ALLIANCE RESOURCE PARTNERS LP - Quarter Report: 2012 March (Form 10-Q)

ALLIANCE RESOURCE PARTNERS LP - Quarter Report: 2012 March (Form 10-Q)

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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 March 31, 2012

¨	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. x Yes ¨ No

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such

files). x Yes ¨ No

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

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange

Act). ¨ Yes x No

As of May 9, 2012, 36,874,949 common units are outstanding.

TABLE OF CONTENTS

PART I

FINANCIAL INFORMATION


		Page
ITEM 1.	Financial Statements (Unaudited)

	ALLIANCE RESOURCE PARTNERS, L.P. AND SUBSIDIARIES

	Condensed Consolidated Balance Sheets as of March 31, 2012 and December 31, 2011		1

	Condensed Consolidated Statements of Income for the three months ended March 31, 2012 and 2011		2

	Condensed Consolidated Statements of Comprehensive Income for the three months ended March 31, 2012 and 2011		3

	Condensed Consolidated Statements of Cash Flows for the three months ended March 31, 2012 and 2011		4

	Notes to Condensed Consolidated Financial Statements		5

ITEM 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		17

ITEM 3.	Quantitative and Qualitative Disclosures about Market Risk		28

ITEM 4.	Controls and Procedures		29

	Forward-Looking Statements		30

PART II

OTHER INFORMATION


ITEM 1.	Legal Proceedings	32

ITEM 1A.	Risk Factors	32

ITEM 2.	Unregistered Sales of Equity Securities and Use of Proceeds	32

ITEM 3.	Defaults upon Senior Securities	32

ITEM 4.	Mine Safety Disclosures	32

ITEM 5.	Other Information	32

ITEM 6.	Exhibits	33

PART I

FINANCIAL INFORMATION

ITEM 1.

FINANCIAL STATEMENTS

ALLIANCE RESOURCE PARTNERS, L.P. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

(In thousands, except unit data)

(Unaudited)


	March 31, 2012			December 31, 2011
ASSETS

CURRENT ASSETS:
Cash and cash equivalents	$	188,959		$	273,528
Trade receivables		119,608			128,643
Other receivables		564			3,525
Due from affiliates		3,161			5,116
Inventories		73,503			33,837
Advance royalties		7,559			7,560
Prepaid expenses and other assets		8,913			11,945

Total current assets		402,267			464,154

PROPERTY, PLANT AND EQUIPMENT:
Property, plant and equipment, at cost		2,087,996			1,974,520
Less accumulated depreciation, depletion and amortization		(826,137	)		(793,200	)

Total property, plant and equipment, net		1,261,859			1,181,320

OTHER ASSETS:
Advance royalties		30,420			27,916
Due from affiliate		776			—
Equity investments in affiliates		41,652			40,118
Other long-term assets		16,479			18,010

Total other assets		89,327			86,044

TOTAL ASSETS	$	1,753,453		$	1,731,518


LIABILITIES AND PARTNERS’ CAPITAL

CURRENT LIABILITIES:
Accounts payable	$	82,658		$	96,869
Due to affiliates		1,015			494
Accrued taxes other than income taxes		19,233			15,873
Accrued payroll and related expenses		33,626			35,876
Accrued interest		6,625			2,195
Workers’ compensation and pneumoconiosis benefits		9,511			9,511
Current capital lease obligations		662			676
Other current liabilities		18,830			15,326
Current maturities, long-term debt		33,000			18,000

Total current liabilities		205,160			194,820

LONG-TERM LIABILITIES:
Long-term debt, excluding current maturities		671,000			686,000
Pneumoconiosis benefits		56,064			54,775
Accrued pension benefit		27,400			27,538
Workers’ compensation		68,222			64,520
Asset retirement obligations		71,103			70,836
Long-term capital lease obligations		2,340			2,497
Other liabilities		7,464			6,774

Total long-term liabilities		903,593			912,940

Total liabilities		1,108,753			1,107,760


COMMITMENTS AND CONTINGENCIES

PARTNERS’ CAPITAL:
Limited Partners - Common Unitholders 36,874,949 and 36,775,741 units outstanding, respectively		961,739			943,325
General Partners’ deficit		(277,203	)		(279,107	)
Accumulated other comprehensive loss		(39,836	)		(40,460	)

Total Partners’ Capital		644,700			623,758

TOTAL LIABILITIES AND PARTNERS’ CAPITAL	$	1,753,453		$	1,731,518

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 March 31,
	2012			2011

SALES AND OPERATING REVENUES:
Coal sales	$	429,599		$	407,685
Transportation revenues		6,585			9,300
Other sales and operating revenues		7,402			6,273

Total revenues		443,586			423,258


EXPENSES:
Operating expenses (excluding depreciation, depletion and amortization)		273,515			256,118
Transportation expenses		6,585			9,300
Outside coal purchases		14,181			3,789
General and administrative		14,289			12,420
Depreciation, depletion and amortization		43,033			37,862

Total operating expenses		351,603			319,489


INCOME FROM OPERATIONS		91,983			103,769

Interest expense (net of interest capitalized for the three months ended March 31, 2012 and 2011 of $2,954 and $145, respectively)		(5,912	)		(9,310	)
Interest income		93			105
Equity in loss of affiliates, net		(3,778	)		—
Other income		215			587

INCOME BEFORE INCOME TAXES		82,601			95,151

INCOME TAX BENEFIT		(367	)		(229	)


NET INCOME	$	82,968		$	95,380


GENERAL PARTNERS’ INTEREST IN NET INCOME	$	25,587		$	21,005


LIMITED PARTNERS’ INTEREST IN NET INCOME	$	57,381		$	74,375


BASIC AND DILUTED NET INCOME PER LIMITED PARTNER UNIT (Note 7)	$	1.54		$	1.99


DISTRIBUTIONS PAID PER LIMITED PARTNER UNIT	$	0.99		$	0.86


WEIGHTED AVERAGE NUMBER OF UNITS OUTSTANDING - BASIC AND DILUTED		36,826,980			36,748,915

See notes to condensed consolidated financial statements.

ALLIANCE RESOURCE PARTNERS, L.P. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(In thousands)

(Unaudited)


	Three Months Ended March 31,
	2012		2011
NET INCOME	$	82,968	$	95,380

OTHER COMPREHENSIVE INCOME:
Defined benefit pension plan
Amortization of actuarial loss		430		122

Total defined benefit pension plan adjustments		430		122
Pneumoconiosis benefits
Amortization of actuarial loss (gain)		194		(56	)

Total pneumoconiosis benefits adjustments		194		(56	)

OTHER COMPREHENSIVE INCOME		624		66

TOTAL COMPREHENSIVE INCOME	$	83,592	$	95,446

See notes to condensed consolidated financial statements.

ALLIANCE RESOURCE PARTNERS, L.P. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)

(Unaudited)


	Three Months Ended March 31,
	2012			2011

CASH FLOWS PROVIDED BY OPERATING ACTIVITIES	$	114,804		$	120,848


CASH FLOWS FROM INVESTING ACTIVITIES:
Property, plant and equipment:
Capital expenditures		(105,339	)		(63,782	)
Changes in accounts payable and accrued liabilities		(6,664	)		(4,836	)
Proceeds from sale of property, plant and equipment		15			54
Purchase of equity investments in affiliate		(4,400	)		—
Payments to affiliate for development of coal reserves		(18,000	)		—
Advances/loans to affiliate		(776	)		—
Other		268			528
Net cash used in investing activities		(134,896)			(68,036)

CASH FLOWS FROM FINANCING ACTIVITIES:
Payments on capital lease obligations		(171	)		(166	)
Net settlement of employee withholding taxes on vesting of Long-Term Incentive Plan		(3,734	)		(2,324	)
Cash contributions by General Partners		150			87
Distributions paid to Partners		(60,722	)		(50,995	)

Net cash used in financing activities		(64,477	)		(53,398	)


NET CHANGE IN CASH AND CASH EQUIVALENTS		(84,569	)		(586	)

CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD		273,528			339,562


CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	188,959		$	338,976


SUPPLEMENTAL CASH FLOW INFORMATION:
Cash paid for interest	$	4,224		$	4,058

Cash paid for income taxes	$	—		$	—

NON-CASH INVESTING AND FINANCING ACTIVITY:
Accounts payable for purchase of property, plant and equipment	$	18,314		$	8,503

Market value of common units issued under Long-Term Incentive and Directors Deferred Compensation Plans before minimum statutory tax withholding requirements	$	11,070		$	6,572

Assets acquired by capital lease	$	—		$	3,525

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”), consisting of substantially all of ARH’s operating subsidiaries, but excluding ARH. ARH is owned by Joseph W. Craft III, the President and Chief Executive Officer and a Director of our managing general partner, and Kathleen S. Craft. SGP, a Delaware limited liability company, is owned by ARH and 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 become the owner and 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 (“IDR”) in ARLP and 15,544,169 common units of ARLP.

Basis of Presentation

The accompanying condensed consolidated financial statements include the accounts and operations of the ARLP Partnership and present our financial position as of March 31, 2012 and December 31, 2011 and the results of our operations, comprehensive income and cash flows for the three months ended March 31, 2012 and 2011. All of our intercompany transactions and accounts 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 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, 2011.

