003,723 | 1 | — | — | (1 | ) | — | — | — | — | — | |||||||||||||||||||||||||||||||||||
| Tax payments related to stock-based compensation |
— | — | (399,584 | ) | — | — | — | (12,386 | ) | — | — | (12,386 | ) | — | (12,386 | ) | ||||||||||||||||||||||||||||||||
| Stock-based compensation |
— | — | — | — | — | — | 15,409 | — | — | 15,409 | — | 15,409 | ||||||||||||||||||||||||||||||||||||
| Series A preferred stock dividends |
1,707,507 | 1 | — | — | — | — | 20,489 | — | (20,499 | ) | — | — | — | |||||||||||||||||||||||||||||||||||
| Series A preferred stock dividends beneficial conversion feature |
— | — | — | — | — | — | 10,180 | — | (10,180 | ) | — | — | — | |||||||||||||||||||||||||||||||||||
| Change in ownership due to Series A preferred stock dividends |
— | — | — | — | — | — | 2,869 | — | — | 2,869 | (2,869 | ) | — | |||||||||||||||||||||||||||||||||||
| Cumulative effect of ASU 2016-01 accounting change |
— | — | — | — | — | — | — | (20,924 | ) | 20,924 | — | — | — | |||||||||||||||||||||||||||||||||||
| Other comprehensive income |
— | — | — | — | — | — | — | 35,829 | — | 35,829 | 4,128 | 39,957 | ||||||||||||||||||||||||||||||||||||
| Net income |
— | — | — | — | — | — | — | — | 16,158 | 16,158 | 1,778 | 17,936 | ||||||||||||||||||||||||||||||||||||
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| December 31, 2019 balance | 12,470,190 | $ | 12 | 16,911,582 | $ | 17 | 3,333,333 | $ | 3 | $356,971 | $ | 14,905 | $(10,963) | $360,945 | $42,842 | $403,787 | ||||||||||||||||||||||||||||||||
| Issuance of Class A common stock related to stock-based compensation |
— | — | 663,538 | — | — | — | — | — | — | — | — | — | ||||||||||||||||||||||||||||||||||||
| Tax payments related to stock-based compensation |
— | — | (245,453 | ) | — | — | — | (4,911 | ) | — | — | (4,911 | ) | — | (4,911 | ) | ||||||||||||||||||||||||||||||||
| Stock-based compensation |
— | — | — | — | — | — | 4,879 | — | — | 4,879 | — | 4,879 | ||||||||||||||||||||||||||||||||||||
| Series A preferred stock dividends |
1,975,620 | 2 | — | — | — | — | 23,707 | — | (23,709 | ) | — | — | — | |||||||||||||||||||||||||||||||||||
| Repurchase of Series A preferred stock |
(36,393 | ) | — | — | — | — | — | (450 | ) | — | — | (450 | ) | — | (450 | ) | ||||||||||||||||||||||||||||||||
| Change in ownership due to Series A preferred stock dividends, net of tax |
— | — | — | — | — | — | 2,623 | — | — | 2,623 | (3,320 | ) | (697 | ) | ||||||||||||||||||||||||||||||||||
| Cumulative effect of ASU 2016-13 accounting change |
— | — | — | — | — | — | — | — | (563 | ) | (563 | ) | (64 | ) | (627 | ) | ||||||||||||||||||||||||||||||||
| Other comprehensive income, net of tax |
— | — | — | — | — | — | — | 8,106 | — | 8,106 | 1,464 | 9,570 | ||||||||||||||||||||||||||||||||||||
| Net loss |
— | — | — | — | — | — | — | — | (8,177 | ) | (8,177 | ) | (2,720 | ) | (10,897 | ) | ||||||||||||||||||||||||||||||||
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| December 31, 2020 balance | 14,409,417 | $ | 14 | 17,329,667 | $ | 17 | 3,333,333 | $ | 3 | $382,819 | $ | 23,011 | $(43,412) | $362,452 | $38,202 | $400,654 | ||||||||||||||||||||||||||||||||
| Issuance of Class A common stock related to stock-based compensation |
— | — | 450,469 | 1 | — | — | (1 | ) | — | — | — | — | — | |||||||||||||||||||||||||||||||||||
| Repurchase of Class A common stock |
— | — | (131,405 | ) | — | — | — | (1,950 | ) | — | — | (1,950 | ) | — | (1,950 | ) | ||||||||||||||||||||||||||||||||
| Tax payments related to stock-based compensation |
— | — | (141,632 | ) | — | — | — | (1,213 | ) | — | — | (1,213 | ) | — | (1,213 | ) | ||||||||||||||||||||||||||||||||
| Stock-based compensation |
— | — | — | — | — | — | 11,190 | — | — | 11,190 | — | 11,190 | ||||||||||||||||||||||||||||||||||||
| Series A preferred stock dividends |
540,354 | 1 | — | — | — | — | 6,483 | — | (28,583 | ) | (22,099 | ) | — | (22,099 | ) | |||||||||||||||||||||||||||||||||
| Change in ownership due to Series A preferred stock dividends |
— | — | — | — | — | — | 828 | — | — | 828 | (828 | ) | — | |||||||||||||||||||||||||||||||||||
| Conversion of Class B common stock and settlement of the Tax Receivable Agreement, inclusive of tax impact |
— | — | 3,333,333 | 3 | (3,333,333 | ) | (3 | ) | 24,585 | — | — | 24,585 | (27,035 | ) | (2,450 | ) | ||||||||||||||||||||||||||||||||
| Cumulative effect of ASU 2020-06 accounting change |
— | — | — | — | — | — | (28,267 | ) | — | 28,267 | — | — | — | |||||||||||||||||||||||||||||||||||
| Other comprehensive loss, net of tax |
— | — | — | — | — | — | — | (23,011 | ) | — | (23,011 | ) | (5,595 | ) | (28,606 | ) | ||||||||||||||||||||||||||||||||
| Net loss |
— | — | — | — | — | — | — | — | (57,358 | ) | (57,358 | ) | (4,744 | ) | (62,102 | ) | ||||||||||||||||||||||||||||||||
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| December 31, 2021 balance | 14,949,771 | $ | 15 | 20,840,432 | $ | 21 | $ | — | $ | — | $394,474 | $ | — | $(101,086) | $293,424 | $ | — | $293,424 | ||||||||||||||||||||||||||||||
The accompanying notes are an integral part of these consolidated financial statements.
F-7
ENVEN ENERGY CORPORATION AND SUBSIDIARIES
Consolidated Statements of Cash Flows
(In thousands)
| Year Ended December 31, | ||||||||||||
| 2021 | 2020 | 2019 | ||||||||||
| Cash flows from operating activities: |
||||||||||||
| Net (loss) income |
$ | (62,102 | ) | $ | (10,897 | ) | $ | 17,936 | ||||
| Adjustments to reconcile net (loss) income to net cash provided by operating activities: |
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| Depreciation, depletion, and amortization |
156,745 | 171,540 | 180,414 | |||||||||
| Accretion of asset retirement obligations |
27,541 | 28,996 | 37,881 | |||||||||
| Stock-based compensation |
11,190 | 4,879 | 15,409 | |||||||||
| Excess tax (deficit) benefit from stock-based compensation |
(424 | ) | 606 | 3,577 | ||||||||
| Amortization and expensing of debt issuance and deferred financing costs |
3,429 | 1,225 | 1,490 | |||||||||
| (Loss) gain on extinguishment of long-term debt |
11,419 | (8,167 | ) | — | ||||||||
| (Gain) loss on fair value of 11.00% Senior Notes due 2023 |
(16,589 | ) | 3,242 | 9,169 | ||||||||
| Loss (gain) on derivatives, net |
171,917 | (22,716 | ) | 42,855 | ||||||||
| Cash (paid) received for derivative settlements, net |
(111,262 | ) | 38,727 | (7,323 | ) | |||||||
| Deferred income taxes |
(5,098 | ) | 8,951 | — | ||||||||
| Other non-cash items |
(1,891 | ) | (2,331 | ) | (3,023 | ) | ||||||
| Changes in operating assets and liabilities: |
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| Accounts receivable |
(14,655 | ) | 31,959 | (6,010 | ) | |||||||
| Income tax |
20,495 | (17,937 | ) | (9,224 | ) | |||||||
| Prepaid expenses and other current assets |
4,026 | (6,741 | ) | 18,985 | ||||||||
| Other well equipment inventory |
(5,670 | ) | (1,963 | ) | — | |||||||
| Accounts payable |
(23,847 | ) | (8 | ) | (7,850 | ) | ||||||
| Revenue and royalties payable |
7,800 | (5,739 | ) | 6,123 | ||||||||
| Accrued liabilities |
16,163 | (1,275 | ) | 1,973 | ||||||||
| Settlement of asset retirement obligations |
(10,781 | ) | (5,912 | ) | (19,172 | ) | ||||||
| Other liabilities |
15,712 | 2,785 | (284 | ) | ||||||||
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| Net cash provided by operating activities |
$ | 194,118 | $ | 209,224 | $ | 282,926 | ||||||
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| Cash flows from investing activities: |
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| Purchases of property, equipment, and other capital expenditures |
$ | (92,996 | ) | $ | (197,414 | ) | $ | (264,534 | ) | |||
| Acquisitions of unevaluated oil and natural gas properties |
(6,546 | ) | (4,717 | ) | (9,235 | ) | ||||||
| Net cash received for the acquisition of proved oil and natural gas properties |
8,169 | — | — | |||||||||
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| Net cash used in investing activities |
$ | (91,373 | ) | $ | (202,131 | ) | $ | (273,769 | ) | |||
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| Cash flows from financing activities: |
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| Repayment of long-term debt |
$ | (291,816 | ) | $ | (40,016 | ) | $ | — | ||||
| Premium paid for the early termination of long-term debt |
(11,419 | ) | — | — | ||||||||
| Proceeds from the issuance of long-term debt |
295,700 | — | — | |||||||||
| Payment of debt issue and deferred financing costs |
(10,292 | ) | — | (156 | ) | |||||||
| Payments on notes payable |
(8,519 | ) | (9,764 | ) | (5,323 | ) | ||||||
| Payment of Series A preferred stock dividends |
(22,099 | ) | — | — | ||||||||
| Payment for the repurchase of Series A preferred stock |
— | (450 | ) | — | ||||||||
| Payment for the repurchase of Class A common stock |
(1,950 | ) | — | — | ||||||||
| Tax payments related to stock-based compensation |
(1,213 | ) | (4,911 | ) | (12,386 | ) | ||||||
| Payment for the settlement of the tax receivable agreement |
(7,000 | ) | — | — | ||||||||
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| Net cash used in financing activities |
$ | (58,608 | ) | $ | (55,141 | ) | $ | (17,865 | ) | |||
| Net increase (decrease) in cash, cash equivalents, and restricted cash |
$ | 44,137 | $ | (48,048 | ) | $ | (8,708 | ) | ||||
| Cash, cash equivalents, and restricted cash - beginning of period |
$ | 145,488 | $ | 193,536 | $ | 202,244 | ||||||
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| Cash, cash equivalents, and restricted cash - end of period |
$ | 189,625 | $ | 145,488 | $ | 193,536 | ||||||
The accompanying notes are an integral part of these consolidated financial statements.
Refer to Note 17—Supplemental Cash Flow Information for supplemental cash flow disclosures.
F-8
ENVEN ENERGY CORPORATION AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Note 1—Organization and Basis of Presentation
EnVen Energy Corporation (individually or together with its subsidiaries, the “Company”) is an independent oil and natural gas company engaged in the development, exploitation, exploration, and acquisition of primarily crude oil properties in the deepwater region of the United States (“U.S.”) Gulf of Mexico. The Company focuses on developing operated, deepwater assets that it believes have untapped, lower-risk drill bit opportunities and will provide strong cash flow and significant production potential. This strategy allows the Company to benefit from the favorable geologic and economic characteristics of the deepwater U.S. Gulf of Mexico fields.
Organization
On October 30, 2015, Energy Ventures GoM Holdings, LLC entered into an agreement to sell 13,732,925 units in a private offering, at a price of $10.00 per unit, to selected institutional investors (the “2015 Equity Offering”). Prior to the closing of the 2015 Equity Offering, the then existing members of Energy Ventures GoM Holdings, LLC contributed 100% of their limited liability company units (the “limited liability interest”) in Energy Ventures GoM LLC (“EnVen GoM”) to a newly formed limited liability company, EnVen Equity Holdings, LLC (“EnVen Equity Holdings”). Therefore, the members of EnVen Equity Holdings indirectly owned 100% of the limited liability interest of EnVen GoM. Following this transaction and also prior to the closing of the 2015 Equity Offering, Energy Ventures GoM Holdings, LLC was converted from a limited liability company to a Delaware corporation and renamed EnVen Energy Corporation. Further, at the time of the 2015 Equity Offering, the Company also entered into a Tax Receivable Agreement (“TRA”) with EnVen Equity Holdings. Refer to Note 10—Related Party Transactions for a further discussion of the Redemption Rights and the TRA.
As specified in the EnVen GoM Second Amended and Restated Limited Liability Company Agreement (the “EnVen GoM LLC Agreement”), the members of EnVen Equity Holdings could have, at any time, required EnVen GoM to repurchase all or any number of its limited liability interest of EnVen GoM for consideration equal to one share of the Company’s $0.001 par value per share (“Class A Common Stock”) per unit of the limited liability interest of EnVen GoM. However, with approval from the Company’s board of directors (the “Board”), the Company could satisfy the obligation by exercising an option to purchase the limited liability interest of EnVen GoM for a cash price equal to the fair value of one share of its Class A Common Stock or by issuing newly issued shares of its Class A Common Stock (collectively, the “Redemption Rights”).
In April 2021, EnVen Equity Holdings exercised its Redemption Rights with respect to all of its limited liability interests of EnVen GoM. Pursuant to the terms of the EnVen GoM LLC Agreement, the Company then elected to settle the Redemption Rights through a direct exchange of such common units for 3,333,333 newly issued shares of its Class A Common Stock and cancelled the associated 3,333,333 shares of its $0.001 par value Class B common stock (“Class B Common Stock”) (collectively, the “Class B Common Stock Conversion”). Concurrent with the Class B Common Stock Conversion, the Company and EnVen Equity Holdings agreed to terminate the TRA for a $7.0 million cash payment to EnVen Equity Holdings (the “TRA Settlement”). As a result of these transactions, EnVen Equity Holdings no longer holds any limited liability interests of EnVen GoM and no longer holds any shares of Company’s Class B Common Stock. The Company accounted for these transactions as an adjustment to its Stockholders’ equity during the second quarter of 2021.
Basis of Presentation and Consolidation
The accompanying consolidated financial statements as of and for the years ended December 31, 2021, 2020 and 2019 are prepared in accordance with accounting principles generally accepted in the U.S. (“GAAP”) and include the accounts for the Company and entities in which it has control. All significant intercompany balances and transactions have been eliminated.
F-9
Prior to the Class B Common Stock Conversion, discussed above, the Company owned the majority interest (approximately 90.5% and 89.8% as of December 31, 2020 and 2019, respectively) of and controlled its subsidiary, EnVen GoM; therefore, the majority interest in EnVen GoM was reflected as a consolidated subsidiary in the accompanying consolidated financial statements as of December 31, 2020 and 2019. The remaining ownership interest (approximately 9.5% and 10.2% as of December 31, 2020 and 2019, respectively) not held by the Company (the “Non-controlling interest”) was included in the accompanying consolidated financial statements as Non-controlling interest. Following the consummation of the Class B Common Stock Conversion in April 2021, the Company owns and controls 100% of its subsidiary EnVen GoM; therefore, as of April 30, 2021, it no longer reports a Non-controlling interest on its consolidated balance sheet. Refer to Note 9 - Stockholders’ Equity for a further discussion of the Non-controlling interest prior to the Class B Common Stock Conversion.
Use of Estimates
The preparation of the financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues, and expenses and the disclosure of contingent assets and liabilities as of the date of the financial statements, the reported amounts of revenues and expenses during the reporting periods and the reported amounts of proved oil and natural gas reserves. Management believes its estimates and assumptions to be reasonable under the circumstances. Certain estimates and assumptions are inherently unpredictable and actual results could differ from those estimates.
Recently Adopted Accounting Standards
Current Expected Credit Losses—ASU No. 2016-13
In June 2016, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2016-13, Financial Instruments—Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments (“ASU 2016-13”), which changes how entities account for credit losses for most financial assets and certain other instruments which are not measured at fair value through net income and will replace the currently required incurred loss approach with an expected loss model for instruments measured at amortized cost. For public and non-public entities, ASU 2016-13, including all of its amendments, is effective for interim and annual periods beginning after December 15, 2019 and 2020, respectively, using a modified retrospective approach and early adoption is permitted.
The Company elected to early adopt ASU 2016-13, effective January 1, 2020, resulting in a cumulative effect adjustment of $0.6 million to its Accumulated deficit balance and $0.1 million to its Non-controlling interest balance related to the estimated credit losses for its notes receivable for certain acquired P&A obligations (the “P&A Notes Receivable”). Upon entering into the P&A Notes Receivable, the Company recorded the P&A Notes Receivable at their present value using estimated imputed interest rates and the related carrying values of the notes receivable are accreted, with the accretion recognized to Interest income and other on the accompanying consolidated statements of operations based on the expected timing of the completion of the P&A obligations. The Company estimates the current expected credit losses related to its P&A Notes Receivable using the probability of default method based on the long-term credit ratings of the counterparties of the notes, which are currently considered “investment grade.” Additionally, the Company has elected to estimate the credit losses on the various components, the originally discounted principal and accreted interest, included in the amortized basis of the P&A Notes Receivable on a combined basis. The Company records the change in the current estimated credit losses related to its P&A Notes Receivable into Interest income and other on the accompanying consolidated statements of operations and presents the P&A Note Receivable net of the related cumulative estimated credit losses on the accompanying consolidated balance sheets.
The Company estimates the current expected credit losses related to its short-term receivables using an aging method based on historical loss data that, if warranted, is adjusted for asset-specific considerations and current
F-10
economic conditions. Upon adoption, the Company analyzed the aging of its short-term oil, natural gas, and NGL revenue, production handling agreements revenue, and joint interest and other accounts receivables and its derivative settlement receivables and determined that it did not need to record an adjustment for credit loss related to those short-term receivables because the credit losses have historically been immaterial. The Company will continue to review the aging of these short-term receivables on a quarterly basis and if necessary, could record an allowance in future periods.
Overall, the adoption of ASU 2016-13 did not have a material impact on the Company’s consolidated financial statements.
Income Taxes—ASU No. 2019-12
In December 2019, the FASB issued ASU No. 2019-12, Income Taxes (Topic 740): Simplifying the Accounting for Income Taxes (“ASU 2019-12”), which is intended to simplify various aspects related to accounting for income taxes by removing certain exceptions to the general principles in Topic 740 and clarifying and amending existing guidance to promote more consistent application. For public entities, ASU 2019-12 is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2020. For non-public entities, ASU 2019-12 is effective for fiscal years beginning after December 15, 2022 and interim periods within fiscal years beginning after December 15, 2022. The Company has elected to early adopt ASU 2019-12, effective January 1, 2020.
The amendments in ASU 2019-12 eliminate several legacy exceptions the Company was subject to in Topic 740. Specifically, the standard eliminates the legacy exception relating to the allocation of income tax expense or benefit for the year to continuing operations, discontinued operations, other comprehensive (loss) income, and other charges or credits recorded directly to shareholders’ equity. ASU 2019-12 requires that the new intraperiod tax allocation guidance be applied prospectively in the period of adoption. The adoption of this standard did not impact the Company’s prior year financial statements or its income tax provision for the years ended December 31, 2021, 2020, or 2019.
Convertible Debt and Preferred Stock—ASU No. 2020-06
In August 2020, the FASB issued ASU No. 2020-06, Debt – Debt with Conversion and Other Options (Subtopic 470-20) and Derivatives and Hedging – Contracts in Entity’s Own Equity (Subtopic 815-40): Accounting for Convertible Instruments and Contracts in an Entity’s Own Equity (“ASU 2020- 06”), which simplifies the accounting for convertible debt and convertible preferred stock by removing the requirements to separately present certain conversion features in equity and eliminates the accounting model for beneficial conversion features. In addition, the amendments in the ASU simplify the guidance in Accounting Standards Codification (“ASC”) Subtopic 815-40, Derivatives and Hedging: Contracts in Entity’s Own Equity, by removing certain criteria that must be satisfied in order to classify a contract as equity.
For public entities, ASU 2020-06 is effective for fiscal years beginning after December 15, 2021, including interim periods within those fiscal years. For non-public entities, ASU 2020-06 is effective for fiscal years beginning after December 15, 2023, including interim periods within those fiscal years. Early adoption is permitted for fiscal years beginning after December 15, 2020, including interim periods within those fiscal years. An entity can only adopt the guidance as of the beginning of its annual fiscal year and can do so through either a modified retrospective method of transition or a fully retrospective method of transition.
The Company elected to early adopt ASU 2020-06, effective January 1, 2021, using the modified retrospective method of transition, eliminating the accounting model for the beneficial conversion feature related to the paid-in-kind dividends of its Series A convertible perpetual preferred stock (“Series A Preferred Stock”), which is classified in the stockholders’ equity section of the accompanying consolidated balance sheets as the shares are not mandatorily redeemable nor do they contain an unconditional conversion obligation. The holders of the
F-11
Series A Preferred Stock are entitled to receive quarterly dividends of $0.45 per Series A Preferred Stock share, at the election of the Company’s Board, in cash or in shares of the Series A Preferred Stock (“PIK Shares”). Prior to the adoption of this ASU, at the end of each reporting period or when PIK Share dividends were declared, the Company would evaluate if there was a beneficial conversion feature related to the PIK Share dividends of its Series A Preferred Stock by comparing the fair value of its Class A Common Stock to the original issue price of $12.00 per share. If the fair value of the Company’s Class A Common Stock was above the original issue price of $12.00 per share, it would record the difference as a beneficial conversion feature associated with its PIK Share dividends and reflect that amount as part of the Series A preferred stock dividends line item on the accompanying consolidated statements of operations. Until the adoption of ASU 2020-06, the Company evaluated if a beneficial conversion existed on a quarterly basis; however, it has not recognized a beneficial conversion feature related to the PIK Share dividends of its Series A Preferred Stock since 2019. Refer to Note 9 - Stockholders’ Equity for a full description of the Company’s Series A Preferred Stock.
To reflect the adoption of ASU 2020-06, the Company has recorded a cumulative effect adjustment of $28.3 million to its Additional paid-in capital and Accumulated deficit balances as of January 1, 2021 to reverse the beneficial conversion feature associated with its Series A Preferred Stock PIK Share dividends outstanding as of January 1, 2021. Additionally, with the adoption of the ASU, the Company is no longer required to include the disclosures required for the beneficial conversion feature in the notes of its consolidated financial statements.
Note 2—Summary of Significant Accounting Policies
Cash and Cash Equivalents
The Company considers all highly liquid investments with an initial maturity of three months or less to be cash and cash equivalents.
Restricted Cash
Restricted cash primarily consists of amounts held in escrow for future P&A obligations in connection with past acquisitions. Pursuant to the purchase agreements, the Company was required to deposit funds in to escrow accounts to use for future P&A obligation costs assumed in the acquisitions. These escrow accounts are fully funded as of October 2021. Refer to Note 14—Commitments and Contingencies for a further discussion of those requirements.
Additionally, prior to the amendment of the first lien senior secured revolving credit facility (the “Revolving Credit Facility”) agreement in April 2021, the Company was required to provide the full outstanding letter of credit amount of $3.6 million in cash to the banks to fulfill a cash security requirement to collateralize its letters of credit, which was recorded as Restricted cash on the consolidated balance sheet as of December 31, 2020. The cash security requirement was removed as part of the Revolving Credit Facility agreement amendment, therefore, the banks have released the previously provided cash required to collateralize its letters of credit back to the Company. Refer to Note 8—Long-term Debt for a further discussion of the Company’s Revolving Credit Facility.
Accounts Receivable
Oil, natural gas, and NGL revenue receivable consists of uncollateralized accrued oil, natural gas, and NGL revenue due under normal trade terms, generally requiring payment within 30 days of production. Joint interest and other receivables consist of uncollateralized joint interest owner obligations due within 30 days of the invoice date and, at times, receivables from the counterparties to the Company’s derivative contracts. In the Company’s capacity as operator, it incurs drilling, operating, and P&A costs that are billed to its partners based on their respective working interests. For receivables from joint interest owners, the Company typically has the ability to withhold revenue distributions to recover any unpaid joint operations billings that are past due.
F-12
The Company estimates the current expected credit losses related to its short-term receivables using an aging method based on historical loss data that, if warranted, is adjusted for asset-specific considerations and current economic conditions. Upon the adoption of ASU 2016-13 effective January 1, 2020, the Company analyzed the aging of its short-term oil, natural gas, and NGL revenue, production handling agreements revenue, and joint interest and other accounts receivables and its derivative settlement receivables and determined that it did not need to record an adjustment for credit loss related to those short-term receivables because the credit losses have historically been immaterial. Further, the Company has determined that no allowance is necessary as of December 31, 2021, 2020 and 2019. The Company will continue to review the aging of these short-term receivables on a quarterly basis and if necessary, could record an allowance in future periods.
Oil and Natural Gas Properties
The Company follows the full cost method of accounting for oil and natural gas activities and capitalizes all the costs associated with the acquisition, exploration, and development of oil and natural gas properties. Capitalized costs include lease acquisitions, geological and geophysical work, delay rentals, costs of drilling, completing, and equipping oil and natural gas wells, whether successful or unsuccessful, and other directly related costs.
The capitalized costs of proved oil and natural gas properties, net of accumulated DD&A plus estimated future development costs related to proved oil and natural gas reserves and estimated future P&A costs are amortized on a unit of production method over the estimated productive life of the proved reserves, which is reflected as DD&A on the accompanying consolidated statements of operations. DD&A related to oil and natural gas properties for the years ended December 31, 2021, 2020 and 2019 was $155.5 million, $170.3 million and $178.5 million, respectively.
Costs related to nonproducing leasehold, geological and geophysical costs associated with unproved acreage, and exploration drilling costs represent investments in unproved properties. Additionally, for any significant capital projects with a development period exceeding six months, the Company will capitalize a portion of its interest expense while the activities are in progress to bring the unproved assets to their intended use. The capitalized interest is added to the cost of the underlying property and treated in the same manner as the underlying asset. All of these costs are excluded from the depreciable base until management determines the existence of proved oil and natural gas reserves on the respective property or the costs are impaired. At least quarterly, the Company reviews its investments in unproved properties individually to determine if the costs should be reclassified and included as a part of the depreciable base. Refer to Note 6—Property and Equipment, net for further information related to the Company’s oil and natural gas properties.
The following table presents the costs of unproved properties excluded from the Company’s depreciable base as of December 31, 2021 and the periods such costs were incurred:
| Year Ended December 31, | ||||||||||||||||||||
| Total | 2021 | 2020 | 2019 | 2018 & Prior | ||||||||||||||||
| (In thousands) | ||||||||||||||||||||
| Acquisition costs |
$ | 37,022 | $ | 667 | $ | 10,596 | $ | 9,456 | $ | 16,303 | ||||||||||
| Exploration costs (1) |
57,440 | 4,401 | 17,046 | 30,186 | 5,807 | |||||||||||||||
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| Total costs |
$ | 94,462 | $ | 5,068 | $ | 27,642 | $ | 39,642 | $ | 22,110 | ||||||||||
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| (1) | The Company’s exploration costs incurred for the years ended December 31, 2021 and 2020, includes capitalized interest of $2.3 million and $1.3 million, respectively, related to certain significant long-term exploratory projects. |
Under the full cost method of accounting, the Company performs the full cost ceiling test at the end of each reporting period. Per the full cost ceiling test, net capitalized costs less deferred income taxes are limited to the
F-13
present value of estimated future net cash flows from proved oil and natural gas reserves computed using the unweighted arithmetic average of the first-day-of-the-month historical price, net of applicable differentials, for each month within the previous 12-month period discounted at 10%, plus the lower of cost or fair market value of unevaluated properties, excluding cash flows related to estimated abandonment costs associated with developed properties (the “ceiling limitation”). If the net capitalized costs exceed the ceiling limitation, the Company would recognize a non-cash impairment expense equal to the excess of the net capitalized costs over the ceiling limitation. The Company did not recognize an impairment of oil and natural gas properties for the years ended December 31, 2021, 2020 and 2019.
Other Property and Equipment
Other property and equipment primarily consists of computer hardware and software, furniture, fixtures, and the Company’s undivided interest in an aircraft, which are depreciated using the straight line method over their estimated useful lives ranging from 2 to 5 years.
Other Well Equipment Inventory
Other well equipment inventory represents the cost of equipment the Company intends to use in its oil and natural gas drilling and development activities, such as drilling pipe, tubulars and certain wellhead equipment. When this inventory is supplied to wells, the cost of the inventory will be capitalized into oil and natural gas properties, and if such property is jointly owned, the proportionate costs will be reimbursed by third-party participants. The Company states its inventory at the lower of cost or net realizable value.
Derivative Instruments
The Company utilizes commodity derivative instruments to reduce its exposure to crude oil and natural gas price volatility for a portion of its estimated production from its proved, developed, producing oil and natural gas properties. The fair values of the Company’s derivative instruments are measured on a recurring basis using a third-party industry-standard pricing model. Refer to Note 5—Fair Value Measurements for a further discussion of the fair value of the Company’s derivative instruments.
The Company has not designated any of its derivative instruments as hedges for accounting purposes; therefore, the aggregate net gains and losses resulting from changes in the fair values of its outstanding derivatives, the settlement of derivative instruments, and any net proceeds or payments related to the early termination of derivative contracts during the period are recognized as net gain or loss on derivatives, as applicable, in the consolidated statements of operations. The Company typically has numerous hedge positions that span several time periods and often result in both fair value derivative asset and liability positions held with that counterparty, therefore, it has elected to net its derivative instrument fair values executed with the same counterparty, pursuant to the International Swaps and Derivatives Association, Inc. (“ISDA”) master agreements, which provide for the net settlement over the term of the contract and in the event of the default or termination of the contract. Refer to Note 4—Derivative Instruments for a discussion of the Company’s outstanding derivative instruments.
Prepaid Expenses and Other Current Assets
The Company’s prepaid expenses and other current assets primarily includes premiums paid to surety companies for its supplemental and performance bonds. These bond premiums are amortized over the life of the surety bonds into Interest expense on the accompanying consolidated statements of operations. As of December 31, 2021 and 2020, the Company’s prepaid balances for its surety bond premiums were $7.7 million and $8.2 million, respectively. Refer to Note 14—Commitments and Contingencies for a further discussion of the Company’s surety bond premiums. Additionally, the Company’s prepaid expenses and other current assets also includes balances related to its commercial insurance packages, which are amortized into LOE over the life of the policy. As of December 31, 2021 and 2020 the Company’s prepaid balances for its commercial insurance packages were $2.2 million and $2.3 million, respectively.
F-14
Notes Receivable, net
The Company holds two notes receivables which consist of commitments from the sellers of oil and natural gas properties, acquired by the Company, related to the costs associated with its performance of the assumed P&A obligations (the “P&A Notes Receivable”). As of December 31, 2021, both of the P&A Notes Receivable have fully accreted to their principal amounts and are presented as such, net of the related cumulative estimated credit losses, on the accompanying consolidated balance sheet. As of December 31, 2020, the P&A Notes Receivable were recorded at their present values using estimated imputed interest rates of 8.0% and 12.0%, net of the related cumulative estimated credit losses, on the accompanying consolidated balance sheet.
Subsequent to the adoption of ASU 2016-13, discussed above, the Company records the change in the current estimated credit losses related to its P&A Notes Receivable into Interest income and other on the accompanying consolidated statements of operations and presents the P&A Note Receivable net of the related cumulative estimated credit losses on the accompanying consolidated balance sheets Refer to Note 14—Commitments and Contingencies for a further discussion of the Company’s outstanding notes receivable.
Notes Payable
The Company has in the past entered into notes payable agreements to purchase certain items or services used in its daily operations. The Company records the fair value of the total principal and interest payments as a note payable utilizing an effective interest rate and amortizes the discount over the term of the agreement. If the agreement requires an upfront consideration payment and installment payments, the Company will record the fair value of the installment payments as a note payable at the effective interest rate stated in the agreement and will amortize the discount over the term of the installment period. If the agreement does not state an effective interest rate, the Company will estimate the imputed rate of interest at the time the note is recognized. Refer to Note 14—Commitments and Contingencies for a discussion of the Company’s outstanding notes payable.
11.00% Senior Notes due 2023
On February 15, 2018, the Company completed the private offering of its $325.0 million aggregate principal amount 11.0% senior secured second lien notes due 2023 (the “2023 Notes”). The 2023 Notes indenture contained certain put and call features that were analyzed at the time of issuance in accordance with ASC Topic 815, Derivatives and Hedging. The Company determined that one of these features was an embedded derivative, which would typically require bifurcation. Due to this embedded derivative feature, the Company elected to account for the 2023 Notes and all of its features using the fair value option; therefore, the 2023 Notes were recorded at their fair value on the consolidated balance sheet as of December 31, 2020. Throughout the fourth quarter of 2020, the Company repurchased $48.2 million principal amount of its 2023 Notes and then in April of 2021, as part of the 2021 Refinancing Transactions described further below, the Company redeemed the remaining $276.8 million principal amount of its outstanding 2023 Notes. Refer to Note 8—Long-term Debt for a discussion of the 2021 Refinancing Transactions.
Prior to the redemption of the 2023 Notes in April 2021, the Company recorded the changes in the fair value of the 2023 Notes in accordance with ASU No. 2016-01, Financial Instruments—Overall (Subtopic 825-10): Recognition and Measurement of Financial Assets and Financial Liabilities (“ASU 2016-01”). Therefore, the change in the fair value of the 2023 Notes attributable to the change in the base market rate was recorded as a component of Gain (loss) on fair value of 11.00% Senior Notes due 2023 on the Company’s consolidated statements of operations and the remainder of the change was attributable to instrument-specific credit risk and was recognized separately as Other comprehensive (loss) income, net on the consolidated statements of comprehensive (loss) income. The Company had elected to use the U.S. Treasury bond rate as its benchmark interest rate to determine the change in the fair value attributable to instrument-specific credit risk, therefore, it compared the change in the fair value of the 2023 Notes to the change in the fair value of the U.S. Treasury bonds based on the interpolated yields of the U.S. Treasury bonds with maturities which coincided with the
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maturity date of the 2023 Notes. The change in the U.S. Treasury bond rate was attributable as the base market rate change and the remainder of the change was attributable to instrument-specific credit risk, which was separately recognized as Other comprehensive (loss) income, net. Refer to Note 8—Long-term Debt for a further discussion of the Company’s 2023 Notes.
Leases
The Company capitalizes its operating leases as right-of-use (“ROU”) assets and lease liabilities on the accompanying consolidated balance sheets and recognizes the fixed minimum lease costs for its operating leases on a straight-line basis over the lease term in accordance with ASC Topic 842, Leases (“ASC 842”). The Company does not recognize leases with initial lease terms less than or equal to 12 months on the balance sheet and only includes those short-term leases as part of its lease-related disclosures. Additionally, the Company does not include any of its variable lease costs in the calculation of its ROU assets and lease liabilities, as none of the variable costs are based on an index or rate. Instead, all of the variable costs are based on the performance of the leased asset or the level of use of other non-lease components due to the election of the practical expedient to not separate the lease and non-lease components when measuring lease payments.
The Company makes certain assumptions and judgments when determining its ROU assets and lease liabilities. When determining whether a contract contains a lease, the Company considers whether there is an identified asset that is physically distinct, whether the supplier has substantive substitution rights, whether the Company has the right to obtain substantially all of the economic benefits from the use of the asset, and whether it has the right to control the asset. Certain of the Company’s leases include one or more options to renew the lease, with renewal terms that can extend the lease term for additional years. When determining if renewals should be included in the lease term to be recognized, the Company utilizes the reasonably certain threshold, therefore, certain of the leases included in the calculation of its ROU assets and lease liabilities include optional renewal periods for which it is not contractually obligated. Additionally, the Company must estimate its incremental borrowing rate when the implicit rate is not stated in the lease agreement and cannot be readily determined. As of December 31, 2021, none of the Company’s active leases contain purchase or termination options that are reasonably certain to be exercised.
The Company has several operating leases for office space and IT Equipment used in its daily operations, for which it records the related lease costs as G&A expenses on the accompanying consolidated statements of operations. Additionally, the Company enters into drilling rig operating contracts with third parties to support its drilling activities. The scope of ASC 842 does not include leases to explore or use minerals, oil, natural gas, and similar non-regenerative resources; therefore, the Company’s oil and natural gas leases are excluded, but the equipment used to explore for natural resources, which includes drilling rigs, marine vessels, and other equipment used in the exploration and development of oil and natural gas assets are included in the scope of ASC 842.
In accordance with the full cost method of accounting for oil and natural gas properties, the Company capitalizes the portion of its lease costs which relate to its drilling rig operating leases as part of its oil and natural gas property balance. In lease agreements where the Company is the designated operator per a joint operations arrangement, any related ROU assets and lease liabilities are calculated using the gross payment amount rather than the net amounts based on its working interest in the related property. However, when the costs are incurred, the Company only recognizes its share of the drilling rig operating lease costs in its consolidated financial statements. Refer to Note 15—Leases for a further discussion of the Company’s leases.
Asset Retirement Obligations
The Company’s oil and natural gas properties include estimates of future expenditures to P&A wells, pipelines, platforms, and other related facilities after the reserves have been depleted. The Company recognizes the present value of the asset retirement obligation costs as a liability when it is incurred and an increase to its capitalized oil
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and natural gas properties. The capitalized asset retirement obligation costs are depleted over the productive lives of the oil and natural gas properties while the asset retirement obligation liability is accreted to the expected settlement value over the productive lives of the oil and natural gas properties. Upon settlement, the difference between the recorded liability amount and the amount of costs incurred is recognized as an adjustment to the capitalized cost of oil and natural gas properties.
The determination of future asset retirement obligations requires estimates of the future costs of removal and restoration, productive lives of the oil and natural gas properties based on reserve estimates, and future inflation rates. Estimated costs consider historical experience, third-party estimates, and government regulatory requirements but do not consider salvage values. These costs could be subject to revisions in subsequent years due to changes in regulatory requirements, the estimated P&A cost, and the estimated timing of the oil and natural gas property retirement. In subsequent periods, if the estimate of the asset retirement obligation liability changes, the Company records an adjustment to both the asset retirement obligation liability and the oil and natural gas property carrying value. Additionally, the Company estimates the credit-risk adjusted discount rate, which is applied to the future inflated P&A costs to determine the discounted present value which is recognized as the initial liability. The determined credit-risk adjusted discount rate is also subsequently applied to accrete the liability. Refer to Note 7—Asset Retirement Obligations for further information related to the Company’s asset retirement obligations.
Series A Preferred Stock
The Company’s Series A Preferred Stock is classified in the stockholders’ equity section of the accompanying consolidated balance sheets as the shares are not mandatorily redeemable nor do they contain an unconditional conversion obligation. The holders of the Series A Preferred Stock are entitled to receive quarterly dividends of $0.45 per Series A Preferred Stock share, at the election of the Company’s Board, in cash or in PIK Shares. Since the Board has the option to pay the dividends in cash or in PIK Shares, the PIK Share dividends are deemed discretionary and are recorded at the declaration date at their stated rate (rather than at fair value) as a reduction to Net (loss) income to determine Net (loss) income attributable to EnVen Energy Corporation Class A common stockholders on the accompanying consolidated statements of operations.
As discussed above in Recently Adopted Accounting Standards, prior to the adoption of ASU 2020-06 on January 1, 2021, at the end of each reporting period or when PIK Share dividends were declared, the Company would evaluate if there was a beneficial conversion feature related to the PIK Share dividends of its Series A Preferred Stock. Although the Company has historically evaluated if a beneficial conversion exists on a quarterly basis, it has not recorded a beneficial conversion feature related to the PIK Share dividends of its Series A Preferred Stock since 2019 due to changes in the fair value of the its Class A Common Stock. Refer to Note 9 - Stockholders’ Equity for a further discussion of the Company’s Series A Preferred Stock.
