Edgar Filing: ALLIANCE RESOURCE PARTNERS LP

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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

xQUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF

THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended September 30, 2015

oTRANSITION 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
(State or other jurisdiction of
incorporation or organization)

73-1564280
(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)

Large Accelerated Filer [X]	Accelerated Filer [ ]		Non-Accelerated Filer [ ]		Smaller Reporting Company [ ]
			(Do not check if smaller reporting company)

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

[ ] Yes [X] No

As of November 6, 2015, 74,188,784 common units are outstanding.

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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 September 30, 2015 and December 31, 2014	1

	Condensed Consolidated Statements of Income for the three and nine months ended September 30, 2015 and 2014	2

	Condensed Consolidated Statements of Comprehensive Income for the three and nine months ended September 30, 2015 and 2014	3

	Condensed Consolidated Statements of Cash Flows for the nine months ended September 30, 2015 and 2014	4

	Notes to Condensed Consolidated Financial Statements	5

ITEM 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	26

ITEM 3.	Quantitative and Qualitative Disclosures about Market Risk	46

ITEM 4.	Controls and Procedures	47

	Forward-Looking Statements	48

PART II

OTHER INFORMATION

ITEM 1.	Legal Proceedings	50

ITEM 1A.	Risk Factors	50

ITEM 2.	Unregistered Sales of Equity Securities and Use of Proceeds	50

ITEM 3.	Defaults Upon Senior Securities	51

ITEM 4.	Mine Safety Disclosures	51

ITEM 5.	Other Information	51

ITEM 6.	Exhibits	52

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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)

	September 30,			December 31,
ASSETS	2015			2014
CURRENT ASSETS:
Cash and cash equivalents	$	35,936		$	24,601
Trade receivables	171,402			184,187
Other receivables	628			1,025
Due from affiliates	168			7,221
Inventories	123,608			83,155
Advance royalties	7,663			9,416
Prepaid expenses and other assets	17,740			31,283
Total current assets	357,145			340,888

PROPERTY, PLANT AND EQUIPMENT:
Property, plant and equipment, at cost	3,215,566			2,815,620
Less accumulated depreciation, depletion and amortization	(1,336,176		)	(1,150,414		)
Total property, plant and equipment, net	1,879,390			1,665,206

OTHER ASSETS:
Advance royalties	26,887			15,895
Due from affiliate	-			11,047
Equity investments in affiliates	48,034			224,611
Goodwill (Note 4)	161,985			-
Other long-term assets	31,952			27,412
Total other assets	268,858			278,965
TOTAL ASSETS	$	2,505,393		$	2,285,059

LIABILITIES AND PARTNERS’ CAPITAL
CURRENT LIABILITIES:
Accounts payable	$	100,456		$	85,843
Due to affiliates	170			370
Accrued taxes other than income taxes	21,032			19,426
Accrued payroll and related expenses	47,514			57,656
Accrued interest	3,330			318
Workers’ compensation and pneumoconiosis benefits	8,893			8,868
Current capital lease obligations	1,333			1,305
Other current liabilities	27,003			17,109
Current maturities, long-term debt	142,159			230,000
Total current liabilities	351,890			420,895
LONG-TERM LIABILITIES:
Long-term debt, excluding current maturities	810,889			591,250
Pneumoconiosis benefits	58,858			55,278
Accrued pension benefit	38,566			40,105
Workers’ compensation	49,084			49,797
Asset retirement obligations	107,820			91,085
Long-term capital lease obligations	14,602			15,624
Other liabilities	22,453			5,978
Total long-term liabilities	1,102,272			849,117
Total liabilities	1,454,162			1,270,012

COMMITMENTS AND CONTINGENCIES
PARTNERS’ CAPITAL:
Alliance Resource Partners, L.P. (“ARLP”) Partners’ Capital:
Limited Partners - Common Unitholders 74,188,784 and 74,060,634 units outstanding, respectively	1,340,572			1,310,517
General Partners’ deficit	(257,593		)	(260,088		)
Accumulated other comprehensive loss	(33,669		)	(35,847		)
Total ARLP Partners’ Capital	1,049,310			1,014,582
Noncontrolling interest	1,921			465
Total Partners’ Capital	1,051,231			1,015,047
TOTAL LIABILITIES AND PARTNERS’ CAPITAL	$	2,505,393		$	2,285,059

See notes to condensed consolidated financial statements.

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ALLIANCE RESOURCE PARTNERS, L.P. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

(In thousands, except unit and per unit data)

(Unaudited)

	Three Months Ended September 30,					Nine Months Ended September 30,
	2015			2014		2015		2014

SALES AND OPERATING REVENUES:
Coal sales	$	547,466		$	548,357	$	1,632,493	$	1,649,093
Transportation revenues	9,395			6,001		24,323		17,816
Other sales and operating revenues	9,584			14,970		74,765		43,019
Total revenues	566,445			569,328		1,731,581		1,709,928

EXPENSES:
Operating expenses (excluding depreciation, depletion and amortization)	336,527			349,170		1,045,954		1,024,305
Transportation expenses	9,395			6,001		24,323		17,816
Outside coal purchases	2			3		326		7
General and administrative	17,948			16,995		52,336		54,201
Depreciation, depletion and amortization	84,661			69,646		242,730		203,539
Asset impairment charge	10,695			-		10,695		-
Total operating expenses	459,228			441,815		1,376,364		1,299,868

INCOME FROM OPERATIONS	107,217			127,513		355,217		410,060

Interest expense (net of interest capitalized for the three months ended September 30, 2015 of $152 and the nine months ended September 30, 2015 and 2014 of $518 and $833, respectively)	(7,352)			(8,584)		(23,626)		(25,395)
Interest income	285			432		1,421		1,238
Equity in (loss) income of affiliates, net	(17,221)			68		(49,049)		(13,546)
Other income	455			549		750		1,178
INCOME BEFORE INCOME TAXES	83,384			119,978		284,713		373,535

INCOME TAX EXPENSE	12			-		17		-

NET INCOME	83,372			119,978		284,696		373,535
LESS: NET LOSS ATTRIBUTABLE TO NONCONTROLLING INTEREST	7			-		27		-

NET INCOME ATTRIBUTABLE TO ALLIANCE RESOURCE PARTNERS, L.P. (“NET INCOME OF ARLP”)	$		83,379	$	119,978	$	284,723	$		373,535

GENERAL PARTNERS’ INTEREST IN NET INCOME OF ARLP	$		37,311	$	35,316	$	111,735	$		103,465

LIMITED PARTNERS’ INTEREST IN NET INCOME OF ARLP	$		46,068	$	84,662	$	172,988	$		270,070

BASIC AND DILUTED NET INCOME OF ARLP PER LIMITED PARTNER UNIT (Note 10)	$		0.61	$	1.13	$	2.29	$		3.59

DISTRIBUTIONS PAID PER LIMITED PARTNER UNIT	$		0.675	$	0.625	$	1.9875	$		1.835

WEIGHTED AVERAGE NUMBER OF UNITS OUTSTANDING – BASIC AND DILUTED	74,188,784			74,060,634		74,169,538		74,038,952

See notes to condensed consolidated financial statements.

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ALLIANCE RESOURCE PARTNERS, L.P. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(In thousands)

(Unaudited)

	Three Months Ended September 30,				Nine Months Ended September 30,
	2015		2014		2015		2014

NET INCOME	$	83,372	$	119,978	$	284,696	$	373,535

OTHER COMPREHENSIVE INCOME/(LOSS):

Defined benefit pension plan:
Amortization of net actuarial loss (1)	839		193		2,516		580
Total defined benefit pension plan adjustments	839		193		2,516		580

Pneumoconiosis benefits:
Amortization of net actuarial gain (1)	(113)		(263)		(338)		(789)
Total pneumoconiosis benefits adjustments	(113)		(263)		(338)		(789)

OTHER COMPREHENSIVE INCOME/(LOSS)	726		(70)		2,178		(209)

COMPREHENSIVE INCOME	84,098		119,908		286,874		373,326

Less: Comprehensive loss attributable to noncontrolling interest	7		-		27		-

COMPREHENSIVE INCOME ATTRIBUTABLE TO ARLP	$	84,105	$	119,908	$	286,901	$	373,326

(1)	Amortization of net actuarial (gain)/loss is included in the computation of net periodic benefit cost (see Notes 11 and 13 for additional details).

See notes to condensed consolidated financial statements.

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ALLIANCE RESOURCE PARTNERS, L.P. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)

(Unaudited)

	Nine Months Ended September 30,
	2015		2014

CASH FLOWS PROVIDED BY OPERATING ACTIVITIES	$	528,895	$	586,393

CASH FLOWS FROM INVESTING ACTIVITIES:
Property, plant and equipment:
Capital expenditures	(159,182)		(233,659)
Changes in accounts payable and accrued liabilities	(3,093)		145
Proceeds from sale of property, plant and equipment	1,519		272
Proceeds from insurance settlement for property, plant and equipment	-		4,512
Purchases of equity investments in affiliates	(47,624)		(85,250)
Payments for acquisitions of businesses, net of cash acquired (Note 4)	(74,953)		-
Payments to affiliate for acquisition and development of coal reserves	-		(1,401)
Advances/loans to affiliate	(7,300)		-
Other	1,807		-
Net cash used in investing activities	(288,826)		(315,381)

CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowings under securitization facility	6,500		-
Payments under securitization facility	(6,500)		-
Payments on term loans	(20,319)		(12,500)
Borrowings under revolving credit facilities	463,000		221,800
Payments under revolving credit facilities	(200,000)		(301,800)
Payment on long-term debt	(205,000)		(18,000)
Payments on capital lease obligations	(994)		(1,113)
Contribution to consolidated company from affiliate noncontrolling interest	1,483		-
Net settlement of employee withholding taxes on vesting of Long-Term Incentive Plan	(2,719)		(2,991)
Cash contributions by General Partners	95		111
Distributions paid to Partners	(258,697)		(235,344)
Other	(5,583)		-
Net cash used in financing activities	(228,734)		(349,837)

NET CHANGE IN CASH AND CASH EQUIVALENTS	11,335		(78,825)

CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD	24,601		93,654

CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	35,936	$	14,829

SUPPLEMENTAL CASH FLOW INFORMATION:
Cash paid for interest	$	20,164	$	20,381
Cash paid for income taxes	$	14	$	-

NON-CASH INVESTING AND FINANCING ACTIVITY:
Accounts payable for purchase of property, plant and equipment	$	12,561	$	18,069
Market value of common units issued under Long-Term Incentive and Directors Deferred Compensation Plans before minimum statutory tax withholding requirements	$	7,389	$	8,417
Acquisition of businesses:
Fair value of assets assumed	$	273,196	$	-
Cash paid	(74,953)		-
Fair value of liabilities assumed	$	198,243	$	-
Disposition of property, plant and equipment:
Net change in assets	$	-	$	846
Book value of liabilities transferred	-		(5,246)
Gain recognized	$	-	$	(4,400)

See notes to condensed consolidated financial statements.

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ALLIANCE RESOURCE PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

1. ORGANIZATION AND PRESENTATION

Significant Relationships Referenced in Notes to Condensed Consolidated Financial Statements

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

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

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

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

· References to “Intermediate Partnership” mean Alliance Resource Operating Partners, L.P., the intermediate partnership of Alliance Resource Partners, L.P.

· References to “Alliance Coal” mean Alliance Coal, LLC, the holding company for the substantial majority of the operations of Alliance Resource Operating Partners, L.P., also referred to as our primary 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 are managed by 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 31,088,338 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 September 30, 2015 and December 31, 2014, the results of our operations and comprehensive income for the three and nine months ended September 30, 2015 and 2014 and the cash flows for the nine months ended September 30, 2015 and 2014. All of our intercompany transactions and accounts have been eliminated.

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These condensed consolidated financial statements and notes are unaudited. However, in the opinion of management, these financial statements reflect all 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 to be expected for the full year ending December 31, 2015.

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 do not include all of the information normally included with financial statements prepared in accordance with generally accepted accounting principles (“GAAP”) of the United States. These financial statements should be read in conjunction with the audited consolidated financial statements and notes thereto included in our Annual Report on Form 10-K for the year ended December 31, 2014.

On June 16, 2014, we completed a two-for-one split of our common units, whereby holders of record as of May 30, 2014 received a one unit distribution on each unit outstanding on that date. The unit split resulted in the issuance of 37,030,317 common units. All references to the number of units and per unit net income of ARLP and distribution amounts included in this report have been adjusted to give effect for this unit split for all periods presented. Also, ARLP’s partnership agreement was amended effective June 16, 2014, to reduce by half the target thresholds for the incentive distribution rights per unit.

Use of Estimates

The preparation of the ARLP Partnership’s condensed consolidated financial statements in conformity with GAAP 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.

Goodwill

Goodwill is not amortized, but is subject to an annual review on November 30, 2015, or at other dates if events or changes in circumstances indicate that the carrying value of goodwill may be impaired. The reporting unit or units used to evaluate and measure goodwill for impairment are determined primarily from the manner in which the business is managed or operated. A reporting unit is an operating segment or a component that is one level below an operating segment. There were no impairments of goodwill during the three and nine month periods ended September 30, 2015.

2. NEW ACCOUNTING STANDARDS

New Accounting Standard Issued and Adopted

In April 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2014-08, Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity (“ASU 2014-08”). ASU 2014-08 changes the requirements for reporting discontinued operations in Accounting Standards Codification (“ASC”) 205, Presentation of Financial Statements, by updating the criteria for determining which disposals can be presented as discontinued operations and requires new disclosures of both discontinued operations and certain other disposals that do not meet the definition of discontinued operations. ASU 2014-08 was effective for fiscal years, and interim periods within those years, beginning after December 15, 2014. The adoption of ASU 2014-08 did not have a material impact on our condensed consolidated financial statements.

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16 is effective for fiscal years, and interim periods within those years, beginning after December 15, 2015 with early adoption permitted and shall be applied prospectively after adoption. We elected to early adopt the standard in September 2015. The adoption of ASU 2015-16 did not have a material impact on our condensed consolidated financial statements.

New Accounting Standards Issued and Not Yet Adopted

In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers (“ASU 2014-09”). ASU 2014-09 is a new revenue recognition standard that provides a five-step analysis of transactions to determine when and how revenue is recognized. The core principle of the new standard is an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. The standard will be applied retrospectively to each period presented or as a cumulative-effect adjustment as of the date of adoption. ASU 2014-09 was originally effective for fiscal years, and interim periods within those years, beginning after December 15, 2016. In August 2015, the FASB issued ASU 2015-14, Revenue from Contracts with Customers: Deferral of the Effective Date, which defers the effective date by one year while providing the option to early adopt the standard on the original effective date. We are currently evaluating the effect of adopting ASU 2014-09.

