UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF

THE SECURITIES EXCHANGE ACT OF 1934

FOR THE FISCAL YEAR ENDED DECEMBER 31, ~~2016~~2017

[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF

THE SECURITIES EXCHANGE ACT OF 1934

FOR THE TRANSITION PERIOD FROM______________TO______________

COMMISSION FILE NO.: 0-51952

ALLIANCE HOLDINGS GP, L.P.

(EXACT NAME OF REGISTRANT AS SPECIFIED IN ITS CHARTER)

DELAWARE		03-0573898
(STATE OR OTHER JURISDICTION OF		(IRS EMPLOYER IDENTIFICATION NO.)
INCORPORATION OR ORGANIZATION)

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

(ADDRESS OF PRINCIPAL EXECUTIVE OFFICES AND ZIP CODE)

(918) 295-1415

(REGISTRANT'S TELEPHONE NUMBER, INCLUDING AREA CODE)

Securities registered pursuant to Section 12(b) of the Act:

	Title of Each Class			Name of Each Exchange On Which Registered
Common Units representing limited partner interests				The NASDAQ Stock Market LLC

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

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

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.

[ ] Yes [X] No

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

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

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

Large Accelerated Filer [ ] Accelerated Filer [ X ] Non-Accelerated Filer [ ] Smaller Reporting Company [ ]

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. [ ]

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

The aggregate value of the common units held by non-affiliates of the registrant (treating all executive officers , individuals who comprise a group under Rule 13d-5(b) of the Securities Exchange Act of 1934 and directors of the registrant, for this purpose, as if they may be affiliates of the registrant) was approximately $~~368~~424,~~988~~408,~~474~~177 as of June 30, ~~2016~~2017, the last business day of the registrant's most recently completed second fiscal quarter, based on the reported closing price of the common units as reported on The NASDAQ Stock Market LLC on such date.

As of February 2423, ~~2017~~2018, 59,863,000 common units were outstanding.

DOCUMENTS INCORPORATED BY REFERENCE: None

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TABLE OF CONTENTS

		Page
	PART I
Item 1.	Business	21
Item 1A.	Risk Factors	24
Item 1B.	Unresolved Staff Comments	47
Item 2.	Properties	4748
Item 3.	Legal Proceedings	50
Item 4.	Mine Safety Disclosures	5051
	PART II
Item 5.	Market for Registrant's Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities	5152
Item 6.	Selected Financial Data	5152
Item 7.	Management's Discussion and Analysis of Financial Condition and Results of Operations	5456
Item 7A.	Quantitative and Qualitative Disclosures about Market Risk	7880
Item 8.	Financial Statements and Supplementary Data	8082
Item 9.	Changes in and Disagreements with Accountant on Accounting and Financial Disclosure	~~133~~134
Item 9A.	Controls and Procedures	~~133~~134
Item 9B.	Other Information	~~136~~137
	PART III
Item 10.	Directors, Executive Officers and Corporate Governance of the General Partner	~~137~~138
Item 11.	Executive Compensation	~~141~~143
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters	~~158~~160
Item 13.	Certain Relationships and Related Transactions, and Director Independence	~~160~~162
Item 14.	Principal Accountant Fees and Services	~~162~~164
	PART IV
Item 15.	Exhibits and Financial Statement Schedules	~~163~~165

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FORWARD-LOOKING STATEMENTS

Certain statements and information in this Annual Report on Form 10-K 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 coal prices, which could affect the ARLP Partnership's operating results and cash flows;

changes in competition in coal markets and the ARLP Partnership's ability to respond to such changes;

legislation, regulations, and court decisions and interpretations thereof, including those relating to the environment and the release of greenhouse gases, 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;

risks associated with the expansion of the ARLP Partnership's operations and properties;

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

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

changing global economic conditions or in industries in which the ARLP Partnership's 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;

fluctuations in coal demand, prices and availability;

· ~~continuation~~changes orin ~~worsening of depressed~~ oil and gas prices, ~~adversely~~which ~~affecting~~could affect the ARLP Partnership's investments in oil and gas mineral interests and gas compression services;

the ARLP Partnership's productivity levels and margins earned on its coal sales;

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;

changes in raw material costs;

changes in the availability of skilled labor;

the ARLP Partnership's ability to maintain satisfactory relations with its employees;

increases in labor costs including costs of health insurance and taxes resulting from the Affordable Care Act, 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 the ARLP Partnership's surety bonds for mine reclamation as well as workers' compensation and black lung benefits;

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

uncertainties in estimating and replacing the ARLP Partnership's coal reserves;

a loss or reduction of benefits from certain tax deductions and credits;

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

difficulty in making accurate assumptions and projections regarding future revenues and costs associated with equity investments in companies the ARLP Partnership does not control; and

other factors, including those discussed in "Item 1A. Risk Factors" and "Item 3. Legal Proceedings."

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If one or more of these or other risks or uncertainties materialize, or should underlying assumptions prove incorrect, our actual results may differ materially from those described in any forward-looking statement. When considering forward-looking statements, you should also keep in mind the risk factors described in "Item 1A.Risk Factors" below. The risk factors could also cause our actual results to differ materially from those contained in any forward-looking statement. We disclaim any obligation to update the above list or to announce publicly the result of any revisions to any of the forward-looking statements to reflect future events or developments.

You should consider the information above when reading any forward-looking statements contained in this Annual Report on Form 10-K; other reports filed by us with the U.S. Securities and Exchange Commission ("SEC"); our press releases; our website http://www.ahgp.com; and written or oral statements made by us or any of our officers or other authorized persons acting on our behalf.

iii

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Significant Relationships Referenced in this Annual Report

References to "we", "us", "our" or "AHGP" mean Alliance Holdings GP, L.P., individually as the parent company, and not on a consolidated basis.

· References to "AHGP Partnership" mean the business and operations of Alliance Holdings GP, L.P., the parent company, as well as its consolidated subsidiaries, including MGP II, LLC ("MGP II"), Alliance Resource Management GP, LLC and Alliance Resource Partners, L.P. and its consolidated subsidiaries.

References to "AGP" mean Alliance GP, LLC, the general partner of Alliance Holdings GP, L.P., also referred to as our general partner.

References to "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~~ARLP's ~~managing~~sole general partner ofand, ~~Alliance~~prior ~~Resource~~to ~~Partners~~the Exchange Transaction discussed below, ~~L.P.~~it's managing general partner

· References to "SGP" mean Alliance Resource GP, LLC, ~~the~~ARLP's special general partner ofprior ~~Alliance~~to ~~Resource~~the ~~Partners,~~Exchange ~~L.P.~~Transaction discussed below

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

References to "Alliance Resource Properties" mean Alliance Resource Properties, LLC, the land-holding company for the mining operations of Alliance Resource Operating Partners, L.P.

References to "Alliance Coal" mean Alliance Coal, LLC, the holding company for the mining operations of Alliance Resource Operating Partners, L.P.

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PART I

ITEM 1. BUSINESS

General

We are a Delaware limited partnership listed on the NASDAQ Global Select Market under the ticker symbol "AHGP." We own, directly and indirectly, 100% of the members' interest in MGP, the ~~managing~~sole general partner of ARLP. We completed our initial public offering ("IPO") in May 2006.

Currently, our only cash-generating assets are our ownership interests in ARLP, which consist of the following:

· a 1.980001% managing general partner interest in ~~ARLP~~the Intermediate Partnership, which we hold through our 100% indirect ownership interest in MGP;

· ~~the~~87,188,338 ~~incentive~~common ~~distribution~~units ~~rights~~of ~~("IDRs")~~ARLP, inrepresenting approximately 66.7% of the 130,704,217 common units of ARLP outstanding as of December 31, 2017; and

· ~~31,088,338~~a ~~common~~0.001% ~~units~~managing ofinterest ~~ARLP,~~in ~~representing~~Alliance ~~approximately~~Coal, ~~41.8%~~which ofwe ~~the~~hold ~~common~~through ~~units~~our of100% ~~ARLP~~indirect asownership ofinterest ~~December~~in ~~31, 2016; and~~MGP.

· a 0.001% managing interest in Alliance Coal, which we hold through our 100% ownership interest in MGP.

We are owned 100% by our limited partners. Our general partner, AGP, has a non-economic interest in us and is owned by Joseph W. Craft III, the Chairman, President and Chief Executive Officer of AGP as well as the President and Chief Executive Officer and a Director of MGP.

Exchange Transaction

On July 28, 2017, our wholly owned subsidiary, MGP contributed to ARLP all of its incentive distribution rights ("IDRs") and its 0.99% managing general partner interest in ARLP in exchange for 56,100,000 ARLP common units and a non-economic general partner interest in ARLP. In conjunction with this transaction and on the same economic basis as MGP, SGP also contributed to ARLP its 0.01% general partner interests in both ARLP and the Intermediate Partnership in exchange for 7,181 ARLP common units (collectively the "Exchange Transaction"). SGP is owned by Alliance Resource Holdings, Inc., a Delaware corporation ("ARH"), which is owned by Joseph W. Craft III and

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Kathleen S. Craft. In connection with the Exchange Transaction, ARLP amended its partnership agreement to reflect, among other things, cancellation of the IDRs and the economic general partner interest in ARLP and issuance of a non-economic general partner interest to MGP. MGP is the sole general partner of ARLP following the Exchange Transaction, and no control, management or governance changes otherwise occurred. We now own directly and indirectly 87,188,338 ARLP common units and a non-economic general partner interest in ARLP. We continue to own, through MGP, a 1.0001% general partner interest in the Intermediate Partnership and a 0.001% managing member interest in Alliance Coal.

Simultaneously with the Exchange Transaction discussed above, MGP became a wholly owned subsidiary of MGP II, which is 100% owned directly and indirectly by us and was created in connection with the Exchange Transaction. As of December 31, 2017, MGP II held the 56,100,000 ARLP common units discussed above.

Simplification Transactions

On February 22, 2018, the board of directors of ARLP's general partner and our Board of Directors approved a simplification agreement (the "Simplification Agreement") pursuant to which, through a series of transactions (i) we would become a wholly owned subsidiary of ARLP, (ii) all of our issued and outstanding common units would be canceled and converted into the right to receive all of the ARLP common units held by us and our subsidiaries (collectively, the "Simplification Transactions") and (iii) MGP will remain the sole general partner of ARLP, and no control, management, or governance changes are otherwise expected to occur. The consummation of Simplification Transactions is subject to the SEC declaring the effectiveness of a registration statement on Form S-4 under the Securities Act of 1933 to register the ARLP common units that will be distributed to our former unitholders and the affirmative vote or consent of the holders of a majority of our outstanding common units. Certain of our unitholders that beneficially own a majority of our outstanding common units have entered into a unitholder support agreement pursuant to which such unitholders have agreed to execute a written consent approving the Simplification Agreement within two business days after the registration statement on Form S-4 is declared effective by the SEC.

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The following diagram depicts our organization and ownership as of December 31, ~~2016~~2017:

(1)

The units held by SGP and most of the units held by the Management Group (some of whom are current or former members of management) are subject to a transfer restrictions agreement that, subject to a number of exceptions (including certain transfers by Mr. Craft in which the other parties to the agreement are entitled or required to participate), prohibits the transfer of such units unless approved by a majority of the disinterested members of the board of directors of AGP ("Board of Directors") pursuant to certain procedures set forth in the agreement or as otherwise provided in the agreement. Certain provisions of the transfer restrictions agreement may cause the parties to it to comprise a group under Rule 13d-5(b) of the Securities Exchange Act of 1934, as amended (the "Exchange Act").

