What changed in this filing

/stocks — the workspaceLOADING

Item 2. Management’s Discussion and Analysis

2024-11-12 compared with 2024-08-07 · 161 added, 118 removed, 151 unchanged (65% of the section changed)

1 unchanged sentence

THE FOLLOWING DISCUSSION UPDATES THE MD&A SECTION OF OUR 2023 ANNUAL REPORT ON FORM 10-K AND SHOULD BE READ IN CONJUNCTION THEREWITH.

Hallador is on a strategic and deliberate path to transform our company and capture increased value from our products and services as we advance up the value chain by expanding our offerings from fuel production to wholesale electricity sales to powering the industrial end user.

For many years, our Sunrise Coal subsidiary was our primary asset, producing fuel to sell to third-party customers.

In the fourth quarter of 2022, we acquired the Merom Power Plant through our Hallador Power Company (“Hallador Power” or “HPC”) subsidiary enabling us the ability to convert the majority of our fuel production into wholesale electricity and capacity, which traditionally sells at higher margins than coal.

As part of this process, we issued $29.0 million of convertible debt in 2022 to improve our capital position and facilitate the acquisition of the Merom Power Plant.

In 2022, $10.0 million of these convertible notes were converted to equity and the remaining balance was converted in the first half of 2024.

Looking at the wholesale electric sales we have made since the acquisition of the Merom Power Plant, along with the prices indicated by the forward power curves, we believe that HPC has the potential to achieve gross profit margins greater than the margins we have historically seen in coal sales.

In the first quarter of this year, our sales to third-party customers from electricity exceeded those of our sales from coal.

In connection with this shift in company focus, we changed our SIC code from 1220 bituminous coal producer to 4911 electric services during the second quarter.

Additionally, in the first quarter of this year we announced the signing of a Memorandum of Understanding (“MOU”) with Hoosier Energy and WIN REMC that provides a pathway to facilitate sales of our electricity to industrial end users of power.

As we continue to transform our product offerings from fuel to wholesale electricity, to supplying power to higher value end-users, we believe we can achieve increasingly higher gross profit margins.

The recent environment for spot electricity sales has been challenging.

This past winter, record high U.S.

natural gas (“Gas”) production ran into the ninth warmest winter on record according to National Oceanic and Atmospheric Administration.

The lack of winter heating demand caused Gas inventory levels to climb as much as 38% above the 5-year average.

As Gas prices adjusted downward to encourage the market to consume excess Gas inventory, wholesale electric (“Energy”) prices also declined.

In the first six months of 2024, approximately 90% of the off-peak Energy hours at the Merom Hub and approximately 60% of the total Energy hours at the Merom Hub priced below our production cost at our Merom facility.

Our goal is for Hallador Power to generate approximately 1.5 million MWh on a quarterly basis, which equates to approximately 6.0 million MWh annually (see Hallador Power’s capacity and utilization information below).

During the first half of 2024, Hallador Power generated 1,596,000 MWh, or 53% of our target.

During the first half of the year, we experienced sales prices of nearly $261.00 per MWh for limited times, balanced against several days of pricing below our variable cost to produce.

Hallador Energy made significant progress in its transformation to an Independent Power Producer this quarter by signing a non-binding term sheet (“Term Sheet”) with a leading global data center developer.

Our team is working diligently to finalize definitive agreements with this partner and relevant utilities that will support the delivery of our in front of the meter energy and capacity to the large hyperscaler.

As we have discussed before, these types of deals are complex arrangements involving multiple parties.

If we reach definitive agreements, we will have contracted large portions of our plant’s energy and capacity at much improved margins for more than a decade to come.

The completion of the transaction contemplated by the Term Sheet 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.

The path to this type of long-term, higher margin transaction has been focused and deliberate.

While we have not yet reached a binding agreement, we are encouraged both by the relationship with our current partner and the heavy interest that we continue to see from alternative counterparties in our energy and capacity offerings.

This continued interest highlights the supply shortage in accredited capacity that we believe the MISO market is experiencing and provides the Company options in the event that we are unable to reach agreement in connection with the executed Term Sheet.

