Edgar Filing: ALLIANCE RESOURCE PARTNERS LP

Form 10-Q

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 September 30, 2007

¨	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 November 9, 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

	Condensed Consolidated Balance Sheets as of September 30, 2007 and December 31, 2006	1

	Condensed Consolidated Statements of Income for the three and nine months ended September 30, 2007 and 2006	2

	Condensed Consolidated Statements of Cash Flows for the nine months ended September 30, 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	29

ITEM 4.	Controls and Procedures	30

	Forward-Looking Statements	31

	PART II

	OTHER INFORMATION



ITEM 1.	Legal Proceedings	33

ITEM 1A.	Risk Factors	33

ITEM 2.	Unregistered Sales of Equity Securities and Use of Proceeds	34

ITEM 3.	Defaults upon Senior Securities	34

ITEM 4.	Submission of Matters to a Vote of Security Holders	34

ITEM 5.	Other Information	34

ITEM 6.	Exhibits	34

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)


	September 30, 2007			December 31, 2006
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	19,105		$	36,789
Trade receivables, net		89,300			96,558
Other receivables		2,256			3,378
Due from affiliates		123			25
Marketable securities		—			260
Inventories		24,998			20,224
Advance royalties		3,316			4,629
Prepaid expenses and other assets		1,012			8,225

Total current assets		140,110			170,088

PROPERTY, PLANT AND EQUIPMENT:
Property, plant and equipment, at cost		922,159			819,991
Less accumulated depreciation, depletion and amortization		(406,954	)		(383,284	)

Total property, plant and equipment, net		515,205			436,707

OTHER ASSETS:
Advance royalties		27,308			22,135
Other long-term assets		14,695			6,032

Total other assets		42,003			28,167

TOTAL ASSETS	$	697,318		$	634,962


LIABILITIES AND PARTNERS’ CAPITAL
CURRENT LIABILITIES:
Accounts payable	$	54,730		$	57,879
Due to affiliates		1,064			1,414
Accrued taxes other than income taxes		12,955			14,618
Accrued payroll and related expenses		17,405			14,698
Accrued interest		1,162			4,264
Workers’ compensation and pneumoconiosis benefits		7,715			7,704
Current capital lease obligation		375			339
Other current liabilities		9,774			13,786
Current maturities, long-term debt		18,000			18,000

Total current liabilities		123,180			132,702

LONG-TERM LIABILITIES:
Long-term debt, excluding current maturities		135,000			126,000
Pneumoconiosis benefits		28,691			26,315
Accrued pension benefit		4,053			6,191
Workers’ compensation		51,752			38,488
Asset retirement obligations		49,110			47,825
Due to affiliates		1,135			994
Long-term capital lease obligation		1,232			1,512
Minority interest		609			839
Other liabilities		6,141			5,616

Total long-term liabilities		277,723			253,780

Total liabilities		400,903			386,482

COMMITMENTS AND CONTINGENCIES
PARTNERS’ CAPITAL:
Limited Partners—Common Unitholders 36,550,659 and 36,419,847 units outstanding, respectively		594,992			549,005
General Partners’ deficit		(291,815	)		(293,569	)
Accumulated other comprehensive income		(6,762	)		(6,956	)

Total Partners’ Capital		296,415			248,480

TOTAL LIABILITIES AND PARTNERS’ CAPITAL	$	697,318		$	634,962

See notes to condensed consolidated financial statements.

ALLIANCE RESOURCE PARTNERS, L.P. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

(In thousands, except unit and per unit data)

(Unaudited)


	Three Months Ended September 30,						Nine Months Ended September 30,
	2007			2006			2007			2006
SALES AND OPERATING REVENUES:
Coal sales	$	242,412		$	228,802		$	723,646		$	652,527
Transportation revenues		9,138			10,966			28,423			29,956
Other sales and operating revenues		8,976			4,972			28,837			21,881

Total revenues		260,526			244,740			780,906			704,364

EXPENSES:
Operating expenses		176,857			162,209			521,814			455,096
Transportation expenses		9,138			10,966			28,423			29,956
Outside purchases		3,737			6,020			17,610			14,251
General and administrative		7,175			7,391			23,370			21,640
Depreciation, depletion and amortization		21,804			17,273			63,022			48,283
Net gain from insurance settlement		—			—			(11,491	)		—

Total operating expenses		218,711			203,859			642,748			569,226

INCOME FROM OPERATIONS		41,815			40,881			138,158			135,138

Interest expense (net of interest capitalized for the three and nine months ended September 30, 2007 and 2006 of $345, $462, $1,008 and $1,153, respectively)		(3,037	)		(2,870	)		(8,697	)		(9,458	)
Interest income		273			712			1,376			2,525
Other income		121			216			1,189			684

INCOME BEFORE INCOME TAXES, CUMULATIVE EFFECT OF ACCOUNTING CHANGE AND MINORITY INTEREST		39,172			38,939			132,026			128,889
INCOME TAX EXPENSE		550			352			1,794			1,658

INCOME BEFORE CUMULATIVE EFFECT OF ACCOUNTING CHANGE AND MINORITY INTEREST		38,622			38,587			130,232			127,231
CUMULATIVE EFFECT OF ACCOUNTING CHANGE		—			—			—			112
MINORITY INTEREST		63			53			230			96

NET INCOME	$	38,685		$	38,640		$	130,462		$	127,439

GENERAL PARTNERS’ INTEREST IN NET INCOME	$	8,175		$	6,051		$	24,112		$	16,985

LIMITED PARTNERS’ INTEREST IN NET INCOME	$	30,510		$	32,589		$	106,350		$	110,454

BASIC NET INCOME PER LIMITED PARTNER UNIT	$	0.70		$	0.70		$	2.30		$	2.26

DILUTED NET INCOME PER LIMITED PARTNER UNIT	$	0.70		$	0.69		$	2.28		$	2.24

DISTRIBUTIONS PAID PER COMMON UNIT	$	0.56		$	0.50		$	1.64		$	1.42

WEIGHTED AVERAGE NUMBER OF UNITS OUTSTANDING-BASIC		36,550,659			36,426,306			36,547,305			36,426,306

WEIGHTED AVERAGE NUMBER OF UNITS OUTSTANDING-DILUTED		36,801,186			36,824,613			36,790,999			36,795,976

See notes to condensed consolidated financial statements.

ALLIANCE RESOURCE PARTNERS, L.P. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)

(Unaudited)


	Nine Months Ended September 30,
	2007			2006
CASH FLOWS PROVIDED BY OPERATING ACTIVITIES	$	211,324		$	184,450

CASH FLOWS FROM INVESTING ACTIVITIES:
Property, plant and equipment:
Capital expenditures		(95,017	)		(141,963	)
Changes in accounts payable and accrued liabilities		(9,297	)		(1,198	)
Proceeds from sale of property, plant and equipment		5,859			599
Proceeds from insurance settlement for replacement assets		2,511			—
Purchase of marketable securities		—			(19,188	)
Proceeds from marketable securities		260			68,343
Payment for acquisition of coal reserves and other assets		(53,309	)		—
Payment for acquisition of business		—			(2,318	)
Advances on Gibson rail project		(5,912	)		—

Net cash used in investing activities		(154,905	)		(95,725	)

CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowings under revolving credit facilities		130,250			—
Payments under revolving credit facilities		(103,250	)		—
Payments on capital lease obligation		(244	)		—
Payment on long-term debt		(18,000	)		(18,000	)
Payment of debt issuance cost		(194	)		(690	)
Equity contribution received by Mid-America Carbonates, LLC		—			1,000
Cash contribution by General Partners		91			—
Distributions paid to Partners		(82,756	)		(66,642	)

Net cash used in financing activities		(74,103	)		(84,332	)

NET CHANGE IN CASH AND CASH EQUIVALENTS		(17,684	)		4,393

CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD		36,789			32,054

CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	19,105		$	36,447

SUPPLEMENTAL CASH FLOW INFORMATION:
CASH PAID FOR:
Interest	$	12,583		$	13,711

Income taxes	$	2,175		$	1,900

NON-CASH INVESTING ACTIVITY:
Purchase of property, plant and equipment	$	2,843		$	8,166

See notes to condensed consolidated financial statements.