Commitments and Contingencies
Liabilities for loss contingencies arising from claims, assessments, litigation, fines, penalties, and other sources are recorded when it is probable that a liability has been incurred and the amount can be reasonably estimated. Legal costs incurred in connection with loss contingencies are expensed as incurred. Refer to Note 14—Commitments and Contingencies for a further discussion of the Company’s commitments and contingencies as of December 31, 2021.
Revenue Recognition
The Company recognizes the sales of oil, natural gas, and NGLs at the point that control of the product is transferred to the customer and production handling revenue is recognized over time as the Company performs on the service contract.
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The Company records revenue in the month production is delivered to the purchaser and invoices revenue by calendar month based on volumes at contractually based rates with payment typically required 30 days after the end of the production month. As a result, at the end of each month when the performance obligation is satisfied, the Company is required to estimate the variable consideration using the amount of production delivered to the purchaser and the price that will be received for the sale of the product. Additionally, the Company has made an accounting election to exclude certain qualifying taxes collected from customers and remitted to governmental authorities from its reported revenues and is presenting those amounts as a component of operating expense in the accompanying consolidated statements of operations. The amounts due from purchasers are accrued in oil, natural gas, and NGL revenue accounts receivable on the accompanying consolidated balance sheets. The Company records the differences between its estimates and the actual amounts received for product sales in the month that payment is received from the purchaser. Additionally, the Company has determined that product returns or refunds are very rare and will account for them as they occur, and it generally provides no warranty other than the implicit promise that goods delivered are free of liens and encumbrances and meet the agreed upon specification.
Oil revenue contracts. The majority of the Company’s oil revenue contracts are structured so that the Company delivers oil to the purchaser at a contractually agreed-upon delivery point at which the purchaser takes custody, title, and risk of loss of the product. Generally, under these arrangements, the Company collects a price net of transportation incurred by the purchaser. The Company concluded that the corresponding transportation deductions related to these arrangements are part of the overall transaction price and records those deductions as a reduction to revenue rather than an expense.
However, in certain arrangements, the Company pays a third-party to transport the product to a contractually agreed-upon delivery point at which time the purchaser takes custody, title, and risk of loss of the product and receives a specified index price from the purchaser with no deduction. In this scenario, the Company recognizes revenue when control transfers to the purchaser at the delivery point based on the price received from the purchaser. The third-party transportation costs are recorded as a component of operating expense in the accompanying consolidated statements of operations.
Natural gas and NGLs revenue contracts. Under the Company’s natural gas processing contracts, the Company delivers natural gas to a processing entity at the wellhead or the inlet of the processing entity’s system. In these contracts, the Company may elect to take residue gas and/or NGLs in-kind at the tailgate of the processing plant and subsequently market the product. Through the marketing process, the Company delivers the product to the purchaser at a contractually agreed-upon delivery point and receives a specified index price from the purchaser. This purchaser can be the natural gas processor or the processor can market the product on the Company’s behalf to a third-party purchaser. In both scenarios, the Company concluded it is the principal in the transaction as control of the product remains with the Company throughout the process. The Company recognizes revenue when control transfers to the ultimate purchaser at the delivery point based on the index price received from the purchaser. Any fees paid to the processor are considered to be for a distinct service with an identifiable benefit that is sufficiently separable. The gathering, processing, and compression fees attributable to the gas processing contract, as well as any transportation fees incurred to deliver the product to the purchaser, are presented as a component of operating expense in the accompanying consolidated statements of operations.
Production handling services contracts. The Company’s production handling service contracts are negotiated in situations where it has a significant working interest in a platform with excess capacity to process and handle produced oil and natural gas. The Company provides processing services to customers with nearby property interests who wish to utilize its excess processing capacity for their production. In certain situations, the Company will also provide services for the operation of the producer’s satellite subsea system. Under these contracts, the Company receives fees for volumes delivered by the customer and processed by the Company. The nature of production handling services is inherently output based on volumes processed and the Company recognizes revenue over time using the output method. Refer to Note 14—Commitments and Contingencies for a further discussion of the Company’s performance obligations related to its production handling services contracts.
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General and Administrative Expenses
G&A expenses consist of overhead, including salaries, incentive compensation, benefits for the Company’s corporate staff, costs of maintaining its headquarters, and costs of managing its production and development operations. The Company records a certain portion of its salaries, wages, and benefits as LOE when they are directly attributable to maintaining the production of its operated oil and natural gas properties. For oil and natural gas properties for which the Company is the operator, it reduces G&A expenses for reimbursements received from other working interest owners for the portion of costs and allowable overhead incurred during the drilling and production phases of the property. G&A expenses also include software fees and audit, legal compliance, and other professional service fees. Additionally, the Company could be subject to legal actions and claims arising in the ordinary course of business, which, if considered probable and reasonably estimable, would require a contingent liability to be recorded as G&A expense.
Stock-based Compensation
The Company recognizes stock-based compensation expense related to its Restricted Stock and stock options based on their fair value on the date of the grant. The Company’s Restricted Stock does not have any post-vesting restrictions; therefore, the fair value of each share on the grant date is determined based on the per share fair value of the Company’s Class A Common Stock on a minority, non-marketable basis. The estimates of the fair value of the Company’s Class A Common Stock are highly complex and subjective, incorporating significant judgments and estimates in the fair value assumptions. Refer to Note 5—Fair Value Measurements for discussion of the fair value of the Company’s Class A Common Stock. The fair value of the stock options granted was estimated on the date of the grant using the Black-Scholes option pricing model.
The Company recognizes compensation expense related to time-based Restricted Stock and stock options using the straight-line method over the requisite service period during which the employee or board member is required to provide services in exchange for the award in accordance with ASC Topic 718, Compensation—Stock Compensation. Compensation expense related to performance-based Restricted Stock is only recognized when the performance condition is deemed probable of occurring and, if necessary, is adjusted based on the probability of the level of achievement of the performance metric. The Company has elected to not estimate the forfeiture rate of its Restricted Stock or stock options in its initial calculation of compensation expense, but instead will adjust compensation expense for forfeitures as they occur. Refer to Note 11—Stock-based Compensation for a further discussion of the Company’s Restricted Stock and stock options.
Income Taxes
The Company accounts for income taxes using the asset and liability method. Deferred tax assets and liabilities are recognized for the future tax consequences attributable to temporary differences between the financial statement carrying amounts of the assets and liabilities and their respective tax basis. Deferred tax assets and liabilities are calculated by applying the existing tax laws and rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in income in the period that includes the enactment date.
A valuation allowance for deferred tax assets, including net operating loss carryforwards, is recognized when it is more likely than not that all or some portion of the benefit from the deferred tax asset will not be realized. To assess that likelihood, the Company uses estimates and judgment regarding its future taxable income, considering the tax consequences in the jurisdiction where such taxable income is generated, to determine whether a valuation allowance is required. Such evidence can include the Company’s current financial position, actual and forecasted results of operations, and tax planning strategies, as well as the current and forecasted business economics of the oil and natural gas industry. The Company assesses all available positive and negative evidence to estimate whether sufficient future taxable income will be generated to permit the use of deferred tax assets. A valuation allowance is provided for deferred tax assets if it is more likely than not that these items will not be
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realized. The effects of a change in the valuation allowance due to changes in circumstances and judgements about the realizability of the related deferred tax asset are included in income from continuing operations. Refer to Note 16—Income Taxes for a further discussion of the Company’s income tax provision.
Note 3—Acquisitions of Oil and Natural Gas Properties
On May 20, 2021, the Company completed the acquisition of an incremental 35% working interest in the U.S. Gulf of Mexico Atwater Valley 574, 575, and 618 (“Neptune”) field from BHP Billiton Petroleum (Deepwater) Inc. and BHP Billiton Petroleum (GOM) Inc. (collectively, “BHP”) with an effective date of July 1, 2020 (collectively, the “Neptune Acquisition”). The Neptune Acquisition was consummated pursuant to a Purchase and Sale Agreement executed on April 6, 2021 and accounted for as an asset acquisition in accordance with ASC Topic 805, Business Combinations. Prior to the acquisition, the Company held a 30% working interest in the Neptune field and following the close of the acquisition, it holds a 65% working interest in the Neptune field. Additionally, the Company became the operator of the Neptune field on August 1, 2021. Per the agreement, the Company did not provide any cash consideration for the Neptune Acquisition, but assumed BHP’s portion of the future P&A obligations associated with the Neptune field. Upon the final settlement of the acquisition, BHP agreed to pay the Company $8.6 million for the Neptune Acquisition, inclusive of customary closing adjustments and net of transaction related costs. Due to the timing of the final settlement, the Company has received $8.2 million of the total consideration in cash as of December 31, 2021, which is reflected in the Net cash used in investing activities section on the consolidated statement of cash flows for the year ended December 31, 2021. The remaining amount was received in January 2022, therefore, it is reflected as non-cash investing activity for the year ended December 31, 2021 in Note 17—Supplemental Cash Flow Information.
The following table presents the allocation of the total consideration to the assets acquired and liabilities assumed, based on their relative fair values, on May 20, 2021:
| (In thousands) | ||||
| Proved oil and natural gas properties |
$ | 5,831 | ||
| Asset retirement obligations |
(14,464 | ) | ||
|
|
|
|||
| Allocated total consideration |
$ | (8,633 | ) | |
|
|
|
|||
Refer to Note 5—Fair Value Measurements for a further discussion of the fair value measurements of the assets acquired and liabilities assumed in the Neptune Acquisition.
Note 4—Derivative Instruments
The Company utilizes commodity derivative instruments to reduce its exposure to crude oil and natural gas price volatility for a portion of its estimated production from its proved, developed, producing oil and natural gas properties. The Company has entered into various derivative contracts with major financial institutions, which, as of December 31, 2021, settle monthly through the first quarter of 2023.
The Company’s crude oil and natural gas derivative instruments consist of various instruments based on its hedging strategy, including financially settled crude oil and natural gas call options, put options, and swaps (including basis swaps), or combinations of these arrangements, which are described below.
| • | Swaps: The Company receives a fixed price and pays a variable market price to the counterparty for contracted commodity volumes over specified time periods. Basis swaps allow the Company to receive a fixed price differential based on the Argus WTI Cushing index price and pay a variable price differential to the counterparty based on the Argus Mars index price for contracted oil volumes over a specified time period. From time to time, the Company may enter into WTI NYMEX roll swaps, which would provide additional protection against variability in the NYMEX roll component of its oil production price. |
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| • | Call Options: A sold call option gives the counterparty the right, but not the obligation, to purchase the underlying commodity volumes from the Company at a specified price (“strike/ceiling price”) over a specified time period. At settlement, if the market price is above the fixed ceiling price of the sold call option, the Company pays the counterparty the difference. In a purchased call option, if the market price settles above the fixed ceiling price of the purchased call option, the Company will receive the difference from the counterparty. If the market price settles below the fixed ceiling price of the sold or purchased call option, no payment is due from either party. |
| • | Purchased Put Options: A purchased put option gives the Company the right, but not the obligation, to sell the underlying commodity volumes to the counterparty at a specified price (“strike/floor price”) over a specified time period. At settlement, if the market price is below the fixed floor price of the purchased put option, the counterparty pays the Company the difference. If the market price settles above the fixed floor price of the purchased put option, no payment is due from either party. |
| • | Put Spreads: A put spread is a combination of a sold put option and a purchased put option. At settlement, if the market price is below the sold put option strike price, the Company receives the difference between the two strike prices from the counterparty. If the market price settles below the purchased put option strike price but above the sold put option strike price, the Company receives the difference between the purchased put option strike price and the market price from the counterparty. If the market price settles above the purchased put option strike price, no payment is due from either party. |
| • | Collars: A collar contains a purchased put option (“fixed floor price”) and a sold call option (“fixed ceiling price”). At settlement, if the market price is below the fixed floor price, the Company receives the difference between the fixed floor price and the market price from the counterparty. If the market price settles above the fixed ceiling price, the Company pays the counterparty the difference between the market price and the fixed ceiling price. If the market price settles between the fixed floor price and fixed ceiling price, no payments are due from either party. |
| • | Three-way Collars: A three-way collar combines a sold call option (“fixed ceiling price”), a purchased put option (“fixed floor price”), and a sold put option (“fixed subfloor price”). At settlement, if the market price settles above the fixed subfloor price but below the fixed floor price, the Company receives the difference between the fixed floor price and the market price from the counterparty. If the market price settles below the fixed subfloor price, the Company receives the market price plus the difference between the fixed subfloor price and the fixed floor price from the counterparty. If the market price settles above the fixed ceiling price, the Company pays the counterparty the difference between the fixed ceiling price and the market price. If the market price settles between the fixed floor price and fixed ceiling price, no payments are due from either party. |
Additionally, the Company may purchase volumetrically offsetting derivative instruments in order to mitigate its exposure against additional commodity price volatility before the settlement date of certain outstanding derivative contracts.
The Company had the following outstanding crude oil derivative contracts, which are indexed to NYMEX WTI, in place as of December 31, 2021:
| 2022 | 2023 | |||||||
| Crude Oil Swaps: |
||||||||
| Notional volume (Bbls) |
275,000 | 90,000 | ||||||
| Weighted average price ($/Bbl) |
$ | 53.04 | $ | 62.00 | ||||
| Crude Oil Purchased Puts: |
||||||||
| Notional volume (Bbls) |
730,000 | — | ||||||
| Weighted average price ($/Bbl) |
$ | 53.86 | $ | — | ||||
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| 2022 | 2023 | |||||||
| Crude Oil Collars: |
||||||||
| Notional volume (Bbls) |
2,998,000 | 270,000 | ||||||
| Weighted average floor price ($/Bbl) |
$ | 39.66 | $ | 51.67 | ||||
| Weighted average ceiling price ($/Bbl) |
$ | 54.92 | $ | 71.79 | ||||
| Crude Oil Collar Offsets: |
||||||||
| Notional volume (Bbls) |
62,000 | — | ||||||
| Weighted average floor price ($/Bbl) |
$ | 38.13 | $ | — | ||||
| Weighted average ceiling price ($/Bbl) |
$ | 50.00 | $ | — | ||||
| Crude Oil Three-way Collars: |
||||||||
| Notional volume (Bbls) |
1,013,200 | 189,000 | ||||||
| Weighted average sub-floor price ($/Bbl) |
$ | 37.69 | $ | 40.00 | ||||
| Weighted average floor price ($/Bbl) |
$ | 47.07 | $ | 50.00 | ||||
| Weighted average ceiling price ($/Bbl) |
$ | 70.00 | $ | 81.48 | ||||
The Company had the following outstanding natural gas derivative contracts, which are indexed to NYMEX HH, in place as of December 31, 2021:
| 2022 | 2023 | |||||||
| Natural Gas Collars: |
||||||||
| Notional volume (MMBtus) |
590,000 | — | ||||||
| Weighted average floor price ($/MMBtu) |
$ | 2.50 | $ | — | ||||
| Weighted average ceiling price ($/MMBtu) |
$ | 3.30 | $ | — | ||||
| Natural Gas Collar Offsets: |
||||||||
| Notional volume (MMBtus) |
590,000 | — | ||||||
| Weighted average floor price ($/MMBtu) |
$ | 2.50 | $ | — | ||||
| Weighted average ceiling price ($/MMBtu) |
$ | 3.30 | $ | — | ||||
| Natural Gas Oil Three-way Collars: |
||||||||
| Notional volume (MMBtus) |
1,215,000 | 900,000 | ||||||
| Weighted average sub-floor price ($/MMBtu) |
$ | 2.99 | $ | 2.50 | ||||
| Weighted average floor price ($/MMBtu) |
$ | 3.56 | $ | 3.00 | ||||
| Weighted average ceiling price ($/MMBtu) |
$ | 6.03 | $ | 5.00 | ||||
The Company recognizes all of its derivative instruments at fair value as assets or liabilities on the accompanying consolidated balance sheets. The Company has not designated any of its derivative instruments as hedges for accounting purposes; therefore, the aggregate net gains and losses resulting from changes in the fair values of its outstanding derivatives, the settlement of derivative instruments, and any net proceeds or payments related to the early termination of derivative contracts during the period are recognized in (Loss) gain on derivatives, net in the accompanying consolidated statements of operations.
The Company typically has numerous hedge positions that span several time periods and often result in both fair value derivative asset and liability positions held with that counterparty. The Company has elected to net its derivative instrument fair values executed with the same counterparty, pursuant to the ISDA master agreements, which provide for the net settlement over the term of the contract and in the event of the default or termination of the contract.
In some cases, the Company might agree to pay a premium on certain of its option derivative contracts. The Company could agree to pay the premium upfront, in which case the premium payment is recorded as a derivative asset. The value of the premium is considered in the underlying derivative fair value and is adjusted in subsequent periods through (Loss) gain on derivatives, net in the accompanying consolidated statements of operations. Alternatively, the Company could defer the payment of the premium until the month the applicable derivative contract settles, in which case it recognizes the deferred premium obligation net against the derivative
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instruments fair value asset or liability, pursuant to the ISDA master netting agreements described above. In the period the derivative contract settles, the Company recognizes the deferred premium obligation in (Loss) gain on derivatives, net in the accompanying consolidated statements of operations.
The following tables present the gross and net fair values of the Company’s derivative instruments, net of any applicable deferred premium obligations recorded on the accompanying consolidated balance sheets:
| December 31, 2021 | ||||||||||||
| Gross Amounts Recognized |
Gross Amounts Offset on the Consolidated Balance Sheet |
Net Amounts Presented on the Consolidated Balance Sheet |
||||||||||
| (In thousands) | ||||||||||||
| Current assets |
$ | 5,205 | $ | (5,205 | ) | $ | — | |||||
| Long-term assets |
2,206 | (2,206 | ) | — | ||||||||
| Current liabilities |
(82,756 | ) | 5,205 | (77,551 | ) | |||||||
| Long-term liabilities |
$ | (4,597 | ) | $ | 2,206 | $ | (2,391 | ) | ||||
| December 31, 2020 | ||||||||||||
| Gross Amounts Recognized |
Gross Amounts Offset on the Consolidated Balance Sheet |
Net Amounts Presented on the Consolidated Balance Sheet |
||||||||||
| (In thousands) | ||||||||||||
| Current assets |
$ | 8,899 | $ | (8,899 | ) | $ | — | |||||
| Long-term assets |
7,290 | (7,290 | ) | — | ||||||||
| Current liabilities |
(24,152 | ) | 8,899 | (15,253 | ) | |||||||
| Long-term liabilities |
$ | (11,324 | ) | $ | 7,290 | $ | (4,034 | ) | ||||
As of December 31, 2021 and 2020, the fair values of the Company’s derivatives are presented net of deferred premium obligations of $7.5 million and $6.4 million, respectively.
The following table presents the components of (Loss) gain on derivatives, net reflected on the accompanying consolidated statements of operations and cash flows for the periods indicated. Total cash (paid) received for derivative settlements, net reflects the gains or losses on derivative contracts which matured during the period, calculated as the difference between the contract price and the market settlement price for those contracts. Any proceeds or payments related to the early termination of derivative contracts, any upfront premiums paid for new derivative contracts during the period, and any cash premium payments associated with derivative contracts settled during the period are included in the total cash (paid) received for derivative settlements, net. Total non-cash loss on derivatives, net represents the changes in the fair values of derivative instruments outstanding at the end of the period and the reversal of previously recognized non-cash gains or losses on derivative contracts that matured during the period.
| Year Ended December 31, | ||||||||||||
| 2021 | 2020 | 2019 | ||||||||||
| (In thousands) | ||||||||||||
| Cash (paid) received for derivative settlements, net: |
||||||||||||
| Crude oil |
$ | (106,828 | ) | $ | 41,069 | $ | (7,901 | ) | ||||
| Natural gas |
(4,434 | ) | 1,717 | 903 | ||||||||
| Diesel |
— | (4,059 | ) | (325 | ) | |||||||
|
|
|
|
|
|
|
|||||||
| Total cash (paid) received for derivative settlements, net |
(111,262 | ) | 38,727 | (7,323 | ) | |||||||
|
|
|
|
|
|
|
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| Year Ended December 31, | ||||||||||||
| 2021 | 2020 | 2019 | ||||||||||
| (In thousands) | ||||||||||||
| Non-cash (loss) gain on derivatives: |
||||||||||||
| Crude oil |
(59,961 | ) | (14,900 | ) | (35,979 | ) | ||||||
| Natural gas |
(694 | ) | (1,496 | ) | 832 | |||||||
| Diesel |
— | 385 | (385 | ) | ||||||||
|
|
|
|
|
|
|
|||||||
| Total non-cash loss on derivatives, net |
(60,655 | ) | (16,011 | ) | (35,532 | ) | ||||||
|
|
|
|
|
|
|
|||||||
| (Loss) gain on derivatives, net |
$ | (171,917 | ) | $ | 22,716 | $ | (42,855 | ) | ||||
|
|
|
|
|
|
|
|||||||
For the year ended December 31, 2021, total cash (paid) received for derivative settlements, net includes deferred premium obligations paid for crude oil derivative contracts of $7.7 million and natural gas derivative contracts of $2.4 million. For the year ended December 31, 2020, total cash (paid) received for derivative settlements, net includes deferred premium obligations paid for crude oil derivative contracts of $6.6 million. Additionally, for the year ended December 31, 2020, total cash (paid) received for derivative settlements, net includes $4.7 million of monetization costs received from counterparties for the early termination of certain oil derivative contracts before their contract settlement dates. For the year ended December 31, 2019, total cash (paid) received for derivative settlements, net includes deferred premium obligations paid for crude oil derivative contracts of $14.1 million.
Note 5—Fair Value Measurements
Certain of the Company’s assets and liabilities are carried at fair value and measured either on a recurring or non-recurring basis. The Company’s fair value measurements are based either on actual market data or assumptions that other market participants would use in pricing an asset or liability in an orderly transaction, using the valuation hierarchy prescribed by GAAP.
The GAAP valuation hierarchy categorizes assets and liabilities measured at fair value into one of three levels depending on the observability of inputs used to determine fair value. The three levels of the fair value hierarchy are as follows:
| • | Level 1: Unadjusted quoted prices for identical assets or liabilities in active markets. |
| • | Level 2: Observable inputs other than Level 1 inputs. These include: quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in markets which are not active, or inputs that are corroborated by observable active market data. |
| • | Level 3: Unobservable inputs for which little or no market data exists. |
The classification of an asset or liability within the fair value hierarchy is based on the lowest level input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement of an asset or liability requires judgment and may affect the valuation of the fair value asset or liability and its placement within the fair value hierarchy. There have been no transfers between fair value hierarchy levels.
Assets and Liabilities Measured at Fair Value on a Recurring Basis
Commodity derivative contracts. The fair values of the Company’s derivative instruments are measured on a recurring basis using a third-party industry-standard pricing model that considers various inputs such as quoted forward commodity prices, discount rates, volatility factors, and current market and contractual prices for the underlying instruments, as well as other relevant data. These significant inputs are observable in the current market or can be corroborated by observable active market data and are therefore considered Level 2 inputs within the fair value hierarchy.
F-24
11.00% Senior Notes due 2023. At the time of the issuance of the 2023 Notes, the Company elected to account for the 2023 Notes and all of its features using the fair value option; therefore, the 2023 Notes were recorded at their fair value on the consolidated balance sheet as of December 31, 2020. In April, as part of the 2021 Refinancing Transactions, described further below, the Company redeemed the total $276.8 million principal amount of its outstanding 2023 Notes. Refer to Note 8—Long-term Debt for a discussion of the Company’s 2023 Notes. Prior to the redemption, the fair value of the Company’s 2023 Notes was measured on a recurring basis and based on unadjusted quoted prices for the liability in an active market, which is considered a Level 1 input.
The following tables present the Company’s assets and liabilities which are measured at fair value on a recurring basis as of December 31, 2021 and 2020 using the fair value hierarchy:
| Fair Value Measurement as of December 31, 2021 | ||||||||||||||||
| Total | Level 1 | Level 2 | Level 3 | |||||||||||||
| (In thousands) | ||||||||||||||||
| Assets: |
||||||||||||||||
| Commodity derivative contracts |
$ | 7,411 | $ | — | $ | 7,411 | $ | — | ||||||||
| Liabilities: |
||||||||||||||||
| Commodity derivative contracts |
$ | (87,353 | ) | $ | — | $ | (87,353 | ) | $ | — | ||||||
| Fair Value Measurement as of December 31, 2020 | ||||||||||||||||
| Total | Level 1 | Level 2 | Level 3 | |||||||||||||
| (In thousands) | ||||||||||||||||
| Assets: |
||||||||||||||||
| Commodity derivative contracts |
$ | 16,189 | $ | — | $ | 16,189 | $ | — | ||||||||
| Liabilities: |
||||||||||||||||
| Commodity derivative contracts |
$ | (35,476 | ) | $ | — | $ | (35,476 | ) | $ | — | ||||||
| 11.00% Senior Notes due 2023 |
$ | (262,646 | ) | $ | (262,646 | ) | $ | — | $ | — | ||||||
Fair Value of Other Financial Instruments
Cash and cash equivalents, restricted cash, accounts receivable, and accounts payable. The carrying amounts of the Company’s cash and cash equivalents, restricted cash, accounts receivable, and accounts payable approximate fair value due to the highly liquid or short-term nature of these instruments.
11.75% Senior Notes due 2026. The Company’s 11.75% senior secured second lien notes due 2026 (the “2026 Notes”) are presented on the consolidated balance sheet as of December 31, 2021 at their carrying value of $275.5 million, which is net of the unamortized discount and deferred financing costs. Refer to Note 8—Long-term Debt for a discussion of the Company’s 2026 Notes. The fair value of the aggregate principal amount outstanding of the 2026 Notes is $296.2 million as of December 31, 2021, and is estimated based on unadjusted quoted prices for the liability in an active market, which is considered a Level 1 input.
Assets and Liabilities Measured at Fair Value on a Non-Recurring Basis
Acquisition-related assets and liabilities. The fair values of assets acquired and liabilities assumed in an acquisition are measured on a non-recurring basis on the acquisition date using a discounted cash flow model. The significant inputs used in the discounted cash flow model include estimates relating to oil and natural gas reserves, future commodity prices, the timing of developing the assets, future operating costs, a credit-risk adjusted discount rate, and other relevant data. These significant inputs are based on unobservable market data and are therefore considered Level 3 inputs within the fair value hierarchy. Refer to Note 3—Acquisitions of Oil and Natural Gas Properties for a further discussion of the Company’s acquisitions.
F-25
Asset retirement obligations. The fair values of any additions to the Company’s asset retirement obligations are measured on a non-recurring basis at the time those obligations are incurred or acquired using a discounted cash flow model. The significant inputs used in the discounted cash flow model include estimates relating to the future P&A settlement timing and costs, a credit-risk adjusted discount rate, and inflation rates. These significant inputs are based on unobservable market data and are therefore considered Level 3 inputs within the fair value hierarchy. Refer to Note 7—Asset Retirement Obligations for a further discussion of the Company’s asset retirement obligations.
Class A Common Stock. The per share fair value of the Company’s Class A Common Stock is estimated on a non-recurring basis. In the second, third, and fourth quarters of 2021, the Company’s Board elected to pay the quarterly Series A Preferred Stock dividends in cash rather than issuing PIK Shares, as they were historically paid, and subsequently changed the valuation model used in determining the fair value of its Class A Common Stock from an option pricing model (“OPM”) to a Monte Carlo simulation model. The Monte Carlo simulation model uses assumptions regarding multiple projections of the Company’s share price paths and must be repeated numerous times to achieve a probabilistic assessment. Both the Monte Carlo model and the OPM estimate the per share fair value of the Company’s Class A Common Stock on a minority, marketable basis, and apply a discount for lack of marketability to account for the illiquidity of the Company’s Class A Common Stock. Both models allocate the Company’s total equity value to the various classes of equity in its capital structure, treating any outstanding shares of the Class A Common Stock, Class B Common Stock, and Series A Preferred Stock as options on the entity’s enterprise value and capturing the option-like characteristics of common stock for entities whose common stock is a small portion of the total capital structure.
The significant inputs used in the Monte Carlo model and the OPM include the timing and probabilities of potential liquidity event dates, equity volatilities, risk-free rates, and an estimate of the Company’s total equity value. A discounted cash flow model is utilized to calculate the total equity fair value by present valuing risk-adjusted future expected cash flows primarily associated with the Company’s oil and natural gas asset reserves. The assumed timing and probabilities of potential liquidity event dates are based on management’s estimates. As there is currently no active market for the Company’s Class A Common Stock, the expected equity volatility is determined using the historical volatility of a publicly traded set of peer companies. The risk-free interest rates utilized are based on the interpolated yields of the U.S. Treasury bonds with maturities that commensurate the timing of potential liquidity event dates. These significant inputs are based on sensitive unobservable market data and are therefore considered Level 3 inputs within the fair value hierarchy.
As of December 31, 2021, the Company’s Monte Carlo valuation model assumed a weighted-average risk-free interest rate of 0.3% and a weighted-average expected stock price volatility rate of 75.0%. As of December 31, 2020, the Company’s OPM valuation assumed a weighted-average risk-free interest rate of 0.2% and a weighted-average expected stock price volatility rate of 80.0%. Historically, the Company has not declared or paid Class A Common Stock cash dividends, nor is it probable that it will do so in the future, therefore, there was no dividend yield included in the OPM.
F-26
Note 6—Property and Equipment, net
The Company’s property and equipment, net consist of the following for the periods indicated:
| December 31, 2021 | December 31, 2020 | |||||||
| (In thousands) | ||||||||
| Proved oil and natural gas properties |
$ | 1,738,217 | $ | 1,628,951 | ||||
| Less: accumulated depreciation, depletion, and amortization |
(1,068,467 | ) | (912,922 | ) | ||||
|
|
|
|
|
|||||
| Proved oil and natural gas properties, net |
669,750 | 716,029 | ||||||
| Unproved oil and natural gas properties |
94,462 | 89,394 | ||||||
|
|
|
|
|
|||||
| Total oil and natural gas properties, net |
764,212 | 805,423 | ||||||
|
|
|
|
|
|||||
| Other property and equipment |
8,545 | 8,414 | ||||||
| Less: accumulated depreciation |
(5,901 | ) | (4,795 | ) | ||||
|
|
|
|
|
|||||
| Total other property and equipment, net |
2,644 | 3,619 | ||||||
|
|
|
|
|
|||||
| Total property and equipment, net |
$ | 766,856 | $ | 809,042 | ||||
|
|
|
|
|
|||||
During each of the years ended December 31, 2021 and 2020, the Company recognized $0.9 million of G&A expenses directly allocable to capital exploratory activities, which were initially capitalized to unproved oil and natural gas properties. Additionally, during the years ended December 31, 2021 and 2020, the Company capitalized $2.3 million and $1.3 million, respectively, of interest expense to unproved oil and natural gas properties related to certain significant long-term exploratory projects. Refer to Note 19—Supplemental Oil and Natural Gas Disclosures (Unaudited) for a summary of the Company’s costs incurred related to its oil and natural gas properties.
Note 7—Asset Retirement Obligations
The following table presents the change in the Company’s asset retirement obligations for the periods indicated:
| December 31, 2021 | December 31, 2020 | |||||||
| (In thousands) | ||||||||
| Asset retirement obligations at the beginning of the period |
$ | 299,674 | $ | 273,530 | ||||
| Liabilities settled |
(10,040 | ) | (5,604 | ) | ||||
| Liabilities incurred |
13 | 521 | ||||||
| Liabilities acquired (1) |
14,464 | — | ||||||
| Revisions of previous estimates |
16,634 | 2,231 | ||||||
| Accretion expense |
27,541 | 28,996 | ||||||
|
|
|
|
|
|||||
| Asset retirement obligations at the end of the period |
348,286 | 299,674 | ||||||
| Less: current portion of asset retirement obligations |
(24,935 | ) | (12,807 | ) | ||||
|
|
|
|
|
|||||
| Asset retirement obligations, less current portion at the end of the period |
$ | 323,351 | $ | 286,867 | ||||
|
|
|
|
|
|||||
| (1) | All of the asset retirement obligation liabilities acquired during the year ended December 31, 2021 relate to the Neptune Acquisition, refer to Note 3—Acquisitions of Oil and Natural Gas Properties for a further discussion. |
F-27
For the years ended December 31, 2021 and 2020, the revisions of previous estimates to the Company’s asset retirement obligation balances are attributable to changes in estimated cash flows and the planned timing of P&A activities.
Note 8—Long-term Debt
The Company’s outstanding long-term debt balances consist of the following for the periods indicated:
| December 31, 2021 | December 31, 2020 | |||||||
| (In thousands) | ||||||||
| 11.75% Senior Notes due 2026 |
$ | 287,500 | $ | — | ||||
| Less: unamortized discount and deferred financing costs |
(11,986 | ) | — | |||||
|
|
|
|
|
|||||
| 11.75% Senior Notes due 2026, net |
275,514 | — | ||||||
| Less: current portion of 11.75% Senior Notes due 2026, net (1) |
(27,045 | ) | — | |||||
|
|
|
|
|
|||||
| Long-term portion of 11.75% Senior Notes due 2026, net |
$ | 248,469 | $ | — | ||||
| 11.00% Senior Notes due 2023 |
$ | — | $ | 276,816 | ||||
| Fair value adjustment |
— | (14,170 | ) | |||||
|
|
|
|
|
|||||
| 11.00% Senior Notes due 2023, at fair value |
— | 262,646 | ||||||
|
|
|
|
|
|||||
| Total long-term portion of debt, net |
$ | 248,469 | $ | 262,646 | ||||
|
|
|
|
|
|||||
| (1) | As of December 31, 2021, the current portion of the 11.75% Senior Notes due 2026 is presented net of the next twelve months of unamortized discount and deferred financing costs. |
The following table presents the components of Interest expense reflected on the accompanying consolidated statements of operations for the periods indicated:
| Year Ended December 31, | ||||||||||||
| 2021 | 2020 | 2019 | ||||||||||
| (In thousands) | ||||||||||||
| Interest expense on 11.75% Senior Notes due 2026 |
$ | 24,810 | $ | — | $ | — | ||||||
| Amortization of discount and deferred financing costs related to the 11.75% Senior Notes due 2026 |
2,127 | — | — | |||||||||
| Interest expense on 11.00% Senior Notes due 2023 |
8,980 | 35,017 | 35,750 | |||||||||
| Fees associated with the Revolving Credit Facility |
1,045 | 1,777 | 1,786 | |||||||||
| Amortization and expensing of deferred financing costs related to the Revolving Credit Facility |
1,302 | 1,225 | 1,490 | |||||||||
| Amortization of surety bond premiums |
10,657 | 10,164 | 13,650 | |||||||||
| Interest expense on notes payable and other |
580 | 779 | 130 | |||||||||
| Less: capitalized interest |
(2,336 | ) | (1,334 | ) | (1,273 | ) | ||||||
|
|
|
|
|
|
|
|||||||
| Total interest expense |
$ | 47,165 | $ | 47,628 | $ | 51,533 | ||||||
|
|
|
|
|
|
|
|||||||
2021 Refinancing Transactions
In April of 2021, the Company completed the offering of its $302.5 million aggregate principal amount 2026 Notes and used the net proceeds from the 2026 Notes offering to redeem the remaining principal amount of its outstanding 2023 Notes. Additionally, the Company amended certain terms of its Revolving Credit Facility agreement, discussed further below, which, among other things, extended the maturity date to January 26, 2024, established a revised borrowing base of $165.0 million, and reduced the aggregate committed amounts
F-28
thereunder to $165.0 million (collectively, the “2021 Refinancing Transactions”). In accordance with ASC Topic 470-50, Modifications and Extinguishment of Debt (“ASC 470-50”), the Company concluded that each of these transactions should be accounted for separately and that the redemption of the 2023 Notes should be accounted for as an extinguishment of debt.
Revolving Credit Facility Amendment. The Company analyzed the borrowing capacity of the Revolving Credit Facility before and after the amendment on a lender by lender basis. The initial debt issuance costs associated with the existing lenders remain capitalized as deferred financing costs, along with $2.9 million of incremental costs incurred for the amendment. These costs will be amortized over the term of the amendment agreement and the unamortized portion of the deferred financing costs are included in Other non-current assets on the accompanying consolidated balance sheets. Additionally, the Company expensed $0.2 million of initial debt issue costs associated with lenders that are no longer a part of the Revolving Credit Facility syndicate.
2026 Notes Issuance. The 2026 Notes were issued at an original issuance discount of $6.8 million and the Company incurred underwriter and other third-party offering costs of $7.3 million. The 2026 Notes are presented at their carrying value, net of the unamortized discount and deferred financing costs on the consolidated balance sheet as of December 31, 2021.
2023 Notes Redemption. As discussed below, at the time of the 2023 Notes offering, the Company elected to account for the 2023 Notes and all of its features using the fair value option; therefore, it has since presented the 2023 Notes at their fair value on the consolidated balance sheet as of December 31, 2020. Due to the election for the fair value option, there is no unamortized discount or deferred financing costs associated with the 2023 Notes to expense upon extinguishment.
Revolving Credit Facility
In 2014, the Company entered into an agreement with a syndicate of banks and established the Revolving Credit Facility, which is secured by substantially all of the Company’s assets on a first lien basis. The Revolving Credit Facility has a maximum line of credit of $500.0 million and the borrowing base is subject to a semi-annual redetermination, based on an assessment of the value of the Company’s proved reserves as determined by a reserve report. In April, as part of the 2021 Refinancing Transactions, the Company amended certain terms of the Revolving Credit Facility agreement and extended the maturity date to January 26, 2024, established a revised borrowing base of $165.0 million, reduced the aggregate committed amounts thereunder to $165.0 million, and modified applicable interest rates. In November 2021, as part of the semi-annual redetermination, the Revolving Credit Facility borrowing base was increased to $200.0 million.
As of December 31, 2021 and 2020, the Revolving Credit Facility remained undrawn and the Company had $3.6 million in outstanding letters of credit to collateralize its oil and natural gas transportation agreements and P&A obligations. Prior to the amendment of the Revolving Credit Facility agreement, the Company was required to provide the full outstanding letter of credit amount of $3.6 million in cash to the banks to fulfill a cash security requirement to collateralize its letters of credit, which was recorded as Restricted cash on the consolidated balance sheet as of December 31, 2020. The cash security requirement was removed as part of the Revolving Credit Facility agreement amendment, therefore, the banks have released the previously provided cash required to collateralize its letters of credit back to the Company. As of December 31, 2021 and 2020, the Company had $161.4 million and $271.4 million, respectively, of availability under its Revolving Credit Facility, including its outstanding letters of credit.
Borrowings under the Revolving Credit Facility, as amended, bear interest at one of the following rates, as selected by the Company: (i) the bank’s prime rate in effect, adjusted by an applicable margin of 2.0%–4.5%; or (ii) the London Interbank Offered Rate, adjusted by an applicable margin of 3.0%–5.5%. Per the agreement, the Company may elect to convert its outstanding borrowings to a different type and interest rate.
F-29
The agreement governing the Revolving Credit Facility contains certain covenants, including maximum ratios of total funded and secured debt to EBITDAX, and a minimum ratio of current assets to current liabilities. The Company’s ability to declare and pay dividends and other restricted payments under its amended Revolving Credit Facility agreement is subject to its compliance with additional incurrence covenants, the Company maintaining a required amount of availability under its Revolving Credit Facility, as well as the absence of any defaults by the Company under its Revolving Credit Facility. Other restrictive covenants include, but are not limited to, limitations on the Company’s ability to incur indebtedness, make loans or investments, enter into certain hedging agreements, materially change its business, or undergo a change of control.
Additionally, the Revolving Credit Facility agreement contains certain requirements relating to the Company’s hedging of its proved, developed, and producing reserves, which are defined in the agreement as the proved, developed, and producing reserves based on the year end or mid-year reserve reports prepared by independent third-party reserve engineers, Netherland, Sewell & Associates, Inc. (“NSAI”). The Revolving Credit Facility agreement limits the Company’s derivative contracts with delivery risk to 85% of the reasonably projected production from its proved, developed, producing reserves in December through July (“non-wind months”) and 70% of the reasonably projected production from its proved, developed, producing reserves in August through November (“wind months”).
