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): September 19, 2023
PERMIAN RESOURCES CORPORATION
(Exact Name of Registrant as Specified in Charter)
Delaware | 001-37697 | 47-5381253 | ||
(State or other jurisdiction of incorporation) |
(Commission File Number) |
(I.R.S. Employer Identification Number) |
300 N. Marienfeld St., Suite 1000
Midland, Texas 79701
(Address of Principal Executive Offices) (Zip Code)
(432) 695-4222
(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 |
Name of each exchange |
||
Class A Common Stock, par value $0.0001 per share | PR | The New York Stock Exchange |
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. ☐
Item 7.01. | Regulation FD Disclosure. |
On September 19, 2023, Permian Resources Corporation (the “Company” or “Permian Resources”) issued a press release announcing the commencement of an underwritten public offering of its Class A Common Stock, par value $0.0001 per share, by certain of its stockholders. 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 Securities Exchange Act of 1934 (as amended, 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 of 1933, as amended (the “Securities Act”), or the Exchange Act.
Item 8.01 | Other Events. |
In connection with the underwritten public offering referred to in Item 7.01 above, the Company provided certain additional disclosures to investors, including to the effect that (i) the Company’s board has fixed the close of business on September 20, 2023 as the record date for the determination of the Company’s stockholders entitled to receive notice of, and to vote at, the Company’s special meeting (or any adjournments or postponements thereof) of the Company’s stockholders relating to the previously announced merger with Earthstone Energy, Inc., and (ii) such special meeting will be held on October 30, 2023 at 10:00 a.m., Central Time, at the Petroleum Club of Midland located at 501 West Wall Street, Midland, Texas 79701.
In addition, this Item 8.01 incorporates by reference:
• | the Unaudited Pro Forma Combined Balance Sheet of the Company as of June 30, 2023 and the Unaudited Pro Forma Combined Statements of Operations of the Company for the Six Months ended June 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 Sheets of Earthstone Energy, Inc.(“Earthstone”) as of December 31, 2022 and 2021, and the Consolidated Statements of Operations, Equity and Cash Flows of Earthstone for the Years Ended December 31, 2022, 2021 and 2020, and the notes related thereto, collectively filed as Exhibit 99.3 herewith; |
• | the Unaudited Condensed Consolidated Balance Sheets of Earthstone as of June 30, 2022 and December 31, 2022, the Unaudited Condensed Consolidated Statements of Operations of Earthstone for the Three and Six Months ended June 30, 2023 and 2022 and the Unaudited Condensed Consolidated Statements of Equity and Cash Flows of Earthstone for the Six Months ended June 30, 2023 and 2022, and the notes related thereto, collectively filed as Exhibit 99.4 herewith; |
• | the Audited Consolidated Balance Sheets of Novo Oil & Gas Holdings, LLC (“Novo”) as of December 31, 2022 and 2021 and the Audited Combined Consolidated Statements of Operations, Changes in Members’ Equity and Cash Flows of Novo for the Years Ended December 31, 2022 and 2021, and the notes related thereto, collectively filed as Exhibit 99.5 herewith; |
• | the Unaudited Condensed Consolidated Balance Sheets of Novo Oil and Gas Legacy Holdings, LLC (formerly Novo) as of June 30, 2023 and December 31, 2022, the Unaudited Condensed Consolidated Statements of Operations of Novo Oil and Gas Legacy Holdings, LLC for the Three and Six Months Ended June 30, 2023 and 2022 and the Unaudited Condensed Consolidated Statements of Equity and Cash Flows of Novo Oil and Gas Legacy Holdings, LLC for the Six Months Ended June 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 Earthstone as of December 31, 2022 using the U.S. Securities and Exchange Commission (“SEC”) guidelines, prepared by Cawley, Gillespie & Associates, Inc., independent petroleum engineers, filed as Exhibit 99.7 herewith; and |
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• | the reserve reports regarding estimated quantities of proved reserves of Novo as of December 31, 2022 using SEC guidelines, prepared by Netherland, Sewell & Associates, Inc., independent petroleum engineers, filed as Exhibits 99.8 and 99.9 herewith, respectively. |
Item 9.01 | Financial Statements and Exhibits. |
(d) | Exhibits. |
Exhibit |
Description |
|
23.1 | Consent of Moss Adams LLP (Earthstone). | |
23.2 | Consent of Moss Adams LLP (Novo). | |
23.3 | Consent of Cawley, Gillespie & Associates, Inc. | |
23.4 | Consent of Netherland, Sewell & Associates, Inc. | |
99.1 | Press Release, dated September 19, 2023 of Permian Resources Corporation. | |
99.2 | Unaudited Pro Forma Combined Financial Statements of the Company. | |
99.3 | Audited Consolidated Financial Statements of Earthstone. | |
99.4 | Unaudited Condensed Consolidated Financial Statements of Earthstone. | |
99.5 | Audited Historical Combined Consolidated Financial Statements of Novo. | |
99.6 | Unaudited Historical Combined Consolidated Financial Statements of Novo. | |
99.7 | Report of Cawley, Gillespie & Associates, Inc. | |
99.8 | Report of Netherland, Sewell & Associates, Inc. | |
99.9 | Report of Netherland, Sewell & Associates, Inc. | |
104 | Cover Page Interactive Data File (embedded within the Inline XBRL document). |
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Legend Information
No Offer or Solicitation
This communication relates to a proposed business combination transaction (the “Transaction”) between Earthstone and Permian Resources. This communication is for informational purposes only and does not constitute an offer to sell or the solicitation of an offer to buy any securities or a solicitation of any vote or approval, in any jurisdiction, pursuant to the Transaction or otherwise, nor shall there be any sale, issuance, exchange or transfer of the securities referred to in this document in any jurisdiction in contravention of applicable law. No offer of securities shall be made except by means of a prospectus meeting the requirements of Section 10 of the Securities Act.
Important Additional Information
In connection with the Transaction, on September 6, 2023, Permian Resources filed with U.S. Securities and Exchange Commission (the “SEC”) a registration statement on Form S-4 that includes a joint proxy statement of Earthstone and Permian Resources and a prospectus of Permian Resources. The Transaction will be submitted to Earthstone’s stockholders and Permian Resources’ stockholders for their consideration. Earthstone and Permian Resources may also file other documents with the SEC regarding the Transaction. The definitive joint proxy statement/prospectus will be sent to the stockholders of Permian Resources and Earthstone. This document is not a substitute for the registration statement and joint proxy statement/prospectus that will be filed with the SEC or any other documents that Permian Resources or Earthstone may file with the SEC or send to stockholders of Permian Resources or Earthstone, respectively, in connection with the Transaction.
INVESTORS AND SECURITY HOLDERS OF EARTHSTONE AND PERMIAN RESOURCES ARE URGED TO READ THE REGISTRATION STATEMENT AND THE JOINT PROXY STATEMENT/PROSPECTUS REGARDING THE TRANSACTION AND ALL OTHER RELEVANT DOCUMENTS THAT ARE FILED OR WILL BE FILED WITH THE SEC, AS WELL AS ANY AMENDMENTS OR SUPPLEMENTS TO THESE DOCUMENTS, CAREFULLY AND IN THEIR ENTIRETY BECAUSE THEY WILL CONTAIN IMPORTANT INFORMATION ABOUT THE TRANSACTION AND RELATED MATTERS.
Investors and security holders are able to obtain free copies of the registration statement and the joint proxy statement/prospectus and all other documents filed or that will be filed with the SEC by Permian Resources or Earthstone through the website maintained by the SEC at http://www.sec.gov. Copies of documents filed with the SEC by Earthstone are available free of charge on Earthstone’s website at https://www.earthstoneenergy.com, under the “Investors” tab, or by directing a request to Investor Relations, Earthstone Energy, Inc., 1400 Woodloch Forest Drive, Suite 300, The Woodlands, TX 77380, Tel. No. (281) 298-4246. Copies of documents filed with the SEC by Permian Resources will be made available free of charge on Permian Resources’ website at https://www.permianres.com, under the “Investor Relations” tab, or by directing a request to Investor Relations, Permian Resources Corporation, 300 N. Marienfeld St., Ste. 1000, Midland, TX 79701, Tel. No. (432) 695-4222.
Participants in the Solicitation
Permian Resources, Earthstone and their respective directors and executive officers may be deemed to be participants in the solicitation of proxies in respect to the Transaction. Information regarding Earthstone’s directors and executive officers is contained in the proxy statement for Earthstone’s 2023 Annual Meeting of Stockholders filed with the SEC on April 27, 2023, and certain of its Current Reports on Form 8-K. You can obtain a free copy of this document at the SEC’s website at http://www.sec.gov or by accessing Earthstone’s website at https://www.earthstoneenergy.com.
Information regarding Permian Resources’ executive officers and directors is contained in the proxy statement for the Permian Resources’ 2023 Annual Meeting of Stockholders filed with the SEC on April 11, 2023 and certain of its Current Reports on Form 8-K. You can obtain a free copy of this document at the SEC’s website at www.sec.gov or by accessing the Permian Resources’ website at https://www.permianres.com. Investors may obtain additional information regarding the interests of those persons and other persons who may be deemed participants in the Transaction by reading the joint proxy statement/prospectus regarding the Transaction. You may obtain free copies of this document as described above.
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SIGNATURE
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized.
PERMIAN RESOURCES CORPORATION | ||
By: | /s/ Guy M. Oliphint |
|
Guy M. Oliphint | ||
Executive Vice President and Chief Financial Officer | ||
Date: | September 19, 2023 |
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Exhibit 23.1
Consent of Independent Registered Public Accounting Firm
We consent to the incorporation by reference in the Registration Statements on Form S-3 (Nos. 333-215621, 333-214355, 333-219739, 333-241649, 333-254300 and 333-267338) and Form S-8 (Nos. 333-215119, 333-231514, 333-238798, 333-264599 and 333-272352) of Permian Resources Corporation (the “Company”), of our report dated March 8, 2023, relating to the consolidated financial statements of Earthstone Energy, Inc. as of December 31, 2022 and 2021 and for each of the three years in the period ended December 31, 2022, appearing in this Current Report on Form 8-K of the Company.
/s/ Moss Adams LLP
Houston, Texas
September 19, 2023
Exhibit 23.2
Consent of Independent Auditors
We consent to the incorporation by reference in the Registration Statements (Nos. 333-215621, 333-214355, 333-219739, 333-241649, 333-254300 and 333-267338) on Form S-3 and the Registration Statements (Nos. 333-215119, 333-231514, 333-238798, 333-264599 and 333-272352) on Form S-8 of Permian Resources Corporation (the “Company”), of our report dated March 31, 2023, relating to the combined consolidated financial statements of Novo Oil & Gas Holdings, LLC as of December 31, 2022 and 2021 and for the years then ended, appearing in this Current Report on Form 8-K of the Company, filed with the Securities and Exchange Commission.
/s/ Moss Adams LLP
Dallas, Texas
September 19, 2023
Exhibit 23.3
CONSENT OF INDEPENDENT PETROLEUM ENGINEERS
The undersigned hereby consents to the references to our firm in the form and context in which they appear, and the inclusion of our reserve report and oil, natural gas and NGL reserves estimates and forecasts of economics of Earthstone Energy, Inc. as of December 31, 2022, in this Current Report on Form 8-K of Permian Resources Corporation (the “Company”), and to the incorporation by reference of such report in the Registration Statements (Nos. 333-215621, 333-214355, 333-219739, 333-241649, 333-254300 and 333-267338) on Form S-3 and the Registration Statements (Nos. 333-215119, 333-231514, 333-238798, 333-264599 and 333-272352) on Form S-8 of the Company, each filed with the U.S. Securities and Exchange Commission, as well as in the notes to the financial statements of Earthstone Energy, Inc. included or incorporated by reference therein. We also consent to the reference to us under the heading “Experts” in such Registration Statements.
Sincerely, |
/s/ W. Todd Brooker |
W. Todd Brooker, P.E. President Cawley, Gillespie & Associates, Inc. |
Texas Registered Engineering Firm F-693 |
September 19, 2023 |
Exhibit 23.4
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 Permian Resources Corporation (the “Company”) of our reserves reports relating to Novo Oil & Gas Legacy Holdings, LLC, each dated September 7, 2023, 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. 333-215621, 333-214355, 333-219739, 333-241649, 333-254300 and 333-267338) on Form S-3 and the Registration Statements (Nos. 333-215119, 333-231514, 333-238798, 333-264599 and 333-272352) 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. |
|
Richard B. Talley, Jr., P.E. | ||
Chief Executive Officer |
Houston, Texas
September 19, 2023
Exhibit 99.1
Permian Resources Corporation Announces Secondary Public Offering of Class A Common Stock
September 19, 2023
MIDLAND, Texas —(BUSINESS WIRE)— Permian Resources Corporation (“Permian Resources” or the “Company”) (NYSE: PR) today announced the commencement of an underwritten public offering of an aggregate 20,300,000 shares of its Class A Common Stock, par value $0.0001 per share (“Class A common stock”), by certain affiliates of NGP Energy Capital Management, L.L.C. (the “Selling Stockholders”). Permian Resources will not sell any shares of Class A common stock in the offering and will not receive any proceeds therefrom. The Selling Stockholders expect to grant the underwriters a 30-day option to purchase up to an additional aggregate 3,045,000 shares of Class A common stock at the public offering price, less the underwriting discounts and commissions.
Concurrently with the closing of the offering, the Company intends to purchase (the “Concurrent OpCo Unit Purchase”) from the Selling Stockholders an aggregate 2,200,000 common units representing limited liability company interests (“OpCo Units”) in Permian Resources Operating, LLC, a Delaware limited liability company and a subsidiary of Permian Resources (“OpCo”), at a price per OpCo Unit equal to the price per share at which the underwriters purchase shares of Class A common stock in the offering and to cancel a corresponding number of shares of the Company’s Class C Common Stock, par value $0.0001 per share, held by the Selling Stockholders. The offering of Class A common stock is not conditioned upon the completion of the Concurrent OpCo Unit Purchase, but the Concurrent OpCo Unit Purchase is conditioned upon the completion of the offering.
J.P. Morgan, BofA Securities, and Truist Securities are serving as joint book-running managers for the offering. The offering is subject to market and other conditions, and there can be no assurance as to whether or when the offering may be completed, or as to the actual size or terms of the offering.
The proposed offering is being made pursuant to a registration statement previously filed by the Company with the U.S. Securities and Exchange Commission (the “SEC”) that became automatically effective upon filing on September 9, 2022.
The proposed offering will be made only by means of a prospectus and prospectus supplement that meet the requirements under the Securities Act of 1933, as amended (the “Securities Act”). Copies of the preliminary prospectus supplement and accompanying base prospectus and final prospectus supplement, when available, may be obtained from: J.P. Morgan, c/o Broadridge Financial Solutions, 1155 Long Island Avenue, Edgewood, NY 11717, by telephone at (866) 803-9204; BofA Securities: BofA Securities, NC1-022-02-25, 201 North Tryon Street, Charlotte, NC 28255-0001, Attn: Prospectus Department or by email at dg.prospectus_requests@bofa.com; Truist Securities: Attention: Prospectus Department, 3333 Peachtree Road NE, 9th Floor, Atlanta, Georgia 30326, TruistSecurities.prospectus@Truist.com; or by accessing the SEC’s website at www.sec.gov.
This press release shall not constitute an offer to sell or a solicitation of an offer to buy shares of Class A common stock or any other securities, nor shall there be any sale of securities in any state or jurisdiction in which such offer, solicitation or sale would be unlawful without registration or qualification under the securities laws of any such state or jurisdiction.
About Permian Resources
Headquartered in Midland, Texas, Permian Resources is an independent oil and natural gas company focused on the responsible acquisition, optimization and development of high return oil and natural gas properties. The Company’s assets and operations are located in the core of the Delaware Basin.
Cautionary Note Regarding Forward-Looking Statements
The information in this press release includes “forward-looking statements” within the meaning of Section 27A of 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 press release, regarding the completion of the offering and the Concurrent OpCo Unit Purchase, the Company’s 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 press release, the words “could,” “may,” “believe,” “anticipate,” “intend,” “estimate,” “expect,” “project,” “goal,” “plan,” “target” 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 management’s current expectations and assumptions about future events and are based on currently available information as to the outcome and timing of future events. Be cautioned that these forward-looking statements are subject to all of the risk and uncertainties, most of which are difficult to predict and many of which are beyond Permian Resources’ control, incident to the development, production, gathering and sale of oil and natural gas. These risks include, but are not limited to, commodity price volatility, inflation, lack of availability of drilling and production equipment and services, risks relating to the Transaction (as defined below), including its consummation or the realization of the anticipated benefits and synergies therefrom. Actual results could differ materially from those anticipated in these forward-looking statements as a result of certain factors, including, but not limited to, those set forth in the Company’s filings with the SEC, including the prospectus relating to the offering, the Registration Statement (as defined below), its Annual Report on Form 10-K for the fiscal year ended December 31, 2022, and its subsequent Quarterly Reports on Form 10-Q, under the caption “Risk Factors,” as may be updated from time to time in the Company’s periodic filings with the SEC. Any forward-looking statement in this press release speaks only as of the date of this release. The Company undertakes no obligation to publicly update or review any forward-looking statement, whether as a result of new information, future developments or otherwise, except as may be required by any applicable securities laws.
No Offer or Solicitation
This press release relates to a proposed business combination transaction (the “Transaction”) between Earthstone Energy, Inc. (“Earthstone”) and Permian Resources. This press release is for informational purposes only and does not constitute an offer to sell or the solicitation of an offer to buy any securities or a solicitation of any vote or approval, in any jurisdiction, pursuant to the Transaction or otherwise, nor shall there be any sale, issuance, exchange or transfer of the securities referred to in this document in any jurisdiction in contravention of applicable law. No offer of securities shall be made except by means of a prospectus meeting the requirements of Section 10 of the Securities Act.
Important Additional Information
In connection with the Transaction, on September 6, 2023, Permian Resources filed with the SEC a registration statement on Form S-4 (the “Registration Statement”) that includes a joint proxy statement of Earthstone and Permian Resources and a prospectus of Permian Resources. The Transaction will be submitted to Earthstone’s stockholders and Permian Resources’ stockholders for their consideration. Earthstone and Permian Resources may also file other documents with the SEC regarding the Transaction. The definitive joint proxy statement/prospectus will be sent to the stockholders of Permian Resources and Earthstone. This document is not a substitute for the registration statement and joint proxy statement/prospectus that will be filed with the SEC or any other documents that Permian Resources or Earthstone may file with the SEC or send to stockholders of Permian Resources or Earthstone, respectively, in connection with the Transaction.
INVESTORS AND SECURITY HOLDERS OF EARTHSTONE AND PERMIAN RESOURCES ARE URGED TO READ THE REGISTRATION STATEMENT AND THE JOINT PROXY STATEMENT/PROSPECTUS REGARDING THE TRANSACTION AND ALL OTHER RELEVANT DOCUMENTS THAT ARE FILED OR WILL BE FILED WITH THE SEC, AS WELL AS ANY AMENDMENTS OR SUPPLEMENTS TO THESE DOCUMENTS, CAREFULLY AND IN THEIR ENTIRETY BECAUSE THEY WILL CONTAIN IMPORTANT INFORMATION ABOUT THE TRANSACTION AND RELATED MATTERS.
Investors and security holders are able to obtain free copies of the registration statement and the joint proxy statement/prospectus and all other documents filed or that will be filed with the SEC by Permian Resources or Earthstone through the website maintained by the SEC at http://www.sec.gov. Copies of documents filed with the SEC by Earthstone are available free of charge on Earthstone’s website at https://www.earthstoneenergy.com, under the “Investors” tab, or by directing a request to Investor Relations, Earthstone Energy, Inc., 1400 Woodloch Forest Drive, Suite 300, The Woodlands, TX 77380, Tel. No. (281) 298-4246. Copies of documents filed with the SEC by Permian Resources will be made available free of charge on Permian Resources’ website at https://www.permianres.com, under the “Investor Relations” tab, or by directing a request to Investor Relations, Permian Resources Corporation, 300 N. Marienfeld St., Ste. 1000, Midland, TX 79701, Tel. No. (432) 695-4222.
Participants in the Solicitation
Permian Resources, Earthstone and their respective directors and executive officers may be deemed to be participants in the solicitation of proxies in respect to the Transaction. Information regarding Earthstone’s directors and executive officers is contained in the proxy statement for Earthstone’s 2023 Annual Meeting of Stockholders filed with the SEC on April 27, 2023, and certain of its Current Reports on Form 8-K. You can obtain a free copy of this document at the SEC’s website at http://www.sec.gov or by accessing Earthstone’s website at https://www.earthstoneenergy.com.
Information regarding Permian Resources’ executive officers and directors is contained in the proxy statement for the Permian Resources’ 2023 Annual Meeting of Stockholders filed with the SEC on April 11, 2023 and certain of its Current Reports on Form 8-K. You can obtain a free copy of this document at the SEC’s website at www.sec.gov or by accessing the Permian Resources’ website at https://www.permianres.com. Investors may obtain additional information regarding the interests of those persons and other persons who may be deemed participants in the Transaction by reading the joint proxy statement/prospectus regarding the Transaction.
You may obtain free copies of this document as described above.
Contacts:
Hays Mabry – Sr. Director, Investor Relations
Mae Herrington – Engineering Advisor, Investor Relations
(832) 240-3265
ir@permianres.com
Exhibit 99.2
UNAUDITED PRO FORMA COMBINED FINANCIAL STATEMENTS
On August 21, 2023, Permian Resources Corporation (“Permian Resources” or the “Company”) and Earthstone Energy, Inc. (“Earthstone”) announced that they have entered into a merger agreement pursuant to which Permian Resources will acquire Earthstone (the “Merger”). The Merger is expected to close prior to December 31, 2023, subject to customary closing conditions, regulatory approvals and shareholder approvals.
If the Merger is completed, (i) each share of Earthstone Class A common stock will be converted into the right to receive 1.446 (the “Exchange Ratio”) shares of Permian Resources Class A common stock, (ii) each share of Earthstone Class B common stock will be converted into the right to receive 1.446 shares of Permian Resources Class C common stock, (iii) each common unit of Earthstone Energy Holdings, LLC, a subsidiary of Earthstone (“Earthstone OpCo”) representing limited liability company membership interests in Earthstone OpCo (the “Earthstone OpCo Units”) will be converted into the right to receive a number of common units representing limited liability company interests in Permian Resources Operating, LLC, a subsidiary of Permian Resources (“Permian Resources OpCo” and such units the “Permian Resources OpCo Units”), equal to the Exchange Ratio, and (iv) all existing shares of Permian Resources common stock will remain outstanding.
The following unaudited pro forma combined financial statements of the Company (which we refer to as the “pro forma combined financial statements”) have been prepared from the respective historical consolidated financial statements of Permian Resources and Earthstone and have been adjusted to reflect (i) the completion of the Merger, (ii) Earthstone’s completion of the Novo Transactions on August 15, 2023 (defined in Note 5 below and collectively referred to in these pro forma combined financial statements as, “Earthstone’s Novo Transactions”) and (iii) Permian Resources’ completion of its acquisition of Colgate Energy Partners III, LLC (“Colgate”) on August 31, 2022 (the “Colgate Merger” and collectively referred to in these pro forma combined financial statements as, the “Transactions”). The unaudited pro forma combined balance sheet as of June 30, 2023, gives effect to the Merger and Earthstone’s Novo Transactions as if they had been completed on June 30, 2023. The unaudited pro forma combined statements of operations for the year ended December 31, 2022, and the six months ended June 30, 2023, give effect to the Transactions as if they had been completed on January 1, 2022.
The Merger will be accounted for as a business combination using the acquisition method of accounting, with Permian Resources as the accounting acquirer. The pro forma combined financial statements have been prepared to reflect transaction accounting adjustments to Permian Resources’ historical financial information that management believes are factually supportable and that are expected to have a continuing impact on results of operations, with the exception of certain nonrecurring items incurred in connection with the Merger.
The pro forma merger consideration and purchase price allocation are preliminary and are based upon estimates of the fair market values of the assets and liabilities of Earthstone as of June 30, 2023, utilizing currently available information. Assumptions and estimates underlying the pro forma adjustments, preliminary merger consideration and preliminary purchase price allocations are described in the accompanying notes, which should be read in conjunction with the pro forma combined financial statements.
As of the date of this filing, the Company has not completed the necessary valuations of the Merger in order to arrive at the required final estimates of the fair value and the related allocations of purchase price, nor has it identified all adjustments necessary to conform Earthstone’s accounting policies to those of the Company. A final determination of the fair value of Earthstone’s assets and liabilities will be based on those that exist as of the closing date, and therefore, cannot be made prior to the completion of the Merger. In addition, the value of the shares to be distributed upon closing of the Merger will be determined based on the market price of the Permian Resources Class A common stock on the closing date. The pro forma adjustments are preliminary and are subject to change as additional information becomes available and as additional analysis is performed. The final purchase price allocation and merger consideration will be performed subsequent to closing and may be materially different than that reflected herein.
The pro forma combined financial statements and related notes are presented to reflect the Transactions for illustrative purposes only. If the Transactions had occurred in the past, the operating results might have been materially different from those presented in the pro forma combined financial statements. The pro forma combined statements of operations should not be relied upon as an indication of operating results that would have been achieved if the Transactions contemplated herein had taken place on the specified date. In addition, future results may vary significantly from the results reflected in the pro forma combined statements of operations and should not be relied on as an indication of the future results of the combined company following the Transactions. The pro forma combined financial statements do not reflect projected synergies including the benefits of expected cost savings (or associated costs to achieve such savings), opportunities to earn additional revenue or other factors that may result after the Merger and, accordingly, do not attempt to predict or suggest future results.
PERMIAN RESOURCES CORPORATION
UNAUDITED PRO FORMA COMBINED BALANCE SHEET
As of June 30, 2023, (in thousands)
Historical | Earthstone’s Novo Transactions |
Transaction Accounting Adjustments |
Pro forma Combined |
|||||||||||||||||||
Permian Resources |
Earthstone | |||||||||||||||||||||
ASSETS |
(a) | (b) | ||||||||||||||||||||
Current assets |
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Cash and cash equivalents |
$ | 18,280 | $ | 49,500 | $ | 487,660 | $ | (468,436 | ) | (c) | $ | 87,004 | ||||||||||
Accounts receivable, net |
309,624 | 135,632 | 56,429 | — | 501,685 | |||||||||||||||||
Derivative instruments |
87,737 | 7,106 | — | — | 94,843 | |||||||||||||||||
Prepaid and other current assets |
10,396 | 19,658 | 88 | — | 30,142 | |||||||||||||||||
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Total current assets |
426,037 | 211,896 | 544,177 | (468,436 | ) | 713,674 | ||||||||||||||||
Property and Equipment |
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Oil and natural gas properties, successful efforts method |
||||||||||||||||||||||
Unproved properties |
1,415,969 | 280,221 | 34,894 | 300,695 | (d) | 2,031,779 | ||||||||||||||||
Proved properties |
9,691,058 | 4,348,453 | 733,192 | (646,750 | ) | (d) | 14,125,953 | |||||||||||||||
Accumulated depreciation, depletion and amortization |
(2,811,580 | ) | (832,886 | ) | (281,322 | ) | 1,114,208 | (d) | (2,811,580 | ) | ||||||||||||
|
|
|
|
|
|
|
|
|
|
|||||||||||||
Total oil and natural gas properties, net |
8,295,447 | 3,795,788 | 486,764 | 768,153 | 13,346,152 | |||||||||||||||||
Other property and equipment, net |
38,731 | 11,552 | 14 | — | 50,297 | |||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|||||||||||||
Total property and equipment, net |
8,334,178 | 3,807,340 | 486,778 | 768,153 | 13,396,449 | |||||||||||||||||
Noncurrent assets |
||||||||||||||||||||||
Operating lease right-of-use assets |
62,049 | 6,573 | — | — | 68,622 | |||||||||||||||||
Other noncurrent assets |
104,061 | 94,632 | — | (75,000 | ) | (c) | 107,304 | |||||||||||||||
(16,389 | ) | (d) | ||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|||||||||||||
TOTAL ASSETS |
$ | 8,926,325 | $ | 4,120,441 | $ | 1,030,955 | $ | 208,328 | $ | 14,286,049 | ||||||||||||
|
|
|
|
|
|
|
|
|
|
|||||||||||||
LIABILITIES AND EQUITY |
||||||||||||||||||||||
Current liabilities |
||||||||||||||||||||||
Accounts payable and accrued expenses |
$ | 661,748 | $ | 322,405 | $ | 89,418 | $ | 84,500 | (e) | $ | 1,158,071 | |||||||||||
Operating lease liabilities |
36,160 | 906 | — | — | 37,066 | |||||||||||||||||
Derivative Instruments |
354 | 31,702 | — | — | 32,056 | |||||||||||||||||
Other current liabilities |
24,462 | 26,867 | 2,333 | (12,722 | ) | (f) | 40,940 | |||||||||||||||
|
|
|
|
|
|
|
|
|
|
|||||||||||||
Total current liabilities |
722,724 | 381,880 | 91,751 | 71,778 | 1,268,133 | |||||||||||||||||
Noncurrent liabilities |
||||||||||||||||||||||
Long-term debt, net |
2,060,070 | 1,021,555 | — | 861,873 | (c) | 3,949,929 | ||||||||||||||||
6,431 | (d) | |||||||||||||||||||||
Asset retirement obligations |
44,546 | 30,555 | 2,856 | 26,634 | (d) | 104,591 | ||||||||||||||||
Deferred income taxes |
78,685 | 174,565 | — | 18,477 | (d) | 271,727 | ||||||||||||||||
Operating lease liabilities |
27,894 | 3,524 | — | — | 31,418 | |||||||||||||||||
Other noncurrent liabilities |
66,396 | 16,535 | 21,194 | (2,179 | ) | (f) | 101,946 | |||||||||||||||
|
|
|
|
|
|
|
|
|
|
|||||||||||||
Total liabilities |
3,000,315 | 1,628,614 | 115,801 | 983,014 | 5,727,744 | |||||||||||||||||
Shareholders’ equity |
||||||||||||||||||||||
Common stock |
||||||||||||||||||||||
Class A |
33 | 106 | — | (106 | ) | (d) | 49 | |||||||||||||||
16 | (g) | |||||||||||||||||||||
Class C |
24 | — | — | 5 | (g) | 29 | ||||||||||||||||
Class B |
— | 34 | — | (34 | ) | (d) | — | |||||||||||||||
Member’s equity |
— | — | 915,154 | (915,154 | ) | (d) | — | |||||||||||||||
Additional paid-in capital |
2,944,785 | 1,345,657 | — | (1,345,657 | ) | (d) | 5,030,540 | |||||||||||||||
2,085,755 | (g) | |||||||||||||||||||||
Retained earnings (accumulated deficit) |
363,881 | 411,301 | — | (411,301 | ) | (d) | 279,381 | |||||||||||||||
(84,500 | ) | (e) | ||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|||||||||||||
Total shareholders’ equity |
3,308,723 | 1,757,098 | 915,154 | (670,976 | ) | 5,309,999 | ||||||||||||||||
Noncontrolling interest |
2,617,287 | 734,729 | — | (734,729 | ) | (d) | 3,248,306 | |||||||||||||||
631,019 | (g) | |||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|||||||||||||
Total equity |
5,926,010 | 2,491,827 | 915,154 | (774,686 | ) | 8,558,305 | ||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|||||||||||||
TOTAL LIABILITIES AND EQUITY |
$ | 8,926,325 | $ | 4,120,441 | $ | 1,030,955 | $ | 208,328 | $ | 14,286,049 | ||||||||||||
|
|
|
|
|
|
|
|
|
|
The accompanying notes are an integral part of the pro forma combined financial statements.
PERMIAN RESOURCES CORPORATION
UNAUDITED PRO FORMA COMBINED STATEMENT OF OPERATIONS
For the Six Months Ended June 30, 2023
(in thousands, except per share data)
Earthstone’s Novo Transactions |
Transaction Accounting Adjustments |
|||||||||||||||||||||
Historical | Pro forma Combined |
|||||||||||||||||||||
Permian Resources |
Earthstone | |||||||||||||||||||||
Operating revenues |
(a) | (b) | ||||||||||||||||||||
Oil and gas sales |
$ | 1,239,666 | $ | 783,144 | $ | 212,263 | $ | — | $ | 2,235,073 | ||||||||||||
Operating expenses |
||||||||||||||||||||||
Lease operating expenses |
157,523 | 126,422 | 33,732 | — | 317,677 | |||||||||||||||||
Severance and ad valorem taxes |
97,436 | 64,958 | 15,879 | — | 178,273 | |||||||||||||||||
Gathering, processing and transportation expenses |
37,235 | 49,158 | — | — | 86,393 | |||||||||||||||||
Depreciation, depletion, and amortization |
403,945 | 222,015 | 51,669 | (52,843 | ) | (h) | 624,786 | |||||||||||||||
General and administrative expenses |
88,210 | 37,571 | 17,241 | (12,453 | ) | (f) | 130,569 | |||||||||||||||
Merger and integration expense |
17,649 | 401 | — | (401 | ) | (i) | 17,649 | |||||||||||||||
Impairment and abandonment expense |
489 | 854 | — | — | 1,343 | |||||||||||||||||
Exploration and other expenses |
9,637 | 6,548 | — | — | 16,185 | |||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|||||||||||||
Total operating expenses |
812,124 | 507,927 | 118,521 | (65,697 | ) | 1,372,875 | ||||||||||||||||
Net gain (loss) on sale of long-lived assets |
66 | 46,114 | — | (46,114 | ) | (i) | 66 | |||||||||||||||
|
|
|
|
|
|
|
|
|
|
|||||||||||||
Income (loss) from operations |
427,608 | 321,331 | 93,742 | 19,583 | 862,264 | |||||||||||||||||
Other income (expense) |
||||||||||||||||||||||
Interest expense |
(73,603 | ) | (50,057 | ) | — | (28,018 | ) | (j) | (151,678 | ) | ||||||||||||
Net gain (loss) on derivative instruments |
75,113 | (66,773 | ) | — | — | 8,340 | ||||||||||||||||
Other income (expense) |
439 | 812 | (1,766 | ) | — | (515 | ) | |||||||||||||||
|
|
|
|
|
|
|
|
|
|
|||||||||||||
Total other income (expense) |
1,949 | (116,018 | ) | (1,766 | ) | (28,018 | ) | (143,853 | ) | |||||||||||||
|
|
|
|
|
|
|
|
|
|
|||||||||||||
Income (loss) before income taxes |
429,557 | 205,313 | 91,976 | (8,435 | ) | 718,411 | ||||||||||||||||
Income tax (expense) benefit |
(60,802 | ) | (36,654 | ) | (107 | ) | 1,172 | (k) | (96,391 | ) | ||||||||||||
|
|
|
|
|
|
|
|
|
|
|||||||||||||
Net income (loss) |
368,755 | 168,659 | 91,869 | (7,263 | ) | 622,020 | ||||||||||||||||
Less: Net (income) loss attributable to noncontrolling interest |
(193,236 | ) | (50,069 | ) | — | (34,642 | ) | (l) | (277,947 | ) | ||||||||||||
|
|
|
|
|
|
|
|
|
|
|||||||||||||
Net income (loss) attributable to Class A common stock |
$ | 175,519 | $ | 118,590 | $ | 91,869 | $ | (41,905 | ) | $ | 344,073 | |||||||||||
|
|
|
|
|
|
|
|
|
|
|||||||||||||
Income (loss) per share of Class A common stock: |
|
|||||||||||||||||||||
Basic |
$ | 0.57 | 0.74 | |||||||||||||||||||
Diluted |
$ | 0.52 | $ | 0.69 | ||||||||||||||||||
Weighted average common shares outstanding: |
||||||||||||||||||||||
Basic |
305,593 | 162,245 | (m) | 467,838 | ||||||||||||||||||
Diluted |
343,935 | 466,209 | (m) | 810,144 |
The accompanying notes are an integral part of the pro forma combined financial statements.
PERMIAN RESOURCES CORPORATION
UNAUDITED PRO FORMA COMBINED STATEMENT OF OPERATIONS
For the Year Ended December 31, 2022
(in thousands, except per share data)
Permian Resources Pro Forma |
Earthstone’s Novo Transactions |
Transaction Accounting Adjustments |
||||||||||||||||||||
Historical | Pro forma | |||||||||||||||||||||
Earthstone | Combined | |||||||||||||||||||||
(n) | (a) | (b) | ||||||||||||||||||||
Operating revenues |
||||||||||||||||||||||
Oil and gas sales |
$ | 3,233,675 | $ | 1,695,154 | $ | 380,860 | $ | — | $ | 5,309,689 | ||||||||||||
Operating expenses |
||||||||||||||||||||||
Lease operating expenses |
271,732 | 162,801 | 30,217 | — | 464,750 | |||||||||||||||||
Severance and ad valorem taxes |
235,847 | 123,054 | 27,597 | — | 386,498 | |||||||||||||||||
Gathering, processing and transportation expenses |
109,754 | 67,714 | — | — | 177,468 | |||||||||||||||||
Depreciation, depletion and amortization |
618,688 | 304,465 | 65,308 | (50,317 | ) | (h) | 938,144 | |||||||||||||||
General and administrative expenses |
200,869 | 74,175 | 7,823 | 41,153 | (f) | 324,020 | ||||||||||||||||
Merger and integration expense |
77,424 | 8,248 | — | (8,248 | ) | (i) | 161,924 | |||||||||||||||
84,500 | (e) | |||||||||||||||||||||
Impairment and abandonment expense |
3,875 | — | — | — | 3,875 | |||||||||||||||||
Exploration and other expenses |
15,110 | 2,492 | 526 | — | 18,128 | |||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|||||||||||||
Total operating expenses |
1,533,299 | 742,949 | 131,471 | 67,088 | 2,474,807 | |||||||||||||||||
Net gain (loss) on sale of long-lived assets |
(1,314 | ) | 13,900 | 76 | (13,976 | ) | (i) | (1,314 | ) | |||||||||||||
|
|
|
|
|
|
|
|
|
|
|||||||||||||
Income (loss) from operations |
1,699,062 | 966,105 | 249,465 | (81,064 | ) | 2,833,568 | ||||||||||||||||
Other income (expense) |
||||||||||||||||||||||
Interest expense |
(156,855 | ) | (66,821 | ) | — | (72,438 | ) | (j) | (296,114 | ) | ||||||||||||
Net gain (loss) on derivative instruments |
(428,426 | ) | (125,107 | ) | — | — | (553,533 | ) | ||||||||||||||
Other income (expense) |
619 | 856 | 2,752 | — | 4,227 | |||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|||||||||||||
Total other income (expense) |
(584,662 | ) | (191,072 | ) | 2,752 | (72,438 | ) | (845,420 | ) | |||||||||||||
|
|
|
|
|
|
|
|
|
|
|||||||||||||
Income (loss) before income taxes |
1,114,400 | 775,033 | 252,217 | (153,502 | ) | 1,988,148 | ||||||||||||||||
Income tax (expense) benefit |
(112,824 | ) | (124,416 | ) | (234 | ) | 21,334 | (k) | (216,140 | ) | ||||||||||||
|
|
|
|
|
|
|
|
|
|
|||||||||||||
Net income (loss) |
1,001,576 | 650,617 | 251,983 | (132,168 | ) | 1,772,008 | ||||||||||||||||
Less: Net (income) loss attributable to noncontrolling interest |
(537,990 | ) | (198,132 | ) | — | (18,479 | ) | (l) | (754,601 | ) | ||||||||||||
|
|
|
|
|
|
|
|
|
|
|||||||||||||
Net income (loss) attributable to Class A common stock |
$ | 463,586 | $ | 452,485 | $ | 251,983 | $ | (113,689 | ) | $ | 1,017,407 | |||||||||||
|
|
|
|
|
|
|
|
|
|
|||||||||||||
Income (loss) per share of Class A common stock: |
||||||||||||||||||||||
Basic |
$ | 1.62 | $ | 2.27 | ||||||||||||||||||
Diluted |
$ | 1.45 | $ | 1.86 | ||||||||||||||||||
Weighted average common shares outstanding: |
||||||||||||||||||||||
Basic |
286,160 | 161,231 | (m) | 447,391 | ||||||||||||||||||
Diluted |
323,579 | 506,380 | (m) | 829,959 |
The accompanying notes are an integral part of the pro forma combined financial statements.
NOTES TO THE UNAUDITED PRO FORMA COMBINED FINANCIAL STATEMENTS
Note 1 - Basis of Presentation
The pro forma combined financial statements were prepared utilizing the historical financial information of Permian Resources and Earthstone in accordance with Article 11 of the SEC Regulation S-X, and they incorporate the acquisition method of accounting in accordance with GAAP. Certain transaction accounting adjustments have been computed in order to show the effects of the Merger on the combined historical financial information of Permian Resources and Earthstone. These adjustments are preliminary and based upon the estimated fair value of merger consideration and management’s estimates of fair value of the assets acquired and liabilities assumed.
The Permian Resources and Earthstone historical financial information have been derived from each respective company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2023 and Annual Report on Form 10-K for the year ended December 31, 2022. The unaudited pro forma adjustments related to Earthstone’s Novo Transactions are derived from Earthstone’s Current Report on Form 8-K/A filed on September 5, 2023, which also include the audited financial statements of Novo for the year ended December 31, 2022. The unaudited pro forma adjustments related to the Colgate Merger are derived from Permian Resources’ Current Report on Form 8-K filed on September 8, 2022, which also include the audited financial statements of Colgate for the years ended December 31, 2021 and 2020. These pro forma combined financial statements should be read in conjunction with the historical financial statements and related notes thereto of Permian Resources, Earthstone and Novo, as well as the pro forma financial information included in the Permian Resources and Earthstone Current Reports on Form 8-K referenced above.
The unaudited pro forma combined balance sheet as of June 30, 2023, gives effect to the Merger and Earthstone’s Novo Transactions as if they had been completed on June 30, 2023. The unaudited pro forma combined statements of operations for the year ended December 31, 2022, and the six months ended June 30, 2023, give effect to the Transactions as if they had been completed on January 1, 2022.
The pro forma combined financial statements reflect pro forma adjustments that are described in the accompanying notes and are based on currently available information. The pro forma combined financial statements do not represent what the combined business’ financial position or results of operations would have been if the Transactions had actually occurred on the dates indicated, nor are they indicative of future financial position or results of operations. Actual results may differ materially from the assumptions and estimates reflected in these pro forma combined financial statements.
Note 2 - Preliminary Purchase Price Allocation
The Merger will be accounted for as a business combination using the acquisition method of accounting in accordance with Accounting Standards Codification Topic 805, Business Combinations, with Permian Resources being identified as the accounting acquirer. The allocation of the preliminary estimated purchase price with respect to the Merger is based upon management’s estimates and assumptions related to the fair value of assets acquired and liabilities assumed as of June 30, 2023 using currently available information. As the pro forma combined financial statements have been prepared based on these preliminary estimates, the final purchase price allocation may be materially different from the pro forma amounts included herein.
Adjustments to the estimated amounts or recognition of additional assets acquired or liabilities assumed may occur as additional information is obtained and as more detailed analyses are completed after the closing date of the Merger, and the purchase price allocation will be finalized as soon as reasonably practicable after this closing date.
The preliminary purchase price allocation is subject to change due to several factors, including, but not limited to:
• | changes in the estimated fair value of Permian Resources common stock and underlying Permian Resources OpCo Units issued to holders of Earthstone common stock and OpCo Units, which will ultimately be based upon the market price per share of Permian Resources Class A common stock, as well as other factors, on the date of closing of the Merger; |
• | changes in the estimated fair value of the identifiable assets acquired and liabilities assumed as of the closing date, which could result from changes in future oil and gas commodity prices, reserve estimates, discount rates, cost assumptions and other factors; |
• | changes to the acquired tax bases of Earthstone’s assets and liabilities as of the closing date; and/or |
• | certain factors described in the section titled “Risk Factors”. |
The following table presents the preliminary merger consideration and purchase price allocation of the assets acquired and liabilities assumed in the Merger:
(in thousands, expect per share amounts) | Preliminary Merger Consideration |
|||
Consideration: |
||||
Shares of Earthstone Class A common stock issued and outstanding |
111,501 | |||
Shares of Earthstone Class B common stock issued and outstanding(1) |
34,258 | |||
|
|
|||
Total shares of Earthstone common stock issued and outstanding to be exchanged(2) |
145,759 | |||
|
|
|||
Exchange Ratio |
1.446 | |||
Shares of Permian Resources Class A common stock to be issued as merger consideration |
161,230 | |||
Shares of Permian Resources Class C common stock to be issued as merger consideration(1) |
49,537 | |||
|
|
|||
Total Shares of Permian Resources common stock to be issued as merger consideration |
210,767 | |||
|
|
|||
Permian Resources Class A common stock price on August 18, 2023(3) |
$ | 12.89 | ||
Total Consideration |
$ | 2,716,796 | ||
(in thousands) | Preliminary Purchase Price Allocation |
|||
Fair value of assets acquired: |
||||
Cash and cash equivalents |
$ | 68,724 | ||
Accounts receivable, net |
192,061 | |||
Prepaid and other current assets |
20,719 | |||
Derivative instruments |
9,390 | |||
Leases |
6,573 | |||
Unproved oil and natural gas properties |
615,811 | |||
Proved oil and natural gas properties |
4,434,895 | |||
Other property and equipment |
11,552 | |||
|
|
|||
Total assets acquired |
$ | 5,359,725 | ||
|
|
|||
Fair value of liabilities assumed: |
||||
Accounts payable and accrued expenses |
$ | 411,823 | ||
Derivative instruments |
42,326 | |||
Long-term debt, net |
1,889,859 | |||
Asset retirement obligations |
60,045 | |||
Deferred income taxes |
193,042 | |||
Leases |
6,664 | |||
Other liabilities, net |
39,170 | |||
|
|
|||
Total liabilities assumed |
$ | 2,642,929 | ||
|
|
|||
Net assets acquired |
$ | 2,716,796 | ||
|
|
(1) | Each share of Earthstone’s Class B common stock will be converted into Permian Resources Class C common stock (with the underlying Earthstone OpCo Units also being converted into a number of Permian Resource OpCo Units equal to the Exchange Ratio), which collectively represent a noncontrolling interest in the Company. The Permian Resources Class C common stock is not publicly traded but can be exchanged, together with its underlying Permian Resources OpCo Unit, for an equal number of shares of Permian Resources Class A common stock. As such, we have utilized the Permian Resources Class A common stock trading price as a proxy for the estimated fair value of Permian Resources Class C common stock (and their underlying Permian Resources OpCo Units) for this pro forma preliminary merger consideration. |
(2) | Represents shares of Earthstone common stock issued and outstanding as of August 21, 2023, and includes 5,170,435 shares reserved for issuance, which represent Earthstone’s unvested restricted and performance stock units that will be fully vested and converted into the right to receive shares of Permian Resources Class A common stock (as included in merger consideration) upon closing of the Merger. |
(3) | The final value of the merger consideration will be determined based on the market price of Permian Resources Class A common stock, among other factors, on the closing date of the Merger. The preliminary merger consideration utilizes the market price of $12.89 per share as of August 18, 2023 as a proxy for Permian Resources’ estimated Class A common stock price as of the closing date of the Merger. A 10% increase or decrease in the closing price of Permian Resources Class A common stock would increase or decrease the total merger consideration by approximately $271.7 million assuming all other factors are held constant. |
Note 3 - Preliminary Accounting and Pro forma Adjustments
The following adjustments included in the column labeled “Transaction Accounting Adjustments” have been made to the accompanying unaudited pro forma financial statements:
(a) | Certain reclassifications have been made to adjust and conform Earthstone’s historical financial information to Permian Resources’ financial statement classification as follows: |
• | reclassification of $5.5 million from land and to other property and equipment, net; |
• | reclassification of $2.3 million from noncurrent derivative asset to other noncurrent assets; |
• | reclassification of $12.5 million from advances and finance lease liabilities to other current liabilities; |
• | reclassification of $11.8 million from derivative liabilities and finance lease liabilities to other noncurrent liabilities; and |
• | reclassification of $49.2 million for the six months ended June 30, 2023, and $67.7 million for the year ended December 31, 2022 from lease operating expenses to gathering, processing and transportation expense. |
(b) | Represents pro forma adjustments related to Earthstone’s Novo Transactions, that were determined to be significant to the pro forma combined financial statements. Refer to Note 5 below for further information on these transactions. |
(c) | Reflects pro forma adjustments made to reflect Earthstone’s Novo Transactions, as defined in Note 5 below, consisting of: |
• | reduction to cash and cash equivalents to reflect cash consideration of $468.4 million paid initially by Earthstone as part of the total purchase price to acquire Novo. However, Earthstone ultimately received this portion of the purchase consideration back from Northern Oil & Gas, Inc. as a result of its Novo Divestiture; |
• | reduction to other noncurrent assets to reflect the $75.0 million escrow deposit paid by Earthstone prior to closing on the Novo Acquisition; and |
• | increase to long-term debt to reflect Earthstone’s borrowings of $861.9 million used to fund its Novo Acquisition. |
(d) | Reflects the preliminary purchase price allocation to adjust Earthstone’s assets acquired and liabilities assumed, including those acquired in the transactions, to their estimated fair values as follows: |
• | an increase in unproved oil and natural gas properties of $300.7 million and a decrease in proved oil and natural gas properties of $646.8 million to reflect their estimated fair values; |
• | the elimination of historical accumulated depreciation, depletion, and amortization (“DD&A”) balances of Earthstone and Novo which aggregated $1.1 billion; |
• | an increase of $6.4 million to long-term debt to reflect Earthstone’s outstanding senior notes at their estimated fair value; |
• | reduction to other noncurrent assets of $16.4 million to eliminate historical unamortized debt issuance costs related to Earthstone’s credit facility; |
• | an increase of $26.6 million to reflect the asset retirement obligations assumed at their estimated fair value; |
• | a $18.5 million increase in deferred income tax liabilities to reflect changes in the excess of the book basis over the tax basis in the acquired assets and liabilities, and such liability is based on the estimated blended federal and state statutory tax rate of 22.4%. This adjustment is net of the change in book versus bases attributable to noncontrolling interest holders; and |
• | the elimination of Earthstone and Novo’s historical shareholders’ equity and noncontrolling interest balances in accordance with the acquisition method of accounting. |
(e) | For the year ended December 31, 2022, reflects estimated nonrecurring transaction costs of approximately $84.5 million related to the Merger that are expected to be incurred for advisory, legal, accounting and other professional fees, employee retention costs and other transaction related fees. As of June 30, 2023, no actual transaction costs had been incurred. Therefore, with respect to the pro forma balance sheet as of June 30, 2023, $84.5 million of estimated transaction costs were reflected as an increase to accounts payable and accrued expenses, with a corresponding decrease to retained earnings. |
Additionally, employees may be party to certain employment agreements that would entitle each employee to certain benefits in the event of a change in control and subsequent termination due to the Merger. This could result in additional material cash payments and associated expenses. However, at this time, employment decisions have not yet been determined. Due to this uncertainty, an estimate of additional termination costs has not been included in these pro forma combined financial statements.
(f) | Reflects pro forma adjustments for Earthstone’s outstanding restricted stock awards and performance-based stock units that will be fully vested and converted into the right to receive Permian Resources Class A common stock (as included in merger consideration) upon closing of the Merger, as follows: |
• | the removal of a portion of Earthstone’s current and noncurrent liabilities for performance-based stock units that were classified as liability based awards but which will be settled in Permian Resources Class A common stock upon closing of the Merger; |
• | a decrease in general and administrative expenses (“G&A”) of $12.5 million for the six months ended June 30, 2023 as stock-based compensation expense for these Earthstone awards would not be recognized during the year ended December 31, 2022 assuming the Merger closed on January 1, 2022; and |
• | an increase in G&A of $41.2 million for the year ended December 31, 2022 to recognize additional stock based compensation expense for the accelerated vesting of these Earthstone awards assuming the Merger closed on January 1, 2022. |
(g) | Reflects the issuance of 161.2 million shares of Permian Resources Class A common stock and 49.5 million shares of Permian Resources Class C common stock (including underlying Permian Resources OpCo Units) to Earthstone’s stockholders as purchase consideration from Permian Resources to effect the Merger. The issuance of Permian Resources Class A common stock resulted in an increase to additional paid in capital and the issuance of Permian Resources Class C common stock resulted in an increase to the noncontrolling interest. Following these issuances, the noncontrolling interest ownership of Permian Resources OpCo is estimated to be 38%. |
(h) | Reflects pro forma DD&A expense calculated in accordance with the successful efforts method of accounting for oil and gas properties utilizing the combined company’s production, combined company’s estimated proved reserves, and the preliminary estimated fair value ascribed to the oil and natural gas properties acquired in the Merger as follows: |
• | a decrease in DD&A expense of $52.8 million in the pro forma combined statement of operations for the six months ended June 30, 2023 consisting of (i) the elimination of $222.0 million of Earthstone’s historical DD&A expense, (ii) the elimination of $51.7 million of Novo’s historical DD&A expense, and (iii) pro forma incremental DD&A expense for the combined companies of $220.9 million for the first half of 2023; and |
• | a decrease in DD&A expense of $50.3 million in the pro forma combined statement of operations for the year ended December 31, 2022 consisting of (i) the elimination of $304.5 million of Earthstone’s historical DD&A expense, (ii) the elimination of $65.3 million of Novo’s historical DD&A expense, and (iii) pro forma incremental DD&A expense for the combined companies of $319.5 million for the year ended December 31, 2022. |
(i) | Reflects the elimination of Earthstone and Novo’s historical gains on sale of long-lived assets and related transaction costs, which would not have been incurred giving effect to the Merger as if they had been completed on January 1, 2022. |
(j) | Reflects pro forma interest expense resulting from (i) additional borrowings under the credit facility for the funding of the Novo Acquisition, (ii) giving effect to Earthstone’s senior notes assumed by Permian Resources in connection with the Merger, as if these notes had been in place and outstanding as of January 1, 2022, and (iii) the adjustment to debt discount amortization to reflect Earthstone’s senior notes at fair value as of the assumed January 1, 2022 closing date of the Merger, which in the aggregate resulted in the following adjustments: |
• | an increase in interest expense of $28.0 million in the pro forma combined statement of operations for the six months ended June 30, 2023 consisting of (i) the elimination of $50.1 million of Earthstone’s historical interest expense, (ii) pro forma interest expense of $48.4 million for Earthstone’s assumed senior notes, as if these notes had been outstanding since January 1, 2022 and their debt discount amortization at fair value as of the merger date, and (iii) pro forma interest expense of $29.7 million for additional borrowings under the credit facility; and |
• | an increase in interest expense of $72.4 million in the pro forma combined statement of operations for the year ended December 31, 2022 consisting of (i) the elimination of $66.8 million of Earthstone’s historical interest expense, (ii) pro forma interest expense of $97.5 million for Earthstone’s assumed senior notes, as if these notes had been outstanding since January 1, 2022 and their debt discount amortization at fair value as of the assumed January 1, 2022 closing date of the Merger, (iii) pro forma interest expense of $39.2 million for additional borrowings under the credit facility, and (iv) pro forma interest expense of $2.5 million related to a commitment fee paid by Permian Resources in conjunction with the Merger. |
Pro forma interest expense for the additional borrowings under the Company’s credit facility was calculated using the weighted average effective interest rate under the Company’s credit facility of 6.9% for the six months ended June 30, 2023 and 4.5% for the year ended December 31, 2022. The Company’s credit facility interest rate is based on a market-based benchmark interest rate plus an applicable margin that is dependent on the percentage of the borrowing base utilized. As a result, the Company’s credit facility interest rate is subject to market fluctuations.
The impact on net income attributable to Permian Resources Class A common stock of a 0.125% increase or decrease in the interest rate would be approximately $0.5 million for the six months ended June 30, 2023 and approximately $1.0 million for the year ended December 31, 2022.
(k) | Reflects the income tax effects of the transaction accounting adjustments and Earthstone’s Novo Transactions pro forma adjustments, where presented (which have been reduced by the corresponding net income attributable to noncontrolling interest that is not taxable to the c-corporation) at the statutory tax rate of 22.4%, for the year ended December 31, 2022 and six months ended June 30, 2023. The blended tax rate of 22.4% is calculated at the federal statutory rate of 21% plus the Company’s state-apportioned statutory rate, net of federal benefit, of 1.4%. |
(l) | Reflects net income attributable to noncontrolling interest owners discussed in item (g) above, which is not subject to U.S. federal or state income tax within the c-corporation. |
(m) | Reflects the adjustment to basic and diluted weighted average shares outstanding to reflect the issuance of Permian Resources common stock issued for merger consideration as if it was issued and outstanding as of January 1, 2022. The effect of potentially dilutive securities from the issuance of Permian Resources Class C common stock was determined using the “if-converted” method. |
(n) | Incorporates pro forma adjustments related to the Colgate Merger completed by Permian Resources during the year ended December 31, 2022. Refer to Note 4 below for further information on these transactions. |
Note 4 - Permian Resources Historical Merger
The Company completed its merger with Colgate, and all results of the acquired assets are included in the consolidated financial statements of Permian Resources following the August 31, 2022, the closing date of the Colgate Merger. The Colgate Merger has been accounted for as a business combination using the acquisition method of accounting, with the Company being identified as the accounting acquirer. Refer to Note 2—Business Combination under Part II, Item 8 of the Company’s Annual Report on Form 10-K for the year ended December 31, 2022 for further information regarding the Colgate Merger, merger consideration and purchase price allocation.
Due to the closing date of the Colgate Merger occurring on August 31, 2022, the financial results of Colgate are not included in the historical financial information of Permian Resources from January 1, 2022 through August 31, 2022. As a result, pro forma financial information has been prepared for the statement of operations of Permian Resources for the year ended December 31, 2022, giving effect to the Colgate Merger as if it had been completed on January 1, 2022.
The pro forma combined financial statements have been prepared from the respective historical consolidated financial statements of the Company and Colgate to reflect transaction accounting adjustments to the Company’s historical financial information that management believes are factually supportable and that are expected to have a continuing impact on results of operations, with the exception of certain nonrecurring items incurred in connection with the Colgate Merger.
