false 0001724965 0001724965 2024-01-17 2024-01-17

 

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

 

FORM 8-K

 

 

CURRENT REPORT

PURSUANT TO SECTION 13 OR 15(D)

OF THE SECURITIES EXCHANGE ACT OF 1934

Date of report (Date of earliest event reported): January 17, 2024

 

 

TALOS ENERGY INC.

(Exact Name of Registrant as Specified in Charter)

 

 

 

Delaware   001-38497   82-3532642

(State or other jurisdiction

of incorporation)

  

(Commission

File Number)

  

(I.R.S. Employer

Identification Number)

333 Clay Street, Suite 3300

Houston, Texas 77002

(Address of Principal Executive Offices) (Zip Code)

(713) 328-3000

(Registrant’s Telephone Number, Including Area Code)

 

 

Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions:

 

☐

Written communication 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 communication pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))

 

☐

Pre-commencement communication 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:

 

Title of each class

  

Trading
Symbol(s)

  

Name of each exchange
on which registered

Common Stock   TALO   NYSE

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.

On the date of this Current Report on Form 8-K, Talos Energy Inc. (the “Company”) commenced an underwritten offering of $300.0 million of shares of its common stock, par value $0.01 per share (the “Common Stock”) made pursuant to the Company’s shelf Registration Statement on Form S-3, including a base prospectus, which was filed with the U.S. Securities and Exchange Commission (the “SEC”) and became effective on June 14, 2022 (such offering, the “Offering”). The Company will file a preliminary prospectus supplement in connection with the Offering, which will contain certain additional disclosures to potential investors, certain relevant excerpts of which are set forth herein.

 

Item 2.02.

Results of Operations and Financial Condition.

Preliminary Operating and Financial Results

As of the date hereof, the Company has not finalized its financial and operational results for the three months or year ended December 31, 2023. However, based on preliminary information, the Company estimates that, for the three months and year ended December 31, 2023, its production ranged from approximately 67 to 68 MBoe/d, and from approximately 66 to 67 MBoe/d, respectively. Similarly, the Company estimates that its revenues for the three months and year ended December 31, 2023 ranged from approximately $380 million to $395 million, and from approximately $1,450 million to $1,465 million, respectively, with direct operating expenses (consisting of lease operating expenses and production taxes) for such periods ranging from approximately $105 million to $120 million, and from approximately $390 million to $410 million, respectively.

Additionally, as of December 31, 2023, the Company estimates that it had $33.6 million of cash and cash equivalents and $1,025.7 million of total indebtedness, approximately $200.0 million of indebtedness and $10.8 million in letters of credit outstanding under our Bank Credit Facility, resulting in remaining availability thereunder of approximately $754.2 million and total liquidity of $787.9 million.

Although the Company’s independent petroleum engineers have yet to prepare, audit or review the Company’s proved reserve estimates as of December 31, 2023, the Company currently expects based on management estimates that, when compared to its 140.6 MMBoe of proved reserves as of December 31, 2022, its proved reserve estimates as of December 31, 2023 will include, among others, the following adjustments: (i) acquisitions of 55.9 MMBoe (including 34.4 MMBoe of proved developed producing (“PDP”) reserves), primarily attributable to the EnVen Acquisition, (ii) additions of between 6.2 MMBoe and 9.3 MMBoe (including 0.2 MMBoe of PDP reserves), primarily attributable to identification of two proved undeveloped locations and the successful drilling of the Sunspear exploration well during 2023, and (iii) downward revisions of between 26.6 MMBoe and 28.6 MMBoe (including between 10.0 MMBoe and 10.7 MMBoe of PDP reserves), approximately 15.2 MMBoe to 16.3 MMBoe of which would be attributable to decreases in commodity pricing based on SEC parameters.

These preliminary estimates are derived from the Company’s internal records and are based on the most current information available to management. These estimates are preliminary and inherently uncertain. The Company’s normal reporting processes with respect to the foregoing preliminary estimates have not been fully completed. Neither the Company’s independent auditors nor its independent petroleum engineers have completed an audit or review of such preliminary estimates. During the course of the Company’s and their review on these preliminary estimates, the Company could identify items that would require it to make adjustments and which could affect its final results. Any such adjustments could be material. These preliminary estimates should not be viewed as indicative of the Company’s financial condition or results as of or for any future period. Actual results could differ from the estimates, trends and expectations discussed herein, and such differences could be material.

September 30 Reserve Update

The following table presents estimated proved oil, natural gas and NGLs reserves and the reserves associated with the Company and the reserves associated with EnVen Acquisition, as of December 31, 2022 adjusted to utilize SEC Pricing as of September 30, 2023. The Talos and EnVen reserve estimates have been calculated using the internal systems of the Company’s management and have not been prepared or audited by an independent, third-party reserve engineer, but otherwise contain the same parameters, except for price.

 

     Talos
Energy Inc.
(1)		      EnVen
Acquisition
(1)		  
     Estimated As of
September 30, 2023 (2)		  

Proved Developed Producing:

      

Oil (MBbls)

      62,056        18,839  

Natural gas (MMcf)

      99,593        14,662  

NGLs (MBbls)

      6,137        794  

Total (MBoe)

      84,792        22,077  

PV-10 (thousands) (3)

    $ 2,943,892      $ 672,570  

Proved Developed Non-Producing:

      

Oil (MBbls)

      16,774        14,949  

Natural gas (MMcf)

      55,219        10,505  

NGLs (MBbls)

      3,008        225  

Total (MBoe)

      28,985        16,925  

PV-10 (thousands) (3)

    $ 386,136      $ 521,160  

Proved Undeveloped:

      

Oil (MBbls)

      10,158        7,473  

Natural gas (MMcf)

      46,656        10,622  

NGLs (MBbls)

      2,693        78  

Total (MBoe)

      20,627        9,321  

PV-10 (thousands) (3)

    $ 336,640      $ 253,438  

Total Proved:

      

Oil (MBbls)

      88,988        41,261  

Natural gas (MMcf)

      201,468        35,789  

NGLs (MBbls)

      11,838        1,097  

Total (MBoe)

      134,404        48,323  

PV-10 (thousands) (3)

    $ 3,666,668      $ 1,447,168  

 

(1)

Reflects proved reserves as of December 31, 2022, as adjusted to utilize SEC pricing as of September 30, 2023.

(2)

Based on SEC Pricing. SEC Pricing adjusted by lease for market differentials for Talos as of September 30, 2023 was $80.40 per Bbl of oil, $3.80 per Mcf of natural gas and $20.42 per Bbl of NGLs. SEC Pricing adjusted by lease for market differentials for EnVen as of September 30, 2023 was $76.82 per Bbl of oil, $4.52 per Mcf of natural gas and $40.47 per Bbl of NGLs.

(3)

PV-10 is a non-GAAP financial measure and differs from the standardized measure of discounted future net cash flows, which is the most directly comparable GAAP financial measure. PV-10 is a computation of the standardized measure of discounted future net cash flows on a pre-tax basis. PV-10 is equal to the standardized measure of discounted future net cash flows at the applicable date, before deducting future income taxes, discounted at 10%. The Company believes that the presentation of PV-10 is relevant and useful to investors because it presents the discounted future net cash flows attributable to its estimated net proved reserves prior to

  taking into account future corporate income taxes, and it is a useful measure for evaluating the relative monetary significance of the Company’s oil and natural gas properties. Further, investors may utilize the measure as a basis for comparison of the relative size and value of the Company’s reserves to other companies without regard to the specific tax characteristics of such entities. The Company uses this measure when assessing the potential return on investment related to its oil and natural gas properties. PV-10, however, is not a substitute for the standardized measure of discounted future net cash flows. The Company’s PV-10 measure and the standardized measure of discounted future net cash flows do not purport to represent the fair value of the Company’s oil and natural gas reserves.

The information above is being furnished pursuant to Item 2.02 of Form 8-K and shall not be deemed “filed” for purposes of Section 18 of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), or otherwise subject to liabilities of that section, and is not incorporated by reference into any filing under the Securities Act of 1933, as amended (the “Securities Act”), or the Exchange Act unless specifically identified therein as being incorporated therein by reference.

 

Item 7.01.

Regulation FD Disclosure.

On January 17, 2024, the Company issued a press release announcing the commencement of the Offering. A copy of the press release is furnished as Exhibit 99.1 hereto and is incorporated into this Item 7.01 by reference.

The information furnished pursuant to this Item 7.01 (including the exhibit) shall not be deemed to be “filed” for purposes of Section 18 of the Exchange Act or otherwise subject to the liabilities of that section, and is not incorporated by reference into any filing under the Securities Act or the Exchange Act.

 

Item 8.01.

Other Events.

In connection with the Offering, the Company intends to provide certain additional disclosures to investors related to the Company’s previously announced acquisition of QuarterNorth Energy Inc. (“QuarterNorth,” and such acquisition, the “QuarterNorth Acquisition”). Specifically, as a result of the QuarterNorth Acquisition, the Company expects to acquire approximately 252,000 net leasehold acres, increasing its total net leasehold acreage position to approximately 1,015,000. QuarterNorth’s producing assets include approximately 365,000 gross acres and are approximately 95% operated. Additionally, the Company expects to realize annual run-rate synergies of approximately $50 million, consisting of both operational and general and administrative cost reductions as a result of the QuarterNorth Acquisition. Pro forma for the QuarterNorth Acquisition, the Company estimates that it would have generated average net daily production for the quarter ended December 31, 2023, ranging from approximately 97.0 MBoe/d to 99.0 MBoe/d.

This Item 8.01 incorporates by reference the information contained in Item 2.02 of this Current Report on Form 8-K. In addition, this Item 8.01 incorporates by reference, the following:

 

  •  

the Unaudited Pro Forma Condensed Combined Balance Sheet of the Company as of September 30, 2023 and the Unaudited Pro Forma Condensed Combined Statements of Operations of the Company for the Nine Months ended September 30, 2023 and the Year Ended December 31, 2022, and the notes related thereto, collectively filed as Exhibit 99.2 herewith;

 

  •  

the Audited Consolidated Balance Sheet of QuarterNorth as of December 31, 2022, and the Audited Consolidated Statements of Operations, Changes in Stockholders’ Equity and Cash Flows of QuarterNorth for the Year Ended December 31, 2022, and the notes related thereto, collectively filed as Exhibit 99.3 herewith;

 

  •  

the Audited Consolidated Balance Sheet of QuarterNorth as of December 31, 2021, and the Audited Consolidated Statements of Operations, Changes in Stockholders’ Equity and Cash Flows of QuarterNorth for the period from August 27, 2021 to December 31, 2021, and the notes related thereto, collectively filed as Exhibit 99.4 herewith;

 

  •  

the Audited Statement of Revenues and Direct Operating Expenses of the oil and natural gas properties acquired by QuarterNorth Energy Inc. and Mako Buyer 2 LLC on August 27, 2021 from Fieldwood Energy Inc. and its debtor affiliates for the period from January 1, 2021 through August 26, 2021, and the notes related thereto, collectively filed as Exhibit 99.5 herewith;

 

  •  

the Unaudited Condensed Consolidated Balance Sheets of QuarterNorth as of September 30, 2023 and December 31, 2022, and the Unaudited Condensed Consolidated Statements of Operations, Changes in Stockholders’ Equity and Cash Flows of QuarterNorth for the Nine Months Ended September 30, 2023 and 2022, and the notes related thereto, collectively filed as Exhibit 99.6 herewith;

 

  •  

the reserve report regarding estimated quantities of proved reserves of QuarterNorth as of December 31, 2022, using SEC guidelines, prepared by Netherland, Sewell and Associates, Inc., filed as Exhibit 99.7 herewith;

 

  •  

the reserve report regarding estimated quantities of proved reserves of QuarterNorth as of September 30, 2023, using SEC guidelines, prepared by Netherland, Sewell and Associates, Inc., filed as Exhibit 99.8 herewith;

Item 9.01.

Financial Statements and Exhibits.

(d)    Exhibits

 

Exhibit    Description
23.1    Consent of Ernst & Young LLP (QuarterNorth 2022).
23.2    Consent of Ernst & Young LLP (QuarterNorth 2021)
23.3    Consent of Ernst & Young LLP (QuarterNorth Assets).
23.4    Consent of Netherland, Sewell and Associates, Inc. (QuarterNorth Reserves).
99.1    Press Release, dated January 17, 2024.
99.2    Unaudited Pro Forma Combined Balance Sheet of Talos Energy Inc. as of September 30, 2023 and Unaudited Pro Forma Combined Statements of Operations of Talos Energy Inc. for the Nine Months ended September 30, 2023 and the Year Ended December 31, 2022, and the notes related thereto.
99.3    Audited Consolidated Balance Sheet of QuarterNorth Energy Inc. as of December 31, 2022, and Audited Consolidated Statements of Operations, Changes in Stockholders’ Equity and Cash Flows of QuarterNorth Energy Inc. for the Year Ended December 31, 2022, and the notes related thereto.
99.4    Audited Consolidated Balance Sheet of QuarterNorth Energy Inc. as of December 31, 2021, and the Audited Consolidated Statements of Operations, Changes in Stockholders’ Equity and Cash Flows of QuarterNorth Energy Inc. for the period from August 27, 2021 to December 31, 2021, and the notes related thereto.
99.5    Audited Statement of Revenues and Direct Operating Expenses of the oil and natural gas properties acquired by QuarterNorth Energy Inc. and Mako Buyer 2 LLC on August 27, 2021 from Fieldwood Energy Inc. and its debtor affiliates for the period from January 1, 2021 through August 26, 2021, and the notes related thereto.
99.6    Unaudited Condensed Consolidated Balance Sheets of QuarterNorth Energy Inc. as of September 30, 2023 and December 31, 2022, and the Unaudited Condensed Consolidated Statements of Operations, Changes in Stockholders’ Equity and Cash Flows of QuarterNorth Energy Inc. for the Nine Months Ended September 30, 2023 and 2022, and the notes related thereto.
99.7    Report of Netherland, Sewell and Associates, Inc. (QuarterNorth Reserves – December 31, 2022).
99.8    Report of Netherland, Sewell and Associates, Inc. (QuarterNorth Reserves – September 30, 2023).
104    Cover Page Interactive Data File (embedded within the Inline XBRL document).

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: January 17, 2024

 

TALOS ENERGY INC.
By:  

/s/ William S. Moss III

Name:   William S. Moss III
  Executive Vice President, General Counsel and Secretary

Exhibit 23.1

Consent of Independent Auditors

We consent to the incorporation by reference in the following Registration Statements:

 

  (1)

Registration Statements (Form S-3 Nos. 333-231925, 333-248754, 333-255489, 333-271232 and 333-265589) of Talos Energy Inc.

 

  (2)

Registration Statements (Form S-8 Nos. 333-225058 and 333-256554) of Talos Energy Inc.

of our report dated March 31, 2023, with respect to the consolidated financial statements of QuarterNorth Energy Inc. as of and for the year ended December 31, 2022 appearing in this Current Report on Form 8-K of Talos Energy Inc.

 

/s/ Ernst & Young LLP
Houston, Texas
January 17, 2024

Exhibit 23.2

Consent of Independent Auditors

We consent to the incorporation by reference in the following Registration Statements:

 

  (1)

Registration Statements (Form S-3 Nos. 333-231925, 333-248754, 333-255489, 333-271232 and 333-265589) of Talos Energy Inc.

 

  (2)

Registration Statements (Form S-8 Nos. 333-225058 and 333-256554) of Talos Energy Inc.

of our report dated March 31, 2022, with respect to the consolidated financial statements of QuarterNorth Energy Inc. as of December 31, 2021 and for the period from August 27, 2021 through December 31, 2021 appearing in this Current Report on Form 8-K of Talos Energy Inc.

 

/s/ Ernst & Young LLP
Houston, Texas
January 17, 2024

Exhibit 23.3

Consent of Independent Auditors

We consent to the incorporation by reference in the following Registration Statements:

 

  (1)

Registration Statements (Form S-3 Nos. 333-231925, 333-248754, 333-255489, 333-271232 and 333-265589) of Talos Energy Inc.

 

  (2)

Registration Statements (Form S-8 Nos. 333-225058 and 333-256554) of Talos Energy Inc.

of our report dated January 9, 2024, with respect to the statement of revenue and direct operating expenses of the oil and natural gas properties acquired by QuarterNorth Energy Inc. and Mako Buyer 2 LLC on August 27, 2021 from Fieldwood Energy Inc. and its debtor affiliates for the period from January 1, 2021 through August 26, 2021 appearing in this Current Report on Form 8-K of Talos Energy Inc.

 

/s/ Ernst & Young LLP
Houston, Texas
January 17, 2024

Exhibit 23.4

 

LOGO

CONSENT OF INDEPENDENT PETROLEUM ENGINEERS AND GEOLOGISTS

We hereby consent to the references to our firm, in the context in which they appear, and to the inclusion in this Current Report on Form 8-K of Talos Energy Inc. (the “Company”) of our reserves reports relating to QuarterNorth Energy Inc., dated January 15, 2024, included as exhibits to this Current Report on Form 8-K of the Company, and to the incorporation by reference of such reports in the Registration Statements (Nos. 333-231925, 333-248754, 333-255489, 333-271232 and 333-265589) on Form S-3 and the Registration Statements (Nos. 333-256554 and 333-225058) on Form S-8 of the Company. We also consent to the reference to us under the heading “Experts” in such Registration Statements.

 

NETHERLAND, SEWELL & ASSOCIATES, INC.
By:  

/s/ Richard B. Talley, Jr., P.E.

  Richard B. Talley, Jr., P.E.
  Chief Executive Officer

Houston, Texas

January 17, 2024

Exhibit 99.1

 

LOGO

Talos Energy Announces Commencement of Underwritten Public Offering of Common Stock

Houston, Texas, January 17, 2024 – Talos Energy Inc. (“Talos” or the “Company”) (NYSE: TALO) today announced that it has commenced an underwritten public offering of $300.0 million of shares of its common stock, par value $0.01 per share (“common stock”). The Company expects to grant the underwriters a 30-day option to purchase $45.0 million of additional shares of its common stock.

The Company intends to use the net proceeds from this offering to fund a portion of the previously announced acquisition of QuarterNorth Energy Inc. (the “QuarterNorth Acquisition”). In the event that the QuarterNorth Acquisition is not completed, the proceeds from this offering will be used for general corporate purposes.

J.P. Morgan Securities LLC, Goldman Sachs & Co. LLC and Mizuho are acting as joint book-running managers and representatives of the underwriters and Citigroup, Morgan Stanley, Capital One Securities, Inc., DNB Markets, Inc., KeyBanc Capital Markets Inc. and Regions Securities LLC are also acting as joint book-running managers.

The offering is being made pursuant to a shelf registration statement on Form S-3, including a base prospectus, which was filed with the U.S. Securities and Exchange Commission (the “SEC”) and became effective on June 14, 2022. The preliminary prospectus supplement, and accompanying base prospectus, relating to the offering, and a final prospectus supplement, when available, will be filed with the SEC and will be available on the SEC’s website at www.sec.gov. Copies of the preliminary prospectus supplement, and accompanying base prospectus, relating to the offering, and the final prospectus supplement, when available, may be obtained by sending a request to: J.P. Morgan, c/o Broadridge Financial Solutions, 1155 Long Island Avenue, Edgewood, NY 11717, by telephone at (866) 803-9204, prospectus-eq_fi@jpmchase.com; Goldman Sachs & Co. LLC, Prospectus Department, 200 West Street, New York, NY 10282, telephone: 1-866-471-2526, facsimile: 212-902-9316 or by emailing Prospectus-ny@ny.email.gs.com; Mizuho Securities USA LLC, ATTN: Equity Capital Markets, 1271 Avenue of the Americas, 3rd Floor, New York, NY 10020, telephone: (212) 205-7600, or by emailing US-ECM@mizuhogroup.com, or by accessing the SEC’s website at www.sec.gov.

This press release shall not constitute an offer to sell or the solicitation of an offer to buy the shares of common stock or any other securities, nor shall there be any sale of such shares of common stock or any other securities in any state or other jurisdiction in which such offer, solicitation or sale would be unlawful prior to registration or qualification under the securities laws of any such state or other jurisdiction.

ABOUT TALOS ENERGY

Talos Energy (NYSE: TALO) is a technically driven, innovative, independent energy company focused on safely and efficiently maximizing long-term value through its Upstream Exploration & Production and Low Carbon Solutions businesses. We currently operate in the United States and offshore Mexico. We leverage decades of technical and offshore operational expertise to acquire, explore, and produce assets in key geological trends while developing opportunities to reduce industrial emissions through carbon capture and storage projects along the U.S. Gulf Coast.

INVESTOR RELATIONS CONTACT

investor@talosenergy.com

FORWARD-LOOKING STATEMENTS

This communication may contain “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended (the “Securities Act”), and Section 21E of the Securities Exchange Act of 1934, as amended. All statements, other than statements of historical fact included in this communication, regarding our strategy, future operations, financial position, estimated revenues and losses, projected costs, prospects, plans and objectives of management are forward-looking statements. When used in this communication, the words “will,” “could,” “believe,” “anticipate,” “intend,” “estimate,” “expect,” “project,” “forecast,” “may,” “objective,” “plan” and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words. These forward-looking statements are based on our current expectations and assumptions about future events and are based on currently available information as to the outcome and timing of future events.

 

TALOS ENERGY INC.    333 Clay St., Suite 3300, Houston, TX 77002
4860-2881-7560v.7   

We caution you that these forward-looking statements are subject to numerous risks and uncertainties, most of which are difficult to predict and many of which are beyond our control. These risks include, but are not limited to, our ability to consummate the proposed transaction with QuarterNorth Energy, Inc. on the terms currently contemplated, the anticipated future performance of the combined company, risks and uncertainties related to economic, market or business conditions, satisfaction of customary closing conditions related to the proposed offering, and the other risks discussed in “Risk Factors” in the Registration Statement on Form S-3, our Annual Report on Form 10-K for the year ended December 31, 2022, our Quarterly Reports on Forms 10-Q filed with the U.S. Securities and Exchange Commission and our other filings with the SEC, all of which can be accessed at the SEC’s website at www.sec.gov.

Should one or more of the risks or uncertainties described herein occur, or should underlying assumptions prove incorrect, our actual results and plans could differ materially from those expressed in any forward-looking statements. All forward-looking statements, expressed or implied, included in this communication are expressly qualified in their entirety by this cautionary statement. This cautionary statement should also be considered in connection with any subsequent written or oral forward-looking statements that we or persons acting on our behalf may issue. Except as otherwise required by applicable law, we disclaim any duty to update any forward-looking statements, all of which are expressly qualified by the statements in this section, to reflect events or circumstances after the date of this communication.

 

TALOS ENERGY INC.    333 Clay St., Suite 3300, Houston, TX 77002
4860-2881-7560v.7   

Exhibit 99.2

Unless the context otherwise requires, references to:

 

  •  

“Talos,” “we,” “us,” “our,” or the “Company,” refer to Talos Energy Inc., a Delaware corporation, and its subsidiaries;

 

  •  

“Talos Production” refer to Talos Production Inc., a Delaware corporation;

 

  •  

“SEC” refer to the U.S. Securities and Exchange Commission;

 

  •  

“EnVen” refer to EnVen Energy Corporation, a Delaware corporation; and

 

  •  

“QuarterNorth” refer to QuarterNorth Energy Inc., a Delaware corporation.

 

1

TALOS ENERGY INC.

UNAUDITED PRO FORMA CONDENSED COMBINED FINANCIAL STATEMENTS

QuarterNorth Acquisition

On January 13, 2024, we entered into a definitive agreement to acquire QuarterNorth, a private operator in the Deepwater U.S. Gulf of Mexico, for consideration consisting of (i) $1,273.9 million in cash and (ii) 24.8 million shares of our common stock (the “QuarterNorth Acquisition,” and such agreement the “QuarterNorth Merger Agreement”). We expect to fund the cash portion of the purchase price for the QuarterNorth Acquisition via borrowings under the Talos Production bank credit facility (the “Bank Credit Facility”), the proceeds from an underwritten equity offering, available cash on hand and, opportunistically to the extent market conditions warrant, other capital markets offerings or other debt financings, as appropriate. The QuarterNorth Acquisition is expected to close in the first quarter of 2024, subject to customary closing conditions.

EnVen Acquisition

On February 13, 2023, we completed the acquisition (the “EnVen Acquisition”) of EnVen, a private operator in the Deepwater U.S. Gulf of Mexico, for consideration consisting of (i) $207.3 million in cash, (ii) 43.8 million shares of the Company’s common stock valued at $832.2 million and (iii) the effective settlement of an accounts receivable balance of $8.4 million.

Other Transaction Accounting Adjustments

The transaction accounting adjustments in the pro forma financial statements for the QuarterNorth Acquisition and EnVen Acquisition consists of those necessary to account for the transactions. Separately, we expect to generate gross proceeds of $300.0 million by issuing shares of our common stock in an underwritten equity offering to partially fund the cash consideration in the QuarterNorth Acquisition. The adjustments related to the issuance of common stock are shown in a separate column as “Equity Financing.”

Pro Forma Presentation

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, EnVen, and QuarterNorth adjusted to give effect to the EnVen Acquisition and QuarterNorth Acquisition and related financing consisting of borrowings under the Bank Credit Facility and planned proceeds from the underwritten equity offering. The unaudited pro forma condensed combined statement of operations for the nine months ended September 30, 2023, and the year ended December 31, 2022, combine the historical consolidated statement of operations of Talos, EnVen, and QuarterNorth, giving effect to the EnVen Acquisition and QuarterNorth Acquisition and related financing as if the transactions had been consummated on January 1, 2022. The unaudited pro forma condensed combined balance sheet combines the historical consolidated balance sheets of Talos and QuarterNorth as of September 30, 2023, giving effect to the QuarterNorth Acquisition and related financing as if the transactions had been consummated on September 30, 2023. The pro forma financial statements contain certain reclassification adjustments to conform the historical EnVen and QuarterNorth financial statement presentation to Talos’s financial statement presentation.

The pro forma financial statements are presented to reflect the EnVen Acquisition and QuarterNorth Acquisition and related financing and do not represent what Talos’s financial position or results of operations would have been had these acquisitions occurred on the dates noted above, nor do they project the financial position or results of operations of the combined company following these acquisitions. The pro forma financial statements are intended to provide information about the continuing impact of the acquisitions 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’s 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 QuarterNorth assets acquired and liabilities assumed. The estimates of fair value of QuarterNorth’s assets and liabilities are based on reviews of QuarterNorth’s internally generated financial statements 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.

 

2

The preliminary purchase price allocation is subject to change due to changes in the estimated fair value of QuarterNorth’s identifiable assets acquired and liabilities assumed as of the closing date, which could result from Talos’s additional valuation analysis, reserves estimates, discount rates and other factors.

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, EnVen’s historical consolidated financial statements and related notes thereto included in the April 12, 2023 current report on Form 8-K, and QuarterNorth’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, 2023

(In thousands, except share amounts)

 

    Historical     Transaction Accounting
Adjustments		                  
    Talos     QuarterNorth     Reclass
Adjustment
(a)		     Pro Forma
Adjustments		         Equity
Financing		     Pro Forma
Combined
Talos		  
                (see Note 4)     (see Note 4)         (see Note 5)        
ASSETS              

Current assets:

              

Cash and cash equivalents

   $ 13,631     $ 387,722     $ —       $ 584,708     (b)   $ 287,800     $ —    
        $ (1,273,861 )    (d)    

Accounts receivable:

              

Trade, net

     181,384       —         83,520       —           —         264,904  

Joint interest, net

     93,798       —         64,458       —           —         158,256  

Other, net

     10,744       —         31,511       —           —         42,255  

Accounts receivable, net

     —         179,489       (179,489 )      —           —         —    

Assets from price risk management activities

     11,497       —         12       —           —         11,509  

Prepaid assets

     86,077       —         13,606       —           —         99,683  

Other current assets

     14,457       40,492       (13,606 )      —           —         41,343  

Material and supplies

     —         49,166       (49,166 )      —           —         —    
 

 

 

    

 

 

    

 

 

    

 

 

      

 

 

    

 

 

  

Total current assets

     411,588       656,869       (49,154 )    $ (689,153 )        287,800       617,950  
 

 

 

    

 

 

    

 

 

    

 

 

      

 

 

    

 

 

  

Property and equipment:

              

Proved properties

     7,691,828       —         1,301,937       (30,513 )    (i)     —         8,963,252  

Unproved properties, not subject to amortization

     267,297       181,384       —         246,720     (i)     —         695,401  

Proved properties, net

     —         858,737       (858,737 )      —           —         —    

Other property and equipment

     33,795       2,667       4,074       —           —         40,536  
 

 

 

    

 

 

    

 

 

    

 

 

      

 

 

    

 

 

  

Total property and equipment

     7,992,920       1,042,788       447,274       216,207         —         9,699,189  

Accumulated depreciation, depletion and amortization

     (3,985,613 )      —         (447,274 )      447,274     (i)     —         (3,985,613 ) 
 

 

 

    

 

 

    

 

 

    

 

 

      

 

 

    

 

 

  

Total property and equipment, net

     4,007,307       1,042,788       —       $ 663,481         —         5,713,576  
 

 

 

    

 

 

    

 

 

    

 

 

      

 

 

    

 

 

  

Other long-term assets:

              

Restricted cash

     101,760       —         —         —           —         101,760  

Assets from price risk management activities

     4,550       —         65       —           —         4,615  

Equity method investments

     141,682       —         —         —           —         141,682  

Other well equipment inventory

     44,643       —         49,166       —           —         93,809  

Notes receivable, net

     15,805       —         —         —           —         15,805  

Operating lease assets

     12,313       —         5,836       —           —         18,149  

Other assets

     13,452       6,704       (5,836 )      —           —         14,320  
 

 

 

    

 

 

    

 

 

    

 

 

      

 

 

    

 

 

  

Total assets

   $ 4,753,100     $ 1,706,361     $ 77     $ (25,672 )      $ 287,800     $ 6,721,666  
 

 

 

    

 

 

    

 

 

    

 

 

      

 

 

    

 

 

  

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, 2023

(In thousands, except share amounts)

 

    Historical     Transaction Accounting
Adjustments		                  
    Talos     QuarterNorth     Reclass
Adjustment
(a)		     Pro Forma
Adjustments		         Equity
Financing		     Pro Forma
Combined
Talos		  
                (see Note 4)     (see Note 4)         (see Note 5)        
LIABILITIES AND STOCKHOLDERS’ EQUITY              

Current liabilities:

              

Accounts payable

   $ 125,557     $ 56,860     $ —       $ —         $ —       $ 182,417  

Accrued liabilities

     205,095       122,680       (14,320 )      14,649     (c)     —         331,753  
          3,649     (n)    

Accrued royalties

     54,092       —         14,182       —           —         68,274  

Current portion of long-term debt

     33,109       —         —         —           —         33,109  

Current portion of asset retirement obligations

     69,288       10,577       —         —           —         79,865  

Liabilities from price risk management activities

     55,042       43,711       12       —           —         98,765  

Accrued interest payable

     30,536       —         138       —           —         30,674  

Current portion of operating lease liabilities

     2,859       —         1,225       —           —         4,084  

Other current liabilities

     54,221       2,943       (1,225 )      —           —         55,939  
 

 

 

    

 

 

    

 

 

    

 

 

      

 

 

    

 

 

  

Total current liabilities

     629,799       236,771       12       18,298         —         884,880  
 

 

 

    

 

 

    

 

 

    

 

 

      

 

 

    

 

 

  

Long-term liabilities:

              

Long-term debt

     1,018,774       182,060       —         584,708     (b)     —         1,788,482  
          2,940     (h)    

Asset retirement obligations

     747,560       112,732       —         —           —         860,292  

Liabilities from price risk management activities

     8,981       9,576       65       —           —         18,622  

Operating lease liabilities

     18,888       —         4,848       —           —         23,736  

Other long-term liabilities

     267,036       4,848       (4,848 )      143,998     (k)     —         479,042  
        68,008          

Deferred income taxes

     —         68,008       (68,008 )          —         —    
 

 

 

    

 

 

    

 

 

    

 

 

      

 

 

    

 

 

  

Total liabilities

     2,691,038       613,995       77       749,944         —         4,055,054  
 

 

 

    

 

 

    

 

 

    

 

 

      

 

 

    

 

 

  

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, 2023

     —         —         —         —           —         —    

Common stock $0.01 par value; 270,000,000 shares authorized; 127,480,361 shares (174,486,135 pro forma shares) issued as of September 30, 2023

