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Item 7. Management’s Discussion and Analysis

2025-03-17 compared with 2024-03-14 · 348 added, 224 removed, 246 unchanged (70% of the section changed)

1 unchanged sentence

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.

The following analysis includes a discussion of metrics on a per mega-watt hour (MWh) and per ton and basis as derived from the consolidated financial statements, which are considered non-GAAP measurements.

These metrics are significant factors in assessing our operating results and profitability.

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.

Our wholly owned subsidiary Hallador Power, operates our Merom Power Plant ("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.

We also mine coal in the State of Indiana through our wholly-owned subsidiary Sunrise Coal, LLC (“Sunrise”), serving the electric power generation industry.

During the fourth quarter of 2024, we completed our review of the coal mining facilities and future mining plans.

The impairment analysis was based upon our finalized coal mining operating plans, market driven pricing and cost trends.

As part of that analysis, we determined the carrying amount of our coal mining long-lived asset group was not recoverable and recorded a non-cash, long-lived asset impairment charge of $215.1 million in the fourth quarter of 2024.

See “Note 19 – Impairment of Coal Properties” to the Consolidated Financial Statements in this Form 10-K for further information on the impairment analysis.

Our business is organized based on the services and products we provide in two segments:

(i) Electric Operations and (ii) Coal Operations.

The Chief Operating Decision Maker (“CODM”), who is the Company’s Chief Executive Officer, reviews and assesses operating performance measures related to our Electric Operations and our Coal Operations segments.

In addition to these reportable segments, the Company has a “Corporate and Other and Eliminations” category, which is not significant enough, on a stand-alone basis, to be considered an operating segment.

Corporate and Other and Eliminations primarily consist of unallocated corporate costs and activities, including a 50% interest in Sunrise Energy LLC and Oaktown Gas, LLC, which are accounted for using the equity method.

Throughout 2024, we made progress on transitioning Hallador Energy from a bituminous coal producer to an integrated independent power producer (“IPP”).

This strategic transition has been a deliberate response to market signals and what we believe to be the superior economics of the IPP business model.

As such, our focus remains on maximizing the value of Merom while actively seeking opportunities to acquire additional dispatchable generators.

We have also prioritized building strong relationships with counterparties to secure favorable terms for collateral, enabling us to effectively leverage forward power sales in 2025 to offset pricing volatility in the spot market.

This approach enhances our financial flexibility and strengthens our position in the evolving energy market.

In the fall of 2024, we reached a key milestone in our IPP transformation by signing a non-binding term sheet with a leading global data center developer for the supply of a significant portion of Merom's output of capacity and energy for well over a decade.

As evidenced by our announcement of an exclusivity agreement with this development partner in January 2025, we are continuing to make progress as we seek to finalize a definitive agreement.

As we have previously disclosed, the exclusivity period runs through the beginning of June 2025, in exchange for payments from the developer to Hallador Power of up to $5.0 million, depending on if and when a definitive agreement is finalized.

This type of deal is complex and involves multiple parties, which adds time and challenges to negotiations.

Despite these challenges, we remain encouraged by our partners and the steady progress that we continue to make.

Our pursuit of this agreement further demonstrates our commitment towards forging a strategic partnership that we believe will create significant value for our shareholders for years to come.

The completion of this proposed transaction is subject to, among other matters, the negotiation and execution of definitive agreements and there can be no assurance that definitive agreements will be entered into or that the proposed transaction will be consummated on the terms or timeframe currently contemplated, or at all.

We continue to witness the prevalent industry trend of retiring dispatchable generators, including coal, in favor of non-dispatchable resources such as wind and solar.

We believe this transition from dispatchable to non-dispatchable generation made the attributes of our subsidiary, Hallador Power, much more valuable due to the enhanced reliability that we provide versus non-dispatchable generators.

However, we believe the retirement of coal-based generation and lower natural gas prices could reduce the demand for coal supply, potentially lowering the value of Sunrise.

During 2024, in response to declining coal demand, we reduced our coal production volume by approximately 40% and idled the higher cost surface mines.

This optimization of coal production reduced our operational cash cost structure and better aligned our coal strategy to primarily support our internal electric generation.

Merom can produce up to 6.0 million Mega-Watthours (“MWh”) annually.

The forward power price curves indicate that the margins earned on energy produced at Merom and the value of the accredited capacity sales assigned to the plant continues to increase.

We are seeing strong indications for both energy and capacity sales in 2025 and beyond, especially considering our negotiations related to supporting data center development within the State of Indiana.

