HALLADOR ENERGY CO 10-K

ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS. Our consolidated financial statements should be read in conjunction with this discussion. The following analysis includes a discussion of metrics on a per ton and per mega-watt hour (MWh) basis as derived from the condensed consolidated financial statements, which are considered non-GAAP measurements. These metrics are significant factors in assessing our operating results and profitability. OVERVIEW Hallador Energy Company (the “Company” or “Hallador”) is an energy company operating in the state of Indiana. Historically, the largest portion of our business has been devoted to coal mining in the State of Indiana through Sunrise Coal, LLC (a wholly-owned subsidiary) serving the electric power generation industry. On October 21, 2022, the Company, through its wholly owned subsidiary Hallador Power, acquired the Merom Generating Energy Station ("Merom"), a one gigawatt (“GW”) power plant located in Sullivan County, Indiana. Merom is located in the Midcontinent Independent System Operator's ("MISO") footprint. We believe this acquisition is the catalyst that began Hallador's transition from a producer of coal to a vertically integrated independent power producer ("IPP"). As a result of the Merom acquisition the Company has two reportable segments: coal operations (operated by Sunrise Coal, LLC) and electric operations (operated by Hallador Power). In addition to our reportable segments, the remainder of our operations are presented as “Corporate and Other” and primarily are comprised of unallocated corporate costs in addition to activities such as a 50% interest in Sunrise Energy, LLC, a private gas exploration company with operations in Indiana, accounted for using the equity method, and our wholly-owned subsidiary Summit Terminal LLC, a logistics transport facility located on the Ohio River. 2023 was the first whole year in which Hallador Power operated Merom. In accordance with the Purchase and Sale Agreement associated with the Merom acquisition, for the first five months of 2023, all fuel consumed at Merom was delivered from a third party and all energy produced was sold at $34 per MWh. Beginning in June 2023, approximately seventy percent of Merom’s energy became available to sell on the open market. However, despite spot prices for electricity at Merom averaging $39 in 2021 and $69 in 2022, generally milder weather and depressed natural gas prices drove down the average spot price for electricity to $31 in 2023. Despite near record margins at our coal division for the full year, the fourth quarter was a particularly challenging quarter for Hallador Power. A failure in Merom’s main Generator Step-Up Transformer (GSU) coupled with a scheduled maintenance outage took half of the plant offline for nearly the entire quarter. The planned maintenance resulted in $12.6 million in expenditures and the transformer replacement resulted in an additional $0.7 million in unplanned capital expenditures. Additionally, natural gas prices, which have great influence on overall electricity price, remained low throughout the second half of 2023 and dropped to an inflation adjusted all-time low in the first quarter of 2024. The acquisition of Merom, brought with it additional capex spending requirements to maintain and return the power plant to top condition, which we expected to pay for with fourth quarter free cash flow from in-quarter power sales. However, with fourth quarter challenges at both Merom and in our coal division, Sunrise Coal, we took steps to protect liquidity and to increase the efficiency of our operations. Thus, in December and early January we improved liquidity and provided operational flexibility through an At-The-Market (ATM) offering. Under the ATM, we sold approximately 800,000 shares of Hallador stock in December 2023 and raised approximately $7.3 million of equity resulting in 34,051,154 shares outstanding at December 31, 2023. Approximately 700,000 shares of Hallador stock was sold in January 2024 raising an additional $6.6 million of equity. Hallador’s share count stands at 34.9 million shares as of March 8, 2024. Liquidity at year end was $26.2 million. Subsequently, in February 2024, we further added to liquidity as several members of Hallador's Board of Directors loaned the company a total of $5 million through an unsecured one year note at an interest rate of 12% per annum. Receipt of roughly $36 million in capacity revenue for the 2024-2025 planning year will begin in the first quarter of 2024, further strengthening our financial position. See Note 4 to our consolidated financial statements for additional discussion about our bank debt and related liquidity. On February 23, 2024, our Coal Operations Segment undertook an initiative designed to strengthen our financial and operational efficiency and to create significant operational savings and higher margins in our coal segment. This step will advance our transition from a company primarily focused on coal production to a more resilient and diversified vertically integrated IPP. As part of this initiative, we idled production at our higher cost Prosperity Mine, and substantially idled production at Freelandville Mine with minimal production. This should reduce our capital reinvestment for coal production in 2024 by approximately $10 million. We also focused our seven units of underground equipment on four units of our lowest cost production at our Oaktown Mine. As part of the initiative, we reduced our workforce by approximately 110 employees. Historically, Sunrise Coal has generated approximately six million tons of coal annually. Following the restructuring, we expect Sunrise to produce roughly 4.5 million tons of coal annually at improved margins to our former structure. Additionally, in 2024, we have secured supplemental coal from third party suppliers at favorable prices. This allows us to diversify self-production supply risk and provides us with additional flexibility in our sales portfolio. The optionality to obtain low-cost tons either internally or from third parties while capturing upward swings in the commodities markets for coal should further maximize margins while optimizing fuels costs at Merom. In addition to the expected improvements in coal margins, Merom has the capability to provide revenue on up to 6 million mega-watt-hours (MWh) annually. Based on the currently available forward power price curves, we believe over time, the margins earned on energy and capacity sales will be more than double our historical margins of approximately eight dollars per ton on coal production. Furthering this belief, in Q3 we reported contracted sales of 3.4 million MWh to be delivered in 2026-2028 at MWh margins that we believe could exceed twenty-five dollars per MWh. We continue to see strong indications