     1,275       —         —         248     (e)     222       1,745  

Common stock

     —         79       —         (79 )    (f)       —    

Additional paid-in capital

     2,541,906       978,531       —         (978,531 )    (f)     287,578       3,164,284  
          334,800     (e)    

Accumulated earnings (deficit)

     (433,615 )      113,756       —         (113,756 )    (f)     —         (451,913 ) 
          (14,649 )    (c)    
          (3,649 )    (n)    

Treasury stock, at cost; 3,400,000 shares as of September 30, 2023

     (47,504 )      —         —         —           —         (47,504 ) 
 

 

 

    

 

 

    

 

 

    

 

 

      

 

 

    

 

 

  

Total stockholders’ equity

     2,062,062       1,092,366       —         (775,616 )        287,800       2,666,612  
 

 

 

    

 

 

    

 

 

    

 

 

      

 

 

    

 

 

  

Total liabilities and stockholders’ equity

   $ 4,753,100     $ 1,706,361     $ 77       (25,672 )      $ 287,800     $ 6,721,666  
 

 

 

    

 

 

    

 

 

    

 

 

      

 

 

    

 

 

  

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, 2023

(In thousands, except per share amounts)

 

           Historical     Transaction Accounting
Adjustments		                    
     Talos pro
forma adjusted
for EnVen
Acquisition		     QuarterNorth     Reclass
Adjustment (a)		     Pro Forma
Adjustments		          Equity
Financing		      Pro Forma
Combined
Talos		  
     (see Note 2)           (see Note 4)     (see Note 4)          (see Note 5)         

Revenues:

                 

Oil

    $ 1,043,775     $ 448,064     $ —       $ —          $ —        $ 1,491,839  

Natural gas

    $ 55,704       24,600       —         —            —          80,304  

NGL

    $ 25,491       13,273       —         —            —          38,764  

Turnkey revenue

      —         87,157       —         (87,157 )    (l)      —          —    

Other revenue

      —         18,005       —         —            —          18,005  
  

 

 

    

 

 

    

 

 

    

 

 

       

 

 

     

 

 

  

Total revenues

      1,124,970       591,099       —         (87,157 )         —          1,628,912  

Operating expenses:

                 

Lease operating expense

      297,387       115,481       13,492       —            —          426,360  

Decommissioning costs of goods sold

      —         61,927       —         (61,927 )    (l)      —          —    

Production taxes

      1,813       —         —         —            —          1,813  

Depreciation, depletion and amortization

      501,455       155,261       —         (377 )    (j)      —          656,339  

Accretion expense

      66,244       8,488       —         —            —          74,732  

General and administrative expense

      162,041       27,314       1,377       —            —          190,732  

Insurance expense

      —         16,175       (16,175 )      —            —          —    

Other operating (income) expense

      (55,172 )      11,428       —         —            —          (43,744 ) 
  

 

 

    

 

 

    

 

 

    

 

 

       

 

 

     

 

 

  

Total operating expenses

      973,768       396,074       (1,306 )      (62,304 )         —          1,306,232  
  

 

 

    

 

 

    

 

 

    

 

 

       

 

 

     

 

 

  

Operating income (loss)

      151,202       195,025       1,306       (24,853 )         —          322,680  

Interest expense

      (136,814 )      (5,769 )      (1,306 )      (35,507 )    (b)      —          (183,052 ) 
           (3,656 )    (m)      

Price risk management activities expense

      (10,312 )      (56,562 )      —         —            —          (66,874 ) 

Equity method investment income

      2,938       —         —         —            —          2,938  

Other income (expense)

      12,107       6,411       —         —            —          18,518  
  

 

 

    

 

 

    

 

 

    

 

 

       

 

 

     

 

 

  

Net income (loss) before income taxes

      19,121       139,105       —         (64,016 )         —          94,210  

Income tax benefit (expense)

      60,742       (30,276 )      —         13,443     (g)      —          43,909  
  

 

 

    

 

 

    

 

 

    

 

 

       

 

 

     

 

 

  

Net income (loss)

    $ 79,863     $ 108,829     $ —       $ (50,573 )       $ —        $ 138,119  
  

 

 

    

 

 

    

 

 

    

 

 

       

 

 

     

 

 

  

Net income (loss) per common share:

                 

Basic

    $ 0.64                 $ 0.80  

Diluted

    $ 0.63                 $ 0.80  

Weighted average common shares outstanding:

                 

Basic

      125,358           24,800     (e)      22,206        172,364  

Diluted

      126,161           24,800     (e)      22,206        173,167  

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, 2022

(In thousands, except per share amounts)

 

           Historical     Transaction Accounting
Adjustments		                    
     Talos pro forma
adjusted for
EnVen
Acquisition		     QuarterNorth     Reclass
Adjustment (a)		     Pro Forma
Adjustments		          Equity
Financing		      Pro Forma
Combined
Talos		  
     (see Note 2)           (see Note 4)     (see Note 4)          (see Note 5)         

Revenues:

                 

Oil

    $ 2,007,690     $ 709,484     $ —       $ —          $ —        $ 2,717,174  

Natural gas

      274,634       83,066       —         —            —          357,700  

NGL

      72,891       27,127       —         —            —          100,018  

Turnkey revenue

      —         70,008       —         (70,008 )    (l)      —          —    

Other revenue

      —         22,787       —         —            —          22,787  
  

 

 

    

 

 

    

 

 

    

 

 

       

 

 

     

 

 

  

Total revenues

      2,355,215       912,472       —         (70,008 )         —          3,197,679  

Operating expenses:

                 

Lease operating expense

      392,257       158,603       16,060       —            —          566,920  

Decommissioning costs of goods sold

      —         57,410       —         (57,410 )    (l)      —          —    

Production taxes

      3,488       —         —         —            —          3,488  

Depreciation, depletion and amortization

      696,533       223,755       —         (2,463 )    (j)      —          917,825  

Accretion expense

      79,635       15,835       —         —            —          95,470  

General and administrative expense

      181,281       20,400       1,697       14,649     (c)      —          221,676  
           3,649     (n)      

Insurance expense

      —         19,198       (19,198 )      —            —          —    

Other operating expense

      33,902       6,826       —         —            —          40,728  
  

 

 

    

 

 

    

 

 

    

 

 

       

 

 

     

 

 

  

Total operating expenses

      1,387,096       502,027       (1,441 )      (41,575 )         —          1,846,107  
  

 

 

    

 

 

    

 

 

    

 

 

       

 

 

     

 

 

  

Operating income

      968,119       410,445       1,441       (28,433 )         —          1,351,572  

Interest expense

      (178,758 )      (20,876 )      (1,441 )      (31,998 )    (b)      —          (237,948 ) 
           (4,875 )    (m)      

Price risk management activities expense

      (365,420 )      (98,104 )      —         —            —          (463,524 ) 

Equity method investment income

      14,222       —         —         —            —          14,222  

Other income (expense)

      38,503       59,891       —         —            —          98,394  
  

 

 

    

 

 

    

 

 

    

 

 

       

 

 

     

 

 

  

Net income (loss) before income taxes

      476,666       351,356       —         (65,306 )         —          762,716  

Income tax benefit (expense)

      (1,130 )      (77,918 )      —         13,714     (g)      —          (65,334 ) 
  

 

 

    

 

 

    

 

 

    

 

 

       

 

 

     

 

 

  

Net income (loss)

    $ 475,536     $ 273,438     $ —       $ (51,592 )       $ —        $ 697,382  
  

 

 

    

 

 

    

 

 

    

 

 

       

 

 

     

 

 

  

Net income (loss) per common share:

                 

Basic

    $ 3.77                 $ 4.03  

Diluted

    $ 3.73                 $ 4.00  

Weighted average common shares outstanding:

                 

Basic

      126,254           24,800     (e)      22,206        173,260  

Diluted

      127,483           24,800     (e)      22,206        174,489  

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 has been derived from its Annual Report on Form 10-K for the year ended December 31, 2022 and Quarterly Report on Form 10-Q for the nine months ended September 30, 2023. The EnVen historical financial information has been derived from its audited annual financial statements for the year ended December 31, 2022 and unaudited financial statements from January 1, 2023 through February 12, 2023. The QuarterNorth historical financial information have been derived from its audited annual financial statements for the year ended December 31, 2022 and unaudited financial statements for the nine months ended September 30, 2023. Certain EnVen and QuarterNorth historical amounts have been reclassified to conform to Talos’s financial statement presentation. The pro forma financial statements should be read in conjunction with Talos’s, EnVen’s, and QuarterNorth’s historical consolidated financial statements and the notes thereto. EnVen’s historical consolidated financial statements and the notes thereto are included in the April 12, 2023 current report on Form 8-K. QuarterNorth’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 QuarterNorth Acquisition and related financing consisting of borrowings under the Bank Credit Facility and proceeds from an underwritten equity offering as if they had been completed on September 30, 2023. The pro forma statement of operations gives effect to the EnVen Acquisition and QuarterNorth Acquisition and related financing as if they had been completed on January 1, 2022.

The pro forma adjustments for the EnVen Acquisition and QuarterNorth Acquisition and the related financing are described in the accompanying notes to the pro forma financial statements. The transaction accounting adjustments in the pro forma financial statements for the QuarterNorth Acquisition and EnVen Acquisition consists of those necessary to account for the transactions. Separately, we expect to generate gross proceeds of $300.0 million by issuing shares of our common stock in an underwritten equity offering to partially fund the cash consideration in the QuarterNorth Acquisition. The adjustments related to the issuance of common stock are shown in a separate column as “Equity Financing.”

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 EnVen Acquisition and QuarterNorth Acquisition and related financing had occurred on the dates indicated, nor are they indicative of Talos’s future financial position or results of operations.

 

8

Note 2—EnVen Acquisition Transaction Accounting Adjustments

The following tables present the unaudited pro forma condensed combined statement of operations for the EnVen Acquisition for the nine months ended September 30, 2023 and the year ended December 31, 2022.

Unaudited Pro Forma Condensed Combined Statement of Operations

For the Nine Months Ended September 30, 2023

(In thousands, except per share amounts)

 

     Historical                   
     Talos (1)     EnVen (2)     Pro Forma
Adjustments		          Talos pro forma
adjusted for EnVen
Acquisition		  

Revenues:

            

Oil

    $ 995,081     $ 48,694     $ —          $ 1,043,775  

Natural gas

      53,383       2,321       —            55,704  

NGL

      24,463       1,028       —            25,491  
  

 

 

    

 

 

    

 

 

       

 

 

  

Total revenues

      1,072,927       52,043       —            1,124,970  

Operating expenses:

            

Lease operating expense

      286,075       11,312       —            297,387  

Production taxes

      1,813       —         —            1,813  

Depreciation, depletion and amortization

      480,476       17,047       3,932     (b)      501,455  

Accretion expense

      63,430       3,391       (577 )    (c)      66,244  

General and administrative expense

      121,257       40,784       —            162,041  

Other operating expense

      (55,172 )      —         —            (55,172 ) 
  

 

 

    

 

 

    

 

 

       

 

 

  

Total operating expenses

      897,879       72,534       3,355          973,768  
  

 

 

    

 

 

    

 

 

       

 

 

  

Operating income (loss)

      175,048       (20,491 )      (3,355 )         151,202  

Interest expense

      (128,850 )      (6,623 )      204     (d)      (136,814 ) 
         (1,526 )    (e)   
         (19 )    (f)   

Price risk management activities expense

      (13,668 )      3,356       —            (10,312 ) 

Equity method investment income

      2,938       —         —            2,938  

Other income (expense)

      10,450       1,555       102     (g)      12,107  
  

 

 

    

 

 

    

 

 

       

 

 

  

Net income (loss) before income taxes

      45,918       (22,203 )      (4,594 )         19,121  

Income tax benefit (expense)

      55,516       4,261       965     (h)      60,742  
  

 

 

    

 

 

    

 

 

       

 

 

  

Net income (loss)

    $ 101,434     $ (17,942 )    $ (3,629 )       $ 79,863  
  

 

 

    

 

 

    

 

 

       

 

 

  

Net income (loss) per common share:

            

Basic

    $ 0.86            $ 0.64  

Diluted

    $ 0.85            $ 0.63  

Weighted average common shares outstanding:

            

Basic

      118,459         6,899     (i)      125,358  

Diluted

      119,262         6,899     (i)      126,161  

 

(1)

Represents Talos consolidated results of operations for the nine months ended September 30, 2023, which includes EnVen beginning on February 13, 2023.

(2)

Represents EnVen stand-alone consolidated results of operations for the period from January 1, 2023 to February 12, 2023 conformed to the Talos financial statement presentation.

Talos historical general and administrative (“G&A”) expense above includes approximately $12.8 million of nonrecurring acquisition-related costs in connection with the EnVen Acquisition. Additionally, Talos incurred $24.9 million in severance expense in connection with the EnVen Acquisition that is included in G&A. EnVen historical G&A expense above includes $20.8 million of stock-based compensation due to restricted stock awards that vested and accelerated as a result of the closing of the EnVen Acquisition as well as $12.7 million of nonrecurring transaction costs associated with the EnVen’s merger with Talos.

 

9

Unaudited Pro Forma Condensed Combined Statement of Operations

For the Year Ended December 31, 2022

(In thousands, except per share amounts)

 

     Historical     Transaction Accounting
Adjustments		             
     Talos     EnVen     Reclass
Adjustment (a)		     Pro Forma
Adjustments		          Talos pro forma
adjusted for
EnVen
Acquisition		  

Revenues:

              

Oil

    $ 1,365,148     $ —       $ 642,542     $ —          $ 2,007,690  

Natural gas

      227,306       —         47,328       —            274,634  

NGL

      59,526       —         13,365       —            72,891  

Oil, natural gas, and NGL revenue

      —         703,235       (703,235 )      —            —    

Production handling and other income

      —         27,505       (27,505 )      —            —    
  

 

 

    

 

 

    

 

 

    

 

 

       

 

 

  

Total revenues

      1,651,980       730,740       (27,505 )      —            2,355,215  

Operating expenses:

              

Lease operating expense

      308,092       81,394       24,302       —            392,257  
         8,939         
         (2,965 )        
         (27,505 )        

Workover, repair, and maintenance

      —         24,302       (24,302 )      —            —    

Transportation, gathering, and processing costs

      —         8,939       (8,939 )      —            —    

Production taxes

      3,488       —         —         —            3,488  

Depreciation, depletion and amortization

      414,630       149,441       —         132,462     (b)      696,533  

Accretion expense

      55,995       26,901       —         (3,261 )    (c)      79,635  

General and administrative expense

      99,754       78,562       2,965       —            181,281  

Other operating expense

      33,902       —         —         —            33,902  
  

 

 

    

 

 

    

 

 

    

 

 

       

 

 

  

Total operating expenses

      915,861       369,539       (27,505 )      129,201          1,387,096  
  

 

 

    

 

 

    

 

 

    

 

 

       

 

 

  

Operating income (loss)

      736,119       361,201       —         (129,201 )         968,119  

Interest expense

      (125,498 )      (46,446 )      —         2,589     (d)      (178,758 ) 
           (8,929 )    (e)   
           (474 )    (f)   

Price risk management activities expense

      (272,191 )      (93,229 )      —         —            (365,420 ) 

Equity method investment income

      14,222       —         —         —            14,222  

Other income (expense)

      31,800       5,203       —         1,500     (g)      38,503  
  

 

 

    

 

 

    

 

 

    

 

 

       

 

 

  

Net income (loss) before income taxes

      384,452       226,729       —         (134,515 )         476,666  

Income tax benefit (expense)

      (2,537 )      (26,841 )      —         28,248     (h)      (1,130 ) 
  

 

 

    

 

 

    

 

 

    

 

 

       

 

 

  

Net income (loss)

    $ 381,915     $ 199,888     $ —       $ (106,267 )       $ 475,536  
  

 

 

    

 

 

    

 

 

    

 

 

       

 

 

  

Net income (loss) per common share:

              

Basic

    $ 4.63              $ 3.77  

Diluted

    $ 4.56              $ 3.73  

Weighted average common shares outstanding:

              

Basic

      82,454           43,800     (i)      126,254  

Diluted

      83,683           43,800     (i)      127,483  

Talos historical general and administrative (“G&A”) expense above includes approximately $9.0 million of nonrecurring acquisition-related costs in connection with the EnVen Acquisition. EnVen historical G&A expense above includes $7.3 million of nonrecurring transaction costs associated with the EnVen merger with Talos.

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 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 EnVen Acquisition. The pro forma depletion rate for the year ended December 31, 2022 was estimated using the proved property amounts based on the preliminary purchase price allocation and estimates of reserves at December 31, 2022, adjusted for actual production. The pro forma depletion rates were applied to production volumes for the Talos properties and EnVen properties for the respective period. Depreciation, depletion and amortization increased by $132.5 million for the year ended December 31, 2022 and $3.9 for the period from January 1, 2023 to February 12, 2023.

 

  (c)

Reflects changes in accretion expense that would have been recorded with respect to the allocated fair values attributable to asset retirement obligations assumed with a decrease to accretion expense of $3.3 million for the year ended December 31, 2022 and a decrease to accretion expense of $0.6 million for the period from January 1, 2023 to February 12, 2023.

 

10

  (d)

Reflects amortization of the premium associated with senior notes assumed as a reduction to interest expense of $2.6 million for the year ended December 31, 2022 and $0.2 for the period from January 1, 2023 to February 12, 2023.

 

  (e)

Reflects an increase in interest expense assuming additional borrowings of $163.2 million under the Bank Credit Facility to fund a portion of the cash consideration. For the year ended December 31, 2022, pro forma interest expense was based on a weighted-average interest rate of 5.47%. For the period from January 1, 2023 to February 12, 2023, pro forma interest expense was based on a weighted-average interest rate of 7.94%. 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, 2023		     Year Ended
December 31, 2022		  

Weighted-average interest rate

      7.94 %      5.47 % 

Interest expense

    $ 1,526     $ 8,929  

Weighted-average interest rate—increase 0.125%

      8.07 %      5.60 % 

Interest expense

    $ 1,550     $ 9,133  

Weighted-average interest rate—decrease 0.125%

      7.82 %      5.35 % 

Interest expense

    $ 1,502     $ 8,725  

 

  (f)

Reflects accretion of the discount as an increase to interest expense of $0.4 million and less than $0.1 million for the year ended December 31, 2022 and period from January 1, 2023 to February 12, 2023, respectively, associated with a consent solicitation fee of $3.1 million related to Talos Production’s senior notes.

 

  (g)

Reflects accretion of discount as an increase to other income (expense) of $1.5 million and $0.1 million for the year ended December 31, 2022 and period from January 1, 2023 to February 12, 2023, respectively, associated with acquired notes receivable.

 

  (h)

Reflects the income tax effect 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 EnVen Acquisition.

 

  (i)

Reflects the increase in shares of Talos common stock resulting from the issuance of shares of Talos common stock to EnVen stockholders to effect the EnVen Acquisition.

Note 3—QuarterNorth Preliminary Acquisition Accounting

Talos has determined it is the accounting acquirer for the QuarterNorth Acquisition 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 QuarterNorth Acquisition 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, 2023 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’s 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 QuarterNorth Acquisition. Talos expects to finalize the purchase price allocation as soon as practicable after completing the QuarterNorth Acquisition.

The preliminary purchase price allocation is subject to change due to changes in the estimated fair value of QuarterNorth’s identifiable assets acquired and liabilities assumed as of the closing date of the QuarterNorth Acquisition, which could result from Talos’s additional valuation analysis, reserves estimates, discount rates and other factors.

 

11

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

      24,800  

Talos common stock price

    $ 13.51  
  

 

 

  

Stock consideration

    $ 335,048  

Cash consideration

    $ 1,273,861  
  

 

 

  

Total purchase price

    $ 1,608,909  
  

 

 

  

The stock consideration was determined using the closing price of Talos common stock on January 12, 2024. The final stock consideration will be based on the market price of Talos common stock when the QuarterNorth Acquisition is consummated. The following table summarizes the change in stock consideration resulting from a 10% fluctuation in the market price of Talos common stock (in thousands, except per share amounts):

 

     Talos share price      Purchase price (equity portion)  

As presented

    $ 13.51      $ 335,048  

10% increase

      14.86        368,553  

10% decrease

      12.16        301,543  

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

    $ 387,722  

Accounts receivable

      179,489  

Prepaid expenses and other current assets

      40,504  

Property and equipment:

   

Proved properties

      1,271,424  

Unproved properties, not subject to amortization

      428,104  

Other property and equipment

      6,741  

Other long-term assets:

   

Operating lease assets

      5,836  

Other well equipment inventory

      49,166  

Other assets

      933  
  

 

 

  

Total assets to be acquired

    $ 2,369,919  
  

 

 

  

Liabilities assumed

   

Current liabilities:

   

Accounts payable

      56,860  

Accrued liabilities

      108,360  

Accrued royalties

      14,182  

Current portion of asset retirement obligations

      10,577  

Liabilities from price risk management activities

      43,723  

Accrued interest payable

      138  

Current portion of operating lease liabilities

      1,225  

Other current liabilities

      1,718  

Long-term liabilities:

   

Long-term debt

      185,000  

Asset retirement obligations

      112,732  

Liabilities from price risk management activities

      9,641  

Operating lease liabilities

      4,848  

Deferred tax liability

      212,006  
  

 

 

  

Total liabilities to be assumed

      761,010  
  

 

 

  

Net assets to be acquired

    $ 1,608,909  
  

 

 

  

 

12

Note 4—QuarterNorth 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 QuarterNorth historical financial statements to conform to Talos’s financial statement presentation.

 

  (b)

Reflects an increase of $584.7 million in long-term debt and associated interest expense attributable to additional borrowings under the Bank Credit Facility to fund a portion of the cash consideration. The increase in interest expense assumes the borrowing occurred on January 1, 2022 and was outstanding for both the year ended December 31, 2022 and nine months ended September 30, 2023. For the year ended December 31, 2022 and nine months ended September 30, 2023, pro forma interest expense was based on a weighted-average interest rate of 5.47% and 8.10%, 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, 2023		     Year Ended
December 31, 2022		  

Weighted-average interest rate

      8.10 %      5.47 % 

Interest expense

    $ 35,507     $ 31,998  

Weighted-average interest rate—increase 0.125%

      8.22 %      5.60 % 

Interest expense

    $ 36,055     $ 32,729  

Weighted-average interest rate—decrease 0.125%

      7.97 %      5.35 % 

Interest expense

    $ 34,958     $ 31,267  

 

  (c)

Reflects the accrual for transaction costs of $14.6 million related to the QuarterNorth Acquisition including, among others, fees paid for financial advisors, legal services and professional accounting services. The costs are not reflected in the historical September 30, 2023 consolidated balance sheet of Talos, but are reflected in the Talos combined pro forma balance sheet as of September 30, 2023, as an increase to Accrued liabilities and increase to Accumulated deficit. The Talos combined pro forma statement of operations for the year ended December 31, 2022, reflects a $14.6 million expense to General and administrative expense as the transaction costs will be expensed by Talos 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, 2023, 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 QuarterNorth Acquisition.

 

  (d)

Reflects the cash consideration paid to QuarterNorth stockholders to effect the QuarterNorth Acquisition.

 

  (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 QuarterNorth stockholders to effect the QuarterNorth Acquisition based on the Talos closing share price of $13.51 on January 12, 2024.

 

  (f)

Reflects the elimination of QuarterNorth’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 QuarterNorth Acquisition.

 

  (h)

Reflects the write-off of QuarterNorth’s historical unamortized and deferred financing costs.

 

13

  (i)

Reflects the adjustments to reflect the preliminary estimated fair value of Talos common stock of $335.0 million and cash consideration of $1,273.9 million allocated to the estimated fair values of the assets acquired and liabilities assumed.

Reflects a $663.5 million increase to Total Property and Equipment, net calculated as the difference between the estimated fair value and QuarterNorth’s historical net book value. The change is primarily a result of (i) a decrease in Proved properties as a result of QuarterNorths’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, (ii) 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 QuarterNorth 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 abandonment costs, (v) estimated cash flows and (vi) a market-based weighted average cost of capital rate. These estimates require significant judgment and may vary due to many factors, such as, but not limited to, the inputs to the fair value measure described above.

 

  (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 QuarterNorth Acquisition. The pro forma depletion rate for the year ended December 31, 2022 was estimated using the proved property amounts based on the preliminary purchase price allocation and estimates of reserves at December 31, 2022, adjusted for actual production. The pro forma depletion rate for the nine months ended September 30, 2023 was estimated using the proved property amounts based on the preliminary purchase price allocation and estimates of reserves at September 30, 2023, adjusted for actual production. The pro forma depletion rates were applied to production volumes for the Talos properties, the EnVen properties and QuarterNorth properties for the respective periods. Depreciation, depletion and amortization decreased by $2.5 million for the year ended December 31, 2022 and $0.4 million for the nine months ended September 30, 2023.

 

  (k)

Reflects purchase accounting adjustment to the Historical QuarterNorth Deferred tax liability of $68.0 million to record the estimated deferred income tax effects of $144.0 million to reflect the QuarterNorth Acquisition. 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 QuarterNorth Acquisition.

 

  (l)

Reflects the elimination of revenues and costs of good sold associated with the disposition of QuarterNorth’s decommissioning services business under turnkey agreements. The revenues and costs are not expected to be incurred in any period beyond 12 months from the closing date of the QuarterNorth Acquisition.

 

  (m)

In the event that additional financing is needed to fund the cash consideration for the QuarterNorth Acquisition, we received a $650.0 million commitment under a bridge credit facility from a syndicate of lenders, including some lenders under our Bank Credit Facility. For pro forma purposes, the bridge loan was unused and the adjustment reflects the amortization of debt issuance costs associated with the unused bridge facility. If the bridge loan were fully utilized to partially fund the cash consideration for the QuarterNorth Acquisition, the incremental interest expense in the pro forma financial statements would be $59.2 million and $37.5 million for the year ended December 31, 2022 and nine months ended September 30, 2023, respectively.

 

  (n)

Reflects the accrual of contractual severance and other separation benefits associated with existing QuarterNorth employment agreements in connection with the termination of certain executive officers of QuarterNorth that will occur immediately after the consummation of the QuarterNorth Acquisition. The post-combination expense is reflected in the Talos combined pro forma balance sheet as of September 30, 2023, 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, 2022, within General and administrative expense.

Note 5—Equity Financing

We expect to generate gross proceeds of $300.0 million (before underwriting discounts and commissions and offering expenses) in an underwritten offering of our common stock to partially fund the cash consideration in the QuarterNorth Acquisition. After deducting the underwriting discounts and commissions and offering expenses payable by us, the total net proceeds are expected to be approximately $287.8 million. Based on the closing price of Talos common stock on January 12, 2024 of $13.51, we expect to issue approximately 22.2 million shares of common stock (assuming no exercise of underwriters’ option to purchase additional shares). The following table summarizes the estimated common stock to be issued resulting from a 10% fluctuation in the market price of Talos common stock (in thousands, except per share amounts):

 

     Talos share price      Common stock
issued		  

As presented

    $ 13.51        22,206  

10% increase

      14.86        20,187  

10% decrease

      12.16        24,673  

 

14

Note 6—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, 2022, along with a summary of changes in quantities of net remaining proved reserves during the year ended December 31, 2022.

The following estimated pro forma oil and gas reserves information is not necessarily indicative of the results that might have occurred had the EnVen Acquisition and QuarterNorth Acquisition been completed on January 1, 2022, and is not intended to be a projection of future results.

 

     Crude Oil Reserves (MBbls)  
     Historical
Talos		      Historical
EnVen		      Historical
QuarterNorth		      Pro Forma
Combined
Talos		  

Total proved reserves at January 1, 2022

      107,764        42,596        42,507        192,867  

Revision of previous estimates

      (5,625 )       4,113        10,500        8,988  

Production

      (14,561 )       (7,049 )       (7,559 )       (29,169 ) 

Purchase of reserves

      —          —          244        244  

Sales of reserves

      (158 )       —          (1,913 )       (2,071 ) 

Extensions and discoveries

      3,639        2,502        4,304        10,445  
  

 

 

     

 

 

     

 

 

     

 

 

  

Total proved reserves at December 31, 2022

      91,059        42,162        48,083        181,304  

Total proved developed reserves as of:

            

December 31, 2021

      93,420        36,281        22,732        152,433  

December 31, 2022

      80,285        34,468        25,201        139,954  

Total proved undeveloped reserves as of:

            

December 31, 2021

      14,344        6,315        19,775        40,434  

December 31, 2022

      10,774        7,694        22,882        41,350  

 

     Natural Gas Reserves (MMcf)  
     Historical
Talos		      Historical
EnVen		      Historical
QuarterNorth		      Pro Forma
Combined
Talos		  

Total proved reserves at January 1, 2022

      236,353        41,003        111,155        388,511  

Revision of previous estimates

      (8,302 )       195        7,147        (960 ) 

Production

      (32,215 )       (5,921 )       (11,689 )       (49,825 ) 

Purchase of reserves

      —          —          363        363  

Sales of reserves

      (7,625 )       —          (3,274 )       (10,899 ) 

Extensions and discoveries

      31,340        1,710        8,599        41,649  
  

 

 

     

 

 

     

 

 

     

 

 

  

Total proved reserves at December 31, 2022

      219,551        36,987        112,301        368,839  

Total proved developed reserves as of:

            

December 31, 2021

      186,442        36,930        58,526        281,898  

December 31, 2022

      161,727        25,717        55,383        242,827  

Total proved undeveloped reserves as of:

            

December 31, 2021

      49,911        4,073        52,629        106,613  

December 31, 2022

      57,824        11,270        56,918        126,012  

 

15

     NGL Reserves (MBbls)  
     Historical
Talos		      Historical
EnVen		      Historical
QuarterNorth		      Pro Forma
Combined
Talos		  

Total proved reserves at January 1, 2022

      14,435        980        5,522        20,937  

Revision of previous estimates

      (2,002 )       340        274        (1,388 ) 

Production

      (1,793 )       (308 )       (686 )       (2,787 ) 

Purchase of reserves

      —          —          17        17  

Sales of reserves

      —          —          (244 )       (244 ) 

Extensions and discoveries

      2,288        109        562        2,959  
  

 

 

     

 

 

     

 

 

     

 

 

  

Total proved reserves at December 31, 2022

      12,928        1,121        5,445        19,494  

Total proved developed reserves as of:

            

December 31, 2021

      11,792        854        2,968        15,614  

December 31, 2022

      9,315        1,036        2,700        13,051  

Total proved undeveloped reserves as of:

            

December 31, 2021

      2,643        126        2,554        5,323  

December 31, 2022

      3,613        85        2,745        6,443  

 

     Total Reserves (Mboe)  
     Historical
Talos		      Historical
EnVen		      Historical
QuarterNorth		      Pro Forma
Combined
Talos		  

Total proved reserves at January 1, 2022

      161,591        50,410        66,555        278,556  

Revision of previous estimates

      (9,010 )       4,485        11,965        7,440  

Production

      (21,723 )       (8,344 )       (10,194 )       (40,261 ) 

Purchase of reserves

      —          —          322        322  

Sales of reserves

      (1,429 )       —          (2,703 )       (4,132 ) 

Extensions and discoveries

      11,150        2,896        6,300        20,346  
  

 

 

     

 

 

     

 

 

     

 

 

  

Total proved reserves at December 31, 2022

      140,579        49,447        72,245        262,271  

Total proved developed reserves as of:

            

December 31, 2021

      136,286        43,290        35,454        215,030  

December 31, 2022

      116,555        39,790        37,132        193,477  

Total proved undeveloped reserves as of:

            

December 31, 2021

      25,305        7,120        31,101        63,526  

December 31, 2022

      24,024        9,657        35,113        68,794  

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, 2022. The pro forma standardized measure information set forth below gives effect to the EnVen Acquisition and QuarterNorth Acquisition as if these acquisitions had been completed on January 1, 2022. 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’s Annual Report on Form 10-K for the year ended December 31, 2022, the “Standardized Measure of Discounted Future Net Cash Flows” reported in EnVen’s Annual Report for the year ended December 31, 2022 and the “Standardized Measure of Discounted Future Net Cash Flows” reported in QuarterNorth’s Annual Report for the year ended December 31, 2022. An explanation of the underlying methodology applied, as required by SEC regulations, can be found within the Talos Annual Report on Form 10-K, EnVen Annual Report and QuarterNorth Annual Report. The calculations assume the continuation of existing economic, operating and contractual conditions at December 31, 2022.

Therefore, the following estimated pro forma standardized measure is not necessarily indicative of the results that might have occurred had these acquisitions been completed on January 1, 2022 and is not intended to be a projection of future results.

