Alliance Resource Partners (ARLP) 10-Q 2007 Q1 Quarterly report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

For the quarterly period ended March 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)

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.    Yes  x    No  ¨

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

Large Accelerated Filer  x    Accelerated Filer  ¨    Non-Accelerated Filer  ¨

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

As of May 10, 2007, 36,550,659 Common Units are outstanding.

TABLE OF CONTENTS

PART I

FINANCIAL INFORMATION

		Page
ITEM 1.	Financial Statements (Unaudited)	1
	Alliance Resource Partners, L.P. and Subsidiaries	1
	Condensed Consolidated Balance Sheets as of March 31, 2007 and December 31, 2006	1
	Condensed Consolidated Statements of Income for the three months ended March 31, 2007 and 2006	2
	Condensed Consolidated Statements of Cash Flows for the three months ended March 31, 2007 and 2006	3
	Notes to Condensed Consolidated Financial Statements	4
ITEM 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	14
ITEM 3.	Quantitative and Qualitative Disclosures about Market Risk	24
ITEM 4.	Controls and Procedures	24
	Forward-Looking Statements	25
	PART II
	OTHER INFORMATION
ITEM 1.	Legal Proceedings	27
ITEM 1A.	Risk Factors	27
ITEM 2.	Unregistered Sales of Equity Securities and Use of Proceeds	28
ITEM 3.	Defaults upon Senior Securities	28
ITEM 4.	Submission of Matters to a Vote of Security Holders	28
ITEM 5.	Other Information	28
ITEM 6.	Exhibits	28

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PART 1

FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

ALLIANCE RESOURCE PARTNERS, L.P. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

(In thousands, except unit data)

(Unaudited)

	March 31, 2007			December 31, 2006
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	40,792		$	36,789
Trade receivables, net		90,997			96,558
Other receivables		2,460			3,378
Due from affiliates		117			25
Marketable securities		—			260
Inventories		33,620			20,224
Advance royalties		3,309			4,629
Prepaid expenses and other assets		5,656			8,225
Total current assets		176,951			170,088
PROPERTY, PLANT AND EQUIPMENT:
Property, plant and equipment, at cost		846,935			819,991
Less accumulated depreciation, depletion and amortization		(399,316	)		(383,284	)
Total property, plant and equipment, net		447,619			436,707
OTHER ASSETS:
Advance royalties		24,713			22,135
Other long-term assets		8,207			6,032
Total other assets		32,920			28,167
TOTAL ASSETS	$	657,490		$	634,962
LIABILITIES AND PARTNERS’ CAPITAL
CURRENT LIABILITIES:
Accounts payable	$	60,264		$	57,879
Due to affiliates		976			1,414
Accrued taxes other than income taxes		15,520			14,618
Accrued payroll and related expenses		14,940			14,698
Accrued interest		1,282			4,264
Workers’ compensation and pneumoconiosis benefits		7,729			7,704
Current capital lease obligation		371			339
Other current liabilities		12,166			13,786
Current maturities, long-term debt		18,000			18,000
Total current liabilities		131,248			132,702
LONG-TERM LIABILITIES:
Long-term debt, excluding current maturities		126,000			126,000
Pneumoconiosis benefits		27,160			26,315
Accrued pension benefit		7,010			6,191
Workers’ compensation		42,276			38,488
Asset retirement obligations		48,301			47,825
Due to affiliates		1,160			994
Long-term capital lease obligation		1,420			1,512
Minority interest		757			839
Other liabilities		6,732			5,616
Total long-term liabilities		260,816			253,780
Total liabilities		392,064			386,482
COMMITMENTS AND CONTINGENCIES
PARTNERS’ CAPITAL:
Limited Partners—Common Unitholders 36,550,659 and 36,419,847 units outstanding, respectively		565,488			549,005
General Partners’ deficit		(293,106	)		(293,569	)
Accumulated other comprehensive income/minimum pension liability		(6,956	)		(6,956	)
Total Partners’ Capital		265,426			248,480
TOTAL LIABILITIES AND PARTNERS’ CAPITAL	$	657,490		$	634,962

See notes to condensed consolidated financial statements.

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ALLIANCE RESOURCE PARTNERS, L.P. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

(In thousands, except unit and per unit data)

(Unaudited)

	Three Months Ended March 31,
	2007			2006
SALES AND OPERATING REVENUES:
Coal sales	$	238,870		$	218,212
Transportation revenues		8,679			10,034
Other sales and operating revenues		9,522			10,074
Total revenues		257,071			238,320
EXPENSES:
Operating expenses		166,989			152,010
Transportation expenses		8,679			10,034
Outside purchases		6,266			3,526
General and administrative		7,929			7,158
Depreciation, depletion and amortization		19,793			14,722
Total operating expenses		209,656			187,450
INCOME FROM OPERATIONS		47,415			50,870
Interest expense (net of interest capitalized for the three months ended March 31, 2007 and 2006 of $316 and $423, respectively)		(2,818	)		(3,149	)
Interest income		534			904
Other income		901			271
INCOME BEFORE INCOME TAXES, CUMULATIVE EFFECT OF ACCOUNTING CHANGE AND MINORITY INTEREST		46,032			48,896
INCOME TAX EXPENSE		574			759
INCOME BEFORE CUMULATIVE EFFECT OF ACCOUNTING CHANGE AND MINORITY INTEREST		45,458			48,137
CUMULATIVE EFFECT OF ACCOUNTING CHANGE		—			112
MINORITY INTEREST		82			—
NET INCOME	$	45,540		$	48,249
GENERAL PARTNERS’ INTEREST IN NET INCOME	$	7,611		$	4,844
LIMITED PARTNERS’ INTEREST IN NET INCOME	$	37,929		$	43,405
BASIC NET INCOME PER LIMITED PARTNER UNIT	$	0.79		$	0.83
DILUTED NET INCOME PER LIMITED PARTNER UNIT	$	0.79		$	0.83
DISTRIBUTIONS PAID PER COMMON UNIT	$	0.54		$	0.46
WEIGHTED AVERAGE NUMBER OF UNITS OUTSTANDING-BASIC		36,540,485			36,426,306
WEIGHTED AVERAGE NUMBER OF UNITS OUTSTANDING-DILUTED		36,765,573			36,765,016

See notes to condensed consolidated financial statements.

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ALLIANCE RESOURCE PARTNERS, L.P. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)

(Unaudited)

	Three Months Ended March 31,
	2007			2006
CASH FLOWS PROVIDED BY OPERATING ACTIVITIES	$	69,005		$	67,640
CASH FLOWS FROM INVESTING ACTIVITIES:
Property, plant and equipment:
Capital expenditures		(30,725	)		(44,714	)
Changes in accounts payable and accrued liabilities		(5,803	)		(567	)
Proceeds from sale of property, plant and equipment		53			418
Purchase of marketable securities		—			(4,735	)
Proceeds from marketable securities		260			14,596
Advance on Gibson rail project		(1,754	)		—
Net cash used in investing activities		(37,969	)		(35,002	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Payments on capital lease obligation		(60	)		—
Cash contribution by General Partners		91			—
Distributions to Partners		(27,064	)		(21,242	)
Net cash used in financing activities		(27,033	)		(21,242	)
NET CHANGE IN CASH AND CASH EQUIVALENTS		4,003			11,396
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD		36,789			32,054
CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	40,792		$	43,450
SUPPLEMENTAL CASH FLOW INFORMATION:
CASH PAID FOR:
Interest	$	6,042		$	6,864
Income taxes	$	650		$	550
NON-CASH INVESTING ACTIVITY:
Purchase of property, plant and equipment	$	6,337		$	8,797

See notes to condensed consolidated financial statements.

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ALLIANCE RESOURCE PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

1. ORGANIZATION AND PRESENTATION

Significant relationships referenced in Notes to Condensed Consolidated Financial Statements

• References to “we,” “us,” “our” or “ARLP Partnership” mean the business and operations of Alliance Resource Partners, L.P., the parent company, as well as its consolidated subsidiaries.

• References to “ARLP” mean Alliance Resource Partners, L.P., individually as the parent company, and not on a consolidated basis.

• References to “MGP” mean Alliance Resource Management GP, LLC, the managing general partner of Alliance Resource Partners, L.P, also referred to as our managing general partner.

• References to “SGP” mean Alliance Resource GP, LLC, the special general partner of Alliance Resource Partners, L.P., also referred to as our special general partner.

• References to “Intermediate Partnership” mean Alliance Resource Operating Partners, L.P., the intermediate partnership of Alliance Resource Partners, L.P., also referred to as our intermediate partnership.

• References to “Alliance Coal” mean Alliance Coal, LLC, the holding company for the operations of Alliance Resource Operating Partners, L.P., also referred to as our operating subsidiary.

• References to “AHGP” mean Alliance Holdings GP, L.P., individually as the parent company, and not on a consolidated basis.

• References to “AGP” mean Alliance GP, LLC, the general partner of Alliance Holdings GP, L.P.