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. SGP, a Delaware limited liability company, 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 and a 0.001% managing member interest in Alliance Coal. 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, 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 September 30, 2007 and December 31, 2006, results of our operations for the three and nine months ended September 30, 2007 and 2006 and our cash flows for the nine months ended September 30, 2007 and 2006. All intercompany transactions and accounts of the ARLP Partnership have been eliminated.

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

Various lawsuits, claims and regulatory proceedings incidental to our business are pending against the ARLP Partnership. We record an accrual for a potential loss related to these matters when, in management’s opinion, such loss is probable and reasonably estimable. Based on known facts and circumstances, we believe the ultimate outcome of these outstanding lawsuits, claims and regulatory proceedings will not have a material adverse effect on our financial condition, results of operations or liquidity. However, if the results of these matters were different from management’s current opinion and in amounts greater than our accruals, then they could have a material adverse effect.

During September 2007, we completed our annual property and casualty insurance renewal with various insurance coverages effective as of October 1, 2007. Available capacity for underwriting property insurance continues to be limited as a result of insurance carrier losses in the mining industry. As a result, we have elected to retain a participating interest along with our insurance carriers at an average rate of approximately 14.7% in the overall $75.0 million commercial property program representing 35% of the primary $30.0 million layer and 2.5% of the second layer of $20.0 million in excess of the $30.0 million primary layer. We do not participate in the third layer of $25.0 million in excess of $50.0 million.

The 14.7% participation rate for this year’s renewal is consistent with our prior year participation. The aggregate maximum limit in the commercial property program is $75.0 million per occurrence, of which, as a result of our participation, we would be responsible for a maximum amount of $11.0 million for each occurrence, excluding a $1.5 million deductible for property damage, a $5.0 million aggregate deductible for extra expense and a 60-day waiting period for business interruption. We can make no assurances that we will not experience significant insurance claims in the future, which, as a result of our level of participation in the commercial property program, could have a material adverse effect on our business, financial condition, results of operations and ability to purchase property insurance in the future.

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 March 2004, XL Specialty Insurance Company (“XL”) filed a lawsuit in state district court in Oklahoma alleging that we and ARH had failed to pay premiums related to the issuance of several surety bonds issued for us by XL. At trial in July 2006, XL sought approximately $0.9 million in damages and interest, and the district court ruled against us. Our appeal to the Oklahoma Supreme Court is pending and, in addition, settlement discussions between the parties are ongoing. We have accrued for damages as determined by the trial court and interest pending final resolution of this matter.

3.	ACQUISITIONS

In June 2007, our subsidiary, Alliance Resource Properties, LLC, acquired the rights to approximately 78.4 million tons of high-sulfur coal reserves in Webster and Hopkins County, Kentucky from Island Creek Coal Company, a subsidiary of Consol Energy, Inc. The purchase price of $53.3 million cash paid at closing was primarily allocated to owned and leased coal rights. We financed the purchase using a combination of existing cash on hand and borrowings under our revolving credit facility.

We intend to mine these reserves from our adjacent Dotiki and Warrior mining complexes utilizing continuous mining units employing room-and-pillar mining techniques. As a result of the purchase, we reclassified 8.4 million tons of high-sulfur, non-reserve coal deposits as reserves. This acquisition represented an approximate 14% increase in our reserves at the acquisition date.

In April 2006, we acquired 100% of the members’ 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 June 18, 2007, we agreed to a full and final resolution of our insurance claim relating to a mine fire that occurred on or about December 25, 2004 at our MC Mining, LLC’s (“MC Mining”) Excel No. 3 mine. This resolution included settlement of all expenses, losses and claims we incurred for the aggregate amount of $31.6 million, inclusive of $8.2 million of various deductibles and co-insurance, netting to $23.4 million of insurance proceeds to us. In 2006 and 2005, we received partial advance payments on the claim totaling $16.2 million, part of which we recognized 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), with the remaining $5.1 million of partial payments previously included in other current liabilities pending final claim resolution. In June 2007, as a result of this final resolution, we received additional cash payments of $7.2 million and recognized a net gain from insurance settlement of approximately $11.5 million, as well as a reduction in operating expenses of approximately $0.8 million.

5.	LONG-TERM DEBT

Our Intermediate Partnership has $126.0 million principal amount of 8.31% senior notes due August 20, 2014, payable in seven remaining equal annual installments of $18.0 million with interest payable semi-annually. On September 25, 2007, our Intermediate Partnership entered into a $150.0 million revolving credit facility (“ARLP Credit Facility”), which expires in 2012. The ARLP Credit Facility amended the previous $100.0 million credit facility that would have expired in 2011. Borrowings under 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 September 30, 2007, the applicable margin for borrowings under the ARLP Credit Facility was 0.75% over London Interbank Offered Rate and the interest rate on the ARLP Credit Facility was 5.13%. Letters of credit can be issued under the ARLP Credit Facility not to exceed $100.0 million. Outstanding letters of credit reduce amounts available under the ARLP Credit Facility. At September 30, 2007, we had $27.0 million of borrowings and $24.7 million of letters of credit outstanding under the ARLP Credit Facility. The deferred cost associated with the amended $100.0 million credit facility accounted for as prescribed by Emerging Issues Task Force (“EITF”) No. 98-14, Debtor’s Accounting for Changes in Line-of-Credit or Revolving-Debt Arrangements, which states that if the borrowing capacity of a new arrangement is greater than or equal to the borrowing capacity of an old arrangement, the unamortized deferred costs associated with the old arrangement should be associated with the new arrangement and amortized over the life of the new arrangement.

6.	NET INCOME PER LIMITED PARTNER UNIT

In March 2004, the Financial Accounting Standards Board (“FASB”) issued 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 September 30,						Nine Months Ended September 30,
	2007			2006			2007			2006
Net income	$	38,685		$	38,640		$	130,462		$	127,439
Adjustments:
General partner’s priority distributions		(7,553	)		(5,386	)		(21,942	)		(14,731	)
General partners’ 2% equity ownership		(622	)		(665	)		(2,170	)		(2,254	)

Limited partners’ interest in net income	$	30,510		$	32,589		$	106,350		$	110,454
Additional earnings allocation to general partners		(4,919	)		(7,041	)		(22,372	)		(28,051	)

Net income available to limited partners under EITF No. 03-6	$	25,591		$	25,548		$	83,978		$	82,403

Weighted average limited partner units – basic		36,551			36,426			36,547			36,426

Basic net income per limited partner unit	$	0.70		$	0.70		$	2.30		$	2.26

Weighted average limited partner units – basic		36,551			36,426			36,547			36,426
Units contingently issuable:
Restricted units for Long-Term Incentive Plan		137			243			126			217
Directors’ compensation units		33			43			33			42
Supplemental Executive Retirement Plan		80			113			85			111

Weighted average limited partner units, assuming dilutive effect of restricted units		36,801			36,825			36,791			36,796

Diluted net income per limited partner unit	$	0.70		$	0.69		$	2.28		$	2.24

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.

7.	COMMON UNIT-BASED COMPENSATION

We have a Long-Term Incentive Plan (“LTIP”) for certain of our 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 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 92,175 restricted units (net of 500 forfeitures) have been issued and 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 $35.84 per unit on a weighted average basis. After consideration of the above mentioned transactions, as of September 30, 2007, 181,255 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 and nine months ended September 30, 2007 and 2006, our LTIP expense was $785,000, $1,171,000, $2,233,000 and $3,100,000, respectively.

As of September 30, 2007, there was $3,953,000 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 1.2 years. As of September 30, 2007, the intrinsic value of the non-vested LTIP grants was $8,726,000. The total obligation associated with the LTIP as of September 30, 2007 was $5,384,000 and is included in the partners’ capital-limited partners line item in our condensed consolidated balance sheets.

