# EDGAR Filing Document

**Accession Number:** 0000789933
**File Stem:** 0000789933-23-000016
**Filing Date:** 2023-3
**Character Count:** 1180371
**Document Hash:** 9d8e81bf7fbe2f8ac5c86db4b647e110
**Contains OCR:** False
**Source Format:** 

## Filing Content

## Filing Summary
**0000789933-23-000016.hdr.sgml**: 20230315

**ACCESSION NUMBER**: 0000789933-23-000016

**CONFORMED SUBMISSION TYPE**: 10-K

**PUBLIC DOCUMENT COUNT**: 251

**CONFORMED PERIOD OF REPORT**: 20221231

**FILED AS OF DATE**: 20230315

**DATE AS OF CHANGE**: 20230315

**FILER**: 

**COMPANY DATA:**
- **COMPANY CONFORMED NAME:** NACCO INDUSTRIES INC
- **CENTRAL INDEX KEY:** 0000789933
- **STANDARD INDUSTRIAL CLASSIFICATION:** BITUMINOUS COAL & LIGNITE SURFACE MINING [1221]
- **IRS NUMBER:** 341505819
- **STATE OF INCORPORATION:** DE
- **FISCAL YEAR END:** 1231

**FILING VALUES:**
- **FORM TYPE:** 10-K
- **SEC ACT:** 1934 Act
- **SEC FILE NUMBER:** 001-09172
- **FILM NUMBER:** 23735831

**BUSINESS ADDRESS:**
- **STREET 1:** 5875 LANDERBROOK DR
- **STREET 2:** SUITE 220
- **CITY:** CLEVELAND
- **STATE:** OH
- **ZIP:** 44124-4069
- **BUSINESS PHONE:** 4402295123

**MAIL ADDRESS:**
- **STREET 1:** 5875 LANDERBROOK DR
- **CITY:** CLEVELAND
- **STATE:** OH
- **ZIP:** 44124

?xml version="1.0" ? nacco-20221231

    

**UNITED STATES**

**SECURITIES AND EXCHANGE COMMISSION**

**WASHINGTON, DC 20549**

**FORM 10-K**

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| | | |
|:---|:---|:---|
| (Mark One) | | |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;☑ | **ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934** | **ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934** |
| | **For the fiscal year ended** | **December 31, 2022** |

---

**or**

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;☐ **TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934**

**Commission File No. 1-9172**

**NACCO INDUSTRIES, INC.**

(Exact name of registrant as specified in its charter)

---

| | | | |
|:---|:---|:---|:---|
| **Delaware** | **Delaware** | **Delaware** | **34-1505819** |
| (State or other jurisdiction of incorporation or organization) | (State or other jurisdiction of incorporation or organization) | (State or other jurisdiction of incorporation or organization) | (I.R.S. Employer Identification No.) |
| **5875 Landerbrook Drive,** | **5875 Landerbrook Drive,** | **Suite 220** | |
| **Cleveland,** | **Ohio** | | **44124-4069** |
| (Address of principal executive offices) | (Address of principal executive offices) | (Address of principal executive offices) | (Zip Code) |

---

Registrant's telephone number, including area code: **(440) 229-5151**

Securities registered pursuant to Section 12(b) of the Act

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| | | |
|:---|:---|:---|
| Title of each class | Trading Symbol | Name of each exchange on which registered |
| Class A Common Stock, $1 par value per share | NC | New York Stock Exchange |

---

Securities registered pursuant to Section 12(g) of the Act: Class B Common Stock, $1 par value per share. Class B Common Stock is not publicly listed for trade on any exchange or market system; however, Class B Common Stock is convertible into Class A Common Stock on a share-for-share basis.

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp; Yes ◻&nbsp;&nbsp;&nbsp;&nbsp;**No** 🗹&nbsp;&nbsp;&nbsp;&nbsp;

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Yes ◻&nbsp;&nbsp;&nbsp;&nbsp;**No** 🗹

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp; **Yes** 🗹&nbsp;&nbsp;&nbsp;&nbsp; No ⬜

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files).

**Yes** 🗹&nbsp;&nbsp;&nbsp;&nbsp; No ⬜

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company or an emerging growth company. See definitions of "large accelerated filer," "accelerated filer," "smaller reporting company" and "emerging growth company" in Rule 12b-2 of the Exchange Act.

---

| | | | | | | | | | |
|:---|:---|:---|:---|:---|:---|:---|:---|:---|:---|
| Large accelerated filer | ☐ | **Accelerated filer** | ☑ | Non-accelerated filer | ☐ | **Smaller reporting company** | ☑ | 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. □

Indicate by check mark whether the registrant has filed a report on and attestation to its management's assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report. ☑

If securities are registered pursuant to Section 12(b) of the Act, indicate by check mark whether the financial statements of the registrant included in the filing reflect the correction of an error to previously issued financial statements. ☐

Indicate by check mark whether any of those error corrections are restatements that required a recovery analysis of incentive-based compensation received by any of the registrant's executive officers during the relevant recovery period pursuant to §240.10D-1(b). ☐

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act) Yes ☐&nbsp;&nbsp;&nbsp;&nbsp;**No** ☑

Aggregate market value of Class A Common Stock and Class B Common Stock held by non-affiliates as of June 30, 2022 (the last business day of the registrant's most recently completed second fiscal quarter): $159,988,559

Number of shares of Class A Common Stock outstanding at March 3, 2023: 5,936,134

Number of shares of Class B Common Stock outstanding at March 3, 2023: 1,565,929

**DOCUMENTS INCORPORATED BY REFERENCE**

Portions of the Company's Proxy Statement for its 2023 annual meeting of stockholders are incorporated herein by reference in Part III of this Form 10-K.

    

------

**<u>NACCO INDUSTRIES, INC.</u>**

**<u>**TABLE OF CONTENTS**</u>**

---

| | | | |
|:---|:---|:---|:---|
| | | | PAGE |
| **<u>[PART I.](#iaf3a05f346f8475da90341366c3f6933_10)</u>** |  |  |  |
|  | <u>[Item 1.](#iaf3a05f346f8475da90341366c3f6933_13)</u> | <u>[BUSINESS](#iaf3a05f346f8475da90341366c3f6933_13)</u> | <u>[1](#iaf3a05f346f8475da90341366c3f6933_13)</u> |
|  | <u>[Item 1A.](#iaf3a05f346f8475da90341366c3f6933_22)</u> | <u>[RISK FACTORS](#iaf3a05f346f8475da90341366c3f6933_22)</u> | <u>[19](#iaf3a05f346f8475da90341366c3f6933_22)</u> |
|  | <u>[Item 1B.](#iaf3a05f346f8475da90341366c3f6933_25)</u> | <u>[UNRESOLVED STAFF COMMENTS](#iaf3a05f346f8475da90341366c3f6933_25)</u> | <u>[29](#iaf3a05f346f8475da90341366c3f6933_25)</u> |
|  | <u>[Item 2.](#iaf3a05f346f8475da90341366c3f6933_28)</u> | <u>[PROPERTIES](#iaf3a05f346f8475da90341366c3f6933_28)</u> | <u>[29](#iaf3a05f346f8475da90341366c3f6933_28)</u> |
|  | <u>[Item 3.](#iaf3a05f346f8475da90341366c3f6933_40)</u> | <u>[LEGAL PROCEEDINGS](#iaf3a05f346f8475da90341366c3f6933_40)</u> | <u>[50](#iaf3a05f346f8475da90341366c3f6933_40)</u> |
|  | <u>[Item 4.](#iaf3a05f346f8475da90341366c3f6933_43)</u> | <u>[MINE SAFETY DISCLOSURES](#iaf3a05f346f8475da90341366c3f6933_43)</u> | <u>[50](#iaf3a05f346f8475da90341366c3f6933_43)</u> |
| **<u>[PART II.](#iaf3a05f346f8475da90341366c3f6933_46)</u>** |  |  |  |
|  | <u>[Item 5.](#iaf3a05f346f8475da90341366c3f6933_49)</u> | <u>[MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES](#iaf3a05f346f8475da90341366c3f6933_49)</u> | <u>[51](#iaf3a05f346f8475da90341366c3f6933_49)</u> |
|  | <u>[Item 6.](#iaf3a05f346f8475da90341366c3f6933_52)</u> | <u>[\[RESERVED\]](#iaf3a05f346f8475da90341366c3f6933_52)</u> | <u>[51](#iaf3a05f346f8475da90341366c3f6933_52)</u> |
|  | <u>[Item 7.](#iaf3a05f346f8475da90341366c3f6933_55)</u> | <u>[MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS](#iaf3a05f346f8475da90341366c3f6933_55)</u> | <u>[52](#iaf3a05f346f8475da90341366c3f6933_55)</u> |
|  | <u>[Item 7A.](#iaf3a05f346f8475da90341366c3f6933_85)</u> | <u>[QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK](#iaf3a05f346f8475da90341366c3f6933_85)</u> | <u>[68](#iaf3a05f346f8475da90341366c3f6933_85)</u> |
|  | <u>[Item 8.](#iaf3a05f346f8475da90341366c3f6933_88)</u> | <u>[FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA](#iaf3a05f346f8475da90341366c3f6933_88)</u> | <u>[68](#iaf3a05f346f8475da90341366c3f6933_88)</u> |
|  | <u>[Item 9.](#iaf3a05f346f8475da90341366c3f6933_91)</u> | <u>[CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE](#iaf3a05f346f8475da90341366c3f6933_91)</u> | <u>[68](#iaf3a05f346f8475da90341366c3f6933_91)</u> |
|  | <u>[Item 9A.](#iaf3a05f346f8475da90341366c3f6933_94)</u> | <u>[CONTROLS AND PROCEDURES](#iaf3a05f346f8475da90341366c3f6933_94)</u> | <u>[68](#iaf3a05f346f8475da90341366c3f6933_94)</u> |
|  | <u>[Item 9B.](#iaf3a05f346f8475da90341366c3f6933_97)</u> | <u>[OTHER INFORMATION](#iaf3a05f346f8475da90341366c3f6933_97)</u> | <u>[68](#iaf3a05f346f8475da90341366c3f6933_97)</u> |
|  | <u>[Item 9C](#iaf3a05f346f8475da90341366c3f6933_100)</u>.  | <u>[DISCLOSURE REGARDING FOREIGN JURISDICTIONS THAT PREVENT INSPECTIONS](#iaf3a05f346f8475da90341366c3f6933_100)</u> | <u>[68](#iaf3a05f346f8475da90341366c3f6933_100)</u> |
| **<u>[PART III.](#iaf3a05f346f8475da90341366c3f6933_103)</u>** |  |  |  |
|  | <u>[Item 10.](#iaf3a05f346f8475da90341366c3f6933_106)</u> | <u>[DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE](#iaf3a05f346f8475da90341366c3f6933_106)</u> | <u>[69](#iaf3a05f346f8475da90341366c3f6933_106)</u> |
|  | <u>[Item 11.](#iaf3a05f346f8475da90341366c3f6933_109)</u> | <u>[EXECUTIVE COMPENSATION](#iaf3a05f346f8475da90341366c3f6933_109)</u> | <u>[69](#iaf3a05f346f8475da90341366c3f6933_109)</u> |
|  | <u>[Item 12.](#iaf3a05f346f8475da90341366c3f6933_112)</u> | <u>[SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS](#iaf3a05f346f8475da90341366c3f6933_112)</u> | <u>[69](#iaf3a05f346f8475da90341366c3f6933_112)</u> |
|  | <u>[Item 13.](#iaf3a05f346f8475da90341366c3f6933_115)</u> | <u>[CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE](#iaf3a05f346f8475da90341366c3f6933_115)</u> | <u>[69](#iaf3a05f346f8475da90341366c3f6933_115)</u> |
|  | <u>[Item 14.](#iaf3a05f346f8475da90341366c3f6933_118)</u> | <u>[PRINCIPAL ACCOUNTANT FEES AND SERVICES](#iaf3a05f346f8475da90341366c3f6933_118)</u> | <u>[69](#iaf3a05f346f8475da90341366c3f6933_118)</u> |
| **<u>[PART IV.](#iaf3a05f346f8475da90341366c3f6933_121)</u>** |  |  |  |
|  | <u>[Item 15.](#iaf3a05f346f8475da90341366c3f6933_124)</u> | <u>[EXHIBITS AND FINANCIAL STATEMENT SCHEDULES](#iaf3a05f346f8475da90341366c3f6933_124)</u> | <u>[70](#iaf3a05f346f8475da90341366c3f6933_124)</u> |
| <u>[SIGNATURES](#iaf3a05f346f8475da90341366c3f6933_127)</u> | <u>[SIGNATURES](#iaf3a05f346f8475da90341366c3f6933_127)</u> | <u>[SIGNATURES](#iaf3a05f346f8475da90341366c3f6933_127)</u> | <u>[76](#iaf3a05f346f8475da90341366c3f6933_127)</u> |
| <u>[FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA](#iaf3a05f346f8475da90341366c3f6933_130)</u> | <u>[FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA](#iaf3a05f346f8475da90341366c3f6933_130)</u> | <u>[FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA](#iaf3a05f346f8475da90341366c3f6933_130)</u> | F-<u>[1](#iaf3a05f346f8475da90341366c3f6933_130)</u> |

---

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<u>[**Table of Contents**](#iaf3a05f346f8475da90341366c3f6933_7)</u>

**PART I**

**Item 1. BUSINESS**

**General**

NACCO Industries, Inc.<sup>®</sup> ("NACCO" or the "Company") brings natural resources to life by delivering aggregates, minerals, reliable fuels and environmental solutions through its robust portfolio of NACCO Natural Resources businesses. The Company operates under three business segments: Coal Mining, North American Mining ("NAMining") and Minerals Management. The Coal Mining segment operates surface coal mines for power generation companies. The NAMining segment is a trusted mining partner for producers of aggregates, activated carbon, lithium and other industrial minerals. The Minerals Management segment, which includes the Catapult Mineral Partners ("Catapult") business, acquires and promotes the development of mineral interests. Mitigation Resources of North America<sup>®</sup> ("Mitigation Resources") provides stream and wetland mitigation solutions.

The Company has items not directly attributable to a reportable segment that are not included as part of the measurement of segment operating profit, which primarily includes administrative costs related to public company reporting requirements at the parent company and the financial results of Mitigation Resources and Bellaire Corporation ("Bellaire"). Bellaire manages the Company's long-term liabilities related to former Eastern U.S. underground mining activities.

NACCO was incorporated as a Delaware corporation in 1986 in connection with the formation of a holding company structure for a predecessor corporation organized in 1913.

**Business Strategy**

NACCO's portfolio of businesses operates under the umbrella of NACCO Natural Resources. NACCO continues to focus on the execution of its two key strategies – Protect the Core and Grow and Diversify. Management continues to be optimistic about the long-term outlook in the NAMining and Minerals Management segments and in the Company's Mitigation Resources business. Each of these businesses continues to expand its pipeline of potential new projects with opportunities for growth and diversification. The Company also continues to pursue activities which can strengthen the resiliency of its existing coal mining operations.

NAMining remains committed to expanding its business while improving operating efficiencies and scalability. NAMining continues to work with Lithium Americas to develop the Thacker Pass Project in northern Nevada, one of the largest lithium projects in the United States. The Company believes NAMining can grow to be a substantial contributor to operating profit over time, but the pace of growth will be dependent on the mix and scale of new projects and the successful implementation of projects to return NAMining to profitability.

The Minerals Management segment continues to pursue acquisitions of mineral and royalty interests in the United States. Catapult, the Company's business unit focused on managing and expanding the Company's portfolio of oil and gas mineral and royalty interests, has developed a proven business model and a strong network to source and secure new acquisitions. The goal is to construct a high-quality diversified portfolio of oil and gas mineral and royalty interests in the United States that deliver near-term cash flow yields and long-term projected growth. The Minerals Management segment will benefit from the continued development of its mineral properties without additional capital investment, as development costs are borne entirely by third-party producers who lease the minerals. This business model can deliver higher average operating margins over the life of a reserve than traditional oil and gas companies that bear the cost of exploration, production and/or development.

Mitigation Resources creates and sells stream and wetland mitigation credits and provides services to those engaged in permittee-responsible mitigation and environmental restoration. This business offers an opportunity for growth and diversification in an industry where the Company has substantial knowledge and expertise and a strong reputation. During 2022, Mitigation Resources purchased property near Dallas-Fort Worth, Texas and near Nashville, Tennessee to establish new mitigation banks. In addition, it established a joint venture to provide mitigation services for the Lake Ralph Hall reservoir project in North Texas. As of December 31, 2022, Mitigation Resources is involved in over 10 mitigation banks and permittee-responsible mitigation projects in Tennessee, Alabama, Mississippi and Texas. With additional projects in its pipeline for 2023, Mitigation Resources is making strong progress toward its goal to be a top ten provider of stream and wetland mitigation services in the southeastern United States. The Company believes that Mitigation Resources can provide solid rates of return as this business matures.

The Company continues to pursue activities which can strengthen the resiliency of its existing coal mining operations. The

Company remains focused on managing coal production costs and maximizing efficiencies and operating capacity at mine

locations to help customers with management fee contracts be more competitive. These activities benefit both customers and

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<u>[**Table of Contents**](#iaf3a05f346f8475da90341366c3f6933_7)</u>

the Company's Coal Mining segment, since fuel cost is a significant driver for power plant dispatch. An increase in power plant dispatch results in increased demand for coal by the Coal Mining segment's customers. Fluctuating natural gas prices and

availability of renewable energy sources, such as wind and solar, could affect the amount of electricity dispatched from coal-fired power plants.

The Company is committed to maintaining a conservative capital structure as it continues to grow and diversify, while avoiding

unnecessary risk. Strategic diversification will generate cash that can be re-invested to strengthen and expand the businesses.

The Company also continues to maintain the highest levels of customer service and operational excellence with an unwavering

focus on safety and environmental stewardship.

**Business Developments**

Mississippi Lignite Mining Company ("MLMC") is the exclusive supplier of lignite to the Red Hills Power Plant in Ackerman, Mississippi. Choctaw Generation Limited Partnership ("CGLP") leases the Red Hills Power Plant from a Southern Company subsidiary pursuant to a leveraged lease arrangement. CGLP's ability to make required payments to the Southern Company subsidiary is dependent on the operational performance of the Red Hills Power Plant. During 2020, Southern Company revised the estimated cash flows to be received under the leveraged lease which resulted in a full impairment of the lease investment. If lease payments are not paid in full, the Southern Company subsidiary may be unable to make its corresponding payment to the holders of the underlying non-recourse debt related to the Red Hills Power Plant. Failure to make the required payment to the debtholders could represent an event of default that would give the debtholders the right to foreclose on, and take ownership of, the Red Hills Power Plant from the Southern Company subsidiary. On October 27, 2022, Southern Company disclosed in its Form 10-Q that it provided notice to the lessee, CGLP, to terminate the related operating and maintenance agreement effective June 30, 2023. CGLP failed to make the semi-annual lease payment due December 15, 2022. As a result, the Southern Company subsidiary was unable to make its corresponding payment to the debtholders. The parties to the lease agreement are currently negotiating a potential restructuring, which could result in rescission of the termination notice. The parties to the lease have entered into a forbearance agreement which suspends the related contractual rights of the parties while they continue restructuring negotiations. The ultimate outcome of this matter cannot be determined at this time but could have a material impact on the Company's financial statements if the operating and maintenance agreement is terminated.

The Falkirk Mining Company ("Falkirk") operates the Falkirk Mine in North Dakota. Falkirk is the sole supplier of lignite coal to the Coal Creek Station power plant. Coal Creek Station was previously owned by Great River Energy ("GRE"). On May 2, 2022, GRE completed the sale of Coal Creek Station and the adjacent high-voltage direct current transmission line to Rainbow Energy Center, LLC ("Rainbow Energy") and its affiliates. As a result of the completion of the sale of Coal Creek Station, the Coal Sales Agreement, the Mortgage and Security Agreement and the Option Agreement between GRE and Falkirk were terminated. The Coal Sales Agreement ("CSA") between Falkirk and Rainbow Energy became effective upon the closing of the transaction. Falkirk continues to supply all coal requirements of Coal Creek Station and is paid a management fee per ton of coal delivered. To support the transfer to new ownership, Falkirk agreed to a reduction in the current per ton management fee from the effective date of the CSA through May 31, 2024. After May 31, 2024, the per ton management fee increases to a higher base in line with 2021 fee levels, and thereafter adjusts annually according to an index which tracks broad measures of U.S. inflation. Rainbow Energy is responsible for funding all mine operating costs, including mine reclamation, and directly or indirectly providing all of the capital required to operate the mine. The initial production period is expected to run through May 1, 2032, but the CSA may be extended or terminated early under certain circumstances.

The Company recognized $30.9 million in the second quarter of 2022 as GRE paid NACoal $14.0 million in cash, transferred ownership of an office building with an estimated fair value of $4.1 million, and conveyed membership units in Midwest AgEnergy Group, LLC ("MAG"), a North Dakota-based ethanol business, with an estimated fair value of $12.8 million, as agreed to under the termination and release of claims agreement between Falkirk and GRE.

Prior to receiving the membership units from GRE, the Company held a $5.0 million investment in MAG. On December 1, 2022, HLCP Ethanol Holdco, LLC ("HLCP") completed its acquisition of MAG. Upon closing of the transaction, NACCO transferred its ownership interest in MAG to HLCP and received a cash payment of $18.6 million.

The Sabine Mining Company ("Sabine") operates the Sabine Mine in Texas. All production from Sabine is delivered to Southwestern Electric Power Company's ("SWEPCO") Henry W. Pirkey Plant (the "Pirkey Plant"). SWEPCO is an American Electric Power ("AEP") company. AEP intends to retire the Pirkey Plant during March 2023. Sabine expects deliveries to cease in March 2023 and final reclamation to begin on April 1, 2023. Funding for mine reclamation is the responsibility of SWEPCO, and Sabine will receive compensation for providing mine reclamation services.

In 2022, Minerals Management, through its Catapult business, completed two acquisitions. It acquired $11.4 million of mineral

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<u>[**Table of Contents**](#iaf3a05f346f8475da90341366c3f6933_7)</u>

and royalty interests in the Texas portion of the Permian Basin and the Wyoming portion of the Powder River Basin. It also completed a small acquisition of mineral interests in the New Mexico portion of the Permian Basin.

**Operations**

***Coal Mining Segment***

The Coal Mining segment, operating as The North American Coal Corporation<sup>®</sup> ("NACoal"), operates surface coal mines under long-term contracts with power generation companies pursuant to a service-based business model. Lignite coal is surface mined in North Dakota, Texas and Mississippi. Each mine is fully integrated with its customer's operations and is the exclusive supplier of coal to its customer's facilities.

During 2022, the Coal Mining segment's operating coal mines were: The Coteau Properties Company ("Coteau"), Coyote Creek Mining Company, LLC ("Coyote Creek"), Falkirk, MLMC and Sabine. Each of these mines supply lignite coal for power generation and delivers its coal production to an adjacent power plant or synfuels plant under a long-term supply contract. MLMC's coal supply contract contains a take or pay provision; all other coal supply contracts are requirements contracts under which earnings can fluctuate. Certain coal supply contracts can be terminated early, which would result in a reduction to future earnings.

At Coteau, Coyote Creek, Falkirk and Sabine, the Company is paid a management fee per ton of coal or heating unit (MMBtu)

delivered. Each contract specifies the indices and mechanics by which fees change over time, generally in line with broad

measures of U.S. inflation. The customers are responsible for funding all mine operating costs, including final mine

reclamation, and directly or indirectly providing all of the capital required to build and operate the mine. This contract structure eliminates exposure to spot coal market price fluctuations while providing income and cash flow with minimal capital

investment. Other than at Coyote Creek, debt financing provided by or supported by the customers is without recourse to

NACCO and NACoal. See Note 16 to the Consolidated Financial Statements in this Form 10-K for further discussion of Coyote Creek's guarantees.

Coteau, Coyote Creek, Falkirk and Sabine each meet the definition of a variable interest entity ("VIE"). In each case, NACCO

is not the primary beneficiary of the VIE as it does not exercise financial control; therefore, NACCO does not consolidate the

results of these operations within its financial statements. Instead, these contracts are accounted for as equity method

investments. The income before income taxes associated with these VIEs is reported as Earnings of unconsolidated operations

on the Consolidated Statements of Operations and the Company's investment is reported on the line Investments in unconsolidated subsidiaries in the Consolidated Balance Sheets. The mines that meet the definition of a VIE are referred to collectively as the "Unconsolidated Subsidiaries." For tax purposes, the Unconsolidated Subsidiaries are included within the NACCO consolidated U.S. tax return; therefore, the Income tax provision line on the Consolidated Statements of Operations includes income taxes related to these entities. See Note 16 to the Consolidated Financial Statements in this Form 10-K for further information on the Unconsolidated Subsidiaries.

While Falkirk meets the definition of a VIE, the completion of the Rainbow Energy transaction resulted in a VIE

reconsideration event. As the terms of the CSA between Falkirk and Rainbow Energy are substantially the same as the terms

of the coal supply contract between Falkirk and GRE, Falkirk remains a VIE and Rainbow Energy is the primary beneficiary; therefore, NACCO will continue to account for Falkirk under the equity method.

The Company performs contemporaneous reclamation activities at each mine in the normal course of operations. Under all of the Unconsolidated Subsidiaries' contracts, the customer has the obligation to fund final mine reclamation activities. Under certain contracts, the Unconsolidated Subsidiary holds the mine permit and is therefore responsible for final mine reclamation activities. To the extent the Unconsolidated Subsidiary performs such final reclamation, it is compensated for providing those services in addition to receiving reimbursement from customers for costs incurred.

The MLMC contract is the only operating coal contract in which the Company is responsible for all operating costs, capital requirements and final mine reclamation; therefore, MLMC is consolidated within NACCO's financial statements. MLMC sells coal to its customer at a contractually agreed-upon price which adjusts monthly, primarily based on changes in the level of established indices which reflect general U.S. inflation rates. Profitability at MLMC is affected by customer demand for coal and changes in the indices that determine sales price and actual costs incurred. As diesel fuel is heavily weighted among the indices used to determine the coal sales price, fluctuations in diesel fuel prices can result in significant fluctuations in earnings at MLMC.

MLMC delivers coal to the Red Hills Power Plant in Ackerman, Mississippi. The Red Hills Power Plant supplies electricity to the Tennessee Valley Authority ("TVA") under a long-term Power Purchase Agreement ("PPA"). MLMC's contract with its

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customer runs through 2032. TVA's power portfolio includes coal, nuclear, hydroelectric, natural gas and renewables. The decision of which power plants to dispatch is determined by TVA. Reduction in dispatch of the Red Hills Power Plant will result in reduced earnings at MLMC.

See "Item 2. Properties" on page 29 in this Form 10-K for discussion of the Company's mineral resources and mineral reserves.

***NAMining Segment***

The NAMining segment provides value-added contract mining and other services for producers of industrial minerals. The segment is a platform for the Company's growth and diversification of mining activities outside of the thermal coal industry. NAMining provides contract mining services for independently owned mines and quarries, creating value for its customers by performing the mining aspects of its customers' operations. This allows customers to focus on their areas of expertise: materials handling and processing, product sales and distribution. NAMining historically operated primarily at limestone quarries in Florida, but is focused on expanding outside of Florida, mining materials other than limestone and expanding the scope of mining operations provided to its customers. As of December 31, 2022, NAMining operates mines in Florida, Texas, Arkansas, Indiana, Virginia and Nebraska and will serve as exclusive contract miner for the Thacker Pass lithium project in northern Nevada.

Certain of the entities within the NAMining segment are VIEs and are accounted for under the equity method as Unconsolidated Subsidiaries. See Note 16 to the Consolidated Financial Statements in this Form 10-K for further information on the Unconsolidated Subsidiaries.

***Minerals Management Segment***

The Minerals Management segment derives income primarily by leasing its royalty and mineral interests to third-party exploration and production companies, and, to a lesser extent, other mining companies, granting them the rights to explore, develop, mine, produce, market and sell gas, oil, and coal in exchange for royalty payments based on the lessees' sales of those minerals.

The Minerals Management segment owns royalty interests, mineral interests, nonparticipating royalty interests and overriding royalty interests.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• Royalty Interest. Royalty interests generally result when the owner of a mineral interest leases the underlying minerals to an exploration and production company pursuant to an oil and gas lease. Typically, the resulting royalty interest is a cost-free percentage of production revenues for minerals extracted from the acreage. A holder of royalty interests is generally not responsible for capital expenditures or lease operating expenses, but royalty interests may be calculated net of post-production expenses, and typically has no environmental liability. Royalty interests leased to producers expire upon the expiration of the oil and gas lease and revert to the mineral owner.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• Mineral Interest. Mineral interests are perpetual rights of the owner to explore, develop, exploit, mine and/or produce any or all of the minerals lying below the surface of the property. The holder of a mineral interest has the right to lease the minerals to an exploration and production company. Upon the execution of an oil and gas lease, the lessee (the exploration and production company) becomes the working interest owner and the lessor (the mineral interest owner) has a royalty interest.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• Non-Participating Royalty Interest ("NPRIs"). NPRI is an interest in oil and gas production which is created from the mineral estate. The NPRI is expense-free, bearing no operational costs of production. The term "non-participating" indicates that the interest owner does not share in the bonus, rentals from a lease, nor the right to participate in the execution of oil and gas leases. The NPRI owner does; however, typically receive royalty payments.

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The Company may own more than one type of mineral and royalty interest in the same tract of land. For example, where the Company owns an ORRI in a lease on the same tract of land in which it owns a mineral interest, the ORRI in that tract will relate to the same gross acres as the mineral interest in that tract.

The Minerals Management segment will benefit from the continued development of its mineral properties without the need for investment of additional capital once mineral and royalty interests have been acquired. The Minerals Management segment does not currently have any material investments under which it would be required to bear the cost of exploration, production or development.

Total consideration for the 2022 and 2021 acquisitions of mineral and royalty interests was $11.9 million and $5.3 million, respectively. The 2022 acquisitions included 13.6 thousand gross acres and 880 net royalty acres. The 2021 acquisitions included 20.6 thousand gross acres and 1.8 thousand net royalty acres. Total mineral and royalty interests included approximately 141.4 thousand gross acres and 60.8 thousand net royalty acres at December 31, 2022.

The acquisition criteria for building a blended portfolio of mineral and royalty interests includes (i) new wells anticipated to come online within one to two years of investment, (ii) areas with forecasted future development within five years after acquisition, or (iii) existing producing wells further along the decline curve that will generate stable cash flow. In addition, acquisitions should extend the geographic footprint to diversify across multiple basins with a preliminary focus on the more oil-rich Permian basin and a secondary focus on other diversifying basins to increase regional exposure. While the current focus is on the acquisition of mineral and royalty interests, the Company would also consider investments in ORRIs, NPRIs or non-operated working interests under certain circumstances. The current acquisition strategy does not contemplate any near-term working interest investments in which the Company would act as the operator.

The Company also manages legacy royalty and mineral interests located in Ohio (Utica and Marcellus shale natural gas), Louisiana (Haynesville shale and Cotton Valley formation natural gas), Texas (Cotton Valley and Austin Chalk formation natural gas), Mississippi (coal), Pennsylvania (coal, coalbed methane and Marcellus shale natural gas), Alabama (coal, coalbed methane and natural gas) and North Dakota (coal, oil and natural gas). The majority of the Company's legacy reserves were acquired as part of its historical coal mining operations.

See "Item 2. Properties" on page 29 in this Form 10-K for discussion of the Company's proved reserves.

**Customers**

The principal customers of the Coal Mining segment are electric utilities and an independent power provider.

The principal customers of the NAMining segment are limestone producers and to a lesser extent, sand and gravel producers. In addition, NAMining will serve as exclusive contract miner for the Thacker Pass lithium project in northern Nevada.

The Minerals Management segment generates income primarily from royalty-based lease payments from oil, gas and to a lesser extent, coal producers. The pricing of oil, gas and coal sales is primarily determined by supply and demand in the marketplace and can fluctuate considerably. As a mineral owner, the Company has limited access to timely information, involvement, and operational control over the volumes of oil, gas and coal produced and sold and the terms and conditions on which such volumes are marketed and sold.

In 2022 and 2021, two customers individually accounted for more than 10% of consolidated revenues. The following represents the revenue attributable to each of these entities as a percentage of consolidated revenues for those years:

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| | | |
|:---|:---|:---|
| | Percentage of Consolidated Revenues | Percentage of Consolidated Revenues |
| **Segment** | **2022** | 2021 |
| Coal Mining customer | 39% | 43% |
| NAMining customer | 17% | 19% |

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The loss of either of these customers could have a material adverse effect on the results of operations attributable to the applicable segment and on the Company's consolidated results of operations.

**Competition**

Coteau, Coyote Creek, Falkirk, MLMC and Sabine each have only one customer for which they extract and deliver coal. The Company's coal mines are directly adjacent to the customer's property, with economical delivery methods that include

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conveyor belt delivery systems linked to the customer's facilities or short-haul rail systems. All of the mines in the Coal Mining segment are the most economical suppliers to each of their respective customers as a result of transportation advantages over competitors. In addition, the customers' facilities were specifically designed to use the coal being mined.

The coal industry competes with other sources of energy, particularly oil, gas, hydro-electric power and nuclear power. In addition, it competes with subsidized sources of energy, primarily wind and solar. Among the factors that affect competition are the price and availability of oil and natural gas, environmental and related political considerations, the time and expenditures required to develop new energy sources, the cost of transportation, the cost of compliance with governmental regulations, the impact of federal and state energy policies, the impact of subsidies on renewable pricing and the Company's customers' dispatch decisions, which may also take into account carbon dioxide emissions. The ability of the Coal Mining segment to maintain comparable levels of coal production at existing facilities and develop its reserves will depend upon the interaction of these factors.

Electricity generating units are chosen to run primarily based on operating costs, of which fuel costs account for the largest share. Natural gas-fired power plants have the most potential to displace coal-fired electric baseload power generation in the near term. Federal and state mandates for increased use of electricity derived from renewable energy sources could also negatively affect demand for coal. Such mandates, combined with other incentives to use renewable energy sources, such as tax credits, make alternative fuel sources more competitive with coal. Fluctuations in natural gas prices and the availability of renewable generation, particularly wind, can contribute to changes in power plant dispatch and customer demand for coal. Sustained higher natural gas prices could lead to increased demand for coal and positively affect the Coal Mining segment results. Over the longer term, the Company continues to believe that customer demand will remain pressured by continuing increases in subsidized renewable generation sources, particularly wind and solar. See "Item 1. Business — Government Regulation" on page 8 in this Form 10-K for further discussion. Environmental, social and governance considerations can also have an impact on power plant dispatch and demand for coal.

Based on industry information, the Company believes it was one of the ten largest coal producers in the U.S. in 2022 based on total coal tons produced.

NAMining faces competition from producers of aggregates, lithium or other minerals that choose to self-perform mining operations and from other mining companies.

In the Minerals Management segment, the oil and gas industry is intensely competitive; the Company primarily competes with companies and investors for the acquisition of oil and gas properties, some of which have greater resources and may be able to pay more for productive oil and natural gas properties or to define, evaluate, bid for and purchase a greater number of properties than the Company's financial resources permit. Additionally, many of the Minerals Management segment's competitors are, or are affiliated with, operators that engage in the exploration and production of their oil and gas properties, which allows them to acquire larger assets that include operated properties. Larger or more integrated competitors may be able to absorb the burden of existing, and any changes to, federal, state and local laws and regulations more easily than the Company can, which would adversely affect its competitive position. The integrated competitors may also have a better understanding of when minerals they acquire will be developed, as they are often the developer. The Minerals Management segment's ability to acquire additional properties in the future will be dependent upon its ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment.

**Seasonality**

The Company has experienced limited variability in its results due to the effect of seasonality; however, variations in coal demand can occur as a result of the timing and duration of planned or unplanned outages at customers' facilities. Variations in coal demand can also occur as a result of changes in market prices of competing fuels such as natural gas, wind and solar power and demand for electricity, which can fluctuate based on changes in weather patterns.

The NAMining segment extracts a significant amount of the annual limestone produced in Florida. The Florida construction industry can be affected by the cyclicality of the economy, seasonal weather conditions and pandemics, all of which can result in variations in demand for aggregates.

In the Minerals Management segment, oil and natural gas wells have high initial production rates and follow a natural decline before settling into relatively stable, long-term production. Decline rates can vary due to factors like well depth, well length, geology, formation pressure, and facility design. In addition to the natural production decline curve, royalty income can fluctuate favorably or unfavorably in response to a number of factors outside of the Company's control, including the number of wells being operated by third parties, fluctuations in commodity prices (primarily oil and natural gas), fluctuations in

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production rates associated with operator decisions, regulatory risks, the Company's lessees' willingness and ability to incur well-development and other operating costs, and changes in the availability and continuing development of infrastructure.

**Human Capital**

As of December 31, 2022, the Company and its subsidiaries had approximately 1,600 employees, including approximately 1,100 employees at the Company's unconsolidated mining operations, none of which are represented by a collective bargaining agreement. NACCO believes it has good relations with its employees.

Market-Based Compensation: NACCO believes its employees are critical to its success and invests in its employees by offering a market-based competitive total rewards package that includes a combination of salaries and wages and a benefits package that promotes employee well-being across all aspects of their lives. The Company provides employee wages that are competitive and consistent with employee positions, skill levels, experience, knowledge and geographic location. Benefits offered to employees include:

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• Medical, dental and vision benefits for employees, spouses and dependents;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• Flexible spending accounts for both healthcare and dependent care;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• Health savings accounts and health reimbursement accounts, both of which receive company contributions;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• Paid vacation and holidays;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• Parental leave;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• Short-term and long-term disability benefits;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• Wellness incentives for employees;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• Life and AD&D insurance benefits;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• Charitable donation matches; and

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• Employee assistance program.

Employee Development: The Company recognizes that its culture and success is strengthened when employees are respected, motivated and engaged. The Company works to match employees with assignments that capitalize on the skills, talents and potential of each employee, and provides opportunities for professional growth. The Company believes in hiring, engaging, developing and promoting people who are fully able to meet the demands of each position, regardless of race, color, religion, gender, sexual orientation, gender identity, national origin, age, veteran status or disability.

Safety: Employee safety in the workplace is one of the Company's core values. The Company is committed to strict compliance with applicable laws and regulations regarding workplace safety and provides on-going safety training, education and communication. The National Mining Association ranks NACCO as an industry leader in safety, and the Company's incident rate is consistently below the national average for comparable mines, based on Mine Safety and Health Administration data. The Company has earned more than 100 safety awards at the state and national levels. Hazards in the workplace are actively identified and management tracks incidents so remedial actions can be taken to improve workplace safety. The Company believes communication related to "near misses," safety incidents and protocols is essential to continuously developing and maintaining best-practices related to safety and enables identification and correction of operational practices that might impair employee safety or health.

Company Ethics: The Company has processes in place for compliance with its Code of Corporate Conduct, Insider Trading Policy and Anti-Corruption Policy. All of the Company's Directors and employees annually complete certifications with respect to compliance with the Company's Code of Corporate Conduct. In addition, all employees of the Company are required to complete annual Code of Corporate Conduct training. The Code of Corporate Conduct, Insider Trading Policy and Anti-Corruption Policy require employees to comply with applicable laws and regulations, maintain high ethical standards and report situations of actual or potential noncompliance. The Company also maintains an ethics related hotline, managed by a third party, through which individuals can anonymously raise concerns or ask questions about business behavior.

Community Engagement: The Company supports its local communities and is committed to helping them remain safe, healthy and resilient. The Company's past activities include corporate donations, volunteerism and education. Community engagement is encouraged and supported through the Company's matching gift program. The Company will match employee contributions up to $5,000 per employee if program criteria are met.

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**Available Information**

The Company makes its annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and any amendments to those reports available through its website, www.nacco.com, as soon as reasonably practicable after such material is electronically filed with, or furnished to, the Securities and Exchange Commission ("SEC"). The content of the Company's website is not incorporated by reference into this Form 10-K or in any other report or document filed with the SEC, and any reference to the Company's website is intended to be an inactive textual reference only. The SEC maintains an internet site at http://www.sec.gov that contains reports, proxy and information statements, and other information regarding the Company and other issuers that file electronically with the SEC.

Under Rule 12b-2 of the Exchange Act, the Company qualifies as a "smaller reporting company" because its public float as of the last business day of the Company's most recently completed second quarter was less than $250 million. For as long as the Company remains a "smaller reporting company," it may take advantage of certain exemptions from the SEC's reporting requirements that are otherwise applicable to public companies that are not smaller reporting companies.

**Government Regulation**

The Company's operations are subject to various federal, state and local laws and regulations on matters such as employee health and safety, and certain environmental laws and regulations relating to, among other matters, the reclamation and restoration of coal mining properties, air pollution, water pollution, the disposal of wastes and effects on groundwater. In addition, the electric power generation industry is subject to extensive regulation regarding the environmental impact of its power generation activities that could affect demand for coal from the Company's Coal Mining segment.

Numerous governmental permits and approvals are required for coal mining operations. The Company's subsidiaries hold or will hold the necessary permits at all of its lignite coal mining operations. At the coal mining operations where the Company's subsidiaries hold the permits, the Company is required to prepare and present to federal, state or local governmental authorities data pertaining to the effect or impact that any proposed exploration for or production of coal may have upon the environment and public and employee health and safety.

Some laws, as discussed below, place many requirements on the coal mining operations and the limestone quarries where the Company provides services. Federal and state regulations require regular monitoring of the Company's operations to ensure compliance.

Many aspects of the production, pricing and marketing of oil and natural gas are regulated by federal and state agencies. Legislation affecting the oil and natural gas industry is under constant review for amendment or expansion, which frequently increases the regulatory burden on affected members of the industry and could affect the results of the Company's Minerals Management segment.

<u>Mine Health and Safety Laws</u>

The Federal Mine Safety and Health Act of 1977 imposes safety and health standards on all mining operations. Regulations are comprehensive and affect numerous aspects of mining operations, including training of mine personnel, mining procedures, blasting, the equipment used in mining operations and other matters. The Federal Mine Safety and Health Administration enforces compliance with these federal laws and regulations.

<u>Environmental Laws</u>

The Company's coal mining operations are subject to various federal environmental laws, as amended, including:

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• the Surface Mining Control and Reclamation Act of 1977 ("SMCRA");

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• the Clean Air Act, including amendments to that act in 1990 ("CAA");

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• the Clean Water Act of 1972 ("CWA");

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• the Resource Conservation and Recovery Act ("RCRA");

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• the National Environmental Policy Act of 1970 ("NEPA"); and

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• the Comprehensive Environmental Response, Compensation and Liability Act ("CERCLA").

In addition to these federal environmental laws, various states have enacted environmental laws that provide for higher levels of environmental compliance than similar federal laws. These state environmental laws require reporting, permitting and/or approval of many aspects of coal mining operations. Both federal and state inspectors regularly visit mines to enforce compliance. The Company has ongoing training, compliance and permitting programs to ensure compliance with such environmental laws. Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent and costly pollution control or waste handling, storage, transport, disposal or cleanup requirements could materially adversely affect the Coal Mining segment.

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<u>Surface Mining Control and Reclamation Act</u>

SMCRA establishes mining, environmental protection and reclamation standards for all aspects of surface coal mining operations. Where state regulatory agencies have adopted federal mining programs under SMCRA, the state becomes the primary regulatory authority.

Coal mine operators must obtain SMCRA permits and permit renewals for coal mining operations from the applicable regulatory agency. These SMCRA permit provisions include requirements for coal prospecting, mine plan development, topsoil removal, storage and replacement, selective handling of overburden materials, mine pit backfilling and grading, protection of the hydrologic balance, surface drainage control, mine drainage and mine discharge control and treatment, and revegetation.

Although mining permits have stated expiration dates, SMCRA provides for a right of successive renewal. The cost of obtaining surface mining permits can vary widely depending on the quantity and type of information that must be provided to obtain the permits; however, the cost of obtaining a permit is usually between $1,000,000 and $5,000,000, and the cost of obtaining a permit renewal is usually between $15,000 and $100,000.

The Abandoned Mine Land Fund, which is provided for by SMCRA, imposes a fee on certain coal mining operations. The proceeds are intended to be used principally to reclaim mine lands closed prior to 1977. In addition, the Abandoned Mine Land Fund also makes transfers annually to the United Mine Workers of America Combined Benefit Fund (the "Fund"), which provides health care benefits to retired coal miners who are beneficiaries of the Fund. The 2021 Infrastructure Investment and Jobs Act reauthorized the Abandoned Mine Land fee at a reduced rate. The fee for lignite coal was reduced from $0.08 per ton to $0.064 per ton and for other surface-mined coal from $0.28 per ton to $0.224 per ton. These fees have been reauthorized until the end of fiscal year 2035.

SMCRA establishes operational, reclamation and closure standards for surface coal mines. The Company accrues for the costs of current mine disturbance and final mine closure, including the cost of treating mine water discharges, at mines where the Company's subsidiaries hold the mining permit. These obligations are largely unfunded, with the exception of the final mine closure costs for the Coyote Creek Mine, which are being funded throughout the production stage.

SMCRA stipulates compliance with many other major environmental programs, including the CAA and CWA. The U.S. Army Corps of Engineers regulates activities affecting navigable waters, and the U.S. Bureau of Alcohol, Tobacco and Firearms regulates the use of explosives for blasting. In addition, the U.S. Environmental Protection Agency (the "EPA"), the U.S. Army Corps of Engineers and the Office of Surface Mining Reclamation and Enforcement ("OSMRE") have engaged in a series of rulemakings and other administrative actions under the CWA and other statutes that are directed at reducing the impact of coal mining operations on water bodies.

The Company does not believe there is any significant risk to the Company's subsidiaries ability to maintain its existing mining permits or its ability to acquire future mining permits for its mines.

<u>Clean Air Act</u>

The process of burning coal can cause many compounds and impurities in the coal to be released into the air, including sulfur dioxide, nitrogen oxides, mercury, particulates and other matter. The CAA and the corresponding state laws that extensively regulate the emissions of materials into the air affect coal mining operations both directly and indirectly. Direct impacts on coal mining operations occur through CAA permitting requirements and/or emission control requirements relating to air contaminants, especially particulate matter. Indirect impacts on coal mining operations occur through regulation of the air emissions of sulfur dioxide, nitrogen oxides, mercury, particulate matter and other compounds emitted by coal-fired power plants. The EPA has promulgated or proposed regulations that impose tighter emission restrictions in a number of areas, some of which are currently subject to litigation. The general effect of tighter restrictions is to reduce demand for coal. Ongoing reduction in coal's share of the capacity for power generation could have a material adverse effect on the Company's business, financial condition and results of operations.

States are required to submit to the EPA revisions to their state implementation plans ("SIPs") that demonstrate the manner in which the states will attain national ambient air quality standards ("NAAQS") every time a NAAQS is issued or revised by the EPA. The EPA has adopted NAAQS for several pollutants, which continue to be reviewed periodically for revisions. When the EPA adopts new, more stringent NAAQS for a pollutant, some states have to change their existing SIPs. If a state fails to revise its SIP and obtain EPA approval, the EPA may adopt regulations to effect the revision. Coal mining operations and coal-fired power plants that emit particulate matter or other specified material are, therefore, affected by changes in the SIPs. Through this process over the last few years, the EPA has reduced the NAAQS for particulate matter, ozone, and nitrogen oxides. The Company's coal mining operations and power generation customers may be directly affected when the revisions to the SIPs are made and incorporate new NAAQS for sulfur dioxide, nitrogen oxides, ozone and particulate matter. In March 2019, the EPA

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published a final rule that retains the current primary (health-based) NAAQS for sulfur oxides ("SOx") without revision. The current primary standard is set at a level of 75 parts per billion, as the 99th percentile of daily maximum 1-hour SO2 concentrations, averaged over 3 years.

In mid-2011, the EPA finalized the Cross-State Air Pollution Rule ("CSAPR") to address interstate transport of pollutants. This affects states in the eastern half of the U.S. and Texas. This rule imposes additional emission restrictions on coal-fired power plants to attain ozone and fine particulate NAAQS. The EPA began implementation of the rule in 2015, when Phase I emission reductions in sulfur dioxide and nitrogen dioxide became effective. Phase II reductions became effective in 2017. In 2016, the EPA mandated additional reductions in nitrogen oxide emissions. The U.S. Court of Appeals for the District of Columbia Circuit ("D.C. Circuit") remanded the CSAPR Update to the EPA to address the court's holding that the rule unlawfully allows significant contribution to continue beyond downwind attainment deadlines. In 2018, the EPA finalized all remaining ozone designations to comply with the 2015 ozone air quality standards. The U.S. Court of Appeals for the D.C. Circuit issued a per curium opinion rejecting various industry challenges to the EPA's 2015 revisions to the ozone NAAQS, including that the EPA was required to consider certain adverse effects and background ozone when setting the standards. None of the power plants supplied by the Company are within non-attainment areas for ozone. In March 2022, the EPA announced a federal plan to "help states fully resolve their Clean Air Act 'good neighbor' obligations for the 2015 ozone NAAQS. This new plan would double the number of covered states and require daily limits on emissions from large coal-fired power plants. The plan would also broaden the existing nitrogen oxides power plant trading program from 12 states to 25 during the summertime ozone season while also ratcheting down nitrogen oxides caps for states, starting in 2023. If this plan is finalized as proposed, it could have a material adverse effect on the Company's business, financial condition or results of operations.

The CAA Acid Rain Control Provisions were promulgated as part of the CAA Amendments of 1990 in Title IV of the CAA ("Acid Rain Program"). The Acid Rain Program required reductions of sulfur dioxide emissions from coal-fired power plants. The Acid Rain Program is now a mature program, and the Company believes that any market impacts of the required controls have likely been factored into the coal market.

The EPA promulgated a regional haze program designed to protect and to improve visibility at and around Class I Areas, which are generally National Parks, National Wilderness Areas and International Parks. This program may restrict the construction of new coal-fired power plants, the operation of which may impair visibility at and around the Class I Areas. Additionally, the program requires certain existing coal-fired power plants to install additional control measures designed to limit haze-causing emissions, such as sulfur dioxide, nitrogen oxide and particulate matter. States were required to submit Regional Haze SIPs to the EPA in 2007; however, many states did not meet that deadline. In 2016, the EPA finalized revisions to the Regional Haze Rule which addresses requirements for the second planning period. In September 2019, the EPA issued final regional haze guidance that indicates that a re-evaluation of sources already subject to best available retrofit technologies ("BART") is likely unnecessary. The guidance also encourages states to balance visibility benefits against other factors in selecting the measures necessary to make "reasonable progress" toward natural visibility conditions. Finally, when comparing various control options to determine which ones may be "cost-effective," the final guidance recommends comparing cost to visibility benefits. In July of 2021, the EPA released a memorandum to clarify the guidance issued in 2019. While this clarification memorandum attempted to reverse some of the core conclusions made in the 2019 guidance, it was released after the air analyses to develop individual SIPs had been completed and just prior to the SIP submittal deadline to the EPA, which was July 31, 2021. Many SIP submittals were delayed due to emissions modeling and continue to be developed and scrutinized. SIPs have been sent to the EPA for approval following both review by federal land managers of the National Park Service, the United States Fish and Wildlife Service and the United States Forest Service and all corresponding public comment periods.

State implementation of the EPA's Regional Haze Rule could require Coyote Creek's customers to incur significant new costs at the Coyote Station power plant, which could result in the premature closure of the power plant and the Coyote Creek mine. The North Dakota Department of Environmental Quality ("NDDEQ") finalized its state implementation plan and submitted it to the EPA for approval in August 2022. The NDDEQ determined that visibility progress was being made and did not require significant emissions controls at Coyote Station power plant. Notwithstanding NDDEQ's determination, the EPA may require additional costly emission controls and it may not be economically feasible for Coyote Creek's customers to invest in such equipment, which could result in early retirement of Coyote Station and the Coyote Creek mine.

Under the CAA, new and modified sources of air pollution must meet certain new source standards (the "New Source Review Program"). In the late 1990s, the EPA filed lawsuits against owners of many coal-fired power plants in the eastern U.S. alleging that the owners performed non-routine maintenance, causing increased emissions that should have triggered the application of these new source standards. Some of these lawsuits have been settled with the owners agreeing to install additional emission control devices in their coal-fired power plants. The EPA has clarified the process for evaluating whether the New Source Review ("NSR") permitting program would apply to proposed projects at existing air pollution sources. Under the NSR program, before constructing a new stationary emission source or a modification of an existing major source, the source owner

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or operator must determine whether the new source will emit or the modification will increase air emissions above certain thresholds. The rule makes it clear that both emissions increases and decreases from a major modification at an existing source are to be considered during Step 1 of the two-step NSR applicability test which is designed to determine if there is a "significant emission increase". In October 2021, the EPA denied a petition for reconsideration and administrative stay of the final rule; however, the remaining litigation and the uncertainty around the NSR program rules could adversely impact demand for coal. Any additional new controls may have an adverse impact on the demand for coal, which may have a material adverse effect on the Company's business, financial condition or results of operations.

Under the CAA, the EPA also adopts national emission standards for hazardous air pollutants. In December 2011, the EPA adopted a final rule called the Mercury and Air Toxics Standard ("MATS"), which applies to new and existing coal-fired and oil-fired units. This rule requires mercury emission reductions in fine particulates, which are being regulated as a surrogate for certain metals.

The Company's power generation customers must incur substantial costs to control emissions to meet all of the CAA requirements, including the requirements under MATS and the EPA's regional haze program. These costs raise the price of coal-generated electricity, making coal-fired power less competitive with other sources of electricity, thereby reducing demand for coal. If the Company's customers cannot offset the cost to control certain regulated pollutant emissions by lowering costs or if the Company's customers elect to close coal-fired units, the Company's business, financial condition and results of operations could be materially adversely affected.

Global climate change continues to attract considerable attention in the United States. The U.S. Congress has considered climate change legislation aimed at reducing greenhouse gas ("GHG") emissions, particularly from coal combustion by power plants. Enactment of laws and passage of regulations regarding GHG emissions by the U.S. or additional states, or other actions to limit carbon dioxide emissions, such as opposition by environmental groups to expansion or modification of coal-fired power plants, could result in electric generators switching from coal to other fuel sources.

The U.S. Congress continues to consider a variety of proposals to reduce GHG emissions from the combustion of coal and other fuels. These proposals include emission taxes, emission reductions, including carbon tax and "cap-and-trade" programs, and mandates or incentives to generate electricity by using renewable resources, such as wind or solar power. Some states have established programs to reduce GHG emissions. Further, governmental agencies have been providing grants or other financial incentives to entities developing or selling alternative energy sources with lower levels of GHG emissions, which may lead to more competition from those entities.

The EPA introduced a GHG regulation program under the CAA by issuing a finding that the emission of six GHGs, including carbon dioxide and methane, may reasonably be anticipated to endanger public health and welfare. Based on that finding, the EPA published a New Source Performance Standard for greenhouse gases, applicable to certain new power plants. In 2019, the EPA issued the Affordable Clean Energy ("ACE") Rule to reduce GHG emissions from existing electric generating units ("EGUs"). In contrast to the Clean Power Plan, which preceded the ACE rule, the ACE rule limited "best system of emission reduction" to only "inside the fenceline" heat rate improvement technologies or systems that can be applied at an affected coal-fired EGU. The ACE rule was challenged by a suite of petitioners before the U.S. Circuit Court of Appeals, District of Columbia Circuit ("DC Circuit") which subsequently ruled that the EPA erred when it rescinded the Clean Power Plan and vacated the ACE rule. In early 2021, the EPA issued an endangerment/significant contribution finding for carbon dioxide emissions from coal-fired power plants. In addition, the DC Circuit court ruling was challenged by several parties, including the Company, and the Supreme Court of the United States granted certiorari. In June 2022, the U.S. Supreme Court reversed the D.C. Circuit's decision on the ACE rule and remanded the case back to the D.C. Circuit. The EPA has indicated that it will draft a new rule to regulate carbon dioxide emissions which, depending on the scope and applicability of the rule, may have a material adverse effect on the Company's business, financial condition or results of operations.

The Taxpayer Certainty and Disaster Tax Relief Act of 2020 extended the production tax credit ("PTC") under Section 45 of the Internal Revenue Code and the investment tax credit ("ITC") under Section 48 of the Code. The PTC for wind was extended at the current phase-out level (60% of the otherwise allowable credits) for facilities where construction began in 2021. The ITC for solar was extended at 26% for energy property where construction begins in 2021-2022 and at 22% where construction begins in 2023-2025. Solar energy property placed in service after December 31, 2025 will receive a 10% ITC.

On August 16, 2022, President Biden signed into law the Inflation Reduction Act of 2022 (the "Inflation Reduction Act"). The Inflation Reduction Act contains hundreds of billions of dollars in incentives for the development of renewable energy, clean hydrogen, clean fuels, electric vehicles and supporting infrastructure and carbon capture and sequestration, among other provisions. These incentives could further accelerate the transition of the U.S. economy away from the use of fossil fuels and impact demand for fossil fuels. The ultimate impact on fossil fuel demand and the Company is uncertain and may change as

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implementation of the Inflation Reduction Act moves forward. The subsidization of alternative energy sources may have a material adverse effect on the Company's business, financial condition or results of operations.

The U.S. has not implemented the 1992 Framework Convention on Global Climate Change ("Kyoto Protocol"), which became effective for many countries on February 16, 2005. The Kyoto Protocol was intended to limit or reduce emissions of GHGs. The U.S. has not ratified the emission targets of the Kyoto Protocol or any other GHG agreement. Though the U.S. has not accepted these international GHG limiting treaties, numerous lawsuits and regulatory actions have been undertaken by states and environmental groups to try to force controls on the emission of carbon dioxide; or to prevent the construction of new coal-fired power plants.

As a successor to the Kyoto Protocol, in 2015, international negotiators finalized the Paris Agreement under the United Nations Framework Convention on Climate Change ("Paris Agreement"). Unlike the Kyoto Protocol, the Paris Agreement has no binding GHG reduction mandates on signatories. Participating countries only submit a description of their intended GHG reductions, and provide periodic progress updates, with no penalties for not meeting their self-imposed targets. The Paris Agreement also includes language stating that developed countries will provide financial assistance to help developing countries meet their GHG targets and adapt to climate change, but there are no mandated contributions. In November 2020, the United States formally withdrew from the Paris Agreement; however, the United States rejoined in February 2021. The renegotiation and implementation of the Paris Agreement, or other international agreements, the regulations promulgated to date by the EPA with respect to GHG emissions or the adoption of new legislation or regulations to control GHG emissions, could have a material adverse effect on the Company's business, financial condition and results of operations.

Significant public opposition has also been raised with respect to the proposed construction of certain new coal-fired EGUs due to the potential for increased air emissions. Such opposition, as well as any corporate or investor policies against coal-fired EGUs or requiring disclosures related to global climate change, could also reduce the demand for the Company's coal or marketability of NACCO stock. Further, policies limiting available financing for the development of new coal-fueled EGUs or coal mines or the retrofitting of existing EGUs could adversely impact the global demand for coal in the future. The potential impact on the Company of future laws, regulations or other policies or circumstances will depend upon the degree to which any such laws, regulations or other policies or circumstances force electricity generators to diminish their reliance on coal as a fuel source. In view of the significant uncertainty surrounding each of these factors, it is not possible for the Company to predict reasonably the impact that any such laws, regulations or other policies may have on the Company's business, financial condition and results of operations. However, such impacts could have a material adverse effect on the Company's business, financial condition and results of operations.

The Company believes it has obtained all necessary permits under the CAA at all of its coal mining operations where it is responsible for permitting and is in compliance with such permits.

<u>Clean Water Act</u>

The Clean Water Act ("CWA") affects coal mining operations by establishing in-stream water quality standards and treatment standards for waste water discharge. Permits requiring regular monitoring, reporting and performance standards govern the discharge of pollutants into water. Waters discharged from coal mines are required to meet these standards. These federal and state requirements could require more costly water treatment and could materially adversely affect the Company's business, financial condition and results of operations.

The Company believes it has obtained all permits required under the CWA and corresponding state laws and is in compliance with such permits. In many instances, mining operations require securing CWA authorization or a permit from the U.S. Army Corps of Engineers for operations in waters of the United States. The U.S. Army Corps of Engineers and EPA jointly revised the definition of a water of the United States ("WOTUS") in the June 2020 Navigable Water Protection Rule ("NWPR"). The new definition was challenged in court and two court cases resulted in vacatur of the NWPR. The Supreme Court of the United States heard the Sackett vs. EPA case in October 2022 that challenges how federal jurisdiction of wetlands should be determined. A decision is expected by June 2023. In the meantime, in January 2023, the EPA published a new rule that redefines WOTUS that relies on the significant nexus test established by the 2006 Rapanos decision. The new definition expands the scope of the federal jurisdiction over land and water features which could cause some of the Company's operations to incur additional costs to mitigate streams and wetlands.

Bellaire is treating mine water drainage from coal refuse piles associated with former underground coal mines in Ohio and Pennsylvania and is treating mine water from a former underground coal mine in Pennsylvania. Bellaire anticipates that it will need to continue these activities indefinitely. Bellaire was notified by the Pennsylvania Department of Environmental Protection during 2004 that in order to obtain renewal of a permit, Bellaire would be required to establish a mine water

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treatment trust. See Note 7 and Note 9 to the Consolidated Financial Statements in this Form 10-K for further information on Bellaire.

<u>Resource Conservation and Recovery Act</u>

The Resource Conservation and Recovery Act ("RCRA") affects coal mining operations by establishing requirements for the treatment, storage and disposal of wastes, including hazardous wastes. Coal mine wastes, such as overburden and coal cleaning wastes, currently are exempted from hazardous waste management. In 2014, the EPA finalized a rule specifying management standards for coal combustion residuals or coal ash ("CCRs") as a non-hazardous waste. In 2018, the EPA finalized revisions to the 2014 regulations in response to litigation of the 2014 rule. One revision allows a state director (in a state with an approved CCR permit program) or the EPA (where EPA is the permitting authority) to suspend groundwater monitoring requirements if there is evidence that there is no potential for migration of hazardous constituents to the uppermost aquifer during the active life of the unit and post closure care. The second revision allows issuance of technical certifications in lieu of a professional engineer. In addition, the EPA revised the groundwater protection standards and extended the deadline for some facilities that must close CCR units. In 2020, the EPA finalized additional changes to the CCR rule that classified all clay-lined surface impoundments that receive CCR as unlined, which triggered a pond closure date of April 2021 for impoundments that failed the aquifer location restriction. The EPA also established alternative deadlines to cease receipt of waste to include new site-specific alternatives due to lack of capacity with a deadline to initiate closure no later than October 15, 2023 and a new site-specific alternative due to permanent cessation of coal-fired boilers with two deadlines to complete closure: (a) no later than October 17, 2023 for surface impoundments 40 acres or smaller; and (b) October 17, 2028 for surface impoundments larger than 40 acres. Additionally, the CCR Part B Final Rule allowed facilities to demonstrate that there is no reasonable probability of adverse effects to human health and the environment at non-conforming units. These new rules may raise the cost for CCR disposal at coal-fired power plants, making them less competitive, and/or result in early closure which could have an adverse impact on demand for coal and ultimately result in the early closure of the mines servicing these plants, including closure of the Company's mines. Any such closure of the Company's mines could have a material adverse effect on the Company's business, financial condition and results of operations.

The EPA rule exempts CCRs beneficially used at mine sites and reserves any regulation thereof to the OSMRE. The OSMRE suspended all rulemaking actions on CCRs, but could re-initiate them in the future. The outcome of these rulemakings, and any subsequent actions by the EPA and OSMRE, could impact those Company operations that beneficially use CCRs. If the Company were unable to beneficially use CCRs, its revenues for handling CCRs from its customers may decrease and its costs may increase due to the purchase of alternative materials for beneficial uses.

<u>National Environmental Policy Act</u>

NEPA requires federal agencies to review the environmental impacts of their decisions and issue either an environmental assessment or an environmental impact statement. There are certain actions associated with surface coal mining that may trigger these types of assessments by federal agencies. When a NEPA action is required, the Company provides the required information to the appropriate federal agency so that they may complete the environmental assessment. Historically, this process has been lengthy and may take several years to complete. In 2020, the White House Council on Environmental Quality ("CEQ") issued a final rule updating the original NEPA regulations; however, it was immediately challenged by states and non-governmental organizations. In April 2022, the CEQ issued a new draft rule rescinding many of the revisions from the 2020 update. In January 2023, the CEQ issued interim guidance that instructs federal agencies to quantify GHG emissions for each alternative and use the social cost of greenhouse gasses to calculate a monetary metric that gives decision makers and the public useful information and context about a proposed actions' climate effects. The revised NEPA regulations and interim guidance could adversely affect the Company's ability to secure necessary permits.

<u>Regulation of the Oil and Natural Gas Industry</u> 

The oil and natural gas industry is extensively regulated by numerous federal, state and local authorities. Legislation affecting the oil and natural gas industry is under constant review for amendment or expansion, frequently increasing the regulatory burden. Also, numerous departments and agencies, both federal and state, are authorized by statute to issue rules and regulations that are binding on the oil and natural gas industry and its individual members, some of which carry substantial penalties for failure to comply. Although the regulatory burden on the oil and natural gas industry increases the cost of doing business, these burdens generally do not affect the Company any differently or to any greater or lesser extent than they affect other companies in the industry with similar types, quantities and locations of production.

The availability, terms and cost of transportation significantly affect sales of oil and natural gas. The interstate transportation of oil and natural gas and the sale or resale of natural gas is subject to federal regulation, including regulation of the terms, conditions and rates for interstate transportation, storage and various other matters, primarily by the Federal Energy Regulatory Commission ("FERC"). Federal and state regulations govern the price and terms for access to oil and natural gas pipeline

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transportation. FERC's regulations for interstate oil and natural gas transmission in some circumstances may also affect the intrastate transportation of oil and natural gas.

Although oil and natural gas prices are currently unregulated, Congress historically has been active in the area of oil and natural gas regulation. The Company cannot predict whether new legislation to regulate oil and natural gas might be proposed, what proposals, if any, might be enacted by Congress or the various state legislatures, and what effect, if any, the proposals might have on the Minerals Management segment. Sales of crude oil, condensate and natural gas liquids ("NGLs") are not currently regulated and are made at market prices.

*Environmental Matters*

Oil and natural gas exploration, development and production operations are subject to stringent laws and regulations governing the discharge of materials into the environment or otherwise relating to protection of the environment or occupational health and safety. These laws and regulations have the potential to impact production on the Company's mineral interests, which could materially adversely affect the Minerals Management segment. Numerous federal, state and local governmental agencies, such as the EPA, issue regulations that often require difficult and costly compliance measures that carry substantial administrative, civil and criminal penalties and may result in injunctive obligations for non-compliance. These laws and regulations may require the acquisition of a permit before drilling commences, restrict the types, quantities and concentrations of various substances that can be released into the environment in connection with drilling and production activities, limit or prohibit construction or drilling activities on certain lands lying within wilderness, wetlands, ecologically sensitive and other protected areas, require action to prevent or remediate pollution from current or former operations, such as plugging abandoned wells or closing earthen pits, result in the suspension or revocation of necessary permits, licenses and authorizations, require that additional pollution controls be installed and impose substantial liabilities for pollution resulting from operations. The strict, joint and several liability nature of such laws and regulations could impose liability upon the operators on the Company's mineral interests, regardless of fault. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of hazardous substances, hydrocarbons or other waste products into the environment. Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent and costly pollution control or waste handling, storage, transport, disposal or cleanup requirements could materially adversely affect the Minerals Management segment.

*Drilling and Production*

The operations of the Company's third-party lessees are subject to various types of regulation at the federal, state and local level. These types of regulation include requiring permits for the drilling of wells, drilling bonds and generating reports concerning operations. The states, and some counties and municipalities, in which the Company has mineral interests also regulate one or more of the following:

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• the location of wells;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• the method of drilling and casing wells;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• the timing of construction or drilling activities, including seasonal wildlife closures;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• the rates of production or "allowables";

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• the surface use and restoration of properties upon which wells are drilled;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• the plugging and abandoning of wells; and

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• notice to, and consultation with, surface owners and other third parties.

State laws regulate the size and shape of drilling and spacing units or proration units governing the pooling of oil and natural gas properties. Some states allow forced pooling or integration of tracts to facilitate exploration while other states rely on voluntary pooling of lands and leases. In some instances, forced pooling or unitization may be implemented by third parties and may reduce the Company's interest in the unitized properties. In addition, state conservation laws establish maximum rates of production from oil and natural gas wells, generally prohibit the venting or flaring of natural gas and impose requirements regarding the ratability of production. These laws and regulations may limit the amount of oil and natural gas that the lessees of the Company's mineral interests can produce from existing wells or limit the number of wells or the locations at which operators can drill. Moreover, each state generally imposes a production or severance tax with respect to the production and sale of oil, natural gas and NGLs within its jurisdiction. States do not regulate wellhead prices or engage in other similar direct regulation, but the effect of any future regulations could have a material effect on the Minerals Management segment. The effect of such future regulations may be to limit the amounts of oil and natural gas that may be produced from the Company's mineral interests, negatively affect the economics of production from these wells or limit the number of locations operators can drill.

Federal, state and local regulations provide detailed requirements for the abandonment of wells, closure or decommissioning of production facilities and pipelines and for site restoration in areas where the operators of the acreage underlying the Company's mineral and royalty interests operate. The U.S. Army Corps of Engineers and many other state and local authorities also have

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regulations for plugging and abandonment, decommissioning and site restoration. Although the U.S. Army Corps of Engineers does not require bonds or other financial assurances, some state agencies and municipalities do have such requirements.

*Regulation of Hydraulic Fracturing*

Hydraulic fracturing is an important common practice that is used to stimulate production of hydrocarbons, particularly natural gas, from tight formations, including shales. The process involves the injection of water, sand and chemicals under pressure into formations to fracture the surrounding rock and stimulate production. The CWA regulates the underground injection of substances through the Underground Injection Control ("UIC") program. Hydraulic fracturing generally is exempt from regulation under the UIC program, and the hydraulic fracturing process is typically regulated by state oil and gas commissions. However, in recent years efforts have been made to regulate hydraulic fracturing at the federal level. The Biden administration has also signaled the intent to stop hydraulic fracturing on federal land.

Several states, including Texas, have adopted, or are considering adopting, regulations that could restrict or prohibit hydraulic fracturing in certain circumstances and/or require the disclosure of the composition of hydraulic fracturing fluids. The Texas Legislature previously adopted legislation requiring oil and gas operators to publicly disclose the chemicals used in the hydraulic fracturing process, effective as of September 1, 2011. The Texas Railroad Commission subsequently adopted rules and regulations implementing this legislation that apply to all wells for which the Railroad Commission issues an initial drilling permit. This law requires that the well operator disclose the list of chemical ingredients subject to the requirements of the Occupational Safety and Health Act for disclosure on an internet website and also file the list of chemicals with the Texas Railroad Commission with the well completion report. The total volume of water used to hydraulically fracture a well must also be disclosed to the public and filed with the Texas Railroad Commission. Further, in May 2013, the Texas Railroad Commission issued a "well integrity rule," which updates the requirements for drilling, putting pipe down, and cementing wells. The rule also includes new testing and reporting requirements, such as: (i) the requirement to submit cementing reports after well completion or after cessation of drilling, whichever is later; and (ii) the imposition of additional testing on wells less than 1,000 feet below usable groundwater. The well integrity rule took effect in January 2014. Local governments also may seek to adopt ordinances within their jurisdictions regulating the time, place and manner of drilling activities in general or hydraulic fracturing activities in particular or prohibit the performance of well drilling in general or hydraulic fracturing in particular.

There has been increasing public controversy regarding hydraulic fracturing with regard to the use of fracturing fluids, impacts on drinking water supplies, use of water and the potential for impacts to surface water, groundwater and the environment generally. A number of lawsuits and enforcement actions have been initiated across the country implicating hydraulic fracturing practices. If new laws or regulations that significantly restrict hydraulic fracturing are adopted, such laws could make it more difficult or costly to perform fracturing to stimulate production from tight formations as well as make it easier for third parties opposing the hydraulic fracturing process to initiate legal proceedings based on allegations that specific chemicals used in the fracturing process could adversely affect groundwater. In addition, if hydraulic fracturing is further regulated at the federal or state level, fracturing activities could become subject to additional permitting and financial assurance requirements, more stringent construction specifications, increased monitoring, reporting and recordkeeping obligations, plugging and abandonment requirements and also to attendant permitting delays and potential increases in costs. Such legislative or regulatory changes could cause operators of the operation on the acreage underlying the Company's mineral interests to incur substantial compliance costs, and compliance or the consequences of any failure to comply by operators could have a material adverse effect on the Minerals Management segment.

In addition, hydraulic fracturing operations require the use of a significant amount of water, and the inability of the operators of the acreage underlying the Company's mineral interests to locate sufficient amounts of water or dispose of or recycle water used in their drilling and production operations could adversely impact their operations. Moreover, new environmental initiatives and regulations could include restrictions on the ability to conduct certain operations such as hydraulic fracturing or disposal of waste, including, but not limited to, produced water, drilling fluids and other wastes associated with the development or production of natural gas.

In some instances, the operation of underground injection wells has been alleged to cause earthquakes. Such issues have sometimes led to orders prohibiting continued injection or the suspension of drilling in certain wells identified as possible sources of seismic activity. Such concerns also have resulted in stricter regulatory requirements in some jurisdictions relating to the location and operation of underground injection wells. Future orders or regulations addressing concerns about seismic activity from well injection could affect operations on the acreage underlying the Company's mineral interests.

*Endangered Species Act*

The Endangered Species Act ("ESA") and analogous state laws restrict activities that may affect endangered or threatened species or their habitats. Pursuant to a settlement with environmental groups, the U.S. Fish and Wildlife Service ("USFWS")

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was required to determine whether over 250 species required listing as threatened or endangered under the ESA. USFWS has not yet completed its review, but the potential remains for new species to be listed under the ESA. Some of the Company's properties or mineral interests may be located in areas that are or may be designated as habitats for endangered or threatened species, and previously unprotected species may later be designated as threatened or endangered in areas where the Company holds interests. For example, recently, there have been renewed calls to review protections currently in place for the Dunes Sagebrush Lizard, whose habitat includes portions of the Permian Basin, and to reconsider listing the species under the ESA. Likewise, there have been calls to review protections in place for the Greater Sage Grouse, which can be found across a large swath of the northwestern United States in oil and gas producing states. The listing of either of these species, or any others, in areas where the Company holds mineral interests could cause lessees to incur increased costs arising from species protection measures, delay the completion of exploration and production activities, and/or result in limitations on operating activities that could have an adverse impact the Minerals Management segment.

*Natural Gas Sales and Transportation*

Historically, federal legislation and regulatory controls have affected the price and marketing of natural gas. FERC has jurisdiction over the transportation and sale for resale of natural gas in interstate commerce by natural gas companies under the Natural Gas Act of 1938 ("NGA") and the Natural Gas Policy Act of 1978. Since 1978, various federal laws have been enacted which have resulted in the complete removal of all price and non-price controls for sales of domestic natural gas sold in "first sales." Under the Energy Policy Act of 2005, FERC has substantial enforcement authority to prohibit the manipulation of natural gas markets and enforce its rules and orders, including the ability to assess substantial civil penalties.

FERC also regulates interstate natural gas transportation rates and service conditions and establishes the terms under which operators may use interstate natural gas pipeline capacity, which affects the marketing of natural gas that operators produce, as well as the revenues operators receive for sales of natural gas and release of natural gas pipeline capacity. Commencing in 1985, FERC promulgated a series of orders, regulations and rule makings that significantly fostered competition in the business of transporting and marketing gas. Today, interstate pipeline companies are required to provide nondiscriminatory transportation services to producers, marketers and other shippers, regardless of whether such shippers are affiliated with an interstate pipeline company. FERC's initiatives have led to the development of a competitive, open access market for natural gas purchases and sales that permits all purchasers of natural gas to buy gas directly from third-party sellers other than pipelines. However, the natural gas industry historically has been very heavily regulated; therefore, the Company cannot guarantee that the less stringent regulatory approach currently pursued by FERC and Congress will continue indefinitely into the future nor can the Company determine what effect, if any, future regulatory changes might have on natural gas-related activities.

Under FERC's current regulatory regime, transmission services must be provided on an open-access, nondiscriminatory basis at cost-based rates or at market-based rates if the transportation market at issue is sufficiently competitive. Gathering service, which occurs upstream of jurisdictional transmission services, is regulated by the states onshore and in-state waters. Section 1(b) of the NGA exempts natural gas gathering facilities from regulation by FERC as a natural gas company under the NGA. Although its policy is still in flux, FERC has in the past reclassified certain jurisdictional transmission facilities as non-jurisdictional gathering facilities, which has the tendency to increase operators' costs of transporting gas to point-of-sale locations.

*Oil Sales and Transportation*

Sales of crude oil, condensate and natural gas liquids are not currently regulated and are made at negotiated prices. Nevertheless, Congress could reenact price controls in the future.

Crude oil sales are affected by the availability, terms and cost of transportation. The transportation of oil in common carrier pipelines is also subject to rate regulation. FERC regulates interstate oil pipeline transportation rates under the Interstate Commerce Act and intrastate oil pipeline transportation rates are subject to regulation by state regulatory commissions. The basis for intrastate oil pipeline regulation, and the degree of regulatory oversight and scrutiny given to intrastate oil pipeline rates, varies from state to state. Insofar as effective interstate and intrastate rates are equally applicable to all comparable shippers, the Company believes that the regulation of oil transportation rates will not affect its operations in any materially different way than such regulation will affect the operations of competitors.

Further, interstate and intrastate common carrier oil pipelines must provide service on a non-discriminatory basis. Under this open access standard, common carriers must offer service to all shippers requesting service on the same terms and under the same rates. When oil pipelines operate at full capacity, access is governed by portioning provisions set forth in the pipelines' published tariffs. Accordingly, the Company believes that access to oil pipeline transportation services generally will be available to its operators to the same extent as to the Company or its competitors.

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*State Regulation*

Texas regulates the drilling for, and the production, gathering and sale of, oil and natural gas, including imposing severance taxes and requirements for obtaining drilling permits. Texas currently imposes a 4.6% severance tax on the market value of oil production and a 7.5% severance tax on the market value of natural gas production. States also regulate the method of developing new fields, the spacing and operation of wells and the prevention of waste of oil and natural gas resources. States may regulate rates of production and may establish maximum daily production allowable from oil and natural gas wells based on market demand or resource conservation, or both. States do not regulate wellhead prices or engage in other similar direct economic regulation, but the Company cannot be certain that they will not do so in the future. The effect of these regulations may be to limit the amount of oil and natural gas that may be produced from wells drilled by third-party lessee's and to limit the number of wells or locations the Company's third-party lessee operators can drill.

The petroleum industry is also subject to compliance with various other federal, state and local regulations and laws. Some of those laws relate to resource conservation and equal employment opportunity. The Company does not believe that compliance with these laws will have a material adverse effect on its results of operations or financial condition.

<u>Comprehensive Environmental Response, Compensation and Liability Act</u>

CERCLA and similar state laws create liabilities for the investigation and remediation of releases of hazardous substances into the environment and for damages to natural resources. The Company must also comply with reporting requirements under the Emergency Planning and Community Right-to-Know Act and the Toxic Substances Control Act.

From time to time, the Company has been the subject of administrative proceedings, litigation and investigations relating to environmental matters.

The extent of the liability and the cost of complying with environmental laws cannot be predicted with certainty due to many factors, including the lack of specific information available with respect to many sites, the potential for new or changed laws and regulations, the development of new remediation technologies and the uncertainty regarding the timing of work with respect to particular sites. As a result, the Company may incur material liabilities or costs related to environmental matters in the future, and such environmental liabilities or costs could materially and adversely affect the Company's results of operations and financial condition. In addition, there can be no assurance that changes in laws or regulations would not affect the manner in which the Company is required to conduct its operations.

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**INFORMATION ABOUT OUR EXECUTIVE OFFICERS**

The following tables set forth as of March 1, 2023 the name, age, current position and principal occupation and employment during the past five years of the Company's executive officers. There exists no arrangement or understanding between any executive officer and any other person pursuant to which such executive officer was selected.

**EXECUTIVE OFFICERS OF THE COMPANY**

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| | | |
|:---|:---|:---|
| **Name** | **Age** | **Current Position** |
| J.C. Butler, Jr. | 62 | President and Chief Executive Officer of NACCO and President and Chief Executive Officer of NACoal (from prior to 2018) |
| Elizabeth I. Loveman | 53 | Vice President and Controller and Principal Financial Officer (from prior to 2018) |
| John D. Neumann | 47 | Vice President, General Counsel and Secretary of NACCO, Vice President, General Counsel and Secretary of NACoal (from prior to 2018) |
| Thomas A. Maxwell | 45 | Vice President - Financial Planning and Analysis and Treasurer (from prior to 2018) |

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**PRINCIPAL OFFICERS OF THE COMPANY'S SUBSIDIARIES**

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| | | |
|:---|:---|:---|
| **Name** | **Age** | **Current Position** |
| J.C. Butler, Jr. | 62 | President and Chief Executive Officer of NACCO and President and Chief Executive Officer of NACoal (from prior to 2018) |
| Carroll L. Dewing | 66 | Vice President - Operations of NACoal (from prior to 2018) |
| John D. Neumann | 47 | Vice President, General Counsel and Secretary of NACCO, Vice President, General Counsel and Secretary of NACoal (from prior to 2018) |
| J. Patrick Sullivan, Jr. | 64 | Vice President and Chief Financial Officer of NACoal (from prior to 2018) |

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**Item 1A. RISK FACTORS**

The Company operates in a rapidly changing environment that involves a number of risks. The following discussion highlights some of these risks and others are discussed elsewhere in this report. These and other risks could materially and adversely affect the Company's business, financial condition, operating results or cash flows. The following risk factors are not an exhaustive list of the risks associated with the Company's business. New factors may emerge or changes to these risks could occur that could materially affect the Company's business.

**Risks related to the Coal Mining segment**

**Termination of or default under long-term mining contracts could adversely affect the Company's business, financial condition, results of operation and cash flows.**

Substantially all of the Coal Mining segment's profits are derived from long-term mining contracts. Although the Company has long-term contracts, numerous regulatory authorities, along with well-funded political and environmental activist groups, are devoting substantial resources to anti-coal activities to minimize or eliminate the use of coal as a source of electricity generation. Any customer's premature facility closure could have a material adverse effect on the Company's business, financial condition and results of operations.

See "Item 1. Business — Business Developments" on page 2 in this Form 10-K for discussion of Sabine's 2023 closure.

See "Item 1. Business — Government Regulation" on page 8 in this Form 10-K for discussion of regulations that could materially adversely affect the Coal Mining segment, particularly the discussion of the implementation of the EPA's Regional Haze Rule and its potential impact at Coyote Creek.

**The loss of, or significant reduction in, purchases by NACCO's coal customers could adversely affect the Company's business, financial condition, results of operation and cash flows.**

Earnings from the Coal Mining segment's customers may fluctuate from time to time based on numerous factors, including market conditions and the realignment of customers' power generation portfolios that reduce the electric power generated from coal, which may be outside of the Company's control. Future environmental regulation of GHG emissions, CCRs and/or new federal and state mandates for increased use of electricity derived from renewable energy sources could accelerate the use by utilities of fuels other than coal. Such mandates, combined with other incentives to use renewable energy sources, such as tax credits, could accelerate the realignment of customers' power generation portfolios to reduce the electric power generated from coal.

If any of the Coal Mining segment's customers experience declining demand due to market, economic, regulatory or competitive conditions, it could have an adverse effect on the Company's profitability, cash flows and financial position. In addition, if any customers were to significantly reduce or eliminate their purchases of coal from us or if the Company is unable to renew expiring long-term sales agreements with existing customers or enter into new supply agreements, the Company's business, financial condition, results of operations and cash flows could be adversely affected. See "Item 1. Business — Business Developments" on page 2 in this Form 10-K for further discussion.

**MLMC is subject to risks associated with its capital investment, operating and equipment costs, growing use of alternative generation that competes with coal-fired generation, changes in customer demand and inflationary adjustments.**

The profitability of MLMC is subject to the risk of loss of investment in this operation, increases in the cost of mining, changes in customer demand, growing competition from alternative power generation that competes with coal-fired generation and the emergence of adverse mining conditions. At MLMC, the costs of mining operations are not reimbursed by MLMC's customer. As such, increased costs at MLMC or decreased revenues could materially reduce the Company's profitability. Any reduction in customer demand at MLMC, including reductions related to reduced mechanical availability of the customer's power plant, would adversely affect the Company's operating results and could result in significant impairments.

Similar to the Company's unconsolidated mines, all production costs at MLMC are capitalized into inventory and recognized in cost of sales as tons are delivered. In periods of limited or no deliveries, MLMC may be required to reduce its inventory carrying value using the lower of cost and net realizable value approach, which could adversely affect MLMC's results of operations.

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MLMC has approximately $125 million of long-lived assets, including property, plant and equipment and a coal supply agreement intangible asset, which are subject to periodic impairment analysis and review. Identifying and assessing whether impairment indicators exist, or if events or changes in circumstances have occurred, including assumptions about future power plant dispatch levels, changes in operating costs and other factors that impact anticipated revenue and customer demand, requires significant judgment. Actual future operating results could differ significantly from these estimates, which may result in an impairment charge in a future period, which could have a substantial impact on the Company's results of operations.

Profitability at MLMC is affected by customer demand for coal and changes in the indices that determine sales price and actual costs incurred. MLMC sells lignite at contractually agreed upon prices which are subject to changes in the level of established indices over time. Diesel fuel is heavily weighted among the indices used to determine the coal sales price. The diesel fuel-related component of the coal sales price is based on average price changes over time whereas the impact on actual costs from changes in diesel fuel prices is more immediate; therefore, fluctuations in diesel fuel prices can result in significant fluctuations in earnings at MLMC.

Changes in customer demand for any reason, including, but not limited to, reduced mechanical availability of the customer's power plant, dispatch of power generated by other energy sources ahead of coal, fluctuations in demand due to unanticipated weather conditions, regulations or comparable policies which may promote planned and unplanned outages at the Red Hills Power Plant, economic conditions, including an economic slowdown and a corresponding decline in the use of electricity, governmental regulations and inflationary adjustments could have a material adverse effect on MLMC's financial condition, results of operations and cash flows.

The contracts with the Unconsolidated Subsidiaries' customers are primarily based on a "management fee" approach, whereby compensation includes reimbursement of all operating costs, plus a fee based on the amount of coal delivered. The fees earned adjust over time in line with various indices which reflect general U.S. inflation rates. During the production stage, the Unconsolidated Subsidiaries' customers pay the Company its agreed upon fee only for the coal delivered to them for consumption or use. As a result, reduced coal usage by customers for any reason, including, but not limited to, fluctuations in demand due to unanticipated weather conditions, scheduled and unscheduled outages at the Coal Mining segment's customers' facilities, unplanned equipment failures, economic conditions or governmental regulations or comparable policies which may promote dispatch of power generated by renewables, such as wind or solar, and the realignment of customers' power generation portfolios that reduce the electric power generated from coal could have a material adverse effect on the Company's results of operations. Because of the contractual price formulas for the management fees at these Unconsolidated Subsidiaries, the profitability of these operations is also subject to fluctuations in inflationary adjustments (or lack thereof) that can impact the agreed upon management fees. These factors could materially reduce the Company's profitability.

**Changes in coal consumption patterns of U.S. electric power generators could adversely affect the Company's profitability.**

The amount of coal consumed by the electric power generation industry is affected by general economic conditions; overall demand for electricity; availability of transmission; competition from alternative fuel sources for power generation, such as natural gas, nuclear, hydroelectric, wind and solar power, and the location, availability, quality and price of those alternative fuel sources; environmental and other governmental regulations, including those impacting coal-fired power plants; and energy conservation efforts and related governmental policies.

Changes in the utility industry that affect NACCO's customers could also adversely affect the Company. The increased availability of renewable energy sources has contributed to a reduction in demand for coal-fired electric power generation. Competition from natural gas-fired plants that are relatively more efficient, less expensive to construct and less difficult to permit than coal-fired plants has the most potential to continue to displace a significant amount of coal-fired electric power generation in the near term. Federal and state mandates for increased use of electricity derived from renewable energy sources have also adversely affected demand for coal-fired electric power generation. Such mandates make alternative fuel sources more competitive with coal-fired electric power generation.

Changes in federal and state mandates that would include an acceleration in the use of electricity derived from renewable energy sources could result in a decrease in coal consumption by the electric power generation industry and the Company's customers.

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Certain of the Coal Mining segment's customers, including MLMC's customer, benefit or have benefited from a tax credit under Section 45 of the Internal Revenue Code. The benefit results in a reduction to the cost of coal-fired electric power generation. The elimination or expiration of the Section 45 tax credit would increase the cost of the coal-fired electric power generation from these facilities and could result in the power these facilities produce being less economical than other sources of power generation, which could reduce demand and result in a decrease in coal consumption.

Any of these risks could result in a decrease in coal consumption by the Company's customers and could have a material adverse effect on the Company's business, financial condition and results of operations.

**Government regulations could impose costly requirements on the Company and its customers.**

The coal mining industry and the electric generation industry are subject to extensive regulation by federal, state and local authorities on matters concerning the health and safety of employees, land use, stream and wetland protection, permit and licensing requirements, air and water quality standards, plant and wildlife protection, reclamation and restoration of mining properties after mining, the discharge of GHGs and other materials into the environment, surface subsidence from underground mining and the effects that mining has on groundwater quality and availability. Legislation mandating certain benefits for current and retired coal miners also affects the industry. Mining operations require numerous governmental and regulatory permits and approvals. The Company is required to prepare and present to federal, state or local authorities data pertaining to the impact the production and combustion of coal may have upon the environment. The public, including non-governmental organizations, opposition groups and individuals, have statutory rights to comment upon and submit objections to requested permits and approvals and to legally challenge certain permits subsequent to their issuance. Compliance with these requirements is costly and time-consuming and may delay commencement or continuation of development or production. New legislation and/or regulations and orders may materially adversely affect the Company's mining operations or its cost structure, or its customers. All of these factors could significantly reduce the Company's profitability. See "Item 1. Business — Government Regulation" on page 8 in this Form 10-K for further discussion.

**The Company is subject to burdensome federal and state mining regulations and the assumptions underlying the Company's reclamation and mine closure obligations could be materially inaccurate.**

Federal and state statutes require the Company to restore mine property in accordance with specified standards and an approved reclamation plan, and require that the Company obtain and periodically renew permits for mining operations. Regulations require the Company to incur the cost of reclaiming current mine disturbance at operations where the Company holds the mining permit. Estimates of the Company's total reclamation and mine closing liabilities are based upon permit requirements and the Company's engineering expertise related to these requirements. While management regularly reviews the estimated reclamation liabilities and believes that appropriate accruals have been recorded for all expected reclamation and other costs associated with closed mines, the estimate can change significantly if actual costs vary from assumptions or if governmental regulations change significantly. Such changes could have a material adverse effect on the Company's business and could significantly reduce its profitability.

**The Clean Air Act could reduce the demand for coal.** 

The process of burning coal can cause many compounds and impurities in the coal to be released into the air, including carbon dioxide, sulfur dioxide, nitrogen oxides, mercury, particulates and other matter. The CAA and the corresponding state laws that extensively regulate the emissions of materials into the air affect coal mining operations both directly and indirectly. Direct impacts on coal mining operations occur through CAA permitting requirements and/or emission control requirements relating to air contaminants, especially particulate matter. Indirect impacts on coal mining operations occur through regulation of the air emissions of carbon dioxide, sulfur dioxide, nitrogen oxides, mercury, particulate matter and other compounds emitted by coal-fired power plants. The EPA has discussed issuing or issued regulations that impose tighter emission restrictions on a number of these compounds, some of which are currently subject to litigation. The general effect of tighter restrictions is to reduce demand for coal. A reduction in coal's share of the capacity for power generation could have a material adverse effect on the Company's business, financial condition and results of operations. See "Item 1. Business — Government Regulation" on page 8 in this Form 10-K for further discussion.

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**The Coal Mining segment's customers' operations require significant capital expenditures.**

Maintaining and installing environmental controls on power plants requires significant capital expenditures. Any delay or reduction in making capital expenditures to maintain or upgrade coal-fired power plants by the Coal Segment's customers, principally electric utilities, could result in an increase in outage days and a corresponding decrease in coal consumption. A decrease in coal consumption could have a material adverse effect on the Coal Mining segment's financial condition, results of operations and cash flows.

**Mining operations are vulnerable to weather and other conditions that are beyond the Company's control.**

Many conditions beyond the Company's control can decrease the delivery, and therefore the use, of coal to the Company's customers. These conditions include weather, pandemics, adverse mining conditions, unexpected maintenance problems and shortages of replacement parts, any of which could significantly reduce the Company's profitability.

**The Company faces numerous uncertainties in estimating economically recoverable reserves and resources, and inaccuracies in estimates could result in lower than expected revenues, higher than expected costs and decreased profitability.**

Information concerning the Company's mining operations in "Item 2 - Properties" on page 28 has been prepared in accordance with the requirements of subpart 1300 of Regulation S-K. A mineral is economically recoverable when the price at which it can be sold exceeds the costs and expenses of mining, processing and selling the mineral. Forecasts of NACCO's future performance are based on, among other things, estimates of mineral reserves and resources. Mineral reserve and resource estimates of the remaining tons of coal at MLMC are based on many factors, including engineering, economic and geological data assembled and analyzed by internal staff, which includes various engineers and geologists, the area and volume covered by mining rights, assumptions regarding extraction rates and duration of mining operations, and the quality of in-place reserves and resources. The reserve and resource estimates as to both quantity and quality are updated from time to time to reflect, among other matters, production of minerals, new mining or other data received.

There are numerous uncertainties inherent in estimating quantities and qualities of minerals and costs to mine recoverable reserves and resources, including many factors beyond the Company's control. While the Company believes that its mineral reserve and resource estimates are developed using well-established practices and with appropriate controls, mineral reserve and mineral resource estimation is an imprecise and subjective process. Estimates of mineral reserves and resources depend upon a number of variable factors and assumptions, any one of which may, if incorrect, result in an estimate that varies considerably from actual results. These factors and assumptions include:

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• Geologic and mining conditions, including the Company's ability to access certain mineral deposits as a result of the nature of the geologic formations of coal deposits or other factors, which may not be fully identified by available exploration data and may differ from past experience;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• Demand for the Company's minerals;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• Contractual arrangements, operating costs and capital expenditures;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• Development and reclamation costs;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• Mining technology and processing improvements;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• The effects of regulation by governmental agencies;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• The ability to obtain, maintain and renew all required permits;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• Employee health and safety; and

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• NACCO's ability to convert all or any part of mineral resources to economically extractable mineral reserves.

As a result, actual tonnage recovered, estimated revenues, expenditures and cash flows with respect to reserves and resources may vary materially from estimates. Thus, these estimates may not accurately reflect the Company's actual reserves and resources. Any material inaccuracy in estimates related to the Company's reserves or resources could result in lower than expected revenues, higher than expected costs or decreased profitability and changes in future cash flow, which could materially and adversely affect the Company business, results of operations, financial position and cash flows. Additionally, reserve and resource estimates may be adversely affected in the future by interpretations of, or changes to, the SEC's property disclosure requirements for mining companies.

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**A defect in title or the loss of a leasehold interest in certain property could limit the Company's ability to mine coal reserves or result in significant unanticipated costs.**

The Company conducts a significant part of its coal mining operations on leased properties. A title defect or the loss of a lease could adversely affect the ability to mine the associated coal reserves. The Company may not verify title to leased properties or associated coal reserves until the Company has committed to developing those properties or coal reserves. The Company may not commit to develop property or coal reserves until the Company has obtained necessary permits and completed exploration. As such, the title to property that the Company intends to lease or mine may contain defects prohibiting the ability to conduct mining operations. Similarly, leasehold interests may be subject to superior property rights of third parties. In order to conduct mining operations on properties where these defects exist, the Company may incur unanticipated costs. In addition, some leases require the Company to produce a minimum quantity of coal and/or pay minimum production royalties. The Company's inability to satisfy those requirements may cause the leasehold interest to terminate.

**Risks related to the NAMining segment**

**The Company has experienced growth in its NAMining business in recent periods and it may not be able to sustain growth or manage future growth effectively.**

The Company has expanded its overall NAMining business, operations and headcount in recent periods. NAMining's operating expenses may continue to increase as the Company scales the NAMining business, including growth outside of Florida. As NACCO continues to grow the NAMining business, the Company must effectively integrate, develop and motivate new employees, as well as existing employees who are promoted or moved into new roles, while maintaining the effectiveness of its business execution. In part, NAMining's success depends on its ability to integrate new customers in an efficient and effective manner. The Company anticipates that it will continue to incur costs and capital expenditures associated with future growth prior to realizing the full measure of anticipated long-term benefits, and the return on these investments may be lower, may develop more slowly than expected or may never be realized. If the Company is unable to manage this growth and the associated expenses effectively, the Company may not be able to take advantage of market opportunities or remain competitive. The Company may also fail to execute on its business plan or respond to competitive pressures, any of which could adversely affect the NAMining business, operating results and financial condition.

**NAMining faces competition from aggregates producers that choose to self-perform mining operations and from other mining companies.**

NAMining faces competition from existing and prospective customers that are capable of performing, or engaging other companies to perform the services NAMining provides. NAMining cannot be certain that its existing customers will continue to outsource these services to NAMining in the future, which could adversely affect the NAMining business, operating results and financial condition.

**The Company is subject to risks involved in the development of new mining projects.**

From time to time, the Company seeks to develop new mining projects, including the Thacker Pass project. The risks associated with such projects can be substantial. New mining projects can take up to several years to complete, are complex and require significant capital expenditures. These projects are subject to significant risks, including delays, extreme weather events, unexpected increases in the cost of required materials, and disputes with third party providers of materials, equipment or services, and a completed project may not yield the anticipated operational or financial benefit, any of which could have a material adverse effect on the Company's business, financial condition and results of operations.

**NAMining operations are currently geographically concentrated and therefore subject to regional economic risk, regulatory conditions, natural disasters, severe weather events or other circumstances affecting Florida.**

As of December 31, 2022, over 75% of the quarries NAMining operates are located in Florida. A prolonged economic downturn or adverse change in regulatory conditions in the Florida mining or construction industry could result in a significant reduction in demand for NAMining's services. The occurrence of one or more natural disasters, severe weather events, terrorist attacks, or disruptive political events in Florida could adversely affect the NAMining business.

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**Risks related to the Minerals Management segment**

**The Company has no control over the timing of the development and operation of its natural gas, oil and coal reserves extracted by third parties.**

The Company owns mineral and royalty interests in the continental United States. The Company does not develop oil and gas reserves and is not a natural gas and oil producer. The Company derives income from royalty-based leases under which lessees make payments to the Company based on their sale of natural gas, oil and coal. Future royalty-based income is dependent on the number of oil and gas wells being developed and operated on the Company's mineral acreage. The decision to pursue development and operation of oil and gas wells is made by third-party operators, not by the Company, and depends on a number of factors outside of the Company's control, including fluctuations in commodity prices (primarily natural gas), regulatory risk, the Company's lessees' willingness and ability to incur well-development and other operating costs, the rate of production of the reserves and changes in the availability and continuing development of infrastructure. Lower commodity prices may reduce the amount of oil and natural gas that third-party operators can produce economically. In the event that new federal or state restrictions related to the hydraulic fracturing process are adopted in areas where the Company owns mineral and royalty interests, the Company's lessees may incur additional costs or permitting requirements to comply with such requirements that may be significant and could result in added restrictions, delays or curtailments in the pursuit of exploration, development, or production activities. In addition, if a lessee were to experience financial difficulty, the lessee might not be able to pay its royalty payments or continue operations. A failure on the part of the lessee to make royalty payments gives the Company the right to terminate the lease, repossess the property and enforce payment obligations under the lease. If the Company repossessed any of its properties, it would seek a replacement lessee. However, the Company may not be able to find a replacement lessee and, if it did, the Company might not be able to enter into a new lease on favorable terms within a reasonable period of time. In addition, if the Company is able to enter into a new lease with a new lessee, the replacement lessee may not achieve the same levels of production or sales prices as the lessee it replaced. Any of these risks could materially reduce the Company's expected royalty income and the Company's profitability.

**Minerals are a depleting asset. Unless the Company replaces existing mineral and royalty interests with new mineral and royalty interests and third-party lessees develop those mineral and royalty interests, the Company's reserves and royalty income will decline.**

Producing oil and natural gas reservoirs are generally characterized by declining production rates that vary depending upon reservoir characteristics and other factors. Unless the Company's third-party lessees conduct successful ongoing well development activities or the Company continually acquires mineral and royalty interests, production and income related to the Company's mineral and royalty interests will decline as those reserves are depleted. The future cash flow and results of operations of the Minerals Management segment are highly dependent on third-party operators' success in developing the Company's current and future mineral and royalty interests. These operators may not have access to the capital needed to develop the Company's mineral interests. The Company may not be able to acquire or find sufficient additional mineral and royalty interests to replace third-party operators' current and future production. Further, the decline curve the Company uses to project future royalty income is subject to numerous assumptions and limitations. Natural gas wells have high initial production rates and follow a natural decline before settling into relatively stable, long-term production. Decline rates can vary due to factors like well depth, well length, formation pressure, and facility design. Any of these risks could materially reduce the Company's expected royalty income and the Company's profitability.

**Substantially all of the Minerals Management segment's revenues are derived from royalty payments that are based on the price at which oil and natural gas produced from the acreage underlying the Company's interests are sold. Prices of oil and natural gas are volatile due to factors beyond the Company's control. A substantial or extended decline in commodity prices may adversely affect the Minerals Management segment's financial condition or results of operations.**

The Minerals Management segment's revenues and operating results depend significantly upon the prevailing prices for oil and natural gas. Historically, oil and natural gas prices have been volatile and are subject to fluctuations in response to changes in supply and demand, market uncertainty and a variety of additional factors that are beyond the Company's control; market expectations about future prices of oil and natural gas; the level of global oil and natural gas exploration and production; the cost of exploring for, developing, producing and delivering oil and natural gas; the price and quantity of foreign imports and U.S. exports of oil and natural gas; the level of U.S. domestic production; political and economic conditions in oil producing regions; the ability of members of the Organization of Petroleum Exporting Countries to agree to and maintain oil price and production controls; trading in oil and natural gas derivative contracts; the level of consumer product demand; weather conditions and natural disasters; technological advances affecting energy consumption, energy storage and energy supply; domestic and foreign governmental regulations and taxes; the continued threat of terrorism and the impact of military and other action, including the ongoing conflict between Russia and Ukraine and associated oil and natural gas import bans as well as

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U.S. military operations in the Middle East and economic sanctions such as those imposed by the U.S. on oil and gas exports from Iran; the proximity, cost, availability and capacity of oil and natural gas pipelines and other transportation facilities; the price and availability of alternative fuels; and overall domestic and global economic conditions. A substantial or extended decline in commodity prices may adversely affect the Minerals Management segment's financial condition or results of operations.

**Risks related to corporate structure**

**The amount and frequency of dividend payments made on NACCO's common stock could change.**

The Board of Directors has the power to determine the amount and frequency of the payment of dividends. Decisions regarding whether or not to pay dividends and the amount of any dividends are based on earnings, capital and future expense requirements, financial conditions and other factors the Board of Directors may consider. Accordingly, holders of NACCO's common stock should not rely on past payments of dividends in a particular amount as an indication of the amount of dividends that will be paid in the future.

**The price of NACCO's securities may be volatile.**

The price of the Company's common stock may fluctuate due to a variety of market and industry factors that may materially reduce the market price of NACCO's common stock regardless of operating performance, including, among others: (i) actual or anticipated fluctuations in the Company's quarterly and annual results and those of other public companies in the industry; (ii) industry cycles and trends; (iii) changes in government regulation; (iv) potential or actual military conflicts or acts of terrorism; (v) announcements concerning NACCO, its customers or its competitors; (vi) lack of trading liquidity as a result of low trading volumes could make it difficult for investors to sell shares; and (vii) the general state of the securities market. In addition, the stock market in general has experienced significant volatility that often has been unrelated to the operating performance of companies whose shares are traded. These market fluctuations could adversely affect the trading price of the Company's common stock, regardless of NACCO's actual operating performance. As a result of all of these factors, investors in the Company's common stock may not be able to resell their stock at or above the price they paid or at all. Further, NACCO could be the subject of securities class action litigation due to any such stock price volatility, which could divert management's attention and have a material adverse effect on the Company's operating results.

**NACCO's certificate of incorporation and by-laws include provisions that may discourage a takeover attempt.** 

Provisions contained in the Company's certificate of incorporation and by-laws and Delaware law could make it more difficult for a third-party to acquire the Company, even if doing so might be beneficial to NACCO's stockholders. Provisions of the Company's by-laws and certificate of incorporation impose various procedural and other requirements that could make it more difficult for stockholders to affect certain corporate actions. These provisions could limit the price that certain investors might be willing to pay in the future for shares of NACCO's common stock and may have the effect of delaying or preventing a change in control.

**The Company's stock repurchase program could affect the price of NACCO's common stock and increase volatility and may not enhance long-term shareholder value.**

The Company's Board of Directors has authorized a stock repurchase program. The timing and amount of any repurchases under the stock repurchase program are determined at the discretion of the Company's management based on a number of factors, including the availability of capital, other capital allocation alternatives, market conditions for the Company's Class A common stock and other legal and contractual restrictions. The stock repurchase program does not require the Company to acquire any specific number of shares and may be modified, suspended, extended or terminated without prior notice and may be executed through open market purchases, privately negotiated transactions or otherwise.

Repurchases under the stock repurchase program could affect the price of the Company's Class A common stock. The existence of a stock repurchase program could cause the price of the Company's Class A common stock to be higher than it would be in the absence of such a program and could potentially reduce the market liquidity for the Company's Class A common stock. There can be no assurance that any stock repurchases will enhance shareholder value because the market price of the Company's Class A common stock may decline below the levels at which the Company repurchased the shares. Although the stock repurchase program is intended to enhance long-term shareholder value, there is no assurance that it will do so and short-term price fluctuations in the Class A common stock could reduce the program's effectiveness. Furthermore, the stock repurchase program does not obligate the Company to repurchase any dollar amount or number of shares of the Company's

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Class A common stock, and it may be suspended or discontinued at any time and any suspension or discontinuation could cause the market price of the Company's Class A common stock to decline.

**NACCO is a smaller reporting company and cannot be certain if the reduced disclosure requirements applicable to smaller reporting companies will make the Company's common stock less attractive to investors.**

The Company is currently a "smaller reporting company" as defined in the Securities Exchange Act of 1934, and thus allowed to provide simplified executive compensation disclosures and other decreased disclosure in SEC filings. The reduced disclosures may make it more difficult to compare the Company's performance with other public companies.

NACCO cannot predict whether investors will find the Company's common stock less attractive because of these exemptions. If some investors find NACCO's common stock less attractive as a result, there may be a less active trading market for the Company's common stock and the stock price may be more volatile.

**Certain members of the Company's extended founding family own a substantial amount of its Class A and Class B common stock and, if they were to act in concert, could control the outcome of director elections and other stockholder votes on significant corporate actions.**

The Company has two classes of common stock: Class A common stock and Class B common stock. Holders of Class A common stock are entitled to cast one vote per share and, as of December 31, 2022, accounted for approximately 27 percent of the voting power of the Company. Holders of Class B common stock are entitled to cast ten votes per share and, as of December 31, 2022, accounted for the remaining voting power of the Company. As of December 31, 2022, certain members of the Company's extended founding family held approximately 34 percent of the Company's outstanding Class A common stock and approximately 99 percent of the Company's outstanding Class B common stock. On the basis of this common stock ownership, certain members of the Company's extended founding family could have exercised approximately 81 percent of the Company's total voting power. Although there is no voting agreement among such extended family members, in writing or otherwise, if they were to act in concert, they could control the outcome of director elections and other stockholder votes on significant corporate actions, such as certain amendments to the Company's certificate of incorporation and sales of the Company or substantially all of its assets. Because certain members of the Company's extended founding family could prevent other stockholders from exercising significant influence over significant corporate actions, the Company may be a less attractive takeover target, which could adversely affect the market price of its common stock.

**General Risk Factors**

**The Company's effective income tax rate could be volatile and materially change as a result of changes in tax laws, mix of earnings and other factors.**

The Company is subject to income taxes in the United States and the effective income tax rate is impacted by certain U.S. federal income tax benefits currently available to coal mining and oil and gas exploration and development companies. Future results of operations could be affected by changes in the Company's effective income tax rate as a result of an increase in the statutory tax rate or the reduction or elimination of percentage depletion as well as changes in the mix of earnings between entities that benefit from percentage depletion and those that do not.

**Current and future capital and credit market conditions could adversely affect the Company's ability to obtain bank financing on reasonable terms. Certain financial institutions have acted to limit available financing for companies in the fossil fuel industry, including coal mining, which could result in increases in costs of borrowing or in the Company's ability to maintain financing at current levels.**

The Company may be unable to obtain financing on reasonable terms. Historically, the Company has addressed its liquidity needs (including funds required to pay dividends and fund working capital and planned capital expenditures) with operating cash flow and borrowings under credit facilities. The Company's wholly-owned subsidiary, NACoal, has a revolving line of credit of up to $150.0 million that expires in November 2025. The Company's ability to access the capital markets and the costs and terms of available financing depends on many factors, including perceived credit risks of companies with coal and/or oil and gas exposure as a result of current market sentiment for fossil fuels. Certain financial institutions have taken actions to limit available financing to entities that produce or use fossil fuels. The volatility in the energy industry combined with recent bankruptcies and additional perceived credit risks of companies with coal and/or oil and gas exposure has resulted in traditional bank lenders seeking to reduce or eliminate their lending exposure to these companies. An inability to obtain bank financing, or

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refinance with terms that are as favorable as the existing terms of such indebtedness, could have a material adverse effect on the Company's operating results and financial condition.

**Failure to obtain financial assurance to secure reclamation and other long-term obligations, including surety bonds and letters of credit on acceptable terms, could affect NACCO's ability to mine.**

Federal and state laws require the Company to provide financial assurance or financial security to secure performance or payment of certain long-term obligations, such as mine closure or reclamation costs, federal and state workers' compensation and black lung benefit costs, leases and other obligations. Future federal and state laws and regulations may require higher amounts of financial security, including as a result of changes to certain factors used to calculate the bonding or security amounts. Bond issuers may demand higher fees or additional collateral, including cash or letters of credit or other terms less favorable upon renewals. As the Company is required by state and federal law to have bonds or other acceptable security in place before mining can commence or continue, the failure to maintain surety bonds, letters of credit or other guarantees or security arrangements would materially and adversely affect NACCO's ability to mine. That failure could result from a variety of factors, including lack of availability, higher expense or unfavorable market terms, the exercise by third-party surety bond issuers of their right to refuse to renew the surety and restrictions on availability of collateral for current and future third-party surety bond issuers under the terms of the Company's financing arrangements. In addition, as a result of increasing credit pressures on the coal industry, it is possible that surety bond providers could demand cash collateral as a condition to providing or maintaining surety bonds. Any such demands, could have a material adverse impact on the Company's liquidity and financial position. If the Company is unable to meet collateral requirements and cannot otherwise obtain or retain required surety bonds, it may be unable to satisfy legal requirements necessary to conduct mining operations. Difficulty in acquiring surety bonds, or additional collateral requirements, would increase the Company's costs and likely require greater use of alternative sources of funding for this purpose, which would reduce the Company's liquidity.

**Insurance coverage is increasingly expensive, contains more stringent terms and may be difficult to obtain in the future. A number of global insurance companies have taken steps to limit coverage for companies in the fossil fuel industry, including coal mining, which could result in significant increases in costs of insurance or in the Company's ability to maintain insurance coverage at current levels.** 

The Company holds a number of insurance policies, including director and officers' liability and property and casualty insurance coverages. Because the Company is involved in coal mining, costs of insurance may increase substantially or insurance carriers may limit or decide not to insure the Company in the future. In addition, if the Company makes significant insurance claims under the Company's insurance policies, such claims may have a material adverse effect on its ability to obtain future insurance coverage at commercially reasonable rates. Limited, or an inability to obtain, insurance coverage, significant increases in the premiums or deductibles of insurance, or losses in excess of its liability insurance coverage limits, could have a material adverse effect on the Company's operating results and financial condition.

**Increasing emphasis and changing expectations with respect to environmental, social and governance matters may impose additional costs on the Company or expose the Company to new or additional risks.**

Expectations relating to environmental, social and governance ("ESG") matters have been rapidly evolving and increasing. Government organizations, including the SEC, are enhancing or advancing legal, regulatory and disclosure requirements specific to ESG matters. The heightened focus on ESG issues requires the continuous monitoring of various and evolving laws, regulations, standards and expectations and the associated reporting requirements. Investor advocacy groups, certain institutional investors, investment funds and other influential investors are also increasingly focused on ESG practices. The Company could face pressures from investors, who are increasingly focused on climate change, to prioritize sustainable energy practices, reduce the Company's carbon footprint and promote sustainability. Investors may request the Company implement ESG procedures or standards as a condition to maintain their investment or to make further investments. Lenders and insurers may also limit lending to and insuring of companies that do not meet certain ESG measures endorsed by them. Additionally, the Company may face reputational challenges in the event its ESG practices are inconsistent with the third-party views of acceptable ESG practices. Companies which do not adapt to or comply with regulatory, investor or stakeholder expectations and standards, which are evolving, or which are perceived to have not responded appropriately, may suffer from reputational damage and the business, financial condition, and/or stock price of such a company could be materially and adversely affected.

**The Company may be subject to litigation seeking to hold energy companies accountable for the effects of climate change.**

Increasing attention to climate change risk has also resulted in a recent trend of governmental investigations and private litigation by local and state governmental agencies as well as private plaintiffs in an effort to hold energy companies

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accountable for the effects of climate change. Other public nuisance lawsuits have been brought in the past against power, coal, oil and gas companies alleging that their operations are contributing to climate change. The plaintiffs in these suits sought various remedies, including punitive and compensatory damages and injunctive relief. While the U.S. Supreme Court held that any federal common law had been displaced by the CAA and thus dismissed the public nuisance claims against the defendants in those cases, tort-type liabilities remain a possibility and a source of concern. We could incur substantial legal costs associated with defending such lawsuits in the future. Government entities in certain states have brought similar claims seeking to hold a wide variety of companies that produce fossil fuels liable for the alleged impacts of the GHG emissions attributable to those fuels or for other grounds related to climate change, such as improper disclosure of climate change risks. Those lawsuits allege damages as a result of climate change and the plaintiffs are seeking unspecified damages and abatement under various tort theories. We have not been made a party to these suits, but it is possible that we could be included in similar future lawsuits initiated by state and local governments as well as private claimants.

**The Company's business could suffer if NACCO's information technology systems are disrupted, cease to operate effectively or if the Company experiences a security breach, a cyber incident or cyber attack.**

Like many other companies, the Company is the target of malicious cyber attack attempts in the normal course of business. Cybersecurity incidents involving businesses and other institutions are on the rise. Cyber threats are rapidly evolving and those threats and the means for obtaining access to information in digital and other storage media are becoming increasingly sophisticated. Cyber threats and cyber attackers can be sponsored by nation states or sophisticated criminal organizations or be the work of independent hackers.

As cyber threats evolve and become more difficult to detect and successfully defend against, one or more cyber attacks might defeat the Company's or a third-party service provider's security measures in the future. Employee error or other irregularities may also result in a failure of security measures and a breach of information systems. Moreover, hardware, software or applications the Company may use have inherent defects of design, manufacture or operations or could be inadvertently or intentionally implemented or used in a manner that could compromise information security.

A security breach and loss of information may not be discovered for a significant period of time after it occurs. Any compromise of data security could result in a violation of applicable privacy and other laws or standards, the loss of valuable business data, or a disruption of the Company's business. A security breach involving the misappropriation, loss or other unauthorized disclosure of sensitive or confidential information could give rise to unwanted media attention, materially damage customer relationships and the Company's reputation, and result in fines, fees, or liabilities, which may not be covered by insurance policies.

The Company relies on information technology systems to operate its business and to record and process transactions; respond to customer inquiries; purchase supplies; provide services; deliver inventory on a timely basis; and maintain cost-efficient operations. Despite the Company's efforts, the Company's information technology systems may be vulnerable, from time to time, to damage or interruption from user error, computer viruses, power outages, third-party intrusions and other technical malfunctions.

Through the Company's business operations, the Company collects and stores confidential information from its customers and vendors and personal information and other confidential information from its employees. Although the Company has taken steps designed to safeguard such information, there can be no assurance that such information will be protected against unauthorized access, use or disclosure. Unauthorized parties may penetrate the Company's or its vendors' network security and, if successful, misappropriate such information. Additionally, methods to obtain unauthorized access to confidential information change frequently and may be difficult to detect, which can impact the Company's ability to respond appropriately.

The Company could be subject to liability for failure to comply with privacy and information security laws, for failing to protect personal information or for failing to respond appropriately. Loss, unauthorized access to, or misuse of confidential or personal information could disrupt the Company's operations, damage the Company's reputation, and expose the Company to claims from customers, financial institutions, regulators, employees and other persons, any of which could have an adverse effect on the Company's business, financial condition and results of operations.

Security breaches, cyber incidents or cyber attacks could include, among other things, computer viruses, malicious or destructive code, ransomware, social engineering attacks (including phishing and impersonation), hacking, denial of service attacks and other attacks. Cybersecurity threats to, and incidents involving, vendors and other third-parties who support the Company's activities could impact the business. For example, although the Company has not experienced any material impacts from the SolarWinds Orion cybersecurity breach that was widely publicized in December 2020, similar future events could have a material impact on the Company. The Company is continuously installing new and upgrading existing information

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technology systems. The Company uses employee awareness training around phishing, malware, and other cyber risks. The Company believes these incidents are likely to continue and is unable to predict the direct or indirect impact of future attacks or breaches to business operations.

**The Company's results of operations, financial condition, cash flows and stock price could be adversely affected by pandemics, epidemics or other public health emergencies.**

The Company's results of operations, financial condition, cash flows and stock price could be adversely affected by pandemics, epidemics or other public health emergencies. Although the Company operates facilities consistent with federal guidelines and state and local orders, any pandemic and the preventive or protective actions taken by governmental authorities may have a material adverse effect on the Company's operations, work force, supply chain or customers, including business shutdowns or disruptions. The extent to which pandemics may adversely impact the Company's businesses depends on future developments, which are highly uncertain and unpredictable, including the extent of new outbreaks, the nature of government public health guidelines and the public's adherence to those guidelines. Any resulting financial impact cannot reasonably be estimated at this time, but could have a material adverse effect on the Company's financial condition, cash flows and results of operations.

Even after any pandemic has subsided, the Company may experience material adverse effects due to a decline in economic activity.

**The Company's operations could be disrupted by natural or human causes beyond its control.**

The Company's operations are subject to disruption from natural or human causes beyond its control, including physical risks from hurricanes, severe storms, floods and other forms of severe weather, accidents, fires, earthquakes, terrorist acts and epidemic or pandemic diseases such as the coronavirus, any of which could result in suspension of operations or harm to people or the environment. While all of the Company's operations are located in the United States, the Company participates in a global supply chain, and if governments regulate or restrict the flow of labor or products or impede the travel of Company personnel, the Company's ability to conduct normal business operations could be impacted which could adversely affect the Company's results of operations and liquidity.

**Item 1B. UNRESOLVED STAFF COMMENTS**

None.

**Item 2. PROPERTIES**

**<u>Coal Mining Segment - Operations</u>**

**NACCO-owned Properties**

**1.0 INTRODUCTION**

Information concerning the Company's mining properties in this Form 10-K have been prepared in accordance with the requirements of subpart 1300 of Regulation S-K. As used in this Report on Form 10-K, the terms "mineral resource," "measured mineral resource," "indicated mineral resource," "inferred mineral resource," "mineral reserve," "proven mineral reserve" and "probable mineral reserve" are defined and used in accordance with subpart 1300 of Regulation S-K. Under subpart 1300 of Regulation S-K, mineral resources may not be classified as "mineral reserves" unless the determination has been made by a qualified person that the mineral resources can be the basis of an economically viable project. Readers are specifically cautioned not to assume that any part or all of the mineral deposits (including any mineral resources) in these categories will ever be converted into mineral reserves, as defined by the subpart 1300 of Regulation S-K.

Readers are cautioned that, except for that portion of mineral resources classified as mineral reserves, mineral resources do not have demonstrated economic value. Inferred mineral resources are estimates based on limited geological evidence and sampling and have too high of a degree of uncertainty as to their existence to apply relevant technical and economic factors likely to influence the prospects of economic extraction in a manner useful for evaluation of economic viability. Estimates of inferred mineral resources may not be converted to a mineral reserve. It cannot be assumed that all or any part of an inferred mineral resource will ever be upgraded to a higher category. A significant amount of exploration must be completed in order to determine whether an inferred mineral resource may be upgraded to a higher category. Therefore, readers are cautioned not to assume that all or any part of an inferred mineral resource exists, that it can be the basis of an economically viable project, or

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that it will ever be upgraded to a higher category. Likewise, readers are cautioned not to assume that all or any part of measured or indicated mineral resources will ever be converted to mineral reserves. See "Item 1A - "Risk Factors" on page 19.

The information that follows is derived, for the most part, from, and in some instances is an extract from, the technical report summary ("TRS") prepared in compliance with the Item 601(b)(96) and subpart 1300 of Regulation S-K. The TRS was prepared by employees of the Company. Portions of the following information are based on assumptions, qualifications and procedures that are not fully described herein. Reference should be made to the full text of the TRS, incorporated herein by reference and made a part of this Report on Form 10-K. The information regarding MLMC was reviewed by employees of the Company that are qualified persons as defined by subpart 1300 of Regulation S-K.

Coteau, Falkirk, Coyote Creek and MLMC, each wholly-owned subsidiaries of NACCO, operate surface coal mines under long-term contracts with power generation companies pursuant to a service-based business model.

The Company operates additional surface coal mines where the customer owns or controls the coal tonnages. The Company conducts activities to extract these customer-owned coal tonnages pursuant to long-term contracts. The Company has determined these properties are not subject to subpart 1300 of Regulation S-K reporting and has not estimated mineral resources or reserves for these properties in accordance with subpart 1300 of Regulation S-K.

Locations of the properties subject to SEC Section 1300 reporting are shown in Figure 1.1 Surface Coal Mines Operational During 2022 Subject to SEC Section 1300 Reporting.

![nacco-20221231_g1.jpg](nacco-20221231_g1.jpg)

Figure 1.1 Surface Coal Mines Operational During 2022 Subject to SEC Section 1300 Reporting

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A summary of coal production at the Mines subject to SEC Section 1300 Reporting for the past three years has been tabulated and is presented on Table 1.1 Production Summary.

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| | | | |
|:---|:---|:---|:---|
| | Tons (in millions) | Tons (in millions) | Tons (in millions) |
| | 2020 | 2021 | **2022** |
| The Coteau Properties Company | 12.6 | 12.5 | **13.4** |
| The Falkirk Mining Company | 7.2 | 7.9 | &nbsp;&nbsp;**7.6** |
| Coyote Creek Mining Company | 2.0 | &nbsp;&nbsp;&nbsp;2.0 | &nbsp;&nbsp;&nbsp;**1.8** |
| Mississippi Lignite Mining Company | 2.5 | &nbsp;&nbsp;&nbsp;3.0 | &nbsp;&nbsp;&nbsp;**3.2** |
| Totals | 24.3 | 25.4 | **26.0** |

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Table 1.1 Production Summary

**2.0 MINING PROPERTIES SUBJECT TO SUBPART 1300 OF REGULATION S-K REPORTING**

**2.1 Red Hills Mine — Mississippi Lignite Mining Company**

MLMC is the owner and operator of the Red Hills Mine. The Red Hills Mine is a lignite surface mine in production. Prior to MLMC, there were no previous mining operations on the Red Hills Mine property.

The MLMC contract is the only operating coal contract in which the Company is responsible for all operating costs, capital requirements and final mine reclamation; therefore, MLMC is consolidated within NACCO's financial statements. MLMC sells coal to its customer at a contractually agreed-upon price which adjusts monthly, primarily based on changes in the level of established indices which reflect general U.S. inflation rates. Profitability at MLMC is affected by customer demand for coal and changes in the indices that determine sales price and actual costs incurred.

A summary of coal production at MLMC for the past three years has been tabulated and is presented on Table 2.1 Production Summary.

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| | | | |
|:---|:---|:---|:---|
| | Tons (in millions) | Tons (in millions) | Tons (in millions) |
| | 2020 | 2021 | **2022** |
| Mississippi Lignite Mining Company | 2.5 | 3.0 | **3.2** |

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Table 2.1 Production Summary

The Red Hills Mine generally produces between 2 million and 3 million tons of lignite coal annually. The Red Hills Mine started delivering coal in 2000. All production from the mine is delivered to its customer's Red Hills Power Plant.

The Red Hills Mine, operated by MLMC, is located approximately 120 miles northeast of Jackson, Mississippi (Figure 2.1). The entrance to the mine is by means of a paved road located approximately one mile west of Highway 9. MLMC owns in fee approximately 7,773 acres of surface interest and 4,761 acres of coal interests. MLMC holds leases granting the right to mine approximately 5,538 acres of coal interests and the right to utilize approximately 5,065 acres of surface interests. MLMC holds subleases under which it has the right to mine approximately 1,623 acres of coal interest. The majority of the leases held by MLMC were originally acquired during the mid-1970s to the early 1980s with terms extending 50 years, many of which can be further extended by the continuation of mining operations. The lignite deposits of the Gulf Coast are found primarily in a narrow band of strata that outcrops/subcrops along the margin of the Mississippi Embayment. The potentially exploitable tertiary lignites in Mississippi are found in the Wilcox Group. The outcropping Wilcox is composed predominately of non-marine sediments deposited on a broad flat plain.

The towns of Ackerman, Eupora, Starkville, Louisville, Kosciusko, and numerous smaller communities are within a 40-mile radius of the Red Hills Mine and provide a vast employment base. Furthermore, Mississippi State University (MSU) is located approximately 30 miles east of the mine in Starkville. MLMC has a history of partnership with MSU as well as the local community colleges for science, technology, engineering, and mathematics (STEM) research and skilled trades training.

The Red Hills Mine sources power for mine office facilities and operations from 4-County Electric Power Association, and water for the mine office facilities from the Choctaw Water Association. Fuel for equipment is supplied by Dickerson

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Petroleum located in Kosciusko. The Red Hills Mine has, or is currently constructing, all supporting infrastructure for mining operations.

Local access to the Red Hills Mine is by way of Highway 9 between Ackerman, Mississippi and Eupora, Mississippi which connects to Pensacola Road that leads to the Red Hills Mine paved access road. Pensacola Road connects with Highway 9 approximately 5 miles north of Ackerman, MS. The mine road is approximately 1 mile west from Highway 9 along Pensacola Road.

Travel to the Red Hills Mine by air is possible using the Jackson-Medgar Wiley Evers International Airport in Jackson, Mississippi, approximately 104 miles south of the mine, and then using ground transportation, traveling via Highway 25, Highway 15, and Highway 9. Alternatively, the Golden Triangle Regional Airport is a smaller airport approximately 50 miles from the Red Hills Mine by means of Highway 82 west, Highway 15 south, and Highway 9 north.

The Red Hills Mine is in close proximately to river ports of the Tennessee-Tombigbee Waterway and the Mississippi River. The Lowndes County Port is approximately 60 miles east of the mine. The Port of Greenville is approximately 135 miles west of the mine, and the Port of Vicksburg, approximately 150 miles southwest of the mine. All ports are connected by major state and federal highways.

In addition to transportation via roadways, air and waterways, the Kansas City Southern (KCS) railroad has a depot located approximately 5 miles south of the mine in Ackerman, and is accessible by Highway 9 and Highway 15. MLMC currently has all permits in place for the Red Hills Mine to operate and adhere to a mine plan projected through April 2032. No mineral processing occurs at the Red Hills Mine.

The geology encountered at the Red Hills Mine is stratigraphic in nature with depositional sequences of sands, silts, clays, and lignite. The vertical repetition of geologic strata facilitated a straightforward setting to establish and study the baseline geological, geochemical, geotechnical, and geohydrological conditions at the Red Hills Mine.

Development of the Red Hills Mine began in 1997, with full commercial deliveries commencing in 2002. The mining operation is comprised of four major equipment fleets. Primary removal of burden is achieved with one 82-cubic yard electric-powered dragline, four large track-type push dozers, and a truck and shovel fleet utilizing a 41-cubic yard electric rope shovel. Lignite is mined using a surface miner or a hydraulic backhoe to load a fleet of end dump haul trucks, and is directly shipped to the RHPP or the lignite stockpile. The overall average quality of the mined lignite seams meets the required power plant quality specifications. Therefore, no mineral processing is performed by MLMC.

The mine office facilities and original equipment fleets at the Red Hills Mine were constructed, acquired, or purchased new during the development stage of the mine. The facilities and equipment are maintained to allow for safe and efficient operation. The equipment is well maintained, in good physical condition and is either updated or replaced periodically with newer models or upgrades available to keep up with modern technology. As equipment wears out, MLMC evaluates what replacement option will be the most cost-efficient, including the evaluation of both new and used equipment.

The total cost of the property and equipment, net of applicable accumulated amortization, depreciation and impairment as of December 31, 2022 is $80.4 million.

The Red Hills Mine currently has no significant encumbrances to the property. No mining permit violations have been issued at the Red Hills Mine in the past ten years. One notice of violation ("NOV") was issued in April 2020 for a water quality exceedance that was determined to not be the fault of Red Hills Mine and no further action was required. A second NOV was issued in June 2022 for a water sampling violation. Both NOVs were not related to the mining permit. Permitting requirements are discussed in Section 17.0 of the TRS.

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**Figure 2.1 – Red Hills Mine Location**

![nacco-20221231_g2.jpg](nacco-20221231_g2.jpg)

Mineral resources and reserves have been summarized from the TRS for MLMC and have been included as Table 2.2 and Table 2.3. Qualities are being reported on an as-received moisture basis. Prices in Table 2.2 are based on economic cut-off grades of $29.66 per ton at MLMC. Prices in Table 2.3 are based on economic cut-off grades of $36.06 per ton at MLMC.

Material assumptions and criteria used in the determination of Mineral Resource and Mineral Reserves reported herein are provided within the filed TRS for the Mississippi Lignite Mining Company – Red Hills Mine dated December 2022.

Section 11.0 of the TRS describes the key assumptions, parameters, and methods used for the estimation of Mineral Resources. Assumptions include a maximum cumulative stripping ratio of 18:1 based on an assumed lignite sales price of $29.66 per ton. A further description of the verified drilling data used to model the lignite deposit for estimation of Mineral Resources is provided in Section 7.2 Drilling Exploration, 8.0 Sample Preparation, Analyses, and Security, and Section 9.0 Data Verification.

Section 12.0 of the TRS describes the key assumptions, parameters, and methods used for the estimation of Mineral Reserves, and include the following:

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• Maximum stripping ratio: 14:1;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• Mining production rates on a cubic yard and per ton basis remain relatively consistent with historical performance;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• Mining costs on a unit basis remain relatively consistent with historical performance;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• Minimum minable lignite thickness: 1.0 feet;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• Minimum parting thickness before seams are composited: 6.0 inches;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• Maximum depth of mining: approximately 320 feet;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• Lignite density defined by seam from coal core drilling data and modified by dilution parameters and approximately 80 lb/ft³; and

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&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• Recovery rates by seam ranging from 67% to 100%.

Modifying factors including dilution parameters and technical information related to the mining process are described in detail under Section 13.0 Mining Methods. Economic factors to support the Mineral Reserve estimates are described in Section 18.0 Capital and Operating Costs and 19.0 Economic Analyses.

The Mineral Resources presented in Table 2.2 below have been estimated by applying a series of geologic and physical limits as well as high-level mining and economic constraints. The mining and economic constraints were limited to a level sufficient to support reasonable prospect for future economic extraction of the estimated Mineral Resources. The categorized Mineral Resources reported herein are exclusive of Mineral Reserves.

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| | | | | | | |
|:---|:---|:---|:---|:---|:---|:---|
| **Lignite Coal** | **Resource Classification** | **Tonnage**<br>**(Kiloton "Kt")** | **Grades/Qualities** | **Grades/Qualities** | **Grades/Qualities** | **Grades/Qualities** |
| **Lignite Coal** | **Resource Classification** | **Tonnage**<br>**(Kiloton "Kt")** | **Calorific Value (Btu/lb)** | **Moisture (%wt)** | **Ash (%wt)** | **Sulfur (%wt)** |
| Mississippi Lignite Mining Company | Measured | 4300 | 5210 | 44.6 | 12.8 | 0.6 |
| Mississippi Lignite Mining Company | Indicated | 500 | 5300 | 43.6 | 12.7 | 0.7 |
| Mississippi Lignite Mining Company | Measured + Indicated | 4800 | 5220 | 44.5 | 12.8 | 0.6 |
| Mississippi Lignite Mining Company | Inferred | 1600 | 5370 | 46.0 | 9.9 | 0.5 |

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Note:

–Mineral Resources that are not Mineral Reserves do not have demonstrated economic viability and there is no certainty that all or any part of such Mineral Resources will be converted into Mineral Reserves.

–Mineral Resources are in-situ and exclusive of 25.4 million tons (Mt) of Mineral Reserves.

–Mineral Resources are reported using an economic cutoff of $29.66 per ton.

–Resources are presented with a minimum 1 foot seam thickness, a maximum as received moisture basis ash content of 30%, and a minimum calorific value of 4000 BTUs on an as received moisture basis cutoff.

–Resources are estimated using Vulcan Software.

–Tonnages and qualities have been rounded to an accuracy level deemed appropriate by the QP. Summation errors due to rounding may exist.

Table 2.2 Mineral Resources Summary as of December 31, 2022

The Mineral Reserves presented in Table 2.3 below were determined to be the economically mineable portion of the measured and indicated Mineral Resources after the consideration of modifying factors related to the mining process. Inferred Mineral Resources were not considered for Mineral Reserves.

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| | | | | | | |
|:---|:---|:---|:---|:---|:---|:---|
| **Lignite Coal** | **Reserve Classification** | **Tonnage<br>(Kt)** | **Grades/Qualities** | **Grades/Qualities** | **Grades/Qualities** | **Grades/Qualities** |
| **Lignite Coal** | **Reserve Classification** | **Tonnage<br>(Kt)** | **Calorific Value (Btu/lb)** | **Moisture (%wt)** | **Ash (%wt)** | **Sulfur (%wt)** |
| Mississippi Lignite Mining Company | Proven | 18000 | 5090 | 43.4 | 14.8 | 0.6 |
| Mississippi Lignite Mining Company | Probable | 7400 | 5120 | 42.6 | 15.4 | 0.7 |
| Mississippi Lignite Mining Company | Total | 25400 | 5100 | 43.1 | 15.0 | 0.6 |

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Note:

–Mineral Reserves have been demonstrated to be economic based on a positive cash flow

–Mineral Reserves are stated on a Run of Mine basis

–An economic cutoff in the Life of Mine plan averaged $36.06 per ton and was used to demonstrate coal reserves

–Recovery varies by coal seam and ranges from 67% to 100%

–Mineral Reserves use an economic cut-off of a maximum cumulative stripping ratio of 14:1. There are some instances where the stripping ratio for a single year could exceed 14:1, but the average for the entire area evaluated is less than 14:1.

–Historical coal recovery rates at Red Hills Mine have been applied to generate the Mineral Reserve tonnages.

–Mineral Reserves are estimated using Vulcan Software.

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–Tonnages and qualities have been rounded to an accuracy level deemed appropriate by the Qualified person ("QP"). Summation errors due to rounding may exist.

Table 2.3 Mineral Reserves Summary as of December 31, 2022

Table 2.4 describes the difference between the Mineral Reserves and Mineral Resources reported as of December 31, 2021 and December 31, 2022.

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| | | | |
|:---|:---|:---|:---|
| **Resource Classification** | **December 31, 2021 Tonnage (Kt)** | **December 31, 2022 Tonnage (Kt)** | **Percent Change** |
| Measured | 11500 | 4300 | (63)% |
| Indicated | 15200 | 500 | (97)% |
| Measured + Indicated | 26700 | 4800 | (82)% |
| Inferred |  | 1600 | N/A |
| **Reserve Classification** | **December 31, 2021 Tonnage (Kt)** | **December 31, 2022 Tonnage (Kt)** | **Percent Change** |
| Proven | 17200 | 18000 | 4% |
| Probable | 10300 | 7400 | (28)% |
| Proven + Probable | 27400 | 25400 | (7)% |

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Table 2.4. Net difference of reported Mineral Resources and Mineral Reserves from previous reporting period to current reporting period.

The Mineral Resources and Mineral Reserves as of December 31, 2022 reflect an update to the life of mine ("LOM") plan and economic assessment. The methodology used to determine the Mineral Resource classification has been revised by the mineral resource QP. The change in methodology included revised estimates of quality and thickness cutoff assumptions as well as the removal of minor seams and the exclusion of certain areas that are no longer considered to contain recoverable coal. Additionally, MLMC delivered 3.2 million tons during 2022.

**2.2 Material Properties with no Mineral Resources or Mineral Reserves** 

The lignite coal tonnages at Coteau, Falkirk and Coyote Creek have not been classified as "measured resources", "indicated resources", or "inferred resources" as defined in Items 1300 through 1305 of Regulation S-K, and as a result, do not have any "proven" or "probable" reserves under such definition and are therefore classified as an "Exploration Stage Property" pursuant to Items 1300 through 1305 of Regulation S-K. Coteau, Falkirk and Coyote Creek will continue to be classified as exploration stage properties until such time as proven or probable mineral reserves have been established in accordance with subpart 1300 of Regulation S-K, even though they continue to deliver lignite to their respective customers.

At Coteau, Coyote Creek and Falkirk, the Company is paid a management fee per ton of coal or heating unit (MMBtu) delivered. Each contract specifies the indices and mechanics by which fees change over time, generally in line with broad measures of U.S. inflation. The customers are responsible for funding all mine operating cost, including final mine reclamation, and directly or indirectly providing all of the capital required to build and operate the mine. This contract structure eliminates the Company's exposure to spot coal market price fluctuations.

Coteau, Coyote Creek and Falkirk each have only one customer for which they extract and deliver coal. These customers operate coal-fired electric generation power plants adjacent to each mine location (and in the case of Coteau, a synthetic natural gas and chemical/fertilizer production facility).

The sales price under the Coteau, Coyote Creek and Falkirk contracts are not market driven. Unlike traditional sales made based on market factors, under the provisions of the long-term mining agreements, the coal sales price at Coteau, Coyote Creek and Falkirk includes (i) all costs incurred to extract, process and deliver coal (i.e. the cost of production) and (ii) the agreed-upon profit per ton of coal or MMBtu unit delivered to the customer. Cost of production includes all the costs actually incurred in the operation of the mine including mining, processing and delivery of coal. Costs included within revenue include all production, transportation and maintenance costs including, without limitation, the following types of costs:

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&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;◦ Labor, which include wages and all related payroll taxes, benefits and fringes, including welfare plans; group insurance, vacations and other comparable benefits of employees

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;◦ Materials and supplies,

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;◦ Tools,

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;◦ Machinery and equipment not capitalized or leased,

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;◦ Costs of acquiring interests in coal reserves and surface lands,

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;◦ Rental of machinery and equipment,

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;◦ Power costs,

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;◦ Reasonable and necessary services by third parties

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;◦ Insurance including worker's compensation

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;◦ Certain taxes, and

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;◦ Cost of reclamation

The contractually-determined coal sales price includes reimbursement of all costs incurred and the agreed-upon profit. The agreed-upon profit adjusts based on changes in the level of established indices (e.g., CPI-U and/or PPI indices). The cost-plus nature of the contracts provide assurance that all costs incurred, including contemporaneous and final reclamation, will be reimbursed by the respective customer and negates any risk of loss which allows the mines to remain cash flow positive through the end of the contract terms. The coal sales price as well as profitability at Coteau, Falkirk and Coyote Creek are not subject to any change based on market factors. Profitability at these mines is affected by two factors: demand for coal (because this impacts units of agreed profit that are charged) and changes in the indices that determine coal sales price (because this adjusts the agreed-upon per unit profit). Under any scenario, Coteau, Coyote Creek and Falkirk will be cash flow positive as a result of the terms of the mining agreements.

Extraction of Coteau, Coyote Creek and Falkirk's lignite tonnages is only economically viable as a result of the long-term mining agreements in place with each mine's respective customer. The development of the Coteau, Coyote Creek and Falkirk mines was conducted in tandem with the development of the respective mine mouth power plants each serve. The power plants were designed to operate exclusively on the coal provided by the adjacent mines. No other market exists for the lignite at Coteau, Coyote Creek and Falkirk as the cost of transportation makes sales to any entity other than the current mine-mouth operator unprofitable.

Coteau, Coyote Creek and Falkirk meet the definition of a variable interest entity ("VIE"). In each case, NACCO is not the primary beneficiary of the VIE as it does not exercise financial control; therefore, NACCO does not consolidate the results of these operations within its financial statements. Instead, these contracts are accounted for as equity method investments. The income before income taxes associated with these VIEs is reported as Earnings of unconsolidated operations on the Consolidated Statements of Operations, and the Company's investment is reported on the line Investments in Unconsolidated Subsidiaries in the Consolidated Balance Sheets

**Coteau**

The Freedom Mine, operated by Coteau, generally produces between 12.5 million and 13.5 million tons of lignite coal annually. The mine started delivering coal in 1983. All production from the mine is delivered to Dakota Coal Company, a wholly owned subsidiary of Basin Electric. Dakota Coal Company then sells the coal to the Synfuels Plant, Antelope Valley Station and Leland Olds Station, all of which are operated by affiliates of Basin Electric. The Synfuels Plant is a coal gasification plant that manufactures synthetic natural gas and produces fertilizers, solvents, phenol, carbon dioxide, and other chemical products for sale.

The Freedom Mine is located approximately 90 miles northwest of Bismarck, North Dakota (Figure 2.2). The main entrance to the Freedom Mine is accessed by means of a paved road and is located on County Road 15. Coteau holds 374 leases granting the right to extract approximately 33,966 acres of coal interests and the right to utilize approximately 23,451 acres of surface interests. In addition, Coteau owns in fee 33,888 acres of surface interests and 4,107 acres of coal interests. Substantially all of the leases held by Coteau were acquired in the early 1970s and have been replaced with new leases or have lease terms for a period sufficient to meet Coteau's contractual production requirements.

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**Figure 2.2 – Freedom Mine Location**

![nacco-20221231_g3.jpg](nacco-20221231_g3.jpg)

The towns of Beulah, Hazen, and Stanton along with other smaller communities are within a 40-mile radius of the Freedom Mine and provide a vast supply of the employment base. Employees also come from the cities of Bismarck, Minot, and Dickinson, all of which are less than 100 miles away from the mine.

The Freedom Mine sources power for mine office facilities and operations from Roughrider Electric Cooperative, and water for the mine office facilities from the Southwest Water Authority. Fuel for equipment is supplied by multiple local vendors. The Freedom Mine has, or is currently constructing, all supporting infrastructure for mining operations.

The main entrance to the Freedom Mine is accessed by traveling north of Beulah on Highway 49 for one mile, then north on County Road 21 for two miles, then west on County Road 26 for three miles, and then north on County Road 15 for two miles as shown on Figure 2.2. Location of the Freedom Mine.

Travel to the Freedom Mine by air is possible by means of the Bismarck Municipal Airport, Bismarck, ND, which is approximately 90 miles southeast of the mine. From the airport, the mine is accessed by means of ground transportation by traveling west approximately 50 miles via Interstate 94, taking exit 110 and traveling north approximately 28 miles on ND Highway 49 to Beulah, ND, and so on as explained in the previous paragraph.

Travel to the Freedom Mine by rail is possible using the Amtrak Network, which runs through northern North Dakota mostly along the US Highway 2 corridor, and passes through the larger cities of Williston, Minot, Grand Forks, and Fargo, and smaller cities of Stanley, Rugby, and Devils Lake. From these locations, the mine can be accesses via ground transportation on Interstate 29 or Interstate 94 and various highways. The main highways are US Highway 2, US Highway 83, US Highway 85, US Highway 200, and US Highway 281.

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North Dakota's freight rail service is largely provided by Burlington Northern Santa Fe Railway and Canadian Pacific Railway.

The coal tonnages are located in Mercer County, North Dakota, starting approximately two miles north of Beulah, North Dakota. The formations of sedimentary origin were deposited in the Williston Basin, the dominant structural feature of western North Dakota. The center of the basin is located near the city of Williston, North Dakota, approximately 100 miles northwest of the Freedom Mine. The economically mineable coal occurs in the Sentinel Butte Formation, and is overlain by the Coleharbor Formation. The Coleharbor Formation unconformably overlies the Sentinel Butte Formation. It includes all of the unconsolidated sediments resulting from deposition during glacial and interglacial periods. Lithologic types include gravel, sand, silt, clay and till. The modified glacial channels are in-filled with gravels, sands, silts and clays overlain by till. The coarser gravel and sand beds are generally limited to near the bottom of the channel fill. The general stratigraphic sequence in the upland portions of the reserve area consists of till, silty sands and clayey silts.

Fill-in drilling programs are routinely conducted by Coteau for the purpose of refining guidance related to ongoing operations. It is common practice at the Freedom Mine to tighten the drilling density within the three to four-year block ahead of active operations to an average drill hole spacing of 660-feet. However, additional exploration may also be scheduled in areas farther out to increase confidence in future mine plan projections.

Coteau utilizes standard surface mining techniques to extract coal from the proposed permit area. Mining operations will typically occur in a sequence of seven events: SPGM removal, overburden removal, coal removal, overburden replacement, final grading, SPGM replacement, and revegetation.

The mine office facilities and original equipment fleets at the Freedom Mine were constructed, acquired, or purchased new during the development stage of the mine. The facilities and equipment are maintained to allow for safe and efficient operation. The equipment is well maintained, in good physical condition and is either updated or replaced periodically with newer models or upgrades available to keep up with modern technology. As equipment wears out, Coteau evaluates what replacement option will be the most cost-efficient, including the evaluation of both new and used equipment.

The total cost of the property, plant and equipment, net of applicable accumulated amortization, depreciation and impairment as of December 31, 2022 is $90.4 million.

The Freedom Mine currently has no significant encumbrances to the property. No NOVs have been issued at the Freedom Mine in the past three years. Coteau currently has all permits in place for the Freedom Mine to operate through 2031. Permit expansions required to extend the life of the mine through 2045 will be acquired as needed. No mineral processing occurs at the Freedom Mine.

**Falkirk Mine**

The Falkirk Mine generally produces between 7 million and 8 million tons of lignite coal annually. The mine started delivering coal in 1978 primarily for the Coal Creek Station, an electric power generating station. Coal Creek Station was owned by GRE until May 1, 2022 when it was purchased by Rainbow Energy. In 2014, Falkirk began delivering coal to Spiritwood Station, another electric power generating station owned by GRE.

The Falkirk Mine, operated by Falkirk, is located approximately 50 miles north of Bismarck, North Dakota on a paved access road off U.S. Highway 83 (Figure 2.3). Falkirk holds 340 leases granting the right to extract approximately 43,648 acres of coal interests and the right to utilize approximately 24,164 acres of surface interests. In addition, Falkirk owns in fee 40,666 acres of surface interests and 1,788 acres of coal interests. Substantially all of the leases held by Falkirk were acquired in the early 1970s with initial terms that have been further extended by the continuation of mining operations.

The towns of Underwood and Washburn are located within ten miles of the mine, with other small communities also nearby. Numerous employees also reside in Bismarck and Mandan, a distance of about 50 miles.

The Falkirk Mine receives both its power and water from Coal Creek Station. However, Falkirk's East shift change building receives water from McLean-Sheridan Rural Water. Fuel for equipment is supplied by multiple local vendors including: Farstad Oil, Missouri Valley Petroleum, and Enerbase Cooperative Resources.

The main entrance to the Falkirk Mine is accessed by traveling north from Bismarck on State Highway 83 for approximately 50 miles, then going west on the access road, 1st Street SW located four miles south of Underwood. The mine office is located two miles to the west.

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Travel to the Falkirk Mine by air is possible using the Bismarck Airport in Bismarck, ND, approximately 55 miles south of the mine, and then using ground transportation, traveling via US Highway 83.

The main railway systems near the Falkirk Mine are Canadian Pacific, BNSF, and Dakota Missouri Valley & Western (DMVW). DMVW crosses through the Falkirk Mine Reserve.

The coal tonnages are located in McLean County, North Dakota, from approximately nine miles northwest of the town of Washburn, North Dakota to four miles north of the town of Underwood, North Dakota. Structurally, the area is located on an intercratonic basin containing a thick sequence of sedimentary rocks. The economically mineable coal occurs in the Sentinel Butte Formation and the Bullion Creek Formation and are unconformably overlain by the Coleharbor Formation. The Sentinel Butte Formation conformably overlies the Bullion Creek Formation. The general stratigraphic sequence in the upland portions of the reserve area (Sentinel Butte Formation) consists of till, silty sands and clayey silts, main hagel lignite bed, silty clay, lower lignite of the hagel lignite interval and silty clays. Beneath the Tavis Creek, there is a repeating sequence of silty to sand clays with generally thin lignite beds.

Operationally, overburden and interburden removal are accomplished using scrapers, dozers, front end loaders, truck shovel fleets, and draglines. Lignite is mined with front end loaders or hydraulic backhoes, and loaded into haul trucks to transport to the stockpile or directly to the customer via truck dumps and conveyors.

Fill-in drilling programs are routinely conducted by Falkirk for the purpose of refining guidance related to ongoing operations. It is common practice at the Falkirk Mine to tighten the drilling density within the three to four-year block ahead of active operations to an average drill hole spacing of 1320-feet. However, additional exploration may also be scheduled in areas farther out to increase confidence in future mine plan projections.

The mine office facilities and original equipment fleets at the Falkirk Mine were constructed, acquired, or purchased new during the development stage of the mine. The facilities and equipment are maintained to allow for safe and efficient operation. The equipment is well maintained, in good physical condition and is either updated or replaced periodically with newer models or upgrades available to keep up with modern technology. As equipment wears out, Falkirk evaluates what replacement option will be the most cost-efficient, including the evaluation of both new and used equipment.

The total cost of the property, plant and equipment, net of applicable accumulated amortization, depreciation and impairment as of December 31, 2022 is $22.4 million.

The Falkirk Mine currently has no significant encumbrances to the property. No Notice of Violations (NOVs) have been issued at the Falkirk Mine in the past three years. There are no outstanding permits related to the LOM plan awaiting regulatory approval. The Falkirk Mining Company currently has all permits in place to operate and adhere to the current mine plan. No mineral processing occurs at the Falkirk Mine.

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**Figure 2.3 – Falkirk Mine Location**

![nacco-20221231_g4.jpg](nacco-20221231_g4.jpg)

**Coyote Creek**

The Coyote Creek Mine generally produces between 1.5 million and 2.0 million tons of lignite annually. The mine began delivering coal in 2016 to the Coyote Station owned by Otter Tail Power Company, Northern Municipal Power Agency, Montana-Dakota Utilities Company and Northwestern Corporation.

The Coyote Creek Mine is located approximately 70 miles northwest of Bismarck, North Dakota (Figure 2.4). The main entrance to the Coyote Creek Mine is accessed by means of a four-mile paved road extending west off of State Highway 49. Coyote Creek holds a sublease to 86 leases granting the right to mine approximately 8,129 acres of coal interests and the right to utilize approximately 15,168 acres of surface interests. In addition, Coyote Creek Mine owns in fee 160 acres of surface interests and has four easements to conduct coal mining operations on approximately 352 acres.

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**Figure 2.4 – Coyote Creek Mine Location**

![nacco-20221231_g5.jpg](nacco-20221231_g5.jpg)

The towns of Beulah, Hazen, and Stanton along with other smaller communities are within a 40-mile radius of the Coyote Creek Mine and provide a vast supply and employment base. A vast supply and employment base also come from some of the major cities of Bismarck, Minot, and Dickinson, all of which are less than 100 miles away from the mine.

The Coyote Creek Mine sources power for mine office facilities and operations from Roughrider Electric Cooperative and Montana-Dakota Utilities Co., and water for the mine office facilities from the Southwest Water Authority. Fuel for equipment is supplied by multiple local vendors. The Coyote Creek Mine has all supporting infrastructure for mining operations.

The main entrance to the mine will be accessed by traveling south of Beulah on Highway 49 for five miles, then west on County Road 25 for four miles. The general location of the Coyote Creek Mine is shown in Figure 1.0 Location of Coyote Creek Mine.

Travel to the Coyote Creek Mine by air is possible using the Bismarck Municipal Airport, Bismarck, ND, approximately 75 miles southeast of the mine. From the airport, the mine is accessed using ground transportation by traveling west approximately 50 miles via Interstate 94, taking exit 110 and traveling north approximately 21 miles on ND Highway 49 to County Road 25, then west for four miles on County Road 25.

Travel to the Coyote Creek Mine by rail is possible using the Amtrak Network, which runs through northern North Dakota mostly along the US Highway 2 corridor, and passes through the larger cities of Williston, Minot, Grand Forks, and Fargo, and smaller cities of Stanley, Rugby, and Devils Lake. From these locations, the mine can be accesses via ground transportation on Interstate 29 or Interstate 94 and various highways. The main highways are US Highway 2, US Highway 83, US Highway 85, US Highway 200, and US Highway 281.

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North Dakota's freight rail service is largely provided by Burlington Northern Santa Fe Railway and Canadian Pacific Railway.

The coal tonnages are located in Mercer County, North Dakota, starting approximately six miles southwest of Beulah, North Dakota. The formations of sedimentary origin were deposited in the Williston Basin, the dominant structural feature of western North Dakota. The center of the basin is located near the city of Williston, North Dakota, approximately 110 miles northwest of the Coyote Creek Mine. The economically mineable coal occurs in the Sentinel Butte Formation, and is overlain by the Coleharbor Formation. The Coleharbor Formation unconformably overlies the Sentinel Butte Formation. It includes all of the unconsolidated sediments resulting from deposition during glacial and interglacial periods. Lithologic types include gravel, sand silt, clay and till. The modified glacial channels are in-filled with gravels, sands, silts and clays overlain by till. The coarser gravel and sand beds are generally limited to near the bottom of the channel fill. The general stratigraphic sequence in the upland portions of the reserve area consists of till, silty sands and clayey silts.

Fill-in drilling programs are routinely conducted by Coyote Creek for the purpose of refining guidance related to ongoing operations. It is common practice at the Coyote Creek Mine to tighten the drilling density within the three to four-year block ahead of active operations to an average drill hole spacing of 660-feet. However, additional exploration may also be scheduled in areas farther out to increase confidence in future mine plan projections.

Operationally, overburden removal is accomplished using scrapers, dozers, front end loaders, excavators, truck fleets, and a dragline. Lignite is mined with front end loaders, and loaded into haul trucks to transport to the coal stockpile.

The mine office facilities and original equipment fleets at the Coyote Creek Mine were constructed, acquired, or purchased during the development stage of the mine. The facilities and equipment are maintained to allow for safe and efficient operation. The equipment is well maintained, in good physical condition and is either updated or replaced periodically with newer models or upgrades available to keep up with modern technology. As equipment wears out, Coyote Creek evaluates what replacement option will be the most cost-efficient, including the evaluation of both new and used equipment.

The total cost of the property, plant and equipment, net of applicable accumulated amortization, depreciation and impairment as of December 31, 2022 is $122.7 million.

The Coyote Creek Mine currently has no significant encumbrances to the property. No NOVs have been issued at the Coyote Creek Mine in the past three years. There are no outstanding permits related to the LOM plan awaiting regulatory approval. Coyote currently has all permits in place for the Coyote Creek Mine to operate and adhere to a mine plan projected through 2040. No mineral processing occurs at the Coyote Creek Mine.

**3.0 Internal Control Disclosure Over Mineral Resources and Reserves** 

The modeling and analysis of the Company's resources and reserves has been developed by Company mine personnel and reviewed by several levels of internal management, including the QPs. The development of such resources and reserves estimates, including related assumptions, was a collaborative effort between the QPs and Company staff. This section summarizes the internal control considerations for the Company's development of estimations, including assumptions, used in resource and reserve analysis and modeling.