Our primary business objective is to increase our cash distributions to our unitholders by actively assisting ARLP in executing its business strategy. ARLP's business strategy is to create sustainable, capital-efficient growth in available cash to maximize its distributions to its unitholders.

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The ARLP Partnership is a diversified producer and marketer of coal primarily to major United States ("U.S.") utilities and industrial users. The ARLP Partnership began mining operations in 1971 and, since then, has grown through acquisitions and internal development to become the second-largest coal producer in the eastern U.S. At December 31, ~~2016~~2017, the ARLP Partnership had approximately 1.7667 billion tons of coal reserves in Illinois, Indiana, Kentucky, Maryland, Pennsylvania and West Virginia. In ~~2016~~2017, the ARLP Partnership sold 3637.78 million tons of coal and produced 3537.26 million tons of coal, of which 1525.24% was low-sulfur coal, 6339.89% was medium-sulfur coal and 2134.07% was high-sulfur coal. In ~~2016~~2017, the ARLP Partnership sold 9080.30% of its total tons to electric utilities, of which 100% was sold to utility plants with installed pollution control devices. These devices, also known as scrubbers, eliminate substantially all emissions of sulfur dioxide. Based on market expectations, the ARLP Partnership classifies low-sulfur coal as coal with a sulfur content of less than 1.5%, medium-sulfur coal as coal with a sulfur content of 1.5% to 3%, and high-sulfur coal as coal with a sulfur content of greater than 3%. The BTU content of the ARLP Partnership's coal ranges from 11,400 to 13,200.

The ARLP Partnership operates eight underground mining complexes in Illinois, Indiana, Kentucky, Maryland and West Virginia. The ARLP Partnership also operates a coal loading terminal on the Ohio River at Mt. Vernon, Indiana. In addition, the ARLP Partnership owns equity interests in various oil and gas mineral interests and gas compression services in various geographic locations within producing basins in the continental U.S. The ARLP Partnership's mining activities are conducted in two geographic regions commonly referred to in the coal industry as the Illinois Basin and Appalachian regions. The ARLP Partnership has grown historically primarily through expansion of its operations by adding and developing mines and coal reserves in these regions.

Our internet address is http://www.ahgp.com, and we make available free of charge on our website our Annual Reports on Form 10-K, our Quarterly Reports on Form 10-Q, our Current Reports on Form 8-K, Forms 3, 4 and 5 for our Section 16 filers and other documents (and amendments and exhibits, such as press releases, to such filings) as soon as reasonably practicable after we electronically file with or furnish such material to the SEC. Information on our website or any other website is not incorporated by reference into this report and does not constitute a part of this report.

The public may read and copy any materials that we file with the SEC at the SEC's Public Reference Room at 100 F Street, N.E., Washington, D.C. 20549. The public may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. Also, the SEC maintains a website that contains reports, proxy and information statements, and other information regarding issuers, including us, that file electronically with the SEC. The public can obtain any documents that we file with the SEC at http://www.sec.gov.

Mining Operations

The ARLP Partnership produces a diverse range of steam and metallurgical coal with varying sulfur and heat contents, which enables it to satisfy the broad range of specifications required by its customers. The following chart summarizes the ARLP Partnership's coal production by region for the last five years.

	Year Ended December 31,
Regions	~~2016~~2017	~~2015~~2016	~~2014~~2015	~~2013~~2014	~~2012~~2013
	(tons in millions)
Illinois Basin	2527.43	3225.04	3032.90	30.79	2830.47
Appalachia	910.83	9.28	9.82	79.48	57.84
Other	—	—	—	~~0.7~~—	0.67
Total	3537.26	4135.2	4041.72	3840.87	3438.8

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The following map shows the location of the ARLP Partnership's coal mining operations:

Illinois Basin Operations:	4. GIBSON COMPLEX	6. SEBREE COMPLEX	9. TUNNEL RIDGE COMPLEX
1. HAMILTON COMPLEX	a. Gibson South Mine	Onton Mine (Idled)	Tunnel Ridge Mine
Hamilton Mine	Mining Type: Underground	Mining Type: Underground	Mining Type: Underground
Mining Type: Underground	Mining Access: Slope & Shaft	Mining Access: Slope & Shaft	Mining Access: Slope & Shaft
Mining Access: Slope & Shaft	Mining Method: Continuous	Mining Method: Continuous	Mining Method: Longwall
Mining Method: Longwall	Miner	Miner	& Continuous Miner
& Continuous Miner	Coal Type: Low/Medium Sulfur	Coal Type: Medium/High Sulfur	Coal Type: Medium/High Sulfur
Coal Type: Medium/High Sulfur	Transportation: Railroad,	Transportation: Barge & Truck	Transportation: Railroad
Transportation: Railroad,	Truck & Barge		& Barge
Truck & Barge		7. HENDERSON/UNION
	b. Gibson North Mine (Idled)	RESERVES	10. METTIKI COMPLEX
	b. Gibson North Mine1	RESERVES	10. METTIKI COMPLEX
2. RIVER VIEW COMPLEX	Mining Type: Underground	Mining Type: Underground	Mountain View Mine
River View Mine	Mining Access: Slope & Shaft	Mining Access: Slope & Shaft	Mining Type: Underground
Mining Type: Underground	Mining Method: Continuous	Mining Method: Continuous Miner	Mining Access: Slope
Mining Access: Slope & Shaft	Miner	Miner	Mining Method: Longwall
Mining Method: Continuous	Coal Type: Low/Medium Sulfur	Coal Type: Medium/High Sulfur	& Continuous Miner
Miner	Transportation: Railroad,	Transportation: Railroad	Coal Type: Medium
Coal Type: Medium/High Sulfur	Truck & Barge	& Barge	Sulfur - Metallurgical
Transportation: Barge			Transportation: Railroad
	5. WARRIOR COMPLEX	Appalachian Operations:	& Truck
3. DOTIKI COMPLEX	Warrior Mine	8. MC MINING COMPLEX
Dotiki Mine	Mining Type: Underground	Excel No. 4 Mine	Other Operations:
Mining Type: Underground	Mining Access: Slope & Shaft	Mining Type: Underground	11. MOUNT VERNON
Mining Access: Slope & Shaft	Mining Method: Continuous	Mining Access: Slope & Shaft	~~TRANSER~~TRANSFER TERMINAL
Mining Method: Continuous	Miner	Mining Method: Continuous	Rail or Truck to Ohio River Barge
Miner	Coal Type: Medium/High Sulfur	Miner	Transloading Facility
Coal Type: High Sulfur	Transportation: Railroad,	Coal Type: Low Sulfur
Transportation: Railroad,	Truck & Barge	Transportation: Railroad,
Truck & Barge		Truck & Barge

1 Gibson North Mine is currently non-producing but is expected to resume production in 2018.

Illinois Basin Operations

The ARLP Partnership's Illinois Basin mining operations are located in western Kentucky, southern Illinois and southern Indiana. As of ~~February 1~~January 25, ~~2017~~2018, the ARLP Partnership had 2,~~067~~086 employees, and operates five mining complexes in the Illinois Basin.

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Hamilton Mining Complex. In July 2015, the ARLP Partnership acquired the remaining equity interest in White Oak Resources LLC ("White Oak"), thereby gaining complete ownership and control of the White Oak Mine No. 1 (now known as the Hamilton mine), located near the city of McLeansboro, Illinois ("White Oak Acquisition"). The ARLP Partnership's subsidiary, Hamilton County Coal, LLC ("Hamilton"), operates the Hamilton mine, which is an underground longwall mining operation producing medium/high-sulfur coal from the Herrin No. 6 seam. Initial development production from the continuous miner units began in 2013, and longwall mining began in October 2014. As part of the initial transaction with White Oak in 2011, Hamilton acquired a preferred equity interest in White Oak and constructed, owned, and operated the coal handling and processing facilities associated with the Hamilton mine, including the preparation plant which has throughput capacity of 2,000 tons of raw coal per hour. Hamilton has the ability to ship production from the Hamilton mine via the CSX Transportation, ~~EVW~~Inc. ("CSX"), Evansville Western Railway and Norfolk Southern Railway Company ("NS") rail directly to customers or to various transloading facilities, including the ARLP Partnership's Mt. Vernon Transfer Terminal, LLC ("Mt. Vernon") transloading facility, for barge deliveries. For more information about the White Oak transactions, please read "Item 8. Financial Statements and Supplementary Data—Note 3. Acquisitions."

River View Complex. The ARLP Partnership's subsidiary, River View Coal, LLC ("River View"), operates the River View mine, which is located in Union County, Kentucky and is currently the largest room-and-pillar underground coal mine in the U.S. The River View mine began production in 2009, and utilizes continuous mining units to produce medium/high-sulfur coal. River View's preparation plant has throughput capacity of 2,700 tons of raw coal per hour. Coal produced from the River View mine is transported by overland belt to a barge loading facility on the Ohio River.

Dotiki Complex. The ARLP Partnership's subsidiary, Webster County Coal, LLC ("Webster County Coal"), operates Dotiki, which is an underground mining complex located near the city of Providence in Webster County, Kentucky. The complex was opened in 1966, and the ARLP Partnership purchased the mine in 1971. The Dotiki complex utilizes continuous mining units employing room-and-pillar mining techniques to produce high-sulfur coal. ~~In connection with the transition of mining operations from the No. 9 and the No. 11 seams, where it has historically operated, to the No. 13 seam,~~ Dotiki's ~~constructed a new~~ preparation plant ~~that became operational in early 2012 and~~ has throughput capacity of 1,800 tons of raw coal per hour. Coal from the Dotiki complex is shipped via the CSX ~~Transportation, Inc. ("CSX")~~ and Paducah & Louisville Railway, Inc. ("PAL") railroads and by truck on U.S. and state highways directly to customers or to various transloading facilities, including the ARLP Partnership's Mt. Vernon ~~Transfer Terminal, LLC ("Mt. Vernon")~~ transloading facility, for barge deliveries.

Gibson Complex. The ARLP Partnership's subsidiary, Gibson County Coal, LLC ("Gibson County Coal"), operates the Gibson South mine, located near the city of Princeton in Gibson County, Indiana. The Gibson South mine is an underground mine and utilizes continuous mining units employing room-and-pillar mining techniques to produce low/medium-sulfur coal. The Gibson South mine's preparation plant has throughput capacity of 1,800 tons of raw coal per hour. Production from the Gibson South mine is shipped by truck on U.S. and state highways or transported by rail on the CSX and ~~Norfolk Southern Railway Company ("~~NS") railroads from the Gibson North rail loadout facility directly to customers or to various transloading facilities, including the Mt. Vernon transloading facility, for barge delivery. Production from the mine began in April 2014.

Gibson County Coal operates the Gibson North mine, an underground mine also located near the city of Princeton in Gibson County, Indiana. The Gibson North mine began production in November 2000 and utilizes continuous mining units employing room-and-pillar mining techniques to produce low/medium-sulfur coal. The Gibson North mine was idled onin ~~December 18,~~the fourth quarter of 2015 in response to market conditions but is expected to resume production in 2018.