PERMIAN RESOURCES CORPORATION HISTORICAL MERGER
UNAUDITED PRO FORMA COMBINED STATEMENT OF OPERATIONS
For the Year Ended December 31, 2022
(in thousands, except per share data)
Historical | Colgate Merger Adjustments |
Permian Resources Pro Forma |
||||||||||||||||
Permian Resources |
Colgate (1/1/22-8/31/22) |
|||||||||||||||||
Operating revenues |
(a) | (b) | ||||||||||||||||
Oil and gas sales |
$ | 2,131,265 | $ | 1,102,410 | $ | — | $ | 3,233,675 | ||||||||||
Operating expenses |
||||||||||||||||||
Lease operating expenses |
171,867 | 99,865 | — | 271,732 | ||||||||||||||
Severance and ad valorem taxes |
155,724 | 80,123 | — | 235,847 | ||||||||||||||
Gathering, processing and transportation expenses |
97,915 | 11,839 | — | 109,754 | ||||||||||||||
Depreciation, depletion, and amortization |
444,678 | 167,644 | 6,366 | (c) | 618,688 | |||||||||||||
General and administrative expenses |
159,554 | 23,179 | 18,136 | (d) | 200,869 | |||||||||||||
Merger and integration expense |
77,424 | — | — | 77,424 | ||||||||||||||
Profit sharing by affiliates |
— | 22,346 | (22,346 | ) | (e) | — | ||||||||||||
Impairment and abandonment expense |
3,875 | — | — | 3,875 | ||||||||||||||
Exploration and other expenses |
11,378 | 3,732 | — | 15,110 | ||||||||||||||
|
|
|
|
|
|
|
|
|||||||||||
Total operating expenses |
1,122,415 | 408,728 | 2,156 | 1,533,299 | ||||||||||||||
Net gain (loss) on sale of long-lived assets |
(1,314 | ) | 53,718 | (53,718 | ) | (f) | (1,314 | ) | ||||||||||
|
|
|
|
|
|
|
|
|||||||||||
Income (loss) from operations |
1,007,536 | 747,400 | (55,874 | ) | 1,699,062 | |||||||||||||
Other income (expense) |
||||||||||||||||||
Interest expense |
(95,645 | ) | (53,196 | ) | (8,014 | ) | (g) | (156,855 | ) | |||||||||
Net gain (loss) on derivative instruments |
(42,368 | ) | (386,058 | ) | — | (428,426 | ) | |||||||||||
Other income (expense) |
609 | 10 | — | 619 | ||||||||||||||
|
|
|
|
|
|
|
|
|||||||||||
Total other income (expense) |
(137,404 | ) | (439,244 | ) | (8,014 | ) | (584,662 | ) | ||||||||||
|
|
|
|
|
|
|
|
|||||||||||
Income (loss) before income taxes |
870,132 | 308,156 | (63,888 | ) | 1,114,400 | |||||||||||||
Income tax (expense) benefit |
(120,292 | ) | — | 7,468 | (h) | (112,824 | ) | |||||||||||
|
|
|
|
|
|
|
|
|||||||||||
Net income (loss) |
749,840 | 308,156 | (56,420 | ) | 1,001,576 | |||||||||||||
Less: Net (income) loss attributable to noncontrolling interest |
(234,803 | ) | — | (303,187 | ) | (i) | (537,990 | ) | ||||||||||
|
|
|
|
|
|
|
|
|||||||||||
Net income (loss) attributable to Class A common stock |
$ | 515,037 | $ | 308,156 | $ | (359,607 | ) | $ | 463,586 | |||||||||
|
|
|
|
|
|
|
|
|||||||||||
Income (loss) per share of Class A common stock: |
||||||||||||||||||
Basic |
$ | 1.80 | 1.62 | |||||||||||||||
Diluted |
$ | 1.61 | 1.45 | |||||||||||||||
Weighted average common shares outstanding: |
||||||||||||||||||
Basic |
286,160 | — | 286,160 | |||||||||||||||
Diluted |
322,816 | 763 | (j) | 323,579 |
The following adjustments included in the column labeled “Colgate Merger Adjustments” have been made to the unaudited pro forma financial statements of Permian Resources:
(a) | Permian Resources’ historical financial results for the year ended December 31, 2022 include the results of operations for assets acquired and liabilities assumed in the Colgate Merger from September 1, 2022 through December 31, 2022. |
(b) | Colgate’s historical financial results include its results of operations for the eight months from January 1, 2022 through August 31, 2022, the closing of the Colgate Merger. |
(c) | Reflects an increase in DD&A expense of $6.4 million in the pro forma combined statement of operations for the year ended December 31, 2022 consisting of (i) the elimination of $167.6 million of Colgate’s historical DD&A expense and (ii) pro forma incremental DD&A expense for the combined companies of $174.0 million for the year ended December 31, 2022. |
(d) | Reflects the expected incremental stock compensation expense related to equity-based restricted stock and performance stock units granted to employees in connection with and on the closing date of the Colgate Merger. |
(e) | Colgate’s historical profit sharing by affiliates expense represents cash payments made directly by affiliates of Colgate to members of its management team for profit interests that they were granted and then subsequently now own at CEP III Holdings, LLC and affiliated entities. These payments are not made directly by Colgate and in the future will not be made by the combined Company. Therefore, $22.3 million for the year end December 31, 2022, was eliminated from the statement of operations as these payments would not have been incurred giving effect to the Colgate Merger as if it had been completed on January 1, 2022. |
(f) | Reflects the elimination of Colgate’s historical gain on sale of long-lived assets that would not have been incurred giving effect to the Colgate Merger as if it had been completed on January 1, 2022. |
(g) | Reflects pro forma interest expense resulting from (i) additional borrowings under the Company’s credit facility for the cash consideration paid to Colgate unitholders, (ii) the assumption of Colgate’s borrowings outstanding under its credit facility as of the Colgate Merger closing date, as if the assumed borrowings had been outstanding since January 1, 2022, and (iii) the adjustment to debt discount amortization to reflect Colgate’s senior notes at fair value, which in the aggregate resulted in the following adjustments: |
• | an increase in interest expense of $8.0 million in the pro forma combined statement of operations for the year ended December 31, 2022 consisting of (i) the elimination of $53.2 million of Colgate’s historical interest expense, (ii) pro forma interest expense of $47.3 million for the senior notes, incorporating debt discount amortization based on the notes fair value as of the merger closing date , and (iii) additional pro forma interest expense of $13.9 million assumed for borrowings under the credit facility as of January 1, 2022. |
(h) | Reflects the income tax effects of the transaction accounting adjustments, where presented (which have been reduced by the corresponding net loss attributable to noncontrolling interest that is not taxable to the c-corporation) at the statutory tax rate of 22.6%, for the year ended December 31, 2022. The blended tax rate of 22.6% is calculated at the federal statutory rate of 21% plus the Company’s state-apportioned statutory rate of 1.6%. |
(i) | Reflects net income (loss) attributable to noncontrolling interest owners, which is not subject to U.S. federal or state income tax within the c-corporation. In connection with the Colgate Merger, 269.3 million shares of Permian Resources Class C common stock were issued for the share consideration to Colgate unitholders including underlying Permian Resources OpCo Units. The issuance of these units creates a noncontrolling interest in the Company, which is equal to approximately 48% of Permian Resources common stock issued and outstanding as of December 31, 2022. |
(j) | Considers the effect of potentially dilutive securities from (i) the Permian Resources Class C common stock issued for the Colgate Merger consideration using the “if-converted” method assuming the Colgate Merger was completed on January 1, 2022; and (ii) unvested equity-based restricted stock and performance stock units granted in connection with the Colgate Merger using the treasury stock method. |
Note 5 - Earthstone’s Novo Transactions
On June 14, 2023, Earthstone OpCo entered into (i) a Securities Purchase Agreement with Novo Oil & Gas Legacy Holdings, LLC, Novo Intermediate, LLC and Novo Oil & Gas Holdings, LLC (collectively “Novo”), pursuant to which Earthstone agreed to acquire 100% of the issued and outstanding equity interests of Novo (the “Novo Acquisition”) and (ii) an Acquisition and Cooperation Agreement with Northern Oil and Gas, Inc. (“NOG”), pursuant to which NOG agreed to acquire, immediately after the closing of the Novo Acquisition, an undivided and one-third interest in Novo’s oil and gas assets acquired in the Novo Acquisition for net proceeds of $468.4 million (the “Novo Divestiture” together with the Novo Acquisition, Earthstone’s “Novo Transactions”).
Earthstone’s Novo Transactions were completed on August 15, 2023. After taking into account preliminary customary purchase price adjustments at closing, Earthstone paid aggregate cash consideration of approximately $1.4 billion, which was funded with a combination of cash on hand of $543.4 million (which included the net proceeds received from NOG pursuant to the Novo Divestiture discussed above) and $861.9 million in borrowings under Earthstone’s credit facility.
The Novo Acquisition was deemed to be material to an investor’s understanding of Earthstone’s business that is being acquired by Permian Resources in the Merger and has therefore been included in the pro forma combined financial statements. The financial impact of the net assets acquired by Earthstone in these transactions is not included in Earthstone’s consolidated financial statements due to Earthstone’s Novo Transactions’ closing date of August 15, 2023, which was subsequent to the periods presented herein. As a result, pro forma financial information for Earthstone’s Novo Transactions has been included in the Company’s pro forma combined financial statements assuming Earthstone’s Novo Transactions were completed on June 30, 2023 for the pro forma combined balance sheet and on January 1, 2022 for the pro forma combined statements of operations. Earthstone’s Novo Transactions pro forma information is presented below and was determined as follows:
(i) Novo Historical - derived from Novo’s historical unaudited interim financial information for the six months ended June 30, 2023 and from Novo’s audited financial information for the year ended December 31, 2022;
(ii) Unacquired Portion of Novo - reflects the unacquired portion of Novo based upon information provided by Earthstone and assumptions made by the Company that management believes are reasonable based upon information available at the time of this filing; and
(iii) Novo Portion Sold to NOG - reflects adjustments to remove the oil and gas property interests sold to NOG in the Novo Divestiture.
This information is based on historical results of operations, adjusted for certain estimated accounting adjustments, and certain assumptions that management believes are reasonable, and does not represent the actual results of operations if the transactions would have occurred on January 1, 2022, nor is it necessarily indicative of future results.
EARTHSTONE’S NOVO TRANSACTIONS
UNAUDITED PRO FORMA COMBINED BALANCE SHEET
As of June 30, 2023
(in thousands) |
Novo Historical |
Unacquired Portion of Novo |
Novo Portion Sold to NOG |
Earthstone’s Novo Transactions |
||||||||||||
ASSETS |
(i) | (ii) | (iii) | |||||||||||||
Current assets |
||||||||||||||||
Cash and cash equivalents |
$ | 19,224 | $ | — | $ | 468,436 | $ | 487,660 | ||||||||
Accounts receivable, net |
66,398 | (9,969 | ) | — | 56,429 | |||||||||||
Derivative instruments |
30,471 | (30,471 | ) | — | — | |||||||||||
Prepaid and other current assets |
1,575 | (1,487 | ) | — | 88 | |||||||||||
|
|
|
|
|
|
|
|
|||||||||
Total current assets |
117,668 | (41,927 | ) | 468,436 | 544,177 | |||||||||||
Property and Equipment |
||||||||||||||||
Oil and natural gas properties, successful efforts method |
||||||||||||||||
Unproved properties |
56,708 | (21,814 | ) | — | 34,894 | |||||||||||
Proved properties |
1,257,560 | (55,932 | ) | (468,436 | ) | 733,192 | ||||||||||
Accumulated depreciation, depletion and amortization |
(293,536 | ) | 12,214 | — | (281,322 | ) | ||||||||||
|
|
|
|
|
|
|
|
|||||||||
Total oil and natural gas properties, net |
1,020,732 | (65,532 | ) | (468,436 | ) | 486,764 | ||||||||||
Other property and equipment, net |
221 | (207 | ) | — | 14 | |||||||||||
|
|
|
|
|
|
|
|
|||||||||
Total property and equipment, net |
1,020,953 | (65,739 | ) | (468,436 | ) | 486,778 | ||||||||||
Noncurrent assets |
||||||||||||||||
Operating lease right-of-use assets |
22 | (22 | ) | — | — | |||||||||||
Other noncurrent assets |
9,116 | (9,116 | ) | — | — | |||||||||||
|
|
|
|
|
|
|
|
|||||||||
TOTAL ASSETS |
$ | 1,147,759 | $ | (116,804 | ) | $ | — | $ | 1,030,955 | |||||||
|
|
|
|
|
|
|
|
|||||||||
LIABILITIES AND EQUITY |
||||||||||||||||
Current liabilities |
||||||||||||||||
Accounts payable and accrued expenses |
$ | 91,492 | $ | (2,074 | ) | $ | — | $ | 89,418 | |||||||
Operating lease liabilities |
22 | (22 | ) | — | — | |||||||||||
Derivative Instruments |
9,969 | (9,969 | ) | — | — | |||||||||||
Other current liabilities |
2,333 | — | — | 2,333 | ||||||||||||
|
|
|
|
|
|
|
|
|||||||||
Total current liabilities |
103,816 | (12,065 | ) | — | 91,751 | |||||||||||
Noncurrent liabilities |
||||||||||||||||
Long-term debt, net |
350,000 | (350,000 | ) | — | — | |||||||||||
Asset retirement obligations |
2,856 | — | — | 2,856 | ||||||||||||
Deferred revenues |
21,194 | — | — | 21,194 | ||||||||||||
Derivative liability |
3,796 | (3,796 | ) | — | — | |||||||||||
|
|
|
|
|
|
|
|
|||||||||
Total liabilities |
481,662 | (365,861 | ) | — | 115,801 | |||||||||||
Shareholders’ equity |
||||||||||||||||
Member’s equity |
666,097 | 249,057 | — | 915,154 | ||||||||||||
|
|
|
|
|
|
|
|
|||||||||
TOTAL LIABILITIES AND EQUITY |
$ | 1,147,759 | $ | (116,804 | ) | $ | — | $ | 1,030,955 | |||||||
|
|
|
|
|
|
|
|
EARTHSTONE’S NOVO TRANSACTIONS
UNAUDITED PRO FORMA COMBINED STATEMENT OF OPERATIONS
For the Six Months Ended June 30, 2023
(in thousands) | Novo Historical | Unacquired Portion of Novo |
Novo Portion Sold to NOG |
Earthstone’s Novo Transactions |
||||||||||||
Operating revenues |
(i) | (ii) | (iii) | |||||||||||||
Oil and gas sales |
$ | 383,058 | $ | (64,663 | ) | $ | (106,132 | ) | $ | 212,263 | ||||||
Operating expenses |
||||||||||||||||
Lease operating expenses |
50,599 | — | (16,867 | ) | 33,732 | |||||||||||
Severance and ad valorem taxes |
28,567 | (4,749 | ) | (7,939 | ) | 15,879 | ||||||||||
Depreciation, depletion, and amortization |
81,668 | (4,164 | ) | (25,835 | ) | 51,669 | ||||||||||
General and administrative expenses |
19,128 | (1,887 | ) | — | 17,241 | |||||||||||
Exploration and other expenses |
123 | (123 | ) | — | — | |||||||||||
|
|
|
|
|
|
|
|
|||||||||
Total operating expense |
180,085 | (10,923 | ) | (50,641 | ) | 118,521 | ||||||||||
Net gain (loss) on sale of long-lived assets |
16 | (16 | ) | — | — | |||||||||||
|
|
|
|
|
|
|
|
|||||||||
Income (loss) from operations |
$ | 202,989 | $ | (53,756 | ) | $ | (55,491 | ) | $ | 93,742 | ||||||
Other income (expense) |
||||||||||||||||
Interest expense |
(13,298 | ) | 13,298 | — | — | |||||||||||
Gain (loss) on commodity derivatives |
28,912 | (28,912 | ) | — | — | |||||||||||
Other income (expense) |
(1,760 | ) | (6 | ) | — | (1,766 | ) | |||||||||
|
|
|
|
|
|
|
|
|||||||||
Total other income (expense) |
13,854 | (15,620 | ) | — | (1,766 | ) | ||||||||||
|
|
|
|
|
|
|
|
|||||||||
Income before income taxes |
216,843 | (69,376 | ) | (55,491 | ) | 91,976 | ||||||||||
Income tax expense |
(160 | ) | — | 53 | (107 | ) | ||||||||||
|
|
|
|
|
|
|
|
|||||||||
Net Income |
$ | 216,683 | $ | (69,376 | ) | $ | (55,438 | ) | $ | 91,869 | ||||||
|
|
|
|
|
|
|
|
For the Year Ended December 31, 2022
(in thousands) | Novo Historical | Unacquired Portion of Novo |
Novo Portion Sold to NOG |
Earthstone’s Novo Transactions |
||||||||||||
Operating revenues |
(i) | (ii) | (iii) | |||||||||||||
Oil and gas sales |
$ | 663,540 | $ | (92,250 | ) | $ | (190,430 | ) | $ | 380,860 | ||||||
Operating expenses |
||||||||||||||||
Lease operating expenses |
45,326 | — | (15,109 | ) | 30,217 | |||||||||||
Severance and ad valorem taxes |
48,969 | (7,574 | ) | (13,798 | ) | 27,597 | ||||||||||
Gathering, processing and transportation expenses |
||||||||||||||||
Depreciation, depletion, and amortization |
102,851 | (4,889 | ) | (32,654 | ) | 65,308 | ||||||||||
General and administrative expenses |
8,641 | (818 | ) | — | 7,823 | |||||||||||
Exploration and other expenses |
808 | (282 | ) | — | 526 | |||||||||||
|
|
|
|
|
|
|
|
|||||||||
Total operating expense |
206,595 | (13,563 | ) | (61,561 | ) | 131,471 | ||||||||||
Net gain (loss) on sale of long-lived assets |
(60 | ) | 136 | — | 76 | |||||||||||
|
|
|
|
|
|
|
|
|||||||||
Income (loss) from operations |
$ | 456,885 | $ | (78,551 | ) | $ | (128,869 | ) | $ | 249,465 | ||||||
Other income (expense) |
||||||||||||||||
Interest expense |
(8,791 | ) | 8,791 | — | — | |||||||||||
Gain (loss) on commodity derivatives |
(10,325 | ) | 10,325 | — | — | |||||||||||
Other income (expense) |
2,664 | 88 | — | 2,752 | ||||||||||||
|
|
|
|
|
|
|
|
|||||||||
Total other income (expense) |
(16,452 | ) | 19,204 | — | 2,752 | |||||||||||
|
|
|
|
|
|
|
|
|||||||||
Income before income taxes |
440,433 | (59,347 | ) | (128,869 | ) | 252,217 | ||||||||||
Income tax expense |
(403 | ) | 52 | 117 | (234 | ) | ||||||||||
|
|
|
|
|
|
|
|
|||||||||
Net Income |
$ | 440,030 | $ | (59,295 | ) | $ | (128,752 | ) | $ | 251,983 | ||||||
|
|
|
|
|
|
|
|
Note 6 - Supplemental Pro Forma Information About Oil and Natural Gas Producing Activities
The following tables present estimated pro forma combined proved oil and gas reserve information as of and for the year ended December 31, 2022. The amounts included below represent the respective estimates made as of December 31, 2022 by Permian Resources, Earthstone, and Novo while they were separate companies. These estimates have not been updated for changes in development plans or other factors, which may have occurred subsequent to December 31, 2022, including the Merger. This pro forma information has been prepared for illustrative purposes and is not intended to be a projection of future results. Future results may vary significantly from the results presented.
Estimated Quantities of Proved Oil and Gas Reserves
The following tables present the estimated pro forma combined net estimated proved developed and undeveloped oil and gas reserves information as of December 31, 2022, along with a summary of changes in quantities of proved oil and gas reserves:
Crude Oil (MBbls) | ||||||||||||||||
Permian Resources Historical |
Earthstone Historical |
Earthstone’s Novo Transactions(1) |
Pro Forma Combined |
|||||||||||||
Total proved reserves: |
||||||||||||||||
Balance - December 31, 2021 |
153,453 | 61,075 | 20,200 | 234,728 | ||||||||||||
Extensions and discoveries |
51,906 | 13,430 | 4,652 | 69,988 | ||||||||||||
Revisions to previous estimates |
(22,181 | ) | (7,432 | ) | (2,131 | ) | (31,744 | ) | ||||||||
Purchases of reserves in place |
124,072 | 85,237 | 70 | 209,379 | ||||||||||||
Divestitures of reserves in place |
(1,983 | ) | (2,044 | ) | — | (4,027 | ) | |||||||||
Production |
(18,235 | ) | (11,866 | ) | (2,259 | ) | (32,360 | ) | ||||||||
|
|
|
|
|
|
|
|
|||||||||
Balance - December 31, 2022 |
287,032 | 138,400 | 20,532 | 445,964 | ||||||||||||
|
|
|
|
|
|
|
|
|||||||||
Proved developed reserves: |
||||||||||||||||
December 31, 2021 |
77,973 | 35,824 | 4,364 | 118,161 | ||||||||||||
December 31, 2022 |
156,941 | 88,759 | 12,335 | 258,035 | ||||||||||||
Proved undeveloped reserves: |
||||||||||||||||
December 31, 2021 |
75,480 | 25,251 | 15,836 | 116,567 | ||||||||||||
December 31, 2022 |
130,091 | 49,641 | 8,197 | 187,929 |
Natural Gas (MMcf) | ||||||||||||||||
Permian Resources Historical |
Earthstone Historical |
Earthstone’s Novo Transactions(1) |
Pro Forma Combined |
|||||||||||||
Total proved reserves: |
||||||||||||||||
Balance - December 31, 2021 |
577,005 | 284,881 | 224,893 | 1,086,779 | ||||||||||||
Extensions and discoveries |
144,316 | 51,346 | 20,743 | 216,405 | ||||||||||||
Revisions to previous estimates |
(111,405 | ) | 37,316 | (26,620 | ) | (100,709 | ) | |||||||||
Purchases of reserves in place |
494,221 | 429,646 | 979 | 924,846 | ||||||||||||
Divestitures of reserves in place |
(10,874 | ) | (6,631 | ) | — | (17,505 | ) | |||||||||
Production |
(59,692 | ) | (54,392 | ) | (18,022 | ) | (132,106 | ) | ||||||||
|
|
|
|
|
|
|
|
|||||||||
Balance - December 31, 2022 |
1,033,571 | 742,166 | 201,973 | 1,977,710 | ||||||||||||
|
|
|
|
|
|
|
|
|||||||||
Proved developed reserves: |
||||||||||||||||
December 31, 2021 |
326,223 | 190,999 | 58,861 | 576,083 | ||||||||||||
December 31, 2022 |
652,270 | 574,762 | 143,669 | 1,370,701 | ||||||||||||
Proved undeveloped reserves: |
||||||||||||||||
December 31, 2021 |
250,782 | 93,882 | 166,032 | 510,696 | ||||||||||||
December 31, 2022 |
381,301 | 167,404 | 58,304 | 607,009 |
Natural Gas Liquids (MBbls) | ||||||||||||||||
Permian Resources Historical |
Earthstone Historical |
Earthstone’s Novo Transactions(1) |
Pro Forma Combined |
|||||||||||||
Total proved reserves: |
||||||||||||||||
Balance - December 31, 2021 |
55,583 | 39,031 | 24,473 | 119,087 | ||||||||||||
Extensions and discoveries |
19,387 | 7,895 | 3,837 | 31,119 | ||||||||||||
Revisions to previous estimates |
(9,279 | ) | 11,663 | 4,787 | 7,171 | |||||||||||
Purchases of reserves in place |
66,437 | 56,268 | 148 | 122,853 | ||||||||||||
Divestitures of reserves in place |
(2,527 | ) | (1,417 | ) | — | (3,944 | ) | |||||||||
Production |
(6,750 | ) | (7,599 | ) | (2,607 | ) | (16,956 | ) | ||||||||
|
|
|
|
|
|
|
|
|||||||||
Balance - December 31, 2022 |
122,851 | 105,841 | 30,638 | 259,330 | ||||||||||||
|
|
|
|
|
|
|
|
|||||||||
Proved developed reserves: |
||||||||||||||||
December 31, 2021 |
30,318 | 25,917 | 6,242 | 62,477 | ||||||||||||
December 31, 2022 |
74,940 | 80,168 | 20,944 | 176,052 | ||||||||||||
Proved undeveloped reserves: |
||||||||||||||||
December 31, 2021 |
25,265 | 13,114 | 18,231 | 56,610 | ||||||||||||
December 31, 2022 |
47,911 | 25,673 | 9,694 | 83,278 |
(1) | Represents reserves acquired as a part of Earthstone’s Novo Transactions discussed in Note 5, which have been adjusted to reflect solely the portion of Novo’s oil and gas reserves retained by Earthstone. |
Standardized Measure of Discounted Future Net Cash Flows
The pro forma combined standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves as of December 31, 2022 is as follows:
Year Ended December 31, 2022 | ||||||||||||||||
(in thousands) | Permian Resources Historical |
Earthstone Historical |
Earthstone’s Novo Transactions(1) |
Pro Forma Combined |
||||||||||||
Future cash inflows |
$ | 36,444,649 | $ | 21,506,026 | $ | 4,013,814 | $ | 61,964,489 | ||||||||
Future development costs |
(3,051,047 | ) | (1,207,597 | ) | (195,155 | ) | (4,453,799 | ) | ||||||||
Future production costs |
(9,381,857 | ) | (6,362,901 | ) | (1,258,890 | ) | (17,003,648 | ) | ||||||||
Future income tax expenses |
(4,821,696 | ) | (1,910,370 | ) | (4,213 | ) | (6,736,279 | ) | ||||||||
|
|
|
|
|
|
|
|
|||||||||
Future net cash flows |
19,190,049 | 12,025,158 | 2,555,556 | 33,770,763 | ||||||||||||
10% discount to reflect timing of cash flows |
(9,764,471 | ) | (5,300,657 | ) | (925,442 | ) | (15,990,570 | ) | ||||||||
|
|
|
|
|
|
|
|
|||||||||
Standardized measure of discounted future net cash flows |
$ | 9,425,578 | $ | 6,724,501 | $ | 1,630,114 | $ | 17,780,193 | ||||||||
|
|
|
|
|
|
|
|
The changes in the pro forma combined standardized measure of discounted future net cash flows relating to proved reserves for the year ended December 31, 2022 are as follows:
Year Ended December 31, 2022 | ||||||||||||||||
(in thousands) | Permian Resources Historical |
Earthstone Historical |
Earthstone’s Novo Transactions(1) |
Pro Forma Combined |
||||||||||||
Standardized measure of discounted future net cash flows, beginning of period |
$ | 3,396,320 | $ | 1,818,372 | $ | 941,569 | $ | 6,156,261 | ||||||||
Sales of oil, natural gas and NGLs, net of production costs |
(1,705,759 | ) | (1,341,586 | ) | (317,711 | ) | (3,365,056 | ) | ||||||||
Purchase of minerals in place |
5,555,649 | 2,011,980 | 8,760 | 7,576,389 | ||||||||||||
Divestiture of minerals in place |
(103,030 | ) | (76,570 | ) | — | (179,600 | ) | |||||||||
Extensions and discoveries, net of future development costs |
1,789,830 | 1,178,521 | 303,632 | 3,271,983 | ||||||||||||
Previously estimated development costs incurred during the period |
369,088 | 246,705 | 103,008 | 718,801 | ||||||||||||
Net change in prices and production costs |
2,508,583 | 3,838,439 | 489,293 | 6,836,315 | ||||||||||||
Change in estimated future development costs |
85,931 | (295,553 | ) | (32,632 | ) | (242,254 | ) | |||||||||
Revisions of previous quantity estimates |
(1,127,536 | ) | 3,283 | (25,082 | ) | (1,149,335 | ) | |||||||||
Accretion of discount |
387,747 | 345,642 | 94,330 | 827,719 | ||||||||||||
Net change in income taxes |
(1,807,957 | ) | (866,805 | ) | (818 | ) | (2,675,580 | ) | ||||||||
Net change in timing of production and other |
76,712 | (137,927 | ) | 65,765 | 4,550 | |||||||||||
|
|
|
|
|
|
|
|
|||||||||
Standardized measure of discounted future net cash flows, end of period |
$ | 9,425,578 | $ | 6,724,501 | $ | 1,630,114 | $ | 17,780,193 | ||||||||
|
|
|
|
|
|
|
|
(1) | Represents reserves acquired as a part of Earthstone’s Novo Transactions discussed in Note 5, which have been adjusted to reflect the portion retained by Earthstone. |
Exhibit 99.3
EARTHSTONE ENERGY, INC.
Index to Consolidated Financial Statements and Supplementary Information
Page | ||||
Report of Independent Registered Public Accounting Firm (Moss Adams LLP, Houston Texas, PCAOB ID: 659) |
F-2 | |||
Audited Financial Statements: |
||||
Consolidated Balance Sheets as of December 31, 2022 and 2021 |
F-5 | |||
Consolidated Statements of Operations for the Years Ended December 31, 2022, 2021 and 2020 |
F-7 | |||
Consolidated Statements of Equity for the Years Ended December 31, 2022, 2021 and 2020 |
F-8 | |||
Consolidated Statements of Cash Flows for the Years Ended December 31, 2022, 2021 and 2020 |
F-9 | |||
Notes to Consolidated Financial Statements |
F-10 | |||
Unaudited Information: |
||||
Supplemental Information on Oil and Gas Exploration and Production Activities |
F-41 |
F-1
Report of Independent Registered Public Accounting Firm
To the Shareholders and the Board of Directors of
Earthstone Energy, Inc.
Opinion on the Financial Statements
We have audited the accompanying consolidated balance sheets of Earthstone Energy, Inc. and subsidiaries (the “Company”) as of December 31, 2022 and 2021, the related consolidated statements of operations, equity, and cash flows for each of the three years in the period ended December 31, 2022, and the related notes (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the consolidated financial position of the Company as of December 31, 2022 and 2021, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2022, in conformity with accounting principles generally accepted in the United States of America.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (“PCAOB”), the Company’s internal control over financial reporting as of December 31, 2022, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated March 8, 2023 expressed an unqualified opinion on the Company’s internal control over financial reporting.
Basis for Opinion
These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s consolidated financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures to respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audits provide a reasonable basis for our opinion.
Critical Audit Matters
The critical audit matters communicated below are matters arising from the current period audit of the (consolidated) financial statements that were communicated or required to be communicated to the audit committee and that (1) relate to accounts or disclosures that are material to the consolidated financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matters below, providing a separate opinion on the critical audit matters or on the accounts or disclosures to which they relate.
F-2
Assessment of the Estimated Proved Oil and Gas Reserves on the Determination of Depreciation, Depletion and Amortization Expense related to Proved Oil and Natural Gas Properties
The Company’s net proved oil and natural gas properties balance was $3,657 million as of December 31, 2022, and the associated depreciation, depletion and amortization (DD&A) expense for the year ended December 31, 2022 was $302 million. As described in Note 7 to the consolidated financial statements, the Company follows the successful efforts method of accounting for its oil and natural gas properties. The Company’s lease acquisition costs and development costs of proved oil and natural gas properties are amortized using the units-of-production method, at the field level, based on total estimated proved oil and natural gas reserves and estimated proved developed oil and natural gas reserves, respectively.
The principal considerations for our determination that performing procedures relating to the impact of proved oil and natural gas reserves on proved net oil and natural gas properties is a critical audit matter are there was (i) significant judgment by management, including the use of specialists, when developing the estimates of proved oil and natural gas reserves; (ii) a high degree of auditor judgment, subjectivity and effort in performing procedures and evaluating management’s significant assumptions related to developing those estimates, including future production amounts and costs, historical oil and natural gas prices, pricing differentials, and future development costs including the Company’s ability to convert proved undeveloped reserves to producing properties within five years of their initial proved booking.
Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the consolidated financial statements. The procedures we performed to address this critical audit matter included:
(i) | Obtaining an understanding, evaluating the design and testing the operating effectiveness of controls over the Company’s process to calculate DD&A, including management’s controls over the completeness and accuracy of the financial data provided to the Company’s engineering technical team and independent petroleum engineering consulting firm for use in estimating the proved oil and gas reserves; |
(ii) | Evaluating the significant assumptions used by management in developing these estimates, including future production, historical oil and gas prices, pricing differentials, and future development costs; |
(iii) | Evaluating management’s development plan for compliance with the SEC rule that undrilled locations are scheduled to be drilled within five years, by assessing consistency of the development projections with the Company’s drill plan and the availability of capital relative to the drill plan; |
(iv) | Utilizing the work of management’s specialists to evaluate the reasonableness of the estimates of proved oil and natural gas reserves. As a basis for this work, the specialists’ qualifications and objectivity were assessed, as well as the reasonableness of methods and assumptions used by the specialists. The procedures performed also included testing the data used by the specialists and evaluating the specialists’ findings. Evaluating the significant assumptions relating to the estimates of proved oil and natural gas reserves also involved obtaining evidence to support whether the assumptions used were consistent with the past performance of the Company, and whether they were consistent with evidence obtained in other areas of the audit; |
(v) | Testing the inputs of and recalculating management’s DD&A calculation. |
Acquisition of Chisholm Energy Operating, LLC and Chisholm Energy Agent, Inc (collectively “Chisholm”) - Valuation of Proved Oil and Natural Gas Properties
As described in Note 4 to the consolidated financial statements, $633.5 million was allocated to proved oil and natural gas properties related to the purchase price of Chisholm on February 15, 2022. As disclosed by management, the Company accounts for business combinations under the acquisition method of accounting. Accordingly, the Company recognizes amounts for identifiable assets acquired and liabilities assumed equal to their estimated acquisition date fair values. The fair value estimate of proved oil and natural gas properties as of an acquisition date was based on estimated proved oil and natural gas reserves and related future net cash flows discounted using a weighted average cost of capital, including estimates and assumptions of future commodity prices and costs, the timing of development activities, projections of oil and natural gas reserves and estimates to abandon and reclaim producing wells. As disclosed by management, the accuracy of the reserve estimates is a function of the quality of data available and of engineering and geological interpretation and judgment. In addition, estimates of reserves may be revised based on actual production, results of subsequent exploration and development activities, recent commodity prices, operating costs and other factors. The estimates of oil and natural gas reserves have been developed by specialists, specifically petroleum engineers.
F-3
The principal considerations for our determination that performing procedures relating to the allocation and valuation of proved oil and natural gas properties acquired in the Chisholm acquisition is a critical audit matter are the (i) the significant judgment by management, including the use of specialists, when determining the fair value of the acquired oil and gas properties, which in turn led to (ii) a high degree of auditor judgment, subjectivity, and effort in performing procedures and evaluating management’s significant assumptions related to production volumes, future commodity prices and price differentials, lease operating costs, reserve risk adjustment factors, and the weighted average cost of capital; and (iii) the audit effort involved the use of professionals with specialized skill and knowledge.
Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the consolidated financial statements. The primary procedures we performed to address this critical audit matter included:
(i) | Obtaining an understanding, evaluating the design and testing the operating effectiveness of controls over the Company’s process to determine the fair value of assets acquired in the business combination, including management’s controls over the completeness and accuracy of the financial data provided to the Company’s engineering technical team for use in estimating the proved oil and gas reserves used in the fair value calculation; |
(ii) | Gaining an understanding of management’s process for developing the fair value measurement of proved natural gas and oil properties; |
(iii) | Evaluating the appropriateness of the discounted cash flow model, which included testing the completeness and accuracy of underlying data used in the model; and evaluating significant assumptions used by management related to future production volumes, future commodity prices and price differentials, lease operating costs, risk adjustment factors, as well as the weighted average cost of capital. The evaluation of management’s assumption related to future commodity prices involved comparing the prices against observable market data. Professionals with specialized skill and knowledge were used to assist in the evaluation of the weighted average cost of capital assumption and the appropriateness of the discounted cash flow model; |
(iv) | Evaluating the professional qualifications and objectivity of the Company’s engineer primarily responsible for overseeing the preparation of the reserve estimates by the internal engineering staff. |
(v) | Assessing the competence, capability and objectivity of the outside valuation consultants engaged by the Company to measure the fair value of the acquired crude oil and natural gas properties including the valuation methodology selected. |
/s/ Moss Adams LLP
Houston, Texas
March 8, 2023
We have served as the Company’s auditor since 2018.
F-4
EARTHSTONE ENERGY, INC.
CONSOLIDATED BALANCE SHEETS
(In thousands, except share and per share amounts)
December 31, | ||||||||
2022 | 2021 | |||||||
ASSETS | ||||||||
Current assets: |
||||||||
Cash |
$ | — | $ | 4,013 | ||||
Accounts receivable: |
||||||||
Oil, natural gas, and natural gas liquids revenues |
161,531 | 50,575 | ||||||
Joint interest billings and other, net of allowance of $19 and $19 at December 31, 2022 and 2021, respectively |
34,549 | 2,930 | ||||||
Derivative asset |
31,331 | 1,348 | ||||||
Prepaid expenses and other current assets |
18,854 | 2,549 | ||||||
|
|
|
|
|||||
Total current assets |
246,265 | 61,415 | ||||||
|
|
|
|
|||||
Oil and gas properties, successful efforts method: |
||||||||
Proved properties |
3,987,901 | 1,625,367 | ||||||
Unproved properties |
282,589 | 222,025 | ||||||
Land |
5,482 | 5,382 | ||||||
|
|
|
|
|||||
Total oil and gas properties |
4,275,972 | 1,852,774 | ||||||
|
|
|
|
|||||
Accumulated depreciation, depletion and amortization |
(619,196 | ) | (395,625 | ) | ||||
|
|
|
|
|||||
Net oil and gas properties |
3,656,776 | 1,457,149 | ||||||
Other noncurrent assets: |
||||||||
Office and other equipment, net of accumulated depreciation of $5,273 and $4,547 at December 31, 2022 and 2021, respectively |
5,394 | 1,986 | ||||||
Derivative asset |
9,117 | 157 | ||||||
Operating lease right-of-use assets |
4,569 | 1,795 | ||||||
Other noncurrent assets |
15,280 | 33,865 | ||||||
|
|
|
|
|||||
TOTAL ASSETS |
$ | 3,937,401 | $ | 1,556,367 | ||||
|
|
|
|
|||||
LIABILITIES AND EQUITY | ||||||||
Current liabilities: |
||||||||
Accounts payable |
$ | 91,815 | $ | 31,397 | ||||
Revenues and royalties payable |
163,368 | 36,189 | ||||||
Accrued expenses |
80,942 | 31,704 | ||||||
Asset retirement obligation |
948 | 395 | ||||||
Derivative liability |
14,053 | 45,310 | ||||||
Advances |
7,312 | 4,088 | ||||||
Operating lease liability |
842 | 681 | ||||||
Finance lease liability |
802 | — | ||||||
Other current liabilities |
16,202 | 851 | ||||||
|
|
|
|
|||||
Total current liabilities |
376,284 | 150,615 | ||||||
Noncurrent liabilities: |
||||||||
Long-term debt |
1,053,879 | 320,000 | ||||||
Asset retirement obligation |
29,611 | 15,471 | ||||||
Derivative liability |
— | 571 | ||||||
Deferred tax liability |
138,336 | 15,731 | ||||||
Operating lease liability |
3,889 | 1,276 | ||||||
Finance lease liability |
876 | — | ||||||
Other noncurrent liabilities |
10,509 | 6,442 | ||||||
|
|
|
|
|||||
Total noncurrent liabilities |
1,237,100 | 359,491 | ||||||
|
|
|
|
|||||
Commitments and Contingencies (Note 15) |
||||||||
Equity: |
||||||||
Preferred stock, $0.001 par value, 20,000,000 shares authorized; none issued or outstanding |
— | — | ||||||
Series A Convertible Preferred Stock, $0.001 par value, none authorized, issued or outstanding |
— | — | ||||||
Class A Common Stock, $0.001 par value, 200,000,000 shares authorized; 105,547,139 and 53,467,307 issued and outstanding at December 31, 2022 and 2021, respectively |
106 | 53 |
F-5
Class B Common Stock, $0.001 par value, 50,000,000 shares authorized; 34,259,641 and 34,344,532 issued and outstanding at December 31, 2022 and 2021, respectively |
34 | 34 | ||||||
Additional paid-in capital |
1,346,463 | 718,181 | ||||||
Retained Earnings (accumulated deficit) |
292,711 | (159,774 | ) | |||||
|
|
|
|
|||||
Total Earthstone Energy, Inc. equity |
1,639,314 | 558,494 | ||||||
Noncontrolling interest |
684,703 | 487,767 | ||||||
|
|
|
|
|||||
Total equity |
2,324,017 | 1,046,261 | ||||||
|
|
|
|
|||||
TOTAL LIABILITIES AND EQUITY |
$ | 3,937,401 | $ | 1,556,367 | ||||
|
|
|
|
The accompanying notes are an integral part of these consolidated financial statements.
F-6
EARTHSTONE ENERGY, INC.
CONSOLIDATED STATEMENTS OF OPERATIONS
(In thousands, except share and per share amounts)
Years Ended December 31, | ||||||||||||
2022 | 2021 | 2020 | ||||||||||
REVENUES |
||||||||||||
Oil |
$ | 1,114,343 | $ | 297,177 | $ | 120,355 | ||||||
Natural gas |
303,846 | 50,809 | 8,567 | |||||||||
Natural gas liquids |
276,965 | 71,657 | 15,601 | |||||||||
|
|
|
|
|
|
|||||||
Total revenues |
1,695,154 | 419,643 | 144,523 | |||||||||
|
|
|
|
|
|
|||||||
OPERATING COSTS AND EXPENSES |
||||||||||||
Lease operating expense |
230,515 | 49,321 | 29,131 | |||||||||
Production and ad valorem taxes |
123,054 | 26,409 | 9,411 | |||||||||
Rig idle and termination expense |
— | — | 426 | |||||||||
Impairment expense |
— | — | 64,498 | |||||||||
Depreciation, depletion and amortization |
301,813 | 106,367 | 96,414 | |||||||||
General and administrative expense |
74,175 | 41,922 | 28,233 | |||||||||
Transaction costs |
8,248 | 4,875 | 622 | |||||||||
Accretion of asset retirement obligation |
2,652 | 1,065 | 307 | |||||||||
Exploration expense |
2,492 | 341 | 298 | |||||||||
|
|
|
|
|
|
|||||||
Total operating costs and expenses |
742,949 | 230,300 | 229,340 | |||||||||
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Gain on sale of oil and gas properties, net |
13,900 | 738 | 204 | |||||||||
Income (loss) from operations |
966,105 | 190,081 | (84,613 | ) | ||||||||
OTHER INCOME (EXPENSE) |
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Interest expense, net |
(66,821 | ) | (10,796 | ) | (5,232 | ) | ||||||
(Loss) gain on derivative contracts, net |
(125,107 | ) | (116,761 | ) | 59,899 | |||||||
Other income, net |
856 | 841 | 400 | |||||||||
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Total other (expense) income |
(191,072 | ) | (126,716 | ) | 55,067 | |||||||
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Income (loss) before income taxes |
775,033 | 63,365 | (29,546 | ) | ||||||||
Income tax (expense) benefit |
(124,416 | ) | (1,859 | ) | 112 | |||||||
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Net income (loss) |
650,617 | 61,506 | (29,434 | ) | ||||||||
Less: Net income (loss) attributable to noncontrolling interest |
198,132 | 26,022 | (15,887 | ) | ||||||||
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Net income (loss) attributable to Earthstone Energy, Inc. |
$ | 452,485 | $ | 35,484 | $ | (13,547 | ) | |||||
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Net income (loss) per common share attributable to Earthstone Energy, Inc.: |
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Basic |
$ | 5.12 | $ | 0.75 | $ | (0.45 | ) | |||||
Diluted |
$ | 4.83 | $ | 0.71 | $ | (0.45 | ) | |||||
Weighted average common shares outstanding: |
||||||||||||
Basic |
88,349,088 | 47,169,948 | 29,911,625 | |||||||||
Diluted |
96,328,217 | 49,952,093 | 29,911,625 |
The accompanying notes are an integral part of these consolidated financial statements.
F-7
EARTHSTONE ENERGY, INC.
CONSOLIDATED STATEMENTS OF EQUITY
(In thousands, except share amounts)
Issued Shares | ||||||||||||||||||||||||||||||||||||||||||||
Series A Convertible Preferred Stock |
Class A Common Stock |
Class B Common Stock |
Series A Convertible Preferred Stock |
Class A Common Stock |
Class B Common Stock |
Additional Paid-in Capital |
Accumulated Deficit |
Earthstone Energy, Inc. Equity |
Noncontrolling Interest |
Total Equity |
||||||||||||||||||||||||||||||||||
At December 31, 2019 |
— | 29,421,131 | 35,260,680 | $ | — | $ | 29 | $ | 35 | $ | 527,246 | $ | (181,711 | ) | $ | 345,599 | $ | 490,152 | $ | 835,751 | ||||||||||||||||||||||||
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Stock-based compensation expense |
— | — | — | — | — | — | 10,054 | — | 10,054 | — | 10,054 | |||||||||||||||||||||||||||||||||
Vesting of restricted stock units, net of taxes paid |
— | 670,981 | — | — | 1 | — | (1 | ) | — | — | — | — | ||||||||||||||||||||||||||||||||
Vested restricted stock units retained by the Company in exchange for payment of recipient mandatory tax withholdings |
— | 243,924 | — | — | — | — | (835 | ) | — | (835 | ) | — | (835 | ) | ||||||||||||||||||||||||||||||
Cancellation of treasury shares |
— | (243,924 | ) | — | — | — | — | — | — | — | — | — | ||||||||||||||||||||||||||||||||
Class B Common Stock converted to Class A Common Stock |
— | 251,309 | (251,309 | ) | — | — | — | 3,610 | — | 3,610 | (3,610 | ) | — | |||||||||||||||||||||||||||||||
Net loss |
— | — | — | — | — | — | — | (13,547 | ) | (13,547 | ) | (15,887 | ) | (29,434 | ) | |||||||||||||||||||||||||||||
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At December 31, 2020 |
— | 30,343,421 | 35,009,371 | $ | — | $ | 30 | $ | 35 | $ | 540,074 | $ | (195,258 | ) | $ | 344,881 | $ | 470,655 | $ | 815,536 | ||||||||||||||||||||||||
Stock-based compensation expense |
— | — | — | — | — | — | 9,132 | — | 9,132 | — | 9,132 | |||||||||||||||||||||||||||||||||
Modification of performance units |
— | — | — | — | — | — | (2,276 | ) | — | (2,276 | ) | — | (2,276 | ) | ||||||||||||||||||||||||||||||
Shares issued in connection with IRM Acquisition |
— | 12,719,594 | — | — | 13 | — | 76,559 | — | 76,572 | — | 76,572 | |||||||||||||||||||||||||||||||||
Shares issued in connection with Tracker Acquisition |
— | 6,200,000 | — | — | 6 | — | 61,808 | — | 61,814 | — | 61,814 | |||||||||||||||||||||||||||||||||
Shares issued in connection with Foreland Acquisition |
— | 2,611,111 | — | — | 2 | — | 28,119 | — | 28,121 | — | 28,121 | |||||||||||||||||||||||||||||||||
Vesting of restricted stock units, net of taxes paid |
— | 928,342 | — | — | 1 | — | (1 | ) | — | — | — | — | ||||||||||||||||||||||||||||||||
Class A Shares retained by the Company in exchange for payment of recipient mandatory tax withholdings |
— | 453,483 | — | — | — | — | (4,144 | ) | — | (4,144 | ) | — | (4,144 | ) | ||||||||||||||||||||||||||||||
Cancellation of treasury shares |
— | (453,483 | ) | — | — | — | — | — | — | — | — | — | ||||||||||||||||||||||||||||||||
Class B Common Stock converted to Class A Common Stock |
— | 664,839 | (664,839 | ) | — | 1 | (1 | ) | 8,910 | — | 8,910 | (8,910 | ) | — | ||||||||||||||||||||||||||||||
Net income |
— | — | — | — | — | — | — | 35,484 | 35,484 | 26,022 | 61,506 | |||||||||||||||||||||||||||||||||
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At December 31, 2021 |
— | 53,467,307 | 34,344,532 | $ | — | $ | 53 | $ | 34 | $ | 718,181 | $ | (159,774 | ) | $ | 558,494 | $ | 487,767 | $ | 1,046,261 | ||||||||||||||||||||||||
Stock-based compensation expense |
— | — | — | — | — | — | 16,733 | — | 16,733 | — | 16,733 | |||||||||||||||||||||||||||||||||
Purchase of treasury shares |
— | (3,000,000 | ) | — | — | (3 | ) | — | (43,934 | ) | — | (43,937 | ) | — | (43,937 | ) | ||||||||||||||||||||||||||||
Preferred stock issuance |
280,000 | — | — | — | — | — | 279,326 | — | 279,326 | — | 279,326 | |||||||||||||||||||||||||||||||||
Conversion of preferred stock |
(280,000 | ) | 25,225,225 | — | — | 25 | — | (25 | ) | — | — | — | — | |||||||||||||||||||||||||||||||
Shares issued in connection with Chisholm Acquisition |
— | 19,417,476 | — | — | 19 | — | 249,495 | — | 249,514 | — | 249,514 | |||||||||||||||||||||||||||||||||
Shares issued in connection with Bighorn Acquisition |
— | 5,650,977 | — | — | 6 | — | 77,752 | — | 77,758 | — | 77,758 | |||||||||||||||||||||||||||||||||
Shares issued in connection with Titus Acquisition |
— | 3,857,015 | — | — | 4 | — | 53,570 | — | 53,574 | — | 53,574 | |||||||||||||||||||||||||||||||||
Vesting of restricted stock units, net of taxes paid |
— | 844,248 | — | — | 2 | — | (2 | ) | — | — | — | — | ||||||||||||||||||||||||||||||||
Class A Shares retained by the Company in exchange for payment of recipient mandatory tax withholdings |
— | 429,547 | — | — | — | — | (5,829 | ) | — | (5,829 | ) | — | (5,829 | ) | ||||||||||||||||||||||||||||||
Cancellation of Treasury shares |
— | (429,547 | ) | — | — | — | — | — | — | — | — | — | ||||||||||||||||||||||||||||||||
Class B Common Stock converted to Class A Common Stock |
— | 84,891 | (84,891 | ) | — | — | — | 1,196 | — | 1,196 | (1,196 | ) | — | |||||||||||||||||||||||||||||||
Net income |
— | — | — | — | — | — | — | 452,485 | 452,485 | 198,132 | 650,617 | |||||||||||||||||||||||||||||||||
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At December 31, 2022 |
— | 105,547,139 | 34,259,641 | — | 106 | 34 | 1,346,463 | 292,711 | 1,639,314 | 684,703 | 2,324,017 | |||||||||||||||||||||||||||||||||
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The accompanying notes are an integral part of these consolidated financial statements.
F-8
EARTHSTONE ENERGY, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands)
Years Ended December 31, | ||||||||||||
2022 | 2021 | 2020 | ||||||||||
Cash flows from operating activities: |
||||||||||||
Net income (loss) |
$ | 650,617 | $ | 61,506 | $ | (29,434 | ) | |||||
Adjustments to reconcile net income (loss) to net cash provided by operating activities: |
||||||||||||
Impairment of proved and unproved oil and gas properties |
— | — | 46,878 | |||||||||
Depreciation, depletion and amortization |
301,813 | 106,367 | 96,414 | |||||||||
Accretion of asset retirement obligations |
2,652 | 1,065 | 307 | |||||||||
Impairment of goodwill |
— | — | 17,620 | |||||||||
Gain on sale of oil and gas properties, net |
(13,900 | ) | (738 | ) | (204 | ) | ||||||
Gain on sale of office and other equipment |
(321 | ) | (140 | ) | — | |||||||
Settlement of asset retirement obligations |
(910 | ) | (185 | ) | (195 | ) | ||||||
Total loss (gain) on derivative contracts, net |
125,107 | 116,761 | (59,899 | ) | ||||||||
Operating portion of net cash (paid) received in settlement of derivative contracts |
(195,876 | ) | (75,966 | ) | 56,044 | |||||||
Stock-based compensation |
35,369 | 21,014 | 10,054 | |||||||||
Deferred income taxes |
122,605 | 1,859 | (657 | ) | ||||||||
Amortization of deferred financing costs |
5,529 | 856 | 322 | |||||||||
Changes in assets and liabilities: |
||||||||||||
(Increase) decrease in accounts receivable |
(168,314 | ) | (19,061 | ) | 11,914 | |||||||
(Increase) decrease in prepaid expenses and other current assets |
(16,282 | ) | 58 | (203 | ) | |||||||
Increase (decrease) in accounts payable and accrued expenses |
68,726 | 9,293 | 481 | |||||||||
Increase (decrease) in revenues and royalties payable |
98,840 | 5,985 | (8,323 | ) | ||||||||
Increase (decrease) in advances |
3,224 | 2,200 | (9,617 | ) | ||||||||
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Net cash provided by operating activities |
1,018,879 | 230,874 | 131,502 | |||||||||
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Cash flows from investing activities: |
||||||||||||
Acquisition of oil and gas properties (net of cash acquired) |
(1,523,813 | ) | (311,324 | ) | — | |||||||
Additions to oil and gas properties |
(491,836 | ) | (114,521 | ) | (88,097 | ) | ||||||
Additions to office and other equipment |
(2,133 | ) | (1,365 | ) | (114 | ) | ||||||
Proceeds from sale of oil and gas properties |
49,546 | 975 | 414 | |||||||||
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Net cash used in investing activities |
(1,968,236 | ) | (426,235 | ) | (87,797 | ) | ||||||
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Cash flows from financing activities: |
||||||||||||
Proceeds from borrowings under Credit Agreement |
3,096,013 | 744,132 | 136,056 | |||||||||
Repayments of borrowings under Credit Agreement |
(3,145,877 | ) | (539,132 | ) | (191,056 | ) | ||||||
Proceeds from issuance of 8% Senior Notes due 2027, net |
537,256 | — | — | |||||||||
Proceeds from term loan |
244,191 | — | — | |||||||||
Proceeds from issuance Series A Convertible Preferred Stock, net of offering costs of $674 |
279,326 | — | — | |||||||||
Cash paid to repurchase Class A Common Stock |
(43,937 | ) | — | — | ||||||||
Cash paid related to the exchange and cancellation of Class A Common Stock |
(5,829 | ) | (4,144 | ) | (836 | ) | ||||||
Cash paid for finance leases |
(649 | ) | (70 | ) | (130 | ) | ||||||
Deferred financing costs |
(15,150 | ) | (2,906 | ) | (67 | ) | ||||||
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Net cash provided by (used in) financing activities |
945,344 | 197,880 | (56,033 | ) | ||||||||
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|||||||
Net increase (decrease) in cash |
(4,013 | ) | 2,519 | (12,328 | ) | |||||||
Cash at beginning of period |
4,013 | 1,494 | 13,822 | |||||||||
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Cash at end of period |
$ | — | $ | 4,013 | $ | 1,494 | ||||||
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Supplemental disclosures of cash flow information (Note 19)
The accompanying notes are an integral part of these consolidated financial statements.
F-9
EARTHSTONE ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 1. Organization and Basis of Presentation
Earthstone Energy, Inc., a Delaware corporation (“Earthstone” and together with its consolidated subsidiaries, the “Company”), is a growth-oriented independent oil and natural gas development and production company. In addition, the Company is active in corporate mergers and the acquisition of oil and natural gas properties that have production and future development opportunities. The Company’s operations are all in the up-stream segment of the oil and natural gas industry and all its properties are onshore in the United States.
Earthstone is the sole managing member of Earthstone Energy Holdings, LLC, a Delaware limited liability company (together with its wholly-owned consolidated subsidiaries, “EEH”), with a controlling interest in EEH. Earthstone, together with its wholly-owned subsidiary, Lynden Energy Corp., a corporation organized under the laws of British Columbia (“Lynden Corp”), and Lynden Corp’s wholly-owned consolidated subsidiary, Lynden USA Inc. (“Lynden US”), collectively own a 75.5% interest in EEH. The Company consolidates the financial results of EEH and presents a noncontrolling interest in the Consolidated Financial Statements representing the economic interests of EEH’s members other than Earthstone and Lynden US. Each of the outstanding shares of Class A common stock, $0.001 par value per share of Earthstone (the “Class A Common Stock”), has a corresponding unit of limited liability company interests denominated as a common unit in EEH (an “EEH Unit”). Each of the outstanding shares of Class B common stock, $0.001 par value per share of Earthstone (the “Class B Common Stock”), has a corresponding EEH Unit and collectively represent the noncontrolling interests in the Consolidated Financial Statements.
At any time, at the holder’s discretion, a holder of an EEH Unit may receive a share of Class A Common Stock in exchange for an EEH Unit and a corresponding share of Class B Common Stock, resulting in the immediate cancellation of both the EEH Unit and share of Class B Common Stock exchanged. As of December 31, 2022, outstanding common shares of Earthstone, along with the equal number of corresponding outstanding EEH Units, were approximately 139.8 million, consisting of 105.5 million shares of Class A Common Stock and 34.3 million shares of Class B Common Stock.
Note 2. Noncontrolling Interest
Noncontrolling Interest represents EEH Units held by members of EEH other than Earthstone and Lynden US and is presented as a component of equity in the Consolidated Balance Sheets as of December 31, 2022 and 2021, as well as an adjustment to Net income in the Consolidated Statements of Operations for the years ended December 31, 2022 and 2021. Pursuant to governing EEH agreements, the noncontrolling members have no direct participation in the operations of EEH.
Earthstone consolidates the financial results of EEH and its subsidiaries, and presents a noncontrolling interest for the economic interest in Earthstone held by members of EEH other than Earthstone and Lynden US, and represented by outstanding shares of Class B Common Stock. Net income attributable to noncontrolling interest in the Consolidated Statements of Operations for the year ended December 31, 2022 represents the portion of net income attributable to the economic interest in the Company held by members of EEH other than Earthstone and Lynden US. The noncontrolling interest in the Consolidated Balance Sheet as of December 31, 2022 represents the portion of net assets of the Company attributable to members of EEH other than Earthstone and Lynden US.
F-10
EARTHSTONE ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
The following table presents the changes in noncontrolling interest for the year ended December 31, 2022:
EEH Units Held By Earthstone and Lynden US |
% | EEH Units Held By Others |
% | Total EEH Units Outstanding |
||||||||||||||||
As of December 31, 2021 |
53,467,307 | 60.9 | % | 34,344,532 | 39.1 | % | 87,811,839 | |||||||||||||
EEH Units issued in connection with the Chisholm Acquisition |
19,417,476 | — | 19,417,476 | |||||||||||||||||
EEH Units issued in connection with the Bighorn Acquisition |
5,650,977 | — | 5,650,977 | |||||||||||||||||
EEH Units issued in connection with the Conversion of Preferred Stock |
25,225,225 | — | 25,225,225 | |||||||||||||||||
EEH Units issued in connection with the Titus Acquisition |
3,857,015 | — | 3,857,015 | |||||||||||||||||
EEH Units and shares of Class B Common Stock exchanged for shares of Class A Common Stock |
84,891 | (84,891 | ) | — | ||||||||||||||||
EEH Units issued in connection with the vesting of restricted stock units |
844,248 | — | 844,248 | |||||||||||||||||
EEH Units cancelled in connection with the share repurchase |
(3,000,000 | ) | — | (3,000,000 | ) | |||||||||||||||
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As of December 31, 2022 |
105,547,139 | 75.5 | % | 34,259,641 | 24.5 | % | 139,806,780 | |||||||||||||
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Note 3. Summary of Significant Accounting Policies
Principles of Consolidation
The Consolidated Financial Statements include the accounts and balances of the Company and have been prepared in accordance with accounting principles generally accepted in the United States (“GAAP”). All intercompany accounts and transactions, including revenues and expenses, are eliminated in consolidation.
Use of Estimates
The preparation of the Company’s Consolidated Financial Statements in conformity with GAAP requires the Company’s management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities, if any, at the date of the Consolidated Financial Statements and the reported amounts of revenues and expenses during the respective reporting periods then ended.
Estimated quantities of crude oil, natural gas and natural gas liquids reserves are the most significant of the Company’s estimates. All reserve data used in the preparation of the Consolidated Financial Statements, as well as included in Note 20. Supplemental Information On Oil And Gas Exploration And Production Activities (Unaudited), are based on estimates. Reservoir engineering is a subjective process of estimating underground accumulations of crude oil, natural gas and natural gas liquids. There are numerous uncertainties inherent in estimating quantities of proved crude oil, natural gas and natural gas liquids reserves. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. As a result, reserve estimates may be different from the quantities of crude oil, natural gas and natural gas liquids that are ultimately recovered.
Other items subject to estimates and assumptions include, but are not limited to, the carrying amounts of property, plant and equipment, asset retirement obligations, valuation allowances for deferred income tax assets, valuation of derivative instruments and valuation of certain performance-based restricted stock unit awards. Management evaluates estimates and assumptions on an ongoing basis using historical experience and other factors, including the current economic and commodity price environment. The volatility of commodity prices results in increased uncertainty inherent in such estimates and assumptions. See Note 20. Supplemental Information On Oil and Gas Exploration and Production Activities (Unaudited).
Although management believes these estimates are reasonable, actual results may differ from estimates and assumptions of future events and these revisions could be material. Future production may vary materially from estimated oil and natural gas proved reserves. Actual future prices may vary significantly from price assumptions used for determining proved reserves and for financial reporting.