When determining resources and reserves, as well as the differences between resources and reserves, management developed specific criteria, each of which must be met to qualify as a resource or reserve, respectively. These criteria, such as demonstration of economic viability, points of reference and grade, are specific and attainable. The QPs and Company management agree on the reasonableness of the criteria for the purposes of estimating resources and reserves. Calculations using these criteria are reviewed and validated by the QPs.

Geological modeling and mine planning efforts serve as a base assumption for resource estimates at MLMC. These outputs have been prepared and reviewed by Company personnel. Mine planning decisions are determined and agreed upon by Company management. Management adjusts forward-looking models by reference to historic mining results, including by reviewing actual versus predicted levels of production from the mineral deposit, and if necessary, re-evaluating mining

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methodologies if production outcomes were not realized as predicted. Ongoing mining of the mineral deposit, coupled with product quality validation pursuant to Company and customer expectations, provides further empirical evidence as to the homogeneity, continuity and characteristics of the deposit. Geologic modeling assumptions are evaluated to historic mining results and are adjusted if necessary to better reflect actual mining results. Ongoing quality validation of production also provides a means to monitor for any potential changes in quality. Also, ongoing monitoring of ground conditions within the mine, surveying for evidence of subsidence and other visible signs of deterioration that may signal the need to re-evaluate rock mechanics and structure of the mine ultimately inform extraction ratios and mine design, which underpin mineral reserve estimates.

Management also assesses risks inherent in mineral resource and reserve estimates, such as the accuracy of geophysical data that is used to support mine planning, changes in QPs, identifying hazards and informing operations of the presence of mineable deposits. Also, management is aware of risks associated with potential gaps in assessing the completeness of mineral extraction licenses, entitlements or rights, or changes in laws or regulations that could directly impact the ability to assess mineral resources and reserves or impact production levels. Risks inherent in overestimated reserves can impact financial performance when revealed, such as changes in amortizations that are based on life of mine estimates.

**4.0 Customer-owned Properties**

**South Hallsville No. 1 Mine — The Sabine Mining Company**

The South Hallsville No. 1 Mine generally produces between 1.5 million and 2.0 million tons of lignite annually. The mine began delivering coal in 1985. All production from the mine is delivered to Southwestern Electric Power Company's ("SWEPCO") Henry W. Pirkey Plant (the "Pirkey Plant"). SWEPCO is an American Electric Power ("AEP") company. The mine's coal tonnages are owned and controlled by AEP. The Company conducts activities to extract these customer-owned and controlled coal tonnages.

The South Hallsville No. 1 Mine, operated by Sabine, is located approximately 150 miles east of Dallas, Texas on FM 968. The entrance to the mine is by means of a paved road. Sabine has no title, claim, lease or option to acquire any of the reserves at the South Hallsville No. 1 Mine. Southwestern Electric Power Company controls all of the reserves within the South Hallsville No. 1 Mine.

AEP intends to retire the Pirkey Plant during 2023. Sabine expects deliveries to cease in March 2023. Sabine expects to begin final reclamation on April 1, 2023. Funding for mine reclamation is the responsibility of SWEPCO.

**5.0 Facilities and Equipment**

The facilities and equipment for each of the coal mines are maintained to allow for safe and efficient operation. The equipment is well maintained, in good physical condition and is either updated or replaced periodically with newer models or upgrades available to keep up with modern technology. As equipment wears out, the mines evaluate what replacement option will be the most cost-efficient, including the evaluation of both new and used equipment, and proceed with that replacement. The mining method and total cost of the property, plant and equipment, net of applicable accumulated amortization, depreciation and impairment as of December 31, 2022 is set forth in the chart below:

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| | | |
|:---|:---|:---|
| **Location** | **Mining Method** | **Total Historical Cost of Mine<br>Property, Plant and Equipment<br>(excluding Coal Land, Real Estate<br>and Construction in Progress), Net of<br>Applicable Accumulated<br>Amortization, Depreciation and Impairment** |
| **Unconsolidated Mining Operations** | | *(in millions)* |
| Freedom Mine — The Coteau Properties Company | Dragline operation with 3 draglines | $90.4 |
| Falkirk Mine — The Falkirk Mining Company | Dragline operation with 4 draglines | $22.4 |
| South Hallsville No. 1 Mine — The Sabine Mining Company | Dragline operation with 4 draglines | $15.0 |
| Coyote Creek Mine — Coyote Creek Mining Company, LLC | Dragline operation with 1 dragline | $122.7 |

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| | | |
|:---|:---|:---|
| **Consolidated Mining Operations** | | |
| Red Hills Mine — Mississippi Lignite Mining Company | Dragline operation with 1 dragline | $80.4 |

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**<u>NAMining Segment - Operations</u>**

NAMining provides contract mining services for independently owned mines and quarries, primarily operating and maintaining draglines at limestone quarries and utilizing other mining equipment at sand and gravel quarries. During 2022, NAMining operated 32 draglines and other equipment at 25 quarries. Of the 32 draglines, 8 are owned by the Company and 24 are owned by customers. At December 31, 2022, NAMining had $42.4 million in property, plant and equipment, net of applicable accumulated amortization, depreciation and impairment.

The mining process at the limestone mines involves excavating limestone from a water-filled quarry utilizing draglines. The excavated limestone is transported and processed by the customer. The following mines were operational during 2022:

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| **Location Name** | **Aggregate** | **Location** | **State** | **Customer** | **Year NACCO Started Operations** |
| White Rock — North | Limestone | Miami | FL | WRQ | 1995 |
| Krome | Limestone | Miami | FL | Cemex | 2003 |
| Alico | Limestone | Ft. Myers | FL | Cemex | 2004 |
| FEC | Limestone | Miami | FL | Cemex | 2005 |
| SCL | Limestone | Miami | FL | Cemex | 2006 |
| Central State Aggregates | Limestone | Zephyrhills | FL | McDonald Group | 2016 |
| Mid Coast Aggregates | Limestone | Sumter County | FL | McDonald Group | 2016 |
| West Florida Aggregates | Limestone | Hernando County | FL | McDonald Group | 2016 |
| St. Catherine | Limestone | Sumter County | FL | Cemex | 2016 |
| Center Hill | Limestone | Sumter County | FL | Cemex | 2016 |
| Inglis | Limestone | Crystal River | FL | Cemex | 2016 |
| Titan Corkscrew | Limestone | Ft. Myers | FL | Titan America | 2017 |
| Palm Beach Aggregates | Limestone | Loxahatchee | FL | Palm Beach Aggregates | 2017 |
| Perry | Limestone | Lamont | FL | Martin Marietta | 2018 |
| SDI Aggregates | Limestone | Florida City | FL | Blue Water Industries | 2018 |
| Queensfield | Sand and gravel | King William County | VA | King William Sand and Gravel Company, Inc. | 2018 |
| Newberry | Limestone | Alachua County | FL | Argos USA, LLC | 2019 |
| Titan Pennsuco <sup>(a)</sup> | Limestone | Miami | FL | Titan America | 2020 |
| Seven Diamonds | Limestone | Pasco County | FL | Seven Diamonds, LLC | 2021 |
| Johnson County | Sand and gravel | Johnson County | IN | Martin Marietta | 2021 |
| Little River | Sand and gravel | Ashdown | AR | Lehigh Hanson | 2021 |
| Rosser | Sand and gravel | Ennis | TX | Lehigh Hanson | 2021 |
| Brooksville Cement Plant | Limestone | Brooksville | FL | Cemex | 2021 |
| Ash Grove | Limestone | Louisville | NE | Ash Grove | 2022 |

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<sup>(a)</sup> The Titan Pennsuco contract was terminated during the second quarter of 2022. NAMining mined de minimis amounts of limestone at this location during the 2022 and 2021 periods.

NAMining's customers control all of the limestone and sand reserves within their respective mines. NAMining has no title, claim, lease or option to acquire any of the reserves at any of the mines where it provides services.

Access to the White Rock mine is by means of a paved road from 122nd Avenue.

Access to the Krome mine is by means of a paved road from Krome Avenue.

Access to the Alico mine is by means of a paved road from Alico Road.

Access to the FEC mine is by means of a paved road from NW 118th Avenue.

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Access to the SCL mine is by means of a paved road from NW 137th Avenue.

Access to the Central State Aggregates mine is by means of a paved road from Yonkers Boulevard.

Access to the Mid Coast Aggregates mine is by means of a paved road from State Road 50.

Access to the West Florida Aggregates mine is by means of a paved road from Cortez Boulevard.

Access to the St. Catherine mine is by means of a paved road from County Road 673.

Access to the Center Hill mine is by means of a paved road from West Kings Highway.

Access to the Inglis mine is by means of a paved road from Highway 19 South.

Access to the Titan Corkscrew mine is by means of a paved road from Corkscrew Road.

Access to the Palm Beach Aggregates mine is by means of a paved road from State Road 80.

Access to the Perry mine is by means of paved road from Nutall Rise Road.

Access to the SDI Aggregates mine is by means of paved road from SW 167<sup>th</sup> AVE.

Access to the Queensfield Mine is by means of paved road from Dabney's Mill Road (SR 604).

Access to the Newberry mine is by means of paved road from NW County Road 235 (CR 235).

Access to the Seven Diamonds mine is by means of a paved road from US-41 S/Broad St.

Access to the Johnson County mine is by means of a paved road from Old State 37/N Waverly Park Road.

Access to the Little River mine is by means of an unpaved road from Little River 60.

Access to the Rosser mine is by means of a paved road from TX-34 S.

Access to Brooksville Cement plant is by means of a paved road from Cement Plant Road.

Access to Ash Grove Louisville Quarry is by means of a paved road from HWY 50.

**<u>Minerals Management - Operations</u>**

As an owner of royalty and mineral interests, the Company's access to information concerning activity and operations of its royalty and mineral interests is limited. The Company does not have information that would be available to a company with oil and natural gas operations because detailed information is not generally available to owners of royalty and mineral interests. Consequently, the exact number of wells producing from or drilling on the Company's mineral interests at a given point in time is not determinable. The following table sets forth the Company's estimate of the number of gross and net productive wells:

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| | | | | |
|:---|:---|:---|:---|:---|
| | **December 31, 2022** | **December 31, 2022** | December 31, 2021 | December 31, 2021 |
| | **Gross** | **Net** | Gross | Net |
| Oil | **1049** | **3.3** | 467 | 0.9 |
| Natural Gas | **251** | **10.1** | 398 | 11.4 |
| Total | **1300** | **13.4** | 865 | 12.3 |

---

Gross wells are the total wells in which an interest is owned.

Net wells are calculated based on the Company's net royalty interest, factoring in both ownership percentage of gross wells and royalty rate.

The majority of the Company's producing mineral and royalty interest acreage now, or in the future, can be pooled with third-party acreage to form pooled units. Pooling proportionately reduces the Company's royalty interest in wells drilled in a pooled unit, and it proportionately increases the number of wells in which the Company has such reduced royalty interest.

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The following table includes the Company's estimate of acreage for oil and gas mineral interests, NPRIs, and ORRIs:

---

| | | | | |
|:---|:---|:---|:---|:---|
| | **December 31, 2022** | **December 31, 2022** | December 31, 2021 | December 31, 2021 |
| | **Gross Acres** | **Net Royalty Acres** | Gross Acres | Net Royalty Acres |
| Appalachia | **34661** | **36199** | 34661 | 36199 |
| Gulf Coast | **27932** | **20105** | 27932 | 20105 |
| Permian | **77278** | **2050** | 63998 | 1243 |
| Rockies | **326** | **72** |  |  |
| Williston | **1194** | **2388** | 1194 | 2388 |
| Total | **141391** | **60814** | 127785 | 59935 |

---

The Company may own more than one type of interest in the same tract of land, but the overlap is not significant. Net Royalty Acres are calculated based on the Company's ownership and royalty rate, normalized to a standard 1/8<sup>th</sup> royalty lease, and assumes a 1/4<sup>th</sup> royalty rate for unleased acres.

The following table includes the Company's estimate of developed and undeveloped acreage based on the gross acres in a basin or region and includes mineral interests, NPRIs, and ORRIs:

---

| | | | | | | |
|:---|:---|:---|:---|:---|:---|:---|
| | **December 31, 2022** | **December 31, 2022** | **December 31, 2022** | December 31, 2021 | December 31, 2021 | December 31, 2021 |
| | **Developed Acreage** | **Undeveloped Acreage** | **Gross Acreage** | Developed Acreage | Undeveloped Acreage | Gross Acreage |
| Appalachia | **32027** | **2634** | **34661** | 28011 | 6650 | 34661 |
| Gulf Coast | **22191** | **5741** | **27932** | 21784 | 6148 | 27932 |
| Permian | **73862** | **3416** | **77278** | 62496 | 1502 | 63998 |
| Rockies | **326** | **—** | **326** | **—** | **—** |  |
| Williston | **—** | **1194** | **1194** | **—** | 1194 | 1194 |
| Total | **128406** | **12985** | **141391** | 112291 | 15494 | 127785 |

---

Undeveloped acres are either unleased and open or are leased acres on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil or natural gas, regardless of whether such acreage contains proved reserves.

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**Production and Price History**

The following table sets forth the estimated oil and natural gas production data related to the Company's mineral and royalty interests as well as certain price and cost information for the years ended December 31:

---

| | | |
|:---|:---|:---|
| | **2022** <sup>(4)</sup> | 2021 <sup>(4)</sup> |
| **Production data:** |  |  |
| Oil (bbl) <sup>(1)</sup> | **46571** | 32627 |
| NGL (bbl) <sup>(1)</sup> | **61511** | 63559 |
| Residue gas (Mcf) <sup>(2)</sup>  | **7329985** | 6225422 |
| Total BOE <sup>(3)</sup> | **1329747** | 1133756 |
| **Average realized prices:** |  |  |
| Oil (bbl) <sup>(1)</sup> | $**94.31** | $66.87 |
| NGL (bbl) <sup>(1)</sup> | $**36.81** | $29.33 |
| Residue gas (Mcf) <sup>(2)</sup>  | $**5.87** | $3.36 |
| **Average unit cost** |  |  |
| BOE <sup>(3)</sup> | $**4.26** | $4.99 |

---

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;<sup>(1)</sup> Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;<sup>(2)</sup> Mcf. One thousand cubic feet of natural gas at the contractual pressure and temperature bases.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;<sup>(3)</sup> BOE. Barrel of Oil Equivalent, a conversion factor of 6 MCF of gas was used for 1 equivalent bbl of oil.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;<sup>(4)</sup> As an owner of mineral and royalty interests, the Company's access to information concerning activity and operations of its royalty and mineral interests is limited. As a result, the Company estimated the last two months of 2022 and 2021 production and pricing data using projections based on decline rates of wells and prior expense information.

**Evaluation and Review of Reserves**

The reserve estimates as of December 31, 2022 were prepared by Haas Petroleum Engineering Services, Inc. ("Haas Engineering"). Haas Engineering has provided reservoir engineering services, consulting and ongoing support for major and independent petroleum companies, public utilities, financial institutions, investors, and government agencies since 1980. Haas Engineering does not own an interest in NACCO or any of the Company's properties, nor is it employed on a contingent basis. A copy of Haas Engineering's estimated proved reserve report as of December 31, 2022 is incorporated by reference herein to Exhibit 99.1 to this Form 10-K.

The properties evaluated for proved reserves are located in Alabama, Louisiana, Ohio, Pennsylvania, Texas and Wyoming and represent all of the Company's oil and gas reserves. A reserves audit is not the same as a financial audit. Reserve engineering is a subjective process of estimating volumes of economically recoverable 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 of engineering and geological interpretation. As a result, the estimates of different engineers often vary. In addition, the results of drilling, testing, and production may justify revisions of such estimates. Accordingly, reserve estimates often differ from the quantities of oil and natural gas that are ultimately recovered. Estimates of economically recoverable oil and natural gas and of future net revenues are based on several variables and assumptions, all of which may vary from actual results, including geologic interpretation, prices, and future production rates and costs.

The reserves estimates have been prepared using standard engineering practices generally accepted by the petroleum industry. Decline curve analysis was used to estimate the remaining reserves of pressure depletion reservoirs with enough historical production data to establish decline trends. Reservoirs under non-pressure depletion drive mechanisms and non-producing reserves were estimated by volumetric analysis, research of analogous reservoirs, or a combination of both. Reserves have been estimated using deterministic and probabilistic methods. The appropriate methodology was used, as deemed necessary, to estimate reserves in conformance with SEC regulations. The maximum remaining reserves life assigned to wells included in this report is 50 years.

Total net proved reserves are defined as those natural gas and hydrocarbon liquid reserves to the Company's interests after deducting all royalties, overriding royalties, and reversionary interests owned by outside parties that become effective upon

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payout of specified monetary balances. All reserves estimates have been prepared using standard engineering practices generally accepted by the petroleum industry and conform to guidelines developed and adopted by the SEC.

**Technologies Used in Reserve Estimation** 

The SEC's reserves rules allow the use of techniques that have been proved effective by actual production from projects in the same reservoir or an analogous reservoir or by other evidence using reliable technology that establishes reasonable certainty. The term "reasonable certainty" implies a high degree of confidence that the quantities of oil, natural gas and/or NGLs actually recovered will equal or exceed the estimate. To achieve reasonable certainty, the Company employed technologies that have been demonstrated to yield results with consistency and repeatability. The technologies and economic data used in the estimation of the Company's proved reserves include, but are not limited to, well logs, geologic maps, seismic data, well test data, production data, historical price and cost information and property ownership interests. The accuracy of the estimates of the Company's reserves is a function of:

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• the quality and quantity of available data and the engineering and geological interpretation of that data;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• estimates regarding the amount and timing of future operating costs, development costs and workovers, all of which may vary considerably from actual results;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• future prices of oil, natural gas and NGLs, which may vary considerably from those estimated; and

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• the judgment of the persons preparing the estimates.

The following table presents the Company's estimated net proved oil and natural gas reserves based on the reserve report prepared by Haas Engineering, the Company's independent petroleum engineering firm. All of the Company's reserves are located in the United States.

---

| | | | | | | |
|:---|:---|:---|:---|:---|:---|:---|
| | **Net reserves as of December 31, 2022** | **Net reserves as of December 31, 2022** | **Net reserves as of December 31, 2022** | Net reserves as of December 31, 2021 | Net reserves as of December 31, 2021 | Net reserves as of December 31, 2021 |
| | **Oil (bbl)** <sup>(1)</sup>  | **NGL (bbl)** <sup>(1)</sup> | **Residue gas (Mcf)** <sup>(2)</sup> | Oil (bbl) <sup>(1)</sup>  | NGL (bbl) <sup>(1)</sup> | Residue gas (Mcf) <sup>(2)</sup> |
| Proved developed | **305710** | **408280** | **25907890** | 167430 | 282230 | 16617360 |
| Proved undeveloped | **32570** | **11030** | **1784670** | 220 | 90 | 1210 |
| Total | **338280** | **419310** | **27692560** | 167650 | 282320 | 16618570 |

---

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;<sup>(1)</sup> Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;<sup>(2)</sup> Mcf. One thousand cubic feet of natural gas at the contractual pressure and temperature bases.

As an owner of mineral and royalty interests and not working interests, the Company is not required to make capital expenditures and did not make capital expenditures to convert proved undeveloped reserves from undeveloped to developed.

**Internal Control Disclosure**

The Company's internal staff works closely with Haas Engineering to ensure the integrity, accuracy and timeliness of the data used to calculate proved reserves relating to NACCO's assets. Internal technical team members met with independent reserve engineers periodically during the period covered by the reserves report to discuss the assumptions and methods used in the proved reserve estimation process.

The preparation of the Company's proved reserve estimates is completed in accordance with internal control procedures. These procedures, which are intended to ensure reliability of reserve estimations, include the following:

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• Review and verification of historical production data, which data is based on actual production as reported by third-party producers who lease the Company's royalty and mineral interests;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• Preparation of reserve estimates by Haas Engineering under the direct supervision of internal staff;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• Verification of property ownership by the Company's land department; and

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• No employee's compensation is tied to the amount of reserves booked.

The Minerals Management Segment's Vice President of Engineering and Finance is the technical person primarily responsible for overseeing the preparation of the internal reserve estimates and for coordinating with Haas Engineering in the preparation of the third-party reserve report. The Vice President of Engineering and Finance has over 15 years of industry experience with positions of increasing responsibility and reports directly to the President of Catapult Mineral Partners, the Company's business unit focused on managing and expanding the Company's portfolio of oil and gas mineral and royalty interests.

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**Estimated Proved Reserves**

The following table summarizes changes in proved reserves during the year ended December 31, 2022:

---

| | | | |
|:---|:---|:---|:---|
| | **Estimated Proved Reserves** | **Estimated Proved Reserves** | **Estimated Proved Reserves** |
| | **Oil (bbl)** <sup>(1)</sup> | **NGL (bbl)** <sup>(1)</sup> | **Residue gas (Mcf)** <sup>(2)</sup> |
| December 31, 2021 | 167650 | 282320 | 16618570 |
| Purchases | 99345 | 35222 | 202314 |
| Extensions and discoveries | 121542 | 68167 | 12801109 |
| Revisions of previous estimates <sup>(3)</sup> | (2504) | 95577 | 5405803 |
| Production | (46571) | (61511) | (7329985) |
| Other | (1182) | (465) | (5251) |
| **December 31, 2022** | **338280** | **419310** | **27692560** |

---

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;<sup>(1)</sup> Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;<sup>(2)</sup> Mcf. One thousand cubic feet of natural gas at the contractual pressure and temperature bases.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;<sup>(3)</sup> Revisions of previous estimates include technical revisions due to changes in commodity prices, historical and projected performance and other factors.

**Estimated Proved Undeveloped Reserves ("PUDs")**

The following table summarizes changes in PUDs during the year ended December 31, 2022:

---

| | | | |
|:---|:---|:---|:---|
| | **Estimated Proved Undeveloped Reserves** | **Estimated Proved Undeveloped Reserves** | **Estimated Proved Undeveloped Reserves** |
| | **Oil (bbl)** <sup>(1)</sup> | **NGL (bbl)** <sup>(1)</sup> | **Residue gas (Mcf)** <sup>(2)</sup> |
| December 31, 2021 | 220 | 90 | 1210 |
| Purchases | 21790 | 5104 | 38571 |
| Extensions and discoveries | 10780 | 5926 | 1746099 |
| Revisions of previous estimates <sup>(3)</sup> | (220) | (90) | (1210) |
| **December 31, 2022** | **32570** | **11030** | **1784670** |

---

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;<sup>(1)</sup> Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;<sup>(2)</sup> Mcf. One thousand cubic feet of natural gas at the contractual pressure and temperature bases.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;<sup>(3)</sup> Revisions of previous estimates include technical revisions due to changes in commodity prices, historical and projected performance and other factors.

As an owner of mineral and royalty interests, the Company generally does not have evidence or approval of operators' development plans. As a result, proved undeveloped reserve estimates are limited to those relatively few locations for which drilling permits have been publicly filed. As of December 31, 2022, PUD reserves consists of 42 wells in various stages of drilling or completions. As of December 31, 2022, approximately 6% of the Company's total proved reserves were classified as PUDs.

**<u>Headquarter locations</u>**

NACCO leases office space in Mayfield Heights, Ohio, a suburb of Cleveland, Ohio, which serves as its corporate headquarters.

Coal Mining and Minerals Management lease corporate headquarters office space in Plano, Texas.

NAMining leases office and warehouse space in Medley, Florida.

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**Item 3. LEGAL PROCEEDINGS**

Neither the Company nor any of its subsidiaries is a party to any material legal proceeding other than ordinary routine litigation incidental to its respective business.

**Item 4. MINE SAFETY DISCLOSURES**

Information concerning mine safety violations or other regulatory matters required by Section 1503(a) of The Dodd-Frank Wall Street Reform and Consumer Protection Act and Item 104 of Regulation S-K is included in Exhibit 95 filed with this Form 10-K.

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**PART II**

**Item 5. MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES**

NACCO's Class A common stock is traded on the New York Stock Exchange under the ticker symbol "NC." Because of transfer restrictions, no trading market has developed, or is expected to develop, for the Company's Class B common stock. The Class B common stock is convertible into Class A common stock on a one-for-one basis.

At December 31, 2022, there were 683 Class A common stockholders of record and 120 Class B common stockholders of record.

**Purchases of Equity Securities by the Issuer and Affiliated Purchasers**

---

| | | | | |
|:---|:---|:---|:---|:---|
| **Issuer Purchases of Equity Securities** <sup>(1)</sup> | **Issuer Purchases of Equity Securities** <sup>(1)</sup> | **Issuer Purchases of Equity Securities** <sup>(1)</sup> | **Issuer Purchases of Equity Securities** <sup>(1)</sup> | **Issuer Purchases of Equity Securities** <sup>(1)</sup> |
| **<u>Period</u>** | **(a)<br>Total Number of Shares Purchased** | **(b)<br>Average Price Paid per Share** | **(c)<br>Total Number of Shares Purchased as Part of the Publicly Announced Program** | **(d)**<br>**Maximum Number of Shares (or Approximate Dollar Value) that May Yet Be Purchased Under the Program** <sup>(1)</sup> |
| October 1 to 31, 2022 |  | $— |  | $22659516 |
| November 1 to 30, 2022 |  | $— |  | $22659516 |
| December 1 to 31, 2022 |  | $— |  | $22659516 |
| &nbsp;&nbsp;&nbsp;&nbsp; Total |  | $— |  | $22659516 |

---

(1)&nbsp;&nbsp;&nbsp;&nbsp;On November 10, 2021, the Company's Board of Directors approved a stock purchase program ("2021 Stock Repurchase Program") providing for the purchase of up to $20.0 million of the Company's outstanding Class A common stock through December 31, 2023. See Note 12 to the Consolidated Financial Statements in this Form 10-K for a discussion of the Company's stock repurchase programs.

**Item 6. [RESERVED]** 

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**Item 7.&nbsp;&nbsp;&nbsp;&nbsp;MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS**

**NACCO INDUSTRIES, INC. AND SUBSIDIARIES**

*(Tabular Amounts in Thousands, Except Per Share and Percentage Data)*

**OVERVIEW**

Management's Discussion and Analysis of Financial Condition and Results of Operations contains forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995. These statements are based upon management's current expectations and are subject to various uncertainties and changes in circumstances. Important factors that could cause actual results to differ materially from those described in these forward-looking statements are set forth below under the heading "Forward-Looking Statements."

Management's Discussion and Analysis of Financial Condition and Results of Operations include NACCO Industries, Inc.<sup>®</sup> ("NACCO" or the "Company"). NACCO brings natural resources to life by delivering aggregates, minerals, reliable fuels and environmental solutions through its robust portfolio of NACCO Natural Resources businesses. The Company operates under three business segments: Coal Mining, North American Mining ("NAMining") and Minerals Management. The Coal Mining segment operates surface coal mines for power generation companies. The NAMining segment is a trusted mining partner for producers of aggregates, activated carbon, lithium and other industrial minerals. The Minerals Management segment, which includes the Catapult Mineral Partners ("Catapult") business, acquires and promotes the development of mineral interests. Mitigation Resources of North America<sup>®</sup> ("Mitigation Resources") provides stream and wetland mitigation solutions.

The Company has items not directly attributable to a reportable segment that are not included as part of the measurement of segment operating profit, which primarily includes administrative costs related to public company reporting requirements at the parent company and the financial results of Mitigation Resources and Bellaire Corporation ("Bellaire"). Bellaire manages the Company's long-term liabilities related to former Eastern U.S. underground mining activities.

Effective January 1, 2022, the Company changed the composition of its reportable segments. As a result, the Company

retrospectively changed its computation of segment operating profit to reclassify the results of Caddo Creek Resources

Company, LLC ("Caddo Creek") and Demery Resources Company, LLC ("Demery") from the Coal Mining segment into the

NAMining segment as these operations provide mining solutions for producers of industrial minerals, rather than for power

generation. The Coal Mining segment now includes only mines that deliver coal to power generation companies. This segment

reporting change has no impact on consolidated operating results. All prior period segment information has been reclassified to

conform to the new presentation.

All financial statement line items below operating profit (other income, including interest expense and interest income, the provision for income taxes and net income) are presented and discussed within this Form 10-K on a consolidated basis.

See "Item 1. Business" beginning on page 1 in this Form 10-K for further discussion of NACCO's subsidiaries. Additional information relating to financial and operating data on a segment basis (including unallocated items) is set forth in Note 15 to the Consolidated Financial Statements contained in this Form 10-K.

**CRITICAL ACCOUNTING POLICIES AND ESTIMATES**

The Company's discussion and analysis of its financial condition and results of operations are based upon the Company's consolidated financial statements, which have been prepared in accordance with U.S. generally accepted accounting principles. The preparation of these financial statements requires the Company to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosure of contingent assets and liabilities (if any). On an ongoing basis, the Company evaluates its estimates based on historical experience, actuarial valuations and various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from those estimates.

The Company believes the following critical accounting policies affect its more significant judgments and estimates used in the preparation of its consolidated financial statements.

**Revenue recognition:** Revenues are recognized when control of the promised goods or services is transferred to the Company's customers, in an amount that reflects the consideration the Company expects to be entitled to in exchange for those goods or services. The Company accounts for revenue in accordance with Accounting Standards Codification ("ASC") Topic 606, "Revenue from Contracts with Customers." See Note 3 to the Consolidated Financial Statements in this Form 10-K for further discussion of the Company's revenue recognition.

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**Item 7.&nbsp;&nbsp;&nbsp;&nbsp;MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS**

**NACCO INDUSTRIES, INC. AND SUBSIDIARIES**

*(Tabular Amounts in Thousands, Except Per Share and Percentage Data)*

**Long-lived assets:** The Company periodically evaluates long-lived assets for impairment when changes in circumstances or the occurrence of certain events indicate the carrying amount of an asset may not be recoverable. Upon identification of indicators of impairment, the Company evaluates the carrying value of the asset by comparing the estimated future undiscounted cash flows generated from the use of the asset and its eventual disposition with the asset's net carrying value. If the carrying value of an asset is considered impaired, an impairment charge is recorded for the amount that the carrying value of the long-lived asset exceeds its fair value. Fair value is estimated 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.

The Company regularly performs reviews of potential future development projects and identified certain legacy coal assets

where future development is unlikely. The long-lived assets, which included land, prepaid royalties and capitalized leasehold

costs, were written off in 2022 and resulted in non-cash asset impairment charges of $3.9 million. See Note 9 to the Consolidated Financial Statements in this Form 10-K for further discussion of the Company's fair value measurements.

At MLMC, the costs of mining operations are not reimbursed by MLMC's customer. As such, increased costs at MLMC or decreased revenues could materially reduce the Company's profitability. Any reduction in customer demand at MLMC, including reductions related to reduced mechanical availability of the customer's power plant, would adversely affect the Company's operating results and could result in significant impairments. MLMC has approximately $125 million of long-lived assets, including property, plant and equipment and its coal supply agreement intangible asset, which are subject to periodic impairment analysis and review. Identifying and assessing whether impairment indicators exist, or if events or changes in circumstances have occurred, including assumptions about future power plant dispatch levels, changes in operating costs and other factors that impact anticipated revenue and customer demand, requires significant judgment. Actual future operating results could differ significantly from these estimates, which may result in an impairment charge in a future period, which could have a substantial impact on the Company's results of operations.

**Income taxes:** The Company files income tax returns in the U.S. federal jurisdiction, and in various state and foreign jurisdictions. Tax law requires certain items to be included in the tax return at different times than the items are reflected in the financial statements. Some of these differences are permanent, such as expenses that are not deductible for tax purposes, and some differences are temporary, reversing over time, such as depreciation expense. These temporary differences create deferred tax assets and liabilities using currently enacted tax rates. The objective of accounting for income taxes is to recognize the amount of taxes payable or refundable for the current year, and deferred tax liabilities and assets for the future tax consequences of events that have been recognized in the financial statements or tax returns. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in the provision for income taxes in the period that includes the enactment date. Management is required to estimate the timing of the recognition of deferred tax assets and liabilities, make assumptions about the future deductibility of deferred tax assets and assess deferred tax liabilities based on enacted laws and tax rates for the appropriate tax jurisdictions to determine the amount of such deferred tax assets and liabilities. Changes in the calculated deferred tax assets and liabilities may occur in certain circumstances, including statutory income tax rate changes, statutory tax law changes, or changes in the structure or tax status.

The Company's tax assets, liabilities, and tax expense are supported by historical earnings and losses and the Company's best estimates and assumptions of future earnings. The Company assesses whether a valuation allowance should be established against its deferred tax assets based on consideration of all available evidence, both positive and negative, using a more likely than not standard. This assessment considers, among other matters, scheduled reversals of deferred tax liabilities, projected future taxable income, tax-planning strategies, and results of recent operations. The assumptions about future taxable income require significant judgment and are consistent with the plans and estimates the Company is using to manage the underlying businesses. When the Company determines, based on all available evidence, that it is more likely than not that deferred tax assets will not be realized, a valuation allowance is established.

Since significant judgment is required to assess the future tax consequences of events that have been recognized in the Company's financial statements or tax returns, the ultimate resolution of these events could result in adjustments to the Company's financial statements and such adjustments could be material. The Company believes the current assumptions, judgments and other considerations used to estimate the current year accrued and deferred tax positions are appropriate. If the actual outcome of future tax consequences differs from these estimates and assumptions, due to changes or future events, the resulting change to the provision for income taxes could have a material impact on the Company's results of operations and financial position. Since 2021, the Company has participated in a voluntary program with the IRS called Compliance Assurance Process ("CAP"). The objective of CAP is to contemporaneously work with the IRS to achieve federal tax compliance and resolve all or most issues prior to the filing of the tax return.

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**Item 7.&nbsp;&nbsp;&nbsp;&nbsp;MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS**

**NACCO INDUSTRIES, INC. AND SUBSIDIARIES**

*(Tabular Amounts in Thousands, Except Per Share and Percentage Data)*

See Note 13 to the Consolidated Financial Statements in this Form 10-K for further discussion of the Company's income taxes.

**CONSOLIDATED FINANCIAL SUMMARY**

The results of operations for NACCO were as follows for the years ended December 31:

---

| | | |
|:---|:---|:---|
| | **2022** | 2021 |
| Revenues: |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Coal Mining | $**95204** | $82831 |
| &nbsp;&nbsp;&nbsp;&nbsp;NAMining | **85664** | 78944 |
| &nbsp;&nbsp;&nbsp;&nbsp;Minerals Management | **60242** | 31003 |
| &nbsp;&nbsp;&nbsp;&nbsp;Unallocated Items | **2952** | 4695 |
| &nbsp;&nbsp;&nbsp;&nbsp;Eliminations | **(2343)** | (5627) |
| Total revenue | $**241719** | $191846 |
| Operating profit (loss): |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Coal Mining | $**38309** | $45784 |
| &nbsp;&nbsp;&nbsp;&nbsp;NAMining | **2202** | 3384 |
| &nbsp;&nbsp;&nbsp;&nbsp;Minerals Management | **52214** | 26080 |
| &nbsp;&nbsp;&nbsp;&nbsp;Unallocated Items | **(23233)** | (19553) |
| &nbsp;&nbsp;&nbsp;&nbsp;Eliminations | **494** | (285) |
| Total operating profit | $**69986** | $55410 |
| &nbsp;&nbsp;&nbsp;&nbsp;Interest expense | **2034** | 1719 |
| &nbsp;&nbsp;&nbsp;&nbsp;Interest income | **(1449)** | (449) |
| &nbsp;&nbsp;&nbsp;&nbsp;Closed mine obligations | **1179** | 1297 |
| &nbsp;&nbsp;&nbsp;&nbsp;Loss (gain) on equity securities | **283** | (3423) |
| &nbsp;&nbsp;&nbsp;&nbsp;Income from equity method investee | **(2194)** |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Other contract termination settlements | **(16882)** |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Other, net | **(708)** | (584) |
| Other income, net | **(17737)** | (1440) |
| Income before income tax provision | **87723** | 56850 |
| Income tax provision | **13565** | 8725 |
| Net income | $**74158** | $48125 |
| Effective income tax rate | **15.5%** | 15.3% |

---

The components of the change in revenues and operating profit are discussed below in "Segment Results."

**Other income, net**

During the second quarter of 2022, GRE transferred ownership of an office building with an estimated fair value of $4.1 million and conveyed membership units in Midwest AgEnergy Group, LLC ("MAG"), a North Dakota-based ethanol business, with an estimated fair value of $12.8 million, as agreed to under the termination and release of claims agreement between Falkirk and GRE. As a result, the Company recognized $16.9 million on the "Other contract termination settlements" line within the accompanying Consolidated Statements of Operations.

Prior to receiving the membership units from GRE, the Company held a $5.0 million investment in MAG. Subsequent to the receipt of the additional membership units, the Company began to account for the investment under the equity method of

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**Item 7.&nbsp;&nbsp;&nbsp;&nbsp;MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS**

**NACCO INDUSTRIES, INC. AND SUBSIDIARIES**

*(Tabular Amounts in Thousands, Except Per Share and Percentage Data)*

accounting. During the third quarter of 2022, the Company recorded $2.2 million, which represented its share of MAG's earnings on the "Income from equity method investee" line within the accompanying Consolidated Statements of Operations.

On December 1, 2022, HLCP Ethanol Holdco, LLC ("HLCP") completed its acquisition of MAG. Upon closing of the transaction, NACCO transferred its ownership interest in MAG to HLCP and received a cash payment of $18.6 million and recognized a $1.3 million loss during the fourth quarter of 2022 on the line "Other, net" within the accompanying Consolidated Statements of Operations.

Interest income increased $1.0 million primarily due to higher interest rates and a higher average invested cash balance during 2022 compared with 2021.

Loss (gain) on equity securities represents changes in the market price of invested assets reported at fair value. The change

during 2022 compared with 2021 was due to fluctuations in the market prices of the exchange-traded equity securities. See Note 9 to the Consolidated Financial Statements in this Form 10-K for further discussion of the Company's invested assets reported at fair value.

**Income Taxes**

Income tax expense of $13.6 million for the year ended December 31, 2022 includes $1.5 million of discrete tax benefits, primarily from the reversal of uncertain tax positions as a result of the conclusion of the IRS examination of the Company's 2013, 2014, 2015 and 2016 federal income tax returns. Excluding the $1.5 million of discrete tax benefits, the effective income tax rate in 2022 was 17.1%.

Income tax expense of $8.7 million for the year ended December 31, 2021 included $1.0 million of discrete tax expense. Excluding the $1.0 million of discrete tax expense, the effective income tax rate in 2021 was 13.5%.

The increase in the effective income tax rate for 2022 compared to 2021, excluding the impact of discrete items, is primarily due to an increase in earnings at entities that do not qualify for percentage depletion. The benefit from percentage depletion is not directly related to the amount of pre-tax income recorded in a period.

See Note 13 to the Consolidated Financial Statements in this Form 10-K for further discussion of the Company's income taxes.

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**Item 7.&nbsp;&nbsp;&nbsp;&nbsp;MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS**

**NACCO INDUSTRIES, INC. AND SUBSIDIARIES**

*(Tabular Amounts in Thousands, Except Per Share and Percentage Data)*

**LIQUIDITY AND CAPITAL RESOURCES**

**Cash Flows**

The following tables detail the change in cash flow for the years ended December 31:

---

| | | | |
|:---|:---|:---|:---|
| | **2022** | 2021 | Change |
| **Operating activities:** |  |  |  |
| Net income | $**74158** | $48125 | $26033 |
| Depreciation, depletion and amortization | **26816** | 23085 | 3731 |
| Deferred income taxes | **(8471)** | (3553) | (4918) |
| Stock-based compensation | **7541** | 5561 | 1980 |
| Gain on sale of assets | **(2463)** | (60) | (2403) |
| Other contract termination settlements | **(15552)** |  | (15552) |
| Asset impairment charges | **3939** |  | 3939 |
| Other | **(345)** | 1973 | (2318) |
| Working capital changes | **(17888)** | (256) | (17632) |
| **Net cash provided by operating activities** | **67735** | 74875 | (7140) |
| **Investing activities:** |  |  |  |
| Expenditures for property, plant and equipment and acquisition of mineral interests | **(54447)** | (44561) | (9886) |
| Proceeds from the sale of assets | **2837** | 633 | 2204 |
| Proceeds from the sale of private company equity units | **18628** |  | 18628 |
| Other | **(170)** | (219) | 49 |
| **Net cash used for investing activities** | **(33152)** | (44147) | 10995 |
| **Cash flow before financing activities** | $**34583** | $30728 | $3855 |

---

The $7.1 million decrease in net cash provided by operating activities was primarily due to a decrease in cash provided by working capital partially offset by an increase in cash provided by net income adjusted for non-cash items. The $17.6 million decrease in net cash provided by working capital was primarily due to a decrease in accounts payable during 2022 compared with an increase in accounts payable during 2021 due to timing of purchases and payments. The Company's non-cash items primarily include Depreciation, depletion and amortization, Deferred income taxes, Stock-based compensation, Gain on sale of assets, Other contract termination settlements and Asset impairment charges.

---

| | | | |
|:---|:---|:---|:---|
| | **2022** | 2021 | Change |
| **Financing activities:** |  |  |  |
| Net reductions to long-term debt and revolving credit agreements | $**(3828)** | $(25801) | $21973 |
| Cash dividends paid | **(6012)** | (5617) | (395) |
| Other | **—** | (1755) | 1755 |
| **Net cash used for financing activities** | $**(9840)** | $(33173) | $23333 |

---

The change in net cash used for financing activities was primarily due to fewer repayments as a result of a reduction in borrowings under the Company's revolving line of credit during 2022 compared with 2021.

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**Item 7.&nbsp;&nbsp;&nbsp;&nbsp;MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS**

**NACCO INDUSTRIES, INC. AND SUBSIDIARIES**

*(Tabular Amounts in Thousands, Except Per Share and Percentage Data)*

**Financing Activities**

Financing arrangements are obtained and maintained at the subsidiary level. NACoal has a secured revolving line of credit of up to $150.0 million (the "NACoal Facility") that expires in November 2025. There were no borrowings outstanding under the NACoal Facility at December 31, 2022. At December 31, 2022, the excess availability under the NACoal Facility was $116.3 million, which reflects a reduction for outstanding letters of credit of $33.7 million.

NACCO has not guaranteed any borrowings of NACoal. The NACoal Facility allows for the payment to NACCO of dividends and advances under certain circumstances. Dividends (to the extent permitted by the NACoal Facility) and management fees are the primary sources of cash for NACCO and enable the Company to pay dividends to stockholders.

The NACoal Facility has performance-based pricing, which sets interest rates based upon NACoal achieving various levels of debt to EBITDA ratios, as defined in the NACoal Facility. Borrowings bear interest at a floating rate plus a margin based on the level of debt to EBITDA ratio achieved. The applicable margins, effective December 31, 2022, for base rate and LIBOR loans were 1.23% and 2.23%, respectively. The NACoal Facility has a commitment fee which is based upon achieving various levels of debt to EBITDA ratios. The commitment fee was 0.34% on the unused commitment at December 31, 2022. During the year ended December 31, 2022, the average borrowing under the NACoal Facility was $2.0 million. The weighted-average annual interest rate, including the floating rate margin, was 2.54% and 4.50% at December 31, 2022 and December 31, 2021, respectively.

The NACoal Facility contains restrictive covenants, which require, among other things, NACoal to maintain a maximum net debt to EBITDA ratio of 2.75 to 1.00 and an interest coverage ratio of not less than 4.00 to 1.00. The NACoal Facility provides the ability to make loans, dividends and advances to NACCO, with some restrictions based on maintaining a maximum debt to

EBITDA ratio of 1.50 to 1.00, or if greater than 1.50 to 1.00, a Fixed Charge Coverage Ratio of 1.10 to 1.00, in conjunction with maintaining unused availability thresholds of borrowing capacity, as defined in the NACoal Facility, of $15.0 million. At December 31, 2022, NACoal was in compliance with all financial covenants in the NACoal Facility.

The obligations under the NACoal Facility are guaranteed by certain of NACoal's direct and indirect, existing and future

domestic subsidiaries, and is secured by certain assets of NACoal and the guarantors, subject to customary exceptions and

limitations.

The Company believes funds available from cash on hand, the NACoal Facility and operating cash flows will provide sufficient liquidity to meet its operating needs and commitments arising during the next twelve months and until the expiration of the NACoal Facility in November 2025.

See Note 8 and Note 10 to the Consolidated Financial Statements in this Form 10-K for further information on the Company's other financing arrangements and leases, respectively.

**Expenditures for property, plant and equipment and mineral interests**

Following is a table which summarizes actual and planned expenditures (in millions):

---

| | | | |
|:---|:---|:---|:---|
| | **Planned**<br>**2023** | **Actual**<br>**2022** | **Actual**<br>**2021** |
| NACCO | $71.5 | $**54.4** | $44.6 |

---

Planned expenditures for 2023 are expected to be approximately $39 million in the NAMining segment, $21 million in the Minerals Management segment, $10 million in the Coal Mining segment and $1 million at Mitigation Resources.

In the NAMining segment, 2023 capital expenditures are primarily related to the acquisition of equipment to be used at the Thacker Pass lithium project. Sawtooth is the contract miner for the Thacker Pass project. Under the terms of the contract mining agreement, the customer will reimburse Sawtooth for these capital expenditures over a five-year period from the equipment acquisition date.

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**Item 7.&nbsp;&nbsp;&nbsp;&nbsp;MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS**

**NACCO INDUSTRIES, INC. AND SUBSIDIARIES**

*(Tabular Amounts in Thousands, Except Per Share and Percentage Data)*

Expenditures are expected to be funded from internally generated funds and/or bank borrowings.

**Capital Structure**

NACCO's consolidated capital structure is presented below:

---

| | | | |
|:---|:---|:---|:---|
| | December 31 | December 31 | |
| | **2022** | 2021 |<br>Change |
| Cash and cash equivalents | $**110748** | $86005 | $24743 |
| Other net tangible assets  | **329045** | 276733 | 52312 |
| Intangible assets, net | **28055** | 31774 | (3719) |
| &nbsp;&nbsp;&nbsp;Net assets | **467848** | 394512 | 73336 |
| Total debt | **(19668)** | (20710) | 1042 |
| Closed mine obligations | **(21214)** | (21686) | 472 |
| Total equity | $**426966** | $352116 | $74850 |
| Debt to total capitalization | **4%** | 6% | (2)% |

---

The $52.3 million increase in other net tangible assets was primarily due to an increase in Property, plant and equipment including mineral interests and investments at Mitigation Resources, an increase in Inventories and an increase in Trade accounts receivable at December 31, 2022 compared with December 31, 2021. Inventories increased in the Coal Mining segment as MLMC is developing a new mine area and building inventory and in the NAMining segment due to an increase in supplies inventory. Trade accounts receivable increased due to higher customer requirements at MLMC.

**Contractual Obligations, Contingent Liabilities and Commitments**

Pension and postretirement funding can vary significantly each year due to plan amendments, changes in the market value of plan assets, legislation and the Company's decisions to contribute above the minimum regulatory funding requirements. The Company does not expect to contribute to its pension plan in 2023. NACCO maintains one supplemental retirement plan that pays monthly benefits to participants directly out of corporate funds and expects to pay benefits of approximately $0.4 million per year from 2023 through 2032. Benefit payments beyond that time cannot currently be estimated. NACCO also expects to make payments related to its other postretirement plans of approximately $0.2 million per year from 2023 through 2032. Benefit payments beyond that time cannot currently be estimated. All other pension benefit payments are made from assets of the pension plan.

NACCO has asset retirement obligations. See Note 7 to the Consolidated Financial Statements in this Form 10-K for further discussion of the Company's asset retirement obligations.

NACCO has unrecognized tax benefits, including interest and penalties. See Note 13 to the Consolidated Financial Statements in this Form 10-K for further discussion of the Company's income taxes.

NACoal is a party to certain guarantees related to Coyote Creek. The Company believes that the likelihood of NACoal's future performance under the guarantees is remote, and no amounts related to these guarantees have been recorded. See Note 16 to the Consolidated Financial Statements in this Form 10-K for further discussion of the Company's guarantees.

The Company utilizes letters of credit to support commitments made in the ordinary course of business. As of December 31, 2022 and 2021, outstanding letters of credit totaled $33.7 million and $29.8 million, respectively.

**ENVIRONMENTAL MATTERS**

The Company is affected by the regulations of numerous agencies, particularly the Federal Office of Surface Mining, the U.S. Environmental Protection Agency, the U.S. Army Corps of Engineers and associated state regulatory authorities. In addition, the Company closely monitors proposed legislation and regulation concerning SMCRA, CAA, ACE, CWA, RCRA, CERCLA and other regulatory actions.

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**Item 7.&nbsp;&nbsp;&nbsp;&nbsp;MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS**

**NACCO INDUSTRIES, INC. AND SUBSIDIARIES**

*(Tabular Amounts in Thousands, Except Per Share and Percentage Data)*

Compliance with these increasingly stringent regulations could result in higher expenditures for both capital improvements and operating costs. The Company's policies stress environmental responsibility and compliance with these regulations. Based on current information, management does not expect compliance with these regulations to have a material adverse effect on the Company's financial condition or results of operations. See Item 1 in Part I of this Form 10-K for further discussion of these matters.

Certain states have enacted, and others are considering enacting, mandatory clean energy standards requiring utilities to meet certain thresholds of renewable and/or carbon-free energy supply. The current presidential administration has made climate change a focus, including consideration for legislation on clean energy standards and GHG emission, and the Company expects that to continue. The Company believes the move to require utilities to generate a greater portion of energy from renewable energy sources could create imbalances in the existing electric grid if fossil-fuel power plants are retired faster than renewable sources are developed resulting in electrical grid disruptions and outages. The Company will continue to monitor the progress of these initiatives and assess the potential impacts they may have on its financial condition, results of operations and disclosures.

**SEGMENT RESULTS**

**COAL MINING SEGMENT**

**FINANCIAL REVIEW**

See "Item 2. Properties" on page 28 in this Form 10-K for discussion of the Company's mineral resources and mineral reserves.

Tons of coal delivered by the Coal Mining segment were as follows for the years ended December 31:

---

| | | |
|:---|:---|:---|
| | **2022** | 2021 |
| Unconsolidated mines | **25236** | 27759 |
| Consolidated mines | **3215** | 3025 |
| Total tons delivered | **28451** | 30784 |

---

The results of operations for the Coal Mining segment were as follows for the years ended December 31:

---

| | | |
|:---|:---|:---|
| | **2022** | 2021 |
| Revenues | $**95204** | $82831 |
| Cost of sales | **89670** | 72596 |
| Gross profit | **5534** | 10235 |
| Earnings of unconsolidated operations<sup>(a)</sup> | **52535** | 56089 |
| Contract termination settlement | **14000** | 10333 |
| Selling, general and administrative expenses | **30049** | 27363 |
| Amortization of intangible assets | **3719** | 3556 |
| Gain on sale of assets | **(8)** | (46) |
| Operating profit | $**38309** | $45784 |

---

<sup>(a)</sup> See Note 16 to the Consolidated Financial Statements in this Form 10-K for a discussion of the Company's unconsolidated subsidiaries, including summarized financial information.

**2022 Compared with 2021** 

Revenues increased 14.9% in 2022 compared with 2021 primarily due to a higher per ton sales price and an increase in customer requirements at MLMC.

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**Item 7.&nbsp;&nbsp;&nbsp;&nbsp;MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS**

**NACCO INDUSTRIES, INC. AND SUBSIDIARIES**

*(Tabular Amounts in Thousands, Except Per Share and Percentage Data)*

The following table identifies the components of change in operating profit for 2022 compared with 2021:

---

| | |
|:---|:---|
| | Operating Profit |
| 2021 | $45784 |
| Increase (decrease) from: |  |
| Gross profit | (4701) |
| Earnings of unconsolidated operations | (3554) |
| Selling, general and administrative expenses | (2686) |
| Amortization of intangibles | (163) |
| Net change on sale of assets | (38) |
| Contract termination settlements in 2022 and 2021, net | 3667 |
| **2022** | $**38309** |

---

Operating profit decreased $7.5 million in 2022 compared with 2021. The change in operating profit was primarily due to a decrease in gross profit, a decrease in the earnings of unconsolidated operations and an increase in selling, general and administrative expenses.

The decrease in gross profit was primarily due to an increase in the cost per ton delivered at MLMC, due in part to an increase

in the cost of diesel fuel.

The decrease in earnings of unconsolidated operations was primarily due to a reduction in the per ton management fee at Falkirk as well as a reduction in earnings as a result of the Bisti contract termination as of September 30, 2021. These decreases were partially offset by a contractual price escalation and an increase in customer requirements at Coteau.

The increase in selling, general and administrative expenses was primarily due to higher employee-related costs and

professional service expenses.

The decreases in operating profit were partially offset by an increase in contract termination settlements. The $14.0 million

contract termination settlement from GRE was recognized during 2022. The $10.3 million payment related to the Bisti contract termination was recognized during 2021.

**NORTH AMERICAN MINING ("NAMining") SEGMENT**

**FINANCIAL REVIEW**

Aggregate tons delivered by the NAMining segment were as follows for the years ended December 31:

---

| | | |
|:---|:---|:---|
| | **2022** | 2021 |
| Total tons delivered | **54223** | 52796 |

---

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**Item 7.&nbsp;&nbsp;&nbsp;&nbsp;MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS**

**NACCO INDUSTRIES, INC. AND SUBSIDIARIES**

*(Tabular Amounts in Thousands, Except Per Share and Percentage Data)*

The results of operations for the NAMining segment were as follows for the years ended December 31:

---

| | | |
|:---|:---|:---|
| | **2022** | 2021 |
| Total revenues | $**85664** | $78944 |
| Reimbursable costs | **52935** | 51028 |
| Revenues excluding reimbursable costs | $**32729** | $27916 |
| Revenues | $**85664** | $78944 |
| Cost of sales | **79842** | 73649 |
| Gross profit | **5822** | 5295 |
| Earnings of unconsolidated operations<sup>(a)</sup> | **4715** | 4754 |
| Selling, general and administrative expenses | **8260** | 6610 |
| Loss on sale of assets | **75** | 55 |
| Operating profit | $**2202** | $3384 |

---

<sup>(a)</sup> See Note 16 to the Consolidated Financial Statements in this Form 10-K for a discussion of the Company's unconsolidated subsidiaries, including summarized financial information.

**2022 Compared with 2021** 

Total revenues increased 8.5% in 2022 compared with 2021 primarily due to an increase in customer requirements as well as reimbursable costs, which have an offsetting amount in cost of sales and have no impact on operating profit. These improvements were partially offset by a reduction in revenue at Caddo Creek as the scope of final reclamation activities declined.

The following table identifies the components of change in operating profit for 2022 compared with 2021.

---

| | |
|:---|:---|
| | Operating Profit |
| 2021 | $3384 |
| Increase (decrease) from: |  |
| Selling, general and administrative expenses | (1413) |
| Voluntary retirement program charge | (769) |
| Earnings of unconsolidated operations | (39) |
| Net change on sale of assets | (20) |
| Gross profit | 1059 |
| **2022** | $**2202** |

---

Operating profit decreased $1.2 million in 2022 compared with 2021 primarily due to an increase in selling, general and administrative expenses and a voluntary retirement program charge, partially offset by an increase in gross profit.

During 2022, the Company implemented a voluntary retirement program for employees who met certain age and service requirements to reduce overall headcount. As a result of this program, operating profit in 2022 includes a charge of $0.8 million related to one-time termination benefits. The increase in selling, general and administrative expenses was primarily due to higher employee-related costs.

The increase in gross profit was primarily attributable to water sales at Caddo Creek as well as an increase in earnings at Sawtooth Mining for the Thacker Pass lithium project, partially offset by a decrease in gross profit from the active operations mainly due to an increase in employee-related costs.

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**Item 7.&nbsp;&nbsp;&nbsp;&nbsp;MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS**

**NACCO INDUSTRIES, INC. AND SUBSIDIARIES**

*(Tabular Amounts in Thousands, Except Per Share and Percentage Data)*

**MINERALS MANAGEMENT SEGMENT**

**FINANCIAL REVIEW**

The results of operations for the Minerals Management segment were as follows for the years ended December 31:

---

| | | |
|:---|:---|:---|
| | **2022** | 2021 |
| Revenues | $**60242** | $31003 |
| Cost of sales | **3935** | 2988 |
| Gross profit | **56307** | 28015 |
| Selling, general and administrative expenses and asset impairment charges | **6623** | 2004 |
| Gain on sale of assets | **(2530)** | (69) |
| Operating profit | $**52214** | $26080 |

---

During 2022, the oil and natural gas industry experienced continued improvement in commodity prices compared with 2021, primarily due to:

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• Higher demand as the impact from COVID-19 abates;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• Changes in domestic supply and demand dynamics as well as increased discipline around production and capital investments by oil and gas companies; and

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• Instability and constraints on global supply, particularly with respect to instability in Russia and Ukraine.

Oil and natural gas prices have been historically volatile and may continue to be volatile in the future. The table below demonstrates such volatility with the average price as reported by the United States Energy Information Administration for the twelve months ended December 31:

---

| | | |
|:---|:---|:---|
| | **2022** | 2021 |
| West Texas Intermediate Average Crude Oil Price | $**94.79** | $67.99 |
| Henry Hub Average Natural Gas Price | $**6.42** | $3.91 |

---

Revenues and operating profit increased in 2022 compared with 2021 primarily due to substantially higher natural gas and oil prices, increased production due in part to income generated from newly developed wells on Company leases during 2022, as well as $2.1 million of settlement income recognized during 2022. The settlement relates to the Company's ownership interest in certain mineral rights. In addition, operating profit includes a $2.4 million gain on the sale of land related to legacy operations during 2022.

The Company regularly performs reviews of potential future development projects and identified certain legacy coal assets

where future development is unlikely. The long-lived assets, which included land, prepaid royalties and capitalized leasehold

costs, were written off during 2022 and resulted in non-cash asset impairment charges of $3.9 million.

**UNALLOCATED ITEMS AND ELIMINATIONS**

**FINANCIAL REVIEW**

Unallocated Items and Eliminations were as follows for the years ended December 31:

---

| | | |
|:---|:---|:---|
| | **2022** | 2021 |
| Operating loss | $**(22739)** | $(19838) |

---

**2022 Compared with 2021**

The operating loss increased during 2022 compared with 2021 primarily due to higher employee-related costs.

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**Item 7.&nbsp;&nbsp;&nbsp;&nbsp;MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS**

**NACCO INDUSTRIES, INC. AND SUBSIDIARIES**

*(Tabular Amounts in Thousands, Except Per Share and Percentage Data)*

**<u>NACCO Industries, Inc. Outlook</u>**

**<u>Coal Mining Outlook</u>**

In 2023, the Company expects coal deliveries to decrease from 2022 levels. The owner of the power plant served by the Company's Sabine Mine in Texas plans to retire the Pirkey power plant in 2023. The cessation of Sabine deliveries starting effective April 1, 2023 is the primary driver for the year-over-year decline in deliveries.

Coal Mining operating profit and Segment Adjusted EBITDA for the 2023 full year are expected to decrease significantly year-over-year, including and excluding the $14.0 million GRE termination payment received in 2022. The decline is primarily the result of an expected significant reduction in earnings at the consolidated operations, an anticipated moderate decrease in earnings of unconsolidated operations and higher operating expenses due to an increase in insurance and outside services expenses.

Results at the consolidated mining operations are projected to decrease significantly in 2023 versus 2022. The decrease is mainly due to an expected substantial decline in earnings at MLMC driven by a reduction in the profit per ton of coal delivered, due in part to increased costs associated with establishing operations in a new mine area, as well as higher depreciation expense related to recent capital expenditures to develop a new mine area. In 2023, capital expenditures are expected to be approximately $10 million, primarily for mine development and equipment replacement. MLMC sells lignite at contractually agreed upon prices which are subject to changes in the level of established indices generally reflecting inflation over time. The increase in production costs will not be offset by an immediate increase in the revenue generated from contractual price escalation as there is a lag in the timing of the effect of inflation on the index-based coal sales price. In addition, certain costs can be passed through to the customer in the year following expense recognition.

The anticipated lower earnings at the unconsolidated coal mining operations is expected to be driven primarily by temporary price concessions at Falkirk effective May 2022 through May 2024. This will result in a reduction in the per ton management fee for 12 months in 2023 compared with eight months in 2022. The planned retirement of the Pirkey power plant and commencement of final reclamation of the Sabine Mine starting on April 1, 2023 will also contribute to the reduction in earnings. Sabine will receive compensation for providing final mine reclamation services, but at a lower rate than during active mining. Funding for Sabine's mine reclamation is the responsibility of the customer. These decreases are expected to be partly offset by higher earnings at Coteau.

The Company's contract structure at each of its coal mining operations eliminates exposure to spot coal market price fluctuations. However, fluctuations in natural gas prices and the availability of renewable power generation, particularly wind, can contribute to changes in power plant dispatch and customer demand for coal. Changes to customer power plant dispatch would affect the Company's outlook for 2023, as well as over the longer term.

**<u>NAMining Outlook</u>**

Full-year 2023 operating profit at NAMining is expected to decrease significantly primarily because final mine reclamation activities at Caddo Creek were substantially completed in 2022. Segment Adjusted EBITDA, however, is expected to increase over 2022 because of a significant unfavorable impact on operating profit from higher depreciation expense.

NAMining's 2022 financial results did not meet expectations. A number of initiatives are underway or in planning stages that are expected to support improved future financial results at NAMining's mining operations. Until profit improves at existing operations, NAMining has narrowed its business development efforts.

In 2023, NAMining capital expenditures are expected to be approximately $39 million primarily for the acquisition of equipment to support the Thacker Pass lithium project.

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**Item 7.&nbsp;&nbsp;&nbsp;&nbsp;MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS**

**NACCO INDUSTRIES, INC. AND SUBSIDIARIES**

*(Tabular Amounts in Thousands, Except Per Share and Percentage Data)*

**<u>Minerals Management Outlook</u>**

The Minerals Management segment derives income from royalty-based leases under which lessees make payments to the Company based on their sale of natural gas, oil, natural gas liquids and coal, extracted primarily by third parties. Changing prices of natural gas and oil have a significant impact on Minerals Management's operating profit.

In 2023, operating profit and Segment Adjusted EBITDA are expected to decrease significantly compared with 2022. This decrease is primarily driven by current market expectations for natural gas and oil prices, an anticipated reduction in volumes as existing wells follow their natural production decline and modest expectations for development of new wells by third-party exploration and production companies.

Based on market expectations, the Company's forecast assumes oil and gas market prices moderate in 2023 to levels in line with 2021 averages; however, commodity prices are inherently volatile. The actions of OPEC, the Russia-Ukraine conflict, inventory levels of natural gas and oil and the uncertainty associated with demand, as well as other factors, have the potential to impact future oil and gas prices. An increase in natural gas and oil prices above current expectations could result in improvements to the 2023 forecast.

As an owner of royalty and mineral interests, the Company's access to information concerning activity and operations with respect to its interests is limited. The Company's expectations are based on the best information currently available and could vary positively or negatively as a result of adjustments made by operators, additional leasing and development and/or changes to commodity prices. Development of additional wells on existing interests in excess of current expectations could be accretive to future results.

Minerals Management is targeting additional investments in mineral and royalty interests of up to $20 million in 2023. Future investments are expected to be accretive, but each investment's contribution to near-term earnings is dependent on the details of that investment, including the size and type of interests acquired and the stage and timing of mineral development.

**<u>Consolidated Outlook</u>**

Management continues to view the long-term business outlook for NACCO positively, despite an expected significant decrease in 2023 consolidated net income versus 2022. A substantial portion of the expected reduction in 2023 earnings is because 2022 included $30.9 million of pre-tax contract termination income. &nbsp;&nbsp;&nbsp;&nbsp;

Excluding the contract termination settlement income recognized in the 2022 second quarter, net income in the first half of 2023 is still expected to be significantly lower than the first half of 2022. The decrease is primarily driven by an expected significant reduction in earnings at the Coal Mining and Minerals Management segments in the first half of 2023 versus the prior-year period. At the Coal Mining segment, an anticipated reduction in inventory levels during the first half of 2023 will result in a higher cost per ton and lower earnings at MLMC. In addition, a reduction in earnings from the unconsolidated mines, primarily Falkirk, is also contributing to the decrease. At Minerals Management, the decrease in the first half of 2023 is primarily driven by an expected significant reduction in commodity prices from historically high price levels in the first half of 2022. While consolidated net income in the second half of 2023 is expected to increase over the first half of 2023, it is expected to decline significantly versus the prior-year second half. Overall, 2023 consolidated net income is expected to decrease substantially versus 2022. These reductions are expected to be partially offset by lower income tax expense. The Company expects an effective income tax rate between 2% and 5% in 2023.

Mitigation Resources of North America<sup>®</sup> continued to build on the substantial foundation established over the past several years and ended 2022 with eight mitigation banks and four permittee-responsible mitigation projects located in Tennessee, Mississippi, Alabama and Texas. Mitigation Resources was recently named a designated provider of abandoned mine land restoration by the State of Texas. It plans to provide ecological restoration services for abandoned surface mines as well as pursue additional environmental restoration projects during 2023.

In 2023, the Company expects capital expenditures of approximately $50 million, excluding Minerals Management. Minerals Management is targeting investments of up to $20 million. Future investments at Minerals Management are expected to continue to align with the Company's strategy and objectives to establish a blended portfolio of mineral and royalty interests.

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**Item 7.&nbsp;&nbsp;&nbsp;&nbsp;MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS**

**NACCO INDUSTRIES, INC. AND SUBSIDIARIES**

*(Tabular Amounts in Thousands, Except Per Share and Percentage Data)*

As a result of the forecasted capital expenditures and anticipated substantial decrease in net income, cash flow before financing activities in 2023 is expected to be positive but decline significantly from 2022.

**<u>Long-Term Growth and Diversification Outlook</u>**

The Company is pursuing growth and diversification by strategically leveraging its core mining and natural resources management skills to build a strong portfolio of affiliated businesses. Management continues to be optimistic about the long-term outlook. In the Minerals Management segment, as well as in the Company's Mitigation Resources business, opportunities for growth remain strong. Acquisitions of additional mineral interests, an improvement in the outlook for the Company's largest Coal Mining segment customers and securing contracts for Mitigation Resources and new NAMining projects could be accretive to the Company's outlook. Additional business development expenditures will be incurred as part of this growth and would provide a partial offset to the additional income.

The Minerals Management segment continues to pursue acquisitions of mineral and royalty interests in the United States. The Minerals Management segment expects to benefit from the continued development of its mineral properties without additional capital investment, as development costs are borne entirely by third-party exploration and development companies who lease the minerals. This business model can deliver higher average operating margins over the life of a reserve than traditional oil and gas companies that bear the cost of exploration, production and/or development. Catapult, the Company's business unit focused on managing and expanding the Company's portfolio of oil and gas mineral and royalty interests, has developed a strong network to source and secure new acquisitions. The goal is to construct a high-quality diversified portfolio of oil and gas mineral and royalty interests in the United States that deliver near-term cash flow yields and long-term projected growth. The Company believes this business will provide unlevered after-tax returns on invested capital in the mid-teens as this business model matures.

The Company remains committed to expanding the NAMining business while improving profitability. NAMining intends to be a substantial contributor to operating profit over time. The pace of achieving that objective will be dependent on the execution and successful implementation of profit improvement initiatives in the aggregates operations, and the mix and scale of new projects. The Sawtooth Mining lithium project is expected to contribute more significantly when production commences at Thacker Pass.

Sawtooth Mining has a mining services agreement to serve as the exclusive contract miner for the Thacker Pass lithium project in northern Nevada, owned by Lithium Nevada Corp., a subsidiary of Lithium Americas Corp. (TSX: LAC) (NYSE: LAC). Lithium Americas owns the lithium reserves at Thacker Pass. In January 2023, Lithium Americas and General Motors announced that they will jointly invest to develop the Thacker Pass project. According to Lithium Americas, the GM agreement is a major milestone in moving Thacker Pass toward production. On March 2, 2023, Lithium Americas announced that construction has commenced. Phase 1 production is projected to begin in the second half of 2026. Sawtooth Mining plans to begin acquiring equipment for this project in 2023. Under the terms of the contract mining agreement, Lithium Americas will reimburse Sawtooth for these capital expenditures over a five-year period from the equipment acquisition date. Sawtooth will be reimbursed for all costs of mine construction plus a construction fee. The Company expects to recognize moderate income in 2024 and 2025 prior to commencement of production in 2026. Once production commences, Sawtooth will receive a management fee per metric ton of lithium delivered. At maturity, this contract is expected to deliver fee income similar to a mid-sized management fee coal mine.

Mitigation Resources continues to expand its business, which creates and sells stream and wetland mitigation credits and provides services to those engaged in permittee-responsible mitigation as well as provides other environmental restoration services. This business offers an opportunity for growth and diversification in an industry where the Company has substantial knowledge and expertise and a strong reputation. Mitigation Resources is making strong progress toward its goal of becoming a top ten provider of stream and wetland mitigation services in the southeastern United States. The Company believes that Mitigation Resources can provide solid rates of return as this business matures.

The Company also continues to pursue activities which can strengthen the resiliency of its existing coal mining operations. The Company remains focused on managing coal production costs and maximizing efficiencies and operating capacity at mine locations to help customers with management fee contracts be more competitive. These activities benefit both customers and the Company's Coal Mining segment, as fuel cost is a significant driver for power plant dispatch. Increased power plant

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**Item 7.&nbsp;&nbsp;&nbsp;&nbsp;MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS**

**NACCO INDUSTRIES, INC. AND SUBSIDIARIES**

*(Tabular Amounts in Thousands, Except Per Share and Percentage Data)*

dispatch results in increased demand for coal by the Coal Mining segment's customers. Fluctuating natural gas prices and availability of renewable energy sources, such as wind and solar, could affect the amount of electricity dispatched from coal-fired power plants. While the Company realizes the coal mining industry faces political and regulatory challenges and demand for coal is projected to decline over the longer-term, the Company believes coal will be an essential part of the energy mix in the United States for the foreseeable future. Subsequent to 2023, the Coal Mining segment expects increased profitability compared with 2023 expectations due in part to improvements at Falkirk and MLMC. At Falkirk, the temporary price concessions end in June 2024. At MLMC, the move to a new mine area will be completed during 2023, and as a result, cost per ton delivered in 2024 is expected to moderate. In addition, certain costs incurred at MLMC in 2023 will be passed through to the customer and included in revenues in 2024.

The Company continues to look for ways to create additional value by utilizing its core mining competencies which include reclamation and permitting. One such way the Company may be able to utilize these skills is through development of utility-scale solar projects on reclaimed mining properties. Reclaimed mining properties offer large tracts of land that could be well-suited for solar and other energy-related projects. These projects could be developed by the Company itself or through joint ventures that include partners with expertise in energy development projects.

The Company is committed to maintaining a conservative capital structure as it continues to grow and diversify, while avoiding unnecessary risk. Strategic diversification will generate cash that can be re-invested to strengthen and expand the businesses. The Company also continues to maintain the highest levels of customer service and operational excellence with an unwavering focus on safety and environmental stewardship.

**RECENTLY ISSUED ACCOUNTING STANDARDS**

See Note 2 to the Consolidated Financial Statements in this Form 10-K for a description of recently issued accounting standards, if any, including actual and expected dates of adoption and effects to the Company's Consolidated Financial Statements.

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**Item 7.&nbsp;&nbsp;&nbsp;&nbsp;MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS**

**NACCO INDUSTRIES, INC. AND SUBSIDIARIES**

*(Tabular Amounts in Thousands, Except Per Share and Percentage Data)*

**FORWARD-LOOKING STATEMENTS**

The statements contained in "Management's Discussion and Analysis of Financial Condition and Results of Operations" and elsewhere throughout this Annual Report on Form 10-K that are not historical facts are "forward-looking statements" within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. These forward-looking statements are made subject to certain risks and uncertainties, which could cause actual results to differ materially from those presented. Readers are cautioned not to place undue reliance on these forward-looking statements, which speak only as of the date hereof. The Company undertakes no obligation to publicly revise these forward-looking statements to reflect events or circumstances that arise after the date hereof. Among the factors that could cause plans, actions and results to differ materially from current expectations are, without limitation: (1) changes to or termination of customer or other third-party contracts, or a customer or other third party default under a contract, (2) any customer's premature facility closure, (3) a significant reduction in purchases by the Company's customers, including as a result of changes in coal consumption patterns of U.S. electric power generators, or changes in the power industry that would affect demand for the Company's coal and other mineral reserves, (4) changes in the prices of hydrocarbons, particularly diesel fuel, natural gas, natural gas liquids and oil, (5) failure or delays by the Company's lessees in achieving expected production of natural gas and other hydrocarbons; the availability and cost of transportation and processing services in the areas where the Company's oil and gas reserves are located; federal and state legislative and regulatory initiatives relating to hydraulic fracturing; and the ability of lessees to obtain capital or financing needed for well-development operations and leasing and development of oil and gas reserves on federal lands, (6) failure to obtain adequate insurance coverages at reasonable rates, (7) supply chain disruptions, including price increases and shortages of parts and materials, (8) changes in tax laws or regulatory requirements, including the elimination of, or reduction in, the percentage depletion tax deduction, changes in mining or power plant emission regulations and health, safety or environmental legislation, (9) the ability of the Company to access credit in the current economic environment, or obtain financing at reasonable rates, or at all, and to maintain surety bonds for mine reclamation as a result of current market sentiment for fossil fuels, (10) impairment charges, (11) the effects of investors' and other stakeholders' increasing attention to environmental, social and governance matters, (12) changes in costs related to geological and geotechnical conditions, repairs and maintenance, new equipment and replacement parts, fuel or other similar items, (13) regulatory actions, changes in mining permit requirements or delays in obtaining mining permits that could affect deliveries to customers, (14) weather conditions, extended power plant outages, liquidity events or other events that would change the level of customers' coal or aggregates requirements, (15) weather or equipment problems that could affect deliveries to customers, (16) changes in the costs to reclaim mining areas, (17) costs to pursue and develop new mining, mitigation and oil and gas opportunities and other value-added service opportunities, (18) delays or reductions in coal or aggregates deliveries, (19) the ability to successfully evaluate investments and achieve intended financial results in new business and growth initiatives, (20) disruptions from natural or human causes, including severe weather, accidents, fires, earthquakes and terrorist acts, any of which could result in suspension of operations or harm to people or the environment, and (21) the ability to attract, retain, and replace workforce and administrative employees.

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**Item 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK**

As a "smaller reporting company" as defined by Rule 12b-2 of the Securities Exchange Act of 1934, the Company is not required to provide this information.

**Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA**

The information required by this Item 8 is set forth in the Financial Statements and Supplementary Data contained in Part IV of this Form 10-K and is hereby incorporated herein by reference to such information.

**Item 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE**

There were no disagreements with accountants on accounting and financial disclosure for the two-year period ended December 31, 2022 that require disclosure pursuant to this Item 9.

**Item 9A**. **CONTROLS AND PROCEDURES**

**Evaluation of disclosure controls and procedures:** An evaluation was carried out under the supervision and with the participation of the Company's management, including the principal executive officer and the principal financial officer, of the effectiveness of the Company's disclosure controls and procedures as of the end of the period covered by this report. Based on that evaluation, these officers have concluded that the Company's disclosure controls and procedures are effective.

**Management's report on internal control over financial reporting:** Management is responsible for establishing and maintaining adequate internal control over financial reporting. Under the supervision and with the participation of management, including the principal executive officer and principal financial officer, the Company conducted an evaluation of the effectiveness of internal control over financial reporting based on the framework in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework). Based on this evaluation under the framework, management concluded that the Company's internal control over financial reporting was effective as of December 31, 2022. The Company's effectiveness of internal control over financial reporting as of December 31, 2022 has been audited by Ernst & Young LLP, an independent registered public accounting firm, as stated in its report, which is included in Item 15 of this Form 10-K and incorporated herein by reference.

**Changes in internal control:** There have been no changes in the Company's internal control over financial reporting, that occurred during the fourth quarter of 2022, that have materially affected, or are reasonably likely to materially affect, the Company's internal control over financial reporting.

**Item 9B**. **OTHER INFORMATION**

None.

**Item 9C. DISCLOSURE REGARDING FOREIGN JURISDICTIONS THAT PREVENT INSPECTIONS**

None.

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**PART III**

**Item 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE**

Information with respect to Directors of the Company will be set forth in the 2023 Proxy Statement under the subheadings "Part III — Proposals To Be Voted On At The 2023 Annual Meeting — Proposal 1 — Election of Directors," which information is incorporated herein by reference.

Information with respect to the audit review committee and the audit review committee financial expert will be set forth in the 2023 Proxy Statement under the subheading "Part I — Corporate Governance Information — Directors' Meetings and Committees," which information is incorporated herein by reference.

Information with respect to compliance with Section 16(a) of the Securities Exchange Act of 1934 by the Company's Directors, executive officers and holders of more than ten percent of the Company's equity securities will be set forth in the 2023 Proxy Statement under the subheading "Part IV — Other Important Information," which information is incorporated herein by reference.

The Company has adopted a code of business conduct and ethics applicable to all Company personnel, including the principal executive officer, principal financial officer, principal accounting officer or controller, or other persons performing similar functions. The code of business conduct and ethics, entitled the "Code of Corporate Conduct," is posted on the Company's website at www.nacco.com under "Corporate Governance." If the Company makes any amendments to or grants any waivers from the code of business conduct and ethics which are required to be disclosed pursuant to the Securities and Exchange Act of 1934, the Company will make such disclosure on the NACCO website.

**Item 11. EXECUTIVE COMPENSATION**

Information with respect to executive compensation will be set forth in the 2023 Proxy Statement under the headings "Part II — Executive Compensation Information" and "Part III — Proposals To Be Voted On At The 2023 Annual Meeting — Proposal 1 — Election of Directors," which information is incorporated herein by reference.

**Item 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS**

Information with respect to security ownership of certain beneficial owners and management will be set forth in the 2023 Proxy Statement under the subheading "Part IV — Other Important Information — Beneficial Ownership of Class A Common and Class B Common," which information is incorporated herein by reference.

Information with respect to compensation plans (including individual compensation arrangements) under which equity securities are authorized for issuance will be set forth in the 2023 Proxy Statement under the subheading "Part IV — Other Important Information — Equity Compensation Plan Information," which information is incorporated herein by reference.

**Item 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE**

Information with respect to certain relationships and related transactions will be set forth in the 2023 Proxy Statement under the subheadings "Part I — Corporate Governance Information — Review and Approval of Related-Person Transactions," which information is incorporated herein by reference.

**Item 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES**

Information with respect to principal accountant fees and services will be set forth in the 2023 Proxy Statement under the heading "Part III — Proposals To Be Voted On At The 2023 Annual Meeting — Proposal 3 — Ratification of the Appointment of Company's Independent Registered Public Accounting Firm," which information is incorporated herein by reference.

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**PART IV**

**Item 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES**

(a) (1) and (2) The response to Item 15(a)(1) and (2) is set forth beginning at page F-1 of this Form 10-K.

(b) Financial Statement Schedules — The response to Item 15(c) is set forth beginning at page F-41 of this Form 10-K.

(c) Exhibits required by Item 601 of Regulation S-K

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| | |
|:---|:---|
| Exhibit Number | Exhibit Description |
| (3) Articles of Incorporation and By-laws. | (3) Articles of Incorporation and By-laws. |
| 3.1(i) | Restated Certificate of Incorporation of the Company is incorporated herein by reference to Exhibit 3(i) to the Company's Annual Report on Form 10-K for the fiscal year ended December 31, 1992, Commission File Number 1-9172. |
| 3.1(ii) | <u>[Amended and Restated By-laws of the Company are incorporated herein by reference to Exhibit 3.1 to the Company's Current Report on Form 8-K, filed by the Company on December 18, 2014, Commission File Number 1-9172.](http://www.sec.gov/Archives/edgar/data/789933/000078993314000084/exhibit31.htm)</u> |

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| | |
|:---|:---|
| (4) Instruments defining the rights of security holders, including indentures. | (4) Instruments defining the rights of security holders, including indentures. |
| 4.1 | The Company by this filing agrees, upon request, to file with the Securities and Exchange Commission the instruments defining the rights of holders of long-term debt of the Company and its subsidiaries where the total amount of securities authorized thereunder does not exceed 10% of the total assets of the Company and its subsidiaries on a consolidated basis. |
| 4.2 | The Mortgage and Security Agreement, dated April 8, 1976, between The Falkirk Mining Company (as Mortgagor) and Cooperative Power Association and United Power Association (collectively, as Mortgagee) is incorporated herein by reference to Exhibit 4(ii) to the Company's Annual Report on Form 10-K for the fiscal year ended December 31, 1992, Commission File Number 1-9172. |
| 4.3 | Amendment No. 1 to the Mortgage and Security Agreement, dated as of December 15, 1993, between Falkirk Mining Company (as Mortgagor) and Cooperative Power Association and United Power Association (collectively, as Mortgagee) is incorporated herein by reference to Exhibit 4(iii) to the Company's Annual Report on Form 10-K for the fiscal year ended December 31, 1997, Commission File Number 1-9172. |
| 4.4 | <u>[Amended and Restated Stockholders' Agreement, dated as of September 29, 2017, among NACCO Industries, Inc., the other signatories thereto and NACCO Industries, Inc., as depository, is incorporated by reference to Exhibit 10.4 to the Company's Current Report on Form 8-K, filed by the Company on October 5, 2017, Commission File Number 1-9172.](http://www.sec.gov/Archives/edgar/data/789933/000078993317000056/nchbbspinoct2017ex104.htm)</u> |
| 4.5 | <u>[Amendment to Amended and Restated Stockholders' Agreement, dated as of February 14, 2019, among NACCO Industries, Inc., the other signatories thereto and NACCO Industries, Inc., as depository, is incorporated by reference to Exhibit 4.5 to the Company's Annual Report on Form 10-K for the fiscal year ended December 31, 2018, Commission File Number 1-9172.](http://www.sec.gov/Archives/edgar/data/789933/000078993319000013/exhibit45201810-k.htm)</u> |
| 4.6 | <u>[Second Amendment to Amended and Restated Stockholders' Agreement, dated as of February 12, 2021, by and among the Depository, NACCO Industries, Inc., the new Participating Stockholders identified on the signature pages thereto and the Participating Stockholders under the Amended and Restated Stockholders' Agreement, dated as of September 29, 2017, as amended, is incorporated by reference to Exhibit 99.60 of the Company's General statement of acquisition of beneficial ownership on Form SC 13D, filed on February 12, 2021, Commission File Number 1-9172.](https://www.sec.gov/Archives/edgar/data/789933/000119312521041640/d127958dex9960.htm)</u> |
| 4.7 | <u>[Third Amendment to Amended and Restated Stockholders' Agreement, dated as of February 11, 2022, by and among the Depository, NACCO Industries, Inc., the new Participating Stockholders identified on the signature pages thereto and the Participating Stockholders under the Amended and Restated Stockholders' Agreement, dated as of September 29, 2017, as amended, is incorporated by reference to Exhibit 99.](https://www.sec.gov/Archives/edgar/data/789933/000119312522036854/d313481dex9962.htm)[62](https://www.sec.gov/Archives/edgar/data/789933/000119312522036854/d313481dex9962.htm)[of the Company's General statement of acquisition of beneficial ownership on Form SC 13D, filed on February 11, 2022, Commission File Number 1-9172.](https://www.sec.gov/Archives/edgar/data/789933/000119312522036854/d313481dex9962.htm)</u> |
| 4.8 | <u>[Fourth Amendment to Amended and Restated Stockholders' Agreement, dated as of](https://www.sec.gov/Archives/edgar/data/789933/000119312523031914/d379983dex9967.htm)[February](https://www.sec.gov/Archives/edgar/data/789933/000119312523031914/d379983dex9967.htm)[1](https://www.sec.gov/Archives/edgar/data/789933/000119312523031914/d379983dex9967.htm)[0](https://www.sec.gov/Archives/edgar/data/789933/000119312523031914/d379983dex9967.htm)[, 2023](https://www.sec.gov/Archives/edgar/data/789933/000119312523031914/d379983dex9967.htm)[, by and among the Depository, NACCO Industries, Inc., the new Participating Stockholders identified on the signature pages thereto and the Participating Stockholders under the Amended and Restated Stockholders' Agreement, dated as of September 29, 2017, as amended, is incorporated by reference to](https://www.sec.gov/Archives/edgar/data/789933/000119312523031914/d379983dex9967.htm)[Exhibit](https://www.sec.gov/Archives/edgar/data/789933/000119312523031914/d379983dex9967.htm)[99.67](https://www.sec.gov/Archives/edgar/data/789933/000119312523031914/d379983dex9967.htm)[of the Company's General statement of acquisition of beneficial ownership on Form SC 13D, filed on](https://www.sec.gov/Archives/edgar/data/789933/000119312523031914/d379983dex9967.htm)[February](https://www.sec.gov/Archives/edgar/data/789933/000119312523031914/d379983dex9967.htm)[1](https://www.sec.gov/Archives/edgar/data/789933/000119312523031914/d379983dex9967.htm)[0](https://www.sec.gov/Archives/edgar/data/789933/000119312523031914/d379983dex9967.htm)[, 2023](https://www.sec.gov/Archives/edgar/data/789933/000119312523031914/d379983dex9967.htm)[, Commission File Number 1-9172.](https://www.sec.gov/Archives/edgar/data/789933/000119312523031914/d379983dex9967.htm)</u> |
| 4.9 | <u>[Description of Securities is incorporated herein by reference to Exhibit 4.6 to the Company's Annual Report on Form 10-K for the fiscal year ended December 31, 2019, Commission File Number 1-9172.](https://www.sec.gov/Archives/edgar/data/789933/000078993320000017/exhibit46to201910-k.htm)</u> |

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| | |
|:---|:---|
| Exhibit Number | Exhibit Description |
| (10) Material contracts | (10) Material contracts |
| 10.1\* | <u>[NACCO Industries, Inc. Supplemental Executive Long-Term Incentive Bonus Plan (Amended and Restated March 1, 2012) is incorporated herein by reference to Appendix B to NACCO's Definitive Proxy Statement, filed by NACCO on March 16, 2012, Commission File Number 1-9172.](http://www.sec.gov/Archives/edgar/data/789933/000078993312000050/ncdef14a31812.htm#s3D848290080B65B364A61114E3236392)</u> |
| 10.2\* | <u>[NACCO Industries, Inc. Executive Long-Term Incentive Compensation Plan (Amended and Restated March 1, 2021) is incorporated herein by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K, filed by the Company on May 19, 2021, Commission File Number 1-9172.](https://www.sec.gov/Archives/edgar/data/789933/000078993321000027/exhibit101ncmay21annual.htm)</u> |
| 10.3\* | <u>[NACCO Industries, Inc. Non-Employee Directors' Equity Compensation Plan (Amended and Restated May 19, 2021) is incorporated herein by reference to Exhibit 10.2 to the Company's Current Report on Form 8-K, filed by the Company on May 19, 2021, Commission File Number 1-9172.](https://www.sec.gov/Archives/edgar/data/789933/000078993321000027/exhibit102ncmay21annual.htm)</u> |
| 10.4\* | <u>[Form of Award Agreement for the NACCO Industries, Inc. Supplemental Executive Long-Term Incentive Bonus Plan is incorporated by reference to Exhibit 10.8 to the Company's Current Report on Form 8-K, filed by the Company on September 17, 2012, Commission File Number 1-9172.](http://www.sec.gov/Archives/edgar/data/789933/000078993312000115/nchyincentiveplanex108.htm)</u> |
| 10.5\* | <u>[Form of Cashless Exercise Award Agreement for the NACCO Industries, Inc. Executive Long-Term Incentive Compensation Plan is incorporated herein by reference to Exhibit 10.9 to the Company's Annual Report on Form 10-K for the fiscal year ended December 31, 2019, Commission File Number 1-9172.](https://www.sec.gov/Archives/edgar/data/789933/000078993320000017/exhibit109201910-k.htm)</u>  |
| 10.6\* | <u>[Form of Non-Cashless Exercise Award Agreement for the NACCO Industries, Inc. Executive Long-Term Incentive Compensation Plan is incorporated herein by reference to Exhibit 10.10 to the Company's Annual Report on Form 10-K for the fiscal year ended December 31, 2019, Commission File Number 1-9172.](https://www.sec.gov/Archives/edgar/data/789933/000078993320000017/exhibit1010201910-k.htm)</u> |
| 10.7 | <u>[Separation Agreement, dated as of September 29, 2017, between NACCO Industries, Inc. and Hamilton Beach Brands Holding Company, is incorporated by reference to Exhibit 10.1 of Hamilton Beach Brands Holding Company's Current Report on Form 8-K, filed on October 4, 2017, Commission File Number 1-9172.](http://www.sec.gov/Archives/edgar/data/1709164/000170916417000003/separationex101.htm)</u> |
| 10.8 | <u>[Tax Allocation Agreement, dated as of September 29, 2017, between NACCO Industries, Inc. and Hamilton Beach Brands Holding Company, is incorporated by reference to Exhibit 10.3 of Hamilton Beach Brands Holding Company's Current Report on Form 8-K, filed on October 4, 2017, Commission File Number 1-9172.](http://www.sec.gov/Archives/edgar/data/1709164/000170916417000003/taxallocationex103.htm)</u> |
| 10.9 | <u>[Consulting Agreement, dated as of September 29, 2017, between NACCO Industries, Inc. and Alfred M. Rankin, Jr., is incorporated by reference to Exhibit 10.5 of NACCO Industries, Inc.'s Current Report on Form 8-K, filed on October 5, 2017, Commission File Number 1-9172.](http://www.sec.gov/Archives/edgar/data/789933/000078993317000056/nchbbspinoct2017ex105.htm)</u> |
| 10.10 | <u>[Amendment to Consulting Agreement, dated as of December 15, 2020, between NACCO Industries, Inc. and Alfred M. Rankin, Jr., is incorporated by reference to Exhibit 10.1 of NACCO Industries, Inc.'s Current Report on Form 8-K, filed on December 15, 2020, Commission File Number 1-9172.](https://www.sec.gov/Archives/edgar/data/789933/000078993320000070/exhibitq42020amrconsulting.htm)</u> |
| 10.11 | <u>[Amendment to Consulting Agreement, dated as of December 21, 2021, between NACCO Industries, Inc. and Alfred M. Rankin, Jr., is incorporated by reference to Exhibit 10.1 of NACCO Industries, Inc.'s Current Report on Form 8-K, filed on December 22, 2021, Commission File Number 1-9172.](https://www.sec.gov/Archives/edgar/data/789933/000078993321000065/amendmenttorankinconsultin.htm)</u> |
| 10.12\* | <u>[NACCO Industries, Inc. Short-Term Incentive Compensation Plan (Effective as of March 1, 2019) is incorporated herein by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K, filed by the Company on February 13, 2019, Commission File Number 1-9172.](http://www.sec.gov/Archives/edgar/data/789933/000078993319000004/exhibit99-stipq119.htm)</u> |
| 10.13\* | <u>[The North American Coal Corporation Supplemental Retirement Benefit Plan (Amended and Restated as of January 1, 2008) is incorporated herein by reference to Exhibit 10.12 to the Company's Current Report on Form 8-K, filed by the Company on December 19, 2007, Commission File Number 1-9172.](http://www.sec.gov/Archives/edgar/data/789933/000095015207009730/l29253aexv10w12.htm)</u> |
| 10.14\* | <u>[Amendment No. 1 to The North America Coal Corporation Supplemental Retirement Benefit Plan (Amended and Restated as of January 1, 2008) is incorporated herein by reference to Exhibit 10.41 to the Company's Annual Report on Form 10-K for the fiscal year ended December 31, 2009, Commission File Number 1-9172.](http://www.sec.gov/Archives/edgar/data/789933/000095012310020094/l38668exv10w41.htm)</u> |
| 10.15\* | <u>[The North American Coal Corporation Annual Incentive Compensation Plan (Amended and Restated Effective March 1, 2015) is incorporated herein by reference to Exhibit 10.3 to the Company's Current Report on Form 8-K, filed by the Company on May 18, 2015, Commission File Number 1-9172.](http://www.sec.gov/Archives/edgar/data/789933/000078993315000039/exhibit1032015nacoalstip.htm)</u> |
| 10.16\* | <u>[Amendment No. 2 to The North American Coal Corporation Supplemental Retirement Benefit Plan (Amended and Restated as of January 1, 2008) is incorporated herein by reference to Exhibit 10.40 to the Company's Annual Report on Form 10-K for the fiscal year ended December 31, 2010, Commission File Number 1-9172.](http://www.sec.gov/Archives/edgar/data/789933/000078993311000019/ncex1040201010k.htm)</u> |
| 10.17 | <u>[Coteau Lignite Sales Agreement by and between The Coteau Properties Company and Dakota Coal Company, dated as of January 1, 1990, is incorporated herein by reference to Exhibit 10.11 to the Company's Quarterly Report on Form 10-Q/A, filed by the Company on March 20, 2013, Commission File Number 1-9172.+](http://www.sec.gov/Archives/edgar/data/789933/000078993313000024/ncex1011coteaulignitesales.htm)</u> |
| 10.18 | <u>[First Amendment to Coteau Lignite Sales Agreement by and between The Coteau Properties Company and Dakota Coal Company, dated as of June 1, 1994, is incorporated herein by reference to Exhibit 10.12 to the Company's Quarterly Report on Form 10-Q/A, filed by the Company on March 20, 2013, Commission File Number 1-9172.+](http://www.sec.gov/Archives/edgar/data/789933/000078993313000024/ncex1012firstamendmenttoco.htm)</u> |

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<u>[**Table of Contents**](#iaf3a05f346f8475da90341366c3f6933_7)</u>

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| | |
|:---|:---|
| Exhibit Number | Exhibit Description |
| 10.19 | <u>[Second Amendment to Coteau Lignite Sales Agreement by and between The Coteau Properties Company and Dakota Coal Company, dated as of January 1, 1997, is incorporated herein by reference to Exhibit 10.13 to the Company's Quarterly Report on Form 10-Q/A, filed by the Company on March 20, 2013, Commission File Number 1-9172.+](http://www.sec.gov/Archives/edgar/data/789933/000078993313000024/ncex1013secondamendmenttoc.htm)</u> |
| 10.20 | <u>[Option and Put Agreement by and among The North American Coal Corporation, Dakota Coal Company and the State of North Dakota, dated as of January 1, 1990, is incorporated herein by reference to Exhibit 10.14 to the Company's Quarterly Report on Form 10-Q/A, filed by the Company on March 20, 2013, Commission File Number 1-9172.](http://www.sec.gov/Archives/edgar/data/789933/000078993312000129/ncex1014.htm)</u> |
| 10.21 | <u>[First Amendment to the Option and Put Agreement by and among The North American Coal Corporation, Dakota Coal Company and the State of North Dakota, dated as of June 1, 1994, is incorporated herein by reference to Exhibit 10.15 to the Company's Quarterly Report on Form 10-Q/A, filed by the Company on March 20, 2013, Commission File Number 1-9172.](http://www.sec.gov/Archives/edgar/data/789933/000078993312000129/ncex1015.htm)</u> |
| 10.22 | <u>[Lignite Sales Agreement by and between Mississippi Lignite Mining Company and Choctaw Generation Limited Partnership, dated as of April 1, 1998, is incorporated herein by reference to Exhibit 10.16 to the Company's Quarterly Report on Form 10-Q/A, filed by the Company on March 20, 2013, Commission File Number 1-9172.+](http://www.sec.gov/Archives/edgar/data/789933/000078993313000024/ncex1016mlmcandchoctaw.htm)</u> |
| 10.23 | <u>[First Amendment to Lignite Sales Agreement by and between Mississippi Lignite Mining Company and Choctaw Generation Limited Partnership, dated as of August 30, 2016, is incorporated herein by reference to Exhibit 10.1 to the Company's Quarterly Report on Form 10-Q, filed by the Company on November 1, 2016, Commission File Number 1-9172.+](http://www.sec.gov/Archives/edgar/data/789933/000078993316000124/exhibit101q316.htm)</u> |
| 10.24 | <u>[Pay Scale Agreement by and between Mississippi Lignite Mining Company and Choctaw Generation Limited Partnership, dated as of September 29, 2005, is incorporated herein by reference to Exhibit 10.17 to the Company's Quarterly Report on Form 10-Q/A, filed by the Company on March 20, 2013, Commission File Number 1-9172.](http://www.sec.gov/Archives/edgar/data/789933/000078993312000129/ncex1017.htm)</u> |
| 10.25 | <u>[Consent and Agreement by and among Mississippi Lignite Mining Company, Choctaw Generation Limited Partnership, SE Choctaw L.L.C. and Citibank, N.A., dated as of December 20, 2002, is incorporated herein by reference to Exhibit 10.29 to the Company's Quarterly Report on Form 10-Q/A, filed by the Company on March 20, 2013, Commission File Number 1-9172.](http://www.sec.gov/Archives/edgar/data/789933/000078993312000134/ncex1029mlmcconsentandagre.htm)</u> |
| 10.26 | <u>[Amendment No. 1 to Lignite Sales Agreement, Settlement Agreement and Release by and between Mississippi Lignite Mining Company and Choctaw Generation Limited Partnership, LLLP, dated as of November 16, 2018, is incorporated herein by reference to Exhibit 10.33 to the Company's Annual Report on Form 10-K for the fiscal year ended December 31, 2018, Commission File Number 1-9172.](http://www.sec.gov/Archives/edgar/data/789933/000078993319000013/exhibit1033201810-k.htm)</u> |
| 10.27 | <u>[Amendment No. 2 to Lignite Sales Agreement, Settlement Agreement and Release by and between Mississippi Lignite Mining Company and Choctaw Generation Limited Partnership, LLLP, dated as of November 24, 2021, is incorporated herein by reference to Exhibit 10.29 to the Company's Annual Report on Form 10-K for the fiscal year ended December 31, 2021, Commission File Number 1-9172.](http://www.sec.gov/Archives/edgar/data/789933/000078993322000015/exhibit1029.htm)</u> |
| 10.28 | <u>[Termination Agreement and Release, by and among The Falkirk Mining Company, Great River Energy and NoDak Energy Investments Corporation, dated June 30, 2021, is incorporated herein by reference to Exhibit 10.6 to the Company's Quarterly Report on Form 10-Q, filed by the Company on August 4, 2021, Commission File Number 1-9172.](https://www.sec.gov/Archives/edgar/data/789933/000078993321000049/exhibit106q221-0003falkirk.htm)</u> |
| 10.29 | <u>[Amendment No. 1 to Termination Agreement and Release, by and between The Falkirk Mining Company, NoDak Energy Investments Corporation and Great River Energy, dated as of December 28, 2021, is incorporated herein by reference to Exhibit 10.36 to the Company's Annual Report on Form 10-K for the fiscal year ended December 31, 2021, Commission File Number 1-9172.](http://www.sec.gov/Archives/edgar/data/789933/000078993322000015/exhibit1036.htm)</u> |
| 10.30<br>\*\*\* | <u>[Coal Sales Agreement, by and between The Falkirk Mining Company and Rainbow Energy Center, LLC, dated June 30, 2021, is incorporated herein by reference to Exhibit 10.1 to the Company's Quarterly Report on Form 10-Q, filed by the Company on August 4, 2021, Commission File Number 1-9172.](https://www.sec.gov/Archives/edgar/data/789933/000078993321000049/exhibit101q221-falkirkxcsa.htm)</u> |
| 10.31 | <u>[First Amendment to Coal Sales Agreement, by and between The Falkirk Mining Company and Rainbow Energy Center, LLC, dated March 8, 2022, is incorporated herein by reference to Exhibit 10.1 to the Company's Quarterly Report on Form 10-Q, filed by the Company on May 4, 2022, Commission File Number 1-9172.](https://www.sec.gov/Archives/edgar/data/789933/000078993322000035/exhibit101-firstamendmentt.htm)</u> |
| 10.32 | <u>[Second Amendment to Coal Sales Agreement, by and between the Falkirk Mining Company and Rainbow Energy Center, LLC, dated August 5, 2022, is incorporated herein by reference to Exhibit 10.1 to the Company's Quarterly Report on Form 10-Q, filed by the Company on November 2, 2022, Commission File Number 1-9172.](https://www.sec.gov/Archives/edgar/data/789933/000078993322000063/exhibit10.htm)</u> |
| 10.33<br>\*\*\* | <u>[Guaranty by REMC Assets, LP, dated June 17, 2021, is incorporated herein by reference to Exhibit 10.2 to the Company's Quarterly Report on Form 10-Q, filed by the Company on August 4, 2021, Commission File Number 1-9172.](https://www.sec.gov/Archives/edgar/data/789933/000078993321000049/exhibit102q221-remcguarant.htm)</u> |
| 10.34<br>\*\*\* | <u>[Mortgage, Assignment of Leases, Rents and As-Extracted Collateral, Security Agreement, Financing Statement and Fixture Filing, by and between The Falkirk Mining Company and Rainbow Energy Center, LLC, dated June 30, 2021, is incorporated herein by reference to Exhibit 10.3 to the Company's Quarterly Report on Form 10-Q, filed by the Company on August 4, 2021, Commission File Number 1-9172.](https://www.sec.gov/Archives/edgar/data/789933/000078993321000049/exhibit103q221-nai_1519069.htm)</u> |

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<u>[**Table of Contents**](#iaf3a05f346f8475da90341366c3f6933_7)</u>

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| | |
|:---|:---|
| Exhibit Number | Exhibit Description |
| 10.35 | <u>[Security Agreement, by and between The Falkirk Mining Company and Rainbow Energy Center, LLC, dated June 30, 2021, is incorporated herein by reference to Exhibit 10.4 to the Company's Quarterly Report on Form 10-Q, filed by the Company on August 4, 2021, Commission File Number 1-9172.](https://www.sec.gov/Archives/edgar/data/789933/000078993321000049/exhibit104q221-nai_1519049.htm)</u> |
| 10.36 | <u>[Option Agreement, by and between The Falkirk Mining Company, Rainbow Energy Center, LLC and the State of North Dakota, Doing Business as The Bank of North Dakota, dated June 30, 2021, is incorporated herein by reference to Exhibit 10.5 to the Company's Quarterly Report on Form 10-Q, filed by the Company on August 4, 2021, Commission File Number 1-9172.](https://www.sec.gov/Archives/edgar/data/789933/000078993321000049/exhibit105q221-0004rainbow.htm)</u> |
| 10.37 | <u>[Third Restatement of Lignite Mining Agreement by and between The Sabine Mining Company and Southwestern Electric Power Company, dated as of January 1, 2008, is incorporated herein by reference to Exhibit 10.21 to the Company's Quarterly Report on Form 10-Q/A, filed by the Company on March 20, 2013, Commission File Number 1-9172.+](http://www.sec.gov/Archives/edgar/data/789933/000078993313000024/ncex1021sabine.htm)</u> |
| 10.38 | <u>[Amendment No. 1 to Third Restatement of Lignite Mining Agreement by and between The Sabine Mining Company and Southwestern Electric Power Company, dated as of October 18, 2013 is incorporated herein by reference to Exhibit 10.43 to the Company's Annual Report on Form 10-K for the fiscal year ended December 31, 2014, Commission File Number 1-9172.](http://www.sec.gov/Archives/edgar/data/789933/000078993315000015/exhibit1043201410-k.htm)</u> |
| 10.39 | <u>[Option Agreement by and among The North American Coal Corporation, Southwestern Electric Power Company and Longview National Bank, dated as of January 15, 1981, is incorporated herein by reference to Exhibit 10.22 to the Company's Quarterly Report on Form 10-Q/A, filed by the Company on March 20, 2013, Commission File Number 1-9172.](http://www.sec.gov/Archives/edgar/data/789933/000078993312000129/ncex1022.htm)</u> |
| 10.40 | <u>[Addendum to Option Agreement, by and among The North American Coal Corporation, Southwestern Electric Power Company and Longview National Bank, dated as of January 15, 1981 is incorporated herein by reference to Exhibit 10.23 to the Company's Quarterly Report on Form 10-Q/A, filed by the Company on March 20, 2013, Commission File Number 1-9172.](http://www.sec.gov/Archives/edgar/data/789933/000078993312000129/ncex1023.htm)</u> |
| 10.41 | <u>[Amendment to Option Agreement, by and among The North American Coal Corporation, Southwestern Electric Power Company and Longview National Bank, dated as of December 2, 1996, is incorporated herein by reference to Exhibit 10.24 to the Company's Quarterly Report on Form 10-Q/A, filed by the Company on March 20, 2013, Commission File Number 1-9172.](http://www.sec.gov/Archives/edgar/data/789933/000078993312000129/ncex1024.htm)</u> |
| 10.42 | <u>[Second Amendment to Option Agreement, by and among The North American Coal Corporation, Southwestern Electric Power Company and Regions Bank, dated as of January 1, 2008, is incorporated herein by reference to Exhibit 10.25 to the Company's Quarterly Report on Form 10-Q/A, filed by the Company on March 20, 2013, Commission File Number 1-9172.](http://www.sec.gov/Archives/edgar/data/789933/000078993312000129/ncex1025.htm)</u> |
| 10.43 | <u>[Agreement by and among The North American Coal Corporation, Southwestern Electric Power Company, Texas Commerce Bank-Longview, Nortex Mining Company and The Sabine Mining Company, dated as of June 30, 1988, is incorporated herein by reference to Exhibit 10.26 to the Company's Quarterly Report on Form 10-Q/A, filed by the Company on March 20, 2013, Commission File Number 1-9172.](http://www.sec.gov/Archives/edgar/data/789933/000078993312000129/ncex1026.htm)</u> |
| 10.44 | <u>[Lignite Sales Agreement between Coyote Creek Mining Company, L.L.C. and Otter Tail Power Company, Northern Municipal Power Agency, Montana-Dakota Utilities Co. and Northwestern Corporation dated as of October 10, 2012 is incorporated herein by reference to Exhibit 10.58 to the Company's Annual Report on Form 10-K, filed by the Company on March 6, 2013, Commission File Number 1-9172.++](http://www.sec.gov/Archives/edgar/data/789933/000078993313000013/ncexh1058201210k.htm)</u> |
| 10.45 | <u>[First Amendment to Lignite Sales Agreement, dated as of January 30, 2014, between Coyote Creek Mining Company, L.L.C. and Otter Tail Power Company, Northern Municipal Power Agency, Montana-Dakota Utilities Co., a division of MDU Resources Group, Inc. and NorthWestern Corporation is incorporated herein by reference to Exhibit 10.1 to the Company's Quarterly Report on Form 8-K, filed by the Company on January 30, 2014, Commission File Number 1-9172.](http://www.sec.gov/Archives/edgar/data/789933/000078993314000005/firstamendmenttolignitesal.htm)</u> |
| 10.46 | <u>[Second Amendment to Lignite Sales Agreement, dated as of March 16, 2015, between Coyote Creek Mining Company, L.L.C. and Otter Tail Power Company, Northern Municipal Power Agency, Montana-Dakota Utilities Co., a division of MDU Resources Group, Inc., and NorthWestern Corporation is incorporated herein by reference to Exhibit 10.1 to the Company's Quarterly Report on Form 10-Q, filed by the Company on May 5, 2015, Commission File Number 1-9172.](http://www.sec.gov/Archives/edgar/data/789933/000078993315000035/exhibit101coyote.htm)</u> |
| 10.47\* | <u>[Amendment No. 3 to The North American Coal Corporation Supplemental Retirement Benefit Plan (Amended and Restated as of January 1, 2008) is incorporated herein by reference to Exhibit 10.1 to the Company's Quarterly Report on Form 10-Q, filed by the Company on October 30, 2013, Commission File Number 1-9172.](http://www.sec.gov/Archives/edgar/data/789933/000078993313000078/ncexhibit101q313.htm)</u> |
| 10.48\* | <u>[Amendment No. 4 to The North American Coal Corporation Supplemental Retirement Benefit Plan (Amended and Restated as of January 1, 2008) is incorporated herein by reference to Exhibit 10.54 to the Company's Annual Report on Form 10-K for the fiscal year ended December 31, 2014, Commission File Number 1-9172.](http://www.sec.gov/Archives/edgar/data/789933/000078993315000015/exhibit1054201410-k.htm)</u> |
| 10.49\* | <u>[Amendment No. 5 to The North American Coal Corporation Supplemental Retirement Benefit Plan (Amended and Restated as of January 1, 2008) is incorporated herein by reference to Exhibit 10.57 to the Company's Annual Report on Form 10-K for the fiscal year ended December 31, 2015, Commission File Number I-9172.](http://www.sec.gov/Archives/edgar/data/789933/000078993316000069/exhibit1057.htm)</u> |

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<u>[**Table of Contents**](#iaf3a05f346f8475da90341366c3f6933_7)</u>

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| | |
|:---|:---|
| Exhibit Number | Exhibit Description |
| 10.50\* | <u>[Amendment No. 6 to The North American Coal Corporation Supplemental Retirement Benefit Plan (Amended and Restated as of January 1, 2008) is incorporated herein by reference to Exhibit 10.52 to the Company's Annual Report on Form 10-K for the fiscal year ended December 31, 2016, Commission File Number I-9172.](http://www.sec.gov/Archives/edgar/data/789933/000078993317000007/exhibit1052201610-k.htm)</u> |
| 10.51 | <u>[Agreement, dated as of March 16, 2015, among The North American Coal Corporation, Otter Tail Power Company, Northern Municipal Power Agency, Montana-Dakota Utilities Co., a division of MDU Resources Group, Inc. and Northwestern Corporation is incorporated herein by reference to Exhibit 10.2 to the Company's Quarterly Report on Form 10-Q, filed by the Company on May 5, 2015, Commission File Number 1-9172](http://www.sec.gov/Archives/edgar/data/789933/000078993315000035/exhibit102coyote.htm)</u>. |
| 10.52 | <u>[The North American Coal Corporation Excess Retirement Plan (Amended and Restated Effective January 1, 2020) is incorporated herein by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K, filed by the Company on December 18, 2019, Commission File Number 1-9172.](http://www.sec.gov/Archives/edgar/data/789933/000078993319000065/exhibit101-thenorthamerica.htm)</u> |
| 10.53 | <u>[Amended and Restated Credit Agreement by and among The North American Coal Corporation and the Guarantors party thereto and the Lenders party thereto and KeyBank National Association as Syndication Agent, PNC Bank National Association as Administrative Agent and KeyBanc Capital Markets Inc. and PNC Capital Markets LLC as Joint Lead Arrangers and Joint Bookrunners, dated as of November 12, 2021 is incorporated herein by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K, filed by the Company on November 15, 2021, Commission File Number 1-9172.](http://www.sec.gov/Archives/edgar/data/789933/000078993321000061/ex101-pncxnorthamericancoa.htm)</u> |
| 10.54 | <u>[Revolving Credit Commitment Increase Agreement, dated as of December 10, 2021 is incorporated herein by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K, filed by the Company on December 13, 2021. Commission File Number 1-9172.](https://www.sec.gov/Archives/edgar/data/789933/000078993321000063/dec 21-revolvingcreditincre.htm)</u> |
| 10.55 | <u>[ESG Amendment to Amended and Restated Credit Agreement, dated as of June 30, 2022, is incorporated herein by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K, filed by the Company on July 7, 2022. Commission File Number 1-9172.](https://www.sec.gov/Archives/edgar/data/789933/000078993322000044/exhibit101esgamendment.htm)</u> |

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(21\*\*) <u>[Subsidiaries. A list of the subsidiaries of the Company is attached hereto as Exhibit 21.](exhibit21202210-k.htm)</u>

(23) Consents of experts and counsel.

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| | |
|:---|:---|
| 23.1\*\* | <u>[Consents of experts and counsel.](exhibit231202210-k.htm)</u> |
| 23.2\*\* | <u>[Consent of Qualified Person.](exhibit232202210-k.htm)</u> |
| 23.3\*\* | <u>[Consent of Qualified Person.](exhibit233202210-k.htm)</u> |
| 23.4\*\* | <u>[Consent of experts and counsel.](exhibit234202210-k.htm)</u> |

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(24) Powers of Attorney.

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| | |
|:---|:---|
| 24.1\*\* | <u>[A copy of a power of attorney for John S. Dalrymple is attached hereto as Exhibit 24.1.](exhibit241202210-k.htm)</u> |
| 24.2\*\* | <u>[A copy of a power of attorney for John P. Jumper is attached hereto as Exhibit 24.2.](exhibit242202210-k.htm)</u> |
| 24.3\*\* | <u>[A copy of a power of attorney for Dennis W. LaBarre is attached hereto as Exhibit 24.3.](exhibit243202210-k.htm)</u> |
| 24.4\*\* | <u>[A copy of a power of attorney for Michael S. Miller is attached hereto as Exhibit 24.4.](exhibit244202210-k.htm)</u> |
| 24.5\*\* | <u>[A copy of a power of attorney for Richard de J. Osborne is attached hereto as Exhibit 24.5.](exhibit245202210-k.htm)</u> |
| 24.6\*\* | <u>[A copy of a power of attorney for Alfred M. Rankin, Jr. is attached hereto as Exhibit 24.6.](exhibit246202210-k.htm)</u> |
| 24.7\*\* | <u>[A copy of a power of attorney for Matthew M. Rankin is attached hereto as Exhibit 24.7.](exhibit247202210-k.htm)</u> |
| 24.8\*\* | <u>[A copy of a power of attorney for Roger F. Rankin is attached hereto as Exhibit 24.8.](exhibit248202210-k.htm)</u> |
| 24.9\*\* | <u>[A copy of a power of attorney for Lori J. Robinson is attached hereto as Exhibit 24.9.](exhibit249202210-k.htm)</u> |
| 24.10\*\* | <u>[A copy of a power of attorney for Robert S. Shapard is attached hereto as Exhibit 24.10.](exhibit2410202210-k.htm)</u> |
| 24.11\*\* | <u>[A copy of a power of attorney for Britton T. Taplin is attached hereto as Exhibit 24.11.](exhibit2411202210-k.htm)</u> |

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<u>[**Table of Contents**](#iaf3a05f346f8475da90341366c3f6933_7)</u>

(31) Rule 13a-14(a)/15d-14(a) Certifications.

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| | |
|:---|:---|
| 31(i)(1)<br>\*\* | <u>[Certification of J.C. Butler, Jr. pursuant to Rule 13a-14(a)/15d-14(a) of the Exchange Act is attached hereto as Exhibit 31(i)(1).](exhibit311202210-k.htm)</u> |
| 31(i)(2)<br>\*\* | <u>[Certification of Elizabeth I. Loveman pursuant to Rule 13a-14(a)/15d-14(a) of the Exchange Act is attached hereto as Exhibit 31(i)(2).](exhibit312202210-k.htm)</u> |
| (32)\*\*\*\* | <u>[Certifications pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, signed and dated by J.C. Butler, Jr. and Elizabeth I. Loveman.](exhibit32202210-k.htm)</u> |
| (95)\*\* | <u>[Mine Safety Disclosure Exhibit is attached hereto as Exhibit 95.](exhibit95202210-k.htm)</u> |
| 96.1\*\* | <u>[Technical Report Summary relating to the Mississippi Lignite Mining Company](exhibit961-mlmcsk1300x0309.htm)[,](exhibit961-mlmcsk1300x0309.htm)[effective date as of](exhibit961-mlmcsk1300x0309.htm)[December 31, 2022.](exhibit961-mlmcsk1300x0309.htm)</u> |
| (99.1\*\*) | <u>[Reserve Report of Catapult Mineral Partners.](exhibit991-202210xk.htm)</u> |
| (99.2\*\*) | <u>[Supplemental Figures Attachment.](exhibit992-202210xk.htm)</u> |
| 101.INS | Inline XBRL Instance Document |
| 101.SCH | Inline XBRL Taxonomy Extension Schema Document |
| 101.CAL | Inline XBRL Taxonomy Extension Calculation Linkbase Document |
| 101.DEF | Inline XBRL Taxonomy Extension Definition Linkbase Document |
| 101.LAB | Inline XBRL Taxonomy Extension Label Linkbase Document |
| 101.PRE | Inline XBRL Taxonomy Extension Presentation Linkbase Document |
| 104 | Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101) |

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| | |
|:---|:---|
| \* | Management contract or compensation plan or arrangement required to be filed as an exhibit pursuant to Item15(b) of this Annual Report on Form 10-K. |
| \*\* | Filed herewith. |
| \*\*\* | Certain confidential information contained in this agreement has been omitted because it (i) is not material and (ii) would be competitively harmful if publicly disclosed. |
| \*\*\*\* | Furnished herewith. |
| **+** | Portions of Exhibit have been omitted and filed separately with the Securities and Exchange Commission in reliance on Rule 24b-2 and an Order from the Commission granting the Company's request for confidential treatment dated March 27, 2013. Portions for which confidential treatment has been granted have been marked with three asterisks [\*\*\*] and a footnote indicating "Confidential treatment requested". |
| ++ | Portions of Exhibit have been omitted and filed separately with the Securities and Exchange Commission in reliance on Rule 24b-2 and an Order from the Commission granting the Company's request for confidential treatment dated April 2, 2013. Portions for which confidential treatment has been granted have been marked with three asterisks [\*\*\*] and a footnote indicating "Confidential treatment requested". |

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<u>[**Table of Contents**](#iaf3a05f346f8475da90341366c3f6933_7)</u>

**SIGNATURES**

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

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| | |
|:---|:---|
| NACCO Industries, Inc. | NACCO Industries, Inc. |
| By: | /s/ Elizabeth I. Loveman |
|  | Elizabeth I. Loveman |
|  | Vice President and Controller <br>(principal financial and accounting officer) |

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March 15, 2023

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<u>[**Table of Contents**](#iaf3a05f346f8475da90341366c3f6933_7)</u>

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

---

| | | |
|:---|:---|:---|
| /s/ J.C. Butler, Jr. | President and Chief Executive Officer (principal executive officer) | March 15, 2023 |
| J.C. Butler, Jr. |  |  |
| /s/ Elizabeth I. Loveman | Vice President and Controller (principal financial and accounting officer) | March 15, 2023 |
| Elizabeth I. Loveman |  |  |
| \*John S. Dalrymple | Director | March 15, 2023 |
| John S. Dalrymple |  |  |
| \* John P. Jumper | Director | March 15, 2023 |
| John P. Jumper |  |  |
| \* Dennis W. LaBarre | Director | March 15, 2023 |
| Dennis W. LaBarre |  |  |
| \* Michael S. Miller | Director | March 15, 2023 |
| Michael S. Miller |  |  |
| \* Richard de J. Osborne | Director | March 15, 2023 |
| Richard de J. Osborne |  |  |
| \* Alfred M. Rankin, Jr. | Director | March 15, 2023 |
| Alfred M. Rankin, Jr. |  |  |
| \* Matthew M. Rankin | Director | March 15, 2023 |
| Matthew M. Rankin |  |  |
| \* Roger F. Rankin | Director | March 15, 2023 |
| Roger F. Rankin |  |  |
| \*Lori J. Robinson | Director | March 15, 2023 |
| Lori J. Robinson |  |  |
| \*Robert S. Shapard | Director | March 15, 2023 |
| Robert S. Shapard |  |  |
| \* Britton T. Taplin | Director | March 15, 2023 |
| Britton T. Taplin |  |  |

---

\* Elizabeth I. Loveman, by signing her name hereto, does hereby sign this Form 10-K on behalf of each of the above named and designated directors of the Company pursuant to a Power of Attorney executed by such persons and filed with the Securities and Exchange Commission.

---

| | |
|:---|:---|
| /s/ Elizabeth I. Loveman | March 15, 2023 |
| Elizabeth I. Loveman, Attorney-in-Fact | |

---

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<u>[**Table of Contents**](#iaf3a05f346f8475da90341366c3f6933_7)</u>

**ANNUAL REPORT ON FORM 10-K** 

**ITEM 8, ITEM 15(a)(1) AND (2), AND ITEM 15(c)**

**FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA**

**LIST OF FINANCIAL STATEMENTS AND FINANCIAL STATEMENT SCHEDULES**

**FINANCIAL STATEMENTS**

**FINANCIAL STATEMENT SCHEDULES**

**YEAR ENDED DECEMBER 31, 2022** 

**NACCO INDUSTRIES, INC.**

**CLEVELAND, OHIO**

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<u>[**Table of Contents**](#iaf3a05f346f8475da90341366c3f6933_7)</u>

**FORM 10-K**

**ITEM 15(a)(1) AND (2)**

**NACCO INDUSTRIES, INC. AND SUBSIDIARIES**

**LIST OF FINANCIAL STATEMENTS AND FINANCIAL STATEMENT SCHEDULES**

The following consolidated financial statements of NACCO Industries, Inc. and Subsidiaries and the reports of the Company's independent registered public accounting firm (PCAOB ID:42) are incorporated by reference in Item 8:

---

| | |
|:---|:---|
| <u>[Report of Ernst & Young LLP, Independent Registered Public Accounting Firm — For each of the two years in the period ended December 31, 2022.](#iaf3a05f346f8475da90341366c3f6933_136)</u> | F-<u>[3](#iaf3a05f346f8475da90341366c3f6933_136)</u> |
| <u>[Report of Ernst & Young LLP, Independent Registered Public Accounting Firm on Internal Control Over Financial Reporting — As of December 31, 2022.](#iaf3a05f346f8475da90341366c3f6933_139)</u> | F-<u>[5](#iaf3a05f346f8475da90341366c3f6933_139)</u> |
| <u>[Consolidated Statements of Operations](#iaf3a05f346f8475da90341366c3f6933_142)</u> | F-<u>[6](#iaf3a05f346f8475da90341366c3f6933_142)</u> |
| <u>[Consolidated Statements of Comprehensive Income (Loss)](#iaf3a05f346f8475da90341366c3f6933_145)</u> | F-<u>[7](#iaf3a05f346f8475da90341366c3f6933_145)</u> |
| <u>[Consolidated Balance Sheets](#iaf3a05f346f8475da90341366c3f6933_148)</u> | F-<u>[8](#iaf3a05f346f8475da90341366c3f6933_148)</u> |
| <u>[Consolidated Statements of Cash Flows](#iaf3a05f346f8475da90341366c3f6933_151)</u> | F-<u>[9](#iaf3a05f346f8475da90341366c3f6933_151)</u> |
| <u>[Consolidated Statements of Equity](#iaf3a05f346f8475da90341366c3f6933_154)</u> | F-<u>[10](#iaf3a05f346f8475da90341366c3f6933_154)</u> |
| <u>[Notes to Consolidated Financial Statements](#iaf3a05f346f8475da90341366c3f6933_157)</u> | F-<u>[11](#iaf3a05f346f8475da90341366c3f6933_157)</u> |

---

The following consolidated financial statement schedules of NACCO Industries, Inc. and Subsidiaries are included in Item 15(c):

<u>[Schedule II — Valuation and Qualifying Accounts](#iaf3a05f346f8475da90341366c3f6933_229)</u><br>

All other schedules for which provision is made in the applicable accounting regulation of the SEC are not required under the related instructions or are inapplicable, and therefore have been omitted.

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<u>[**Table of Contents**](#iaf3a05f346f8475da90341366c3f6933_133)</u>

**Report of Independent Registered Public Accounting Firm**

To the Stockholders and the Board of Directors of NACCO Industries, Inc.

**Opinion on the Financial Statements** 

We have audited the accompanying consolidated balance sheets of NACCO Industries, Inc. and Subsidiaries (the Company) as of December 31, 2022 and 2021, the related consolidated statements of operations, comprehensive income (loss), equity and cash flows for the years then ended, and the related notes and the financial statement schedules listed in the Index at Item 15(a) (collectively referred to as the "consolidated financial statements"). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company at December 31, 2022 and 2021, and the results of its operations and its cash flows for the years then ended, in conformity with U.S. generally accepted accounting principles.

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 issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) and our report dated March 15, 2023 expressed an unqualified opinion thereon.

**Basis for Opinion** 

These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the Company's 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 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 financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the 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 financial statements. We believe that our audits provide a reasonable basis for our opinion.

**Critical Audit Matter**

The critical audit matter communicated below is a matter arising from the current period audit of the financial statements that was communicated or required to be communicated to the audit review committee and that: (1) relates to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective or complex judgments. The communication of the critical audit matter 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 matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.

------

<u>[**Table of Contents**](#iaf3a05f346f8475da90341366c3f6933_133)</u>

**Falkirk VIE Reconsideration Event**

---

| | |
|:---|:---|
| **Description of the Matter** | As discussed in Note 1 to the consolidated financial statements, on May 2, 2022, Great River Energy ("GRE") completed the sale of Coal Creek Station and the adjacent high-voltage direct current transmission line to Rainbow Energy Center, LLC ("Rainbow Energy") and its affiliates.<br>While Falkirk meets the definition of a VIE, the completion of the Rainbow Energy transaction resulted in a VIE reconsideration event. As the terms of the CSA between Falkirk and Rainbow Energy are substantially the same as the terms of the coal supply contract between Falkirk and GRE, Falkirk remains a VIE and Rainbow Energy is the primary beneficiary; therefore, NACCO will continue to account for Falkirk under the equity method.<br>Auditing the disclosure of the terms of the transaction was especially complex in determining whether the completion of the Rainbow Energy transaction resulted in a VIE reconsideration event, a change in the conclusion that Falkirk meets the definition of a VIE and the determination of the primary beneficiary of the VIE. Evaluating the Company's judgments in determining whether an entity is a VIE and the primary beneficiary of the VIE requires a high degree of complex auditor judgment. |
| **How We Addressed the Matter in Our Audit** | We obtained an understanding, evaluated and tested the design and operating effectiveness of the controls surrounding the Company's processes to assess the implications of significant transactions and events that could trigger a VIE reconsideration event.<br>To test the implications of the transaction, our audit procedures included, among other things, inspecting the new CSA between Falkirk and Rainbow Energy that became effective upon regulatory approval of the sale of Coal Creek Station and evaluating the VIE assessment performed by the Company. We evaluated the significant terms of the contract and whether the agreement between Falkirk and Rainbow Energy resulted in a reconsideration event, a change in the conclusion that Falkirk meets the definition of a VIE and the determination of the primary beneficiary. |

---

/s/ Ernst & Young LLP

We have served as the Company's auditor since 2002.

Cleveland, Ohio

March 15, 2023

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<u>[**Table of Contents**](#iaf3a05f346f8475da90341366c3f6933_133)</u>

**Report of Independent Registered Public Accounting Firm**

To the Stockholders and the Board of Directors of NACCO Industries, Inc.

**Opinion on Internal Control Over Financial Reporting**

We have audited NACCO Industries, Inc. and Subsidiaries' internal control over financial reporting as of December 31, 2022, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) (the COSO criteria). In our opinion, NACCO Industries, Inc. and Subsidiaries (the Company) maintained, in all material respects, effective internal control over financial reporting as of December 31, 2022, based on the COSO criteria.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the 2022 consolidated financial statements of the Company and our report dated March 15, 2023 expressed an unqualified opinion thereon.

**Basis for Opinion**

The Company's management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management's report on internal control over financial reporting in Item 9A. Our responsibility is to express an opinion on the Company's internal control over financial reporting based on our audit. 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 audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects.

Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

**Definition and Limitations of Internal Control Over Financial Reporting** 

A company's internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

/s/ Ernst & Young LLP

Cleveland, Ohio

March 15, 2023

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<u>[**Table of Contents**](#iaf3a05f346f8475da90341366c3f6933_133)</u>

**NACCO INDUSTRIES, INC. AND SUBSIDIARIES**

**CONSOLIDATED STATEMENTS OF OPERATIONS**

---

| | | |
|:---|:---|:---|
| | Year Ended December 31 | Year Ended December 31 |
| | **2022** | 2021 |
| | (In thousands, except per share data) | (In thousands, except per share data) |
| **Revenues** | $**241719** | $191846 |
| Cost of sales | **173877** | 148394 |
| **Gross profit** | **67842** | 43452 |
| **Earnings of unconsolidated operations** | **57250** | 60843 |
| **Contract termination settlement** | **14000** | 10333 |
| **Operating expenses** |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Selling, general and administrative expenses | **63911** | 55722 |
| &nbsp;&nbsp;&nbsp;&nbsp;Amortization of intangible assets | **3719** | 3556 |
| &nbsp;&nbsp;&nbsp;&nbsp;Gain on sale of assets | **(2463)** | (60) |
| &nbsp;&nbsp;&nbsp;&nbsp; Asset impairment charges | **3939** |  |
|  | **69106** | 59218 |
| **Operating profit** | **69986** | 55410 |
| Other (income) expense |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Interest expense | **2034** | 1719 |
| &nbsp;&nbsp;&nbsp;&nbsp;Interest income | **(1449)** | (449) |
| &nbsp;&nbsp;&nbsp;&nbsp;Closed mine obligations | **1179** | 1297 |
| &nbsp;&nbsp;&nbsp;&nbsp;Loss (gain) on equity securities | **283** | (3423) |
| &nbsp;&nbsp;&nbsp;&nbsp;Income from equity method investee | **(2194)** |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Other contract termination settlements | **(16882)** |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Other, net | **(708)** | (584) |
|  | **(17737)** | (1440) |
| **Income before income tax provision** | **87723** | 56850 |
| Income tax provision | **13565** | 8725 |
| **Net income** | $**74158** | $48125 |
| **Earnings per share:** |  |  |
| **Basic earnings per share** | $**10.14** | $6.73 |
| **Diluted earnings per share** | $**10.06** | $6.69 |
| **Basic weighted average shares outstanding** | **7312** | 7146 |
| **Diluted weighted average shares outstanding** | **7373** | 7190 |

---

See notes to the Consolidated Financial Statements.

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<u>[**Table of Contents**](#iaf3a05f346f8475da90341366c3f6933_133)</u>

**NACCO INDUSTRIES, INC. AND SUBSIDIARIES**

**CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)**

---

| | | |
|:---|:---|:---|
| | Year Ended December 31 | Year Ended December 31 |
| | **2022** | 2021 |
| | (In thousands) | (In thousands) |
| **Net income** | $**74158** | $48125 |
| Other comprehensive income |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Current period pension and postretirement plan adjustment, net of $363 tax benefit and $864 tax expense in 2022 and 2021, respectively | **(1310)** | 2851 |
| &nbsp;&nbsp;&nbsp;&nbsp;Reclassification of pension and postretirement adjustments into earnings, net of $140 and $170 tax benefit in 2022 and 2021, respectively | **473** | 572 |
| **Total other comprehensive (loss) income** | **(837)** | 3423 |
| **Comprehensive income** | $**73321** | $51548 |

---

See notes to the Consolidated Financial Statements.

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<u>[**Table of Contents**](#iaf3a05f346f8475da90341366c3f6933_133)</u>

 **NACCO INDUSTRIES, INC. AND SUBSIDIARIES**

**CONSOLIDATED BALANCE SHEETS** 

---

| | | |
|:---|:---|:---|
| | December 31 | December 31 |
| | **2022** | 2021 |
| | (In thousands, except share data) | (In thousands, except share data) |
| **ASSETS** |  |  |
| **Current assets** |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Cash and cash equivalents | $**110748** | $86005 |
| &nbsp;&nbsp;&nbsp;&nbsp;Trade accounts receivable | **37940** | 25667 |
| &nbsp;&nbsp;&nbsp;&nbsp;Accounts receivable from affiliates | **6638** | 5605 |
| &nbsp;&nbsp;&nbsp;&nbsp;Inventories | **71488** | 54085 |
| &nbsp;&nbsp;&nbsp;&nbsp;Federal income tax receivable | **15687** | 15054 |
| &nbsp;&nbsp;&nbsp;&nbsp;Prepaid insurance | **1999** | 2016 |
| &nbsp;&nbsp;&nbsp;&nbsp;Other current assets | **15907** | 14621 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;**Total current assets** | **260407** | 203053 |
| **Property, plant and equipment, net** | **217952** | 193167 |
| **Intangibles, net** | **28055** | 31774 |
| **Investment in unconsolidated subsidiaries** | **14927** | 19090 |
| **Operating lease right-of-use assets** | **6419** | 8911 |
| **Other non-current assets** | **40312** | 51225 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;**Total assets** | $**568072** | $507220 |
| **LIABILITIES AND EQUITY** |  |  |
| **Current liabilities** |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Accounts payable | $**11952** | $12208 |
| &nbsp;&nbsp;&nbsp;&nbsp;Accounts payable to affiliates | **1362** | 741 |
| &nbsp;&nbsp;&nbsp;&nbsp;Current maturities of long-term debt | **3649** | 2527 |
| &nbsp;&nbsp;&nbsp;&nbsp;Asset retirement obligations | **1746** | 1820 |
| &nbsp;&nbsp;&nbsp;&nbsp;Accrued payroll | **18105** | 16339 |
| &nbsp;&nbsp;&nbsp;&nbsp;Deferred revenue | **833** | 4082 |
| &nbsp;&nbsp;&nbsp;&nbsp;Other current liabilities | **6623** | 8299 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;**Total current liabilities** | **44270** | 46016 |
| **Long-term debt** | **16019** | 18183 |
| **Operating lease liabilities** | **7528** | 9733 |
| **Asset retirement obligations** | **44256** | 42131 |
| **Pension and other postretirement obligations** | **5082** | 6605 |
| **Deferred income taxes** | **6122** | 14792 |
| **Liability for uncertain tax positions** | **9329** | 10113 |
| **Other long-term liabilities** | **8500** | 7531 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;**Total liabilities** | **141106** | 155104 |
| **Stockholders' equity** |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Common stock: |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Class A, par value $1 per share, 5,782,944 shares outstanding (2021 - 5,616,568 shares outstanding) | **5783** | 5616 |
| &nbsp;&nbsp;&nbsp;&nbsp;Class B, par value $1 per share, convertible into Class A on a one-for-one basis, 1,566,129 shares outstanding (2021 - 1,566,613 shares outstanding) | **1566** | 1567 |
| &nbsp;&nbsp;&nbsp;&nbsp;Capital in excess of par value | **23706** | 16331 |
| &nbsp;&nbsp;&nbsp;&nbsp;Retained earnings | **404924** | 336778 |
| &nbsp;&nbsp;&nbsp;&nbsp;Accumulated other comprehensive loss | **(9013)** | (8176) |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;**Total stockholders' equity** | **426966** | 352116 |
| **Total liabilities and equity** | $**568072** | $507220 |

---

See notes to the Consolidated Financial Statements.

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<u>[**Table of Contents**](#iaf3a05f346f8475da90341366c3f6933_133)</u>

**NACCO INDUSTRIES, INC. AND SUBSIDIARIES**

**CONSOLIDATED STATEMENTS OF CASH FLOWS** 

---

| | | |
|:---|:---|:---|
|  | Year Ended December 31 | Year Ended December 31 |
|  | **2022** | 2021 |
|  | (In thousands) | (In thousands) |
| **Operating Activities** |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Net income | $**74158** | $48125 |
| &nbsp;&nbsp;&nbsp;&nbsp;Adjustments to reconcile net income to net cash provided by operating activities: |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Depreciation, depletion and amortization | **26816** | 23085 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Amortization of deferred financing fees | **446** | 326 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Deferred income taxes | **(8471)** | (3553) |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Stock-based compensation | **7541** | 5561 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Gain on sale of assets | **(2463)** | (60) |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Other contract termination settlements | **(15552)** |  |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Asset impairment charges | **3939** |  |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Other | **(791)** | 1647 |
| &nbsp;&nbsp;&nbsp;&nbsp;Working capital changes: |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Affiliates receivable/payable | **—** | 495 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Accounts receivable | **(13224)** | (13685) |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Inventories | **(6834)** | (6534) |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Other current assets | **1308** | 3320 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Accounts payable | **252** | 7445 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Income taxes receivable/payable | **(416)** | 2699 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Other current liabilities | **1026** | 6004 |
| **Net cash provided by operating activities** | **67735** | 74875 |
| **Investing Activities** |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Expenditures for property, plant and equipment | **(42523)** | (39230) |
| &nbsp;&nbsp;&nbsp;&nbsp;Acquisition of mineral interests | **(11924)** | (5331) |
| &nbsp;&nbsp;&nbsp;&nbsp;Proceeds from the sale of assets | **2837** | 633 |
| &nbsp;&nbsp;&nbsp;&nbsp;Proceeds from the sale of private company equity units | **18628** |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Other | **(170)** | (219) |
| **Net cash used for investing activities** | **(33152)** | (44147) |
| **Financing Activities** |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Net reductions to revolving credit agreement | **(4000)** | (26000) |
| &nbsp;&nbsp;&nbsp;&nbsp;Additions to long-term debt | **3091** | 3634 |
| &nbsp;&nbsp;&nbsp;&nbsp;Reductions to long-term debt | **(2919)** | (3435) |
| &nbsp;&nbsp;&nbsp;&nbsp;Cash dividends paid | **(6012)** | (5617) |
| &nbsp;&nbsp;&nbsp;&nbsp;Other | **—** | (1755) |
| **Net cash used for financing activities** | **(9840)** | (33173) |
| **Cash and Cash Equivalents** |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Total increase (decrease) for the year | **24743** | (2445) |
| &nbsp;&nbsp;&nbsp;&nbsp;Balance at the beginning of the year | **86005** | 88450 |
| &nbsp;&nbsp;&nbsp;&nbsp;**Balance at the end of the year** | $**110748** | $86005 |

---

See notes to the Consolidated Financial Statements.

------

<u>[**Table of Contents**](#iaf3a05f346f8475da90341366c3f6933_133)</u>

**NACCO INDUSTRIES, INC. AND SUBSIDIARIES**

**CONSOLIDATED STATEMENTS OF EQUITY** 

---

| | | | | | | |
|:---|:---|:---|:---|:---|:---|:---|
| | **Class A Common Stock** | **Class B Common Stock** | **Capital in Excess of Par Value** | **Retained Earnings** | **Accumulated Other Comprehensive (Loss) Income** | **Total Stockholders' Equity** |
| | (In thousands, except per share data) | (In thousands, except per share data) | (In thousands, except per share data) | (In thousands, except per share data) | (In thousands, except per share data) | (In thousands, except per share data) |
| **Balance, January 1, 2021** | $5490 | $1568 | $10895 | $294270 | $(11599) | $300624 |
| Stock-based compensation | 125 |  | 5436 |  |  | 5561 |
| Conversion of Class B to Class A shares | 1 | (1) |  |  |  |  |
| Net income |  |  |  | 48125 |  | 48125 |
| Cash dividends on Class A and Class B common stock: $0.7850 per share |  |  |  | (5617) |  | (5617) |
| Current period other comprehensive income, net of tax |  |  |  |  | 2851 | 2851 |
| Reclassification adjustment to net income, net of tax |  |  |  |  | 572 | 572 |
| **Balance, December 31, 2021** | $5616 | $1567 | $16331 | $336778 | $(8176) | $352116 |
| Stock-based compensation | **166** | **—** | **7375** | **—** | **—** | **7541** |
| Conversion of Class B to Class A shares | **1** | **(1)** | **—** | **—** | **—** | **—** |
| Net income | **—** | **—** | **—** | **74158** | **—** | **74158** |
| Cash dividends on Class A and Class B common stock: $0.8200 per share | **—** | **—** | **—** | **(6012)** | **—** | **(6012)** |
| Current period other comprehensive income, net of tax | **—** | **—** | **—** | **—** | **(1310)** | **(1310)** |
| Reclassification adjustment to net income, net of tax | **—** | **—** | **—** | **—** | **473** | **473** |
| **Balance, December 31, 2022** | $**5783** | $**1566** | $**23706** | $**404924** | $**(9013)** | $**426966** |

---

See notes to the Consolidated Financial Statements.

------

<u>[**Table of Contents**](#iaf3a05f346f8475da90341366c3f6933_133)</u>

**NOTES TO CONSOLIDATED FINANCIAL STATEMENTS**

**NACCO INDUSTRIES, INC. AND SUBSIDIARIES**

*(Tabular Amounts in Thousands, Except Per Share, Percentage Data and Oil and Gas Disclosures)*

**NOTE 1—Principles of Consolidation and Nature of Operations** 

The Consolidated Financial Statements include the accounts of NACCO Industries, Inc.<sup>®</sup> ("NACCO") and its wholly owned subsidiaries (collectively, the "Company"). NACCO brings natural resources to life by delivering aggregates, minerals, reliable fuels and environmental solutions through its robust portfolio of NACCO Natural Resources businesses. The Company operates under three business segments: Coal Mining, North American Mining ("NAMining") and Minerals Management. The Coal Mining segment operates surface coal mines for power generation companies. The NAMining segment is a trusted mining partner for producers of aggregates, activated carbon, lithium and other industrial minerals. The Minerals Management segment, which includes the Catapult Mineral Partners ("Catapult") business, acquires and promotes the development of mineral interests. Mitigation Resources of North America<sup>®</sup> ("Mitigation Resources") provides stream and wetland mitigation solutions.

The Company also has items not directly attributable to a reportable segment. Intercompany accounts and transactions are eliminated in consolidation. See Note 15 to the Consolidated Financial Statements for further discussion of segment reporting.

The Company's operating segments are further described below:

**Coal Mining Segment** 

The Coal Mining segment, operating as The North American Coal Corporation<sup>®</sup> ("NACoal"), operates surface coal mines under long-term contracts with power generation companies pursuant to a service-based business model. Coal is surface mined in North Dakota, Texas, Mississippi and through September 30, 2021, on the Navajo Nation in New Mexico. Each mine is fully integrated with its customer's operations.

As of December 31, 2022, the Company's operating coal mines were: The Coteau Properties Company ("Coteau"), Coyote Creek Mining Company, LLC ("Coyote Creek"), The Falkirk Mining Company ("Falkirk"), Mississippi Lignite Mining Company ("MLMC") and The Sabine Mining Company ("Sabine").

MLMC is the exclusive supplier of lignite to the Red Hills Power Plant in Ackerman, Mississippi. Choctaw Generation Limited Partnership ("CGLP") leases the Red Hills Power Plant from a Southern Company subsidiary pursuant to a leveraged lease arrangement. CGLP's ability to make required payments to the Southern Company subsidiary is dependent on the operational performance of the Red Hills Power Plant. During 2020, Southern Company revised the estimated cash flows to be received under the leveraged lease which resulted in a full impairment of the lease investment. If lease payments are not paid in full, the Southern Company subsidiary may be unable to make its corresponding payment to the holders of the underlying non-recourse debt related to the Red Hills Power Plant. Failure to make the required payment to the debtholders could represent an event of default that would give the debtholders the right to foreclose on, and take ownership of, the Red Hills Power Plant from the Southern Company subsidiary. On October 27, 2022, Southern Company disclosed in its Form 10-Q that it provided notice to the lessee, CGLP, to terminate the related operating and maintenance agreement effective June 30, 2023. CGLP failed to make the semi-annual lease payment due December 15, 2022. As a result, the Southern Company subsidiary was unable to make its corresponding payment to the debtholders. The parties to the lease agreement are currently negotiating a potential restructuring, which could result in rescission of the termination notice. The parties to the lease have entered into a forbearance agreement which suspends the related contractual rights of the parties while they continue restructuring negotiations. The ultimate outcome of this matter cannot be determined at this time but could have a material impact on the Company's financial statements if the operating and maintenance agreement is terminated.

On May 2, 2022, Great River Energy ("GRE") completed the sale of Coal Creek Station and the adjacent high-voltage direct current transmission line to Rainbow Energy Center, LLC ("Rainbow Energy") and its affiliates. As a result of the completion of the sale of Coal Creek Station, the Coal Sales Agreement, the Mortgage and Security Agreement and the Option Agreement between GRE and Falkirk were terminated. The Coal Sales Agreement ("CSA") between Falkirk and Rainbow Energy became effective upon the closing of the transaction. Falkirk continues to supply all coal requirements of Coal Creek Station and is paid a management fee per ton of coal delivered. To support the transfer to new ownership, Falkirk agreed to a reduction in the current per ton management fee from the effective date of the CSA through May 31, 2024. After May 31, 2024, the per ton management fee increases to a higher base in line with 2021 fee levels, and thereafter adjusts annually according to an index which tracks broad measures of U.S. inflation. Rainbow Energy is responsible for funding all mine operating costs, including

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**NACCO INDUSTRIES, INC. AND SUBSIDIARIES**

*(Tabular Amounts in Thousands, Except Per Share, Percentage Data and Oil and Gas Disclosures)*

mine reclamation, and directly or indirectly providing all of the capital required to operate the mine. The initial production period is expected to run through May 1, 2032, but the CSA may be extended or terminated early under certain circumstances.

The Company recognized a gain of $30.9 million within the accompanying Condensed Consolidated Statements of Operations during the second quarter of 2022 as GRE paid NACoal $14.0 million in cash, as well as transferred ownership of an office building with an estimated fair value of $4.1 million, and conveyed membership units in Midwest AgEnergy Group, LLC ("MAG"), a North Dakota-based ethanol business, with an estimated fair value of $12.8 million, as agreed to under the termination and release of claims agreement between Falkirk and GRE.

Prior to receiving the membership units from GRE, the Company held a $5.0 million investment in the same privately-held company carried at cost, less impairment. Subsequent to the receipt of the additional membership units, the Company began to account for the investment under the equity method of accounting. During the third quarter, the Company recorded $2.2 million, which represented its share of MAG's earnings on the "Income from equity method investee" line within the accompanying Consolidated Statements of Operations.

On December 1, 2022, HLCP Ethanol Holdco, LLC ("HLCP") completed its acquisition of MAG. Upon closing of the transaction, NACCO transferred its ownership interest in MAG to HLCP and received a cash payment of $18.6 million and recognized a $1.3 million loss during the fourth quarter of 2022 on the line "Other, net" within the accompanying Consolidated Statements of Operations.

The HLCP acquisition agreement includes two contingent earn-out arrangements under which additional payments are possible. The first earn-out is based on the achievement of EBITDA targets through December 31, 2024. The second earn-out is based on the development of a carbon dioxide pipeline that will support a carbon dioxide sequestration project over a four-year period commencing on the transaction closing date. Additional payments to NACCO could range from $0 to approximately $13.6 million based on achievement of the two earn-outs as well as payment of amounts held in escrow. Any future payments associated with the earn-outs or amounts held in escrow will be recognized when realized, consistent with the accounting for gain contingencies.

Sabine operates the Sabine Mine in Texas. All production from Sabine is delivered to Southwestern Electric Power Company's ("SWEPCO") Henry W. Pirkey Plant (the "Pirkey Plant"). SWEPCO is an American Electric Power ("AEP") company. AEP intends to retire the Pirkey Plant during March 2023. Sabine expects deliveries to cease in March 2023 and final reclamation to begin on April 1, 2023. Funding for mine reclamation is the responsibility of SWEPCO, and Sabine will receive compensation for providing mine reclamation services.

The contract mining agreement between Bisti Fuels Company, LLC ("Bisti") and its customer, Navajo Transitional Energy Company ("NTEC") was terminated effective September 30, 2021. As required under the agreement, NTEC paid the Company a termination fee of $10.3 million reported on the line Contract termination settlement on the Consolidated Statements of Operations. As of October 1, 2021, NTEC assumed control and responsibility for operation and all reclamation of the Navajo Mine.

At all operating coal mines other than MLMC, the Company is paid a management fee per ton of coal or heating unit (MMBtu) delivered. Each contract specifies the indices and mechanics by which fees change over time, generally in line with broad measures of U.S. inflation. The customers are responsible for funding all mine operating costs, including final mine reclamation, and directly or indirectly provide all of the capital required to build and operate the mine. This contract structure eliminates exposure to spot coal market price fluctuations while providing income and cash flow with minimal capital investment. Other than at Coyote Creek, debt financing provided by or supported by the customers is without recourse to NACCO and NACoal. See Note 16 for further discussion of Coyote Creek's guarantees.

All operating coal mines other than MLMC meet the definition of a VIE. In each case, NACCO is not the primary beneficiary of the VIE as it does not exercise financial control; therefore, NACCO does not consolidate the results of these operations within its financial statements. Instead, these contracts are accounted for as equity method investments. The income before income taxes associated with these VIEs is reported as Earnings of unconsolidated operations on the Consolidated Statements of Operations, and the Company's investment is reported on the line Investments in unconsolidated subsidiaries in the Consolidated Balance Sheets. The mines that meet the definition of a VIE are referred to collectively as the "Unconsolidated Subsidiaries." For tax purposes, the Unconsolidated Subsidiaries are included within the NACCO consolidated U.S. tax return;

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therefore, the income tax expense line on the Consolidated Statements of Operations includes income taxes related to these entities. See Note 16 for further information on the Unconsolidated Subsidiaries.

While Falkirk meets the definition of a VIE, the completion of the Rainbow Energy transaction resulted in a VIE

reconsideration event. As the terms of the CSA between Falkirk and Rainbow Energy are substantially the same as the terms

of the coal supply contract between Falkirk and GRE, Falkirk remains a VIE and Rainbow Energy is the primary beneficiary; therefore, NACCO will continue to account for Falkirk under the equity method.

The Company performs contemporaneous reclamation activities at each mine in the normal course of operations. Under all of the Unconsolidated Subsidiaries' contracts, the customer has the obligation to fund final mine reclamation activities. Under certain contracts, the Unconsolidated Subsidiary holds the mine permit and is therefore responsible for final mine reclamation activities. To the extent the Unconsolidated Subsidiary performs such final reclamation, it is compensated for providing those services in addition to receiving reimbursement from customers for costs incurred.

The MLMC contract is the only operating coal contract in which the Company is responsible for all operating costs, capital requirements and final mine reclamation; therefore, MLMC is consolidated within NACCO's financial statements. MLMC sells coal to its customer at a contractually agreed-upon price which adjusts monthly, primarily based on changes in the level of established indices which reflect general U.S. inflation rates. Profitability at MLMC is affected by customer demand for coal and changes in the indices that determine sales price and actual costs incurred. As diesel fuel is heavily weighted among the indices used to determine the coal sales price, fluctuations in diesel fuel prices can result in significant fluctuations in earnings at MLMC.

MLMC delivers coal to the Red Hills Power Plant in Ackerman, Mississippi. The Red Hills Power Plant supplies electricity to the Tennessee Valley Authority ("TVA") under a long-term Power Purchase Agreement ("PPA"). MLMC's contract with its customer runs through 2032. TVA's power portfolio includes coal, nuclear, hydroelectric, natural gas and renewables. The decision of which power plants to dispatch is determined by TVA.

**NAMining Segment**

The NAMining segment provides value-added contract mining and other services for producers of industrial minerals. The segment is a platform for the Company's growth and diversification of mining activities outside of the thermal coal industry. NAMining provides contract mining services for independently owned mines and quarries, creating value for its customers by performing the mining aspects of its customers' operations. This allows customers to focus on their areas of expertise: materials handling and processing, product sales and distribution. NAMining historically operated primarily at limestone quarries in Florida, but is focused on expanding outside of Florida, mining materials other than limestone and expanding the scope of mining operations provided to its customers. As of December 31, 2022, NAMining operates mines in Florida, Texas, Arkansas, Indiana, Virginia and Nebraska and will serve as exclusive contract miner for the Thacker Pass lithium project in northern Nevada.

Certain of the entities within the NAMining segment are VIEs and are accounted for under the equity method as Unconsolidated Subsidiaries. See Note 16 for further discussion.

**Minerals Management Segment**

The Minerals Management segment derives income primarily by leasing its royalty and mineral interests to third-party exploration and production companies, and, to a lesser extent, other mining companies, granting them the rights to explore, develop, mine, produce, market and sell gas, oil, and coal in exchange for royalty payments based on the lessees' sales of those minerals.

The Minerals Management segment owns royalty interests, mineral interests, nonparticipating royalty interests and overriding royalty interests.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• Royalty Interest. Royalty interests generally result when the owner of a mineral interest leases the underlying minerals to an exploration and production company pursuant to an oil and gas lease. Typically, the resulting royalty interest is a cost-free percentage of production revenues for minerals extracted from the acreage. A holder of royalty interests is generally not responsible for capital expenditures or lease operating expenses, but royalty interests may be calculated

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*(Tabular Amounts in Thousands, Except Per Share, Percentage Data and Oil and Gas Disclosures)*

net of post-production expenses, and typically has no environmental liability. Royalty interests leased to producers expire upon the expiration of the oil and gas lease and revert to the mineral owner.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• Mineral Interest. Mineral interests are perpetual rights of the owner to explore, develop, exploit, mine and/or produce any or all of the minerals lying below the surface of the property. The holder of a mineral interest has the right to lease the minerals to an exploration and production company. Upon the execution of an oil and gas lease, the lessee (the exploration and production company) becomes the working interest owner and the lessor (the mineral interest owner) has a royalty interest.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• Non-Participating Royalty Interest ("NPRIs"). NPRI is an interest in oil and gas production which is created from the mineral estate. The NPRI is expense-free, bearing no operational costs of production. The term "non-participating" indicates that the interest owner does not share in the bonus, rentals from a lease, nor the right to participate in the execution of oil and gas leases. The NPRI owner does; however, typically receive royalty payments.

The Company may own more than one type of mineral and royalty interest in the same tract of land. For example, where the Company owns an ORRI in a lease on the same tract of land in which it owns a mineral interest, the ORRI in that tract will relate to the same gross acres as the mineral interest in that tract.

The Minerals Management segment will benefit from the continued development of its mineral properties without the need for investment of additional capital once mineral and royalty interests have been acquired. The Minerals Management segment does not currently have any material investments under which it would be required to bear the cost of exploration, production or development.

Total consideration for the 2022 and 2021 acquisitions of mineral and royalty interests was $11.9 million and $5.3 million, respectively. The 2022 acquisitions included 13.6 thousand gross acres and 880 net royalty acres. The 2021 acquisitions included 20.6 thousand gross acres and 1.8 thousand net royalty acres. Total mineral and royalty interests included approximately 141.4 thousand gross acres and 60.8 thousand net royalty acres at December 31, 2022. See Note 18 for further discussion of Minerals Management.

The Company also manages legacy royalty and mineral interests located in Ohio (Utica and Marcellus shale natural gas), Louisiana (Haynesville shale and Cotton Valley formation natural gas), Texas (Cotton Valley and Austin Chalk formation natural gas), Mississippi (coal), Pennsylvania (coal, coalbed methane and Marcellus shale natural gas), Alabama (coal, coalbed methane and natural gas) and North Dakota (coal, oil and natural gas). The majority of the Company's legacy reserves were acquired as part of its historical coal mining operations.

**NOTE 2—Significant Accounting Policies** 

**Use of Estimates:** The preparation of financial statements in conformity with U.S. generally accepted accounting principles requires management to make estimates and judgments. These estimates and judgments affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities (if any) at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

**Cash and Cash Equivalents:** Cash and cash equivalents include cash in banks and highly liquid investments with original maturities of three months or less.

**Property, Plant and Equipment, Net:** Property, plant and equipment are initially recorded at cost. Depreciation, depletion and amortization are provided in amounts sufficient to amortize the cost of the assets, including assets recorded under finance leases, over their estimated useful lives using the straight-line method or the units-of-production method. Buildings and

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building improvements are depreciated over the life of the mine, which is generally 30 years. Estimated lives for machinery and equipment range from three to 15 years. The units-of-production method is used to amortize certain assets based on estimated recoverable tonnages. Repairs and maintenance costs are expensed when incurred, unless such costs extend the estimated useful life of the asset, in which case such costs are capitalized and depreciated. Asset retirement costs associated with asset retirement obligations are capitalized with the carrying amount of the related long-lived asset and depreciated over the asset's estimated useful life.

**Royalty Interests in Oil and Natural Gas Properties:** The Company follows the successful efforts method of accounting for its royalty and mineral interests. Under this method, costs to acquire mineral and royalty interests in oil and natural gas properties are capitalized when incurred. Acquisitions of royalty interests of oil and natural gas properties are considered asset acquisitions and are recorded at cost. As an owner of mineral and royalty interests and not working interests, the Company is not required to make capital expenditures and did not make capital expenditures to convert proved undeveloped reserves from undeveloped to developed.

Acquisition costs of proved royalty and mineral interests are amortized using the units of production method over the life of the property, which is estimated using proved reserves. For purposes of amortization, interests in oil and natural gas properties are grouped in a reasonable aggregation of properties with common geological structural features or stratigraphic condition.

The Company reviews and evaluates its royalty interests in oil and natural gas properties for impairment when events or changes in circumstances indicate that the related carrying amounts may not be recoverable. Proved oil and gas properties are reviewed for impairment when events and circumstances indicate a potential decline in the fair value of such properties below the carrying value, such as a downward revision of the reserve estimates or lower commodity prices. When such events or changes in circumstances occur, the Company estimates the undiscounted future cash flows expected in connection with the properties and compares such future cash flows to the carrying amounts of the properties to determine if the carrying amounts are recoverable. If the carrying value of the properties is determined to not be recoverable based on the undiscounted cash flows, an impairment charge is recognized by comparing the carrying value to the estimated fair value of the properties.