We believe accredited capacity in MISO continues to increase in value and demand, particularly in our sales region of MISO Zone 6, an area that includes Indiana and a portion of western Kentucky.

This is important to Hallador based on our belief that Hallador has a significant amount of the remaining unsold accredited capacity in MISO Zone 6 over the next few years.

Our current belief is guided by several factors, including:

● Demand for power is growing at the fastest rate in several decades due to new demand from data centers, electric vehicles, and onshoring of industry.

● Indiana is seeing consistent interest from data center developers, likely due to favorable Indiana tax law for datacenter development and a pro-business climate.

● Supply Response is Restricted:

o MISO has significantly reduced the capacity accreditation it awards to wind and solar generation (non-dispatchable), making it challenging to support accredited capacity needs from generating resources other than coal, U.S.

natural gas (“Gas”), and nuclear (dispatchable).

o We are currently seeing minimal supply response of accredited capacity which we believe relates to the regulatory and environmental challenges for all types of baseload generation, including Gas.

Additionally, we believe the muted supply response is exacerbated by the glut of solar and wind projects, which provide minimal accredited capacity, overwhelming the queue and delaying access to dispatchable generation projects that would supplement the supply of accredited capacity.

● While our data center PPA negotiations proceed, we continue to focus on improving our balance sheet and access to liquidity.

During the quarter we modified our credit facility to provide the Company with short-term covenant relief to pursue additional liquidity.

Subsequent to the quarter, we executed a prepaid forward power sale in the amount of $60.0 million (see “Item 1.

Footnote 21 - Subsequent Events” ), delivering power from June 2025 through December 2026.

A portion of the proceeds were used to pay down $20.0 million on our Term Loan, which satisfies our January 2025, April 2025, July 2025 and a portion of our October 2025 required quarterly Term Loan payments.

Our October 2025 required quarterly Term Loan payment is reduced to $6.0 million as part of the $20.0 million Term Loan pay down.

We also paid $34.0 million on our revolver.

We did not utilize the ATM in the third quarter.

● Quarter-over-Quarter our financial results improved.

Our wholly owned subsidiary, Hallador Power, generated 1,074,000 MWh during the quarter versus 780,000 MWh in the second quarter of 2024.

This is a result of stronger power pricing during the quarter and a significant decrease in Gas inventory levels against the imbalances we saw in the first half of the year.

As Gas inventory decreased and prices increased, coal generation’s position in the dispatch stack improved.

During the third quarter of 2024, our power plant operated more frequently than in the second quarter of 2024, partly due to having no planned maintenance, and as a result, our costs at the plant improved to $44.42 per MWh from $62.98 per MWh.

● During the third quarter, results at our Sunrise Coal subsidiary also improved in connection with the restructuring of our mining division that we undertook beginning in the first quarter of 2024 (see “Item 1.

Footnote 16 – Organizational Restructuring” ).

In July of 2024, we completed a project for four of our most productive units, which allowed all units to be on a split air system, which helped to improve efficiency and reduce operating costs at the mine to $66.43 per ton produced, a decrease of $1.59 from the second quarter of 2024.

Sunrise Coal entered into a third-party coal contract to provide 2.5 million tons of coal from January 2026 to December 31, 2028, at an average price of $57.60 per ton.

Our goal is for Hallador Power to generate approximately 1,500,000 MWh on a quarterly basis, which equates to approximately 6,000,000 MWh annually (see Hallador Power’s capacity and utilization information below).

During the nine months ended September 30, 2024, Hallador Power generated 2,670,000 MWh, or 59.3% of our target.

During the first nine months of the year, we experienced sales prices of nearly $261.00 per MWh for limited times, balanced against several days of pricing below our variable cost to produce.

These fluctuations led to an inconsistent dispatch schedule.

Three Months Ended June 30,

Six Months Ended June 30,

Three Months Ended September 30,

Nine Months Ended September 30,

Power Capacity and Utilization

6 unchanged sentences

Average seasonal accreditations were 769 MW and 838 MW per day for 2024 and 2023, respectively.