Use of Estimates

The preparation of the ARLP Partnership’s condensed consolidated financial statements in conformity with generally accepted accounting principles (“GAAP”) of the United States (“U.S.”) requires management to make estimates and assumptions that affect the reported amounts and disclosures in our condensed consolidated financial statements. Actual results could differ from those estimates.

2. NEW ACCOUNTING STANDARDS

New Accounting Standards Issued and Adopted

In May 2011, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2011-04, Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRSs (“ASU 2011-04”). ASU 2011-04 amends Accounting Standards Codification (“ASC”) 820, Fair Value Measurement, to provide a consistent definition of fair value and ensure that the fair value measurement and disclosure requirements are similar between GAAP and International Financial Reporting Standards. ASU 2011-04 changes certain fair value measurement principles and enhances the disclosure requirements particularly for Level 3 fair value measurements. ASU 2011-04 is effective for fiscal years, and interim periods within those years, beginning after December 15, 2011. The adoption of ASU 2011-04 did not have a material impact on our condensed consolidated financial statements.

In June 2011, the FASB issued ASU 2011-05, Presentation of Comprehensive Income (“ASU 2011-05”). ASU 2011-05 removes the presentation options in ASC 220, Comprehensive Income, and requires entities to report components of comprehensive income in either a continuous statement of comprehensive income or two separate but consecutive statements. Under the two statement approach, the first statement would include components of net income, and the second statement would include components of other comprehensive income (“OCI”). ASU 2011-05 does not change the items that must be reported in OCI. ASU 2011-05 is effective for fiscal years, and interim periods within those years, beginning after December 15, 2011, and its provisions must be applied retrospectively for all periods presented in the financial statements. In December 2011, the FASB issued ASU 2011-12, Comprehensive Income (Topic 220): Deferral of the Effective Date for Amendments to the Presentation of Reclassifications of Items Out of Accumulated Other Comprehensive Income in Accounting Standards Update No. 2011-05 (“ASU 2011-12”), which indefinitely deferred a provision of ASU 2011-05 that

required entities to present reclassification adjustments out of accumulated other comprehensive income by component in both the statement in which net income is presented and the statement in which OCI is presented. The adoption of ASU 2011-05 did not have a material impact on our condensed consolidated financial statements.

3. 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.

4. FAIR VALUE MEASUREMENTS

We apply the provisions of FASB ASC 820, Fair Value Measurement, which, among other things, defines fair value, requires enhanced disclosures about assets and liabilities carried at fair value and establishes a hierarchal disclosure framework based upon the quality of inputs used to measure fair value.

Valuation techniques are based upon observable and unobservable inputs. Observable inputs reflect market data obtained from independent sources, while unobservable inputs reflect our own market assumptions. These two types of inputs create the following fair value hierarchy:

•

Level 1 – Quoted prices for identical instruments in active markets.

•

Level 2 – Quoted prices for similar instruments in active markets; quoted prices for identical or similar instruments in markets that are not active; and model derived valuations whose inputs are observable or whose significant value drivers are observable.

•

Level 3 – Instruments whose significant value drivers are unobservable.

The carrying amounts for cash equivalents, accounts receivable and accounts payable approximate fair value because of the short maturity of those instruments. At March 31, 2012 and December 31, 2011, the estimated fair value of our long-term debt, including current maturities, was approximately $748.4 million and $746.5 million, respectively, based on interest rates that we believe are currently available to us for issuance of debt with similar terms and remaining maturities (Note 5). The fair value of debt, which is based upon interest rates for similar instruments in active markets, is classified as a Level 2 measurement under the fair value hierarchy.

5. LONG-TERM DEBT

Long-term debt consists of the following, (in thousands):


	March 31, 2012			December 31, 2011
Credit facility	$	—		$	—
Senior notes		54,000			54,000
Series A senior notes		205,000			205,000
Series B senior notes		145,000			145,000
Term loan		300,000			300,000

		704,000			704,000
Less current maturities		(33,000	)		(18,000	)

Total long-term debt	$	671,000		$	686,000

Our Intermediate Partnership has a $142.5 million revolving credit facility (the “ARLP Credit Facility”) which matures September 25, 2012, $54.0 million in senior notes (“Senior Notes”), $205.0 million in Series A and $145.0 million in Series B senior notes (collectively, the “2008 Senior Notes”) and a $300 million term loan (collectively, the “ARLP Debt Arrangements”), which are guaranteed by all of the material direct and indirect subsidiaries of our Intermediate Partnership. The ARLP Debt Arrangements 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 ARLP Debt Arrangements also require the Intermediate Partnership to remain in control of a certain amount of mineable coal reserves relative to its annual production. In addition, the ARLP Debt Arrangements require our Intermediate Partnership to maintain the following: (a) debt to cash flow ratio of not more than 3.0 to 1.0 and (b) cash flow to interest expense ratio of not less than 4.0 to 1. 0, in each case, during the four most recently ended fiscal quarters. The ARLP Credit Facility, Senior Notes and the 2008 Senior Notes limit our Intermediate Partnership’s maximum annual capital expenditures, excluding acquisitions (including the purchase price allocated to any equipment, fixed assets, real property or improvements acquired in connection with an acquisition). The amount of any annual limit in excess of actual capital expenditures for that year carries forward and is added to the annual limit of the subsequent year. As a result, the capital expenditure limit for 2012 is approximately $460.0 million. The debt to cash flow ratio and cash flow to interest expense ratio were 1.22 to 1.0 and 16.2 to 1.0, respectively, for the trailing twelve months ended March 31, 2012. Actual capital expenditures were $105.3 million for the three months ended March 31, 2012. We were in compliance with the covenants of the ARLP Debt Arrangements as of March 31, 2012.

At March 31, 2012, we had $11.6 million of letters of credit outstanding with $130.9 million available for borrowing under the ARLP Credit Facility. We had no borrowings outstanding under the ARLP Credit Facility as of March 31, 2012 and December 31, 2011. We utilize the ARLP Credit Facility, as appropriate, to meet working capital requirements, anticipated capital expenditures, scheduled debt payments or distribution payments. We incur an annual commitment fee of 0.375% on the undrawn portion of the ARLP Credit Facility.

6. WHITE OAK TRANSACTIONS

On September 22, 2011 (the “Transaction Date”), we entered into a series of transactions with White Oak Resources LLC (“White Oak”) and related entities to support development of a longwall mining operation

currently under construction. The transactions feature several components, including an equity investment in White Oak (represented by “Series A Units” containing certain distribution and liquidation preferences), the acquisition and leaseback of certain reserves and surface rights, a coal handling and services agreement and a backstop equipment financing facility. Our initial investment at the Transaction Date, using existing cash on hand, was $69.5 million and we committed to additionally fund approximately $330.5 million to $455.5 million over the next three to four years, of which $124.0 million was funded from the Transaction Date through March 31, 2012. We expect to fund these additional commitments using existing cash balances, future cash flows from operations, borrowings under revolving credit facilities and cash provided from the issuance of debt or equity. The following information discusses each component of these transactions in further detail.

Hamilton County, Illinois Reserve Acquisition

Our subsidiary, Alliance WOR Properties, LLC (“WOR Properties”) acquired from White Oak the rights to approximately 204.9 million tons of proven and probable high-sulfur coal reserves, of which 105.2 million tons are currently being developed for future mining by White Oak and certain surface properties and rights in Hamilton County, Illinois (the “Reserve Acquisition”), which is adjacent to White County, Illinois, where our White County Coal, LLC Pattiki mine is located. The asset purchase price of $33.8 million cash paid at closing was allocated to owned and leased coal rights. WOR Properties also provided $17.0 million to White Oak for the development of the acquired reserves between the Transaction Date and December 31, 2011. During the three months ended March 31, 2012, WOR Properties provided $18.0 million to White Oak for development of the acquired coal reserves and has a remaining commitment of $16.6 million for further development funding and $54.6 million for additional coal reserve acquisitions.

Equity Investment – Series A Units

Concurrent with the Reserve Acquisition, our subsidiary, Alliance WOR Processing, LLC (“WOR Processing”) made an equity investment of $35.7 million in White Oak to purchase Series A Units representing ownership in White Oak. WOR Processing also purchased $7.0 million of additional Series A Units between the Transaction Date and December 31, 2011. During the three months ended March 31, 2012, WOR Processing purchased $4.4 million of additional Series A Units.

WOR Processing’s ownership and member’s voting interest in White Oak at March 31, 2012 was 7.3% based upon currently outstanding voting units. The remainder of the equity ownership in White Oak, represented by Series B Units, is held by other investors and members of White Oak management.

We continually review all rights provided to WOR Processing and us by various agreements and continue to conclude all such rights are protective or participating in nature and do not provide WOR Processing or us the ability to unilaterally direct any of the four primary activities of White Oak that most significantly impact its economic performance. As such, we recognize WOR Processing’s interest in White Oak as an equity investment in affiliate in our consolidated balance sheets. As of March 31, 2012, WOR Processing had invested $47.1 million in Series A Units of White Oak equity, which represents our current maximum exposure to loss as a result of our involvement with White Oak. White Oak has made no distributions to WOR Processing or us.

We record WOR Processing’s equity in earnings or losses of affiliates under the hypothetical liquidation at book value method of accounting due to the preferences WOR Processing receives on distributions. For the three months ended March 31, 2012, we were allocated losses of $4.0 million.

