Speaker #1: Greetings. Welcome to Alliance Resource Partners' fourth quarter 2025 earnings conference call. At this time, all participants will be in listen-only mode. A question-and-answer session will follow the formal presentation.
Operator: Greetings. Welcome to Alliance Resource Partners' Fourth Quarter 2025 Earnings Conference Call. At this time, all participants will be in listen-only mode. A question-and-answer session will follow the formal presentation. If anyone today should require operator assistance during the conference, please press star zero from your telephone keypad. Please note, this conference is being recorded. At this time, I'd like to turn the conference over to Cary Marshall, Senior Vice President and Chief Financial Officer. Thank you, Cary. You may now begin.
Speaker #1: If anyone today should require operator assistance during the conference, please press star zero (*) from your telephone keypad. Please note, this conference is being recorded.
Speaker #1: At this time, I'd like to turn the conference over to Cary Marshall, Senior Vice President and Chief Financial Officer. Thank you, Cary. You may now.
Speaker #1: begin. Thank you,
Cary Marshall: Thank you, operator. Good morning and welcome, everyone. Earlier today, Alliance Resource Partners released its fourth quarter 2025 financial and operating results, and we will now discuss those results as well as our perspective on current market conditions, and outlook for 2026. Following our prepared remarks, we will open the call to answer your questions.
Speaker #2: Operator: Good morning, and welcome, everyone. Earlier today, Alliance Resource Partners released its fourth quarter 2025 financial and operating results, and we will now discuss those results, as well as our perspective on current market conditions and outlook for 2026.
Speaker #2: Following our prepared remarks, we will open the call to answer your questions. Before beginning, a reminder that some of our remarks today may include forward-looking statements subject to a variety of risks, uncertainties, and assumptions, contained in our filings from time to time with the Securities and Exchange Commission and are also reflected in this morning's press release.
Operator: Before beginning, a reminder that some of our remarks today may include forward-looking statements subject to a variety of risks, uncertainties, and assumptions contained in our filings from time to time with the Securities and Exchange Commission and are also reflected in this morning's press release. While these forward-looking statements are based on information currently available to us, if one or more of these risks or uncertainties materialize or if our underlying assumptions prove incorrect, actual results may vary materially from those we projected or expected. In providing these remarks, the partnership has no obligation to publicly update or revise any forward-looking statement, whether as a result of new information, future events, or otherwise, unless required by law to do so.
Before beginning, a reminder that some of our remarks today may include forward-looking statements subject to a variety of risks, uncertainties, and assumptions contained in our filings from time to time with the Securities and Exchange Commission and are also reflected in this morning's press release. While these forward-looking statements are based on information currently available to us, if one or more of these risks or uncertainties materialize or if our underlying assumptions prove incorrect, actual results may vary materially from those we projected or expected. In providing these remarks, the partnership has no obligation to publicly update or revise any forward-looking statement, whether as a result of new information, future events, or otherwise, unless required by law to do so.
Speaker #2: While these forward-looking statements are based on information currently available to us, if one or more of these risks or uncertainties materialize, or if our underlying assumptions prove incorrect, actual results may vary materially from those we projected or expected.
Speaker #2: In providing these remarks, the Partnership has no obligation to publicly update or revise any forward-looking statement, whether as a result of new information, future events, or otherwise, unless required by law to do so.
Speaker #2: Finally, we will also be discussing certain non-GAAP financial measures. Definitions and reconciliations of the differences between these non-GAAP financial measures and the most directly comparable GAAP financial measures are contained at the end of ARLP's press release, which has been posted on our website and furnished to the SEC on Form 8-K.
Operator: Finally, we will also be discussing certain non-GAAP financial measures, definitions, and reconciliations of the differences between these non-GAAP financial measures, and the most directly comparable GAAP financial measures are contained at the end of ARLP's press release, which has been posted on our website and furnished to the SEC on Form 8-K. With the required preliminaries out of the way, I will begin with a review of our fourth quarter 2025 results, discuss our 2026 guidance, then turn the call over to Joe Craft, our Chairman, President, and Chief Executive Officer, for his comments. For the fourth quarter of 2025, which we refer to as the 2025 quarter, Adjusted EBITDA was $191.1 million, up 54.1% from the fourth quarter of 2024, which we refer to as the 2024 quarter, and up 2.8% compared to the third quarter of 2025, which we refer to as the sequential quarter.
Finally, we will also be discussing certain non-GAAP financial measures, definitions, and reconciliations of the differences between these non-GAAP financial measures, and the most directly comparable GAAP financial measures are contained at the end of ARLP's press release, which has been posted on our website and furnished to the SEC on Form 8-K. With the required preliminaries out of the way, I will begin with a review of our fourth quarter 2025 results, discuss our 2026 guidance, then turn the call over to Joe Craft, our Chairman, President, and Chief Executive Officer, for his comments. For the fourth quarter of 2025, which we refer to as the 2025 quarter, Adjusted EBITDA was $191.1 million, up 54.1% from the fourth quarter of 2024, which we refer to as the 2024 quarter, and up 2.8% compared to the third quarter of 2025, which we refer to as the sequential quarter.
Speaker #2: With the required preliminaries out of the way, I will begin with a review of our fourth quarter 2025 results, discuss our 2026 guidance, then turn the call over to Joe Craft, our Chairman, President, and Chief Executive Officer, for his comments.
Speaker #2: For the fourth quarter of 2025, which we refer to as the 2025 quarter, adjusted EBITDA was $191.1 million, up 54.1% from the fourth quarter of 2024, which we refer to as the 2024 quarter, and up 2.8% compared to the third quarter of 2025, which we refer to as the sequential quarter.
Speaker #2: Our net income attributable to ARLP in the 2025 quarter was $82.7 million, or $0.64 per unit, as compared to $16.3 million, or $0.12 per unit, in the 2024 quarter.
Operator: Our net income attributable to ARLP in the 2025 quarter was $82.7 million or $0.64 per unit as compared to $16.3 million or $0.12 per unit in the 2024 quarter. This was the result of lower operating expenses, lower impairment charges, and higher investment income, including $20 million in investment income in the 2025 quarter, of which $17.5 million was related to our share of an increase in the fair value of a coal-fired power plant indirectly owned and operated by an equity method investee. This helped offset a $15.4 million decrease in the fair value of our digital assets. Total revenues were $535.5 million in the 2025 quarter compared to $590.1 million in the 2024 quarter. This year-over-year decline was driven primarily by lower coal sales and transportation revenues, partially offset by record oil and gas royalty volumes.
Our net income attributable to ARLP in the 2025 quarter was $82.7 million or $0.64 per unit as compared to $16.3 million or $0.12 per unit in the 2024 quarter. This was the result of lower operating expenses, lower impairment charges, and higher investment income, including $20 million in investment income in the 2025 quarter, of which $17.5 million was related to our share of an increase in the fair value of a coal-fired power plant indirectly owned and operated by an equity method investee. This helped offset a $15.4 million decrease in the fair value of our digital assets. Total revenues were $535.5 million in the 2025 quarter compared to $590.1 million in the 2024 quarter. This year-over-year decline was driven primarily by lower coal sales and transportation revenues, partially offset by record oil and gas royalty volumes.
Speaker #2: This was the result of lower operating expenses, lower impairment charges, and higher investment income, including $20 million in investment income in the 2025 quarter.
Speaker #2: Of this, $17.5 million was related to our share of an increase in the fair value of a coal-fired power plant indirectly owned and operated by an equity method investee.
Speaker #2: This helped offset a $15.4 million decrease in the fair value of our digital assets. Total revenues were $535.5 million in the 2025 quarter, compared to $590.1 million in the 2024 quarter.
Speaker #2: This year-over-year decline was driven primarily by lower coal sales and transportation revenues, partially offset by record oil and gas royalty volumes. Compared to the sequential quarter, total revenues decreased 6.3% due to lower coal sales volumes and prices.
Operator: Compared to the sequential quarter, total revenues decreased 6.3% due to lower coal sales volumes and prices. Our average coal sales price per ton for the 2025 quarter was $57.57, a 4% decrease versus the 2024 quarter and a 2.1% decrease sequentially. As noted during prior calls, higher-priced legacy coal contracts entered into during the 2022 energy crisis continue to roll off and are being replaced at coal pricing levels assumed in our 2026 guidance ranges. Total coal production in the 2025 quarter was 8.2 million tons compared to 6.9 million tons in the 2024 quarter. Coal sales volumes were 8.1 million tons, down from 8.4 and 8.7 million tons compared to the 2024 and sequential quarters. Segment-adjusted EBITDA expense per ton sold for our coal operations was $40.24 per ton in the 2025 quarter, a decrease of 16.3% and 1.8% versus the 2024 and sequential quarters.
Compared to the sequential quarter, total revenues decreased 6.3% due to lower coal sales volumes and prices. Our average coal sales price per ton for the 2025 quarter was $57.57, a 4% decrease versus the 2024 quarter and a 2.1% decrease sequentially. As noted during prior calls, higher-priced legacy coal contracts entered into during the 2022 energy crisis continue to roll off and are being replaced at coal pricing levels assumed in our 2026 guidance ranges. Total coal production in the 2025 quarter was 8.2 million tons compared to 6.9 million tons in the 2024 quarter. Coal sales volumes were 8.1 million tons, down from 8.4 and 8.7 million tons compared to the 2024 and sequential quarters. Segment-adjusted EBITDA expense per ton sold for our coal operations was $40.24 per ton in the 2025 quarter, a decrease of 16.3% and 1.8% versus the 2024 and sequential quarters.
Speaker #2: Our average coal sales price per ton for the 2025 quarter was $57.57, a 4% decrease versus the 2024 quarter and a 2.1% decrease sequentially.
Speaker #2: As noted during prior calls, higher-priced legacy coal contracts entered into during the 2022 energy crisis continue to roll off and are being replaced at coal pricing levels assumed in our 2026 guidance ranges.
Speaker #2: Total coal production in the 2025 quarter was 8.2 million tons, compared to 6.9 million tons in the 2024 quarter. Coal sales volumes were 8.1 million tons, down from 8.4 and 8.7 million tons compared to the 2024 and sequential quarters.
Speaker #2: Segment-adjusted EBITDA expense per ton sold for our coal operations was $40.24 per ton in the 2025 quarter, a decrease of 16.3% and 1.8% versus the 2024 and sequential quarters.
Speaker #2: In the Illinois Basin, coal sales volumes were 6.5 million tons in the 2025 quarter, down approximately 2% compared to both the 2024 and sequential quarters, primarily due to timing of committed deliveries.
Operator: In the Illinois Basin, coal sales volumes were 6.5 million tons in the 2025 quarter, down approximately 2% compared to both the 2024 and sequential quarters, primarily due to timing of committed deliveries. I would like to highlight the outstanding performance at our Hamilton mining complex, where we achieved record production volumes and saleable yield during the 2025 full year. Segment-Adjusted EBITDA Expense per ton in the Illinois Basin decreased 14.4% compared to the 2024 quarter due primarily to increased production at Hamilton, resulting from fewer longwall move days and improved recoveries. Compared to the sequential quarter, Illinois Basin expense per ton decreased 3.8%. In our Appalachia region, coal sales volumes were 1.7 million tons in the 2025 quarter, down from 1.8 and 2.1 million tons in the 2024 and sequential quarters, respectively.