In August 2014, the FASB issued ASU 2014-15, Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern (“ASU 2014-15”). ASU 2014-15 provides guidance on management’s responsibility in evaluating whether there is substantial doubt about an entity’s ability to continue as a going concern and to provide related footnote disclosures. ASU 2014-15 is effective for the annual period ending after December 15, 2016, and for annual periods and interim periods thereafter with early adoption permitted. We do not anticipate the adoption of ASU 2014-15 will have a material impact on our consolidated financial statements.

In February 2015, the FASB issued ASU 2015-02, Consolidation (“ASU 2015-02”). ASU 2015-02 changes the requirements and analysis required when determining the reporting entity’s need to consolidate an entity, including modifying the evaluation of limited partnership variable interest status, presumption that a general partner should consolidate a limited partnership and the consolidation criterion applied by a reporting entity involved with variable interest entities. ASU 2015-02 is effective for fiscal years, and interim periods within those years, beginning after December 15, 2015 and shall be applied retrospectively to each period presented. Early adoption is permitted. We are currently evaluating the effect of adopting ASU 2015-02.

In April 2015, the FASB issued ASU 2015-03, Interest – Imputation of Interest (“ASU 2015-03”). ASU 2015-03 changes the classification and presentation of debt issuance costs by requiring debt issuance costs to be reported as a direct deduction from the face amount of the debt liability rather than an asset. Amortization of the costs is reported as interest expense. The amendment does not affect the current guidance on the recognition and measurement of debt issuance costs. ASU 2015-03 is effective for fiscal years, and interim periods within those years, beginning after December 15, 2015 and shall be applied retrospectively to each period presented. We do not anticipate the adoption of ASU 2015-03 will have a material impact on our consolidated financial statements.

In April 2015, the FASB issued ASU 2015-06, Effects on Historical Earnings per Unit of Master Limited Partnership Dropdown Transactions (“ASU 2015-06”). ASU 2015-06 specifies that for purposes of calculating historical earnings per unit under the two-class method, the earnings of a transferred business before the date of a dropdown transaction should be allocated entirely to the general partner. Earnings per unit of the limited partners would not change as a result of the dropdown transaction. ASU 2015-06 is effective for fiscal years, and interim periods within those years, beginning after December 15, 2015 and shall be applied retrospectively to each period presented. Early adoption is permitted. We are currently evaluating the effect of adopting ASU 2015-06.

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3. CONTINGENCIES

Various lawsuits, claims and regulatory proceedings incidental to our business are pending against the ARLP Partnership. We record accruals for potential losses related to these matters when, in management’s opinion, such losses are 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. ACQUISITIONS

White Oak Resources

On July 31, 2015 (the “Hamilton Acquisition Date”) our subsidiary, Alliance WOR Processing, LLC (now known as Hamilton County Coal, LLC, or “Hamilton”) acquired the remaining Series A and B Units, representing 60% of the voting interests of White Oak Resources LLC (“White Oak”), from White Oak Finance Inc. and other parties (the “Sellers”) for total fair value consideration of $287.3 million (the “Hamilton Acquisition”), consisting of the following:

	(in thousands)
Cash on hand	$	50,000
Contingent consideration	14,300
Settlement of pre-existing relationships	119,663
Previously held equity-method investment	103,322
Total consideration	$	287,285

The Partnership now owns 100% of the interests in White Oak and has assumed operating control of the White Oak Mine No. 1 (now known as Hamilton Mine No. 1), an underground longwall mining operation located in Hamilton County, Illinois. The Hamilton Acquisition is consistent with our general business strategy and a strategic complement to our current coal mining operations. The Partnership expects to achieve synergies and cost reductions by using its other owned facilities and reserves, as well as utilizing its centralized marketing, operations and administrative functions.

The contingent consideration is payable to the Sellers to the extent Hamilton’s quarterly average coal sales price exceeds a specified amount on future sales. Amounts payable under the contingent consideration arrangement are subject to a defined maximum of $110.0 million reduced for any payments that we make under an overriding royalty agreement between White Oak and certain of the Sellers relating to undeveloped mineral interests controlled by White Oak. The fair value of the contingent consideration arrangement at the Hamilton Acquisition Date was $14.3 million. We estimated the fair value of the contingent consideration using a probability-weighted discounted cash flow model. The assumptions used in the model included a risk-adjusted discount rate, forward coal sales price curves, and probabilities of meeting certain threshold prices. The fair value measurement is based on significant inputs not observable in the market and thus represents a Level 3 fair value measurement. As of September 30, 2015, there were no significant changes in the range of outcomes for the contingent consideration recognized as a result of the Hamilton Acquisition.

We are in the process of performing our valuation of our previously held equity method investment, our pre-existing relationships, the contingent consideration, and the acquired assets and liabilities. Given the recent date of the acquisition and the number of valuations we need to complete, we have not finalized our valuations and therefore have recorded our acquisition using our best estimates of the fair value of the various measurements based on preliminary information. As we finalize the various valuations and we complete our review of those valuations in subsequent periods, it is possible that certain amounts related to this transaction could result in measurement period adjustments which would be recorded in those subsequent periods. As a result, we consider our accounting of the Hamilton Acquisition to be preliminary pending completion of our valuations.

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Prior to the Hamilton Acquisition Date, we accounted for our 40% interest in White Oak as an equity-method investment. The acquisition date fair value of the previous equity interest was $103.3 million and is included in the measurement of the consideration transferred. We re-measured our equity investment immediately prior to the Hamilton Acquisition using a discounted cash flow model. The assumptions used in the determination of the fair value include projected financial information, forward coal price curves, and a risk adjusted discount rate. The assumptions used in this fair value measurement are not observable in the market and therefore represents a Level 3 fair value measurement.

In connection with the Hamilton Acquisition, we settled our pre-existing relationships with White Oak which included existing account balances of $49.6 million and contractual agreements comprised of coal leases, a coal handling and preparation agreement, a coal supply agreement, a marketing and transportation agreement and certain debt agreements. As a result of settling the existing account balances between White Oak and the Partnership, as well as the recognition of net gains associated with the above-market components of our pre-existing contractual relationships, we included $119.7 million in the measurement of consideration transferred. As part of our settlement of these agreements, we considered the rates at which a market participant would enter into these agreements and recognized gains for the above-market rates and losses for the below-market rates contained in the various agreements. We developed a discounted cash flow model to determine the fair value of each of these agreements at market rates and compared the valuations to similar models using the contractual rates of the agreements to determine our gains or losses. The assumptions used in these valuation models include processing rates, royalty rates, transportation rates, marketing rates, forward coal price curves, current interest rates, projected financial information and risk-adjusted discount rates. These fair value measurements were based on the previously discussed assumptions which are not observable in the market and therefore represent Level 3 fair value measurements.

As a result of our re-measurement of our equity investment, we recognized a loss which was completely offset by an overall gain related to the above-market rates associated with our pre-existing relationships.

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The following table summarizes the preliminary fair value allocation of assets acquired and liabilities assumed at the Hamilton Acquisition Date:

	Preliminary as of September 30, 2015
	(in thousands)

Cash and cash equivalents	$	3,125
Trade receivables	3,122
Prepaid expenses	4,364
Inventories	7,240
Other current assets	9,415
Property, plant and equipment	258,798
Advance royalties	3,349
Deposits	6,981
Other assets	5,580
Total identifiable assets acquired	301,974

Accounts payable	(31,399)
Accrued expenses	(18,609)
Deferred revenue	(517)
Current maturities, long-term debt	(29,529)
Long-term debt, excluding current maturities	(64,588)
Other long-term liabilities	(15,175)
Asset retirement obligations	(12,484)
Total liabilities assumed	(172,301)
Net identifiable assets acquired	$	129,673
Goodwill	157,612
Net assets acquired	$	287,285

The goodwill recognized is attributable to expected synergies primarily consisting of being able to utilize our previously owned coal handling and preparation plant rather than incurring external fees, the reduction of royalties associated with reserves being leased from us by Hamilton, and the use of our centralized marketing, operations and administrative functions. Allocation of the goodwill to its reporting units has not been completed, however, it is expected to be allocated to applicable reporting units within the Illinois Basin segment. As of September 30, 2015, there were no changes in the recognized amounts of goodwill resulting from the Hamilton Acquisition.

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The amounts of revenue and earnings of Hamilton included in the Partnership’s condensed consolidated statements of income from the acquisition date to the period ending September 30, 2015 are as follows:

	(in thousands)

Revenue	$	29,302
Net income	(6,120)

The following represents the pro forma condensed consolidated income statement as if Hamilton had been included in the consolidated results of the Partnership since January 1, 2014. These amounts have been calculated after applying the Partnership’s accounting. Additionally, the Partnership’s results have been adjusted to remove the effect of its equity investment in White Oak and the preexisting relationships that it had in White Oak.

		Three Months Ended September 30,				Nine Months Ended September 30,
		2015		2014		2015	2014
		(in thousands)

Total revenues
As reported	$	566,445	$	569,328	$	1,731,581	$	1,709,928
Pro forma		575,160		578,869		1,795,228	1,733,404

Net income
As reported	$	83,372	$	119,978	$	284,696	$	373,535
Pro forma		80,299		110,991		272,327	361,361

Patriot Coal Corporation

On December 31, 2014 (the “Initial Closing Date”), we entered into asset purchase agreements with Patriot Coal Corporation (“Patriot”) regarding certain assets relating to two of Patriot’s western Kentucky mining operations, including certain coal sales agreements, unassigned coal reserves and underground mining equipment and infrastructure. Both of the mining operations – the former Dodge Hill and Highland mining operations – were closed by Patriot in late 2014 prior to entering into these asset purchase agreements. Also on December 31, 2014, Patriot affiliates entered into agreements to sell other assets from Highland to a third party. Additional details of the transactions are discussed below.

On the Initial Closing Date, our subsidiary, Alliance Coal acquired the rights to certain coal supply agreements from an affiliate of Patriot for approximately $21.0 million. Of the $21.0 million purchase price, $9.3 million was paid into escrow subject to obtaining certain assignment consents. In February 2015, $7.5 million of the escrowed amount was released to Patriot for a consent received and $1.8 million was returned to Alliance Coal as a result of a consent not received, reducing our purchase price to $19.2 million. The acquired agreements provide for delivery of a total of approximately 5.1 million tons of coal from 2015 through 2017.

On February 3, 2015 (the “Acquisition Date”), Alliance Coal and Alliance Resource Properties acquired from Patriot an estimated 84.1 million tons of proven and probable high-sulfur coal reserves in western Kentucky (substantially all of which was leased by Patriot), and substantially all of Dodge Hill’s assets related to its former coal mining operation in western Kentucky, which principally included underground mining equipment and an estimated 43.2 million tons of non-reserve coal deposits (substantially all of which was leased by Dodge Hill). In addition, we assumed Dodge Hill’s reclamation liabilities totaling $2.3 million. Also on the Acquisition Date, the Intermediate Partnership’s newly formed subsidiaries, UC Mining, LLC and UC Processing, LLC, acquired certain underground mining equipment and spare parts inventory from Patriot’s former Highland mining operation.

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The mining and reserve assets acquired from Patriot described above are located in Union and Henderson Counties, Kentucky. The mining equipment, spare parts and underground infrastructure that we acquired from Patriot has been and is continuing to be dispersed to our existing operations in the Illinois Basin region in accordance with their highest and best use. Our purchase price of $19.2 million and $20.5 million paid on the Initial Closing Date and the Acquisition Date, respectively, described above was financed using existing cash on hand. In addition, our purchase price was increased by $8.3 million, comprising $2.1 million cash paid prior to the Acquisition Date related to the transaction and an agreement to pay approximately $6.2 million additional consideration as discussed below. As we have no intentions of operating the former Dodge Hill mining complex as a business and only acquired certain assets of Highland, we believe unaudited pro forma information of revenue and earnings is not meaningful as it relates to the acquisition of Patriot assets described above and furthermore not materially different than revenue and earnings as presented in our condensed consolidated statements of income. The primary ongoing benefit derived from the transaction relates to the coal supply agreements acquired, which would have permitted the sale of 0.8 million tons and 2.4 million tons at average pricing of $46.67 per ton sold during the three and nine months ended September 30, 2014, respectively, based on the contract price and sales volumes, if we had owned the contracts during that period. Revenues generated by these contracts since the Initial Closing Date were $29.4 million and $108.7 million, respectively, for the three and nine months ended September 30, 2015.

In conjunction with our acquisitions on the Acquisition Date, WKY CoalPlay, LLC (“WKY CoalPlay”), a related party, acquired approximately 39.1 million tons of proven and probable high-sulfur owned coal reserves located in Henderson and Union Counties, Kentucky from Central States Coal Reserves of Kentucky, LLC (“Central States”), a subsidiary of Patriot, for $25.0 million and in turn leased those reserves to us. In February 2015, we paid $2.1 million to WKY CoalPlay for the initial annual minimum royalty payment (Note 8).

The fair value of the acquired tangible and intangible assets and assumed liabilities are based on discounted cash flow projections and estimated replacement cost valuation techniques. We used an estimate of replacement cost based on comparable market prices to value the acquired equipment and utilized discounted cash flows to value intangible assets and reserves. Key assumptions used in the valuations included projections of future cash flows, and estimated weighted-average cost of capital, and internal rates of return. Due to the unobservable nature of these inputs, these estimates are considered Level 3 fair value measurements.

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The following table summarizes the consideration transferred from us to Patriot and the preliminary and final fair value allocation of assets acquired and liabilities assumed as valued at the Acquisition Date, incorporating fair value adjustments made subsequent to the Acquisition Date:

	Preliminary as of March 31, 2015	Adjustments		Final as of September 30, 2015
	(in thousands)

Consideration transferred	$ 47,514			$ 47,874

Recognized amounts of net tangible and intangible assets acquired and liabilities assumed:

Inventories	3,255	(1,261	)	1,994
Property, plant and equipment, including mineral rights and leased equipment	26,995	5,034		32,029
Customer contracts, net	19,193		-	19,193
Other assets	326	(326	)	-
Asset retirement obligation	(2,255)		-	(2,255)
Other liabilities	-	(3,087	)	(3,087)

Net tangible and intangible assets acquired	$ 47,514			$ 47,874

Included in the above consideration transferred is an agreement to pay an additional $6.2 million related to the acquisition, of which $5.6 million was paid as of September 30, 2015. Additionally, a fair value adjustment of $3.1 million to increase liabilities and property, plant and equipment was recorded to reflect the impact of operating leases assumed in the acquisition. Other adjustments to the preliminary fair values resulted from additional information obtained about facts in existence on February 3, 2015.