Organization

ARLP is a Delaware limited partnership listed on the NASDAQ Global Select Market under the ticker symbol “ARLP.” ARLP was formed in May 1999, to acquire upon completion of ARLP’s initial public offering on August 19, 1999, certain coal production and marketing assets of Alliance Resource Holdings, Inc., a Delaware corporation (“ARH”) (formerly known as Alliance Coal Corporation), consisting of substantially all of ARH’s operating subsidiaries, but excluding ARH. ARH was previously owned by our current and former management. In June 2006, our special general partner, SGP, and its parent, ARH, became wholly-owned, directly and indirectly, by Joseph W. Craft, III, our President and Chief Executive Officer. The SGP is a Delaware limited liability company, which holds a 0.01% general partner interest in each of ARLP and the Intermediate Partnership. We lease certain assets, including coal reserves and certain surface facilities, owned by SGP.

We are managed by our managing general partner, MGP, a Delaware limited liability company, which holds a 0.99% and a 1.0001% managing general partner interest in ARLP and the Intermediate Partnership, respectively. AHGP is a Delaware limited partnership that was formed to own and become the controlling member of MGP. AHGP completed its initial public offering on May 15, 2006. AHGP owns, directly and indirectly 100% of the members’ interest of MGP, a 0.001% managing interest in Alliance Coal, the incentive distribution rights in ARLP and 15,544,169 common units of ARLP.

The accompanying condensed consolidated financial statements include the accounts and operations of the ARLP Partnership and present our financial position as of March 31, 2007 and December 31, 2006, results of our operations for the three months ended March 31, 2007 and 2006 and our cash flows for the three months ended March 31, 2007 and 2006. All intercompany transactions and accounts of the ARLP Partnership have been eliminated.

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These condensed consolidated financial statements and notes are unaudited. However, in the opinion of management, these financial statements reflect all adjustments (which include only normal recurring adjustments) necessary for a fair presentation of the results for the periods presented. Results for interim periods are not necessarily indicative of results for a full year.

These condensed consolidated financial statements and notes are prepared pursuant to the rules and regulations of the Securities and Exchange Commission (“SEC”) for interim reporting and should be read in conjunction with the consolidated financial statements and notes included in our Annual Report on Form 10-K for the year ended December 31, 2006.

2. CONTINGENCIES

We are involved in various lawsuits, claims and regulatory proceedings incidental to our business. Currently, we are not engaged in any litigation that we believe is material to our operations, including without limitation, any litigation relating to any of our long-term supply contracts or under the various environmental protection statutes to which we are subject. We provide for costs related to litigation and regulatory proceedings, including civil fines issued as part of the outcome of these proceedings, when a loss is probable and the amount is reasonably determinable. Although the ultimate outcome of these matters cannot be predicted with certainty, in the opinion of management, the outcome of any litigation matters to the extent not previously provided for or covered under insurance, is not expected to have a material adverse effect on our business, financial position or results of operations. Nonetheless, these estimates are based on current facts and circumstances, and these matters if resolved in a manner different from the basis on which management has formed its opinion, could have a material adverse effect on our financial position or results of operations.

At certain of our operations, property tax assessments for several years are under audit by various state tax authorities. We believe that we have recorded adequate liabilities based on reasonable estimates of any property tax assessments that may be ultimately assessed as a result of these audits.

In November 2005, we settled a contract dispute with ICG, LLC (“ICG”). Under this settlement, which was effective August 1, 2005, Pontiki Coal, LLC (“Pontiki”), one of our subsidiaries, shipped coal in approximately ratable monthly quantities until the remaining obligation of 1,681,303 tons under a coal supply agreement with ICG was complete. This shipment obligation was completed in April 2007. As part of this settlement, we also executed a new coal sales agreement with ICG whereby another subsidiary of ours was to purchase approximately 887,000 tons of coal from ICG. Approximately 63,000, 588,000 and 206,000 tons were purchased and sold at a profit during 2005, 2006 and the three months ended March 31, 2007, respectively, and the remaining 30,000 tons were purchased and sold at a profit during April 2007. Consequently, we have fully satisfied our coal sales agreement with ICG.

In March 2004, XL Specialty Insurance Company (“XL”) filed litigation against ARH and us in state court of Oklahoma alleging that we and ARH had failed to indemnify XL for Alliance Coal’s failure to pay certain annual premiums associated with four surety bonds issued to the Commonwealth of Kentucky to secure Alliance Coal’s self-insurance workers’ compensation status. All four of these surety bonds were cancelled by XL in 2001 after it made the business decision to withdraw from the surety market. In the lawsuit, XL requested that the trial court determine, under two indemnity agreements, we and ARH be found jointly and severely liable to XL for bond premiums on the four cancelled surety bonds. We and ARH filed an answer raising a number of affirmative defenses and counterclaims against XL for breach of contract and bad faith. In July 2006, a bench trial occurred in which XL alleged that Alliance Coal owed approximately $876,000 (including interest) through September 2005. In support of our counterclaim, we and ARH alleged damages of approximately $400,000 relating to certain increased costs associated with Alliance Coal’s surety bond program. In September 2006, the trial court rendered a

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decision adverse to us and ARH. Accordingly, we have recorded a liability and expense to reflect the approximate damages determination made by the trial court for the period through September 30, 2005 and additional estimated expenses through March 31, 2007. We have appealed the state district court’s decision to the Oklahoma Supreme Court. In addition, settlement discussions recently have been initiated between the parties. However, we cannot give assurance that the outcome of the appeal or settlement process will not differ materially from our current estimated liability recorded on our condensed consolidated balance sheet.

3. RIVER VIEW COAL, LLC ACQUISITION

In April 2006, we acquired 100% of the membership interest in River View Coal, LLC (“River View”) for approximately $1.65 million from ARH. At the time, River View had the right to purchase certain assets, including additional coal reserves, surface properties, facilities and permits from an unrelated party, for $4.15 million plus an overriding royalty on all coal mined and sold by River View from certain of the leased properties included in the assets. In April 2006, River View purchased such assets and assumed related asset retirement obligations of $2.9 million. River View controls through coal leases or direct ownership approximately 110.0 million tons of high sulfur coal reserves in the No. 7, No. 9 and No. 11 coal seams, located in Union County, Kentucky.

Our acquisition of River View was a related-party transaction and, as such, was reviewed by the board of directors of our managing general partner (“Board of Directors”) and its conflicts committee (“Conflicts Committee”). Based upon this review, the Conflicts Committee determined that this transaction reflected market-clearing terms and conditions customary in the coal industry. As a result, the Board of Directors and its Conflicts Committee approved the River View acquisition as fair and reasonable to us and our limited partners. Because the River View acquisition was between entities under common control, it was accounted for at historical cost.

4. MC MINING MINE FIRE

On December 26, 2004, our MC Mining, LLC’s (“MC Mining”) Excel No. 3 mine was temporarily idled following a mine fire (the “MC Mining Fire Incident”). Following suppression of the mine fire, the area affected by the mine fire was completely isolated and efforts commenced to repair and rehabilitate the Excel No. 3 mine. On February 21, 2005, the repair and rehabilitation efforts had progressed sufficiently to allow resumption of production. Coal production has returned to near normal levels, but continues to be adversely impacted by inefficiencies attributable to the MC Mining Fire Incident.

We maintain commercial property (including business interruption and extra expense) insurance with various underwriters. We believe such insurance policies will cover a substantial portion of the total cost of the disruption to MC Mining’s operations resulting from the MC Mining Fire Incident. However, until the claim is resolved through the adjustment process, settlement, or litigation, we can make no assurance of the amount or timing of recovery of insurance proceeds.

Partial payments of $4.0 million and $12.2 million were received in 2006 and 2005, respectively. There have been no additional payments received during the three months ended March 31, 2007. Extra expenses that would not have been incurred, but for the MC Mining Fire Incident, were expensed as incurred with related actual and/or estimated insurance recoveries recorded as they are considered to be probable, up to the amount of the actual cost incurred. The net book value of property destroyed of $154,000, was written off in the first quarter of 2005 with a corresponding amount recorded as an estimated insurance recovery, since such recovery is considered probable. Expenses associated with business interruption losses are expensed as incurred, and estimated insurance recoveries of such losses are recognized to the extent such recoveries are considered to be probable, up to the actual amount incurred.

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Pursuant to the accounting methodology described above, we have recorded as an offset to operating expenses, $0.4 million and $10.7 million in the three months ended March 31, 2006 and the year ended December 31, 2005, respectively from the $16.2 million of partial payments received as described above. These amounts represent the current estimated insurance recovery of actual costs incurred, net of the 2005 deductibles and 2005 co-insurance. The remaining $5.1 million of partial payments are included in other current liabilities in the condensed consolidated financial statements as of March 31, 2007 until the claim is settled, at which time recoveries in excess of actual costs incurred will be recorded as a gain.