In the Illinois Basin, coal sales volumes were 6.5 million tons in the 2025 quarter, down approximately 2% compared to both the 2024 and sequential quarters, primarily due to timing of committed deliveries. I would like to highlight the outstanding performance at our Hamilton mining complex, where we achieved record production volumes and saleable yield during the 2025 full year. Segment-Adjusted EBITDA Expense per ton in the Illinois Basin decreased 14.4% compared to the 2024 quarter due primarily to increased production at Hamilton, resulting from fewer longwall move days and improved recoveries. Compared to the sequential quarter, Illinois Basin expense per ton decreased 3.8%. In our Appalachia region, coal sales volumes were 1.7 million tons in the 2025 quarter, down from 1.8 and 2.1 million tons in the 2024 and sequential quarters, respectively.
Speaker #2: I would like to highlight the outstanding performance at our Hamilton Mining Complex, where we achieved record production volumes and saleable yield during the full year 2025.
Speaker #2: Segment-adjusted EBITDA expense per ton in the Illinois Basin decreased 14.4% compared to the 2024 quarter, due primarily to increased production at Hamilton resulting from fewer longwall move days and improved recoveries.
Speaker #2: Compared to the sequential quarter, Illinois Basin expense per ton decreased 3.8%. In our Appalachia region, coal sales volumes were 1.7 million tons in the 2025 quarter, down from 1.8 and 2.1 million tons in the 2024 and sequential quarters, respectively.
Speaker #2: This decrease was caused primarily by timing of committed sales at our Metiki Mine and Tunnel Ridge volumes that were impacted by a December longwall jump, necessitated by a block of support coal needed to be left beneath four gas pipelines.
Operator: This decrease was caused primarily by timing of committed sales at our Mettiki mine and Tunnel Ridge volumes that were impacted by a December longwall move necessitated by a block of support coal needed to be left beneath four gas pipelines. Segment-adjusted EBITDA expense per ton decreased 17.5% versus the 2024 quarter due primarily to increased production at our MC Mining and Mettiki operations and higher recoveries at Tunnel Ridge. Compared to the sequential quarter, segment-adjusted EBITDA expense increased 9.7%, primarily due to lower production and recoveries across the region. As I mentioned earlier at Mettiki, a series of outages at a key customer's plant negatively impacted our shipments in the 2025 quarter. We have recently been informed that the plant expects additional outages during 2026, and they are not in a position to commit to purchase any additional tons from Mettiki for the foreseeable future.
This decrease was caused primarily by timing of committed sales at our Mettiki mine and Tunnel Ridge volumes that were impacted by a December longwall move necessitated by a block of support coal needed to be left beneath four gas pipelines. Segment-adjusted EBITDA expense per ton decreased 17.5% versus the 2024 quarter due primarily to increased production at our MC Mining and Mettiki operations and higher recoveries at Tunnel Ridge. Compared to the sequential quarter, segment-adjusted EBITDA expense increased 9.7%, primarily due to lower production and recoveries across the region. As I mentioned earlier at Mettiki, a series of outages at a key customer's plant negatively impacted our shipments in the 2025 quarter. We have recently been informed that the plant expects additional outages during 2026, and they are not in a position to commit to purchase any additional tons from Mettiki for the foreseeable future.
Speaker #2: Segment-adjusted EBITDA expense per ton decreased 17.5% versus the 2024 quarter, due primarily to increased production at our MC Mining and Mettiki operations and higher recoveries at Tunnel Ridge.
Speaker #2: Compared to the sequential quarter, segment-adjusted EBITDA expense increased 9.7%, primarily due to lower production and recoveries across the region. As I mentioned earlier, at Metike, a series of outages at a key customer's plant negatively impacted our shipments in the 2025 quarter.
Speaker #2: We have recently been informed that the plant expects additional outages during 2026, and they are not in a position to commit to purchase any additional tons from Metike for the foreseeable future.
Speaker #2: Metike depends on this customer purchasing a minimum of 1 million tons per year, and with no clear alternative customer to absorb production, issuing warrant act notices became unavoidable.
Operator: Mettiki depends on this customer purchasing a minimum of 1 million tons per year, and with no clear alternative customer to absorb production, issuing WARN Act notices became unavoidable. Mettiki expects to fulfill its existing contractual commitments, which are scheduled to conclude in March 2026, primarily from existing inventory. For the 2025 full year, Segment-Adjusted EBITDA less capital expenditures at Mettiki was approximately $3.5 million. The anticipated impact of reduced sales volumes at Mettiki is reflected in our 2026 guidance. Additionally, the partnership will evaluate any potential impairment related to this decision during Q1 2026. ARLP ended the 2025 quarter with 1.1 million tons of coal inventory, representing an increase of 0.4 and 0.1 million tons compared to the 2024 quarter and sequential quarter, respectively.
Mettiki depends on this customer purchasing a minimum of 1 million tons per year, and with no clear alternative customer to absorb production, issuing WARN Act notices became unavoidable. Mettiki expects to fulfill its existing contractual commitments, which are scheduled to conclude in March 2026, primarily from existing inventory. For the 2025 full year, Segment-Adjusted EBITDA less capital expenditures at Mettiki was approximately $3.5 million. The anticipated impact of reduced sales volumes at Mettiki is reflected in our 2026 guidance. Additionally, the partnership will evaluate any potential impairment related to this decision during Q1 2026. ARLP ended the 2025 quarter with 1.1 million tons of coal inventory, representing an increase of 0.4 and 0.1 million tons compared to the 2024 quarter and sequential quarter, respectively.
Speaker #2: Metike expects to fulfill its existing contractual commitments, which are scheduled to conclude in March 2026, primarily from existing inventory. For the 2025 full year, segment-adjusted EBITDA less capital expenditures at Metike was approximately $3.5 million.
Speaker #2: The anticipated impact of reduced sales volumes at Metike is reflected in our 2026 guidance. Additionally, the partnership will evaluate any potential impairment related to this decision during the first quarter of 2026.
Speaker #2: ARLP ended the 2025 quarter with 1.1 million tons of coal inventory, representing an increase of 0.4 and 0.1 million tons compared to the 2024 quarter and sequential quarter, respectively.
Speaker #2: In the 2025 quarter, Hamilton continued to produce at record levels, accelerating the completion of District 3, which we felt was necessary due to deterioration in the active leader entries.
Operator: In the 2025 quarter, Hamilton continued to produce at record levels, accelerating the completion of District 3, which we felt was necessary due to deterioration in the active leader entries. This will result in an extended longwall move that started last week, while the first longwall panel in District 4 awaits completion scheduled for the first week of May 2026. In our royalty segments, we delivered strong results during the 2025 quarter. Total revenue was $56.8 million, up 17.2% year-over-year due to higher coal royalty tons, higher revenue per ton sold, and record oil and gas BOE volumes, which helped offset lower benchmark oil prices. For the full year 2025, our oil and gas royalty segment achieved another record year of volumes on a BOE basis. In the 2025 quarter, BOE volumes increased 20.2% year-over-year and 10% sequentially, resulting in Segment-Adjusted EBITDA of $30 million.
In the 2025 quarter, Hamilton continued to produce at record levels, accelerating the completion of District 3, which we felt was necessary due to deterioration in the active leader entries. This will result in an extended longwall move that started last week, while the first longwall panel in District 4 awaits completion scheduled for the first week of May 2026. In our royalty segments, we delivered strong results during the 2025 quarter. Total revenue was $56.8 million, up 17.2% year-over-year due to higher coal royalty tons, higher revenue per ton sold, and record oil and gas BOE volumes, which helped offset lower benchmark oil prices. For the full year 2025, our oil and gas royalty segment achieved another record year of volumes on a BOE basis. In the 2025 quarter, BOE volumes increased 20.2% year-over-year and 10% sequentially, resulting in Segment-Adjusted EBITDA of $30 million.
Speaker #2: This will result in an extended longwall move that started last week, while the first longwall panel in District 4 awaits completion, scheduled for the first week of May 2026.
Speaker #2: In our royalty segments, we delivered strong results during the 2025 quarter. Total revenue was $56.8 million, up 17.2% year-over-year due to higher coal royalty tons, higher revenue per ton sold, and record oil and gas BOE volumes, which helped offset lower benchmark oil prices.
Speaker #2: For the full year 2025, our oil and gas royalty segment achieved another record year of volumes on a BOE basis. In the 2025 quarter, BOE volumes increased 20.2% year-over-year and 10% sequentially, resulting in segment-adjusted EBITDA of $30 million.
Speaker #2: As discussed last quarter, a high-royalty interest multi-well development pad in the Permian Delaware Basin was awaiting completion. Those wells were brought online during the 2025 quarter, and we are now benefiting from flush production from those recent completions.
Operator: As discussed last quarter, a high royalty interest multi-well development pad in the Permian Delaware Basin was awaiting completion. Those wells were brought online during the 2025 quarter, and we are now benefiting from flush production from those recent completions. Additionally, acquisition activity picked up in the 2025 quarter, and we completed $14.4 million of oil and gas minerals acquisitions. Segment-Adjusted EBITDA for our coal royalty segment increased to $14.6 million in the 2025 quarter compared to $10.5 million in the 2024 quarter due to higher royalty tons sold primarily from Tunnel Ridge. Turning now to our strong balance sheet as well as our cash flows, as of 31 December 2025, our total and net leverage ratios improved to 0.66 and 0.56 times debt to trailing 12 months Adjusted EBITDA. Total liquidity was $518.5 million, which included $71.2 million of cash and cash equivalents on hand.
As discussed last quarter, a high royalty interest multi-well development pad in the Permian Delaware Basin was awaiting completion. Those wells were brought online during the 2025 quarter, and we are now benefiting from flush production from those recent completions. Additionally, acquisition activity picked up in the 2025 quarter, and we completed $14.4 million of oil and gas minerals acquisitions. Segment-Adjusted EBITDA for our coal royalty segment increased to $14.6 million in the 2025 quarter compared to $10.5 million in the 2024 quarter due to higher royalty tons sold primarily from Tunnel Ridge. Turning now to our strong balance sheet as well as our cash flows, as of 31 December 2025, our total and net leverage ratios improved to 0.66 and 0.56 times debt to trailing 12 months Adjusted EBITDA. Total liquidity was $518.5 million, which included $71.2 million of cash and cash equivalents on hand.
Speaker #2: Additionally, acquisition activity picked up in the 2025 quarter, and we completed $14.4 million of oil and gas minerals acquisitions. Segment-adjusted EBITDA for our coal royalty segment increased to $14.6 million in the 2025 quarter, compared to $10.5 million in the 2024 quarter, due to higher royalty tons sold, primarily from Tunnel Ridge.
Speaker #2: Turning now to our strong balance sheet, as well as our cash flows, as of December 31, 2025, our total and net leverage ratios improved to 0.66 and 0.56 times debt to trailing 12 months adjusted EBITDA.
Speaker #2: Total liquidity was $518.5 million, which included $71.2 million of cash and cash equivalents on hand. Additionally, we held 592 bitcoins, valued at $51.8 million, at year-end.