for both energy and capacity sales in 2024 and in future years. Our approach has been to sell energy primarily through bi-lateral agreements on a unit contingent basis in an attempt to reduce our exposure to market risk if we fail to produce due to operational issues in what we believe to be an increasingly volatile power market. While we are seeing success in this approach, sales of this type are largely bespoke and require more time and negotiation than a typical firm power sale as we build our forward sales positions. As we methodically work to contract our forward sales book, we continue to sell energy on the spot market, resulting in episodic cash generation largely dependent on demand created by seasonal weather and various other conditions which stress the power grid. The ability to store a commodity is inherently tied to the volatility of that commodity. Coal can be piled up for years, thus its volatility is low. Oil and gas face transportation and storage challenges which increase price volatility. Batteries and hydro generation are improving, but current technology and expense limit the ability to economic practicability of implementing the technology on a large-scale basis. We believe that the lack of economically viable storage options coupled with the challenges of non-dispatchable generation gaining market share in an environment where the sun does not always shine and the wind does not always blow, indicates that energy’s price volatility is likely to increase over the next decade. This volatility appears to be keeping the forward power price premium intact. In an effort to capture additional margins above our traditional wholesale energy markets, we recently agreed to a structure with Hoosier Energy and their distribution member, WIN REMC, that should allow us to attract industrial users of power, such as data centers, AI providers and power dense manufacturers, to the Merom property. We believe leveraging our plant to help supply these large users of energy with reliable, resilient electricity should allow us to operate more efficiently in a volatile power environment, generate increased margins and support the fragile power grid as it navigates the challenges of transition to new sources of energy in the coming decades. These types of relationships should allow us to capture the upside of increasing demand and volatility while providing stability to our earnings and ability to dispatch in a world that is consistently seeking more electricity but lacks the real time infrastructure and generation to satisfy those increasing power needs. Combined with our increased volume of forward power sales, we believe that these types of opportunities will continue to improve the outlook for the company and provide a stable platform to leverage both our power and coal assets in a responsible and sustainable manner. We are excited about the transformation of Hallador from a commodity focused producer of coal to a vertically integrated IPP. We believe that this transition provides significant opportunity to capture the increased margins of the energy markets, to take advantage of the increasing demand for electricity and to step up the value chain in a more sustainable and future proofed industry than that which we have traditionally operated in. As evidenced by the ongoing build of our long-term sales book, our deliberate movement into the electricity sector should materially strengthen our company and the products that we sell. 30 Table of Contents Solid Forward Sales Position - Segment Basis, Before Intercompany Eliminations 2024 2025 2026 2027 2028 Total Coal Priced tons - 3rd party (in millions) 3.4 1.8 0.5 0.5 - 6.2 Average price per ton - 3rd party $ 51.82 $ 50.57 $ 56.09 $ 56.09 $ - Priced tons (in millions) - Hallador Power 1.5 2.3 2.3 2.3 2.3 10.7 Average price per ton - Hallador Power $ 51.00 $ 51.00 $ 51.00 $ 51.00 $ 51.00 Contracted coal revenue (in millions) $ 252.69 $ 208.33 $ 145.35 $ 145.35 $ 117.30 $ 869.02 % Priced 109 % 91 % 62 % 62 % 51 % Committed & unpriced tons (in millions) - 3rd party - 1.0 1.0 1.0 - 3.0 Committed & unpriced tons (in millions) - Hallador Power - - - - - - Total contracted tons (in millions) 4.9 5.1 3.8 3.8 2.3 19.9 % Coal Sold* 109 % 113 % 84 % 84 % 51 % Average cost per ton of coal sold was $33.67 for the year ended December 31, 2023 ($26.98 after eliminating for intercompany sales to Hallador Power) 2024 Coal Capex Budget (in millions) $ 25.00 Power Energy Contracted MWh (in millions) 1.87 1.90 1.83 1.78 1.09 8.47 Average contracted price per MWh $ 35.23 $ 36.06 $ 55.37 $ 54.65 $ 52.98 Contracted revenue (in millions) $ 65.88 $ 68.51 $ 101.33 $ 97.28 $ 57.75 $ 390.75 % Energy Sold* 31 % 32 % 31 % 30 % 18 % Capacity Average daily contracted capacity 810 748 743 623 454 % Capacity Contracted** 94 % 87 % 86 % 72 % 53 % Average contracted capacity price per MWd $ 200 $ 210 $ 230 $ 226 $ 224 Contracted capacity revenue (in millions) $ 59.13 $ 57.33 $ 62.37 $ 51.39 $ 37.12 $ 267.34 Total Energy & Capacity Revenue Contracted Power Revenue (in millions) $ 125.01 $ 125.84 $ 163.70 $ 148.67 $ 94.87 $ 658.09 Contracted Power Revenue per MWh* $ 45.69 $ 47.05 $ 67.40 $ 66.47 $ 64.70 2023 average cost per MWh sold was $33.67 for the year ended December 31, 2023 ($26.98 assuming intercompany sales of coal were sold at cost) 2024 Power Capex Budget (in millions) $ 18.00 TOTAL CONTRACTED REVENUE (IN MILLIONS) $ 377.70 $ 334.17 $ 309.05 $ 294.02 $ 212.17 $ 1,527.11 * Based on coal production of 4.5 million tons and 6.0 million MWh annually. ** Based on a MISO accreditation of 860MW per day. Accreditations are adjusted annually based on 3-year rolling performance metrics. Internal Controls Disclosure The preparation of coal reserve and resource estimates is conducted by independent individuals who are by virtue of their education, experience and professional association considered qualified persons (as defined in SEC rules). Company personnel meet on an annual basis with the independent qualified person to provide updates to the reserve and resource estimates. Company personnel review the work of the qualified person to ensure such work is prepared in accordance with applicable rules and regulations and that the data and assumptions provided were properly applied to the final reserve and resource model. The Company’s engineering personnel ensure estimates are based on current mine plans, incorporate the most recent drilling and lab data, properly reflect changes in permitting status, consider known encumbrances, and are consistent with operating knowledge and expectations in terms of mining methods, recovery rates, minimum seam heights or maximum strip ratios, and saleable qualities. An American National Standards Institute-certified third-party laboratory is utilized to support reserve and resource estimates. The laboratory