Intangible assets related to coal supply agreements, represented as “Customer contracts, net” in the table above are reflected in the Prepaid expenses and other assets and Other long-term assets line items in our condensed consolidated balance sheets. For the three and nine months ended September 30, 2015, amortization expense for the acquired coal supply agreements of $4.0 million and $10.1 million, respectively, has been recognized based on the weighted-average term of the contracts on a per unit basis.

MAC

In March 2006, White County Coal, and Alexander J. House entered into a limited liability company agreement to form Mid-America Carbonates, LLC (“MAC”). MAC was formed to engage in the development and operation of a rock dust mill and to manufacture and sell rock dust. White County Coal initially invested $1.0 million in exchange for a 50% equity interest in MAC. Our equity investment in MAC was $1.6 million at December 31, 2014. Effective on January 1, 2015, we purchased the remaining 50% equity interest in MAC from Mr. House for $5.5 million cash paid at closing. In conjunction with the acquisition, we recorded $4.2 million of goodwill which is reflected in Other and Corporate in our segment presentation (Note 14) and is included in Goodwill on our condensed consolidated balance sheets.

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5. LONG-LIVED ASSET IMPAIRMENT

In September 2015, we surrendered a lease agreement for certain undeveloped coal reserves and related property in western Kentucky. We determined that coal reserves held under this lease agreement were no longer a core part of our foreseeable development plans. As such, we surrendered the lease in order to avoid the high holding costs of those reserves. We recorded an impairment charge of $10.7 million to our Illinois Basin segment during the quarter ended September 30, 2015 to remove certain assets associated with the lease, including mineral rights, advanced royalties and mining permits.

6. FAIR VALUE MEASUREMENTS

We measure fair value in accordance with GAAP which defines fair value, requires 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 used in our fair value measurements 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 following table summarizes our recurring fair value measurements within the hierarchy:

	September 30, 2015						December 31, 2014
	Level 1		Level 2		Level 3		Level 1		Level 2		Level 3
	(in thousands)
Long-term debt	$	-	$	963,801	$	-	$	-	$	833,351	$	-
Contingent consideration	-		-		14,300		-		-		-
Total	$	-	$	963,801	$	14,300	$	-	$	833,351	$	-

The carrying amounts for cash equivalents, accounts receivable, accounts payable, due from affiliates and due to affiliates approximate fair value because of the short maturity of those instruments.

At September 30, 2015 and December 31, 2014, the estimated fair value of our long-term debt, including current maturities, was approximately $963.8 million and $833.4 million, respectively, based on interest rates that we believe are currently available to us in active markets for issuance of debt with similar terms and remaining maturities (Note 7). The fair value of debt, which is based upon these interest rates, is classified as a Level 2 measurement under the fair value hierarchy.

At September 30, 2015, the fair value of our contingent consideration arrangement related to the Hamilton Acquisition was $14.3 million (Note 4).

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7. LONG-TERM DEBT

Long-term debt consists of the following:

	September 30, 2015			December 31, 2014
	(in thousands)

Revolving Credit facility	$	403,000		$	140,000
Series A senior notes	-			205,000
Series B senior notes	145,000			145,000
Term loan	212,500			231,250
Securitization facility	100,000			100,000
Hamilton revolving credit facility	10,000			-
Hamilton equipment financing agreement	82,548			-
	953,048			821,250
Less current maturities	(142,159		)	(230,000		)
Total long-term debt	$	810,889		$	591,250

Our Intermediate Partnership has a $700.0 million revolving credit facility (“Revolving Credit Facility”), $145.0 million in Series B senior notes (“Series B Senior Notes”) and a $212.5 million term loan (“Term Loan” and collectively, with the Revolving Credit Facility and the Series B Senior Notes, the “ARLP Debt Arrangements”), which are guaranteed by all of the material direct and indirect subsidiaries of our Intermediate Partnership. On October 16, 2015 the Revolving Credit Facility was amended to increase the baskets for capital lease obligations and sale-leaseback arrangements from $10.0 million to $100.0 million. Our Intermediate Partnership also has a $100.0 million accounts receivable securitization facility (“Securitization Facility”). In addition, as a result of the Hamilton Acquisition (Note 4), we assumed a $10.0 million revolving credit facility (“Hamilton Revolving Credit Facility”) and an equipment financing note (“Hamilton Equipment Financing Note”). At September 30, 2015, current maturities include the Hamilton Revolving Credit Facility and a portion of the Term Loan. On June 26, 2015 the outstanding balance of the Series A senior notes totaling $205.0 million was paid.

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, incurrence of additional indebtedness and liens, sale of assets, investments, mergers and consolidations and 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 (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 3.0 to 1.0, in each case, during the four most recently ended fiscal quarters. The debt to cash flow ratio and cash flow to interest expense ratio were 1.23 to 1.0 and 24.3 to 1.0, respectively, for the trailing twelve months ended September 30, 2015. We were in compliance with the covenants of the ARLP Debt Arrangements as of September 30, 2015.

At September 30, 2015, we had borrowings of $403.0 million and $5.4 million of letters of credit outstanding with $291.6 million available for borrowing under the Revolving Credit Facility. We utilize the Revolving Credit Facility, as appropriate, for working capital requirements, capital expenditures and investments in affiliates, scheduled debt payments and distribution payments. We incur an annual commitment fee of 0.25% on the undrawn portion of the Revolving Credit Facility.

On December 5, 2014, certain direct and indirect wholly-owned subsidiaries of our Intermediate Partnership entered into the Securitization Facility providing additional liquidity and funding. Under the Securitization Facility, certain subsidiaries sell trade receivables on an ongoing basis to our Intermediate

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Partnership, which then sells the trade receivables to AROP Funding, LLC (“AROP Funding”), a wholly-owned bankruptcy-remote special purpose subsidiary of our Intermediate Partnership, which in turn borrows on a revolving basis up to $100.0 million secured by the trade receivables. After the sale, Alliance Coal, as servicer of the assets, collects the receivables on behalf of AROP Funding. The Securitization Facility bears interest based on a Eurodollar Rate. The Securitization Facility has an initial term of 364 days; however, we have the contractual ability and the intent to extend the term for an additional 364 days. At September 30, 2015, we had $100.0 million outstanding under the Securitization Facility.

As a result of the Hamilton Acquisition, we assumed the Hamilton Revolving Credit Facility and the Hamilton Equipment Financing Agreement. In November 2014, White Oak entered into the Hamilton Revolving Credit Facility allowing for periodic borrowings up to $10.0 million, collateralized by White Oak’s accounts receivable. Borrowings under the Hamilton Revolving Credit Facility carried interest at the prime rate plus 0.1%, which was 3.35% at September 30, 2015. On October 19, 2015, the outstanding balance of the Hamilton Revolving Credit Facility totaling $10.0 million was repaid.

In 2012, White Oak acquired vendor financing totaling $100.0 million through the Hamilton Equipment Financing Agreement, which was secured by continuous mining, long-wall mining, and underground belt system equipment purchased from the lender. The Hamilton Equipment Financing Agreement required repayment of principal and interest in equal monthly installments of $2.1 million from July 2014 until June 2019. As of September 30, 2015, $82.5 million remained outstanding on the note and carried an annual interest rate of 8%. On October 16, 2015, the outstanding balance of the Hamilton Equipment Financing Agreement totaling $80.6 million was repaid without penalty with funds drawn on the Revolving Credit Facility.

On October 29, 2015, we entered into a sale-leaseback transaction whereby we sold certain mining equipment for $100.0 million and concurrently entered into a lease agreement for the sold equipment with a four-year term. Under the lease agreement, we will pay an initial monthly rent of $1.9 million. A balloon payment equal to 20% of the equipment cost is due at the end of the lease term. We have recognized this transaction as a capital lease.

On October 6, 2015, Cavalier Minerals JV, LLC (“Cavalier Minerals”) (Note 8) entered into a credit agreement (the “Cavalier Credit Agreement”) with Mineral Lending, LLC (“Mineral Lending”) for a $100.0 million line of credit (the “Cavalier Credit Facility”). Mineral Lending is an entity owned by Alliance Resource Holdings II, Inc. (“ARH II,” the parent of ARH), an entity owned by an officer of ARH who is also a director of ARH II (“ARH Officer”) and foundations established by our President and Chief Executive Officer and Kathleen S. Craft. There is no commitment fee under the facility. Borrowings under the Cavalier Credit Facility bear interest at a one month LIBOR rate plus 6% with interest payable quarterly. Repayment of the principal balance will begin following the first fiscal quarter after the earlier of the date on which the aggregate amount borrowed exceeds $90.0 million or December 31, 2017, in quarterly payments of an amount equal to the greater of $1.3 million initially, escalated to $2.5 million after two years, or fifty percent of Cavalier Minerals’ excess cash flow. The Cavalier Credit Facility matures September 30, 2024, at which time all amounts then outstanding are required to be repaid. Cavalier Minerals may prepay the Cavalier Credit Facility at any time in whole or in part subject to terms and conditions described in the Cavalier Credit Agreement.

8. VARIABLE INTEREST ENTITIES

Cavalier Minerals

On November 10, 2014, our wholly owned subsidiary, Alliance Minerals, LLC (“Alliance Minerals”), and Bluegrass Minerals Management, LLC (“Bluegrass Minerals”) entered into a limited liability company agreement (the “Cavalier Agreement”) to create Cavalier Minerals, which was formed to indirectly acquire oil and gas mineral interests through its noncontrolling ownership interest initially in

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AllDale Minerals L.P. and subsequently also in AllDale Minerals II, L.P. (collectively “AllDale Minerals”) (Note 9). Alliance Minerals and Bluegrass Minerals initially committed funding of $48.0 million and $2.0 million, respectively, to Cavalier Minerals, and Cavalier Minerals committed funding of $49.0 million to AllDale Minerals. Alliance Minerals’ contributions through December 31, 2014 to Cavalier Minerals totaled $11.5 million. During the three and nine months ended September 30, 2015, Alliance Minerals contributed $16.4 million and $35.6 million, respectively, bringing our total investment in Cavalier Minerals to $47.1 million at September 30, 2015. Our remaining commitment to Cavalier Minerals of $0.9 million was made October 26, 2015. Bluegrass Minerals, which is owned and controlled by the ARH Officer and is Cavalier Minerals’ managing member, contributed $2.0 million as of September 30, 2015.

On October 6, 2015, Alliance Minerals and Bluegrass Minerals committed to fund an additional $96.0 million and $4.0 million, respectively, to Cavalier Minerals, and Cavalier Minerals committed to fund an additional $100.0 million to AllDale Minerals. At Alliance Minerals’ election, Cavalier Minerals will meet its remaining funding commitment to AllDale Minerals through contributions from Alliance Minerals and Bluegrass Minerals or from borrowings under the Cavalier Credit Facility (Note 7). We expect to fund our remaining commitments utilizing existing cash balances, future cash flows from operations, borrowings under credit and securitization facilities and cash provided from the issuance of debt or equity, or by requiring Cavalier Minerals to draw on the Cavalier Credit Facility. Cavalier Minerals also reimburses Bluegrass Minerals for certain insignificant general and administrative costs incurred on behalf of Cavalier Minerals.

In accordance with the Cavalier Agreement, Bluegrass Minerals is entitled to receive an incentive distribution from Cavalier Minerals equal to 25% of all distributions (including in liquidation) after return of members’ capital reduced by certain distributions received by Bluegrass Minerals or its owner from AllDale Minerals Management, LLC, the managing member of AllDale Minerals. Alliance Minerals’ ownership interest in Cavalier Minerals at September 30, 2015 was 96%. The remainder of the equity ownership is held by Bluegrass Minerals. As of September 30, 2015, Cavalier Minerals had not made any distributions to its owners. We have consolidated Cavalier Minerals’ financial results as we concluded that Cavalier Minerals is a variable interest entity (“VIE”) and we are the primary beneficiary because our consent is required for significant activities of Cavalier Minerals and due to Bluegrass Minerals’ relationship to us as described above. Bluegrass Minerals equity ownership of Cavalier Minerals is accounted for as noncontrolling ownership interest in our condensed consolidated balance sheets. In addition, earnings attributable to Bluegrass Minerals are recognized as net loss attributable to noncontrolling interest in our condensed consolidated statements of income.

WKY CoalPlay

On November 17, 2014, SGP Land, LLC (“SGP Land”), a wholly-owned subsidiary of SGP, and two limited liability companies owned by irrevocable trusts established by our President and Chief Executive Officer (“Craft Companies”) entered into a limited liability company agreement to form WKY CoalPlay. WKY CoalPlay was formed, in part, to purchase and lease coal reserves. WKY CoalPlay is managed by an entity controlled by the ARH Officer who is an employee of SGP Land and trustee of the irrevocable trusts owning the Craft Companies.

In February 2015, WKY CoalPlay acquired approximately 39.1 million tons of proven and probable high-sulfur owned coal reserves located in Henderson and Union Counties, Kentucky from a wholly-owned subsidiary of Patriot for $25.0 million and in turn leased those reserves to us (“CoalPlay 2015 Lease”). The CoalPlay 2015 Lease has an initial term of 20 years and provides for earned royalty payments to WKY CoalPlay of 4% of the coal sales price and annual minimum royalty payments of $2.1 million. All annual minimum royalty payments are recoupable against earned royalty payments. An option was also granted to us to acquire the leased reserves at any time during a three-year period beginning in February 2018 for a purchase price that would provide WKY CoalPlay a 7% internal rate of return on its investment in these reserves taking into account payments previously made under the lease. We paid WKY CoalPlay $2.1 million in February 2015 for the initial annual minimum royalty payment.

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As of September 30, 2015, we had paid $10.8 million of advanced royalties to WKY CoalPlay, none of which have been recouped, and which is reflected in the long-term Advance royalties line item in our condensed consolidated balance sheets and includes previous annual minimum royalty payments made to WKY CoalPlay associated with leases entered into in 2014, in addition to the initial annual minimum royalty payment for the CoalPlay 2015 Lease.