5. NET INCOME PER LIMITED PARTNER UNIT

In March 2004, the Financial Accounting Standards Board (“FASB”) issued Emerging Issues Task Force (“EITF”) No. 03-6, which addresses the computation of earnings per share by entities that have issued securities other than common stock that contractually entitle the holder to participate in dividends and earnings of the entity when, and if, it declares dividends on its common stock. Essentially, EITF No. 03-6 provides that in any accounting period where our aggregate net income exceeds the aggregate distributions to unitholders for such period, we are required to present earnings per unit as if all of the earnings for the period were distributed, regardless of the pro forma nature of this allocation and whether those earnings would actually be distributed during a particular period from an economic probability standpoint. EITF No. 03-6 was effective for fiscal periods beginning after March 31, 2004. EITF No. 03-6 does not impact our aggregate distributions to unitholders for any period, but it can have the impact of reducing our earnings per limited partner unit. This result occurs as a larger portion of our aggregate earnings, as if distributed, is allocated to the incentive distribution rights held by our managing general partner, even though we make cash distributions on the basis of cash available for distributions to unitholders, not earnings, in any given accounting period. In accounting periods where aggregate net income does not exceed our aggregate distributions for such period, EITF No. 03-6 does not have any impact on our earnings per unit calculation. The following is a reconciliation of net income and weighted average units used in computing basic and diluted earnings per unit (in thousands, except per unit data):

	Three Months Ended March 31,
	2007			2006
Net income	$	45,540		$	48,249
Adjustments:
General partner’s priority distributions		(6,837	)		(3,958	)
General partners’ 2% equity ownership		(774	)		(886	)
Limited partners’ interest in net income	$	37,929		$	43,405
Additional earnings allocation to general partners’		(8,910	)		(13,052	)
Net income available to limited partners under EITF No. 03-6	$	29,019		$	30,353
Weighted average limited partner units – basic		36,540			36,426
Basic net income per limited partner unit	$	0.79		$	0.83
Weighted average limited partner units – basic		36,540			36,426
Units contingently issuable:
Restricted units for Long-Term Incentive Plan		97			189
Directors’ compensation units		33			40
Supplemental Executive Retirement Plan		96			110
Weighted average limited partner units, assuming dilutive effect of restricted units		36,766			36,765
Diluted net income per limited partner unit	$	0.79		$	0.83

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Our net income for partners’ capital purposes is allocated to the general partners and limited partners in accordance with their respective partnership percentages, after giving effect to any priority income allocations for incentive distributions, if any, to our managing general partner, the holder of the incentive distribution rights pursuant to our partnership agreement, which are declared and paid following the close of each quarter. For purposes of computing basic and diluted net income per limited partner unit, in periods when our aggregate net income exceeds the aggregate distributions to unitholders for such periods, an increased amount of net income is allocated to the general partners for the additional pro forma priority income attributable to the application of EITF No. 03-6.

Under the quarterly incentive distribution rights provisions of our partnership agreement, our managing general partner is entitled to receive 15% of the amount we distribute in excess of $0.275 per unit, 25% of the amount we distribute in excess of $0.3125 per unit, and 50% of the amount we distribute in excess of $0.375 per unit.

6. COMMON UNIT-BASED COMPENSATION

We have a Long-Term Incentive Plan (“LTIP”) for certain employees and directors of our managing general partner and its affiliates who perform services for us. On December 7, 2006, the compensation committee of our managing general partner (“Compensation Committee”) determined that the vesting requirements for the 2004 grants of 205,570 restricted units (net of 9,230 forfeitures) had been satisfied for vesting as of December 31, 2006. As a result of this vesting, on January 8, 2007, we issued 130,812 common units to the LTIP participants. The remaining units were settled in cash to satisfy the individual tax obligations of the LTIP participants. On January 24, 2007, the Compensation Committee authorized additional grants up to 94,075 restricted units of which 89,875 have been issued and which will vest January 1, 2010, subject to the satisfaction of certain financial tests. The fair value of the 2007 grants is based upon the intrinsic value at the date of grant, which was $35.64 per unit. After consideration of the

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above mentioned transactions, as of March 31, 2007, 179,355 units remain available for issuance in the future, assuming that all grants currently issued and outstanding for 2005, 2006 and 2007 are settled with common units and no future forfeitures occur. For the three months ended March 31, 2007 and 2006, our LTIP expense was $658,000 and $1,060,000, respectively.

As of March 31, 2007, there was $5,405,000 in total unrecognized compensation expense related to the non-vested LTIP grants. That expense is expected to be recognized over a weighted-average period of 1.7 years. As of March 31, 2007, the intrinsic value of the non-vested LTIP grants was $9,257,000. The total obligation associated with the LTIP as of March 31, 2007 was $3,819,000 and is included in partners’ capital-limited partners line item in our condensed consolidated balance sheets.

7. COMPONENTS OF PENSION PLAN NET PERIODIC BENEFIT COSTS

Components of the net periodic benefit cost for each of the periods presented are as follows (in thousands):

	Three Months Ended March 31,
	2007			2006
Service cost	$	859		$	829
Interest cost		567			487
Expected return on plan assets		(672	)		(567	)
Prior service cost		—			11
Net loss		64			78
	$	818		$	838

We previously disclosed in our financial statements for the year ended December 31, 2006, that we expected to contribute $1,200,000 to the pension plan in 2007. We typically make a single contribution to our pension plan in the third quarter of a year. Accordingly, as of March 31, 2007, we had made no contributions to the pension plan in 2007.

8. MINE DEVELOPMENT

Mine development costs are capitalized until production, other than production incidental to the mine development process, commences and are amortized over the estimated life of the mine. Mine development costs represent costs incurred in establishing access to mineral reserves and include costs associated with sinking or driving shafts and underground drifts, permanent excavations, roads and tunnels.

9. GIBSON RAIL ADVANCES

In 2007, Gibson County Coal, LLC (“Gibson County Coal”) has entered into various contracts with CSX Transportation, Inc. (“CSXT”) and Norfolk Southern Railway Company (“NS”), pursuant to which Gibson is constructing a rail loop and the railroads are constructing certain connections and siding facilities, which must be constructed in order to obtain access to CSXT and NS railways. Although these connections and siding facilities will be assets of the respective rail company, Gibson County Coal will advance up to approximately $8.0 million on a combined basis to CSXT and NS during 2007 toward the cost of construction of their necessary infrastructure mentioned above. These advances will be repaid to Gibson County Coal by rail rebates as coal is shipped on the respective railways, and Gibson County Coal will also qualify for additional rail rebates from both CSXT and NS. The rail rebates will be credited to

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operating expenses in the consolidated income statement as earned under the terms of each agreement. As of March 31, 2007 Gibson County Coal has advanced $1.8 million which is recorded in other long-term assets in the condensed consolidated balance sheet.

10. NEW ACCOUNTING STANDARDS

In June 2006, the FASB issued FASB Interpretation (“FIN”) No. 48,Accounting for Uncertainty in Income Taxes, an interpretation of FASB Statement No. 109. This interpretation clarifies the accounting for uncertainty in income taxes recognized in an enterprise’s financial statements in accordance with FASB Statement No. 109,Accounting for Income Taxes. The interpretation prescribes a recognition threshold and measurement attribute for a tax position taken or expected to be taken in a tax return and also provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure and transition. The provisions of FIN No. 48 are effective for fiscal years beginning after December 15, 2006. Our adoption of FIN No. 48 on January 1, 2007 did not have a material impact on our consolidated financial statements.

In September 2006, the FASB issued SFAS No. 157,Fair Value Measurements.This standard defines fair value, establishes a framework for measuring fair value in accounting principles generally accepted in the United States of America, and expands disclosure about fair value measurements. SFAS No. 157 applies under other accounting standards that require or permit fair value measurements. Accordingly, this statement does not require any new fair value measurement. SFAS No. 157 is effective for fiscal years beginning after November 15, 2007. We are currently evaluating the requirements of SFAS No. 157 and have not yet determined the impact, if any, on our consolidated financial statements.

In February 2007, the FASB issued SFAS No. 159,The Fair Value Option for Financial Assets and Financial Liabilities. SFAS No. 159 allows entities to choose to measure financial instruments and certain other eligible items at fair value which are not otherwise currently required to be measured at fair value. Under SFAS No. 159, the decision to measure items at fair value is made at specified election dates on an irrevocable instrument-by-instrument basis. SFAS No. 159 is effective for fiscal years beginning after November 15, 2007. We are currently evaluating the requirements of SFAS No. 159 and have not yet determined the impact, if any, on our consolidated financial statements.

11. COMPREHENSIVE INCOME

The following table summarizes the effect of our marketable securities available for sale in other comprehensive income (in thousands):

	Three Months Ended March 31,
	2007		2006
Net income	$	45,540	$	48,249
Unrealized gain		—		16
Comprehensive income	$	45,540	$	48,265

Comprehensive income differs from net income by the amount of unrealized gain or loss resulting from valuation changes of our marketable securities available for sale.