Operator: Additionally, we held 592 Bitcoins valued at $51.8 million at year-end. For the 2025 quarter, after $44.8 million in capital expenditures, Alliance generated free cash flow of $93.8 million. We reported distributable cash flow of $100.1 million. Based on our $0.60 per unit quarterly cash distribution, this represented us paying out 77.7% of distributable cash flow and resulting in a distribution coverage ratio of 1.29 times. Looking now to our initial 2026 guidance detailed in this morning's release, there are a few notable areas that I would like to highlight. We anticipate ARLP's overall coal sales volumes for 2026 to increase and be in the range of 33.75 to 35.25 million tons.
Additionally, we held 592 Bitcoins valued at $51.8 million at year-end. For the 2025 quarter, after $44.8 million in capital expenditures, Alliance generated free cash flow of $93.8 million. We reported distributable cash flow of $100.1 million. Based on our $0.60 per unit quarterly cash distribution, this represented us paying out 77.7% of distributable cash flow and resulting in a distribution coverage ratio of 1.29 times. Looking now to our initial 2026 guidance detailed in this morning's release, there are a few notable areas that I would like to highlight. We anticipate ARLP's overall coal sales volumes for 2026 to increase and be in the range of 33.75 to 35.25 million tons.
Speaker #2: For the 2025 quarter, after $44.8 million in capital expenditures, Alliance generated free cash flow of $93.8 million. We reported distributable cash flow of $100.1 million.
Speaker #2: And based on our $0.60 per unit quarterly cash distribution, this represented us paying out 77.7% of distributable cash flow and resulted in a distribution coverage ratio of 1.29 times.
Speaker #2: Looking now to our initial 2026 guidance detailed in this morning's release, there are a few notable areas that I would like to highlight. We anticipate ARLP's overall coal sales volumes for 2026 to increase and be in the range of 33.75 to 35.25 million tons.
Speaker #2: This guidance assumes the impact of reduced coal sales volumes at our Metike Mine, and still represents an increase in sales volumes of 0.75 to 2.25 million tons across the Illinois Basin and at Tunnel Ridge versus 2025.
Operator: This guidance assumes the impact of reduced coal sales volumes at our Mettiki mine, and still represents an increase in sales volumes of 0.75 to 2.25 million tons across the Illinois Basin and at Tunnel Ridge versus 2025. Demand fundamentals continue to strengthen, supported by higher natural gas prices and low growth from data centers and U.S. manufacturing, driving increased demand for our coal supply. Contracting activity has been robust, with over 93% of expected volumes in 2026 already committed and priced at the midpoint of our guidance. This is materially better than where we were 12 months ago. In total, we anticipate 2026 full-year average realized coal pricing to be approximately 3% to 6% below Q4 2025 levels.
This guidance assumes the impact of reduced coal sales volumes at our Mettiki mine, and still represents an increase in sales volumes of 0.75 to 2.25 million tons across the Illinois Basin and at Tunnel Ridge versus 2025. Demand fundamentals continue to strengthen, supported by higher natural gas prices and low growth from data centers and U.S. manufacturing, driving increased demand for our coal supply. Contracting activity has been robust, with over 93% of expected volumes in 2026 already committed and priced at the midpoint of our guidance. This is materially better than where we were 12 months ago. In total, we anticipate 2026 full-year average realized coal pricing to be approximately 3% to 6% below Q4 2025 levels.
Speaker #2: Demand fundamentals continue to strengthen, supported by higher natural gas prices and low growth from data centers, and U.S. manufacturing driving increased demand for our coal supply.
Speaker #2: Contracting activity has been robust, with over 93% of expected volumes in 2026 already committed and priced at the midpoint of our guidance. This is materially better than where we were 12 months ago.
Speaker #2: In total, we anticipate 2026 full-year average realized coal pricing to be approximately 3% to 6% below fourth-quarter 2025 levels. In the Illinois Basin, we anticipate 2026 sales pricing to be in the range of $50 to $52 per ton, as compared to $52.09 in 2025, and $66 to $71 per ton for 2026 in Appalachia, as compared to $81.99 per ton in 2025, which included a larger mix of higher-priced Metike tons.
Operator: In the Illinois Basin, we anticipate 2026 sales pricing to be in the range of $50 to $52 per ton as compared to $52.09 in 2025 and $66 to $71 per ton for 2026 in Appalachia as compared to $81.99 per ton in 2025, which included a larger mix of higher-priced Mettiki tons. On the cost side, we expect full-year segment-adjusted EBITDA expense per ton to be in a range of $33 to $35 per ton in the Illinois Basin as compared to $34.71 per ton in 2025 and $49 to $53 per ton in Appalachia for 2026 as compared to $63.82 in 2025, which included a larger mix of higher-cost Mettiki tons.
In the Illinois Basin, we anticipate 2026 sales pricing to be in the range of $50 to $52 per ton as compared to $52.09 in 2025 and $66 to $71 per ton for 2026 in Appalachia as compared to $81.99 per ton in 2025, which included a larger mix of higher-priced Mettiki tons. On the cost side, we expect full-year segment-adjusted EBITDA expense per ton to be in a range of $33 to $35 per ton in the Illinois Basin as compared to $34.71 per ton in 2025 and $49 to $53 per ton in Appalachia for 2026 as compared to $63.82 in 2025, which included a larger mix of higher-cost Mettiki tons.
Speaker #2: On the cost side, we expect full-year segment-adjusted EBITDA expense per ton to be in a range of $33 to $35 per ton in the Illinois Basin, as compared to $34.71 per ton in 2025; and $49 to $53 per ton in Appalachia for 2026, as compared to $63.82 in 2025, which included a larger mix of higher-cost Metike tons.
Speaker #2: On a quarterly basis for 2026, it is reasonable to assume first quarter 2026 segment-adjusted EBITDA expense per ton to be 6% to 10% higher than the 2025 quarter, as a result of the extended longwall outage in the Illinois Basin at our Hamilton mine.
Operator: On a quarterly basis for 2026, it is reasonable to assume Q1 2026 Segment-Adjusted EBITDA Expense per ton to be 6% to 10% higher than the Q1 2025 as a result of the extended longwall move in the Illinois Basin at our Hamilton mine. Across our mining portfolio, particularly at Riverview and Tunnel Ridge, we expect an improvement in Segment-Adjusted EBITDA Expense per ton in 2026 and the same for Hamilton in the back half of 2026, supporting our efforts to preserve operating margins with continued cost discipline and operational execution. In our oil and gas royalty segment, we expect volumes of 1.5 to 1.6 million barrels of oil, 6.3 to 6.7 million MCF of natural gas, and 825,000 to 875,000 barrels of natural gas liquids. Segment-Adjusted EBITDA Expense is expected to be approximately 14% of oil and gas royalty revenues.
On a quarterly basis for 2026, it is reasonable to assume Q1 2026 Segment-Adjusted EBITDA Expense per ton to be 6% to 10% higher than the Q1 2025 as a result of the extended longwall move in the Illinois Basin at our Hamilton mine. Across our mining portfolio, particularly at Riverview and Tunnel Ridge, we expect an improvement in Segment-Adjusted EBITDA Expense per ton in 2026 and the same for Hamilton in the back half of 2026, supporting our efforts to preserve operating margins with continued cost discipline and operational execution. In our oil and gas royalty segment, we expect volumes of 1.5 to 1.6 million barrels of oil, 6.3 to 6.7 million MCF of natural gas, and 825,000 to 875,000 barrels of natural gas liquids. Segment-Adjusted EBITDA Expense is expected to be approximately 14% of oil and gas royalty revenues.
Speaker #2: Across our mining portfolio, particularly at Riverview and Tunnel Ridge, we expect an improvement in segment-adjusted EBITDA expense per ton in 2026, and the same for Hamilton in the back half of 2026, supporting our efforts to preserve operating margins with continued cost discipline and operational execution.
Speaker #2: In our oil and gas royalty segment, we expect volumes of 1.5 to 1.6 million barrels of oil; 6.3 to 6.7 million MCF of natural gas; and 825,000 to 875,000 barrels of natural gas liquids.
Speaker #2: Segment-adjusted EBITDA expense is expected to be approximately 14% of oil and gas royalty revenues. We remain committed to investing in our oil and gas royalties business and will continue to pursue disciplined growth in this segment in 2026.
Operator: We remain committed to investing in our oil and gas royalties business and will continue to pursue disciplined growth in this segment in 2026. Additionally, at the midpoint of our 2026 guidance, coal royalty tons sold are expected to be 6 million tons higher or 25% above 2025 levels, reflecting higher volumes at our Hamilton and Tunnel Ridge mines. Finally, we are expecting 2026 capital expenditures to be $280 to $300 million. For distribution coverage purposes, estimated maintenance capital per ton produced has been updated and is assumed to be $7.23 per ton produced in 2026 versus $7.28 per ton produced in 2025. And with that, I will turn the call over to Joe for comments on the market and his outlook for ARLP. Joe? Thank you, Cary. Good morning, everyone. Thank you for joining the call today.
We remain committed to investing in our oil and gas royalties business and will continue to pursue disciplined growth in this segment in 2026. Additionally, at the midpoint of our 2026 guidance, coal royalty tons sold are expected to be 6 million tons higher or 25% above 2025 levels, reflecting higher volumes at our Hamilton and Tunnel Ridge mines. Finally, we are expecting 2026 capital expenditures to be $280 to $300 million. For distribution coverage purposes, estimated maintenance capital per ton produced has been updated and is assumed to be $7.23 per ton produced in 2026 versus $7.28 per ton produced in 2025. And with that, I will turn the call over to Joe for comments on the market and his outlook for ARLP. Joe?
Speaker #2: Additionally, at the midpoint of our 2026 guidance, coal royalty tons sold are expected to be 6 million higher, or 25% above 2025 levels, reflecting higher volumes at our Hamilton and Tunnel Ridge mines.
Speaker #2: And finally, we are expecting 2026 capital expenditures to be $280 to $300 million, and for distribution coverage purposes, estimated maintenance capital per ton produced has been updated and is assumed to be $7.23 per ton produced in 2026 versus $7.28 per ton produced in 2025.
Speaker #2: And with that, I will turn the call over to Joe for comments on the market and his outlook for ARLP. Joe, thank you, Cary.
Joe Craft: Thank you, Cary. Good morning, everyone. Thank you for joining the call today.
Speaker #2: Good morning, everyone. Thank you for joining the call today. Alliance delivered solid performance during the fourth quarter and full year 2025, highlighted by resilient coal generation across our core markets, consistent operating performance from our Illinois Basin mines, and tightening fundamentals throughout U.S. power markets.
Operator: ALLIANCE delivered solid performance during the fourth quarter and full year 2025, highlighted by resilient coal generation across our core markets, consistent operating performance from our Illinois Basin mines, and tightening fundamentals throughout US power markets. As Cary mentioned, we closed out the year with strong contracting activity. As we move into 2026, we have committed and priced more than 93% of our projected 2026 sales tons, as reflected at the midpoint of our guidance range. Utilities are increasingly opting for longer-term agreements to lock in volume with reliable suppliers like ALLIANCE as we enter a period of favorable supply-demand dynamics. Customers are prioritizing reliability, and we believe this reflects a growing recognition that future supply will not be as flexible or abundant as in past cycles. Before turning to the broader market, I do want to briefly discuss a few areas as I reflect on 2025.
