October 3, 2025

​

Via EDGAR

​

Securities and Exchange Commission

Division of Corporation Finance

100 F Street, N.E.

Washington, D.C. 20549

​

​

Ladies and Gentlemen:

​

This letter sets forth the responses of Alliance Resource Partners, L.P. (the “Partnership”) to the comments provided by the staff (the “Staff”) of the Securities and Exchange Commission in its comment letter dated September 5, 2025 (the “Comment Letter”) with respect to the Form 10-K for the year ended December 31, 2024 filed by the Partnership on February 27, 2025 (the “Form 10-K”).

​

For your convenience, we have repeated each comment of the Staff exactly as given in the Comment Letter in bold and italics below and provided our response below to each such comment. We respectfully believe that the proposed changes are appropriately made in future filings, as they do not appear to so materially impact extant disclosure as to necessitate an amendment to our Form 10-K, a conclusion which we would be happy to discuss with the Staff should you have any questions.

​

Properties

Oil & Gas Reserves

Summary of Oil & Gas Reserves, page 74

​

​

Your discussion should clearly identify the source of each change, e.g. revisions, improved recovery, extensions and discoveries, transfers to proved developed, sales and acquisitions, and include an explanation relating to each of the items you identify. If two or more unrelated factors are combined to arrive at the overall change for an item, you should separately identify and quantify each factor so the change in net reserve quantities between periods is fully explained.

​

The disclosure of revisions in previous estimates of your proved undeveloped reserves should identify the changes associated with individual factors, such as changes caused by commodity prices, costs, royalty adjustments, well performance, unsuccessful and/or uneconomic proved undeveloped locations, or the removal of proved undeveloped locations due to changes in a previously adopted development plan.

​

Please similarly revise your discussion of changes in the net quantities of total proved reserves due to revisions under the section “Oil & Gas Reserves” on page 148, to comply with FASB ASC 932-235-50-5.

​

Response: We acknowledge the Staff’s comment and in response we propose an expanded discussion of the changes in our proved undeveloped reserves in future filings as illustrated below:

​

During the year ended December 31, 2024, PUD reserves were reduced as a result of conversion to proved developed reserves primarily in the Permian and Anadarko basins as the result of well completions during the year.

​

Extensions and discoveries contributed to an increase in PUD reserves during the year ended December 31, 2024 primarily as the result of permitting activities in the Permian Basin.

​

Revisions of previous estimates resulted in a decline of 13 MBOE due to changes in the underlying commodity prices during the year and 426 MBOE due to revisions to quantity estimates across all basins.

​

With respect to our discussion of the changes in net quantities of total proved reserves due to revisions under the section “Oil & Gas Reserves” on page 148, we propose expanding our discussion in future filings to include the language as illustrated below in bold.

​

Notable changes in proved reserves during the year ended December 31, 2022, included:

​

​

​

Notable changes in proved reserves during the year ended December 31, 2023, included:

​

​

​

Notable changes in proved reserves during the year ended December 31, 2024, included:

​

​

​

​

If material amounts of your proved undeveloped reserves will not be converted to proved developed status within five years of initial disclosure as proved reserves, please also expand your disclosure to explain the reasons for the delay.

​

You may refer to Item 1203(d) of Regulation S-K and Question 131.03 in the Compliance and Disclosure Interpretations (C&DIs) regarding Oil and Gas Rules if you require further clarification or guidance.

​

Response: We acknowledge the Staff’s comment and in response propose clarifying our disclosures in future filings to include the language illustrated below in bold.

​

As a mineral interest owner we have no transparency into or control over the operators’ investments and operational progress to convert PUDs to proved developed producing reserves nor do we have insight into the operators’ drilling plans. Since we do not have insight into the operators’ drilling plans, we use active drilling permits as evidence of economic viability and intention to expend capital to develop reserves within five years as there is generally a statutory two-year timeframe associated with permits. We do not incur any capital expenditures or lease operating expenses in connection with the development of our PUDs, which costs are borne entirely by the operators. As a result, during the year ended December 31, 2024, we did not have any expenditures to convert PUDs to proved developed producing reserves. PUDs that have not been developed within two years of permitting are reviewed and removed from proved reserves as necessary. Because we remove PUDs from proved reserves that have not been developed within two years of initial classification as proved reserves, we have no material PUDs that will not be developed within five years of initial classification as proved reserves. Since January 1, 2022, our average permit to first sales timeframe is 383 days. For our 2024 reserve reporting we had scheduled all PUD locations to be drilled within a year and a half using the average historical development pacing on our acreage in the individual basins in which we own mineral interests. As of December 31, 2024, approximately 10.87% of our total proved reserves were classified as PUDs.

​

Evaluation and Review of Reserves, page 75

​

​

Response: We acknowledge the Staff’s comment and in response propose to include the following expanded discussion in future filings as illustrated below.

​

Non-producing reserve estimates, for both developed and undeveloped properties, are based on regional type curve methodologies by reservoir or productive bench. These methods provide a relatively high degree of accuracy for predicting proved developed non-producing and undeveloped reserves for our properties, due to the mature nature of properties targeted for development and an abundance of historical production data on which we base statistical average type forecasts.

​

New drills on our acreage include planned drills, wells currently drilling, and/or permitted wells. For each new drill, a reserve category of proved developed non-producing or PUD is assigned based on whether the location has been spud or permitted. Generally, we book a location as a PUD when it has been permitted by the operator and a PUD becomes a proved developed non-producing reserve when the operator has spud that well to begin drilling operations.