The Revolving Credit Facility agreement also contains a minimum hedging requirement, which was amended as part of the semi-annual redetermination in November 2021. Per the agreement, as amended, if the Company’s leverage ratio is below a defined threshold on the minimum hedging test dates of March 15th and September 15th of each year (the “Minimum Hedging Test Date”), it is required to hedge a minimum of 50% of the reasonably projected production from its proved, developed, producing reserves, on a Boe basis, for the first twelve months following the Minimum Hedging Test Date. If the Company’s leverage ratio is above the defined threshold on the Minimum Hedging Test Date, then the minimum hedging requirements change to 70% of the reasonably projected production from its proved, developed, producing reserves, on a Boe basis, for the first twelve months and 50% of the reasonably projected production from its proved, developed, producing reserves, on a Boe basis, for months 13 through 18 following the Minimum Hedging Test Date.
As of December 31, 2021, the Company is in compliance with all of the covenants and hedging requirements contained in its Revolving Credit Facility agreement.
11.75% Senior Notes due 2026
On April 15, 2021, the Company completed the private offering of its $302.5 million aggregate principal amount 2026 Notes, which resulted in net proceeds of $288.4 million, net of the original issuance discount of $6.8 million and underwriter and other third-party offering costs of $7.3 million. The 2026 Notes were issued by EnVen GoM and co-issued by EnVen GoM’s wholly-owned subsidiary, EnVen Finance Corporation and are initially guaranteed by the Company and its domestic subsidiaries which guarantee the Revolving Credit Facility. The 2026 Notes and the related guarantees are secured by second-priority liens on the Company’s and the guarantors’ assets that secure all of the indebtedness under the Revolving Credit Facility, subject to certain exceptions. The 2026 Notes will mature on April 15, 2026 and interest accrues from April 15, 2021, the date of issuance, and is to be paid semi-annually in cash in arrears on April 15th and October 15th of each year, beginning October 15, 2021. The Company amortizes the 2026 Notes discount and deferred financing costs into Interest expense on the accompanying consolidated statements of operations over the term of the 2026 Notes using the interest method with an effective interest rate of 13.3%. Additionally, per the 2026 Notes indenture, the Company is required to redeem $15.0 million of the principal amount outstanding at par value on the April 15th and October 15th of each year, beginning October 15, 2021. In accordance with ASC Topic 210, Balance Sheet, the Company classifies the portion of the 2026 Notes, net of unamortized discount and deferred financing costs, which will be paid within the next twelve months as a current liability on its consolidated balance sheets.
F-30
The indenture governing the 2026 Notes also contains certain covenants, which are customary with respect to non-investment grade debt securities, including limitations on the Company’s ability to incur and guarantee additional indebtedness, repay, redeem, or repurchase certain debt and capital stock, issue certain preferred stock or similar equity securities, pay dividends or make other distributions on capital stock, enter into certain types of transactions with affiliates, make loans or investments, and make other restricted payments. Additionally, certain covenants restrict the Company’s subsidiaries’ ability to pay dividends, create liens, and sell certain assets. As of December 31, 2021, the Company is in compliance with all of the debt covenants contained in the indenture governing the 2026 Notes.
11.00% Senior Notes due 2023
On February 15, 2018, the Company completed the private offering of its $325.0 million aggregate principal amount 2023 Notes, resulting in net proceeds of $317.0 million, after deducting initial purchaser fees and offering expenses of $8.0 million. The 2023 Notes were issued by EnVen GoM and co-issued by EnVen GoM’s wholly-owned subsidiary, EnVen Finance Corporation and were initially guaranteed by the Company and its domestic subsidiaries which guaranteed the Revolving Credit Facility. The 2023 Notes and the related guarantees were secured by second-priority liens on the Company’s and the guarantors’ assets that secured all of the indebtedness under the Revolving Credit Facility, subject to certain exceptions. The 2023 Notes were set to mature on February 15, 2023 and interest accrued from February 15, 2018, the date of issuance, and was paid semi-annually in cash in arrears on February 15th and August 15th of each year, beginning August 15, 2018. As of the date of issuance and until the 2023 Notes were redeemed, the Company was in compliance with all of the debt covenants contained in the indenture governing the 2023 Notes.
Throughout the fourth quarter of 2020, the Company paid $41.3 million to repurchase $48.2 million principal amount of its 2023 Notes, including $1.3 million in accrued interest. Then as part of the 2021 Refinancing Transactions completed in April, the Company redeemed the remaining $276.8 million principal amount of its outstanding 2023 Notes, which included paying $5.2 million of accrued interest. Additionally, upon redemption, the Company paid a call premium of $11.4 million, which is recognized as (Loss) gain on extinguishment of long-term debt on the accompanying consolidated statement of operations for the year ended December 31, 2021 and reflects the difference between the par value and the redemption price of the 2023 Notes.
The 2023 Notes indenture contained certain put and call features that were analyzed at the time of issuance in accordance with ASC Topic 815, Derivatives and Hedging. The Company determined that one of these features was an embedded derivative, which would typically require bifurcation. Due to this embedded derivative feature, the Company had elected to account for the 2023 Notes and all of its features using the fair value option and had recorded the 2023 Notes at their fair value of $262.6 million on the accompanying consolidated balance sheet as of December 31, 2020.
Prior to the redemption of the 2023 Notes, the Company recorded the changes in the fair value of the 2023 Notes in accordance with ASU 2016-01. Therefore, the change in the fair value of the 2023 Notes attributable to the change in the base market rate was recorded as a component of Gain (loss) on fair value of 11.00% Senior Notes due 2023 on the Company’s consolidated statements of operations and the remainder of the change was attributable to instrument-specific credit risk and was recognized separately as Other comprehensive (loss) income, net on the consolidated statements of comprehensive (loss) income. The Company had elected to use the U.S. Treasury bond rate as its benchmark interest rate to determine the change in the fair value attributable to instrument-specific credit risk, therefore, it compared the change in the fair value of the 2023 Notes to the change in the fair value of the U.S. Treasury bonds based on the interpolated yields of the U.S. Treasury bonds with maturities which coincided with the maturity date of the 2023 Notes. The change in the U.S. Treasury bond rate was attributable as the base market rate change and the remainder of the change was attributable to instrument-specific credit risk, which was separately recognized as Other comprehensive (loss) income, net.
F-31
For the year ended December 31, 2019, the Company recognized $9.2 million as Loss on fair value of 11.00% Senior Notes due 2023 and attributed the remainder of the decrease in the fair value as instrument-specific credit risk, recognizing a gain of $35.8 million as Other comprehensive (loss) income, net of $4.1 million attributable to non-controlling interest. Further, at the time of the adoption of ASU 2016-01, the Company recorded a cumulative effect adjustment of $20.9 million in the opening balance of its Accumulated deficit and Accumulated other comprehensive income as of December 31, 2019 to reflect the portion of the change in the fair value of the 2023 Notes attributable to instrument-specific credit risk prior to January 1, 2019.
Additionally, ASC 470-50 specifies that if the Company extinguishes debt which was recorded using the fair value option then the net carrying amount of the extinguished debt should equal its fair value at the date of the repurchase or redemption and any related gains or losses that have been recognized separately in Other comprehensive (loss) income should be reclassified to Net income or loss upon extinguishment. Therefore, at each repurchase date throughout the fourth quarter of 2020, the Company recorded the outstanding amount of the 2023 Notes at their fair value and allocated the change in fair value between the change in the base market rate and the change attributable to instrument-specific credit risk. The Company then reclassified the proportional amount of the change attributable to instrument-specific credit risk associated with the 2023 Notes repurchases from Other comprehensive (loss) income, net on the accompanying consolidated statement of comprehensive (loss) income to either (Loss) gain on extinguishment of long-term debt or Gain (loss) on fair value of 11.00% Senior Notes due 2023 on the accompanying consolidated statement of operations. The amount reclassified to the (Loss) gain on extinguishment of long-term debt reflects the difference between the par value and the fair value of the 2023 Notes on the dates of the repurchases and the remaining amount reclassified from the Other comprehensive (loss) income, net amount was recognized as a component of Gain (loss) on fair value of 11.00% Senior Notes due 2023.
During the year ended December 31, 2020, pursuant to the 2023 Notes repurchases, the Company had reclassified $11.0 million gross, $8.7 million net of deferred income tax expense, from Other comprehensive (loss) income, net, $8.2 million of which was recognized as a gain on the extinguishment of long-term debt and $2.8 million of which was recognized as a gain on the fair value of the 2023 Notes. Overall, during the year ended December 31, 2020, the Company recognized a loss of $3.2 million as Gain (loss) on fair value of 11.00% Senior Notes due 2023 and a gain of $8.1 million as Other comprehensive (loss) income, net of $1.5 million attributable to non-controlling interest.
Further, when the Company redeemed the remaining 2023 Notes in April 2021, it recorded the outstanding amount of the 2023 Notes at their fair value and allocated the change in fair value between the change in the base market rate and the change attributable to instrument-specific credit risk. The Company then reclassified the Accumulated other comprehensive income associated with the 2023 Notes of $5.0 million to its consolidated statement of operations for the year ended December 31, 2021 as Gain (loss) on fair value of 11.00% Senior Notes due 2023. Additionally, the gain on the fair value of the 2023 Notes recognized for the year ended December 31, 2021 includes the reversal of $11.4 million of losses previously recognized to account for the changes in the base market rate of the 2023 Notes. Overall, during the year ended December 31, 2021, the Company recognized a gain of $16.6 million as Gain (loss) on fair value of 11.00% Senior Notes due 2023 and a loss of $23.0 million as Other comprehensive (loss) income, net of $5.6 million attributable to non-controlling interest.
Note 9—Stockholders’ Equity
Prior to the 2015 Equity Offering, as discussed in Note 1—Organization and Basis of Presentation, the Company amended its certificate of incorporation to authorize the issuance of 275,000,000 shares of capital stock consisting of 200,000,000 shares of Class A Common Stock, 50,000,000 shares of Class B Common Stock, and 25,000,000 shares of Series A Preferred Stock.
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Additionally, as part of the 2015 Equity Offering, the Company issued Series A and Series B Warrants, which were exercisable at any time into 2,000,000 shares of Class A Common Stock. None of these warrants were exercised before they expired on November 6, 2020.
Class A & Class B Common Stock
As discussed in Note 1—Organization and Basis of Presentation, prior to the closing of the 2015 Equity Offering, the then existing members of Energy Ventures GoM Holdings, LLC contributed 100% of their limited liability interest in EnVen GoM to a newly formed limited liability company, EnVen Equity Holdings. Following this transaction and also prior to the closing of the 2015 Equity Offering, Energy Ventures GoM Holdings, LLC was converted from a limited liability company to a Delaware corporation and renamed EnVen Energy Corporation. Concurrently, the Company issued 3,333,333 shares of its Class B Common Stock to the owners of EnVen Equity Holdings.
In April 2021, EnVen Equity Holdings exercised its Redemption Rights, discussed above in Note 1—Organization and Basis of Presentation, with respect to all of its limited liability interests of EnVen GoM. Pursuant to the terms of the EnVen GoM LLC Agreement, the Company then elected to settle the Redemption Rights through a direct exchange of such common units for 3,333,333 newly issued shares of its Class A Common Stock and cancelled the associated 3,333,333 shares of its Class B Common Stock, resulting in the Class B Common Stock Conversion. As a result, EnVen Equity Holdings no longer holds any limited liability interests of EnVen GoM and no longer holds any shares of Company’s Class B Common Stock. The Company accounted for these transactions as an adjustment to its Stockholders’ equity during the second quarter of 2021.
Prior to the Class B Common Stock Conversion, the Company owned the majority interest (approximately 90.5% and 89.8% as of December 31, 2020 and 2019, respectively) of and controlled its subsidiary, EnVen GoM; therefore, the majority interest in EnVen GoM was reflected as a consolidated subsidiary in the accompanying consolidated financial statements as of December 31, 2020. The Non-controlling interest (approximately 9.5% and 10.2% as of December 31, 2020 and 2019, respectively) not held by the Company was included in the accompanying consolidated financial statements as Non-controlling interest. The Non-controlling interest percentage was based on the proportionate amount of the Company’s Class B Common Stock outstanding to the total shares outstanding, inclusive of its Class A Common Stock, Series A Preferred Stock, and the PIK Share dividends; therefore, it changed if and when shares of Class A Common Stock, Series A Preferred Stock, and PIK Share dividends were issued. EnVen GoM was considered a variable interest entity for which the Company was the primary beneficiary, as it was the sole managing member of EnVen GoM and had the power to direct the activities most significant to EnVen GoM’s economic performance, as well as the obligation to absorb losses and receive benefits that were potentially significant. Following the consummation of the Class B Common Stock Conversion in April 2021, the Company owns and controls 100% of its subsidiary EnVen GoM; therefore, as of April 30, 2021, it no longer reports a Non-controlling interest on its consolidated balance sheet.
Excluding Class A Common Stock shares issued as part of the Class B Conversion discussed above, during the years ended December 31, 2021 and 2020, the Company only issued Class A Common Stock as part of its employee incentive award plan. Additionally, during the year ended December 31, 2021, the Company repurchased and retired 131,405 vested Restricted Stock shares from current employees. Refer to Note 11—Stock-based Compensation for a further discussion.
Series A Preferred Stock
On December 30, 2016, the Board designated 9,867,930 shares of the Company’s authorized and unissued shares of preferred stock with a par value of $0.001 per share as Series A Preferred Stock. The Company subsequently issued the Series A Preferred Stock to investors for $12.00 per share in conjunction with funding the acquisition of certain oil and natural gas properties.
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The Series A Preferred Stock certificate of designation (“COD”) provides the holders certain rights and preferential privileges not available to the holders of other classes of the Company’s stock. In June 2021, the Company executed an amendment to the Series A Preferred Stock COD to reflect certain administrative changes. In conjunction with the amendment, the Company paid a $1.9 million consent fee to the Series A Preferred Stock holders, which is presented as a component of Net cash used in financing activities on the consolidated statement of cash flows for the year ended December 31, 2021. The Series A Preferred Stock COD amendment did not change the nature or fair value of the Series A Preferred Stock or the rights of the Series A Preferred Stock holders.
The holders of the Series A Preferred Stock are entitled to receive quarterly dividends of $0.45 per Series A Preferred Stock share, at the election of the Company’s Board, in cash or in PIK Shares. The Series A Preferred Stock dividends are cumulative from the issue date and are payable in arrears beginning on December 31, 2016. In the first quarter of 2021 and during the years ended December 31, 2020 and 2019, the Company paid the quarterly Series A Preferred Stock dividends by issuing PIK Shares. However, in the second, third, and fourth quarters of 2021, the Company’s Board elected to pay the dividends in cash rather than issuing PIK Shares, which is presented as a component of Net cash used in financing activities on the consolidated statement of cash flows for the year ended December 31, 2021.
As discussed in Note 1—Organization and Basis of Presentation—Recently Adopted Accounting Standards, the Company elected to early adopt ASU 2020-06, effective January 1, 2021, eliminating the accounting model for the beneficial conversion feature related to its PIK Share dividends. Prior to the adoption of this ASU, at the end of each reporting period or when PIK Share dividends were declared, the Company would evaluate if there was a beneficial conversion feature related to the PIK Share dividends of its Series A Preferred Stock by comparing the fair value of its Class A Common Stock to the original issue price of $12.00 per share. If the fair value of the Company’s Class A Common Stock was above the original issue price of $12.00 per share, it would record the difference as a beneficial conversion feature associated with its PIK Share dividends and reflect that amount as part of the Series A preferred stock dividends line item on the accompanying consolidated statements of operations. Until the adoption of ASU 2020-06, the Company evaluated if a beneficial conversion existed on a quarterly basis; however, it has not recognized a beneficial conversion feature related to the PIK Share dividends of its Series A Preferred Stock since 2019. For the year ended December 31, 2019, the Company recognized $10.2 million for the beneficial conversion feature related to the PIK Share dividends of its Series A Preferred Stock, which was reflected as part of the Series A preferred stock dividends line item on the accompanying consolidated statement of operations for the year ended December 31, 2019.
The holders of the Series A Preferred Stock are entitled to one vote per share of Class A Common Stock, on an as-converted basis, discussed further below, on all matters to be voted on by the Company’s shareholders. Additionally, the holders of the Series A Preferred Stock are entitled to receive a cash liquidation preference in the event of a liquidation, dissolution or other winding up of the affairs of the Company, including the consolidation or merger of the Company or the sale of all or substantially all of the assets of the Company, equal to the greater of either: (i) $24.00 per outstanding share, excluding any previously issued PIK Share dividends, plus accrued and unpaid dividends, or (ii) $12.00 per outstanding share, inclusive of any previously issued PIK Share dividends, plus accrued and unpaid dividends. The Series A Preferred Stock COD also contains several conversion and redemption features. The Series A Preferred Stock shares are convertible into shares of Class A Common Stock at any time at the option of the holder at the original issue price of $12.00 per share (the “Initial Conversion Price”). Upon the consummation of a qualified initial public offering (“QIPO”) (as defined in the COD), all of the shares of the Series A Preferred Stock will automatically convert into a variable number of shares of Class A Common Stock based on a calculation, stated in the COD, using either the price of the Class A Common Stock shares sold in the QIPO or the price of the Series A Preferred Stock shares on the date of conversion (“Conversion Price”), whichever results in a greater number of Class A Common Stock shares, as adjusted for any Series A Preferred Stock shares that have been repurchased, converted, or redeemed prior to the QIPO. The Conversion Price is based on the Initial Conversion Price and is subject to adjustments for stock dividends, stock splits, stock combinations, and certain issuances of common stock or warrants for less than the
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Conversion Price. The timing and occurrence of a possible conversion is unknown and contains uncertainties; therefore, neither of the conversion features embody an unconditional obligation. Additionally, at any time prior to the closing of a QIPO, the Company may offer to redeem shares of the Series A Preferred Stock, for cash, at a price equal to the Initial Conversion Price per share, plus any accrued but unpaid dividends. The holders have the right to elect not to have their shares redeemed; therefore, the redemption is not mandatory.
Note 10—Related Party Transactions
Tax Receivable Agreement
As discussed in Note 1—Organization and Basis of Presentation, in connection with the 2015 Equity Offering, the members of EnVen Equity Holdings indirectly owned the limited liability interests of EnVen GoM and as specified in the EnVen GoM LLC Agreement had the ability to exercise their Redemption Rights at any time. Additionally, at the time of the 2015 Equity Offering, the Company also entered into a TRA with EnVen Equity Holdings. Pursuant to the TRA, the Company would be required to remit 85% of the cash tax savings, determined on a with-and-without basis, to EnVen Equity Holdings should it convert its limited liability interest of EnVen GoM into shares of the Company’s Class A Common Stock or if payments were accelerated pursuant to the terms of the TRA. The Company had the right to terminate the TRA early, in which case it would be required to make an immediate payment equal to the present value of the anticipated future tax benefits subject to the TRA, calculated based on certain assumptions and deemed events as set forth in the TRA. The TRA remained in effect until (i) EnVen Equity Holdings or any successor holders exchanged all of its limited liability interest of EnVen GoM pursuant to the Redemption Rights, discussed above, and the payment of all amounts required to be paid under the TRA and (ii) the TRA was terminated pursuant to its terms.
Since any amounts payable pursuant to the TRA would only arise if EnVen Equity Holdings converted its limited liability interest of EnVen GoM into shares of the Company’s Class A Common Stock, the criteria for reporting a liability had not been met as of December 31, 2020 as such conversions have not occurred; therefore the Company’s consolidated balance sheet as of December 31, 2020 did not reflect a liability for any amounts that could have become payable pursuant to the TRA.
In April 2021, EnVen Equity Holdings exercised its Redemption Rights with respect to all of its limited liability interests of EnVen GoM. Pursuant to the terms of the EnVen GoM LLC Agreement, the Company then elected to settle the Redemption Rights through the Class B Common Stock Conversion transaction, as discussed in Note 1—Organization and Basis of Presentation. Concurrent with the Class B Common Stock Conversion, the Company and EnVen Equity Holdings agreed to terminate the TRA for a $7.0 million cash payment to EnVen Equity Holdings, which was paid in April of 2021. Therefore, the Company has no future liability associated with the TRA and has recorded the TRA Settlement as an adjustment to its Stockholders’ equity.
Bain Capital Credit
As of December 31, 2021, entities affiliated with Bain Capital Credit (“Bain”) held 46.2% of the Company’s Class A Common Stock and Series A Preferred Stock and three members of the Company’s Board are affiliated with Bain.
As discussed in Note 8—Long-term Debt, as part of the 2021 Refinancing Transactions completed in April, the Company issued the 2026 Notes and used the net proceeds to redeem the remaining principal amount of its outstanding 2023 Notes. At the date of issuance, an entity affiliated with Bain purchased 8.3% of the Company’s 2026 Notes and prior to the redemption, an entity affiliated with Bain held 13.3% of the 2023 Notes. Additionally, at the date of issuance, an affiliated equity investor purchased 3.3% of the 2026 Notes and certain members of management purchased less than 1% of the 2026 Notes.
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Note 11—Stock-based Compensation
Incentive Award Plan
The Company has established the EnVen Energy Corporation and Energy Ventures GoM LLC 2015 Incentive Award Plan (the “2015 Plan”) which authorizes the granting of Restricted Stock, stock options, performance bonuses, and other incentive awards to eligible employees, consultants, and members of its Board. Pursuant to the 2015 Plan, the Company was authorized to award up to 2,583,301 shares of its Class A Common Stock. On December 13, 2018, the Company amended the 2015 Plan (“2015 Plan Amendment”) and all of the awards granted on or after December 13, 2018 will be granted under the 2015 Plan Amendment. Pursuant to the 2015 Plan Amendment, the Company is authorized to award up to 2,720,000 shares of its Class A Common Stock. As of December 31, 2021, the Company had 617,827 shares of its Class A Common Stock available for grant under the 2015 Plan Amendment and all incentive awards granted to date have been to employees or members of its Board.
Restricted Stock Awards and Units
The Company awards time-vested and performance-based non-qualified Restricted Stock subject to the terms, restrictions, and vesting requirements defined in the restricted stock agreements. Additionally, the Company has employment agreements with certain employees with varying terms that provide for, among other things, the accelerated vesting of all non-vested equity awards upon the (i) retirement after the eligible age of 65 or (ii) termination of employment without cause (the “Accelerated Vesting Conditions”).
The Company’s Restricted Stock does not have any post-vesting restrictions, therefore, the fair value of each share of Restricted Stock on the date of the grant is determined based on the per share fair value of its Class A Common Stock on a minority, non-marketable basis. The per share fair value of the Company’s Class A Common Stock is estimated at the grant date of the shares. Refer to Note 5—Fair Value Measurements for a further discussion of the fair value of the Company’s Class A Common Stock. Substantially all of the Restricted Stock granted during the year ended December 31, 2021 was granted during the second quarter of 2021 and the Monte Carlo valuation for the granted Restricted Stock assumed a weighted-average risk-free interest rate of 0.3% and a weighted-average expected stock price volatility rate of 75.0%. All of the Restricted Stock granted during the year ended December 31, 2020 was granted during the second quarter of 2020 and the OPM valuation for the granted Restricted Stock assumed a risk-free interest rate of 0.2% and a 75.0% expected stock price volatility rate. All of the Restricted Stock granted during the year ended December 31, 2019 was granted during the first quarter of 2019 and the OPM valuation for the granted Restricted Stock assumed a risk-free interest rate of 2.3% and an expected stock price volatility rate of 65.0%.
During the years ended December 31, 2021, 2020 and 2019, the aggregate fair value of the vested Restricted Stock was $3.9 million, $13.2 million and $17.0 million, respectively, and the Company withheld 141,632 shares, 245,453 shares and 399,584 shares, respectively, of the vested Restricted Stock on behalf of the Restricted Stock holders to satisfy the related tax withholding obligations. Any shares withheld in connection with such tax withholdings will be available for new grants.
Additionally, during the year ended December 31, 2021, the Company repurchased and retired 131,405 vested Restricted Stock shares from current employees for $2.0 million, the aggregate fair value of the vested Restricted Stock on the date of the repurchase. The repurchased shares are not available for new grants.
Time-based Restricted Stock
The Company awards time-vested non-qualified Restricted Stock subject to the terms, restrictions, and vesting requirements defined in the restricted stock agreements. Time-vested Restricted Stock contains a vesting period subject to the Restricted Stock holder continuing employment or service and generally vests in installments over a period of three years.
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The Company recognizes compensation expense related to time-based Restricted Stock on a straight-line basis over the requisite service period based on the fair value of the Restricted Stock on the grant date. In accordance with ASC Topic 718, Compensation—Stock Compensation, for the time-vested Restricted Stock subject to Accelerated Vesting Conditions, as discussed above, the Company considers the accelerated vesting when determining the requisite service period over which to recognize the compensation expense and utilizes the lesser of the stated service period or the period in which the Restricted Stock holder is no longer required to continue employment or service.
The following table presents the Company’s time-based Restricted Stock activity for the periods indicated:
| Time-based Restricted Stock |
Weighted Average Grant Date Fair Value |
|||||||
| Year ended December 31, 2019: |
||||||||
| Non-vested at the beginning of the period |
1,133,651 | $ | 14.69 | |||||
| Granted |
366,900 | $ | 18.13 | |||||
| Vested |
(543,338 | ) | $ | 15.58 | ||||
| Forfeitures |
(78,860 | ) | $ | 16.40 | ||||
|
|
|
|||||||
| Non-vested at the end of the period |
878,353 | $ | 17.00 | |||||
|
|
|
|||||||
| Year ended December 31, 2020: |
||||||||
| Non-vested at the beginning of the period |
878,353 | $ | 17.00 | |||||
| Granted |
390,903 | $ | 8.72 | |||||
| Vested |
(549,072 | ) | $ | 18.74 | ||||
| Forfeitures |
(26,700 | ) | $ | 18.12 | ||||
|
|
|
|||||||
| Non-vested at the end of the period |
693,484 | $ | 13.14 | |||||
|
|
|
|||||||
| Year ended December 31, 2021: |
||||||||
| Non-vested at the beginning of the period |
693,484 | $ | 13.14 | |||||
| Granted |
434,616 | $ | 13.98 | |||||
| Vested |
(354,706 | ) | $ | 14.45 | ||||
| Forfeitures |
(14,129 | ) | $ | 12.42 | ||||
|
|
|
|||||||
| Non-vested at the end of the period |
759,265 | $ | 12.82 | |||||
|
|
|
|||||||
During the years ended December 31, 2021, 2020 and 2019, the Company recognized compensation expense related to time-vested Restricted Stock of $5.1 million, $4.2 million and $9.7 million, respectively. As of December 31, 2021, there was $3.6 million of unrecognized compensation expense related to time-vested Restricted Stock, which is expected to be recognized over a weighted average period of 1.3 years.
Performance-based Restricted Stock
The Company awards performance-based non-qualified Restricted Stock subject to the terms, restrictions, and vesting requirements defined in the restricted stock agreements. Performance-based Restricted Stock vests only if the Company achieves certain performance goals during a predetermined performance period. Depending on the performance metric, the vesting of certain performance-based Restricted Stock is subject to the Restricted Stock holder fulfilling varying employment conditions. Pursuant to certain employment agreements which contain Accelerated Vesting Conditions, the performance-based Restricted Stock subject to accelerated vesting may be
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deemed to have been achieved at maximum performance levels. When the level of a performance metric is determined, the Company considers any difference between the number of awards associated with the maximum and the actual performance level as canceled.
The Company periodically assesses the probability that the performance conditions associated with its performance-based Restricted Stock will be achieved and recognizes compensation expense related to its the performance-based Restricted Stock at the time the performance condition is deemed probable of occurring, based on the fair value of the Restricted Stock on the grant date. If necessary, compensation expense related to performance-based Restricted Stock is adjusted based on the probability of the level of achievement of the performance metric. For the performance-based Restricted Stock subject to Accelerated Vesting Conditions, as noted above, the Company considers the accelerated vesting when determining the requisite service period over which to recognize the compensation expense and utilizes the lesser of the stated performance period or the period in which the Restricted Stock holder is no longer required to continue employment or service. If the performance-based Restricted Stock awards are subject to Accelerated Vesting Conditions because the employee has reached the eligible retirement age, the compensation expense associated with those awards reflects the number of awards that are expected to vest, including those deemed to be achieved at maximum performance levels, as adjusted for the awards that ultimately vest prior to the actual retirement of relevant employees.
The following table presents the Company’s performance-based Restricted Stock activity for the periods indicated:
| Performance-based Restricted Stock |
Weighted Average Grant Date Fair Value |
|||||||
| Year ended December 31, 2019: | ||||||||
| Non-vested at the beginning of the period |
789,888 | $ | 14.89 | |||||
| Granted |
502,817 | $ | 18.13 | |||||
| Vested |
(460,385 | ) | $ | 15.04 | ||||
| Forfeitures |
(99,404 | ) | $ | 12.67 | ||||
|
|
|
|||||||
| Non-vested at the end of the period |
732,916 | $ | 16.89 | |||||
|
|
|
|||||||
| Year ended December 31, 2020: | ||||||||
| Non-vested at the beginning of the period |
732,916 | $ | 16.89 | |||||
| Granted |
462,265 | $ | 8.71 | |||||
| Vested |
(114,466 | ) | $ | 17.08 | ||||
| Forfeitures |
(43,027 | ) | $ | 18.33 | ||||
| Canceled |
(144,614 | ) | $ | 18.19 | ||||
|
|
|
|||||||
| Non-vested at the end of the period |
893,074 | $ | 12.37 | |||||
|
|
|
|||||||
| Year ended December 31, 2021: | ||||||||
| Non-vested at the beginning of the period |
893,074 | $ | 12.37 | |||||
| Granted |
528,317 | $ | 13.46 | |||||
| Vested |
(95,763 | ) | $ | 8.72 | ||||
| Forfeitures |
(25,715 | ) | $ | 14.48 | ||||
| Canceled |
(223,507 | ) | $ | 8.72 | ||||
|
|
|
|||||||
| Non-vested at the end of the period |
1,076,406 | $ | 13.51 | |||||
|
|
|
|||||||
A portion of the performance-based Restricted Stock granted will vest based on the achievement of certain performance metrics in future years. As of December 31, 2021, the performance metrics associated with 384,774 shares, net of forfeitures, granted in June 2020 and May 2021 have not been established; therefore, the Company cannot yet determine the grant date or the fair value of these shares and is considering the shares as issued, but not yet granted. During the year ended December 31, 2021, the baseline for a performance metric
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associated with 191,372 shares of performance-based Restricted Stock granted in March 2019 and June 2020 was finalized, as a result, these shares are considered granted during the year ended December 31, 2021 and are presented as such in the table above.
During the years ended December 31, 2021, 2020 and 2019, the Company recognized compensation expense of $6.1 million, $0.7 million, and $5.7 million, respectively, for performance-based Restricted Stock for which performance metrics were deemed probable of occurring or is subject to accelerated vesting. As of December 31, 2021, there was less than $0.1 million of unrecognized compensation expense related to these performance-based Restricted Stock shares, which is expected to be recognized over a weighted average period of one year.
As of December 31, 2021, there was $7.7 million of total unrecognized compensation expense related to performance-based Restricted Stock. As discussed above, the performance metrics for certain of the performance-based Restricted Stock issued in June 2020 and May 2021 have not been established; therefore, the Company cannot yet determine the grant date or the related fair value and compensation expense associated with those performance-based shares.
Stock Options
The Company had previously awarded non-qualified stock options, which represent the right to purchase its Class A Common Stock at a specified price (“Stock Option”). The Company did not grant any Stock Options during the years ended December 31, 2021, 2020 or 2019 and as of January 1, and December 31, 2021, all of the 682,650 outstanding Stock Options were vested and exercisable. As of December 31, 2021, all of the Company’s outstanding Stock Options have an exercise price of $10.00 and a weighted average remaining contractual term of 3.9 years. The Company recognized compensation expense related to Stock Options of less than $0.1 million during the year ended December 31, 2019 and did not recognize any compensation expense related to Stock Options during the years ended December 31, 2021 and 2020.
Note 12—Employee Benefit Plan
Defined-Contribution Plan
The Company has a qualified, contributory 401(k) savings plan for all eligible employees. Eligible employees may contribute up to 90% of gross compensation, up to the limits set by the Internal Revenue Service, into the plan and the Company can make matching contributions or can contribute discretionary amounts, at their determination at the end of each year. During the years ended December 31, 2021, 2020 and 2019, the Company contributed $1.1 million, $1.0 million and $1.1 million, respectively, to the defined contribution plan.
Note 13—Concentrations of Risk
Major Customers
During the years ended December 31, 2021, 2020 and 2019, Shell Offshore Inc. accounted for approximately 85.2%, 84.5% and 87.0%, respectively, of the Company’s total revenues and was the only purchaser to account for more than 10% of the Company’s total revenue during those periods. However, based on the adequate number of potential other purchasers, the Company does not believe that the loss of any major customer would have a significant effect on its results of operations or financial position.
Accounts Receivable
The Company does not require its oil and natural gas purchasers to post collateral and an inability or failure of any its significant customers to meet their obligations or their insolvency or liquidation could adversely affect its financial results. The Company evaluates the credit standing of its oil and natural gas purchasers as it deems appropriate under the circumstances, which may include reviewing a purchaser’s credit rating, latest financial
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information, their historical payment record, the financial ability of the purchaser’s parent company to make payment if the purchaser cannot, and undertaking the due diligence necessary to determine credit terms and credit limits.
Derivative Instruments
The Company’s use of derivative instruments exposes it to the risk that its derivative counterparties will be unable to meet their commitments under the arrangements. The Company manages this risk by using multiple counterparties, all of which are registered swap dealers that have an “investment grade” credit rating. The Company continually monitors the creditworthiness of its derivative counterparties to determine if any credit risk adjustment is necessary to the fair values of its derivative instruments or if any nonperformance risk exists. Since all of the Company’s derivative counterparties are large financial institutions with investment-grade credit ratings, the Company believes it does not have any significant credit risk associated with its counterparties and does not currently anticipate any nonperformance from its counterparties.
Note 14—Commitments and Contingencies
Legal Proceedings
From time to time, the Company could be subject to legal actions and claims arising in the ordinary course of business. It is the opinion of management that the outcome of these matters will not have a material adverse effect on the Company’s financial position or results of operations.
In June 2019, David M. Dunwoody, Jr., former President of the Company, filed a lawsuit against the Company in Texas District Court alleging that the circumstances of his resignation constituted “Good Reason” under his employment agreement dated as of November 6, 2015 (the “Employment Agreement”), and entitled him to the severance payments and benefits as set forth in his Employment Agreement for a resignation for “Good Reason.” In September 2021, the trial court entered a judgment of $12.4 million in favor of Mr. Dunwoody, inclusive of Mr. Dunwoody’s legal fees and interest, which the Company has recorded as a non-current liability on its consolidated balance sheet as of December 31, 2021. The Company disagrees with many of the trial court’s rulings and does not agree with Mr. Dunwoody’s assertion that he had “Good Reason” to resign from his employment. The Company expects the appellate process to continue for the foreseeable future.
In July 2019, the Company filed a lawsuit against Mr. Dunwoody in Delaware Chancery Court for breach of fiduciary duty and equitable fraud relating to Mr. Dunwoody’s conduct while he was President of the Company. In January 2020, the Company filed an amended complaint that added claims against Oilfield Pipe of Texas, LLC for aiding and abetting Mr. Dunwoody’s breach of his fiduciary duty and equitable fraud. Although this case has been stayed pending resolution of the Texas litigation, in October 2021, the Delaware Chancery Court allowed the parties to proceed with motion practice. The Company expects this case to continue for the foreseeable future.
The Company may recognize additional liabilities and expenses in future periods related to this litigation with Mr. Dunwoody.
Environmental Compliance
During the third quarter of 2018, the Company conducted an internal investigation, led by outside counsel, surrounding certain instances of environmental noncompliance at the Company owned Cognac platform located in the U.S. Gulf of Mexico Mississippi Canyon block 194. The Company made self-disclosures to the Environmental Protection Agency (the “EPA”) and also reported to the Bureau of Safety and Environmental Enforcement. By a letter dated June 26, 2019, the EPA notified the Company that it had concluded its inquiry into these matters and recommended that the Company not be prosecuted criminally. There are no asserted
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claims by any agency arising out of these matters. Based on the letter, the Company reversed its previously recorded $2.0 million contingent liability related to these matters during the three months ended June 30, 2019.
Asset Retirement Obligations
Marathon Acquisition. In December 2015, the Company acquired its ownership interests and the operatorship of the U.S. Gulf of Mexico Ewing Bank 873, 917, and 963, including the Lobster platform (collectively, “Lobster”), a subsea facility, and 29 wells and the ownership interest in the U.S. Gulf of Mexico Vioska Knoll 742, 786, and 830, including 23 wells, from Marathon Oil Corporation. Additionally, in February 2016, the Company acquired a 30% ownership interest in the Neptune field from Marathon Oil Corporation. Pursuant to the agreements, the Company was required to deposit approximately $100.0 million into escrow accounts to use for future P&A obligation costs assumed in the acquisitions. In December 2015, the Company deposited approximately $30.0 million into escrow to fully fund one of the P&A obligations and funded the remaining $70.0 million obligation by depositing a percentage of net revenues from the acquired properties into a separate escrow account, on a quarterly basis, beginning in January 2017 until October 2021. As of December 31, 2021, the escrow accounts are fully funded and the Company has no remaining future funding obligations. As of December 31, 2021 and 2020, these escrow accounts are reflected as Restricted cash on the consolidated balance sheets and have combined balances of $100.7 million and $85.9 million, respectively, inclusive of interest earned to date.
Notes receivable, net. The Company holds two notes receivables which consist of commitments from the sellers of oil and natural gas properties, acquired by the Company, related to the costs associated with its performance of the assumed P&A obligations. The Company records the change in the current estimated credit losses related to its P&A Notes Receivable into Interest income and other on the accompanying consolidated statements of operations. During the years ended December 31, 2021, 2020 and 2019, the Company recognized interest income of $2.6 million, $5.4 million and $5.0 million, respectively, and the carrying values of these P&A Notes Receivable, net of current expected credit losses, were $65.1 million and $62.5 million as of December 31, 2021 and 2020, respectively.
Additionally, with the adoption of ASU 2016-13 on January 1, 2020, the Company has recorded cumulative effect adjustments of $0.6 million and $0.1 million to its Accumulated deficit and Non-controlling interest, respectively, balances as of January 1, 2020 to reflect the estimated credit losses for its P&A Notes Receivable.
Other obligations. The Bureau of Ocean Management and certain third-parties require the Company to post supplemental and performance bonds as a means to ensure its decommissioning obligations, such as the plugging of wells, the removal of platforms and other offshore facilities, the abandonment of offshore pipelines, and the clearing of the seafloor of obstructions. If needed, the Company may enter into arrangements with surety companies who provide such bonds on its behalf. In exchange, the Company pays an annual premium to the surety for its financial strength to extend the credit. These surety bond premiums are recognized in Prepaid expenses and other current assets on the accompanying consolidated balance sheets and amortized over the life of the surety bonds into Interest expense on the accompanying consolidated statements of operations. During the years ended December 31, 2021, 2020 and 2019, the Company paid $12.9 million, $13.3 million and $12.5 million, respectively, for surety bond premiums and amortized $10.7 million, $10.2 million and $13.7 million, respectively, of the premiums into Interest expense on the accompanying consolidated statements of operations.
Additionally, these arrangements could require the Company to provide cash collateral to support the issuance of these bonds. During the year ended December 31, 2019, the Company’s surety providers, at their discretion, released all of the previously provided cash collateral back to the Company. The Company did not provide any cash collateral to sureties during the years ended December 31, 2021 and 2020.
F-41
Notes Payable
On June 15, 2019, the Company entered into a note payable agreement to finance a portion of its commercial insurance premiums for a total of $8.4 million. The note payable had an annual interest rate of 3.7% and required monthly payments beginning on June 15, 2019 through April 15, 2020. In January 2020, the Company paid the remaining principal and interest of $3.1 million related to this note, resulting in a zero balance as of December 31, 2020.
On December 30, 2019, the Company entered into a financing agreement for payments due under a licensing agreement for seismic data, paying an initial installment of $3.0 million in the first quarter of 2020, and agreeing to pay eight quarterly installments of $2.2 million beginning on July 1, 2020 through April 1, 2022, at an imputed interest rate of 4.75%. Per the agreement, the Company paid $8.9 million and $7.5 million during the years ended December 31, 2021 and 2020, respectively. As of December 31, 2021, the outstanding balance of this note payable was $4.4 million, all of which is recorded as a current note payable. As of December 31, 2020, the outstanding balance of this note payable was $12.9 million, $4.4 million of which was recorded as a long-term note payable and $8.5 million of which was recorded as a current note payable.