ALLIANCE delivered solid performance during the fourth quarter and full year 2025, highlighted by resilient coal generation across our core markets, consistent operating performance from our Illinois Basin mines, and tightening fundamentals throughout US power markets. As Cary mentioned, we closed out the year with strong contracting activity. As we move into 2026, we have committed and priced more than 93% of our projected 2026 sales tons, as reflected at the midpoint of our guidance range. Utilities are increasingly opting for longer-term agreements to lock in volume with reliable suppliers like ALLIANCE as we enter a period of favorable supply-demand dynamics. Customers are prioritizing reliability, and we believe this reflects a growing recognition that future supply will not be as flexible or abundant as in past cycles. Before turning to the broader market, I do want to briefly discuss a few areas as I reflect on 2025.
Speaker #2: As Cary mentioned, we closed out the year with strong contracting activity as we move into 2026. We have committed and priced more than 93% of our projected 2026 sales tons, as reflected at the midpoint of our guidance range.
Speaker #2: Utilities are increasingly opting for longer-term agreements to lock in volume with reliable suppliers like Alliance, as we enter a period of favorable supply-demand dynamics.
Speaker #2: Customers are prioritizing reliability, and we believe this reflects a growing recognition that future supply will not be as flexible or abundant as in past cycles.
Speaker #2: Before turning to the broader market, I do want to briefly discuss a few areas as I reflect on 2025. First, the Illinois Basin delivered a stellar quarter and year.
Operator: First, the Illinois Basin delivered a stellar quarter and year, supported by robust customer demand and continued execution of our plan to enhance mine productivity and cost performance, solidifying our positioning as the premier mining operator in the basin. Hamilton set a new record for full-year clean tons in 2025. Segment-adjusted EBITDA expense per ton in the region improved 14.4% quarter-over-quarter and 8.2% year-over-year, driven by meaningful cost reductions at both Hamilton and Warrior. In Appalachia, we endured a number of challenges in 2025, including recent events that led to last week's difficult decision to issue a WARN notice at Mettiki. At the same time, the strategic importance of Tunnel Ridge in the region continues to grow, and I am confident in our team's ability to improve execution and drive continued improvement in 2026.
First, the Illinois Basin delivered a stellar quarter and year, supported by robust customer demand and continued execution of our plan to enhance mine productivity and cost performance, solidifying our positioning as the premier mining operator in the basin. Hamilton set a new record for full-year clean tons in 2025. Segment-adjusted EBITDA expense per ton in the region improved 14.4% quarter-over-quarter and 8.2% year-over-year, driven by meaningful cost reductions at both Hamilton and Warrior. In Appalachia, we endured a number of challenges in 2025, including recent events that led to last week's difficult decision to issue a WARN notice at Mettiki. At the same time, the strategic importance of Tunnel Ridge in the region continues to grow, and I am confident in our team's ability to improve execution and drive continued improvement in 2026.
Speaker #2: Supported by robust customer demand and continued execution of our plan to enhance mine productivity and cost performance, solidifying our positioning as the premier mining operator in the basin.
Speaker #2: Hamilton set a new record for full-year clean tons in 2025. Segment-adjusted EBITDA expense per ton in the region improved 14.4% quarter-over-quarter and 8.2% year-over-year, driven by meaningful cost reductions at both Hamilton and Warrior.
Speaker #2: In Appalachia, we endured a number of challenges in 2025, including recent events that led to last week's difficult decision to issue a WARN notice at Metike.
Speaker #2: At the same time, the strategic importance of Tunnel Ridge in the region continues to grow. I am confident in our team's ability to improve execution and drive continued improvement in 2026.
Speaker #2: While Tunnel Ridge represented approximately 73% of Appalachia's sales tons in 2025, it generated over 98% of the region's cash flow in 2025, underscoring its materiality and long-term value.
Operator: While Tunnel Ridge represented approximately 73% of Appalachia sales tons in 2025, it generated over 98% of the region's cash flow in 2025, underscoring its materiality and long-term value. Finally, in our oil and gas royalty segment, as Cary mentioned earlier, we acquired $14.4 million of additional mineral interest during Q4 2025. While lower oil pricing has sidelined many sellers and reduced the number of marketed acquisition opportunities, we remain committed to disciplined investment. Our focus is on proactively sourcing off-market bilateral opportunities and strengthening our targeted ground game efforts to expand our pipeline of attractive acquisition opportunities. Shifting to the macro, as we entered 2026, natural gas prices had softened in early January from the fourth quarter due to milder than normal weather. However, that softness proved short-lived.
While Tunnel Ridge represented approximately 73% of Appalachia sales tons in 2025, it generated over 98% of the region's cash flow in 2025, underscoring its materiality and long-term value. Finally, in our oil and gas royalty segment, as Cary mentioned earlier, we acquired $14.4 million of additional mineral interest during Q4 2025. While lower oil pricing has sidelined many sellers and reduced the number of marketed acquisition opportunities, we remain committed to disciplined investment. Our focus is on proactively sourcing off-market bilateral opportunities and strengthening our targeted ground game efforts to expand our pipeline of attractive acquisition opportunities. Shifting to the macro, as we entered 2026, natural gas prices had softened in early January from the fourth quarter due to milder than normal weather. However, that softness proved short-lived.
Speaker #2: Finally, in our oil and gas royalty segment, as Cary mentioned earlier, we acquired $14.4 million of additional mineral interest during the fourth quarter of 2025.
Speaker #2: While lowering oil pricing has sidelined many sellers and reduced the number of marketed acquisition opportunities, we remain committed to disciplined investment. Our focus is on proactively sourcing off-market bilateral opportunities and strengthening our targeted ground game efforts to expand our pipeline of attractive acquisition opportunities.
Speaker #2: Shifting to the macro, as we entered 2026, natural gas prices had softened in early January from the fourth quarter due to milder-than-normal weather. However, that softness proved short-lived.
Speaker #2: By mid-January, a nationwide Arctic blast delivered some of the coldest temperatures in years across the Midwest, Mid-Atlantic, and Northeast, followed immediately by a winter storm burn.
Operator: By mid-January, a nationwide Arctic blast delivered some of the coldest temperatures in years across the Midwest, Mid-Atlantic, and Northeast, followed immediately by a winter storm burn. These events pushed electricity demand to record winter levels as natural gas deliverability tightened and renewable output remained limited during the hours when generation was needed most. Wood Mackenzie reported that natural gas freeze-offs reached a single-day record high of 17 billion cubic feet on 25 January, and regional hub pricing reached $100 for natural gas, proving once again that reliability goes hand in hand with affordability. By the way, our initial guidance we have referenced today did not factor in this Arctic blast, which weather experts are expecting will continue into mid-February, if not longer. During the most stressed periods over the past couple of weeks, coal-fired generation once again served as the backbone of reliability.
By mid-January, a nationwide Arctic blast delivered some of the coldest temperatures in years across the Midwest, Mid-Atlantic, and Northeast, followed immediately by a winter storm burn. These events pushed electricity demand to record winter levels as natural gas deliverability tightened and renewable output remained limited during the hours when generation was needed most. Wood Mackenzie reported that natural gas freeze-offs reached a single-day record high of 17 billion cubic feet on 25 January, and regional hub pricing reached $100 for natural gas, proving once again that reliability goes hand in hand with affordability. By the way, our initial guidance we have referenced today did not factor in this Arctic blast, which weather experts are expecting will continue into mid-February, if not longer. During the most stressed periods over the past couple of weeks, coal-fired generation once again served as the backbone of reliability.
Speaker #2: These events pushed electricity demand to record winter levels, as natural gas deliverability tightened and renewable output remained limited during the hours when generation was needed most.
Speaker #2: Wood Mackenzie reported that natural gas freeze-offs reached a single-day record high of 17 billion cubic feet on January 25th. And regional hub pricing reached $100 for natural gas, proving once again that reliability goes hand in hand with affordability.
Speaker #2: By the way, our initial guidance that we have referenced today did not factor in this Arctic blast, which weather experts are expecting will continue into mid-February, if not longer.
Speaker #2: During the most stressed periods over the past couple of weeks, coal-fired generation, once again, served as the backbone of reliability. A January 25th article in The Wall Street Journal highlighted that coal supplied 40% of MISO's generation and 24% of PJM's generation during the winter event, playing a critical stabilizing role across the Midwest and Mid-Atlantic. These developments mirrored exactly what NERC highlighted in its 2025-2026 Winter Reliability Assessment: that resources that appear adequate under normal conditions can quickly become insufficient during widespread extreme cold, especially when fuel deliverability constraints emerge.
Operator: A 25 January article in The Wall Street Journal highlighted that coal supplied 40% of MISO's generation and 24% of PJM's generation during the winter event, playing a critical stabilizing role across the Midwest and Mid-Atlantic. These developments mirrored exactly what NERC highlighted in its 2025-2026 winter reliability assessment, that resources that appear adequate under normal conditions can quickly become insufficient during widespread extreme cold, especially when fuel deliverability constraints emerge. Load growth remains one of the most significant long-term forces shaping US power markets. Across PJM, MISO, and CERC, operators continue to project the strongest multi-year demand growth in decades, driven by rapidly expanding data center and AI computing loads, and industrial development. These fundamentals are showing up most clearly in PJM's auction capacity markets.
A 25 January article in The Wall Street Journal highlighted that coal supplied 40% of MISO's generation and 24% of PJM's generation during the winter event, playing a critical stabilizing role across the Midwest and Mid-Atlantic. These developments mirrored exactly what NERC highlighted in its 2025-2026 winter reliability assessment, that resources that appear adequate under normal conditions can quickly become insufficient during widespread extreme cold, especially when fuel deliverability constraints emerge. Load growth remains one of the most significant long-term forces shaping US power markets. Across PJM, MISO, and CERC, operators continue to project the strongest multi-year demand growth in decades, driven by rapidly expanding data center and AI computing loads, and industrial development. These fundamentals are showing up most clearly in PJM's auction capacity markets.
Speaker #2: Load growth remains one of the most significant long-term forces shaping US power markets. Across PJM, MISO, and CERC, operators continue to project the strongest multi-year demand growth in decades.
Speaker #2: By the rapidly expanding data-driven centers and AI computing loads, and industrial development, these fundamentals are showing up most clearly in PJM's auction capacity markets.
Speaker #2: In December '25, the base residual auction for 2027-2028 delivery years cleared at the FERC-approved cap across all areas. But PJM still fell approximately 6.5 gigawatts short of its reliability targets, as the temporary price caps limited how much capacity the market could attract.
Operator: In December 25, the base residual auction for 2027-2028 delivered years cleared at the FERC-approved cap across all areas, but PJM still fell approximately 6.5GW short of its reliability targets as the temporary price caps limited how much capacity the market could attract. This follows two consecutive auctions with similarly elevated outcomes, underscoring that PJM's accredited capacity challenge is structural. Since then, FERC has begun evaluating reforms intended to curb volatility, better balance affordability and reliability, and support the construction of new generation, though the ultimate direction and timeline of these reforms remain uncertain. These market developments reinforce what we have consistently communicated. Fuel-secure dispatchable generation remains indispensable, and coal's value to our nation's grid is increasingly being recognized by customers, energy markets, and regulators.