follows standard sample preparation, security, and environmental procedures. In addition, the Company’s qualified person performs independent data verification procedures to ensure data is of sufficient quantity and reliability to reasonably support the coal reserve and resource estimates. Estimates of any mineral reserve and resources are always subject to a degree of uncertainty. The level of confidence that can be applied to a particular estimate is a function of, among other things, the amount, quality, and completeness of exploration data; geological complexity of the deposit; and economic, legal, social, and environmental factors associated with mining the reserve/resource. The Company’s current coal reserves and resource estimates are based on the best information available and are subject to updates as conditions change. Also refer to "Item 1A. Risk Factors" for discussion of risks associated with the estimates of the Company’s reserves and resources. Summary of All Mining Properties The Company has six total mining properties. These properties are the Oaktown Mining Complex, which is comprised of Oaktown Fuels No. 1 Mine and Oaktown Fuels No. 2 Mine, the Ace in the Hole Mine, the Ace in the Hole Mine #2 Reserves, Prosperity and Freelandville. The Oaktown Fuels No. 1 Mine is an underground mine in the Illinois Basin located near Oaktown in Knox County, Indiana. Oaktown Fuels No. 1 Mine utilizes continuous mining units operating in room and pillar mining techniques to produce high-sulfur coal. The Oaktown Fuels No. 2 Mine is an underground mine in the Illinois Basin located near Oaktown in Knox County, Indiana. The Oaktown Fuels No. 2 Mine utilizes continuous mining units operating in room and pillar mining techniques to produce high-sulfur coal. The preparation plant at the Oaktown Mine Complex has a throughput capacity of 1,600 tons of raw coal per hour. Freelandville is a surface mine in the Illinois Basin located near Freelandville in Knox County, Indiana. Freelandville utilizes surface mining techniques to produce high-sulfur coal from as many as three seams. Prosperity is a surface mine in the Illinois Basin located near Petersburg in Pike County, Indiana. Prosperity utilizes surface mining techniques to produce low-sulfur coal. The low-sulfur coal is trucked to the Oaktown Complex and other Sunrise Coal logistic facilities where it is blended with coal from the Oaktown Mines. Ace in the Hole Mine is now depleted. These properties and further summaries concerning property description, purpose, property overview, geology, background, processing operations, mine infrastructure, and market analysis can be found and are hereby incorporated by reference from Sections 1.1, 1.2, 1.3, 1.6, 2.1, 3, 4, 5, 6, 7.1, 7.3, 7.4, 8, 9, and 10 from the October 2023 Technical Report Summary prepared by the John T. Boyd Company, attached as Exhibit 99.1 to this Form 10-K. The following figure shows the general location of All Mining Properties discussed above: Individual Mining Properties The following information concerning our mining properties has been prepared in accordance with the requirements of subpart 1300 of Regulation S-K. Subpart 1300 of Regulation S-K requires us to disclose our mineral (coal) resources, which we have none, in addition to our mineral (coal) reserves, as of the end of our most recently completed fiscal year both in the aggregate and for each of our individually material mining properties. As used in this Annual Report on Form 10-K, the terms “mineral resources,” “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 (QP) that the mineral resources can be the basis of an economically viable project. You 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 SEC. Internal qualified person(s) have estimated the Company’s mineral reserves and mineral resources based on geologic data, coal ownership (control) information, and current and/or proposed operating plans. Periodic updates occur to mineral reserve and mineral resource estimates attributable to revised mine plans, new exploration data, depletion from coal production, property acquisitions or dispositions, and/or other geologic or mining data. Sunrise’s estimates of mineral reserves are proven and probable reserves that could be extracted or produced at the time of the reserve determination, economically, legally, and after considering all material modifying factors. Modifications or updates of the estimates of the Company’s mineral reserves is limited to qualified geologists and mining engineers. All modifications or updates of the estimates of recoverable coal reserves are documented. The John T. Boyd Company, a qualified person firm, has assessed the Company’s estimates of mineral reserves and mineral resources and supporting information. Based upon the review, John T. Boyd Company provided modification to the Company’s estimates of mineral reserves where warranted. The information that follows is derived, for the most part, from, and in some instances is extracted from, the Oaktown Mining Complex technical report summary (“TRS”) from John T. Boyd Company dated October, 2023 in accordance with Subpart 1300 of Regulation S-K (Coal Resources and Coal Reserves, Oaktown Mining Complex) attached hereto as Exhibit 99.1 to this Form 10-K; and a letter, dated January, 29, 2024, from John T. Boyd Company providing an update of estimated coal reserves at the Oaktown Mining Complex as of December 31, 2023, attached as Exhibit 99.2 to this Form 10-K. The Oaktown Mining Complex is the Company’s individually material property. Sections of the following information provided herein do not fully describe assumptions, qualifications, and procedures. Reference should be made to the full text of the TRS which is made a part of this Annual report on Form 10-K and incorporated hereby by reference. The Oaktown Mining Complex TRS was prepared by the John T. Boyd Company in compliance with the Item 60(b)(96) and subpart 1300 of Regulation S-K. The Company hereby incorporates by reference Section 6.3 "Coal Reserves" from the TRS, attached as Exhibit 99.1 to this Form 10-K, as to the mineral price, cut-off grade, and metallurgical recovery factors utilized in John T. Boyd Company's preparation of the mineral reserve estimates. The Company hereby incorporates the letter, dated January 29, 2024, from John T. Boyd Company, attached as Exhibit 99.2 to this Form 10-K, providing an update of the Company's mineral reserves at the Oaktown Mining Complex as of December 31, 2023 and including a comparison of the Company's mineral reserves at the Oaktown Mining Complex as of December 31, 2023 and as of December 31, 2022. The following table provides a summary of all of the Company’s mineral reserves determined by the John T. Boyd Company as of the end of the fiscal year ended December 31, 2023: SUMMARY MINERAL