Services Agreement

Simultaneous with the closing of the Reserve Acquisition, WOR Processing entered into a Coal Handling and Preparation Agreement (“Services Agreement”) with White Oak pursuant to which WOR Processing committed to construct and operate a coal preparation plant and related facilities and a rail loop and loadout facility to service the White Oak longwall Mine No. 1. The expected cost to construct the facilities contemplated by the Services Agreement is approximately $99.5 million and will be expended by WOR Processing over the next three years. In addition, the Intermediate Partnership agreed to loan $10.5 million to White Oak for the construction of various assets on the surface property, including but not limited to, a bathhouse, office and warehouse (“Construction Loan”). The Construction Loan has a term of 20 years, with repayment scheduled to begin in 2015. White Oak has not used any amounts available under the Construction Loan as of March 31, 2012.

Equipment Financing Commitment

Also on the Transaction Date, the Intermediate Partnership committed to provide $100.0 million of fully collateralized equipment financing with a five-year term to White Oak for the purchase of coal mining equipment should other third-party funding sources not be available. White Oak had used $0.8 million of the equipment financing as of March 31, 2012, which is included in Due from Affiliates on our condensed consolidated balance sheet.

7. NET INCOME PER LIMITED PARTNER UNIT

We apply the provisions of FASB ASC 260, Earnings Per Share (“FASB ASC 260”), which require the two-class method in calculating basic and diluted earnings per unit (“EPU”). Net income is allocated to the general partners and limited partners in accordance with their respective partnership percentages, after giving effect to any special income or expense allocations, including incentive distributions to our managing general partner, the holder of the IDR pursuant to our partnership agreement, which are declared and paid following the end of each quarter. Under the quarterly IDR 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. Our partnership agreement contractually limits our distributions to available cash; therefore, undistributed earnings of the ARLP Partnership are not allocated to the IDR holder. In addition, our outstanding awards under our Long-Term Incentive Plan (“LTIP”), Supplemental Executive Retirement Plan (“SERP”) and the MGP Amended and Restated Deferred Compensation Plan for Directors (“Deferred Compensation Plan”)include rights to nonforfeitable distributions or distribution equivalents and are therefore considered participating securities. As such, we allocate undistributed and distributed earnings to these outstanding awards in our calculation of EPU.

The following is a reconciliation of net income used for calculating basic earnings per unit and the weighted average units used in computing EPU for the three months ended March 31, 2012 and 2011, respectively, (in thousands, except per unit data):


	Three Months Ended March 31,
	2012			2011

Net income	$	82,968		$	95,380
Adjustments:
General partner’s priority distributions		(24,416	)		(19,488	)
General partners’ 2% equity ownership		(1,171	)		(1,517	)


Limited partners’ interest in net income		57,381			74,375

Less:
Distributions to participating securities		(498	)		(470	)
Undistributed earnings attributable to participating securities		(269	)		(600	)


Net income available to limited partners	$	56,614		$	73,305

Weighted average limited partner units outstanding – basic and diluted		36,827			36,749

Basic and diluted net income per limited partner unit⁽¹⁾	$	1.54		$	1.99

(1)

Diluted EPU gives effect to all dilutive potential common units outstanding during the period using the treasury stock method. Diluted EPU excludes all dilutive potential units calculated under the treasury stock method if their effect is anti-dilutive. For the three months ended March 31, 2012 and 2011, LTIP, SERP and Deferred Compensation Plan units of 377,229 and 410,971 were considered anti-dilutive under the treasury stock method.

8. WORKERS’ COMPENSATION AND PNEUMOCONIOSIS

The changes in the workers’ compensation liability (including current and long-term liability balances) for each of the periods presented were as follows (in thousands):


	Three Months Ended March 31,
	2012			2011

Beginning balance	$	73,201		$	67,687
Accruals increase		5,923			5,557
Payments		(2,906	)		(3,227	)
Interest accretion		684			793
Valuation loss		—			155

Ending balance	$	76,902		$	70,965

Certain of our mine operating entities are liable under state statutes and the Federal Coal Mine Health and Safety Act of 1969, as amended, to pay pneumoconiosis, or black lung, benefits to eligible employees and former employees and their dependents. Components of the net periodic benefit cost for each of the periods presented are as follows (in thousands):


	Three Months Ended March 31,
	2012		2011
Service cost	$	872	$	841
Interest cost		576		596
Amortization of net loss (gain)		194		(56	)

Net periodic benefit cost	$	1,642	$	1,381

9. COMPENSATION PLANS

Long-Term Incentive Plan

We have the LTIP for certain employees and officers of our managing general partner and its affiliates who perform services for us. The LTIP awards are grants of non-vested “phantom” or notional units, which upon satisfaction of vesting requirements, entitle the LTIP participant to receive ARLP common units. Annual grant levels and vesting provisions for designated participants are recommended by our President and Chief Executive Officer, subject to review and approval of the compensation committee of the MGP board of directors (the “Compensation Committee”). On January 25, 2012, the Compensation Committee determined that the vesting requirements for the 2009 grants of 9,125 restricted units (net of 500 forfeitures) and the grants issued during the three months ended December 31, 2008 of 135,305 restricted units (net of 5,840 forfeitures) had been satisfied as of January 1, 2012. As a result of this vesting, on February 14, 2012, we issued 93,938 unrestricted common units to the LTIP participants. The remaining units were settled in cash to satisfy the individual tax withholding obligations for the LTIP participants. On February 6, 2012, the Compensation Committee authorized additional grants of up to 106,779 restricted units, all of which were granted during the three months ended March 31, 2012 and will vest on January 1, 2015 subject to satisfaction of certain financial tests. The fair value of these 2012 grants is equal to the intrinsic value at the date of grant, which was $77.78 per unit. LTIP expense was $1.5 million and $1.1 million for the three months ended March 31, 2012 and 2011, respectively. After consideration of the January 1, 2012 vesting and subsequent issuance of 93,938 common units, approximately 2.2 million units remain available for issuance under the LTIP in the future, assuming all grants issued in 2010, 2011 and 2012 currently outstanding are settled with common units and no future forfeitures occur. On April 26, 2012, the Compensation Committee authorized additional grants of up to 8,500 restricted units, none of which have yet been granted.

As of March 31, 2012, there was $12.9 million in total unrecognized compensation expense related to the non-vested LTIP grants that are expected to vest. That expense is expected to be recognized over a weighted-average period of 1.7 years. As of March 31, 2012, the intrinsic value of the non-vested LTIP grants was $20.8 million. As of March 31, 2012, the total obligation associated with the LTIP was $7.1 million and is included in the partners’ capital-limited partners line item in our condensed consolidated balance sheets.

As provided under the distribution equivalent rights provisions of the LTIP, all non-vested grants include contingent rights to receive quarterly cash distributions in an amount equal to the cash distributions we make to unitholders during the vesting period.

SERP and Directors Deferred Compensation Plan

We utilize the SERP to provide deferred compensation benefits for certain officers and key employees. All allocations made to participants under the SERP are made in the form of “phantom” ARLP units.

Our directors participate in the Deferred Compensation Plan. Pursuant to the Deferred Compensation Plan, for amounts deferred either automatically or at the election of the director, a notional account is established and credited with notional common units of ARLP, described in the plan as “phantom” units.

For both the SERP and Deferred Compensation Plan, when quarterly cash distributions are made with respect to ARLP common units, an amount equal to such quarterly distribution is credited to each participant’s notional account as additional phantom units. All grants of phantom units under the SERP and Deferred Compensation Plan vest immediately.

Amounts that were payable under either the SERP or Deferred Compensation Plan on or prior to January 1, 2011, were paid in either cash or common units of ARLP. Effective for amounts that become payable after January 1, 2011, both the Deferred Compensation Plan and the SERP require that vested benefits be paid to participants only in common units of ARLP, and therefore the phantom units have qualified for equity award accounting treatment since that date. As a result, we reclassified a total of $9.2 million of obligations for the SERP and the Deferred Compensation Plan from due to affiliates and other long-term liabilities to partners’ capital in our condensed consolidated balance sheets as required under FASB ASC 718, Compensation-Stock Compensation, on January 1, 2011. For the three months ended March 31, 2012 and 2011, SERP and Deferred Compensation Plan participant notional account balances were credited with a total of 2,000 and 3,186 phantom units, respectively, and the fair value of these phantom units was $73.00 and $69.53, respectively, on a weighted-average basis. Total SERP and Deferred Compensation Plan expense was approximately $0.2 million for the three months ended March 31, 2012 and 2011, respectively.

As of March 31, 2012, there were 150,705 total phantom units outstanding under the SERP and Deferred Compensation Plan and the total intrinsic value of the SERP and Deferred Compensation Plan phantom units was $9.1 million. As of March 31, 2012, the total obligation associated with the SERP and Deferred Compensation Plan was $10.0 million and is included in the partners’ capital-limited partners line item in our condensed consolidated balance sheets.