F-11
EARTHSTONE ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
Accounts Receivable
Accounts receivable include estimated amounts due from crude oil, natural gas, and natural gas liquids purchasers, other operators for which the Company holds an interest, and from non-operating working interest owners. Accrued crude oil, natural gas, and natural gas liquids sales from purchasers and operators consist of accrued revenues due under normal trade terms, generally requiring payment within 60 days of production. For receivables from joint interest owners, the Company typically has the ability to withhold future revenue disbursements to recover any non-payment of joint interest billings.
An allowance for doubtful accounts is established based on reviews of individual customer accounts, recent loss experience, current economic conditions, and other pertinent factors. Accounts deemed uncollectible are charged to the allowance.
Provisions for bad debts and recoveries on accounts previously charged off are added to the allowance. The Company routinely assesses the recoverability of all material trade receivables and other receivables to determine their collectability. Allowance for uncollectible accounts receivable was $0.02 million and $0.02 million at December 31, 2022 and 2021, respectively.
Derivative Instruments
The Company utilizes derivative instruments in order to manage exposure to risks associated with fluctuating commodity prices and interest rates. The Company recognizes all derivatives as either assets or liabilities, measured at fair value, and recognizes changes in the fair value of derivatives in current earnings. The Company has elected to not designate any of its positions under the hedge accounting rules. Accordingly, these derivative contracts are mark-to-market and any changes in the estimated values of derivative contracts held at the balance sheet date are recognized in (Loss) gain on derivative contracts, net in the Consolidated Statements of Operations as unrealized gains or losses on derivative contracts. Realized gains or losses on derivative contracts are also recognized in (Loss) gain on derivative contracts, net in the Consolidated Statements of Operations.
Oil and Natural Gas Properties
The method of accounting for oil and natural gas properties determines what costs are capitalized and how these costs are ultimately matched with revenues and expenses. The Company uses the successful efforts method of accounting for oil and natural gas properties. For more information see Note 8. Oil and Natural Gas Properties.
Office and Other Equipment
Office and other equipment primarily includes leasehold improvements, vehicles, computer equipment and software, office furniture and fixtures and field equipment. These items are recorded at cost, or fair value if acquired, and are depreciated using the straight-line method based on expected lives of the individual assets or group of assets ranging from two years to 10 years. The Company had office and other equipment of $5.4 million and $2.0 million, net of accumulated depreciation and amortization of $5.3 million and $4.5 million, at December 31, 2022 and 2021, respectively. During the years ended December 31, 2022, 2021 and 2020, the Company recognized depreciation expense of $1.3 million, $0.7 million and $0.5 million, respectively. See separate finance lease disclosures in Note 18. Leases.
Noncontrolling Interest
Noncontrolling Interest represents third-party equity ownership of EEH and is presented as a component of equity in the Consolidated Balance Sheets as of December 31, 2022 and 2021, as well as an adjustment to Net income in the Consolidated Statements of Operations for the years ended December 31, 2022 and 2021. As of December 31, 2022, Earthstone and Lynden US owned a 75.5% membership interest in EEH while Bold Energy Holdings, LLC (“Bold Holdings”), the noncontrolling third-party, or its permitted transferees, owned the remaining 24.5%. See further discussion in Note 2. Noncontrolling Interest.
Segment Reporting
Operating segments are components of an enterprise that (i) engage in activities from which it may earn revenues and incur expenses (ii) for which separate operational financial information is available and is regularly evaluated by the chief operating decision maker for the purpose of allocating resources and assessing performance.
Based on the Company’s organization and management, it has only one reportable operating segment, which is oil and natural gas exploration and production.
Comprehensive Income
The Company has no elements of comprehensive income other than net income.
Asset Retirement Obligations
Asset retirement obligations associated with the retirement of long-lived assets are recognized as liabilities with an increase to the carrying amounts of the related long-lived assets in the period incurred. The cost of the asset, including the asset retirement cost, is depreciated over the useful life of the asset. Asset retirement obligations are recorded at estimated fair value, measured by reference to the expected future cash outflows required to satisfy the retirement obligations discounted at the Company’s credit-adjusted risk-free interest rate.
F-12
EARTHSTONE ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
Accretion expense is recognized over time as the discounted liabilities are accreted to their expected settlement value. If estimated future costs of asset retirement obligations change, an adjustment is recorded to both the asset retirement obligations and the long-lived asset. Revisions to estimated asset retirement obligations can result from changes in retirement cost estimates, revisions to estimated inflation rates, and changes in the estimated timing of abandonment. For further discussion, see Note 13. Asset Retirement Obligations.
Business Combinations
The Company accounts for its acquisitions of oil and gas properties not commonly controlled in accordance with Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) Topic 805, Business Combinations, which, among other things, requires the Company to determine if an asset or a business has been acquired. If the Company determines an asset(s) has been acquired, the asset(s) acquired, as well as any liabilities assumed, are measured and recorded at the acquisition date cost. If the Company determines a business has been acquired, the assets acquired and liabilities assumed are measured and recorded at their fair values as of the acquisition date, recording goodwill for amounts paid in excess of fair value.
Revenue Recognition
The Company’s revenues are comprised solely of revenues from customers and include the sale of oil, natural gas and natural gas liquids. The Company believes that the disaggregation of revenue into these three major product types, as presented in the Consolidated Statements of Operations, appropriately depicts how the nature, amount, timing and uncertainty of revenue and cash flows are affected by economic factors based on its single geographic region. Revenues are recognized when the recognition criteria of ASC 606 “Revenue from Contracts with Customers,” (“ASC 606”) are met, which generally occurs at a point in time when production is sold to a purchaser at a determinable price, delivery has occurred, control has transferred and collection of the revenue is probable. The Company fulfills its performance obligations under its customer contracts through delivery of oil, natural gas and natural gas liquids and revenues are recorded on a monthly basis and the Company receives payment from one to three months after delivery. Generally, each unit of product represents a separate performance obligation. The prices received for oil, natural gas and natural gas liquids sales under the Company’s contracts are generally derived from stated market prices which are then adjusted to reflect deductions including transportation, fractionation and processing. As a result, revenues from the sale of oil, natural gas and natural gas liquids will decrease if market prices decline. The sales of oil, natural gas and natural gas liquids, as presented on the Consolidated Statements of Operations, represent the Company’s share of revenues net of royalties and excluding revenue interests owned by others. When selling oil, natural gas and natural gas liquids on behalf of royalty or working interest owners, the Company is acting as an agent and thus reports the revenue on a net basis. To the extent actual volumes and prices of oil and natural gas sales are unavailable for a given reporting period because of timing or information not received from third parties, the expected sales volumes and prices for those properties are estimated and recorded. Variances between the Company’s estimated revenue and actual payment are recorded in the month the payment is received. Historically, however, differences have been insignificant.
At the end of each month when the performance obligation is satisfied, the variable consideration can be reasonably estimated and amounts due from customers are recorded in “Accounts receivable: oil, natural gas, and natural gas liquids revenues” in the Consolidated Balance Sheets. As of December 31, 2022 and 2021, amounts receivable from contracts with customers were $161.5 million and $50.6 million, respectively. Taxes assessed by governmental authorities on oil, natural gas and natural gas liquid sales are presented separately from such revenues in the Consolidated Statements of Operations.
Oil Sales
Oil production is transported from the wellhead to tank batteries or delivery points through flow-lines or gathering systems. Purchasers of the oil take delivery at (i) the tank batteries and transport the oil by truck, or (ii) at a pipeline delivery point and the Company collects a market price, net of pricing differentials. Revenue is recognized when control transfers to the purchaser at the net price received by the Company. Starting in October 2019, certain of the Company’s oil sales activity involves buy/sell arrangements that effect a change in location with required repurchase of oil at a delivery point. Because the Company acts as the agent in these transactions, the buy/sell activity is recorded on a net basis and the residual transportation fee is included in Lease operating expenses in the Consolidated Statements of Operations.
Natural Gas and Natural Gas Liquid Sales
Under the Company’s natural gas sales arrangements, the purchaser takes control of wet gas at a delivery point near the wellhead or at the inlet of the purchaser’s processing facility. The purchaser gathers and processes the wet gas and remits proceeds to the Company for the resulting natural gas and natural gas liquid sales. Based on the nature of these arrangements, the Company is the agent and the purchaser is the Company’s customer, thus, the Company recognizes natural gas and natural gas liquid sales based on the net amount of proceeds received from the purchaser.
F-13
EARTHSTONE ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
Imbalances
The Company recognizes revenue for all oil, natural gas and natural gas liquid sold to purchasers regardless of whether the sales are proportionate to the Company’s ownership interest in the property. Production imbalances are recognized as a liability to the extent an imbalance on a specific property exceeds the Company’s share of remaining proved oil, natural gas liquid and natural gas reserves. The Company is also subject to natural gas pipeline imbalances, which are recorded as accounts receivable or payable at values consistent with contractual arrangements with the owner of the pipeline. The Company had no imbalances as of December 31, 2022 or 2021.
Contract Balances
Under the Company’s product sales contracts, the Company invoices customers once performance obligations have been satisfied, at which point payment is unconditional. Accordingly, the Company’s product sales contracts do not give rise to contract assets or liabilities under ASC 606.
Transaction Price Allocated to Remaining Performance Obligations
Substantially all of the Company’s product sales are short-term in nature, with a contract term of one year or less. For these contracts, the Company has utilized the practical expedient in ASC 606 which exempts the Company from the requirements to disclose the transaction price allocated to remaining performance obligations if the performance obligation is part of a contract that has an original expected duration of one year or less.
For the Company’s product sales that have a contract term greater than one year, the Company has utilized the practical expedient in ASC 606 which states the Company is not required to disclose the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. Under these contracts, each unit of product generally represents a separate performance obligation; therefore, future volumes are wholly unsatisfied, and disclosure of the transaction price allocated to remaining performance obligations is not required.
Prior-Period Performance Obligations
The Company records revenue in the month that product is delivered to the purchaser. Settlement statements for certain natural gas and natural gas liquids sales, however, may not be received for 30 to 90 days after the date the product is delivered, and as a result the Company is required to estimate the amount of product delivered to the purchaser and the price that will be received for the sale of the product. In these situations, the Company records the differences between its estimates and the actual amounts received for product sales in the month that payment is received from the purchaser. Any identified differences between the Company’s revenue estimates and actual revenue received have historically been insignificant. For the years ended December 31, 2022 and 2021, revenue recognized in the reporting period related to performance obligations satisfied in prior reporting periods was not material.
Concentration of Credit Risk
Credit risk represents the actual or perceived financial loss that the Company would record if its purchasers, operators, or counterparties failed to perform pursuant to contractual terms.
The purchasers of the Company’s oil, natural gas, and natural gas liquids production consist primarily of independent marketers, major oil and natural gas companies and natural gas pipeline companies. Historically, the Company has not experienced any significant losses from uncollectible accounts. In the year ended December 31, 2022, three purchasers accounted for 21%, 20% and 14%, respectively, of the Company’s oil, natural gas, and natural gas liquids revenues. In the year ended December 31, 2021, two purchasers accounted for 34% and 13%, respectively, of the Company’s oil, natural gas, and natural gas liquids revenues. In the year ended December 31, 2020, three purchasers accounted for 32%, 15% and 12%, respectively, of the Company’s oil, natural gas, and natural gas liquids revenues. No other purchaser accounted for 10% or more of the Company’s oil, natural gas, and natural gas liquids revenues during the years ended December 31, 2022, 2021 or 2020. Additionally, at December 31, 2022, four purchasers accounted for 21%, 19% , 18% and 14%, respectively, of the Company’s oil, natural gas and natural gas liquids receivables. At December 31, 2021, three purchasers accounted for 26%, 21% and 12%, respectively, of the Company’s oil, natural gas, and natural gas liquids receivables. No other purchaser accounted for 10% or more of the Company’s oil, natural gas, and natural gas liquids receivables at December 31, 2022 and 2021.
The Company holds working interests in oil and natural gas properties for which a third-party serves as operator. The operator sells the oil, natural gas, and natural gas liquids to the purchaser, collects the cash, and distributes the cash to the Company. In the year ended December 31, 2022, one operator distributed 8% of the Company’s oil, natural gas and natural gas liquids revenues. In the year ended December 31, 2021 one operator distributed 13% of the Company’s oil, natural gas and natural gas liquids revenues. In the year ended December 31, 2020, one operator distributed 15% of the Company’s oil, natural gas and natural gas liquids revenues.
F-14
EARTHSTONE ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
The derivative instruments of the Company are with a small number of counterparties and, from time-to-time, may represent material assets in the Consolidated Balance Sheets. It is our policy to enter into derivative contracts only with counterparties that are creditworthy financial institutions deemed by management as competent and competitive. At December 31, 2022, the Company had a net derivative asset position of $26.4 million. At December 31, 2021, the Company had a net derivative liability position of $44.4 million.
The Company regularly maintains its cash in bank deposit accounts. Balances held by the Company at its banks typically exceed Federal Deposit Insurance Corporation (“FDIC”) insurance coverage and, as a result, there is a concentration of credit risk related to the amounts of deposit in excess of FDIC insurance coverage.
Stock-Based Compensation
The Company recognized stock-based compensation expense associated with restricted stock units, which include both time- and performance-based awards. The Company accounts for forfeitures of equity-based incentive awards as they occur. Stock-based compensation expense related to time-based restricted stock units is based on the price of the Class A Common Stock on the grant date and recognized over the vesting period using the straight-line method. The Company classifies grants to be settled in shares as equity awards and awards to be settled in cash a liability awards. The Company accounts for these awards based on a grant date Monte Carlo Simulation pricing model, which calculates multiple potential outcomes for an award and establishes fair value based on the most likely outcome, and is recognized over the vesting period using the straight-line method. The fair value of the liability awards is updated on a quarterly basis. See Note 11. Stock-Based Compensation for further details.
Income Taxes
The Company is a U.S. company operating in Texas and New Mexico, as of December 31, 2022, and includes one foreign legal entity, Lynden Corp, which is a Canadian company. Consequently, the Company’s tax provision is based upon the tax laws and rates in effect in the applicable jurisdiction in which its operations are conducted and income is earned. The income tax rates imposed and methods of computing taxable income in these jurisdictions vary. Therefore, as a part of the process of preparing the Consolidated Financial Statements, the Company is required to estimate the income taxes in each of these jurisdictions. This process involves estimating the actual current tax exposure together with assessing temporary differences resulting from differing treatment of items, such as depreciation, amortization and certain accrued liabilities for tax and accounting purposes. The Company’s effective tax rate for financial statement purposes will continue to fluctuate from year to year as its operations are conducted in different taxing jurisdictions.
The Company records an income tax provision consistent with its status as a corporation. The Company’s corporate structure requires the filing of two separate consolidated U.S. Federal income tax returns and one Canadian income tax return resulting from Earthstone’s acquisition of Lynden Corp in May 2016 (the “Lynden Arrangement”) that includes Lynden US, Earthstone, and Lynden Corp. As such, taxable income of Earthstone cannot be offset by tax attributes, including net operating losses, of Lynden US, nor can taxable income of Lynden US be offset by tax attributes of Earthstone. Earthstone and Lynden US record a tax provision, respectively, for their share of the book income or loss of EEH, net of the noncontrolling interest, as well as any standalone income or loss generated by each company. As EEH is treated as a partnership for U.S. Federal income tax purposes, it is not subject to income tax at the federal level and only recognizes the Texas Margin Tax.
The Company’s deferred tax expense or benefit represents the change in the balance of deferred tax assets or liabilities reported in the Consolidated Balance Sheets. Valuation allowances are established to reduce deferred tax assets when it is more likely than not that some portion or all of the deferred tax assets will not be realized. At December 31, 2022 and 2021, the Company has recorded a valuation allowance for its deferred tax assets in the Consolidated Balance Sheets.
The Company applies the accounting standards related to uncertainty in income taxes. This accounting guidance clarifies the accounting for uncertainties in income taxes by prescribing a minimum recognition threshold that a tax position is required to meet before being recognized in the Consolidated Financial Statements. It requires that the Company recognize in the Consolidated Financial Statements the financial effects of a tax position, if that position is more likely than not of being sustained upon examination, including resolution of any appeals or litigation processes, based upon the technical merits of the position. It also provides guidance on measurement, classification, interest, penalties and disclosure. The Company’s tax positions related to its pass-through status and state income tax liability, including deductibility of expenses, have been reviewed by the Company’s management and they believe those positions would more likely than not be sustained upon examination. Accordingly, the Company has not recorded an income tax liability for uncertain tax positions at December 31, 2022 or 2021.
F-15
EARTHSTONE ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
Recently Issued Accounting Standards
Reference Rate Reform - In March 2020, the FASB issued an update that provides optional guidance for a limited period of time to ease the transition from LIBOR to an alternative reference rate. The ASU intends to address certain concerns relating to
accounting for contract modifications and hedge accounting. The Company amended its credit facility on January 30, 2022, which, among other things, provided mechanics relating to the transition from LIBOR to a benchmark replacement rate. The transition from LIBOR did not have a material impact on the Company’s consolidated financial statements.
Note 4. Acquisitions and Divestitures
The initial accounting for acquisitions and divestitures may not be complete and adjustments to provisional amounts, or recognition of additional assets acquired or liabilities assumed, may occur as additional information is obtained about the facts and circumstances that existed as of the acquisition dates.
Titus Acquisition
On June 27, 2022, Earthstone and EEH, as buyer, and Titus Oil & Gas Production, LLC, a Delaware limited liability company, Titus Oil & Gas Corporation, a Delaware corporation, Lenox Minerals, LLC, a Delaware limited liability company and Lenox Mineral Title Holdings, Inc., a Delaware corporation (collectively, “Titus I”), as seller, entered into a purchase and sale agreement (the “Titus I Purchase Agreement”) which provided that EEH or its designated wholly-owned subsidiary would acquire (the “Titus I Acquisition”) interests in oil and gas leases and related property of Titus I located in the Northern Delaware Basin of New Mexico (the “Titus I Assets”). Also on June 27, 2022, Earthstone and EEH, as buyer, and Titus Oil & Gas Production II, LLC, a Delaware limited liability company, Lenox Minerals II, LLC, a Delaware limited liability company and Lenox Mineral Holdings II, Inc., a Delaware limited liability company (collectively, “Titus II” and together with Titus I, “Titus”), as seller, entered into a purchase and sale agreement (the “Titus II Purchase Agreement” and together with the Titus I Purchase Agreement, the “Titus Purchase Agreements”) which provided that EEH or its designated wholly-owned subsidiary would acquire (the “Titus II Acquisition” and together with the Titus I Acquisition, the “Titus Acquisition”) interests in oil and gas leases and related property of Titus II located in the Northern Delaware Basin of New Mexico (the “Titus II Assets” and together with the Titus I Assets, the “Titus Assets”).
On August 10, 2022, the transactions contemplated in the Titus Purchase Agreements were consummated whereby EEH acquired the Titus Assets for aggregate consideration of approximately $567.7 million in cash, net of customary purchase price adjustments, and 3,857,015 shares of Class A Common Stock.
The Titus Acquisition was accounted for as an asset acquisition. The fair value of the consideration paid by us and allocation of that amount to the underlying assets acquired, on a relative fair value basis, was recorded on our books as of the date of the closing of the Titus Acquisition. Additionally, costs directly related to the Titus Acquisition were capitalized as a component of the purchase price. The consideration transferred, fair value of assets acquired and liabilities assumed by the Company were recorded as follows (in thousands, except share amounts and stock price):
Consideration: |
||||
Shares of Class A Common Stock issued |
3,857,015 | |||
Class A Common Stock price as of August 10, 2022 |
$ | 13.89 | ||
|
|
|||
Class A Common Stock consideration |
53,574 | |||
Cash consideration |
566,532 | |||
Direct transaction costs (1) |
1,144 | |||
|
|
|||
Total consideration transferred |
$ | 621,250 | ||
|
|
|||
Fair value of assets acquired: |
||||
Oil and gas properties |
$ | 625,017 | ||
|
|
|||
Amount attributable to assets acquired |
$ | 625,017 | ||
|
|
|||
Fair value of liabilities assumed: |
||||
Current liabilities |
$ | 2,853 | ||
Noncurrent liabilities - ARO |
914 | |||
|
|
|||
Amount attributable to liabilities assumed |
$ | 3,767 | ||
|
|
(1) | Represents $1.1 million of transaction costs associated with the Titus Acquisition which have been capitalized in accordance with ASC 805-50. |
Bighorn Acquisition
On January 30, 2022, Earthstone, EEH, as buyer, and Bighorn Asset Company, LLC, a Delaware limited liability company (“Bighorn”), as seller, entered into a purchase and sale agreement (the “Bighorn Agreement”). Pursuant to the Bighorn Agreement, EEH acquired (the “Bighorn Acquisition”) interests in oil and gas leases and related property of Bighorn located in the Midland Basin, Texas (the “Bighorn Assets”).
F-16
EARTHSTONE ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
On April 14, 2022, Earthstone, EEH and Bighorn consummated the transactions contemplated in the Bighorn Agreement whereby EEH acquired the Bighorn Assets for aggregate consideration of approximately $628.2 million in cash, net of customary purchase price adjustments, and 5,650,977 shares of Class A Common Stock.
The Bighorn Acquisition was accounted for as an asset acquisition. The fair value of the consideration paid by us and allocation of that amount to the underlying assets acquired, on a relative fair value basis, was recorded on our books as of the date of the closing of the Bighorn Acquisition. Additionally, costs directly related to the Bighorn Acquisition were capitalized as a component of the purchase price. The consideration transferred, fair value of assets acquired and liabilities assumed by the Company were recorded as follows (in thousands, except share amounts and stock price):
Consideration: |
||||
Shares of Class A Common Stock issued |
5,650,977 | |||
Class A Common Stock price as of April 14, 2022 |
$ | 13.76 | ||
|
|
|||
Class A Common Stock consideration |
$ | 77,757 | ||
Cash consideration |
625,842 | |||
Direct transaction costs (1) |
2,347 | |||
|
|
|||
Total consideration transferred |
$ | 705,946 | ||
|
|
|||
Fair value of assets acquired: |
||||
Current assets |
$ | 769 | ||
Oil and gas properties |
746,116 | |||
|
|
|||
Amount attributable to assets acquired |
$ | 746,885 | ||
|
|
|||
Fair value of liabilities assumed: |
||||
Suspense payable |
$ | 25,710 | ||
Other current liabilities |
2,035 | |||
Noncurrent liabilities - ARO |
13,194 | |||
|
|
|||
Amount attributable to liabilities assumed |
$ | 40,939 | ||
|
|
(1) | Represents $2.4 million of transaction costs associated with the Bighorn Acquisition which have been capitalized in accordance with ASC 805-50. |
Chisholm Acquisition
As part of the execution of its growth strategy to further increase its scale, on December 15, 2021, Earthstone, EEH, as buyer, Chisholm Energy Operating, LLC (“OpCo”) and Chisholm Energy Agent, Inc. (“Agent” and collectively with OpCo, “Chisholm”), collectively as seller, entered into a Purchase and Sale Agreement (the “Chisholm Agreement”), which provided that EEH would acquire (the “Chisholm Acquisition”) interests in oil and gas leases and related property of Chisholm located in Lea County and Eddy County, New Mexico (the “Chisholm Assets”).
On February 15, 2022, Earthstone, EEH and Chisholm consummated the transactions contemplated in the Chisholm Agreement whereby EEH acquired the Chisholm Assets for aggregate consideration consisting of: (i) approximately $314.0 million in cash, net of customary purchase price adjustments, paid at the closing of the Chisholm Acquisition, (ii) $70 million in cash paid on April 15, 2022 and (iii) 19,417,476 shares of Class A Common Stock. The fair value of each share of Class A Common Stock was determined using the closing sales price of $12.85 per share on February 15, 2022. A Significant Shareholder, as identified below, was the majority owner of Chisholm as of the closing of the Chisholm Acquisition. See Note 14. Related Party Transactions, for further discussion.
F-17
EARTHSTONE ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
The Chisholm Acquisition has been accounted for as a business combination using the acquisition method of accounting, with Earthstone identified as the acquirer. The consideration transferred, fair value of assets acquired and liabilities assumed by Earthstone were recorded as follows (in thousands, except share amounts and stock price):
Consideration: |
||||
Shares of Class A Common Stock issued |
19,417,476 | |||
Class A Common Stock price as of February 15, 2022 |
$ | 12.85 | ||
|
|
|||
Class A Common Stock consideration |
$ | 249,515 | ||
Cash consideration |
383,976 | |||
|
|
|||
Total consideration transferred |
$ | 633,491 | ||
|
|
|||
Fair value of assets acquired: |
||||
Oil and gas properties |
$ | 642,485 | ||
|
|
|||
Amount attributable to assets acquired |
$ | 642,485 | ||
|
|
|||
Fair value of liabilities assumed: |
||||
Other current liabilities |
$ | 3,023 | ||
Asset retirement obligation - noncurrent |
5,971 | |||
|
|
|||
Amount attributable to liabilities assumed |
$ | 8,994 | ||
|
|
IRM Acquisition
As part of the execution of its growth strategy to further increase its scale, on January 7, 2021, the Company completed the acquisition (the “IRM Acquisition”) of all of the issued and outstanding limited liability company interests in Independence Resources Management, LLC (“IRM”) and certain wholly owned subsidiaries for consideration consisting of (i) net cash of approximately $140.5 million and (ii) 12,719,594 shares of Class A Common Stock. The fair value of each share of Class A Common Stock was determined using the closing price of $6.02 per share on January 7, 2021. The purchase agreement contained customary representations and warranties for transactions of this nature. The Company obtained representation and warranty insurance to provide coverage in the event of certain breaches of representations and warranties of the seller contained in the purchase agreement, which are subject to various exclusions, deductibles and other terms and conditions set forth therein.
F-18
EARTHSTONE ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
The IRM Acquisition was accounted for as a business combination using the acquisition method of accounting, with Earthstone identified as the acquirer. The consideration transferred, fair value of assets acquired and liabilities assumed by Earthstone were recorded as follows (in thousands, except share amounts and stock price):
Consideration: |
||||
Shares of Class A Common Stock issued |
12,719,594 | |||
Class A Common Stock price as of January 7, 2021 |
$ | 6.02 | ||
|
|
|||
Class A Common Stock consideration |
$ | 76,572 | ||
Cash consideration |
140,507 | |||
|
|
|||
Total consideration transferred |
$ | 217,079 | ||
|
|
|||
Fair value of assets acquired: |
||||
Cash |
$ | 4,763 | ||
Other current assets |
11,524 | |||
Oil and gas properties |
224,112 | |||
Other non-current assets |
252 | |||
|
|
|||
Amount attributable to assets acquired |
$ | 240,651 | ||
|
|
|||
Fair value of liabilities assumed: |
||||
Derivative liability |
$ | 10,177 | ||
Other current liabilities |
5,196 | |||
Asset retirement obligation - noncurrent |
8,199 | |||
|
|
|||
Amount attributable to liabilities assumed |
$ | 23,572 | ||
|
|
Tracker/Sequel Acquisitions
On March 31, 2021, Earthstone, EEH, Tracker Resource Development III, LLC, a Delaware limited liability company (“Tracker Opco”), and TRD III Royalty Holdings (TX), LP, a Delaware limited partnership (“RoyaltyCo” and collectively with Tracker Opco, “Tracker”), entered into a purchase and sale agreement (the “Tracker Agreement”), which provided that EEH would acquire (the “Tracker Acquisition”) interests in oil and gas leases and related property of Tracker located in Irion County, Texas (the “Tracker Assets”). Also on March 31, 2021, Earthstone, EEH, SEG-TRD LLC, a Delaware limited liability company (“SEG-I”), and SEG-TRD II LLC, a Delaware limited liability company (“SEG-II” and collectively with SEG-I, “Sequel”) entered into a purchase and sale agreement (the “Sequel Agreement” and collectively with the Tracker Agreement, the “Tracker/Sequel Purchase Agreements”), which provided that EEH would acquire (the “Sequel Acquisition” and collectively with the Tracker Acquisition, the “Tracker/Sequel Acquisitions”) certain well-bore interests and related equipment (the “Sequel Assets”).
On July 20, 2021, Earthstone, EEH and Tracker consummated the transactions contemplated in the Tracker Agreement. At the closing of the Tracker Agreement, among other things, EEH acquired the Tracker Assets for aggregate consideration consisting of: (i) $18.8 million in cash, net of customary purchase price adjustments, and (ii) 4.7 million shares of Class A Common Stock. Also, on July 20, 2021, Earthstone, EEH and Sequel consummated the transactions contemplated in the Sequel Agreement. At the closing of the Sequel Agreement, among other things, EEH acquired the Sequel Assets for aggregate consideration consisting of: (i) $41.4 million in cash, net of customary purchase price adjustments, and (ii) 1.5 million shares of Class A Common Stock. The Significant Shareholder, as described in the Note referenced below, owned approximately 49% of Tracker as of the closing of the Tracker Acquisition. See Note 14. Related Party Transactions, for further discussion.
F-19
EARTHSTONE ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
In accordance with ASC Topic 805, Business Combinations (referred to as “ASC 805”), the Tracker/Sequel Acquisitions have been accounted for as asset acquisitions. The consideration transferred, fair value of assets acquired and liabilities assumed by Earthstone were recorded as follows (in thousands, except share amounts and stock price):
Total | ||||
Consideration: |
||||
Shares of Earthstone Class A Common Stock issued |
6,200,000 | |||
Earthstone Class A Common Stock price as of July 20, 2021 |
$ | 9.97 | ||
|
|
|||
Class A Common Stock consideration |
$ | 61,814 | ||
Cash consideration (1) |
60,159 | |||
Direct transaction costs (2) |
1,715 | |||
|
|
|||
Total consideration transferred |
$ | 123,688 | ||
|
|
|||
Fair value of assets acquired: |
||||
Oil and gas properties |
$ | 124,288 | ||
|
|
|||
Amount attributable to assets acquired |
$ | 124,288 | ||
|
|
|||
Fair value of liabilities assumed: |
||||
Noncurrent liabilities - ARO |
$ | 600 | ||
|
|
|||
Amount attributable to liabilities assumed |
$ | 600 | ||
|
|
(1) | Includes customary purchase price adjustments. |
(2) | Represents $1.7 million of transaction costs associated with the Tracker Acquisition and the Sequel Acquisition that have been capitalized in accordance with ASC 805-50. |
The following unaudited supplemental pro forma condensed results of operations present consolidated information as though the Chisholm Acquisition and IRM Acquisition had been completed as of January 1, 2021. The unaudited supplemental pro forma financial information was derived from the historical consolidated and combined statements of operations for Chisholm, IRM and Earthstone and adjusted to include depletion expense applied to the adjusted basis of the properties acquired. These unaudited supplemental pro forma results of operations are provided for illustrative purposes only and do not purport to be indicative of the actual results that would have been achieved by the Company for the periods presented or that may be achieved by the Company in the future. Future results may vary significantly from the results reflected in this unaudited pro forma financial information (in thousands, except per share amounts):
Years Ended December 31, | ||||||||
2022 | 2021 | |||||||
Revenue |
$ | 1,731,159 | $ | 637,803 | ||||
Income (loss) before taxes |
$ | 795,447 | $ | (63,479 | ) | |||
Net income (loss) |
$ | 671,031 | $ | (65,339 | ) | |||
Less: Net income (loss) attributable to noncontrolling interest |
$ | 204,349 | $ | (27,644 | ) | |||
Net income (loss) attributable to Earthstone Energy, Inc. |
$ | 466,682 | $ | (37,695 | ) | |||
Pro forma net income (loss) per common share attributable to Earthstone Energy, Inc.: |
||||||||
Basic |
$ | 5.14 | $ | (0.56 | ) | |||
Diluted |
$ | 4.85 | $ | (0.54 | ) |
The Company has included in its Consolidated Statements of Operations, revenues of $300.0 million and operating expenses of $131.5 million for the period from February 15, 2022 to December 31, 2022 related to the Chisholm Acquisition. During the year ended December 31, 2022, the Company recorded $10.7 million of legal and professional fees related to the Chisholm Acquisition which are included in Transaction costs in the Consolidated Statements of Operations.
The fair value measurements of assets acquired and liabilities assumed are based on inputs that are not observable in the market and therefore represent Level 3 inputs. The fair value of oil and gas properties and asset retirement obligations were measured using the discounted cash flow technique of valuation.
Significant inputs to the valuation of oil and 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 future cash flows, and (vi) a market-based weighted average cost of capital rate. These inputs require significant judgments and estimates and are the most sensitive and subject to change.
F-20
EARTHSTONE ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
Eagle Ford Acquisitions
In May and June 2021, the Company completed acquisitions of working interests in certain assets it operates located in southern Gonzales County, Texas (collectively, the “Eagle Ford Acquisitions”) from four separate sellers. The aggregate purchase price of the Eagle Ford Acquisitions was approximately $45.2 million. One of the four separate sellers was a related party. See Note 14. Related Party Transactions for further discussion. The Eagle Ford Acquisitions have been accounted for as asset acquisitions in accordance with ASC 805. The preliminary allocation of each purchase was based upon management’s estimates of and assumptions related to the relative fair value of assets acquired and liabilities assumed.
Foreland-BCC Acquisition
On November 2, 2021, Earthstone, EEH and Foreland Investments LP, a Delaware limited partnership (“Foreland”), consummated the transactions contemplated in the Purchase and Sale Agreement dated as of September 30, 2021 by and among Earthstone, EEH and Foreland (the “Foreland Purchase Agreement”). At the closing of the Foreland Purchase Agreement, EEH acquired (the “Foreland Acquisition”) interests in oil and gas leases and related property of Foreland located in Irion County and Crockett County, Texas, for a purchase price consisting of: (i) $13.4 million in cash, net of customary purchase price adjustments, and (ii) 2,611,111 shares of Class A Common Stock.
Also, on November 2, 2021, Earthstone, EEH and BCC-Foreland LLC, a Delaware limited liability company (“BCC”), consummated the transactions contemplated in the Purchase and Sale Agreement dated as of September 30, 2021 by and among Earthstone, EEH and BCC (the “BCC Purchase Agreement”). At the closing of the BCC Purchase Agreement, EEH acquired (the “BCC Acquisition” and with the Foreland Acquisition, the “Foreland-BCC Acquisition”) certain well-bore interests and related equipment held by BCC that were part of a joint development agreement between Foreland, Foreland Operating, LLC, and BCC involving portions of the acreage covered by the Foreland Purchase Agreement for a purchase price of $20.5 million in cash, net of customary purchase price adjustments.
Divestitures
During the year ended December 31, 2022, the Company sold certain non-core properties for approximately $49.5 million in cash, resulting in net gains of approximately $13.9 million recorded in Gain on sale of oil and gas properties, net in the Consolidated Statements of Operations.
There were no material divestitures during the years ended December 31, 2021 or 2020.
Note 5. Transaction Costs
During the year ended December 31, 2022, the Company recorded transaction costs of $8.2 million primarily due to legal, consulting and other fees related to the Chisholm Acquisition and certain divestiture transactions.
During the year ended December 31, 2021, the Company recorded transaction costs primarily due to legal, consulting and other fees of approximately $4.0 million related to the IRM Acquisition, $1.8 million related to the Chisholm Acquisition and $0.3 million related to other potential transactions, offset by net reimbursements of $1.2 million related to the business combination (the “Bold Transaction”) pursuant to the Bold Contribution Agreement (as defined below) which closed on May 9, 2017.
During the year ended December 31, 2020, the Company recorded transaction costs primarily due to legal, consulting and other fees of approximately $1.0 million related to the IRM Acquisition noted above and $0.3 million related to other potential transactions, offset by net reimbursements of $0.7 million related to the Bold Transaction.
Note 6. Fair Value Measurements
FASB ASC Topic 820, defines fair value as the price that would be received to sell an asset, or paid to transfer a liability, in an orderly transaction between market participants at the measurement date. ASC Topic 820 provides a framework for measuring fair value, establishes a three-level hierarchy for fair value measurements based upon the transparency of inputs to the valuation of an asset or liability as of the measurement date and requires consideration of the counterparty’s creditworthiness when valuing certain assets.
F-21
EARTHSTONE ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
The three-level fair value hierarchy for disclosure of fair value measurements defined by ASC Topic 820 is as follows:
Level 1 – Unadjusted, quoted prices in active markets that are accessible at the measurement date for identical, unrestricted assets or liabilities. An active market is defined as a market where transactions for the financial instrument occur with sufficient frequency and volume to provide pricing information on an ongoing basis.
Level 2 – Inputs, other than quoted prices within Level 1, that are either directly or indirectly observable for the asset or liability through correlation with market data at the measurement date and for the duration of the instrument’s anticipated life.
Level 3 – Prices or valuations that require unobservable inputs that are both significant to the fair value measurement and unobservable. Valuation under Level 3 generally involves a significant degree of judgment from management.
A financial instrument’s level within the fair value hierarchy is based on the lowest level of any input that is significant to the fair value measurement. Where available, fair value is based on observable market prices or parameters or derived from such prices or parameters. Where observable prices or inputs are not available, valuation models are applied. These valuation techniques involve some level of management estimation and judgment, the degree of which is dependent on the price transparency for the instruments or market and the instrument’s complexity. The Company reflects transfers between the three levels at the beginning of the reporting period in which the availability of observable inputs no longer justifies classification in the original level. There were no transfers between fair value hierarchy levels for the year ended December 31, 2022.
Fair Value on a Recurring Basis
Derivative Financial Instruments
Derivative financial instruments are carried at fair value and measured on a recurring basis. The derivative financial instruments consist of fixed price swaps, basis swaps, costless collars and deferred premium put options for crude oil and natural gas and interest rate swaps. The Company’s commodity price hedges and interest rate swaps are valued based on discounted future cash flow models that are primarily based on published forward commodity price curves and published LIBOR forward curves; thus, these inputs are designated as Level 2 within the valuation hierarchy.
The fair values of derivative instruments in asset positions include measures of counterparty nonperformance risk, and the fair values of derivative instruments in liability positions include measures of the Company’s nonperformance risk. These measurements were not material to the Consolidated Financial Statements.
Share-based Compensation Liability
Certain of our performance-based stock awards (“PSUs”) may be payable in cash. The Company classifies the awards that may be settled in cash as liability awards. These awards are valued quarterly utilizing the Monte Carlo Simulation pricing model, which calculates multiple potential outcomes for an award and establishes grant date fair value based on the most likely outcome. The inputs for the Monte Carlo model are designated as Level 2 within the valuation hierarchy. The share-based compensation liability related to the PSU liability awards is included in Accrued expenses and Other noncurrent liabilities in the Consolidated Balance Sheet as of December 31, 2022.
F-22
EARTHSTONE ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
The following table summarizes the fair value of the Company’s financial assets and liabilities, by level within the fair-value hierarchy (in thousands):
Level 1 | Level 2 | Level 3 | Total | |||||||||||||
December 31, 2022 |
||||||||||||||||
Financial assets |
||||||||||||||||
Derivative asset- current |
$ | — | $ | 31,331 | $ | — | $ | 31,331 | ||||||||
Derivative asset- noncurrent |
— | 9,117 | — | 9,117 | ||||||||||||
|
|
|
|
|
|
|
|
|||||||||
Total financial assets |
$ | — | $ | 40,448 | $ | — | $ | 40,448 | ||||||||
|
|
|
|
|
|
|
|
|||||||||
Financial liabilities |
||||||||||||||||
Derivative liability - current |
$ | — | $ | 14,053 | $ | — | $ | 14,053 | ||||||||
Share-based compensation liability - current |
— | 14,411 | — | 14,411 | ||||||||||||
Share-based compensation liability - noncurrent |
— | 10,357 | — | 10,357 | ||||||||||||
|
|
|
|
|
|
|
|
|||||||||
Total financial liabilities |
$ | — | $ | 38,821 | $ | — | $ | 38,821 | ||||||||
|
|
|
|
|
|
|
|
|||||||||
December 31, 2021 |
||||||||||||||||
Financial assets |
||||||||||||||||
Derivative asset- current |
$ | — | $ | 1,348 | $ | — | $ | 1,348 | ||||||||
Derivative asset- noncurrent |
— | 157 | — | 157 | ||||||||||||
|
|
|
|
|
|
|
|
|||||||||
Total financial assets |
$ | — | $ | 1,505 | $ | — | $ | 1,505 | ||||||||
|
|
|
|
|
|
|
|
|||||||||
Financial liabilities |
||||||||||||||||
Derivative liability - current |
$ | — | $ | 45,310 | $ | — | $ | 45,310 | ||||||||
Derivative liability - noncurrent |
— | 571 | — | 571 | ||||||||||||
Share-based compensation liability - current |
— | 7,835 | — | 7,835 | ||||||||||||
Share-based compensation liability - noncurrent |
— | 6,324 | — | 6,324 | ||||||||||||
|
|
|
|
|
|
|
|
|||||||||
Total financial liabilities |
$ | — | $ | 60,040 | $ | — | $ | 60,040 | ||||||||
|
|
|
|
|
|
|
|
Other financial instruments include cash, accounts receivable and payable, and revenue royalties. The carrying amount of these instruments approximates fair value because of their short-term nature. The Company’s long-term debt obligation bears interest at floating market rates, therefore carrying amounts and fair value are approximately equal.
Fair Value on a Nonrecurring Basis
The Company applies the provisions of the fair value measurement standard on a non-recurring basis to its non-financial assets and liabilities, including oil and gas properties, goodwill, business combinations and asset retirement obligations. These assets and liabilities are not measured at fair value on an ongoing basis but are subject to fair value adjustments if events or changes in certain circumstances indicate that adjustments may be necessary. Due to significant declines in commodity prices and global demand for oil and natural gas products resulting from the COVID-19 pandemic, the Company assessed the fair values of its oil and natural gas properties and goodwill resulting in non-cash impairment charges during the three months ended March 31, 2020. Since then, commodity prices have recovered and no other such triggering events that require further assessment were observed during the years ended December 31, 2022 and 2021.
Items Not Recorded at Fair Value
The carrying amounts reported on the unaudited consolidated balance sheets for cash, accounts receivable, prepaid expenses, other current assets accounts payable, revenues and royalties payable, accrued expenses and other current liabilities approximate their fair values.
The Company has not elected to account for its debt instruments at fair value. Borrowings under the revolving tranche and term loan tranche of the Company’s credit facility bear interest at floating market rates, therefore the carrying amounts and fair values were approximately equal as of December 31, 2022 and December 31, 2021. The carrying value of EEH’s 8.000% Senior Notes due 2027, net of $10.9 million deferred financing costs, of $539.1 million and accrued interest of $9.5 million had an estimated fair value of $530.3 million. There were no other debt instruments outstanding at December 31, 2022.
F-23
EARTHSTONE ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
Note 7. Derivative Financial Instruments
Commodity Derivative Instruments
The Company’s hedging activities primarily consist of derivative instruments entered into in order to hedge against changes in oil and natural gas prices through the use of fixed price swap agreements, costless collars and deferred premium put options. Swaps exchange floating price risk in the future for a fixed price at the time of the hedge. Costless collars set both a maximum (sold ceiling) and a minimum (bought floor) future price. A deferred premium put option represents a bought floor except, unlike a standard put option, the premium is not paid until the expiration of the option. Consistent with its hedging policy, the Company has entered into a series of derivative instruments to hedge a portion of its expected oil and natural gas production through December 31, 2024. Typically, these derivative instruments require payments to (receipts from) counterparties based on specific indices as required by the derivative agreements. Although not risk free, the Company believes these instruments reduce its exposure to oil and natural gas price fluctuations and, thereby, allow the Company to achieve a more predictable cash flow. The Company does not enter into derivative instruments for trading or other speculative purposes.
The Company’s derivative instruments are cash flow hedge transactions in which it is hedging the variability of cash flow related to a forecasted transaction. The Company does not enter into derivative instruments for trading or other speculative purposes. These transactions are recorded in the Consolidated Financial Statements in accordance with FASB ASC Topic 815. The Company has accounted for these transactions using the mark-to-market accounting method. Generally, the Company incurs accounting losses on derivatives during periods where prices are rising and gains during periods where prices are falling which may cause significant fluctuations in the Consolidated Balance Sheets and Consolidated Statements of Operations.
The Company nets its derivative instrument fair value amounts executed with each counterparty pursuant to an International Swap Dealers Association Master Agreement (“ISDA”), which provides for net settlement over the term of the contract. The ISDA is a standard contract that governs all derivative contracts entered into between the Company and the respective counterparty. The ISDA allows for offsetting of amounts payable or receivable between the Company and the counterparty, at the election of both parties, for transactions that occur on the same date and in the same currency.
The following table sets forth the Company’s outstanding derivative contracts at December 31, 2022. When aggregating multiple contracts, the weighted average contract price is disclosed.
Period |
Commodity | Volume (Bbls / MMBtu) |
Price ($/Bbl / $/MMBtu) |
|||||||
2023 |
Crude Oil Swap | 1,642,500 | $ | 76.94 | ||||||
2023 |
Crude Oil Basis Swap(1) | 9,488,500 | $ | 0.92 | ||||||
2023 |
Natural Gas Swap | 3,670,000 | $ | 3.52 | ||||||
2023 |
Natural Gas Basis Swap(2) | 51,100,000 | $ | (1.67 | ) | |||||
2024 |
Natural Gas Basis Swap(2) | 36,600,000 | $ | (1.05 | ) |
(1) | The basis differential price is between WTI Midland Argus Crude and the WTI NYMEX. |
(2) | The basis differential price is between W. Texas (WAHA) and the Henry Hub NYMEX. |
Costless Collars | ||||||||||||||
Period |
Commodity | Volume (Bbls / MMBtu) |
Bought Floor ($/Bbl / $/MMBtu) |
Sold Ceiling ($/Bbl / $/MMBtu) |
||||||||||
2023 |
Crude Oil Costless Collar | 2,080,500 | $ | 63.33 | $ | 82.83 | ||||||||
2023 |
Natural Gas Costless Collar | 22,188,000 | $ | 3.82 | $ | 7.44 | ||||||||
Deferred Premium Puts | ||||||||||||||
Period |
Commodity | Volume (Bbls / MMBtu) |
$/Bbl (Put Price) | $/Bbl (Net of Premium) | ||||||||||
2023 |
Crude Oil | 1,931,500 | $ | 69.53 | $ | 64.12 |
F-24
EARTHSTONE ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
Interest Rate Swaps
At times, the Company’s hedging activities include the use of interest rate swaps entered into in order to manage cash flow variability resulting from changes in interest rates. These derivative instruments are not accounted for under hedge accounting.
In December 2021, the Company unwound its interest rate swap contracts, receiving a one-time settlement payment of $1.1 million. The Company had no interest rate swaps in place as of December 31, 2022 or 2021.
The following table summarizes the location and fair value amounts of all derivative instruments in the Consolidated Balance Sheets as well as the gross recognized derivative assets, liabilities, and amounts offset in the Consolidated Balance Sheets (in thousands):
December 31, 2022 | December 31, 2021 | |||||||||||||||||||||||||
Derivatives not |
Balance Sheet Location |
Gross Recognized Assets / Liabilities |
Gross Amounts Offset |
Net Recognized Assets / Liabilities |
Gross Recognized Assets / Liabilities |
Gross Amounts Offset |
Net Recognized Assets / Liabilities |
|||||||||||||||||||
Commodity contracts |
Derivative asset - current | $ | 51,803 | $ | (20,472 | ) | $ | 31,331 | $ | 3,191 | $ | (1,843 | ) | $ | 1,348 | |||||||||||
Commodity contracts |
Derivative liability - current | $ | 34,525 | $ | (20,472 | ) | $ | 14,053 | $ | 47,153 | $ | (1,843 | ) | $ | 45,310 | |||||||||||
Commodity contracts |
Derivative asset - noncurrent | $ | 9,117 | $ | — | $ | 9,117 | $ | 2,721 | $ | (2,564 | ) | $ | 157 | ||||||||||||
Commodity contracts |
Derivative liability - noncurrent | $ | — | $ | — | $ | — | $ | 3,135 | $ | (2,564 | ) | $ | 571 |
The follow table summarizes the location and amounts of the Company’s realized and unrealized gains and losses on derivatives instruments in the Company’s Consolidated Statements of Operations and Consolidated Statements of Cash Flows (in thousands):
Derivatives not designated as hedging contracts under ASC Topic 815 |
Years Ended December 31, | |||||||||||||||
Statement of Cash Flows Location |
Statement of Operations Location |
2022 | 2021 | 2020 | ||||||||||||
Unrealized gain (loss) |
Not presented separately | Not presented separately | $ | 70,769 | $ | (40,795 | ) | $ | 3,855 | |||||||
Realized (loss) gain |
Operating portion of net cash received in settlement of derivative contracts | Not presented separately | (195,876 | ) | (75,966 | ) | 56,044 | |||||||||
|
|
|
|
|
|
|
|
|||||||||
Total loss (gain) on derivative contracts, net |
(Loss) gain on derivative contracts, net | $ | (125,107 | ) | $ | (116,761 | ) | $ | 59,899 | |||||||
|
|
|
|
|
|
Note 8. Oil and Natural Gas Properties
The Company follows the successful efforts method of accounting for its oil and natural gas properties. Under this method, costs to acquire oil and natural gas properties, drill and equip exploratory wells that find proved reserves, and drill and equip development wells are capitalized. Exploration costs, including unsuccessful exploratory wells and geological and geophysical costs, are charged to operations as incurred. Upon sale or retirement of oil and natural gas properties, the costs and related accumulated depreciation, depletion and amortization are eliminated from the accounts and the resulting gain or loss is recognized.
Costs incurred to maintain wells and related equipment, lease and well operating costs, and other exploration costs are charged to expense as incurred. Gains and losses arising from the sale of properties are included in operating income in the Consolidated Statements of Operations.
The Company’s lease acquisition costs and development costs of proved oil and natural gas properties are amortized using the units-of-production method, at the field level, based on total proved reserves and proved developed reserves, respectively. Depletion expense for oil and natural gas producing property and related equipment was $300.5 million, $105.7 million and $95.9 million for the years ended December 31, 2022, 2021 and 2020, respectively.
Proved Oil and Natural Gas Properties
Proved oil and natural gas properties are reviewed for impairment on a nonrecurring basis. The impairment charge reduces the carrying values to their estimated fair values. These fair value measurements are classified as Level 3 measurements and include many unobservable inputs. Fair value is calculated as the estimated discounted future net cash flows attributable to the assets. The Company’s primary assumptions in preparing the estimated discounted future net cash flows to be recovered from oil and natural gas properties are based on (i) proved reserves, (ii) forward commodity prices and assumptions as to costs and expenses, and (iii) the estimated discount rate that would be used by potential purchasers to determine the fair value of the assets.
F-25
EARTHSTONE ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
Unproved Oil and Natural Gas Properties
Unproved properties consist of costs incurred to acquire undeveloped leases as well as the cost to acquire unproved reserves. Undeveloped lease costs and unproved reserve acquisition costs are capitalized. Unproved oil and natural gas leases are generally for a primary term of three to five years. In most cases, the term of the unproved leases can be extended by paying delay rentals, meeting contractual drilling obligations, or by the presence of producing wells on the leases. Unproved costs related to successful exploratory drilling are reclassified to proved properties and depleted on a units-of-production basis.
The Company reviews its unproved properties periodically for impairment. In determining whether an unproved property is impaired, the Company considers numerous factors including, but not limited to, current exploration and development plans, favorable or unfavorable exploration activity on the property being evaluated and/or adjacent properties, the Company’s geologists’ evaluation of the property, and the remaining months in the lease term for the property.
Impairments to Oil and Natural Gas Properties
The Company recorded no non-cash asset impairment charges for the years ended December 31, 2022 or 2021.
During the year ended December 31, 2020, primarily as a result of the decline in crude oil price futures, the Company recorded non-cash impairment charges of $25.3 million to its proved oil and natural gas properties and $13.2 million to its unproved oil and natural gas properties, located in the Eagle Ford Trend. As a result of certain acreage expirations, the Company recorded non-cash impairment charges of $8.4 million to its unproved oil and natural gas properties during the year ended December 31, 2020.
Accumulated impairments to proved and unproved oil and natural gas properties as of December 31, 2022 and 2021 were $168.0 million and $168.0 million, respectively.
Note 9. Net Income (Loss) Per Common Share
Net income (loss) per common share—basic is calculated by dividing Net income (loss) by the weighted average number of shares of common stock outstanding during the period. Net income (loss) per common share—diluted assumes the conversion of all potentially dilutive securities and is calculated by dividing Net income (loss) by the sum of the weighted average number of shares of common stock, as defined above, outstanding plus potentially dilutive securities. Net income (loss) per common share—diluted considers the impact of potentially dilutive securities except in periods in which there is a loss because the inclusion of the potential common shares, as defined above, would have an anti-dilutive effect.
F-26
EARTHSTONE ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
A reconciliation of Net income (loss) per common share is as follows:
Years Ended December 31, | ||||||||||||
(In thousands, except per share amounts) | 2022 | 2021 | 2020 | |||||||||
Net income (loss) attributable to Earthstone Energy, Inc. |
$ | 452,485 | $ | 35,484 | $ | (13,547 | ) | |||||
|
|
|
|
|
|
|||||||
Net income (loss) attributable to Earthstone Energy, Inc. from assumed conversion of Series A Convertible Preferred Stock (1) |
12,388 | — | — | |||||||||
|
|
|
|
|
|
|||||||
Net income (loss) attributable to Earthstone Energy, Inc. - Diluted |
$ | 464,873 | $ | 35,484 | $ | (13,547 | ) | |||||
|
|
|
|
|
|
|||||||
Net income (loss) per common share attributable to Earthstone Energy, Inc.: |
||||||||||||
Basic |
$ | 5.12 | $ | 0.75 | $ | (0.45 | ) | |||||
|
|
|
|
|
|
|||||||
Diluted |
$ | 4.83 | $ | 0.71 | $ | (0.45 | ) | |||||
|
|
|
|
|
|
|||||||
Weighted average common shares outstanding |
||||||||||||
Basic |
88,349,088 | 47,169,948 | 29,911,625 | |||||||||
|
|
|
|
|
|
|||||||
Add potentially dilutive securities: |
||||||||||||
Unvested restricted stock units |
416,031 | 539,803 | — | |||||||||
Unvested performance units |
1,757,841 | 2,242,342 | — | |||||||||
Series A Convertible Preferred Stock(1) |
5,805,257 | — | — | |||||||||
|
|
|
|
|
|
|||||||
Diluted weighted average common shares outstanding |
96,328,217 | 49,952,093 | 29,911,625 | |||||||||
|
|
|
|
|
|
(1) | On April 14, 2022, Earthstone issued 280,000 shares of Series A Convertible Preferred Stock which automatically converted into 25,225,225 shares of Class A Common Stock on July 6, 2022. Under the “If-Converted” method, the shares would have been assumed issued on April 14, 2022, which would have resulted in an additional allocation of Net income (loss) attributable to Earthstone Energy, Inc. of $12.4 million for the year ended December 31, 2022. |
The Class B Common Stock has been excluded, as its conversion would eliminate noncontrolling interest and Net income attributable to noncontrolling interest of $198.1 million for the year ended December 31, 2022, Net loss attributable to noncontrolling interest of $26.0 million for the year ended December 31, 2021, and Net income attributable to noncontrolling interest of $15.9 million for the year ended December 31, 2020 would be added back to Net income (loss) attributable to Earthstone Energy, Inc. for the years then ended, having no dilutive effect on Net income (loss) per common share attributable to Earthstone Energy, Inc. For the year ended December 31, 2020, the Company excluded 1.1 million and 1.9 million shares, respectively, for the dilutive effect of restricted stock units and performance units in calculating diluted earnings per share as the effect was anti-dilutive due to the net loss incurred for the period.
Note 10. Common Stock and Preferred Stock
Class A Common Stock
At December 31, 2022 and 2021, there were 105,547,139 and 53,467,307 shares of Class A Common Stock issued and outstanding, respectively. During the year ended December 31, 2022, Earthstone issued a total of approximately 28.9 million shares of Class A Common Stock in connection with the Chisholm Acquisition, Bighorn Acquisition and the Titus Acquisition, as well as approximately 25.2 million shares of Class A Common Stock upon conversion of the Series A Convertible Preferred Stock described below. During the year ended December 31, 2021, Earthstone issued a total of approximately 21.5 million shares of Class A Common Stock in connection with the IRM Acquisition, Tracker/Sequel Acquisitions and the Foreland Acquisition. No shares were issued in connection with acquisitions during 2020. During the years ended December 31, 2022, 2021 and 2020, as a result of the vesting and settlement of restricted stock units under the Earthstone Amended and Restated 2014 Long-Term Incentive Plan, as amended (the “2014 Plan”), Earthstone issued 1,273,795, 1,381,825 and 914,905 shares of Class A Common Stock, respectively, of which 429,547, 453,483 and 243,924 shares of Class A Common Stock, respectively, were retained as treasury stock and cancelled to satisfy the related employee income tax liability.
On October 11, 2022, Earthstone purchased and immediately cancelled 3,000,000 shares of Class A Common Stock from certain affiliates of Warburg Pincus LLC (“Warburg”) in a private transaction, for an aggregate purchase price of $43,740,000, or $14.58 per share.
F-27
EARTHSTONE ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
Class B Common Stock
At December 31, 2022 and 2021, there were 34,259,641 and 34,344,532 shares of Class B Common Stock issued and outstanding, respectively. Each share of Class B Common Stock, together with one EEH Unit, is convertible into one share of Class A Common Stock. During the years ended December 31, 2022, 2021 and 2020, 84,891, 664,839 and 251,309 shares, respectively, of Class B Common Stock and EEH Units were exchanged for an equal number of shares of Class A Common Stock.
Series A Convertible Preferred Stock
On January 30, 2022, Earthstone entered into a securities purchase agreement (the “SPA”) with EnCap Energy Capital Fund XI, L.P. (“EnCap Fund XI”), an affiliate of EnCap Investments L.P. (“EnCap”), and Cypress Investments, LLC, a fund managed by Post Oak Energy Capital, LP (“Post Oak” and collectively with EnCap Fund XI, the “Investors”) to sell, in a private placement (the “Private Placement”), 280,000 shares of newly authorized convertible preferred stock, $0.001 par value per share (the “Series A Convertible Preferred Stock”), each share of which would be convertible into 90.0900900900901 shares of Class A Common Stock for anticipated gross proceeds of $280.0 million, at a price of $1,000.00 per share of Series A Convertible Preferred Stock (or $11.10 per share of Class A Common Stock on an as-converted basis). The Private Placement was contingent upon the closing of the Bighorn Acquisition. The Company used the net proceeds from the sale of the Series A Convertible Preferred Stock to partially fund the Bighorn Acquisition. See Note 14. Related Party Transactions for further discussion.
On April 14, 2022, Earthstone, EnCap Fund XI and Cypress consummated the sale and issuance of 280,000 shares of Series A Convertible Preferred Stock pursuant to the SPA in exchange for cash proceeds of $279.3 million, net of offering costs.
On July 6, 2022, the Series A Convertible Preferred Stock automatically converted into 25,225,225 shares of Class A Common Stock. As such, the Series A Convertible Preferred Stock is no longer outstanding and the Investors were issued the 25,225,225 shares of Class A Common Stock upon the conversion of the Series A Convertible Preferred Stock.
On July 15, 2022, Earthstone filed a certificate of elimination with the Secretary of State of the State of Delaware eliminating all provisions of the certificate of designations previously filed by Earthstone with the Secretary of State of the State of Delaware on April 13, 2022 related to the Series A Convertible Preferred Stock.
At December 31, 2022 and 2021, there were no shares of Series A Convertible Preferred Stock issued or outstanding.
Note 11. Stock-Based Compensation
Restricted Stock Units
The 2014 Plan allows, among other things, for the grant of restricted stock units (“RSUs”). As of December 31, 2022, the maximum number of shares of Class A Common Stock that may be issued under the 2014 Plan was 12.0 million shares.