 

16

     Historical      Historical      Historical      Pro Forma
Combined		  
     Talos      EnVen      QuarterNorth      Talos  
     (In thousands)  

At December 31, 2022

   

Future cash inflows

    $ 10,674,896      $ 4,172,745      $ 5,507,038      $ 20,354,679  

Future costs:

            

Production

      (1,906,752 )       (999,608 )       (1,273,184 )       (4,179,544 ) 

Development and abandonment

      (1,873,453 )       (524,314 )       (521,676 )       (2,919,443 ) 
  

 

 

     

 

 

     

 

 

     

 

 

  

Future net cash flows before income taxes

      6,894,691        2,648,823        3,712,178        13,255,692  

Future income tax expense

      (1,114,409 )       (521,708 )       (686,808 )       (2,322,925 ) 
  

 

 

     

 

 

     

 

 

     

 

 

  

Future net cash flows after income taxes

      5,780,282        2,127,115        3,025,370        10,932,767  

Discount at 10% annual rate

      (1,411,834 )       (500,588 )       (775,938 )       (2,688,360 ) 
  

 

 

     

 

 

     

 

 

     

 

 

  

Standardized measure of discounted future net cash flows

    $ 4,368,448      $ 1,626,527      $ 2,249,432      $ 8,244,407  
  

 

 

     

 

 

     

 

 

     

 

 

  

 

17

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, 2022 are as follows:

 

     Historical      Historical      Historical      Pro Forma
Combined		  
     Talos      EnVen      QuarterNorth      Talos  
     (In thousands)  

Standardized measure at January 1, 2022

    $ 3,440,611      $ 1,140,435      $ 1,381,632      $ 5,962,678  

Sales and transfers of oil, net gas and NGLs produced during the period

      (1,340,400 )       (588,601 )       (769,587 )       (2,698,588 ) 

Net change in prices and production costs

      2,388,442        734,853        1,345,716        4,469,011  

Changes in estimated future development and abandonment costs

      (84,391 )       (10,620 )       10,717        (84,294 ) 

Previously estimated development and abandonment costs incurred

      20,107        8,866        4,788        33,761  

Accretion of discount

      392,600        139,678        138,163        670,441  

Net change in income taxes

      (327,265 )       (131,681 )       (517,669 )       (976,615 ) 

Purchase of reserves

      —          —          14,149        14,149  

Sales of reserves

      (5,218 )       —          (63,448 )       (68,666 ) 

Extensions and discoveries

      202,239        184,936        289,031        676,206  

Net change due to revision in quantity estimates

      (255,743 )       198,557        471,733        414,547  

Changes in production rates (timing) and other

      (62,534 )       (49,896 )       (55,793 )       (168,223 ) 
  

 

 

     

 

 

     

 

 

     

 

 

  

Standardized measure at December 31, 2022

    $ 4,368,448      $ 1,626,527      $ 2,249,432      $ 8,244,407  
  

 

 

     

 

 

     

 

 

     

 

 

  

 

18

Exhibit 99.3

 

LOGO

QUARTERNORTH ENERGY INC.

CONSOLIDATED FINANCIAL STATEMENTS

YEAR ENDED DECEMBER 31, 2022

LOGO

Report of Independent Auditors

To the Board of Directors of QuarterNorth Energy Inc.,

Opinion

We have audited the consolidated financial statements of QuarterNorth Energy Inc. (the Company), which comprise the consolidated balance sheet as of December 31, 2022, and the related consolidated statements of operations, changes in stockholders’ equity and cash flows for the year then ended, 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, 2022, and the results of its operations and its cash flows for the year then ended in accordance with accounting principles generally accepted in the United States of America.

Basis for Opinion

We conducted our audit 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 audit. We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our audit opinion.

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.

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.

LOGO

 

  •  

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.

Supplementary Information

Our audit was conducted for the purpose of forming an opinion on the financial statements as a whole. The Supplemental Consolidating Financial Information and the Supplemental Information on Oil and Natural Gas Operations are presented for purposes of additional analysis and are not a required part of the financial statements. Such information is the responsibility of management and was derived from and relates directly to the underlying accounting and other records used to prepare the financial statements. The information, except for that portion marked “unaudited,” has been subjected to the auditing procedures applied in the audit of the financial statements and certain additional procedures, including comparing and reconciling such information directly to the underlying accounting and other records used to prepare the financial statements or to the financial statements themselves, and other additional procedures in accordance with auditing standards generally accepted in the United States of America. In our opinion, the information, except for that portion marked “unaudited” on which we express no opinion, is fairly stated, in all material respects, in relation to the financial statements as a whole.

 

LOGO

March 31, 2023

 

QUARTERNORTH ENERGY INC.

CONSOLIDATED BALANCE SHEET

AS OF DECEMBER 31, 2022

(In thousands, except share amounts)

 

Assets

 

Current assets:

   

Cash and cash equivalents

    $ 400,816  

Short-term investment

      60,170  

Accounts receivable, net

      144,060  

Materials and supplies

      46,002  

Derivative contracts

      8,440  

Other current assets

      38,478  
  

 

 

  

Total current assets

      697,966  
  

 

 

  

Proved properties, net

      884,796  

Unproved properties, not subject to amortization

      183,779  

Other property and equipment, net

      1,213  

Restricted cash

      1,097  

Other assets

      7,115  
  

 

 

  

Total assets

    $ 1,775,966  
  

 

 

  
Liabilities and Stockholders’ Equity

 

Current liabilities:

   

Accounts payable

    $ 44,449  

Accrued liabilities

      133,368  

Derivative contracts

      8,156  

Current maturities of debt

      1,000  

Current portion of asset retirement obligations

      4,048  

Other current liabilities

      16,997  
  

 

 

  

Total current liabilities

      208,018  
  

 

 

  

Long-term debt

      180,939  

Asset retirement obligations

      129,132  

Deferred income taxes

      66,651  

Other long-term liabilities

      6,946  
  

 

 

  

Total liabilities

      591,686  
  

 

 

  

Commitments and contingencies (see Note 13)

   

Stockholders’ equity:

   

Common stock, par value $0.01; 50,000,000 shares authorized;
7,540,813 shares issued and outstanding as of December 31, 2022

      75  

Additional paid-in capital

      978,531  

Retained earnings

      205,674  
  

 

 

  

Total stockholders’ equity

      1,184,280  
  

 

 

  

Total liabilities and stockholders’ equity

    $ 1,775,966  
  

 

 

  

See notes to consolidated financial statements

 

1

QUARTERNORTH ENERGY INC.

CONSOLIDATED STATEMENT OF OPERATIONS

YEAR ENDED DECEMBER 31, 2022

(In thousands)

 

Revenues:

   

Oil revenue

    $ 709,484  

Natural gas revenue

      83,066  

Natural gas liquids revenue

      27,127  

Turnkey revenue

      70,008  

Other revenue

      22,787  
  

 

 

  

Total revenues

      912,472  
  

 

 

  

Operating expenses:

   

Lease operating expense

      158,603  

Decommissioning cost of goods sold

      57,410  

Depletion, depreciation and amortization

      223,755  

General and administrative expense

      20,400  

Insurance expense

      19,198  

Accretion expense

      15,835  

Other operating expense

      6,826  
  

 

 

  

Total operating expenses

      502,027  
  

 

 

  

Income from operations

      410,445  

Other income (expense), net:

   

Interest expense

      (20,876 ) 

Commodity derivative expense

      (98,104 ) 

Other

      59,891  
  

 

 

  

Income before income taxes

      351,356  

Income tax expense

      (77,918 ) 
  

 

 

  

Net income

    $ 273,438  
  

 

 

  

See notes to consolidated financial statements

 

2

QUARTERNORTH ENERGY INC.

CONSOLIDATED STATEMENT OF CASH FLOWS

YEAR ENDED DECEMBER 31, 2022

(In thousands)

 

Cash flows from operating activities:

   

Net income

    $ 273,438  

Adjustment to reconcile net income to net cash provided by operating activities:

   

Amortization in interest expense

      1,816  

Accretion of asset retirement obligations

      15,835  

Depreciation, depletion and amortization

      223,755  

Risk management activities

      (37,869 ) 

Deferred income tax expense

      63,271  

Changes in operating assets and liabilities:

   

Accounts receivable and other assets

      (21,297 ) 

Accounts payable and other liabilities

      8,456  

Expenditures on asset retirement obligations, net

      (29,352 ) 
  

 

 

  

Net cash provided by operating activities

      498,053  
  

 

 

  

Cash flows from investing activities:

   

Additions to property and equipment

      (168,339 ) 

Changes in operating assets and liabilities associated with investing activities

      30,154  

Acquisitions, net of cash received

      240  

Investment in short-term investments

      (99,588 ) 

Proceeds from short-term investments

      40,000  

Investment in Fieldwood Mexico

      (4,108 ) 

Proceeds from sale of assets held for sale

      55,749  

Proceeds from sale of oil and gas properties

      10,629  
  

 

 

  

Net cash used in investing activities

      (135,263 ) 
  

 

 

  

Cash Flows from financing activities:

   

Repayments of first lien term loan

      (99,000 ) 

Debt issuance costs

      (1,170 ) 

Payment of finance lease

      (168 ) 

Dividends paid

      (79,293 ) 
  

 

 

  

Net cash used in financing activities

      (179,631 ) 
  

 

 

  

Net increase in cash and cash equivalents, including restricted cash

      183,159  

Cash and cash equivalents, including restricted cash, beginning of period

      218,754  
  

 

 

  

Cash and cash equivalents, including restricted cash, end of period

    $ 401,913  
  

 

 

  

See notes to consolidated financial statements

 

3

QUARTERNORTH ENERGY INC.

CONSOLIDATED STATEMENT OF CHANGES IN STOCKHOLDERS’ EQUITY

YEAR ENDED DECEMBER 31, 2022

(In thousands, except share amounts)

 

     Common Stock      Additional
Paid-In
Capital		     Retained
Earnings		     Total  
     Shares      Amount  

Balance, beginning of period

      6,973,765      $ 70      $ 995,695     $ 11,529     $ 1,007,294  

Issuance of common stock from exercise of warrants

      567,048        5        —         —         5  

Dividends to stockholders

      —          —          —         (79,293 )      (79,293 ) 

Measurement period adjustment

      —          —          (17,164 )      —         (17,164 ) 

Net income

      —          —          —         273,438       273,438  
  

 

 

     

 

 

     

 

 

    

 

 

    

 

 

  

Balance, end of period

      7,540,813      $ 75      $ 978,531     $ 205,674       1,184,280  
  

 

 

     

 

 

     

 

 

    

 

 

    

 

 

  

See notes to consolidated financial statements

 

4

QUARTERNORTH ENERGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Except as noted within the context of each footnote disclosure, the dollar amounts presented in the tabular data within these footnote disclosures are in thousands of dollars.

Note 1—Basis of Presentation and Summary of Significant Accounting Policies

Description of Company

QuarterNorth Energy Inc. (“QuarterNorth”, “we”, “us”, “our” or “the Company”) was incorporated in Delaware on June 4, 2021, and amended as of July 16, 2021. On June 4, 2021, the Company formed four indirect wholly owned subsidiaries: QuarterNorth Energy Holding Inc.; QuarterNorth Energy Intermediate Inc.; QuarterNorth Energy LLC; and Mako Buyer 2 LLC. All four entities are Delaware corporations or limited liability companies and were formed in contemplation of the Credit Bid Acquisition (as defined herein).

Business Operations and Strategy

QuarterNorth is an independent oil and natural gas producer with substantially all of its operations in the U.S. Gulf of Mexico (“GOM”). We commenced operations on August 27, 2021, when QuarterNorth Energy LLC purchased certain oil and natural gas properties (the “Credit Bid Acquisition”) from Fieldwood Energy Inc. and subsidiaries (collectively, “Fieldwood”) pursuant to a purchase and sale agreement (the “Purchase Agreement” or “PSA”), see Note 3 – Credit Bid Acquisition for details. We are active in the exploration, operations, exploitation, development and acquisition of oil and gas properties.

We maintain offices in Houston, Texas (headquarters) and Lafayette, Louisiana, as well as certain other shore-based field locations in Louisiana. We had 304 employees as of December 31, 2022.

We operate our business through ourselves and our consolidated subsidiaries, primarily through QuarterNorth Energy LLC, our main operating subsidiary, which owns all of our oil and gas properties and is operator of record for many of the properties.

Basis of Presentation

The accompanying consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”). All intercompany transactions have been eliminated.

The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities as of the date of the financial statements, the reported amounts of revenues and expenses during the reporting period and the reported amounts of proved oil and natural gas reserves. Actual results could differ from those estimates.

In preparing the accompanying consolidated financial statements, we have reviewed, as determined necessary by management, events that have occurred after December 31, 2022, up until the issuance of the consolidated financial statements, which occurred on March 31, 2023.

See Note 5—Debt for information regarding subsequent events.

Summary of Significant Accounting Policies

Accounts Receivable. We sell oil and natural gas to various customers and participate with other parties in the drilling, completion, and operation of oil and natural gas wells. Joint interest and oil and natural gas sales receivables related to our operations are generally unsecured. The purchasers of the Company’s oil and natural gas production consist of independent marketers, major oil and natural gas companies and gas pipeline companies.

 

5

QUARTERNORTH ENERGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

 

Asset Retirement Obligations (“AROs”). We record the fair value of a liability for a legal obligation to retire a tangible long-lived asset in the period in which the liability is incurred and can be reasonably estimated with the corresponding cost capitalized by increasing the carrying amount of the related long-lived asset. The liability is accreted to its present value each period and the capitalized costs are amortized using the unit-of-production method. The accretion expense is recorded as an operating expense. Estimates of AROs are revised as information about material changes to the liability becomes known. Revisions are recorded as adjustments to existing liabilities and to the carrying amount of the related assets. Settlement gains or losses are charged to oil and natural gas properties. Our AROs relate primarily to the plugging and abandonment of oil and natural gas wells and to the decommissioning of related pipelines, facilities and structures. See Note 6—Asset Retirement Obligations for further information.

Cash, Cash Equivalents, and Restricted Cash. Cash and cash equivalents represent unrestricted cash on hand, demand deposits, and investments with original maturities of three months or less. We consider cash equivalents to include short-term, highly liquid investments that are readily convertible to known amounts of cash and which are subject to an insignificant risk of changes in value.

Our restricted cash serves as collateral for certain of our obligations. These restricted funds are generally invested in interest-bearing accounts.

The following table provides a reconciliation of cash and cash equivalents, and restricted cash reported within the Consolidated Balance Sheet that sums to the total of the amounts shown in the Statement of Consolidated Cash Flows.

 

     End of
Period		      Beginning of
Period		  

Cash

    $ 400,816      $ 218,512  

Restricted cash

      1,097        242  
  

 

 

     

 

 

  
   $ 401,913      $ 218,754  
  

 

 

     

 

 

  

Short-term investments. Our short-term investments are comprised of U.S. Treasury securities with original maturities greater than three months. Management has both the positive intent and ability to hold these securities until the maturity date and thus considered these securities to be Held-to-maturity. These securities are carried at amortized cost.

Concentration of Credit Risk. We extend credit, primarily in the form of uncollateralized oil and natural gas sales and joint interest owner receivables, to various companies in the oil and natural gas industry, which results in a concentration of credit risk. The concentration of credit risk may be affected by changes in economic or other conditions within the oil and natural gas industry and may accordingly impact our overall credit risk. We believe our joint interest partners specific to our owned and operated properties primarily consist of large independent oil and natural gas companies and the risk of these unsecured receivables is substantially mitigated by the size, reputation and nature of the companies to which we extend credit.

The following table lists the percentage of our consolidated oil and natural gas revenues with purchasers that accounted for more than 10% of our consolidated oil, natural gas, and natural gas liquids revenues for the year ended December 31, 2022:

 

Shell Trading (US) Co.

      41 % 

Exxon Mobil Corp.

      29 % 

Our allowance for doubtful accounts is based on estimates of future uncollectible accounts. In evaluating the collectability of accounts receivable, we make judgments regarding each party’s ability to make required payments, economic events, and other factors. As the financial condition of any party changes, circumstances develop or additional information becomes available, adjustments to an allowance for doubtful accounts may be required.

 

6

QUARTERNORTH ENERGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

 

Allowance for doubtful accounts, beginning of period

    $ —    

Charged to costs and expenses

      2,660  
  

 

 

  

Allowance for doubtful accounts, end of period

    $ 2,660  
  

 

 

  

We use commodity derivative contracts to mitigate the effects of commodity price fluctuations. These derivative contracts expose us to counterparty credit risk. Our counterparties are generally major banks, commodity trading firms, or financial institutions. All derivative contracts are executed under master agreements, which allow us, in the event of default, to elect early termination of all contracts with the defaulting counterparty. If we choose to elect early termination, all asset and liability positions with the defaulting counterparty would be net settled at the time of election. We monitor the creditworthiness of our counterparties. However, we are not able to predict sudden changes in our counterparties’ creditworthiness. Should a financial counterparty not perform, we may not realize the benefit of some of our derivative contracts under lower commodity prices, and we may incur a loss.

Consolidation Policy. Our consolidated financial statements include the accounts of majority-owned, controlled subsidiaries. When we do not have the ability to exert significant influence, the cost method is used. Undivided interests in oil and gas joint ventures, pipelines, processing facilities, and certain other assets are consolidated on a proportionate basis.

Contingencies. Certain conditions may exist as of the date our consolidated financial statements are issued, which may result in a loss to us, but which will only be resolved when one or more future events occurs or fails to occur. Our management and legal counsel assess such contingent liabilities, and such assessment inherently involves an exercise in judgment.

In assessing loss contingencies related to legal or regulatory matters that are pending against us or unasserted claims that may result in such proceedings, our management, and legal counsel evaluate the perceived merits of any legal proceedings or unasserted claims as well as the perceived merits of the amount of relief sought or expected to be sought therein. If the assessment of a contingency indicates that it is probable that a material loss has been incurred and the amount of liability can be estimated, then the estimated liability would be accrued in our consolidated financial statements. If the assessment indicates that a potentially material loss contingency is not probable but is reasonably possible, or is probable but cannot be estimated, then the nature of the contingent liability, together with an estimate of the range of possible loss (if determinable and material), is disclosed.

Liabilities for environmental remediation costs arising from claims, assessments, litigation, fines, and penalties and other sources are charged to expense when it is probable that a liability has been incurred and the amount of the assessment and/or remediation can be reasonably estimated. Management believes we are in material compliance with all applicable federal, state, local and foreign laws and regulations associated with our properties.

Loss contingencies considered remote are generally not disclosed unless they involve guarantees, in which case the guarantees would be disclosed.

Derivative Contracts. We recognize derivative contracts at fair value as either assets or liabilities. Changes in fair value are recognized in earnings and included in other income unless designated as a hedging instrument. We have elected not to designate price risk management activities as accounting hedges under applicable accounting guidance. No master netting agreements exist as of December 31, 2022. The related cash flow impact of our derivative activities is reflected as cash flows from operating activities.

Fair Value Measurements. Assets and liabilities required to be measured at fair value are categorized within the fair value hierarchy into one of three different levels depending on the observability of the inputs employed in the measurement. Level 1 inputs are quoted prices in active markets for identical assets or liabilities. Level 2 inputs are observable inputs other than quoted prices included within Level 1 for the asset or liability, either directly or indirectly through market-corroborated inputs. Level 3 inputs are unobservable inputs for the asset or liability reflecting significant modifications to observable related market data or our assumptions about pricing by market participants. Refer to Note 9—Fair Value Measurements for a further discussion.

Financing Costs. Costs incurred in connection with the issuance of debt are capitalized and amortized to interest expense over the term of the related debt. If these costs are associated with a related debt issuance, they are netted against the debt instrument in our consolidated balance sheet.

 

7

QUARTERNORTH ENERGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

 

General and Administrative Expense. General and administrative expenses are reported net of recoveries from owners in properties operated by us and net of amounts related to lease operating activities or capitalized pursuant to the full cost method of accounting. We capitalized general and administrative expenses of $22.1 million for the year ended December 31, 2022.

Income Taxes. We use the liability method of accounting for income taxes in accordance with the Income Taxes Topic of the Accounting Standards Codification. Under this method, deferred tax assets and liabilities are determined by applying tax rates in effect at the end of a reporting period to the cumulative temporary differences between the tax bases of assets and liabilities and their reported amounts in the financial statements.

The effects of changes in tax rates and laws on deferred tax balances are recognized in the period in which the new legislation is enacted. In assessing the need for a valuation allowance on our deferred tax assets, we consider whether it is more likely than not that some portion or all of them will not be realized.

We recognize uncertain tax positions in our financial statements when it is more likely than not that we will sustain the benefit taken or expected to be taken. We classify interest and penalties related to uncertain tax positions in income tax expense. See Note 15—Income Taxes for additional information.

Lease Operating Expense. Lease operating expense includes labor, materials and supplies, repairs, maintenance, transportation, allocated overhead costs, ad valorem taxes and other costs incidental to production net to our ownership interests.

Materials and Supplies. We maintain inventories which include costs of materials, supplies, and production equipment to be used in drilling and abandonment operations, carried at net realizable value. During 2022, we incurred a write-down related to materials and supplies of $3.3 million.

Oil and Natural Gas Properties. Oil and Natural gas properties consisted of the following on December 31, 2022:

 

Proved properties

    $ 1,174,296  

Accumulated depreciation, depletion and amortization

      (289,500 ) 
  

 

 

  

Proved properties, net

    $ 884,796  
  

 

 

  

Unproved properties, not subject to amortization

    $ 183,779  
  

 

 

  

We follow the full cost method of accounting for oil and natural gas properties. Under this method, all costs related to the acquisition, exploration, and development of oil and natural gas reserves are capitalized and accumulated in a single cost center representing our activities. Such costs include lease acquisition costs, geological and geophysical expenditures, lease rentals on undeveloped properties, costs of drilling both productive and nonproductive wells, and general and administrative expenses directly related to acquisition, exploration, and development activities, and do not include any costs related to production, general corporate overhead or similar activities.

Under full cost accounting, we may exclude certain unevaluated costs from the amortization base pending determination of whether proved reserves can be assigned to such properties. The costs classified as unevaluated are transferred to the amortization base as the properties are developed, tested and evaluated. At least annually, we test these assets for impairment based on an evaluation of management’s expectations of future pricing, evaluation of lease expiration terms, and planned project development activities. Unevaluated costs of $0.3 million were transferred to the amortization base during 2022.

Oil and natural gas properties included in the amortization base are amortized using the units-of-production method based on production and estimates of proved reserves quantities. In addition to costs associated with evaluated properties and capitalized ARO, the amortization base includes estimated future development costs to be incurred in developing proved reserves as well as estimated plugging and abandonment costs, net of salvage value, related to developing proved reserves. Future development costs related to proved reserves are not recorded as liabilities on the balance sheet, but are part of the calculation of depletion expense.

 

8

QUARTERNORTH ENERGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

 

Our capitalized costs are limited to a ceiling based on the present value of future net revenues from proved reserves, computed using a discount factor of 10 percent, plus the lower of cost or estimated fair value of unproved oil and natural gas properties not being amortized less the related tax effects. Any costs over the ceiling are recognized as a non-cash impairment expense in our consolidated statement of operations and an increase to accumulated depreciation, depletion, and amortization on our consolidated balance sheet. The expense may not be reversed in future periods, even though higher crude oil, natural gas and natural gas liquids prices may subsequently increase the ceiling. We perform this ceiling test calculation each quarter.

We utilize SEC pricing when performing the ceiling test. We also hold prices and costs constant over the life of the reserves, even though actual prices and costs of oil and natural gas are often volatile and may change from period to period. We did not record a ceiling test impairment during 2022.

Other income. Other income includes income unrelated to primary oil and gas activities, and other one-time income generated during the year, including income from litigation and litigation related activities.

Other Property and Equipment. Other property and equipment consisted of the following on December 31, 2022:

 

Other property and equipment

    $ 3,726  

Accumulated depreciation

      (2,513 ) 
  

 

 

  

Other property and equipment, net

    $ 1,213  
  

 

 

  

Other property and equipment, which consists primarily of office furniture, equipment, computers and computer software, is stated at cost. Also included in this category are several sets of equipment for plugging and abandoning oil and gas wells. Depreciation on other property and equipment is calculated on the straight-line method over the estimated useful lives of the assets, which range from three to five years.

Other Revenue. The following table presents other revenue information for the year ended December 31, 2022:

 

Production handling/pipeline transportation

    $ 18,292  

Other

      4,495  
  

 

 

  
   $ 22,787  
  

 

 

  

We provide services related to certain production handling arrangements and pipeline transportation contracts. For the majority of these contracts, we promise to perform a series of distinct integrated services over a period of time, which is a single performance obligation, and the transaction price includes fixed or variable consideration, or a combination of both. The amount of consideration is determinable at contract inception or at each month’s end based on the value of services provided to the customer in that month. Revenue is recognized over the service period specified in the contract as the services are rendered using a time-based (passage of time) or units-based (units of service transferred) method for measuring progress towards satisfaction of the performance obligation. Payment is generally received from the customer in the month of service or the month following the service. Contracts with customers generally are a combination of month-to-month and multi-year agreements.

We have entered into agreements to plug, abandon, decommission and remove certain third-party assets in the GOM. These services are performed under turnkey arrangements where the transaction price is fixed but, subject to the specific contract, potentially subject to change for certain qualified conditions and adjustment to the overall cost environment at least annually. Revenue is recognized when the Company satisfies the performance obligation at a point in time.

Revenue Recognition. We recognize revenue from the sale of oil, natural gas, and natural gas liquids when our performance obligations are satisfied. Our contracts with customers are primarily short-term (within a year). Our responsibilities to deliver a unit of crude oil, natural gas liquids, and natural gas under these contracts represent separate, distinct performance obligations. These performance obligations are satisfied at the point in time control of each unit is transferred to the customer. Pricing is primarily determined utilizing a particular pricing or market index, plus or minus adjustments reflecting quality or location differentials.

 

9

QUARTERNORTH ENERGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

 

We record oil and natural gas revenues based upon physical deliveries to our customers, which can be different from our net revenue ownership interest of production. These differences create imbalances that we recognize as a liability only when the estimated remaining recoverable reserves of a property will not be sufficient to enable the under-produced party to recoup its entitled share through production. We do not record receivables for those properties in which we have taken less than our ownership share of production.

 

10

QUARTERNORTH ENERGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

 

Note 2— Supplemental Disclosures to the Balance Sheet and the Statement of Cash Flows

The following tables show additional balance sheet information as of December 31, 2022.

 

Accounts receivable

   

Operating revenues

    $ 61,954  

Joint interest receivables, net

      62,461  

Other

      19,645  
  

 

 

  
   $ 144,060  
  

 

 

  

Other current assets

   

Prepaids and other

    $ 11,011  

Decommissioning work-in-progress

      27,467  
  

 

 

  
   $ 38,478  
  

 

 

  

Other assets

   

Right-of-use asset

    $ 5,967  

Other

      1,148  
  

 

 

  
   $ 7,115  
  

 

 

  

Accrued liabilities

   

Production expense

    $ 22,484  

Capital/Decommissioning

      50,219  

Owner advances

      21,050  

Accrued royalties

      11,051  

Accrued interest

      125  

Other

      28,439  
  

 

 

  
   $ 133,368  
  

 

 

  

Other current liabilities

   

Compressor lease

    $ 1,327  

Lease obligation

      966  

Plug and abandonment obligation

      4,038  

Other

      10,666  
  

 

 

  
   $ 16,997  
  

 

 

  

Other long-term liabilities

   

Compressor lease

    $ 1,378  

Lease obligation

      4,501  

Other

      1,067  
  

 

 

  
   $ 6,946  
  

 

 

  

Supplemental Cash Flow Information

Supplemental disclosures to the statement of cash flows for the year ended December 31, 2022 are presented below.

 

Supplemental disclosures of cash payments (receipts):

   

Interest paid, net of amounts capitalized

    $ 26,135  

Income taxes paid

      9,169  

Noncash investing and financing activities:

   

Credit Bid Acquisition

   

Assumption of net working capital liability

      34,892  

Transfer of note receivable as consideration

      (17,164 ) 

Note 3—Credit Bid Acquisition

On August 27, 2021 (“Effective Date”, or “Acquisition Date”), we acquired from Fieldwood certain GOM oil and natural gas properties, pursuant to a purchase and sale agreement.

 

11

QUARTERNORTH ENERGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

 

Purchase Price Allocation

We have accounted for the Credit Bid Acquisition as a business combination, using the acquisition method. The following table represents the final allocation of the total purchase price to the identifiable assets acquired and the liabilities assumed based on the fair values as of the Acquisition Date, including measurement period adjustments made during 2022. Those adjustments comprise:

 

  •  

a $20.0 million upward revision to materials and supplies, reflecting new information about the fair value of items acquired from Fieldwood;

 

  •  

a $34.9 million upward revision to the net working capital liability assumed, reflecting updated information regarding certain pre-acquisition contingencies of Fieldwood;

 

  •  

a $2.2 million downward revision to our investment in Fieldwood Mexico to reflect the final accounting for that transaction, and

 

  •  

a $17.2 million downward revision to the credit bid amount (a component of the purchase price).

The allocation of the purchase price for this acquisition, for the dates indicated below, is as follows:

 

     December 31,
2021		      Measurement
period
adjustments		      August 27,
2022		  

Consideration:

         

Cash

    $ 12,171      $ —          $ 12,171  

Net working capital liability assumed(1)

      2,072        34,892        36,964  

Debt assumed

      118,599        —          118,599  

Credit bid amount

      747,278        (17,164 )       730,114  

Warrants, at fair value

      208,478        —          208,478  
  

 

 

     

 

 

     

 

 

  
   $ 1,088,598      $ 17,728      $ 1,106,326  
  

 

 

     

 

 

     

 

 

  

Fair Value of Assets Acquired:

         

Oil and natural gas properties(2)

    $ 1,213,146      $ —        $ 1,213,146  

Investment in Fieldwood Mexico

      53,925        (2,234 )       51,691  

Materials and supplies (1)

      26,931        19,962        46,893  

Other assets

      3,657        —          3,657  
  

 

 

     

 

 

     

 

 

  
   $ 1,297,659      $ 17,728      $ 1,315,387  
  

 

 

     

 

 

     

 

 

  

Fair Value of Liabilities Assumed:

         

Commodity derivatives

    $ 16,408      $ —        $ 16,408  

Asset retirement obligations

      192,653        —          192,653  
  

 

 

     

 

 

     

 

 

  
   $ 209,061      $ —        $ 209,061  
  

 

 

     

 

 

     

 

 

  

Total identifiable net assets

    $ 1,088,598      $ 17,728      $ 1,106,326  
  

 

 

     

 

 

     

 

 

  

 

(1)

In accordance with the PSA, certain of Fieldwood’s working capital assets and liabilities were assumed by QuarterNorth on the closing date, with subsequent adjustments to fair value reflected as adjustments to the purchase price consideration.

(2)

In estimating the fair value of the oil and natural gas properties, the Company used an income approach, which incorporated the estimated reserve cash flows, risked by reserve category and discounted using a weighted average cost of capital rate of 12%. Oil and natural gas pricing was derived from NYMEX future prices and research analysts’ estimated pricing. This estimation includes the use of unobservable inputs, such as estimated future production, oil and natural gas revenues and expenses. The use of these unobservable inputs results in the fair value estimate being classified as Level 3.

Note 4—Leases

We primarily lease office spaces, production equipment, and other facilities and equipment. At inception, contracts are reviewed to determine whether the agreement contains a lease. A contract is considered a lease when the arrangement either explicitly or implicitly conveys the right to control the use of the identified property, plant or equipment for a period of time in exchange for consideration. In order to obtain control, we must obtain substantially all of the economic benefits for the use of the identified asset and have the right to direct the use of the identified asset. Leases are evaluated for classification as operating or finance leases at the commencement date of

 

12

QUARTERNORTH ENERGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

 

the lease and right-of-use assets and corresponding liabilities are recognized on our consolidated balance sheet based on the present value of future lease payments relating to the use of the underlying asset during the lease term. The discount rate used to determine present value is the rate implicit in the lease unless the rate cannot be determined, in which case an incremental borrowing rate is used. The incremental borrowing rate reflects the estimated rate of interest we would incur over a similar term for an amount equal to the lease payments on a collateralized basis in a similar economic environment.