In addition, while we largely held to our traditional approach of selling energy through bespoke bi-lateral agreements on a unit or plant contingent basis, during 2024 we sold a limited amount of power on a firm basis.

While we continue to limit these types of firm sales to mitigate risk and wait for higher priced contracts to take effect, we will strategically utilize them to smooth our exposure to the spot market.

This approach enables us to capture some of the episodic cash generation driven by demand from extreme weather and various other conditions stressing the power grid while limiting our exposure to periods of mild weather and lower demand.

In 2024, the ongoing surplus of natural gas in the market and mild weather patterns continued to moderate energy prices throughout the year and kept spot energy prices weak.

We began to see favorable pricing signals at the end of the fourth quarter of 2024 and subsequent to year-end.

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.

Oil and natural gas face transportation and storage challenges which increase price volatility.

The limitations of storing viable energy, coupled with non-dispatchable generation gaining market share in an environment where there is unpredictability in the weather, indicates to us that energy's price volatility is likely to increase over the next decade.

This volatility will keep the forward power price premium intact.

We are excited by the opportunity for Hallador Power to capture higher prices and energy volumes in 2025 and beyond compared to what we have historically achieved in our relatively short ownership tenure of Merom.

In 2024, we sold 4.2 million MWh at an average sales price of approximately $48.62 per MWh.

At the start of the year, we had 1.9 million MWh contracted, leaving us with significant exposure to the spot electricity market.

Heading into 2025, we have contracted approximately 4.3 million MWh at an average price of $37.24 per MWh, which should help to smooth our exposure to the spot market.

For 2026, we have already contracted 3.4 million MWh at $44.43 per MWh.

Following 2026, we are optimistic that we can sell energy at higher prices in support of data center development and/or to traditional wholesale customers in line with the indicators of a higher forward curve.

The tables included below highlight some of the revenue and margin improvements we have seen in our forward contracted power sales for 2025 and thereafter.

These tables do not include the significantly higher prices that we are expecting if we are able to finalize our agreements in support of data center development.

In addition to the transaction we are negotiating with Merom, we continue to evaluate other strategic transactions that could add durability, scale, and geographic expansion opportunities to our electric operations.

While these types of deals are limited and complex, we believe that Hallador is uniquely positioned to transform retiring and/or underperforming assets into future opportunities.

This will enable us to supply high demand end users, such as data centers and on-shored industrial customers, with minimal impact to retail consumers, unlike a traditional utility siphoning off consumer power to serve these types of large load end-users.

By continuing the operations of the dispatchable plants to support large load industrial users as the utilities transition to non-dispatchable generation, the new generation becomes additive to the already struggling grid rather than cannibalizing the overall reliability of what exists today.

We are optimistic about the potential to add to our strategic portfolio and the long-term benefits that such a transaction could produce for the Company, its shareholders and its customers.

This model for growth enables us to shift from transactional pricing related to plant acquisition, to traditional wholesale market pricing, and ultimately to the enhanced pricing associated with supporting data centers and other large load end users.

In the first quarter of 2024, we announced a restructuring of our Coal Operations to address the increase in costs we experienced at our mines.

See “Note 17 – Organizational Restructuring” to the Consolidated Financial Statements in this Form 10-K for further information.

We spent much of the year adjusting to this restructuring to optimize production, headcount, and strategy to best support our Electric Operations and our existing third-party coal contracts.

By reducing headcount, focusing production on our most profitable mines and units within those mines, and improving our infrastructure and processes within those favored units, we were able to both slow the impact of rapidly increasing costs and reduce costs to better support the continued operations of our mines.

Historically, Sunrise has produced between four and six million tons annually.

As we continue to optimize the mines in support of the plant, we expect to produce approximately 3.6 million tons of coal in 2025, with approximately 2.3 million tons produced directed to support our Electric Operations.

We have also secured supplemental coal from third party suppliers at favorable prices to diversify self-production supply risk and to provide us additional flexibility in our sales portfolio and to fulfill future sales obligations to third-parties and Merom as shown in the table below.

The optionality to obtain low-cost tons either internally or from third parties while capturing upward swings in the commodity markets for coal should further maximize margins while optimizing fuels costs at Merom.

We remain excited about the continued and deliberate transformation of Hallador from a commodity focused producer of coal to an IPP.

We believe this transition provides significant opportunity to capture the expanding margins of the energy markets and capitalize on the soaring demand for electricity.