Warrior Complex. The ARLP Partnership's subsidiary, Warrior Coal, LLC ("Warrior"), operates an underground mining complex located near the city of Madisonville in Hopkins County, Kentucky. The Warrior complex was opened in 1985, and the ARLP Partnership acquired it in February 2003. Warrior utilizes continuous mining units employing room-and-pillar mining techniques to produce medium/high-sulfur coal. Warrior completed construction of a new preparation plant in 2009, which has throughput capacity of 1,200 tons of raw coal per hour. Warrior's production is shipped via the CSX and PAL railroads and by truck on U.S. and state highways directly to customers or to various transloading facilities, including the Mt. Vernon transloading facility, for barge deliveries. Warrior is currently in the process of transitioning from the No. 11 seam to the No. 9 seam, which is expected to ~~continue~~be ~~for~~completed ~~approximately~~during ~~one~~the ~~year~~second quarter of 2018.

Sebree Complex. On April 2, 2012, the ARLP Partnership acquired substantially all of Green River Collieries, LLC's ("Green River") assets related to its coal mining business and operations located in Webster and Hopkins

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Sebree Complex. On April 2, 2012, the ARLP Partnership acquired substantially all of Green River Collieries, LLC's assets related to its coal mining business and operations located in Webster and Hopkins Counties, Kentucky, including the Onton No. 9 mining complex ("Onton mine"). The Onton mine is operated by the ARLP Partnership's subsidiary, Sebree Mining, LLC ("Sebree"). The Onton mine was idled onin ~~November 6,~~the fourth quarter of 2015.

Alliance Resource Properties. Alliance Resource Properties owns or controls coal reserves that it leases to certain of the ARLP Partnership's subsidiaries that operate its mining complexes.

Alliance WOR Properties, LLC. In September 2011, and in subsequent follow-on transactions, Alliance Resource Properties' subsidiary, Alliance WOR Properties, LLC ("WOR Properties"), acquired from and leased back to White Oak the rights to approximately 309.6 million tons of proven and probable medium/high-sulfur coal reserves. Prior to the White Oak Acquisition, White Oak paid WOR Properties earned royalties during the period beginning January 1, 2015 and ending July 31, 2015 in the amount of $11.4 million. Earned royalties from coal production in 2014 in the amount of $0.2 million were paid to WOR Properties by White Oak. Following the White Oak Acquisition royalty activities under leases between Hamilton and Alliance Resource Properties are accounted for as intercompany transactions and are eliminated upon consolidation.

Other. In December 2014 and February 2015, WKY CoalPlay, LLC ("WKY CoalPlay"), a related party, or its subsidiaries entered into coal lease agreements with us regarding coal reserves located in Henderson and Union Counties, Kentucky ("Henderson/Union Reserves") and Webster County, Kentucky. For more information about the WKY CoalPlay transactions, please read "Item 8. Financial Statements and Supplementary Data – Note 3. Acquisitions and Note 18. Related-Party Transactions."

Pattiki Complex. The ARLP Partnership's subsidiary, White County Coal, LLC ("White County Coal"), operated Pattiki, an underground mining complex located near the city of Carmi in White County, Illinois. The ARLP Partnership began construction of the complex in 1980 and operated it until it ceased production in December 2016.

Hopkins Complex. The Hopkins complex, which the ARLP Partnership acquired in January 1998, is located near the city of Madisonville in Hopkins County, Kentucky. The ARLP Partnership's subsidiary, Hopkins County Coal, LLC ("Hopkins County Coal") operated the Elk Creek underground mine until it ceased production inon ~~early~~April 1, 2016.

Appalachian Operations

The ARLP Partnership's Appalachian mining operations are located in eastern Kentucky, Maryland and West Virginia. As of ~~February~~January 125, ~~2017~~2018, the ARLP Partnership had ~~878~~880 employees, and operates three mining complexes in Appalachia.

MC Mining Complex. The MC Mining Complex is located near the city of Pikeville in Pike County, Kentucky. The ARLP Partnership acquired the mine in 1989. The ARLP Partnership's subsidiary, MC Mining, LLC ("MC Mining"), owns the mining complex and controls the reserves, and its subsidiary, Excel Mining, LLC ("Excel") conducts all mining operations. The underground operation utilizes continuous mining units employing room-and-pillar mining techniques to produce low-sulfur coal. The preparation plant has throughput capacity of 1,000 tons of raw coal per hour. Substantially all of the coal produced at MC Mining in ~~2016~~2017 met or exceeded the compliance requirements of Phase II of the Federal Clean Air Act ("CAA") (see "—Regulation and Laws—Air Emissions" below). Coal produced from the mine is shipped via the CSX railroad directly to customers or to various transloading facilities on the Ohio River for barge deliveries, or by truck via U.S. and state highways directly to customers or to various docks on the Big Sandy River for barge deliveries.

Tunnel Ridge Complex. The ARLP Partnership's subsidiary, Tunnel Ridge, LLC ("Tunnel Ridge"), operates the Tunnel Ridge mine, an underground longwall mine in the Pittsburgh No. 8 coal seam, located near Wheeling, West Virginia. Tunnel Ridge began construction of the mine and related facilities in 2008. Development mining began in 2010, and longwall mining operations began at Tunnel Ridge in May 2012. The Tunnel Ridge preparation plant has throughput capacity of 2,000 tons of raw coal per hour. Coal produced from the Tunnel Ridge mine is a medium/high-sulfur coal and is transported by conveyor belt to a barge loading facility on the Ohio River. Through an agreement with a third party, Tunnel Ridge has the ability to transload coal from barges for rail shipment on the Wheeling and Lake Erie Railway and the NS.

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Mettiki Complex. The Mettiki Complex comprises the Mountain View mine located in Tucker County, West Virginia operated by the ARLP Partnership's subsidiary Mettiki Coal (WV), LLC ("Mettiki (WV)") and a preparation plant located near the city of Oakland in Garrett County, Maryland operated by its subsidiary Mettiki Coal, LLC ("Mettiki (MD)"). In addition, production from the Mountain View mine can be supplemented with production from a temporarily sealed smaller-scale mine in Maryland controlled by another of the ARLP Partnership's subsidiaries, Backbone Mountain, LLC. Mettiki (WV) began continuous miner development of the Mountain View mine in July 2005 and began longwall mining in November 2006. The Mountain View mine produces medium-sulfur coal, which is transported by truck either to the Mettiki (MD) preparation plant for processing (including for shipment into the metallurgical coal market) or directly to the coal blending facility at the Virginia Electric and Power Company Mt. Storm Power Station. The Mettiki (MD) preparation plant has throughput capacity of 1,350 tons of raw coal per hour. Coal processed at the preparation plant can be trucked to the blending facility at Mt. Storm or shipped via the CSX railroad, which provides the opportunity to ship into the domestic and international thermal and metallurgical coal markets.

Other Operations

Mt. Vernon Transfer Terminal, LLC

The ARLP Partnership's subsidiary, Mt. Vernon, leases land and operates a coal loading terminal on the Ohio River at Mt. Vernon, Indiana. Coal is delivered to Mt. Vernon by both rail and truck. The terminal has a capacity of 8.0 million tons per year with existing ground storage of approximately 60,000 to 70,000 tons. During ~~2016~~2017, the terminal loaded approximately 34.60 million tons for customers of Gibson County Coal, ~~Hamilton~~ and ~~White County Coal~~Hamilton.

Coal Brokerage

As markets allow, Alliance Coal buys coal from its mining operations and outside producers principally throughout the eastern U.S., which it then resells. The ARLP Partnership has a policy of matching its outside coal purchases and sales to minimize market risks associated with buying and reselling coal. In ~~2016~~2017, the ARLP Partnership did not make outside coal purchases for brokerage activity.

Matrix Group

The ARLP Partnership's subsidiaries, Matrix Design Group, LLC ("Matrix Design") and its subsidiaries Matrix Design International, LLC and Matrix Design Africa (PTY) LTD, and Alliance Design Group, LLC ("Alliance Design") (collectively the Matrix Design entities and Alliance Design are referred to as the "Matrix Group"), provide a variety of mining technology products and services for the ARLP Partnership's mining operations and certain industrial and mining technology products and services to third parties. Matrix Group's products and services include miner and equipment tracking systems and proximity detection systems. The ARLP Partnership acquired this business in September 2006.

Alliance Minerals

On November 10, 2014 ~~(the "Cavalier Formation Date")~~, the ARLP Partnership's subsidiary, Alliance Minerals, LLC ("Alliance Minerals") purchased a 96% ownership interest in Cavalier Minerals JV, LLC ("Cavalier Minerals"). Cavalier Minerals acquired a 71.7% limited partner interest in AllDale Minerals, LP ("AllDale I") and subsequently acquired a 72.8% limited partner interest in AllDale Minerals II, LP ("AllDale II", collectively with AllDale I, "AllDale Minerals"),. The AllDale Minerals entities were created to purchase oil and gas mineral interests in various geographic locations within producing basins in the continental U.S. ~~Between~~As ~~the~~of ~~Cavalier Formation Date and~~ December 31, ~~2016~~2017, Cavalier Minerals has contributed a total of $~~142~~149.70 million to AllDale Minerals, of which $~~137~~143.1 million was funded by Alliance Minerals. In February 2017, Alliance Minerals committed to directly (rather than through Cavalier Minerals) invest $30.0 million in AllDale Minerals III, LP ("AllDale III") in similar geographical locations discussed above and in 2017 invested $14.4 million in AllDale III. AllDale III, together with AllDale Minerals are considered the "AllDale Partnerships." On July 19, 2017, Alliance Minerals purchased $100 million of Series A-1 Preferred Interests from Kodiak Gas Services, LLC ("Kodiak"), a privately-held company providing large-scale, high-utilization gas compression assets to customers operating primarily in the Permian Basin. For more information about Cavalier Minerals, please read "Item 8. Financial Statements and Supplementary Data—Note 10. Variable Interest Entities." For more information about the AllDale ~~Minerals~~Partnerships and ~~AllDale III~~Kodiak, please read "Item 8. Financial Statements and Supplementary Data—Note 12. ~~Equity~~ Investments."

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Additional Services

The ARLP Partnership develops and markets additional services in order to establish itself as the supplier of choice for its customers. Historically, and in ~~2016~~2017, outside revenues from these services were immaterial.

Reportable Segments

Please read "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations," and Segment Information under "Item 8. Financial Statements and Supplementary Data—Note 21. Segment Information" for information concerning our reportable segments.

Coal Marketing and Sales

As is customary in the coal industry, the ARLP Partnership has entered into long-term coal supply agreements with many of its customers. These arrangements are mutually beneficial to the ARLP Partnership and its customers in that they provide greater predictability of sales volumes and sales prices. Although many utility customers recently have appeared to favor a shorter term contracting strategy, in ~~2016~~2017 approximately 8771.7% and 9174.57% of the ARLP Partnership's sales tonnage and total coal sales, respectively, were sold under long-term contracts (contracts having a term of one year or greater) with committed term expirations ranging from ~~2017~~2018 to ~~2021~~2022. As of February 14 15, ~~2017~~2018, the ARLP Partnership's nominal commitment under long-term contracts was approximately 34.07 million tons in ~~2017~~2018, 1813.96 million tons in ~~2018~~2019, 98.05 million tons in ~~2019~~2020 and 41.3 million tons in ~~2020~~2021. The commitment of coal under contract is an approximate number because a limited number of the contracts contain provisions that could cause the nominal commitment to increase or decrease; however, the overall variance to total committed sales is minimal. The contractual time commitments for customers to nominate future purchase volumes under these contracts are typically sufficient to allow the ARLP Partnership to balance its sales commitments with prospective production capacity. In addition, the nominal commitment can otherwise change because of reopener provisions contained in certain of these long-term contracts.