Each RSU represents the contingent right to receive one share of Class A Common Stock. The holders of outstanding RSUs do not receive dividends or have voting rights prior to vesting and settlement. The Company determines the fair value of granted RSUs based on the market price of the Class A Common Stock on the date of the grant. Compensation expense for granted RSUs is recognized on a straight-line basis over the vesting term and is net of forfeitures, as incurred. Stock-based compensation is included in General and administrative expense in the Consolidated Statements of Operations and is recorded with a corresponding increase in Additional paid-in capital within the Consolidated Balance Sheets.
The table below summarizes unvested RSU activity for the year ended December 31, 2022:
Shares | Weighted-Average Grant Date Fair Value |
|||||||
Unvested RSUs at December 31, 2021 |
771,817 | $ | 5.91 | |||||
Granted |
780,765 | $ | 13.65 | |||||
Forfeited |
(16,934 | ) | $ | 8.17 | ||||
Vested |
(665,670 | ) | $ | 7.75 | ||||
|
|
|
|
|||||
Unvested RSUs at December 31, 2022 |
869,978 | $ | 11.40 | |||||
|
|
|
|
During the year ended December 31, 2022, Earthstone granted 727,765 RSUs to employees and 53,000 RSUs to certain members of the Board with vesting periods ranging from 12 to 36 months. The total grant date fair value of the RSUs granted during the years ended December 31, 2022, 2021 and 2020 were $10.7 million, $4.1 million and $4.4 million, respectively, with a weighted average grant date fair value per share of $13.65, $6.16 and 5.07, respectively. The total vesting date fair value of the RSUs that vested during 2022, 2021 and 2020 was $8.9 million, $8.8 million and $3.0 million, respectively. As of December 31, 2022, there was approximately $9.2 million of total unrecognized stock-based compensation expense related to unvested RSUs, which will be amortized over the remaining vesting periods. The weighted average remaining vesting period of the unrecognized compensation expense is 1.20 years.
F-28
EARTHSTONE ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
For the years ended December 31, 2022, 2021 and 2020, stock-based compensation related to RSUs was $6.0 million, $5.2 million and $5.4 million, respectively.
Performance Units
The table below summarizes performance unit (“PSU”) activity for the year ended December 31, 2022:
Shares | Weighted-Average Grant Date Fair Value |
|||||||
Unvested PSUs at December 31, 2021 |
2,751,725 | $ | 8.42 | |||||
Granted |
472,485 | $ | 19.42 | |||||
Vested |
(608,125 | ) | $ | 9.30 | ||||
|
|
|
|
|||||
Unvested PSUs at December 31, 2022 |
2,616,085 | $ | 10.21 | |||||
|
|
|
|
The total grant date fair value of the PSUs granted during the years ended December 31, 2022, 2021 and 2020 were $9.2 million, $11.9 million and $5.6 million, respectively, with a weighted average grant date fair value per share of $19.42, $10.85 and $5.36, respectively. The total vesting date fair value of the PSUs that vested during 2022 and 2021 was $8.3 million and $3.5 million respectively. No PSUs vested during 2020. As of December 31, 2022, there was $16.1 million of unrecognized compensation expense related to the PSU awards which will be amortized over a weighted average period of 0.71 years.
For the years ended December 31, 2022, 2021 and 2020, stock-based compensation related to the PSUs was approximately $29.4 million, $15.8 million and $4.6 million, respectively.
The Company classifies awards that will be settled in cash as liability awards. PSU grants to be settled in shares are classified as equity awards. Corresponding liabilities of $14.4 million and $7.8 million related to the PSUs were included in Other current liabilities and Accrued expenses, respectively, in the Consolidated Balance Sheets as of December 31, 2022 and 2021, respectively. Additionally, corresponding liabilities of $10.4 million and $6.3 million related to the PSUs were included in Other noncurrent liabilities in the Consolidated Balance Sheets as of December 31, 2022 and 2021, respectively.
On February 1, 2022, the Board granted 472,485 PSUs (the “2022 PSUs”) to certain officers pursuant to the 2014 Plan. The 2022 PSUs are payable in cash or shares of Class A Common Stock upon the achievement by Earthstone over a period commencing on January 1, 2022 and ending on December 31, 2024 (the “2022 Performance Period”) of certain performance criteria established by the Board. The Company classifies these awards that will be settled in cash as liability awards. PSU grants to be settled in shares are classified as equity awards.
The 2022 PSUs are eligible to be earned based on the annualized Total Shareholder Return (“TSR”) of the Class A Common Stock during a three-year period beginning on January 1, 2022. Between 0x to 2.0x of the Performance Units are eligible to be earned based on Earthstone achieving an annualized TSR based on the following pre-established goals:
Earthstone’s Annualized TSR |
TSR Multiplier | |||
23.9% or greater |
2.0 | |||
14.5% |
1.0 | |||
8.4% |
0.5 | |||
Less than 8.4% |
0.0 |
In the event that greater than 1.0x of the 2022 PSUs are earned, such additional PSUs may be paid in cash rather than the issuance of shares of Class A Common Stock.
The Company accounts for these awards as market-based awards which are valued utilizing the Monte Carlo Simulation pricing model, which calculates multiple potential outcomes for an award and establishes grant date fair value based on the most likely outcome. For the 2022 PSUs, assuming a risk-free rate of 1.4% and volatility of 86.0%, the Company calculated the weighted average grant date fair value per PSU to be $19.42.
TSR for the Company and each of the peer companies is generally determined by dividing (A) the volume weighted average price of a share of stock for the trading days during the thirty calendar days ending on and including the last calendar day of the applicable performance period minus the volume weighted average price of a share of stock for the trading days during the thirty calendar days ending on and including the first day of the applicable performance period plus cash dividends paid over the applicable performance period by (B) the volume weighted average price of a share of stock for the trading days during the thirty calendar days ending on and including the first day of the applicable performance period.
F-29
EARTHSTONE ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
On January 27, 2021, the Board granted 1,099,800 PSUs (the “2021 PSUs”) to certain officers pursuant to the 2014 Plan (the “2021 Grant”). The 2021 PSUs are payable in cash or shares of Class A Common Stock upon the achievement by the Company over a period commencing on January 1, 2021 and ending on December 31, 2023 of certain performance criteria established by the Board. The Company classifies these awards that will be settled in cash as liability awards. PSU grants to be settled in shares are classified as equity awards.
The 2021 PSUs are eligible to be earned based on the annualized TSR of the Class A Common Stock during a three-year period beginning on February 1, 2021. Between 0x to 2.0x of the Performance Units are eligible to be earned based on Earthstone achieving an annualized TSR based on the following pre-established goals:
Earthstone’s Annualized TSR |
TSR Multiplier | |||
20.5% or greater |
2.0 | |||
14.5% |
1.0 | |||
7.7% |
0.5 | |||
Less than 7.7% |
0.0 |
In the event that greater than 1.0x of the 2021 PSUs are earned, such additional PSUs may be paid in cash rather than the issuance of shares of Class A Common Stock.
The Company accounts for these awards as market-based awards which are valued quarterly utilizing the Monte Carlo Simulation pricing model, which calculates multiple potential outcomes for an award and establishes grant date fair value based on the most likely outcome. For the 2021 PSUs, assuming a risk-free rate of 0.3% and volatility of 86.0%, the Company calculated the weighted average grant date fair value per PSU to be $10.85.
On January 30, 2020, the Board granted 1,043,800 PSUs (the “2020 PSUs”) to certain officers pursuant to the 2014 Plan (the “2020 Grant”). The 2020 PSUs are payable in shares of Class A Common Stock based upon the achievement by the Company over a period commencing on February 1, 2020 and ending on January 31, 2023 of certain performance criteria established by the Board.
The 2020 PSUs are eligible to be earned based on the annualized TSR of the Class A Common Stock during a three-year period beginning on February 1, 2020. Between 0x to 2.0x of the Performance Units are eligible to be earned based on Earthstone achieving an annualized TSR based on the following pre-established goals:
Earthstone’s Annualized TSR |
TSR Multiplier | |||
23.9% or greater |
2.0 | |||
14.5% |
1.0 | |||
8.4% |
0.5 | |||
Less than 8.4% |
0.0 |
In the event that greater than 1.0x of the 2020 PSUs are earned, such additional PSUs may be paid in cash rather than the issuance of shares of Class A Common Stock, solely at the discretion of the Board.
The Company accounts for these awards as market-based awards which are valued utilizing the Monte Carlo Simulation pricing model, which calculates multiple potential outcomes for an award and establishes grant date fair value based on the most likely outcome. For the 2020 PSUs, assuming a risk-free rate of 1.4% and volatility of 62.0%, the Company calculated the weighted average grant date fair value per PSU to be $5.36.
On January 28, 2019, the Board granted 669,550 PSUs (the “2019 PSUs”) to certain executive officers pursuant to the 2014 Plan. The PSUs are payable in shares of Class A Common Stock based upon the achievement by the Company over a period commencing on February 1, 2019 and ending on January 31, 2022 of performance criteria established by the Board.
The number of shares of Class A Common Stock that may be issued will be determined by multiplying the number of PSUs granted by the Relative TSR Percentage (0% to 200%). The “Relative TSR Percentage” is the percentage, if any, achieved by attainment of a certain predetermined range of targets for the three-year period beginning on February 1, 2019.
The Company accounts for these awards as market-based awards which are valued utilizing the Monte Carlo Simulation pricing model, which calculates multiple potential outcomes for an award and establishes grant date fair value based on the most likely outcome. For the PSUs granted on January 28, 2019, assuming a risk-free rate of 2.6% and volatilities ranging from 40.1% to 114.1%, the Company calculated the weighted average grant date fair value per PSU to be $9.30.
F-30
EARTHSTONE ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
The 2019 PSUs were settled on February 9, 2022 resulting in the issuance of 608,125 shares of Class A Common Stock and cash payments totaling $8.1 million.
Modification of Performance Units
All outstanding PSUs may be paid in either cash or the issuance of shares of Class A Common Stock or any combination of the two therein, at the discretion of the Board. In January 2023, the Board, at its discretion, consented to settlement of the 2020 Grant in shares of Class A Common Stock up to 100% and the remaining 100% in cash. In consideration of the settlement of the 2020 Grant, which was consistent with the 2019 Grant, the Company deemed it appropriate to modify the remaining performance-based grants (the “Modification”). Based on the Modification, the Company calculated the fair value of the cash settled portion of each award representing an estimated accumulative increase to the liability of $9.9 million as of December 31, 2022, consisting of $17.1 million in additional stock-based compensation during the year ended December 31, 2022, partially offset by $7.2 million of stock-based compensation previously recognized in Additional Paid-in Capital.
During the years ended December 31, 2022 and 2021, the Company recorded gross expense related to stock-based compensation of approximately $35.4 million (net of $4.1 million of income tax benefit) and $21.0 million (net of $2.8 million of income tax benefit), respectively.
Note 12. Long-Term Debt
The Company’s long-term debt consisted of the following (in thousands):
December 31, 2022 | December 31, 2021 | |||||||
Revolving credit facility(1) |
$ | 270,136 | $ | 320,000 | ||||
Term loan under credit facility due 2027 |
250,000 | — | ||||||
8.000% Senior notes due 2027 |
550,000 | — | ||||||
|
|
|
|
|||||
$ | 1,070,136 | $ | 320,000 | |||||
Unamortized debt issuance costs on term loan |
(5,309 | ) | — | |||||
Unamortized debt issuance costs on 8.000% Senior notes |
(10,948 | ) | — | |||||
|
|
|
|
|||||
Long-term debt, net |
$ | 1,053,879 | $ | 320,000 | ||||
|
|
|
|
(1) | Related to the revolving credit facility borrowings, the Company had debt issuance costs of $15.3 million and $6.7 million, net of accumulated amortization of $6.5 million and $3.3 million, as of December 31, 2022 and 2021, respectively. Unamortized deferred financing costs on the revolving credit facility borrowings are included in Other noncurrent assets in the Consolidated Balance Sheets. |
Credit Agreement
On November 21, 2019, Earthstone, EEH (the “Borrower”), Wells Fargo Bank, National Association, as Administrative Agent and Issuing Bank (“Wells Fargo”), BOKF, NA dba Bank of Texas, as Issuing Bank with respect to Existing Letters of Credit, Royal Bank of Canada, as Syndication Agent, Truist Bank, as successor by merger to SunTrust Bank, as Documentation Agent, and the Lenders party thereto (collectively, the “Parties”) entered into a credit agreement (the “Credit Agreement”), which replaced the prior credit facility, which was terminated on November 21, 2019.
On January 30, 2022, Earthstone, EEH, as Borrower, Wells Fargo as Administrative Agent, the lenders party thereto (the “Lenders”) and the guarantors party thereto entered into an amended and restated Fifth Amendment (the “Fifth Amendment”) to the Credit Agreement. Among other things, the Fifth Amendment increased the borrowing base and corresponding elected commitments from $650 million to $825 million upon the closing of the Chisholm Agreement.
On April 14, 2022, in connection with the closing of the Bighorn Acquisition, the Notes Offering and pursuant to the Fifth Amendment, amongst other things, the borrowing base increased to $1,325 million and elected commitments were reduced to $800 million compared to the maximum of $1,325 million provided for in the Fifth Amendment in the event that the Bighorn Acquisition had closed prior to the Notes Offering.
On June 2, 2022, the Company, EEH, Wells Fargo, the Lenders and the guarantors party thereto entered into an amendment (the “Sixth Amendment”) to the Credit Agreement. Among other things, the Sixth Amendment extended the maturity of the Credit Agreement to June 2027, increased the borrowing base from $1.325 billion to $1.4 billion and reduced the interest rate for amounts outstanding. Elected commitments under the Credit Agreement remained at $800 million.
On August 10, 2022, Earthstone, EEH, Wells Fargo as Administrative Agent, the Lenders and the guarantors party thereto entered into an amendment (the “Seventh Amendment”) to the Credit Agreement. Among other things, the Seventh Amendment increased the borrowing base from $1.4 billion to $1.7 billion and increased elected commitments from $800 million to $1.2 billion.
F-31
EARTHSTONE ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
The Seventh Amendment also established a fully funded $250 million term loan tranche as a portion of the $1.2 billion of available commitments under the Credit Agreement (the “Term Loan”), with the remaining $950 million of commitments in the form of revolving commitments. The Term Loan is fully pre-payable without premium or penalty, subject to the satisfaction of certain specified conditions, and bears an interest rate of Term SOFR (as defined in the Credit Agreement) plus 3.25%, increasing by 0.25% each 180-day period following the Term Loan funding. The Term Loan is co-terminus with the revolving loans’ maturity date of June 2, 2027, subject to a potential acceleration of the maturity date to as soon as January 14, 2027 (the “Springing Maturity Date”, as defined in the Credit Agreement) applicable to revolving loans and term loans. The interest rate applicable to revolving loans remains a rate of Term SOFR plus an applicable margin between 2.25% and 3.25%, depending upon borrowing base utilization.
On September 29, 2022, in connection with a regularly scheduled borrowing base redetermination, the borrowing base increased from $1.7 billion to $1.85 billion.
The next regularly scheduled redetermination of the borrowing base is expected to occur on or around May 1, 2023. Subsequent redeterminations are expected to occur on or about each November 1st and May 1st thereafter. The amounts borrowed under the Credit Agreement bear annual interest rates at either (a) the adjusted SOFR Rate (as customarily defined) (the “Adjusted Term SOFR Rate”) plus 2.25% to 3.25% or (b) the sum of (i) the greatest of (A) the prime rate of Wells Fargo, (B) the federal funds rate plus 1⁄2 of 1.0%, and (C) the Adjusted Term SOFR Rate for an interest rate period of one month plus 1.0%, (ii) plus 1.25% to 2.25%, depending on the amount borrowed under the Credit Agreement. Principal amounts outstanding under the Credit Agreement are due and payable in full at maturity on June 2, 2027. All of the obligations under the Credit Agreement, and the guarantees of those obligations, are secured by substantially all of EEH’s assets. Additional payments due under the Credit Agreement include paying a commitment fee of 0.375% to 0.50% per year, depending on the amount borrowed under the Credit Agreement, to the Lenders in respect of the unutilized commitments thereunder. EEH is also required to pay customary letter of credit fees.
The Credit Agreement contains a number of covenants that, among other things, restrict, subject to certain exceptions, EEH’s ability to incur additional indebtedness, create liens on assets, make investments, pay dividends and distributions or repurchase its limited liability interests, engage in mergers or consolidations, sell certain assets, sell or discount any notes receivable or accounts receivable and engage in certain transactions with affiliates.
In addition, the Credit Agreement requires EEH to maintain the following financial covenants: a current ratio, (as such term is defined in the Credit Agreement) of not less than 1.0 to 1.0 and a consolidated leverage ratio of not greater than 3.5 to 1.0. Consolidated leverage ratio means the ratio of (i) the aggregate debt of EEH and its consolidated subsidiaries as at the last day of the fiscal quarter to (ii) EBITDAX for the applicable period, which was calculated as EBITDAX for the four consecutive fiscal quarters ending on such date. The term “EBITDAX” means, for any period, the sum of consolidated net income (loss) for such period plus (a) the following expenses or charges to the extent deducted from consolidated net income (loss) in such period: (i) interest, (ii) taxes, (iii) depreciation, (iv) depletion, (v) amortization, (vi) certain distributions to employees related to the stock compensation, (vii) certain transaction related expenses, (viii) reimbursed indemnification expenses related to certain dispositions and investments, (ix) non-cash extraordinary, usual, or nonrecurring expenses or losses, (x) other non-cash charges and minus (b) to the extent included in consolidated net income (loss) in such period: (i) non-cash income, (ii) gains on asset dispositions, disposals and abandonments outside of the ordinary course of business and (iii) to the extent not otherwise deducted from consolidated net income (loss), the aggregate amount of any pass-through cash distributions received by Borrower during such period in an amount equal to the aggregate amount of pass-through cash distributions actually made by Borrower during such period.
The Credit Agreement contains customary affirmative covenants and defines events of default to include failure to pay principal or interest, breach of covenants, breach of representations and warranties, insolvency, judgment default and a change in control. Upon the occurrence and continuance of an event of default, the Lenders have the right to accelerate repayment of the loans and exercise their remedies with respect to the collateral. As of December 31, 2022, EEH was in compliance with the covenants under the Credit Agreement.
As of December 31, 2022, $270.1 million and $250.0 million of borrowings were outstanding under the revolving tranche and the term loan tranche of the Credit Agreement, respectively, bearing annual interest of 7.238% and 7.670%, respectively, resulting in an additional $679.9 million of borrowing availability under the Credit Agreement. At December 31, 2021, there were $320.0 million of borrowings outstanding under the Credit Agreement.
For the year ended December 31, 2022, the Company had borrowings of $3.1 billion and $3.1 billion in repayments of borrowings.
F-32
EARTHSTONE ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
For the year ended December 31, 2022, interest on the revolving tranche of the Credit Agreement averaged 4.74% per annum, which excluded commitment fees of $1.7 million and amortization of deferred financing costs of $3.2 million. For the year ended December 31, 2022, interest on the term loan tranche of the Credit Agreement averaged 6.67% per annum, which excluded amortization of deferred financing costs of $0.5 million. For the years ended December 31, 2021 and 2020, interest on borrowings under the Credit Agreement averaged 3.40% and 2.83% per annum, respectively, which excluded commitment fees of $0.9 million and $0.6 million for each period ended, respectively, and amortization of deferred financing costs of $0.9 million and $0.3 million for each period ended, respectively.
During the year ended December 31, 2022, the Company capitalized $6.5 million and $5.8 million of costs associated with the revolving tranche and term loan tranche of the Credit Agreement, respectively. The Company capitalized $2.8 million costs associated with the Credit Agreement for the year ended December 31, 2021. No costs associated with the Credit Agreement were capitalized during the year ended December 31, 2020. The Company’s policy is to capitalize the financing costs associated with its debt and amortize those costs on a straight-line basis over the term of the associated debt, which approximates the effective interest method over the term of the related debt.
8.000% Senior Notes
On April 12, 2022, EEH issued $550.0 million aggregate principal amount of unsecured 8.000% senior notes due 2027 (the “Notes”) for net proceeds of approximately $537.2 million (after deducting underwriting discounts and commissions) (the “Notes Offering”) which was used primarily to fund the Bighorn Acquisition and the remainder for general corporate purposes.
On April 12, 2022, in connection with the completion of the Notes Offering, EEH entered into an indenture, dated as of April 12, 2022 (the “Indenture”), among EEH, the guarantors party thereto and U.S. Bank Trust Company, National Association, as trustee.
The Notes will mature on April 15, 2027 with interest accruing at a rate of 8.000% per annum payable semi-annually in cash in arrears on April 15 and October 15 of each year, which commenced on October 15, 2022. Before April 15, 2024, EEH may redeem some or all of the Notes at a redemption price equal to 100% of the aggregate principal amount of the Notes redeemed plus the “applicable premium” as of and accrued and unpaid interest, if any. EEH may redeem, at its option, all or part of the Notes at any time on or after April 15, 2024, at the applicable redemption price plus accrued and unpaid interest to, but not including, the date of redemption. Further, before April 15, 2024, EEH may on one or more occasions redeem up to 35% of the aggregate principal amount of the Notes in an amount not exceeding the net proceeds from one or more private or public equity offerings at a redemption price of 108.000% of the principal amount of the Notes, plus accrued and unpaid interest to the date of redemption, if at least 65% of the aggregate principal amount of the Notes remains outstanding immediately after such redemption and the redemption occurs within 180 days of the closing date of each such equity offering. Upon a Change of Control (as defined in the Indenture) EEH must offer to repurchase the Notes on terms and conditions set forth in detail in the Indenture.
The Notes are guaranteed on a senior unsecured basis by the Company and its subsidiaries (the “Guarantors”) and may be guaranteed by certain of EEH’s future restricted subsidiaries. The Notes are unsecured, rank equally in right of payment with all existing and future senior unsecured indebtedness of EEH and the Guarantors and rank senior in right of payment to any future subordinated indebtedness of EEH and the Guarantors. The Notes will rank effectively junior to all secured indebtedness of EEH and the Guarantors, including indebtedness under the Credit Agreement, to the extent of the value of the assets securing such indebtedness. The Notes will rank structurally junior in right of payment to all indebtedness and other liabilities, including trade payables, of any future subsidiary of EEH that are not guarantors.
The Indenture restricts EEH’s ability and the ability of its Restricted Subsidiaries (as defined in the Indenture), including the Guarantors, to: (i) incur or guarantee additional indebtedness or issue certain types of preferred stock; (ii) pay dividends on capital stock or redeem, repurchase or retire its capital stock or subordinated indebtedness; (iii) transfer or sell assets; (iv) make investments; (v) create certain liens; (vi) enter into agreements that restrict dividends or other payments from its Restricted Subsidiaries to EEH; (vii) consolidate, merge or transfer all or substantially all of its assets; (viii) engage in transactions with affiliates; and (ix) create unrestricted subsidiaries. These covenants are subject to important exceptions and qualifications set forth in the Indenture. If the Notes achieve an Investment Grade Rating (as defined in the Indenture) or better from two of three of Moody’s Investors Service, Inc., S&P Global Ratings, or Fitch Ratings, Inc., many of these covenants will be suspended.
The Indenture contains customary events of default (each an “Event of Default”). If an Event of Default occurs and is continuing, the Trustee or the holders of not less than 25% in aggregate principal amount of the outstanding Notes may declare the unpaid principal of, premium, if any, and accrued but unpaid interest on, all the Notes then outstanding to be due and payable. Upon such a declaration, such principal, premium, if any, and interest will be due and payable immediately. If an Event of Default relating to certain events of bankruptcy or insolvency of EEH or any Significant Subsidiary (as defined in the Indenture) occurs, the principal of, premium, if any, and the interest on, all the Notes will become immediately due and payable without any declaration or other act on the part of the Trustee or any holders of the Notes. Under certain circumstances, the holders of a majority in principal amount of the outstanding Notes may rescind any such acceleration with respect to the Notes and its consequences.
F-33
EARTHSTONE ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
During the year ended December 31, 2022, the Company capitalized $12.7 million of costs associated with the Notes. No costs associated with the Notes were capitalized during the years ended December 31, 2021 and 2020. The Company’s policy is to capitalize the debt issuance costs associated with the Notes and amortize those costs on a straight-line basis over the term of the Notes.
As of December 31, 2022, accrued interest of $9.5 million associated with the Notes was included in Accrued expenses in the Consolidated Balance Sheets.
Note 13. Asset Retirement Obligations
The Company has asset retirement obligations associated with the future plugging and abandonment of oil and natural gas properties and related facilities. Revisions to the liability typically occur due to changes in the estimated abandonment costs, well economic lives, and the discount rate.
The following table summarizes the Company’s asset retirement obligation transactions recorded during the years ended December 31, 2022 and 2021 (in thousands):
2022 | 2021 | |||||||
Beginning asset retirement obligations |
$ | 15,866 | $ | 3,027 | ||||
Associated with acquisitions |
20,078 | 9,821 | ||||||
Liabilities incurred |
533 | 163 | ||||||
Property dispositions |
(10,284 | ) | (41 | ) | ||||
Liabilities settled |
(910 | ) | (185 | ) | ||||
Accretion expense |
2,652 | 1,065 | ||||||
Revision of estimates |
2,625 | 2,016 | ||||||
|
|
|
|
|||||
Ending asset retirement obligations |
$ | 30,560 | $ | 15,866 | ||||
|
|
|
|
Note 14. Related Party Transactions
FASB ASC Topic 850, Related Party Disclosures, requires that information about transactions with related parties that would make a difference in decision making shall be disclosed so that users of the financial statements can evaluate their significance. The Audit Committee of the Board independently reviews and approves all related party transactions.
Earthstone has three significant shareholders that consist of various investment funds managed by each of the three private equity firms who may manage other investments in entities with which the Company interacts in the normal course of business (the “Significant Shareholders” or separately, each a “Significant Shareholder”).
On February 12, 2020, the Company sold certain of its interests in oil and natural gas leases and wells in a transaction to a portfolio company of a Significant Shareholder (not under common control) for cash consideration of approximately $0.4 million.
As discussed in Note 4. Acquisitions and Divestitures, on March 31, 2021, the Company entered into the Tracker/Sequel Purchase Agreements. The Tracker/Sequel Acquisitions were consummated on July 20, 2021, whereby the Company acquired the Tracker Assets for a purchase price of $18.8 million in cash and 4.7 million shares of Class A Common Stock. A Significant Shareholder owned approximately 49% of Tracker as of the closing of the Tracker Acquisition. A majority of the stockholders of Earthstone not affiliated with the Significant Shareholder approved the issuance of 6.2 million shares of Class A Common Stock in connection with the closing of the Tracker/Sequel Purchase Agreements at Earthstone’s Annual Meeting of Stockholders held on July 20, 2021.
As discussed in Note 4. Acquisitions and Divestitures, during the second quarter of 2021, the Company completed the Eagle Ford Acquisitions for a purchase price of approximately $45.2 million in cash. A Significant Shareholder controlled one of the four sellers. After participating in a competitive sales process, the Company acquired the aforementioned assets for $8.2 million in cash from that related party entity.
As discussed in Note 4. Acquisitions and Divestitures, the Chisholm Acquisition was consummated on February 15, 2022, whereby the Company acquired the Chisholm Assets for a purchase price of $377.5 million in cash, net of customary purchase price adjustments, and approximately 19.4 million shares of Class A Common Stock. A Significant Shareholder was the majority owner of Chisholm as of the closing of the Chisholm Acquisition. The deferred payment of $70 million as of March 31, 2022 was paid on April 15, 2022 and included in Deferred acquisition payment – Chisholm in the Condensed Consolidated Balance Sheet as of March 31, 2022. The issuance of approximately 19.4 million shares of Class A Common Stock in connection with the closing of the Chisholm Agreement was (1) approved by a majority of the voting power of all outstanding disinterested shares of the Common Stock and (2) increased the Significant Stockholder’s beneficial ownership of Class A Common Stock from approximately 25% to 36% as of February 15, 2022.
F-34
EARTHSTONE ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
On January 30, 2022, Earthstone entered into the SPA with certain affiliates of EnCap and Post Oak (collectively, the “Investors”) to issue 220,000 shares and 60,000 shares, respectively, of the Series A Convertible Preferred Stock. On April 14, 2022, the SPA was consummated resulting in the issuance of the total of 280,000 shares of the Series A Convertible Preferred Stock in exchange for cash proceeds of $279.3 million, net of offering costs.
On July 6, 2022, the Series A Convertible Preferred Stock automatically converted into 25,225,225 shares of Class A Common Stock.
The Company paid $0.5 million to one of its Significant Shareholders for reimbursement of certain costs associated with the Bighorn Acquisition and related SPA.
On October 11, 2022, Earthstone repurchased an aggregate of 3,000,000 shares of Class A Common Stock, held by affiliates of Warburg in a private transaction, for an aggregate purchase price of approximately $43.7 million, or $14.58 per share (the “Repurchase”). Additionally, on October 11, 2022, affiliates of Warburg sold 3,750,000 shares of Class A Common Stock to an unrelated party for $14.58 per share (collectively with the Repurchase, the “Warburg Sales”). Immediately preceding the Warburg Sales, Warburg owned approximately 18.7% of the outstanding Class A Common Stock and 14.1% of the Class A Common Stock and Class B Common Stock combined. Immediately following the Warburg Sales and through December 31, 2022, Warburg owned approximately 12.3% of the Class A Common Stock and 9.3% of the Class A Common Stock and Class B Common Stock combined.
Note 15. Commitments and Contingencies
Contractual Commitments
Future minimum contractual commitments as of December 31, 2022 under non-cancellable agreements having initial or remaining terms in excess of one year are as follows:
2023 | 2024 | 2025 | 2026 | 2027 | Thereafter | |||||||||||||||||||
Office leases |
$ | 1,138 | $ | 1,160 | $ | 868 | $ | 1,052 | $ | 961 | $ | 327 | ||||||||||||
Automobile leases |
907 | 724 | 200 | — | — | — | ||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||
Total |
$ | 2,045 | $ | 1,884 | $ | 1,068 | $ | 1,052 | $ | 961 | $ | 327 | ||||||||||||
|
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|
|
|
|
|
|
|
|
|
|
Additionally, the Company leases corporate office space in The Woodlands, Texas; Midland, Texas and San Angelo, Texas. Rent expense was approximately $0.9 million, $0.8 million and $0.8 million, for the years ended December 31, 2022, 2021 and 2020, respectively. Minimum lease payments under the terms of non-cancellable operating leases as of December 31, 2022 are included in the table above.
Environmental
The Company’s operations are subject to risks normally associated with the drilling, completion and production of oil and gas, including blowouts, fires, and environmental risks such as oil spills or gas leaks that could expose the Company to liabilities associated with these risks.
In the Company’s acquisition of existing or previously drilled well bores, the Company may not be aware of prior environmental safeguards, if any, that were taken at the time such wells were drilled or during such time the wells were operated. The Company maintains comprehensive insurance coverage that it believes is adequate to mitigate the risk of any adverse financial effects associated with these risks.
However, should it be determined that a liability exists with respect to any environmental cleanup or restoration, the liability to cure such a violation could still fall upon the Company. No claim has been made, nor is the Company aware of any liability which the Company may have, as it relates to any environmental cleanup, restoration, or the violation of any rules or regulations relating thereto except for the matter discussed above.
Legal
George Assad, et. al. v. EnCap Investments L.P., et. al.: On September 12, 2022, a complaint (the “Complaint”) styled as a “derivative action” was filed in the Delaware Court of Chancery (the “Court”) by George Assad (the “plaintiff”) a purported holder of a small number of shares of Class A Common Stock against Earthstone, six of its 10 directors and EnCap, a principal stockholder.
F-35
EARTHSTONE ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
The Complaint alleges that a majority of Earthstone’s directors were conflicted and, along with EnCap, breached their fiduciary duties in approving the sale of shares of Series A Convertible Preferred Stock that is convertible into Class A Common Stock pursuant to the SPA. The plaintiff requested the Court to declare that the defendants breached their fiduciary duties, award of unspecified monetary damages, including interest and costs, and/ or rescind the stock purchase transaction. On October 14, 2022, the defendants filed a motion to dismiss the amended Complaint. Earthstone believes the Complaint is completely without merit and intends to contest vigorously the allegations made therein and to seek reimbursement for its costs and expenses in so doing. Earthstone carries insurance for the claims asserted against it and the officer and director defendants in the Complaint, and the carrier has accepted coverage subject to applicable self-retentions and limits of liability. The Company does not expect this case to have a material adverse effect on the results of operations, financial position or cash flows of the Company.
From time to time, the Company may be involved in other various legal proceedings and claims in the ordinary course of business.
Note 16. Income Taxes
The Company’s corporate structure requires the filing of two separate consolidated U.S. Federal income tax returns and one Canadian income tax return which include Lynden US, Earthstone, and Lynden Corp. As such, taxable income of Earthstone cannot be offset by tax attributes, including net operating losses, of Lynden US, nor can taxable income of Lynden US be offset by tax attributes of Earthstone. Earthstone and Lynden US record a tax provision, respectively, for their share of the book income or loss of EEH, net of the non-controlling interest. As EEH is treated as a partnership for U.S. Federal income tax purposes, it is not subject to income tax at the federal level and only recognizes the Texas Margin Tax.
The following table shows the components of the Company’s income tax provision for the years ended December 31, 2022, 2021 and 2020 (in thousands):
Years Ended December 31, | ||||||||||||
2022 | 2021 | 2020 | ||||||||||
Current: |
||||||||||||
Federal |
$ | — | $ | — | $ | — | ||||||
State |
1,811 | 625 | 545 | |||||||||
|
|
|
|
|
|
|||||||
Total current |
$ | 1,811 | $ | 625 | $ | 545 | ||||||
|
|
|
|
|
|
|||||||
Deferred: |
||||||||||||
Federal |
$ | 114,876 | $ | 901 | $ | (147 | ) | |||||
State |
7,729 | 333 | (510 | ) | ||||||||
|
|
|
|
|
|
|||||||
Total deferred |
$ | 122,605 | $ | 1,234 | $ | (657 | ) | |||||
|
|
|
|
|
|
|||||||
Total income tax expense (benefit) |
$ | 124,416 | $ | 1,859 | $ | (112 | ) | |||||
|
|
|
|
|
|
Effective Tax Rate
A reconciliation of the effective tax rate to the federal statutory rate for the years ended December 31, 2022, 2021 and 2020 is as follows (in thousands, except percentages):
Years Ended December 31, | ||||||||||||
2022 | 2021 | 2020 | ||||||||||
Net income (loss) before income taxes |
$ | 775,033 | $ | 63,365 | $ | (29,546 | ) | |||||
|
|
|
|
|
|
|||||||
Statutory rate |
21 | % | 21 | % | 21 | % | ||||||
|
|
|
|
|
|
|||||||
Tax expense (benefit) computed at statutory rate |
$ | 162,757 | $ | 13,307 | $ | (6,204 | ) | |||||
Noncontrolling interest |
(41,743 | ) | (5,613 | ) | 3,349 | |||||||
Non-deductible general and administrative expenses |
1,360 | (455 | ) | 1,943 | ||||||||
Return to accrual and other true-up |
(73 | ) | — | 157 | ||||||||
State income taxes, net of Federal benefit |
9,187 | 958 | 35 | |||||||||
Valuation allowance |
(7,072 | ) | (6,338 | ) | 608 | |||||||
|
|
|
|
|
|
|||||||
Total income tax expense (benefit) |
$ | 124,416 | $ | 1,859 | $ | (112 | ) | |||||
|
|
|
|
|
|
|||||||
Effective tax rate |
16.1 | % | 2.9 | % | 0.4 | % | ||||||
|
|
|
|
|
|
F-36
EARTHSTONE ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
During the year ended December 31, 2022, the Company recorded total income tax expense of $124.4 million which included (1) deferred income tax expense for Lynden US of $7.1 million as a result of its share of the distributable income from EEH, (2) deferred income tax expense for Earthstone of $107.8 million, which included a deferred income tax expense of $114.9 million, resulting from its share of the distributable income from EEH, offset by a $7.1 million release of valuation allowance, (3) current income tax expense of $1.8 million solely related to the Texas Margin Tax and (4) state deferred income tax expense of $0.8 million related to the Texas Margin Tax and $6.9 million related to New Mexico corporate income tax expense. Lynden Corp incurred no material income or loss, or related income tax expense or benefit, for the year ended December 31, 2022.
During the year ended December 31, 2021, the Company recorded total income tax expense of $1.9 million which included (1) deferred income tax expense for Lynden US of $0.9 million as a result of its share of the distributable income from EEH, (2) deferred income tax expense for Earthstone of $6.3 million as a result of its share of the distributable income from EEH, which was offset by a valuation allowance as future realization of the net deferred tax asset cannot be assured and (3) current income tax expense of $0.63 million, offset by deferred income tax expense of $0.33 million related to the Texas Margin Tax. Lynden Corp incurred no material income or loss, or related income tax expense or benefit, for the year ended December 31, 2021.
During the year ended December 31, 2020, the Company recorded total income tax benefit of $0.11 million which included (1) deferred income tax benefit for Lynden US of $0.15 million as a result of its share of the distributable income from EEH, (2) deferred income tax benefit for Earthstone of $0.61 million as a result of its share of the distributable income from EEH, which was used to reduce the valuation allowance recorded against its deferred tax asset cannot be assured and (3) current income tax expense of $0.55 million, offset by deferred income tax benefit of $0.51 million related to the Texas Margin Tax. Lynden Corp incurred no material income or loss, or related income tax expense or benefit, for the year ended December 31, 2020.
Deferred Tax Assets and Liabilities
The Company’s deferred tax position reflects the net tax effects of the temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax reporting. Significant components of the deferred tax assets and liabilities at December 31, 2022 and 2021 are as follows (in thousands):
Years Ended December 31, | ||||||||
2022 | 2021 | |||||||
Deferred noncurrent income tax assets (liabilities): |
||||||||
Oil & gas properties |
$ | 11,437 | $ | 20,909 | ||||
Basis difference in subsidiary obligation |
(2,364 | ) | (2,211 | ) | ||||
Investment in Partnerships |
(186,925 | ) | (40,141 | ) | ||||
Federal net operating loss carryforward |
40,695 | 16,544 | ||||||
Interest limitation |
2,581 | — | ||||||
|
|
|
|
|||||
Net deferred noncurrent tax (liability) asset |
$ | (134,576 | ) | $ | (4,899 | ) | ||
|
|
|
|
|||||
Valuation allowance |
(3,760 | ) | (10,832 | ) | ||||
|
|
|
|
|||||
Net deferred tax liability |
$ | (138,336 | ) | $ | (15,731 | ) | ||
|
|
|
|
As of December 31, 2022, the Company had a valuation allowance recorded against its deferred tax asset of $3.8 million which is in excess of its net deferred noncurrent tax liabilities of $134.6 million, as presented above. The Company’s corporate organizational structure requires the filing of two separate consolidated U.S. Federal corporate income tax returns, one separate U.S. Federal partnership income tax return and one Canadian income tax return. As a result, tax attributes of one group cannot be offset by the tax attributes of another. At December 31, 2022, the deferred tax assets and liabilities related to the two U.S. Federal corporate income tax returns, one Canadian income tax return and one related to the Texas Margin Tax are a $113.7 million deferred tax liability, a $18.5 million deferred tax liability, a $3.8 million deferred tax asset and a $6.1 million deferred tax liability, respectively, before considering the valuation allowance of $3.8 million.
As of December 31, 2021, the Company had a valuation allowance recorded against its deferred tax assets of $10.8 million which is in excess of its Net deferred noncurrent tax assets of $7.8 million, as presented above. The Company’s corporate organizational structure requires the filing of two separate consolidated U.S. Federal income tax returns, one separate U.S. Federal partnership income tax return and one Canadian income tax return. As a result, tax attributes of one group cannot be offset by the tax attributes of another. At December 31, 2021, the deferred tax assets and liabilities related to the two U.S. Federal income tax returns, one Canadian income tax and one related to the Texas Margin Tax were a $19.7 million deferred tax asset, a $10.4 million deferred tax liability, a $3.8 million deferred tax asset and a $5.3 million deferred tax liability, respectively, before considering the valuation allowance of $10.8 million.
As of December 31, 2022, (1) Earthstone had estimated U.S. net operating loss carryforwards of $29.1 million, expiring in 2036 and 2037 and $120.1 million with an indefinite carryforward life (“ICL”), (2) Lynden US had estimated U.S. net operating loss carryforwards available for use of $3.7 million, expiring from 2036 through 2037 and $22.4 million with an indefinite carryforward life, and, (3) Lynden Corp had Canadian net operating loss carryforwards of $10.0 million, the first expiring in 2024 and the last in 2037. ICL loss deductions are limited to 80% of the excess of taxable income in the year utilized.
F-37
EARTHSTONE ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
Additionally, the ability to utilize net operating losses and other tax attributes could be subject to a significant limitation if the Company were to undergo an ownership change for the purposes of Section 382 (“Sec 382”) of the Internal Revenue Code of 1986, as amended (the “Code”). On February 15, 2022, the Company completed the Chisholm Acquisition which included the issuance of 19,417,476 shares of Class A Common Stock, which resulted in an ownership change within the meaning of Sec 382. As a result of the ownership change, the Company’s annual usage of net operating losses (“NOLs”) and credits generated prior to the ownership change date may be limited, however, at this time, we do not expect any of the losses to expire unused as a result of this ownership change. Earthstone generated approximately $97.6 million in NOL carryforward assets in 2022, of which, $85.3 million relates to the time period post ownership change within the meaning of Section 382 and is not subject to limitation. Lynden US generated approximately $14.3 million in NOL carryforward assets in 2022, of which, $12.5 million relates to the time period post ownership change within the meaning of Section 382 and is not subject to limitation. Lynden US previously experienced an ownership change on May 17, 2016 and at that time certain NOLs were identified as being expected to expire unusable. The Company continues to evaluate the impact, if any, of potential Sec 382 limitations.
Uncertain Tax Positions
FASB ASC Topic 740, Income Taxes (“ASC 740”) prescribes a recognition threshold and a measurement attribute for the financial statement recognition and measurement of income tax positions taken or expected to be taken in an income tax return. For those benefits to be recognized, an income tax position must be more-likely-than-not to be sustained upon examination by taxing authorities. As of December 31, 2022, the Company had no material uncertain tax positions. The Company’s uncertain tax positions may change in the next twelve months; however, the Company does not expect any possible change to have a significant impact on its results of operations or financial position.
The Company files two Federal income tax returns, one Canadian income tax return and various combined and separate filings in several state and local jurisdictions. The Company’s practice is to recognize estimated interest and penalties, if any, related to potential underpayment of income taxes as a component of income tax expense in its Consolidated Statement of Operations. As of December 31, 2022, the Company did not have any accrued interest or penalties associated with any uncertain tax liabilities.
Note 17. Defined Contribution Plan
The Company sponsors a 401(k) defined contribution plan (the “401(k) Plan”) for substantially all of its employees, which was initiated in April 2017. Eligible employees may make contributions to the 401(k) Plan by electing to contribute up to 100% of their annual compensation, not to exceed annual limits established by the federal government. The Company makes matching contributions of 100% of employee contributions, not to exceed six percent of the employee’s annual eligible compensation. The Company’s matching contributions vest immediately. The Company’s contributions to the 401(k) Plan for the years ended December 31, 2022, 2021 and 2020 were $1.1 million, $0.5 million and $0.5 million, respectively.
Note 18. Leases
The Company’s operating lease activities consist of leases for office space. The Company’s finance lease activities consist of leases for vehicles. Leases with an initial term of 12 months or less are not recorded on the balance sheet. Most leases include one or more options to renew, with renewal terms generally ranging from one to three years. The exercise of lease renewal options is at the Company’s sole discretion. Certain leases also include options to purchase the leased property. The depreciable life of assets and leasehold improvements is limited by the expected lease term, unless there is a transfer of title or purchase option reasonably certain of exercise. None of the lease agreements include variable lease payments. The lease agreements do not contain any material residual value guarantees or material restrictive covenants.
F-38
EARTHSTONE ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
The following table shows the classification and location of the Company’s leases on the Consolidated Balance Sheets (in thousands):
December 31, | ||||||||||
Leases |
Balance Sheet Location |
2022 | 2021 | |||||||
Assets |
||||||||||
Noncurrent: |
||||||||||
Operating |
Operating lease right-of-use assets | $ | 4,569 | $ | 1,795 | |||||
Finance |
Office and other equipment, net of accumulated depreciation and amortization | 1,678 | — | |||||||
|
|
|
|
|||||||
Total lease assets |
$ | 6,247 | $ | 1,795 | ||||||
|
|
|
|
|||||||
Liabilities |
||||||||||
Current: |
||||||||||
Operating |
Operating lease liabilities | $ | 842 | $ | 681 | |||||
Finance |
Finance lease liabilities | 802 | — | |||||||
Noncurrent: |
||||||||||
Operating |
Operating lease liabilities | 3,889 | 1,276 | |||||||
Finance |
Finance lease liabilities | 876 | — | |||||||
|
|
|
|
|||||||
Total lease liabilities |
$ | 6,409 | $ | 1,957 | ||||||
|
|
|
|
The following table shows the classification and location of the Company’s lease costs on the Consolidated Statements of Operations (in thousands):
Years Ended December 31, | ||||||||||||||
Statement of Operations Location |
2022 | 2021 | 2020 | |||||||||||
Operating lease expense |
General and administrative expense | $ | 884 | $ | 803 | $ | 786 | |||||||
Finance lease expense: |
||||||||||||||
Amortization of right-of-use assets |
Depreciation, depletion and amortization | $ | 549 | $ | 74 | $ | 217 | |||||||
Interest on lease liability |
Interest expense, net | 100 | 2 | 13 | ||||||||||
|
|
|
|
|
|
|||||||||
Total lease expense |
$ | 1,533 | $ | 879 | $ | 1,016 | ||||||||
|
|
|
|
|
|
Additionally, the Company capitalized as part of oil and gas properties $23.9 million, $6.4 million and $2.9 million of short-term lease costs related to drilling rig contracts during the years ended December 31, 2022, 2021 and 2020. All of the Company’s drilling rig contracts have enforceable terms of less than one year.
Minimum contractual obligations for the Company’s leases (undiscounted) as of December 31, 2022 were as follows (in thousands):
Operating | Finance | |||||||
2023 |
$ | 1,138 | $ | 907 | ||||
2024 |
1,160 | 724 | ||||||
2025 |
868 | 200 | ||||||
2026 |
1,052 | — | ||||||
2027 |
961 | — | ||||||
Thereafter |
327 | — | ||||||
|
|
|
|
|||||
Total lease payments |
$ | 5,506 | $ | 1,831 | ||||
Less imputed interest |
(775 | ) | (153 | ) | ||||
|
|
|
|
|||||
Total lease liability |
$ | 4,731 | $ | 1,678 | ||||
|
|
|
|
F-39
EARTHSTONE ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
The following table shows the weighted average remaining lease term and the weighted average discount rate for the Company’s leases as of the dates indicated:
December 31, 2022 | December 31, 2021 | |||||||||||||||
Operating Leases | Finance Leases | Operating Leases | Finance Leases | |||||||||||||
Weighted-average remaining lease term (in years) |
4.1 | 2.3 | 2.9 | n/a | ||||||||||||
Weighted-average discount rate (1) |
6.67 | % | 8.00 | % | 4.35 | % | n/a |
(1) | The discount rate used for operating leases is based on the Company’s incremental borrowing rate at lease commencement and may be adjusted if modifications to lease terms or lease reassessments occur. The discount rate used for finance leases is based on the rates implicit in the leases. |
The following table includes other quantitative information for the Company’s leases (in thousands):
Years Ended December 31, | ||||||||
2022 | 2021 | |||||||
Cash paid for amounts included in the measurement of lease liabilities: |
||||||||
Cash payments for operating leases |
$ | 857 | $ | 778 | ||||
Cash payments for finance leases |
$ | 649 | $ | 70 | ||||
Right-of-use assets obtained in exchange for new operating lease liabilities |
$ | 3,447 | $ | — | ||||
Right-of-use assets obtained in exchange for new finance lease liabilities |
$ | 2,227 | $ | — |
Note 19. Supplemental Disclosures
Accounts Payable
The following table summarizes the Company’s current accounts payable at December 31, 2022 and 2021 (in thousands):
December 31, | ||||||||
2022 | 2021 | |||||||
Accounts payable related to vendors |
$ | 76,044 | $ | 22,877 | ||||
Accounts payable related to severance taxes |
10,380 | 2,603 | ||||||
Other |
5,391 | 5,917 | ||||||
|
|
|
|
|||||
Total accounts payable |
$ | 91,815 | $ | 31,397 | ||||
|
|
|
|
Revenue and Royalties Payable
The following table summarizes the Company’s current revenues and royalties payable at December 31, 2022 and 2021 (in thousands):
December 31, | ||||||||
2022 | 2021 | |||||||
Revenue held in suspense |
$ | 101,838 | $ | 14,777 | ||||
Revenue and royalties payable |
61,530 | 21,412 | ||||||
|
|
|
|
|||||
Total revenue and royalties payable |
$ | 163,368 | $ | 36,189 | ||||
|
|
|
|
F-40
EARTHSTONE ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
Accrued Expenses
The following table summarizes the Company’s current accrued expenses at December 31, 2022 and 2021 (in thousands):
December 31, | ||||||||
2022 | 2021 | |||||||
Accrued capital expenditures |
$ | 38,482 | $ | 10,563 | ||||
Accrued lease operating expenses |
14,173 | 2,858 | ||||||
Accrued interest |
10,995 | 648 | ||||||
Accrued general and administrative expense |
7,351 | 8,011 | ||||||
Accrued ad valorem taxes |
4,243 | 544 | ||||||
Other |
5,698 | 9,080 | ||||||
|
|
|
|
|||||
Total accrued expenses |
$ | 80,942 | $ | 31,704 | ||||
|
|
|
|
Supplemental Cash Flow Information
The following table provides supplemental disclosures of cash flow information for the years ended December 31, 2022, 2021 and 2020 (in thousands):
Years Ended December 31, | ||||||||||||
2022 | 2021 | 2020 | ||||||||||
Cash paid for: |
||||||||||||
Interest |
$ | 12,520 | $ | 9,648 | $ | 4,588 | ||||||
Income taxes |
$ | 625 | $ | 325 | $ | — | ||||||
Non-cash investing and financing activities: |
||||||||||||
Class A Common Stock issued in Chisholm Acquisition |
$ | 249,515 | $ | — | $ | — | ||||||
Class A Common Stock issued in Bighorn Acquisition |
$ | 77,757 | $ | — | $ | — | ||||||
Class A Common Stock issued in Titus Acquisition |
$ | 53,574 | $ | — | $ | — | ||||||
Class A Common Stock issued in IRM Acquisition |
$ | — | $ | 76,572 | $ | — | ||||||
Class A Common Stock issued in Tracker/Sequel Acquisition |
$ | — | $ | 61,814 | $ | — | ||||||
Class A Common Stock issued in Foreland Acquisition |
$ | — | $ | 28,121 | $ | — | ||||||
Accrued capital expenditures |
$ | 58,569 | $ | 23,558 | $ | 7,328 | ||||||
Lease asset additions - ASC 842 |
$ | 5,674 | $ | — | $ | — | ||||||
Asset retirement obligations |
$ | 3,158 | $ | 2,178 | $ | 762 |
Note 20. Supplemental Information On Oil And Gas Exploration And Production Activities (Unaudited)
Costs Incurred Related to Oil and Gas Activities
Capitalized costs include the cost of properties, equipment, and facilities for oil and natural gas producing activities. Capitalized costs for proved properties include costs for oil and natural gas leaseholds where proved reserves have been identified, development wells, and related equipment and facilities, including development wells in progress. Capitalized costs for unproved properties include costs for acquiring oil and natural gas leaseholds where no proved reserves have been identified, including costs of exploratory wells that are in the process of drilling or in active completion, and costs of exploratory wells suspended or waiting on completion.
F-41
EARTHSTONE ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
The Company’s oil and natural gas activities for 2022, 2021 and 2020 were entirely within the United States of America. Costs incurred in oil and natural gas producing activities were as follows (in thousands):
Years Ended December 31, | ||||||||||||
2022 | 2021 | 2020 | ||||||||||
Acquisition cost: |
||||||||||||
Proved |
$ | 1,934,602 | $ | 465,144 | $ | — | ||||||
Unproved |
77,378 | 43 | — | |||||||||
Exploration costs: |
||||||||||||
Geological and geophysical |
2,492 | 341 | 298 | |||||||||
Development costs |
538,114 | 134,035 | 67,550 | |||||||||
|
|
|
|
|
|
|||||||
Total additions |
$ | 2,552,586 | $ | 599,563 | $ | 67,848 | ||||||
|
|
|
|
|
|
During the years ended December 31, 2022, 2021 and 2020, additions to oil and natural gas properties of $3.2 million, $2.2 million and $0.8 million, respectively, were recorded for estimated costs of future abandonment related to new wells drilled or acquired.
During the years ended December 31, 2022, 2021 and 2020, the Company had no capitalized exploratory well costs, nor capitalized costs related to share-based compensation, general corporate overhead or similar activities.
Capitalized Costs
Capitalized costs, impairment, and depreciation, depletion and amortization relating to the Company’s oil and natural gas properties producing activities, all of which are conducted within the continental United States as of December 31, 2022 and 2021, are summarized below (in thousands):
December 31, | ||||||||
2022 | 2021 | |||||||
Oil and gas properties, successful efforts method: |
||||||||
Proved properties |
$ | 4,088,553 | $ | 1,726,019 | ||||
Accumulated impairment to proved properties |
(100,652 | ) | (100,652 | ) | ||||
|
|
|
|
|||||
Proved properties, net of accumulated impairments |
3,987,901 | 1,625,367 | ||||||
Unproved properties |
349,905 | 289,341 | ||||||
Accumulated impairment to Unproved properties |
(67,316 | ) | (67,316 | ) | ||||
|
|
|
|
|||||
Unproved properties, net of accumulated impairments |
282,589 | 222,025 | ||||||
Land |
5,482 | 5,382 | ||||||
|
|
|
|
|||||
Total oil and gas properties, net of accumulated impairments |
4,275,972 | 1,852,774 | ||||||
Accumulated depreciation, depletion and amortization |
(619,196 | ) | (395,625 | ) | ||||
|
|
|
|
|||||
Net oil and gas properties |
$ | 3,656,776 | $ | 1,457,149 | ||||
|
|
|
|
Oil and Natural Gas Reserves
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 in the evaluation of all available geological, engineering and economic data for each reservoir. The data for a given reservoir may also change substantially over time as a result of numerous factors including, but not limited to, additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. As a result, revisions to existing reserve estimates may occur from time to time. Although every reasonable effort is made to ensure reserve estimates reported represent the most accurate assessments possible, the subjective decisions and variances in available data for various reservoirs make these estimates generally less precise than other estimates included in the financial statement disclosures.
Proved reserves represent estimated quantities of oil, natural gas 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 reserves represent estimated quantities expected to be recovered through wells and equipment in place and under operating methods used when the estimates were made.
F-42
EARTHSTONE ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
The proved reserves estimates shown herein for the years ended December 31, 2022, 2021 and 2020 have been prepared by Cawley, Gillespie & Associates, Inc., independent petroleum engineers. Proved reserves were estimated in accordance with guidelines established by the SEC, which require that reserve estimates be prepared under existing economic and operating conditions based upon the 12-month unweighted average of the first-day-of-the-month prices.
The reserve information in these Consolidated Financial Statements represents only estimates. There are a number of uncertainties inherent in estimating quantities of proved reserves, including many factors beyond the Company’s control, such as commodity pricing. Reserve engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact manner. The accuracy of any reserve estimate is a function of the quality of available data and engineering and geological interpretation and judgment. As a result, estimates by different engineers may vary. In addition, results of drilling, testing and production subsequent to the date of an estimate may lead to revising the original estimate. Accordingly, initial reserve estimates are often different from the quantities of oil and natural gas that are ultimately recovered. The meaningfulness of such estimates depends primarily on the accuracy of the assumptions upon which they were based. Except to the extent the Company acquires additional properties containing proved reserves or conducts successful exploration and development activities or both, the Company’s proved reserves will decline as reserves are produced.
The following table illustrates the Company’s estimated net proved reserves, including changes, and proved developed and proved undeveloped reserves for the periods indicated. The oil prices as of December 31, 2022, 2021 and 2020 are based on the respective 12-month unweighted average of the first of the month prices of the West Texas Intermediate (“WTI”) spot prices which equates to $93.67 per barrel, $66.56 per barrel and $39.57 per barrel, respectively. The natural gas prices as of December 31, 2022, 2021 and 2020 are based on the respective 12-month unweighted average of the first of month prices of the Henry Hub spot price which equates to $6.36 per MMBtu, $3.60 per MMBtu and $1.99 per MMBtu, respectively. Natural gas liquids are made up of ethane, propane, isobutane, normal butane and natural gasoline, each of which have different uses and different pricing characteristics. The natural gas liquids prices used to value reserves as of December 31, 2022, 2021 and 2020 averaged $39.24 per barrel, $30.16 per barrel and $11.61 per barrel, respectively. All prices are adjusted by lease or field for energy content, transportation fees, and market differentials, resulting in the aforementioned oil, natural gas and natural gas liquids reserves as of December 31, 2022 being valued using prices of $95.82 per barrel, $5.51 per MMBtu and $39.24 per barrel, respectively. All prices are held constant in accordance with SEC guidelines.