See Note 18 for further discussion of the Company's royalty and mineral interests.

**Long-Lived Assets:** The Company periodically evaluates long-lived assets for impairment when changes in circumstances or the occurrence of certain events indicate the carrying amount of an asset or asset group may not be recoverable. Upon identification of indicators of impairment, the Company evaluates the carrying value of the asset by comparing the estimated future undiscounted cash flows generated from the use of the asset or asset group and its eventual disposition with the asset's net carrying value. If the carrying value of an asset is considered impaired, an impairment charge is recorded for the amount that the carrying value of the long-lived asset or asset group exceeds its fair value. Fair value is estimated 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. See Note 9 for further discussion of the Company's nonrecurring fair value measurements.

At MLMC, the costs of mining operations are not reimbursed by MLMC's customer. As such, increased costs at MLMC or decreased revenues could materially reduce the Company's profitability. Any reduction in customer demand at MLMC, including reductions related to reduced mechanical availability of the customer's power plant, would adversely affect the Company's operating results and could result in significant impairments. MLMC has approximately $125 million of long-lived assets, including property, plant and equipment and its coal supply agreement intangible asset, which are subject to periodic impairment analyses and review. Identifying and assessing whether impairment indicators exist, or if events or changes in circumstances have occurred, including assumptions about future power plant dispatch levels, changes in future sales price, operating costs and other factors that impact anticipated revenue and customer demand, requires significant judgment. Actual future operating results could differ significantly from these estimates, which may result in an impairment charge in a future period, which could have a substantial impact on the Company's results of operations.

**Self-insurance Liabilities:** The Company is generally self-insured for medical claims, certain workers' compensation claims and certain closed mine liabilities. An estimated provision for claims reported and for claims incurred but not yet reported under the self-insurance programs is recorded and revised periodically based on industry trends, historical experience and management judgment. In addition, industry trends are considered within management's judgment for valuing claims. Changes in assumptions for such matters as legal judgments and settlements, inflation rates, medical costs and actual experience could cause estimates to change in the near term.

**Revenue Recognition:** See Note 3 to the Consolidated Financial Statements for discussion of revenue recognition.

**Stock Compensation:** The Company maintains long-term incentive programs that allow for the grant of shares of Class A common stock, subject to restrictions, as a means of retaining and rewarding selected employees for long-term performance and

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to increase ownership in the Company. Shares awarded under the plans are fully vested and entitle the stockholder to all rights of common stock ownership except that shares may not be assigned, pledged or otherwise transferred during the restriction period. In general, for shares awarded for years ended December 31, 2022 and December 31, 2021, the restriction period ends at the earliest of (i) three years after the participant's retirement date, (ii) three, five or ten years from the award date, or (iii) the participant's death or permanent disability. Pursuant to the plans, the Company issued 165,574 and 138,306 shares related to the years ended December 31, 2022 and 2021, respectively. After the issuance of these shares, there were 396,120 shares of Class A common stock available for issuance under these plans. Compensation expense related to these share awards was $6.4 million ($5.0 million net of tax) and $4.1 million ($3.2 million net of tax) for the years ended December 31, 2022 and 2021, respectively. Compensation expense represents fair value based on the market price of the shares of Class A common stock at the grant date.

The Company also has a stock compensation plan for non-employee directors of the Company under which a portion of the annual retainer for each non-employee director is paid in restricted shares of Class A common stock. For the year ended December 31, 2022, $110,000 ($150,000 for the Chairman) of the non-employee director's annual retainer of $175,000 ($250,000 for the Chairman) was paid in restricted shares of Class A common stock. For the year ended December 31, 2021, $105,000 ($150,000 for the Chairman) of the non-employee director's annual retainer of $167,000 ($250,000 for the Chairman) was paid in restricted shares of Class A common stock. Shares awarded under the plan are fully vested and entitle the stockholder to all rights of common stock ownership except that shares may not be assigned, pledged, hypothecated or otherwise transferred during the restriction period. In general, the restriction period ends at the earliest of (i) ten years from the award date, (ii) the date of the director's death or permanent disability, (iii) five years (or earlier with the approval of the Board of Directors) after the director's date of retirement from the Board of Directors, (iv) the date the director has both retired from the Board of Directors and has reached age 70, or (v) at such other time as determined by the Board of Directors in its sole and absolute discretion. Pursuant to this plan, the Company issued 30,034 and 45,223 shares related to the years ended December 31, 2022 and 2021, respectively. In addition to the mandatory retainer fee received in restricted stock, directors may elect to receive shares of Class A common stock in lieu of cash for up to 100% of the balance of their annual retainer, committee retainer and any committee chairman's fees. These voluntary shares are not subject to any restrictions. Total shares issued under voluntary elections were 480 in 2022 and 753 in 2021. After the issuance of these shares, there were 136,047 shares of Class A common stock available for issuance under this plan. Compensation expense related to these awards was $1.3 million ($1.0 million net of tax) and $1.3 million ($1.1 million net of tax) for the years ended December 31, 2022 and 2021, respectively. Compensation expense represents fair value based on the market price of the shares of Class A common stock at the grant date.

**Financial Instruments:** Financial instruments held by the Company include cash and cash equivalents, accounts receivable, equity securities, accounts payable, revolving credit agreements and long-term debt.

**Fair Value Measurements:** The Company accounts for the fair value measurement of its financial assets and liabilities in accordance with U.S. generally accepted accounting principles, which 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.

A fair value hierarchy requires an entity to maximize the use of observable inputs, where available, and minimize the use of unobservable inputs when measuring fair value.

Described below are the three levels of inputs that may be used to measure fair value:

Level 1 - Quoted prices in active markets that are accessible at the measurement date for identical assets or liabilities.

Level 2 - Observable prices that are based on inputs not quoted on active markets, but corroborated by market data.

Level 3 - Unobservable inputs are used when little or no market data is available.

The hierarchy is based upon the transparency of inputs to the valuation of an asset or liability as of the measurement date. The classification of fair value measurements within the hierarchy is based upon the lowest level of input that is significant to the measurement. See Note 9 for further discussion of fair value measurements.

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**NOTE 3—Revenue Recognition** 

**Nature of Performance Obligations**

At contract inception, the Company assesses the goods and services promised in its contracts with customers and identifies a performance obligation for each promised good or service that is distinct. To identify the performance obligations, the Company considers all of the goods or services promised in the contract regardless of whether they are explicitly stated or are implied by customary business practices.

Each mine or mine area has a contract with its respective customer that represents a contract under ASC 606. For its consolidated entities, the Company's performance obligations vary by contract and consist of the following:

At MLMC, each MMBtu delivered during the production period is considered a separate performance obligation. Revenue is recognized at the point in time that control of each MMBtu of lignite transfers to the customer. Fluctuations in revenue from period to period generally result from changes in customer demand.

At NAMining, the management service to oversee the operation of the equipment and delivery of aggregates or other minerals is the performance obligation accounted for as a series. Performance momentarily creates an asset that the customer simultaneously receives and consumes; therefore, control is transferred to the customer over time. Consistent with the conclusion that the customer simultaneously receives and consumes the benefits provided, an input-based measure of progress is appropriate. As each month of service is completed, revenue is recognized for the amount of actual costs incurred, plus the management fee or fixed fee and the general and administrative fee (as applicable). Fluctuations in revenue from period to period result from changes in customer demand primarily due to increases and decreases in activity levels on individual contracts and variances in reimbursable costs.

Included within NAMining, Caddo Creek has a fixed-price contract to perform mine reclamation. The management service to perform mine reclamation is the performance obligation accounted for as a series. Performance momentarily creates an asset that the customer simultaneously receives and consumes; therefore, control is transferred to the customer over time. Revenue from this contract is recognized over time utilizing the cost-to-cost method to measure the extent of progress toward completion of the performance obligation. The Company believes the cost-to-cost method is the most appropriate method to measure progress and that the rate at which costs are incurred to fulfill the contract best depicts the transfer of control to the customer. The extent of progress towards completion is measured based on the ratio of costs incurred to date compared to total estimated costs at completion, and revenue is recorded proportionally based on an estimated profit margin.

The Minerals Management segment enters into contracts which grant the right to explore, develop, produce and sell minerals controlled by the Company. These arrangements result in the transfer of mineral rights for a period of time; however, no rights to the actual land are granted other than access for purposes of exploration, development, production and sales. The mineral rights revert back to the Company at the expiration of the contract.

Under these contracts, granting exclusive right, title, and interest in and to minerals, if any, is the performance obligation. The performance obligation under these contracts represents a series of distinct goods or services whereby each day of access that is provided is distinct. The transaction price consists of a variable sales-based royalty and, in certain arrangements, a fixed component in the form of an up-front lease bonus payment. As the amount of consideration the Company will ultimately be entitled to is entirely susceptible to factors outside its control, the entire amount of variable consideration is constrained at contract inception. The Company believes that the pricing provisions of royalty contracts are customary in the industry. Up-front lease bonus payments represent the fixed portion of the transaction price and are recognized over the primary term of the contract, which is generally three to five years.

Mitigation Resources generates and sells stream and wetland mitigation credits (known as mitigation banking) and provides services to those engaged in permittee-responsible stream and wetland mitigation. Each mitigation credit sale is considered a separate performance obligation. Revenue is recognized at the point in time that control of each mitigation credit transfers to the customer. Fluctuations in revenue from period to period generally result from changes in customer demand. Under the permittee-responsible stream and wetland mitigation model, the contracts are generally structured as a management fee agreement under which Mitigation Resources is reimbursed for all costs incurred in performing the required mitigation plus an agreed profit percentage or a fixed fee. The mitigation services provided is the performance obligation and is accounted for as a series. Performance momentarily creates an asset that the customer simultaneously receives and consumes; therefore, control is transferred to the customer as work is completed. Consistent with the conclusion that the customer simultaneously receives and

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consumes the benefits provided, an input-based measure of progress is appropriate. As each month of service is completed, revenue is recognized for the amount of actual costs incurred, plus the management fee or fixed fee. Fluctuations in revenue from period to period result from changes in customer demand primarily due to increases and decreases in activity levels of individual contracts and variances in reimbursable costs.

**Significant Judgments**

The Company's contracts with its customers contain different types of variable consideration including, but not limited to, management fees that adjust based on volumes or MMBtu delivered, however, the terms of these variable payments relate specifically to the Company's efforts to satisfy one or more, but not all of, the performance obligations (or to a specific outcome from satisfying the performance obligations) in the contract. Therefore, the Company allocates each variable payment (and subsequent changes to that payment) entirely to the specific performance obligation to which it relates. Management fees, as well as general and administrative fees, are also adjusted based on changes in specified indices (e.g., CPI) to compensate for general inflation changes. Index adjustments, if applicable, are effective prospectively.

Recognition of revenue and recognition of profit related to the Caddo Creek contract requires the use of assumptions and estimates related to the total contract value, the total cost at completion, and the measurement of progress towards completion of the performance obligation. Due to the nature of the contract, developing the estimated total contract value and total cost at completion requires the use of significant judgment. The total contract value includes variable consideration. The Company includes variable consideration in the transaction price at the most likely amount to be earned, based upon the Company's assessment of expected performance. The Company records these amounts only to the extent it is probable that a significant reversal of cumulative revenue recognized will not occur when the uncertainty associated with the variable consideration is resolved.

**Cost Reimbursement**

Certain contracts include reimbursement from customers of actual costs incurred for the purchase of supplies, equipment and services in accordance with contractual terms. Such reimbursable revenue is variable and subject to uncertainty, as the amounts received and timing thereof is highly dependent on factors outside of the Company's control. Accordingly, reimbursable revenue is fully constrained and not recognized until the uncertainty is resolved, which typically occurs when the related costs are incurred on behalf of a customer. The Company is considered a principal in such transactions and records the associated revenue at the gross amount billed to the customer with the related costs recorded as an expense within cost of sales.

**Prior Period Performance Obligations**

The Company records royalty income in the month production is delivered to the purchaser. As a mineral owner the Company has limited visibility into when new wells start producing and production statements may not be received for 30 to 90 days or more after the date production is delivered. As a result, the Company is required to estimate the amount of production delivered to the purchaser of the product and the price that will be received for the sale of the product. The expected sales volumes and prices for these properties are estimated and recorded in "Trade accounts receivable" in the accompanying Consolidated Balance Sheets. The difference between the Company's estimates and the actual amounts received is recorded in the month that payment is received from the third-party lessee. During 2022, royalty income of $2.1 million was recognized for a settlement related to the Company's ownership interest in certain mineral rights. During 2021, the Company recognized $1.8 million of variable consideration that was previously constrained due to uncertainty of collectability.

**Disaggregation of Revenue**

In accordance with ASC 606-10-50, the Company disaggregates revenue from contracts with customers into major goods and service lines and timing of transfer of goods and services. The Company determined that disaggregating revenue into these categories achieves the disclosure objective of depicting how the nature, amount, timing, and uncertainty of revenue and cash flows are affected by economic factors. The Company's business consists of the Coal Mining, NAMining and Minerals Management segments as well as Unallocated Items. See Note 15 to the Consolidated Financial Statements for further discussion of segment reporting.

------

<u>[**Table of Contents**](#iaf3a05f346f8475da90341366c3f6933_133)</u>

**NOTES TO CONSOLIDATED FINANCIAL STATEMENTS**

**NACCO INDUSTRIES, INC. AND SUBSIDIARIES**

*(Tabular Amounts in Thousands, Except Per Share, Percentage Data and Oil and Gas Disclosures)*

The following table disaggregates revenue by major sources for the years ended December 31:

---

| | | |
|:---|:---|:---|
| <u>Major Goods/Service Lines</u> | **2022** | 2021 |
| Coal Mining | $**95204** | $82831 |
| NAMining | **85664** | 78944 |
| Minerals Management | **60242** | 31003 |
| Unallocated Items | **2952** | 4695 |
| Eliminations | **(2343)** | (5627) |
| Total revenues | $**241719** | $191846 |
| <u>Timing of Revenue Recognition</u> |  |  |
| Goods transferred at a point in time | $**92842** | $80515 |
| Services transferred over time | **148877** | 111331 |
| Total revenues | $**241719** | $191846 |

---

**Contract Balances**

The opening and closing balances of the Company's current and long-term contract assets and liabilities and receivables are as follows:

---

| | | | | | |
|:---|:---|:---|:---|:---|:---|
| | Contract balances | Contract balances | Contract balances | Contract balances | Contract balances |
| | Trade accounts receivable | Contract asset<br>(current) | Contract asset<br>(long-term) | Contract liability (current) | Contract liability (long-term) |
| Balance at January 1, 2022 | $25667 | $— | $5985 | $4082 | $1453 |
| **Balance at December 31, 2022** | **37940** | **409** | **5985** | **833** | **1709** |
| Increase (decrease) | $12273 | $409 | $— | $(3249) | $256 |

---

As described above, the Company enters into royalty contracts that grant exclusive right, title, and interest in and to minerals.

The transaction price consists of a variable sales-based royalty and, in certain arrangements, a fixed component in the form of

an up-front lease bonus payment. The timing of the payment of the fixed portion of the transaction price is upfront, however,

the performance obligation is satisfied over the primary term of the contract, which is generally three to five years. Therefore, at the time any such up-front payment is received, a contract liability is recorded which represents deferred revenue. The amount of royalty revenue recognized in the years ended December 31, 2022 and December 31, 2021 that was included in the opening contract liability was $1.0 million and $1.4 million, respectively. This revenue consists of up-front lease bonus payments received under royalty contracts that are recognized over the primary term of the royalty contracts, which are generally three to five years.

The Company expects to recognize $0.8 million in 2023, $1.5 million in 2024, $0.2 million in 2025, and de minimis amounts in 2026 and 2027 related to the contract liability remaining at December 31, 2022. The difference between the opening and closing balances of the Company's contract balances results from the timing difference between the Company's performance and the customer's payment.

The Company has no contract assets recognized from the costs to obtain or fulfill a contract with a customer.

------

<u>[**Table of Contents**](#iaf3a05f346f8475da90341366c3f6933_133)</u>

**NOTES TO CONSOLIDATED FINANCIAL STATEMENTS**

**NACCO INDUSTRIES, INC. AND SUBSIDIARIES**

*(Tabular Amounts in Thousands, Except Per Share, Percentage Data and Oil and Gas Disclosures)*

**NOTE 4—Inventories** 

Inventories are summarized as follows:

---

| | | |
|:---|:---|:---|
| | December 31 | December 31 |
| | **2022** | 2021 |
| Coal | $**27927** | $19352 |
| Mining supplies | **43561** | 34733 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Total inventories | $**71488** | $54085 |

---

The weighted average method is used for inventory valuation.

**NOTE 5—Property, Plant and Equipment, Net** 

Property, plant and equipment, net includes the following:

---

| | | |
|:---|:---|:---|
| | **December 31** | **December 31** |
| | **2022** | 2021 |
| Coal lands and real estate | $**60277** | $52011 |
| Mineral interests | **31436** | 19512 |
| Plant and equipment | **290511** | 264110 |
| Property, plant and equipment, at cost | **382224** | 335633 |
| Less allowances for depreciation, depletion and amortization | **164272** | 142466 |
|  | $**217952** | $193167 |

---

Total depreciation, depletion and amortization expense on property, plant and equipment was $23.1 million and $19.5 million during 2022 and 2021, respectively.

**NOTE 6—Intangible Assets** 

The Company has a coal supply agreement intangible asset which is subject to amortization based on units of production over the term of the lignite sales agreement which expires in 2032. The gross and net balances are set forth in the following table:

---

| | | | |
|:---|:---|:---|:---|
| | **Gross Carrying <br>Amount** | **Accumulated <br>Amortization** | **Net <br>Balance** |
| **Balance at December 31, 2022** | | | |
| &nbsp;&nbsp;&nbsp;&nbsp;**Coal supply agreement** | $**84200** | $**(56145)** | $**28055** |
| Balance at December 31, 2021 |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Coal supply agreement | $84200 | $(52426) | $31774 |

---

Amortization expense for intangible assets was $3.7 million and $3.6 million in 2022 and 2021, respectively.

Expected annual amortization expense of the coal supply agreement is $3.2 million in 2023, $3.1 million in 2024 and $3.0 million in 2025 through 2027.

**NOTE 7—Asset Retirement Obligations** 

The Company's obligations associated with the retirement of long-lived assets are recognized at fair value at the time the legal

obligations are incurred. Upon initial recognition of a liability, a corresponding amount is capitalized as part of the carrying

value of the related long-lived asset and is depreciated either by the straight-line method or the units-of-production method. The

liability is accreted each period until the liability is settled, at which time the liability is removed. If the liability is settled for an amount other than the recorded amount, a gain or loss is recognized.

------

<u>[**Table of Contents**](#iaf3a05f346f8475da90341366c3f6933_133)</u>

**NOTES TO CONSOLIDATED FINANCIAL STATEMENTS**

**NACCO INDUSTRIES, INC. AND SUBSIDIARIES**

*(Tabular Amounts in Thousands, Except Per Share, Percentage Data and Oil and Gas Disclosures)*

The Company's asset retirement obligations are principally for costs to close its surface mines and reclaim the land it has disturbed as a result of its normal mining activities as well as for costs to dismantle certain mining equipment at the end of the life of the mine. Management's estimate involves a high degree of subjectivity. In particular, the obligation's fair value is determined using a discounted cash flow technique and is based upon mining permit requirements and various assumptions including credit adjusted risk-free-rates, estimates of disturbed acreage, life of the mine, estimated reclamation costs, the application of various environmental laws and regulation and assumptions regarding equipment productivity. The Company reviews its asset retirement obligations at each mine site at least annually and makes necessary adjustments for permit changes and for revisions of estimates of the timing and extent of reclamation activities and cost estimates.

The accretion of the liability is being recognized over the estimated life of each individual asset retirement obligation and is recorded in the line Cost of sales in the accompanying Consolidated Statements of Operations. The associated asset is recorded in Property, Plant and Equipment, net in the accompanying Consolidated Balance Sheets. The depreciation of the asset is recorded in the line Cost of sales in the accompanying Consolidated Statements of Operations.

A reconciliation of the Company's beginning and ending aggregate carrying amount of the asset retirement obligations are as follows:

---

| | | | |
|:---|:---|:---|:---|
| | Coal Mining | Unallocated Items | NACCO <br>Consolidated |
| Balance at January 1, 2021 | $25040 | $16692 | $41732 |
| &nbsp;&nbsp;&nbsp;Liabilities settled during the period | (184) | (869) | (1053) |
| &nbsp;&nbsp;&nbsp;Accretion expense | 1996 | 1304 | 3300 |
| &nbsp;&nbsp;&nbsp;Revision of estimated cash flows | 46 | (74) | (28) |
| Balance at December 31, 2021 | $26898 | $17053 | $43951 |
| &nbsp;&nbsp;&nbsp;Liabilities settled during the period | **(223)** | **(956)** | **(1179)** |
| &nbsp;&nbsp;&nbsp;Accretion expense | **2190** | **1332** | **3522** |
| &nbsp;&nbsp;&nbsp;Revision of estimated cash flows | **(405)** | **113** | **(292)** |
| **Balance at December 31, 2022** | $**28460** | $**17542** | $**46002** |

---

Bellaire Corporation ("Bellaire") is a non-operating subsidiary of the Company with legacy liabilities relating to closed mining operations, primarily former Eastern U.S. underground coal mining operations. These legacy liabilities include obligations for water treatment and other environmental remediation that arose as part of the normal course of closing these underground mining operations. Since Bellaire's properties are no longer active operations, no associated asset has been capitalized.

Prior to 2021, Bellaire established a $5.0 million Mine Water Treatment Trust to provide a financial assurance mechanism in order to assure the long-term treatment of post-mining discharges. The fair value of Bellaire's Mine Water Treatment assets, which are recognized as a component of Other non-current assets on the Consolidated Balance Sheets, are $9.9 million and $12.3 million at December 31, 2022 and December 31, 2021, respectively, and are legally restricted for purposes of settling the Bellaire asset retirement obligation. See Note 9 for further discussion of the Mine Water Treatment Trust.

------

<u>[**Table of Contents**](#iaf3a05f346f8475da90341366c3f6933_133)</u>

**NOTES TO CONSOLIDATED FINANCIAL STATEMENTS**

**NACCO INDUSTRIES, INC. AND SUBSIDIARIES**

*(Tabular Amounts in Thousands, Except Per Share, Percentage Data and Oil and Gas Disclosures)*

**NOTE 8—Current and Long-Term Financing** 

Financing arrangements are obtained and maintained at the subsidiary level. NACCO has not guaranteed any borrowings of its subsidiaries.

The following table summarizes the Company's available and outstanding borrowings:

---

| | | |
|:---|:---|:---|
| | December 31 | December 31 |
| | **2022** | 2021 |
| Total outstanding borrowings of NACoal: |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Revolving credit agreement | $**—** | $4000 |
| &nbsp;&nbsp;&nbsp;&nbsp;Other debt | **19668** | 16710 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Total debt outstanding | $**19668** | $20710 |
| &nbsp;&nbsp;&nbsp;&nbsp;Current portion of borrowings outstanding | $**3649** | $2527 |
| &nbsp;&nbsp;&nbsp;&nbsp;Long-term portion of borrowings outstanding | **16019** | 18183 |
|  | $**19668** | $20710 |
| &nbsp;&nbsp;&nbsp;&nbsp;Total available borrowings, net of limitations, under revolving credit agreement | $**116285** | $120231 |
| &nbsp;&nbsp;&nbsp;&nbsp;Unused revolving credit agreement | $**116285** | $116231 |
| &nbsp;&nbsp;&nbsp;&nbsp;Weighted average stated interest rate on total borrowings | **3.9%** | 3.7% |

---

Annual maturities of total debt, excluding leases, are as follows:

---

| | |
|:---|:---|
| 2023 | 2873 |
| 2024 | 2497 |
| 2025 | 1620 |
| 2026 | 5955 |
| 2027 | 236 |
| Thereafter | 5692 |
|  | $18873 |

---

Interest paid on total debt was $2.0 million and $1.6 million during 2022 and 2021, respectively. Deferred financing fees of $1.8 million were capitalized during 2021.

NACoal has a secured revolving line of credit of up to $150.0 million (the "NACoal Facility") that was refinanced during 2021 and expires in November 2025. There were no borrowings outstanding under the NACoal Facility at December 31, 2022. At December 31, 2022, the excess availability under the NACoal Facility was $116.3 million, which reflects a reduction for outstanding letters of credit of $33.7 million.

The NACoal Facility has performance-based pricing, which sets interest rates based upon NACoal achieving various levels of debt to EBITDA ratios, as defined in the NACoal Facility. Borrowings bear interest at a floating rate plus a margin based on the level of debt to EBITDA ratio achieved. The applicable margins, effective December 31, 2022, for base rate and LIBOR loans were 1.23% and 2.23%, respectively. The NACoal Facility has a commitment fee which is based upon achieving various levels of debt to EBITDA ratios. The commitment fee was 0.34% on the unused commitment at December 31, 2022. During the year ended December 31, 2022, the average borrowing under the NACoal Facility was $2.0 million. The weighted-average annual interest rate, including the floating rate margin, was 2.54% and 4.50% at December 31, 2022 and December 31, 2021, respectively.

The NACoal Facility contains restrictive covenants, which require, among other things, NACoal to maintain a maximum net debt to EBITDA ratio of 2.75 to 1.00 and an interest coverage ratio of not less than 4.00 to 1.00. The NACoal Facility provides the ability to make loans, dividends and advances to NACCO, with some restrictions based on maintaining a maximum debt to EBITDA ratio of 1.50 to 1.00, or if greater than 1.50 to 1.00, a Fixed Charge Coverage Ratio of 1.10 to 1.00, in conjunction

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<u>[**Table of Contents**](#iaf3a05f346f8475da90341366c3f6933_133)</u>

**NOTES TO CONSOLIDATED FINANCIAL STATEMENTS**

**NACCO INDUSTRIES, INC. AND SUBSIDIARIES**

*(Tabular Amounts in Thousands, Except Per Share, Percentage Data and Oil and Gas Disclosures)*

with maintaining unused availability thresholds of borrowing capacity, as defined in the NACoal Facility, of $15.0 million. At December 31, 2022, NACoal was in compliance with all financial covenants in the NACoal Facility.

The obligations under the NACoal Facility are guaranteed by certain of NACoal's direct and indirect, existing and future

domestic subsidiaries, and is secured by certain assets of NACoal and the guarantors, subject to customary exceptions and

limitations.

NACoal has a demand note payable to Coteau, one of the unconsolidated subsidiaries, which bears interest based on the applicable quarterly federal short-term interest rate as announced from time to time by the Internal Revenue Service. At December 31, 2022 and 2021, the balance of the note was $5.7 million and $2.6 million and the interest rate was 3.36% and 0.18%, respectively.

NACoal has seven notes payable that are secured by twelve specified units of equipment, bear interest at a weighted average rate of 4.11%, and expire at various dates through 2027. One note includes a principal payment of $4.4 million at the end of the term on December 15, 2026. At December 31, 2022 and 2021, the outstanding balances of the notes were $13.2 million and $13.8 million, respectively.

**NOTE 9—Fair Value Disclosure** 

**Recurring Fair Value Measurements**: The following table presents the Company's assets accounted for at fair value on a recurring basis:

---

| | | | | |
|:---|:---|:---|:---|:---|
| | | Fair Value Measurements at Reporting Date Using | Fair Value Measurements at Reporting Date Using | Fair Value Measurements at Reporting Date Using |
| | | Quoted Prices in | | Significant |
| | | Active Markets for | Significant Other | Unobservable |
| | | Identical Assets | Observable Inputs | Inputs |
| Description | December 31, 2022 | (Level 1) | (Level 2) | (Level 3) |
| Assets: |  |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Equity securities | $**15534** | $**15534** | $**—** | $**—** |
|  | $**15534** | $**15534** | $**—** | $**—** |

---

---

| | | | | |
|:---|:---|:---|:---|:---|
| | | Fair Value Measurements at Reporting Date Using | Fair Value Measurements at Reporting Date Using | Fair Value Measurements at Reporting Date Using |
| | | Quoted Prices in | | Significant |
| | | Active Markets for | Significant Other | Unobservable |
| | | Identical Assets | Observable Inputs | Inputs |
| Description | December 31, 2021 | (Level 1) | (Level 2) | (Level 3) |
| Assets: |  |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Equity securities | $16070 | $16070 | $— | $— |
|  | $16070 | $16070 | $— | $— |

---

Bellaire's Mine Water Treatment Trust invests in available for sale securities that are reported at fair value based upon quoted market prices in active markets for identical assets; therefore, they are classified as Level 1 within the fair value hierarchy. The Mine Water Treatment Trust realized a loss of $2.2 million and a gain of $1.7 million in the years ended December 31, 2022 and 2021, respectively. See Note 7 for further discussion of Bellaire's Mine Water Treatment Trust.

Prior to 2021, the Company invested $2.0 million in equity securities of a public company with a diversified portfolio of royalty producing mineral interests. The investment is reported at fair value based upon quoted market prices in active markets for identical assets; therefore, it is classified as Level 1 within the fair value hierarchy. The Company recognized a gain of $1.9 million and $1.7 million in the years ended December 31, 2022 and 2021, related to the investment in these equity securities. The change in fair value of equity securities is reported on the line Loss (gain) on equity securities in the Other (income) expense section of the Consolidated Statements of Operations.

There were no transfers into or out of Levels 1, 2 or 3 during the year ended December 31, 2022.

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<u>[**Table of Contents**](#iaf3a05f346f8475da90341366c3f6933_133)</u>

**NOTES TO CONSOLIDATED FINANCIAL STATEMENTS**

**NACCO INDUSTRIES, INC. AND SUBSIDIARIES**

*(Tabular Amounts in Thousands, Except Per Share, Percentage Data and Oil and Gas Disclosures)*

**Nonrecurring Fair Value Measurements:** The Company recorded the estimated fair value of an office building during the second quarter of 2022. In determining the $4.1 million fair value of the office building, the Company engaged an independent real estate appraiser to appraise the property utilizing observed sales transactions for similar assets as well as consideration of an income approach; therefore, it is classified as Level 2 within the fair value hierarchy. The office building is included in Property, plant and equipment, net in the accompanying Consolidated Balance Sheets.

The Company regularly performs reviews of potential future development projects and identified certain legacy assets where future development is unlikely. As a result, the Company estimated the fair value of the assets using unobservable inputs, which are classified as Level 3 inputs. The long-lived assets, which included land, prepaid royalties and capitalized leasehold costs, were written off to zero in the third quarter of 2022 and resulted in non-cash asset impairment charges of $3.9 million in the Minerals Management segment. The impairment charges are reported on the line Asset impairment charges in the Consolidated Statements of Operations.

**Other Fair Value Measurement Disclosures:** The carrying amounts of cash and cash equivalents, accounts receivable and accounts payable approximate fair value due to the short-term maturities of these instruments. The fair values of revolving credit agreements and long-term debt, excluding finance leases, were determined using current rates offered for similar obligations taking into account subsidiary credit risk, which is Level 2 as defined in the fair value hierarchy. The fair value and the book value of revolving credit agreements and long-term debt, excluding finance leases, was $18.1 million and $18.9 million, respectively, at December 31, 2022 and $20.5 million and $20.4 million, respectively, at December 31, 2021.

Financial instruments that potentially subject the Company to concentration of credit risk consist principally of accounts receivable. Under its mining contracts, the Company recognizes revenue and a related receivable as coal or other aggregates are delivered or predevelopment services are provided. These mining contracts provide for monthly settlements. The Company's significant credit concentration is uncollateralized; however, historically minimal credit losses have been incurred. To further reduce credit risk associated with accounts receivable, the Company performs periodic credit evaluations of its customers, but does not generally require advance payments or collateral.

**NOTE 10—Leases**

The Company recognizes right-of-use assets ("ROU assets") and lease liabilities for operating leases of real estate, mining and other equipment that expire at various dates through 2032. The majority of the Company's leases are operating leases. NACCO does not recognize leases with a term of 12 months or less on the balance sheet. Instead, the Company recognizes the related lease expense on a straight-line basis over the lease term. The Company accounts for lease and non-lease components as a single lease component. The Company's lease agreements do not contain lease payments that depend on an index or a rate, as such, minimum lease payments do not include variable lease payments.

Leased assets and liabilities include the following at December 31:

---

| | | | |
|:---|:---|:---|:---|
| **Description** | **Location** | **2022** | **2021** |
| **Assets** |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Operating | Operating lease right-of-use assets | $**6419** | $8911 |
| &nbsp;&nbsp;&nbsp;&nbsp;Finance | Property, plant and equipment, net <sup>(a)</sup> | **843** | 334 |
| **Liabilities** |  |  |  |
| Current |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Operating | Other current liabilities | $**1039** | $1463 |
| &nbsp;&nbsp;&nbsp;&nbsp;Finance | Current maturities of long-term debt | **776** | 150 |
| Non-current |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Operating | Operating lease liabilities | $**7528** | $9733 |
| &nbsp;&nbsp;&nbsp;&nbsp;Finance | Long-term debt | **19** | 190 |

---

<sup>(a)</sup> Finance leased assets are recorded net of accumulated amortization of $0.2 million and $0.3 million as of December 31, 2022 and December 31, 2021, respectively.

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<u>[**Table of Contents**](#iaf3a05f346f8475da90341366c3f6933_133)</u>

**NOTES TO CONSOLIDATED FINANCIAL STATEMENTS**

**NACCO INDUSTRIES, INC. AND SUBSIDIARIES**

*(Tabular Amounts in Thousands, Except Per Share, Percentage Data and Oil and Gas Disclosures)*

The components of lease expense for the years ended December 31 are as follows:

---

| | | | |
|:---|:---|:---|:---|
| **Description** | **Location** | **2022** | 2021 |
| **Lease expense** |  |  |  |
| Operating lease cost | Selling, general and administrative expenses | $**1881** | $2122 |
| Finance lease cost: |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Amortization of leased assets | Cost of sales | **128** | 220 |
| &nbsp;&nbsp;&nbsp;&nbsp;Interest on lease liabilities | Interest expense | **13** | 31 |
| Variable lease expense | Selling, general and administrative expenses | **534** | 571 |
| Short-term lease expense | Selling, general and administrative expenses | **3434** | 1176 |
| Total lease expense |  | $**5990** | $4120 |

---

Future minimum finance and operating lease payments were as follows at December 31, 2022:

---

| | | | |
|:---|:---|:---|:---|
| | **Finance Leases** | **Operating Leases** | **Total** |
| 2023 | $778 | $1599 | $2377 |
| 2024 | 12 | 1474 | 1486 |
| 2025 | 7 | 1283 | 1290 |
| 2026 |  | 1314 | 1314 |
| 2027 |  | 1345 | 1345 |
| Subsequent to 2027 |  | 4177 | 4177 |
| Total minimum lease payments | 797 | 11192 | $11989 |
| Amounts representing interest | 2 | 2625 |  |
| Present value of net minimum lease payments | $795 | $8567 |  |

---

As most of the Company's leases do not provide an implicit rate, the Company determines the incremental borrowing rate based on the information available at the lease commencement date in determining the present value of lease payments. The Company considers its credit rating and the current economic environment in determining this collateralized rate. The assumptions used in accounting for ASC 842 for the years ended December 31 are as follows:

---

| | | |
|:---|:---|:---|
| | **2022** | 2021 |
| **Weighted average remaining lease term (years)** |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Operating | **7.66** | 8.38 |
| &nbsp;&nbsp;&nbsp;&nbsp;Finance | **1.41** | 2.44 |
| **Weighted average discount rate** |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Operating | **7.13%** | 7.08% |
| &nbsp;&nbsp;&nbsp;&nbsp;Finance | **3.11%** | 4.16% |

---

The following table details cash paid for amounts included in the measurement of lease liabilities for the years ended December 31:

---

| | | |
|:---|:---|:---|
| | **2022** | 2021 |
| Operating cash flows from operating leases | $**2097** | $2260 |
| Operating cash flows from finance leases | **13** | 31 |
| Financing cash flows from finance leases | **183** | 275 |

---

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<u>[**Table of Contents**](#iaf3a05f346f8475da90341366c3f6933_133)</u>

**NOTES TO CONSOLIDATED FINANCIAL STATEMENTS**

**NACCO INDUSTRIES, INC. AND SUBSIDIARIES**

*(Tabular Amounts in Thousands, Except Per Share, Percentage Data and Oil and Gas Disclosures)*

**NOTE 11—Contingencies** 

Various legal and regulatory proceedings and claims have been or may be asserted against NACCO and certain subsidiaries relating to the conduct of their businesses. These proceedings and claims are incidental to the ordinary course of business of the Company. Management believes that it has meritorious defenses and will vigorously defend the Company in these actions. Any costs that management estimates will be paid as a result of these claims are accrued when the liability is considered probable and the amount can be reasonably estimated. If a range of amounts can be reasonably estimated and no amount within the range is a better estimate than any other amount, then the minimum of the range is accrued. The Company does not accrue liabilities when the likelihood that the liability has been incurred is probable but the amount cannot be reasonably estimated or when the liability is believed to be only reasonably possible or remote. For contingencies where an unfavorable outcome is probable or reasonably possible and which are material, the Company discloses the nature of the contingency and, in some circumstances, an estimate of the possible loss.

These matters are subject to inherent uncertainties, and unfavorable rulings could occur. If an unfavorable ruling were to occur, there exists the possibility of an adverse impact on the Company's financial position, results of operations and cash flows of the period in which the ruling occurs, or in future periods.

**NOTE 12—Stockholders' Equity and Earnings Per Share** 

NACCO Industries, Inc. Class A common stock is traded on the New York Stock Exchange under the ticker symbol "NC." Because of transfer restrictions on Class B common stock, no trading market has developed, or is expected to develop, for the Company's Class B common stock. The Class B common stock is convertible into Class A common stock on a one-for-one basis at any time at the request of the holder. The Company's Class A common stock and Class B common stock have the same cash dividend rights per share. As the liquidation and dividend rights are identical, any distribution of earnings would be allocated to Class A and Class B stockholders on a proportionate basis, and accordingly the net income per share for each class of common stock is identical. The Class A common stock has one vote per share and the Class B common stock has ten votes per share. The total number of authorized shares of Class A common stock and Class B common stock at December 31, 2022 was 25,000,000 shares and 6,756,176 shares, respectively. Treasury shares of Class A common stock totaling 2,434,769 and 2,600,661 at December 31, 2022 and 2021, respectively, have been deducted from shares outstanding.

**Stock Repurchase Program:** On November 10, 2021, the Company's Board of Directors approved a stock purchase program ("2021 Stock Repurchase Program") providing for the purchase of up to $20.0 million of the Company's outstanding Class A common stock through December 31, 2023. The timing and amount of any repurchases under the 2021 Stock Repurchase Program are determined at the discretion of the Company's management based on a number of factors, including the availability of capital, other capital allocation alternatives, market conditions for the Company's Class A common stock and other legal and contractual restrictions. The 2021 Stock Repurchase Program does not require the Company to acquire any specific number of shares and may be modified, suspended, extended or terminated by the Company without prior notice and may be executed through open market purchases, privately negotiated transactions or otherwise. All or part of the repurchases under the 2021 Stock Repurchase Program may be implemented under a Rule 10b5-1 trading plan, which would allow repurchases under pre-set terms at times when the Company might otherwise be restricted from doing so under applicable securities laws. There were no stock repurchases in 2022 or 2021 under the 2021 Stock Repurchase Program.

**Stock Compensation:** See Note 2 for a discussion of the Company's restricted stock awards.

**Earnings per Share:** The weighted average number of shares of Class A common stock and Class B common stock outstanding used to calculate basic and diluted earnings per share were as follows:

---

| | | |
|:---|:---|:---|
| | **2022** | 2021 |
| Basic weighted average shares outstanding | **7312** | 7146 |
| Dilutive effect of restricted stock awards | **61** | 44 |
| Diluted weighted average shares outstanding | **7373** | 7190 |
| Basic earnings per share | $**10.14** | $6.73 |
| Diluted earnings per share | $**10.06** | $6.69 |

---

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<u>[**Table of Contents**](#iaf3a05f346f8475da90341366c3f6933_133)</u>

**NOTES TO CONSOLIDATED FINANCIAL STATEMENTS**

**NACCO INDUSTRIES, INC. AND SUBSIDIARIES**

*(Tabular Amounts in Thousands, Except Per Share, Percentage Data and Oil and Gas Disclosures)*

**NOTE 13—Income Taxes** 

The Company provides for income taxes and the related accounts under the asset and liability method. Deferred tax assets and liabilities are determined based on the difference between the financial statement and tax bases of assets and liabilities using enacted tax rates expected to be in effect during the year in which the basis differences reverse. Valuation allowances are established when management determines it is more likely than not that some portion, or all, of the deferred tax assets will not be realized.

The components of Income before income tax provision and the Income tax provision for the years ended December 31 are as follows:

---

| | | |
|:---|:---|:---|
| | **2022** | 2021 |
| **Income before income tax provision** |  |  |
| Domestic | $**87975** | $57019 |
| Foreign | **(252)** | (169) |
|  | $**87723** | $56850 |
| **Income tax provision** |  |  |
| Current income tax provision (benefit): |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Federal | $**20761** | $10870 |
| &nbsp;&nbsp;&nbsp;&nbsp;State | **1328** | 1443 |
| &nbsp;&nbsp;&nbsp;&nbsp;Foreign | **(53)** | (35) |
| &nbsp;&nbsp;&nbsp;&nbsp;Total current | **22036** | 12278 |
| Deferred income tax (benefit) provision: |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Federal | **(8887)** | (4449) |
| &nbsp;&nbsp;&nbsp;&nbsp;State | **416** | 896 |
| &nbsp;&nbsp;&nbsp;&nbsp;Total deferred | **(8471)** | (3553) |
|  | $**13565** | $8725 |

---

The Company made income tax payments of $23.4 million and $11.5 million during 2022 and 2021, respectively. During the same periods, income tax refunds totaled $0.1 million and $2.6 million, respectively.

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<u>[**Table of Contents**](#iaf3a05f346f8475da90341366c3f6933_133)</u>

**NOTES TO CONSOLIDATED FINANCIAL STATEMENTS**

**NACCO INDUSTRIES, INC. AND SUBSIDIARIES**

*(Tabular Amounts in Thousands, Except Per Share, Percentage Data and Oil and Gas Disclosures)*

The provision for income taxes differs from the amount computed by applying the statutory federal income tax rate to income before the provision for income taxes. A reconciliation of the federal statutory and effective income tax rate for the years ended December 31 is as follows:

---

| | | |
|:---|:---|:---|
| | **2022** | 2021 |
| **Income before income tax provision** | $**87723** | $56850 |
| Statutory taxes at 21.0% | $**18422** | $11939 |
| &nbsp;&nbsp;&nbsp;&nbsp;State and local income taxes | **1629** | 1890 |
| &nbsp;&nbsp;&nbsp;&nbsp;Non-deductible expenses | **745** | 725 |
| &nbsp;&nbsp;&nbsp;&nbsp;Percentage depletion | **(4866)** | (6245) |
| &nbsp;&nbsp;&nbsp;&nbsp;R&D and other federal credits | **(300)** | (363) |
| &nbsp;&nbsp;&nbsp;&nbsp;Settlements and uncertain tax positions | **(787)** | 166 |
| &nbsp;&nbsp;&nbsp;&nbsp;Other, net | **(1278)** | 613 |
| Income tax provision | $**13565** | $8725 |
| Effective income tax rate | **15.5%** | 15.3% |

---

The Company recorded income tax expense of $13.6 million for the year ended December 31, 2022 on income before income tax of $87.7 million, or 15.5%, compared to income tax expense of $8.7 million on income before income tax of $56.9 million, or 15.3%, for the year ended December 31, 2021.

The income tax provision for the year ended December 31, 2022 includes $1.5 million of discrete tax benefits, primarily from the reversal of uncertain tax positions as a result of the conclusion of the IRS examination of the Company's 2013, 2014, 2015 and 2016 federal income tax returns. Excluding the $1.5 million of discrete tax benefits, the effective income tax rate in 2022 was 17.1%. The year ended December 31, 2021 included $1.0 million of discrete tax expense. Excluding the $1.0 million of discrete tax expense, the effective income tax rate in 2021 was 13.5%.

The increase in the effective income tax rate for 2022 compared to 2021, excluding the impact of discrete items, is primarily due to an increase in earnings at entities that do not qualify for percentage depletion. The benefit from percentage depletion is not directly related to the amount of pre-tax income recorded in a period.

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<u>[**Table of Contents**](#iaf3a05f346f8475da90341366c3f6933_133)</u>

**NOTES TO CONSOLIDATED FINANCIAL STATEMENTS**

**NACCO INDUSTRIES, INC. AND SUBSIDIARIES**

*(Tabular Amounts in Thousands, Except Per Share, Percentage Data and Oil and Gas Disclosures)*

A detailed summary of the total deferred tax assets and liabilities in the Company's Consolidated Balance Sheets resulting from differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax purposes is as follows:

---

| | | |
|:---|:---|:---|
| | December 31 | December 31 |
| | **2022** | 2021 |
| Deferred tax assets |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Lease liabilities | $**21880** | $24500 |
| &nbsp;&nbsp;&nbsp;&nbsp;Tax carryforwards | **12398** | 13837 |
| &nbsp;&nbsp;&nbsp;&nbsp;Inventories | **5571** | 4522 |
| &nbsp;&nbsp;&nbsp;&nbsp;Accrued liabilities | **8176** | 9243 |
| &nbsp;&nbsp;&nbsp;&nbsp;Employee benefits | **3086** | 3496 |
| &nbsp;&nbsp;&nbsp;&nbsp;Land valuation adjustment | **6261** | 5988 |
| &nbsp;&nbsp;&nbsp;&nbsp;Other | **6850** | 6527 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Total deferred tax assets | **64222** | 68113 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Less: Valuation allowance | **11809** | 11695 |
|  | **52413** | 56418 |
| Deferred tax liabilities |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Lease right-of-use assets | **21880** | 24500 |
| &nbsp;&nbsp;&nbsp;&nbsp;Depreciation and depletion | **19665** | 25851 |
| &nbsp;&nbsp;&nbsp;&nbsp;Partnership investment - development costs | **6069** | 9840 |
| &nbsp;&nbsp;&nbsp;&nbsp;Accrued pension benefits | **10921** | 10941 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Total deferred tax liabilities | **58535** | 71132 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Net deferred liability | $**(6122)** | $(14714) |

---

The following table summarizes the tax carryforwards and associated carryforward periods and related valuation allowances where the Company has determined that realization is uncertain:

---

| | | | |
|:---|:---|:---|:---|
| | **December 31, 2022** | **December 31, 2022** | **December 31, 2022** |
| | Net deferred tax <br>asset | Valuation <br>allowance | Carryforwards <br>expire during: |
| State net operating loss | $**15347** | $**14422** | **2023-2042** |

---

---

| | | | |
|:---|:---|:---|:---|
| | December 31, 2021 | December 31, 2021 | December 31, 2021 |
| | Net deferred tax <br>asset | Valuation <br>allowance | Carryforwards <br>expire during: |
| State net operating loss | $17516 | $14694 | 2022-2041 |

---

The Company has a valuation allowance for certain state and foreign deferred tax assets. Based upon the review of historical earnings and the relevant expiration of carryforwards, including utilization limitations in the various state taxing jurisdictions, the Company believes the valuation allowances are appropriate and does not expect to release valuation allowances within the next twelve months that would have a significant effect on the Company's financial position or results of operations.

Since 2021, the Company has participated in a voluntary program with the IRS called Compliance Assurance Process ("CAP"). The objective of CAP is to contemporaneously work with the IRS to achieve federal tax compliance and resolve all or most issues prior to the filing of the tax return. In general, the Company operates in taxing jurisdictions that provide a statute of limitations period ranging from three to five years for the taxing authorities to review the applicable tax filings. The tax returns of the Company and certain of its subsidiaries are under routine examination by various taxing authorities. The Company has not been informed of any material assessment for which an accrual has not been previously provided and the Company would

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**NOTES TO CONSOLIDATED FINANCIAL STATEMENTS**

**NACCO INDUSTRIES, INC. AND SUBSIDIARIES**

*(Tabular Amounts in Thousands, Except Per Share, Percentage Data and Oil and Gas Disclosures)*

vigorously contest any material assessment. Management believes any potential adjustment would not materially affect the Company's financial condition or results of operations.

The following is a reconciliation of the Company's total gross unrecognized tax benefits, defined as the aggregate tax effect of differences between tax return positions and the benefits recognized in the financial statements for the years ended December 31, 2022 and 2021. Approximately $5.5 million and $6.4 million of the gross unrecognized tax benefits as of December 31, 2022 and 2021, respectively, relate to permanent items that, if recognized, would impact the effective income tax rate. This amount differs from the gross unrecognized tax benefits presented in the table below due to (1) the deferred tax asset which would be available if the position were not sustained upon audit and (2) the decrease in U.S. federal income taxes which would occur upon the recognition of the state tax benefits included herein.

---

| | | |
|:---|:---|:---|
| | **2022** | 2021 |
| Balance at January 1 | $**10554** | $10459 |
| Additions based on tax positions related to prior years | **—** | 95 |
| Decreases based on settlements with tax authorities | **(928)** |  |
| **Balance at December 31** | $**9626** | $10554 |

---

The Company records interest and penalties on uncertain tax positions as a component of the income tax provision. The Company recognized net expense of less than $0.1 million in interest and penalties related to uncertain tax positions during both 2022 and 2021. The total amount of interest and penalties accrued was $0.3 million and $0.2 million as of December 31, 2022 and 2021, respectively.

The Company expects the amount of unrecognized tax benefits will change within the next 12 months; however, the change in unrecognized tax benefits, which is reasonably possible within the next 12 months, is not expected to have a significant effect on the Company's financial position, results of operations or cash flows.

**NOTE 14—Retirement Benefit Plans**

**Defined Benefit Plans:** The Company maintains defined benefit pension plans that provide benefits based on years of service and average compensation during certain periods. Prior to 2021, the Company amended the Combined Defined Benefit Plan for NACCO Industries, Inc. and its subsidiaries (the "Combined Plan") to freeze pension benefits for all employees. The Company also amended the Supplemental Retirement Benefit Plan (the "SERP") to freeze all pension benefits. All eligible employees of the Company, including employees whose pension benefits are frozen, receive retirement benefits under defined contribution retirement plans.

The assumptions used in accounting for the defined benefit plans were as follows for the years ended December 31:

---

| | | |
|:---|:---|:---|
| | **2022** | 2021 |
| &nbsp;&nbsp;&nbsp;&nbsp;Weighted average discount rates for pension benefit obligation | **5.36% - 5.40%** | 2.53% - 2.77% |
| &nbsp;&nbsp;&nbsp;&nbsp;Weighted average discount rates for net periodic benefit cost | **2.53% - 2.77%** | 2.02% - 2.36% |
| &nbsp;&nbsp;&nbsp;&nbsp;Expected long-term rate of return on assets for net periodic benefit cost | **7.00%** | 7.00% |

---

Set forth below is detail of the net periodic pension income for the defined benefit plans for the years ended December 31:

---

| | | |
|:---|:---|:---|
| | **2022** | 2021 |
| &nbsp;&nbsp;&nbsp;&nbsp;Interest cost | $**1105** | $1002 |
| &nbsp;&nbsp;&nbsp;&nbsp;Expected return on plan assets | **(2707)** | (2568) |
| &nbsp;&nbsp;&nbsp;&nbsp;Amortization of actuarial loss | **543** | 718 |
| &nbsp;&nbsp;&nbsp;&nbsp;Amortization of prior service cost | **58** | 59 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Net periodic pension income | $**(1001)** | $(789) |

---

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**NOTES TO CONSOLIDATED FINANCIAL STATEMENTS**

**NACCO INDUSTRIES, INC. AND SUBSIDIARIES**

*(Tabular Amounts in Thousands, Except Per Share, Percentage Data and Oil and Gas Disclosures)*

Set forth below is detail of other changes in plan assets and benefit obligations recognized in other comprehensive loss (income) for the years ended December 31:

---

| | | |
|:---|:---|:---|
| | **2022** | 2021 |
| &nbsp;&nbsp;&nbsp;&nbsp;Current year actuarial (gain) loss | $**1717** | $(3793) |
| &nbsp;&nbsp;&nbsp;&nbsp;Amortization of actuarial loss | **(543)** | (718) |
| &nbsp;&nbsp;&nbsp;&nbsp;Amortization of prior service cost | **(58)** | (59) |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Total recognized in other comprehensive loss (income) | $**1116** | $(4570) |

---

The following table sets forth the changes in the benefit obligation and the plan assets during the year and the funded status of the defined benefit plans at December 31:

---

| | | |
|:---|:---|:---|
| | **2022** | 2021 |
| **Change in benefit obligation** |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Projected benefit obligation at beginning of year | $**41663** | $44600 |
| &nbsp;&nbsp;&nbsp;&nbsp;Interest cost | **1105** | 1002 |
| &nbsp;&nbsp;&nbsp;&nbsp;Actuarial gain | **(8396)** | (1367) |
| &nbsp;&nbsp;&nbsp;&nbsp;Benefits paid | **(2650)** | (2572) |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Projected benefit obligation at end of year | $**31722** | $41663 |
| **Accumulated benefit obligation at end of year** | $**31722** | $41663 |
| **Change in plan assets** |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Fair value of plan assets at beginning of year | $**44009** | $41099 |
| &nbsp;&nbsp;&nbsp;&nbsp;Actual return on plan assets | **(7405)** | 4995 |
| &nbsp;&nbsp;&nbsp;&nbsp;Employer contributions | **531** | 487 |
| &nbsp;&nbsp;&nbsp;&nbsp;Benefits paid | **(2650)** | (2572) |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Fair value of plan assets at end of year | $**34485** | $44009 |
| **Funded status at end of year** | $**2763** | $2346 |
| **Amounts recognized in the balance sheets consist of:** |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Non-current assets | $**6991** | $7806 |
| &nbsp;&nbsp;&nbsp;&nbsp;Current liabilities | **(491)** | (542) |
| &nbsp;&nbsp;&nbsp;&nbsp;Non-current liabilities | **(3737)** | (4918) |
|  | $**2763** | $2346 |
| **Components of accumulated other comprehensive loss consist of:** |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Actuarial loss | $**10682** | $9510 |
| &nbsp;&nbsp;&nbsp;&nbsp;Prior service cost | **645** | 703 |
| &nbsp;&nbsp;&nbsp;&nbsp;Deferred taxes | **(2490)** | (2254) |
|  | $**8837** | $7959 |

---

The Company recognizes as a component of benefit (income) cost, as of the measurement date, any unrecognized actuarial net gains or losses that exceed 10% of the larger of the projected benefit obligations or the plan assets, defined as the "corridor." Amounts outside the corridor are amortized over the average expected remaining service of active participants expected to benefit under the retiree medical plans or over the average expected remaining lifetime of inactive participants for the pension plans. The (gain) loss amounts recognized in AOCI are not expected to be fully recognized until the plan is terminated or as settlements occur, which would trigger accelerated recognition. Prior service costs resulting from plan changes are also in AOCI.

The Company's policy is to make contributions to fund its pension plans within the range allowed by applicable regulations.

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**NOTES TO CONSOLIDATED FINANCIAL STATEMENTS**

**NACCO INDUSTRIES, INC. AND SUBSIDIARIES**

*(Tabular Amounts in Thousands, Except Per Share, Percentage Data and Oil and Gas Disclosures)*

The Company maintains one supplemental defined benefit plan that pays monthly benefits to participants directly out of corporate funds. All other pension benefit payments are made from assets of the pension plans.

Future pension benefit payments expected to be paid from assets of the pension plans are:

---

| | |
|:---|:---|
| 2023 | $2731 |
| 2024 | 2729 |
| 2025 | 2700 |
| 2026 | 2691 |
| 2027 | 2681 |
| 2028 - 2032 | 12536 |
|  | $26068 |

---

The expected long-term rate of return on defined benefit plan assets reflects management's expectations of long-term rates of return on funds invested to provide for benefits included in the projected benefit obligations. In establishing the expected long-term rate of return assumption for plan assets, the Company considers the historical rates of return over a period of time that is consistent with the long-term nature of the underlying obligations of these plans as well as a forward-looking rate of return. The historical and forward-looking rates of return for each of the asset classes used to determine the Company's estimated rate of return assumption were based upon the rates of return earned or expected to be earned by investments in the equivalent benchmark market indices for each of the asset classes.

Expected returns for pension plans are based on a calculated market-related value for pension plan assets. Under this methodology, asset gains and losses resulting from actual returns that differ from the Company's expected returns are recognized in the market-related value of assets ratably over three years.

The pension plans maintain investment policies that, among other things, establish a portfolio asset allocation methodology with percentage allocation bands for individual asset classes. The investment policies provide that investments are reallocated between asset classes as balances exceed or fall below the appropriate allocation bands.

The following is the actual allocation percentage and target allocation percentage for the pension plan assets at December 31:

---

| | | | |
|:---|:---|:---|:---|
| | **2022<br>Actual <br>Allocation** | 2021<br>Actual <br>Allocation | Target Allocation <br>Range |
| U.S. equity securities | **44.9%** | 48.7% | 36.0% - 54.0% |
| Non-U.S. equity securities | **20.5%** | 19.7% | 16.0% - 24.0% |
| Fixed income securities | **34.1%** | 31.2% | 30.0% - 40.0% |
| Money market funds | **0.5%** | 0.4% | 0.0% - 10.0% |

---

The defined benefit pension plans do not have any direct ownership of NACCO common stock.

The fair value of each major category of the Company's pension plan assets are valued using quoted market prices in active markets for identical assets, or Level 1 in the fair value hierarchy. Following are the values as of December 31:

---

| | | |
|:---|:---|:---|
| | **Level 1** | **Level 1** |
| | **2022** | 2021 |
| U.S. equity securities | $**15499** | $21434 |
| Non-U.S. equity securities | **7055** | 8678 |
| Fixed income securities | **11753** | 13723 |
| Money market funds | **178** | 174 |
| &nbsp;&nbsp;&nbsp;&nbsp;Total | $**34485** | $44009 |

---

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**NOTES TO CONSOLIDATED FINANCIAL STATEMENTS**

**NACCO INDUSTRIES, INC. AND SUBSIDIARIES**

*(Tabular Amounts in Thousands, Except Per Share, Percentage Data and Oil and Gas Disclosures)*

**Postretirement Health Care:** The Company also maintains health care plans which provide benefits to grandfathered eligible retired employees. All health care plans of the Company have a cap on the Company's share of the costs. The health care plans have network provided benefits which result in cost savings for the Company. These plans have no assets. Under the Company's current policy, plan benefits are funded at the time they are due to participants.

The assumptions used in accounting for the postretirement health care plans are set forth below for the years ended December 31:

---

| | | |
|:---|:---|:---|
| | **2022** | 2021 |
| Weighted average discount rates for benefit obligation | **5.29%** | 2.12% |
| Weighted average discount rates for net periodic benefit cost | **2.12%** | 1.37% |
| Health care cost trend rate assumed for next year | **6.25%** | 6.50% |
| Rate to which the cost trend rate is assumed to decline (ultimate trend rate) | **4.50% - 4.75%** | 4.50% |
| Year that the rate reaches the ultimate trend rate | **2029** | 2029 |

---

Set forth below is detail of the net periodic benefit expense for the postretirement health care plans for the years ended December 31:

---

| | | |
|:---|:---|:---|
| | **2022** | 2021 |
| Service cost | $**12** | $13 |
| Interest cost | **38** | 27 |
| Amortization of actuarial loss | **64** | 19 |
| Amortization of prior service credit | **(52)** | (54) |
| &nbsp;&nbsp;&nbsp;&nbsp;Net periodic benefit expense | $**62** | $5 |

---

Set forth below is detail of other changes in plan assets and benefit obligations recognized in other comprehensive (income) loss for the years ended December 31:

---

| | | |
|:---|:---|:---|
| | **2022** | 2021 |
| Current year actuarial gain | $**(44)** | $(48) |
| Amortization of actuarial loss | **(64)** | (19) |
| Amortization of prior service credit | **52** | 54 |
| Transfers | **—** | 126 |
| &nbsp;&nbsp;&nbsp;&nbsp;Total recognized in other comprehensive (income) loss | $**(56)** | $113 |

---

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<u>[**Table of Contents**](#iaf3a05f346f8475da90341366c3f6933_133)</u>

**NOTES TO CONSOLIDATED FINANCIAL STATEMENTS**

**NACCO INDUSTRIES, INC. AND SUBSIDIARIES**

*(Tabular Amounts in Thousands, Except Per Share, Percentage Data and Oil and Gas Disclosures)*

The following sets forth the changes in benefit obligations during the year and the funded status of the postretirement health care at December 31:

---

| | | |
|:---|:---|:---|
| | **2022** | 2021 |
| **Change in benefit obligation** |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Benefit obligation at beginning of year | $**1877** | $2054 |
| &nbsp;&nbsp;&nbsp;&nbsp;Service cost | **12** | 13 |
| &nbsp;&nbsp;&nbsp;&nbsp;Interest cost | **38** | 27 |
| &nbsp;&nbsp;&nbsp;&nbsp;Actuarial gain | **(44)** | (48) |
| &nbsp;&nbsp;&nbsp;&nbsp;Benefits paid | **(332)** | (169) |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Benefit obligation at end of year | $**1551** | $1877 |
| **Funded status at end of year** | $**(1551)** | $(1877) |
| **Amounts recognized in the balance sheets consist of:** |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Current liabilities | $**(206)** | $(190) |
| &nbsp;&nbsp;&nbsp;&nbsp;Noncurrent liabilities | **(1345)** | (1687) |
|  | $**(1551)** | $(1877) |
| **Components of accumulated other comprehensive loss consist of:** |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Actuarial loss | $**412** | $520 |
| &nbsp;&nbsp;&nbsp;&nbsp;Prior service credit | **(56)** | (108) |
| &nbsp;&nbsp;&nbsp;&nbsp;Deferred taxes | **(180)** | (195) |
|  | $**176** | $217 |

---

Future postretirement health care benefit payments expected to be paid are:

---

| | |
|:---|:---|
| 2023 | 211 |
| 2024 | 188 |
| 2025 | 179 |
| 2026 | 183 |
| 2027 | 185 |
| 2028 - 2032 | 654 |
|  | $1600 |

---

**Defined Contribution Plans:** NACCO and its subsidiaries maintain a defined contribution (401(k)) plan for substantially all employees and provide employer matching contributions based on plan provisions. The plan also provides for a minimum employer contribution. Total costs, including Company contributions, for these plans were $3.3 million and $2.9 million in 2022 and 2021, respectively.

**NOTE 15—Business Segments** 

The Company's operating segments are: (i) Coal Mining, (ii) NAMining and (iii) Minerals Management. The Company determines its reportable segments by first identifying its operating segments, and then by assessing whether any components of these segments constitute a business for which discrete financial information is available and where segment management regularly reviews the operating results of that component. The Company's Chief Operating Decision Maker utilizes operating profit to evaluate segment performance and allocate resources.

The Company has items not directly attributable to a reportable segment which are not included as part of the measurement of segment operating profit, which are primarily administrative costs related to public company reporting requirements at the parent company and the financial results of Mitigation Resources and Bellaire. Mitigation Resources generates and sells stream and wetland mitigation credits (known as mitigation banking) and provides services to those engaged in permittee-responsible

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**NOTES TO CONSOLIDATED FINANCIAL STATEMENTS**

**NACCO INDUSTRIES, INC. AND SUBSIDIARIES**

*(Tabular Amounts in Thousands, Except Per Share, Percentage Data and Oil and Gas Disclosures)*

stream and wetland mitigation. Bellaire manages the Company's long-term liabilities related to former Eastern U.S. underground mining activities.

Effective January 1, 2022, the Company changed the composition of its reportable segments. As a result, the Company retrospectively changed its computation of segment operating profit to reclassify the results of Caddo Creek Resources Company, LLC ("Caddo Creek") and Demery Resources Company, LLC ("Demery") from the Coal Mining segment into the NAMining segment as these operations provide mining solutions for producers of industrial minerals, rather than for power generation. The Coal Mining segment now includes only mines that deliver coal to power generation companies. This segment reporting change has no impact on consolidated operating results. All prior period segment information has been reclassified to conform to the new presentation.

All financial statement line items below operating profit (other income including interest expense and interest income, the provision for income taxes and net income) are presented and discussed within this Form 10-K on a consolidated basis.

See Note 1 for additional discussion of the Company's reportable segments. All current operations reside in the U.S. The accounting policies of the reportable segments are described in Note 2 and Note 18.

In 2022 and 2021, two customers individually accounted for more than 10% of consolidated revenue. The following represents the revenue attributable to each of these entities as a percentage of consolidated revenue for those years:

---

| | | |
|:---|:---|:---|
| | Percentage of Consolidated Revenue | Percentage of Consolidated Revenue |
| **Segment** | **2022** | 2021 |
| Coal Mining customer | **39%** | 43% |
| NAMining customer | **17%** | 19% |

---

------

<u>[**Table of Contents**](#iaf3a05f346f8475da90341366c3f6933_133)</u>

**NOTES TO CONSOLIDATED FINANCIAL STATEMENTS**

**NACCO INDUSTRIES, INC. AND SUBSIDIARIES**

*(Tabular Amounts in Thousands, Except Per Share, Percentage Data and Oil and Gas Disclosures)*

The following tables present revenue, operating profit, depreciation expense and capital expenditures for the years ended December 31:

---

| | | |
|:---|:---|:---|
| | **2022** | 2021 |
| **Revenues** |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Coal Mining | $**95204** | $82831 |
| &nbsp;&nbsp;&nbsp;&nbsp;NAMining | **85664** | 78944 |
| &nbsp;&nbsp;&nbsp;&nbsp;Minerals Management | **60242** | 31003 |
| &nbsp;&nbsp;&nbsp;&nbsp;Unallocated Items | **2952** | 4695 |
| &nbsp;&nbsp;&nbsp;&nbsp;Eliminations | **(2343)** | (5627) |
| &nbsp;&nbsp;&nbsp;&nbsp;Total | $**241719** | $191846 |
| **Operating profit (loss)** |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Coal Mining | $**38309** | $45784 |
| &nbsp;&nbsp;&nbsp;&nbsp;NAMining | **2202** | 3384 |
| &nbsp;&nbsp;&nbsp;&nbsp;Minerals Management | **52214** | 26080 |
| &nbsp;&nbsp;&nbsp;&nbsp;Unallocated Items | **(23233)** | (19553) |
| &nbsp;&nbsp;&nbsp;&nbsp;Eliminations | **494** | (285) |
| &nbsp;&nbsp;&nbsp;&nbsp;Total | $**69986** | $55410 |

---

---

| | | |
|:---|:---|:---|
| **Expenditures for property, plant and equipment and acquisition of mineral interests** | | |
| &nbsp;&nbsp;&nbsp;&nbsp;Coal Mining | $**14853** | $16830 |
| &nbsp;&nbsp;&nbsp;&nbsp;NAMining | **13203** | 21100 |
| &nbsp;&nbsp;&nbsp;&nbsp;Minerals Management | **13388** | 6423 |
| &nbsp;&nbsp;&nbsp;&nbsp;Unallocated Items | **13003** | 208 |
| &nbsp;&nbsp;&nbsp;&nbsp;Total | $**54447** | $44561 |
| **Depreciation, depletion and amortization** |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Coal Mining | $**17074** | $16510 |
| &nbsp;&nbsp;&nbsp;&nbsp;NAMining | **6457** | 4574 |
| &nbsp;&nbsp;&nbsp;&nbsp;Minerals Management | **3026** | 1858 |
| &nbsp;&nbsp;&nbsp;&nbsp;Unallocated Items | **259** | 143 |
| &nbsp;&nbsp;&nbsp;&nbsp;Total | $**26816** | $23085 |

---

Asset information by segment is not discretely maintained for internal reporting or used in evaluating performance.

**NOTE 16—Unconsolidated Subsidiaries** 

Each of the Company's wholly owned Unconsolidated Subsidiaries, within the Coal Mining and NAMining segments, meet the definition of a VIE. The Unconsolidated Subsidiaries are capitalized primarily with debt financing provided by or supported by their respective customers, and generally without recourse to NACCO and NACoal. Although NACoal owns 100% of the equity and manages the daily operations of the Unconsolidated Subsidiaries, the Company has determined that the equity capital provided by NACoal is not sufficient to adequately finance the ongoing activities or absorb any expected losses without additional support from the customers. The customers have a controlling financial interest and have the power to direct the activities that most significantly affect the economic performance of the entities. As a result, the Company is not the primary beneficiary and therefore does not consolidate these entities' financial positions or results of operations. See Note 1 for a discussion of these entities.

------

<u>[**Table of Contents**](#iaf3a05f346f8475da90341366c3f6933_133)</u>

**NOTES TO CONSOLIDATED FINANCIAL STATEMENTS**

**NACCO INDUSTRIES, INC. AND SUBSIDIARIES**

*(Tabular Amounts in Thousands, Except Per Share, Percentage Data and Oil and Gas Disclosures)*

The Investment in the unconsolidated subsidiaries and related tax positions totaled $14.9 million and $19.1 million at December 31, 2022 and 2021, respectively. The Company's risk of loss relating to these entities is limited to its invested capital, which was $7.1 million and $7.6 million at December 31, 2022 and 2021, respectively.

NACoal is a party to certain guarantees related to Coyote Creek. Under certain circumstances of default or termination of Coyote Creek's Lignite Sales Agreement ("LSA"), NACoal would be obligated for payment of a "make-whole" amount to Coyote Creek's third-party lenders. The "make-whole" amount is based on the excess, if any, of the discounted value of the remaining scheduled debt payments over the principal amount. In addition, in the event Coyote Creek's LSA is terminated on or after January 1, 2024 by Coyote Creek's customers, NACoal is obligated to purchase Coyote Creek's dragline and rolling stock for the then net book value of those assets. To date, no payments have been required from NACoal since the inception of these guarantees. The Company believes that the likelihood NACoal would be required to perform under the guarantees is remote, and no amounts related to these guarantees have been recorded.

Summarized financial information for the unconsolidated subsidiaries is as follows:

---

| | | |
|:---|:---|:---|
| | **2022** | 2021 |
| **Statement of Operations** |  |  |
| Revenue | $**664824** | $764759 |
| Gross profit | $**47748** | $68076 |
| Income before income taxes | $**57250** | $60865 |
| Net income | $**48467** | $53248 |
| **Balance Sheet** |  |  |
| Current assets | $**214098** | $168669 |
| Non-current assets | $**805833** | $900924 |
| Current liabilities | $**116701** | $98887 |
| Non-current liabilities | $**896134** | $963128 |

---

Revenue includes all mine operating costs that are reimbursed by the customers of the Unconsolidated Subsidiaries as well as the compensation per ton of coal, heating unit (MMBtu) or ton of limestone delivered. Reimbursed costs have offsetting expenses and have no impact on income before income taxes. Income before income taxes represents the Earnings of the unconsolidated operations.

NACoal received dividends of $49.0 million and $51.7 million from the Unconsolidated Subsidiaries in 2022 and 2021, respectively.

**NOTE 17—Related Party Transactions** 

One of the Company's directors is a retired Jones Day partner. Legal services rendered by Jones Day approximated $1.0 million and $1.2 million for the years ended December 31, 2022 and 2021.

Alfred M. Rankin, Jr. serves as the Chairman of the Board of Directors of NACCO and supports the President and Chief Executive Officer of NACCO upon request under the terms of a consulting agreement. Fees for consulting services rendered by Mr. Rankin approximated $0.3 million and $0.5 million for the years ended December 31, 2022 and 2021, respectively.

Hyster-Yale Materials Handling, Inc. ("Hyster-Yale") is a former subsidiary of the Company that was spun-off to stockholders in 2012. Mr. Rankin is Chairman, President and Chief Executive Officer of Hyster-Yale Materials Handling and Chairman, Hyster-Yale Group. In the ordinary course of business, NACoal leases or buys Hyster-Yale lift trucks. The terms may not be comparable to terms that would be obtained in a transaction between unaffiliated parties.

------

<u>[**Table of Contents**](#iaf3a05f346f8475da90341366c3f6933_133)</u>

**NOTES TO CONSOLIDATED FINANCIAL STATEMENTS**

**NACCO INDUSTRIES, INC. AND SUBSIDIARIES**

*(Tabular Amounts in Thousands, Except Per Share, Percentage Data and Oil and Gas Disclosures)*

**NOTE 18—Supplemental Oil and Gas Disclosures (Unaudited)**

The Minerals Management segment derives income primarily by leasing its royalty and mineral interests to third-party exploration and production companies, and, to a lesser extent, other mining companies, granting them the rights to explore, develop, mine, produce, market and sell gas, oil, and coal in exchange for royalty payments based on the lessees' sales of those minerals. As an owner of royalty and mineral interests, the Company's access to information concerning activity and operations of its royalty and mineral interests is limited. The Company does not have information that would be available to a company with working interests in oil and natural gas operations because detailed information is not generally available to owners of royalty and mineral interests. See Note 1, Note 2 and Note 15 for additional discussion of the Minerals Management segment.

Aggregate capitalized costs related to oil and gas royalty and mineral interests with applicable accumulated depreciation, depletion and amortization at December 31 are as follows:

---

| | | |
|:---|:---|:---|
| | **2022** | 2021 |
| Proved developed | $**7302** | $3266 |
| Proved undeveloped | **24134** | 16246 |
| Proved reserves | **31436** | 19512 |
| Less: accumulated depreciation, depletion and amortization | **1936** | 868 |
| Net royalty interests in oil and natural gas properties | $**29500** | $18644 |

---

Total net proved reserves are defined as those natural gas and hydrocarbon liquid reserves to Company interests after deducting all royalties, overriding royalties, and reversionary interests owned by outside parties that become effective upon payout of specified monetary balances. Decline curve analysis was used to estimate the remaining reserves of pressure depletion reservoirs with enough historical production data to establish decline trends. Reservoirs under non-pressure depletion drive mechanisms and non-producing reserves were estimated by volumetric analysis, research of analogous reservoirs, or a combination of both. Reserves have been estimated using deterministic and probabilistic methods. All reserves estimates have been prepared using standard engineering practices generally accepted by the petroleum industry and conform to guidelines developed and adopted by the SEC.

The following table presents the Company's estimated net proved oil and natural gas reserves as of December 31 based on the reserve report prepared by Haas Engineering, the Company's independent petroleum engineering firm. All of the Company's reserves are located in the United States.

---

| | | | |
|:---|:---|:---|:---|
| | **Net reserves as of December 31, 2022** | **Net reserves as of December 31, 2022** | **Net reserves as of December 31, 2022** |
| | **Oil (bbl)** <sup>(1)</sup>  | **NGL (bbl)** <sup>(1)</sup> | **Residue gas (Mcf)** <sup>(2)</sup> |
| Proved developed | **305710** | **408280** | **25907890** |
| Proved undeveloped | **32570** | **11030** | **1784670** |
| Total | **338280** | **419310** | **27692560** |

---

---

| | | | |
|:---|:---|:---|:---|
| | Net reserves as of December 31, 2021 | Net reserves as of December 31, 2021 | Net reserves as of December 31, 2021 |
| | Oil (bbl) <sup>(1)</sup>  | NGL (bbl) <sup>(1)</sup> | Residue gas (Mcf) <sup>(2)</sup> |
| Proved developed | 167430 | 282230 | 16617360 |
| Proved undeveloped | 220 | 90 | 1210 |
| Total | 167650 | 282320 | 16618570 |

---

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;<sup>(1)</sup> Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;<sup>(2)</sup> Mcf. One thousand cubic feet of natural gas at the contractual pressure and temperature bases.

------

<u>[**Table of Contents**](#iaf3a05f346f8475da90341366c3f6933_133)</u>

**NOTES TO CONSOLIDATED FINANCIAL STATEMENTS**

**NACCO INDUSTRIES, INC. AND SUBSIDIARIES**

*(Tabular Amounts in Thousands, Except Per Share, Percentage Data and Oil and Gas Disclosures)*

**Estimated Proved Reserves**

The following table summarizes changes in proved reserves during the year ended December 31, 2022:

---

| | | | |
|:---|:---|:---|:---|
| | **Estimated Proved Reserves** | **Estimated Proved Reserves** | **Estimated Proved Reserves** |
| | **Oil (bbl)** <sup>(1)</sup> | **NGL (bbl)** <sup>(1)</sup> | **Residue gas (Mcf)** <sup>(2)</sup> |
| December 31, 2021 | 167650 | 282320 | 16618570 |
| Purchases | 99345 | 35222 | 202314 |
| Extensions and discoveries | 121542 | 68167 | 12801109 |
| Revisions of previous estimates <sup>(3)</sup> | (2504) | 95577 | 5405803 |
| Production | (46571) | (61511) | (7329985) |
| Other | (1182) | (465) | (5251) |
| **December 31, 2022** | **338280** | **419310** | **27692560** |

---

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;<sup>(1)</sup> Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;<sup>(2)</sup> Mcf. One thousand cubic feet of natural gas at the contractual pressure and temperature bases.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;<sup>(3)</sup> Revisions of previous estimates include technical revisions due to changes in commodity prices, historical and projected performance and other factors.

**Estimated Proved Undeveloped Reserves ("PUDs")**

The following table summarizes changes in PUDs during the year ended December 31, 2022:

---

| | | | |
|:---|:---|:---|:---|
| | **Estimated Proved Undeveloped Reserves** | **Estimated Proved Undeveloped Reserves** | **Estimated Proved Undeveloped Reserves** |
| | **Oil (bbl)** <sup>(1)</sup> | **NGL (bbl)** <sup>(1)</sup> | **Residue gas (Mcf)** <sup>(2)</sup> |
| December 31, 2021 | 220 | 90 | 1210 |
| Purchases | 21790 | 5104 | 38571 |
| Extensions and discoveries | 10780 | 5926 | 1746099 |
| Revisions of previous estimates <sup>(3)</sup> | (220) | (90) | (1210) |
| **December 31, 2022** | **32570** | **11030** | **1784670** |

---

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;<sup>(1)</sup> Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;<sup>(2)</sup> Mcf. One thousand cubic feet of natural gas at the contractual pressure and temperature bases.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;<sup>(3)</sup> Revisions of previous estimates include technical revisions due to changes in commodity prices, historical and projected performance and other factors.

As an owner of mineral and royalty interests, the Company generally does not have evidence of approval of operators' development plans. As a result, proved undeveloped reserve estimates are limited to those relatively few locations for which drilling permits have been publicly filed. As of December 31, 2022, PUD reserves consists of 42 wells in various stages of drilling or completions. As of December 31, 2022, approximately 6% of the Company's total proved reserves were classified as PUDs.

------

<u>[**Table of Contents**](#iaf3a05f346f8475da90341366c3f6933_133)</u>

**NOTES TO CONSOLIDATED FINANCIAL STATEMENTS**

**NACCO INDUSTRIES, INC. AND SUBSIDIARIES**

*(Tabular Amounts in Thousands, Except Per Share, Percentage Data and Oil and Gas Disclosures)*

**Standardized Measure of Discounted Future Net Cash Flows**

Future cash inflows represent expected revenues from production of period-end quantities of proved reserves based on the 12-month unweighted average of first-day-of-the-month commodity prices for the periods presented. Future cash inflows are computed by applying applicable prices relating to proved reserves to the year-end quantities of those reserves. Future production and costs are derived based on current costs assuming continuation of existing economic conditions. Federal income tax expenses are deducted from future production revenues in the calculation of the standardized measure using the statutory tax rate. The Company is subject to certain state-based taxes; however, these amounts are not material. The projections should not be viewed as realistic estimates of future cash flows, nor should the "standardized measure" be interpreted as representing current value to the Company. Material revisions to estimates of proved reserves may occur in the future; development and production of the reserves may not occur in the periods assumed; actual prices realized are expected to vary significantly from those used; and actual costs may vary.

The following table provides the future net cash flows relating to proved oil and gas reserves based on the standardized measure of discounted cash flows as of December 31, 2022:

---

| | | | |
|:---|:---|:---|:---|
| | **Gross Amounts** | **Statutory tax rate** | **Net Amounts** |
| Future cash inflows | $**218982** |  |  |
| Future production costs | **39841** |  |  |
| Future net cash flows before income tax expense | **179141** | **21%** | **141521** |
| 10% discount to reflect timing of cash flows | **(62615)** | **21%** | **(49465)** |
| Standardized measure of discounted cash flows | $**116526** | **21%** | $**92056** |

---

The following table provides the future net cash flows relating to proved oil and gas reserves based on the standardized measure of discounted cash flows as of December 31, 2021:

---

| | | | |
|:---|:---|:---|:---|
| | **Gross Amounts** | **Statutory tax rate** | **Net Amounts** |
| Future cash inflows | $**71400** |  |  |
| Future production costs | **14664** |  |  |
| Future net cash flows before income tax expense | **56736** | **21%** | **44821** |
| 10% discount to reflect timing of cash flows | **(19897)** | **21%** | **(15719)** |
| Standardized measure of discounted cash flows | $**36839** | **21%** | $**29102** |

---

The following summarizes the principal sources of change in the standardized measure of discounted future net cash flows during 2022:

---

| | |
|:---|:---|
| | **Gross amounts** |
| December 31, 2021 | $36839 |
| Purchases | 6236 |
| Extensions and discoveries | 54795 |
| Revisions of previous estimates <sup>(3)</sup> | 18695 |
| Other | (39) |
| **December 31, 2022** | $**116526** |

---

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;<sup>(3)</sup> Revisions of previous estimates include technical revisions due to changes in commodity prices, historical and projected performance and other factors.

------

<u>[**Table of Contents**](#iaf3a05f346f8475da90341366c3f6933_133)</u>

 **SCHEDULE II—VALUATION AND QUALIFYING ACCOUNTS**

**NACCO INDUSTRIES, INC. AND SUBSIDIARIES**

**YEAR ENDED DECEMBER 31, 2022 AND 2021**

---

| | | | | | |
|:---|:---|:---|:---|:---|:---|
| | | Additions | Additions | | |
| Description | Balance at Beginning of Period | Charged to <br>Costs and <br>Expenses | Charged to <br>Other Accounts <br>— Describe | Deductions <br>— Describe | Balance at <br>End of <br>Period (A) |
| (In thousands) | (In thousands) | (In thousands) | (In thousands) | (In thousands) | (In thousands) |
| **2022** |  |  |  |  |  |
| **Reserves deducted from asset accounts:** |  |  |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;**Deferred tax valuation allowances** | $**11695** | $**114** | $**—** | $**—** | $**11809** |
| 2021 |  |  |  |  |  |
| Reserves deducted from asset accounts: |  |  |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Deferred tax valuation allowances | $11549 | $146 | $— | $— | $11695 |

---

(A)Balances which are not required to be presented and those which are immaterial have been omitted.

## Ex-21

**Exhibit 21**

**SUBSIDIARIES OF NACCO INDUSTRIES, INC.**

The following is a list of active subsidiaries as of the date of the filing with the Securities and Exchange Commission of the Annual Report on Form 10-K to which this is an Exhibit. Except as noted, all of these subsidiaries are wholly owned, directly or indirectly.

---

| | |
|:---|:---|
| **<u>Name</u>** | **<u>Incorporation</u>** |
| America Lignite Energy LLC | Delaware (50%) |
| Bellaire Corporation | Ohio |
| C&H Mining Company, Inc. | Alabama |
| Caddo Creek Resources Company, LLC | Nevada |
| Camino Real Fuels, LLC | Nevada |
| Catapult Mineral Partners, LLC | Nevada |
| Centennial Natural Resources, LLC | Nevada |
| Coyote Creek Mining Company, LLC | Nevada |
| Demery Resources Company, LLC | Nevada |
| The Coteau Properties Company | Ohio |
| The Falkirk Mining Company | Ohio |
| GRENAC, LLC | Delaware (50%) |
| Liberty Fuels Company, LLC | Nevada |
| Mississippi Lignite Mining Company | Texas |
| Mitigation Resources of North America, LLC | Nevada |
| Mitigate Alabama, LLC | Nevada |
| Mitigate Tennessee, LLC | Nevada |
| Mitigate Texas, LLC | Nevada |
| NAM - AGL,LLC | Nevada |
| NAM - CMX, LLC | Nevada |
| NAM - Corkscrew, LLC | Nevada |
| NAM - CSA, LLC | Nevada |
| NAM - IND, LLC | Nevada |
| NAM - Little River, LLC | Nevada |
| NAM - MCA, LLC | Nevada |
| NAM - Newberry, LLC | Nevada |
| NAM - PBA, LLC | Nevada |
| NAM - Pasco, LLC | Nevada |
| NAM - Perry, LLC | Nevada |
| NAM - QueenField, LLC | Nevada |
| NAM - Rosser, LLC | Nevada |
| NAM - SDI, LLC | Nevada |
| NAM - WFA, LLC | Nevada |
| NAM - WRQ, LLC | Nevada |
| NAM - 7D, LLC | Nevada |
| NoDak Energy Investments Corporation | Nevada |
| The North American Coal Corporation | Delaware |
| North American Coal Corporation India Private Limited | India |
| North American Coal, LLC | Nevada |
| North American Mining, LLC | Nevada |
| North American Coal Royalty Company | Delaware |
| Otter Creek Mining Company LLC | Nevada |
| Red Hills Property Company LLC | Mississippi |
| The Sabine Mining Company | Nevada |
| Sawtooth Mining, LLC | Nevada |
| Trident Technology Services Group, LLC | Nevada |
| Trifecta Renewable Solutions, LLC | Delaware |
| TRU Global Energy Services, LLC | Delaware |
| TRU Energy Services, LLC | Nevada |
| Reed Minerals, Inc. | Alabama |
| Yockanookany Mitigation Resources, LLC | Nevada |

---

## Exhibit 23.1

**Exhibit 23.1**

**Consent of Independent Registered Public Accounting Firm**

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

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(1)Registration Statement (Form S-8 No. 333-256443) pertaining to the Amended and Restated Executive Long-Term Incentive Compensation Plan,

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(2)Registration Statement (Form S-8 No. 333-256445) pertaining to the Amended and Restated Non-Employee Directors' Equity Compensation Plan

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(3)Registration Statement (Form S-8 No. 333-231316) pertaining to the Amended and Restated Executive Long-Term Incentive Compensation Plan,

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(4)Registration Statement (Form S-8 No. 333-231315) pertaining to the Amended and Restated Non-Employee Directors' Equity Compensation Plan,

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(5)Registration Statement (Form S-8 No. 333-139268) pertaining to the NACCO Industries, Inc. Executive Long-Term Incentive Compensation Plan,

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(6)Registration Statement (Form S-8 No. 333-166944) pertaining to the NACCO Industries, Inc. Executive Long-Term Incentive Compensation Plan,

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(7)Registration Statement (Form S-8 No. 333-183242) pertaining to the NACCO Industries, Inc. Supplemental Executive Long-Term Incentive Compensation Plan,

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(8)Registration Statement (Form S-8 No. 333-217862) pertaining to the NACCO Industries, Inc. Executive Long-Term Incentive Compensation Plan (Amended and Restated Effective March 1, 2017), and

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(9)Registration Statement (Form S-8 No. 333-217900) pertaining to NACCO Industries, Inc. Non-Employee Directors' Equity Compensation Plan (Amended and Restated Effective May 9, 2017);

of our reports dated March 15, 2023, with respect to the consolidated financial statements and schedules of NACCO Industries, Inc. and Subsidiaries and the effectiveness of internal control over financial reporting of NACCO Industries, Inc. and Subsidiaries included in this Annual Report (Form 10-K) of NACCO Industries, Inc. for the year ended December 31, 2022.

---

| | |
|:---|:---|
| | /s/ Ernst & Young LLP |
| Cleveland, Ohio | |
| March 15, 2023 | |

---

## Exhibit 23.2

**Exhibit 23.2**

**Consent of Jefferson King**

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

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(1)Registration Statement (Form S-8 No. 333-256443) pertaining to the Amended and Restated Executive Long-Term Incentive Compensation Plan,

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(2)Registration Statement (Form S-8 No. 333-256445) pertaining to the Amended and Restated Non-Employee Directors' Equity Compensation Plan

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(3)Registration Statement (Form S-8 No. 333-231316) pertaining to the Amended and Restated Executive Long-Term Incentive Compensation Plan,

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(4)Registration Statement (Form S-8 No. 333-231315) pertaining to the Amended and Restated Non-Employee Directors' Equity Compensation Plan,

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(5)Registration Statement (Form S-8 No. 333-139268) pertaining to the NACCO Industries, Inc. Executive Long-Term Incentive Compensation Plan,

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(6)Registration Statement (Form S-8 No. 333-166944) pertaining to the NACCO Industries, Inc. Executive Long-Term Incentive Compensation Plan,

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(7)Registration Statement (Form S-8 No. 333-183242) pertaining to the NACCO Industries, Inc. Supplemental Executive Long-Term Incentive Compensation Plan,

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(8)Registration Statement (Form S-8 No. 333-217862) pertaining to the NACCO Industries, Inc. Executive Long-Term Incentive Compensation Plan (Amended and Restated Effective March 1, 2017), and

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(9)Registration Statement (Form S-8 No. 333-217900) pertaining to NACCO Industries, Inc. Non-Employee Directors' Equity Compensation Plan (Amended and Restated Effective May 9, 2017);

of the references to my name, the use of the SEC S-K 1300 Technical Report Summary, Mississippi Lignite Mining Company – Red Hills Mine, Ackerman, Mississippi (the "Technical Report") and the information derived from the Technical Report, including any quotation from or summarization of the Technical Report, which are included in the Annual Report on Form 10-K.

---

| | |
|:---|:---|
| | /s/ Jefferson King |
| March 15, 2023 | |

---

## Exhibit 23.3

**Exhibit 23.3**

**Consent of Benson Chow**

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

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(1)Registration Statement (Form S-8 No. 333-256443) pertaining to the Amended and Restated Executive Long-Term Incentive Compensation Plan,

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(2)Registration Statement (Form S-8 No. 333-256445) pertaining to the Amended and Restated Non-Employee Directors' Equity Compensation Plan

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(3)Registration Statement (Form S-8 No. 333-231316) pertaining to the Amended and Restated Executive Long-Term Incentive Compensation Plan,

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(4)Registration Statement (Form S-8 No. 333-231315) pertaining to the Amended and Restated Non-Employee Directors' Equity Compensation Plan,

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(5)Registration Statement (Form S-8 No. 333-139268) pertaining to the NACCO Industries, Inc. Executive Long-Term Incentive Compensation Plan,

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(6)Registration Statement (Form S-8 No. 333-166944) pertaining to the NACCO Industries, Inc. Executive Long-Term Incentive Compensation Plan,

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(7)Registration Statement (Form S-8 No. 333-183242) pertaining to the NACCO Industries, Inc. Supplemental Executive Long-Term Incentive Compensation Plan,

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(8)Registration Statement (Form S-8 No. 333-217862) pertaining to the NACCO Industries, Inc. Executive Long-Term Incentive Compensation Plan (Amended and Restated Effective March 1, 2017), and

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(9)Registration Statement (Form S-8 No. 333-217900) pertaining to NACCO Industries, Inc. Non-Employee Directors' Equity Compensation Plan (Amended and Restated Effective May 9, 2017);

of the references to my name, the use of the SEC S-K 1300 Technical Report Summary, Mississippi Lignite Mining Company – Red Hills Mine, Ackerman, Mississippi (the "Technical Report") and the information derived from the Technical Report, including any quotation from or summarization of the Technical Report, which are included in the Annual Report on Form 10-K.

---

| | |
|:---|:---|
| | /s/ Benson Chow |
| March 15, 2023 | |

---

## Exhibit 23.4

**Exhibit 23.4**

**Consent of Haas Petroleum Engineering Services, Inc**

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

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(1)Registration Statement (Form S-8 No. 333-256443) pertaining to the Amended and Restated Executive Long-Term Incentive Compensation Plan,

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(2)Registration Statement (Form S-8 No. 333-256445) pertaining to the Amended and Restated Non-Employee Directors' Equity Compensation Plan

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(3)Registration Statement (Form S-8 No. 333-231316) pertaining to the Amended and Restated Executive Long-Term Incentive Compensation Plan,

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(4)Registration Statement (Form S-8 No. 333-231315) pertaining to the Amended and Restated Non-Employee Directors' Equity Compensation Plan,

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(5)Registration Statement (Form S-8 No. 333-139268) pertaining to the NACCO Industries, Inc. Executive Long-Term Incentive Compensation Plan,

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(6)Registration Statement (Form S-8 No. 333-166944) pertaining to the NACCO Industries, Inc. Executive Long-Term Incentive Compensation Plan,

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(7)Registration Statement (Form S-8 No. 333-183242) pertaining to the NACCO Industries, Inc. Supplemental Executive Long-Term Incentive Compensation Plan,

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(8)Registration Statement (Form S-8 No. 333-217862) pertaining to the NACCO Industries, Inc. Executive Long-Term Incentive Compensation Plan (Amended and Restated Effective March 1, 2017), and

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(9)Registration Statement (Form S-8 No. 333-217900) pertaining to NACCO Industries, Inc. Non-Employee Directors' Equity Compensation Plan (Amended and Restated Effective May 9, 2017);

of the references to our name, the use of the Reserve Report of Catapult Mineral Partners ("Reserve Report") and the information derived from the Reserve Report, including any quotation from or summarization of the Reserve Report, which are included in the Annual Report on Form 10-K.

---

| | |
|:---|:---|
| | /s/ Haas Petroleum Engineering Services, Inc |
| March 15, 2023 | |

---

## Exhibit 24.1

**Exhibit 24.1**

**<u>POWER OF ATTORNEY</u>** 

KNOW ALL MEN BY THESE PRESENTS, that the undersigned director of NACCO Industries, Inc. hereby appoints Elizabeth I. Loveman as the true and lawful attorney or attorney-in-fact, with full power of substitution and revocation, for the undersigned and in the name, place and stead of the undersigned, to sign on behalf of the undersigned as director of NACCO Industries, Inc., a Delaware corporation, an Annual Report pursuant to Section 13 of the Securities Exchange Act of 1934 on Form 10-K for the fiscal year ended December 31, 2022 and to sign any and all amendments to such Annual Report, and to file the same, with all exhibits thereto, and other documents in connection therewith, with the Securities and Exchange Commission, granting to said attorney or attorney-in-fact full power and authority to do so and perform each and every act and thing requisite and necessary to be done in and about the premises, as fully to all intents and purposes as the undersigned might or could do in person, hereby ratifying and confirming all that said attorney or attorney-in-fact substitute or substitutes may lawfully do or cause to be done by virtue hereof.

---

| | |
|:---|:---|
| /s/ John S. Dalrymple | February 22, 2023 |
| John S. Dalrymple | Date |

---

## Exhibit 24.2

**Exhibit 24.2**

**<u>POWER OF ATTORNEY</u>** 

KNOW ALL MEN BY THESE PRESENTS, that the undersigned director of NACCO Industries, Inc. hereby appoints Elizabeth I. Loveman as the true and lawful attorney or attorney-in-fact, with full power of substitution and revocation, for the undersigned and in the name, place and stead of the undersigned, to sign on behalf of the undersigned as director of NACCO Industries, Inc., a Delaware corporation, an Annual Report pursuant to Section 13 of the Securities Exchange Act of 1934 on Form 10-K for the fiscal year ended December 31, 2022 and to sign any and all amendments to such Annual Report, and to file the same, with all exhibits thereto, and other documents in connection therewith, with the Securities and Exchange Commission, granting to said attorney or attorney-in-fact full power and authority to do so and perform each and every act and thing requisite and necessary to be done in and about the premises, as fully to all intents and purposes as the undersigned might or could do in person, hereby ratifying and confirming all that said attorney or attorney-in-fact substitute or substitutes may lawfully do or cause to be done by virtue hereof.

---

| | |
|:---|:---|
| /s/ John P. Jumper | February 22, 2023 |
| John P. Jumper | Date |

---

## Exhibit 24.3

**Exhibit 24.3**

**<u>POWER OF ATTORNEY</u>** 

KNOW ALL MEN BY THESE PRESENTS, that the undersigned director of NACCO Industries, Inc. hereby appoints Elizabeth I. Loveman as the true and lawful attorney or attorney-in-fact, with full power of substitution and revocation, for the undersigned and in the name, place and stead of the undersigned, to sign on behalf of the undersigned as director of NACCO Industries, Inc., a Delaware corporation, an Annual Report pursuant to Section 13 of the Securities Exchange Act of 1934 on Form 10-K for the fiscal year ended December 31, 2022 and to sign any and all amendments to such Annual Report, and to file the same, with all exhibits thereto, and other documents in connection therewith, with the Securities and Exchange Commission, granting to said attorney or attorney-in-fact full power and authority to do so and perform each and every act and thing requisite and necessary to be done in and about the premises, as fully to all intents and purposes as the undersigned might or could do in person, hereby ratifying and confirming all that said attorney or attorney-in-fact substitute or substitutes may lawfully do or cause to be done by virtue hereof.

---

| | |
|:---|:---|
| /s/ Dennis W. LaBarre | February 22, 2023 |
| Dennis W. LaBarre | Date |

---

## Exhibit 24.4

**Exhibit 24.4**

**<u>POWER OF ATTORNEY</u>** 

KNOW ALL MEN BY THESE PRESENTS, that the undersigned director of NACCO Industries, Inc. hereby appoints Elizabeth I. Loveman as the true and lawful attorney or attorney-in-fact, with full power of substitution and revocation, for the undersigned and in the name, place and stead of the undersigned, to sign on behalf of the undersigned as director of NACCO Industries, Inc., a Delaware corporation, an Annual Report pursuant to Section 13 of the Securities Exchange Act of 1934 on Form 10-K for the fiscal year ended December 31, 2022 and to sign any and all amendments to such Annual Report, and to file the same, with all exhibits thereto, and other documents in connection therewith, with the Securities and Exchange Commission, granting to said attorney or attorney-in-fact full power and authority to do so and perform each and every act and thing requisite and necessary to be done in and about the premises, as fully to all intents and purposes as the undersigned might or could do in person, hereby ratifying and confirming all that said attorney or attorney-in-fact substitute or substitutes may lawfully do or cause to be done by virtue hereof.

---

| | |
|:---|:---|
| /s/ Michael S. Miller | February 22, 2023 |
| Michael S. Miller | Date |

---

## Exhibit 24.5

**Exhibit 24.5**

**<u>POWER OF ATTORNEY</u>** 

KNOW ALL MEN BY THESE PRESENTS, that the undersigned director of NACCO Industries, Inc. hereby appoints Elizabeth I. Loveman as the true and lawful attorney or attorney-in-fact, with full power of substitution and revocation, for the undersigned and in the name, place and stead of the undersigned, to sign on behalf of the undersigned as director of NACCO Industries, Inc., a Delaware corporation, an Annual Report pursuant to Section 13 of the Securities Exchange Act of 1934 on Form 10-K for the fiscal year ended December 31, 2022 and to sign any and all amendments to such Annual Report, and to file the same, with all exhibits thereto, and other documents in connection therewith, with the Securities and Exchange Commission, granting to said attorney or attorney-in-fact full power and authority to do so and perform each and every act and thing requisite and necessary to be done in and about the premises, as fully to all intents and purposes as the undersigned might or could do in person, hereby ratifying and confirming all that said attorney or attorney-in-fact substitute or substitutes may lawfully do or cause to be done by virtue hereof.

---

| | |
|:---|:---|
| /s/ Richard de J. Osborne | February 22, 2023 |
| Richard de J. Osborne | Date |

---

## Exhibit 24.6

**Exhibit 24.6**

**<u>POWER OF ATTORNEY</u>** 

KNOW ALL MEN BY THESE PRESENTS, that the undersigned director of NACCO Industries, Inc. hereby appoints Elizabeth I. Loveman as the true and lawful attorney or attorney-in-fact, with full power of substitution and revocation, for the undersigned and in the name, place and stead of the undersigned, to sign on behalf of the undersigned as director of NACCO Industries, Inc., a Delaware corporation, an Annual Report pursuant to Section 13 of the Securities Exchange Act of 1934 on Form 10-K for the fiscal year ended December 31, 2022 and to sign any and all amendments to such Annual Report, and to file the same, with all exhibits thereto, and other documents in connection therewith, with the Securities and Exchange Commission, granting to said attorney or attorney-in-fact full power and authority to do so and perform each and every act and thing requisite and necessary to be done in and about the premises, as fully to all intents and purposes as the undersigned might or could do in person, hereby ratifying and confirming all that said attorney or attorney-in-fact substitute or substitutes may lawfully do or cause to be done by virtue hereof.

---

| | |
|:---|:---|
| /s/ Alfred M. Rankin, Jr. | February 22, 2023 |
| Alfred M. Rankin, Jr. | Date |

---

## Exhibit 24.7

**Exhibit 24.7**

**<u>POWER OF ATTORNEY</u>** 

KNOW ALL MEN BY THESE PRESENTS, that the undersigned director of NACCO Industries, Inc. hereby appoints Elizabeth I. Loveman as the true and lawful attorney or attorney-in-fact, with full power of substitution and revocation, for the undersigned and in the name, place and stead of the undersigned, to sign on behalf of the undersigned as director of NACCO Industries, Inc., a Delaware corporation, an Annual Report pursuant to Section 13 of the Securities Exchange Act of 1934 on Form 10-K for the fiscal year ended December 31, 2022 and to sign any and all amendments to such Annual Report, and to file the same, with all exhibits thereto, and other documents in connection therewith, with the Securities and Exchange Commission, granting to said attorney or attorney-in-fact full power and authority to do so and perform each and every act and thing requisite and necessary to be done in and about the premises, as fully to all intents and purposes as the undersigned might or could do in person, hereby ratifying and confirming all that said attorney or attorney-in-fact substitute or substitutes may lawfully do or cause to be done by virtue hereof.

---

| | |
|:---|:---|
| /s/ Matthew M. Rankin | February 22, 2023 |
| Matthew M. Rankin | Date |

---

## Exhibit 24.8

**Exhibit 24.8**

**<u>POWER OF ATTORNEY</u>** 

KNOW ALL MEN BY THESE PRESENTS, that the undersigned director of NACCO Industries, Inc. hereby appoints Elizabeth I. Loveman as the true and lawful attorney or attorney-in-fact, with full power of substitution and revocation, for the undersigned and in the name, place and stead of the undersigned, to sign on behalf of the undersigned as director of NACCO Industries, Inc., a Delaware corporation, an Annual Report pursuant to Section 13 of the Securities Exchange Act of 1934 on Form 10-K for the fiscal year ended December 31, 2022 and to sign any and all amendments to such Annual Report, and to file the same, with all exhibits thereto, and other documents in connection therewith, with the Securities and Exchange Commission, granting to said attorney or attorney-in-fact full power and authority to do so and perform each and every act and thing requisite and necessary to be done in and about the premises, as fully to all intents and purposes as the undersigned might or could do in person, hereby ratifying and confirming all that said attorney or attorney-in-fact substitute or substitutes may lawfully do or cause to be done by virtue hereof.

---

| | |
|:---|:---|
| /s/ Roger F. Rankin | February 22, 2023 |
| Roger F. Rankin | Date |

---

## Exhibit 24.9

**Exhibit 24.9**

**<u>POWER OF ATTORNEY</u>** 

KNOW ALL MEN BY THESE PRESENTS, that the undersigned director of NACCO Industries, Inc. hereby appoints Elizabeth I. Loveman as the true and lawful attorney or attorney-in-fact, with full power of substitution and revocation, for the undersigned and in the name, place and stead of the undersigned, to sign on behalf of the undersigned as director of NACCO Industries, Inc., a Delaware corporation, an Annual Report pursuant to Section 13 of the Securities Exchange Act of 1934 on Form 10-K for the fiscal year ended December 31, 2022 and to sign any and all amendments to such Annual Report, and to file the same, with all exhibits thereto, and other documents in connection therewith, with the Securities and Exchange Commission, granting to said attorney or attorney-in-fact full power and authority to do so and perform each and every act and thing requisite and necessary to be done in and about the premises, as fully to all intents and purposes as the undersigned might or could do in person, hereby ratifying and confirming all that said attorney or attorney-in-fact substitute or substitutes may lawfully do or cause to be done by virtue hereof.

---

| | |
|:---|:---|
| /s/ Lori J. Robinson | February 22, 2023 |
| Lori J. Robinson | Date |

---

## Exhibit 24.10

**Exhibit 24.10**

**<u>POWER OF ATTORNEY</u>** 

KNOW ALL MEN BY THESE PRESENTS, that the undersigned director of NACCO Industries, Inc. hereby appoints Elizabeth I. Loveman as the true and lawful attorney or attorney-in-fact, with full power of substitution and revocation, for the undersigned and in the name, place and stead of the undersigned, to sign on behalf of the undersigned as director of NACCO Industries, Inc., a Delaware corporation, an Annual Report pursuant to Section 13 of the Securities Exchange Act of 1934 on Form 10-K for the fiscal year ended December 31, 2022 and to sign any and all amendments to such Annual Report, and to file the same, with all exhibits thereto, and other documents in connection therewith, with the Securities and Exchange Commission, granting to said attorney or attorney-in-fact full power and authority to do so and perform each and every act and thing requisite and necessary to be done in and about the premises, as fully to all intents and purposes as the undersigned might or could do in person, hereby ratifying and confirming all that said attorney or attorney-in-fact substitute or substitutes may lawfully do or cause to be done by virtue hereof.

---

| | |
|:---|:---|
| /s/ Robert S. Shapard | February 22, 2023 |
| Robert S. Shapard | Date |

---

## Exhibit 24.11

**Exhibit 24.11**

**<u>POWER OF ATTORNEY</u>** 

KNOW ALL MEN BY THESE PRESENTS, that the undersigned director of NACCO Industries, Inc. hereby appoints Elizabeth I. Loveman as the true and lawful attorney or attorney-in-fact, with full power of substitution and revocation, for the undersigned and in the name, place and stead of the undersigned, to sign on behalf of the undersigned as director of NACCO Industries, Inc., a Delaware corporation, an Annual Report pursuant to Section 13 of the Securities Exchange Act of 1934 on Form 10-K for the fiscal year ended December 31, 2022 and to sign any and all amendments to such Annual Report, and to file the same, with all exhibits thereto, and other documents in connection therewith, with the Securities and Exchange Commission, granting to said attorney or attorney-in-fact full power and authority to do so and perform each and every act and thing requisite and necessary to be done in and about the premises, as fully to all intents and purposes as the undersigned might or could do in person, hereby ratifying and confirming all that said attorney or attorney-in-fact substitute or substitutes may lawfully do or cause to be done by virtue hereof.

---

| | |
|:---|:---|
| /s/ Britton T. Taplin | February 22, 2023 |
| Britton T. Taplin | Date |

---

## Exhibit 31.1

**Exhibit 31(i)(1)**

**Certifications** 

I, J.C. Butler, Jr., certify that:

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;1.I have reviewed this annual report on Form 10-K of NACCO Industries, Inc.;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;4.The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;a)Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;b)Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;c)Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;d)Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;5.The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;a)All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;b)Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

---

| | | |
|:---|:---|:---|
| Date: | March 15, 2023 | /s/ J.C. Butler, Jr. |
| | | J.C. Butler, Jr. |
| | | President and Chief Executive Officer<br>(principal executive officer) |

---

## Exhibit 31.2

**Exhibit 31(i)(2)** 

**Certifications** 

I, Elizabeth I. Loveman, certify that:

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;1.I have reviewed this annual report on Form 10-K of NACCO Industries, Inc.;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;4.The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;a)Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;b)Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;c)Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;d)Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;5.The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;a)All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;b)Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

---

| | | |
|:---|:---|:---|
| Date: | March 15, 2023 | /s/ Elizabeth I. Loveman |
| | | Elizabeth I. Loveman |
| | | Vice President and Controller <br>(principal financial officer) |

---

## Ex-32

**Exhibit 32** 

**CERTIFICATION PURSUANT TO 18 U.S.C. SECTION 1350, AS ADOPTED PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002** 

In connection with the Annual Report of NACCO Industries, Inc. (the "Company") on Form 10-K for the year ended December 31, 2022, as filed with the Securities and Exchange Commission on the date hereof (the "Report"), each of the undersigned officers of the Company certifies, pursuant to 18 U.S.C. § 1350, as adopted pursuant to § 906 of the Sarbanes-Oxley Act of 2002, that, to such officer's knowledge:

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(1)The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(2)The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company as of the dates and for the periods expressed in the Report.

---

| | | |
|:---|:---|:---|
| Date: | March 15, 2023 | /s/ J.C. Butler, Jr. |
| | | J.C. Butler, Jr. |
| | | President and Chief Executive Officer<br>(principal executive officer) |

---

---

| | | |
|:---|:---|:---|
| Date: | March 15, 2023 | /s/ Elizabeth I. Loveman |
| | | Elizabeth I. Loveman |
| | | Vice President and Controller <br>(principal financial officer) |

---

## Ex-95

**Exhibit 95**

**MINE SAFETY DISCLOSURES**

NACCO Industries, Inc. (the "Company") believes that The North American Coal Corporation and its affiliated mining companies (collectively, "NACoal") is an industry leader in safety. NACoal has health and safety programs in place that include extensive employee training, accident prevention, workplace inspection, emergency response, accident investigation, regulatory compliance and program auditing. The objectives for NACoal's programs are to eliminate workplace incidents, comply with all mining-related regulations and provide support for both regulators and the industry to improve mine safety.

Under the Dodd-Frank Wall Street Reform and Consumer Protection Act, each operator of a coal or other mine is required to include certain mine safety results in its periodic reports filed with the Securities and Exchange Commission. The operation of NACoal's mines is subject to regulation by the Federal Mine Safety and Health Administration ("MSHA") under the Federal Mine Safety and Health Act of 1977 (the "Mine Act"). MSHA inspects NACoal's mines on a regular basis and issues various citations and orders when it believes a violation has occurred under the Mine Act. The Company has presented information below regarding certain mining safety and health matters for NACoal's mining operations for the year ended December 31, 2022. In evaluating this information, consideration should be given to factors such as: (i) the number of citations and orders will vary depending on the size of the mine, (ii) the number of citations issued will vary from inspector to inspector and from mine to mine, and (iii) citations and orders can be contested and appealed, and in that process, are often reduced in severity and amount, and are sometimes vacated.

During the year ended December 31, 2022, neither the Company's current mining operations nor it's closed mines: (i) were assessed any Mine Act section 104(b) orders for alleged failure to totally abate the subject matter of a Mine Act section 104(a) citation within the period specified in the citation; (ii) were assessed any Mine Act section 110(b)(2) penalties for failure to correct the subject matter of a Mine Act section 104(a) citation within the specified time period, which failure was deemed flagrant (i.e., reckless or repeated failure to make reasonable efforts to eliminate a known violation that substantially and proximately caused, or reasonably could have been expected to cause, death or serious bodily injury); (iii) received any Mine Act section 107(a) imminent danger orders to immediately remove miners; or (iv) received any MSHA written notices under Mine Act section 104(e) of a pattern of violation of mandatory health or safety standards or of the potential to have such a pattern. In addition, there were no mining-related fatalities at the Company's operations or it's closed mines during the year ended December 31, 2022.

------

The following table sets forth the total number of specific citations and orders, the total dollar value of the proposed civil penalty assessments that were issued by MSHA, the total number of legal actions initiated and resolved before the Federal Mine Safety and Health Review Commission ("FMSHRC") during the year ended December 31, 2022, and the total number of legal actions pending before the FMSHRC at December 31, 2022, pursuant to the Mine Act, by individual mine at NACoal:

---

| | | | | | | |
|:---|:---|:---|:---|:---|:---|:---|
| Name of Mine or Quarry <sup>(1)</sup> | Mine Act Section 104 Significant & Substantial Citations <sup>(2)(3)</sup> | Mine Act Section 104(d) Citations | Total Dollar Value of Proposed MSHA Assessment | Number of Legal Actions Initiated before the FMSHRC for the year ended at December 31, 2022 | Number of Legal Actions Resolved before the FMSHRC for the year ended at December 31, 2022 | Number of Legal Actions Pending before the FMSHRC at December 31, 2022 |
| Coteau (Freedom Mine) |  |  | $348 |  |  |  |
| Falkirk (Falkirk Mine) |  |  |  |  |  |  |
| Sabine (South Hallsville No. 1 Mine) | 1 |  | 927 |  |  |  |
| Demery (Five Forks Mine) |  |  |  |  |  |  |
| Caddo Creek (Marshall Mine) |  |  |  |  |  |  |
| Coyote Creek (Coyote Creek Mine) |  |  |  |  |  |  |
| MLMC (Red Hills Mine) |  |  | 481 |  |  |  |
| North American Mining Operations: |  |  |  |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Alico Quarry |  |  |  |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Center Hill Quarry |  |  | 133 |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;FEC Quarry | 1 |  | 909 |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Inglis Quarry |  |  |  |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Krome Quarry |  |  |  |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;SCL Quarry |  |  | 252 |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;St. Catherine Quarry |  |  |  |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Seven Diamonds Quarry |  |  |  |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Central State Aggregates Quarry |  |  |  |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Johnson County Quarry |  |  |  |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Little River Quarry | 3 |  | 2086 | 1 | 1 |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Mid Coast Aggregates Quarry |  |  |  |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Newberry Quarry |  |  | 610 |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;County Line Quarry |  |  |  |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Palm Beach Aggregates Quarry | 1 |  | 2198 |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Perry Quarry |  |  |  |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Queensfield Mine |  |  |  |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Rosser Quarry |  |  |  |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;SDI Aggregates Quarry |  |  |  |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;West Florida Aggregates Quarry |  |  |  |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Titan Corkscrew Quarry |  |  |  |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;White Rock Quarry - North |  |  |  |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Ash Grove |  |  |  |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Total | 6 |  | $7944 | 1 | 1 |  |

---

<sup>(1)</sup> &nbsp;&nbsp;&nbsp;&nbsp;Bellaire's, Centennial's and Liberty's closed mines are not included in the table above and did not receive any of the indicated citations.

<sup>(2)</sup> &nbsp;&nbsp;&nbsp;&nbsp;Mine Act section 104(a) significant and substantial citations are for alleged violations of a mining safety standard or regulation where there exists a reasonable likelihood that the hazard contributed to or will result in an injury or illness of a reasonably serious nature.

<sup>(3)</sup> &nbsp;&nbsp;&nbsp;&nbsp;Two of the reported significant and substantial citations at Little River Quarry during the year ended December 31, 2022, were originally classified by MSHA as significant and substantial. These citations have been reduced to non-significant and substantial.

## Exhibit 96.1

SEC S-K 1300 Technical Report Summary

Mississippi Lignite Mining Company – Red Hills Mine&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;March 2023

SEC S-K 1300 Technical Report Summary

Mississippi Lignite Mining Company – Red Hills Mine

Ackerman, Mississippi &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;

Effective Date: December 31, 2022

Report Date: March 10, 2023

Report Prepared by:

![image_0.jpg](image_0.jpg)

Mississippi Lignite Mining Company

1000 McIntire Road

Ackerman, MS 39735

**Signed by Qualified Persons:** 

Jefferson King, P.E., P.S.

Benson Chow, P.G., SME-RM

------

SEC S-K 1300 Technical Report Summary

Mississippi Lignite Mining Company – Red Hills Mine&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;March 2023

**Table of Contents**

---

| | |
|:---|:---|
| Signature and Report Date | [9](#i4c7fd59bc6e74e49b8ebc1c48a2ae18b_1) |
| 1.&nbsp;&nbsp;&nbsp;&nbsp;Executive Summary | [12](#i4c7fd59bc6e74e49b8ebc1c48a2ae18b_1) |
| 1.1.&nbsp;&nbsp;&nbsp;&nbsp;Property Description and Ownership | [12](#i4c7fd59bc6e74e49b8ebc1c48a2ae18b_1) |
| 1.2.&nbsp;&nbsp;&nbsp;&nbsp;Geology and Mineralization | [12](#i4c7fd59bc6e74e49b8ebc1c48a2ae18b_1) |
| 1.3.&nbsp;&nbsp;&nbsp;&nbsp;Status of Exploration | [13](#i4c7fd59bc6e74e49b8ebc1c48a2ae18b_1) |
| 1.4.&nbsp;&nbsp;&nbsp;&nbsp;Development and Operations | [13](#i4c7fd59bc6e74e49b8ebc1c48a2ae18b_1) |
| 1.5.&nbsp;&nbsp;&nbsp;&nbsp;Mineral Resource Estimate | [14](#i4c7fd59bc6e74e49b8ebc1c48a2ae18b_1) |
| 1.6.&nbsp;&nbsp;&nbsp;&nbsp;Mineral Reserve Estimate | [15](#i4c7fd59bc6e74e49b8ebc1c48a2ae18b_1) |
| 1.7.&nbsp;&nbsp;&nbsp;&nbsp;Economic Assessment | [18](#i4c7fd59bc6e74e49b8ebc1c48a2ae18b_1) |
| 1.8.&nbsp;&nbsp;&nbsp;&nbsp;Permitting Requirements | [21](#i4c7fd59bc6e74e49b8ebc1c48a2ae18b_1) |
| 1.9.&nbsp;&nbsp;&nbsp;&nbsp;Qualified Person's Conclusions and Recommendations | [21](#i4c7fd59bc6e74e49b8ebc1c48a2ae18b_1) |
| 2.&nbsp;&nbsp;&nbsp;&nbsp;Introduction | [22](#i4c7fd59bc6e74e49b8ebc1c48a2ae18b_1) |
| 3.&nbsp;&nbsp;&nbsp;&nbsp;Property Description | [25](#i4c7fd59bc6e74e49b8ebc1c48a2ae18b_1) |
| 3.1.&nbsp;&nbsp;&nbsp;&nbsp;Property Location | [25](#i4c7fd59bc6e74e49b8ebc1c48a2ae18b_1) |
| 3.2.&nbsp;&nbsp;&nbsp;&nbsp;Property Area | [27](#i4c7fd59bc6e74e49b8ebc1c48a2ae18b_1) |
| 3.3.&nbsp;&nbsp;&nbsp;&nbsp;Leases and Mineral Rights | [27](#i4c7fd59bc6e74e49b8ebc1c48a2ae18b_1) |
| 3.4.&nbsp;&nbsp;&nbsp;&nbsp;Significant Encumbrances to the Property | [37](#i4c7fd59bc6e74e49b8ebc1c48a2ae18b_1) |
| 3.5.&nbsp;&nbsp;&nbsp;&nbsp;Significant Factors and Risks | [37](#i4c7fd59bc6e74e49b8ebc1c48a2ae18b_1) |
| 3.6.&nbsp;&nbsp;&nbsp;&nbsp;Registrant Royalties and Interests | [37](#i4c7fd59bc6e74e49b8ebc1c48a2ae18b_1) |
| 4.&nbsp;&nbsp;&nbsp;&nbsp;Accessibility, Climate, Local Resources, Infrastructure, and Physiography | [38](#i4c7fd59bc6e74e49b8ebc1c48a2ae18b_1) |
| 4.1.&nbsp;&nbsp;&nbsp;&nbsp;Physiography, Topography and Vegetation | [38](#i4c7fd59bc6e74e49b8ebc1c48a2ae18b_1) |
| 4.2.&nbsp;&nbsp;&nbsp;&nbsp;Accessibility | [38](#i4c7fd59bc6e74e49b8ebc1c48a2ae18b_1) |
| 4.3.&nbsp;&nbsp;&nbsp;&nbsp;Climate | [39](#i4c7fd59bc6e74e49b8ebc1c48a2ae18b_1) |
| 4.4.&nbsp;&nbsp;&nbsp;&nbsp;Local Resources and Infrastructure | [39](#i4c7fd59bc6e74e49b8ebc1c48a2ae18b_1) |
| 5.&nbsp;&nbsp;&nbsp;&nbsp;History of the Property | [40](#i4c7fd59bc6e74e49b8ebc1c48a2ae18b_1) |
| 5.1.&nbsp;&nbsp;&nbsp;&nbsp;Previous Operations | [40](#i4c7fd59bc6e74e49b8ebc1c48a2ae18b_1) |
| 5.2.&nbsp;&nbsp;&nbsp;&nbsp;Exploration and Development History Prior to MLMC | [40](#i4c7fd59bc6e74e49b8ebc1c48a2ae18b_1) |
| 6.&nbsp;&nbsp;&nbsp;&nbsp;Geological Setting, Mineralization and Deposit | [41](#i4c7fd59bc6e74e49b8ebc1c48a2ae18b_1) |
| 6.1.&nbsp;&nbsp;&nbsp;&nbsp;Geology | [41](#i4c7fd59bc6e74e49b8ebc1c48a2ae18b_1) |
| 6.1.1.&nbsp;&nbsp;&nbsp;&nbsp;Regional Geology | [41](#i4c7fd59bc6e74e49b8ebc1c48a2ae18b_1) |
| 6.1.2.&nbsp;&nbsp;&nbsp;&nbsp;Local and Property Geology | [43](#i4c7fd59bc6e74e49b8ebc1c48a2ae18b_1) |
| 6.2.&nbsp;&nbsp;&nbsp;&nbsp;Mineral Deposit Type | [43](#i4c7fd59bc6e74e49b8ebc1c48a2ae18b_1) |

---

------

SEC S-K 1300 Technical Report Summary

Mississippi Lignite Mining Company – Red Hills Mine&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;March 2023

---

| | |
|:---|:---|
| 6.2.1.&nbsp;&nbsp;&nbsp;&nbsp;Gravel Creek Member | [43](#i4c7fd59bc6e74e49b8ebc1c48a2ae18b_1) |
| 6.2.2.&nbsp;&nbsp;&nbsp;&nbsp;Grampian Hills Member | [44](#i4c7fd59bc6e74e49b8ebc1c48a2ae18b_1) |
| 6.2.3.&nbsp;&nbsp;&nbsp;&nbsp;Tuscahoma Formation | [44](#i4c7fd59bc6e74e49b8ebc1c48a2ae18b_1) |
| 6.3.&nbsp;&nbsp;&nbsp;&nbsp;Stratigraphic Column | [45](#i4c7fd59bc6e74e49b8ebc1c48a2ae18b_1) |
| 7.&nbsp;&nbsp;&nbsp;&nbsp;Exploration | [49](#i4c7fd59bc6e74e49b8ebc1c48a2ae18b_10) |
| 7.1.&nbsp;&nbsp;&nbsp;&nbsp;Exploration | [49](#i4c7fd59bc6e74e49b8ebc1c48a2ae18b_10) |
| 7.2.&nbsp;&nbsp;&nbsp;&nbsp;Drilling Exploration | [49](#i4c7fd59bc6e74e49b8ebc1c48a2ae18b_10) |
| 7.2.1.&nbsp;&nbsp;&nbsp;&nbsp;Drilling Type and Extent | [49](#i4c7fd59bc6e74e49b8ebc1c48a2ae18b_10) |
| 7.2.2.&nbsp;&nbsp;&nbsp;&nbsp;General Drilling Procedures | [52](#i4c7fd59bc6e74e49b8ebc1c48a2ae18b_16) |
| 7.2.3.&nbsp;&nbsp;&nbsp;&nbsp;Drilling Exploration Programs | [52](#i4c7fd59bc6e74e49b8ebc1c48a2ae18b_16) |
| 7.2.4.&nbsp;&nbsp;&nbsp;&nbsp;Qualified Person Opinion – Drilling Exploration | [55](#i4c7fd59bc6e74e49b8ebc1c48a2ae18b_16) |
| 7.3.&nbsp;&nbsp;&nbsp;&nbsp;Hydrogeologic Characterization | [56](#i4c7fd59bc6e74e49b8ebc1c48a2ae18b_16) |
| 7.3.1.&nbsp;&nbsp;&nbsp;&nbsp;Surface Water | [56](#i4c7fd59bc6e74e49b8ebc1c48a2ae18b_16) |
| 7.3.2.&nbsp;&nbsp;&nbsp;&nbsp;Groundwater | [56](#i4c7fd59bc6e74e49b8ebc1c48a2ae18b_16) |
| 7.3.3.&nbsp;&nbsp;&nbsp;&nbsp;Qualified Person Opinion – Hydrogeologic Characterization | [57](#i4c7fd59bc6e74e49b8ebc1c48a2ae18b_16) |
| 7.4.&nbsp;&nbsp;&nbsp;&nbsp;Geotechnical Studies | [59](#i4c7fd59bc6e74e49b8ebc1c48a2ae18b_22) |
| 7.4.1.&nbsp;&nbsp;&nbsp;&nbsp;Early Geotechnical Studies | [59](#i4c7fd59bc6e74e49b8ebc1c48a2ae18b_22) |
| 7.4.2.&nbsp;&nbsp;&nbsp;&nbsp;Buffer Block Study | [60](#i4c7fd59bc6e74e49b8ebc1c48a2ae18b_22) |
| 7.4.3.&nbsp;&nbsp;&nbsp;&nbsp;Qualified Person Opinion – Geotechnical Studies | [61](#i4c7fd59bc6e74e49b8ebc1c48a2ae18b_22) |
| 8.&nbsp;&nbsp;&nbsp;&nbsp;Sample Preparation, Analysis, and Security | [64](#i4c7fd59bc6e74e49b8ebc1c48a2ae18b_22) |
| 8.1.&nbsp;&nbsp;&nbsp;&nbsp;Sample Collection and Shipment | [64](#i4c7fd59bc6e74e49b8ebc1c48a2ae18b_22) |
| 8.2.&nbsp;&nbsp;&nbsp;&nbsp;Sample Preparation and Analysis | [65](#i4c7fd59bc6e74e49b8ebc1c48a2ae18b_22) |
| 8.2.1.&nbsp;&nbsp;&nbsp;&nbsp;Receiving Dock/Sample Storage Room | [66](#i4c7fd59bc6e74e49b8ebc1c48a2ae18b_22) |
| 8.2.2.&nbsp;&nbsp;&nbsp;&nbsp;Prep Room | [67](#i4c7fd59bc6e74e49b8ebc1c48a2ae18b_22) |
| 8.2.3.&nbsp;&nbsp;&nbsp;&nbsp;Laboratory Testing | [67](#i4c7fd59bc6e74e49b8ebc1c48a2ae18b_22) |
| 8.3.&nbsp;&nbsp;&nbsp;&nbsp;Quality Control Procedures | [67](#i4c7fd59bc6e74e49b8ebc1c48a2ae18b_22) |
| 8.4.&nbsp;&nbsp;&nbsp;&nbsp;QP Statement on the Adequacy of Sample Preparation, Security and Analytical Procedures | [68](#i4c7fd59bc6e74e49b8ebc1c48a2ae18b_22) |
| 9.&nbsp;&nbsp;&nbsp;&nbsp;Data Verification | [69](#i4c7fd59bc6e74e49b8ebc1c48a2ae18b_22) |
| 9.1.&nbsp;&nbsp;&nbsp;&nbsp;Data Verification Procedures for Mineral Resources | [69](#i4c7fd59bc6e74e49b8ebc1c48a2ae18b_22) |
| 9.1.1.&nbsp;&nbsp;&nbsp;&nbsp;QP Site Visit | [69](#i4c7fd59bc6e74e49b8ebc1c48a2ae18b_22) |
| 9.1.2.&nbsp;&nbsp;&nbsp;&nbsp;Verification of Drill Hole Data and Geologic (Mineral Resource) Model | [70](#i4c7fd59bc6e74e49b8ebc1c48a2ae18b_22) |
| 9.1.3.&nbsp;&nbsp;&nbsp;&nbsp;Verification of the Reasonable Prospect for Economic Extraction to Support Mineral Resource Estimation | [71](#i4c7fd59bc6e74e49b8ebc1c48a2ae18b_22) |
| 9.1.4.&nbsp;&nbsp;&nbsp;&nbsp;Limitations on Data Verification for Mineral Resources | [71](#i4c7fd59bc6e74e49b8ebc1c48a2ae18b_22) |

---

------

SEC S-K 1300 Technical Report Summary

Mississippi Lignite Mining Company – Red Hills Mine&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;March 2023

---

| | |
|:---|:---|
| 9.1.5.&nbsp;&nbsp;&nbsp;&nbsp;QP's Statement of Adequacy of Data for Mineral Resources | [72](#i4c7fd59bc6e74e49b8ebc1c48a2ae18b_22) |
| 9.2.&nbsp;&nbsp;&nbsp;&nbsp;Data Verification Procedures for Mineral Reserves | [72](#i4c7fd59bc6e74e49b8ebc1c48a2ae18b_22) |
| 9.2.1.&nbsp;&nbsp;&nbsp;&nbsp;QP Site Visit | [72](#i4c7fd59bc6e74e49b8ebc1c48a2ae18b_22) |
| 9.2.2.&nbsp;&nbsp;&nbsp;&nbsp;Verification of Hydrogeology Data | [72](#i4c7fd59bc6e74e49b8ebc1c48a2ae18b_22) |
| 9.2.3.&nbsp;&nbsp;&nbsp;&nbsp;Verification of Geotechnical Data | [72](#i4c7fd59bc6e74e49b8ebc1c48a2ae18b_22) |
| 9.2.4.&nbsp;&nbsp;&nbsp;&nbsp;Verification of Cut-off Grade, Dilution Assumptions and Modifying Factors | [72](#i4c7fd59bc6e74e49b8ebc1c48a2ae18b_22) |
| 9.2.5.&nbsp;&nbsp;&nbsp;&nbsp;Verification of Ultimate Pit Configuration | [73](#i4c7fd59bc6e74e49b8ebc1c48a2ae18b_22) |
| 9.2.6.&nbsp;&nbsp;&nbsp;&nbsp;Verification of Cost Estimate, Pricing Assumptions, and Economic Analysis | [73](#i4c7fd59bc6e74e49b8ebc1c48a2ae18b_22) |
| 9.2.7.&nbsp;&nbsp;&nbsp;&nbsp;Workforce, Staffing and Equipment | [73](#i4c7fd59bc6e74e49b8ebc1c48a2ae18b_22) |
| 9.2.8.&nbsp;&nbsp;&nbsp;&nbsp;Environmental Factors | [73](#i4c7fd59bc6e74e49b8ebc1c48a2ae18b_22) |
| 9.2.9.&nbsp;&nbsp;&nbsp;&nbsp;Limitations on Data Verification for Mineral Reserves | [73](#i4c7fd59bc6e74e49b8ebc1c48a2ae18b_22) |
| 9.2.10.&nbsp;&nbsp;&nbsp;&nbsp;QP's Statement of Adequacy of Data for Mineral Reserves | [74](#i4c7fd59bc6e74e49b8ebc1c48a2ae18b_22) |
| 10.&nbsp;&nbsp;&nbsp;&nbsp;Mineral Processing | [75](#i4c7fd59bc6e74e49b8ebc1c48a2ae18b_22) |
| 11.&nbsp;&nbsp;&nbsp;&nbsp;Mineral Resource Estimates | [76](#i4c7fd59bc6e74e49b8ebc1c48a2ae18b_22) |
| 11.1.&nbsp;&nbsp;&nbsp;&nbsp;Key Assumptions, Parameters and Methods | [76](#i4c7fd59bc6e74e49b8ebc1c48a2ae18b_22) |
| 11.1.1.&nbsp;&nbsp;&nbsp;&nbsp;Horizons | [76](#i4c7fd59bc6e74e49b8ebc1c48a2ae18b_22) |
| 11.1.2.&nbsp;&nbsp;&nbsp;&nbsp;Quality Parameters and Density Determination | [77](#i4c7fd59bc6e74e49b8ebc1c48a2ae18b_22) |
| 11.1.3.&nbsp;&nbsp;&nbsp;&nbsp;Modeling Process | [78](#i4c7fd59bc6e74e49b8ebc1c48a2ae18b_22) |
| 11.1.4.&nbsp;&nbsp;&nbsp;&nbsp;Justification of Modeling Methods | [78](#i4c7fd59bc6e74e49b8ebc1c48a2ae18b_22) |
| 11.1.5.&nbsp;&nbsp;&nbsp;&nbsp;Limits and Constraints on the Mineral Resource Estimates | [78](#i4c7fd59bc6e74e49b8ebc1c48a2ae18b_22) |
| 11.1.6.&nbsp;&nbsp;&nbsp;&nbsp;Generation of Pit Shells for Mineral Resource Estimates | [79](#i4c7fd59bc6e74e49b8ebc1c48a2ae18b_22) |
| 11.2.&nbsp;&nbsp;&nbsp;&nbsp;Mineral Resource Estimates | [80](#i4c7fd59bc6e74e49b8ebc1c48a2ae18b_22) |
| 11.2.1.&nbsp;&nbsp;&nbsp;&nbsp;Basis for Mineral Resource Estimate | [80](#i4c7fd59bc6e74e49b8ebc1c48a2ae18b_22) |
| 11.2.2.&nbsp;&nbsp;&nbsp;&nbsp;Mineral Resource Statement | [81](#i4c7fd59bc6e74e49b8ebc1c48a2ae18b_22) |
| 11.3.&nbsp;&nbsp;&nbsp;&nbsp;Cut-off Quality, Assumed Cost and Sales Price | [81](#i4c7fd59bc6e74e49b8ebc1c48a2ae18b_22) |
| 11.4.&nbsp;&nbsp;&nbsp;&nbsp;QP's Classification of Mineral Resources | [82](#i4c7fd59bc6e74e49b8ebc1c48a2ae18b_22) |
| 11.5.&nbsp;&nbsp;&nbsp;&nbsp;Uncertainty in the Mineral Resource Estimate | [86](#i4c7fd59bc6e74e49b8ebc1c48a2ae18b_28) |
| 11.6.&nbsp;&nbsp;&nbsp;&nbsp;QP's Opinion on Potential Influences Affecting Mineral Resource Estimates | [87](#i4c7fd59bc6e74e49b8ebc1c48a2ae18b_28) |
| 12.&nbsp;&nbsp;&nbsp;&nbsp;Mineral Reserve Estimates | [88](#i4c7fd59bc6e74e49b8ebc1c48a2ae18b_28) |
| 12.1.&nbsp;&nbsp;&nbsp;&nbsp;Key Assumptions, Parameters, and Methods | [88](#i4c7fd59bc6e74e49b8ebc1c48a2ae18b_28) |
| 12.1.1.&nbsp;&nbsp;&nbsp;&nbsp;Stripping Ratio and Pit Limits | [88](#i4c7fd59bc6e74e49b8ebc1c48a2ae18b_28) |
| 12.1.2.&nbsp;&nbsp;&nbsp;&nbsp;Lignite Quality | [88](#i4c7fd59bc6e74e49b8ebc1c48a2ae18b_28) |
| 12.1.3.&nbsp;&nbsp;&nbsp;&nbsp;Modeled Mining Parameters | [88](#i4c7fd59bc6e74e49b8ebc1c48a2ae18b_28) |

---

------

SEC S-K 1300 Technical Report Summary

Mississippi Lignite Mining Company – Red Hills Mine&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;March 2023

---

| | |
|:---|:---|
| 12.1.4.&nbsp;&nbsp;&nbsp;&nbsp;Assumptions and Modifying Factors | [88](#i4c7fd59bc6e74e49b8ebc1c48a2ae18b_28) |
| 12.1.5.&nbsp;&nbsp;&nbsp;&nbsp;Method | [89](#i4c7fd59bc6e74e49b8ebc1c48a2ae18b_28) |
| 12.2.&nbsp;&nbsp;&nbsp;&nbsp;Mineral Reserve Estimates | [90](#i4c7fd59bc6e74e49b8ebc1c48a2ae18b_28) |
| 12.2.1.&nbsp;&nbsp;&nbsp;&nbsp;Basis for Mineral Reserve Estimate | [90](#i4c7fd59bc6e74e49b8ebc1c48a2ae18b_28) |
| 12.3.&nbsp;&nbsp;&nbsp;&nbsp;Cut-off Quality and Sales Price | [91](#i4c7fd59bc6e74e49b8ebc1c48a2ae18b_28) |
| 12.4.&nbsp;&nbsp;&nbsp;&nbsp;Mineral Reserve Statement | [91](#i4c7fd59bc6e74e49b8ebc1c48a2ae18b_28) |
| 12.5.&nbsp;&nbsp;&nbsp;&nbsp;Multiple Commodity Mineral Reserve | [92](#i4c7fd59bc6e74e49b8ebc1c48a2ae18b_28) |
| 12.6.&nbsp;&nbsp;&nbsp;&nbsp;QP's Opinion on Risk Factors that could Affect Mineral Reserve Estimates | [92](#i4c7fd59bc6e74e49b8ebc1c48a2ae18b_28) |
| 13.&nbsp;&nbsp;&nbsp;&nbsp;Mining Methods | [93](#i4c7fd59bc6e74e49b8ebc1c48a2ae18b_28) |
| 13.1.&nbsp;&nbsp;&nbsp;&nbsp;Geotechnical and Hydrological Considerations | [95](#i4c7fd59bc6e74e49b8ebc1c48a2ae18b_34) |
| 13.1.1.&nbsp;&nbsp;&nbsp;&nbsp;Pit Design | [95](#i4c7fd59bc6e74e49b8ebc1c48a2ae18b_34) |
| 13.1.2.&nbsp;&nbsp;&nbsp;&nbsp;Spoil Stability Studies | [96](#i4c7fd59bc6e74e49b8ebc1c48a2ae18b_34) |
| 13.1.3.&nbsp;&nbsp;&nbsp;&nbsp;Excess Spoil Piles | [99](#i4c7fd59bc6e74e49b8ebc1c48a2ae18b_34) |
| 13.2.&nbsp;&nbsp;&nbsp;&nbsp;Lignite Production Rate, Mine Life, Mining Dimensions and Dilution and Recovery Factors | [99](#i4c7fd59bc6e74e49b8ebc1c48a2ae18b_34) |
| 13.2.1.&nbsp;&nbsp;&nbsp;&nbsp;Production Rate | [99](#i4c7fd59bc6e74e49b8ebc1c48a2ae18b_34) |
| 13.2.2.&nbsp;&nbsp;&nbsp;&nbsp;Mine Life | [100](#i4c7fd59bc6e74e49b8ebc1c48a2ae18b_34) |
| 13.2.3.&nbsp;&nbsp;&nbsp;&nbsp;Mining Dimensions | [100](#i4c7fd59bc6e74e49b8ebc1c48a2ae18b_34) |
| 13.2.4.&nbsp;&nbsp;&nbsp;&nbsp;Haulroad Design | [100](#i4c7fd59bc6e74e49b8ebc1c48a2ae18b_34) |
| 13.2.5.&nbsp;&nbsp;&nbsp;&nbsp;Mining Dilution | [100](#i4c7fd59bc6e74e49b8ebc1c48a2ae18b_34) |
| 13.2.6.&nbsp;&nbsp;&nbsp;&nbsp;Recovery Factors | [101](#i4c7fd59bc6e74e49b8ebc1c48a2ae18b_34) |
| 13.3.&nbsp;&nbsp;&nbsp;&nbsp;Requirements for Stripping and Backfilling | [101](#i4c7fd59bc6e74e49b8ebc1c48a2ae18b_34) |
| 13.4.&nbsp;&nbsp;&nbsp;&nbsp;Major Equipment and Personnel | [103](#i4c7fd59bc6e74e49b8ebc1c48a2ae18b_34) |
| 14.&nbsp;&nbsp;&nbsp;&nbsp;Processing and Recovery Methods | [105](#i4c7fd59bc6e74e49b8ebc1c48a2ae18b_34) |
| 15.&nbsp;&nbsp;&nbsp;&nbsp;Infrastructure | [106](#i4c7fd59bc6e74e49b8ebc1c48a2ae18b_34) |
| 16.&nbsp;&nbsp;&nbsp;&nbsp;Market Studies | [108](#i4c7fd59bc6e74e49b8ebc1c48a2ae18b_40) |
| 16.1.&nbsp;&nbsp;&nbsp;&nbsp;Markets | [108](#i4c7fd59bc6e74e49b8ebc1c48a2ae18b_40) |
| 16.2.&nbsp;&nbsp;&nbsp;&nbsp;Material Contracts | [108](#i4c7fd59bc6e74e49b8ebc1c48a2ae18b_40) |
| 17.&nbsp;&nbsp;&nbsp;&nbsp;Environmental Studies, Permitting, and Plans, Negotiations, or Agreements with Local Individuals or Groups | [109](#i4c7fd59bc6e74e49b8ebc1c48a2ae18b_40) |
| 17.1.&nbsp;&nbsp;&nbsp;&nbsp;Environmental and Baseline Studies | [109](#i4c7fd59bc6e74e49b8ebc1c48a2ae18b_40) |
| 17.2.&nbsp;&nbsp;&nbsp;&nbsp;Waste Disposal, Site Monitoring and Water Management | [109](#i4c7fd59bc6e74e49b8ebc1c48a2ae18b_40) |
| 17.2.1.&nbsp;&nbsp;&nbsp;&nbsp;Waste Disposal | [109](#i4c7fd59bc6e74e49b8ebc1c48a2ae18b_40) |
| 17.2.2.&nbsp;&nbsp;&nbsp;&nbsp;Site Monitoring | [110](#i4c7fd59bc6e74e49b8ebc1c48a2ae18b_40) |
| 17.2.3.&nbsp;&nbsp;&nbsp;&nbsp;Water Management | [110](#i4c7fd59bc6e74e49b8ebc1c48a2ae18b_40) |

---

------

SEC S-K 1300 Technical Report Summary

Mississippi Lignite Mining Company – Red Hills Mine&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;March 2023

---

| | |
|:---|:---|
| 17.3.&nbsp;&nbsp;&nbsp;&nbsp;Project Permitting Requirements | [110](#i4c7fd59bc6e74e49b8ebc1c48a2ae18b_40) |
| 17.3.1.&nbsp;&nbsp;&nbsp;&nbsp;Permit Status | [110](#i4c7fd59bc6e74e49b8ebc1c48a2ae18b_40) |
| 17.3.2.&nbsp;&nbsp;&nbsp;&nbsp;Reclamation Bond Requirements | [113](#i4c7fd59bc6e74e49b8ebc1c48a2ae18b_40) |
| 17.4.&nbsp;&nbsp;&nbsp;&nbsp;Plans, Negotiations, or Agreements with Local Individuals or Groups | [113](#i4c7fd59bc6e74e49b8ebc1c48a2ae18b_40) |
| 17.5.&nbsp;&nbsp;&nbsp;&nbsp;Mine Closure Plans | [113](#i4c7fd59bc6e74e49b8ebc1c48a2ae18b_40) |
| 17.6.&nbsp;&nbsp;&nbsp;&nbsp;QP's Opinion of Adequacy of Current Plans | [113](#i4c7fd59bc6e74e49b8ebc1c48a2ae18b_40) |
| 17.7.&nbsp;&nbsp;&nbsp;&nbsp;Description of any Commitments to Ensure Local Procurement and Hiring | [113](#i4c7fd59bc6e74e49b8ebc1c48a2ae18b_40) |
| 18.&nbsp;&nbsp;&nbsp;&nbsp;Capital and Operating Costs | [114](#i4c7fd59bc6e74e49b8ebc1c48a2ae18b_40) |
| 18.1.&nbsp;&nbsp;&nbsp;&nbsp;Operating Costs | [114](#i4c7fd59bc6e74e49b8ebc1c48a2ae18b_40) |
| 18.2.&nbsp;&nbsp;&nbsp;&nbsp;Capital Costs | [114](#i4c7fd59bc6e74e49b8ebc1c48a2ae18b_40) |
| 19.&nbsp;&nbsp;&nbsp;&nbsp;Economic Analysis | [116](#i4c7fd59bc6e74e49b8ebc1c48a2ae18b_40) |
| 19.1.&nbsp;&nbsp;&nbsp;&nbsp;Key Assumptions, Parameters and Methods | [116](#i4c7fd59bc6e74e49b8ebc1c48a2ae18b_40) |
| 19.2.&nbsp;&nbsp;&nbsp;&nbsp;Annual Cash Flows | [116](#i4c7fd59bc6e74e49b8ebc1c48a2ae18b_40) |
| 19.3.&nbsp;&nbsp;&nbsp;&nbsp;Sensitivity Analysis | [119](#i4c7fd59bc6e74e49b8ebc1c48a2ae18b_40) |
| 20.&nbsp;&nbsp;&nbsp;&nbsp;Adjacent Properties | [120](#i4c7fd59bc6e74e49b8ebc1c48a2ae18b_40) |
| 21.&nbsp;&nbsp;&nbsp;&nbsp;Other Relevant Data and Information | [121](#i4c7fd59bc6e74e49b8ebc1c48a2ae18b_40) |
| 22.&nbsp;&nbsp;&nbsp;&nbsp;Interpretations and Conclusions | [122](#i4c7fd59bc6e74e49b8ebc1c48a2ae18b_40) |
| 22.1.&nbsp;&nbsp;&nbsp;&nbsp;Mineral Resources | [122](#i4c7fd59bc6e74e49b8ebc1c48a2ae18b_40) |
| 22.2.&nbsp;&nbsp;&nbsp;&nbsp;Mineral Reserves | [122](#i4c7fd59bc6e74e49b8ebc1c48a2ae18b_40) |
| 23.&nbsp;&nbsp;&nbsp;&nbsp;Recommendations | [123](#i4c7fd59bc6e74e49b8ebc1c48a2ae18b_40) |
| 23.1.&nbsp;&nbsp;&nbsp;&nbsp;Mineral Resources | [123](#i4c7fd59bc6e74e49b8ebc1c48a2ae18b_40) |
| 23.2.&nbsp;&nbsp;&nbsp;&nbsp;Mineral Reserves | [123](#i4c7fd59bc6e74e49b8ebc1c48a2ae18b_40) |
| 24.&nbsp;&nbsp;&nbsp;&nbsp;References | [124](#i4c7fd59bc6e74e49b8ebc1c48a2ae18b_40) |
| 25.&nbsp;&nbsp;&nbsp;&nbsp;Reliance on Information Provided by the Registrant | [125](#i4c7fd59bc6e74e49b8ebc1c48a2ae18b_40) |

---

------

SEC S-K 1300 Technical Report Summary

Mississippi Lignite Mining Company – Red Hills Mine&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;March 2023

**List of Tables**

---

| | |
|:---|:---|
| Table 1.1 Mineral Resource Estimates as of December 31, 2022 | [15](#i4c7fd59bc6e74e49b8ebc1c48a2ae18b_1) |
| Table 1.2 LOM Production Schedule | [16](#i4c7fd59bc6e74e49b8ebc1c48a2ae18b_1) |
| Table 1.3 Mineral Reserve Estimate as of December 31, 2022 | [17](#i4c7fd59bc6e74e49b8ebc1c48a2ae18b_1) |
| Table 1.4 Historical and Forecasted Coal Price | [18](#i4c7fd59bc6e74e49b8ebc1c48a2ae18b_1) |
| Table 1.5 Summary of Income Statement and Cash Flow for LOM plan delivering approximately 27.7 million MMBtu | [20](#i4c7fd59bc6e74e49b8ebc1c48a2ae18b_1) |
| Table 3.1 Identification of Leases | [28](#i4c7fd59bc6e74e49b8ebc1c48a2ae18b_1) |
| Table 3.2 Identification of Acquisitions | [32](#i4c7fd59bc6e74e49b8ebc1c48a2ae18b_1) |
| Table 5.1 Historical Production | [40](#i4c7fd59bc6e74e49b8ebc1c48a2ae18b_1) |
| Table 7.1 Exploration Drilling Summary | [53](#i4c7fd59bc6e74e49b8ebc1c48a2ae18b_16) |
| Table 8.1 List of ASTM standards for Standard Laboratory, Casper location | [66](#i4c7fd59bc6e74e49b8ebc1c48a2ae18b_22) |
| Table 9.1 Resource QP Drill Hole Survey Verification | [70](#i4c7fd59bc6e74e49b8ebc1c48a2ae18b_22) |
| Table 11.1 Quality (as-received basis) and Thickness Limits | [76](#i4c7fd59bc6e74e49b8ebc1c48a2ae18b_22) |
| Table 11.2 Stratigraphic Horizons | [77](#i4c7fd59bc6e74e49b8ebc1c48a2ae18b_22) |
| Table 11.3 Mineral Resource Estimates | [81](#i4c7fd59bc6e74e49b8ebc1c48a2ae18b_22) |
| Table 11.4 Mineral Resource Categories – distances from C Seam Ash Variogram | [84](#i4c7fd59bc6e74e49b8ebc1c48a2ae18b_22) |
| Table 11.5 Resource Classification Uncertainty Summary | [87](#i4c7fd59bc6e74e49b8ebc1c48a2ae18b_28) |
| Table 12.1 Mineral Reserve Estimates | [91](#i4c7fd59bc6e74e49b8ebc1c48a2ae18b_28) |
| Table 13.1 Effective highwall angle by depth | [95](#i4c7fd59bc6e74e49b8ebc1c48a2ae18b_34) |
| Table 13.2 LOM Production Schedule | [100](#i4c7fd59bc6e74e49b8ebc1c48a2ae18b_34) |
| Table 13.3 ROM Dilution Parameters | [101](#i4c7fd59bc6e74e49b8ebc1c48a2ae18b_34) |
| Table 13.4 Recovery Rates by Seam | [101](#i4c7fd59bc6e74e49b8ebc1c48a2ae18b_34) |
| Table 13.5 Major and primary auxiliary equipment list | [104](#i4c7fd59bc6e74e49b8ebc1c48a2ae18b_34) |
| Table 13.6 MLMC Personnel | [104](#i4c7fd59bc6e74e49b8ebc1c48a2ae18b_34) |
| Table 16.1 Historical and Forecasted Coal Price | [108](#i4c7fd59bc6e74e49b8ebc1c48a2ae18b_40) |
| Table 17.1 Red Hills Mine Permit Summary and Status | [111](#i4c7fd59bc6e74e49b8ebc1c48a2ae18b_40) |
| Table 18.1 LOM Operating Costs to deliver approximately 27.7 million MMBtu per year | [114](#i4c7fd59bc6e74e49b8ebc1c48a2ae18b_40) |
| Table 18.2 LOM Capital Costs to deliver approximately 27.7 million MMBtu per year | [115](#i4c7fd59bc6e74e49b8ebc1c48a2ae18b_40) |
| Table 19.1 Summary of Income Statement and Cash Flow for LOM plan delivering approximately 27.7 million MMBtu | [118](#i4c7fd59bc6e74e49b8ebc1c48a2ae18b_40) |

---

------

SEC S-K 1300 Technical Report Summary

Mississippi Lignite Mining Company – Red Hills Mine&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;March 2023

**List of Figures**

---

| | |
|:---|:---|
| Figure 3.1 Regional Location Map | [25](#i4c7fd59bc6e74e49b8ebc1c48a2ae18b_1) |
| Figure 3.2 Location of the Red Hills Mine | [26](#i4c7fd59bc6e74e49b8ebc1c48a2ae18b_1) |
| Figure 6.1 Geologic Formations of Mississippi (Dicken, Nicholson, Horton, Foose, & Mueller, 2005) | [42](#i4c7fd59bc6e74e49b8ebc1c48a2ae18b_1) |
| Figure 6.2 Stratigraphic Column of the Red Hills Mine | [45](#i4c7fd59bc6e74e49b8ebc1c48a2ae18b_1) |
| Figure 6.3 Geologic Cross Sections planer reference | [46](#i4c7fd59bc6e74e49b8ebc1c48a2ae18b_1) |
| Figure 6.4 Geologic Cross Section E-W2, MS-002 permit area (Excerpted from SMCRA permit MS-002, R3, Appendix 2509-6) | [47](#i4c7fd59bc6e74e49b8ebc1c48a2ae18b_4) |
| Figure 6.5 Geologic Cross Sections C-C' and D-D', MS-004 permit area (Excerpted from SMCRA permit MS-004, Appendix 2509-6) | [48](#i4c7fd59bc6e74e49b8ebc1c48a2ae18b_7) |
| Figure 7.1 Location of Drill Holes | [51](#i4c7fd59bc6e74e49b8ebc1c48a2ae18b_13) |
| Figure 7.2 Groundwater Map | [58](#i4c7fd59bc6e74e49b8ebc1c48a2ae18b_19) |
| Figure 7.3 Location of Geotechnical Borings | [63](#i4c7fd59bc6e74e49b8ebc1c48a2ae18b_22) |
| Figure 8.1 NACoal 2020 Round Robin Program Summary. (NACoal, 2020) | [68](#i4c7fd59bc6e74e49b8ebc1c48a2ae18b_22) |
| Figure 9.1 Resource QP Site Visit Photographs | [69](#i4c7fd59bc6e74e49b8ebc1c48a2ae18b_22) |
| Figure 11.1 C Seam Ash Histogram | [82](#i4c7fd59bc6e74e49b8ebc1c48a2ae18b_22) |
| Figure 11.2 C Seam Ash Variogram | [83](#i4c7fd59bc6e74e49b8ebc1c48a2ae18b_22) |
| Figure 11.3 C Seam Thickness Variogram | [83](#i4c7fd59bc6e74e49b8ebc1c48a2ae18b_22) |
| Figure 11.4 Red Hills Mine Mineral Resource Classification for C Seam | [85](#i4c7fd59bc6e74e49b8ebc1c48a2ae18b_25) |
| Figure 13.1 Layout of the Red Hills Mine | [94](#i4c7fd59bc6e74e49b8ebc1c48a2ae18b_31) |
| Figure 13.2 Typical Pit Configuration for plan at steady state. (Mississippi Lignite Mining Company, 2019) | [96](#i4c7fd59bc6e74e49b8ebc1c48a2ae18b_34) |
| Figure 13.3 Soil Stability Assessment. (Barr Engineering, 2014) | [97](#i4c7fd59bc6e74e49b8ebc1c48a2ae18b_34) |
| Figure 13.4 Slope Stability Study (Aquaterra Engineering, LLC., 2010) | [98](#i4c7fd59bc6e74e49b8ebc1c48a2ae18b_34) |
| Figure 13.5 Pit Layout - Truck and shovel operation. (Mississippi Lignite Mining Company, 2019) | [102](#i4c7fd59bc6e74e49b8ebc1c48a2ae18b_34) |
| Figure 13.6 Pit Layout - Dozer operation. (Mississippi Lignite Mining Company, 2019) | [102](#i4c7fd59bc6e74e49b8ebc1c48a2ae18b_34) |
| Figure 13.7 Pit Layout - Dragline operation. (Mississippi Lignite Mining Company, 2019) | [103](#i4c7fd59bc6e74e49b8ebc1c48a2ae18b_34) |
| Figure 15.1 Red Hills Mine Facilities Map | [107](#i4c7fd59bc6e74e49b8ebc1c48a2ae18b_37) |

---

------

SEC S-K 1300 Technical Report Summary

Mississippi Lignite Mining Company – Red Hills Mine&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;March 2023

**Signature and Report Date**

The effective date of this Technical Report Summary (TRS) is December 31, 2022.

---

| | | |
|:---|:---|:---|
| **QP Name** | **Sections Responsible For** | **Signature** |
| Jefferson King, P.E., P.S. | 1.1, 1.4, 1.6, 1.7, 1.8, 1.9, 2.0, 3.0, 4.0, 5.0, 7.3, 7.4, 9.2, 10.0, 12.0, 13.0, 14.0, 15.0, 16.0, 17.0, 18.0, 19.0, 20.0, 22.2, 23.2, 24.0, 25.0 | /s/ Jefferson King |
| Benson Chow, P.G., SME-RM | 1.2, 1.3, 1.5, 1.9, 6.0, 7.1, 7.2, 8.0, 9.1, 11.0, 21.0, 22.1, 23.1, 25.0 | /s/ Benson Chow |

---

------

SEC S-K 1300 Technical Report Summary

Mississippi Lignite Mining Company – Red Hills Mine&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;March 2023

CERTIFICATE OF QUALIFIED PERSON JEFFERSON KING

(a)I am the Engineering Manager at Mississippi Lignite Mining Company's Red Hills Mine in Ackerman, MS; a position I have held since 2022.

(b)This certificate applies to the Technical Report Summary titled, "SEC S-K 1300 Technical Report Summary, Mississippi Lignite Mining Company – Red Hills Mine, Ackerman, Mississippi" with an effective date of December 31, 2022.

