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CORRESP
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Correspondence Letter

 Brian L. Cantrell

 Senior Vice President and

 Chief Financial Officer

 918.295.7673

 February 29, 2008

 By Facsimile and Federal Express

 Ms. Anne Nguyen Parker

 Branch Chief

 Division of Corporation Finance

 Securities and Exchange Commission

 100F Street, N.E., Mail Stop 7010

 Washington, D.C. 20549

Re:
Alliance Resource Partners, L.P.

Form 10-K for the Fiscal Year Ended December 31, 2006

Filed March 1, 2007

File No. 0-26823

Form 10-Q for the Period Ended September 30, 2007

Filed November 9, 2007

 Dear Ms. Parker:

 This letter sets forth the responses of Alliance Resource Partners, L.P. (the “Partnership”) to the comments of the staff (the
“Staff”) of the Securities and Exchange Commission (the “Commission”) in its comment letter dated February 28, 2008 (the “Comment Letter”) with respect to the Partnership’s Annual Report
on Form 10-K for the fiscal year ended December 31, 2006 (the “2006 Form 10-K”) and Form 10-Q for the period ended September 30, 2007. For your convenience, we have repeated each comment of the Staff exactly as
given in the Comment Letter and set forth below each such comment is the Partnership’s response.

 The Partnership is in the process of
preparing its Annual Report on Form 10-K for the year ended December 31, 2007 (the “2007 Form 10-K”), which it will file today. Because the Partnership’s proposed disclosure revisions do not include a financial restatement
or otherwise material revisions to content, the Partnership respectfully requests that the Staff permit the Partnership to include the following changes on a prospective basis in its upcoming 2007 Form 10-K filings as well as in all subsequent
filings under the Securities Exchange Act of 1934, as amended, rather than amending its previous reports.

 1717 South Boulder, Suite 400, Tulsa, Oklahoma 74119

 P. O. Box 22027, Tulsa, Oklahoma
74121-2027

 Fax: (918) 295-7357

 Form 10-K for the year ended December 31, 2006

 River View, Penn Ridge, Tunnel Ridge, pages 5 & 7

 Coal reserves, page 31

 COMMENT

1.
In your responses to prior comments number 16 and 17 from our letter dated December 20, 2007, you indicate that you will provide certain disclosure in future filings. Please
provide specific of examples of the additional disclosure you propose to include in future filings.

 RESPONSE

 Attached as Annex A hereto are excerpts from our draft 2007 Form 10-K that show the additional disclosure items in response to your
prior comments. We have provided these excerpts to Ken Schuler supplementally. We hereby undertake that the disclosures set forth on Annex A will be included in the final form of the 2007 Form 10-K filed with the Commission.

 Segment Information, page 41

 COMMENT

2.
We note your response to prior comment number 5 with respect to your Segment Adjusted EBITDA Expense non-GAAP measure. Please further clarify how your measure is meaningful and
useful as a measure of your segment operating expenses. In this respect, it does not appear that you are currently reporting this measure as part of your segment disclosures. In addition, it does not appear that this measure correlates to your
Segment Adjusted EBITDA profitability measure you report in accordance with SFAS 131. Please further clarify the usefulness of this measure as it relates to your segments or revise the description of this measure in future filings to more
accurately reflect the use of the measure.

 RESPONSE

 Based on our telephone conference with members of the Staff on February 28, 2008 concerning this comment, we will include the following explanation
as to why we believe Segment Adjusted EBITDA Expense is meaningful and useful as a measure of our segment operating expenses:

(2)
Segment Adjusted EBITDA Expense includes operating expenses, outside purchases and other income. Transportation expenses are excluded as these expenses are passed through to our
customers, consequently we do not realize any margin on transportation revenues. Segment Adjusted EBITDA Expense is used as a supplemental financial measure by our management to assess the operating performance of our segments. In our evaluation of
EBITDA, which is discussed above under “- How We Evaluate Our Performance,” Segment Adjusted EBITDA Expense is a key component of EBITDA in addition to coal sales and other sales and operating revenues. The exclusion of
corporate general and administrative expenses from Segment Adjusted EBITDA Expense allows management to focus solely on the evaluation of segment operating performance as it primarily relates to our operating expenses. Outside purchases are included
in Segment Adjusted EBITDA Expense because tons sold and coal sales include sales from outside purchases.