In December 25, the base residual auction for 2027-2028 delivered years cleared at the FERC-approved cap across all areas, but PJM still fell approximately 6.5GW short of its reliability targets as the temporary price caps limited how much capacity the market could attract. This follows two consecutive auctions with similarly elevated outcomes, underscoring that PJM's accredited capacity challenge is structural. Since then, FERC has begun evaluating reforms intended to curb volatility, better balance affordability and reliability, and support the construction of new generation, though the ultimate direction and timeline of these reforms remain uncertain. These market developments reinforce what we have consistently communicated. Fuel-secure dispatchable generation remains indispensable, and coal's value to our nation's grid is increasingly being recognized by customers, energy markets, and regulators.
Speaker #2: This follows two consecutive auctions with similarly elevated outcomes, underscoring that PJM's accredited capacity challenge is structural. Since then, FERC has begun evaluating reforms intended to curb volatility, better balance affordability and reliability, and support the construction of new generation.
Speaker #2: Though the ultimate direction and timeline of these reforms remain uncertain, these market developments reinforce what we have consistently communicated: fuel-secure, dispatchable generation remains indispensable, and coal's value to our nation's grid is increasingly being recognized by customers, energy markets, and regulators.
Speaker #2: From a policy and planning perspective, these conditions underscore why a balanced resource mix that includes coal remains essential as the grid navigates rapid change, to ensure the United States can win the global AI race.
Operator: From a policy and planning perspective, these conditions underscore why a balanced resource mix that includes coal remains essential as the grid navigates rapid change to ensure the United States can win the global AI race. I want to acknowledge the Trump administration's foresight in supporting policies to preserve coal units and recognize their contribution to grid reliability. From the first day President Trump was sworn into office one year ago, he understood the importance of preserving all existing base load generating units in order to protect our national security interest. Every day since, the Energy Dominance Council has worked tirelessly on this objective, with particular focus on affordability, reliability, and preserving the existing coal fleet, as well as providing a regulatory framework that allows the operating lives of these plants to be extended. Fortunately, their leadership is making a difference.
From a policy and planning perspective, these conditions underscore why a balanced resource mix that includes coal remains essential as the grid navigates rapid change to ensure the United States can win the global AI race. I want to acknowledge the Trump administration's foresight in supporting policies to preserve coal units and recognize their contribution to grid reliability. From the first day President Trump was sworn into office one year ago, he understood the importance of preserving all existing base load generating units in order to protect our national security interest. Every day since, the Energy Dominance Council has worked tirelessly on this objective, with particular focus on affordability, reliability, and preserving the existing coal fleet, as well as providing a regulatory framework that allows the operating lives of these plants to be extended. Fortunately, their leadership is making a difference.
Speaker #2: I want to acknowledge the Trump administration's foresight in supporting policies to preserve coal units, and recognize their contribution to grid reliability. From the first day President Trump was sworn into office, one year ago, he understood the importance of preserving all existing baseload generating units in order to protect our national security interest.
Speaker #2: In everyday sense, the Energy Dominance Council has worked tirelessly on this objective, with particular focus on affordability, reliability, and preserving the existing coal fleet, as well as providing a regulatory framework that allows the operating lives of these plants to be extended.
Speaker #2: Fortunately, their leadership is making a difference. According to America's Power, utilities in 19 states have reversed or delayed more than 31,000 megawatts of coal retirements based on low growth or reliability concerns.
Operator: According to America's Power, utilities in 19 states have reversed or delayed more than 31,000 megawatts of coal retirements based on low growth or reliability concerns, reinforcing that policy is becoming increasingly aligned with real-world grid reliability needs. As we look to 2026 and beyond, we remain committed to a disciplined capital allocation framework by investing in high-return opportunities across our core operations and royalty platforms and returning capital to unit holders, all while maintaining a strong balance sheet. We believe this balanced approach positions Alliance to capitalize on strategic growth opportunities while maintaining financial flexibility in a rapidly evolving energy landscape. I want to thank our employees for their outstanding performance throughout the year. We look forward to building on this momentum. That concludes our prepared comments, and I'll now ask the operator to open the call for questions. Operator. Thank you.
According to America's Power, utilities in 19 states have reversed or delayed more than 31,000 megawatts of coal retirements based on low growth or reliability concerns, reinforcing that policy is becoming increasingly aligned with real-world grid reliability needs. As we look to 2026 and beyond, we remain committed to a disciplined capital allocation framework by investing in high-return opportunities across our core operations and royalty platforms and returning capital to unit holders, all while maintaining a strong balance sheet. We believe this balanced approach positions Alliance to capitalize on strategic growth opportunities while maintaining financial flexibility in a rapidly evolving energy landscape. I want to thank our employees for their outstanding performance throughout the year. We look forward to building on this momentum. That concludes our prepared comments, and I'll now ask the operator to open the call for questions. Operator.
Speaker #2: Reinforcing that policy is becoming increasingly aligned with real-world grid reliability needs. As we look to 2026 and beyond, we remain committed to a disciplined capital allocation framework by investing in high-return opportunities across our core operations and royalty platforms, and returning capital to unitholders, all while maintaining a strong balance sheet.
Speaker #2: We believe this balanced approach positions Alliance to capitalize on strategic growth opportunities, while maintaining financial flexibility in a rapidly evolving energy landscape. I want to thank our employees for their outstanding performance throughout the year.
Speaker #2: We look forward to building on this momentum. That concludes our prepared comments, and I'll now ask the operator to open the call for questions.
Speaker #2: Operator? Thank you. We’ll now be conducting a question and answer session. If you’d like to ask a question at this time, please press star one on your telephone keypad, and a confirmation tone will indicate your line is in the question queue.
Operator: Thank you. We'll now be conducting a question and answer session. If you'd like to ask a question at this time, please press star one on your telephone keypad, and a confirmation tone will indicate your line is in the question queue. You may press star two if you'd like to remove your question from the queue. For participants who are using speaker equipment, it may be necessary to pick up your handset before pressing the star keys. One moment, please, while we pull for our first question. Thank you. Thank you. The first question is from the line of Nathan Martin with Benchmark Company. Please receive your question.
Operator: We'll now be conducting a question and answer session. If you'd like to ask a question at this time, please press star one on your telephone keypad, and a confirmation tone will indicate your line is in the question queue. You may press star two if you'd like to remove your question from the queue. For participants who are using speaker equipment, it may be necessary to pick up your handset before pressing the star keys. One moment, please, while we pull for our first question. Thank you. Thank you. The first question is from the line of Nathan Martin with Benchmark Company. Please receive your question. Morning. Thanks, operator. Good morning, Joe. Good morning, Cary. Morning, Nate. Morning. As you guys said in your prepared remarks, more than 93% committed in price for 2026 based at the midpoint of guidance.
Speaker #2: You may press star two if you'd like to remove your question from the queue. For participants who are using speaker equipment, it may be necessary to pick up your handset before pressing the star keys.
Speaker #2: One moment, please, while we pull for our first question. Thank you. Thank you. And the first question is from the line of Nathan Martin with Benchmark Company.
Speaker #2: Please proceed with your question.
Nathan Martin: Morning. Thanks, operator. Good morning, Joe. Good morning, Cary.
Speaker #3: Good morning. Thanks, Operator. Good morning, Joe. Good morning,
Speaker #3: Good morning. Thanks, Operator. Good morning, Joe. Good morning.
Speaker #3: Cary: Good morning, Nate. You know, as
Cary Marshall: Morning, Nate.
Speaker #5: morning.
Joe Craft: Morning.
Nathan Martin: As you guys said in your prepared remarks, more than 93% committed in price for 2026 based at the midpoint of guidance.
Speaker #3: You guys said in your prepared remarks, more than 93% committed in price for ’26, based at the midpoint of guidance. With such a large chunk priced, what does it take to get you to the high or low end of your price per ton guidance? I guess, in other words, what portion of your tons is still exposed to the market and could either go up or down, depending on how things progress from here?
Operator: With such a large chunk price, what does it take to get you to the high or low end of your price per ton guidance? I guess, in other words, what portion of your tons is still exposed to the market and could either go up or down, depending on how things progress from here? Thanks. Yeah. So I think that most of our tons that are remaining to be sold are in the Illinois Basin. We do have a little bit at MC Mining, where we got about 200,000 tons to sell, but most is in the Illinois Basin, primarily Gibson South and Hamilton. We do believe that we're well positioned. I think that one thing that we have to factor in is that some of the tons that we have committed in those basins include optionality for our customers.
With such a large chunk price, what does it take to get you to the high or low end of your price per ton guidance? I guess, in other words, what portion of your tons is still exposed to the market and could either go up or down, depending on how things progress from here? Thanks.
Speaker #3: Thanks.
Joe Craft: Yeah. So I think that most of our tons that are remaining to be sold are in the Illinois Basin. We do have a little bit at MC Mining, where we got about 200,000 tons to sell, but most is in the Illinois Basin, primarily Gibson South and Hamilton. We do believe that we're well positioned. I think that one thing that we have to factor in is that some of the tons that we have committed in those basins include optionality for our customers.
Speaker #4: Yeah, so I think that most of our tons that are remaining to be sold are in the Illinois Basin. We do have a little bit at MC Mining, where we've got about 200,000 tons to sell.
Speaker #4: But primarily, Gibson South and most is in the Illinois Basin—Hamilton. We do believe that we're well positioned. I think that one thing we have to factor in is that some of the tons that we have committed in those basins include optionality for our customers.
Speaker #4: So, even though the price has increased this quarter because of the Arctic air that we've seen, and now the natural gas prices rising like they have, there should be some upside.
Operator: So even though the price has increased this quarter because of the Arctic air that we've seen, and now the natural gas price is rising like they have, there should be some upside that allows for the Illinois Basin pricings to potentially end up towards the end at the high end of the range, if not exceed it a little bit. But that really depends on how our customers flex up contracts that we have, just basically assumed in our contracted position that those are at their base levels and doesn't factor in their optionality. And I don't know exactly precisely how that trends, but I do believe it's safe to assume that as we look at the markets right now, that we would be at the high end of the range on Illinois Basin. And in Appalachia, we just don't have that many tons to sell.
So even though the price has increased this quarter because of the Arctic air that we've seen, and now the natural gas price is rising like they have, there should be some upside that allows for the Illinois Basin pricings to potentially end up towards the end at the high end of the range, if not exceed it a little bit. But that really depends on how our customers flex up contracts that we have, just basically assumed in our contracted position that those are at their base levels and doesn't factor in their optionality. And I don't know exactly precisely how that trends, but I do believe it's safe to assume that as we look at the markets right now, that we would be at the high end of the range on Illinois Basin. And in Appalachia, we just don't have that many tons to sell.
Speaker #4: That allows for the Illinois Basin pricings to potentially end up towards the end at the high end of the range, if not exceeded a little bit. But that really depends on how our customers flex up contracts. We have just basically assumed in our contracted position that those are at their base levels and doesn't factor in their optionality.
Speaker #4: And I don't know exactly, precisely how that trends, but I do believe it's safe to assume that, as we look at the markets right now, we would be at the high end of the range on the Illinois Basin.
Speaker #4: And Appalachia, we just don't have that many tons to sell. Tunnel Ridge is basically sold out. MC, like I said, is 200,000. And we have seen an uptick in the export markets, which is positive for MC.