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

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.

When forward selling Capacity, we target annual sales of around $65.0 million to offset our fixed annual costs at the plant of approximately $60.0 million.

We have already sold a large portion of our future Capacity, which we believe makes our forward Capacity sales goals attainable as illustrated in our "Solid Forward Sales Position" table below.

Our forward contracted energy sales position has a significant price increase in future years as illustrated in the graph below.

Lower Energy prices negatively affected both HPC’s generation model and the dispatch rates of Sunrise Coal’s utility customers.

In response to dispatching less, those customers slowed coal shipments from Sunrise during the winter season and throughout the shoulder season this spring.

We have already sold a large portion of our near term Capacity, which we believe makes our forward Capacity sales goals attainable as illustrated in our “Solid Forward Sales Position” table below.

In addition to the Term Sheet discussed above, which is not included in the graph below, our forward contracted energy sales position has a significant price increase in future years as illustrated in the graph below.

To match Sunrise’s production levels and cost structure to that of the market demands, we restructured Sunrise operations in the first quarter of 2024.

3 unchanged sentences

We are encouraged by the early results of Sunrise’s restructuring and have seen improvement in mining costs since we made the decision to adjust our operations.

Historically, Sunrise Coal has generated approximately six million tons of coal annually.

Following the restructuring, we expect Sunrise to produce roughly 3.5 million tons of coal on an annualized basis for 2024.

Total production for the first half of 2024 was 2.2 million tons, and we shipped 2.1 tons at an average sales price of $54.92 on a segment basis.

If market conditions warrant, our current operations are capable of producing at a 4.5-million-ton annualized pace.

In 2024, we have also 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 fuel costs at our Merom facility.

In response to lower Energy prices and our challenging mining conditions during the first half of 2024, we executed on several financing opportunities, including raising $34.5 million through an At-The-Market (“ATM”) equity offering selling 4.7 million shares at an average price of $7.38 per share and borrowing $5.0 million from several Directors on our Board.

In June, we received a $45.0 million prepayment for an 11-month forward Energy sale representing approximately 22% of our annual 6.0 million MWh goal during the term of the contract.

The Company last reviewed its long-lived assets for impairment during the fourth quarter of 2023 and concluded no impairment was indicated.

In preparing the Company’s impairment analysis, it utilizes undiscounted net cash flows over the expected life of the long-lived asset based upon anticipated production along with contracted and forward prices as well as historical operating expenses adjusted for inflation.

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 fourth 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.

During the third quarter of 2024, the Company began a review of our mining assets and our future mining plans.

This review will continue through the fourth quarter of 2024.

Should the anticipated future mining activity be reduced, an impairment of our mining assets could occur.

The amount of any such potential impairment, if any, is not currently estimable and will ultimately be based upon the finalized operating plans of the Company as approved by its Board of Directors, market driven pricing and cost trends, which are not known at this time.

Nevertheless, the carrying amount of the Company’s mining assets is material to its condensed consolidated balance sheet at September 30, 2024 and any future impairment of such assets could therefore be material.

The Company has concluded that no impairment exists as of September 30, 2024 as no triggering events have occurred during the period ended September 30, 2024.

Our condensed consolidated financial statements should be read in conjunction with this discussion.

1 unchanged sentence

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

Q2 2024 Net Loss of $10.2 million.

Q3 2024 Net Income of $1.6 million.

Electric Operations:

During the second quarter of 2024, we sold 780,000 MWh representing a 4.4% decline in total MWh sold and an increase of $0.90 in operating revenues per MWh from Q1 2024.

The decline in total MWh sold during Q2 2024 was driven by MISO pricing that was lower than our cost to produce for approximately two-thirds of the quarter, lower Electric Power demand due to a mild 2024 spring and summer and higher Gas utilization due to low Gas pricing.

During the third quarter of 2024, we sold 1,183,000 MWh representing a 41.0% increase in total MWh sold and a decrease of $10.31 in operating revenues per MWh from Q2 2024.