The provisions of long-term contracts are the results of both bidding procedures and extensive negotiations with each customer. As a result, the provisions of these contracts vary significantly in many respects, including, among other factors, price adjustment features, price and contract reopener terms, permitted sources of supply, force majeure provisions, and coal qualities and quantities. Virtually all of the ARLP Partnership's long-term contracts are subject to price adjustment provisions, which periodically permit an increase or decrease in the contract price, typically to reflect changes in specified indices or changes in production costs resulting from regulatory changes, or both. These provisions, however, may not assure that the contract price will reflect every change in production or other costs. Failure of the parties to agree on a price pursuant to an adjustment or a reopener provision can, in some instances, lead to early termination of a contract. Some of the long-term contracts also permit the contract to be reopened for renegotiation of terms and conditions other than pricing terms, and where a mutually acceptable agreement on terms and conditions cannot be concluded, either party may have the option to terminate the contract. The long-term contracts typically stipulate procedures for transportation of coal, quality control, sampling and weighing. Most contain provisions requiring the ARLP Partnership to deliver coal within stated ranges for specific coal characteristics such as heat, sulfur, ash, moisture, grindability, volatility and other qualities. Failure to meet these specifications can result in economic penalties, rejection or suspension of shipments or termination of the contracts. While most of the contracts specify the approved seams and/or approved locations from which the coal is to be mined, some contracts allow the coal to be sourced from more than one mine or location. Although the volume to be delivered pursuant to a long-term contract is stipulated, the buyers often have the option to vary the volume within specified limits.

Reliance on Major Customers

The ARLP Partnership's ~~three~~did ~~largest~~not ~~customers~~derive in 2016 were Duke Energy, Louisville Gas and Electric Company and Tennessee Valley Authority. During 2016, the ARLP Partnership derived approximately 39.4% of its total revenues from these three customers and at least 10.0% or more of its total revenues from ~~each~~any ofindividual ~~the~~customer ~~three. For~~during ~~more information about these customers, please read "Item 8~~2017. ~~Financial Statements and Supplementary Data—Note 20. Concentration of Credit Risk and Major Customers."~~

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Competition

The coal industry is intensely competitive. The most important factors on which the ARLP Partnership competes are coal price, coal quality (including sulfur and heat content), transportation costs from the mine to the customer and the reliability of supply. The ARLP Partnership's principal competitors include Arch Coal, Inc., ~~CNX~~CONSOL Coal Resources LP, CONSOL Energy, Inc. ~~("CONSOL")~~, Contura Energy, Inc., Foresight Energy LP, Murray Energy, Inc., and Peabody Energy Corporation. While a number of the ARLP Partnership's competitors ~~are experiencing significant financial distress as a result of deteriorating market conditions, and some are or recently~~ have been involved in reorganization in bankruptcy, ~~the ARLP Partnership believes~~ these events ~~will~~have not ~~result~~resulted in a material diminution in available coal supply and ~~that~~there ~~they~~remains ~~or their reorganized successors will remain~~ significant competition for ongoing coal sales. The ARLP Partnership also competes directly with a number of smaller producers in the Illinois Basin and Appalachian regions. The prices the ARLP Partnership is able to obtain for its coal are primarily linked to coal consumption patterns of domestic electricity generating utilities, which in turn are influenced by economic activity, government regulations, weather and technological developments. At times, the ARLP Partnership has exported a portion of its coal into the international coal markets and historically the prices the ARLP Partnership obtained for its export coal have been influenced by a number of factors, such as global economic conditions, weather patterns and political instability, among others. Further, coal competes with other fuels such as natural gas, nuclear energy, petroleum and renewable energy sources for electrical power generation. Over time, costs and other factors, such as safety and environmental considerations, may affect the overall demand for coal as a fuel. For additional information, please see "Item 1A. Risk Factors." At times, the ARLP Partnership may also compete with companies that produce coal from one or more foreign countries.

Transportation

The ARLP Partnership's coal is transported to its customers by rail, barge and truck. Depending on the proximity of the customer to the mine and the transportation available for delivering coal to that customer, transportation costs can be a substantial part of the total delivered cost of a customer's coal. As a consequence, the availability and cost of transportation constitute important factors in the marketability of coal. The ARLP Partnership believes its mines are located in favorable geographic locations that minimize transportation costs for its customers, and in many cases it is able to accommodate multiple transportation options. The ARLP Partnership's customers typically pay the transportation costs from the mining complex to the destination, which is the standard practice in the industry. Approximately 3842.24% of the ARLP Partnership's ~~2016~~2017 sales volume was initially shipped from the mines by ~~rail~~barge, 4236.56% was shipped from the mines by ~~barge~~rail and 1921.30% was shipped from the mines by truck. In ~~2016~~2017, the largest volume transporter of the ARLP Partnership's coal shipments was the CSX railroad, which moved approximately 2325.47% of the ARLP Partnership's tonnage over its rail system. The practices of, rates set by and capacity availability of, the transportation company serving a particular mine or customer may affect, either adversely or favorably, the ARLP Partnership's marketing efforts with respect to coal produced from the relevant mine.

Regulation and Laws

The coal mining industry is subject to extensive regulation by federal, state and local authorities on matters such as:

employee health and safety;

mine permits and other licensing requirements;

air quality standards;

water quality standards;

storage of petroleum products and substances that are regarded as hazardous under applicable laws or that, if spilled, could reach waterways or wetlands;

plant and wildlife protection;

reclamation and restoration of mining properties after mining is completed;

discharge of materials;

storage and handling of explosives;

wetlands protection;

surface subsidence from underground mining; and

the effects, if any, that mining has on groundwater quality and availability.

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· the effects, if any, that mining has on groundwater quality and availability.

In addition, the utility industry is subject to extensive regulation regarding the environmental impact of its power generation activities, which has adversely affected demand for coal. It is possible that new legislation or regulations may be adopted, or that existing laws or regulations may be differently interpreted or more stringently enforced, any of which could have a significant impact on the ARLP Partnership's mining operations or its customers' ability to use coal. For more information, please see risk factors described in "Item 1A. Risk Factors" below.

The ARLP Partnership is committed to conducting mining operations in compliance with applicable federal, state and local laws and regulations. However, because of the extensive and detailed nature of these regulatory requirements, particularly the regulatory system of the Mine Safety and Health Administration ("MSHA") where citations can be issued without regard to fault and many of the standards include subjective elements, it is not reasonable to expect any coal mining company to be free of citations. When the ARLP Partnership receives a citation, it attempts to remediate any identified condition immediately. While the ARLP Partnership has not quantified all of the costs of compliance with applicable federal and state laws and associated regulations, those costs have been and are expected to continue to be significant. Compliance with these laws and regulations has substantially increased the cost of coal mining for domestic coal producers.

Capital expenditures for environmental matters have not been material in recent years. The ARLP Partnership has accrued for the present value of the estimated cost of asset retirement obligations and mine closings, including the cost of treating mine water discharge, when necessary. The accruals for asset retirement obligations and mine closing costs are based upon permit requirements and the costs and timing of asset retirement obligations and mine closing procedures. Although management believes it has made adequate provisions for all expected reclamation and other costs associated with mine closures, future operating results would be adversely affected if these accruals were insufficient.

Mining Permits and Approvals

Numerous governmental permits or approvals are required for mining operations. Applications for permits require extensive engineering and data analysis and presentation, and must address a variety of environmental, health, and safety matters associated with a proposed mining operation. These matters include the manner and sequencing of coal extraction, the storage, use and disposal of waste and other substances and impacts on the environment, the construction of water containment areas, and reclamation of the area after coal extraction. Meeting all requirements imposed by any of these authorities may be costly and time consuming, and may delay or prevent commencement or continuation of mining operations.

The permitting process for certain mining operations can extend over several years and can be subject to administrative and judicial challenge, including by the public. Some required mining permits are becoming increasingly difficult to obtain in a timely manner, or at all. We cannot assure you that the ARLP Partnership will not experience difficulty or delays in obtaining mining permits in the future or that a current permit will not be revoked.

The ARLP Partnership is required to post bonds to secure performance under its permits. Under some circumstances, substantial fines and penalties, including revocation of mining permits, may be imposed under the laws and regulations described above. Monetary sanctions and, in severe circumstances, criminal sanctions may be imposed for failure to comply with these laws and regulations. Regulations also provide that a mining permit can be refused or revoked if the permit applicant or permittee owns or controls, directly or indirectly through other entities, mining operations that have outstanding environmental violations. Although, like other coal companies, the ARLP Partnership has been cited for violations in the ordinary course of its business, it has never had a permit suspended or revoked because of any violation, and the penalties assessed for these violations have not been material.

Mine Health and Safety Laws

Stringent safety and health standards have been imposed by federal legislation since the Federal Coal Mine Health and Safety Act of 1969 ("CMHSA") was adopted. The Federal Mine Safety and Health Act of 1977 ("FMSHA"), and regulations adopted pursuant thereto, significantly expanded the enforcement of health and safety standards of the CMHSA, and imposed extensive and detailed safety and health standards on numerous aspects of mining operations, including training of mine personnel, mining procedures, blasting, the equipment used in mining operations, and numerous other matters. MSHA monitors and rigorously enforces compliance with these federal laws and regulations.

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including training of mine personnel, mining procedures, blasting, the equipment used in mining operations, and numerous other matters. MSHA monitors and rigorously enforces compliance with these federal laws and regulations. In addition, most of the states where the ARLP Partnership operates have state programs for mine safety and health regulation and enforcement. Federal and state safety and health regulations affecting the coal mining industry are perhaps the most comprehensive and rigorous system in the U.S. for protection of employee safety and have a significant effect on the ARLP Partnership's operating costs. Although many of the requirements primarily impact underground mining, the ARLP Partnership's competitors in all of the areas in which it operates are subject to the same laws and regulations.

The FMSHA has been construed as authorizing MSHA to issue citations and orders pursuant to the legal doctrine of strict liability, or liability without fault, and FMSHA requires imposition of a civil penalty for each cited violation. Negligence and gravity assessments, and other factors can result in the issuance of various types of orders, including orders requiring withdrawal from the mine or the affected area, and some orders can also result in the imposition of civil penalties. The FMSHA also contains criminal liability provisions. For example, criminal liability may be imposed upon corporate operators who knowingly and willfully authorize, order or carry out violations of the FMSHA, or its mandatory health and safety standards.

The Federal Mine Improvement and New Emergency Response Act of 2006 ("MINER Act") significantly amended the FMSHA, imposing more extensive and stringent compliance standards, increasing criminal penalties and establishing a maximum civil penalty for non-compliance, and expanding the scope of federal oversight, inspection, and enforcement activities. Following the passage of the MINER Act, MSHA has issued new or more stringent rules and policies on a variety of topics, including:

sealing off abandoned areas of underground coal mines;

mine safety equipment, training and emergency reporting requirements;

substantially increased civil penalties for regulatory violations;

training and availability of mine rescue teams;

underground "refuge alternatives" capable of sustaining trapped miners in the event of an emergency;

flame-resistant conveyor belts, fire prevention and detection, and use of air from the belt entry; and

post-accident two-way communications and electronic tracking systems.