(c)I am a Qualified Person (QP) for the purpose of SEC S-K 1300. My qualifications as a QP are as follows:

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;a.I am a graduate of Mississippi State University and graduated with a Bachelor of Science in Civil Engineering in 2003, and a Masters of Business Administration in 2005.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;b.I am a Professional Engineer (License Number 18896) and a Professional Surveyor (License Number 3033) registered in the state of Mississippi.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;c.My relevant experience is over 18 years for the purpose of the Technical Report Summary. This includes 12 years of mining operations experience, which have all been in the coal industry, and 6 years of consulting experience outside of the mining industry.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;d.As the Engineering Manager for Mississippi Lignite Mining Company's Red Hills Mine, I conduct personal inspections of each mining area described in this Technical Report Summary on a regular basis.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;e.I am responsible for the sections listed in the signature table on page 9 of this Technical Report Summary.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;f.I have read the SEC S-K 1300 Technical Report Summary requirements. The part of the Technical Report Summary for which I am responsible has been prepared in compliance with this requirement.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;g.At the effective date of the Technical Report Summary, to the best of my knowledge, information, and belief, the parts of the Technical Report Summary for which I am responsible, contains all scientific and technical information that is required to be disclosed to make the Technical Report Summary not misleading.

------

SEC S-K 1300 Technical Report Summary

Mississippi Lignite Mining Company – Red Hills Mine&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;March 2023

CERTIFICATE OF QUALIFIED PERSON BENSON CHOW

(d)I am the Principal Geologist at NACCO Natural Resources, Plano, TX; a position I held since 2013. I have been employed by NACCO Natural Resources since 1999.

(e)This certificate applies to the Technical Report Summary titled, "SEC S-K 1300 Technical Report Summary, Mississippi Lignite Mining Company – Red Hills Mine, Ackerman, Mississippi" with an effective date of December 31, 2022.

(f) I am a Qualified Person (QP) for the purpose of SEC S-K 1300. My qualifications as a QP are as follows:

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;a.I am a graduate of Mississippi State University with a Bachelor of Science in Geosciences and I graduated in 1998.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;b.I am a Registered Professional Geologist of the state of Mississippi (License Number 0715) and a Registered Member of SME, ID 4317057.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;c.My relevant experience of over 24 years, for the purpose of the Technical Report Summary, includes 8 years of mining operations experience and 16 years of corporate project development experience in various technical roles, of which have been in coal and industrial minerals.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;d.As the Principal Geologist for NACCO Natural Resources, I conducted personal inspections of each mining area described in this Technical Report Summary.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;e.I am responsible for the sections listed in the signature table on page 9 of this Technical Report Summary.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;f.I have read SEC S-K 1300 Technical Report Summary requirements. The part of the Technical Report Summary for which I am responsible has been prepared in compliance with this requirement.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;g.At the effective date of the Technical Report Summary, to the best of my knowledge, information, and belief, the parts of the Technical Report Summary for which I am responsible, contains all scientific and technical information that is required to be disclosed to make the Technical Report Summary not misleading.

------

SEC S-K 1300 Technical Report Summary

Mississippi Lignite Mining Company – Red Hills Mine&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;March 2023

**1. Executive Summary**

This Technical Report Summary (TRS) was prepared for the Mississippi Lignite Mining Company (MLMC) to report Mineral Resources and Mineral Reserves for the Red Hill Mine in Choctaw County, Mississippi.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;**1.1.Property Description and Ownership** 

NACCO Industries (NACCO), through a portfolio of mining and natural resources businesses, operates under three business segments: Coal Mining, North American Mining and Minerals Management. The Coal Mining segment operates surface coal mines under long-term contracts with power generation companies and an activated carbon producer pursuant to a service-based business model. Coal is surface-mined in North Dakota, Texas, Mississippi and Louisiana. Each mine is fully integrated with its customer's operations.

The Red Hills Mine, an active lignite surface mine in Mississippi, is operated by MLMC, a wholly-owned subsidiary of North American Coal (NACoal) which is a wholly-owned subsidiary of NACCO. The Red Hills Mine was designed to supply approximately 2.6 to 3.2 million tons of lignite per year to the adjacent Red Hills Power Plant (RHPP). Actual production is dictated by customer MMBtu demand. MLMC provides the lignite for the RHPP under a contract that runs until April 1, 2032. Mining dimensions are discussed in Sections 13.1 and 13.3 of this TRS.

MLMC is the exclusive supplier of lignite to the RHPP in Choctaw County, Mississippi under a lignite sales agreement (LSA) with Choctaw Generation Limited Partnership (CGLP) that runs until April 1, 2032. The RHPP supplies electricity to the Tennessee Valley Authority (TVA) under a long-term Power Purchase Agreement (PPA). CGLP leases the RHPP from a Southern Company subsidiary pursuant to a leveraged lease arrangement. The Life of Mine (LOM) plan used in this TRS report covers the period from January 1, 2023 through April 1, 2032 as the LOM plan assumes the RHPP will not continue to operate after the expiration of the current LSA with CGLP and the expiration of the existing PPA between TVA and CGLP in April 2032. MLMC sells coal to CGLP at a contractually agreed-upon price which adjusts monthly, primarily based on changes in the level of established indices which reflect general U.S. inflation rates. MLMC is responsible for all operating costs, capital requirements and final mine reclamation. Profitability at MLMC is affected by customer demand for coal and changes in the indices that determine sales price and actual costs incurred. Additional discussion of material contracts is provided in "16.0 Market Studies - 16.2 – Material Contracts."

The Red Hills Mine is located approximately 7 miles northwest of Ackerman, Mississippi in Choctaw County, which is approximately 120 miles northeast of Jackson, Mississippi. The entrance to the mine is by means of a paved road located approximately 1 mile west of MS Highway 9.

MLMC owns in fee approximately 7,773 acres of surface interest and 4,761 acres of coal interest. MLMC holds leases granting the right to mine approximately 5,538 acres of coal interests and the right to utilize approximately 5,065 acres of surface interests. MLMC holds subleases under which it has the right to mine approximately 1,623 acres of coal interest. Most of the leases held by MLMC have terms extending 50 years, and can be further extended by the continuation of mining operations.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;**1.2.Geology and Mineralization**

The Red Hills Mine is in the Wilcox Group of Mississippi which is the most prolific lignite-bearing stratum in the state of Mississippi. The formations within the Wilcox Group and the underlying Midway Group consist of sands, silts, clay, and lignite which were deposited during Paleogene time, approximately 66 to 23 million years ago.

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SEC S-K 1300 Technical Report Summary

Mississippi Lignite Mining Company – Red Hills Mine&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;March 2023

Deposition occurred in a cyclical manner representing a transition from a transgressive sequence of valley fill, marginal marine strata to predominantly regressive, nonmarine, deltaic strata.

During each depositional geologic sequence, organic material was repeatedly buried by sediment in an ideal, oxygen-free environment. This ideal environment was attributed to the humid, subtropical conditions and high water-table of wetlands present during Paleogene time which prevented plant matter from decaying prior to burial. The oxygen-free environment combined with heat and pressure from continual deposition of overlying sediments allowed for the formation of peat and further mineralization of lignite over time by undergoing a process known as humification and biochemical gelification.

The average thickness of the Wilcox section containing the mineable lignite seams at the Red Hills Mine and surrounding area is approximately 140 feet. Mineable lignite seams may be as thin as 1-foot and typically do not exceed 5-feet in thickness. Currently, six primary lignite seams are targeted for mining.

The local structural geology for the Red Hills Mine follows the regional structure with a northwest-southeast strike dipping to the southwest. The lignite seams are gently undulating due to differential compaction of the underlying sediments.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;**1.3.Status of Exploration** 

Exploration programs described in this TRS have considered the stratigraphic nature of the mineralization for the determination of hole spacing, drilling and sampling method, and quality analyses in order to geologically map and evaluate the structural and quality characteristics of the lignite deposit. The Red Hills Mine lignite deposit is evaluated on a seam-by-seam basis. Drilling exploration data including geologic lithologies, qualities, and hole locations have been compiled in an electronic, geologic database.

From 1975 through 1980 drilling campaigns were completed under the sole direction of Phillips Coal Company (Phillips). Since 1997, independent drilling and geophysical logging contractors have operated under the guidance and direction of MLMC.

Over 1,400 drill holes including pilot holes, coal core holes, overburden holes, geotechnical holes, and monitoring wells have been drilled within the Red Hills Mine lignite deposit. Drilling campaigns conducted at the mine have comprised largely of rotary wash drilling methods. Drill holes were geophysically logged for natural gamma, density, caliper, and resistivity responses to obtain data related to the subsurface structure. Coal core samples collected for quality analyses were sent to independent commercial laboratories for testing.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;**1.4.Development and Operations** 

The Red Hills Mine is a multiple lignite seam surface mining operation which supplies approximately 2.6 to 3.2 million tons of lignite per year to the adjacent RHPP. Actual annual production is dictated by customer demand. The RHPP supplies electricity to TVA under a long-term PPA. MLMC's customer's demand for coal is driven by the decision of which power plants to dispatch as determined by TVA. An increase in the number of days TVA dispatches the RHPP would increase demand. A decrease in the number of days TVA dispatches the RHPP would reduce demand.

The lignite at the Red Hills Mine surface mining operation is uncovered using dragline, dozer push, and conventional truck and shovel mining methods due to the proximity of the lignite to the surface and the physical characteristics of the deposit. Lignite is mined using a surface miner or a hydraulic backhoe to load a fleet of end dump haul trucks and is directly shipped to the RHPP or the lignite stockpile. The overall average ROM quality of

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SEC S-K 1300 Technical Report Summary

Mississippi Lignite Mining Company – Red Hills Mine&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;March 2023

the mined lignite seams meets the required power plant quality specifications. Therefore, no mineral processing is performed by MLMC.

The Red Hills Mine began operations in the MS-002 permit area in Mine Area 1 and is in the process of transitioning to Mine Area 3 which is within the MS-004 permit area. Initial development of the Red Hills Mine began in 1998, with full production and commercial deliveries commencing in 2002. Boxcut construction for Mine Area 3 began in 2021 where mining will continue until April 1, 2032. The Red Hills Mine has, or is currently constructing, all supporting infrastructure for mining operations within the permitted areas.

The Red Hills Mine employs a staff and workforce of approximately 200 employees with fluctuations in employment levels for changes in demand at the RHPP or special projects such as the transition of mining from Mine Area 1 to Mine Area 3.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;**1.5.Mineral Resource Estimate** 

The Mineral Resources in this TRS have been estimated by applying a series of geologic and physical limits as well as high-level mining and economic constraints. The mining and economic constraints were limited to a level sufficient to support reasonable prospect for economic extraction of the estimated Mineral Resources. The potential for economic extraction is justified by the terms of the existing LSA with the RHPP that runs through April 2032.

The QP based the Mineral Resource estimates for the Red Hills Mine on a stratigraphic geologic model generated from the verified drilling exploration data. For a lignite seam to be considered a Mineral Resource by the QP, the seam must have a minimum of ten coal core samples for quality estimation, a maximum ash cutoff of 30% and a minimum calorific value cutoff of 4,000 BTU/lb, both on an as-received moisture basis, and a minimum thickness of 1 foot. Mineral Resources were then further defined for each identified lignite seam by applying projected pit shells based on physical constraints, including but not limited to lease and fee coal boundaries, and a maximum cumulative stripping ratio of 18:1 based on an assumed lignite sales price of $29.66 per ton.

Mineral Resources were divided into three categories of Measured, Indicated, or Inferred and were ranked by increasing level of confidence. The Mineral Resource categorization applied by the QP included the consideration of the type and amount of data per drill hole and the variography of quality and structural continuity among holes with the C Seam present and cored. Measured Mineral Resources are defined as tonnages which meet the general resource requirements and fall within an area where the distance from a core hole is less than or equal to 2,667 feet. Indicated Mineral Resources are defined as tonnages which meet the general resource requirements and fall within an area where the distance from a core hole is greater than 2,667 feet and less than or equal to 5,333 feet. Inferred Mineral Resources are defined as tonnages which meet the general resource requirements and fall within an area where the distance from a core hole is greater the 5,333 feet and less than or equal to 8,000 feet.

Mineral Resources as of December 31, 2022 are shown in Table 1.1, and are reported as in-situ tons such that no adjustments were made to account for mining recovery or losses. Mineral Resources are reported exclusive of in-situ Mineral Reserves.

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SEC S-K 1300 Technical Report Summary

Mississippi Lignite Mining Company – Red Hills Mine&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;March 2023

**Table 1.1 Mineral Resource Estimates as of December 31, 2022**

---

| | | | | | | |
|:---|:---|:---|:---|:---|:---|:---|
| | | | **Quality (As-Received)** | **Quality (As-Received)** | **Quality (As-Received)** | **Quality (As-Received)** |
|<br>**Red Hills Mine** |<br>**Resource Classification** |<br>**Tonnage**<br>**(Kt)** | **Calorific Value (Btu/lb)** | **Moisture (%wt)** | **Ash (%wt)** | **Sulfur (%wt)** |
| Mine Area 1 | Measured | 0 | 0 | 0.0 | 0.0 | 0.0 |
| Mine Area 1 | Indicated | 0 | 0 | 0.0 | 0.0 | 0.0 |
| Mine Area 1 | Measured + Indicated | 0 | 0 | 0.0 | 0.0 | 0.0 |
| Mine Area 1 | Inferred | 0 | 0 | 0.0 | 0.0 | 0.0 |
| Mine Area 2 | Measured | 4300 | 5210 | 44.6 | 12.8 | 0.6 |
| Mine Area 2 | Indicated | 400 | 5230 | 44.3 | 12.8 | 0.6 |
| Mine Area 2 | Measured + Indicated | 4700 | 5210 | 44.5 | 12.8 | 0.6 |
| Mine Area 2 | Inferred | 0 | 0 | 0.0 | 0.0 | 0.0 |
| Mine Area 3 | Measured | 0 | 0 | 0.0 | 0.0 | 0.0 |
| Mine Area 3 | Indicated | 100 | 5490 | 41.6 | 12.4 | 1.0 |
| Mine Area 3 | Measured + Indicated | 100 | 5490 | 41.6 | 12.4 | 1.0 |
| Mine Area 3 | Inferred | 1600 | 5370 | 46.0 | 9.9 | 0.5 |
| Total Resources | Measured | 4300 | 5210 | 44.6 | 12.8 | 0.6 |
| Total Resources | Indicated | 500 | 5300 | 43.6 | 12.7 | 0.7 |
| Total Resources | Measured + Indicated | 4800 | 5220 | 44.5 | 12.8 | 0.6 |
| Total Resources | Inferred | 1600 | 5370 | 46.0 | 9.9 | 0.5 |

---

Notes:

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;1.Mineral Resources that are not Mineral Reserves do not have demonstrated economic viability and there is no certainty that all or any part of such Mineral Resources will be converted into Mineral Reserves.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;2.Mineral Resources are in-situ and exclusive of 25.4 million tons (Mt) of Mineral Reserves.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;3.Mineral Resources are reported using an economic cutoff of $29.66 per ton coal.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;4.Resources are presented with a minimum 1 foot seam thickness, a maximum as-received moisture basis ash content of 30%, and a minimum calorific value of 4,000 BTU/lb on an as-received moisture basis.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;5.Resources are estimated using Vulcan Software.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;6.Tonnages and qualities have been rounded to an accuracy level deemed appropriate by the QP. Summation errors due to rounding may exist.

In the opinion of the QP it is important to note that additional exploration may positively or negatively affect Mineral Resource estimates. Additionally, Mineral Resource estimates may be materially affected by a change in the assumptions including general mining costs and land control. New regulations may also impose additional economic factors, delays to future permit renewals, or restrictions to physical estimation boundaries.

At the time of this TRS, the QP is not aware of any specific factors that would materially affect the Mineral Resource estimates presented herein.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;**1.1.Mineral Reserve Estimate** 

The Mineral Reserves in this TRS were determined to be the economically mineable portion of the Measured and Indicated Mineral Resources after the consideration of modifying factors related to the mining process, which convert Measured Resources to Proven Mineral Reserves and Indicated Resources to Probable Mineral Reserves. Inferred Mineral Resources were not considered for Mineral Reserves.

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SEC S-K 1300 Technical Report Summary

Mississippi Lignite Mining Company – Red Hills Mine&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;March 2023

Parameters for mining dilution, minimum mining thickness, and minimum parting thickness were applied by the QP to the geologic model to create the Mineral Reserve model. Mining pits were projected based on current mining equipment operating parameters and a maximum cumulative stripping ratio of 14:1, over the entire area evaluated, based on an estimated average price per ton of $36.06. Mining pits were then sectioned into 500-foot blocks; adjusting endwall blocks as necessary. Blocks were reviewed by the QP to ensure quality thresholds were met. Recovery rates were applied to the lignite tonnages by seam and then the blocks were sequenced based on a projected total delivered heat requirement measured in million British Thermal Units (MMBTU) through the LOM plan to determine the Measured and Indicated Resources that would be converted to Proven and Probable Mineral Reserves. The details of the LOM plan are shown in Table 1.2.

**Table 1.2 LOM Production Schedule** 

---

| | | | | | | |
|:---|:---|:---|:---|:---|:---|:---|
| | **2023** | **2024** | **2025** | **2026** | **2027** | **2028** |
| Delivered Coal (000 tons) | 2900 | 2800 | 2700 | 2700 | 2800 | 2800 |
| Delivered MMBTU (000) | 30000 | 29000 | 27700 | 27700 | 27700 | 27700 |
| Calorific Value, Btu/lb | 5120 | 5110 | 5100 | 5090 | 5050 | 5040 |
| Total Overburden Material (000 CY) | 37200 | 32900 | 32800 | 35100 | 42000 | 41200 |
|  | **2029** | **2030** | **2031** | **2032** | **Total** |  |
| Delivered Coal (000 tons) | 2700 | 2700 | 2600 | 700 | **25400** |  |
| Delivered MMBTU (000) | 27700 | 27700 | 27700 | 6900 | **259800** |  |
| Calorific Value, Btu/lb | 5090 | 5180 | 5250 | 5260 | **5100** |  |
| Total Overburden Material (000 CY) | 47100 | 51800 | 51800 | 9300 | **381200** |  |

---

This disclosure of Mineral Reserves is based upon the QP's opinion that the LOM plan and cost estimates have been completed to a Pre-feasibility (PFS) level of accuracy, as defined in 17 Code of Federal Regulations (CFR) Part 229.1300, which includes and supports the QP's determination of Mineral Reserves.

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SEC S-K 1300 Technical Report Summary

Mississippi Lignite Mining Company – Red Hills Mine&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;March 2023

The Red Hills Mine Mineral Reserve estimate as of December 31, 2022 is shown in Table 1.3.

**Table 1.3 Mineral Reserve Estimate as of December 31, 2022**

---

| | | | | | | |
|:---|:---|:---|:---|:---|:---|:---|
| | | | **Quality** | **Quality** | **Quality** | **Quality** |
| **Red Hills Mine** | **Reserve Classification** | **Tonnage (Kt)** | **Calorific Value (Btu/lb)** | **Moisture (%wt)** | **Ash (%wt)** | **Sulfur (%wt)** |
| Mine Area 1 | Proven | 900 | 4980 | 43.5 | 15.8 | 0.6 |
| Mine Area 1 | Probable | 0 | 4710 | 42.0 | 20.5 | 0.6 |
| Mine Area 1 | Total | 900 | 4980 | 43.4 | 15.9 | 0.6 |
| Mine Area 3 | Proven | 16200 | 5100 | 43.4 | 14.8 | 0.6 |
| Mine Area 3 | Probable | 7400 | 5120 | 42.5 | 15.2 | 0.7 |
| Mine Area 3 | Total | 23600 | 5110 | 43.1 | 14.9 | 0.6 |
| Stockpile & Silos | Proven | 900 | 5080 | 43.2 | 15.4 | 0.5 |
| Total Reserves | Proven | 18000 | 5090 | 43.4 | 14.8 | 0.6 |
| Total Reserves | Probable | 7400 | 5120 | 42.6 | 15.4 | 0.7 |
| Total Reserves | Total | 25400 | 5100 | 43.1 | 15.0 | 0.6 |

---

Notes:

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;1.Mineral Reserves use an economic cutoff of a maximum cumulative stripping ratio of 14:1. There are some instances where the stripping ratio for a single year could exceed 14:1, but the average for the entire area evaluated is less than 14:1.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;2.Historical coal recovery rates at Red Hills Mine have been applied to generate the Mineral Reserve tonnages.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;3.Mineral Reserves are estimated using Vulcan Software.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;4.Tonnages and qualities have been rounded to an accuracy level deemed appropriate by the QP. Summation errors due to rounding may exist.

The QP's opinion on risks that could potentially affect the Mineral Reserve estimates include changes in customer demand for any reason, including, but not limited to, dispatch of power generated by other energy sources ahead of coal, fluctuations in demand due to unanticipated weather conditions, regulations or comparable policies which could potentially promote planned and unplanned outages at the RHPP, economic conditions, including an economic slowdown that would affect manufacturing and a corresponding decline in the use of electricity, governmental regulations and/or inflationary adjustments. All of which could potentially have a material adverse effect on MLMC's financial condition.

At the time of this TRS, the QP is not aware of any specific factors that would materially affect the Mineral Reserve estimates.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;**1.1.Economic Assessment** 

The primary driver in determining the economic viability of the Red Hills Mine was the expected annual operating performance of the RHPP, which was forecasted using two main inputs: the annual projection notice (nomination for MMBtu requirements) received from the RHPP and a comparison to historical prior years actual delivered lignite fuel. The typical annual MMBtu requirement used in the Red Hills LOM Economic Model was approximately 27.7 million MMBtu. The MMBtu requirement for the first two years was slightly higher due to speculation of higher natural gas prices that would increase RHPP dispatch. This resulted in a production schedule of approximately 2.7 million tons (Mt) of dedicated lignite per year each year until LSA contract expiration in April 2032.

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SEC S-K 1300 Technical Report Summary

Mississippi Lignite Mining Company – Red Hills Mine&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;March 2023

LOM operating costs for a plan delivering approximately 27.7 million MMBtu per year to the RHPP total approximately $907 million (M). Operating costs included major cost categories for mine development, burden removal, severing of lignite, reclamation, maintenance and handling of stockpiled lignite and delivery to the adjacent RHPP along with the necessary maintenance required to keep all equipment operating safely and efficiently.

Capital costs to fulfill the LSA for a plan delivering approximately 27.7 million MMBtu per year to the RHPP are expected to total approximately $31 M. Capital Costs included categories for equipment expenditures, mine development, mitigation, and land acquisitions.

The base price for the dedicated lignite is defined in the LSA and consists of eight indexed components in addition to a power cost component, a pass-through component, a royalty component and a fixed component. The base price in the LOM is evaluated on an annual basis and is determined based on the actual performance of the 8 indexed components specified in the LSA. Over the LOM plan, the average price per ton for lignite delivered and sold is $36.06 providing revenues totaling approximately $914 M. The Red Hills Mine began commercial deliveries in 2001. The sales price over the last three years has averaged approximately $28 as shown in Table 1.4. The forecasted coal price for the LOM is also shown in Table 1.4.

**Table 1.4 Historical and Forecasted Coal Price** 

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| | | | | | | | | | | | |
|:---|:---|:---|:---|:---|:---|:---|:---|:---|:---|:---|:---|
| Historical | 2013 | 2014 | 2015 | 2016 | 2017 | 2018 | 2019 | 2020 | 2021 | 2022 | Total\* |
| Tons Sold (000 ton) | 3200 | 2600 | 3200 | 3000 | 2400 | 3000 | 2600 | 2500 | 3000 | 3200 | 28700 |
| Coal Price $/Ton | 20.61 | 21.61 | 22.61 | 23.61 | 24.61 | 25.61 | 26.61 | 27.61 | 27.20 | 29.66 | 28.16 |
| Forecasted | 2023 | 2024 | 2025 | 2026 | 2027 | 2028 | 2029 | 2030 | 2031 | 2032 | Total |
| Tons Sold (000 ton) | 2900 | 2800 | 2700 | 2700 | 2800 | 2800 | 2700 | 2700 | 2600 | 700 | 25400 |
| Coal Price $/Ton | 29.65 | 32.95 | 34.64 | 33.60 | 36.78 | 37.06 | 38.29 | 39.80 | 40.00 | 45.37 | 36.06 |

---

\*Average Coal price $/ton is from 2020-2022.

The projected annual cash flow forecast based on the lignite production schedule over the remaining LOM results in a total after-tax cash flow projection of $121 M resulting in a net present value of $73 M after tax at a 10% discount rate.

The Economic Assessment used what could be considered a conservative assumption in light of historical trends, current conditions and expected future developments for delivered fuel to the RHPP of approximately 27.7 million MMBtu annually. Therefore, the QP is of the opinion that any downside risks to the economic viability of the project to be minimal. There is a risk to the LOM plan if the RHPP takes less than the LOM plan MMBtu's, but this scenario is not considered a significant risk as a result of the minimum take provisions included in the LSA. Other downside risks considered were the effects of an increase in diesel prices and labor.

The Income Statement and Annual Cash Flows based on the lignite production schedule for the LOM plan, along with the Net Present Value are detailed in Table 1.5. A Discount Rate of 10% was used, as this was consistent with the Red Hills Mine's weighted average cost of capital. The calculation of Net Present Value and Internal Rate of Return are nuanced due to the ongoing nature of this mining operation. As modeled, the cash flows for the period 2023 through 2045 indicate the project is cash flow positive over the remaining life of the project.

In the opinion of the QP, the income statement and cash flow projection based on the LOM plan assumptions as shown in Table 1.5 are reasonable in light of historical trends, current conditions and expected future developments. As modeled, the future cash flow projection is estimated to be approximately $121 M and the net present value is estimated to be approximately $73 M after tax.

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SEC S-K 1300 Technical Report Summary

Mississippi Lignite Mining Company – Red Hills Mine&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;March 2023

Note that the net present value estimated for this report does not consider previous cash inflows and outflows and is only estimated from 2023 through the remainder of the LOM and therefore does not consider any historical cash flows already realized.

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SEC S-K 1300 Technical Report Summary

Mississippi Lignite Mining Company – Red Hills Mine&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;March 2023

**Table 1.5 Summary of Income Statement and Cash Flow for LOM plan delivering approximately 27.7 million MMBtu**![image_1.jpg](image_1.jpg)

![image.jpg](image.jpg)

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SEC S-K 1300 Technical Report Summary

Mississippi Lignite Mining Company – Red Hills Mine&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;March 2023

&nbsp;&nbsp;&nbsp;&nbsp;**1.8. Permitting Requirements**

The Red Hills Mine operates under the state of Mississippi Surface Coal Mining and Reclamation Permit MS-002, Renewal 3 and Surface Coal Mining and Reclamation Permit MS-004 issued by the Mississippi Department of Environmental Quality (MDEQ) under delegated authority of the United States Department of the Interior, Office of Surface Mining Reclamation Enforcement (OSMRE) Surface Mining Control and Reclamation Act (SMCRA). In addition to the mining permit, MLMC has secured 45 other permit and agreements, including a National Pollutant Discharge Elimination System (NPDES) permit and an Individual Permit issued by the United States Army Corp of Engineers (USCOE). All permits have been secured and continue to be renewed in a timely fashion.

MLMC currently has all permits in place for the Red Hills Mine to operate and adhere to a mine plan projected through April 2032. Barring any regulatory changes out of MLMC's control, the QP does not anticipate hurdles for approval of future renewal applications.

&nbsp;&nbsp;&nbsp;&nbsp;**1.9. Qualified Person's Conclusions and Recommendations**

In the QP's opinion, the geological data, sampling, modeling, and estimate are carried out in a manner that both represents the data well and mitigates the likelihood of material misrepresentations for the statements of Mineral Resources. Additional drilling and sampling should be performed in Mine Area 3 to better define upper seams qualities while expanding and upgrading mineral resources and reserves. Representative splits from coal cores samples should be tested by an independent laboratory different from the testing laboratory and inclusion of sample standards and blanks should be performed for QA/QC protocol.

In the QP's opinion, the operational and mine planning data, LOM Plan, and estimation are carried out in a manner that both represents the data and operational experience and methodology well and mitigates the likelihood of material misrepresentations for the statements of Mineral Reserves. Current additional work that is budgeted in the discounted cash flows (DCF) that the Red Hills Mine will complete include:

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• Continue with the exploration drilling program;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• Monitor pit pore pressures in future pit area identified of potential concern;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• Continue to evaluate used equipment to reduce capital costs;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• Continue the current practice of reconciliation of actual to budget lignite recoveries, qualities, and costs;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• Update the LOM plan and economic analyses accordingly.

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SEC S-K 1300 Technical Report Summary

Mississippi Lignite Mining Company – Red Hills Mine&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;March 2023

**2. Introduction**

This Technical Report Summary (TRS) was prepared for the Mississippi Lignite Mining Company (MLMC), a wholly-owned subsidiary of the North American Coal Corporation (NACoal) which is a wholly-owned subsidiary of NACCO Natural Resources.

The purpose for which this TRS was prepared is to report Mineral Resources and Mineral Reserves for the Red Hill Mine located in Choctaw County, Mississippi.

The sources of information and data contained in the technical report or used in its preparations were supplied by MLMC and include data used to produce geologic models, Annual and Life of Mine (LOM) plans, production data, environmental support documents, independent technical studies, resource and reserve estimates, cost estimates, and economic analyses. A large portion of the technical information is summarized from active Surface Mining Control and Reclamation Act (SMCRA) permits addressing Title 11 of the Miss. Admin. Code Pt.8, Ch-2, Mississippi Commission on Environmental Quality Regulations Governing Surface Coal Mining, hereby known as the mine permit requirements. Additional references to specific studies and documents are provided in Section 24.0 of this TRS.

Benson Chow, Mineral Resource QP, is a Registered Professional Geologist in the state of Mississippi, License Number 0175 and a Registered Member of the Society for Mining, Metallurgy & Exploration (SME), ID 4317057 and is in good standing with both organizations. He has been involved with the exploration, geology, and mining operations at Red Hills Mine since 1999 and his most recent site visit was on February 13 through 16, 2023. The purpose of this visit was to complete a site visit of the two active mining areas and independent verification of the exploration drill holes. During the visit the QP completed the following task:

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• Inspected the active pit areas for Mine Area 1 west, middle and east end of the pit.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• Observed the extraction of the D Seam coal using the Wirtgen in Mine Area 1. Visited the boxcut in Mine Area 3. Performed survey verification of several previously drilled exploration drill holes.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• Verified drill hole collar locations and elevations from the 2011, 2015, and 2021 drilling programs.

Jefferson King, is serving as the Mineral Reserve QP, a licensed Professional Engineer (License Number 18896) and Land Surveyor (License Number 3033) in the State of Mississippi. He has had direct involvement with production, technical projects, development of the LOM plan and financial analysis since 2013. He has held various roles in the Engineering department at Red Hills and is currently serving as the Engineering Manager. In the role of Engineering Manager, he has direct involvement with daily production operations and oversight and management of technical projects, and is directly involved in the development of the LOM finances at the Red Hills Mine.

Unless otherwise stated, the terms of reference for this TRS include:

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• US English spelling;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• Imperial units of measurement;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• Lignite qualities are presented in weight percent (wt%) and lignite tonnages are present in short tons (2000 lbs);

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• Coordinate System is presented in imperial units using the North American Datum 1983 (NAD83);

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• Nominal US Dollars as of 2022.

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SEC S-K 1300 Technical Report Summary

Mississippi Lignite Mining Company – Red Hills Mine&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;March 2023

This is the second TRS filed to the United States Securities and Exchange Commission (SEC) for MLMC. The previous TRS was dated December 16, 2022 and titled: "SEC S-K 1300 Technical Report Summary, Revision 1, Mississippi Lignite Mining Company – Red Hills Mine, Ackerman, Mississippi."

Key Acronyms and definitions for this TRS include:

---

| | |
|:---|:---|
| &nbsp;&nbsp;AOP | &nbsp;&nbsp;Annual Operating Plan |
| &nbsp;&nbsp;AR | &nbsp;&nbsp;As-Received Basis |
| &nbsp;&nbsp;ARO | &nbsp;&nbsp;Asset Retirement Obligation |
| &nbsp;&nbsp;ASTM | &nbsp;&nbsp;American Society for Testing and Materials |
| &nbsp;&nbsp;BCY | &nbsp;&nbsp;Bank Cubic Yard |
| &nbsp;&nbsp;BMPs | &nbsp;&nbsp;Best Management Practices |
| &nbsp;&nbsp;BOX | &nbsp;&nbsp;Base of Oxidation |
| &nbsp;&nbsp;BUD | &nbsp;&nbsp;Beneficial (Ash) Use Determination |
| &nbsp;&nbsp;Cardno GLS | &nbsp;&nbsp;Cardno Geophysical Logging Services |
| &nbsp;&nbsp;Century GLS | &nbsp;&nbsp;Century Geophysical Logging Services |
| &nbsp;&nbsp;CGLP | &nbsp;&nbsp;Choctaw Generation Limited Partnership |
| &nbsp;&nbsp;COC | &nbsp;&nbsp;Chain of Custody |
| &nbsp;&nbsp;CRIRSCO | &nbsp;&nbsp;Committee for Mineral Reserves International Reporting Standards |
| &nbsp;&nbsp;DMRs | &nbsp;&nbsp;Discharge Monitoring Reports |
| &nbsp;&nbsp;DTM | &nbsp;&nbsp;Digital Terrain Model |
| &nbsp;&nbsp;EIS | &nbsp;&nbsp;Environmental Impact Statement |
| &nbsp;&nbsp;FoS | &nbsp;&nbsp;Factor of Safety |
| &nbsp;&nbsp;GEA | &nbsp;&nbsp;Geotechnical Engineering Associates |
| &nbsp;&nbsp;gpm | &nbsp;&nbsp;Gallons per Minute |
| &nbsp;&nbsp;GSE | &nbsp;&nbsp;Great Southern Engineering |
| &nbsp;&nbsp;HDPE | &nbsp;&nbsp;High Density Polyethylene |
| &nbsp;&nbsp;Kt | &nbsp;&nbsp;Kiloton |
| &nbsp;&nbsp;Lbs | &nbsp;&nbsp;Pounds |
| &nbsp;&nbsp;LOM | &nbsp;&nbsp;Life of Mine |
| &nbsp;&nbsp;LSA | &nbsp;&nbsp;Lignite Sales Agreement |
| &nbsp;&nbsp;M | &nbsp;&nbsp;Million (dollars) |
| &nbsp;&nbsp;MA1 | &nbsp;&nbsp;Mine Area 1 |
| &nbsp;&nbsp;MA3 | &nbsp;&nbsp;Mine Area 3 |
| &nbsp;&nbsp;MDA&H | &nbsp;&nbsp;Mississippi Department of Archives and History |
| &nbsp;&nbsp;MDEQ | &nbsp;&nbsp;Mississippi Department of Environmental Quality |
| &nbsp;&nbsp;MDOT | &nbsp;&nbsp;Mississippi Department of Transportation |
| &nbsp;&nbsp;MLMC | &nbsp;&nbsp;The Mississippi Lignite Mining Company |
| &nbsp;&nbsp;MMbtu | &nbsp;&nbsp;Metric Million British Thermal Units |
| &nbsp;&nbsp;MS-002 permit | &nbsp;&nbsp;Surface Mining Control and Reclamation Act (SMCRA) permit MS-002, Renewal 3 |
| &nbsp;&nbsp;MS-004 permit | &nbsp;&nbsp;Surface Mining Control and Reclamation Act (SMCRA) permit MS-004 |
| &nbsp;&nbsp;mg/L | &nbsp;&nbsp;Milligrams per Liter |
| &nbsp;&nbsp;msl | &nbsp;&nbsp;Mean Sea Level |
| &nbsp;&nbsp;Mt | &nbsp;&nbsp;Million Tons |
| &nbsp;&nbsp;MSU | &nbsp;&nbsp;Mississippi State University |
| &nbsp;&nbsp;MS | &nbsp;&nbsp;Mississippi |
| &nbsp;&nbsp;NACCO | &nbsp;&nbsp;NACCO Industries |
| &nbsp;&nbsp;NACoal | &nbsp;&nbsp;North American Coal |
| &nbsp;&nbsp;NOV | &nbsp;&nbsp;Notice of Violation |
| &nbsp;&nbsp;NPDES | &nbsp;&nbsp;National Pollutant Discharge Elimination System |

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SEC S-K 1300 Technical Report Summary

Mississippi Lignite Mining Company – Red Hills Mine&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;March 2023

---

| | |
|:---|:---|
| &nbsp;&nbsp;NPS | &nbsp;&nbsp;National Park Service |
| &nbsp;&nbsp;NRCS | &nbsp;&nbsp;Natural Resources Conservation Service |
| &nbsp;&nbsp;OSMRE | &nbsp;&nbsp;United States Department of the Interior, Office of Surface Mining Reclamation Enforcement |
| &nbsp;&nbsp;Phillips | &nbsp;&nbsp;Phillips Coal Company |
| &nbsp;&nbsp;Prox | &nbsp;&nbsp;Proximate |
| &nbsp;&nbsp;PPA | &nbsp;&nbsp;Power Purchase Agreement |
| &nbsp;&nbsp;QAR PTP | &nbsp;&nbsp;Proficiency Testing Program by Quality Assurance Resources, LLC |
| &nbsp;&nbsp;QA/QC | &nbsp;&nbsp;Quality Assurance/Quality Control |
| &nbsp;&nbsp;QP(s) | &nbsp;&nbsp;Qualified Person(s) |
| &nbsp;&nbsp;RHPP | &nbsp;&nbsp;Red Hills Power Plant |
| &nbsp;&nbsp;R-O-M | &nbsp;&nbsp;Run of Mine |
| &nbsp;&nbsp;R-O-W | &nbsp;&nbsp;Right of Way |
| &nbsp;&nbsp;SEC | &nbsp;&nbsp;United States Security and Exchange Commission |
| &nbsp;&nbsp;SG | &nbsp;&nbsp;Specific Gravity |
| &nbsp;&nbsp;S-K 1300 | &nbsp;&nbsp;SEC's Subpart S-K 1300 (17 CFR Part 229.1300) |
| &nbsp;&nbsp;SMCRA | &nbsp;&nbsp;Surface Mining Control and Reclamation Act |
| &nbsp;&nbsp;SPGM | &nbsp;&nbsp;Suitable Plant Growth Material |
| &nbsp;&nbsp;SPT | &nbsp;&nbsp;Standard Penetration Testing |
| &nbsp;&nbsp;SWPPP | &nbsp;&nbsp;Storm Water Pollution and Prevention Plan |
| &nbsp;&nbsp;TDS | &nbsp;&nbsp;Total Dissolved Solids |
| &nbsp;&nbsp;TRS | &nbsp;&nbsp;Technical Report Summary |
| &nbsp;&nbsp;TSS | &nbsp;&nbsp;Total Suspended Solids |
| &nbsp;&nbsp;TVA | &nbsp;&nbsp;the Tennessee Valley Authority |
| &nbsp;&nbsp;USCOE | &nbsp;&nbsp;United States Corps of Engineers |
| &nbsp;&nbsp;USCS | &nbsp;&nbsp;Unified Soil Classification System |
| &nbsp;&nbsp;USGS | &nbsp;&nbsp;United States Geological Survey |
| &nbsp;&nbsp;WOTUS | &nbsp;&nbsp;Waters of the United States |

---

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SEC S-K 1300 Technical Report Summary

Mississippi Lignite Mining Company – Red Hills Mine&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;March 2023

**3. Property Description**

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;**3.1.Property Location** 

The Red Hills Mine is an operating lignite surface mine located approximately 7 miles northwest of Ackerman, Mississippi, in Choctaw County, which is approximately 120 miles northeast of Jackson, Mississippi (Figure 3.1).

**Figure 3.1 Regional Location Map**

![image_2.jpg](image_2.jpg)

The entrance to the mine is by means of a paved road that is located approximately 1 mile west of MS Highway 9. The general location of the Red Hills Mine is shown in Figure 3.2. The RHPP is adjacent to the Red Hills Mine.

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SEC S-K 1300 Technical Report Summary

Mississippi Lignite Mining Company – Red Hills Mine&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;March 2023

**Figure 3.2 Location of the Red Hills Mine**

![image_3.jpg](image_3.jpg)

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SEC S-K 1300 Technical Report Summary

Mississippi Lignite Mining Company – Red Hills Mine&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;March 2023

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;**3.2.Property Area**

The Red Hills Mine is encompassed by two permit areas, MS-002 and MS-004 as indicated in Figure 3.1. One Mineral Resource areas fall within the MS-002 permit area, and is identified as Mine Area 2. A second Mineral Resource area falls within the MS-004 permit area, and is identified as Mine Area 3. Mine Area 1 and Mine Area 3 include Mineral Reserves. Mine Area 2 is a small, permitted auxiliary pit which may be used for tons to supplement the mine plan, but is not currently sequenced in the LOM plan, and as such only includes Mineral Resources, not Mineral Reserves. Mine Area 1 is 202 acres, Mine Area 2 is 202 acres, and Mine Area 3 is 1,915 acres.

MLMC holds leases granting the right to mine approximately 5,538 acres of coal interests and the right to utilize approximately 5,065 acres of surface interests. In addition to leases with independent landowners, MLMC owns in fee approximately 7,773 acres of surface interest and 4,761 acres of coal interest. MLMC holds subleases under which it has the right to mine approximately 1,623 acres of coal interest.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;**3.3.Leases and Mineral Rights**

The name or number and expiration date of each title, claim, mineral right, lease, or option under which MLMC or an affiliated NACCO company has or will have the right to hold or operate on the property is described on Table 3.1 and Table 3.2.

The leases, sub-leases and fee acquisitions were obtained by land acquisition staff employed by Phillips and NACoal. Most of the leases held by MLMC have terms extending 50 years, and can be further extended by the continuation of mining operations. The surface and mineral leases and associated sub-leases held by MLMC require payments specified by lease agreement to retain the property. Typically, a standard production royalty rate of $0.50 per ton of lignite mined is tied to the leases. Royalties are estimated monthly based on surveyed mined tons and are paid to the landowners on a quarterly basis. In addition to production royalties, payments related to landowner leases may also include surface damage payments and/or advanced royalties.

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SEC S-K 1300 Technical Report Summary

Mississippi Lignite Mining Company – Red Hills Mine&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;March 2023

---

| | | | |
|:---|:---|:---|:---|
| **Table 3.1 Identification of Leases**  | **Table 3.1 Identification of Leases**  | **Table 3.1 Identification of Leases**  | **Table 3.1 Identification of Leases**  |
| **Lease Id** | **Lease Type** | **Lease Date** | **Lease Expiration Date** |
| 955-900002 | Coal Lease | 12/31/2013 | 12/30/2038 |
| 955-900003 | Coal Lease | 12/31/2013 | 12/30/2038 |
| 955-900004 | Coal Lease | 12/31/2013 | 12/30/2038 |
| 955-900005 | Coal Lease | 12/31/2013 | 12/30/2038 |
| 955-900006 | Coal Lease | 12/31/2013 | 12/30/2038 |
| 955-900007 | Coal Lease | 12/31/2013 | 12/30/2038 |
| 955-900008 | Coal Lease | 12/31/2013 | 12/30/2038 |
| 955-900009 | Coal Lease | 12/31/2013 | 12/30/2038 |
| 955-900010 | Coal Lease | 12/31/2013 | 12/30/2038 |
| 955-900011 | Coal Lease | 12/31/2013 | 12/30/2038 |
| 955-900012 | Coal Lease | 12/31/2013 | 12/30/2038 |
| 955-900013 | Coal Lease | 12/31/2013 | 12/30/2038 |
| 955-900014 | Coal Lease | 12/31/2013 | 12/30/2038 |
| 955-900015 | Coal Lease | 12/31/2013 | 12/30/2038 |
| 955-900016 | Coal Lease | 12/31/2013 | 12/30/2038 |
| 955-900017 | Coal Lease | 12/31/2013 | 12/30/2038 |
| 955-900018 | Coal Lease | 12/31/2013 | 12/30/2038 |
| 955-900019 | Coal Lease | 12/31/2013 | 12/30/2038 |
| 955-900023 | Coal Lease | 7/10/2015 | 7/9/2040 |
| 955-900024 | Coal Lease | 7/10/2015 | 7/9/2040 |
| 955-900025 | Coal Lease | 7/10/2015 | 7/9/2040 |
| 955-900026 | Coal Lease | 7/10/2015 | 7/9/2040 |
| 955-900027 | Coal Lease | 7/10/2015 | 7/9/2040 |
| 955-900028 | Coal Lease | 7/10/2015 | 7/9/2040 |
| 955-900029 | Coal Lease | 7/10/2015 | 7/9/2040 |
| 955-900030 | Coal Lease | 10/26/2015 | 10/25/2040 |
| 955-900031 | Coal Lease | 10/26/2015 | 10/25/2040 |
| 955-900032 | Coal Lease | 5/6/2016 | 5/5/2041 |
| 955-900033 | Coal Lease | 10/1/2017 | 9/30/2042 |
| 955-900038 | Coal Lease | 6/1/2019 | 5/31/2044 |
| 955-900038 | Coal Lease | 8/1/2022 | 7/31/2047 |
| 956-929485 | Coal Lease | 5/9/1975 | 5/8/2025 |
| 956-929508 | Coal Lease | 5/14/1975 | 5/13/2025 |
| 956-929588 | Coal Lease | 3/5/1981 | 3/4/2031 |
| 956-929589 | Coal Lease | 6/16/1975 | 6/15/2025 |
| 956-929597 | Coal Lease | 6/24/1975 | 6/23/2025 |
| 956-929599 | Coal Lease | 5/12/1975 | 5/11/2025 |
| 956-929603 | Coal Lease | 6/26/1975 | 6/25/2025 |

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SEC S-K 1300 Technical Report Summary

Mississippi Lignite Mining Company – Red Hills Mine&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;March 2023

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| | | | |
|:---|:---|:---|:---|
| 956-929646 | Coal Lease | 6/2/1975 | 6/1/2025 |
| 956-929743 | Coal Lease | 5/14/1975 | 5/13/2025 |
| 956-929744 | Coal Lease | 6/11/1975 | 6/10/2025 |
| 956-929745 | Coal Lease | 6/11/1975 | 6/10/2025 |
| 956-929748 | Coal Lease | 5/22/1978 | 5/21/2028 |
| 956-929749 | Coal Lease | 8/7/1975 | 8/6/2025 |
| 956-929750 | Coal Lease | 8/4/1975 | 8/3/2025 |
| 956-929751 | Coal Lease | 6/17/1975 | 6/16/2025 |
| 956-929752 | Coal Lease | 6/5/1975 | 6/4/2025 |
| 956-929755 | Coal Lease | 8/7/1975 | 8/6/2025 |
| 956-929757 | Coal Lease | 8/25/1975 | 8/24/2025 |
| 956-929759 | Coal Lease | 8/27/1975 | 8/26/2025 |
| 956-929801 | Coal Lease | 10/24/1974 | 10/23/2025 |
| 956-929802 | Exploration Contract & Coal Lease | 10/30/1974 | 10/29/2025 |
| 956-929803 | Coal Lease | 9/4/1975 | 9/3/2025 |
| 956-929835 | Exploration Contract & Coal Lease | 10/24/1974 | 10/23/2025 |
| 956-929839 | Coal Lease | 9/15/1975 | 9/14/2025 |
| 956-929841 | Coal Lease | 9/15/1975 | 9/14/2025 |
| 956-929842 | Coal Lease | 9/24/1975 | 9/23/2025 |
| 956-929910 | Exploration Contract & Coal Lease | 10/11/1974 | 10/10/2025 |
| 956-929911 | Exploration Contract & Coal Lease | 10/28/1974 | 10/27/2025 |
| 956-929955 | Coal Lease | 9/25/1975 | 9/24/2025 |
| 956-929956 | Coal Lease | 9/26/1975 | 9/25/2025 |
| 956-929957 | Coal Lease | 9/20/1975 | 9/19/2025 |
| 956-929958 | Coal Lease | 10/2/1975 | 10/1/2025 |
| 956-929959 | Coal Lease | 10/3/1975 | 10/2/2025 |
| 956-930068 | Coal Lease | 10/13/1975 | 10/12/2025 |
| 956-930187 | Coal Lease | 10/7/1975 | 10/6/2025 |
| 956-930280 | Coal Lease | 12/18/1975 | 12/17/2025 |
| 956-930367 | Coal Lease | 12/16/1975 | 12/15/2025 |
| 956-930413 | Coal Lease | 2/27/1976 | 2/26/2026 |
| 956-930414 | Coal Lease | 2/27/1976 | 2/26/2026 |
| 956-930474 | Coal Lease | 1/26/1976 | 1/25/2026 |
| 956-930480 | Coal Lease | 2/3/1976 | 2/2/2026 |
| 956-930482 | Coal Lease | 2/25/1976 | 2/24/2026 |
| 956-930483 | Coal Lease | 2/19/1976 | 2/18/2026 |
| 956-930488 | Coal Lease | 3/18/1976 | 3/17/2026 |
| 956-930493 | Coal Lease | 3/10/1976 | 3/9/2026 |
| 956-930494 | Coal Lease | 3/17/1976 | 12/31/2036 |
| 956-930495 | Coal Lease | 3/22/1976 | 3/21/2026 |

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SEC S-K 1300 Technical Report Summary

Mississippi Lignite Mining Company – Red Hills Mine&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;March 2023

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| | | | |
|:---|:---|:---|:---|
| 956-930497 | Coal Lease | 3/23/1976 | 3/22/2026 |
| 956-930499 | Coal Lease | 3/18/1976 | 3/17/2001\* |
| 956-930500 | Coal Lease | 3/8/1976 | 3/7/2026 |
| 956-930501 | Coal Lease | 3/31/1976 | 3/30/2026 |
| 956-930513 | Coal Lease | 4/21/1976 | 4/20/2026 |
| 956-930514 | Coal Lease | 4/21/1976 | 4/20/2026 |
| 956-930515 | Coal Lease | 4/13/1976 | 4/12/2026 |
| 956-930516 | Coal Lease | 5/1/1976 | 4/30/2026 |
| 956-930530 | Coal Lease | 5/4/1976 | 5/3/2026 |
| 956-930593 | Coal Lease | 3/16/1976 | 3/15/2026 |
| 956-931123 | Coal Lease | 4/11/1978 | 4/10/2028 |
| 956-931124 | Coal Lease | 4/11/1978 | 4/10/2028 |
| 956-931250 | Coal Lease | 8/14/1978 | 8/13/2028 |
| 956-931266 | Coal Lease | 1/19/1983 | 1/18/2008\* |
| 956-931267 | Coal Lease | 1/21/1983 | 1/20/2008\* |
| 956-931308 | Coal Lease | 6/25/1980 | 6/24/2030 |
| 956-931314 | Coal Lease | 7/31/1980 | 7/30/2030 |
| 956-931316 | Coal Lease | 8/12/1980 | 8/11/2030 |
| 956-931317 | Coal Lease | 9/11/1980 | 9/10/2030 |
| 956-931318 | Coal Lease | 9/18/1980 | 9/17/2030 |
| 956-931323 | Coal Lease | 10/8/1980 | 10/7/2030 |
| 956-931395 | Coal Lease | 7/29/1981 | 7/28/2031 |
| 956-931396 | Coal Lease | 8/24/1981 | 8/23/2031 |
| 956-931397 | Coal Lease | 8/24/1981 | 8/23/2031 |
| 956-931398 | Coal Lease | 2/10/1982 | 2/9/2032 |
| 956-931409 | Coal Lease | 7/31/1981 | 7/30/2031 |
| 956-931484 | Coal Lease | 5/10/1982 | 5/9/2032 |
| 956-931485 | Coal Lease | 5/10/1982 | 5/9/2032 |
| 956-931524 | Coal Lease | 10/8/1982 | 10/7/2032 |
| 956-931537 | Coal Lease | 12/13/1982 | 12/12/2032 |
| 956-931579 | Coal Lease | 5/2/1983 | 5/1/2008\* |
| 956-931658 | Coal Lease | 11/23/1999 | 11/22/2024 |
| 956-931677 | Coal Lease | 5/17/2000 | 5/16/2050 |
| 956-931705 | Coal Lease | 7/16/2001 | 7/15/2026 |
| 956-931706 | Coal Lease | 10/6/2005 | 10/5/2030 |
| 956-931708 | Coal Excavation Lease | 12/10/2007 | 12/9/2047 |
| 956-931709 | Coal Lease | 3/22/2010 | 3/21/2035 |
| 956-931710 | Coal Lease | 5/25/2011 | 5/24/2061 |
| 956-931711 | Coal Lease | 12/20/2012 | 12/19/2062 |
| 956-931712 | Coal Lease | 12/17/2012 | 12/16/2062 |

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SEC S-K 1300 Technical Report Summary

Mississippi Lignite Mining Company – Red Hills Mine&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;March 2023

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| | | | |
|:---|:---|:---|:---|
| 956-931713 | Coal Lease | 12/20/2012 | 12/19/2062 |
| 956-931714 | Coal Lease | 9/11/2013 | 9/10/2063 |
| 956-931716 | Coal Lease | 12/20/2013 | 12/19/2063 |
| 956-931718 | Lignite Mining Lease | 9/25/2013 | 9/24/2063 |
| 956-931719 | Coal Lease | 12/20/2013 | 12/19/2063 |
| 956-931723 | Coal Lease | 4/19/2016 | 4/18/2066 |
| 956-931724 | Coal Lease | 9/9/2016 | 9/8/2066 |
| 956-931728 | Coal & Lignite Lease Agreement | 11/14/2017 | 11/13/2047 |
| 956-931729 | Coal Lease | 11/16/2017 | 11/15/2067 |
| 956-931730 | Lignite Mining Lease | 12/18/2017 | 12/17/2067 |
| 956-931734 | Coal Lease | 9/28/2018 | 9/27/2043 |
| 956-931735 | Coal Lease | 1/23/2019 | 1/22/2044 |
| 956-931737 | Coal Lease | 3/13/2019 | 3/12/2069 |
| 956-931738 | Coal Strip Mining Lease | 10/25/2019 | 10/24/2034 |
| 956-931741 | Protective Lease |  |  |
| 956-931742 | Coal Lease | 1/31/2021 | 1/30/2071 |
| 956-931743 | Coal Lease | 6/25/2021 | 6/24/2071 |
| \*Lease continued past expiration by annual payment. | \*Lease continued past expiration by annual payment. |  |  |

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SEC S-K 1300 Technical Report Summary

Mississippi Lignite Mining Company – Red Hills Mine&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;March 2023

**Table 3.2 Identification of Acquisitions** 

---

| | | | |
|:---|:---|:---|:---|
| **Agreement Id** | **Agreement Type** | **Agreement Date** | **Agreement Expiration Date** |
| 957-MLC001 | Warranty Deed | 8/19/1998 | 8/18/2097 |
| 957-MLC002 | Coal Warranty Deed | 10/1/1997 | 12/31/2099 |
| 957-MLC003 | Warranty Deed | 9/17/1998 | 9/16/2097 |
| 957-MLC004 | Warranty Deed | 12/22/2000 | 12/21/2999 |
| 957-MLC005 | Warranty Deed | 9/20/2001 | 9/19/2100 |
| 957-MLC006 | Warranty Deed | 10/12/1998 | 12/31/2099 |
| 957-MLC007 | Warranty Deed | 10/1/2001 | 9/30/2100 |
| 957-MLC008 | Warranty Deed | 1/22/2002 | 1/21/2101 |
| 957-MLC009 | Warranty Deed | 1/22/2002 | 1/21/2101 |
| 957-MLC010 | Warranty Deed | 10/29/1996 | 10/28/2096 |
| 957-MLC011 | Warranty Deed | 6/1/1999 | 6/1/2099 |
| 957-MLC012 | Warranty Deed | 1/5/1999 | 1/5/2098 |
| 957-MLC013 | Coal and Lignite Deed | 7/8/2005 | 7/7/2104 |
| 957-MLC014 | Special Warranty Deed | 4/2/1998 | 4/1/2097 |
| 957-MLC015 | Special Warranty Deed | 8/11/1998 | 8/10/2097 |
| 957-MLC016 | Warranty Deed | 9/5/1998 | 12/31/2099 |
| 957-MLC017 | Warranty Deed | 1/24/2000 | 1/24/2099 |
| 957-MLC018 | Warranty Deed | 8/19/1998 | 8/19/2097 |
| 957-MLC019 | Warranty Deed | 1/24/2000 | 1/23/2099 |
| 957-MLC020 | Warranty Deed | 8/17/1998 | 8/16/2098 |
| 957-MLC021 | Warranty Deed | 6/30/1998 | 6/29/2097 |
| 957-MLC022 | Warranty Deed | 3/11/1998 | 3/10/2098 |
| 957-MLC023 | Warranty Deed | 2/25/2003 | 2/24/2102 |
| 957-MLC024 | Warranty Deed | 11/10/1998 | 11/9/2097 |
| 957-MLC025 | Warranty Deed | 11/24/1998 | 11/23/2097 |
| 957-MLC026 | Warranty Deed | 5/14/1999 | 5/13/2098 |
| 957-MLC027 | Warranty Deed | 4/8/1999 | 4/7/2098 |
| 957-MLC028 | Warranty Deed | 4/22/1999 | 4/22/2999 |
| 957-MLC029 | Warranty Deed | 7/7/1999 | 7/6/2098 |
| 957-MLC030 | Warranty Deed | 5/2/2003 | 5/1/2102 |
| 957-MLC031 | Warranty Deed | 5/5/2003 | 5/4/2102 |
| 957-MLC032 | Warranty Deed | 5/2/2003 | 5/1/2102 |
| 957-MLC033 | Warranty Deed | 7/8/2003 | 7/7/2102 |
| 957-MLC034 | Warranty Deed | 3/17/2004 | 12/31/2099 |
| 957-MLC035 | Warranty Deed | 7/16/2004 | 7/15/2103 |
| 957-MLC036 | Warranty Deed | 11/15/2004 | 12/31/2999 |
| 957-MLC037 | Warranty Deed | 2/18/2005 | 12/31/2999 |
| 957-MLC038 | Warranty Deed | 2/23/2005 | 2/22/2104 |
| 957-MLC039 | Warranty Deed | 4/8/2005 | 4/7/2104 |
| 957-MLC040 | Warranty Deed | 2/28/2006 | 2/27/2105 |
| 957-MLC041 | Warranty Deed | 6/28/2007 | 6/28/2106 |
| 957-MLC042 | Warranty Deed | 7/26/2006 | 7/25/2105 |
| 957-MLC043 | Warranty Deed | 10/28/2006 | 10/27/2105 |
| 957-MLC044 | Warranty Deed | 10/28/2006 | 10/27/2105 |
| 957-MLC045 | Warranty Deed | 10/27/2006 | 10/26/2105 |
| 957-MLC046 | Warranty Deed | 8/1/2007 | 7/31/2106 |
| 957-MLC047 | Warranty Deed | 11/20/2007 | 11/19/2106 |

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SEC S-K 1300 Technical Report Summary

Mississippi Lignite Mining Company – Red Hills Mine&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;March 2023

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| | | | |
|:---|:---|:---|:---|
| 957-MLC048 | Special Warranty Deed | 11/7/2007 | 11/6/2106 |
| 957-MLC049 | Warranty Deed | 11/26/2007 | 11/25/2106 |
| 957-MLC050 | Warranty Deed | 6/13/2008 | 12/31/2099 |
| 957-MLC051 | Warranty Deed | 9/4/2008 | 12/31/2099 |
| 957-MLC052 | Warranty Deed | 4/23/2009 | 12/31/2999 |
| 957-MLC053 | Warranty Deed | 12/21/2010 | 12/31/2999 |
| 957-MLC054 | Warranty Deed | 5/25/2011 | 12/31/2999 |
| 957-MLC055 | Special Warranty Deed | 6/27/2011 | 12/31/2999 |
| 957-MLC056 | Special Warranty Deed | 7/3/2011 | 12/31/2999 |
| 957-MLC057 | Special Warranty Deed | 7/8/2011 | 12/31/2999 |
| 957-MLC058 | Warranty Deed | 10/13/2011 | 12/31/2999 |
| 957-MLC059 | Warranty Deed | 10/13/2011 | 12/31/2999 |
| 957-MLC060 | Warranty Deed | 12/30/2011 | 12/31/2999 |
| 957-MLC061 | Warranty Deed | 7/17/2012 | 12/31/2099 |
| 957-MLC062 | Warranty Deed | 7/13/2012 | 12/31/2099 |
| 957-MLC063 | Warranty Deed | 7/13/2012 | 12/31/2099 |
| 957-MLC064 | Warranty Deed | 9/20/2012 | 12/31/2099 |
| 957-MLC065 | Warranty Deed | 12/6/2012 | 12/31/2999 |
| 957-MLC066 | Warranty Deed | 12/6/2012 | 12/31/2099 |
| 957-MLC067 | Warranty Deed | 12/3/2012 | 12/31/2099 |
| 957-MLC068 | Warranty Deed | 4/3/2013 | 12/31/2099 |
| 957-MLC069 | Warranty Deed | 12/20/2012 | 12/31/2099 |
| 957-MLC070 | Warranty Deed | 12/17/2012 | 12/31/2099 |
| 957-MLC071 | Warranty Deed | 12/14/2012 | 12/31/2099 |
| 957-MLC072 | Warranty Deed | 12/14/2012 | 12/31/2099 |
| 957-MLC073 | Warranty Deed | 12/20/2012 | 12/31/2099 |
| 957-MLC074 | Warranty Deed | 12/20/2012 | 12/31/2099 |
| 957-MLC075 | Warranty Deed | 10/5/2012 | 12/31/2099 |
| 957-MLC076 | Warranty Deed | 4/3/2013 | 12/31/2099 |
| 957-MLC077 | Warranty Deed | 5/3/2013 | 12/31/2099 |
| 957-MLC078 | Warranty Deed | 6/13/2013 | 12/31/2999 |
| 957-MLC079 | Warranty Deed | 6/14/2013 | 12/31/2099 |
| 957-MLC080 | Warranty Deed | 9/11/2013 | 12/31/2099 |
| 957-MLC081 | Special Warranty Deed | 12/31/2013 | 12/31/2999 |
| 957-MLC082 | Special Warranty Deed | 12/31/2013 | 12/31/2099 |
| 957-MLC084 | Warranty Deed | 12/20/2013 | 12/31/2099 |
| 957-MLC085 | Quit Claim Deed | 7/10/2015 | 12/31/2099 |
| 957-MLC086 | Quit Claim Deed | 7/10/2015 | 12/31/2999 |
| 957-MLC087 | Quit Claim Deed | 7/10/2015 | 12/31/2099 |
| 957-MLC088 | Warranty Deed | 12/20/2013 | 12/31/2999 |
| 957-MLC089 | Quit Claim Deed | 7/10/2015 | 12/31/2099 |
| 957-MLC091 | Quit Claim Deed | 7/10/2015 | 12/31/2099 |
| 957-MLC092 | Quit Claim Deed | 7/10/2015 | 12/31/2099 |
| 957-MLC094 | Quit Claim Deed | 7/10/2015 | 12/31/2099 |
| 957-MLC095 | Quit Claim Deed | 7/10/2015 | 12/31/2099 |
| 957-MLC096 | Quit Claim Deed | 10/26/2015 | 12/31/2099 |
| 957-MLC097 | Quit Claim Deed | 10/26/2015 | 12/31/2099 |
| 957-MLC098 | Quit Claim Deed | 10/26/2015 | 12/31/2099 |
| 957-MLC099 | Quit Claim Deed | 5/6/2016 | 12/31/2099 |
| 957-MLC100 | Quit Claim Deed | 9/1/2016 | 12/31/2099 |

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SEC S-K 1300 Technical Report Summary

Mississippi Lignite Mining Company – Red Hills Mine&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;March 2023

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| | | | |
|:---|:---|:---|:---|
| 957-MLC101 | Quit Claim Deed | 9/1/2016 | 12/31/2099 |
| 957-MLC102 | Quit Claim Deed | 9/1/2016 | 12/31/2099 |
| 957-MLC103 | Quit Claim Deed | 6/1/2017 | 12/31/2099 |
| 957-MLC109 | Quit Claim Deed | 10/1/2017 | 12/31/2099 |
| 957-MLC111 | Quit Claim Deed | 6/1/2019 | 12/31/2099 |
| 957-MLC112 | Quit Claim Deed | 4/1/2020 | 12/31/2099 |
| 609-RML061 | Warranty Deed | 12/31/2013 | 12/31/2099 |
| 609-RML062 | Warranty Deed | 12/31/2013 | 12/31/2099 |
| 609-RML063 | Warranty Deed | 12/31/2013 | 12/31/2099 |
| 609-RML064 | Warranty Deed | 12/31/2013 | 12/31/2099 |
| 609-RML065 | Warranty Deed | 12/31/2013 | 12/31/2999 |
| 609-RML066 | Warranty Deed | 12/31/2013 | 12/31/2099 |
| 609-RML067 | Warranty Deed | 12/31/2013 | 12/31/2099 |
| 609-RML068 | Warranty Deed | 12/31/2013 | 12/31/2099 |
| 609-RML069 | Warranty Deed | 12/31/2013 | 12/31/2099 |
| 609-RML070 | Warranty Deed | 12/31/2013 | 12/31/2099 |
| 609-RML071 | Warranty Deed | 12/31/2013 | 12/31/2099 |
| 609-RML072 | Warranty Deed | 12/31/2013 | 12/31/2099 |
| 609-RML073 | Warranty Deed | 12/31/2013 | 12/31/2099 |
| 609-RML074 | Warranty Deed | 12/31/2013 | 12/31/2099 |
| 609-RML075 | Warranty Deed | 12/31/2013 | 12/31/2099 |
| 609-RML076 | Warranty Deed | 12/31/2013 | 12/31/2099 |
| 609-RML077 | Warranty Deed | 12/31/2013 | 12/31/2099 |
| 609-RML078 | Warranty Deed | 12/31/2013 | 12/31/2999 |
| 609-RML079 | Warranty Deed | 12/31/2013 | 12/31/2099 |
| 609-RML080 | Warranty Deed | 12/31/2013 | 12/31/2099 |
| 609-RML081 | Warranty Deed | 9/10/2013 | 12/31/2999 |
| 609-RML082 | Warranty Deed | 9/10/2013 | 12/31/2099 |
| 609-RML084 | Warranty Deed | 7/10/2015 | 12/31/2099 |
| 609-RML085 | Warranty Deed | 12/20/2013 | 12/31/2099 |
| 609-RML086 | Warranty Deed | 12/20/2013 | 12/31/2999 |
| 609-RML087 | Warranty Deed | 12/20/2013 | 12/31/2099 |
| 609-RML088 | Warranty Deed | 12/20/2013 | 12/31/2999 |
| 609-RML089 | Warranty Deed | 12/20/2013 | 12/31/2099 |
| 609-RML091 | Warranty Deed | 2/21/2014 | 12/31/2099 |
| 609-RML092 | Warranty Deed | 7/21/2014 | 12/31/2099 |
| 609-RML094 | Warranty Deed | 10/16/2014 | 12/31/2099 |
| 609-RML095 | Warranty Deed | 2/19/2015 | 12/31/2099 |
| 609-RML096 | Quit Claim Deed | 6/8/2015 | 12/31/2099 |
| 609-RML097 | Warranty Deed | 6/25/2015 | 12/31/2099 |
| 609-RML098 | Warranty Deed | 6/25/2015 | 12/31/2099 |
| 609-RML099 | Warranty Deed | 8/12/2015 | 12/31/2099 |
| 609-RML100 | Warranty Deed | 4/8/2016 | 12/31/2099 |
| 609-RML101 | Warranty Deed | 4/8/2016 | 12/31/2099 |
| 609-RML102 | Warranty Deed | 5/8/2016 | 12/31/2099 |
| 609-RML103 | Warranty Deed | 9/9/2016 | 12/31/2099 |
| 609-RML104 | Warranty Deed | 2/11/2017 | 12/31/2099 |
| 609-RML105 | Warranty Deed | 5/26/2017 | 12/31/2099 |
| 609-RML106 | Warranty Deed | 6/14/2017 | 12/31/2099 |
| 609-RML107 | Warranty Deed | 6/28/2017 | 12/31/2099 |

---

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SEC S-K 1300 Technical Report Summary

Mississippi Lignite Mining Company – Red Hills Mine&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;March 2023

---

| | | | |
|:---|:---|:---|:---|
| 609-RML108 | Warranty Deed | 7/28/2017 | 12/31/2099 |
| 609-RML109 | Warranty Deed | 8/23/2017 | 12/31/2099 |
| 609-RML110 | Warranty Deed | 8/28/2017 | 12/31/2099 |
| 609-RML111 | Warranty Deed | 10/10/2017 | 12/31/2099 |
| 609-RML112 | Special (Limited) Warranty Deed | 12/21/2017 | 12/31/2099 |
| 609-RML113 | Warranty Deed | 1/26/2018 | 12/31/2099 |
| 609-RML114 | Warranty Deed | 1/23/2018 | 12/31/2099 |
| 609-RML115 | Warranty Deed | 3/16/2018 | 12/31/2099 |
| 609-RML116 | Warranty Deed | 6/18/2020 | 12/31/2099 |
| 609-RML117 | Warranty Deed | 11/28/2018 | 12/31/2099 |
| 609-RML118 | Warranty Deed | 3/21/2019 | 12/31/2099 |
| 609-RML119 | Warranty Deed | 3/21/2019 | 12/31/2099 |
| 609-RML120 | Warranty Deed | 6/4/2019 | 12/31/2099 |
| 609-RML121 | Warranty Deed | 12/30/2019 | 12/31/2099 |
| 609-RML122 | Warranty Deed | 2/26/2020 | 12/31/2099 |
| 609-RML123 | Warranty Deed | 7/17/2020 | 12/31/2099 |
| 609-RML124 | Warranty Deed | 12/10/2020 | 12/31/2099 |
| 609-RML125 | Warranty Deed | 1/11/2021 | 12/31/2099 |
| 609-RML126 | Warranty Deed | 6/15/2021 | 12/31/2099 |
| 609-RML127 | Warranty Deed | 9/3/2021 | 12/31/2099 |
| 609-RML128 | Warranty Deed | 11/18/2021 | 12/31/2099 |
| 609-RML129 | Warranty Deed | 12/23/2021 | 12/31/2099 |
| 609-RML130 | Warranty Deed | 02/07/20222 | 12/31/2099 |
| 609-RML131 | Warranty Deed | 5/14/2022 | 12/31/2099 |
| 609-RML132 | Warranty Deed | 5/23/2022 | 12/31/2099 |
| 609-RML133 | Warranty Deed | 05/23/2022 | 12/31/2099 |
| 609-RML134 | Warranty Deed | 7/21/2022 | 12/31/2099 |
| 609-RML135 | Warranty Deed | 9/7/2022 | 12/31/2099 |
| 609-RML136 | Warranty Deed | 10/27/2022 | 12/31/2099 |
| 609-RML137 | Warranty Deed | 09/26/2022 | 12/31/2099 |
| 609-RML138 | Warranty Deed | 09/27/2022 | 12/31/2099 |
| 609-RML139 | Warranty Deed | 09/27/2022 | 12/31/2099 |
| 609-RML140 | Warranty Deed | 09/27/2022 | 12/31/2099 |
| 609-RML141 | Warranty Deed | 09/27/2022 | 12/31/2099 |
| 609-RML142 | Warranty Deed | 09/27/2022 | 12/31/2099 |
| 609-RML143 | Warranty Deed | 09/27/2022 | 12/31/2099 |
| 609-RML144 | Warranty Deed | 09/27/2022 | 12/31/2099 |
| 609-RML145 | Warranty Deed | 09/28/2022 | 12/31/2099 |
| 609-RML146 | Warranty Deed | 09/29/2022 | 12/31/2099 |
| 609-RML147 | Warranty Deed | 09/29/2022 | 12/31/2099 |
| 609-RML148 | Warranty Deed | 09/29/2022 | 12/31/2099 |
| 609-RML149 | Warranty Deed | 09/30/2022 | 12/31/2099 |
| 609-RML150 | Warranty Deed | 09/30/2022 | 12/31/2099 |
| 609-RML151 | Warranty Deed | 09/30/2022 | 12/31/2099 |
| 609-RML152 | Warranty Deed | 09/30/2022 | 12/31/2099 |
| 609-RML153 | Warranty Deed | 10/01/2022 | 12/31/2099 |
| 609-RML154 | Warranty Deed | 10/01/2022 | 12/31/2099 |
| 609-RML155 | Warranty Deed | 10/01/2022 | 12/31/2099 |
| 609-RML156 | Warranty Deed | 10/01/2022 | 12/31/2099 |
| 609-RML157 | Warranty Deed | 10/01/2022 | 12/31/2099 |

---

------

SEC S-K 1300 Technical Report Summary

Mississippi Lignite Mining Company – Red Hills Mine&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;March 2023

---

| | | | |
|:---|:---|:---|:---|
| 609-RML158 | Warranty Deed | 10/01/2022 | 12/31/2099 |
| 609-RML159 | Warranty Deed | 10/03/2022 | 12/31/2099 |
| 609-RML160 | Warranty Deed | 10/03/2022 | 12/31/2099 |
| 609-RML161 | Warranty Deed | 10/13/2022 | 12/31/2099 |
| 609-RML162 | Warranty Deed | 10/14/2022 | 12/31/2099 |
| 609-RML163 | Warranty Deed | 11/23/2022 | 12/31/2099 |
| 609-RML164 | Warranty Deed | 10/10/2022 | 12/31/2099 |
| 609-RML165 | Warranty Deed | 12/20/2022 | 12/31/2099 |
| 609-RML166 | Warranty Deed | 12/20/2022 | 12/31/2099 |
| 609-RML167 | Warranty Deed | 12/20/2022 | 12/31/2099 |

---

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SEC S-K 1300 Technical Report Summary

Mississippi Lignite Mining Company – Red Hills Mine&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;March 2023

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;**3.4.Significant Encumbrances to the Property**

The Red Hills Mine currently has no significant encumbrances to the property. No mining permit violations have been issued at the Red Hills Mine in the past ten years. One NOV was issued in April 2020 for a water quality exceedance that was determined to not be the fault of Red Hills Mine and no further action was required. A second NOV was issued in June, 2022 for a water sampling violation. Both NOVs were not related to the mining permit. Permitting requirements are discussed in Section 17.0 of this TRS.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;**3.5.Significant Factors and Risks**

MLMC has not identified any significant risks that may affect the right or ability to perform work on the property. However, if a lease were to expire and MLMC had not yet noticed this property for disturbance by mining activities, the landowner may choose not to release this property for mining.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;**3.6.Registrant Royalties and Interests**

Discussed in Section 3.3 of this TRS.

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SEC S-K 1300 Technical Report Summary

Mississippi Lignite Mining Company – Red Hills Mine&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;March 2023

**5. Accessibility, Climate, Local Resources, Infrastructure, and Physiography**

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;**4.1.Physiography, Topography and Vegetation**

The Red Hills Mine, located in Choctaw County, Mississippi, is part of the "red hills phase" of the North Central Hills physiographic province. The region is characterized by dissected upland hills and relatively wide flats in the major stream drainages. The maximum relief of the Red Hills Mine is approximately 280 feet (msl), with the elevation ranging from 360 feet (msl) in the Big Bywy drainage in the north to nearly 640 feet (msl) in the Tertiary upland ridge tops in the southeastern area of the Red Hills Mine.

The Soil Survey of Choctaw County indicate the land-use of the county is approximately 73-percent commercial forestland. Vegetative baseline studies of the permitted areas further indicate the prominent vegetation of the Red Hills Mine to be forested pine plantations along with managed pine habitats which include prepared clearcuts and areas with young, planted pine. Other vegetative designations include deciduous forest, grassland, cropland, and residential lawns.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;**4.2.Accessibility** 

Local access to the Red Hills Mine is by way of Highway 9 between Ackerman, Mississippi and Eupora, Mississippi which connects to Pensacola Road that leads to the Red Hills Mine paved access road. Pensacola Road connects with Highway 9 approximately 5 miles north of Ackerman, MS. The mine road is approximately 1 mile west from Highway 9 along Pensacola Road.

Travel to the Red Hills Mine by air is possible using the Jackson-Medgar Wiley Evers International Airport in Jackson, Mississippi, approximately 104 miles south of the mine, and then using ground transportation, traveling via Highway 25, Highway 15, and Highway 9. Alternatively, the Golden Triangle Regional Airport is a smaller airport approximately 50 miles from the Red Hills Mine by means of Highway 82 west, Highway 15 south, and Highway 9 north.

The Red Hills Mine is in close proximately to river ports of the Tennessee-Tombigbee Waterway and the Mississippi River. The Lowndes County Port is approximately 60 miles east of the mine. The Port of Greenville is approximately 135 miles west of the mine, and the Port of Vicksburg, approximately 150 miles southwest of the mine. All ports are connected by major state and federal highways.

In additional to transportation via roadways, air and waterways, the Kansas City Southern (KCS) railroad has a depot located approximately 5 miles south of the mine in Ackerman and is accessible by Highway 9 and Highway 15.

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SEC S-K 1300 Technical Report Summary

Mississippi Lignite Mining Company – Red Hills Mine&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;March 2023

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;**4.3.Climate**

The climate of the Red Hills Mine varies seasonally with a warm, humid summer and a generally mild, humid winter. The Red Hills Mine operates through all seasons. Heavy precipitation events may temporarily slow production but have minimal impact on the overall mining operation. Nearby Ackerman, Mississippi has the following climate (Climate in Ackerman, Mississippi, 2021):

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• 56 inches of rain annually, on average

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• &nbsp;&nbsp;&nbsp;&nbsp;One inch of snow per year

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• &nbsp;&nbsp;&nbsp;&nbsp;96 days per year with some sort of precipitation

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• &nbsp;&nbsp;&nbsp;&nbsp;217 sunny days per year

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• &nbsp;&nbsp;&nbsp;&nbsp;Temperatures: July High: 90°F; January Low: 31°F

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;**4.4.Local Resources and Infrastructure**

The towns of Ackerman, Eupora, Starkville, Louisville, Kosciusko, and numerous smaller communities are within a 40-mile radius of the Red Hills Mine and provide a vast employment base. Furthermore, Mississippi State University (MSU) is located approximately 30 miles east of the mine in Starkville. MLMC has a history of partnership with MSU as well as the local community colleges for science, technology, engineering, and mathematics (STEM) research and skilled trades training.

The Red Hills Mine sources power for mine office facilities and operations from 4-County Electric Power Association, and water for the mine office facilities from the Reform Water Association. Fuel for equipment is supplied by a local vendor. Most supplies to operate the mine are within the region. The Red Hills Mine has, or is currently constructing, all supporting infrastructure for mining operations through the LOM plan. See Section 15.0 of the TRS for further detail pertaining to the mine specific infrastructure.

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SEC S-K 1300 Technical Report Summary

Mississippi Lignite Mining Company – Red Hills Mine&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;March 2023

**5. History of the Property**

The Red Hills Mine began operations in the MS-002 permit area in Mine Area 1 and is in the process of transitioning to Mine Area 3 within the MS-004 permit area. Initial development of the Red Hills Mine began in 1998, with full production and commercial deliveries commencing in 2002. Boxcut construction for Mine Area 3 began in 2021 where mining will continue through April 2032. The Red Hills Mine has, or is currently constructing, all supporting infrastructure for mining operations within the permitted areas.

Excluding the partial year of 2001, the average tons sold from 2002-2022 was 3.1 million tons/year. Table 5.1 shows the historical production for Red Hills Mine.

**Table 5.1 Historical Production** 

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| | | | | | | | | | | | |
|:---|:---|:---|:---|:---|:---|:---|:---|:---|:---|:---|:---|
| | 2001 | 2002 | 2003 | 2004 | 2005 | 2006 | 2007 | 2008 | 2009 | 2010 | 2011 |
| Tons Sold (000 ton) | 500 | 2900 | 3700 | 3600 | 3600 | 3600 | 3400 | 3000 | 3700 | 3600 | 2700 |
|  | 2012 | 2013 | 2014 | 2015 | 2016 | 2017 | 2018 | 2019 | 2020 | 2021 | 2022 |
| Tons Sold (000 ton) | 3100 | 3200 | 2600 | 3200 | 3000 | 2400 | 3000 | 2600 | 2500 | 3000 | 3200 |

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&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;**5.1.&nbsp;&nbsp;&nbsp;&nbsp;Previous Operations**

There are no previous mining operations on the Red Hills Mine property.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;**5.2.Exploration and Development History Prior to MLMC** 

Original exploration of the Red Hills Mine area was conducted by Phillips from 1975 to 1980. Phillips contracted independent drilling services to drill and geophysically log over 800 boreholes. The data collected from the Phillips' drilling exploration was the basis of the Red Hills Project, which included the Red Hills Mine and the RHPP.

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SEC S-K 1300 Technical Report Summary

Mississippi Lignite Mining Company – Red Hills Mine&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;March 2023

**6. Geological Setting, Mineralization and Deposit**

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;**6.1.Geology**

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;**6.1.1. Regional Geology**

The Red Hills Mine is in the Wilcox Group of Mississippi (Figure 6.1) which is the most prolific lignite-bearing stratum in the state of Mississippi. The Wilcox Group and underlying Midway Group were deposited during Paleogene time; 66 to 23 million years ago. The most prominent characteristics of the Wilcox Group formations are the cyclical deposition and lateral persistence of the lithologic units, especially the lignite seams. The stratigraphy of the Wilcox Group is depicted on Figure 6.2. The section from the Gravel Creek Member through the Tuscahoma Formation represents a transition from a transgressive sequence of valley fill, marginal marine strata (lower Gravel Creek) to predominantly regressive, nonmarine, deltaic strata (upper Gravel Creek through the Tuscahoma).

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SEC S-K 1300 Technical Report Summary

Mississippi Lignite Mining Company – Red Hills Mine&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;March 2023

**Figure 6.1 Geologic Formations of Mississippi (Dicken, Nicholson, Horton, Foose, & Mueller, 2005)**

![image_4.jpg](image_4.jpg)

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SEC S-K 1300 Technical Report Summary

Mississippi Lignite Mining Company – Red Hills Mine&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;March 2023

During each depositional geologic sequence, organic material was repeatedly buried by sediment in an ideal, oxygen-free environment. This ideal environment was attributed to the humid, subtropical conditions and high water-table of wetlands present during Paleogene time which prevented plant matter from decaying prior to burial. The oxygen-free environment combined with heat and pressure from continual deposition of overlying sediments allowed for the formation of peat and further mineralization of lignite over time by undergoing a process known as humification and biochemical gelification.

The regional structural geology is fairly consistent. The regional strike is northwest-southeast. The strata are nearly flat lying, dipping to the southwest at only 25 to 35 feet per mile. No evidence of any significant faulting has been observed in the region.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;**6.1.2. Local and Property Geology**

The average thickness of the Wilcox section containing the mineable lignite seams at the Red Hills Mine and surrounding area is approximately 140 feet (Figure 6.2). Vertical repetition of the geological characteristics results in a straightforward depositional setting facilitating comprehensive analysis of the geological, as well as the geochemical, geotechnical, and geohydrological baseline conditions of the Red Hills Mine.

Following the regional geology, trends in lignite seam sulfur content at the Red Hills Mine support a geologic transition from marine to nonmarine environments. Increased sulfur values are generally associated with marine influences. The C-seam marks a transition from higher sulfur below to lower sulfur contents above.

The local structural geology for the Red Hills Mine also follows the regional structure with a northwest-southeast strike dipping to the southwest. The lignite seams are gently undulating due to differential compaction of the underlying sediments. Small, localized faults have been encountered within the lignite seams while mining through the MS-002 permit area, and are anticipated to be encountered in the MS-004 permit area. These faults have been discontinuous and the seam displacement has typically been less than 10 feet. The faults have not materially affected mining or production at the Red Hills Mine.

Since mining began, no unique or especially significant geological features, formations, or paleontological resources have been identified at the Red Hills Mine. No known workings of active, inactive, or abandoned underground mines have been identified. Additionally, no fatal flaws related to geological conditions have been identified.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;**6.2.Mineral Deposit Type**

The Red Hills Mine is solely focused on mining lignite from the project area. Details on the geological units encountered at the Red Hills Mine are described below and shown in Figure 6.1:

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;**6.2.1. Gravel Creek Member**

The top of the Gravel Creek Member of the Nanafalia Formation (Wilcox Group) lies just below the C-seam and includes a thin sand layer directly beneath the C-seam. The C-seam is currently the lowest lignite seam stratigraphically mined. However, upon further exploration, the B-seam may be mined in the future, particularly in areas with low laying terrain within the MS-004 permit area.

A basal sand unit, of up to 100 feet in thickness or more, characterizes the Gravel Creek Member. From the limited drill hole data that extends through this member, it appears that these sand units can be fairly widespread, but also may be completely absent. On the geophysical logs and limited cuttings data, the sand unit typically appears to be

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SEC S-K 1300 Technical Report Summary

Mississippi Lignite Mining Company – Red Hills Mine&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;March 2023

fairly massive and poorly- to well-sorted, fine- to medium-grained sand. These sand units, along with the sands in the underlying Coal Bluff Formation (Midway Group) are often referred to as the Lower Wilcox aquifer.

Above this basal sand are interbedded silt, clay, sand and lignite (A-seam). Due to the relative depth, anticipated lower quality, and closer proximity to the basal sands, the A-seam is not currently considered a resource targeted for mining.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;**6.2.2. Grampian Hills Member**

Five of the six lignite seams recovered at Red Hills Mine are contained in the Grampian Hills Member of the Nanafalia Formation (Wilcox Group). The formation conformably overlies the Gravel Creek Member and consists of interbedded and interlaminated clays, silts, sands, and lignite. Overall, the section is relatively sand poor.

The clays and silts are typically finely interlaminated. Munsell color varies from dark gray (N 4/ to N 5/) to greenish gray (10BG 5/1). Immediately below the lignite seams, the color is dark grayish brown (10YR 4/2) due to the presence of carbonaceous fragments. These carbonaceous layers often contain lignitized plant roots establishing an autochthonous origin for the peats that formed the lignite seams.

The sands are light gray (2.5Y 7/1) to gray (N 5/) or greenish gray (5GY 5/1). The pale greenish-gray color of many of the sands and silts is a distinctive feature of this unit. Typically, the sands are very-fine-grained, and commonly interbedded with silts and clays. One exception is the tabular sand bed between the D-seam and C-seam. The sand units between the D-seam and G-seam are typically silty, infrequent, lenticular, and probably represent narrow sand channels in the crevasse splay sequences that were penecontemporaneous with peat accumulation. Sand and silty sands compact much less than silts and clays. This phenomenon is probably the chief cause of the gentle structural undulations found in the lignite seams.

Cemented horizons, commonly referred to as "hard streaks", are also associated with the sand units. These indurated zones are most abundant within the sand channels and the silty, sandy natural levee deposits flanking the channels. The thickness of these hard streaks ranges from less than one foot to about two feet. These zones are cemented with calcite, silica, iron oxide, or siderite, and are suggestive of periods of sub-areal oxidizing conditions during deposition. Modern analogies in the natural levee deposits of the Mississippi Delta have been noted.

The color of the lignite seams ranges from black (N 2.5/) to very dark gray (10Y 3/1). Occasional layers of carbonaceous clay or zones of clay clasts increase the ash content of the lignite. The minimum thickness for recovery is one foot. The maximum thickness of the lignite seams is about eight feet.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;**6.2.3.Tuscahoma Formation**

The Tuscahoma Formation (Wilcox Group) conformably overlies the Grampian Hills Member of the Nanafalia Formation. The basal portion of this formation is the uppermost stratum to be disturbed by mining. The base of the Tuscahoma is marked by a predominantly sandy, often coarse-grained unit with a variable thickness of 10 feet to 110 feet. The variability is due to the occurrence of contemporaneously bedded clay, silt, and lignite. Laterally, these sands grade into finer grained overbank deposits including lignite seams. The overbank facies of the Tuscahoma are essentially identical to the descriptions for the Grampian Hills Member described above.

The H-seam, which is the uppermost seam that will be consistently recovered, lies at the base of the Tuscahoma. Because of its relatively high stratigraphic position, the H-seam is restricted to the upland areas above approximately 450 feet in elevation within the Red Hills Mine. Other lignite seams lying above the H-seam, including the H2-seamand the I-seam, may be encountered on occasion and are mined when seam thickness and quality are sufficient.

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SEC S-K 1300 Technical Report Summary

Mississippi Lignite Mining Company – Red Hills Mine&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;March 2023

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;**6.3.Stratigraphic Column**

A typical stratigraphic column is shown on Figure 6.2 while a planer view of two cross sections are is included on Figure 6.3. Geologic cross section E-W2 and geologic cross section C-C' are included as Figure 6.4 and Figure 6.5, respectively. The cross-sections were constructed primarily based on the drill hole geophysical logs supplemented with lithology descriptions from the drill cuttings, as well as the data from the core holes. The stratigraphic framework of the geologic cross sections follows the detailed surface mapping and subsurface investigations completed by the MDEQ, Office of Geology.

**Figure 6.2 Stratigraphic Column of the Red Hills Mine**

![image_5.jpg](image_5.jpg)

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SEC S-K 1300 Technical Report Summary

Mississippi Lignite Mining Company – Red Hills Mine&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;March 2023

**Figure 6.3 Geologic Cross Sections planer reference**

![image_6.jpg](image_6.jpg)

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SEC S-K 1300 Technical Report Summary

Mississippi Lignite Mining Company – Red Hills Mine&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;March 2023

**Figure 6.4 Geologic Cross Section E-W2, MS-002 permit area (Excerpted from SMCRA permit MS-002, R3, Appendix 2509-6)**

![image_7.jpg](image_7.jpg)

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SEC S-K 1300 Technical Report Summary

Mississippi Lignite Mining Company – Red Hills Mine&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;March 2023

**Figure 6.5 Geologic Cross Sections C-C' and D-D', MS-004 permit area (Excerpted from SMCRA permit MS-004, Appendix 2509-6)**

![image_8.jpg](image_8.jpg)

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SEC S-K 1300 Technical Report Summary

Mississippi Lignite Mining Company – Red Hills Mine&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;March 2023

**7.&nbsp;&nbsp;&nbsp;&nbsp;Exploration**

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;**7.1.Exploration**

No exploration work other than drilling and associated geophysical logging has been conducted at the Red Hills Mine. Geophysical logging is discussed with drilling in Section 7.2 of this TRS.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;**7.2.&nbsp;&nbsp;&nbsp;&nbsp;Drilling Exploration**

Data collected during drilling exploration programs at the Red Hills Mine is the sole information available for modeling the lignite deposit for the determination of Mineral Resources. Coal core drilling following the U.S. Geological Survey's (USGS) guidance for sampling coal for chemical analysis is the exclusive method used by Red Hills Mine for modeling quality of the lignite deposit. The Red Hills Mine lignite deposit is evaluated on a seam by seam basis. Drilling exploration data including geologic lithologies, qualities, and hole locations have been compiled electronically in Excel files. Cross sections produced from drill hole data are shown in Section 6.3 of this TRS. The information below summarizes the various drilling programs.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;**7.2.1. Drilling Type and Extent**

Drilling exploration programs conducted at the Red Hills Mine have comprised largely of rotary wash drilling methods. Historically, MLMC has contracted independent drilling services and geophysical logging services to operate under the guidance and direction of MLMC. Drill holes completed at the Red Hills Mine are vertical in orientation and have been broken into four categories which are described below. A drill hole location map for the Red Hills Mine is presented in Figure 7.1.

Exploratory drill holes, also referred to as pilot holes, typically range in size from 4.0 to 4.5-inches outer hole diameter (od) and terminate at a minimum of 10-feet below the lowest targeted lignite seam as specified by the geologist. Drill hole cuttings are typically recovered by the driller, in accordance with established drilling and sampling protocols, on a 5 or 10-foot interval and are described by the geologist. All pilot holes are geophysically logged by an independent geophysical logging contractor for natural gamma, density, caliper, and resistivity responses. Related drilling data has been reviewed by the QP for inclusion in the geologic model.

Coal core holes to collect samples for quality testing are advanced next to pilot holes at specified locations in accordance with protocols described herein. Core holes are typically 6.5-inches (od) or 4.25-inches (od) with a respective sample diameter of 3.3-inches (od) or 2.125-inches (od). Samples are collected with a double core barrel or Shelby tube sampler. Coring intervals are determined by the geologist based on the pilot hole's geophysical log and cuttings descriptions. Core holes terminate 10-feet below the lowest targeted lignite seam. Typically, coal cores from the drilling campaigns at the Red Hills Mine are fully recovered. The minimum core recovery accepted is 90-percent (see Section 8.0 for discussion on sample preparation). Coal core data have been reviewed by the QP for inclusion in the geologic model.

Overburden core holes, or continuous cores, are drilled following protocols similar to the coal cores as described above. Rather than specifying specific intervals to collect coal cores for quality testing, overburden cores are advanced in continuous ten-foot core sections using a double core barrel or Shelby tube sampler from top of hole to bottom of hole such that the geologist can log and sample burdens in addition to lignite. Burden (overburden and interburden) samples are shipped to a separate independent soil laboratory for geochemical analysis. Overburden cores require 75-percent total run recovery for soil analysis, while coal core intervals require a minimum of 90-percent recovery within continuous core runs, such that parameters outlined for coal core collection previously are

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SEC S-K 1300 Technical Report Summary

Mississippi Lignite Mining Company – Red Hills Mine&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;March 2023

maintained. Data specific to the coal cores collected during these continuous core sampling programs have been reviewed by the QP for inclusion in the geological model.

The fourth, and final, category of drill holes are comprised of geotechnical holes and monitoring wells which have been geophysically logged and extend through multiple coal seams. These drill holes follow the parameters outlined for pilot holes and available data has been reviewed by the QP.

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SEC S-K 1300 Technical Report Summary

Mississippi Lignite Mining Company – Red Hills Mine&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;March 2023

**Figure 7.1 Location of Drill Holes**![image_9.jpg](image_9.jpg)

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SEC S-K 1300 Technical Report Summary

Mississippi Lignite Mining Company – Red Hills Mine&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;March 2023

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;**7.2.2. General Drilling Procedures** 

Details may vary with each exploration program and are discussed in the next subsection, however general procedures for drilling at Red Hills Mine include:

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• Identification of land control; acquire drilling leases for properties not owned or previously leased and noticed.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• &nbsp;&nbsp;&nbsp;&nbsp;Site preparation.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• &nbsp;&nbsp;&nbsp;&nbsp;Rotary wash drilling by an independent drilling contractor; typically, cuttings are collected every 5-feet until a depth of 30-feet is reached then cuttings are collected every 10-feet to final depth.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• &nbsp;&nbsp;&nbsp;&nbsp;Geologist logs description of cuttings including depth, texture, general color.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• &nbsp;&nbsp;&nbsp;&nbsp;Independent contractor geophysically logs drill hole for natural gamma, density, caliper, and resistivity.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• Geologist reviews geophysical log.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• &nbsp;&nbsp;&nbsp;&nbsp;Hole determined complete and abandoned by independent drilling contractor in accordance with state regulatory requirements.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• &nbsp;&nbsp;&nbsp;&nbsp;Survey drill hole collar location.

To continue with a coal core hole:

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• &nbsp;&nbsp;&nbsp;&nbsp;Coring intervals are determined by the geologist from pilot hole geophysical log.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• &nbsp;&nbsp;&nbsp;&nbsp;Coal core drilling by an independent drilling contractor.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• &nbsp;&nbsp;&nbsp;&nbsp;Core extracted from barrel by independent drilling contractor and placed in logging tray.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• &nbsp;&nbsp;&nbsp;&nbsp;Geologist cleans core sample of drilling mud, measures the core length and identifies the roof and floor. If an acceptable length of core is not recovered, independent drilling contractor may attempt to retrieve the remaining core from the current hole. If no success, the core run interval will be "re-cored" as an additional core hole. After sufficient attempts have been made to re-core the interval, the geologist may accept a core recovery of 90-percent.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• &nbsp;&nbsp;&nbsp;&nbsp;Geologist logs the core including depths, fractures, texture, color, and characteristics of the lignite.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• &nbsp;&nbsp;&nbsp;&nbsp;Geologist double bags and double tags sample.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• &nbsp;&nbsp;&nbsp;&nbsp;Once all intervals are cored, independent contractor geophysically logs drill hole.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• &nbsp;&nbsp;&nbsp;&nbsp;Geologist reviews geophysical log.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• &nbsp;&nbsp;&nbsp;&nbsp;Hole determined complete and abandoned by independent drilling contractor in accordance with state regulatory requirements.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• &nbsp;&nbsp;&nbsp;&nbsp;Survey drill hole collar location.

Additional drilling tasks include:

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• &nbsp;&nbsp;&nbsp;&nbsp;Maintaining daily drilling report and record of collected samples.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• &nbsp;&nbsp;&nbsp;&nbsp;Proper storage of lignite core samples in secure location of the mine office and transfer to the warehouse to prepare for shipment to laboratory.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;**7.2.3. Drilling Exploration Programs**

Numerous drilling exploration programs have been conducted at the Red Hills Mine. Over 1,400 exploration holes have been drilled. 281 of those drill hole locations were sampled for coal quality testing. Figure 7.1, Table 7.1 and the text below describes the various drilling programs at Red Hills to date.

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SEC S-K 1300 Technical Report Summary

Mississippi Lignite Mining Company – Red Hills Mine&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;March 2023

**Table 7.1 Exploration Drilling Summary**![image_10.jpg](image_10.jpg)

Notes:

1 Contracted by Phillips Coal Company; included Diversified Drilling Services

2 Pilot Holes include Geotechnical Holes

3 Core Holes include Continuous Core Holes

4 Pilot Holes include Geotechnical Holes and Monitoring Wells

5 Core data excluded from model due to uncertainty in drilling method

6 Pilot Holes include Monitoring Wells

<u>1975 - 1980</u>

From 1975 to 1980 Phillips conducted drilling exploration activities. Independent drilling contractors including Diversified Drilling Services and Century Geophysical Logging Services (Century GLS) completed this work using rotary wash drilling methods. Initial hole spacing in 1975 and 1976 averaged three quarters of a mile. In 1979 and 1980, the general spacing of drill holes averaged 1500-feet, however spacing still exceeded a half mile in areas.

All drill holes were geophysically logged, and field logs were maintained to describe the geology. Coal cores collected during these drilling campaigns had an average linear core recovery of 99.8% and were analyzed by Core Laboratories, Inc. in Tyler, Texas. The method used to survey these drill hole locations is unknown.

These data were the basis for the characterization of the lignite deposit to justify the Red Hills Project including the Red Hills Mine and the RHPP. Despite uncertainty in how these early drill holes were surveyed, the data collected by Phillips has remained fairly consistent when compared to current fill-in drilling and quality analyzed during active mining operations. The QP has evaluated the reliability of the drilling data provided by Phillips to NACoal including review of geophysical logs, field logs, and coal quality certificates. Drill holes deemed reliable, such that at minimum lithology could be verified by a geophysical log have been used to model the lignite structure, and core

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SEC S-K 1300 Technical Report Summary

Mississippi Lignite Mining Company – Red Hills Mine&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;March 2023

holes in which the quality data could be verified by laboratory reports were used to model lignite quality. Original drilling files acquired from Phillips are securely stored in the NACoal corporate warehouse.

<u>1997-1998</u>

In 1997 and 1998, MLMC conducted a drilling exploration program which primarily increased the drill hole density of the first 5-year mining block in the MS-002 permit area to an average spacing of 1000-feet or less. 12 of the 59 drill holes were distributed across the northern portion of the permit area and largely consisted of continuous cores in which soil geochemistry was evaluated in addition to lignite quality. Phillips personnel oversaw drilling activities. Drilling activities consisted of rotary wash methods and was performed by Diversified Drilling Services and Century GLS. Geophysical logs, field logs, and lab results were maintained for each hole during this program. The average coal core recovery rate from 1997 through 1998 was 100%. Coal cores were analyzed by Core Laboratories, Inc. in Tyler, Texas. Collar surveys were obtained by handheld GPS units. It is unknown to what accuracy these surveys were obtained. However, the QP feels the data is appropriate for use in the geologic model after comparison of the collar elevations with the pre-mine topography.

<u>2000-2008</u>

From 2000 through 2008 Diversified Drilling Services and Century GLS were contracted by MLMC to drill over 180 holes using rotary wash methods. Hole types included pilots, coal cores, and continuous cores which increased the hole density, again to an average spacing of 500-feet, within the MS-002 permit area immediately ahead of active mining. Geologists from MLMC oversaw these drilling activities and logged core samples. The average coal core recovery rate from 2000 through 2008 was 99.9%. Core samples were shipped to Standard Laboratories in Casper, Wyoming for analysis. Collar surveys were originally obtained by Trimble units connected to a known base station, followed by Leica survey equipment for a brief period until Topcon Hyper V Rovers with RTK correction tied to a known GPS base were established in 2007.

Upon the QP's review of drilling data completed from 2000 to 2008, copies of the laboratory analysis for the 22 core holes in 2003 were not available to check the quality inputs stored in the electronic, geologic database. The QP contacted Standard Laboratories for copies of the original quality reports. However, the time of record exceeded the laboratory's holding period of seven years and copies were not available. The QP then compared the related quality of the drilling database to the associated month end reconciliation reports and found that modeled tonnages in the area of the 2003 drilling were representative of the actual mined tonnage as shipped to the RHPP. As such, it is the QP's opinion that the quality values documented in the electronic, geologic database for these 22 holes are representative of the deposit.

<u>2009-2015</u>

From 2009 through 2015, MLMC contracted Aquaterra Engineering, LLC (Aquaterra), a Terracon Company, which fully transitioned to Terracon in 2011 to perform drilling exploration work. Century GLS and Cardno Geophysical Logging Services (Cardno GLS) were contracted by MLMC to geophysically log the drill holes. Approximately 180 holes were drilled including pilots, coal cores, continuous cores, and monitoring wells. The majority of drilling was once again focused in the MS-002 permit area ahead of mining operations to achieve an average drill hole density of 1000-feet or less. However, in 2015, MLMC also began fill-in drilling within the MS-004 permit area where the next mine area was projected to be in full operation in 2023. The extent of work for the MS-004 permit area included 6 continuous core holes and 3 monitoring well locations. Geologists from MLMC oversaw these drilling activities and logged core samples which were shipped to Standard Laboratories in Casper, Wyoming for analysis.

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SEC S-K 1300 Technical Report Summary

Mississippi Lignite Mining Company – Red Hills Mine&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;March 2023

The average coal core recovery rate from 2009 through 2015 was 100%. Collar surveys were obtained by Topcon Hyper V Rovers with RTK correction tied to a known GPS base.

Most of the area drilled from 2009 through 2015 in the MS-002 permit area was mined out by December 2020.

<u>2016</u>

In 2016, Liberty Fuels, another subsidiary of NACoal, conducted drilling services for MLMC under a mutual cost reimbursement agreement. Cardno GLS was contracted to geophysically log the drill holes. 34 holes were drilled using rotary wash methods within the MS-002 and MS-004 permit areas. Two core holes were drilled successfully during this program targeting the F-seam and C-seam quality in the MS-004 permit area. Due to poor core recovery on multiple attempts, no other seams were sampled for quality during this program. Geologists from MLMC oversaw these drilling activities and logged core samples which were shipped to Standard Laboratories in Casper, Wyoming for analysis. The coal core recovery of the sampled F- and C-seams in 2016 was 100%. Collar surveys were obtained by Topcon Hyper V Rovers with RTK correction tied to a known GPS base.

<u>2017</u>

In 2017, MLMC contracted Great Southern Engineering (GSE) to collect lignite cores for quality assessment using sonic drilling methods, but due to uncertainty in the representative quality from excessive heating and fracturing of the coal cores during the sample collection process, the QP determined these coal core data would be excluded from the geologic model. 7 pilot holes in advance of these coal cores were conducted by Geotechnical Engineering Associates (GEA) using rotary wash methods. Century GLS geophysically logged these holes. Collar surveys were obtained by Topcon Hyper V Rovers with RTK correction tied to a known GPS base. Information related to the pilot holes in advance of these coal core holes, including geophysical logs and cuttings descriptions were evaluated by the QP and included in the geologic model to further define the structure of the lignite deposit.

<u>2018-2021</u>

From 2018 to 2021, MLMC contracted MHC X-Ploration Corporation, Century GLS, and Marshall Miller and Associates (previously Cardno GLS) to drill and geophysically log approximately 170 pilot holes, coal core holes, and a monitoring well. The holes were drilled using rotary wash methods, and were primarily concentrated in the MS-004 permit area to increase the drill hole density north of the planned boxcut location. However, drilling activities also included the MS-002 permit area as well as additional exploration outside the currently permitted areas. Geologists from MLMC oversaw these drilling activities and logged core samples which were shipped to Standard Laboratories in Casper, Wyoming for analysis. The average coal core recovery rate from 2018 through 2021 was 100%. Collar surveys were obtained by Topcon Hyper V Rovers with RTK correction tied to a known GPS base.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;**7.2.4. Qualified Person Opinion – Drilling Exploration**

The drilling campaigns completed from 2015 through 2021 in conjunction with the original exploration conducted by Phillips chiefly influence the Red Hills Mine Mineral Resource estimations discussed in Section 11.0.

As described in the above drilling programs, MLMC does plan exploration activities to attain an average 500-foot drilling density for the four-year projection ahead of active mining operations. This drilling density is optimal for day-to-day operations to capture the gentle undulation of the lignite seams. Identifying these slight differences in roof elevations is key to optimizing lignite recovery efforts, particularly on the thinner seams.

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SEC S-K 1300 Technical Report Summary

Mississippi Lignite Mining Company – Red Hills Mine&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;March 2023

However, as a whole, it should be noted for the purpose of Mineral Resource estimations and LOM projections, the QP has determined a high level of confidence in the resource classification distances. This confidence comes from the continuity of the lignite seams including both lithologic and quality characteristics, as well as the ability to compare modeled seam projections to active and historical mining operations. Slight structural changes are defined in the tighter drill hole spacing, but these localized structural anomalies tend to not effect quality nor materially affect the structure. Further justification of drill hole distances specific to Mineral Resource Classifications is discussed in Section 11.0.

Physical constraints such as stream buffers and unnavigable terrain may affect the consistency in drill hole spacing. Additionally, drilling exploration for later years does not always land within fully permitted areas which may limit the extent of disturbance allowed.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;**7.3. Hydrogeologic Characterization**

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;**7.3.1. Surface Water**

Beginning in 1996, surface water monitoring sites were established and monitored by Mississippi State University (MSU) under the direction of MLMC within the various streams and tributaries surrounding and intersecting the Red Hills Mine. Baseline flow rates collected by MSU were compared to selected USGS stations within the vicinity of the study area watershed and were analyzed to characterize general runoff conditions. Surface water flow measurements were performed at the monitoring stations using the velocity-area method. As recommended by the USGS, if the depth of flow was greater than two feet, a two-point method of measuring average velocity was used.

To further characterize study area watersheds, rainfall-runoff simulations were performed for storm events with a duration of 24 hours and different return periods. These simulations were performed using the U. S. Army Corps of Engineers HEC-1 flood hydrograph model. Necessary HEC-1 model input includes watershed area, specified rainfall loss and runoff methods, and a design precipitation event. The Soil Conservation Service (SCS) method, now the Natural Resources Conservation Service (NRCS), for abstractions utilizing a curve number (CN), was chosen as the loss rate method, and a SCS/NRCS idealized unit hydrograph was used to model watershed runoff response, as study area watersheds are generally small. Modeled precipitation events were obtained from the U. S. Weather Bureau's Technical Paper No. 40.

Based on baseline flow data, the average runoff for the Red Hills Mine was determined to be approximately 1.25 cfs/square mile of drainage area.

Surface water samples from each monitoring site were collected and analyzed for physical and chemical parameters including pH, conductivity, total dissolved solids (TDS), sulfate, chloride, total suspended solids (TSS), iron, manganese, nitrates, dissolved trace metals, coliforms, acidity, alkalinity, and various organic pollutants. All of the monitoring sites exhibited waters with very similar water quality and with very small seasonal variations. Averages of general water quality results from baseline data include a pH of 6.9 s.u., conductivity of 55 umohos/cm, TDS of 54 mg/l, and TSS of 8 mg/l. Laboratory analytical analysis for samples taken from the monitoring sites for baseline water quality was conducted by Inter-Mountain Laboratories, Inc. Surface water samples were analyzed by EPA approved methods current at the time of sample collection.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;**7.3.2. Groundwater**

In 1996 and 1997 MLMC contracted R.W. Harden & Associates to conduct hydrogeologic studies focusing on groundwater. Work conducted included construction of test wells, sampling of groundwater chemistry, measurement of potentiometric surfaces, and testing of the aquifers.

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SEC S-K 1300 Technical Report Summary

Mississippi Lignite Mining Company – Red Hills Mine&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;March 2023

The primary water bearing strata at the Red Hills Mine is within the Wilcox group, which is composed primarily of fine-grained deposits of interbedded clay, sandy clay and silt. Sand thicknesses were acquired from geophysical log data gathered during the early Phillip's exploration drilling programs and test well installation for initial characterization of aquifers within the Red Hills Mine.

Approximately 43 test wells were installed as part of the initial studies (Figure 7.2). Water levels were measured quarterly in all test wells constructed to determine potentiometric surface of various sand units. Aquifer testing, including pump tests and slug tests, was conducted in 15 of the test wells to study the more permeable horizons in the overburden and underburden of the mine. The testing indicated transmissivities ranging from 0.2 to 16,600 gallons per day per foot, and provided a range of hydraulic conductivities ranging from 0.004 to 31 feet per day. Horizons with higher hydraulic conductivity were generally associated with the coarser sand units in the underburden. Aquifer test results in overburden sands generally show lower transmissivities because only thin sand layers are present and are typically of finer and siltier texture.

Laboratory hydraulic conductivity tests were conducted on clay samples taken from boreholes drilled in the permit area. Results from eight permeability tests indicated, as is typical of Wilcox clay units, that hydraulic conductivities of these clays were low, ranging from 1 x 10-7 to 9.4 x 10-9 centimeters per second, and thus, clay units acted as confining layers to the stratigraphically lower Wilcox sand units. Results of these tests indicated little or no vertical hydraulic communication between sand units separated by clay strata. The layers of clay, predominant in the overburden and underburden materials, act effectively as confining layers. This was confirmed by the results of the laboratory hydraulic conductivity tests indicating low values for these clays.

Natural groundwater movement rates, in both water-table and artesian areas, are very slow and range from a few feet to 50 feet per year in the more permeable sand zones. Vertical hydraulic communication between sand zones is known to be small when separated by low hydraulic conductivity clays. This was demonstrated by the amount of rejected recharge during aquifer testing, indicating little seepage into adjoining beds downdip, and pumping-test data, indicating essentially no influence on drawdown between overlying and underlying sand zones.

Twelve months of water well, monitoring well and spring groundwater quality data was collected by MSU from 21 test wells in 1997 for alkalinity, hardness, total suspended solids (TSS), major cations/anions and select metals. Water samples collected for analyses were analyzed by an independent laboratory, ETC Laboratory, in Memphis, TN. Groundwater samples were analyzed by EPA approved methods current at the time of sample collection. Groundwater quality results from the Wilcox sands is fresh with average total dissolved solids concentrations less than 300 milligrams per liter (mg/L) and minor to moderate iron and manganese concentrations thought to be naturally occurring.

No formal QA/QC document was available for the initial baseline data. However, use of duplicate samples and blanks were noted by the QP upon review of laboratory reports, chain of custody (COC) forms, and field notes related to the data collected by MSU and R.W. Harden & Associates.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;**7.3.3. Qualified Person Opinion – Hydrogeologic Characterization**

The hydrogeology of the Red Hills Mine has been well studied. MLMC has continued to gain an understanding of the water bearing units during mining, established groundwater and surface water monitoring programs, fill-in drilling, and installation of new monitoring wells. In the QP's opinion, these additional observations and collected data from the past 20 years of mining align with the results of the original surface water quantity measurements, aquifer tests, hydraulic conductivity tests, and water quality results.

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SEC S-K 1300 Technical Report Summary

Mississippi Lignite Mining Company – Red Hills Mine&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;March 2023

**Figure 7.2 Groundwater Map**

![image_11.jpg](image_11.jpg)

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SEC S-K 1300 Technical Report Summary

Mississippi Lignite Mining Company – Red Hills Mine&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;March 2023

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;**7.4. Geotechnical Studies**

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;**7.4..1. Early Geotechnical Studies**

Geotechnical soil drilling has been carried out at the property during several investigations. The most notable studies concerning baseline geotechnical properties are described below.

In 1997, Burns Cooley Dennis, Inc. conducted a study to establish ground conditions and geotechnical properties for the various formations in the Red Hills project area. Three geotechnical boreholes to a maximum depth of 70 feet were completed using a 6-inch diameter short-flight earth auger to a depth of 10-feet followed by rotary wash methods to final depth. Each boring was sampled to a depth of 60-feet, drilled an additional 10-feet then geophysically logged by Century GLS. All soils encountered during drilling were classified with respect to material composition and consistency or density by a geotechnical/geological engineer.

Following the previous investigation in 1997, Geoscience Engineering, LLC. completed four cored holes (including an initial pilot hole) drilled to depths ranging from 170 to 360 feet at a 6-inch diameter. The pilot holes and core holes were advanced using rotary wash methods. Soil Samples were collected using a double core barrel.

In 2004, Aquaterra Engineering, LLC. completed eight soil borings using rotary wash methods to a maximum depth of 200 feet. Each soil boring was advanced with a 4-inch diameter drill bit. The soil sampling program included the collection of both disturbed and undisturbed soil samples. The samples were collected at various depths. Relatively undisturbed samples were obtained by pushing a 3-inch diameter, Shelby tube sampler to collect soil samples for geotechnical laboratory testing. Locations of geotechnical borings are shown on Figure 7.3.

The typical geotechnical borehole log included the following geotechnical descriptions and records of the samples collected during investigation:

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• <u>Lithology</u>: Descriptions of the lithology (typically sandy silts, silts and clayey silts) are recorded for each stratigraphic interval in conjunction with a soil type in accordance with the Unified Soil Classification System (USCS). The soil types encountered by Burns Cooley Dennis, Inc., 1997 at the boring locations include clayey sands (SC), silty sands (SM), slightly silty sands (SP-SM), silty and sandy clays (CL), clays (CH) and lignite.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• <u>Consistency/Relative Density</u>: Aquaterra Engineering, LLC., 2004 determined the relative strength estimates of the sample by hand penetrometer readings. In the more granular conditions at this site and at locations where the very dry nature of the surface soils prevented undisturbed sampling, Standard Penetration Testing (SPT) was performed.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• <u>Sample Type and Laboratory Data</u>: The soil borings included various samples collected during the geotechnical investigations. The Aquaterra Engineering investigation (2004) collected piston (Shelby tube) samples (2.0 to 2.5 feet in length) at nominal 10-foot intervals. The piston samples are considered to be relatively "undisturbed" samples and suitable for laboratory testing such as the various strength tests. The index properties determined were the moisture content, Atterberg limits, and grain size determination. The laboratory investigation by burns Colley Dennis, Inc., 1997, included unconfined compression tests, consolidated and unconsolidated undrained triaxial compression tests, water content determination, shear strengths, mechanical sieve analysis, proctor compaction tests, and chemical/corrosion testing. The laboratory investigation by Geoscience Engineering, LLC., 1997 determined the undrained shear strength, unconfined compression test, drained shear strength, moisture content, Atterberg limits, consolidation, and grain size analysis of site materials.

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SEC S-K 1300 Technical Report Summary

Mississippi Lignite Mining Company – Red Hills Mine&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;March 2023

The geotechnical reports available for the QP's review did not document QA/QC protocols and procedures followed by the independent contractor at time of testing and sample collection, however the laboratory standards were indicated. The typical laboratory tests performed in the three investigations described above were performed in accordance with the relevant American Society for Testing and Materials (ASTM) standards at independent certified laboratories and include the following:

Soil Index properties:

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• &nbsp;&nbsp;&nbsp;&nbsp;Moisture content determination – ASTM D 2216, ASTM D 4959

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• Atterberg limit determination – ASTM D 4318

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• Consolidation tests – ASTM D 2435

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• Grain size determination – ASTM D 422 and ASTM D 1140

Soil Strength properties:

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• &nbsp;&nbsp;&nbsp;&nbsp;Direct shear strength tests – ASTM D 3080

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• &nbsp;&nbsp;&nbsp;&nbsp;Consolidated shear strength tests – ASTM D 3080

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• &nbsp;&nbsp;&nbsp;&nbsp;Unconfined compression tests – ASTM D 2166

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• &nbsp;&nbsp;&nbsp;&nbsp;Unconsolidated undrained triaxial tests – ASTM D 2850

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• &nbsp;&nbsp;&nbsp;&nbsp;Consolidated undrained triaxial compression tests – ASTM D 4767

In the QP's opinion the laboratory testing methods completed to determine the geotechnical soil parameters are appropriate for the purpose of detailed pit design outlined in Section 13.5 of this TRS.

Further detail concerning pit design and ground control parameters related to geotechnical studies and additional geotechnical studies related to pore water pressures and effects on pit stability are discussed in Section 13.0 Mining Methods.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;**7.4.2. Buffer Block Study**

In 2011, NACoal conducted an additional geotechnical study to determine the design parameters for a buffer block left between future mine area boxcuts directly adjacent to previously mined pits at the Red Hills Mine. NACoal contracted Terracon, an independent geotechnical company, to drill, sample, and conduct laboratory testing for 8 soil borings within the area of interest (Figure 7.3). Century Geophysical, an independent contractor, geophysically logged the bore holes.

The soil sampling program included the collection of both disturbed and undisturbed soil samples. Relatively undisturbed samples were obtained by pushing a three-inch diameter, Shelby tube sampler a distance of two feet into the soil in general accordance with ASTM D1587.

After the Shelby tube was removed from the boring, the sample was carefully extruded in the field and visually classified. Relative strength estimates of the sample were obtained by penetrometer readings. Disturbed portions of the sample were discarded and the undisturbed sample was placed in a protective container for transportation to the laboratory. An additional portion of the sample was placed in a plastic jar to minimize moisture loss during transport to the laboratory and to aid in visual classification of the sample.

In more granular conditions, the standard penetration test (SPT) was performed. In this case, representative disturbed samples were obtained in cohesionless soils by driving a 2-inch OD split-spoon sampler a distance of 18 inches into the soil with blows from a 140-pound hammer falling a distance of 30-inches (ASTM D 1586). Representative

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SEC S-K 1300 Technical Report Summary

Mississippi Lignite Mining Company – Red Hills Mine&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;March 2023

samples removed from the split spoon sampler and placed in plastic jars to minimize moisture loss provided a sample for laboratory testing.

At selected boring locations, auger samples were also collected to allow collection of soils for classification purposes only. In this case, the sample was retrieved directly from the auger being used to advance the boring. The auger sample was placed in a plastic jar to minimize moisture loss during transport to the laboratory.

The soil samples were delivered to the Terracon laboratory for testing. Laboratory test assignments were made by NACoal. Laboratory testing was accomplished to determine index and strength properties of the soils encountered. These procedures are listed below.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• Index properties: Moisture content (ASTM D2216), Atterberg Limits (ASTM D4318), Grain Size Determination (ASTM D422 and D1140), and Standard Effort Compaction Test (ASTM D 698)

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• Strength Tests: Unconfined Compression (ASTM D2166), Consolidated Undrained Triaxial Compression (ASTM D4767), Unconsolidated Undrained Triaxial Compression (ASTM D2850), Direct Shear Test (ASTM D3080)

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• Permeability Tests (ASTM D5084 and ASTM 2434)

All soils were visually classified and in accordance with criteria stipulated by Unified Soil Classification System (USCS).

During the soil boring advancement and sampling operation, observations for free groundwater was not made because the rotary wash technique was used for the entire boring advancement. Therefore, groundwater levels were not determined. However, ground water information from existing monitoring wells and on-site ground water management programs was available.

Using the results of the laboratory tests and field observations, NACoal conducted a slope stability analysis using the computer program Slope W and a method called Morgenstern-Price to obtain likely factors of safety for opening up a boxcut adjacent to a previously mined pit. Three scenarios for block widths between mine areas were analyzed including a 500-foot block, 250-foot block, and 100-foot block. All scenarios initially assumed 41-degree slopes on either side of the buffer block. All three scenarios resulted in a recommendation that the low wall of a new boxcut adjacent to a previously mined area should be no steeper than 30-degrees to prevent instability and increase the factor of safety near the low wall slope to 1.3.

In the QP's opinion the drilling, sampling, testing, and analysis completed were appropriate to establish low wall pit parameters for opening up a box cut for a new mine area adjacent to a previously mined pit. In the current LOM plan, this parameter only applies to the Mine Area 2 boxcut.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;**7.4.3. Qualified Person Opinion – Geotechnical Studies**

Subsurface conditions and geologic units encountered have remained fairly consistent since mining commenced in 2000. Overburden core holes in which individual sections of burden were collected and tested for physical and geochemical properties, as described previously under drilling exploration, have been evenly distributed throughout the permitted mine areas and continually serve as an indicator for soils to be encountered ahead of mining. Furthermore, the geologic structural data acquired from geophysical logs during drilling campaigns indicate consistent depths between burdens and lignite seams among other subsurface characteristics. Special situations, such as deep pore water pressures described in Section 13.0 of this TRS, have led to additional geotechnical studies specific to the issue encountered while mining. However, the general pit parameters defined by the above studies

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SEC S-K 1300 Technical Report Summary

Mississippi Lignite Mining Company – Red Hills Mine&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;March 2023

have not warranted a need for further studies from the continued information obtained from drilling exploration and active mining operations. The QP understands that additional geotechnical studies may be required on an as needed basis to address special conditions that may be encountered in future mining. These conditions will be monitored and addressed as needed as mining progresses.

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SEC S-K 1300 Technical Report Summary

Mississippi Lignite Mining Company – Red Hills Mine&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;March 2023

**Figure 7.3 Location of Geotechnical Borings**

![image_12.jpg](image_12.jpg)

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SEC S-K 1300 Technical Report Summary

Mississippi Lignite Mining Company – Red Hills Mine&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;March 2023

**8. Sample Preparation, Analysis, and Security**

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;**8.1.Sample Collection and Shipment** 

The Red Hills Mine lignite deposit is evaluated on a seam by seam basis. As a regular practice in the coal industry, lignite cores are bagged and sent to the independent coal testing laboratory. The procedures at the Red Hills Mine for current and historical sample collection are summarized below.

Core runs are specified by the geologist by referencing the geophysical log of the pilot hole. As coal seams rarely exceed 6 feet in thickness, a single 10-foot core run can typically capture a full lignite seam. Once a specified core run is brought to the surface, the geologist observes the drillers extract the lignite sample from the double barrel core to ensure the integrity of the sample is maintained, and to verify the top and the bottom of the coal core run. The core sample is transferred from the core barrel to a core cradle (i.e. halved pvc pipe) and is carried to the geologist's work station. The geologist washes excess drilling mud from the core sample with water, verifies the roof and floor of the lignite core is present and checks the expected coal seam thickness referenced from the pilot hole's geophysical log to determine coal core recovery. If full core recovery cannot be verified, the driller may attempt to retrieve the remainder of the lignite core run from the current hole. If no successful attempt is made to recover the remaining lignite, the driller must re-core the lost interval in a new adjacent core hole to achieve a minimum of 90-percent recovery.

Upon verifying recovery of the core run, logs the lignite run. A typical log describes:

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• &nbsp;&nbsp;&nbsp;&nbsp;"to" and "from" depths of burdens and lignite;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• &nbsp;&nbsp;&nbsp;&nbsp;joints and fractures at specified depths;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• &nbsp;&nbsp;&nbsp;&nbsp;characteristics of burden above and below the lignite core;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• &nbsp;&nbsp;&nbsp;&nbsp;roof and floor of lignite seam (i.e. sharp or gradational);

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• &nbsp;&nbsp;&nbsp;&nbsp;presence of pyrite or petrified wood;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• &nbsp;&nbsp;&nbsp;&nbsp;observations of clay or sands imbedded in the lignite core;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• &nbsp;&nbsp;&nbsp;&nbsp;and any other prominent characteristics.

After the geologist describes the core run, the entire lignite section is double bagged and double tagged. Tags include the date, mine identifier, hole ID, seam ID, and "to" and "from" intervals. Double bagging preserves the moisture of the sample, and double tagging safeguards the identification of the sample from the field through transportation to the independent laboratory. Historically, Red Hills Mine has not photographed coal cores prior to bagging samples, but starting with the 2022 drilling campaign, photographs of core samples are performed as a regular QA/QC practice in logging core samples.

Lignite cores may be split into multiple samples for the following reasons:

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• &nbsp;&nbsp;&nbsp;&nbsp;Prominent roof, floors, or partings within a continuous seam;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• &nbsp;&nbsp;&nbsp;&nbsp;Identification of composition concentrations (i.e. to determine if sulfur trends toward top, middle or bottom of seam).

Total core runs are shipped for analysis following industry standards, thus split samples in the context of a retained sample are not stored at the Red Hills Mine. Lignite tends to be a high moisture coal which oxidizes rapidly and does not have a long shelf life once removed from the ground. If core split samples were retained, they would not be representative of in-situ coal properties over time.

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SEC S-K 1300 Technical Report Summary

Mississippi Lignite Mining Company – Red Hills Mine&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;March 2023

After samples are bagged, they are stored in a dry, shaded area until the geologist returns to the mine office. Core samples are then securely stored in the office until transferred by the geologist to specified pallet boxes in the warehouse to be shipped to the independent laboratory. The warehouse is climate controlled, such that the samples are not kept in a hot environment that could adversely affect the quality results. Furthermore, the Red Hills Mine office and warehouse is secured with user specified fob access and camera surveillance.

Prior to shipping the samples, the geologist reviews each sample against the field records and the chain-of-custody (COC). The date, mine identifier, hole ID, seam ID, and "to" and "from" intervals are verified. In addition to the COC included in the physical shipping container, a copy is emailed to the laboratory manager to notify that a shipment is in route. Copies of the COC forms for coal cores shipped from 2015 through 2021 were available for the QP to review. Coal core samples are shipped to the independent laboratory via insured freight with tracking information.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;**8.2.Sample Preparation and Analysis**

Minimum analyses of coal cores include short proximate (ash, calorific value (BTU/lb), sulfur, moisture) and specific gravity. These parameters are the primary quality inputs used to model the Red Hills Mine lignite deposit. Additional analyses of coal cores may include mineral analysis of ash, trace elements, ash fusion, and forms of sulfur. Historically, full proximate, ultimate analysis, and grindability have been requested on a specialized basis. However, these parameters are not modeled or currently relevant for consideration in Mineral Resource estimations.

As mentioned in Section 7.0, coal cores collected by Phillips in the early years of exploration were sent to Core Laboratories, Inc., an independent laboratory in Tyler, Texas. QA/QC information related to these samples was not provided to MLMC by Phillips when data was acquired in 2000. However, the QP was able to review laboratory certificates to verify quality data related to these core holes.

Since 2000, Red Hills Mine has sent lignite core samples to Standard Laboratories, Inc. (Standard), an independent laboratory in Casper, Wyoming for analyses. Standard is a certified ANAB Accredited and ISO 17025 accredited laboratory for coal including typical lignite coals.

The Mineral Resources QP toured the Standard Laboratory facility in Casper, Wyoming on June 24, 2021. The QP reviewed procedures for chain of custody, QA/QC, and observed laboratory processes and found the operation to be clean, well-managed, and professionally operated. No concerns were noted.

Short proximate parameters, as used to define Mineral Resources and Reserves, are tested at the Casper laboratory location. Other tests at the Casper location include, but are not limited to, mineral analysis of ash and ash fusion. Lignite core samples requesting trace mineral analysis and forms of sulfur analyses are completed by the Freeburg, IL Standard laboratory location from sample splits prepared at the Casper location.

The laboratory ASTM standards used at the Casper location are listed in Table 8.1. A modification to ASTM D3302/D3302M-18 Total Moisture is completed at Standard. Due to lignite having a higher moisture content and faster oxidation rate than higher rank coals, the temperature limit for air-drying was modified to reduce the drying time. Minimal to no evidence of bias was noted in any of the parameters (TM, Dry Ash, AR BTU/lb, MAF Btu) in any of the modified drying times and temperature combinations.

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SEC S-K 1300 Technical Report Summary

Mississippi Lignite Mining Company – Red Hills Mine&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;March 2023

**Table 8.1 List of ASTM standards for Standard Laboratory, Casper location**

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| | | | |
|:---|:---|:---|:---|
| **Specific Tests and/or Properties Measured** | **Specification, Standard, Method, or Test Technique** | **Items, Materials or Product Tested** | **Key Equipment or Technology** |
| Ash in the Analysis Sample | ASTM D 3174 | Coal | Furnace |
| Calorific Value | ASTM D5865 | Coal | Calorimeter |
| Carbon, Hydrogen, and Nitrogen | ASTM D5373 | Coal | Elemental Analyzer |
| Equilibrium Moisture | ASTM D1412 | Coal | Waterbath Method |
| Free-Swelling Index | ASTM D720 | Coal | Electric Method |
| Fusibility of Ash | ASTM D1857 | Coal | Furnace |
| Grindability of Coal | ASTM D409/D409M (MOD) | Coal | Grindability Machine |
| Loss on Ignition | ASTM 7348 | Coal | Oven/Furnace |
| Major and Minor Elements | ASTM D6349 | Coal | ICP-OES, Mixed Acid Digestion |
| Mercury | ASTM D6722 | Coal | Direct Combustion Analysis |
| Moisture in the Analysis Sample | ASTM D3173 | Coal | Oven |
| Moisture (Total) | ASTM D3302/D3302M (MOD) | Coal | Commercial Method |
| Preparing Samples for Analysis | ASTM D2013/D3302M (MOD) | Coal | Crusher/Pulverizer |
| Sulfur (Total) | ASTM D4239 | Coal | Furnace |
| Volatile Matter | ASTM D7582 | Coal | TGA |
| Water Soluble Alkali Content | ASTM D8010 Method A | Coal | ICP-OES |

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&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;**8.2.1. Receiving Dock/Sample Storage Room**

The receiving dock doubles as the sample storage room and is climate controlled (ventilated and heat). Casper, WY has a moderate summer climate, with cold winters that can be mitigated with heaters. From the receiving dock and storage room there is access to the sample prep room and main laboratory.

During non-operational hours Standard is locked down with an active alarm system including door, window and motion detectors which is monitored by a local company.

Once a shipment is received, the shipment is logged and opened then the number of individual samples are logged along with the date and time. Each sample is cross referenced with the COC and is then weighed using certified balances. Paper records including Standard laboratory logs, COC's, and any additional paperwork received in the shipment are transferred to an electronic database at this point.

Once samples are logged, they are stored in this storage room until there is available space in the prep room. It was noted there is a slight potential for moisture loss during this storage period. MLMC acknowledges this potential and, as such, double bags samples in the field to preserve as much in-situ moisture as possible.

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SEC S-K 1300 Technical Report Summary

Mississippi Lignite Mining Company – Red Hills Mine&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;March 2023

Retained pulverized and dried 60-mesh samples are also stored in this room. These samples can be retested within 6 months for selective parameters. Due to the sample being dry and potential for oxidation moisture parameters and Btu/lb cannot be retested. Standard contacts and verifies with the client prior to disposal of retains.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;**8.2.2. Prep Room** 

The prep room is a temperature-controlled room (AC and Heat) accessible from the receiving dock. Within the prep room samples are crushed to 8-mesh size using a Holmes crusher and are then run through a Holmes riffler. Pulverizer screens and rifflers are inspected daily, before and after each batch. The distance between the riffler fin spread is regularly checked in accordance with ASTM standards. An air hose is used to clean out after each sample to mitigate contamination. It was noted that the prep room was very clean. No visible residual material was observed in the riffler.

8-mesh samples are divided into 1000 g per tray following ASTM standards using calibrated balances. Additional sample material is placed in a bag which then has the air mechanically removed and heat sealed for storage in a separate room off of the prep room. The same storage process is used for round robin samples. Similar to the retained samples, Standard verifies with the client prior to disposal of sample splits.

Prepared 1000 g trays are placed in one of three air dry units for overnight drying following the modified standards discussed previously. Drying time and temperatures are regulated on the air-dry units. Certified thermometers are used which also indicate minimum and maximum temperature values to ensure there is no exceedance of the max allowable temperature. Temperature gauges are certified annually, and additional checks are performed quarterly.

Once air-drying is complete and samples are re-weighed and logged. Dried samples are pulverized to 60-mesh and split samples are obtained with a Holmes sample riffle. Split samples are stored in pre-labeled high-density polyethylene (HDPE) bottles with foam lined caps.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;**8.2.3. Laboratory Testing**

After the prep room process, 60-mesh split bottles are transferred to the main portion of the laboratory where they are first run through a mixing wheel for 10 minutes to ensure a homogeneous sample. All equipment maintains logs of processes and results. This portion of the laboratory is climate controlled (AC and heat).

Review of all analysis results is by the laboratory manager, or assistant laboratory manager. Review includes but is not limited to identification of outliers, and comparison of results with historical information by site, if available. The laboratory manager may request a rerun on a sample if needed.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;**8.3.Quality Control Procedures**

There is currently no formal program in place at Red Hills Mine for the inclusion of blanks, standards, pulverized duplicates, or field duplicates. However, Standard completes several internal QA/QC checks to verify samples.

Standard also participates in a monthly round robin coal testing program including 32 other laboratories. A 4-mesh program and an 8-mesh program are included in this round robin. In 2020, Standard also participated in a lignite (coal) specific round robin testing program facilitated by NACoal including 8 commercial laboratories that were used by various NACoal mine locations. The round robin consisted of four samples labeled 2001, 2002, 2003, and 2004. Two samples were sourced from Red Hills Mine and two samples were sourced from another NACoal mine. The two locations provided a range of samples with variability in moisture, ash, sulfur and sodium. The labs

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SEC S-K 1300 Technical Report Summary

Mississippi Lignite Mining Company – Red Hills Mine&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;March 2023

participating in the round robin were provided 8-mesh splits and dried 60-mesh splits of all 4 samples. The general results are summarized in Figure 8.1. Standard is labeled "Laboratory #6" and all results fell within ASTM Range.

**Figure 8.1 NACoal 2020 Round Robin Program Summary. (NACoal, 2020)**

![image_13.jpg](image_13.jpg)

In addition to the monthly round robin coal program, a formal Proficiency Testing Program by Quality Assurance Resources, LLC (QAR PTP) which includes a 4-mesh program and 8-mesh program is also completed monthly. If there is an error or out of tolerance reported, an investigation is immediately completed. Upon investigation, corrective action will be taken to remediate the issue and additional training will be completed if deemed necessary. Trainings were documented. The most current QAR PTP results were posted and personally reviewed by the QP and NACoal's principal geologist during the lab visit.

Along with the above programs, internally at Standard, a daily short proximate testing program was in place.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;**8.4.QP Statement on the Adequacy of Sample Preparation, Security and Analytical Procedures**

Although no formal written procedure existed until recently for the process to collect coal samples at the Red Hills Mine, the consistency in core collection from one drilling program to the next has been thoroughly documented. Through records review and personal observation of numerous drilling campaigns, it is the QP's opinion that historic coal core collection has remained consistent with U.S. Geological Survey's (USGS) guidance for sampling coal for chemical analysis. The process of double bagging and tagging the cores in addition to multiple checkpoints to log samples from field to shipment to the laboratory further ensures the integrity and security of each sample is maintained.

Additionally, in the QP's opinion the methodologies used by Standard Laboratories are within ASTM standards for sample preparation, process of sample splitting and reduction, general quality control, and security of samples to ensure that validity and integrity of samples is upheld.

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SEC S-K 1300 Technical Report Summary

Mississippi Lignite Mining Company – Red Hills Mine&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;March 2023

**9. Data Verification**

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;**9.1.Data Verification Procedures for Mineral Resources**

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;**9.1.1. QP Site Visit**

Benson Chow, Mineral Resource QP, is a Registered Professional Geologist in the state of Mississippi, License Number 0175 and a Registered Member of SME, ID 4317057 and is in good standing with both organizations. He has been involved with the exploration, geology, and mining operations at Red Hills Mine since 1999 and his most recent site visit was on February 13 through 16, 2023. The purpose of this visit was to complete a site visit of the two active mining areas and independent verification of the exploration drill holes. During the visit the QP completed the following task:

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• Inspected the active pit areas for Mine Area 1 west, middle and east end of the pit.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• Observed the extraction of the D Seam coal using the Wirtgen in Mine Area 1. Visited the boxcut in Mine Area 3. Performed survey verification of several previously drilled exploration drill holes. Figure 2-1 shows Mine Areas 1 and 3 inspection and the survey verification of several exploration drill holes. Table 2-1 outlines the holes verified and the variance in northing, easting and elevation.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• Verified drill hole collar locations and elevations from the 2011, 2015, and 2021 drilling programs.

**Figure 9.1 Resource QP Site Visit Photographs**

![image_14.jpg](image_14.jpg)

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SEC S-K 1300 Technical Report Summary

Mississippi Lignite Mining Company – Red Hills Mine&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;March 2023

**Table 9.1 Resource QP Drill Hole Survey Verification**![image_15.jpg](image_15.jpg)

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;**9.1.2. Verification of Drill Hole Data and Geologic (Mineral Resource) Model**

The drilling database for the Red Hills Mine was organized into three Excel files related to lithology intervals, collar survey, and quality. The files encompassed the geologic modeling inputs including lithology picks, total depth of hole, base of oxidation (weathering), hole coordinates, and coal core quality data. A secondary compilation of drilling data was created to verify completeness of data related to each drill hole including the file location of geologist field logs and laboratory certificates or reports for core quality, and details of each drilling program such as contractors who performed the work and year drilled.

The drilling files were saved on the MLMC network drive which contains the geologic model and has limited access by engineering and geology at MLMC.

Once the drilling database was compiled, a series of routine data integrity checks were performed by the QP on the database to check for common errors and omissions. The QP visually inspected the database after updates were made, then conducted a second data validation check using Maptek Vulcan software. The validation checks included, but were not limited to, the following:

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• Verified each hole has a unique collar location.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• Verified the total hole depth on the collar table matches the total depth on the lithology table.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• Verified the from and to depths on the lithology table and quality table increase down hole.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• Verified for overlapping intervals in the lithology table based on from and to depths.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• Verified the from and to depths on the quality table match the associated seam depths on the lithology table.

For any errors or omissions reported, the QP reviewed the geophysical logs, field logs, and quality reports related to the specified holes to reconcile the differences.

After the initial checks were performed, the QP identified any holes in close proximity to other holes such as twinned or re-drilled holes. If two drill holes fell within 50-foot of one another, the data from the two holes was reviewed. The hole with the highest confidence and most complete data was selected to be included in the model. After database checks and reconciliations were completed, the QP completed the modeling process which is detailed in Section 11.1 of this TRS.

The QP reviewed and validated the constructed geological model using various checks between drill hole data and modeled horizons. Drill hole locations were randomly selected to verify modeled values of each horizon and were found to be representative of the imported drill hole data. Additional visual inspection of the model included review of various consecutive cross sections as well as isopach maps of the modeled structure and quality. Newly modeled grids were also compared to previous models. Changes in modeled values were minor and isolated to areas where new drilling data had been included from recent exploration programs. Anomalies were reviewed against the original drill hole data, any errors in the drilling database were reconciled and the model was reconstructed.

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SEC S-K 1300 Technical Report Summary

Mississippi Lignite Mining Company – Red Hills Mine&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;March 2023

It is the QP's opinion that the analytical results from the coal cores collected during MLMC's exploration programs are consistent with actual as-delivered quality from the active mining operations at the Red Hills Mine. This opinion was based on comparison of historical quality projected from the geologic model for the annual operating plans to actual as-delivered quality indicated by the customer's (Red Hills Power Plant) independent laboratory, Advanced Analytical Laboratories. It is also the QP's opinion that the modeled structure of the lignite seams is consistent with active mining operations based on comparisons of modeled seam thickness and trends against actual surveyed seam thicknesses and trends.

The QP found the geologic model for Mineral Resource estimation was a reasonable and reliable representation of the geologic structure and quality of the lignite seams (horizons) at the Red Hills Mine.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;**9.1.3. Verification of the Reasonable Prospect for Economic Extraction to Support Mineral Resource Estimation**

The Red Hills Mine has acquired data related to mine development and production within the local lignite deposit over an extended operational history. The QP verified the assumptions made for the estimation of Mineral Resources were well within accuracy required for an initial assessment (IA) level of study based on actual historical metrics and a contract period defined by the LSA with the RHPP. Data referenced for verification included actual month end reconciliations, production reports, and mine permit requirements. The potential for economic extraction is justified by the terms of the existing LSA with the RHPP through April 2032.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;**9.1.4. Limitations on Data Verification for Mineral Resources**

Representatives of MLMC or NACoal were not involved in the original drilling exploration programs conducted by Phillips prior to 1997. MLMC obtained the collar surveys, geophysical logs, coal core analyses, and geologist field logs for each hole from Phillips, but was unable to observe the drilling, sampling, or sample preparation related to these data. The largest uncertainty lies in the method of the collar survey of the early data drilled from 1975 to 1980. It is unknown to what degree these holes were surveyed. Collar elevations for these early drill holes were plotted against a topographic digital terrain model (DTM) contoured at 5-foot intervals and checked for discrepancies. All plotted drill hole locations fell appropriately within the respective contour interval.

MLMC, historically, has contracted Diversified Drilling Services and Century GLS, contractors used by Phillips for the early exploration, to perform in-fill drilling programs, such that MLMC has gained familiarity in these contractors' drilling and downhole mapping methods. Furthermore, comparisons of new drilling data to the older Phillips data have been completed as fill-in drilling progresses ahead of mining. These comparisons, and the level of documentation Phillips provided upon acquisition of the coal assets translates to a level of confidence in these data to use in the geologic modeling for Mineral Resource estimation. Nonetheless, there is still some uncertainty related to the Phillips drill hole data which the QP has considered in the determination Mineral Resource estimations as discussed in Section 11.0 of this TRS.

Additionally, as discussed previously in Section 7.2 of this TRS, the QP was also unable to verify laboratory records for the 22 coal cores collected in 2003 as included in the drilling database. The QP reached out to the independent laboratory for copies of the original quality reports. However, the time of record exceeded the laboratory's holding period of seven years and copies were not available. The QP then compared the related quality of the drilling database to the associated month end reconciliation reports and found that modeled tonnages in the area of the 2003 drilling were representative of the actual mined tonnage as shipped to the RHPP. After this comparison, the QP determined the uncertainty in the modeled 2003 quality would not materially affect the Mineral Resource estimations.

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SEC S-K 1300 Technical Report Summary

Mississippi Lignite Mining Company – Red Hills Mine&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;March 2023

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;**9.1.5. QP's Statement of Adequacy of Data for Mineral Resources**

Data disclosed in this TRS used for the preparation of geologic models for the purpose of Mineral Resource estimations at the Red Hills Mine have been verified by the QP. The QP has been involved with the collection of these data during drilling exploration programs since 1999. These data include drill hole surveys, geophysical logs, coal core quality, and other relevant test data. Procedures discussed previously in this section were used by the QP to reconcile any discrepancies upon review of the available data. In addition to a substantial geologic database, historical data since the mine opened the original boxcut in 2000 was available to the QP to review to ensure appropriate mining costs were applied to estimate Mineral Resources.

It is the QP's opinion that the data provided for this TRS is sufficient for the determination of Mineral Resources at the Red Hills Mine.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;**9.2.Data Verification Procedures for Mineral Reserves**

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;**9.2.1. QP Site Visit**

Jefferson King, is serving as the Mineral Reserve QP, a licensed Professional Engineer (License Number 18896) and Land Surveyor (License Number 3033) in the State of Mississippi. He has had direct involvement with production, technical projects, development of the LOM plan and financial analysis since 2013. He has held various roles in the Engineering department at Red Hills and is currently serving as the Engineering Manager. In the role of Engineering Manager, he has direct involvement with daily production operations and oversight and management of technical projects, and is directly involved in the development of the LOM finances at the Red Hills Mine.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;**9.2.2. Verification of Hydrogeology Data**

Groundwater and surface water studies were conducted on the Red Hills Mine site, as described in Section 7.3 of this TRS, and used to develop mine plans as described in Section 13.0 of this TRS. The QP has reviewed the findings of these studies and believes they are thorough, complete and provide the necessary information for the start-up and ongoing operation of the Red Hills Mine. Sampling and modelling techniques used in the studies were adequate and completed in a professional manner for a PFS level assessment of the hydrology/hydrogeology. The locations of the surface water sampling sites and monitoring/test well locations are adequate for the MS-002 and MS-004 permit areas. The Red Hills Mine has operated for 20 years and is continuously gaining an improved understanding of how the groundwater and surface water impacts mining operations along with environmental compliance.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;**9.2.3. Verification of Geotechnical Data**

Several geotechnical studies were initially conducted on the Red Hills Mine site as described in Section 7.4 of this TRS and subsequent studies conducted and described in Section 13.5 of this TRS. These studies have been reviewed by the QP and they provided the basis for the mine plan designs. Sampling and modelling techniques used in the studies were adequate and completed in a professional manner for a PFS level assessment of the geotechnical parameters. It is the opinion of the QP that the geotechnical studies reviewed have been consistent with conditions experienced in the field from the active mining operation and are adequate for use in the MS-002 and MS-004 mining areas.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;**9.2.4. Verification of Cut-off Grade, Dilution Assumptions and Modifying Factors**

The QP reviewed the cut-off grade, dilution assumptions, and all modifying factors for completeness and reasonableness and found them to be consistent with the realized results from the active mining operation.

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SEC S-K 1300 Technical Report Summary

Mississippi Lignite Mining Company – Red Hills Mine&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;March 2023

Quality reject specifications from the LSA are the basis for determining the cut-off grades. While the cut off grades vary from the LSA reject specifications any coal that meets the cut off grades can ultimately be blended with other coal seams to meet the LSA requirements. The QP has reviewed the cut-off grades and LSA and in his opinion these have been properly established.

Dilution parameters are reasonable and have been verified by comparing projected to actual as-delivered quality data which confirms the established dilution parameters are a good representation of final results. Recovery rates have been refined over the course of operating the Red Hills Mine and are constantly being compared to actual recoveries for verification.

Modifying factors used in pit designs, as described in Section 13.0 of this TRS, have remained consistent since mine inception with limited changes. The modifying factors have been reviewed by the QP and consistently applied in the mine design process.

It is the opinion of the QP that the cut-off grade, dilution assumptions and modifying factors are adequate for purposes of determining Mineral Reserves.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;**9.2.5. Verification of Ultimate Pit Configuration**

The ultimate pit configuration is defined by physical constraints including permitted boundaries and related offsets and buffers, and areas where the stripping ratio exceeds economic limits. It is the opinion of the QP that the ultimate pit configuration has been properly defined and is adequate for purposes of determining Mineral Reserves.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;**9.2.6. Verification of Cost Estimate, Pricing Assumptions, and Economic Analysis**

The QP has reviewed annual historical values for all costs, pricing assumptions and economic analysis to be reasonable for future projections, which will continue to be refined annually as more data is collected from ongoing operations, to improve the accuracy of the projections. This information has been used to support parameters used during mine planning.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;**9.2.7. Workforce, Staffing and Equipment**

The QP considers that reconciliations of staffing and workforce requirements, actual equipment capacities and productivities have been appropriately considered while establishing the needs of executing the mine plan. The Red Hills Mine is an active, on-going operation and the staffing, workforce, and equipment requirements are well established. Ultimately the required staffing, workforce, and equipment needs are driven by the dispatch of the RHPP.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;**9.2.8. Environmental Factors**

The QP has worked closely with the Red Hills Mine Environmental Manager and has helped develop the site closure and reclamation plans and the related costs. Proper monitoring programs to meet mine permit requirements are in place. Field work has been observed routinely by nature of the QP's on-site role to verify the conditions and assumptions that underscore the environmental data used in this TRS.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;**9.2.9. Limitations on Data Verification for Mineral Reserves**

It is the opinion of the QP that there are no limitations to data verification for Mineral Reserves.

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SEC S-K 1300 Technical Report Summary

Mississippi Lignite Mining Company – Red Hills Mine&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;March 2023

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;**9.2.10. QP's Statement of Adequacy of Data for Mineral Reserves**

The QP has verified the data disclosed, including prior technical studies used in the development of the modifying factors, cut-off grade, ultimate pit configuration, mine design, schedule, workforce and staff requirements, equipment needs, environmental factors, cost assumptions, pricing assumptions and economic analysis. The QP has been involved with the collection and use of this data since 2013 while being employed at the Red Hills Mine. Red Hills Mine has established internal policies and controls to manage the environmental, regulatory and social or community aspects for the mining operations. These are periodically reviewed by the QP and other managers at the Red Hills Mine and NACoal management for their effectiveness in a culture which follows the principle of continuous improvement. The QP is of the opinion that a reasonable level of verification has been completed and that no material issues have been left unidentified in the course of collecting and analyzing the data described in this report.

It is the QP's opinion that the data provided for this TRS is sufficient for the determination of Mineral Reserves at the Red Hills Mine.

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SEC S-K 1300 Technical Report Summary

Mississippi Lignite Mining Company – Red Hills Mine&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;March 2023

**10. Mineral Processing**

It was identified early on that the Red Hills Mine and power plant project would only be viable if the fuel source could be used as a direct feed ROM fuel source. Therefore, no washability tests for processing or metallurgical tests were conducted.

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SEC S-K 1300 Technical Report Summary

Mississippi Lignite Mining Company – Red Hills Mine&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;March 2023

**11. Mineral Resource Estimates**

This section contains forward-looking information related to the Mineral Resource estimates for the Red Hills Mine. The material factors that could cause actual results to differ from the conclusions, estimates, designs, forecasts or projections include geological modeling, grade interpolations, cutoff parameters, lignite price estimates, mining cost estimates, and mine design parameters.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;**11.1. Key Assumptions, Parameters and Methods**

The QP developed the stratigraphic geologic model for Mineral Resource estimation using Maptek Vulcan software. All verified drilling data as of July 23, 2021 was considered for inclusion in the model. Key assumptions, parameters and methods to estimate Mineral Resources are discussed herein. In-fill drilling has been completed through 2022, however has not been included in the current geological model. In the opinion of the QP, the drill holes from the 2022 program are in-fill and will not materially affect the Mineral Resource estimates stated in this TRS.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;**11.1.1. Horizons**

The structure of the Red Hills Mine deposit is determined by "to" and "from" depth picks from geophysical logs and geologist's drill hole field logs correlated to the drill hole collar survey. Depth picks represent the roof or floor of a lignite seam which define each horizon or domain.

Laboratory results for split cores are reviewed prior to inclusion in the geologic database for modeling. Quality results for all split samples to identify composition concentrations are identified as a continuous seam in the geologic database. The weighted average is computed in the modeling process, which allows for a single composite value for each lignite seam per drill hole.

Roofs, floors and parting samples that meet a minable quality and thickness (see Table 11.1) are identified as part of the associated seam and are modeled in the same manner as the split samples described previously. Roofs, floors and partings that do not meet a minable quality or thickness are included in the geologic database as a point of record, but are not modeled with a seam identifier, and thus the quality and thickness of those sample splits are not composited with the associated seam.

**Table 11.1 Quality (as-received basis) and Thickness Limits** 

---

| | | |
|:---|:---|:---|
| **Parameter** | **Minimum** | **Maximum** |
| Calorific Value, Btu/lb | 4000 | N/A |
| Ash, %wt | N/A | 30.0 |
| Thickness, feet | 1.0 | N/A |

---

Table 11.2 presents the stratigraphic horizons modeled. Horizons considered for Mineral Resource estimates are indicated with an asterisk. Modeled horizons were required to have a minimum of ten coal core samples in the drilling database to be considered. The QP found a minimum of 10 coal core samples provided the statistical confidence to characterize the quality of a lignite seam.

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SEC S-K 1300 Technical Report Summary

Mississippi Lignite Mining Company – Red Hills Mine&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;March 2023

**Table 11.2 Stratigraphic Horizons**

---

| | | |
|:---|:---|:---|
| **HORIZON ID** | **SEAM NAME** | **AVERAGE THICKNESS** |
| COJ | J-Seam | 1.7 |
| CI2 | I2-Seam | 1.1 |
| COI | I-Seam | 1.6 |
| CI1 | I1-Seam | 1.1 |
| CH2 | H2-Seam | 1.4 |
| **COH\*** | **H-Seam\*** | **2.5** |
| CH1 | H1-Seam | 1.2 |
| CG2 | G2-Seam | 1.4 |
| **COG\*** | **G-Seam\*** | **3.0** |
| CG1 | G1-Seam | 1.2 |
| CG3 | G3-Seam | 1.3 |
| CF2 | F2-Seam | 1.0 |
| **COF\*** | **F-Seam\*** | **2.8** |
| CF1 | F1-Seam | 1.4 |
| CE2 | E2-Seam | 0.9 |
| **COE\*** | **E-Seam\*** | **3.5** |
| CD6 | D6-Seam | 1.1 |
| CD4 | D4-Seam | 1.3 |
| CD2 | D2-Seam | 1.2 |
| **COD\*** | **D-Seam\*** | **3.3** |
| CC2 | C2-Seam | 0.9 |
| **COC\*** | **C-Seam\*** | **3.1** |
| CC1 | C1-Seam | 1.0 |
| CB2 | B2-Seam | 1.1 |
| COB | B-Seam | 3.1 |
| CB1 | B1-Seam | 1.5 |
| CB3 | B3-Seam | 1.0 |
| **\*** Indicates horizon with an average drill hole quality and an adequate number of core samples which meet the limits for consideration as a Mineral Resource. | **\*** Indicates horizon with an average drill hole quality and an adequate number of core samples which meet the limits for consideration as a Mineral Resource. | **\*** Indicates horizon with an average drill hole quality and an adequate number of core samples which meet the limits for consideration as a Mineral Resource. |

---

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;**11.1.2. Quality Parameters and Density Determination**

The quality parameters modeled in the resource model are calorific value (Btu/lb), moisture (wt%), ash (wt%), and sulfur (wt%); typical Short Proximate analysis reported on an as-received (AR) moisture basis. The minimum and maximum quality constraints which determine feasibility to be categorized as a Mineral Resource are also listed in Table 11.1.

In addition to the quality grids, each lignite seam (horizon) has a modeled density grid. Specific Gravity (SG) analysis is regularly tested on lignite core samples. Modeled SG values by horizon are converted to a density grid in the modeling process by converting grams per cubic centimeter (g/cm<sup>3</sup>) to tons per cubic foot (tons/ft<sup>3</sup>) such that: SG \* Density of Water (62.43 lb/ft<sup>3</sup>) \* 2000 lb/ton.

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SEC S-K 1300 Technical Report Summary

Mississippi Lignite Mining Company – Red Hills Mine&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;March 2023

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;**11.1.3. Modeling Process**

After the QP verified the drilling data following procedures outlined in Section 9.1 of this TRS, the stored drill hole data encompassing geologic lithology picks, quality data, and collar surveys was imported into the modeling software.

The lithology and location tables were then referenced by the modeling program and the structural model was developed. The lignite horizons were correlated and modeled using 50-foot grid cells. During the modelling process, lithologic data were extrapolated from ten surrounding drill holes using an inverse distance squared calculation to infill the grids where appropriate.

The base of oxidation (BOX) depth determined from drill cuttings and continuous (overburden) cores was modeled to provide the limit for suitable plant growth material (SPGM) for operations. This limit also generalizes the base of weathering in that lignite above this depth has been partially oxidized and typically exhibits unacceptable quality characteristics. The depth of the BOX layer was modeled by the grid calculation method using 50-foot grid cells and the extrapolated depth of the BOX from drill hole to drill hole. Lignite seams were then subcropped based on the BOX and lignite seams above the BOX were removed from the model.

The structural model was validated based on geological cross sections and isopach maps of the seam roofs and floors that were created, and checked by the QP. Any errors identified in the lithologic descriptions were reconciled.

Lignite quality was then modeled for the entire deposit. As described above, quality data was first composited for each lignite seam by drill hole. As with the structural model, the quality model uses 50-foot grid cells to model quality of the deposit. Drill holes missing quality data employed an inverse distance squared calculation to assign averaged values from ten surrounding drill holes.

In-situ tonnages for the lignite seams were estimated within Maptek Vulcan by applying a formula to each horizon by the area, thickness, density, and real/extrapolated quality values (i.e. modeled parameters).