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12. SEGMENT INFORMATION

We operate in the eastern United States as a producer and marketer of coal to major utilities and industrial users, also located in the eastern United States. We have the following four reportable segments: the Illinois Basin, Central Appalachia, Northern Appalachia and Other and Corporate. The first three segments also represent the three major coal deposits in the eastern United States. Coal quality, coal seam height, transportation methods and regulatory issues are similar within each of these three segments. The Illinois Basin segment is comprised of the Dotiki, Gibson, Hopkins, Pattiki and Warrior mines, and the River View and Gibson South properties. The Central Appalachian segment is comprised of the Pontiki and MC Mining mines. The Northern Appalachian segment is comprised of the Mettiki and Mountain View mines, two small third-party mining operations, and the Tunnel Ridge and Penn Ridge properties. In late 2006, we completed the transition of longwall operations from the Mettiki mine to the Mountain View mine. We are in the process of permitting the River View, Gibson South, Tunnel Ridge and Penn Ridge properties for future mine development.

Other and Corporate, includes marketing and administrative expenses, the Mt. Vernon dock activities, coal brokerage activity, Mid-America Carbonates, LLC (“MAC”) and Matrix Design Group, Inc. (“Matrix Design”). Operating segment results for the three months ended March 31, 2007 and 2006 are presented below.

	Illinois Basin		Central Appalachia		Northern Appalachia		Other and Corporate		Consolidated
	(in thousands)
Operating segment results as of or for the three months ended March 31, 2007 were as follows:
Total revenues (1)	$	167,873	$	43,503	$	38,780	$	6,915	$	257,071
Selected production expenses (2)		90,702		28,562		22,783		6,512		148,559
Segment Adjusted EBITDA (3)		56,496		10,347		8,860		335		76,038
Total assets		366,693		102,720		125,492		62,585		657,490
Capital expenditures		22,583		3,149		4,325		668		30,725
Operating segment results as of or for the three months ended March 31, 2006 were as follows:
Total revenues (1)	$	155,347	$	48,169	$	28,304	$	6,500	$	238,320
Selected production expenses (2)		82,638		30,576		14,674		3,921		131,809
Segment Adjusted EBITDA (3)		51,311		11,904		7,885		1,921		73,021
Total assets		297,658		90,344		86,002		96,152		570,156
Capital expenditures		29,560		3,805		8,174		3,175		44,714

(1) Revenues included in the Other and Corporate column are attributable to Mt. Vernon transloading revenues, brokerage coal sales for the three months ended March 31, 2007 and 2006, and Matrix Design revenues for the three months ended March 31, 2007.

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(2) Selected production expenses are comprised of operating expenses and outside purchases (as reflected in the condensed consolidated statements of income), excluding production taxes and royalties that are incurred as a percentage of coal sales or volumes. Selected production expenses are reconciled to operating expenses and outside purchases below.

	Three Months Ended March 31,
	2007		2006
	(in thousands)
Reconciliation of Selected Production Expenses to Combined Operating Expenses and Outside Purchases:
Selected production expenses	$	148,559	$	131,809
Production taxes and royalties		24,696		23,727
Combined operating expenses and outside purchases	$	173,255	$	155,536

(3) Segment Adjusted EBITDA is defined as income before income taxes, cumulative effect of accounting change, minority interest, interest expense, interest income, depreciation, depletion and amortization, and general and administrative expense. Segment Adjusted EBITDA is reconciled to net income below.

	Three Months Ended March 31,
	2007			2006
	(in thousands)
Reconciliation of Segment Adjusted EBITDA to net income:
Segment Adjusted EBITDA	$	76,038		$	73,021
General and administrative		(7,929	)		(7,158	)
Depreciation, depletion and amortization		(19,793	)		(14,722	)
Interest expense, net		(2,284	)		(2,245	)
Income taxes		(574	)		(759	)
Cumulative effect of accounting change		—			112
Minority interest		82			—
Net income	$	45,540		$	48,249

13. MINORITY INTEREST

In March 2006, White County Coal, LLC (“White County Coal”), a subsidiary of Alliance Coal, and Alexander J. House (“House”) entered into a limited liability company agreement to form MAC. MAC was formed to develop and operate a rock dust mill and to manufacture and sell rock dust. White County Coal initially invested $1.0 million in exchange for a 50% equity interest in MAC. We consolidate MAC’s financial results in accordance with FIN No. 46RConsolidation of Variable Interest Entities, an interpretation of ARB No. 51. Based on the guidance in FIN No. 46R, we concluded that MAC is a variable interest entity and that we are the primary beneficiary. House’s equity ownership in the net assets of MAC was $757,000 as of March 31, 2007, which is recorded as minority interest on our condensed consolidated balance sheet.

On March 19, 2007, MAC entered into a $600,000 line of credit (“LOC”) which expires on March 19, 2008. Borrowings bear interest at the annual rate of 8.25% from the initial borrowing date until the expiration date, payable monthly on the outstanding balance. The LOC is secured by assignment of the Rock Dust Supply Agreement between Alliance Coal and MAC and the Limestone Purchase Agreement between MAC and Hastie Mining Company, an unrelated third-party.

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14. SUBSEQUENT EVENTS

On April 30, 2007, we declared a quarterly distribution for the quarter ended March 31, 2007, of $0.54 per unit, totaling approximately $26,977,000 (which includes our managing general partners’ incentive distributions), on all common units outstanding, payable on May 15, 2007 to all unitholders of record as of May 8, 2007.

On May 2, 2007, SGP Land, LLC (“SGP Land”), a subsidiary of our special general partner, entered into a time sharing agreement with Alliance Coal, our operating subsidiary, concerning two airplanes owned and operated by SGP Land. In accordance with the provisions of the time sharing agreement, we will reimburse SGP Land for certain expenses associated with our use of these airplanes.

Because the transaction described above was a related-party transaction, it was reviewed by the Board of Directors and the Conflicts Committee and determined to be fair and reasonable to us and our limited partners.

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ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Significant relationships referenced in this management’s discussion and analysis of financial condition and results of operations include the following:

• References to “we,” “us,” “our” or “ARLP Partnership” mean the business and operations of Alliance Resource Partners, L.P., the parent company, as well as its consolidated subsidiaries.

• References to “ARLP” mean Alliance Resource Partners, L.P., individually as the parent company, and not on a consolidated basis.

• References to “MGP” mean Alliance Resource Management GP, LLC, the managing general partner of Alliance Resource Partners, L.P., also referred to as our managing general partner.

• References to “SGP” mean Alliance Resource GP, LLC, the special general partner of Alliance Resource Partners, L.P., also referred to as our special general partner.

• References to “Intermediate Partnership” mean Alliance Resource Operating Partners, L.P., the intermediate partnership of Alliance Resource Partners, L.P., also referred to as our intermediate partnership.

• References to “Alliance Coal” mean Alliance Coal, LLC, the holding company for operations of Alliance Resource Operating Partners, L.P., also referred to as our operating subsidiary.

• References to “AHGP” mean Alliance Holdings GP, L.P., individually as the parent company, and not on a consolidated basis.

• References to “AGP” mean Alliance GP, LLC, the general partner of Alliance Holdings GP, L.P.

Summary

We are a diversified producer and marketer of steam coal to major United States utilities and industrial users. We began mining operations in 1971 and, since then, have grown through acquisitions and internal development to become what we believe to be the fourth largest coal producer in the eastern United States. We currently operate eight mining complexes in Illinois, Indiana, Kentucky, Maryland and West Virginia. Three of our mining complexes supply coal feedstock and provide services to third-party coal synfuel facilities located at or near these complexes. We also operate a coal loading terminal on the Ohio River at Mt. Vernon, Indiana.

We have four reportable segments: the Illinois Basin, Central Appalachia, Northern Appalachia and Other and Corporate. The first three of these segments also represent the three major coal deposits in the eastern United States. As is customary in the coal industry, we have entered into long-term coal supply agreements with many of our customers, and we have contractual commitments for substantially all of our planned 2007 production.

We reported quarterly net income for the three months ended March 31, 2007 (the 2007 Quarter) of $45.5 million compared to $48.2 million for the three months ended March 31, 2006 (the 2006 Quarter). The decrease in net income is primarily due to higher depreciation, depletion and amortization expense resulting from recent capital expenditures related to our growth initiatives.

We receive revenues from coal sales, rental, marketing and other services provided under synfuel-related agreements at three of our mining operations. Each of these agreements, which expire on December 31, 2007, is dependent on the ability of the coal synfuel owners to use certain qualifying federal income tax credits available to their respective coal synfuel facilities and are subject to early cancellation if the synfuel tax credits become unavailable due to a rise in the price of domestic crude oil or otherwise. Pursuant to our agreements with the Coal Synfuel Owners, we are not obligated to make retroactive adjustments or reimbursements if synfuel credits are disallowed.

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Due to the increase in wellhead price of domestic crude oil, the operational status of our synfuel facilities has been sporadic. Assuming the synfuel facilities operate throughout 2007, the incremental net income benefit to us from all of our synfuel-related agreements is expected to be in the range of $25.0 million to $27.0 million. Net income in the 2007 Quarter included approximately $8.1 million from various coal synfuel-related agreements.