 The following is a reconciliation of Segment Adjusted EBITDA Expense to Operating expense (in thousands):

Year Ended December 31,

2007

2006

 Segment Adjusted EBITDA Expense

$
705,669

$
646,033

 Outside purchases

(21,969
)

(19,213
)

 Other income

1,385

936

 Operating expense

$
685,085

$
627,756

 CLOSING COMMENTS

 In connection with these responses, the Partnership acknowledges that:

•

 the Partnership is responsible for the adequacy and accuracy of the disclosure in the filing;

•

 staff comments or changes to disclosure in response to Staff comments do not foreclose the Commission from taking any action with respect to the filing; and

•

 the Partnership may not assert Staff comments as a defense in any proceeding initiated by the Commission or any person under the federal securities laws of the
United States.

 If you have any questions or wish to discuss, please do not hesitate to contact me (918-295-7673), or our
legal counsel, David P. Oelman (713-758-3708) or Stephen M. Gill (713-758-4458), each of Vinson & Elkins L.L.P.

Sincerely,

/s/ Brian L. Cantrell

 Brian L. Cantrell

 Senior Vice President and Chief
Financial Officer

cc:
David P. Oelman, Vinson & Elkins L.L.P.

Stephen M. Gill, Vinson & Elkins L.L.P.

Mike Karney, Securities and Exchange Commission

 ANNEX A

 (Excerpts from the 2007 Form 10-K)

 UNITED STATES

 SECURITIES AND
EXCHANGE COMMISSION

 Washington, D.C. 20549

 FORM 10-K

x
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

 FOR THE FISCAL YEAR ENDED DECEMBER 31, 2007

 OR

¨
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

 FOR THE TRANSITION PERIOD FROM
TO

 COMMISSION FILE NO.: 0-26823

 ALLIANCE RESOURCE PARTNERS, L.P.

 (EXACT NAME OF REGISTRANT AS SPECIFIED IN
ITS CHARTER)

DELAWARE

73-1564280

 (STATE OR OTHER JURISDICTION OF

 INCORPORATION OR ORGANIZATION)

 (IRS EMPLOYER

 IDENTIFICATION NO.)

 1717 SOUTH BOULDER AVENUE, SUITE 400, TULSA, OKLAHOMA 74119

 (ADDRESS OF PRINCIPAL EXECUTIVE OFFICES AND ZIP CODE)

 (918) 295-7600

 (REGISTRANT’S TELEPHONE NUMBER, INCLUDING AREA CODE)

 Securities registered pursuant to Section 12(b) of the Act: Common Units representing limited partner interests

 Title of Each Class

 Name of Each Exchange On Which Registered

Common Units

NASDAQ Stock Market, LLC

 Securities registered pursuant to Section 12(g) of the Act: None

 Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.    x  Yes    ¨  No

 Indicate by check
mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.    ¨  Yes    x  No

 Indicate by check mark whether the registrant (1) has filed all reports required to be
filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for
the past 90 days.    x  Yes    ¨  No

 Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy
or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.  ¨

 Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See definitions of “large accelerated filer,”
“accelerated filer,” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (check one)

 Large Accelerated Filer  x    Accelerated Filer  ¨    Non-Accelerated Filer  ¨    Smaller Reporting Company  ¨

 (Do not check if smaller reporting company)

 Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the
Exchange Act).    ¨  Yes    x  No

 The aggregate value of the common units held by non-affiliates of the registrant (treating all executive officers and directors of the registrant, for this purpose, as if they may be affiliates of the registrant) was
approximately $857,632,818 as of June 29, 2007, the last business day of the registrant’s most recently completed second fiscal quarter, based on the reported closing price of the common units as reported on the NASDAQ Stock Market, LLC on
such date.

 As of February 25, 2008, 36,613,458 common units were outstanding.

 DOCUMENTS INCORPORATED BY REFERENCE: None

 Gibson Complex. Our subsidiary, Gibson County Coal, LLC (“Gibson County Coal”), operates
the Gibson mine, an underground mining complex located near the city of Princeton in Gibson County, Indiana. The mine began production in November 2000 and utilizes continuous mining units employing room-and-pillar mining techniques to produce
low-sulfur coal. The preparation plant has a throughput capacity of 700 tons of raw coal an hour. We refer to the reserves mined at this location as the “Gibson North” reserves. We also control undeveloped reserves in Gibson County that
are not contiguous to the reserves currently being mined, which we refer to as the “Gibson South” reserves.

 Production from
Gibson is a low-sulfur coal that historically has been primarily shipped via truck approximately 10 miles on U.S. and state highways to Gibson’s principal customer, PSI Energy Inc. (d/b/a Duke Energy Indiana, Inc.), a subsidiary of Cinergy
Corporation (d/b/a Duke Energy Corporation) (“PSI”). Gibson’s production is also trucked or railed to our Mt. Vernon transloading facility for sale to utilities capable of receiving barge deliveries. In 2007, we completed construction
of a new rail loop at Gibson, providing access to both the CSX and Norfolk Southern Railway Company (“NS”) railroads and expanding the market for coal produced at Gibson.