In Q3 2024, Electric Operations operating revenues were $71.9 million, or $60.78 per MWh, on a segment basis.

In Q2 2024, Electric Operations operating expenses per MWh were $64.39, which represents an increase of $10.88 per MWh from Q1 2024.

Q2 2024 Electric Operations income from operations was $8.71 per MWh, a decline of $9.98 from Q1 2024.

In Q3 2024, Electric Operations operating expenses were $52.5 million, or $44.42 per MWh, which represents a decrease of $18.56 per MWh from Q2 2024.

Q3 2024 Electric Operations income from operations was $16.36 per MWh, an increase of $8.25 from Q2 2024.

Coal Operations:

During the second quarter of 2024, 0.8 million tons of coal were shipped on a segment basis during the quarter, with approximately 0.3 million tons of that being shipped to the Merom Power Plant for $13.0 million.

This is a decline of 0.4 million tons of coal shipped from Q1 2024, primarily due to decreased demand from a mild 2024 spring and summer and continued low Gas prices.

During the third quarter of 2024, 0.9 million tons of coal were shipped on a segment basis during the quarter, with approximately 0.3 million tons of that being shipped to the Merom Power Plant for $16.7 million.

This is an increase of 0.1 million tons of coal shipped from Q2 2024, on a segment basis.

In Q3 2024, Coal Operations operating revenues were $49.3 million, or $53.27 per ton, on a segment basis.

In Q2 2024, Hallador's Coal Operations operating expenses were $68.02 per ton on a segment basis, which represents a $3.50 per ton increase from Q1 2024.

While Coal Operations operating expenses decreased $20.6 million in the second quarter of 2024 compared to the first quarter, tons sold also decreased 365,000 tons, or 30.1%, causing a higher operating expense per ton amount.

In Q3 2024, Hallador’s Coal Operations operating expenses were $66.43 per ton on a segment basis, which represents a $1.59 per ton decrease from Q2 2024.

We recorded a loss from operations for the quarter of $13.16 per ton on a segment basis.

This is a decline of $(3.89) per ton from Q1 2024 income from operations.

These declines were due primarily to the reduction in contract average sales prices and the reduction in demand for coal due to low Gas prices.

This is a decrease in our loss of $0.17 per ton from Q2 2024 income from operations.

Q3 2024 Activity

Cash Flow & Debt

During Q2 2024, our operating cash flow was $23.5 million, and we decreased our bank debt by $31.5 million.

As of June 30, 2024, our bank debt was $45.5 million, liquidity was $60.7 million, and our leverage ratio came in at 2.12X, within our covenant of 2.25X.

During Q2 2024, we entered into an 11-month, $45.0 million prepaid physically delivered power contract in which we will provide a total of 1,302,480 MW, as discussed in “Item 1.

Footnote 7 – Revenue”.

During Q2 2024, we paid off the $5.0 million unsecured one-year notes from related parties affiliated with certain members of the Board of Directors that were issued during Q1 2024.

Our ATM offering program raised $27.9 million through the issuance of 3.9 million shares of our common stock.

We converted our remaining $11.0 million of senior unsecured convertible notes, including accrued interest with 1,840,729 shares of our Company common stock.

We also issued 249,271 shares of our Company’s common stock as additional value to the holders for converting.

During Q3 2024, we had net cash used in operating activities of $12.9 million, and we increased our bank debt by $24.5 million.

During the third quarter of 2024, we executed the First Amendment to our Credit Agreement.

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

As of September 30, 2024, our bank debt was $70.0 million and our total liquidity was $34.9 million.

Total liquidity is comprised of a) our additional borrowing capacity which is net of outstanding letters of credit that we are required to maintain for surety bonds and amounts drawn on our revolver, and b) cash and cash equivalents.

Footnote 5 – Bank Debt” .

During Q3 2024, we signed a ninety-day ROFR with a potential buyer of our wholly-owned subsidiary Summit for $3.2 million.

Summit is included in our “Corporate and other and eliminations” segment and primarily holds property, plant and equipment.