Results of Operations

Three Months Ended March 31, 2007 Compared to Three Months Ended March 31, 2006

	March 31,				March 31,
	2007		2006		2007		2006
	(in thousands)				(per ton sold)
Tons sold		6,178		6,102		N/A		N/A
Tons produced		6,557		6,248		N/A		N/A
Coal sales	$	238,870	$	218,212	$	38.66	$	35.76
Operating expenses and outside purchases	$	173,255	$	155,536	$	28.04	$	25.49

Coal sales. Coal sales for the 2007 Quarter increased 9.5% to $238.9 million from $218.2 million for the 2006 Quarter. The increase of $20.7 million was a result of higher coal sales prices (contributing $17.9 million of the increase) and increased sales volumes (contributing $2.8 million of the increase). Tons sold were 6.2 million and 6.1 million for the 2007 and 2006 Quarters, respectively. Tons produced increased 4.9% to 6.6 million tons for the 2007 Quarter from 6.2 million tons for the 2006 Quarter.

Operating expenses. Operating expenses increased 9.9% to $167.0 million for the 2007 Quarter from $152.0 million for the 2006 Quarter. The increase of $15.0 million resulted from higher operating expenses associated with the following specific factors:

• Labor and benefit costs increased $4.1 million reflecting increased headcount due to capacity expansion, pay rate increases, workers’ compensation adverse claims development and increased health care costs;

• Material and supplies, and maintenance costs increased $2.2 million and $1.7 million, respectively, reflecting increased costs for certain products and services used in the mining process;

• Contract mining costs decreased $1.5 million, primarily reflecting the shutdown of the Hopkins County surface mine and decreased production volume at two small-scale third-party mining operations at our Mettiki complex;

• Production taxes and royalties (which were directly correlated to coal sales) increased $1.0 million, and included the impact of West Virginia severance tax on the Mountain View mine production;

• Increased expenses of $1.5 million in the 2007 Quarter were associated with the purchase of coal tons under the settlement agreement we entered into with ICG, LLC (ICG) in November 2005. Consistent with the guidance in the Financial Accounting Standards Board’s (FASB) Emerging Issues Task Force (EITF) No. 04-13,Accounting for Purchases and Sales of

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Inventory with the Same Counterparty, Pontiki Coal, LLC’s (Pontiki) sale of coal to ICG and Alliance Coal’s purchase of coal from ICG are combined. Therefore, the excess of Alliance Coal’s purchase price from ICG over Pontiki’s sales price to ICG is reported as an operating expense. For more information about the ICG settlement agreement, please read Part I. “Item 1. Financial Statements (Unaudited) – Note 2. Contingencies” of this Quarterly Report on Form 10-Q;

• The 2006 Quarter operating expenses were reduced by $4.8 million reflecting capitalized costs net of revenues received for incidental coal production during mine development. In 2007 there was no incidental coal production associated with the mine development. See Note 8. Mine Development to the Unaudited Condensed Consolidated Financial Statements included in “Item 1. Financial Statements (Unaudited) – Note 8. Mine Development” of this Quarterly Report on Form 10-Q; and

• Reduced tax credit benefit of $1.3 million in the 2007 Quarter was due to reduced coal production in Maryland.

General and administrative. General and administrative expenses increased to $7.9 million for the 2007 Quarter compared to $7.2 million for the 2006 Quarter. The increase of $0.7 million was primarily attributable to increased headcount and related expenses.

Other sales and operating revenues. Other sales and operating revenues are principally comprised of service fees from coal synfuel production facilities, Mt. Vernon transloading revenues and administrative service revenue from affiliates. Other sales and operating revenues decreased 5.9% to $9.5 million for the 2007 Quarter from $10.1 million for the 2006 Quarter. The decrease of $0.6 million is primarily attributable to a reduction in rental and service fees associated with decreased volumes at third-party coal synfuel facilities and reduced transloading revenues due to decreased volumes. Please read “Summary” above for a discussion regarding the status of third-party coal synfuel facilities.

Outside purchases. Outside purchases increased to $6.3 million for the 2007 Quarter from $3.5 million in the 2006 Quarter. The increase of $2.8 million was primarily attributable to higher purchased volume on coal supply agreements with third-party suppliers in the Central Appalachian operation and the Illinois Basin operations ($1.7 million and $0.9 million, respectively).

Depreciation, depletion and amortization. Depreciation, depletion and amortization expense increased to $19.8 million for the 2007 Quarter from $14.7 million for the 2006 Quarter. The increase of $5.1 million was primarily attributable to additional depreciation expense associated with recent increased capital expenditures incurred in certain production capacity expansion projects and infrastructure investments, including development of the Elk Creek and Mountain View mines.

Interest expense. Interest expense, net of capitalized interest, decreased to $2.8 million for the 2007 Quarter from $3.1 million for the 2006 Quarter. The decrease of $0.3 million was principally attributable to the decreased capitalization of interest expense related to capital projects and mine development costs along with reduced interest expense resulting from our August 2006 principal payment of $18.0 million on our senior notes. We had no borrowings under the revolving credit facility during the 2007 Quarter.

Interest income.Interest income decreased to $0.5 million for the 2007 Quarter from $0.9 million for the 2006 Quarter. The decrease of $0.4 million resulted from decreased interest income earned on marketable securities, which were substantially liquidated to fund increased capital expenditures during 2006.

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Transportation revenues and expenses. Transportation revenues and expenses each decreased to $8.7 million for the 2007 Quarter compared to $10.0 million for the 2006 Quarter. The decrease of $1.3 million was primarily attributable to lower coal sales volumes for which we arrange transportation. The cost of transportation services are passed through to our customers. Consequently, we do not realize any margin on transportation revenues.

Income before income taxes, cumulative effect of accounting change and minority interest. Income before income taxes, cumulative effect of accounting change and minority interest for the 2007 and 2006 Quarters was $46.0 million and $48.9 million, respectively, and reflects the impact of the changes in revenues and expenses described above.

Income tax expense. Income tax expense decreased to $0.6 million for the 2007 Quarter from $0.8 million for the 2006 Quarter resulting from decreased volume at a third-party coal synfuel facility.

Cumulative effect of accounting change.In the 2006 Quarter, the cumulative effect of accounting change of $0.1 million was attributable to the adoption of SFAS No. 123R on January 1, 2006.

Minority interest. In March 2006 our subsidiary, White County Coal, LLC (White County Coal) and Alexander J. House (House) entered into a limited liability company agreement to form Mid-America Carbonates, LLC (MAC). MAC was formed to engage in the development and operation of a rock dust mill and to manufacture and sell rock dust. White County Coal initially invested $1.0 million in exchange for a 50% equity interest in MAC. We consolidate MAC’s financial results in accordance with FASB Interpretation (FIN) No. 46R,Consolidation of Variable Interest Entities, an interpretation of ARB No. 51. Based on the guidance in FIN No. 46R, we concluded that MAC is a variable interest entity and that we are the primary beneficiary. House’s portion of MAC’s net loss was $82,000 for the three months ended March 31, 2007 and is recorded as minority interest on our condensed consolidated income statement.

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Segment Adjusted EBITDA. Our 2007 Quarter Segment Adjusted EBITDA increased $3.0 million, or 4.1%, to $76.0 million from 2006 Quarter Segment Adjusted EBITDA of $73.0 million. Segment Adjusted EBITDA, tons sold, coal sales, other sales and operating revenues and Segment Adjusted EBITDA Expense by segment are as follows (in thousands):

	Three Months Ended March 31,
	2007		2006		Increase/(Decrease)
Segment Adjusted EBITDA
Illinois Basin	$	56,496	$	51,311	$	5,185		10.1	%
Central Appalachia		10,347		11,904		(1,557	)	(13.1	)%
Northern Appalachia		8,860		7,885		975		12.4	%
Other and Corporate		335		1,921		(1,586	)	(82.6	)%
Total Segment Adjusted EBITDA (1)	$	76,038	$	73,021	$	3,017		4.1	%
Tons sold
Illinois Basin		4,528		4,309		219		5.1	%
Central Appalachia		838		975		(137	)	(14.1	)%
Northern Appalachia		812		818		(6	)	(0.7	)%
Other and Corporate		—		—		—		—
Total tons sold		6,178		6,102		76		1.2	%
Coal sales
Illinois Basin	$	155,192	$	141,314	$	13,878		9.8	%
Central Appalachia		42,995		47,198		(4,203	)	(8.9	)%
Northern Appalachia		34,524		24,716		9,808		39.7	%
Other and Corporate		6,159		4,984		1,175		23.6	%
Total coal sales	$	238,870	$	218,212	$	20,658		9.5	%
Other sales and operating revenues
Illinois Basin	$	7,690	$	8,237	$	(547	)	(6.6	)%
Central Appalachia		72		238		(166	)	(69.7	)%
Northern Appalachia		1,004		553		451		81.6	%
Other and Corporate		756		1,046		(290	)	(27.7	)%
Total other sales and operating revenues	$	9,522	$	10,074	$	(552	)	(5.5	)%
Segment Adjusted EBITDA Expense
Illinois Basin	$	106,386	$	98,241	$	8,145		8.3	%
Central Appalachia		32,721		35,532		(2,811	)	(7.9	)%
Northern Appalachia		26,668		17,385		9,283		53.4	%
Other and Corporate		6,579		4,107		2,472		60.2	%
Total Segment Adjusted EBITDA Expense (2)	$	172,354	$	155,265	$	17,089		11.0	%

(1) Segment Adjusted EBITDA is defined as income before income taxes, cumulative effect of accounting change, minority interest, interest expense, interest income, depreciation, depletion and amortization and general and administrative expense. Segment Adjusted EBITDA is reconciled to net income below.