Revenue Performance Obligations
Generally, all of the Company’s sales contracts, other than its production handling service contracts discussed further below, are short-term in nature with a contract term of one year or less. As such, the Company has elected to utilize the practical expedient within ASC Topic 606, Revenue from Contracts with Customers (“ASC 606”) exempting it from the disclosure of the transaction price allocated to the remaining performance obligations if the performance obligation is part of a contract that has an original expected duration of one year or less. Additionally, under the Company’s contracts, each unit of product represents a separate wholly unsatisfied performance obligation for which the variable payment relates specifically to the efforts to satisfy that performance obligation and allocating the variable consideration is consistent with the allocation objective. Therefore, the disclosure of the transaction price allocated to the remaining performance obligations is not required under ASC 606-10-32-40.
In July 2020, the Company executed a new production handling agreement with the other working interest partners for the U.S. Gulf of Mexico Ewing Banks blocks 877 and 921 (“Spruance”) field to be tied back with a 14 mile subsea line to its owned and operated Lobster facility for production processing. As of December 31, 2021, the Company had approximately $17.0 million of remaining performance obligations related to its production handling service contracts with expected durations of one to twelve years. During the years ended December 31, 2021, 2020 and 2019, the Company recognized $1.7 million, $1.8 million and $1.8 million, respectively, of revenue related to its production handling service contracts performance obligations. The Company expects to recognize approximately $3.0 million, $2.0 million, and $1.2 million of the remaining performance obligations as revenue annually over the next three years and the remaining amount allocated to those performance obligations ratably over the following nine years. The transaction price for these contracts is comprised of both fixed and variable consideration which is resolved monthly as the distinct service is provided. The fixed consideration typically relates to monthly minimum fees or production system operation fees. The variable consideration may include operating, infrastructure access, and production handling fees which are based on either contractual rates for units of production serviced or a proportionate expense fee.
Note 15—Leases
Office space and information technology equipment leases. The Company has several operating leases for office space and IT Equipment used in its daily operations, for which it records the related lease costs as G&A expenses on the accompanying consolidated statements of operations.
F-42
The following table presents the components of the Company’s office space and IT Equipment operating lease costs during the periods indicated:
| Year Ended December 31, | ||||||||||||
| 2021 | 2020 | 2019 | ||||||||||
| (In thousands) | ||||||||||||
| Office space and IT equipment operating lease costs |
$ | 2,896 | $ | 3,091 | $ | 1,329 | ||||||
| Short-term office space and IT equipment operating lease cost (1) |
— | — | 178 | |||||||||
| Variable office space and IT equipment operating lease costs |
1,461 | 399 | 666 | |||||||||
|
|
|
|
|
|
|
|||||||
| Total office space and IT equipment operating lease costs |
$ | 4,357 | $ | 3,490 | $ | 2,173 | ||||||
|
|
|
|
|
|
|
|||||||
| (1) | None of the total office space and IT equipment operating lease costs for the years ended December 31, 2021 and 2020 relate to short-term leases. |
During the years ended December 31, 2021, 2020 and 2019, the Company made cash payments related to its office space and IT Equipment leases of $3.8 million, $1.0 million and $2.1 million, respectively, which are included in its cash flows from operating activities on the accompanying consolidated statements of cash flows. Additionally, during the year ended December 31, 2019, the Company incurred costs of $4.7 million to bring its new office space leases to the condition of its intended use, which is included in cash flows from investing activities on the accompanying consolidated statement of cash flows and in ROU assets on the accompanying consolidated balance sheet upon the commencement of the leases.
Drilling rig operating leases. In accordance with the full cost method of accounting for oil and natural gas properties, the Company capitalizes the portion of its lease costs which relate to its drilling rig operating leases as part of its oil and natural gas property balance.
The following table presents the components of the Company’s drilling rig operating leases capitalized during the periods indicated:
| Year Ended December 31, | ||||||||||||
| 2021 | 2020 | 2019 | ||||||||||
| (In thousands) | ||||||||||||
| Drilling rig operating lease costs, excluding short-term |
$ | 11,717 | $ | 17,344 | $ | 23,316 | ||||||
| Short-term drilling rig operating lease costs (1) |
— | 5,817 | 13,034 | |||||||||
| Variable drilling rig operating lease costs (1) |
1,427 | 1,647 | 1,761 | |||||||||
|
|
|
|
|
|
|
|||||||
| Total drilling rig operating lease costs |
$ | 13,144 | $ | 24,808 | $ | 38,111 | ||||||
|
|
|
|
|
|
|
|||||||
| (1) | The short-term and variable drilling rig operating lease costs incurred during the year ended December 31, 2021 are not indicative of the Company’s current short-term lease obligations, which are approximately $8.7 million, or its future short-term lease costs and obligations, as it routinely enters into short-term contracts for the use of drilling rigs to support its drilling activities. |
Additionally, during the years ended December 31, 2021, 2020 and 2019, the Company recognized $0.5 million, $0.4 million and $1.0 million, respectively, of drilling rig operating lease costs related to P&A costs, inclusive of immaterial amounts of variable lease costs.
F-43
During the years ended December 31, 2021, 2020 and 2019, the Company made cash payments of $19.8 million, $45.9 million and $44.8 million, respectively, related to its drilling rig operating lease costs, $14.2 million, $24.7 million and $33.4 million, respectively, of which are included in its cash flows from investing activities on the accompanying consolidated statements of cash flows.
Total lease liabilities. As of December 31, 2021, the Company had total lease liabilities of $19.1 million on the accompanying consolidated balance sheet. To determine the present value of its future lease payments as of December 31, 2021, the Company applied a weighted average incremental borrowing rate of 5.6% and a weighted average remaining lease term of 7.5 years. During the year ended December 31, 2021, the Company recognized an additional $14.9 million in both ROU asset and lease liabilities.
As of December 31, 2021, the Company’s lease liabilities consisted of the following:
| (In thousands) | ||||
| Future lease payments due: |
||||
| January 1, 2022 through December 31, 2022 |
$ | 5,032 | ||
| January 1, 2023 through December 31, 2023 |
2,318 | |||
| January 1, 2024 through December 31, 2024 |
2,272 | |||
| January 1, 2025 through December 31, 2025 |
2,138 | |||
| January 1, 2026 through December 31, 2026 |
2,179 | |||
| Thereafter |
9,146 | |||
|
|
|
|||
| Total future lease payments (1) |
23,085 | |||
|
|
|
|||
| Less: present value discount |
(3,957 | ) | ||
|
|
|
|||
| Total lease liabilities as of December 31, 2021 |
$ | 19,128 | ||
|
|
|
| (1) | As of December 31, 2021, total future lease payments include payments of $2.7 million, $20.0 million, and $0.4 million for drilling rigs, office space, and IT equipment, respectively. Payments for drilling rigs are presented on a gross basis and do not reflect the Company’s net proportionate share of such amounts, as the Company will bill other joint interest owners for their working interest share of such costs. The Company’s share of the drilling rig costs are generally capitalized as part of its oil and natural gas property balance. |
Note 16—Income Taxes
Following the consummation of the Class B Common Stock Conversion in April 2021, as discussed in Note 1—Organization and Basis of Presentation, the Company will file consolidated tax returns for 100% of the activity of its subsidiary, EnVen GoM, which is treated as a partnership for U.S. income tax purposes. For accounting and tax purposes, the EnVen GoM partnership activity includes the activities of various single member limited liability companies, which are wholly-owned by EnVen GoM. All references to EnVen GoM also include the related activities of such lower-tier entities.
Deferred taxes related to EnVen GoM’s activities are recorded based upon the difference between the financial statement basis of the Company’s consolidated investment in EnVen GoM and the Company’s outside tax basis in its consolidated interest in EnVen GoM (not including the Company’s share of EnVen GoM consolidated tax liabilities). Following the consummation of the Class B Common Stock Conversion in April 2021, as the Company consolidates its financial statements, the financial statement basis in EnVen GoM is generally equal to the net equity of EnVen GoM. The Company’s outside tax basis in EnVen GoM is computed as the sum of the Company’s contributions to EnVen GoM plus its share of allocable items of EnVen GoM taxable income less its share of allocable items of EnVen GoM tax deductions, losses, non-deductible expenses, and distributions.
F-44
On March 27, 2020, the U.S. Coronavirus Aid, Relief, and Economic Security Act (the “CARES Act“) was signed into law. The CARES Act is an economic stimulus package designed to aid in offsetting the economic damage caused by the ongoing coronavirus pandemic and includes various changes to U.S. income tax regulations. The CARES Act permits the carryback of certain net operating losses that under previous law were only available to be carried forward. As a result, during the year ended December 31, 2021, the Company received an income tax refund of $5.8 million for a net operating loss carryback claim for 2019. Additionally, the Company applied an income tax refund of $9.7 million for a net operating loss carryback claim for 2020 to its income tax liability for the tax year ending December 31, 2021. Therefore, the Company has recorded a $2.7 million current income tax payable on its consolidated balance sheet as of December 31, 2021, which includes its applied income tax refund for the net operating loss carryback claim and an estimate of the current income tax impact through December 31, 2021.
For the years ended December 31, 2021, 2020 and 2019, the Company had an income tax expense (benefit) of $11.3 million, $(18.3) million and $(0.5) million, respectively. The Company’s provision (benefit) for income taxes is comprised of the following items for the period indicated:
| Year Ended December 31, | ||||||||||||
| 2021 | 2020 | 2019 | ||||||||||
| (In thousands) | ||||||||||||
| Current income tax expense (benefit): |
||||||||||||
| United States federal |
$ | 13,965 | $ | (25,130 | ) | $ | (485 | ) | ||||
| Louisiana |
472 | — | — | |||||||||
|
|
|
|
|
|
|
|||||||
| Total current income tax expense (benefit) |
14,437 | (25,130 | ) | (485 | ) | |||||||
| Deferred income tax expense: |
||||||||||||
| United States federal |
(3,130 | ) | 6,796 | — | ||||||||
|
|
|
|
|
|
|
|||||||
| Total deferred income tax expense |
(3,130 | ) | 6,796 | — | ||||||||
|
|
|
|
|
|
|
|||||||
| Total income tax expense (benefit) |
$ | 11,307 | $ | (18,334 | ) | $ | (485 | ) | ||||
|
|
|
|
|
|
|
|||||||
The difference in the Company’s income tax provision calculation using its effective rate rates of 22.3%, 62.7% and 2.8% for the years ended December 31, 2021, 2020 and 2019, respectively, from the amounts calculated by applying the U.S. federal income tax rate of 21% to its pretax income from continuing operations were due to the following items for the periods indicated:
| Year Ended December 31, | ||||||||||||
| 2021 | 2020 | 2019 | ||||||||||
| (In thousands, except percentages) | ||||||||||||
| Expected tax expense (benefit) provision |
$ | (10,667 | ) | $ | (6,140 | ) | $ | 3,664 | ||||
| Increase (decrease) in income taxes resulting from: |
||||||||||||
| Adjustments for non-controlling interest |
996 | 571 | (373 | ) | ||||||||
| Excess tax expense (benefit) from stock-based compensation |
424 | (606 | ) | (5,345 | ) | |||||||
| State income taxes |
373 | — | — | |||||||||
| Rate differential for net operating loss carryforwards |
— | (5,565 | ) | — | ||||||||
| Permanent differences |
765 | 144 | 319 | |||||||||
| Valuation allowance |
22,269 | (6,861 | ) | 1,096 | ||||||||
F-45
| Year Ended December 31, | ||||||||||||
| 2021 | 2020 | 2019 | ||||||||||
| (In thousands, except percentages) | ||||||||||||
| Reclassification of a stranded deferred tax balance(1) |
(3,130 | ) | — | — | ||||||||
| Return to provision and other adjustments |
277 | 123 | 154 | |||||||||
|
|
|
|
|
|
|
|||||||
| Income tax expense (benefit) |
$ | 11,307 | $ | (18,334 | ) | $ | (485 | ) | ||||
|
|
|
|
|
|
|
|||||||
| Effective tax rate |
22.3 | % | (62.7 | )% | (2.8 | )% | ||||||
| (1) | During the year ended December 31, 2021, the Company recorded a deferred income tax benefit of $3.1 million for the recognition of a stranded deferred tax balance in Accumulated other comprehensive income associated with the credit risk adjustment on its 2023 Notes, which were repurchased in April 2021. Refer to Note 8—Long-term Debt for a further discussion of the 2023 Notes. |
As of December 31, 2021, the Company has a gross deferred tax asset with respect to its investment in the underlying partnership and no gross deferred tax liability, resulting in a net deferred tax asset which is subject to a full valuation allowance. Any temporary differences between the book and tax earnings of the underlying partnership that are allocated to the Company affect the components of the net deferred tax asset balance. However, since the valuation allowance is applied to the net deferred tax asset, the temporary differences do not produce a deferred tax benefit or expense which would otherwise offset the current tax effect of the temporary differences between book and taxable income. The Company has considered all available positive and negative evidence related to the realization of its net deferred tax asset and has determined it is not more likely than not to be realized. As such, the Company has recorded a 100% valuation allowance against its net deferred tax asset as of December 31, 2021.
The components of the Company’s net deferred tax asset and liability were as follows for the periods indicated:
| December 31, 2021 | December 31, 2020 | |||||||
| (In thousands) | ||||||||
| Deferred tax asset: |
||||||||
| Net operating loss carryforward |
$ | — | $ | — | ||||
| Interest expense carryforward |
— | — | ||||||
| Other |
— | — | ||||||
| Investment in partnership |
$ | 22,269 | $ | — | ||||
|
|
|
|
|
|||||
| Net deferred tax asset |
22,269 | — | ||||||
| Valuation allowance |
(22,269 | ) | — | |||||
|
|
|
|
|
|||||
| Deferred tax asset, net of valuation allowance |
$ | — | $ | — | ||||
|
|
|
|
|
|||||
| Deferred tax liability: | ||||||||
| Investment in partnership |
$ | — | $ | (9,648 | ) | |||
|
|
|
|
|
|||||
| Deferred tax liability |
$ | — | $ | (9,648 | ) | |||
|
|
|
|
|
|||||
For the year ending December 31, 2021, the Company presents its Other comprehensive (loss) income net of a deferred income tax benefit of $2.2 million. Additionally, the Company presents the Class B Common Stock Conversion and TRA Settlement transactions on its consolidated statement of changes in equity for the year ending December 31, 2021 net of a deferred income tax benefit of $4.5 million. For the year ending December 31, 2020, the Company presents its Other comprehensive (loss) income net of deferred income tax expense of $4.5 million and presents the changes in ownership due to Series A preferred stock dividends on its consolidated statement of changes in equity for the year ending December 31, 2020 net of deferred income tax expense of $0.7 million.
F-46
The 2018 through 2020 tax years remain open to examination by the tax jurisdictions in which the Company is subject to tax. The statute of limitations with respect to the U.S. federal and state income tax returns of the Company for the year ended December 31, 2017 and prior are closed (except to the extent of any net operating loss carryover balances).
Note 17—Supplemental Cash Flow Information
The following table presents a reconciliation of cash, cash equivalents, and restricted cash reported on the accompanying consolidated statements of cash flows for the periods indicated:
| December 31, | ||||||||||||||||
| 2021 | 2020 | 2019 | 2018 | |||||||||||||
| (In thousands) | ||||||||||||||||
| Cash and cash equivalents |
$ | 88,930 | $ | 56,009 | $ | 122,175 | $ | 121,184 | ||||||||
| Current portion of restricted cash (1) |
— | — | — | 354 | ||||||||||||
| Long-term portion of restricted cash (1) |
100,695 | 89,479 | 71,361 | 80,706 | ||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Total cash, cash equivalents, and restricted cash |
$ | 189,625 | $ | 145,488 | $ | 193,536 | $ | 202,244 | ||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| (1) | Current and long-term restricted cash primarily consists of restricted cash held for future P&A obligations, refer to Note 14—Commitments and Contingencies for further discussion of these P&A obligations. |
The following table presents non-cash investing and financing activities and supplemental disclosure relating to cash paid for interest and income taxes for the periods indicated:
| Year Ended December 31, | ||||||||||||
| 2021 | 2020 | 2019 | ||||||||||
| (In thousands) | ||||||||||||
| Non-cash investing and financing activities: |
||||||||||||
| Expenditures for property and equipment in accrued liabilities |
$ | (640 | ) | $ | (19,513 | ) | $ | 5,982 | ||||
| Expenditures for unevaluated oil and natural gas leases in accrued liabilities |
(5,879 | ) | 5,879 | — | ||||||||
| Neptune Acquisition closing adjustments (1) |
(464 | ) | — | — | ||||||||
| Changes in asset retirement obligations (2) |
31,111 | 2,753 | (55,483 | ) | ||||||||
| Lease cost property additions |
(18 | ) | (85 | ) | 41 | |||||||
| Note payable issued for insurance premiums |
— | — | 8,376 | |||||||||
| Note payable issued for seismic data |
— | — | 19,617 | |||||||||
| Series A preferred stock dividends—paid-in-kind (3) |
(6,484 | ) | (23,709 | ) | (20,490 | ) | ||||||
| Series A preferred stock dividends—beneficial conversion feature (4) |
28,267 | — | (10,180 | ) | ||||||||
| Supplemental disclosure: |
||||||||||||
| Interest paid on debt, net of amounts capitalized |
$ | 37,160 | $ | 37,582 | $ | 36,368 | ||||||
| Income taxes paid |
1,950 | — | 8,200 | |||||||||
| (1) | Reflects the remaining cash payment from BHP received in January 2022 for the Neptune Acquisition, refer to Note 3—Acquisitions of Oil and Natural Gas Properties for a further discussion. |
| (2) | The non-cash changes in asset retirement obligations for the years ended December 31, 2021 and 2020 reflect the Company’s revisions of previous asset retirement obligation estimates. Additionally, the non-cash changes in asset retirement obligations for the year ended December 31, 2021 includes the future P&A obligations assumed by the Company in the Neptune Acquisition, refer to Note 3—Acquisitions of Oil and Natural Gas Properties for a further discussion. |
F-47
| (3) | In the first quarter of 2021 and during the year ended December 31, 2020, the Company paid the quarterly Series A Preferred Stock dividends by issuing PIK Shares. However, in the second, third, and fourth quarters of 2021, the Company’s Board elected to pay the dividends in cash rather than issuing PIK Shares. |
| (4) | Reflects the cumulative effect adjustment for the adoption of ASU 2020-06 to reverse the beneficial conversion feature associated with the Company’s Series A Preferred Stock PIK Share dividends outstanding as of January 1, 2021. Refer to Note 1—Organization and Basis of Presentation—Recently Adopted Accounting Standards for a further discussion of the adoption of ASU 2020-06. |
Note 18—Subsequent Events
The Company has evaluated subsequent events from the balance sheet date as of December 31, 2021 through February 28, 2022, the date at which these consolidated financial statements were available to be issued and has determined there are no other events to disclose.
Note 19—Supplemental Oil and Natural Gas Disclosures (Unaudited)
Costs Incurred in Oil and Natural Gas Property Acquisition, Exploration, and Development Activities
The following table presents the costs incurred in oil and natural gas acquisition, exploration, and development activities for the periods indicated:
| Year Ended December 31, | ||||||||||||
| 2021 | 2020 | 2019 | ||||||||||
| (In thousands) | ||||||||||||
| Property acquisition costs: |
||||||||||||
| Proved properties |
$ | 5,831 | $ | — | $ | — | ||||||
| Unproved properties, not subject to amortization |
667 | 10,596 | 9,235 | |||||||||
|
|
|
|
|
|
|
|||||||
| Total property acquisition costs |
6,498 | 10,596 | 9,235 | |||||||||
| Exploration costs |
4,401 | 32,291 | 64,769 | |||||||||
| Development costs |
103,435 | 145,759 | 161,685 | |||||||||
|
|
|
|
|
|
|
|||||||
| Total costs incurred |
$ | 114,334 | $ | 188,646 | $ | 235,689 | ||||||
|
|
|
|
|
|
|
|||||||
For the year ended December 31, 2021, the Company’s development costs incurred include $17.4 million of asset retirement obligations costs, revisions, and liabilities incurred. All of the Company’s proved property acquisition costs incurred for the year ended December 31, 2021 relate to the Neptune Acquisition and include $14.5 million of asset retirement obligations costs assumed in the acquisition, refer to Note 3—Acquisitions of Oil and Natural Gas Properties for a further discussion. For the years ended December 31, 2020 and 2019, the Company’s development costs incurred include $3.1 million and $(57.6) million, respectively, of asset retirement obligation costs and. Additionally, during the years ended December 31, 2021, 2020 and 2019, the Company capitalized $2.3 million, $1.3 million and $1.3 million, respectively, of interest expense to unproved oil and natural gas properties related to certain significant long-term exploratory projects.
Proved Reserves
Proved reserves are those quantities of oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible, from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations, prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. There are numerous uncertainties inherent in estimating the quantities of proved oil and natural gas reserves and periodic revisions to estimated reserves and future cash flows may be necessary as a result of numerous factors,
F-48
including reservoir performance, new drilling, oil, natural gas, and NGL prices, changes in costs, technological advances, new geological or geophysical data, or other economic factors. Accordingly, reserve estimates may differ significantly from the quantities of oil and natural gas ultimately recovered or reserve quantities reported by other entities.
The Company’s reserve estimates as of December 31, 2021, 2020 and 2019, are based on estimates prepared in accordance with the rules and regulations of the Securities and Exchange Commission (“SEC”) in Regulation S-X, Rule 4-10. All of the Company’s proved reserves presented below are located in the U.S. Gulf of Mexico. The Company’s estimated proved reserves and the related net revenues and Standardized Measure were determined using the 12-month unweighted arithmetic average of the first-day-of-the-month price for each month in the period January through December (“SEC Prices”). For the years ended December 31, 2021, 2020 and 2019, SEC Prices used in the calculations were $66.55 per Bbl, $39.54 per Bbl and $55.85 per Bbl, respectively, for oil and NGL volumes and $3.60 per MMBtu, $1.99 per MMBtu and $2.58 per MMBtu, respectively, for natural gas volumes. The SEC Prices for oil and NGL volumes are adjusted by field for quality, transportation fees, and market differentials and the SEC Prices for natural gas volumes are adjusted by field for energy content, transportation fees, and market differentials. These prices are held constant throughout the lives of the oil and natural gas properties. For proved reserves as of December 31, 2021, 2020 and 2019, the average SEC Prices adjusted for the differentials, as discussed above, weighted by production over the remaining lives of the oil and natural gas properties were $64.58 per Bbl, $37.43 per Bbl and $60.19 per Bbl, respectively, for oil volumes and $4.95 per Mcf, $2.45 per Mcf and $3.25 per Mcf, respectively, for natural gas volumes.
The following table presents the quantities of the Company’s estimated proved, proved developed, and proved undeveloped oil, natural gas, and NGL reserves and the changes in the quantities of estimated proved oil, natural gas, and NGL reserves for the periods indicated:
| Oil (MBbl) |
Natural Gas (MMcf) |
NGLs (MBbl) |
Total (MBoe) |
|||||||||||||
| Proved reserves as of January 1, 2019 |
45,023 | 60,133 | 1,487 | 56,532 | ||||||||||||
| Revisions of previous estimates |
651 | (11,903 | ) | (440 | ) | (1,773 | ) | |||||||||
| Extensions and discoveries |
5,380 | 4,275 | 321 | 6,414 | ||||||||||||
| Production |
(7,649 | ) | (8,925 | ) | (218 | ) | (9,355 | ) | ||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Proved reserves as of December 31, 2019 |
43,405 | 43,580 | 1,150 | 51,818 | ||||||||||||
| Revisions of previous estimates |
(2,606 | ) | (3,194 | ) | (112 | ) | (3,250 | ) | ||||||||
| Extensions and discoveries |
3,348 | 2,307 | 225 | 3,958 | ||||||||||||
| Production |
(7,815 | ) | (8,267 | ) | (253 | ) | (9,446 | ) | ||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Proved reserves as of December 31, 2020 |
36,332 | 34,426 | 1,010 | 43,080 | ||||||||||||
| Revisions of previous estimates |
10,935 | 12,618 | 110 | 13,148 | ||||||||||||
| Extensions and discoveries |
915 | 577 | 40 | 1,051 | ||||||||||||
| Purchases of reserves |
1,591 | 387 | 29 | 1,685 | ||||||||||||
| Production |
(7,177 | ) | (7,005 | ) | (209 | ) | (8,554 | ) | ||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Proved reserves as of December 31, 2021 |
42,596 | 41,003 | 980 | 50,410 | ||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Proved developed reserves: |
||||||||||||||||
| January 1, 2019 |
33,274 | 45,830 | 1,129 | 42,041 | ||||||||||||
| December 31, 2019 |
35,811 | 36,906 | 752 | 42,714 | ||||||||||||
| December 31, 2020 |
29,876 | 29,977 | 779 | 35,651 | ||||||||||||
| December 31, 2021 |
36,281 | 36,930 | 854 | 43,290 | ||||||||||||
| Proved undeveloped reserves: |
||||||||||||||||
| January 1, 2019 |
11,749 | 14,303 | 358 | 14,491 | ||||||||||||
| December 31, 2019 |
7,594 | 6,674 | 398 | 9,104 | ||||||||||||
| December 31, 2020 |
6,456 | 4,449 | 231 | 7,429 | ||||||||||||
| December 31, 2021 |
6,315 | 4,073 | 126 | 7,120 | ||||||||||||
F-49
During the year ended December 31, 2021, EnVen added 7.3 MMBoe of estimated proved reserves, primarily due to positive revisions of 13.1 MMBoe, which include upward proved developed producing performance revisions of 6.2 MMBoe at several of its fields, as well as positive price revisions of 6.9 MMBoe due to increased SEC prices used in the estimation of proved reserves at December 31, 2021 compared to December 31, 2020. The Company also had 1.1 MMBoe of additional estimated proved reserves from extensions and discoveries as a result of its successful drilling activities at its operated Lobster field and 1.7 MMBoe of additional estimated proved reserves from the Neptune Acquisition completed in May 2021. These increases were partially offset by 8.6 MMBoe of production during the year ended December 31, 2021.
During the year ended December 31, 2020, the Company’s estimated proved reserves deceased 8.7 MMBoe, largely due to 9.4 MMBoe of production during the year and 3.3 MMBoe of negative revisions, which are primarily attributable to decreased SEC Prices used in the determination of proved reserves at December 31, 2020 compared to December 31, 2019. These decreases were partially offset with 4.0 MMBoe of additional estimated proved reserves from extensions and discoveries driven by the Company’s successful drilling activities during the year, which resulted in approximately 3.1 MMBoe of proved reserve additions to its operated Lobster field and approximately 0.9 MMBoe of new proved undeveloped reserves at its Spruance field.
During the year ended December 31, 2019, the Company’s estimated proved reserves deceased 4.7 MMBoe, largely due to 9.4 MMBoe of production during the year and 1.8 MMBoe of negative revisions, which were partially driven by the de-recognition of 3.9 MMBoe of proved undeveloped reserves primarily due to the extension of the economic life of a zone that was producing in 2019, which shifted the timing of a successive sidetrack proved undeveloped reserve location past the economic limit of the field. These negative revisions were partially offset by net positive revisions of 2.2 MMBoe due to upward proved developed producing reserves at the Company’s Brutus, Glider, and Lobster fields. These decreases were also partially offset by extensions and discoveries primarily attributable to the Company’s successful drilling activities during the year, which resulted in approximately 3.3 MMBoe of new proved undeveloped reserves at its U.S. Gulf of Mexico Green Canyon block 21 (“Bulleit”) and Spruance exploratory prospects and 3.1 MMBoe of proved reserve additions at its operated Brutus, Lobster, and Cognac fields.
Standardized Measure of Discounted Future Net Cash Flows
The Standardized Measure is the present value, discounted at 10%, of future net cash flows from estimated proved reserves calculated using the 12-month unweighted arithmetic average of the first-day-of-the-month price for each month in the period January through December (with consideration of price changes only to the extent provided by contractual arrangements). The estimated future net cash flows are reduced by projected future development, all estimated future costs to settle our asset retirement obligations associated with our proved reserves, including proved undeveloped reserves and production (excluding DD&A and any impairments of oil and natural gas properties) costs and estimated future income tax expenses.
Although the Company’s estimates of total proved reserves, development costs, and production rates were based on the best available information, the development and production of the oil and natural gas reserves may not occur in the periods assumed. Actual prices realized, costs incurred, and production quantities may vary significantly from those used. Therefore, the Standardized Measure should not be considered to represent the Company’s estimate of the expected revenues or the fair value of its proved oil, natural gas, and NGL reserves.
The following table presents the Standardized Measure relating to the Company’s estimated proved oil and natural gas reserves for the periods indicated:
| Year Ended December 31, | ||||||||||||
| 2021 | 2020 | 2019 | ||||||||||
| (In thousands) | ||||||||||||
| Future cash inflows |
$ | 2,982,723 | $ | 1,455,838 | $ | 2,781,011 | ||||||
| Future production costs |
(731,167 | ) | (469,173 | ) | (785,773 | ) | ||||||
F-50
| Year Ended December 31, | ||||||||||||
| 2021 | 2020 | 2019 | ||||||||||
| (In thousands) | ||||||||||||
| Future development and abandonment costs |
(440,282 | ) | (434,352 | ) | (538,759 | ) | ||||||
| Future income taxes |
(336,047 | ) | (98,449 | ) | (252,592 | ) | ||||||
|
|
|
|
|
|
|
|||||||
| Future net cash flows |
1,475,227 | 453,864 | 1,203,887 | |||||||||
| 10% annual discount for estimated timing of cash flows |
(334,792 | ) | (32,968 | ) | (232,677 | ) | ||||||
|
|
|
|
|
|
|
|||||||
| Standardized Measure |
$ | 1,140,435 | $ | 420,896 | $ | 971,210 | ||||||
|
|
|
|
|
|
|
|||||||
The following table presents the changes in the Standardized Measure relating to the Company’s estimated proved oil and natural gas reserves for the periods indicated:
| Year Ended December 31, | ||||||||||||
| 2021 | 2020 | 2019 | ||||||||||
| (In thousands) | ||||||||||||
| Standardized Measure at the beginning of the period |
$ | 420,896 | $ | 971,210 | $ | 1,152,470 | ||||||
| Net change in sales prices and production costs related to future production |
784,528 | (618,856 | ) | (152,935 | ) | |||||||
| Changes in estimated future development and abandonment costs |
15,807 | 8,385 | 51,358 | |||||||||
| Sales and transfers of oil and natural gas produced, net of production costs |
(398,819 | ) | (207,544 | ) | (371,683 | ) | ||||||
| Extensions, discoveries, and other additions, net of future production and development costs |
50,261 | 64,429 | 116,055 | |||||||||
| Purchases of reserves |
3,972 | — | — | |||||||||
| Revisions of previous quantity estimates |
404,430 | (100,164 | ) | (27,369 | ) | |||||||
| Development and abandonment costs incurred during the period |
31,540 | 64,163 | 104,130 | |||||||||
| Accretion of discount |
50,071 | 117,072 | 140,303 | |||||||||
| Net change in income taxes |
(176,522 | ) | 119,692 | 51,046 | ||||||||
| Changes in production rates, timing, and other |
(45,729 | ) | 2,509 | (92,165 | ) | |||||||
|
|
|
|
|
|
|
|||||||
| Net increase (decrease) in Standardized Measure |
719,539 | (550,314 | ) | (181,260 | ) | |||||||
|
|
|
|
|
|
|
|||||||
| Standardized Measure at the end of the period |
$ | 1,140,435 | $ | 420,896 | $ | 971,210 | ||||||
|
|
|
|
|
|
|
|||||||
F-51
Exhibit 99.2
ENVEN ENERGY CORPORATION AND SUBSIDIARIES
Condensed Consolidated Balance Sheets
(In thousands, except share amounts)
(Unaudited)
| September 30, 2022 | December 31, 2021 | |||||||
| Assets: |
||||||||
| Current assets: |
||||||||
| Cash and cash equivalents |
$ | 192,124 | $ | 88,930 | ||||
| Accounts receivable: |
||||||||
| Oil, natural gas, and NGL revenue |
60,856 | 56,323 | ||||||
| Joint interest and other |
16,575 | 11,961 | ||||||
| Prepaid expenses and other current assets |
12,688 | 11,426 | ||||||
| Prepaid income tax |
5,058 | — | ||||||
|
|
|
|
|
|||||
| Total current assets |
287,301 | 168,640 | ||||||
| Property and equipment: |
||||||||
| Oil and natural gas properties, full cost method, including $96,794 and $94,462 of unevaluated properties not being amortized as of September 30, 2022 and December 31, 2021, respectively |
1,942,021 | 1,832,679 | ||||||
| Other property and equipment |
8,545 | 8,545 | ||||||
| Less: accumulated depreciation, depletion, and amortization |
(1,189,030 | ) | (1,074,368 | ) | ||||
|
|
|
|
|
|||||
| Property and equipment, net |
761,536 | 766,856 | ||||||
| Restricted cash |
100,460 | 100,695 | ||||||
| Notes receivable, net |
65,137 | 65,089 | ||||||
| Derivative assets |
1,666 | — | ||||||
| Right-of-use assets |
21,798 | 21,662 | ||||||
| Other well equipment inventory |
14,716 | 11,408 | ||||||
| Other non-current assets |
3,800 | 4,540 | ||||||
|
|
|
|
|
|||||
| Total assets |
$ | 1,256,414 | $ | 1,138,890 | ||||
|
|
|
|
|
|||||
| Liabilities and Stockholders’ Equity: |
||||||||
| Current liabilities: |
||||||||
| Accounts payable |
$ | 27,123 | $ | 21,487 | ||||
| Revenue and royalties payable |
23,555 | 17,508 | ||||||
| Accrued liabilities |
75,836 | 58,905 | ||||||
| Derivative liabilities |
14,223 | 77,551 | ||||||
| Asset retirement obligations |
16,590 | 24,935 | ||||||
| 11.75% Senior Notes due 2026, net |
27,112 | 27,045 | ||||||
| Lease liabilities |
5,710 | 4,233 | ||||||
| Notes payable |
— | 4,413 | ||||||
| Income tax payable |
— | 2,740 | ||||||
| Other current liabilities |
6,143 | 2,199 | ||||||
|
|
|
|
|
|||||
| Total current liabilities |
196,292 | 241,016 | ||||||
| Derivative liabilities |
— | 2,391 | ||||||
| Asset retirement obligations, less current portion |
334,368 | 323,351 | ||||||
| 11.75% Senior Notes due 2026, net, less current portion |
235,636 | 248,469 | ||||||
| Lease liabilities, less current portion |
13,689 | 14,895 | ||||||
| Deferred tax liability |
1,512 | — | ||||||
| Other non-current liabilities |
17,859 | 15,344 | ||||||
|
|
|
|
|
|||||
| Total liabilities |
$ | 799,356 | $ | 845,466 | ||||
F-1
| September 30, 2022 | December 31, 2021 | |||||||
| Commitments and contingencies (Note 10) |
||||||||
| Stockholders’ equity: |
||||||||
| Series A convertible perpetual preferred stock, $0.001 par value, 25,000,000 shares authorized and 14,949,771 shares issued and outstanding as of September 30, 2022 and December 31, 2021 |
$ | 15 | $ | 15 | ||||
| Class A common stock, $0.001 par value, 200,000,000 shares authorized and 21,271,937 and 20,840,432 shares issued and outstanding as of September 30, 2022 and December 31, 2021, respectively |
21 | 21 | ||||||
| Additional paid-in capital |
399,493 | 394,474 | ||||||
| Retained earnings (accumulated deficit) |
57,529 | (101,086 | ) | |||||
|
|
|
|
|
|||||
| Total stockholders’ equity |
457,058 | 293,424 | ||||||
|
|
|
|
|
|||||
| Total liabilities and stockholders’ equity |
$ | 1,256,414 | $ | 1,138,890 | ||||
|
|
|
|
|
|||||
The accompanying notes are an integral part of these condensed consolidated financial statements.
F-2
ENVEN ENERGY CORPORATION AND SUBSIDIARIES
Condensed Consolidated Statements of Operations
(In thousands)
(Unaudited)
| Three Months Ended September 30, |
Nine Months Ended September 30, |
|||||||||||||||
| 2022 | 2021 | 2022 | 2021 | |||||||||||||
| Revenues: |
||||||||||||||||
| Oil, natural gas, and NGL revenue |
$ | 175,040 | $ | 115,519 | $ | 578,923 | $ | 363,018 | ||||||||
| Production handling and other income |
8,302 | 4,425 | 20,860 | 16,716 | ||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Total revenues |
183,342 | 119,944 | 599,783 | 379,734 | ||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Operating expenses: |
||||||||||||||||
| Lease operating expenses |
19,477 | 22,864 | 60,915 | 61,603 | ||||||||||||
| Workover, repair, and maintenance expenses |
4,514 | 3,803 | 16,635 | 17,676 | ||||||||||||
| Transportation, gathering, and processing costs |
2,882 | 2,143 | 7,366 | 5,440 | ||||||||||||
| Depreciation, depletion, and amortization |
38,585 | 33,467 | 114,662 | 119,787 | ||||||||||||
| Accretion of asset retirement obligations |
5,934 | 6,477 | 21,092 | 20,869 | ||||||||||||
| General and administrative expenses |
25,104 | 19,090 | 52,678 | 52,509 | ||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Total operating expenses |
96,496 | 87,844 | 273,348 | 277,884 | ||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Operating income |
86,846 | 32,100 | 326,435 | 101,850 | ||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Other income (expenses): |
||||||||||||||||
| Gain (loss) on derivatives, net |
42,851 | (23,648 | ) | (89,121 | ) | (162,113 | ) | |||||||||
| Interest expense |
(11,565 | ) | (12,579 | ) | (35,191 | ) | (35,164 | ) | ||||||||
| Loss on extinguishment of long-term debt |
— | — | — | (11,419 | ) | |||||||||||
| Gain on fair value of 11.00% Senior Notes due 2023 |
— | — | — | 16,589 | ||||||||||||
| Other income |
391 | 19 | 4,487 | 2,802 | ||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Total other income (expenses) |
31,677 | (36,208 | ) | (119,825 | ) | (189,305 | ) | |||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Income (loss) before income taxes |
118,523 | (4,108 | ) | 206,610 | (87,455 | ) | ||||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Income tax expense |
15,707 | 827 | 27,814 | 9,558 | ||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Net income (loss) |
102,816 | (4,935 | ) | 178,796 | (97,013 | ) | ||||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Net loss attributable to non-controlling interest |
— | — | — | (4,744 | ) | |||||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Net income (loss) attributable to EnVen Energy Corporation |
102,816 | (4,935 | ) | 178,796 | (92,269 | ) | ||||||||||
| Series A preferred stock dividends |
(6,727 | ) | (6,727 | ) | (20,181 | ) | (21,856 | ) | ||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Net income (loss) attributable to EnVen Energy Corporation Class A common stockholders |
$ | 96,089 | $ | (11,662 | ) | $ | 158,615 | $ | (114,125 | ) | ||||||
|
|
|
|
|
|
|
|
|
|||||||||
The accompanying notes are an integral part of these condensed consolidated financial statements.
F-3
ENVEN ENERGY CORPORATION AND SUBSIDIARIES
Condensed Consolidated Statements of Comprehensive Income (Loss)
(In thousands)
(Unaudited)
| Three Months Ended September 30, |
Nine Months Ended September 30, |
|||||||||||||||
| 2022 | 2021 | 2022 | 2021 | |||||||||||||
| Net income (loss) |
$ | 102,816 | $ | (4,935 | ) | $ | 178,796 | $ | (97,013 | ) | ||||||
| Other comprehensive income (loss), net: |
||||||||||||||||
| Credit risk adjustment on 11.00% Senior Notes due 2023 before reclassification, net of deferred income tax benefit of $0 million for each of the three months ended September 30, 2022 and 2021 and $0 million and $2.2 million for the nine months ended September 30, 2022 and 2021, respectively |
— | — | — | (23,571 | ) | |||||||||||
| Amounts reclassified from accumulated other comprehensive income |
— | — | — | (5,035 | ) | |||||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Total comprehensive income (loss), net |
102,816 | (4,935 | ) | 178,796 | (125,619 | ) | ||||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Less: comprehensive loss attributable to non-controlling interest |
— | — | — | (10,339 | ) | |||||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Comprehensive income (loss) attributable to EnVen Energy Corporation |
$ | 102,816 | $ | (4,935 | ) | $ | 178,796 | $ | (115,280 | ) | ||||||
|
|
|
|
|
|
|
|
|
|||||||||
The accompanying notes are an integral part of these condensed consolidated financial statements.