10. COMPONENTS OF PENSION PLAN NET PERIODIC BENEFIT COSTS

Eligible employees at certain of our mining operations participate in a defined benefit plan (the “Pension Plan”) that we sponsor. The benefit formula for the Pension Plan is a fixed dollar unit based on years of service. Components of the net periodic benefit cost for each of the periods presented are as follows (in thousands):


	Three Months Ended March 31,
	2012			2011
Service cost	$	754		$	618
Interest cost		818			788
Expected return on plan assets		(956	)		(972	)
Amortization of net loss		430			122

Net periodic benefit cost	$	1,046		$	556

We previously disclosed in our financial statements for the year ended December 31, 2011 that we expected to contribute $5.4 million to the Pension Plan in 2012. During the three months ended March 31, 2012, we made a contribution payment of $0.8 million for the 2011 plan year. Additionally, on April 5, 2012, we made a payment of $2.2 million for the 2011 plan year. We do not expect to make

any further contributions in 2012 for the 2011 plan year. However, we do expect to make quarterly contributions of $1.0 million for the remainder of 2012 for the 2012 plan year and, therefore, will contribute approximately $6.0 million to the Pension Plan in 2012.

11. SEGMENT INFORMATION

We operate in the eastern U.S. as a producer and marketer of coal to major utilities and industrial users. We aggregate multiple operating segments into five reportable segments: the Illinois Basin, Central Appalachia, Northern Appalachia, White Oak and Other and Corporate. The first three reportable segments correspond to the three major coal producing regions in the eastern U.S. Similar economic characteristics for our operating segments within each of these three reportable segments include coal quality, coal seam height, mining and transportation methods and regulatory issues. The White Oak reportable segment includes our activities associated with the White Oak longwall Mine No. 1 development project. These activities currently encompass an equity investment in White Oak, the purchase and funding of development of the White Oak coal reserves and the construction and operation of surface facilities.

The Illinois Basin reportable segment is comprised of multiple operating segments, including Webster County Coal, LLC’s Dotiki mining complex, Gibson mining complex which includes Gibson County Coal, LLC’s Gibson North mine and the Gibson County Coal (South), LLC (“Gibson South”) project, Hopkins County Coal, LLC’s Elk Creek mining complex, White County Coal, LLC’s Pattiki mining complex, Warrior Coal, LLC’s mining complex, River View Coal, LLC’s mining complex, the Sebree Mining, LLC (“Sebree”) property and certain properties of Alliance Resource Properties, LLC (“Alliance Resource Properties”) and ARP Sebree, LLC. The development of the Gibson South mine is currently underway and we are in the process of permitting the Sebree property for future mine development. For information regarding the acquisition of the Onton No. 9 mining complex, which was added to the Illinois Basin segment in April 2012, please see Note 12 below.

The Central Appalachian reportable segment is comprised of two operating segments, the Pontiki Coal, LLC and MC Mining, LLC mining complexes.

The Northern Appalachian reportable segment is comprised of multiple operating segments, including Mettiki Coal, LLC’s mining complex, Mettiki Coal (WV) LLC’s Mountain View mining complex, two small third-party mining operations (one of which ceased operations in July 2011), the Tunnel Ridge, LLC (“Tunnel Ridge”) mine and the Penn Ridge Coal, LLC (“Penn Ridge”) property. In May 2010, incidental production began from mine development activities at Tunnel Ridge and longwall production is expected to begin in May 2012. We are in the process of permitting the Penn Ridge property for future mine development.

The White Oak reportable segment is comprised of two operating segments, WOR Properties and WOR Processing. WOR Processing includes both the surface operations at White Oak currently under construction and the equity investment in White Oak. WOR Properties owns coal reserves acquired from White Oak and is committed to fund future development of these reserves by White Oak. The White Oak reportable segment also includes a loan to White Oak for current financial activities related to the acquisition of mining equipment and will include future financing activities for another loan to construct certain surface facilities (Note 6).

Other and Corporate includes marketing and administrative expenses, Alliance Service, Inc. and its subsidiary, Matrix Design Group, LLC (“Matrix Design”), Alliance Design Group, LLC (“Alliance Design”) (collectively, Matrix Design and Alliance Design are referred to as the “Matrix Group”), the Mt. Vernon Transfer Terminal, LLC (“Mt. Vernon”) dock activities, coal brokerage activity, our equity investment in Mid-America Carbonates, LLC and certain properties of Alliance Resource Properties.

Reportable segment results as of and for the three months ended March 31, 2012 and 2011 are presented below.


	Illinois Basin		Central Appalachia		Northern Appalachia		White Oak			Other and Corporate		Elimination (1)			Consolidated
	(in thousands)
Reportable segment results as of and for the three months ended March 31, 2012 were as follows:

Total revenues (2)	$	342,230	$	41,166	$	47,105	$	—		$	17,104	$	(4,019	)	$	443,586
Segment Adjusted EBITDA Expense (3)		201,548		30,754		44,230		135			14,917		(4,103	)		287,481
Segment Adjusted EBITDA (4)(5)		136,892		10,210		282		(4,126	)		2,399		85			145,742
Total assets (6)		829,320		91,496		492,629		116,886			223,800		(678	)		1,753,453
Capital expenditures (7)		54,145		4,101		31,515		24,943			8,635		—			123,339

Reportable segment results as of and for the three months ended March 31, 2011 were as follows:

Total revenues (2)	$	317,587	$	47,705	$	53,703	$	—		$	9,677	$	(5,414	)	$	423,258
Segment Adjusted EBITDA Expense (3)		180,244		33,517		41,314		—			9,659		(5,414	)		259,320
Segment Adjusted EBITDA (4)(5)		130,733		13,571		10,315		—			19		—			154,638
Total assets (6)		782,637		84,228		338,755		—			358,761		(1,975	)		1,562,406
Capital expenditures		35,441		6,357		21,458		—			526		—			63,782

(1)	The elimination column represents the elimination of intercompany transactions and is primarily comprised of sales from the Matrix Group to our mining operations.

(2)	Revenues included in the Other and Corporate column are primarily attributable to the Matrix Group revenues, Mt. Vernon transloading revenues, administrative service revenues from affiliates and brokerage sales.

(3)

Segment Adjusted EBITDA Expense includes operating expenses, outside coal purchases and other income. Transportation expenses are excluded as these expenses are passed through to our customers and consequently we do not realize any gain or loss on transportation revenues. We review Segment Adjusted EBITDA Expense per ton for cost trends.

The following is a reconciliation of consolidated Segment Adjusted EBITDA Expense to operating expenses (excluding depreciation, depletion and amortization) (in thousands):


	Three Months Ended
	March 31,
	2012			2011
Segment Adjusted EBITDA Expense	$	287,481		$	259,320
Outside coal purchases		(14,181	)		(3,789	)
Other income		215			587

Operating expenses (excluding depreciation, depletion and amortization)	$	273,515		$	256,118

(4)

Segment Adjusted EBITDA is defined as net income before net interest expense, income taxes, depreciation, depletion and amortization and general and administrative expenses. Management therefore is able to focus solely on the evaluation of segment operating profitability as it relates to our revenues and operating expenses, which are primarily controlled by our segments. Consolidated Segment Adjusted EBITDA is reconciled to net income as follows (in thousands):


	Three Months Ended
	March 31,
	2012			2011
Consolidated Segment Adjusted EBITDA	$	145,742		$	154,638
General and administrative		(14,289	)		(12,420	)
Depreciation, depletion and amortization		(43,033	)		(37,862	)
Interest expense, net		(5,819	)		(9,205	)
Income tax benefit		367			229

Net income	$	82,968		$	95,380

(5)

Includes equity in income (loss) of affiliates for the three months ended March 31, 2012 of $(4.0) million included in the White Oak segment and $0.2 million included in the Other and Corporate segment. Includes equity in income of affiliates for the three months ended March 31, 2011 of $0.3 million included in the Other and Corporate segment.

(6)	Includes investments in affiliates at March 31, 2012 of $40.0 million included in the White Oak segment and $1.7 million included in the Other and Corporate segment. Includes investments in affiliates at March 31, 2011 of $1.5 million included in the Other and Corporate segment.

(7)	Capital expenditures shown above for the three months ended March 31, 2012, includes development funding to White Oak of $18.0 million (Note 6), which is described as “Payments to affiliate for development of coal reserves” in our condensed consolidated statements of cash flow.

12. SUBSEQUENT EVENTS

On April 30, 2012, we declared a quarterly distribution for the quarter ended March 31, 2012, of $1.025 per unit, on all common units outstanding, totaling approximately $63.0 million (which includes our managing general partner’s incentive distributions), payable on May 15, 2012 to all unitholders of record as of May 8, 2012.

On April 2, 2012, Alliance Coal and other subsidiaries of the ARLP Partnership acquired substantially all of Green River Collieries, LLC’s (“Green River”) coal-related assets located in Webster and Hopkins Counties, Kentucky. The transaction includes the Onton No. 9 mining complex and an estimated 40.0 million tons of coal reserves in the West Kentucky No. 9 coal seam. The Green River acquisition is consistent with our general business strategy and complements our current coal mining operations. A determination of the acquisition date fair values of the assets acquired and liabilities assumed from Green River is pending the completion of an independent appraisal and other evaluations.