 In January 2005, Gibson County Coal entered into long-term agreements with PC Indiana Synthetic Fuel #2, L.L.C. (“PCIN”) to host its coal
synfuel facility, supply the facility with coal feedstock, assist PCIN with the marketing of coal synfuel and provide other services. The synfuel facility commenced operations at Gibson in May 2005. A significant portion of Gibson’s production
was sold to PCIN, providing us with coal sales, rental and service fees from PCIN based on the synfuel facility throughput tonnages. PCIN shipped coal synfuel to various customers that have been purchasers of our coal and with which we maintained
“back-up” coal supply agreements, which automatically provided for the sale of our coal to them in the event they did not purchase coal synfuel from PCIN. In 2008, our primary customer for coal produced at Gibson will be PSI, pursuant to a
long-term coal supply agreement that was one of these “back-up” agreements. On December 31, 2007, the federal non-conventional source fuel tax credit expired. As a result, and under their terms, the PCIN agreements expired on
December 31, 2007. For 2007, the incremental net income benefit from the combination of the various coal synfuel related agreements associated with the facility located at Gibson was approximately $4.3 million, assuming that coal pricing would
not have increased without the availability of synfuel. As such, while we will be able to sell the production that would have been sold to PCIN to PSI and other “back-up” purchasers, we may not be able to recover the incremental net income
benefit of the synfuel related operations.

 We have partially completed the permitting process for the Gibson South reserves and continue
to actively evaluate its development. Capital expenditures required to develop the Gibson South reserves are estimated to be in the range of approximately $100 million to $110 million, excluding capitalized interest and capitalized mine development
costs associated with net cost related to incidental production. For more information about mine development costs, please read “Mine Development Costs” under “Item 8. Financial Statements and Supplementary Data – Note 2. Summary
of Significant Accounting Policies.” Assuming sufficient sales commitments are obtained and the permitting process continues as anticipated, initial production could commence in 2010 to 2012. For more information on the permitting process, and
matters that could hinder or delay the process, please read “Regulation and Laws – Mining Permits and Approvals.” When the Gibson South mine reaches full production capacity, we expect annual production of approximately
2.7 million to 3.1 million tons. Definitive development commitment for Gibson South is dependent upon final approval by the board of directors of our managing general partner (“Board of Directors”).

 River View. In April 2006, we acquired 100% of the membership interest in River View Coal, LLC (“River View”) from ARH. River View
currently controls, through coal leases or direct ownership, approximately 117.1 million tons of proven and probable high-sulfur coal in the Kentucky No. 7, No. 9 and No. 11 coal seams underlying properties located primarily in
Union County, Kentucky, as well as certain surface properties, facilities and permits. River View is in the process of updating its existing permits and evaluating the timing and manner of future development of the reserve. We expect to develop
River View as an underground mining complex using continuous mining units employing room-and-pillar mining techniques, with production from the operation of four mining units and capacity to expand to up to eight mining units. In July 2007, we began
construction of the slope and shaft at River View. However, definitive development commitment for River View is dependent upon final approval of the Board of Directors. Capital expenditures required to develop the River View reserves are estimated
to be in the range of approximately $130 million to $160 million, excluding capitalized interest and capitalized mine development costs associated with net cost related to incidental production. For more information about mine development costs,
please read “Mine Development Costs” under “Item 8. Financial Statements and Supplementary Data – Note 2. Summary of Significant Accounting Policies.”

 6

 Production from the Mountain View mine in 2007 was primarily supplied to Mt. Storm Coal Supply, LLC
(“Mt. Storm”) for its synfuel facility, which was located at the Mt. Storm Power Station. Our agreement to supply coal to Mt. Storm terminated at the end of 2007 in conjunction with the termination of the synfuel tax credit program. For
2007, the incremental net income benefit from this agreement was approximately $1.8 million, assuming that coal pricing would not have increased without the availability of synfuel.

 Our primary customer for the medium-sulfur coal produced at Mettiki is VEPCO, which purchases the coal for use in the scrubbed generating units at its
Mt. Storm Power Station in West Virginia. A seven-year agreement to supply coal to the VEPCO Mt. Storm Power Station from the Mountain View mine was negotiated and finalized in June 2005. Prior to termination of our agreement to supply coa