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;**11.1.4. Justification of Modeling Methods**

Historically, geologic models at the Red Hills Mine have been generated using inverse distance methods. The models have proved to be consistent with field conditions (structure and quality), which is likely attributed to the simplistic, stratigraphic geology of the region as described in Section 6.0 of this TRS. Geologic units are laterally consistent with generally graded quality. Use of inverse distance methods has proven to be robust in continuous stratigraphic deposits. The QP did not see a need for MLMC to alter geologic modeling methods.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;**11.1.5. Limits and Constraints on the Mineral Resource Estimates**

The Mineral Resources presented in Table 11.4 were estimated by applying a series of geologic and physical limits in addition to mining and economic constraints which meet the level of accuracy required for an initial assessment (IA). The potential of economic extraction is justified by the terms of the existing LSA contract and are clearly

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SEC S-K 1300 Technical Report Summary

Mississippi Lignite Mining Company – Red Hills Mine&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;March 2023

defined through April 2032. Key constraints used by the QP to determine Mineral Resource estimates are summarized below. Details pertaining to physical constraints are discussed further within Sections 3.0 and 17.0 of this TRS. Mining and economic constraints specific to Mineral Resource estimates are discussed herein.

Geologic Constraints:

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• &nbsp;&nbsp;&nbsp;&nbsp;Modeled roof and floors of each lignite seam (horizon);

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• &nbsp;&nbsp;&nbsp;&nbsp;Base of oxidation (BOX);

Physical Constraints:

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• &nbsp;&nbsp;&nbsp;&nbsp;Topography surface;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• &nbsp;&nbsp;&nbsp;&nbsp;Lease and fee coal boundaries;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• &nbsp;&nbsp;&nbsp;&nbsp;Surveys of mined out tonnages as of December 31, 2022;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• &nbsp;&nbsp;&nbsp;&nbsp;Offsets from unleased land tracts and occupied dwellings;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• &nbsp;&nbsp;&nbsp;&nbsp;Buffers from state and federal parks;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• &nbsp;&nbsp;&nbsp;&nbsp;Existing roads and highways, major utilities, and major surface infrastructure without prior agreements for relocation or temporary closure;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• &nbsp;&nbsp;&nbsp;&nbsp;Stream offsets for Waters of the US (WOTUS) that fall outside of mitigation permits.

Mining and Economic Constraints:

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• &nbsp;&nbsp;&nbsp;&nbsp;Resource categorization parameters based on distance from point of observation and drill hole sample count criteria;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• &nbsp;&nbsp;&nbsp;&nbsp;Resource pit shells developed from general mine design parameters and reasonable unit costs used to determine the max cumulative strip ratio for the tonnage to be economical;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• &nbsp;&nbsp;&nbsp;&nbsp;Stated in-situ without any mining loss, dilution or other modifying factors applied;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• &nbsp;&nbsp;&nbsp;&nbsp;Stated exclusive of Mineral Reserves;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• &nbsp;&nbsp;&nbsp;&nbsp;Limits on quality and thickness parameters presented in Table 11.1.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;**11.1.6. Generation of Pit Shells for Mineral Resource Estimates**

Resource pit shells were projected and confirmed to meet the supply requirements of the LSA.

The QP determined the maximum reasonable cumulative stripping ratio was 18:1 for the Red Hills Mine deposit assuming a lignite sales price based on the LSA of $29.66 per ton as of December 31, 2022. Assumptions of mining costs were based on knowledge of surface mining methods in a simple multi-seam, stratigraphic deposit.

Three pit shells were identified for Mineral Resource estimates. Mine Area 1 and Mine Area 2 fall within the MS-002 permit area, and Mine Area 3 falls in the MS-004 permit area.

The geologic model was used to create a stripping ratio map of the deposit. Recovery of tonnage was assumed to be 100-percent. No dilution factors were applied. The C- seam was assumed by the QP to be the lowest potentially mined lignite seam. Highwalls and endwalls were projected up from the lowest mineable seam to the topography at 40-degrees, an angle appropriate for surface mining in soft materials. Preliminary pit shells were determined by the QP based on the maximum cumulative stripping ratio, then modified for any physical constraints.

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SEC S-K 1300 Technical Report Summary

Mississippi Lignite Mining Company – Red Hills Mine&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;March 2023

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;**11.2. Mineral Resource Estimates**

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;**11.2.1. Basis for Mineral Resource Estimate**

The basis of the Mineral Resource estimates for the Red Hills Mine deposit and the methods in which they were prepared are summarized for this item. The S-K 1300 regulations (17 CFR 229.1300) define a Mineral Resource as:

"A concentration or occurrence of material of economic interest in or on the Earth's crust in such form, grade or quality, and quantity that there are reasonable prospects for economic extraction. A Mineral Resource is a reasonable estimate of mineralization, considering relevant factors, such as cut-off grade, likely mining dimensions, location, or continuity, that, with the assumed and justifiable technical and economic conditions, is likely to, in whole or in part, become economically extractable. It is not merely an inventory of all mineralization drilled or sampled."

Following definitions presented in 17 CFR 229.1300 and guidance from the Committee for Mineral Reserves International Reporting Standards (CRIRSCO), Mineral Resources are divided into three categories as listed below and are ranked by increasing level of confidence. Mineral Resources are reported as in-situ tons such that no adjustments have been made to account for mining recovery or losses.

Measured Mineral Resources are defined as a Mineral Resource for which quantity and quality are estimated on the basis of conclusive geological evidence and sampling such that the geologic certainty of the Mineral Resource is sufficient to allow the QP to apply modifying factors in detail to support detailed mine planning and final evaluation of the economic viability of the deposit. Measured Mineral Reserves have the greatest confidence defined by the QP, and may be converted to a Proven Mineral Reserve.

Indicated Mineral Resources are defined as a Mineral Resource for which quantity and quality are estimated on the basis of adequate geological evidence and sampling such that the QP can apply modifying factors in sufficient detail to support mine planning and evaluation of the economic viability of the deposit. These Mineral Resources may be converted to a Probable Mineral Reserve. Indicated Mineral Resources have a moderate level of confidence determined by the QP, and could be upgraded to a Measured Mineral Resource with further exploration.

Inferred Mineral Resources are defined as a Mineral Resource for which quantity and quality are estimated on the basis of limited geological evidence and sampling. Geological evidence is sufficient to imply but not verify geological and quality continuity. Inferred Mineral Resources have the lowest level of confidence determined by the QP.

The QP based the Mineral Resource estimates presented in Table 11.3 for the Red Hills Mine on a stratigraphic geologic model generated from the verified drilling exploration data presented in Section 7.2 of this TRS. The choice of stratigraphic modeling is due to the lateral persistence and continuous extent of the lignite seams.

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SEC S-K 1300 Technical Report Summary

Mississippi Lignite Mining Company – Red Hills Mine&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;March 2023

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;**11.2.2. Mineral Resource Statement**

The categorized Mineral Resources reported in Table 11.3 are exclusive of in situ Mineral Reserves. The effective date of Mineral Resource estimates is December 31, 2022.

**Table 11.3 Mineral Resource Estimates**

---

| | | | | | | |
|:---|:---|:---|:---|:---|:---|:---|
| | | | **Quality (As-Received)** | **Quality (As-Received)** | **Quality (As-Received)** | **Quality (As-Received)** |
|<br>**Red Hills Mine** |<br>**Resource Classification** |<br>**Tonnage**<br>**(Kt)** | **Calorific Value (Btu/lb)** | **Moisture (%wt)** | **Ash (%wt)** | **Sulfur (%wt)** |
| Mine Area 1 | Measured | 0 | 0 | 0.0 | 0.0 | 0.0 |
| Mine Area 1 | Indicated | 0 | 0 | 0.0 | 0.0 | 0.0 |
| Mine Area 1 | Measured + Indicated | 0 | 0 | 0.0 | 0.0 | 0.0 |
| Mine Area 1 | Inferred | 0 | 0 | 0.0 | 0.0 | 0.0 |
| Mine Area 2 | Measured | 4300 | 5210 | 44.6 | 12.8 | 0.6 |
| Mine Area 2 | Indicated | 400 | 5230 | 44.3 | 12.8 | 0.6 |
| Mine Area 2 | Measured + Indicated | 4700 | 5210 | 44.5 | 12.8 | 0.6 |
| Mine Area 2 | Inferred | 0 | 0 | 0.0 | 0.0 | 0.0 |
| Mine Area 3 | Measured | 0 | 0 | 0.0 | 0.0 | 0.0 |
| Mine Area 3 | Indicated | 100 | 5490 | 41.6 | 12.4 | 1.0 |
| Mine Area 3 | Measured + Indicated | 100 | 5490 | 41.6 | 12.4 | 1.0 |
| Mine Area 3 | Inferred | 1600 | 5370 | 46.0 | 9.9 | 0.5 |
| Total Resources | Measured | 4300 | 5210 | 44.6 | 12.8 | 0.6 |
| Total Resources | Indicated | 500 | 5300 | 43.6 | 12.7 | 0.7 |
| Total Resources | Measured + Indicated | 4800 | 5220 | 44.5 | 12.8 | 0.6 |
| Total Resources | Inferred | 1600 | 5370 | 46.0 | 9.9 | 0.5 |

---

Notes:

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;1.Mineral Resources that are not Mineral Reserves do not have demonstrated economic viability and there is no certainty that all or any part of such Mineral /resources will be converted into Mineral Reserves.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;2.Mineral Resources are in-situ and exclusive of 25.4 million tons (Mt) of Mineral Reserves.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;3.Mineral Resources are reported using an economic cutoff of $29.66 per ton.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;4.Resources are presented with a minimum 1 foot seam thickness, a maximum as received moisture basis ash content of 30%, and a minimum calorific value of 4000 BTU/lb on an as received moisture basis cutoff.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;5.Resources are estimated using Vulcan Software.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;6.Tonnages and qualities have been rounded to an accuracy level deemed appropriate by the QP. Summation errors due to rounding may exist.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;**11.3.Cut-off Quality, Assumed Cost and Sales Price**

Quality limits were previously discussed with Table 11.1 and in subsection Limits and Constraints on the Mineral Resource Estimates under Section 11.1 of this TRS.

Assumed cost and sales price to determine Mineral Resources was previously defined by the stripping ratio and discussed in subsection Generation of Pit Shells for Mineral Resource Estimates of Section 11.1 of this TRS.

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SEC S-K 1300 Technical Report Summary

Mississippi Lignite Mining Company – Red Hills Mine&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;March 2023

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;**11.4. QP's Classification of Mineral Resources**

The Mineral Resource categorization applied by the QP includes the consideration of quality and thickness by seam and by drill hole and the spatial distribution of drill holes. Mineral Resources presented in this TRS were estimated and categorized as Measured, Indicated, or Inferred.

Table 11.2 identified the lignite seams for initial consideration of a Mineral Resource by the QP. The indicated seams had a minimum of ten coal core samples for quality estimation, and an average coal core sample quality which fell within the limits provided in Table 11.1. Mineral Resources were then further defined by the three identified resource pit shells.

As discussed in Section 7.2 all drill holes within the Red Hills Mine deposit obtained structural data related to the lignite seams, where a portion of these drill holes also included quality data from the collection of coal core samples. As such, the QP determined it would be appropriate that the defined distances for Mineral Resource categories were supported by the ash variography of the C Seam. C Seam is the stratigraphically deepest and most spatially consistent seam within the deposit and represents the basal seam of the LOM plan. A histogram of the ash distribution has been included as Figure 11.1 which shows a typical positive skew distribution of ash samples for C Seam. Figure 11.2 shows the variogram developed for C Seam ash which displays the continuity of the ash content within the C Seam. A range of 8,000 feet can be estimated from this C Seam ash variogram. Samples beyond the range are no longer considered to have a correlation.

**Figure 11.1 C Seam Ash Histogram**

![image_16.jpg](image_16.jpg)

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SEC S-K 1300 Technical Report Summary

Mississippi Lignite Mining Company – Red Hills Mine&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;March 2023

**Figure 11.2 C Seam Ash Variogram**

![a112trsa.jpg](a112trsa.jpg)

A variogram of C Seam thickness was developed to show the continuity of the structural thickness of the C Seam and has been included as Figure 11.3. A range of 12,000 feet can estimated from the C Seam thickness variogram.

**Figure 11.3 C Seam Thickness Variogram**

![a113trsa.jpg](a113trsa.jpg)

The QP has determined that a maximum classification distance of 8,000 feet is appropriate for the deposit by analyzing the variogram ranges from the C Seam ash and comparing this range with the variogram range for the C Seam thickness. The C Seam ash variogram range distance is conservative and is within the 12,000 feet range for the structural thickness continuality of the C Seam. Potential overstating of reserves is mitigated by using the C Seam ash variogram range with the shorter distance when compared with the larger C Seam thickness range.

After review, the QP determined distances from core holes of 2,667 feet, 5,333 feet, and 8,000 feet are appropriate for categorization of Mineral Resources as Measured, Indicated, or Inferred, respectively (Table 11.4). These classification distances are applied to each seam by only using holes where each representative seam was sampled for quality as points of reference.

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SEC S-K 1300 Technical Report Summary

Mississippi Lignite Mining Company – Red Hills Mine&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;March 2023

**Table 11.4 Mineral Resource Categories – distances from C Seam Ash Variogram**

---

| | | |
|:---|:---|:---|
| **Mineral Resource Category** | **Lower Distance (Ft)** | **Upper Distance (Ft)** |
| Measured | 0 | 2,667 |
| Indicated | 2,668 | 5,333 |
| Inferred | 5,334 | 8,000 |

---

As stated previously, all Mineral Resource tonnages meet the minimum of 10 samples per seam for estimation, meet the quality limits, and fall within a defined resource pit shell. The distinguishing factor between Measured, Indicated, and Inferred Resources is the distance of the resource from a core hole as described below and shown in Figure 11.4. Please note that Figure 11.4 is only for the C Seam, as an example, individual maps and influence polygons were compiled for each individual seam and those were utilized for the Mineral Resource estimate.

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SEC S-K 1300 Technical Report Summary

Mississippi Lignite Mining Company – Red Hills Mine&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;March 2023

**Figure 11.4 Red Hills Mine Mineral Resource Classification for C Seam**

![image_19.jpg](image_19.jpg)

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SEC S-K 1300 Technical Report Summary

Mississippi Lignite Mining Company – Red Hills Mine&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;March 2023

Measured Mineral Resources are defined as tonnages which meet the general resource requirements and fall within an area where the distance from a core hole is less than or equal to 2,667 feet. An extensive amount of fill-in drilling has occurred in areas where core holes have been drilled at a distance within 1,000-feet of each other. At this distance, much of the structural data has been tightened to a density of 500-feet or less. Most of this drilling data was collected by MLMC using known sampling methods and surveying methods. Due to the level of control and oversight during collection of this drilling data, the resulting resource estimates have a high level of confidence by the QP and a low level of uncertainty.

Indicated Mineral Resources are defined as tonnages which meet the general resource requirements and fall within an area where the distance from a core hole is greater than 2,667 feet and less than or equal to 5,333 feet. While a portion of this data still relies on some of the early exploration data collected by Phillips, much of the area has been filled-in with data collected by MLMC using known sampling methods and surveying methods. While some uncertainty still exists in this data due to the influence of the early Phillips drilling, a moderate level of confidence in this data has been applied by the QP from more recent fill-in drilling.

Inferred Mineral Resources are defined as tonnages which meet the general resource requirements and fall within an area where the distance from a core hole is greater the 5,333 feet and less than or equal to 8,000 feet. Modeled values at this distance require a large amount of interpolation from drilling data collected in the early exploration stage conducted by Phillip's from 1975 through 1980 and, as such, holds the greatest uncertainty in sample collection and survey methods. Fill-in drilling, including twinned holes would increase the confidence in these data.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;**11.5. Uncertainty in the Mineral Resource Estimate**

The drilling methods, sampling methods, hole survey, sample storage and preparation, and data processing for the Phillips holes are unknown and cannot be verified. More recent drilling appears to agree with the results of the original Phillips drilling. Risk associated with using the Phillips data is considered minimal since the newer data validates the Phillips drilling and sampling methods, sample storage, and data testing and processing. This is considered a low risk of uncertainty for all Mineral Resource classifications.

Geological uncertainties exist in the modeled limits of the coal seams. Although there are over 1,400 holes drilled and used to model this deposit, but subcropping of seams have been encountered in the Mine Area 1 that were not identified in any exploratory drilling campaign. These areas have been small and limited in aerial extent. Measured and Indicated classifications have a low risk to its resources due to the high density of sampling. Inferred class has a moderate level of risk of uncertainty to the geologic modeling.

Resource estimation distances were derived from a statistical analysis of C Seam as-received ash content and C Seam thickness. Variograms were developed for ash and thickness and the ranges were determined for each variogram. The variogram range for ash is estimated at 8,000 feet while thickness range is estimated at 12,000. By selecting the more conservative distance for the Inferred classification the QP believes that all there is a low risk of uncertainty for all Mineral Resource classifications.

Table 11.5 shows a tabular summary of the resource classification uncertainty.

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SEC S-K 1300 Technical Report Summary

Mississippi Lignite Mining Company – Red Hills Mine&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;March 2023

**Table 11.5 Resource Classification Uncertainty Summary**

---

| | | | |
|:---|:---|:---|:---|
| Uncertainty Type | Measured Uncertainty | Indicated Uncertainty | Inferred Uncertainty |
| Drilling | Low | Low | Low |
| Sampling | Low | Low | Low |
| Data Processing and Handling | Low | Low | Low |
| Hole Survey | Low | Low | Low |
| Geological Modeling | Low | Low | Moderate |
| Geostatistical Analysis | Low | Low | Low |
| Mineral Resource Estimate | Low | Low | Low |

---

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;**11.6. QP's Opinion on Potential Influences Affecting Mineral Resource Estimates**

Due to the contract provisions of the LSA, factors including contract term or likelihood of economic extraction, lignite sales price, and quality parameters/limits have far less risk of being affected than a mineral sold on the open market. Nonetheless some risks still need to be addressed.

Additional exploration may positively or negatively affect Mineral Resource estimates. Furthermore, Mineral Resource estimates may be materially affected by a change in the assumptions including general mining costs and land control. New regulations may impose additional economic factors, delays to future permit renewals, or restrictions to physical estimation boundaries.

The QP is not aware of any specific factors that would currently materially affect the prospect of economic extraction.

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SEC S-K 1300 Technical Report Summary

Mississippi Lignite Mining Company – Red Hills Mine&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;March 2023

**12. Mineral Reserve Estimates**

This section contains forward-looking information related to the Mineral Reserve estimates for the Red Hills Mine. The material factors that could cause actual results to differ from the conclusions, estimates, designs, forecasts or projections include geological modeling, grade interpolations, cutoff parameters, lignite price estimates, mining cost estimates, and final pit shell limits such as more detailed exploration drilling or final pit slope angle.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;**12.1. Key Assumptions, Parameters, and Methods** 

To develop the estimate of Mineral Reserves, modifying factors were applied to Measured and Indicated Resources. Inferred Mineral Resources were not considered for Mineral Reserves. The following modifying factors were applied using key assumptions, parameters and methods to convert Mineral Resources to Proven and Probable Mineral Reserves.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;**12.1.1. Stripping Ratio and Pit Limits**

The maximum stripping ratio for Mineral Reserves was determined from analysis of historical and future costs compared to the estimated base sales price per MMBtu as defined in the LSA through April 1, 2032 as described in Section 19.0 of this TRS. The cost and price per MMBtu establish the maximum allowable cumulative stripping ratio limit of 14:1, which is averaged over the LOM plan. MLMC has historically found this stripping ratio to provide the necessary economic mining cost compared to selling price. The base price for the dedicated lignite is defined in the LSA with the estimated average price per ton of $36.06 for lignite delivered and sold over the LOM plan. All costs were escalated at various rates based on the forward-looking Consumer/Producer Price Index with budgeted 2022 costs used as the base year. The maximum allowable cumulative stripping ratio establishes the pit limits within the Mineral Resource pit shells.

Stripping ratios remain relatively consistent across the MS-002 and MS-004 permit areas with the exception of high stripping ratios along the east side of the MS-004 permit area which defines the eastern boundary of mining.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;**12.1.2.Lignite Quality**

Lignite that was unable to be blended to meet the quality specifications as outlined in the LSA (Table 11.1) was eliminated from consideration and not included in reserve estimates.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;**12.1.3.Modeled Mining Parameters** 

The geologic model used for estimation of Mineral Resources was modified to account for the minimum mining thickness of 1-foot and dilution parameters as described in Section 13.2 and Table 13.3 of this TRS. Additionally, seams with a parting thickness of less than 6-inches were composited.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;**12.1.4. Assumptions and Modifying Factors**

The following key assumptions, parameters and modifying factors were used by the QP to estimate the recoverable Proven and Probable Reserves contained within the LOM:

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• &nbsp;&nbsp;&nbsp;&nbsp;All recoverable lignite required to fulfill the contractual obligations of the LSA is contained within the LOM plan pit extents;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• &nbsp;&nbsp;&nbsp;&nbsp;Geological structure and quality model are as described in Section 11.0 of this TRS;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• &nbsp;&nbsp;&nbsp;&nbsp;Only Measured and Indicated Resources were included;

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SEC S-K 1300 Technical Report Summary

Mississippi Lignite Mining Company – Red Hills Mine&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;March 2023

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• &nbsp;&nbsp;&nbsp;&nbsp;Maximum cumulative stripping ratio 14:1 (averaged over LOM plan);

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• &nbsp;&nbsp;&nbsp;&nbsp;Mining production rates on a cubic yard and per ton basis remain relatively consistent with historical performance;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• &nbsp;&nbsp;&nbsp;&nbsp;Mining costs on a unit basis remain relatively consistent with historical performance;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• &nbsp;&nbsp;&nbsp;&nbsp;Depth of weathering (base of oxidation) as defined by Section 11.0 of this TRS;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• &nbsp;&nbsp;&nbsp;&nbsp;Minimum minable lignite thickness: 1.0 feet;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• &nbsp;&nbsp;&nbsp;&nbsp;Minimum parting thickness before seams are composited: 6.0 inches;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• &nbsp;&nbsp;&nbsp;&nbsp;Maximum depth of mining: approximately 320 feet;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• &nbsp;&nbsp;&nbsp;&nbsp;The Mineral Reserves fall within the Mineral Resource pit shells which have clearly defined physical constraints;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• &nbsp;&nbsp;&nbsp;&nbsp;Mining dilution parameters defined in Table 13.2 R-O-M Dilution Parameters;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• &nbsp;&nbsp;&nbsp;&nbsp;Lignite density defined by seam from coal core drilling data and modified by dilution parameters and approximately 80 lb/ft³;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• &nbsp;&nbsp;&nbsp;&nbsp;Recovery rates by seam as presented in Table 13.4;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• &nbsp;&nbsp;&nbsp;&nbsp;Quality limits as defined by the LSA and presented in Table 11.1 were applied after dilution has been accounted for, and;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• &nbsp;&nbsp;&nbsp;&nbsp;Forecasted annual power plant MMBtu requirements.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;**12.1.5. Method**

The RHPP provides a forecast of MMBtu requirements to MLMC on an annual basis. MLMC compares this forecast to historical plant requirements to develop a workplan of MMBtu demand for the LOM. The LOM plan assumes the RHPP will not continue to operate after the expiration of the current contract with CGLP on April 1, 2032.

To develop the LOM plan, modifying factors including minimum mining thickness, minimum parting thickness, and mining dilution parameters were applied to the geologic (Mineral Resource) model within Maptek Vulcan to create the Mineral Reserve model.

MLMC engineers then project mining pits within Maptek Vulcan. Projections were directed to the topography from the lowest mineable lignite seam. The mining pit width is 170' based on the current mining equipment operating parameters. The mining pit length varies based on mining pit limits. Highwalls are projected at 42-degrees. Endwalls are projected at 40-degrees with the allowance for a 150-foot wide bench to establish haul roads. Final pit extents were limited by a maximum cumulative stripping ratio of 14:1 (average over the LOM plan). Further justification of pit design parameters is provided in Section 13.0 of this TRS.

Once mining pits were projected, volumes, tonnages, and associated quality parameters were exported from Maptek Vulcan. The blocks were exported as volume for burden horizons and as tons for lignite horizons. The QP reviewed the exported quality for each lignite horizon block to ensure quality thresholds were met. Any lignite block that did not meet the minimum quality parameters was not considered a Mineral Reserve and the associated block was considered waste material (burden block). The exported data was then sequenced and the overburden blocks were then assigned to the appropriate mining fleet to perform the work. The first step in sequencing was to apply recovery rates to lignite tonnages by seam.

Once the above modifying factors were applied, the sequencing program allotted lignite tonnages and burden volumes to the four major operational fleets of truck and shovel, dozer push, dragline, and lignite load and haul by period based on the workplan MMBtu requirements. The sequencer creates an output of volumes by fleet, including rehandle volumes, and projected tonnages and qualities by period.

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SEC S-K 1300 Technical Report Summary

Mississippi Lignite Mining Company – Red Hills Mine&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;March 2023

This output then flowed through a series of steps to estimate equipment hours based on equipment production rates for each necessary piece of equipment. Calculations also included adjustments for:

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• &nbsp;&nbsp;&nbsp;&nbsp;Equipment mechanical, operational, and weather availabilities;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• &nbsp;&nbsp;&nbsp;&nbsp;Fleet capacity including limiting production factors;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• &nbsp;&nbsp;&nbsp;&nbsp;Variations in haulage routes;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• &nbsp;&nbsp;&nbsp;&nbsp;Assumptions for crew sizes and;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• &nbsp;&nbsp;&nbsp;&nbsp;New and/or retiring equipment.

The output of allotted volumes, lignite tonnages, quality, and equipment hours by period were the inputs for the Red Hills Mine financial model. These inputs flow through the financial model, which was developed and refined by MLMC based on actual performance, along with escalated inputs for cost estimates for labor, materials and supplies, fuel and other cost components to generate cost projections for the LOM plan. In addition to general operating costs, contemporaneous reclamation, royalties, mine closure, and capital projects were projected and escalated accordingly. It is the opinion of the QP that the final LOM plan and related projected MMBtu costs and forecasted pricing justify the selection of the maximum cumulative stripping ratio and supports the conversion of Measured and Indicated Mineral Resources to Mineral Reserves.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;**12.2. Mineral Reserve Estimates**

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;**12.2.1. Basis for Mineral Reserve Estimate**

This Item discloses the Mineral Reserve estimates for the Red Hills Mine based on the QP's detailed evaluation of the modifying factors as applied to indicated or measured mineral resources, which demonstrate economic viability of the Red Hills Mine property. The estimated Mineral Reserves are in accordance with the definitions of "Mineral Reserve" as described by the S-K 1300 regulations (17 CRF 229.1300) as:

"A coal reserve is the economically mineable part of a Measured or Indicated coal resource demonstrated by at least a Preliminary Feasibility Study, which includes information on mining, processing, economic and other relevant factors that demonstrate, at the time of reporting, that economic extraction can be justified."

Following definitions presented in 17 CFR 229.1300, and guidance from the Committee for Mineral Reserves International Reporting Standards (CRIRSCO), Mineral Reserves are divided into two categories as listed below and are ranked by increasing level of confidence.

Proven Mineral Reserve is the economically mineable part of a measured mineral resource and can only result from conversion of a measured mineral resource. A Proven Mineral Reserve implies a high degree of confidence in the Modifying Factors.

Probable Mineral Reserve is the economically mineable part of an indicated and, in some cases, a measured mineral resource. The confidence in the Modifying Factors applying to a Probable Mineral Reserve is lower than that applying to a Proven Mineral Reserve.

The reference point at which Mineral Reserves are defined, is the point of sale to the RHPP, which is after two 20k ton storage silos following the truck dump hopper.

This disclosure of Mineral Reserves is based upon the qualified person's opinion that the LOM plan has been completed to a PFS level of accuracy, as defined in 17 CFR Part 229.1300, which includes and supports the qualified person's determination of Mineral Reserves.

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SEC S-K 1300 Technical Report Summary

Mississippi Lignite Mining Company – Red Hills Mine&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;March 2023

The LOM plan included annual stripping and lignite production qualities and quantities. Annual production costs were estimated based on the mine plan quantities, surface mining methods, equipment fleets in use, and unit prices that have been proven by historical production at the Red Hills Mine. The current mining methods, used at the Red Hills Mine since inception, are planned to continue until enough lignite reserve is depleted to fulfill the contractual obligations of the LSA for fuel supply to the RHPP.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;**12.3. Cut-off Quality and Sales Price**

Cut-off quality and price were previously discussed in Section 12.1 under subsection Stripping Ratio and Pit Limits.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;**12.4. Mineral Reserve Statement**

Based on the LOM plan and modifying factors discussed above, the Red Hills Mine contains the economically minable Mineral Reserves listed in Table 12.1. The Mineral Reserves include approximately 25.4 Mt of ROM lignite, with an average calorific value of 5,100 Btu/lb, moisture content of 43.1 %wt., ash content of 15.0 %wt., and sulfur content of 0.6 %wt. The point of reference for Mineral Reserves is as delivered to the dump and RHPP silos as of December 31, 2022.

**Table 12.1** Mineral Reserve Estimates

---

| | | | | | | |
|:---|:---|:---|:---|:---|:---|:---|
| | | | **Quality** | **Quality** | **Quality** | **Quality** |
| **Red Hills Mine** | **Reserve Classification** | **Tonnage (Kt)** | **Calorific Value (Btu/lb)** | **Moisture (%wt)** | **Ash (%wt)** | **Sulfur (%wt)** |
| Mine Area 1 | Proven | 900 | 4980 | 43.5 | 15.8 | 0.6 |
| Mine Area 1 | Probable | 0 | 4710 | 42.0 | 20.5 | 0.6 |
| Mine Area 1 | Total | 900 | 4980 | 43.4 | 15.9 | 0.6 |
| Mine Area 3 | Proven | 16200 | 5100 | 43.4 | 14.8 | 0.6 |
| Mine Area 3 | Probable | 7400 | 5120 | 42.5 | 15.2 | 0.7 |
| Mine Area 3 | Total | 23600 | 5110 | 43.1 | 14.9 | 0.6 |
| Stockpile & Silos | Proven | 900 | 5080 | 43.2 | 15.4 | 0.5 |
| Total Reserves | Proven | 18000 | 5090 | 43.4 | 14.8 | 0.6 |
| Total Reserves | Probable | 7400 | 5120 | 42.6 | 15.4 | 0.7 |
| Total Reserves | Total | 25400 | 5100 | 43.1 | 15.0 | 0.6 |

---

Notes:

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;1.Mineral Reserves use an economic cut-off of a maximum cumulative stripping ratio of 14:1. There are some instances where the stripping ratio for a single year could exceed 14:1, but the average for the entire area evaluated is less than 14:1.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;2.Historical coal recovery rates at Red Hills Mine have been applied to generate the Mineral Reserve tonnages.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;3.Mineral Reserves are estimated using Vulcan Software.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;4.Tonnages and qualities have been rounded to an accuracy level deemed appropriate by the QP. Summation errors due to rounding may exist.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;**12.5.Multiple Commodity Mineral Reserve**

The Red Hills Mine is a single commodity Mineral Reserve.

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SEC S-K 1300 Technical Report Summary

Mississippi Lignite Mining Company – Red Hills Mine&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;March 2023

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;**12.6. QP's Opinion on Risk Factors that could Affect Mineral Reserve Estimates**

The Red Hills Mine began commercial deliveries in 2002. Since this is a well-established operation, the deposit, mining, and environmental aspects of the Project are very well understood. The knowledge for the Red Hills Mine is based on the collective experience of personnel from MLMC's site operations and technical disciplines gained since mine inception. This knowledge is supported by years of production data and observations at the Red Hills Mine.

The LOM plan included annual stripping and lignite production qualities and quantities. Production costs were estimated based on the mine plan quantities, surface mining methods, equipment fleets in use, and unit prices that have been proven by historical production at the Red Hills Mine. The current mining methods, used at the Red Hills Mine since inception, are planned to continue until enough of the lignite reserve is depleted to fulfill the contractual obligations of the LSA for fuel supply to the RHPP.

With this said, there are some risks that could materially affect Mineral Reserve estimates. Risks include changes in customer demand for any reason, including, but not limited to, dispatch of power generated by other energy sources ahead of coal, fluctuations in demand due to unanticipated weather conditions, regulations or comparable policies which could potentially promote planned and unplanned outages at the RHPP, economic conditions, including an economic slowdown that would affect manufacturing and a corresponding decline in the use of electricity, governmental regulations and/or inflationary adjustments. All of which could potentially have a material adverse effect on MLMC's financial condition.

Other risks include unforeseen changes in the LOM plan from additional exploration, changes in land control and new regulations that could delay future permit renewals or restrictions to physical mining boundaries.

At the time of this TRS, the QP is not aware of any specific factors that would currently materially affect the prospect of economic extraction.

Uncertainty in the Mineral Resource estimates was previously discussed in in subsection Uncertainty in the Mineral Resource Estimate in Section 11.5 of this TRS.

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SEC S-K 1300 Technical Report Summary

Mississippi Lignite Mining Company – Red Hills Mine&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;March 2023

**13. Mining Methods**

This section contains forward-looking information related to the mining methods for the Red Hills Mine. The material factors that could cause actual results to differ from the conclusions, estimates, designs, forecasts or projections include mine design parameters, production rates, equipment selection, and personnel requirements.

The Red Hills Mine began commercial deliveries in 2002. Since this is an established operation, the deposit, mining, and environmental aspects of the project are very well understood. The geological knowledge is based on the collective experience of personnel from MLMC operations, geology, engineering, environmental, and other disciplines gained during years of lignite mining at Red Hills Mine and other mining operations in the United States.

The lignite at Red Hills Mine surface mining operation is recovered using dragline, dozer push, and conventional truck and shovel mining methods due to the proximity of the lignite to the surface and the physical characteristics of the deposit. Mining operations progress in a five-step process, which includes clear and grub, overburden and interburden removal, lignite production, spoil backfill and grading, and reclamation. In the development phase, drainage and water control were established, and then the required infrastructure consisting of power, mine office and maintenance facilities, lignite stockpile facilities, and roadways were established.

The Red Hills Mine began operations in the MS-002 permit area in Mine Area 1 (MA1) and is in the process of transitioning to the MS-004 permit area in Mine Area 3 (MA3). The initial boxcut construction for MA3 began in 2021 and mining in this area will continue until April 1, 2032. Figure 13.1 presents the layout of the Red Hills Mine and identifies the total area to be affected over the mine.

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SEC S-K 1300 Technical Report Summary

Mississippi Lignite Mining Company – Red Hills Mine&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;March 2023

**Figure 13.1 Layout of the Red Hills Mine**

![image_20.jpg](image_20.jpg)

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SEC S-K 1300 Technical Report Summary

Mississippi Lignite Mining Company – Red Hills Mine&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;March 2023

&nbsp;&nbsp;&nbsp;&nbsp;**13.1. Geotechnical and Hydrological Considerations**

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;**13.1.1. Pit Design**

The initial geotechnical parameters for the design of the pit slopes was provided in the Geoscience Engineering report completed in 1997 and Aquaterra report completed in 1994 to define soil index properties and soil strength parameters as discussed previously in Section 7.4 of this TRS. The early geotechnical studies were the basis of the pit design which is fully detailed in the Red Hills Mine Ground Control Plan and summarized herein.

To determine highwall stability, a circular arc failure approach has been utilized. A minimum FoS of 1.2 was estimated using the Modified Bishop Method for each highwall configuration that will be encountered by the mine. Due to the depth and multiple seam nature of the lignite deposit, benching will be required to allow for continuous burden removal and lignite mining. For individual slopes less than 80 feet, the highwall angle is stable up to 70 degrees. Between 80 and 180 feet, the effective slope angle decreases with a linear relationship from 60 to 40 degrees as shown in Table 13.1.

**Table 13.1 Effective highwall angle by depth**

---

| | |
|:---|:---|
| **Depth (ft)** | **Effective Highwall Angle** |
| 80 to 110 | 60 degrees |
| 110 to 145 | 50 degrees |
| 145 to 180 | 40 degrees |

---

For slopes greater than 180 feet, benching is required. Figure 13.2 illustrates the combination of highwall slopes and safety benches that are used to meet the effective slopes outlined above. In general, the truck and shovel operating level is located 150 to 160 feet above the pit floor and naturally creates a bench with a minimum width of 150 feet. When benches and offsets are accounted for pits may range from 100 to 210 feet in width. Initial design assumes a 170-foot pit width.

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SEC S-K 1300 Technical Report Summary

Mississippi Lignite Mining Company – Red Hills Mine&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;March 2023

**Figure 13.2 Typical Pit Configuration for plan at steady state. (Mississippi Lignite Mining Company, 2019)**

![image_21.jpg](image_21.jpg)

Low wall or spoil side angles were based on the type of materials found throughout the mine area, an angle-of-repose of 33 degrees was recommended by geotechnical studies. MLMC's digging plan reduces the effective spoil angle to 33 degrees or less by allowing for an operating bench on the spoil side of the pit.

As a whole, Red Hills Mine pits are designed with an effective highwall angle of approximately 42 degrees, effective endwall angles of approximately 40 degrees, and effective low wall angles of 33 degrees or less.

Mining has been ongoing at the Red Hills Mine since 1998 and the design methodology for the pit slopes has been satisfactory as evidenced by each pit progression. Due to the stratigraphic nature of the Red Hills Mine geology, which is checked by regular drilling exploration programs ahead of mining, repetition of geologic units leads to consistency in applying geotechnical parameters.

NACoal and MLMC engineering have made minor adjustment to the pit design since 1998. However, these adjustments are primarily for optimization, to address new equipment specifications or additional ramps to reduce haul distances. Other adjustments include additional benching in the highwall where topography is higher or the depth to the C-seam increases to establish ramps and functional road systems. This additional benching also increases the FoS of the highwall by reducing the overall effective angle in these instances. Optimization of drainage is another factor that greatly influences the pit design.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;**13.1.2. Spoil Stability Studies** 

The bulk of geotechnical studies at the Red Hills Mine since 2004 pertain to spoil stability which influence operation plans for production and reclamation. Two types of spoil failures have been observed at the mine. The first type comprised of a rotational failure occurring at the toe of the dragline bench with radial cracks extending into the

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SEC S-K 1300 Technical Report Summary

Mississippi Lignite Mining Company – Red Hills Mine&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;March 2023

bench toward the spoil piles. The second bench failure type observed at the mine included heaving of the C-seam followed by a slump failure. There were several spoil studies performed using software packages developed by GEO-SLOPE International, and RocScience. Some of the pit slope analyses can be found in the report, titled "Design Report for Red Hills Mine Slope Stability Study" by Barr Engineering (Barr), 2014; "Red Hills Slope Stability Mitigation Test Plan" by Aquaterra, 2010; and "Red Hills Mine Slide Investigation" by Aquaterra, 2009.

**Figure 13.3 Soil Stability Assessment. (Barr Engineering, 2014)**

![image_22.jpg](image_22.jpg)

The report "Red Hills Slope Stability Mitigation Test Plan" by Aquaterra tried to determine changes in stresses and pore pressures during the mining operation. A 2-D coupled stress-pore pressure model was conducted using the Sigma/W application as developed by GEO-SLOPE International. The Sigma/W program provides a finite element mesh analysis stresses and deformations within the subsurface soils sing transient loads. An example of a slope stability analysis is presented in Figure 13.4.

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SEC S-K 1300 Technical Report Summary

Mississippi Lignite Mining Company – Red Hills Mine&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;March 2023

**Figure 13.4 Slope Stability Study (Aquaterra Engineering, LLC., 2010)**

![image_23.jpg](image_23.jpg)

To help remediate the potential rotational bench failures, the truck-shovel operation does not dump material within the first two spoil peaks from the active pit, and spoil piles are not to exceed 90-feet in height above the dragline bench height. Furthermore, extra attention is given to ensure water is not stored in spoil valleys for a prolonged period. In addition, the work area is inspected by shift supervisors and fleet leadmen for cracking, heaving, flowing groundwater, or any other abnormal conditions prior to starting work in an area, and following any precipitation or freeze/thaw event. The inspection requirements are specified as part of MLMC's safeguards under the Ground Control Plan. A certified person must document inspections of the work areas during each shift and after every rain, freeze, or thaw. Dragline operators and groundmen are continuously monitoring bench and spoil conditions as they dig.

Potential heaving of the C-seam followed by a slump failure was attributed to the ground water recharge and increased pore pressures due to seepage from three sand seams below the C-seam. These failures are described in depth in the Barr and Aquaterra reports. Based on these studies, earthquake drains, and dewatering well systems were implemented to address the increased head pressure from the lower aquifers. These systems were installed by registered drillers immediately following the severance of the C-seam. More details on these systems were provided in the "Red Hills Slope Stability Mitigation Test Plan" report. MLMC engineers continued to install earthquake

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SEC S-K 1300 Technical Report Summary

Mississippi Lignite Mining Company – Red Hills Mine&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;March 2023

drains for a few pits once the B-seam came back into existence. Once the earthquake drains were retired, MLMC then continued to monitor the pore pressures below the dragline bench as mining progressed with wireline piezometers for a few pits and noted no pressure changes. Although earthquake drains are not anticipated for the remainder of mining in the MS-002 permit area, they are anticipated for some future areas in the MS-004 permit area. This assumption is based on cross referencing sand thickness maps with the B-seam existence limits and projected pits. Pore pressures below bench grade will be monitored leading into this area of interest with the installation of wireline piezometers, followed by the installation of earthquake drains with the mining progression if deemed necessary by MLMC engineers.

A dewatering well system was installed annually ahead of mining from 2008 through 2014. As discussed in the hydrogeology portion of Section 7.3 of this TRS, the upper stratigraphic sands of the Wilcox sediments which are mined through are minor. The systems MLMC put into place were a recommendation from a geotechnical study with the idea that the groundwater flow, although minimal, was contributing to the saturation of the spoils contributing to spoil side failures. This system was discontinued as mining pits advanced and moved out of the area with the geological conditions that were producing these types of failures.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;**13.1.3. Excess Spoil Piles**

In addition to pit design and spoil stability, regulations governing the permanent placement of excess spoil require geotechnical studies to ensure stability of the placed material. In 1999, Pritchard Engineering, Inc. carried out the geotechnical investigation to gather soil index properties and soil strength properties which were then used as inputs by NACoal to perform a stability study under static and seismic conditions for the excess spoil piles in the MS-002 permit area. MLMC is in the process of constructing excess spoil piles for the MS-004 permit area. As mining operations continue in the MS-004 permit area, a geotechnical study of similar parameters will be conducted to assess the stability of the spoil piles in the MS-004 permit area. Due to the similarity of the pre-mine topography for the new excess spoil piles, similar soil characteristics/chemistry, the lateral extensiveness of the geology in the region, and furthermore an extended history of operating heavy equipment in various dump conditions, MLMC does not anticipate major changes to the mine plan from future geotechnical investigations of the excess spoil piles. Existing and proposed excess spoil pile locations are shown on Figure 13.1.

&nbsp;&nbsp;&nbsp;&nbsp;**13.2. Lignite Production Rate, Mine Life, Mining Dimensions and Dilution and Recovery Factors**

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;**13.2.1. Production Rate**

The Red Hills Mine was designed to supply approximately 2.6 to 3.2 million tons of lignite per year to the adjacent RHPP. Actual production is dictated by customer MMBtu demand. The details of the LOM plan are shown in Table 13.2.

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SEC S-K 1300 Technical Report Summary

Mississippi Lignite Mining Company – Red Hills Mine&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;March 2023

**Table 13.2 LOM Production Schedule**

---

| | | | | | | |
|:---|:---|:---|:---|:---|:---|:---|
| | **2023** | **2024** | **2025** | **2026** | **2027** | **2028** |
| Delivered Coal (000 tons) | 2900 | 2800 | 2700 | 2700 | 2800 | 2800 |
| Delivered MMBTU (000) | 30000 | 29000 | 27700 | 27700 | 27700 | 27700 |
| Calorific Value, Btu/lb | 5120 | 5110 | 5100 | 5090 | 5050 | 5040 |
| Total Overburden Material (000 CY) | 37200 | 32900 | 32800 | 35100 | 42000 | 41200 |
|  | **2029** | **2030** | **2031** | **2032** | **Total** |  |
| Delivered Coal (000 tons) | 2700 | 2700 | 2600 | 700 | **25400** |  |
| Delivered MMBTU (000) | 27700 | 27700 | 27700 | 6900 | **259800** |  |
| Calorific Value, Btu/lb | 5090 | 5180 | 5250 | 5260 | **5100** |  |
| Total Overburden Material (000 CY) | 47100 | 51800 | 51800 | 9300 | **381200** |  |

---

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;**13.2.2. Mine Life**

MLMC provides the lignite for the RHPP under a contract that runs until April 1, 2032.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;**13.2.3. Mining Dimensions**

Mining dimensions are discussed in Sections 13.1 and 13.3 of this TRS.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;**13.2.4. Haulroad Design**

Haul roads and spoil ramps are typically designed to a minimum width of 90 feet to allow for two-way traffic. In some circumstances, one-lane roads may be established with proper signage. Highwall ramps are designed to a width of 70 feet, and dragline walkways must be a minimum of 120 feet wide.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;**13.2.5. Mining Dilution** 

ROM tonnages at the Red Hills Mine meet the following conditions:

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• &nbsp;&nbsp;&nbsp;&nbsp;Minimum mining thickness: 1.0 ft;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• &nbsp;&nbsp;&nbsp;&nbsp;Maximum burden depth: approximately 320 feet;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• &nbsp;&nbsp;&nbsp;&nbsp;Average lignite density: approximately 80 lb/ft<sup>3</sup>

The base of weathering, which closely aligns with the depth of the BOX as described in Section 11.0 of this TRS may affect lignite recovery. Special considerations for lignite above this depth must be considered as it may have been partially oxidized and typically exhibits unacceptable quality characteristics for the power plant.

Mining dilution was initially determined from statistical analysis of coal core data collected from 1975 through 1997. During the 2011 drilling exploration program, roof and floor samples were collected and analyzed for each coal seam to verify dilution parameters used in modeling. The drilling data was compared to actual as-delivered quality data and confirmed that the original dilution parameters remained applicable. Dilution parameters are applied to all lignite seams and are listed in Table 13.3.

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SEC S-K 1300 Technical Report Summary

Mississippi Lignite Mining Company – Red Hills Mine&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;March 2023

**Table 13.3 ROM Dilution Parameters**

---

| | |
|:---|:---|
| **Structural (Roof and Floor)** | **Structural (Roof and Floor)** |
| Loss (ft) | 0.25 |
| Gain (ft) | 0.083 |
| **Quality (Roof and Floor)** | **Quality (Roof and Floor)** |
| Density (lb/ft<sup>3</sup>) | 85.4 |
| Calorific Value (Btu/lb) | 1859 |
| Moisture (%wt) | 26.48 |
| Ash (%wt) | 53.98 |
| Sulfur (%wt) | 0.26 |

---

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;**13.2.6. Recovery Factors**

Recovery rates of individual coal seams are presented in Table 13.4 and were determined from various comparisons between surveyed severed tons, haul truck payloads, delivered tons to RHPP, and modeled tons accounting for dilution and minimum mining thickness. The low recovery of C-seam is due to a 50-foot wide swath of lignite that is left in the pit to assist with stabilizing the spoil and dragline bench.

**Table 13.4 Recovery Rates by Seam**

---

| | |
|:---|:---|
| **Seam** | **Recovery Rate** |
| H | 72% |
| G | 84% |
| F | 97% |
| E | 90% |
| D | 100% |
| C | 67% |

---

&nbsp;&nbsp;&nbsp;&nbsp;**13.3. Requirements for Stripping and Backfilling**

The Red Hills Mine is a multiple lignite seam surface mining operation.

The primary burden removal units for a typical mining sequence at the Red Hills Mine include:

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• one 82-cubic yard electric-powered walking dragline;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• one 41-cubic yard electric rope shovel;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• a fleet of 150-ton and 200-ton end-dump haul trucks and;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• four large track-type push dozers.

Lignite is severed and loaded by a surface miner or hydraulic backhoe.

Figure 13.5 through Figure 13.7 illustrate typical pit layouts to show the mining process. Similar mining processes will be followed in both MA1 and MA3 for production and reclamation. Figures are not to scale.

First, the truck and shovel fleet remove overburden to an elevation which approximates the first minable lignite seam; usually this will be the H-seam. This overburden material is hauled to fill in the topography to final grade

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SEC S-K 1300 Technical Report Summary

Mississippi Lignite Mining Company – Red Hills Mine&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;March 2023

during the reclamation process. Truck and shovel operations may be required to remove other interburdens and rehandle material depending on sequencing/production and reclamation planning.

Following removal of the H-seam, the dozers push the interburden, which overlies the second G-seam, into the previously mined pit. This process is repeated through successive lignite seams until the accumulated interburden has reached a point where it is level across the pit. This typically occurs at or near the E-seam elevation.

Finally, the dragline sits spoil side on a bench primarily constructed from the material the dozers pushed and then removes both the D-seam and C-seam interburdens.

**Figure 13.5 Pit Layout - Truck and shovel operation. (Mississippi Lignite Mining Company, 2019)**

![image_24.jpg](image_24.jpg)

**Figure 13.6 Pit Layout - Dozer operation. (Mississippi Lignite Mining Company, 2019)**

![image_25.jpg](image_25.jpg)

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SEC S-K 1300 Technical Report Summary

Mississippi Lignite Mining Company – Red Hills Mine&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;March 2023

**Figure 13.7 Pit Layout - Dragline operation. (Mississippi Lignite Mining Company, 2019)**

![image_26.jpg](image_26.jpg)

Rough backfilling and grading of reclamation are accomplished using dozers as the haul trucks dump material between the dragline spoils. Hydraulic backhoes may be used to rehandle spoil material that exceeds final grade. In accordance with the mine permit requirements, a minimum of 4 feet of suitable plant growth material (SPGM), or red oxidized soil that meets textural parameters, must be placed on top of the gray unoxidized material in the dump unless otherwise approved. MLMC follows an approved final grading plan using a "balanced acreage" approach in that the same reclaimed areas must be brought up to grade within 29-months of lignite removal. This plan is approved for both permitted areas.

In MA1, mining progresses through three to four pits per year. Due to a shorter pit length in MA3, MLMC anticipates mining five to seven pits per year.

&nbsp;&nbsp;&nbsp;&nbsp;**13.4. Major Equipment and Personnel**

A list of major and auxiliary equipment used at the Red Hills Mine is presented in Table 13.5. The equipment at the Red Hills Mine is well maintained, in good physical condition and is either updated or replaced periodically with newer models to maintain reliability and to keep up with technological advancements.

As equipment wears out, MLMC evaluates what replacement option will be the most cost-efficient, including the evaluation of both new and used equipment.

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SEC S-K 1300 Technical Report Summary

Mississippi Lignite Mining Company – Red Hills Mine&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;March 2023

**Table 13.5 Major and primary auxiliary equipment list**

---

| | | | |
|:---|:---|:---|:---|
| **Unit(s)** | **Equipment** | **Approximate Production Rates** | **Major Fleet** |
| 1 | Marion 8200 Dragline | 3200 yd3 per hour | Dragline |
| 1 | P&H 2800 Electric Rope Shovel | 2100 yd3 per hour | Truck and Shovel (T-S) |
| 1 | Wirtgen 4200 Surface-miner | 2000 tons per hour | Lignite |
| 1 | CAT 6040 Hydraulic Backhoe | 1800 yd3 per hour | T-S/Lignite Support |
| 1 | CAT 6040 Hydraulic Shovel | 1800 yd3 per hour | T-S Support |
| 1 | CAT 5230 Hydraulic Shovel | 1400 yd3 per hour | Lignite |
| 1 | Komatsu PC2000 Hydraulic Backhoe | 1200 yd3 per hour | T-S/Lignite Support |
| 4 | CAT D-11 Tractors | 850 yd3 per hour | Dozer Push |
| 5 | CAT D-10 Tractors |  | Dragline/Dump Support |
| 1 | CAT D-8 LGP Tractor |  | Auxiliary Support |
| 3 | CAT D-6 LGP Tractor |  | Ash Placement |
| 1 | CAT 844 Rubber Tire Tractor |  | T-S Support |
| 12 | CAT 789 A, B, C, & D End-Dump Trucks | 200-ton payload | T-S and Lignite Haul |
| 4 | CAT 785 A & B End-Dump Trucks | 150-ton payload | T-S and Lignite Haul |
| 3 | CAT 773 Side-Dump Ash Train | 140-ton payload | Ash Placement |
| 2 | CAT 24 Class Motor Grader |  | Road/Reclamation Grading |
| 2 | CAT 16 Class Motor Grader |  | Road/Reclamation Grading |
| 1 | 21,000 Gallon CAT 777 Water Truck |  | Dust Suppression |
| 1 | 32,000 Gallon CAT 785 Water Truck |  | Dust Suppression |
| 3 | 3-5 yd3 CAT Backhoes |  | Auxiliary Support |
| 4 | 40 Tons CAT ADT trucks | 40-ton payload | Auxiliary Support |

---

At normal operating levels, the Red Hills Mine on average employs +/-200 personnel (**Table 13.6**)**.**

**Table 13.6 MLMC Personnel**

---

| | | | |
|:---|:---|:---|:---|
| **STAFF** | **STAFF** | **WORKFORCE** | **WORKFORCE** |
| Full Time | 39 | Production | 99 |
| Interns/Co-ops | 1 or 2 | Maintenance | 56 |
| | | Warehouse | 5 |
| | | Temporary | Varies |

---

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SEC S-K 1300 Technical Report Summary

Mississippi Lignite Mining Company – Red Hills Mine&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;March 2023

**14. Processing and Recovery Methods**

The overall average quality of the mined lignite seams meets the quality specifications stated in the LSA without beneficiation. No mineral processing is performed by MLMC.

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SEC S-K 1300 Technical Report Summary

Mississippi Lignite Mining Company – Red Hills Mine&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;March 2023

**15. Infrastructure**

The Red Hills Mine public utility lines and facilities locations are presented in **Figure 15.1** showing the mine infrastructure and details of the mine facilities.

MLMC purchases power from 4-County Electric Power Association, a cooperative of the TVA. A 69kV line runs parallel to the TVA 500kV line from the Highway 9 Right-of-Way (R-O-W) to the mine office substation. This line then continues past the office to feed the RP-27-1 transformer and the Pump Building transformer.

A second 69kV line runs north along the west R-O-W of Highway 9 to feed the dragline substation currently in use. This dragline substation will be used for the remainder of the MS-002 permit area, and the entire MS-004 permit area. MLMC anticipates a permit to bore under Highway 9 to feed dragline cable to the east side of the highway in 2023.

Water for the mine office facilities is supplied by the Reform Water Association via a 6-inch line which runs along the R-O-W of McIntire Road. A registered groundwater well sourced from the Lower Wilcox aquifer feeds the equipment wash bay, boot wash, irrigation, and fire hydrants.

The Red Hills Mine has a sanitary waste treatment plant with a permitted NPDES outfall. This is an active sludge treatment plant. Onsite sedimentation ponds are permitted for Beneficial Water Use and serve as the water source for dust suppression

There are no leach pads or tailings ponds at the Red Hills Mine. Lignite is mined and transported to a stockpile or to the customer's hopper. Public roads are not used for the transport of lignite to the RHPP. Mine site haul routes are depicted in Figure 13.1 and Figure 15.1. To transport lignite from the MS-004 permit area to Stockpile B or the customer's hopper, an overpass for Highway 9 traffic has been constructed northeast of the Hopper. Mine traffic generally travels below the Highway 9 traffic via an underpass. A secondary haul route will be available via the dragline deadhead road. This is an at-grade crossing approximately 1,300 feet southeast of the overpass/underpass. The highway department must be notified in advance to detour traffic around this at-grade crossing; therefore, this crossing will only be used to mobilize large equipment or emergency use.

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SEC S-K 1300 Technical Report Summary

Mississippi Lignite Mining Company – Red Hills Mine&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;March 2023

**Figure 15.1 Red Hills Mine Facilities Map**

![image_27.jpg](image_27.jpg)

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SEC S-K 1300 Technical Report Summary

Mississippi Lignite Mining Company – Red Hills Mine&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;March 2023

**16. Market Studies**

This section contains forward-looking information related to the market studies for the Red Hills Mine. The material factors that could cause actual results to differ from the conclusions, estimates, designs, forecasts or projections include plant dispatch rate, plant availability rate, fuel pricing, and other commodity pricing.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;**16.1. Markets**

The primary market for the Red Hills Mine lignite is the adjacent RHPP for which the mine was developed. The Red Hills Mine is a mine-mouth operation where the lignite is delivered directly to the power plant. The Red Hills Mine is a high moisture, low calorific value fuel, which precludes transporting the lignite as a viable option to expand market share, thus no known marketing studies have been conducted for the Red Hills Mine. The LOM plan assumes the RHPP will not continue to operate after the expiration of the current LSA with CGLP and the expiration of the existing PPA between TVA and CGLP in April 2032. The Red Hills Mine is expected to begin final reclamation in April 2032. NACoal and MLMC have made efforts to identify specialty niche markets for the lignite with limited success.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;**16.2. Material Contracts**

Red Hills Mine is a fully developed and functioning mining operation. All aspects of the mining, haulage and delivery of lignite to the RHPP are defined in the LSA between CGLP and MLMC. The RHPP supplies electricity to the TVA under a long-term PPA. CGLP leases the RHPP from a Southern Company subsidiary pursuant to a leveraged lease arrangement. The LOM plan assumes the RHPP will not continue to operate after the expiration of the current LSA with CGLP and the expiration of the existing PPA between TVA and CGLP in April 2032.

Red Hills Mine is an active operation and all material contracts are in place for the continued operation of the mine. The Red Hills Mine is a mine-mouth project where the lignite is delivered directly to the power plant using off highway haul trucks.

The base price for the dedicated lignite is defined in the LSA and consists of eight indexed components in addition to a power cost component, a pass-through component, a royalty component and a fixed component. The base price in the LOM plan is evaluated on an annual basis and is determined based on the actual performance of the 8 indexed components specified in the LSA. Over the LOM plan, the average price per ton for lignite delivered and sold is $36.06 providing revenues totaling approximately $914 M. The Red Hills Mine began commercial deliveries in 2001. The sales price over the last three years has averaged $28 as shown in Table 16.1. The forecasted coal price for the LOM is also shown in Table 16.1.

**Table 16.1 Historical and Forecasted Coal Price** 

---

| | | | | | | | | | | | |
|:---|:---|:---|:---|:---|:---|:---|:---|:---|:---|:---|:---|
| Historical | 2013 | 2014 | 2015 | 2016 | 2017 | 2018 | 2019 | 2020 | 2021 | 2022 | Total\* |
| Tons Sold (000 ton) | 3200 | 2600 | 3200 | 3000 | 2400 | 3000 | 2600 | 2500 | 3000 | 3200 | 28700 |
| Coal Price $/Ton | 20.61 | 21.61 | 22.61 | 23.61 | 24.61 | 25.61 | 26.61 | 27.61 | 27.20 | 29.66 | 28.16 |
| Forecasted | 2023 | 2024 | 2025 | 2026 | 2027 | 2028 | 2029 | 2030 | 2031 | 2032 | Total |
| Tons Sold (000 ton) | 2900 | 2800 | 2700 | 2700 | 2800 | 2800 | 2700 | 2700 | 2600 | 700 | 25400 |
| Coal Price $/Ton | 29.65 | 32.95 | 34.64 | 33.60 | 36.78 | 37.06 | 38.29 | 39.80 | 40.00 | 45.37 | 36.06 |

---

\*Average Coal Price $/Ton is from 2020-2022.

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SEC S-K 1300 Technical Report Summary

Mississippi Lignite Mining Company – Red Hills Mine&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;March 2023

**17. Environmental Studies, Permitting, and Plans, Negotiations, or Agreements with Local Individuals or Groups**

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;**17.1. Environmental and Baseline Studies**

In July, 1998, a final Environmental Impact Statement (EIS) was issued for the Red Hills Power Project. The impacts of the Red Hills Mine were considered during this process. This EIS evaluated anticipated impacts associated with mining at the Red Hills Mine. The EIS evaluated project impacts to the following resources:

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• &nbsp;&nbsp;&nbsp;&nbsp;Air Resources

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• &nbsp;&nbsp;&nbsp;&nbsp;Geology

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• &nbsp;&nbsp;&nbsp;&nbsp;Soils

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• &nbsp;&nbsp;&nbsp;&nbsp;Groundwater Resources

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• &nbsp;&nbsp;&nbsp;&nbsp;Surface Water Resources

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• &nbsp;&nbsp;&nbsp;&nbsp;Aquatic Ecology

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• &nbsp;&nbsp;&nbsp;&nbsp;Streams and Wetlands

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• &nbsp;&nbsp;&nbsp;&nbsp;Terrestrial Ecology

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• &nbsp;&nbsp;&nbsp;&nbsp;Threatened and Endangered Species

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• &nbsp;&nbsp;&nbsp;&nbsp;Land Use

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• &nbsp;&nbsp;&nbsp;&nbsp;Cultural and Historical Resources

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• &nbsp;&nbsp;&nbsp;&nbsp;Socioeconomics

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• &nbsp;&nbsp;&nbsp;&nbsp;Environmental Justice

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• &nbsp;&nbsp;&nbsp;&nbsp;Transportation Facilities

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• &nbsp;&nbsp;&nbsp;&nbsp;Public Health

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• &nbsp;&nbsp;&nbsp;&nbsp;Hazardous and Solid Waste

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• &nbsp;&nbsp;&nbsp;&nbsp;Noise

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• &nbsp;&nbsp;&nbsp;&nbsp;Recreation

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• &nbsp;&nbsp;&nbsp;&nbsp;Visual Resources

The EIS evaluated these areas individually for the action and no action alternatives as well as cumulative impacts for past, present and proposed actions. A Record of Decision (ROD) was issued August 8, 1998 by the TVA that detailed the decision to build the Red Hills Mine. The EIS encompasses all areas within the currently approved Surface Mine Control and Reclamation Act (SMCRA) permits.

The results of the geological baseline studies are detailed in Section 6.0 of this report. Additionally, the results of the surface and groundwater baseline studies and geotechnical studies are documented in Sections 7.3 and 7.4, respectively. In addition, the Red Hills Mine completed baseline assessments of the area soils, prime farmlands, land uses, biological resources, threatened and endangered species, and cultural resources which were used to support the mining permits continuously issued by the Mississippi Department of Environmental Quality (MDEQ) since 1998.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;**17.2. Waste Disposal, Site Monitoring and Water Management** 

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;**17.2.1. Waste Disposal**

No processing of lignite occurs at the Red Hills Mine; therefore, no lignite processing or tailing wastes have been or will be generated.

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SEC S-K 1300 Technical Report Summary

Mississippi Lignite Mining Company – Red Hills Mine&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;March 2023

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;**17.2.2. Site Monitoring**

The Red Hills Mine is required to conduct routine groundwater, surface water and soil sampling in accordance with SMCRA and NPDES permit requirements. Surface and groundwater monitoring occur both within the active mine area as well as in adjacent, undisturbed areas upstream and downstream of the active mining operations. Red Hills Mine also conducts routine soil sampling to ensure the reclaimed environment meets regulatory chemical and textural requirements. The water and soil data are submitted to MDEQ in accordance with permit requirements.

Red Hills Mine will continue to monitor surface water, groundwater, and soils in accordance with all permit requirements until such time mining and reclamation activities are complete and MDEQ has released the entire project from the reclamation performance bond requirements. This release can only happen once Red Hills Mine has quantitatively demonstrated that the reclaimed areas meet performance criteria detailed in the mining permit. Once the reclamation performance bond is released, the Red Hills Mine will have no further site monitoring requirements.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;**17.2.3. Water Management** 

Because rainfall averages more than 55 inches per year, water management is a critical focus at the Red Hills Mine. Prior to initiating mining activities, streams that would otherwise flow through the active mine area are typically rerouted around the perimeter of the mine. This allows the natural hydrologic balance to be maintained except for stormwater that falls within the footprint of the active mine area. Red Hills manages stormwater by constructing large, strategically located sedimentation ponds. The sedimentation ponds are constructed in accordance with permit requirements to retain a 10-year, 24-hour storm event. Once the retained water meets NPDES water quality requirements, the water is released back into the natural system. The results of the NPDES monitoring are reported monthly to MDEQ through the eDMR system.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;**17.3. Project Permitting Requirements**

The Red Hills Mine is operating under the state of Mississippi Surface Coal Mining and Reclamation Permits MS-002, Renewal 3 and MS-004. The permits were issued by the Mississippi Department of Environmental Quality (MDEQ) under delegated authority of the United States Department of the Interior, Office of Surface Mining Reclamation Enforcement (OSMRE) under the Surface Mining Control and Reclamation Act (SMCRA).

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;**17.3.1. Permit Status**

In addition to the mining permits, the Red Hills Mine is required to obtain and maintain numerous other regulatory permits and approvals (**Table 17.1**).

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SEC S-K 1300 Technical Report Summary

Mississippi Lignite Mining Company – Red Hills Mine&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;March 2023

**Table 17.1 Red Hills Mine Permit Summary and Status**

---

| | | | |
|:---|:---|:---|:---|
| **Type of Permit** | **Name and Address of Issuing Authority** | **Identification Number** | **Status** |
| &nbsp;&nbsp;State Coal Exploration | &nbsp;&nbsp;Department of Environmental Quality | &nbsp;&nbsp;NA | &nbsp;&nbsp;Issued 08/15/00 |
| &nbsp;&nbsp;License | &nbsp;&nbsp;Office of Geology |  |  |
|  | &nbsp;&nbsp;P. O. Box 20307 |  |  |
|  | &nbsp;&nbsp;Jackson, Mississippi 39289-1307 |  |  |
| &nbsp;&nbsp;State Coal Mining Permit | &nbsp;&nbsp;Department of Environmental Quality | &nbsp;&nbsp;MS-002 Renewal 3 | &nbsp;&nbsp;Issued 02/13/18 |
|  | &nbsp;&nbsp;Office of Geology | &nbsp;&nbsp;MS-004 | &nbsp;&nbsp;Issued 02/11/20 |
|  | &nbsp;&nbsp;P.O. Box 20307 |  |  |
|  | &nbsp;&nbsp;Jackson, Mississippi 39289-1307 |  |  |
| &nbsp;&nbsp;Mine Identification No. | &nbsp;&nbsp;Mine Safety and Health Administration | &nbsp;&nbsp;No. 22-00690 | &nbsp;&nbsp;Issued 08/26/97 |
|  | &nbsp;&nbsp;U. S. Department of Labor |  |  |
|  | &nbsp;&nbsp;District II |  |  |
|  | &nbsp;&nbsp;135 Gemini Circle, Suite 213 |  |  |
|  | &nbsp;&nbsp;Birmingham, Alabama 35209 |  |  |
| &nbsp;&nbsp;State of Mississippi | &nbsp;&nbsp;Department of Environmental Quality | &nbsp;&nbsp;No. MS0054046 | &nbsp;&nbsp;Modified 02/11/20 |
| &nbsp;&nbsp;Water Pollution Control | &nbsp;&nbsp;Office of Pollution Control | &nbsp;&nbsp;No. MSR108199 | &nbsp;&nbsp;Issued 06/15/20 |
| &nbsp;&nbsp;Permit (includes Mining | &nbsp;&nbsp;P. O. Box 10385 |  |  |
| &nbsp;&nbsp;Stormwater Pollution | &nbsp;&nbsp;Jackson, Mississippi 39289-0385 |  |  |
| &nbsp;&nbsp;Prevention Plan) | &nbsp;&nbsp;Issuing Authority: Mississippi Environmental Quality Permit Board |  |  |
| &nbsp;&nbsp;Section 404 Permit | &nbsp;&nbsp;Vicksburg District | &nbsp;&nbsp;No. MVK-2017-257 | &nbsp;&nbsp;Issued 3/28/18 |
|  | &nbsp;&nbsp;P. O. Box 60 |  | &nbsp;&nbsp;Modified 7/11/18 |
|  | &nbsp;&nbsp;Vicksburg, MS 39180-0060 | &nbsp;&nbsp;No. MVK-2016-509 | &nbsp;&nbsp;Issued 12/21/20 |
| &nbsp;&nbsp;Section 401 State Water | &nbsp;&nbsp;Department of Environmental Quality | &nbsp;&nbsp;NA | &nbsp;&nbsp;Issued by the |
| &nbsp;&nbsp;Quality Certification | &nbsp;&nbsp;Office of Pollution Control |  | &nbsp;&nbsp;Commission for |
|  | &nbsp;&nbsp;P. O. Box 10385 |  | &nbsp;&nbsp;USACE |
|  | &nbsp;&nbsp;Jackson, Mississippi 39289-0385 |  |  |
|  | &nbsp;&nbsp;Issuing Authority: Mississippi Environmental Quality Permit Board |  |  |
| &nbsp;&nbsp;Exclusion for Rubbish | &nbsp;&nbsp;Department of Environmental Quality | &nbsp;&nbsp;NA | &nbsp;&nbsp;Issued 08/25/98 |
| &nbsp;&nbsp;Disposal Activities | &nbsp;&nbsp;Office of Pollution Control |  |  |
|  | &nbsp;&nbsp;P. O. Box 10385 |  |  |
|  | &nbsp;&nbsp;Jackson, Mississippi 39289-0385 |  |  |
| &nbsp;&nbsp;Mississippi Conditionally | &nbsp;&nbsp;Department of Environmental Quality | &nbsp;&nbsp;MSR000005330 | &nbsp;&nbsp;Issued 3/17/99 |
| &nbsp;&nbsp;Exempt Small Quantity | &nbsp;&nbsp;Office of Pollution Control |  |  |
| &nbsp;&nbsp;Generator | &nbsp;&nbsp;P. O. Box 10385 |  |  |
|  | &nbsp;&nbsp;Jackson, Mississippi 39289-0385 |  |  |
| &nbsp;&nbsp;Spill Prevention Control and | &nbsp;&nbsp;USEPA, Region IV and | &nbsp;&nbsp;NA | &nbsp;&nbsp;Revised 6/11/18 |
| &nbsp;&nbsp;Countermeasure Plan | &nbsp;&nbsp;Department of Environmental Quality |  |  |
|  | &nbsp;&nbsp;Office of Pollution Control |  |  |
|  | &nbsp;&nbsp;P. O. Box 10385 |  |  |
|  | &nbsp;&nbsp;Jackson, Mississippi 39289-0385 |  |  |

---

------

SEC S-K 1300 Technical Report Summary

Mississippi Lignite Mining Company – Red Hills Mine&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;March 2023

---

| | | | |
|:---|:---|:---|:---|
| &nbsp;&nbsp;Dragline Boom | &nbsp;&nbsp;U.S. Department of Transportation | &nbsp;&nbsp;NA | &nbsp;&nbsp;Exemption Request |
| &nbsp;&nbsp;Height | &nbsp;&nbsp;FAA |  | &nbsp;&nbsp;Approved 3/3/98 |
|  | &nbsp;&nbsp;2300 East Devon Avenue |  |  |
|  | &nbsp;&nbsp;Des Plains, Illinois 60018 |  |  |
| &nbsp;&nbsp;Radio Station Authorization | &nbsp;&nbsp;Federal Communications Commission | &nbsp;&nbsp;NA | &nbsp;&nbsp;Issued 10/21/2015 |
|  | &nbsp;&nbsp;Wireless Telecommunications Bureau |  |  |
| &nbsp;&nbsp;Water Withdrawal Permit | &nbsp;&nbsp;Department of Environmental Quality | &nbsp;&nbsp;No. MS-GW-15160 | &nbsp;&nbsp;Well (Issued 8/25/98) |
| &nbsp;&nbsp;for Beneficial Uses | &nbsp;&nbsp;Office of Land and Water Resources | &nbsp;&nbsp;No. MS-GW-15254 | &nbsp;&nbsp;Well (Re-issued 07/16/2018) |
| &nbsp;&nbsp;for Public Water of the | &nbsp;&nbsp;P. O. Box 10385 | &nbsp;&nbsp;No. MS-SW-02755 | &nbsp;&nbsp;R-1 (Re-issued 05/12/2008) |
| &nbsp;&nbsp;State of Mississippi | &nbsp;&nbsp;Jackson, Mississippi 39289-0385 | &nbsp;&nbsp;No. MS-SW-02791 | &nbsp;&nbsp;P-4-1 (Re-issued 05/12/2008) |
|  |  | &nbsp;&nbsp;No. MS-SW-10088 | &nbsp;&nbsp;RP-33-1 (Issued 4/20/2009) |
|  |  | &nbsp;&nbsp;No. MS-SW-10104 | &nbsp;&nbsp;P-29-2 (Issued 6/22/2009) |
|  |  | &nbsp;&nbsp;No. MS-SW-10150 | &nbsp;&nbsp;RP-27-1 (Issued 8/23/2010) |
|  |  | &nbsp;&nbsp;No. MS-SW-10530 | &nbsp;&nbsp;SP-8 (Issued 5/4/2020) |
| &nbsp;&nbsp;Beneficial Use | &nbsp;&nbsp;Department of Environmental Quality | &nbsp;&nbsp;BUD 0015 | &nbsp;&nbsp;Issued 12/14/06 |
| &nbsp;&nbsp;Determination (BUD) | &nbsp;&nbsp;Office of Pollution Control | &nbsp;&nbsp;BUD 0099 | &nbsp;&nbsp;Issued 05/04/21 |
|  | &nbsp;&nbsp;P.O. Box 10385 |  |  |
|  | &nbsp;&nbsp;Jackson, Mississippi 39289-0631 |  |  |
| &nbsp;&nbsp;Handheld XRF Analyzer | &nbsp;&nbsp;Mississippi State Department of Health | &nbsp;&nbsp;No. X-326 | &nbsp;&nbsp;Issued 09/08/20 |
| &nbsp;&nbsp;Analytical X-Ray | &nbsp;&nbsp;Division of Radiology |  |  |
|  | &nbsp;&nbsp;3150 Lawson Street |  |  |
|  | &nbsp;&nbsp;Jackson, Mississippi 39213 |  |  |
| &nbsp;&nbsp;Work within TVA Transmission | &nbsp;&nbsp;TVA Transmission R-O-W Team | &nbsp;&nbsp;NA | &nbsp;&nbsp;Issued 03/23/20 |
| &nbsp;&nbsp;Right-of-Way | &nbsp;&nbsp;Tennessee Valley Authority |  |  |
|  | &nbsp;&nbsp;400 West Summit Hill Drive |  |  |
|  | &nbsp;&nbsp;Knoxville, TN 37902 |  |  |
| &nbsp;&nbsp;Road Closures, Relocations | &nbsp;&nbsp;The Choctaw County Board | &nbsp;&nbsp;Prewitt Road | &nbsp;&nbsp;Issued 08/01/2011 |
| &nbsp;&nbsp;and operations within 100' | &nbsp;&nbsp;of Supervisors | &nbsp;&nbsp;State HWY 415 | &nbsp;&nbsp;Issued 03/22/04 |
| &nbsp;&nbsp;of Outside Right of Ways | &nbsp;&nbsp;P. O. Box 250 | &nbsp;&nbsp;State HWY 415 | &nbsp;&nbsp;Issued 03/26/04 |
|  | &nbsp;&nbsp;Ackerman, Mississippi 39734 | &nbsp;&nbsp;East Clear Springs Rd. | &nbsp;&nbsp;Issued 03/22/04 |
|  |  | &nbsp;&nbsp;East Clear Springs Rd. | &nbsp;&nbsp;Issued 6/8/2009 |
|  |  | &nbsp;&nbsp;East Clear Springs Rd. | &nbsp;&nbsp;Issued 2012 |
|  |  | &nbsp;&nbsp;McIntire Road | &nbsp;&nbsp;Issued 10/02/05 |
|  |  | &nbsp;&nbsp;McIntire Road | &nbsp;&nbsp;Issued 2012 |
|  |  | &nbsp;&nbsp;McIntire Road | &nbsp;&nbsp;Issued 2013 |
|  |  | &nbsp;&nbsp;Nebo Road | &nbsp;&nbsp;Issued 03/17/03 |
|  |  | &nbsp;&nbsp;Nebo Road | &nbsp;&nbsp;Issued 2013 |
|  |  | &nbsp;&nbsp;Null Road | &nbsp;&nbsp;Issued 10/02/05 |
|  |  | &nbsp;&nbsp;Null Road | &nbsp;&nbsp;Issued 2013 |

---

------

SEC S-K 1300 Technical Report Summary

Mississippi Lignite Mining Company – Red Hills Mine&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;March 2023

---

| | | |
|:---|:---|:---|
| | &nbsp;&nbsp;Salem-Bywy Road | &nbsp;&nbsp;Issued 03/22/04 |
| | &nbsp;&nbsp;Salem-Bywy Road | &nbsp;&nbsp;Issued 05/24/04 |
| | &nbsp;&nbsp;Salem-Bywy Road | &nbsp;&nbsp;Issued 08/30/04 |
| | &nbsp;&nbsp;Salem-Bywy Road | &nbsp;&nbsp;Issued 04/03/06 |
| | &nbsp;&nbsp;Salem-Bywy Road | &nbsp;&nbsp;Issued 2013 |
|  | &nbsp;&nbsp;Salem-Bywy Road | &nbsp;&nbsp;Issued 2015 |
| &nbsp;&nbsp;MDOT | &nbsp;&nbsp;State HWY 415 | &nbsp;&nbsp;Issued 03/26/04 |
| &nbsp;&nbsp;Post Office Box 2060 | &nbsp;&nbsp;State HWY 9 | &nbsp;&nbsp;Issued 02/21/20 |
| &nbsp;&nbsp;Tupelo, Mississippi 38803-2060 | &nbsp;&nbsp;State HWY 9 | &nbsp;&nbsp;Issued 08/25/21 |

---

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;**17.3.2. Reclamation Bond Requirements**

MDEQ regulations require the Red Hills Mine post a reclamation performance bond that would allow MDEQ to affect final reclamation of the project in the unlikely event the Red Hills Mine goes out of business. Bonding is estimated based on a worst-case scenario. The amount of the financial security as of December 31, 2022 is $74 M.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;**17.4. Plans, Negotiations, or Agreements with Local Individuals or Groups** 

The Red Hills Mine has secured agreements with all third parties that are necessary to conduct mining operations in accordance with applicable law.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;**17.5. Mine Closure Plans**

Following the expiration of the LSA, the mine will be required to complete final remediation in accordance with the detailed plans in the approved mining permit. Final reclamation and closure activities will begin in the original permit area in 2023 as active mining in this area phases out. Closure activities will continue throughout the mine life, with the projected completion of the expanded permit area in 2045. Financial assurance for the ultimate reclamation of facilities is documented in the reclamation plan, and security for costs that will be incurred to execute site closure is provided by a third-party insurer to the State of Mississippi in the form of a surety bond.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;**17.6. QP's Opinion of Adequacy of Current Plans**

MLMC currently has all permits in place for the Red Hills Mine to operate and adhere to a mine plan projected to April 1, 2032. Barring any regulatory changes out of MLMC's control, the QP does not anticipate hurdles for approval of future renewal applications. The QP bases this opinion on the mine's history to meet regulatory requirements. Proper monitoring is ongoing in accordance with permit requirements. Furthermore, appropriate bonding and closure plans are in place.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;**17.7. Description of any Commitments to Ensure Local Procurement and Hiring**

Purchasing strives to place orders with regards to dependability and service records of the supplier, the nature of the guaranty and warranty of the product, its price, and quality. Preference is given to suppliers who are developing new and improved products or equipment, or designing and developing a special product, specifically for the Red Hills Mine. Consideration is also provided to local suppliers near the Red Hills Mine. Suppliers must have a reputation of adhering to specifications and delivery schedules.

Positions at the Red Hills Mine are posted with Mississippi Department of Employment Security for priority availability to all veterans and other job seekers. MLMC also participates with regional state job fairs, recruits on local college campuses, and participates in local community sponsored activities.

------

SEC S-K 1300 Technical Report Summary

Mississippi Lignite Mining Company – Red Hills Mine&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;March 2023

**18. Capital and Operating Costs**

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;**18.1. Operating Costs**

Annual operating costs were estimated in conjunction with the mining methods discussed in Section 13.0. LOM operating costs for a plan delivering approximately 27.7 million MMBtu to the RHPP are expected to total approximately $907 M from January 2023 through the end of reclamation in 2045 are summarized in Table 18.1.

All costs were estimated to a PFS level of study based on historical costs and performance measures that have been maintained by MLMC since its inception. These costs are reviewed and updated on an annual basis to account for changes in site conditions or the operating plan. This information was then used to estimate the projected future costs included in the LOM plan from January 2023 through the expiration of the LSA in April 2032. All costs were escalated at various rates based on the forward-looking Consumer/Producer Price Index with budgeted 2022 costs used as the base year.

Operating costs included major cost categories for mine development, burden removal, severing of lignite, reclamation, maintenance and handling of stockpiled lignite and delivery to the adjacent RHPP along with the necessary maintenance required to keep all equipment operating safely and efficiently. Direct costs were categorized as expenses directly related to the severing and delivery of lignite. All other general business expenses were categorized as indirect costs. Direct costs included production, maintenance, and staff labor, materials and supplies, fuel, equipment repairs, outside contractors, administration, production taxes and royalties, depletion, depreciation, and amortization (DD&A), inventory adjustments, interest expense, income taxes, and accretion on asset retirement obligations (ARO). Accretion costs are estimated by taking the escalated cash flows of the ARO liability over time and discounting it to its present value as required under U.S. GAAP.

**Table 18.1 LOM Operating Costs to deliver approximately 27.7 million MMBtu per year**

---

| | |
|:---|:---|
| **Operating Cost** | **Cost (M$)** |
| Direct Cost of Sales | $589.62 |
| Indirect Cost of Sales | $317.49 |
| Operating Cost | $907.11 |

---

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;**18.2.Capital Costs**

Capital Costs were estimated to a PFS level of study based on vendor quotes, historical land purchases, mine development costs, mitigation costs and other costs. Capital costs to fulfil the LSA for a LOM plan delivering approximately 27.7 million MMBtu per year to the RHPP are expected to total approximately $31 M from January 2023 through the end of the LSA in April 2032 and are summarized in Table 18.2. Consistent with operating costs, all capital costs were escalated at various rates based on the forward-looking Customer/Producer Price Index using 2022 as the base year. There are risks regarding the estimated capital costs including escalating costs of raw materials, equipment availability or supply chain gaps.

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SEC S-K 1300 Technical Report Summary

Mississippi Lignite Mining Company – Red Hills Mine&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;March 2023

**Table 18.2 LOM Capital Costs to deliver approximately 27.7 million MMBtu per year**

---

| | |
|:---|:---|
| **Capital Cost** | **Cost (M$)** |
| Equipment Expenditures | $15.5 |
| Development | $3.6 |
| Wetlands | $6.3 |
| Reserve/Land Acquisition | $5.5 |
| Capital Cost | $30.9 |

---

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SEC S-K 1300 Technical Report Summary

Mississippi Lignite Mining Company – Red Hills Mine&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;March 2023

**19. Economic Analysis**

This section contains forward-looking information related to the economic analysis for the Red Hills Mine. The material factors that could cause actual results to differ from the conclusions, estimates, designs, forecasts or projections include estimates of mineral resources and reserves, mine production plans, labor and salary rates, mine closure cost, plant dispatch rate, plant availability rate, fuel and other commodity pricing, and royalty, production, or income tax rates.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;**19.1. Key Assumptions, Parameters and Methods**

The primary key assumption to determine the economic viability of the Red Hills Mine was the annual operating performance of the RHPP. The forecasted operating performance of RHPP was determined using two main inputs: the annual projection notice (nomination for MMBtu requirements) received from the RHPP based on projected customer requirements and a comparison to prior years actual delivered lignite fuel to develop the expectation for future MMBtu requirements. The estimated annual MMBtu requirement used in the Red Hills LOM Model was approximately 27.7 million MMBtu. This resulted in a production schedule of approximately 2.7 Mt of dedicated lignite per year and was assumed to continue for the full LSA contract term, expiring in April 2032.

The base price for the dedicated lignite is defined in the LSA. This base price consists of eight indexed components in addition to a power cost component, a pass-through component, a royalty component and a fixed component. Over the LOM, the average estimated sales price per ton for lignite delivered and sold is $36.06 providing revenues totaling approximately $914 M.

Key assumptions and methods used to determine the capital and operating costs associated with the production schedule were detailed previously in Section 18.0 Capital and Operating Costs of this TRS.

Additional key assumptions include:

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• &nbsp;&nbsp;&nbsp;&nbsp;The LOM production plan was based primarily on surface mining methods including a truck and shovel, dozer push and dragline operations;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• &nbsp;&nbsp;&nbsp;&nbsp;Total number of employees per year was approximately 200, but varies by year depending on the forecasted overburden to be moved and the dispatch of the RHPP. Also included are temporary employees on an as needed basis;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• &nbsp;&nbsp;&nbsp;&nbsp;Diesel price was estimated to be $3.07 per gallon at the beginning of 2023. This price was escalated based on NY Harbor ULSD Futures for 2023 and 2024. After 2024 a flat 2% escalation was assumed. This projected diesel costs to reach $3.39 per gallon by 2032;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• &nbsp;&nbsp;&nbsp;&nbsp;Revenue $/MMBtu was escalated using the eight indexed components defined in the LSA;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• &nbsp;&nbsp;&nbsp;&nbsp;The economic analysis period of the Red Hills Mine LOM plan was the remaining production operation from January 1, 2023 until April 1, 2032 plus 13 years of post-mining reclamation;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• &nbsp;&nbsp;&nbsp;&nbsp;$0.064/ton sold Reclamation Fee assessed on delivered tons;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• &nbsp;&nbsp;&nbsp;&nbsp;Discount rate of 10% was used to account for cost of capital and;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• 12% estimated effective income tax rate. The effective income tax rate of 12% differs from the U.S. federal statutory rate primarily due to the benefit from percentage depletion. The benefit of percentage depletion is not directly related to the amount of pre-tax income recorded in a period.

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SEC S-K 1300 Technical Report Summary

Mississippi Lignite Mining Company – Red Hills Mine&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;March 2023

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;**19.2. Annual Cash Flows**

The Income Statement and Annual Cash Flows based on the lignite production schedule for the LOM plan, along with the Net Present Value are detailed in Table 19.1. A Discount Rate of 10% was used as this was consistent with the Red Hills Mine's weighted average cost of capital. The calculation of Net Present Value and Internal Rate of Return are nuanced due to the ongoing nature of this mining operation. As modeled, the cash flows for the period 2023 through 2045 indicate the project is cash flow positive over the remaining life of the project.

In the opinion of the QP, the income statement and cash flow projection based on the LOM plan assumptions as shown in Table 19.1 are reasonable in light of historical trends, current conditions and expected future developments. As modeled, the future cash flow projection is estimated to be approximately $121 M and the net present value is estimated to be approximately $73 M after tax.

Note that the net present value estimated for this report does not consider previous cash inflows and outflows and is only estimated from 2023 through the remainder of the LOM.

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SEC S-K 1300 Technical Report Summary

Mississippi Lignite Mining Company – Red Hills Mine&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;March 2023

**Table 19.1 Summary of Income Statement and Cash Flow for LOM plan delivering approximately 27.7 million MMBtu**

![image.jpg](image.jpg)

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SEC S-K 1300 Technical Report Summary

Mississippi Lignite Mining Company – Red Hills Mine&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;March 2023

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;**19.3. Sensitivity Analysis**

Additional LOM scenarios were modeled to analyze the effect of changes in key assumptions. The most significant affect was an increase in the annual MMBtu requirement. A 10% upside case with an increased annual MMBtu requirement by the RHPP to 30,438,145 MMBtu was considered. This scenario is well within the operating capacity of the RHPP, and results in an average increase in cash flows of $2 M on an annual basis. If this increase were to continue for the life of the project a portion of the resources in Mine Area 2 would have to be evaluated and used as reserves to supply the demand. Significant risk from a downside case, where the RHPP takes less than the LOM plan MMBtu's, is protected by a minimum annual take provision included in the LSA.

Other key assumptions considered were the effects of an increase in diesel prices and labor. Any increase in the cost of labor or diesel fuel has an offsetting effect in revenue due to the labor and diesel indices used to calculate revenue also increasing. Therefor the any additional costs incurred by increased labor and diesel pricing is offset by the adjusted revenue calculation. Ultimately the main factor affecting profitability at MLMC is customer demand.

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SEC S-K 1300 Technical Report Summary

Mississippi Lignite Mining Company – Red Hills Mine&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;March 2023

**20. Adjacent Properties**

There are no other properties adjacent to the Red Hills Mine. There is no information used in this TRS that has been sourced from adjacent properties. No public drilling information was available or sourced for the development of the geological model.

The drilling and exploration activities at the Red Hills Mine well defines the lignite geology, Mineral Resource estimates and Mineral Reserve estimates. Due to this and the relatively simple geology at the Red Hills Mine, material changes to the Mineral Resource estimates and Mineral Reserve estimates are not likely if adjacent property information is included in future estimates.

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SEC S-K 1300 Technical Report Summary

Mississippi Lignite Mining Company – Red Hills Mine&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;March 2023

**21. Other Relevant Data and Information**

In the QPs opinion, all material information has been stated in the above sections of this TRS.

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SEC S-K 1300 Technical Report Summary

Mississippi Lignite Mining Company – Red Hills Mine&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;March 2023

**22. Interpretations and Conclusions**

**22.1. Mineral Resources**

In the QP's opinion, the geological data, sampling, modeling, and estimate are carried out in a manner that both represents the data well and mitigates the likelihood of material misrepresentations for the statements of Mineral Resources. There are currently no recommendations for Mineral Resources.

**22.2. Mineral Reserves** 

In the QP's opinion, the operational and mine planning data, LOM Plan, and estimation are carried out in a manner that both represents the data and operational experience and methodology well and mitigates the likelihood of material misrepresentations for the statements of Mineral Reserves. There are currently no recommendations for Mineral Reserves.

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SEC S-K 1300 Technical Report Summary

Mississippi Lignite Mining Company – Red Hills Mine&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;March 2023

**23. Recommendations**

**23.1. Mineral Resources**

The QP has the following recommendations for additional work:

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• Additional coal coring should be performed in Mine Area 3 to better define upper seams qualities while potentially expanding and upgrading mineral resources and reserves.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• Develop a coal standard, blank insertion, and secondary laboratory splitting and testing QA/QC program.

**23.2. Mineral Reserves** 

The QP has no recommendations for additional work.

Current work plans that are budgeted in the discounted cash flows (DCF) that the Red Hills Mine will complete include:

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• &nbsp;&nbsp;&nbsp;&nbsp;Continue with exploration drilling program;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• &nbsp;&nbsp;&nbsp;&nbsp;Monitor pit pore pressures in future in pit areas identified of potential concern;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• &nbsp;&nbsp;&nbsp;&nbsp;Continue to evaluate used equipment to reduce capital costs;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• &nbsp;&nbsp;&nbsp;&nbsp;Continue the current practice and reconciliation of actual to budget lignite recoveries, qualities and costs;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• &nbsp;&nbsp;&nbsp;&nbsp;Update the LOM plan and economic analyses accordingly.

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SEC S-K 1300 Technical Report Summary

Mississippi Lignite Mining Company – Red Hills Mine&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;March 2023

**24. References** 

Aquaterra Engineering, LLC. (2004, October 27). Geotechnical Investigation.

Aquaterra Engineering, LLC. (2009, April 15). Red Hills Mine Slide Investigation.

Aquaterra Engineering, LLC. (2010, April 15). Red Hills Slope Stability Mitigation Test Plan.

Barr Engineering. (2014, March). Design Report for Red Hills Mine Slope Stability Study.

Burns Cooley Dennis, Inc. (1997, June 23). Preliminary Geotechnical Investigation.

*Climate in Ackerman, Mississippi*. (2021, June 6). Retrieved from Best Places: https://www.bestplaces.net/climate/city/mississippi/ackerman

CRIRSCO. (2019, November). The International Reporting Template.

Dicken, C. L., Nicholson, S. W., Horton, J. D., Foose, M. P., & Mueller, J. A. (2005). Integrated Geologic Map Databases for the United States: Mississippi. *U.S. Geological Survey Open File Report 2005-1323*. Reston, VA: U.S. Geological Survey .

FEIS. (1998). Final Environmental Impact Statement . Tennessee Valley Authority.

Geoscience Engineering, LLC. (1997, August 27). Geotechnical Data Report Res Hills Lignite Mine.

Mississippi Lignite Mining Company. (2019, August 19). Red Hills Mine Ground Control Plan.

NACoal. (2020, November 30). 2020 Lignite Coal Quality Round Robin.

Pritchard Engineering, I., & NACoal. (1999, November 5). Stability of Excess Spoil Piles at the Red Hills Mine.

Tittle, D. (2013). *Getting the Coal Out*. NACCO Industries.

U.S. Department of the Interior. (1989). Methods for Sampling and Inorganic Analysis of Coal. *U.S. Geological Survey Bulletin 1823.*

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SEC S-K 1300 Technical Report Summary

Mississippi Lignite Mining Company – Red Hills Mine&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;March 2023

**25. Reliance on Information Provided by the Registrant**

At time of signing, the QPs for this report are employees of the registrant, and all information was sourced from the registrant or studies commissioned by the registrant.

## Exhibit 99.1

**Exhibit 99.1**

![haasimage.jpg](haasimage.jpg)

------

APPRAISAL OF CERTAIN

OIL AND NATURAL GAS INTERESTS OWNED BY

CATAPULT MINERAL PARTNERS

A NAACO INDUSTRIES, INC. COMPANY

LOCATED IN

VARIOUS COUNTIES IN ALABAMA, LOUISIANA, NEW MEXICO, OHIO, PENNSYLVANIA, TEXAS, AND WYOMING

AS OF JANUARY 1, 2023

PREPARED FOR CATAPULT MINERAL PARTNERS

Haas Petroleum Engineering Services, Inc. F-0002950

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp; <u>/s/Franklin W. Stagg, P.E.</u>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;

Franklin W. Stagg, P.E. &nbsp;&nbsp;&nbsp;&nbsp;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp; March 6, 2023&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;

------

![haasimage.jpg](haasimage.jpg)

750 N. St. Paul Street

&nbsp;&nbsp;&nbsp;&nbsp;Suite 1750

&nbsp;&nbsp;&nbsp;&nbsp;Dallas, Texas 75201

&nbsp;&nbsp;&nbsp;&nbsp;Phone (214) 754-7090

March 6, 2023

Mr. Brian Larson

Catapult Mineral Partners, LLC.

A NACCO Natural Resources Company

5340 Legacy Drive, Suite 300

Plano, TX 75024

Mr. Larson:

As requested, Haas Petroleum Engineering Services, Inc. (hereinafter referred to as "Haas Engineering") has prepared an estimate of certain hydrocarbon Proved Reserves owned by Catapult Mineral Partners, LLC. (hereinafter referred to as "Catapult"), a wholly owned subsidiary of NACCO Industries, Inc. ("NACCO"). The properties evaluated in this report are primarily located in Alabama, Louisiana, New Mexico, Ohio, Pennsylvania, Texas, and Wyoming. This estimate of Reserves was completed on or about the above date of this letter. This report was prepared for NACCO's inclusion as an exhibit in their filing with the United States Securities and Exchange Commission ("SEC"), and it is our understanding that it contains approximately 100 percent of Catapult's Proved Reserves. With the exception of the exclusion of future income taxes, this evaluation conforms to the FASB Accounting Standards Codification Topic

932, Extractive Industries - Oil and Gas. It is Haas Engineering's opinion that the assumptions, data,

methods, and procedures used in the preparation of this report are appropriate for this purpose.

Production data was generally available through June 30, 2022, with many properties updated through November 30, 2022. As of January 01, 2023, Catapult's net Reserves, future net income ("FNI"), and net present worth discounted at 10 percent per annum ("NPV") have been estimated to be as follows:

![a2022haasreport-table1.jpg](a2022haasreport-table1.jpg)

FNI is after deducting estimated operating and future development costs, severance and ad valorem taxes, but before Federal income taxes. Total net Proved Reserves are defined as those natural gas and hydrocarbon liquid Reserves to Catapult interests after deducting all royalties, overriding royalties, and reversionary interests owned by outside parties that become effective upon payout of specified monetary balances. All Reserves estimates have been prepared using standard engineering practices generally accepted by the petroleum industry and conform to guidelines developed and adopted by the SEC. All hydrocarbon liquid Reserves are expressed in United States barrels ("bbl") of 42 gallons.

------

Natural gas Reserves are expressed in thousand standard cubic feet ("Mcf") at the contractual pressure and temperature bases and include shrinkage adjustment related to field and plant losses.

**<u>RESERVES ESTIMATE METHODOLOGY</u>**

The Reserves estimates contained in this report have been prepared using standard engineering practices generally accepted by the petroleum industry. Decline curve analysis was used to estimate the remaining Reserves of pressure depletion reservoirs with enough historical production data to establish decline trends. Reservoirs under non-pressure depletion drive mechanisms and non-producing Reserves were estimated by volumetric analysis, research of analogous reservoirs, or a combination of both. Reserves in this report have been estimated using deterministic and probabilistic methods. The appropriate methodology was used, as deemed necessary, to estimate Reserves in conformance with SEC regulations. The maximum remaining Reserves life assigned to wells included in this report is 50 years. This report does not include any gas sales imbalances.

**<u>RESERVES CLASSIFICATION</u>**

The Reserves estimates contained in this report conform to guidelines specified by the SEC. For more information regarding Reserves classification definitions see Appendix A. A complete discussion of the Reserves classification definitions can be found on the United States Government Printing Office website (<u>www.gpo.gov</u>).

As Catapult is a mineral and royalty company, there is some uncertainty in the timing of future completions and development. Haas Engineering has used professional judgment in forecasting such timing. For the purposes of this report, completed, non-producing and drilled, and uncompleted wells have been classified as Proved Behind Pipe, and locations with an active permit have been classified as Proved Undeveloped.

**<u>COMMODITY PRICES</u>**

Pursuant to SEC guidelines, the cash flow projections in this report utilize the unweighted 12 month arithmetic average of the first-day-of month benchmark prices for January through December 2022. The benchmark price for natural gas is taken to be the price received at Henry Hub and the benchmark price for hydrocarbon liquids is taken to be the price received for West Texas Intermediate ("WTI") crude oil at the Cushing, OK sales point.

The unweighted arithmetic average cash market price for natural gas delivered at Henry Hub during this time period is $6.36 per MMBTU. The Henry Hub price was held constant throughout the life of the wells and is adjusted for BTU content and basis differentials resulting in a weighted average net price of $6.17 per Mcf.

The unweighted arithmetic average cash market price for WTI crude oil sold at Cushing, OK during this time period is $93.67 per bbl. For natural gas liquids ("NGL"), the WTI crude oil price was held constant throughout the life of the wells and is adjusted for BTU content and basis differentials, resulting in a weighted average net price of $39.95 per bbl. For crude oil, the WTI crude oil price was held constant throughout the life of the wells and is adjusted for crude quality, BS&W, purchaser bonuses and basis differentials, resulting in a weighted average net price of $93.02 per bbl.

Fees associated with gathering, marketing, processing, and transportation were applied as expenses in this report.

Catapult Mineral Partners, LLC \| March 6, 2023\| Page 2 of 5

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Revenue accounting data for the period of July 1, 2021 to June 30, 2022 was used in this evaluation.

**<u>OPERATING EXPENSES</u>**

As Catapult is a mineral and royalty company, it is not burdened by operating expenses and capital costs. Therefore, Asset Retirement Obligations ("ARO") have not been included in this evaluation. The lease operating costs used in this evaluation have been included to truncate the commercial life of the property and were estimated based on knowledge of analogous wells producing under similar conditions. The lease operating expenses in this report represent field level operating costs.

Operating expenses and capital costs were not escalated in this evaluation.

**<u>DISCLAIMERS</u>**

The Proved Reserves presented in this report are estimates only and should not be construed as being exact quantities. They may or may not be actually recovered; and, if recovered, the revenues therefrom and the actual costs related thereto could be more or less than the estimated amounts. Because of governmental policies and uncertainties of supply and demand, the product prices and the costs incurred in recovering these Reserves may vary from the price and cost assumptions in this report. Because these estimates are based on existing governmental regulations, changes could affect the ability to recover these Reserves. In any case, quantities of Reserves may increase or decrease as a result of future operations.

Reserves estimates for individual properties included in this report are only valid when considered within the context of the overall report and should not be considered independently. The future net income and net present value estimates contained in this report do not represent an estimate of fair market value.

All information pertaining to the operating expenses, prices, and the interests of Catapult in the properties appraised has been accepted as represented. It was not considered necessary to make a field examination of the appraised properties. Data used in performing this appraisal were obtained from Catapult, public sources, and our own files. Supporting work papers pertinent to the appraisal are retained in our files and are available to you or designated parties at your convenience.

It was beyond the scope of this Haas Engineering report to evaluate the potential environmental liability costs from the operation and abandonment of these properties. In addition, no evaluation was made to determine the degree of operator compliance with current environmental rules, regulations, and reporting requirements. Therefore, no estimate of the potential economic liability, if any, from environmental concerns is included in the forecasts presented herein.

Nothing contained in this report is intended to create or confer, or shall be construed as having created or conferred, any rights in any third party, and all claims, rights, remedies, and obligations of Haas Engineering or Catapult, as the case may be, in connection with this report shall accrue or apply solely to Haas Engineering or Catapult. For all purposes of this paragraph, the term "third party" means any party other than Catapult or Haas Engineering, including without limitation Catapult's owners, prospective investors, lenders or prospective lenders, partners or prospective partners, and vendors or other service providers. Without the express written consent of Haas Engineering, only Catapult is entitled to rely on this report and any information, conclusions, and/or opinions contained herein.

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Haas Engineering is independent with respect to Catapult, as provided in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers.

The technical persons primarily responsible for conducting this Report meets the requirements regarding qualifications, independence, objectivity, and confidentiality, as defined by the SPE Standards. Franklin Stagg, a Licensed Professional Engineer in the State of Texas, has been practicing consulting petroleum engineering at Haas Engineering since 2016 and has over 7 years of industry experience.

**<u>GENERAL INFORMATION</u>**

Attached are summary tables of economic analysis of predicted future performance. Other tables identify the properties appraised with summary Reserves and the economic factors applicable to each. A list of tables is included.

We appreciate this opportunity to have been of service and hope that this report will fulfill your requirements.

*[Remainder of page intentionally left blank. Signature page follows.]*

Catapult Mineral Partners, LLC \| March 6, 2023\| Page 4 of 5

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Respectfully submitted,

Haas Petroleum Engineering Services, Inc. F-0002950

<u>/s/Franklin W. Stagg, P.E.</u>&nbsp;&nbsp;&nbsp;&nbsp;

Franklin W. Stagg, P.E. March 6, 2023

Catapult Mineral Partners, LLC \| March 6, 2023\| Page 5 of 5

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Appendix

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**Appendix A**

**Definitions of Oil and Gas Reserves - Securities and Exchange Commission**

**The list of definitions below were compiled by HPESI. They represent selected definitions from the Securities and Exchange Commission's Rule 4-10 document. This document was amended on January 14, 2009, and the definitions below reflect the changes resulting from the amendment. Comprehensive versions of Rule 4-10 and the amendments to Rule 4-10 can be obtained online at <u>http://www.gpoaccess.gov/</u> .**

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(a) **Definitions.** The following definitions apply to the terms listed below as they are used in this section:

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(1)&nbsp;&nbsp;&nbsp;&nbsp;*Developed oil and gas reserves.* Developed oil and gas reserves are reserves of any category that can be expected to be recovered:

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(i)&nbsp;&nbsp;&nbsp;&nbsp;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

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(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.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(2)&nbsp;&nbsp;&nbsp;&nbsp;*Possible reserves.* Possible reserves are those additional reserves that are less certain to be recovered than probable reserves.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(i)&nbsp;&nbsp;&nbsp;&nbsp;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.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(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.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(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.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(iv)&nbsp;&nbsp;&nbsp;&nbsp;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.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(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.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(vi)&nbsp;&nbsp;&nbsp;&nbsp;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.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(3)&nbsp;&nbsp;&nbsp;&nbsp;*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.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(i)&nbsp;&nbsp;&nbsp;&nbsp;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.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(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.

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**Appendix A**

**Definitions of Oil and Gas Reserves - Securities and Exchange Commission**

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(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.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(iv) See also guidelines in paragraphs (a)(17)(iv) and (a)(17)(vi) of this section.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(4)&nbsp;&nbsp;&nbsp;&nbsp;*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.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(i) The area of the reservoir considered as proved includes:

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(A) The area identified by drilling and limited by fluid contacts, if any, and

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(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.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(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.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(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.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(iv)&nbsp;&nbsp;&nbsp;&nbsp;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:

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(A)&nbsp;&nbsp;&nbsp;&nbsp;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

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(B) The project has been approved for development by all necessary parties and entities, including governmental entities.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(v)&nbsp;&nbsp;&nbsp;&nbsp;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.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(5)&nbsp;&nbsp;&nbsp;&nbsp;*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.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(6)&nbsp;&nbsp;&nbsp;&nbsp;*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.

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**Appendix A**

**Definitions of Oil and Gas Reserves - Securities and Exchange Commission**

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(7)&nbsp;&nbsp;&nbsp;&nbsp;*Reserves.* Reserves are estimated remaining quantities of oil and gas and related substances &nbsp;&nbsp;&nbsp;&nbsp;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).

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(8)&nbsp;&nbsp;&nbsp;&nbsp;*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.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(i)&nbsp;&nbsp;&nbsp;&nbsp;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.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(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.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(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.

**<u>-SEE NACCO'S EXHIBIT 99.2 - SUPPLEMENTAL FIGURES ATTACHMENT</u>**

## Exhibit 99.2

![](exhibit992-202210xk001.jpg)

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;LIST OF ECONOMIC TABLES Table No. Summary Economic Analysis Cash Flow Total Proved ........................................................................................................................ 2 Proved Developed Producing .............................................................................................. 3 Proved Developed Behind Pipe ........................................................................................... 4 Proved Undeveloped ........................................................................................................... 5 Tabular Summary of Economic Analysis All Reserves Categories ...................................................................................................... 6 Gross Ultimate Reserves, Cumulative Production and Basic Economic Data All Reserves Categories ....................................................................................................... 7

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![](exhibit992-202210xk002.jpg)

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Cash Flow Summaries

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![](exhibit992-202210xk003.jpg)

Total Year Oil ------ Mbbl Residue Gas ------ MMcf ------ NGL ------- Mbbl ------- Oil ------- Mbbl ------- Gas ----- MMcf----- ------ Net Reserves Volume -------------- Estimated 8/8 Prod. ------- NGL - $/bbl - Oil - $/bbl - Production and Economic Projection As of: 1/1/2023 Wells Res. Gas - $/Mcf - ---------- Plant Net Sales Volume Wet Gas ------ MMcf TABLE 2 30,149.97 50.67 6,000.94 230,335.13 57.34 39.92 6.13 93.102023 1,232 6,170.46 28,419.09 51.82 5,149.36 207,253.37 48.41 40.06 6.07 93.042024 1,265 5,303.13 20,292.42 34.09 3,083.45 151,076.38 38.27 40.02 6.13 93.052025 1,287 3,195.89 17,408.01 26.88 2,082.86 122,254.86 31.55 40.05 6.16 93.022026 1,296 2,171.82 12,455.66 20.10 1,548.81 96,867.65 26.09 39.98 6.19 93.002027 1,288 1,620.65 9,901.69 16.24 1,220.68 80,120.93 22.09 39.94 6.21 92.992028 1,279 1,280.70 8,242.46 13.62 992.86 67,839.13 18.97 39.91 6.22 92.982029 1,274 1,044.04 7,084.97 11.75 830.93 58,780.27 16.56 39.90 6.23 92.982030 1,266 875.47 6,208.54 10.32 709.13 51,712.54 14.62 39.88 6.24 92.972031 1,261 748.40 5,532.48 9.20 615.89 46,165.22 13.06 39.87 6.24 92.972032 1,253 650.96 4,957.49 8.25 536.65 41,360.77 11.69 39.86 6.25 92.972033 1,250 568.06 4,492.39 7.48 475.48 37,466.80 10.56 39.85 6.25 92.982034 1,241 503.88 4,088.90 6.81 424.48 34,104.22 9.58 39.85 6.25 92.982035 1,230 450.27 3,750.62 6.25 382.41 31,261.81 8.75 39.85 6.26 92.982036 1,220 405.99 3,431.96 5.71 343.89 28,573.68 7.98 39.85 6.26 92.982037 1,214 365.41 36,095.37After 309,738.56 59.10 3,294.77 83.80 Total 406,593.39 3,698,985.77Ult. 202,512.01 1,594,911.33 338.28 419.31 27,692.56 Cum. Sub-T 39.95 6.17 93.02 39.91 6.27 93.00 166,416.64 1,285,172.76 279.19 335.51 24,397.80 93.03 39.96 6.15 0.00% Lease Shrinkage and 4.11% Plant Shrinkage 2,104,074.45 204,081.37 28,878.15 3,523.01 25,355.14 Gas ------ M$ ------ Oil ------ M$ ------ Other ------ M$ ------ Year ----------------------------------- Company Future Gross Revenue ---------------------------------- NGL ------ M$ ------ Total ------ M$ ------ Prod Tax ------ M$ ------ Adv Tax ------ M$ ------ after Sev & Adv ------- M$ -------- ------- Prod & Adv Taxes ----- Revenue 4,717.11 2,289.16 36,805.35 0.00 43,811.62 1,007.91 1,623.72 41,180.002023 4,821.86 1,939.42 31,273.82 0.00 38,035.09 1,013.18 1,146.07 35,875.852024 3,172.04 1,531.54 18,888.56 0.00 23,592.13 615.44 840.12 22,136.582025 2,500.89 1,263.62 12,839.70 0.00 16,604.21 429.04 655.70 15,519.472026 1,868.94 1,043.01 9,587.62 0.00 12,499.56 317.57 526.47 11,655.522027 1,510.19 882.37 7,577.74 0.00 9,970.31 251.78 436.80 9,281.732028 1,266.12 757.12 6,175.91 0.00 8,199.15 206.95 368.61 7,623.602029 1,092.23 660.64 5,176.60 0.00 6,929.46 175.31 317.11 6,437.052030 959.12 582.99 4,422.79 0.00 5,964.90 151.29 276.48 5,537.132031 855.81 520.51 3,844.66 0.00 5,220.99 132.94 244.28 4,843.772032 767.16 465.80 3,352.01 0.00 4,584.97 117.54 215.78 4,251.652033 695.37 420.71 2,971.66 0.00 4,087.73 105.25 193.46 3,789.022034 633.10 381.82 2,654.45 0.00 3,669.37 94.86 174.45 3,400.062035 580.78 348.80 2,392.47 0.00 3,322.05 86.13 158.58 3,077.342036 531.10 318.08 2,152.12 0.00 3,001.30 78.05 143.69 2,779.572037 5,496.11 20,648.86After Total 31,467.93 16,749.62 170,764.30 0.00 0.00 3,344.02 Sub-T 218,981.85 29,488.99 5,568.00 784.77 8,746.05 1,424.75 204,667.79 27,279.47 25,971.81 13,405.60 150,115.44 0.00 189,492.85 4,783.23 7,321.30 177,388.32 Cumulative ------- M$ ------- Annual ------ M$ ------ Disc. Cum. Annual @ 10.00% ------- M$ ------- -------------------- Future Net Income Before Income Taxes ------------------------------------------------------- Deductions Trans. Costs ------ M$ ------ Net Investments ------ M$ ------ Lease Net Costs ------ M$ ------ Net Profits ------ M$ ------ Undiscounted Discounted Ann @ 10.00% -------M$ ------- Year 2023 0.00 0.00 5,060.10 0.00 36,119.90 34,418.94 34,418.94 36,119.90 2024 0.00 0.00 4,005.41 0.00 31,870.44 27,717.54 62,136.48 67,990.33 2025 0.00 0.00 2,637.07 0.00 19,499.51 15,422.03 77,558.51 87,489.84 2026 0.00 0.00 1,921.13 0.00 13,598.34 9,768.41 87,326.92 101,088.18 2027 0.00 0.00 1,494.80 0.00 10,160.72 6,632.50 93,959.42 111,248.89 2028 0.00 0.00 1,214.44 0.00 8,067.29 4,785.24 98,744.66 119,316.19 2029 0.00 0.00 1,009.38 0.00 6,614.22 3,565.60 102,310.26 125,930.41 2030 0.00 0.00 858.43 0.00 5,578.62 2,733.65 105,043.91 131,509.03 2031 0.00 0.00 741.40 0.00 4,795.73 2,136.24 107,180.16 136,304.77 2032 0.00 0.00 649.86 0.00 4,193.91 1,698.05 108,878.20 140,498.68 2033 0.00 0.00 570.38 0.00 3,681.27 1,354.79 110,232.99 144,179.95 2034 0.00 0.00 508.26 0.00 3,280.76 1,097.62 111,330.61 147,460.71 2035 0.00 0.00 456.06 0.00 2,944.00 895.44 112,226.05 150,404.71 2036 0.00 0.00 412.51 0.00 2,664.83 736.75 112,962.81 153,069.55 2037 0.00 0.00 372.15 0.00 2,407.41 605.03 113,567.84 155,476.96 2,958.21 0.00 23,663.71 0.00 0.00 25,527.13 3,615.76 0.00 179,140.67 116,526.05 179,140.67 Sub-T After Total 0.00 0.00 0.00 21,911.36 0.00 155,476.96 113,567.84 113,567.84 116,526.05 0.00 23,663.71 2,958.21 155,476.96 Present Worth Profile (M$) PW 5.00% : PW 8.00% : PW 10.00% : PW 12.00% : PW 15.00% : PW 20.00% : 138,586.81 124,075.81 116,526.05 110,155.07 102,217.98 91,948.01

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![](exhibit992-202210xk004.jpg)

Proved Producing Rsv Class & Category Year Oil ------ Mbbl Residue Gas ------ MMcf ------ NGL ------- Mbbl ------- Oil ------- Mbbl ------- Gas ----- MMcf----- ------ Net Reserves Volume -------------- Estimated 8/8 Prod. ------- NGL - $/bbl - Oil - $/bbl - Production and Economic Projection As of: 1/1/2023 Wells Res. Gas - $/Mcf - ---------- Plant Net Sales Volume Wet Gas ------ MMcf TABLE 3 23,539.02 41.05 4,889.12 208,543.67 55.29 40.03 6.20 93.002023 1,166 5,041.11 15,073.63 26.45 2,976.87 137,792.12 41.35 40.01 6.23 92.912024 1,159 3,084.74 11,191.67 19.58 2,094.15 101,981.27 32.52 40.00 6.24 92.882025 1,157 2,177.10 8,897.31 15.51 1,587.62 80,361.24 26.48 39.99 6.25 92.862026 1,152 1,654.43 7,354.23 12.77 1,258.78 65,776.47 22.11 39.98 6.26 92.862027 1,144 1,314.28 6,254.86 10.80 1,031.70 55,416.75 18.82 39.96 6.27 92.852028 1,135 1,078.81 5,394.65 9.28 861.28 47,372.76 16.18 39.95 6.27 92.852029 1,130 901.81 4,740.74 8.13 734.08 41,251.42 14.13 39.94 6.27 92.852030 1,122 769.51 4,216.53 7.22 634.95 36,377.57 12.46 39.94 6.27 92.852031 1,117 666.26 3,796.89 6.49 557.12 32,503.56 11.11 39.93 6.28 92.852032 1,109 585.12 3,428.01 5.84 489.16 29,109.56 9.93 39.93 6.28 92.862033 1,106 514.24 3,122.75 5.31 436.19 26,344.01 8.95 39.92 6.28 92.862034 1,097 458.85 2,849.53 4.84 391.41 23,938.26 8.11 39.92 6.28 92.862035 1,086 411.97 2,617.82 4.44 354.12 21,908.10 7.40 39.92 6.28 92.872036 1,076 372.90 2,397.65 4.06 319.53 19,991.13 6.74 39.92 6.28 92.872037 1,070 336.66 24,870.94After 210,756.69 41.14 3,098.05 69.64 Total 333,827.60 3,243,499.01Ult. 129,746.23 1,139,424.57 222.91 361.20 21,714.14 Cum. Sub-T 39.98 6.25 92.90 39.96 6.28 92.89 104,875.29 928,667.87 181.77 291.56 18,616.09 92.90 39.98 6.24 0.00% Lease Shrinkage and 4.11% Plant Shrinkage 2,104,074.45 204,081.37 22,644.85 3,277.07 19,367.79 Gas ------ M$ ------ Oil ------ M$ ------ Other ------ M$ ------ Year ----------------------------------- Company Future Gross Revenue ---------------------------------- NGL ------ M$ ------ Total ------ M$ ------ Prod Tax ------ M$ ------ Adv Tax ------ M$ ------ after Sev & Adv ------- M$ -------- ------- Prod & Adv Taxes ----- Revenue 3,817.88 2,213.58 30,302.92 0.00 36,334.38 761.46 1,599.18 33,973.752023 2,457.20 1,654.56 18,532.81 0.00 22,644.57 475.27 1,060.96 21,108.342024 1,818.87 1,300.63 13,072.42 0.00 16,191.92 342.01 784.61 15,065.292025 1,440.12 1,058.90 9,927.85 0.00 12,426.87 264.36 614.56 11,547.942026 1,185.75 883.77 7,880.78 0.00 9,950.30 213.41 498.51 9,238.382027 1,002.99 751.80 6,464.39 0.00 8,219.17 177.62 415.36 7,626.192028 861.98 646.46 5,399.80 0.00 6,908.24 150.43 351.18 6,406.632029 755.21 564.24 4,604.61 0.00 5,924.07 129.96 302.35 5,491.752030 670.06 497.57 3,984.09 0.00 5,151.72 113.63 263.68 4,774.412031 602.16 443.68 3,496.63 0.00 4,542.47 100.78 232.94 4,208.752032 542.35 396.41 3,070.42 0.00 4,009.17 89.69 205.66 3,713.822033 493.09 357.37 2,738.36 0.00 3,588.81 80.69 184.29 3,323.832034 449.32 323.71 2,457.86 0.00 3,230.89 72.93 166.09 2,991.872035 412.31 295.21 2,224.04 0.00 2,931.56 66.34 150.89 2,714.322036 376.99 268.84 2,006.91 0.00 2,652.74 60.18 136.63 2,455.922037 3,821.92 19,458.66After Total 20,708.19 14,439.44 135,622.54 0.00 0.00 2,782.71 Sub-T 170,770.16 26,063.29 3,697.39 598.62 8,312.45 1,345.55 158,760.33 24,119.12 16,886.26 11,656.73 116,163.87 0.00 144,706.87 3,098.76 6,966.90 134,641.21 Cumulative ------- M$ ------- Annual ------ M$ ------ Disc. Cum. Annual @ 10.00% ------- M$ ------- -------------------- Future Net Income Before Income Taxes ------------------------------------------------------- Deductions Trans. Costs ------ M$ ------ Net Investments ------ M$ ------ Lease Net Costs ------ M$ ------ Net Profits ------ M$ ------ Undiscounted Discounted Ann @ 10.00% -------M$ ------- Year 2023 0.00 0.00 4,518.21 0.00 29,455.54 28,228.05 28,228.05 29,455.54 2024 0.00 0.00 2,926.74 0.00 18,181.61 15,811.61 44,039.67 47,637.15 2025 0.00 0.00 2,136.17 0.00 12,929.12 10,213.68 54,253.34 60,566.27 2026 0.00 0.00 1,658.99 0.00 9,888.95 7,099.39 61,352.73 70,455.23 2027 0.00 0.00 1,337.33 0.00 7,901.04 5,155.50 66,508.23 78,356.27 2028 0.00 0.00 1,108.90 0.00 6,517.29 3,864.94 70,373.17 84,873.56 2029 0.00 0.00 933.71 0.00 5,472.92 2,949.90 73,323.07 90,346.48 2030 0.00 0.00 801.08 0.00 4,690.67 2,298.30 75,621.37 95,037.15 2031 0.00 0.00 696.19 0.00 4,078.22 1,816.49 77,437.86 99,115.37 2032 0.00 0.00 613.03 0.00 3,595.72 1,455.77 78,893.63 102,711.09 2033 0.00 0.00 539.82 0.00 3,174.01 1,168.05 80,061.68 105,885.09 2034 0.00 0.00 482.32 0.00 2,841.52 950.64 81,012.32 108,726.61 2035 0.00 0.00 433.70 0.00 2,558.17 778.07 81,790.39 111,284.78 2036 0.00 0.00 392.95 0.00 2,321.37 641.79 82,432.18 113,606.16 2037 0.00 0.00 354.98 0.00 2,100.95 528.00 82,960.18 115,707.10 2,591.57 0.00 20,659.36 0.00 0.00 22,393.87 3,459.77 0.00 136,366.46 85,551.76 136,366.46 Sub-T After Total 0.00 0.00 0.00 18,934.10 0.00 115,707.10 82,960.18 82,960.18 85,551.76 0.00 20,659.36 2,591.57 115,707.10 Present Worth Profile (M$) PW 5.00% : PW 8.00% : PW 10.00% : PW 12.00% : PW 15.00% : PW 20.00% : 103,085.26 91,490.19 85,551.76 80,598.53 74,509.50 66,777.86

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![](exhibit992-202210xk005.jpg)

Proved Behind Pipe Rsv Class & Category Year Oil ------ Mbbl Residue Gas ------ MMcf ------ NGL ------- Mbbl ------- Oil ------- Mbbl ------- Gas ----- MMcf----- ------ Net Reserves Volume -------------- Estimated 8/8 Prod. ------- NGL - $/bbl - Oil - $/bbl - Production and Economic Projection As of: 1/1/2023 Wells Res. Gas - $/Mcf - ---------- Plant Net Sales Volume Wet Gas ------ MMcf TABLE 4 6,610.94 9.61 760.50 19,005.22 2.04 36.96 5.85 93.542023 65 774.48 12,850.97 20.79 1,525.17 62,860.95 6.14 40.51 5.85 93.082024 102 1,561.33 6,345.43 10.11 691.71 39,098.58 4.78 40.30 5.85 93.122025 102 714.80 3,939.66 6.22 346.53 26,210.39 3.68 39.97 5.84 93.132026 102 362.32 2,853.67 4.48 204.54 19,836.87 3.00 39.76 5.84 93.142027 102 216.59 2,237.00 3.50 134.09 16,051.96 2.55 39.62 5.84 93.142028 102 143.89 1,827.43 2.85 93.84 13,443.31 2.20 39.51 5.84 93.142029 102 102.07 1,545.47 2.40 69.39 11,601.21 1.94 39.43 5.83 93.142030 102 76.51 1,337.24 2.08 53.38 10,207.18 1.74 39.36 5.83 93.142031 102 59.65 1,180.36 1.83 42.45 9,133.12 1.58 39.32 5.83 93.142032 102 48.07 1,050.43 1.62 34.43 8,217.82 1.43 39.29 5.83 93.142033 102 39.48 947.87 1.46 28.58 7,479.77 1.31 39.28 5.83 93.142034 102 33.17 862.98 1.33 24.12 6,846.50 1.20 39.27 5.82 93.142035 102 28.32 792.54 1.22 20.69 6,305.02 1.11 39.28 5.82 93.142036 102 24.55 725.97 1.12 17.84 5,788.96 1.02 39.28 5.82 93.142037 102 21.38 7,898.52After 67,153.91 12.17 146.49 11.36 Total 53,006.48 329,240.77Ult. 53,006.48 329,240.77 82.80 47.08 4,193.75 Cum. Sub-T 39.61 5.84 93.17 39.45 5.81 93.14 45,107.95 262,086.85 70.63 35.72 4,047.25 93.18 39.66 5.85 0.00% Lease Shrinkage and 4.51% Plant Shrinkage 0.00 0.00 4,391.98 185.38 4,206.60 Gas ------ M$ ------ Oil ------ M$ ------ Other ------ M$ ------ Year ----------------------------------- Company Future Gross Revenue ---------------------------------- NGL ------ M$ ------ Total ------ M$ ------ Prod Tax ------ M$ ------ Adv Tax ------ M$ ------ after Sev & Adv ------- M$ -------- ------- Prod & Adv Taxes ----- Revenue 899.23 75.57 4,447.47 0.00 5,422.27 184.26 24.54 5,213.472023 1,934.99 248.55 8,919.33 0.00 11,102.87 385.44 57.94 10,659.492024 941.50 192.60 4,043.91 0.00 5,178.01 186.22 30.96 4,960.822025 579.48 146.93 2,025.19 0.00 2,751.60 103.64 20.17 2,627.792026 417.38 119.37 1,194.92 0.00 1,731.67 68.14 15.07 1,648.462027 325.85 100.92 783.04 0.00 1,209.82 49.50 12.07 1,148.252028 265.36 87.04 547.78 0.00 900.17 38.12 10.03 852.032029 223.85 76.68 404.89 0.00 705.42 30.79 8.59 666.042030 193.27 68.49 311.33 0.00 573.10 25.67 7.51 539.912031 170.29 61.96 247.51 0.00 479.76 21.99 6.68 451.092032 151.30 56.19 200.64 0.00 408.13 19.08 5.98 383.072033 136.33 51.44 166.49 0.00 354.26 16.85 5.42 331.992034 123.97 47.27 140.46 0.00 311.70 15.04 4.95 291.712035 113.78 43.63 120.43 0.00 277.83 13.58 4.56 259.702036 104.20 40.08 103.85 0.00 248.12 12.25 4.18 231.702037 1,133.54 851.17After Total 7,714.33 1,864.85 24,508.40 0.00 0.00 448.12 Sub-T 34,087.57 2,432.83 1,296.92 126.35 264.87 46.21 32,525.79 2,260.28 6,580.79 1,416.73 23,657.23 0.00 31,654.74 1,170.57 218.66 30,265.52 Cumulative ------- M$ ------- Annual ------ M$ ------ Disc. Cum. Annual @ 10.00% ------- M$ ------- -------------------- Future Net Income Before Income Taxes ------------------------------------------------------- Deductions Trans. Costs ------ M$ ------ Net Investments ------ M$ ------ Lease Net Costs ------ M$ ------ Net Profits ------ M$ ------ Undiscounted Discounted Ann @ 10.00% -------M$ ------- Year 2023 0.00 0.00 373.27 0.00 4,840.20 4,498.28 4,498.28 4,840.20 2024 0.00 0.00 771.04 0.00 9,888.45 8,608.28 13,106.56 14,728.66 2025 0.00 0.00 358.89 0.00 4,601.93 3,648.11 16,754.67 19,330.59 2026 0.00 0.00 185.93 0.00 2,441.86 1,756.94 18,511.61 21,772.45 2027 0.00 0.00 113.76 0.00 1,534.71 1,002.95 19,514.55 23,307.15 2028 0.00 0.00 77.37 0.00 1,070.88 635.77 20,150.32 24,378.03 2029 0.00 0.00 56.16 0.00 795.86 429.32 20,579.64 25,173.90 2030 0.00 0.00 43.04 0.00 623.00 305.44 20,885.08 25,796.90 2031 0.00 0.00 34.28 0.00 505.63 225.32 21,110.40 26,302.53 2032 0.00 0.00 28.18 0.00 422.91 171.28 21,281.68 26,725.44 2033 0.00 0.00 23.59 0.00 359.48 132.33 21,414.01 27,084.92 2034 0.00 0.00 20.17 0.00 311.82 104.34 21,518.36 27,396.74 2035 0.00 0.00 17.50 0.00 274.21 83.41 21,601.77 27,670.94 2036 0.00 0.00 15.40 0.00 244.31 67.55 21,669.32 27,915.25 2037 0.00 0.00 13.59 0.00 218.11 54.82 21,724.14 28,133.35 260.57 0.00 2,133.12 0.00 0.00 2,259.31 127.15 0.00 30,266.48 21,984.71 30,266.48 Sub-T After Total 0.00 0.00 0.00 2,132.16 0.00 28,133.35 21,724.14 21,724.14 21,984.71 0.00 2,133.12 260.57 28,133.35 Present Worth Profile (M$) PW 5.00% : PW 8.00% : PW 10.00% : PW 12.00% : PW 15.00% : PW 20.00% : 25,158.08 23,113.69 21,984.71 20,991.62 19,697.29 17,919.17

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![](exhibit992-202210xk006.jpg)

Proved Undeveloped Rsv Class & Category Year Oil ------ Mbbl Residue Gas ------ MMcf ------ NGL ------- Mbbl ------- Oil ------- Mbbl ------- Gas ----- MMcf----- ------ Net Reserves Volume -------------- Estimated 8/8 Prod. ------- NGL - $/bbl - Oil - $/bbl - Production and Economic Projection As of: 1/1/2023 Wells Res. Gas - $/Mcf - ---------- Plant Net Sales Volume Wet Gas ------ MMcf TABLE 5 0.00 0.00 351.31 2,786.24 0.00 0.00 5.85 0.002023 1 354.86 494.49 4.59 647.31 6,600.30 0.92 39.34 5.90 93.622024 4 657.06 2,755.32 4.40 297.59 9,996.54 0.97 39.41 5.96 93.622025 28 303.99 4,571.04 5.16 148.70 15,683.24 1.40 41.39 5.96 93.362026 42 155.07 2,247.76 2.84 85.49 11,254.30 0.98 40.72 5.99 93.462027 42 89.77 1,409.83 1.94 54.88 8,652.21 0.73 40.55 6.02 93.482028 42 58.00 1,020.38 1.48 37.73 7,023.07 0.58 40.46 6.05 93.482029 42 40.16 798.76 1.21 27.46 5,927.64 0.49 40.41 6.09 93.492030 42 29.44 654.77 1.02 20.81 5,127.79 0.42 40.37 6.12 93.492031 42 22.49 555.24 0.89 16.32 4,528.54 0.37 40.34 6.16 93.502032 42 17.78 479.05 0.79 13.06 4,033.40 0.33 40.32 6.20 93.502033 42 14.35 421.77 0.71 10.72 3,643.02 0.30 40.31 6.23 93.502034 42 11.86 376.39 0.64 8.95 3,319.47 0.27 40.30 6.27 93.502035 42 9.98 340.25 0.58 7.61 3,048.69 0.25 40.29 6.31 93.502036 42 8.55 308.35 0.53 6.51 2,793.59 0.23 40.29 6.35 93.502037 42 7.38 3,325.91After 31,827.96 5.78 50.22 2.80 Total 19,759.31 126,245.99Ult. 19,759.31 126,245.99 32.57 11.03 1,784.67 Cum. Sub-T 40.37 5.96 93.51 40.38 6.75 93.50 16,433.40 94,418.03 26.79 8.23 1,734.45 93.51 40.37 5.94 0.00% Lease Shrinkage and 3.08% Plant Shrinkage 0.00 0.00 1,841.31 60.56 1,780.75 Gas ------ M$ ------ Oil ------ M$ ------ Other ------ M$ ------ Year ----------------------------------- Company Future Gross Revenue ---------------------------------- NGL ------ M$ ------ Total ------ M$ ------ Prod Tax ------ M$ ------ Adv Tax ------ M$ ------ after Sev & Adv ------- M$ -------- ------- Prod & Adv Taxes ----- Revenue 0.00 0.00 2,054.96 0.00 2,054.96 62.18 0.00 1,992.782023 429.67 36.31 3,821.68 0.00 4,287.65 152.47 27.17 4,108.012024 411.67 38.31 1,772.23 0.00 2,222.21 87.20 24.55 2,110.472025 481.29 57.79 886.66 0.00 1,425.74 61.04 20.96 1,343.732026 265.81 39.86 511.92 0.00 817.60 36.03 12.90 768.682027 181.35 29.65 330.31 0.00 541.31 24.65 9.36 507.302028 138.78 23.63 228.33 0.00 390.74 18.40 7.40 364.942029 113.17 19.71 167.09 0.00 299.98 14.56 6.16 279.262030 95.78 16.93 127.38 0.00 240.09 11.98 5.29 222.812031 83.36 14.88 100.51 0.00 198.75 10.17 4.65 183.922032 73.51 13.21 80.95 0.00 167.67 8.77 4.14 154.762033 65.95 11.90 66.81 0.00 144.66 7.72 3.74 133.202034 59.81 10.83 56.14 0.00 126.77 6.89 3.41 116.482035 54.70 9.96 48.01 0.00 112.66 6.22 3.13 103.312036 49.91 9.17 41.36 0.00 100.44 5.61 2.87 91.952037 540.65 339.02After Total 3,045.41 445.33 10,633.37 0.00 0.00 113.20 Sub-T 14,124.11 992.87 573.70 59.80 168.74 32.99 13,381.67 900.07 2,504.77 332.13 10,294.34 0.00 13,131.25 513.90 135.75 12,481.60 Cumulative ------- M$ ------- Annual ------ M$ ------ Disc. Cum. Annual @ 10.00% ------- M$ ------- -------------------- Future Net Income Before Income Taxes ------------------------------------------------------- Deductions Trans. Costs ------ M$ ------ Net Investments ------ M$ ------ Lease Net Costs ------ M$ ------ Net Profits ------ M$ ------ Undiscounted Discounted Ann @ 10.00% -------M$ ------- Year 2023 0.00 0.00 168.63 0.00 1,824.15 1,692.61 1,692.61 1,824.15 2024 0.00 0.00 307.64 0.00 3,800.37 3,297.64 4,990.26 5,624.52 2025 0.00 0.00 142.01 0.00 1,968.45 1,560.24 6,550.50 7,592.98 2026 0.00 0.00 76.21 0.00 1,267.53 912.08 7,462.58 8,860.50 2027 0.00 0.00 43.71 0.00 724.97 474.05 7,936.64 9,585.47 2028 0.00 0.00 28.18 0.00 479.12 284.53 8,221.17 10,064.59 2029 0.00 0.00 19.50 0.00 345.44 186.38 8,407.55 10,410.03 2030 0.00 0.00 14.30 0.00 264.96 129.92 8,537.46 10,674.98 2031 0.00 0.00 10.93 0.00 211.88 94.43 8,631.89 10,886.87 2032 0.00 0.00 8.64 0.00 175.28 71.00 8,702.89 11,062.15 2033 0.00 0.00 6.98 0.00 147.78 54.40 8,757.29 11,209.93 2034 0.00 0.00 5.77 0.00 127.43 42.64 8,799.94 11,337.37 2035 0.00 0.00 4.86 0.00 111.62 33.96 8,833.89 11,448.99 2036 0.00 0.00 4.16 0.00 99.16 27.42 8,861.31 11,548.14 2037 0.00 0.00 3.59 0.00 88.36 22.21 8,883.52 11,636.50 106.07 0.00 871.23 0.00 0.00 873.94 28.85 0.00 12,507.73 8,989.59 12,507.73 Sub-T After Total 0.00 0.00 0.00 845.09 0.00 11,636.50 8,883.52 8,883.52 8,989.59 0.00 871.23 106.07 11,636.50 Present Worth Profile (M$) PW 5.00% : PW 8.00% : PW 10.00% : PW 12.00% : PW 15.00% : PW 20.00% : 10,343.47 9,471.93 8,989.59 8,564.91 8,011.19 7,250.98

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![](exhibit992-202210xk007.jpg)

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Tabular Summaries

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![](exhibit992-202210xk008.jpg)

Economic One-Liners Lease Name Life (years) Oil (Mbbl) Residue Gas (MMcf) Residue Gas (M$) Other (M$) Expense & Tax (M$) Invest. (M$) Non-Disc. (M$) Cash FlowNet Sales Volumes Net Revenue As of Date: 1/1/2023 Reserve Category Oil (M$) Disc. 10% (M$) NGL (M$) NGL (Mbbl) TABLE 6 Proved Producing Rsv Class & Category 126.63 74.80 27.77 0.00 0.00 0.00 151.82 25.20 0.00P-DP 43.68AUSTIN 5H - 5H 0.00 0.00 130.04 75.04 28.52 0.00 0.00 0.00 155.92 25.88 0.00P-DP 44.75AUSTIN 6H - 6H 0.00 0.00 148.76 83.56 32.62 0.00 0.00 0.00 178.36 29.60 0.00P-DP 46.90AUSTIN 7H - 7H 0.00 0.00 156.72 87.21 34.37 0.00 0.00 0.00 187.91 31.18 0.00P-DP 47.72AUSTIN 8H - 8H 0.00 0.00 2.40 1.60 0.42 0.00 0.00 0.00 2.59 0.19 0.00P-DP 26.64ALPHA 210488 1A - 1A 0.00 0.00 3.11 1.90 0.54 0.00 0.00 0.00 3.36 0.25 0.00P-DP 33.63ALPHA 210488 2B - 2B 0.00 0.00 5.25 2.97 0.92 0.00 0.00 0.00 5.67 0.42 0.00P-DP 41.75ALPHA 210488 3C - 3C 0.00 0.00 51.89 31.35 9.09 0.00 0.00 0.00 56.04 4.15 0.00P-DP 46.64CHARLIE 210468 7A - 7A 0.00 0.00 37.46 23.03 6.56 0.00 0.00 0.00 40.46 3.00 0.00P-DP 42.45CHARLIE 210468 8B - 8B 0.00 0.00 528.55 327.66 92.56 0.00 0.00 0.00 570.83 42.27 0.00P-DP 46.71CHARLIE 210469 10B - 10B 0.00 0.00 515.78 319.28 90.32 0.00 0.00 0.00 557.03 41.25 0.00P-DP 46.47CHARLIE 210469 9A - 9A 0.00 0.00 414.92 221.97 72.66 0.00 0.00 0.00 448.11 33.18 0.00P-DP 38.44CHARLIE 210472 4A - 4A 0.00 0.00 405.93 232.79 71.08 0.00 0.00 0.00 438.40 32.46 0.00P-DP 36.42CHARLIE 210472 5B - 5B 0.00 0.00 279.26 164.19 48.90 0.00 0.00 0.00 301.60 22.33 0.00P-DP 31.46CHARLIE 210472 6C - 6C 0.00 0.00 31.92 20.53 5.59 0.00 0.00 0.00 34.47 2.55 0.00P-DP 39.64CROWIE E RCH BL 3H - 3H 0.00 0.00 37.82 22.00 6.62 0.00 0.00 0.00 40.85 3.02 0.00P-DP 44.64CROWIE RCH BL 1H - 1H 0.00 0.00 0.28 0.17 0.05 0.00 0.00 0.00 0.30 0.02 0.00P-DP 42.65DILLES BOTTOM 210744 3B - 3B 0.00 0.00 10.72 7.17 1.88 0.00 0.00 0.00 11.58 0.86 0.00P-DP 45.25HENDERSHOT 210471 1A - 1A 0.00 0.00 11.53 7.30 2.02 0.00 0.00 0.00 12.45 0.92 0.00P-DP 48.56HENDERSHOT 210471 2B - 2B 0.00 0.00 946.87 514.69 165.81 0.00 0.00 0.00 1,022.59 75.73 0.00P-DP 46.42KRUPA 210483 3A - 3A 0.00 0.00 326.92 184.95 57.25 0.00 0.00 0.00 353.07 26.15 0.00P-DP 46.66KRUPA 211259 2A - 2A 0.00 0.00 2.33 1.34 0.41 0.00 0.00 0.00 2.51 0.19 0.00P-DP 37.38REITZ UNIT 5H - 5H 0.00 0.00 573.16 364.24 100.37 0.00 0.00 0.00 619.00 45.84 0.00P-DP 48.18SHANNON 210470 3C - 3C 0.00 0.00 671.89 425.77 117.66 0.00 0.00 0.00 725.63 53.74 0.00P-DP 50.00SHANNON 210470 4B - 4B 0.00 0.00 436.88 282.78 76.50 0.00 0.00 0.00 471.82 34.94 0.00P-DP 45.04SHANNON 211271 1B - 1B 0.00 0.00 547.28 348.52 95.84 0.00 0.00 0.00 591.05 43.77 0.00P-DP 48.14SHANNON 211271 2A - 2A 0.00 0.00 480.19 325.04 84.09 0.00 0.00 0.00 518.59 38.40 0.00P-DP 33.71SIDWELL SE WHL BL 10H - 10H 0.00 0.00 718.97 446.40 125.90 0.00 0.00 0.00 776.47 57.50 0.00P-DP 42.03SIDWELL SE WHL BL 8H - 8H 0.00 0.00 220.24 110.19 38.57 0.00 0.00 0.00 237.86 17.61 0.00P-DP 50.00SIDWELL SW WHL BL 2H - 2H 0.00 0.00 51.54 30.60 9.02 0.00 0.00 0.00 55.66 4.12 0.00P-DP 32.25SIDWELL SW WHL BL 4H - 4H 0.00 0.00 1.43 1.03 0.25 0.00 0.00 0.00 1.55 0.11 0.00P-DP 29.06SMASHOSAURUS 3 - 3 0.00 0.00 141.21 95.76 24.73 0.00 0.00 0.00 152.50 11.29 0.00P-DP 31.56SMASHOSAURUS 5 - 5 0.00 0.00 1.89 1.09 0.33 0.00 0.00 0.00 2.04 0.15 0.00P-DP 34.26SPITFIRE 1H - 1H 0.00 0.00 1.16 0.69 0.20 0.00 0.00 0.00 1.25 0.09 0.00P-DP 31.08SPITFIRE 3H - 3H 0.00 0.00

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![](exhibit992-202210xk009.jpg)

Economic One-Liners Lease Name Life (years) Oil (Mbbl) Residue Gas (MMcf) Residue Gas (M$) Other (M$) Expense & Tax (M$) Invest. (M$) Non-Disc. (M$) Cash FlowNet Sales Volumes Net Revenue As of Date: 1/1/2023 Reserve Category Oil (M$) Disc. 10% (M$) NGL (M$) NGL (Mbbl) TABLE 6 39.38 23.90 6.90 0.00 0.00 0.00 42.53 3.15 0.00P-DP 37.47TIGER 210187 2A - 2A 0.00 0.00 32.58 19.66 5.71 0.00 0.00 0.00 35.19 2.61 0.00P-DP 35.64TIGER 210187 3C - 3C 0.00 0.00 22.96 14.68 4.02 0.00 0.00 0.00 24.80 1.84 0.00P-DP 29.26TIGER 210187 5B - 5B 0.00 0.00 0.08 0.05 0.01 0.00 0.00 0.00 0.09 0.01 0.00P-DP 35.32TIGER 210475 4C - 4C 0.00 0.00 37.73 22.60 6.61 0.00 0.00 0.00 40.75 3.02 0.00P-DP 37.58TIGER 210476 1A - 1A 0.00 0.00 73.64 46.25 12.89 0.00 0.00 0.00 79.52 5.89 0.00P-DP 31.02VALERIE 210473 1A - 1A 0.00 0.00 72.43 45.90 12.68 0.00 0.00 0.00 78.22 5.79 0.00P-DP 30.50VALERIE 210473 2B - 2B 0.00 0.00 97.00 55.54 16.99 0.00 0.00 0.00 104.75 7.76 0.00P-DP 37.53VALERIE 210473 4C - 4C 0.00 0.00 564.56 288.41 98.86 0.00 0.00 0.00 609.71 45.15 0.00P-DP 50.00VANNELLE SW WHL BL 2H - 2H 0.00 0.00 0.10 0.05 0.02 0.00 0.00 0.00 0.10 0.01 0.00P-DP 40.35YANKEE 210475 5A - 5A 0.00 0.00 4.47 2.73 0.87 0.00 0.00 0.00 5.45 0.98 0.00P-DP 14.73CV RB SUV;SHELBY INTERESTS 31 001 - 001 0.00 0.00 124.88 65.11 24.21 0.00 0.00 0.00 152.41 27.53 0.00P-DP 31.01CV RB SUW;LESHE 36 001 - 001 0.00 0.00 51.49 28.58 9.98 0.00 0.00 0.00 62.84 11.35 0.00P-DP 21.92CV RB SUW;NAC 36 001-ALT - 001-ALT 0.00 0.00 98.15 68.06 19.03 0.00 0.00 0.00 119.78 21.64 0.00P-DP 30.74HA RA SU77;LEE 25-36 HC 001-ALT - 001-ALT 0.00 0.00 0.60 0.30 0.00 0.01 0.00 0.65 0.00 0.05 0.00P-DP 34.05BILLINGSLEY 12 1 - 1 0.00 0.00 30.28 18.36 0.29 0.31 0.00 28.75 1.66 2.96 0.00P-DP 47.31CHAPARRAL UNIT A2 7AH - 7AH 2.83 0.06 27.53 16.78 0.28 0.28 0.00 25.97 1.58 2.71 0.00P-DP 46.01CHAPARRAL UNIT A3 14SH - 14SH 2.69 0.06 27.06 16.45 0.40 0.26 0.00 23.75 2.30 2.91 0.00P-DP 45.79CHAPARRAL UNIT A3 20H - 20H 3.92 0.09 37.36 22.71 0.40 0.38 0.00 34.82 2.32 3.74 0.00P-DP 49.62CHAPARRAL UNIT A4 6AH - 6AH 3.96 0.09 26.37 14.48 0.63 0.22 0.00 19.96 3.58 3.27 0.00P-DP 49.31HIGGINBOTHAM UNIT A 30-18 2AH - 2AH 6.11 0.13 27.63 14.28 0.33 0.27 0.00 25.38 1.87 2.82 0.00P-DP 49.75HIGGINBOTHAM UNIT A 30-18 3AH - 3AH 3.19 0.07 5.20 3.12 0.10 0.05 0.00 4.22 0.59 0.61 0.00P-DP 27.83HIGGINBOTHAM UNIT A 30-18 4AH - 4AH 1.01 0.02 11.78 6.39 0.17 0.11 0.00 10.43 0.96 1.26 0.00P-DP 36.66HIGGINBOTHAM UNIT B 30-19 1H - 1H 1.64 0.04 15.55 8.57 0.32 0.13 0.00 12.47 1.81 1.83 0.00P-DP 40.55HIGGINBOTHAM UNIT B 30-19 7AH - 7AH 3.10 0.07 23.92 12.37 0.42 0.22 0.00 20.14 2.39 2.69 0.00P-DP 48.99HIGGINBOTHAM UNIT C 30-18 5AH - 5AH 4.08 0.09 17.29 9.21 0.42 0.14 0.00 13.00 2.38 2.16 0.00P-DP 45.08HIGGINBOTHAM UNIT C 30-18 6AH - 6AH 4.07 0.09 19.92 11.21 0.49 0.16 0.00 14.84 2.80 2.50 0.00P-DP 41.81JOTUNN UNIT A 25-24 3AH - 3AH 4.78 0.10 15.95 8.63 0.44 0.12 0.00 11.17 2.54 2.10 0.00P-DP 39.85JOTUNN UNIT A 25-24 4AH - 4AH 4.34 0.09 17.10 9.73 0.29 0.16 0.00 14.55 1.65 1.90 0.00P-DP 37.46JOTUNN UNIT A 25-24 5AH - 5AH 2.81 0.06 33.84 17.19 0.98 0.25 0.00 23.21 5.60 4.53 0.00P-DP 50.00JOTUNN UNIT B 25-13 6AH - 6AH 9.57 0.21 22.18 12.46 0.47 0.19 0.00 17.48 2.72 2.66 0.00P-DP 45.36JOTUNN UNIT B 25-13 7AH - 7AH 4.64 0.10 16.93 9.55 0.39 0.14 0.00 13.02 2.21 2.07 0.00P-DP 43.13LEVIATHAN UNIT A 29-17 4AH - 4AH 3.77 0.08 20.77 11.60 0.03 0.24 0.00 22.00 0.18 1.72 0.00P-DP 43.53LEVIATHAN UNIT A 29-17 5AH - 5AH 0.31 0.01 21.48 11.02 0.85 0.13 0.00 11.62 4.86 3.30 0.00P-DP 43.98LEVIATHAN UNIT A 29-17 6AH - 6AH 8.30 0.18 3.81 2.60 0.13 0.03 0.00 2.32 0.75 0.55 0.00P-DP 17.94LEVIATHAN UNIT B 29-20 7AH - 7AH 1.29 0.03

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![](exhibit992-202210xk010.jpg)

Economic One-Liners Lease Name Life (years) Oil (Mbbl) Residue Gas (MMcf) Residue Gas (M$) Other (M$) Expense & Tax (M$) Invest. (M$) Non-Disc. (M$) Cash FlowNet Sales Volumes Net Revenue As of Date: 1/1/2023 Reserve Category Oil (M$) Disc. 10% (M$) NGL (M$) NGL (Mbbl) TABLE 6 26.60 12.96 1.13 0.14 0.00 13.33 6.46 4.23 0.00P-DP 41.57LEVIATHAN UNIT B 29-20 8SH - 8SH 11.04 0.24 10.38 5.73 0.37 0.07 0.00 6.22 2.10 1.51 0.00P-DP 31.91LEVIATHAN UNIT B 29-20 9AH(8AH) - 9AH 3.58 0.08 21.60 11.60 0.70 0.15 0.00 13.73 4.03 3.04 0.00P-DP 39.41MEDUSA UNIT A 28-21 1AH - 1AH 6.88 0.15 22.43 11.74 0.71 0.16 0.00 14.49 4.09 3.12 0.00P-DP 40.03MEDUSA UNIT A 28-21 2AH - 2AH 6.98 0.15 21.26 12.04 0.51 0.17 0.00 16.00 2.92 2.65 0.00P-DP 39.02MEDUSA UNIT B 28-21 7AH - 7AH 4.99 0.11 20.90 11.60 0.72 0.14 0.00 12.72 4.13 3.02 0.00P-DP 37.29MEDUSA UNIT B 28-21 8AH - 8AH 7.06 0.15 19.42 11.21 0.02 0.22 0.00 20.67 0.13 1.59 0.00P-DP 41.92MEDUSA UNIT C 28-09 3AH - 3AH 0.22 0.00 16.56 9.69 0.39 0.14 0.00 12.56 2.24 2.05 0.00P-DP 41.68MEDUSA UNIT C 28-09 6AH - 6AH 3.82 0.08 4.13 2.13 0.74 0.00 0.00 0.00 4.67 0.54 0.00P-DP 28.38CV RA SU91;EDGAR S TALBERT 9 H 001 - 001 0.00 0.00 4.20 2.36 0.75 0.00 0.00 0.00 4.75 0.55 0.00P-DP 24.39HA RA SU98;PACE 8-14-16 H 001 - 001 0.00 0.00 1.27 0.93 0.02 0.02 0.00 1.41 0.09 0.23 0.00P-DP 20.25AMAZON 3304-02H - 3304-02H 0.00 0.00 5.83 3.53 0.06 0.07 0.00 6.49 0.40 1.05 0.00P-DP 42.14AMAZON 3304-03H - 3304-03H 0.00 0.00 5.14 3.10 0.52 0.04 0.00 3.60 3.17 1.63 0.00P-DP 42.69AMAZON 3304-04H - 3304-04H 0.00 0.00 4.90 3.07 0.36 0.04 0.00 4.08 2.17 1.34 0.00P-DP 40.38AMAZON 3304-05H - 3304-05H 0.00 0.00 4.55 2.58 0.06 0.05 0.00 5.02 0.36 0.83 0.00P-DP 28.79BOLT 15-33H - 15-33H 0.00 0.00 49.35 32.29 2.60 0.50 0.00 45.50 15.86 12.00 0.00P-DP 28.50BOLT 406-0904H - 406-0904H 0.00 0.00 48.82 29.88 1.94 0.52 0.00 47.91 11.82 10.91 0.00P-DP 29.95BOLT 407-0904H - 407-0904H 0.00 0.00 160.22 85.12 3.64 1.85 0.00 169.67 22.20 31.65 0.00P-DP 46.43LEAVITT FED 1-9-4PH - 1-9-4PH 0.00 0.00 124.89 61.73 10.72 1.05 0.00 96.18 65.42 36.71 0.00P-DP 50.00LEAVITT FED 1-9-4TH - 1-9-4TH 0.00 0.00 229.52 112.45 7.10 2.55 0.00 234.41 43.33 48.22 0.00P-DP 50.00LEAVITT FED 2-9-4PH - 2-9-4PH 0.00 0.00 0.47 0.30 0.00 0.01 0.00 0.50 0.00 0.04 0.00P-DP 12.66BROWN, A. D. 2 - 2 0.00 0.00 47.59 28.14 0.33 0.49 0.00 45.69 1.97 4.26 0.00P-DP 50.00CHAPARRAL UNIT A5 13SH - 13SH 4.20 0.09 22.06 13.56 0.13 0.23 0.00 21.60 0.76 1.92 0.00P-DP 43.34CHAPARRAL UNIT A5 19H - 19H 1.61 0.04 7.54 2.59 0.00 0.09 0.00 8.10 0.00 0.57 0.00P-DP 50.00DAVID 1 - 1 0.00 0.00 0.06 0.04 0.00 0.00 0.00 0.06 0.00 0.00 0.00P-DP 12.10EAST ACKERLY DEAN UNIT 99 - 99 0.00 0.00 10.75 5.10 0.11 0.10 0.00 9.83 0.62 1.02 0.00P-DP 42.69OAK VALLEY 2 1 - 1 1.33 0.03 11.03 5.22 0.10 0.11 0.00 10.16 0.61 1.04 0.00P-DP 43.46OV UNIT 1 - 1 1.30 0.03 12.88 6.14 0.15 0.12 0.00 11.39 0.88 1.27 0.00P-DP 34.87OVMLC 1 - 1 1.88 0.04 11.02 5.37 0.04 0.12 0.00 11.20 0.23 0.91 0.00P-DP 41.79OVMLC 2 - 2 0.50 0.01 0.30 0.15 0.00 0.00 0.00 0.33 0.00 0.02 0.00P-DP 32.11WALLACE, T. L. 1 - 1 0.00 0.00 0.15 0.11 0.00 0.00 0.00 0.16 0.00 0.01 0.00P-DP 9.13WALLACE, T. L. 3 - 3 0.00 0.00 0.55 0.25 0.00 0.01 0.00 0.58 0.00 0.04 0.00P-DP 32.39WHITE 19 - 19 0.01 0.00 0.36 0.29 0.06 0.00 0.00 0.00 0.39 0.03 0.00P-DP 8.27HA RA SUSS;JORDAN 16-21 HC 001-ALT - 001-ALT 0.00 0.00 0.29 0.24 0.05 0.00 0.00 0.00 0.31 0.02 0.00P-DP 5.80HA RA SUTT;BSMC LA 21 HZ 001 - 001 0.00 0.00 57.94 32.57 2.09 0.34 0.00 30.87 13.93 5.10 0.00P-DP 50.00ADAMEK UNIT 2H - 2H 18.23 0.51

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![](exhibit992-202210xk011.jpg)