8.	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 September 30,						Nine Months Ended September 30,
	2007			2006			2007			2006
Service cost	$	859		$	829		$	2,576		$	2,487
Interest cost		566			487			1,700			1,461
Expected return on plan assets		(672	)		(568	)		(2,015	)		(1,702	)
Prior service cost		—			10			—			32
Amortization of actuarial loss		65			79			194			235

Net periodic benefit cost	$	818		$	837		$	2,455		$	2,513

For the nine months ended September 30, 2007 and 2006, we have made contributions of $4.4 million and $4.6 million, respectively, to the pension plan.

9.	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.

10.

GIBSON RAIL ADVANCES

In 2007, our subsidiary, Gibson County Coal, LLC (“Gibson County Coal”) entered into contracts with CSX Transportation, Inc. (“CSXT”) and Norfolk Southern Railway Company (“NS”), pursuant to which Gibson County Coal is constructing a rail loop and the railroads are constructing connections and siding facilities, in order to provide Gibson County Coal 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 infrastructure. These advances will be repaid to Gibson County Coal by rebates from CSXT and NS as coal is shipped on their respective railways. In addition, Gibson County

Coal will also qualify for additional rebates from both CSXT and NS. The additional rebates will be credited to operating expenses in the consolidated income statement as earned under the terms of each agreement. As of September 30, 2007, Gibson County Coal had advanced $5.9 million in aggregate to CSXT and NS, which is recorded in other receivables and other long-term assets in our condensed consolidated balance sheet.

11.

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. Our adoption of FIN No. 48 on January 1, 2007 did not have a material impact on our condensed consolidated financial statements.

In September 2006, the FASB issued Statement of Financial Accounting Standards (“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 condensed consolidated financial statements.

12.

COMPREHENSIVE INCOME

The following table summarizes the effect of our marketable securities available for sale and the amortization of actuarial loss related to our pension plan on other comprehensive income for the three and nine months ended September 30, 2007 and 2006, respectively, (in thousands):


	Three Months Ended September 30,				Nine Months Ended September 30,
	2007		2006		2007		2006
Net income	$	38,685	$	38,640	$	130,462	$	127,439
Unrealized gain		—		2		—		68
Amortization of actuarial loss		65		—		194		—

Comprehensive income	$	38,750	$	38,642	$	130,656	$	127,507

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 and amortization of actuarial loss associated with the adoption of SFAS No. 158, Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans—an amendment of FASB Statements No. 87, 88, 106, and 132 (R).

13.

SEGMENT INFORMATION

We operate in the eastern United States as a producer and marketer of coal to major utilities and industrial users. We have four reportable segments: the Illinois Basin, Central Appalachia, Northern Appalachia and Other and Corporate. The first three segments correspond to the three major coal producing regions in the eastern United States. Coal quality, coal seam height, mining and transportation methods and regulatory issues are similar within each of these three segments.

The Illinois Basin segment is comprised of Webster County Coal, LLC’s Dotiki mine, Gibson County Coal’s Gibson North mine and Gibson South property, Hopkins County Coal, LLC’s Elk Creek mine, White County Coal, LLC’s (“White County Coal”) Pattiki mine, Warrior Coal, LLC’s Cardinal mine, and Alliance Resource Properties, LLC (Note 3). In 2007, mine development has begun at the River View property. We are in the process of permitting the Gibson South property for future mine development.

The Central Appalachian segment is comprised of Pontiki Coal LLC’s Pond Creek and Van Lear mines, and MC Mining’s Excel No. 3 mine.

The Northern Appalachian segment is comprised of Mettiki Coal, LLC’s D-Mine and Mettiki Coal (WV), LLC’s Mountain View mine, two small third-party mining operations, and the Tunnel Ridge, LLC and Penn Ridge Coal, LLC properties. In late 2006, we completed the transition of longwall operations from the D-Mine to the Mountain View mine. We are in the process of permitting the Tunnel Ridge and Penn Ridge properties for future mine development.

Other and Corporate includes marketing and administrative expenses, the Mt. Vernon Transfer Terminal, LLC (“Mt. Vernon”) dock activities, coal brokerage activity, Mid-America Carbonates, LLC (“MAC”) and Matrix Design Group, LLC (“Matrix Design”). Operating segment results for the three and nine months ended September 30, 2007 and 2006 are presented below:


	Illinois Basin		Central Appalachia		Northern Appalachia		Other and Corporate			Consolidated
	(in thousands)
Operating segment results for the three months ended September 30, 2007:
Total revenues (1)	$	166,732	$	49,467	$	43,160	$	1,167		$	260,526
Selected production expenses (2)		92,227		35,452		24,936		1,409			154,024
Segment Adjusted EBITDA (3)		51,826		9,200		10,216		(327	)		70,915
Capital expenditures		18,286		3,908		3,000		653			25,847

Operating segment results for the three months ended September 30, 2006:
Total revenues (1)	$	159,964	$	43,562	$	33,518	$	7,696		$	244,740
Selected production expenses (2)		91,143		30,751		17,049		6,294			145,237
Segment Adjusted EBITDA (3)		47,911		7,114		9,422		1,314			65,761
Capital expenditures		27,357		7,590		13,961		1,038			49,946

Operating segment results as of or for the nine months ended September 30, 2007:
Total revenues (1)	$	502,514	$	145,979	$	121,730	$	10,683		$	780,906
Selected production expenses (2)		281,452		96,654		74,242		10,162			462,510
Segment Adjusted EBITDA (3)		154,694		46,036		24,731		278			225,739
Total assets		437,523		102,620		124,849		32,326			697,318
Capital expenditures (4)		68,856		10,367		13,318		2,476			95,017

Operating segment results as of or for the nine months ended September 30, 2006:
Total revenues (1)	$	459,549	$	139,686	$	86,905	$	18,224		$	704,364
Selected production expenses (2)		251,050		91,901		44,898		13,153			401,002
Segment Adjusted EBITDA (3)		146,606		30,761		24,172		4,206			205,745
Total assets		342,919		98,220		109,363		53,873			604,375
Capital expenditures (4)		86,818		17,808		27,612		9,725			141,963

(1)

Revenues included in the Other and Corporate column are attributable to Mt. Vernon transloading revenues, brokerage coal sales for the three and nine months ended September 30, 2007 and 2006, and Matrix Design and outside MAC rock dust revenues for the three and nine months ended September 30, 2007.

(2)

Selected production expenses are comprised of operating expenses and outside purchases (as reflected in our 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 September 30,				Nine Months Ended September 30,
	2007		2006		2007		2006
	(in thousands)
Selected production expenses	$	154,024	$	145,237	$	462,510	$	401,002
Production taxes and royalties		26,570		22,992		76,914		68,345

Combined operating expenses and outside purchases	$	180,594	$	168,229	$	539,424	$	469,347

(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 September 30,						Nine Months Ended September 30,
	2007			2006			2007			2006
	(in thousands)
Segment Adjusted EBITDA	$	70,915		$	65,761		$	225,739		$	205,745
General and administrative		(7,175	)		(7,391	)		(23,370	)		(21,640	)
Depreciation, depletion and amortization		(21,804	)		(17,273	)		(63,022	)		(48,283	)
Interest expense, net		(2,764	)		(2,158	)		(7,321	)		(6,933	)
Income taxes		(550	)		(352	)		(1,794	)		(1,658	)
Cumulative effect of accounting change		—			—			—			112
Minority interest		63			53			230			96

Net income	$	38,685		$	38,640		$	130,462		$	127,439

(4)	Capital expenditures do not include acquisitions of coal reserves and other assets in the Illinois Basin of $53.3 million or business acquisitions separately reported in our condensed consolidated statements of cash flows.

14.

MINORITY INTEREST

In March 2006, 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. 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 equity ownership in the net assets of MAC was $609,000 as of September 30, 2007, which is recorded as minority interest on our condensed consolidated balance sheet.