We have elected to account for lease and non-lease components in our contracts as a single lease component for all asset classes. Lease agreements may include options to renew the lease, terminate the lease or purchase the underlying asset. We determine the lease term at the lease commencement date as the non-cancelable period of the lease, including options to extend or terminate the lease when such an option is reasonably certain to be exercised. Factors we use to assess the reasonable certainty of rights to extend or terminate a lease include current and forecasted drillings plans, anticipated changes in development strategies, historical practice in extending similar contracts and current market conditions. We have elected to not apply the recognition requirements of Topic 842 to leases with durations of twelve months or less (i.e. short-term).

Lease Balances

The following table summarizes the present value of the fixed lease payments recorded as right-of-use assets and liabilities, including the balance sheet presentation, as of December 31, 2022.

 

Operating leases:

   

Other assets

    $ 5,194  

Other current liabilities

      918  

Other long-term liabilities

      3,664  
  

 

 

  

Total operating lease liabilities

    $ 4,582  
  

 

 

  

Financing lease :

   

Other assets

    $ 773  

Other current liabilities

      48  

Other long-term liabilities

      837  
  

 

 

  

Total financing leas liabilities

    $ 885  
  

 

 

  

Lease Costs

The following table presents the components of lease costs incurred during the year ended December 31, 2022. The amounts shown are gross and have not been adjusted to reflect amounts recovered or reimbursed from other working interest owners.

 

Operating lease cost

    $ 2,310  

Financing lease cost

   

Interest on lease liabilities

      176  

Amortization of right-of-use assets

      216  

Short-term lease cost

      355  
  

 

 

  

Total lease cost

    $ 3,057  
  

 

 

  

Minimum Future Commitments

The following table shows our minimum future commitments related to leases as of December 31, 2022, on an undiscounted basis with a reconciliation to the discounted present value recognized on our consolidated balance sheet.

 

     Operating
Leases		      Financing
Leases		  

2023

    $ 960      $ 119  

2024

      859        119  

2025

      657        119  

2026

      612        119  

2027

      612        119  

Thereafter

      2,612        773  
  

 

 

     

 

 

  

Total lease payments

      6,312        1,368  

Imputed interest

      (1,730 )       (483 ) 
  

 

 

     

 

 

  

Total

    $ 4,582      $ 885  
  

 

 

     

 

 

  

 

13

QUARTERNORTH ENERGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

 

Lease Terms and Discount Rate

The following table presents the weighted average remaining lease terms and weighted average discount rate as of December 31, 2022.

 

Weighted average remaining lease term:

   

Operating leases

      4.1 years  

Financing leases

      11.5 years  

Weighted average discount rate:

   

Operating leases

      8.31 % 

Financing leases

      8.31 % 

Supplemental Cash Flow Information

The following table presents supplemental cash flow information related to our leases for the year ended December 31, 2022.

 

Operating cash outflow from financing leases

    $ 179  

Financing cash outflow from financing leases

      168  

Operating cash outflow from financing leases

      1,772  

Note 5—Debt

We had the following debt outstanding as of December 31, 2022:

 

First Lien Term Loan, variable rate, due 2023

    $ 1,000  

Second Lien Term Loan, variable rate, due 2026

      185,000  

Less: unamortized discount

      (2,705 ) 

Less: unamortized debt issuance costs

      (1,356 ) 
  

 

 

  

Total debt, net

      181,939  

Less current portion

      (1,000 ) 
  

 

 

  

Total long-term debt, net

    $ 180,939  
  

 

 

  

First Lien Term Loan. On August 27, 2021, QuarterNorth Energy Holding Inc., as borrower, and its parent entity and subsidiaries, as guarantors, entered into the Third Amended and Restated First Lien Term Loan Agreement (“FLTL”), with lenders party thereto and Goldman Sachs Bank USA, as administrative agent and collateral agent for the lenders. The initial aggregate principal amount of loans outstanding under the agreement totaled $118.6 million.

As amended in 2022, borrowings under the FLTL bear interest at either an alternative base rate (ABR) plus an applicable margin with a 2% ABR floor or Secured Overnight Financing Rate (“SOFR”) plus an applicable margin with a 1.00% SOFR floor. Interest payments are due each quarter, and the maturity date of the loan is December 31, 2023.

Obligations under the FLTL are secured by liens on substantially all of our assets. The FLTL requires ongoing compliance with customary affirmative and negative covenants.

 

14

QUARTERNORTH ENERGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

 

The FLTL loan was amended on March 22, 2022 and December 23, 2022, as follows:

 

  •  

we paid $74 million in principal;

 

  •  

LIBOR and LIBOR loans were removed from the agreement and replaced with SOFR and SOFR loans;

 

  •  

the applicable margin definition was amended to mean 4.5% for ABR loans and 5.5% for SOFR loans;

 

  •  

the maturity was changed to December 31, 2023 and all future required principal payments were removed;

 

  •  

certain information covenants were amended and the requirement to prepare a budget for the year ended December 31, 2023 was removed;

 

  •  

all minimum hedge requirements were removed;

 

  •  

the restricted payments basket was increased from $1.0 million to $20 million.

Second Lien Term Loan. On August 27, 2021, QuarterNorth Energy Holding Inc., as borrower, and its parent entity and subsidiaries, as guarantors, entered into the Second Lien Term Loan Agreement (“SLTL”), with lenders party thereto and Cantor Fitzgerald Securities, as administrative agent and collateral agent for the lenders. The maturity of the SLTL is August 27, 2026.

On August 27, 2021, the Company borrowed $185 million under the SLTL. Cash proceeds received were $180.4 million, equal to the borrowing amount less an issue discount of $3.7 million and fees of $0.9 million.

Borrowings under the SLTL bear interest at either an ABR plus an applicable margin of 7.00% or LIBOR plus an applicable margin of 8.00%. The Company may, at its sole discretion, elect to pay interest-in-kind (“PIK”), by delivering a PIK notice to the lenders during any PIK election trigger period. The PIK election trigger period is a period in which the borrower and its restricted subsidiaries have less than $75.0 million as of the end of the most recently ended fiscal quarter. Obligations under the SLTL are secured by second liens on substantially all of our assets. The SLTL requires ongoing compliance with affirmative and negative covenants.

QuarterNorth has the right at any time and from time to time to prepay the SLTL in whole or in part, without premium or penalty, in an aggregate principal amount that is an integral multiple of $0.5 million and not less than $1.0 million.

Affirmative covenants include, among others, requirements of QuarterNorth relating to: (i) minimum hedging requirements; (ii) the preservation of existence; (iii) the payment of obligations, including taxes; (iv) the maintenance of insurance and books and records; (v) the compliance with laws and material contracts; (vi) compliance with environmental law (vii) use of proceeds; (viii) notice of certain material events; and (ix) certain periodic reporting requirements.

Negative covenants include, among others, restrictions on QuarterNorth’s and its subsidiary guarantors’ ability to, subject in each case to certain exceptions and baskets: (i) create, incur, assume or suffer to exist indebtedness; (ii) create or permit to exist liens on their properties; (iii) merge with or into another person, liquidate or dissolve; (iv) make asset sales; (v) pay cash dividends or other restricted payments; and (vi) enter into transactions with affiliates.

Further, negative covenants in the SLTL restrict QuarterNorth’s ability to engage in business activities other than those, among other things, related to the ownership of interest in QuarterNorth, performing our obligations under other indebtedness documents and receiving restricted payments. On March 22, 2022, the SLTL was amended which, among other things, required the Company to make the restricted payment baskets consistent with the FLTL, as amended.

As of December 31, 2022, QuarterNorth was in compliance with all covenants under its debt agreements.

Subsequent event

On February 14, 2023, the SLTL was amended which modified the requirement to prepare a budget for the year ended December 31, 2023.

 

15

QUARTERNORTH ENERGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

 

Note 6—Asset Retirement Obligations

The following table summarizes the activity for our asset retirement obligations for the year ended December 31, 2022.

 

Beginning balance

    $ 193,514  

Liabilities incurred or assumed through acquisition

      1,328  

Liabilities divested

      (21,771 ) 

Liabilities settled

      (24,642 ) 

Accretion expense

      15,835  

Revisions to previous estimates

      (31,084 ) 
  

 

 

  
   $ 133,180  
  

 

 

  

Current portion

    $ 4,048  

Long-term portion

      129,132  
  

 

 

  
   $ 133,180  
  

 

 

  

Note 7—Risk Management Activities

Our principal market risks are our exposure to changes in commodity prices, particularly to the prices of crude oil and natural gas, and nonperformance by our counterparties.

Our revenues are derived principally from the sale of crude oil and natural gas. The prices of crude oil and natural gas are subject to market fluctuations in response to changes in supply, demand, market uncertainty and a variety of additional factors beyond our control. We monitor these risks and enter into commodity derivative contracts to secure a commodity price for a portion of our expected future production that is acceptable at the time of the transaction. We do not enter into derivative contracts for speculative purposes.

The counterparties to our derivative contracts include financial institutions. Our derivative contracts expose us to market and credit risks, and which may, at times, be concentrated with certain counterparties or groups of counterparties. The credit worthiness of our counterparties is subject to continual review. We monitor the nonperformance risk of ourselves and of each of our counterparties and assesses the possibility of whether each counterparty to the derivative contract would default by failing to make any contractually required payments as scheduled in the derivative instrument in determining the fair value.

Our commodity derivative contracts may include, but are not limited to, “swap”, “collar” and “put” positions. Commodity derivative contracts outstanding as of December 31, 2022 are shown below:

 

Crude Oil (WTI Index)

  
     Swaps      Puts      Collars      Participating Swaps  

Period

    Volume
(MBbls)		      Average
$/Bbl		      Volume
(MBbls)		      Average
$/Bbl		      Volume
(MBbls)		      Floor
$/Bbl		      Ceiling
$/Bbl		      Volume
(Bbl/d)		      Swap
$/Bbl		      Call
$/Bbl		  

1st Qtr 2023

      344      $ 60.42        2,000      $ 100.00        4,156      $ 60.00      $ 76.70        3,000      $ 73.23      $ 90.00  

2nd Qtr 2023

      3,800        64.54        2,000        100.00        —          —          —          3,000        73.23        90.00  

3rd Qtr 2022

      —          —          2,000        100.00        —          —          —          —          —          —    

4th Qtr 2023

      —          —          2,000        100.00        —          —          —          —          —          —    

 

Natural Gas (Henry Hub Index)

  
     Puts      Swaps  

Period

    Volume
(MMbtu/d)		      Average
$/MMbtu		      Volume
(MMbtu/d)		      Average
$/MMbtu		  

1st Qtr 2023

      7,000      $ 2.75        15,000      $ 8.80  

2nd Qtr 2023

      5,600        2.50        —          —    

With swaps, we receive an agreed upon fixed price for a specified notional quantity of oil or natural gas and we pay the counterparty a floating price for that same quantity based upon published index prices. Index pricing used is based on grades that we believe best represent the revenue we receive for our underlying physical production. Our swap contracts provide us with protection if market prices decline below the contracted price. If market prices rise above the contracted prices, we will receive less revenue than in the absence of swaps.

Collars contain a fixed floor price and a fixed ceiling price. If the published index price exceeds the ceiling price or falls below the floor price, we receive the fixed price and pay the index price. If the index price is between the floor and ceiling prices, no payments are due from either party.

 

16

QUARTERNORTH ENERGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

 

A put option gives the owner the right, but not the obligation, to sell the underlying commodity at a specified price (strike price) within a specific time period. Depending on market conditions, strike prices, and the value of the contracts, we may, at times, purchase put options, which require us to pay premiums. The premiums may be paid when the option is purchased, or deferred until each monthly settlement occurs. The ownership of put options is consistent with our derivative strategy inasmuch as the value of the puts will increase as commodity prices decline, helping to offset the cash flow impact of a decline in realized prices for the underlying commodity. However, if the underlying commodity increases in value, there is a risk that the put option will expire worthless, in which case the net premiums paid would be recognized as a loss.

The following reflects the fair values of our derivative contracts, including the fair value of option premiums, and the line items where they appear on our consolidated balance sheet:

 

     Balance Sheet
Location		    December 31,
2022		  

Commodity derivatives

    Current assets    $ 8,440  
     

 

 

  
   Total    $ 8,440  
     

 

 

  

 

     Balance Sheet
Location		    December 31,
2022		  

Commodity derivatives

    Current liabilities    $ 8,156  
     

 

 

  
   Total    $ 8,156  
     

 

 

  

The following reflects the effect of netting agreements with counterparties on the balance sheet presentation of our derivative contracts:

 

Assets:

   

Current

    $ 12,503  

Noncurrent

      —    
  

 

 

  

Total gross fair value

      12,503  

Less: counterparty offset

      (4,063 ) 
  

 

 

  

Total net fair value

    $ 8,440  
  

 

 

  

Liabilities:

   

Current

    $ 12,219  

Noncurrent

      —    
  

 

 

  

Total gross fair value

      12,219  

Less: counterparty offset

      (4,063 ) 
  

 

 

  

Total net fair value

    $ 8,156  
  

 

 

  

See Note 9—Fair Value Measurements for additional disclosures related to derivative contracts.

Note 8—Stockholders’ Equity

On August 27, 2021, in conjunction with the Credit Bid Acquisition, the Company issued the following equity instruments:

Common Stock.

Certain holders of Fieldwood’s debt contributed a portion of their holdings to the Company in exchange for 5,000,000 shares of our common stock. The contributed debt constituted the credit-bid portion of the Credit Bid Acquisition consideration.

The Company issued to certain of Fieldwood’s creditors stock subscription rights to acquire $40 million of our common stock. In total, 720,305 shares were issued, in exchange for $40 million in cash.

An ad hoc group of Fieldwood’s creditors agreed to provide backstop coverage to a portion of the $40 million subscription rights offering in exchange for a backstop fee payable in shares of the Company. The backstop fee was paid with our issuance of 324,192 shares of our common stock.

 

17

QUARTERNORTH ENERGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

 

Stock Warrants

In conjunction with the Credit Bid acquisition, the Company issued stock warrants that provide the holder with the right to purchase shares of our common stock. The warrants were valued using a Black-Scholes-Merton option pricing model to derive a relative fair value and are not subject to subsequent remeasurement. The warrants have been classified as equity and are recognized within additional paid-in capital in our consolidated balance sheet. The following table summarizes the warrants issued:

 

Description

    Shares      Term    Exercise
Price		  

GUC Warrants

      389,330      8 years    $ 166.09  

SLTL Tranche 1 Warrants

      2,780,926      8 years      166.09  

SLTL Tranche 2 Warrants

      5,355,857      8 years      189.42  

New Money Warrants

      1,908,828      7 years      0.01  

As of December 31, 2022, the holders of the New Money Warrants had exercised 1,496,316 warrants with an exercise price of $0.01.

Common Stock Dividend

On March 22, 2022, the Company declared a dividend of $3.7720 (subject to rounding) per outstanding share of common stock and underlying share of common stock represented by the New Money Warrants. The dividend was payable to the stockholders of the Company and to the holders of New Money Warrants of record at the close of business on March 29, 2022, which totaled 7,953,325 equivalent shares. The total dividend of $30 million was paid on April 12, 2022.

On August 2, 2022, the Company declared a dividend of $3.0987 (subject to rounding) per outstanding share of common stock, New Money Warrant, and time-based RSUs outstanding. The dividend was payable to the stockholders of the Company and to the holders of New Money Warrants of record at the close of business on August 31, 2022, which totaled 7,953,325 equivalent shares. The total dividend of $25 million was paid on September 21, 2022, with approximately $24.6 million being paid to holders of common stock and New Money Warrants and approximately $0.4 million paid on RSUs.

On December 8, 2022, the Company declared a dividend of $3.0991 (subject to rounding) per outstanding share of common stock, New Money Warrant, and time-based RSUs outstanding. The dividend was payable to the stockholders of the Company and to the holders of New Money Warrants of record at the close of business on December 15, 2022, which totaled 7,953,325 equivalent shares. The total dividend of $25 million was paid on December 23, 2022, with approximately $24.6 million being paid to holders of common stock and New Money Warrants and approximately $0.4 million paid on RSUs.

The payment of dividends related to time-based RSUs are deferred until the time-based RSUs vest. The time-based RSU dividend units are paid to and are held in a separate account until vesting of these units occurs.

Note 9—Fair Value Measurements

Derivative Contracts

Our commodity derivative contracts are presented in our consolidated financial statements at fair value. These contracts consist of over-the-counter transactions, which are not traded on a public exchange.

The fair values of our commodity derivative contracts are determined based on inputs that are readily available in public markets or can be derived from information available in publicly quoted markets. Therefore, we have categorized these contracts as Level 2.

We have consistently applied these valuation techniques and believe we have obtained the most accurate information available for the types of derivative contracts we hold.

 

18

QUARTERNORTH ENERGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

 

The following table sets forth, by level within the fair value hierarchy, our derivative assets and liabilities measured at fair value on a recurring basis as of December 31, 2022:

 

     Total      Level 1      Level 2      Level 3  

Assets

            

Commodity derivative contracts

    $ 8,440      $ —        $ 8,440      $ —    
  

 

 

     

 

 

     

 

 

     

 

 

  
   $ 8,440      $ —        $ 8,440      $ —    
  

 

 

     

 

 

     

 

 

     

 

 

  

Liabilities

            

Commodity derivative contracts

    $ 8,156      $ —        $ 8,156      $ —    
  

 

 

     

 

 

     

 

 

     

 

 

  
   $ 8,156      $ —        $ 8,156      $ —    
  

 

 

     

 

 

     

 

 

     

 

 

  

These derivative assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of the fair value assets and liabilities and their placement within the fair value hierarchy levels.

Business Combination

On August 27, 2021, we acquired certain oil and natural gas properties from Fieldwood, and recorded the assets acquired and liabilities assumed at their acquisition date fair values. See Note 3—Credit Bid Acquisition, for a discussion of the fair value approaches used by the Company and the classification of the estimates within the fair value hierarchy.

Debt

We use a market approach to determine the fair value of our debt using estimates provided by an independent financial data services firm (a Level 2 fair value measurement). The carrying amount and fair value of our debt as of December 31, 2022 is shown in the following table.

 

     Carrying
Amount		      Fair
Value		  

First Lien Term Loan

    $ 1,000      $ 1,000  

Second Lien Term Loan

      180,939        185,000  
  

 

 

     

 

 

  
   $ 181,939      $ 186,000  
  

 

 

     

 

 

  

We believe the carrying values of cash, accounts receivable, accounts payable, and accrued liabilities included in the accompanying consolidated balance sheet approximate their fair value as of December 31, 2022.

Asset Retirement Obligations

We follow the provisions of ASC 820, for nonfinancial assets and liabilities measured at fair value on a non-recurring basis. These provisions apply to the Company’s initial recognition of asset retirement obligations for which fair value is used. The asset retirement obligation estimates are derived from historical costs and management’s expectation of future cost environments; and therefore, the Company has designated these liabilities as Level 3. See Note 6—Asset Retirement Obligations for a reconciliation of the beginning and ending balances of the Company’s asset retirement obligations.

Note 10—Employee Benefits

We sponsor a qualified 401(k) Plan that provides for matching of up to 100% of the first 6% of employee contributions. Employees are immediately 100% vested in their contributions and our matching contributions. Our matching contributions were $2.3 million for the year ended December 31, 2022.

Note 11—Share-Based Compensation

On April 1, 2022, our board of directors adopted (“the Adoption date”) the QuarterNorth Energy Inc. Equity Incentive Plan (the “Incentive Plan”). The Incentive Plan provides for the grant of stock-based awards to any officer, employee, director, independent contractor, or consultant of the Company or a subsidiary of the Company. A total of 621,689 shares of our common stock have been reserved for issuance through awards under the Incentive Plan. Under certain circumstances to protect against dilution of awards, the administrator of the Incentive Plan may adjust the number of underlying shares with respect to any award.

 

19

QUARTERNORTH ENERGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

 

The Company awarded restricted stock units (RSUs) that are time-based awards (“time-based RSUs”) and performance-based restricted stock units (“performance-based RSUs”) that vest at a percentage (i.e., 0%—100%) based upon certain threshold target levels of proceeds received in connection with a liquidity event.

The time-based RSUs are subject to a three-year vesting requirement. The vesting commencement date is the latter of August 27, 2021 or commencement of employment. If there is an event that results in a change of control of the Company during the vesting period, the time-based RSU vesting will accelerate and occur when that event occurs. The time-based RSUs will expire if a liquidity event has not occurred prior to the seventh anniversary of the grant date. Both time-based RSUs and performance-based RSUs settle upon the occurrence of a liquidity event. As a result of the liquidity event vesting requirement, no compensation cost will be recognized until it is deemed probable that a liquidity event will occur.

The grant date fair value of both the time-based RSUs and performance-based RSUs were determined by a third party valuation expert who used a bottoms-up strategy, utilizing the economic conditions present on the Adoption date, as well as, the projected operating environment of the Company.

The following summarizes the Company’s activity for the year ended December 31, 2022:

 

     Time-based
RSUs		      Weighted-
Average
Grant Date
Fair Value		      Performance -
based RSUs		      Weighted-
Average
Grant Date
Fair Value		  

Non-vested, beginning of period

      —          —          —          —    

Granted

      115,140      $ 85.05        389,028      $ 50.52  

Forfeited

      (7,204 )     $ 85.05        (26,568 )     $ 50.52  

Issued

      —          —          —          —    
  

 

 

        

 

 

     

Non-vested, end of period

      107,936      $ 85.05        362,460      $ 50.52  
  

 

 

        

 

 

     

At December 31, 2022, the unrecognized compensation cost from unvested time-based RSUs and performance-based RSUs was indeterminable.

If an employee leaves the Company for “good reason” or is terminated without “cause”, both as defined in the Incentive Plan, any unvested awards are forfeited. If an employee is terminated for “cause” all awards are forfeited. Any share that is not issuable because the related award is forfeited, canceled, or expires without being exercised or otherwise terminates without payment or issuance of shares shall again be available for grant pursuant to an award under the Incentive Plan.

Note 12—Related Party Transactions

During 2022, we had agreements to provide technical, operational, engineering, procurement, construction and installation services, management and administrative services to Fieldwood Mexico. Fees pursuant to these agreements were $2.2 million for the year ended December 31, 2022. They have been recognized in the financial statements as reductions of general and administrative expense.

We will no longer receive recoveries from services provided to Fieldwood Mexico as these contracts were terminated at the time of our sale of Fieldwood Mexico. See Note 14—Assets Held for Sale for more information.

Note 13—Commitments and Contingencies

Legal Proceedings. From time to time, we may be involved in litigation arising out of the normal course of our business. We maintain insurance coverage applicable to certain litigation, which, subject to applicable deductibles, may reduce our actual liability under any litigation. In management’s opinion, we are not involved in any litigation, the outcome of which would have a material effect on our consolidated financial position, results of operations, or liquidity.

 

20

QUARTERNORTH ENERGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

 

Note 14—Assets Held for Sale

As part of the Credit Bid Acquisition, we acquired Fieldwood’s investment in Fieldwood Mexico, B.V. (“Fieldwood Mexico”). Prior to the Credit Bid Acquisition, Fieldwood entered into a purchase and sale agreement to sell its investment to a subsidiary of PJSC Lukoil Oil Company (“Lukoil”), pending the Mexican government’s approval of the transaction.

During the first quarter of 2022, the Company completed its sale of the Fieldwood Mexico investment. We received $55.7 million at closing.

Note 15—Income Taxes

Components of income tax expense for the year ended December 31, 2022 are as follows:

 

Current:

   

Federal

    $ 13,254  

State

      1,393  
  

 

 

  

Total current income tax expense

      14,647  
  

 

 

  

Deferred:

   

Federal

      60,433  

State

      2,838  
  

 

 

  

Total deferred income tax expense

      63,271  
  

 

 

  

Total income tax expense

    $ 77,918  
  

 

 

  

Our reconciliation of income taxes computed at the U.S. federal statutory tax rate to our income tax expense is as follows:

 

Income before income taxes

    $ 351,356  
  

 

 

  

Income tax expense at the federal statutory rate

    $ 73,785  

Increases resulting from:

   

State tax expense

      3,978  

Permanent items

      15  

Other

      140  
  

 

 

  

Income tax expense

    $ 77,918  
  

 

 

  

Effective income tax rate

      22.2 % 

Deferred income taxes reflect the net tax effects of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax purposes. Significant components of our deferred tax assets and liabilities as of December 31, 2022 are:

 

Deferred tax assets:

   

Asset retirement obligations

    $ 29,313  

Leases

      1,203  

Other

      585  
  

 

 

  
     31,101  
  

 

 

  

Deferred tax liabilities:

   

Property and equipment, net

      94,244  

Derivative contracts

      63  

Accruals

      1,865  

Leases

      1,313  

Other property and equipment, net

      267  
  

 

 

  
     97,752  
  

 

 

  

Net deferred tax liability

    $ (66,651 ) 
  

 

 

  

Accounting for uncertainty in income taxes prescribes a recognition threshold and measurement methodology for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. As of December 31, 2022, we had no unrecognized tax benefits.

 

21

QUARTERNORTH ENERGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

 

We file income tax returns in the U.S. federal jurisdiction and in Louisiana and Texas. Tax years that remain subject to examination include 2021.

Any net operating loss carryforwards (“NOLs”) generated can be carried forward indefinitely.

Note 16—Significant Risks and Uncertainties

Oil and Natural Gas Prices

The price that we receive for our oil and natural gas production affects our revenue, profitability, liquidity, access to capital and future growth rate. Historically, the oil and natural gas markets have been volatile and will likely continue to be volatile in the future. Oil and natural gas prices depend on numerous factors, all of which are beyond our control. These factors include, but are not limited to, the following:

 

  •  

changes in supply and demand for oil and natural gas;

 

  •  

actions by the Organization of Petroleum Exporting Countries and other state-controlled oil companies;

 

  •  

the price and quantity of imports of foreign oil and natural gas;

 

  •  

speculation as to the future price of oil and the speculative trading of oil futures contracts;

 

  •  

global economic conditions, including the strength of the U.S. dollar;

 

  •  

the level of global oil and natural gas exploration and production activity;

 

  •  

weather conditions and other natural disasters; and

 

  •  

the length and severity of the recent COVID-19 (coronavirus) outbreak, including its impacts on the price and demand for oil and natural gas, and overall global economic activity.

Significant declines in oil and natural gas prices for an extended period may have the following effects on our business:

 

  •  

limiting our financial condition, liquidity, ability to finance our capital expenditures and results of operations;

 

  •  

reducing the amount of oil and natural gas that we can produce economically;

 

  •  

causing us to delay, postpone or terminate our exploration and development activities;

 

  •  

reducing any future revenues, operating income and cash flows;

 

  •  

reducing the carrying value of our crude oil and natural gas properties; or

 

  •  

limiting our access to sources of capital, such as equity and debt.

BOEM Financial Assurances Requirements

The Bureau of Ocean Energy Management (“BOEM”) requires that lessees demonstrate financial strength and reliability according to its regulations or post surety bonds or other acceptable financial assurances that such decommissioning obligations will be satisfied. Presently, we do not have any supplemental bonding requests outstanding.

On July 14, 2016, BOEM issued Notice to Lessees and Operators (“NTL”) 2016-N01 revising supplemental bonding requirements and procedures related to obligations for decommissioning activities on the federal Outer Continental Shelf of the Gulf of Mexico. NTL 2016-N01 would have implemented a phase-in period for establishing compliance with additional security obligations for certain categories of properties covered under NTL 2016-N01, whereby a lessee may seek compliance with its additional security requirements under a tailored plan that is approved by BOEM. On January 6, 2017, BOEM suspended the implementation of NTL 2016-N01 for a six-month period and withdrew all previously issued bonding orders. On June 22, 2017 suspension on the implementation of NTL 2016-N01 was extended beyond the initial six-month period. At this time, a new timeline for finalization has not been determined. Were BOEM to finalize implementation of NTL 2016-N01, or a similar NTL or regulation, this could result in additional demands for surety bonds or other financial assurances.

 

22

QUARTERNORTH ENERGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

 

The availability of surety bonds to the Company as well as the terms, cost and collateral requirements may change subject to market conditions and the surety providers’ evaluation of the creditworthiness of the Company. If we fail to comply with any future orders of BOEM to provide additional surety bonds or other financial assurances, BOEM could commence enforcement proceedings or take other remedial action, including assessing civil penalties, ordering suspension of operations or production, or initiating procedures to cancel leases, which, if upheld, could have a material adverse effect on our business, properties, results of operations and financial condition.

Note 17 – Supplemental Consolidating Financial Information

QuarterNorth Energy Holding Inc. is the borrower under the loans described in Note 5—Debt. The following condensed consolidating financial statements shows the accounts of the parent company, QuarterNorth Energy Inc. on a standalone basis, the accounts of the borrower and its consolidated subsidiaries, and intercompany eliminations to arrive at the consolidated statements of the Company.

QUARTERNORTH ENERGY INC.

CONDENSED CONSOLIDATING BALANCE SHEET

AS OF DECEMBER 31, 2022

(In thousands)

 

     QuarterNorth
Energy Inc.		     QuarterNorth
Energy Holding
Inc.		      Intercompany
Eliminations		     Consolidated  
Assets

 

Current assets:

          

Cash and cash equivalents

    $ —         400,816      $ —       $ 400,816  

Accounts receivable and other assets

      —         297,150        —         297,150  
  

 

 

    

 

 

     

 

 

    

 

 

  

Total current assets

      —         697,966        —         697,966  
  

 

 

    

 

 

     

 

 

    

 

 

  

Property and equipment net

      —         1,069,788        —         1,069,788  

Investments in subsidiaries

      1,184,780       —          (1,184,780 )      —    

Advances to (from) subsidiaries

      (500 )      500        —         —    

Other assets

      111       8,212        (111 )      8,212  
  

 

 

    

 

 

     

 

 

    

 

 

  

Total assets

      1,184,391     $ 1,776,466      $ (1,184,891 )    $ 1,775,966  
  

 

 

    

 

 

     

 

 

    

 

 

  
Liabilities and Stockholders’ Equity

 

Current liabilities

          

Accounts payable and accrued liabilities

    $ —       $ 177,817      $ —       $ 177,817  

Current maturities of debt

      —         1,000        —         1,000  

Other current liabilities

      —         29,201        —         29,201  
  

 

 

    

 

 

     

 

 

    

 

 

  

Total current liabilities

      —         208,018        —         208,018  
  

 

 

    

 

 

     

 

 

    

 

 

  

Long-term debt

      —         180,939        —         180,939  

Asset retirement obligations

      —         129,132        —         129,132  

Other long-term liabilities

      —         73,597        —         73,597  
  

 

 

    

 

 

     

 

 

    

 

 

  

Total liabilities

      —         591,686        —         591,686  
  

 

 

    

 

 

     

 

 

    

 

 

  

Stockholders’ equity

      1,184,391       1,184,780        (1,184,891 )      1,184,280  
  

 

 

    

 

 

     

 

 

    

 

 

  

Total liabilities and stockholders’ equity

    $ 1,184,391     $ 1,776,466      $ (1,184,891 )    $ 1,775,966  
  

 

 

    

 

 

     

 

 

    

 

 

  

 

23

QUARTERNORTH ENERGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

 

QUARTERNORTH ENERGY INC.

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

Year Ended December 31, 2022

(In thousands)

 

     QuarterNorth
Energy Inc.		     QuarterNorth
Energy Holding
Inc.		     Intercompany
Eliminations		     Consolidated  

Revenues

         

Total revenues

    $ —       $ 912,472     $ —       $ 912,472  
  

 

 

    

 

 

    

 

 

    

 

 

  

Operating expenses

         

Lease operating expense

      —         158,603       —         158,603  

Depletion, depreciation and amortization

      —         223,755       —         223,755  

General and administrative expense

      500       19,900       —         20,400  

Other operating expense

      —         99,269       —         99,269  
  

 

 

    

 

 

    

 

 

    

 

 

  

Total operating expense

      500       501,527       —         502,027  
  

 

 

    

 

 

    

 

 

    

 

 

  

Income (loss) from operations

      (500 )      410,945       —         410,445  

Other income (expense), net

         

Equity in earnings of subsidiaries

      273,827       —         (73,827 )      —    

Other

      —         (59,089 )      —         (59,089 ) 
  

 

 

    

 

 

    

 

 

    

 

 

  

Income (loss) before income taxes

      273,327       351,856       (273,827 )      351,356  

Income tax (expense) benefit

      111       (78,029 )      —         (77,918 ) 
  

 

 

    

 

 

    

 

 

    

 

 

  

Net income

    $ 273,438     $ 273,827     $ (273,827 )    $ 273,438  
  

 

 

    

 

 

    

 

 

    

 

 

  

Note 18—Supplemental Information on Oil and Natural Gas Operations (Unaudited)

Oil and Natural Gas Reserves

Proved reserves represent estimated quantities of natural gas, crude oil and condensate and natural gas liquids that geological and engineering data demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs under economic and operating conditions in effect when the estimates were made. Proved developed oil and natural gas reserves are proved reserves that can be expected to be recovered through existing wells and equipment in place and under operating methods being utilized at the time the estimates were made. Users of this information should be aware that the process of estimating quantities of “proved” and “proved developed” oil and natural gas reserves is very complex, requiring significant subjective decisions.