F-4
ENVEN ENERGY CORPORATION AND SUBSIDIARIES
Condensed Consolidated Statements of Changes in Equity
(In thousands, except share amounts)
(Unaudited)
| Series A preferred stock | Class A common stock | |||||||||||||||||||||||||||
| Shares | Amount | Shares | Amount | Additional paid-in capital |
Retained earnings (accumulated deficit) |
Total stockholders’ equity |
||||||||||||||||||||||
| January 1, 2022 balance |
14,949,771 | $ | 15 | 20,840,432 | $ | 21 | $ | 394,474 | $ | (101,086 | ) | $ | 293,424 | |||||||||||||||
| Issuance of Class A common stock related to stock-based compensation |
— | — | 824,907 | — | — | — | — | |||||||||||||||||||||
| Tax payments related to stock-based compensation |
— | — | (302,727 | ) | — | (7,139 | ) | — | (7,139 | ) | ||||||||||||||||||
| Stock-based compensation |
— | — | — | — | 1,068 | — | 1,068 | |||||||||||||||||||||
| Repurchase of Class A common stock |
— | — | (85,834 | ) | — | (2,221 | ) | — | (2,221 | ) | ||||||||||||||||||
| Series A preferred stock dividends |
— | — | — | — | — | (6,727 | ) | (6,727 | ) | |||||||||||||||||||
| Net loss |
— | — | — | — | — | (12,616 | ) | (12,616 | ) | |||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||||
| March 31, 2022 balance |
14,949,771 | 15 | 21,276,778 | 21 | 386,182 | (120,429 | ) | 265,789 | ||||||||||||||||||||
| Stock-based compensation |
— | — | — | — | 4,349 | — | 4,349 | |||||||||||||||||||||
| Repurchase of Class A common stock |
— | — | (4,841 | ) | — | (126 | ) | — | (126 | ) | ||||||||||||||||||
| Series A preferred stock dividends |
— | — | — | — | — | (6,727 | ) | (6,727 | ) | |||||||||||||||||||
| Net income |
— | — | — | — | — | 88,596 | 88,596 | |||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||||
| June 30, 2022 balance |
14,949,771 | 15 | 21,271,937 | 21 | 390,405 | (38,560 | ) | 351,881 | ||||||||||||||||||||
| Stock-based compensation |
— | — | — | — | 9,088 | — | 9,088 | |||||||||||||||||||||
| Series A preferred stock dividends |
— | — | — | — | — | (6,727 | ) | (6,727 | ) | |||||||||||||||||||
| Net income |
— | — | — | — | — | 102,816 | 102,816 | |||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||||
| September 30, 2022 balance |
14,949,771 | $ | 15 | 21,271,937 | $ | 21 | $ | 399,493 | $ | 57,529 | $ | 457,058 | ||||||||||||||||
The accompanying notes are an integral part of these condensed consolidated financial statements.
F-5
| Series A preferred stock |
Class A common stock |
Class B common stock |
||||||||||||||||||||||||||||||||||||||||||||||
| Shares | Amount | Shares | Amount | Shares | Amount | Additional paid-in capital |
Accumulated other comprehensive income |
Accumulated deficit |
Total stockholders’ equity |
Non-controlling interest |
Total equity |
|||||||||||||||||||||||||||||||||||||
| January 1, 2021 balance |
14,409,417 | $ | 14 | 17,329,667 | $ | 17 | 3,333,333 | $ | 3 | $ | 382,819 | $ | 23,011 | $ | (43,412 | ) | $ | 362,452 | $ | 38,202 | $ | 400,654 | ||||||||||||||||||||||||||
| Issuance of Class A common stock related to stock-based compensation |
— | — | 450,469 | 1 | — | — | (1 | ) | — | — | — | — | — | |||||||||||||||||||||||||||||||||||
| Tax payments related to stock-based compensation |
— | — | (141,632 | ) | — | — | — | (1,213 | ) | — | — | (1,213 | ) | — | (1,213 | ) | ||||||||||||||||||||||||||||||||
| Stock-based compensation |
— | — | — | — | — | — | 451 | — | — | 451 | — | 451 | ||||||||||||||||||||||||||||||||||||
| Series A preferred stock dividends |
540,354 | 1 | — | — | — | — | 6,483 | — | (6,484 | ) | — | — | — | |||||||||||||||||||||||||||||||||||
| Change in ownership due to Series A preferred stock dividends |
— | — | — | — | — | — | 828 | — | — | 828 | (828 | ) | — | |||||||||||||||||||||||||||||||||||
| Cumulative effect of ASU 2020-06 accounting change |
— | — | — | — | — | — | (28,267 | ) | — | 28,267 | — | — | — | |||||||||||||||||||||||||||||||||||
| Other comprehensive loss, net of tax |
— | — | — | — | — | — | — | (8,093 | ) | — | (8,093 | ) | (1,047 | ) | (9,140 | ) | ||||||||||||||||||||||||||||||||
| Net loss |
— | — | — | — | — | — | — | — | (26,882 | ) | (26,882 | ) | (3,647 | ) | (30,529 | ) | ||||||||||||||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||||||||||||||
| March 31, 2021 balance |
14,949,771 | 15 | 17,638,504 | 18 | 3,333,333 | 3 | 361,100 | 14,918 | (48,511 | ) | 327,543 | 32,680 | 360,223 | |||||||||||||||||||||||||||||||||||
| Repurchase of Class A common stock |
— | — | (131,405 | ) | — | — | — | (1,950 | ) | — | — | (1,950 | ) | — | (1,950 | ) | ||||||||||||||||||||||||||||||||
| Stock-based compensation |
— | — | — | — | — | — | 1,818 | — | — | 1,818 | — | 1,818 | ||||||||||||||||||||||||||||||||||||
| Series A preferred stock dividends |
— | — | — | — | — | — | — | — | (8,645 | ) | (8,645 | ) | — | (8,645 | ) | |||||||||||||||||||||||||||||||||
| Conversion of Class B common stock and settlement of the Tax Receivable Agreement, inclusive of tax impact |
— | — | 3,333,333 | 3 | (3,333,333 | ) | (3 | ) | 24,585 | — | — | 24,585 | (27,035 | ) | (2,450 | ) | ||||||||||||||||||||||||||||||||
| Other comprehensive loss, net of tax |
— | — | — | — | — | — | — | (14,918 | ) | — | (14,918 | ) | (4,548 | ) | (19,466 | ) | ||||||||||||||||||||||||||||||||
| Net loss |
— | — | — | — | — | — | — | — | (60,452 | ) | (60,452 | ) | (1,097 | ) | (61,549 | ) | ||||||||||||||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||||||||||||||
| June 30, 2021 balance |
14,949,771 | 15 | 20,840,432 | 21 | — | — | 385,553 | — | (117,608 | ) | 267,981 | — | 267,981 | |||||||||||||||||||||||||||||||||||
| Stock-based compensation |
— | — | — | — | — | — | 3,318 | — | — | 3,318 | — | 3,318 | ||||||||||||||||||||||||||||||||||||
| Series A preferred stock dividends |
— | — | — | — | — | — | — | — | (6,727 | ) | (6,727 | ) | — | (6,727 | ) | |||||||||||||||||||||||||||||||||
| Net loss |
— | — | — | — | — | — | — | — | (4,935 | ) | (4,935 | ) | — | (4,935 | ) | |||||||||||||||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||||||||||||||
| September 30, 2021 balance |
14,949,771 | $ | 15 | 20,840,432 | $ | 21 | — | $ | — | $ | 388,871 | $ | — | $ | (129,270 | ) | $ | 259,637 | $ | — | $ | 259,637 | ||||||||||||||||||||||||||
The accompanying notes are an integral part of these condensed consolidated financial statements.
F-6
ENVEN ENERGY CORPORATION AND SUBSIDIARIES
Condensed Consolidated Statements of Cash Flows
(In thousands)
(Unaudited)
| Nine Months Ended September 30, |
||||||||
| 2022 | 2021 | |||||||
| Cash flows from operating activities: |
||||||||
| Net income (loss) |
$ | 178,796 | $ | (97,013 | ) | |||
| Adjustments to reconcile net income (loss) to net cash provided by operating activities: |
||||||||
| Depreciation, depletion, and amortization |
114,662 | 119,787 | ||||||
| Accretion of asset retirement obligations |
21,092 | 20,869 | ||||||
| Stock-based compensation |
14,505 | 5,587 | ||||||
| Excess tax benefit (deficit) from stock-based compensation |
1,634 | (424 | ) | |||||
| Amortization of debt discount and deferred financing costs |
3,178 | 2,384 | ||||||
| Loss on extinguishment of long-term debt |
— | 11,419 | ||||||
| Gain on fair value of 11.00% Senior Notes due 2023 |
— | (16,589 | ) | |||||
| Loss on derivatives, net |
89,121 | 162,113 | ||||||
| Cash paid for derivative settlements, net |
(156,506 | ) | (73,301 | ) | ||||
| Deferred income taxes |
1,512 | (5,098 | ) | |||||
| Other non-cash items |
34 | (2,015 | ) | |||||
| Changes in operating assets and liabilities: |
||||||||
| Accounts receivable |
(9,611 | ) | 5,449 | |||||
| Income tax |
(9,432 | ) | 18,746 | |||||
| Prepaid expenses and other current assets |
(1,211 | ) | 4,260 | |||||
| Other well equipment inventory |
(3,308 | ) | 63 | |||||
| Accounts payable |
5,636 | (30,688 | ) | |||||
| Revenue and royalties payable |
6,047 | 1,515 | ||||||
| Accrued liabilities |
6,062 | 33,914 | ||||||
| Settlement of asset retirement obligations |
(21,576 | ) | (10,022 | ) | ||||
| Other liabilities |
4,116 | (383 | ) | |||||
|
|
|
|
|
|||||
| Net cash provided by operating activities |
$ | 244,751 | $ | 150,573 | ||||
|
|
|
|
|
|||||
| Cash flows from investing activities: |
||||||||
| Purchases of property, equipment, and other capital expenditures |
$ | (92,518 | ) | $ | (61,598 | ) | ||
| Net cash received for the acquisition of proved oil and natural gas properties |
464 | 8,169 | ||||||
| Acquisitions of unevaluated oil and natural gas properties |
(658 | ) | (6,546 | ) | ||||
|
|
|
|
|
|||||
| Net cash used in investing activities |
$ | (92,712 | ) | $ | (59,975 | ) | ||
|
|
|
|
|
|||||
| Cash flows from financing activities: |
||||||||
| Payment of Series A preferred stock dividends |
$ | (20,181 | ) | $ | (15,372 | ) | ||
| Payment for the repurchase of Class A common stock |
(2,347 | ) | (1,950 | ) | ||||
| Tax payments related to stock-based compensation |
(7,139 | ) | (1,213 | ) | ||||
| Payment for the settlement of the tax receivable agreement |
— | (7,000 | ) | |||||
| Payments on notes payable |
(4,413 | ) | (6,351 | ) | ||||
| Repayment of long-term debt |
(15,000 | ) | (276,816 | ) | ||||
| Premium paid for the early termination of long-term debt |
— | (11,419 | ) | |||||
| Proceeds from the issuance of long-term debt |
— | 295,700 | ||||||
| Payment of debt issue and deferred financing costs |
— | (10,251 | ) | |||||
|
|
|
|
|
|||||
F-7
| Nine Months Ended September 30, |
||||||||
| 2022 | 2021 | |||||||
| Net cash used in financing activities |
$ | (49,080 | ) | $ | (34,672 | ) | ||
|
|
|
|
|
|||||
| Net increase in cash, cash equivalents, and restricted cash |
$ | 102,959 | $ | 55,926 | ||||
| Cash, cash equivalents, and restricted cash - beginning of period |
$ | 189,625 | $ | 145,488 | ||||
|
|
|
|
|
|||||
| Cash, cash equivalents, and restricted cash - end of period |
$ | 292,584 | $ | 201,414 | ||||
The accompanying notes are an integral part of these condensed consolidated financial statements.
Refer to Note 13 - Supplemental Cash Flow Information for supplemental cash flow disclosures.
F-8
ENVEN ENERGY CORPORATION AND SUBSIDIARIES
Notes to Condensed Consolidated Financial Statements
(Unaudited)
Note 1—Organization and Basis of Presentation
EnVen Energy Corporation (individually or together with its subsidiaries, the “Company”) is an independent oil and natural gas company engaged in the development, exploitation, exploration, and acquisition of primarily crude oil properties in the deepwater region of the United States (“U.S.”) Gulf of Mexico. The Company focuses on developing operated, deepwater assets that it believes have untapped, lower-risk drill bit opportunities and will provide strong cash flow and significant production potential. This strategy allows the Company to benefit from the favorable geologic and economic characteristics of the deepwater U.S. Gulf of Mexico fields.
Organization
On October 30, 2015, Energy Ventures GoM Holdings, LLC entered into an agreement to sell 13,732,925 units in a private offering, at a price of $10.00 per unit, to selected institutional investors (the “2015 Equity Offering”). Prior to the closing of the 2015 Equity Offering, the then existing members of Energy Ventures GoM Holdings, LLC contributed 100% of their limited liability company units (the “limited liability interest”) in Energy Ventures GoM LLC (“EnVen GoM”) to a newly formed limited liability company, EnVen Equity Holdings, LLC (“EnVen Equity Holdings”). Therefore, the members of EnVen Equity Holdings indirectly owned 100% of the limited liability interest of EnVen GoM. Following this transaction and also prior to the closing of the 2015 Equity Offering, Energy Ventures GoM Holdings, LLC was converted from a limited liability company to a Delaware corporation and renamed EnVen Energy Corporation. Further, at the time of the 2015 Equity Offering, the Company also entered into a Tax Receivable Agreement (“TRA”) with EnVen Equity Holdings.
As specified in the EnVen GoM Second Amended and Restated Limited Liability Company Agreement (the “EnVen GoM LLC Agreement”), the members of EnVen Equity Holdings could have, at any time, required EnVen GoM to repurchase all or any number of its limited liability interest of EnVen GoM for consideration equal to one share of the Company’s Class A common stock $0.001, par value per share (“Class A Common Stock”) per unit of the limited liability interest of EnVen GoM. However, with approval from the Company’s board of directors (the “Board”), the Company could satisfy the obligation by exercising an option to purchase the limited liability interest of EnVen GoM for a cash price equal to the fair value of one share of its Class A Common Stock or by issuing newly issued shares of its Class A Common Stock (collectively, the “Redemption Rights”). Refer to “Notes to Audited Consolidated Financial Statements—Note 10—Related Party Transactions” for a full discussion of the TRA and the Redemption Rights.
In April 2021, EnVen Equity Holdings exercised its Redemption Rights with respect to all of its limited liability interests of EnVen GoM. Pursuant to the terms of the EnVen GoM LLC Agreement, the Company then elected to settle the Redemption Rights through a direct exchange of such common units for 3,333,333 newly issued shares of its Class A Common Stock and cancelled the associated 3,333,333 shares of its $0.001 par value Class B common stock (“Class B Common Stock”) (collectively, the “Class B Common Stock Conversion”). Concurrent with the Class B Common Stock Conversion, the Company and EnVen Equity Holdings agreed to terminate the TRA for a $7.0 million cash payment to EnVen Equity Holdings. As a result of these transactions, EnVen Equity Holdings no longer holds any limited liability interests of EnVen GoM and no longer holds any shares of Company’s Class B Common Stock. The Company accounted for these transactions as an adjustment to its Stockholders’ equity during the second quarter of 2021. Refer to “Notes to Audited Consolidated Financial Statements—Note 9—Stockholders’ Equity” for a further discussion of these transactions.
Talos Merger Agreement
On September 21, 2022, the Company and Talos Energy Inc. (“Talos”) announced that they entered into an Agreement and Plan of Merger (the “Merger Agreement”), pursuant to which Talos will acquire the Company in
F-9
a stock and cash transaction. Under the terms of the Merger Agreement, the Company’s shareholders will receive 43,800,000 shares of Talos common stock and approximately $212.5 million in cash (subject to certain adjustments) (the “Talos Merger”). The transaction is expected to close in late 2022 or early 2023, subject to the satisfaction of customary closing conditions, including obtaining the requisite shareholder and regulatory approvals. The transaction has been unanimously approved by both companies’ Boards of Directors.
Pursuant to the Merger Agreement, immediately prior to the closing of the merger, all outstanding shares of the Company’s Series A convertible perpetual preferred stock (“Series A Preferred Stock”) will be automatically converted into shares of the Company’s Class A Common Stock, per the Series A Preferred Stock certificate of designation, as amended in connection with the Merger Agreement on September 21, 2022. Additionally, immediately prior to the closing of the merger, all of the time-based and performance-based Restricted Stock shares issued and outstanding will vest into shares of the Company’s Class A Common Stock. The Merger Agreement also addresses the treatment of the Company’s stock options. Refer to “Notes to Audited Consolidated Financial Statements—Note 9—Stockholders’ Equity” for a further discussion of the Company’s Series A Preferred Stock and to Note 8—Stock-based Compensation below for a further discussion of the Company’s time-based and performance-based Restricted Stock and stock options.
The Merger Agreement includes certain restrictions on the conduct of the business of the Company until the closing of the merger, such as a requirement to operate in the ordinary course of business and limitations on, among other things, entering into acquisition or divestiture agreements, issuing dividends, and conducting stock or debt repurchases. The Merger Agreement also contains certain termination rights for both the Company and Talos, including, among others, if the merger is not completed by June 21, 2023. If the Merger Agreement is terminated under certain circumstances, Talos may be required to pay the Company a termination fee of $42.5 million (or $12.0 million under certain circumstances), or the Company may be required to pay Talos a termination fee of $28.0 million.
Basis of Presentation and Consolidation
The accompanying condensed consolidated financial statements as of September 30, 2022 and for the three and nine months ended September 30, 2022 and 2021 are prepared in accordance with accounting principles generally accepted in the U.S. (“GAAP”) and include the accounts for the Company and entities in which it has control. All significant intercompany balances and transactions have been eliminated. Prior to the Class B Common Stock Conversion in April 2021, discussed above, the Company owned the majority interest of and controlled its subsidiary, EnVen GoM; therefore, the majority interest in EnVen GoM was reflected as a condensed consolidated subsidiary in the accompanying condensed consolidated financial statements. The remaining ownership interest not held by the Company was included in the accompanying condensed consolidated financial statements as Non-controlling interest. Following the consummation of the Class B Common Stock Conversion in April 2021, the Company owns and controls 100% of its subsidiary EnVen GoM and no longer reports a Non-controlling interest on its condensed consolidated balance sheet.
The condensed consolidated financial statements as of September 30, 2022 and for the three and nine months ended September 30, 2022 and 2021 are unaudited and were derived from the audited consolidated financial statements included in this proxy statement/consent solicitation statement/prospectus. In preparing the accompanying condensed consolidated financial statements, the Company has evaluated events or transactions through the date that these condensed consolidated financial statements are available to be issued. In management’s opinion, all normal recurring adjustments necessary for the fair presentation of the Company’s interim and prior period results have been made.
Certain disclosures have been condensed or omitted from these condensed consolidated financial statements; however, management believes the disclosures are adequate to make the information not misleading. The accompanying unaudited condensed consolidated financial statements and related note disclosures should be read
F-10
in conjunction with the audited consolidated financial statements and related notes thereto included in this proxy statement/consent solicitation statement/prospectus.
Use of Estimates
The preparation of the financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues, and expenses and the disclosure of contingent assets and liabilities as of the date of the financial statements, the reported amounts of revenues and expenses during the reporting periods and the reported amounts of proved oil and natural gas reserves. Management believes its estimates and assumptions to be reasonable under the circumstances. Certain estimates and assumptions are inherently unpredictable and actual results could differ from those estimates.
Significant Accounting Policies
The Company has provided a discussion of its significant accounting policies, estimates, and judgments in “Notes to Audited Consolidated Financial Statements—Note 2—Summary of Significant Accounting Policies”. The Company has not changed any of its other significant accounting policies during the nine months ended September 30, 2022.
Note 2—Acquisitions of Oil and Natural Gas Properties
On May 20, 2021, the Company completed the acquisition of an incremental 35% working interest in the U.S. Gulf of Mexico Atwater Valley 574, 575, and 618 (“Neptune”) field from BHP Billiton Petroleum (Deepwater) Inc. and BHP Billiton Petroleum (GOM) Inc. (collectively, “BHP”) with an effective date of July 1, 2020 (collectively, the “Neptune Acquisition”). The Neptune Acquisition was consummated pursuant to a Purchase and Sale Agreement executed on April 6, 2021 and accounted for as an asset acquisition in accordance with Accounting Standards Codification (“ASC”) Topic 805, Business Combinations. Prior to the acquisition, the Company held a 30% working interest in the Neptune field and following the close of the acquisition, it holds a 65% working interest in the Neptune field. Additionally, the Company became the operator of the Neptune field on August 1, 2021. Per the agreement, the Company did not provide any cash consideration for the Neptune Acquisition, but assumed BHP’s portion of the future P&A obligations associated with the Neptune field. Upon final settlement of the acquisition, BHP agreed to pay the Company $8.6 million for the Neptune Acquisition, inclusive of customary closing adjustments and net of transaction related costs. Due to the timing of the final settlement, the Company received $8.2 million of the total consideration in cash during the nine months ended September 30, 2021 and the remaining amount was received in January 2022. The net cash received for the Neptune Acquisition is reflected in the Net cash used in investing activities section on the condensed consolidated statements of cash flows for the nine months ended September 30, 2022 and 2021.
The following table presents the allocation of the total consideration to the assets acquired and liabilities assumed, based on their relative fair values, on May 20, 2021:
| (In thousands) | ||||
| Proved oil and natural gas properties |
$ | 5,831 | ||
| Asset retirement obligations |
(14,464 | ) | ||
|
|
|
|||
| Allocated total consideration |
$ | (8,633 | ) | |
|
|
|
|||
Refer to Note 4—Fair Value Measurements for a further discussion of the fair value measurements of the assets acquired and liabilities assumed in the Neptune Acquisition.
Note 3—Derivative Instruments
The Company utilizes commodity derivative instruments to reduce its exposure to crude oil and natural gas price volatility for a portion of its estimated production from its proved, developed, producing oil and natural gas
F-11
properties. The Company has various crude oil and natural gas derivative contracts with multiple major financial institutions consisting of various instruments based on its hedging strategy, including financially settled crude oil and natural gas call options, put options, and swaps, or combinations of these arrangements, which are described below.
| • | Swaps: The Company receives a fixed price and pays a variable market price to the counterparty for contracted commodity volumes over specified time periods. From time to time, the Company may enter into basis swaps or WTI NYMEX roll swaps to provide additional protection against the variability of other pricing components. |
| • | Call Options: A sold call option gives the counterparty the right, but not the obligation, to purchase the underlying commodity volumes from the Company at a specified price (“strike/ceiling price”) over a specified time period. At settlement, if the market price is above the fixed ceiling price of the sold call option, the Company pays the counterparty the difference. In a purchased call option, if the market price settles above the fixed ceiling price of the purchased call option, the Company will receive the difference from the counterparty. If the market price settles below the fixed ceiling price of the sold or purchased call option, no payment is due from either party. |
| • | Purchased Put Options: A purchased put option gives the Company the right, but not the obligation, to sell the underlying commodity volumes to the counterparty at a specified price (“strike/floor price”) over a specified time period. At settlement, if the market price is below the fixed floor price of the purchased put option, the counterparty pays the Company the difference. If the market price settles above the fixed floor price of the purchased put option, no payment is due from either party. |
| • | Put Spreads: A put spread is a combination of a sold put option and a purchased put option. At settlement, if the market price is below the sold put option strike price, the Company receives the difference between the two strike prices from the counterparty. If the market price settles below the purchased put option strike price but above the sold put option strike price, the Company receives the difference between the purchased put option strike price and the market price from the counterparty. If the market price settles above the purchased put option strike price, no payment is due from either party. |
| • | Collars: A collar contains a purchased put option (“fixed floor price”) and a sold call option (“fixed ceiling price”). At settlement, if the market price is below the fixed floor price, the Company receives the difference between the fixed floor price and the market price from the counterparty. If the market price settles above the fixed ceiling price, the Company pays the counterparty the difference between the market price and the fixed ceiling price. If the market price settles between the fixed floor price and fixed ceiling price, no payments are due from either party. |
| • | Three-way Collars: A three-way collar combines a sold call option (“fixed ceiling price”), a purchased put option (“fixed floor price”), and a sold put option (“fixed subfloor price”). At settlement, if the market price settles above the fixed subfloor price but below the fixed floor price, the Company receives the difference between the fixed floor price and the market price from the counterparty. If the market price settles below the fixed subfloor price, the Company receives the market price plus the difference between the fixed subfloor price and the fixed floor price from the counterparty. If the market price settles above the fixed ceiling price, the Company pays the counterparty the difference between the fixed ceiling price and the market price. If the market price settles between the fixed floor price and fixed ceiling price, no payments are due from either party. |
Additionally, the Company may purchase volumetrically offsetting derivative instruments in order to mitigate its exposure against additional commodity price volatility before the settlement date of certain outstanding derivative contracts.
F-12
As of September 30, 2022, the Company had the following outstanding crude oil and natural gas derivative contracts in place, which settle monthly and are indexed to NYMEX WTI and NYMEX HH, respectively:
| Settling During the Year Ended December 31, 2022 |
Settling During the Year Ended December 31, 2023 |
Settling During the Year Ended December 31, 2024 |
||||||||||
| Crude Oil Swaps: |
||||||||||||
| Notional volume (Bbls) |
92,000 | 90,000 | — | |||||||||
| Weighted average price ($/Bbl) |
$ | 62.00 | $ | 62.00 | — | |||||||
| Crude Oil Purchased Puts: |
||||||||||||
| Notional volume (Bbls) |
414,000 | — | — | |||||||||
| Weighted average price ($/Bbl) |
$ | 57.27 | $ | — | — | |||||||
| Crude Oil Collars: |
||||||||||||
| Notional volume (Bbls) |
634,800 | 772,500 | — | |||||||||
| Weighted average floor price ($/Bbl) |
$ | 50.72 | $ | 59.17 | — | |||||||
| Weighted average ceiling price ($/Bbl) |
$ | 74.89 | $ | 85.08 | — | |||||||
| Crude Oil Three-way Collars: |
||||||||||||
| Notional volume (Bbls) |
18,400 | 3,079,000 | 291,200 | |||||||||
| Weighted average sub-floor price ($/Bbl) |
$ | 40.00 | $ | 50.22 | $ | 57.27 | ||||||
| Weighted average floor price ($/Bbl) |
$ | 50.00 | $ | 63.44 | $ | 70.00 | ||||||
| Weighted average ceiling price ($/Bbl) |
$ | 81.48 | $ | 106.34 | $ | 98.01 | ||||||
| Natural Gas Three-way Collars: |
||||||||||||
| Notional volume (MMBtus) |
610,000 | 900,000 | — | |||||||||
| Weighted average sub-floor price ($/MMBtu) |
$ | 2.50 | $ | 2.50 | — | |||||||
| Weighted average floor price ($/MMBtu) |
$ | 3.00 | $ | 3.00 | — | |||||||
| Weighted average ceiling price ($/MMBtu) |
$ | 5.00 | $ | 5.00 | — | |||||||
Additionally, the Company enters into diesel swap derivative contracts to hedge against variability in cash flows associated with the purchase of diesel fuel used in its production and drilling activities. Under these diesel derivative swap contracts, the Company pays a fixed price to the counterparty for contracted commodity volumes over specified time periods.
As of September 30, 2022, the Company had the following outstanding diesel swap derivative contracts in place, which settle monthly and are indexed to the Platts U.S.:
| Settling During the Year Ended December 31, 2022 |
||||
| Diesel Swaps: |
||||
| Notional volume (Gals) |
600,000 | |||
| Weighted average price ($/Gal) |
$ | 2.92 | ||
The Company recognizes all of its derivative instruments at fair value as assets or liabilities on the accompanying condensed consolidated balance sheets. The Company has not designated any of its derivative instruments as hedges for accounting purposes; therefore, the aggregate net gains and losses resulting from changes in the fair values of its outstanding derivatives, the settlement of derivative instruments, and any net proceeds or payments related to the early termination of derivative contracts during the period are recognized as part of Gain (loss) on derivatives, net on the accompanying condensed consolidated statements of operations.
F-13
The Company typically has numerous hedge positions that span several time periods and often result in both fair value derivative asset and liability positions held with that counterparty. The Company has elected to net its derivative instrument fair values executed with the same counterparty, pursuant to the International Swaps and Derivatives Association, Inc. (“ISDA”) master agreements, which provide for the net settlement over the term of the contract and in the event of the default or termination of the contract.
In some cases, the Company might agree to pay a premium on certain of its option derivative contracts. The Company could agree to pay the premium upfront, in which case the premium payment is recorded as a derivative asset. The value of the premium is considered in the underlying derivative fair value and is adjusted in subsequent periods through Gain (loss) on derivatives, net on the accompanying condensed consolidated statements of operations. Alternatively, the Company could defer the payment of the premium until the month the applicable derivative contract settles, in which case it recognizes the deferred premium obligation net against the derivative instruments fair value asset or liability, pursuant to the ISDA master netting agreements described above. In the period the derivative contract settles, the Company recognizes the deferred premium obligation in Gain (loss) on derivatives, net on the accompanying condensed consolidated statements of operations.
The following tables present the gross and net fair values of the Company’s derivative instruments, net of any applicable deferred premium obligations recorded on the accompanying condensed consolidated balance sheets:
| September 30, 2022 | ||||||||||||
| Gross Amounts Recognized |
Gross Amounts Offset on the Consolidated Balance Sheet |
Net Amounts Presented on the Consolidated Balance Sheet |
||||||||||
| (In thousands) | ||||||||||||
| Current assets |
$ | 19,663 | $ | (19,663 | ) | $ | — | |||||
| Long-term assets |
14,549 | (12,883 | ) | 1,666 | ||||||||
| Current liabilities |
(33,886 | ) | 19,663 | (14,223 | ) | |||||||
| Long-term liabilities |
$ | (12,883 | ) | $ | 12,883 | $ | — | |||||
| December 31, 2021 | ||||||||||||
| Gross Amounts Recognized |
Gross Amounts Offset on the Consolidated Balance Sheet |
Net Amounts Presented on the Consolidated Balance Sheet |
||||||||||
| (In thousands) | ||||||||||||
| Current assets |
$ | 5,205 | $ | (5,205 | ) | $ | — | |||||
| Long-term assets |
2,206 | (2,206 | ) | — | ||||||||
| Current liabilities |
(82,756 | ) | 5,205 | (77,551 | ) | |||||||
| Long-term liabilities |
$ | (4,597 | ) | $ | 2,206 | $ | (2,391 | ) | ||||
As of September 30, 2022 and December 31, 2021, the fair values of the Company’s derivatives are presented net of deferred premium obligations of $2.4 million and $7.5 million, respectively.
The following table presents the components of Gain (loss) on derivatives, net reflected on the accompanying condensed consolidated statements of operations and cash flows for the periods indicated. Total cash paid for derivative settlements, net reflects the net losses or gains on derivative contracts which matured during the period, calculated as the difference between the contract price and the market settlement price for those contracts. Any proceeds or payments related to the early termination of derivative contracts, any upfront premiums paid for new derivative contracts during the period, and any cash premium payments associated with derivative contracts settled during the period are included in the total cash paid for derivative settlements, net. Total non-cash gain
F-14
(loss) on derivatives, net represents the changes in the fair values of derivative instruments outstanding at the end of the period and the reversal of previously recognized non-cash losses or gains on derivative contracts that matured during the period.
| Three Months Ended September 30, |
Nine Months Ended September 30, |
|||||||||||||||
| 2022 | 2021 | 2022 | 2021 | |||||||||||||
| (In thousands) | ||||||||||||||||
| Cash (paid) received for derivative settlements, net: |
||||||||||||||||
| Crude oil |
$ | (42,783 | ) | $ | (30,822 | ) | $ | (155,180 | ) | $ | (70,584 | ) | ||||
| Natural gas |
(604 | ) | (1,616 | ) | (1,670 | ) | (2,717 | ) | ||||||||
| Diesel |
344 | — | 344 | — | ||||||||||||
|
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|
|
|
|
|
|
|
|||||||||
| Total cash paid for derivative settlements, net |
(43,043 | ) | (32,438 | ) | (156,506 | ) | (73,301 | ) | ||||||||
| Non-cash gain (loss) on derivatives: |
||||||||||||||||
| Crude oil |
88,028 | 11,521 | 69,120 | (84,886 | ) | |||||||||||
| Natural gas |
(1,367 | ) | (2,731 | ) | (1,822 | ) | (3,926 | ) | ||||||||
| Diesel |
(767 | ) | — | 87 | — | |||||||||||
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|
|
|||||||||
| Total non-cash gain (loss) on derivatives, net |
85,894 | 8,790 | 67,385 | (88,812 | ) | |||||||||||
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|
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| Gain (loss) on derivatives, net |
42,851 | (23,648 | ) | (89,121 | ) | (162,113 | ) | |||||||||
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For the three months ended September 30, 2022 and 2021, total cash paid for derivative settlements, net includes deferred premium obligations paid for crude oil derivative contracts of $1.1 million and $2.3 million, respectively. Additionally, total cash paid for derivative settlements, net for the three months ended September 30, 2021 includes deferred premium obligations paid for natural gas derivative contracts of $0.6 million. For the nine months ended September 30, 2022 and 2021, total cash paid for derivative settlements, net includes deferred premium obligations paid for crude oil derivative contracts of $5.3 million and $5.7 million, respectively, and deferred premium obligations paid for natural gas derivative contracts of $1.2 million and $0.6 million, respectively. Additionally, for the three and nine months ended September 30, 2022, the total cash paid for natural gas derivative settlements, net includes a $0.6 million payment to unwind certain natural gas derivative contracts before their settlement date.
Note 4—Fair Value Measurements
Certain of the Company’s assets and liabilities are carried at fair value and measured either on a recurring or non-recurring basis. The Company’s fair value measurements are based either on actual market data or assumptions that other market participants would use in pricing an asset or liability in an orderly transaction, using the valuation hierarchy prescribed by GAAP.
The GAAP valuation hierarchy categorizes assets and liabilities measured at fair value into one of three levels depending on the observability of inputs used to determine fair value. The three levels of the fair value hierarchy are as follows:
| • | Level 1: Unadjusted quoted prices for identical assets or liabilities in active markets. |
| • | Level 2: Observable inputs other than Level 1 inputs. These include: quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in markets which are not active, or inputs that are corroborated by observable active market data. |
| • | Level 3: Unobservable inputs for which little or no market data exists. |
F-15
The classification of an asset or liability within the fair value hierarchy is based on the lowest level input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement of an asset or liability requires judgment and may affect the valuation of the fair value asset or liability and its placement within the fair value hierarchy. There have been no transfers between fair value hierarchy levels.
Assets and Liabilities Measured at Fair Value on a Recurring Basis
Commodity derivative contracts. The fair values of the Company’s derivative instruments are measured on a recurring basis using a third-party industry-standard pricing model that considers various inputs such as quoted forward commodity prices, discount rates, volatility factors, and current market and contractual prices for the underlying instruments, as well as other relevant data. These significant inputs are observable in the current market or can be corroborated by observable active market data and are therefore considered Level 2 inputs within the fair value hierarchy.
The following tables present the Company’s commodity derivative contract assets and liabilities, which are measured at fair value on a recurring basis, as of September 30, 2022 and December 31, 2021, using the fair value hierarchy:
| Fair Value Measurement as of September 30, 2022 | ||||||||||||||||
| Total | Level 1 | Level 2 | Level 3 | |||||||||||||
| (In thousands) | ||||||||||||||||
| Assets: |
||||||||||||||||
| Commodity derivative contracts |
$ | 34,212 | $ | — | $ | 17,020 | $ | — | ||||||||
| Liabilities: |
||||||||||||||||
| Commodity derivative contracts |
$ | (46,769 | ) | $ | — | $ | (46,769 | ) | $ | — | ||||||
| Fair Value Measurement as of December 31, 2021 | ||||||||||||||||
| Total | Level 1 | Level 2 | Level 3 | |||||||||||||
| (In thousands) | ||||||||||||||||
| Assets: |
||||||||||||||||
| Commodity derivative contracts |
$ | 7,411 | $ | — | $ | 7,411 | $ | — | ||||||||
| Liabilities: |
||||||||||||||||
| Commodity derivative contracts |
$ | (87,353 | ) | $ | — | $ | (87,353 | ) | $ | — | ||||||
Fair Value of Other Financial Instruments
Cash and cash equivalents, restricted cash, accounts receivable, and accounts payable. The carrying amounts of the Company’s cash and cash equivalents, restricted cash, accounts receivable, and accounts payable approximate fair value due to the highly liquid or short-term nature of these instruments.
11.75% Senior Notes due 2026. The Company’s 11.75% senior secured second lien notes due 2026 (the “2026 Notes”) are presented on the condensed consolidated balance sheets as of September 30, 2022 and December 31, 2021 at their carrying values of $262.7 million and $275.5 million, respectively, which is net of the unamortized discount and deferred financing costs. Refer to Note 6—Long-term Debt for a discussion of the Company’s 2026 Notes. As of September 30, 2022 and December 31, 2021, the fair value of the aggregate principal amount outstanding of the 2026 Notes was $279.5 million and $296.2 million, respectively. The fair value of the 2026 Notes is estimated based on the unadjusted quoted prices for the liability in an active market, which is considered a Level 1 input.
Assets and Liabilities Measured at Fair Value on a Non-Recurring Basis
Acquisition-related assets and liabilities. The fair values of assets acquired and liabilities assumed in an acquisition are measured on a non-recurring basis on the acquisition date using a discounted cash flow model.
F-16
The significant inputs used in the discounted cash flow model include estimates relating to oil and natural gas reserves, future commodity prices, the timing of developing the assets, future operating costs, a credit-risk adjusted discount rate, and other relevant data. These significant inputs are based on unobservable market data and are therefore considered Level 3 inputs within the fair value hierarchy. Refer to Note 2—Acquisitions of Oil and Natural Gas Properties for a further discussion of the Company’s acquisitions.
Asset retirement obligations. The fair values of any additions to the Company’s asset retirement obligations are measured on a non-recurring basis at the time those obligations are incurred or assumed using a discounted cash flow model. The significant inputs used in the discounted cash flow model include estimates relating to the future P&A settlement timing and costs, a credit-risk adjusted discount rate, and inflation rates. These significant inputs are based on unobservable market data and are therefore considered Level 3 inputs within the fair value hierarchy. Refer to Note 5—Asset Retirement Obligations for a further discussion of the Company’s asset retirement obligations.
Class A Common Stock. The per share fair value of the Company’s Class A Common Stock is estimated on a non-recurring basis using a Monte Carlo simulation model, which uses assumptions regarding multiple projections of the Company’s share price paths and must be repeated numerous times to achieve a probabilistic assessment. The Monte Carlo model estimates the per share fair value of the Company’s Class A Common Stock on a minority, marketable basis, and applies a discount for lack of marketability to account for the illiquidity of the Company’s Class A Common Stock. The model allocates the Company’s total equity value to the various classes of equity in its capital structure, treating all outstanding shares of the Class A Common Stock and Series A Preferred Stock as options on the entity’s enterprise value and capturing the option-like characteristics of common stock for entities whose common stock is a small portion of the total capital structure.
The significant inputs used in the Monte Carlo model include the timing and probabilities of potential liquidity event dates, equity volatilities, risk-free rates, and an estimate of the Company’s total equity value. As of September 30, 2022, the Company’s Monte Carlo valuation model assumed a risk-free interest rate of 1.61% and an expected stock price volatility rate of 65.0%. These significant inputs are based on sensitive unobservable market data and are therefore considered Level 3 inputs within the fair value hierarchy.
Note 5—Asset Retirement Obligations
The Company’s oil and natural gas properties include estimates of future expenditures to P&A wells, pipelines, platforms, and other related facilities after the reserves have been depleted. The Company recognizes the present value of the asset retirement obligation costs as a liability when it is incurred or assumed and an increase to its capitalized oil and natural gas properties. The capitalized asset retirement obligation costs are depleted over the productive lives of the oil and natural gas properties while the asset retirement obligation liability is accreted to the expected settlement value over the productive lives of the oil and natural gas properties. Upon settlement, the difference between the recorded liability amount and the amount of costs incurred is recognized as an adjustment to the capitalized cost of oil and natural gas properties.