Summit met the held-for-sale criteria and its assets were included in “assets held-for-sale” in our current assets section of our condensed consolidated balance sheets.

Footnote 20 – Assets Held-For-Sale” .

Solid Forward Sales Position (unaudited)

2 unchanged sentences

Contracted revenue (in millions)

Average daily contracted capacity MWh

Average contracted capacity price per MWd

Average daily contracted capacity MW

Average contracted capacity price per MW

Contracted capacity revenue (in millions)

11 unchanged sentences

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.

LIQUIDITY AND CAPITAL RESOURCES

Liquidity and Capital Resources

As set forth in our condensed consolidated statements of cash flows, cash provided by operations was $39.9 million and $44.2 million for the six months ended June 30, 2024 and 2023, respectively.

Our projected electric capital expenditure budget for the remainder of 2024 is $6.5 million.

Our projected coal operations capital expenditure budget for the remainder of 2024 is $8.8 million.

We paid down bank debt of $46.0 million in the first half of 2024.

As of June 30, 2024, our bank debt was $45.5 million.

We expect cash from operations generated primarily to fund our capital expenditures and our debt service.

As of June 30, 2024, we also had an additional borrowing capacity of $54.4 million.

As set forth in our condensed consolidated statements of cash flows, cash provided by operations was $27.0 million and $79.5 million for the nine months ended September 30, 2024 and 2023, respectively.

Bank debt was reduced by $21.5 million during the nine months ended September 30, 2024.

As of September 30, 2024, our bank debt was $70.0 million.

We expect cash generated from operations to primarily fund our capital expenditures and our debt service.

As of September 30, 2024, we also had an additional borrowing capacity of $31.1 million.

Total liquidity as of September 30, 2024 was $34.9 million.

Material Off-Balance Sheet Arrangements

3 unchanged sentences

CAPITAL EXPENDITURES (capex)

For the first six months of 2024, capex was $28.0 million allocated as follows (in millions):

For the nine months ended September 30, 2024, capex was $39.6 million allocated as follows (in millions):

Oaktown – maintenance capex

6 unchanged sentences

Electric Operations and Coal 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 and Eliminations" within the Notes to the Condensed 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.

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 and Eliminations” within the Notes to the Condensed 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 held-for-sale wholly-owned subsidiary Summit Terminal LLC, a logistics transport facility located on the Ohio River.

Electric Operations

Three Months Ended June 30,

Six Months Ended June 30,

Three Months Ended September 30,

Nine Months Ended September 30,

(in thousands)

3 unchanged sentences

Other operating and maintenance costs

Cost of purchased power

Depreciation, depletion and amortization

Asset retirement obligations accretion

Exploration costs

General and administrative

Total operating expenses

INCOME FROM OPERATIONS

Three Months Ended June 30,

Six Months Ended June 30,

INCOME (LOSS) FROM OPERATIONS

Three Months Ended September 30,

Nine Months Ended September 30,

(per MWh Sold)

MWh Generated (in thousands)

MWh Purchased (in thousands)

MWh Sold (in thousands)

Delivered Energy

1 unchanged sentence

Other operating and maintenance costs

Cost of purchased power

Depreciation, depletion and amortization

2 unchanged sentences

Total operating expenses

INCOME FROM OPERATIONS:

2023 (second quarter)

Operating revenues from electric operations decreased $14.1 million, or 19.8%, compared to the second quarter of 2023 due to approximately 60% of total Energy hours at the Merom Hub being priced below our production cost at our Merom Facility, low Electric Power demand due to a mild 2024 spring and summer, and higher demand for Gas as Gas prices averaged $2.08 per MBtu during the second quarter of 2024 compared to $2.16 per MBtu during the second quarter of 2023.

Fuel decreased $20.5 million, or 47.7%, compared to the second quarter of 2023 due to lower coal usage and energy production as a result of weakened demand for electricity.

Electric production decreased by 263,000 MWh, or 25.2%, from the second quarter of 2023.

We were also able to acquire third-party coal at prices below our production costs for coal, further reducing our fuel expense during the quarter.