MSHA continues to interpret and implement various provisions of the MINER Act, along with introducing new proposed regulations and standards.

In 2014, MSHA began implementation of a finalized new regulation titled "Lowering Miner's Exposure to Respirable Coal Mine Dust, Including Continuous Personal Dust Monitors." The final rule implements a reduction in the allowable respirable coal mine dust exposure limits, requires the use of sampling data taken from a single sample rather than an average of samples, and increases oversight by MSHA regarding coal mine dust and ventilation issues at each mine, including the approval process for ventilation plans at each mine, all of which increase mining costs. The second phase of the rule began in February 2016 and requires additional sampling for designated and other occupations using the new continuous personal dust monitor technology, which provides real time dust exposure information to the miner. Phase three of the rule began in August 2016, and resulted in lowering the current respirable dust level of 2.0 milligrams per cubic meter to 1.5 milligrams per cubic meter of air. Compliance with these rules can result in increased costs on ~~our~~the ARLP Partnership's operations, including, but not limited to, the purchasing of new equipment and the hiring of additional personnel to assist with monitoring, reporting, and recordkeeping obligations.

Additionally, in July 2014, MSHA proposed a rule addressing the "criteria and procedures for assessment of civil penalties." Public commenters have expressed concern that the proposed rule exceeds MSHA's rulemaking authority and would result in substantially increased civil penalties for regulatory violations cited by MSHA. MSHA last revised the process for proposing civil penalties in 2006 and, as discussed above, civil penalties increased significantly. The notice-and-comment period for this proposed rule closed, and it is uncertain when MSHA will present a final rule addressing these civil penalties.

In January 2015, MSHA published a final rule requiring mine operators to install proximity detection systems on continuous mining machines, over a staggered time frame ranging from November 2015 through March 2018. The proximity detection systems initiate a warning or shutdown the continuous mining machine depending on the proximity of the machine to a miner. MSHA subsequently proposed a rule requiring mine operators to also install

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proximity detection systems ~~initiate~~on aother ~~warning~~types orof ~~shutdown~~underground ~~the~~mobile ~~continuous~~ mining ~~machine~~equipment. The ~~depending~~comment period for this proposed rule closed on ~~the~~April ~~proximity~~10, of2017, ~~the~~and ~~machine~~it tois auncertain ~~miner.~~ when MSHA ~~subsequently~~will ~~proposed~~promulgate a final rule ~~requiring~~addressing ~~mine~~the ~~operators~~issue toof ~~also install~~ proximity detection systems on ~~other types of~~ underground mobile mining equipment~~. The~~, ~~comment~~other ~~period~~than ~~for~~continuous ~~this~~mining ~~proposed rule will close on April 10, 2017~~machines.

In June 2016, MSHA published a request for information on Exposure of Underground Miners to Diesel Exhaust. Following a comment period that closed in November 2016, MSHA received requests for MSHA and the National Institute for Occupational Safety and Health to hold a Diesel Exhaust Partnership to address the issues covered by MSHA's request for information. The comment period for the request for information was reopened and closed in January 2018. It is uncertain whether MSHA will present a proposed rule pertaining to exposure of underground miners to diesel exhaust, after completing its evaluation of the comments received.

Subsequent to passage of the MINER Act, Illinois, Kentucky, Pennsylvania and West Virginia have enacted legislation addressing issues such as mine safety and accident reporting, increased civil and criminal penalties, and increased inspections and oversight. Additionally, state administrative agencies can promulgate administrative rules and regulations affecting the ARLP Partnership's operations. Other states may pass similar legislation or administrative regulations in the future.

Some of the costs of complying with existing regulations and implementing new safety and health regulations may be passed on to the ARLP Partnership's customers. Although the ARLP Partnership has not quantified the full impact, implementing and complying with these new state and federal safety laws and regulations have had, and are expected to continue to have, an adverse impact on its results of operations and financial position.

Black Lung Benefits Act

The Black Lung Benefits Act of 1977 and the Black Lung Benefits Reform Act of 1977, as amended in 1981 ("BLBA") requires businesses that conduct current mining operations to make payments of black lung benefits to current and former coal miners with black lung disease and to some survivors of a miner who dies from this disease. The BLBA levies a tax on production of $1.10 per ton for underground-mined coal and $0.55 per ton for surface-mined coal, but not to exceed 4.4% of the applicable sales price, in order to compensate miners who are totally disabled due to black lung disease and some survivors of miners who died from this disease, and who were last employed as miners prior to 1970 or subsequently where no responsible coal mine operator has been identified for claims. In addition, the BLBA provides that some claims for which coal operators had previously been responsible are or will become obligations of the government trust funded by the tax. The Revenue Act of 1987 extended the termination date of this tax from January 1, 1996, to the earlier of January 1, 2014, or the date on which the government trust becomes solvent. For miners last employed as miners after 1969 and who are determined to have contracted black lung, the ARLP Partnership self-insures the potential cost of compensating such miners using its actuary estimates of the cost of present and future claims. The ARLP Partnership is also liable under state statutes for black lung claims. Congress and state legislatures regularly consider various items of black lung legislation, which, if enacted, could adversely affect the ARLP Partnership's business, results of operations and financial position.

The revised BLBA regulations took effect in January 2001, relaxing the stringent award criteria established under previous regulations and thus potentially allowing new federal claims to be awarded and allowing previously denied claimants to re-file under the revised criteria. These regulations may also increase black lung related medical costs by broadening the scope of conditions for which medical costs are reimbursable and increase legal costs by shifting more of the burden of proof to the employer.

The Patient Protection and Affordable Care Act enacted in 2010, includes significant changes to the federal black lung program, retroactive to 2005, including an automatic survivor benefit paid upon the death of a miner with an awarded black lung claim and establishes a rebuttable presumption with regard to pneumoconiosis among miners with 15 or more years of coal mine employment that are totally disabled by a respiratory condition. These changes could have a material impact on the ARLP Partnership's costs expended in association with the federal black lung program.

Workers' Compensation

The ARLP Partnership provides income replacement and medical treatment for work-related traumatic injury claims as required by applicable state laws. Workers' compensation laws also compensate survivors of workers who suffer employment related deaths. Several states in which the ARLP Partnership operates consider changes in workers' compensation laws from time to time. The ARLP Partnership generally self-insures this potential expense using its actuary estimates of the cost of present and future claims. For more information concerning the ARLP Partnership's requirement to maintain bonds to secure its workers' compensation obligations, see the discussion of surety bonds below under "—Bonding Requirements."

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Workers' Compensation

Coal Industry Retiree Health Benefits Act

The Federal Coal Industry Retiree Health Benefits Act ("CIRHBA") was enacted to fund health benefits for some United Mine Workers of America retirees. CIRHBA merged previously established union benefit plans into a single fund into which "signatory operators" and "related persons" are obligated to pay annual premiums for beneficiaries. CIRHBA also created a second benefit fund for miners who retired between July 21, 1992 and September 30, 1994, and whose former employers are no longer in business. Because of the ARLP Partnership's union-free status, it is not required to make payments to retired miners under CIRHBA, with the exception of limited payments made on behalf of predecessors of MC Mining. However, in connection with the sale of the coal assets acquired by ARH in 1996, MAPCO Inc., now a wholly owned subsidiary of The Williams Companies, Inc., agreed to retain, and be responsible for, all liabilities under CIRHBA.

Surface Mining Control and Reclamation Act

The Federal Surface Mining Control and Reclamation Act of 1977 ("SMCRA") and similar state statutes establish operational, reclamation and closure standards for all aspects of surface mining as well as many aspects of deep mining. Although the ARLP Partnership has minimal surface mining activity and no mountaintop removal mining activity, SMCRA nevertheless requires that comprehensive environmental protection and reclamation standards be met during the course of and upon completion of its mining activities.

SMCRA and similar state statutes require, among other things, that mined property be restored in accordance with specified standards and approved reclamation plans. SMCRA requires the ARLP Partnership to restore the surface to approximate the original contours as contemporaneously as practicable with the completion of surface mining operations. Federal law and some states impose on mine operators the responsibility for replacing certain water supplies damaged by mining operations and repairing or compensating for damage to certain structures occurring on the surface as a result of mine subsidence, a consequence of longwall mining and possibly other mining operations. The ARLP Partnership believes it is in compliance in all material respects with applicable regulations relating to reclamation.

In addition, the Abandoned Mine Lands Program, which is part of SMCRA, imposes a tax on all current mining operations, the proceeds of which are used to restore mines closed before 1977. The tax for surface-mined and underground-mined coal is $0.28 per ton and $0.12 per ton, respectively. The ARLP Partnership has accrued the estimated costs of reclamation and mine closing, including the cost of treating mine water discharge when necessary. Please read "Item 8. Financial Statements and Supplementary Data—Note 16. Asset Retirement Obligations." In addition, states from time to time have increased and may continue to increase their fees and taxes to fund reclamation or orphaned mine sites and acid mine drainage control on a statewide basis.

Under SMCRA, responsibility for unabated violations, unpaid civil penalties and unpaid reclamation fees of independent contract mine operators and other third parties can be imputed to other companies that are deemed, according to the regulations, to have "owned" or "controlled" the third-party violator. Sanctions against the "owner" or "controller" are quite severe and can include being blocked from receiving new permits and having any permits revoked that were issued after the time of the violations or after the time civil penalties or reclamation fees became due. The ARLP partnership is not aware of any currently pending or asserted claims against it relating to the "ownership" or "control" theories discussed above. However, the ARLP Partnership cannot assure you that such claims will not be asserted in the future.

The U.S. Office of Surface Mining Reclamation ("OSM") published in November 2009, an Advance Notice of Proposed Rulemaking, announcing its intent to revise the Stream Buffer Zone ("SBZ") rule published in December 2008. The SBZ rule prohibits mining disturbances within 100 feet of streams if there would be a negative effect on water quality. Environmental groups brought lawsuits challenging the rule, and in a March 2010 settlement, the OSM agreed to rewrite the SBZ rule. In January 2013, the environmental groups reopened the litigation against OSM for failure to abide by the terms of the settlement. Oral arguments were heard on January 31, 2014. OSM published a notice in December 2014 to vacate the 2008 SBZ rule to comply with an order issued by the U.S. District Court for the District of Columbia. OSM reimplemented the 1983 SBZ rule.

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OSM issued its final Stream Protection Rule ("SPR") in December 2016 to replace the vacated SBZ rule. The rule would have generally prohibited the approval of permits issued pursuant to SMCRA where the proposed operations would result in "material damage to the hydrologic balance outside the permit area." Pursuant to the rule, permittees would have also been required to restore any perennial or intermittent streams that a permittee mined through. Finally, the rule would have also imposed additional baseline data collection, surface/groundwater monitoring, and bonding and financial assurance requirements. However, in February 2017, both the U.S. House of Representatives and the Senate passed resolutions disapproving the SPR under the Congressional Review Act ("CRA"). President Trump signed the resolution on February 16, 2017 and, pursuant to the CRA, the SPR "shall have no force or effect" and OSM cannot promulgate a substantially similar rule absent future legislation. Whether Congress will enact future legislation to require a new SPR rule remains uncertain.