Economic One-Liners Lease Name Life (years) Oil (Mbbl) Residue Gas (MMcf) Residue Gas (M$) Other (M$) Expense & Tax (M$) Invest. (M$) Non-Disc. (M$) Cash FlowNet Sales Volumes Net Revenue As of Date: 1/1/2023 Reserve Category Oil (M$) Disc. 10% (M$) NGL (M$) NGL (Mbbl) TABLE 6 39.15 20.29 0.53 0.37 0.00 33.94 3.56 3.01 0.00P-DP 45.62BOENING UNIT 1H - 1H 4.66 0.13 39.67 21.10 1.48 0.22 0.00 20.24 9.87 3.36 0.00P-DP 50.00BOENING UNIT 2H - 2H 12.92 0.36 143.96 81.25 4.23 0.97 0.00 89.12 28.27 10.43 0.00P-DP 33.01BOENING UNIT 3H - 3H 37.00 1.04 80.28 47.57 2.04 0.60 0.00 54.69 13.61 5.82 0.00P-DP 50.00BOENING UNIT 4H - 4H 17.81 0.50 124.64 76.46 2.51 1.04 0.00 95.04 16.73 9.02 0.00P-DP 28.63BOENING UNIT 6L - 6L 21.89 0.62 159.06 89.53 3.54 1.27 0.00 115.98 23.63 11.48 0.00P-DP 38.69BOENING UNIT 6U - 6U 30.93 0.87 1.01 0.70 0.03 0.01 0.00 0.59 0.22 0.09 0.00P-DP 11.87CHUMCHAL UNIT 1H - 1H 0.29 0.01 13.45 8.86 0.25 0.12 0.00 10.68 1.65 1.05 0.00P-DP 13.80CHUMCHAL UNIT 4H - 4H 2.16 0.06 95.49 55.97 2.03 0.78 0.00 71.04 13.57 6.89 0.00P-DP 37.37CHUMCHAL UNIT 6L - 6L 17.77 0.50 90.10 54.04 1.98 0.72 0.00 66.07 13.23 6.51 0.00P-DP 50.00CHUMCHAL UNIT 7L - 7L 17.32 0.49 118.46 58.68 2.37 1.00 0.00 91.15 15.85 9.27 0.00P-DP 50.00COLLE UNIT 1H - 1H 20.74 0.58 71.94 35.42 1.87 0.54 0.00 49.06 12.47 5.91 0.00P-DP 50.00FIELDS UNIT 1H - 1H 16.32 0.46 43.23 21.41 1.18 0.31 0.00 28.54 7.91 3.57 0.00P-DP 46.86FIELDS UNIT 2H - 2H 10.35 0.29 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00P-DP 0.00FIELDS UNIT 3H - 3H 0.00 0.00 60.33 35.25 2.13 0.36 0.00 32.65 14.21 5.11 0.00P-DP 49.78FIELDS UNIT 4H - 4H 18.59 0.52 19.04 8.70 0.37 0.16 0.00 14.86 2.47 1.52 0.00P-DP 50.00GERDES UNIT 1H - 1H 3.23 0.09 66.29 30.63 2.40 0.38 0.00 35.08 16.02 5.76 0.00P-DP 50.00GERDES UNIT 2H - 2H 20.96 0.59 34.78 16.02 0.90 0.26 0.00 23.74 6.01 2.84 0.00P-DP 50.00GERDES UNIT 3H - 3H 7.87 0.22 52.49 28.57 1.08 0.44 0.00 39.98 7.21 4.12 0.00P-DP 25.52GERDES UNIT 4H - 4H 9.43 0.26 116.16 70.70 2.28 0.98 0.00 89.37 15.24 8.38 0.00P-DP 25.57GERDES UNIT 5H - 5H 19.94 0.56 131.42 76.19 2.63 1.10 0.00 100.32 17.57 9.46 0.00P-DP 28.61GERDES UNIT 6H - 6H 22.99 0.65 185.35 102.21 4.08 1.48 0.00 135.75 27.26 13.34 0.00P-DP 50.00GERDES-LANGHOFF 1L - 1L 35.68 1.00 199.02 109.76 4.51 1.57 0.00 143.91 30.08 14.35 0.00P-DP 50.00GERDES-RATHKAMP 1L - 1L 39.37 1.11 0.16 0.11 0.01 0.00 0.00 0.00 0.07 0.02 0.00P-DP 8.24HOERMANN UNIT 1H - 1H 0.10 0.00 22.43 13.81 0.40 0.20 0.00 17.94 2.70 1.74 0.00P-DP 33.91HOERMANN UNIT 2H - 2H 3.53 0.10 135.46 72.38 2.54 1.17 0.00 107.13 16.94 10.79 0.00P-DP 50.00HOERMANN UNIT 3H - 3H 22.17 0.62 122.10 67.04 1.92 1.12 0.00 102.00 12.84 9.55 0.00P-DP 37.61HOERMANN UNIT 4H - 4H 16.81 0.47 2.31 1.88 0.00 0.03 0.00 2.48 0.00 0.16 0.00P-DP 4.85JANAK UNIT 1H - 1H 0.00 0.00 43.29 24.56 0.63 0.40 0.00 36.91 4.19 3.29 0.00P-DP 29.13JANAK UNIT 3H - 3H 5.49 0.15 69.47 37.59 1.71 0.53 0.00 48.71 11.43 5.62 0.00P-DP 49.70JANAK UNIT 4H - 4H 14.95 0.42 60.01 29.85 1.74 0.42 0.00 38.13 11.64 4.99 0.00P-DP 50.00JANAK UNIT 5H - 5H 15.23 0.43 57.38 35.87 1.46 0.43 0.00 39.03 9.75 4.17 0.00P-DP 35.39JANAK UNIT 7L - 7L 12.76 0.36 58.49 35.52 1.34 0.46 0.00 42.09 8.94 4.24 0.00P-DP 48.53JANAK-LOOS 6L - 6L 11.70 0.33 19.87 11.03 0.55 0.14 0.00 12.99 3.68 1.63 0.00P-DP 30.41KAISER UNIT 1H - 1H 4.82 0.14 60.28 32.33 2.58 0.28 0.00 25.79 17.21 5.25 0.00P-DP 50.00KAISER UNIT 4H - 4H 22.53 0.63

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![](exhibit992-202210xk012.jpg)

Economic One-Liners Lease Name Life (years) Oil (Mbbl) Residue Gas (MMcf) Residue Gas (M$) Other (M$) Expense & Tax (M$) Invest. (M$) Non-Disc. (M$) Cash FlowNet Sales Volumes Net Revenue As of Date: 1/1/2023 Reserve Category Oil (M$) Disc. 10% (M$) NGL (M$) NGL (Mbbl) TABLE 6 59.89 28.97 1.54 0.45 0.00 41.08 10.26 4.87 0.00P-DP 50.00KAISER UNIT 5H - 5H 13.42 0.38 25.78 13.03 1.82 0.00 0.00 0.44 12.14 2.69 0.00P-DP 50.00LANGHOFF UNIT A 1H - 1H 15.89 0.45 4.72 3.33 0.11 0.04 0.00 3.44 0.72 0.37 0.00P-DP 13.98LANGHOFF UNIT A 2H - 2H 0.94 0.03 7.02 4.21 0.34 0.03 0.00 2.47 2.24 0.63 0.00P-DP 33.71LANGHOFF UNIT A 3H - 3H 2.93 0.08 5.11 3.26 0.26 0.02 0.00 1.55 1.74 0.45 0.00P-DP 27.80LANGHOFF UNIT A 4H - 4H 2.27 0.06 81.32 48.32 2.36 0.56 0.00 50.82 15.77 5.92 0.00P-DP 50.00LANGHOFF UNIT A 8L - 8L 20.64 0.58 67.13 39.15 2.01 0.45 0.00 41.03 13.42 4.89 0.00P-DP 50.00LANGHOFF UNIT A 9L - 9L 17.57 0.49 20.63 12.51 0.68 0.13 0.00 11.59 4.57 1.51 0.00P-DP 50.00LANGHOFF UNIT B 701 - 701 5.98 0.17 8.24 6.07 0.09 0.08 0.00 7.40 0.62 0.59 0.00P-DP 12.02LOOS UNIT 10H - 10H 0.81 0.02 132.58 75.83 3.41 0.98 0.00 89.56 22.79 9.59 0.00P-DP 50.00LOOS UNIT 11L - 11L 29.82 0.84 121.80 68.45 3.52 0.84 0.00 76.36 23.50 8.83 0.00P-DP 50.00LOOS UNIT 12L - 12L 30.76 0.86 5.06 3.63 0.26 0.02 0.00 1.58 1.71 0.47 0.00P-DP 11.03LOOS UNIT 1H - 1H 2.24 0.06 9.91 5.50 0.25 0.07 0.00 6.72 1.69 0.72 0.00P-DP 28.33LOOS UNIT 8H - 8H 2.21 0.06 106.88 59.88 1.87 0.94 0.00 85.79 12.46 7.67 0.00P-DP 50.00LOOS UNIT 9H - 9H 16.30 0.46 25.67 13.39 0.35 0.24 0.00 22.21 2.34 1.95 0.00P-DP 39.83POTH UNIT 1H - 1H 3.07 0.09 10.25 5.85 0.22 0.08 0.00 7.71 1.45 0.80 0.00P-DP 28.13RATHKAMP UNIT 1H - 1H 1.89 0.05 12.84 7.49 0.35 0.09 0.00 8.45 2.36 1.05 0.00P-DP 38.34RATHKAMP UNIT 3H - 3H 3.09 0.09 21.29 10.59 0.95 0.09 0.00 8.53 6.35 1.90 0.00P-DP 50.00RATHKAMP UNIT 4H - 4H 8.31 0.23 0.39 0.34 0.00 0.00 0.00 0.42 0.00 0.03 0.00P-DP 3.60BLACK, S.E. 42 1 - 1 0.00 0.00 4.80 2.20 0.24 0.03 0.00 2.65 1.41 0.75 0.00P-DP 28.98BOYD, FANNIE 4 - 4 1.49 0.04 3.89 1.95 0.19 0.02 0.00 2.19 1.11 0.60 0.00P-DP 24.34BOYD, FANNIE 5 - 5 1.18 0.03 0.90 0.64 0.09 0.00 0.00 0.00 0.54 0.22 0.00P-DP 9.00BOYD, FANNIE 8 - 8 0.57 0.02 3.57 2.13 0.14 0.03 0.00 2.40 0.80 0.49 0.00P-DP 29.29HULING 'A' 18-7 ESL (ALLOC) 1HA - 1HA 0.85 0.03 0.93 0.61 0.03 0.01 0.00 0.72 0.16 0.11 0.00P-DP 17.24HULING 'D' 18-7 ESL (ALLOC) 4HS - 4HS 0.17 0.01 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00P-DP 0.00SPRABERRY DRIVER UNIT 478 - 478 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00P-DP 0.00SPRABERRY DRIVER UNIT 479 - 479 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00P-DP 0.00SPRABERRY DRIVER UNIT 480 - 480 0.00 0.00 70.12 41.96 1.11 0.68 0.00 63.88 6.45 7.04 0.00P-DP 45.24STONE-GIST W45A 1H - 1H 6.83 0.20 60.74 37.32 1.08 0.58 0.00 54.20 6.22 6.27 0.00P-DP 42.75STONE-GIST W45B 2H - 2H 6.59 0.20 64.86 40.37 0.85 0.65 0.00 60.91 4.94 6.23 0.00P-DP 43.95STONE-GIST W45C 3H - 3H 5.23 0.16 33.10 19.33 0.59 0.31 0.00 29.45 3.44 3.43 0.00P-DP 38.05STONE-GIST W45I 9H - 9H 3.64 0.11 80.59 45.95 1.08 0.81 0.00 75.52 6.23 7.76 0.00P-DP 45.66STONE-GIST W45J 10H - 10H 6.60 0.20 2,480.08 1,482.16 395.20 0.00 0.00 0.00 2,588.06 1,395.72 0.00P-DP 45.31BUELL 10-11-5 10H - 10H 1,287.74 31.97 179.44 104.37 28.41 0.01 0.00 1.29 186.07 100.50 0.00P-DP 33.50BUELL 10-11-5 1H - 1H 92.58 2.30 2,595.61 1,444.64 413.54 0.01 0.00 0.53 2,708.14 1,460.54 0.00P-DP 50.00BUELL 10-11-5 206H - 206H 1,347.49 33.45

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![](exhibit992-202210xk013.jpg)

Economic One-Liners Lease Name Life (years) Oil (Mbbl) Residue Gas (MMcf) Residue Gas (M$) Other (M$) Expense & Tax (M$) Invest. (M$) Non-Disc. (M$) Cash FlowNet Sales Volumes Net Revenue As of Date: 1/1/2023 Reserve Category Oil (M$) Disc. 10% (M$) NGL (M$) NGL (Mbbl) TABLE 6 3,133.73 1,783.31 499.05 0.03 0.00 2.20 3,268.14 1,762.74 0.00P-DP 49.51BUELL 10-11-5 210H - 210H 1,626.13 40.37 118.20 73.98 18.63 0.02 0.00 1.44 122.02 65.97 0.00P-DP 26.30BUELL 10-11-5 2H - 2H 60.71 1.51 156.43 93.05 24.81 0.01 0.00 0.85 162.46 87.71 0.00P-DP 31.38BUELL 10-11-5 3H - 3H 80.84 2.01 235.54 132.98 37.07 0.04 0.00 3.28 242.77 131.31 0.00P-DP 34.99BUELL 10-11-5 4H - 4H 120.80 3.00 1,076.67 669.79 171.57 0.00 0.00 0.00 1,123.54 605.92 0.00P-DP 42.79BUELL 10-11-5 6H - 6H 559.04 13.88 532.11 329.52 81.61 0.02 0.00 1.62 534.44 269.86 0.00P-DP 50.00HOCHSTETLER 7-11-5 5H - 5H 265.92 6.60 498.33 278.50 77.54 0.15 0.00 13.29 507.79 275.41 0.00P-DP 37.69MATTIE 18-11-5 6H - 6H 252.66 6.27 409.72 228.06 64.60 0.06 0.00 4.88 423.07 228.73 0.00P-DP 36.36MATTIE 18-11-5 7H - 7H 210.51 5.23 557.45 300.49 87.51 0.11 0.00 9.37 573.09 310.17 0.00P-DP 40.56MATTIE 18-11-5 8H - 8H 285.15 7.08 125.69 68.82 19.63 0.03 0.00 2.86 128.53 69.65 0.00P-DP 34.51NM HARRISON 16-11-5 10H - 10H 63.95 1.59 101.54 56.44 15.75 0.04 0.00 3.03 103.17 55.99 0.00P-DP 31.91NM HARRISON 16-11-5 6H - 6H 51.33 1.27 93.81 51.51 14.92 0.00 0.00 0.23 97.68 52.71 0.00P-DP 31.94NM HARRISON 16-11-5 8H - 8H 48.60 1.21 714.68 400.34 113.73 0.01 0.00 1.06 744.81 401.80 0.00P-DP 25.64NORTH AMERICAN COAL ROYALTY CO BUELL 1 - 1 370.60 9.20 649.43 361.28 102.88 0.05 0.00 4.29 673.75 363.85 0.00P-DP 33.83NORTH AMERICAN COAL ROYALTY CO BUELL 8H - 8H 335.24 8.32 1,168.19 698.44 186.15 0.00 0.00 0.00 1,219.05 657.43 0.00P-DP 40.11SADIE 33-10-4 1H - 1H 606.56 15.06 1,503.03 870.94 239.51 0.00 0.00 0.00 1,568.47 845.86 0.00P-DP 43.89SADIE 33-10-4 201H - 201H 780.42 19.38 212.67 130.99 33.89 0.00 0.00 0.00 221.93 119.69 0.00P-DP 42.04SADIE 33-10-4 205H - 205H 110.43 2.74 701.87 423.28 111.84 0.00 0.00 0.00 732.43 394.99 0.00P-DP 41.79SADIE 33-10-4 3H - 3H 364.43 9.05 671.23 383.94 106.96 0.00 0.00 0.00 700.45 377.75 0.00P-DP 44.48SADIE 33-10-4 5H - 5H 348.52 8.65 6.17 3.99 0.09 0.06 0.00 5.57 0.49 0.73 0.00P-DP 31.49ALLRED UNIT B 08-05 5AH - 5AH 0.84 0.02 3.26 2.21 0.16 0.02 0.00 1.43 0.93 0.68 0.00P-DP 16.63ALLRED UNIT B 08-05 5BH - 5BH 1.59 0.03 9.04 5.35 0.25 0.07 0.00 6.53 1.44 1.39 0.00P-DP 42.00ALLRED UNIT B 08-05 5MH - 5MH 2.46 0.05 8.64 5.16 0.19 0.07 0.00 6.84 1.12 1.21 0.00P-DP 41.30ALLRED UNIT B 08-05 5SH - 5SH 1.90 0.04 13.06 7.76 0.27 0.12 0.00 10.65 1.54 1.77 0.00P-DP 46.07ALLRED UNIT B 08-05 6AH - 6AH 2.63 0.06 9.15 5.48 0.15 0.08 0.00 7.80 0.88 1.04 0.00P-DP 37.62ALLRED UNIT B 08-05 6MH - 6MH 1.51 0.03 10.52 6.07 0.32 0.08 0.00 7.02 1.83 1.45 0.00P-DP 46.00ALLRED UNIT B 08-05 6SH - 6SH 3.12 0.07 10.05 5.95 0.28 0.08 0.00 7.20 1.63 1.56 0.00P-DP 43.18ALLRED UNIT B 08-05 7AH - 7AH 2.78 0.06 7.77 4.57 0.34 0.04 0.00 4.05 1.93 1.50 0.00P-DP 37.91ALLRED UNIT B 08-05 7BH - 7BH 3.29 0.07 6.28 3.96 0.05 0.07 0.00 6.14 0.29 0.65 0.00P-DP 33.26ALLRED UNIT B 08-05 8AH - 8AH 0.50 0.01 3.56 2.27 0.06 0.03 0.00 3.04 0.36 0.46 0.00P-DP 26.42ALLRED UNIT B 08-05 8SH - 8SH 0.62 0.01 59.52 37.38 2.36 0.37 0.00 33.87 13.51 10.93 0.00P-DP 29.08ARON 41-32 #1AH - 1AH 23.07 0.50 82.48 49.53 1.67 0.73 0.00 67.69 9.56 11.10 0.00P-DP 35.79ARON 41-32 #2SH - 2SH 16.32 0.36 84.00 49.48 0.49 0.92 0.00 84.62 2.81 8.24 0.00P-DP 35.79ARON 41-32 #3AH - 3AH 4.81 0.10 38.98 25.06 0.07 0.45 0.00 41.26 0.43 3.43 0.00P-DP 25.37ARON 41-32 #3SH - 3SH 0.73 0.02 0.36 0.25 0.00 0.00 0.00 0.39 0.00 0.03 0.00P-DP 9.66BAKER TRUST 1 - 1 0.00 0.00

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![](exhibit992-202210xk014.jpg)

Economic One-Liners Lease Name Life (years) Oil (Mbbl) Residue Gas (MMcf) Residue Gas (M$) Other (M$) Expense & Tax (M$) Invest. (M$) Non-Disc. (M$) Cash FlowNet Sales Volumes Net Revenue As of Date: 1/1/2023 Reserve Category Oil (M$) Disc. 10% (M$) NGL (M$) NGL (Mbbl) TABLE 6 0.07 0.06 0.00 0.00 0.00 0.06 0.01 0.01 0.00P-DP 5.01BIG EL 45-04 #1AH - 1AH 0.01 0.00 0.09 0.07 0.00 0.00 0.00 0.07 0.01 0.01 0.00P-DP 4.59BIG EL 45-04 #1SH - 1SH 0.02 0.00 19.59 16.09 1.56 0.01 0.00 1.00 8.92 5.58 0.00P-DP 4.68BRUT 40-33 #1AH - 1AH 15.24 0.33 0.67 0.50 0.00 0.01 0.00 0.71 0.00 0.06 0.00P-DP 7.17CATES 24 1 - 1 0.01 0.00 23.63 13.73 0.57 0.20 0.00 18.23 3.25 3.40 0.00P-DP 47.91CHAPARRAL UNIT A1 15SH - 15SH 5.55 0.12 23.39 13.94 0.20 0.25 0.00 22.71 1.16 2.46 0.00P-DP 45.89CHAPARRAL UNIT A1 21H - 21H 1.98 0.04 28.81 17.34 0.38 0.28 0.00 26.29 2.17 3.36 0.00P-DP 45.89CHAPARRAL UNIT A1 8AH - 8AH 3.71 0.08 226.68 137.52 4.11 2.08 0.00 192.31 23.50 29.27 0.00P-DP 50.00CLARICE STARLING SUNDOWN B 4521LS - 4521LS 40.14 0.87 185.02 109.84 4.41 1.55 0.00 143.19 25.26 26.58 0.00P-DP 50.00CLARICE STARLING SUNDOWN D 4542WA - 4542WA 43.15 0.94 0.67 0.38 0.00 0.01 0.00 0.66 0.03 0.07 0.00P-DP 30.82COLE 36-37 A UNIT A 2H - A 2H 0.05 0.00 60.56 36.87 1.46 0.50 0.00 46.63 8.38 8.75 0.00P-DP 32.32CRAZY CAT 41-32 #1SH - 1SH 14.31 0.31 32.16 20.04 0.96 0.24 0.00 22.36 5.51 5.12 0.00P-DP 25.43CRAZY CAT 41-32 #2AH - 2AH 9.41 0.21 100.55 60.87 3.25 0.72 0.00 66.83 18.58 16.59 0.00P-DP 37.40CRAZY CAT 41-32 #3SH - 3SH 31.74 0.69 45.52 27.67 0.83 0.42 0.00 38.56 4.74 5.89 0.00P-DP 29.08CRAZY CAT 41-32 #4AH - 4AH 8.10 0.18 1.68 0.92 0.00 0.02 0.00 1.82 0.00 0.14 0.00P-DP 22.18EAST B.C. CANYON 1 - 1 0.00 0.00 16.86 10.21 0.33 0.15 0.00 13.96 1.90 2.24 0.00P-DP 38.60GRANT 18A 4HL - 4HL 3.24 0.07 12.19 7.03 0.28 0.10 0.00 9.60 1.59 1.72 0.00P-DP 39.87GRANT 18B 5HJ - 5HJ 2.72 0.06 15.71 8.70 0.37 0.13 0.00 12.19 2.13 2.25 0.00P-DP 43.98GRANT 18B 6HK - 6HK 3.64 0.08 0.64 0.43 0.02 0.00 0.00 0.37 0.14 0.10 0.00P-DP 11.22GUITAR 11 1 - 1 0.23 0.01 0.01 0.01 0.00 0.00 0.00 0.02 0.00 0.00 0.00P-DP 0.52GUITAR 11 2 - 2 0.00 0.00 0.86 0.64 0.03 0.01 0.00 0.56 0.16 0.12 0.00P-DP 10.19GUITAR 13 1 - 1 0.27 0.01 5.59 3.19 0.02 0.06 0.00 5.81 0.11 0.51 0.00P-DP 43.40GUNSLINGER UNIT L 4H - L 4H 0.18 0.00 1.21 0.61 0.00 0.01 0.00 1.26 0.02 0.11 0.00P-DP 29.55HALL 18 1 - 1 0.03 0.00 0.69 0.37 0.00 0.01 0.00 0.75 0.00 0.06 0.00P-DP 23.41HALL 18 2 - 2 0.00 0.00 0.44 0.25 0.00 0.01 0.00 0.47 0.00 0.04 0.00P-DP 18.89HALL 18 3 - 3 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00P-DP 0.39HALL 18 4 - 4 0.00 0.00 26.86 15.09 0.33 0.27 0.00 24.63 1.87 2.85 0.00P-DP 49.00KINGSLEY 10HK - 10HK 3.20 0.07 32.79 18.17 0.42 0.33 0.00 30.06 2.41 3.79 0.00P-DP 46.42KINGSLEY 1HJ - 1HJ 4.11 0.09 29.94 17.18 0.48 0.28 0.00 26.22 2.74 3.70 0.00P-DP 44.61KINGSLEY 2HF - 2HF 4.68 0.10 32.60 20.90 0.41 0.32 0.00 29.80 2.32 3.47 0.00P-DP 43.84KINGSLEY 3HK - 3HK 3.96 0.09 85.24 48.88 0.90 0.87 0.00 80.06 5.16 8.79 0.00P-DP 45.50KINGSLEY 4HJ - 4HJ 8.82 0.19 105.54 58.01 0.87 1.11 0.00 102.55 4.97 10.45 0.00P-DP 49.95KINGSLEY 5HK - 5HK 8.48 0.18 79.12 44.16 1.33 0.73 0.00 67.58 7.59 9.02 0.00P-DP 47.14KINGSLEY 6HF - 6HF 12.97 0.28 25.46 14.41 0.31 0.25 0.00 23.36 1.77 2.70 0.00P-DP 47.98KINGSLEY 7HJ - 7HJ 3.02 0.07 22.32 12.65 0.47 0.19 0.00 17.75 2.69 2.71 0.00P-DP 45.09KINGSLEY 8HK - 8HK 4.59 0.10

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![](exhibit992-202210xk015.jpg)

Economic One-Liners Lease Name Life (years) Oil (Mbbl) Residue Gas (MMcf) Residue Gas (M$) Other (M$) Expense & Tax (M$) Invest. (M$) Non-Disc. (M$) Cash FlowNet Sales Volumes Net Revenue As of Date: 1/1/2023 Reserve Category Oil (M$) Disc. 10% (M$) NGL (M$) NGL (Mbbl) TABLE 6 20.96 11.92 0.24 0.21 0.00 19.40 1.39 2.20 0.00P-DP 45.54KINGSLEY 9HJ - 9HJ 2.37 0.05 11.76 7.21 0.31 0.09 0.00 8.76 1.75 1.75 0.00P-DP 39.30KRAKEN 10-3 E1 251 - 251 3.00 0.07 25.33 15.46 0.59 0.21 0.00 19.43 3.35 3.17 0.00P-DP 44.43KRAKEN 10-3 UNIT 2 153 - 153 5.72 0.12 40.52 22.69 0.90 0.34 0.00 31.57 5.15 5.01 0.00P-DP 50.00KRAKEN 10-3 UNIT 2 162 - 162 8.80 0.19 33.19 19.29 0.73 0.28 0.00 25.99 4.17 4.08 0.00P-DP 48.91KRAKEN 10-3 UNIT 2 171 - 171 7.12 0.16 7.24 4.53 0.06 0.08 0.00 7.12 0.32 0.74 0.00P-DP 29.50KRAKEN 10-3 UNIT 2 252 - 252 0.54 0.01 25.19 14.71 0.56 0.21 0.00 19.66 3.19 3.11 0.00P-DP 45.64KRAKEN 10-3 UNIT 2 261 - 261 5.44 0.12 28.64 16.72 0.69 0.23 0.00 21.52 3.97 3.64 0.00P-DP 47.11KRAKEN 10-3 UNIT 2 272 - 272 6.79 0.15 1.05 0.74 0.00 0.01 0.00 1.14 0.00 0.09 0.00P-DP 10.38LONG 18 1 - 1 0.00 0.00 0.15 0.10 0.00 0.00 0.00 0.14 0.01 0.02 0.00P-DP 43.23MABEE DDA J8 3HK - 3HK 0.02 0.00 0.20 0.14 0.01 0.00 0.00 0.14 0.03 0.03 0.00P-DP 11.43MEADOR, J. J. 3 - 3 0.06 0.00 3.47 1.94 0.10 0.03 0.00 2.45 0.55 0.46 0.00P-DP 25.71MIDDLETON 21 1 - 1 0.93 0.02 11.26 6.32 0.33 0.09 0.00 7.96 1.87 1.76 0.00P-DP 31.88NEWTON 43A 1HE - 1HE 3.20 0.07 7.16 3.88 0.05 0.08 0.00 7.05 0.31 0.73 0.00P-DP 31.30NEWTON 43A 2HK - 2HK 0.54 0.01 0.44 0.32 0.01 0.00 0.00 0.30 0.08 0.07 0.00P-DP 8.94NEWTON 43B 3HJ - 3HJ 0.14 0.00 0.46 0.36 0.01 0.00 0.00 0.31 0.08 0.06 0.00P-DP 6.79NEWTON 43B 4HE - 4HE 0.14 0.00 0.65 0.50 0.01 0.01 0.00 0.57 0.06 0.07 0.00P-DP 8.38NEWTON 43B 5HK - 5HK 0.10 0.00 1.42 0.79 0.05 0.01 0.00 0.91 0.26 0.20 0.00P-DP 18.77NEWTON 43BK 4HE - 4HE 0.44 0.01 1.89 1.03 0.03 0.02 0.00 1.59 0.19 0.22 0.00P-DP 21.24NEWTON 43BK 5HK - 5HK 0.33 0.01 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00P-DP 30.33NEWTON 43C 6HJ - 6HJ 0.00 0.00 3.67 2.09 0.00 0.04 0.00 3.98 0.00 0.31 0.00P-DP 28.83PHILLIPS 7 1 - 1 0.00 0.00 1.02 0.59 0.00 0.01 0.00 1.10 0.00 0.09 0.00P-DP 17.84RINGNECK DOVE 3 - 3 0.00 0.00 213.87 114.05 3.84 1.97 0.00 181.84 22.00 27.54 0.00P-DP 44.78RISING SUN 40-33 #1AH - 1AH 37.57 0.82 323.49 200.21 1.31 3.61 0.00 333.42 7.50 30.25 0.00P-DP 50.00SIMPSON SMITH 0844 A 1W - 1WH 12.82 0.28 44.92 29.09 0.28 0.49 0.00 44.96 1.63 4.46 0.00P-DP 27.34SUNDOWN 4524LS - 4524LS 2.79 0.06 407.87 243.32 7.53 3.72 0.00 344.21 43.09 53.03 0.00P-DP 50.00SUNDOWN 4541WA - 4541WA 73.60 1.60 31.69 26.82 0.15 0.35 0.00 32.36 0.87 3.02 0.00P-DP 5.12SUNDOWN 4566WB - 4566WB 1.48 0.03 5.81 3.22 0.13 0.05 0.00 4.59 0.75 0.82 0.00P-DP 44.87THE KING 45-04 #1AH - 1AH 1.28 0.03 3.06 1.84 0.05 0.03 0.00 2.72 0.26 0.37 0.00P-DP 34.06THE KING 45-04 #1SH - 1SH 0.45 0.01 267.07 160.46 2.20 2.82 0.00 260.81 12.58 27.80 0.00P-DP 35.97TISH 46-03 #1AH - 1AH 21.48 0.47 165.09 99.67 3.09 1.50 0.00 138.80 17.67 21.57 0.00P-DP 43.43TOMCAT 4448WA - 4448WA 30.19 0.66 9.98 5.88 0.27 0.08 0.00 7.25 1.57 1.53 0.00P-DP 31.15TREE FROG 47 EAST A 1LS - 1LS 2.69 0.06 15.55 9.29 0.30 0.14 0.00 12.99 1.70 2.05 0.00P-DP 36.55TREE FROG 47 EAST A 1WA - 1WA 2.90 0.06 15.15 8.95 0.31 0.13 0.00 12.45 1.75 2.03 0.00P-DP 37.56TREE FROG 47 EAST C 3LS - 3LS 2.98 0.06 21.39 12.42 0.54 0.18 0.00 16.23 3.06 3.13 0.00P-DP 40.89TREE FROG 47 EAST C 3WA - 3WA 5.23 0.11

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![](exhibit992-202210xk016.jpg)

Economic One-Liners Lease Name Life (years) Oil (Mbbl) Residue Gas (MMcf) Residue Gas (M$) Other (M$) Expense & Tax (M$) Invest. (M$) Non-Disc. (M$) Cash FlowNet Sales Volumes Net Revenue As of Date: 1/1/2023 Reserve Category Oil (M$) Disc. 10% (M$) NGL (M$) NGL (Mbbl) TABLE 6 13.35 7.94 0.22 0.13 0.00 11.63 1.25 1.66 0.00P-DP 36.92TREE FROG 47 EAST C 3WB - 3WB 2.13 0.05 12.29 7.16 0.11 0.13 0.00 11.92 0.61 1.29 0.00P-DP 36.97TREE FROG 47 WEST UNIT 5LS - 5LS 1.05 0.02 18.91 11.20 0.23 0.19 0.00 17.46 1.33 2.16 0.00P-DP 40.66TREE FROG 47 WEST UNIT 5WA - 5WA 2.28 0.05 14.80 8.71 0.18 0.15 0.00 13.73 1.02 1.68 0.00P-DP 38.00TREE FROG 47 WEST UNIT 5WB - 5WB 1.74 0.04 11.75 7.66 0.30 0.10 0.00 8.89 1.69 1.73 0.00P-DP 35.46TREE FROG 47 WEST UNIT 7LS - 7LS 2.89 0.06 25.21 15.51 0.77 0.19 0.00 17.27 4.43 4.06 0.00P-DP 45.71TREE FROG 47 WEST UNIT 7WA - 7WA 7.57 0.16 85.22 49.26 3.16 0.56 0.00 51.34 18.09 15.10 0.00P-DP 39.64URSULA 0848WA - 0848WA 30.89 0.67 55.30 36.25 0.66 0.56 0.00 51.36 3.78 6.28 0.00P-DP 34.37URSULA 1546WA - 1546WA 6.45 0.14 24.79 16.70 0.33 0.24 0.00 22.62 1.87 2.89 0.00P-DP 36.50URSULA BIG DADDY B 1527LS - 1527LS 3.19 0.07 25.29 15.95 0.32 0.25 0.00 23.29 1.81 2.91 0.00P-DP 39.96URSULA BIG DADDY B 1547WA - 1547WA 3.09 0.07 61.09 38.67 1.17 0.55 0.00 51.04 6.68 8.04 0.00P-DP 47.48URSULA BIG DADDY C 1528LS - 1528LS 11.41 0.25 171.59 107.46 2.36 1.68 0.00 155.22 13.53 20.27 0.00P-DP 44.34URSULA TOMCAT A 4446WA - 4446WA 23.11 0.50 137.55 83.43 1.65 1.38 0.00 127.54 9.47 15.64 0.00P-DP 42.54URSULA TOMCAT B 4421LS - 4421LS 16.18 0.35 285.57 160.05 5.13 2.63 0.00 242.81 29.37 36.77 0.00P-DP 50.00URSULA TOMCAT C 4447WA - 4447WA 50.17 1.09 115.14 69.08 1.18 1.18 0.00 109.37 6.78 12.59 0.00P-DP 45.46VIPER FOSTER B 4545WA - 4545WA 11.58 0.25 135.19 79.10 2.44 1.24 0.00 114.87 13.94 17.42 0.00P-DP 49.43VIPER FOSTER C 4525LS - 4525LS 23.81 0.52 139.69 82.14 2.31 1.31 0.00 121.35 13.23 17.49 0.00P-DP 49.33VIPER FOSTER D 4546WA - 4546WA 22.60 0.49 35.49 20.26 0.32 0.37 0.00 34.35 1.81 3.75 0.00P-DP 44.42WARD 18CC 1804D - 1804D 3.08 0.07 10.83 6.76 0.08 0.12 0.00 10.65 0.48 1.11 0.00P-DP 31.09WARD 18D 1803D - 1803D 0.82 0.02 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00P-DP 0.00ALEX TAMSULA 2 - 2 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00P-DP 0.00ALEX TAMSULA 3 - 3 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00P-DP 0.00ALEX TAMSULA 4 - 4 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00P-DP 0.00BONACCI 1 - 1 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00P-DP 0.00BONACCI 2 - 2 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00P-DP 0.00CHARLES ADAMCHICK 4 - 4 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00P-DP 0.00CHARLES ADAMCHICK 5 - 5 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00P-DP 0.00CHARLES ADAMCHICK 7 - 7 0.00 0.00 9.09 6.91 2.04 0.00 0.00 0.00 9.88 0.79 0.00P-DP 6.98CLAWSON 1 - 1 0.00 0.00 21.63 14.36 4.87 0.00 0.00 0.00 23.51 1.88 0.00P-DP 12.11CLAWSON 3 - 3 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00P-DP 0.00DANIEL D & EDNA MILLER 1 - 1 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00P-DP 0.00DAVID L BONACCI 0031 - 0031 0.00 0.00 200.97 109.13 45.21 0.00 0.00 0.00 218.44 17.48 0.00P-DP 31.01GENFIVE ENERGY LLC UNIT 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00P-DP 0.00L E STARTZELL 2 - 2 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00P-DP 0.00N A C R C 1-15 ACRES 1 - 1 0.00 0.00 0.32 0.31 0.07 0.00 0.00 0.00 0.34 0.03 0.00P-DP 0.35N A C R C 5-132 - 5-132 0.00 0.00

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![](exhibit992-202210xk017.jpg)

Economic One-Liners Lease Name Life (years) Oil (Mbbl) Residue Gas (MMcf) Residue Gas (M$) Other (M$) Expense & Tax (M$) Invest. (M$) Non-Disc. (M$) Cash FlowNet Sales Volumes Net Revenue As of Date: 1/1/2023 Reserve Category Oil (M$) Disc. 10% (M$) NGL (M$) NGL (Mbbl) TABLE 6 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00P-DP 0.00NORTH AMERICAN COAL 1S - 1S 0.00 0.00 21.58 12.96 4.40 0.00 0.00 0.00 28.25 6.66 0.00P-DP 50.00AMBER NE WEL JF 3H - 3H 0.00 0.00 29.26 17.64 5.96 0.00 0.00 0.00 38.30 9.03 0.00P-DP 50.00AMBER NW WEL JF 1H - 1H 0.00 0.00 318.21 210.24 64.85 0.00 0.00 0.00 416.42 98.21 0.00P-DP 31.32ARCHIE E WYN JF 6H - 6H 0.00 0.00 255.07 178.20 51.98 0.00 0.00 0.00 333.79 78.72 0.00P-DP 26.76ARCHIE E WYN JF 8H - 8H 0.00 0.00 1,910.31 1,134.09 389.30 0.00 0.00 0.00 2,499.91 589.60 0.00P-DP 50.00ATHENA N SMF JF 3H - 3H 0.00 0.00 2,512.58 1,487.54 512.03 0.00 0.00 0.00 3,288.06 775.48 0.00P-DP 50.00ATHENA NE SMF JF 5H - 5H 0.00 0.00 3,463.63 2,041.59 705.84 0.00 0.00 0.00 4,532.64 1,069.01 0.00P-DP 50.00ATHENA NE SMF JF 7H - 7H 0.00 0.00 1,784.45 1,088.99 363.65 0.00 0.00 0.00 2,335.20 550.75 0.00P-DP 50.00ATHENA NW SMF JF 1H - 1H 0.00 0.00 2,352.06 1,255.30 479.32 0.00 0.00 0.00 3,077.99 725.94 0.00P-DP 49.75BATES S CRC JF 5H - 5H 0.00 0.00 192.09 130.37 39.15 0.00 0.00 0.00 251.38 59.29 0.00P-DP 27.85BORUM E SMF JF 4H - 4H 0.00 0.00 274.75 164.47 55.99 0.00 0.00 0.00 359.55 84.80 0.00P-DP 37.79BORUM E SMF JF 6H - 6H 0.00 0.00 13.33 8.04 2.72 0.00 0.00 0.00 17.44 4.11 0.00P-DP 34.98BORUM W SMF JF 2H - 2H 0.00 0.00 1,201.50 779.54 244.85 0.00 0.00 0.00 1,572.33 370.83 0.00P-DP 38.33CENA WYN JF 2H - 2H 0.00 0.00 666.93 466.33 135.91 0.00 0.00 0.00 872.77 205.84 0.00P-DP 28.93CENA WYN JF 4H - 4H 0.00 0.00 1,266.36 797.61 258.07 0.00 0.00 0.00 1,657.20 390.85 0.00P-DP 35.36COLLINS WYN JF 2H - 2H 0.00 0.00 1,610.49 977.12 328.20 0.00 0.00 0.00 2,107.56 497.06 0.00P-DP 39.25COLLINS WYN JF 4H - 4H 0.00 0.00 683.97 466.06 139.38 0.00 0.00 0.00 895.07 211.10 0.00P-DP 26.11COLLINS WYN JF 6H - 6H 0.00 0.00 1,623.62 875.34 330.87 0.00 0.00 0.00 2,124.73 501.11 0.00P-DP 40.87CROSS CREEK A 5H-20 - 5H-20 0.00 0.00 1,631.99 1,112.32 332.58 0.00 0.00 0.00 2,135.69 503.70 0.00P-DP 33.01DICKSON CRC JF 1H - 1H 0.00 0.00 1,043.97 689.24 212.75 0.00 0.00 0.00 1,366.18 322.21 0.00P-DP 29.74DICKSON CRC JF 3H - 3H 0.00 0.00 330.05 189.43 67.26 0.00 0.00 0.00 431.91 101.86 0.00P-DP 50.00DOYEN NE WEL JF 3H - 3H 0.00 0.00 15.08 8.58 3.07 0.00 0.00 0.00 19.74 4.66 0.00P-DP 50.00DOYEN NW WEL JF 1H - 1H 0.00 0.00 784.36 483.69 159.84 0.00 0.00 0.00 1,026.45 242.08 0.00P-DP 34.09GORDON SE CRC JF 4H - 4H 0.00 0.00 891.17 545.65 181.61 0.00 0.00 0.00 1,166.21 275.05 0.00P-DP 35.68GORDON SE CRC JF 6H - 6H 0.00 0.00 847.06 521.09 172.62 0.00 0.00 0.00 1,108.49 261.43 0.00P-DP 33.45GORDON SW CRC JF 2H - 2H 0.00 0.00 498.33 314.91 101.55 0.00 0.00 0.00 652.14 153.81 0.00P-DP 36.33GRISWOLD S WYN JF 4H - 4H 0.00 0.00 131.22 83.73 26.74 0.00 0.00 0.00 171.73 40.50 0.00P-DP 36.18GRISWOLD SW WYN JF 2H - 2H 0.00 0.00 521.42 356.30 106.26 0.00 0.00 0.00 682.34 160.93 0.00P-DP 26.31GRISWOLD WYN JF 6H - 6H 0.00 0.00 854.94 523.13 174.23 0.00 0.00 0.00 1,118.81 263.87 0.00P-DP 35.43GRISWOLD WYN JF 8H - 8H 0.00 0.00 277.95 185.04 56.64 0.00 0.00 0.00 363.74 85.79 0.00P-DP 33.76MINGO S CRC JF 4H - 4H 0.00 0.00 780.91 483.16 159.14 0.00 0.00 0.00 1,021.92 241.02 0.00P-DP 40.50MINGO SE CRC JF 6H - 6H 0.00 0.00 117.91 79.02 24.03 0.00 0.00 0.00 154.30 36.39 0.00P-DP 32.79MINGO SW CRC JF 2H - 2H 0.00 0.00 405.15 263.31 82.56 0.00 0.00 0.00 530.19 125.04 0.00P-DP 31.61MINGO W CRC JF 8H - 8H 0.00 0.00 476.48 264.64 97.10 0.00 0.00 0.00 623.54 147.06 0.00P-DP 27.33NAC 3H-20 - 3H-20 0.00 0.00

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![](exhibit992-202210xk018.jpg)

Economic One-Liners Lease Name Life (years) Oil (Mbbl) Residue Gas (MMcf) Residue Gas (M$) Other (M$) Expense & Tax (M$) Invest. (M$) Non-Disc. (M$) Cash FlowNet Sales Volumes Net Revenue As of Date: 1/1/2023 Reserve Category Oil (M$) Disc. 10% (M$) NGL (M$) NGL (Mbbl) TABLE 6 166.48 118.11 33.93 0.00 0.00 0.00 217.87 51.38 0.00P-DP 14.25NAC 3H-20 - 3H-20 0.00 0.00 1,285.19 726.00 261.91 0.00 0.00 0.00 1,681.85 396.66 0.00P-DP 36.39NAC 4H-20 - 4H-20 0.00 0.00 823.91 549.45 167.90 0.00 0.00 0.00 1,078.21 254.29 0.00P-DP 27.41NAC B WYN JF 1H - 1H 0.00 0.00 289.72 189.76 59.04 0.00 0.00 0.00 379.14 89.42 0.00P-DP 19.23NAC B WYN JF 3H - 3H 0.00 0.00 977.81 664.09 199.27 0.00 0.00 0.00 1,279.61 301.79 0.00P-DP 28.33NAC B WYN JF 5H - 5H 0.00 0.00 404.18 277.81 82.37 0.00 0.00 0.00 528.93 124.75 0.00P-DP 20.00NAC GAS UNIT B 3H-3 - 3H-3 0.00 0.00 372.93 287.81 76.00 0.00 0.00 0.00 488.03 115.10 0.00P-DP 9.96NOLAN NE CRC JF 3H - 3H 0.00 0.00 2,273.03 1,283.15 463.21 0.00 0.00 0.00 2,974.57 701.54 0.00P-DP 45.69NOLAN NW CRC JF 1H - 1H 0.00 0.00 1,202.41 758.82 245.04 0.00 0.00 0.00 1,573.52 371.11 0.00P-DP 34.98NOLAN S CRC JF 2H - 2H 0.00 0.00 958.56 617.46 195.34 0.00 0.00 0.00 1,254.41 295.85 0.00P-DP 31.87NOLAN S CRC JF 4H - 4H 0.00 0.00 1,115.15 736.85 227.25 0.00 0.00 0.00 1,459.32 344.18 0.00P-DP 32.55NOLAN S CRC JF 6H - 6H 0.00 0.00 61.30 34.73 12.93 0.00 0.00 0.00 83.05 21.76 0.00P-DP 19.41PALOS 01-12-241 0.00 0.00 36.82 19.42 7.77 0.00 0.00 0.00 49.89 13.07 0.00P-DP 22.67PALOS 02-10-239 0.00 0.00 114.47 62.70 24.15 0.00 0.00 0.00 155.11 40.63 0.00P-DP 24.01PALOS 02-16-240 0.00 0.00 92.97 46.30 19.62 0.00 0.00 0.00 125.96 33.00 0.00P-DP 25.93PALOS 03-06-245 0.00 0.00 78.49 43.13 16.56 0.00 0.00 0.00 106.35 27.86 0.00P-DP 21.55PALOS 03-10-232 0.00 0.00 44.39 29.00 9.37 0.00 0.00 0.00 60.14 15.75 0.00P-DP 13.71PALOS 03-14-233 0.00 0.00 73.60 44.60 15.53 0.00 0.00 0.00 99.73 26.12 0.00P-DP 18.40PALOS 03-16-231 0.00 0.00 1,702.17 1,182.01 346.88 0.00 0.00 0.00 2,227.53 525.36 0.00P-DP 33.49PUGGLE E WYN JF 4H - 4H 0.00 0.00 1,852.11 1,270.14 377.44 0.00 0.00 0.00 2,423.74 571.63 0.00P-DP 34.97PUGGLE E WYN JF 6H - 6H 0.00 0.00 85.37 75.98 17.40 0.00 0.00 0.00 111.71 26.35 0.00P-DP 4.97PUGGLE W WYN JF 2H - 2H 0.00 0.00 469.43 319.62 95.66 0.00 0.00 0.00 614.31 144.88 0.00P-DP 31.64ROXY CRC JF 1H - 1H 0.00 0.00 113.17 79.08 23.06 0.00 0.00 0.00 148.09 34.93 0.00P-DP 30.00ROXY N CRC JF 3H - 3H 0.00 0.00 33.54 24.03 6.83 0.00 0.00 0.00 43.89 10.35 0.00P-DP 27.34ROXY NE CRC JF 5H - 5H 0.00 0.00 2,962.13 1,941.35 603.65 0.00 0.00 0.00 3,876.36 914.23 0.00P-DP 48.76SPORT E WYN JF 3H - 3H 0.00 0.00 4,400.24 2,884.07 896.71 0.00 0.00 0.00 5,758.32 1,358.08 0.00P-DP 50.00SPORT W WYN JF 1H - 1H 0.00 0.00 1,099.15 720.99 223.99 0.00 0.00 0.00 1,438.39 339.24 0.00P-DP 30.86TANNER WYN JF 2H - 2H 0.00 0.00 1,533.04 979.08 312.41 0.00 0.00 0.00 2,006.19 473.15 0.00P-DP 35.34TANNER WYN JF 4H - 4H 0.00 0.00 7.18 4.59 1.46 0.00 0.00 0.00 9.40 2.22 0.00P-DP 35.83THOMPSON E SMF JF 5H - 5H 0.00 0.00 80.18 54.66 16.34 0.00 0.00 0.00 104.93 24.75 0.00P-DP 30.42THOMPSON W SMF JF 1H - 1H 0.00 0.00 109.17 69.29 22.25 0.00 0.00 0.00 142.87 33.70 0.00P-DP 37.10THOMPSON W SMF JF 3H - 3H 0.00 0.00 40.03 23.14 0.74 0.40 0.00 36.83 4.41 3.12 0.00P-DP 20.59FAIREY UNIT 1H - 1H 1.92 0.06 48.19 27.11 0.16 0.55 0.00 50.30 0.97 3.52 0.00P-DP 29.70GILLESPIE UNIT 1H - 1H 0.42 0.01 61.95 35.15 0.75 0.66 0.00 60.23 4.48 4.70 0.00P-DP 21.93KUBENKA UNIT 1H - 1H 1.95 0.06 28.79 19.43 1.55 0.20 0.00 18.10 9.25 2.59 0.00P-DP 12.39MOLNOSKEY UNIT 1H - 1H 4.03 0.13

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![](exhibit992-202210xk019.jpg)

Economic One-Liners Lease Name Life (years) Oil (Mbbl) Residue Gas (MMcf) Residue Gas (M$) Other (M$) Expense & Tax (M$) Invest. (M$) Non-Disc. (M$) Cash FlowNet Sales Volumes Net Revenue As of Date: 1/1/2023 Reserve Category Oil (M$) Disc. 10% (M$) NGL (M$) NGL (Mbbl) TABLE 6 99.92 58.99 0.00 1.17 0.00 107.08 0.01 7.18 0.00P-DP 34.00MOLNOSKEY UNIT 2H - 2H 0.00 0.00 16.03 8.39 0.35 0.16 0.00 14.33 2.08 1.29 0.00P-DP 42.34NANCY 1H - 1H 0.91 0.03 28.68 16.07 0.32 0.31 0.00 28.11 1.91 2.17 0.00P-DP 23.34SUSTR UNIT 1H - 1H 0.83 0.03 32.42 21.58 0.35 0.35 0.00 31.90 2.06 2.45 0.00P-DP 14.69TARGAC UNIT 1H - 1H 0.90 0.03 21.53 12.54 0.16 0.23 0.00 21.93 1.70 2.91 0.00P-DP 40.92CHAROLAIS 28 21 B2NC STATE COM 001H - 001H 0.81 0.02 7.90 3.82 0.05 0.09 0.00 8.10 0.59 1.07 0.00P-DP 36.93CUATRO HIJOS FEE 003H - 003H 0.28 0.01 5.06 4.00 0.03 0.06 0.00 5.21 0.37 0.69 0.00P-DP 5.80CUATRO HIJOS FEE 004H - 004H 0.18 0.00 0.96 0.70 0.01 0.01 0.00 0.96 0.09 0.13 0.00P-DP 11.25CUATRO HIJOS FEE 008H - 008H 0.04 0.00 153.59 86.77 0.98 1.69 0.00 158.59 10.70 20.81 0.00P-DP 50.00HEREFORD 29 20 W1NC STATE COM 001H - 001H 5.12 0.13 6.84 4.14 0.03 0.08 0.00 7.32 0.32 0.94 0.00P-DP 39.72RAMBO E2 08 17 STATE COM 001H - 001H 0.15 0.00 9.30 5.29 0.04 0.11 0.00 9.89 0.47 1.28 0.00P-DP 44.66RAMBO E2 08 17 STATE COM 002H - 002H 0.23 0.01 10.30 5.94 0.40 0.07 0.00 6.80 2.55 1.75 0.00P-DP 43.61B AND B 1H - 1H 2.70 0.06 15.89 8.98 0.67 0.11 0.00 9.86 4.29 2.81 0.00P-DP 42.79B AND B 2H - 2H 4.55 0.10 10.50 5.85 0.39 0.07 0.00 6.90 2.49 1.54 0.00P-DP 46.64B AND B STATE 4H - 4H 2.65 0.06 18.70 10.40 0.72 0.13 0.00 11.98 4.61 2.78 0.00P-DP 50.00B AND B STATE A 5H - 5H 4.89 0.10 4.15 2.08 0.14 0.03 0.00 2.94 0.92 0.67 0.00P-DP 50.00BOBCAT 55-1-28 UNIT 1H - 1H 0.97 0.02 3.16 1.60 0.10 0.03 0.00 2.37 0.62 0.49 0.00P-DP 49.80BUCKEYE 55-1-28 UNIT 1H - 1H 0.65 0.01 3.73 1.92 0.11 0.03 0.00 2.81 0.73 0.58 0.00P-DP 40.94CHINOOK 55-1-7 UNIT 1H - 1H 0.77 0.02 2.08 1.12 0.06 0.02 0.00 1.56 0.41 0.32 0.00P-DP 50.00HAWKS 55-1-28 UNIT 1H - 1H 0.44 0.01 5.37 2.83 0.19 0.04 0.00 3.78 1.19 0.87 0.00P-DP 48.85QUICK SILVER 55-1-7 UNIT 1H - 1H 1.26 0.03 2.17 1.16 0.06 0.02 0.00 1.66 0.41 0.33 0.00P-DP 50.00RAINIER 55-1-28 UNIT 1H - 1H 0.43 0.01 3.67 2.10 0.00 0.04 0.00 4.01 0.01 0.35 0.00P-DP 38.58REED 24 UNIT 2H - 2H 0.01 0.00 2.56 1.35 0.04 0.03 0.00 2.41 0.23 0.31 0.00P-DP 35.39REED 24 UNIT 4H - 4H 0.24 0.01 6.74 3.84 0.15 0.06 0.00 5.66 0.98 0.94 0.00P-DP 42.79REED 24 UNIT 5H - 5H 1.04 0.02 8.30 4.60 0.19 0.07 0.00 6.91 1.24 1.17 0.00P-DP 45.53REED 24 UNIT 7H - 7H 1.32 0.03 3.64 2.18 0.01 0.04 0.00 3.86 0.08 0.37 0.00P-DP 37.36REED 24 UNIT 8H - 8H 0.08 0.00 13.81 7.10 0.10 0.15 0.00 13.93 0.67 1.50 0.00P-DP 50.00RUSTLER A UNIT #3H - 3H 0.71 0.01 12.84 6.55 0.24 0.12 0.00 11.34 1.54 1.67 0.00P-DP 50.00RUSTLER A UNIT #4H - 4H 1.63 0.03 12.54 6.53 0.27 0.12 0.00 10.66 1.74 1.70 0.00P-DP 50.00RUSTLER B UNIT #1H - 1H 1.84 0.04 12.95 6.79 0.11 0.14 0.00 12.97 0.69 1.43 0.00P-DP 50.00RUSTLER B UNIT #3H - 3H 0.73 0.02 8.61 5.07 0.38 0.06 0.00 5.17 2.41 1.54 0.00P-DP 41.55RUSTLER C UNIT #1H - 1H 2.56 0.05 7.41 4.46 0.00 0.09 0.00 8.10 0.00 0.70 0.00P-DP 39.77RUSTLER C UNIT #2H - 2H 0.00 0.00 11.45 6.05 0.10 0.12 0.00 11.43 0.63 1.27 0.00P-DP 48.97RUSTLER D UNIT #1H - 1H 0.66 0.01 6.34 3.34 0.07 0.07 0.00 6.20 0.42 0.72 0.00P-DP 42.26RUSTLER D UNIT #2H - 2H 0.44 0.01 6.39 3.59 0.07 0.07 0.00 6.20 0.45 0.74 0.00P-DP 40.82RUSTLER D UNIT #4H - 4H 0.47 0.01

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![](exhibit992-202210xk020.jpg)

Economic One-Liners Lease Name Life (years) Oil (Mbbl) Residue Gas (MMcf) Residue Gas (M$) Other (M$) Expense & Tax (M$) Invest. (M$) Non-Disc. (M$) Cash FlowNet Sales Volumes Net Revenue As of Date: 1/1/2023 Reserve Category Oil (M$) Disc. 10% (M$) NGL (M$) NGL (Mbbl) TABLE 6 10.66 5.66 0.11 0.11 0.00 10.42 0.71 1.22 0.00P-DP 48.15RUSTLER D UNIT #5H - 5H 0.75 0.02 0.28 0.15 0.00 0.00 0.00 0.30 0.00 0.03 0.00P-DP 25.31THORPE 1-74 LOV 1H - 1H 0.00 0.00 0.07 0.04 0.00 0.00 0.00 0.05 0.01 0.01 0.00P-DP 13.14THORPE 1-74 LOV 2H - 2H 0.01 0.00 1.21 0.59 0.02 0.01 0.00 1.07 0.15 0.16 0.00P-DP 42.05THORPE 1-74 LOV 3H - 3H 0.16 0.00 0.55 0.33 0.01 0.01 0.00 0.51 0.05 0.07 0.00P-DP 23.30THORPE 1-74 LOV 4H - 4H 0.06 0.00 12.31 6.50 0.23 0.12 0.00 10.88 1.47 1.60 0.00P-DP 50.00WRANGLER A UNIT #1H - 1H 1.56 0.03 14.84 8.43 0.14 0.16 0.00 14.61 0.92 1.67 0.00P-DP 48.47WRANGLER A UNIT #2H - 2H 0.98 0.02 3.79 2.20 0.04 0.04 0.00 3.66 0.28 0.44 0.00P-DP 34.42WRANGLER B UNIT #1H - 1H 0.30 0.01 10.83 5.75 0.27 0.09 0.00 8.77 1.75 1.55 0.00P-DP 50.00WRANGLER B UNIT #2H - 2H 1.86 0.04 15.09 8.16 0.28 0.14 0.00 13.38 1.78 1.96 0.00P-DP 50.00WRANGLER C UNIT #1H - 1H 1.89 0.04 13.91 7.65 0.20 0.14 0.00 12.99 1.26 1.69 0.00P-DP 50.00WRANGLER C UNIT #2H - 2H 1.34 0.03 10.16 5.74 0.16 0.10 0.00 9.27 1.05 1.27 0.00P-DP 46.80WRANGLER D UNIT #1H - 1H 1.11 0.02 17.07 9.65 0.25 0.17 0.00 15.82 1.63 2.10 0.00P-DP 50.00WRANGLER D UNIT #2H - 2H 1.72 0.04 0.02 0.02 0.00 0.00 0.00 0.02 0.00 0.00 0.00P-DP 6.34WRIGHT 1-22W WRD 1H - 1H 0.00 0.00 2.98 1.68 0.00 0.03 0.00 3.21 0.03 0.29 0.00P-DP 43.66YELLOW ROSE A UNIT 1H - 1H 0.03 0.00 2.71 1.58 0.01 0.03 0.00 2.90 0.04 0.27 0.00P-DP 41.75YELLOW ROSE A UNIT 2H - 2H 0.04 0.00 2.04 1.24 0.06 0.02 0.00 1.55 0.39 0.31 0.00P-DP 34.63YELLOW ROSE A UNIT 3H - 3H 0.41 0.01 5.76 3.32 0.01 0.07 0.00 6.18 0.07 0.57 0.00P-DP 50.00YELLOW ROSE B UNIT 1H - 1H 0.08 0.00 1.44 0.87 0.00 0.02 0.00 1.55 0.02 0.14 0.00P-DP 33.83YELLOW ROSE B UNIT 2H - 2H 0.02 0.00 7.36 4.24 0.21 0.06 0.00 5.73 1.33 1.10 0.00P-DP 50.00YELLOW ROSE B UNIT 3H - 3H 1.41 0.03 1.46 0.86 0.01 0.02 0.00 1.41 0.06 0.12 0.00P-DP 33.86ACKERLY BROWN 9 1 - 1 0.11 0.00 55.65 33.97 1.48 0.41 0.00 38.55 8.29 7.13 0.00P-DP 24.39AGGIE THE BULLDOG 39-46 A 1LS - 1LS 15.95 0.40 124.07 70.77 0.08 1.41 0.00 132.30 0.47 9.60 0.00P-DP 38.68AGGIE THE BULLDOG 39-46 A 1WA - 1WA 0.90 0.02 168.87 95.34 4.51 1.25 0.00 116.73 25.24 21.68 0.00P-DP 37.02AGGIE THE BULLDOG 39-46 A 1WB - 1WB 48.58 1.21 136.77 87.90 4.68 0.85 0.00 79.80 26.17 19.56 0.00P-DP 28.15AGGIE THE BULLDOG 39-46 B 2DN - 2DN 50.35 1.25 60.47 38.38 0.97 0.55 0.00 51.15 5.41 6.49 0.00P-DP 29.12AGGIE THE BULLDOG 39-46 B 2WA - 2WA 10.40 0.26 23.06 20.82 1.58 0.02 0.00 2.02 8.85 4.85 0.00P-DP 2.75AGGIE THE BULLDOG 39-46 C 3LS - 3LS 17.04 0.42 61.87 39.70 0.76 0.59 0.00 55.66 4.24 6.19 0.00P-DP 26.63AGGIE THE BULLDOG 39-46 C 3WB - 3WB 8.16 0.20 149.91 89.80 3.63 1.17 0.00 109.09 20.29 18.50 0.00P-DP 35.05AGGIE THE BULLDOG 39-46 C 4WA - 4WA 39.03 0.97 8.99 5.79 0.16 0.08 0.00 7.33 0.91 1.00 0.00P-DP 25.73AGGIE THE BULLDOG 39-46 D 5LS - 5LS 1.75 0.04 94.24 62.06 2.46 0.70 0.00 65.95 13.77 11.99 0.00P-DP 32.01AGGIE THE BULLDOG 39-46 D 5WB - 5WB 26.50 0.66 107.46 68.82 2.25 0.89 0.00 83.28 12.57 12.57 0.00P-DP 30.95AGGIE THE BULLDOG 39-46 D 6WA - 6WA 24.18 0.60 71.33 45.27 0.80 0.70 0.00 65.28 4.46 6.98 0.00P-DP 28.43AGGIE THE BULLDOG 39-46 E 6DN - 6DN 8.57 0.21 66.92 39.44 0.90 0.63 0.00 59.01 5.05 6.86 0.00P-DP 29.43AGGIE THE BULLDOG 39-46 E 7LS - 7LS 9.72 0.24 126.11 77.39 1.46 1.23 0.00 114.72 8.15 12.44 0.00P-DP 35.40AGGIE THE BULLDOG 39-46 E 7WA - 7WA 15.68 0.39

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![](exhibit992-202210xk021.jpg)

Economic One-Liners Lease Name Life (years) Oil (Mbbl) Residue Gas (MMcf) Residue Gas (M$) Other (M$) Expense & Tax (M$) Invest. (M$) Non-Disc. (M$) Cash FlowNet Sales Volumes Net Revenue As of Date: 1/1/2023 Reserve Category Oil (M$) Disc. 10% (M$) NGL (M$) NGL (Mbbl) TABLE 6 173.90 103.72 2.77 1.57 0.00 147.22 15.50 18.65 0.00P-DP 38.59AGGIE THE BULLDOG 39-46 E 7WB - 7WB 29.83 0.74 52.90 24.65 0.77 0.49 0.00 45.79 4.33 5.54 0.00P-DP 47.42ANN COLE TRUST 1 - 1 8.33 0.21 0.01 0.01 0.00 0.00 0.00 0.01 0.00 0.00 0.00P-DP 3.42BAYES 16 1 - 1 0.00 0.00 0.03 0.03 0.00 0.00 0.00 0.04 0.00 0.00 0.00P-DP 6.51BAYES 16 2 - 2 0.00 0.00 0.83 0.40 0.03 0.00 0.00 0.43 0.18 0.12 0.00P-DP 41.23BAYES 16A 1 - 1 0.34 0.01 0.87 0.44 0.00 0.01 0.00 0.88 0.02 0.07 0.00P-DP 39.22BAYES 4 3 - 3 0.04 0.00 0.28 0.17 0.01 0.00 0.00 0.19 0.04 0.04 0.00P-DP 23.38BAYES 4A 2 - 2 0.08 0.00 0.12 0.08 0.00 0.00 0.00 0.12 0.00 0.01 0.00P-DP 12.98BAYES 4A 3 - 3 0.01 0.00 0.68 0.37 0.01 0.01 0.00 0.59 0.06 0.07 0.00P-DP 34.71BAYES 4A 4 - 4 0.11 0.00 7.87 4.62 0.02 0.09 0.00 8.14 0.13 0.64 0.00P-DP 43.32BIG JAY 10-15 A 1JD - 1JD 0.25 0.01 6.84 4.03 0.03 0.07 0.00 6.87 0.19 0.59 0.00P-DP 41.61BIG JAY 10-15 A 1LS - 1LS 0.37 0.01 8.70 5.09 0.09 0.09 0.00 8.06 0.51 0.84 0.00P-DP 44.50BIG JAY 10-15 A 1MS - 1MS 0.98 0.02 17.23 9.99 0.72 0.09 0.00 8.19 4.02 2.72 0.00P-DP 49.85BIG JAY 10-15 A 1WA - 1WA 7.74 0.19 7.96 4.63 0.28 0.05 0.00 4.59 1.54 1.14 0.00P-DP 42.86BIG JAY 10-15 B 2DN - 2DN 2.97 0.07 7.44 4.37 0.31 0.04 0.00 3.55 1.73 1.17 0.00P-DP 39.76BIG JAY 10-15 B 2LS - 2LS 3.33 0.08 7.54 4.35 0.38 0.03 0.00 2.70 2.11 1.31 0.00P-DP 36.44BIG JAY 10-15 B 2WB - 2WB 4.05 0.10 6.58 3.89 0.19 0.05 0.00 4.34 1.06 0.87 0.00P-DP 41.07BIG JAY 10-15 B 3JC - 3JC 2.04 0.05 5.98 3.64 0.22 0.03 0.00 3.27 1.23 0.88 0.00P-DP 37.40BIG JAY 10-15 C 4LS - 4LS 2.37 0.06 6.91 4.20 0.32 0.03 0.00 2.78 1.81 1.16 0.00P-DP 35.40BIG JAY 10-15 C 4WA - 4WA 3.48 0.09 3.30 2.00 0.13 0.02 0.00 1.65 0.74 0.51 0.00P-DP 30.77BIG JAY 10-15 D 5JC - 5JC 1.42 0.04 7.80 4.58 0.21 0.06 0.00 5.33 1.19 1.01 0.00P-DP 43.16BIG JAY 10-15 D 6DN - 6DN 2.29 0.06 6.15 3.63 0.20 0.04 0.00 3.67 1.14 0.87 0.00P-DP 39.99BIG JAY 10-15 D 6LS - 6LS 2.20 0.05 7.35 4.34 0.35 0.03 0.00 2.86 1.96 1.25 0.00P-DP 37.05BIG JAY 10-15 D 6WB - 6WB 3.77 0.09 5.59 3.37 0.11 0.05 0.00 4.48 0.60 0.63 0.00P-DP 38.83BIG JAY 10-15 E 7JD - 7JD 1.15 0.03 7.12 4.26 0.18 0.05 0.00 5.12 0.99 0.89 0.00P-DP 41.71BIG JAY 10-15 E 7LS - 7LS 1.90 0.05 2.55 1.57 0.09 0.02 0.00 1.46 0.50 0.37 0.00P-DP 29.84BIG JAY 10-15 E 7MS - 7MS 0.96 0.02 6.15 3.62 0.27 0.03 0.00 2.72 1.51 1.00 0.00P-DP 36.32BIG JAY 10-15 E 7WA - 7WA 2.91 0.07 8.32 4.80 0.23 0.06 0.00 5.68 1.27 1.08 0.00P-DP 44.26BIG JAY 10-15 F 4MS - 4MS 2.44 0.06 0.67 0.39 0.01 0.01 0.00 0.55 0.07 0.07 0.00P-DP 32.11BOX NAIL 2LM - 2LM 0.13 0.00 0.74 0.44 0.01 0.01 0.00 0.61 0.07 0.08 0.00P-DP 33.29BOX NAIL 3LL - 3LL 0.14 0.00 0.88 0.50 0.02 0.01 0.00 0.67 0.11 0.10 0.00P-DP 34.66BOX NAIL E 1LM - 1LM 0.21 0.01 30.75 14.54 0.35 0.30 0.00 28.06 1.95 3.02 0.00P-DP 42.08BROOKS 1 - 1 3.75 0.09 10.24 5.30 0.15 0.09 0.00 8.89 0.83 1.07 0.00P-DP 38.49DARWIN 22 1 - 1 1.59 0.04 1.18 0.82 0.00 0.01 0.00 1.23 0.02 0.10 0.00P-DP 13.14DARWIN 22 2 - 2 0.03 0.00 177.35 111.15 2.45 1.66 0.00 155.51 13.72 18.27 0.00P-DP 50.00DIRE WOLF UNIT 1 0404BH - 0404BH 26.40 0.66

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![](exhibit992-202210xk022.jpg)

Economic One-Liners Lease Name Life (years) Oil (Mbbl) Residue Gas (MMcf) Residue Gas (M$) Other (M$) Expense & Tax (M$) Invest. (M$) Non-Disc. (M$) Cash FlowNet Sales Volumes Net Revenue As of Date: 1/1/2023 Reserve Category Oil (M$) Disc. 10% (M$) NGL (M$) NGL (Mbbl) TABLE 6 519.26 306.71 4.36 5.30 0.00 495.93 24.39 47.98 0.00P-DP 50.00DIRE WOLF UNIT 1 0414AH - 0414AH 46.93 1.17 97.16 57.51 0.82 0.99 0.00 92.79 4.56 8.98 0.00P-DP 47.95DIRE WOLF UNIT 1 0424SH - 0424SH 8.78 0.22 17.64 11.04 0.10 0.19 0.00 17.51 0.57 1.54 0.00P-DP 28.19DIRE WOLF UNIT 1 0433SH - 0433SH 1.10 0.03 64.41 38.33 0.97 0.59 0.00 55.30 5.44 6.80 0.00P-DP 43.12DIRE WOLF UNIT 1 0474JH - 0474JH 10.46 0.26 101.46 59.88 1.35 0.96 0.00 89.74 7.55 10.35 0.00P-DP 50.00DIRE WOLF UNIT 2 0406BH - 0406BH 14.53 0.36 102.27 60.37 1.25 0.98 0.00 92.10 6.97 10.21 0.00P-DP 50.00DIRE WOLF UNIT 2 0407BH - 0407BH 13.41 0.33 85.94 50.74 0.93 0.84 0.00 79.01 5.23 8.36 0.00P-DP 50.00DIRE WOLF UNIT 2 0415AH - 0415AH 10.06 0.25 68.40 40.41 0.52 0.71 0.00 66.12 2.90 6.21 0.00P-DP 50.00DIRE WOLF UNIT 2 0416AH - 0416AH 5.59 0.14 63.32 37.39 0.63 0.63 0.00 59.04 3.53 6.05 0.00P-DP 50.00DIRE WOLF UNIT 2 0417AH - 0417AH 6.80 0.17 32.04 18.98 0.43 0.30 0.00 28.22 2.43 3.28 0.00P-DP 46.26DIRE WOLF UNIT 2 0426SH - 0426SH 4.67 0.12 39.82 23.53 0.52 0.38 0.00 35.38 2.90 4.04 0.00P-DP 48.83DIRE WOLF UNIT 2 0427SH - 0427SH 5.58 0.14 47.29 27.91 0.58 0.45 0.00 42.51 3.25 4.73 0.00P-DP 50.00DIRE WOLF UNIT 2 0428SH - 0428SH 6.26 0.16 2.94 1.98 0.01 0.03 0.00 3.06 0.04 0.24 0.00P-DP 19.29DIRE WOLF UNIT 2 0435SH - 0435SH 0.08 0.00 10.07 6.16 0.12 0.10 0.00 9.10 0.67 1.00 0.00P-DP 32.76DIRE WOLF UNIT 2 0437SH - 0437SH 1.29 0.03 37.36 18.78 1.00 0.28 0.00 25.75 5.61 4.81 0.00P-DP 39.12DYER 3301 - 3301 10.80 0.27 25.76 12.59 1.26 0.10 0.00 9.62 7.03 4.42 0.00P-DP 36.62DYER 3303 - 3303 13.53 0.34 14.66 8.03 0.69 0.06 0.00 5.79 3.88 2.47 0.00P-DP 27.97DYER 33B - 33B 7.46 0.19 12.02 6.71 0.54 0.05 0.00 5.15 3.03 1.97 0.00P-DP 25.38DYER 33D - 33D 5.82 0.14 10.01 6.12 0.32 0.07 0.00 6.19 1.78 1.38 0.00P-DP 16.77DYER 33F - 33F 3.42 0.08 17.75 9.95 0.68 0.10 0.00 9.36 3.78 2.67 0.00P-DP 29.21DYER 33H - 33H 7.28 0.18 2.31 1.54 0.02 0.02 0.00 2.21 0.11 0.20 0.00P-DP 16.24FISHERMAN -A- 2 - 2 0.20 0.01 116.35 68.61 1.19 1.15 0.00 108.11 6.63 11.16 0.00P-DP 47.22FISHERMAN-BRISTOW 23A 1H - 1H 12.77 0.32 90.52 54.97 0.76 0.92 0.00 86.44 4.25 8.37 0.00P-DP 43.50FISHERMAN-BRISTOW 23B 2H - 2H 8.19 0.20 118.06 68.73 1.24 1.17 0.00 109.14 6.95 11.40 0.00P-DP 47.39FISHERMAN-BRISTOW 23C 3H - 3H 13.37 0.33 143.12 84.35 1.45 1.42 0.00 133.14 8.10 13.71 0.00P-DP 50.00FISHERMAN-BRISTOW 23D 4H - 4H 15.59 0.39 14.78 7.14 0.12 0.15 0.00 14.10 0.70 1.37 0.00P-DP 50.00GEORGIA 39 1 - 1 1.35 0.03 0.30 0.12 0.00 0.00 0.00 0.30 0.01 0.02 0.00P-DP 50.00GLASS -Y- 1 - 1 0.01 0.00 66.41 39.33 0.52 0.68 0.00 63.64 2.90 5.71 0.00P-DP 50.00GUNSMOKE 1-40 A 1JM - 1JM 5.58 0.14 53.46 31.09 0.94 0.46 0.00 43.28 5.25 5.17 0.00P-DP 50.00GUNSMOKE 1-40 B 2LS - 2LS 10.10 0.25 76.24 43.46 0.71 0.77 0.00 71.77 3.99 7.19 0.00P-DP 50.00GUNSMOKE 1-40 C 3WA - 3WA 7.67 0.19 60.65 36.15 0.83 0.57 0.00 53.30 4.64 6.23 0.00P-DP 50.00GUNSMOKE 1-40 D 4WA - 4WA 8.93 0.22 51.17 31.17 0.41 0.52 0.00 49.09 2.32 4.70 0.00P-DP 49.54GUNSMOKE 40-1 E 5JM - 5JM 4.46 0.11 48.15 29.50 0.51 0.47 0.00 44.45 2.86 4.66 0.00P-DP 48.94GUNSMOKE 40-1 F 6LS - 6LS 5.50 0.14 99.59 59.27 1.87 0.86 0.00 80.28 10.44 11.22 0.00P-DP 50.00GUNSMOKE 40-1 G 7WA - 7WA 20.09 0.50 36.37 27.14 0.53 0.34 0.00 31.47 2.97 3.80 0.00P-DP 12.27GUNSMOKE 40-1 H 8WB - 8WB 5.72 0.14

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![](exhibit992-202210xk023.jpg)

Economic One-Liners Lease Name Life (years) Oil (Mbbl) Residue Gas (MMcf) Residue Gas (M$) Other (M$) Expense & Tax (M$) Invest. (M$) Non-Disc. (M$) Cash FlowNet Sales Volumes Net Revenue As of Date: 1/1/2023 Reserve Category Oil (M$) Disc. 10% (M$) NGL (M$) NGL (Mbbl) TABLE 6 43.83 26.52 0.68 0.40 0.00 37.40 3.79 4.66 0.00P-DP 48.58GUNSMOKE 40-1 H 8WB - 8WB 7.30 0.18 67.14 39.66 1.40 0.56 0.00 52.01 7.86 7.85 0.00P-DP 50.00GUNSMOKE 40-1 I 9LS - 9LS 15.12 0.38 89.13 58.79 1.43 0.80 0.00 75.34 7.99 9.57 0.00P-DP 50.00GUNSMOKE 40-1 J 10WA - 10WA 15.37 0.38 42.56 25.66 0.90 0.35 0.00 32.77 5.06 5.00 0.00P-DP 49.15GUNSMOKE 40-1 K 11WB - 11WB 9.74 0.24 21.23 12.25 0.04 0.24 0.00 22.21 0.25 1.70 0.00P-DP 29.86HALL TRUST 38 1 - 1 0.47 0.01 20.03 10.22 0.01 0.23 0.00 21.37 0.07 1.54 0.00P-DP 46.77HALL TRUST 38 2 - 2 0.13 0.00 2.21 1.06 0.00 0.02 0.00 2.32 0.02 0.18 0.00P-DP 49.30HARPER-BAYES 16 1 - 1 0.04 0.00 17.05 9.72 0.31 0.15 0.00 13.58 1.75 1.67 0.00P-DP 45.82HYDRA 45-4 UNIT 1 112 - 112 3.38 0.08 14.29 8.04 0.24 0.13 0.00 11.76 1.33 1.37 0.00P-DP 44.09HYDRA 45-4 UNIT 1 122 - 122 2.57 0.06 23.78 13.10 0.37 0.21 0.00 19.98 2.07 2.25 0.00P-DP 50.00HYDRA 45-4 UNIT 1 124 - 124 3.98 0.10 25.10 13.81 0.45 0.22 0.00 20.17 2.52 2.44 0.00P-DP 50.00HYDRA 45-4 UNIT 1 132 - 132 4.85 0.12 15.00 8.43 0.28 0.13 0.00 11.84 1.58 1.47 0.00P-DP 44.64HYDRA 45-4 UNIT 1 142 - 142 3.05 0.08 18.84 10.55 0.33 0.16 0.00 15.29 1.84 1.82 0.00P-DP 47.33HYDRA 45-4 UNIT 1 211 - 211 3.54 0.09 28.48 15.88 0.17 0.30 0.00 28.12 0.94 2.39 0.00P-DP 50.00HYDRA 45-4 UNIT 1 221 - 221 1.82 0.05 21.33 11.75 0.37 0.19 0.00 17.40 2.05 2.05 0.00P-DP 50.00HYDRA 45-4 UNIT 1 223 - 223 3.94 0.10 14.42 8.10 0.24 0.13 0.00 11.84 1.36 1.38 0.00P-DP 44.21HYDRA 45-4 UNIT 1 231 - 231 2.61 0.06 26.68 14.62 0.52 0.22 0.00 20.87 2.89 2.63 0.00P-DP 50.00HYDRA 45-4 UNIT 1 241 - 241 5.56 0.14 0.17 0.12 0.01 0.00 0.00 0.08 0.04 0.02 0.00P-DP 18.83JMW NAIL 10 1 - 1 0.07 0.00 0.14 0.09 0.01 0.00 0.00 0.07 0.03 0.02 0.00P-DP 19.99JMW NAIL 10 2 - 2 0.05 0.00 0.09 0.06 0.00 0.00 0.00 0.06 0.01 0.01 0.00P-DP 17.10JMW NAIL 10 3 - 3 0.03 0.00 0.21 0.14 0.01 0.00 0.00 0.12 0.04 0.02 0.00P-DP 22.12JMW NAIL 10 4 - 4 0.08 0.00 0.10 0.07 0.00 0.00 0.00 0.07 0.01 0.01 0.00P-DP 17.44JMW NAIL 10A 3 - 3 0.02 0.00 0.24 0.16 0.00 0.00 0.00 0.19 0.02 0.02 0.00P-DP 23.77JMW NAIL 10A 4 - 4 0.05 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00P-DP 11.12KEMPER 1 - 1 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00P-DP 12.34KEMPER 1 - 1 0.00 0.00 0.17 0.09 0.00 0.00 0.00 0.18 0.00 0.01 0.00P-DP 22.11KEMPER 16 1 - 1 0.00 0.00 0.17 0.11 0.00 0.00 0.00 0.18 0.00 0.01 0.00P-DP 18.06KEMPER 16 2 - 2 0.00 0.00 149.89 87.93 1.65 1.47 0.00 137.46 9.25 14.62 0.00P-DP 48.54KENTEX-HARRISON 35A 1H - 1H 17.81 0.44 152.30 87.65 2.23 1.41 0.00 131.69 12.50 15.94 0.00P-DP 48.34KENTEX-HARRISON 35B 2H - 2H 24.05 0.60 146.47 82.34 1.00 1.53 0.00 143.25 5.57 13.08 0.00P-DP 50.00KENTEX-HARRISON 35C 3H - 3H 10.72 0.27 85.28 50.70 1.18 0.80 0.00 74.76 6.60 8.79 0.00P-DP 44.89KENTEX-HARRISON 35D 4H - 4H 12.70 0.32 33.46 19.42 0.71 0.27 0.00 25.26 3.96 3.37 0.00P-DP 49.05KRAKEN 10-3 UNIT 2 181 - 181 7.62 0.19 22.09 12.94 0.46 0.18 0.00 16.85 2.55 2.21 0.00P-DP 44.06KRAKEN 10-3 UNIT 2 183 - 183 4.90 0.12 10.56 6.60 0.20 0.09 0.00 8.28 1.13 1.04 0.00P-DP 34.15KRAKEN 10-3 UNIT 2 273 - 273 2.18 0.05 36.44 21.30 0.73 0.30 0.00 28.20 4.06 3.62 0.00P-DP 49.87KRAKEN 10-3 UNIT 2 282 - 282 7.81 0.19

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![](exhibit992-202210xk024.jpg)

Economic One-Liners Lease Name Life (years) Oil (Mbbl) Residue Gas (MMcf) Residue Gas (M$) Other (M$) Expense & Tax (M$) Invest. (M$) Non-Disc. (M$) Cash FlowNet Sales Volumes Net Revenue As of Date: 1/1/2023 Reserve Category Oil (M$) Disc. 10% (M$) NGL (M$) NGL (Mbbl) TABLE 6 6.65 3.89 0.09 0.06 0.00 5.92 0.48 0.67 0.00P-DP 43.50MARYRUTH-ANDERSON 47C 103H - 103H 0.92 0.02 4.28 2.61 0.07 0.04 0.00 3.54 0.41 0.47 0.00P-DP 36.63MARYRUTH-ANDERSON 47D 104H - 104H 0.79 0.02 6.50 3.90 0.04 0.07 0.00 6.41 0.23 0.57 0.00P-DP 44.15MARYRUTH-ANDERSON 47E 105H - 105H 0.44 0.01 6.27 3.72 0.04 0.07 0.00 6.23 0.20 0.55 0.00P-DP 43.85MARYRUTH-ANDERSON 47F 106H - 106H 0.38 0.01 64.34 35.18 1.09 0.57 0.00 53.55 6.09 7.02 0.00P-DP 42.59MIMS 32H 3306BH - 3306BH 11.72 0.29 38.46 22.17 0.82 0.32 0.00 29.61 4.57 4.52 0.00P-DP 32.74MIMS 32H 3307BH - 3307BH 8.80 0.22 52.04 30.44 0.97 0.45 0.00 42.00 5.44 5.86 0.00P-DP 38.73MIMS 32H 3315AH - 3315AH 10.46 0.26 37.97 23.36 1.09 0.27 0.00 25.21 6.08 5.01 0.00P-DP 28.00MIMS 32H 3317AH - 3317AH 11.69 0.29 27.74 16.78 0.53 0.24 0.00 22.23 2.96 3.14 0.00P-DP 31.24MIMS 32H 3318AH - 3318AH 5.69 0.14 17.81 11.50 0.39 0.14 0.00 13.54 2.18 2.12 0.00P-DP 21.11MIMS 32H 3326SH - 3326SH 4.20 0.10 21.95 13.76 0.42 0.19 0.00 17.59 2.34 2.49 0.00P-DP 24.07MIMS 32H 3327SH - 3327SH 4.51 0.11 25.27 15.54 0.30 0.24 0.00 22.89 1.67 2.50 0.00P-DP 29.89MIMS 32H 3345SH - 3345SH 3.22 0.08 63.75 37.43 0.54 0.65 0.00 60.77 3.04 5.91 0.00P-DP 40.89MIMS 32H 3347SH - 3347SH 5.85 0.15 50.45 30.97 0.42 0.51 0.00 48.21 2.36 4.66 0.00P-DP 34.74MIMS 32H 3348SH - 3348SH 4.53 0.11 0.42 0.13 0.01 0.00 0.00 0.37 0.03 0.04 0.00P-DP 50.00NAIL -A- 1 - 1 0.06 0.00 0.08 0.04 0.00 0.00 0.00 0.06 0.01 0.01 0.00P-DP 24.09NAIL -C- 1 - 1 0.01 0.00 0.07 0.03 0.00 0.00 0.00 0.07 0.00 0.01 0.00P-DP 29.99NAIL -C- 1 - 1 0.01 0.00 0.09 0.05 0.00 0.00 0.00 0.09 0.01 0.01 0.00P-DP 20.61NAIL -E- 2 - 2 0.01 0.00 0.12 0.06 0.00 0.00 0.00 0.11 0.01 0.01 0.00P-DP 22.89NAIL -E- 3 - 3 0.01 0.00 0.22 0.07 0.00 0.00 0.00 0.22 0.01 0.02 0.00P-DP 50.00NAIL -K- 1 - 1 0.02 0.00 0.06 0.04 0.00 0.00 0.00 0.06 0.00 0.01 0.00P-DP 15.24NAIL -P- 1 - 1 0.01 0.00 0.12 0.05 0.00 0.00 0.00 0.10 0.01 0.01 0.00P-DP 43.33NAIL J 1 - 1 0.02 0.00 0.25 0.13 0.00 0.00 0.00 0.24 0.01 0.02 0.00P-DP 30.77NAIL O 1 - 1 0.02 0.00 0.42 0.23 0.01 0.00 0.00 0.33 0.04 0.04 0.00P-DP 34.60NAIL RANCH 10 1 - 1 0.08 0.00 0.27 0.14 0.00 0.00 0.00 0.25 0.01 0.02 0.00P-DP 31.81NAIL RANCH 10 2 - 2 0.03 0.00 0.22 0.13 0.00 0.00 0.00 0.23 0.00 0.02 0.00P-DP 25.62NAIL RANCH 10 3 - 3 0.00 0.00 0.20 0.13 0.00 0.00 0.00 0.18 0.02 0.02 0.00P-DP 22.22NAIL RANCH 10 4 - 4 0.03 0.00 0.49 0.25 0.01 0.00 0.00 0.38 0.05 0.05 0.00P-DP 38.52NE NAIL 10 1 - 1 0.10 0.00 0.57 0.30 0.01 0.00 0.00 0.39 0.08 0.06 0.00P-DP 41.41NE NAIL 10 2 - 2 0.16 0.00 0.20 0.11 0.00 0.00 0.00 0.16 0.02 0.02 0.00P-DP 27.26NE NAIL 10 3 - 3 0.04 0.00 0.22 0.14 0.00 0.00 0.00 0.17 0.03 0.02 0.00P-DP 24.72NE NAIL 10 4 - 4 0.05 0.00 0.21 0.12 0.00 0.00 0.00 0.16 0.02 0.02 0.00P-DP 25.52NE NAIL 10 5 - 5 0.04 0.00 46.99 28.12 1.38 0.33 0.00 30.73 7.70 6.26 0.00P-DP 37.24NORRIS UNIT 32-H 3301BH - 3301BH 14.82 0.37 63.14 37.20 1.88 0.44 0.00 40.91 10.50 8.47 0.00P-DP 40.87NORRIS UNIT 32-H 3303BH - 3303BH 20.20 0.50 44.55 26.76 0.36 0.46 0.00 42.78 2.00 4.09 0.00P-DP 36.57NORRIS UNIT 32-H 3304BH - 3304BH 3.85 0.10

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![](exhibit992-202210xk025.jpg)

Economic One-Liners Lease Name Life (years) Oil (Mbbl) Residue Gas (MMcf) Residue Gas (M$) Other (M$) Expense & Tax (M$) Invest. (M$) Non-Disc. (M$) Cash FlowNet Sales Volumes Net Revenue As of Date: 1/1/2023 Reserve Category Oil (M$) Disc. 10% (M$) NGL (M$) NGL (Mbbl) TABLE 6 43.65 25.84 1.74 0.23 0.00 21.91 9.73 6.72 0.00P-DP 35.49NORRIS UNIT 32-H 3312AH - 3312AH 18.73 0.46 73.99 42.94 3.04 0.38 0.00 35.81 17.01 11.58 0.00P-DP 42.99NORRIS UNIT 32-H 3313AH - 3313AH 32.74 0.81 82.16 48.17 2.50 0.56 0.00 52.33 14.01 11.15 0.00P-DP 43.95NORRIS UNIT 32-H 3322SH - 3322SH 26.96 0.67 193.11 112.38 6.73 1.18 0.00 110.82 37.67 27.85 0.00P-DP 50.00NORRIS UNIT 32-H 3323SH - 3323SH 72.48 1.80 103.34 60.03 3.66 0.63 0.00 58.53 20.46 15.01 0.00P-DP 46.78NORRIS UNIT 32-H 3361DH - 3361DH 39.36 0.98 102.43 59.53 3.42 0.65 0.00 60.94 19.14 14.48 0.00P-DP 46.67NORRIS UNIT 32-H 3363DH - 3363DH 36.83 0.91 76.63 45.01 1.56 0.64 0.00 59.95 8.74 8.88 0.00P-DP 43.11NORRIS UNIT 32-H 3364DH - 3364DH 16.82 0.42 61.37 35.70 1.88 0.42 0.00 38.89 10.54 8.35 0.00P-DP 40.88NORRIS UNIT 32-H 3371JH - 3371JH 20.29 0.50 57.19 33.79 1.74 0.39 0.00 36.45 9.74 7.75 0.00P-DP 39.70NORRIS UNIT 32-H 3373JH - 3373JH 18.75 0.47 53.43 31.64 1.57 0.37 0.00 34.85 8.80 7.14 0.00P-DP 38.90NORRIS UNIT 32-H 3374JH - 3374JH 16.93 0.42 46.82 28.04 1.18 0.36 0.00 33.41 6.59 5.86 0.00P-DP 37.19NORRIS-MIMS ALLOCATION 3315AH - 3315AH 12.68 0.31 70.33 41.72 2.28 0.46 0.00 42.81 12.77 9.81 0.00P-DP 41.91NORRIS-MIMS ALLOCATION 3325SH - 3325SH 24.57 0.61 8.16 3.74 0.21 0.06 0.00 5.81 1.16 1.03 0.00P-DP 46.18PERCY 39 1R - 1R 2.23 0.06 3.63 2.10 0.01 0.04 0.00 3.75 0.06 0.30 0.00P-DP 17.85POWELL 43 1 - 1 0.11 0.00 3.87 3.01 0.06 0.03 0.00 3.25 0.35 0.42 0.00P-DP 6.08POWELL A 2 - 2 0.68 0.02 3.20 2.51 0.06 0.03 0.00 2.58 0.34 0.36 0.00P-DP 7.21POWELL A 3 - 3 0.65 0.02 7.90 3.82 0.17 0.07 0.00 6.10 0.93 0.93 0.00P-DP 41.81POWELL B 1 - 1 1.79 0.04 10.11 4.88 0.18 0.09 0.00 8.36 0.98 1.11 0.00P-DP 44.44POWELL C 1 - 1 1.89 0.05 9.54 7.37 0.12 0.10 0.00 9.11 0.69 0.95 0.00P-DP 9.46RAGLAND 2 0.69 0.02 115.56 62.61 1.39 1.11 0.00 104.38 7.75 11.49 0.00P-DP 45.04RAGLAND-ANDERSON 47A 1H - 1H 14.92 0.37 123.93 69.99 1.57 1.18 0.00 110.71 8.79 12.49 0.00P-DP 44.34RAGLAND-ANDERSON 47B 2H - 2H 16.92 0.42 94.34 54.53 1.92 0.79 0.00 73.78 10.77 10.94 0.00P-DP 38.75RAGLAND-ANDERSON 47C 3H - 3H 20.72 0.51 6.33 3.00 0.14 0.05 0.00 4.82 0.77 0.75 0.00P-DP 42.27SABINE 39 1 - 1 1.48 0.04 4.21 2.29 0.08 0.04 0.00 3.32 0.47 0.48 0.00P-DP 34.78SABINE 39 2 - 2 0.90 0.02 59.87 38.77 0.44 0.62 0.00 58.06 2.47 5.41 0.00P-DP 49.60SILVERADO 40-1 A 1JM - 1JM 4.75 0.12 48.28 33.00 0.42 0.49 0.00 45.90 2.35 4.49 0.00P-DP 25.78SILVERADO 40-1 B 2LS - 2LS 4.52 0.11 75.50 45.98 0.37 0.81 0.00 75.97 2.04 6.45 0.00P-DP 50.00SILVERADO 40-1 C 3WA - 3WA 3.93 0.10 62.98 40.38 0.66 0.62 0.00 58.21 3.71 6.08 0.00P-DP 50.00SILVERADO 40-1 E 5JM - 5JM 7.14 0.18 46.85 32.27 0.44 0.47 0.00 44.07 2.46 4.42 0.00P-DP 43.12SILVERADO 40-1 F 6LS - 6LS 4.73 0.12 36.92 23.27 0.38 0.37 0.00 34.21 2.14 3.55 0.00P-DP 44.80SILVERADO 40-1 G 7LS - 7LS 4.12 0.10 95.76 62.67 0.89 0.96 0.00 90.18 4.99 9.02 0.00P-DP 50.00SILVERADO 40-1 H 8WA - 8WA 9.60 0.24 50.79 29.76 0.86 0.45 0.00 42.28 4.81 5.54 0.00P-DP 50.00SILVERADO 40-1 I 9WB - 9WB 9.25 0.23 65.38 38.57 2.06 0.43 0.00 40.71 11.52 9.00 0.00P-DP 50.00SILVERADO 40-1 J 10WB - 10WB 22.16 0.55 106.98 67.32 2.69 0.82 0.00 76.39 15.04 13.39 0.00P-DP 50.00SILVERADO 40-1 K 11WA - 11WA 28.94 0.72 0.28 0.19 0.00 0.00 0.00 0.24 0.02 0.03 0.00P-DP 15.36SIXTEEN PENNY NAIL 310 1LL - 1LL 0.05 0.00

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![](exhibit992-202210xk026.jpg)

Economic One-Liners Lease Name Life (years) Oil (Mbbl) Residue Gas (MMcf) Residue Gas (M$) Other (M$) Expense & Tax (M$) Invest. (M$) Non-Disc. (M$) Cash FlowNet Sales Volumes Net Revenue As of Date: 1/1/2023 Reserve Category Oil (M$) Disc. 10% (M$) NGL (M$) NGL (Mbbl) TABLE 6 0.11 0.09 0.00 0.00 0.00 0.09 0.01 0.01 0.00P-DP 8.25SIXTEEN PENNY NAIL 310 2LM - 2LM 0.02 0.00 3.98 2.38 0.04 0.04 0.00 3.70 0.23 0.38 0.00P-DP 43.11SIXTEEN PENNY NAIL 310 8JM - 8JM 0.44 0.01 0.89 0.53 0.01 0.01 0.00 0.87 0.03 0.08 0.00P-DP 29.21SIXTEEN PENNY NAIL 310A 3LL - 3LL 0.06 0.00 1.57 0.91 0.05 0.01 0.00 1.03 0.26 0.21 0.00P-DP 38.61SIXTEEN PENNY NAIL 310A 9JM - 9JM 0.50 0.01 1.23 0.71 0.00 0.01 0.00 1.30 0.01 0.10 0.00P-DP 35.82SIXTEEN PENNY NAIL 310B 10JM - 10JM 0.01 0.00 0.73 0.45 0.03 0.00 0.00 0.42 0.14 0.11 0.00P-DP 23.07SIXTEEN PENNY NAIL 310B 4LM - 4LM 0.27 0.01 0.88 0.53 0.03 0.01 0.00 0.55 0.15 0.12 0.00P-DP 25.60SIXTEEN PENNY NAIL 310B 5LL - 5LL 0.29 0.01 2.33 1.35 0.03 0.02 0.00 2.08 0.17 0.23 0.00P-DP 42.47SIXTEEN PENNY NAIL 310C 11JM - 11JM 0.32 0.01 0.58 0.35 0.02 0.00 0.00 0.37 0.10 0.08 0.00P-DP 22.02SIXTEEN PENNY NAIL 310C 6LM - 6LM 0.19 0.00 0.31 0.20 0.01 0.00 0.00 0.20 0.05 0.04 0.00P-DP 15.92SIXTEEN PENNY NAIL 310C 7LL - 7LL 0.10 0.00 2.26 1.33 0.04 0.02 0.00 1.90 0.21 0.24 0.00P-DP 19.12STIMSON BURLEY -D- 1 - 1 0.40 0.01 0.03 0.03 0.00 0.00 0.00 0.03 0.00 0.00 0.00P-DP 2.28STIMSON BURLEY -E- 3DW - 3DW 0.00 0.00 0.07 0.04 0.00 0.00 0.00 0.07 0.00 0.01 0.00P-DP 21.33STIMSON-BURLEY -C- 1 - 1 0.01 0.00 0.16 0.07 0.00 0.00 0.00 0.17 0.00 0.01 0.00P-DP 37.81STIMSON-BURLEY -C- 3 - 3 0.00 0.00 0.09 0.08 0.00 0.00 0.00 0.06 0.02 0.01 0.00P-DP 4.50STIMSON-BURLEY 1 - 1 0.03 0.00 0.20 0.14 0.01 0.00 0.00 0.07 0.06 0.04 0.00P-DP 8.64STIMSON-BURLEY 4 - 4 0.11 0.00 0.10 0.08 0.00 0.00 0.00 0.05 0.02 0.01 0.00P-DP 4.76STIMSON-BURLEY 6 - 6 0.04 0.00 5.37 3.28 0.00 0.06 0.00 5.72 0.03 0.42 0.00P-DP 30.32TITO'S 31-42 1LS - 1LS 0.05 0.00 5.50 3.38 0.00 0.06 0.00 5.85 0.03 0.43 0.00P-DP 30.40TITO'S 31-42 1WA - 1WA 0.05 0.00 4.34 2.70 0.00 0.05 0.00 4.61 0.02 0.34 0.00P-DP 27.73TITO'S 31-42 1WB - 1WB 0.04 0.00 14.28 8.57 0.05 0.16 0.00 14.58 0.30 1.19 0.00P-DP 35.14TITO'S 31-42 2LS - 2LS 0.58 0.01 7.42 4.98 0.32 0.04 0.00 3.31 1.81 1.20 0.00P-DP 18.99TITO'S 31-42 2WA - 2WA 3.49 0.09 5.16 3.33 0.06 0.05 0.00 4.68 0.34 0.51 0.00P-DP 23.16TITO'S 31-42 2WB - 2WB 0.66 0.02 3.31 2.16 0.02 0.03 0.00 3.24 0.12 0.29 0.00P-DP 24.30TITO'S 31-42 3WA - 3WA 0.23 0.01 50.09 26.12 0.50 0.50 0.00 46.75 2.77 4.78 0.00P-DP 33.56WATKINS 7 1 - 1 5.34 0.13 15.59 7.47 0.13 0.16 0.00 14.92 0.72 1.44 0.00P-DP 50.00WELCH 39 1 - 1 1.38 0.03 7.18 4.41 0.06 0.07 0.00 6.81 0.35 0.67 0.00P-DP 36.94WELCH 39 2 - 2 0.68 0.02 4.02 2.41 0.06 0.04 0.00 3.52 0.31 0.41 0.00P-DP 32.31WELCH 39 3 - 3 0.60 0.01 7.00 3.91 0.07 0.07 0.00 6.57 0.37 0.66 0.00P-DP 39.77WELCH 39 4 - 4 0.71 0.02 5.43 3.06 0.15 0.04 0.00 3.71 0.83 0.70 0.00P-DP 42.39WILLIE THE WILDCAT 3-15 A 1JC - 1JC 1.59 0.04 7.84 4.44 0.19 0.06 0.00 5.73 1.05 0.96 0.00P-DP 46.38WILLIE THE WILDCAT 3-15 A 1LS - 1LS 2.02 0.05 16.40 9.21 0.42 0.12 0.00 11.58 2.35 2.07 0.00P-DP 50.00WILLIE THE WILDCAT 3-15 A 1WA - 1WA 4.53 0.11 5.19 3.54 0.16 0.03 0.00 3.26 0.91 0.71 0.00P-DP 34.46WILLIE THE WILDCAT 3-15 B 2DN - 2DN 1.74 0.04 7.78 4.50 0.20 0.06 0.00 5.50 1.12 0.98 0.00P-DP 45.65WILLIE THE WILDCAT 3-15 B 2LS - 2LS 2.15 0.05 7.14 4.30 0.39 0.02 0.00 2.04 2.19 1.31 0.00P-DP 34.14WILLIE THE WILDCAT 3-15 B 2WB - 2WB 4.21 0.10

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![](exhibit992-202210xk027.jpg)

Economic One-Liners Lease Name Life (years) Oil (Mbbl) Residue Gas (MMcf) Residue Gas (M$) Other (M$) Expense & Tax (M$) Invest. (M$) Non-Disc. (M$) Cash FlowNet Sales Volumes Net Revenue As of Date: 1/1/2023 Reserve Category Oil (M$) Disc. 10% (M$) NGL (M$) NGL (Mbbl) TABLE 6 4.96 3.17 0.15 0.03 0.00 3.12 0.86 0.68 0.00P-DP 37.52WILLIE THE WILDCAT 3-15 B 3JD - 3JD 1.66 0.04 4.43 2.58 0.16 0.03 0.00 2.41 0.92 0.66 0.00P-DP 36.98WILLIE THE WILDCAT 3-15 C 4LS - 4LS 1.76 0.04 8.95 5.04 0.40 0.04 0.00 3.81 2.26 1.47 0.00P-DP 43.24WILLIE THE WILDCAT 3-15 C 4WA - 4WA 4.35 0.11 4.46 2.67 0.10 0.04 0.00 3.31 0.58 0.54 0.00P-DP 38.71WILLIE THE WILDCAT 3-15 D 5JD - 5JD 1.12 0.03 10.19 6.07 0.27 0.08 0.00 7.06 1.52 1.30 0.00P-DP 48.11WILLIE THE WILDCAT 3-15 D 6DN - 6DN 2.92 0.07 7.89 4.81 0.21 0.06 0.00 5.48 1.17 1.01 0.00P-DP 40.07WILLIE THE WILDCAT 3-15 D 6LS - 6LS 2.25 0.06 9.07 5.45 0.20 0.07 0.00 6.87 1.12 1.08 0.00P-DP 46.19WILLIE THE WILDCAT 3-15 D 6WB - 6WB 2.16 0.05 7.94 4.99 0.02 0.09 0.00 8.27 0.11 0.64 0.00P-DP 43.12WILLIE THE WILDCAT 3-15 E 7JC - 7JC 0.20 0.01 19.79 11.45 0.24 0.19 0.00 17.86 1.33 1.97 0.00P-DP 50.00WILLIE THE WILDCAT 3-15 E 7LS - 7LS 2.56 0.06 10.27 6.01 0.63 0.02 0.00 2.03 3.50 2.01 0.00P-DP 27.38WILLIE THE WILDCAT 3-15 E 7WA - 7WA 6.74 0.17 0.98 0.38 0.01 0.01 0.00 0.99 0.03 0.09 0.00P-DP 45.59BIZZELL -B- 1 - 1 0.05 0.00 0.62 0.30 0.01 0.01 0.00 0.60 0.03 0.06 0.00P-DP 31.32BIZZELL -B- 2 - 2 0.05 0.00 12.05 6.08 0.33 0.10 0.00 9.03 1.96 1.61 0.00P-DP 29.06BIZZELL 1 - 1 2.67 0.07 78.09 44.42 1.54 0.70 0.00 65.77 9.12 9.20 0.00P-DP 50.00BIZZELL-IRVIN 15L UNIT 116H - 116H 12.40 0.33 49.31 28.16 1.82 0.33 0.00 31.39 10.78 7.52 0.00P-DP 47.24BIZZELL-IRVIN 15L UNIT 13H - 13H 14.66 0.39 45.74 25.85 1.88 0.29 0.00 26.82 11.15 7.37 0.00P-DP 43.01BIZZELL-IRVIN 15L UNIT 18H - 18H 15.15 0.40 44.72 25.11 1.05 0.38 0.00 35.73 6.18 5.60 0.00P-DP 47.90BIZZELL-IRVIN 15U UNIT 113H - 113H 8.41 0.22 76.68 42.87 1.73 0.66 0.00 61.99 10.24 9.48 0.00P-DP 50.00BIZZELL-IRVIN 15U UNIT 114H - 114H 13.93 0.37 45.54 27.14 0.84 0.42 0.00 39.02 5.00 5.26 0.00P-DP 44.03BIZZELL-IRVIN 15U UNIT 115H - 115H 6.79 0.18 39.98 23.90 0.86 0.35 0.00 32.84 5.08 4.85 0.00P-DP 42.50BIZZELL-IRVIN 15U UNIT 117H - 117H 6.91 0.18 71.11 41.42 1.48 0.63 0.00 58.96 8.77 8.54 0.00P-DP 50.00BIZZELL-IRVIN 15U UNIT 118H - 118H 11.92 0.32 43.91 26.14 0.92 0.39 0.00 36.30 5.46 5.29 0.00P-DP 43.66BIZZELL-IRVIN 15U UNIT 14H - 14H 7.43 0.20 48.33 28.14 1.12 0.41 0.00 38.74 6.62 6.03 0.00P-DP 47.90BIZZELL-IRVIN 15U UNIT 15H - 15H 9.00 0.24 68.72 39.71 1.68 0.58 0.00 54.06 9.92 8.74 0.00P-DP 50.00BIZZELL-IRVIN 15U UNIT 16H - 16H 13.48 0.36 114.86 63.97 0.82 1.21 0.00 114.06 4.83 10.61 0.00P-DP 50.00BIZZELL-IRVIN 15U UNIT 17H - 17H 6.57 0.18 23.80 14.93 0.18 0.25 0.00 23.53 1.05 2.21 0.00P-DP 50.00BRAUN B S1 2008LH - 2008LH 1.43 0.04 20.32 12.67 0.22 0.21 0.00 19.31 1.29 2.02 0.00P-DP 50.00BRAUN B S10 2014JH - 2014JH 1.75 0.05 15.37 9.63 0.12 0.16 0.00 15.11 0.72 1.44 0.00P-DP 46.12BRAUN B S11 2004LH - 2004LH 0.98 0.03 24.62 15.70 0.11 0.27 0.00 25.21 0.66 2.14 0.00P-DP 50.00BRAUN B S12 2004MH - 2004MH 0.89 0.02 18.20 11.40 0.16 0.19 0.00 17.68 0.96 1.75 0.00P-DP 48.35BRAUN B S13 2003LH - 2003LH 1.30 0.03 23.17 14.71 0.17 0.24 0.00 22.92 1.02 2.15 0.00P-DP 50.00BRAUN B S14 2003MH - 2003MH 1.38 0.04 8.28 5.33 0.07 0.09 0.00 8.11 0.40 0.78 0.00P-DP 38.26BRAUN B S2 2008MH - 2008MH 0.55 0.01 20.60 12.92 0.18 0.21 0.00 20.11 1.04 1.96 0.00P-DP 49.75BRAUN B S3 2007LH - 2007LH 1.41 0.04 14.13 9.01 0.12 0.15 0.00 13.82 0.69 1.34 0.00P-DP 44.75BRAUN B S4 2007MH - 2007MH 0.94 0.03 22.32 14.17 0.18 0.23 0.00 21.87 1.08 2.11 0.00P-DP 50.00BRAUN B S5 2016JH - 2016JH 1.47 0.04

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![](exhibit992-202210xk028.jpg)

Economic One-Liners Lease Name Life (years) Oil (Mbbl) Residue Gas (MMcf) Residue Gas (M$) Other (M$) Expense & Tax (M$) Invest. (M$) Non-Disc. (M$) Cash FlowNet Sales Volumes Net Revenue As of Date: 1/1/2023 Reserve Category Oil (M$) Disc. 10% (M$) NGL (M$) NGL (Mbbl) TABLE 6 19.36 12.12 0.16 0.20 0.00 18.91 0.97 1.84 0.00P-DP 49.05BRAUN B S6 2006LH - 2006LH 1.32 0.04 21.20 13.35 0.14 0.23 0.00 21.15 0.84 1.94 0.00P-DP 49.74BRAUN B S7 2006MH - 2006MH 1.15 0.03 17.16 10.72 0.18 0.17 0.00 16.38 1.05 1.70 0.00P-DP 47.88BRAUN B S8 2005LH - 2005LH 1.43 0.04 22.10 14.01 0.17 0.23 0.00 21.77 1.02 2.07 0.00P-DP 50.00BRAUN B S9 2005MH - 2005MH 1.38 0.04 36.84 21.10 0.37 0.38 0.00 35.28 2.19 3.62 0.00P-DP 50.00BRAUN B W1 2001MH - 2001MH 2.98 0.08 25.69 14.79 0.17 0.27 0.00 25.68 1.00 2.34 0.00P-DP 48.75BRAUN B W3 2001LH - 2001LH 1.36 0.04 28.80 15.77 0.23 0.30 0.00 28.33 1.35 2.70 0.00P-DP 50.00BRAUN C W5 2108LH - 2108LH 1.83 0.05 0.20 0.13 0.00 0.00 0.00 0.21 0.00 0.02 0.00P-DP 13.43COWDEN A 2401 - 2401 0.00 0.00 0.10 0.07 0.00 0.00 0.00 0.10 0.00 0.01 0.00P-DP 7.62COWDEN A 2402 - 2402 0.01 0.00 0.07 0.05 0.00 0.00 0.00 0.06 0.00 0.01 0.00P-DP 5.89COWDEN A 2403 - 2403 0.00 0.00 0.29 0.18 0.00 0.00 0.00 0.29 0.01 0.03 0.00P-DP 16.16COWDEN A 2404 - 2404 0.01 0.00 0.42 0.25 0.01 0.00 0.00 0.39 0.03 0.04 0.00P-DP 19.66COWDEN A 2405 - 2405 0.04 0.00 0.62 0.35 0.00 0.01 0.00 0.64 0.02 0.05 0.00P-DP 23.54COWDEN A 2406 - 2406 0.02 0.00 1.01 0.65 0.01 0.01 0.00 0.97 0.06 0.10 0.00P-DP 24.64COWDEN F 2401 - 2401 0.08 0.00 0.79 0.47 0.01 0.01 0.00 0.74 0.06 0.08 0.00P-DP 24.44COWDEN F 2402 - 2402 0.08 0.00 0.92 0.52 0.01 0.01 0.00 0.87 0.06 0.09 0.00P-DP 27.49COWDEN F 2403 - 2403 0.08 0.00 1.04 0.58 0.01 0.01 0.00 1.00 0.06 0.10 0.00P-DP 22.41COWDEN F 2404 - 2404 0.08 0.00 0.61 0.35 0.00 0.01 0.00 0.62 0.02 0.05 0.00P-DP 23.14COWDEN F 2405 - 2405 0.02 0.00 0.87 0.49 0.00 0.01 0.00 0.91 0.01 0.07 0.00P-DP 23.41COWDEN F 2406 - 2406 0.02 0.00 3.73 2.05 0.03 0.04 0.00 3.65 0.19 0.35 0.00P-DP 30.08FRED HALL UNIT 1 - 1 0.25 0.01 2.86 1.67 0.02 0.03 0.00 2.78 0.15 0.27 0.00P-DP 26.09FRED HALL UNIT 2 - 2 0.20 0.01 6.41 3.79 0.04 0.07 0.00 6.44 0.23 0.58 0.00P-DP 33.83FRED HALL UNIT 3 - 3 0.31 0.01 3.74 2.13 0.09 0.03 0.00 3.02 0.50 0.46 0.00P-DP 30.25GUY COWDEN UNIT 2 2505BH - 2505BH 0.68 0.02 5.96 3.70 0.29 0.03 0.00 2.95 1.72 1.05 0.00P-DP 28.50GUY COWDEN UNIT 2 2506BH - 2506BH 2.34 0.06 1.74 1.15 0.09 0.01 0.00 0.77 0.55 0.32 0.00P-DP 18.32GUY COWDEN UNIT 2 2507BH - 2507BH 0.74 0.02 14.14 8.19 0.58 0.09 0.00 8.32 3.43 2.27 0.00P-DP 41.65GUY COWDEN UNIT 2 2508BH - 2508BH 4.67 0.12 1.21 0.84 0.03 0.01 0.00 0.94 0.18 0.16 0.00P-DP 15.69GUY COWDEN UNIT 2 2515AH - 2515AH 0.25 0.01 5.49 3.28 0.19 0.04 0.00 3.68 1.11 0.81 0.00P-DP 31.94GUY COWDEN UNIT 2 2516AH - 2516AH 1.51 0.04 3.60 2.17 0.12 0.03 0.00 2.46 0.71 0.52 0.00P-DP 27.40GUY COWDEN UNIT 2 2517AH - 2517AH 0.96 0.03 17.20 9.85 0.18 0.17 0.00 16.37 1.07 1.71 0.00P-DP 48.65GUY COWDEN UNIT 2 2518AH - 2518AH 1.46 0.04 21.26 14.82 0.76 0.15 0.00 13.87 4.48 3.18 0.00P-DP 29.25HALL-PORTER 621-596 A 112 - 112 6.09 0.16 30.19 21.46 0.87 0.24 0.00 22.11 5.17 4.11 0.00P-DP 34.23HALL-PORTER 621-596 A 211 - 211 7.02 0.19 21.28 14.35 0.74 0.15 0.00 14.16 4.35 3.14 0.00P-DP 30.92HALL-PORTER 621-596 B 122 - 122 5.91 0.16 27.71 14.83 1.52 0.12 0.00 11.70 9.00 5.23 0.00P-DP 46.32HALL-PORTER 621-596 B 221 - 221 12.24 0.33 27.34 15.57 1.62 0.11 0.00 10.08 9.61 5.41 0.00P-DP 30.24HALL-PORTER 621-596 B 224 - 224 13.06 0.35

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![](exhibit992-202210xk029.jpg)

Economic One-Liners Lease Name Life (years) Oil (Mbbl) Residue Gas (MMcf) Residue Gas (M$) Other (M$) Expense & Tax (M$) Invest. (M$) Non-Disc. (M$) Cash FlowNet Sales Volumes Net Revenue As of Date: 1/1/2023 Reserve Category Oil (M$) Disc. 10% (M$) NGL (M$) NGL (Mbbl) TABLE 6 23.22 15.28 0.67 0.18 0.00 17.06 3.95 3.16 0.00P-DP 39.18HALL-PORTER 621-596 C 132 - 132 5.37 0.14 16.59 9.26 0.56 0.12 0.00 11.16 3.33 2.43 0.00P-DP 47.46HALL-PORTER 621-596 C 231R - 231R 4.53 0.12 30.31 16.81 1.09 0.21 0.00 19.65 6.45 4.56 0.00P-DP 46.56HALL-PORTER 621-596 C 233 - 233 8.77 0.23 15.84 8.94 0.31 0.14 0.00 13.36 1.84 1.86 0.00P-DP 45.16HALL-PORTER 621-596 D 142 - 142 2.50 0.07 20.52 11.64 0.43 0.18 0.00 16.97 2.55 2.47 0.00P-DP 43.65HALL-PORTER 621-596 D 241 - 241 3.47 0.09 0.57 0.23 0.01 0.01 0.00 0.52 0.05 0.06 0.00P-DP 49.58HOFFERKAMP 1 - 1 0.07 0.00 0.29 0.19 0.00 0.00 0.00 0.26 0.03 0.03 0.00P-DP 15.49HOFFERKAMP 1 - 1 0.03 0.00 44.56 24.57 0.31 0.47 0.00 44.35 1.83 4.10 0.00P-DP 39.28HOUSE 47 1 - 1 2.49 0.07 5.49 3.21 0.10 0.05 0.00 4.70 0.60 0.63 0.00P-DP 42.40LRT UNIT 2 ALLOCATION 2318AH - 2318AH 0.82 0.02 0.20 0.12 0.00 0.00 0.00 0.17 0.02 0.02 0.00P-DP 39.06MABEE 22A 1H - 1H 0.03 0.00 0.10 0.06 0.00 0.00 0.00 0.09 0.01 0.01 0.00P-DP 42.07MABEE-ELKIN W16B 2H - 2H 0.02 0.00 0.97 0.56 0.02 0.01 0.00 0.82 0.11 0.11 0.00P-DP 40.01MABEE-STIMSON 22B 2H - 2H 0.16 0.00 0.09 0.06 0.00 0.00 0.00 0.08 0.01 0.01 0.00P-DP 40.11MABEE-TREDAWAY W16A 1H - 1H 0.02 0.00 6.40 4.39 0.03 0.07 0.00 6.49 0.20 0.57 0.00P-DP 10.33O'NEAL -D- 1 - 1 0.27 0.01 12.30 6.06 0.18 0.12 0.00 11.09 1.07 1.33 0.00P-DP 28.88O'NEAL 1 - 1 1.46 0.04 38.63 23.53 0.94 0.32 0.00 30.48 5.53 4.90 0.00P-DP 40.52OLDHAM-GRAHAM 35A 1H - 1H 7.52 0.20 33.63 20.30 0.88 0.27 0.00 25.74 5.21 4.40 0.00P-DP 40.59OLDHAM-GRAHAM 35B 2H - 2H 7.08 0.19 50.07 29.94 1.31 0.41 0.00 38.30 7.76 6.55 0.00P-DP 43.91OLDHAM-GRAHAM 35C 3H - 3H 10.55 0.28 41.98 24.45 1.35 0.31 0.00 29.08 8.01 6.00 0.00P-DP 43.89OLDHAM-GRAHAM 35D 4H - 4H 10.89 0.29 57.12 33.85 0.97 0.53 0.00 50.02 5.72 6.40 0.00P-DP 45.64OLDHAM-GRAHAM 35E 5H - 5H 7.78 0.21 51.26 29.20 0.98 0.46 0.00 43.58 5.78 5.97 0.00P-DP 46.89OLDHAM-GRAHAM 35F 6H - 6H 7.86 0.21 3.56 1.83 0.00 0.04 0.00 3.84 0.00 0.28 0.00P-DP 34.89PARKS 1 - 1 0.00 0.00 11.36 5.93 0.39 0.08 0.00 7.58 2.31 1.67 0.00P-DP 36.41PARKS FIELD UNIT 2 1450BH - 1450BH 3.14 0.08 10.30 5.66 0.38 0.07 0.00 6.57 2.24 1.57 0.00P-DP 41.24PARKS FIELD UNIT 2 1450LH - 1450LH 3.05 0.08 14.85 7.79 0.26 0.14 0.00 12.95 1.52 1.68 0.00P-DP 42.51PARKS FIELD UNIT 2 1451LH - 1451LH 2.06 0.06 4.30 2.37 0.08 0.04 0.00 3.74 0.44 0.49 0.00P-DP 28.48PARKS FIELD UNIT 2 1454H - 1454H 0.60 0.02 21.58 11.27 0.29 0.21 0.00 19.75 1.74 2.27 0.00P-DP 47.36PARKS FIELD UNIT 2 1454LH - 1454LH 2.36 0.06 10.24 5.19 0.16 0.10 0.00 9.15 0.94 1.12 0.00P-DP 39.38PARKS FIELD UNIT 2 1455LH - 1455LH 1.27 0.03 29.42 16.27 1.50 0.15 0.00 13.78 8.88 5.32 0.00P-DP 40.39PARKS FIELD UNIT 2 1458CH - 1458CH 12.08 0.32 35.89 18.82 1.73 0.19 0.00 18.03 10.24 6.29 0.00P-DP 45.33PARKS FIELD UNIT 2 1458LH - 1458LH 13.91 0.37 6.59 3.81 0.25 0.04 0.00 4.09 1.49 1.02 0.00P-DP 28.24PARKS FIELD UNIT 2 1863BH - 1863BH 2.03 0.05 8.57 4.83 0.25 0.07 0.00 6.31 1.45 1.16 0.00P-DP 32.88PARKS FIELD UNIT 2 1863LH - 1863LH 1.97 0.05 7.61 4.03 0.12 0.07 0.00 6.76 0.71 0.84 0.00P-DP 38.72PARKS FIELD UNIT 2 1904BH - 1904BH 0.97 0.03 9.49 5.04 0.40 0.06 0.00 5.41 2.38 1.55 0.00P-DP 33.31PARKS FIELD UNIT 2 1921H - 1921H 3.24 0.09 16.52 9.38 0.60 0.11 0.00 10.59 3.58 2.51 0.00P-DP 46.09PARKS FIELD UNIT 2 2001BH - 2001BH 4.86 0.13

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![](exhibit992-202210xk030.jpg)

Economic One-Liners Lease Name Life (years) Oil (Mbbl) Residue Gas (MMcf) Residue Gas (M$) Other (M$) Expense & Tax (M$) Invest. (M$) Non-Disc. (M$) Cash FlowNet Sales Volumes Net Revenue As of Date: 1/1/2023 Reserve Category Oil (M$) Disc. 10% (M$) NGL (M$) NGL (Mbbl) TABLE 6 13.71 7.14 0.45 0.10 0.00 9.42 2.66 1.97 0.00P-DP 45.64PARKS FIELD UNIT 2 2308BH - 2308BH 3.61 0.10 31.30 15.57 0.67 0.27 0.00 25.78 3.94 3.78 0.00P-DP 50.00PARKS FIELD UNIT 2 2308LH - 2308LH 5.36 0.14 24.33 12.56 0.64 0.20 0.00 18.57 3.80 3.19 0.00P-DP 50.00PARKS FIELD UNIT 2 2308MH - 2308MH 5.16 0.14 4.53 2.46 0.18 0.03 0.00 2.68 1.09 0.73 0.00P-DP 25.81PARKS FIELD UNIT 2 2329LH - 2329LH 1.49 0.04 1.73 1.33 0.13 0.00 0.00 0.27 0.79 0.40 0.00P-DP 6.58PARKS FIELD UNIT 2 2336BH - 2336BH 1.07 0.03 0.20 0.17 0.01 0.00 0.00 0.05 0.09 0.04 0.00P-DP 4.08PARKS FIELD UNIT 2 2346CH - 2346CH 0.12 0.00 14.79 7.21 0.05 0.16 0.00 15.32 0.31 1.26 0.00P-DP 46.09PARKS FIELD UNIT 2 2348H - 2348H 0.42 0.01 0.15 0.13 0.01 0.00 0.00 0.02 0.07 0.04 0.00P-DP 4.62PARKS FIELD UNIT 2 2401 - 2401 0.10 0.00 3.60 2.27 0.30 0.00 0.00 0.27 1.79 0.89 0.00P-DP 13.94PARKS FIELD UNIT 2 2630H - 2630H 2.43 0.06 16.93 8.81 0.32 0.15 0.00 14.41 1.90 1.97 0.00P-DP 43.66PARKS FIELD UNIT 2 2709H - 2709H 2.59 0.07 3.57 1.48 0.24 0.01 0.00 0.97 1.43 0.76 0.00P-DP 47.73PARKS FIELD UNIT NO. 2 1320H - 1320H 1.94 0.05 6.10 2.80 0.47 0.01 0.00 0.93 2.80 1.43 0.00P-DP 41.12PARKS FIELD UNIT NO. 2 1421H - 1421H 3.81 0.10 7.24 3.03 0.56 0.01 0.00 1.14 3.30 1.69 0.00P-DP 47.30PARKS FIELD UNIT NO. 2 1422H - 1422H 4.49 0.12 0.74 0.45 0.04 0.00 0.00 0.32 0.24 0.14 0.00P-DP 15.77PARKS FIELD UNIT NO. 2 1423H - 1423H 0.33 0.01 1.46 0.72 0.11 0.00 0.00 0.28 0.64 0.33 0.00P-DP 25.27PARKS FIELD UNIT NO. 2 1829H - 1829H 0.87 0.02 1.21 0.60 0.11 0.00 0.00 0.00 0.64 0.31 0.00P-DP 34.66PARKS FIELD UNIT NO. 2 1831H - 1831H 0.88 0.02 3.21 1.62 0.21 0.01 0.00 0.91 1.26 0.68 0.00P-DP 30.56PARKS FIELD UNIT NO. 2 2324H - 2324H 1.71 0.05 0.38 0.25 0.03 0.00 0.00 0.00 0.20 0.10 0.00P-DP 11.28PARKS FIELD UNIT NO. 2 2401 - 2401 0.27 0.01 0.04 0.03 0.00 0.00 0.00 0.00 0.02 0.01 0.00P-DP 1.58PARKS FIELD UNIT NO. 2 2401 - 2401 0.02 0.00 0.37 0.25 0.03 0.00 0.00 0.04 0.18 0.09 0.00P-DP 10.35PARKS FIELD UNIT NO. 2 2417H - 2417H 0.25 0.01 0.20 0.13 0.00 0.00 0.00 0.22 0.00 0.02 0.00P-DP 14.49PARKS, CHARLOTTE 14 1 - 1 0.00 0.00 3.20 2.13 0.04 0.03 0.00 2.98 0.23 0.33 0.00P-DP 31.81PARKS, ROY 306BH - 306BH 0.32 0.01 3.77 2.50 0.02 0.04 0.00 3.79 0.14 0.34 0.00P-DP 35.25PARKS, ROY 306LH - 306LH 0.19 0.01 3.72 2.39 0.04 0.04 0.00 3.52 0.24 0.37 0.00P-DP 35.85PARKS, ROY 307BH - 307BH 0.33 0.01 2.01 1.17 0.14 0.01 0.00 0.53 0.81 0.43 0.00P-DP 38.90PARKS, ROY 307LH - 307LH 1.10 0.03 2.89 1.90 0.04 0.03 0.00 2.59 0.26 0.31 0.00P-DP 31.38PARKS, ROY 308BH - 308BH 0.35 0.01 0.90 0.61 0.06 0.00 0.00 0.29 0.34 0.19 0.00P-DP 24.06PARKS, ROY 308LH - 308LH 0.46 0.01 7.43 5.05 0.05 0.08 0.00 7.42 0.29 0.68 0.00P-DP 44.12PARKS, ROY 308MH - 308MH 0.40 0.01 1.37 0.87 0.04 0.01 0.00 1.03 0.22 0.18 0.00P-DP 24.35PARKS, ROY 316CH - 316CH 0.30 0.01 4.05 2.39 0.05 0.04 0.00 3.75 0.31 0.42 0.00P-DP 41.48PARKS, ROY 316LH - 316LH 0.42 0.01 1.00 0.59 0.09 0.00 0.00 0.06 0.50 0.25 0.00P-DP 22.46PARKS, ROY 99H - 99H 0.68 0.02 53.11 33.67 0.24 0.58 0.00 54.40 1.41 4.62 0.00P-DP 45.82PARKS-COYOTE 1506 A 15HJ - 15HJ 1.92 0.05 33.70 19.81 0.48 0.33 0.00 30.63 2.82 3.59 0.00P-DP 39.63PARKS-COYOTE 1506 A 1HM - 1HM 3.83 0.10 65.70 41.45 0.63 0.67 0.00 63.27 3.74 6.40 0.00P-DP 49.23PARKS-COYOTE 1506 A 8HS - 8HS 5.09 0.14 17.74 10.77 0.23 0.17 0.00 16.32 1.38 1.85 0.00P-DP 31.96PARKS-COYOTE 1506 B 2HM - 2HM 1.88 0.05

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![](exhibit992-202210xk031.jpg)

Economic One-Liners Lease Name Life (years) Oil (Mbbl) Residue Gas (MMcf) Residue Gas (M$) Other (M$) Expense & Tax (M$) Invest. (M$) Non-Disc. (M$) Cash FlowNet Sales Volumes Net Revenue As of Date: 1/1/2023 Reserve Category Oil (M$) Disc. 10% (M$) NGL (M$) NGL (Mbbl) TABLE 6 61.62 37.37 0.61 0.63 0.00 59.11 3.62 6.04 0.00P-DP 49.42PARKS-COYOTE 1506 B 9HS - 9HS 4.93 0.13 48.43 30.81 0.50 0.49 0.00 46.26 2.95 4.78 0.00P-DP 45.42PARKS-COYOTE 1506 C 10HS - 10HS 4.01 0.11 57.90 36.41 0.44 0.61 0.00 57.22 2.58 5.39 0.00P-DP 47.49PARKS-COYOTE 1506 C 16HJ - 16HJ 3.50 0.09 29.82 18.03 0.80 0.24 0.00 22.58 4.74 3.94 0.00P-DP 34.26PARKS-COYOTE 1506 C 3HM - 3HM 6.44 0.17 51.39 32.39 0.48 0.53 0.00 49.69 2.83 4.97 0.00P-DP 46.22PARKS-COYOTE 1506 D 11HS - 11HS 3.84 0.10 38.66 24.64 0.40 0.39 0.00 36.94 2.34 3.81 0.00P-DP 42.65PARKS-COYOTE 1506 D 17HS - 17HS 3.19 0.09 29.15 16.83 0.27 0.30 0.00 28.17 1.61 2.82 0.00P-DP 38.84PARKS-COYOTE 1506 D 4HM - 4HM 2.19 0.06 46.02 29.30 0.46 0.47 0.00 44.12 2.72 4.51 0.00P-DP 44.74PARKS-COYOTE 1506 E 12HS - 12HS 3.70 0.10 44.92 28.55 0.46 0.46 0.00 42.96 2.71 4.42 0.00P-DP 44.51PARKS-COYOTE 1506 E 18HJ - 18HJ 3.68 0.10 29.69 17.15 0.26 0.31 0.00 28.90 1.53 2.84 0.00P-DP 39.21PARKS-COYOTE 1506 E 5HM - 5HM 2.09 0.06 64.93 39.63 0.43 0.69 0.00 64.85 2.55 5.93 0.00P-DP 49.41PARKS-COYOTE 1506 F 13HS - 13HS 3.46 0.09 24.51 15.44 0.21 0.25 0.00 23.95 1.23 2.33 0.00P-DP 34.97PARKS-COYOTE 1506 F 6HM - 6HM 1.67 0.04 110.32 67.52 0.59 1.19 0.00 111.93 3.46 9.78 0.00P-DP 50.00PARKS-COYOTE 1506 G 14HS - 14HS 4.71 0.13 23.98 15.47 0.24 0.24 0.00 22.96 1.43 2.36 0.00P-DP 36.75PARKS-COYOTE 1506 G 19HS - 19HS 1.94 0.05 61.92 35.91 0.51 0.65 0.00 60.61 3.04 5.86 0.00P-DP 47.47PARKS-COYOTE 1506 G 7HM - 7HM 4.14 0.11 37.36 20.17 0.27 0.39 0.00 36.87 1.62 3.34 0.00P-DP 38.11SHIRLEY -B- 3815R - 3815R 2.21 0.06 21.39 10.79 0.12 0.23 0.00 21.55 0.72 1.87 0.00P-DP 33.68SHIRLEY 3806 - 3806 0.98 0.03 12.28 7.06 0.09 0.13 0.00 12.17 0.51 1.09 0.00P-DP 25.76SHIRLEY 3807 - 3807 0.69 0.02 17.18 8.79 0.17 0.18 0.00 16.46 0.98 1.59 0.00P-DP 31.63SHIRLEY 3808 - 3808 1.33 0.04 1.61 0.89 0.04 0.01 0.00 1.24 0.24 0.21 0.00P-DP 26.10STIMSON BURLEY -B- 1 - 1 0.33 0.01 1.51 0.87 0.02 0.01 0.00 1.39 0.12 0.16 0.00P-DP 24.05STIMSON BURLEY -B- 4 - 4 0.16 0.00 0.02 0.01 0.00 0.00 0.00 0.02 0.00 0.00 0.00P-DP 24.40STIMSON BURLEY -M- 1 - 1 0.00 0.00 2.22 1.08 0.04 0.02 0.00 1.95 0.25 0.32 0.00P-DP 32.39STIMSON-BURLEY 18 1 - 1 0.34 0.01 2.61 1.29 0.03 0.03 0.00 2.49 0.16 0.26 0.00P-DP 32.27STINSON-BURLEY K 1 - 1 0.22 0.01 0.60 0.37 0.01 0.01 0.00 0.55 0.05 0.06 0.00P-DP 37.20TIMMERMAN J1 2208MH - 2208MH 0.07 0.00 1.11 0.66 0.02 0.01 0.00 1.01 0.09 0.12 0.00P-DP 44.44TIMMERMAN J10 2206LH - 2206LH 0.12 0.00 0.81 0.49 0.02 0.01 0.00 0.60 0.14 0.11 0.00P-DP 38.95TIMMERMAN J11 2206BH - 2206BH 0.19 0.00 0.93 0.54 0.02 0.01 0.00 0.81 0.09 0.10 0.00P-DP 42.95TIMMERMAN J2 2208LH - 2208LH 0.13 0.00 0.73 0.42 0.02 0.01 0.00 0.58 0.10 0.09 0.00P-DP 39.66TIMMERMAN J3 2208BH - 2208BH 0.14 0.00 1.28 0.74 0.02 0.01 0.00 1.14 0.12 0.14 0.00P-DP 46.80TIMMERMAN J4 2207MH - 2207MH 0.16 0.00 0.82 0.49 0.02 0.01 0.00 0.65 0.12 0.10 0.00P-DP 38.95TIMMERMAN J5 2207LH - 2207LH 0.16 0.00 0.49 0.30 0.01 0.00 0.00 0.42 0.05 0.06 0.00P-DP 33.93TIMMERMAN J6 2207BH - 2207BH 0.07 0.00 0.73 0.44 0.02 0.01 0.00 0.58 0.10 0.09 0.00P-DP 38.06TIMMERMAN J7 2217LH - 2217LH 0.14 0.00 0.52 0.32 0.02 0.00 0.00 0.36 0.10 0.08 0.00P-DP 32.33TIMMERMAN J8 2207CH - 2207CH 0.14 0.00 1.45 0.85 0.03 0.01 0.00 1.26 0.15 0.16 0.00P-DP 47.40TIMMERMAN J9 2206MH - 2206MH 0.20 0.01

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![](exhibit992-202210xk032.jpg)

Economic One-Liners Lease Name Life (years) Oil (Mbbl) Residue Gas (MMcf) Residue Gas (M$) Other (M$) Expense & Tax (M$) Invest. (M$) Non-Disc. (M$) Cash FlowNet Sales Volumes Net Revenue As of Date: 1/1/2023 Reserve Category Oil (M$) Disc. 10% (M$) NGL (M$) NGL (Mbbl) TABLE 6 14.53 8.42 2.74 0.00 0.00 0.00 15.70 1.17 0.00P-DP 47.27RICHARD E LEHMAN SWITZ9BHSU - SWITZ9BHSU 0.00 0.00 10.06 5.86 1.90 0.00 0.00 0.00 10.87 0.81 0.00P-DP 43.26RICHARD E LEHMAN SWITZ9DHSU - SWITZ9DHSU 0.00 0.00 7.67 4.24 0.07 0.08 0.00 7.46 0.49 0.79 0.00P-DP 48.37EL KABONG UNIT 48-17-8 301H - 301H 0.52 0.01 9.52 5.14 0.11 0.10 0.00 8.98 0.75 1.01 0.00P-DP 50.00EL KABONG UNIT 48-17-8 302H - 302H 0.80 0.02 4.94 2.78 0.05 0.05 0.00 4.71 0.36 0.52 0.00P-DP 42.39EL KABONG UNIT 48-17-8 701H - 701H 0.39 0.01 8.75 4.71 0.17 0.08 0.00 7.32 1.20 1.04 0.00P-DP 48.44EL KABONG UNIT 48-17-8 702H - 702H 1.27 0.03 8.32 4.49 0.06 0.09 0.00 8.31 0.40 0.83 0.00P-DP 49.89EL KABONG UNIT 48-17-8 703H - 703H 0.43 0.01 5.73 3.31 0.06 0.06 0.00 5.47 0.42 0.60 0.00P-DP 44.47EL KABONG UNIT 48-17-8 704H - 704H 0.44 0.01 3.72 2.38 0.05 0.04 0.00 3.39 0.36 0.40 0.00P-DP 39.08EL KABONG UNIT 48-17-8 705H - 705H 0.38 0.01 0.61 0.47 0.04 0.00 0.00 0.12 0.30 0.12 0.00P-DP 7.90EL KABONG UNIT 48-17-8 801H - 801H 0.31 0.01 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00P-DP 0.00RIPLEY UNIT 1 - 1 0.00 0.00 4.49 3.55 0.36 0.02 0.00 1.44 1.73 0.51 0.00P-DP 6.43CHILDRESS 140 1 - 1 1.82 0.05 0.14 0.14 0.01 0.00 0.00 0.12 0.03 0.01 0.00P-DP 0.33CHILDRESS 140 2 - 2 0.00 0.00 5.26 4.01 0.14 0.05 0.00 5.03 0.67 0.44 0.00P-DP 7.49CHILDRESS 140 5 - 5 0.00 0.00 197.50 114.10 14.81 0.81 0.00 74.63 70.60 21.94 0.00P-DP 33.92SUGG A 141-140 (ALLOC-A) 1SM - 1SM 74.21 2.20 153.68 85.08 12.97 0.49 0.00 44.54 61.87 17.77 0.00P-DP 40.47SUGG A 141-140 (ALLOC-B) 2SU - 2SU 65.04 1.93 233.23 127.34 19.21 0.79 0.00 72.05 91.61 26.74 0.00P-DP 45.76SUGG A 141-140 (ALLOC-C) 3SM - 3SM 96.30 2.86 155.10 85.24 13.03 0.50 0.00 45.52 62.15 17.91 0.00P-DP 41.26SUGG A 141-140 (ALLOC-D) 4SU - 4SU 65.33 1.94 186.46 110.98 17.30 0.43 0.00 39.51 82.52 22.31 0.00P-DP 23.58SUGG A 141-140 (ALLOC-E) 5RM - 5RM 86.74 2.57 72.47 41.98 7.22 0.12 0.00 10.76 34.43 8.91 0.00P-DP 29.92SUGG A 141-140 (ALLOC-F) 6SM - 6SM 36.19 1.07 84.85 38.67 7.56 0.23 0.00 20.87 36.07 10.00 0.00P-DP 42.70SUGG A 141-140 (ALLOC-F) 6SU - 6SU 37.92 1.12 161.57 95.84 16.57 0.21 0.00 19.58 79.02 20.09 0.00P-DP 39.84SUGG A 141-140 (ALLOC-G) 7SM - 7SM 83.06 2.46 195.51 100.92 20.58 0.20 0.00 18.74 98.15 24.56 0.00P-DP 45.05SUGG A 141-140 (ALLOC-G) 7SU - 7SU 103.18 3.06 321.91 161.17 35.02 0.22 0.00 20.40 166.98 40.99 0.00P-DP 50.00SUGG A 141-140 (ALLOC-H) 8SM - 8SM 175.52 5.21 102.36 60.43 9.82 0.20 0.00 18.68 46.84 12.40 0.00P-DP 34.71SUGG A 141-140 (ALLOC-H) 8SU - 8SU 49.24 1.46 2.57 1.72 0.49 0.00 0.00 0.00 2.89 0.33 0.00P-DP 11.35CV RB SU58;SJ MONDELLO ETAL 18 001 - 001 0.00 0.00 1,906.75 1,203.13 367.22 0.00 0.00 0.00 2,148.02 241.27 0.00P-DP 40.54HA RA SUA;GOLSON 36-25 HC 001-ALT - 001-ALT 0.00 0.00 2,418.47 1,430.89 465.78 0.00 0.00 0.00 2,724.49 306.01 0.00P-DP 45.48HA RA SUA;GOLSON 36-25 HC 002-ALT - 002-ALT 0.00 0.00 416.81 284.37 80.27 0.00 0.00 0.00 469.55 52.74 0.00P-DP 28.14HA RA SUA;WIGGINS 36-25 HC 001 - 001 0.00 0.00 95.83 68.20 18.46 0.00 0.00 0.00 107.95 12.13 0.00P-DP 14.76HA RA SUA;WIGGINS 36-25 HC 002-ALT - 002-ALT 0.00 0.00 105.65 73.21 20.35 0.00 0.00 0.00 119.02 13.37 0.00P-DP 33.94HA RA SUB;LAWSON 31-30 HC 001-ALT - 001-ALT 0.00 0.00 116.77 82.08 22.49 0.00 0.00 0.00 131.54 14.77 0.00P-DP 34.42HA RA SUB;LAWSON 31-30-19 HC 002-ALT - 002-ALT 0.00 0.00 202.13 140.03 38.93 0.00 0.00 0.00 227.70 25.58 0.00P-DP 37.70HA RA SUB;LAWSON 31-30-19 HC 003-ALT - 003-ALT 0.00 0.00 19.34 12.98 3.72 0.00 0.00 0.00 21.78 2.45 0.00P-DP 31.61HA RA SUL;L & L INV 18-19 HC 001-ALT - 001-ALT 0.00 0.00 19.84 13.30 3.82 0.00 0.00 0.00 22.36 2.51 0.00P-DP 30.98HA RA SUL;L & L INV 18-19 HC 002-ALT - 002-ALT 0.00 0.00

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![](exhibit992-202210xk033.jpg)

Economic One-Liners Lease Name Life (years) Oil (Mbbl) Residue Gas (MMcf) Residue Gas (M$) Other (M$) Expense & Tax (M$) Invest. (M$) Non-Disc. (M$) Cash FlowNet Sales Volumes Net Revenue As of Date: 1/1/2023 Reserve Category Oil (M$) Disc. 10% (M$) NGL (M$) NGL (Mbbl) TABLE 6 15.76 8.76 3.03 0.00 0.00 0.00 17.75 1.99 0.00P-DP 20.39HA RA SUL;MADDEN 18 H 001 - 001 0.00 0.00 104.36 71.26 20.10 0.00 0.00 0.00 117.57 13.20 0.00P-DP 24.65HA RA SUL;MADDEN 18 H 002-ALT - 002-ALT 0.00 0.00 9.65 6.46 1.86 0.00 0.00 0.00 10.87 1.22 0.00P-DP 23.17HA RA SUL;MADDEN 18-19 HC 001-ALT - 001-ALT 0.00 0.00 354.06 253.05 68.19 0.00 0.00 0.00 398.86 44.80 0.00P-DP 45.41HA RA SUL;SCHION 18-19 HC 001-ALT - 001-ALT 0.00 0.00 3,141.79 2,487.38 605.08 0.00 0.00 0.00 3,539.32 397.54 0.00P-DP 32.01HA RA SUS;MJR FAMLLC21-28-33HC 001-ALT - 001-ALT 0.00 0.00 7,685.77 5,606.06 1,480.21 0.00 0.00 0.00 8,658.27 972.50 0.00P-DP 48.21HA RA SUS;MJR FAMLLC21-28-33HC 002-ALT - 002-ALT 0.00 0.00 2,491.66 1,798.34 479.87 0.00 0.00 0.00 2,806.93 315.27 0.00P-DP 35.03HA RA SUS;POOLE-DRAKE 21 H 001 - 001 0.00 0.00 4.84 3.40 0.93 0.00 0.00 0.00 5.45 0.61 0.00P-DP 10.17HA RA SUZ;GLOVER 20 001 - 001 0.00 0.00 69.78 34.09 13.44 0.00 0.00 0.00 78.61 8.83 0.00P-DP 38.20HA RA SUZ;GLOVER 20 002-ALT - 002-ALT 0.00 0.00 57.69 30.80 11.11 0.00 0.00 0.00 64.99 7.30 0.00P-DP 34.27HA RA SUZ;GLOVER 20 003-ALT - 003-ALT 0.00 0.00 0.38 0.37 0.07 0.00 0.00 0.00 0.43 0.05 0.00P-DP 0.87HA RA SUZ;JUNCACEAE 20 001-ALT - 001-ALT 0.00 0.00 23.87 15.36 4.60 0.00 0.00 0.00 26.89 3.02 0.00P-DP 19.51HA RA SUZ;JUNCACEAE 20 002-ALT - 002-ALT 0.00 0.00 36.50 19.49 7.03 0.00 0.00 0.00 41.11 4.62 0.00P-DP 29.62HA RA SUZ;JUNCACEAE 20 003-ALT - 003-ALT 0.00 0.00 2,542.65 1,878.67 489.69 0.00 0.00 0.00 2,864.38 321.73 0.00P-DP 40.64HA RB SU69;NAC ROYALTY 33 H 001 - 001 0.00 0.00 11.96 11.52 2.30 0.00 0.00 0.00 13.48 1.51 0.00P-DP 1.14HA RB SU74;NAC ROYALTY 28 H 001 - 001 0.00 0.00 35.68 23.64 6.87 0.00 0.00 0.00 40.20 4.51 0.00P-DP 12.66HA RB SU77;WAHL 27 H 001 - 001 0.00 0.00 766.73 539.43 147.66 0.00 0.00 0.00 863.74 97.02 0.00P-DP 37.53HA RB SU90;BYU PIERRE29-12-10H 001-ALT - 001-ALT 0.00 0.00 481.97 369.11 92.82 0.00 0.00 0.00 542.95 60.98 0.00P-DP 28.79HA RB SU90;BYU PIERRE29-12-10H 002-ALT - 002-ALT 0.00 0.00 223.71 149.17 43.09 0.00 0.00 0.00 252.02 28.31 0.00P-DP 27.27HA RB SU90;NRG 29-12-10 H 001 - 001 0.00 0.00 418.85 317.23 80.67 0.00 0.00 0.00 471.84 53.00 0.00P-DP 25.67HA RB SU90;NRG 29-12-10 H 002-ALT - 002-ALT 0.00 0.00 1,766.59 1,301.63 340.23 0.00 0.00 0.00 1,990.12 223.53 0.00P-DP 42.83HA RB SU90;NRG 29-12-10 H 003-ALT - 003-ALT 0.00 0.00 1,994.30 1,467.73 384.08 0.00 0.00 0.00 2,246.64 252.34 0.00P-DP 44.29HA RB SU90;NRG 29-12-10 H 004-ALT - 004-ALT 0.00 0.00 21.57 18.70 4.15 0.00 0.00 0.00 24.30 2.73 0.00P-DP 3.36HA RB SU92;NAC ROYALTY 34 H 001 - 001 0.00 0.00 14.58 7.31 0.48 0.12 0.00 11.33 2.79 2.04 0.00P-DP 50.00ADMIRAL 4-48 47 1H - 1H 2.51 0.05 128.08 70.18 11.00 0.39 0.00 36.06 63.63 28.83 0.00P-DP 49.59ALLMAN 24 1H - 1H 57.23 1.22 1.98 1.12 0.01 0.02 0.00 2.04 0.07 0.19 0.00P-DP 33.22BOREAS 79 1H - 1H 0.06 0.00 12.55 6.19 0.20 0.13 0.00 11.81 1.13 1.40 0.00P-DP 41.26BUZZARD NORTH 6972 A 1H - A 1H 1.02 0.02 21.69 12.07 0.49 0.20 0.00 18.93 2.86 2.68 0.00P-DP 46.20BUZZARD NORTH 6972 B 2H - B 2H 2.58 0.05 28.17 15.52 0.89 0.24 0.00 22.22 5.17 3.88 0.00P-DP 49.40BUZZARD NORTH 6972 S 3H - S 3H 4.65 0.10 46.11 25.36 1.46 0.39 0.00 36.38 8.46 6.35 0.00P-DP 50.00BUZZARD SOUTH 6972 A 3H - A 3H 7.61 0.16 35.20 20.54 1.44 0.26 0.00 24.19 8.31 4.77 0.00P-DP 50.00BUZZARD SOUTH 6972 A 4H - A 4H 7.47 0.16 36.91 19.69 1.12 0.32 0.00 29.58 6.50 5.01 0.00P-DP 47.56BUZZARD SOUTH 6972 B 1H - B 1H 5.84 0.12 1.22 0.69 0.10 0.00 0.00 0.36 0.60 0.27 0.00P-DP 30.00DONALDSON 4-54 1H - 1H 0.54 0.01 4.25 2.21 0.34 0.02 0.00 1.42 1.98 0.92 0.00P-DP 45.48DONALDSON 4-54 U 34H - U 34H 1.78 0.04 17.58 9.27 0.57 0.15 0.00 13.73 3.32 2.45 0.00P-DP 50.00ELKHEAD 4144 A 2H - A 2H 2.98 0.06

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![](exhibit992-202210xk034.jpg)

Economic One-Liners Lease Name Life (years) Oil (Mbbl) Residue Gas (MMcf) Residue Gas (M$) Other (M$) Expense & Tax (M$) Invest. (M$) Non-Disc. (M$) Cash FlowNet Sales Volumes Net Revenue As of Date: 1/1/2023 Reserve Category Oil (M$) Disc. 10% (M$) NGL (M$) NGL (Mbbl) TABLE 6 14.66 7.93 0.59 0.11 0.00 10.36 3.44 2.23 0.00P-DP 50.00ELKHEAD 4144 A 5H - A 5H 3.09 0.07 17.27 9.49 0.85 0.12 0.00 10.76 4.94 2.87 0.00P-DP 46.68ELKHEAD 4144 A 7H - A 7H 4.44 0.09 11.22 6.09 0.32 0.10 0.00 9.17 1.86 1.49 0.00P-DP 44.55ELKHEAD 4144 B 1H - B 1H 1.68 0.04 9.73 5.30 0.50 0.06 0.00 5.88 2.90 1.65 0.00P-DP 38.11ELKHEAD 4144 B 6H - B 6H 2.60 0.06 13.57 7.48 0.61 0.10 0.00 9.04 3.52 2.16 0.00P-DP 47.17ELKHEAD 4144 B 8H - B 8H 3.17 0.07 10.35 5.77 0.48 0.07 0.00 6.71 2.80 1.68 0.00P-DP 40.86ELKHEAD 4144 C 4H - C 4H 2.52 0.05 9.38 5.06 0.17 0.09 0.00 8.55 1.01 1.09 0.00P-DP 45.71ELKHEAD 4144 S 3H - S 3H 0.91 0.02 70.27 35.65 6.14 0.20 0.00 18.74 35.55 15.99 0.00P-DP 45.02FLEMING 13 10H - 10H 31.98 0.68 8.45 5.36 0.77 0.02 0.00 1.92 4.48 1.98 0.00P-DP 21.55GEORGE T STAGG 5-2 UNIT 1H - 1H 4.03 0.09 6.42 3.82 0.25 0.05 0.00 4.63 1.44 0.96 0.00P-DP 31.72GRIZZLY BEAR 7780 2U A 2H - A 2H 1.30 0.03 5.41 3.19 0.35 0.03 0.00 2.57 2.04 1.04 0.00P-DP 25.42GRIZZLY BEAR 7780 3U A 3H - A 3H 1.84 0.04 18.52 9.45 0.63 0.15 0.00 14.20 3.65 2.62 0.00P-DP 46.23GRIZZLY BEAR 7780 4U A 4H - A 4H 3.29 0.07 3.47 2.05 0.19 0.02 0.00 2.00 1.09 0.60 0.00P-DP 23.45GRIZZLY BEAR 7780 5U A 5H - A 5H 0.98 0.02 15.92 8.12 0.73 0.11 0.00 10.49 4.20 2.55 0.00P-DP 42.90GRIZZLY BEAR 7780 6U A 6H - A 6H 3.78 0.08 4.34 3.07 0.24 0.03 0.00 2.38 1.38 0.66 0.00P-DP 14.14GRIZZLY SOUTH 7673 A 1H - A 1H 1.24 0.03 45.44 25.96 1.00 0.43 0.00 40.03 5.77 5.54 0.00P-DP 45.69GRIZZLY SOUTH 7673 A 3H - A 3H 5.19 0.11 44.51 26.91 1.51 0.37 0.00 34.25 8.71 6.28 0.00P-DP 44.08GRIZZLY SOUTH 7673 A 5H - A 5H 7.83 0.17 71.84 42.85 2.13 0.63 0.00 58.11 12.31 9.66 0.00P-DP 49.92GRIZZLY SOUTH 7673 A 8H - A 8H 11.07 0.24 22.94 13.69 0.24 0.25 0.00 22.69 1.38 2.37 0.00P-DP 36.01GRIZZLY SOUTH 7673 B 2H - B 2H 1.24 0.03 18.51 11.00 0.64 0.15 0.00 14.10 3.71 2.64 0.00P-DP 34.96GRIZZLY SOUTH 7673 B 4H - B 4H 3.34 0.07 43.25 25.00 1.54 0.35 0.00 32.56 8.91 6.23 0.00P-DP 44.99GRIZZLY SOUTH 7673 B 6H - B 6H 8.01 0.17 12.89 6.90 0.66 0.08 0.00 7.83 3.81 2.18 0.00P-DP 33.95GRIZZLY WEST 77 1H - 1H 3.43 0.07 5.38 3.10 0.06 0.06 0.00 5.31 0.33 0.56 0.00P-DP 29.39GRIZZLY WEST 77 A 3H - A 3H 0.30 0.01 6.12 3.44 0.18 0.05 0.00 4.93 1.06 0.83 0.00P-DP 28.99GRIZZLY WEST 77 C 2H - C 2H 0.95 0.02 2.94 1.89 0.33 0.00 0.00 0.00 1.89 0.64 0.00P-DP 12.76HARGROVE, BETTY 1 - 1 1.70 0.04 14.59 7.37 0.78 0.09 0.00 8.51 4.53 2.53 0.00P-DP 45.49KENOSHA 4441 1H - 1H 4.08 0.09 10.00 5.35 0.41 0.08 0.00 7.03 2.37 1.53 0.00P-DP 50.00KENOSHA 4441 B 2H - B 2H 2.13 0.05 16.38 11.37 0.67 0.12 0.00 11.52 3.86 2.47 0.00P-DP 44.93KENOSHA-KEYHOLE 4341 1U A 1H - A 1H 3.47 0.07 18.24 12.36 1.04 0.11 0.00 10.09 5.99 3.22 0.00P-DP 46.11KENOSHA-KEYHOLE 4341 2U B 2H - B 2H 5.39 0.12 8.85 4.43 0.17 0.09 0.00 8.05 0.97 1.04 0.00P-DP 49.11KEYHOLE 43 1H - 1H 0.87 0.02 16.95 9.90 0.66 0.13 0.00 12.24 3.81 2.53 0.00P-DP 48.37KODIAK 7677 1U B 1H - B 1H 3.43 0.07 7.84 4.78 0.30 0.06 0.00 5.71 1.73 1.16 0.00P-DP 38.69KODIAK 7677 2U B 2H - B 2H 1.56 0.03 17.29 10.35 0.39 0.16 0.00 15.09 2.28 2.13 0.00P-DP 48.10KODIAK 7677 3U A 3H - A 3H 2.05 0.04 12.14 7.29 0.44 0.10 0.00 9.11 2.52 1.75 0.00P-DP 44.02KODIAK 7677 4U A 4H - A 4H 2.26 0.05 2.17 1.14 0.03 0.02 0.00 2.06 0.18 0.24 0.00P-DP 50.00LAURA WILDER 72-69 UNIT A 3H - 3H 0.16 0.00

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![](exhibit992-202210xk035.jpg)