F-17
The following table presents the change in the Company’s asset retirement obligations during the nine months ended September 30, 2022:
| (In thousands) | ||||
| Asset retirement obligations as of January 1, 2022 |
$ | 348,286 | ||
| Liabilities settled |
(18,790 | ) | ||
| Liabilities incurred |
370 | |||
| Accretion expense |
21,092 | |||
|
|
|
|||
| Asset retirement obligations as of September 30, 2022 |
350,958 | |||
| Less: current portion of asset retirement obligations |
(16,590 | ) | ||
|
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|
|||
| Asset retirement obligations, less current portion as of September 30, 2022 |
$ | 334,368 | ||
|
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|
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Note 6—Long-term Debt
The Company’s outstanding long-term debt balances consist of the following for the periods indicated:
| September 30, 2022 | December 31, 2021 | |||||||
| (In thousands) | ||||||||
| 11.75% Senior Notes due 2026 (1) |
$ | 272,500 | $ | 287,500 | ||||
| Less: unamortized discount and deferred financing costs |
(9,752 | ) | (11,986 | ) | ||||
|
|
|
|
|
|||||
| 11.75% Senior Notes due 2026, net |
262,748 | 275,514 | ||||||
| Less: current portion of 11.75% Senior Notes due 2026, net (2) |
(27,112 | ) | (27,045 | ) | ||||
|
|
|
|
|
|||||
| Long-term portion of 11.75% Senior Notes due 2026, net |
$ | 235,636 | $ | 248,469 | ||||
|
|
|
|
|
|||||
| (1) | The Company redeemed $15.0 million of its 2026 Notes outstanding principal amount at par value on April 15, 2022 as required per the 2026 Notes indenture. |
| (2) | As of September 30, 2022 and December 31, 2021, the current portion of the 11.75% Senior Notes due 2026 is presented net of the next twelve months of the unamortized discount and deferred financing costs. |
F-18
The following table presents the components of Interest expense reflected on the accompanying condensed consolidated statements of operations for the periods indicated:
| Three Months Ended September 30, | Nine Months Ended September 30, | |||||||||||||||
| 2022 | 2021 | 2022 | 2021 | |||||||||||||
| (In thousands) | ||||||||||||||||
| Interest expense on 11.75% Senior Notes due 2026 |
$ | 8,005 | $ | 8,886 | $ | 24,528 | $ | 16,291 | ||||||||
| Amortization of discount and deferred financing costs related to 11.75% Senior Notes due 2026 |
747 | 766 | 2,234 | 1,385 | ||||||||||||
| Interest expense on 11.00% Senior Notes due 2023 |
— | — | — | 8,980 | ||||||||||||
| Amortization of deferred financing costs related to the Revolving Credit Facility |
342 | 298 | 944 | 999 | ||||||||||||
| Fees associated with the Revolving Credit Facility |
282 | 296 | 708 | 833 | ||||||||||||
| Amortization of surety bond premiums |
2,625 | 2,857 | 8,074 | 8,066 | ||||||||||||
| Other interest expense |
156 | 87 | 510 | 334 | ||||||||||||
| Less: capitalized interest |
(592 | ) | (611 | ) | (1,807 | ) | (1,724 | ) | ||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Total interest expense |
$ | 11,565 | $ | 12,579 | $ | 35,191 | $ | 35,164 | ||||||||
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Revolving Credit Facility
In 2014, the Company entered into an agreement with a syndicate of banks and established the first lien senior secured revolving credit facility (the “Revolving Credit Facility”), which is secured by substantially all of the Company’s assets on a first lien basis. The Revolving Credit Facility has a maximum line of credit of $500.0 million and the borrowing base is subject to a semi-annual redetermination, based on an assessment of the value of the Company’s proved reserves as determined by a reserve report. In April 2021, the Company amended certain terms of the Revolving Credit Facility agreement and extended the maturity date to January 26, 2024, established a revised borrowing base of $165.0 million, reduced the aggregate committed amounts thereunder to $165.0 million, and modified applicable interest rates. As part of the semi-annual redeterminations, in November 2021, the Revolving Credit Facility borrowing base was increased to $200.0 million and in June 2022, the Revolving Credit Facility borrowing base and aggregated committed amounts were increased to $250.0 million and $200.0 million, respectively.
As of September 30, 2022 and December 31, 2021, the Revolving Credit Facility remained undrawn and the Company had $3.6 million in outstanding letters of credit to collateralize its oil and natural gas transportation agreements and P&A obligations, resulting in $196.4 million and $161.4 million, respectively, of availability under its Revolving Credit Facility, including its outstanding letters of credit.
Borrowings under the Revolving Credit Facility, as amended, bear interest at one of the following rates, as selected by the Company: (i) the bank’s prime rate in effect, adjusted by an applicable margin of 2.0%–4.5%; or (ii) the London Interbank Offered Rate, adjusted by an applicable margin of 3.0%–5.5%. Per the agreement, the Company may elect to convert its outstanding borrowings to a different type and interest rate.
The agreement governing the Revolving Credit Facility contains certain covenants, including maximum ratios of total funded and secured debt to EBITDAX, and a minimum ratio of current assets to current liabilities. The Company’s ability to declare and pay dividends and other restricted payments under its amended Revolving Credit Facility agreement is subject to its compliance with additional incurrence covenants, the Company
F-19
maintaining a required amount of availability under its Revolving Credit Facility, as well as the absence of any defaults by the Company under its Revolving Credit Facility. Other restrictive covenants include, but are not limited to, limitations on the Company’s ability to incur indebtedness, make loans or investments, enter into certain hedging agreements, materially change its business, or undergo a change of control.
On October 13, 2022, the Company and a majority of the lenders under its Revolving Credit Facility entered into a consent and waiver agreement (the “Consent and Waiver Agreement”), pursuant to which the consenting lenders (i) consented to the change-of-control transaction that would result from the pending merger with Talos under the terms of the Revolving Credit Facility, and (ii) agreed to waive any default or event of default under the Revolving Credit Facility resulting from such change-of-control transaction. The provisions of the Revolving Credit Facility, except as provided in the Consent and Waiver Agreement, otherwise remain in full force and effect.
Additionally, the Revolving Credit Facility agreement contains certain requirements relating to the Company’s hedging of its proved, developed, and producing reserves, which are defined in the agreement as the proved, developed, and producing reserves based on the year end or mid-year reserve reports prepared by independent third-party reserve engineers, Netherland, Sewell & Associates, Inc. The Revolving Credit Facility agreement limits the Company’s derivative contracts with delivery risk to 85% of the reasonably projected production from its proved, developed, producing reserves in December through July (“non-wind months”) and 70% of the reasonably projected production from its proved, developed, producing reserves in August through November (“wind months”).
The Revolving Credit Facility agreement also contains a minimum hedging requirement, which was amended as part of the semi-annual redetermination in November 2021. Per the agreement, as amended, if the Company’s leverage ratio is below a defined threshold on the minimum hedging test dates of March 15th and September 15th of each year (the “Minimum Hedging Test Date”), it is required to hedge a minimum of 50% of the reasonably projected production from its proved, developed, producing reserves, on a Boe basis, for the first twelve months following the Minimum Hedging Test Date. If the Company’s leverage ratio is above the defined threshold on the Minimum Hedging Test Date, then the minimum hedging requirements change to 70% of the reasonably projected production from its proved, developed, producing reserves, on a Boe basis, for the first twelve months and 50% of the reasonably projected production from its proved, developed, producing reserves, on a Boe basis, for months 13 through 18 following the Minimum Hedging Test Date.
As of September 30, 2022, the Company is in compliance with all of the covenants and hedging requirements contained in its Revolving Credit Facility agreement.
11.75% Senior Notes due 2026
On April 15, 2021, the Company completed the private offering of its $302.5 million aggregate principal amount 2026 Notes, which resulted in net proceeds of $288.4 million, net of the original issuance discount of $6.8 million and underwriter and other third-party offering costs of $7.3 million. The 2026 Notes were issued by EnVen GoM and co-issued by EnVen GoM’s wholly-owned subsidiary, EnVen Finance Corporation, and are initially guaranteed by the Company and its domestic subsidiaries which guarantee the Revolving Credit Facility. The 2026 Notes and the related guarantees are secured by second-priority liens on the Company’s and the guarantors’ assets that secure all of the indebtedness under the Revolving Credit Facility, subject to certain exceptions. The 2026 Notes will mature on April 15, 2026 and interest accrues from April 15, 2021, the date of issuance, and is to be paid semi-annually in cash in arrears on April 15th and October 15th of each year, beginning October 15, 2021. The Company amortizes the 2026 Notes discount and deferred financing costs into Interest expense on the accompanying condensed consolidated statements of operations over the term of the 2026 Notes using the interest method with an effective interest rate of 13.3%. Additionally, per the 2026 Notes indenture, the Company is required to redeem $15.0 million of the principal amount outstanding at par value on the April 15th and October 15th of each year, beginning October 15, 2021. In accordance with ASC Topic 210,
F-20
Balance Sheet, the Company classifies the portion of the 2026 Notes, net of the unamortized discount and deferred financing costs, which will be paid within the next twelve months as a current liability on its condensed consolidated balance sheets.
The indenture governing the 2026 Notes also contains certain covenants, which are customary with respect to non-investment grade debt securities, including limitations on the Company’s ability to incur and guarantee additional indebtedness, repay, redeem, or repurchase certain debt and capital stock, issue certain preferred stock or similar equity securities, pay dividends or make other distributions on capital stock, enter into certain types of transactions with affiliates, make loans or investments, and make other restricted payments. Additionally, certain covenants restrict the Company’s subsidiaries’ ability to pay dividends, create liens, and sell certain assets. As of September 30, 2022, the Company is in compliance with all of the debt covenants contained in the indenture governing the 2026 Notes.
11.00% Senior Notes due 2023
On February 15, 2018, the Company completed the private offering of its $325.0 million aggregate principal amount 11.00% senior secured second lien notes due 2023 (the “2023 Notes”), resulting in net proceeds of $317.0 million, after deducting initial purchaser fees and offering expenses of $8.0 million. The 2023 Notes were issued by EnVen GoM and co-issued by EnVen GoM’s wholly-owned subsidiary, EnVen Finance Corporation and were initially guaranteed by the Company and its domestic subsidiaries which guaranteed the Revolving Credit Facility. The 2023 Notes and the related guarantees were secured by second-priority liens on the Company’s and the guarantors’ assets that secured all of the indebtedness under the Revolving Credit Facility, subject to certain exceptions. The 2023 Notes were set to mature on February 15, 2023 and interest accrued from February 15, 2018, the date of issuance, and was paid semi-annually in cash in arrears on February 15th and August 15th of each year, beginning August 15, 2018. As of the date of issuance and until the 2023 Notes were redeemed, the Company was in compliance with all of the debt covenants contained in the indenture governing the 2023 Notes.
Throughout the fourth quarter of 2020, the Company paid $41.3 million to repurchase $48.2 million principal amount of its 2023 Notes, including $1.3 million in accrued interest. In April 2021, the Company redeemed the remaining $276.8 million principal amount of its outstanding 2023 Notes, which included paying $5.2 million of accrued interest. Additionally, upon redemption, the Company paid a call premium of $11.4 million, which is recognized as Loss on extinguishment of long-term debt on the accompanying condensed consolidated statements of operations for the nine months ended September 30, 2021 and reflects the difference between the par value and the redemption price of the 2023 Notes.
At the time of the 2023 Notes issuance, the Company analyzed the put and call features contained in the 2023 Notes indenture in accordance with ASC Topic 815, Derivatives and Hedging and determined that one of these features was an embedded derivative. The Company then elected to account for the 2023 Notes and all of its features using the fair value option instead of bifurcating the derivative; therefore, it recorded the 2023 Notes at fair value on its balance sheet and all subsequent changes in the fair value were recorded in accordance with Accounting Standards Update (“ASU”) No. 2016-01, Financial Instruments—Overall (Subtopic 825-10): Recognition and Measurement of Financial Assets and Financial Liabilities. Therefore, the change in the fair value of the 2023 Notes attributable to the change in the base market rate was recorded as a component of Gain on fair value of 11.00% Senior Notes due 2023 on the Company’s condensed consolidated statements of operations and the remainder of the change was attributable to instrument-specific credit risk and was recognized separately as Other comprehensive income (loss), net on the condensed consolidated statements of comprehensive income (loss). The Company had elected to use the U.S. Treasury bond rate as its benchmark interest rate to determine the change in the fair value attributable to instrument-specific credit risk, therefore, it compared the change in the fair value of the 2023 Notes to the change in the fair value of the U.S. Treasury bonds based on the interpolated yields of the U.S. Treasury bonds with maturities which coincided with the maturity date of the 2023 Notes. The change in the U.S. Treasury bond rate was attributable as the base market
F-21
rate change and the remainder of the change was attributable to instrument-specific credit risk, which was separately recognized as Other comprehensive income (loss), net. Additionally, ASC Topic 470-50, Modifications and Extinguishment of Debt specifies that if the Company extinguishes debt that is recorded using the fair value option then the net carrying amount of the extinguished debt should equal its fair value at the date of the redemption and any related gains or losses that have been recognized separately in Other comprehensive income (loss) should be reclassified to Net income (loss) upon extinguishment.
Therefore, at the time of the redemption, the Company recorded the outstanding amount of the 2023 Notes at their fair value and allocated the change in fair value between the change in the base market rate and the change attributable to instrument-specific credit risk. The Company then reclassified the Accumulated other comprehensive income associated with the 2023 Notes of $5.0 million to its condensed consolidated statement of operations for the nine months ended September 30, 2021 as a component of Gain on fair value of 11.00% Senior Notes due 2023. Additionally, the Gain on fair value of 11.00% Senior Notes due 2023 recognized for the nine months ended September 30, 2021 includes the reversal of $11.4 million of losses previously recognized to account for the changes in the base market rate of the 2023 Notes. Overall, during the nine months ended September 30, 2021, the Company recognized $16.6 million as Gain on fair value of 11.00% Senior Notes due 2023 and $23.0 million as Other comprehensive income (loss), net of $5.6 million attributable to non-controlling interest.
Note 7—Related Party Transactions
As of September 30, 2022, entities affiliated with Bain Capital Credit (“Bain”) held 45.7% of the Company’s Class A Common Stock and Series A Preferred Stock and three members of the Company’s Board are affiliated with Bain. Additionally, as of September 30, 2022, Adage Capital Management, L.P. (“Adage”) held 15.4% of the Company’s Class A Common Stock and Series A Preferred Stock.
In April 2021, the Company issued the 2026 Notes and used the net proceeds to redeem the remaining principal amount of its outstanding 2023 Notes. At the date of issuance, an entity affiliated with Bain purchased 8.3% of the Company’s 2026 Notes and prior to the redemption, an entity affiliated with Bain held 13.3% of the 2023 Notes. Additionally, at the date of issuance, Adage purchased 3.3% of the 2026 Notes and certain members of management purchased less than 1% of the 2026 Notes.
In connection with the Merger Agreement, Bain, Adage, and certain other equity investors holding a majority of the outstanding shares of the Company’s Class A Common Stock (collectively, the “EnVen Supporting Stockholders”) entered into several agreements with the Company and Talos (the “EnVen Support Agreements”). Pursuant to the EnVen Support Agreements, the EnVen Supporting Stockholders have agreed, among other things, to vote all shares of the Company’s Class A Common Stock and Series A Preferred Stock beneficially owned by such equity holders (i) in favor of approving the Merger Agreement, the Merger, and the conversion of the Company’s Series A Preferred Stock (as specified in the Merger Agreement) and (ii) against any Acquisition Proposal (as defined in the Merger Agreement) with respect to the Company and any other action, proposal, transaction, or agreement that could reasonably be expected to impede, interfere with, delay, postpone, or materially and adversely affect the Talos Merger.
Note 8—Stock-based Compensation
Incentive Award Plan
The Company has established the EnVen Energy Corporation and Energy Ventures GoM LLC 2015 Incentive Award Plan (the “2015 Incentive Plan”) which authorizes the granting of Restricted Stock, stock options, performance bonuses, and other incentive awards to eligible employees, consultants, and members of its Board. Pursuant to the 2015 Incentive Plan, the Company was authorized to award up to 2,583,301 shares of its Class A Common Stock. On December 13, 2018, the Company amended the 2015 Plan (“2015 Incentive Plan Amendment”) and all of the awards granted on or after December 13, 2018 will be granted under the 2015
F-22
Incentive Plan Amendment. Pursuant to the 2015 Incentive Plan Amendment, the Company is authorized to award up to 2,720,000 shares of its Class A Common Stock. As of September 30, 2022, the Company had 373,209 shares of its Class A Common Stock available for grant under the 2015 Incentive Plan Amendment and all incentive awards granted to date have been to employees or members of its Board.
Restricted Stock Awards and Units
The Company awards time-based and performance-based non-qualified Restricted Stock subject to the terms, restrictions, and vesting requirements defined in the restricted stock agreements. Additionally, the Company has employment agreements with certain employees with varying terms that provide for, among other things, the accelerated vesting of all non-vested equity awards upon the (i) retirement after the eligible age of 65 or (ii) termination of employment without cause (the “Accelerated Vesting Conditions”).
The Company’s Restricted Stock does not have any post-vesting restrictions, therefore, the fair value of each share of Restricted Stock on the date of the grant is determined based on the per share fair value of its Class A Common Stock on a minority, non-marketable basis. The per share fair value of the Company’s Class A Common Stock is estimated at the grant date of the shares. Refer to Note 4—Fair Value Measurements for a discussion of the fair value of the Company’s Class A Common Stock.
The aggregate fair value of the Restricted Stock vested during the nine months ended September 30, 2022 was $19.5 million and the Company withheld 302,727 shares of the vested Restricted Stock on behalf of the Restricted Stock holders to satisfy the related tax withholding obligations. Any shares withheld in connection with such tax withholdings will be available for new grants. Additionally, during the nine months ended September 30, 2022, the Company repurchased and retired 90,675 shares of vested Restricted Stock from current employees and members of its Board for $2.3 million, the aggregate fair value of the vested Restricted Stock on the date of the repurchase. These repurchased shares are not available for new grants.
Time-based Restricted Stock
The Company awards time-vested non-qualified Restricted Stock subject to the terms, restrictions, and vesting requirements defined in the restricted stock agreements. Time-vested Restricted Stock contains a vesting period subject to the Restricted Stock holder continuing employment or service and generally vests in installments over a period of three years.
The Company recognizes compensation expense related to time-based Restricted Stock on a straight-line basis over the requisite service period based on the fair value of the Restricted Stock on the grant date. In accordance with ASC Topic 718, Compensation—Stock Compensation, for the time-based Restricted Stock subject to Accelerated Vesting Conditions, as discussed above, the Company considers the accelerated vesting when determining the requisite service period over which to recognize the compensation expense and utilizes the lesser of the stated service period or the period in which the Restricted Stock holder is no longer required to continue employment or service. Additionally, the Company has elected to not estimate the forfeiture rate of its time-based Restricted Stock in its initial calculation of compensation expense, but instead adjusts compensation expense for forfeitures as they occur.
F-23
The following table presents the Company’s time-based Restricted Stock activity during the nine months ended September 30, 2022:
| Time-based Restricted Stock |
Weighted Average Grant Date Fair Value |
|||||||
|
Non-vested as of January 1, 2022 |
759,265 | $ | 12.82 | |||||
| Granted |
295,898 | $ | 32.45 | |||||
| Vested |
(374,519 | ) | $ | 13.69 | ||||
| Forfeitures |
(5,510 | ) | $ | 20.22 | ||||
|
|
|
|||||||
| Non-vested as of September 30, 2022 |
675,134 | $ | 20.89 | |||||
|
|
|
|||||||
The Company recognized compensation expense related to time-based Restricted Stock of $2.2 million and $5.4 million during the three and nine months ended September 30, 2022, respectively, and $1.5 million and $3.0 million during the three and nine months ended September 30, 2021, respectively. As of September 30, 2022, there was $7.7 million of unrecognized compensation expense related to time-based Restricted Stock, which is expected to be recognized over a weighted average period of 1.3 years.
Performance-based Restricted Stock
The Company awards performance-based non-qualified Restricted Stock subject to the terms, restrictions, and vesting requirements defined in the restricted stock agreements. Performance-based Restricted Stock vests only if the Company achieves certain performance goals during a predetermined performance period and depending on the performance metric, the vesting of certain performance-based Restricted Stock is subject to the Restricted Stock holder fulfilling varying employment conditions. On a quarterly basis, the Company assesses the likelihood that the performance conditions associated with its performance-based Restricted Stock will be achieved and the expected level of achievement. When the level of a performance metric is determined, the Company considers any difference between the number of awards associated with the maximum and the actual performance level as canceled. Additionally, the Company considers any unvested performance-based Restricted Stock remaining at the end of any predetermined performance period as canceled.
The Company only begins recognizing compensation expense related to its performance-based Restricted Stock at the time the performance condition is deemed probable of occurring. Once the performance condition is deemed probable of occurring, the Company recognizes the compensation expense related to those performance-based Restricted Stock shares on a straight-line basis over the stated performance period based on the fair value of the Restricted Stock on the grant date. If necessary, the Company may adjust the compensation expense related to performance-based Restricted Stock to reflect material changes in the probability or achievement level of the metric. For the performance-based Restricted Stock subject to Accelerated Vesting Conditions, as noted above, the Company considers the accelerated vesting when determining the requisite service period over which to recognize the compensation expense and utilizes the lesser of the stated performance period or the period in which the Restricted Stock holder is no longer required to continue employment or service. Additionally, the Company has elected to not estimate the forfeiture rate of its performance-based Restricted Stock in its initial calculation of compensation expense, but instead adjusts compensation expense for forfeitures as they occur.
F-24
The following table presents the Company’s performance-based Restricted Stock activity during the nine months ended September 30, 2022:
| Performance-based Restricted Stock |
Weighted Average Grant Date Fair Value |
|||||||
| Non-vested as of January 1, 2022 |
1,076,406 | $ | 13.51 | |||||
| Granted |
479,195 | $ | 32.45 | |||||
| Vested |
(450,388 | ) | $ | 14.56 | ||||
| Canceled |
(140,890 | ) | $ | 11.97 | ||||
| Forfeitures |
(8,234 | ) | $ | 21.77 | ||||
|
|
|
|||||||
| Non-vested as of September 30, 2022 |
956,089 | $ | 22.55 | |||||
|
|
|
|||||||
A portion of the performance-based Restricted Stock granted will vest based on the achievement of certain performance metrics in future years. As of September 30, 2022, the performance metrics associated with 311,662 shares, net of forfeitures, granted in May 2021 and March 2022 have not been established; therefore, the Company cannot yet determine the grant date or the fair value of these shares and is considering the shares as issued, but not yet granted. During the nine months ended September 30, 2022, the baseline for a performance metric associated with 251,940 shares of performance-based Restricted Stock granted in June 2020 and May 2021 was finalized, as a result, these shares are considered granted, at their maximum performance level, during the nine months ended September 30, 2022 and are presented as such in the table above.
During the nine months ended September 30, 2022, the Company determined that certain performance metrics associated with some of its performance-based Restricted Stock will likely be met. As a result, the Company recognized $6.9 million and $9.1 million in compensation expense during the three and nine months ended September 30, 2022, respectively. During the three and nine months ended September 30, 2021, the Company recognized $1.8 million and $2.6 million, respectively, in compensation expense related to certain performance-based Restricted Stock.
As of September 30, 2022, there is $12.2 million of unrecognized compensation expense related to the Company’s non-vested performance-based Restricted Stock, $3.6 million of which approximates the maximum expense associated with certain shares that have a weighted average stated performance period of 0.3 years. The remaining unrecognized compensation expense is associated with non-vested performance-based Restricted Stock shares which have a weighted average term of 3.6 years. Additionally, as discussed above, the performance metrics for certain of the performance-based Restricted Stock issued in May 2021 and March 2022 have not been established; therefore, the Company cannot yet determine the grant date or the related fair value and compensation expense associated with those performance-based shares.
Stock Options
The Company had previously awarded non-qualified stock options, which represent the right to purchase its Class A Common Stock at a specified price (“Stock Options”). The Company did not grant any Stock Options during the nine months ended September 30, 2022 and as of January 1, and September 30, 2022, all of the 682,650 outstanding Stock Options were vested and exercisable. As of September 30, 2022, all of the Company’s outstanding Stock Options have an exercise price of $10.00 and a weighted average remaining contractual term of 3.1 years. The Company has recognized all of the compensation expense related to its Stock Options prior to 2020.
Note 9—Concentrations of Risk
Accounts Receivable
The Company does not require its oil and natural gas purchasers to post collateral and an inability or failure of any its significant customers to meet their obligations or their insolvency or liquidation could adversely affect its
F-25
financial results. The Company evaluates the credit standing of its oil and natural gas purchasers as it deems appropriate under the circumstances, which may include reviewing a purchaser’s credit rating, latest financial information, their historical payment record, the financial ability of the purchaser’s parent company to make payment if the purchaser cannot, and undertaking the due diligence necessary to determine credit terms and credit limits.
Derivative Instruments
The Company’s use of derivative instruments exposes it to the risk that its derivative counterparties will be unable to meet their commitments under the arrangements. The Company manages this risk by using multiple counterparties, all of which are registered swap dealers that have an “investment grade” credit rating. Additionally, the Company continually monitors the creditworthiness of its derivative counterparties to determine if any credit risk adjustment is necessary to the fair values of its derivative instruments or if any nonperformance risk exists. Since all of the Company’s derivative counterparties are large financial institutions with investment-grade credit ratings, the Company believes it does not have any significant credit risk associated with its counterparties and does not currently anticipate any nonperformance from its counterparties.
Current Expected Credit Losses
The Company estimates the current expected credit losses related to its short-term receivables using an aging method based on historical loss data that, if warranted, is adjusted for asset-specific considerations and current economic conditions. Upon the adoption of ASU No. 2016-13, Financial Instruments—Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments effective January 1, 2020, the Company analyzed the aging of its short-term oil, natural gas, and NGL revenue, production handling agreements revenue, and joint interest and other accounts receivables and its derivative settlement receivables and determined that it did not need to record an adjustment for credit loss related to those short-term receivables because the credit losses have historically been immaterial. Further, the Company has determined that no allowance is necessary as of September 30, 2022 and December 31, 2021. The Company will continue to review the aging of these short-term receivables on a quarterly basis and if necessary, could record an allowance in future periods.
Note 10—Commitments and Contingencies
Revenue Performance Obligations
Oil and natural gas production sales contracts. All of the Company’s oil and natural gas production sales contracts are short-term in nature with a contract term of one year or less. As such, the Company has elected to utilize the practical expedient within ASC Topic 606, Revenue from Contracts with Customers (“ASC 606”) exempting it from the disclosure of the transaction price allocated to the remaining performance obligations if the performance obligation is part of a contract that has an original expected duration of one year or less. Additionally, under the Company’s oil and natural gas production sales contracts, each unit of product represents a separate wholly unsatisfied performance obligation for which the variable payment relates specifically to the efforts to satisfy that performance obligation and allocating the variable consideration is consistent with the allocation objective. Therefore, the disclosure of the transaction price allocated to the remaining performance obligations for these contracts is not required under ASC 606-10-32-40.
Production handling service contracts. All of the Company’s production handling service contracts are long-term in nature with a contract term of one year or more. The transaction price for the Company’s production handling service contracts is comprised of both fixed and variable consideration, which are received monthly as the distinct service is provided. The fixed consideration typically relates to monthly minimum fees, production system operation fees, or infrastructure access fees. The variable consideration may include operating and production handling fees which are based on either contractual rates for units of production serviced or a proportionate expense fee.
F-26
As of September 30, 2022, the Company had approximately $15.0 million of remaining performance obligations related to the fixed consideration of its production handling service contracts with expected durations of approximately half a year to 11.3 years. The Company recognized $0.7 million and $2.1 million of revenue related to the fixed consideration of its production handling service contracts performance obligations during the three and nine months ended September 30, 2022, respectively. In August 2021, Hurricane Ida caused all of the Company’s platforms that provide third-party processing to be shut-in for several weeks; therefore, the Company was not able to collect certain monthly minimum fees, resulting in $0.3 million and $1.2 million of revenue related to the fixed consideration of its production handling service contracts performance obligations during the three and nine months ended September 30, 2021, respectively. The Company expects to recognize approximately $2.4 million, $1.2 million, and $1.2 million of the remaining fixed consideration performance obligations as revenue annually over the next three years and the remaining amount allocated to those performance obligations ratably over the following 8.4 years.
Asset Retirement Obligations
Marathon Acquisition. Pursuant to purchase agreements executed in December 2015 and February 2016, the Company was required to deposit approximately $100.0 million into escrow accounts to use for future P&A obligation costs assumed in the acquisitions. In December 2015, the Company deposited approximately $30.0 million into escrow to fully fund one of the P&A obligations and funded the remaining $70.0 million obligation by depositing a percentage of net revenues from the acquired properties into a separate escrow account, on a quarterly basis, beginning in January 2017 until October 2021. As of December 31, 2021, the escrow accounts are fully funded and the Company has no remaining future funding obligations. As of September 30, 2022 and December 31, 2021, these escrow accounts have a combined balance of $100.5 million and $100.7 million, respectively, inclusive of interest earned to date, and are reflected as Restricted cash on the condensed consolidated balance sheets.
Notes receivable, net. The Company holds two notes receivables which consist of commitments from the sellers of oil and natural gas properties, acquired by the Company, related to the costs associated with its performance of the assumed P&A obligations (the “P&A Notes Receivable”). As of September 30, 2022 and December 31, 2021, both of the P&A Notes Receivable have fully accreted to their principal amounts of $65.1 million and are presented as such, net of related cumulative estimated credit losses, on the accompanying condensed consolidated balance sheets.
The Company estimates any current expected credit losses related to its P&A Notes Receivable on a combined amortized basis using the probability of default method based on the long-term credit ratings of the counterparties of the notes, which are currently considered “investment grade.” The Company records any changes in the current estimated credit losses related to its P&A Notes Receivable as part of Other income on the accompanying condensed consolidated statements of operations. During the nine months ended September 30, 2022 and 2021, the Company recognized interest income of less than $0.1 million and $2.6 million, respectively, related to its P&A Notes Receivable. The Company did not recognize any interest income related to its P&A Notes Receivable during the three months ended September 30, 2022 or 2021.
Other obligations. The Bureau of Ocean Management and certain third-parties require the Company to post supplemental and performance bonds as a means to ensure its decommissioning obligations, such as the plugging of wells, the removal of platforms and other offshore facilities, the abandonment of offshore pipelines, and the clearing of the seafloor of obstructions. If needed, the Company may enter into arrangements with surety companies who provide such bonds on its behalf. In exchange, the Company pays an annual premium to the surety for its financial strength to extend the credit. These surety bond premiums are recognized in Prepaid expenses and other current assets on the accompanying condensed consolidated balance sheets and are amortized over the life of the surety bonds into Interest expense on the accompanying condensed consolidated statements of operations. The Company did not pay any cash for surety bond premiums during the three months ended September 30, 2022 and paid $5.3 million during the nine months ended September 30, 2022. During the three
F-27
and nine months ended September 30, 2022, the Company amortized $2.6 million and $8.1 million, respectively, of the premiums into Interest expense on the accompanying condensed consolidated statements of operations. During the three and nine months ended September 30, 2021, the Company paid $2.5 million and $8.5 million, respectively, for surety bond premiums and amortized $2.9 million and $8.1 million, respectively, of the premiums into Interest expense on the accompanying condensed consolidated statements of operations.
Notes Payable
On December 30, 2019, the Company entered into a financing agreement for payments due under a licensing agreement for seismic data, paying an initial installment of $3.0 million in the first quarter of 2020, and agreeing to pay eight quarterly installments of $2.2 million beginning on July 1, 2020 through April 1, 2022, at an imputed interest rate of 4.75%. Per the agreement, the Company paid $2.2 million and $6.7 million of the notes payable balance during the three and nine months ended September 30, 2021, respectively. As of December 31, 2021, the outstanding balance of this note payable was $4.4 million which is reflected as a current note payable on the accompanying condensed consolidated balance sheet. Per the agreement, the Company paid $4.5 million of notes payable balance during the nine months ended September 30, 2022, which included the final installment on April 1, 2022, resulting in a zero balance as of September 30, 2022.
Legal Proceedings
From time to time, the Company could be subject to legal actions and claims arising in the ordinary course of business. It is the opinion of management that the outcome of these matters will not have a material adverse effect on the Company’s financial position or results of operations.
In June 2019, David M. Dunwoody, Jr., former President of the Company, filed a lawsuit against the Company in Texas District Court alleging that the circumstances of his resignation constituted “Good Reason” under his employment agreement dated as of November 6, 2015 (the “Employment Agreement”), and entitled him to the severance payments and benefits as set forth in his Employment Agreement for a resignation for “Good Reason.” In September 2021, the trial court entered a judgment of $12.4 million in favor of Mr. Dunwoody, inclusive of Mr. Dunwoody’s legal fees and interest, which the Company has recorded as a non-current liability on its condensed consolidated balance sheets as of September 30, 2022 and December 31, 2021. The Company disagrees with many of the trial court’s rulings and does not agree with Mr. Dunwoody’s assertion that he had “Good Reason” to resign from his employment. The Company expects the appellate process to continue for the foreseeable future.
In July 2019, the Company filed a lawsuit against Mr. Dunwoody in Delaware Chancery Court for breach of fiduciary duty and equitable fraud relating to Mr. Dunwoody’s conduct while he was President of the Company. In January 2020, the Company filed an amended complaint that added claims against Oilfield Pipe of Texas, LLC for aiding and abetting Mr. Dunwoody’s breach of his fiduciary duty and equitable fraud. On April 21, 2022, the Delaware Chancery Court denied Mr. Dunwoody’s renewed motion to dismiss and the parties are engaged in discovery. The Delaware Chancery Court has scheduled the trial for July 2023. The Company may recognize additional liabilities and expenses in future periods related to this litigation with Mr. Dunwoody.
Note 11—Leases
The Company capitalizes its operating leases as right-of-use (“ROU”) assets and lease liabilities on the accompanying condensed consolidated balance sheets and recognizes the fixed minimum lease costs for its operating leases on a straight-line basis over the lease term in accordance with ASC Topic 842, Leases (“ASC 842”). The Company does not recognize leases with initial lease terms less than or equal to 12 months on the balance sheet and only includes those short-term leases as part of its lease-related disclosures. Additionally, the Company does not include any of its variable lease costs in the calculation of its ROU assets and lease liabilities, as none of the variable costs are based on an index or rate. Instead, all of the variable costs are based on the
F-28
performance of the leased asset or the level of use of other non-lease components due to the election of the practical expedient to not separate the lease and non-lease components when measuring lease payments.
The Company makes certain assumptions and judgments when determining its ROU assets and lease liabilities. When determining whether a contract contains a lease, the Company considers whether there is an identified asset that is physically distinct, whether the supplier has substantive substitution rights, whether the Company has the right to obtain substantially all of the economic benefits from the use of the asset, and whether it has the right to control the asset. Certain of the Company’s leases include one or more options to renew the lease, with renewal terms that can extend the lease term for additional years. When determining if renewals should be included in the lease term to be recognized, the Company utilizes the reasonably certain threshold, therefore, certain of the leases included in the calculation of its ROU assets and lease liabilities include optional renewal periods for which it is not contractually obligated. Additionally, the Company must estimate its incremental borrowing rate when the implicit rate is not stated in the lease agreement and cannot be readily determined. As of September 30, 2022, none of the Company’s active leases contain purchase or termination options that are reasonably certain to be exercised.
Office space and information technology equipment leases. The Company has several operating leases for office space and information technology equipment (“IT Equipment”) used in its daily operations, for which it records the related lease costs as G&A expenses on the accompanying condensed consolidated statements of operations.
The following table presents the components of the Company’s office space and IT Equipment operating lease costs during the periods indicated:
| Three Months Ended September 30, |
Nine Months Ended September 30, |
|||||||||||||||
| 2022 | 2021 | 2022 | 2021 | |||||||||||||
| (In thousands) | ||||||||||||||||
| Office space and IT equipment operating lease costs |
$ | 718 | $ | 712 | $ | 2,155 | $ | 2,178 | ||||||||
| Variable office space and IT equipment operating lease costs |
390 | 383 | 1,170 | 1,078 | ||||||||||||
|
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|
|
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|
|
|
|||||||||
| Total office space and IT equipment operating lease costs (1) |
1,108 | 1,095 | 3,325 | 3,256 | ||||||||||||
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|
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| (1) | None of the total office space and IT equipment operating lease costs incurred during the three and nine months ended September 30, 2022 and 2021 relate to short-term leases. |
During the nine months ended September 30, 2022 and 2021, the Company made cash payments related to its office space and IT Equipment leases of $3.0 million and $2.8 million, respectively, which are included in its cash flows from operating activities on the accompanying condensed consolidated statements of cash flows.
Drilling rig operating leases. The scope of ASC 842 does not include leases to explore or use minerals, oil, natural gas, and similar non-regenerative resources; therefore, the Company’s oil and natural gas leases are excluded, but the equipment used to explore for natural resources, which includes drilling rigs, marine vessels, and other equipment used in the exploration and development of oil and natural gas assets are included in the scope of ASC 842. In accordance with the full cost method of accounting for oil and natural gas properties, the Company capitalizes the portion of its lease costs which relate to its drilling rig operating leases as part of its oil and natural gas property balance. In lease agreements where the Company is the designated operator per a joint operations arrangement, any related ROU assets and lease liabilities are calculated using the gross payment amount rather than the net amounts based on its working interest in the related property. However, when the costs are incurred, the Company only recognizes its share of the drilling rig operating lease costs in its condensed consolidated financial statements.
F-29
The following table presents the components of the Company’s drilling rig operating leases capitalized during the periods indicated:
| Three Months Ended September 30, |
Nine Months Ended September 30, |
|||||||||||||||
| 2022 | 2021 | 2022 | 2021 | |||||||||||||
| (In thousands) | ||||||||||||||||
| Drilling rig operating lease costs |
$ | 2,769 | $ | 2,139 | $ | 9,668 | $ | 7,762 | ||||||||
| Variable drilling rig operating lease costs |
168 | 262 | 1,404 | 745 | ||||||||||||
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|
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| Total drilling rig operating lease costs (1) |
$ | 2,937 | $ | 2,401 | $ | 11,072 | $ | 8,507 | ||||||||
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| (1) | None of the total drilling rig operating lease costs incurred during the three and nine months ended September 30, 2022 and 2021 relate to short-term leases; however, the total drilling rig operating lease costs for the current period are not indicative of the Company’s current or future lease costs and obligations, as it routinely enters into short-term drilling rigs contracts to support its drilling activities. As of September 30, 2022, the Company’s short-term lease obligations are approximately $23.7 million. |
Additionally, during each of the three and nine months ended September 30, 2021, the Company recognized $0.4 million of drilling rig operating lease costs related to P&A costs. The Company did not recognize any drilling rig operating lease costs related to P&A costs during the three and nine months ended September 30, 2022.
During the nine months ended September 30, 2022 and 2021, the Company made cash payments of $14.4 million and $14.1 million, respectively, related to its drilling rig operating lease costs, $12.3 million and $10.8 million, respectively, of which are included in its cash flows from investing activities on the accompanying condensed consolidated statements of cash flows.
Total lease liabilities. As of September 30, 2022, the Company had total lease liabilities of $19.4 million on the accompanying condensed consolidated balance sheet. To determine the present value of its future lease payments as of September 30, 2022, the Company applied a weighted average incremental borrowing rate of 5.9% and a weighted average remaining lease term of 6.4 years. During the nine months ended September 30, 2022, the Company recognized an additional $13.9 million in both ROU asset and lease liabilities. The Company did not recognize any additional ROU assets or liabilities during the three months ended September 30, 2022.