Results of Operations for Oil and Gas Producing Activities

Separate disclosure is not required because our oil- and gas-producing activities represent substantially all of our business activities, and we operate in a single geographic area. See our consolidated statement of operations.

Costs Incurred

The following table reflects the costs incurred in oil and natural gas property acquisition, exploration and development activities for the year ended December 31, 2022. Costs incurred also includes capitalized general and administrative expense, acquired asset retirement obligations, new asset retirement obligations established in the current period, as well as increases or decreases to our asset retirement obligations resulting from changes to cost estimates during the current period.

 

Acquisition costs

   

Proved

    $ (30,086 ) 

Unproved

      507  

Exploration costs

      65,378  

Development costs

      101,920  
  

 

 

  
   $ 137,719  
  

 

 

  

Capitalized Costs

The following table illustrates the total amount of capitalized costs and accumulated depreciation, depletion and amortization relating to our oil and natural gas properties as of December 31, 2022.

 

Proved properties

    $ 1,174,296  

Unproved properties, not being amortized

      183,779  

Accumulated DD&A

      (289,500 ) 
  

 

 

  
   $ 1,068,575  
  

 

 

  

 

24

QUARTERNORTH ENERGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

 

The following table sets forth certain information relative to the amortization of our investment in oil and gas properties and the impairment of our oil and gas properties for the year ended December 31, 2022.

 

Provision for DD&A

    $ 221,800  

Impairment of oil and gas properties

      —    

DD&A per BOE

      21.76  

Proved Reserves

The following information summarizes our net proved reserves of oil (including condensate), natural gas and natural gas liquids as of December 31, 2022. All of our oil and natural gas reserves are located in the U.S. Gulf of Mexico.

 

     Oil
(MBbls)		      Natural
Gas
(MMcf)		      NGL
(MBbls)		      Mboe  

As of December 31, 2021

      42,507        111,155        5,522        66,555  

Acquisitions

      244        363        17        322  

Divestitures

      (1,913 )       (3,274 )       (244 )       (2,703 ) 

Extensions and discoveries

      4,304        8,599        562        6,299  

Revisions of previous estimates

      10,500        7,147        274        11,965  

Production

      (7,559 )       (11,689 )       (686 )       (10,194 ) 
  

 

 

     

 

 

     

 

 

     

 

 

  

Estimated proved reserves

      48,083        112,301        5,445        72,245  
  

 

 

     

 

 

     

 

 

     

 

 

  

Estimated proved developed reserves

            

As of December 31, 2021

      22,732        58,526        2,968        35,454  

As of December 31, 2022

      25,201        55,383        2,700        37,132  

Estimated proved undeveloped reserves

            

As of December 31, 2021

      19,775        52,629        2,554        31,101  

As of December 31, 2022

      22,882        56,918        2,745        35,113  

Management believes the reserve estimates presented herein are reasonable and prepared in accordance with guidelines established by the SEC as prescribed in Regulation S-X, Rule 4-10 as of December 31, 2022. However, there are numerous uncertainties inherent in estimating quantities and values of proved reserves and in projecting future rates of production and the amount and timing of development expenditures, including many factors beyond our control. See Note 16—Significant Risks and Uncertainties for a listing of significant risks and uncertainties. Reserve engineering is a subjective process of estimating the recovery from underground accumulations of oil and natural gas that cannot be measured in an exact manner, and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Because all oil and natural gas reserve estimates are to some degree subjective, the quantities of oil and natural gas that are ultimately recovered, production and operating costs, the amount and timing of future development expenditures and future crude oil and natural gas sales prices may all differ from those assumed in these estimates. In addition, different reserve engineers may make different estimates of reserve quantities and cash flows based upon the same available data.

Therefore, the standardized measure of discounted future net cash flows (Standardized Measure) shown below represents estimates only and should not be construed as the current market value of the estimated reserves attributable to our oil and gas properties. The Standardized Measure has been developed utilizing ASC 932, Extractive Activities – Oil and Gas (ASC 932) procedures and based on oil and natural gas reserve production volumes estimated by the Company’s engineering staff.

The Company believes that the following factors should be taken into account when reviewing the following information:

 

  •  

future costs and selling prices will probably differ from those required to be used in these calculations;

 

  •  

due to future market conditions and governmental regulations, actual rates of production in future years may vary significantly from the rate of production assumed in the calculations;

 

  •  

a 10% discount rate may not be reasonable as a measure of the relative risk inherent in realizing future net oil and natural gas revenues; and

 

  •  

future net revenues may be subject to different rates of income taxation.

 

25

QUARTERNORTH ENERGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

 

Standardized Measure of Discounted Future Net Cash Flows

At December 31, 2022, as specified by the SEC, the prices for oil and natural gas used in this calculation were the unweighted 12-month average of the first day of the month prices. The 2022 average historical twelve-month oil and natural gas prices were $95.08 per Bbl of oil, $33.21 per Bbl of natural gas liquids and $6.69 per Mcf of natural gas. Estimates of future income taxes are computed using current income tax rates including consideration for estimated future statutory depletion and tax credits. The resulting net cash flows are reduced to present value amounts by applying a 10% discount factor.

 

Future cash inflows

    $ 5,507,038  

Future production costs

      (1,273,184 ) 

Future development costs

      (521,676 ) 

Future income taxes

      (686,808 ) 
  

 

 

  
     3,025,370  

10% annual discount

      (775,938 ) 
  

 

 

  

Standardized measure of discounted future net cash flows

    $ 2,249,432  
  

 

 

  

 

Standardized measure at beginning of year

    $  1,381,632  

Net change in prices and production costs

      1,345,716  

Net change in future development costs

      10,717  

Oil and gas net revenue

      (769,587 ) 

Extensions

      289,031  

Acquisition of reserves

      14,149  

Divestiture of reserves

      (63,448 ) 

Revisions of previous quantity estimates

      471,733  

Previously estimated development costs incurred

      4,788  

Net change in income taxes

      (517,669 ) 

Accretion of discount

      138,163  

Changes in timing and other

      (55,793 ) 
  

 

 

  

Standardized measure at end of year

    $ 2,249,432  
  

 

 

  

 

26

Exhibit 99.4

 

LOGO   

 

Ernst & Young LLP

5 Houston Center

Suite 2400

1401 McKinney Street

Houston, TX 77010

   

 

Tel: +1 713 750 1500

Fax: +1 713 7501501

ey.com

Report of Independent Auditors

To the Board of Directors of QuarterNorth Energy Inc.,

Opinion

We have audited the consolidated financial statements of QuarterNorth Energy Inc. (the Company), which comprise the consolidated balance sheet as of December 31, 2021, and the related consolidated statements of operations, changes in stockholders’ equity and cash flows for the period from August 27, 2021 to December 31, 2021, 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 the results of its operations and its cash flows for the period then ended in accordance with accounting principles generally accepted in the United States of America.

Basis for Opinion

We conducted our audit 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 audit. We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our audit opinion.

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.

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.

LOGO

 

  •  

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.

Other Information

Management is responsible for the other information. The other information comprises the information included in the annual report but does not include the financial statements and our auditor’s report thereon. Our opinion on the financial statements does not cover the other information, and we do not express an opinion or any form of assurance thereon.

In connection with our audit of the financial statements, our responsibility is to read the other information and consider whether a material inconsistency exists between the other information and the financial statements, or the other information otherwise appears to be materially misstated. If, based on the work performed, we conclude that an uncorrected material misstatement of the other information exists, we are required to describe it in our report.

 

LOGO

March 31, 2022

 

QUARTERNORTH ENERGY INC.

CONSOLIDATED BALANCE SHEET

AS OF DECEMBER 31, 2021

(In thousands, except share amounts)

 

Assets

 

Current assets:

   

Cash and cash equivalents

    $ 218,512  

Accounts receivable, net

      137,416  

Materials and supplies

      27,894  

Assets held for sale

      53,925  

Other current assets

      36,323  
  

 

 

  

Total current assets

      474,070  
  

 

 

  

Proved properties, net

      1,010,313  

Unproved properties, not subject to amortization

      174,120  

Other property and equipment, net

      3,168  

Derivative contracts

      182  

Restricted cash

      242  

Other assets

      11,601  
  

 

 

  

Total assets

    $ 1,673,696  
  

 

 

  
Liabilities and Stockholders’ Equity

 

Current liabilities:

   

Accounts payable

    $ 29,641  

Accrued liabilities

      69,020  

Derivative contracts

      36,703  

Current maturities of debt

      15,000  

Current portion of asset retirement obligations

      10,553  

Other current liabilities

      39,931  
  

 

 

  

Total current liabilities

      200,848  
  

 

 

  

Long-term debt

      265,294  

Asset retirement obligations

      182,961  

Deferred income taxes

      3,380  

Derivative contracts

      1,064  

Other long-term liabilities

      12,855  
  

 

 

  

Total liabilities

      666,402  
  

 

 

  

Commitments and contingencies (see Note 12)

   

Stockholders’ equity:

   

Common stock, par value $0.01; 50,000,000 shares authorized; 6,973,765 shares issued and outstanding as of December 31, 2021

      70  

Additional paid-in capital

      995,695  

Retained earnings

      11,529  
  

 

 

  

Total stockholders’ equity

      1,007,294  
  

 

 

  

Total liabilities and stockholders’ equity

    $ 1,673,696  
  

 

 

  

See notes to consolidated financial statements

 

1

QUARTERNORTH ENERGY INC.

CONSOLIDATED STATEMENT OF OPERATIONS

PERIOD FROM AUGUST 27, 2021 THROUGH DECEMBER 31, 2021

(In thousands)

 

Revenues:

   

Oil revenue

    $ 169,402  

Natural gas revenue

      18,127  

Natural gas liquids revenue

      8,250  

Other revenue

      17,007  
  

 

 

  

Total revenues

      212,786  
  

 

 

  

Operating expenses:

   

Lease operating expense

      50,090  

Decommissioning cost of goods sold

      7,430  

Depletion, depreciation and amortization

      68,258  

General and administrative expense

      3,334  

Insurance expense

      8,052  

Accretion expense

      5,547  

Other operating expense

      1,676  
  

 

 

  

Total operating expenses

      144,387  
  

 

 

  

Income from operations

      68,399  

Other income (expense), net:

   

Interest income (expense)

      (9,393 ) 

Commodity derivative income (loss)

      (44,112 ) 

Other

      17  
  

 

 

  

Income before income taxes

      14,911  

Income tax expense

      (3,382 ) 
  

 

 

  

Net income

    $ 11,529  
  

 

 

  

See notes to consolidated financial statements

 

2

QUARTERNORTH ENERGY INC.

CONSOLIDATED STATEMENT OF CASH FLOWS

PERIOD FROM AUGUST 27, 2021 THROUGH DECEMBER 31, 2021

(In thousands)

 

Cash flows from operating activities:

   

Net income

    $ 11,529  

Adjustments to reconcile net income to net cash provided by operating activities:

   

Amortization in interest expense

      332  

Accretion of asset retirement obligations

      5,547  

Depreciation, depletion and amortization

      68,258  

Risk management activities

      21,177  

Deferred income tax expense

      3,380  

Changes in operating assets and liabilities:

   

Accounts receivable and other assets

      61,595  

Accounts payable and other liabilities

      (120,748 ) 

Expenditures on asset retirement obligations, net

      (2,392 ) 
  

 

 

  

Net cash provided by operating activities

      48,678  
  

 

 

  

Cash flows from investing activities:

   

Additions to property and equipment

      (19,046 ) 

Acquisitions, net of cash received

      (12,171 ) 
  

 

 

  

Net cash used in investing activities

      (31,217 ) 
  

 

 

  

Cash flows from financing activities:

   

Proceeds from debt issuance, net of discount

      181,300  

Repayments of first lien term loan

      (18,599 ) 

Debt issuance costs

      (1,338 ) 

Payment of finance lease

      (79 ) 

Issuance of common stock

      40,009  
  

 

 

  

Net cash provided by financing activities

      201,293  
  

 

 

  

Net increase in cash and cash equivalents, including restricted cash

      218,754  

Cash and cash equivalents, including restricted cash, beginning of period

      —    
  

 

 

  

Cash and cash equivalents, including restricted cash, end of period

    $ 218,754  
  

 

 

  

See notes to consolidated financial statements

 

3

QUARTERNORTH ENERGY INC.

CONSOLIDATED STATEMENT OF CHANGES IN STOCKHOLDERS’ EQUITY

PERIOD FROM AUGUST 27, 2021 THROUGH DECEMBER 31, 2021

(In thousands, except share amounts)

 

                   Additional                
     Common Stock      Paid-In      Retained         
     Shares      Amount      Capital      Earnings      Total  

Balance, beginning of period

      —        $ —        $ —        $ —        $ —    

Issuance of common stock

      6,044,497        61        787,217        —          787,278  

Issuance of warrants

      —          —          208,478        —          208,478  

Issuance of common stock from exercise of warrants

      929,268        9        —          —          9  

Net income

      —          —          —          11,529        11,529  
  

 

 

     

 

 

     

 

 

     

 

 

     

 

 

  

Balance, end of period

      6,973,765      $ 70      $ 995,695      $ 11,529      $ 1,007,294  
  

 

 

     

 

 

     

 

 

     

 

 

     

 

 

  

See notes to consolidated financial statements

 

4

QUARTERNORTH ENERGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Except as noted within the context of each footnote disclosure, the dollar amounts presented in the tabular data within these footnote disclosures are in thousands of dollars.

Note 1—Basis of Presentation and Summary of Significant Accounting Policies

Description of Company

QuarterNorth Energy Inc. (“QuarterNorth”, “we”, “us”, “our” or “the Company”) was incorporated in Delaware on June 4, 2021, and amended as of July 16, 2021. On June 4, 2021, the Company formed four indirect wholly owned subsidiaries: QuarterNorth Energy Holding Inc.; QuarterNorth Energy Intermediate Inc.; QuarterNorth Energy LLC; and Mako Buyer 2 LLC. All four entities are Delaware corporations or limited liability companies, and were formed in contemplation of the Acquisition (as defined herein).

Business Operations and Strategy

QuarterNorth is an independent oil and natural gas producer with substantially all of its operations in the U.S. Gulf of Mexico (“GOM”). We commenced operations on August 27, 2021, when QuarterNorth Energy LLC purchased certain oil and natural gas properties (“the Acquisition”) from Fieldwood Energy Inc. and subsidiaries (“Fieldwood”) pursuant to a purchase and sale agreement (the “Purchase Agreement”). We are active in the exploration, operations, exploitation, development and acquisition of oil and gas properties. We maintain offices in Houston, Texas (headquarters) and Lafayette, Louisiana, as well as certain other shore-based field locations in Louisiana and Texas. We had 552 employees as of December 31, 2021.

We operate our business through ourselves and our consolidated subsidiaries. Our oil and gas properties are owned and operated by QuarterNorth Energy LLC.

Basis of Presentation

The accompanying consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”). These financial statements cover the period from August 27, 2021, the date we commenced operations, through December 31, 2021.

In preparing the accompanying consolidated financial statements, we have reviewed, as determined necessary by management, events that have occurred after December 31, 2021, up until the issuance of the consolidated financial statements, which occurred on March 31, 2022.

See Note 5—Debt, Note 7—Risk Management Activities, Note 8—Stockholders’ Equity, and Note 13—Assets Held for Sale, for information regarding subsequent events.

Summary of Significant Accounting Policies

Accounts Receivable. We sell oil and natural gas to various customers and participate with other parties in the drilling, completion, and operation of oil and natural gas wells. Joint interest and oil and natural gas sales receivables related to our operations are generally unsecured. The purchasers of the Company’s oil and natural gas production consist of independent marketers, major oil and natural gas companies and gas pipeline companies.

 

5

Asset Retirement Obligations (“AROs”). We record the fair value of a liability for a legal obligation to retire a tangible long-lived asset in the period in which the liability is incurred and can be reasonably estimated with the corresponding cost capitalized by increasing the carrying amount of the related long-lived asset. The liability is accreted to its present value each period and the capitalized costs are amortized using the unit-of-production method. The accretion expense is recorded as an operating expense. Estimates of AROs are revised as information about material changes to the liability becomes known. Revisions are recorded as adjustments to existing liabilities and to the carrying amount of the related assets. Settlement gains or losses are charged to oil and natural gas properties. Our AROs relate primarily to the plugging and abandonment of oil and natural gas wells and to the decommissioning of related pipelines, facilities and structures. See Note 6 for further information.

Cash and Cash Equivalents. Cash and cash equivalents represent unrestricted cash on hand, demand deposits, and investments with original maturities of three months or less. We consider cash equivalents to include short-term, highly liquid investments that are readily convertible to known amounts of cash and which are subject to an insignificant risk of changes in value.

Concentration of Credit Risk. We extend credit, primarily in the form of uncollateralized oil and natural gas sales and joint interest owners’ receivables, to various companies in the oil and natural gas industry, which results in a concentration of credit risk. The concentration of credit risk may be affected by changes in economic or other conditions within the oil and natural gas industry and may accordingly impact our overall credit risk. We believe our joint interest partners specific to our owned and operated properties primarily consist of large independent oil and natural gas companies and the risk of these unsecured receivables is substantially mitigated by the size, reputation and nature of the companies to which we extend credit.

The following table lists the percentage of our consolidated oil and natural gas revenues with purchasers that accounted for more than 10% of our consolidated oil, natural gas, and natural gas liquids revenues for the period from August 27, 2021 through December 31, 2021:

 

BP Products N.A., Inc.

      26 % 

Exxon Mobil Corp.

      25 % 

Shell Trading (US) Co.

      22 % 

Our allowance for doubtful accounts is based on estimates of future uncollectible accounts. In evaluating the collectability of accounts receivable, we make judgments regarding each party’s ability to make required payments, economic events, and other factors. As the financial condition of any party changes, circumstances develop or additional information becomes available, adjustments to an allowance for doubtful accounts may be required.

We use commodity derivative contracts to mitigate the effects of commodity price fluctuations. These derivative contracts expose us to counterparty credit risk. Our counterparties are generally major banks, commodity trading firms, or financial institutions. All derivative contracts are executed under master agreements, which allow us, in the event of default, to elect early termination of all contracts with the defaulting counterparty. If we choose to elect early termination, all asset and liability positions with the defaulting counterparty would be net settled at the time of election. We monitor the creditworthiness of our counterparties. However, we are not able to predict sudden changes in our counterparties’ creditworthiness. Should a financial counterparty not perform, we may not realize the benefit of some of our derivative contracts under lower commodity prices, and we may incur a loss.

 

6

Consolidation Policy. Our consolidated financial statements include the accounts of majority-owned, controlled subsidiaries. When we do not have the ability to exert significant influence, the cost method is used. Undivided interests in oil and gas joint ventures, pipelines, processing facilities, and certain other assets are consolidated on a proportionate basis.

Contingencies. Certain conditions may exist as of the date our consolidated financial statements are issued, which may result in a loss to us, but which will only be resolved when one or more future events occurs or fails to occur. Our management and legal counsel assess such contingent liabilities, and such assessment inherently involves an exercise in judgment.

In assessing loss contingencies related to legal or regulatory matters that are pending against us or unasserted claims that may result in such proceedings, our management, and legal counsel evaluate the perceived merits of any legal proceedings or unasserted claims as well as the perceived merits of the amount of relief sought or expected to be sought therein. If the assessment of a contingency indicates that it is probable that a material loss has been incurred and the amount of liability can be estimated, then the estimated liability would be accrued in our consolidated financial statements. If the assessment indicates that a potentially material loss contingency is not probable but is reasonably possible, or is probable but cannot be estimated, then the nature of the contingent liability, together with an estimate of the range of possible loss (if determinable and material), is disclosed.

Liabilities for environmental remediation costs arising from claims, assessments, litigation, fines, and penalties and other sources are charged to expense when it is probable that a liability has been incurred and the amount of the assessment and/or remediation can be reasonably estimated. Management believes we are in material compliance with all applicable federal, state, local and foreign laws and regulations associated with our properties.

Loss contingencies considered remote are generally not disclosed unless they involve guarantees, in which case the guarantees would be disclosed.

Derivative Contracts. We recognize derivative contracts at fair value as either assets or liabilities. Changes in fair value are recognized in earnings and included in other income unless designated as a hedging instrument. We have elected not to designate price risk management activities as accounting hedges under applicable accounting guidance. Derivative assets and liabilities are netted whenever we have a legally enforceable master netting agreement with the counterparty to a derivative contract. The related cash flow impact of our derivative activities is reflected as cash flows from operating activities.

Fair Value Measurements. Assets and liabilities required to be measured at fair value are categorized within the fair value hierarchy into one of three different levels depending on the observability of the inputs employed in the measurement. Level 1 inputs are quoted prices in active markets for identical assets or liabilities. Level 2 inputs are observable inputs other than quoted prices included within Level 1 for the asset or liability, either directly or indirectly through market-corroborated inputs. Level 3 inputs are unobservable inputs for the asset or liability reflecting significant modifications to observable related market data or our assumptions about pricing by market participants. Refer to Note 9—Fair Value Measurements for a further discussion.

 

7

Financing Costs. Costs incurred in connection with the issuance of debt are capitalized and amortized to interest expense over the term of the related debt. If these costs are associated with a related debt issuance, they are netted against the debt instrument in our consolidated balance sheet.

General and Administrative Expense. General and administrative expenses are reported net of recoveries from owners in properties operated by us and net of amounts related to lease operating activities or capitalized pursuant to the full cost method of accounting. We capitalized general and administrative expenses of $5.5 million for the period from August 27, 2021 through December 31, 2021.

Income Taxes. We use the liability method of accounting for income taxes in accordance with the Income Taxes Topic of the Accounting Standards Codification. Under this method, deferred tax assets and liabilities are determined by applying tax rates in effect at the end of a reporting period to the cumulative temporary differences between the tax bases of assets and liabilities and their reported amounts in the financial statements.

The effects of changes in tax rates and laws on deferred tax balances are recognized in the period in which the new legislation is enacted. In assessing the need for a valuation allowance on our deferred tax assets, we consider whether it is more likely than not that some portion or all of them will not be realized.

We recognize uncertain tax positions in our financial statements when it is more likely than not that we will sustain the benefit taken or expected to be taken. We classify interest and penalties related to uncertain tax positions in income tax expense. See Note 14—Income Taxes for additional information.

Lease Operating Expense. Lease operating expense includes labor, materials and supplies, repairs, maintenance, transportation, allocated overhead costs, ad valorem taxes and other costs incidental to production net to our ownership interests.

Materials and Supplies. We maintain inventories which include costs of materials, supplies, and production equipment to be used in drilling and abandonment operations, carried at net realizable value. During 2021, we did not incur material write-downs related to materials or supplies.

Oil and Natural Gas Properties.

 

     December 31,
2021		  

Proved properties

    $ 1,078,013  

Accumulated depreciation, depletion and amortization

      (67,700 ) 
  

 

 

  

Proved properties, net

    $ 1,010,313  
  

 

 

  

Unproved properties, not subject to amortization

    $ 174,120  
  

 

 

  

We follow the full cost method of accounting for oil and natural gas properties. Under this method, all costs related to the acquisition, exploration, and development of oil and natural gas reserves are capitalized and accumulated in a single cost center representing our activities. Such costs include lease acquisition costs, geological and geophysical expenditures, lease rentals on undeveloped properties, costs of drilling both productive and nonproductive wells, and general and administrative expenses directly related to acquisition, exploration, and development activities, and do not include any costs related to production, general corporate overhead or similar activities.

 

8

Under full cost accounting, we may exclude certain unevaluated costs from the amortization base pending determination of whether proved reserves can be assigned to such properties. The costs classified as unevaluated are transferred to the amortization base as the properties are developed, tested and evaluated. At least annually, we test these assets for impairment based on an evaluation of management’s expectations of future pricing, evaluation of lease expiration terms, and planned project development activities. Unevaluated costs of $0.3 million were transferred to the amortization base during 2021.

Oil and natural gas properties included in the amortization base are amortized using the units-of-production method based on production and estimates of proved reserves quantities. In addition to costs associated with evaluated properties and capitalized asset retirement obligations (“ARO”), the amortization base includes estimated future development costs to be incurred in developing proved reserves as well as estimated plugging and abandonment costs, net of salvage value, related to developing proved reserves. Future development costs related to proved reserves are not recorded as liabilities on the balance sheet, but are part of the calculation of depletion expense.

Our capitalized costs are limited to a ceiling based on the present value of future net revenues from proved reserves, computed using a discount factor of 10 percent, plus the lower of cost or estimated fair value of unproved oil and natural gas properties not being amortized less the related tax effects. Any costs over the ceiling are recognized as a non-cash impairment expense in our consolidated statement of operations and an increase to accumulated depreciation, depletion, and amortization on our consolidated balance sheet. The expense may not be reversed in future periods, even though higher crude oil, natural gas and natural gas liquids prices may subsequently increase the ceiling. We perform this ceiling test calculation each quarter.

We utilize SEC pricing when performing the ceiling test. We also hold prices and costs constant over the life of the reserves, even though actual prices and costs of oil and natural gas are often volatile and may change from period to period. We did not record a ceiling test impairment

Other Property and Equipment.

 

     December 31,
2021		  

Other property and equipment

    $ 3,726  

Accumulated depreciation

      (558 ) 
  

 

 

  

Other property and equipment, net

    $ 3,168  
  

 

 

  

Other property and equipment, which consists primarily of office furniture, equipment, computers and computer software, is stated at cost. Also included in this category are several sets of equipment for plugging and abandoning oil and gas wells. The plugging and abandoning equipment had a fair value on the acquisition date of $2.2 million. Depreciation on other property and equipment is calculated on the straight-line method over the estimated useful lives of the assets, which range from three to five years.

Restricted Cash. Our restricted cash serves as collateral for certain of our obligations. These restricted funds are generally invested in interest-bearing accounts.

Revenue Recognition. We recognize revenue from the sale of oil, natural gas, and natural gas liquids when our performance obligations are satisfied. Our contracts with customers are primarily short-term (within a year). Our responsibilities to deliver a unit of crude oil, natural gas liquids, and natural gas under these contracts represent separate, distinct performance obligations. These performance obligations are satisfied at the point in time control of each unit is transferred to the customer. Pricing is primarily determined utilizing a particular pricing or market index, plus or minus adjustments reflecting quality or location differentials.

 

9

We record oil and natural gas revenues based upon physical deliveries to our customers, which can be different from our net revenue ownership interest of production. These differences create imbalances that we recognize as a liability only when the estimated remaining recoverable reserves of a property will not be sufficient to enable the under-produced party to recoup its entitled share through production. We do not record receivables for those properties in which we have taken less than our ownership share of production.

Other Revenue

The following table presents other revenue information for the period from August 27, 2021 through December 31, 2021 are presented below:

 

Production handling/pipeline transportation

    $ 5,147  

Turnkey arrangement

      10,088  

Other

      1,772  
  

 

 

  
   $ 17,007  
  

 

 

  

We provide services related to certain production handling arrangements and pipeline transportation contracts. For the majority of these contracts, we promise to perform a series of distinct integrated services over a period of time, which is a single performance obligation, and the transaction price includes fixed or variable consideration, or a combination of both. The amount of consideration is determinable at contract inception or at each month’s end based on the value of services provided to the customer in that month. Revenue is recognized over the service period specified in the contract as the services are rendered using a time-based (passage of time) or units-based (units of service transferred) method for measuring progress towards satisfaction of the performance obligation. Payment is generally received from the customer in the month of service or the month following the service. Contracts with customers generally are a combination of month-to-month and multi-year agreements.

We have entered into agreements to plug, abandon, decommission and remove certain third-party assets in GOM. These services are performed under turnkey arrangements where the transaction price is fixed. The fixed prices are subject to change for certain qualified conditions. Revenue is recognized when the Company satisfies the performance obligation at a point in time.

Use of Estimates. The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosures of contingent assets and liabilities as of the date of the financial statements and the reported amounts of revenues and expenses during the period. Estimates and judgments are based on information available at the time such estimates and judgments are made. Adjustments made with respect to the use of these estimates and judgments often relate to information not previously available. Actual results could differ materially from estimated amounts.

 

10

Note 2—Supplemental Disclosures to the Balance Sheet and the Statement of Cash Flows

The following tables show additional balance sheet information as of December 31, 2021.

 

Accounts receivable

   

Operating revenues

    $ 49,635  

Joint interest receivables, net

      78,767  

Other

      9,014  
  

 

 

  
   $ 137,416  
  

 

 

  

Other current assets

   

Prepaids and other

    $ 6,303  

Decommissioning work-in-progress

      7,819  

Other

      22,201  
  

 

 

  
   $ 36,323  
  

 

 

  

Other assets

   

Right-of-use asset

    $ 10,963  

Oil & natural gas imbalances receivable

      510  

Other

      128  
  

 

 

  
   $ 11,601  
  

 

 

  

Accrued liabilities

   

Production expense

    $ 19,938  

Capital/Decommissioning

      17,142  

Accrued royalties

      10,057  

Accrued interest

      2,937  

Other

      18,946  
  

 

 

  
   $ 69,020  
  

 

 

  

Other current liabilities

   

Compressor lease

    $ 991  

Lease obligation

      2,382  

Other

      36,558  
  

 

 

  
   $ 39,931  
  

 

 

  

Other long-term liabilities

   

Compressor lease

    $ 3,101  

Lease obligation

      8,904  

Other

      850  
  

 

 

  
   $ 12,855  
  

 

 

  

 

11

Supplemental Cash Flow Information

Supplemental disclosures to the statement of cash flows for the period from August 27, 2021 through December 31, 2021 are presented below.

 

Supplemental disclosures of cash payments (receipts):

   

Interest paid, net of amounts capitalized

    $ 5,792  

Noncash investing and financing activities:

   

Fieldwood Energy Acquisition

   

Assumption of net working capital liability

      2,072  

Assumption of debt

      118,599  

Issuance of stock warrants

      208,478  

Transfer of note receivable as consideration

      747,278  

Note 3—Fieldwood Energy Acquisition

On August 27, 2021 (“Effective Date”, or “Acquisition Date”), we acquired from Fieldwood certain GOM oil and natural gas properties, pursuant to a purchase and sale agreement (the “PSA”).

Preliminary Purchase Price Allocation

We have accounted for the acquisition as a business combination, using the acquisition method. The following table represents the preliminary allocation of the total purchase price to the identifiable assets acquired and the liabilities assumed based on the fair values as of the acquisition date. Certain data necessary to complete the purchase price allocation is not yet available, and includes, but is not limited to, the final settled amount of the working capital liability assumed from Fieldwood, the valuation of pre-acquisition contingencies, and the effect changes to those amounts will have on the valuation of the issued stock warrants. We expect to complete the purchase price allocation during the 12-month period following the acquisition date, during which time the value of the assets, liabilities, and the stock warrants may be revised as appropriate.

 

Consideration:

   

Cash

    $ 12,171  

Net working capital liability assumed (1)

     2,072  

Debt assumed

      118,599  

Credit bid amount

      747,278  

Warrants, at fair value

      208,478  
  

 

 

  
   $ 1,088,598  
  

 

 

  

 

12

Fair Value of Assets Acquired:

   

Oil and natural gas properties (2)

   $ 1,213,146  

Investment in Fieldwood Mexico

      53,925  

Materials and supplies

      26,931  

Other assets

      3,657  
  

 

 

  
   $ 1,297,659  
  

 

 

  

Fair Value of Liabilities Assumed:

   

Commodity derivatives

    $ 16,408  

Asset retirement obligations

      192,653  
  

 

 

  
   $ 209,061  
  

 

 

  

Total identifiable net assets

    $ 1,088,598  
  

 

 

  

 

(1)

In accordance with the PSA, certain of Fieldwood’s working capital assets and liabilities were assumed by QuarterNorth on the closing date, and have been reflected as adjustments to the purchase price consideration.

(2)

In estimating the fair value of the oil and natural gas properties, the Company used an income approach, which incorporated the estimated reserve cash flows, risked by reserve category and discounted using a weighted average cost of capital rate of 12%. Oil and natural gas pricing was derived from NYMEX future prices and research analysts’ estimated pricing. This estimation includes the use of unobservable inputs, such as estimated future production, oil and natural gas revenues and expenses. The use of these unobservable inputs results in the fair value estimate being classified as Level 3.