RESERVES AT END OF THE FISCAL YEAR ENDED DECEMBER 31, 2023 Mineral Reserves (tons in millions) Proven Probable Total Oaktown Mining Complex Oaktown Fuels No. 1 Mine 29.9 4.2 34.1 Oaktown Fuels No. 2 Mine 20.4 6.2 26.6 Total 50.3 10.4 60.7 31 Table of Contents Oaktown Mining Complex The Oaktown Mining Complex is a coal mining and processing operation located in Knox and Sullivan counties, Indiana, and Crawford and Lawrence counties, Illinois. The following figure shows the general location of the Oaktown Mining Complex: 32 Table of Contents Comprising 118 square miles within the ILB coal-producing region of the mid-western U.S., the Oaktown Mining Complex is one of the largest underground Room-and-Pillar (R&P) coal mining complexes in North America. The Oaktown Mining Complex operations currently consist of two active underground mines - Oaktown Fuels No. 1 Mine and Oaktown Fuels No. 2 Mine - and related infrastructure. Geographically, the Oaktown Complex Coal Preparation Plant is located at approximately 28°51’24.7” N latitude and 87°25’30.9” W longitude. Within the Oaktown Mining Complex area and immediate vicinity, our Company controls approximately 75,000 acres of mineral rights. This control exists as a complex collection of leases that apply to more than 2,000 tracts. Each of which range from less than an acre to several hundred acres in size. Ownership of the surface rights and the mineral rights is often severed for the properties and the estates are often fractions, in which mineral rights are split between several owners. The Company and its predecessors have acquired the necessary rights to support development and operations through purchase or lease agreements with predominately private owners or entities. As part of the Oaktown Mining Complex, the Company controls surface rights through fee simple ownership for over 1,700 permitted acres. Upon those acres resides the surface facilities for mine accesses, processing, storing, shipping, and refuse disposal facilities (i.e., refuse impoundment site and fine refuse injection sites). Our involvement with the Oaktown Mining Complex dates to 2014 with the acquisition of Oaktown Fuels No. 1 and No. 2 Mines from Vectren Fuels. Each mine of the Oaktown Mining Complex utilizes R&P mining (employing Continuous Miners, or CM) for primary production. This mining method is highly productive and commercially demonstrated; it has been one of the primary approaches to underground mining the Indiana V Seam for decades. Oaktown Mining Complex has utilized this mining method since the inception of each operation. To date, Oaktown Mining Complex has produced a combi ned 71.1 millio n tons of clean coal. The complex is configured to operate up to 7 CM sections, with an annual production target of approximately 4.5 million product tons. The Oaktown Complex Coal Preparation Plant serves as the coal washing and shipment facility for the Oaktown Mining Complex’s two R&P mines. The plant was commissioned in 2009 to wash coal by the Oaktown Fuels No. 1 Mine. The Oaktown Complex Coal Preparation Plant's processing capacity was upgraded to 1,800 raw tons-per-hour (TPH) from its previous 1,600 raw TPH. Product coal from the Oaktown Mining Complex is transported to its customer base via rail, truck, or a combination of both. The Oaktown Complex Coal Preparation Plant is served by both the CSX Railroad and Indiana Railroad (INRD) via a rail spur and rail loop that connects the complex with the mainline rail just north of Oaktown, Indiana. Additionally, the Oaktown Complex Coal Preparation Plant can facilitate the loading of trucks for direct transport to select customers, or to our transload facility in Princeton, Indiana serviced by the Norfolk Southern (NS) Railroad. Sources of electrical power, water, supplies, and materials are readily available. Electrical power is provided to the mines and facilities by regional utility companies. Water is supplied by public water services, surface impoundments, or water wells. Multiple permits are required by federal and state law for underground mining, coal preparation and related facilities, and other incidental activities. All necessary permits to support current operations are in place or pending approval. New permits or permit revisions may be necessary from time to time to facilitate future operations. Given sufficient time and planning, we should be able to secure new permits, as required, to maintain our planned operations within the context of the current regulations. Permits generally require that the Company post a performance bond in an amount established by the regulator program to: (1) provide assurance that any disturbance or liability created during mining operation is properly mitigated, and (2) assure that all regulation requirements of the permit are fully satisfied. We hold surety bonds of $9.9 million to cover obligations relating to mining and reclamation, road repair, etc. at the Oaktown Mining Complex. 33 Table of Contents Additional information is provided in the following table regarding the Oaktown Mining Complex mineral reserves: OAKTOWN MINING COMPLEX Recoverable Coal Reserves as of December 31, 2023 and 2022 As Received As Received Heat SO2 Value Content (Btu/lb) (lbs/MMBtu) Owned Leased Recoverable Coal Reserves (As-Received) Mine/Reserve Approximate Approximate (%) (%) Proven Probable 12/31/2023 12/31/2022 Oaktown Mining Complex Oaktown Fuels No. 1 Mine 11,527 6.0 — 100.0 29.9 4.2 34.1 36.7 Oaktown Fuels No. 2 Mine 11,518 5.4 — 100.0 20.4 6.2 26.6 29.6 Total 50.3 10.4 60.7 66.3 Oaktown Fuels No. 1 Mine As of December 31, 2023, the assigned and accessible reserve base for the Oaktown Fuels No. 1 Mine contains 34.1 million tons of recoverable Indiana V seam coal, of which 34.1 million tons are currently permitted. The reserve contains saleable tons which average heating content of approximately 11,527 Btu per pound with approximately 6.0 pounds of sulfur dioxide per MMBtu on an as-received basis. Access to the Oaktown Fuels No. 1 Mine is via a 90-foot-deep box cut and a 2,200-foot long slope, which facilitates the egress of coals being mined in excess of 375 feet below the surface. Since beginning first commercial coal production in 2009, the mine workings have substantially grown, and an additional mine access (elevator) was constructed for employee and supply ingress/egress closer to the active production faces. Oaktown Fuels No. 2 Mine As of December 31, 2023, the assigned and accessible reserve base for the Oaktown Fuels No. 2 Mine contains 26.6 million tons of recoverable Indiana V seam coal, of which 21.3 million tons are currently permitted. The reserve contains saleable tons which average heating content of approximately 11,518 Btu per pound with approximately 5.4 pounds of sulfur dioxide per MMBtu on an as-received basis. Access to the Oaktown Fuels