Other operating and maintenance costs increased $8.7 million, or 160.8%, compared to the second quarter of 2023 primarily due to the planned maintenance outage which resulted in $6.8 million in additional costs for the period.

Income from operations decreased $2.5 million, or 26.7%, and decreased $0.13 per MWh, from the three months ended June 30, 2023.

INCOME (LOSS) FROM OPERATIONS:

2023 (third quarter)

Revenues from electric operations increased $4.4 million, or 6.5%, compared to the third quarter of 2023.

While the Merom Facility ran less hours in the third quarter of 2024 compared to 2023, the contracted hours were at higher prices.

We have new delivered energy contracts and capacity contracts with sales starting in 2024.

We entered into three new delivered energy contracts during the current year which increased revenues by $20.9 million.

We entered into three capacity contracts during 2023 that began delivery in 2024 and one new capacity contract that we entered into during the current year, which increased revenues by $10.9 million.

Revenue increases from new contracts were offset by suppressed MISO pricing (~66% of total energy hours at the Merom node being priced below our production cost at our Merom Facility), and reductions in demand for Power and higher demand for Gas as Gas inventories remained high, with a continued decline in average spot pricing per MBtu of $2.11 compared to $2.59 during the same three-month period in 2023.

Fuel decreased $21.1 million, or 41.6%, compared to the third quarter of 2023.

Our MWh sold decreased by 124 MWh, or 9.5%, from the third quarter of 2023.

The decrease in fuel costs are primarily related to our decreased electricity sales and declines in coal market pricing.

We used 0.1 million less tons of coal in our electric production compared to the third quarter of 2023.

The average purchase price per ton of coal used in the plant on a segment basis, was $53.33 in the third quarter of 2024, decreasing from $76.94 per ton in the third quarter of 2023.

Cost of purchased power was $3.1 million during the third quarter of 2024.

As noted above, when 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.

Income from operations increased $22.0 million, or 823.3%, and increased $18.39 per MWh, from the three months ended September 30, 2023.

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

2023 (first six months)

Operating revenues from electric operations decreased $47.7 million, or 29.1%, compared to the first half of 2023 due to MISO pricing that was lower than our cost to produce at times during the period, low Power demand due to a mild 2024 spring and summer, and higher demand for Gas as Gas prices during the spring season of 2024 (March through May) averaged $1.74 per MBtu compared to $2.21 per MBtu in the spring season of 2023.

Fuel decreased $49.5 million, or 51.3%, compared to the first half of 2023 due to lower coal usage and production as a result of weakened demand.

Production decreased by 709,000 MWh, or 30.8%, from the first six months of 2023.

Gas average spot prices were down $0.30 per MMBtu decreasing the demand for Electric Power.

Other operating and maintenance costs increased $8.9 million, or 81.3%, compared to the first half of 2023 primarily due to the planned maintenance outage which resulted in $6.6 million in additional costs for the period.

Income from operations decreased $5.9 million, or 21.2%, and increased $1.68 per MWh, from the six months ended June 30, 2023.

2023 (nine months)

Delivered energy revenues from electric operations decreased $37.3 million, or 20.2%, compared to the nine months ended September 30, 2023 due to suppressed MISO pricing (~75% of total energy hours at the Merom Hub being priced below our production cost at our Merom Facility), reductions in demand for Power and higher demand for Gas as Gas inventories remained high with a continued decline in average spot pricing per MBtu of $2.11 compared to $2.47 during the same nine-month period in 2023.

Fuel decreased $70.5 million, or 48.0%, compared to the nine months ended September 30, 2023.

Production decreased by 942 MWh, or 26.1%, from the first nine months of 2023.

The decrease in fuel costs are due to the expiration of a coal purchase contract in June of 2023 and declines in coal market pricing.

We used 0.5 million less tons of coal in our electric production compared to the nine months ended September 30, 2023.

The average purchase price per ton of coal used in the plant on a segment basis, was $54.83 for the nine months ended September 30, 2024, decreasing from $62.37 during the nine months ended September 30, 2023.