We have concluded that WKY CoalPlay is a VIE because of our ability to exercise the option noted above as well as two other similar options granted to us by WKY CoalPlay in December 2014, which is not within the control of the equity holders and, if it occurs, could potentially limit the expected residual return to the owners of WKY CoalPlay. We do not have any economic or governance rights related to WKY CoalPlay and our options that provide us with a variable interest in WKY CoalPlay’s reserve assets do not give us any rights that constitute power to direct the primary activities that most significantly impact WKY CoalPlay’s economic performance. SGP Land has the sole ability to replace the manager of WKY CoalPlay at its discretion and therefore has power to direct the activities of WKY CoalPlay. Consequently, we concluded that SGP Land is the primary beneficiary of WKY CoalPlay.

9. EQUITY INVESTMENT

AllDale Minerals

On November 10, 2014, Cavalier Minerals (Note 8) made an initial contribution of $7.4 million in return for a limited partner interest in AllDale Minerals, which was created to purchase oil and gas mineral interests in various geographic locations within producing basins in the continental U.S. As of December 31, 2014, Cavalier Minerals’ had contributed $11.6 million to AllDale Minerals. During the three and nine months ended September 30, 2015, Cavalier Minerals contributed an additional $16.9 million and $37.4 million, respectively, bringing the total investment in AllDale Minerals to $49.0 million as of September 30, 2015. We continually review all rights provided to Cavalier Minerals and us by various agreements and continue to conclude all such rights do not provide Cavalier Minerals or us the ability to unilaterally direct any of the activities of AllDale Minerals that most significantly impact its economic performance. As such, we account for Cavalier Minerals’ ownership interest in the income or loss of AllDale Minerals as an equity investment in our condensed consolidated financial statements. We record equity income or loss based on AllDale Minerals’ distribution structure. Cavalier Minerals’ limited partner interest in AllDale Minerals was 71.7% at September 30, 2015. For the three and nine months ended September 30, 2015, we have been allocated losses of $0.1 million and $0.6 million, respectively, from AllDale Minerals.

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10. NET INCOME OF ARLP PER LIMITED PARTNER UNIT

We utilize the two-class method in calculating basic and diluted earnings per unit (“EPU”). Net income of ARLP 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 $0.1375 per unit, 25% of the amount we distribute in excess of $0.15625 per unit, and 50% of the amount we distribute in excess of $0.1875 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, outstanding awards under our Long-Term Incentive Plan (“LTIP”) and phantom units in notional accounts under our 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 of ARLP used for calculating basic earnings per unit and the weighted-average units used in computing EPU for the three and nine months ended September 30, 2015 and 2014:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2015		2014		2015		2014
	(in thousands, except per unit data)

Net income of ARLP	$	83,379	$	119,978	$	284,723	$	373,535
Adjustments:
Managing general partner’s priority distributions	(36,371)		(33,588)		(108,205)		(97,954)
General partners’ 2% equity ownership	(940)		(1,728)		(3,530)		(5,511)

Limited partners’ interest in net income of ARLP	46,068		84,662		172,988		270,070

Less:
Distributions to participating securities	(880)		(751)		(2,602)		(2,188)
Undistributed earnings attributable to participating securities	-		(585)		(367)		(2,027)

Net income of ARLP available to limited partners	$	45,188	$	83,326	$	170,019	$	265,855

Weighted-average limited partner units outstanding – basic and diluted	74,189		74,061		74,170		74,039

Basic and diluted net income of ARLP per limited partner unit (1)	$	0.61	$	1.13	$	2.29	$	3.59

(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 and nine months ended September 30, 2015 and 2014, the combined total of LTIP, SERP and Deferred Compensation Plan units of 627, 844, 735 and 776, respectively, were considered anti-dilutive under the treasury stock method.

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11. 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:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2015		2014		2015		2014
	(in thousands)

Beginning balance	$	55,671	$	61,515	$	57,557	$	62,909
Accruals increase	2,959		1,291		9,126		8,755
Payments	(2,250)		(2,667)		(6,864)		(8,194)
Interest accretion	489		646		1,466		1,939
Valuation gain (1)	-		-		(4,416)		(4,624)
Ending balance	$	56,869	$	60,785	$	56,869	$	60,785

(1) Our liability for the estimated present value of current workers’ compensation benefits is based on our actuarial estimates. Our actuarial calculations are based on a blend of actuarial projection methods and numerous assumptions including claim development patterns, mortality, medical costs and interest rates. We conducted a mid-year review of our actuarial assumptions in the second quarter of 2015 which resulted in a valuation gain primarily attributable to favorable changes in claims development and an increase in the discount rate used to calculate the estimated present value of future obligations from 3.41% at December 31, 2014 to 3.71% at June 30, 2015. Our mid-year review of our actuarial assumptions in the second quarter of 2014 also resulted in a valuation gain primarily attributable to favorable changes in claims development, offset partially by a decrease in the utilized discount rate from 4.11% at December 31, 2013 to 3.67% at June 30, 2014.

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:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2015		2014		2015		2014
	(in thousands)

Service cost	$	773	$	857	$	2,237	$	2,571
Interest cost	524		566		1,571		1,697
Amortization of net actuarial gain (1)	(113)		(263)		(338)		(789)
Net periodic benefit cost	$	1,184	$	1,160	$	3,470	$	3,479

(1) Amortization of net actuarial gain is included in the Operating expenses (excluding depreciation, depletion and amortization) line item within our condensed consolidated statements of income.

12. 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

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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 26, 2015, the Compensation Committee determined that the vesting requirements for the 2012 grants of 202,778 restricted units (which is net of 11,450 forfeitures) had been satisfied as of January 1, 2015. As a result of this vesting, on February 11, 2015, we issued 128,150 unrestricted common units to the LTIP participants. The remaining units were settled in cash to satisfy the tax withholding obligations for the LTIP participants. On January 26, 2015, the Compensation Committee authorized additional grants of up to 314,019 restricted units, of which 303,165 were granted during the nine months ended September 30, 2015 and will vest on January 1, 2018, subject to satisfaction of certain financial tests. The fair value of these 2015 grants is equal to the intrinsic value at the date of grant, which was $37.18 per unit. LTIP expense was $2.8 million and $2.5 million for the three months ended September 30, 2015 and 2014, respectively, and $8.3 million and $7.1 million for the nine months ended September 30, 2015 and 2014, respectively. After consideration of the January 1, 2015 vesting and subsequent issuance of 128,150 common units, approximately 3.7 million units remain available under the LTIP for issuance in the future, assuming all grants issued in 2013, 2014 and 2015 currently outstanding are settled with common units, without reduction for tax withholding, and no future forfeitures occur.

As of September 30, 2015, there was $15.0 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 1.3 years. As of September 30, 2015, the intrinsic value of the non-vested LTIP grants was $20.9 million. As of September 30, 2015, the total obligation associated with the LTIP was $18.4 million and is included in the partners’ capital Limited partners-common unitholders 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. The SERP is administered by the Compensation Committee.

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 Deferred Compensation 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.

For the nine months ended September 30, 2015 and 2014, SERP and Deferred Compensation Plan participant notional account balances were credited with a total of 24,741 and 15,860 phantom units, respectively, and the fair value of these phantom units was $30.23 per unit and $44.47 per unit, respectively, on a weighted-average basis. Total SERP and Deferred Compensation Plan expense was $0.4 million and $0.3 million for the three months ended September 30, 2015 and 2014, respectively, and $1.0 million and $0.9 million for the nine months ended September 30, 2015 and 2014, respectively.

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As of September 30, 2015, there were 393,722 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 $8.8 million. As of September 30, 2015, the total obligation associated with the SERP and Deferred Compensation Plan was $13.3 million and is included in the partners’ capital Limited partners-common unitholders line item in our condensed consolidated balance sheets.

13. 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:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2015		2014		2015		2014
	(in thousands)

Service cost	$	618	$	543	$	1,855	$	1,630
Interest cost	1,074		1,019		3,222		3,056
Expected return on plan assets	(1,398)		(1,368)		(4,193)		(4,106)
Amortization of net loss (1)	839		193		2,516		580
Net periodic benefit cost	$	1,133	$	387	$	3,400	$	1,160

(1) Amortization of net actuarial loss is included in the Operating expenses (excluding depreciation, depletion and amortization) line item within our condensed consolidated statements of income.

During the nine months ended September 30, 2015, we made contribution payments of $1.0 million to the Pension Plan for the 2014 plan year and $1.4 million for the 2015 plan year. On October 14, 2015, we made a contribution payment of $0.7 million for the 2015 plan year.

14. 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 two reportable segments: Illinois Basin and Appalachia and an “all other” category referred to as Other and Corporate. Our reportable segments correspond to major coal producing regions in the eastern U.S. Similar economic characteristics for our operating segments within each of these two reportable segments generally include coal quality, geology, coal marketing opportunities, mining and transportation methods and regulatory issues.

As a result of acquiring the remaining equity interests in Hamilton, formerly known as White Oak (Note 4), we restructured our reportable segments to include Hamilton as part of our Illinois Basin segment due to the similarities in product, management, location, and operation with other mines included in the segment. This new organization reflects how our chief operating decision maker manages and allocates resources to our various operations. Prior periods have been recast to include Hamilton in our Illinois Basin segment.

The Illinois Basin reportable segment is comprised of multiple operating segments, including Webster County Coal, LLC’s Dotiki mining complex, Gibson County Coal, LLC’s mining complex (“Gibson”), which includes the Gibson North mine and Gibson South mine, Hopkins County Coal, LLC’s Elk Creek mine and the Fies property, White County Coal, LLC’s Pattiki mining complex, Warrior Coal, LLC’s mining complex, Sebree Mining, LLC’s mining complex (“Sebree”), which includes the Onton mine, River View Coal, LLC’s mining complex and the Hamilton mining complex. In April 2014, production began at the Gibson South mine. The Elk Creek mine is currently expected to cease production in early 2016. On November 6, 2015, Gibson and Sebree issued Worker Adjustment and Retraining Notification (“WARN”) Act notices. See Note 15.

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The Appalachia reportable segment is comprised of multiple operating segments, including the Mettiki mining complex, the Tunnel Ridge, LLC mining complex, the MC Mining, LLC mining complex and the Penn Ridge Coal, LLC (“Penn Ridge”) property. The Mettiki mining complex includes Mettiki Coal (WV), LLC’s Mountain View mine and Mettiki Coal, LLC’s preparation plant. The Penn Ridge property is held by us for future mine development.

Other and Corporate includes marketing and administrative expenses, Alliance Service, Inc. (“ASI”) and its subsidiary, Matrix Design Group, LLC and its subsidiaries Matrix Design International, LLC and Matrix Design Africa (PTY) LTD (“Matrix Design”), Alliance Design Group, LLC (“Alliance Design”) (collectively, Matrix Design and Alliance Design are referred to as the “Matrix Group”), ASI’s ownership of aircraft, the Mt. Vernon Transfer Terminal, LLC (“Mt. Vernon”) dock activities, coal brokerage activity, MAC (Note 4), certain activities of Alliance Resource Properties, the Pontiki Coal, LLC mining complex, which sold most of its assets in May 2014, Wildcat Insurance, LLC (“Wildcat Insurance”), Alliance Minerals, and its affiliate, Cavalier Minerals (Note 8), which holds an equity investment in AllDale Minerals (Note 9), and AROP Funding (Note 7).

Reportable segment results as of and for the three and nine months ended September 30, 2015 and 2014 are presented below.

	Illinois Basin	Appalachia	Other and Corporate	Elimination (1)	Consolidated
	(in thousands)

*Three months ended September 30, 2015*

Total revenues (2)	$ 420,517	$ 136,741	$ 40,264	$ (31,077)	$ 566,445
Segment Adjusted EBITDA Expense (3)	249,615	80,421	33,701	(27,663)	336,074
Segment Adjusted EBITDA (4)(5)	147,522	53,380	6,266	(3,413)	203,755
Capital expenditures (7)	37,350	11,616	2,458	-	51,424

*Three months ended September 30, 2014 (recast)*

Total revenues (2)	$ 395,984	$ 167,391	$ 7,730	$ (1,777)	$ 569,328
Segment Adjusted EBITDA Expense (3)	247,625	95,956	6,820	(1,777)	348,624
Segment Adjusted EBITDA (4)(5)	145,255	68,501	1,015	-	214,771
Capital expenditures (7)	62,830	13,371	2,880	-	79,081

*Nine months ended September 30, 2015*

Total revenues (2)	$1,237,819	$ 460,154	$ 147,079	$ (113,471)	$ 1,731,581
Segment Adjusted EBITDA Expense (3)	728,048	296,980	124,321	(103,819)	1,045,530
Segment Adjusted EBITDA (4)(5)	445,819	154,760	21,752	(9,652)	612,679
Total assets (6)	1,799,170	565,213	278,068	(137,058)	2,505,393
Capital expenditures (7)	105,536	49,055	4,591	-	159,182

*Nine months ended September 30, 2014 (recast)*

Total revenues (2)	$1,224,877	$ 468,671	$ 23,660	$ (7,280)	$ 1,709,928
Segment Adjusted EBITDA Expense (3)	736,174	275,446	18,794	(7,280)	1,023,134
Segment Adjusted EBITDA (4)(5)	465,851	184,460	5,121	-	655,432
Total assets (6)	1,526,744	591,516	56,742	(1,400)	2,173,602
Capital expenditures (7)	182,884	42,040	10,136	-	235,060

(1) The elimination column represents the elimination of intercompany transactions and is primarily comprised of sales from the Matrix Group and MAC to our mining operations, coal sales and purchases between operations within different segments, sales of receivables to AROP Funding and insurance premiums paid to Wildcat Insurance.

(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, MAC revenues, Wildcat Insurance revenues and brokerage coal sales.

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(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):

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2015		2014		2015		2014
	(in thousands)

Segment Adjusted EBITDA Expense	$	336,074	$	348,624	$	1,045,530	$	1,023,134
Outside coal purchases	(2)		(3)		(326)		(7		)
Other income	455		549		750		1,178
Operating expenses (excluding depreciation, depletion and amortization)	$	336,527	$	349,170	$	1,045,954	$	1,024,305

(4) Segment Adjusted EBITDA is defined as net income (prior to the allocation of noncontrolling interest) before net interest expense, income taxes, depreciation, depletion and amortization, general and administrative expenses and asset impairment charge. 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:

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2015		2014		2015		2014
	(in thousands)

Consolidated Segment Adjusted EBITDA	$	203,755	$	214,771	$	612,679	$	655,432
General and administrative	(17,948)		(16,995)		(52,336)		(54,201)
Depreciation, depletion and amortization	(84,661)		(69,646)		(242,730)		(203,539)
Asset impairment charge	(10,695)		-		(10,695)		-
Interest expense, net	(7,067)		(8,152)		(22,205)		(24,157)
Income tax expense	(12)		-		(17)		-
Net income	$	83,372	$	119,978	$	284,696	$	373,535

(5) Includes equity in loss of affiliates for the three and nine months ended September 30, 2015 of $(17.1) million and $(48.5) million, respectively, included in the Illinois Basin segment and $(0.1) million and $(0.6) million, respectively, included in Other and Corporate. Includes equity in income (loss) of affiliates for the three and nine months ended September 30, 2014 of $39,000 and $(13.8) million, respectively, included in the Illinois Basin segment and $0.2 million and $0.3 million, respectively, included in Other and Corporate.