Economic One-Liners Lease Name Life (years) Oil (Mbbl) Residue Gas (MMcf) Residue Gas (M$) Other (M$) Expense & Tax (M$) Invest. (M$) Non-Disc. (M$) Cash FlowNet Sales Volumes Net Revenue As of Date: 1/1/2023 Reserve Category Oil (M$) Disc. 10% (M$) NGL (M$) NGL (Mbbl) TABLE 6 2.38 1.26 0.06 0.02 0.00 2.06 0.32 0.30 0.00P-DP 43.37LAURA WILDER 72-69 UNIT B 4HL - 4HL 0.29 0.01 0.79 0.47 0.03 0.01 0.00 0.58 0.17 0.12 0.00P-DP 24.16LOST SADDLE 45 1H - 1H 0.15 0.00 4.11 2.11 0.09 0.04 0.00 3.63 0.51 0.50 0.00P-DP 50.00RICHMOND 39 2H - 2H 0.46 0.01 3.51 1.73 0.12 0.03 0.00 2.73 0.67 0.49 0.00P-DP 47.69RICHMOND 39 3H - 3H 0.60 0.01 1.04 0.61 0.05 0.01 0.00 0.67 0.28 0.17 0.00P-DP 46.11RICHMOND W STATE 4239 A-A 70H - 70H 0.25 0.01 1.09 0.65 0.05 0.01 0.00 0.72 0.29 0.17 0.00P-DP 35.77RICHMOND W STATE 4239 A-B 71H - 71H 0.26 0.01 0.63 0.37 0.03 0.00 0.00 0.37 0.19 0.11 0.00P-DP 40.46RICHMOND W STATE 4239 A-C 72H - 72H 0.17 0.00 0.80 0.46 0.04 0.01 0.00 0.50 0.23 0.13 0.00P-DP 43.90RICHMOND W STATE 4239 A-D 73H - 73H 0.21 0.00 45.27 25.96 2.70 0.26 0.00 23.89 15.61 8.27 0.00P-DP 33.37SANTANA 29 2H - 2H 14.04 0.30 24.05 13.91 0.97 0.18 0.00 17.00 5.64 3.65 0.00P-DP 42.63SHADRACH 68 UNIT 134H - 134H 5.07 0.11 32.61 19.56 1.60 0.22 0.00 20.44 9.25 5.40 0.00P-DP 42.96SHADRACH 68 UNIT 1H - 1H 8.32 0.18 33.98 19.83 1.71 0.23 0.00 20.89 9.89 5.70 0.00P-DP 50.00SHADRACH 68 UNIT 223H - 223H 8.90 0.19 29.09 17.38 0.94 0.25 0.00 22.81 5.43 4.03 0.00P-DP 44.46SHADRACH 68 UNIT 2H - 2H 4.88 0.10 21.05 12.96 1.02 0.14 0.00 13.33 5.89 3.47 0.00P-DP 34.26SHADRACH 68 UNIT 324H - 324H 5.30 0.11 31.19 17.98 1.13 0.25 0.00 23.33 6.52 4.52 0.00P-DP 46.62SHADRACH 68 UNIT 332H - 332H 5.86 0.13 15.00 8.37 0.68 0.11 0.00 9.91 3.93 2.37 0.00P-DP 45.50SHADRACH MOSES CANTALOUPE 221H - 221H 3.53 0.08 16.82 7.85 0.58 0.14 0.00 12.84 3.36 2.39 0.00P-DP 50.00STATE MUDDY WATERS 30 2H - 2H 3.02 0.06 30.44 15.87 0.75 0.28 0.00 26.00 4.37 3.85 0.00P-DP 39.78SUGARLOAF 74 1H - 1H 3.93 0.08 46.72 24.02 2.06 0.34 0.00 31.49 11.90 7.36 0.00P-DP 44.08SUGARLOAF 7475 1U B 1H - B 1H 10.70 0.23 18.20 10.82 0.60 0.15 0.00 14.17 3.46 2.54 0.00P-DP 37.07SUGARLOAF 7475 2U B 2H - B 2H 3.11 0.07 39.67 22.72 1.29 0.34 0.00 30.98 7.48 5.52 0.00P-DP 42.78SUGARLOAF 7475 3U A 3H - A 3H 6.73 0.14 19.57 11.44 0.77 0.15 0.00 14.03 4.46 2.94 0.00P-DP 38.60THURMOND 132 ALLOC C 11H - 11H 4.02 0.09 26.94 15.07 1.46 0.17 0.00 15.62 8.42 4.68 0.00P-DP 36.83THURMOND A137 ALLOC. A 10H - 10H 7.58 0.16 12.46 6.37 0.53 0.09 0.00 8.52 3.09 1.94 0.00P-DP 50.00TIN STAR A L 33H - L 33H 2.78 0.06 4.84 2.62 0.26 0.03 0.00 2.84 1.49 0.84 0.00P-DP 38.49TIN STAR B L 42H - L 42H 1.34 0.03 8.75 4.79 0.40 0.06 0.00 5.73 2.34 1.41 0.00P-DP 49.51TIN STAR D U 46H - U 46H 2.10 0.04 30.37 16.28 1.52 0.20 0.00 18.11 8.80 4.45 0.00P-DP 47.83TOWNSEN 24265 ALLOC. A 10H - 2H 7.91 0.17 3.74 2.29 0.14 0.03 0.00 2.71 0.83 0.56 0.00P-DP 22.57TRIANGLE 75 2H - 2H 0.75 0.02 5.24 2.91 0.27 0.03 0.00 3.15 1.57 0.88 0.00P-DP 49.48VINTAGE A U 06H - U 06H 1.41 0.03 5.48 3.21 0.34 0.03 0.00 2.79 1.94 1.01 0.00P-DP 50.00VINTAGE B T 13H - T 13H 1.75 0.04 1.24 0.74 0.07 0.01 0.00 0.69 0.41 0.22 0.00P-DP 50.00VINTAGE D T 26H - T 26H 0.36 0.01 51.79 29.24 2.71 0.33 0.00 30.87 15.68 8.86 0.00P-DP 35.16WILLETT POT STILL 5-2C UNIT 1H - 1H 14.10 0.30 3.28 1.88 0.14 0.02 0.00 2.24 0.82 0.51 0.00P-DP 42.64WINDY MOUNTAIN 7879 1U B 1H - B 1H 0.74 0.02 1.63 0.97 0.07 0.01 0.00 1.17 0.38 0.25 0.00P-DP 34.59WINDY MOUNTAIN 7879 2U B 2H - B 2H 0.34 0.01 13.78 6.40 2.60 0.00 0.00 0.00 17.54 3.76 0.00P-DP 41.15ELY GAS UNIT NO. 2 1 - 1 0.00 0.00

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Economic One-Liners Lease Name Life (years) Oil (Mbbl) Residue Gas (MMcf) Residue Gas (M$) Other (M$) Expense & Tax (M$) Invest. (M$) Non-Disc. (M$) Cash FlowNet Sales Volumes Net Revenue As of Date: 1/1/2023 Reserve Category Oil (M$) Disc. 10% (M$) NGL (M$) NGL (Mbbl) TABLE 6 79.93 40.00 15.10 0.00 0.00 0.00 101.74 21.81 0.00P-DP 33.35NORTH AMERICAN COAL GAS UNIT 1 - 1 0.00 0.00 4.10 2.67 0.76 0.00 0.00 0.00 4.57 0.46 0.00P-DP 15.98JUR RA SUG;OLYMPIA MIN 30 H 001 - 001 0.00 0.00 1.26 1.13 0.25 0.00 0.00 0.00 1.36 0.10 0.00P-DP 2.40MEHAFFEY - BURNEM 1 - 1 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00P-DP 0.00RIPLEY UNIT 3 - 3 0.00 0.00 15.63 9.31 0.67 0.11 0.00 9.92 3.93 2.38 0.00P-DP 39.40XBC-CAROLINE 3B 302H - 302H 4.16 0.13 16.98 9.70 0.71 0.12 0.00 10.96 4.17 2.55 0.00P-DP 41.38XBC-CAROLINE 3C 303H - 303H 4.41 0.13 12.51 7.57 0.57 0.08 0.00 7.61 3.34 1.96 0.00P-DP 35.92XBC-CAROLINE 3K 311H - 311H 3.53 0.11 14.89 8.63 0.67 0.10 0.00 9.17 3.91 2.32 0.00P-DP 38.28XBC-CAROLINE 3L 312H - 312H 4.13 0.13 20.42 11.34 0.82 0.14 0.00 13.61 4.77 3.00 0.00P-DP 43.75XBC-CAROLINE 3M 313H - 313H 5.04 0.15 21.72 12.29 0.52 0.19 0.00 18.03 3.04 2.57 0.00P-DP 47.20XBC-UNRUH 3A 16H - 16H 3.22 0.10 15.76 9.34 0.47 0.13 0.00 12.09 2.78 2.04 0.00P-DP 41.00XBC-UNRUH 3B 17H - 17H 2.93 0.09 2.54 1.48 0.14 0.02 0.00 1.44 0.76 0.45 0.00P-DP 37.56ABIGAIL 218-219 UNIT 1H - 1H 0.79 0.02 0.57 0.29 0.01 0.01 0.00 0.56 0.04 0.06 0.00P-DP 40.65BARNES, D. E. ESTATE 2 - 2 0.04 0.00 2.68 1.50 0.06 0.03 0.00 2.34 0.33 0.34 0.00P-DP 35.03BARNES, D. E. ESTATE 3H - 3H 0.34 0.01 6.59 3.69 0.05 0.07 0.00 6.75 0.25 0.68 0.00P-DP 44.09BARNES, D. E. ESTATE 4H - 4H 0.27 0.01 0.01 0.00 0.00 0.00 0.00 0.01 0.00 0.00 0.00P-DP 41.92BARSTOW -18- 1 - 1 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00P-DP 13.14BARSTOW -18- 2 - 2 0.00 0.00 0.01 0.01 0.00 0.00 0.00 0.01 0.00 0.00 0.00P-DP 28.44BARSTOW -18- 3 - 3 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00P-DP 22.87BARSTOW -18- 4 - 4 0.00 0.00 0.01 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00P-DP 30.49BARSTOW -18- 5 - 5 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00P-DP 17.00BARSTOW -23- 1 - 1 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00P-DP 20.19BARSTOW -23- 2 - 2 0.00 0.00 0.02 0.01 0.00 0.00 0.00 0.02 0.00 0.00 0.00P-DP 48.17BARSTOW -23- 3 - 3 0.00 0.00 0.01 0.01 0.00 0.00 0.00 0.01 0.00 0.00 0.00P-DP 36.16BARSTOW -23- 4 - 4 0.00 0.00 0.01 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00P-DP 24.61BARSTOW -23- 6 - 6 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00P-DP 0.14BARSTOW -23- 6A - 6A 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00P-DP 20.08BARSTOW -23- 7 - 7 0.00 0.00 0.01 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00P-DP 25.14BARSTOW -23- 8 - 8 0.00 0.00 0.01 0.01 0.00 0.00 0.00 0.00 0.00 0.00 0.00P-DP 35.76BARSTOW -23- 9 - 9 0.00 0.00 0.02 0.01 0.00 0.00 0.00 0.02 0.00 0.00 0.00P-DP 38.73BARSTOW 155 1 - 1 0.00 0.00 0.05 0.03 0.00 0.00 0.00 0.05 0.00 0.01 0.00P-DP 29.23BARSTOW 155 2 - 2 0.00 0.00 0.01 0.00 0.00 0.00 0.00 0.01 0.00 0.00 0.00P-DP 30.27BARSTOW 27 1 - 1 0.00 0.00 0.02 0.01 0.00 0.00 0.00 0.02 0.00 0.00 0.00P-DP 43.66BARSTOW 27 2 - 2 0.00 0.00 0.03 0.01 0.00 0.00 0.00 0.03 0.00 0.00 0.00P-DP 48.56BARSTOW 27 3 - 3 0.00 0.00 0.04 0.02 0.00 0.00 0.00 0.04 0.00 0.00 0.00P-DP 50.00BARSTOW 27 4 - 4 0.00 0.00

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![](exhibit992-202210xk037.jpg)

Economic One-Liners Lease Name Life (years) Oil (Mbbl) Residue Gas (MMcf) Residue Gas (M$) Other (M$) Expense & Tax (M$) Invest. (M$) Non-Disc. (M$) Cash FlowNet Sales Volumes Net Revenue As of Date: 1/1/2023 Reserve Category Oil (M$) Disc. 10% (M$) NGL (M$) NGL (Mbbl) TABLE 6 0.03 0.01 0.00 0.00 0.00 0.03 0.00 0.00 0.00P-DP 46.68BARSTOW 27 5 - 5 0.00 0.00 0.03 0.01 0.00 0.00 0.00 0.02 0.00 0.00 0.00P-DP 47.90BARSTOW 27 6 - 6 0.00 0.00 0.02 0.01 0.00 0.00 0.00 0.02 0.00 0.00 0.00P-DP 43.59BARSTOW 27 7 - 7 0.00 0.00 0.03 0.02 0.00 0.00 0.00 0.03 0.00 0.00 0.00P-DP 28.80BARSTOW 27 8 - 8 0.00 0.00 0.02 0.01 0.00 0.00 0.00 0.02 0.01 0.00 0.00P-DP 20.30BARSTOW 33 UA 1BS - 1BS 0.01 0.00 0.10 0.05 0.00 0.00 0.00 0.08 0.02 0.02 0.00P-DP 39.96BARSTOW 33 UB 2BS - 2BS 0.02 0.00 0.04 0.02 0.00 0.00 0.00 0.03 0.01 0.01 0.00P-DP 39.41BARSTOW 33-34 1H - 1H 0.01 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00P-DP 8.53BARSTOW 33-35 1H - 1H 0.00 0.00 0.02 0.01 0.00 0.00 0.00 0.01 0.00 0.00 0.00P-DP 36.07BARSTOW 33-35 2H - 2H 0.00 0.00 0.04 0.02 0.00 0.00 0.00 0.03 0.01 0.01 0.00P-DP 43.64BARSTOW 33-35 3H - 3H 0.01 0.00 0.01 0.01 0.00 0.00 0.00 0.01 0.00 0.00 0.00P-DP 50.00BARSTOW A 3652H - 3652H 0.00 0.00 13.48 8.65 0.70 0.08 0.00 7.86 3.90 2.36 0.00P-DP 34.28BRACERO 226-34 UNIT 1H - 1H 4.08 0.08 14.35 6.79 0.68 0.10 0.00 8.95 3.83 2.44 0.00P-DP 42.60BRAMBLETT 34-216 1H - 1H 4.00 0.08 28.52 15.33 1.67 0.16 0.00 14.70 9.35 5.30 0.00P-DP 50.00BROOKE 184-185 UNIT 2H - 2H 9.77 0.19 0.06 0.03 0.01 0.00 0.00 0.00 0.04 0.02 0.00P-DP 19.98BURKHOLDER A UNIT 1 - 1 0.04 0.00 3.34 1.83 0.07 0.03 0.00 3.01 0.36 0.42 0.00P-DP 41.30BYRD 34-170 UNIT 3H - 3H 0.38 0.01 0.18 0.16 0.02 0.00 0.00 0.05 0.09 0.04 0.00P-DP 4.12BYRD 34-170 UNIT 4H - 4H 0.09 0.00 32.20 18.23 1.61 0.21 0.00 19.35 9.02 5.59 0.00P-DP 50.00CALIFORNIA CHROME UNIT 2H - 2H 9.42 0.19 30.98 15.55 1.59 0.20 0.00 18.22 8.90 5.45 0.00P-DP 50.00CALIFORNIA CHROME UNIT 5003HR - 5003HR 9.30 0.18 84.11 44.53 1.85 0.79 0.00 73.76 10.35 10.82 0.00P-DP 47.30CHALUPA 34-153 UNIT 1H - 1H 10.82 0.21 134.61 74.82 1.84 1.39 0.00 129.08 10.29 15.52 0.00P-DP 50.00CHALUPA 34-153 UNIT 2H - 2H 10.75 0.21 7.79 4.52 0.11 0.08 0.00 7.40 0.63 0.91 0.00P-DP 50.00CHURRO 34-157/158 UNIT 1H - 1H 0.66 0.01 0.08 0.05 0.00 0.00 0.00 0.07 0.01 0.01 0.00P-DP 21.17COLUMBINE 34-167 3H - 3H 0.01 0.00 0.40 0.20 0.01 0.00 0.00 0.37 0.04 0.05 0.00P-DP 39.83COLUMBINE 34-167 4H - 4H 0.04 0.00 0.32 0.15 0.01 0.00 0.00 0.24 0.06 0.05 0.00P-DP 50.00CONSTANTAN 34-174 (N) 1H - 1H 0.07 0.00 22.87 12.47 0.94 0.17 0.00 15.78 5.25 3.64 0.00P-DP 48.93CORNELL 226-34 1H - 1H 5.48 0.11 0.47 0.41 0.00 0.01 0.00 0.50 0.01 0.05 0.00P-DP 3.90CRAZY CAMEL 1 - 1 0.01 0.00 7.37 3.78 0.01 0.09 0.00 7.90 0.08 0.70 0.00P-DP 27.81CRAZY CAMEL 2 - 2 0.09 0.00 0.73 0.59 0.05 0.00 0.00 0.32 0.27 0.15 0.00P-DP 5.73CRAZY CAMEL 5 - 5 0.29 0.01 0.85 0.69 0.03 0.01 0.00 0.63 0.17 0.13 0.00P-DP 6.07CRAZY CAMEL 6 - 6 0.18 0.00 5.73 3.73 0.06 0.06 0.00 5.68 0.33 0.62 0.00P-DP 20.39CRAZY CAMEL 7 - 7 0.34 0.01 11.74 5.97 0.20 0.12 0.00 10.85 1.13 1.42 0.00P-DP 49.55CROSS V RANCH 34-170 UNIT 1H - 1H 1.18 0.02 5.56 3.01 0.20 0.04 0.00 4.13 1.11 0.84 0.00P-DP 49.64DANIELLE 183 UNIT 1H - 1H 1.16 0.02 6.03 3.19 0.28 0.04 0.00 3.87 1.55 1.01 0.00P-DP 50.00DANIELLE 183 UNIT 2H - 2H 1.62 0.03 7.83 4.61 0.47 0.04 0.00 3.98 2.60 1.48 0.00P-DP 46.78DAVIS 201-200-199 UNIT 1H - 1H 2.72 0.05

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Economic One-Liners Lease Name Life (years) Oil (Mbbl) Residue Gas (MMcf) Residue Gas (M$) Other (M$) Expense & Tax (M$) Invest. (M$) Non-Disc. (M$) Cash FlowNet Sales Volumes Net Revenue As of Date: 1/1/2023 Reserve Category Oil (M$) Disc. 10% (M$) NGL (M$) NGL (Mbbl) TABLE 6 0.23 0.12 0.01 0.00 0.00 0.17 0.05 0.03 0.00P-DP 24.33DRAINAGE 34-136 1H - 1H 0.05 0.00 1.30 0.74 0.03 0.01 0.00 1.17 0.14 0.16 0.00P-DP 23.68DRAINAGE 34-136 2H - 2H 0.15 0.00 3.88 2.04 0.01 0.04 0.00 4.12 0.07 0.38 0.00P-DP 38.28DRAINAGE 34-136 3H - 3H 0.07 0.00 4.64 2.51 0.03 0.05 0.00 4.83 0.14 0.47 0.00P-DP 39.45DRAINAGE 34-136 4H - 4H 0.15 0.00 4.96 2.97 0.07 0.05 0.00 4.70 0.40 0.57 0.00P-DP 47.54DRAINAGE A3 6LA - 6LA 0.42 0.01 3.68 2.03 0.05 0.04 0.00 3.52 0.29 0.43 0.00P-DP 37.79EILAND 1806A-33 1H - 1H 0.30 0.01 7.74 4.19 0.05 0.09 0.00 7.93 0.30 0.81 0.00P-DP 48.53EILAND 1806B-33 1H - 1H 0.31 0.01 2.86 1.85 0.06 0.03 0.00 2.53 0.34 0.36 0.00P-DP 32.34EILAND 1806B-33 62H - 62H 0.35 0.01 5.11 2.95 0.07 0.05 0.00 4.92 0.38 0.59 0.00P-DP 41.67EILAND 1806C-33 1H - 1H 0.40 0.01 3.84 2.48 0.04 0.04 0.00 3.84 0.20 0.41 0.00P-DP 36.04EILAND 1806C-33 81H - 81H 0.21 0.00 7.76 4.30 0.08 0.08 0.00 7.74 0.42 0.83 0.00P-DP 48.89EILAND 1806C-33 82H - 82H 0.44 0.01 7.28 4.16 0.10 0.08 0.00 7.00 0.55 0.84 0.00P-DP 45.82EILAND 1806C-33 83H - 83H 0.57 0.01 10.72 6.48 0.14 0.11 0.00 10.33 0.79 1.23 0.00P-DP 37.36EILAND 6047A-34 41H - 41H 0.83 0.02 6.46 3.40 0.41 0.03 0.00 3.02 2.29 1.26 0.00P-DP 50.00EMMA 218-219 UNIT 1H - 1H 2.40 0.05 14.69 8.47 0.40 0.13 0.00 12.17 2.21 2.01 0.00P-DP 48.48FIRE FROG 57-32 A 1WA - 1WA 2.31 0.05 25.68 14.42 0.69 0.27 0.00 25.20 3.84 3.44 0.00P-DP 50.00FIRE FROG 57-32 B 2BS - 2BS 0.10 0.00 15.37 8.61 0.42 0.16 0.00 15.03 2.37 2.08 0.00P-DP 49.13FIRE FROG 57-32 C 3WA - 3WA 0.06 0.00 28.13 15.31 0.90 0.29 0.00 26.96 5.04 4.00 0.00P-DP 50.00FIRE FROG 57-32 D 4BS - 4BS 0.13 0.00 0.08 0.04 0.00 0.00 0.00 0.04 0.02 0.01 0.00P-DP 24.54FIREBIRD 52 1 - 1 0.03 0.00 0.05 0.03 0.00 0.00 0.00 0.04 0.01 0.01 0.00P-DP 50.00FUNKY BOSS B 8251H - 8251H 0.01 0.00 0.03 0.02 0.00 0.00 0.00 0.02 0.01 0.01 0.00P-DP 42.14FUNKY BOSS C 8270H - 8270H 0.01 0.00 0.74 0.43 0.01 0.01 0.00 0.69 0.07 0.09 0.00P-DP 42.87GADDIE 1-31 UNIT 1H - 1H 0.08 0.00 0.26 0.14 0.00 0.00 0.00 0.25 0.02 0.03 0.00P-DP 33.31GADDIE 1-31 UNIT 2H - 2H 0.02 0.00 0.12 0.07 0.00 0.00 0.00 0.13 0.00 0.01 0.00P-DP 25.28GADDIE 1-31 UNIT 3H - 3H 0.00 0.00 4.22 2.29 0.26 0.02 0.00 2.10 1.43 0.80 0.00P-DP 43.00HORNSILVER 1H - 1H 1.49 0.03 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00P-DP 43.02JACKSON A 34-166-175 5201H - 5201H 0.00 0.00 24.20 13.93 0.38 0.24 0.00 22.69 2.14 2.87 0.00P-DP 29.85LEE 34-154 1H - 1H 2.24 0.04 6.18 2.99 0.06 0.07 0.00 6.13 0.35 0.68 0.00P-DP 50.00LEEDE UNIT 7 1H - 1H 0.37 0.01 4.12 2.04 0.07 0.04 0.00 3.84 0.38 0.49 0.00P-DP 36.11LEEDE UNIT 7 2H - 2H 0.39 0.01 6.37 3.40 0.35 0.04 0.00 3.56 1.94 1.15 0.00P-DP 43.58MARY GRACE 201-202 UNIT 1H - 1H 2.02 0.04 5.86 3.25 0.27 0.04 0.00 3.70 1.54 0.99 0.00P-DP 41.68MARY GRACE 201-202 UNIT 3H - 3H 1.61 0.03 0.11 0.07 0.00 0.00 0.00 0.11 0.00 0.01 0.00P-DP 12.77MELISSA A 1 - 1 0.00 0.00 2.07 1.12 0.09 0.01 0.00 1.39 0.50 0.34 0.00P-DP 46.02MERIDITH 183 UNIT 1H - 1H 0.52 0.01 0.04 0.04 0.00 0.00 0.00 0.04 0.00 0.00 0.00P-DP 2.96MONROE 34-158 UNIT 1H - 1H 0.00 0.00 0.35 0.27 0.00 0.00 0.00 0.34 0.02 0.04 0.00P-DP 10.42MONROE 34-158 UNIT 2H - 2H 0.02 0.00

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![](exhibit992-202210xk039.jpg)

Economic One-Liners Lease Name Life (years) Oil (Mbbl) Residue Gas (MMcf) Residue Gas (M$) Other (M$) Expense & Tax (M$) Invest. (M$) Non-Disc. (M$) Cash FlowNet Sales Volumes Net Revenue As of Date: 1/1/2023 Reserve Category Oil (M$) Disc. 10% (M$) NGL (M$) NGL (Mbbl) TABLE 6 2.51 1.48 0.03 0.03 0.00 2.46 0.16 0.28 0.00P-DP 34.76MONROE 34-158 UNIT 3H - 3H 0.17 0.00 0.02 0.02 0.00 0.00 0.00 0.02 0.00 0.00 0.00P-DP 2.07MONROE 34-158 UNIT 4H - 4H 0.00 0.00 4.35 2.73 0.16 0.04 0.00 4.07 0.91 0.66 0.00P-DP 38.68MUD HEN 57-31 A 1WA - 1WA 0.02 0.00 13.57 8.20 0.31 0.15 0.00 13.54 1.72 1.74 0.00P-DP 47.50MUD HEN 57-31 B 2BS - 2BS 0.04 0.00 8.37 4.84 0.19 0.09 0.00 8.36 1.04 1.07 0.00P-DP 45.66MUD HEN 57-31 C 3WA - 3WA 0.03 0.00 17.13 10.11 0.44 0.18 0.00 16.88 2.46 2.27 0.00P-DP 50.00MUD HEN 57-31 D 4BS - 4BS 0.06 0.00 44.02 26.23 1.85 0.32 0.00 29.87 10.35 7.02 0.00P-DP 50.00PALMER 52 UNIT 222H - 222H 10.81 0.21 39.87 24.33 2.37 0.22 0.00 20.19 13.28 7.48 0.00P-DP 50.00PALMER 52 UNIT 332H - 332H 13.87 0.27 12.09 6.40 0.75 0.06 0.00 5.81 4.22 2.34 0.00P-DP 41.75PRIMA 1H - 1H 4.41 0.09 8.25 4.35 0.43 0.05 0.00 4.77 2.42 1.46 0.00P-DP 40.74PRONTO 1H - 1H 2.53 0.05 0.18 0.09 0.00 0.00 0.00 0.16 0.02 0.02 0.00P-DP 45.90PRUETT 20 2 - 2 0.02 0.00 0.14 0.08 0.00 0.00 0.00 0.14 0.01 0.02 0.00P-DP 27.20PRUETT 20 4H - 4H 0.01 0.00 0.12 0.06 0.00 0.00 0.00 0.10 0.02 0.02 0.00P-DP 24.66PRUETT 20 5H - 5H 0.02 0.00 0.50 0.24 0.01 0.00 0.00 0.45 0.05 0.06 0.00P-DP 41.71PRUETT 20 6H - 6H 0.05 0.00 0.25 0.16 0.01 0.00 0.00 0.22 0.03 0.03 0.00P-DP 24.70PRUETT 23 1H - 1H 0.03 0.00 0.22 0.12 0.00 0.00 0.00 0.24 0.00 0.02 0.00P-DP 26.45PRUETT 23 2H - 2H 0.00 0.00 0.62 0.30 0.01 0.01 0.00 0.61 0.04 0.07 0.00P-DP 38.40PRUETT 23A 1H - 1H 0.04 0.00 0.09 0.06 0.00 0.00 0.00 0.09 0.01 0.01 0.00P-DP 17.51PRUETT 23A 1H - 1H 0.01 0.00 0.67 0.35 0.01 0.01 0.00 0.65 0.05 0.08 0.00P-DP 38.35PRUETT 23A 2H - 2H 0.05 0.00 80.77 47.40 2.15 0.72 0.00 67.19 12.01 10.99 0.00P-DP 45.05QUESO 34-153 UNIT 1H - 1H 12.55 0.25 118.67 61.55 1.95 1.19 0.00 110.40 10.90 14.03 0.00P-DP 50.00QUESO 34-153 UNIT 2H - 2H 11.39 0.23 0.27 0.14 0.00 0.00 0.00 0.29 0.00 0.03 0.00P-DP 29.70QUITO WEST UNIT 306 - 306 0.00 0.00 0.02 0.02 0.00 0.00 0.00 0.02 0.00 0.00 0.00P-DP 4.92QUITO, S. W. (DELAWARE) UNIT 201 - 201 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00P-DP 0.00QUITO, S. W. (DELAWARE) UNIT 702 - 702 0.00 0.00 0.01 0.01 0.00 0.00 0.00 0.01 0.00 0.00 0.00P-DP 2.74QUITO, S. W. (DELAWARE) UNIT 801 - 801 0.00 0.00 12.25 6.38 0.08 0.14 0.00 12.65 0.42 1.27 0.00P-DP 50.00RENDEZVOUS NORTH POOLED UNIT 1LA - 1LA 0.44 0.01 7.44 3.87 0.11 0.08 0.00 7.05 0.62 0.87 0.00P-DP 48.41RENDEZVOUS NORTH POOLED UNIT 9UA - 9UA 0.64 0.01 31.69 18.81 0.95 0.33 0.00 30.66 5.29 4.39 0.00P-DP 50.00RIVER CAT 57-33 A 1WA - 1WA 0.13 0.00 2.07 1.07 0.07 0.02 0.00 1.58 0.37 0.27 0.00P-DP 24.76ROADRUNNER 1 - 1 0.39 0.01 3.86 1.95 0.07 0.04 0.00 3.51 0.39 0.44 0.00P-DP 30.93ROADRUNNER 2 - 2 0.41 0.01 8.29 4.20 0.11 0.09 0.00 7.99 0.61 0.95 0.00P-DP 41.36ROCA UNIT 7 1H - 1H 0.64 0.01 4.22 2.21 0.07 0.04 0.00 3.92 0.40 0.51 0.00P-DP 33.45ROCA UNIT 7 2H - 2H 0.42 0.01 0.05 0.03 0.00 0.00 0.00 0.04 0.01 0.01 0.00P-DP 50.00SHOSHONE A 34-166-165 5201H - 5201H 0.01 0.00 18.26 10.02 1.15 0.09 0.00 8.60 6.46 3.56 0.00P-DP 45.97SPIRE 226-34 UNIT 1H - 1H 6.75 0.13 4.14 2.22 0.15 0.03 0.00 3.03 0.86 0.63 0.00P-DP 50.00SRO 551 ALLOC B 101H - 101H 0.89 0.02

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![](exhibit992-202210xk040.jpg)

Economic One-Liners Lease Name Life (years) Oil (Mbbl) Residue Gas (MMcf) Residue Gas (M$) Other (M$) Expense & Tax (M$) Invest. (M$) Non-Disc. (M$) Cash FlowNet Sales Volumes Net Revenue As of Date: 1/1/2023 Reserve Category Oil (M$) Disc. 10% (M$) NGL (M$) NGL (Mbbl) TABLE 6 2.56 1.33 0.14 0.02 0.00 1.39 0.80 0.47 0.00P-DP 37.36SRO 551 ALLOC. A 100H - 100H 0.84 0.02 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00P-DP 0.00STATE EILAND 3-33 11H - 11H 0.00 0.00 4.18 2.71 0.07 0.04 0.00 3.86 0.41 0.51 0.00P-DP 29.59STATE EILAND 6047B-34 51H - 51H 0.42 0.01 2.01 1.05 0.09 0.01 0.00 1.31 0.50 0.33 0.00P-DP 37.71STELLA STATE 34-208 WRD UNIT 1H - 1H 0.52 0.01 3.90 1.93 0.16 0.03 0.00 2.71 0.89 0.62 0.00P-DP 41.51STELLA STATE 34-208 WRD UNIT 2H - 2H 0.92 0.02 1.79 0.95 0.10 0.01 0.00 0.97 0.56 0.33 0.00P-DP 50.00STICKLINE 1H - 1H 0.59 0.01 3.32 1.89 0.03 0.04 0.00 3.30 0.19 0.37 0.00P-DP 31.98TEEWINOT NORTH UNIT 4LA - 4LA 0.20 0.00 8.45 4.04 0.05 0.09 0.00 8.75 0.28 0.87 0.00P-DP 45.85TEEWINOT SOUTH UNIT 5LA - 5LA 0.29 0.01 0.01 0.00 0.00 0.00 0.00 0.01 0.00 0.00 0.00P-DP 22.24TIPI CHAPMAN 34-163 1H - 1H 0.00 0.00 0.01 0.00 0.00 0.00 0.00 0.01 0.00 0.00 0.00P-DP 30.90TIPI CHAPMAN 34-163 2H - 2H 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00P-DP 17.05TIPI CHAPMAN 34-163 3H - 3H 0.00 0.00 0.02 0.01 0.00 0.00 0.00 0.02 0.00 0.00 0.00P-DP 34.72TIPI CHAPMAN 34-163 4H - 4H 0.00 0.00 1.45 0.80 0.00 0.02 0.00 1.54 0.02 0.14 0.00P-DP 32.59TRAUBE 1-11 WRD 1H - 1H 0.03 0.00 2.04 1.10 0.04 0.02 0.00 1.82 0.24 0.26 0.00P-DP 35.29TRAUBE 1-11 WRD 2H - 2H 0.25 0.00 1.38 0.77 0.08 0.01 0.00 0.74 0.44 0.25 0.00P-DP 32.42TRIDACNA 34-208 WRD UNIT 1H - 1H 0.46 0.01 1.34 0.76 0.08 0.01 0.00 0.70 0.43 0.25 0.00P-DP 29.81TRIDACNA 34-208 WRD UNIT 2H - 2H 0.45 0.01 1.24 0.70 0.05 0.01 0.00 0.84 0.29 0.20 0.00P-DP 33.54TRIDACNA 34-208 WRD UNIT 3H - 3H 0.31 0.01 0.38 0.23 0.02 0.00 0.00 0.25 0.09 0.06 0.00P-DP 21.17TROTT 34-183 1H - 1H 0.10 0.00 0.90 0.65 0.03 0.01 0.00 0.68 0.18 0.13 0.00P-DP 11.62VICKERS '34-127' 1H - 1H 0.18 0.00 1.51 0.93 0.02 0.02 0.00 1.46 0.11 0.17 0.00P-DP 22.32VICKERS '34-127' 2H - 2H 0.12 0.00 2.16 1.34 0.01 0.02 0.00 2.22 0.08 0.22 0.00P-DP 33.52WHIRLAWAY 99 1HA - 1HA 0.08 0.00 0.26 0.15 0.00 0.00 0.00 0.26 0.01 0.03 0.00P-DP 50.00WHISKEY RIVER 9596A-34 11H - 11H 0.01 0.00 0.07 0.04 0.00 0.00 0.00 0.06 0.01 0.01 0.00P-DP 35.73WHISKEY RIVER 9596A-34 12H - 12H 0.01 0.00 0.05 0.03 0.00 0.00 0.00 0.05 0.00 0.01 0.00P-DP 31.80WHISKEY RIVER 9596A-34 13H - 13H 0.00 0.00 0.07 0.04 0.00 0.00 0.00 0.07 0.00 0.01 0.00P-DP 41.56WHISKEY RIVER 9596B-34 1H - 1H 0.00 0.00 0.13 0.07 0.00 0.00 0.00 0.13 0.01 0.02 0.00P-DP 46.57WHISKEY RIVER 9596B-34 31H - 31H 0.01 0.00 0.18 0.10 0.00 0.00 0.00 0.16 0.02 0.02 0.00P-DP 47.38WHISKEY RIVER 9596B-34 32H - 32H 0.02 0.00 0.21 0.10 0.00 0.00 0.00 0.21 0.01 0.02 0.00P-DP 50.00WHISKEY RIVER 9596C-34 1H - 1H 0.01 0.00 0.13 0.07 0.00 0.00 0.00 0.13 0.01 0.02 0.00P-DP 46.03WHISKEY RIVER 9596D-34 81H - 81H 0.01 0.00 11.13 6.05 0.67 0.06 0.00 5.59 3.74 2.11 0.00P-DP 50.00WILSON 184-185 UNIT 2H - 2H 3.91 0.08 0.56 0.36 0.01 0.01 0.00 0.51 0.05 0.07 0.00P-DP 22.64WRIGHT 1-22 E WRD UNIT 2H - 2H 0.05 0.00 1.30 0.74 0.02 0.01 0.00 1.23 0.11 0.15 0.00P-DP 34.51WRIGHT 1-22 W WRD UNIT 2H - 2H 0.11 0.00 0.66 0.34 0.01 0.01 0.00 0.61 0.07 0.08 0.00P-DP 45.65WRIGHT 1-22E WRD 1H - 1H 0.07 0.00 3.90 2.75 0.25 0.02 0.00 1.46 1.60 0.85 0.00P-DP 12.41LION #1H - 1H 1.69 0.04 7.88 4.91 0.58 0.02 0.00 2.10 3.71 1.86 0.00P-DP 31.30LION #3H - 3H 3.93 0.08

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![](exhibit992-202210xk041.jpg)

Economic One-Liners Lease Name Life (years) Oil (Mbbl) Residue Gas (MMcf) Residue Gas (M$) Other (M$) Expense & Tax (M$) Invest. (M$) Non-Disc. (M$) Cash FlowNet Sales Volumes Net Revenue As of Date: 1/1/2023 Reserve Category Oil (M$) Disc. 10% (M$) NGL (M$) NGL (Mbbl) TABLE 6 23.78 13.26 1.98 0.04 0.00 3.67 12.70 6.07 0.00P-DP 34.55NE AXIS #2H - 2H 13.48 0.28 19.42 11.31 0.53 0.17 0.00 15.30 3.38 2.85 0.00P-DP 50.00TIGIWON 2627-C23 E 433H - 1H 3.59 0.08 222.91 85,551.76 136,366.46 0.00 34,403.70 0.00 135,622.54 20,708.19 21,714.14Total 50.00 14,439.44 361.20 Proved Behind Pipe Rsv Class & Category 49.98 32.84 0.66 0.46 0.00 42.82 3.92 5.12 0.00P-BP 49.42CHAPARRAL UNIT A5 5AH - 5AH 8.35 0.19 160.66 102.04 4.88 1.31 0.00 122.30 28.25 19.83 0.00P-BP 50.00CALVERLEY-LANE 30G 7H - 7H 29.94 0.89 137.98 90.83 3.26 1.23 0.00 114.73 18.84 15.54 0.00P-BP 48.73CALVERLEY-LANE 30H 8H - 8H 19.96 0.59 160.43 101.63 4.88 1.31 0.00 122.12 28.21 19.80 0.00P-BP 50.00CALVERLEY-LANE 30I 9H - 9H 29.90 0.89 222.70 130.46 9.74 1.48 0.00 138.86 56.34 32.21 0.00P-BP 50.00CALVERLEY-LANE 30J 10H - 10H 59.71 1.77 165.17 104.40 5.02 1.34 0.00 125.73 29.04 20.39 0.00P-BP 50.00CALVERLEY-LANE 30K 11H - 11H 30.78 0.91 217.33 127.02 9.50 1.45 0.00 135.51 54.98 31.43 0.00P-BP 50.00CALVERLEY-LANE 30L 12H - 12H 58.26 1.73 201.26 125.86 6.12 1.64 0.00 153.21 35.39 24.84 0.00P-BP 50.00DRIVER-LANE 30A 1H - 1H 37.50 1.11 270.96 156.70 11.85 1.81 0.00 168.96 68.55 39.18 0.00P-BP 50.00DRIVER-LANE 30B 2H - 2H 72.64 2.15 201.47 125.70 6.12 1.64 0.00 153.37 35.43 24.87 0.00P-BP 50.00DRIVER-LANE 30C 3H - 3H 37.54 1.11 270.95 156.33 11.85 1.81 0.00 168.95 68.55 39.18 0.00P-BP 50.00DRIVER-LANE 30D 4H - 4H 72.64 2.15 199.71 124.32 6.07 1.63 0.00 152.03 35.12 24.65 0.00P-BP 50.00DRIVER-LANE 30E 5H - 5H 37.21 1.10 280.42 161.37 12.26 1.87 0.00 174.85 70.94 40.55 0.00P-BP 50.00DRIVER-LANE 30F 6H - 6H 75.17 2.23 26.88 16.64 0.82 0.22 0.00 20.47 4.73 3.32 0.00P-BP 50.00HULING 7-19 B 221 - 221 5.01 0.15 28.54 17.64 0.87 0.23 0.00 21.72 5.02 3.52 0.00P-BP 50.00HULING 7-19 D 241 - 241 5.32 0.16 89.81 53.60 1.71 0.81 0.00 75.06 9.81 11.82 0.00P-BP 50.00LULO 2531LP 4H - 4H 16.76 0.37 64.32 39.82 1.26 0.58 0.00 53.40 7.18 8.53 0.00P-BP 50.00LULO 2533LP 8H - 8H 12.27 0.27 65.89 40.74 1.29 0.59 0.00 54.70 7.36 8.74 0.00P-BP 50.00LULO 2543DP 6H - 6H 12.57 0.27 113.67 67.20 1.49 1.12 0.00 103.84 8.51 13.23 0.00P-BP 50.00LULO 2551AP 5H - 5H 14.54 0.32 65.88 40.64 1.29 0.59 0.00 54.70 7.36 8.74 0.00P-BP 50.00LULO 2553AP 9H - 9H 12.57 0.27 106.95 63.08 1.40 1.06 0.00 97.70 8.01 12.45 0.00P-BP 50.00LULO 3641DP 2H - 2H 13.68 0.30 978.67 570.69 15.17 9.34 0.00 863.49 86.80 119.90 0.00P-BP 50.00SCATTER TISH 10-46 (ALLOC-D) 4NA 148.28 3.23 773.22 458.34 13.95 7.11 0.00 656.81 79.80 99.69 0.00P-BP 50.00SCATTER TISH 10-46 (ALLOC-D) 4NS 136.31 2.97 93.36 55.72 1.82 0.84 0.00 77.51 10.42 12.38 0.00P-BP 50.00TREE FROG 47 WEST UNIT 7WB - 7WB 17.80 0.39 16.65 9.99 3.39 0.00 0.00 0.00 21.79 5.14 0.00P-BP 43.27POINTER N CRC JF 7H - 7H 0.00 0.00 23.96 14.21 4.88 0.00 0.00 0.00 31.35 7.39 0.00P-BP 48.99POINTER N CRC JF 9H - 9H 0.00 0.00 19.35 11.53 3.94 0.00 0.00 0.00 25.33 5.97 0.00P-BP 45.65POINTER W CRC JF 5H - 5H 0.00 0.00 25.24 16.39 0.75 0.21 0.00 19.16 4.80 3.82 0.00P-BP 50.00B AND B 6H - 6H 5.09 0.11 20.31 13.18 0.60 0.17 0.00 15.42 3.86 3.08 0.00P-BP 50.00B AND B STATE B 7H - 7H 4.10 0.09 23.27 15.49 0.42 0.20 0.00 18.94 2.37 2.60 0.00P-BP 50.00BADFISH 31-43 A 1JM - 1JM 4.56 0.11 26.09 16.70 0.46 0.23 0.00 21.38 2.60 2.89 0.00P-BP 50.00BADFISH 31-43 A 4LS - 4LS 5.00 0.12

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![](exhibit992-202210xk042.jpg)

Economic One-Liners Lease Name Life (years) Oil (Mbbl) Residue Gas (MMcf) Residue Gas (M$) Other (M$) Expense & Tax (M$) Invest. (M$) Non-Disc. (M$) Cash FlowNet Sales Volumes Net Revenue As of Date: 1/1/2023 Reserve Category Oil (M$) Disc. 10% (M$) NGL (M$) NGL (Mbbl) TABLE 6 26.02 16.63 0.46 0.23 0.00 21.32 2.59 2.88 0.00P-BP 50.00BADFISH 31-43 B 9LS - 9LS 4.99 0.12 31.94 20.30 0.39 0.31 0.00 28.73 2.19 3.19 0.00P-BP 50.00BADFISH 31-43 E 5WA - 5WA 4.21 0.10 26.61 17.11 0.60 0.21 0.00 20.00 3.36 3.20 0.00P-BP 50.00BADFISH 31-43 E 7WB - 7WB 6.46 0.16 33.17 21.03 0.41 0.32 0.00 29.84 2.27 3.32 0.00P-BP 50.00BADFISH 31-43 F 6WA - 6WA 4.38 0.11 25.69 16.47 0.58 0.21 0.00 19.30 3.24 3.09 0.00P-BP 50.00BADFISH 31-43 F 8WB - 8WB 6.23 0.15 32.93 20.82 0.40 0.32 0.00 29.62 2.26 3.29 0.00P-BP 50.00BADFISH 31-43 J 10WA - 10WA 4.34 0.11 26.09 16.69 0.59 0.21 0.00 19.60 3.29 3.13 0.00P-BP 50.00BADFISH 31-43 J 11WB - 11WB 6.33 0.16 22.43 14.78 0.41 0.20 0.00 18.26 2.28 2.50 0.00P-BP 50.00BADFISH 31-43 L 12MS - 12MS 4.39 0.11 22.08 14.53 0.40 0.19 0.00 17.97 2.25 2.46 0.00P-BP 50.00BADFISH 31-43 M 13JM - 13JM 4.32 0.11 26.11 16.51 0.46 0.23 0.00 21.40 2.60 2.89 0.00P-BP 50.00BADFISH 31-43 M 3LS - 3LS 5.00 0.12 124.73 78.67 2.81 1.00 0.00 93.72 15.73 14.98 0.00P-BP 50.00DIRE WOLF UNIT 1 0402BH - 0402BH 30.26 0.75 227.22 141.34 2.78 2.18 0.00 204.38 15.58 22.71 0.00P-BP 50.00DIRE WOLF UNIT 1 0411AH - 0411AH 29.98 0.74 227.07 141.06 2.78 2.18 0.00 204.24 15.57 22.70 0.00P-BP 50.00DIRE WOLF UNIT 1 0413AH - 0413AH 29.96 0.74 178.51 111.33 3.18 1.56 0.00 146.31 17.78 19.78 0.00P-BP 50.00DIRE WOLF UNIT 1 0422SH - 0422SH 34.21 0.85 157.94 102.23 2.87 1.37 0.00 128.56 16.07 17.62 0.00P-BP 49.60DIRE WOLF UNIT 1 0471JH - 0471JH 30.93 0.77 48.79 29.81 0.60 0.47 0.00 43.88 3.34 4.88 0.00P-BP 50.00HYDRA 45-4 UNIT 2 151 - 151 6.44 0.16 37.69 23.13 0.67 0.33 0.00 30.89 3.75 4.18 0.00P-BP 50.00HYDRA 45-4 UNIT 2 161 - 161 7.22 0.18 51.16 31.19 0.63 0.49 0.00 46.02 3.51 5.11 0.00P-BP 50.00HYDRA 45-4 UNIT 2 164 - 164 6.75 0.17 39.34 24.08 0.70 0.34 0.00 32.24 3.92 4.36 0.00P-BP 50.00HYDRA 45-4 UNIT 2 171 - 171 7.54 0.19 50.69 30.83 0.62 0.49 0.00 45.60 3.48 5.07 0.00P-BP 50.00HYDRA 45-4 UNIT 2 173 - 173 6.69 0.17 39.55 24.14 0.70 0.35 0.00 32.41 3.94 4.38 0.00P-BP 50.00HYDRA 45-4 UNIT 2 181 - 181 7.58 0.19 47.88 29.05 0.59 0.46 0.00 43.06 3.28 4.79 0.00P-BP 50.00HYDRA 45-4 UNIT 2 262 - 262 6.32 0.16 47.64 28.87 0.58 0.46 0.00 42.85 3.27 4.76 0.00P-BP 50.00HYDRA 45-4 UNIT 2 263 - 263 6.28 0.16 50.65 30.66 0.62 0.49 0.00 45.56 3.47 5.06 0.00P-BP 50.00HYDRA 45-4 UNIT 2 272 - 272 6.68 0.17 40.11 24.56 0.90 0.32 0.00 30.14 5.06 4.82 0.00P-BP 50.00HYDRA 45-4 UNIT 2 274 - 274 9.73 0.24 50.73 30.63 0.62 0.49 0.00 45.64 3.48 5.07 0.00P-BP 50.00HYDRA 45-4 UNIT 2 282 - 282 6.69 0.17 78.72 47.73 1.40 0.69 0.00 64.52 7.84 8.72 0.00P-BP 50.00LAMAR 13-1-A 03LS - 03LS 15.08 0.37 100.83 60.74 1.24 0.97 0.00 90.69 6.91 10.08 0.00P-BP 50.00LAMAR 13-1-B 03WA - 03WA 13.30 0.33 80.14 48.85 1.81 0.64 0.00 60.22 10.10 9.62 0.00P-BP 50.00LAMAR 13-1-C 08WB - 08WB 19.44 0.48 79.23 47.86 1.41 0.69 0.00 64.94 7.89 8.78 0.00P-BP 50.00LAMAR 13-1-D 10JM - 10JM 15.18 0.38 100.49 60.33 1.23 0.97 0.00 90.39 6.89 10.04 0.00P-BP 50.00LAMAR 13-1-E 13WA - 13WA 13.26 0.33 79.16 47.71 1.41 0.69 0.00 64.88 7.88 8.77 0.00P-BP 50.00LAMAR 13-1-F 17LS - 17LS 15.17 0.38 78.75 47.41 1.40 0.69 0.00 64.55 7.84 8.73 0.00P-BP 50.00LAMAR 13-1-H 22JM - 22JM 15.09 0.37 80.04 48.49 1.80 0.64 0.00 60.14 10.09 9.61 0.00P-BP 50.00LAMAR 13-1-H G 18WB 19.41 0.48 195.58 119.72 3.56 1.70 0.00 159.21 19.90 21.82 0.00P-BP 49.84NORRIS UNIT 32-H 3332SH - 3332SH 38.30 0.95

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![](exhibit992-202210xk043.jpg)

Economic One-Liners Lease Name Life (years) Oil (Mbbl) Residue Gas (MMcf) Residue Gas (M$) Other (M$) Expense & Tax (M$) Invest. (M$) Non-Disc. (M$) Cash FlowNet Sales Volumes Net Revenue As of Date: 1/1/2023 Reserve Category Oil (M$) Disc. 10% (M$) NGL (M$) NGL (Mbbl) TABLE 6 198.52 121.39 3.61 1.73 0.00 161.60 20.20 22.15 0.00P-BP 49.85NORRIS UNIT 32-H 3333SH - 3333SH 38.87 0.97 224.84 137.31 4.09 1.96 0.00 183.03 22.88 25.09 0.00P-BP 49.86NORRIS-MIMS ALLOCATION 3335SH - 3335SH 44.02 1.09 57.91 33.43 1.30 0.46 0.00 43.52 7.30 6.95 0.00P-BP 50.00WELCH-COX W39F 206H - 206H 14.04 0.35 73.95 42.10 0.91 0.71 0.00 66.52 5.07 7.39 0.00P-BP 50.00WELCH-COX W39G 207H - 207H 9.75 0.24 59.70 34.38 1.34 0.48 0.00 44.86 7.52 7.17 0.00P-BP 50.00WELCH-COX W39H 208H - 208H 14.48 0.36 74.16 42.12 0.91 0.71 0.00 66.71 5.08 7.41 0.00P-BP 50.00WELCH-COX W39I 209H - 209H 9.78 0.24 59.47 34.17 1.34 0.48 0.00 44.69 7.49 7.14 0.00P-BP 50.00WELCH-COX W39J 210H - 210H 14.42 0.36 50.60 29.93 0.92 0.44 0.00 41.19 5.15 5.65 0.00P-BP 50.00WELCH-COX W39K 211H - 211H 9.91 0.25 59.02 33.58 1.05 0.52 0.00 48.38 5.88 6.54 0.00P-BP 50.00WELCH-COX W39L 212H - 212H 11.31 0.28 52.14 30.78 0.95 0.45 0.00 42.45 5.30 5.82 0.00P-BP 49.60WELCH-COX W39M 213H - 213H 10.21 0.25 57.55 32.65 1.02 0.50 0.00 47.17 5.73 6.38 0.00P-BP 50.00WELCH-COX W39N 214H - 214H 11.02 0.27 50.67 29.85 0.92 0.44 0.00 41.25 5.15 5.65 0.00P-BP 49.29WELCH-COX W39O 215H - 215H 9.92 0.25 50.86 29.92 0.92 0.44 0.00 41.41 5.17 5.67 0.00P-BP 49.34WELCH-COX W39P 216H - 216H 9.96 0.25 13.39 7.54 0.39 0.10 0.00 9.76 2.31 1.83 0.00P-BP 50.00STIMSON-NAIL E17T 120H - 120H 3.14 0.08 4.79 2.69 0.14 0.04 0.00 3.49 0.83 0.66 0.00P-BP 50.00STIMSON-NAIL W17P 16H - 16H 1.12 0.03 4.79 2.69 0.14 0.04 0.00 3.49 0.83 0.66 0.00P-BP 50.00STIMSON-NAIL W17Q 17H - 17H 1.12 0.03 4.79 2.69 0.14 0.04 0.00 3.49 0.83 0.66 0.00P-BP 50.00STIMSON-NAIL W17T 20H - 20H 1.12 0.03 2,069.58 1,635.64 398.58 0.00 0.00 0.00 2,331.45 261.87 0.00P-BP 35.27HA RB SU77;NAC ROYALTY 27-41HC 002-ALT - 002-ALT 0.00 0.00 16,311.66 12,894.50 3,141.47 0.00 0.00 0.00 18,375.61 2,063.95 0.00P-BP 35.25HA RB SU92;NAC ROYALTY 34 H 002-ALT - 002-ALT 0.00 0.00 2,070.72 1,563.33 398.80 0.00 0.00 0.00 2,332.73 262.01 0.00P-BP 35.75NAC ROYALTY 27-41 HC 001 - 001 0.00 0.00 71.49 41.24 3.53 0.48 0.00 44.52 20.40 11.78 0.00P-BP 50.00LOST KEYS 4345 1U B 1H - B 1H 18.35 0.39 79.82 45.57 3.11 0.62 0.00 57.47 17.98 11.81 0.00P-BP 50.00LOST KEYS 4345 2U A 2H - A 2H 16.17 0.35 80.94 46.16 3.15 0.63 0.00 58.28 18.24 11.98 0.00P-BP 50.00LOST KEYS 4345 3U A 3H - A 3H 16.40 0.35 51.60 29.39 2.01 0.40 0.00 37.15 11.62 7.63 0.00P-BP 50.00LOST KEYS 4345 4U A 4H - A 4H 10.46 0.22 58.30 33.48 2.88 0.39 0.00 36.31 16.64 9.60 0.00P-BP 50.00LOST KEYS 4345 5U B 5H - B 5H 14.96 0.32 66.26 37.65 2.58 0.52 0.00 47.71 14.93 9.80 0.00P-BP 50.00LOST KEYS 4345 6U A 6H - A 6H 13.43 0.29 100.30 55.55 3.90 0.78 0.00 72.23 22.59 14.85 0.00P-BP 50.00STATE MUDDY WATERS UNIT 711H - 711H 20.32 0.43 92.04 51.37 4.54 0.62 0.00 57.33 26.26 15.17 0.00P-BP 50.00STATE MUDDY WATERS UNIT 731H - 731H 23.62 0.50 89.92 50.14 4.43 0.61 0.00 56.01 25.65 14.82 0.00P-BP 50.00STATE MUDDY WATERS UNIT 732H - 732H 23.07 0.49 88.47 49.27 4.36 0.60 0.00 55.11 25.24 14.58 0.00P-BP 50.00STATE MUDDY WATERS UNIT 733H - 733H 22.70 0.48 87.71 48.78 4.32 0.59 0.00 54.63 25.02 14.45 0.00P-BP 50.00STATE MUDDY WATERS UNIT 751H - 751H 22.51 0.48 98.60 57.55 3.19 0.83 0.00 77.11 18.44 13.54 0.00P-BP 50.00SUGARLOAF 7475 5U B 5H - B 5H 16.59 0.35 25.43 15.49 1.03 0.25 0.00 23.46 5.78 3.95 0.00P-BP 50.00Mud Hen 5 0.14 0.00 39.46 23.78 1.60 0.39 0.00 36.39 8.96 6.11 0.00P-BP 50.00RIVER CAT 57-33 B 2BS - 2BS 0.22 0.00 20.25 12.20 0.82 0.20 0.00 18.67 4.59 3.13 0.00P-BP 49.16RIVER CAT 57-33 C 3TS - 3TS 0.11 0.00

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![](exhibit992-202210xk044.jpg)

Economic One-Liners Lease Name Life (years) Oil (Mbbl) Residue Gas (MMcf) Residue Gas (M$) Other (M$) Expense & Tax (M$) Invest. (M$) Non-Disc. (M$) Cash FlowNet Sales Volumes Net Revenue As of Date: 1/1/2023 Reserve Category Oil (M$) Disc. 10% (M$) NGL (M$) NGL (Mbbl) TABLE 6 0.06 0.03 0.00 0.00 0.00 0.04 0.01 0.01 0.00P-BP 50.00SHOSHONE B 34-166-165 TB 2H - 2H 0.01 0.00 82.80 21,984.71 30,266.48 0.00 3,821.10 0.00 24,508.40 7,714.33 4,193.75Total 50.00 1,864.85 47.08 Proved Undeveloped Rsv Class & Category 48.85 24.90 0.95 0.44 0.00 40.57 5.45 6.48 0.00P-UD 50.00TREE FROG 47 WEST UNIT 7MS - 7MS 9.31 0.20 29.39 16.25 5.99 0.00 0.00 0.00 38.47 9.07 0.00P-UD 50.00POINTER E CRC JF 11H - 11H 0.00 0.00 1,167.43 649.17 19.29 10.89 0.00 1,019.95 209.68 162.62 0.00P-UD 50.00CHAROLAIS 33 21 B1GB STATE COM 001H - 001H 100.42 2.55 1,167.43 649.17 19.29 10.89 0.00 1,019.95 209.68 162.62 0.00P-UD 50.00CHAROLAIS 33 21 B1HA STATE COM 001H - 001H 100.42 2.55 49.32 25.01 0.90 0.43 0.00 40.15 5.01 5.50 0.00P-UD 50.00WELCH-COX E39A 301H - 301H 9.65 0.24 49.31 24.93 0.90 0.43 0.00 40.15 5.01 5.50 0.00P-UD 50.00WELCH-COX E39B 302H - 302H 9.65 0.24 49.21 24.80 0.89 0.43 0.00 40.07 5.00 5.49 0.00P-UD 50.00WELCH-COX E39C 303H - 303H 9.63 0.24 49.23 24.73 0.89 0.43 0.00 40.08 5.01 5.49 0.00P-UD 50.00WELCH-COX E39D 304H - 304H 9.63 0.24 49.24 24.66 0.89 0.43 0.00 40.09 5.01 5.49 0.00P-UD 50.00WELCH-COX E39E 305H - 305H 9.63 0.24 49.49 24.71 0.90 0.43 0.00 40.29 5.03 5.52 0.00P-UD 50.00WELCH-COX E39F 306H - 306H 9.68 0.24 51.34 25.55 0.93 0.45 0.00 41.80 5.22 5.73 0.00P-UD 50.00WELCH-COX E39S 319H - 319H 10.04 0.25 51.29 25.44 0.93 0.45 0.00 41.76 5.22 5.72 0.00P-UD 50.00WELCH-COX E39T 320H - 320H 10.04 0.25 51.34 25.39 0.93 0.45 0.00 41.80 5.22 5.73 0.00P-UD 50.00WELCH-COX E39U 321H - 321H 10.04 0.25 51.46 25.37 0.94 0.45 0.00 41.90 5.23 5.74 0.00P-UD 50.00WELCH-COX E39V 322H - 322H 10.07 0.25 51.65 25.39 0.94 0.45 0.00 42.06 5.25 5.76 0.00P-UD 50.00WELCH-COX E39W 323H - 323H 10.11 0.25 106.67 57.77 2.65 0.89 0.00 83.85 15.66 14.12 0.00P-UD 50.00SCRAMBLE C 47-11 4403H - 4403H 21.28 0.57 13.35 6.79 0.39 0.10 0.00 9.74 2.30 1.83 0.00P-UD 50.00STIMSON-NAIL E17K 111H - 111H 3.13 0.08 13.37 6.78 0.39 0.10 0.00 9.75 2.31 1.83 0.00P-UD 50.00STIMSON-NAIL E17L 112H - 112H 3.14 0.08 13.37 6.76 0.39 0.10 0.00 9.76 2.31 1.83 0.00P-UD 50.00STIMSON-NAIL E17M 113H - 113H 3.14 0.08 13.33 6.72 0.39 0.10 0.00 9.73 2.30 1.82 0.00P-UD 50.00STIMSON-NAIL E17N 114H - 114H 3.13 0.08 13.33 6.70 0.39 0.10 0.00 9.72 2.30 1.82 0.00P-UD 50.00STIMSON-NAIL E17O 115H - 115H 3.13 0.08 13.33 6.68 0.39 0.10 0.00 9.72 2.30 1.82 0.00P-UD 50.00STIMSON-NAIL E17P 116H - 116H 3.13 0.08 13.33 6.66 0.39 0.10 0.00 9.72 2.30 1.82 0.00P-UD 50.00STIMSON-NAIL E17Q 117H - 117H 3.13 0.08 13.33 6.64 0.39 0.10 0.00 9.72 2.30 1.82 0.00P-UD 50.00STIMSON-NAIL E17R 118H - 118H 3.13 0.08 13.37 6.64 0.39 0.10 0.00 9.76 2.31 1.83 0.00P-UD 50.00STIMSON-NAIL E17S 119H - 119H 3.14 0.08 4.78 2.37 0.14 0.04 0.00 3.49 0.82 0.65 0.00P-UD 50.00STIMSON-NAIL W17K 11H - 11H 1.12 0.03 4.78 2.36 0.14 0.04 0.00 3.49 0.82 0.65 0.00P-UD 50.00STIMSON-NAIL W17L 12H - 12H 1.12 0.03 4.78 2.35 0.14 0.04 0.00 3.49 0.82 0.65 0.00P-UD 50.00STIMSON-NAIL W17M 13H - 13H 1.12 0.03 4.78 2.34 0.14 0.04 0.00 3.49 0.82 0.65 0.00P-UD 50.00STIMSON-NAIL W17N 14H - 14H 1.12 0.03 4.78 2.34 0.14 0.04 0.00 3.49 0.82 0.65 0.00P-UD 50.00STIMSON-NAIL W17O 15H - 15H 1.12 0.03 4.95 2.41 0.14 0.04 0.00 3.61 0.85 0.68 0.00P-UD 50.00STIMSON-NAIL W17R 18H - 18H 1.16 0.03 4.78 2.32 0.14 0.04 0.00 3.49 0.82 0.65 0.00P-UD 50.00STIMSON-NAIL W17S 19H - 19H 1.12 0.03

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![](exhibit992-202210xk045.jpg)

Economic One-Liners Lease Name Life (years) Oil (Mbbl) Residue Gas (MMcf) Residue Gas (M$) Other (M$) Expense & Tax (M$) Invest. (M$) Non-Disc. (M$) Cash FlowNet Sales Volumes Net Revenue As of Date: 1/1/2023 Reserve Category Oil (M$) Disc. 10% (M$) NGL (M$) NGL (Mbbl) TABLE 6 7.68 3.54 0.22 0.06 0.00 5.61 1.33 1.05 0.00P-UD 50.00WILLOW LAKES 19 192H - 192H 1.80 0.05 7.70 3.53 0.22 0.06 0.00 5.62 1.33 1.05 0.00P-UD 50.00WILLOW LAKES 19 193H - 193H 1.81 0.05 8,872.91 7,035.32 1,708.84 0.00 0.00 0.00 9,995.62 1,122.71 0.00P-UD 31.08HA RB SU92;NAC ROYALTY 34 H 003-ALT - 003-ALT 0.00 0.00 98.28 49.51 3.17 0.83 0.00 76.90 18.36 13.49 0.00P-UD 50.00SUGARLOAF 7475 6U A 6H - A 6H 16.51 0.35 98.01 49.22 3.16 0.83 0.00 76.69 18.31 13.45 0.00P-UD 50.00SUGARLOAF 7475 7U A 7H - A 7H 16.47 0.35 98.13 49.13 3.17 0.83 0.00 76.79 18.33 13.47 0.00P-UD 50.00SUGARLOAF 7475 8U A 8H - A 8H 16.49 0.35 98.44 49.13 3.18 0.83 0.00 77.02 18.38 13.51 0.00P-UD 50.00SUGARLOAF 7475 9U B 9H - B 9H 16.54 0.35 0.07 0.04 0.00 0.00 0.00 0.05 0.02 0.01 0.00P-UD 50.00SHOSHONE C 34-166-165 WA 3H - 3H 0.02 0.00 0.06 0.03 0.00 0.00 0.00 0.04 0.01 0.01 0.00P-UD 50.00SHOSHONE D 34-166-165 TB 4H - 4H 0.01 0.00 0.06 0.03 0.00 0.00 0.00 0.04 0.01 0.01 0.00P-UD 50.00SHOSHONE E 34-166-165 WB 5H - 5H 0.01 0.00 32.57 8,989.59 12,507.73 0.00 1,616.38 0.00 10,633.37 3,045.41 1,784.67Total 50.00 445.33 11.03 Grand Total 338.28 116,526.05 179,140.67 0.00 39,841.18 0.00 170,764.30 31,467.93 27,692.56Total 50.00 16,749.62 419.31

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![](exhibit992-202210xk046.jpg)

&nbsp;&nbsp;&nbsp;&nbsp;Gross Ultimates, Interests, & Prices

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![](exhibit992-202210xk047.jpg)

LEASE NAME GAS PRC INITIAL $/Mcf GROSS ULTIMATE Mbbl GROSS ULTIMATE MMcf CUM GAS MMcf CUM OIL Mbbl EXPENSE INITIAL DECIMAL INTEREST FINAL DECIMAL REVENUE INITIAL DECIMAL INTEREST FINAL DECIMAL OIL PRC INITIAL $/bbl RES CAT AS OF DATE FIXED COST $/MO As of : 01/01/2023 GROSS ULTIMATE RESERVES, CUMULATIVE PRODUCTION AND BASIC ECONOMIC DATA TABLE 7 Proved Producing Rsv Class & Category AUSTIN 5H P-DP 0.0000000 0.0060725 0.0060725 0.0000000 7,541.74 0.00 5.47 91.83 0.00 2,923.01 0 AUSTIN 6H P-DP 0.0000000 0.0060725 0.0060725 0.0000000 7,754.27 0.00 5.47 91.83 0.00 3,011.04 0 AUSTIN 7H P-DP 0.0000000 0.0060725 0.0060725 0.0000000 8,573.93 0.00 5.47 91.83 0.00 3,148.00 0 AUSTIN 8H P-DP 0.0000000 0.0060725 0.0060725 0.0000000 8,749.20 0.00 5.47 91.83 0.00 3,032.76 0 ALPHA 210488 1A P-DP 0.0000000 0.0003237 0.0003237 0.0000000 6,790.12 0.00 6.17 91.83 0.00 5,464.84 0 ALPHA 210488 2B P-DP 0.0000000 0.0003237 0.0003237 0.0000000 8,106.04 0.00 6.17 91.83 0.00 6,389.13 0 ALPHA 210488 3C P-DP 0.0000000 0.0003237 0.0003237 0.0000000 10,500.09 0.00 6.17 91.83 0.00 7,602.32 0 CHARLIE 210468 7A P-DP 0.0000000 0.0018185 0.0018185 0.0000000 14,911.54 0.00 6.17 91.83 0.00 9,812.60 0 CHARLIE 210468 8B P-DP 0.0000000 0.0018185 0.0018185 0.0000000 12,959.01 0.00 6.17 91.83 0.00 9,277.81 0 CHARLIE 210469 10B P-DP 0.0000000 0.0172842 0.0172842 0.0000000 17,530.00 0.00 6.17 91.83 0.00 12,065.66 0 CHARLIE 210469 9A P-DP 0.0000000 0.0172842 0.0172842 0.0000000 17,436.58 0.00 6.17 91.83 0.00 12,104.32 0 CHARLIE 210472 4A P-DP 0.0000000 0.0386492 0.0386492 0.0000000 9,918.04 0.00 6.17 91.83 0.00 7,999.72 0 CHARLIE 210472 5B P-DP 0.0000000 0.0386492 0.0386492 0.0000000 10,718.07 0.00 6.17 91.83 0.00 8,841.31 0 CHARLIE 210472 6C P-DP 0.0000000 0.0386492 0.0386492 0.0000000 9,702.24 0.00 6.17 91.83 0.00 8,411.10 0 CROWIE E RCH BL 3H P-DP 0.0000000 0.0016896 0.0016896 0.0000000 14,354.04 0.00 6.17 91.83 0.00 10,978.54 0 CROWIE RCH BL 1H P-DP 0.0000000 0.0016896 0.0016896 0.0000000 10,039.36 0.00 6.17 91.83 0.00 6,039.36 0 DILLES BOTTOM 210744 3B P-DP 0.0000000 0.0000137 0.0000137 0.0000000 15,733.32 0.00 6.17 91.83 0.00 12,084.94 0 HENDERSHOT 210471 1A P-DP 0.0000000 0.0003040 0.0003040 0.0000000 15,537.29 0.00 6.17 91.83 0.00 9,237.17 0 HENDERSHOT 210471 2B P-DP 0.0000000 0.0003040 0.0003040 0.0000000 16,138.75 0.00 6.17 91.83 0.00 9,361.23 0 KRUPA 210483 3A P-DP 0.0000000 0.0425468 0.0425468 0.0000000 14,804.23 0.00 6.17 91.83 0.00 10,827.58 0 KRUPA 211259 2A P-DP 0.0000000 0.0130602 0.0130602 0.0000000 16,971.04 0.00 6.17 91.83 0.00 12,498.14 0 REITZ UNIT 5H P-DP 0.0000000 0.0002016 0.0002016 0.0000000 12,048.84 0.00 6.17 91.83 0.00 9,985.97 0 SHANNON 210470 3C P-DP 0.0000000 0.0147315 0.0147315 0.0000000 16,875.51 0.01 6.17 91.83 0.01 9,923.28 0 SHANNON 210470 4B P-DP 0.0000000 0.0147315 0.0147315 0.0000000 18,987.85 0.02 6.17 91.83 0.02 10,838.01 0 SHANNON 211271 1B P-DP 0.0000000 0.0147315 0.0147315 0.0000000 14,622.60 0.01 6.17 91.83 0.01 9,323.41 0 SHANNON 211271 2A P-DP 0.0000000 0.0147315 0.0147315 0.0000000 16,509.19 0.01 6.17 91.83 0.01 9,870.85 0 SIDWELL SE WHL BL 10H P-DP 0.0000000 0.0340845 0.0340845 0.0000000 7,927.74 0.00 6.17 91.83 0.00 5,410.34 0 SIDWELL SE WHL BL 8H P-DP 0.0000000 0.0340845 0.0340845 0.0000000 9,344.36 0.00 6.17 91.83 0.00 5,575.15 0 SIDWELL SW WHL BL 2H P-DP 0.0000000 0.0068418 0.0068418 0.0000000 9,440.78 0.00 6.17 91.83 0.00 3,688.62 0 SIDWELL SW WHL BL 4H P-DP 0.0000000 0.0068418 0.0068418 0.0000000 10,827.49 0.00 6.17 91.83 0.00 9,481.48 0 SMASHOSAURUS 3 P-DP 0.0000000 0.0001016 0.0001016 0.0000000 20,075.27 0.00 6.17 91.83 0.00 17,557.08 0 SMASHOSAURUS 5 P-DP 0.0000000 0.0122069 0.0122069 0.0000000 17,270.93 0.00 6.17 91.83 0.00 15,203.92 0 SPITFIRE 1H P-DP 0.0000000 0.0001648 0.0001648 0.0000000 12,137.94 0.00 6.17 91.83 0.00 10,089.70 0 SPITFIRE 3H P-DP 0.0000000 0.0001648 0.0001648 0.0000000 8,596.07 0.00 6.17 91.83 0.00 7,343.04 0 TIGER 210187 2A P-DP 0.0000000 0.0028920 0.0028920 0.0000000 11,138.82 0.00 6.17 91.83 0.00 8,705.46 0 TIGER 210187 3C P-DP 0.0000000 0.0028920 0.0028920 0.0000000 10,172.59 0.00 6.17 91.83 0.00 8,159.29 0

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![](exhibit992-202210xk048.jpg)

LEASE NAME GAS PRC INITIAL $/Mcf GROSS ULTIMATE Mbbl GROSS ULTIMATE MMcf CUM GAS MMcf CUM OIL Mbbl EXPENSE INITIAL DECIMAL INTEREST FINAL DECIMAL REVENUE INITIAL DECIMAL INTEREST FINAL DECIMAL OIL PRC INITIAL $/bbl RES CAT AS OF DATE FIXED COST $/MO As of : 01/01/2023 GROSS ULTIMATE RESERVES, CUMULATIVE PRODUCTION AND BASIC ECONOMIC DATA TABLE 7 TIGER 210187 5B P-DP 0.0000000 0.0028920 0.0028920 0.0000000 8,365.78 0.00 6.17 91.83 0.00 6,946.87 0 TIGER 210475 4C P-DP 0.0000000 0.0000077 0.0000077 0.0000000 9,199.19 0.00 6.17 91.83 0.00 7,372.25 0 TIGER 210476 1A P-DP 0.0000000 0.0028516 0.0028516 0.0000000 10,982.02 0.00 6.17 91.83 0.00 8,617.87 0 VALERIE 210473 1A P-DP 0.0000000 0.0083562 0.0083562 0.0000000 10,776.22 0.00 6.17 91.83 0.00 9,201.61 0 VALERIE 210473 2B P-DP 0.0000000 0.0083562 0.0083562 0.0000000 11,189.23 0.00 6.17 91.83 0.00 9,640.41 0 VALERIE 210473 4C P-DP 0.0000000 0.0083562 0.0083562 0.0000000 12,782.91 0.00 6.17 91.83 0.00 10,708.74 0 VANNELLE SW WHL BL 2H P-DP 0.0000000 0.0121791 0.0121791 0.0000000 15,542.94 0.00 6.17 91.83 0.00 7,259.85 0 YANKEE 210475 5A P-DP 0.0000000 0.0000077 0.0000077 0.0000000 10,729.42 0.00 6.17 91.83 0.00 8,477.60 0 CV RB SUV;SHELBY INTERESTS 31 001 P-DP 0.0000000 0.0192857 0.0192857 0.0000000 525.15 1.24 6.29 91.83 1.24 479.79 0 CV RB SUW;LESHE 36 001 P-DP 0.0000000 0.0986163 0.0986163 0.0000000 1,324.21 0.27 6.29 91.83 0.27 1,076.19 0 CV RB SUW;NAC 36 001-ALT P-DP 0.0000000 0.0986163 0.0986163 0.0000000 652.43 0.26 6.29 91.83 0.26 550.17 0 HA RA SU77;LEE 25-36 HC 001-ALT P-DP 0.0000000 0.0092009 0.0092009 0.0000000 5,953.55 0.00 6.29 91.83 0.00 3,864.35 0 BILLINGSLEY 12 1 P-DP 0.0000000 0.0003906 0.0003906 0.0000000 29.29 43.97 5.72 92.42 25.92 29.29 0 CHAPARRAL UNIT A2 7AH P-DP 0.0000000 0.0010526 0.0010526 0.0000000 659.13 417.24 5.72 92.42 121.70 149.83 0 CHAPARRAL UNIT A3 14SH P-DP 0.0000000 0.0010601 0.0010601 0.0000000 585.07 347.41 5.72 92.42 82.31 104.08 0 CHAPARRAL UNIT A3 20H P-DP 0.0000000 0.0010691 0.0010691 0.0000000 842.58 343.93 5.72 92.42 103.59 147.12 0 CHAPARRAL UNIT A4 6AH P-DP 0.0000000 0.0010590 0.0010590 0.0000000 859.51 503.20 5.72 92.42 147.46 151.31 0 HIGGINBOTHAM UNIT A 30-18 2AH P-DP 0.0000000 0.0011510 0.0011510 0.0000000 1,516.83 551.21 5.72 92.42 363.61 510.59 0 HIGGINBOTHAM UNIT A 30-18 3AH P-DP 0.0000000 0.0011510 0.0011510 0.0000000 890.71 535.38 5.72 92.42 296.79 364.83 0 HIGGINBOTHAM UNIT A 30-18 4AH P-DP 0.0000000 0.0011510 0.0011510 0.0000000 380.90 256.19 5.72 92.42 216.55 215.47 0 HIGGINBOTHAM UNIT B 30-19 1H P-DP 0.0000000 0.0013530 0.0013530 0.0000000 428.20 283.14 5.72 92.42 199.75 197.98 0 HIGGINBOTHAM UNIT B 30-19 7AH P-DP 0.0000000 0.0013530 0.0013530 0.0000000 769.86 384.31 5.72 92.42 284.61 336.09 0 HIGGINBOTHAM UNIT C 30-18 5AH P-DP 0.0000000 0.0011500 0.0011500 0.0000000 909.20 368.94 5.72 92.42 179.44 236.65 0 HIGGINBOTHAM UNIT C 30-18 6AH P-DP 0.0000000 0.0011500 0.0011500 0.0000000 899.43 291.57 5.72 92.42 169.28 229.69 0 JOTUNN UNIT A 25-24 3AH P-DP 0.0000000 0.0015620 0.0015620 0.0000000 861.43 367.46 5.72 92.42 264.63 281.26 0 JOTUNN UNIT A 25-24 4AH P-DP 0.0000000 0.0015620 0.0015620 0.0000000 798.93 257.93 5.72 92.42 180.53 273.05 0 JOTUNN UNIT A 25-24 5AH P-DP 0.0000000 0.0015620 0.0015620 0.0000000 690.10 347.17 5.72 92.42 246.41 349.13 0 JOTUNN UNIT B 25-13 6AH P-DP 0.0000000 0.0012790 0.0012790 0.0000000 1,762.73 429.28 5.72 92.42 232.96 345.75 0 JOTUNN UNIT B 25-13 7AH P-DP 0.0000000 0.0012790 0.0012790 0.0000000 975.54 438.44 5.72 92.42 290.54 287.88 0 LEVIATHAN UNIT A 29-17 4AH P-DP 0.0000000 0.0011530 0.0011530 0.0000000 853.52 318.79 5.72 92.42 196.61 233.88 0 LEVIATHAN UNIT A 29-17 5AH P-DP 0.0000000 0.0011530 0.0011530 0.0000000 360.10 496.09 5.72 92.42 289.64 309.19 0 LEVIATHAN UNIT A 29-17 6AH P-DP 0.0000000 0.0011530 0.0011530 0.0000000 1,699.35 322.13 5.72 92.42 213.10 335.48 0 LEVIATHAN UNIT B 29-20 7AH P-DP 0.0000000 0.0017400 0.0017400 0.0000000 370.61 188.46 5.72 92.42 174.04 230.60 0 LEVIATHAN UNIT B 29-20 8SH P-DP 0.0000000 0.0017400 0.0017400 0.0000000 1,569.03 240.23 5.72 92.42 157.35 366.75 0 LEVIATHAN UNIT B 29-20 9AH(8AH) P-DP 0.0000000 0.0017400 0.0017400 0.0000000 673.13 250.76 5.72 92.42 212.08 283.47 0 MEDUSA UNIT A 28-21 1AH P-DP 0.0000000 0.0020270 0.0020270 0.0000000 982.34 304.96 5.72 92.42 231.67 339.51 0 MEDUSA UNIT A 28-21 2AH P-DP 0.0000000 0.0020270 0.0020270 0.0000000 932.60 230.81 5.72 92.42 153.48 280.27 0

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![](exhibit992-202210xk049.jpg)

LEASE NAME GAS PRC INITIAL $/Mcf GROSS ULTIMATE Mbbl GROSS ULTIMATE MMcf CUM GAS MMcf CUM OIL Mbbl EXPENSE INITIAL DECIMAL INTEREST FINAL DECIMAL REVENUE INITIAL DECIMAL INTEREST FINAL DECIMAL OIL PRC INITIAL $/bbl RES CAT AS OF DATE FIXED COST $/MO As of : 01/01/2023 GROSS ULTIMATE RESERVES, CUMULATIVE PRODUCTION AND BASIC ECONOMIC DATA TABLE 7 MEDUSA UNIT B 28-21 7AH P-DP 0.0000000 0.0020250 0.0020250 0.0000000 711.39 283.59 5.72 92.42 198.12 244.40 0 MEDUSA UNIT B 28-21 8AH P-DP 0.0000000 0.0020250 0.0020250 0.0000000 1,050.53 302.69 5.72 92.42 234.71 390.24 0 MEDUSA UNIT C 28-09 3AH P-DP 0.0000000 0.0011540 0.0011540 0.0000000 252.24 459.37 5.72 92.42 265.60 216.49 0 MEDUSA UNIT C 28-09 6AH P-DP 0.0000000 0.0011540 0.0011540 0.0000000 919.32 334.83 5.72 92.42 217.10 292.34 0 CV RA SU91;EDGAR S TALBERT 9 H 001 P-DP 0.0000000 0.0011082 0.0011082 0.0000000 2,966.14 8.88 6.36 91.83 8.88 2,296.13 0 HA RA SU98;PACE 8-14-16 H 001 P-DP 0.0000000 0.0014598 0.0014598 0.0000000 4,161.76 0.00 6.36 91.83 0.00 3,644.99 0 AMAZON 3304-02H P-DP 0.0000000 0.0003120 0.0003120 0.0000000 160.42 251.43 6.10 91.83 202.24 110.54 0 AMAZON 3304-03H P-DP 0.0000000 0.0003120 0.0003120 0.0000000 402.34 589.76 6.10 91.83 363.35 194.66 0 AMAZON 3304-04H P-DP 0.0000000 0.0003120 0.0003120 0.0000000 3,996.31 318.84 6.10 91.83 193.30 2,330.81 0 AMAZON 3304-05H P-DP 0.0000000 0.0003120 0.0003120 0.0000000 3,162.29 381.95 6.10 91.83 239.65 2,023.44 0 BOLT 15-33H P-DP 0.0000000 0.0006200 0.0006200 0.0000000 192.52 271.12 6.10 91.83 182.99 98.07 0 BOLT 406-0904H P-DP 0.0000000 0.0080600 0.0080600 0.0000000 749.55 388.40 6.10 91.83 326.93 427.25 0 BOLT 407-0904H P-DP 0.0000000 0.0080600 0.0080600 0.0000000 711.72 528.87 6.10 91.83 464.15 471.49 0 LEAVITT FED 1-9-4PH P-DP 0.0000000 0.0080600 0.0080600 0.0000000 789.09 591.15 6.10 91.83 361.91 337.88 0 LEAVITT FED 1-9-4TH P-DP 0.0000000 0.0080600 0.0080600 0.0000000 2,904.48 355.26 6.10 91.83 225.31 1,574.69 0 LEAVITT FED 2-9-4PH P-DP 0.0000000 0.0080600 0.0080600 0.0000000 1,359.12 663.35 6.10 91.83 346.64 478.38 0 BROWN, A. D. 2 P-DP 0.0000000 0.0026042 0.0026042 0.0000000 70.46 99.18 5.91 93.66 97.12 70.46 0 CHAPARRAL UNIT A5 13SH P-DP 0.0000000 0.0010590 0.0010590 0.0000000 990.87 561.90 5.91 93.66 101.29 117.66 0 CHAPARRAL UNIT A5 19H P-DP 0.0000000 0.0010543 0.0010543 0.0000000 423.16 316.42 5.91 93.66 97.63 85.99 0 DAVID 1 P-DP 0.0000000 0.0031250 0.0031250 0.0000000 50.15 107.60 5.91 93.66 79.90 50.15 0 EAST ACKERLY DEAN UNIT 99 P-DP 0.0000000 0.0000223 0.0000223 0.0000000 58.12 151.42 5.91 93.66 121.45 44.32 0 OAK VALLEY 2 1 P-DP 0.0000000 0.0035807 0.0035807 0.0000000 163.58 84.01 5.91 93.66 54.69 82.09 0 OV UNIT 1 P-DP 0.0000000 0.0034314 0.0034314 0.0000000 174.35 86.24 5.91 93.66 54.64 90.73 0 OVMLC 1 P-DP 0.0000000 0.0035807 0.0035807 0.0000000 298.68 105.09 5.91 93.66 71.13 183.11 0 OVMLC 2 P-DP 0.0000000 0.0035807 0.0035807 0.0000000 58.23 92.05 5.91 93.66 58.64 27.62 0 WALLACE, T. L. 1 P-DP 0.0000000 0.0002339 0.0002339 0.0000000 149.40 476.47 5.91 93.66 461.55 149.40 0 WALLACE, T. L. 3 P-DP 0.0000000 0.0002390 0.0002390 0.0000000 39.39 112.75 5.91 93.66 105.55 39.39 0 WHITE 19 P-DP 0.0000000 0.0006510 0.0006510 0.0000000 121.98 57.20 5.91 93.66 47.69 119.65 0 HA RA SUSS;JORDAN 16-21 HC 001-ALT P-DP 0.0000000 0.0004531 0.0004531 0.0000000 9,593.23 0.00 6.29 91.83 0.00 9,455.40 0 HA RA SUTT;BSMC LA 21 HZ 001 P-DP 0.0000000 0.0006879 0.0006879 0.0000000 3,955.34 0.00 6.29 91.83 0.00 3,883.34 0 ADAMEK UNIT 2H P-DP 0.0000000 0.0105000 0.0105000 0.0000000 1,807.95 122.58 6.68 91.44 90.43 1,356.20 0 BOENING UNIT 1H P-DP 0.0000000 0.0106684 0.0106684 0.0000000 1,189.90 186.64 6.68 91.44 151.85 1,076.23 0 BOENING UNIT 2H P-DP 0.0000000 0.0106684 0.0106684 0.0000000 1,704.69 167.12 6.68 91.44 146.38 1,389.72 0 BOENING UNIT 3H P-DP 0.0000000 0.0106684 0.0106684 0.0000000 2,463.10 281.85 6.68 91.44 190.49 1,560.96 0 BOENING UNIT 4H P-DP 0.0000000 0.0106684 0.0106684 0.0000000 1,859.19 237.28 6.68 91.44 181.22 1,425.00 0 BOENING UNIT 6L P-DP 0.0000000 0.0106684 0.0106684 0.0000000 1,670.09 239.98 6.68 91.44 142.56 1,136.29 0 BOENING UNIT 6U P-DP 0.0000000 0.0106684 0.0106684 0.0000000 1,598.18 251.40 6.68 91.44 132.51 844.05 0

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![](exhibit992-202210xk050.jpg)

LEASE NAME GAS PRC INITIAL $/Mcf GROSS ULTIMATE Mbbl GROSS ULTIMATE MMcf CUM GAS MMcf CUM OIL Mbbl EXPENSE INITIAL DECIMAL INTEREST FINAL DECIMAL REVENUE INITIAL DECIMAL INTEREST FINAL DECIMAL OIL PRC INITIAL $/bbl RES CAT AS OF DATE FIXED COST $/MO As of : 01/01/2023 GROSS ULTIMATE RESERVES, CUMULATIVE PRODUCTION AND BASIC ECONOMIC DATA TABLE 7 CHUMCHAL UNIT 1H P-DP 0.0000000 0.0101899 0.0101899 0.0000000 731.99 116.44 6.68 91.44 115.81 724.61 0 CHUMCHAL UNIT 4H P-DP 0.0000000 0.0101899 0.0101899 0.0000000 867.88 126.27 6.68 91.44 114.81 812.67 0 CHUMCHAL UNIT 6L P-DP 0.0000000 0.0101899 0.0101899 0.0000000 1,641.70 241.45 6.68 91.44 165.21 1,188.18 0 CHUMCHAL UNIT 7L P-DP 0.0000000 0.0101899 0.0101899 0.0000000 1,763.15 247.04 6.68 91.44 176.13 1,321.10 0 COLLE UNIT 1H P-DP 0.0000000 0.0199165 0.0199165 0.0000000 1,598.84 208.49 6.68 91.44 158.44 1,327.96 0 FIELDS UNIT 1H P-DP 0.0000000 0.0217246 0.0217246 0.0000000 1,229.38 129.91 6.68 91.44 105.21 1,034.01 0 FIELDS UNIT 2H P-DP 0.0000000 0.0217246 0.0217246 0.0000000 1,021.28 85.23 6.68 91.44 70.86 897.38 0 FIELDS UNIT 3H P-DP 0.0000000 0.0217246 0.0000000 0.0000000 745.14 83.70 6.68 91.44 83.70 745.14 0 FIELDS UNIT 4H P-DP 0.0000000 0.0217246 0.0217246 0.0000000 962.23 99.51 6.68 91.44 83.07 739.62 0 GERDES UNIT 1H P-DP 0.0000000 0.0176399 0.0176399 0.0000000 1,167.65 175.24 6.68 91.44 166.03 1,119.99 0 GERDES UNIT 2H P-DP 0.0000000 0.0176399 0.0176399 0.0000000 1,154.63 152.46 6.68 91.44 130.71 845.55 0 GERDES UNIT 3H P-DP 0.0000000 0.0176399 0.0176399 0.0000000 1,018.85 159.09 6.68 91.44 144.38 902.78 0 GERDES UNIT 4H P-DP 0.0000000 0.0176399 0.0176399 0.0000000 1,346.33 183.06 6.68 91.44 158.28 1,207.28 0 GERDES UNIT 5H P-DP 0.0000000 0.0176399 0.0176399 0.0000000 1,329.33 199.46 6.68 91.44 144.06 1,035.26 0 GERDES UNIT 6H P-DP 0.0000000 0.0176399 0.0176399 0.0000000 1,388.91 209.46 6.68 91.44 147.26 1,049.83 0 GERDES-LANGHOFF 1L P-DP 0.0000000 0.0140696 0.0140696 0.0000000 2,161.55 336.81 6.68 91.44 231.29 1,501.94 0 GERDES-RATHKAMP 1L P-DP 0.0000000 0.0124874 0.0124874 0.0000000 2,319.67 355.71 6.68 91.44 229.67 1,499.56 0 HOERMANN UNIT 1H P-DP 0.0000000 0.0100962 0.0100962 0.0000000 847.89 150.35 6.68 91.44 150.35 845.37 0 HOERMANN UNIT 2H P-DP 0.0000000 0.0100962 0.0100962 0.0000000 1,197.66 194.30 6.68 91.44 174.87 1,106.73 0 HOERMANN UNIT 3H P-DP 0.0000000 0.0100962 0.0100962 0.0000000 2,389.43 368.57 6.68 91.44 252.52 1,818.13 0 HOERMANN UNIT 4H P-DP 0.0000000 0.0100962 0.0100962 0.0000000 1,832.27 337.32 6.68 91.44 226.84 1,399.18 0 JANAK UNIT 1H P-DP 0.0000000 0.0251620 0.0251620 0.0000000 634.17 96.17 6.68 91.44 95.09 634.17 0 JANAK UNIT 3H P-DP 0.0000000 0.0251620 0.0251620 0.0000000 995.60 104.36 6.68 91.44 88.32 938.86 0 JANAK UNIT 4H P-DP 0.0000000 0.0251620 0.0251620 0.0000000 1,373.24 144.67 6.68 91.44 123.49 1,218.65 0 JANAK UNIT 5H P-DP 0.0000000 0.0251620 0.0251620 0.0000000 1,229.71 120.71 6.68 91.44 104.13 1,072.26 0 JANAK UNIT 7L P-DP 0.0000000 0.0251620 0.0251620 0.0000000 604.68 66.49 6.68 91.44 49.53 472.72 0 JANAK-LOOS 6L P-DP 0.0000000 0.0128380 0.0128380 0.0000000 1,059.42 121.09 6.68 91.44 85.23 822.37 0 KAISER UNIT 1H P-DP 0.0000000 0.0189370 0.0189370 0.0000000 1,088.06 95.21 6.68 91.44 87.70 1,021.85 0 KAISER UNIT 4H P-DP 0.0000000 0.0189370 0.0189370 0.0000000 1,376.40 112.98 6.68 91.44 98.09 1,066.95 0 KAISER UNIT 5H P-DP 0.0000000 0.0189370 0.0189370 0.0000000 1,476.26 129.76 6.68 91.44 106.04 1,291.86 0 LANGHOFF UNIT A 1H P-DP 0.0000000 0.0103536 0.0103536 0.0000000 2,354.42 212.69 6.68 91.44 212.22 1,955.21 0 LANGHOFF UNIT A 2H P-DP 0.0000000 0.0103536 0.0103536 0.0000000 1,002.17 130.64 6.68 91.44 127.00 978.64 0 LANGHOFF UNIT A 3H P-DP 0.0000000 0.0103536 0.0103536 0.0000000 733.95 63.88 6.68 91.44 61.26 660.26 0 LANGHOFF UNIT A 4H P-DP 0.0000000 0.0103536 0.0103536 0.0000000 1,182.61 118.38 6.68 91.44 116.74 1,125.46 0 LANGHOFF UNIT A 8L P-DP 0.0000000 0.0103536 0.0103536 0.0000000 1,553.98 144.25 6.68 91.44 90.57 1,035.31 0 LANGHOFF UNIT A 9L P-DP 0.0000000 0.0103536 0.0103536 0.0000000 1,170.25 101.42 6.68 91.44 58.08 728.87 0 LANGHOFF UNIT B 701 P-DP 0.0000000 0.0021378 0.0021378 0.0000000 3,351.52 357.50 6.68 91.44 298.22 2,623.77 0

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![](exhibit992-202210xk051.jpg)

LEASE NAME GAS PRC INITIAL $/Mcf GROSS ULTIMATE Mbbl GROSS ULTIMATE MMcf CUM GAS MMcf CUM OIL Mbbl EXPENSE INITIAL DECIMAL INTEREST FINAL DECIMAL REVENUE INITIAL DECIMAL INTEREST FINAL DECIMAL OIL PRC INITIAL $/bbl RES CAT AS OF DATE FIXED COST $/MO As of : 01/01/2023 GROSS ULTIMATE RESERVES, CUMULATIVE PRODUCTION AND BASIC ECONOMIC DATA TABLE 7 LOOS UNIT 10H P-DP 0.0000000 0.0124811 0.0124811 0.0000000 543.58 93.54 6.68 91.44 87.06 526.66 0 LOOS UNIT 11L P-DP 0.0000000 0.0124811 0.0124811 0.0000000 1,979.30 252.84 6.68 91.44 174.36 1,357.78 0 LOOS UNIT 12L P-DP 0.0000000 0.0124811 0.0124811 0.0000000 1,864.45 190.32 6.68 91.44 123.40 1,223.35 0 LOOS UNIT 1H P-DP 0.0000000 0.0124811 0.0124811 0.0000000 941.05 151.74 6.68 91.44 150.35 894.33 0 LOOS UNIT 8H P-DP 0.0000000 0.0124811 0.0124811 0.0000000 572.24 75.65 6.68 91.44 69.75 526.17 0 LOOS UNIT 9H P-DP 0.0000000 0.0124811 0.0124811 0.0000000 1,341.78 237.40 6.68 91.44 162.23 1,001.97 0 POTH UNIT 1H P-DP 0.0000000 0.0073981 0.0073981 0.0000000 1,546.52 167.81 6.68 91.44 134.97 1,438.69 0 RATHKAMP UNIT 1H P-DP 0.0000000 0.0097130 0.0097130 0.0000000 1,196.70 173.30 6.68 91.44 164.61 1,146.00 0 RATHKAMP UNIT 3H P-DP 0.0000000 0.0097130 0.0097130 0.0000000 1,345.43 132.44 6.68 91.44 122.92 1,262.76 0 RATHKAMP UNIT 4H P-DP 0.0000000 0.0097130 0.0097130 0.0000000 1,048.06 87.42 6.68 91.44 77.81 825.55 0 BLACK, S.E. 42 1 P-DP 0.0000000 0.0117187 0.0117187 0.0000000 316.68 66.75 5.79 93.54 66.36 316.68 0 BOYD, FANNIE 4 P-DP 0.0000000 0.0083859 0.0083859 0.0000000 254.43 48.05 5.79 93.54 44.67 210.49 0 BOYD, FANNIE 5 P-DP 0.0000000 0.0083859 0.0083859 0.0000000 309.26 189.28 5.79 93.54 186.48 274.53 0 BOYD, FANNIE 8 P-DP 0.0000000 0.0083859 0.0083859 0.0000000 225.99 29.79 5.79 93.54 29.79 209.09 0 HULING 'A' 18-7 ESL (ALLOC) 1HA P-DP 0.0000000 0.0004419 0.0004419 0.0000000 1,155.42 202.85 5.79 93.54 144.85 678.65 0 HULING 'D' 18-7 ESL (ALLOC) 4HS P-DP 0.0000000 0.0004425 0.0004425 0.0000000 347.80 117.75 5.79 93.54 100.40 252.75 0 SPRABERRY DRIVER UNIT 478 P-DP 0.0000000 0.0000000 0.0000000 0.0000000 42.05 143.27 5.79 93.54 143.27 42.05 0 SPRABERRY DRIVER UNIT 479 P-DP 0.0000000 0.0000000 0.0000000 0.0000000 15.16 6.27 5.79 93.54 6.27 15.16 0 SPRABERRY DRIVER UNIT 480 P-DP 0.0000000 0.0000000 0.0000000 0.0000000 17.78 8.30 5.79 93.54 8.30 17.78 0 STONE-GIST W45A 1H P-DP 0.0000000 0.0031123 0.0031123 0.0000000 819.33 524.34 5.79 93.54 304.93 276.82 0 STONE-GIST W45B 2H P-DP 0.0000000 0.0031557 0.0031557 0.0000000 865.55 476.99 5.79 93.54 293.38 349.26 0 STONE-GIST W45C 3H P-DP 0.0000000 0.0031135 0.0031135 0.0000000 814.66 542.01 5.79 93.54 332.86 399.19 0 STONE-GIST W45I 9H P-DP 0.0000000 0.0031129 0.0031129 0.0000000 490.84 280.88 5.79 93.54 179.73 201.61 0 STONE-GIST W45J 10H P-DP 0.0000000 0.0031508 0.0031508 0.0000000 810.98 485.38 5.79 93.54 229.13 293.30 0 BUELL 10-11-5 10H P-DP 0.0000000 0.0940794 0.0940794 0.0000000 16,966.61 15.98 6.55 86.44 15.98 12,246.71 0 BUELL 10-11-5 1H P-DP 0.0000000 0.0209883 0.0209883 0.0000000 6,316.20 47.20 6.55 86.44 46.49 4,795.15 0 BUELL 10-11-5 206H P-DP 0.0000000 0.0749937 0.0749937 0.0000000 18,877.27 45.57 6.55 86.44 45.49 12,681.45 0 BUELL 10-11-5 210H P-DP 0.0000000 0.0940794 0.0940794 0.0000000 18,072.85 13.25 6.55 86.44 12.98 12,112.67 0 BUELL 10-11-5 2H P-DP 0.0000000 0.0209883 0.0209883 0.0000000 5,882.35 38.45 6.55 86.44 37.65 4,884.90 0 BUELL 10-11-5 3H P-DP 0.0000000 0.0209883 0.0209883 0.0000000 6,361.72 43.02 6.55 86.44 42.55 5,033.64 0 BUELL 10-11-5 4H P-DP 0.0000000 0.0209883 0.0209883 0.0000000 7,986.42 48.17 6.55 86.44 46.36 6,001.81 0 BUELL 10-11-5 6H P-DP 0.0000000 0.0452066 0.0452066 0.0000000 15,749.38 24.58 6.55 86.44 24.58 11,485.16 0 HOCHSTETLER 7-11-5 5H P-DP 0.0000000 0.0147059 0.0147059 0.0000000 12,959.93 53.63 6.55 86.44 52.36 6,724.63 0 MATTIE 18-11-5 6H P-DP 0.0000000 0.0413913 0.0413913 0.0000000 7,042.16 36.68 6.55 86.44 32.97 4,937.28 0 MATTIE 18-11-5 7H P-DP 0.0000000 0.0413913 0.0413913 0.0000000 6,168.11 35.95 6.55 86.44 34.59 4,414.43 0 MATTIE 18-11-5 8H P-DP 0.0000000 0.0413913 0.0413913 0.0000000 7,688.94 38.40 6.55 86.44 35.78 5,313.39 0 NM HARRISON 16-11-5 10H P-DP 0.0000000 0.0154884 0.0154884 0.0000000 5,848.34 21.27 6.55 86.44 19.13 4,424.54 0

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![](exhibit992-202210xk052.jpg)

LEASE NAME GAS PRC INITIAL $/Mcf GROSS ULTIMATE Mbbl GROSS ULTIMATE MMcf CUM GAS MMcf CUM OIL Mbbl EXPENSE INITIAL DECIMAL INTEREST FINAL DECIMAL REVENUE INITIAL DECIMAL INTEREST FINAL DECIMAL OIL PRC INITIAL $/bbl RES CAT AS OF DATE FIXED COST $/MO As of : 01/01/2023 GROSS ULTIMATE RESERVES, CUMULATIVE PRODUCTION AND BASIC ECONOMIC DATA TABLE 7 NM HARRISON 16-11-5 6H P-DP 0.0000000 0.0155018 0.0155018 0.0000000 6,567.38 57.09 6.55 86.44 54.83 5,425.54 0 NM HARRISON 16-11-5 8H P-DP 0.0000000 0.0154886 0.0154886 0.0000000 7,146.64 45.04 6.55 86.44 44.87 6,064.59 0 NORTH AMERICAN COAL ROYALTY CO BUELL 1 P-DP 0.0000000 0.0788856 0.0788856 0.0000000 10,399.79 32.79 6.55 86.44 32.63 8,779.84 0 NORTH AMERICAN COAL ROYALTY CO BUELL 8H P-DP 0.0000000 0.0788856 0.0788856 0.0000000 10,243.15 33.27 6.55 86.44 32.64 8,777.76 0 SADIE 33-10-4 1H P-DP 0.0000000 0.0704641 0.0704641 0.0000000 11,777.66 1.06 6.55 86.44 1.06 8,809.36 0 SADIE 33-10-4 201H P-DP 0.0000000 0.0704641 0.0704641 0.0000000 12,466.15 2.35 6.55 86.44 2.35 8,647.04 0 SADIE 33-10-4 205H P-DP 0.0000000 0.0082758 0.0082758 0.0000000 15,991.27 0.66 6.55 86.44 0.66 11,390.13 0 SADIE 33-10-4 3H P-DP 0.0000000 0.0306224 0.0306224 0.0000000 14,808.25 4.35 6.55 86.44 4.35 10,704.53 0 SADIE 33-10-4 5H P-DP 0.0000000 0.0309096 0.0309096 0.0000000 13,912.16 1.73 6.55 86.44 1.73 10,024.07 0 ALLRED UNIT B 08-05 5AH P-DP 0.0000000 0.0005800 0.0005800 0.0000000 879.50 693.38 5.72 92.42 589.56 603.70 0 ALLRED UNIT B 08-05 5BH P-DP 0.0000000 0.0005800 0.0005800 0.0000000 1,355.37 220.92 5.72 92.42 194.30 837.49 0 ALLRED UNIT B 08-05 5MH P-DP 0.0000000 0.0005800 0.0005800 0.0000000 1,069.48 254.86 5.72 92.42 133.06 266.48 0 ALLRED UNIT B 08-05 5SH P-DP 0.0000000 0.0005800 0.0005800 0.0000000 849.33 257.91 5.72 92.42 130.37 227.16 0 ALLRED UNIT B 08-05 6AH P-DP 0.0000000 0.0005800 0.0005800 0.0000000 1,165.27 408.01 5.72 92.42 209.31 305.71 0 ALLRED UNIT B 08-05 6MH P-DP 0.0000000 0.0005800 0.0005800 0.0000000 685.48 285.92 5.72 92.42 140.41 192.18 0 ALLRED UNIT B 08-05 6SH P-DP 0.0000000 0.0005800 0.0005800 0.0000000 1,397.17 250.65 5.72 92.42 119.74 376.91 0 ALLRED UNIT B 08-05 7AH P-DP 0.0000000 0.0005800 0.0005800 0.0000000 1,230.56 278.24 5.72 92.42 143.93 322.48 0 ALLRED UNIT B 08-05 7BH P-DP 0.0000000 0.0005800 0.0005800 0.0000000 1,449.15 158.62 5.72 92.42 83.02 374.15 0 ALLRED UNIT B 08-05 8AH P-DP 0.0000000 0.0005800 0.0005800 0.0000000 590.11 667.42 5.72 92.42 552.85 428.35 0 ALLRED UNIT B 08-05 8SH P-DP 0.0000000 0.0005800 0.0005800 0.0000000 683.79 460.28 5.72 92.42 403.53 482.70 0 ARON 41-32 #1AH P-DP 0.0000000 0.0083770 0.0083770 0.0000000 812.98 200.60 5.72 92.42 156.85 291.15 0 ARON 41-32 #2SH P-DP 0.0000000 0.0083770 0.0083770 0.0000000 461.43 251.72 5.72 92.42 164.29 92.24 0 ARON 41-32 #3AH P-DP 0.0000000 0.0083770 0.0083770 0.0000000 447.49 302.78 5.72 92.42 193.47 338.81 0 ARON 41-32 #3SH P-DP 0.0000000 0.0083770 0.0083770 0.0000000 90.31 216.04 5.72 92.42 162.75 73.84 0 BAKER TRUST 1 P-DP 0.0000000 0.0030208 0.0030208 0.0000000 39.90 30.34 5.72 92.42 28.94 39.90 0 BIG EL 45-04 #1AH P-DP 0.0000000 0.0002840 0.0002840 0.0000000 301.99 255.17 5.72 92.42 252.78 292.80 0 BIG EL 45-04 #1SH P-DP 0.0000000 0.0002840 0.0002840 0.0000000 431.08 298.07 5.72 92.42 295.52 416.72 0 BRUT 40-33 #1AH P-DP 0.0000000 0.0140910 0.0140910 0.0000000 434.88 207.45 5.72 92.42 206.68 229.98 0 CATES 24 1 P-DP 0.0000000 0.0043750 0.0043750 0.0000000 69.04 39.39 5.72 92.42 37.62 68.77 0 CHAPARRAL UNIT A1 15SH P-DP 0.0000000 0.0011199 0.0011199 0.0000000 1,245.42 407.89 5.72 92.42 231.78 305.81 0 CHAPARRAL UNIT A1 21H P-DP 0.0000000 0.0010455 0.0010455 0.0000000 629.94 491.05 5.72 92.42 256.04 271.56 0 CHAPARRAL UNIT A1 8AH P-DP 0.0000000 0.0010427 0.0010427 0.0000000 1,020.28 628.86 5.72 92.42 356.05 346.46 0 CLARICE STARLING SUNDOWN B 4521LS P-DP 0.0000000 0.0053340 0.0053340 0.0000000 1,809.23 675.52 5.72 92.42 285.40 383.58 0 CLARICE STARLING SUNDOWN D 4542WA P-DP 0.0000000 0.0038700 0.0038700 0.0000000 2,661.06 787.85 5.72 92.42 387.50 548.70 0 COLE 36-37 A UNIT A 2H P-DP 0.0000000 0.0001085 0.0001085 0.0000000 112.67 155.60 5.72 92.42 89.62 31.22 0 CRAZY CAT 41-32 #1SH P-DP 0.0000000 0.0083920 0.0083920 0.0000000 601.81 255.25 5.72 92.42 195.13 278.82 0

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![](exhibit992-202210xk053.jpg)

LEASE NAME GAS PRC INITIAL $/Mcf GROSS ULTIMATE Mbbl GROSS ULTIMATE MMcf CUM GAS MMcf CUM OIL Mbbl EXPENSE INITIAL DECIMAL INTEREST FINAL DECIMAL REVENUE INITIAL DECIMAL INTEREST FINAL DECIMAL OIL PRC INITIAL $/bbl RES CAT AS OF DATE FIXED COST $/MO As of : 01/01/2023 GROSS ULTIMATE RESERVES, CUMULATIVE PRODUCTION AND BASIC ECONOMIC DATA TABLE 7 CRAZY CAT 41-32 #2AH P-DP 0.0000000 0.0083920 0.0083920 0.0000000 406.50 223.35 5.72 92.42 194.52 194.07 0 CRAZY CAT 41-32 #3SH P-DP 0.0000000 0.0083920 0.0083920 0.0000000 1,096.33 270.17 5.72 92.42 184.00 379.81 0 CRAZY CAT 41-32 #4AH P-DP 0.0000000 0.0083920 0.0083920 0.0000000 301.01 216.22 5.72 92.42 166.51 118.04 0 EAST B.C. CANYON 1 P-DP 0.0000000 0.0032222 0.0032222 0.0000000 38.16 35.85 5.72 92.42 29.73 38.16 0 GRANT 18A 4HL P-DP 0.0000000 0.0009554 0.0009554 0.0000000 1,257.32 438.34 5.72 92.42 280.20 615.19 0 GRANT 18B 5HJ P-DP 0.0000000 0.0006149 0.0006149 0.0000000 1,310.28 487.17 5.72 92.42 318.32 471.38 0 GRANT 18B 6HK P-DP 0.0000000 0.0006149 0.0006149 0.0000000 1,735.15 511.84 5.72 92.42 297.34 613.04 0 GUITAR 11 1 P-DP 0.0000000 0.0041667 0.0041667 0.0000000 90.99 44.13 5.72 92.42 43.18 80.42 0 GUITAR 11 2 P-DP 0.0000000 0.0031250 0.0031250 0.0000000 73.13 40.61 5.72 92.42 40.55 73.12 0 GUITAR 13 1 P-DP 0.0000000 0.0041111 0.0041111 0.0000000 162.53 62.88 5.72 92.42 61.42 150.06 0 GUNSLINGER UNIT L 4H P-DP 0.0000000 0.0002894 0.0002894 0.0000000 341.83 536.13 5.72 92.42 318.81 221.01 0 HALL 18 1 P-DP 0.0000000 0.0011905 0.0011905 0.0000000 172.63 41.65 5.72 92.42 30.15 167.73 0 HALL 18 2 P-DP 0.0000000 0.0011905 0.0011905 0.0000000 31.65 22.55 5.72 92.42 15.75 31.60 0 HALL 18 3 P-DP 0.0000000 0.0011905 0.0011905 0.0000000 40.10 14.56 5.72 92.42 10.29 39.74 0 HALL 18 4 P-DP 0.0000000 0.0011905 0.0011905 0.0000000 6.41 4.98 5.72 92.42 4.95 6.40 0 KINGSLEY 10HK P-DP 0.0000000 0.0010712 0.0010712 0.0000000 890.91 496.37 5.72 92.42 247.63 324.58 0 KINGSLEY 1HJ P-DP 0.0000000 0.0014351 0.0014351 0.0000000 839.41 428.82 5.72 92.42 202.20 296.29 0 KINGSLEY 2HF P-DP 0.0000000 0.0014266 0.0014266 0.0000000 955.32 390.24 5.72 92.42 191.36 333.99 0 KINGSLEY 3HK P-DP 0.0000000 0.0014262 0.0014262 0.0000000 896.23 481.40 5.72 92.42 255.35 370.23 0 KINGSLEY 4HJ P-DP 0.0000000 0.0038606 0.0038606 0.0000000 802.67 462.82 5.72 92.42 238.45 370.04 0 KINGSLEY 5HK P-DP 0.0000000 0.0038423 0.0038423 0.0000000 751.70 528.28 5.72 92.42 239.51 333.51 0 KINGSLEY 6HF P-DP 0.0000000 0.0038583 0.0038583 0.0000000 1,023.55 367.90 5.72 92.42 178.38 386.62 0 KINGSLEY 7HJ P-DP 0.0000000 0.0010875 0.0010875 0.0000000 850.07 469.61 5.72 92.42 237.18 323.36 0 KINGSLEY 8HK P-DP 0.0000000 0.0010708 0.0010708 0.0000000 1,243.32 392.35 5.72 92.42 213.02 430.35 0 KINGSLEY 9HJ P-DP 0.0000000 0.0010795 0.0010795 0.0000000 651.69 386.88 5.72 92.42 192.39 235.56 0 KRAKEN 10-3 E1 251 P-DP 0.0000000 0.0005532 0.0005532 0.0000000 1,604.44 522.02 5.72 92.42 350.68 578.50 0 KRAKEN 10-3 UNIT 2 153 P-DP 0.0000000 0.0010769 0.0010769 0.0000000 1,454.92 441.33 5.72 92.42 246.09 448.89 0 KRAKEN 10-3 UNIT 2 162 P-DP 0.0000000 0.0010769 0.0010769 0.0000000 2,063.29 605.85 5.72 92.42 288.64 515.10 0 KRAKEN 10-3 UNIT 2 171 P-DP 0.0000000 0.0010769 0.0010769 0.0000000 1,748.16 526.52 5.72 92.42 265.43 495.57 0 KRAKEN 10-3 UNIT 2 252 P-DP 0.0000000 0.0010769 0.0010769 0.0000000 283.57 278.17 5.72 92.42 206.64 188.34 0 KRAKEN 10-3 UNIT 2 261 P-DP 0.0000000 0.0010769 0.0010769 0.0000000 1,341.04 411.33 5.72 92.42 213.79 383.16 0 KRAKEN 10-3 UNIT 2 272 P-DP 0.0000000 0.0010769 0.0010769 0.0000000 1,666.25 470.75 5.72 92.42 254.55 472.31 0 LONG 18 1 P-DP 0.0000000 0.0032222 0.0032222 0.0000000 35.80 28.20 5.72 92.42 24.37 35.80 0 MABEE DDA J8 3HK P-DP 0.0000000 0.0000068 0.0000068 0.0000000 703.90 431.64 5.72 92.42 203.44 274.56 0 MEADOR, J. J. 3 P-DP 0.0000000 0.0003120 0.0003120 0.0000000 227.44 88.87 5.72 92.42 84.10 191.58 0 MIDDLETON 21 1 P-DP 0.0000000 0.0041667 0.0041667 0.0000000 194.07 24.81 5.72 92.42 18.46 151.63 0 NEWTON 43A 1HE P-DP 0.0000000 0.0011938 0.0011938 0.0000000 949.89 246.64 5.72 92.42 174.54 442.83 0

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![](exhibit992-202210xk054.jpg)

LEASE NAME GAS PRC INITIAL $/Mcf GROSS ULTIMATE Mbbl GROSS ULTIMATE MMcf CUM GAS MMcf CUM OIL Mbbl EXPENSE INITIAL DECIMAL INTEREST FINAL DECIMAL REVENUE INITIAL DECIMAL INTEREST FINAL DECIMAL OIL PRC INITIAL $/bbl RES CAT AS OF DATE FIXED COST $/MO As of : 01/01/2023 GROSS ULTIMATE RESERVES, CUMULATIVE PRODUCTION AND BASIC ECONOMIC DATA TABLE 7 NEWTON 43A 2HK P-DP 0.0000000 0.0011912 0.0011912 0.0000000 455.49 204.64 5.72 92.42 140.64 370.40 0 NEWTON 43B 3HJ P-DP 0.0000000 0.0004990 0.0004990 0.0000000 374.70 178.77 5.72 92.42 172.31 322.33 0 NEWTON 43B 4HE P-DP 0.0000000 0.0010780 0.0010780 0.0000000 393.73 43.50 5.72 92.42 40.43 369.46 0 NEWTON 43B 5HK P-DP 0.0000000 0.0010802 0.0010802 0.0000000 178.43 230.57 5.72 92.42 224.89 161.00 0 NEWTON 43BK 4HE P-DP 0.0000000 0.0010780 0.0010780 0.0000000 349.41 132.70 5.72 92.42 123.54 271.57 0 NEWTON 43BK 5HK P-DP 0.0000000 0.0010802 0.0010802 0.0000000 493.58 269.44 5.72 92.42 253.50 435.79 0 NEWTON 43C 6HJ P-DP 0.0000000 0.0000000 0.0000000 0.0000000 722.73 387.21 5.72 92.42 311.85 379.66 0 PHILLIPS 7 1 P-DP 0.0000000 0.0031014 0.0031014 0.0000000 65.30 53.84 5.72 92.42 39.97 65.30 0 RINGNECK DOVE 3 P-DP 0.0000000 0.0031014 0.0031014 0.0000000 7.85 20.62 5.72 92.42 16.77 7.85 0 RISING SUN 40-33 #1AH P-DP 0.0000000 0.0140130 0.0140130 0.0000000 750.66 393.35 5.72 92.42 252.93 242.66 0 SIMPSON SMITH 0844 A 1W P-DP 0.0000000 0.0078080 0.0078080 0.0000000 695.22 970.83 5.72 92.42 508.79 384.20 0 SUNDOWN 4524LS P-DP 0.0000000 0.0078090 0.0078090 0.0000000 550.16 543.82 5.72 92.42 481.52 482.58 0 SUNDOWN 4541WA P-DP 0.0000000 0.0078090 0.0078090 0.0000000 2,287.83 908.82 5.72 92.42 431.88 502.23 0 SUNDOWN 4566WB P-DP 0.0000000 0.0078090 0.0078090 0.0000000 360.55 378.56 5.72 92.42 333.72 324.53 0 THE KING 45-04 #1AH P-DP 0.0000000 0.0003560 0.0003560 0.0000000 1,069.71 518.80 5.72 92.42 379.26 387.33 0 THE KING 45-04 #1SH P-DP 0.0000000 0.0003560 0.0003560 0.0000000 491.51 291.48 5.72 92.42 208.81 252.83 0 TISH 46-03 #1AH P-DP 0.0000000 0.0251410 0.0251410 0.0000000 495.14 501.56 5.72 92.42 389.31 333.25 0 TOMCAT 4448WA P-DP 0.0000000 0.0090220 0.0090220 0.0000000 934.91 494.84 5.72 92.42 328.39 300.90 0 TREE FROG 47 EAST A 1LS P-DP 0.0000000 0.0010000 0.0010000 0.0000000 1,029.68 394.07 5.72 92.42 315.63 520.86 0 TREE FROG 47 EAST A 1WA P-DP 0.0000000 0.0010154 0.0010154 0.0000000 1,051.19 643.32 5.72 92.42 504.88 509.35 0 TREE FROG 47 EAST C 3LS P-DP 0.0000000 0.0009949 0.0009949 0.0000000 1,081.16 394.50 5.72 92.42 259.09 513.30 0 TREE FROG 47 EAST C 3WA P-DP 0.0000000 0.0009948 0.0009948 0.0000000 1,724.26 480.65 5.72 92.42 304.11 728.25 0 TREE FROG 47 EAST C 3WB P-DP 0.0000000 0.0009963 0.0009963 0.0000000 886.60 348.42 5.72 92.42 222.06 481.07 0 TREE FROG 47 WEST UNIT 5LS P-DP 0.0000000 0.0010396 0.0010396 0.0000000 587.41 469.43 5.72 92.42 345.38 396.75 0 TREE FROG 47 WEST UNIT 5WA P-DP 0.0000000 0.0010396 0.0010396 0.0000000 1,055.85 597.23 5.72 92.42 415.46 640.92 0 TREE FROG 47 WEST UNIT 5WB P-DP 0.0000000 0.0010396 0.0010396 0.0000000 731.82 431.43 5.72 92.42 288.53 415.53 0 TREE FROG 47 WEST UNIT 7LS P-DP 0.0000000 0.0010396 0.0010396 0.0000000 777.24 246.78 5.72 92.42 154.30 249.90 0 TREE FROG 47 WEST UNIT 7WA P-DP 0.0000000 0.0010396 0.0010396 0.0000000 1,878.44 336.69 5.72 92.42 156.93 498.86 0 URSULA 0848WA P-DP 0.0000000 0.0047990 0.0047990 0.0000000 1,599.61 433.31 5.72 92.42 317.55 380.00 0 URSULA 1546WA P-DP 0.0000000 0.0047990 0.0047990 0.0000000 479.40 325.32 5.72 92.42 209.53 224.80 0 URSULA BIG DADDY B 1527LS P-DP 0.0000000 0.0015210 0.0015210 0.0000000 711.28 391.24 5.72 92.42 230.35 313.38 0 URSULA BIG DADDY B 1547WA P-DP 0.0000000 0.0015870 0.0015870 0.0000000 738.21 479.43 5.72 92.42 320.61 369.34 0 URSULA BIG DADDY C 1528LS P-DP 0.0000000 0.0018030 0.0018030 0.0000000 1,702.54 628.91 5.72 92.42 322.59 503.73 0 URSULA TOMCAT A 4446WA P-DP 0.0000000 0.0076140 0.0076140 0.0000000 1,097.68 686.54 5.72 92.42 465.95 522.66 0 URSULA TOMCAT B 4421LS P-DP 0.0000000 0.0076140 0.0076140 0.0000000 792.92 524.13 5.72 92.42 342.88 390.43 0 URSULA TOMCAT C 4447WA P-DP 0.0000000 0.0076140 0.0076140 0.0000000 1,675.17 761.75 5.72 92.42 416.69 426.91 0 VIPER FOSTER B 4545WA P-DP 0.0000000 0.0050520 0.0050520 0.0000000 759.67 597.03 5.72 92.42 362.79 325.52 0

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![](exhibit992-202210xk055.jpg)

LEASE NAME GAS PRC INITIAL $/Mcf GROSS ULTIMATE Mbbl GROSS ULTIMATE MMcf CUM GAS MMcf CUM OIL Mbbl EXPENSE INITIAL DECIMAL INTEREST FINAL DECIMAL REVENUE INITIAL DECIMAL INTEREST FINAL DECIMAL OIL PRC INITIAL $/bbl RES CAT AS OF DATE FIXED COST $/MO As of : 01/01/2023 GROSS ULTIMATE RESERVES, CUMULATIVE PRODUCTION AND BASIC ECONOMIC DATA TABLE 7 VIPER FOSTER C 4525LS P-DP 0.0000000 0.0050420 0.0050420 0.0000000 1,279.87 591.98 5.72 92.42 345.47 385.27 0 VIPER FOSTER D 4546WA P-DP 0.0000000 0.0050450 0.0050450 0.0000000 1,346.31 641.15 5.72 92.42 380.89 497.62 0 WARD 18CC 1804D P-DP 0.0000000 0.0015893 0.0015893 0.0000000 840.41 578.97 5.72 92.42 345.10 472.72 0 WARD 18D 1803D P-DP 0.0000000 0.0015893 0.0015893 0.0000000 506.56 448.84 5.72 92.42 376.36 409.32 0 ALEX TAMSULA 2 P-DP 0.0000000 0.1100000 0.1100000 0.0000000 64.91 0.00 4.83 91.83 0.00 64.91 0 ALEX TAMSULA 3 P-DP 0.0000000 0.1003470 0.1003470 0.0000000 66.41 0.11 4.83 91.83 0.11 66.41 0 ALEX TAMSULA 4 P-DP 0.0000000 0.1100000 0.1100000 0.0000000 30.05 0.00 4.83 91.83 0.00 30.05 0 BONACCI 1 P-DP 0.0000000 0.1250000 0.1250000 0.0000000 90.19 0.00 4.83 91.83 0.00 90.19 0 BONACCI 2 P-DP 0.0000000 0.1250000 0.1250000 0.0000000 75.99 0.00 4.83 91.83 0.00 75.99 0 CHARLES ADAMCHICK 4 P-DP 0.0000000 0.1250000 0.1250000 0.0000000 37.67 0.00 4.83 91.83 0.00 37.67 0 CHARLES ADAMCHICK 5 P-DP 0.0000000 0.1250000 0.1250000 0.0000000 42.91 0.00 4.83 91.83 0.00 42.91 0 CHARLES ADAMCHICK 7 P-DP 0.0000000 0.1250000 0.1250000 0.0000000 137.89 0.00 4.83 91.83 0.00 137.89 0 CLAWSON 1 P-DP 0.0000000 0.1250000 0.1250000 0.0000000 108.71 0.00 4.83 91.83 0.00 92.35 0 CLAWSON 3 P-DP 0.0000000 0.1250000 0.1250000 0.0000000 193.35 0.00 4.83 91.83 0.00 154.43 0 DANIEL D & EDNA MILLER 1 P-DP 0.0000000 0.1250000 0.1250000 0.0000000 91.62 0.00 4.83 91.83 0.00 91.62 0 DAVID L BONACCI 0031 P-DP 0.0000000 0.1250000 0.1250000 0.0000000 40.75 0.00 4.83 91.83 0.00 40.75 0 GENFIVE ENERGY LLC UNIT P-DP 0.0000000 0.1250000 0.1250000 0.0000000 13,420.01 0.17 4.83 91.83 0.17 12,895.87 0 L E STARTZELL 2 P-DP 0.0000000 0.0301781 0.0301781 0.0000000 108.01 0.00 4.83 91.83 0.00 108.01 0 N A C R C 1-15 ACRES 1 P-DP 0.0000000 0.1250000 0.1250000 0.0000000 33.14 0.00 4.83 91.83 0.00 33.14 0 N A C R C 5-132 P-DP 0.0000000 0.1250000 0.1250000 0.0000000 72.67 0.00 4.83 91.83 0.00 71.84 0 NORTH AMERICAN COAL 1S P-DP 0.0000000 0.1250000 0.1250000 0.0000000 36.21 0.00 4.83 91.83 0.00 36.21 0 AMBER NE WEL JF 3H P-DP 0.0000000 0.0007121 0.0007121 0.0000000 13,714.32 0.00 6.42 91.83 0.00 7,537.46 0 AMBER NW WEL JF 1H P-DP 0.0000000 0.0010075 0.0010075 0.0000000 14,222.76 0.00 6.42 91.83 0.00 8,303.40 0 ARCHIE E WYN JF 6H P-DP 0.0000000 0.0312851 0.0312851 0.0000000 8,749.57 0.00 6.42 91.83 0.00 6,676.79 0 ARCHIE E WYN JF 8H P-DP 0.0000000 0.0312851 0.0312851 0.0000000 7,066.24 0.00 6.42 91.83 0.00 5,404.76 0 ATHENA N SMF JF 3H P-DP 0.0000000 0.0392073 0.0392073 0.0000000 17,770.30 0.00 6.42 91.83 0.00 7,841.07 0 ATHENA NE SMF JF 5H P-DP 0.0000000 0.0574113 0.0574113 0.0000000 16,179.43 0.00 6.42 91.83 0.00 7,260.75 0 ATHENA NE SMF JF 7H P-DP 0.0000000 0.0574113 0.0574113 0.0000000 18,218.96 0.00 6.42 91.83 0.00 5,924.44 0 ATHENA NW SMF JF 1H P-DP 0.0000000 0.0289381 0.0289381 0.0000000 18,912.30 0.00 6.42 91.83 0.00 6,345.85 0 BATES S CRC JF 5H P-DP 0.0000000 0.0802990 0.0802990 0.0000000 18,729.88 0.00 6.42 91.83 0.00 12,760.70 0 BORUM E SMF JF 4H P-DP 0.0000000 0.0211292 0.0211292 0.0000000 10,878.76 0.00 6.42 91.83 0.00 9,026.08 0 BORUM E SMF JF 6H P-DP 0.0000000 0.0211292 0.0211292 0.0000000 12,114.77 0.00 6.42 91.83 0.00 9,464.82 0 BORUM W SMF JF 2H P-DP 0.0000000 0.0013045 0.0013045 0.0000000 10,243.83 0.00 6.42 91.83 0.00 8,161.37 0 CENA WYN JF 2H P-DP 0.0000000 0.0653532 0.0653532 0.0000000 15,234.99 0.00 6.42 91.83 0.00 11,488.43 0 CENA WYN JF 4H P-DP 0.0000000 0.0653532 0.0653532 0.0000000 10,421.91 0.00 6.42 91.83 0.00 8,342.25 0 COLLINS WYN JF 2H P-DP 0.0000000 0.1005277 0.1005277 0.0000000 9,644.10 0.00 6.42 91.83 0.00 7,076.97 0 COLLINS WYN JF 4H P-DP 0.0000000 0.1005277 0.1005277 0.0000000 10,769.57 0.00 6.42 91.83 0.00 7,504.81 0

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![](exhibit992-202210xk056.jpg)

LEASE NAME GAS PRC INITIAL $/Mcf GROSS ULTIMATE Mbbl GROSS ULTIMATE MMcf CUM GAS MMcf CUM OIL Mbbl EXPENSE INITIAL DECIMAL INTEREST FINAL DECIMAL REVENUE INITIAL DECIMAL INTEREST FINAL DECIMAL OIL PRC INITIAL $/bbl RES CAT AS OF DATE FIXED COST $/MO As of : 01/01/2023 GROSS ULTIMATE RESERVES, CUMULATIVE PRODUCTION AND BASIC ECONOMIC DATA TABLE 7 COLLINS WYN JF 6H P-DP 0.0000000 0.1005277 0.1005277 0.0000000 9,183.41 0.00 6.42 91.83 0.00 7,796.89 0 CROSS CREEK A 5H-20 P-DP 0.0000000 0.1190618 0.1190618 0.0000000 9,792.74 0.00 6.42 91.83 0.00 7,013.73 0 DICKSON CRC JF 1H P-DP 0.0000000 0.1203236 0.1203236 0.0000000 13,867.06 0.00 6.42 91.83 0.00 11,103.02 0 DICKSON CRC JF 3H P-DP 0.0000000 0.1203236 0.1203236 0.0000000 11,796.74 0.00 6.42 91.83 0.00 10,028.60 0 DOYEN NE WEL JF 3H P-DP 0.0000000 0.0093247 0.0093247 0.0000000 16,049.41 0.00 6.42 91.83 0.00 8,836.38 0 DOYEN NW WEL JF 1H P-DP 0.0000000 0.0002367 0.0002367 0.0000000 24,039.75 0.00 6.42 91.83 0.00 11,052.30 0 GORDON SE CRC JF 4H P-DP 0.0000000 0.0752589 0.0752589 0.0000000 11,025.96 0.00 6.42 91.83 0.00 8,902.05 0 GORDON SE CRC JF 6H P-DP 0.0000000 0.0752589 0.0752589 0.0000000 10,863.31 0.00 6.42 91.83 0.00 8,450.19 0 GORDON SW CRC JF 2H P-DP 0.0000000 0.0871079 0.0871079 0.0000000 9,731.86 0.00 6.42 91.83 0.00 7,750.19 0 GRISWOLD S WYN JF 4H P-DP 0.0000000 0.0357289 0.0357289 0.0000000 13,408.43 0.00 6.42 91.83 0.00 10,566.07 0 GRISWOLD SW WYN JF 2H P-DP 0.0000000 0.0092237 0.0092237 0.0000000 13,970.88 0.00 6.42 91.83 0.00 11,071.61 0 GRISWOLD WYN JF 6H P-DP 0.0000000 0.0740675 0.0740675 0.0000000 8,752.19 0.00 6.42 91.83 0.00 7,317.58 0 GRISWOLD WYN JF 8H P-DP 0.0000000 0.0740675 0.0740675 0.0000000 10,022.63 0.00 6.42 91.83 0.00 7,670.37 0 MINGO S CRC JF 4H P-DP 0.0000000 0.0209787 0.0209787 0.0000000 14,330.20 0.00 6.42 91.83 0.00 11,630.17 0 MINGO SE CRC JF 6H P-DP 0.0000000 0.0409383 0.0409383 0.0000000 15,971.03 0.00 6.42 91.83 0.00 12,083.73 0 MINGO SW CRC JF 2H P-DP 0.0000000 0.0095069 0.0095069 0.0000000 13,406.37 0.00 6.42 91.83 0.00 10,878.84 0 MINGO W CRC JF 8H P-DP 0.0000000 0.0412216 0.0412216 0.0000000 9,751.59 0.00 6.42 91.83 0.00 7,748.64 0 NAC 3H-20 P-DP 0.0000000 0.1190618 0.1190618 0.0000000 6,081.14 0.00 6.42 91.83 0.00 5,265.59 0 NAC 3H-20 P-DP 0.0000000 0.1190618 0.1190618 0.0000000 974.35 0.00 6.42 91.83 0.00 689.39 0 NAC 4H-20 P-DP 0.0000000 0.1190618 0.1190618 0.0000000 7,314.04 0.00 6.42 91.83 0.00 5,114.29 0 NAC B WYN JF 1H P-DP 0.0000000 0.1157926 0.1157926 0.0000000 6,941.30 0.00 6.42 91.83 0.00 5,491.27 0 NAC B WYN JF 3H P-DP 0.0000000 0.1157926 0.1157926 0.0000000 4,297.37 0.00 6.42 91.83 0.00 3,787.48 0 NAC B WYN JF 5H P-DP 0.0000000 0.1157926 0.1157926 0.0000000 8,085.64 0.00 6.42 91.83 0.00 6,364.75 0 NAC GAS UNIT B 3H-3 P-DP 0.0000000 0.1157926 0.1157926 0.0000000 6,097.33 0.07 6.42 91.83 0.07 5,386.00 0 NOLAN NE CRC JF 3H P-DP 0.0000000 0.0915912 0.0915912 0.0000000 8,763.55 0.00 6.42 91.83 0.00 7,933.80 0 NOLAN NW CRC JF 1H P-DP 0.0000000 0.0972461 0.0972461 0.0000000 22,056.26 0.00 6.42 91.83 0.00 17,292.94 0 NOLAN S CRC JF 2H P-DP 0.0000000 0.0982250 0.0982250 0.0000000 11,857.97 0.00 6.42 91.83 0.00 9,363.32 0 NOLAN S CRC JF 4H P-DP 0.0000000 0.0982250 0.0982250 0.0000000 9,750.91 0.00 6.42 91.83 0.00 7,762.17 0 NOLAN S CRC JF 6H P-DP 0.0000000 0.0972461 0.0972461 0.0000000 10,938.70 0.00 6.42 91.83 0.00 8,601.82 0 PALOS 01-12-241 P-DP 0.0000000 0.1591250 0.1591250 0.0000000 284.05 0.00 6.42 91.83 0.00 202.77 0 PALOS 02-10-239 P-DP 0.0000000 0.0800417 0.0800417 0.0000000 358.15 0.00 6.42 91.83 0.00 261.10 0 PALOS 02-16-240 P-DP 0.0000000 0.1587292 0.1587292 0.0000000 440.29 0.00 6.42 91.83 0.00 288.12 0 PALOS 03-06-245 P-DP 0.0000000 0.1666667 0.1666667 0.0000000 354.75 0.00 6.42 91.83 0.00 237.05 0 PALOS 03-10-232 P-DP 0.0000000 0.1666667 0.1666667 0.0000000 414.76 0.00 6.42 91.83 0.00 315.39 0 PALOS 03-14-233 P-DP 0.0000000 0.1666667 0.1666667 0.0000000 376.67 0.00 6.42 91.83 0.00 320.48 0 PALOS 03-16-231 P-DP 0.0000000 0.1666667 0.1666667 0.0000000 574.85 0.00 6.42 91.83 0.00 481.67 0 PUGGLE E WYN JF 4H P-DP 0.0000000 0.1107177 0.1107177 0.0000000 12,183.40 0.00 6.42 91.83 0.00 9,050.38 0

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![](exhibit992-202210xk057.jpg)

LEASE NAME GAS PRC INITIAL $/Mcf GROSS ULTIMATE Mbbl GROSS ULTIMATE MMcf CUM GAS MMcf CUM OIL Mbbl EXPENSE INITIAL DECIMAL INTEREST FINAL DECIMAL REVENUE INITIAL DECIMAL INTEREST FINAL DECIMAL OIL PRC INITIAL $/bbl RES CAT AS OF DATE FIXED COST $/MO As of : 01/01/2023 GROSS ULTIMATE RESERVES, CUMULATIVE PRODUCTION AND BASIC ECONOMIC DATA TABLE 7 PUGGLE E WYN JF 6H P-DP 0.0000000 0.1107177 0.1107177 0.0000000 12,251.78 0.00 6.42 91.83 0.00 8,842.77 0 PUGGLE W WYN JF 2H P-DP 0.0000000 0.1033932 0.1033932 0.0000000 8,584.33 0.00 6.42 91.83 0.00 8,416.07 0 ROXY CRC JF 1H P-DP 0.0000000 0.0396138 0.0396138 0.0000000 9,192.12 0.00 6.42 91.83 0.00 6,777.21 0 ROXY N CRC JF 3H P-DP 0.0000000 0.0099981 0.0099981 0.0000000 10,318.51 0.00 6.42 91.83 0.00 8,011.90 0 ROXY NE CRC JF 5H P-DP 0.0000000 0.0034336 0.0034336 0.0000000 10,133.28 0.00 6.42 91.83 0.00 8,142.80 0 SPORT E WYN JF 3H P-DP 0.0000000 0.0750150 0.0750150 0.0000000 11,130.56 0.00 6.42 91.83 0.00 3,083.56 0 SPORT W WYN JF 1H P-DP 0.0000000 0.0901972 0.0901972 0.0000000 13,786.33 0.00 6.42 91.83 0.00 3,844.62 0 TANNER WYN JF 2H P-DP 0.0000000 0.1162524 0.1162524 0.0000000 12,321.30 0.00 6.42 91.83 0.00 10,394.51 0 TANNER WYN JF 4H P-DP 0.0000000 0.1162524 0.1162524 0.0000000 14,399.70 0.00 6.42 91.83 0.00 11,712.32 0 THOMPSON E SMF JF 5H P-DP 0.0000000 0.0005497 0.0005497 0.0000000 11,576.06 0.00 6.42 91.83 0.00 8,914.33 0 THOMPSON W SMF JF 1H P-DP 0.0000000 0.0075886 0.0075886 0.0000000 11,652.84 0.00 6.42 91.83 0.00 9,499.50 0 THOMPSON W SMF JF 3H P-DP 0.0000000 0.0075886 0.0075886 0.0000000 12,226.12 0.00 6.42 91.83 0.00 9,294.28 0 FAIREY UNIT 1H P-DP 0.0000000 0.0187018 0.0187018 0.0000000 441.67 136.17 5.98 91.37 114.62 375.96 0 GILLESPIE UNIT 1H P-DP 0.0000000 0.0262016 0.0262016 0.0000000 451.11 161.05 5.98 91.37 140.03 440.75 0 KUBENKA UNIT 1H P-DP 0.0000000 0.0279630 0.0279630 0.0000000 264.47 117.26 5.98 91.37 93.69 219.81 0 MOLNOSKEY UNIT 1H P-DP 0.0000000 0.0230365 0.0230365 0.0000000 762.36 184.75 5.98 91.37 176.16 650.34 0 MOLNOSKEY UNIT 2H P-DP 0.0000000 0.0230365 0.0230365 0.0000000 132.64 146.84 5.98 91.37 95.96 132.51 0 NANCY 1H P-DP 0.0000000 0.0044356 0.0044356 0.0000000 879.25 148.24 5.98 91.37 112.87 748.42 0 SUSTR UNIT 1H P-DP 0.0000000 0.0107181 0.0107181 0.0000000 549.69 201.52 5.98 91.37 172.81 500.02 0 TARGAC UNIT 1H P-DP 0.0000000 0.0235042 0.0235042 0.0000000 409.51 170.91 5.98 91.37 156.05 385.03 0 CHAROLAIS 28 21 B2NC STATE COM 001H P-DP 0.0000000 0.0013984 0.0013984 0.0000000 385.99 410.16 10.87 93.62 242.66 221.87 0 CUATRO HIJOS FEE 003H P-DP 0.0000000 0.0019336 0.0019336 0.0000000 123.14 154.14 10.87 93.62 109.37 81.99 0 CUATRO HIJOS FEE 004H P-DP 0.0000000 0.0019336 0.0019336 0.0000000 97.25 132.21 10.87 93.62 103.44 71.64 0 CUATRO HIJOS FEE 008H P-DP 0.0000000 0.0019336 0.0019336 0.0000000 147.59 143.02 10.87 93.62 137.70 141.44 0 HEREFORD 29 20 W1NC STATE COM 001H P-DP 0.0000000 0.0049500 0.0049500 0.0000000 455.39 580.64 10.87 93.62 238.44 163.07 0 RAMBO E2 08 17 STATE COM 001H P-DP 0.0000000 0.0004834 0.0004834 0.0000000 124.52 236.92 10.87 93.62 75.20 36.20 0 RAMBO E2 08 17 STATE COM 002H P-DP 0.0000000 0.0004834 0.0004834 0.0000000 193.76 312.88 10.87 93.62 94.44 62.01 0 B AND B 1H P-DP 0.0000000 0.0005308 0.0005308 0.0000000 2,456.70 309.96 6.42 92.64 171.71 1,357.92 0 B AND B 2H P-DP 0.0000000 0.0005308 0.0005308 0.0000000 3,797.15 418.80 6.42 92.64 218.20 1,946.55 0 B AND B STATE 4H P-DP 0.0000000 0.0004530 0.0004530 0.0000000 1,968.71 277.59 6.42 92.64 113.20 708.17 0 B AND B STATE A 5H P-DP 0.0000000 0.0004530 0.0004530 0.0000000 3,566.32 439.27 6.42 92.64 153.72 1,236.09 0 BOBCAT 55-1-28 UNIT 1H P-DP 0.0000000 0.0000895 0.0000895 0.0000000 4,770.65 821.33 6.42 92.64 467.17 2,428.42 0 BUCKEYE 55-1-28 UNIT 1H P-DP 0.0000000 0.0000895 0.0000895 0.0000000 3,868.37 704.92 6.42 92.64 418.90 2,290.24 0 CHINOOK 55-1-7 UNIT 1H P-DP 0.0000000 0.0001410 0.0001410 0.0000000 3,071.04 530.74 6.42 92.64 315.78 1,889.92 0 HAWKS 55-1-28 UNIT 1H P-DP 0.0000000 0.0000624 0.0000624 0.0000000 3,766.44 752.40 6.42 92.64 483.21 2,254.39 0 QUICK SILVER 55-1-7 UNIT 1H P-DP 0.0000000 0.0001410 0.0001410 0.0000000 4,234.05 686.99 6.42 92.64 397.29 2,298.86 0 RAINIER 55-1-28 UNIT 1H P-DP 0.0000000 0.0000624 0.0000624 0.0000000 3,758.71 784.25 6.42 92.64 496.42 2,263.68 0

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![](exhibit992-202210xk058.jpg)

LEASE NAME GAS PRC INITIAL $/Mcf GROSS ULTIMATE Mbbl GROSS ULTIMATE MMcf CUM GAS MMcf CUM OIL Mbbl EXPENSE INITIAL DECIMAL INTEREST FINAL DECIMAL REVENUE INITIAL DECIMAL INTEREST FINAL DECIMAL OIL PRC INITIAL $/bbl RES CAT AS OF DATE FIXED COST $/MO As of : 01/01/2023 GROSS ULTIMATE RESERVES, CUMULATIVE PRODUCTION AND BASIC ECONOMIC DATA TABLE 7 REED 24 UNIT 2H P-DP 0.0000000 0.0002962 0.0002962 0.0000000 714.78 624.20 6.42 92.64 478.01 710.27 0 REED 24 UNIT 4H P-DP 0.0000000 0.0002962 0.0002962 0.0000000 462.40 268.29 6.42 92.64 180.60 287.07 0 REED 24 UNIT 5H P-DP 0.0000000 0.0002962 0.0002962 0.0000000 2,008.17 693.05 6.42 92.64 486.74 1,251.57 0 REED 24 UNIT 7H P-DP 0.0000000 0.0002962 0.0002962 0.0000000 2,369.45 776.48 6.42 92.64 524.59 1,409.06 0 REED 24 UNIT 8H P-DP 0.0000000 0.0002962 0.0002962 0.0000000 661.97 592.25 6.42 92.64 451.77 601.88 0 RUSTLER A UNIT #3H P-DP 0.0000000 0.0004679 0.0004679 0.0000000 1,015.98 783.87 6.42 92.64 462.45 688.59 0 RUSTLER A UNIT #4H P-DP 0.0000000 0.0004679 0.0004679 0.0000000 1,884.36 861.61 6.42 92.64 600.06 1,130.77 0 RUSTLER B UNIT #1H P-DP 0.0000000 0.0004679 0.0004679 0.0000000 1,961.52 908.83 6.42 92.64 662.80 1,112.25 0 RUSTLER B UNIT #3H P-DP 0.0000000 0.0004679 0.0004679 0.0000000 1,218.27 829.12 6.42 92.64 529.98 882.99 0 RUSTLER C UNIT #1H P-DP 0.0000000 0.0004690 0.0004690 0.0000000 2,318.33 662.79 6.42 92.64 543.78 1,140.05 0 RUSTLER C UNIT #2H P-DP 0.0000000 0.0004690 0.0004690 0.0000000 325.44 430.31 6.42 92.64 243.86 324.71 0 RUSTLER D UNIT #1H P-DP 0.0000000 0.0004679 0.0004679 0.0000000 678.56 495.20 6.42 92.64 231.48 372.60 0 RUSTLER D UNIT #2H P-DP 0.0000000 0.0004679 0.0004679 0.0000000 572.83 376.32 6.42 92.64 233.33 367.95 0 RUSTLER D UNIT #4H P-DP 0.0000000 0.0004679 0.0004679 0.0000000 852.72 444.58 6.42 92.64 301.48 634.57 0 RUSTLER D UNIT #5H P-DP 0.0000000 0.0004679 0.0004679 0.0000000 796.38 490.45 6.42 92.64 250.00 451.15 0 THORPE 1-74 LOV 1H P-DP 0.0000000 0.0002102 0.0002102 0.0000000 207.40 118.97 6.42 92.64 103.32 207.40 0 THORPE 1-74 LOV 2H P-DP 0.0000000 0.0000797 0.0000797 0.0000000 397.78 56.07 6.42 92.64 48.62 369.99 0 THORPE 1-74 LOV 3H P-DP 0.0000000 0.0000797 0.0000797 0.0000000 1,135.36 460.79 6.42 92.64 316.10 712.24 0 THORPE 1-74 LOV 4H P-DP 0.0000000 0.0001593 0.0001593 0.0000000 428.80 276.77 6.42 92.64 242.17 354.14 0 WRANGLER A UNIT #1H P-DP 0.0000000 0.0004679 0.0004679 0.0000000 1,668.69 676.31 6.42 92.64 425.38 947.70 0 WRANGLER A UNIT #2H P-DP 0.0000000 0.0004679 0.0004679 0.0000000 1,263.88 887.72 6.42 92.64 550.62 812.78 0 WRANGLER B UNIT #1H P-DP 0.0000000 0.0004679 0.0004679 0.0000000 842.53 494.34 6.42 92.64 410.00 705.05 0 WRANGLER B UNIT #2H P-DP 0.0000000 0.0004679 0.0004679 0.0000000 1,803.31 654.81 6.42 92.64 452.48 947.63 0 WRANGLER C UNIT #1H P-DP 0.0000000 0.0004679 0.0004679 0.0000000 1,619.07 739.20 6.42 92.64 430.56 746.29 0 WRANGLER C UNIT #2H P-DP 0.0000000 0.0004679 0.0004679 0.0000000 1,671.07 864.39 6.42 92.64 564.69 1,052.18 0 WRANGLER D UNIT #1H P-DP 0.0000000 0.0004679 0.0004679 0.0000000 1,436.82 695.14 6.42 92.64 481.21 923.83 0 WRANGLER D UNIT #2H P-DP 0.0000000 0.0004679 0.0004679 0.0000000 2,204.00 1,071.80 6.42 92.64 706.86 1,408.45 0 WRIGHT 1-22W WRD 1H P-DP 0.0000000 0.0000705 0.0000705 0.0000000 209.45 159.80 6.42 92.64 156.68 206.35 0 YELLOW ROSE A UNIT 1H P-DP 0.0000000 0.0001586 0.0001586 0.0000000 538.44 703.80 6.42 92.64 485.45 496.16 0 YELLOW ROSE A UNIT 2H P-DP 0.0000000 0.0001586 0.0001586 0.0000000 600.16 667.89 6.42 92.64 470.59 541.96 0 YELLOW ROSE A UNIT 3H P-DP 0.0000000 0.0001586 0.0001586 0.0000000 2,119.65 475.86 6.42 92.64 370.06 1,559.20 0 YELLOW ROSE B UNIT 1H P-DP 0.0000000 0.0001586 0.0001586 0.0000000 583.18 888.22 6.42 92.64 467.71 476.25 0 YELLOW ROSE B UNIT 2H P-DP 0.0000000 0.0001586 0.0001586 0.0000000 250.07 339.41 6.42 92.64 234.19 228.19 0 YELLOW ROSE B UNIT 3H P-DP 0.0000000 0.0001586 0.0001586 0.0000000 3,763.30 839.07 6.42 92.64 449.02 1,848.86 0 ACKERLY BROWN 9 1 P-DP 0.0000000 0.0006510 0.0006510 0.0000000 176.65 137.26 5.60 93.62 114.05 146.58 0 AGGIE THE BULLDOG 39-46 A 1LS P-DP 0.0000000 0.0102086 0.0102086 0.0000000 540.84 225.47 5.60 93.62 185.14 261.74 0 AGGIE THE BULLDOG 39-46 A 1WA P-DP 0.0000000 0.0101899 0.0101899 0.0000000 340.85 484.82 5.60 93.62 346.14 325.07 0

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![](exhibit992-202210xk059.jpg)

LEASE NAME GAS PRC INITIAL $/Mcf GROSS ULTIMATE Mbbl GROSS ULTIMATE MMcf CUM GAS MMcf CUM OIL Mbbl EXPENSE INITIAL DECIMAL INTEREST FINAL DECIMAL REVENUE INITIAL DECIMAL INTEREST FINAL DECIMAL OIL PRC INITIAL $/bbl RES CAT AS OF DATE FIXED COST $/MO As of : 01/01/2023 GROSS ULTIMATE RESERVES, CUMULATIVE PRODUCTION AND BASIC ECONOMIC DATA TABLE 7 AGGIE THE BULLDOG 39-46 A 1WB P-DP 0.0000000 0.0102037 0.0102037 0.0000000 1,350.17 424.51 5.60 93.62 302.31 499.81 0 AGGIE THE BULLDOG 39-46 B 2DN P-DP 0.0000000 0.0122385 0.0122385 0.0000000 1,379.73 362.95 5.60 93.62 293.30 644.83 0 AGGIE THE BULLDOG 39-46 B 2WA P-DP 0.0000000 0.0102027 0.0102027 0.0000000 680.61 270.04 5.60 93.62 216.48 498.51 0 AGGIE THE BULLDOG 39-46 C 3LS P-DP 0.0000000 0.0101997 0.0101997 0.0000000 804.72 180.43 5.60 93.62 178.32 506.36 0 AGGIE THE BULLDOG 39-46 C 3WB P-DP 0.0000000 0.0101958 0.0101958 0.0000000 447.76 247.11 5.60 93.62 188.79 304.81 0 AGGIE THE BULLDOG 39-46 C 4WA P-DP 0.0000000 0.0102037 0.0102037 0.0000000 1,404.61 449.55 5.60 93.62 335.35 721.31 0 AGGIE THE BULLDOG 39-46 D 5LS P-DP 0.0000000 0.0014785 0.0014785 0.0000000 549.73 251.05 5.60 93.62 198.12 338.20 0 AGGIE THE BULLDOG 39-46 D 5WB P-DP 0.0000000 0.0101988 0.0101988 0.0000000 949.48 280.87 5.60 93.62 211.80 485.34 0 AGGIE THE BULLDOG 39-46 D 6WA P-DP 0.0000000 0.0102056 0.0102056 0.0000000 1,096.59 349.49 5.60 93.62 262.33 673.32 0 AGGIE THE BULLDOG 39-46 E 6DN P-DP 0.0000000 0.0102056 0.0102056 0.0000000 760.38 389.38 5.60 93.62 321.06 610.32 0 AGGIE THE BULLDOG 39-46 E 7LS P-DP 0.0000000 0.0102076 0.0102076 0.0000000 492.42 295.98 5.60 93.62 234.22 322.43 0 AGGIE THE BULLDOG 39-46 E 7WA P-DP 0.0000000 0.0102096 0.0102096 0.0000000 782.92 510.04 5.60 93.62 390.02 508.54 0 AGGIE THE BULLDOG 39-46 E 7WB P-DP 0.0000000 0.0102076 0.0102076 0.0000000 980.86 523.19 5.60 93.62 369.14 458.89 0 ANN COLE TRUST 1 P-DP 0.0000000 0.0131250 0.0131250 0.0000000 273.92 182.38 5.60 93.62 145.12 160.59 0 BAYES 16 1 P-DP 0.0000000 0.0003348 0.0003348 0.0000000 229.74 39.41 5.60 93.62 38.97 229.43 0 BAYES 16 2 P-DP 0.0000000 0.0003348 0.0003348 0.0000000 108.38 42.36 5.60 93.62 41.20 108.30 0 BAYES 16A 1 P-DP 0.0000000 0.0003720 0.0003720 0.0000000 600.68 77.59 5.60 93.62 65.23 436.42 0 BAYES 4 3 P-DP 0.0000000 0.0003348 0.0003348 0.0000000 305.87 107.84 5.60 93.62 79.65 285.21 0 BAYES 4A 2 P-DP 0.0000000 0.0003599 0.0003599 0.0000000 162.89 32.63 5.60 93.62 27.08 120.72 0 BAYES 4A 3 P-DP 0.0000000 0.0003599 0.0003599 0.0000000 51.02 23.00 5.60 93.62 19.53 48.46 0 BAYES 4A 4 P-DP 0.0000000 0.0003599 0.0003599 0.0000000 477.46 54.67 5.60 93.62 37.18 423.43 0 BIG JAY 10-15 A 1JD P-DP 0.0000000 0.0004640 0.0004640 0.0000000 192.61 390.86 5.60 93.62 203.44 97.37 0 BIG JAY 10-15 A 1LS P-DP 0.0000000 0.0004639 0.0004639 0.0000000 262.27 367.35 5.60 93.62 209.14 120.73 0 BIG JAY 10-15 A 1MS P-DP 0.0000000 0.0004640 0.0004640 0.0000000 595.15 343.33 5.60 93.62 157.77 219.78 0 BIG JAY 10-15 A 1WA P-DP 0.0000000 0.0004640 0.0004640 0.0000000 4,411.21 426.54 5.60 93.62 238.06 1,431.22 0 BIG JAY 10-15 B 2DN P-DP 0.0000000 0.0004638 0.0004638 0.0000000 1,658.80 279.06 5.60 93.62 173.32 516.08 0 BIG JAY 10-15 B 2LS P-DP 0.0000000 0.0004639 0.0004639 0.0000000 1,876.66 229.60 5.60 93.62 147.83 594.21 0 BIG JAY 10-15 B 2WB P-DP 0.0000000 0.0004642 0.0004642 0.0000000 2,142.24 184.17 5.60 93.62 122.14 583.26 0 BIG JAY 10-15 B 3JC P-DP 0.0000000 0.0004642 0.0004642 0.0000000 1,200.00 267.64 5.60 93.62 167.67 413.54 0 BIG JAY 10-15 C 4LS P-DP 0.0000000 0.0004637 0.0004637 0.0000000 1,401.17 251.10 5.60 93.62 175.71 490.04 0 BIG JAY 10-15 C 4WA P-DP 0.0000000 0.0004640 0.0004640 0.0000000 2,111.86 239.38 5.60 93.62 175.40 771.19 0 BIG JAY 10-15 D 5JC P-DP 0.0000000 0.0004641 0.0004641 0.0000000 880.36 111.80 5.60 93.62 73.79 333.73 0 BIG JAY 10-15 D 6DN P-DP 0.0000000 0.0004642 0.0004642 0.0000000 1,427.35 324.78 5.60 93.62 202.07 547.27 0 BIG JAY 10-15 D 6LS P-DP 0.0000000 0.0004642 0.0004642 0.0000000 1,385.07 284.81 5.60 93.62 200.36 538.41 0 BIG JAY 10-15 D 6WB P-DP 0.0000000 0.0004643 0.0004643 0.0000000 2,334.42 204.06 5.60 93.62 138.24 882.29 0 BIG JAY 10-15 E 7JD P-DP 0.0000000 0.0004663 0.0004663 0.0000000 921.25 298.96 5.60 93.62 196.45 479.43 0 BIG JAY 10-15 E 7LS P-DP 0.0000000 0.0004643 0.0004643 0.0000000 1,307.41 365.05 5.60 93.62 247.28 577.26 0

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![](exhibit992-202210xk060.jpg)