As discussed above, average spot prices for Gas were down per MMBtu decreasing the demand for Electric Power.

Cost of purchased power was $7.7 million during the first nine months of 2024.

As noted above, when 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.

Other operating and maintenance costs increased $9.3 million, or 56.0%, compared to the nine months ended September 30, 2023 primarily due to our planned maintenance outage during the second quarter of 2024 which resulted in $7.0 million in additional costs for the period.

Income from operations increased $16.1 million, or 63.7%, and increased $7.23 per MWh, from the nine months ended September 30, 2023.

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

Coal Operations

Three Months Ended June 30,

Six Months Ended June 30,

Three Months Ended September 30,

Nine Months Ended September 30,

(in thousands)

8 unchanged sentences

INCOME (LOSS) FROM OPERATIONS

Three Months Ended June 30,

Six Months Ended June 30,

Three Months Ended September 30,

Nine Months Ended September 30,

Tons Sold (in thousands)

OPERATING REVENUES:

6 unchanged sentences

INCOME (LOSS) FROM OPERATIONS:

2023 (second quarter)

Segment operating revenues from coal operations decreased $66.7 million, or 58.9%, from the second quarter of 2023.

Consolidated operating revenues from coal operations decreased $56.0 million, or 63%, from the second quarter of 2023.

2023 (third quarter)

Segment operating revenues from coal operations decreased $85.6 million, or 63.4%, from the third quarter of 2023.

Consolidated operating revenues from coal operations decreased $65.2 million, or 66.6%, from the third quarter of 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 $11.29 per ton and we sold 0.9 million tons less compared to the second quarter of 2023.

Our average sales price on a consolidated basis decreased $7.21 per ton and we sold 0.8 million tons less compared to the second quarter of 2023.

Operating revenues for the second quarter of 2024 include $12.9 million in sales to the Merom plant which were eliminated in the consolidation.

Other operating and maintenance costs decreased $14.7 million, or 40.5%, and labor decreased $9.7 million, or 33.3%, from the second quarter of 2023.

These changes were driven by the Reorganization Plan disclosed in “Item 1.

Our average sales price, on a segment basis, decreased $12.40 per ton and we sold 1.1 million tons less compared to the third quarter of 2023.

Our average sales price on a consolidated basis decreased $7.91 per ton and we sold 1.0 million tons less compared to the third quarter of 2023.

Operating revenues for the third quarter of 2024 include $16.7 million in sales to the Merom plant which were eliminated in the consolidation.

Other operating and maintenance costs decreased $32.7 million, or 54.7%, and labor decreased $10.6 million, or 35.3%, from the third quarter of 2023.

These changes were driven by impacts from the Reorganization Plan disclosed in “Item 1.

Note 16 — Organizational Restructuring” to the Condensed Consolidated Financial Statements.

During the second quarter 2024, we produced 0.4 million tons less than first quarter 2024, we reduced production days from 7 days to 5 days and further reduced our coal employee headcount by 130 employees.

Depreciation, depletion, and amortization decreased $3.5 million, or 28.4%, from the second quarter of 2023 due to decreases in coal production and the remaining useful lives of the mine development assets.

Income (loss) from operations decreased $37.7 million, or 142.9%, and decreased $28.71 per ton, from the three months ended June 30, 2023.

During the third quarter 2024, underground costs such as roof support and belt maintenance, fuel and utilities, as well as maintenance costs all had significant decreases in comparison to the third quarter of 2023.

We produced 0.7 million tons less in the third quarter of 2024 than the third quarter of 2023.

Depreciation, depletion, and amortization decreased $2.5 million, or 21.7%, from the third quarter of 2023 due to decreases in coal production and the remaining useful lives of the mine development assets.

Income (loss) from operations decreased $36.9 million, or 149.2%, and decreased $25.22 per ton, from the three months ended September 30, 2023.

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

2023 (first six months)

Segment operating revenues from coal operations decreased $95.1 million, or 45.6%, from the first half of 2023.