F-43
EARTHSTONE ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
A summary of the Company’s changes in quantities of proved oil, natural gas and natural gas liquid reserves for the years ended December 31, 2022, 2021 and 2020 are as follows:
Oil (MBbl) |
Natural Gas (MMcf) |
Natural Gas Liquids (MBbl) |
Total (MBoe) |
|||||||||||||
Balance - December 31, 2019 |
52,650 | 107,990 | 23,688 | 94,336 | ||||||||||||
Extensions |
420 | 1,258 | 230 | 860 | ||||||||||||
Production |
(3,180 | ) | (7,282 | ) | (1,237 | ) | (5,630 | ) | ||||||||
Revision to previous estimates |
(9,800 | ) | 9,249 | (2,432 | ) | (10,691 | ) | |||||||||
|
|
|
|
|
|
|
|
|||||||||
Balance - December 31, 2020 |
40,090 | 111,215 | 20,249 | 78,875 | ||||||||||||
Extensions |
7,016 | 49,846 | 6,532 | 21,856 | ||||||||||||
Sales of minerals in place |
(8 | ) | (1 | ) | — | (8 | ) | |||||||||
Purchases of minerals in place |
25,114 | 106,539 | 17,103 | 59,973 | ||||||||||||
Production |
(4,381 | ) | (14,505 | ) | (2,257 | ) | (9,055 | ) | ||||||||
Revision to previous estimates |
(6,756 | ) | 31,787 | (2,596 | ) | (4,054 | ) | |||||||||
|
|
|
|
|
|
|
|
|||||||||
Balance - December 31, 2021 |
61,075 | 284,881 | 39,031 | 147,587 | ||||||||||||
Extensions |
13,430 | 51,346 | 7,895 | 29,883 | ||||||||||||
Sales of minerals in place |
(2,044 | ) | (6,631 | ) | (1,417 | ) | (4,566 | ) | ||||||||
Purchases of minerals in place |
85,237 | 429,646 | 56,268 | 213,113 | ||||||||||||
Production |
(11,866 | ) | (54,392 | ) | (7,599 | ) | (28,531 | ) | ||||||||
Revision to previous estimates |
(7,432 | ) | 37,316 | 11,663 | 10,450 | |||||||||||
|
|
|
|
|
|
|
|
|||||||||
Balance - December 31, 2022 |
138,400 | 742,166 | 105,841 | 367,936 | ||||||||||||
|
|
|
|
|
|
|
|
|||||||||
Proved developed reserves: |
||||||||||||||||
December 31, 2019 |
18,220 | 35,120 | 7,447 | 31,521 | ||||||||||||
|
|
|
|
|
|
|
|
|||||||||
December 31, 2020 |
18,878 | 55,764 | 10,125 | 38,298 | ||||||||||||
|
|
|
|
|
|
|
|
|||||||||
December 31, 2021 |
35,824 | 190,999 | 25,917 | 93,575 | ||||||||||||
|
|
|
|
|
|
|
|
|||||||||
December 31, 2022 |
88,759 | 574,762 | 80,168 | 264,721 | ||||||||||||
|
|
|
|
|
|
|
|
|||||||||
Proved undeveloped reserves: |
||||||||||||||||
|
|
|
|
|
|
|
|
|||||||||
December 31, 2019 |
34,430 | 72,870 | 16,241 | 62,815 | ||||||||||||
|
|
|
|
|
|
|
|
|||||||||
December 31, 2020 |
21,212 | 55,450 | 10,123 | 40,577 | ||||||||||||
|
|
|
|
|
|
|
|
|||||||||
December 31, 2021 |
25,251 | 93,882 | 13,114 | 54,012 | ||||||||||||
|
|
|
|
|
|
|
|
|||||||||
December 31, 2022 |
49,641 | 167,404 | 25,673 | 103,215 | ||||||||||||
|
|
|
|
|
|
|
|
F-44
EARTHSTONE ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
The table below presents the quantities of proved oil, natural gas and natural gas liquids reserves attributable to noncontrolling interests as of December 31, 2022 and 2021 and 2020:
As of December 31, 2022 | Oil (MBbl) |
Natural Gas (MMcf) |
Natural Gas Liquids (MBbl) |
Total (MBoe) |
||||||||||||
Proved developed |
21,750 | 140,845 | 19,645 | 64,870 | ||||||||||||
Proved undeveloped |
12,165 | 41,022 | 6,291 | 25,293 | ||||||||||||
|
|
|
|
|
|
|
|
|||||||||
Total proved |
33,915 | 181,867 | 25,936 | 90,163 | ||||||||||||
|
|
|
|
|
|
|
|
|||||||||
As of December 31, 2021 | Oil (MBbl) |
Natural Gas (MMcf) |
Natural Gas Liquids (MBbl) |
Total (MBoe) |
||||||||||||
Proved developed |
14,011 | 74,702 | 10,137 | 36,598 | ||||||||||||
Proved undeveloped |
9,876 | 36,719 | 5,129 | 21,125 | ||||||||||||
|
|
|
|
|
|
|
|
|||||||||
Total proved |
23,887 | 111,421 | 15,266 | 57,723 | ||||||||||||
|
|
|
|
|
|
|
|
|||||||||
As of December 31, 2020 | Oil (MBbl) |
Natural Gas (MMcf) |
Natural Gas Liquids (MBbl) |
Total (MBoe) |
||||||||||||
Proved developed |
10,113 | 29,873 | 5,424 | 20,516 | ||||||||||||
Proved undeveloped |
11,363 | 29,704 | 5,423 | 21,737 | ||||||||||||
|
|
|
|
|
|
|
|
|||||||||
Total proved |
21,476 | 59,577 | 10,847 | 42,253 | ||||||||||||
|
|
|
|
|
|
|
|
Notable changes in proved reserves for the year ended December 31, 2022 included the following:
• | Extensions. In 2022, extensions of 29.9 MMBoe were primarily the result of successful drilling results in the Midland Basin. |
• | Purchases of minerals in place. In 2022, the Company completed multiple acquisitions that resulted in 213.1 MMBoe in additional reserves, as disclosed in Note 4. Acquisitions and Divestitures. |
• | Revision to previous estimates. In 2022, the upward revisions of prior reserves of 10.5 MMBoe consisted of 6.5 MMBoe related to changes in price and 4.0 MMBoe related to changes in performance and other economic factors. |
Notable changes in proved reserves for the year ended December 31, 2021 included the following:
• | Extensions. In 2021, total extensions of 21.9 MMBoe were primarily the result of successful drilling results in the Midland Basin. |
• | Purchases of mineral in place. In 2021, the Company completed multiple acquisitions that resulted in 60.0 MMBoe in additional reserves, as disclosed above in Note 4. Acquisitions and Divestitures. |
• | Revision to previous estimates. In 2021, the downward revisions of prior reserves of 4.1 MMBoe consisted of changes in anticipated well densities and changes in performance and other economic factors totaling 9.2 MMBoe and 5.5 MMBoe, respectively, offset by a positive revision of 10.6 MMBoe related to changes in prices. |
Notable changes in proved reserves for the year ended December 31, 2020 included the following:
• | Extensions. In 2020, total extensions of 860.0 MBoe were primarily the result of successful drilling results in the Midland Basin. |
• | Revision to previous estimates. In 2020, the downward revisions of prior reserves of 10.7 MMBoe were composed of negative revisions due to the reclassification of 11.9 MMBoe of reserves from proved undeveloped to non-proved due to the SEC’s five-year development rule and negative revisions of 2.7 MMBoe due to changes in price offset by revisions of 3.9 MMBoe related to changes in performance and other economic factors. |
For wells classified as proved developed producing where sufficient production history existed, reserves were based on individual well performance evaluation and production decline curve extrapolation techniques. For undeveloped locations and wells that lack sufficient production history, reserves were based on analogy to producing wells within the same area exhibiting similar geologic and reservoir characteristics. Well spacing was determined from drainage patterns derived from a combination of performance-based recoveries and analogous producing wells for each area or field.
F-45
EARTHSTONE ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
PUD locations were limited to areas of uniformly high-quality reservoir properties, between existing commercial producers where the reservoir can, with reasonable certainty, be judged to be continuous with existing producers and contain economically producible oil and natural gas on the basis of available geoscience and engineering data.
Changes in PUD reserves for the years ended December 31, 2022, 2021 and 2020 were as follows (in MBoe):
Proved undeveloped reserves at December 31, 2019 (1) |
62,815 | |||
Conversions to developed |
(8,200 | ) | ||
Extensions |
— | |||
Revision to previous estimates |
(14,038 | ) | ||
|
|
|||
Proved undeveloped reserves at December 31, 2020 (2) |
40,577 | |||
Conversions to developed |
(8,274 | ) | ||
Extensions |
20,521 | |||
Purchases of minerals in place |
11,577 | |||
Revision to previous estimates |
(10,389 | ) | ||
|
|
|||
Proved undeveloped reserves at December 31, 2021 (3) |
54,012 | |||
Conversions to developed |
(22,637 | ) | ||
Extensions |
16,499 | |||
Purchases of minerals in place |
57,432 | |||
Revision to previous estimates |
(2,091 | ) | ||
|
|
|||
Proved undeveloped reserves at December 31, 2022 (4) |
103,215 | |||
|
|
(1) | Includes 34,243 MBoe attributable to noncontrolling interests. |
(2) | Includes 21,737 MBoe attributable to noncontrolling interests. |
(3) | Includes 21,125 MBoe attributable to noncontrolling interests. |
(4) | Includes 25,293 MBoe attributable to noncontrolling interests. |
2022 Changes in Proved Undeveloped Reserves
Conversions to developed. In the Company’s year-end 2021 plan to develop its PUDs within five years, it was estimated that $190.2 million of capital would be expended in 2022 for the conversion of 45 gross / 31.8 net PUDs to add 24.5 MMBoe. In 2022, the Company spent $191.2 million to convert 42 gross / 26.6 net PUDs adding 22.6 MMBoe to developed.
Extensions. In 2022, extensions of 16.5 MMBoe were primarily the result of successful drilling results in the Delaware Basin and the Midland Basin.
Purchases of minerals in place. In 2022, the Company completed multiple acquisitions that resulted in 57.4 MMBoe of additional reserves, as disclosed in Note 4. Acquisitions and Divestitures.
Revision to previous estimates. Downward revisions of prior reserves of 2.1 MMBoe consisted of 2.4 MMBoe related to changes in performance and other economic factors, offset by a positive revision of 0.3 MMBoe related to changes in prices.
2021 Changes in Proved Undeveloped Reserves
Conversions to developed. In the Company’s year-end 2020 plan to develop its PUDs within five years, it was estimated that $41.1 million of capital would be expended in 2021 for the conversion of 13 gross / 10.5 net PUDs to add 6.7 MMBoe. In 2021, due to improved commodity prices, the Company spent $55.1 million to convert 16 gross / 13.1 net PUDs adding 8.3 MMBoe to developed.
Revision to previous estimates. Downward revisions of prior reserves of 10.4 MMBoe consisted of changes in anticipated well densities and changes in performance and other economic factors of 9.2 MMBoe and 2.9 MMBoe, respectively, offset by a positive revision of 1.7 MMBoe related to changes in prices.
2020 Changes in Proved Undeveloped Reserves
Conversions to developed. In the Company’s year-end 2019 plan to develop its PUDs within five years, the Company estimated that $111.1 million of capital would be expended in 2020 for the conversion of 28 gross / 17.6 net PUDs to add 11.3 MMBoe.
F-46
EARTHSTONE ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
In 2020, due to unforeseeable conditions previously described, the Company spent $67.8 million to convert 18 gross / 10.3 net PUDs adding 8.2 MMBoe to developed.
Revision to previous estimates. The Company maintains a five-year development plan, reviewed annually to ensure capital is allocated to the wells that have the highest risk-adjusted rates of return within the Company’s inventory of undrilled well locations. In response to lower commodity prices, the Company reduced the pace of activity in its five-year development plan. This resulted in the reclassification of 11.9 MMBoe of reserves from proved undeveloped to non-proved during the year ended December 31, 2020 due to the five-year development rule. Based on the Company’s then-current acreage position, strip prices, anticipated well economics, and its development plans at the time these reserves were classified as proved, the Company’s management believes the previous classification of these locations as proved undeveloped was appropriate. The remaining revisions of 2.1 MMBoe were primarily due to reduced commodity prices.
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Natural Gas Reserves
The following Standardized Measure of Discounted Future Net Cash Flows (Standardized Measure) has been developed utilizing FASB ASC Topic 932, Extractives Activities – Oil and Gas (“ASC 932”) procedures and based on oil and natural gas reserve and production volumes estimated by the Company’s third-party petroleum engineering firm. It can be used for some comparisons, but should not be the only method used to evaluate the Company or its performance. Further, the information in the following table may not represent realistic assessments of future cash flows, nor should the Standardized Measure be viewed as representative of the current value of the Company.
The Company believes that the following factors should be taken into account when reviewing the following information:
• | Future costs and commodity 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. |
At December 31, 2022, 2021 and 2020, 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, except for volumes subject to fixed price contracts. Prices used to estimate reserves are included in Oil and Natural Gas Reserves above. Future production costs include per-well overhead expenses allowed under joint operating agreements, abandonment costs (net of salvage value), and a non-cancellable fixed cost agreement to reserve pipeline capacity of 10,000 MMBtu per day for gathering and processing. Estimates of future income taxes are computed using current statutory 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.
The Standardized Measure at December 31, 2022, 2021 and 2020 is as follows (in thousands):
December 31, | ||||||||||||
2022 | 2021 | 2020 | ||||||||||
Future cash inflows |
$ | 21,506,026 | $ | 6,042,508 | $ | 1,902,073 | ||||||
Future production costs |
(6,362,901 | ) | (1,641,130 | ) | (633,248 | ) | ||||||
Future development costs |
(1,207,597 | ) | (470,008 | ) | (285,088 | ) | ||||||
Future income tax expense |
(1,910,370 | ) | (381,663 | ) | (35,557 | ) | ||||||
|
|
|
|
|
|
|||||||
Future net cash flows |
12,025,158 | 3,549,707 | 948,180 | |||||||||
10% annual discount for estimated timing of cash flows |
(5,300,657 | ) | (1,731,335 | ) | (487,327 | ) | ||||||
|
|
|
|
|
|
|||||||
Standardized measure of discounted future net cash flows (1) |
$ | 6,724,501 | $ | 1,818,372 | $ | 460,853 | ||||||
|
|
|
|
|
|
(1) | At December 31, 2022, 2021 and 2020, the portion of the standardized measure of discounted future net cash flows attributable to noncontrolling interests was $1.6 billion, $711.2 million and $246.9 million, respectively. |
F-47
EARTHSTONE ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
Changes in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Natural Gas Reserves
The following is a summary of the changes in the Standardized Measure for the Company’s proved oil and natural gas reserves during each of the years in the three-year period ended December 31, 2022 (in thousands):
December 31, | ||||||||||||
2022 | 2021 | 2020 | ||||||||||
Beginning of year |
$ | 1,818,372 | $ | 460,853 | $ | 789,577 | ||||||
Sales of oil and gas produced, net of production costs |
(1,341,586 | ) | (343,914 | ) | (105,555 | ) | ||||||
Sales of minerals in place |
(76,570 | ) | 14 | 14 | ||||||||
Net changes in prices and production costs |
3,838,439 | 1,346,851 | (381,769 | ) | ||||||||
Extensions and improved recoveries |
1,178,521 | 216,583 | 14,644 | |||||||||
Changes in income taxes, net |
(866,805 | ) | (185,757 | ) | 17,826 | |||||||
Previously estimated development costs incurred during the period |
246,705 | 41,120 | 66,788 | |||||||||
Net changes in future development costs |
(295,553 | ) | (104,223 | ) | 258,741 | |||||||
Purchases of minerals in place |
2,011,980 | 465,187 | — | |||||||||
Revisions of previous quantity estimates |
3,283 | (151,748 | ) | (273,781 | ) | |||||||
Accretion of discount |
345,642 | 76,121 | 81,999 | |||||||||
Changes in timing of estimated cash flows and other |
(137,927 | ) | (2,715 | ) | (7,631 | ) | ||||||
|
|
|
|
|
|
|||||||
End of year (1) |
$ | 6,724,501 | $ | 1,818,372 | $ | 460,853 | ||||||
|
|
|
|
|
|
(1) | At December 31, 2022, 2021 and 2020, the portion of the standardized measure of discounted future net cash flows attributable to noncontrolling interests was $1.6 billion, $711.2 million and $246.9 million, respectively. |
F-48
Exhibit 99.4
EARTHSTONE ENERGY, INC.
CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)
(In thousands, except share and per share amounts)
June 30, 2023 |
December 31, 2022 |
|||||||
ASSETS | ||||||||
Current assets: |
||||||||
Cash and cash equivalents |
$ | 49,500 | $ | — | ||||
Accounts receivable: |
||||||||
Oil, natural gas, and natural gas liquids revenues |
111,436 | 161,531 | ||||||
Joint interest billings and other, net of allowance of $19 and $19 at June 30, 2023 and December 31, 2022, respectively |
24,196 | 34,549 | ||||||
Derivative asset |
7,106 | 31,331 | ||||||
Prepaid expenses and other current assets |
19,658 | 18,854 | ||||||
|
|
|
|
|||||
Total current assets |
211,896 | 246,265 | ||||||
|
|
|
|
|||||
Oil and gas properties, successful efforts method: |
||||||||
Proved properties |
4,348,453 | 3,987,901 | ||||||
Unproved properties |
280,221 | 282,589 | ||||||
Land |
5,482 | 5,482 | ||||||
|
|
|
|
|||||
Total oil and gas properties |
4,634,156 | 4,275,972 | ||||||
|
|
|
|
|||||
Accumulated depreciation, depletion and amortization |
(832,886 | ) | (619,196 | ) | ||||
|
|
|
|
|||||
Net oil and gas properties |
3,801,270 | 3,656,776 | ||||||
|
|
|
|
|||||
Other noncurrent assets: |
||||||||
Office and other equipment, net of accumulated depreciation of $6,090 and $5,273 at June 30, 2023 and December 31, 2022, respectively |
6,056 | 5,394 | ||||||
Derivative asset |
2,284 | 9,117 | ||||||
Operating lease right-of-use assets |
6,573 | 4,569 | ||||||
Other noncurrent assets |
92,362 | 15,280 | ||||||
|
|
|
|
|||||
TOTAL ASSETS |
$ | 4,120,441 | $ | 3,937,401 | ||||
|
|
|
|
|||||
LIABILITIES AND EQUITY | ||||||||
Current liabilities: |
||||||||
Accounts payable |
$ | 53,824 | $ | 91,815 | ||||
Revenues and royalties payable |
166,380 | 163,368 | ||||||
Accrued expenses |
102,201 | 80,942 | ||||||
Asset retirement obligation |
860 | 948 | ||||||
Derivative liability |
31,702 | 14,053 | ||||||
Advances |
11,449 | 7,312 | ||||||
Operating lease liabilities |
906 | 842 | ||||||
Finance lease liabilities |
1,083 | 802 | ||||||
Other current liabilities |
14,335 | 16,202 | ||||||
|
|
|
|
|||||
Total current liabilities |
382,740 | 376,284 | ||||||
Noncurrent liabilities: |
||||||||
Long-term debt, net |
1,021,555 | 1,053,879 | ||||||
Deferred tax liability |
174,565 | 138,336 | ||||||
Asset retirement obligation |
29,695 | 29,611 | ||||||
Derivative liability |
10,624 | — | ||||||
Operating lease liabilities |
3,524 | 3,889 | ||||||
Finance lease liabilities |
1,151 | 876 | ||||||
Other noncurrent liabilities |
4,760 | 10,509 | ||||||
|
|
|
|
|||||
Total noncurrent liabilities |
1,245,874 | 1,237,100 | ||||||
|
|
|
|
|||||
Commitments and Contingencies (Note 13) |
||||||||
Equity: |
||||||||
Preferred stock, $0.001 par value, 20,000,000 shares authorized; none issued or outstanding |
— | — | ||||||
Class A Common Stock, $0.001 par value, 200,000,000 shares authorized; 106,331,055 and 105,547,139 issued and outstanding at June 30, 2023 and December 31, 2022, respectively |
106 | 106 | ||||||
Class B Common Stock, $0.001 par value, 50,000,000 shares authorized; 34,257,641 and 34,259,641 issued and outstanding at June 30, 2023 and December 31, 2022, respectively |
34 | 34 | ||||||
Additional paid-in capital |
1,345,657 | 1,346,463 | ||||||
Retained earnings |
411,301 | 292,711 | ||||||
|
|
|
|
|||||
Total Earthstone Energy, Inc. equity |
1,757,098 | 1,639,314 | ||||||
Noncontrolling interest |
734,729 | 684,703 | ||||||
|
|
|
|
|||||
Total equity |
2,491,827 | 2,324,017 | ||||||
|
|
|
|
|||||
TOTAL LIABILITIES AND EQUITY |
$ | 4,120,441 | $ | 3,937,401 | ||||
|
|
|
|
The accompanying notes are an integral part of these unaudited Condensed Consolidated Financial Statements.
1
EARTHSTONE ENERGY, INC.
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (UNAUDITED)
(In thousands, except share and per share amounts)
Three Months Ended | Six Months Ended | |||||||||||||||
June 30, | June 30, | |||||||||||||||
2023 | 2022 | 2023 | 2022 | |||||||||||||
REVENUES |
||||||||||||||||
Oil |
$ | 294,997 | $ | 286,632 | $ | 612,375 | $ | 424,384 | ||||||||
Natural gas |
20,649 | 96,125 | 50,667 | 119,083 | ||||||||||||
Natural gas liquids |
54,362 | 89,794 | 120,102 | 125,234 | ||||||||||||
|
|
|
|
|
|
|
|
|||||||||
Total revenues |
370,008 | 472,551 | 783,144 | 668,701 | ||||||||||||
|
|
|
|
|
|
|
|
|||||||||
OPERATING COSTS AND EXPENSES |
||||||||||||||||
Lease operating expense |
87,602 | 50,514 | 175,580 | 72,145 | ||||||||||||
Production and ad valorem taxes |
31,805 | 34,195 | 64,958 | 47,510 | ||||||||||||
Depreciation, depletion and amortization |
109,990 | 66,463 | 220,740 | 100,789 | ||||||||||||
Impairment expense |
854 | — | 854 | — | ||||||||||||
General and administrative expense |
19,992 | 14,077 | 37,571 | 26,383 | ||||||||||||
Transaction costs |
208 | (402 | ) | 401 | 10,340 | |||||||||||
Accretion of asset retirement obligation |
646 | 708 | 1,275 | 1,105 | ||||||||||||
Exploration expense |
6,082 | — | 6,548 | 92 | ||||||||||||
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|
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Total operating costs and expenses |
257,179 | 165,555 | 507,927 | 258,364 | ||||||||||||
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|
|
|||||||||
Gain on sale of oil and gas properties |
49,254 | — | 46,114 | — | ||||||||||||
Income from operations |
162,083 | 306,996 | 321,331 | 410,337 | ||||||||||||
OTHER INCOME (EXPENSE) |
||||||||||||||||
Interest expense, net |
(22,092 | ) | (16,625 | ) | (44,948 | ) | (21,943 | ) | ||||||||
Write-off of deferred financing costs |
— | — | (5,109 | ) | — | |||||||||||
Loss on derivative contracts, net |
(40,309 | ) | (49,907 | ) | (66,773 | ) | (201,387 | ) | ||||||||
Other income, net |
819 | 249 | 812 | 296 | ||||||||||||
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|
|
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|
|||||||||
Total other income (expense) |
(61,582 | ) | (66,283 | ) | (116,018 | ) | (223,034 | ) | ||||||||
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|||||||||
Income before income taxes |
100,501 | 240,713 | 205,313 | 187,303 | ||||||||||||
Income tax expense |
(18,053 | ) | (22,688 | ) | (36,654 | ) | (21,155 | ) | ||||||||
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Net income |
82,448 | 218,025 | 168,659 | 166,148 | ||||||||||||
Less: Net income attributable to noncontrolling interest |
24,406 | 73,140 | 50,069 | 54,741 | ||||||||||||
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Net income attributable to Earthstone Energy, Inc. |
$ | 58,042 | $ | 144,885 | $ | 118,590 | $ | 111,407 | ||||||||
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Net income per common share attributable to Earthstone Energy, Inc.: |
||||||||||||||||
Basic |
$ | 0.55 | $ | 1.85 | $ | 1.12 | $ | 1.57 | ||||||||
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Diluted |
$ | 0.54 | $ | 1.46 | $ | 1.10 | $ | 1.37 | ||||||||
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Weighted average common shares outstanding: |
||||||||||||||||
Basic |
106,209,657 | 78,291,037 | 106,091,850 | 70,909,353 | ||||||||||||
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Diluted |
107,336,695 | 102,410,036 | 107,438,062 | 84,266,422 | ||||||||||||
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The accompanying notes are an integral part of these unaudited Condensed Consolidated Financial Statements.
2
EARTHSTONE ENERGY, INC.
CONDENSED CONSOLIDATED STATEMENTS OF EQUITY (UNAUDITED)
(In thousands, except share amounts)
Issued Shares | ||||||||||||||||||||||||||||||||||||||||||||
Series A Convertible Preferred Stock |
Class A Common Stock |
Class B Common Stock |
Series A Convertible Preferred Stock |
Class A Common Stock |
Class B Common Stock |
Additional Paid-in Capital |
Retained Earnings |
Total Earthstone Energy, Inc. Equity |
Noncontrolling Interest |
Total Equity | ||||||||||||||||||||||||||||||||||
At December 31, 2022 |
— | 105,547,139 | 34,259,641 | $ | — | $ | 106 | $ | 34 | $ | 1,346,463 | $ | 292,711 | $ | 1,639,314 | $ | 684,703 | $ | 2,324,017 | |||||||||||||||||||||||||
Stock-based compensation expense |
— | — | — | — | — | — | 3,844 | — | 3,844 | — | 3,844 | |||||||||||||||||||||||||||||||||
Vesting of restricted stock units, net of taxes paid |
— | 756,429 | — | — | — | — | — | — | — | — | — | |||||||||||||||||||||||||||||||||
Class A Shares retained by the Company in exchange for payment of recipient mandatory tax withholdings |
— | 460,473 | — | — | — | — | (6,342 | ) | — | (6,342 | ) | — | (6,342 | ) | ||||||||||||||||||||||||||||||
Cancellation of Treasury shares |
— | (460,473 | ) | — | — | — | — | — | — | — | — | — | ||||||||||||||||||||||||||||||||
Net income |
— | — | — | — | — | — | — | 60,548 | 60,548 | 25,663 | 86,211 | |||||||||||||||||||||||||||||||||
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At March 31, 2023 |
— | 106,303,568 | 34,259,641 | — | $ | 106 | $ | 34 | $ | 1,343,965 | $ | 353,259 | $ | 1,697,364 | 710,366 | $ | 2,407,730 | |||||||||||||||||||||||||||
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Stock-based compensation expense |
— | — | — | — | — | — | 3,937 | — | 3,937 | — | 3,937 | |||||||||||||||||||||||||||||||||
Vesting of restricted stock units, net of taxes paid |
— | 131,381 | — | — | — | — | — | — | — | — | — | |||||||||||||||||||||||||||||||||
Class A Shares retained by the Company in exchange for payment of recipient mandatory tax withholdings |
— | 56,683 | — | — | — | — | (799 | ) | — | (799 | ) | — | (799 | ) | ||||||||||||||||||||||||||||||
Cancellation of Treasury shares |
— | (56,683 | ) | — | — | — | — | — | — | — | — | — | ||||||||||||||||||||||||||||||||
Class B Common Stock converted to Class A Common Stock |
— | 2,000 | (2,000 | ) | — | — | — | 43 | — | 43 | (43 | ) | — | |||||||||||||||||||||||||||||||
Settlement of Chisholm escrow shares |
— | (105,894 | ) | — | — | — | — | (1,489 | ) | — | (1,489 | ) | — | (1,489 | ) | |||||||||||||||||||||||||||||
Net income |
— | — | — | — | — | — | — | 58,042 | 58,042 | 24,406 | 82,448 | |||||||||||||||||||||||||||||||||
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At June 30, 2023 |
— | 106,331,055 | 34,257,641 | — | $ | 106 | $ | 34 | $ | 1,345,657 | $ | 411,301 | $ | 1,757,098 | 734,729 | $ | 2,491,827 | |||||||||||||||||||||||||||
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3
Issued Shares | ||||||||||||||||||||||||||||||||||||||||||||
Series A Convertible Preferred Stock |
Class A Common Stock |
Class B Common Stock |
Series A Convertible Preferred Stock |
Class A Common Stock |
Class B Common Stock |
Additional Paid-in Capital |
(Accumulated Deficit) |
Total Earthstone Energy, Inc. Equity |
Noncontrolling Interest |
Total Equity | ||||||||||||||||||||||||||||||||||
At December 31, 2021 |
— | 53,467,307 | 34,344,532 | $ | — | $ | 53 | $ | 34 | $ | 718,181 | $ | (159,774 | ) | $ | 558,494 | $ | 487,767 | $ | 1,046,261 | ||||||||||||||||||||||||
Stock-based compensation expense - equity portion |
— | — | — | — | — | — | 2,301 | — | 2,301 | — | 2,301 | |||||||||||||||||||||||||||||||||
Shares issued in connection with Chisholm Acquisition |
— | 19,417,476 | — | — | 19 | — | 249,496 | — | 249,515 | — | 249,515 | |||||||||||||||||||||||||||||||||
Vesting of restricted stock units, net of taxes paid |
— | 483,251 | — | — | 1 | — | (1 | ) | — | — | — | — | ||||||||||||||||||||||||||||||||
Class A Shares retained by the Company in exchange for payment of recipient mandatory tax withholdings |
— | 286,892 | — | — | — | — | (3,898 | ) | — | (3,898 | ) | — | (3,898 | ) | ||||||||||||||||||||||||||||||
Cancellation of Treasury shares |
— | (286,892 | ) | — | — | — | — | — | — | — | — | — | ||||||||||||||||||||||||||||||||
Class B Common Stock converted to Class A Common Stock |
— | 72,766 | (72,766 | ) | — | — | — | 1,014 | — | 1,014 | (1,014 | ) | — | |||||||||||||||||||||||||||||||
Net loss |
— | — | — | — | — | — | — | (33,478 | ) | (33,478 | ) | (18,399 | ) | (51,877 | ) | |||||||||||||||||||||||||||||
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At March 31, 2022 |
— | 73,440,800 | 34,271,766 | — | $ | 73 | $ | 34 | $ | 967,093 | $ | (193,252 | ) | $ | 773,948 | $ | 468,354 | $ | 1,242,302 | |||||||||||||||||||||||||
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Stock-based compensation expense - equity portion |
— | — | — | — | — | — | 2,693 | — | 2,693 | — | 2,693 | |||||||||||||||||||||||||||||||||
Issuance of Series A Convertible Preferred Stock, net of offering costs of $674 |
280,000 | — | — | — | — | — | 279,326 | — | 279,326 | — | 279,326 | |||||||||||||||||||||||||||||||||
Shares issued in connection with Bighorn Acquisition |
— | 5,650,977 | — | — | 6 | — | 77,751 | — | 77,757 | — | 77,757 | |||||||||||||||||||||||||||||||||
Vesting of restricted stock units, net of taxes paid |
— | 115,521 | — | — | — | — | — | — | — | — | — | |||||||||||||||||||||||||||||||||
Class A Shares retained by the Company in exchange for payment of recipient mandatory tax withholdings |
— | 48,232 | — | — | — | — | (719 | ) | — | (719 | ) | — | (719 | ) | ||||||||||||||||||||||||||||||
Cancellation of Treasury shares |
— | (48,232 | ) | — | — | — | — | — | — | — | — | — | ||||||||||||||||||||||||||||||||
Class B Common Stock converted to Class A Common Stock |
— | 10,125 | (10,125 | ) | — | — | — | 149 | — | 149 | (149 | ) | — | |||||||||||||||||||||||||||||||
Net income |
— | — | — | — | — | — | — | 144,885 | 144,885 | 73,140 | 218,025 | |||||||||||||||||||||||||||||||||
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At June 30, 2022 |
280,000 | 79,217,423 | 34,261,641 | — | $ | 79 | $ | 34 | $ | 1,326,293 | $ | (48,367 | ) | $ | 1,278,039 | $ | 541,345 | $ | 1,819,384 | |||||||||||||||||||||||||
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The accompanying notes are an integral part of these unaudited Condensed Consolidated Financial Statements.
4
EARTHSTONE ENERGY, INC.
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)
(In thousands)
For the Six Months Ended June 30, |
||||||||
2023 | 2022 | |||||||
Cash flows from operating activities: |
||||||||
Net income |
$ | 168,659 | $ | 166,148 | ||||
Adjustments to reconcile net income to net cash provided by operating activities: |
||||||||
Depreciation, depletion and amortization |
220,740 | 100,789 | ||||||
Impairment of oil and gas properties |
854 | — | ||||||
Accretion of asset retirement obligations |
1,275 | 1,105 | ||||||
Settlement of asset retirement obligations |
(1,036 | ) | (475 | ) | ||||
Gain on sale of oil and gas properties |
(46,114 | ) | — | |||||
Gain on sale of office and other equipment |
(33 | ) | (46 | ) | ||||
Total loss on derivative contracts, net |
66,773 | 201,387 | ||||||
Operating portion of net cash paid in settlement of derivative contracts |
(7,443 | ) | (110,785 | ) | ||||
Stock-based compensation - equity and liability awards |
12,453 | 11,790 | ||||||
Deferred income taxes |
36,229 | 20,546 | ||||||
Write-off of deferred financing costs |
5,109 | — | ||||||
Amortization of deferred financing costs |
3,459 | 2,069 | ||||||
Changes in assets and liabilities: |
||||||||
(Increase) decrease in accounts receivable |
63,303 | (184,315 | ) | |||||
(Increase) decrease in prepaid expenses and other current assets |
(834 | ) | (11,103 | ) | ||||
Increase (decrease) in accounts payable and accrued expenses |
(62,031 | ) | 64,658 | |||||
Increase (decrease) in revenues and royalties payable |
11,267 | 85,570 | ||||||
Increase (decrease) in advances |
4,137 | (9,661 | ) | |||||
|
|
|
|
|||||
Net cash provided by operating activities |
476,767 | 337,677 | ||||||
|
|
|
|
|||||
Cash flows from investing activities: |
||||||||
Acquisition of oil and gas properties, net of cash acquired |
(76,078 | ) | (1,035,289 | ) | ||||
Additions to oil and gas properties |
(357,186 | ) | (180,381 | ) | ||||
Additions to office and other equipment |
(482 | ) | (1,356 | ) | ||||
Proceeds from sales of oil and gas properties |
56,062 | — | ||||||
|
|
|
|
|||||
Net cash used in investing activities |
(377,684 | ) | (1,217,026 | ) | ||||
|
|
|
|
|||||
Cash flows from financing activities: |
||||||||
Proceeds from borrowings under Credit Agreement |
1,890,487 | 1,471,572 | ||||||
Repayments of borrowings under Credit Agreement |
(2,160,624 | ) | (1,396,572 | ) | ||||
Proceeds from issuance of 8.000% Senior Notes due 2027, net |
— | 537,250 | ||||||
Proceeds from issuance of 9.875% Senior Notes due 2031, net |
481,215 | — | ||||||
Repayment of term loan |
(250,000 | ) | — | |||||
Proceeds from issuance of Series A Convertible Preferred Stock, net of offering costs of $674 |
— | 279,326 | ||||||
Cash paid related to the exchange and cancellation of Class A Common Stock |
(7,141 | ) | (4,617 | ) | ||||
Cash paid for finance leases |
(441 | ) | — | |||||
Deferred financing costs |
(3,079 | ) | (11,623 | ) | ||||
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|
|
|
|||||
Net cash (used in) provided by financing activities |
(49,583 | ) | 875,336 | |||||
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|
|||||
Net increase (decrease) in cash and cash equivalents |
49,500 | (4,013 | ) | |||||
Cash and cash equivalents at beginning of period |
— | 4,013 | ||||||
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|
|||||
Cash and cash equivalents at end of period |
$ | 49,500 | $ | — | ||||
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The accompanying notes are an integral part of these unaudited Condensed Consolidated Financial Statements.
5
EARTHSTONE ENERGY, INC.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Note 1. Basis of Presentation and Summary of Significant Accounting Policies
Earthstone Energy, Inc., a Delaware corporation (“Earthstone” and together with its consolidated subsidiaries, the “Company”), is a growth-oriented independent oil and natural gas development and production company. In addition, the Company is active in corporate mergers and the acquisition of oil and natural gas properties that have production and future development opportunities. The Company’s operations are all in the upstream segment of the oil and natural gas industry and all its properties are onshore in Texas and New Mexico.
Earthstone is the sole managing member of Earthstone Energy Holdings, LLC, a Delaware limited liability company (together with its wholly-owned consolidated subsidiaries, “EEH”), with a controlling interest in EEH. Earthstone, together with its wholly-owned subsidiary, Lynden Energy Corp., a corporation organized under the laws of British Columbia (“Lynden Corp”), and Lynden Corp’s wholly-owned consolidated subsidiary, Lynden USA Inc., a Utah corporation (“Lynden US”), collectively own a 75.6% interest in EEH. The Company consolidates the financial results of EEH and presents a noncontrolling interest in the Condensed Consolidated Financial Statements representing the economic interests of EEH’s members other than Earthstone and Lynden US. Each of the outstanding shares of Class A common stock, $0.001 par value per share of Earthstone (the “Class A Common Stock”), has a corresponding unit of limited liability company interests denominated as a common unit in EEH (an “EEH Unit”). Each of the outstanding shares of Class B common stock, $0.001 par value per share of Earthstone (the “Class B Common Stock” and with the Class A Common Stock, “Common Stock”), has a corresponding EEH Unit and collectively represent the noncontrolling interests in the Condensed Consolidated Financial Statements.
At any time, at the holder’s discretion, a holder of an EEH Unit and a share of Class B Common Stock may receive a share of Class A Common Stock in exchange for an EEH Unit and a corresponding share of Class B Common Stock, resulting in the immediate cancellation of both the EEH Unit and share of Class B Common Stock exchanged. As of June 30, 2023, outstanding common shares of Earthstone, along with the equal number of corresponding outstanding EEH Units, were approximately 140.6 million, consisting of 106.3 million shares of Class A Common Stock and 34.3 million shares of Class B Common Stock.
The accompanying unaudited Condensed Consolidated Financial Statements and notes thereto have been prepared in accordance with the rules and regulations of the Securities and Exchange Commission (“SEC”) applicable to interim financial statements. Pursuant to such rules and regulations, certain disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”) have been omitted. The accompanying unaudited Condensed Consolidated Financial Statements and notes should be read in conjunction with the financial statements and notes included in Earthstone’s 2022 Annual Report on Form 10-K.
The information furnished herein reflects all adjustments that are, in the opinion of management, necessary for the fair presentation of the Company’s financial position, results of operations and cash flows for the periods presented. Any such adjustments are of a normal, recurring nature. The Company’s Condensed Consolidated Balance Sheet as of December 31, 2022 is derived from the audited Consolidated Financial Statements at that date.
For the purposes of these Condensed Consolidated Financial Statements, short-term investments, which have an original maturity of three months or less, are considered cash equivalents.
Note 2. Noncontrolling Interest
Earthstone consolidates the financial results of EEH and its subsidiaries and records a noncontrolling interest for the economic interest in Earthstone held by the members of EEH other than Earthstone and Lynden US. Net income attributable to noncontrolling interest in the Condensed Consolidated Statements of Operations for the three and six months ended June 30, 2023 and 2022 represents the portion of net income attributable to the economic interest in the Company held by the members of EEH other than Earthstone and Lynden US. Noncontrolling interest in the Condensed Consolidated Balance Sheets as of June 30, 2023 and December 31, 2022 represents the portion of net assets of the Company attributable to the members of EEH other than Earthstone and Lynden US.
6
EARTHSTONE ENERGY, INC.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (continued)
The following table presents the changes in noncontrolling interest for the six months ended June 30, 2023:
EEH Units Held By Earthstone and Lynden US |
% | EEH Units Held By Others |
% | Total EEH Units Outstanding |
||||||||||||||||
As of December 31, 2022 |
105,547,139 | 75.5 | % | 34,259,641 | 24.5 | % | 139,806,780 | |||||||||||||
EEH Units exchanged for shares of Class A Common Stock |
2,000 | (2,000 | ) | — | ||||||||||||||||
EEH Units cancelled in connection with the settlement of Chisholm escrow shares |
(105,894 | ) | — | (105,894 | ) | |||||||||||||||
EEH Units issued in connection with the vesting of restricted stock units and performance units |
887,810 | — | 887,810 | |||||||||||||||||
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|||||||||||
As of June 30, 2023 |
106,331,055 | 75.6 | % | 34,257,641 | 24.4 | % | 140,588,696 | |||||||||||||
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Note 3. Fair Value Measurements
The Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) Topic 820, defines fair value as the price that would be received to sell an asset, or paid to transfer a liability, in an orderly transaction between market participants at the measurement date. FASB ASC Topic 820 provides a framework for measuring fair value, establishes a three-level hierarchy for fair value measurements based upon the transparency of inputs to the valuation of an asset or liability as of the measurement date and requires consideration of the counterparty’s creditworthiness when valuing certain assets.
The three-level fair value hierarchy for disclosure of fair value measurements defined by FASB ASC Topic 820 is as follows:
Level 1 – Unadjusted, quoted prices in active markets that are accessible at the measurement date for identical, unrestricted assets or liabilities. An active market is defined as a market where transactions for the financial instrument occur with sufficient frequency and volume to provide pricing information on an ongoing basis.
Level 2 – Inputs, other than quoted prices within Level 1, that are either directly or indirectly observable for the asset or liability through correlation with market data at the measurement date and for the duration of the instrument’s anticipated life.
Level 3 – Prices or valuations that require unobservable inputs that are both significant to the fair value measurement and unobservable. Valuation under Level 3 generally involves a significant degree of judgment from management.
A financial instrument’s level within the fair value hierarchy is based on the lowest level of any input that is significant to the fair value measurement. Where available, fair value is based on observable market prices or parameters or derived from such prices or parameters. Where observable prices or inputs are not available, valuation models are applied. These valuation techniques involve some level of management estimation and judgment, the degree of which is dependent on the price transparency for the instruments or market and the instrument’s complexity. The Company reflects transfers between the three levels at the beginning of the reporting period in which the availability of observable inputs no longer justifies classification in the original level. There were no transfers between fair value hierarchy levels for the six months ended June 30, 2023.
Fair Value on a Recurring Basis
Derivative Financial Instruments
Derivative financial instruments are carried at fair value and measured on a recurring basis. The derivative financial instruments consist of fixed price swaps, basis swaps, costless collars and deferred premium put options. The Company’s commodity price hedges are valued based on discounted future cash flow models that are primarily based on published forward commodity price curves; thus, these inputs are designated as Level 2 within the valuation hierarchy.
The fair values of derivative instruments in asset positions include measures of counterparty nonperformance risk, and the fair values of derivative instruments in liability positions include measures of the Company’s nonperformance risk. These measurements were not material to the Condensed Consolidated Financial Statements.
7
EARTHSTONE ENERGY, INC.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (continued)
Share-based Compensation Liability
Certain of our performance-based stock awards (“PSUs”) and performance-based restricted stock units (“PRSUs” and collectively with the PSUs, “performance units”) may be payable in cash. The Company classifies the awards that may be settled in cash as liability awards. These awards are valued quarterly utilizing the Monte Carlo Simulation pricing model, which calculates multiple potential outcomes for an award and establishes grant date fair value based on the most likely outcome. The inputs for the Monte Carlo model are designated as Level 2 within the valuation hierarchy. The share-based compensation liability related to the performance unit liability awards is included in Other noncurrent liabilities in the Condensed Consolidated Balance Sheet as of June 30, 2023.
The following table summarizes the fair value of the Company’s financial assets and liabilities, by level within the fair-value hierarchy (in thousands):
Level 1 | Level 2 | Level 3 | Total | |||||||||||||
June 30, 2023 |
||||||||||||||||
Financial assets |
||||||||||||||||
Derivative asset - current |
$ | — | $ | 7,106 | $ | — | $ | 7,106 | ||||||||
Derivative asset - noncurrent |
— | 2,284 | — | 2,284 | ||||||||||||
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Total financial assets |
$ | — | $ | 9,390 | $ | — | $ | 9,390 | ||||||||
|
|
|
|
|
|
|
|
|||||||||
Financial liabilities |
||||||||||||||||
Derivative liability - current |
$ | — | $ | 31,702 | $ | — | $ | 31,702 | ||||||||
Derivative liability - noncurrent |
— | 10,624 | — | 10,624 | ||||||||||||
Share-based compensation liability - current |
— | 12,722 | — | 12,722 | ||||||||||||
Share-based compensation liability - noncurrent |
— | 2,179 | — | 2,179 | ||||||||||||
|
|
|
|
|
|
|
|
|||||||||
Total financial liabilities |
$ | — | $ | 57,227 | $ | — | $ | 57,227 | ||||||||
|
|
|
|
|
|
|
|
|||||||||
December 31, 2022 |
||||||||||||||||
Financial assets |
||||||||||||||||
Derivative asset - current |
$ | — | $ | 31,331 | $ | — | $ | 31,331 | ||||||||
Derivative asset - noncurrent |
— | 9,117 | — | 9,117 | ||||||||||||
|
|
|
|
|
|
|
|
|||||||||
Total financial assets |
$ | — | $ | 40,448 | $ | — | $ | 40,448 | ||||||||
|
|
|
|
|
|
|
|
|||||||||
Financial liabilities |
||||||||||||||||
Derivative liability - current |
$ | — | $ | 14,053 | $ | — | $ | 14,053 | ||||||||
Share-based compensation liability - current |
— | 14,411 | — | 14,411 | ||||||||||||
Share-based compensation liability - noncurrent |
— | 10,357 | — | 10,357 | ||||||||||||
|
|
|
|
|
|
|
|
|||||||||
Total financial liabilities |
$ | — | $ | 38,821 | $ | — | $ | 38,821 | ||||||||
|
|
|
|
|
|
|
|
Other financial instruments include cash, accounts receivable and payable, and revenue royalties. The carrying amount of these instruments approximates fair value because of their short-term nature. The Company’s revolving credit facility obligation bears interest at floating market rates, therefore carrying amounts and fair value of any outstanding amounts would be approximately equal. The 2027 Notes and 2031 Notes bear interest at fixed rates.
Fair Value on a Nonrecurring Basis
The Company applies the provisions of the fair value measurement standard on a non-recurring basis to its non-financial assets and liabilities, including oil and gas properties, business combinations and asset retirement obligations. These assets and liabilities are not measured at fair value on an ongoing basis but are subject to fair value adjustments if events or changes in certain circumstances indicate that adjustments may be necessary. No triggering events that require assessment were observed during the six months ended June 30, 2023. See further discussion in Note 6. Oil and Natural Gas Properties.
Items Not Recorded at Fair Value
The carrying amounts reported on the unaudited consolidated balance sheets for cash, accounts receivable, prepaid expenses, other current assets accounts payable, revenues and royalties payable, accrued expenses and other current liabilities approximate their fair values.
8
EARTHSTONE ENERGY, INC.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (continued)
The Company has not elected to account for its debt instruments at fair value. Borrowings under the revolving tranche and term loan tranche of the Company’s credit facility bear interest at floating market rates, therefore the carrying amounts and fair values were approximately equal as of June 30, 2023 and December 31, 2022. The carrying value of the 2027 Notes, net of $9.7 million of deferred financing costs, of $540.3 million and accrued interest of $9.3 million had an estimated fair value of $530.9 million as of June 30, 2023. The carrying value of the 2031 Notes, net of the $10.2 million original issue discount and $8.6 million of deferred financing costs, of $481.2 million and accrued interest of $0.1 million had an estimated fair value of $494.7 million as of June 30, 2023. There were no other debt instruments outstanding at June 30, 2023.
Note 4. Derivative Financial Instruments
Commodity Derivative Instruments
The Company’s hedging activities primarily consist of derivative instruments entered into in order to hedge against changes in oil and natural gas prices through the use of fixed price swap agreements, costless collars and deferred premium put options. Swaps exchange floating price risk in the future for a fixed price at the time of the hedge. Costless collars set both a maximum (sold ceiling) and a minimum (bought floor) future price. A deferred premium put option represents a bought floor except, unlike a standard put option, the premium is not paid until the expiration of the option. Consistent with its hedging policy, the Company has entered into a series of derivative instruments to hedge a portion of its expected oil and natural gas production through December 31, 2024 and maintains certain natural gas basis swaps through December 31, 2025. Typically, these derivative instruments require payments to (receipts from) counterparties based on specific indices as required by the derivative agreements. Although not risk free, the Company believes these instruments reduce its exposure to oil and natural gas price fluctuations and, thereby, allow the Company to achieve a more predictable cash flow. The Company does not enter into derivative instruments for trading or other speculative purposes.
The Company’s derivative instruments are cash flow hedge transactions in which it is hedging the variability of cash flow related to a forecasted transaction. These transactions are recorded in the Condensed Consolidated Financial Statements in accordance with FASB ASC Topic 815. The Company has accounted for these transactions using the mark-to-market accounting method. Generally, the Company incurs accounting losses on derivatives during periods where prices are rising and gains during periods where prices are falling which may cause significant fluctuations in the Condensed Consolidated Balance Sheets and Condensed Consolidated Statements of Operations.
The Company nets its derivative instrument fair value amounts executed with each counterparty pursuant to an International Swap Dealers Association Master Agreement (“ISDA”), which provides for net settlement over the term of the contract. The ISDA is a standard contract that governs all derivative contracts entered into between the Company and the respective counterparty. The ISDA allows for offsetting of amounts payable or receivable between the Company and the counterparty, at the election of both parties, for transactions that occur on the same date and in the same currency.
The following table sets forth the Company’s open crude oil and natural gas derivative contracts as of June 30, 2023. When aggregating multiple contracts, the weighted average contract price is disclosed.
Price Swaps |
||||||||||
Period |
Commodity |
Volume (Bbls / MMBtu) |
Weighted Average Price ($/Bbl / $/MMBtu) |
|||||||
Q3 - Q4 2023 |
Crude Oil | 1,145,200 | $ | 74.90 | ||||||
Q1 - Q4 2024 |
Crude Oil | 621,600 | $ | 69.28 | ||||||
Q3 - Q4 2023 |
Crude Oil Basis Swap (1) | 4,692,000 | $ | 0.92 | ||||||
Q3 - Q4 2023 |
Natural Gas | 2,300,000 | $ | 3.35 | ||||||
Q3 - Q4 2023 |
Natural Gas Basis Swap (2) | 25,760,000 | $ | (1.67 | ) | |||||
Q1 - Q4 2024 |
Natural Gas Basis Swap (2) | 36,600,000 | $ | (1.05 | ) | |||||
Q1 - Q4 2025 |
Natural Gas Basis Swap (2) | 14,600,000 | $ | (0.74 | ) |
(1) | The basis differential price is between WTI Midland Crude and the WTI NYMEX. |
(2) | The basis differential price is between W. Texas (WAHA) and the Henry Hub NYMEX. |
9
EARTHSTONE ENERGY, INC.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (continued)
Costless Collars |
||||||||||||||
Period |
Commodity |
Volume (Bbls / MMBtu) |
Bought Floor ($/Bbl / $/MMBtu) |
Sold Ceiling ($/Bbl / $/MMBtu) |
||||||||||
Q3 - Q4 2023 |
Crude Oil Costless Collar | 2,120,800 | $ | 62.73 | $ | 85.26 | ||||||||
Q1 - Q4 2024 |
Crude Oil Costless Collar | 732,000 | $ | 60.00 | $ | 76.01 | ||||||||
Q3 - Q4 2023 |
Natural Gas Costless Collar | 13,298,800 | $ | 3.12 | $ | 5.21 | ||||||||
Q1 - Q4 2024 |
Natural Gas Costless Collar | 14,640,000 | $ | 2.56 | $ | 4.51 |
Deferred Premium Puts |
||||||||||||||
Period |
Commodity |
Volume (Bbls / MMBtu) |
$/Bbl (Put Price) | $/Bbl (Net of Premium) | ||||||||||
Q3 - Q4 2023 |
Crude Oil | 791,200 | $ | 70.00 | $ | 64.54 | ||||||||
Q1 - Q4 2024 |
Crude Oil | 915,000 | $ | 65.00 | $ | 60.04 |
The following table summarizes the location and fair value amounts of all derivative instruments in the Condensed Consolidated Balance Sheets as well as the gross recognized derivative assets, liabilities, and amounts offset in the Condensed Consolidated Balance Sheets (in thousands):
June 30, 2023 | December 31, 2022 | |||||||||||||||||||||||||
Derivatives not |
Balance Sheet Location | Gross Recognized Assets / Liabilities |
Gross Amounts Offset |
Net Recognized Assets / Liabilities |
Gross Recognized Assets / Liabilities |
Gross Amounts Offset |
Net Recognized Assets / Liabilities |
|||||||||||||||||||
Commodity contracts |
Derivative asset - current |
$ | 20,420 | $ | (13,314 | ) | $ | 7,106 | $ | 51,803 | $ | (20,472 | ) | $ | 31,331 | |||||||||||
Commodity contracts |
Derivative liability - current |
$ | 45,016 | $ | (13,314 | ) | $ | 31,702 | $ | 34,525 | $ | (20,472 | ) | $ | 14,053 | |||||||||||
Commodity contracts |
Derivative asset - noncurrent |
$ | 3,516 | $ | (1,232 | ) | $ | 2,284 | $ | 9,117 | $ | — | $ | 9,117 | ||||||||||||
Commodity contracts |
Derivative liability - noncurrent |
$ | 11,856 | $ | (1,232 | ) | $ | 10,624 | $ | — | $ | — | $ | — |
The following table summarizes the location and amounts of the Company’s realized and unrealized gains and losses on derivatives instruments in the Condensed Consolidated Statements of Operations and Condensed Consolidated Statements of Cash Flows (in thousands):
Derivatives not designated as hedging contracts under ASC Topic 815 |
Three Months Ended June 30, |
Six Months Ended June 30, |
||||||||||||||||||
Statement of Cash Flows Location |
Statement of Operations Location |
2023 | 2022 | 2023 | 2022 | |||||||||||||||
Unrealized (loss) gain |
Not separately presented |
Not separately presented |
$ | (39,891 | ) | $ | 29,192 | $ | (59,330 | ) | $ | (90,602 | ) | |||||||
Realized loss |
Operating portion of net cash paid in settlement of derivative contracts |
Not separately presented |
(418 | ) | (79,099 | ) | (7,443 | ) | (110,785 | ) | ||||||||||
|
|
|
|
|
|
|
|
|||||||||||||
Total loss on derivative contracts, net |
Loss on derivative contracts, net |
$ | (40,309 | ) | $ | (49,907 | ) | $ | (66,773 | ) | $ | (201,387 | ) | |||||||
|
|
|
|
|
|
|
|
Note 5. Acquisitions and Divestitures
Novo Acquisition
On June 14, 2023, EEH entered into (i) a Securities Purchase Agreement (the “Novo Purchase Agreement”) with Novo Oil & Gas Legacy Holdings, LLC (“Holdings”), Novo Intermediate, LLC (“Intermediate,” and together with Holdings, collectively, the “Sellers”) and Novo Oil & Gas Holdings, LLC (“Novo”), pursuant to which EEH will acquire 100% of the issued and outstanding equity interests (the “Subject Securities”) of Novo (the “Novo Acquisition”); and (ii) an Acquisition and Cooperation Agreement (the “Cooperation Agreement”) with Northern Oil and Gas, Inc. (“NOG”), pursuant to which NOG has agreed to acquire, immediately after the closing of the Novo Acquisition, an undivided 1/3 interest in Novo’s oil and natural gas properties and related assets (the “Novo Assets”) acquired pursuant to the Novo Purchase Agreement (the “Novo Divestiture” and, together with the Novo Acquisition, the “Novo Transactions”). A Significant Shareholder is the majority owner of the Sellers.
10
EARTHSTONE ENERGY, INC.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (continued)
Under the terms and conditions of the Novo Purchase Agreement, which has an economic effective date of May 1, 2023, the aggregate consideration to be paid to the Sellers in the Novo Acquisition will consist of $1.5 billion in cash (the “Novo Consideration”), subject to customary purchase price adjustments. Pursuant to the Novo Purchase Agreement, on the execution date thereof, EEH (together with NOG) deposited approximately $112.5 million (the “Acquisition Deposit”) into escrow, which will be credited toward the Novo Consideration payable at the closing of the Novo Acquisition. EEH’s portion of the deposit was $75 million which is included in Other noncurrent assets in the Condensed Consolidated Balance Sheets (Unaudited) as of June 30, 2023.
Immediately after the consummation of the Novo Acquisition, pursuant to the Cooperation Agreement, EEH has agreed to transfer to NOG an undivided 1/3 interest in the Novo Assets acquired pursuant to the Novo Purchase Agreement in exchange for consideration of approximately $500.0 million in cash, subject to certain customary purchase price adjustments. As a result, assuming an undivided 1/3 interest in the Novo Assets are transferred at the closing of the Cooperation Agreement, the Company will have acquired Novo, and retained ownership of an undivided 2/3 interest in the Novo Assets, for an unadjusted aggregate purchase price of approximately $1.0 billion in cash.
The Sellers and Purchaser have made customary representations and warranties in the Novo Purchase Agreement. The Novo Purchase Agreement also contains customary covenants and agreements, including, among others, covenants and agreements relating to (a) the conduct of Novo’s businesses during the period between the execution of the Novo Purchase Agreement and closing of the Novo Acquisition and (b) the efforts of the parties to cause the Novo Acquisition to be completed, including obtaining any required governmental approval and causing any applicable waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976 to expire or terminate.
Titus Acquisition
On June 27, 2022, Earthstone and EEH, as buyer, and Titus Oil & Gas Production, LLC, a Delaware limited liability company, Titus Oil & Gas Corporation, a Delaware corporation, Lenox Minerals, LLC, a Delaware limited liability company and Lenox Mineral Title Holdings, Inc., a Delaware corporation (collectively, “Titus I”), as seller, entered into a purchase and sale agreement (the “Titus I Purchase Agreement”) which provided that EEH or its designated wholly-owned subsidiary would acquire (the “Titus I Acquisition”) interests in oil and gas leases and related property of Titus I located in the Northern Delaware Basin of New Mexico (the “Titus I Assets”). Also on June 27, 2022, Earthstone and EEH, as buyer, and Titus Oil & Gas Production II, LLC, a Delaware limited liability company, Lenox Minerals II, LLC, a Delaware limited liability company and Lenox Mineral Holdings II, Inc., a Delaware limited liability company (collectively, “Titus II” and together with Titus I, “Titus”), as seller, entered into a purchase and sale agreement (the “Titus II Purchase Agreement” and together with the Titus I Purchase Agreement, the “Titus Purchase Agreements”) which provided that EEH or its designated wholly-owned subsidiary would acquire (the “Titus II Acquisition” and together with the Titus I Acquisition, the “Titus Acquisition”) interests in oil and gas leases and related property of Titus II located in the Northern Delaware Basin of New Mexico (the “Titus II Assets” and together with the Titus I Assets, the “Titus Assets”).
On August 10, 2022, the transactions contemplated in the Titus Purchase Agreements were consummated whereby EEH acquired the Titus Assets for aggregate consideration of approximately $568.5 million in cash, net of customary purchase price adjustments, and 3,857,015 shares of Class A Common Stock.
The Titus Acquisition was accounted for as an asset acquisition. The consideration paid by the Company and allocation of that amount to the underlying assets acquired, on a relative fair value basis, was recorded on the Company’s books as of the date of the closing of the Titus Acquisition. Additionally, costs directly related to the Titus Acquisition were capitalized as a component of the purchase price. The consideration transferred, assets acquired and liabilities assumed by the Company were recorded as follows (in thousands, except share amounts and stock price):
11
EARTHSTONE ENERGY, INC.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (continued)
Consideration: |
||||
Shares of Class A Common Stock issued |
3,857,015 | |||
Class A Common Stock price as of August 10, 2022 |
$ | 13.89 | ||
|
|
|||
Class A Common Stock consideration |
53,574 | |||
Cash consideration |
567,334 | |||
Direct transaction costs |
1,202 | |||
|
|
|||
Total consideration transferred |
$ | 622,110 | ||
|
|
|||
Assets acquired: |
||||
Oil and gas properties |
$ | 626,696 | ||
|
|
|||
Amount attributable to assets acquired |
$ | 626,696 | ||
|
|
|||
Liabilities assumed: |
||||
Current liabilities |
$ | 3,672 | ||
Noncurrent liabilities - ARO |
914 | |||
|
|
|||
Amount attributable to liabilities assumed |
$ | 4,586 | ||
|
|
Bighorn Acquisition
On January 30, 2022, Earthstone, EEH, as buyer, and Bighorn Asset Company, LLC, a Delaware limited liability company (“Bighorn”), as seller, entered into a purchase and sale agreement (the “Bighorn Agreement”). Pursuant to the Bighorn Agreement, EEH acquired (the “Bighorn Acquisition”) interests in oil and gas leases and related property of Bighorn located in the Midland Basin, Texas (the “Bighorn Assets”).
On April 14, 2022, Earthstone, EEH and Bighorn consummated the transactions contemplated in the Bighorn Agreement whereby EEH acquired the Bighorn Assets for aggregate consideration of approximately $628.3 million in cash, net of customary purchase price adjustments, and 5,650,977 shares Class A Common Stock.