LEASE NAME GAS PRC INITIAL $/Mcf GROSS ULTIMATE Mbbl GROSS ULTIMATE MMcf CUM GAS MMcf CUM OIL Mbbl EXPENSE INITIAL DECIMAL INTEREST FINAL DECIMAL REVENUE INITIAL DECIMAL INTEREST FINAL DECIMAL OIL PRC INITIAL $/bbl RES CAT AS OF DATE FIXED COST $/MO As of : 01/01/2023 GROSS ULTIMATE RESERVES, CUMULATIVE PRODUCTION AND BASIC ECONOMIC DATA TABLE 7 BIG JAY 10-15 E 7MS P-DP 0.0000000 0.0004641 0.0004641 0.0000000 718.98 90.87 5.60 93.62 57.17 349.94 0 BIG JAY 10-15 E 7WA P-DP 0.0000000 0.0004640 0.0004640 0.0000000 1,726.73 278.35 5.60 93.62 215.72 606.87 0 BIG JAY 10-15 F 4MS P-DP 0.0000000 0.0004647 0.0004647 0.0000000 1,264.16 252.78 5.60 93.62 122.17 326.10 0 BOX NAIL 2LM P-DP 0.0000000 0.0000713 0.0000713 0.0000000 721.33 321.57 5.60 93.62 239.57 397.08 0 BOX NAIL 3LL P-DP 0.0000000 0.0000709 0.0000709 0.0000000 799.04 366.52 5.60 93.62 274.40 456.17 0 BOX NAIL E 1LM P-DP 0.0000000 0.0000706 0.0000706 0.0000000 1,005.42 333.14 5.60 93.62 232.26 476.59 0 BROOKS 1 P-DP 0.0000000 0.0112500 0.0112500 0.0000000 176.58 95.45 5.60 93.62 68.81 116.98 0 DARWIN 22 1 P-DP 0.0000000 0.0041071 0.0041071 0.0000000 141.02 72.22 5.60 93.62 49.11 71.90 0 DARWIN 22 2 P-DP 0.0000000 0.0041071 0.0041071 0.0000000 30.01 24.08 5.60 93.62 20.88 28.62 0 DIRE WOLF UNIT 1 0404BH P-DP 0.0000000 0.0034180 0.0034180 0.0000000 1,507.16 576.18 5.60 93.62 90.20 127.75 0 DIRE WOLF UNIT 1 0414AH P-DP 0.0000000 0.0034180 0.0034180 0.0000000 2,636.88 1,716.28 5.60 93.62 166.48 184.60 0 DIRE WOLF UNIT 1 0424SH P-DP 0.0000000 0.0034180 0.0034180 0.0000000 499.93 328.37 5.60 93.62 38.39 41.11 0 DIRE WOLF UNIT 1 0433SH P-DP 0.0000000 0.0034180 0.0034180 0.0000000 61.47 59.49 5.60 93.62 4.78 3.81 0 DIRE WOLF UNIT 1 0474JH P-DP 0.0000000 0.0034180 0.0034180 0.0000000 582.10 192.15 5.60 93.62 19.33 35.25 0 DIRE WOLF UNIT 2 0406BH P-DP 0.0000000 0.0013021 0.0013021 0.0000000 2,185.44 851.40 5.60 93.62 115.24 192.95 0 DIRE WOLF UNIT 2 0407BH P-DP 0.0000000 0.0013021 0.0013021 0.0000000 2,039.28 884.93 5.60 93.62 129.40 200.07 0 DIRE WOLF UNIT 2 0415AH P-DP 0.0000000 0.0013021 0.0013021 0.0000000 1,509.30 744.19 5.60 93.62 96.02 129.89 0 DIRE WOLF UNIT 2 0416AH P-DP 0.0000000 0.0013021 0.0013021 0.0000000 845.68 627.22 5.60 93.62 84.79 79.34 0 DIRE WOLF UNIT 2 0417AH P-DP 0.0000000 0.0013021 0.0013021 0.0000000 1,032.12 566.07 5.60 93.62 81.76 99.73 0 DIRE WOLF UNIT 2 0426SH P-DP 0.0000000 0.0013021 0.0013021 0.0000000 703.53 265.24 5.60 93.62 33.73 62.52 0 DIRE WOLF UNIT 2 0427SH P-DP 0.0000000 0.0013021 0.0013021 0.0000000 843.36 337.71 5.60 93.62 47.46 77.93 0 DIRE WOLF UNIT 2 0428SH P-DP 0.0000000 0.0013021 0.0013021 0.0000000 943.24 402.91 5.60 93.62 54.21 84.94 0 DIRE WOLF UNIT 2 0435SH P-DP 0.0000000 0.0013021 0.0013021 0.0000000 12.10 29.13 5.60 93.62 4.00 1.52 0 DIRE WOLF UNIT 2 0437SH P-DP 0.0000000 0.0013021 0.0013021 0.0000000 195.71 85.89 5.60 93.62 11.21 18.57 0 DYER 3301 P-DP 0.0000000 0.0183333 0.0183333 0.0000000 244.74 91.21 5.60 93.62 76.20 139.55 0 DYER 3303 P-DP 0.0000000 0.0183333 0.0183333 0.0000000 286.08 50.73 5.60 93.62 45.12 154.23 0 DYER 33B P-DP 0.0000000 0.0183333 0.0183333 0.0000000 174.64 15.95 5.60 93.62 12.58 101.96 0 DYER 33D P-DP 0.0000000 0.0183333 0.0183333 0.0000000 202.16 83.67 5.60 93.62 80.67 145.41 0 DYER 33F P-DP 0.0000000 0.0183333 0.0183333 0.0000000 118.86 22.86 5.60 93.62 19.25 85.52 0 DYER 33H P-DP 0.0000000 0.0183333 0.0183333 0.0000000 148.78 20.11 5.60 93.62 14.65 77.84 0 FISHERMAN -A- 2 P-DP 0.0000000 0.0052083 0.0052083 0.0000000 96.45 25.52 5.60 93.62 21.00 89.51 0 FISHERMAN-BRISTOW 23A 1H P-DP 0.0000000 0.0037045 0.0037045 0.0000000 938.48 599.15 5.60 93.62 287.42 322.92 0 FISHERMAN-BRISTOW 23B 2H P-DP 0.0000000 0.0037783 0.0037783 0.0000000 677.17 526.32 5.60 93.62 281.94 290.13 0 FISHERMAN-BRISTOW 23C 3H P-DP 0.0000000 0.0037009 0.0037009 0.0000000 976.66 650.02 5.60 93.62 335.02 331.32 0 FISHERMAN-BRISTOW 23D 4H P-DP 0.0000000 0.0037701 0.0037701 0.0000000 1,113.61 752.27 5.60 93.62 375.06 375.09 0 GEORGIA 39 1 P-DP 0.0000000 0.0023438 0.0023438 0.0000000 325.97 139.95 5.60 93.62 75.69 223.42 0 GLASS -Y- 1 P-DP 0.0000000 0.0000860 0.0000860 0.0000000 198.14 125.17 5.60 93.62 87.38 177.22 0

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![](exhibit992-202210xk061.jpg)

LEASE NAME GAS PRC INITIAL $/Mcf GROSS ULTIMATE Mbbl GROSS ULTIMATE MMcf CUM GAS MMcf CUM OIL Mbbl EXPENSE INITIAL DECIMAL INTEREST FINAL DECIMAL REVENUE INITIAL DECIMAL INTEREST FINAL DECIMAL OIL PRC INITIAL $/bbl RES CAT AS OF DATE FIXED COST $/MO As of : 01/01/2023 GROSS ULTIMATE RESERVES, CUMULATIVE PRODUCTION AND BASIC ECONOMIC DATA TABLE 7 GUNSMOKE 1-40 A 1JM P-DP 0.0000000 0.0016151 0.0016151 0.0000000 813.69 588.86 5.60 93.62 167.96 196.86 0 GUNSMOKE 1-40 B 2LS P-DP 0.0000000 0.0016244 0.0016244 0.0000000 1,352.72 485.54 5.60 93.62 200.92 242.07 0 GUNSMOKE 1-40 C 3WA P-DP 0.0000000 0.0016160 0.0016160 0.0000000 1,198.11 783.05 5.60 93.62 308.65 350.33 0 GUNSMOKE 1-40 D 4WA P-DP 0.0000000 0.0016110 0.0016110 0.0000000 1,385.31 627.12 5.60 93.62 273.70 394.83 0 GUNSMOKE 40-1 E 5JM P-DP 0.0000000 0.0016151 0.0016151 0.0000000 615.03 462.68 5.60 93.62 138.01 122.29 0 GUNSMOKE 40-1 F 6LS P-DP 0.0000000 0.0016356 0.0016356 0.0000000 777.95 434.14 5.60 93.62 143.87 177.05 0 GUNSMOKE 40-1 G 7WA P-DP 0.0000000 0.0016350 0.0016350 0.0000000 2,564.64 780.15 5.60 93.62 255.70 369.80 0 GUNSMOKE 40-1 H 8WB P-DP 0.0000000 0.0016357 0.0016357 0.0000000 900.32 361.15 5.60 93.62 155.62 275.57 0 GUNSMOKE 40-1 H 8WB P-DP 0.0000000 0.0016357 0.0016357 0.0000000 1,072.05 399.44 5.60 93.62 155.24 275.14 0 GUNSMOKE 40-1 I 9LS P-DP 0.0000000 0.0016283 0.0016283 0.0000000 1,829.72 467.78 5.60 93.62 126.58 171.24 0 GUNSMOKE 40-1 J 10WA P-DP 0.0000000 0.0016353 0.0016353 0.0000000 2,102.23 807.46 5.60 93.62 315.35 423.15 0 GUNSMOKE 40-1 K 11WB P-DP 0.0000000 0.0016350 0.0016350 0.0000000 1,365.31 375.45 5.60 93.62 161.38 301.65 0 HALL TRUST 38 1 P-DP 0.0000000 0.0039063 0.0039063 0.0000000 350.50 211.05 5.60 93.62 150.32 328.88 0 HALL TRUST 38 2 P-DP 0.0000000 0.0039063 0.0039063 0.0000000 201.95 156.82 5.60 93.62 98.38 196.02 0 HARPER-BAYES 16 1 P-DP 0.0000000 0.0003720 0.0003720 0.0000000 164.01 150.16 5.60 93.62 83.46 144.65 0 HYDRA 45-4 UNIT 1 112 P-DP 0.0000000 0.0007586 0.0007586 0.0000000 1,128.10 372.78 5.60 93.62 181.55 333.30 0 HYDRA 45-4 UNIT 1 122 P-DP 0.0000000 0.0007586 0.0007586 0.0000000 882.25 317.39 5.60 93.62 151.77 277.83 0 HYDRA 45-4 UNIT 1 124 P-DP 0.0000000 0.0007586 0.0007586 0.0000000 1,358.67 524.44 5.60 93.62 243.14 421.30 0 HYDRA 45-4 UNIT 1 132 P-DP 0.0000000 0.0007586 0.0007586 0.0000000 1,656.96 553.99 5.60 93.62 269.96 514.73 0 HYDRA 45-4 UNIT 1 142 P-DP 0.0000000 0.0007586 0.0007586 0.0000000 1,039.83 322.81 5.60 93.62 156.15 321.83 0 HYDRA 45-4 UNIT 1 211 P-DP 0.0000000 0.0007586 0.0007586 0.0000000 1,204.75 420.25 5.60 93.62 205.03 371.96 0 HYDRA 45-4 UNIT 1 221 P-DP 0.0000000 0.0007586 0.0007586 0.0000000 573.86 762.48 5.60 93.62 366.60 146.28 0 HYDRA 45-4 UNIT 1 223 P-DP 0.0000000 0.0007586 0.0007586 0.0000000 1,343.20 476.92 5.60 93.62 231.93 416.35 0 HYDRA 45-4 UNIT 1 231 P-DP 0.0000000 0.0007586 0.0007586 0.0000000 868.43 326.94 5.60 93.62 160.21 254.46 0 HYDRA 45-4 UNIT 1 241 P-DP 0.0000000 0.0007586 0.0007586 0.0000000 1,828.35 582.76 5.60 93.62 288.87 520.37 0 JMW NAIL 10 1 P-DP 0.0000000 0.0002151 0.0002151 0.0000000 199.21 69.74 5.60 93.62 65.90 137.65 0 JMW NAIL 10 2 P-DP 0.0000000 0.0002151 0.0002151 0.0000000 153.53 36.99 5.60 93.62 33.57 108.28 0 JMW NAIL 10 3 P-DP 0.0000000 0.0002151 0.0002151 0.0000000 118.29 35.25 5.60 93.62 32.33 94.64 0 JMW NAIL 10 4 P-DP 0.0000000 0.0002151 0.0002151 0.0000000 174.70 48.69 5.60 93.62 42.86 109.70 0 JMW NAIL 10A 3 P-DP 0.0000000 0.0002151 0.0002151 0.0000000 108.27 38.47 5.60 93.62 34.76 88.41 0 JMW NAIL 10A 4 P-DP 0.0000000 0.0002151 0.0002151 0.0000000 137.69 51.96 5.60 93.62 42.31 98.93 0 KEMPER 1 P-DP 0.0000000 0.0000000 0.0000000 0.0000000 137.33 44.10 5.60 93.62 37.88 137.33 0 KEMPER 1 P-DP 0.0000000 0.0000000 0.0000000 0.0000000 137.33 45.00 5.60 93.62 37.88 137.33 0 KEMPER 16 1 P-DP 0.0000000 0.0003348 0.0003348 0.0000000 116.21 52.11 5.60 93.62 46.32 115.58 0 KEMPER 16 2 P-DP 0.0000000 0.0003348 0.0003348 0.0000000 114.09 28.36 5.60 93.62 22.58 113.31 0 KENTEX-HARRISON 35A 1H P-DP 0.0000000 0.0041020 0.0041020 0.0000000 1,119.82 731.83 5.60 93.62 373.90 344.50 0 KENTEX-HARRISON 35B 2H P-DP 0.0000000 0.0041890 0.0041890 0.0000000 1,430.63 587.98 5.60 93.62 252.18 405.17 0

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![](exhibit992-202210xk062.jpg)

LEASE NAME GAS PRC INITIAL $/Mcf GROSS ULTIMATE Mbbl GROSS ULTIMATE MMcf CUM GAS MMcf CUM OIL Mbbl EXPENSE INITIAL DECIMAL INTEREST FINAL DECIMAL REVENUE INITIAL DECIMAL INTEREST FINAL DECIMAL OIL PRC INITIAL $/bbl RES CAT AS OF DATE FIXED COST $/MO As of : 01/01/2023 GROSS ULTIMATE RESERVES, CUMULATIVE PRODUCTION AND BASIC ECONOMIC DATA TABLE 7 KENTEX-HARRISON 35C 3H P-DP 0.0000000 0.0040994 0.0040994 0.0000000 766.94 701.69 5.60 93.62 328.43 299.68 0 KENTEX-HARRISON 35D 4H P-DP 0.0000000 0.0041869 0.0041869 0.0000000 890.87 382.57 5.60 93.62 191.84 348.89 0 KRAKEN 10-3 UNIT 2 181 P-DP 0.0000000 0.0010769 0.0010769 0.0000000 1,754.90 515.07 5.60 93.62 264.56 491.62 0 KRAKEN 10-3 UNIT 2 183 P-DP 0.0000000 0.0010769 0.0010769 0.0000000 1,158.54 341.53 5.60 93.62 174.42 345.27 0 KRAKEN 10-3 UNIT 2 273 P-DP 0.0000000 0.0010769 0.0010769 0.0000000 536.62 198.12 5.60 93.62 115.97 174.73 0 KRAKEN 10-3 UNIT 2 282 P-DP 0.0000000 0.0010769 0.0010769 0.0000000 1,873.84 592.09 5.60 93.62 312.42 579.13 0 MARYRUTH-ANDERSON 47C 103H P-DP 0.0000000 0.0002698 0.0002698 0.0000000 1,141.83 760.60 5.60 93.62 526.31 529.76 0 MARYRUTH-ANDERSON 47D 104H P-DP 0.0000000 0.0002697 0.0002697 0.0000000 1,000.18 576.23 5.60 93.62 435.93 475.18 0 MARYRUTH-ANDERSON 47E 105H P-DP 0.0000000 0.0002696 0.0002696 0.0000000 728.19 646.95 5.60 93.62 393.13 436.52 0 MARYRUTH-ANDERSON 47F 106H P-DP 0.0000000 0.0002695 0.0002695 0.0000000 629.26 755.25 5.60 93.62 508.20 376.53 0 MIMS 32H 3306BH P-DP 0.0000000 0.0045833 0.0045833 0.0000000 1,175.54 409.81 5.60 93.62 285.02 718.74 0 MIMS 32H 3307BH P-DP 0.0000000 0.0045833 0.0045833 0.0000000 961.74 238.69 5.60 93.62 169.67 618.82 0 MIMS 32H 3315AH P-DP 0.0000000 0.0045833 0.0045833 0.0000000 1,357.83 420.89 5.60 93.62 323.01 950.24 0 MIMS 32H 3317AH P-DP 0.0000000 0.0045833 0.0045833 0.0000000 1,456.03 282.04 5.60 93.62 223.28 1,000.45 0 MIMS 32H 3318AH P-DP 0.0000000 0.0045833 0.0045833 0.0000000 685.26 249.23 5.60 93.62 197.41 463.41 0 MIMS 32H 3326SH P-DP 0.0000000 0.0045833 0.0045833 0.0000000 521.67 165.06 5.60 93.62 133.51 357.98 0 MIMS 32H 3327SH P-DP 0.0000000 0.0045833 0.0045833 0.0000000 523.84 203.85 5.60 93.62 162.85 348.19 0 MIMS 32H 3345SH P-DP 0.0000000 0.0045833 0.0045833 0.0000000 381.67 285.45 5.60 93.62 232.11 256.34 0 MIMS 32H 3347SH P-DP 0.0000000 0.0045833 0.0045833 0.0000000 793.69 636.48 5.60 93.62 494.86 565.54 0 MIMS 32H 3348SH P-DP 0.0000000 0.0045833 0.0045833 0.0000000 802.35 617.48 5.60 93.62 505.12 625.62 0 NAIL -A- 1 P-DP 0.0000000 0.0002151 0.0002151 0.0000000 258.64 77.16 5.60 93.62 58.82 209.95 0 NAIL -C- 1 P-DP 0.0000000 0.0000860 0.0000860 0.0000000 366.53 119.50 5.60 93.62 111.65 337.67 0 NAIL -C- 1 P-DP 0.0000000 0.0000860 0.0000860 0.0000000 351.66 120.40 5.60 93.62 111.56 337.10 0 NAIL -E- 2 P-DP 0.0000000 0.0002151 0.0002151 0.0000000 169.80 98.15 5.60 93.62 93.78 161.16 0 NAIL -E- 3 P-DP 0.0000000 0.0002151 0.0002151 0.0000000 187.27 103.91 5.60 93.62 98.50 175.43 0 NAIL -K- 1 P-DP 0.0000000 0.0001075 0.0001075 0.0000000 172.52 84.62 5.60 93.62 63.02 146.47 0 NAIL -P- 1 P-DP 0.0000000 0.0001344 0.0001344 0.0000000 174.03 69.53 5.60 93.62 65.06 162.19 0 NAIL J 1 P-DP 0.0000000 0.0000860 0.0000860 0.0000000 217.50 93.63 5.60 93.62 81.26 174.16 0 NAIL O 1 P-DP 0.0000000 0.0002151 0.0002151 0.0000000 176.79 100.81 5.60 93.62 88.76 161.01 0 NAIL RANCH 10 1 P-DP 0.0000000 0.0002151 0.0002151 0.0000000 191.69 63.96 5.60 93.62 47.64 122.05 0 NAIL RANCH 10 2 P-DP 0.0000000 0.0002151 0.0002151 0.0000000 113.77 65.95 5.60 93.62 53.36 90.49 0 NAIL RANCH 10 3 P-DP 0.0000000 0.0002151 0.0002151 0.0000000 72.49 68.16 5.60 93.62 56.82 68.67 0 NAIL RANCH 10 4 P-DP 0.0000000 0.0002151 0.0002151 0.0000000 196.06 78.94 5.60 93.62 70.19 172.08 0 NE NAIL 10 1 P-DP 0.0000000 0.0002151 0.0002151 0.0000000 171.17 70.25 5.60 93.62 51.36 87.06 0 NE NAIL 10 2 P-DP 0.0000000 0.0002151 0.0002151 0.0000000 355.92 79.03 5.60 93.62 59.70 223.66 0 NE NAIL 10 3 P-DP 0.0000000 0.0002151 0.0002151 0.0000000 184.44 98.09 5.60 93.62 90.06 154.54 0 NE NAIL 10 4 P-DP 0.0000000 0.0002151 0.0002151 0.0000000 102.89 19.67 5.60 93.62 11.18 61.90 0

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![](exhibit992-202210xk063.jpg)

LEASE NAME GAS PRC INITIAL $/Mcf GROSS ULTIMATE Mbbl GROSS ULTIMATE MMcf CUM GAS MMcf CUM OIL Mbbl EXPENSE INITIAL DECIMAL INTEREST FINAL DECIMAL REVENUE INITIAL DECIMAL INTEREST FINAL DECIMAL OIL PRC INITIAL $/bbl RES CAT AS OF DATE FIXED COST $/MO As of : 01/01/2023 GROSS ULTIMATE RESERVES, CUMULATIVE PRODUCTION AND BASIC ECONOMIC DATA TABLE 7 NE NAIL 10 5 P-DP 0.0000000 0.0002151 0.0002151 0.0000000 98.34 24.56 5.60 93.62 16.41 64.18 0 NORRIS UNIT 32-H 3301BH P-DP 0.0000000 0.0045833 0.0045833 0.0000000 813.70 139.79 5.60 93.62 68.17 236.31 0 NORRIS UNIT 32-H 3303BH P-DP 0.0000000 0.0045833 0.0045833 0.0000000 1,075.94 194.93 5.60 93.62 99.59 288.66 0 NORRIS UNIT 32-H 3304BH P-DP 0.0000000 0.0045833 0.0045833 0.0000000 204.68 201.61 5.60 93.62 101.91 54.46 0 NORRIS UNIT 32-H 3312AH P-DP 0.0000000 0.0045833 0.0045833 0.0000000 982.06 113.28 5.60 93.62 62.23 252.17 0 NORRIS UNIT 32-H 3313AH P-DP 0.0000000 0.0045833 0.0045833 0.0000000 1,714.76 170.42 5.60 93.62 86.96 438.85 0 NORRIS UNIT 32-H 3322SH P-DP 0.0000000 0.0045833 0.0045833 0.0000000 1,434.20 258.17 5.60 93.62 136.21 383.48 0 NORRIS UNIT 32-H 3323SH P-DP 0.0000000 0.0045833 0.0045833 0.0000000 3,949.24 556.52 5.60 93.62 298.25 1,124.64 0 NORRIS UNIT 32-H 3361DH P-DP 0.0000000 0.0045833 0.0045833 0.0000000 2,067.51 289.64 5.60 93.62 153.23 533.46 0 NORRIS UNIT 32-H 3363DH P-DP 0.0000000 0.0045833 0.0045833 0.0000000 1,952.76 286.73 5.60 93.62 144.71 517.40 0 NORRIS UNIT 32-H 3364DH P-DP 0.0000000 0.0045833 0.0045833 0.0000000 974.29 284.29 5.60 93.62 144.58 318.79 0 NORRIS UNIT 32-H 3371JH P-DP 0.0000000 0.0045833 0.0045833 0.0000000 1,045.61 190.24 5.60 93.62 99.60 254.97 0 NORRIS UNIT 32-H 3373JH P-DP 0.0000000 0.0045833 0.0045833 0.0000000 996.66 180.78 5.60 93.62 95.82 266.04 0 NORRIS UNIT 32-H 3374JH P-DP 0.0000000 0.0045833 0.0045833 0.0000000 909.10 178.78 5.60 93.62 97.56 249.51 0 NORRIS-MIMS ALLOCATION 3315AH P-DP 0.0000000 0.0045833 0.0045833 0.0000000 749.60 182.54 5.60 93.62 104.67 255.32 0 NORRIS-MIMS ALLOCATION 3325SH P-DP 0.0000000 0.0045833 0.0045833 0.0000000 1,510.98 228.05 5.60 93.62 128.29 553.62 0 PERCY 39 1R P-DP 0.0000000 0.0023438 0.0023438 0.0000000 332.27 68.53 5.60 93.62 42.07 162.58 0 POWELL 43 1 P-DP 0.0000000 0.0027778 0.0027778 0.0000000 105.81 71.57 5.60 93.62 57.13 98.55 0 POWELL A 2 P-DP 0.0000000 0.0031250 0.0031250 0.0000000 308.37 132.41 5.60 93.62 121.28 269.45 0 POWELL A 3 P-DP 0.0000000 0.0031250 0.0031250 0.0000000 89.74 20.60 5.60 93.62 11.77 52.87 0 POWELL B 1 P-DP 0.0000000 0.0031250 0.0031250 0.0000000 242.98 86.62 5.60 93.62 65.76 140.44 0 POWELL C 1 P-DP 0.0000000 0.0031250 0.0031250 0.0000000 272.04 100.34 5.60 93.62 71.76 164.23 0 RAGLAND 2 P-DP 0.0000000 0.0062500 0.0062500 0.0000000 477.87 184.10 5.60 93.62 168.53 458.08 0 RAGLAND-ANDERSON 47A 1H P-DP 0.0000000 0.0050365 0.0050365 0.0000000 846.44 517.82 5.60 93.62 296.44 317.38 0 RAGLAND-ANDERSON 47B 2H P-DP 0.0000000 0.0050319 0.0050319 0.0000000 976.50 536.38 5.60 93.62 301.38 375.94 0 RAGLAND-ANDERSON 47C 3H P-DP 0.0000000 0.0050327 0.0050327 0.0000000 1,092.37 420.22 5.60 93.62 263.62 356.88 0 SABINE 39 1 P-DP 0.0000000 0.0023438 0.0023438 0.0000000 518.88 105.53 5.60 93.62 83.55 405.78 0 SABINE 39 2 P-DP 0.0000000 0.0023438 0.0023438 0.0000000 192.13 27.59 5.60 93.62 12.46 123.25 0 SILVERADO 40-1 A 1JM P-DP 0.0000000 0.0016332 0.0016332 0.0000000 672.75 547.17 5.60 93.62 167.45 152.87 0 SILVERADO 40-1 B 2LS P-DP 0.0000000 0.0016337 0.0016337 0.0000000 639.00 463.01 5.60 93.62 162.89 144.72 0 SILVERADO 40-1 C 3WA P-DP 0.0000000 0.0016343 0.0016343 0.0000000 538.52 631.53 5.60 93.62 134.97 108.64 0 SILVERADO 40-1 E 5JM P-DP 0.0000000 0.0016275 0.0016275 0.0000000 966.36 560.50 5.60 93.62 178.45 182.79 0 SILVERADO 40-1 F 6LS P-DP 0.0000000 0.0016344 0.0016344 0.0000000 697.68 455.61 5.60 93.62 167.57 180.40 0 SILVERADO 40-1 G 7LS P-DP 0.0000000 0.0016340 0.0016340 0.0000000 669.86 393.79 5.60 93.62 170.12 219.40 0 SILVERADO 40-1 H 8WA P-DP 0.0000000 0.0016344 0.0016344 0.0000000 1,339.34 865.60 5.60 93.62 276.21 289.89 0 SILVERADO 40-1 I 9WB P-DP 0.0000000 0.0016332 0.0016332 0.0000000 1,258.91 422.31 5.60 93.62 145.82 246.99 0 SILVERADO 40-1 J 10WB P-DP 0.0000000 0.0016296 0.0016296 0.0000000 2,877.86 410.73 5.60 93.62 143.90 449.13 0

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![](exhibit992-202210xk064.jpg)

LEASE NAME GAS PRC INITIAL $/Mcf GROSS ULTIMATE Mbbl GROSS ULTIMATE MMcf CUM GAS MMcf CUM OIL Mbbl EXPENSE INITIAL DECIMAL INTEREST FINAL DECIMAL REVENUE INITIAL DECIMAL INTEREST FINAL DECIMAL OIL PRC INITIAL $/bbl RES CAT AS OF DATE FIXED COST $/MO As of : 01/01/2023 GROSS ULTIMATE RESERVES, CUMULATIVE PRODUCTION AND BASIC ECONOMIC DATA TABLE 7 SILVERADO 40-1 K 11WA P-DP 0.0000000 0.0016331 0.0016331 0.0000000 3,614.62 823.45 5.60 93.62 323.78 449.23 0 SIXTEEN PENNY NAIL 310 1LL P-DP 0.0000000 0.0001428 0.0001428 0.0000000 543.34 258.91 5.60 93.62 241.16 484.55 0 SIXTEEN PENNY NAIL 310 2LM P-DP 0.0000000 0.0001434 0.0001434 0.0000000 242.13 146.72 5.60 93.62 139.77 217.59 0 SIXTEEN PENNY NAIL 310 8JM P-DP 0.0000000 0.0001447 0.0001447 0.0000000 1,179.69 488.84 5.60 93.62 215.74 640.42 0 SIXTEEN PENNY NAIL 310A 3LL P-DP 0.0000000 0.0001435 0.0001435 0.0000000 407.21 225.35 5.60 93.62 160.79 328.36 0 SIXTEEN PENNY NAIL 310A 9JM P-DP 0.0000000 0.0001444 0.0001444 0.0000000 1,050.77 156.67 5.60 93.62 80.74 435.09 0 SIXTEEN PENNY NAIL 310B 10JM P-DP 0.0000000 0.0001447 0.0001447 0.0000000 92.75 183.91 5.60 93.62 87.73 74.80 0 SIXTEEN PENNY NAIL 310B 4LM P-DP 0.0000000 0.0001433 0.0001433 0.0000000 910.57 185.99 5.60 93.62 154.36 571.13 0 SIXTEEN PENNY NAIL 310B 5LL P-DP 0.0000000 0.0001434 0.0001434 0.0000000 964.62 235.61 5.60 93.62 194.38 597.31 0 SIXTEEN PENNY NAIL 310C 11JM P-DP 0.0000000 0.0001449 0.0001449 0.0000000 722.85 299.39 5.60 93.62 146.37 329.18 0 SIXTEEN PENNY NAIL 310C 6LM P-DP 0.0000000 0.0001435 0.0001435 0.0000000 898.14 277.36 5.60 93.62 249.82 659.63 0 SIXTEEN PENNY NAIL 310C 7LL P-DP 0.0000000 0.0001427 0.0001427 0.0000000 464.22 165.88 5.60 93.62 151.06 338.76 0 STIMSON BURLEY -D- 1 P-DP 0.0000000 0.0021506 0.0021506 0.0000000 174.46 186.80 5.60 93.62 177.35 141.54 0 STIMSON BURLEY -E- 3DW P-DP 0.0000000 0.0002151 0.0002151 0.0000000 4.42 3.44 5.60 93.62 2.10 2.12 0 STIMSON-BURLEY -C- 1 P-DP 0.0000000 0.0001344 0.0001344 0.0000000 231.94 139.41 5.60 93.62 133.76 223.56 0 STIMSON-BURLEY -C- 3 P-DP 0.0000000 0.0001344 0.0001344 0.0000000 183.83 122.06 5.60 93.62 108.78 180.02 0 STIMSON-BURLEY 1 P-DP 0.0000000 0.0021506 0.0021506 0.0000000 299.76 98.68 5.60 93.62 98.41 297.07 0 STIMSON-BURLEY 4 P-DP 0.0000000 0.0021506 0.0021506 0.0000000 306.31 70.97 5.60 93.62 70.61 297.20 0 STIMSON-BURLEY 6 P-DP 0.0000000 0.0021506 0.0021506 0.0000000 70.15 43.02 5.60 93.62 42.75 67.02 0 TITO'S 31-42 1LS P-DP 0.0000000 0.0008172 0.0008172 0.0000000 170.46 380.77 5.60 93.62 306.07 159.52 0 TITO'S 31-42 1WA P-DP 0.0000000 0.0008171 0.0008171 0.0000000 185.05 396.03 5.60 93.62 319.58 173.53 0 TITO'S 31-42 1WB P-DP 0.0000000 0.0008172 0.0008172 0.0000000 142.54 316.24 5.60 93.62 255.96 133.81 0 TITO'S 31-42 2LS P-DP 0.0000000 0.0009102 0.0009102 0.0000000 361.11 510.48 5.60 93.62 339.33 246.89 0 TITO'S 31-42 2WA P-DP 0.0000000 0.0008172 0.0008172 0.0000000 1,769.00 211.56 5.60 93.62 168.29 1,005.89 0 TITO'S 31-42 2WB P-DP 0.0000000 0.0009101 0.0009101 0.0000000 468.64 211.83 5.60 93.62 156.95 339.74 0 TITO'S 31-42 3WA P-DP 0.0000000 0.0009099 0.0009099 0.0000000 178.06 266.11 5.60 93.62 228.04 131.96 0 WATKINS 7 1 P-DP 0.0000000 0.0333333 0.0333333 0.0000000 133.98 78.58 5.60 93.62 63.59 105.38 0 WELCH 39 1 P-DP 0.0000000 0.0023438 0.0023438 0.0000000 425.39 228.42 5.60 93.62 160.42 320.15 0 WELCH 39 2 P-DP 0.0000000 0.0023438 0.0023438 0.0000000 109.25 53.82 5.60 93.62 22.77 57.31 0 WELCH 39 3 P-DP 0.0000000 0.0023438 0.0023438 0.0000000 220.45 47.94 5.60 93.62 31.88 174.85 0 WELCH 39 4 P-DP 0.0000000 0.0023438 0.0023438 0.0000000 327.29 78.70 5.60 93.62 48.73 272.82 0 WILLIE THE WILDCAT 3-15 A 1JC P-DP 0.0000000 0.0003773 0.0003773 0.0000000 1,133.66 240.20 5.60 93.62 135.21 380.31 0 WILLIE THE WILDCAT 3-15 A 1LS P-DP 0.0000000 0.0003803 0.0003803 0.0000000 1,438.63 358.60 5.60 93.62 197.59 491.04 0 WILLIE THE WILDCAT 3-15 A 1WA P-DP 0.0000000 0.0003828 0.0003828 0.0000000 3,135.34 729.52 5.60 93.62 406.40 1,020.84 0 WILLIE THE WILDCAT 3-15 B 2DN P-DP 0.0000000 0.0003835 0.0003835 0.0000000 1,447.35 371.67 5.60 93.62 281.00 635.44 0 WILLIE THE WILDCAT 3-15 B 2LS P-DP 0.0000000 0.0003835 0.0003835 0.0000000 1,524.23 384.86 5.60 93.62 231.75 523.02 0 WILLIE THE WILDCAT 3-15 B 2WB P-DP 0.0000000 0.0003837 0.0003837 0.0000000 3,031.95 214.13 5.60 93.62 157.27 1,070.94 0

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![](exhibit992-202210xk065.jpg)

LEASE NAME GAS PRC INITIAL $/Mcf GROSS ULTIMATE Mbbl GROSS ULTIMATE MMcf CUM GAS MMcf CUM OIL Mbbl EXPENSE INITIAL DECIMAL INTEREST FINAL DECIMAL REVENUE INITIAL DECIMAL INTEREST FINAL DECIMAL OIL PRC INITIAL $/bbl RES CAT AS OF DATE FIXED COST $/MO As of : 01/01/2023 GROSS ULTIMATE RESERVES, CUMULATIVE PRODUCTION AND BASIC ECONOMIC DATA TABLE 7 WILLIE THE WILDCAT 3-15 B 3JD P-DP 0.0000000 0.0003837 0.0003837 0.0000000 1,282.11 294.93 5.60 93.62 208.20 510.80 0 WILLIE THE WILDCAT 3-15 C 4LS P-DP 0.0000000 0.0003843 0.0003843 0.0000000 1,195.65 252.77 5.60 93.62 185.68 376.77 0 WILLIE THE WILDCAT 3-15 C 4WA P-DP 0.0000000 0.0003819 0.0003819 0.0000000 2,816.94 336.66 5.60 93.62 229.99 782.08 0 WILLIE THE WILDCAT 3-15 D 5JD P-DP 0.0000000 0.0003814 0.0003814 0.0000000 814.87 235.56 5.60 93.62 142.90 291.54 0 WILLIE THE WILDCAT 3-15 D 6DN P-DP 0.0000000 0.0003824 0.0003824 0.0000000 2,528.36 526.35 5.60 93.62 329.17 1,165.50 0 WILLIE THE WILDCAT 3-15 D 6LS P-DP 0.0000000 0.0003846 0.0003846 0.0000000 1,541.23 426.62 5.60 93.62 274.44 494.72 0 WILLIE THE WILDCAT 3-15 D 6WB P-DP 0.0000000 0.0003845 0.0003845 0.0000000 2,110.16 399.58 5.60 93.62 208.76 1,105.09 0 WILLIE THE WILDCAT 3-15 E 7JC P-DP 0.0000000 0.0003752 0.0003752 0.0000000 148.43 393.98 5.60 93.62 158.45 51.73 0 WILLIE THE WILDCAT 3-15 E 7LS P-DP 0.0000000 0.0003860 0.0003860 0.0000000 1,715.94 879.93 5.60 93.62 385.60 530.62 0 WILLIE THE WILDCAT 3-15 E 7WA P-DP 0.0000000 0.0003857 0.0003857 0.0000000 4,361.53 300.44 5.60 93.62 244.27 1,238.29 0 BIZZELL -B- 1 P-DP 0.0000000 0.0006609 0.0006609 0.0000000 117.64 117.26 5.91 93.95 101.36 101.77 0 BIZZELL -B- 2 P-DP 0.0000000 0.0006609 0.0006609 0.0000000 357.67 112.65 5.91 93.95 103.00 342.20 0 BIZZELL 1 P-DP 0.0000000 0.0138640 0.0138640 0.0000000 321.11 80.67 5.91 93.95 73.73 277.55 0 BIZZELL-IRVIN 15L UNIT 116H P-DP 0.0000000 0.0021906 0.0021906 0.0000000 1,503.28 533.53 5.91 93.95 213.95 222.70 0 BIZZELL-IRVIN 15L UNIT 13H P-DP 0.0000000 0.0021906 0.0021906 0.0000000 2,050.24 306.02 5.91 93.95 153.52 536.43 0 BIZZELL-IRVIN 15L UNIT 18H P-DP 0.0000000 0.0021906 0.0021906 0.0000000 1,990.79 250.41 5.91 93.95 120.11 426.36 0 BIZZELL-IRVIN 15U UNIT 113H P-DP 0.0000000 0.0021906 0.0021906 0.0000000 1,126.15 300.97 5.91 93.95 127.37 258.06 0 BIZZELL-IRVIN 15U UNIT 114H P-DP 0.0000000 0.0021906 0.0021906 0.0000000 1,800.88 498.58 5.91 93.95 197.37 363.05 0 BIZZELL-IRVIN 15U UNIT 115H P-DP 0.0000000 0.0021906 0.0021906 0.0000000 935.04 361.20 5.91 93.95 171.64 233.83 0 BIZZELL-IRVIN 15U UNIT 117H P-DP 0.0000000 0.0021906 0.0021906 0.0000000 980.53 303.54 5.91 93.95 143.95 267.45 0 BIZZELL-IRVIN 15U UNIT 118H P-DP 0.0000000 0.0021906 0.0021906 0.0000000 1,598.15 495.66 5.91 93.95 209.17 367.58 0 BIZZELL-IRVIN 15U UNIT 14H P-DP 0.0000000 0.0021906 0.0021906 0.0000000 1,040.16 328.85 5.91 93.95 152.45 273.24 0 BIZZELL-IRVIN 15U UNIT 15H P-DP 0.0000000 0.0021906 0.0021906 0.0000000 1,212.89 348.56 5.91 93.95 160.33 284.00 0 BIZZELL-IRVIN 15U UNIT 16H P-DP 0.0000000 0.0021906 0.0021906 0.0000000 1,764.49 454.39 5.91 93.95 191.71 372.64 0 BIZZELL-IRVIN 15U UNIT 17H P-DP 0.0000000 0.0021906 0.0021906 0.0000000 866.76 929.19 5.91 93.95 374.97 188.24 0 BRAUN B S1 2008LH P-DP 0.0000000 0.0006027 0.0006027 0.0000000 673.03 578.24 5.91 93.95 162.73 135.71 0 BRAUN B S10 2014JH P-DP 0.0000000 0.0006027 0.0006027 0.0000000 781.86 473.22 5.91 93.95 132.27 125.34 0 BRAUN B S11 2004LH P-DP 0.0000000 0.0006027 0.0006027 0.0000000 464.54 373.77 5.91 93.95 106.85 97.62 0 BRAUN B S12 2004MH P-DP 0.0000000 0.0006027 0.0006027 0.0000000 435.28 593.55 5.91 93.95 148.30 99.81 0 BRAUN B S13 2003LH P-DP 0.0000000 0.0006027 0.0006027 0.0000000 602.64 444.80 5.91 93.95 132.47 113.51 0 BRAUN B S14 2003MH P-DP 0.0000000 0.0006027 0.0006027 0.0000000 628.80 555.70 5.91 93.95 150.95 109.28 0 BRAUN B S2 2008MH P-DP 0.0000000 0.0006027 0.0006027 0.0000000 239.87 180.33 5.91 93.95 37.13 33.80 0 BRAUN B S3 2007LH P-DP 0.0000000 0.0006027 0.0006027 0.0000000 658.09 501.91 5.91 93.95 146.79 127.97 0 BRAUN B S4 2007MH P-DP 0.0000000 0.0006027 0.0006027 0.0000000 419.67 321.27 5.91 93.95 77.13 65.22 0 BRAUN B S5 2016JH P-DP 0.0000000 0.0006027 0.0006027 0.0000000 676.69 536.08 5.91 93.95 149.85 123.28 0 BRAUN B S6 2006LH P-DP 0.0000000 0.0006027 0.0006027 0.0000000 623.59 475.34 5.91 93.95 141.34 128.11 0 BRAUN B S7 2006MH P-DP 0.0000000 0.0006027 0.0006027 0.0000000 511.70 478.82 5.91 93.95 105.34 80.88 0

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![](exhibit992-202210xk066.jpg)

LEASE NAME GAS PRC INITIAL $/Mcf GROSS ULTIMATE Mbbl GROSS ULTIMATE MMcf CUM GAS MMcf CUM OIL Mbbl EXPENSE INITIAL DECIMAL INTEREST FINAL DECIMAL REVENUE INITIAL DECIMAL INTEREST FINAL DECIMAL OIL PRC INITIAL $/bbl RES CAT AS OF DATE FIXED COST $/MO As of : 01/01/2023 GROSS ULTIMATE RESERVES, CUMULATIVE PRODUCTION AND BASIC ECONOMIC DATA TABLE 7 BRAUN B S8 2005LH P-DP 0.0000000 0.0006027 0.0006027 0.0000000 658.65 408.28 5.91 93.95 118.96 123.40 0 BRAUN B S9 2005MH P-DP 0.0000000 0.0006027 0.0006027 0.0000000 621.83 518.80 5.91 93.95 134.28 103.35 0 BRAUN B W1 2001MH P-DP 0.0000000 0.0008036 0.0008036 0.0000000 1,287.75 937.86 5.91 93.95 470.55 448.06 0 BRAUN B W3 2001LH P-DP 0.0000000 0.0008036 0.0008036 0.0000000 794.64 738.63 5.91 93.95 398.54 412.79 0 BRAUN C W5 2108LH P-DP 0.0000000 0.0008036 0.0008036 0.0000000 911.09 697.91 5.91 93.95 322.72 396.21 0 COWDEN A 2401 P-DP 0.0000000 0.0009375 0.0009375 0.0000000 24.44 32.10 5.91 93.95 29.71 23.94 0 COWDEN A 2402 P-DP 0.0000000 0.0009375 0.0009375 0.0000000 28.89 19.84 5.91 93.95 18.74 27.65 0 COWDEN A 2403 P-DP 0.0000000 0.0009375 0.0009375 0.0000000 26.27 16.99 5.91 93.95 16.26 25.24 0 COWDEN A 2404 P-DP 0.0000000 0.0009375 0.0009375 0.0000000 43.31 38.95 5.91 93.95 35.70 39.88 0 COWDEN A 2405 P-DP 0.0000000 0.0009375 0.0009375 0.0000000 90.23 35.86 5.91 93.95 31.41 79.77 0 COWDEN A 2406 P-DP 0.0000000 0.0009375 0.0009375 0.0000000 73.11 79.82 5.91 93.95 72.60 67.36 0 COWDEN F 2401 P-DP 0.0000000 0.0009375 0.0009375 0.0000000 100.12 44.70 5.91 93.95 33.73 81.07 0 COWDEN F 2402 P-DP 0.0000000 0.0009375 0.0009375 0.0000000 103.82 40.25 5.91 93.95 31.82 85.20 0 COWDEN F 2403 P-DP 0.0000000 0.0009375 0.0009375 0.0000000 91.48 30.16 5.91 93.95 20.26 71.89 0 COWDEN F 2404 P-DP 0.0000000 0.0009375 0.0009375 0.0000000 84.80 31.34 5.91 93.95 20.01 65.60 0 COWDEN F 2405 P-DP 0.0000000 0.0009375 0.0009375 0.0000000 65.49 23.69 5.91 93.95 16.68 59.73 0 COWDEN F 2406 P-DP 0.0000000 0.0009375 0.0009375 0.0000000 19.65 30.38 5.91 93.95 20.00 15.83 0 FRED HALL UNIT 1 P-DP 0.0000000 0.0029612 0.0029612 0.0000000 709.76 102.37 5.91 93.95 89.24 690.49 0 FRED HALL UNIT 2 P-DP 0.0000000 0.0029612 0.0029612 0.0000000 77.92 47.17 5.91 93.95 37.17 62.60 0 FRED HALL UNIT 3 P-DP 0.0000000 0.0029612 0.0029612 0.0000000 121.53 76.19 5.91 93.95 53.03 97.67 0 GUY COWDEN UNIT 2 2505BH P-DP 0.0000000 0.0005088 0.0005088 0.0000000 880.94 233.47 5.91 93.95 170.34 576.55 0 GUY COWDEN UNIT 2 2506BH P-DP 0.0000000 0.0005088 0.0005088 0.0000000 3,180.26 326.84 5.91 93.95 265.12 2,138.41 0 GUY COWDEN UNIT 2 2507BH P-DP 0.0000000 0.0005088 0.0005088 0.0000000 1,117.25 98.08 5.91 93.95 81.96 786.82 0 GUY COWDEN UNIT 2 2508BH P-DP 0.0000000 0.0005088 0.0005088 0.0000000 6,100.71 625.11 5.91 93.95 451.11 4,026.42 0 GUY COWDEN UNIT 2 2515AH P-DP 0.0000000 0.0005088 0.0005088 0.0000000 600.06 163.02 5.91 93.95 143.41 489.76 0 GUY COWDEN UNIT 2 2516AH P-DP 0.0000000 0.0005088 0.0005088 0.0000000 2,212.89 297.44 5.91 93.95 220.46 1,542.85 0 GUY COWDEN UNIT 2 2517AH P-DP 0.0000000 0.0005088 0.0005088 0.0000000 1,723.94 201.41 5.91 93.95 149.99 1,296.81 0 GUY COWDEN UNIT 2 2518AH P-DP 0.0000000 0.0005088 0.0005088 0.0000000 1,612.00 1,062.22 5.91 93.95 719.77 963.21 0 HALL-PORTER 621-596 A 112 P-DP 0.0000000 0.0014830 0.0014830 0.0000000 1,360.20 241.98 5.91 93.95 142.43 431.38 0 HALL-PORTER 621-596 A 211 P-DP 0.0000000 0.0014830 0.0014830 0.0000000 1,888.24 387.94 5.91 93.95 229.22 817.12 0 HALL-PORTER 621-596 B 122 P-DP 0.0000000 0.0014830 0.0014830 0.0000000 1,448.21 289.96 5.91 93.95 188.30 546.99 0 HALL-PORTER 621-596 B 221 P-DP 0.0000000 0.0014830 0.0014830 0.0000000 2,880.91 300.71 5.91 93.95 216.76 1,014.30 0 HALL-PORTER 621-596 B 224 P-DP 0.0000000 0.0014830 0.0014830 0.0000000 2,851.04 281.33 5.91 93.95 209.00 859.26 0 HALL-PORTER 621-596 C 132 P-DP 0.0000000 0.0014830 0.0014830 0.0000000 1,348.61 308.52 5.91 93.95 186.10 529.08 0 HALL-PORTER 621-596 C 231R P-DP 0.0000000 0.0007406 0.0007406 0.0000000 2,275.51 430.90 5.91 93.95 270.54 891.89 0 HALL-PORTER 621-596 C 233 P-DP 0.0000000 0.0014830 0.0014830 0.0000000 2,112.56 379.79 5.91 93.95 238.78 774.51 0 HALL-PORTER 621-596 D 142 P-DP 0.0000000 0.0008464 0.0008464 0.0000000 1,206.58 452.88 5.91 93.95 284.93 537.32 0

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![](exhibit992-202210xk067.jpg)

LEASE NAME GAS PRC INITIAL $/Mcf GROSS ULTIMATE Mbbl GROSS ULTIMATE MMcf CUM GAS MMcf CUM OIL Mbbl EXPENSE INITIAL DECIMAL INTEREST FINAL DECIMAL REVENUE INITIAL DECIMAL INTEREST FINAL DECIMAL OIL PRC INITIAL $/bbl RES CAT AS OF DATE FIXED COST $/MO As of : 01/01/2023 GROSS ULTIMATE RESERVES, CUMULATIVE PRODUCTION AND BASIC ECONOMIC DATA TABLE 7 HALL-PORTER 621-596 D 241 P-DP 0.0000000 0.0008464 0.0008464 0.0000000 1,700.54 590.83 5.91 93.95 377.45 772.72 0 HOFFERKAMP 1 P-DP 0.0000000 0.0002581 0.0002581 0.0000000 315.66 117.93 5.91 93.95 96.38 258.60 0 HOFFERKAMP 1 P-DP 0.0000000 0.0002581 0.0002581 0.0000000 52.44 23.95 5.91 93.95 13.16 22.59 0 HOUSE 47 1 P-DP 0.0000000 0.0156250 0.0156250 0.0000000 274.91 168.38 5.91 93.95 138.17 238.94 0 LRT UNIT 2 ALLOCATION 2318AH P-DP 0.0000000 0.0002397 0.0002397 0.0000000 1,831.58 604.47 5.91 93.95 395.83 1,059.12 0 MABEE 22A 1H P-DP 0.0000000 0.0000159 0.0000159 0.0000000 739.65 296.54 5.91 93.95 180.42 355.82 0 MABEE-ELKIN W16B 2H P-DP 0.0000000 0.0000068 0.0000068 0.0000000 972.79 333.26 5.91 93.95 195.65 447.23 0 MABEE-STIMSON 22B 2H P-DP 0.0000000 0.0000537 0.0000537 0.0000000 1,165.67 374.95 5.91 93.95 213.22 510.96 0 MABEE-TREDAWAY W16A 1H P-DP 0.0000000 0.0000067 0.0000067 0.0000000 1,048.34 341.57 5.91 93.95 219.50 533.82 0 O'NEAL -D- 1 P-DP 0.0000000 0.0117184 0.0117184 0.0000000 243.06 90.99 5.91 93.95 85.09 237.75 0 O'NEAL 1 P-DP 0.0000000 0.0156250 0.0156250 0.0000000 239.02 89.89 5.91 93.95 82.33 217.88 0 OLDHAM-GRAHAM 35A 1H P-DP 0.0000000 0.0026452 0.0026452 0.0000000 856.16 241.72 5.91 93.95 119.08 213.46 0 OLDHAM-GRAHAM 35B 2H P-DP 0.0000000 0.0023377 0.0023377 0.0000000 993.99 244.94 5.91 93.95 127.73 309.10 0 OLDHAM-GRAHAM 35C 3H P-DP 0.0000000 0.0026494 0.0026494 0.0000000 1,195.15 310.86 5.91 93.95 156.98 294.25 0 OLDHAM-GRAHAM 35D 4H P-DP 0.0000000 0.0023569 0.0023569 0.0000000 1,357.73 258.11 5.91 93.95 126.76 312.79 0 OLDHAM-GRAHAM 35E 5H P-DP 0.0000000 0.0026473 0.0026473 0.0000000 861.79 335.68 5.91 93.95 134.55 197.08 0 OLDHAM-GRAHAM 35F 6H P-DP 0.0000000 0.0023368 0.0023368 0.0000000 1,023.20 353.18 5.91 93.95 154.66 262.07 0 PARKS 1 P-DP 0.0000000 0.0020090 0.0020090 0.0000000 121.63 109.27 5.91 93.95 88.92 121.63 0 PARKS FIELD UNIT 2 1450BH P-DP 0.0000000 0.0008036 0.0008036 0.0000000 1,761.05 364.86 5.91 93.95 264.43 876.70 0 PARKS FIELD UNIT 2 1450LH P-DP 0.0000000 0.0008036 0.0008036 0.0000000 1,904.77 480.06 5.91 93.95 392.98 1,046.05 0 PARKS FIELD UNIT 2 1451LH P-DP 0.0000000 0.0008036 0.0008036 0.0000000 1,185.11 702.79 5.91 93.95 531.30 604.34 0 PARKS FIELD UNIT 2 1454H P-DP 0.0000000 0.0008036 0.0008036 0.0000000 483.54 302.14 5.91 93.95 252.65 313.48 0 PARKS FIELD UNIT 2 1454LH P-DP 0.0000000 0.0008036 0.0008036 0.0000000 1,325.98 981.70 5.91 93.95 720.09 661.11 0 PARKS FIELD UNIT 2 1455LH P-DP 0.0000000 0.0008036 0.0008036 0.0000000 713.93 462.74 5.91 93.95 341.55 355.97 0 PARKS FIELD UNIT 2 1458CH P-DP 0.0000000 0.0008036 0.0008036 0.0000000 6,109.45 792.01 5.91 93.95 609.47 2,710.79 0 PARKS FIELD UNIT 2 1458LH P-DP 0.0000000 0.0008036 0.0008036 0.0000000 6,625.12 841.97 5.91 93.95 603.14 2,708.72 0 PARKS FIELD UNIT 2 1863BH P-DP 0.0000000 0.0008036 0.0008036 0.0000000 1,994.74 381.74 5.91 93.95 327.62 1,423.05 0 PARKS FIELD UNIT 2 1863LH P-DP 0.0000000 0.0008036 0.0008036 0.0000000 1,758.36 594.45 5.91 93.95 510.83 1,203.62 0 PARKS FIELD UNIT 2 1904BH P-DP 0.0000000 0.0008036 0.0008036 0.0000000 558.10 374.04 5.91 93.95 284.47 285.71 0 PARKS FIELD UNIT 2 1921H P-DP 0.0000000 0.0008036 0.0008036 0.0000000 3,232.64 392.53 5.91 93.95 320.81 2,320.67 0 PARKS FIELD UNIT 2 2001BH P-DP 0.0000000 0.0008036 0.0008036 0.0000000 2,168.14 333.79 5.91 93.95 193.53 799.63 0 PARKS FIELD UNIT 2 2308BH P-DP 0.0000000 0.0008036 0.0008036 0.0000000 1,822.72 416.94 5.91 93.95 292.19 806.14 0 PARKS FIELD UNIT 2 2308LH P-DP 0.0000000 0.0008036 0.0008036 0.0000000 2,426.66 884.67 5.91 93.95 543.22 917.87 0 PARKS FIELD UNIT 2 2308MH P-DP 0.0000000 0.0008036 0.0008036 0.0000000 2,337.86 785.90 5.91 93.95 539.96 885.67 0 PARKS FIELD UNIT 2 2329LH P-DP 0.0000000 0.0008036 0.0008036 0.0000000 1,009.09 264.38 5.91 93.95 228.94 590.95 0 PARKS FIELD UNIT 2 2336BH P-DP 0.0000000 0.0008036 0.0008036 0.0000000 1,028.41 53.80 5.91 93.95 50.16 726.96 0 PARKS FIELD UNIT 2 2346CH P-DP 0.0000000 0.0008036 0.0008036 0.0000000 195.35 18.06 5.91 93.95 17.42 162.81 0

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![](exhibit992-202210xk068.jpg)

LEASE NAME GAS PRC INITIAL $/Mcf GROSS ULTIMATE Mbbl GROSS ULTIMATE MMcf CUM GAS MMcf CUM OIL Mbbl EXPENSE INITIAL DECIMAL INTEREST FINAL DECIMAL REVENUE INITIAL DECIMAL INTEREST FINAL DECIMAL OIL PRC INITIAL $/bbl RES CAT AS OF DATE FIXED COST $/MO As of : 01/01/2023 GROSS ULTIMATE RESERVES, CUMULATIVE PRODUCTION AND BASIC ECONOMIC DATA TABLE 7 PARKS FIELD UNIT 2 2348H P-DP 0.0000000 0.0008036 0.0008036 0.0000000 433.31 684.34 5.91 93.95 481.46 314.55 0 PARKS FIELD UNIT 2 2401 P-DP 0.0000000 0.0008036 0.0008036 0.0000000 276.17 83.16 5.91 93.95 82.91 248.87 0 PARKS FIELD UNIT 2 2630H P-DP 0.0000000 0.0008036 0.0008036 0.0000000 1,987.43 67.82 5.91 93.95 64.28 1,302.49 0 PARKS FIELD UNIT 2 2709H P-DP 0.0000000 0.0008036 0.0008036 0.0000000 1,831.46 1,164.00 5.91 93.95 973.17 1,103.70 0 PARKS FIELD UNIT NO. 2 1320H P-DP 0.0000000 0.0008036 0.0008036 0.0000000 1,918.01 40.67 5.91 93.95 27.81 1,372.27 0 PARKS FIELD UNIT NO. 2 1421H P-DP 0.0000000 0.0008036 0.0008036 0.0000000 9,284.38 187.86 5.91 93.95 175.58 8,213.29 0 PARKS FIELD UNIT NO. 2 1422H P-DP 0.0000000 0.0008036 0.0008036 0.0000000 8,470.05 154.73 5.91 93.95 139.64 7,205.93 0 PARKS FIELD UNIT NO. 2 1423H P-DP 0.0000000 0.0008036 0.0008036 0.0000000 1,624.34 48.49 5.91 93.95 44.30 1,532.62 0 PARKS FIELD UNIT NO. 2 1829H P-DP 0.0000000 0.0008036 0.0008036 0.0000000 3,440.61 56.09 5.91 93.95 52.35 3,195.39 0 PARKS FIELD UNIT NO. 2 1831H P-DP 0.0000000 0.0008036 0.0008036 0.0000000 10,103.32 221.11 5.91 93.95 221.11 9,856.63 0 PARKS FIELD UNIT NO. 2 2324H P-DP 0.0000000 0.0008036 0.0008036 0.0000000 3,933.76 116.02 5.91 93.95 103.98 3,451.07 0 PARKS FIELD UNIT NO. 2 2401 P-DP 0.0000000 0.0008036 0.0008036 0.0000000 412.94 27.67 5.91 93.95 27.67 335.93 0 PARKS FIELD UNIT NO. 2 2401 P-DP 0.0000000 0.0008036 0.0008036 0.0000000 31.50 0.11 5.91 93.95 0.09 24.53 0 PARKS FIELD UNIT NO. 2 2417H P-DP 0.0000000 0.0008036 0.0008036 0.0000000 2,434.16 53.80 5.91 93.95 53.33 2,364.61 0 PARKS, CHARLOTTE 14 1 P-DP 0.0000000 0.0008036 0.0008036 0.0000000 14.37 55.91 5.91 93.95 53.05 13.89 0 PARKS, ROY 306BH P-DP 0.0000000 0.0002678 0.0002678 0.0000000 857.94 459.00 5.91 93.95 340.70 590.34 0 PARKS, ROY 306LH P-DP 0.0000000 0.0002678 0.0002678 0.0000000 502.20 595.80 5.91 93.95 445.35 342.73 0 PARKS, ROY 307BH P-DP 0.0000000 0.0002678 0.0002678 0.0000000 699.81 463.15 5.91 93.95 323.16 421.72 0 PARKS, ROY 307LH P-DP 0.0000000 0.0002678 0.0002678 0.0000000 1,536.14 71.17 5.91 93.95 50.00 609.46 0 PARKS, ROY 308BH P-DP 0.0000000 0.0002678 0.0002678 0.0000000 531.52 390.64 5.91 93.95 287.87 232.36 0 PARKS, ROY 308LH P-DP 0.0000000 0.0002678 0.0002678 0.0000000 901.91 24.05 5.91 93.95 12.67 511.09 0 PARKS, ROY 308MH P-DP 0.0000000 0.0002678 0.0002678 0.0000000 741.29 859.36 5.91 93.95 564.33 407.32 0 PARKS, ROY 316CH P-DP 0.0000000 0.0002678 0.0002678 0.0000000 523.83 191.38 5.91 93.95 150.45 267.36 0 PARKS, ROY 316LH P-DP 0.0000000 0.0002678 0.0002678 0.0000000 621.63 452.20 5.91 93.95 303.32 267.63 0 PARKS, ROY 99H P-DP 0.0000000 0.0002678 0.0002678 0.0000000 1,343.72 183.42 5.91 93.95 180.92 765.70 0 PARKS-COYOTE 1506 A 15HJ P-DP 0.0000000 0.0020089 0.0020089 0.0000000 315.47 412.71 5.91 93.95 124.50 99.17 0 PARKS-COYOTE 1506 A 1HM P-DP 0.0000000 0.0020089 0.0020089 0.0000000 947.45 419.32 5.91 93.95 257.02 515.81 0 PARKS-COYOTE 1506 A 8HS P-DP 0.0000000 0.0020089 0.0020089 0.0000000 712.06 475.41 5.91 93.95 140.21 139.37 0 PARKS-COYOTE 1506 B 2HM P-DP 0.0000000 0.0020089 0.0020089 0.0000000 773.00 289.53 5.91 93.95 203.04 561.02 0 PARKS-COYOTE 1506 B 9HS P-DP 0.0000000 0.0020089 0.0020089 0.0000000 667.81 406.69 5.91 93.95 93.51 112.98 0 PARKS-COYOTE 1506 C 10HS P-DP 0.0000000 0.0020089 0.0020089 0.0000000 568.36 365.43 5.91 93.95 120.36 117.24 0 PARKS-COYOTE 1506 C 16HJ P-DP 0.0000000 0.0020089 0.0020089 0.0000000 498.11 428.27 5.91 93.95 125.12 103.74 0 PARKS-COYOTE 1506 C 3HM P-DP 0.0000000 0.0020089 0.0020089 0.0000000 1,396.83 359.21 5.91 93.95 239.58 671.80 0 PARKS-COYOTE 1506 D 11HS P-DP 0.0000000 0.0020089 0.0020089 0.0000000 528.89 355.05 5.91 93.95 91.78 96.46 0 PARKS-COYOTE 1506 D 17HS P-DP 0.0000000 0.0020089 0.0020089 0.0000000 445.09 276.83 5.91 93.95 81.13 86.23 0 PARKS-COYOTE 1506 D 4HM P-DP 0.0000000 0.0020089 0.0020089 0.0000000 901.88 440.96 5.91 93.95 291.68 655.27 0 PARKS-COYOTE 1506 E 12HS P-DP 0.0000000 0.0020089 0.0020089 0.0000000 498.17 318.74 5.91 93.95 84.97 82.14 0

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![](exhibit992-202210xk069.jpg)

LEASE NAME GAS PRC INITIAL $/Mcf GROSS ULTIMATE Mbbl GROSS ULTIMATE MMcf CUM GAS MMcf CUM OIL Mbbl EXPENSE INITIAL DECIMAL INTEREST FINAL DECIMAL REVENUE INITIAL DECIMAL INTEREST FINAL DECIMAL OIL PRC INITIAL $/bbl RES CAT AS OF DATE FIXED COST $/MO As of : 01/01/2023 GROSS ULTIMATE RESERVES, CUMULATIVE PRODUCTION AND BASIC ECONOMIC DATA TABLE 7 PARKS-COYOTE 1506 E 18HJ P-DP 0.0000000 0.0020089 0.0020089 0.0000000 493.89 308.46 5.91 93.95 80.86 79.79 0 PARKS-COYOTE 1506 E 5HM P-DP 0.0000000 0.0020089 0.0020089 0.0000000 714.38 423.05 5.91 93.95 269.91 479.59 0 PARKS-COYOTE 1506 F 13HS P-DP 0.0000000 0.0020089 0.0020089 0.0000000 472.67 421.33 5.91 93.95 77.74 83.09 0 PARKS-COYOTE 1506 F 6HM P-DP 0.0000000 0.0020089 0.0020089 0.0000000 665.36 400.72 5.91 93.95 273.85 477.75 0 PARKS-COYOTE 1506 G 14HS P-DP 0.0000000 0.0020089 0.0020089 0.0000000 647.16 726.28 5.91 93.95 133.26 116.81 0 PARKS-COYOTE 1506 G 19HS P-DP 0.0000000 0.0020089 0.0020089 0.0000000 268.04 167.09 5.91 93.95 45.42 49.29 0 PARKS-COYOTE 1506 G 7HM P-DP 0.0000000 0.0020089 0.0020089 0.0000000 909.98 669.00 5.91 93.95 347.89 444.32 0 SHIRLEY -B- 3815R P-DP 0.0000000 0.0140625 0.0140625 0.0000000 103.58 91.39 5.91 93.95 63.48 68.11 0 SHIRLEY 3806 P-DP 0.0000000 0.0140625 0.0140625 0.0000000 86.27 76.85 5.91 93.95 60.54 70.45 0 SHIRLEY 3807 P-DP 0.0000000 0.0140625 0.0140625 0.0000000 52.00 30.15 5.91 93.95 20.93 40.93 0 SHIRLEY 3808 P-DP 0.0000000 0.0140625 0.0140625 0.0000000 78.20 49.99 5.91 93.95 37.53 56.77 0 STIMSON BURLEY -B- 1 P-DP 0.0000000 0.0021506 0.0021506 0.0000000 283.98 101.87 5.91 93.95 95.71 249.05 0 STIMSON BURLEY -B- 4 P-DP 0.0000000 0.0021506 0.0021506 0.0000000 269.02 81.01 5.91 93.95 74.14 251.80 0 STIMSON BURLEY -M- 1 P-DP 0.0000000 0.0000215 0.0000215 0.0000000 218.73 76.46 5.91 93.95 68.72 203.19 0 STIMSON-BURLEY 18 1 P-DP 0.0000000 0.0021506 0.0021506 0.0000000 148.30 180.33 5.91 93.95 170.68 112.84 0 STINSON-BURLEY K 1 P-DP 0.0000000 0.0021506 0.0021506 0.0000000 264.71 86.16 5.91 93.95 73.85 241.37 0 TIMMERMAN J1 2208MH P-DP 0.0000000 0.0000399 0.0000399 0.0000000 818.31 466.15 5.91 93.95 320.49 427.14 0 TIMMERMAN J10 2206LH P-DP 0.0000000 0.0000399 0.0000399 0.0000000 1,278.12 701.48 5.91 93.95 432.01 583.48 0 TIMMERMAN J11 2206BH P-DP 0.0000000 0.0000399 0.0000399 0.0000000 2,134.02 476.29 5.91 93.95 315.53 1,079.07 0 TIMMERMAN J2 2208LH P-DP 0.0000000 0.0000399 0.0000399 0.0000000 1,192.87 548.67 5.91 93.95 331.64 474.53 0 TIMMERMAN J3 2208BH P-DP 0.0000000 0.0000399 0.0000399 0.0000000 1,613.45 425.40 5.91 93.95 271.54 822.26 0 TIMMERMAN J4 2207MH P-DP 0.0000000 0.0000399 0.0000399 0.0000000 1,629.29 691.23 5.91 93.95 387.60 711.09 0 TIMMERMAN J5 2207LH P-DP 0.0000000 0.0000399 0.0000399 0.0000000 1,546.53 502.46 5.91 93.95 330.22 636.51 0 TIMMERMAN J6 2207BH P-DP 0.0000000 0.0000399 0.0000399 0.0000000 1,338.11 368.46 5.91 93.95 256.99 932.28 0 TIMMERMAN J7 2217LH P-DP 0.0000000 0.0000399 0.0000399 0.0000000 1,381.12 458.46 5.91 93.95 304.08 579.74 0 TIMMERMAN J8 2207CH P-DP 0.0000000 0.0000399 0.0000399 0.0000000 1,584.33 245.83 5.91 93.95 150.11 795.33 0 TIMMERMAN J9 2206MH P-DP 0.0000000 0.0000399 0.0000399 0.0000000 1,915.41 874.84 5.91 93.95 538.33 758.43 0 RICHARD E LEHMAN SWITZ9BHSU P-DP 0.0000000 0.0005064 0.0005064 0.0000000 16,932.41 0.00 5.72 91.83 0.00 11,458.52 0 RICHARD E LEHMAN SWITZ9DHSU P-DP 0.0000000 0.0005064 0.0005064 0.0000000 16,176.37 0.00 5.72 91.83 0.00 12,388.33 0 EL KABONG UNIT 48-17-8 301H P-DP 0.0000000 0.0002629 0.0002629 0.0000000 726.13 585.70 6.99 94.56 285.70 335.34 0 EL KABONG UNIT 48-17-8 302H P-DP 0.0000000 0.0002629 0.0002629 0.0000000 918.27 776.22 6.99 94.56 414.76 314.92 0 EL KABONG UNIT 48-17-8 701H P-DP 0.0000000 0.0002629 0.0002629 0.0000000 470.39 448.84 6.99 94.56 259.28 178.44 0 EL KABONG UNIT 48-17-8 702H P-DP 0.0000000 0.0002629 0.0002629 0.0000000 1,460.06 578.91 6.99 94.56 284.55 498.43 0 EL KABONG UNIT 48-17-8 703H P-DP 0.0000000 0.0002629 0.0002629 0.0000000 548.33 671.97 6.99 94.56 337.44 225.66 0 EL KABONG UNIT 48-17-8 704H P-DP 0.0000000 0.0002629 0.0002629 0.0000000 605.42 531.69 6.99 94.56 311.63 272.73 0 EL KABONG UNIT 48-17-8 705H P-DP 0.0000000 0.0002629 0.0002629 0.0000000 401.16 211.01 6.99 94.56 74.71 114.23 0 EL KABONG UNIT 48-17-8 801H P-DP 0.0000000 0.0002629 0.0002629 0.0000000 614.77 132.16 6.99 94.56 127.25 378.51 0

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![](exhibit992-202210xk070.jpg)

LEASE NAME GAS PRC INITIAL $/Mcf GROSS ULTIMATE Mbbl GROSS ULTIMATE MMcf CUM GAS MMcf CUM OIL Mbbl EXPENSE INITIAL DECIMAL INTEREST FINAL DECIMAL REVENUE INITIAL DECIMAL INTEREST FINAL DECIMAL OIL PRC INITIAL $/bbl RES CAT AS OF DATE FIXED COST $/MO As of : 01/01/2023 GROSS ULTIMATE RESERVES, CUMULATIVE PRODUCTION AND BASIC ECONOMIC DATA TABLE 7 RIPLEY UNIT 1 P-DP 0.0000000 0.0152740 0.0152740 0.0000000 13.58 1.65 6.10 91.83 1.65 13.58 0 CHILDRESS 140 1 P-DP 0.0000000 0.0500000 0.0500000 0.0000000 177.32 13.12 4.77 91.77 12.80 167.50 0 CHILDRESS 140 2 P-DP 0.0000000 0.0500000 0.0500000 0.0000000 27.05 8.28 4.77 91.77 8.25 26.87 0 CHILDRESS 140 5 P-DP 0.0000000 0.0500000 0.0500000 0.0000000 163.89 26.79 4.77 91.77 25.69 160.09 0 SUGG A 141-140 (ALLOC-A) 1SM P-DP 0.0000000 0.0121102 0.0121102 0.0000000 3,283.00 265.44 4.77 91.77 198.28 1,630.92 0 SUGG A 141-140 (ALLOC-B) 2SU P-DP 0.0000000 0.0128238 0.0128238 0.0000000 2,581.39 169.28 4.77 91.77 131.43 1,214.11 0 SUGG A 141-140 (ALLOC-C) 3SM P-DP 0.0000000 0.0124861 0.0124861 0.0000000 3,676.72 230.14 4.77 91.77 167.25 1,597.39 0 SUGG A 141-140 (ALLOC-D) 4SU P-DP 0.0000000 0.0122146 0.0122146 0.0000000 2,493.67 175.50 4.77 91.77 134.88 1,051.70 0 SUGG A 141-140 (ALLOC-E) 5RM P-DP 0.0000000 0.0121537 0.0121537 0.0000000 3,771.60 179.16 4.77 91.77 143.73 1,847.57 0 SUGG A 141-140 (ALLOC-F) 6SM P-DP 0.0000000 0.0121297 0.0121297 0.0000000 2,333.07 76.77 4.77 91.77 67.10 1,528.66 0 SUGG A 141-140 (ALLOC-F) 6SU P-DP 0.0000000 0.0122156 0.0122156 0.0000000 1,945.97 131.49 4.77 91.77 112.88 1,109.20 0 SUGG A 141-140 (ALLOC-G) 7SM P-DP 0.0000000 0.0122500 0.0122500 0.0000000 3,679.10 115.87 4.77 91.77 98.45 1,851.16 0 SUGG A 141-140 (ALLOC-G) 7SU P-DP 0.0000000 0.0123396 0.0123396 0.0000000 3,892.71 120.19 4.77 91.77 103.64 1,638.54 0 SUGG A 141-140 (ALLOC-H) 8SM P-DP 0.0000000 0.0121654 0.0121654 0.0000000 6,150.10 128.05 4.77 91.77 109.78 2,260.42 0 SUGG A 141-140 (ALLOC-H) 8SU P-DP 0.0000000 0.0123361 0.0123361 0.0000000 2,542.90 127.92 4.77 91.77 111.42 1,466.86 0 CV RB SU58;SJ MONDELLO ETAL 18 001 P-DP 0.0000000 0.0156250 0.0156250 0.0000000 402.89 0.00 5.85 91.83 0.00 370.90 0 HA RA SUA;GOLSON 36-25 HC 001-ALT P-DP 0.0000000 0.0986163 0.0986163 0.0000000 8,323.25 0.00 5.85 91.83 0.00 4,561.89 0 HA RA SUA;GOLSON 36-25 HC 002-ALT P-DP 0.0000000 0.0986163 0.0986163 0.0000000 9,008.50 0.00 5.85 91.83 0.00 4,237.68 0 HA RA SUA;WIGGINS 36-25 HC 001 P-DP 0.0000000 0.0493230 0.0493230 0.0000000 12,311.74 0.00 5.85 91.83 0.00 10,667.79 0 HA RA SUA;WIGGINS 36-25 HC 002-ALT P-DP 0.0000000 0.0503545 0.0503545 0.0000000 12,121.86 0.00 5.85 91.83 0.00 11,751.65 0 HA RA SUB;LAWSON 31-30 HC 001-ALT P-DP 0.0000000 0.0073240 0.0073240 0.0000000 13,887.12 0.00 5.85 91.83 0.00 11,080.82 0 HA RA SUB;LAWSON 31-30-19 HC 002-ALT P-DP 0.0000000 0.0073300 0.0073300 0.0000000 15,603.99 0.00 5.85 91.83 0.00 12,504.97 0 HA RA SUB;LAWSON 31-30-19 HC 003-ALT P-DP 0.0000000 0.0099298 0.0099298 0.0000000 17,089.81 0.00 5.85 91.83 0.00 13,129.91 0 HA RA SUL;L & L INV 18-19 HC 001-ALT P-DP 0.0000000 0.0012590 0.0012590 0.0000000 12,515.56 0.00 5.85 91.83 0.00 9,527.62 0 HA RA SUL;L & L INV 18-19 HC 002-ALT P-DP 0.0000000 0.0013872 0.0013872 0.0000000 12,890.77 0.00 5.85 91.83 0.00 10,107.97 0 HA RA SUL;MADDEN 18 H 001 P-DP 0.0000000 0.0156397 0.0156397 0.0000000 2,629.62 0.00 5.85 91.83 0.00 2,433.63 0 HA RA SUL;MADDEN 18 H 002-ALT P-DP 0.0000000 0.0156397 0.0156397 0.0000000 7,769.13 0.00 5.85 91.83 0.00 6,471.03 0 HA RA SUL;MADDEN 18-19 HC 001-ALT P-DP 0.0000000 0.0019049 0.0019049 0.0000000 8,956.64 0.00 5.85 91.83 0.00 7,971.13 0 HA RA SUL;SCHION 18-19 HC 001-ALT P-DP 0.0000000 0.0078136 0.0078136 0.0000000 17,133.24 0.00 5.85 91.83 0.00 8,318.09 0 HA RA SUS;MJR FAMLLC21-28-33HC 001-ALT P-DP 0.0000000 0.1163630 0.1163630 0.0000000 6,882.92 0.00 5.85 91.83 0.00 1,630.47 0 HA RA SUS;MJR FAMLLC21-28-33HC 002-ALT P-DP 0.0000000 0.1077978 0.1077978 0.0000000 16,317.03 0.00 5.85 91.83 0.00 2,446.99 0 HA RA SUS;POOLE-DRAKE 21 H 001 P-DP 0.0000000 0.1176788 0.1176788 0.0000000 13,112.09 0.00 5.85 91.83 0.00 8,993.11 0 HA RA SUZ;GLOVER 20 001 P-DP 0.0000000 0.0078075 0.0078075 0.0000000 9,253.27 0.00 5.85 91.83 0.00 9,132.63 0 HA RA SUZ;GLOVER 20 002-ALT P-DP 0.0000000 0.0078075 0.0078075 0.0000000 11,038.21 0.00 5.85 91.83 0.00 9,299.54 0 HA RA SUZ;GLOVER 20 003-ALT P-DP 0.0000000 0.0078075 0.0078075 0.0000000 11,131.27 0.00 5.85 91.83 0.00 9,693.85 0 HA RA SUZ;JUNCACEAE 20 001-ALT P-DP 0.0000000 0.0078075 0.0078075 0.0000000 7,741.60 0.00 5.85 91.83 0.00 7,732.17 0 HA RA SUZ;JUNCACEAE 20 002-ALT P-DP 0.0000000 0.0078075 0.0078075 0.0000000 9,151.92 0.00 5.85 91.83 0.00 8,557.12 0

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![](exhibit992-202210xk071.jpg)

LEASE NAME GAS PRC INITIAL $/Mcf GROSS ULTIMATE Mbbl GROSS ULTIMATE MMcf CUM GAS MMcf CUM OIL Mbbl EXPENSE INITIAL DECIMAL INTEREST FINAL DECIMAL REVENUE INITIAL DECIMAL INTEREST FINAL DECIMAL OIL PRC INITIAL $/bbl RES CAT AS OF DATE FIXED COST $/MO As of : 01/01/2023 GROSS ULTIMATE RESERVES, CUMULATIVE PRODUCTION AND BASIC ECONOMIC DATA TABLE 7 HA RA SUZ;JUNCACEAE 20 003-ALT P-DP 0.0000000 0.0078075 0.0078075 0.0000000 10,363.86 0.00 5.85 91.83 0.00 9,454.50 0 HA RB SU69;NAC ROYALTY 33 H 001 P-DP 0.0000000 0.0782261 0.0782261 0.0000000 14,291.46 0.00 5.85 91.83 0.00 7,968.28 0 HA RB SU74;NAC ROYALTY 28 H 001 P-DP 0.0000000 0.1311698 0.1311698 0.0000000 4,894.33 0.00 5.85 91.83 0.00 4,876.59 0 HA RB SU77;WAHL 27 H 001 P-DP 0.0000000 0.0437142 0.0437142 0.0000000 4,859.82 0.00 5.85 91.83 0.00 4,701.03 0 HA RB SU90;BYU PIERRE29-12-10H 001-ALT P-DP 0.0000000 0.0375773 0.0375773 0.0000000 11,686.14 0.00 5.85 91.83 0.00 7,716.83 0 HA RB SU90;BYU PIERRE29-12-10H 002-ALT P-DP 0.0000000 0.0375773 0.0375773 0.0000000 6,298.80 0.00 5.85 91.83 0.00 3,803.67 0 HA RB SU90;NRG 29-12-10 H 001 P-DP 0.0000000 0.0375773 0.0375773 0.0000000 8,462.56 0.00 5.85 91.83 0.00 7,304.40 0 HA RB SU90;NRG 29-12-10 H 002-ALT P-DP 0.0000000 0.0375773 0.0375773 0.0000000 18,294.17 0.00 5.85 91.83 0.00 16,125.83 0 HA RB SU90;NRG 29-12-10 H 003-ALT P-DP 0.0000000 0.0375773 0.0375773 0.0000000 13,419.57 0.00 5.85 91.83 0.00 4,274.03 0 HA RB SU90;NRG 29-12-10 H 004-ALT P-DP 0.0000000 0.0375773 0.0375773 0.0000000 14,995.39 0.00 5.85 91.83 0.00 4,670.99 0 HA RB SU92;NAC ROYALTY 34 H 001 P-DP 0.0000000 0.1572809 0.1572809 0.0000000 1,263.42 0.00 5.85 91.83 0.00 1,236.74 0 ADMIRAL 4-48 47 1H P-DP 0.0000000 0.0005432 0.0005432 0.0000000 3,838.17 667.98 5.79 92.44 442.32 2,607.11 0 ALLMAN 24 1H P-DP 0.0000000 0.0043022 0.0043022 0.0000000 8,239.38 306.53 5.79 92.44 215.86 4,689.21 0 BOREAS 79 1H P-DP 0.0000000 0.0002688 0.0002688 0.0000000 691.03 336.72 5.79 92.44 254.74 627.67 0 BUZZARD NORTH 6972 A 1H P-DP 0.0000000 0.0009749 0.0009749 0.0000000 2,636.31 927.50 5.79 92.44 796.47 2,357.81 0 BUZZARD NORTH 6972 B 2H P-DP 0.0000000 0.0009749 0.0009749 0.0000000 1,401.22 380.69 5.79 92.44 170.61 696.16 0 BUZZARD NORTH 6972 S 3H P-DP 0.0000000 0.0009749 0.0009749 0.0000000 2,067.41 419.17 5.79 92.44 172.58 793.53 0 BUZZARD SOUTH 6972 A 3H P-DP 0.0000000 0.0011548 0.0011548 0.0000000 2,774.04 584.50 5.79 92.44 243.64 1,014.37 0 BUZZARD SOUTH 6972 A 4H P-DP 0.0000000 0.0009749 0.0009749 0.0000000 2,928.30 462.20 5.79 92.44 193.77 883.29 0 BUZZARD SOUTH 6972 B 1H P-DP 0.0000000 0.0011548 0.0011548 0.0000000 3,046.03 829.86 5.79 92.44 552.74 1,695.28 0 DONALDSON 4-54 1H P-DP 0.0000000 0.0002250 0.0002250 0.0000000 3,197.72 93.41 5.79 92.44 75.87 2,562.90 0 DONALDSON 4-54 U 34H P-DP 0.0000000 0.0002250 0.0002250 0.0000000 4,047.35 163.27 5.79 92.44 95.05 1,939.87 0 ELKHEAD 4144 A 2H P-DP 0.0000000 0.0004602 0.0004602 0.0000000 5,657.44 957.47 5.79 92.44 634.69 3,927.80 0 ELKHEAD 4144 A 5H P-DP 0.0000000 0.0004602 0.0004602 0.0000000 3,851.93 536.23 5.79 92.44 292.81 2,059.23 0 ELKHEAD 4144 A 7H P-DP 0.0000000 0.0004602 0.0004602 0.0000000 5,285.17 620.61 5.79 92.44 367.74 2,708.45 0 ELKHEAD 4144 B 1H P-DP 0.0000000 0.0004602 0.0004602 0.0000000 2,920.07 770.79 5.79 92.44 555.34 1,947.61 0 ELKHEAD 4144 B 6H P-DP 0.0000000 0.0004602 0.0004602 0.0000000 3,003.73 337.87 5.79 92.44 199.57 1,493.40 0 ELKHEAD 4144 B 8H P-DP 0.0000000 0.0004602 0.0004602 0.0000000 3,801.35 476.70 5.79 92.44 264.21 1,964.31 0 ELKHEAD 4144 C 4H P-DP 0.0000000 0.0004602 0.0004602 0.0000000 3,014.85 388.99 5.79 92.44 231.35 1,552.92 0 ELKHEAD 4144 S 3H P-DP 0.0000000 0.0004602 0.0004602 0.0000000 2,173.91 485.48 5.79 92.44 284.45 1,647.21 0 FLEMING 13 10H P-DP 0.0000000 0.0040391 0.0040391 0.0000000 4,403.62 120.60 5.79 92.44 70.41 2,290.74 0 GEORGE T STAGG 5-2 UNIT 1H P-DP 0.0000000 0.0034293 0.0034293 0.0000000 2,019.68 68.73 5.79 92.44 62.67 1,705.91 0 GRIZZLY BEAR 7780 2U A 2H P-DP 0.0000000 0.0006487 0.0006487 0.0000000 1,482.43 362.78 5.79 92.44 285.50 947.75 0 GRIZZLY BEAR 7780 3U A 3H P-DP 0.0000000 0.0006490 0.0006490 0.0000000 1,768.10 228.57 5.79 92.44 185.80 1,012.96 0 GRIZZLY BEAR 7780 4U A 4H P-DP 0.0000000 0.0006540 0.0006540 0.0000000 2,485.56 525.83 5.79 92.44 290.91 1,144.74 0 GRIZZLY BEAR 7780 5U A 5H P-DP 0.0000000 0.0006460 0.0006460 0.0000000 1,225.09 202.16 5.79 92.44 168.68 819.26 0 GRIZZLY BEAR 7780 6U A 6H P-DP 0.0000000 0.0006488 0.0006488 0.0000000 2,801.06 534.39 5.79 92.44 359.42 1,247.88 0

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![](exhibit992-202210xk072.jpg)

LEASE NAME GAS PRC INITIAL $/Mcf GROSS ULTIMATE Mbbl GROSS ULTIMATE MMcf CUM GAS MMcf CUM OIL Mbbl EXPENSE INITIAL DECIMAL INTEREST FINAL DECIMAL REVENUE INITIAL DECIMAL INTEREST FINAL DECIMAL OIL PRC INITIAL $/bbl RES CAT AS OF DATE FIXED COST $/MO As of : 01/01/2023 GROSS ULTIMATE RESERVES, CUMULATIVE PRODUCTION AND BASIC ECONOMIC DATA TABLE 7 GRIZZLY SOUTH 7673 A 1H P-DP 0.0000000 0.0019953 0.0019953 0.0000000 1,383.67 488.78 5.79 92.44 475.88 1,217.82 0 GRIZZLY SOUTH 7673 A 3H P-DP 0.0000000 0.0019953 0.0019953 0.0000000 1,076.15 374.74 5.79 92.44 157.70 382.49 0 GRIZZLY SOUTH 7673 A 5H P-DP 0.0000000 0.0019953 0.0019953 0.0000000 1,695.70 394.02 5.79 92.44 208.32 647.78 0 GRIZZLY SOUTH 7673 A 8H P-DP 0.0000000 0.0019953 0.0019953 0.0000000 2,389.42 612.24 5.79 92.44 297.21 908.01 0 GRIZZLY SOUTH 7673 B 2H P-DP 0.0000000 0.0019953 0.0019953 0.0000000 1,685.91 717.33 5.79 92.44 594.32 1,520.10 0 GRIZZLY SOUTH 7673 B 4H P-DP 0.0000000 0.0019953 0.0019953 0.0000000 958.34 167.80 5.79 92.44 91.37 511.78 0 GRIZZLY SOUTH 7673 B 6H P-DP 0.0000000 0.0019953 0.0019953 0.0000000 1,841.24 343.13 5.79 92.44 166.61 769.64 0 GRIZZLY WEST 77 1H P-DP 0.0000000 0.0010076 0.0010076 0.0000000 1,806.35 367.23 5.79 92.44 283.16 898.86 0 GRIZZLY WEST 77 A 3H P-DP 0.0000000 0.0010076 0.0010076 0.0000000 774.70 210.15 5.79 92.44 153.10 696.44 0 GRIZZLY WEST 77 C 2H P-DP 0.0000000 0.0010076 0.0010076 0.0000000 918.35 165.92 5.79 92.44 112.98 665.41 0 HARGROVE, BETTY 1 P-DP 0.0000000 0.0159713 0.0159713 0.0000000 1,817.11 0.00 5.79 92.44 0.00 1,788.78 0 KENOSHA 4441 1H P-DP 0.0000000 0.0004248 0.0004248 0.0000000 7,644.96 822.92 5.79 92.44 606.11 5,084.03 0 KENOSHA 4441 B 2H P-DP 0.0000000 0.0004248 0.0004248 0.0000000 3,903.49 587.30 5.79 92.44 408.22 2,564.95 0 KENOSHA-KEYHOLE 4341 1U A 1H P-DP 0.0000000 0.0004206 0.0004206 0.0000000 3,073.00 469.09 5.79 92.44 172.87 869.62 0 KENOSHA-KEYHOLE 4341 2U B 2H P-DP 0.0000000 0.0004206 0.0004206 0.0000000 4,514.93 414.65 5.79 92.44 155.20 1,095.02 0 KEYHOLE 43 1H P-DP 0.0000000 0.0004034 0.0004034 0.0000000 2,028.46 663.53 5.79 92.44 447.74 1,453.16 0 KODIAK 7677 1U B 1H P-DP 0.0000000 0.0005786 0.0005786 0.0000000 1,968.36 309.26 5.79 92.44 80.38 386.08 0 KODIAK 7677 2U B 2H P-DP 0.0000000 0.0005779 0.0005779 0.0000000 969.72 170.82 5.79 92.44 63.88 250.49 0 KODIAK 7677 3U A 3H P-DP 0.0000000 0.0005765 0.0005765 0.0000000 1,258.65 391.92 5.79 92.44 108.75 307.60 0 KODIAK 7677 4U A 4H P-DP 0.0000000 0.0005743 0.0005743 0.0000000 1,382.98 249.58 5.79 92.44 77.93 330.79 0 LAURA WILDER 72-69 UNIT A 3H P-DP 0.0000000 0.0000688 0.0000688 0.0000000 3,146.12 1,036.47 5.79 92.44 712.67 2,507.38 0 LAURA WILDER 72-69 UNIT B 4HL P-DP 0.0000000 0.0001452 0.0001452 0.0000000 1,630.66 529.98 5.79 92.44 376.47 1,094.44 0 LOST SADDLE 45 1H P-DP 0.0000000 0.0001628 0.0001628 0.0000000 1,842.54 207.40 5.79 92.44 168.83 1,592.02 0 RICHMOND 39 2H P-DP 0.0000000 0.0001197 0.0001197 0.0000000 2,897.63 751.26 5.79 92.44 422.69 1,868.72 0 RICHMOND 39 3H P-DP 0.0000000 0.0001197 0.0001197 0.0000000 2,831.16 550.42 5.79 92.44 303.68 1,490.66 0 RICHMOND W STATE 4239 A-A 70H P-DP 0.0000000 0.0000418 0.0000418 0.0000000 2,797.39 353.97 5.79 92.44 181.09 1,172.64 0 RICHMOND W STATE 4239 A-B 71H P-DP 0.0000000 0.0000415 0.0000415 0.0000000 2,993.08 381.79 5.79 92.44 193.82 1,329.74 0 RICHMOND W STATE 4239 A-C 72H P-DP 0.0000000 0.0000415 0.0000415 0.0000000 1,909.85 191.21 5.79 92.44 94.97 788.48 0 RICHMOND W STATE 4239 A-D 73H P-DP 0.0000000 0.0000415 0.0000415 0.0000000 2,276.67 237.48 5.79 92.44 107.39 945.27 0 SANTANA 29 2H P-DP 0.0000000 0.0035482 0.0035482 0.0000000 4,911.69 248.85 5.79 92.44 176.01 3,855.68 0 SHADRACH 68 UNIT 134H P-DP 0.0000000 0.0009551 0.0009551 0.0000000 2,354.73 416.99 5.79 92.44 224.41 938.22 0 SHADRACH 68 UNIT 1H P-DP 0.0000000 0.0009551 0.0009551 0.0000000 4,193.82 708.95 5.79 92.44 477.42 1,868.30 0 SHADRACH 68 UNIT 223H P-DP 0.0000000 0.0009551 0.0009551 0.0000000 3,928.65 523.19 5.79 92.44 286.60 1,441.88 0 SHADRACH 68 UNIT 2H P-DP 0.0000000 0.0009551 0.0009551 0.0000000 4,850.76 634.99 5.79 92.44 376.60 3,486.89 0 SHADRACH 68 UNIT 324H P-DP 0.0000000 0.0009551 0.0009551 0.0000000 4,334.88 652.48 5.79 92.44 501.56 2,853.37 0 SHADRACH 68 UNIT 332H P-DP 0.0000000 0.0009551 0.0009551 0.0000000 2,897.14 530.51 5.79 92.44 266.32 1,258.80 0 SHADRACH MOSES CANTALOUPE 221H P-DP 0.0000000 0.0004688 0.0004688 0.0000000 3,332.28 492.55 5.79 92.44 263.80 1,320.88 0

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![](exhibit992-202210xk073.jpg)

LEASE NAME GAS PRC INITIAL $/Mcf GROSS ULTIMATE Mbbl GROSS ULTIMATE MMcf CUM GAS MMcf CUM OIL Mbbl EXPENSE INITIAL DECIMAL INTEREST FINAL DECIMAL REVENUE INITIAL DECIMAL INTEREST FINAL DECIMAL OIL PRC INITIAL $/bbl RES CAT AS OF DATE FIXED COST $/MO As of : 01/01/2023 GROSS ULTIMATE RESERVES, CUMULATIVE PRODUCTION AND BASIC ECONOMIC DATA TABLE 7 STATE MUDDY WATERS 30 2H P-DP 0.0000000 0.0025281 0.0025281 0.0000000 2,847.10 244.08 5.79 92.44 189.16 2,528.47 0 SUGARLOAF 74 1H P-DP 0.0000000 0.0021897 0.0021897 0.0000000 2,072.99 517.96 5.79 92.44 389.50 1,594.17 0 SUGARLOAF 7475 1U B 1H P-DP 0.0000000 0.0017861 0.0017861 0.0000000 2,630.92 400.43 5.79 92.44 209.72 1,032.14 0 SUGARLOAF 7475 2U B 2H P-DP 0.0000000 0.0015462 0.0015462 0.0000000 1,639.02 330.12 5.79 92.44 231.00 1,101.92 0 SUGARLOAF 7475 3U A 3H P-DP 0.0000000 0.0016105 0.0016105 0.0000000 3,034.73 775.43 5.79 92.44 567.31 1,919.43 0 THURMOND 132 ALLOC C 11H P-DP 0.0000000 0.0015190 0.0015190 0.0000000 2,127.38 253.29 5.79 92.44 153.35 1,421.92 0 THURMOND A137 ALLOC. A 10H P-DP 0.0000000 0.0014494 0.0014494 0.0000000 2,935.56 366.55 5.79 92.44 249.98 1,540.50 0 TIN STAR A L 33H P-DP 0.0000000 0.0002979 0.0002979 0.0000000 5,642.47 750.98 5.79 92.44 441.46 3,151.57 0 TIN STAR B L 42H P-DP 0.0000000 0.0002462 0.0002462 0.0000000 3,663.65 405.27 5.79 92.44 280.69 2,207.78 0 TIN STAR D U 46H P-DP 0.0000000 0.0002933 0.0002933 0.0000000 5,408.21 584.60 5.79 92.44 373.40 3,496.34 0 TOWNSEN 24265 ALLOC. A 10H P-DP 0.0000000 0.0006926 0.0006926 0.0000000 6,636.92 733.13 5.79 92.44 450.27 3,587.51 0 TRIANGLE 75 2H P-DP 0.0000000 0.0008994 0.0008994 0.0000000 1,110.55 201.85 5.79 92.44 169.21 888.90 0 VINTAGE A U 06H P-DP 0.0000000 0.0001720 0.0001720 0.0000000 3,243.70 351.97 5.79 92.44 154.12 1,051.43 0 VINTAGE B T 13H P-DP 0.0000000 0.0001526 0.0001526 0.0000000 5,331.97 371.30 5.79 92.44 173.20 2,274.23 0 VINTAGE D T 26H P-DP 0.0000000 0.0000398 0.0000398 0.0000000 4,759.09 355.80 5.79 92.44 168.00 2,312.96 0 WILLETT POT STILL 5-2C UNIT 1H P-DP 0.0000000 0.0033416 0.0033416 0.0000000 2,952.35 302.20 5.79 92.44 202.27 1,826.14 0 WINDY MOUNTAIN 7879 1U B 1H P-DP 0.0000000 0.0001809 0.0001809 0.0000000 3,116.64 379.60 5.79 92.44 245.45 2,031.53 0 WINDY MOUNTAIN 7879 2U B 2H P-DP 0.0000000 0.0001797 0.0001797 0.0000000 2,457.74 363.51 5.79 92.44 293.34 1,954.38 0 ELY GAS UNIT NO. 2 1 P-DP 0.0000000 0.0079574 0.0079574 0.0000000 1,589.41 0.00 6.74 91.83 0.00 1,255.72 0 NORTH AMERICAN COAL GAS UNIT 1 P-DP 0.0000000 0.0544738 0.0544738 0.0000000 1,283.49 0.05 6.74 91.83 0.05 1,000.71 0 JUR RA SUG;OLYMPIA MIN 30 H 001 P-DP 0.0000000 0.0026730 0.0026730 0.0000000 7,448.56 0.00 5.98 91.83 0.00 7,159.85 0 MEHAFFEY - BURNEM 1 P-DP 0.0000000 0.0625000 0.0625000 0.0000000 193.93 0.96 5.34 91.83 0.96 189.30 0 RIPLEY UNIT 3 P-DP 0.0000000 0.0152740 0.0152740 0.0000000 109.27 1.40 5.34 91.83 1.40 109.27 0 XBC-CAROLINE 3B 302H P-DP 0.0000000 0.0006273 0.0006273 0.0000000 2,415.54 533.85 5.85 93.90 365.44 884.07 0 XBC-CAROLINE 3C 303H P-DP 0.0000000 0.0006275 0.0006275 0.0000000 2,475.88 509.44 5.85 93.90 323.36 853.43 0 XBC-CAROLINE 3K 311H P-DP 0.0000000 0.0006350 0.0006350 0.0000000 2,163.31 446.77 5.85 93.90 319.23 879.34 0 XBC-CAROLINE 3L 312H P-DP 0.0000000 0.0006470 0.0006470 0.0000000 2,330.50 464.15 5.85 93.90 313.26 854.87 0 XBC-CAROLINE 3M 313H P-DP 0.0000000 0.0006438 0.0006438 0.0000000 2,611.82 552.53 5.85 93.90 327.48 801.95 0 XBC-UNRUH 3A 16H P-DP 0.0000000 0.0006519 0.0006519 0.0000000 1,968.72 696.18 5.85 93.90 401.67 828.83 0 XBC-UNRUH 3B 17H P-DP 0.0000000 0.0006606 0.0006606 0.0000000 2,064.60 559.04 5.85 93.90 364.18 1,038.11 0 ABIGAIL 218-219 UNIT 1H P-DP 0.0000000 0.0001208 0.0001208 0.0000000 3,853.88 304.09 5.60 92.85 175.66 2,396.65 0 BARNES, D. E. ESTATE 2 P-DP 0.0000000 0.0000900 0.0000900 0.0000000 207.60 280.08 5.60 92.85 213.64 107.96 0 BARNES, D. E. ESTATE 3H P-DP 0.0000000 0.0003553 0.0003553 0.0000000 558.47 279.82 5.60 92.85 208.75 343.50 0 BARNES, D. E. ESTATE 4H P-DP 0.0000000 0.0003553 0.0003553 0.0000000 400.95 466.12 5.60 92.85 261.61 234.70 0 BARSTOW -18- 1 P-DP 0.0000000 0.0000036 0.0000036 0.0000000 1,046.52 197.52 5.60 92.85 176.21 942.52 0 BARSTOW -18- 2 P-DP 0.0000000 0.0000036 0.0000036 0.0000000 179.05 120.38 5.60 92.85 116.99 167.01 0 BARSTOW -18- 3 P-DP 0.0000000 0.0000036 0.0000036 0.0000000 235.01 88.35 5.60 92.85 73.16 124.49 0

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![](exhibit992-202210xk074.jpg)

LEASE NAME GAS PRC INITIAL $/Mcf GROSS ULTIMATE Mbbl GROSS ULTIMATE MMcf CUM GAS MMcf CUM OIL Mbbl EXPENSE INITIAL DECIMAL INTEREST FINAL DECIMAL REVENUE INITIAL DECIMAL INTEREST FINAL DECIMAL OIL PRC INITIAL $/bbl RES CAT AS OF DATE FIXED COST $/MO As of : 01/01/2023 GROSS ULTIMATE RESERVES, CUMULATIVE PRODUCTION AND BASIC ECONOMIC DATA TABLE 7 BARSTOW -18- 4 P-DP 0.0000000 0.0000036 0.0000036 0.0000000 461.20 83.88 5.60 92.85 78.93 398.45 0 BARSTOW -18- 5 P-DP 0.0000000 0.0000036 0.0000036 0.0000000 589.28 155.37 5.60 92.85 143.34 474.99 0 BARSTOW -23- 1 P-DP 0.0000000 0.0000039 0.0000039 0.0000000 327.81 99.96 5.60 92.85 92.37 301.06 0 BARSTOW -23- 2 P-DP 0.0000000 0.0000039 0.0000039 0.0000000 323.19 73.31 5.60 92.85 69.79 243.46 0 BARSTOW -23- 3 P-DP 0.0000000 0.0000039 0.0000039 0.0000000 385.58 198.50 5.60 92.85 148.47 210.03 0 BARSTOW -23- 4 P-DP 0.0000000 0.0000039 0.0000039 0.0000000 745.90 206.28 5.60 92.85 178.14 638.07 0 BARSTOW -23- 6 P-DP 0.0000000 0.0000039 0.0000039 0.0000000 453.18 58.31 5.60 92.85 49.70 347.79 0 BARSTOW -23- 6A P-DP 0.0000000 0.0000039 0.0000039 0.0000000 46.30 51.93 5.60 92.85 51.91 46.29 0 BARSTOW -23- 7 P-DP 0.0000000 0.0000039 0.0000039 0.0000000 539.84 111.00 5.60 92.85 108.00 464.09 0 BARSTOW -23- 8 P-DP 0.0000000 0.0000039 0.0000039 0.0000000 238.16 94.18 5.60 92.85 86.85 128.15 0 BARSTOW -23- 9 P-DP 0.0000000 0.0000039 0.0000039 0.0000000 1,140.51 97.44 5.60 92.85 87.92 888.00 0 BARSTOW 155 1 P-DP 0.0000000 0.0000075 0.0000075 0.0000000 56.42 68.08 5.60 92.85 33.99 31.36 0 BARSTOW 155 2 P-DP 0.0000000 0.0000075 0.0000075 0.0000000 106.53 92.97 5.60 92.85 22.85 19.65 0 BARSTOW 27 1 P-DP 0.0000000 0.0000050 0.0000050 0.0000000 266.72 199.79 5.60 92.85 187.18 195.96 0 BARSTOW 27 2 P-DP 0.0000000 0.0000050 0.0000050 0.0000000 132.96 122.07 5.60 92.85 71.88 84.90 0 BARSTOW 27 3 P-DP 0.0000000 0.0000050 0.0000050 0.0000000 117.07 209.60 5.60 92.85 144.45 65.37 0 BARSTOW 27 4 P-DP 0.0000000 0.0000050 0.0000050 0.0000000 454.54 212.59 5.60 92.85 125.06 312.00 0 BARSTOW 27 5 P-DP 0.0000000 0.0000050 0.0000050 0.0000000 538.43 129.50 5.60 92.85 74.45 431.74 0 BARSTOW 27 6 P-DP 0.0000000 0.0000050 0.0000050 0.0000000 516.03 136.01 5.60 92.85 84.65 380.46 0 BARSTOW 27 7 P-DP 0.0000000 0.0000050 0.0000050 0.0000000 463.71 123.73 5.60 92.85 84.18 371.17 0 BARSTOW 27 8 P-DP 0.0000000 0.0000050 0.0000050 0.0000000 153.58 88.10 5.60 92.85 25.12 35.91 0 BARSTOW 33 UA 1BS P-DP 0.0000000 0.0000114 0.0000114 0.0000000 852.82 234.56 5.60 92.85 220.02 736.40 0 BARSTOW 33 UB 2BS P-DP 0.0000000 0.0000114 0.0000114 0.0000000 1,412.03 313.15 5.60 92.85 241.20 1,002.33 0 BARSTOW 33-34 1H P-DP 0.0000000 0.0000025 0.0000025 0.0000000 2,335.59 742.72 5.60 92.85 591.93 1,830.88 0 BARSTOW 33-35 1H P-DP 0.0000000 0.0000018 0.0000018 0.0000000 616.05 314.18 5.60 92.85 296.45 589.83 0 BARSTOW 33-35 2H P-DP 0.0000000 0.0000018 0.0000018 0.0000000 772.35 339.23 5.60 92.85 253.86 526.07 0 BARSTOW 33-35 3H P-DP 0.0000000 0.0000018 0.0000018 0.0000000 3,200.20 695.61 5.60 92.85 501.58 2,185.51 0 BARSTOW A 3652H P-DP 0.0000000 0.0000003 0.0000003 0.0000000 5,835.44 1,157.54 5.60 92.85 699.11 3,454.49 0 BRACERO 226-34 UNIT 1H P-DP 0.0000000 0.0011740 0.0011740 0.0000000 1,886.90 177.81 5.60 92.85 105.73 1,115.57 0 BRAMBLETT 34-216 1H P-DP 0.0000000 0.0014654 0.0014654 0.0000000 1,365.69 186.80 5.60 92.85 121.01 758.89 0 BROOKE 184-185 UNIT 2H P-DP 0.0000000 0.0005642 0.0005642 0.0000000 8,061.22 651.35 5.60 92.85 370.66 4,214.70 0 BURKHOLDER A UNIT 1 P-DP 0.0000000 0.0001481 0.0001481 0.0000000 65,805.02 0.01 5.60 92.85 0.01 65,745.64 0 BYRD 34-170 UNIT 3H P-DP 0.0000000 0.0002005 0.0002005 0.0000000 983.89 469.90 5.60 92.85 307.97 562.67 0 BYRD 34-170 UNIT 4H P-DP 0.0000000 0.0002005 0.0002005 0.0000000 622.00 177.21 5.60 92.85 174.63 521.49 0 CALIFORNIA CHROME UNIT 2H P-DP 0.0000000 0.0008218 0.0008218 0.0000000 7,202.43 669.56 5.60 92.85 416.01 4,655.33 0 CALIFORNIA CHROME UNIT 5003HR P-DP 0.0000000 0.0008218 0.0008218 0.0000000 6,722.67 620.00 5.60 92.85 381.28 4,207.62 0 CHALUPA 34-153 UNIT 1H P-DP 0.0000000 0.0030208 0.0030208 0.0000000 1,711.81 662.37 5.60 92.85 399.38 916.51 0

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![](exhibit992-202210xk075.jpg)

LEASE NAME GAS PRC INITIAL $/Mcf GROSS ULTIMATE Mbbl GROSS ULTIMATE MMcf CUM GAS MMcf CUM OIL Mbbl EXPENSE INITIAL DECIMAL INTEREST FINAL DECIMAL REVENUE INITIAL DECIMAL INTEREST FINAL DECIMAL OIL PRC INITIAL $/bbl RES CAT AS OF DATE FIXED COST $/MO As of : 01/01/2023 GROSS ULTIMATE RESERVES, CUMULATIVE PRODUCTION AND BASIC ECONOMIC DATA TABLE 7 CHALUPA 34-153 UNIT 2H P-DP 0.0000000 0.0030208 0.0030208 0.0000000 1,951.59 1,232.20 5.60 92.85 772.00 1,160.77 0 CHURRO 34-157/158 UNIT 1H P-DP 0.0000000 0.0001395 0.0001395 0.0000000 2,188.65 1,253.04 5.60 92.85 681.65 1,136.68 0 COLUMBINE 34-167 3H P-DP 0.0000000 0.0000337 0.0000337 0.0000000 405.71 91.91 5.60 92.85 69.91 326.36 0 COLUMBINE 34-167 4H P-DP 0.0000000 0.0000337 0.0000337 0.0000000 996.14 428.30 5.60 92.85 309.26 734.01 0 CONSTANTAN 34-174 (N) 1H P-DP 0.0000000 0.0000090 0.0000090 0.0000000 4,929.19 799.05 5.60 92.85 513.48 3,275.61 0 CORNELL 226-34 1H P-DP 0.0000000 0.0008204 0.0008204 0.0000000 3,716.10 403.72 5.60 92.85 196.54 2,231.07 0 CRAZY CAMEL 1 P-DP 0.0000000 0.0021149 0.0021149 0.0000000 25.59 20.70 5.60 92.85 18.14 24.85 0 CRAZY CAMEL 2 P-DP 0.0000000 0.0021149 0.0021149 0.0000000 46.38 88.33 5.60 92.85 48.12 37.20 0 CRAZY CAMEL 5 P-DP 0.0000000 0.0021149 0.0021149 0.0000000 56.82 4.57 5.60 92.85 2.96 26.86 0 CRAZY CAMEL 6 P-DP 0.0000000 0.0021149 0.0021149 0.0000000 26.09 9.20 5.60 92.85 6.01 7.09 0 CRAZY CAMEL 7 P-DP 0.0000000 0.0021149 0.0021149 0.0000000 61.56 41.39 5.60 92.85 12.46 25.69 0 CROSS V RANCH 34-170 UNIT 1H P-DP 0.0000000 0.0004007 0.0004007 0.0000000 1,366.29 631.71 5.60 92.85 340.20 710.29 0 DANIELLE 183 UNIT 1H P-DP 0.0000000 0.0001309 0.0001309 0.0000000 4,561.78 702.69 5.60 92.85 362.53 2,599.21 0 DANIELLE 183 UNIT 2H P-DP 0.0000000 0.0001309 0.0001309 0.0000000 5,802.01 693.81 5.60 92.85 375.65 3,050.63 0 DAVIS 201-200-199 UNIT 1H P-DP 0.0000000 0.0002820 0.0002820 0.0000000 6,008.63 392.79 5.60 92.85 240.59 3,865.01 0 DRAINAGE 34-136 1H P-DP 0.0000000 0.0003759 0.0003759 0.0000000 350.16 163.26 5.60 92.85 158.34 322.05 0 DRAINAGE 34-136 2H P-DP 0.0000000 0.0003759 0.0003759 0.0000000 495.55 231.26 5.60 92.85 197.80 408.41 0 DRAINAGE 34-136 3H P-DP 0.0000000 0.0003759 0.0003759 0.0000000 528.20 589.92 5.60 92.85 471.84 485.01 0 DRAINAGE 34-136 4H P-DP 0.0000000 0.0003759 0.0003759 0.0000000 661.88 596.76 5.60 92.85 458.46 574.51 0 DRAINAGE A3 6LA P-DP 0.0000000 0.0001931 0.0001931 0.0000000 679.47 404.23 5.60 92.85 141.89 195.11 0 EILAND 1806A-33 1H P-DP 0.0000000 0.0003115 0.0003115 0.0000000 859.89 458.28 5.60 92.85 336.57 646.31 0 EILAND 1806B-33 1H P-DP 0.0000000 0.0002850 0.0002850 0.0000000 819.16 762.51 5.60 92.85 462.64 575.09 0 EILAND 1806B-33 62H P-DP 0.0000000 0.0002850 0.0002850 0.0000000 942.28 486.44 5.60 92.85 390.68 665.76 0 EILAND 1806C-33 1H P-DP 0.0000000 0.0002850 0.0002850 0.0000000 902.32 559.89 5.60 92.85 374.03 591.75 0 EILAND 1806C-33 81H P-DP 0.0000000 0.0002849 0.0002849 0.0000000 355.39 320.75 5.60 92.85 175.60 193.91 0 EILAND 1806C-33 82H P-DP 0.0000000 0.0002849 0.0002849 0.0000000 709.25 634.88 5.60 92.85 342.38 367.07 0 EILAND 1806C-33 83H P-DP 0.0000000 0.0002850 0.0002850 0.0000000 930.62 613.62 5.60 92.85 348.92 485.77 0 EILAND 6047A-34 41H P-DP 0.0000000 0.0007587 0.0007587 0.0000000 874.59 543.93 5.60 92.85 397.32 631.80 0 EMMA 218-219 UNIT 1H P-DP 0.0000000 0.0001208 0.0001208 0.0000000 8,895.21 542.93 5.60 92.85 273.23 4,485.73 0 FIRE FROG 57-32 A 1WA P-DP 0.0000000 0.0005029 0.0005029 0.0000000 1,744.03 497.80 5.60 92.85 237.20 722.33 0 FIRE FROG 57-32 B 2BS P-DP 0.0000000 0.0005662 0.0005662 0.0000000 2,756.48 883.65 5.60 92.85 404.37 1,183.87 0 FIRE FROG 57-32 C 3WA P-DP 0.0000000 0.0005288 0.0005288 0.0000000 1,774.02 565.69 5.60 92.85 259.68 735.42 0 FIRE FROG 57-32 D 4BS P-DP 0.0000000 0.0006019 0.0006019 0.0000000 3,159.33 866.98 5.60 92.85 384.56 1,215.92 0 FIREBIRD 52 1 P-DP 0.0000000 0.0001179 0.0001179 0.0000000 288.95 22.80 5.60 92.85 18.72 241.31 0 FUNKY BOSS B 8251H P-DP 0.0000000 0.0000010 0.0000010 0.0000000 5,738.62 1,235.11 5.60 92.85 823.54 3,517.90 0 FUNKY BOSS C 8270H P-DP 0.0000000 0.0000010 0.0000010 0.0000000 4,490.63 556.48 5.60 92.85 367.79 2,302.15 0 GADDIE 1-31 UNIT 1H P-DP 0.0000000 0.0000335 0.0000335 0.0000000 1,500.74 682.43 5.60 92.85 461.84 997.84 0

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![](exhibit992-202210xk076.jpg)

LEASE NAME GAS PRC INITIAL $/Mcf GROSS ULTIMATE Mbbl GROSS ULTIMATE MMcf CUM GAS MMcf CUM OIL Mbbl EXPENSE INITIAL DECIMAL INTEREST FINAL DECIMAL REVENUE INITIAL DECIMAL INTEREST FINAL DECIMAL OIL PRC INITIAL $/bbl RES CAT AS OF DATE FIXED COST $/MO As of : 01/01/2023 GROSS ULTIMATE RESERVES, CUMULATIVE PRODUCTION AND BASIC ECONOMIC DATA TABLE 7 GADDIE 1-31 UNIT 2H P-DP 0.0000000 0.0000335 0.0000335 0.0000000 625.39 296.96 5.60 92.85 218.13 483.02 0 GADDIE 1-31 UNIT 3H P-DP 0.0000000 0.0000335 0.0000335 0.0000000 46.18 251.29 5.60 92.85 210.76 46.11 0 HORNSILVER 1H P-DP 0.0000000 0.0001203 0.0001203 0.0000000 6,195.27 452.52 5.60 92.85 264.55 3,436.70 0 JACKSON A 34-166-175 5201H P-DP 0.0000000 0.0000000 0.0000000 0.0000000 1,040.61 502.72 5.60 92.85 321.42 682.27 0 LEE 34-154 1H P-DP 0.0000000 0.0045313 0.0045313 0.0000000 312.56 184.27 5.60 92.85 130.33 202.89 0 LEEDE UNIT 7 1H P-DP 0.0000000 0.0005495 0.0005495 0.0000000 672.78 487.16 5.60 92.85 367.03 523.16 0 LEEDE UNIT 7 2H P-DP 0.0000000 0.0005495 0.0005495 0.0000000 540.83 282.78 5.60 92.85 207.53 381.76 0 MARY GRACE 201-202 UNIT 1H P-DP 0.0000000 0.0001950 0.0001950 0.0000000 4,870.85 471.80 5.60 92.85 275.09 2,565.54 0 MARY GRACE 201-202 UNIT 3H P-DP 0.0000000 0.0001950 0.0001950 0.0000000 4,507.61 474.34 5.60 92.85 270.08 2,676.80 0 MELISSA A 1 P-DP 0.0000000 0.0003638 0.0003638 0.0000000 364.36 27.27 5.60 92.85 24.06 362.12 0 MERIDITH 183 UNIT 1H P-DP 0.0000000 0.0000983 0.0000983 0.0000000 2,734.59 333.00 5.60 92.85 180.96 1,555.08 0 MONROE 34-158 UNIT 1H P-DP 0.0000000 0.0002791 0.0002791 0.0000000 476.35 381.56 5.60 92.85 379.86 474.08 0 MONROE 34-158 UNIT 2H P-DP 0.0000000 0.0002791 0.0002791 0.0000000 657.17 479.55 5.60 92.85 466.31 640.96 0 MONROE 34-158 UNIT 3H P-DP 0.0000000 0.0002791 0.0002791 0.0000000 800.83 512.05 5.60 92.85 416.98 667.41 0 MONROE 34-158 UNIT 4H P-DP 0.0000000 0.0002791 0.0002791 0.0000000 173.99 168.16 5.60 92.85 167.29 173.25 0 MUD HEN 57-31 A 1WA P-DP 0.0000000 0.0002888 0.0002888 0.0000000 1,330.14 353.97 5.60 92.85 202.07 596.74 0 MUD HEN 57-31 B 2BS P-DP 0.0000000 0.0004518 0.0004518 0.0000000 1,891.57 669.07 5.60 92.85 346.33 1,008.50 0 MUD HEN 57-31 C 3WA P-DP 0.0000000 0.0003635 0.0003635 0.0000000 1,256.51 449.44 5.60 92.85 201.71 589.54 0 MUD HEN 57-31 D 4BS P-DP 0.0000000 0.0004281 0.0004281 0.0000000 2,344.76 756.32 5.60 92.85 331.68 1,013.24 0 PALMER 52 UNIT 222H P-DP 0.0000000 0.0012230 0.0012230 0.0000000 2,749.19 364.08 5.60 92.85 101.00 785.23 0 PALMER 52 UNIT 332H P-DP 0.0000000 0.0012230 0.0012230 0.0000000 3,592.70 256.36 5.60 92.85 78.53 1,072.82 0 PRIMA 1H P-DP 0.0000000 0.0003637 0.0003637 0.0000000 5,317.85 368.98 5.60 92.85 196.99 2,627.12 0 PRONTO 1H P-DP 0.0000000 0.0003630 0.0003630 0.0000000 3,007.63 271.69 5.60 92.85 130.28 1,461.41 0 PRUETT 20 2 P-DP 0.0000000 0.0000412 0.0000412 0.0000000 424.28 221.22 5.60 92.85 178.16 304.29 0 PRUETT 20 4H P-DP 0.0000000 0.0000412 0.0000412 0.0000000 179.04 205.52 5.60 92.85 168.73 131.92 0 PRUETT 20 5H P-DP 0.0000000 0.0000412 0.0000412 0.0000000 235.38 86.94 5.60 92.85 60.20 142.40 0 PRUETT 20 6H P-DP 0.0000000 0.0000412 0.0000412 0.0000000 771.24 366.18 5.60 92.85 247.46 476.20 0 PRUETT 23 1H P-DP 0.0000000 0.0000687 0.0000687 0.0000000 16,924.65 112.74 5.60 92.85 78.16 16,819.60 0 PRUETT 23 2H P-DP 0.0000000 0.0000687 0.0000687 0.0000000 94.40 151.07 5.60 92.85 113.66 92.18 0 PRUETT 23A 1H P-DP 0.0000000 0.0000687 0.0000687 0.0000000 503.56 327.79 5.60 92.85 232.74 360.26 0 PRUETT 23A 1H P-DP 0.0000000 0.0000687 0.0000687 0.0000000 260.58 154.57 5.60 92.85 140.94 232.44 0 PRUETT 23A 2H P-DP 0.0000000 0.0000687 0.0000687 0.0000000 361.55 225.67 5.60 92.85 123.87 191.17 0 QUESO 34-153 UNIT 1H P-DP 0.0000000 0.0030208 0.0030208 0.0000000 2,690.52 736.55 5.60 92.85 496.99 1,767.47 0 QUESO 34-153 UNIT 2H P-DP 0.0000000 0.0030208 0.0030208 0.0000000 2,425.79 940.41 5.60 92.85 546.78 1,588.08 0 QUITO WEST UNIT 306 P-DP 0.0000000 0.0002557 0.0002557 0.0000000 169.06 409.45 5.60 92.85 397.20 167.70 0 QUITO, S. W. (DELAWARE) UNIT 201 P-DP 0.0000000 0.0003638 0.0003638 0.0000000 232.68 299.94 5.60 92.85 299.32 230.53 0 QUITO, S. W. (DELAWARE) UNIT 702 P-DP 0.0000000 0.0003638 0.0003638 0.0000000 1.30 1.01 5.60 92.85 1.01 1.30 0

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![](exhibit992-202210xk077.jpg)

LEASE NAME GAS PRC INITIAL $/Mcf GROSS ULTIMATE Mbbl GROSS ULTIMATE MMcf CUM GAS MMcf CUM OIL Mbbl EXPENSE INITIAL DECIMAL INTEREST FINAL DECIMAL REVENUE INITIAL DECIMAL INTEREST FINAL DECIMAL OIL PRC INITIAL $/bbl RES CAT AS OF DATE FIXED COST $/MO As of : 01/01/2023 GROSS ULTIMATE RESERVES, CUMULATIVE PRODUCTION AND BASIC ECONOMIC DATA TABLE 7 QUITO, S. W. (DELAWARE) UNIT 801 P-DP 0.0000000 0.0003638 0.0003638 0.0000000 18.95 0.74 5.60 92.85 0.46 18.01 0 RENDEZVOUS NORTH POOLED UNIT 1LA P-DP 0.0000000 0.0002748 0.0002748 0.0000000 779.16 1,184.10 5.60 92.85 688.35 422.01 0 RENDEZVOUS NORTH POOLED UNIT 9UA P-DP 0.0000000 0.0002748 0.0002748 0.0000000 1,198.98 717.30 5.60 92.85 440.86 678.73 0 RIVER CAT 57-33 A 1WA P-DP 0.0000000 0.0006221 0.0006221 0.0000000 2,774.95 797.38 5.60 92.85 266.52 801.81 0 ROADRUNNER 1 P-DP 0.0000000 0.0035091 0.0035091 0.0000000 98.80 27.58 5.60 92.85 22.73 74.28 0 ROADRUNNER 2 P-DP 0.0000000 0.0035091 0.0035091 0.0000000 969.89 43.68 5.60 92.85 32.92 944.10 0 ROCA UNIT 7 1H P-DP 0.0000000 0.0006594 0.0006594 0.0000000 835.86 534.87 5.60 92.85 404.30 621.61 0 ROCA UNIT 7 2H P-DP 0.0000000 0.0006594 0.0006594 0.0000000 527.41 288.80 5.60 92.85 224.84 387.31 0 SHOSHONE A 34-166-165 5201H P-DP 0.0000000 0.0000010 0.0000010 0.0000000 3,446.85 883.58 5.60 92.85 438.58 1,395.95 0 SPIRE 226-34 UNIT 1H P-DP 0.0000000 0.0011695 0.0011695 0.0000000 3,725.88 244.69 5.60 92.85 165.46 2,443.33 0 SRO 551 ALLOC B 101H P-DP 0.0000000 0.0001342 0.0001342 0.0000000 3,299.57 451.58 5.60 92.85 208.51 1,819.55 0 SRO 551 ALLOC. A 100H P-DP 0.0000000 0.0001342 0.0001342 0.0000000 3,188.22 314.07 5.60 92.85 202.21 1,805.51 0 STATE EILAND 3-33 11H P-DP 0.0000000 0.0005021 0.0005021 0.0000000 758.88 311.05 5.60 92.85 311.05 758.88 0 STATE EILAND 6047B-34 51H P-DP 0.0000000 0.0004966 0.0004966 0.0000000 984.93 471.81 5.60 92.85 388.06 795.42 0 STELLA STATE 34-208 WRD UNIT 1H P-DP 0.0000000 0.0002116 0.0002116 0.0000000 1,901.08 235.08 5.60 92.85 168.19 1,350.97 0 STELLA STATE 34-208 WRD UNIT 2H P-DP 0.0000000 0.0002116 0.0002116 0.0000000 2,272.09 307.76 5.60 92.85 169.86 1,301.34 0 STICKLINE 1H P-DP 0.0000000 0.0000282 0.0000282 0.0000000 8,285.54 677.09 5.60 92.85 306.04 3,667.27 0 TEEWINOT NORTH UNIT 4LA P-DP 0.0000000 0.0004880 0.0004880 0.0000000 487.57 403.82 5.60 92.85 331.06 396.41 0 TEEWINOT SOUTH UNIT 5LA P-DP 0.0000000 0.0004880 0.0004880 0.0000000 752.95 718.82 5.60 92.85 525.68 620.28 0 TIPI CHAPMAN 34-163 1H P-DP 0.0000000 0.0000016 0.0000016 0.0000000 489.36 271.09 5.60 92.85 235.33 417.66 0 TIPI CHAPMAN 34-163 2H P-DP 0.0000000 0.0000016 0.0000016 0.0000000 358.07 336.71 5.60 92.85 274.34 301.51 0 TIPI CHAPMAN 34-163 3H P-DP 0.0000000 0.0000016 0.0000016 0.0000000 756.88 162.15 5.60 92.85 140.69 601.10 0 TIPI CHAPMAN 34-163 4H P-DP 0.0000000 0.0000016 0.0000016 0.0000000 1,442.96 537.19 5.60 92.85 434.22 1,067.35 0 TRAUBE 1-11 WRD 1H P-DP 0.0000000 0.0002124 0.0002124 0.0000000 714.87 604.39 5.60 92.85 526.38 688.63 0 TRAUBE 1-11 WRD 2H P-DP 0.0000000 0.0002124 0.0002124 0.0000000 806.78 351.16 5.60 92.85 258.92 548.73 0 TRIDACNA 34-208 WRD UNIT 1H P-DP 0.0000000 0.0001060 0.0001060 0.0000000 2,648.89 319.99 5.60 92.85 244.59 1,693.08 0 TRIDACNA 34-208 WRD UNIT 2H P-DP 0.0000000 0.0001060 0.0001060 0.0000000 2,544.42 306.05 5.60 92.85 234.66 1,598.84 0 TRIDACNA 34-208 WRD UNIT 3H P-DP 0.0000000 0.0001060 0.0001060 0.0000000 2,391.17 345.35 5.60 92.85 259.88 1,746.39 0 TROTT 34-183 1H P-DP 0.0000000 0.0000983 0.0000983 0.0000000 1,171.59 158.74 5.60 92.85 131.33 951.27 0 VICKERS '34-127' 1H P-DP 0.0000000 0.0004386 0.0004386 0.0000000 481.62 205.89 5.60 92.85 189.25 388.77 0 VICKERS '34-127' 2H P-DP 0.0000000 0.0004386 0.0004386 0.0000000 223.40 164.51 5.60 92.85 128.70 164.88 0 WHIRLAWAY 99 1HA P-DP 0.0000000 0.0002250 0.0002250 0.0000000 245.26 366.19 5.60 92.85 259.86 164.95 0 WHISKEY RIVER 9596A-34 11H P-DP 0.0000000 0.0000059 0.0000059 0.0000000 1,214.37 1,143.76 5.60 92.85 675.26 708.14 0 WHISKEY RIVER 9596A-34 12H P-DP 0.0000000 0.0000055 0.0000055 0.0000000 913.57 325.92 5.60 92.85 210.72 468.17 0 WHISKEY RIVER 9596A-34 13H P-DP 0.0000000 0.0000056 0.0000056 0.0000000 464.97 356.20 5.60 92.85 263.02 276.88 0 WHISKEY RIVER 9596B-34 1H P-DP 0.0000000 0.0000056 0.0000056 0.0000000 384.97 426.49 5.60 92.85 281.51 299.86 0 WHISKEY RIVER 9596B-34 31H P-DP 0.0000000 0.0000056 0.0000056 0.0000000 858.00 493.72 5.60 92.85 250.10 400.50 0

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![](exhibit992-202210xk078.jpg)

LEASE NAME GAS PRC INITIAL $/Mcf GROSS ULTIMATE Mbbl GROSS ULTIMATE MMcf CUM GAS MMcf CUM OIL Mbbl EXPENSE INITIAL DECIMAL INTEREST FINAL DECIMAL REVENUE INITIAL DECIMAL INTEREST FINAL DECIMAL OIL PRC INITIAL $/bbl RES CAT AS OF DATE FIXED COST $/MO As of : 01/01/2023 GROSS ULTIMATE RESERVES, CUMULATIVE PRODUCTION AND BASIC ECONOMIC DATA TABLE 7 WHISKEY RIVER 9596B-34 32H P-DP 0.0000000 0.0000056 0.0000056 0.0000000 1,490.21 613.69 5.60 92.85 303.65 710.65 0 WHISKEY RIVER 9596C-34 1H P-DP 0.0000000 0.0000056 0.0000056 0.0000000 968.93 734.21 5.60 92.85 334.13 396.13 0 WHISKEY RIVER 9596D-34 81H P-DP 0.0000000 0.0000056 0.0000056 0.0000000 1,003.85 649.97 5.60 92.85 407.13 542.74 0 WILSON 184-185 UNIT 2H P-DP 0.0000000 0.0001883 0.0001883 0.0000000 9,228.09 725.16 5.60 92.85 405.16 4,619.66 0 WRIGHT 1-22 E WRD UNIT 2H P-DP 0.0000000 0.0001410 0.0001410 0.0000000 318.79 174.13 5.60 92.85 134.81 232.51 0 WRIGHT 1-22 W WRD UNIT 2H P-DP 0.0000000 0.0001410 0.0001410 0.0000000 424.39 239.73 5.60 92.85 145.60 247.29 0 WRIGHT 1-22E WRD 1H P-DP 0.0000000 0.0001410 0.0001410 0.0000000 433.59 235.49 5.60 92.85 189.09 323.48 0 LION #1H P-DP 0.0000000 0.0003660 0.0003660 0.0000000 3,735.94 248.13 6.42 92.64 205.07 2,737.50 0 LION #3H P-DP 0.0000000 0.0003660 0.0003660 0.0000000 4,863.20 367.62 6.42 92.64 305.65 2,544.28 0 NE AXIS #2H P-DP 0.0000000 0.0007720 0.0007720 0.0000000 6,661.98 179.25 6.42 92.64 127.96 2,894.51 0 TIGIWON 2627-C23 E 433H P-DP 0.0000000 0.0004920 0.0004920 0.0000000 3,361.19 755.70 6.42 92.64 420.00 1,786.79 0 333,827.60 3,243,499.01 204,081.37 2,104,074.45 Proved Behind Pipe Rsv Class & Category CHAPARRAL UNIT A5 5AH P-BP 0.0000000 0.0010532 0.0010532 0.0000000 1,746.32 434.13 5.91 93.66 0.00 0.00 0 CALVERLEY-LANE 30G 7H P-BP 0.0000000 0.0032227 0.0032227 0.0000000 2,295.74 405.71 5.79 93.54 0.00 0.00 0 CALVERLEY-LANE 30H 8H P-BP 0.0000000 0.0032227 0.0032227 0.0000000 1,530.57 380.60 5.79 93.54 0.00 0.00 0 CALVERLEY-LANE 30I 9H P-BP 0.0000000 0.0032227 0.0032227 0.0000000 2,292.46 405.13 5.79 93.54 0.00 0.00 0 CALVERLEY-LANE 30J 10H P-BP 0.0000000 0.0032227 0.0032227 0.0000000 4,578.42 460.64 5.79 93.54 0.00 0.00 0 CALVERLEY-LANE 30K 11H P-BP 0.0000000 0.0032227 0.0032227 0.0000000 2,360.18 417.10 5.79 93.54 0.00 0.00 0 CALVERLEY-LANE 30L 12H P-BP 0.0000000 0.0032227 0.0032227 0.0000000 4,467.87 449.53 5.79 93.54 0.00 0.00 0 DRIVER-LANE 30A 1H P-BP 0.0000000 0.0032227 0.0032227 0.0000000 2,875.82 508.25 5.79 93.54 0.00 0.00 0 DRIVER-LANE 30B 2H P-BP 0.0000000 0.0032227 0.0032227 0.0000000 5,570.22 560.48 5.79 93.54 0.00 0.00 0 DRIVER-LANE 30C 3H P-BP 0.0000000 0.0032227 0.0032227 0.0000000 2,878.76 508.78 5.79 93.54 0.00 0.00 0 DRIVER-LANE 30D 4H P-BP 0.0000000 0.0032227 0.0032227 0.0000000 5,570.04 560.47 5.79 93.54 0.00 0.00 0 DRIVER-LANE 30E 5H P-BP 0.0000000 0.0032227 0.0032227 0.0000000 2,853.62 504.34 5.79 93.54 0.00 0.00 0 DRIVER-LANE 30F 6H P-BP 0.0000000 0.0032227 0.0032227 0.0000000 5,764.58 580.05 5.79 93.54 0.00 0.00 0 HULING 7-19 B 221 P-BP 0.0000000 0.0004340 0.0004340 0.0000000 2,852.31 504.11 5.79 93.54 0.00 0.00 0 HULING 7-19 D 241 P-BP 0.0000000 0.0004340 0.0004340 0.0000000 3,027.42 535.08 5.79 93.54 0.00 0.00 0 LULO 2531LP 4H P-BP 0.0000000 0.0010156 0.0010156 0.0000000 3,125.71 799.67 5.72 92.42 0.00 0.00 0 LULO 2533LP 8H P-BP 0.0000000 0.0010156 0.0010156 0.0000000 2,288.53 568.93 5.72 92.42 0.00 0.00 0 LULO 2543DP 6H P-BP 0.0000000 0.0010156 0.0010156 0.0000000 2,344.31 582.78 5.72 92.42 0.00 0.00 0 LULO 2551AP 5H P-BP 0.0000000 0.0010156 0.0010156 0.0000000 2,712.78 1,106.29 5.72 92.42 0.00 0.00 0 LULO 2553AP 9H P-BP 0.0000000 0.0010156 0.0010156 0.0000000 2,344.25 582.77 5.72 92.42 0.00 0.00 0 LULO 3641DP 2H P-BP 0.0000000 0.0010156 0.0010156 0.0000000 2,552.46 1,040.89 5.72 92.42 0.00 0.00 0 SCATTER TISH 10-46 (ALLOC-D) 4NA P-BP 0.0000000 0.0129760 0.0129760 0.0000000 2,164.91 720.03 5.72 92.42 0.00 0.00 0 SCATTER TISH 10-46 (ALLOC-D) 4NS P-BP 0.0000000 0.0129760 0.0129760 0.0000000 1,990.16 547.69 5.72 92.42 0.00 0.00 0 TREE FROG 47 WEST UNIT 7WB P-BP 0.0000000 0.0019838 0.0019838 0.0000000 1,700.34 422.77 5.72 92.42 0.00 0.00 0

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![](exhibit992-202210xk079.jpg)

LEASE NAME GAS PRC INITIAL $/Mcf GROSS ULTIMATE Mbbl GROSS ULTIMATE MMcf CUM GAS MMcf CUM OIL Mbbl EXPENSE INITIAL DECIMAL INTEREST FINAL DECIMAL REVENUE INITIAL DECIMAL INTEREST FINAL DECIMAL OIL PRC INITIAL $/bbl RES CAT AS OF DATE FIXED COST $/MO As of : 01/01/2023 GROSS ULTIMATE RESERVES, CUMULATIVE PRODUCTION AND BASIC ECONOMIC DATA TABLE 7 POINTER N CRC JF 7H P-BP 0.0000000 0.0011640 0.0011640 0.0000000 2,915.60 0.00 6.42 91.83 0.00 0.00 0 POINTER N CRC JF 9H P-BP 0.0000000 0.0011640 0.0011640 0.0000000 4,194.13 0.00 6.42 91.83 0.00 0.00 0 POINTER W CRC JF 5H P-BP 0.0000000 0.0011640 0.0011640 0.0000000 3,388.24 0.00 6.42 91.83 0.00 0.00 0 B AND B 6H P-BP 0.0000000 0.0005308 0.0005308 0.0000000 2,071.15 389.73 6.42 92.64 0.00 0.00 0 B AND B STATE B 7H P-BP 0.0000000 0.0004530 0.0004530 0.0000000 1,953.10 367.53 6.42 92.64 0.00 0.00 0 BADFISH 31-43 A 1JM P-BP 0.0000000 0.0003973 0.0003973 0.0000000 2,049.16 509.25 5.60 93.62 0.00 0.00 0 BADFISH 31-43 A 4LS P-BP 0.0000000 0.0003973 0.0003973 0.0000000 2,247.57 574.81 5.60 93.62 0.00 0.00 0 BADFISH 31-43 B 9LS P-BP 0.0000000 0.0003973 0.0003973 0.0000000 2,241.48 573.26 5.60 93.62 0.00 0.00 0 BADFISH 31-43 E 5WA P-BP 0.0000000 0.0003973 0.0003973 0.0000000 1,894.65 772.45 5.60 93.62 0.00 0.00 0 BADFISH 31-43 E 7WB P-BP 0.0000000 0.0003973 0.0003973 0.0000000 2,902.88 537.62 5.60 93.62 0.00 0.00 0 BADFISH 31-43 F 6WA P-BP 0.0000000 0.0003973 0.0003973 0.0000000 1,967.55 802.20 5.60 93.62 0.00 0.00 0 BADFISH 31-43 F 8WB P-BP 0.0000000 0.0003973 0.0003973 0.0000000 2,802.06 518.95 5.60 93.62 0.00 0.00 0 BADFISH 31-43 J 10WA P-BP 0.0000000 0.0003973 0.0003973 0.0000000 1,953.10 796.30 5.60 93.62 0.00 0.00 0 BADFISH 31-43 J 11WB P-BP 0.0000000 0.0003973 0.0003973 0.0000000 2,845.16 526.94 5.60 93.62 0.00 0.00 0 BADFISH 31-43 L 12MS P-BP 0.0000000 0.0003973 0.0003973 0.0000000 1,975.28 490.90 5.60 93.62 0.00 0.00 0 BADFISH 31-43 M 13JM P-BP 0.0000000 0.0003973 0.0003973 0.0000000 1,944.13 483.17 5.60 93.62 0.00 0.00 0 BADFISH 31-43 M 3LS P-BP 0.0000000 0.0003973 0.0003973 0.0000000 2,248.99 575.20 5.60 93.62 0.00 0.00 0 DIRE WOLF UNIT 1 0402BH P-BP 0.0000000 0.0023604 0.0023604 0.0000000 2,289.91 424.14 5.60 93.62 0.00 0.00 0 DIRE WOLF UNIT 1 0411AH P-BP 0.0000000 0.0034180 0.0034180 0.0000000 1,566.50 638.71 5.60 93.62 0.00 0.00 0 DIRE WOLF UNIT 1 0413AH P-BP 0.0000000 0.0034180 0.0034180 0.0000000 1,565.38 638.27 5.60 93.62 0.00 0.00 0 DIRE WOLF UNIT 1 0422SH P-BP 0.0000000 0.0034180 0.0034180 0.0000000 1,787.58 457.23 5.60 93.62 0.00 0.00 0 DIRE WOLF UNIT 1 0471JH P-BP 0.0000000 0.0034180 0.0034180 0.0000000 1,616.18 401.76 5.60 93.62 0.00 0.00 0 HYDRA 45-4 UNIT 2 151 P-BP 0.0000000 0.0007586 0.0007586 0.0000000 1,515.35 617.89 5.60 93.62 0.00 0.00 0 HYDRA 45-4 UNIT 2 161 P-BP 0.0000000 0.0007586 0.0007586 0.0000000 1,700.54 434.99 5.60 93.62 0.00 0.00 0 HYDRA 45-4 UNIT 2 164 P-BP 0.0000000 0.0007586 0.0007586 0.0000000 1,589.01 647.94 5.60 93.62 0.00 0.00 0 HYDRA 45-4 UNIT 2 171 P-BP 0.0000000 0.0007586 0.0007586 0.0000000 1,774.91 454.02 5.60 93.62 0.00 0.00 0 HYDRA 45-4 UNIT 2 173 P-BP 0.0000000 0.0007586 0.0007586 0.0000000 1,574.58 642.05 5.60 93.62 0.00 0.00 0 HYDRA 45-4 UNIT 2 181 P-BP 0.0000000 0.0007586 0.0007586 0.0000000 1,784.16 456.40 5.60 93.62 0.00 0.00 0 HYDRA 45-4 UNIT 2 262 P-BP 0.0000000 0.0007586 0.0007586 0.0000000 1,487.04 606.36 5.60 93.62 0.00 0.00 0 HYDRA 45-4 UNIT 2 263 P-BP 0.0000000 0.0007586 0.0007586 0.0000000 1,479.59 603.32 5.60 93.62 0.00 0.00 0 HYDRA 45-4 UNIT 2 272 P-BP 0.0000000 0.0007586 0.0007586 0.0000000 1,573.30 641.54 5.60 93.62 0.00 0.00 0 HYDRA 45-4 UNIT 2 274 P-BP 0.0000000 0.0007586 0.0007586 0.0000000 2,290.65 424.35 5.60 93.62 0.00 0.00 0 HYDRA 45-4 UNIT 2 282 P-BP 0.0000000 0.0007586 0.0007586 0.0000000 1,575.82 642.57 5.60 93.62 0.00 0.00 0 LAMAR 13-1-A 03LS P-BP 0.0000000 0.0015625 0.0015625 0.0000000 1,724.16 441.06 5.60 93.62 0.00 0.00 0 LAMAR 13-1-B 03WA P-BP 0.0000000 0.0015625 0.0015625 0.0000000 1,520.44 619.99 5.60 93.62 0.00 0.00 0 LAMAR 13-1-C 08WB P-BP 0.0000000 0.0015625 0.0015625 0.0000000 2,222.14 411.67 5.60 93.62 0.00 0.00 0 LAMAR 13-1-D 10JM P-BP 0.0000000 0.0015625 0.0015625 0.0000000 1,735.33 443.92 5.60 93.62 0.00 0.00 0

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![](exhibit992-202210xk080.jpg)

LEASE NAME GAS PRC INITIAL $/Mcf GROSS ULTIMATE Mbbl GROSS ULTIMATE MMcf CUM GAS MMcf CUM OIL Mbbl EXPENSE INITIAL DECIMAL INTEREST FINAL DECIMAL REVENUE INITIAL DECIMAL INTEREST FINAL DECIMAL OIL PRC INITIAL $/bbl RES CAT AS OF DATE FIXED COST $/MO As of : 01/01/2023 GROSS ULTIMATE RESERVES, CUMULATIVE PRODUCTION AND BASIC ECONOMIC DATA TABLE 7 LAMAR 13-1-E 13WA P-BP 0.0000000 0.0015625 0.0015625 0.0000000 1,515.37 617.93 5.60 93.62 0.00 0.00 0 LAMAR 13-1-F 17LS P-BP 0.0000000 0.0015625 0.0015625 0.0000000 1,733.91 443.56 5.60 93.62 0.00 0.00 0 LAMAR 13-1-H 22JM P-BP 0.0000000 0.0015625 0.0015625 0.0000000 1,724.88 441.25 5.60 93.62 0.00 0.00 0 LAMAR 13-1-H G 18WB P-BP 0.0000000 0.0015625 0.0015625 0.0000000 2,219.33 411.16 5.60 93.62 0.00 0.00 0 NORRIS UNIT 32-H 3332SH P-BP 0.0000000 0.0045833 0.0045833 0.0000000 1,492.40 371.04 5.60 93.62 0.00 0.00 0 NORRIS UNIT 32-H 3333SH P-BP 0.0000000 0.0045833 0.0045833 0.0000000 1,514.80 376.61 5.60 93.62 0.00 0.00 0 NORRIS-MIMS ALLOCATION 3335SH P-BP 0.0000000 0.0045833 0.0045833 0.0000000 1,715.64 426.55 5.60 93.62 0.00 0.00 0 WELCH-COX W39F 206H P-BP 0.0000000 0.0011719 0.0011719 0.0000000 2,140.58 396.68 5.60 93.62 0.00 0.00 0 WELCH-COX W39G 207H P-BP 0.0000000 0.0011719 0.0011719 0.0000000 1,486.67 606.34 5.60 93.62 0.00 0.00 0 WELCH-COX W39H 208H P-BP 0.0000000 0.0011719 0.0011719 0.0000000 2,206.63 408.93 5.60 93.62 0.00 0.00 0 WELCH-COX W39I 209H P-BP 0.0000000 0.0011719 0.0011719 0.0000000 1,490.86 608.06 5.60 93.62 0.00 0.00 0 WELCH-COX W39J 210H P-BP 0.0000000 0.0011719 0.0011719 0.0000000 2,198.16 407.36 5.60 93.62 0.00 0.00 0 WELCH-COX W39K 211H P-BP 0.0000000 0.0011719 0.0011719 0.0000000 1,509.82 375.41 5.60 93.62 0.00 0.00 0 WELCH-COX W39L 212H P-BP 0.0000000 0.0011719 0.0011719 0.0000000 1,723.14 440.94 5.60 93.62 0.00 0.00 0 WELCH-COX W39M 213H P-BP 0.0000000 0.0011719 0.0011719 0.0000000 1,555.76 386.91 5.60 93.62 0.00 0.00 0 WELCH-COX W39N 214H P-BP 0.0000000 0.0011719 0.0011719 0.0000000 1,680.14 429.95 5.60 93.62 0.00 0.00 0 WELCH-COX W39O 215H P-BP 0.0000000 0.0011719 0.0011719 0.0000000 1,511.66 376.00 5.60 93.62 0.00 0.00 0 WELCH-COX W39P 216H P-BP 0.0000000 0.0011719 0.0011719 0.0000000 1,517.33 377.41 5.60 93.62 0.00 0.00 0 STIMSON-NAIL E17T 120H P-BP 0.0000000 0.0001924 0.0001924 0.0000000 3,694.83 540.17 5.91 93.95 0.00 0.00 0 STIMSON-NAIL W17P 16H P-BP 0.0000000 0.0000752 0.0000752 0.0000000 3,379.57 494.08 5.91 93.95 0.00 0.00 0 STIMSON-NAIL W17Q 17H P-BP 0.0000000 0.0000752 0.0000752 0.0000000 3,379.52 494.08 5.91 93.95 0.00 0.00 0 STIMSON-NAIL W17T 20H P-BP 0.0000000 0.0000752 0.0000752 0.0000000 3,379.46 494.07 5.91 93.95 0.00 0.00 0 HA RB SU77;NAC ROYALTY 27-41HC 002-ALT P-BP 0.0000000 0.0226226 0.0226226 0.0000000 17,796.70 0.00 5.85 91.83 0.00 0.00 0 HA RB SU92;NAC ROYALTY 34 H 002-ALT P-BP 0.0000000 0.1780109 0.1780109 0.0000000 17,825.91 0.00 5.85 91.83 0.00 0.00 0 NAC ROYALTY 27-41 HC 001 P-BP 0.0000000 0.0226226 0.0226226 0.0000000 17,806.45 0.00 5.85 91.83 0.00 0.00 0 LOST KEYS 4345 1U B 1H P-BP 0.0000000 0.0005208 0.0005208 0.0000000 9,402.51 924.72 5.79 92.44 0.00 0.00 0 LOST KEYS 4345 2U A 2H P-BP 0.0000000 0.0005208 0.0005208 0.0000000 8,287.99 1,193.70 5.79 92.44 0.00 0.00 0 LOST KEYS 4345 3U A 3H P-BP 0.0000000 0.0005208 0.0005208 0.0000000 8,404.76 1,210.52 5.79 92.44 0.00 0.00 0 LOST KEYS 4345 4U A 4H P-BP 0.0000000 0.0005208 0.0005208 0.0000000 5,357.67 771.67 5.79 92.44 0.00 0.00 0 LOST KEYS 4345 5U B 5H P-BP 0.0000000 0.0005208 0.0005208 0.0000000 7,667.36 754.11 5.79 92.44 0.00 0.00 0 LOST KEYS 4345 6U A 6H P-BP 0.0000000 0.0005208 0.0005208 0.0000000 6,880.19 990.99 5.79 92.44 0.00 0.00 0 STATE MUDDY WATERS UNIT 711H P-BP 0.0000000 0.0012734 0.0012734 0.0000000 4,258.97 613.65 5.79 92.44 0.00 0.00 0 STATE MUDDY WATERS UNIT 731H P-BP 0.0000000 0.0012734 0.0012734 0.0000000 4,950.07 487.03 5.79 92.44 0.00 0.00 0 STATE MUDDY WATERS UNIT 732H P-BP 0.0000000 0.0012734 0.0012734 0.0000000 4,836.36 475.85 5.79 92.44 0.00 0.00 0 STATE MUDDY WATERS UNIT 733H P-BP 0.0000000 0.0012734 0.0012734 0.0000000 4,758.28 468.17 5.79 92.44 0.00 0.00 0 STATE MUDDY WATERS UNIT 751H P-BP 0.0000000 0.0012734 0.0012734 0.0000000 4,717.20 464.13 5.79 92.44 0.00 0.00 0 SUGARLOAF 7475 5U B 5H P-BP 0.0000000 0.0015437 0.0015437 0.0000000 2,867.83 540.36 5.79 92.44 0.00 0.00 0

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![](exhibit992-202210xk081.jpg)

LEASE NAME GAS PRC INITIAL $/Mcf GROSS ULTIMATE Mbbl GROSS ULTIMATE MMcf CUM GAS MMcf CUM OIL Mbbl EXPENSE INITIAL DECIMAL INTEREST FINAL DECIMAL REVENUE INITIAL DECIMAL INTEREST FINAL DECIMAL OIL PRC INITIAL $/bbl RES CAT AS OF DATE FIXED COST $/MO As of : 01/01/2023 GROSS ULTIMATE RESERVES, CUMULATIVE PRODUCTION AND BASIC ECONOMIC DATA TABLE 7 Mud Hen 5 P-BP 0.0000000 0.0004290 0.0004290 0.0000000 3,126.52 588.91 5.60 92.85 0.00 0.00 0 RIVER CAT 57-33 B 2BS P-BP 0.0000000 0.0006221 0.0006221 0.0000000 3,343.85 629.93 5.60 92.85 0.00 0.00 0 RIVER CAT 57-33 C 3TS P-BP 0.0000000 0.0006221 0.0006221 0.0000000 1,714.32 323.27 5.60 92.85 0.00 0.00 0 SHOSHONE B 34-166-165 TB 2H P-BP 0.0000000 0.0000010 0.0000010 0.0000000 2,612.76 492.23 5.60 92.85 0.00 0.00 0 53,006.48 329,240.77 0.00 0.00 Proved Undeveloped Rsv Class & Category TREE FROG 47 WEST UNIT 7MS P-UD 0.0000000 0.0010396 0.0010396 0.0000000 1,696.77 422.21 5.72 92.42 0.00 0.00 0 POINTER E CRC JF 11H P-UD 0.0000000 0.0011640 0.0011640 0.0000000 5,146.12 0.00 6.42 91.83 0.00 0.00 0 CHAROLAIS 33 21 B1GB STATE COM 001H P-UD 0.0000000 0.0092812 0.0092812 0.0000000 3,055.76 1,173.84 10.87 93.62 0.00 0.00 0 CHAROLAIS 33 21 B1HA STATE COM 001H P-UD 0.0000000 0.0092812 0.0092812 0.0000000 3,055.76 1,173.84 10.87 93.62 0.00 0.00 0 WELCH-COX E39A 301H P-UD 0.0000000 0.0011719 0.0011719 0.0000000 1,470.77 365.99 5.60 93.62 0.00 0.00 0 WELCH-COX E39B 302H P-UD 0.0000000 0.0011719 0.0011719 0.0000000 1,470.71 365.98 5.60 93.62 0.00 0.00 0 WELCH-COX E39C 303H P-UD 0.0000000 0.0011719 0.0011719 0.0000000 1,467.68 365.23 5.60 93.62 0.00 0.00 0 WELCH-COX E39D 304H P-UD 0.0000000 0.0011719 0.0011719 0.0000000 1,468.12 365.35 5.60 93.62 0.00 0.00 0 WELCH-COX E39E 305H P-UD 0.0000000 0.0011719 0.0011719 0.0000000 1,468.52 365.45 5.60 93.62 0.00 0.00 0 WELCH-COX E39F 306H P-UD 0.0000000 0.0011719 0.0011719 0.0000000 1,475.80 367.27 5.60 93.62 0.00 0.00 0 WELCH-COX E39S 319H P-UD 0.0000000 0.0011719 0.0011719 0.0000000 1,530.90 380.99 5.60 93.62 0.00 0.00 0 WELCH-COX E39T 320H P-UD 0.0000000 0.0011719 0.0011719 0.0000000 1,529.57 380.67 5.60 93.62 0.00 0.00 0 WELCH-COX E39U 321H P-UD 0.0000000 0.0011719 0.0011719 0.0000000 1,530.92 381.00 5.60 93.62 0.00 0.00 0 WELCH-COX E39V 322H P-UD 0.0000000 0.0011719 0.0011719 0.0000000 1,534.62 381.92 5.60 93.62 0.00 0.00 0 WELCH-COX E39W 323H P-UD 0.0000000 0.0011719 0.0011719 0.0000000 1,540.29 383.36 5.60 93.62 0.00 0.00 0 SCRAMBLE C 47-11 4403H P-UD 0.0000000 0.0021843 0.0021843 0.0000000 2,203.94 408.60 5.91 93.95 0.00 0.00 0 STIMSON-NAIL E17K 111H P-UD 0.0000000 0.0001924 0.0001924 0.0000000 3,683.27 538.83 5.91 93.95 0.00 0.00 0 STIMSON-NAIL E17L 112H P-UD 0.0000000 0.0001924 0.0001924 0.0000000 3,688.61 539.62 5.91 93.95 0.00 0.00 0 STIMSON-NAIL E17M 113H P-UD 0.0000000 0.0001924 0.0001924 0.0000000 3,689.47 539.77 5.91 93.95 0.00 0.00 0 STIMSON-NAIL E17N 114H P-UD 0.0000000 0.0001924 0.0001924 0.0000000 3,677.59 538.04 5.91 93.95 0.00 0.00 0 STIMSON-NAIL E17O 115H P-UD 0.0000000 0.0001924 0.0001924 0.0000000 3,677.41 538.03 5.91 93.95 0.00 0.00 0 STIMSON-NAIL E17P 116H P-UD 0.0000000 0.0001924 0.0001924 0.0000000 3,677.24 538.01 5.91 93.95 0.00 0.00 0 STIMSON-NAIL E17Q 117H P-UD 0.0000000 0.0001924 0.0001924 0.0000000 3,677.06 538.00 5.91 93.95 0.00 0.00 0 STIMSON-NAIL E17R 118H P-UD 0.0000000 0.0001924 0.0001924 0.0000000 3,676.89 537.99 5.91 93.95 0.00 0.00 0 STIMSON-NAIL E17S 119H P-UD 0.0000000 0.0001924 0.0001924 0.0000000 3,688.76 539.73 5.91 93.95 0.00 0.00 0 STIMSON-NAIL W17K 11H P-UD 0.0000000 0.0000752 0.0000752 0.0000000 3,373.29 493.58 5.91 93.95 0.00 0.00 0 STIMSON-NAIL W17L 12H P-UD 0.0000000 0.0000752 0.0000752 0.0000000 3,373.12 493.57 5.91 93.95 0.00 0.00 0 STIMSON-NAIL W17M 13H P-UD 0.0000000 0.0000752 0.0000752 0.0000000 3,372.96 493.55 5.91 93.95 0.00 0.00 0 STIMSON-NAIL W17N 14H P-UD 0.0000000 0.0000752 0.0000752 0.0000000 3,372.79 493.54 5.91 93.95 0.00 0.00 0 STIMSON-NAIL W17O 15H P-UD 0.0000000 0.0000752 0.0000752 0.0000000 3,372.63 493.53 5.91 93.95 0.00 0.00 0 STIMSON-NAIL W17R 18H P-UD 0.0000000 0.0000752 0.0000752 0.0000000 3,491.20 510.89 5.91 93.95 0.00 0.00 0

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![](exhibit992-202210xk082.jpg)

LEASE NAME GAS PRC INITIAL $/Mcf GROSS ULTIMATE Mbbl GROSS ULTIMATE MMcf CUM GAS MMcf CUM OIL Mbbl EXPENSE INITIAL DECIMAL INTEREST FINAL DECIMAL REVENUE INITIAL DECIMAL INTEREST FINAL DECIMAL OIL PRC INITIAL $/bbl RES CAT AS OF DATE FIXED COST $/MO As of : 01/01/2023 GROSS ULTIMATE RESERVES, CUMULATIVE PRODUCTION AND BASIC ECONOMIC DATA TABLE 7 STIMSON-NAIL W17S 19H P-UD 0.0000000 0.0000752 0.0000752 0.0000000 3,372.31 493.50 5.91 93.95 0.00 0.00 0 WILLOW LAKES 19 192H P-UD 0.0000000 0.0002451 0.0002451 0.0000000 1,663.06 243.47 5.91 93.95 0.00 0.00 0 WILLOW LAKES 19 193H P-UD 0.0000000 0.0002451 0.0002451 0.0000000 1,666.75 244.01 5.91 93.95 0.00 0.00 0 HA RB SU92;NAC ROYALTY 34 H 003-ALT P-UD 0.0000000 0.1273627 0.1273627 0.0000000 13,552.64 0.00 5.85 91.83 0.00 0.00 0 SUGARLOAF 7475 6U A 6H P-UD 0.0000000 0.0015437 0.0015437 0.0000000 2,854.67 538.89 5.79 92.44 0.00 0.00 0 SUGARLOAF 7475 7U A 7H P-UD 0.0000000 0.0015437 0.0015437 0.0000000 2,846.90 537.44 5.79 92.44 0.00 0.00 0 SUGARLOAF 7475 8U A 8H P-UD 0.0000000 0.0015437 0.0015437 0.0000000 2,850.35 538.12 5.79 92.44 0.00 0.00 0 SUGARLOAF 7475 9U B 9H P-UD 0.0000000 0.0015437 0.0015437 0.0000000 2,859.03 539.78 5.79 92.44 0.00 0.00 0 SHOSHONE C 34-166-165 WA 3H P-UD 0.0000000 0.0000010 0.0000010 0.0000000 4,205.99 528.05 5.60 92.85 0.00 0.00 0 SHOSHONE D 34-166-165 TB 4H P-UD 0.0000000 0.0000010 0.0000010 0.0000000 2,619.94 494.20 5.60 92.85 0.00 0.00 0 SHOSHONE E 34-166-165 WB 5H P-UD 0.0000000 0.0000010 0.0000010 0.0000000 2,615.83 493.45 5.60 92.85 0.00 0.00 0 19,759.31 126,245.99 0.00 0.00 Grand Total 406,593.39 3,698,985.77 204,081.37 2,104,074.45

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