We are pleased by the strong interest we continue to see from potential counterparties in our energy and capacity offerings, bolstered by Indiana’s efforts to attract data centers and other high-density power users through its business-friendly climate and favorable tax policies.

With the continued growth of our sales book, coupled with our ongoing focus to transition our operations to primarily electricity generation, we believe we are well positioned to materially strengthen our opportunities for growth and cash flow generation.

Solid Forward Sales Position - Segment Basis, Before Intercompany Eliminations

Priced tons - 3rd party (in millions)

Average price per ton - 3rd party

Priced tons (in millions) - Hallador Power

Average price per ton - Hallador Power

Contracted coal revenue (in millions)

Committed & unpriced tons (in millions) - 3rd party

Committed & unpriced tons (in millions) - Hallador Power

Total contracted tons (in millions)

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)

Contracted MWh (in millions)

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Contracted revenue (in millions)

% Energy Sold*

Average daily contracted capacity

% Capacity Contracted**

Average daily contracted capacity MWh

Average contracted capacity price per MWd

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Contracted Power revenue (in millions)

Contracted Power Revenue per MWh*

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)

TOTAL CONTRACTED REVENUE (IN MILLIONS)

* 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.

Priced tons - 3rd party (in millions)

Avg price per ton - 3rd party

Contracted coal revenue - 3rd party (in millions)

TOTAL CONTRACTED REVENUE (IN MILLIONS) - CONSOLIDATED

Priced tons - Intercompany (in millions)

Avg price per ton - Intercompany

Contracted coal revenue - Intercompany (in millions)

TOTAL CONTRACTED REVENUE (IN MILLIONS) - SEGMENT

Actual revenue related to solid forward sales positions may differ materially for various reasons, including price adjustment features for coal quality and cost escalations, volume optionality provisions and potential force majeure events.

Electric Operations

Internal Controls Disclosure

Our electric operations employ third party service providers for the day-to-day operations and maintenance of Merom as well as managing market transactions and optimizing plant dispatch.

We contract with Consolidated Asset Management Services (“CAMS”) to manage ongoing operations, maintenance and asset management functions at Merom.

CAMS provides an operations and maintenance program which includes daily management of plant performance, safety protocols and workforce management.

CAMS develops and implements predictive and preventative maintenance schedules designed to maximize plant availability and maintain compliance with environmental and regulatory standards.

In coordination with our engineering teams, CAMS identifies and manages capital projects that aim to improve operational efficiency and reduce long-term costs.

CAMS also provides performance monitoring and reporting.

CAMS provides regular reports on key performance indicators (“KPIs”) such as heat rates and forced outage rates to help us assess plant efficiency.

CAMS assists in ensuring adherence to local, state and federal regulations including

environmental rules and safety mandates.

We maintain oversight of CAMS through regular audits and performance reviews, confirming all procedures align with our company policies and best practices.

We engage with Alliance for Cooperative Energy Services Power Marketing, LLC (“ACES”), as our agent to manage our wholesale power market activities and risk management strategies related to electric operations.

Through this relationship, ACES manages the dispatch and scheduling on the real-time and day-ahead markets.

ACES manages bidding strategies, scheduling our generation in the relevant regional transmission organizations (“RTOs”) or independent system operators (“ISOs”).

To optimize our sales portfolio, ACES analyzes energy market dynamics, identifies opportunities to optimize plant dispatch, and recommends operational adjustments to capture favorable margins.

ACES assists in risk management by executing short-term trades on our behalf to mitigate price volatility and lock in predictable revenues as well as ensures that our participation in the energy markets adheres to relevant market rules and regulations.

We receive regular risk reports and settlement statements, which our internal teams review to confirm accuracy and compliance with our company policies.

We regularly review the performance and controls of CAMS and ACES.

Our formal review processes include monthly performance reviews through joint meetings with CAMS and ACES to evaluate KPI trends, discuss operational challenges, and plan market strategies.

Periodic internal and external audits examine environmental, safety, and financial compliance, ensuring third-party activities align with regulatory standards and Company objectives.

We also have a risk committee that evaluates all marketing activities and exposures.

Merom operates under permits issued by various agencies.

CAMS provides support and expertise to ensure compliance with emissions requirements, water use regulations, and waste disposal guidelines.

The power markets we operate in periodically update their rules and tariffs, which may affect how we dispatch our plants or manage financial positions.

ACES continuously monitors changes, recommending updates to our strategies as needed.

Volatility in wholesale power prices can impact revenue.

ACES provides strategies to mitigate price risk.

Equipment failures or unexpected downtime at coal plants can lead to missed market opportunities or contractual liabilities.