Note 4—Leases

We primarily lease office spaces and production equipment, as well as marine transport vessels, tugboats, helicopters, and other facilities and equipment. At inception, contracts are reviewed to determine whether the agreement contains a lease. A contract is considered a lease when the arrangement either explicitly or implicitly conveys the right to control the use of the identified property, plant or equipment for a period of time in exchange for consideration. In order to obtain control, we must obtain substantially all of the economic benefits for the use of the identified asset and have the right to direct the use of the identified asset. Leases are evaluated for classification as operating or finance leases at the commencement date of the lease and right-of-use assets and corresponding liabilities are recognized on our consolidated balance sheet based on the present value of future lease payments relating to the use of the underlying asset during the lease term. The discount rate used to determine present value is the rate implicit in the lease unless the rate cannot be determined, in which case an incremental borrowing rate is used. The incremental borrowing rate reflects the estimated rate of interest we would incur over a similar term for an amount equal to the lease payments on a collateralized basis in a similar economic environment.

We have elected to account for lease and non-lease components in our contracts as a single lease component for all asset classes. Lease agreements may include options to renew the lease, terminate the lease or purchase the underlying asset. We determine the lease term at the lease commencement date as the non-cancelable period of the lease, including options to extend or terminate the lease when such an option is reasonably certain to be exercised. Factors we use to assess the reasonable certainty of rights to extend or terminate a lease include current and forecasted drillings plans, anticipated changes in development strategies, historical practice in extending similar contracts and current market conditions. We have elected to not apply the recognition requirements of Topic 842 to leases with durations of twelve months or less (i.e. short-term).

 

13

Lease Balances

The following table summarizes the present value of the fixed lease payments recorded as right-of-use assets and liabilities, including the balance sheet presentation, as of December 31, 2021.

 

Operating leases:

   

Other assets

    $ 8,164  

Other current liabilities

      2,131  

Other long-term liabilities

      6,057  
  

 

 

  

Total operating lease liabilities

    $ 8,188  
  

 

 

  

Financing leases:

   

Other assets

    $ 2,799  

Other current liabilities

      251  

Other long-term liabilities

      2,847  
  

 

 

  

Total financing lease liabilities

    $ 3,098  
  

 

 

  

Lease Costs

The following table presents the components of lease costs incurred during the period from August 27, 2021, through December 31, 2021. The amounts shown are gross and have not been adjusted to reflect amounts recovered or reimbursed from other working interest owners.

 

Operating lease cost

    $ 895  

Financing lease cost

   

Interest on lease liabilities

      87  

Amortization of right-of-use assets

      105  

Short-term lease cost

      164  
  

 

 

  

Total lease cost

    $ 1,251  
  

 

 

  

 

14

Minimum Future Commitments

The following table shows our minimum future commitments related to leases as of December 31, 2021, on an undiscounted basis with a reconciliation to the discounted present value recognized on our consolidated balance sheet.

 

     Operating
Leases		      Financing
Leases		  

2022

    $ 2,410      $ 497  

2023

      2,067        497  

2024

      1,726        497  

2025

      612        497  

2026

      612        425  

Thereafter

      3,224        2,173  
  

 

 

     

 

 

  

Total lease payments

      10,651        4,586  

Imputed interest

      (2,463 )       (1,488 ) 
  

 

 

     

 

 

  

Total

    $ 8,188      $ 3,098  
  

 

 

     

 

 

  

Lease Terms and Discount Rate

The following table presents the weighted average remaining lease terms and weighted average discount rate as of December 31, 2021.

 

Weighted average remaining lease term:

   

Operating leases

      6.7 years  

Financing leases

      10.1 years  

Weighted average discount rate:

   

Operating leases

      8.31 % 

Financing leases

      8.31 % 

Supplemental Cash Flow Information

The following table presents supplemental cash flow information related to our leases for the period from August 27, 2021 through December 31, 2021.

 

Operating cash outflow from financing leases

    $ 87  

Financing cash outflow from financing leases

      79  

Operating cash outflow from operating leases

      1,052  

 

15

Note 5—Debt

We had the following debt outstanding as of December 31, 2021:

 

First Lien Term Loan, variable rate, due 2025

    $ 100,000  

Second Lien Term Loan, variable rate, due 2026

      185,000  

Less: unamortized discount

      (3,445 ) 

Less: unarmortized debt issuance costs

      (1,261 ) 
  

 

 

  

Total debt, net

      280,294  

Less current portion

      (15,000 ) 
  

 

 

  

Total long-term debt, net

    $ 265,294  
  

 

 

  

First Lien Term Loan, due August 2025. On August 27, 2021, QuarterNorth Energy Holding Inc., as borrower, and its parent entity and subsidiaries, as guarantors, entered into the Third Amended and Restated First Lien Term Loan Agreement (“FLTL”), with lenders party thereto and Goldman Sachs Bank USA, as administrative agent and collateral agent for the lenders. The initial aggregate principal amount of loans outstanding under the agreement totaled $118.6 million. The loan equaled the principal amount of loans outstanding for Fieldwood Energy immediately prior to the credit bid purchase and sale to QuarterNorth. Payment terms under the FLTL include the following:

 

  •  

Commencing with the quarter ending September 30, 2021, we are required to make, subject to certain exceptions, quarterly principal repayments of $3.8 million;

 

  •  

the Company is required to pay 100% of net proceeds of any sale of assets, which include the possible sale of our investment in Fieldwood Mexico B.V, subject to certain provisions within the agreement;

 

  •  

the Company shall have the right at any time and from time to time to prepay the FLTL in whole or in part, without premium or penalty, in an aggregate principal amount that is an integral multiple of $0.5 million and not less than $1.0 million;

 

  •  

Any amount equal to the then unpaid principal amount is due on August 27, 2025

Borrowings under the FLTL bear interest at either an alternative base rate (ABR) plus an applicable margin ranging from 4.0%-5.0% or LIBOR plus an applicable margin ranging from 5.0%-6.0% with a 1.00% LIBOR floor. The applicable margin (as defined in the agreement) varies with the change in aggregate borrowings outstanding under the loan as well as the Company’s asset coverage ratio. Interest payments are due each quarter and the maturity date of the loan is August 27, 2025.

Obligations under the FLTL are secured by liens on substantially all of our assets. The FLTL requires ongoing compliance with affirmative and negative covenants, including minimum hedging requirements and certain financial covenants. QuarterNorth is obligated to maintain on the last day of each fiscal quarter a consolidated total net leverage ratio of, or less than, 2.25 to 1.00. Further, QuarterNorth is obligated to maintain an asset coverage ratio, as of the last day of any fiscal quarter to be 2.25 to 1.00 or greater.

 

16

Subsequent Event

During the first quarter of 2022, the Company sold its Fieldwood Mexico B.V. asset to PJSC Lukoil Oil Company and received cash proceeds of $53.6 million. On March 22, 2021, the FLTL was amended as follows:

 

  •  

the mandatory prepayment amount related to the Mexico transaction was reduced to $35 million. The payment was made on March 22, 2022;

 

  •  

the facility borrowing limit was adjusted to $100 million, with $65 million funded and $35 million unfunded as of the amendment date;

 

  •  

the $35 million unfunded amount is available as multi-draw term loans for the 24-month period after the amendment date, with a commitment fee equal to 0.75% per annum on the unfunded amount;

 

  •  

LIBOR and LIBOR loans were removed from the agreement and replaced with SOFR (secured overnight financing rate) and SOFR loans;

 

  •  

the applicable margin definition was amended to mean 4.5% for ABR loans and 5.5% for SOFR loans;

 

  •  

the Company paid an amendment fee of $0.5 million.

Second Lien Term Loan, due August 2026. On August 27, 2021, QuarterNorth Energy Holding Inc., as borrower, and its parent entity and subsidiaries, as guarantors, entered into the Second Lien Term Loan Agreement (“SLTL”), with lenders party thereto and Cantor Fitzgerald Securities, as administrative agent and collateral agent for the lenders.

On August 27, 2021, the Company borrowed $185 million under the SLTL. Cash proceeds received were $180.4 million, equal to the borrowing amount less an issue discount of $3.7 million and fees of $0.9 million.

Borrowings under the SLTL bear interest at either an ABR plus an applicable margin of 7.00% or LIBOR plus an applicable margin of 8.00%. The Company may, at its sole discretion, elect to pay interest-in-kind (“PIK”), by delivering a PIK notice to the lenders during any PIK election trigger period. The PIK election trigger period is a period in which the borrower and its restricted subsidiaries have less than $75.0 million as of the end of the most recently ended fiscal quarter. Obligations under the SLTL are secured by second liens on substantially all of our assets. The SLTL requires ongoing compliance with affirmative and negative covenants.

QuarterNorth has the right at any time and from time to time to prepay the SLTL in whole or in part, without premium or penalty, in an aggregate principal amount that is an integral multiple of $0.5 million and not less than $1.0 million.

Affirmative covenants include, among others, requirements of QuarterNorth relating to: (i) minimum hedging requirements; (ii) the preservation of existence; (iii) the payment of obligations, including taxes; (iv) the maintenance of insurance and books and records; (v) the compliance with laws and material contracts; (vi) compliance with environmental law (vii) use of proceeds; (viii) notice of certain material events; and (ix) certain periodic reporting requirements.

Negative covenants include, among others, restrictions on QuarterNorth’s and its subsidiary guarantors’ ability to, subject in each case to certain exceptions and baskets: (i) create, incur, assume or suffer to exist indebtedness; (ii) create or permit to exist liens on their properties; (iii) merge with or into another person, liquidate or dissolve; (iv) make asset sales; (v) pay cash dividends or other restricted payments; and (vi) enter into transactions with affiliates.

 

17

Further, negative covenants in the SLTL restrict QuarterNorth’s ability to engage in business activities other than those, among other things, related to the ownership of interest in QuarterNorth, performing our obligations under other indebtedness documents and receiving restricted payments.

Subsequent Event

On March 22, 2021, the SLTL was amended to make the restricted payment baskets consistent with the FLTL, as amended.

As of December 31, 2021, QuarterNorth was in compliance with all covenants under the FLTL and SLTL.

Note 6—Asset Retirement Obligations

The following table summarizes the activity for our asset retirement obligations for the period from August 27, 2021 through December 31, 2021.

 

Beginning balance

    $ —    

Liabilities incurred or assumed through acquisition

      192,653  

Liabilities settled

      (8,067 ) 

Accretion expense

      5,547  

Revisions to previous estimates

      3,381  
  

 

 

  
   $ 193,514  
  

 

 

  

Current portion

    $ 10,553  

Long-term portion

      182,961  
  

 

 

  
   $ 193,514  
  

 

 

  

Note 7—Risk Management Activities

Our principal market risks are our exposure to changes in commodity prices, particularly to the prices of crude oil and natural gas, and nonperformance by our counterparties.

Our revenues are derived principally from the sale of crude oil and natural gas. The prices of crude oil and natural gas are subject to market fluctuations in response to changes in supply, demand, market uncertainty and a variety of additional factors beyond our control. We monitor these risks and enter into commodity derivative contracts to secure a commodity price for a portion of our expected future production that is acceptable at the time of the transaction. We do not enter into derivative contracts for speculative purposes.

The counterparties to our derivative contracts include financial institutions and purchasers of crude oil and natural gas. Our derivative contracts expose us to market and credit risks, and which may, at times, be concentrated with certain counterparties or groups of counterparties. The credit worthiness of our counterparties is subject to continual review. We monitor the nonperformance risk of ourselves and of each of our counterparties and assesses the possibility of whether each counterparty to the derivative contract would default by failing to make any contractually required payments as scheduled in the derivative instrument in determining the fair value.

 

18

Our commodity derivative contracts may include, but are not limited to, “swap”, “collar” and “put” positions. Commodity derivative contracts outstanding as of December 31, 2021 are shown below:

 

Crude Oil (WTI Index)

  
     Swaps      Collars      Puts  

Period

    Volume
(MBbls)		      Average
$/Bbl		      Volume
(MBbls)		      Floor
$/Bbl		      Ceiling
$/Bbl		      Volume
(MBbls)		      Average
$/Bbl		  

1st Qtr 2022

      1,350      $ 64.72        —        $ —        $ —          270      $ 65.00  

2nd Qtr 2022

      1,061        63.38        31        60.00        85.05        273        65.00  

3rd Qtr 2022

      859        63.36        123        60.00        85.05        276        65.00  

4th Qtr 2022

      898        65.46        —          —          —          276        65.00  

1st Qtr 2023

      31        60.42        374        60.00        76.70        —          —    

2nd Qtr 2023

      346        64.54        —          —          —          —          —    

 

Natural Gas (Henry Hub Index)

  
     Puts  

Period

    Volume
(MMBtu) 		     Average
$/MMbtu		  

1st Qtr 2022

      1,440,000      $ 2.50  

2nd Qtr 2022

      1,365,000        2.50  

3rd Qtr 2022

      1,380,000        2.50  

4th Qtr 2022

      1,380,000        2.50  

1st Qtr 2023

      630,000        2.75  

2nd Qtr 2023

      509,600        2.50  

With swaps, we receive an agreed upon fixed price for a specified notional quantity of oil or natural gas and we pay the counterparty a floating price for that same quantity based upon published index prices. Index pricing used is based on grades that we believe best represent the revenue we receive for our underlying physical production. Our swap contracts provide us with protection if market prices decline below the contracted price. If market prices rise above the contracted prices, we will receive less revenue than in the absence of swaps.

Collars contain a fixed floor price and a fixed ceiling price. If the published index price exceeds the ceiling price or falls below the floor price, we receive the fixed price and pay the index price. If the index price is between the floor and ceiling prices, no payments are due from either party.

A put option gives the owner the right, but not the obligation, to sell the underlying commodity at a specified price (strike price) within a specific time period. Depending on market conditions, strike prices, and the value of the contracts, we may, at times, purchase put options, which require us to pay premiums. The premiums may be paid when the option is purchased, or deferred until each monthly settlement occurs. The ownership of put options is consistent with our derivative strategy inasmuch as the value of the puts will increase as commodity prices decline, helping to offset the cash flow impact of a decline in realized prices for the underlying commodity. However, if the underlying commodity increases in value, there is a risk that the put option will expire worthless, in which case the net premiums paid would be recognized as a loss.

 

19

Subsequent Event

During 2022, we entered into the following commodity derivative contracts:

 

     Crude Oil (WTI Index)  
     Swaps      Calls  

Period

    Volume
(MBbls)		      Average
$/Bbl		      Volume
(MBbls)		      Average
$/Bbl		  

4th Qtr 2022

      184      $ 86.65        184      $ 90.00  

1st Qtr 2023

      270        83.10        270        90.00  

2nd Qtr 2023

      273        83.10        273        90.00  

The following reflects the fair values of our derivative contracts, including the fair value of option premiums, and the line items where they appear on our consolidated balance sheet:

 

    

Balance Sheet

Location

    December 31,
2021		  

Commodity derivatives

    Long-term assets    $ 182  
     

 

 

  
   Total    $ 182  
     

 

 

  
    

Balance Sheet

Location

    December 31,
2021		  

Commodity derivatives

    Current liabilities    $ 36,703  

Commodity derivatives

    Long-term liabilities      1,064  
     

 

 

  
   Total    $ 37,767  
     

 

 

  

 

20

The following reflects the effect of master netting agreements on the balance sheet presentation of our derivative contracts:

 

     December 31,
2021		  

Assets:

   

Current

    $ 3,124  

Noncurrent

      2,730  
  

 

 

  

Total gross fair value

      5,854  

Less: counterparty offset

      (5,672 ) 
  

 

 

  

Total net fair value

    $ 182  
  

 

 

  

Liabilities:

   

Current

    $ 39,827  

Noncurrent

      3,612  
  

 

 

  

Total gross fair value

      43,439  

Less: counterparty offset

      (5,672 ) 
  

 

 

  

Total net fair value

    $ 37,767  
  

 

 

  

See Note 9 for additional disclosures related to derivative contracts.

Note 8—Stockholders’ Equity

On August 27, 2021, in conjunction with the Fieldwood Acquisition, the Company issued the following equity instruments:

Common Stock.

Certain holders of Fieldwood’s debt contributed a portion of their holdings to the Company in exchange for five million shares of our common stock. The contributed debt constituted the credit-bid portion of the Fieldwood Acquisition consideration.

The Company issued to certain of Fieldwood’s creditors stock subscription rights to acquire $40 million of our common stock, issued at a 43% discount to the value of our equity on the Effective Date. In total, 720,305 shares were issued, in exchange for $40 million in cash.

An ad hoc group of Fieldwood’s creditors agreed to provide backstop coverage to a portion of the $40 million subscription rights offering in exchange for a backstop fee payable in shares of the Company. The backstop fee was paid with our issuance of 324,192 shares of our common stock.

 

21

Stock Warrants

In conjunction with the Fieldwood acquisition, the Company issued stock warrants that provide the holder with the right to purchase shares of our common stock. The warrants were valued using a Black-Scholes-Merton option pricing model to derive a relative fair value and are not subject to subsequent remeasurement. The warrants have been classified as equity and are recognized within additional paid-in capital in our consolidated balance sheet. The following table summarizes the warrants issued:

 

Description

    Shares      Term      Exercise
Price		      Fair Market
Value		  

GUC Warrants

      389,330        8 years      $ 166.09      $ 9,890  

SLTL Tranche 1 Warrants

      2,780,926        8 years        166.09        70,643  

SLTL Tranche 2 Warrants

      5,355,857        8 years        189.42        127,945  

New Money Warrants

      1,908,828        7 years        0.01        —    

As of December 31, 2021, the holders of the New Money Warrants had exercised 929,268 warrants with an exercise price of $0.01.

Subsequent Event

The Board of Directors has approved and declared a dividend on common equity of up to $30 million ($3.772 per share of common stock and New Money Warrant, subject to rounding). The dividend will be paid on April 12, 2022 to all common stock and New Money Warrant holders of record as of March 29, 2022.

Note 9—Fair Value Measurements

Derivative Contracts

Our commodity derivative contracts are presented in our consolidated financial statements at fair value. These contracts consist of over-the-counter transactions, which are not traded on a public exchange.

The fair values of our commodity derivative contracts are determined based on inputs that are readily available in public markets or can be derived from information available in publicly quoted markets. Therefore, we have categorized these contracts as Level 2.

We have consistently applied these valuation techniques and believe we have obtained the most accurate information available for the types of derivative contracts we hold.

The following table sets forth, by level within the fair value hierarchy, our derivative assets and liabilities measured at fair value on a recurring basis as of December 31, 2021:

 

     Total      Level 1      Level 2      Level 3  

Assets

            

Commodity derivative contracts

    $ 182      $ —        $ 182      $ —    
  

 

 

     

 

 

     

 

 

     

 

 

  
   $ 182      $ —        $ 182      $ —    
  

 

 

     

 

 

     

 

 

     

 

 

  

Liabilities

            

Commodity derivative contracts

    $ 37,767      $ —        $ 37,767      $ —    
  

 

 

     

 

 

     

 

 

     

 

 

  
   $ 37,767      $ —        $ 37,767      $ —    
  

 

 

     

 

 

     

 

 

     

 

 

  

These derivative assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of the fair value assets and liabilities and their placement within the fair value hierarchy levels.

 

22

Business Combination

On August 27, 2021, we acquired oil and natural gas properties from Fieldwood Energy, and recorded the assets acquired and liabilities assumed at their acquisition date fair values. See Note 3, for a discussion of the fair value approaches used by the Company and the classification of the estimates within the fair value hierarchy.

Debt

We use a market approach to determine the fair value of our debt using estimates provided by an independent financial data services firm (a Level 2 fair value measurement). The carrying amount and fair value of our debt as of December 31, 2021 is shown in the following table.

 

     Carrying
Amount		      Fair
Value		  

First Lien Term Loan

    $ 100,000      $ 100,000  

Second Lien Term Loan

      180,294        185,000  
  

 

 

     

 

 

  
   $ 280,294      $ 285,000  
  

 

 

     

 

 

  

We believe the carrying values of cash, accounts receivable, accounts payable, and accrued liabilities included in the accompanying consolidated balance sheet approximate their fair value as of December 31, 2021.

Asset Retirement Obligations

We follow the provisions of ASC 820, for nonfinancial assets and liabilities measured at fair value on a non-recurring basis. These provisions apply to the Company’s initial recognition of asset retirement obligations for which fair value is used. The asset retirement obligation estimates are derived from historical costs and management’s expectation of future cost environments; and therefore, the Company has designated these liabilities as Level 3. See Note 6 for a reconciliation of the beginning and ending balances of the Company’s asset retirement obligations.

Note 10—Employee Benefits

We sponsor a qualified 401(k) Plan that provides for matching of up to 100% of the first 6% of employee contributions. Employees are immediately 100% vested in their contributions and our matching contributions. Our matching contributions were $0.7 million for the period from August 27, 2021, through December 31, 2021.

Note 11—Related Party Transactions

We have agreements to provide technical, operational, engineering, procurement, construction and installation services, management and administrative services to Fieldwood Mexico. Fees pursuant to these agreements were $7.4 million for the period from August 27, 2021, through December 31, 2021. They have been recognized in the financial statements as reductions of general and administrative expense.

 

23

Note 12—Commitments and Contingencies

Legal Proceedings. From time to time, we may be involved in litigation arising out of the normal course of our business. We maintain insurance coverage applicable to certain litigation, which, subject to applicable deductibles, may reduce our actual liability under any litigation. In management’s opinion, we are not involved in any litigation, the outcome of which would have a material effect on our consolidated financial position, results of operations, or liquidity.

Note 13—Assets Held for Sale

As part of the Fieldwood acquisition, we acquired Fieldwood’s investment in Fieldwood Mexico, B.V. (“Mexico”). Prior to the Acquisition, Fieldwood entered into a purchase and sale agreement to sell its investment to a subsidiary of PJSC Lukoil Oil Company, but the transaction closing was on hold pending the Mexican government’s approval of the transaction. Our investment in Mexico was $53.9 million as of December 31, 2021.

Subsequent Event

During the first quarter of 2022, the Company completed its sale of the Mexico investment. We received $53.6 million at closing. The remaining sales price of $4.5 million is in a holdback account, which we expect to receive in less than one year. A portion of the proceeds were used to make a $35 million principal payment on our FLTL. See Note 5 for more information.

Note 14—Income Taxes

Components of income tax expense for the period from August 27, 2021 through December 31, 2021 are as follows:

 

Current:

   

Federal

    $ —    

State

      2  
  

 

 

  

Total current income tax expense

      2  
  

 

 

  

Deferred:

   

Federal

      3,160  

State

      220  

Valuation allowance

      —    
  

 

 

  

Total deferred income tax expense

      3,380  
  

 

 

  

Total income tax expense

    $ 3,382  
  

 

 

  

 

24

Our reconciliation of income taxes computed at the U.S. federal statutory tax rate to our income tax expense is as follows:

 

Income before income taxes

    $ 14,911  
  

 

 

  

Income tax expense at the federal statutory rate

    $ 3,203  

Increases resulting from:

   

State tax expense at the statutory rate, net

      176  

Permanent items

      3  
  

 

 

  

Income tax expense

    $ 3,382  
  

 

 

  

Effective income tax rate

      22.7 % 
  

 

 

  

Deferred income taxes reflect the net tax effects of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax purposes. Significant components of our deferred tax assets and liabilities as of December 31, 2021 are:

 

Deferred tax assets:

   

Derivative contracts

    $ 4,688  

Net operating loss

      21,375  

Asset retirement obligations

      42,839  

Leases

      2,499  

Other

      6  
  

 

 

  
     71,407  
  

 

 

  

Deferred tax liabilities:

   

Property and equipment, net

      70,505  

Accruals

      1,153  

Leases

      2,427  

Other property and equipment, net

      701  
  

 

 

  
     74,786  
  

 

 

  

Net deferred tax asset (liability) before valuation allowance

      (3,380 ) 

Less: valuation allowance

      —    
  

 

 

  

Net deferred tax liability

    $ (3,380 ) 
  

 

 

  

Accounting for uncertainty in income taxes prescribes a recognition threshold and measurement methodology for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. As of December 31, 2021, we had no unrecognized tax benefits.

We file income tax returns in the U.S. federal jurisdiction and in Louisiana and Texas.

Any net operating loss carryforwards (“NOLs”) generated can be carried forward indefinitely. As of December 31, 2021 we have NOLs of $97 million that can be carried forward indefinitely.

 

25

Note 15—Significant Risks and Uncertainties

Oil and Natural Gas Prices

The price that we receive for our oil and natural gas production affects our revenue, profitability, liquidity, access to capital and future growth rate. Historically, the oil and natural gas markets have been volatile and will likely continue to be volatile in the future. Oil and natural gas prices depend on numerous factors, all of which are beyond our control. These factors include, but are not limited to, the following:

 

  •  

changes in supply and demand for oil and natural gas;

 

  •  

actions by the Organization of Petroleum Exporting Countries and other state-controlled oil companies;

 

  •  

the price and quantity of imports of foreign oil and natural gas;

 

  •  

speculation as to the future price of oil and the speculative trading of oil futures contracts;

 

  •  

global economic conditions, including the strength of the U.S. dollar;

 

  •  

the level of global oil and natural gas exploration and production activity;

 

  •  

weather conditions and other natural disasters; and

 

  •  

the length and severity of the recent COVID-19 (coronavirus) outbreak, including its impacts on the price and demand for oil and natural gas, and overall global economic activity.

Significant declines in oil and natural gas prices for an extended period may have the following effects on our business:

 

  •  

limiting our financial condition, liquidity, ability to finance our capital expenditures and results of operations;

 

  •  

reducing the amount of oil and natural gas that we can produce economically;

 

  •  

causing us to delay, postpone or terminate our exploration and development activities;

 

  •  

reducing any future revenues, operating income and cash flows;

 

  •  

reducing the carrying value of our crude oil and natural gas properties; or

 

  •  

limiting our access to sources of capital, such as equity and debt.

BOEM Financial Assurances Requirements

The Bureau of Ocean Energy Management (“BOEM”) requires that lessees demonstrate financial strength and reliability according to its regulations or post surety bonds or other acceptable financial assurances that such decommissioning obligations will be satisfied. Presently, we do not have any supplemental bonding requests outstanding.

On July 14, 2016, BOEM issued Notice to Lessees and Operators (“NTL”) 2016-N01 revising supplemental bonding requirements and procedures related to obligations for decommissioning activities on the federal Outer Continental Shelf of the Gulf of Mexico. NTL 2016-N01 would have implemented a phase-in period for establishing compliance with additional security obligations for certain categories of properties covered under NTL 2016-N01, whereby a lessee may seek compliance with its additional security requirements under a tailored plan that is approved by BOEM. On January 6, 2017, BOEM suspended the implementation of NTL 2016-N01 for a six-month period and withdrew all previously issued bonding orders. On June 22, 2017 suspension on the implementation of NTL 2016-N01 was extended beyond the initial six-month period. At this time, a new timeline for finalization has not been determined. Were BOEM to finalize implementation of NTL 2016-N01, or a similar NTL or regulation, this could result in additional demands for surety bonds or other financial assurances.

 

26

The availability of surety bonds to the Company as well as the terms, cost and collateral requirements may change subject to market conditions and the surety providers’ evaluation of the creditworthiness of the Company. If we fail to comply with any future orders of BOEM to provide additional surety bonds or other financial assurances, BOEM could commence enforcement proceedings or take other remedial action, including assessing civil penalties, ordering suspension of operations or production, or initiating procedures to cancel leases, which, if upheld, could have a material adverse effect on our business, properties, results of operations and financial condition.

 

27

Note 16 – Supplemental Consolidating Financial Information

QuarterNorth Energy Holding Inc. is the borrower under the loans described in Note 5. The following condensed consolidating financial statements shows the accounts of the parent company, QuarterNorth Energy Inc. on a standalone basis, the accounts of the borrower and its consolidated subsidiaries, and intercompany eliminations to arrive at the consolidated statements of the Company.

QUARTERNORTH ENERGY INC.

CONDENSED CONSOLIDATING BALANCE SHEET

AS OF DECEMBER 31, 2021

(In thousands)

 

     QuarterNorth
Energy Inc.		     QuarterNorth
Energy Holding
Inc.		      Intercompany
Eliminations		     Consolidated  

Assets

 

Current assets:

          

Cash and cash equivalents

    $ —       $ 218,512      $ —       $ 218,512  

Accounts receivable and other assets

      —         255,558        —         255,558  
  

 

 

    

 

 

     

 

 

    

 

 

  

Total current assets

      —         474,070        —         474,070  
  

 

 

    

 

 

     

 

 

    

 

 

  

Property and equipment net

      —         1,187,601        —         1,187,601  

Investments in subsidiaries

      1,007,428       —          (1,007,428 )      —    

Advances to (from) subsidiaries

      (173 )      173        —         —    

Other assets

      39       12,025        (39 )      12,025  
  

 

 

    

 

 

     

 

 

    

 

 

  

Total assets

    $ 1,007,294     $ 1,673,869      $ (1,007,467 )    $ 1,673,696  
  

 

 

    

 

 

     

 

 

    

 

 

  
Liabilities and Stockholders’ Equity

 

Current liabilities

          

Accounts payable and accrued liabilities

    $ —       $ 98,661      $ —       $ 98,661  

Current maturities of debt

      —         15,000        —         15,000  

Other current liabilities

      —         87,187        —         87,187  
  

 

 

    

 

 

     

 

 

    

 

 

  

Total currrent liabilities

      —         200,848        —         200,848  
  

 

 

    

 

 

     

 

 

    

 

 

  

Long-term debt

      —         265,294        —         265,294  

Asset retirement obligations

      —         182,961        —         182,961  

Other long-term liabilities

      —         17,338        (39 )      17,299  
  

 

 

    

 

 

     

 

 

    

 

 

  

Total liabilities

      —         666,441        (39 )      666,402  
  

 

 

    

 

 

     

 

 

    

 

 

  

Stockholders’ equity

      1,007,294       1,007,428        (1,007,428 )      1,007,294  
  

 

 

    

 

 

     

 

 

    

 

 

  

Total liabilities and stockholders’ equity

    $ 1,007,294     $ 1,673,869      $ (1,007,467 )    $ 1,673,696  
  

 

 

    

 

 

     

 

 

    

 

 

  

 

28

QUARTERNORTH ENERGY INC.

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

PERIOD FROM AUGUST 27, 2021 THROUGH DECEMBER 31, 2021

(In thousands)

 

     QuarterNorth
Energy Inc.		     QuarterNorth
Energy Holding
Inc.		     Intercompany
Eliminations		     Consolidated  

Revenues

         

Total revenues

    $ —       $ 212,786     $ —       $ 212,786  
  

 

 

    

 

 

    

 

 

    

 

 

  

Operating expenses

         

Lease operating expense

      —         50,090       —         50,090  

Depletion, depreciation and amortization

      —         68,258       —         68,258  

General and administrative expense

      173       3,161       —         3,334  

Other operating expense

      —         22,705       —         22,705  
  

 

 

    

 

 

    

 

 

    

 

 

  

Total operating expense

      173       144,214       —         144,387  
  

 

 

    

 

 

    

 

 

    

 

 

  

Income (loss) from operations

      (173 )      68,572       —         68,399  

Other income (expense), net

         

Equity in earnings of subsidiaries

      11,663       —         (11,663 )      —    

Other

      —         (53,488 )      —         (53,488 ) 
  

 

 

    

 

 

    

 

 

    

 

 

  

Income (loss) before income taxes

      11,490       15,084       (11,663 )      14,911  

Income tax (expense) benefit

      39       (3,421 )      —         (3,382 ) 
  

 

 

    

 

 

    

 

 

    

 

 

  

Net income

    $ 11,529     $ 11,663     $ (11,663 )    $ 11,529  
  

 

 

    

 

 

    

 

 

    

 

 

  

Note 17—Supplemental Information on Oil and Natural Gas Operations (Unaudited)

Oil and Natural Gas Reserves

Proved reserves represent estimated quantities of natural gas, crude oil and condensate and natural gas liquids that geological and engineering data demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs under economic and operating conditions in effect when the estimates were made. Proved developed oil and natural gas reserves are proved reserves that can be expected to be recovered through existing wells and equipment in place and under operating methods being utilized at the time the estimates were made. Users of this information should be aware that the process of estimating quantities of “proved” and “proved developed” oil and natural gas reserves is very complex, requiring significant subjective decisions.