On March 19, 2007, MAC entered into a secured line of credit (“LOC”) which was scheduled to expire on March 19, 2008. In September 2007, MAC entered into a $1.5 million Revolving Credit Agreement (“Revolver”) with ARLP. Concurrent with the execution of the Revolver, MAC repaid all amounts outstanding under the LOC. Due to the consolidation of MAC in accordance with FIN 46R, the intercompany transactions associated with the Revolver are eliminated.

15.

SUBSEQUENT EVENTS

On October 29, 2007, we declared a quarterly distribution for the quarter ended September 30, 2007, of $0.56 per unit, totaling approximately $28,439,000 (which includes our managing general partner’s incentive distributions), on all common units outstanding, payable on November 14, 2007 to all unitholders of record as of November 7, 2007.

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 “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 “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.

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 correspond to the three major coal producing regions 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 remaining 2007 production.

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 facilities 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.

Net income included approximately $8.0 million and $3.7 million for the three months ended September 30, 2007 (the 2007 Quarter) and September 30, 2006 (the 2006 Quarter), respectively, and approximately $24.9 million and $18.1 million for the nine months ended September 30, 2007 (the 2007 Period) and September 30, 2006 (the 2006 Period), respectively,

from various coal synfuel-related agreements Assuming the synfuel facilities operate in a manner consistent with previous fourth quarters, the incremental net income to us for 2007 from all synfuel-related agreements is expected to be in the range of $25 million to $27 million and the fourth quarter 2007 benefit should be approximately one-third of the benefit realized in the 2007 third quarter. In 2006, operations of our synfuel facilities were interrupted temporarily at times due to the increase in the wellhead price of domestic crude oil.

Results of Operations

Three Months Ended September 30, 2007 Compared to Three Months Ended September 30, 2006

We reported net income for the 2007 Quarter of $38.7 million compared to $38.6 million for the 2006 Quarter. The benefits of a 1.1% increase in tons sold, a 4.8% increase in average coal sales price per ton sold and improved salable yield during the 2007 Quarter as compared to the 2006 Quarter, were partially offset by increased operating expenses which reflect, among other factors described below, the impact of compliance costs and reduced productivity associated with the implementation of recently enacted mine safety regulations.


	September 30,				September 30,
	2007		2006		2007		2006
	(in thousands)				(per ton sold)
Tons sold		6,230		6,164		N/A		N/A
Tons produced		6,083		6,114		N/A		N/A
Coal sales	$	242,412	$	228,802	$	38.91	$	37.12
Operating expenses and outside purchases	$	180,594	$	168,229	$	28.99	$	27.29

Coal sales. Coal sales for the 2007 Quarter increased 5.9% to $242.4 million from $228.8 million for the 2006 Quarter. The increase of $13.6 million was a result primarily of higher coal sales prices, contributing $11.2 million of the increase. Tons sold were comparable at 6.2 million for the 2007 and 2006 Quarters, respectively. Tons produced for the 2007 and 2006 Quarters were comparable at 6.1 million tons, respectively.

Operating expenses. Operating expenses increased 9.0% to $176.9 million for the 2007 Quarter from $162.2 million for the 2006 Quarter. The increase of $14.7 million resulted from higher operating expenses associated with an additional 170,000 produced tons sold as well as the following specific factors:

•

Labor and benefit costs increased $7.0 million reflecting increased headcount due to capacity expansion, pay rate increases, and increased workers’ compensation and health care costs;

•

Material and supplies, and maintenance costs increased $3.7 million and $1.4 million, respectively, reflecting increased costs for certain products and services used in the mining process, as well as higher costs associated with compliance with recently enacted federal and state mine safety regulations. In addition to the impact on materials and supplies and maintenance costs during the 2007 Quarter, the recently enacted federal and state mine safety regulations reduced productivity and increased mine administrative expenses;

•

Production taxes and royalties (which are incurred as a percentage of coal sales revenue or volumes) increased $3.6 million and included the impact of higher West Virginia severance

tax on coal sold from the Mountain View mine as compared to Maryland. We completed the transition of longwall operations to the Mountain View mine in West Virginia from the depleted Mettiki D-Mine in Maryland in the fourth quarter of 2006;

•

Reduced expenses of $4.6 million in the 2007 Quarter as compared to the 2006 Quarter were associated with the purchase and sale of coal during the 2006 Quarter under a 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 Inventory with the Same Counterparty, Pontiki Coal, LLC’s (Pontiki Coal) sale of coal to ICG and Alliance Coal’s purchase of coal from ICG pursuant to that settlement agreement are combined. Therefore, the excess of Alliance Coal’s purchase price from ICG over Pontiki Coal’s sales price to ICG is reported as an operating expense. We have fully satisfied our coal sales agreement with ICG;

•

The 2006 Quarter operating expenses were reduced by $4.0 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 mine development activities. See Note 9. Mine Development to the Unaudited Condensed Consolidated Financial Statements included in “Item 1. Financial Statements (Unaudited)” of this Quarterly Report on Form 10-Q;

•

Reduced tax credit benefit of $1.7 million in the 2007 Quarter was due to reduced coal production in Maryland. (See comments above concerning production taxes and royalties and depletion of the Mettiki D-Mine in Maryland); and

•

The 2007 Quarter operating expenses benefited from net gains of $2.7 million realized from sales of surplus equipment.

General and administrative. General and administrative expenses were comparable for the 2007 and 2006 Quarters at $7.2 million and $7.4 million, respectively.

Other sales and operating revenues. Other sales and operating revenues are principally comprised of rental and service fees from third-party coal synfuel production facilities, Mt. Vernon transloading revenues, and outside services and administrative services revenue from affiliates. Other sales and operating revenues increased to $9.0 million for the 2007 Quarter from $5.0 million for the 2006 Quarter. The increase of $4.0 million is primarily attributable to higher rental and service fees associated with increased volumes at third-party coal synfuel facilities and revenue from outside services. Please read “Summary” above for a discussion regarding the status of third-party coal synfuel facilities.

Outside purchases. Outside purchases decreased to $3.7 million for the 2007 Quarter from $6.0 million in the 2006 Quarter. The decrease of $2.3 million was primarily attributable to a decrease in outside purchases at our Illinois Basin and Northern Appalachian regions partially offset by increased purchases in the Central Appalachian region.

Depreciation, depletion and amortization. Depreciation, depletion and amortization expense increased to $21.8 million for the 2007 Quarter from $17.3 million for the 2006 Quarter. The increase of $4.5 million was primarily attributable to additional depreciation expense associated with production capacity expansion projects and infrastructure investments in recent years, including development of the Mountain View mine. In addition, we accelerated depreciation on certain transportation assets resulting in additional depreciation expense of $0.9 million during the 2007 Quarter.

Interest expense. Interest expense, net of capitalized interest, was comparable for the 2007 and 2006 Quarters at $3.0 million and $2.9 million, respectively.

Interest income. Interest income decreased to $0.3 million for the 2007 Quarter from $0.7 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.

Transportation revenues and expenses. Transportation revenues and expenses each decreased to $9.1 million for the 2007 Quarter compared to $11.0 million for the 2006 Quarter. The decrease of $1.9 million was primarily attributable to a lower average per ton transportation charge in the 2007 Quarter as compared to the 2006 Quarter, primarily driven by the location of our customers for which we arranged transportation. This decrease was partially offset by higher transported coal volumes in the 2007 Quarter. 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 $39.2 million and $38.9 million, respectively, and reflects the impact of the changes in revenues and expenses described above.

Income tax expense. Income tax expense was comparable for the 2007 and 2006 Quarters at $0.6 million and $0.4 million, respectively.

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 $63,000 and $53,000 for the 2007 and 2006 Quarters, respectively, and is recorded as minority interest on our condensed consolidated income statement.