The Bighorn Acquisition was accounted for as an asset acquisition. The consideration paid by the Company and allocation of that amount to the underlying assets acquired, on a relative fair value basis, was recorded on the Company’s books as of the date of the closing of the Bighorn Acquisition. Additionally, costs directly related to the Bighorn Acquisition were capitalized as a component of the purchase price. The consideration transferred, assets acquired and liabilities assumed by the Company were recorded as follows (in thousands, except share amounts and stock price):
12
EARTHSTONE ENERGY, INC.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (continued)
Consideration: |
||||
Shares of Class A Common Stock issued |
5,650,977 | |||
Class A Common Stock price as of April 14, 2022 |
$ | 13.76 | ||
|
|
|||
Class A Common Stock consideration |
77,757 | |||
Cash consideration |
625,887 | |||
Direct transaction costs |
2,397 | |||
|
|
|||
Total consideration transferred |
$ | 706,041 | ||
|
|
|||
Assets acquired: |
||||
Current assets |
$ | 769 | ||
Oil and gas properties |
746,211 | |||
|
|
|||
Amount attributable to assets acquired |
$ | 746,980 | ||
|
|
|||
Liabilities assumed: |
||||
Suspense payable |
$ | 25,710 | ||
Other current liabilities |
2,035 | |||
Noncurrent liabilities - ARO |
13,194 | |||
|
|
|||
Amount attributable to liabilities assumed |
$ | 40,939 | ||
|
|
Chisholm Acquisition
On December 15, 2021, Earthstone, EEH, as buyer, Chisholm Energy Operating, LLC (“OpCo”) and Chisholm Energy Agent, Inc. (“Agent” and collectively with OpCo, “Chisholm”), collectively as seller, entered into a Purchase and Sale Agreement (the “Chisholm Agreement”), which provided that EEH would acquire (the “Chisholm Acquisition”) interests in oil and gas leases and related property of Chisholm located in Lea County and Eddy County, New Mexico (the “Chisholm Assets”).
On February 15, 2022, Earthstone, EEH and Chisholm consummated the transactions contemplated in the Chisholm Agreement whereby EEH acquired the Chisholm Assets for aggregate consideration consisting of: (i) approximately $313.9 million in cash, net of customary purchase price adjustments, paid at the closing of the Chisholm Acquisition, (ii) $70 million in cash paid on April 15, 2022 and (iii) 19,417,476 shares of Class A Common Stock. The fair value of each share of Class A Common Stock was determined using the closing sales price of $12.85 per share on February 15, 2022. On April 10, 2023, 105,894 shares of Class A Common Stock were released to Earthstone from escrow and canceled in connection with the settlement of the Chisholm Acquisition. A Significant Shareholder, as identified below, was the majority owner of Chisholm as of the closing of the Chisholm Acquisition. See Note 12. Related Party Transactions for further discussion.
13
EARTHSTONE ENERGY, INC.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (continued)
The Chisholm Acquisition has been accounted for as a business combination using the acquisition method of accounting, with Earthstone identified as the acquirer. The consideration transferred, fair value of assets acquired and liabilities assumed by Earthstone were recorded as follows (in thousands, except share amounts and stock price):
Consideration: |
||||
Shares of Class A Common Stock issued |
19,311,582 | |||
Class A Common Stock price as of February 15, 2022 |
$ | 12.85 | ||
|
|
|||
Class A Common Stock consideration |
248,154 | |||
Cash consideration |
383,877 | |||
|
|
|||
Total consideration transferred |
$ | 632,031 | ||
|
|
|||
Fair value of assets acquired: |
||||
Oil and gas properties |
$ | 642,391 | ||
|
|
|||
Amount attributable to assets acquired |
$ | 642,391 | ||
|
|
|||
Fair value of liabilities assumed: |
||||
Other current liabilities |
$ | 4,389 | ||
Asset retirement obligation - noncurrent |
5,971 | |||
|
|
|||
Amount attributable to liabilities assumed |
$ | 10,360 | ||
|
|
The fair value measurements of assets acquired and liabilities assumed are based on inputs that are not observable in the market and therefore represent Level 3 inputs. The fair value of oil and gas properties and asset retirement obligations were measured using the discounted cash flow technique of valuation.
Significant inputs to the valuation of oil and 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 future cash flows, and (vi) a market-based weighted average cost of capital rate. These inputs require significant judgments and estimates and are the most sensitive and subject to change.
Divestitures
During the three and six months ended June 30, 2023, the Company sold certain non-core properties for approximately $54.2 million and $56.1 million, respectively, in cash, resulting in net gains of approximately $49.3 million and $46.1 million, respectively, recorded in Gain on sale of oil and gas properties, net in the Condensed Consolidated Statements of Operations for each of the periods then ended. There were no material divestitures during the six months ended June 30, 2022.
Note 6. Oil and Natural Gas Properties
The Company follows the successful efforts method of accounting for its oil and natural gas properties. Under this method, costs to acquire oil and natural gas properties, drill and equip exploratory wells that find proved reserves, and drill and equip development wells are capitalized. Exploration costs, including unsuccessful exploratory wells and geological and geophysical costs, are charged to operations as incurred. Upon sale or retirement of oil and natural gas properties, the costs and related accumulated depreciation, depletion and amortization are eliminated from the accounts and the resulting gain or loss is recognized.
Costs incurred to maintain wells and related equipment, lease and well operating costs, and other exploration costs are charged to expense as incurred. Gains and losses arising from the sale of properties are included in Income from operations in the Condensed Consolidated Statements of Operations.
The Company’s lease acquisition costs and development costs of proved oil and natural gas properties are amortized using the units-of-production method, at the field level, based on total proved reserves and proved developed reserves, respectively. For the three and six months ended June 30, 2023, depletion expense for oil and gas producing property and related equipment was $109.6 million and $219.9 million, respectively For the three and six months ended June 30, 2022, depletion expense for oil and gas producing property and related equipment was $66.2 million and $100.3 million, respectively.
14
EARTHSTONE ENERGY, INC.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (continued)
Our accrual basis capital expenditures for the three and six months ended June 30, 2023, were as follows (in thousands):
Three Months Ended June 30, 2023 |
Six Months Ended June 30, 2023 |
|||||||
Development costs |
$ | 173,702 | $ | 375,086 | ||||
Leasehold costs |
738 | 1,626 | ||||||
|
|
|
|
|||||
Total capital expenditures |
$ | 174,440 | $ | 376,712 | ||||
|
|
|
|
Proved Properties
Proved oil and natural gas properties are reviewed for impairment on a nonrecurring basis. The impairment charge reduces the carrying values to their estimated fair values. These fair value measurements are classified as Level 3 measurements and include many unobservable inputs. Fair value is calculated as the estimated discounted future net cash flows attributable to the assets. The Company’s primary assumptions in preparing the estimated discounted future net cash flows to be recovered from oil and gas properties are based on (i) proved reserves, (ii) forward commodity prices and assumptions as to costs and expenses, and (iii) the estimated discount rate that would be used by potential purchasers to determine the fair value of the assets.
Unproved Properties
Unproved properties consist of costs incurred to acquire undeveloped leases. Unproved oil and gas leases are generally for a primary term of three to five years. In most cases, the term of the unproved leases can be extended by paying a lease renewal fee, meeting contractual drilling obligations, or by the presence of producing wells on the leases. Unproved costs related to successful drilling on unproved leases are reclassified to proved properties.
The Company reviews its unproved properties periodically for impairment. In determining whether an unproved property is impaired, the Company considers numerous factors including, but not limited to, current exploration and development plans, favorable or unfavorable exploration activity on the property being evaluated and/or adjacent properties, the Company’s geologists’ evaluation of the property, and the remaining months in the lease term for the property.
Impairments to Oil and Natural Gas Properties
During the three and six months ended June 30, 2023, the Company recorded non-cash impairment charges of $0.9 million to its oil and natural gas properties due to acreage expirations in non-core operating areas. No impairments were recorded to the Company’s oil and natural gas properties during the three and six months ended June 30, 2022.
Note 7. Net Income Per Common Share
Net income per common share—basic is calculated by dividing Net income by the weighted average number of shares of common stock outstanding during the period. Net income per common share—diluted assumes the conversion of all potentially dilutive securities and is calculated by dividing Net income by the sum of the weighted average number of shares of common stock, as defined above, outstanding plus potentially dilutive securities. Net income per common share—diluted considers the impact of potentially dilutive securities except in periods in which there is a loss because the inclusion of the potential common shares, as defined above, would have an anti-dilutive effect.
15
EARTHSTONE ENERGY, INC.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (continued)
A reconciliation of Net income per common share is as follows:
Three Months Ended June 30, |
Six Months Ended June 30, |
|||||||||||||||
(In thousands, except per share amounts) | 2023 | 2022 | 2023 | 2022 | ||||||||||||
Net income attributable to Earthstone Energy, Inc. |
$ | 58,042 | $ | 144,885 | $ | 118,590 | $ | 111,407 | ||||||||
|
|
|
|
|
|
|
|
|||||||||
Net income attributable to Earthstone Energy, Inc. from assumed conversion of Series A Convertible Preferred Stock |
— | 4,351 | — | 4,351 | ||||||||||||
|
|
|
|
|
|
|
|
|||||||||
Net income attributable to Earthstone Energy, Inc. - Diluted |
$ | 58,042 | $ | 149,236 | $ | 118,590 | $ | 115,758 | ||||||||
|
|
|
|
|
|
|
|
|||||||||
Net income per common share attributable to Earthstone Energy, Inc.: |
||||||||||||||||
Basic |
$ | 0.55 | $ | 1.85 | $ | 1.12 | $ | 1.57 | ||||||||
|
|
|
|
|
|
|
|
|||||||||
Diluted |
$ | 0.54 | $ | 1.46 | $ | 1.10 | $ | 1.37 | ||||||||
|
|
|
|
|
|
|
|
|||||||||
Weighted average common shares outstanding |
||||||||||||||||
Basic |
106,209,657 | 78,291,037 | 106,091,850 | 70,909,353 | ||||||||||||
|
|
|
|
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|
|||||||||
Add potentially dilutive securities: |
||||||||||||||||
Unvested restricted stock units |
204,310 | 493,600 | 276,434 | 506,760 | ||||||||||||
Unvested performance units |
922,728 | 2,003,778 | 1,069,778 | 1,979,770 | ||||||||||||
Series A Convertible Preferred Stock |
— | 21,621,621 | — | 10,870,539 | ||||||||||||
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|
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Diluted weighted average common shares outstanding |
107,336,695 | 102,410,036 | 107,438,062 | 84,266,422 | ||||||||||||
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|
|
|
|
|
The Class B Common Stock has been excluded, as its conversion would eliminate noncontrolling interest and net income attributable to noncontrolling interest of $24.4 million for the three months ended June 30, 2023 and net income attributable to noncontrolling interest of $50.1 million for the six months ended June 30, 2023 would be added back to Net income attributable to Earthstone Energy, Inc. for the periods then ended, having no dilutive effect on Net income per common share attributable to Earthstone Energy, Inc.
The Class B Common Stock has been excluded, as its conversion would eliminate noncontrolling interest and net income attributable to noncontrolling interest of $73.1 million for the three months ended June 30, 2022 and net income attributable to noncontrolling interest of $54.7 million for the six months ended June 30, 2022 would be added back to Net income attributable to Earthstone Energy, Inc. for the periods then ended, having no dilutive effect on Net income per common share attributable to Earthstone Energy, Inc.
Note 8. Common Stock
Class A Common Stock
At June 30, 2023 and December 31, 2022, there were 106,331,055 and 105,547,139 shares of Class A Common Stock issued and outstanding, respectively.
During the three and six months ended June 30, 2023, as a result of the vesting and settlement of performance units and restricted stock units under the Earthstone Energy, Inc. Amended and Restated 2014 Long-Term Incentive Plan, as amended (the “2014 Plan”), Earthstone issued 188,064 and 1,404,966 shares, respectively, of Class A Common Stock, of which 56,683 and 517,156 shares, respectively, of Class A Common Stock were retained as treasury stock and canceled to satisfy the related employee income tax liability. For further discussion, see Note 9. Stock-Based Compensation. Additionally, on April 10, 2023, 105,894 shares of Class A Common Stock were released to Earthstone from escrow and canceled in connection with the settlement of the Chisholm Acquisition.
During the three and six months ended June 30, 2022, as a result of the vesting and settlement of performance units and restricted stock units under the 2014 Plan, Earthstone issued 163,753 and 933,896 shares, respectively, of Class A Common Stock, of which 48,232 and 335,124 shares, respectively, of Class A Common Stock were retained as treasury stock and canceled to satisfy the related employee income tax liability. In connection with the Chisholm Acquisition, on February 15, 2022, Earthstone issued 19,417,476 shares of Class A Common Stock valued at approximately $249.5 million on that date. In connection with the closing of the Bighorn Acquisition, on April 14, 2022, Earthstone issued 5,650,977 shares of Class A Common Stock valued at approximately $77.8 million on that date.
16
EARTHSTONE ENERGY, INC.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (continued)
Class B Common Stock
At June 30, 2023 and December 31, 2022, there were 34,257,641 and 34,259,641 shares of Class B Common Stock issued and outstanding. Each share of Class B Common Stock, together with one EEH Unit, is convertible into one share of Class A Common Stock. During the three and six months ended June 30, 2023, 2,000 shares of Class B Common Stock and EEH Units were exchanged for an equal number of shares of Class A Common Stock. During the three and six months ended June 30, 2022, 10,125 and 82,891 shares, respectively, of Class B Common Stock and EEH Units were exchanged for an equal number of shares of Class A Common Stock.
Note 9. Stock-Based Compensation
Restricted Stock Units
The 2014 Plan, allows, among other things, for the grant of restricted stock units (“RSUs”). As of June 30, 2023, the maximum number of shares of Class A Common Stock that may be issued under the 2014 Plan was 12.0 million shares.
Each RSU represents the contingent right to receive one share of Class A Common Stock. The holders of outstanding RSUs do not have voting rights prior to vesting and settlement. Holders of outstanding RSUs granted prior to December 1, 2022 do not have dividend rights prior to vesting and settlement. Holders of outstanding RSUs granted subsequent to December 1, 2022 do have dividend rights. The Company determines the fair value of granted RSUs based on the market price of the Class A Common Stock on the date of the grant. Compensation expense for granted RSUs is recognized on a straight-line basis over the vesting period and is net of forfeitures, as incurred. Stock-based compensation is included in General and administrative expense in the Condensed Consolidated Statements of Operations and is recorded with a corresponding increase in Additional paid-in capital within the Condensed Consolidated Balance Sheets.
The table below summarizes RSU award activity for the six months ended June 30, 2023:
Shares | Weighted-Average Grant Date Fair Value |
|||||||
Unvested RSUs at December 31, 2022 |
869,978 | $ | 11.40 | |||||
Granted |
420,655 | $ | 13.37 | |||||
Forfeited |
(22,252 | ) | $ | 12.14 | ||||
Vested |
(361,166 | ) | $ | 11.10 | ||||
|
|
|
|
|||||
Unvested RSUs at June 30, 2023 |
907,215 | $ | 12.41 | |||||
|
|
|
|
As of June 30, 2023, there was $11.0 million of unrecognized compensation expense related to the RSU awards which will be recognized over a weighted average period of 1.06 years.
For the three and six months ended June 30, 2023, Stock-based compensation related to RSUs was $1.8 million and $3.6 million, respectively. For the three and six months ended June 30, 2022, Stock-based compensation related to RSUs was $1.5 million and $2.7 million, respectively.
Performance Units
Performance units include both performance-based stock units (“PSUs”) and performance-based restricted stock units (“PRSUs”). The table below summarizes performance unit activity for the six months ended June 30, 2023:
Shares | Weighted-Average Grant Date Fair Value |
|||||||
Unvested Performance Units at December 31, 2022 |
2,616,085 | $ | 10.21 | |||||
Granted |
559,325 | $ | 18.86 | |||||
Vested |
(1,043,800 | ) | $ | 5.36 | ||||
|
|
|
|
|||||
Unvested Performance Units at June 30, 2023 |
2,131,610 | $ | 14.85 | |||||
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|
17
EARTHSTONE ENERGY, INC.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (continued)
On January 6, 2023, the Board of Directors of Earthstone (the “Board”) granted 258,150 PRSUs (the “2023 RTSR PRSUs”) to certain officers pursuant to the 2014 Plan. The 2023 RTSR PRSUs are payable in cash or shares of Class A Common Stock upon the achievement by Earthstone over a period commencing on January 1, 2023 and ending on December 31, 2025 (the “2023 Performance Period”) of certain performance criteria established by the Board. The Company classifies these awards that will be settled in cash as liability awards. PRSU grants to be settled in shares are classified as equity awards. The holders of 2023 RTSR PRSUs do not have any voting rights with respect to such PRSUs until vesting and settlement; however, such holders do have dividend rights.
The number of shares of Class A Common Stock that may be earned will be determined based on the TSR (as defined below) achieved by Earthstone relative to the TSR of each of the companies in the predetermined peer group during the Performance Period. Between 0x to 2.0x of the PRSUs are eligible to be earned based on Earthstone’s ranking relative to the companies in the predetermined peer group. In the event that greater than 1.0x of the 2023 RTSR PRSUs are earned, such additional PRSUs may be paid in cash rather than the issuance of shares of Class A Common Stock
Total shareholder return is generally determined by dividing (A) the volume weighted average price of a share of stock for the trading days during the thirty calendar days ending on and including the last calendar day of the applicable performance period minus the volume weighted average price of a share of stock for the trading days during the thirty calendar days ending on and including the first day of the applicable performance period plus cash dividends paid over the applicable performance period by (B) the volume weighted average price of a share of stock for the trading days during the thirty calendar days ending on and including the first day of the applicable performance period (“TSR”).
The Company accounts for the 2023 RTSR PRSU awards as market-based awards which are valued utilizing the Monte Carlo Simulation pricing model, which calculates multiple potential outcomes for an award and establishes grant date fair value based on the most likely outcome. For the 2023 RTSR PRSUs, assuming a risk-free rate of 3.89% and volatilities ranging from 40.6% to 142.5%, the Company calculated the weighted average grant date fair value per PRSU to be $20.06.
On January 6, 2023, the Board granted 301,175 PRSUs (the “2023 ATSR PRSUs”) to certain officers pursuant to the 2014 Plan. The 2023 ATSR PRSUs are payable in cash or shares of Class A Common Stock upon the achievement by Earthstone over the 2023 Performance Period of certain performance criteria established by the Board. The Company classifies these awards that will be settled in cash as liability awards. PRSU grants to be settled in shares are classified as equity awards. The holders of 2023 ATSR PRSUs do not have any voting rights with respect to such PRSUs until vesting and settlement; however, such holders do have dividend rights.
The 2023 ATSR PRSUs are eligible to be earned based on the annualized TSR of the Class A Common Stock during the 2023 Performance Period. Between 0x to 2.0x of the Performance Units are eligible to be earned based on Earthstone achieving an annualized TSR based on the following pre-established goals:
Earthstone’s Annualized TSR |
TSR Multiplier | |||
23.9% or greater |
2.0 | |||
14.5% |
1.0 | |||
8.4% |
0.5 | |||
Less than 8.4% |
0.0 |
In the event that greater than 1.0x of the 2023 ATSR PRSUs are earned, such additional PRSUs may be paid in cash rather than the issuance of shares of Class A Common Stock.
The Company accounts for the 2023 ATSR PRSUs as market-based awards which are valued utilizing the Monte Carlo Simulation pricing model, which calculates multiple potential outcomes for an award and establishes grant date fair value based on the most likely outcome. For the 2023 ATSR PRSUs, assuming a risk-free rate of 3.89% and volatility of 77%, the Company calculated the weighted average grant date fair value per PRSU to be $17.84.
On January 30, 2020, the Board granted 1,043,800 PSUs (the “2020 PSUs”) to certain officers pursuant to the 2014 Plan (the “2020 Grant”).
18
EARTHSTONE ENERGY, INC.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (continued)
The 2020 PSUs were settled on January 31, 2023 resulting in the issuance of 1,043,800 shares of Class A Common Stock and cash payments totaling approximately $14.5 million.
As of June 30, 2023, there was $17.7 million of unrecognized compensation expense related to all PSU awards which will be amortized over a weighted average period of 0.89 years.
For the three and six months ended June 30, 2023, Stock-based compensation related to all performance units was approximately $6.1 million and $8.9 million, respectively. For the three and six months ended June 30, 2022, Stock-based compensation related to all performance units was approximately $4.5 million and $9.1 million, respectively.
The Company classifies awards that will be settled in cash as liability awards. PSU grants to be settled in shares are classified as equity awards. Corresponding liabilities of $12.7 million and $14.4 million related to the performance units were included in Other current liabilities and Accrued expenses, respectively, in the Condensed Consolidated Balance Sheets as of June 30, 2023 and December 31, 2022, respectively. Additionally, corresponding liabilities of $2.2 million and $10.4 million related to the performance units were included in Other noncurrent liabilities in the Condensed Consolidated Balance Sheets as of June 30, 2023 and December 31, 2022, respectively.
Note 10. Long-Term Debt
The Company’s long-term debt consisted of the following (in thousands):
June 30, 2023 | December 31, 2022 | |||||||
Revolving credit facility(1) |
$ | — | $ | 270,136 | ||||
Term loan under credit facility due 2027 |
— | 250,000 | ||||||
8.000% Senior notes due 2027 |
550,000 | 550,000 | ||||||
9.875% Senior notes due 2031 |
500,000 | — | ||||||
|
|
|
|
|||||
1,050,000 | 1,070,136 | |||||||
Unamortized debt issuance costs on term loan |
— | (5,309 | ) | |||||
Unamortized debt issuance costs on 8.000% Senior notes |
(9,660 | ) | (10,948 | ) | ||||
Original issue discount on 9.875% Senior notes(2) |
(10,160 | ) | — | |||||
Unamortized debt issuance costs on 9.875% Senior notes(2) |
(8,625 | ) | — | |||||
|
|
|
|
|||||
Long-term debt, net |
$ | 1,021,555 | $ | 1,053,879 | ||||
|
|
|
|
(1) | Related to the borrowings under the revolving credit facility, the Company had debt issuance costs of $16.4 million and $15.3 million, net of accumulated amortization of $8.5 million and $6.5 million, as of June 30, 2023 and December 31, 2022, respectively. Unamortized deferred financing costs on the borrowings under the revolving credit facility are included in Other noncurrent assets in the Condensed Consolidated Balance Sheets. |
(2) | The 9.875% Senior notes due 2031 were issued on June 30, 2023 resulting in no amortization of the original issue discount and debt issuance costs in the current period. Beginning July 1, 2023, the Company will show amortization of the original issue discount and debt issuance costs as interest expense in the Condensed Consolidated Statement of Operations. |
Credit Agreement
On November 21, 2019, Earthstone, EEH (the “Borrower”), Wells Fargo Bank, National Association, as Administrative Agent and Issuing Bank (“Wells Fargo”), BOKF, NA dba Bank of Texas, as Issuing Bank with respect to Existing Letters of Credit, Royal Bank of Canada, as Syndication Agent, Truist Bank, as successor by merger to SunTrust Bank, as Documentation Agent, and the Lenders party thereto (collectively, the “Parties”) entered into a credit agreement (together with all amendments or other modifications, the “Credit Agreement”), which replaced the prior credit facility, which was terminated on November 21, 2019.
On March 30, 2023, Earthstone, EEH, Wells Fargo, the lenders party thereto (the “Lenders”) and the guarantors party thereto entered into an amendment (the “Eighth Amendment”) to the Credit Agreement. Among other things, the Eighth Amendment (i) increased elected commitments from $1.2 billion to $1.4 billion, (ii) settled the $250 million term loan tranche under the Credit Agreement (the “Term Loan”) through an elected revolving commitment, (iii) redetermined the borrowing base at $1.65 billion as a part of the regularly scheduled redetermination, (iv) added new banks to the lending group, and (v) made certain administrative changes.
On July 7, 2023, Earthstone, EEH, Wells Fargo, the Lenders and the guarantors party thereto entered into an amendment (the “Ninth Amendment”) to the Credit Agreement. Among other things, the Amendment (i) adds JPMorgan Chase Bank, N.A. and Citibank N.A. as new Lenders, arrangers, and documentation agents for the Lenders under the Credit Agreement, (ii) increases the aggregate elected borrowing base commitments from $1.40 billion to $1.75 billion, and (iii) increases the borrowing base from $1.65 billion to $2.00 billion. The effectiveness of the Amendment is conditioned upon, among other things, the closing of the previously announced Novo Transactions.
19
EARTHSTONE ENERGY, INC.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (continued)
The next regularly scheduled redetermination of the borrowing base is expected to occur on or around October 1, 2023. Subsequent redeterminations are expected to occur on or about each May 1st and November 1st thereafter. The amounts borrowed under the Credit Agreement bear annual interest rates at either (a) the adjusted SOFR Rate (as customarily defined) (the “Adjusted Term SOFR Rate”) plus 2.25% to 3.25% or (b) the sum of (i) the greatest of (A) the prime rate of Wells Fargo, (B) the federal funds rate plus 1⁄2 of 1.0%, and (C) the Adjusted Term SOFR Rate for an interest rate period of one month plus 1.0%, (ii) plus 1.25% to 2.25%, depending on the amount borrowed under the Credit Agreement. Principal amounts outstanding under the Credit Agreement are due and payable in full at maturity on June 2, 2027. All of the obligations under the Credit Agreement, and the guarantees of those obligations, are secured by substantially all of EEH’s assets. Additional payments due under the Credit Agreement include paying a commitment fee of 0.375% to 0.50% per year, depending on the amount borrowed under the Credit Agreement, to the Lenders in respect of the unutilized commitments thereunder. EEH is also required to pay customary letter of credit fees.
The Credit Agreement contains a number of covenants that, among other things, restrict, subject to certain exceptions, EEH’s ability to incur additional indebtedness, create liens on assets, make investments, pay dividends and distributions or repurchase its limited liability interests, engage in mergers or consolidations, sell certain assets, sell or discount any notes receivable or accounts receivable and engage in certain transactions with affiliates.
In addition, the Credit Agreement requires EEH to maintain the following financial covenants: a current ratio, (as such term is defined in the Credit Agreement) of not less than 1.0 to 1.0 and a consolidated leverage ratio of not greater than 3.5 to 1.0. Consolidated leverage ratio means the ratio of (i) the aggregate debt of EEH and its consolidated subsidiaries as at the last day of the fiscal quarter to (ii) EBITDAX for the applicable period, which was calculated as EBITDAX for the four consecutive fiscal quarters ending on such date. The term “EBITDAX” means, for any period, the sum of consolidated net income (loss) for such period plus (a) the following expenses or charges to the extent deducted from consolidated net income (loss) in such period: (i) interest, (ii) taxes, (iii) depreciation, (iv) depletion, (v) amortization, (vi) certain distributions to employees related to the stock compensation, (vii) certain transaction related expenses, (viii) reimbursed indemnification expenses related to certain dispositions and investments, (ix) non-cash extraordinary, usual, or nonrecurring expenses or losses, (x) other non-cash charges and minus (b) to the extent included in consolidated net income (loss) in such period: (i) non-cash income, (ii) gains on asset dispositions, disposals and abandonments outside of the ordinary course of business and (iii) to the extent not otherwise deducted from consolidated net income (loss), the aggregate amount of any pass-through cash distributions received by Borrower during such period in an amount equal to the aggregate amount of pass-through cash distributions actually made by Borrower during such period.
The Credit Agreement contains customary affirmative covenants and defines events of default to include failure to pay principal or interest, breach of covenants, breach of representations and warranties, insolvency, judgment default and a change in control. Upon the occurrence and continuance of an event of default, the Lenders have the right to accelerate repayment of the loans and exercise their remedies with respect to the collateral. As of June 30, 2023, EEH was in compliance with the covenants under the Credit Agreement.
As of June 30, 2023, no borrowings were outstanding under the Credit Agreement, resulting in $1.4 billion of borrowing base availability. At December 31, 2022, $270.1 million and $250.0 million of borrowings were outstanding under the revolving tranche and the term loan tranche of the Credit Agreement, respectively.
For the three and six months ended June 30, 2023, the interest rate on borrowings under the revolving tranche of the Credit Agreement averaged 7.60% and 7.56% per annum, respectively, which excluded commitment fees of $0.9 million and $1.6 million, respectively, and amortization of deferred financing costs of $1.0 million and $2.0 million, respectively. For the three and six months ended June 30, 2022, the interest rate on borrowings under the Credit Agreement averaged 4.42% and 4.04% per annum, respectively, which excluded commitment fees of $0.0 million and $0.2 million, respectively, and amortization of deferred financing costs of $0.9 million and $1.6 million, respectively.
No costs associated with the revolving tranche of the Credit Agreement were capitalized during the three months ended June 30, 2023. During the six months ended June 30, 2023, the Company capitalized $3.1 million of costs associated with the revolving tranche of the Credit Agreement. There were no costs associated with the term loan tranche of the Credit Agreement to capitalize during the three and six months ended June 30, 2023. During the three and six months ended June 30, 2022, the Company capitalized $5.7 million and $11.6 million, respectively, of costs associated with the Credit Agreement. The Company’s policy is to capitalize the financing costs associated with its debt and amortize those costs on a straight-line basis over the term of the associated debt, which approximates the effective interest method over the term of the related debt.
20
EARTHSTONE ENERGY, INC.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (continued)
8.000% Senior Notes
At June 30, 2023, there were $550.0 million of outstanding senior notes due 2027 (the “2027 Notes”). The 2027 Notes will mature on April 15, 2027 with interest accruing at a rate of 8.000% per annum payable semi-annually in cash in arrears on April 15 and October 15 of each year. The 2027 Notes are guaranteed on a senior unsecured basis by Earthstone and four subsidiaries of EEH (the “Guarantors”) and the 2027 Notes may be guaranteed by certain of EEH’s future restricted subsidiaries. The 2027 Notes are unsecured, rank equally in right of payment with all existing and future senior unsecured indebtedness of EEH and the Guarantors, including the 2031 Notes, and rank senior in right of payment to any future subordinated indebtedness of EEH and the Guarantors. The 2027 Notes will rank effectively junior to all secured indebtedness of EEH and the Guarantors, including indebtedness under the Credit Agreement, to the extent of the value of the assets securing such indebtedness. The 2027 Notes will rank structurally junior in right of payment to all indebtedness and other liabilities, including trade payables, of any future subsidiary of EEH that are not guarantors. The indenture dated April 12, 2022 under which the 2027 Notes were issued also contains certain restrictive covenants, redemption rights, events of default and other customary provisions.
As of June 30, 2023, accrued interest of $9.3 million associated with the 2027 Notes was included in Accrued expenses in the Condensed Consolidated Balance Sheets.
9.875% Senior Notes
On June 30, 2023, EEH completed an offering of $500.0 million aggregate principal amount of EEH’s 9.875% senior notes due 2031 (the “2031 Notes”). The 2031 Notes will mature on July 15, 2031 with interest accruing at a rate of 9.875% per annum payable semi-annually in cash in arrears on January 15 and July 15 of each year, commencing January 15, 2024. The 2031 Notes are guaranteed on a senior unsecured basis by the Guarantors and the 2031 Notes may be guaranteed by certain of EEH’s future restricted subsidiaries. The 2031 Notes are unsecured, rank equally in right of payment with all existing and future senior unsecured indebtedness of EEH and the Guarantors, including the 2027 Notes, and rank senior in right of payment to any future subordinated indebtedness of EEH and the Guarantors. The 2031 Notes will rank effectively junior to all secured indebtedness of EEH and the Guarantors, including indebtedness under the Credit Agreement, to the extent of the value of the assets securing such indebtedness. The 2031 Notes will rank structurally junior in right of payment to all indebtedness and other liabilities, including trade payables, of any future subsidiary of EEH that are not guarantors. The indenture dated June 30, 2023 under which the 2031 Notes were issued (the “Indenture”) also contains certain restrictive covenants, redemption rights, events of default and other customary provisions.
Subject to the terms of the Indenture, if the consummation of the Novo Acquisition does not occur before a specified date, EEH will be required to redeem all of the 2031 Notes issued on the issue date at a redemption price equal to 100% of the initial issue price of the 2031 Notes, plus accrued and unpaid interest on the 2031 Notes being redeemed, if any.
As of June 30, 2023, accrued interest of $0.1 million associated with the 2031 Notes was included in Accrued expenses in the Condensed Consolidated Balance Sheets.
Note 11. Asset Retirement Obligations
The Company has asset retirement obligations associated with the future plugging and abandonment of oil and gas properties and related facilities. Revisions to the liability typically occur due to changes in the estimated abandonment costs, well economic lives, and the discount rate.
The following table summarizes the Company’s asset retirement obligation transactions recorded during the six months ended June 30, 2023 (in thousands):
2023 | ||||
Beginning asset retirement obligations |
$ | 30,559 | ||
Liabilities incurred |
171 | |||
Liabilities settled |
(1,036 | ) | ||
Accretion expense |
1,275 | |||
Divestitures |
(892 | ) | ||
Revision of estimates |
478 | |||
|
|
|||
Ending asset retirement obligations |
$ | 30,555 | ||
|
|
21
EARTHSTONE ENERGY, INC.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (continued)
Note 12. Related Party Transactions
FASB ASC Topic 850, Related Party Disclosures, requires that information about transactions with related parties that would make a difference in decision making shall be disclosed so that users of the financial statements can evaluate their significance. The Audit Committee of the Board independently reviews and approves all related party transactions.
Earthstone has two significant shareholders that consist of various investment funds managed by each of the two private equity firms who may manage other investments in entities with which the Company interacts in the normal course of business (the “Significant Shareholders” or separately, each a “Significant Shareholder”).
As discussed in Note 5. Acquisitions and Divestitures, the Chisholm Acquisition was consummated on February 15, 2022, whereby the Company acquired the Chisholm Assets for a purchase price of $383.9 million in cash, net of customary purchase price adjustments, and approximately 19.4 million shares of Class A Common Stock. A Significant Shareholder was the majority owner of Chisholm as of the closing of the Chisholm Acquisition. The deferred payment of $70 million as of March 31, 2022 was paid on April 15, 2022 and included in Deferred acquisition payment – Chisholm in the Condensed Consolidated Balance Sheet as of March 31, 2022. The issuance of approximately 19.4 million shares of Class A Common Stock in connection with the closing of the Chisholm Acquisition was (1) approved by a majority of the voting power of all outstanding disinterested shares of the Common Stock and (2) increased the Significant Stockholder’s beneficial ownership of Class A Common Stock from approximately 25% to 36% as of February 15, 2022. On April 10, 2023, 105,894 shares of Class A Common Stock were released to Earthstone from escrow and canceled in connection with the settlement of the Chisholm Acquisition.
As discussed in Note 5. Acquisitions and Divestitures, on June 14, 2023, EEH entered into the Novo Purchase Agreement. Pursuant to the Novo Purchase Agreement, EEH will acquire the Novo Assets for an aggregate purchase price of $1.5 billion in cash, subject to customary purchase price adjustments, and reduced by NOG’s portion of the purchase price pursuant to the Cooperation Agreement. A Significant Shareholder is the majority owner of the Sellers.
Note 13. Commitments and Contingencies
Legal
George Assad, et. al. v. EnCap Investments L.P., et. al.: On September 12, 2022, a complaint (the “Complaint”) styled as a “derivative action” was filed in the Delaware Court of Chancery (the “Court”) by George Assad (the “plaintiff”) a purported holder of a small number of shares of Class A Common Stock against Earthstone, six of its 10 directors and EnCap Investments L.P. (“EnCap”), a principal stockholder. The Complaint alleges that a majority of Earthstone’s directors were conflicted and, along with EnCap, breached their fiduciary duties in approving the sale of shares of Series A Convertible Preferred Stock that is convertible into Class A Common Stock pursuant to the Securities Purchase Agreement dated as of January 30, 2022, by and among Earthstone and the Investors. The plaintiff requested the Court to declare that the defendants breached their fiduciary duties, award of unspecified monetary damages, including interest and costs, and/ or rescind the stock purchase transaction. On October 14, 2022, the defendants filed a motion to dismiss the amended Complaint. Earthstone believes the Complaint is completely without merit and intends to contest vigorously the allegations made therein and to seek reimbursement for its costs and expenses in so doing. Earthstone carries insurance for the claims asserted against it and the officer and director defendants in the Complaint, and the carrier has accepted coverage subject to applicable self-retentions and limits of liability. The Company does not expect this case to have a material adverse effect on the results of operations, financial position or cash flows of the Company.
From time to time, the Company may be involved in other various legal proceedings and claims in the ordinary course of business, none of which are reasonably expected to result in a material liability to the Company as of June 30, 2023.
Environmental and Regulatory
As of June 30, 2023, there were no known environmental or other regulatory matters related to the Company’s properties or operations that are reasonably expected to result in a material liability to the Company.
Note 14. Income Taxes
The Company’s corporate structure requires the filing of two separate U.S. Federal income tax returns and one Canadian income tax return which include Lynden US, Earthstone, and Lynden Corp, respectively. As such, taxable income of Earthstone cannot be offset by tax attributes, including net operating losses, of Lynden US, nor can taxable income of Lynden US be offset by tax attributes of Earthstone. Earthstone and Lynden US record a tax provision, respectively, for their share of the book income or loss of EEH, net of the non-controlling interest. As EEH is treated as a partnership for U.S. Federal income tax purposes, it is not subject to income tax at the federal level and only recognizes the Texas Margin Tax.
22
EARTHSTONE ENERGY, INC.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (continued)
On February 15, 2022, the Company completed the Chisholm Acquisition which included the issuance of 19,311,582 shares of Class A Common Stock, which resulted in an ownership change within the meaning of Section 382 of the Internal Revenue Code of 1986, as amended (the “Code”). As a result of the ownership change, the Company’s ability to utilize net operating losses (“NOLs”) and credits generated prior to the ownership change date may be limited to offset taxable income incurred after the ownership change date (the “382 Limitation”).
As of June 30, 2023 and December 31, 2022, current liabilities of $1.6 million and $1.8 million, respectively, are included in Other current liabilities in the Condensed Consolidated Balance Sheets related solely to current Texas Margin Tax payable.
During the six months ended June 30, 2023, the Company recorded income tax expense of approximately $36.7 million comprised of (1) deferred federal income tax expense for Earthstone of $31.0 million resulting from its share of the distributable income from EEH, (2) a deferred federal income tax expense for Lynden US of $1.8 million as a result of its share of the distributable income from EEH and (3) income tax expense of $3.9 million related to both current and deferred state income taxes. Lynden Corp incurred no material income or loss, or related income tax expense or benefit, for the six months ended June 30, 2023.
During the six months ended June 30, 2022, the Company recorded income tax expense of approximately $21.2 million which included (1) a deferred income tax expense for Earthstone of $17.9 million which included a deferred income tax expense of $24.3 million resulting from its share of the distributable income from EEH, offset by a $6.4 million release of valuation allowance, (2) a deferred income tax expense for Lynden US of $2.0 million as a result of its share of the distributable income from EEH and (3) income tax expense of $1.3 million related to state taxes. Lynden Corp incurred no material income or loss, or related income tax expense or benefit, for the six months ended June 30, 2022.
Note 15. Supplemental Disclosures
Accounts Payable
The following table summarizes the Company’s current accounts payable at June 30, 2023 and December 31, 2022 (in thousands):
June 30, | December 31, | |||||||
2023 | 2022 | |||||||
Accounts payable related to vendors |
$ | 37,430 | $ | 76,044 | ||||
Accounts payable related to severance taxes |
8,752 | 10,380 | ||||||
Other |
7,642 | 5,391 | ||||||
|
|
|
|
|||||
Total accounts payable |
$ | 53,824 | $ | 91,815 | ||||
|
|
|
|
Revenue and Royalties Payable
The following table summarizes the Company’s revenues held in suspense and royalties payable at June 30, 2023 and December 31, 2022 (in thousands):
June 30, | December 31, | |||||||
2023 | 2022 | |||||||
Revenue held in suspense |
$ | 115,540 | $ | 101,838 | ||||
Revenue and royalties payable |
50,840 | 61,530 | ||||||
|
|
|
|
|||||
Total revenue and royalties payable |
$ | 166,380 | $ | 163,368 | ||||
|
|
|
|
23
EARTHSTONE ENERGY, INC.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (continued)
Accrued Expenses
The following table summarizes the Company’s current accrued expenses at June 30, 2023 and December 31, 2022 (in thousands):
June 30, | December 31, | |||||||
2023 | 2022 | |||||||
Accrued capital expenditures |
$ | 42,866 | $ | 38,482 | ||||
Accrued lease operating expenses |
16,342 | 14,173 | ||||||
Accrued interest |
9,450 | 10,995 | ||||||
Accrued general and administrative expense |
8,417 | 7,351 | ||||||
Accrued ad valorem taxes |
18,873 | 4,243 | ||||||
Other |
6,253 | 5,698 | ||||||
|
|
|
|
|||||
Total accrued expenses |
$ | 102,201 | $ | 80,942 | ||||
|
|
|
|
Supplemental Cash Flow Information
The following table provides supplemental disclosures of cash flow information for the three months ended June 30, 2023 and 2022 (in thousands):
For the Six Months Ended June 30, |
||||||||
2023 | 2022 | |||||||
Cash paid for: |
||||||||
Interest |
$ | 43,035 | $ | 9,468 | ||||
Income taxes |
$ | 1,251 | $ | 625 | ||||
Non-cash investing and financing activities: |
||||||||
Class A Common Stock issued in Chisholm Acquisition |
$ | (1,361 | ) | $ | 249,515 | |||
Class A Common Stock issued in Bighorn Acquisition |
$ | — | $ | 77,757 | ||||
Accrued capital expenditures |
$ | 74,689 | $ | 44,285 | ||||
Lease asset additions - ASC 842 |
$ | 997 | $ | 678 | ||||
Asset retirement obligations |
$ | 649 | $ | 284 |
24
Exhibit 99.5
Report of Independent Auditors
The Board of Managers and Members
Novo Oil & Gas Holdings, LLC
Report on the Audit of the Financial Statements
Opinion
We have audited the combined consolidated financial statements of Novo Oil & Gas Holdings, LLC and its subsidiaries, which comprise the consolidated balance sheets as of December 31, 2022 and 2021, and the related combined consolidated statements of operations, changes in members’ equity, and cash flows for the years then ended, and the related notes to the combined consolidated financial statements.
In our opinion, the accompanying combined consolidated financial statements present fairly, in all material respects, the financial position of Novo Oil & Gas Holdings, LLC and its subsidiaries as of December 31, 2022 and 2021, and the results of its operations and its cash flows for the years 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 Novo Oil & Gas Holdings, LLC and its subsidiaries and to meet our other ethical responsibilities, in accordance with the relevant ethical requirements relating to our audits. We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our audit opinion.
Responsibilities of Management for the Financial Statements
Management is responsible for the preparation and fair presentation of the combined consolidated 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 from material misstatement, whether due to fraud or error.
In preparing the combined consolidated financial statements, management is required to evaluate whether there are conditions or events, considered in the aggregate, that raise substantial doubt about Novo Oil & Gas Holdings, LLC and its subsidiaries’ ability to continue as a going concern within one year after the date that the combined consolidated financial statements are available to be issued.
1
Auditor’s Responsibilities for the Audit of the Financial Statements
Our objectives are to obtain reasonable assurance about whether the combined consolidated financial statements as a whole are free from 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 combined consolidated 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 combined consolidated 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 combined consolidated financial statements. |
• | Obtain an understanding of internal control relevant to the audit in order to design audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of Novo Oil & Gas Holdings, LLC and its subsidiaries’ 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 combined consolidated financial statements. |
• | Conclude whether, in our judgment, there are conditions or events, considered in the aggregate, that raise substantial doubt about Novo Oil & Gas Holdings, LLC and its subsidiaries’ 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 combined consolidated financial statements as a whole. The accompanying Supplemental Schedules about Oil and Natural Gas Producing Properties are presented for purposes of additional analysis and is not a required part of the combined consolidated financial statements. Because of the significance of the matter described above, it is inappropriate to, and we do not, express an opinion on this supplementary information.
Dallas, Texas
March 31, 2023
2
Novo Oil & Gas Holdings, LLC
Combined Consolidated Balance Sheets
December 31, 2022 and 2021
2022 | 2021 | |||||||
ASSETS |
||||||||
CURRENT ASSETS |
||||||||
Cash and cash equivalents |
$ | 25,387,306 | $ | 17,005,132 | ||||
Accounts receivable |
||||||||
Oil and gas sales |
48,998,017 | 26,137,534 | ||||||
Joint interest owners |
17,628,002 | 4,537,388 | ||||||
Related party |
1,450 | 10,650 | ||||||
Commodity derivative asset, short term |
37,692,443 | — | ||||||
Prepaid expenses and other assets |
1,468,000 | 428,465 | ||||||
|
|
|
|
|||||
Total current assets |
131,175,218 | 48,119,169 | ||||||
PROPERTY AND EQUIPMENT |
||||||||
Oil and gas properties, successful efforts method |
||||||||
Proved |
1,083,345,141 | 587,486,686 | ||||||
Unproved |
60,157,459 | 81,428,206 | ||||||
Right-of-use asset, net |
149,570 | — | ||||||
Furniture, fixtures, and other |
2,118,139 | 1,947,290 | ||||||
Inventory |
405,777 | 271,401 | ||||||
|
|
|
|
|||||
Total property and equipment |
1,146,176,086 | 671,133,583 | ||||||
Accumulated depletion, depreciation, and amortization |
(213,914,619 | ) | (111,182,929 | ) | ||||
|
|
|
|
|||||
Property and equipment, net |
932,261,467 | 559,950,654 | ||||||
OTHER ASSETS |
||||||||
Debt issuance costs, net |
3,313,492 | 1,059,310 | ||||||
Commodity derivative asset, long term |
2,474,020 | — | ||||||
Deposit |
20,640 | 20,640 | ||||||
|
|
|
|
|||||
TOTAL ASSETS |
$ | 1,069,244,837 | $ | 609,149,773 | ||||
|
|
|
|
See accompanying notes.
3
Novo Oil & Gas Holdings, LLC
Combined Consolidated Balance Sheets
December 31, 2022 and 2021
2022 | 2021 | |||||||
LIABILITIES AND MEMBERS’ EQUITY |
|
|||||||
CURRENT LIABILITIES |
||||||||
Accounts payable |
||||||||
Trade |
$ | 78,219,906 | $ | 45,147,136 | ||||
Revenue payable |
33,234,352 | 9,251,552 | ||||||
Accrued liabilities |
5,959,428 | 1,120,378 | ||||||
Operating lease liabilities, current |
149,570 | — | ||||||
Advances from joint interest partners |
18,986 | 27,154,896 | ||||||
Commodity derivatives liability, current |
5,062,877 | 9,517,796 | ||||||
Deferred midstream revenue, current |
2,333,333 | 2,333,333 | ||||||
|
|
|
|
|||||
Total current liabilities |
124,978,452 | 94,525,091 | ||||||
NON-CURRENT LIABILITIES |
||||||||
Revolving credit facility |
250,000,000 | 10,000,000 | ||||||
Commodity derivative liability, long-term |
4,904,914 | 3,441,119 | ||||||
Deferred midstream revenue, long-term |
22,361,111 | 24,694,445 | ||||||
Asset retirement obligation |
2,705,686 | 1,034,668 | ||||||
|
|
|
|
|||||
Total non-current liabilities |
404,950,163 | 133,695,323 | ||||||
COMMITMENT AND CONTINGENCIES (Note 8) |
||||||||
MEMBERS’ EQUITY |
664,294,674 | 475,454,450 | ||||||
|
|
|
|
|||||
TOTAL LIABILITIES & MEMBERS’ EQUITY |
$ | 1,069,244,837 | $ | 609,149,773 | ||||
|
|
|
|
See accompanying notes.
4
Novo Oil & Gas Holdings, LLC
Combined Consolidated Statements of Operations
Years Ended December 31, 2022 and 2021
2022 | 2021 | |||||||
REVENUES |
||||||||
Oil sales |
$ | 371,050,382 | $ | 109,828,955 | ||||
Natural gas sales |
153,414,695 | 55,289,349 | ||||||
Natural gas liquids sales |
139,074,955 | 42,778,233 | ||||||
|
|
|
|
|||||
Total revenues |
663,540,032 | 207,896,537 | ||||||
OPERATING COSTS AND EXPENSES |
||||||||
Lease operating |
45,326,041 | 22,143,457 | ||||||
Production taxes |
48,969,260 | 12,204,787 | ||||||
Exploration |
807,751 | 571,809 | ||||||
General and administrative |
8,641,209 | 6,173,678 | ||||||
Depletion, depreciation, and amortization |
102,731,690 | 40,850,322 | ||||||
Accretion of discount on asset retirement obligations |
118,987 | 71,287 | ||||||
|
|
|
|
|||||
Total operating costs and expenses |
206,594,938 | 82,015,340 | ||||||
|
|
|
|
|||||
OPERATING INCOME |
456,945,094 | 125,881,197 | ||||||
OTHER INCOME (EXPENSE) |
||||||||
Interest expense |
(8,795,463 | ) | (741,973 | ) | ||||
Interest income |
3,635 | 20,416 | ||||||
Loss on sale of O&G properties |
(59,979 | ) | (8,209,375 | ) | ||||
Realized commodity derivative loss |
(49,741,750 | ) | (22,074,250 | ) | ||||
Unrealized commodity derivative gain (loss) |
39,416,737 | (8,953,305 | ) | |||||
Deferred midstream revenue |
2,333,333 | 2,333,333 | ||||||
Other income |
330,886 | 1,665,152 | ||||||
|
|
|
|
|||||
Total other expense |
(16,512,601 | ) | (35,960,002 | ) | ||||
|
|
|
|
|||||
NET INCOME BEFORE TAXES |
440,432,493 | 89,921,195 | ||||||
MARGIN TAX EXPENSE |
402,624 | — | ||||||
|
|
|
|
|||||
NET INCOME |
$ | 440,029,869 | $ | 89,921,195 | ||||
|
|
|
|
See accompanying notes.
5
Novo Oil & Gas Holdings, LLC
Combined Consolidated Statements of Changes in Members’ Equity
Years Ended December 31, 2022 and 2021
Class A | Class B | |||||||||||||||||||
Units | Capital | Units | Capital | Total | ||||||||||||||||
BALANCES, January 1, 2022 |
3,092,175 | $ | 407,428,051 | 63,106 | $ | 5,608,727 | $ | 413,036,778 | ||||||||||||
Distributions |
— | (26,970,952 | ) | — | (532,571 | ) | (27,503,523 | ) | ||||||||||||
Net income |
— | 88,122,771 | — | 1,798,424 | 89,921,195 | |||||||||||||||
|
|
|
|
|
|
|
|
|
|
|||||||||||
BALANCES, December 31, 2022 |
3,092,175 | 468,579,870 | 63,106 | 6,874,580 | 475,454,450 | |||||||||||||||
Distributions |
— | (246,165,853 | ) | — | (5,023,792 | ) | (251,189,645 | ) | ||||||||||||
Net income |
— | 431,229,219 | — | 8,800,650 | 440,029,869 | |||||||||||||||
|
|
|
|
|
|
|
|
|
|
|||||||||||
BALANCES, December 31, 2023 |
3,092,175 | $ | 653,643,236 | 63,106 | $ | 10,651,438 | $ | 664,294,674 | ||||||||||||
|
|
|
|
|
|
|
|
|
|
See accompanying notes.
6
Novo Oil & Gas Holdings, LLC
Combined Consolidated Statements of Cash Flows
Years Ended December 31, 2022 and 2021
2023 | 2021 | |||||||
CASH FLOWS FROM OPERATING ACTIVITIES |
||||||||
Net income |
$ | 440,029,869 | $ | 89,921,195 | ||||
Adjustments to reconcile net income to net cash from operating activities |
||||||||
Depletion, depreciation, and amortization |
102,731,690 | 40,850,322 | ||||||
Deferred financing cost amortization |
973,883 | 386,411 | ||||||
Accretion of discount on asset retirement obligations |
118,987 | 71,287 | ||||||
Deferred midstream revenue |
(2,333,333 | ) | (2,333,333 | ) | ||||
Unrealized (gain) loss on derivatives |
(39,416,737 | ) | 8,953,305 | |||||
Loss on sale of O&G properties |
59,979 | 8,209,375 | ||||||
Change in working capital items |
||||||||
Accounts receivable |
(35,941,896 | ) | (10,444,786 | ) | ||||
Prepaid expenses and other assets |
(1,039,535 | ) | 520,611 | |||||
Accounts payable |
12,787,030 | 11,627,340 | ||||||
Advances from joint interest partners |
(27,135,910 | ) | 27,154,202 | |||||
Revenue payables |
23,982,800 | 4,822,424 | ||||||
Accrued liabilities |
(9,808,568 | ) | 1,117,751 | |||||
|
|
|
|
|||||
Net cash from operating activities |
465,008,259 | 180,856,104 | ||||||
CASH FLOWS FROM INVESTING ACTIVITIES |
||||||||
Purchase of derivative premiums |
(3,740,850 | ) | — | |||||
Additions to oil and gas properties |
(438,402,651 | ) | (142,805,526 | ) | ||||
Additions to other property and equipment |
(170,849 | ) | (141,743 | ) | ||||
Proceeds from sales of oil and gas properties |
105,976 | 603,276 | ||||||
|
|
|
|
|||||
Net cash from investing activities |
(442,208,374 | ) | (142,343,993 | ) | ||||
CASH FLOWS FROM FINANCING ACTIVITIES |
||||||||
Payments for deferred financing cost |
(3,228,066 | ) | (1,174,799 | ) | ||||
Borrowings proceeds from credit agreement |
240,000,000 | 10,000,000 | ||||||
Repayment on borrowings |
— | (20,166,667 | ) | |||||
Distribution to members |
(251,189,645 | ) | (27,503,523 | ) | ||||
|
|
|
|
|||||
Net cash from financing activities |
(14,417,711 | ) | (38,844,989 | ) | ||||
NET CHANGE IN CASH AND CASH EQUIVALENTS |
8,382,174 | (332,878 | ) | |||||
CASH AND CASH EQUIVALENTS, beginning of year |
17,005,132 | 17,338,010 | ||||||
|
|
|
|
|||||
CASH AND CASH EQUIVALENTS, end of year |
$ | 25,387,306 | $ | 17,005,132 | ||||
|
|
|
|
|||||
SUPPLEMENTAL DISCLOSURES OF NON-CASH TRANSACTIONS |
||||||||
Change in accounts payable related to oil and gas properties |
$ | 32,983,698 | $ | (1,294,668 | ) | |||
|
|
|
|
|||||
SUPPLEMENTAL DISCLOSURES OF CASH TRANSACTIONS |
||||||||
Cash paid for interest |
$ | 7,217,739 | $ | 281,395 | ||||
|
|
|
|
|||||
Cash paid for margin tax |
$ | 138,625 | $ | — | ||||
|
|
|
|
See accompanying notes.
7
Novo Oil & Gas Holdings, LLC
Notes to Combined Consolidated Financial Statements
Note 1 – Summary of Significant Accounting Policies
Organization – Novo Oil & Gas Holdings, LLC (Novo or the Company), was formed August 29, 2016, as a limited liability company under the laws of the state of Delaware. Its status as a limited liability company will have perpetual existence unless and until it is dissolved in accordance with the provisions of the Limited Liability Company Agreement (the Agreement). Except as otherwise expressly agreed in writing, members of Novo (the Members) are not personally liable for any obligations of the Company. Revenues and costs and expenses of Novo are allocated to the Members based upon the provisions of the Company’s Agreement.
The Company’s principal business is in oil and natural gas acquisition, exploration, development, and production. The Company’s operations are geographically concentrated in west Texas and southeast New Mexico.
As part of a corporate restructuring, in May 2021, Novo received 100% of Scala Energy Assets, LLC; Scala Energy Assets NM, LLC; Scala Energy Operating, LLC; Scala Energy Minerals, LLC; and Scala Energy, LLC (collectively, Scala Entities) from Scala Energy Holdings, LLC, a portfolio company of EnCap Energy Capital Fund X, L.P (Encap). The corporate restructuring represents a transaction from entities under common control due to common ownership by Encap. Accounting principles generally accepted in the United States of America (U.S. GAAP) requires retrospective combination of all of the entities for all of 2021 as if the corporate restructuring had been in effect for the entire period presented in these financial statements and related notes presented herein represent the combined consolidated results of operations and cash flows through December 31, 2021. There was no such transaction for the year ended December 31, 2022, and the entities were consolidated for the entirety of 2022.
A summary of the significant accounting policies consistently applied in the preparation of the accompanying financial statements follows.
Consolidation and basis of presentation – The accompanying audited combined consolidated financial statements have been prepared in accordance with U.S. GAAP. The accompanying combined consolidated financial statements include the accounts of the Company and its subsidiaries, which include the following:
• | Novo Oil & Gas, LLC |
• | Novo Fee Mineral, LLC |
• | Novo Oil and Gas Northern Delaware, LLC |
• | Novo Oil & Gas Texas, LLC |
• | Novo Minerals, LP |
• | Scala Energy Assets, LLC |
• | Scala Energy Assets NM, LLC |
• | Scala Energy Operating, LLC |
• | Scala Energy Minerals, LLC |
• | Scala Energy, LLC |
All significant intercompany balances and transactions have been eliminated in consolidation.
8
Novo Oil & Gas Holdings, LLC
Notes to Combined Consolidated Financial Statements
Cash and cash equivalents – Cash and cash equivalents consist of all demand deposits and funds invested in highly liquid instruments purchased with original maturities of three months or less. The Company maintains its cash in bank deposit accounts which, at times, may exceed federally insured limits. The Company has not experienced any losses in such accounts and believes it is not exposed to any significant credit risk on cash and cash equivalents.
Oil and natural gas property and equipment – The Company accounts for its oil and gas exploration and production activities using the successful efforts method of accounting. Under this method, costs to acquire mineral interests in oil and gas properties, to drill and equip exploratory wells which find proved reserves, and to drill and equip development wells are capitalized. At December 31, 2022 and 2021, the Company had $93,087,551 and $74,645,064, respectively, in capitalized development costs that were pending determination of economic reserves. If the Company determines that the wells do not find proved reserves, the costs are charged to expense. The costs of unproved leasehold interests determined to be proved are transferred to proved oil and natural gas properties. Geological and geophysical costs, delay rentals, and costs to drill exploratory wells which do not find proved reserves are expensed as incurred.
Upon the sale or retirement of oil and gas properties, the cost and related accumulated depreciation, depletion, and amortization and impairment are eliminated from the accounts, and the resulting gain or loss is recognized. On the sale of an entire interest in an unproved property for cash or cash equivalents, gain or loss is recognized to the extent of the difference between the proceeds received and the net carrying value of the property. Proceeds from sales of partial interests in unproved properties are accounted for as a recovery of costs unless the proceeds exceed the entire cost of the property. During 2022, the Company sold certain oil and gas properties for $105,976 and recorded a loss on sale of oil and gas properties of $59,979. During 2021, the Company sold certain oil and gas properties for $603,276 and recorded a loss on sale of oil and gas properties of $8,209,375.
Oil and natural gas properties consisted of the following at December 31:
2022 | 2021 | |||||||
Unproved mineral interests |
$ | 60,157,459 | $ | 81,428,206 | ||||
Proved mineral interests |
226,375,004 | 194,173,294 | ||||||
Wells and related equipment |
857,375,914 | 393,584,792 | ||||||
Total oil and gas property and equipment |
1,143,908,377 | 669,186,292 | ||||||
Accumulated depletion, depreciation, and amortization |
(212,079,300 | ) | (109,441,335 | ) | ||||
|
|
|
|
|||||
Total oil and gas property and equipment, net |
$ | 931,829,077 | $ | 559,744,957 | ||||
|
|
|
|
Depletion, depreciation, and amortization – Capitalized costs of proved oil and natural gas properties are depleted based on the unit-of-production method over total estimated proved reserves, and capitalized costs of wells and related equipment and facilities are depleted based on the unit-of-production method over estimated proved developed reserves. Gas is converted to equivalent barrels at the rate of six Mcf of gas to one barrel of oil equivalent. Capitalized drilling and equipment costs of producing oil and gas properties are amortized and charged to operations using the units-of-production method on a geological zone-by-zone basis based on estimated proved oil and gas reserves. Depletion, depreciation, and amortization expense for oil and natural gas properties amounted to $102,637,964 and $40,740,975 for the years ended December 31, 2022 and 2021, respectively.
9
Novo Oil & Gas Holdings, LLC
Notes to Combined Consolidated Financial Statements
The costs attributable to interests in unproved leaseholds, which the Company expects to retain for development or exploration, are classified separately in oil and gas properties. The impairment assessment for unproved leaseholds is affected by factors such as the results of exploration and development activities, commodity price projections, remaining lease terms, and potential shifts in business strategy. There were no such impairments of unproved leaseholds during the years ended December 31, 2022 and 2021.