(6) Total assets for Other and Corporate include investments in affiliate of $48.0 million at September 30, 2015. Total assets for the Illinois Basin segment and Other and Corporate include investments in affiliates of $200.1 million and $1.5 million, respectively, at September 30, 2014.

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(7) Capital expenditures shown above exclude the Hamilton Acquisition on July 31, 2015, the Patriot acquisition on February 3, 2015 and the MAC acquisition on January 1, 2015 (Note 4).

15. SUBSEQUENT EVENTS

On October 27, 2015, we declared a quarterly distribution for the quarter ended September 30, 2015, of $0.675 per unit, on all common units outstanding, totaling approximately $87.5 million, including our managing general partner’s incentive distributions, payable on November 13, 2015 to all unitholders of record as of November 6, 2015.

On November 6, 2015 Gibson issued WARN Act notices to approximately 120 of its employees in anticipation of eliminating one and a half production units at its Gibson North and Gibson South mines. By December 31, 2015, we currently expect Gibson to be operating four production units at the Gibson South mine with the Gibson North mine idled. Resumption of production at the Gibson North mine will be market dependent.

On November 6, 2015 Sebree issued WARN Act notices to all of its employees at the Onton mine, and stopped coal production at the mine. As a result of employment opportunities at our other operations, we currently expect this reduction in force to affect approximately 140 employees.

We are currently evaluating the impact to our financial statements as a result of these production reductions.

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

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

·	References to “we,” “us,” “our” or “ARLP Partnership” mean the business and operations of Alliance Resource Partners, L.P., the parent company, as well as its consolidated subsidiaries.
·	References to “ARLP” mean Alliance Resource Partners, L.P., individually as the parent company, and not on a consolidated basis.
·	References to “MGP” mean Alliance Resource Management GP, LLC, the managing general partner of Alliance Resource Partners, L.P.
·	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.
·	References to “Alliance Coal” mean Alliance Coal, LLC, the holding company for the substantial majority of the operations of Alliance Resource Operating Partners, L.P., also referred to as our primary 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. As is customary in the coal industry, we have entered into long-term coal supply agreements with many of our customers. We operate eleven underground mining complexes in Illinois, Indiana, Kentucky, Maryland and West Virginia, and operate a coal loading terminal on the Ohio River at Mt. Vernon, Indiana. Our mining complexes include the Hamilton County Coal, LLC longwall mining complex (“Hamilton”), formerly referred to as the White Oak Mine No. 1, in southern Illinois which was acquired on July 31, 2015 (the “Acquisition”) by purchasing the remaining equity ownership in White Oak Resources LLC (“White Oak”). Please read “Item 1. Financial Statements (Unaudited) – Note 4. Acquisitions” of this Quarterly Report on Form 10-Q. Prior to July 31, 2015, we owned a non-controlling, preferred equity interest in White Oak, leased coal reserves to White Oak and owned and operated certain surface facilities at White Oak’s mining complex, which commenced initial longwall operation in late October 2014.

We have two reportable segments: Illinois Basin and Appalachia and an “all other” category referred to as Other and Corporate. Our reportable segments correspond to major coal producing regions in the eastern U.S. Factors similarly affecting financial performance of our operating segments within each of these two reportable segments generally include coal quality, geology, coal marketing opportunities, mining and transportation methods and regulatory issues.

As a result of acquiring the remaining equity interests in White Oak, we restructured our reportable segments to include Hamilton as part of our Illinois Basin segment due to the similarities in product, management, location, and operation with other mines included in the segment. This new organization reflects how our chief operating decision maker manages and allocates resources to our various operations. Prior periods have been recast to include White Oak in our Illinois Basin segment.

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

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Complex;” Hopkins County Coal, LLC mining complex (“Hopkins”), which includes the Elk Creek mine and the Fies property; White County Coal, LLC’s Pattiki mining complex; Warrior Coal, LLC’s mining complex (“Warrior”); Sebree Mining, LLC’s mining complex (“Sebree”), which includes the Onton mine and Steamport, LLC; River View Coal, LLC’s mining complex (“River View”); Hamilton; CR Services, LLC; and certain properties of Alliance Resource Properties, LLC (“Alliance Resource Properties”), ARP Sebree, LLC and ARP Sebree South, LLC. In April 2014, initial production began at the Gibson South mine. The Elk Creek mine is currently expected to cease production in early 2016. The Fies property is held for future mine development. On November 6, 2015, Gibson and Sebree issued Worker Adjustment and Retraining Notification Act notices. See “Item 1. Financial Statements (Unaudited) – Note 15. Subsequent Events” of this Quarterly Report on Form 10-Q.

· Appalachia reportable segment is comprised of multiple operating segments, including the Mettiki mining complex (“Mettiki”), the Tunnel Ridge, LLC mining complex (“Tunnel Ridge”), the MC Mining, LLC mining complex (“MC Mining”) and the Penn Ridge Coal, LLC (“Penn Ridge”) property. The Mettiki mining complex includes Mettiki Coal (WV), LLC’s Mountain View mine and Mettiki Coal, LLC’s preparation plant. The Penn Ridge property is held for future mine development.

· Other and Corporate includes marketing and administrative expenses; Alliance Service, Inc. (“ASI”) and its subsidiary, Matrix Design Group, LLC (“Matrix Design”) and its subsidiaries Matrix Design International, LLC and Matrix Design Africa (PTY) LTD; Alliance Design Group, LLC; ASI’s ownership of aircraft; the Mt. Vernon Transfer Terminal, LLC (“Mt. Vernon”) dock activities; coal brokerage activity; Mid-America Carbonates, LLC (“MAC”); certain activities of Alliance Resource Properties; the Pontiki Coal, LLC mining complex, which sold most of its assets in May 2014; Wildcat Insurance, LLC (“Wildcat Insurance”), which was established in September 2014 to assist the ARLP Partnership with its insurance requirements; Alliance Minerals, LLC and its affiliate, Cavalier Minerals JV, LLC, which holds an equity investment in AllDale Minerals, L.P. (“AllDale Minerals”) and AROP Funding, LLC (“AROP Funding”). Please read “Item 1. Financial Statements (Unaudited) – Note 7. Long-term Debt” and “– Note 8. Variable Interest Entities” of this Quarterly Report on Form 10-Q.

Three Months Ended September 30, 2015 Compared to Three Months Ended September 30, 2014

We reported net income of $83.4 million for the three months ended September 30, 2015 (“2015 Quarter”) compared to $120.0 million for the three months ended September 30, 2014 (“2014 Quarter”). The decrease of $36.6 million was principally due to lower average coal sales prices, lower other sales and operating revenues, increased depreciation, depletion and amortization expense, a non-cash asset impairment and higher equity in loss of affiliates from White Oak prior to the Acquisition offset by lower operating expenses due to an inventory build at various operations in the 2015 Quarter and a favorable production mix as compared to the 2014 Quarter. Sales and production volumes increased to 10.3 million tons sold and a record 11.5 million tons produced in the 2015 Quarter compared to 9.8 million tons sold and 10.2 million tons produced in the 2014 Quarter.

	Three Months Ended September 30,
	2015	2014	2015	2014
	(in thousands)		(per ton sold)
Tons sold	10,294	9,825	N/A	N/A
Tons produced	11,450	10,219	N/A	N/A
Coal sales	$547,466	$548,357	$53.18	$55.81
Operating expenses and outside coal purchases	$336,529	$349,173	$32.69	$35.54

Coal sales. Coal sales for the 2015 Quarter decreased 0.2% to $547.5 million from $548.4 million for the 2014 Quarter. The decrease of $0.9 million in coal sales is due to a $27.0 million decrease

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as a result of lower average coal sales prices offset by $26.1 million additional coal sales as a result of increased tons sold. Average coal sales prices decreased by $2.63 per ton sold to $53.18 in the 2015 Quarter compared to $55.81 per ton sold in the 2014 Quarter, primarily as a result of current market conditions and lower-priced legacy contracts inherited at the Hamilton mine. Higher coal sales volumes are attributable to increased production at our Gibson South mine and additional volumes from the assumption of operations at the Hamilton mine, offset in part by reduced unit shifts at our Pattiki, Warrior, Onton and Gibson North mines in response to current market conditions.

Operating expenses and outside coal purchases. Operating expenses and outside coal purchases combined decreased to $336.5 million for the 2015 Quarter from $349.2 million for the 2014 Quarter, primarily due to an inventory build at various operations in the 2015 Quarter and a favorable production mix resulting from increased production and improved recoveries at our Gibson South mine, the addition of lower-cost longwall production from our Hamilton mine and increased recoveries and fewer longwall move days at our Tunnel Ridge mine, partially offset by higher workers’ compensation expenses. On a per ton basis, operating expenses and outside coal purchases decreased 8.0% to $32.69 per ton sold also due to the increased mix of lower-cost production discussed above and reduced unit shifts at certain higher-cost per ton Illinois Basin operations. Operating expenses were impacted by various other factors, the most significant of which are discussed below:

· Labor and benefit expenses per ton produced, excluding workers’ compensation, decreased 9.8% to $10.55 per ton in the 2015 Quarter from $11.70 per ton in the 2014 Quarter. This decrease of $1.15 per ton was primarily attributable to lower labor and benefit costs per ton resulting from the increased mix of lower-cost production discussed above, reduced overtime in response to market conditions and lower medical expenses at various mines in both reportable segments;

· Material and supplies expenses per ton produced decreased 10.0% to $10.76 per ton in the 2015 Period from $11.96 per ton in the 2014 Period. The decrease of $1.20 per ton produced resulted primarily from the increased mix of lower-cost production discussed above and related decreases of $0.51 per ton for material and supplies for roof support, $0.20 per ton for contract labor used in the mining process, $0.18 per ton for certain ventilation related materials and supplies expenses and $0.17 per ton for various preparation plant expenses;

· Maintenance expenses per ton produced decreased 7.5% to $3.70 per ton in the 2015 Quarter from $4.00 per ton in the 2014 Quarter. The decrease of $0.30 per ton produced was primarily due to production variances at certain mines discussed above; and

· Production taxes and royalties expenses incurred as a percentage of coal sales prices and volumes decreased $0.48 per produced ton sold in the 2015 Quarter compared to the 2014 Quarter primarily as a result of lower average coal sales prices as discussed above and increased brokerage coal sales which have minimal production taxes and royalty expenses if any.

Operating expenses and outside coal purchases per ton decreases discussed above were offset partially by the following increase:

· Workers’ compensation expenses per ton produced increased to $0.52 per ton in the 2015 Quarter from $0.36 per ton in the 2014 Quarter. The increase of $0.16 per ton produced resulted from increased accruals at various operations.

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primarily due to the absence of certain payments in lieu of shipments received from a customer in the 2014 Quarter related to an Appalachian coal sales contract. Lower other sales and operating revenues in the 2015 Quarter also reflect the termination upon closing of the Acquisition of the previously existing coal leases and surface facilities services agreement with White Oak.

Depreciation, depletion and amortization. Depreciation, depletion and amortization increased $15.0 million to $84.7 million in the 2015 Quarter compared to the 2014 Quarter, due to the reduction of the economic mine life at our Elk Creek mine, which is expected to close by the end of the first quarter of 2016, increased production at the Gibson South mine, which commenced initial production in April 2014, amortization of coal supply agreements acquired in December 2014 and the addition of the Hamilton mine in the 2015 Quarter.

Asset impairment charge. In the 2015 Quarter, we recognized an asset impairment charge of $10.7 million to write down assets associated with the recent surrender of a lease agreement for certain undeveloped coal reserves and related property in western Kentucky. We determined that coal reserves held under this lease were not a core part of our foreseeable development plans and, after unsuccessful negotiations with the lessor, surrendered the lease in September 2015 in order to avoid the high holding costs of those reserves.

Interest expense. Interest expense, net of capitalized interest, decreased to $7.4 million in the 2015 Quarter from $8.6 million in the 2014 Quarter primarily due to the repayment of our Series A senior notes in June 2015 offset in part by interest incurred on debt assumed in the Acquisition.

Equity in income (loss) of affiliates, net. Equity in loss of affiliates, net for the 2015 Quarter includes our equity investments in White Oak prior to the Acquisition and AllDale Minerals. The 2014 Quarter includes White Oak and MAC. Regarding MAC’s exclusion from the 2015 Quarter, please read “Item 1. Financial Statements (Unaudited) – Note 4. Acquisitions” of this Quarterly Report on Form 10-Q. For the 2015 Quarter, we recognized equity in loss of affiliates of $17.2 million compared to equity in income of affiliates of $0.1 million for the 2014 Quarter. The change in net equity in earnings of affiliates is primarily related to our previous equity investment in White Oak and the impact of changes in allocations of equity income or losses resulting from equity contributions during the 2014 Quarter from another White Oak partner as well as the impact of White Oak’s first longwall move in July 2015 that increased expenses prior to the Acquisition.

Transportation revenues and expenses. Transportation revenues and expenses were $9.4 million and $6.0 million for the 2015 and 2014 Quarters, respectively. The increase of $3.4 million was primarily attributable to increased tonnage for which we arrange transportation at certain mines. The cost of transportation services are passed through to our customers. Consequently, we do not realize any gain or loss on transportation revenues.