Segment Adjusted EBITDA. Our 2007 Quarter Segment Adjusted EBITDA increased $5.1 million, or 7.8%, to $70.9 million from 2006 Quarter Segment Adjusted EBITDA of $65.8 million. Segment Adjusted EBITDA, tons sold, coal sales, other sales and operating revenues and Segment Adjusted EBITDA Expense by segment are (in thousands):


	Three Months Ended September 30,					Increase/(Decrease)
	2007			2006		Increase/(Decrease)
Segment Adjusted EBITDA
Illinois Basin	$	51,826		$	47,911	$	3,915		8.2	%
Central Appalachia		9,200			7,114		2,086		29.3	%
Northern Appalachia		10,216			9,422		794		8.4	%
Other and Corporate		(327	)		1,314		(1,641	)	(3	)

Total Segment Adjusted EBITDA (1)	$	70,915		$	65,761	$	5,154		7.8	%

Tons sold
Illinois Basin		4,519			4,409		110		2.5	%
Central Appalachia		851			793		58		7.3	%
Northern Appalachia		860			943		(83	)	(8.8	)%
Other and Corporate		—			19		(19	)	(3	)

Total tons sold		6,230			6,164		66		1.1	%

Coal sales
Illinois Basin	$	154,060		$	150,990	$	3,070		2.0	%
Central Appalachia		49,244			42,384		6,860		16.2	%
Northern Appalachia		39,108			28,999		10,109		34.9	%
Other and Corporate		—			6,429		(6,429	)	(3	)

Total coal sales	$	242,412		$	228,802	$	13,610		5.9	%

Other sales and operating revenues
Illinois Basin	$	6,687		$	3,193	$	3,494		(3	)
Central Appalachia		—			—		—		—
Northern Appalachia		1,121			513		608		(3	)
Other and Corporate		1,168			1,266		(98	)	(7.7	)%

Total other sales and operating revenues	$	8,976		$	4,972	$	4,004		80.5	%

Segment Adjusted EBITDA Expense
Illinois Basin	$	108,922		$	106,272	$	2,650		2.5	%
Central Appalachia		40,044			35,268		4,776		13.5	%
Northern Appalachia		30,012			20,090		9,922		49.4	%
Other and Corporate		1,495			6,383		(4,888	)	(76.6	)%

Total Segment Adjusted EBITDA Expense (2)	$	180,473		$	168,013	$	12,460		7.4	%

(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 and net gains from insurance settlement are excluded.

(3)	Percentage increase was greater than or equal to 100%.

Illinois Basin – Segment Adjusted EBITDA for the 2007 and 2006 Quarters, as defined in reference (1) to the table above, increased 8.2% or $3.9 million to $51.8 million in the 2007 Quarter, from $47.9 million in the 2006 Quarter. This increase is primarily the result of a 2.5% increase in tons sold and a $3.5 million increase in other sales and operating revenues in the 2007 Quarter as compared to the 2006 Quarter. Coal sales increased $3.1 million or 2.0% to $154.1 million in the 2007 Quarter, as compared to $151.0 million in the 2006 Quarter, as the result of an increase in tons sold of 110,000 tons, which was primarily driven by increased production at the Elk Creek mine, increased production due to improved mining and geologic conditions at the Pattiki mine, and partially offset by reduced production due to adverse geologic conditions at the Dotiki mine. Other sales and operating revenues increased $3.5 million, primarily due to higher rental and service fees associated with increased volumes at third-party coal synfuel facilities in the 2007 Quarter. Please read “Summary” above for a discussion regarding the status of third-party coal synfuel facilities. Segment Adjusted EBITDA Expense, as defined in reference (2) to the above table, for the 2007 Quarter increased 2.5% to $108.9 million from $106.3 million in the 2006 Quarter. The increase in the 2007 Quarter Segment Adjusted EBITDA Expense compared to the 2006 Quarter reflects the impact of the cost increases described above under consolidated operating expenses, and costs associated with higher coal production volumes, partially offset by certain favorable operating tax adjustments and net gains of $2.8 million from the sale of surplus equipment.

Central Appalachia – Segment Adjusted EBITDA for the 2007 Quarter, as defined in reference (1) to the table above, increased $2.1 million to $9.2 million; compared to the 2006 Quarter Segment Adjusted EBITDA of $7.1 million. Coal sales increased $6.9 million, primarily reflecting an 8.4% increase in average coal sales price to $57.92 per ton in the 2007 Quarter, as compared to $53.42 per ton in the 2006 Quarter, and secondarily reflecting increased tons sold as a result of improved mining conditions at the MC Mining mine. Segment Adjusted EBITDA Expense, as defined in reference (2) to the above table, for the 2007 Quarter increased 13.5% to $40.0 million from $35.3 million in the 2006 Quarter. The average Segment Adjusted EBITDA Expense per ton sold during the 2007 Quarter was $47.10, an increase of $2.65 per ton, or 6.0%, as compared to $44.45 per ton in the 2006 Quarter. The increase in Segment Adjusted EBITDA Expense was primarily a result of higher operating expenses associated with compliance with the new mine safety standards, increased purchased coal volume, as well as other cost increases described above under consolidated operating expenses, partially offset by certain favorable operating tax adjustments.

Northern Appalachia – Segment Adjusted EBITDA for the 2007 Quarter, as defined in reference (1) to the table above, increased $0.8 million, or 8.4%, to $10.2 million as compared to the 2006 Quarter Segment Adjusted EBITDA of $9.4 million. The increase was primarily attributable to higher average coal sales prices in Northern Appalachia of $45.46 per ton during the 2007 Quarter as compared to $30.78 per ton during the 2006 Quarter, which are the result of new coal sales contracts reflecting the impact of the anticipated higher operating costs at the Mountain View mining operation. This increase in coal sales prices was offset by a higher Segment Adjusted EBITDA Expense per ton of $34.89 during the 2007 Quarter as compared to $21.32 per ton during the 2006 Quarter (for a definition of Segment Adjusted EBITDA Expense, see reference (2) to the above table), as a result of the transition, completed during the 2006 fourth quarter, from the Mettiki D-Mine longwall operation in Maryland to the new Mountain View longwall operation in West Virginia. Higher Segment Adjusted EBITDA expense per ton in Northern Appalachia primarily reflects higher trucking costs, West Virginia severance taxes, the loss of certain Maryland state tax benefits and among other factors.

Other and Corporate – The decrease in Segment Adjusted EBITDA Expense as defined in reference (2) to the above table primarily reflects lower operating expenses for the 2007 Quarter attributable to lower brokerage coal purchases associated with the ICG agreement referred to above under consolidated operating expenses, partially offset by increased expenses associated with higher outside services revenue.

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


	Three Months Ended September 30,
	2007			2006
Segment Adjusted EBITDA	$	70,915		$	65,761

General and administrative		(7,175	)		(7,391	)
Depreciation, depletion and amortization		(21,804	)		(17,273	)
Interest expense, net		(2,764	)		(2,158	)
Income tax expense		(550	)		(352	)
Minority interest		63			53

Net income	$	38,685		$	38,640

Nine Months Ended September 30, 2007 Compared to Nine Months Ended September 30, 2006

We reported net income for the 2007 Period of $130.5 million, an increase of 2.4% over the 2006 Period. Increased results for the 2007 Period were primarily attributable to the final settlement with our insurance underwriters for claims relating to the MC Mining Mine Fire Incident (Please read “MC Mining Mine Fire” below), which resulted in a $12.3 million increase to income in the 2007 Period, higher coal sales volumes and higher average coal sales prices. The benefits were partially offset by increased compliance costs and reduced productivity associated with the implementation of recently enacted mine safety regulations and increased operating expenses associated with an additional 851,000 tons sold.


	September 30,				September 30,
	2007		2006		2007		2006
	(in thousands)				(per ton sold)
Tons sold		18,687		17,836		N/A		N/A
Tons produced		18,278		18,164		N/A		N/A
Coal sales	$	723,646	$	652,527	$	38.72	$	36.58
Operating expenses and outside purchases	$	539,424	$	469,347	$	28.87	$	26.31

Coal sales. Coal sales increased 10.9% to $723.6 million for the 2007 Period from $652.5 million for the 2006 Period. The increase of $71.1 million reflects higher coal sales prices (contributing $40.0 million of the increase) and higher sales volumes (contributing $31.1 million of the increase). Tons sold increased 4.8% to 18.7 million tons for the 2007 Period from 17.8 million tons for the 2006 Period. Tons produced increased to 18.3 million tons for the 2007 Period from 18.2 million tons for the 2006 Period.