No. 2 Mine is via an 80-foot-deep box cut and 2,600-foot long slope, which facilitates the egress of coals being mined in excess of 400 feet below the surface. Since beginning first commercial coal production in 2013 the mines workings have substantially grown and, during 2021, an additional mine access (elevator) was constructed for employee and supply ingress/egress closer to the active production faces. Tonnages are reported on a clean recoverable basis with average long-term pricing based on available third-party forecasts and historical pricing adjusted for quality at the end of 2023, with the coal sales price estimated over the life of the reserve averaging approximately $47 (ranging from $42.50 to $64 per short ton), which are the coal sales prices used by John T. Boyd Company to estimate the amount of coal mineral reserves for the Oaktown Fuels No. 1 Mine and Oaktown Fuels No. 2 Mine as listed above. Coal sales prices vary based on coal quality, access to transportation, and other factors at each location. All reserves are classified as underground mineable in the production stage. The Company hereby incorporates by reference (i) the TRS, attached as Exhibit 99.1 to this Form 10-K, including Section 6.3 thereof titled "Coal Reserves", as to the recoverable coal reserves reported above for the Oaktown Fuels No. 1 Mine and Oaktown Fuels No. 2 Mine; and (ii) letter, dated January 29, 2024, from John T. Boyd Company, attached as Exhibit 99.2 to this Form 10-K, providing an update of the Company's mineral reserves at the Oaktown Mining Complex as of December 31, 2023 and including a comparison of the Company's mineral reserves at the Oaktown Mining Complex as of December 31, 2023 and as of December 31, 2022. Historical production for our Oaktown Mining Complex during the years ended December 31, 2023, 2022, and 2021 is provided in the following table: Annual Saleable Production Tons (Million Tons) Mine/Reserve 2023 2022 2021 Oaktown Mining Complex Oaktown Fuels No. 1 Mine 3.9 3.9 3.5 Oaktown Fuels No. 2 Mine 2.5 2.5 2.1 Total Oaktown Mining Complex Production 6.4 6.4 5.6 34 Table of Contents Other Properties The Company holds other recoverable coal reserves in the ILB, which are not deemed individually material. Ace in the Hole Mine (Ace) (surface) – Assigned Ace Mine is now depleted. Remaining inventory of coal and base was moved to our Carlisle and Oaktown wash plants in early 2023. Reclamation resumed in the Spring of 2023. Phase 1 and 2 reclamation is substantially complete as of December 31, 2023. Prosperity (surface) – Assigned The Prosperity mine contains approximately 0.2 million tons of low sulfur coal needed to blend with our Oaktown coal to reduce the sulfur content to a salable level for Southeastern US markets. The mine opened in the summer of 2022. The mine produced coal and reclaimed the slurry pond and refuse pile left by the Prosperity underground mine. Additional reserves are in the area that may extend the life of this mine. In February 2024, this mine was temporarily idled. Freelandville (surface) – Assigned Sunrise is a contract miner at the Freelandville East Mine Center Pit, Permit No. S 358. Sunrise had an option through May 31, 2023 to assume the permit that contained approximately 1.7 million tons of salable coal with an additional 0.6 million available. Mining started in the fall of 2022 and continued through April 2023. In February 2024, this mine was idled. Our Coal Contracts In 2023, on a segment basis Sunrise sold 6.9 million tons of coal to 11 power plants in five different states across six different customers. During 2023, on a segment basis we derived 94% of our revenue from five customers (11 power plants), with each of the five customers representing at least 10% of our coal sales. During 2022, on a segment basis we derived 90% of our revenue from five customers (10 power plants), with each of the five customers representing at least 10% of our coal sales. Significant customers in 2023 include Vectren Corporation, a wholly-owned subsidiary of CenterPoint Energy (NYSE: CNP), Orlando Utility Commission (OUC), Alcoa Power Generating, Inc., a subsidiary of Alcoa Corporation (NYSE: AA), Alabama Power, a subsidiary of Southern Company (NYSE: SO), and Duke Energy Corporation (NYSE: DUK). Of our 2023 sales, on a segment basis 33%, excluding Merom Power Plant, were derived to locations in the State of Indiana. 35 Table of Contents Our future coal commitments are as follows: 3rd Party Merom Power Plant Contracted Contracted Estimated tons tons Priced Year (millions)* (millions)* Total per ton 2024 3.4 1.5 4.9 $ 53.91 2025 - 2028 (total) 5.8 9.2 15.0 ** Total 9.2 10.7 19.9 ______________________ * Contracted tons are subject to adjustment in instances of force majeure and exercise of customer options to either take additional tons or reduce tonnage if such option exists in the customer contract. ** Unpriced or partially priced committed tons As of December 31, 2023, we are committed to supplying third-party customers up to a maximum of 9.2 million tons of coal through 2027 of which 6.2 million tons are priced. We are committed to supplying coal to Merom Power Plant up to a maximum of 10.7 million tons of coal through 2028. All committed tons to Merom are priced. Based on the contracted tons described above, we anticipate our mines will need to produce at a 4.5 million ton annualized pace for the foreseeable future to meet the Merom plant and third-party market demand. We expect to continue selling a significant portion of our coal under supply agreements with terms of one year or longer. Typically, customers enter into coal supply agreements to secure reliable sources of coal at predictable prices while we seek stable sources of revenue to support the investments required to open, expand and maintain, or improve productivity at the mines needed to supply these contracts. The terms of coal supply agreements result from competitive bidding and extensive negotiations with customers. Some utility customers have proposed shuttering certain plant units or entire plants in the coming years. It remains to be seen whether these plans will be implemented. Liquidity and Capital Resources As set forth in our Consolidated Statements of Cash Flows, cash provided by operations was $59.4 million and $54.2 million for the years ended December 31, 2023 and 2022 respectively. Operating cash flow increased due to an increase in operating margins at our coal mines brought on by the addition of higher priced contracts. This was offset by lower margins from our power plant and a decrease in working capital. Our capital expenditure budget for 2024 is $43 million, of which the majority is for maintenance capex. Of the $43 million, the budget for coal operations is $25 million and the budget for electric operations is $18 million. As of December 31, 