Our relationship with CAMS is designed to minimize these risks through comprehensive operations and maintenance practices.

Future environmental or market regulations may require capital investments or shift market behavior.

Our teams, in conjunction with CAMS and ACES, monitor emerging policies to proactively plan operational or strategic adjustments.

Through Hallador Power, the Company owns and operates Merom, a 1,080 MW net coal fired power generating station, consisting of two 590 MW sub-critical water tube drum type steam turbine generators.

Unit 1 entered commercial operations in 1982 and Unit 2 in 1983.

The units are dispatched to the MISO interconnection.

Hallador Power sells wholesale energy and accredited capacity to utilities within the MISO system through PPA’s and other bilateral transactions.

Merom is located in Sullivan County, Indiana, on approximately 691 acres, which also holds a 112-acre landfill.

Hallador Power has two tracts under option for approximately 72 acres for expansion and future development at Merom.

Merom is about twenty miles from Sunrise’s Oaktown Mining Complex and has rail and truck access.

The Company acquired Merom from Hoosier Energy Rural Electric Cooperative, Inc.

Year Ended December 31,

Power Capacity and Utilization

Nameplate capacity (MW) (i)

Accredited capacity for the period (MW) (ii)

Accredited capacity utilization (iii)

Nameplate capacity for the Merom Power Plant refers to the maximum electric output generated by the plant in the period presented and may not reflect actual production.

Actual production each period varies based on weather conditions, operational conditions, and other factors.

Accredited capacity is based on MISO’s average seasonal accreditations for the year.

Average seasonal accreditations were 808 MW and 838 MW per day for 2024 and 2023, respectively.

Accreditations are weighted and adjusted annually based on 3-year rolling performance metrics.

Accredited capacity utilization is measured as power produced (MWh) divided by accredited capacity for the period (MW) multiplied by 24 times the number of days for the period.

Permits are required by federal and state law for Merom’s facilities and landfill.

Merom holds several construction and environmental permits for air, wastewater and solids waste disposal.

All necessary permits to support current operations are in place.

New permits or permit revisions may be necessary from time to time to facilitate future operations or to keep pace with the changing regulatory landscape.

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.

Merom continually excels in environmental excellence and compliance.

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 is properly mitigated, and (2) assure that all regulation requirements of the permit are fully satisfied.

We hold surety bonds of $9.7 million to cover obligations relating to reclamation at Merom.

Coal Operations

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).

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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.

The Company has seven total mining properties.

These properties are the Oaktown Mining Complex (“Oaktown”), 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.

2 Mine, the Ace in the Hole Mine, the Ace in the Hole Mine #2 Reserves, Prosperity, Freelandville and Carlisle.

Oaktown Fuels No.

2, Prosperity and Freelandville were temporarily idled in February of 2024 as part of the Organizational Restructuring in “ Note 17 – Organizational Restructuring ” to the Consolidated Financial Statements below.

Ace in the Hole Mine and Carlisle are fully depleted.

The Oaktown Fuels No.

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The Oaktown Fuels No.

2 Mine is an underground mine in the Illinois Basin located near Oaktown in Knox County, Indiana.

2 Mine is an underground mine in the Illinois Basin (“ILB”) 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.

The preparation plant at Oaktown 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.

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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.

The low-sulfur coal is trucked to the Oaktown and other Sunrise Coal logistic facilities where it is blended with coal from the Oaktown Mines.

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 March 2025 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:

The following figure shows the general location of Merom and our mining properties discussed above:

Individual Mining Properties

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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.

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.

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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 dated March 2025 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 March 7, 2025, from John T.

Boyd Company providing an update of estimated coal reserves at the Oaktown Mining Complex as of December 31, 2024, attached as Exhibit 99.2 to this Form 10-K.

6 unchanged sentences

Boyd Company’s preparation of the mineral reserve estimates.

The Company hereby incorporates the letter, dated January 29, 2024, from John T.

The Company hereby incorporates the letter, dated March 7, 2025, 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, 2024 and including a comparison of the Company’s mineral reserves at the Oaktown Mining Complex as of December 31, 2024 and as of December 31, 2023.

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Mineral Reserves (tons in millions)

Oaktown Mining Complex

Oaktown Fuels No.

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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:

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.

Oaktown is an underground Room-and-Pillar (“R&P”) coal mining complex.

It is comprised of 83 square miles within the ILB coal-producing region of the mid-western U.S.

Oaktown operations currently consists of one active underground mine - Oaktown Fuels No.