Operating expenses. Operating expenses increased 14.7% to $521.8 million for the 2007 Period from $455.1 million for the 2006 Period. The increase of $66.7 million resulted from an increase in operating expenses associated with an additional 824,000 produced tons sold as well as the following specific factors:

•

Labor and benefit costs increased $23.2 million reflecting increased headcount, due to capacity expansion, pay rate increases, and increased workers compensation and health care costs;

•

Material and supplies and maintenance costs increased $16.8 million and $6.7 million, respectively, reflecting increased production and increased costs for certain products and services used in the mining process, as well as, higher costs associated with compliance with recently enacted mine safety regulations. In addition to the impact on materials and supplies and maintenance costs during the 2007 Period, recently enacted federal and state mine safety regulations have resulted in reduced productivity and increased mine administrative expenses;

•

Production taxes and royalties (which are incurred as a percentage of coal sales revenue or volumes) increased $8.6 million and included the impact of West Virginia severance tax on coal sold from the Mountain View mine as compared to Maryland. We completed the transition of longwall operations to the Mountain View mine in West Virginia from the depleted Mettiki D-Mine in Maryland in the fourth quarter of 2006;

•

The 2006 Period operating expenses were reduced by $11.1 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 mine development. See Note 9. Mine Development to the Unaudited Condensed Consolidated Financial Statements included in “Item 1. Financial Statements (Unaudited)” of this Quarterly Report on Form 10-Q;

•

Reduced expenses of $4.8 million in the 2007 Period as compared to the 2006 Period were associated with the purchase and sale of more coal during the 2006 Period under a settlement agreement we entered into with ICG, LLC (ICG) in November 2005. Consistent with the guidance in the FASB’s EITF No. 04-13, Accounting for Purchases and Sales of Inventory with the Same Counterparty, Pontiki Coal’s sale of coal to ICG and Alliance Coal’s purchase of coal from ICG pursuant to that settlement agreement are combined. Therefore, the excess of Alliance Coal’s purchase price from ICG over Pontiki Coal’s sales price to ICG is reported as an operating expense. We fully satisfied our coal sales agreement with ICG;

•

Reduced tax credit benefit of $5.7 million in the 2007 Period was due to reduced coal production in Maryland. (See comments above concerning production taxes and royalties and depletion of the Mettiki D-Mine in Maryland); and

•

The 2007 Period benefited from net gains of $3.6 million realized from sales of surplus equipment.

General and administrative. General and administrative expenses increased to $23.4 million for the 2007 Period from $21.6 million for the 2006 Period. The increase of $1.8 million was primarily attributable to increased headcount and related salary and benefit expenses.

Other sales and operating revenues. Other sales and operating revenues increased 31.8% to $28.8 million for the 2007 Period from $21.9 million for the 2006 Period. The increase of $6.9 million was primarily attributable to an increase in rental and service fees associated with increased volumes at third-party coal synfuel facilities and revenue from outside services, partially offset by lower 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 $17.6 million for the 2007 Period from $14.3 million in the 2006 Period. This increase of $3.3 million was primarily attributable to an increase in outside purchases in our Central Appalachia region to supply new market opportunities partially offset by lower outside purchases in Northern Appalachia region.

Depreciation, depletion and amortization. Depreciation, depletion and amortization expense increased to $63.0 million for the 2007 Period from $48.3 million for the 2006 Period. The increase of $14.7 million is primarily attributable to additional depreciation expense associated with an increase in capital expenditures, particularly at our Elk Creek, Mountain View and Van Lear mines, and other infrastructure investments in recent years that have increased our production capacity.

Interest expense. Interest expense decreased to $8.7 million for the 2007 Period from $9.5 million for the 2006 Period. The decrease of $0.8 million was principally attributable to reduced interest expense associated with the August 2007 scheduled principal payment of $18.0 million on our senior notes, partially offset by increased interest expense under our revolving credit facility.

Interest income. Interest income decreased to $1.4 million for the 2007 Period from $2.5 million for the 2006 Period. The decrease of $1.1 million resulted from decreased interest income earned on marketable securities, which were substantially liquidated to fund increased capital expenditures during 2006.

Transportation revenues and expenses. Transportation revenues and expenses each decreased to $28.4 million for the 2007 Period from $30.0 million for the 2006 Period. The decrease of $1.6 million was primarily attributable to lower average per ton transportation charge in the 2007 Period as compared to the 2006 Period, primarily driven by the location of our customers for which we arranged transportation. The decrease was partially offset by higher transported coal volumes in the 2007 Period. 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 increased to $132.0 million for the 2007 Period from $128.9 million for the 2006 Period. The increase of $3.1 million reflects the impact of the changes in revenues and expenses described above.

Income tax expense. Income tax expense was comparable for the 2007 and 2006 Periods at $1.8 million and $1.7 million, respectively.

Cumulative effect of accounting change. The cumulative effect of accounting change of $0.1 million was attributable to the adoption of Statement of Financial Accounting Standards (SFAS) No. 123R, Share-Based Payment, on January 1, 2006.

Minority interest. In March 2006 White County Coal and House entered into a Limited Liability Company Agreement to form MAC. MAC was formed to engage in the development and operation of a rock dust mill and to manufacture and sell rock dust. We consolidate MAC’s financial results in accordance with FIN No. 46R. 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 $230,000 and $96,000 for the 2007 and 2006 Periods, respectively, and is recorded as minority interest on our condensed consolidated income statement.

Segment Adjusted EBITDA. Our 2007 Period Segment Adjusted EBITDA increased $20.0 million, or 9.7%, to $225.7 million from the 2006 Period Segment Adjusted EBITDA of $205.7 million. Segment Adjusted EBITDA, tons sold, coal sales, operating revenues and Segment Adjusted EBITDA Expense by segment are (in thousands):


	Nine Months Ended September 30,
	2007		2006		Increase/(Decrease)
Segment Adjusted EBITDA
Illinois Basin	$	154,694	$	146,606	$	8,088		5.5	%
Central Appalachia		46,036		30,761		15,275		49.7	%
Northern Appalachia		24,731		24,172		559		2.3	%
Other and Corporate		278		4,206		(3,928	)	(93.4	)%

Total Segment Adjusted EBITDA (1)	$	225,739	$	205,745	$	19,994		9.7	%

Tons sold
Illinois Basin		13,550		12,642		908		7.2	%
Central Appalachia		2,608		2,674		(66	)	(2.5	)%
Northern Appalachia		2,529		2,501		28		1.1	%
Other and Corporate		—		19		(19	)	(3	)

Total tons sold		18,687		17,836		851		4.8	%

Coal sales
Illinois Basin	$	462,423	$	425,743	$	36,680		8.6	%
Central Appalachia		144,633		136,951		7,682		5.6	%
Northern Appalachia		109,506		75,576		33,930		44.9	%
Other and Corporate		7,084		14,257		(7,173	)	(50.3	)%

Total coal sales	$	723,646	$	652,527	$	71,119		10.9	%

Other sales and operating revenues
Illinois Basin	$	21,971	$	16,579	$	5,392		32.5	%
Central Appalachia		72		238		(166	)	(69.7	)%
Northern Appalachia		3,195		1,565		1,630		(3	)
Other and Corporate		3,599		3,499		100		2.9	%

Total other sales and operating revenues	$	28,837	$	21,881	$	6,956		31.8	%

Segment Adjusted EBITDA Expense
Illinois Basin	$	329,700	$	295,716	$	33,984		11.5	%
Central Appalachia		110,161		106,427		3,734		3.5	%
Northern Appalachia		87,969		52,969		35,000		66.1	%
Other and Corporate		10,405		13,551		(3,146	)	(23.2	)%

Total Segment Adjusted EBITDA Expense (2)	$	538,235	$	468,663	$	69,572		14.8	%

(1)

Segment Adjusted EBITDA is defined as income before income taxes, cumulative effect of accounting change and minority interest, interest expense and 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 and net gains from insurance settlement are excluded.