2023, our bank debt was $91.5 million. On March 13, 2023, we executed an amendment to our credit agreement with PNC Bank, National Association (in its capacity as administrative agent, “PNC”), administrative agent for our lenders under our credit agreement. The primary purpose of the amendment was to convert $35 million of the revolver into a new term loan with a maturity of March 31, 2024, and extend the maturity date of the revolver to May 31, 2024. On August 2, 2023, we executed an additional amendment with PNC. The primary purpose of the amendment was to convert $65 million of the existing outstanding debt into a new term loan with a maturity of March 31, 2026, and enter into a revolver of $75 Million with a maturity date of July 31, 2026. Principal payments for the term loan were $3.3 million per quarter for September 30, 2023, and December 31, 2023, and $6.5 million per quarter starting March 31, 2024, through maturity. The effect of the amendment on our future cash flow is to extend the maturity date of $65.0 million of our outstanding debt to May 31, 2026, and our revolver to July 31, 2026. We expect cash from operations generated primarily by our expected higher coal margins in 2023 to fund our capital expenditures and our debt service. See Note 4 to our consolidated financial statements for additional discussion about our bank debt and related liquidity. 36 Table of Contents Off-Balance Sheet Arrangements Other than our surety bonds for reclamation, we have no material off-balance sheet arrangements. We have recorded the present value of reclamation obligations of $16.6 million, including $5.2 million at Merom, presented as asset retirement obligations (ARO) in our accompanying balance sheets. In the event we are not able to perform reclamation, we have surety bonds in place totaling $37.5 million to cover ARO. Capital Expenditures (capex) For the year ended December 31, 2023, our capex was $75.4 million allocated as follows (in millions): Oaktown – maintenance capex $ 36.2 Oaktown – investment 18.3 Prosperity mine 0.8 Freelandville mine 1.2 Merom plant 18.8 Other 0.1 Capex per the Consolidated Statements of Cash Flows $ 75.4 Results of Operations Presentation of Segment Information Our operations are divided into two primary reportable segments: Coal Operations and Electric Operations. The remainder of our operations, which are not significant enough on a stand-alone basis to warrant treatment as an operating segment, are presented as “Corporate and Other” within the Notes to the Consolidated Financial Statements and primarily are comprised of unallocated corporate costs and activities, including a 50% interest in Sunrise Energy, LLC, a private gas exploration company with operations in Indiana, which we account for using the equity method, and our wholly-owned subsidiary Summit Terminal LLC, a logistics transport facility located on the Ohio River. Coal Operations 2023 2022 OPERATING REVENUES: $ 435,425 $ 293,344 EXPENSES: Operating expenses 311,041 236,416 Depreciation, depletion and amortization 48,365 43,612 Asset retirement obligations accretion 1,228 1,010 Exploration costs 904 651 General and administrative 10,287 7,919 Total operating expenses 371,825 289,608 INCOME (LOSS) FROM OPERATIONS $ 63,600 $ 3,736 Operating revenues from coal operations increased 48% over 2022 due in large part to unprecedented increases in natural gas prices. As a result, higher priced contracts sold in the summer of 2022 and delivered in Q4 of 2022 through all of 2023 increased our average sales price by $16.90 per ton from 2022. We also sold 581,000 additional tons over 2022 at the higher average price due to lower inventories and the higher gas prices. Operating expenses increased, however, by ~$7.50 per ton. The addition of the higher cost Freelandville and Prosperity surface mines as well as significant inflationary pressures and geological conditions contributed significantly to the increased costs. 37 Table of Contents Depreciation, depletion, and amortization increased 11%. The majority of this change is due to significant capital additions in the coal division. General and administrative expenses increased 30% over 2022 due in large part to additional professional fees related to bank refinancing and additional audit requirements. Increased wages due to bonuses and incentives to retain and attract talent also contributed to the increased costs. Electric Operations 2023 2022 OPERATING REVENUES: $ 268,341 $ 66,316 EXPENSES: Operating expenses 231,560 29,608 Depreciation, depletion and amortization 18,739 3,117 Asset retirement obligations accretion 576 — General and administrative 4,914 2,086 Total operating expenses 255,789 34,811 INCOME FROM OPERATIONS $ 12,552 $ 31,505 A comparative discussion is not relevant as the Electric Operations did not begin until the Merom Acquisition closed in October 2022. Operating revenue is derived from sales to the Midcontinent Independent System Operator ("MISO") wholesale market and a power purchase agreement (PPA) signed with Hoosier in conjunction with the Merom Acquisition. The PPA included sales at fixed prices which were below market prices at the date we entered into the agreement. The power purchase agreement expires in 2025 and requires us to provide a fixed amount of power over the term of the agreement. As a result of the below market contract, we recorded a contract liability at the close of the acquisition totaling $184.5 million that will be amortized over the term of the agreement as the contract is fulfilled. For the years ended December 31, 2023, we recorded $70.5 million and $23.3 million, respectively of revenue as a result of amortizing the contract liability. Operating expenses include coal purchased under an agreement signed with Hoosier in conjunction with the Merom acquisition at fixed prices which were below market prices at the date we entered into the agreement. The coal purchase agreement expired in May 2023 and required us to purchase a fixed amount of coal over the term of the agreement. As a result of the below market contract, we recorded a contract asset at the close of the acquisition totaling $34.3 million that was amortized over the term of the agreement as the contract was fulfilled. The contract asset was fully amortized with an asset value of $0 as of December 31, 2023. For the years ended December 31, 2023 and 2022, we recorded $30.7 million and $3.6 million respectively in additional operating expense for coal purchased and used. 38 Table of Contents The following tables presenting our quarterly results of operations should be read in conjunction with the consolidated financial statements and related notes included in Item 8 of this Form 10-K. We have prepared the unaudited information on the same basis as our audited consolidated financial statements. Our operating results for