Operator: Tunnel Ridge is basically sold out. MC, like I said, is 200,000, and we have seen an uptick in the export markets, which is positive for MC, but that hasn't materialized yet. We did book some tons just recently, but we're anticipating that price may go a little higher. So we feel pretty good there, but we just don't have that many tons there to really influence what that price is going to be for our price ranges there for Appalachia. So I'd say they will probably come in at the midpoint level. All right. So that was very helpful. I appreciate that. Maybe a little bit bigger picture. If coal thermal coal demand specifically continues to be supported, utilities look more and more to contract for a longer duration, as you mentioned in your prepared remarks. What would it take for Alliance to increase production?
Tunnel Ridge is basically sold out. MC, like I said, is 200,000, and we have seen an uptick in the export markets, which is positive for MC, but that hasn't materialized yet. We did book some tons just recently, but we're anticipating that price may go a little higher. So we feel pretty good there, but we just don't have that many tons there to really influence what that price is going to be for our price ranges there for Appalachia. So I'd say they will probably come in at the midpoint level.
Speaker #4: But that hasn't materialized yet. We did book some tons just recently, but we're anticipating that price may go a little higher. So we feel pretty good there.
Speaker #4: But we just don't have that many tons there to really influence what that price is going to be for, yeah, for our price ranges there for Appalachia.
Speaker #4: So, I'd say they will probably come in at the midpoint.
Speaker #4: level. All right.
Nathan Martin: All right. So that was very helpful. I appreciate that. Maybe a little bit bigger picture. If coal thermal coal demand specifically continues to be supported, utilities look more and more to contract for a longer duration, as you mentioned in your prepared remarks. What would it take for Alliance to increase production?
Speaker #3: Joe, that was very helpful. I appreciate that. Maybe a little bit bigger picture: if thermal coal demand specifically continued to be supported, utilities look more and more to contract for longer duration, as you mentioned in your prepared remarks.
Speaker #3: What would it take for Alliance to increase production? I guess, where are you guys kind of tapped today, and what could you increase production to, with approximately how much?
Operator: I guess where are you guys kind of capped today, and what could you increase production to with approximately how much investment? I think right now we do not plan to add any units. So the one area where we could add units is at Riverview. We could add a unit there, but we're not anticipating to do that. I think that if there's any incremental demand, that we could potentially just work a little bit more overtime on the weekends and things of that nature. But I think our primary growth is going to just be an improved productivity. We're very focused on improving our productivity, and specifically in Illinois Basin, we're encouraged by some of the investments we've made in our equipment.
I guess where are you guys kind of capped today, and what could you increase production to with approximately how much investment?
Speaker #3: Investment? I think right now we...
Joe Craft: I think right now we do not plan to add any units. So the one area where we could add units is at Riverview. We could add a unit there, but we're not anticipating to do that. I think that if there's any incremental demand, that we could potentially just work a little bit more overtime on the weekends and things of that nature. But I think our primary growth is going to just be an improved productivity. We're very focused on improving our productivity, and specifically in Illinois Basin, we're encouraged by some of the investments we've made in our equipment.
Speaker #4: We do not plan to add any units. So, the one area where we could add units is at Riverview. We could add a unit there.
Speaker #4: But we're not anticipating doing that. I think that if there's any incremental demand, we could potentially just work a little bit more—overtime, on the weekends, and things of that nature.
Speaker #4: But I think our primary growth is going to just be in improved productivity. We're very focused on improving our productivity, and specifically in the Illinois Basin.
Speaker #4: We're encouraged by some of the investments we've made in our equipment. We had the joint development agreement with Infinitum, where we're converting some of our shuttle cars to the technology utilizing the Infinitum motor.
Operator: We had the joint development agreement with Infinitum, where we're converting some of our shuttle cars to the technology utilizing the Infinitum motor, and that's proving to be a very attractive improvement in our productivity. And we're rolling that out with our shuttle car rebuilds. So we do think that there could be an opportunity if things continue to progress on the trend line that they are, that we could show a little higher production in Illinois Basin for our continuous miner operations as we focus on productivity improvements. But we're not adding or planning to add any additional capital to increase with units and things of that nature. If a customer wants to come and lock up tons for a longer term, we would consider that. But at this moment, there's no plans to do so. Okay. Got it. Thank you for that.
We had the joint development agreement with Infinitum, where we're converting some of our shuttle cars to the technology utilizing the Infinitum motor, and that's proving to be a very attractive improvement in our productivity. And we're rolling that out with our shuttle car rebuilds. So we do think that there could be an opportunity if things continue to progress on the trend line that they are, that we could show a little higher production in Illinois Basin for our continuous miner operations as we focus on productivity improvements. But we're not adding or planning to add any additional capital to increase with units and things of that nature. If a customer wants to come and lock up tons for a longer term, we would consider that. But at this moment, there's no plans to do so.
Speaker #4: And that's proving to be a very attractive improvement in our productivity. And we're rolling that out with our new shuttle car rebuilds. So we do think that there could be an opportunity, if things continue to progress on the trend line that they are, that we could show a little higher production in the Illinois Basin for our continuous miner operations.
Speaker #4: As we focus on productivity—not adding or planning to add improvements—but were any additional capital to increase with units and things of that nature.
Speaker #4: If a customer wants to come and lock up tons for a longer term, we would consider that. But at this moment, there's no plans to do so.
Speaker #4: so. Okay.
Nathan Martin: Okay. Got it. Thank you for that.
Speaker #3: Got it. Thank you for that. And then maybe one final, more modeling question—maybe for Cary. Equity method investments benefited from that $17.5 million in income.
Operator: And then maybe one final more modeling question, maybe for Cary. Equity method investments benefited from that $17.5 million in income from your previous investment at the Gavin coal-fired power plant. Cary, any thoughts on how to model that going forward, or is it just going to be lumpy? And then maybe any updates on other potential investment opportunities like that that you guys see in the marketplace today. Thank you. Yeah. Sure. Sure, Nate, on that. I think when you look at that equity investment income, I think taking out the part associated with the increase in the fair value of the equity method investment is fair to do. So I think as you look at it on a going forward basis, we were at $17 million here.
And then maybe one final more modeling question, maybe for Cary. Equity method investments benefited from that $17.5 million in income from your previous investment at the Gavin coal-fired power plant. Cary, any thoughts on how to model that going forward, or is it just going to be lumpy? And then maybe any updates on other potential investment opportunities like that that you guys see in the marketplace today. Thank you.
Speaker #3: From your previous investment at the Gavin Coal-Fired Power Plant, Cary, any thoughts on how to model that going forward? Or is it just going to be lumpy?
Speaker #3: And then, maybe, any updates on other potential investment opportunities like that, that you guys see in the marketplace today? Thank you.
Cary Marshall: Yeah. Sure. Sure, Nate, on that. I think when you look at that equity investment income, I think taking out the part associated with the increase in the fair value of the equity method investment is fair to do. So I think as you look at it on a going forward basis, we were at $17 million here.
Speaker #2: Yeah, sure. Sure, Nate, on that. I think when you look at that equity investment income, I think taking out the part associated with the increase in the fair value of the equity method investment is fair to do.
Speaker #2: So I think, as you look at it on a going-forward basis, we were at $17 million here. I think a lower run rate on that, more along the lines of $3 million or so per quarter, is probably a fair number to take a look at here from a modeling perspective going forward.
Operator: I think a lower run rate on that, more along the lines of $3 million or so per quarter, is probably a fair number to take a look at here from a modeling perspective going forward, Nate. As far as looking at other opportunities, we are evaluating other opportunities to invest in existing coal-fired generation. So that is on our radar, and it would be great if we could find more opportunities that would deliver the results that the Gavin plant has afforded us. That's been a very good investment. Okay. Great. I'll pass it on. Appreciate the time, gentlemen, and best of luck. Thank you, Nate. Our next question is from the line of Matthew Key with Texas Capital. Please proceed with your question. Good morning, everyone, and thanks for taking my questions. I wanted to talk a little bit about expected sales cadence in 2026.
I think a lower run rate on that, more along the lines of $3 million or so per quarter, is probably a fair number to take a look at here from a modeling perspective going forward, Nate.
Speaker #2: Nate, as far as looking at
Joe Craft: As far as looking at other opportunities, we are evaluating other opportunities to invest in existing coal-fired generation. So that is on our radar, and it would be great if we could find more opportunities that would deliver the results that the Gavin plant has afforded us. That's been a very good investment.
Speaker #4: Other opportunities—we are evaluating other opportunities to invest in existing coal-fired generation. So that is on our radar, and it would be great if we could find more opportunities to deliver the results that the Gavin plant has afforded us.
Speaker #4: It's been a very good investment.
Nathan Martin: Okay. Great. I'll pass it on. Appreciate the time, gentlemen, and best of luck.
Speaker #3: Okay, great. I'll pass it on. Appreciate the time, gentlemen, and best of luck.
Cary Marshall: Thank you, Nate.
Speaker #2: Thank you, Nate.
Operator: Our next question is from the line of Matthew Key with Texas Capital. Please proceed with your question.
Speaker #1: Our next question is from the line of Matthew Key with Texas Capital. Please just see if your—
Speaker #1: questions. Good morning,
Matthew Key: Good morning, everyone, and thanks for taking my questions. I wanted to talk a little bit about expected sales cadence in 2026.
Speaker #5: Everyone, and thanks for taking my questions. I wanted to ask a little bit about expected sales cadence in 2026. Obviously, Matiki is expected to come offline in March 2026.
Operator: Obviously, Mettiki [is] expect[ed] to come offline in March 2026, and I think you mentioned that you'll have some catch-up sales and longwall moves as well. Just at a high level, how should we be thinking about cadence and quarterly sales as we go through this year? I think when you look at the quarterly sales, Q1 is going to be the lowest level for us throughout the year. So first level or Q1 will be on the low end. I would anticipate probably somewhere in the neighborhood [of] slight growth from where we were in Q4, maybe 1% to 2% in terms of total sales growth for the quarter. Q2 should be a little bit better. We do have the extended longwall move that I mentioned at Hamilton going on.
Obviously, Mettiki [is] expect[ed] to come offline in March 2026, and I think you mentioned that you'll have some catch-up sales and longwall moves as well. Just at a high level, how should we be thinking about cadence and quarterly sales as we go through this year?
Speaker #5: And I think you mentioned that you'll have some catch-up sales and long-haul moves as well. Just at a high level, how should we be thinking about cadence and quarterly sales as we go through this?
Speaker #5: Year? I think when you look at the
Joe Craft: I think when you look at the quarterly sales, Q1 is going to be the lowest level for us throughout the year. So first level or Q1 will be on the low end. I would anticipate probably somewhere in the neighborhood [of] slight growth from where we were in Q4, maybe 1% to 2% in terms of total sales growth for the quarter. Q2 should be a little bit better. We do have the extended longwall move that I mentioned at Hamilton going on.
Speaker #2: Quarterly sales in the first quarter are going to be at the lowest level for us throughout the year. So, the first level, or first quarter, will be on the low end.
Speaker #2: I would anticipate probably somewhere in the neighborhood, slight growth from where we were in the fourth quarter. Maybe 1 to 2 percent in terms of total sales growth for the quarter.
Speaker #2: Second quarter should be a little bit better. We do have the extended long-haul move that I mentioned at Hamilton going on really throughout the first quarter.