1 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.

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 area and its immediate vicinity, our Company controls approximately 64,000 acres of mineral rights.

We have a complex collection of leases that apply to more than 1,000 tracts.

Leased tracts 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.

2 Mines from Vectren Fuels.

Each mine of the Oaktown Mining Complex utilizes R&P mining (employing Continuous Miners, or CM) for primary production.

The Company controls surface rights through fee simple ownership for over 1,700 permitted acres, holding mine accesses, processing, storing, shipping, and refuse disposal facilities (i.e., refuse impoundment site and fine refuse injection sites).

We acquired Oaktown Fuels No.

2 Mines from Vectren Fuels in 2014.

Oaktown 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.

Oaktown has utilized this mining method since the inception of each operation.

To date, Oaktown has produced a combined 75.0 million tons of clean coal.

Oaktown is configured to operate up to 6 CM sections (currently operating 4 CM sections), with an annual production target of approximately 3.6 million tons.

The Oaktown Preparation Plant serves as the coal washing and shipment facility for Oaktown’s two R&P mines.

The plant was commissioned in 2009 to wash coal by the Oaktown Fuels No.

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.

The Oaktown Preparation Plant’s processing capacity was upgraded to 1,800 raw tons-per-hour (TPH) from its previous 1,600 raw TPH in 2023.

Coal from Oaktown is transported to customers via rail and truck.

The Oaktown 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 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.

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at the Oaktown Mining Complex.

Additional information is provided in the following table regarding the Oaktown Mining Complex mineral reserves:

OAKTOWN MINING COMPLEX

Additional information is provided in the following table regarding Oaktown’s mineral reserves:

Recoverable Coal Reserves as of December 31, 2024 and 2023

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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.

In 2021, an additional mine access (elevator) was constructed for employee and supply ingress/egress closer to the active production faces.

Oaktown Fuels No.

2 was temporarily idled in February of 2024.

Coal tons 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 2024, with the coal sales price estimated over the life of the reserve averaging approximately $49 (ranging from $47.25 to $51.47 per 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.

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1 Mine and Oaktown Fuels No.

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:

and (ii) letter, dated March 7, 2025, 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 Oaktown as of December 31, 2024 and including a comparison of the Company’s mineral reserves at Oaktown as of December 31, 2024 and as of December 31, 2023.

Historical production for Oaktown during the years ended December 31, 2024, 2023, and 2022 are provided in the following table:

Annual Saleable Production Tons

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Ace Mine is now depleted.

Remaining inventory of coal and base was moved to our Carlisle and Oaktown wash plants in early 2023.

Remaining inventory of coal and base was moved to our Oaktown wash plant in early 2023.

Reclamation resumed in the Spring of 2023.

Phase 1 and 2 reclamation is substantially complete as of December 31, 2023.

There are four phases of reclamation that extend through 2029, of which, Phase 1 and 2 were completed as of December 31, 2024.

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 Prosperity mine contains approximately 0.2 million tons of low sulfur coal.

The mine opened in the summer of 2022.

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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.

That option was extended from May 2023 until May 2026.

Mining started in the fall of 2022 and continued through April 2023 with limited production in 2024.

Remaining reserves under the permit are 0.4 million tons.

There are additional reserves of 1.2 million tons available with the completion and approval of an Army Corps of Engineers permit.

In February 2024, this mine was idled.

The Carlisle mine is located near the town of Carlisle, Indiana in Sullivan County.

It became operational in January 2007 for both surface and underground mining.

The mine was permanently closed for mining operations in 2020.

A wash plant was relocated to the Carlisle mine in 2022 and was sold in 2024.

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.

In 2024, on a segment basis Sunrise sold 3.9 million tons of coal to 6 power plants in four different states across five different customers.

During 2024, on a segment basis we derived 96% of our revenue from four customers (5 power plants), with each of the four customers representing at least 10% of our coal sales.

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.

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:

Of our 2023 sales, on a segment basis 33%, excluding Merom Power Plant, were derived to locations in the State of Indiana.

Significant third-party customers in 2024 include Vectren Corporation, a wholly-owned subsidiary of CenterPoint Energy (NYSE:

CNP), Orlando Utility Commission (OUC), and Duke Energy Corporation (NYSE:

Of our 2024 sales, on a segment basis 43%, excluding Merom, were derived to locations in the State of Indiana.

Our future coal commitments are as follows:

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2026 - 2028 (total)

______________________

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.