any quarter are not necessarily indicative of results for any future quarters or for a full year. The tables present our unaudited quarterly results of operations for the eight quarters ended December 31, 2023, and include all adjustments, consisting only of normal recurring adjustments, that we consider necessary for fair presentation of our consolidated operating results for the quarters presented. Mar-31 Jun-30 Sep-30 Dec-31 2023 2023 2023 2023 Total 2023 SALES AND OPERATING REVENUES: Coal sales $ 94,602 $ 88,574 $ 97,420 $ 81,330 $ 361,926 Electric sales 92,392 71,017 67,403 37,115 267,927 Other revenues 1,340 1,603 945 739 4,627 Total revenue 188,334 161,194 165,768 119,184 634,480 EXPENSES: Operating expenses 133,521 115,420 119,042 105,407 473,390 Depreciation, depletion and amortization 17,976 17,169 16,230 15,836 67,211 Asset retirement obligations accretion 451 461 468 424 1,804 Exploration costs 206 305 171 222 904 General and administrative 6,947 5,595 6,054 7,563 26,159 Total operating expenses 159,101 138,950 141,965 129,452 569,468 INCOME (LOSS) FROM OPERATIONS 29,233 22,244 23,803 (10,268 ) 65,012 Bank debt and other interest (3,899 ) (3,541 ) (3,030 ) (3,241 ) (13,711 ) Loss on extinguishment of debt — — (1,491 ) — (1,491 ) Equity method investment income 69 (217 ) (177 ) (227 ) (552 ) INCOME (LOSS) BEFORE INCOME TAXES 25,403 18,486 19,105 (13,736 ) 49,258 INCOME TAX EXPENSE (BENEFIT): Current 432 61 (178 ) (479 ) (164 ) Deferred 2,920 1,510 3,208 (3,009 ) 4,629 Total income tax expense (benefit) 3,352 1,571 3,030 (3,488 ) 4,465 NET INCOME (LOSS) $ 22,051 $ 16,915 $ 16,075 $ (10,248 ) $ 44,793 NET INCOME (LOSS) PER SHARE: Basic $ 0.67 $ 0.51 $ 0.49 $ (0.31 ) $ 1.35 Diluted $ 0.61 $ 0.47 $ 0.44 $ (0.31 ) $ 1.25 WEIGHTED AVERAGE SHARES OUTSTANDING: Basic 32,983 33,137 33,140 33,245 33,133 Diluted 36,740 36,708 36,848 33,245 36,827 39 Table of Contents Mar-31 Jun-30 Sep-30 Dec-31 2022 2022 2022 2022 Total 2022 SALES AND OPERATING REVENUES: Coal sales $ 57,010 $ 64,161 $ 83,562 $ 84,643 $ 289,376 Electric sales — — — 66,252 66,252 Other revenues 1,897 1,768 1,522 1,176 6,363 Total revenue 58,907 65,929 85,084 152,071 361,991 EXPENSES: Operating expenses 54,601 51,394 64,557 96,056 266,608 Depreciation, depletion and amortization 9,531 11,164 11,187 14,993 46,875 Asset retirement obligations accretion 246 250 255 259 1,010 Exploration costs 57 215 121 258 651 General and administrative 3,149 3,722 3,569 5,977 16,417 Total operating expenses 67,584 66,745 79,689 117,543 331,561 INCOME (LOSS) FROM OPERATIONS (8,677 ) (816 ) 5,395 34,528 30,430 Bank debt and other interest (1,710 ) (1,770 ) (2,360 ) (2,438 ) (8,278 ) Amortization and swap related interest (74 ) (567 ) (995 ) (1,098 ) (2,734 ) Equity method investment income 150 188 168 (63 ) 443 INCOME (LOSS) BEFORE INCOME TAXES (10,311 ) (2,965 ) 2,208 30,929 19,861 INCOME TAX EXPENSE (BENEFIT): Current — — — — — Deferred (177 ) 421 596 916 1,756 Total income tax expense (benefit) (177 ) 421 596 916 1,756 NET INCOME (LOSS) $ (10,134 ) $ (3,386 ) $ 1,612 $ 30,013 $ 18,105 NET INCOME (LOSS) PER SHARE: Basic $ (0.33 ) $ (0.11 ) $ 0.05 $ 0.91 $ 0.57 Diluted $ (0.33 ) $ (0.11 ) $ 0.05 $ 0.83 $ 0.55 WEIGHTED AVERAGE SHARES OUTSTANDING: Basic 30,785 30,785 32,983 32,983 32,043 Diluted 30,785 30,809 33,268 36,428 33,649 40 Table of Contents Quarterly coal sales and cost data follow on a segment basis (in 000’s, except for per ton data and wash plant recovery percentage): All Mines 1st 2023 2nd 2023 3rd 2023 4th 2023 T4Qs Tons produced 2,006 1,723 1,594 1,331 6,654 Tons sold 1,693 1,714 2,054 1,461 6,922 Coal sales $ 94,602 $ 112,171 $ 134,400 $ 91,714 $ 432,887 Average price per ton $ 55.88 $ 65.44 $ 65.43 $ 62.77 $ 62.54 Wash plant recovery in % 70 % 67 % 65 % 62 % Operating costs $ 65,700 $ 71,168 $ 95,592 $ 78,581 $ 311,041 Average cost per ton $ 38.81 $ 41.52 $ 46.54 $ 53.79 $ 44.94 Margin $ 28,902 $ 41,003 $ 38,808 $ 13,133 $ 121,846 Margin per ton $ 17.07 $ 23.92 $ 18.89 $ 8.99 $ 17.60 Capex $ 12,639 $ 14,445 $ 11,570 $ 17,867 $ 56,521 Maintenance capex $ 7,778 $ 9,754 $ 7,938 $ 13,567 $ 39,037 Maintenance capex per ton $ 4.59 $ 5.69 $ 3.86 $ 9.29 $ 5.64 All Mines 1st 2022 2nd 2022 3rd 2022 4th 2022 T4Qs Tons produced 1,397 1,762 1,663 1,721 6,543 Tons sold 1,377 1,595 1,705 1,664 6,341 Coal sales $ 57,010 $ 64,161 $ 83,563 $ 84,641 $ 289,375 Average price per ton $ 41.40 $ 40.23 $ 49.01 $ 50.87 $ 45.64 Wash plant recovery in % 67 % 71 % 69 % 68 % Operating costs $ 54,443 $ 50,776 $ 63,876 $ 67,319 $ 236,414 Average cost per ton $ 39.54 $ 31.83 $ 37.46 $ 40.46 $ 37.28 Margin $ 2,567 $ 13,385 $ 19,687 $ 17,322 $ 52,961 Margin per ton $ 1.86 $ 8.39 $ 11.55 $ 10.41 $ 8.35 Capex $ 9,082 $ 13,821 $ 15,096 $ 12,368 $ 50,367 Maintenance capex $ 4,481 $ 7,600 $ 6,625 $ 5,748 $ 24,454 Maintenance capex per ton $ 3.25 $ 4.76 $ 3.89 $ 3.45 $ 3.86 Quarterly electric sales and cost data (in thousands, except per MWh data) are provided below. Fixed costs in the table are considered "non-GAAP" and are a component of operating expenses, the most comparable GAAP measure. We consider fixed costs to be costs associated with the plant whether or not the plant is in operation. 1st 2023 2nd 2023 3rd 2023 4th 2023 2023 MWh sold 1,262 1,043 1,307 612 4,224 Capacity revenue $ 15,970 $ 17,155 $ 13,012 $ 10,018 $ 56,155 Delivered energy and PPA revenue 76,422 53,862 54,391 27,097 211,772 Total electric sales 92,392 71,017 67,403 37,115 267,927 Less amortization of contract liability (33,347 ) (19,555 ) (10,281 ) (7,347 ) (70,530 ) Total electric sales less amortization of contract liability $ 59,045 $ 51,462 $ 57,122 $ 29,768 $ 197,397 Average price/MWh of delivered energy and PPA revenue less amortization of contract liability $ 34.13 $ 32.89 $ 33.75 $ 32.27 $ 35.18 Operating expenses (on a segment basis) $ 67,682 $ 55,996 $ 64,172 $ 43,710 $ 231,560 Less fixed costs (12,807 ) (11,693 ) (11,858 ) (22,259 ) (58,617 ) Less amortization of contract asset (17,778 ) (12,962 ) - - (30,740 ) Operating expenses less fixed costs and amortization of contract asset $ 37,097 $ 31,341 $ 52,314 $ 21,451 $ 142,203 Average variable cost/MWh of operating expenses less fixed costs and amortization of contract asset $ 29.40 $ 30.05 $ 40.03 $ 35.05 $ 33.44 Energy and PPA margin less fixed costs and amortization of contract asset and liabilities $ 5,978 $ 2,966 $ (8,204 ) $ (1,701 ) $ (961 ) Energy & PPA margin/MWh less fixed costs amortization of contract asset and liabilities $ 4.74 $ 2.84 $ (6.28 ) $ (2.78 ) $ (0.23 ) Critical Accounting Estimates We believe that the estimates of coal reserves, asset retirement obligation liabilities, deferred tax accounts, valuation of inventory, treatment of business combinations, and the estimates used in impairment analysis are our critical accounting estimates. The reserve estimates are used in the