Operator: Really, throughout the first quarter, there is a longwall move scheduled for Tunnel Ridge in the second quarter, early on in the second quarter. So you should gradually get better in the second quarter. And then the last half of the year, we don't have any additional longwall moves. So those longwalls will be running full out at that particular point in time. So back half of the year, volumes will be the best volumes on a quarterly basis as we look quarterly throughout the year. Got it. That's helpful, Caller. And in regards to export sales for 2026, I see there's roughly 1.7 million tons committed. How do you expect export sales to compare to 2025 levels, and what type of netbacks are you currently seeing in that market? Yeah.
Really, throughout the first quarter, there is a longwall move scheduled for Tunnel Ridge in the second quarter, early on in the second quarter. So you should gradually get better in the second quarter. And then the last half of the year, we don't have any additional longwall moves. So those longwalls will be running full out at that particular point in time. So back half of the year, volumes will be the best volumes on a quarterly basis as we look quarterly throughout the year.
Speaker #2: There is a long-haul move scheduled for Tunnel Ridge in the second quarter. Early on in the second quarter, so you should gradually get better in the second quarter.
Speaker #2: And then, the last half of the year, we don't have any additional long haul moves. So those long hauls will be running full out at that particular point in time.
Speaker #2: So, back half of the year volumes will be the best volumes on a quarterly basis as we look quarterly throughout the year.
Matthew Key: Got it. That's helpful, Caller. And in regards to export sales for 2026, I see there's roughly 1.7 million tons committed. How do you expect export sales to compare to 2025 levels, and what type of netbacks are you currently seeing in that market?
Speaker #1: Got it. That's helpful, caller. And in regards to export sales for 2026, I see there's roughly 1.7 million tons committed. How do you expect export sales to compare to 2025 levels?
Speaker #1: And what type of netbacks are you currently seeing in that market?
Joe Craft: Yeah. I think going forward, right now, the only exposure we would have to the export market will be the MC Mining tons. I mentioned the 200,000 tons. So there's not much that we're looking at export. As always, we're primarily focused on our domestic customers, and we do believe with the demand they're going to have, that they're going to need all of the production that we have that's available. We do have the ability at Gibson to ship into that export market, but currently, we see the domestic market as having higher netbacks. So the only shipments we have are based on what we've contracted that we're really targeting in 2026, and those were based on prices that we entered into a year ago.
Speaker #4: Yeah, I think going forward right now, the only exposure we would have to the export market will be the MC Mining tons. I mentioned the 200,000 tons.
Operator: I think going forward, right now, the only exposure we would have to the export market will be the MC Mining tons. I mentioned the 200,000 tons. So there's not much that we're looking at export. As always, we're primarily focused on our domestic customers, and we do believe with the demand they're going to have, that they're going to need all of the production that we have that's available. We do have the ability at Gibson to ship into that export market, but currently, we see the domestic market as having higher netbacks. So the only shipments we have are based on what we've contracted that we're really targeting in 2026, and those were based on prices that we entered into a year ago.
Speaker #4: So, there's not much that we're looking at export. We're, as always, primarily focused on our domestic customers, and we do believe, with the demand they're going to have, that they're going to need all of the production that we have that's available.
Speaker #4: We do have the ability at Gibson to ship into that export market, but currently, we see the domestic market as having a higher netback.
Speaker #4: So, the only shipments we have are based on what we've had contracted that we're really targeting in '26. And those were based on prices that we entered into a year ago.
Speaker #4: So the actual netbacks that we're looking at right now—I can't give you a number because we're not actively looking at that market, other than at MC, where the netbacks have been around $83, I think, or $85.
Operator: So the actual netbacks that we're looking at right now, I can't give you a number because we're not actively looking at that market other than at MC, where the netbacks have been around $83, I think, or $85 for the small tonnage that we did book this month. Got it. That's helpful. Thank you for your time, and best of luck moving forward. Thank you, Matt. Our next question is from the line of Mark Reichman with Noble Capital Markets. Please receive your questions. Good morning. It was interesting this morning. The EIA had kind of a report out on the monthly wholesale electricity prices. And just like, for example, in the Mid-Atlantic and the Midwest regions, the total generation increased 3% or 49 billion kWh. But natural gas declined while coal generation increased by 49 billion kWh.
So the actual netbacks that we're looking at right now, I can't give you a number because we're not actively looking at that market other than at MC, where the netbacks have been around $83, I think, or $85 for the small tonnage that we did book this month.
Speaker #4: For the small tonnage that we did book this month.
Matthew Key: Got it. That's helpful. Thank you for your time, and best of luck moving forward.
Speaker #1: Got it. That's helpful. Thank you for your time, and best of luck moving forward.
Cary Marshall: Thank you, Matt.
Speaker #2: Thank you,
Speaker #2: Matt. Our next question is
Operator: Our next question is from the line of Mark Reichman with Noble Capital Markets. Please receive your questions.
Speaker #1: In the line of Mark Reichman with Noble Capital Markets. Please just see if you have questions.
Mark Reichman: Good morning. It was interesting this morning. The EIA had kind of a report out on the monthly wholesale electricity prices. And just like, for example, in the Mid-Atlantic and the Midwest regions, the total generation increased 3% or 49 billion kWh. But natural gas declined while coal generation increased by 49 billion kWh.
Speaker #6: Good morning. It's interesting, this morning the EIA had kind of a report out on the monthly wholesale electricity prices. And just like, for example, in the Mid-Atlantic and the Midwest—regions that total generation increased 3%, or 49 billion kilowatt-hours.
Speaker #6: But natural gas declined, while coal generation increased by 49 billion kilowatt-hours. And so it looks like you saw a pretty healthy increase in coal in the Midwest, the Mid-Atlantic, Central, and even in the Southeast to some extent.
Operator: And so it looks like you saw pretty healthy increases in coal in the Midwest, the Mid-Atlantic, Central, and even in the Southeast to some extent. And I was just kind of curious, is it still kind of a horse race between the Spark Spread and the Dark Spread, or have we reached a point where for utilities, the reliability, the deliverability is more important? Well, during this winter storm, it was definitely the reliability. There were freeze-offs. There were a lot of utilities that were curtailing some of our customers, but the coal plants were running flat out for numerous reasons that coal does have an advantage in winter storms because we have storage on site. And I think that the freeze-offs did play a role on that.
And so it looks like you saw pretty healthy increases in coal in the Midwest, the Mid-Atlantic, Central, and even in the Southeast to some extent. And I was just kind of curious, is it still kind of a horse race between the Spark Spread and the Dark Spread, or have we reached a point where for utilities, the reliability, the deliverability is more important?
Speaker #6: And I was just kind of curious, is it still kind of a horse race between the spark spread and the dark spread, or have we reached a point where, for utilities, the reliability and the deliverability is more—
Speaker #6: important? Well,
Joe Craft: Well, during this winter storm, it was definitely the reliability. There were freeze-offs. There were a lot of utilities that were curtailing some of our customers, but the coal plants were running flat out for numerous reasons that coal does have an advantage in winter storms because we have storage on site. And I think that the freeze-offs did play a role on that.
Speaker #4: During this winter storm, it was definitely the reliability. There were freeze-offs. There were a lot of utilities that were curtailing—some of our customers. But the coal plants were running flat out.
Speaker #4: For the numerous reasons that coal does have an advantage in winter storms—because we have storage on site—and I think that the freeze-offs did play a role.
Speaker #4: On that, I think as far as February is, and as indicated earlier with the February pricing, we continue to believe that coal burns are going to be strong in February.
Operator: I think as far as February, as I indicated earlier with the February pricing, we continue to believe that coal burns are going to be strong in February. We are seeing March gas be very volatile. Gas prices have jumped $0.50 a day over the last week, so it's hard to predict exactly where that's going to go. But there was significant draw over the last week of natural gas in the regions where we market. So I believe that both demand for data centers, the winter that we have, we're in good position relative to coal and gas demand for 2026, at least through the first half of the year. And then we'll focus on the next half when we start anticipating what the weather demands and the energy demand or the actual demand for electricity is in the second half of the year.
I think as far as February, as I indicated earlier with the February pricing, we continue to believe that coal burns are going to be strong in February. We are seeing March gas be very volatile. Gas prices have jumped $0.50 a day over the last week, so it's hard to predict exactly where that's going to go. But there was significant draw over the last week of natural gas in the regions where we market. So I believe that both demand for data centers, the winter that we have, we're in good position relative to coal and gas demand for 2026, at least through the first half of the year. And then we'll focus on the next half when we start anticipating what the weather demands and the energy demand or the actual demand for electricity is in the second half of the year.
Speaker #4: We are seeing March gas be very volatile. Gas prices have jumped $0.50 a day over the last week, so it's hard to predict exactly where that's going to go.
Speaker #4: But there was significant draw over the last week of natural gas in the regions where we market. So I believe that both demand for data centers, the winter that we have, we're in good position relative to coal on gas.
Speaker #4: Demand for 2026, at least through the first half of the year. And then we'll focus on the next half when we start anticipating what the weather demands and the energy demand, or the actual demand for electricity, is in the second half of the year.
Speaker #4: But I think we're in very good shape. From a coal perspective, to see the demand in 2026—and as we mentioned, we do believe that supply is pretty limited.
Operator: But I think we're in very good shape from a coal perspective to see the demand in 2026. And as we mentioned, we do believe that supply is pretty limited. I mean, supply increase is limited, so that should bode well on supply-demand balance as far as pricing as we roll into the midyear and start thinking about pricing for 2027 going forward. Yeah, I would think so. Cary, maybe you looked at this wrong, but I was just kind of curious, the guidance on the total sales tons for coal versus the royalty tons sold, I mean, there was a bigger delta between, say, the 2025 guidance and the 2026 guidance between those two segments. What was driving that? So when we're looking at 2026, I think you were kind of for 2026 for royalty tons, you're 30 to 30.8.
But I think we're in very good shape from a coal perspective to see the demand in 2026. And as we mentioned, we do believe that supply is pretty limited. I mean, supply increase is limited, so that should bode well on supply-demand balance as far as pricing as we roll into the midyear and start thinking about pricing for 2027 going forward.
Speaker #4: I mean, supply increase is limited, so that should bode well for the supply-demand balance as far as pricing. As we roll into the mid-year and start thinking about pricing for '27 going forward.
Mark Reichman: Yeah, I would think so. Cary, maybe you looked at this wrong, but I was just kind of curious, the guidance on the total sales tons for coal versus the royalty tons sold, I mean, there was a bigger delta between, say, the 2025 guidance and the 2026 guidance between those two segments. What was driving that?
Speaker #1: Yeah, I would think so. Now, I may be looking at this wrong, but I was just kind of curious. The guidance on the total sales tons for coal versus the royalty tons sold—there was a bigger delta between, say, the 2025 guidance and the 2026 guidance.
Speaker #1: Between those two segments, what was driving
Speaker #1: So when we're looking at 2026, I think you were kind of, I think you were for '26—for royalty tons, you're 30 to 30.8.
Joe Craft: So when we're looking at 2026, I think you were kind of for 2026 for royalty tons, you're 30 to 30.8.
Speaker #1: I think '25 guidance was 23 and a half to 24.50. So that's a pretty big delta whereas the total sales tons, it was 32 and a half to 33.25 last year.