Results of Operations for Oil and Gas Producing Activities

Separate disclosure is not required because our oil- and gas-producing activities represent substantially all of our business activities, and we operate in a single geographic area. See our consolidated statement of operations.

 

29

Costs Incurred

The following table reflects the costs incurred in oil and natural gas property acquisition, exploration and development activities for the period from August 27, 2021 through December 31, 2021. Costs incurred also includes capitalized general and administrative expense, acquired asset retirement obligations, new asset retirement obligations established in the current period, as well as increases or decreases to our asset retirement obligations resulting from changes to cost estimates during the current period.

 

Acquisition costs

   

Proved

    $ 1,047,452  

Unproved

      165,317  

Exploration costs

      14,215  

Development costs

      25,149  
  

 

 

  
   $ 1,252,133  
  

 

 

  

Capitalized Costs

The following table illustrates the total amount of capitalized costs and accumulated depreciation, depletion and amortization relating to our oil and natural gas properties as of December 31, 2021.

 

Proved properties

    $ 1,078,013  

Unproved properties, not being amortized

      174,120  

Accumulated DD&A

      (67,700 ) 
  

 

 

  
   $ 1,184,433  
  

 

 

  

The following table sets forth certain information relative to the amortization of our investment in oil and gas properties and the impairment of our oil and gas properties for the period from August 27, 2021 through December 31, 2021.

 

Provision for DD&A

    $ 67,700  

Impairment of oil and gas properties

      —    

DD&A per BOE

      1.02  

 

30

Proved Reserves

The following information summarizes our net proved reserves of oil (including condensate), natural gas and natural gas liquids as of December 31, 2021. All of our oil and natural gas reserves are located in the U.S. Gulf of Mexico.

 

     Oil
(MBbls)		      Natural Gas
(MMcf)		      NGL
(MBbls)		      Mboe  

Estimated proved reserves

      42,507        111,155        5,522        66,555  
  

 

 

     

 

 

     

 

 

     

 

 

  

Estimated proved developed reserves

      22,732        58,526        2,968        35,454  
  

 

 

     

 

 

     

 

 

     

 

 

  

Estimated proved undeveloped reserves

      19,775        52,629        2,554        31,101  
  

 

 

     

 

 

     

 

 

     

 

 

  

Management believes the reserve estimates presented herein are reasonable and prepared in accordance with guidelines established by the SEC as prescribed in Regulation S-X, Rule 4-10 as of December 31, 2021. However, there are numerous uncertainties inherent in estimating quantities and values of proved reserves and in projecting future rates of production and the amount and timing of development expenditures, including many factors beyond our control. See Note 15 for a listing of significant risks and uncertainties. Reserve engineering is a subjective process of estimating the recovery from underground accumulations of oil and natural gas that cannot be measured in an exact manner, and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Because all oil and natural gas reserve estimates are to some degree subjective, the quantities of oil and natural gas that are ultimately recovered, production and operating costs, the amount and timing of future development expenditures and future crude oil and natural gas sales prices may all differ from those assumed in these estimates. In addition, different reserve engineers may make different estimates of reserve quantities and cash flows based upon the same available data.

Therefore, the standardized measure of discounted future net cash flows (Standardized Measure) shown below represents estimates only and should not be construed as the current market value of the estimated reserves attributable to our oil and gas properties. The Standardized Measure has been developed utilizing ASC 932, Extractive Activities – Oil and Gas (ASC 932) procedures and based on oil and natural gas reserve production volumes estimated by the Company’s engineering staff.

The Company believes that the following factors should be taken into account when reviewing the following information:

 

  •  

future costs and selling prices will probably differ from those required to be used in these calculations;

 

  •  

due to future market conditions and governmental regulations, actual rates of production in future years may vary significantly from the rate of production assumed in the calculations;

 

  •  

a 10% discount rate may not be reasonable as a measure of the relative risk inherent in realizing future net oil and natural gas revenues; and

 

  •  

future net revenues may be subject to different rates of income taxation.

 

31

Standardized Measure of Discounted Future Net Cash Flows

At December 31, 2021, as specified by the SEC, the prices for oil and natural gas used in this calculation were the unweighted 12-month average of the first day of the month prices. The 2021 average historical twelve-month oil and natural gas prices were $66.56 per Bbl of oil, $43.80 per Bbl of natural gas liquids and $3.61 per Mcf of natural gas. Estimates of future income taxes are computed using current income tax rates including consideration for estimated future statutory depletion and tax credits. The resulting net cash flows are reduced to present value amounts by applying a 10% discount factor.

 

Future cash inflows

    $ 3,418,529  

Future production costs

      (799,762 ) 

Future development costs

      (792,663 ) 

Future income taxes

      (330,129 ) 
  

 

 

  
     1,495,975  

10% annual discount

      (362,270 ) 
  

 

 

  

Standardized measure of discounted future net cash flows

    $ 1,133,705  
  

 

 

  

 

32

Exhibit 99.5

 

LOGO

STATEMENT OF REVENUES AND DIRECT OPERATING EXPENSES AND NOTES TO STATEMENT OF REVENUES AND DIRECT OPERATING EXPENSES OF THE OIL AND NATURAL GAS PROPERTIES ACQUIRED BY QUARTERNORTH ENERGY LLC AND MAKO BUYER 2 LLC ON AUGUST 27, 2021 FROM FIELDWOOD ENERGY LLC AND ITS DEBTOR AFFILIATES

For the period January 1, 2021 through August 26, 2021

LOGO  

 

Ernst & Young LLP

5 Houston Center

Suite 2400

1401 McKinney Street

Houston, TX 77010

  

 

Tel: +1 713 750 1500

Fax: +1 713 750 1501

ey.com

   

Report of Independent Auditors

To the Board of Directors of QuarterNorth Energy Inc.

We have audited the accompanying statement of revenues and direct operating expenses of the oil and natural gas properties acquired by QuarterNorth Energy Inc. and Mako Buyer 2 LLC (the “Company”) on August 27, 2021 from Fieldwood Energy Inc. and its debtor affiliates (the “Properties” as described in Note 1) for the period from January 1, 2021 through August 26, 2021, and the related notes (the “financial statement”).

Management’s Responsibility for the Financial Statement

Management is responsible for the preparation and fair presentation of this financial statement in conformity with U.S. generally accepted accounting principles; this includes the design, implementation and maintenance of internal control relevant to the preparation and fair presentation of the financial statement that is free of material misstatement, whether due to fraud or error.

Auditor’s Responsibility

Our responsibility is to express an opinion on the financial statement based on our audit. We conducted our audit in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statement is free of material misstatement.

An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the financial statement. The procedures selected depend on the auditor’s judgment, including the assessment of the risks of material misstatement of the financial statement, whether due to fraud or error. In making those risk assessments, the auditor considers internal control relevant to the entity’s preparation and fair presentation of the financial statement 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 entity’s internal control. Accordingly, we express no such opinion. An audit also includes evaluating the appropriateness of accounting policies used and the reasonableness of significant accounting estimates made by management, as well as evaluating the overall presentation of the financial statement.

We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our audit opinion.

Opinion

In our opinion, the financial statement referred to above presents fairly, in all material respects, the revenues and direct operating expenses of the Properties as described in Note 1 of the financial statement for the period from January 1, 2021 through August 26, 2021, in conformity with U.S. generally accepted accounting principles.

Basis of Accounting

We draw attention to Note 1 to the financial statement, which describes that the accompanying financial statement was prepared for the purpose of complying with the rules and regulations of the Securities and Exchange Commission and is not intended to be a complete presentation of the Properties’ revenues and expenses. As a result, the financial statement may not be suitable for another purpose. Our opinion is not modified with respect to this matter.

 

LOGO     

January 9, 2024

STATEMENT OF REVENUES AND DIRECT OPERATING EXPENSES

(In thousands)

 

     January 1, 2021
Through
August 26, 2021		  

Revenues:

   

Oil revenue

    $ 284,867  

Natural gas revenue

      21,864  

Natural gas liquids revenue

      11,246  

Other revenue

      7,268  
  

 

 

  

Total revenues

      325,245  

Direct operating expenses

      83,559  
  

 

 

  

Excess of revenues over direct operating expenses

    $ 241,686  
  

 

 

  

The accompanying notes are an integral part of the statement of revenues and direct operating expenses

 

1

NOTES TO THE STATEMENT OF REVENUES AND DIRECT OPERATING EXPENSES

Note 1 - Basis of Presentation

QuarterNorth Energy Inc. (“QuarterNorth”) is an independent oil and natural gas producer with substantially all of its operations in the U.S. Gulf of Mexico (“GOM”) through its subsidiaries. QuarterNorth commenced operations on August 27, 2021, when QuarterNorth Energy LLC and Mako Buyer 2 LLC, both Delaware limited liability companies and indirectly wholly-owned subsidiaries of QuarterNorth, purchased certain oil and natural gas properties (“the Properties”) from Fieldwood Energy Inc. and its debtor affiliates (“Fieldwood”) pursuant to a purchase and sale agreement dated August 27, 2021 (“PSA”).

The accompanying Statement of Revenues and Direct Operating Expenses (the “Statement”) represents the direct undivided interests in the revenues and direct operating expenses associated with the Properties prior to QuarterNorth acquiring them from Fieldwood. The Statement of Revenues and Direct Operating Expenses has been derived from the historical records related to the Properties. During the period presented, the Properties were not accounted for or operated as a separate entity, subsidiary, segment or division by Fieldwood. Accordingly, a complete set of financial statements required by the Securities and Exchange Commission’s Regulation S-X, including a balance sheet and statement of cash flows, prepared in accordance with accounting principles generally accepted in the United States of America (“U.S. GAAP”) is not available or practicable to prepare for the Properties. The accompanying Statement varies from a complete income statement in accordance with U.S. GAAP in that it does not reflect certain expenses incurred in connection with the ownership and operation of the Properties, including but not limited to depreciation, depletion and amortization, impairments, accretion of asset retirement obligations, general and administrative expenses, interest expense, effects of derivative transactions, and federal and state income taxes. These costs were not separately allocated to the working interests of the Properties based on the records related to the Properties. In addition, as the Properties were owned by Fieldwood during the period presented and such Properties were operated by a mix of Fieldwood and other operators which are not necessarily comparable to the operations of QuarterNorth, the Statement is not indicative of the results of operations for the Properties on a go-forward basis.

Note 2 - Summary of Significant Accounting Policies

Revenue Recognition

Revenue from the sale of oil, natural gas, and natural gas liquids is recognized when the related performance obligations are satisfied. Contracts with customers are primarily short-term (within a year). The responsibility to deliver a unit of crude oil, natural gas liquids, and natural gas under these contracts represents separate, distinct performance obligations. These performance obligations are satisfied at the point in time control of each unit is transferred to the customer. Pricing is primarily determined utilizing a particular pricing or market index, plus or minus adjustments reflecting quality or location differentials.

Direct Operating Expenses

Direct operating expenses are recognized when incurred and consist of the direct expenses of operating the Properties. Direct operating expenses include lease operating expenses, production taxes and gathering, processing and transportation costs. Lease operating expenses include well repair expenses, saltwater disposal costs, facility maintenance expenses, and other field-related expenses. Lease operating expenses also include expenses directly associated with support personnel, support services, equipment and facilities directly related to oil and natural gas production activities.

 

2

NOTES TO THE STATEMENT OF REVENUES AND DIRECT OPERATING EXPENSES

Use of Estimates

The Statement of Revenues and Direct Operating Expenses is derived from the historical operating statements of Fieldwood related to the Properties. Accounting principles generally accepted in the United States of America require management to make estimates and assumptions that affect the amounts reported in the Statement. Actual results could differ from those estimates. Revenues and direct operating expenses relate to the historical net revenue interest and net working interest, respectively, in the Properties.

Note 3 – Contingencies

The activities of the Properties may become subject to potential claims and litigation in the ordinary course of operations. The Company is not aware of any legal, environmental, or other claims or other contingencies that would have a material effect on the Statement.

Note 4 – Subsequent Events

The Company has evaluated subsequent events through January 9, 2024, the date this Statement was available to be issued, and concluded that no events need to be reported.

Note 5 – Supplemental Oil and Gas Reserve Information - Unaudited

The following tables summarize the net ownership interest in the estimated quantities of proved oil and natural gas reserves and the standardized measure of discounted future net cash flows (“Standardized Measure”) of the Properties at August 26, 2021. The proved oil and natural gas reserve estimates and other components of the Standardized Measure are based on reserve studies generally prepared in accordance with the Securities and Exchange Commission. All of the oil and natural gas producing activities related to the Properties were conducted within the U.S. Gulf of Mexico.

Proved Reserves

Proved reserves represent estimated quantities of natural gas, crude oil and condensate and natural gas liquids that geological and engineering data demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs under economic and operating conditions in effect when the estimates were made. Proved developed oil and natural gas reserves are proved reserves that can be expected to be recovered through existing wells and equipment in place and under operating methods being utilized at the time the estimates were made. Users of this information should be aware that the process of estimating quantities of “proved” and “proved developed” oil and natural gas reserves is very complex, requiring significant subjective decisions.

 

3

NOTES TO THE STATEMENT OF REVENUES AND DIRECT OPERATING EXPENSES

The following table summarizes net proved reserves of oil (including condensate), natural gas and natural gas liquids related to the Properties as of August 26, 2021.

 

     Crude Oil
(Mbbl)		      Natural Gas
(MMcf)		      NGLs
(Mbbl)		      Total
(Mboe)		  

Net proved reserves at January 1, 2021

      43,904        121,613        5,285        69,458  

Revisions

      (119 )       (938 )       18        (257 ) 

Production

      (4,392 )       (6,145 )       (370 )       (5,786 ) 
  

 

 

     

 

 

     

 

 

     

 

 

  

Net proved reserves at August 26, 2021

      39,393        114,530        4,933        63,415  
  

 

 

     

 

 

     

 

 

     

 

 

  

Proved developed reserves at August 26, 2021

      22,293        55,757        2,558        34,144  

Proved undeveloped reserves at August 26, 2021

      17,100        58,773        2,375        29,271  

Standardized Measure of Discounted Future Net Cash Flows

The Standardized Measure represents the present value of estimated future net cash flows from estimated net oil, natural gas, and NGL reserves, less future development, production, plugging and abandonment costs, and income tax expenses, discounted at 10% per annum to reflect timing of future cash flows. Production costs do not include depreciation, depletion and amortization of capitalized acquisition, exploration and development costs. Additionally, the standardized measure and changes in standardized measure presented here excludes income taxes as the tax basis of the properties is not applicable on a go forward basis.

The future cash inflows represent expected revenues from production of period-end quantities of proved reserves based on the 12-month average oil and natural gas index, calculated as the unweighted arithmetic average first-day-of-the-month price for each month during the prior twelve months as prescribed by Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) 932. The average prices (adjusted for quality differentials, transportation fees, geographical differentials, marketing bonuses or deductions and other factors affecting the price at the wellhead) related to proved reserves at August 26, 2021 were $49.78/Bbl for oil and $2.42/MMBtu for natural gas.

Estimated future production costs related to period-end reserves are based on period-end costs. Such costs include, but are not limited to, production taxes and direct operating costs. Inflation and other anticipatory costs are not considered until the actual cost change takes effect.

The following table sets forth unaudited information concerning future net cash flows excluding income taxes for oil, natural gas and NGL reserves associated with the Properties.

 

     August 26,
2021
(in thousands)		  

Future cash inflows

    $ 2,291,708  

Future production costs

      (623,358 ) 

Future development costs

      (695,663 ) 
  

 

 

  

Future net cash flows

      972,687  

10% annual discount

      (216,584 ) 
  

 

 

  

Standardized measure of discounted future net cash flows

    $ 756,103  
  

 

 

  

 

4

NOTES TO THE STATEMENT OF REVENUES AND DIRECT OPERATING EXPENSES

The Standardized Measure does not purport, nor should be interpreted, to present the fair market value of the Properties’ reserves. It is intended to present a standardized disclosure concerning possible future net cash flows from reserves that would result under the assumptions used and ignores future changes in prices and costs and the risks inherent in reserve estimates, among other things. The various assumptions used, including prices, costs, production rates and discount rates, are inherently imprecise. Further, since prices and costs do not remain static, the results are not necessarily indicative of the fair market value of estimated reserves. Accordingly, the estimates of future net cash flows from reserves and the present value thereof may be materially different than actual subsequent results, and the results may not be comparable to estimates disclosed by other oil and natural gas producers.

Changes in Standardized Measure of Discounted Future Net Cash Flows

The following table sets forth the changes in Standardized Measure of discounted future net cash flows applicable to estimated net proved oil, natural gas and NGL reserves of the Properties for the period presented (in thousands):

 

(in thousands)       

Standardized measure at January 1, 2021

    $ 533,936  

Net change in prices and production costs

      447,100  

Net change in future development costs

      2,000  

Oil and gas net revenue

      (234,418 ) 

Revisions of previous quantity estimates

      (3,923 ) 

Previously estimated development costs incurred

      206  

Accretion of discount

      34,669  

Changes in timing and other

      (23,467 ) 
  

 

 

  

Standardized measure at August 26, 2021

    $ 756,103  
  

 

 

  

 

5

Exhibit 99.6

 

LOGO

QUARTERNORTH ENERGY INC.

CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

QUARTERLY PERIOD ENDED SEPTEMBER 30, 2023

QUARTERNORTH ENERGY INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

(In thousands, except share amounts)

(Unaudited)

 

     September 30,
2023		      December 31,
2022		  
Assets      

Current assets:

      

Cash and cash equivalents

    $ 387,722      $ 400,816  

Short-term investment

      —          60,170  

Accounts receivable, net

      179,489        144,060  

Materials and supplies

      49,166        46,002  

Derivative contracts

      —          8,440  

Other current assets

      40,492        38,478  
  

 

 

     

 

 

  

Total current assets

      656,869        697,966  
  

 

 

     

 

 

  

Proved properties, net

      858,737        884,796  

Unproved properties, not subject to amortization

      181,384        183,779  

Other property and equipment, net

      2,667        1,213  

Restricted cash

      —          1,097  

Other assets

      6,704        7,115  
  

 

 

     

 

 

  

Total assets

    $ 1,706,361      $ 1,775,966  
  

 

 

     

 

 

  
Liabilities and Stockholders’ Equity      

Current liabilities:

      

Accounts payable

    $ 56,860      $ 44,449  

Accrued liabilities

      122,680        133,368  

Derivative contracts

      43,711        8,156  

Current maturities of debt

      —          1,000  

Current portion of asset retirement obligations

      10,577        4,048  

Other current liabilities

      2,943        16,997  
  

 

 

     

 

 

  

Total current liabilities

      236,771        208,018  
  

 

 

     

 

 

  

Long-term debt

      182,060        180,939  

Asset retirement obligations

      112,732        129,132  

Deferred income taxes

      68,008        66,651  

Derivative contracts

      9,576        —    

Other long-term liabilities

      4,848        6,946  
  

 

 

     

 

 

  

Total liabilities

      613,995        591,686  
  

 

 

     

 

 

  

Stockholders’ equity:

      

Common stock, par value $0.01; 50,000,000 shares authorized; 7,889,685 shares issued and outstanding as of September 30, 2023 and 7,540,813 shares issued and outstanding as of December 31, 2022

      79        75  

Additional paid-in capital

      978,531        978,531  

Retained earnings

      113,756        205,674  
  

 

 

     

 

 

  

Total stockholders’ equity

      1,092,366        1,184,280  
  

 

 

     

 

 

  

Total liabilities and stockholders’ equity

    $ 1,706,361      $ 1,775,966  
  

 

 

     

 

 

  

See notes to condensed consolidated financial statements

 

1

QUARTERNORTH ENERGY INC.

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(In thousands)

(Unaudited)

 

     Three Months Ended
September 30		     Nine Months Ended
September 30		  
     2023     2022     2023     2022  

Revenues:

         

Oil revenue

    $ 178,041     $ 186,710     $ 448,064     $ 550,465  

Natural gas revenue

      9,859       30,925       24,600       65,290  

Natural gas liquids revenue

      5,134       7,774       13,273       22,521  

Turnkey revenue

      63,179       10,761       87,157       23,219  

Other revenue

      7,815       4,626       18,005       15,434  
  

 

 

    

 

 

    

 

 

    

 

 

  

Total revenues

      264,028       240,796       591,099       676,929  
  

 

 

    

 

 

    

 

 

    

 

 

  

Operating expenses:

         

Lease operating expense

      38,750       41,767       115,481       119,849  

Decommissioning cost of goods sold

      40,544       10,909       61,927       25,993  

Depletion, depreciation, and amortization

      56,343       66,152       155,261       173,006  

General and administrative expense

      11,810       3,479       27,314       11,744  

Insurance expense

      5,586       2,749       16,175       13,742  

Accretion expense

      127       3,848       8,488       12,002  

Other operating expense

      8,593       651       11,428       1,296  
  

 

 

    

 

 

    

 

 

    

 

 

  

Total operating expenses

      161,753       129,555       396,074       357,632  
  

 

 

    

 

 

    

 

 

    

 

 

  

Income from operations

      102,275       111,241       195,025       319,297  

Other income (expense), net:

         

Interest expense

      (3,574 )      (5,343 )      (5,769 )      (16,947 ) 

Commodity derivative expense

      (67,347 )      48,708       (56,562 )      (83,143 ) 

Other

      6,044       12       6,411       127  
  

 

 

    

 

 

    

 

 

    

 

 

  

Income before income taxes

      37,398       154,618       139,105       219,334  

Income tax expense

      (7,430 )      (34,449 )      (30,276 )      (48,563 ) 
  

 

 

    

 

 

    

 

 

    

 

 

  

Net income

    $ 29,968     $ 120,169     $ 108,829     $ 170,771  
  

 

 

    

 

 

    

 

 

    

 

 

  

See notes to condensed consolidated financial statements

 

2

QUARTERNORTH ENERGY INC.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)

(Unaudited)

 

     Nine Months Ended September 30  
     2023     2022  

Cash flows from operating activities:

     

Net income

    $ 108,829     $ 170,771  

Adjustments to reconcile net income to net cash provided by operating activities:

     

Amortization in interest expense

      1,265       1,142  

Accretion of asset retirement obligations

      8,488       12,002  

Depreciation, depletion, and amortization

      155,261       173,006  

Risk management activities

      53,571       (35,237 ) 

Deferred income tax expense

      1,357       40,951  

Gain on sale of assets

      (6,052 )      —    

Changes in operating assets and liabilities:

     

Accounts receivable and other assets

      (38,211 )      (39,190 ) 

Accounts payable and other liabilities

      (3,862 )      31,525  

Expenditures on asset retirement obligations, net

      (15,567 )      (25,525 ) 
  

 

 

    

 

 

  

Net cash provided by operating activities

      265,079       329,445  
  

 

 

    

 

 

  

Cash flows from investing activities:

     

Additions to property and equipment

      (156,688 )      (116,605 ) 

Changes in operating assets and liabilities associated with investing activities

      (15,766 )      23,527  

Acquisitions of proved properties

      —         240  

Investment in short-term investments

      —         (99,276 ) 

Proceeds from short-term investments

      60,297       —    

Investment in Fieldwood Mexico

      —         (4,108 ) 

Proceeds from sale of assets held for sale

      —         55,749  

Proceeds from sale of assets

      6,000       —    

Proceeds from sale of oil and gas properties

      28,815       10,629  
  

 

 

    

 

 

  

Net cash used in investing activities

      (77,342 )      (129,844 ) 
  

 

 

    

 

 

  

Cash flows from financing activities:

     

Repayment of first lien term loan

      (1,000 )      (60,000 ) 

Debt issuance costs

      (145 )      (807 ) 

Payment of finance lease

      (36 )      (1,154 ) 

Dividends paid

      (200,747 )      (54,645 ) 
  

 

 

    

 

 

  

Net cash used in financing activities

      (201,928 )      (116,606 ) 
  

 

 

    

 

 

  

Net increase (decrease) in cash and cash equivalents, including restricted cash

      (14,191 )      82,995  

Cash and cash equivalents, including restricted cash, beginning of period

      401,913       218,754  
  

 

 

    

 

 

  

Cash and cash equivalents, including restricted cash, end of period

    $ 387,722     $ 301,749  
  

 

 

    

 

 

  

See notes to condensed consolidated financial statements

 

3

QUARTERNORTH ENERGY INC.

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS’ EQUITY

(In thousands, except share amounts)

(Unaudited)

 

     Common Stock      Additional Paid-
In Capital		     Retained
Earnings
(Deficit)		     Total  
     Shares      Amount  

Balance, December 31, 2021

      6,973,765      $ 70      $ 995,695     $ 11,529     $ 1,007,294  

Issuance of common stock from exercise of warrants

      567,048        5        —         —         5  

Dividends to stockholders

      —          —          —         (54,645 )      (54,645 ) 

Measurement period adjustment

      —          —          (17,164 )      —         (17,164 ) 

Net income

      —          —          —         170,771       170,771  
  

 

 

     

 

 

     

 

 

    

 

 

    

 

 

  

Balance, September 30, 2022

      7,540,813      $ 75      $ 978,531     $ 127,655     $ 1,106,261  
  

 

 

     

 

 

     

 

 

    

 

 

    

 

 

  

Balance, December 31, 2022

      7,540,813      $ 75      $ 978,531     $ 205,674     $ 1,184,280  

Issuance of common stock from exercise of warrants

      348,872        4        —         —         4  

Dividends to stockholders

      —          —          —         (200,747 )      (200,747 ) 

Net income

      —          —          —         108,829       108,829  
  

 

 

     

 

 

     

 

 

    

 

 

    

 

 

  

Balance, September 30, 2023

      7,889,685      $ 79      $ 978,531     $ 113,756     $ 1,092,366  
  

 

 

     

 

 

     

 

 

    

 

 

    

 

 

  

 

     Common Stock      Additional Paid-
In Capital		     Retained
Earnings
(Deficit)		     Total  
     Shares      Amount  

Balance, June 30, 2022

      7,540,813      $ 75      $ 1,000,898     $ 32,131     $ 1,033,104  

Dividends to stockholders

      —          —          —         (24,645 )      (24,645 ) 

Measurement period adjustment

      —          —          (22,367 )      —         (22,367 ) 

Net income

      —          —          —         120,169       120,169  
  

 

 

     

 

 

     

 

 

    

 

 

    

 

 

  

Balance, September 30, 2022

      7,540,813      $ 75      $ 978,531     $ 127,655     $ 1,106,261  
  

 

 

     

 

 

     

 

 

    

 

 

    

 

 

  

Balance, June 30, 2023

      7,889,685      $ 79      $ 978,531     $ 87,372     $ 1,065,982  

Dividends to stockholders

      —          —          —         (3,584 )      (3,584 ) 

Net income

      —          —          —         29,968       29,968  
  

 

 

     

 

 

     

 

 

    

 

 

    

 

 

  

Balance, September 30, 2023

      7,889,685      $ 79      $ 978,531     $ 113,756     $ 1,092,366  
  

 

 

     

 

 

     

 

 

    

 

 

    

 

 

  

See notes to condensed consolidated financial statements

 

4

QUARTERNORTH ENERGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Except as noted within the context of each footnote disclosure, the dollar amounts presented in the tabular data within these footnote disclosures are in thousands of dollars.

Note 1—Basis of Presentation and Summary of Significant Accounting Policies

Description of Company

QuarterNorth Energy Inc. (“QuarterNorth”, “we”, “us”, “our” or “the Company”) was incorporated in Delaware on June 4, 2021, and amended as of July 16, 2021. On June 4, 2021, the Company formed four indirect wholly owned subsidiaries: QuarterNorth Energy Holding Inc.; QuarterNorth Energy Intermediate Inc.; QuarterNorth Energy LLC; and Mako Buyer 2 LLC. All four entities are Delaware corporations or limited liability companies and were formed in contemplation of the Credit Bid Acquisition (as defined herein).

On June 21, 2023, the Company formed QNE Finco LLC as a wholly owned subsidiary. QNE Finco LLC is a Delaware limited liability company, see Note 4—Debt for additional disclosures.

Business Operations and Strategy

QuarterNorth Energy Inc. (“QuarterNorth”, “we”, “us”, “our” or “the Company”) is an independent oil and natural gas producer with substantially all of its operations in the U.S. Gulf of Mexico (“GOM”). We commenced operations on August 27, 2021, when QuarterNorth Energy LLC purchased certain oil and natural gas properties (the “Credit Bid Acquisition”) from Fieldwood Energy Inc. and subsidiaries (collectively, “Fieldwood”) pursuant to a purchase and sale agreement. We are active in the exploration, operations, exploitation, development and acquisition of oil and gas properties.

We operate our business through ourselves and our consolidated subsidiaries, primarily through QuarterNorth Energy LLC, our main operating subsidiary, which owns all of our oil and gas properties and is operator of record for many of the properties.

Interim Financial Statements

The accompanying unaudited condensed consolidated financial statements have been prepared in accordance with U.S. generally accepted accounting principles (“GAAP”) for interim periods. Certain notes and other information have been condensed or omitted. In the opinion of management, all adjustments (including normal recurring accruals) considered necessary for a fair presentation have been incorporated.

These condensed consolidated financial statements should be read in conjunction with our audited consolidated financial statements as of and for the year ended December 31, 2022 and notes thereto. The results of operations for interim periods are not necessarily indicative of results for the entire year.

Certain prior year amounts have been reclassified for consistency with the current year presentation. These reclassifications had no effect on the reported balance sheet, results of operations, or cash flows.

Use of Estimates

The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosures of contingent assets and liabilities as of the date of the financial statements and the reported amounts of revenues and expenses during the period. Actual results could differ materially from estimated amounts.

In preparing the accompanying condensed consolidated financial statements, we have reviewed, as determined necessary by management, events that have occurred after September 30, 2023, up until November 13, 2023, the date the condensed consolidated financial statements are available to be issued.

 

5

Accounting Standards Recently Adopted

On January 1, 2023, we adopted Accounting Standards Update (“ASU”) 2016-13 Financial Instruments – Credit losses (Topic 326): Measurement of credit losses on financial instruments. ASU 2016-13 amended Accounting Standards Codification (“ASC”) Topic 326, which changed the recognition of credit losses from an incurred or probable impairment methodology to a current expected credit loss (“CECL”) methodology. The CECL methodology is applicable to the measurement of credit losses related to our trade receivables, among other financial assets. The adoption of this guidance did not have a material effect on the Company’s Consolidated Financial Statements or related disclosures.

Note 2— Supplemental Disclosures to the Balance Sheet and the Statement of Cash Flows

The following tables show additional balance sheet information as of the dates indicated below:

 

     September 30,
2023		      December 31,
2022		  

Accounts receivable

      

Operating revenues

    $ 83,520      $ 61,954  

Joint interest receivables, net

      64,458        62,461  

Other

      31,511        19,645  
  

 

 

     

 

 

  
   $ 179,489      $ 144,060  
  

 

 

     

 

 

  

Other current assets

      

Prepaids and other

    $ 13,606      $ 11,011  

Decommissioning work-in-progress

      25,284        27,467  

Other

      1,602        —    
  

 

 

     

 

 

  
   $ 40,492      $ 38,478  
  

 

 

     

 

 

  

Other assets

      

Right-of-use asset

    $ 5,836      $ 5,967  

Other

      868        1,148  
  

 

 

     

 

 

  
   $ 6,704      $ 7,115  
  

 

 

     

 

 

  

 

     September 30,
2023		      December 31,
2022		  

Accrued liabilities

      

Production expense

    $ 19,952      $ 22,484  

Capital/decommissioning

      38,975        50,219  

Owner advances

      5,937        21,050  

Accrued royalties

      14,182        11,051  

Accrued taxes

      22,677        5,793  

Other

      20,957        22,771  
  

 

 

     

 

 

  
   $ 122,680      $ 133,368  
  

 

 

     

 

 

  

Other current liabilities

      

Compressor lease

      1,718      $ 1,327  

Lease obligation

      1,225        966  

Plug and abandonment obligation

      —          4,038  

Other

      —          10,666  
  

 

 

     

 

 

  
   $ 2,943      $ 16,997  
  

 

 

     

 

 

  

Other long-term liabilities

      

Lease obligation

    $ 4,848      $ 4,501  

Compressor lease

      —          1,378  

Other

      —          1,067  
  

 

 

     

 

 

  
   $ 4,848      $ 6,946  
  

 

 

     

 

 

  

 

6

Supplemental Cash Flow Information

Supplemental disclosures to the statement of cash flows are presented below:

 

     Nine Months Ended
September 30		  
     2023      2022  

Supplemental disclosures of cash payments (receipts):

      

Interest paid, net of amounts capitalized

    $ 18,243      $ 19,972  

Income taxes paid

      10,958        6,366  

The following table provides a summary of the components of the beginning and ending balances of cash and cash equivalents, including restricted cash, shown in our condensed consolidated statements of cash flows.