As of December 31, 2024, we are committed to supplying third-party customers a base amount of 8.5 million tons of coal through 2028 of which 8.5 million tons are priced.

We are committed to supplying coal to Merom a base amount of 9.2 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.

Based on the contracted tons described above, we anticipate our mines will need to produce at a 3.6 million ton annualized pace for the foreseeable future to meet Merom and third-party market demand.

We also have contracts in place to purchase coal through March of 2026, and anticipate similar contracts in the future.

We expect to continue selling a significant portion of our coal under supply agreements with terms of one year or longer.

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As set forth in our Consolidated Statements of Cash Flows, cash provided by operations was $65.9 million and $59.4 million for the years ended December 31, 2024 and 2023 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.

Operating cash flow increased mainly due to prepaid physically delivered power contracts entered into during 2024.

Our capital expenditure budget for 2025 is $66.0 million.

Of the $66.0 million, the electric operations budget is $31.0 million for maintenance capex and $14.0 million for ELG.

The coal operations budget is $14.8 million plus an additional $5.8 million for discretionary items.

As of December 31, 2024, our bank debt was $44.0 million.

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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.

The effect of the amendment on our future cash flow is to extend the maturity date of $65.0 million of our outstanding term debt to March 31, 2026, and our revolver to July 31, 2026.

On September 27, 2024, the Company executed the First Amendment (“First Amendment”) to the Fourth Amended and Restated Credit Agreement, dated as of August 2, 2023 (as amended, the “Credit Agreement”), with PNC.

The primary purpose of the First Amendment was to provide the Company with short-term covenant relief to pursue additional liquidity.

The First Amendment provides for additional flexibility for the Company to enter into prepaid forward power sale contracts, provided that the Company repays outstanding term loans under the Credit Agreement (“Term Loan”) with proceeds received from certain eligible power purchase agreements, up to a maximum of $20.0 million.

These required prepaid forward power sale Term Loan repayments, if any, will take the place of the $6.5 million quarterly Term Loan payments.

We expect cash from operations generated primarily by our expected higher Electric Operation margins in 2025 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.

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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.

We have recorded the present value of reclamation obligations of $16.9 million, including $5.7 million at Merom, presented as asset retirement obligations (ARO) in our accompanying consolidated balance sheets.

In the event we are not able to perform reclamation, we have surety bonds in place totaling $30.8 million to cover ARO.

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Oaktown – investment

Prosperity mine

Freelandville mine

Capex per the Consolidated Statements of Cash Flows

Capex per the Condensed Consolidated Statements of Cash Flows

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.

Our business is organized based on the services and products we provide in two segments:

(i) Electric Operations and (ii) Coal Operations.

Corporate and Other and Eliminations primarily consist of unallocated corporate costs and activities, including a 50.0% interest in Sunrise Energy, which is accounted for using the equity method.

Electric Operations

Year Ended December 31,

(in thousands)

Delivered Energy

Capacity Revenue

Electric Sales

Other Operating Costs (1)

Other Operating and Maintenance Costs (2)

Cost of Purchased Power

General and Administrative

EBITDA Margin

Other Operating Revenue

Amortization of Contract Asset

Depreciation, Depletion and Amortization

Asset Retirement Obligations Accretion

Interest expense

Income (Loss) before Income Taxes

1) Other operating costs include costs for limestone, dibasic acid, ammonia, lime dust and soda ash.

2) Other operating and maintenance costs include all other operating and maintenance costs with the exceptions of those costs considered variable as discussed above in 1).

Year Ended December 31,

MWh Generated (in thousands)

MWh Purchased (in thousands)

MWh Sold (in thousands)

Delivered Energy

Capacity Revenue

Electric Sales

Other Operating Costs (1)

Other Operating and Maintenance Costs (2)

Cost of Purchased Power

General and Administrative

EBITDA Margin

Other Operating Revenue

Amortization of Contract Asset

Depreciation, Depletion and Amortization

Asset Retirement Obligations Accretion

Interest expense

Income (Loss) before Income Taxes

1) Other operating costs include costs for limestone, dibasic acid, ammonia, lime dust and soda ash.

2) Other operating and maintenance costs include all other operating and maintenance costs with the exceptions of those costs considered variable as discussed above in 1).

Fuel decreased $27.7 million, or 19.9%, from 2023 due to production decreasing by 394 MWh, or 9.3%, and the expiration of a purchased coal contract in 2023 reducing our average coal pricing by $8.61 per ton, or 14%, on a segment basis.

We used 189,000 tons, or 9.2%, less in production compared to the prior year.