(2) Segment Adjusted EBITDA Expense includes operating expenses, outside purchases and other income. Pass through transportation expenses are excluded.

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Illinois Basin – Segment Adjusted EBITDA for the 2007 Quarter, as defined in reference (1) to the table above, increased 10.1%, to $56.5 million from the 2006 Quarter Segment Adjusted EBITDA of $51.3 million. The increase of $5.2 million was primarily attributable to increased coal sales which rose by $13.9 million, or 9.8%, to $155.2 million in the 2007 Quarter, as compared to $141.3 million in the 2006 Quarter. Increased coal sales in the 2007 Quarter reflected a higher average coal sales price per ton, which increased $1.47 per ton to $34.27 per ton (contributing $6.7 million of the increase in coal sales and increased volume sold of 219,000 tons (contributing $7.2 million of the increase in coal sales). Other sales and operating revenues decreased $0.5 million, primarily due to a reduction in rental and service fees associated with decreased volumes at third-party coal synfuel facilities. Segment Adjusted EBITDA Expense as defined in reference (2) to the above table for the 2007 Quarter increased 8.3% to $106.4 million from $98.2 million in the 2006 Quarter. On a per ton sold basis, 2007 Quarter Segment Adjusted EBITDA Expense rose to $23.50 per ton, an increase of 3.1% over the 2006 Quarter Segment Adjusted EBITDA Expense of $22.80 per ton. The increase in the 2007 Quarter Segment Adjusted EBITDA Expense compared to the 2006 Quarter reflected the impact of cost increases described above under consolidated operating expenses. The Illinois Basin costs have been negatively impacted by decreased saleable yield from raw coal production, increased workers’ compensation expense, higher costs of roof control and increased equipment maintenance costs. Additionally, Illinois Basin costs increased due to the continued ramp-up of production capacity at the Elk Creek mine, which emerged from development in the second quarter of 2006, as well as, increased purchased coal volume, among other factors.

Central Appalachia – Segment Adjusted EBITDA for the 2007 Quarter, as defined in reference (1) to the table above, decreased $1.6 million, or 13.1%, to $10.3 million as compared to the 2006 Quarter Segment Adjusted EBITDA of $11.9 million. The decrease was primarily attributable to reduced production in response to soft market demand and decreased saleable yield. As a result, coal sales decreased $4.2 million, notwithstanding a coal sales price increase of $2.87 per ton to an average price of $51.28 per ton in the 2007 Quarter, as compared to $48.41 per ton in the 2006 Quarter. Segment Adjusted EBITDA Expense as defined in reference (2) to the above table for the 2007 Quarter decreased 7.9% to $32.7 million from $35.5 million in the 2006 Quarter. The decrease in the 2007 Quarter Segment Adjusted EBITDA Expense primarily reflected reduced production and tonnage sold volume. The average Segment Adjusted EBITDA Expense per ton during the 2007 Quarter was $39.03 per ton, an increase of $2.59 per ton, or 7.1%, over the 2006 Quarter Segment Adjusted EBITDA Expense of $36.44 per ton. Major factors contributing to this increase include increased purchased coal volume, decreased saleable yield, and increased workers’ compensation expense.

Northern Appalachia – Segment Adjusted EBITDA for the 2007 Quarter, as defined in reference (1) to the table above, increased $1.0 million, or 12.4%, to $8.9 million as compared to the 2006 Quarter Segment Adjusted EBITDA of $7.9 million. The increase was primarily attributable to the transition completed during fourth quarter 2006 from the Mettiki longwall operation in Maryland to the new Mountain View longwall operation in West Virginia, which is reflected both in a higher coal sales price during the 2007 Quarter of $42.54 per ton as compared to $30.22 per ton during the 2006 Quarter, offset in part by a higher Segment Adjusted EBITDA Expense per ton of $32.86 during the 2007 Quarter as compared to $21.23 per ton during the 2006 Quarter (for a definition of Segment Adjusted Expense, see reference (2) to the above table). Higher average coal sales prices in Northern Appalachia are the result of new coal sales contracts, which reflect the impact of the anticipated higher operating costs at the Mountain View mining operation. Higher Segment Adjusted EBITDA expense per ton in Northern Appalachia primarily reflects higher transportation costs, West Virginia severance taxes and the loss of certain Maryland state tax benefits, among other factors.

Other and Corporate – The increase in coal sales and Segment Adjusted EBITDA Expense as defined in reference (2) to the above table primarily reflects the coal sales and operating expenses attributable to the brokerage coal purchases and coal sales associated with the ICG agreement referred to above under consolidating operating expenses.

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The following is a reconciliation of Segment Adjusted EBITDA to net income (in thousands):

	Three Months Ended March 31,
	2007			2006
Segment Adjusted EBITDA	$	76,038		$	73,021
General and administrative		(7,929	)		(7,158	)
Depreciation, depletion and amortization		(19,793	)		(14,722	)
Interest expense, net		(2,284	)		(2,245	)
Income tax expense		(574	)		(759	)
Cumulative effect of accounting change		—			112
Minority interest		82			—
Net income	$	45,540		$	48,249

MC Mining Mine Fire

On December 26, 2004, our MC Mining, LLC’s (MC Mining) Excel No. 3 mine was temporarily idled following a mine fire (the MC Mining Fire Incident). Following suppression of the mine fire, the area affected by the mine fire was completely isolated and efforts commenced to repair and rehabilitate the Excel No. 3 mine. On February 21, 2005, the repair and rehabilitation efforts had progressed sufficiently to allow resumption of production. Coal production has returned to near normal levels, but continues to be adversely impacted by inefficiencies attributable to the MC Mining Fire Incident.

We maintain commercial property (including business interruption and extra expense) insurance with various underwriters. We believe such insurance policies will cover a substantial portion of the total cost of the disruption to MC Mining’s operations resulting from the MC Mining Fire Incident. However, until the claim is resolved through the adjustment process, settlement, or litigation, we can make no assurance of the amount or timing of recovery of insurance proceeds.

Partial payments of $4.0 million and $12.2 million were received in 2006 and 2005, respectively. There have been no additional payments received during the three months ended March 31, 2007. Extra expenses that would not have been incurred, but for the MC Mining Fire Incident, were expensed as incurred with related actual and/or estimated insurance recoveries recorded as they are considered to be probable, up to the amount of the actual cost incurred. The net book value of property destroyed of $154,000, was written off in the first quarter of 2005 with a corresponding amount recorded as an estimated insurance recovery, since such recovery is considered probable. Expenses associated with business interruption losses are expensed as incurred, and estimated insurance recoveries of such losses are recognized to the extent such recoveries are considered to be probable, up to the actual amount incurred.

Pursuant to the accounting methodology described above, we have recorded as an offset to operating expenses, $0.4 million and $10.7 million in the three months ended March 31, 2006 and the year ended December 31, 2005, respectively from the $16.2 million of partial payments received as described above. These amounts represent the current estimated insurance recovery of actual costs incurred, net of the 2005 deductibles and 2005 co-insurance. The remaining $5.1 million of partial payments are included in other current liabilities in the condensed consolidated financial statements as of March 31, 2007 until the claim is settled, at which time recoveries in excess of actual costs incurred will be recorded as a gain.

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Liquidity and Capital Resources

Cash Flows

Cash provided by operating activities was $69.0 million for the 2007 Quarter compared to $67.6 million for the 2006 Quarter. The increase in cash provided by operating activities was primarily attributable to increased sales and operating revenues partially offset by higher total operating expenses excluding depreciation, depletion and amortization.

Net cash used in investing activities was $38.0 million for the 2007 Quarter compared to $35.0 million for the 2006 Quarter. The increase was primarily attributable to an increased use of cash in the 2007 Quarter as a result of timing differences in accounts payable and accrued liabilities related to capital expenditures and advances made on the Gibson rail project described under “Other” below, partially offset by a decrease in capital expenditures and a decrease in proceeds from marketable securities, which were substantially liquidated to fund increased capital expenditures during 2006. The decrease in capital expenditures in the 2007 Quarter was primarily attributable to the completion of the Elk Creek and Mountain View mines during 2006. Including initial development capital for the River View mine, we are currently estimating total capital expenditures in 2007 to range from approximately $111.0 million to 126.0 million. We will continue to have significant future capital requirements over the long-term including remaining mine development at River View and future mine development capital for the previously announced Tunnel Ridge, Gibson South and Penn Ridge properties. Future capital commitments for these mine developments are, however, dependent upon securing the required permits and coal sales agreements necessary to obtain final approval of the board of directors. We currently fund our capital expenditures with cash from operations and/or borrowings under our revolving credit facility, however future capital commitments may require us to incur additional debt or seek additional equity capital. The availability of additional debt or equity capital will depend upon prevailing market conditions, the market price of our common units and several other factors over which we have limited control, as well as our financial condition and results of operations. Based on our recent operating results, current cash position, anticipated future cash flows, and sources of financing that we expect will be available to us, we do not anticipate that we will experience significant liquidity constraints in the foreseeable future.