Following the spill of coal combustion residues ("CCRs") in the Tennessee Valley Authority impoundment in Kingston, Tennessee, in December 2009, the U.S. Environmental Protection Agency ("EPA") issued proposed rules on CCRs in 2010. This final rule was published in December 2014. The EPA's final rule does not address the placement of CCRs in minefills or non-minefill uses of CCRs at coal mine sites. OSM has announced their intention to release a proposed rule to regulate placement and use of CCRs at coal mine sites, but, to date, no further action has been taken. These actions by OSM, potentially could result in additional delays and costs associated with obtaining permits, prohibitions or restrictions relating to mining activities, and additional enforcement actions.

Bonding Requirements

Federal and state laws require bonds to secure the ARLP Partnership's obligations to reclaim lands used for mining, to pay federal and state workers' compensation, to pay certain black lung claims, and to satisfy other miscellaneous obligations. These bonds are typically renewable on a yearly basis. It has become increasingly difficult for the ARLP Partnership and for its competitors to secure new surety bonds without posting collateral. In addition, surety bond costs have increased while the market terms of surety bonds have generally become less favorable to the ARLP Partnership. It is possible that surety bond issuers may refuse to renew bonds or may demand additional collateral upon those renewals. The ARLP Partnership's failure to maintain, or inability to acquire, surety bonds that are required by state and federal laws would have a material adverse effect on its ability to produce coal, which could affect its profitability and cash flow. For additional information, please see "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Off-Balance Sheet Arrangements."

Air Emissions

The CAA and similar state and local laws and regulations regulate emissions into the air and affect coal mining operations. The CAA directly impacts the ARLP Partnership's coal mining and processing operations by imposing permitting requirements and, in some cases, requirements to install certain emissions control equipment, achieve certain emissions standards, or implement certain work practices on sources that emit various air pollutants. The CAA also indirectly affects coal mining operations by extensively regulating the air emissions of coal-fired electric power generating plants and other coal-burning facilities. There have been a series of federal rulemakings focused on emissions from coal-fired electric generating facilities. Installation of additional emissions control technology and any additional measures required under applicable state and federal laws and regulations related to air emissions will make it more costly to operate coal-fired power plants and possibly other facilities that consume coal and, depending on the requirements of individual state implementation plans ("SIPs"), could make coal a less attractive fuel alternative in the planning and building of power plants in the future. A significant reduction in coal's share of power generating capacity could have a material adverse effect on our business, financial condition and results of operations. Since ~~2010, utilities have completed or formally announced the retirement or conversion of over 500 coal-fired electric generating units through 2030.~~

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2010, utilities have completed or formally announced the retirement or conversion of over 600 coal-fired electric generating units through 2030.

In addition to the greenhouse gas ("GHG") issues discussed below, the air emissions programs that may affect the ARLP Partnership's operations, directly or indirectly, include, but are not limited to, the following:

· The EPA's Acid Rain Program, provided in Title IV of the CAA, regulates emissions of sulfur dioxide from electric generating facilities. Sulfur dioxide is a by-product of coal combustion. Affected facilities purchase or are otherwise allocated sulfur dioxide emissions allowances, which must be surrendered annually in an amount equal to a facility's sulfur dioxide emissions in that year. Affected facilities may sell or trade excess allowances to other facilities that require additional allowances to offset their sulfur dioxide emissions. In addition to purchasing or trading for additional sulfur dioxide allowances, affected power facilities can satisfy the requirements of the EPA's Acid Rain Program by switching to lower sulfur fuels, installing pollution control devices such as flue gas desulfurization systems, or "scrubbers," or by reducing electricity generating levels. In ~~2016~~2017, the ARLP Partnership sold 9080.30% of its total tons to electric utilities, of which 100% was sold to utility plants with installed pollution control devices. These requirements would not be supplanted by a replacement rule for the Clean Air Interstate Rule ("CAIR"), discussed below.

· The CAIR calls for power plants in 28 states and Washington, D.C. to reduce emission levels of sulfur dioxide and nitrogen oxide pursuant to a cap-and-trade program similar to the system in effect for acid rain. In June 2011, the EPA finalized the Cross-State Air Pollution Rule ("CSAPR"), a replacement rule for CAIR, which would have required 28 states in the Midwest and eastern seaboard to reduce power plant emissions that cross state lines and contribute to ozone and/or fine particle pollution in other states. Under CSAPR, the first phase of the nitrogen oxide and sulfur dioxide emissions reductions would have commenced in 2012 with further reductions effective in 2014. However, in August 2012, the D.C. Circuit Court of Appeals vacated CSAPR, finding the EPA exceeded its statutory authority under the CAA and striking down the EPA's decision to require federal implementation plans ("FIPs"), rather than SIPs, to implement mandated reductions. In its ruling, the D.C. Circuit Court of Appeals ordered the EPA to continue administering CAIR but proceed expeditiously to promulgate a replacement rule for CAIR. The U.S. Supreme Court granted the EPA's certiorari petition appealing the D.C. Circuit Court of Appeals' decision and heard oral arguments in December 2013. In April 2014, the U.S. Supreme Court reversed and remanded the D.C. Circuit Court of Appeals' decision, concluding that the EPA's approach is lawful. CSAPR has been reinstated and the EPA began implementation of Phase 1 requirements in January 2015. In September 2016, EPA finalized the CSAPR Update to respond to the remand by the D.C. Circuit Court of Appeals. Implementation of Phase 2 ~~will~~began ~~begin~~ in 2017. Further litigation is expected against the CSAPR Update in the D.C. Circuit Court of Appeals. The impacts of CSAPR Update are unknown at the present time due to the implementation of Mercury and Air Toxic Standards ("MATS"), discussed below, and the significant number of coal retirements that have resulted and that potentially will result from MATS.

· In February 2012, the EPA adopted the MATS, which regulates the emission of mercury and other metals, fine particulates, and acid gases such as hydrogen chloride from coal and oil-fired power plants. In March 2013, the EPA finalized a reconsideration of the MATS rule as it pertains to new power plants, principally adjusting emissions limits to levels attainable by existing control technologies. Appeals were filed and oral arguments were heard by the D.C. Circuit Court of Appeals in December 2013. In April 2014, the D.C. Circuit Court of Appeals upheld MATS. In June 2015, the U.S. Supreme Court remanded the final rule back to the D.C. Circuit holding that the agency must consider cost before deciding whether regulation is necessary and appropriate. In December 2015, the EPA issued, for comment, the proposed Supplemental Finding. In April 2016, the EPA issued a final supplemental finding upholding the rule and concluding that a cost analysis supports the MATS rule. In April 2017, the D.C Circuit Court of Appeals granted EPA's request to cancel oral arguments and ordered the case held in abeyance for an EPA review of the supplemental finding. Many electric generators have already announced retirements due to the MATS rule. Although various issues surrounding the MATS rule remain subject to litigation in the D.C. Circuit, the MATS will force generators to make capital investments to retrofit power plants and could lead to additional premature retirements of older coal-fired generating units. The announced and possible additional retirements are likely to reduce the demand for coal. Apart from MATS, several states have enacted or proposed regulations requiring reductions in mercury emissions from coal-fired power plants, and federal legislation to reduce mercury emissions from power plants has been proposed. Regulation of mercury emissions by the EPA, states, or Congress may decrease the future demand for coal. We continue to evaluate the possible scenarios associated with CSAPR Update and MATS and the effects they may have on the ARLP Partnership's business and our results of operations, financial condition or cash flows.

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mercury emissions from power plants has been proposed. Regulation of mercury emissions by the EPA, states, or Congress may decrease the future demand for coal. We continue to evaluate the possible scenarios associated with CSAPR Update and MATS and the effects they may have on the ARLP Partnership's business and our results of operations, financial condition or cash flows.

In January 2013, the EPA issued final Maximum Achievable Control Technology ("MACT") standards for several classes of boilers and process heaters, including large coal-fired boilers and process heaters ("Boiler MACT"), which require owners of industrial, commercial, and institutional boilers to comply with standards for air pollutants, including mercury and other metals, fine particulates, and acid gases such as hydrogen chloride. Businesses and environmental groups have filed legal challenges to Boiler MACT in the D.C. Circuit Court of Appeals and petitioned the EPA to reconsider the rule. In December 2014, the EPA announced reconsideration of the standard and will accept public comment on five issues for its standards on area sources, will review three issues related to its major-source boiler standards, and four issues relating to commercial and solid waste incinerator units. Before reconsideration, the EPA estimated the rule will affect 1,700 existing major source facilities with an estimated 14,316 boilers and process heaters. While some owners would make capital expenditures to retrofit boilers and process heaters, a number of boilers and process heaters could be prematurely retired. Retirements are likely to reduce the demand for coal. In August 2016, the D.C. Circuit Court of Appeals vacated a portion of the rule while remanding portions back to the EPA. In December 2016, the D.C. Circuit Court of Appeals agreed to the EPA request to remand the rule back to the EPA without vacatur. The impact of the regulations will depend on the EPA's reconsideration and the outcome of subsequent legal challenges.

· The EPA is required by the CAA to periodically re-evaluate the available health effects information to determine whether the national ambient air quality standards ("NAAQS") should be revised. Pursuant to this process, the EPA has adopted more stringent NAAQS for fine particulate matter ("PM"), ozone, nitrogen oxide and sulfur dioxide. As a result, some states will be required to amend their existing SIPs to attain and maintain compliance with the new air quality standards and other states will be required to develop new SIPs for areas that were previously in "attainment" but do not attain the new standards. In addition, under the revised ozone NAAQS, significant additional emissions control expenditures may be required at coal-fired power plants. Initial non-attainment determinations related to the revised sulfur dioxide standard became effective in October 2013. In addition, in January 2013, the EPA updated the NAAQS for fine particulate matter emitted by a wide variety of sources including power plants, industrial facilities, and gasoline and diesel engines, tightening the annual PM 2.5 standard to 12 micrograms per cubic meter. The revised standard became effective in March 2013. In November 2013, the EPA proposed a rule to clarify PM 2.5 implementation requirements to the states for current 1997 and 2006 non-attainment areas. In July 2016, EPA issued a final rule for states to use in creating their plans to address particulate matter. In October 2015, the EPA published a final rule that reduced the ozone NAAQS from 75 to 70 ppb. Murray Energy, Inc. filed a challenge to the final rule in the D.C. Circuit. Since that time, other industry and state petitioners have filed challenges as have several environmental groups. Attainment dates for the new standards range between 2013 and 2030, depending on the severity of the non-attainment. In April 2017, the D.C. Court of Appeals granted EPA's request to cancel oral arguments and ordered the case held in abeyance for an EPA review of the 2015 Rule. In July 2009, the D.C. Circuit Court of Appeals vacated part of a rule implementing the ozone NAAQS and remanded certain other aspects of the rule to the EPA for further consideration. In June 2013, the EPA proposed a rule for implementing the 2008 ozone NAAQS. Under a consent decree published in the Federal Register in January 2017, EPA has agreed to review the NAAQS for nitrogen oxides with a final decision due by 2018 and review the NAAQS for sulfur oxide with a final decision due by 2019. In July 2017, the EPA proposed to retain the current NAAQS for nitrogen oxides. The comment period for the proposal closed in September 2017. New standards may impose additional emissions control requirements on new and expanded coal-fired power plants and industrial boilers. Because coal mining operations and coal-fired electric generating facilities emit particulate matter and sulfur dioxide, the ARLP Partnership's mining operations and customers could be affected when the new standards are implemented by the applicable states, and developments might indirectly reduce the demand for coal.