 

     September 30,
2023		      December 31,
2022		      September 30,
2022		      December 31,
2021		  

Cash

    $ 387,722      $ 400,816      $ 300,950      $ 218,512  

Restricted cash(1)

      —          1,097        799        242  
  

 

 

     

 

 

     

 

 

     

 

 

  
   $ 387,722      $ 401,913      $ 301,749      $ 218,754  
  

 

 

     

 

 

     

 

 

     

 

 

  

 

(1)

Our restricted cash serves as collateral for certain of our obligations. These restricted funds are generally invested in interest-bearing accounts.

The following table presents supplemental cash flow information related to our leases:

 

     Nine Months Ended
September 30,		  
     2023      2022  

Operating cash outflow from financing leases

    $ 53      $ 161  

Financing cash outflow from financing leases

      36        190  

Operating cash outflows from operating leases

      115        1,793  

Note 3—Property, Plant and Equipment

Oil and natural gas properties as of the dates indicated are shown below:

 

     September 30,
2023		      December 31,
2022		  

Proved properties

    $ 1,301,937      $ 1,174,296  

Accumulated depreciation, depletion, and amortization

      (443,200 )       (289,500 ) 
  

 

 

     

 

 

  

Proved properties, net

    $ 858,737      $ 884,796  
  

 

 

     

 

 

  

Unproved properties, not subject to amortization

    $ 181,384      $ 183,779  
  

 

 

     

 

 

  

At September 30, 2023, the Company’s ceiling test computation was based on SEC pricing of $78.54 per Bbl of oil, $3.44 per Mcf of natural gas and $31.35 per Bbl of NGLs. Using these prices, the Company’s net book value of proved oil and natural gas properties as of September 30, 2023 was below the current ceiling and did not result in any ceiling test write-down during the period.

 

7

Note 4—Debt

We had the following debt outstanding as of the dates indicated below:

 

     September 30,
2023		      December 31,
2022		  

First Lien Term Loan, variable rate, due 2023

    $ —        $ 1,000  

Second Lien Term Loan, variable rate, due 2026

      185,000        185,000  

Less: unamortized discount

      (2,152 )       (2,705 ) 

Less: unamortized debt issuance costs

      (788 )       (1,356 ) 
  

 

 

     

 

 

  

Total debt, net

      182,060        181,939  

Less current portion

      —          (1,000 ) 
  

 

 

     

 

 

  

Total long-term debt, net

    $ 182,060      $ 180,939  
  

 

 

     

 

 

  

The First Lien Term Loan (“FLTL”) agreement was amended on June 29, 2023. The amendment simplifies the administrative burden of carrying the loan while continuing the first lien collateral position of the hedge counterparties. QNE FinCo LLC, acquired the existing lenders’ rights and obligations in their capacity as the lender under the agreement and Cantor Fitzgerald Securities was appointed as the successor administrative agent and collateral agent.

For contractual purposes, the FLTL credit agreement remains outstanding, but for GAAP purposes the debt is extinguished because the lender is an affiliate of the borrower. Previously unamortized debt issuance costs and the cost of the amendment were charged to interest expense.

As of September 30, 2023, QuarterNorth was in compliance with all covenants under its debt agreements.

Note 5—Risk Management Activities

Our principal market risks are our exposure to changes in commodity prices, particularly to the prices of crude oil and natural gas, and nonperformance by our counterparties.

Our revenues are derived principally from the sale of crude oil and natural gas. The prices of crude oil and natural gas are subject to market fluctuations in response to changes in supply, demand, market uncertainty and a variety of additional factors beyond our control. We monitor these risks and enter into commodity derivative contracts to secure a commodity price for a portion of our expected future production that is acceptable at the time of the transaction. We do not enter into derivative contracts for speculative purposes.

The counterparties to our derivative contracts include financial institutions. Our derivative contracts expose us to market and credit risks, and which may, at times, be concentrated with certain counterparties or groups of counterparties. The credit worthiness of our counterparties is subject to continual review. We monitor the nonperformance risk of ourselves and of each of our counterparties and assesses the possibility of whether each counterparty to the derivative contract would default by failing to make any contractually required payments as scheduled in the derivative instrument in determining the fair value.

Our commodity derivative contracts may include, but are not limited to, “swap”, “collar” and “put” positions. Commodity derivative contracts outstanding as of September 30, 2023 are shown below:

 

Crude Oil (WTI Index)

  
     Swaps      Puts      Swaps with Solid Put      Collars  

Period

    Volume
(Bopd)		      Average
$/Bbl		      Volume
(Bopd)		      Average
$/Bbl		      Volume
(Bopd)		      Average
$/Bbl		      Put Strike
$/Bbl		      Volume
(Bbl/d)		      Swap
$/Bbl		      Call
$/Bbl		  

4th Qtr 2023

      8,000      $ 72.41        2,000      $ 100.00        1,000      $ 72.20      $ 60.00        2,000      $ 60.00      $ 77.45  

1st Qtr 2024

      9,000        72.18        —          —          1,000        72.20        60.00        —          —          —    

2nd Qtr 2024

      6,000        70.10        2,000        70.00        1,000        72.20        60.00        —          —          —    

3rd Qtr 2024

      6,000        70.10        2,000        70.00        1,000        72.20        60.00        —          —          —    

4th Qtr 2024

      5,000        70.10        2,000        70.00        1,000        72.20        60.00        —          —          —    

1st Qtr 2025

      4,000        70.62        —          —          —          —          —          —          —          —    

2nd Qtr 2025

      4,000        71.58        —          —          —          —          —          —          —          —    

 

Natural Gas (Henry Hub Index)

  
     Puts  

Period

    Volume
(MMbtu/d)		      Average
$/MMbtu		  

4th Qtr 2023

      13,660      $ 2.90  

1st Qtr 2024

      13,660        2.90  

2nd Qtr 2024

      13,660        2.90  

3rd Qtr 2024

      13,660        2.90  

 

8

With swaps, we receive an agreed upon fixed price for a specified notional quantity of oil or natural gas and we pay the counterparty a floating price for that same quantity based upon published index prices. Index pricing used is based on grades that we believe best represent the revenue we receive for our underlying physical production. Our swap contracts provide us with protection if market prices decline below the contracted price. If market prices rise above the contracted prices, we will receive less revenue than in the absence of swaps.

Collars contain a fixed floor price and a fixed ceiling price. If the published index price exceeds the ceiling price or falls below the floor price, we receive the fixed price and pay the index price. If the index price is between the floor and ceiling prices, no payments are due from either party.

A put option gives the owner the right, but not the obligation, to sell the underlying commodity at a specified price (“strike price”) within a specific time period. Depending on market conditions, strike prices, and the value of the contracts, we may, at times, purchase put options, which require us to pay premiums. The premiums may be paid when the option is purchased, or deferred until each monthly settlement occurs. The ownership of put options is consistent with our derivative strategy inasmuch as the value of the puts will increase as commodity prices decline, helping to offset the cash flow impact of a decline in realized prices for the underlying commodity. However, if the underlying commodity increases in value, there is a risk that the put option will expire worthless, in which case the net premiums paid would be recognized as a loss.

Counterparty swaptions. Our outstanding swaption agreements provide the counterparty a one-time option to enter into a swap agreement with us on the swaption exercise date. At September 30, 2023, our outstanding swaptions comprised a one-time counterparty option on March 28, 2024 for 2,000 barrels per day of WTI swaps for the period from April 1, 2024 through December 31, 2024 at a price of $72.00 per barrel.

The following reflects the fair values of our derivative contracts, including the fair value of option premiums, and the line items where they appear on our condensed consolidated balance sheets:

 

    

Balance Sheet Location

    September 30,
2023		      December 31,
2022		  

Commodity derivatives

   

Current assets

    $ —        $ 8,440  
     

 

 

     

 

 

  
  

Total

    $ —        $ 8,440  
     

 

 

     

 

 

  

Commodity derivatives

   

Current liabilities

    $ 43,711      $ 8,156  

Commodity derivatives

   

Long-term liabilities

      9,576        —    
     

 

 

     

 

 

  
  

Total

    $ 53,287      $ 8,156  
     

 

 

     

 

 

  

The following reflects the effect of netting agreements with counterparties on the balance sheet presentation of our derivative contracts:

 

     September 30,
2023		      December 31,
2022		  

Assets:

      

Current

    $ 12      $ 12,503  

Noncurrent

      65        —    
  

 

 

     

 

 

  

Total gross fair value

      77        12,503  

Less: counterparty offset

      (77 )       (4,063 ) 
  

 

 

     

 

 

  

Total net fair value

    $ —          8,440  
  

 

 

     

 

 

  

Liabilities:

      

Current

    $ 43,723      $ 12,219  

Noncurrent

      9,641        —    
  

 

 

     

 

 

  

Total gross fair value

      53,364        12,219  

Less: counterparty offset

      (77 )       (4,063 ) 
  

 

 

     

 

 

  

Total net fair value

    $ 53,287      $ 8,156  
  

 

 

     

 

 

  

 

9

See Note 6—Fair Value Measurements for additional disclosures related to derivative contracts.

Note 6—Fair Value Measurements

Derivative Contracts

Our commodity derivative contracts are presented in our condensed consolidated financial statements at fair value. These contracts consist of over-the-counter transactions, which are not traded on a public exchange.

The fair values of our commodity derivative contracts are determined based on inputs that are readily available in public markets or can be derived from information available in publicly quoted markets. Therefore, we have categorized these contracts as Level 2.

We have consistently applied these valuation techniques and believe we have obtained the most accurate information available for the types of derivative contracts we hold.

The following table sets forth, by level within the fair value hierarchy, our derivative assets and liabilities measured at fair value on a recurring basis for the dates indicated below:

 

As of September 30, 2023

  
     Total      Level 1      Level 2      Level 3  

Assets

            

Commodity derivative contracts

    $ —        $ —        $ —        $ —    
  

 

 

     

 

 

     

 

 

     

 

 

  
   $ —        $ —        $ —        $ —    
  

 

 

     

 

 

     

 

 

     

 

 

  

Liabilities

            

Commodity derivative contracts

    $ 53,287      $ —        $ 53,287      $ —    
  

 

 

     

 

 

     

 

 

     

 

 

  
   $ 53,287      $ —        $ 53,287      $ —    
  

 

 

     

 

 

     

 

 

     

 

 

  

 

As of December 31, 2022

  
     Total      Level 1      Level 2      Level 3  

Assets

            

Commodity derivative contracts

    $ 8,440      $ —        $ 8,440      $ —    
  

 

 

     

 

 

     

 

 

     

 

 

  
   $ 8,440      $ —        $ 8,440      $ —    
  

 

 

     

 

 

     

 

 

     

 

 

  

Liabilities

            

Commodity derivative contracts

    $ 8,156      $ —        $ 8,156      $ —    
  

 

 

     

 

 

     

 

 

     

 

 

  
   $ 8,156      $ —        $ 8,156      $ —    
  

 

 

     

 

 

     

 

 

     

 

 

  

These derivative assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of the fair value assets and liabilities and their placement within the fair value hierarchy levels.

Debt

We use a market approach to determine the fair value of our debt using estimates provided by an independent financial data services firm (a Level 2 fair value measurement). The carrying amount and fair value of our debt is shown in the following table.

 

10

     September 30, 2023      December 31, 2022  
     Carrying
Amount		      Fair
Value		      Carrying
Amount		      Fair
Value		  

First Lien Term Loan

    $ —        $ —        $ 1,000      $ 1,000  

Second Lien Term Loan

      182,060        185,000        180,939        185,000  
  

 

 

     

 

 

     

 

 

     

 

 

  
     $182,060      $185,000      $181,939      $186,000  
  

 

 

     

 

 

     

 

 

     

 

 

  

We believe the carrying values of cash, accounts receivable, accounts payable, and accrued liabilities included in the accompanying condensed consolidated balance sheets approximate their fair value as of September 30, 2023 and December 31, 2022.

Asset Retirement Obligations

We follow the provisions of ASC 820, for nonfinancial assets and liabilities measured at fair value on a non-recurring basis. These provisions apply to the Company’s initial recognition of asset retirement obligations for which fair value is used. The asset retirement obligation estimates are derived from historical costs and management’s expectation of future cost environments; and therefore, the Company has designated these liabilities as Level 3.

Note 7—Commitments and Contingencies

Legal Proceedings. From time to time, we may be involved in litigation arising out of the normal course of our business. We maintain insurance coverage applicable to certain litigation, which, subject to applicable deductibles, may reduce our actual liability under any litigation. In management’s opinion, we are not involved in any litigation, the outcome of which would have a material effect on our consolidated financial position, results of operations, or liquidity.

Firm Commitment

On November 3, 2023, we entered into a rig contract with a commitment of approximately $33 million and which is expected to be utilized in 2024.

Note 8—Income Taxes

Our effective tax rates for the three-month periods ended September 30, 2023 and 2022 were 19.9 percent and 22.0 percent. For the nine-month periods ended September 30, 2023 and 2022, the effective tax rates were 21.8 percent and 22.0 percent. The estimated annual effective tax rate differs from the federal tax rate of 21.0 percent due to state income taxes and the impact of certain nondeductible items.

Note 9 – Supplemental Consolidating Financial Information

QuarterNorth Energy Holding Inc. is the borrower under the loans described in Note 4—Debt. The following condensed consolidating financial statements shows the accounts of the parent company, QuarterNorth Energy Inc. on a standalone basis, the accounts of the borrower and its consolidated subsidiaries, and intercompany eliminations to arrive at the consolidated statements of the Company.

 

11

QUARTERNORTH ENERGY INC.

CONDENSED CONSOLIDATING BALANCE SHEET

AS OF SEPTEMBER 30, 2023

(In thousands)

(Unaudited)

 

     Quarter North
Energy Inc.		     Quarter North
Energy Holding
Inc.		      Intercompany
Eliminations		     Consolidated  

Assets

          

Current assets:

          

Cash and cash equivalents

    $ —       $ 387,722      $ —       $ 387,722  

Accounts receivable and other assets

      —         269,147        —         269,147  
  

 

 

    

 

 

     

 

 

    

 

 

  

Total current assets

      —         656,869        —         656,869  
  

 

 

    

 

 

     

 

 

    

 

 

  

Property and equipment net

      —         1,042,788        —         1,042,788  

Investments in subsidiaries

      1,093,046       —          (1,093,046 )      —    

Advances to (from) subsidiaries

      (1,692 )      1,692        —         —    

Other assets

      1,164       6,704        (1,164 )      6,704  
  

 

 

    

 

 

     

 

 

    

 

 

  

Total assets

    $ 1,092,518     $ 1,708,053      $ (1,094,210 )    $ 1,706,361  
  

 

 

    

 

 

     

 

 

    

 

 

  

Liabilities and Stockholders’ Equity

          

Current liabilities:

          

Accounts payable and accrued liabilities

    $ —       $ 179,540      $ —       $ 179,540  

Current maturities of debt

      —         1,000        (1,000 )      —    

Other current liabilities

      —         57,243        (12 )      57,231  
  

 

 

    

 

 

     

 

 

    

 

 

  

Total current liabilities

      —         237,783        (1,012 )      236,771  
  

 

 

    

 

 

     

 

 

    

 

 

  

Long-term debt

      —         182,060        —         182,060  

Asset retirement obligations

      —         112,732        —         112,732  

Other long-term liabilities

      —         82,432        —         82,432  
  

 

 

    

 

 

     

 

 

    

 

 

  

Total liabilities

      —         615,007        (1,012 )      613,995  
  

 

 

    

 

 

     

 

 

    

 

 

  

Stockholders’ equity

      1,092,518       1,093,046        (1,093,198 )      1,092,366  
  

 

 

    

 

 

     

 

 

    

 

 

  

Total liabilities and stockholders’ equity

    $ 1,092,518     $ 1,708,053      $ (1,094,210 )    $ 1,706,361  
  

 

 

    

 

 

     

 

 

    

 

 

  

 

12

QUARTERNORTH ENERGY INC.

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

(In thousands)

(Unaudited)

 

                                                                                                               

Nine Months Ending

September 30, 2023

    Quarter North
Energy Inc.		     Quarter North
Energy Holding
Inc.		     Intercompany
Eliminations		     Consolidated  

Revenues

         

Total revenues

    $ —         591,099     $ —       $ 591,099  
  

 

 

    

 

 

    

 

 

    

 

 

  

Operating expenses

         

Lease operating expense

      —         115,481       —         115,481  

Depletion, depreciation and amortization

      —         155,261       —         155,261  

General and administrative expense

      692       26,622       —         27,314  

Other operating expense

      —         98,018       —         98,018  
  

 

 

    

 

 

    

 

 

    

 

 

  

Total operating expense

      692       395,382       —         396,074  
  

 

 

    

 

 

    

 

 

    

 

 

  

Income (loss) from operations

      (692 )      195,717       —         195,025  

Other income (expense), net

         

Equity in earnings of subsidiaries

      109,673       —         (109,673 )      —    

Other

      —         (55,920 )      —         (55,920 ) 
  

 

 

    

 

 

    

 

 

    

 

 

  

Income before income taxes

      108,981       139,797       (109,673 )      139,105  

Income tax expense

      (152 )      (30,124 )      —         (30,276 ) 
  

 

 

    

 

 

    

 

 

    

 

 

  

Net income

    $ 108,829     $ 109,673     $ (109,673 )    $ 108,829  
  

 

 

    

 

 

    

 

 

    

 

 

  

 

                                                                                                               

Three Months Ending

September 30, 2023

    Quarter North
Energy Inc.		     Quarter North
Energy Holding
Inc.		     Intercompany
Eliminations		     Consolidated  

Revenues

         

Total revenues

    $ —       $ 264,028     $ —       $ 264,028  
  

 

 

    

 

 

    

 

 

    

 

 

  

Operating expenses

         

Lease operating expense

      —         38,750       —         38,750  

Depletion, depreciation and amortization

      —         56,343       —         56,343  

General and administrative expense

      441       11,369       —         11,810  

Other operating expense

      —         54,850       —         54,850  
  

 

 

    

 

 

    

 

 

    

 

 

  

Total operating expense

      441       161,312       —         161,753  
  

 

 

    

 

 

    

 

 

    

 

 

  

Income (loss) from operations

      (441 )      102,716         102,275  

Other income (expense), net

         

Equity in earnings of subsidiaries

      30,506       —         (30,506 )      —    

Other

      —         (64,877 )      —         (64,877 ) 
  

 

 

    

 

 

    

 

 

    

 

 

  

Income before income taxes

      30,065       37,839       (30,506 )      37,398  

Income tax expense

      (97 )      (7,333 )      —         (7,430 ) 
  

 

 

    

 

 

    

 

 

    

 

 

  

Net income

    $ 29,968     $ 30,506     $ (30,506 )    $ 29,968  
  

 

 

    

 

 

    

 

 

    

 

 

  

 

13

QUARTERNORTH ENERGY INC.

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

(In thousands)

(Unaudited)

 

                                                                                                               

Nine Months Ending

September 30, 2022

    Quarter North
Energy Inc.		     Quarter North
Energy Holding
Inc.		     Intercompany
Eliminations		     Consolidated  

Revenues

         

Total revenues

    $ —       $ 676,929     $ —       $ 676,929  
  

 

 

    

 

 

    

 

 

    

 

 

  

Operating expenses

         

Lease operating expense

      —         119,849       —         119,849  

Depletion, depreciation and amortization

      —         173,006       —         173,006  

General and administrative expense

      376       11,368       —         11,744  

Other operating expense

      —         53,033       —         53,033  
  

 

 

    

 

 

    

 

 

    

 

 

  

Total operating expense

      376       357,256       —         357,632  
  

 

 

    

 

 

    

 

 

    

 

 

  

Income (loss) from operations

      (376 )      319,673       —         319,297  

Other income (expense), net

         

Equity in earnings of subsidiaries

      171,064       —         (171,064 )      —    

Other

      —         (99,963 )      —         (99,963 ) 
  

 

 

    

 

 

    

 

 

    

 

 

  

Income before income taxes

      170,688       219,710       (171,064 )      219,334  

Income tax (expense) benefit

      83       (48,646 )      —         (48,563 ) 
  

 

 

    

 

 

    

 

 

    

 

 

  

Net income

    $ 170,771     $ 171,064     $ (171,064 )    $ 170,771  
  

 

 

    

 

 

    

 

 

    

 

 

  

 

                                                                                                               

Three Months Ending

September 30, 2022

    Quarter North
Energy Inc.		     Quarter North
Energy Holding
Inc.		     Intercompany
Eliminations		     Consolidated  

Revenues

         

Total revenues

    $ —       $ 240,796     $ —       $ 240,796  
  

 

 

    

 

 

    

 

 

    

 

 

  

Operating expenses

         

Lease operating expense

      —         41,767       —         41,767  

Depletion, depreciation and amortization

      —         66,152       —         66,152  

General and administrative expense

      125       3,354       —         3,479  

Other operating expense

      —         18,157       —         18,157  
  

 

 

    

 

 

    

 

 

    

 

 

  

Total operating expense

      125       129,430       —         129,555  
  

 

 

    

 

 

    

 

 

    

 

 

  

Income (loss) from operations

      (125 )      111,366       —         111,241  

Other income (expense), net

         

Equity in earnings of subsidiaries

      120,267       —         (120,267 )      —    

Other

      —         43,377       —         43,377  
  

 

 

    

 

 

    

 

 

    

 

 

  

Income before income taxes

      120,142       154,743       (120,267 )      154,618  

Income tax (expense) benefit

      27       (34,476 )      —         (34,449 ) 
  

 

 

    

 

 

    

 

 

    

 

 

  

Net loss

    $ 120,169     $ 120,267     $ (120,267 )    $ 120,169  
  

 

 

    

 

 

    

 

 

    

 

 

  

 

14

Exhibit 99.7

 

LOGO         
   EXECUTIVE CHAIRMAN    CHIEF EXECUTIVE OFFICER    EXECUTIVE COMMITTEE
   C.H. (SCOTT) REES III    RICHARD B. TALLEY, JR.    ROBERT C. BARG
   DANNY D. SIMMONS    PRESIDENT & COO    P. SCOTT FROST
      ERIC J. STEVENS    JOHN G. HATTNER
         JOSEPH J. SPELLMAN

 

January 15, 2024

Mr. Jason Smith

QuarterNorth Energy LLC

Suite 800

3737 Buffalo Speedway

Houston, Texas 77098

Dear Mr. Smith:

In accordance with your request, we have estimated the proved reserves and future revenue, as of December 31, 2022, to the QuarterNorth Energy LLC (QNE) interest in certain oil and gas properties located in state and federal waters in the Gulf of Mexico. It is our understanding that QNE plans to furnish this reserves report to a company considering purchasing the QNE interest. We completed our evaluation on or about the date of this letter. It is our understanding that the proved reserves estimated in this report constitute all of the proved reserves owned by QNE. 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 QNE interest in these properties, as of December 31, 2022, to be:

 

     Net Reserves      Future Net Revenue (M$)  

Category

    Oil
(MBBL)		      NGL
(MBBL)		      Gas
(MMCF)		      Total      Present Worth
at 10%		  

Proved Developed Producing

      19,302.5        1,721.7        32,255.8        1,754,863.1        1,455,721.5  

Proved Developed Non-Producing

      5,888.1        976.6        23,113.1        550,407.1        342,218.6  

Proved Undeveloped

      22,871.9        2,744.6        56,904.2        1,704,194.9        1,095,789.6  

Proved Abandonment Costs

      0.0        0.0        0.0        -303,469.7        -130,764.4  
  

 

 

     

 

 

     

 

 

     

 

 

     

 

 

  

Total Proved

      48,062.4        5,442.9        112,273.1        3,705,995.3        2,762,964.7  

Totals may not add because of rounding.

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 QNE’s share of the gross (100 percent) revenue from the properties prior to any deductions. Future net revenue is after deductions for QNE’s share of production taxes, 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.

 

 

 

2l00 ROSS AVENUE, SUITE 2200 • DALLAS TEXAS 75201 • PH:214-969-5401 • FAX 214-969-5411    info@nsai-petro.com
130l McKINNEY STREET, SUITE 3200 • HOUSON, TEXAS 77010 • PH 713-654-4950 • FAX 713-654-4951-654-4951    netherlandsewell.com

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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 2022. For oil and NGL volumes, the average West Texas Intermediate spot price of $94.14 per barrel is adjusted by field for quality, transportation fees, and market differentials. For gas volumes, the average Henry Hub spot price of $6.357 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 $94.64 per barrel of oil, $33.21 per barrel of NGL, and $6.680 per MCF of gas.

Operating costs used in this report are based on operating expense records of QNE. For the nonoperated properties, these costs include production handling agreement (PHA) fees, the per-well overhead expenses allowed under joint operating agreements, and other estimates of costs to be incurred at and below the district and field levels. As requested, operating costs for the operated properties include PHA fees, direct lease- and field-level costs, and QNE’s estimate of the portion of its headquarters general and administrative overhead expenses necessary to operate the properties. Also as requested, operating costs used in this report for Green Canyon 65 Field have been reduced by expenditure reimbursements, as allowed under the PHAs. Operating costs have been divided into field-level costs, per-well costs, and per-unit-of-production costs. As requested, the field-level costs are allocated by month among the proved reserves categories. Operating costs are not escalated for inflation.

Capital costs used in this report were provided by QNE 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 QNE’s estimates of the costs to abandon the wells, platforms, and production facilities, net of any salvage value. 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 QNE 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 QNE 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.

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 QNE, 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

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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. A substantial portion of these reserves are for behind-pipe zones, non-producing zones, and undeveloped locations; such reserves are based on estimates of reservoir volumes and recovery efficiencies along with analogy to properties with similar geologic and reservoir characteristics. 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 QNE, 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. Kyle B. Haft, a Licensed Professional Engineer in the State of Texas, has been practicing consulting petroleum engineering at NSAI since 2019 and has over 7 years of prior industry experience. Edward C. Roy III, a Licensed Professional Geoscientist in the State of Texas, has been practicing consulting petroleum geoscience at NSAI since 2008 and has over 11 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/ Richard B. Talley, Jr.

 

Richard B. Talley, Jr., P.E.

 

Chief Executive Officer

 

By:   /s/ Kyle B. Haft   LOGO     By:   /s/ Edward C. Roy III   LOGO
 

Kyle B. Haft, P.E. 128929

Petroleum Engineer

      

Edward C. Roy III, P.G. 2364

Vice President

Date Signed: January 15, 2024     Date Signed: January 15, 2024
KBH: DMN      

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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

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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

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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

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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

 

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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

LOGO

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

Exhibit 99.8

 

LOGO    EXECUTIVE CHAIRMAN    CHIEF EXECUTIVE OFFICER    EXECUTIVE COMMITTEE
   C.H. (SCOTT) REES III    RICHARD B. TALLEY, JR.    ROBERT C. BARG
   DANNY D. SIMMONS    PRESIDENT & COO    P. SCOTT FROST
      ERIC J. STEVENS    JOHN G. HATTNER
         JOSEPH J. SPELLMAN

 

 

January 15, 2024

Mr. Jason Smith

QuarterNorth Energy LLC

Suite 800

3737 Buffalo Speedway

Houston, Texas 77098

Dear Mr. Smith:

In accordance with your request, we have estimated the proved reserves and future revenue, as of September 30, 2023, to the QuarterNorth Energy LLC (QNE) interest in certain oil and gas properties located in federal waters in the Gulf of Mexico. It is our understanding that QNE plans to furnish this reserves report to a company considering purchasing the QNE interest. We completed our evaluation on or about the date of this letter. It is our understanding that the proved reserves estimated in this report constitute all of the proved reserves owned by QNE. 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 QNE interest in these properties, as of September 30, 2023, to be:

 

     Net Reserves      Future Net Revenue (M$)  

Category

    Oil
(MBBL)		      NGL
(MBBL)		      Gas
(MMCF)		      Total      Present Worth
at 10%		  

Proved Developed Producing

      24,276.9        2,624.2        42,558.1        1,567,814.2        1,294,077.7  

Proved Developed Non-Producing

      5,525.5        953.6        20,452.4        299,217.0        193,488.7  

Proved Undeveloped

      15,713.9        2,072.9        44,678.3        711,909.8        362,095.2  

Proved Abandonment Costs

      0.0        0.0        0.0        -302,700.6        -124,130.2  
  

 

 

     

 

 

     

 

 

     

 

 

     

 

 

  

Total Proved

      45,516.3        5,650.8        107,688.8        2,276,240.4        1,725,491.4  

Totals may not add because of rounding.

               

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 QNE’s share of the gross (100 percent) revenue from the properties prior to any deductions. Future net revenue is after deductions for QNE’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.

 

 

2l00 ROSS AVENUE, SUITE 2200 • DALLAS TEXAS 75201 • PH: 214-969-5401 • FAX 214-969-5411    info@nsai-petro.com
l30l McKINNEY STREET, SUITE 3200 • HOUSTON, TEXAS 77010 • PH 713-654-4950 • FAX 713-654-4951    netherlandsewell.com

LOGO

 

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 October 2022 through September 2023. For oil and NGL volumes, the average West Texas Intermediate spot price of $78.53 per barrel is adjusted by field for quality and market differentials. For gas volumes, the average Henry Hub spot price of $3.419 per MMBTU is adjusted by field for energy content 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 $79.04 per barrel of oil, $18.78 per barrel of NGL, and $3.420 per MCF of gas.

Operating costs used in this report are based on operating expense records of QNE. For the nonoperated properties, these costs include production handling agreement (PHA) fees, transportation fees, the per-well overhead expenses allowed under joint operating agreements, and other estimates of costs to be incurred at and below the district and field levels. As requested, operating costs for the operated properties include PHA fees, transportation fees, direct lease- and field-level costs, and QNE’s estimate of the portion of its headquarters general and administrative overhead expenses necessary to operate the properties. Also as requested, operating costs used in this report for Green Canyon 65 Field have been reduced by expenditure reimbursements, as allowed under the PHAs. Operating costs have been divided into field-level costs, per-well costs, and per-unit-of-production costs. As requested, the field-level costs are allocated by month among the proved reserves categories. Operating costs are not escalated for inflation.

Capital costs used in this report were provided by QNE 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 QNE’s estimates of the costs to abandon the wells, platforms, and production facilities, net of any salvage value. 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 QNE 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 QNE 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.

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 QNE, 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.    

LOGO

 

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. A substantial portion of these reserves are for behind-pipe zones, non-producing zones, and undeveloped locations; such reserves are based on estimates of reservoir volumes and recovery efficiencies along with analogy to properties with similar geologic and reservoir characteristics. 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 QNE, 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. Kyle B. Haft, a Licensed Professional Engineer in the State of Texas, has been practicing consulting petroleum engineering at NSAI since 2019 and has over 7 years of prior industry experience. Edward C. Roy III, a Licensed Professional Geoscientist in the State of Texas, has been practicing consulting petroleum geoscience at NSAI since 2008 and has over 11 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/ Richard B. Talley, Jr.
 

Richard B. Talley, Jr., P.E.

Chief Executive Officer

 

By:   /s/ Kyle B. Haft   LOGO     By:   /s/ Edward C. Roy III   LOGO
 

Kyle B. Haft, P.E. 128929

Petroleum Engineer

      

Edward C. Roy III, P.G. 2364

Vice President

Date Signed: January 15, 2024     Date Signed: January 15, 2024
KBH:DMN      

LOGO

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

LOGO

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

LOGO

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

LOGO

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

LOGO

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

LOGO

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

v3.23.4
Document and Entity Information
Jan. 17, 2024
Cover [Abstract]  
Amendment Flag false
Entity Central Index Key 0001724965
Document Type 8-K
Document Period End Date Jan. 17, 2024
Entity Registrant Name TALOS ENERGY INC.
Entity Incorporation State Country Code DE
Entity File Number 001-38497
Entity Tax Identification Number 82-3532642
Entity Address, Address Line One 333 Clay Street
Entity Address, Address Line Two Suite 3300
Entity Address, City or Town Houston
Entity Address, State or Province TX
Entity Address, Postal Zip Code 77002
City Area Code (713)
Local Phone Number 328-3000
Written Communications false
Soliciting Material false
Pre Commencement Tender Offer false
Pre Commencement Issuer Tender Offer false
Security 12b Title Common Stock
Trading Symbol TALO
Security Exchange Name NYSE
Entity Emerging Growth Company false
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