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Segment Adjusted EBITDA. Our 2015 Quarter Segment Adjusted EBITDA decreased $11.0 million, or 5.1%, to $203.8 million from the 2014 Quarter Segment Adjusted EBITDA of $214.8 million. Segment Adjusted EBITDA, tons sold, coal sales, other sales and operating revenues and Segment Adjusted EBITDA Expense by segment are:

	Three Months Ended September 30,
	2015		2014 (recast)		Increase/(Decrease)
			(in thousands)
Segment Adjusted EBITDA
Illinois Basin	$	147,522	$	145,255	$	2,267	1.6	%
Appalachia	53,380		68,501		(15,121)		(22.1	)%
Other and Corporate	6,266		1,015		5,251		(1	)
Elimination	(3,413)		-		(3,413)		-
Total Segment Adjusted EBITDA (2)	$	203,755	$	214,771	$	(11,016)	(5.1	)%

Tons sold
Illinois Basin	8,134		7,361		773		10.5	%
Appalachia	2,160		2,464		(304)		(12.3	)%
Other and Corporate	600		-		600		-
Elimination	(600)		-		(600)		-
Total tons sold	10,294		9,825		469		4.8	%

Coal sales
Illinois Basin	$	410,796	$	388,802	$	21,994	5.7	%
Appalachia	133,082		159,555		(26,473)		(16.6	)%
Other and Corporate	29,398		-		29,398		-
Elimination	(25,810)		-		(25,810)		-
Total coal sales	$	547,466	$	548,357	$	(891)	(0.2	)%

Other sales and operating revenues
Illinois Basin	$	3,416	$	4,117	$	(701)	(17.0	)%
Appalachia	718		4,902		(4,184)		(85.4	)%
Other and Corporate	10,717		7,728		2,989		38.7	%
Elimination	(5,267)		(1,777)		(3,490)		(1	)
Total other sales and operating revenues	$	9,584	$	14,970	$	(5,386)	(36.0	)%

Segment Adjusted EBITDA Expense
Illinois Basin	$	249,615	$	247,625	$	1,990	0.8	%
Appalachia	80,421		95,956		(15,535)		(16.2	)%
Other and Corporate	33,701		6,820		26,881		(1	)
Elimination	(27,663)		(1,777)		(25,886)		(1	)
Total Segment Adjusted EBITDA Expense (3)	$	336,074	$	348,624	$	(12,550)	(3.6	)%

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

(2) Segment Adjusted EBITDA, which is not a financial measure calculated in accordance with generally accepted accounting principles (“GAAP”), is defined as net income (prior to the allocation of noncontrolling interest) before net interest expense, income taxes, depreciation, depletion and amortization, general and administrative expenses and asset impairment charge. 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:

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·	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 consolidated 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:

	Three Months Ended
	September 30,
	2015		2014
	(in thousands)

Segment Adjusted EBITDA	$	203,755	$	214,771

General and administrative	(17,948)		(16,995)
Depreciation, depletion and amortization	(84,661)		(69,646)
Asset impairment charge	(10,695)		-
Interest expense, net	(7,067)		(8,152)
Income tax expense	(12)		-
Net income	$	83,372	$	119,978

(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 Segment Adjusted 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.

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

	Three Months Ended
	September 30,
	2015		2014
	(in thousands)

Segment Adjusted EBITDA Expense	$	336,074	$	348,624

Outside coal purchases	(2)		(3)
Other income	455		549
Operating expenses (excluding depreciation, depletion and amortization)	$	336,527	$	349,170

Illinois Basin – Segment Adjusted EBITDA increased 1.6% to $147.5 million in the 2015 Quarter from $145.3 million in the 2014 Quarter. The increase of $2.2 million was primarily attributable to higher coal sales, which increased 5.7% to $410.8 million compared to $388.8 million in the 2014 Quarter, partially offset by an increase of $17.0 million in equity in loss of affiliates from White Oak prior to the Acquisition primarily due to a July 2015 longwall move and the impact of changes in allocations of equity income or losses resulting from equity contributions during the 2014 Quarter from another White Oak partner. The increase of $22.0 million in coal sales reflects higher tons sold, which increased 10.5% to 8.1 million tons in the 2015 Quarter, as a result of higher coal sales volumes from our Gibson South mine and additional volumes from the assumption of operations at the Hamilton mine, offset in part by reduced unit shifts at our Pattiki, Warrior, Onton and Gibson North mines and lower average coal sales prices of $50.50 in the 2015 Quarter compared to $52.82 in the 2014 Quarter due to the assumption of lower-priced legacy contracts as a result of the Acquisition and the impact of current market conditions. Segment Adjusted EBITDA Expense increased slightly to $249.6 million in the 2015 Quarter from $247.6 million in the 2014 Quarter reflecting production variances discussed above. Segment Adjusted EBITDA Expense per ton sold decreased 8.8% to $30.69 from $33.64 per ton sold in the 2014 Quarter, primarily due to the addition of lower-cost longwall production from the Hamilton mine, increased production and recoveries from our Gibson South mine, improved recoveries from our Dotiki and Hopkins mines and lower coal inventory charges, as well as certain cost decreases described above under “–Operating expenses and outside coal purchases.”

Appalachia – Segment Adjusted EBITDA decreased to $53.4 million for the 2015 Quarter from $68.5 million in the 2014 Quarter. The decrease of $15.1 million was primarily attributable to lower tons sold, which decreased 12.3% to 2.2 million tons sold in the 2015 Quarter, lower average coal sales prices of $61.61 per ton sold during the 2015 Quarter compared to $64.76 per ton sold in the 2014 Quarter and the absence of certain payments in lieu of shipments received from a customer in the 2014 Quarter related to a Tunnel Ridge coal sales contract. Coal sales decreased 16.6% to $133.1 million compared to $159.6 million in the 2014 Quarter. The decrease of $26.5 million was primarily due to reduced sales volumes from our Tunnel Ridge mine and lower average coal sales prices at our MC Mining and Tunnel Ridge mines due to current market conditions. Segment Adjusted EBITDA Expense decreased 16.2% to $80.4 million in the 2015 Quarter from $96.0 million in the 2014 Quarter, primarily due to an inventory build at our Tunnel Ridge and MC Mining mines. Segment Adjusted EBITDA Expense per ton decreased $1.71 per ton sold to $37.23 compared to $38.94 per ton sold in the 2014 Quarter, primarily due to increased recoveries and fewer longwall move days at our Tunnel Ridge mine, lower coal inventory charges in the 2015 Quarter and certain cost decreases described above under “–Operating expenses and outside coal purchases.”

Other and Corporate – Segment Adjusted EBITDA increased $5.3 million in the 2015 Quarter from the 2014 Quarter and Segment Adjusted EBITDA Expense increased to $33.7 million for the 2015 Quarter compared to $6.8 million for the 2014 Quarter. These increases were primarily as a result of

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increased Mt. Vernon transloading services and other intercompany related activity such as increased coal brokerage activity and revenues and expenses of AROP Funding and Wildcat Insurance, which are eliminated upon consolidation.

Elimination – Segment Adjusted EBITDA Expense and coal sales eliminations significantly increased in the 2015 Quarter to $27.7 million and $25.8 million, respectively, reflecting additional intercompany coal sales to Alliance Coal, our operating subsidiary, to support increased coal brokerage activity resulting from new coal supply agreements acquired from Patriot on December 31, 2014. For more information on the Patriot acquisition, please read “Item 1. Financial Statements (Unaudited) – Note 4. Acquisitions” of this Quarterly Report on Form 10-Q.

Nine Months Ended September 30, 2015 Compared to Nine Months Ended September 30, 2014

We reported net income of $284.7 million for the nine months ended September 30, 2015 (“2015 Period”) compared to $373.5 million for the nine months ended September 30, 2014 (“2014 Period”). The decrease of $88.8 million was principally due to lower average coal sales prices, increased operating expenses, increased depreciation, depletion and amortization, a non-cash asset impairment, and higher equity in loss of affiliates. Average coal sales prices decreased by $1.64 to $53.92 per ton sold in the 2015 Period compared to $55.56 per ton sold in the 2014 Period. Higher operating expenses during the 2015 Period primarily resulted from increased sales and production volumes from our Gibson South, Mettiki and Tunnel Ridge mines and additional volumes from the assumption of operations at the Hamilton mine as well as non-recurring expense reductions in the 2014 Period related to Onton insurance proceeds and a gain on the sale of Pontiki assets both discussed below. The increases in operating expenses were partially offset by the impact of lower sales at our Warrior, Gibson North, Pattiki and Onton mines due to shift reductions in response to market conditions as well as an inventory build at several locations. In addition to shift reductions, reduced production from Warrior also resulted from its continuing transition to a new mining area. Decreases to net income were also offset partially by increased other sales and operating revenues primarily reflecting higher surface facility services and coal royalties from White Oak prior to the Acquisition.

	Nine Months Ended September 30,
	2015	2014	2015	2014
	(in thousands)		(per ton sold)
Tons sold	30,276	29,682	N/A	N/A
Tons produced	31,471	30,233	N/A	N/A
Coal sales	$1,632,493	$1,649,093	$53.92	$55.56
Operating expenses and outside coal purchases	$1,046,280	$1,024,312	$34.56	$34.51

Coal sales. Coal sales decreased 1.0% to $1.63 billion for the 2015 Period from $1.65 billion for the 2014 Period. The decrease of $16.6 million in coal sales reflected lower average coal sales prices which reduced coal sales by $49.6 million, partially offset by the benefit of record tons sold which contributed $33.0 million in additional coal sales. Average coal sales prices decreased by $1.64 to $53.92 per ton sold in the 2015 Period compared to $55.56 per ton sold in the 2014 Period, primarily as a result of current market conditions and lower-priced legacy contracts inherited at the Hamilton mine. Sales and production volumes rose to 30.3 million tons sold and 31.5 million tons produced in the 2015 Period compared to 29.7 million tons sold and 30.2 million tons produced in the 2014 Period, primarily due to increased production at our Tunnel Ridge mine, the ramp up of coal production at our Gibson South mine following the commencement of operations in April 2014 and the addition of Hamilton production beginning August 1, 2015, offset in part by reduced unit shifts at various mines discussed above in response to market conditions.

Operating expenses and outside coal purchases. Operating expenses and outside coal purchases increased 2.1% to $1.05 billion for the 2015 Period from $1.02 billion for the 2014 Period primarily reflecting higher sales and production volumes in the 2015 period discussed above. On a per ton basis,

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operating expenses and outside coal purchases increased slightly by 0.1% to $34.56 per ton sold in the 2015 Period from $34.51 per ton sold in the 2014 Period, primarily due to lower recoveries at our Warrior, Gibson North and Appalachian mines, increased material and supplies expenses at our Tunnel Ridge mine and shift reductions at our Pattiki, Warrior, Gibson North and Onton mines, partially offset by increased production and improved recoveries at our Gibson South mine and the addition of lower-cost longwall production from the Hamilton mine. Operating expenses were impacted by various other factors, the most significant of which are discussed below:

· Operating expenses for the 2015 Period increased as a result of the benefit of $7.0 million of insurance proceeds in the 2014 Period related to claims from the adverse geological event at the Onton mine in 2013 which were absent in the 2015 Period; and

· Operating expenses for the 2015 Period also increased as a result of the benefit of a gain of $4.4 million recognized in the 2014 Period on the sale of Pontiki’s assets which was absent in the 2015 Period. In May 2014, Pontiki completed the sale of most of its assets, including certain coal reserves, mining equipment and infrastructure and surface facilities.

Operating expenses and outside coal purchases per ton increases discussed above were offset partially by the following decreases:

· Labor and benefit expenses per ton produced, excluding workers’ compensation, decreased 1.0% to $11.40 per ton in the 2015 Period from $11.51 per ton in the 2014 Period. This decrease of $0.11 per ton was primarily attributable to lower labor and benefit costs per ton resulting from increased production and a favorable production mix in the 2015 Period discussed above and reduced overtime hours as a result of reduced unit shifts at certain mines offset partially by higher medical expenses in the 2015 period;

· Material and supplies expenses per ton produced decreased 1.3% to $11.39 per ton in the 2015 Period from $11.54 per ton in the 2014 Period. The decrease of $0.15 per ton produced resulted primarily from the benefits of increased production and a favorable production mix in the 2015 Period discussed above and related decreases of $0.19 per ton for material and supplies for roof support, $0.12 per ton for certain ventilation related materials and supplies expenses, partially offset by an increase of $0.12 per ton in longwall subsidence expense; and

· Production taxes and royalties expenses incurred as a percentage of coal sales prices and volumes decreased $0.41 per produced ton sold in the 2015 Period compared to the 2014 Period primarily as a result of lower average coal sales prices as discussed above and increased brokerage coal sales which have minimal production taxes and royalty expenses if any.

Other sales and operating revenues. Other sales and operating revenues are principally comprised of Mt. Vernon transloading revenues, Matrix Design sales, surface facility services and coal royalty revenues received from White Oak prior to the Acquisition and other outside services and administrative services revenue from affiliates. Other sales and operating revenues increased to $74.8 million for the 2015 Period from $43.0 million for the 2014 Period. The increase of $31.8 million was primarily attributable to increased surface facility services and coal royalty revenues received from White Oak prior to the Acquisition as a result of the ramp-up of longwall production and increased revenues at our Mt. Vernon operations primarily due to increased transloading for Hamilton mine volumes.

General and administrative. General and administrative expenses for the 2015 Period decreased to $52.3 million compared to $54.2 million in the 2014 Period. The decrease of $1.9 million was primarily due to lower incentive compensation expenses and other professional services.

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Depreciation, depletion and amortization. Depreciation, depletion and amortization expense increased to $242.7 million for the 2015 Period from $203.5 million for the 2014 Period. The increase of $39.2 million was attributable to the reduction of the economic mine life at our Elk Creek mine, which is expected to close by the end of the first quarter of 2016, increased production at the Gibson South mine, which commenced initial production in April 2014, amortization of coal supply agreements acquired in December 2014 and the addition of the Hamilton mine in late July 2015.

Asset impairment charge. In the 2015 Period, we recognized an asset impairment charge of $10.7 million to write down assets associated with the recent surrender of a lease agreement for certain undeveloped coal reserves and related property in western Kentucky. We determined that coal reserves held under this lease were not a core part of our foreseeable development plans and surrendered the lease in order to avoid the high holding costs for those reserves.

Interest expense. Interest expense, net of capitalized interest, decreased to $23.6 million for the 2015 Period from $25.4 million for the 2014 Period. The decrease of $1.8 million was principally attributable to the repayment of our Series A senior notes in June 2015 offset in part by interest incurred on debt assumed in the Acquisition.

Equity in loss of affiliates, net. Equity in loss of affiliates, net for the 2015 Period includes our equity investments in White Oak prior to the Acquisition and AllDale Minerals. The 2014 Period includes White Oak and MAC. Please read “Item 1. Financial Statements (Unaudited) – Note 4. Acquisitions” and “– Note 9. Equity Investment” of this Quarterly Report on Form 10-Q. For the 2015 Period, we recognized equity in loss of affiliates of $49.0 million compared to $13.5 million for the 2014 Period. The increase in equity in loss of affiliates, net is primarily due to low coal sales price realizations and higher expenses related to White Oak’s ramp up of longwall operations in the 2015 Period prior to the Acquisition and the impact of changes in allocations of equity income or losses resulting from reduced equity contributions during the 2015 Period from another White Oak partner.