(3)	Percentage increase was greater than or equal to 100%.

Illinois Basin – Segment Adjusted EBITDA for the 2007 Period, as defined in reference (1) to the table above, increased 5.5% to $154.7 million from the 2006 Period Segment Adjusted EBITDA of

$146.6 million. The increase of $8.1 million was primarily attributable to increased production capacity at the Elk Creek mine and an increase of $5.4 million in other sales and operating revenues, as compared to the 2006 Period. Coal sales increased by $36.7 million, or 8.6%, to $462.4 million during the 2007 Period as compared to $425.7 million in the 2006 Period. Increased coal sales in the 2007 Period reflect a higher average coal sales price per ton which increased $0.45 to $34.13 per ton (contributing $6.1 million of the increase in coal sales) and increased tons sold of 908,000 tons (contributing $30.6 million of the increase in coal sales). Other sales and operating revenues increased $5.4 million, primarily due to an increase in rental and service fees associated with increased volumes at third-party coal synfuel facilities in the 2007 Period. Please read “Summary” above for a discussion regarding the status of third-party coal synfuel facilities. Total Segment Adjusted EBITDA Expense, as defined in reference (2) to the above table, for the 2007 Period increased 11.5% to $329.7 million from $295.7 million in the 2006 Period. On a per ton sold basis, the 2007 Period Segment Adjusted EBITDA Expense rose to $24.33 per ton, an increase of 4.0% over the 2006 Period Segment Adjusted EBITDA Expense per ton of $23.39. In addition to the increased tons sold, the increase in the 2007 Period Segment Adjusted EBITDA Expense compared to the 2006 Period primarily reflects the impact of cost increases described above under consolidated operating expenses. Further, the Illinois Basin costs have been negatively impacted during the 2007 Period by decreased saleable yield from raw coal production as a result of adverse geologic conditions encountered at Gibson County Coal, LLC (Gibson County Coal).

Central Appalachia – Segment Adjusted EBITDA for the 2007 Period, as defined in reference (1) to the table above, increased $15.2 million, or 49.7%, to $46.0 million as compared to the 2006 Period Segment Adjusted EBITDA of $30.8 million. This increase was primarily the result of the final settlement of the MC Mining Fire Incident, which resulted in a net gain from insurance settlement of approximately $11.5 million and a reduction in operating expenses of approximately $0.8 million. Please read “MC Mining Mine Fire” below. Coal sales for the 2007 and 2006 Periods totaling $144.6 million and $137.0 million, respectively, were favorably impacted by a higher average coal sales price per ton of $55.46 in the 2007 Period, an increase of $4.25 per ton or 8.3% over the 2006 Period average coal sales price per ton of $51.21 (resulting in $11.1 million increase in coal sales), partially offset by a decrease of 66,000 tons sold, or 2.5% (resulting in $3.4 million decrease in coal sales). Segment Adjusted EBITDA Expense, as defined in reference (2) to the above table, for the 2007 Period increased 3.5% to $110.2 million from $106.4 million in the 2006 Period. The average Segment Adjusted EBITDA Expense per ton during the 2007 Quarter was $42.24, an increase of $2.44 per ton, or 6.1% over the 2006 Period Segment Adjusted EBITDA Expense per ton of $39.80. The increase in Segment Adjusted EBITDA Expense per ton was primarily a result of higher operating expenses associated with the new mine safety standards and increased purchased coal volume, among other cost increases described above under consolidated operating expenses.

Northern Appalachia – Segment Adjusted EBITDA for the 2007 and 2006 Periods, as defined in reference (1) to the table above, were comparable at $24.7 million and $24.2 million, respectively. The net increase in Segment Adjusted EBITDA of $0.5 million reflects both an increase in the average sales price of $13.08 per ton to $43.30 per ton due to new coal sales contracts, as well as increased other sales and operating revenues of $1.6 million, partially offset by an increase in Segment Adjusted EBITDA Expense, as defined in reference (2) to the above table, of $13.60 per ton to $34.78 per ton during the 2007 Period as compared to $21.18 per ton during the 2006 Period. These variances reflect the impact of the higher operating costs from the transition of the Mettiki D-Mine longwall operation in Maryland to the new Mountain View longwall operation in West Virginia, as well as, higher contract sales prices. Other impacts on EBITDA for the 2007 Period as compared to the 2006 Period include the cost increases described above under consolidated operating expenses and a 1.1% increase in tons sold.

Other and Corporate – The decrease in Segment Adjusted EBITDA Expense as defined in reference (2) to the above table primarily reflects lower operating expenses for the 2007 Period attributable to lower brokerage coal purchases, associated with the ICG agreement referred to above under consolidated operating expenses, partially offset by increased expenses associated with higher outside services revenue.

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


	Nine Months Ended September 30,
	2007			2006
Segment Adjusted EBITDA	$	225,739		$	205,745

General and administrative		(23,370	)		(21,640	)
Depreciation, depletion and amortization		(63,022	)		(48,283	)
Interest expense, net		(7,321	)		(6,933	)
Income taxes		(1,794	)		(1,658	)
Minority interest		230			96
Cumulative effect of accounting change		—			112

Net income	$	130,462		$	127,439

MC Mining Mine Fire

On June 18, 2007, we agreed to a full and final resolution of our insurance claims relating to a mine fire that occurred on or about December 25, 2004 at our MC Mining’s Excel No. 3 mine. This resolution included settlement of all expenses, losses and claims we incurred for the aggregate amount of $31.6 million, inclusive of $8.2 million of various deductibles and co-insurance, netting to $23.4 million of insurance proceeds to us. In 2006 and 2005, we received partial advance payments on the claim totaling $16.2 million, part of which we recognized 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), with the remaining $5.1 million of partial payments previously included in other current liabilities in our consolidated financial statements pending final claim resolution. In June 2007, as a result of this final resolution, we received additional cash payments of $7.2 million and recognized a net gain from insurance settlement of approximately $11.5 million, as well as a reduction in operating expenses of approximately $0.8 million.

Liquidity and Capital Resources

Cash Flows

Cash provided by operating activities was $211.3 million for the 2007 Period compared to $184.5 million for the 2006 Period. The increase in cash provided by operating activities was primarily attributable to increased workers’ compensation liabilities, comparatively less of an increase in coal inventory and increased revenues partially offset by higher total operating expenses (excluding depreciation, depletion and amortization) associated with 851,000 additional tons sold, increased compliance costs, reduced production in response to an over supplied market in the 2007 Period and lost production associated with compliance with recently enacted federal and state mine safety regulations.

Net cash used in investing activities was $154.9 million for the 2007 Period compared to $95.7 million for the 2006 Period. The increased use of cash in the 2007 Period was primarily attributable to our acquisition of the rights to approximately 78.4 million tons of high-sulfur coal reserves in Webster and Hopkins County, Kentucky from Island Creek Coal Company, a subsidiary of Consol Energy, Inc. (the Providence Reserve Acquisition). See Note 3 Acquisitions to the Unaudited Condensed

Consolidated Financial Statements included in “Item 1. Financial Statement (Unaudited)” of this Quarterly Report on Form 10-Q. Additionally, there was a net decrease in proceeds from marketable securities, which were substantially liquidated to fund increased capital expenditures during 2006 and timing differences in accounts payable and accrued liabilities related to capital expenditures and advances made on the Gibson County Coal rail project described under “Other” below, partially offset by a decrease in capital expenditures. The decrease in capital expenditures in the 2007 Period (excluding the Providence Reserve Acquisition) was primarily attributable to the completion of the Elk Creek and Mountain View mines during 2006. The 2007 Quarter also benefited from increased proceeds from the sale of surplus plant, property and equipment.