The decrease in demand for electric power was related to mild weather throughout 2024 and the associated higher demand for natural gas as natural gas inventories remained high causing a decline in the average spot prices for natural gas which changed $0.34 per mbtu, or 13.5% from 2023.

Other operating and maintenance costs decreased $5.2 million, or 15.3%, from 2023 primarily due to 2023 year-to-date planned maintenance of $13.0 million compared to $9.1 million in 2024.

Cost of purchased power increased $10.9 million, or 100.0%, from 2023.

W hen energy hours at the Merom Hub are priced below our production cost at our Merom Facility, we make net hourly purchases of power in the MISO market.

Amortization of the contract asset decreased by $26.6 million, or 100.0%, from 2023 due to the expiration of our coal purchase contract.

Income (loss) before income taxes increased $39.1 million, or 320.0%, and increased $9.39 per MWh, from 2023 due to the items described in the discussion above.

Coal Operations

OPERATING REVENUES:

Operating expenses

Year Ended December 31,

(in thousands)

Other Operating and Maintenance Costs

General and Administrative

EBITDA Margin

Other Operating Revenue

Depreciation, Depletion and Amortization

Asset Impairment

Asset Retirement Obligations Accretion

Exploration Costs

Gain (loss) on disposal or abandonment of assets, net

Interest expense

Loss on Extinguishment of Debt

Settlement of Litigation

Income (Loss) before Income Taxes

Year Ended December 31,

Other Operating and Maintenance Costs

General and Administrative

Total operating expenses

INCOME (LOSS) FROM OPERATIONS

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.

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

OPERATING REVENUES:

Operating expenses

EBITDA Margin

Other Operating Revenue

Depreciation, Depletion and Amortization

Asset Impairment

Asset Retirement Obligations Accretion

General and administrative

Total operating expenses

INCOME FROM OPERATIONS

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.

Exploration Costs

Gain (loss) on disposal or abandonment of assets, net

Interest expense

Loss on Extinguishment of Debt

Settlement of Litigation

Income (Loss) before Income Taxes

During 2024, we undertook an Organizational Restructuring of our Coal Operations.

See “ Note 17 – Organizational Restructuring ” in the Consolidated Financial Statements for further information.

Segment operating revenues from coal operations decreased $230.4 million, or 53.2%, from 2023.

Consolidated operating revenues from coal operations decreased $224.5 million, or 62.0%, from 2023.

These declines were due to reductions in volume and average sales price for our coal.

Our average sales price, on a segment basis, decreased $10.13 per ton and we sold 3.1 million tons less compared to 2023.

Our average sales price, on a consolidated basis, for 2024 decreased $7.58 per ton and we sold 3.3 million tons less compared to 2023.

Other operating and maintenance costs decreased $76.2 million, or 46.0%.

Labor decreased $35.9 million, or 29.6%, from 2023, however labor cost per ton sold increased $4.57 per ton sold.

These changes were driven by the Reorganization Plan disclosed in “Note 17 — Organizational Restructuring” to the Consolidated Financial Statements.

As part of the Organizational Restructuring, we incurred aggregate expenses of $1.9 million ($1.1 million in the first

quarter of 2024 and $0.8 million in the second quarter of 2024) that were included in coal operations “Labor” .

These charges related to compensation, tax, professional, and insurance related expenses and are considered one-time charges paid during 2024.

During 2024, we produced 2.7 million tons less on a segment basis than 2023.

Additionally, we went from 5 mines producing to 1 mine producing and reduced our coal employee headcount by 305 employees.

We recorded an asset impairment of $215.1 million during 2024.

During the fourth quarter of 2024, we began our annual business plan review.

We evaluated core hole samples at several of our mines, reviewing the quality of the mine seam and density of the coal.

Based upon market price trends, we believe that the required course of action is to only produce those reserves that will allow us the lowest possible cost, and therefore capture the highest possible margins.

The core hole samples at our Oaktown 2 mine were of a lower quality and density than that of the Oaktown 1 mine.

As such, at the conclusion our annual business plan review during the fourth quarter of 2024, we decided to temporarily seal the Oaktown 2 mine, and to focus coal production at the Oaktown 1 mine, which has lower recovery costs.

Due to that decision, we determined a triggering event had occurred and completed an impairment review to determine if the carrying value of our coal properties were impaired by comparing the net book value of our coal properties to estimated undiscounted future net cash flows.

The result of this undiscounted cash flow test indicated the carrying amount of our coal properties may not be recoverable.