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 coal primarily to major United States ("U.S.") utilities and industrial users. We began mining operations in 1971 and, since then, have grown through acquisitions and internal development to become the third largest coal producer in the eastern U.S. We operate eleven underground mining complexes, including the new Tunnel Ridge, LLC (“Tunnel Ridge”) mine in West Virginia, in Illinois, Indiana, Kentucky, Maryland and West Virginia. We are constructing a new mine in southern Indiana and operate a coal loading terminal on the Ohio River at Mt. Vernon, Indiana. Also, we have equity investments in White Oak Resources LLC (“White Oak”), we purchase and fund the development of reserves and are constructing surface facilities at White Oak’s new mining complex in southern Illinois. As is customary in the coal industry, we have entered into long-term coal supply agreements with many of our customers. For information regarding the acquisition of the Onton No. 9 mining complex, which was added to the Illinois Basin segment in April 2012, please read “Item 1. Financial Statements (Unaudited) – Note 12. Subsequent Events” of this Quarterly Report on Form 10-Q.

We have five reportable segments: Illinois Basin, Central Appalachia, Northern Appalachia White Oak and Other and Corporate. The first three reportable segments correspond to the three major coal producing regions in the eastern U.S. Factors similarly affecting financial performance of our operating segments within each of these three reportable segments include coal quality, coal seam height, mining and transportation methods and regulatory issues are similar within each of these three segments. The White Oak segment includes our activities associated with the White Oak longwall Mine No. 1 development project in southern Illinois which currently encompass an equity investment in White Oak, the purchase, leaseback and funding of development of the White Oak coal reserves and the construction and operation of surface facilities.

•

Illinois Basin reportable segment is comprised of multiple operating segments, including Webster County Coal, LLC’s Dotiki mining complex (“Dotiki”), the Gibson mining complex which includes Gibson County Coal, LLC’s Gibson North (“Gibson North”) mine and the Gibson

County Coal (South), LLC (“Gibson South”) project, Hopkins County Coal, LLC’s Elk Creek mining complex, White County Coal, LLC’s Pattiki mine, Warrior Coal, LLC’s mining complex, River View Coal, LLC’s (“River View”) mining complex, the Sebree Mining, LLC (“Sebree”) property and certain properties of Alliance Resource Properties, LLC (“Alliance Resource Properties”) and ARP Sebree, LLC. The development of the Gibson South mine is currently underway and we are in the process of permitting the Sebree property for future mine development. Sebree also includes the new Onton No. 9 mining complex, discussed above.

•

Central Appalachian reportable segment is comprised of two operating segments, the Pontiki Coal, LLC and MC Mining, LLC (“MC Mining”) mining complexes.

•

Northern Appalachian reportable segment is comprised of multiple operating segments, including Mettiki Coal, LLC’s mining complex (“Mettiki”), Mettiki Coal (WV), LLC’s Mountain View mining complex, two small third-party mining operations (one of which ceased operations in July 2011), the Tunnel Ridge mine and the Penn Ridge Coal, LLC (“Penn Ridge”) property. In May 2010, incidental production began from mine development activities at Tunnel Ridge and longwall production is expected to begin in May 2012. We are in the process of permitting the Penn Ridge property for future mine development.

•

White Oak reportable segment is comprised of Alliance WOR Properties, LLC (“WOR Properties”) and Alliance WOR Processing, LLC (“WOR Processing”). WOR Processing includes both the surface operations at White Oak currently under construction and the equity investment in White Oak. WOR Properties owns and controls the coal reserves acquired from White Oak, leases the reserves back to White Oak and is committed to certain funding of future development of these reserves by White Oak. The White Oak reportable segment also includes a loan to White Oak for current financial activities related to the acquisition of mining equipment and will include future financing activities for another loan to construct certain surface facilities.

•

Other and Corporate reportable segment includes marketing and administrative expenses, Alliance Service, Inc. (“ASI”) and its subsidiary, Matrix Design Group, LLC (“Matrix Design”), Alliance Design Group, LLC (collectively, Matrix Design and Alliance Design Group, LLC are referred to as the “Matrix Group”), the Mt. Vernon Transfer Terminal, LLC ("Mt. Vernon") dock activities, coal brokerage activity, our equity investment in Mid-America Carbonates, LLC ("MAC"), and certain properties of Alliance Resource Properties.

Three Months Ended March 31, 2012 Compared to Three Months Ended March 31, 2011

We reported net income of $83.0 million for the three months ended March 31, 2012 (“2012 Quarter”) compared to $95.4 million for the three months ended March 31, 2011 (“2011 Quarter”). This decrease of $12.4 million was principally due to delayed shipments of coal export sales, the pass through of losses related to the White Oak development project and higher operating expenses resulting from increased sales and production volumes, which particularly impacted materials and supplies expenses, labor-related expenses, maintenance costs and sales-related expenses, as well as higher depreciation, depletion and amortization and outside coal purchases. Labor-related expenses were further impacted by pay rate increases in the 2012 Quarter compared to the 2011 Quarter. Increased operating expenses also reflect increased incidental production at our Tunnel Ridge mine. The decreases to net income mentioned above were partially offset by improved pricing resulting in a higher quarterly average coal sales price of $54.99 per ton sold for the 2012 Quarter, as compared to $54.08 per ton sold for the 2011 Quarter. We had higher tons sold of 7.8 million tons and record tons produced of 8.5 million tons in the 2012 Quarter, compared to 7.5 million tons sold and 8.2 million tons produced in the 2011 Quarter.


	Three Months Ended March 31,
	2012		2011		2012		2011
	(in thousands)				(per ton sold)
Tons sold		7,812		7,538		N/A		N/A
Tons produced		8,512		8,220		N/A		N/A
Coal sales	$	429,599	$	407,685	$	54.99	$	54.08
Operating expenses and outside coal purchases	$	287,696	$	259,907	$	36.83	$	34.48

Coal sales. Coal sales for the 2012 Quarter increased 5.4% to $429.6 million from $407.7 million for the 2011 Quarter. The increase of $21.9 million in coal sales reflected the benefit of increased tons sold (contributing $14.8 million in additional coal sales) and higher average coal sales prices (contributing $7.1 million in additional coal sales). These increases were offset partially by lower coal export sales in the Northern Appalachian region in the 2012 Quarter. Average coal sales prices increased $0.91 per ton sold to $54.99 per ton in the 2012 Quarter compared to $54.08 per ton in the 2011 Quarter, primarily as a result of improved contract pricing.

Operating expenses and outside coal purchases. Operating expenses and outside coal purchases increased 10.7% to $287.7 million for the 2012 Quarter from $259.9 million for the 2011 Quarter, primarily due to increased coal sales and record production volumes. On a per ton basis, operating expenses and outside coal purchases increased 6.8% to $36.83 per ton sold. Operating expenses were impacted by various other factors, the most significant of which are also discussed below:

•

Labor and benefit expenses per ton produced, excluding workers’ compensation, increased 14.7% to $12.33 per ton in the 2012 Quarter from $10.75 per ton in the 2011 Quarter. This increase of $1.58 per ton represents pay rate increases and higher benefit expenses, particularly increased health care costs and retirement expenses, the impact of increased headcount as we continue to hire and train additional employees for our new Tunnel Ridge mine and the impact of lower recoveries at our Dotiki mine reflecting the transition to a new coal seam;

•

Materials and supplies expenses per ton produced increased 8.8% to $12.38 per ton in the 2012 Quarter from $11.38 per ton in the 2011 Quarter. The increase of $1.00 per ton produced resulted from an increase in cost for certain products and services, primarily outside services and contract labor used in the mining process (increase of $0.55 per ton), roof support (increase of $0.31 per ton), and power used in the mining process (increase of $0.13 per ton) in addition to the impact of increased incidental production from our new Tunnel Ridge mine;

•

Maintenance expenses per ton produced increased 7.0% to $4.30 per ton in the 2012 Quarter from $4.02 per ton in the 2011 Quarter. The increase of $0.28 per ton produced was primarily due to increased maintenance costs at our new Tunnel Ridge mine, increased longwall maintenance costs at our Mettiki mine and increased maintenance costs at our Dotiki mine as it transitions to a new coal seam;

•

Mine administration expenses increased $1.4 million for the 2012 Quarter compared to the 2011 Quarter, primarily due to higher regulatory costs and higher mine administration expenses at our Tunnel Ridge mine;

•

Contract mining expenses decreased $1.2 million for the 2012 Quarter compared to the 2011 Quarter. The decrease primarily reflects the permanent closure of one third-party mining operation in the Northern Appalachian region in July 2011;

•

Production taxes and royalties expenses (which were incurred as a percentage of coal sales prices and volumes) increased $0.15 per produced ton sold in the 2012 Quarter compared to the 2011 Quarter, primarily as a result of higher average coal sales prices; and

•

Outside coal purchases increased to $14.1 million for the 2012 Quarter compared to $3.8 million in the 2011 Quarter. The increase of $10.3 million was primarily attributable to increased coal brokerage activity as well as Mettiki’s higher cost per ton of coal purchased.

General and administrative. General and administrative expenses for the 2012 Quarter increased to $14.3 million compared to $12.4 million in the 2011 Quarter. The increase of $1.9 million was primarily due to increases in salary and wage related expenses as well as an increase in contributions to certain industry and advocacy groups.

Other sales and operating revenues. Other sales and operating revenues are principally comprised of Mt. Vernon transloading revenues, Matrix Design revenues and other outside services and administrative services revenue from affiliates. Other sales and operating revenues increased to $7.4 million for the 2012 Quarter from $6.3 million for the 2011 Quarter. The increase of $1.1 million was primarily attributable to increased Matrix Design product sales, partially offset by lower transloading revenues.