Net cash used in financing activities was $27.0 million for the 2007 Quarter compared to $21.2 million for the 2006 Quarter. The increase primarily was attributable to increased distributions to partners in the 2007 Quarter.

Capital Expenditures

Capital expenditures decreased to $30.7 million in the 2007 Quarter from $44.7 million in the 2006 Quarter. See discussion of “Cash Flows” above concerning the decrease in capital expenditures.

Debt Obligations

Senior Notes and Credit Facility

Our Intermediate Partnership has $144.0 million principal amount of 8.31% senior notes due August 20, 2014, payable in eight remaining equal annual installments of $18.0 million with interest payable semi-annually (Senior Notes). On April 13, 2006, our Intermediate Partnership entered into a $100.0 million revolving credit facility (ARLP Credit Facility), which expires in 2011. Borrowings under

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the ARLP Credit Facility bear interest based on a floating base rate plus an applicable margin. The applicable margin is based on a leverage ratio of our Intermediate Partnership, as computed from time to time. As of March 31, 2007, the applicable margin for borrowings under the ARLP Credit Facility is 0.875% over London Interbank Offered Rate (LIBOR) borrowings. Letters of credit can be issued under the ARLP Credit Facility not to exceed $50.0 million. Outstanding letters of credit reduce amounts available under the ARLP Credit Facility. At March 31, 2007, we had letters of credit of $24.7 million outstanding under the ARLP Credit Facility. We had no borrowings outstanding under the ARLP Credit Facility at March 31, 2007.

The Senior Notes and ARLP Credit Facility are guaranteed by all of the subsidiaries of our Intermediate Partnership. The Senior Notes and ARLP Credit Facility contain various covenants affecting our Intermediate Partnership and its subsidiaries restricting, among other things, the amount of distributions by our Intermediate Partnership, the incurrence of additional indebtedness and liens, the sale of assets, the making of investments, the entry into mergers and consolidations and the entry into transactions with affiliates, in each case subject to various exceptions. The Senior Notes and the ARLP Credit Facility also require the Intermediate Partnership to remain in control of a certain amount of mineable coal based on a ratio of the amount of total mineable tons controlled by the Intermediate Partnership relative to its annual production. In addition, the Senior Notes and the ARLP Credit Facility require the Intermediate Partnership to comply with certain financial ratios, including a maximum leverage ratio and a minimum interest coverage ratio. We were in compliance with the covenants of both the ARLP Credit Facility and Senior Notes at March 31, 2007.

We have previously entered into and have maintained specific agreements with two banks to provide additional letters of credit in an aggregate amount of $31.0 million to maintain surety bonds to secure certain asset retirement obligations and our obligations for workers’ compensation benefits. At March 31, 2007, we had $30.6 million in letters of credit outstanding under these agreements. Our special general partner guarantees $5.0 million of these outstanding letters of credit.

On March 19, 2007 MAC entered into a $600,000 secured line of credit (LOC) which expires on March 19, 2008. Borrowings bear interest at the annual rate of 8.25% from the initial borrowing date until the expiration date, payable monthly on the outstanding balance. There was no balance outstanding as of March 31, 2007 on the LOC. The LOC is secured by assignment of the Rock Dust Supply Agreement between Alliance Coal and MAC and the Limestone Purchase Agreement between MAC and Hastie Mining Company, an unrelated third-party.

Related-Party Transactions

We have continuing related-party transactions with our managing general partner, AHGP, and our special general partner, including our special general partner’s affiliates. These related-party transactions relate principally to the provision of administrative services to AHGP and Alliance Resource Holdings II, Inc. and their respective affiliates, mineral and equipment leases with our special general partner and its affiliates, and guarantees from our special general partner for letters of credit.

Please read our Annual Report on Form 10-K for the year ended December 31, 2006, “Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations – Related-Party Transactions” for additional information concerning the related party transactions described above.

On May 2, 2007, SGP Land, LLC (SGP Land), a subsidiary of our special general partner, entered into a time sharing agreement with Alliance Coal, our operating subsidiary, concerning two airplanes owned and operated by SGP Land. In accordance with the provisions of the time sharing agreement, we will reimburse SGP Land for certain expenses associated with our use of the airplanes.

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Because the transaction described above was a related-party transaction, it was reviewed by the Board of Directors of our managing general partner and its conflicts committee and determined to be fair and reasonable to us and our limited partners.

New Accounting Standards

In June 2006, the FASB issued FIN No. 48,Accounting for Uncertainty in Income Taxes, an interpretation of FASB Statement No. 109. This interpretation clarifies the accounting for uncertainty in income taxes recognized in an enterprise’s financial statements in accordance with FASB Statement No. 109,Accounting for Income Taxes. The interpretation prescribes a recognition threshold and measurement attribute for a tax position taken or expected to be taken in a tax return and also provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure, and transition. The provisions of FIN No. 48 are effective for fiscal years beginning after December 15, 2006. Our adoption of FIN No. 48 on January 1, 2007 did not have a material impact on our consolidated financial statements.

In September 2006, the FASB issued SFAS No. 157,Fair Value Measurements.This standard defines fair value, establishes a framework for measuring fair value in accounting principles generally accepted in the United States of America, and expands disclosure about fair value measurements. SFAS No. 157 applies under other accounting standards that require or permit fair value measurements. Accordingly, this statement does not require any new fair value measurement. SFAS No. 157 is effective for fiscal years beginning after November 15, 2007. We are currently evaluating the requirements of SFAS No. 157 and have not yet determined the impact, if any, on our condensed consolidated financial statements.

In February 2007, the FASB issued SFAS No. 159,The Fair Value Option for Financial Assets and Financial Liabilities. SFAS No. 159 allows entities to choose to measure financial instruments and certain other eligible items at fair value which are not otherwise currently required to be measured at fair value. Under SFAS No. 159, the decision to measure items at fair value is made at specified election dates on an irrevocable instrument-by-instrument basis. SFAS No. 159 is effective for fiscal years beginning after November 15, 2007. We are currently evaluating the requirements of SFAS No. 159 and have not yet determined the impact, if any, on our consolidated financial statements.

Other

Gibson Rail Advances

In 2007, Gibson County Coal, LLC (Gibson County Coal) has entered into various contracts with CSX Transportation, Inc. (CSXT) and Norfolk Southern Railway Company (NS), pursuant to which Gibson is constructing a rail loop and the railroads are constructing certain connections and siding facilities, which must be constructed in order to obtain access to CSXT and NS railways. Although these connections and siding facilities will be assets of the respective rail company, Gibson County Coal will advance up to approximately $8.0 million on a combined basis to CSXT and NS during 2007 toward the cost of construction of their necessary infrastructure mentioned above. These advances will be repaid to Gibson County Coal by rail rebates as coal is shipped on the respective railways, and Gibson County Coal will also qualify for additional rail rebates from both CSXT and NS. The rail rebates will be credited to operating expenses in the consolidated income statement as earned under the terms of each agreement. As of March 31, 2007 Gibson County Coal has advanced $1.8 million which is recorded in other long-term assets in the condensed consolidated balance sheet.

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MINER Act

In June 2006, Congress passed and President Bush signed the Mine Improvement and New Emergency Response Act of 2006 (MINER Act), which, among other things, requires mine-specific emergency response plans, enhanced communication and tracking systems, and more available mine rescue teams, as well as larger penalty assessments by MSHA for noncompliance by mine operators. In December 2006, MSHA implemented several aspects of the MINER Act through promulgation of its final rule on Emergency Mine Evacuation, which includes requirements for increased availability and storage of self-contained self-rescue (SCSR) devices; improved emergency evacuation drills and SCSR training and the installation and maintenance of lifelines in underground coal mines. Coal producing states, including West Virginia, Illinois, and Kentucky, passed similar legislation in 2006. While the full cost of compliance remains unknown, we do anticipate our capital expenditures and operating expenses will increase as a result of implementing and complying with these new laws and regulations.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

We have significant long-term coal supply agreements. Virtually all of our long-term coal supply agreements are subject to price adjustment provisions, which permit an increase or decrease periodically in the contract price to principally reflect changes in specified price indices or items such as taxes, royalties or actual production costs.

Almost all of our transactions are denominated in U.S. dollars and, as a result, we do not have material exposure to currency exchange-rate risks. At the current time, we do not have any interest rate, foreign currency exchange rate or commodity price-hedging transactions outstanding.

Borrowings under the ARLP Credit Facility are at variable rates and, as a result, we have interest rate exposure. Our earnings are not materially affected by changes in interest rates as we had no borrowings outstanding under the ARLP Credit Facility during the quarter ended March 31, 2007.