As a result, the Company prepared a discounted cash flow model (Level 3 fair value measurement under the fair value hierarchy) to estimate fair value.

Income (loss) before income taxes decreased $324.4 million, or 645.6%, and decreased $78.49 per ton, from 2023.

The main drivers of this change in income from operations are described in the discussion above.

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.

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The tables present our unaudited quarterly results of operations for the eight quarters ended December 31, 2024, 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.

In the fourth quarter of 2024, the Company made certain reclassifications that reduced “other operating and maintenance costs” and increased “depreciation, depletion and amortization” for certain assets with a useful life of one to three years.

The entire adjustment is reflected in the fourth quarter of 2024.

Previous interim periods and prior year periods were not adjusted as the amounts were not material.

The amounts recognized in the fourth quarter of 2024 that are related to the first, second and third quarters of 2024 were $2.1 million, $2.6 million and $1.7 million, respectively.

(in thousands, except per share information)

SALES AND OPERATING REVENUES:

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Total revenue

Operating expenses

Other operating and maintenance costs

Cost of purchased power

Depreciation, depletion and amortization

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General and administrative

Asset impairment

(Gain) loss on disposal or abandonment of assets, net

Settlement of litigation

Total operating expenses

INCOME (LOSS) FROM OPERATIONS

Bank debt and other interest

Interest expense (1)

Loss on extinguishment of debt

Equity method investment income

Equity method investment income (loss)

INCOME (LOSS) BEFORE INCOME TAXES

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WEIGHTED AVERAGE SHARES OUTSTANDING:

(in thousands, except per share information)

SALES AND OPERATING REVENUES:

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Total revenue

Operating expenses

Other operating and maintenance costs

Cost of purchased power

Depreciation, depletion and amortization

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General and administrative

(Gain) loss on disposal or abandonment of assets, net

Total operating expenses

INCOME (LOSS) FROM OPERATIONS

Bank debt and other interest

Amortization and swap related interest

Equity method investment income

Interest expense (1)

Loss on extinguishment of debt

Equity method investment income (loss)

INCOME (LOSS) BEFORE INCOME TAXES

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Tons produced

Average price per ton

Wash plant recovery in %

Operating costs

Average cost per ton

Margin per ton

Maintenance capex

Maintenance capex per ton

Capex (Coal Operations)

Maintenance capex (Coal Operations)

Maintenance capex per ton sold (Coal Operations)

Average cost per ton sold⁽ⁱ⁾

Tons produced

Average price per ton

Wash plant recovery in %

Operating costs

Average cost per ton

Margin per ton

Maintenance capex

Maintenance capex per ton

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.

Capacity revenue

Delivered energy and PPA revenue

Total electric sales

Less amortization of contract liability

Total electric sales less amortization of contract liability

Average price/MWh of delivered energy and PPA revenue less amortization of contract liability

Operating expenses (on a segment basis)

Less fixed costs

Less amortization of contract asset

Operating expenses less fixed costs and amortization of contract asset

Average variable cost/MWh of operating expenses less fixed costs and amortization of contract asset

Energy and PPA margin less fixed costs and amortization of contract asset and liabilities

Energy & PPA margin/MWh less fixed costs amortization of contract asset and liabilities

Capex (Coal Operations)

Maintenance capex (Coal Operations)

Maintenance capex per ton sold (Coal Operations)

Average cost per ton sold⁽ⁱ⁾

i) Average cost per ton sold is calculated as the sum of the Coal Operation’s “Fuel”, “Other Operating and Maintenance Costs”, “Utilities” and “Labor” costs as adjusted for the fourth quarter 2024 reclassification adjustments previously described, divided by tons sold for the respective period in this table.

Coal Operations costs are presented in the “Presentation of Segment Information” above.

Critical Accounting Estimates

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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.

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.

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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.

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.

As of December 31, 2024, and December 31, 2023, coal inventory includes NRV adjustments of $0.3 million and $2.0 million, respectively .

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.

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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.

This cash flow analysis is largely dependent upon the operating plans of the Company, which are reviewed by the Company and its Board of Directors no less than annually, normally during the 4 th quarter of each year.

Changes in anticipated activity levels, pricing or operating expenses can have significant effects on the ultimate value of the undiscounted cash flow analysis.

Compared sentence by sentence after normalising whitespace, quotation marks, case and digits, so re-formatting and restated figures do not read as changed language. Wording changes appear as one removal and one addition. The current filing and the prior one are authoritative.

What changed 10-K

Item 7. Management’s Discussion and Analysis