Depreciation, depletion and amortization. Depreciation, depletion and amortization expense increased to $43.0 million for the 2012 Quarter from $37.9 million for the 2011 Quarter. The increase of $5.1 million was attributable to additional depreciation expense related to the expansion of production capacity at the River View mine and continuing capital expenditures related to various infrastructure improvements and equipment expenditures at various mines.

Interest expense. Interest expense, net of capitalized interest, decreased to $5.9 million for the 2012 Quarter from $9.3 million for the 2011 Quarter. The decrease of $3.4 million was principally attributable to increased capitalized interest and reduced interest expense resulting from our August 2011 principal repayment of $18.0 million on our original senior notes issued in 1999, which is discussed in more detail below under “–Debt Obligations.”

Equity in loss of affiliates, net. Equity in loss of affiliates, net includes our equity investments in MAC and White Oak. For the 2012 Quarter, equity in loss of affiliates was $3.8 million, which was primarily attributable to losses of $4.0 million allocated to us due to our equity investment in White Oak.

Transportation revenues and expenses. Transportation revenues and expenses were $6.6 million and $9.3 million for the 2012 and 2011 Quarters, respectively. The decrease of $2.7 million was primarily attributable to reduced tonnage for which we arrange transportation at certain mines as well as a decrease in average transportation rates in the 2012 Quarter. The cost of transportation services are passed through to our customers. Consequently, we do not realize any gain or loss on transportation revenues.

Income tax benefit. The income tax benefit for the 2012 Quarter was $0.4 million compared to $0.2 million for the 2011 Quarter. Income taxes are primarily due to the operations of Matrix Design. The income tax benefit for the 2012 Quarter was due to a net operating loss carryforward related to Matrix Design from prior years as well as a research and development tax credit earned by Matrix Design. The income tax benefit in the 2011 Quarter was due to operating losses from our Matrix Design operation.

Segment Adjusted EBITDA. Our 2012 Quarter Segment Adjusted EBITDA decreased $8.9 million, or 5.8%, to $145.7 million from the 2011 Quarter Segment Adjusted EBITDA of $154.6 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 March 31,
	2012			2011			Increase/(Decrease)
Segment Adjusted EBITDA
Illinois Basin	$	136,892		$	130,733		$	6,159		4.7	%
Central Appalachia		10,210			13,571			(3,361	)	(24.8	)%
Northern Appalachia		282			10,315			(10,033	)	(97.3	)%
White Oak		(4,126	)		—			(4,126	)	(1	)
Other and Corporate		2,399			19			2,380		(1	)
Elimination		85			—			85		(1	)

Total Segment Adjusted EBITDA (2)	$	145,742		$	154,638		$	(8,896	)	(5.8	)%


Tons sold
Illinois Basin		6,513			6,174			339		5.5	%
Central Appalachia		509			595			(86	)	(14.5	)%
Northern Appalachia		708			769			(61	)	(7.9	)%
White Oak		—			—			—		—
Other and Corporate		82			—			82		(1	)
Elimination		—			—			—		—

Total tons sold		7,812			7,538			274		3.6	%


Coal sales
Illinois Basin	$	337,980		$	310,008		$	27,972		9.0	%
Central Appalachia		40,948			46,965			(6,017	)	(12.8	)%
Northern Appalachia		43,958			50,712			(6,754	)	(13.3	)%
White Oak		—			—			—		—
Other and Corporate		6,713			—			6,713		(1	)
Elimination		—			—			—		—

Total coal sales	$	429,599		$	407,685		$	21,914		5.4	%


Other sales and operating revenues
Illinois Basin	$	460		$	969		$	(509	)	(52.5	)%
Central Appalachia		16			123			(107	)	(87.0	)%
Northern Appalachia		554			917			(363	)	(39.6	)%
White Oak		—			—			—		—
Other and Corporate		10,391			9,678			713		7.4	%
Elimination		(4,019	)		(5,414	)		1,395		25.8	%

Total other sales and operating revenues	$	7,402		$	6,273		$	1,129		18.0	%


Segment Adjusted EBITDA Expense
Illinois Basin	$	201,548		$	180,244		$	21,304		11.8	%
Central Appalachia		30,754			33,517			(2,763	)	(8.2	)%
Northern Appalachia		44,230			41,314			2,916		7.1	%
White Oak		135			—			135		(1	)
Other and Corporate		14,917			9,659			5,258		54.4	%
Elimination		(4,103	)		(5,414	)		1,311		24.2	%

Total Segment Adjusted EBITDA Expense (3)	$	287,481		$	259,320		$	28,161		10.9	%

(1)	Percentage change was greater than or equal to 100%.

(2)

Segment Adjusted EBITDA (a non-GAAP financial measure) is defined as net income before net interest expense, income taxes, depreciation, depletion and amortization, and general and administrative expenses. Segment Adjusted EBITDA is a key component of consolidated EBITDA, which is used as a supplemental financial measure by management and by external users of our financial statements such as investors, commercial banks, research analysts and others, to assess:

•

the financial performance of our assets without regard to financing methods, capital structure or historical cost basis;

•

the ability of our assets to generate cash sufficient to pay interest costs and support our indebtedness;

•

our operating performance and return on investment compared to those of other companies in the coal energy sector, without regard to financing or capital structures; and

•

the viability of acquisitions and capital expenditure projects and the overall rates of return on alternative investment opportunities.

Segment Adjusted EBITDA is also used as a supplemental financial measure by our management for reasons similar to those stated in the previous explanation of EBITDA. In addition, the exclusion of corporate general and administrative expenses from Segment Adjusted EBITDA allows management to focus solely on the evaluation of segment operating profitability as it relates to our revenues and operating expenses, which are primarily controlled by our segments.

The following is a reconciliation of consolidated Segment Adjusted EBITDA to net income, the most comparable GAAP financial measure (in thousands):


	Three Months Ended March 31,
	2012			2011
Segment Adjusted EBITDA	$	145,742		$	154,638
General and administrative		(14,289	)		(12,420	)
Depreciation, depletion and amortization		(43,033	)		(37,862	)
Interest expense, net		(5,819	)		(9,205	)
Income tax benefit		367			229

Net income	$	82,968		$	95,380

(3)

Segment Adjusted EBITDA Expense (a non-GAAP financial measure) includes operating expenses, outside coal purchases and other income. Transportation expenses are excluded as these expenses are passed through to our customers and, consequently, we do not realize any gain or loss on transportation revenues. Segment Adjusted EBITDA Expense is used as a supplemental financial measure by our management to assess the operating performance of our segments. Segment Adjusted EBITDA Expense is a key component of EBITDA in addition to coal sales and other sales and operating revenues. The exclusion of corporate general and administrative expenses from Segment Adjusted EBITDA Expense allows management to focus solely on the evaluation of segment operating performance as it primarily relates to our operating expenses. Outside coal purchases are included in Segment Adjusted EBITDA Expense because tons sold and coal sales include sales from outside coal purchases.

The following is a reconciliation of consolidated Segment Adjusted EBITDA Expense to operating expense, the most comparable GAAP financial measure (in thousands):


	Three Months Ended March 31,
	2012			2011
Segment Adjusted EBITDA Expense	$	287,481		$	259,320
Outside coal purchases		(14,181	)		(3,789	)
Other income		215			587

Operating expense (excluding depreciation, depletion and amortization)	$	273,515		$	256,118

Illinois Basin – Segment Adjusted EBITDA increased 4.7% to $136.9 million in the 2012 Quarter from $130.7 million in the 2011 Quarter. The increase of $6.2 million was primarily attributable to increased tons sold, which increased 5.5% to 6.5 million tons in the 2012 Quarter, as well as improved contract pricing resulting in a higher average coal sales price of $51.90 per ton sold during the 2012 Quarter compared to $50.21 per ton sold for the 2011 Quarter. Coal sales increased 9.0% to $338.0 million in the 2012 Quarter compared to $310.0 million in the 2011 Quarter. The increase of $28.0 million reflects the increase in the average coal sales price discussed above and increased tons produced and sold from expansion of production capacity at our River View mine, partially offset by difficult mining conditions affecting production at certain mine operations. Total Segment Adjusted EBITDA Expense for the 2012 Quarter increased 11.8% to $201.5 million from $180.2 million in the 2011 Quarter and increased $1.76 per ton sold to $30.95 from $29.19 per ton sold, primarily as a result of certain cost increases described above under consolidated operating expenses, as well as lower coal production and recoveries at our Gibson North and Dotiki mines due to difficult mining conditions, partially offset by increased production at our River View mine.

Central Appalachia – Segment Adjusted EBITDA decreased 24.8% to $10.2 million for the 2012 Quarter compared to $13.6 million in the 2011 Quarter. The decrease of $3.4 million was primarily attributable to lower sales volumes as a result of difficult mining conditions at our MC Mining mine experienced during the 2012 Quarter and the continued impact of losing a production unit at the Pontiki mine due to regulatory action during the 2011 fourth quarter, partially offset by higher coal sales price per ton, which increased to $80.48 per ton sold in the 2012 Quarter from $78.98 per ton sold in the 2011 Quarter. Segment Adjusted EBITDA Expense per ton sold during the 2012 Quarter increased to $60.44 compared to $56.36 per ton sold in the 2011 Quarter, an increase of $4.08 per ton sold reflecting certain cost increases described above under consolidated operating expenses, including continued stringent regulatory compliance requirements, as well as lower production volumes described above. Although Segment Adjusted EBITDA Expense per ton sold increased in the 2012 Quarter, Segment Adjusted EBITDA Expense for the 2012 Quarter decreased 8.2% to $30.8 million from $33.5 million in the 2011 Quarter primarily as a result of lower coal sales volumes that partially offset the higher expenses per ton described above.