Transportation revenues and expenses. Transportation revenues and expenses were $24.3 million and $17.8 million for the 2015 and 2014 Periods, respectively. The increase of $6.5 million was primarily attributable to increased tonnage for which we arrange transportation at certain mines, partially offset by a decrease in average transportation rates in the 2015 Period. The cost of transportation services are passed through to our customers. Consequently, we do not realize any gain or loss on transportation revenues.

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Segment Adjusted EBITDA. Our 2015 Period Segment Adjusted EBITDA decreased $42.7 million, or 6.5%, to $612.7 million from the 2014 Period Segment Adjusted EBITDA of $655.4 million. Segment Adjusted EBITDA, tons sold, coal sales, other sales and operating revenues and Segment Adjusted EBITDA Expense by segment are:

	Nine Months Ended September 30,
	2015		2014(recast)		Increase/(Decrease)
	(in thousands)
Segment Adjusted EBITDA
Illinois Basin	$	445,819	$	465,851	$	(20,032)	(4.3)%
Appalachia	154,760		184,460		(29,700)		(16.1)%
Other and Corporate	21,752		5,121		16,631		(1)
Elimination	(9,652)		-		(9,652)		-
Total Segment Adjusted EBITDA (2)	$	612,679	$	655,432	$	(42,753)	(6.5)%

Tons sold
Illinois Basin	22,992		22,857		135		0.6%
Appalachia	7,276		6,825		451		6.6%
Other and Corporate	2,298		-		2,298		-
Elimination	(2,290)		-		(2,290)		-
Total tons sold	30,276		29,682		594		2.0%

Coal sales
Illinois Basin	$	1,180,862	$	1,201,980	$	(21,118)	(1.8)%
Appalachia	441,350		446,953		(5,603)		(1.3)%
Other and Corporate	108,748		160		108,588		(1)
Elimination	(98,467)		-		(98,467)		-
Total coal sales	$	1,632,493	$	1,649,093	$	(16,600)	(1.0)%

Other sales and operating revenues
Illinois Basin	$	41,458	$	13,847	$	27,611	(1)
Appalachia	10,389		12,953		(2,564)		(19.8)%
Other and Corporate	37,922		23,499		14,423		61.4%
Elimination	(15,004)		(7,280)		(7,724)		(1)
Total other sales and operating revenues	$	74,765	$	43,019	$	31,746	73.8%

Segment Adjusted EBITDA Expense
Illinois Basin	$	728,048	$	736,174	$	(8,126)	(1.1)%
Appalachia	296,980		275,446		21,534		7.8%
Other and Corporate	124,321		18,794		105,527		(1)
Elimination	(103,819)		(7,280)		(96,539)		(1)
Total Segment Adjusted EBITDA Expense (3)	$	1,045,530	$	1,023,134	$	22,396	2.2%

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

(2)	Segment Adjusted EBITDA (a non-GAAP financial measure) is defined as net income (prior to the allocation of noncontrolling interest) before net interest expense, income taxes, depreciation, depletion and amortization, general and administrative expenses and asset impairment charge. 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:

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· 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.

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

	Nine Months Ended
	September 30,
	2015		2014
	(in thousands)

Segment Adjusted EBITDA	$	612,679	$	655,432

General and administrative	(52,336)		(54,201)
Depreciation, depletion and amortization	(242,730)		(203,539)
Asset impairment charge	(10,695)		-
Interest expense, net	(22,205)		(24,157)
Income tax benefit	(17)		-
Net income	$	284,696	$	373,535

(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 Segment Adjusted 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.

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

	Nine Months Ended
	September 30,
	2015	2014
	(in thousands)

Segment Adjusted EBITDA Expense	$ 1,045,530	$ 1,023,134

Outside coal purchases	(326)	(7)
Other income	750	1,178
Operating expenses (excluding depreciation, depletion and amortization)	$ 1,045,954	$ 1,024,305

Illinois Basin – Segment Adjusted EBITDA decreased 4.3% to $445.8 million in the 2015 Period from $465.9 million in the 2014 Period. The decrease of $20.1 million was primarily attributable to lower coal sales, which decreased 1.8% to $1.18 billion in the 2015 Period from $1.20 billion in the 2014 Period, and higher equity in loss of affiliates from White Oak prior to the Acquisition as discussed above, partially offset by increased surface facility services and coal royalty revenues received from White Oak prior to the Acquisition. The decrease of $21.1 million in coal sales primarily reflects lower average coal sales prices of $51.36 in the 2015 Period compared to $52.59 in the 2014 Period resulting from current market conditions and the assumption of lower-priced legacy contracts inherited from the Hamilton mine, lower recoveries and shift reductions at our Warrior and Gibson North mines and shift reductions at our Pattiki and Onton mines, offset in part by higher coal sales volumes from our Gibson South mine and additional volumes from the assumption of operations at the Hamilton mine. Segment Adjusted EBITDA Expense decreased 1.1% to $728.0 million in the 2015 Period from $736.2 million in the 2014 Period and decreased $0.54 per ton sold to $31.67 from $32.21 per ton sold in the 2014 Period, primarily due to production variances discussed above which created a favorable production mix in the 2015 Period offset partially by insurance proceeds received in the 2014 Period related to the Onton mine, as well as the impact of certain other cost increases and decreases described above under “–Operating expenses and outside coal purchases.”

Appalachia – Segment Adjusted EBITDA decreased to $154.8 million for the 2015 Period as compared to $184.5 million for the 2014 Period. The decrease of $29.7 million was primarily attributable to lower average coal sales prices as a result of current market conditions, lower production recoveries across the region and decreased payments in lieu of shipments received from a customer related to a Tunnel Ridge coal supply agreement. Coal sales decreased 1.3% to $441.4 million in the 2015 Period compared to $447.0 million in the 2014 Period. The decrease of $5.6 million was primarily attributable to lower average coal sales prices of $60.66 per ton sold during the 2015 Period compared to $65.49 per ton sold in the 2014 Period reflecting the impact of market conditions at our Tunnel Ridge and MC Mining mines, offset in part by increased tons sold, which increased 6.6% to 7.3 million tons in the 2015 Period compared to 6.8 million tons sold in the 2014 Period resulting from increased production and sales volumes at our Tunnel Ridge and Mettiki mines. Segment Adjusted EBITDA Expense increased 7.8% to $297.0 million in the 2015 Period from $275.4 million in the 2014 Period and increased $0.46 per ton sold to $40.82 from $40.36 per ton sold in the 2014 Period, primarily due to lower recoveries discussed above and increased materials and supplies and maintenance costs at our Tunnel Ridge mine partially offset by the benefit of fewer longwall move days in the 2015 Period, as well as the impact of certain other cost increases and decreases discussed above under “–Operating expenses and outside coal purchases.”

Other and Corporate – Segment Adjusted EBITDA increased $16.7 million to $21.8 million in the 2015 Period from $5.1 million in the 2014 Period and Segment Adjusted EBITDA Expense increased to $124.3 million for the 2015 Period from $18.8 million in the 2014 Period. These increases were

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primarily as a result of increased Mt. Vernon transloading services and intercompany related activity such as increased coal brokerage activity, MAC sales and revenues and expenses of AROP Funding and Wildcat Insurance, which are eliminated upon consolidation. Segment Adjusted EBITDA Expense also increased in the 2015 Period due to the benefit of a gain of $4.4 million recognized in the 2014 Period on the sale of Pontiki’s assets.

Liquidity and Capital Resources

Liquidity

We have historically satisfied our working capital requirements and funded our capital expenditures, equity investments and debt service obligations with cash generated from operations, cash provided by the issuance of debt or equity and borrowings under credit and securitization facilities. We believe that existing cash balances, future cash flows from operations, borrowings under credit facilities and cash provided from the issuance of debt or equity will be sufficient to meet our working capital requirements, capital expenditures and additional equity investments, debt payments, commitments and distribution payments. Our ability to satisfy our obligations 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. 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 our Annual Report on Form 10-K for the year ended December 31, 2014.

Cash Flows

Cash provided by operating activities was $528.9 million for the 2015 Period compared to $586.4 million for the 2014 Period. The decrease in cash provided by operating activities was primarily due to a nominal decrease in net income adjusted for increased non-cash items, a decrease in accounts payable during the 2015 Period compared to an increase during the 2014 Period, a decrease in payroll and related benefits accruals during the 2015 Period compared to an increase during the 2014 Period reflecting higher annual incentive compensation payments in the 2015 Period, an increase in inventories during the 2015 Period as compared to the 2014 Period, an increase in advance royalties in the 2015 Period compared to a decrease in the 2014 Period, and a decrease in amounts due to affiliates compared to an increase in the 2014 Period, offset by an increase in trade receivables during the 2015 Period compared to an decrease during the 2014 Period.

Net cash used in investing activities was $288.8 million for the 2015 Period compared to $315.4 million for the 2014 Period. The decrease in cash used in investing activities was primarily attributable to the lower capital expenditures for mine infrastructure and equipment at various mines, particularly at our Gibson South mine, and a decrease in funding of the White Oak equity investment in the 2015 Period, partially offset by cash and loans extended in connection with acquisitions in the 2015 Period. For more information regarding acquisitions, please read “Item 1. Financial Statements (Unaudited) – Note 4. Acquisitions” of this Quarterly Report on Form 10-Q.

Net cash used in financing activities was $228.7 million for the 2015 Period compared to $349.8 million for the 2014 Period. The decrease in cash used in financing activities was primarily attributable to a decrease in payments and an increase in borrowings under our revolving credit facilities during the 2015 Period, partially offset by increased distributions paid to partners in the 2015 Period and repayment of our Series A Senior Notes in the 2015 Period, which is discussed in more detail below under “–Debt Obligations.”

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Capital Expenditures

Capital expenditures decreased to $159.2 million in the 2015 Period from $233.7 million in the 2014 Period.

Our anticipated total capital expenditures for the year ending December 31, 2015 are estimated in a range of $265.0 million to $285.0 million, which includes expenditures for infrastructure projects and maintenance capital at various mines. In addition to these capital expenditures, we now anticipate funding in 2015 investments of approximately $105.0 million to $115.0 million. Included in this estimate is approximately $40.0 million completing our initial commitment to acquire oil and gas mineral interests, $10.3 million of preferred equity contribution funded to White Oak in the 2015 Period and the $50.0 million payment to acquire the remaining equity interests in White Oak. For more information on White Oak, please read “Item 1. Financial Statements (Unaudited) – Note 4. Acquisitions” of this Quarterly Report on Form 10-Q. We also recently elected to increase our commitment to the acquisition of oil and gas mineral interests by an additional $100.0 million and our 2015 estimated investments include funding approximately $10.0 million of this increased commitment. Management anticipates funding remaining 2015 capital requirements with cash and cash equivalents ($35.9 million as of September 30, 2015), cash flows from operations, borrowings under the revolving credit and securitization facilities as discussed below and, if necessary, accessing the debt or equity capital markets. 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

Credit Facility. On May 23, 2012, our Intermediate Partnership entered into a credit agreement (the “Credit Agreement”) with various financial institutions for a revolving credit facility (the “Revolving Credit Facility”) of $700.0 million and a term loan (the “Term Loan”) in the aggregate principal amount of $250.0 million (collectively, the Revolving Credit Facility and Term Loan are referred to as the “Credit Facility”). Borrowings under the Credit Agreement bear interest at a Base Rate or Eurodollar Rate, at our election, plus an applicable margin that fluctuates depending upon the ratio of Consolidated Debt to Consolidated Cash Flow (each as defined in the Credit Agreement). We have elected a Eurodollar Rate which, with applicable margin, was 1.85% on borrowings outstanding as of September 30, 2015. The Credit Facility matures May 23, 2017, at which time all amounts then outstanding are required to be repaid. Interest is payable quarterly, with principal of the Term Loan due as follows: for each quarter commencing June 30, 2014 and ending March 31, 2016, quarterly principal payments in an amount per quarter equal to 2.50% of the aggregate amount of the Term Loan advances outstanding; for each quarter beginning June 30, 2016 through December 31, 2016, 20% of the aggregate amount of the Term Loan advances outstanding; and the remaining balance of the Term Loan advances at maturity. In June 2014, we began making quarterly principal payments on the Term Loan, leaving a balance of $212.5 million at September 30, 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 Credit Agreement. Upon a “change of control” (as defined in the Credit Agreement), the unpaid principal amount of the Credit Facility, all interest thereon and all other amounts payable under the Credit Agreement would become due and payable. On October 16, 2015 the Revolving Credit Facility was amended to increase the baskets for capital lease obligations and sale-leaseback arrangements from $10.0 million to $100.0 million.

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

The Series B Notes and the Credit Facility described above (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, incurrence of additional indebtedness and liens, sale of assets, investments, mergers and consolidations and 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 (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 3.0 to 1.0, in each case, during the four most recently ended fiscal quarters. The debt to cash flow ratio and cash flow to interest expense ratio were 1.23 to 1.0 and 24.3 to 1.0, respectively, for the trailing twelve months ended September 30, 2015. We were in compliance with the covenants of the ARLP Debt Arrangements as of September 30, 2015.

Accounts Receivable Securitization. On December 5, 2014, certain direct and indirect wholly owned subsidiaries of our Intermediate Partnership entered into a $100.0 million accounts receivable securitization facility (“Securitization Facility”) providing additional liquidity and funding. Under the Securitization Facility, certain subsidiaries sell trade receivables on an ongoing basis to our Intermediate Partnership, which then sells the trade receivables to AROP Funding, a wholly owned bankruptcy-remote special purpose subsidiary of our Intermediate Partnership, which in turn borrows on a revolving basis up to $100.0 million secured by the trade receivables. After the sale, Alliance Coal, as servicer of the assets, collects the receivables on behalf of AROP Funding. The Securitization Facility bears interest based on a Eurodollar Rate. The Securitization Facility has an initial term of 364 days; however, we have the contractual ability and the intent to extend the term for an additional 364 days. At September 30, 2015, we had $100.0 million outstanding under the Securitization Facility. Debt issuance costs were immaterial for this transaction.

Hamilton Revolving Credit Facility. As a result of the Hamilton Acquisition, we assumed the Hamilton Revolving Credit Facility and the Hamilton Equipment Financing Note. Please read “Item 1. Financial Statements (Unaudited) – Note 4. Acquisitions” of this Quarterly Report on Form 10-Q. In November 2014, White Oak entered into the Hamilton Revolving Credit Facility with Farmers State Bank allowing for periodic borrowings up to $10.0 million, collateralized by White Oak’s accounts receivable. Borrowings under the Hamilton Revolving Credit Facility carried interest at the prime rate plus 0.1%, which was 3.35% at September 30, 2015. On October 19, 2015, the outstanding balance of the Hamilton Revolving Credit Facility totaling $10.0 million was repaid.