· The EPA's regional haze program is designed to protect and improve visibility at and around national parks, national wilderness areas and international parks. Under the program, states are required to develop SIPs to improve visibility. Typically, these plans call for reductions in sulfur dioxide and nitrogen oxide emissions from coal-fueled electric plants. In recent cases, the EPA has decided to negate the SIPs and impose stringent requirements through FIPs. The regional haze program, including particularly the EPA's FIPs, and any future regulations may restrict the construction of new coal-fired power plants whose operation may impair visibility at and around federally protected areas and may require some existing coal-fired power plants to install additional control measures designed to limit haze-causing emissions. These requirements could limit the demand for coal in some locations.

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from coal-fueled electric plants. In recent cases, the EPA has decided to negate the SIPs and impose stringent requirements through FIPs. The regional haze program, including particularly the EPA's FIPs, and any future regulations may restrict the construction of new coal-fired power plants whose operation may impair visibility at and around federally protected areas and may require some existing coal-fired power plants to install additional control measures designed to limit haze-causing emissions. These requirements could limit the demand for coal in some locations.

The EPA's new source review ("NSR") program under the CAA in certain circumstances requires existing coal-fired power plants, when modifications to those plants significantly increase emissions, to install more stringent air emissions control equipment. The Department of Justice, on behalf of the EPA, has filed lawsuits against a number of coal-fired electric generating facilities alleging violations of the NSR program. The EPA has alleged that certain modifications have been made to these facilities without first obtaining certain permits issued under the program. Several of these lawsuits have settled, but others remain pending. Depending on the ultimate resolution of these cases, demand for coal could be affected.

Carbon Dioxide Emissions

Combustion of fossil fuels, such as the coal the ARLP Partnership produces, results in the emission of carbon dioxide, which is considered a GHG. Combustion of fuel for mining equipment used in coal production also emits GHGs. Future regulation of GHG emissions in the U.S. could occur pursuant to future U.S. treaty commitments, new domestic legislation or regulation by the EPA. Former President Obama expressed support for a mandatory cap and trade program to restrict or regulate emissions of GHGs and Congress has considered various proposals to reduce GHG emissions, and it is possible federal legislation could be adopted in the future. Internationally, the Kyoto Protocol set binding emission targets for developed countries that ratified it (the U.S. did not ratify, and Canada officially withdrew from its Kyoto commitment in 2012) to reduce their global GHG emissions. The Kyoto Protocol was nominally extended past its expiration date of December 2012, with a requirement for a new legal construct to be put into place by 2015. The United Nations Framework Convention on Climate Change met in Paris, France in December 2015 and agreed to an international climate agreement (the "Paris Agreement"). Although this agreement does not create any binding obligations for nations to limit their GHG emissions, it does include pledges to voluntarily limit or reduce future emissions. These commitments could further reduce demand and prices for the ARLP Partnership's coal. ~~The~~ In ~~U.S.~~June isof ~~currently a party to the Paris Agreement; however~~2017, President Trump ~~has~~announced ~~said~~ that hethe U.S. would ~~"cancel~~ withdraw from the Paris ~~Climate~~ Agreement, ~~and~~which ~~stop~~has ~~all~~a ~~payments~~four ofyear ~~U.S.~~exit ~~tax dollars to U~~process.~~N. global warming programs."~~ Future participation in the Paris Agreement by the U.S. remains uncertain. However, many states, regions and governmental bodies have adopted GHG initiatives and have or are considering the imposition of fees or taxes based on the emission of GHGs by certain facilities, including coal-fired electric generating facilities. Depending on the particular regulatory program that may be enacted, at either the federal or state level, the demand for coal could be negatively impacted, which would have an adverse effect on the ARLP Partnership's operations.

Even in the absence of new federal legislation, the EPA has begun to regulate GHG emissions under the CAA based on the U.S. Supreme Court's 2007 decision in Massachusetts v. Environmental Protection Agency that the EPA has authority to regulate GHG emissions. In 2009, the EPA issued a final rule, known as the ("Endangerment Finding"), ~~declaring~~which found that GHG emissions, including carbon dioxide and methane, endanger public health and welfare and that six GHGs, including carbon dioxide and methane, emitted by motor vehicles endanger both the public health and welfare.

In May 2010, the EPA issued its final "tailoring rule" for GHG emissions, a policy aimed at shielding small emission sources from CAA permitting requirements. The EPA's rule phases in various GHG-related permitting requirements beginning in January 2011. Beginning July 1, 2011, the EPA requires facilities that must already obtain NSR permits (new or modified stationary sources) for other pollutants to include GHGs in their permits for new construction projects that emit at least 100,000 tons per year of GHGs and existing facilities that increase their emissions by at least 75,000 tons per year. These permits require that the permittee adopt the Best Available Control Technology ("BACT"). In June 2014, the U.S. Supreme Court invalidated the EPA's position that power plants and other sources can be subject to permitting requirements based on their GHG emissions alone. For ~~CO₂~~ CO2 BACT to apply, CAA permitting must be triggered by another regulated pollutant (e.g., ~~SO₂~~SO2).

As a result of revisions to its preconstruction permitting rules that became fully effective in 2011, the EPA is now requiring new sources, including coal-fired power plants, to undergo control technology reviews for GHGs (predominantly carbon dioxide) as a condition of permit issuance. These reviews may impose limits on GHG emissions, or otherwise be used to compel consideration of alternative fuels and generation systems, as well as increase litigation risk for—and so discourage development of—coal-fired power plants. The EPA has also issued final rules requiring the monitoring and reporting of greenhouse gas emissions from certain sources.

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InAs ~~March 2012, the EPA proposed New Source Performance Standards ("NSPS") for carbon dioxide emissions from new fossil fuel-fired power plants. The proposal requires new coal units to meet~~ a ~~carbon~~result ~~dioxide emissions standard~~ of ~~1,000~~revisions ~~lbs. CO₂/MWh, which is equivalent~~ to ~~the~~its ~~carbon~~preconstruction ~~dioxide~~permitting ~~emitted~~rules that bybecame afully ~~natural~~effective ~~gas~~in ~~combined cycle unit. In January 2014~~2011, the EPA ~~formally~~is ~~published~~now ~~its~~requiring ~~re-proposed NSPS for carbon dioxide emissions from~~ new ~~power plants. The re-proposed rule requires an emissions standard of 1~~sources,~~100~~ ~~lbs.~~including ~~CO₂/MWh for new~~ coal-fired power plants~~. To meet such a standard~~, ~~new~~to ~~coal~~undergo ~~plants~~control ~~would~~technology bereviews ~~required~~for toGHGs ~~install~~(predominantly carbon ~~capture and storage ("CCS"~~dioxide) ~~technology. In~~as ~~August~~a ~~2015,~~condition ~~the~~of ~~EPA~~permit ~~released~~issuance. These ~~final~~reviews ~~rules~~may ~~requiring~~impose ~~newly~~limits ~~constructed~~on ~~coal-fired~~GHG ~~steam electric generating units ("EGUs") to emit no more than 1~~emissions,~~400~~ ~~lbs~~or ~~CO₂/MWh~~otherwise ~~(gross) and~~ be ~~constructed~~used ~~with CCS~~ to ~~capture~~compel ~~16%~~consideration of ~~CO₂~~alternative ~~produced~~fuels byand angeneration ~~electric generating unit burning bituminous coal. At the same time~~systems, ~~the~~as ~~EPA~~well ~~finalized~~as ~~GHG~~increase ~~emissions~~litigation ~~regulations~~risk for ~~modified~~ —and ~~existing~~so ~~power~~discourage ~~plants. The~~development ~~rule for modified sources required reducing GHG emissions from any modified or reconstructed source and could limit the ability~~ of ~~generators to upgrade~~ —coal-fired power plants ~~thereby reducing the demand for coal~~. The ~~rule~~EPA ~~for~~has ~~existing~~also ~~sources~~issued ~~proposes~~final torules ~~establish~~requiring ~~different~~the ~~target~~monitoring ~~emission rates (lbs per megawatt hour) for each state~~ and ~~has~~reporting ~~an overall goal to achieve a 32% reduction~~ of ~~carbon~~greenhouse ~~dioxide~~gas emissions from ~~2005~~certain ~~levels by 2030~~sources. The compliance period begins in 2022 and in 2030 CO₂ emissions goals must be met. Challenges to the NSPS have been filed in U.S. Court of Appeal for the D.C. Circuit and oral arguments are set for April 2017.