depreciation, depletion and amortization calculations and our internal cash flow projections. If these estimates turn out to be materially under or over-stated, our depreciation, depletion and amortization expense and impairment test may be affected. The process of estimating reserves is complex, requiring significant judgment in the evaluation of all available geological, geophysical, engineering and economic data. The reserve estimates are prepared by professional engineers, both internal and external, and are subject to change over time as more data becomes available. Changes in the reserves estimates from the prior year were nominal. SMCRA and similar state statutes require, among other things, that surface disturbance be restored in accordance with specified standards and approved reclamation plans. SMCRA requires us to restore affected surface areas to approximate the original contours as contemporaneously as practicable with the completion of surface mining operations. Federal law and some states impose on mine operators the responsibility for replacing certain water supplies damaged by mining operations and repairing or compensating for damage to certain structures occurring on the surface as a result of mine subsidence, a consequence of longwall mining and possibly other mining operations. Obligations are reflected at the present value of their future cash flows. We reflect accretion of the obligations for the period from the date they are incurred through the date they are extinguished. The ARO assets are amortized using the units-of-production method over estimated recoverable (proven and probable) reserves. We use credit-adjusted risk-free discount rates ranging from 7% to 10% to discount the obligation, inflation rates anticipated during the time to reclamation, and cost estimates prepared by its engineers inclusive of market risk premiums. Activities include reclamation of pit and support acreage at surface mines, sealing portals at underground mines, and reclamation of refuse areas and slurry ponds. Accretion expense is recognized on the obligation through the expected settlement date. On at least an annual basis, we review our entire reclamation liability and make necessary adjustments for permit changes as granted by state authorities, changes in the timing and extent of reclamation activities, and revisions to cost estimates and productivity assumptions, to reflect current experience. Any difference between the recorded amount of the liability and the actual cost of reclamation will be recognized as a gain or loss when the obligation is settled. We have analyzed our filing positions in all of the federal and state jurisdictions where we are required to file income tax returns, as well as all open tax years in these jurisdictions. We identified our federal tax return and our Indiana state tax return as “major” tax jurisdictions. We believe that our income tax filing positions and deductions would be sustained on audit and do not anticipate any adjustments that will result in a material change to our consolidated financial position. We have not taken any significant uncertain tax positions and our tax provision and returns are prepared by a large public accounting firm with significant experience in energy related industries. Changes to the estimates from reported amounts in the prior year were not significant. Inventory is valued at lower of cost or net realizable value (NRV). Anticipated utilization of low sulfur, higher-cost coal from our Freelandville, and Prosperity mines has the potential to create NRV adjustments as our estimated needs change. The NRV adjustments are subject to change as our costs may fluctuate due to higher or lower production and our NRV may fluctuate based on sales contracts we enter into from time to time. There were no significant changes to our NRV adjustment estimates from the prior year. 41 Table of Contents We account for business acquisitions as either asset acquisitions or business combination depending on the circumstances as outlined in ASC 805-50. For acquisitions accounted for as a business combination, we record the assets acquired, including identified intangible assets and liabilities assumed at their fair value. For acquisitions accounted for as asset acquisitions, we allocate the fair value of consideration exchanged in the transaction to each of the acquired assets based upon their relative fair value. Fair value in many instances involves estimates based on third-party valuations, such as appraisals, or internal valuations based on discounted cash flow analyses or other valuation techniques. Those estimates are subject to a high degree of uncertainty, thus we typically will retain professionals in the relevant industries of the acquiree to assist us with our analysis and valuations. See “ Item 8. Finan cial Statements - Note 15 - Acquisition” for more information on the Merom Acquisition. Long-lived assets used in operations are depreciated and assessed for impairment annually or whenever changes in facts and circumstances indicate a possible significant deterioration in future cash flows is expected to be generated by an asset group. For impairment assessments, management groups individual assets based on a judgmental assessment of the lowest level for which there are identifiable cash flows that are largely independent of the cash flows of other groups of assets. The determination of the lowest level of cash flows is largely based on nature of production, common infrastructure, common sales points, common regulation and management oversight to make such determinations. These determinations could impact the determination and measurement of a potential asset impairment. Management evaluates assets for impairment through an established process in which changes to significant assumptions such as prices, volumes and future development plans are reviewed. If, upon review, the sum of the undiscounted pre-tax cash flows is less than the carrying value of the asset group, the carrying value is written down to estimated fair value. Because there usually is a lack of quoted market prices for long-lived assets, the fair value of impaired assets is typically determined based on the present values of expected future cash flows using discount rates believed to be consistent with those used by principal market participants. The expected future cash flows used for impairment reviews and related fair value calculations are typically based on judgmental assessments of future volumes, commodity prices, operating costs and capital investment plans, considering all available information at the date of review. Changes to any of the market-based assumptions can significantly affect estimates of undiscounted and discounted pre-tax cash flows and impact the recognition and amount of impairments. 42 Table of Contents