The Company assesses impairment of its proved oil and gas properties primarily on a geological location and interest type, based on an analysis of undiscounted net cash flows. If undiscounted cash flows are insufficient to recover the net capitalized costs related to proved properties, then an impairment charge is recognized in income from operations equal to the difference between the net capitalized costs related to proved properties and their estimated fair values based on the present value of the related future net cash flows. There were no such impairments indicated during the years ended December 31, 2022 and 2021.
Other property and equipment – Other property and equipment consist primarily of office furniture and computer equipment, which are recorded at cost and are depreciated on the straight-line method over estimated useful lives of three to five years. Depreciation expense related to other property and equipment for the years ended December 31, 2022 and 2021 was $93,726 and $109,347, respectively.
Prepaid expenses and other – Prepaid expenses consist primarily of payments for insurance, rent, and various other items in the current year in exchange for services to be rendered in subsequent periods.
Income taxes – The Company is a nontaxable entity for U.S. federal income tax purposes with tax liabilities and/or benefits being passed on to its members. As such, no provision for federal income tax expense has been provided. Texas margin tax is assessed on a taxable margin apportioned to Texas. As the tax base for computing Texas margin tax is derived from an income-based measure, the Company has determined that the margin tax is an income tax. The Company has determined that the provision for Texas margin tax and the related deferred tax assets and liabilities were inconsequential as of December 31, 2022 and 2021, and for the years then ended.
Deferred income taxes represent the estimated future tax consequences of temporary differences, at enacted statutory rates, between the carrying amount of assets and liabilities in the Company’s financial statements and tax returns. The Company has reviewed its federal tax-exempt status, as well as other tax provisions, and determined no uncertain tax positions exist. No interest and penalties have been accrued or recorded.
Oil and gas operations
Accounts receivable – Oil and gas sales consist of crude oil and natural gas sales proceeds receivable from purchasers. Accounts receivable – joint interest owners consist of amounts due from joint interest partners for drilling, completion, and operating costs. Accounts receivable are due within 30 to 60 days of production. No interest is charged on past-due balances. Payments made on all accounts receivable are applied to the earliest unpaid items. Management reviews accounts receivable periodically and reduces the carrying amount by a valuation allowance that reflects the estimate of the amount that may not be collectible. No such allowance was considered necessary at December 31, 2022 and 2021.
10
Novo Oil & Gas Holdings, LLC
Notes to Combined Consolidated Financial Statements
Undistributed revenues – Undistributed revenues represent amounts collected from purchasers for oil, natural gas liquids, and gas sales due to other revenue interest owners. Generally, the Company is required to remit amounts due under these liabilities within 60 days of the end of the month in which the related production occurred.
Production costs – Production costs, including lease operating expenses, production taxes, and gathering, transportation, and marketing costs, are expensed as incurred and included in operating costs and expenses on the combined consolidated statements of operations.
Advances from joint interest partners – Advances from joint interest partners consist of funds received from working interest owners by the Company to pay for their ownership share of future development of oil and gas properties.
Asset retirement obligations – Asset retirement obligations relate to future plugging and abandonment expenses on oil and gas properties. The Company records such obligations at fair value on the date incurred, using significant unobservable inputs, including estimates of current plugging and abandonment expenses, inflation rates, credit-adjusted, risk-free rates, and anticipated timing of cash flows. At least, annually, the Company reassesses the obligation to determine whether a change in estimated obligation is necessary. The Company evaluates whether there are indicators that suggest that estimated cash flows underlying the obligation have materially changed. Should those indicators suggest the estimated obligation has materially changed, the Company will update its assessment accordingly. As a result of the Company’s assessment in 2022, the estimated asset retirement obligation was increased by $636,756 due to a change in the plugging estimated cost. As a result of the Company’s assessment in 2021, the estimated asset retirement obligation was decreased by $406,901 due to a change in the plugging estimated cost. Given the unobservable nature of the inputs, the initial recognition of an asset retirement obligation is a non-recurring Level 3 fair value measurement.
The following table describes the changes in asset retirement obligation for the years ended December 31, 2022 and 2021:
2022 | 2021 | |||||||
Asset retirement obligation, beginning of period |
$ | 1,034,668 | $ | 1,030,714 | ||||
Liabilities incurred |
915,276 | 380,822 | ||||||
Liabilities sold |
— | (41,254 | ) | |||||
Change of estimate |
636,756 | (406,901 | ) | |||||
Accretion of discount |
118,987 | 71,287 | ||||||
|
|
|
|
|||||
Asset retirement obligation, end of period |
$ | 2,705,687 | $ | 1,034,668 | ||||
|
|
|
|
The use of estimates in preparing financial statements – In preparing financial statements, accounting principles generally accepted in the United States of America require management to make estimates and assumptions that affect the amounts reported in the financial statements and accompanying notes. Significant assumptions are required in the estimates of proved crude oil and natural gas reserves and related estimates of the present value of future net revenues, asset retirement obligations, and valuation of commodity derivative contracts. It is at least reasonably possible these estimates could be revised in the near term, and these revisions could be material.
11
Novo Oil & Gas Holdings, LLC
Notes to Combined Consolidated Financial Statements
Derivative financial instruments – The Company utilizes commodity derivative contracts to manage risks associated with exposure to fluctuations in commodity price for oil, natural gas, and natural gas liquids, which have historically been volatile. The Company’s derivative activities are conducted with major commercial institutions or investment banks. The Company believes these entities present minimal credit risks. The Company does not enter into derivatives for speculative purposes.
Settlements of gains and losses on derivative financial instruments have been realized monthly and reported as a component of other income and expense in the combined consolidated statements of operations and operating cash flows in the period realized.
The Company records all derivative instruments on the balance sheet at fair value. Changes in the derivative’s fair value are recognized in other income and expense in the combined consolidated statements of operations.
Financial instruments and fair value – The carrying amounts of financial instruments, including cash and cash equivalents, accounts receivable, accounts payable, undistributed revenues, advances from joint partners, and accrued liabilities approximate fair values as of December 31, 2022 and 2021. The carrying values of our borrowings under the revolving credit facility approximate fair value, as these are subject to short-term floating interest rates that approximate the rates available to us for those periods. Derivative financial instruments are recorded at their fair values.
Financial assets and liabilities, which are recorded at fair value are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. In general, fair values determined by Level 1 inputs utilize quoted prices (unadjusted) in active markets of identical assets or liabilities. Fair values determined by Level 2 inputs utilize data points that are observable such as quoted prices, interest rates, and yield curves. Fair values determined by Level 3 inputs are unobservable data points for the asset or liability and include situations where there is little, if any, market activity for the asset or liability. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the estimate of fair value of the assets or liabilities and their placement within the fair value hierarchy levels. The following table sets forth by level, within the fair value hierarchy, the Company’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of December 31, 2022 and 2021:
December 31, 2022 | ||||||||||||||||
Level 1 | Level 2 | Level 3 | Fair Value | |||||||||||||
Commodity derivative asset, current (Note 5) |
$ | — | $ | 37,692,443 | $ | — | $ | 37,692,443 | ||||||||
Commodity derivative asset, long-term (Note 5) |
— | 2,474,020 | — | 2,474,020 | ||||||||||||
Commodity derivative liability, current (Note 5) |
— | (5,062,877 | ) | — | (5,062,877 | ) | ||||||||||
Commodity derivative liability, long-term (Note 5) |
— | (4,904,914 | ) | — | (4,904,914 | ) | ||||||||||
|
|
|
|
|
|
|
|
|||||||||
Total |
$ | — | $ | 30,198,672 | $ | — | $ | 30,198,672 | ||||||||
|
|
|
|
|
|
|
|
|||||||||
December 31, 2021 | ||||||||||||||||
Level 1 | Level 2 | Level 3 | Fair Value | |||||||||||||
Commodity derivative liability, current (Note 5) |
$ | — | $ | (9,517,796 | ) | $ | — | $ | (9,517,796 | ) | ||||||
Commodity derivative liability, long-term (Note 5) |
— | (3,441,119 | ) | — | (3,441,119 | ) | ||||||||||
|
|
|
|
|
|
|
|
|||||||||
Total |
$ | — | $ | (12,958,915 | ) | $ | — | $ | (12,958,915 | ) | ||||||
|
|
|
|
|
|
|
|
12
Novo Oil & Gas Holdings, LLC
Notes to Combined Consolidated Financial Statements
The fair value of the commodity derivatives is valued using Level 2 fair value methodologies. The Partnership is able to value the assets and liabilities based on observable market data for similar instruments. This observable data includes the forward curve for commodity prices based on quoted market prices. Assets and liabilities accounted for at fair value on non-recurring basis in accordance with Level 3 of the fair value hierarchy include the potential impairment of oil and gas properties.
Concentration of credit risk – Three customers accounted for 77% of the Company’s oil and natural gas sales for the year ended December 31, 2022. At December 31, 2021, 72% of the Company’s oil and natural gas sales related to three customers. The Company does not believe that the loss of these purchasers would have a material adverse effect on the Company’s results of operations or cash flows as it believes it could readily locate other purchasers.
The Company’s financial condition, results of operations, and capital resources are highly dependent upon the prevailing market prices of, and supply and demand for, crude oil and natural gas. These commodity prices are subject to wide fluctuations and market uncertainties due to a variety of factors that are beyond the Company’s control. These factors include the level of global and regional supply and demand for the petroleum products, the establishment of and compliance with production quotas by oil exporting countries, weather conditions, the price and availability of alternative fuels, and overall economic conditions, both foreign and domestic. The Company cannot predict future oil and natural gas prices with any degree of certainty.
Sustained weakness in oil and natural gas prices may adversely affect the financial condition and results of operations and may also reduce the amount of net oil and natural gas reserves the Company can produce economically. Similarly, any improvement in oil and natural gas prices can have a favorable impact on the Company’s financial condition, results of operations, and capital resources.
Newly adopted accounting pronouncements – In February 2016, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) No. 2016-02, Leases (Topic 842), which, together with its related clarifying ASUs (collectively, Accounting Standards Codification 842 or ASC 842), amended the previous guidance for lease accounting and related disclosure requirements. The new guidance requires the recognition of right-of-use (ROU) assets and lease liabilities on the combined consolidated balance sheets for lease with terms greater than 12 months or leases that contain a purchase option that is reasonably certain to be exercised. Lessees are required to classify leases as either finance or operating leases, which will determine whether lease expense is recognized based on an effective interest method or a straight-line basis over the term of the lease. For leases with a term of 12 months or less, a lessee can make an accounting policy election by class of underlying asset to not recognize an asset and corresponding liability. Lessees are also required to provide additional qualitative and quantitative disclosures regarding the amount, timing, and uncertainty of cash flows arising from leases. Effective January 1, 2022, the Company adopted ASC 842 using the modified retrospective method, meaning it has been applied to leases that existed or have been entered into on or after January 1, 2022. See Note 9 Leases for further discussion of the adoption and the impact on the Company’s combined consolidated financial statements.
13
Novo Oil & Gas Holdings, LLC
Notes to Combined Consolidated Financial Statements
Note 2 – Revenue Recognition
Oil revenues – The Company sells oil production to customers at the Company’s lease locations or other contractually defined delivery locations. Revenue is recognized when control transfers to the customer upon delivery to the contractually agreed-upon delivery point at which the customer takes custody, title, and risk of loss of the product. Revenue is recorded based on contract pricing terms, which reflect prevailing market prices, net of any contractual pricing differentials. Oil revenues are recognized during the month in which control transfers to the customer, and it is probable the Company will collect the consideration it is entitled to receive. Proceeds from oil sales are generally received within one month after the month in which a sale has occurred.
Natural gas liquids (NGLs) and gas sales – The Company sells the majority of its natural gas and NGLs to midstream customers at the inlet of the midstream entity’s gathering system or other contractual delivery point. The midstream entity gathers, processes, and remits proceeds to the Company for the resulting sale of NGLs and residue gas. Under these arrangements, the midstream customers obtain control of the unprocessed gas stream at the inlet of the gathering system or other contractual delivery point, and revenues from each sale are determined using contractually agreed pricing formulas which contain multiple components. Pricing formulas for sales of gas and NGLs to midstream entities include the volume and BTU content of the gas and liquid products sold, and the midstream customer’s proceeds from the sale of residue gas and NGLs at secondary downstream markets. The Company has concluded that the midstream entities are the customer, and revenues are recognized net of pricing adjustments applied by the midstream customer during the month in which control transfers to the customer at the delivery point, and it is probable the Company will collect the consideration it is entitled to receive. Natural gas sales proceeds are generally received within one month after the month in which a sale has occurred.
Non-operated oil, gas, and NGLs revenue – The Company’s proportionate share of production from properties operated by unrelated third parties is generally marketed at the discretion of the third-party operators. For these properties, the Company receives a net payment from the operator representing its proportionate share of sales proceeds, which is net of costs incurred by the operator, if any. Such non-operator revenues are recognized at the net amount of proceeds to be received by the Company during the month in which production occurs, and it is probable the Company will collect the consideration it is entitled to receive. Proceeds are generally received by the Company within two to three months after the month in which production occurs.
Deferred upfront proceeds recognition – During 2018, the Company received upfront proceeds of $35,000,000 for entering into an agreement in which the Company provided acreage dedications to a midstream service provider for gathering, processing, transportation, and the sale and marketing of hydrocarbons (Midstream Proceeds Agreement).
The Company ratably recognized upfront proceeds over the 15-year term of the agreement. For the years ending December 31, 2022 and 2021, the Company recognized $2,333,333 in upfront proceeds related to the Midstream Proceeds Agreement, which has been included in other income and expense in the combined consolidated statements of operations.
At December 31, 2022 and 2021, the Company had $2,333,333 recorded as deferred upfront proceeds, current and $22,361,111 and $24,694,445 recorded as deferred upfront proceeds, non-current, respectively, in the combined consolidated balance sheets.
14
Novo Oil & Gas Holdings, LLC
Notes to Combined Consolidated Financial Statements
Note 3 – Acquisitions
On May 7, 2021, through the issuance of additional membership interests, Novo completed the acquisition of 100% of the outstanding membership interests in the Scala Entities. All entities involved in the acquisition are under common control and the net assets were recorded using the historical book value of the Scala Entities at the date of the acquisition. The excess historical book value acquired is treated as an equity transaction. The following table summarizes the assets, liabilities, and excess historical book value amounts related to the acquisition:
Historical book value of assets acquired |
||||
Cash and cash equivalents |
$ | 3,599,671 | ||
Accounts receivable |
16,653,399 | |||
Prepaid expenses and other assets |
37,465 | |||
Commodity derivative assets |
365,197 | |||
Oil and gas properties, net |
202,007,510 | |||
Other property and equipment, net |
39,923 | |||
|
|
|||
Total historical book value of assets acquired |
222,703,165 | |||
|
|
|||
Historical book value of liabilities acquired |
||||
Accounts payable |
1,936,794 | |||
Accrued liabilities |
4,507,893 | |||
Revenue payable |
4,063,004 | |||
Commodity derivative liabilities |
4,370,806 | |||
Deferred revenue |
29,361,111 | |||
Long-term debt, net |
19,895,745 | |||
Asset retirement obligation |
949,890 | |||
|
|
|||
Total historical book value of liabilities acquired |
65,085,243 | |||
|
|
|||
Excess historical book value |
||||
Contributed capital |
$ | 157,617,922 | ||
|
|
ASC Section 805-50 addresses accounting for common control transactions. The acquisitions represent acquisitions of entities under common control. The combined consolidated financial statements of the Company report the operations for the year ended December 31, 2021, as though the combination of the Scala Entities had always been in effect. The following table summarizes the revenues and expenses included in the Company’s combined consolidated statements of operations from the acquisitions:
Revenues |
$ | 69,352,097 | ||
Operating costs and expenses |
(29,241,017 | ) | ||
Other expense, net |
(6,801,445 | ) | ||
|
|
|||
Net income (loss) |
$ | 33,309,635 | ||
|
|
15
Novo Oil & Gas Holdings, LLC
Notes to Combined Consolidated Financial Statements
Note 4 – Employee Benefit Plan
In November 2016, the Company established a 401(k) retirement plan for all employees. The Company matches employee contributions 100%, up to the 4% of each employee’s gross wages, limited to eligible compensation. Contributions made by the Company totaled $140,915 and $111,322 for the years ended December 31, 2022 and 2021, respectively. Additionally, the Company awarded discretionary 401(k) bonus contributions of $341,878 and $247,012 and for the years ended December 31, 2022 and 2021, respectively.
Note 5 – Derivatives
The following is a summary of the Company’s crude oil and natural gas commodity derivatives at December 31, 2022 and 2021. Oil derivative volumes are measured in barrels of oil (BBls) and natural gas volumes are measured in million British Thermal Units (MMBTU).
December 31, 2022 |
||||||||||||||||||||||||
Period |
Instrument | Commodity | Total Volumes |
Floor | Ceiling | Fair Value | ||||||||||||||||||
Jan 2023 - June 2023 |
Swap | WTI | 269,000 | $ | 88.28 | $ | — | $ | 2,929,647 | |||||||||||||||
Mar 2023 - Dec 2023 |
Swap | WTI | 132,000 | $ | 79.95 | $ | — | $ | 561,159 | |||||||||||||||
Jan 2023 - Dec 2023 |
Swap | WTI | 1,450,500 | $ | 77.69 | $ | — | $ | 10,971,675 | |||||||||||||||
Jan 2023 - Dec 2024 |
Swap | WTI | 720,000 | $ | 71.35 | $ | — | $ | 995,685 | |||||||||||||||
Jan 2024 - June 2024 |
Swap | WTI | 293,000 | $ | 83.72 | $ | — | $ | 4,148,064 | |||||||||||||||
Jan 2024 - Dec 2024 |
Swap | WTI | 173,000 | $ | 74.08 | $ | — | $ | 439,263 | |||||||||||||||
Jan 2024 - Mar 2024 |
Swap | NG | 450,000 | $ | 5.46 | $ | — | $ | 267,088 | |||||||||||||||
April 2023 - Dec 2025 |
Swap | NG | 5,755,000 | $ | 4.71 | $ | — | $ | 2,601,513 | |||||||||||||||
Jan 2023 - June 2023 |
Collar | WTI | 312,000 | $ | 52.00 | $ | 64.00 | $ | (5,710,198 | ) | ||||||||||||||
Jan 2023 - Feb 2023 |
Put | WTI | 248,000 | $ | 82.00 | $ | — | $ | 1,177,575 | |||||||||||||||
Jan 2023 - Mar 2023 |
Collar | NG | 5,403,000 | $ | 3.50 | $ | 13.25 | $ | 10,361,734 | |||||||||||||||
Jan 2023 - June 2023 |
Collar | NG | 2,030,000 | $ | 2.40 | $ | 3.44 | $ | (2,147,840 | ) | ||||||||||||||
April 2023 - Oct 2023 |
Collar | NG | 3,940,000 | $ | 4.00 | $ | 6.20 | $ | 1,865,012 | |||||||||||||||
April 2023 - June 2024 |
Collar | NG | 2,870,000 | $ | 4.00 | $ | 6.42 | $ | 1,178,925 | |||||||||||||||
Nov 2023 - June 2024 |
Collar | NG | 4,110,000 | $ | 4.00 | $ | 6.43 | $ | 962,269 | |||||||||||||||
Jan 2024 - Mar 2024 |
Collar | NG | 1,800,000 | $ | 4.00 | $ | 10.00 | $ | 138,790 | |||||||||||||||
April 2023 - Dec 2025 |
Collar | NG | 5,755,000 | $ | 4.00 | $ | 5.75 | $ | 1,721,172 | |||||||||||||||
Period |
Instrument | Commodity | Total Volumes |
Price | Fair Value | |||||||||||||||||||
Jan 2023 |
Basis Swap | NG | 1,085,000 | $ | (0.22 | ) | $ | (232,344 | ) | |||||||||||||||
Jan 2023 - Mar 2023 |
Basis Swap | NG | 135,000 | $ | (0.79 | ) | 56,934 | |||||||||||||||||
Jan 2023 - Mar 2023 |
Basis Swap | NG | 518,000 | $ | (1.34 | ) | (88,865 | ) | ||||||||||||||||
Jan 2023 - Mar 2023 |
Basis Swap | NG | 1,493,250 | $ | (1.05 | ) | 191,878 | |||||||||||||||||
Jan 2023 - Mar 2023 |
Basis Swap | NG | 1,430,000 | $ | (1.36 | ) | (314,944 | ) | ||||||||||||||||
Jan 2023 - Mar 2023 |
Basis Swap | NG | 876,750 | $ | (1.07 | ) | 97,682 | |||||||||||||||||
Jan 2023 - Dec 2025 |
Basis Swap | NG | 9,309,625 | $ | (2.14 | ) | (1,377,479 | ) | ||||||||||||||||
Jan 2023 - Dec 2025 |
Basis Swap | NG | 9,309,625 | $ | (2.05 | ) | (580,274 | ) | ||||||||||||||||
Jan 2023 - June 2023 |
Basis Swap | WTI | 312,000 | $ | 0.45 | (15,448 | ) | |||||||||||||||||
|
|
|||||||||||||||||||||||
Total |
$ | 30,198,672 | ||||||||||||||||||||||
|
|
16
Novo Oil & Gas Holdings, LLC
Notes to Combined Consolidated Financial Statements
December 31, 2021 |
||||||||||||||||||||||||
Period |
Instrument | Commodity | Total Volumes |
Floor | Ceiling | Fair Value | ||||||||||||||||||
Jan 2022 - Dec 2022 |
Swap | WTI | 96,000 | $ | 60.77 | $ | — | $ | (1,125,600 | ) | ||||||||||||||
Jan 2022 - Dec 2022 |
Collar | WTI | 514,000 | $ | 58.43 | $ | 64.86 | (4,413,865 | ) | |||||||||||||||
Jan 2022 - June 2023 |
Collar | WTI | 312,000 | $ | 54.34 | $ | 62.18 | (2,379,049 | ) | |||||||||||||||
Jan 2022 - Dec 2022 |
Collar | NG | 6,928,000 | $ | 2.62 | $ | 3.18 | (3,978,331 | ) | |||||||||||||||
Jan 2022 - June 2023 |
Collar | NG | 2,030,000 | $ | 2.48 | $ | 3.21 | (1,062,070 | ) | |||||||||||||||
|
|
|||||||||||||||||||||||
Total |
$ | (12,958,915 | ) | |||||||||||||||||||||
|
|
The Company realized a commodity derivative loss of $49,741,750 and $22,074,250 as of December 31, 2022 and 2021, respectively. Because the Company does not apply hedge accounting treatment to its derivative contracts, the changes in fair value of these contracts are recognized in income in the period of change. The Company recorded an unrealized gain of $39,416,737 as of December 31, 2022 and an unrealized loss of $8,953,305 as of December 31, 2021, from changes in fair market value. Unrealized gains and losses, at fair value, are recorded on the Company’s combined consolidated balance sheets as current or non-current asset and liabilities based on the anticipated timing of settlements under the related contracts, under the caption “commodity derivatives.”
Note 6 – Revolving Credit Facility
On June 20, 2018, Scala Energy Holdings, LLC and Subsidiaries entered into a $750,000,000 credit facility. The credit facility was extinguished at the time of the restructure and the full outstanding balance of $20,166,667, plus accrued interest of $14,509 was paid off.
On July 13, 2021, the Company entered into a senior secured revolving credit facility with a bank with a maximum commitment of $500,000,000 and with an initial borrowing base of $95,000,000. The revolving credit facility has semi-annual borrowing base redeterminations on May 1 and November 1 each year commencing on November 1, 2021. On May 20, 2022, the borrowing base was increased to $125,000,000 and on September 20, 2022, the borrowing base increased to $400,000,000. As of December 31, 2022, the Company had $250,000,000 of outstanding borrowings out of a borrowing base of $400,000,000. The Company pledged substantially all of its oil and gas properties and other assets as collateral to secure amounts outstanding under the revolving credit facility.
17
Novo Oil & Gas Holdings, LLC
Notes to Combined Consolidated Financial Statements
Interest on the revolving credit facility is either (i) Base Rate, plus a margin between 2% and 3% or (ii) the adjusted London Inter-Bank Offered Rate (LIBOR), plus a margin between 3% and 4%. The annual commitment fee on the unused portion of the revolving credit facility is between 0.375% to 0.50%. At December 31, 2022 and 2021, the interest rate on the revolving credit facility was 6.95% and 3.50%, respectively. The revolving credit facility contains representations, warranties, covenants, conditions, and defaults customary for transactions of this type, including but not limited to (i) limitations on liens and incurrence of debt covenants; (ii) limitations on the sale of property, mergers, consolidations, and other similar transactions covenants; (iii) limitations on investments, loans and advances covenants; and (iv) limitations on dividends, distributions, redemptions, and restricted payments covenants. The revolving credit facility also contains financial covenants requiring the Company to comply with a consolidated leverage ratio, as of the last day of any fiscal quarter commencing June 30, 2021, to be greater than 3.25 to 1.0 and a current ratio, as of the last day of any fiscal quarter commencing June 30, 2021, to not be less than 1.0 to 1.0. Novo was in compliance with terms and covenants of the revolving credit facility as of December 31, 2022.
Note 7 – Members’ Equity
At the inception of the Company, the Company authorized three classes of membership interests consisting of Class A units, Class B units, and Class C units. These membership interests are differentiated by ownership, voting rights, capital contribution requirements, and payout treatment. Income and loss allocations and dividend distributions are payable first to Class A Members and Class B Members in proportion to their aggregate capital contributions until they have received an amount equal to their aggregate capital contribution, plus a return on those capital contributions. Any remaining income or distributions are made in accordance with the Agreement of the Company. There have been $251,189,645 and $27,503,523 in distributions through December 31, 2022 and 2021, respectively. On May 29, 2019, the Company amended the LLC and Unit Purchase Agreements, which increased Encap’s equity commitment from $196,000,000 to $294,000,000 and management’s equity commitment from $4,000,000 to $6,000,000 and increased Class A units from 1,960,000 to 2,940,000 and Class B units from 40,000 to 60,000, respectively.
On May 7, 2021, Novo issued 250,000 Series A units to Encap in exchange for 100% of the membership interests in the Scala Entities. Additionally, Novo entered into the 2nd amendment of its LLC agreement, which increased Encap’s commitment amount from $294,000,000 to $417,000,000 and increased Class A units from 2,940,000 to 4,170,000. At this time, management also contributed an additional $510,204 for 5,102 Class B units.
As of December 31, 2022 and 2021, 4,170,175 Class A units, 80,000 Class B units, and 100,000 Class C units were authorized. The Class A and Class B units are authorized to be issued at $100 per unit. Class C units are non-voting units and to date have been granted to certain members of management. Founding management members’ units have a vesting period of four years from the grant date, and other Class C unit holders fully vest immediately prior to the consummation of a transaction that will result in an exit event. In all cases, the Class C unit grants were determined to have a minimal value on grant date. At December 31, 2022 and 2021, the Company had issued 3,092,175 Class A units, 63,106 Class B units, and 100,000 Class C units.
18
Novo Oil & Gas Holdings, LLC
Notes to Combined Consolidated Financial Statements
Note 8 – Commitments and Contingencies
As of December 31, 2022 and 2021, the Company was a party to a noncancelable lease for office space in Oklahoma City, Oklahoma, which expired on July 31, 2022. Rent expense for the year ended December 31, 2021, was approximately $242,986. For the year 2022, under ASC 840, the approximate future minimum lease payment under the lease is approximately $144,480.
Due to the nature of the oil and natural gas business, the Company is exposed to possible environmental risks. The Company has implemented various policies and procedures to avoid environmental contamination and risks from environmental contamination. The Company has historically not experienced any significant environmental liability and is not aware of any potential material environmental issues or claims that existed at December 31, 2022 and 2021.
During March and April of 2022, the Company entered into two drilling agreements with third party providers for a one-year period which included early termination penalties.
Note 9 – Leases
On January 1, 2022, the Company adopted ASU 2016-02, which requires the recognition of right-of-use assets and lease liabilities on the combined consolidated balance sheets for leases with terms greater than 12 months. The Company elected to utilize the package of practical expedients in ASC 842-10-65-1(f) that, upon adoption of ASU 2016-02, allowed entities to (1) not reassess whether any expired or existing contracts are or contain leases, (2) retain the classification of leases (e.g., operating or finance lease) existing as of the date of adoption, and (3) not reassess initial direct costs for any existing lease. Accordingly, adoption of the new standard resulted in recording an operating lease ROU asset and operating lease liability of $393,286 on the combined consolidated balance sheets as of January 1, 2022. Adoption of the standard did not have an impact on the Company’s beginning members’ capital, results from operations, or cash flows.
Operating lease ROU assets represent the Company’s right to use an underlying asset for the lease term, and lease liabilities represent the Company’s obligation to make lease payments arising from the lease. ROU assets and lease liabilities are recognized at the lease commencement date based on the estimated present value of lease payments over the lease term. The Company uses its estimated incremental borrowing rate based on the information available at the lease commencement date in determining the present value of future payments. The operating lease ROU asset also includes any upfront lease payments made and excludes lease incentives and initial direct costs incurred. The Company has elected the practical expedients allowing (1) the short-term lease recognition exemption whereby ROU assets and lease liabilities will not be recognized for leasing arrangements with terms less than one year and (2) the combination of lease and non-lease components and expensing variable payments as rent/lease expense in the period incurred.
The Company leases office space under a non-cancelable operating lease with an original lease term of four years. The lease has one renewal option at the election of the Company to extend the lease for an additional year. The lease renewal option is included in the expected lease term as the Company determined it was reasonably certain to exercise the renewal option upon adoption. The Company does not have any finance leases.
19
Novo Oil & Gas Holdings, LLC
Notes to Combined Consolidated Financial Statements
Lease expenses are included in general and administrative expense on the combined consolidated statements of operations and include the following components for the year ended December 31, 2022:
Year Ended | ||||
Lease Expenses |
December 31, 2022 | |||
Operating lease cost |
$ | 252,480 | ||
Variable lease cost |
— | |||
Short-term lease costs |
2,080,849 | |||
Lease costs capitalized in proved oil & gas properties |
14,120,442 | |||
|
|
|||
Total lease cost |
$ | 16,453,770 | ||
|
|
Supplemental information related to the Company’s leases for the year ended December 31, 2022 was as follows:
Cash paid for operating leases |
$ | 252,480 | ||
Right-of-use assets obtained in exchange for new operating lease liabilities |
$ | 393,286 | ||
Weighted-average remaining lease term - operating leases |
0.58 years | |||
Weighted-average discount rate - operating leases |
3.50% |
The total future minimum lease payments under non-cancelable operating leases as of December 31, 2022 were as follows:
Year Ended December 31, |
Operating Leases | |||
2023 |
$ | 151,321 | ||
2024 |
— | |||
2025 |
— | |||
|
|
|||
Total future minimum lease payments |
151,321 | |||
Less imputed interest |
(1,751 | ) | ||
|
|
|||
Present value of lease liabilities |
$ | 149,570 | ||
|
|
Note 10 – Subsequent Events
Management has evaluated the effects of subsequent events for inclusion and disclosure in the accompanying combined consolidated financial statements through March 31, 2023, the date the accompanying combined consolidated financial statements were available to be issued and is not aware of any subsequent events that would have a material impact on the accompanying combined consolidated financial statements, other than those which have already been disclosed.
During January, February, and March 2023, the Company made distributions to members for a total of $110,000,000 and made additional borrowings on its revolving credit facility of $60,000,000.
20
Supplementary Information
Novo Oil & Gas Holdings, LLC
Supplemental Schedules about Oil and Natural Gas Producing Properties
(Unaudited)
Costs Incurred
The following tables reflect the costs incurred in oil and gas property acquisition, exploration, and development activities (in thousands):
Years Ended December 31, | ||||||||
2022 | 2021 | |||||||
Property acquisition costs |
||||||||
Proved properties |
$ | 800 | $ | — | ||||
Unproved properties |
10,307 | 10,364 | ||||||
Exploration costs |
174,200 | 24,475 | ||||||
Development costs |
286,268 | 109,923 | ||||||
|
|
|
|
|||||
Total costs incurred |
$ | 471,575 | $ | 144,762 | ||||
|
|
|
|
|||||
Capitalized Costs
Capitalized costs, impairment, and depreciation, depletion and amortization relating to the Company’s oil and gas producing activities, all of which are conducted within the continental United States as of December 31, 2022 and 2021, are summarized below (in thousands):
Years Ended December 31, | ||||||||
2022 | 2021 | |||||||
Oil and natural gas properties, successful efforts method: |
||||||||
Proved properties |
$ | 1,083,345 | $ | 587,487 | ||||
Accumulated impairment of proved properties |
— | — | ||||||
|
|
|
|
|||||
Proved properties, net of accumulated impairments |
1,083,345 | 587,487 | ||||||
Unproved properties |
60,158 | 81,428 | ||||||
Accumulated impairment of unproved properties |
— | — | ||||||
|
|
|
|
|||||
Unproved properties, net of accumulated impairments |
60,158 | 81,428 | ||||||
|
|
|
|
|||||
Total oil and gas properties, net of accumulated impairments |
1,143,503 | 668,915 | ||||||
Accumulated depreciation, depletion and amortization |
(212,079 | ) | (109,441 | ) | ||||
|
|
|
|
|||||
Net oil and gas properties |
$ | 931,424 | $ | 559,474 | ||||
|
|
|
|
22
Novo Oil & Gas Holdings, LLC
Supplemental Schedules about Oil and Natural Gas Producing Properties
(Unaudited)
Results of Operations
The following table presents the results of operations of crude oil, natural gas, and NGL producing activities (excluding corporate overhead and interest costs) for the periods indicated (in thousands):
Years Ended December 31, | ||||||||
2022 | 2021 | |||||||
Revenues: |
||||||||
Crude oil, natural gas, and NGL sales, net |
$ | 663,540 | $ | 207,897 | ||||
Production costs: |
||||||||
Lease operating and workover expenses |
45,326 | 22,143 | ||||||
Exploration expense |
808 | 572 | ||||||
Severance taxes |
48,969 | 12,205 | ||||||
|
|
|
|
|||||
Total production costs |
95,103 | 34,920 | ||||||
Other costs: |
||||||||
Depletion, depreciation, and amortization expense |
102,732 | 40,850 | ||||||
Accretion of asset retirement obligation |
119 | 71 | ||||||
|
|
|
|
|||||
Total other costs |
102,851 | 40,921 | ||||||
|
|
|
|
|||||
Results of operations |
$ | 465,586 | $ | 132,056 | ||||
|
|
|
|
Net Proved Crude Oil, NGLs, and Natural Gas Reserves
For the years ended December 31, 2022 and 2021, the Company utilized Netherland, Sewell and Associates, Inc. in the preparation of its oil and gas reserves. In accordance with Securities and Exchange Commission (SEC) regulations, the reserves as of December 31, 2022 and 2021 were estimated using realized prices, which reflect adjustments to the benchmark prices for quality, certain transportation fees, geographical differentials, marketing bonuses or deductions and other factors affecting the price received at the delivery point. The Company’s reserves are reported in three streams: crude oil, natural gas, and NGLs.
The SEC has defined proved reserves as the estimated quantities of crude oil, natural gas, and NGLs that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. The process of estimating crude oil, natural gas, and NGLs reserves is complex, requiring significant decisions in the evaluation of available geological, geophysical, engineering, and economic data. The data for a given property may also change substantially over time as a result of numerous factors, including additional development activity, evolving production history and a continual reassessment of the viability of production under changing economic conditions. As a result, material revisions to existing reserve estimates occur from time to time. Although every reasonable effort is made to ensure that reserve estimates reported represent the most accurate assessments possible, the subjective decisions and variances in available data for various properties increase the likelihood of significant changes in these estimates. If such changes are material, they could significantly affect future amortization of capitalized costs and result in impairment of assets that may be material.
23
Novo Oil & Gas Holdings, LLC
Supplemental Schedules about Oil and Natural Gas Producing Properties
(Unaudited)
The following tables provide an analysis of the changes in estimated proved reserve quantities of crude oil, natural gas, and NGLs for the years ended December 31, 2022 and 2021, all of which are located within the United States:
Year Ended December 31, 2022 | ||||||||||||||||
Crude Oil (Bbl) |
Natural Gas (Mcf) |
Liquids (Bbl) |
Total Boe |
|||||||||||||
Proved reserves as of December 31, 2021 |
35,782 | 379,080 | 41,584 | 140,546 | ||||||||||||
Revisions of previous estimates |
(3,780 | ) | (44,852 | ) | 8,128 | (3,128 | ) | |||||||||
Extensions, discoveries, and other additions |
8,253 | 34,949 | 6,516 | 20,594 | ||||||||||||
Production |
(3,953 | ) | (30,523 | ) | (4,455 | ) | (13,495 | ) | ||||||||
Sales of minerals in place |
— | — | — | — | ||||||||||||
Purchase of minerals in place |
125 | 1,649 | 252 | 652 | ||||||||||||
|
|
|
|
|
|
|
|
|||||||||
Proved reserves as of December 31, 2022 |
36,427 | 340,303 | 52,025 | 145,169 | ||||||||||||
|
|
|
|
|
|
|
|
|||||||||
Proved developed reserves |
||||||||||||||||
Beginning of year |
7,730 | 99,217 | 10,606 | 34,872 | ||||||||||||
End of year |
22,003 | 242,252 | 35,565 | 97,944 | ||||||||||||
Proved undeveloped reserves |
||||||||||||||||
Beginning of year |
28,052 | 279,863 | 30,978 | 105,674 | ||||||||||||
End of year |
14,424 | 98,051 | 16,460 | 47,225 | ||||||||||||
Year Ended December 31, 2021 | ||||||||||||||||
Crude Oil (Bbl) |
Natural Gas (Mcf) |
Liquids (Bbl) |
Total Boe |
|||||||||||||
Proved reserves as of December 31, 2020 |
16,708 | 216,187 | 25,114 | 77,852 | ||||||||||||
Revisions of previous estimates |
(266 | ) | 27,573 | 914 | 5,244 | |||||||||||
Extensions, discoveries, and other additions |
20,990 | 150,003 | 17,108 | 63,099 | ||||||||||||
Production |
(1,646 | ) | (14,339 | ) | (1,525 | ) | (5,561 | ) | ||||||||
Sales of minerals in place |
(4 | ) | (344 | ) | (27 | ) | (88 | ) | ||||||||
Purchase of minerals in place |
— | — | — | — | ||||||||||||
|
|
|
|
|
|
|
|
|||||||||
Proved reserves as of December 31, 2021 |
35,782 | 379,080 | 41,584 | 140,546 | ||||||||||||
|
|
|
|
|
|
|
|
|||||||||
Proved developed reserves |
||||||||||||||||
Beginning of year |
5,547 | 71,972 | 8,064 | 25,606 | ||||||||||||
End of year |
7,730 | 99,217 | 10,606 | 34,872 | ||||||||||||
Proved undeveloped reserves |
||||||||||||||||
Beginning of year |
11,161 | 144,215 | 17,050 | 52,246 | ||||||||||||
End of year |
28,052 | 279,863 | 30,978 | 105,674 |
For the year ended December 31, 2022, extensions, discoveries, and other additions resulted from the addition of five proved undeveloped locations for 4,407 Boe and 16,187 Boe from 20 new wells drilled.
24
Novo Oil & Gas Holdings, LLC
Supplemental Schedules about Oil and Natural Gas Producing Properties
(Unaudited)
For the year ended December 31, 2021, extensions, discoveries, and other additions resulted from the addition of 44 proved undeveloped locations for 62,035 Boe and 1,064 Boe from eight new wells drilled.
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Crude Oil, NGLs, and Natural Gas Reserves
The standardized measure of discounted future net cash flows does not purport to be, nor should it be interpreted to present, the fair value of the oil, NGLs, and natural gas reserves of the property. An estimate of fair value would take into account, among other things, the recovery of reserves not presently classified as proved, the value of proved properties, and consideration of expected future economic and operating conditions. Future cash inflows and production and development costs are determined by applying prices and costs, including transportation, quality, and basis differentials, to the year-end estimated future reserve quantities. The following prices, as adjusted for transportation, quality, and basis differentials, were used in the calculation of the standardized measure:
2022 | 2021 | |||||||
Oil (per Bbl) |
$ | 95.04 | $ | 65.20 | ||||
Natural gas (per Mcf) |
$ | 4.79 | $ | 2.48 | ||||
NGLs (per Bbl) |
$ | 35.92 | $ | 31.16 |
The estimates of future cash flows and future production and development costs as of December 31, 2022 and 2021 are based on realized prices, which reflect adjustments to the benchmark prices for quality, certain transportation fees, geographical differentials, marketing bonuses or deductions, and other factors affecting the price received at the delivery point. All realized prices are held flat over the forecast period for all reserve categories in calculating the discounted future net cash flows. Any effect from the Company’s commodity hedges is excluded. In accordance with SEC regulations, the proved reserves were anticipated to be economically producible from the “as of date” forward based on existing economic conditions, including prices and costs at which economic producibility from a reservoir was determined. These costs, held flat over the forecast period, include development costs, operating costs, ad valorem and production taxes, and abandonment costs after salvage. Future income tax expenses would have been computed using the appropriate year-end statutory tax rates applied to the future pretax net cash flows from proved oil, NGLs, and natural gas reserves, less the tax basis of the Company’s oil and natural gas properties. The estimated future net cash flows are then discounted at a rate of 10%.
The following table presents the standardized measure of discounted future net cash flows relating to proved oil, NGLs, and natural gas reserves for the periods presented:
December 31, | ||||||||
In thousands | 2022 | 2021 | ||||||
Future cash inflows |
$ | 6,960,907 | $ | 4,568,970 | ||||
Future production costs |
(2,024,200 | ) | (1,218,371 | ) | ||||
Future development and abandonment costs |
(306,833 | ) | (389,289 | ) | ||||
Future income taxes |
(7,434 | ) | (5,685 | ) | ||||
|
|
|
|
|||||
Future net cash flows |
4,622,440 | 2,955,625 | ||||||
10% annual discount for estimated timing of cash flows |
(1,704,692 | ) | (1,270,307 | ) | ||||
|
|
|
|
|||||
Standardized measure of discounted future net cash flows |
$ | 2,917,748 | $ | 1,685,318 | ||||
|
|
|
|
25
Novo Oil & Gas Holdings, LLC
Supplemental Schedules about Oil and Natural Gas Producing Properties
(Unaudited)
It is not intended that the FASB’s standardized measure of discounted future net cash flows represent the fair market value of the Company’s proved reserves. The Company cautions that the disclosures shown are based on estimates of proved reserve quantities and future production schedules which are inherently imprecise and subject to revision, and the 10% discount rate is arbitrary. In addition, prices, and costs as of the measurement date are used in the determinations, and no value may be assigned to probable or possible reserves.
The following table presents the changes in the standardized measure of discounted future net cash flows relating to proved oil, NGLs, and natural gas reserves for the periods presented:
December 31, | ||||||||
2022 | 2021 | |||||||
Standardized measure of discounted future net cash flows at January 1 |
$ | 1,685,318 | $ | 196,051 | ||||
Net change in prices and production costs |
875,788 | 769,871 | ||||||
Changes in estimated future development and abandonment costs |
(58,408 | ) | 42,004 | |||||
Sales of crude oil and natural gas produced, net of production costs |
(568,673 | ) | (172,669 | ) | ||||
Extensions, discoveries and improved recoveries, less related costs |
543,472 | 801,242 | ||||||
Purchases of minerals in place |
15,680 | — | ||||||
Divestitures of minerals in place |
— | (137 | ) | |||||
Revisions of previous quantity estimates |
(44,894 | ) | 78,659 | |||||
Development costs incurred during the period |
184,375 | 4,497 | ||||||
Change in income taxes |
(1,465 | ) | (2,090 | ) | ||||
Accretion of discount |
168,842 | 19,707 | ||||||
Change in timing of estimated future production and other |
117,713 | (51,817 | ) | |||||
|
|
|
|
|||||
Net change |
1,232,430 | 1,489,267 | ||||||
Standardized measure of discounted future net cash flows at December 31 |
$ | 2,917,748 | $ | 1,685,318 | ||||
|
|
|
|
Estimates of economically recoverable oil, NGLs, and natural gas reserves and of future net cash flows are based upon a number of variable factors and assumptions, all of which are, to some degree, subjective and may vary considerably from actual results. Therefore, actual production, revenues, development, and operating expenditures may not occur as estimated. The reserve data are estimates only, are subject to many uncertainties and are based on data gained from production histories and on assumptions as to geologic formations and other matters. Actual quantities of oil, NGLs, and natural gas may differ materially from the amounts estimated.
26
Exhibit 99.6
NOVO OIL & GAS LEGACY HOLDINGS, LLC
(Formerly Novo Oil & Gas Holdings, LLC)
Condensed Consolidated Balance Sheets (Unaudited)
(in thousands)
June 30, 2023 | December 31, 2022 | |||||||
ASSETS |
||||||||
Current assets: |
||||||||
Cash and cash equivalents |
$ | 19,224 | $ | 25,387 | ||||
Accounts receivable, net |
66,398 | 66,628 | ||||||
Prepaid expenses and other assets |
1,575 | 1,468 | ||||||
Commodity derivative assets |
30,471 | 37,692 | ||||||
|
|
|
|
|||||
Total current assets |
117,668 | 131,175 | ||||||
Property and equipment: |
||||||||
Oil and gas property and equipment, based on successful efforts method of accounting, net |
1,020,732 | 931,423 | ||||||
Other property and equipment, net |
221 | 283 | ||||||
Right-of-use asset, net |
22 | 150 | ||||||
Inventory |
5,025 | 406 | ||||||
|
|
|
|
|||||
Total property and equipment |
1,026,000 | 932,262 | ||||||
Other assets: |
||||||||
Debt issuance costs, net |
2,649 | 3,313 | ||||||
Commodity derivative asset, long-term |
1,421 | 2,474 | ||||||
Deposit |
21 | 21 | ||||||
|
|
|
|
|||||
Total assets |
$ | 1,147,759 | $ | 1,069,245 | ||||
|
|
|
|
|||||
LIABILITIES AND MEMBERS’ EQUITY |
||||||||
Current liabilities: |
||||||||
Accounts payable: |
||||||||
Trade |
$ | 50,157 | $ | 78,220 | ||||
Revenue payable |
29,307 | 33,234 | ||||||
Accrued liabilities |
12,028 | 5,959 | ||||||
Operating lease liabilities, current |
22 | 150 | ||||||
Advances from joint interest partners |
— | 19 | ||||||
Commodity derivatives liability, current |
9,969 | 5,063 | ||||||
Deferred midstream revenue, current |
2,333 | 2,333 | ||||||
|
|
|
|
|||||
Total current liabilities |
103,816 | 124,978 | ||||||
Noncurrent liabilities: |
||||||||
Revolving credit facility |
350,000 | 250,000 | ||||||
Commodity derivative liability, long-term |
3,796 | 4,905 | ||||||
Deferred midstream revenue, long-term |
21,194 | 22,361 | ||||||
Asset retirement obligation |
2,856 | 2,706 | ||||||
|
|
|
|
|||||
Total liabilities |
481,662 | 404,950 | ||||||
Commitments and contingencies (Note 11) |
||||||||
Members’ equity |
666,097 | 664,295 | ||||||
|
|
|
|
|||||
Total liabilities and members’ equity |
$ | 1,147,759 | $ | 1,069,245 | ||||
|
|
|
|
1
NOVO OIL & GAS LEGACY HOLDINGS, LLC
(Formerly Novo Oil & Gas Holdings, LLC)
Condensed Consolidated Statements of Operations (Unaudited)
(in thousands)
Three Months Ended June 30, |
Six Months Ended June 30, |
|||||||||||||||
2023 | 2022 | 2023 | 2022 | |||||||||||||
REVENUES: |
||||||||||||||||
Crude oil, natural gas, and NGL sales |
$ | 205,539 | $ | 192,388 | $ | 383,058 | $ | 306,938 | ||||||||
OPERATING COSTS AND EXPENSES: |
||||||||||||||||
Lease operating |
29,109 | 9,675 | 50,599 | 16,559 | ||||||||||||
Production taxes |
15,538 | 14,262 | 28,567 | 22,495 | ||||||||||||
Exploration |
62 | 429 | 123 | 517 | ||||||||||||
General and administrative |
17,405 | 1,628 | 19,128 | 3,423 | ||||||||||||
Depletion, depreciation, and amortization |
45,180 | 24,019 | 81,518 | 42,264 | ||||||||||||
Accretion of discount on asset retirement obligations |
76 | 29 | 150 | 57 | ||||||||||||
|
|
|
|
|
|
|
|
|||||||||
Total operating expenses |
107,370 | 50,042 | 180,085 | 85,315 | ||||||||||||
OPERATING INCOME |
98,169 | 142,346 | 202,973 | 221,623 | ||||||||||||
OTHER INCOME (EXPENSE): |
||||||||||||||||
Interest income |
128 | 1 | 226 | 1 | ||||||||||||
Interest expense |
(7,735 | ) | (936 | ) | (13,524 | ) | (1,256 | ) | ||||||||
Gain (loss) on sale of oil and gas properties |
8 | (136 | ) | 16 | (136 | ) | ||||||||||
Commodity derivative gain (loss), net |
(3,022 | ) | (9,565 | ) | 28,912 | (61,185 | ) | |||||||||
Deferred midstream revenue |
583 | 583 | 1,166 | 1,167 | ||||||||||||
Other expense |
(3,000 | ) | (88 | ) | (2,926 | ) | (86 | ) | ||||||||
|
|
|
|
|
|
|
|
|||||||||
Total other income (expense) |
(13,038 | ) | (10,141 | ) | 13,870 | (61,495 | ) | |||||||||
NET INCOME BEFORE TAXES |
85,131 | 132,205 | 216,843 | 160,128 | ||||||||||||
MARGIN TAX EXPENSE |
(89 | ) | (118 | ) | (160 | ) | (271 | ) | ||||||||
|
|
|
|
|
|
|
|
|||||||||
NET INCOME |
$ | 85,042 | $ | 132,087 | $ | 216,683 | $ | 159,857 | ||||||||
|
|
|
|
|
|
|
|
2
NOVO OIL & GAS LEGACY HOLDINGS, LLC
(Formerly Novo Oil & Gas Holdings, LLC)
Condensed Consolidated Statements of Equity (Unaudited)
(in thousands)
Class A | Class B | |||||||||||||||||||
Units | Capital | Units | Capital | Total | ||||||||||||||||
January 1, 2022 |
3,092,175 | $ | 468,580 | 63,106 | $ | 6,874 | $ | 475,454 | ||||||||||||
Distributions |
— | (49,905 | ) | — | (1,018 | ) | (50,923 | ) | ||||||||||||
Net income |
— | 156,660 | — | 3,197 | 159,857 | |||||||||||||||
|
|
|
|
|
|
|
|
|
|
|||||||||||
June 30, 2022 |
3,092,175 | $ | 575,335 | 63,106 | $ | 9,053 | $ | 584,388 | ||||||||||||
|
|
|
|
|
|
|
|
|
|
|||||||||||
January 1, 2023 |
3,092,175 | $ | 653,643 | 63,106 | $ | 10,652 | $ | 664,295 | ||||||||||||
Distributions |
— | (210,275 | ) | — | (4,606 | ) | (214,881 | ) | ||||||||||||
Net income |
— | 212,350 | — | 4,333 | 216,683 | |||||||||||||||
|
|
|
|
|
|
|
|
|
|
|||||||||||
June 30, 2023 |
3,092,175 | $ | 655,718 | 63,106 | $ | 10,379 | $ | 666,097 | ||||||||||||
|
|
|
|
|
|
|
|
|
|
3
NOVO OIL & GAS LEGACY HOLDINGS, LLC
(Formerly Novo Oil & Gas Holdings, LLC)
Condensed Consolidated Statements of Cash Flows (Unaudited)
(in thousands)
Six Months Ended June 30, | ||||||||
2023 | 2022 | |||||||
CASH FLOWS FROM OPERATING ACTIVITIES: |
||||||||
Net income |
$ | 216,683 | $ | 159,857 | ||||
Adjustments to reconcile net income to net cash from operating activities: |
||||||||
Depletion, depreciation, and amortization |
81,518 | 42,264 | ||||||
Accretion of discount on asset retirement obligations |
150 | 57 | ||||||
Deferred midstream revenue |
(1,166 | ) | (1,167 | ) | ||||
Deferred financing cost amortization |
843 | 268 | ||||||
Unrealized loss on derivatives |
15,386 | 22,740 | ||||||
Purchase of derivative premiums |
(4,936 | ) | — | |||||
(Gain) loss on sale of oil and gas properties |
(16 | ) | 136 | |||||
Change in working capital items: |
||||||||
Accounts receivable |
229 | (54,456 | ) | |||||
Prepaid expenses and other assets |
(108 | ) | (142 | ) | ||||
Accounts payable |
2,998 | (2,078 | ) | |||||
Advances from joint interest partners |
(19 | ) | (25,044 | ) | ||||
Revenue payables |
(3,924 | ) | 17,479 | |||||
Accrued liabilities |
6,065 | 4,283 | ||||||
|
|
|
|
|||||
Net cash provided by operating activities |
313,703 | 164,197 | ||||||
CASH FLOWS FROM INVESTING ACTIVITIES: |
||||||||
Additions to oil and gas properties |
(204,822 | ) | (188,427 | ) | ||||
Additions to other property and equipment |
— | (10 | ) | |||||
Proceeds from sales of oil and gas properties |
16 | 30 | ||||||
|
|
|
|
|||||
Net cash used in investing activities |
(204,806 | ) | (188,407 | ) | ||||
CASH FLOWS FROM FINANCING ACTIVITIES: |
||||||||
Distributions to members |
(214,881 | ) | (50,923 | ) | ||||
Payments for deferred financing costs |
(179 | ) | (1,875 | ) | ||||
Borrowings from revolving credit facility |
100,000 | 80,000 | ||||||
|
|
|
|
|||||
Net (used in) provided by financing activities |
(115,060 | ) | 27,202 | |||||
NET CHANGE IN CASH AND CASH EQUIVALENTS |
(6,163 | ) | 2,992 | |||||
CASH AND CASH EQUIVALENTS, beginning of period |
25,387 | 17,005 | ||||||
|
|
|
|
|||||
CASH AND CASH EQUIVALENTS, end of quarter |
$ | 19,224 | $ | 19,997 | ||||
|
|
|
|
4
NOVO OIL & GAS LEGACY HOLDINGS, LLC
(Formerly Novo Oil & Gas Holdings, LLC)
Notes to Condensed Consolidated Financial Statements (Unaudited)
Note 1. Organization and Summary of Significant Accounting Policies
Description
Novo Oil and Gas Legacy Holdings, LLC (the “Company”) was formed is a limited liability company under the laws of the state of Delaware. The Company’s principal business is in oil and natural gas acquisition, exploration, development, and production. The Company’s operations are concentrated in the Northern Delaware Basin of Southeast New Mexico and West Texas, a region of high-quality, liquids rich, stacked pay zones.
On June 15, 2023, the Company signed a definitive agreement with Earthstone Energy, Inc. (“Earthstone”) to sell substantially all of its oil and gas assets for $1.5 billion. Due to the Company selling substantially all of its oil and gas properties, held for sale or discontinued operations accounting and related disclosures were determined to not be additive to the users of the financial statements as of, and for the period ending, June 30, 2023. The Company completed the sale of substantially all of its oil and gas assets on August 15, 2023.
Basis of Presentation of Unaudited Condensed Consolidated Interim Financial Statements
The Company is the successor to Novo Oil & Gas Holdings, LLC (the “Novo Holdings”), the former reporting entity formed on August 29, 2016, as a limited liability company under the laws of the state of Delaware. The Company undertook a reorganization on June 14, 2023 in order to effectuate the sale of its oil and gas properties to Earthstone. The reorganization involved the formation of the Company and the drop-down of Novo Holdings, the former reporting entity, as a subsidiary of the Company. The reorganization did not impact the consolidated ownership structure other than through the formation of the Company as parent to Novo Holdings and all subsidiaries. This change in reporting entity did not impact any of Novo Holdings previously issued consolidated financial statements. Additionally, the consolidated financial statements of the Company are on the same basis as Novo Holdings, and as a result, no prior period information has been modified.
The unaudited condensed consolidated interim financial statements (“Condensed Consolidated Financial Statements”) have been prepared in accordance with accounting principles generally accepted in the United States of America (“U.S. GAAP”). Certain disclosures normally included in the Condensed Consolidated Financial Statements prepared in accordance with U.S. GAAP have been omitted. The accompanying Condensed Consolidated Financial Statements and notes should be read in conjunction with the financial statements and notes included in Novo Holding’s combined consolidated financial statements as of and for the years ended December 31, 2022 and 2021. The accompanying Condensed Consolidated Financial Statements reflect all adjustments that are, in the opinion of management, necessary for a fair statement of the Company’s results of operations and cash flows for three and six-month periods ended June 30, 2023 and 2022 and the Company’s financial position as of June 30, 2023.
The accompanying Condensed Consolidated Financial Statements include the accounts of the Company and its wholly owned subsidiaries. Intercompany accounts and transactions have been eliminated.
5
NOVO OIL & GAS LEGACY HOLDINGS, LLC
(Formerly Novo Oil & Gas Holdings, LLC)
Notes to Condensed Consolidated Financial Statements (Unaudited)
Note 2. Accounts Receivable
Components of accounts receivable include the following (in thousands):
June 30, 2023 | December 31, 2022 | |||||||
Crude oil, natural gas, and NGL sales |
$ | 55,292 | $ | 48,998 | ||||
Joint interest billings |
11,103 | 17,628 | ||||||
Related party |
3 | 2 | ||||||
|
|
|
|
|||||
Gross accounts receivable |
66,398 | 66,628 | ||||||
Allowance for doubtful accounts |
— | — | ||||||
|
|
|
|
|||||
Net accounts receivable |
$ | 66,398 | $ | 66,628 | ||||
|
|
|
|
As of January 1, 2023 and 2022, the accounts receivable balance representing amounts due or billable under the terms of contracts with purchasers was $49.0 million and $26.1 million, respectively. The Company reviews accounts receivable periodically and reduces the carrying amount by a valuation allowance that reflects the estimate of the amount that may not be collectible. No such allowance was considered necessary at June 30, 2023 and December 31, 2022.
Note 3. Oil and Natural Gas Properties
Capitalized Costs
The following table reflects the aggregate capitalized costs (in thousands):
June 30, 2023 | December 31, 2022 | |||||||
Oil and natural gas properties: |
||||||||
Proved properties |
$ | 1,257,559 | $ | 1,083,345 | ||||
Unproved properties |
56,708 | 60,158 | ||||||
|
|
|
|
|||||
Total oil and gas properties |
1,314,267 | 1,143,503 | ||||||
Less: accumulated depreciation, depletion, and amortization |
(293,535 | ) | (212,080 | ) | ||||
|
|
|
|
|||||
Oil and gas properties, net |
$ | 1,020,732 | $ | 931,423 | ||||
|
|
|
|
No lease expirations were included as exploration costs in the consolidated statements of operations for the six months ended June 30, 2023 and 2022. In addition, there were no impairments of unproved leaseholds during the three and six months ended June 30, 2023 and 2022.