As of March 31, 2007, the estimated fair value of the Senior Notes was approximately $157.0 million. The fair values of long-term debt are estimated using discounted cash flow analyses, based upon our current incremental borrowing rates for similar types of borrowing arrangements as of March 31, 2007. There were no other significant changes in our quantitative and qualitative disclosures about market risk as set forth in our Annual Report on Form 10-K for the year ended December 31, 2006.

ITEM 4. CONTROLS AND PROCEDURES

We maintain controls and procedures designed to ensure that we are able to collect the information we are required to disclose in the reports we file with the SEC, and to process, summarize and disclose this information within the time periods specified in the rules of the SEC. An evaluation of the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rule 13a-15(e) or Rule 15d-15(e) of the Securities Exchange Act) was performed as of the end of the period covered by this report. This evaluation was performed under the supervision and with the participation of our management, including our Chief Executive and Chief Financial Officers. Based on an evaluation of our disclosure controls and procedures as of the end of the period covered by this report conducted by our management, with the participation of our Chief Executive and Chief Financial Officers, our Chief Executive and Chief Financial Officers believe the design and operation of these controls and procedures are effective to ensure that the ARLP Partnership is able to collect, process and disclose the information it is required to disclose in the reports it files with the SEC within the required time periods, and during the quarterly period ended March 31, 2007, there have not been any changes in our internal control over financial reporting (as defined in Rule 13a-15(f) under the Securities Exchange Act of 1934) identified in connection with this evaluation that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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FORWARD-LOOKING STATEMENTS

This Quarterly Report on Form 10-Q contains forward-looking statements within the meaning of Section 27A of the Securities Act and Section 21E of the Exchange Act and are intended to come within the safe harbor protection provided by those sections. These statements are based on our beliefs as well as assumptions made by, and information currently available to, us. When used in this document, the words “anticipate,” “believe,” “continue,” “estimate,” “expect,” “forecast,” “may,” “project,” “will,” and similar expressions identify forward-looking statements. Without limiting the foregoing, all statements relating to our future outlook, anticipated capital expenditures, future cash flows and borrowings and sources of funding are forward-looking statements. These statements reflect our current views with respect to future events and are subject to numerous assumptions that we believe are reasonable, but are open to a wide range of uncertainties and business risks, and actual results may differ materially from those discussed in these statements. Among the factors that could cause actual results to differ from those in the forward-looking statements are:

• increased competition in coal markets and our ability to respond to the competition;

• fluctuation in coal prices, which could adversely affect our operating results and cash flows;

• risks associated with the expansion of our operations and properties;

• deregulation of the electric utility industry or the effects of any adverse change in the domestic coal industry, electric utility industry, or general economic conditions;

• dependence on significant customer contracts, including renewing customer contracts upon expiration of existing contracts;

• customer bankruptcies and/or cancellations or breaches to existing contracts;

• customer delays or defaults in making payments;

• fluctuations in coal demand, prices and availability due to labor and transportation costs and disruptions, equipment availability, governmental regulations and other factors;

• our productivity levels and margins that we earn on our coal sales;

• greater than expected increases in raw material costs;

• greater than expected shortage of skilled labor;

• any unanticipated increases in labor costs, adverse changes in work rules, or unexpected cash payments associated with post-mine asset retirement obligations and workers’ compensation claims;

• any unanticipated increases in transportation costs and risk of transportation delays or interruptions;

• greater than expected environmental regulation, costs and liabilities;

• a variety of operational, geologic, permitting, labor and weather-related factors;

• risks associated with major mine-related accidents, such as mine fires, or interruptions;

• results of litigation, including claims not yet asserted;

• difficulty maintaining our surety bonds for mine asset retirement obligations as well as workers’ compensation and black lung benefits;

• coal market’s share of electricity generation;

• prices of fuel that compete with or impact coal usage, such as oil or natural gas;

• legislation, regulatory and court decisions;

• the impact from provisions of The Energy Policy Act of 2005;

• replacement of coal reserves;

• a loss or reduction of the direct or indirect benefit from certain state and federal tax credits, including non-conventional source fuel tax credits;

• difficulty obtaining commercial property insurance, and risks associated with our participation (excluding any applicable deductible) in the commercial insurance property program; and

• other factors, including those discussed below in Item 1. “Legal Proceedings” and Item 1A. “Risk Factors.”

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If one or more of these or other risks or uncertainties materialize, or should underlying assumptions prove incorrect, our actual results may differ materially from those described in any forward-looking statement. When considering forward-looking statements, you should also keep in mind the risk factors described in “Risk Factors” below. The risk factors could also cause our actual results to differ materially from those contained in any forward-looking statement. We disclaim any obligation to update the above list or to announce publicly the result of any revisions to any of the forward-looking statements to reflect future events or developments.

You should consider the information above when reading any forward-looking statements contained:

• in this Quarterly Report on Form 10-Q;

• other reports filed by us with the SEC;

• our press releases; and

• written or oral statements made by us or any of our officers or other authorized persons acting on our behalf.

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PART II

OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

We are subject to various types of litigation in the ordinary course of our business. We are not engaged in any litigation that we believe is material to our operations, including without limitation, any litigation relating to our long-term coal supply contracts or under the various environmental protection statutes to which we are subject. However, we cannot assure you that disputes or litigation will not arise or that we will be able to resolve any such future disputes or litigation in a satisfactory manner.

The information in Note 2. Contingencies to the Unaudited Condensed Consolidated Financial Statements included in “Item 1, Financial Statements (Unaudited)” of this Quarterly Report on Form 10-Q herein is hereby incorporated by reference. See also “Item 3, Legal Proceedings” in the Annual Report on Form 10-K for the year ended December 31, 2006.

ITEM 1A. RISK FACTORS

In addition to the other information set forth in the Quarterly Report on Form 10-Q, you should carefully consider the factors discussed in Part I, Item 1A. “Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2006, which could materially affect our business, financial condition or future results. The risks described in our Annual Report on Form 10-K are not our only risks. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial based on current knowledge and factual circumstances and, if such knowledge or factors change, also may materially adversely affect our business, financial condition and/or operating results in the future. Other risk factors to consider are as follows:

We have adopted certain valuation methodologies that may result in a shift of income, gain, loss and deduction between the general partner and the unitholders. The IRS may challenge this treatment, which could adversely affect the value of the common units.

When we issue additional units or engage in certain other transactions, we determine the fair market value of our assets and allocate any unrealized gain or loss attributable to our assets to the capital accounts of our unitholders and our general partner. Our methodology may be viewed as understating the value of our assets. In that case, there may be a shift of income, gain, loss and deduction between certain unitholders and the general partner, which may be unfavorable to such unitholders. Moreover, under our current valuation methods, subsequent purchasers of common units may have a greater portion of their Internal Revenue Code Section 743(b) adjustment allocated to our tangible assets and a lesser portion allocated to our intangible assets. The IRS may challenge our valuation methods, or our allocation of the Section 743(b) adjustment attributable to our tangible and intangible assets, and allocations of income, gain, loss and deduction between the general partner and certain of our unitholders.

A successful IRS challenge to these methods or allocations could adversely affect the amount of taxable income or loss being allocated to our unitholders. It also could affect the amount of gain from our unitholders’ sale of common units and could have a negative impact on the value of the common units or result in audit adjustments to our unitholders’ tax returns without the benefit of additional deductions.

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ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

None.

ITEM 3. DEFAULTS UPON SENIOR SECURITIES

None.

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

None.

ITEM 5. OTHER INFORMATION

None.

ITEM 6. EXHIBITS

31.1*	Certification of Joseph W. Craft III, President and Chief Executive Officer of Alliance Resource Management GP, LLC, the managing general partner of Alliance Resource Partners, L.P., dated May 10, 2007, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 furnished herewith.
31.2*	Certification of Brian L. Cantrell, Senior Vice President and Chief Financial Officer of Alliance Resource Management GP, LLC, the managing general partner of Alliance Resource Partners, L.P., dated May 10, 2007, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 furnished herewith.
32.1**	Certification of Joseph W. Craft III, President and Chief Executive Officer of Alliance Resource Management GP, LLC, the managing general partner of Alliance Resource Partners, L.P., dated May 10, 2007, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 furnished herewith.
32.2**	Certification of Brian L. Cantrell, Senior Vice President and Chief Financial Officer of Alliance Resource Management GP, LLC, the managing general partner of Alliance Resource Partners, L.P., dated May 10, 2007, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 furnished herewith.

* Filed herewith.

** Furnished herewith.

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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized, in Tulsa, Oklahoma, on May 10, 2007.

ALLIANCE RESOURCE PARTNERS, L.P.
By:	Alliance Resource Management GP, LLC
	its managing general partner
	/s/ Joseph W. Craft, III
	Joseph W. Craft, III
	President, Chief Executive Officer and Director
	/s/ Brian L. Cantrell
	Brian L. Cantrell
	Senior Vice President and Chief Financial Officer

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