Hamilton Equipment Financing Agreement. In 2012, White Oak acquired vendor financing totaling $100.0 million through the Hamilton Equipment Financing Agreement, which was secured by continuous mining, long-wall mining, and underground belt system equipment purchased from the vendor. The Hamilton Equipment Financing Agreement required repayment of principal and interest in equal monthly installments of $2.1 million from July 2014 until June 2019. As of September 30, 2015, $82.5 million remained outstanding on the note and carried an annual interest rate of 8%. On October 16, 2015, the outstanding balance of the Hamilton Equipment Financing Agreement totaling $80.6 million was repaid without penalty with funds drawn on the Revolving Credit Facility.

Equipment Financing Agreement. On October 29, 2015, we entered into a sale-leaseback transaction whereby we sold certain mining equipment for $100.0 million and concurrently entered into a lease agreement for the sold equipment with a four-year term. Under the lease agreement, we will pay an initial monthly rent of $1.9 million. A balloon payment equal to 20% of the equipment cost is due at the end of the lease term.

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Cavalier Credit Agreement. On October 6, 2015, Cavalier Minerals JV, LLC (“Cavalier Minerals”) entered into a credit agreement (the “Cavalier Credit Agreement”) with Mineral Lending, LLC (“Mineral Lending”) for a $100.0 million line of credit (the “Cavalier Credit Facility”). Please read “Item 1. Financial Statements (Unaudited) – Note 8. Variable Interest Entities” of this Quarterly Report on Form 10-Q. There is no commitment fee under the facility. Borrowings under the Cavalier Credit Facility bear interest at a one month LIBOR rate plus 6% with interest payable quarterly. Repayment of the principal balance will begin following the first fiscal quarter after the earlier of the date on which the aggregate amount borrowed exceeds $90.0 million or December 31, 2017, in quarterly payments of an amount equal to the greater of $1.3 million initially, escalated to $2.5 million after two years, or fifty percent of Cavalier Minerals’ excess cash flow. The Cavalier Credit Facility matures September 30, 2024, at which time all amounts then outstanding are required to be repaid. Cavalier Minerals may prepay the Cavalier Credit Facility at any time in whole or in part subject to terms and conditions described in the Cavalier Credit Agreement.

Other. In addition to the letters of credit available under the 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 September 30, 2015, 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 agreements relating to the use of aircraft. Recently, we entered into three mineral leases with WKY CoalPlay, LLC (“WKY CoalPlay”), an affiliate of SGP. We have also had transactions with AllDale Minerals and Bluegrass Minerals to support the acquisition of oil and gas mineral interests. For more information regarding WKY CoalPlay, AllDale Minerals and Bluegrass Minerals, please read “Item 1. Financial Statements (Unaudited) – Note 8. Variable Interest Entities” and “– Note 9. Equity Investment” of this Quarterly Report on Form 10-Q. Please read our Annual Report on Form 10-K for the year ended December 31, 2014, “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Related-Party Transactions” for additional information concerning related-party transactions.

On July 31, 2015, we acquired the remaining equity interests in White Oak, which we had previously considered to be a related party as a result of our 40% ownership. As a result of this acquisition, White Oak’s activities are included in our consolidated results. For more information regarding the White Oak acquisition, please read “Item 1. Financial Statements (Unaudited) – Note 4. Acquisitions” of this Quarterly Report on Form 10-Q.

New Accounting Standards

New Accounting Standard Issued and Adopted

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do not meet the definition of discontinued operations. ASU 2014-08 was effective for fiscal years, and interim periods within those years, beginning after December 15, 2014. The adoption of ASU 2014-08 did not have a material impact on our condensed consolidated financial statements.

In September 2015, the FASB issued ASU 2015-16, Simplifying the Accounting for Measurement-Period Adjustments (“ASU 2015-16”). ASU 2015-16 requires that an acquirer within a business combination recognize adjustments to provisional amounts that are identified during the measurement period in the reporting period in which the adjustment amounts are determined. ASU 2015-16 is effective for fiscal years, and interim periods within those years, beginning after December 15, 2015 with early adoption permitted and shall be applied prospectively after adoption. We elected to early adopt the standard in September 2015. The adoption of ASU 2015-16 did not have a material impact on our condensed consolidated financial statements.

New Accounting Standards Issued and Not Yet Adopted

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Other Information

White Oak IRS Notice

We received notice that the Internal Revenue Service issued White Oak Resources LLC a “Notice of Beginning of Administrative Proceeding” in conjunction with an audit of the income tax return of White Oak for the tax year ended December 31, 2011.

Regulation and Laws

Reference is made to “Item 1. Business – Regulation and Laws – Air Emissions” in our Annual Report on Form 10-K for the year ended December 31, 2014.

In August 2015, the EPA issued its final Clean Power Plan rules that establish carbon pollution standards for power plants, called CO2 emission performance rates. The EPA expects each state to develop implementation plans for power plants in its state to meet the individual state targets established in the Clean Power Plan. The EPA has given states the option to develop compliance plans for annual rate-based reductions (pounds per megawatt hour) or mass-based tonnage limits for CO2. The state plans are due in September 2016, subject to potential extensions of up to two years for final plan submission. The compliance period begins in 2022, and emission reductions will be phased in up to 2030. The EPA also proposed a federal compliance plan to implement the Clean Power Plan in the event that an approvable state plan is not submitted to the EPA. We expect that judicial challenges will be filed, which may result in a stay of the implementation of the rules. Nevertheless, if the rules are implemented in their current form, the market for coal may be decreased, potentially significantly. We are continuing to evaluate the rules and are not in position to make any meaningful determination about the extent of the impacts to our operations.

In October 2015, the EPA issued final regulations that lower the National Ambient Air Quality Standard, or NAAQS, for ozone from 75 parts per billion, or ppb, for both the 8-hour primary and secondary standards, to 70 ppb. The EPA intends to designate attainment and nonattainment areas by October 1, 2017, and states with moderate or higher nonattainment areas must submit state implementation plans, or SIPs, by October 1, 2021. The adoption of the revised ozone NAAQS may require states to enact additional regulations to control emissions of volatile organic compounds and nitrogen oxides from certain sources, which could apply to our operations and result in increased compliance costs.

In May 2015, the EPA released a final rule that sets forth changes to its definition of “waters of the United States” under the Clean Water Act (“CWA”). In August 2015, a federal district judge in North Dakota enjoined implementation of the rule in 13 states. Federal district judges in West Virginia and Georgia denied similar motions for injunctions for lack of subject matter jurisdiction, while district judges in several other jurisdictions have stayed their cases until the Judicial Panel on Multidistrict Litigation ruled on whether to consolidate all of the district court cases in a single court. In October 2015, the Judicial Panel on Multidistrict Litigation declined to consolidate the various district court cases in a single court. In addition, in October 2015, the Sixth Circuit issued a nationwide stay of the rule until it

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determines whether it has jurisdiction over the petitions for review brought in the federal appellate courts. Although the EPA has stated that the rule does not create any new permitting requirements and maintains all previous exemptions and exclusions to CWA jurisdiction, we are currently evaluating the effects, if any, the finalized rule may have on our operations or permitting obligations. Any expansion to CWA jurisdiction could impose additional permitting obligations on our operations, which may adversely impact our coal production or results of operations.

Insurance

Effective October 1, 2015, we renewed our annual property and casualty insurance program. Our property insurance was procured from our wholly owned captive insurance company, Wildcat Insurance. Wildcat Insurance charged certain of our subsidiaries for the premiums on this program and in return purchased reinsurance for the program in the standard market. The maximum limit in the commercial property program is $100.0 million per occurrence, excluding a $1.5 million deductible for property damage, a 75, 90 or 120 day waiting period for underground business interruption depending on the mining complex and an additional $10.0 million overall aggregate deductible. We can make no assurances that we will not experience significant insurance claims in the future that could have a material adverse effect on our business, financial condition, results of operations and ability to purchase property insurance in the future.

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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 the creditworthiness of each customer 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 prepayment for shipments or establishing customer trust accounts held for our benefit in the event of a failure to pay.

Exchange Rate Risk

Almost all of our transactions are denominated in U.S. Dollars, and as a result, we do not have material exposure to currency exchange-rate risks.

Interest Rate Risk

Borrowings under the Revolving Credit Facility, Securitization Facility, Hamilton Revolving Credit Facility and Cavalier Credit 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 $403.0 million in borrowings under the Revolving Credit Facility, $212.5 million outstanding under the Term Loan, $10.0 million outstanding under the Hamilton Revolving Credit Facility and $100.0 million in borrowings under the Securitization Facility at September 30, 2015. A one percentage point increase in the interest rates related to the Revolving Credit Facility, Term Loan and Securitization Facility would result in an annualized increase in 2015 interest expense of $7.3 million, based on interest rate and borrowing levels at September 30, 2015. With respect to our fixed-rate borrowings, a one percentage point increase in interest rates would result in a decrease of approximately $3.9 million in the estimated fair value of these borrowings.

As of September 30, 2015, the estimated fair value of the ARLP Debt Arrangements was approximately $963.8 million. The fair values of long-term debt are estimated using discounted cash flow analyses, based upon our current incremental borrowing rates for similar types of borrowing arrangements as of September 30, 2015. 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, 2014.

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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 Securities and Exchange Commission (“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 Securities Exchange Act of 1934, as amended (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 Exchange Act) as of September 30, 2015. Based on this evaluation, our Chief Executive Officer and Chief Financial Officer concluded that these controls and procedures are effective as of September 30, 2015.

During the quarterly period ended September 30, 2015, other than changes that have resulted or may result from our purchase of the remaining equity of White Oak Resources LLC (“White Oak”) which included the operations of the Hamilton mine (“Hamilton”) as described below, there have not been any changes in our internal control over financial reporting (as defined in Rule 13a-15(f) under the Exchange Act) identified in connection with this evaluation that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

On July 31, 2015 (the “Hamilton Acquisition Date”), we acquired the remaining Series A and B Units, representing 60% of the voting interests in White Oak as described in “Item 1. Financial Statements (Unaudited) – Note 4. Acquisitions” of this Quarterly Report on Form 10-Q. As of the Hamilton Acquisition Date, we owned 100% of the equity interests in White Oak and assumed operating control of the Hamilton mine and began accounting for White Oak on a consolidated basis. At this time, we continue to evaluate the business and internal controls and processes of Hamilton and are making various changes to their operating and organizational structures based on our business plan. We are in the process of implementing our internal control structure over the acquired business. We expect to complete the evaluation and integration of the internal controls and processes of Hamilton in fiscal year 2016.

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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;
·	legislation, regulations, and court decisions and interpretations thereof, including those relating to the environment, mining, miner health and safety and health care;
·	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;
·	our productivity levels and margins earned on our coal sales;
·	changes in raw material costs;
·	changes in the availability of skilled labor;
·	our ability to maintain satisfactory relations with our employees;
·	increases in labor costs, adverse changes in work rules, or cash payments or projections associated with post-mine reclamation and workers’ compensation claims;
·	increases in transportation costs and risk of transportation delays or interruptions;
·	operational interruptions due to geologic, permitting, labor, weather-related or other 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;
·	the coal industry’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 other sources of electricity, 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 deductions and credits;
·	difficulty obtaining commercial property insurance, and risks associated with our participation (excluding any applicable deductible) in the commercial insurance property program;

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·	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.

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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 our Annual Report on Form 10-K for the year ended December 31, 2014.

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, 2014 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. We do not believe there have been any material changes to the risk factors previously disclosed in our Annual Report on Form 10-K for the year ended December 31, 2014, except as follows.

The tax treatment of publicly traded partnerships or an investment in our units could be subject to potential legislative, judicial or administrative changes or differing interpretations, possibly applied on a retroactive basis.

The present U.S. federal income tax treatment of publicly traded partnerships, including us, or an investment in our common units may be modified by administrative, legislative or judicial changes or differing interpretations at any time. For example, the Fiscal Year 2016 Budget proposed by the President recommends that certain publicly traded partnerships earning income from activities related to fossil fuels be taxed as corporations beginning in 2021. From time to time, members of Congress propose and consider such substantive changes to the existing U.S. federal income tax laws that affect publicly traded partnerships. If successful, the Obama administration’s proposal or other similar proposals could eliminate the qualifying income exception to the treatment of all publicly-traded partnerships as corporations upon which we rely for our treatment as a partnership for U.S. federal income tax purposes.

In addition, the IRS, on May 5, 2015, issued proposed regulations concerning which activities give rise to qualifying income within the meaning of Section 7704 of the Internal Revenue Code. We do not believe the proposed regulations affect our ability to qualify as a publicly traded partnership. However, finalized regulations could modify the amount of our gross income that we are able to treat as qualifying income for the purposes of the qualifying income requirement.

Any modification to the U.S. federal income tax laws may be applied retroactively and could make it more difficult or impossible for us to meet the exception for certain publicly traded partnerships to be treated as partnerships for U.S. federal income tax purposes. We are unable to predict whether any of these changes or other proposals will ultimately be enacted. Any such changes could negatively impact the value of an investment in our common units.

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

None.

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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 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.

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ITEM 6. EXHIBITS

Incorporated by Reference

Exhibit
Number

Exhibit Description

Form

SEC
File No. and
Film No.

Exhibit

Filing Date

Filed
Herewith*

10.1

Amendment No. 1 to the Third Amended and Restated Credit Agreement dated as of October 16, 2015.

8-K

000-26823

151170915

10.1

10/22/2015

10.2

Master Lease Agreement, dated as of October 29, 2015, between Alliance Resource Operating Partners, L.P., Hamilton County Coal, LLC and White Oak Resources LLC, as lessees, and PNC Equipment Finance, LLC and the other lessors named therein.

8-K

000-26823

151198024

10.1

11/04/2015

31.1

Certification of Joseph W. Craft III, President and Chief Executive Officer of Alliance Resource Management GP, LLC, the managing general partner of Alliance Resource Partners, L.P., dated November 6, 2015, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31.2

Certification of Brian L. Cantrell, Senior Vice President and Chief Financial Officer of Alliance Resource Management GP, LLC, the managing general partner of Alliance Resource Partners, L.P., dated November 6, 2015, 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 September 30, 2015 filed in XBRL).

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

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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized, in Tulsa, Oklahoma, on November 6, 2015.

	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