Note 4. Other Property and Equipment, Net
Other property and equipment, net consists of the following (in thousands):
June 30, 2023 | December 31, 2022 | |||||||
Furniture, fixtures, and other |
$ | 2,118 | $ | 2,118 | ||||
Less: accumulated depreciation |
(1,897 | ) | (1,835 | ) | ||||
|
|
|
|
|||||
Other property and equipment, net |
$ | 221 | $ | 283 | ||||
|
|
|
|
6
NOVO OIL & GAS LEGACY HOLDINGS, LLC
(Formerly Novo Oil & Gas Holdings, LLC)
Notes to Condensed Consolidated Financial Statements (Unaudited)
Note 5. Revenue
Disaggregation of Revenue
The following table presents the disaggregation of crude oil, natural gas and natural gas liquids (NGLs) revenue (in thousands):
Three Months Ended June 30, | Six Months Ended June 30, | |||||||||||||||
2023 | 2022 | 2023 | 2022 | |||||||||||||
Crude oil |
$ | 162,119 | $ | 100,440 | $ | 300,670 | $ | 174,833 | ||||||||
Natural gas |
11,474 | 48,669 | 22,016 | 66,069 | ||||||||||||
NGLs |
31,946 | 43,279 | 60,372 | 66,036 | ||||||||||||
|
|
|
|
|
|
|
|
|||||||||
Total crude oil, natural gas, and NGL sales, net |
$ | 205,539 | $ | 192,388 | $ | 383,058 | $ | 306,938 | ||||||||
|
|
|
|
|
|
|
|
Note 6. Derivative Financial Instruments
Commodity Derivatives
As of June 30, 2023, the Company had the following open crude oil derivative positions:
Price Swaps | Price Collars | |||||||||||||||||||
Period |
Volume (Bbls) |
Weighted Average Price ($/Bbl) |
Volume (Bbls) |
Weighted Average Floor Price ($/Bbl) |
Weighted Average Ceiling Price ($/Bbl) |
|||||||||||||||
July 2023 - December 2023 |
1,206,500 | $ | 83.93 | — | $ | — | $ | — | ||||||||||||
January 2024 - December 2024 |
723,000 | $ | 76.39 | — | $ | — | $ | — | ||||||||||||
July 2023 - December 2023 |
— | $ | — | 977,000 | $ | 70.46 | $ | 81.35 |
7
NOVO OIL & GAS LEGACY HOLDINGS, LLC
(Formerly Novo Oil & Gas Holdings, LLC)
Notes to Condensed Consolidated Financial Statements (Unaudited)
As of June 30, 2023, the Company had the following open natural gas derivative positions:
Price Swaps | Price Collars | |||||||||||||||||||
Period |
Volume (MMBtu) |
Weighted Average Price ($/MMBtu) |
Volume (MMBtu) |
Weighted Average Floor Price ($/MMBtu) |
Weighted Average Ceiling Price ($/MMBtu) |
|||||||||||||||
July 2023 - December 2023 |
3,940,000 | $ | 3.52 | — | $ | — | $ | — | ||||||||||||
January 2024 - December 2024 |
2,025,000 | $ | 4.88 | — | $ | — | $ | — | ||||||||||||
January 2025 - December 2025 |
1,785,000 | $ | 4.71 | — | $ | — | $ | — | ||||||||||||
July 2023 - December 2023 |
— | $ | — | 7,935,000 | $ | 3.88 | $ | 6.04 | ||||||||||||
January 2024 - December 2024 |
— | $ | — | 9,665,000 | $ | 3.75 | $ | 6.03 | ||||||||||||
January 2025 - December 2025 |
— | $ | — | 5,185,000 | $ | 3.67 | $ | 5.45 |
Natural Gas Basis Swaps | ||||||||||||
Period |
Index | Volume (Bbls) |
Weighted Average Basis Differentials ($/Bbl) |
|||||||||
July 2023 - December 2023 |
WAHA | 11,020,000 | $ | (1.63 | ) | |||||||
January 2024 - December 2024 |
WAHA | 12,150,000 | $ | (1.43 | ) | |||||||
January 2025 - December 2025 |
WAHA | 8,477,500 | $ | (1.17 | ) |
Derivative Gains and Losses
Cash receipts and payments reflect the gains or losses on derivative contracts which matured during the applicable period, calculated as the difference between the contract price and the market settlement price of matured contracts. The derivative contracts of the Company are settled based upon reported settlement prices on commodity exchanges. Because the Company does not apply hedge accounting treatment to its derivative contracts, the changes in fair value of these contracts are recognized in income as unrealized gains (losses) in the period of change.
8
NOVO OIL & GAS LEGACY HOLDINGS, LLC
(Formerly Novo Oil & Gas Holdings, LLC)
Notes to Condensed Consolidated Financial Statements (Unaudited)
The following table presents cash receipts and payments along with unrealized gains and losses of commodity derivative contracts (in thousands):
Three Months Ended June 30, | Six Months Ended June 30, | |||||||||||||||
2023 | 2022 | 2023 | 2022 | |||||||||||||
Cash received (paid) on derivatives |
$ | 15,208 | $ | (27,439 | ) | $ | 44,298 | $ | (38,445 | ) | ||||||
Unrealized gain (loss) on derivatives |
(18,230 | ) | 17,874 | (15,386 | ) | (22,740 | ) | |||||||||
|
|
|
|
|
|
|
|
|||||||||
Gain (loss) on derivatives, net |
$ | (3,022 | ) | $ | (9,565 | ) | $ | 28,912 | $ | (61,185 | ) | |||||
|
|
|
|
|
|
|
|
Financial Statement Presentation
All derivative financial instruments are recognized at their current fair value as either assets or liabilities in the consolidated balance sheets. Amounts related to contracts allowed to be netted upon payment subject to a master netting arrangement with the same counterparty are reported on a net basis in the consolidated balance sheets. The table below presents a summary of these positions at June 30, 2023 (in thousands):
June 30, 2023 | ||||||||||||
Gross Fair Value |
Amounts Netted |
Net Fair Value | ||||||||||
Commodity derivative assets: |
||||||||||||
Commodity derivative asset, current |
$ | 41,148 | $ | (10,677 | ) | $ | 30,471 | |||||
Commodity derivative asset, noncurrent |
9,878 | (8,457 | ) | 1,421 | ||||||||
|
|
|
|
|
|
|||||||
Total commodity derivative assets |
$ | 51,026 | $ | (19,134 | ) | $ | 31,892 | |||||
|
|
|
|
|
|
|||||||
Commodity derivative liabilities: |
||||||||||||
Commodity derivative liability, current |
$ | (20,646 | ) | $ | 10,677 | $ | 9,969 | |||||
Commodity derivative liability, noncurrent |
(12,253 | ) | 8,457 | 3,796 | ||||||||
|
|
|
|
|
|
|||||||
Total commodity derivative liabilities |
$ | (32,899 | ) | $ | 19,134 | $ | 13,765 | |||||
|
|
|
|
|
|
December 31, 2022 | ||||||||||||
Gross Fair Value |
Amounts Netted |
Net Fair Value | ||||||||||
Commodity derivative assets: |
||||||||||||
Commodity derivative asset, current |
$ | 47,633 | $ | (9,941 | ) | $ | 37,692 | |||||
Commodity derivative asset, noncurrent |
8,927 | (6,453 | ) | 2,474 | ||||||||
|
|
|
|
|
|
|||||||
Total commodity derivative assets |
$ | 56,560 | $ | (16,394 | ) | $ | 40,166 | |||||
|
|
|
|
|
|
|||||||
Commodity derivative liabilities: |
||||||||||||
Commodity derivative liability, current |
$ | (15,004 | ) | $ | 9,941 | $ | (5,063 | ) | ||||
Commodity derivative liability, noncurrent |
(11,358 | ) | 6,453 | (4,905 | ) | |||||||
|
|
|
|
|
|
|||||||
Total commodity derivative liabilities |
$ | (26,362 | ) | $ | 16,394 | $ | (9,968 | ) | ||||
|
|
|
|
|
|
9
NOVO OIL & GAS LEGACY HOLDINGS, LLC
(Formerly Novo Oil & Gas Holdings, LLC)
Notes to Condensed Consolidated Financial Statements (Unaudited)
Note 7. Revolving Credit Facility
The Company has a senior secured revolving credit facility (“Revolving Credit Facility”) with a bank with a maximum commitment of $500.0 million. The Revolving Credit Facility has semi-annual borrowing base redeterminations on April 1 and October 1 each year. On March 28, 2023, the borrowing base of the Revolving Credit Facility was reaffirmed at $400.0 million. As of June 30, 2023 and December 31, 2022, the Company had $350.0 million and $250.0 million of outstanding borrowings under the Revolving Credit Facility, respectively. The Company has pledged substantially all of its oil and gas properties and other assets as collateral to secure amounts outstanding under the Revolving Credit Facility.
At June 30, 2023 and December 31, 2022, the interest rate on the Revolving Credit Facility was 8.9% and 6.9%, respectively. The Revolving Credit Facility contains representations, warranties, covenants, conditions, and defaults customary for transactions of this type, including but not limited to (i) limitations on liens and incurrence of debt covenants; (ii) limitations on the sale of property, mergers, consolidations, and other similar transactions covenants; (iii) limitations on investments, loans and advances covenants; and (iv) limitations on dividends, distributions, redemptions, and restricted payments covenants. The revolving credit facility also contains financial covenants requiring the Company to comply with a consolidated leverage ratio, as of the last day of any fiscal quarter, to be greater than 3.25 to 1.0 and a consolidated current ratio, as of the last day of any fiscal quarter, to not be less than 1.0 to 1.0. The Company was in compliance with terms and covenants of the Revolving Credit Facility as of June 30, 2023 and December 31, 2022.
Note 8. Asset Retirement Obligations
The following table presents changes in asset retirement obligations (in thousands):
June 30, | ||||||||
2023 | 2022 | |||||||
Asset retirement obligations at beginning of period |
$ | 2,706 | $ | 1,035 | ||||
Accretion expense on discounted obligation |
150 | 57 | ||||||
|
|
|
|
|||||
Asset retirement obligations at end of period |
$ | 2,856 | $ | 1,092 | ||||
|
|
|
|
Given the unobservable nature of the inputs, the initial recognition of an asset retirement obligation is a non-recurring Level 3 fair value measurement.
Note 9. Fair Value Measurement
The carrying amounts of financial instruments, including cash and cash equivalents, accounts receivable, accounts payable, revenue payable, advances from joint interest partners, and accrued liabilities included in the accompanying condensed consolidated balance sheets approximated fair value due to their short-term maturities. The carrying value of the Companies’ revolving credit facility approximates fair value because the Credit Agreement’s variable interest rate resets frequently and approximates current market rates available to the Companies.
10
NOVO OIL & GAS LEGACY HOLDINGS, LLC
(Formerly Novo Oil & Gas Holdings, LLC)
Notes to Condensed Consolidated Financial Statements (Unaudited)
Note 10. Members’ Equity
The Company has three authorized classes of membership interests consisting of Class A units, Class B units, and Class C units. These membership interests are differentiated by ownership, voting rights, capital contribution requirements, and payout treatment. The Class C units first payout hurdle, as defined in the Limited Liability Company Agreement (“LLC Agreement”), was achieved during the six months ended June 30, 2023. Class C units are considered profits interests in accordance with ASC 710 – Compensation. Distributions are made in accordance with the achievement of certain performance criteria by Company and will be recorded as compensation expense when achieved and paid.
For the six months ended June 30, 2023, the Company made distributions of $230.3 million, of which $15.4 million was distributed to the Class C unit holders. The Company recorded the Class C unit distributions of $15.4 million as compensation expense and included in general and administrative expense on the condensed consolidated statements of operations. For the six months ended June 30, 2022, the Company made distributions of $50.9 million to Class A and Class B unit holders.
As of June 30, 2023 and December 31, 2022, 4,170,175 Class A units, 80,000 Class B units, and 100,000 Class C units were authorized. At June 30, 2023 and December 31, 2022, the Company had issued 3,092,175 Class A units, 63,106 Class B units, and 100,000 Class C units.
Note 11. Commitments and Contingencies
Due to the nature of the oil and natural gas business, the Company is exposed to possible environmental risks. The Company has implemented various policies and procedures to avoid environmental contamination and risks from environmental contamination. The Company has not historically experienced any significant environmental liabilities and is not aware of any potential material environmental issues or claims that are considered probable and estimable at June 30, 2023 and December 31, 2022.
Note 12. Leases
Operating lease costs and short-term lease costs are included in “general and administrative expense” in the accompanying consolidated statements of operations and included in the following components (in thousands):
Three Months Ended June 30, | Six Months Ended June 30, | |||||||||||||||
2023 | 2022 | 2023 | 2022 | |||||||||||||
Operating lease cost |
$ | 65 | $ | 62 | $ | 130 | $ | 124 | ||||||||
Short-term lease costs |
$ | 1,404 | $ | 631 | $ | 2,830 | $ | 1,073 | ||||||||
Lease costs capitalized in proved oil and gas properties |
$ | 3,115 | $ | 9,007 | $ | 6,944 | $ | 10,879 |
11
NOVO OIL & GAS LEGACY HOLDINGS, LLC
(Formerly Novo Oil & Gas Holdings, LLC)
Notes to Condensed Consolidated Financial Statements (Unaudited)
Note 13. Supplemental Disclosures to Consolidated Financial Statements
Accrued Liabilities
Accrued liabilities consisted of the following at the dates indicated (in thousands):
June 30, 2023 | December 31, 2022 | |||||||
Accrued production taxes |
$ | 6,406 | $ | 4,939 | ||||
Accrued interest |
1,727 | 678 | ||||||
Accrued compensation costs and other |
3,895 | 342 | ||||||
|
|
|
|
|||||
Accrued liabilities |
$ | 12,028 | $ | 5,959 | ||||
|
|
|
|
Supplemental Cash Flow Information
The following table provides certain supplemental cash flow information for the periods indicated (in thousands):
June 30, | ||||||||
2023 | 2022 | |||||||
Supplemental disclosure of non-cash information: |
||||||||
Change in accounts payable related to oil and gas properties |
$ | 29,439 | $ | 18,201 | ||||
|
|
|
|
Note 14. Subsequent Events
In preparing the accompanying Consolidated Financial Statements, management has evaluated all subsequent events and transactions for potential recognition or disclosure through August 30, 2023, the date the Condensed Consolidated Financial Statements of the Company were available for issuance and concluded there were no material subsequent events other than discussed below.
Subsequent to June 30, 2023, the Company made distributions to members for a total of $939.3 million. The distribution was shared in accordance with the limited liability company agreement governing the sharing of such future distributions under the achievement of the first payout level.
As previously discussed in Note 1, on August 15, 2023, the Company completed the sale of substantially all its oil and gas assets to Earthstone. As a result of the sale, the Company paid the Revolving Credit Facility in full.
12
Exhibit 99.7
CAWLEY, GILLESPIE & ASSOCIATES, INC.
PETROLEUM CONSULTANTS
13640 BRIARWICK DRIVE, SUITE 100 AUSTIN, TEXAS 78729-1106 512-249-7000 |
306 WEST SEVENTH STREET, SUITE 302 FORT WORTH, TEXAS 76102-4987 817-336-2461 WWW.cgaus.com |
1000 LOUISIANA STREET, SUITE 1900 HOUSTON, TEXAS 77002-5008 713-651-9944 |
January 24, 2023
Geoff Vernon
Vice President of Reservoir Engineering and A&D
Earthstone Energy, Inc.
1400 Woodloch Forest Dr., Suite 300
The Woodlands, Texas 77380
Re: | Evaluation Summary – SEC Price Case |
Earthstone Energy, Inc. Interests
Total Proved Reserves
Certain Properties in New Mexico and Texas
As of December 31, 2022
Pursuant to the Guidelines of the Securities and
Exchange Commission for Reporting Corporate
Reserves and Future Net Revenue
Dear Mr. Vernon:
As you have requested, this report was completed on January 24, 2023 for the purpose of submitting our estimates of proved reserves and forecasts of economics attributable to the Earthstone Energy, Inc. (“Earthstone”) interests. We evaluated 100% of Earthstone’s reserves, which are made up of oil and gas properties in New Mexico and Texas. This report utilized an effective date of December 31, 2022, was prepared using constant prices and costs, and conforms to Item 1202(a)(8) of Regulation S-K and other rules of the Securities and Exchange Commission (“SEC”). This report was prepared for the inclusion as an exhibit in a filing made with the SEC. The results of this evaluation are presented in the accompanying tabulation, with a composite summary of the values presented below:
Proved Developed Producing |
Proved Developed Non- Producing |
Proved Developed |
Proved Undeveloped |
Total Proved |
||||||||||||||||||||
Net Reserves |
||||||||||||||||||||||||
Oil |
- Mbbl | 85,949.3 | 2,810.4 | 88,759.7 | 49,640.7 | 138,400.4 | ||||||||||||||||||
Gas |
- MMcf | 566,040.0 | 8,721.3 | 574,761.2 | 167,404.3 | 742,165.6 | ||||||||||||||||||
NGL |
- Mbbl | 79,008.7 | 1,158.8 | 80,167.5 | 25,673.0 | 105,840.5 | ||||||||||||||||||
Net Revenue |
||||||||||||||||||||||||
Oil |
- M$ | 8,229,010.4 | 271,415.1 | 8,500,424.7 | 4,761,062.9 | 13,261,489.2 | ||||||||||||||||||
Gas |
- M$ | 3,131,587.6 | 48,121.0 | 3,179,708.7 | 911,800.8 | 4,091,509.2 | ||||||||||||||||||
NGL |
- M$ | 3,092,366.6 | 44,865.0 | 3,137,232.1 | 1,015,796.4 | 4,153,027.8 | ||||||||||||||||||
Severance Taxes |
- M$ | 925,354.7 | 20,238.0 | 945,592.8 | 430,052.0 | 1,375,644.5 | ||||||||||||||||||
Ad Valorem Taxes |
- M$ | 173,641.2 | 4,799.9 | 178,441.1 | 67,647.8 | 246,088.8 | ||||||||||||||||||
Operating Expenses |
- M$ | 3,548,749.0 | 62,968.6 | 3,611,718.0 | 1,027,049.6 | 4,638,768.0 | ||||||||||||||||||
Abandonment Cost |
- M$ | 92,177.5 | 593.7 | 92,771.2 | 9,627.7 | 102,398.8 | ||||||||||||||||||
Future Development Costs |
- M$ | 0.0 | 7,000.0 | 7,000.0 | 1,200,596.6 | 1,207,596.5 | ||||||||||||||||||
Future Net Cash Flow (BFIT) |
- M$ | 9,713,042.4 | 268,800.9 | 9,981,840.4 | 3,953,685.8 | 13,935,531.0 | ||||||||||||||||||
Discounted @ 10% |
- M$ | 5,670,219.3 | 170,452.1 | 5,840,672.8 | 1,948,945.4 | 7,789,619.2 |
Earthstone Energy, Inc. Interests – SEC Price Case
January 24, 2023
Page 2
Future net revenue is prior to deducting state production taxes and ad valorem taxes. Future net cash flow is after deducting these taxes, future capital (development) costs and operating expenses, but before consideration of federal income taxes. In accordance with SEC guidelines, the future net cash flow has been discounted at an annual rate of ten percent to determine its “present worth”. The present worth is shown to indicate the effect of time on the value of money and should not be construed as being the fair market value of the reserves by Cawley, Gillespie & Associates, Inc. (“CG&A”).
The oil reserves include oil and condensate. Oil and natural gas liquid (NGL) volumes are expressed in barrels (42 U.S. gallons). Gas volumes are expressed in thousands of standard cubic feet (Mcf) at contract temperature and pressure base.
Hydrocarbon Pricing
As requested for SEC purposes, the base oil and gas prices calculated for December 31, 2022 were $93.67/BBL and $6.358/MMBTU, respectively. As specified by the SEC, a company must use a 12-month average price, calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month period prior to the end of the reporting period. The base oil price is based upon WTI-Cushing spot prices (EIA) during January 2022 through December 2022 and the base gas price is based upon Henry Hub spot prices (Platts Gas Daily) during January 2022 through December 2022. NGL prices were adjusted on a per-property basis and averaged 41.0% of the net oil price on a composite basis.
The base prices were adjusted for differentials on a per-property basis, which may include local basis differential, treating cost, transportation, gas shrinkage, gas heating value (BTU content) and/or crude quality and gravity corrections. After these adjustments, the net realized prices for the SEC price case over the life of the proved properties was estimated to be $95.82 per barrel for oil, $5.51 per MCF for natural gas and $39.24 per barrel for NGL. All economic factors were held constant in accordance with SEC guidelines.
Future Development Costs, Expenses and Taxes
Capital expenditures (Future Development Costs), lease operating expenses and ad valorem tax values were forecast as provided by Earthstone. As you explained, the capital costs were based on the most current estimates, lease operating expenses were based on the analysis of historical actual expenses, operating overhead is included for non-operated properties and no credit or deduction is made for producing overhead paid to the company by other owners of the operated properties. Lease operating expenses are applied based on location, operatorship and wellbore orientation on a per-property or per-unit basis. Capital costs and lease operating expenses were held constant in accordance with SEC guidelines.
Severance tax rates were applied at normal state percentages of oil and gas revenue. Severance tax rates in certain instances, where authorized by taxing authorities, have severance tax abatements and were provided by your office and applied when appropriate.
SEC Conformance and Regulations
The reserve classifications and the economic considerations used herein conform to the criteria of the SEC as defined in pages 3 and 4 of the Appendix. The reserves and economics are predicated on regulatory agency classifications, rules, policies, laws, taxes and royalties currently in effect except as noted herein. Federal, state, and local laws and regulations, which are currently in effect and that govern the development and production of oil and natural gas, have been considered in the evaluation of proved reserves for this report. The possible effects of changes in legislation or other Federal or State restrictive actions which could affect the reserves and economics have not been considered. These possible changes could have an effect on the reserves and economics. However, we do not anticipate nor are we aware of any legislative changes or restrictive regulatory actions that may impact the recovery of reserves.
Earthstone Energy, Inc. Interests – SEC Price Case
January 24, 2023
Page 3
This evaluation includes ten (10) developed non-producing properties including wells anticipated to begin production in early 2023 and 204 proved undeveloped locations, all of which are commercial using required SEC pricing. More specifically, proved developed non-producing reserves represent newly drilled wells in the process of being completed or recently completed but not yet producing as of the effective date. Further, each of these commercial drilling locations proposed as part of Earthstone’s development plans conforms to the proved undeveloped standards as set forth by the SEC. In our opinion, Earthstone has indicated it has every intent to complete this development plan as scheduled. Furthermore, Earthstone has demonstrated that it has adequate company staffing, financial backing and prior development success to ensure this development plan will be fully executed.
Reserve Estimation Methods
The methods employed in estimating reserves are described on page 2 of the Appendix. Reserves for proved developed producing wells were estimated using production performance methods for the vast majority of properties. Certain new producing properties with very little production history were forecast using a combination of production performance and analogy to similar production, both of which are considered to provide a relatively high degree of accuracy.
Non-producing reserve estimates, including undeveloped properties, were forecast using either volumetric or analogy methods, or a combination of both. These methods provide a relatively high degree of accuracy for predicting proved undeveloped reserves. The assumptions, data, methods and procedures used herein are appropriate for the purpose served by this report.
Miscellaneous
An on-site field inspection of the properties has not been performed nor has the mechanical operation or condition of the wells and their related facilities been examined, nor have the wells been tested by Cawley, Gillespie & Associates, Inc. Possible environmental liability related to the properties has not been investigated nor considered. However, the estimated costs of plugging and abandoning wells have been included herein as provided.
The reserve estimates and forecasts were based upon interpretations of data furnished by Earthstone and available from our files. Ownership information and economic factors such as liquid and gas prices, price differentials and expenses were furnished by Earthstone. To some extent, information from public records was used to check and/or supplement these data. The basic engineering and geological data were utilized subject to third party reservations and qualifications. Nothing has come to our attention, however, that would cause us to believe that we are not justified in relying on such data. All estimates represent our best judgment based on the data available at the time of preparation. Due to inherent uncertainties in future production rates, commodity prices and geologic conditions, it should be realized that the reserve estimates, the reserves actually recovered, the revenue derived therefrom and the actual cost incurred could be more or less than the estimated amounts.
Closing
Cawley, Gillespie & Associates, Inc. is a Texas Registered Engineering Firm (F-693), made up of independent registered professional engineers and geologists that have provided petroleum consulting services to the oil and gas industry for over 60 years. This evaluation was supervised by W. Todd Brooker, President at Cawley, Gillespie & Associates, Inc. and a State of Texas Licensed Professional Engineer (License #83462). We do not own an interest in the properties or Earthstone Energy, Inc. and are not employed on a contingent basis. We have used all methods and procedures that we consider necessary under the circumstances to prepare this report. Our work-papers and related data utilized in the preparation of these estimates are available in our office.
Earthstone Energy, Inc. Interests – SEC Price Case
January 24, 2023
Page 4
Yours very truly, | ||
CAWLEY, GILLESPIE & ASSOCIATES, INC. TEXAS REGISTERED ENGINEERING FIRM F-693 |
/s/ W. Todd Brooker
W. TODD BROOKER, P.E.
PRESIDENT
/s/ Robert P. Bergeron, Jr.
ROBERT P. BERGERON, JR., P.E.
PARTNER
Exhibit 99.8
SEPTEMBER 7, 2023
Mr. Kyle Hoover
Novo Oil & Gas, LLC
1001 West Wilshire Boulevard, Suite 206
Oklahoma City, Oklahoma 73116
Dear Mr. Hoover:
In accordance with your request, we have estimated the proved reserves and future revenue, as of December 31, 2022, to the Novo Oil & Gas, LLC (Novo) leasehold interest in certain oil and gas properties located in New Mexico and Texas. We completed our evaluation on or about May 30, 2023. It is our understanding that the proved reserves estimated in this report constitute approximately 85 percent of all proved reserves owned by Novo. 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 Novo leasehold interest in these properties, as of December 31, 2022, to be:
Net Reserves | Future Net Revenue (M$) | |||||||||||||||||||
Oil | NGL | Gas | Present Worth | |||||||||||||||||
Category |
(MBBL) | (MBBL) | (MMCF) | Total | at 10% | |||||||||||||||
Proved Developed Producing |
12,721.8 | 23,519.6 | 164,310.4 | 1,875,888.5 | 1,246,418.3 | |||||||||||||||
Proved Developed Non-Producing |
5,192.3 | 7,068.7 | 46,026.6 | 668,182.5 | 463,272.4 | |||||||||||||||
Proved Undeveloped |
11,878.4 | 14,135.3 | 85,164.4 | 1,137,929.2 | 645,876.6 | |||||||||||||||
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Total Proved |
29,792.4 | 44,723.6 | 295,501.3 | 3,681,999.9 | 2,355,567.6 |
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 Novo’s share of the gross (100 percent) revenue from the properties prior to any deductions. Future net revenue is after deductions for Novo’s share of production taxes, ad valorem 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.
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 for quality, transportation fees, and market differentials. For gas volumes, the average Henry Hub spot price of $6.357 per MMBTU is adjusted 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 $95.03 per barrel of oil, $35.98 per barrel of NGL, and $4.751 per MCF of gas.
Operating costs used in this report are based on operating expense records of Novo. For the nonoperated properties, these costs include the per-well overhead expenses allowed under joint operating agreements along with estimates of costs to be incurred at and below the district and field levels. As requested, operating costs for the operated properties are limited to direct lease- and field-level costs and Novo’s estimate of the portion of its headquarters general and administrative overhead expenses necessary to operate the properties. Operating costs have been divided into per-well costs and per-unit-of-production costs and are not escalated for inflation.
Capital costs used in this report were provided by Novo and are based on authorizations for expenditure and actual costs from recent activity. Capital costs are included as required for artificial lift installations, 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 Novo’s estimates of the costs to abandon the wells 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 Novo leasehold 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 Novo 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 Novo, 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, geologic maps, 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 and analogy, 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 undeveloped locations; such reserves are based on 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 Novo, 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 person primarily responsible for preparing the estimates presented herein meets 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. 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 |
|
Kyle B. Haft, P.E. 128929 | ||
Petroleum Engineer | ||
Date Signed: September 7, 2023 |
KBH:SMD
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.
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(7) Development costs. Costs incurred to obtain access to proved reserves and to provide facilities for extracting, treating, gathering and storing the oil and gas. More specifically, development costs, including depreciation and applicable operating costs of support equipment and facilities and other costs of development activities, are costs incurred to:
(i) | Gain access to and prepare well locations for drilling, including surveying well locations for the purpose of determining specific development drilling sites, clearing ground, draining, road building, and relocating public roads, gas lines, and power lines, to the extent necessary in developing the proved reserves. |
(ii) | Drill and equip development wells, development-type stratigraphic test wells, and service wells, including the costs of platforms and of well equipment such as casing, tubing, pumping equipment, and the wellhead assembly. |
Definitions - Page 1 of 6
DEFINITIONS OF OIL AND GAS RESERVES
Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)
(iii) | Acquire, construct, and install production facilities such as lease flow lines, separators, treaters, heaters, manifolds, measuring devices, and production storage tanks, natural gas cycling and processing plants, and central utility and waste disposal systems. |
(iv) | Provide improved recovery systems. |
(8) Development project. A development project is the means by which petroleum resources are brought to the status of economically producible. As examples, the development of a single reservoir or field, an incremental development in a producing field, or the integrated development of a group of several fields and associated facilities with a common ownership may constitute a development project.
(9) Development well. A well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive.
(10) Economically producible. The term economically producible, as it relates to a resource, means a resource which generates revenue that exceeds, or is reasonably expected to exceed, the costs of the operation. The value of the products that generate revenue shall be determined at the terminal point of oil and gas producing activities as defined in paragraph (a)(16) of this section.
(11) Estimated ultimate recovery (EUR). Estimated ultimate recovery is the sum of reserves remaining as of a given date and cumulative production as of that date.
(12) Exploration costs. Costs incurred in identifying areas that may warrant examination and in examining specific areas that are considered to have prospects of containing oil and gas reserves, including costs of drilling exploratory wells and exploratory-type stratigraphic test wells. Exploration costs may be incurred both before acquiring the related property (sometimes referred to in part as prospecting costs) and after acquiring the property. Principal types of exploration costs, which include depreciation and applicable operating costs of support equipment and facilities and other costs of exploration activities, are:
(i) | Costs of topographical, geographical and geophysical studies, rights of access to properties to conduct those studies, and salaries and other expenses of geologists, geophysical crews, and others conducting those studies. Collectively, these are sometimes referred to as geological and geophysical or “G&G” costs. |
(ii) | Costs of carrying and retaining undeveloped properties, such as delay rentals, ad valorem taxes on properties, legal costs for title defense, and the maintenance of land and lease records. |
(iii) | Dry hole contributions and bottom hole contributions. |
(iv) | Costs of drilling and equipping exploratory wells. |
(v) | Costs of drilling exploratory-type stratigraphic test wells. |
(13) Exploratory well. An exploratory well is a well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir. Generally, an exploratory well is any well that is not a development well, an extension well, a service well, or a stratigraphic test well as those items are defined in this section.
(14) Extension well. An extension well is a well drilled to extend the limits of a known reservoir.
(15) Field. An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition. There may be two or more reservoirs in a field which are separated vertically by intervening impervious strata, or laterally by local geologic barriers, or by both. Reservoirs that are associated by being in overlapping or adjacent fields may be treated as a single or common operational field. The geological terms “structural feature” and “stratigraphic condition” are intended to identify localized geological features as opposed to the broader terms of basins, trends, provinces, plays, areas-of-interest, etc.
(16) Oil and gas producing activities.
(i) | Oil and gas producing activities include: |
(A) | The search for crude oil, including condensate and natural gas liquids, or natural gas (“oil and gas”) in their natural states and original locations; |
(B) | The acquisition of property rights or properties for the purpose of further exploration or for the purpose of removing the oil or gas from such properties; |
(C) | The construction, drilling, and production activities necessary to retrieve oil and gas from their natural reservoirs, including the acquisition, construction, installation, and maintenance of field gathering and storage systems, such as: |
(1) | Lifting the oil and gas to the surface; and |
(2) | Gathering, treating, and field processing (as in the case of processing gas to extract liquid hydrocarbons); and |
Definitions - Page 2 of 6
DEFINITIONS OF OIL AND GAS RESERVES
Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)
(D) | Extraction of saleable hydrocarbons, in the solid, liquid, or gaseous state, from oil sands, shale, coalbeds, or other nonrenewable natural resources which are intended to be upgraded into synthetic oil or gas, and activities undertaken with a view to such extraction. |
Instruction 1 to paragraph (a)(16)(i): The oil and gas production function shall be regarded as ending at a “terminal point”, which is the outlet valve on the lease or field storage tank. If unusual physical or operational circumstances exist, it may be appropriate to regard the terminal point for the production function as:
a. | The first point at which oil, gas, or gas liquids, natural or synthetic, are delivered to a main pipeline, a common carrier, a refinery, or a marine terminal; and |
b. | In the case of natural resources that are intended to be upgraded into synthetic oil or gas, if those natural resources are delivered to a purchaser prior to upgrading, the first point at which the natural resources are delivered to a main pipeline, a common carrier, a refinery, a marine terminal, or a facility which upgrades such natural resources into synthetic oil or gas. |
Instruction 2 to paragraph (a)(16)(i): For purposes of this paragraph (a)(16), the term saleable hydrocarbons means hydrocarbons that are saleable in the state in which the hydrocarbons are delivered.
(ii) | Oil and gas producing activities do not include: |
(A) | Transporting, refining, or marketing oil and gas; |
(B) | Processing of produced oil, gas, or natural resources that can be upgraded into synthetic oil or gas by a registrant that does not have the legal right to produce or a revenue interest in such production; |
(C) | Activities relating to the production of natural resources other than oil, gas, or natural resources from which synthetic oil and gas can be extracted; or |
(D) | Production of geothermal steam. |
(17) Possible reserves. Possible reserves are those additional reserves that are less certain to be recovered than probable reserves.
(i) | When deterministic methods are used, the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves. When probabilistic methods are used, there should be at least a 10% probability that the total quantities ultimately recovered will equal or exceed the proved plus probable plus possible reserves estimates. |
(ii) | Possible reserves may be assigned to areas of a reservoir adjacent to probable reserves where data control and interpretations of available data are progressively less certain. Frequently, this will be in areas where geoscience and engineering data are unable to define clearly the area and vertical limits of commercial production from the reservoir by a defined project. |
(iii) | Possible reserves also include incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than the recovery quantities assumed for probable reserves. |
(iv) | The proved plus probable and proved plus probable plus possible reserves estimates must be based on reasonable alternative technical and commercial interpretations within the reservoir or subject project that are clearly documented, including comparisons to results in successful similar projects. |
(v) | Possible reserves may be assigned where geoscience and engineering data identify directly adjacent portions of a reservoir within the same accumulation that may be separated from proved areas by faults with displacement less than formation thickness or other geological discontinuities and that have not been penetrated by a wellbore, and the registrant believes that such adjacent portions are in communication with the known (proved) reservoir. Possible reserves may be assigned to areas that are structurally higher or lower than the proved area if these areas are in communication with the proved reservoir. |
(vi) | Pursuant to paragraph (a)(22)(iii) of this section, where direct observation has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves should be assigned in the structurally higher portions of the reservoir above the HKO only if the higher contact can be established with reasonable certainty through reliable technology. Portions of the reservoir that do not meet this reasonable certainty criterion may be assigned as probable and possible oil or gas based on reservoir fluid properties and pressure gradient interpretations. |
(18) Probable reserves. Probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.
(i) | When deterministic methods are used, it is as likely as not that actual remaining quantities recovered will exceed the sum of estimated proved plus probable reserves. When probabilistic methods are used, there should be at least a 50% probability that the actual quantities recovered will equal or exceed the proved plus probable reserves estimates. |
Definitions - Page 3 of 6
DEFINITIONS OF OIL AND GAS RESERVES
Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)
(ii) | Probable reserves may be assigned to areas of a reservoir adjacent to proved reserves where data control or interpretations of available data are less certain, even if the interpreted reservoir continuity of structure or productivity does not meet the reasonable certainty criterion. Probable reserves may be assigned to areas that are structurally higher than the proved area if these areas are in communication with the proved reservoir. |
(iii) | Probable reserves estimates also include potential incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than assumed for proved reserves. |
(iv) | See also guidelines in paragraphs (a)(17)(iv) and (a)(17)(vi) of this section. |
(19) Probabilistic estimate. The method of estimation of reserves or resources is called probabilistic when the full range of values that could reasonably occur for each unknown parameter (from the geoscience and engineering data) is used to generate a full range of possible outcomes and their associated probabilities of occurrence.
(20) Production costs.
(i) | Costs incurred to operate and maintain wells and related equipment and facilities, including depreciation and applicable operating costs of support equipment and facilities and other costs of operating and maintaining those wells and related equipment and facilities. They become part of the cost of oil and gas produced. Examples of production costs (sometimes called lifting costs) are: |
(A) | Costs of labor to operate the wells and related equipment and facilities. |
(B) | Repairs and maintenance. |
(C) | Materials, supplies, and fuel consumed and supplies utilized in operating the wells and related equipment and facilities. |
(D) | Property taxes and insurance applicable to proved properties and wells and related equipment and facilities. |
(E) | Severance taxes. |
(ii) | Some support equipment or facilities may serve two or more oil and gas producing activities and may also serve transportation, refining, and marketing activities. To the extent that the support equipment and facilities are used in oil and gas producing activities, their depreciation and applicable operating costs become exploration, development or production costs, as appropriate. Depreciation, depletion, and amortization of capitalized acquisition, exploration, and development costs are not production costs but also become part of the cost of oil and gas produced along with production (lifting) costs identified above. |
(21) Proved area. The part of a property to which proved reserves have been specifically attributed.
(22) Proved oil and gas reserves. Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.
(i) | The area of the reservoir considered as proved includes: |
(A) | The area identified by drilling and limited by fluid contacts, if any, and |
(B) | Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data. |
(ii) | In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty. |
(iii) | Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty. |
(iv) | Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when: |
(A) | Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and |
Definitions - Page 4 of 6
DEFINITIONS OF OIL AND GAS RESERVES
Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)
(B) | The project has been approved for development by all necessary parties and entities, including governmental entities. |
(v) | Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions. |
(23) Proved properties. Properties with proved reserves.
(24) Reasonable certainty. If deterministic methods are used, reasonable certainty means a high degree of confidence that the quantities will be recovered. If probabilistic methods are used, there should be at least a 90% probability that the quantities actually recovered will equal or exceed the estimate. A high degree of confidence exists if the quantity is much more likely to be achieved than not, and, as changes due to increased availability of geoscience (geological, geophysical, and geochemical), engineering, and economic data are made to estimated ultimate recovery (EUR) with time, reasonably certain EUR is much more likely to increase or remain constant than to decrease.
(25) Reliable technology. Reliable technology is a grouping of one or more technologies (including computational methods) that has been field tested and has been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation.
(26) Reserves. Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project.
Note to paragraph (a)(26): Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir, or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).
Excerpted from the FASB Accounting Standards Codification Topic 932, Extractive Activities—Oil and Gas:
932-235-50-30 A standardized measure of discounted future net cash flows relating to an entity’s interests in both of the following shall be disclosed as of the end of the year:
a. Proved oil and gas reserves (see paragraphs 932-235-50-3 through 50-11B)
b. Oil and gas subject to purchase under long-term supply, purchase, or similar agreements and contracts in which the entity participates in the operation of the properties on which the oil or gas is located or otherwise serves as the producer of those reserves (see paragraph 932-235-50-7).
The standardized measure of discounted future net cash flows relating to those two types of interests in reserves may be combined for reporting purposes.
932-235-50-31 All of the following information shall be disclosed in the aggregate and for each geographic area for which reserve quantities are disclosed in accordance with paragraphs 932-235-50-3 through 50-11B:
a. Future cash inflows. These shall be computed by applying prices used in estimating the entity’s proved oil and gas reserves to the year-end quantities of those reserves. Future price changes shall be considered only to the extent provided by contractual arrangements in existence at year-end.
b. Future development and production costs. These costs shall be computed by estimating the expenditures to be incurred in developing and producing the proved oil and gas reserves at the end of the year, based on year-end costs and assuming continuation of existing economic conditions. If estimated development expenditures are significant, they shall be presented separately from estimated production costs.
c. Future income tax expenses. These expenses shall be computed by applying the appropriate year-end statutory tax rates, with consideration of future tax rates already legislated, to the future pretax net cash flows relating to the entity’s proved oil and gas reserves, less the tax basis of the properties involved. The future income tax expenses shall give effect to tax deductions and tax credits and allowances relating to the entity’s proved oil and gas reserves.
d. Future net cash flows. These amounts are the result of subtracting future development and production costs and future income tax expenses from future cash inflows.
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.
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Definitions - Page 5 of 6
DEFINITIONS OF OIL AND GAS RESERVES
Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)
(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).
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(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 99.9
SEPTEMBER 7, 2023
Mr. Kyle Hoover
Novo Oil & Gas, LLC
1001 West Wilshire Boulevard, Suite 206
Oklahoma City, Oklahoma 73116
Dear Mr. Hoover:
In accordance with your request, we have estimated the proved reserves and future revenue, as of December 31, 2022, to the Novo Oil & Gas, LLC (Novo) royalty and overriding royalty interest in certain oil and gas properties located in Eddy and Lea Counties, New Mexico. We completed our evaluation on or about May 30, 2023. It is our understanding that the proved reserves estimated in this report constitute approximately 2 percent of all proved reserves owned by Novo. 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 Novo royalty and overriding royalty 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 |
391.4 | 610.7 | 3,848.5 | 69,293.6 | 42,033.7 | |||||||||||||||
Proved Developed Non-Producing |
198.1 | 219.0 | 1,327.0 | 29,791.4 | 18,601.1 | |||||||||||||||
Proved Undeveloped |
417.0 | 405.6 | 2,292.3 | 58,694.9 | 33,586.1 | |||||||||||||||
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Total Proved |
1,006.5 | 1,235.4 | 7,467.8 | 157,779.9 | 94,221.0 |
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 Novo’s share of the gross (100 percent) revenue from the properties prior to any deductions. Future net revenue is after deductions for Novo’s share of production taxes and ad valorem taxes but before consideration of any income taxes. The future net revenue has been discounted at an annual rate of 10 percent to determine its present worth, which is shown to indicate the effect of time on the value of money. Future net revenue presented in this report, whether discounted or undiscounted, should not be construed as being the fair market value of the properties.
Prices used in this report are based on the 12-month unweighted arithmetic average of the first-day-of-the-month price for each month in the period January through December 2022. For oil and NGL volumes, the average West Texas Intermediate spot price of $94.14 per barrel is adjusted for quality, transportation fees, and market differentials. For gas volumes, the average Henry Hub spot price of $6.357 per MMBTU is adjusted 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 $95.12 per barrel of oil, $35.73 per barrel of NGL, and $4.920 per MCF of gas.
Because this report is for the Novo royalty and overriding royalty interest in these properties, no operating costs, capital costs, or abandonment costs would be incurred. However, estimated operating costs and capital costs have been used to confirm economic producibility and determine economic limits for the properties. Operating costs used in this report are based on operating expense records of Novo. For the nonoperated properties, these costs include the per-well overhead expenses allowed under joint operating agreements along with estimates of costs to be incurred at and below the district and field levels. As requested, operating costs for the operated properties are limited to direct lease- and field-level costs and Novo’s estimate of the portion of its headquarters general and administrative overhead expenses necessary to operate the properties. Operating costs have been divided into per-well costs and per-unit-of-production costs. Capital costs used in this report were provided by Novo and are based on authorizations for expenditure and actual costs from recent activity. Capital costs are included as required for artificial lift installations, new development wells, and production equipment. Based on our understanding of Novo’s 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. Operating costs and capital 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. Because this report is for the Novo royalty and overriding royalty interest in these properties, no costs due to possible environmental liability would be incurred.
We have made no investigation of potential volume and value imbalances resulting from overdelivery or underdelivery to the Novo 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 Novo receiving its royalty and overriding royalty 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 Novo, 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 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 by the working interest owners 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, geologic maps, 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 and analogy, 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 undeveloped locations; such reserves are based on 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 Novo, 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 person primarily responsible for preparing the estimates presented herein meets 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. 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. |
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Richard B. Talley, Jr., P.E. | ||
Chief Executive Officer | ||
By: | /s/ Kyle B. Haft |
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Kyle B. Haft, P.E. 128929 | ||
Petroleum Engineer | ||
Date Signed: September 7, 2023 |
KBH:SMD
DEFINITIONS OF OIL AND GAS RESERVES
Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)
The following definitions are set forth in U.S. Securities and Exchange Commission (SEC) Regulation S-X Section 210.4-10(a). Also included is supplemental information from (1) the 2018 Petroleum Resources Management System approved by the Society of Petroleum Engineers, (2) the FASB Accounting Standards Codification Topic 932, Extractive Activities—Oil and Gas, and (3) the SEC’s Compliance and Disclosure Interpretations.
(1) Acquisition of properties. Costs incurred to purchase, lease or otherwise acquire a property, including costs of lease bonuses and options to purchase or lease properties, the portion of costs applicable to minerals when land including mineral rights is purchased in fee, brokers’ fees, recording fees, legal costs, and other costs incurred in acquiring properties.
(2) Analogous reservoir. Analogous reservoirs, as used in resources assessments, have similar rock and fluid properties, reservoir conditions (depth, temperature, and pressure) and drive mechanisms, but are typically at a more advanced stage of development than the reservoir of interest and thus may provide concepts to assist in the interpretation of more limited data and estimation of recovery. When used to support proved reserves, an “analogous reservoir” refers to a reservoir that shares the following characteristics with the reservoir of interest:
(i) | Same geological formation (but not necessarily in pressure communication with the reservoir of interest); |
(ii) | Same environment of deposition; |
(iii) | Similar geological structure; and |
(iv) | Same drive mechanism. |
Instruction to paragraph (a)(2): Reservoir properties must, in the aggregate, be no more favorable in the analog than in the reservoir of interest.
(3) Bitumen. Bitumen, sometimes referred to as natural bitumen, is petroleum in a solid or semi-solid state in natural deposits with a viscosity greater than 10,000 centipoise measured at original temperature in the deposit and atmospheric pressure, on a gas free basis. In its natural state it usually contains sulfur, metals, and other non-hydrocarbons.
(4) Condensate. Condensate is a mixture of hydrocarbons that exists in the gaseous phase at original reservoir temperature and pressure, but that, when produced, is in the liquid phase at surface pressure and temperature.
(5) Deterministic estimate. The method of estimating reserves or resources is called deterministic when a single value for each parameter (from the geoscience, engineering, or economic data) in the reserves calculation is used in the reserves estimation procedure.
(6) Developed oil and gas reserves. Developed oil and gas reserves are reserves of any category that can be expected to be recovered:
(i) | Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and |
(ii) | Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well. |
Supplemental definitions from the 2018 Petroleum Resources Management System:
Developed Producing Reserves – Expected quantities to be recovered from completion intervals that are open and producing at the effective date of the estimate. Improved recovery Reserves are considered producing only after the improved recovery project is in operation.
Developed Non-Producing Reserves – Shut-in and behind-pipe Reserves. Shut-in Reserves are expected to be recovered from (1) completion intervals that are open at the time of the estimate but which have not yet started producing, (2) wells which were shut-in for market conditions or pipeline connections, or (3) wells not capable of production for mechanical reasons. Behind-pipe Reserves are expected to be recovered from zones in existing wells that will require additional completion work or future re-completion before start of production with minor cost to access these reserves. In all cases, production can be initiated or restored with relatively low expenditure compared to the cost of drilling a new well.
(7) Development costs. Costs incurred to obtain access to proved reserves and to provide facilities for extracting, treating, gathering and storing the oil and gas. More specifically, development costs, including depreciation and applicable operating costs of support equipment and facilities and other costs of development activities, are costs incurred to:
(i) | Gain access to and prepare well locations for drilling, including surveying well locations for the purpose of determining specific development drilling sites, clearing ground, draining, road building, and relocating public roads, gas lines, and power lines, to the extent necessary in developing the proved reserves. |
(ii) | Drill and equip development wells, development-type stratigraphic test wells, and service wells, including the costs of platforms and of well equipment such as casing, tubing, pumping equipment, and the wellhead assembly. |
Definitions - Page 1 of 6
DEFINITIONS OF OIL AND GAS RESERVES
Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)
(iii) | Acquire, construct, and install production facilities such as lease flow lines, separators, treaters, heaters, manifolds, measuring devices, and production storage tanks, natural gas cycling and processing plants, and central utility and waste disposal systems. |
(iv) | Provide improved recovery systems. |
(8) Development project. A development project is the means by which petroleum resources are brought to the status of economically producible. As examples, the development of a single reservoir or field, an incremental development in a producing field, or the integrated development of a group of several fields and associated facilities with a common ownership may constitute a development project.
(9) Development well. A well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive.
(10) Economically producible. The term economically producible, as it relates to a resource, means a resource which generates revenue that exceeds, or is reasonably expected to exceed, the costs of the operation. The value of the products that generate revenue shall be determined at the terminal point of oil and gas producing activities as defined in paragraph (a)(16) of this section.
(11) Estimated ultimate recovery (EUR). Estimated ultimate recovery is the sum of reserves remaining as of a given date and cumulative production as of that date.
(12) Exploration costs. Costs incurred in identifying areas that may warrant examination and in examining specific areas that are considered to have prospects of containing oil and gas reserves, including costs of drilling exploratory wells and exploratory-type stratigraphic test wells. Exploration costs may be incurred both before acquiring the related property (sometimes referred to in part as prospecting costs) and after acquiring the property. Principal types of exploration costs, which include depreciation and applicable operating costs of support equipment and facilities and other costs of exploration activities, are:
(i) | Costs of topographical, geographical and geophysical studies, rights of access to properties to conduct those studies, and salaries and other expenses of geologists, geophysical crews, and others conducting those studies. Collectively, these are sometimes referred to as geological and geophysical or “G&G” costs. |
(ii) | Costs of carrying and retaining undeveloped properties, such as delay rentals, ad valorem taxes on properties, legal costs for title defense, and the maintenance of land and lease records. |
(iii) | Dry hole contributions and bottom hole contributions. |
(iv) | Costs of drilling and equipping exploratory wells. |
(v) | Costs of drilling exploratory-type stratigraphic test wells. |
(13) Exploratory well. An exploratory well is a well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir. Generally, an exploratory well is any well that is not a development well, an extension well, a service well, or a stratigraphic test well as those items are defined in this section.
(14) Extension well. An extension well is a well drilled to extend the limits of a known reservoir.
(15) Field. An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition. There may be two or more reservoirs in a field which are separated vertically by intervening impervious strata, or laterally by local geologic barriers, or by both. Reservoirs that are associated by being in overlapping or adjacent fields may be treated as a single or common operational field. The geological terms “structural feature” and “stratigraphic condition” are intended to identify localized geological features as opposed to the broader terms of basins, trends, provinces, plays, areas-of-interest, etc.
(16) Oil and gas producing activities.
(i) | Oil and gas producing activities include: |
(A) | The search for crude oil, including condensate and natural gas liquids, or natural gas (“oil and gas”) in their natural states and original locations; |
(B) | The acquisition of property rights or properties for the purpose of further exploration or for the purpose of removing the oil or gas from such properties; |
(C) | The construction, drilling, and production activities necessary to retrieve oil and gas from their natural reservoirs, including the acquisition, construction, installation, and maintenance of field gathering and storage systems, such as: |
(1) | Lifting the oil and gas to the surface; and |
(2) | Gathering, treating, and field processing (as in the case of processing gas to extract liquid hydrocarbons); and |
Definitions - Page 2 of 6
DEFINITIONS OF OIL AND GAS RESERVES
Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)
(D) | Extraction of saleable hydrocarbons, in the solid, liquid, or gaseous state, from oil sands, shale, coalbeds, or other nonrenewable natural resources which are intended to be upgraded into synthetic oil or gas, and activities undertaken with a view to such extraction. |
Instruction 1 to paragraph (a)(16)(i): The oil and gas production function shall be regarded as ending at a “terminal point”, which is the outlet valve on the lease or field storage tank. If unusual physical or operational circumstances exist, it may be appropriate to regard the terminal point for the production function as:
a. | The first point at which oil, gas, or gas liquids, natural or synthetic, are delivered to a main pipeline, a common carrier, a refinery, or a marine terminal; and |
b. | In the case of natural resources that are intended to be upgraded into synthetic oil or gas, if those natural resources are delivered to a purchaser prior to upgrading, the first point at which the natural resources are delivered to a main pipeline, a common carrier, a refinery, a marine terminal, or a facility which upgrades such natural resources into synthetic oil or gas. |
Instruction 2 to paragraph (a)(16)(i): For purposes of this paragraph (a)(16), the term saleable hydrocarbons means hydrocarbons that are saleable in the state in which the hydrocarbons are delivered.
(ii) | Oil and gas producing activities do not include: |
(A) | Transporting, refining, or marketing oil and gas; |
(B) | Processing of produced oil, gas, or natural resources that can be upgraded into synthetic oil or gas by a registrant that does not have the legal right to produce or a revenue interest in such production; |
(C) | Activities relating to the production of natural resources other than oil, gas, or natural resources from which synthetic oil and gas can be extracted; or |
(D) | Production of geothermal steam. |
(17) Possible reserves. Possible reserves are those additional reserves that are less certain to be recovered than probable reserves.
(i) | When deterministic methods are used, the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves. When probabilistic methods are used, there should be at least a 10% probability that the total quantities ultimately recovered will equal or exceed the proved plus probable plus possible reserves estimates. |
(ii) | Possible reserves may be assigned to areas of a reservoir adjacent to probable reserves where data control and interpretations of available data are progressively less certain. Frequently, this will be in areas where geoscience and engineering data are unable to define clearly the area and vertical limits of commercial production from the reservoir by a defined project. |
(iii) | Possible reserves also include incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than the recovery quantities assumed for probable reserves. |
(iv) | The proved plus probable and proved plus probable plus possible reserves estimates must be based on reasonable alternative technical and commercial interpretations within the reservoir or subject project that are clearly documented, including comparisons to results in successful similar projects. |
(v) | Possible reserves may be assigned where geoscience and engineering data identify directly adjacent portions of a reservoir within the same accumulation that may be separated from proved areas by faults with displacement less than formation thickness or other geological discontinuities and that have not been penetrated by a wellbore, and the registrant believes that such adjacent portions are in communication with the known (proved) reservoir. Possible reserves may be assigned to areas that are structurally higher or lower than the proved area if these areas are in communication with the proved reservoir. |
(vi) | Pursuant to paragraph (a)(22)(iii) of this section, where direct observation has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves should be assigned in the structurally higher portions of the reservoir above the HKO only if the higher contact can be established with reasonable certainty through reliable technology. Portions of the reservoir that do not meet this reasonable certainty criterion may be assigned as probable and possible oil or gas based on reservoir fluid properties and pressure gradient interpretations. |
(18) Probable reserves. Probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.
(i) | When deterministic methods are used, it is as likely as not that actual remaining quantities recovered will exceed the sum of estimated proved plus probable reserves. When probabilistic methods are used, there should be at least a 50% probability that the actual quantities recovered will equal or exceed the proved plus probable reserves estimates. |
Definitions - Page 3 of 6
DEFINITIONS OF OIL AND GAS RESERVES
Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)
(ii) | Probable reserves may be assigned to areas of a reservoir adjacent to proved reserves where data control or interpretations of available data are less certain, even if the interpreted reservoir continuity of structure or productivity does not meet the reasonable certainty criterion. Probable reserves may be assigned to areas that are structurally higher than the proved area if these areas are in communication with the proved reservoir. |
(iii) | Probable reserves estimates also include potential incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than assumed for proved reserves. |
(iv) | See also guidelines in paragraphs (a)(17)(iv) and (a)(17)(vi) of this section. |
(19) Probabilistic estimate. The method of estimation of reserves or resources is called probabilistic when the full range of values that could reasonably occur for each unknown parameter (from the geoscience and engineering data) is used to generate a full range of possible outcomes and their associated probabilities of occurrence.
(20) Production costs.
(i) | Costs incurred to operate and maintain wells and related equipment and facilities, including depreciation and applicable operating costs of support equipment and facilities and other costs of operating and maintaining those wells and related equipment and facilities. They become part of the cost of oil and gas produced. Examples of production costs (sometimes called lifting costs) are: |
(A) | Costs of labor to operate the wells and related equipment and facilities. |
(B) | Repairs and maintenance. |
(C) | Materials, supplies, and fuel consumed and supplies utilized in operating the wells and related equipment and facilities. |
(D) | Property taxes and insurance applicable to proved properties and wells and related equipment and facilities. |
(E) | Severance taxes. |
(ii) | Some support equipment or facilities may serve two or more oil and gas producing activities and may also serve transportation, refining, and marketing activities. To the extent that the support equipment and facilities are used in oil and gas producing activities, their depreciation and applicable operating costs become exploration, development or production costs, as appropriate. Depreciation, depletion, and amortization of capitalized acquisition, exploration, and development costs are not production costs but also become part of the cost of oil and gas produced along with production (lifting) costs identified above. |
(21) Proved area. The part of a property to which proved reserves have been specifically attributed.
(22) Proved oil and gas reserves. Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.
(i) | The area of the reservoir considered as proved includes: |
(A) | The area identified by drilling and limited by fluid contacts, if any, and |
(B) | Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data. |
(ii) | In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty. |
(iii) | Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty. |
(iv) | Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when: |
(A) | Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and |
Definitions - Page 4 of 6
DEFINITIONS OF OIL AND GAS RESERVES
Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)
(B) | The project has been approved for development by all necessary parties and entities, including governmental entities. |
(v) | Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions. |
(23) Proved properties. Properties with proved reserves.
(24) Reasonable certainty. If deterministic methods are used, reasonable certainty means a high degree of confidence that the quantities will be recovered. If probabilistic methods are used, there should be at least a 90% probability that the quantities actually recovered will equal or exceed the estimate. A high degree of confidence exists if the quantity is much more likely to be achieved than not, and, as changes due to increased availability of geoscience (geological, geophysical, and geochemical), engineering, and economic data are made to estimated ultimate recovery (EUR) with time, reasonably certain EUR is much more likely to increase or remain constant than to decrease.
(25) Reliable technology. Reliable technology is a grouping of one or more technologies (including computational methods) that has been field tested and has been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation.
(26) Reserves. Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project.
Note to paragraph (a)(26): Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir, or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).
Excerpted from the FASB Accounting Standards Codification Topic 932, Extractive Activities—Oil and Gas:
932-235-50-30 A standardized measure of discounted future net cash flows relating to an entity’s interests in both of the following shall be disclosed as of the end of the year:
a. | Proved oil and gas reserves (see paragraphs 932-235-50-3 through 50-11B) |
b. | Oil and gas subject to purchase under long-term supply, purchase, or similar agreements and contracts in which the entity participates in the operation of the properties on which the oil or gas is located or otherwise serves as the producer of those reserves (see paragraph 932-235-50-7). |
The standardized measure of discounted future net cash flows relating to those two types of interests in reserves may be combined for reporting purposes.
932-235-50-31 All of the following information shall be disclosed in the aggregate and for each geographic area for which reserve quantities are disclosed in accordance with paragraphs 932-235-50-3 through 50-11B:
a. | Future cash inflows. These shall be computed by applying prices used in estimating the entity’s proved oil and gas reserves to the year-end quantities of those reserves. Future price changes shall be considered only to the extent provided by contractual arrangements in existence at year-end. |
b. | Future development and production costs. These costs shall be computed by estimating the expenditures to be incurred in developing and producing the proved oil and gas reserves at the end of the year, based on year-end costs and assuming continuation of existing economic conditions. If estimated development expenditures are significant, they shall be presented separately from estimated production costs. |
c. | Future income tax expenses. These expenses shall be computed by applying the appropriate year-end statutory tax rates, with consideration of future tax rates already legislated, to the future pretax net cash flows relating to the entity’s proved oil and gas reserves, less the tax basis of the properties involved. The future income tax expenses shall give effect to tax deductions and tax credits and allowances relating to the entity’s proved oil and gas reserves. |
d. | Future net cash flows. These amounts are the result of subtracting future development and production costs and future income tax expenses from future cash inflows. |
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. |
Definitions - Page 5 of 6
DEFINITIONS OF OIL AND GAS RESERVES
Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)
(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