​

Drill scheduling is determined by historical development pacing on our acreage in each basin and it is assumed that future pacing will mirror that of the historical pace. This projection is then adjusted to take into account anticipated commodity prices and other industry economic factors which tend to either reduce or increase future development pacing. First, known completed locations are developed in chronological order based on state filings or publicly sourced completion data. The development schedule for these locations estimates the turn-in-line rate of these locations due to production data lag. Second, spud locations with unknown completion status are scheduled based on the historical spud to completion time within each basin. Third, permitted locations, without development timing, are scheduled in chronological order by filing date.

​

​

Response: We acknowledge the Staff’s comment and in response propose clarifying our disclosures in future filings to include the language illustrated below in bold.

​

Excluding our share of proved reserves held by AllDale III, our 2024 year-end estimate of proved reserves were prepared by our internal engineering team. Our engineering team works to ensure the integrity, accuracy, and timeliness of the data used to calculate our estimated proved reserves. Our proved reserve estimates, with the exception of AllDale III, which comprise 4.2% of our total proved reserves, were audited by CGA. Our engineering team met with CGA periodically during the period covered by the above referenced reserve report to discuss the assumptions and methods used in the reserve estimation process. Our engineering team provided historical information to CGA for our properties, such as oil & gas production, well test data, and realized commodity prices. Our engineering team also provided ownership interest information with respect to our properties. Our internal petroleum engineer, primarily responsible for overseeing the petroleum reserves preparation, has over 20 years of engineering and operations experience in the oil & gas sector and a Bachelor of Science in Petroleum Engineering.

​

Acreage Concentrations, page 77

​

​

Response: We acknowledge the Staff’s comment and in response propose expanding our disclosure in future filings as illustrated below.

​

The 50,755 developed and undeveloped net mineral acres in the table above represent the number of acres that are owned for the mineral rights under a given tract of land, whereas the 69,393 developed and undeveloped net royalty acres are our net mineral acres normalized to 1/8^th royalty leasing terms. As an example, if 100 net mineral acres were leased for a 25% royalty, this would be equivalent to 200 net royalty acres, normalized to 1/8^th royalty (100 x .25/.125 = 200).

​

​

Response: We acknowledge the Staff’s comment and in response we propose expanding our disclosure in future filings as illustrated below.

​

Our royalty interests are predominately perpetual mineral interests. As a mineral interest owner, we generally hold our acreage in perpetuity and not through a lease. As a result, our undeveloped acreage is generally not subject to expiration. Our royalty interests do include a small portion that come in the form of overriding royalites (ORRI) that are subject to lease terminations once the wells on that lease cease to produce oil & gas in commercial quantities, As a result, we do have limited long-dated lease expiration exposure; however, nearly all of these ORRIs are part of leases with proved developed producing reserves and ongoing development that we believe will be sufficient to maintain these leases for decades.

​

Oil & Gas Production, Prices and Production Costs, page 77

​

​

You may refer to the disclosure requirements in Item 1204(a) of Regulation S-K and the definition of a field in Rule 4-10(a)(15) of Regulation S-X if you require further clarification or guidance.

​

Response: We acknowledge the Staff’s comment and in response we propose to include BOE production by basin in our production table in future filings as illustrated below.

​

​

Productive Wells, page 77

​

​

Response: We acknowledge the Staff’s comment and address the comment in our response to comment 10 below.

​

​

Response: We acknowledge the Staff’s comment and address the comment in our response to comment 10 below.

​

​

For the purposes of disclosing “net” productive wells and “net” wells drilled during each of the last three fiscal years pursuant to Items 1208(a) and 1205 of Regulation SK, the net revenue interest may be utilized as a substitute for these disclosures, consistent with your disclosure of the “net” developed and undeveloped mineral acreage pursuant to Item 1208 of Regulation S-K.

​

Response: We acknowledge the Staff’s comment and in response propose expanding our disclosure of productive wells and drilling results in future filings as illustrated below.

​

Productive Wells

​

As of December 31, 2024, our productive wells were as follows:

​

​

Productive wells consist of producing wells and wells capable of production, including natural gas wells awaiting pipeline connections to commence deliveries and oil wells awaiting connection to production facilities. We do not own any material working interests in any wells and therefore have used our net revenue interest to determine our net wells.

​

Drilling Results

​

As a holder of mineral interests, we generally are not provided with information as to whether wells drilled on the acreage associated with our mineral interests are classified as exploratory or as developmental wells. We are not aware of any dry holes drilled on the acreage associated with our mineral interests during the year ended December 31, 2024. Based on our net revenue interests, 9, 10 and 4 net wells were drilled on our interests during the years ended December 31, 2024, 2023 and 2022, respectively.

​

Supplemental Oil & Gas Reserve Information (Unaudited)

Oil & Gas Reserves, page 148

​

​

However, as FASB ASC 932-235-50-8c pertains to the disclosures prescribed by FASB ASC 932-235-50-4, you should additionally disclose this information separately for your consolidated interests and equity method investee interests. For additional guidance regarding the disclosure of reserve quantity information, please refer to the illustration and accompanying notes in FASB ASC 932-235-55-2.

​

Also expand your disclosure to include the net quantities of proved developed and proved undeveloped reserves at the beginning of the initial year shown in the reserves reconciliation, i.e. as of January 1, 2022 (for the year ended December 31, 2022) to comply with FASB ASC 932-235-50-4.

​

Response: We acknowledge the Staff’s comment and in response we intend to provide the requested information with respect to proved developed and proved undeveloped reserves separately for our consolidated interests and our equity method investee interests in future filings as illustrated in the table below.

​

​

​

* * *

​

​

Please direct any questions or comments regarding the foregoing to the undersigned or to our counsel at Vinson & Elkins L.L.P., David Oelman at (713)758-3708 or doelman@velaw.com or Brenda Lenahan at (212) 237-0133 or blenahan@velaw.com.

​

​