As of September 30, 2022, the Company’s lease liabilities consisted of the following:
| (In thousands) | ||||
| October 1, 2022 through September 30, 2023 |
$ | 6,472 | ||
| October 1, 2023 through September 30, 2024 |
2,321 | |||
| October 1, 2024 through September 30, 2025 |
2,134 | |||
| October 1, 2025 through September 30, 2026 |
2,169 | |||
| October 1, 2026 through September 30, 2027 |
2,211 | |||
| Thereafter |
7,479 | |||
|
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|||
| Total future lease payments (1) |
22,786 | |||
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|
|||
| Less: present value discount |
(3,387 | ) | ||
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|||
| Total lease liabilities as of September 30, 2022 |
$ | 19,399 | ||
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|
| (1) | As of September 30, 2022, total future lease payments include payments of $18.4 million, $4.1 million, and $0.3 million for office space, drilling rigs and IT equipment, respectively. Payments for drilling rigs are presented on a gross basis and do not reflect the Company’s net proportionate share of such amounts, as the Company will bill other joint interest owners for their working interest share of such costs. The Company’s share of the drilling rig costs are generally capitalized as part of its oil and natural gas property balance. |
F-30
Note 12—Income Taxes
The Company estimates its annual effective income tax rate on a quarterly basis based on its current annual forecasted operating results adjusted for any discrete items in the period in which they are identified. Each quarter, the Company updates these rates and records a cumulative adjustment to income tax expense or benefit by applying the updated rates to the year-to-date pre-tax income or loss.
Any temporary differences between the book and tax earnings of the underlying partnership that are allocated to the Company affect the components of the deferred tax balance.
The Company’s effective tax rates were 13.3% and 13.5% for the three and nine months ended September 30, 2022, respectively, and 20.1% and 10.9% for the three and nine months ended September 30, 2021, respectively. The overall change in the Company’s effective tax rates for the three and nine months ended September 30, 2022 compared to the same periods of 2021, is primarily a result utilizing certain deferred tax assets which were previously subjected to a valuation allowance in 2021. Additionally, during the three and nine months ended September 30, 2021, the Company recorded a discrete income tax benefit of $3.1 million related to the 2023 Notes.
Note 13—Supplemental Cash Flow Information
The following table presents a reconciliation of cash, cash equivalents, and restricted cash reported on the accompanying condensed consolidated statements of cash flows for the periods indicated:
| September 30, | ||||||||
| 2022 | 2021 | |||||||
| (In thousands) | ||||||||
| Cash and cash equivalents |
$ | 192,124 | $ | 104,466 | ||||
| Restricted cash (1) |
100,460 | 96,948 | ||||||
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| Total cash, cash equivalents, and restricted cash |
$ | 292,548 | $ | 201,414 | ||||
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| December 31, 2021 | ||||||||
| (In thousands) | ||||||||
| Cash and cash equivalents |
$ | 88,930 | ||||||
| Restricted cash (1) |
100,695 | |||||||
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| Total cash, cash equivalents, and restricted cash |
$ | 189,625 | ||||||
|
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| (1) | Restricted cash primarily consists of cash held in escrow for future P&A obligations, refer to Note 10—Commitments and Contingencies for a discussion of the restricted cash balances related to certain of the Company’s P&A obligations. |
F-31
The following table presents non-cash investing and financing activities and the supplemental disclosure relating to cash paid for interest and income taxes during the periods indicated:
| Nine Months Ended September 30, |
||||||||
| 2022 | 2021 | |||||||
| (In thousands) | ||||||||
| Non-cash investing and financing activities: |
||||||||
| Expenditures for property and equipment in accrued liabilities and non-current liabilities |
$ | 13,212 | $ | (1,021 | ) | |||
| Expenditures for unevaluated oil and natural gas leases in accrued liabilities |
— | (5,879 | ) | |||||
| Neptune Acquisition closing adjustments (1) |
464 | — | ||||||
| Changes in asset retirement obligations |
370 | 14,464 | ||||||
| Lease cost property additions |
(202 | ) | 35 | |||||
| Series A preferred stock dividends—paid-in-kind (2) |
— | (6,484 | ) | |||||
| Series A preferred stock dividends—beneficial conversion feature (3) |
— | 28,267 | ||||||
| Supplemental disclosure: |
||||||||
| Interest paid on debt, net of amounts capitalized |
$ | 15,814 | $ | 19,733 | ||||
| Income taxes paid (4) |
20,800 | 1,950 | ||||||
| (1) | Reflects the remaining final settlement payment from BHP received in January 2022 for the Neptune Acquisition, which was reflected as non-cash investing activity for the year ended December 31, 2021. Refer to Note 2—Acquisitions of Oil and Natural Gas Properties for a further discussion. |
| (2) | In the first quarter of 2021, the Company paid the quarterly Series A Preferred Stock dividends by issuing shares of its Series A Preferred Stock (“PIK Shares”). However, the second and third quarters of 2021 and throughout 2022, the Company’s Board has elected to pay the dividends in cash rather than issuing PIK Shares. |
| (3) | Reflects the cumulative effect adjustment for the adoption ASU No. 2020-06, Debt – Debt with Conversion and Other Options (Subtopic 470-20) and Derivatives and Hedging – Contracts in Entity’s Own Equity (Subtopic 815-40): Accounting for Convertible Instruments and Contracts in an Entity’s Own Equity, effective January 1, 2021, to reverse the beneficial conversion feature associated with the Company’s Series A Preferred Stock PIK Share dividends outstanding as the effective date. The adoption of this ASU eliminated the accounting model for the beneficial conversion feature related to the PIK Share dividends of the Company’s Series A Preferred Stock. |
| (4) | During the nine months ended September 30, 2022, the Company made estimated tax payments of $32.7 million in accordance with the U.S. Internal Revenue Code and its current tax projections. |
Note 14—Subsequent Events
As discussed in Note 6—Long-term Debt, on October 13, 2022, the Company and a majority of the lenders under its Revolving Credit Facility entered into a Consent and Waiver Agreement, in which the consenting lenders (i) consented to the change-of-control transaction that would result from the pending merger with Talos under the terms of the Revolving Credit Facility, and (ii) agreed to waive any default or event of default under the Revolving Credit Facility resulting from such change-of-control transaction.
The Company has evaluated subsequent events from the balance sheet date as of September 30, 2022 through December 5, 2022, the date at which these unaudited condensed consolidated financial statements were available to be issued and has determined there are no other events to disclose.
F-32
Exhibit 99.3
Unless the context otherwise requires, references to:
| • | “Talos,” “we,” “us,” “our,” or the “Company,” refer to Talos Energy Inc., a Delaware corporation; |
| • | “Talos Production” refer to Talos Production Inc., a Delaware corporation; |
| • | “Merger Sub Inc.” refer to Tide Merger Sub I Inc., a Delaware corporation and a wholly owned, direct subsidiary of Talos; |
| • | “Merger Sub LLC” refer to Tide Merger Sub II LLC, a Delaware limited liability company and a wholly owned, direct subsidiary of Talos; |
| • | “UnSub” refer to Tide Merger Sub III LLC, a Delaware limited liability company and wholly owned subsidiary of Talos Production; |
| • | “EnVen” refer to EnVen Energy Corporation, a Delaware corporation; |
| • | “Equityholders’ Representative” refer to BCC Enven Investments, L.P., a Delaware limited partnership, or any successor thereto; |
| • | “Merger Agreement” refer to the Agreement and Plan of Merger, dated as of September 21, 2022, by and between Talos, Talos Production, Merger Sub Inc., Merger Sub LLC, UnSub, the Equityholders’ Representative and EnVen; |
| • | “First Merger” refer to the merger, pursuant to the Merger Agreement, of Merger Sub Inc. with and into EnVen, with EnVen continuing as the First Surviving Corporation in the First Merger; |
| • | “First Surviving Corporation” refer to EnVen following the First Merger; |
| • | “Surviving Company” refer to Merger Sub LLC following the Second Merger; |
| • | “Second Merger” refer to the merger, pursuant to the Merger Agreement and immediately following the First Merger, of the First Surviving Corporation with and into Merger Sub LLC, with Merger Sub LLC continuing as the Surviving Company; |
| • | “Talos Second Lien Notes” refer to the 12.00% Second-Priority Senior Secured Notes due 2026 issued pursuant to the Talos Second Lien Notes Indenture; |
| • | “Talos Second Lien Notes Indenture” refer to the Indenture relating to the Talos Second Lien Notes by and among Talos Production, the guarantors party thereto and Wilmington Trust, National Association as trustee and collateral agent, dated as of January 4, 2021, as supplemented by that certain First Supplemental Indenture, dated as of January 14, 2021; |
| • | “EnVen Second Lien Notes” refer to the 11.75% Senior Secured Second Lien Notes due 2026 of EnVen; |
| • | “Third Merger” refer to the merger, pursuant to the Merger Agreement and immediately following the Second Merger, of the Surviving Company with and into Talos Production or UnSub, as the case may be; |
| • | “Effective Time” refer to the effective time of the First Merger; |
| • | “Mergers” refer to the First Merger, the Second Merger and the Third Merger, collectively; |
| • | “Closing” refer to the closing of the Mergers; |
| • | “Closing Date” refer to the date of the Effective Time; |
| • | EnVen PSUs” refer to the performance-based restricted stock units of EnVen issued pursuant to the EnVen Incentive Award Plan; |
| • | “EnVen Incentive Award Plan” refer to the EnVen Energy Corporation and Energy Ventures GoM LLC 2015 Incentive Award Plan, as amended; |
| • | “EnVen RSUs” refer to the time-based restricted stock units of EnVen issued pursuant to the EnVen Incentive Award Plan; |
| • | “EnVen Options” refer to the outstanding options issued under the EnVen Incentive Award Plan to purchase shares of EnVen Common Stock; and |
| • | “EnVen Common Stock” refer to the Class A common stock of EnVen, par value $0.001 per share. |
1
TALOS ENERGY INC.
UNAUDITED PRO FORMA CONDENSED COMBINED FINANCIAL STATEMENTS
On September 21, 2022, Talos, Talos Production, Merger Sub Inc., Merger Sub LLC, UnSub, EnVen, and the Equityholders’ Representative entered into the Merger Agreement. The Merger Agreement provides that, among other things and upon the terms and subject to the conditions set forth therein, Merger Sub Inc. will merge with and into EnVen, with EnVen continuing as the First Surviving Corporation in the First Merger, and, immediately following the First Merger, the First Surviving Corporation will merge with and into Merger Sub LLC, with Merger Sub LLC continuing as the Surviving Company in the Second Merger. In connection therewith, Talos initiated a notes consent solicitation (the “Notes Consent Solicitation”) on October 21, 2022 to obtain the requisite holders’ consent to certain amendments to the Talos Second Lien Notes Indenture to permit the incurrence of indebtedness in respect of the EnVen Second Lien Notes. The Notes Consent Solicitation closed on October 27, 2022, with consents received from holders of 95.8% of the aggregate principal amount of the Talos Second Lien Notes. As a result, the Surviving Company merged with and into Talos Production, with Talos Production surviving the Third Merger as the surviving entity on February 13, 2023.
At the Effective Time, merger consideration consisted of the following:
| a) | 43,800,000 shares of Talos Common Stock; and |
| b) | cash equal to (i) $212.5 million, less (ii) the amount of cash paid by EnVen (and not otherwise funded by the applicable awardholder) in respect of withholding tax liabilities associated with the settlement of EnVen time-based restricted stock units and performance-based restricted stock units and the exercise of EnVen stock options outstanding as of immediately prior to the Effective Time, each in accordance with the Merger Agreement, plus (iii) the aggregate exercise price of all EnVen stock options received by EnVen in cash prior to the Effective Time in connection with the exercise of EnVen stock options outstanding as of immediately prior to the Effective Time in accordance with the Merger Agreement. |
The following unaudited pro forma combined financial statements (which we refer to as the “pro forma financial statements”) have been prepared from the respective historical consolidated financial statements of Talos and EnVen, adjusted to give effect to the Mergers and related financing consisting of borrowings under Talos Production’s revolving credit facility. The unaudited pro forma condensed combined statement of operations for the nine months ended September 30, 2022, and the year ended December 31, 2021, combine the historical consolidated statement of operations of Talos and EnVen, giving effect to the Mergers and related financing as if the transaction had been consummated on January 1, 2021. The unaudited pro forma condensed combined balance sheet combines the historical consolidated balance sheets of Talos and EnVen as of September 30, 2022, giving effect to the Mergers and related financing as if the transaction had been consummated on September 30, 2022. The pro forma financial statements contain certain reclassification adjustments to conform the historical EnVen financial statement presentation to Talos’ financial statement presentation.
The pro forma financial statements are presented to reflect the Mergers and related financing and do not represent what Talos’ financial position or results of operations would have been had the Mergers occurred on the dates noted above, nor do they project the financial position or results of operations of the combined company following the Mergers. The pro forma financial statements are intended to provide information about the continuing impact of the Mergers and related financing as if the transaction had been consummated earlier. The pro forma adjustments are based on available information and certain assumptions that management believes are factually supportable and are expected to have a continuing impact on Talos’ results of operations. In the opinion of management, all adjustments necessary to present fairly the pro forma financial statements have been made.
Talos used currently available information to determine preliminary fair value estimates for the consideration and its allocation to the EnVen assets acquired and liabilities assumed. The estimates of fair value of EnVen’s assets and liabilities are based on reviews of EnVen’s internally generated financial statements, preliminary valuation studies, and other due diligence procedures. The assumptions and estimates used to determine the preliminary purchase price allocation and fair value adjustments are described in the notes accompanying the pro forma financial statements.
The preliminary purchase price allocation is subject to change due to changes in the estimated fair value of EnVen’s identifiable assets acquired and liabilities assumed as of the Closing Date of the First Merger, which could result from Talos’s additional valuation analysis, reserves estimates, discount rates and other factors.
2
As a result of the foregoing, the pro forma adjustments are preliminary and subject to change as additional information becomes available and additional analysis is performed. The preliminary pro forma adjustments have been made solely for the purpose of providing the pro forma financial statements presented below. Any increases or decreases in the fair value of assets acquired and liabilities assumed upon completion of the final valuation will result in adjustments to the pro forma balance sheet and if applicable, the pro forma statement of operations. The final purchase price allocation may be materially different than that reflected in the preliminary purchase price allocation presented herein.
The pro forma financial statements have been developed from and should be read in conjunction with the separate historical consolidated financial statements and related notes thereto in Talos’s SEC filings and EnVen’s historical consolidated financial statements and related notes thereto included in this current report on Form 8-K.
3
UNAUDITED PRO FORMA CONDENSED COMBINED BALANCE SHEET
As of September 30, 2022
(In thousands, except share amounts)
| Historical | Transaction Accounting Adjustments |
|||||||||||||||||||
| Talos | EnVen | Reclass Adjustment (a) |
Pro Forma Adjustments |
Pro Forma Combined Talos |
||||||||||||||||
| ASSETS | ||||||||||||||||||||
| Current assets: |
||||||||||||||||||||
| Cash and cash equivalents |
$ | 64,490 | $ | 192,124 | $ | — | $ | 142,821 | (b) | $ | 198,951 | |||||||||
| (207,311 | )(d) | |||||||||||||||||||
| 6,827 | (l) | |||||||||||||||||||
| Accounts receivable: |
||||||||||||||||||||
| Trade, net |
150,099 | 60,856 | (6 | ) | — | 210,949 | ||||||||||||||
| Joint interest, net |
42,259 | — | 16,563 | — | 58,822 | |||||||||||||||
| Other, net |
9,450 | — | — | — | 9,450 | |||||||||||||||
| Joint interest and other |
— | 16,575 | (16,575 | ) | — | — | ||||||||||||||
| Assets from price risk management activities |
27,389 | — | 19,663 | — | 47,052 | |||||||||||||||
| Prepaid assets |
76,397 | — | 12,591 | — | 88,988 | |||||||||||||||
| Other current assets |
1,894 | — | 5,075 | — | 6,969 | |||||||||||||||
| Prepaid expenses and other current assets |
— | 12,688 | (12,688 | ) | — | — | ||||||||||||||
| Prepaid income tax |
— | 5,058 | (5,058 | ) | — | — | ||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
| Total current assets |
371,978 | 287,301 | 19,565 | (57,663 | ) | 621,181 | ||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
| Property and equipment: |
||||||||||||||||||||
| Proved properties |
5,522,951 | — | 1,845,227 | (550,769 | )(i) | 6,725,309 | ||||||||||||||
| (92,100 | )(i) | |||||||||||||||||||
| Unproved properties, not subject to amortization |
213,802 | — | 96,794 | 153,449 | (i) | 464,045 | ||||||||||||||
| Oil and natural gas properties |
— | 1,942,021 | (1,942,021 | ) | — | — | ||||||||||||||
| Other property and equipment |
30,601 | 8,545 | — | (6,744 | )(i) | 32,402 | ||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
| Total property and equipment |
5,767,354 | 1,950,566 | — | (496,164 | ) | 7,221,756 | ||||||||||||||
| Accumulated depreciation, depletion and amortization |
(3,387,124 | ) | (1,189,030 | ) | — | 1,189,030 | (i) | (3,387,124 | ) | |||||||||||
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
| Total property and equipment, net |
2,380,230 | 761,536 | — | 692,866 | 3,834,632 | |||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
| Other long-term assets: |
||||||||||||||||||||
| Restricted cash |
— | 100,460 | — | — | 100,460 | |||||||||||||||
| Notes receivable, net |
— | 65,137 | — | (50,043 | )(i) | 15,094 | ||||||||||||||
| Assets from price risk management activities |
19,540 | 1,666 | 12,883 | — | 34,089 | |||||||||||||||
| Equity method investments |
2,121 | — | — | — | 2,121 | |||||||||||||||
| Other well equipment inventory |
27,043 | 14,716 | 97 | — | 41,856 | |||||||||||||||
| Operating lease assets |
5,518 | 21,798 | — | — | 27,316 | |||||||||||||||
| Other assets |
6,936 | 3,800 | (1,823 | ) | — | 8,913 | ||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
| Total assets |
$ | 2,813,366 | $ | 1,256,414 | $ | 30,722 | $ | 585,160 | $ | 4,685,662 | ||||||||||
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
The accompanying notes are an integral part of the unaudited pro forma condensed combined financial statements.
4
UNAUDITED PRO FORMA CONDENSED COMBINED BALANCE SHEET
As of September 30, 2022
(In thousands, except share amounts)
| Historical | Transaction Accounting Adjustments |
|||||||||||||||||||
| Talos | EnVen | Reclass Adjustment (a) |
Pro Forma Adjustments |
Pro Forma Combined Talos |
||||||||||||||||
| LIABILITIES AND STOCKHOLDERS’ EQUITY | ||||||||||||||||||||
| Current liabilities: |
||||||||||||||||||||
| Accounts payable |
$ | 109,964 | $ | 27,123 | $ | 5,830 | $ | — | $ | 142,917 | ||||||||||
| Accrued liabilities |
189,743 | 75,836 | (12,845 | ) | 31,000 | (c) | 310,254 | |||||||||||||
| 14,505 | (k) | |||||||||||||||||||
| 12,015 | (l) | |||||||||||||||||||
| Accrued royalties |
45,476 | 23,555 | — | — | 69,031 | |||||||||||||||
| Current portion of long-term debt |
— | 27,112 | — | 2,888 | (h) | 30,000 | ||||||||||||||
| Current portion of asset retirement obligations |
65,613 | 16,590 | — | (9,511 | )(i) | 72,692 | ||||||||||||||
| Liabilities from price risk management activities |
99,180 | 14,223 | 19,663 | — | 133,066 | |||||||||||||||
| Accrued interest payable |
17,537 | — | 13,157 | — | 30,694 | |||||||||||||||
| Current portion of operating lease liabilities |
1,885 | 5,710 | — | — | 7,595 | |||||||||||||||
| Other current liabilities |
26,930 | 6,143 | (6,143 | ) | — | 26,930 | ||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
| Total current liabilities |
556,328 | 196,292 | 19,662 | 50,897 | 823,179 | |||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
| Long-term liabilities: |
||||||||||||||||||||
| Long-term debt, net of discount and deferred financing costs |
652,108 | 235,636 | (1,823 | ) | 142,821 | (b) | 1,041,316 | |||||||||||||
| 8,687 | (h) | |||||||||||||||||||
| 7,000 | (i) | |||||||||||||||||||
| (3,113 | )(c) | |||||||||||||||||||
| Asset retirement obligations |
387,651 | 334,368 | — | (82,589 | )(i) | 639,430 | ||||||||||||||
| Liabilities from price risk management activities |
7,126 | — | 12,883 | — | 20,009 | |||||||||||||||
| Operating lease liabilities |
14,895 | 13,689 | — | — | 28,584 | |||||||||||||||
| Other long-term liabilities |
39,915 | 17,859 | — | — | 57,774 | |||||||||||||||
| Deferred tax liability |
— | 1,512 | — | 133,895 | (m) | 135,407 | ||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
| Total liabilities |
1,658,023 | 799,356 | 30,722 | 257,598 | 2,745,699 | |||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
| Commitments and contingencies |
||||||||||||||||||||
| Stockholders’ equity: |
||||||||||||||||||||
| Preferred stock, $0.01 par value; 30,000,000 shares authorized and no shares issued or outstanding as of September 30, 2022 |
— | — | — | — | — | |||||||||||||||
| Common stock $0.01 par value; 270,000,000 shares authorized; 82,570,328 shares (126,370,328 pro forma shares) issued and outstanding as of September 30, 2022 |
826 | — | — | 438 | (e) | 1,264 | ||||||||||||||
| Series A convertible perpetual preferred stock |
— | 15 | — | (15 | )(f) | — | ||||||||||||||
| Class A common stock |
— | 21 | — | (21 | )(f) | — | ||||||||||||||
| Additional paid-in capital |
1,692,316 | 399,493 | — | 831,762 | (e) | 2,547,488 | ||||||||||||||
| 35,425 | (l) | |||||||||||||||||||
| (12,015 | )(l) | |||||||||||||||||||
| (399,493 | )(f) | |||||||||||||||||||
| Retained earnings (accumulated deficit) |
(537,799 | ) | 57,529 | — | (27,887 | )(c) | (608,789 | ) | ||||||||||||
| (57,529 | )(f) | |||||||||||||||||||
| (28,598 | )(l) | |||||||||||||||||||
| (14,505 | )(k) | |||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
| Total stockholders’ equity |
1,155,343 | 457,058 | — | 327,562 | 1,939,963 | |||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
| Total liabilities and stockholders’ equity |
$ | 2,813,366 | $ | 1,256,414 | $ | 30,722 | $ | 585,160 | $ | 4,685,662 | ||||||||||
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
The accompanying notes are an integral part of the unaudited pro forma condensed combined financial statements.
5
UNAUDITED PRO FORMA CONDENSED COMBINED STATEMENT OF OPERATIONS
For the Nine Months Ended September 30, 2022
(In thousands, except per share amounts)
| Historical | Transaction Accounting Adjustments |
|||||||||||||||||||
| Talos | EnVen | Reclass Adjustment (a) |
Pro Forma Adjustments |
Pro Forma Combined Talos |
||||||||||||||||
| Revenues: |
||||||||||||||||||||
| Oil |
$ | 1,078,800 | $ | — | $ | 527,236 | $ | — | $ | 1,606,036 | ||||||||||
| Natural gas |
181,747 | — | 40,130 | — | 221,877 | |||||||||||||||
| NGL |
49,232 | — | 11,557 | — | 60,789 | |||||||||||||||
| Oil, natural gas, and NGL revenue |
— | 578,923 | (578,923 | ) | — | — | ||||||||||||||
| Production handling and other income |
— | 20,860 | — | — | 20,860 | |||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
| Total revenues |
1,309,779 | 599,783 | — | — | 1,909,562 | |||||||||||||||
| Operating expenses: |
||||||||||||||||||||
| Lease operating expense |
229,156 | 60,915 | 16,635 | — | 311,919 | |||||||||||||||
| 7,366 | ||||||||||||||||||||
| (2,153 | ) | |||||||||||||||||||
| Workover, repair, and maintenance |
— | 16,635 | (16,635 | ) | — | — | ||||||||||||||
| Transportation, gathering, and processing costs |
— | 7,366 | (7,366 | ) | — | — | ||||||||||||||
| Production taxes |
2,670 | — | — | — | 2,670 | |||||||||||||||
| Depreciation, depletion and amortization |
295,174 | 114,662 | — | 40,745 | (j) | 450,581 | ||||||||||||||
| Accretion expense |
42,400 | 21,092 | — | (3,362 | )(i) | 60,130 | ||||||||||||||
| General and administrative expense |
70,742 | 52,678 | 2,153 | — | 125,573 | |||||||||||||||
| Other operating expense |
12,142 | — | — | — | 12,142 | |||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
| Total operating expenses |
652,284 | 273,348 | — | 37,383 | 963,015 | |||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
| Operating income (expense) |
657,495 | 326,435 | — | (37,383 | ) | 946,547 | ||||||||||||||
| Interest expense |
(91,531 | ) | (35,191 | ) | — | 996 | (i) | (131,383 | ) | |||||||||||
| (5,259 | )(b) | |||||||||||||||||||
| (398 | )(c) | |||||||||||||||||||
| Price risk management activities expense |
(231,133 | ) | (89,121 | ) | — | — | (320,254 | ) | ||||||||||||
| Equity method investment income |
14,599 | — | — | — | 14,599 | |||||||||||||||
| Other income (expense) |
31,991 | 4,487 | — | 1,277 | (i) | 37,755 | ||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
| Net income (loss) before income taxes |
381,421 | 206,610 | — | (40,767 | ) | 547,264 | ||||||||||||||
| Income tax benefit (expense) |
(2,256 | ) | (27,814 | ) | — | 8,561 | (g) | (21,509 | ) | |||||||||||
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
| Net income (loss) |
$ | 379,165 | $ | 178,796 | $ | — | $ | (32,206 | ) | $ | 525,755 | |||||||||
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
| Net income (loss) per common share: |
||||||||||||||||||||
| Basic |
$ | 4.60 | $ | 4.17 | ||||||||||||||||
| Diluted |
$ | 4.54 | $ | 4.13 | ||||||||||||||||
| Weighted average common shares outstanding: |
||||||||||||||||||||
| Basic |
82,406 | 43,800 | (e) | 126,206 | ||||||||||||||||
| Diluted |
83,438 | 43,800 | (e) | 127,238 | ||||||||||||||||
The accompanying notes are an integral part of the unaudited pro forma condensed combined financial statements.
6
UNAUDITED PRO FORMA CONDENSED COMBINED STATEMENT OF OPERATIONS
For the Year Ended December 31, 2021
(In thousands, except per share amounts)
| Historical | Transaction Accounting Adjustments |
|||||||||||||||||||
| Talos | EnVen | Reclass Adjustment (a) |
Pro Forma Adjustments |
Pro Forma Combined Talos |
||||||||||||||||
| Revenues: |
||||||||||||||||||||
| Oil |
$ | 1,064,161 | $ | — | $ | 468,035 | $ | — | $ | 1,532,196 | ||||||||||
| Natural gas |
130,616 | — | 33,217 | — | 163,833 | |||||||||||||||
| NGL |
49,763 | — | 7,649 | — | 57,412 | |||||||||||||||
| Oil, natural gas, and NGL revenue |
— | 508,901 | (508,901 | ) | — | — | ||||||||||||||
| Production handling and other income |
— | 21,390 | — | — | 21,390 | |||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
| Total revenues |
1,244,540 | 530,291 | — | — | 1,774,831 | |||||||||||||||
| Operating expenses: |
||||||||||||||||||||
| Lease operating expense |
283,601 | 79,789 | 23,027 | — | 391,005 | |||||||||||||||
| 7,261 | ||||||||||||||||||||
| (2,673 | ) | |||||||||||||||||||
| Workover, repair, and maintenance |
— | 23,027 | (23,027 | ) | — | — | ||||||||||||||
| Transportation, gathering, and processing costs |
— | 7,261 | (7,261 | ) | — | — | ||||||||||||||
| Production taxes |
3,363 | — | — | — | 3,363 | |||||||||||||||
| Depreciation, depletion and amortization |
395,994 | 156,745 | — | 33,849 | (j) | 586,588 | ||||||||||||||
| Write-down of oil and natural gas properties |
18,123 | — | — | — | 18,123 | |||||||||||||||
| Accretion expense |
58,129 | 27,541 | — | (3,901 | )(i) | 81,769 | ||||||||||||||
| General and administrative expense |
78,677 | 75,601 | 2,673 | 27,887 | (c) | 227,941 | ||||||||||||||
| 14,505 | (k) | |||||||||||||||||||
| 28,598 | (l) | |||||||||||||||||||
| Other operating expense |
32,037 | — | — | — | 32,037 | |||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
| Total operating expenses |
869,924 | 369,964 | — | 100,938 | 1,340,826 | |||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
| Operating income (expense) |
374,616 | 160,327 | — | (100,938 | ) | 434,005 | ||||||||||||||
| Interest expense |
(133,138 | ) | (47,165 | ) | — | 1,323 | (i) | (184,480 | ) | |||||||||||
| (5,026 | )(b) | |||||||||||||||||||
| (474 | )(c) | |||||||||||||||||||
| Price risk management activities expense |
(419,077 | ) | (171,917 | ) | — | — | (590,994 | ) | ||||||||||||
| Other income (expense) |
(6,988 | ) | 2,790 | 5,170 | 1,500 | (i) | 2,472 | |||||||||||||
| (Loss) gain on extinguishment of long-term debt |
— | (11,419 | ) | 11,419 | — | — | ||||||||||||||
| Gain (loss) on fair value of 11% Senior Notes due 2023 |
— | 16,589 | (16,589 | ) | — | — | ||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
| Net income (loss) before income taxes |
(184,587 | ) | (50,795 | ) | — | (103,615 | ) | (338,997 | ) | |||||||||||
| Income tax benefit (expense) |
1,635 | (11,307 | ) | — | 21,759 | (g) | 12,087 | |||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
| Net income (loss) |
$ | (182,952 | ) | $ | (62,102 | ) | $ | — | $ | (81,856 | ) | $ | (326,910 | ) | ||||||
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
| Net income (loss) per common share: |
||||||||||||||||||||
| Basic |
$ | (2.24 | ) | $ | (2.60 | ) | ||||||||||||||
| Diluted |
$ | (2.24 | ) | $ | (2.60 | ) | ||||||||||||||
| Weighted average common shares outstanding: |
||||||||||||||||||||
| Basic |
81,769 | 43,800 | (e) | 125,569 | ||||||||||||||||
| Diluted |
81,769 | 43,800 | (e) | 125,569 | ||||||||||||||||
The accompanying notes are an integral part of the unaudited pro forma condensed combined financial statements.
7
NOTES TO UNAUDITED PRO FORMA CONDENSED COMBINED FINANCIAL STATEMENTS
Note 1—Basis of Presentation
The Talos historical financial information have been derived from its Quarterly Report on Form 10-Q for the quarter ended September 30, 2022 and Annual Report on Form 10-K for the year ended December 31, 2021. The EnVen historical financial information have been derived from its unaudited quarterly financial statements ended September 30, 2022 and audited annual financial statements for the year ended December 31, 2021. Certain of EnVen’s historical amounts have been reclassified to conform to Talos’ financial statement presentation. The pro forma financial statements should be read in conjunction with Talos’s and EnVen’s historical consolidated financial statements and the notes thereto. EnVen’s historical consolidated financial statements and the notes thereto are included in this current report on Form 8-K. The pro forma balance sheet gives effect to the Mergers and related financing consisting of borrowings under Talos Production’s revolving credit facility as if they had been completed on September 30, 2022. The pro forma statement of operations give effect to the Mergers and related financing as if they had been completed on January 1, 2021.
The pro forma adjustments for the Mergers and the related financing are described in the accompanying notes to the pro forma financial statements. In the opinion of Talos’s management, all material adjustments have been made that are necessary to present fairly, in accordance with Article 11 of Regulation S-X of the SEC, the pro forma financial statements. The pro forma financial statements do not purport to be indicative of the financial position or results of operations of the combined company that would have occurred if the Mergers and related financing had occurred on the dates indicated, nor are they indicative of Talos’s future financial position or results of operations.
Note 2—Preliminary Acquisition Accounting
Talos has determined it is the accounting acquirer to the Mergers which will be accounted for under the acquisition method of accounting for business combinations in accordance with Accounting Standards Codification 805, Business Combinations (“ASC 805”). The allocation of the preliminary estimated purchase price with respect to the Mergers is based upon management’s estimates of and assumptions related to the fair values of assets to be acquired and liabilities to be assumed as of September 30, 2022, using currently available information. Due to the fact that the unaudited pro forma combined financial statements have been prepared based on these preliminary estimates, the final purchase price allocation and the resulting effect on Talos’ financial position and results of operations may differ significantly from the pro forma amounts included herein.
The final purchase price allocation for the business combination will be performed subsequent to closing and adjustments to estimated amounts or recognition of additional assets acquired or liabilities assumed may occur as more detailed analyses are completed and additional information is obtained about the facts and circumstances that existed as of the Closing Date of the Mergers. Talos expects to finalize the purchase price allocation as soon as practicable after completing the Mergers.
The preliminary purchase price allocation is subject to change due to changes in the estimated fair value of EnVen’s identifiable assets acquired and liabilities assumed as of the Closing Date of the First Merger, which could result from Talos’s additional valuation analysis, reserves estimates, discount rates and other factors.
8
Preliminary Estimated Purchase Price
The following table summarizes the preliminary estimate of the purchase price (in thousands, except per share data):
| Shares of Talos Common Stock |
43,800 | |||
| Talos Common Stock price |
$ | 19.00 | ||
|
|
|
|||
| Stock consideration |
$ | 832,200 | ||
| Cash consideration |
$ | 207,311 | ||
|
|
|
|||
| Total purchase price |
$ | 1,039,511 | ||
|
|
|
The stock consideration was determined using the closing price of Talos Common Stock on February 13, 2023, the closing date of the First Merger. The cash consideration reflects the actual cash transferred on February 13, 2023. The cash consideration was computed as follows: (i) $212.5 million less (ii) $12.0 million tax withholdings associated with the settlement of EnVen RSUs and EnVen PSUs plus (iii) $6.8 million representing the aggregate exercise price of all EnVen Options received in cash prior to the Effective Time in connection with the exercise of EnVen Options outstanding and exercised as of immediately prior to the Effective Time.
Preliminary Estimated Purchase Price Allocation
The following table summarizes the allocation of the preliminary estimate of the purchase price to the assets acquired and liabilities assumed (in thousands):
| Assets Acquired |
||||
| Current assets: |
||||
| Cash and cash equivalents |
$ | 192,124 | ||
| Accounts receivable |
77,413 | |||
| Prepaid expenses and other current assets |
37,329 | |||
| Property and equipment: |
||||
| Proved properties |
1,202,358 | |||
| Unproved properties, not subject to amortization |
250,243 | |||
| Other property and equipment |
1,801 | |||
| Other long-term assets: |
||||
| Restricted cash |
100,460 | |||
| Notes receivable |
15,094 | |||
| Other well equipment inventory |
14,813 | |||
| Operating lease assets |
21,798 | |||
| Other assets |
16,526 | |||
|
|
|
|||
| Total assets to be acquired |
$ | 1,929,959 | ||
|
|
|
|||
| Liabilities assumed |
||||
| Current liabilities: |
||||
| Accounts payable |
32,953 | |||
| Accrued liabilities |
62,991 | |||
| Accrued royalties |
23,555 | |||
| Current portion of long-term debt |
30,000 | |||
| Current portion of asset retirement obligations |
7,079 | |||
| Liabilities from price risk management activities |
33,886 | |||
| Accrued interest payable |
13,157 | |||
| Current portion of operating lease liabilities |
5,710 | |||
| Long-term liabilities: |
||||
| Long-term debt |
249,500 | |||
| Asset retirement obligations |
251,779 | |||
| Liabilities from price risk management activities |
12,883 | |||
| Operating lease liabilities |
13,689 | |||
| Other long-term liabilities |
17,859 | |||
| Deferred tax liability |
135,407 | |||
|
|
|
|||
| Total liabilities to be assumed |
890,448 | |||
|
|
|
|||
| Net assets to be acquired |
$ | 1,039,511 | ||
|
|
|
9
Note 3—Transaction Accounting Adjustments
The following adjustments and assumptions were made in the preparation of the unaudited pro forma financial statements:
| (a) | Reflects reclassifications to the EnVen historical financial statements to conform to Talos’ financial statement presentation. |
| (b) | Reflects an increase of $142.8 million in long-term debt attributable to additional borrowings under the Talos Production revolving bank credit facility to fund a portion of the cash consideration. The increase in interest expense assumes the borrowing occurred on January 1, 2021 and was outstanding for the year ended December 31, 2021 and the nine months ended September 30, 2022. For the nine months ended September 30, 2022 and year ended December 31, 2021, pro forma interest expense was based on a weighted-average interest rate of 4.91% and 3.52%, respectively. The table below represents the effects of a one-eighth percentage point change in the interest rate on the pro forma interest associated with the additional borrowings (dollars in thousands): |
| Nine Months Ended September 30, 2022 |
Year Ended December 31, 2021 |
|||||||
| Weighted-average interest rate |
4.91 | % | 3.52 | % | ||||
| Interest expense |
$ | 5,259 | $ | 5,026 | ||||
| Weighted-average interest rate—increase 0.125% |
5.04 | % | 3.64 | % | ||||
| Interest expense |
$ | 5,393 | $ | 5,204 | ||||
| Weighted-average interest rate—decrease 0.125% |
4.79 | % | 3.39 | % | ||||
| Interest expense |
$ | 5,125 | $ | 4,847 | ||||
| (c) | Reflects the accrual of transaction costs of $31.0 million related to the Mergers including, among others, fees paid for financial advisors, legal services, and professional accounting services. The costs are not reflected in the historical September 30, 2022 consolidated balance sheets of Talos and EnVen, but are reflected in the Talos combined pro forma balance sheet as of September 30, 2022, as an increase to Accrued liabilities, a $27.9 million increase to Accumulated deficit and a $3.1 million reduction to Long-term debt, net of discount and deferred financing costs. The Talos combined pro forma statement of operations for the year ended December 31, 2021, reflects a $27.9 million expense to General and administrative expense as they will be expensed by Talos and EnVen as incurred. These amounts and their corresponding tax effect have not been reflected in the pro forma statement of operations for the nine months ended September 30, 2022, due to their nonrecurring nature. These costs are not expected to be incurred in any period beyond 12 months from the Closing Date of the Mergers. |
The Notes Consent Solicitation fee of $3.1 million is being reflected as an additional discount to the Talos Second Lien Notes and the corresponding accretion of the discount as an increase to interest expense of $0.4 million and $0.5 million for the both the year ended December 31, 2022 and December 31, 2021, respectively.
| (d) | Reflects the cash consideration paid to EnVen stockholders to effect the Mergers. |
| (e) | Reflects the increase in shares of Talos common stock and additional paid-in capital in excess of par resulting from the issuance of shares of Talos common stock to EnVen stockholders to effect the Mergers based on the Talos closing share price of $19.00 on February 13, 2023, the closing date of the First Merger. |
| (f) | Reflects the elimination of EnVen’s historical equity balances in accordance with the acquisition method of accounting. |
| (g) | Reflect the income tax effects of the transaction accounting adjustments presented using the statutory tax rate in effect during the period. Because the tax rates used for these unaudited pro forma condensed combined statement of operations are an estimate, the blended rate will vary from the actual effective rate in periods subsequent to completion of the Merger. |
| (h) | Reflects the write-off of the EnVen’s historical unamortized and deferred financing costs. |
| (i) | Reflects the adjustments to reflect the preliminary estimated fair value of Talos Common Stock of $832.2 million and cash consideration of $207.3 million allocated to the estimated fair values of the assets acquired and liabilities assumed as follows: |
| a. | $692.9 million increase to Total Property and Equipment, net calculated as the difference between the estimated fair value and EnVen’s historical book value. The change is primarily a result of (i) a decrease in Proved properties as a result of EnVen’s partial depletion of proved oil and natural gas reserves which is presented in Accumulated depreciation, depletion and amortization offset by the increase in estimated fair value of the remaining proved reserves over historical cost and a decrease in Proved properties as a result a downward revision to the asset retirement obligation (described below), (ii) an increase in Unproved properties, not subject to amortization due to higher fair values of properties compared to historical value and (iii) the elimination of the historical EnVen Accumulated depreciation, depletion and amortization. The fair value of oil and natural gas properties were measured using a discounted cash flow technique of valuation. Inputs to the valuation of oil and natural gas properties include estimates of: (i) reserves, (ii) future operating and development costs, (iii) future commodity prices, (iv) future plugging and |
10
| abandonment costs, (v) estimated cash flows and (vi) a market-based weighted average cost of capital rate. These estimates require significant judgement and may vary due to many factors, such as, but not limited to, the inputs to the fair value measure described above. |
| b. | $7.0 million increase to long-term debt, net of discount and deferred financing costs, and the corresponding amortization of the premium as a reduction to interest expense of $1.0 million and $1.3 million for the nine months ended September 30, 2022 and the year ended December 31, 2021, respectively. |
| c. | $50.0 million decrease to total Notes Receivable, net and the corresponding accretion of discount as an increase to other income (expense) of $1.3 million and $1.5 million for the nine months ended September 30, 2022 and the year ended December 31, 2021, respectively. |
| d. | $92.1 million downward revision to total asset retirement obligations primarily due to the estimated timing with an offset to Proved properties. Also, reflects changes in accretion expense that would have been recorded with respect to the allocated fair values attributable to asset retirment obligations assumed with a decrease to accretion expense of $3.4 million and $3.9 million for the nine months ended September 30, 2022 and year ended December 31, 2021, respectively. |
| (j) | Reflects changes in depletion that would have been recorded with respect to the allocated fair values attributable to proved oil and natural gas properties acquired as a result of the application of the full cost method of accounting for oil and natural gas activities following the Mergers. The pro forma depletion rates for the nine months ended September 30, 2022 and year ended December 31, 2021 were estimated using the proved property amounts based on the preliminary purchase price allocation and estimates of reserves at September 30, 2022 and December 31, 2021, adjusted for actual production. The pro forma depletion rates were applied to production volumes for the Talos properties and EnVen properties for the respective periods. |
| (k) | Reflects the accrual of contractual severance and other separation benefits associated with existing EnVen employment agreements in connection with the termination of certain executive officers of EnVen that occurred immediately after the consummation of the First Merger. The post-combination expense is reflected in the Talos combined pro forma balance sheet as of September 30, 2022, as an increase to Accrued liabilities and to Accumulated deficit, and in the Talos combined pro forma statement of operations for the year ended December 31, 2021, within General and administrative expense. |
| (l) | Reflects the cash exercise of EnVen Options outstanding as of September 30, 2022 and the accelerated vesting of both EnVen PSUs and EnVen RSUs outstanding as of September 30, 2022 that would occur immediately prior to the First Merger due to preexisting contractual change-in-control provisions. The stock-based compensation of $28.6 million associated with the accelerated vesting of restricted stock awards is reflected in the Talos combined pro forma balance sheet as of September 30, 2022, as an increase to Accumulated deficit, and in the Talos combined pro forma statement of operations for the year ended December 31, 2021, within General and administrative expense. Actual tax withholding obligations of $12.0 million associated with the acceleration of stock-based compensation awards as a result of the closing of the First Merger on February 13, 2023 are reflected in the Talos combined pro forma balance sheet as of September 30, 2022, as an increase to Accrued liabilities and a reduction to Additional paid-in capital. There were 682,650 EnVen Options that were exercised and 1,061,474 EnVen restricted stock awards that vested and accelerated as a result of the closing of the First Merger on February 13, 2023. Certain of the EnVen restricted stock awards outstanding as of September 30, 2022 vested in the ordinary course prior to the closing of the First Merger based on the achievement of the applicable performance targets or the passage of time. |
| (m) | Reflects purchase accounting adjustment to the Historical EnVen Deferred tax liability of $1.5 million to record the estimated deferred income tax effects of $135.4 million to reflect the Mergers. Because the tax rates used for these unaudited pro forma condensed balance sheet are an estimate, the blended rate will vary from the actual effective rate in periods subsequent to completion of the Merger. |
11
Note 4—Supplemental Pro Forma Oil and Gas Reserves Information
The following tables present the estimated pro forma combined net proved developed and undeveloped oil and gas reserves information as of December 31, 2021, along with a summary of changes in quantities of net remaining proved reserves during the year ended December 31, 2021.