Northern Appalachia – Segment Adjusted EBITDA decreased 97.3% to $0.3 million for the 2012 Quarter as compared to $10.3 million in the 2011 Quarter. This decrease of $10.0 million was primarily attributable to lower coal sales volumes due to export coal shipment delays, as well as a lower average coal sales price of $62.06 per ton sold for the 2012 Quarter compared to $65.94 per ton sold for the 2011 Quarter. Total Segment Adjusted EBITDA Expense for the 2012 Quarter increased 7.1% to $44.2 million from $41.3 million in the 2011 Quarter and increased $8.73 per ton sold to $62.45 from $53.72 per ton sold, primarily as a result of higher cost per ton of purchased coal, the impact of increased incidental production from our new Tunnel Ridge mine and less coal produced from third-party operations due to one third party operator ceasing production in July 2011, as well as the other cost increases described above under consolidated operating expenses.

White Oak – Segment Adjusted EBITDA was $(4.1) million in the 2012 Quarter primarily attributable to losses allocated to us due to our equity interest in White Oak.

Other and Corporate – Segment Adjusted EBITDA increased $2.4 million in the 2012 Quarter from the 2011 Quarter. This increase was primarily attributable to higher coal brokerage sales and higher Matrix Group safety equipment sales. Segment Adjusted EBITDA Expense increased 54.4% to $14.9 million for the 2012 Quarter, primarily due to increased outside coal purchases, partially offset by decreased component expenses associated with safety equipment sales by Matrix Group.

Liquidity and Capital Resources

Liquidity

We have historically satisfied our working capital requirements and funded our capital expenditures and debt service obligations from cash generated from operations, cash provided by the issuance of debt or equity and borrowings under revolving credit facilities. We believe that existing cash balances, future cash flows from operations, borrowing under revolving credit facilities and cash provided from the issuance of debt or equity will be sufficient to meet our working capital requirements, anticipated capital expenditures, scheduled debt payments, commitments and distribution payments. Our ability to satisfy our obligations, commitments and planned expenditures will depend upon our future operating performance and access to and cost of financing sources, which will be affected by prevailing economic conditions generally and in the coal industry specifically, which are beyond our control. We expect that part of our financing and liquidity needs will be met through the issuance of debt or equity securities in the near term. Based on our recent operating results, current cash position, anticipated future cash flows and sources of financing that we expect to have available, we do not anticipate any significant liquidity constraints in the foreseeable future. However, to the extent operating cash flow or access to and cost of financing sources are materially different than expected, future liquidity may be adversely affected. Please read "Item 1A. Risk Factors" in the Annual Report on Form 10-K for the year ended December 31, 2011.

Cash Flows

Cash provided by operating activities was $114.8 million for the 2012 Quarter compared to $120.8 million for the 2011 Quarter. The decrease in cash provided by operating activities was principally attributable to lower net income, a decrease in the change in accounts payable during the 2012 Quarter compared to an increase during the 2011 Quarter and an increase in higher cost per ton coal inventory during the 2012 Quarter as compared to the 2011 Quarter. These decreases in cash provided by operating activities were partially offset by a decrease in trade receivables during the 2012 Quarter as compared to an increase during the 2011 Quarter.

Net cash used in investing activities was $134.9 million for the 2012 Quarter compared to $68.0 million for the 2011 Quarter. The increase in cash used in investing activities was primarily attributable to higher mine infrastructure and equipment capital expenditures at the Dotiki and Tunnel Ridge mines as well as increased capital expenditures at other mines and our funding of the White Oak project during the 2012 Quarter.

Net cash used in financing activities was $64.5 million for the 2012 Quarter compared to $53.4 million for the 2011 Quarter. The increase in cash used in financing activities was primarily attributable to increased distributions paid to partners in the 2012 Quarter.

Capital Expenditures

Capital expenditures increased to $105.3 million in the 2012 Quarter from $63.8 million in the 2011 Quarter. See “—Cash Flows” above for additional information regarding capital expenditures.

Our anticipated total capital expenditures for the year ending December 31, 2012 are estimated in a range of $565.0 to $610.0 million, which includes the acquisition of coal reserves from White Oak, funds provided to develop the reserves and construction of the related surface facilities of approximately $95.0 to $110.0 million and the acquisition of the Onton No. 9 mine in April 2012. For information regarding the acquisition of the Onton No. 9 mine, please read “Item 1. Financial Statements (Unaudited) – Note 12. Subsequent Events” of this Quarterly Report on Form 10-Q. Management anticipates funding remaining 2012 capital requirements with cash and cash equivalents ($189.0 million as of March 31, 2012), cash flows provided by operations and sources of financing that we expect to have available. We will continue to have significant capital requirements over the long-term, which may require us to obtain additional debt or equity capital. The availability and cost of additional 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.

Debt Obligations

ARLP Credit Facility. Our Intermediate Partnership maintains the ARLP Credit Facility, a $142.5 million revolving credit facility that matures September 25, 2012. The ARLP Credit Facility limits our annual capital expenditures, excluding acquisitions (including the purchase price allocated to any equipment, fixed assets, real property or improvements acquired in connection with an acquisition). The capital expenditure limit is $460.0 million for 2012. Our anticipated capital expenditures after exclusions noted above falls below the capital expenditure limit. The amount of any annual limit in excess of actual capital expenditures for that year carries forward and is added to the annual limit for the subsequent year.

At March 31, 2012, we had $11.6 million of letters of credit outstanding with $130.9 million available for borrowing under the ARLP Credit Facility. We had no borrowings outstanding under the ARLP Credit Facility as of March 31, 2012 or December 31, 2011. We utilize the ARLP Credit Facility, as appropriate, to meet working capital requirements, anticipated capital expenditures, scheduled debt payments or distribution payments. We incur an annual commitment fee of 0.375% on the undrawn portion of the ARLP Credit Facility.

Senior Notes. Our Intermediate Partnership has $54.0 million principal amount of 8.31% senior notes due August 20, 2014, payable in three remaining equal annual installments of $18.0 million with interest payable semi-annually (“Senior Notes”).

Series A Senior Notes. On June 26, 2008, our Intermediate Partnership entered into a Note Purchase Agreement (the “2008 Note Purchase Agreement”) with a group of institutional investors in a private placement offering. We issued $205.0 million of Series A senior notes, which bear interest at 6.28% and mature on June 26, 2015 with interest payable semi-annually.

Series B Senior Notes. On June 26, 2008, we issued under the 2008 Note Purchase Agreement $145.0 million of Series B senior notes (together with the Series A senior notes, the “2008 Senior Notes”), which bear interest at 6.72% and mature on June 26, 2018 with interest payable semi-annually.

Term Loan. On December 29, 2010, our Intermediate Partnership entered into a term loan agreement (the “Term Loan Agreement”) with various financial institutions for a term loan (the “Term Loan”) in the aggregate principal amount of $300 million. The Term Loan bears interest at a variable rate

plus an applicable margin which fluctuates depending upon whether we elect the Term Loan (or a portion thereof) to bear interest at the Base Rate or the Eurodollar Rate (as defined in the Term Loan Agreement). We have elected the Eurodollar Rate which, with applicable margin, was 2.25% as of March 31, 2012. Interest is payable quarterly with principal due as follows: $15 million due per quarter beginning March 31, 2013 through December 31, 2013, $18.75 million due per quarter beginning March 31, 2014 through September 30, 2015 and the balance of $108.75 million due on December 31, 2015. We have the option to prepay the Term Loan at any time in whole or in part subject to terms and conditions described in the Term Loan Agreement. Upon a “change of control” (as defined in the Term Loan Agreement), the unpaid principal amount of the Term Loan, all interest thereon and all other amounts payable under the Term Loan Agreement will become due and payable.

The ARLP Credit Facility, Senior Notes, 2008 Senior Notes and the Term Loan (collectively, “ARLP Debt Arrangements”) are guaranteed by all of the material direct and indirect subsidiaries of our Intermediate Partnership. The ARLP Debt Arrangements 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 ARLP Debt Arrangements also require the Intermediate Partnership to remain in control of a certain amount of mineable coal reserves relative to its annual production. In addition, the ARLP Debt Arrangements require our Intermediate Partnership to maintain the following: (a) debt to cash flow ratio of not more than 3.0 to 1.0 and (b) cash flow to interest expense ratio of not less than 4.0 to 1.0, in both cases, during the four most recently ended fiscal quarters. The ARLP Credit Facility, Senior Notes and the 2008 Senior Notes limit our Intermediate Partnership’s maximum annual capital expenditures, excluding acquisitions (including the purchase price allocated to any equipment, fixed assets, real property or improvements acquired in connection with an acquisition). The debt to cash flow ratio and cash flow to interest expense ratio were 1.22 to 1.0 and 16.2 to 1.0, respectively, for the trailing twelve months ended March 31, 2012. Actual capital expenditures were $105.3 million for the 2012 Quarter. We were in compliance with the covenants of the ARLP Debt Arrangements as of March 31, 2012.