Operator: I think 2025 guidance was 23.5 to 24.50. So that's a pretty big delta, whereas the total sales tons was 32.5 to 33.25 last year, and now it's 33.75 to 35.25. Yeah. I think, Mark, I think what the biggest delta is in there in terms of coal royalty tons and the increase that you're seeing is the movement over at Tunnel Ridge into the new district is leading to higher coal royalty volumes associated with that new district. So that new district does have we do lease those Tunnel Ridge does lease those from our coal royalty division there. And then additionally, we've got higher volumes projected coming from our Hamilton operation as well. And so those are the two primary differences that are leading to the increase in the guidance range, the largest of which is going to be at Tunnel Ridge.
I think 2025 guidance was 23.5 to 24.50. So that's a pretty big delta, whereas the total sales tons was 32.5 to 33.25 last year, and now it's 33.75 to 35.25.
Speaker #1: Now it's 33.75 and 35.25.
Cary Marshall: Yeah. I think, Mark, I think what the biggest delta is in there in terms of coal royalty tons and the increase that you're seeing is the movement over at Tunnel Ridge into the new district is leading to higher coal royalty volumes associated with that new district. So that new district does have we do lease those Tunnel Ridge does lease those from our coal royalty division there. And then additionally, we've got higher volumes projected coming from our Hamilton operation as well. And so those are the two primary differences that are leading to the increase in the guidance range, the largest of which is going to be at Tunnel Ridge.
Speaker #2: Yeah, I think—Mark, I think what the biggest delta is in there, in terms of coal royalty tons and the increase that you're seeing, is the movement over at Tonal Ridge into the new district.
Speaker #2: Is leading to higher coal royalty volumes associated with that new district. So, that new district does have—we do lease those; Tonal Ridge does lease those from our coal royalty division there.
Speaker #2: And then additionally, we've got higher volumes projected coming from our Hamilton operation as well. And so, those are the two primary differences that are leading to the increase in the guidance range.
Speaker #2: The largest of which is going to be at Tonal Ridge. Really, all of the Tonal Ridge volumes now that we will be selling will flow into our coal royalties area.
Operator: Really, all of the Tunnel Ridge volumes now that we will be selling will flow into our coal royalties area. That was based on an acquisition we did a couple of years ago of reserves in that district. Okay. No, that's very helpful. Thank you very much. Thank you, Mark. Thank you. The next question is from the line of Michael Mathison with Sidoti & Company. Please proceed with your question. Good morning, you guys, and congratulations on all the visibility for coal over the past few weeks. Thank you. Coming to my questions, you referred briefly to 2027 pricing. With demand increasing the way it's been, are you seeing firmer pricing, and could you put any color behind that?
Really, all of the Tunnel Ridge volumes now that we will be selling will flow into our coal royalties area. That was based on an acquisition we did a couple of years ago of reserves in that district.
Speaker #4: Yeah, that was based on an acquisition we did a couple of years ago. That reserves in that district.
Mark Reichman: Okay. No, that's very helpful. Thank you very much.
Speaker #1: Okay, no, that's very helpful. Thank you very much.
Speaker #1: Okay. No, that's very helpful. Thank you very much. Thank you.
Cary Marshall: Thank you, Mark.
Speaker #2: you, Mark.
Speaker #1: Thank you. The next question is from the line of Michael Matheson with Sedotian Company. Please just see if you have any questions.
Mark Reichman: Thank you. The next question is from the line of Michael Mathison with Sidoti & Company. Please proceed with your question.
Michael Mathison: Good morning, you guys, and congratulations on all the visibility for coal over the past few weeks.
Speaker #7: Good morning, you guys, and congratulations on all the visibility for coal over the past few.
Speaker #7: weeks. Thank
Cary Marshall: Thank you.
Michael Mathison: Coming to my questions, you referred briefly to 2027 pricing. With demand increasing the way it's been, are you seeing firmer pricing, and could you put any color behind that?
Speaker #7: Coming to my you. questions, you referred briefly to 2027 pricing. With demand increasing the way it's been, are you seeing firmer pricing, and could you put any color behind that?
Speaker #7: that? Well, of
Speaker #4: The tons that we contracted this year, over this last quarter, I think we did contract one and a half million tons. In 2027, that tonnage did price a little bit higher than the high end of our range.
Operator: Of the tons that we contracted this year over this last quarter, I think we did contract 1.5 million tons in 2027, and that tonnage did price a little bit higher than the high end of our range that we got right at the high end of the range for 2026. It was a little higher than what our Q4 sales prices were. Going in the out years, we had one contract that actually was a five-year contract, so we are seeing increases on a yearly basis. For that contract, we had two other contracts that were three years, 2026, 2027, 2028 timeframe. So those prices, mostly, they were all in Illinois Basin, and they were priced at the high end of our 2026 range in 2027, and then they got a little higher than that in 2028 going forward.
Joe Craft: Of the tons that we contracted this year over this last quarter, I think we did contract 1.5 million tons in 2027, and that tonnage did price a little bit higher than the high end of our range that we got right at the high end of the range for 2026. It was a little higher than what our Q4 sales prices were. Going in the out years, we had one contract that actually was a five-year contract, so we are seeing increases on a yearly basis. For that contract, we had two other contracts that were three years, 2026, 2027, 2028 timeframe. So those prices, mostly, they were all in Illinois Basin, and they were priced at the high end of our 2026 range in 2027, and then they got a little higher than that in 2028 going forward.
Speaker #4: That we've got right in at the high end of the range. For 2026, it was a little higher than what our fourth quarter sales prices were.
Speaker #4: Going into the out years, we had one contract that actually was a five-year contract, so we are seeing increases on a yearly basis for that contract. We had two other contracts that were three years.
Speaker #4: ‘26, ‘27, ‘28 time frame. So those prices, mostly, they were all in the Illinois Basin. And they were priced at the high end of our 2026 range.
Speaker #4: In '27, and then they got a little higher than that in '28 going forward. So that, again, as I mentioned, in our guidance we really didn't reflect what we saw with the Arctic weather and the higher gas prices.
Operator: So again, as I mentioned in our guidance, we really didn't reflect what we saw with the Arctic weather and the higher gas prices. So if we were to contract today, those prices would be higher. Now, how long that sustains itself is totally dependent on energy demand and what gas prices do going forward. Well, in trying to look at longer-term demand factors, inventory of coal-fueled power plants was significantly down in 2025, big burn-off already here in Q1 2026. Do you see inventories at this level just kind of making where you were last year almost a trough in pricing, and we should look at just higher pricing going forward for the new normal? I think so. I think that, again, the supply is limited. I don't think we're going to see supply growth. We're actually seeing some mines that will deplete over the next three years.
So again, as I mentioned in our guidance, we really didn't reflect what we saw with the Arctic weather and the higher gas prices. So if we were to contract today, those prices would be higher. Now, how long that sustains itself is totally dependent on energy demand and what gas prices do going forward.
Speaker #4: So, if we were to contract today, those prices would be higher. Now, how long that sustains itself is totally dependent on energy demand and what gas prices do going forward.
Speaker #4: Forward. Well, in trying to look at
Michael Mathison: Well, in trying to look at longer-term demand factors, inventory of coal-fueled power plants was significantly down in 2025, big burn-off already here in Q1 2026. Do you see inventories at this level just kind of making where you were last year almost a trough in pricing, and we should look at just higher pricing going forward for the new normal?
Speaker #1: Longer-term demand factors—inventory of coal held at power plants was significantly down in '25. Big burn-off already here in Q1 '26. Do you see inventories at this level just kind of making where you were last year almost a trough in pricing, and we should look at just higher pricing going forward for the new normal?
Joe Craft: I think so. I think that, again, the supply is limited. I don't think we're going to see supply growth. We're actually seeing some mines that will deplete over the next three years.
Speaker #4: I think so. I think that, again, the supply is limited. I don't think we're going to see supply growth. We're actually seeing some mines that will deplete over the next three years.
Speaker #4: I don't believe that those companies are going to recap to try to maintain that volume, so I do see supply pretty flat, trending down.
Operator: I don't believe that those companies are going to recap to try to maintain that volume. So I do see supply pretty flat trending down for the domestic Eastern markets, and I do believe the demand's going to go up. We've seen the extra capacity these coal units have available based off the coal burn we've seen in January. And as demand goes up for data centers and those data centers are completed, I expect that our energy demand for coal for data centers will, in fact, go up. So that should put us in a favorable supply-demand perspective that would support higher pricing. Well, great. That's very helpful. So thank you, and good luck in coming quarters. Thank you. Thank you. Thank you. At this time, we've reached the end of our question-and-answer session. I'll hand the floor back to Cary Marshall for closing comments. Thank you, operator.
I don't believe that those companies are going to recap to try to maintain that volume. So I do see supply pretty flat trending down for the domestic Eastern markets, and I do believe the demand's going to go up. We've seen the extra capacity these coal units have available based off the coal burn we've seen in January. And as demand goes up for data centers and those data centers are completed, I expect that our energy demand for coal for data centers will, in fact, go up. So that should put us in a favorable supply-demand perspective that would support higher pricing.
Speaker #4: For the domestic eastern markets, and I do believe the demand is going to go up. We've seen the extra capacity these coal units have available based off the coal burn we've seen in January, and as demand goes up for data centers and those data centers are completed, I expect that our energy demand for coal for data centers will, in fact, go up.
Speaker #4: So that should put us in a favorable supply-demand perspective. That would support higher—
Speaker #1: Well, great. That's very helpful, so thank you. And good luck in the coming quarters.
Michael Mathison: Well, great. That's very helpful. So thank you, and good luck in coming quarters.
Speaker #1: quarters.
Joe Craft: Thank you.
Speaker #4: Thank you. Thank
Cary Marshall: Thank you.
Speaker #1: Thank you. At this time, we've reached the end of our question-and-answer session. I hand the floor back to Cary Marshall for closing comments.
Speaker #1: Thank you. At this time, we've reached the end of our question-and-answer session. I hand the floor back to Cary Marshall for closing comments.
Operator: Thank you. At this time, we've reached the end of our question-and-answer session. I'll hand the floor back to Cary Marshall for closing comments.
Cary Marshall: Thank you, operator. To everyone on the call, we appreciate your time this morning and also your continued support and interest in Alliance. Our next call to discuss our Q1 2026 financial and operating results is currently expected to occur in April, and we hope everyone will join us again at that time. This concludes our call for the day. Thank you.
Speaker #2: Thank you, operator. To everyone on the call, we appreciate your time this morning and also your continued support and interest in Alliance. Our next call to discuss our first quarter 2026 financial and operating results is currently expected to occur in April, and we hope everyone will join us again at that time.
Operator: To everyone on the call, we appreciate your time this morning and also your continued support and interest in Alliance. Our next call to discuss our Q1 2026 financial and operating results is currently expected to occur in April, and we hope everyone will join us again at that time. This concludes our call for the day. Thank you. Ladies and gentlemen, thank you for your participation. This does conclude today's teleconference. You may disconnect your lines at this time and have a wonderful day.
Speaker #2: This concludes our call for the day. Thank you.
Speaker #2: This concludes our call for the day. Thank you. Ladies and gentlemen, thank you for your participation.
Operator: Ladies and gentlemen, thank you for your participation. This does conclude today's teleconference. You may disconnect your lines at this time and have a wonderful day.