The following estimated pro forma oil and gas reserves information is not necessarily indicative of the results that might have occurred had the Mergers been completed on January 1, 2021, and is not intended to be a projection of future results.
| Crude Oil Reserves (MBbls) | ||||||||||||
| Historical Talos |
Historical EnVen |
Pro Forma Combined Talos |
||||||||||
| Total proved reserves at December 31, 2020 |
109,307 | 36,332 | 145,639 | |||||||||
| Revision of previous estimates |
13,619 | 10,935 | 24,554 | |||||||||
| Production |
(16,159 | ) | (7,177 | ) | (23,336 | ) | ||||||
| Purchases of reserves |
— | 1,591 | 1,591 | |||||||||
| Extensions and discoveries |
997 | 915 | 1,912 | |||||||||
|
|
|
|
|
|
|
|||||||
| Total proved reserves at December 31, 2021 |
107,764 | 42,596 | 150,360 | |||||||||
| Total proved developed reserves as of: |
||||||||||||
| December 31, 2020 |
85,007 | 29,876 | 114,883 | |||||||||
| December 31, 2021 |
93,420 | 36,281 | 129,701 | |||||||||
| Total proved undeveloped reserves as of: |
||||||||||||
| December 31, 2020 |
24,300 | 6,456 | 30,756 | |||||||||
| December 31, 2021 |
14,344 | 6,315 | 20,659 | |||||||||
| Natural Gas Reserves (MMcf) | ||||||||||||
| Historical Talos |
Historical EnVen |
Pro Forma Combined Talos |
||||||||||
| Total proved reserves at December 31, 2020 |
257,208 | 34,426 | 291,634 | |||||||||
| Revision of previous estimates |
8,979 | 12,618 | 21,597 | |||||||||
| Production |
(32,795 | ) | (7,005 | ) | (39,800 | ) | ||||||
| Purchases of reserves |
— | 387 | 387 | |||||||||
| Extensions and discoveries |
2,961 | 577 | 3,538 | |||||||||
|
|
|
|
|
|
|
|||||||
| Total proved reserves at December 31, 2021 |
236,353 | 41,003 | 277,356 | |||||||||
| Total proved developed reserves as of: |
||||||||||||
| December 31, 2020 |
204,054 | 29,977 | 234,031 | |||||||||
| December 31, 2021 |
186,442 | 36,930 | 223,372 | |||||||||
| Total proved undeveloped reserves as of: |
||||||||||||
| December 31, 2020 |
53,154 | 4,449 | 57,603 | |||||||||
| December 31, 2021 |
49,911 | 4,073 | 53,984 | |||||||||
| NGL Reserves (MBbls) | ||||||||||||
| Historical Talos |
Historical EnVen |
Pro Forma Combined Talos |
||||||||||
| Total proved reserves at December 31, 2020 |
10,858 | 1,010 | 11,868 | |||||||||
| Revision of previous estimates |
5,137 | 110 | 5,247 | |||||||||
| Production |
(1,875 | ) | (209 | ) | (2,084 | ) | ||||||
| Purchases of reserves |
— | 29 | 29 | |||||||||
| Extensions and discoveries |
315 | 40 | 355 | |||||||||
|
|
|
|
|
|
|
|||||||
| Total proved reserves at December 31, 2021 |
14,435 | 980 | 15,415 | |||||||||
| Total proved developed reserves as of: |
||||||||||||
| December 31, 2020 |
8,104 | 779 | 8,883 | |||||||||
| December 31, 2021 |
11,792 | 854 | 12,646 | |||||||||
| Total proved undeveloped reserves as of: |
||||||||||||
| December 31, 2020 |
2,754 | 231 | 2,985 | |||||||||
| December 31, 2021 |
2,643 | 126 | 2,769 | |||||||||
12
| Total Reservers (Mboe) | ||||||||||||
| Historical Talos |
Historical EnVen |
Pro Forma Combined Talos |
||||||||||
| Total proved reserves at December 31, 2020 |
163,033 | 43,080 | 206,113 | |||||||||
| Revision of previous estimates |
20,252 | 13,148 | 33,400 | |||||||||
| Production |
(23,500 | ) | (8,554 | ) | (32,054 | ) | ||||||
| Purchases of reserves |
— | 1,685 | 1,685 | |||||||||
| Extensions and discoveries |
1,806 | 1,051 | 2,857 | |||||||||
|
|
|
|
|
|
|
|||||||
| Total proved reserves at December 31, 2021 |
161,591 | 50,410 | 212,001 | |||||||||
| Total proved developed reserves as of: |
||||||||||||
| December 31, 2020 |
127,120 | 35,651 | 162,771 | |||||||||
| December 31, 2021 |
136,286 | 43,290 | 179,576 | |||||||||
| Total proved undeveloped reserves as of: |
||||||||||||
| December 31, 2020 |
35,913 | 7,429 | 43,342 | |||||||||
| December 31, 2021 |
25,305 | 7,120 | 32,425 | |||||||||
Pro Forma Standardized Measure of Discounted Future Net Cash Flows
The following table presents the estimated pro forma discounted future net cash flows at December 31, 2021. The pro forma standardized measure information set forth below gives effect to the Mergers as if the Mergers had been completed on January 1, 2021. The disclosures below were determined by referencing the “Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil, Natural Gas and NGL Reserves” reported in Talos’ Annual Report on Form 10-K for the year ended December 31, 2021 and the “Standardized Measure of Discounted Future Net Cash Flows” reported in EnVen’s Annual Report for the year ended December 31, 2021. An explanation of the underlying methodology applied, as required by SEC regulations, can be found within the Talos Annual Report on Form 10-K and EnVen Annual Report. The calculations assume the continuation of existing economic, operating and contractual conditions at December 31, 2021.
Therefore, the following estimated pro forma standardized measure is not necessarily indicative of the results that might have occurred had the merger been completed on January 1, 2021 and is not intended to be a projection of future results.
| Historical | Historical | Pro Forma Combined |
||||||||||
| Talos | EnVen | Talos | ||||||||||
| (In thousands) | ||||||||||||
| At December 31, 2021 |
||||||||||||
| Future cash inflows |
$ | 8,496,005 | $ | 2,982,723 | $ | 11,478,728 | ||||||
| Future costs: |
||||||||||||
| Production |
(1,868,818 | ) | (731,167 | ) | (2,599,985 | ) | ||||||
| Development and abandonment |
(1,422,507 | ) | (440,282 | ) | (1,862,789 | ) | ||||||
|
|
|
|
|
|
|
|||||||
| Future net cash flows before income taxes |
5,204,680 | 1,811,274 | 7,015,954 | |||||||||
| Future income tax expense |
(676,778 | ) | (336,047 | ) | (1,012,825 | ) | ||||||
|
|
|
|
|
|
|
|||||||
| Future net cash flows after income taxes |
4,527,902 | 1,475,227 | 6,003,129 | |||||||||
| Discount at 10% annual rate |
(1,087,291 | ) | (334,792 | ) | (1,422,083 | ) | ||||||
|
|
|
|
|
|
|
|||||||
| Standardized measure of discounted future net cash flows |
$ | 3,440,611 | $ | 1,140,435 | $ | 4,581,046 | ||||||
|
|
|
|
|
|
|
|||||||
13
Pro Forma Change in Standardized Measure of Discounted Future Net Cash Flows
The change in the pro forma standardized measure of discounted future net cash flows relating to proved reserves for the year ended December 31, 2021 are as follows:
| Historical | Historical | Pro Forma Combined |
||||||||||
| Talos | EnVen | Talos | ||||||||||
| (In thousands) | ||||||||||||
| Standardized measure at January 1, 2021 |
$ | 1,904,934 | $ | 420,896 | $ | 2,325,830 | ||||||
| Sales and transfers of oil, net gas and NGLs produced during the period |
(957,576 | ) | (398,819 | ) | (1,356,395 | ) | ||||||
| Net change in prices and production costs |
2,049,980 | 784,528 | 2,834,508 | |||||||||
| Changes in estimated future development costs |
(57,876 | ) | 15,807 | (42,069 | ) | |||||||
| Previously estimated development costs incurred |
69,125 | 31,540 | 100,665 | |||||||||
| Accretion of discount |
199,849 | 50,071 | 249,920 | |||||||||
| Net change in income taxes |
(391,834 | ) | (176,522 | ) | (568,356 | ) | ||||||
| Purchases of reserves |
— | 3,972 | 3,972 | |||||||||
| Extensions and discoveries |
45,485 | 50,261 | 95,746 | |||||||||
| Net change due to revision in quantity estimates |
426,357 | 404,430 | 830,787 | |||||||||
| Changes in production rates (timing) and other |
152,167 | (45,729 | ) | 106,438 | ||||||||
|
|
|
|
|
|
|
|||||||
| Standardized measure at December 31, 2021 |
$ | 3,440,611 | $ | 1,140,435 | $ | 4,581,046 | ||||||
|
|
|
|
|
|
|
|||||||
14
Exhibit 99.4
December 16, 2022
Mr. Kendall J. Meyers
EnVen Energy Ventures, LLC
Suite 3200
609 Main Street
Houston, Texas 77002
Dear Mr. Meyers:
In accordance with your request, we have estimated the proved reserves and future revenue, as of December 31, 2021, to the EnVen Energy Ventures, LLC (EnVen) interest in certain oil and gas properties located in federal waters in the Gulf of Mexico. We completed our evaluation on or about February 2, 2022. It is our understanding that the proved reserves estimated in this report constitute all of the proved reserves owned by EnVen. The estimates in this report have been prepared in accordance with the definitions and regulations of the U.S. Securities and Exchange Commission (SEC) and, with the exception of the exclusion of future income taxes, conform to the FASB Accounting Standards Codification Topic 932, Extractive Activities—Oil and Gas. Definitions are presented immediately following this letter. This report has been prepared for use in filing with the SEC; in our opinion the assumptions, data, methods, and procedures used in the preparation of this report are appropriate for such purpose.
We estimate the net reserves and future net revenue to the EnVen interest in these properties for oil and gas extraction activities, as of December 31, 2021, to be:
| Net Reserves | Future Net Revenue (M$) | |||||||||||||||||||
| Oil | NGL | Gas | Present Worth | |||||||||||||||||
| Category |
(MBBL) | (MBBL) | (MMCF) | Total | at 10% | |||||||||||||||
| Proved Developed Producing |
27,353.3 | 732.9 | 20,836.5 | 1,014,965.0 | 897,407.6 | |||||||||||||||
| Proved Developed Non-Producing |
8,928.0 | 121.3 | 16,094.0 | 532,408.4 | 327,480.4 | |||||||||||||||
| Proved Undeveloped |
6,314.5 | 126.2 | 4,072.9 | 263,900.2 | 171,887.2 | |||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
| Total Proved |
42,595.8 | 980.4 | 41,003.4 | 1,811,273.6 | 1,396,775.2 | |||||||||||||||
The oil volumes shown include crude oil and condensate. Oil and natural gas liquids (NGL) volumes are expressed in thousands of barrels (MBBL); a barrel is equivalent to 42 United States gallons. Gas volumes are expressed in millions of cubic feet (MMCF) at standard temperature and pressure bases.
Reserves categorization conveys the relative degree of certainty; reserves subcategorization is based on development and production status. As requested, probable and possible reserves that exist for these properties have not been included. The estimates of reserves and future revenue included herein have not been adjusted for risk. This report does not include any value that could be attributed to interests in undeveloped acreage beyond those tracts for which undeveloped reserves have been estimated.
Gross revenue is EnVen’s share of the gross (100 percent) revenue from the properties prior to any deductions. Future net revenue is after deductions for EnVen’s share of capital costs, abandonment costs, and operating expenses but before consideration of any income taxes. The future net revenue has been discounted at an annual rate of 10 percent to determine its present worth, which is shown to indicate the effect of time on the value of money. Future net revenue presented in this report, whether discounted or undiscounted, should not be construed as being the fair market value of the properties.
Prices used in this report are based on the 12-month unweighted arithmetic average of the first-day-of-the-month price for each month in the period January through December 2021. For oil and NGL volumes, the average West Texas Intermediate spot price of $66.55 per barrel is adjusted by field for quality, transportation fees, and market differentials. For gas volumes, the average Henry Hub spot price of $3.598 per MMBTU is adjusted by field for energy content, transportation fees, and market differentials. All prices are held constant throughout the lives of the properties. The average adjusted product prices weighted by production over the remaining lives of the properties are $64.58 per barrel of oil, $29.90 per barrel of NGL, and $4.945 per MCF of gas.
Operating costs used in this report are based on operating expense records of EnVen. For the nonoperated properties, these costs include the per-well overhead expenses allowed under joint operating agreements along with estimates of costs to be incurred at and below the district and field levels. As requested, operating costs for the operated properties are limited to direct lease- and field-level costs and EnVen’s estimate of the portion of its headquarters general and administrative overhead expenses necessary to operate the properties. Operating costs have been divided into field-level costs, per-well costs, and per-unit-of-production costs and are not escalated for inflation.
Capital costs used in this report were provided by EnVen and are based on authorizations for expenditure and actual costs from recent activity. Capital costs are included as required for workovers, new development wells, and production equipment. Based on our understanding of future development plans, a review of the records provided to us, and our knowledge of similar properties, we regard these estimated capital costs to be reasonable. Abandonment costs used in this report are EnVen’s estimates of the costs to abandon the wells, platforms, and production facilities, net of any salvage value. Abandonment costs for Mississippi Canyon 194 Field are offset by two notes receivable from Shell Offshore Inc. (Shell) and Eni Petroleum US LLC (Eni) that total approximately $66 million. The payment obligations for Shell and Eni are provided within the Purchase and Sale Agreements, with EnVen as purchaser. These payments are projected to be in excess of the realized abandonment costs for Mississippi Canyon 194 Field and are included in the analysis. Capital costs and abandonment costs are not escalated for inflation.
For the purposes of this report, we did not perform any field inspection of the properties, nor did we examine the mechanical operation or condition of the wells and facilities. We have not investigated possible environmental liability related to the properties; therefore, our estimates do not include any costs due to such possible liability.
We have made no investigation of potential volume and value imbalances resulting from overdelivery or underdelivery to the EnVen interest. Therefore, our estimates of reserves and future revenue do not include adjustments for the settlement of any such imbalances; our projections are based on EnVen receiving its net revenue interest share of estimated future gross production. Additionally, we have made no specific investigation of any firm transportation contracts that may be in place for these properties; our estimates of future revenue include the effects of such contracts only to the extent that the associated fees are accounted for in the historical field- and lease-level accounting statements. EnVen receives additional revenue, not included in the amounts shown above, by processing production from oil and gas fields that it does not operate.
The reserves shown in this report are estimates only and should not be construed as exact quantities. Proved reserves are those quantities of oil and gas which, by analysis of engineering and geoscience data, can be estimated with reasonable certainty to be economically producible; probable and possible reserves are those additional reserves which are sequentially less certain to be recovered than proved reserves. Estimates of reserves may increase or decrease as a result of market conditions, future operations, changes in regulations, or actual reservoir performance. In addition to the primary economic assumptions discussed herein, our estimates are based on certain assumptions including, but not limited to, that the properties will be developed consistent with current development plans as provided to us by EnVen, that the properties will be operated in a prudent manner, that no governmental regulations or controls will be put in place that would impact the ability of the interest owner to recover the reserves, and that our projections of future production will prove consistent with actual performance. If the reserves are recovered, the revenues therefrom and the costs related thereto could be more or less than the estimated amounts. Because of governmental policies and uncertainties of supply and demand, the sales rates, prices received for the reserves, and costs incurred in recovering such reserves may vary from assumptions made while preparing this report.
For the purposes of this report, we used technical and economic data including, but not limited to, well logs, geologic maps, seismic data, well test data, production data, historical price and cost information, and property ownership interests. The reserves in this report have been estimated using deterministic methods; these estimates have been prepared in accordance with the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers (SPE Standards). We used standard engineering and geoscience methods, or a combination of methods, including performance analysis, volumetric analysis, analogy, and reservoir modeling, that we considered to be appropriate and necessary to categorize and estimate reserves in accordance with SEC definitions and regulations. As in all aspects of oil and gas evaluation, there are uncertainties inherent in the interpretation of engineering and geoscience data; therefore, our conclusions necessarily represent only informed professional judgment.
The data used in our estimates were obtained from EnVen, public data sources, and the nonconfidential files of Netherland, Sewell & Associates, Inc. (NSAI) and were accepted as accurate. Supporting work data are on file in our office. We have not examined the titles to the properties or independently confirmed the actual degree or type of interest owned. The technical persons primarily responsible for preparing the estimates presented herein meet the requirements regarding qualifications, independence, objectivity, and confidentiality set forth in the SPE Standards. Gregory S. Cohen, a Licensed Professional Engineer in the State of Texas, has been practicing consulting petroleum engineering at NSAI since 2013 and has over 14 years of prior industry experience. Ruurdjan (Rudi) de Zoeten, a Licensed Professional Geoscientist in the State of Texas, has been practicing consulting petroleum geoscience at NSAI since 2008 and has over 18 years of prior industry experience. We are independent petroleum engineers, geologists, geophysicists, and petrophysicists; we do not own an interest in these properties nor are we employed on a contingent basis.
| Sincerely, | ||
| NETHERLAND, SEWELL & ASSOCIATES, INC. | ||
| Texas Registered Engineering Firm F-2699 | ||
| By: | /s/ C.H. (Scott) Rees III | |
| C.H. (Scott) Rees III, P.E. | ||
| Executive Chairman | ||
| By: | /s/ Gregory S. Cohen | By: | /s/ Ruurdjan (Rudi) de Zoeten | |||||
| Gregory S. Cohen, P.E. 117412 | Ruurdjan (Rudi) de Zoeten, P.G. 3179 | |||||||
| Vice President | Vice President | |||||||
| Date Signed: December 16, 2022 |
Date Signed: December 16, 2022 | |||||||
GSC:LKT
DEFINITIONS OF OIL AND GAS RESERVES
Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)
The following definitions are set forth in U.S. Securities and Exchange Commission (SEC) Regulation S-X Section 210.4-10(a). Also included is supplemental information from (1) the 2018 Petroleum Resources Management System approved by the Society of Petroleum Engineers, (2) the FASB Accounting Standards Codification Topic 932, Extractive Activities—Oil and Gas, and (3) the SEC’s Compliance and Disclosure Interpretations.
(1) Acquisition of properties. Costs incurred to purchase, lease or otherwise acquire a property, including costs of lease bonuses and options to purchase or lease properties, the portion of costs applicable to minerals when land including mineral rights is purchased in fee, brokers’ fees, recording fees, legal costs, and other costs incurred in acquiring properties.
(2) Analogous reservoir. Analogous reservoirs, as used in resources assessments, have similar rock and fluid properties, reservoir conditions (depth, temperature, and pressure) and drive mechanisms, but are typically at a more advanced stage of development than the reservoir of interest and thus may provide concepts to assist in the interpretation of more limited data and estimation of recovery. When used to support proved reserves, an “analogous reservoir” refers to a reservoir that shares the following characteristics with the reservoir of interest:
| (i) | Same geological formation (but not necessarily in pressure communication with the reservoir of interest); |
| (ii) | Same environment of deposition; |
| (iii) | Similar geological structure; and |
| (iv) | Same drive mechanism. |
Instruction to paragraph (a)(2): Reservoir properties must, in the aggregate, be no more favorable in the analog than in the reservoir of interest.
(3) Bitumen. Bitumen, sometimes referred to as natural bitumen, is petroleum in a solid or semi-solid state in natural deposits with a viscosity greater than 10,000 centipoise measured at original temperature in the deposit and atmospheric pressure, on a gas free basis. In its natural state it usually contains sulfur, metals, and other non-hydrocarbons.
(4) Condensate. Condensate is a mixture of hydrocarbons that exists in the gaseous phase at original reservoir temperature and pressure, but that, when produced, is in the liquid phase at surface pressure and temperature.
(5) Deterministic estimate. The method of estimating reserves or resources is called deterministic when a single value for each parameter (from the geoscience, engineering, or economic data) in the reserves calculation is used in the reserves estimation procedure.
(6) Developed oil and gas reserves. Developed oil and gas reserves are reserves of any category that can be expected to be recovered:
| (i) | Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and |
| (ii) | Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well. |
|
Supplemental definitions from the 2018 Petroleum Resources Management System:
Developed Producing Reserves – Expected quantities to be recovered from completion intervals that are open and producing at the effective date of the estimate. Improved recovery Reserves are considered producing only after the improved recovery project is in operation.
Developed Non-Producing Reserves – Shut-in and behind-pipe Reserves. Shut-in Reserves are expected to be recovered from (1) completion intervals that are open at the time of the estimate but which have not yet started producing, (2) wells which were shut-in for market conditions or pipeline connections, or (3) wells not capable of production for mechanical reasons. Behind-pipe Reserves are expected to be recovered from zones in existing wells that will require additional completion work or future re-completion before start of production with minor cost to access these reserves. In all cases, production can be initiated or restored with relatively low expenditure compared to the cost of drilling a new well. |
(7) Development costs. Costs incurred to obtain access to proved reserves and to provide facilities for extracting, treating, gathering and storing the oil and gas. More specifically, development costs, including depreciation and applicable operating costs of support equipment and facilities and other costs of development activities, are costs incurred to:
| (i) | Gain access to and prepare well locations for drilling, including surveying well locations for the purpose of determining specific development drilling sites, clearing ground, draining, road building, and relocating public roads, gas lines, and power lines, to the extent necessary in developing the proved reserves. |
| (ii) | Drill and equip development wells, development-type stratigraphic test wells, and service wells, including the costs of platforms and of well equipment such as casing, tubing, pumping equipment, and the wellhead assembly. |
Definitions - Page 1 of 6
DEFINITIONS OF OIL AND GAS RESERVES
Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)
| (iii) | Acquire, construct, and install production facilities such as lease flow lines, separators, treaters, heaters, manifolds, measuring devices, and production storage tanks, natural gas cycling and processing plants, and central utility and waste disposal systems. |
| (iv) | Provide improved recovery systems. |
(8) Development project. A development project is the means by which petroleum resources are brought to the status of economically producible. As examples, the development of a single reservoir or field, an incremental development in a producing field, or the integrated development of a group of several fields and associated facilities with a common ownership may constitute a development project.
(9) Development well. A well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive.
(10) Economically producible. The term economically producible, as it relates to a resource, means a resource which generates revenue that exceeds, or is reasonably expected to exceed, the costs of the operation. The value of the products that generate revenue shall be determined at the terminal point of oil and gas producing activities as defined in paragraph (a)(16) of this section.
(11) Estimated ultimate recovery (EUR). Estimated ultimate recovery is the sum of reserves remaining as of a given date and cumulative production as of that date.
(12) Exploration costs. Costs incurred in identifying areas that may warrant examination and in examining specific areas that are considered to have prospects of containing oil and gas reserves, including costs of drilling exploratory wells and exploratory-type stratigraphic test wells. Exploration costs may be incurred both before acquiring the related property (sometimes referred to in part as prospecting costs) and after acquiring the property. Principal types of exploration costs, which include depreciation and applicable operating costs of support equipment and facilities and other costs of exploration activities, are:
| (i) | Costs of topographical, geographical and geophysical studies, rights of access to properties to conduct those studies, and salaries and other expenses of geologists, geophysical crews, and others conducting those studies. Collectively, these are sometimes referred to as geological and geophysical or “G&G” costs. |
| (ii) | Costs of carrying and retaining undeveloped properties, such as delay rentals, ad valorem taxes on properties, legal costs for title defense, and the maintenance of land and lease records. |
| (iii) | Dry hole contributions and bottom hole contributions. |
| (iv) | Costs of drilling and equipping exploratory wells. |
| (v) | Costs of drilling exploratory-type stratigraphic test wells. |
(13) Exploratory well. An exploratory well is a well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir. Generally, an exploratory well is any well that is not a development well, an extension well, a service well, or a stratigraphic test well as those items are defined in this section.
(14) Extension well. An extension well is a well drilled to extend the limits of a known reservoir.
(15) Field. An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition. There may be two or more reservoirs in a field which are separated vertically by intervening impervious strata, or laterally by local geologic barriers, or by both. Reservoirs that are associated by being in overlapping or adjacent fields may be treated as a single or common operational field. The geological terms “structural feature” and “stratigraphic condition” are intended to identify localized geological features as opposed to the broader terms of basins, trends, provinces, plays, areas-of-interest, etc.
(16) Oil and gas producing activities.
| (i) | Oil and gas producing activities include: |
| (A) | The search for crude oil, including condensate and natural gas liquids, or natural gas (“oil and gas”) in their natural states and original locations; |
| (B) | The acquisition of property rights or properties for the purpose of further exploration or for the purpose of removing the oil or gas from such properties; |
| (C) | The construction, drilling, and production activities necessary to retrieve oil and gas from their natural reservoirs, including the acquisition, construction, installation, and maintenance of field gathering and storage systems, such as: |
| (1) | Lifting the oil and gas to the surface; and |
| (2) | Gathering, treating, and field processing (as in the case of processing gas to extract liquid hydrocarbons); and |
Definitions - Page 2 of 6
DEFINITIONS OF OIL AND GAS RESERVES
Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)
| (D) | Extraction of saleable hydrocarbons, in the solid, liquid, or gaseous state, from oil sands, shale, coalbeds, or other nonrenewable natural resources which are intended to be upgraded into synthetic oil or gas, and activities undertaken with a view to such extraction. |
Instruction 1 to paragraph (a)(16)(i): The oil and gas production function shall be regarded as ending at a “terminal point”, which is the outlet valve on the lease or field storage tank. If unusual physical or operational circumstances exist, it may be appropriate to regard the terminal point for the production function as:
| a. | The first point at which oil, gas, or gas liquids, natural or synthetic, are delivered to a main pipeline, a common carrier, a refinery, or a marine terminal; and |
| b. | In the case of natural resources that are intended to be upgraded into synthetic oil or gas, if those natural resources are delivered to a purchaser prior to upgrading, the first point at which the natural resources are delivered to a main pipeline, a common carrier, a refinery, a marine terminal, or a facility which upgrades such natural resources into synthetic oil or gas. |
Instruction 2 to paragraph (a)(16)(i): For purposes of this paragraph (a)(16), the term saleable hydrocarbons means hydrocarbons that are saleable in the state in which the hydrocarbons are delivered.
| (ii) | Oil and gas producing activities do not include: |
| (A) | Transporting, refining, or marketing oil and gas; |
| (B) | Processing of produced oil, gas, or natural resources that can be upgraded into synthetic oil or gas by a registrant that does not have the legal right to produce or a revenue interest in such production; |
| (C) | Activities relating to the production of natural resources other than oil, gas, or natural resources from which synthetic oil and gas can be extracted; or |
| (D) | Production of geothermal steam. |
(17) Possible reserves. Possible reserves are those additional reserves that are less certain to be recovered than probable reserves.
| (i) | When deterministic methods are used, the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves. When probabilistic methods are used, there should be at least a 10% probability that the total quantities ultimately recovered will equal or exceed the proved plus probable plus possible reserves estimates. |
| (ii) | Possible reserves may be assigned to areas of a reservoir adjacent to probable reserves where data control and interpretations of available data are progressively less certain. Frequently, this will be in areas where geoscience and engineering data are unable to define clearly the area and vertical limits of commercial production from the reservoir by a defined project. |
| (iii) | Possible reserves also include incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than the recovery quantities assumed for probable reserves. |
| (iv) | The proved plus probable and proved plus probable plus possible reserves estimates must be based on reasonable alternative technical and commercial interpretations within the reservoir or subject project that are clearly documented, including comparisons to results in successful similar projects. |
| (v) | Possible reserves may be assigned where geoscience and engineering data identify directly adjacent portions of a reservoir within the same accumulation that may be separated from proved areas by faults with displacement less than formation thickness or other geological discontinuities and that have not been penetrated by a wellbore, and the registrant believes that such adjacent portions are in communication with the known (proved) reservoir. Possible reserves may be assigned to areas that are structurally higher or lower than the proved area if these areas are in communication with the proved reservoir. |
| (vi) | Pursuant to paragraph (a)(22)(iii) of this section, where direct observation has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves should be assigned in the structurally higher portions of the reservoir above the HKO only if the higher contact can be established with reasonable certainty through reliable technology. Portions of the reservoir that do not meet this reasonable certainty criterion may be assigned as probable and possible oil or gas based on reservoir fluid properties and pressure gradient interpretations. |
(18) Probable reserves. Probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.
| (i) | When deterministic methods are used, it is as likely as not that actual remaining quantities recovered will exceed the sum of estimated proved plus probable reserves. When probabilistic methods are used, there should be at least a 50% probability that the actual quantities recovered will equal or exceed the proved plus probable reserves estimates. |
Definitions - Page 3 of 6
DEFINITIONS OF OIL AND GAS RESERVES
Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)
| (ii) | Probable reserves may be assigned to areas of a reservoir adjacent to proved reserves where data control or interpretations of available data are less certain, even if the interpreted reservoir continuity of structure or productivity does not meet the reasonable certainty criterion. Probable reserves may be assigned to areas that are structurally higher than the proved area if these areas are in communication with the proved reservoir. |
| (iii) | Probable reserves estimates also include potential incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than assumed for proved reserves. |
| (iv) | See also guidelines in paragraphs (a)(17)(iv) and (a)(17)(vi) of this section. |
(19) Probabilistic estimate. The method of estimation of reserves or resources is called probabilistic when the full range of values that could reasonably occur for each unknown parameter (from the geoscience and engineering data) is used to generate a full range of possible outcomes and their associated probabilities of occurrence.
(20) Production costs.
| (i) | Costs incurred to operate and maintain wells and related equipment and facilities, including depreciation and applicable operating costs of support equipment and facilities and other costs of operating and maintaining those wells and related equipment and facilities. They become part of the cost of oil and gas produced. Examples of production costs (sometimes called lifting costs) are: |
| (A) | Costs of labor to operate the wells and related equipment and facilities. |
| (B) | Repairs and maintenance. |
| (C) | Materials, supplies, and fuel consumed and supplies utilized in operating the wells and related equipment and facilities. |
| (D) | Property taxes and insurance applicable to proved properties and wells and related equipment and facilities. |
| (E) | Severance taxes. |
| (ii) | Some support equipment or facilities may serve two or more oil and gas producing activities and may also serve transportation, refining, and marketing activities. To the extent that the support equipment and facilities are used in oil and gas producing activities, their depreciation and applicable operating costs become exploration, development or production costs, as appropriate. Depreciation, depletion, and amortization of capitalized acquisition, exploration, and development costs are not production costs but also become part of the cost of oil and gas produced along with production (lifting) costs identified above. |
(21) Proved area. The part of a property to which proved reserves have been specifically attributed.
(22) Proved oil and gas reserves. Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.
| (i) | The area of the reservoir considered as proved includes: |
| (A) | The area identified by drilling and limited by fluid contacts, if any, and |
| (B) | Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data. |
| (ii) | In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty. |
| (iii) | Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty. |
| (iv) | Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when: |
| (A) | Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and |
Definitions - Page 4 of 6
DEFINITIONS OF OIL AND GAS RESERVES
Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)
| (B) | The project has been approved for development by all necessary parties and entities, including governmental entities. |
| (v) | Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions. |
(23) Proved properties. Properties with proved reserves.
(24) Reasonable certainty. If deterministic methods are used, reasonable certainty means a high degree of confidence that the quantities will be recovered. If probabilistic methods are used, there should be at least a 90% probability that the quantities actually recovered will equal or exceed the estimate. A high degree of confidence exists if the quantity is much more likely to be achieved than not, and, as changes due to increased availability of geoscience (geological, geophysical, and geochemical), engineering, and economic data are made to estimated ultimate recovery (EUR) with time, reasonably certain EUR is much more likely to increase or remain constant than to decrease.
(25) Reliable technology. Reliable technology is a grouping of one or more technologies (including computational methods) that has been field tested and has been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation.
(26) Reserves. Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project.
Note to paragraph (a)(26): Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir, or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).
Excerpted from the FASB Accounting Standards Codification Topic 932, Extractive Activities—Oil and Gas:
932-235-50-30 A standardized measure of discounted future net cash flows relating to an entity’s interests in both of the following shall be disclosed as of the end of the year:
| a. | Proved oil and gas reserves (see paragraphs 932-235-50-3 through 50-11B) |
| b. | Oil and gas subject to purchase under long-term supply, purchase, or similar agreements and contracts in which the entity participates in the operation of the properties on which the oil or gas is located or otherwise serves as the producer of those reserves (see paragraph 932-235-50-7). |
The standardized measure of discounted future net cash flows relating to those two types of interests in reserves may be combined for reporting purposes.
932-235-50-31 All of the following information shall be disclosed in the aggregate and for each geographic area for which reserve quantities are disclosed in accordance with paragraphs 932-235-50-3 through 50-11B:
| a. | Future cash inflows. These shall be computed by applying prices used in estimating the entity’s proved oil and gas reserves to the year-end quantities of those reserves. Future price changes shall be considered only to the extent provided by contractual arrangements in existence at year-end. |
| b. | Future development and production costs. These costs shall be computed by estimating the expenditures to be incurred in developing and producing the proved oil and gas reserves at the end of the year, based on year-end costs and assuming continuation of existing economic conditions. If estimated development expenditures are significant, they shall be presented separately from estimated production costs. |
| c. | Future income tax expenses. These expenses shall be computed by applying the appropriate year-end statutory tax rates, with consideration of future tax rates already legislated, to the future pretax net cash flows relating to the entity’s proved oil and gas reserves, less the tax basis of the properties involved. The future income tax expenses shall give effect to tax deductions and tax credits and allowances relating to the entity’s proved oil and gas reserves. |
| d. | Future net cash flows. These amounts are the result of subtracting future development and production costs and future income tax expenses from future cash inflows. |
Definitions - Page 5 of 6
DEFINITIONS OF OIL AND GAS RESERVES
Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)
| e. | Discount. This amount shall be derived from using a discount rate of 10 percent a year to reflect the timing of the future net cash flows relating to proved oil and gas reserves. |
| f. | Standardized measure of discounted future net cash flows. This amount is the future net cash flows less the computed discount. |
(27) Reservoir. A porous and permeable underground formation containing a natural accumulation of producible oil and/or gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.
(28) Resources. Resources are quantities of oil and gas estimated to exist in naturally occurring accumulations. A portion of the resources may be estimated to be recoverable, and another portion may be considered to be unrecoverable. Resources include both discovered and undiscovered accumulations.
(29) Service well. A well drilled or completed for the purpose of supporting production in an existing field. Specific purposes of service wells include gas injection, water injection, steam injection, air injection, salt-water disposal, water supply for injection, observation, or injection for in-situ combustion.
(30) Stratigraphic test well. A stratigraphic test well is a drilling effort, geologically directed, to obtain information pertaining to a specific geologic condition. Such wells customarily are drilled without the intent of being completed for hydrocarbon production. The classification also includes tests identified as core tests and all types of expendable holes related to hydrocarbon exploration. Stratigraphic tests are classified as “exploratory type” if not drilled in a known area or “development type” if drilled in a known area.
(31) Undeveloped oil and gas reserves. Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.
| (i) | Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances. |
| (ii) | Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time. |
From the SEC’s Compliance and Disclosure Interpretations (October 26, 2009):
Although several types of projects — such as constructing offshore platforms and development in urban areas, remote locations or environmentally sensitive locations — by their nature customarily take a longer time to develop and therefore often do justify longer time periods, this determination must always take into consideration all of the facts and circumstances. No particular type of project per se justifies a longer time period, and any extension beyond five years should be the exception, and not the rule.
Factors that a company should consider in determining whether or not circumstances justify recognizing reserves even though development may extend past five years include, but are not limited to, the following:
| • | The company’s level of ongoing significant development activities in the area to be developed (for example, drilling only the minimum number of wells necessary to maintain the lease generally would not constitute significant development activities); |
| • | The company’s historical record at completing development of comparable long-term projects; |
| • | The amount of time in which the company has maintained the leases, or booked the reserves, without significant development activities; |
| • | The extent to which the company has followed a previously adopted development plan (for example, if a company has changed its development plan several times without taking significant steps to implement any of those plans, recognizing proved undeveloped reserves typically would not be appropriate); and |
| • | The extent to which delays in development are caused by external factors related to the physical operating environment (for example, restrictions on development on Federal lands, but not obtaining government permits), rather than by internal factors (for example, shifting resources to develop properties with higher priority). |
| (iii) | Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, as defined in paragraph (a)(2) of this section, or by other evidence using reliable technology establishing reasonable certainty. |
(32) Unproved properties. Properties with no proved reserves.
Definitions - Page 6 of 6