Consolidated operating revenues from coal operations decreased $100.8 million, or 55%, from the first half of 2023.

2023 (nine months)

Segment operating revenues from coal operations decreased $180.6 million, or 52.6%, from the nine months ended September 30, 2023.

Consolidated operating revenues from coal operations decreased $166.0 million, or 58.7%, from the nine months ended September 30, 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 $6.24 per ton and we sold 1.3 million tons less compared to the first six months of 2023.

Our average sales price, on a consolidated basis, for the six months ended 2024, decreased $3.11 per ton and we sold 1.6 million tons less compared to the first six months of 2023.

Other operating and maintenance costs decreased $9.8 million, or 15.5%, and labor decreased $14.0 million, or 23.0%, from the first six months of 2023.

Our average sales price, on a segment basis, decreased $8.45 per ton and we sold 2.5 million tons less compared to the first nine months of 2023.

Our average sales price, on a consolidated basis, for the first nine months of 2024, decreased $4.63 per ton and we sold 2.6 million tons less compared to the first nine months of 2023.

Other operating and maintenance costs decreased $42.5 million, or 34.6%, and labor decreased $24.6 million, or 27.1%, from the nine months ended September 30, 2023.

These changes were driven by the Reorganization Plan disclosed in “Item 1.

Note 16 — Organizational Restructuring” to the Condensed Consolidated Financial Statements.

During the first six months of 2024, we produced 1.6 million tons less on a segment basis than first six months of 2023, we went from 5 mines producing to 2 mines producing and further reduced our coal employee headcount by 339 employees.

Depreciation, depletion, and amortization decreased $6.1 million, or 23.6%, from the first half of 2023 due to decreases in coal production and the remaining useful lives of the mine development assets.

Income (loss) from operations decreased $62.2 million, or 157.7%, and decreased $22.62 per ton, from the six months ended June 30, 2023.

During the first nine months of 2024, we produced 2.3 million tons less on a segment basis than the first nine months of 2023.

Additionally, we went from 5 mines producing to 1 mine producing and reduced our coal employee headcount by 313 employees as part of the Reorganization Plan.

Depreciation, depletion, and amortization decreased $8.6 million, or 23.0%, from the nine months ended September 30, 2023 due to decreases in coal production and the remaining useful lives of the mine development assets.

Income (loss) from operations decreased $99.2 million, or 154.4%, and decreased $23.45 per ton, from the nine months ended September 30, 2023.

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

3 unchanged sentences

Maintenance capex

Maintenance capex per ton

Maintenance capex per ton sold

Tons produced

4 unchanged sentences

EARNINGS (LOSS) PER SHARE

Our effective tax rate (ETR) is estimated at ~23% and ~11% for the six months ended June 30, 2024, and 2023, respectively.

For the six months ended June 30, 2024, we recorded income taxes using an estimated annual effective tax rate based upon projected annual income, forecasted permanent tax differences, discrete items, and statutory rates in states in which we operate.

Our effective tax rate (ETR) is estimated at ~24% and ~13% for the nine months ended September 30, 2024 and 2023, respectively.

For the nine months ended September 30, 2024, we recorded income taxes using an estimated annual effective tax rate based upon projected annual income (loss), forecasted permanent tax differences, discrete items, and statutory rates in states in which we operate.

Our ETR differs from the statutory rate due primarily to statutory depletion in excess of tax basis and changes in the valuation allowance.

28 unchanged sentences

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.

As of June 30, 2024, and December 31, 2023, coal inventory includes NRV adjustments of $0.9 million and $2.0 million, respectively.

As of September 30, 2024, and December 31, 2023, coal inventory includes NRV adjustments of $1.8 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.

2 unchanged sentences

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.

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

During the third quarter of 2024, the Company began a review of its Oaktown mining facilities and future mining plan related to this complex.

This review will continue through the fourth quarter of 2024.

Should the anticipated future mining activity related to the Company’s Oaktown mining facilities be reduced, an impairment of certain mining assets could occur.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

1 unchanged sentence

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-Q

Item 2. Management’s Discussion and Analysis