Other. In addition to the letters of credit available under the ARLP Credit Facility discussed above, we also have agreements with two banks to provide additional letters of credit in an aggregate amount of $31.1 million to maintain surety bonds to secure certain asset retirement obligations and our obligations for workers’ compensation benefits. At March 31, 2012, we had $30.7 million in letters of credit outstanding under agreements with these two banks.

Related-Party Transactions

We have continuing related-party transactions with our managing general partner, AHGP and SGP and its 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 SGP and its affiliates and transactions with White Oak and related entities to support development of a longwall mining operation currently under construction.

On March 1, 2012, JC Air, LLC (“JC Air”), a wholly-owned subsidiary of our special general partner, was merged into our subsidiary, ASI. JC Air’s sole assets were two airplanes, one of which was previously subject to a time sharing agreement between SGP Land, LLC, another subsidiary of our special general partner, and us. In consideration for this merger, we paid SGP approximately $8.0 million cash at closing. Because the transaction was between entities under common control, it was reviewed by the board of directors of our managing general partner (the “Board of Directors”) and its conflicts committee (the “Conflicts Committee”). Based on this review, the Conflicts Committee determined that the transaction reflected market-clearing terms and conditions. As a result, the Board of Directors and the Conflicts Committee approved the transaction as fair and reasonable to us and our limited partners.

Please read our Annual Report on Form 10-K for the year ended December 31, 2011, "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations – Related-Party Transactions" for additional information concerning related-party transactions.

New Accounting Standards

New Accounting Standards Issued and Adopted

Other

Proposed Regulation

On March 27, 2012, the EPA proposed New Source Performance Standards (“NSPS”) for certain GHG (carbon dioxide) emissions from new and modified electricity generation units (“EGUs”). The proposed NSPS set the first numerical limits for carbon dioxide emissions for an entire source category. The proposed NSPS, if promulgated as proposed, would pose significant challenges for the construction of new coal-fired EGUs for some time. The proposed rule does not regulate existing EGUs or new EGUs that already have been permitted. If the rule is finalized as proposed, we would anticipate the rule would be legally challenged.

ITEM 3.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Commodity Price Risk

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

We have exposure to price risk for items that are used directly or indirectly in the normal course of coal production such as steel, electricity and other supplies. We manage our risk for these items through strategic sourcing contracts for normal quantities required by our operations. We do not utilize any commodity price-hedges or other derivatives related to these risks.

Credit Risk

Most of our sales tonnage is consumed by electric utilities. Therefore, our credit risk is primarily with domestic electric power generators. Our policy is to independently evaluate each customer’s creditworthiness prior to entering into transactions and to constantly monitor outstanding accounts receivable against established credit limits. When deemed appropriate by our credit management department, we will take steps to reduce our credit exposure to customers that do not meet our credit standards or whose credit has deteriorated. These steps may include obtaining letters of credit or cash collateral, requiring prepayments for shipments or establishing customer trust accounts held for our benefit in the event of a failure to pay.

Exchange Rate Risk

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.

Interest Rate Risk

Borrowings under the ARLP Credit Facility and Term Loan Agreement 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. We do not utilize any interest rate derivative instruments related to our outstanding debt. We had no borrowings under the ARLP Credit Facility and $300.0 million outstanding

under the Term Loan Agreement at March 31, 2012. A one percentage point increase in the interest rates related to the Term Loan Agreement would result in an annualized increase in 2012 interest expense of $3.0 million, based on borrowing levels at March 31, 2012. With respect to our fixed-rate borrowings, a one percentage point increase in interest rates would result in a decrease of approximately $15.8 million in the estimated fair value of these borrowings.

As of March 31, 2012, the estimated fair value of the ARLP Debt Arrangements was approximately $748.4 million. The fair values of long-term debt are estimated using discounted cash flow analyses, based upon our current incremental borrowing rates for similar types of borrowing arrangements as of March 31, 2012. There were no other 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, 2011.

ITEM 4.

CONTROLS AND PROCEDURES

We maintain controls and procedures designed to provide reasonable assurance that information required to be disclosed in the reports we file with the SEC is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC and that such information is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow for timely decisions regarding required disclosure. As required by Rule 13a-15(b) of the Exchange Act, we have evaluated, under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, 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 of 1934) as of March 31, 2012. Based on this evaluation, our Chief Executive Officer and Chief Financial Officer concluded that these controls and procedures are effective as of March 31, 2012.

During the quarterly period ended March 31, 2012, 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

Certain statements and information in this Quarterly Report on Form 10-Q may constitute “forward-looking statements.” 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:

•

changes in competition in coal markets and our ability to respond to such changes;

•

changes in coal prices, which could affect our operating results and cash flows;

•

risks associated with the expansion of our operations and properties;

•

the impact of health care legislation;

•

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

•

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

•

changing global economic conditions or in industries in which our customers operate;

•

liquidity constraints, including those resulting from any future unavailability of financing;

•

customer bankruptcies, cancellations or breaches to existing contracts, or other failures to perform;

•

customer delays, failure to take coal under contracts or defaults in making payments;

•

adjustments made in price, volume or terms to existing coal supply agreements;

•

fluctuations in coal demand, prices and availability due to labor and transportation costs and disruptions, equipment availability, governmental regulations, including those related to carbon dioxide emissions, and other factors;

•

legislation, regulatory and court decisions and interpretations thereof, including issues related to air and water quality and miner health and safety;

•

our productivity levels and margins earned on our coal sales;

•

unexpected changes in raw material costs;

•

unexpected changes in the availability of skilled labor;

•

our ability to maintain satisfactory relations with our employees;

•

any unanticipated increases in labor costs, adverse changes in work rules, or unexpected cash payments or projections associated with post-mine reclamation 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 reclamation as well as workers’ compensation and black lung benefits;

•

difficulty in making accurate assumptions and projections regarding pension, black lung benefits and other post-retirement benefit liabilities;

•

coal market’s share of electricity generation, including as a result of environmental concerns related to coal mining and combustion and the cost and perceived benefits of alternative sources of energy, such as natural gas, nuclear energy and renewable fuels;

•

uncertainties in estimating and replacing our coal reserves;

•

a loss or reduction of benefits from certain tax credits;

•

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

•

difficulty in making accurate assumptions and projections regarding future revenues and costs associated with equity investments in companies we do not control; and

•

other factors, including those discussed in “Part II. Item 1A. Risk Factors” and “Part II. Item 1. Legal Proceedings” of this Quarterly Report on Form 10-Q.

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 risks described in "Risk Factors" below. These risks 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 or considering any forward-looking statements contained in:

•

this Quarterly Report on Form 10-Q;

•

other reports filed by us with the SEC;

•

our press releases;

•

our website http://www.arlp.com; 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 3. Contingencies to the Unaudited Condensed Consolidated Financial Statements included in “Part I. 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” of the Annual Report on Form 10-K for the year ended December 31, 2011.

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, 2011 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.

ITEM 2.

UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

None.

ITEM 3.

DEFAULTS UPON SENIOR SECURITIES

None.

ITEM 4.

MINE SAFETY DISCLOSURES

Information concerning mine safety violations or other regulatory matters required by Section 1503(a) of the Dodd-Frank Wall Street Reform and Consumer Protection Act (“Dodd-Frank Act”) and Item 104 of Regulation S-K (17 CFR 229.104) is included in Exhibit 95.1 to this Quarterly Report on Form 10-Q.

ITEM 5.

OTHER INFORMATION

None.

ITEM 6.

EXHIBITS

Incorporated by Reference

Exhibit
Number

Exhibit Description

Form

SEC

File No. and

Film No.

Exhibit

Filing Date

Filed
Herewith*

10.1⁽¹⁾

Base Contract for Purchase and Sale of Coal, dated March 16, 2012, between Seminole Electric Cooperative, Inc. and Alliance Coal, LLC

10.2⁽¹⁾

Contract of Confirmation, effective March 16, 2012, between Seminole Electric Cooperative, Inc., Alliance Coal, LLC and Alliance Resource Partners, L.P.

10.3

Guaranty by Alliance Resource Partners, L.P.

31.1

Certification of Joseph W. Craft III, President and Chief Executive Officer of Alliance Resource Management GP, LLC, the managing general partner of Alliance Resource Partners, L.P., dated May 9, 2012, 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 May 9, 2012, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

32.1

32.2

95.1

Federal Mine Safety and Health Act Information

101

Interactive Data File (Form 10-Q for the quarter ended March 31, 2012 furnished in XBRL). The financial information contained in the XBRL-related documents is “unaudited” and “unreviewed” and, in accordance with Rule 406T of Regulation S-T, is not deemed “filed” or part of a registration statement or prospectus for purposes of Sections 11 and 12 of the Securities Act of 1933, as amended, and Section 18 of the Securities Exchange Act of 1934, as amended, or otherwise subject to liability under these sections.

*	Or furnished, in the case of Exhibits 32.1 and 32.2.

(1)	Application has been made to the Commission for confidential treatment of certain provisions of this exhibit. Omitted material for which confidential treatment has been requested has been filed separately with the Commission.

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized, in Tulsa, Oklahoma, on May 9, 2012.


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, duly authorized to sign on behalf of the registrant.

		/s/ Brian L. Cantrell
		Brian L. Cantrell
		Senior Vice President and Chief Financial Officer

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