Including initial development capital for the River View mine, we are currently estimating total capital expenditures in 2007 to range from approximately $170.0 million to $180.0 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, LLC, Gibson South and Penn Ridge Coal, LLC 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 from the board of directors of our managing general partner (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 $74.1 million for the 2007 Period compared to $84.3 million for the 2006 Period. The reduced use of cash primarily was attributable to net borrowings under our revolving credit facility of $27.0 million in the 2007 Period used to partially finance the Providence Reserve Acquisition partially offset by an increase in distributions paid to partners in the 2007 Period.

Capital Expenditures

Capital expenditures decreased to $95.0 million in the 2007 Period from $142.0 million in the 2006 Period. See discussion of “Cash Flows” above concerning the decrease in capital expenditures.

Debt Obligations

Senior Notes and Credit Facility

outstanding under the ARLP Credit Facility. The deferred cost associated with the amended $100.0 million credit facility accounted for as prescribed by EITF No. 98-14, Debtor’s Accounting for Changes in Line-of-Credit or Revolving-Debt Arrangements, which states that if the borrowing capacity of a new arrangement is greater than or equal to the borrowing capacity of an old arrangement, the unamortized deferred costs associated with the old arrangement should be associated with the new arrangement and amortized over the life of the new arrangement.

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 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 September 30, 2007.

We maintain 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 September 30, 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 secured line of credit (LOC) which was scheduled to expire on March 19, 2008. In September 2007, MAC entered into a $1.5 million Revolving Credit Agreement (Revolver) with ARLP. Concurrent with the execution of the Revolver, MAC repaid all amounts outstanding under the LOC. Due to the consolidation of MAC in accordance with FIN 46R, the intercompany transactions associated with the Revolver are eliminated.

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.

Because the transaction described above was a related-party transaction, it was reviewed by the Board of Directors 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. Our adoption of FIN No. 48 on January 1, 2007 did not have a material impact on our condensed 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.

Other

Gibson Rail Advances

In 2007, our subsidiary, Gibson County Coal has entered into contracts with CSX Transportation, Inc. (CSXT) and Norfolk Southern Railway Company (NS), pursuant to which Gibson County Coal is constructing a rail loop and the railroads are constructing connections and siding facilities, in order to provide Gibson County Coal 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 infrastructure. These advances will be repaid to Gibson County Coal by rebates from CSXT and NS as coal is shipped on their respective railways. In addition, Gibson County Coal will also qualify for additional rebates from both CSXT and NS. The additional rebates will be credited to operating expenses in the consolidated income statement as earned under the terms of each agreement. As of September 30, 2007, Gibson County Coal had advanced $5.9 million in aggregate to CSXT and NS, which is recorded in other receivables and other long-term assets in our condensed consolidated balance sheet.

Insurance

average rate of approximately 14.7% in the overall $75.0 million commercial property program representing 35% of the primary $30.0 million layer and 2.5% of the second layer of $20.0 million in excess of the $30.0 million primary layer. We do not participate in the third layer of $25.0 million in excess of $50.0 million.

The 14.7% participation rate for this year’s renewal is consistent with our prior year participation. The aggregate maximum limit in the commercial property program is $75.0 million per occurrence of which, as a result of our participation, we would be responsible for a maximum amount of $11.0 million for each occurrence, excluding a $1.5 million deductible for property damage, a $5.0 million aggregate deductible for extra expense and a 60-day waiting period for business interruption. We can make no assurances that we will not experience significant insurance claims in the future, which as a result of our level of participation in the commercial property program, could have a material adverse effect on our business, financial condition, results of operations and ability to purchase property insurance in the future.

MINER Act

The Mine Improvement and New Emergency Response Act of 2006 (MINER Act) requires mine-specific emergency response plans, enhanced communication and tracking systems, and more available mine rescue teams, as well as significantly higher penalty assessments by the Mine Safety and Health Administration (MSHA) for noncompliance by mine operators. Coal producing states, including West Virginia, Illinois, and Kentucky, passed similar legislation in 2006. 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. In April 2007, MSHA implemented new methods of calculation of penalty assessments, as required by the MINER Act, and in May 2007, MSHA adopted an Emergency Temporary Standard regulating construction and maintenance of mine seals. While the ultimate impact of these actions and the full cost of compliance remains unknown, during the 2007 Period we experienced reduced productivity and lost production and incurred increased capital expenditures and operating costs responding to these new laws and regulations, and continuing implementation of the MINER Act could result in further reductions in productivity and increased costs. In addition, future mine safety legislation also could impact our productivity and costs.

ITEM 3.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

We have long-term coal supply agreements. Virtually all of our long-term coal supply agreements contain price adjustment provisions, which permit an increase or decrease periodically in the contract price principally to 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. 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. Historically, our earnings have not been materially affected by changes in interest rates.

As of September 30, 2007, the estimated fair value of the Senior Notes was approximately $137.1 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 September 30, 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 U.S. Securities and Exchange Commission (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 September 30, 2007. This evaluation was performed under the supervision and with the participation of our management, including our Chief Executive and Chief Financial Officers. Based on this evaluation, 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 September 30, 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.

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 Securities 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 or cancellations or breaches of 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 action and court decisions;

•

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

•

the impact from provisions of or changes in enforcement activities associated with the Mine Improvement and New Emergency Response Act of 2006 as well as any subsequent federal or state safety legislation or regulations;

•

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 Part II, Item 1. “Legal Proceedings” and Item 1A. “Risk Factors.”

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.

PART II

OTHER INFORMATION

ITEM 1.

LEGAL PROCEEDINGS

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.

On April 24, 2006, we were served with a complaint from Mr. Ned Comer, et al., who we refer to as the plaintiffs, alleging that approximately 40 oil and coal companies, including us, which we refer to as the defendants, are liable to the plaintiffs for tortiously causing damage to plaintiffs’ property in Mississippi. The complaint was filed in the United States District Court, Southern District of Mississippi, Southern Division. The plaintiffs allege that the defendants’ greenhouse gas emissions caused global warming and resulted in the increase in the destructive capacity of Hurricane Katrina. On August 30, 2007, the court dismissed the plaintiffs’ complaint. On September 17, 2007 plaintiffs filed a notice of appeal of that dismissal to the United States Court of Appeals for the Fifth Circuit. We believe this complaint is without merit and we do not believe that an adverse decision in this litigation matter, if any, will have a material adverse effect on our business, financial position or results of operations.

On June 15, 2006, Mettiki Coal, LLC (Mettiki (MD)) was issued a Notice of Violation by the Maryland Department of the Environment (MDE) for alleged exceedances of permitted sulfur dioxide emissions. These alleged exceedances occurred between May 23, 2006 and June 12, 2006, at the Mettiki (MD) Thermal Coal Dryer associated with the longwall mining operation, located in Garrett County, Maryland. This self-reported violation was promptly corrected and Mettiki (MD) demonstrated to the satisfaction of MDE that it is in compliance with MDE regulations. On July 18, 2007 a consent decree was filed by the MDE which required Mettiki (MD) to pay a penalty assessment of $150,000. The assessment has been paid.

ITEM 1A.

RISK FACTORS

In addition to the other information set forth in this 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, as well as the additional risk factors discussed below which could materially affect our business, financial condition or future results. The risks described in our Annual Report on Form 10-K and this Quarterly Report on Form 10-Q 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, if such knowledge or facts 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 Internal Revenue Service (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.

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


10.1		Second Amended and Restated Credit Agreement, dated as of September 25, 2007, among Alliance Resource Operating Partners, L.P. as Borrower and the Initial Lenders, Initial Issuing Banks and Swing Line Bank and JPMorgan Chase Bank, N.A. as Paying Agent and Citicorp USA, Inc. and JP Morgan Chase Bank, N.A. as Co-Administrative Agents and Citigroup Global Markets Inc. and J.P. Morgan Securities Inc. as Joint Lead Arrangers and Joint Bookrunners (Incorporated by reference to Exhibit 99.1 of the Registrant’s Form 8-K filed with the Commission on September 27, 2007, File No. 000-26823).

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 November 9, 2007, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

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 November 9, 2007, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

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 November 9, 2007, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.


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 November 9, 2007, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

*	Filed herewith.

**	Furnished herewith.

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 November 9, 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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