In ~~June 2014~~March 2012, the EPA proposed ~~CO₂~~New ~~emission~~Source Performance Standards ("~~guidelines~~NSPS") for ~~modified~~carbon ~~and~~dioxide ~~existing~~emissions from new fossil fuel-fired power plants ~~under Section 111(d) of the CAA~~. The ~~EPA~~proposal ~~finalized~~requires ~~the~~new ~~"Clean~~coal ~~Power~~units ~~Plan" ("CPP")~~to inmeet ~~August 2015,~~a ~~which established~~ carbon ~~pollution~~dioxide ~~standards~~emissions ~~for~~standard ~~power~~of ~~plants~~1,000 ~~called CO₂ emission performance rates~~lbs. ~~The~~ ~~EPA~~CO2/MWh, ~~expects~~which ~~each~~is ~~state~~equivalent to ~~develop~~the ~~implementation~~carbon ~~plans~~dioxide ~~for~~emitted ~~power~~by ~~plants~~a innatural ~~its~~gas ~~state~~combined tocycle ~~meet~~unit. In January 2014, the ~~individual~~EPA ~~state~~formally ~~targets~~published ~~established~~its inre-proposed ~~the~~NSPS ~~CPP. The~~for ~~EPA~~carbon ~~has~~dioxide ~~given~~emissions ~~states~~from ~~the~~new ~~option~~power toplants. The ~~develop~~re-proposed ~~compliance~~rule ~~plans~~requires ~~for~~an ~~annual~~emissions ~~rate-based~~standard ~~reductions~~of ~~(pounds~~1,100 ~~per~~lbs. ~~megawatt~~CO2/MWh ~~hour)~~for ornew ~~mass~~coal-~~based~~fired ~~tonnage~~power ~~limits for CO₂~~plants. ~~The~~To ~~state~~meet ~~plans~~such ~~are~~a ~~due in September 2016~~standard, ~~subject~~new tocoal ~~potential~~plants ~~extensions~~would ofbe uprequired to ~~two~~install ~~years~~carbon ~~for~~capture ~~final~~and ~~plan~~storage ~~submission~~("CCS") technology. ~~The~~In ~~compliance~~August ~~period~~2015, ~~begins~~the inEPA ~~2022,~~released ~~and~~final ~~emission~~rules ~~reductions~~requiring ~~will~~newly beconstructed ~~phased~~coal-fired insteam upelectric togenerating ~~2030. The~~units ~~EPA~~("EGUs") ~~also~~to ~~proposed~~emit ano ~~federal~~more ~~compliance~~than ~~plan~~1,400 tolbs ~~implement~~CO2/MWh ~~the~~(gross) ~~CPP~~and inbe ~~the~~constructed ~~event~~with ~~that~~CCS anto ~~approvable~~capture ~~state~~16% ~~plan~~of isCO2 ~~not~~produced ~~submitted~~by toan ~~the~~electric ~~EPA. Although~~generating ~~each~~unit ~~state~~burning ~~can~~bituminous ~~determine~~coal. ~~its~~At ~~own~~the ~~method~~same ~~of compliance~~time, the ~~requirements~~EPA ~~rely~~finalized onGHG ~~decreased~~emissions ~~use~~regulations offor ~~coal~~modified and ~~increased~~existing ~~use~~power ofplants. The ~~natural~~rule ~~gas~~for ~~and~~modified ~~renewables~~sources ~~for~~required ~~electricity~~reducing ~~generation,~~GHG asemissions ~~well~~from asany ~~reductions~~modified inor ~~the~~reconstructed ~~amount~~source ofand ~~electricity~~could ~~used~~limit bythe ~~consumers. Judicial~~ability ~~challenges~~of ~~have~~generators ~~been~~to ~~filed and~~upgrade ~~oral~~coal-fired ~~arguments~~power ~~were~~plants ~~heard~~thereby byreducing the Ddemand for coal.C. In ~~Circuit~~April ~~Court~~2017, ofthe ~~Appeals~~EPA published notice in ~~September~~the ~~2016,~~federal ~~but~~register athat ~~final~~the ~~decision~~agency has ~~not~~initiated ~~yet~~a ~~been~~review ~~issued. On~~of ~~February 9,~~the ~~2016,~~NSPS ~~the~~for ~~U.S.~~new ~~Supreme~~and ~~Court~~modified ~~issued~~fossil afuel ~~stay,~~fired ~~halting~~power ~~implementation~~plants ofand that, following the ~~regulations. The~~review, ~~stay~~the EPA will beinitiate inreconsideration ~~place~~proceedings ~~until~~to ~~the~~suspend, ~~D.C.~~revise ~~Circuit~~or ~~Court~~rescind ofthis ~~Appeals~~NSPS. Challenges ~~rules on~~to the ~~merits~~NSPS ofhave ~~the~~been ~~legal~~filed ~~challenges~~in ~~and,~~U.S. ifCourt ~~following~~of aAppeal ~~ruling~~for by the D.C. Circuit ~~Court~~and oforal ~~Appeals,~~arguments awere ~~writ~~set offor ~~certiorari~~April ~~from~~2017; however, in April 2017, the ~~Supreme~~U.S Court isof ~~sought~~Appeal ~~and~~for ~~granted,~~ the ~~stay~~D.C. ~~will~~Circuit ~~remain~~ordered inthe ~~place~~NSPS ~~until~~case ~~the~~held ~~Supreme~~in ~~Court~~abeyance ~~issues~~for ~~its~~an ~~decision~~EPA onreview of the ~~merits~~rule. ~~If,~~It ~~despite~~is ~~the~~likely ~~legal~~than ~~challenges,~~any ~~the~~repeal ~~rules were~~or ~~implemented~~revisions into ~~their~~the ~~current~~NSPS ~~form, demand for coal~~ will ~~likely~~ be ~~further~~subject ~~decreased,~~to ~~potentially~~legal ~~significantly,~~challenges ~~and~~as ~~adversely impact our business~~well. Future implementation of the ~~CPP~~NSPS ~~remains~~is uncertain at this time.

~~Collectively~~In August 2015, ~~these~~the ~~requirements~~EPA ~~have~~issued ~~led~~its tofinal ~~premature~~Clean ~~retirements~~Power ~~and~~Plan ~~could~~("CPP") ~~lead~~rules that establish carbon pollution standards for power plants, called CO2 emission performance rates. Judicial challenges led the U.S. Supreme Court to ~~additional~~grant ~~premature~~a ~~retirements~~stay in February 2016 of ~~coal-fired~~the ~~generating~~implementation ~~units~~of ~~and~~the ~~reduce~~CPP before the ~~demand~~United States Court of Appeals for ~~coal~~the District of Columbia ("Circuit Court") even issued a decision. ~~Congress~~By ~~has~~its ~~rejected~~terms, ~~legislation~~this stay will remain in effect throughout the pendency of the appeals process including at the Circuit Court and the Supreme Court through any certiorari petition that may be granted. The Supreme Court's stay applies only to ~~restrict~~EPA's ~~carbon~~regulations ~~dioxide~~for CO2 emissions from existing power plants and itwill not affect EPA's standards for new power plants. It is ~~unclear~~not ~~whether~~yet clear how either the ~~EPA~~Circuit ~~has~~Court or the ~~legal~~Supreme ~~authority~~Court will rule on the legality of the CPP. Additionally, in October 2017 EPA proposed to ~~regulate~~repeal ~~carbon~~the ~~dioxide~~CPP, although the final outcome of this action and the pending litigation regarding the CPP is uncertain at this time. In connection with this proposed repeal, EPA issued an Advance Notice of Proposed Rulemaking ("ANPRM") in December 2017 regarding emission guidelines to limit GHG emissions from existing ~~and~~electricity ~~modified~~utility ~~power~~generating ~~plants~~units. The asANPRM ~~proposed~~seeks comment regarding what the EPA should include in a potential new, existing-source regulation under the ~~NSPS~~Clean ~~and~~Air ~~CPP~~Act of GHG emissions from electric utility generating units that it may propose. ~~Substantial~~If ~~limitations~~the oneffort to repeal the rules is unsuccessful and the rules were upheld at the conclusion of this appellate process and were implemented in their current form, or if the ANPRM results in a different proposal to control GHG emissions ~~could~~from ~~adversely~~electric ~~affect~~utility generating units, demand for ~~the~~ coal wewould ~~produce~~likely be further decreased, potentially significantly, and our business would be adversely impacted.

~~There~~Collectively, these requirements have ~~been~~led ~~numerous~~to ~~protests~~premature ofretirements and ~~challenges~~could lead to ~~the~~additional ~~permitting~~premature retirements of ~~new~~ coal-fired ~~power~~generating ~~plants~~units ~~by environmental organizations~~ and ~~state~~reduce ~~regulators~~the demand for ~~concerns related to GHG emissions~~coal. ~~For~~Congress ~~instance,~~has ~~various state regulatory authorities have~~ rejected ~~the~~legislation ~~construction~~to ofrestrict ~~new~~carbon ~~coal-fueled~~dioxide ~~power plants based on the uncertainty surrounding the potential costs associated with GHG~~ emissions from ~~these~~existing ~~plants under future laws limiting the emissions of carbon dioxide. In addition, several permits issued to new coal-fueled~~ power plants ~~without~~and ~~limits~~it onis ~~GHG~~unclear ~~emissions~~whether ~~have been appealed to~~ the EPA's ~~Environmental~~has ~~Appeals~~the ~~Board. In~~legal ~~addition,~~authority ~~over thirty states have currently adopted "renewable energy standards" or "renewable portfolio standards," which encourage or require electric utilities~~ to ~~obtain~~regulate acarbon ~~certain~~dioxide ~~percentage~~emissions ~~of their electric generation portfolio~~ from ~~renewable~~existing ~~resources~~and bymodified apower ~~certain~~plants ~~date. These~~as ~~standards~~proposed ~~range~~in ~~generally from 10% to 30%, over time periods that generally extend from~~ the ~~present~~NSPS ~~until between 2020~~ and ~~2030~~CPP. ~~Other~~Substantial ~~states~~limitations ~~may~~on ~~adopt~~GHG ~~similar~~emissions ~~requirements,~~could ~~and~~adversely ~~federal~~affect ~~legislation~~demand isfor ~~a possibility in this area. To~~ the ~~extent~~coal ~~these requirements affect~~ the ARLP Partnership's ~~current and prospective customers, they may reduce the demand for coal-fired power, and may affect long-term demand for its coal~~produces. ~~Finally, a federal appeals court allowed a lawsuit pursuing federal common law claims to proceed against certain utilities on~~

There have been numerous protests of and challenges to the permitting of new coal-fired power plants by environmental organizations and state regulators for concerns related to GHG emissions. For instance, various state regulatory authorities have rejected the construction of new coal-fueled power plants based on the uncertainty surrounding the potential costs associated with GHG emissions from these plants under future laws limiting the emissions of carbon dioxide. In addition, several permits issued to new coal-fueled power plants without limits on GHG emissions have been appealed to the EPA's Environmental Appeals Board. In addition, over thirty states have

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currently adopted "renewable energy standards" or "renewable portfolio standards," which encourage or require electric utilities to obtain a certain percentage of their electric generation portfolio from renewable resources by a certain date. These standards range generally from 10% to 30%, over time periods that generally extend from the present until between 2020 and 2030. Other states may adopt similar requirements, and federal legislation is a possibility in this area. To the extent these requirements affect the ARLP Partnership's current and prospective customers, they may reduce the demand for coal-fired power, and may affect long-term demand for its coal. Finally, a federal appeals court allowed a lawsuit pursuing federal common law claims to proceed against certain utilities on the basis that they may have created a public nuisance due to their emissions of carbon dioxide, while a second federal appeals court dismissed a similar case on procedural grounds. The U.S. Supreme Court overturned that decision in June 2011, holding that federal common law provides no basis for public nuisance claims against utilities due to their carbon dioxide emissions. The U.S. Supreme Court did not, however, decide whether similar claims can be brought under state common law. As a result, despite this favorable ruling, tort-type liabilities remain a concern.

In addition, environmental advocacy groups have filed a variety of judicial challenges claiming that the environmental analyses conducted by federal agencies before granting permits and other approvals necessary for certain coal activities do not satisfy the requirements of the National Environmental Policy Act ("NEPA"). These groups assert that the environmental analyses in question do not adequately consider the climate change impacts of these particular projects. In December 2014 the Council on Environmental Quality ("CEQ") released updated draft guidance discussing how federal agencies should consider the effects of GHG emissions and climate change in their NEPA evaluations. The guidance encourages agencies to provide more detailed discussion of the direct, indirect, and cumulative impacts of a proposed action's reasonably foreseeable emissions and effects. This guidance could create additional delays and costs in the NEPA review process or in the ARLP Partnership's operations, or even an inability to obtain necessary federal approvals for the ARLP Partnership's future operations, including due to the increased risk of legal challenges from environmental groups seeking additional analysis of climate impacts. In April 2017, CEQ withdrew its final 2016 guidance on how federal agencies should incorporate climate change and GHG considerations into NEPA reviews of federal actions.

Many states and regions have adopted GHG initiatives and certain governmental bodies have or are considering the imposition of fees or taxes based on the emission of GHG by certain facilities, including coal-fired electric generating facilities. For example, in 2005, ten Northeastern states entered into the Regional Greenhouse Gas Initiative agreement ("RGGI"), calling for implementation of a cap and trade program aimed at reducing carbon dioxide emissions from power plants in the participating states. The members of RGGI have established in statutes and/or regulations a carbon dioxide trading program. Auctions for carbon dioxide allowances under the program began in September 2008. ~~Though~~Since ~~New Jersey withdrew from RGGI in 2011, since~~ its inception, several additional northeastern states and Canadian provinces have joined as participants or observers. In addition, New Jersey has announced its intention to rejoin RGGI following the change in state government administrations.

Following the RGGI model, five Western states launched the Western Regional Climate Action Initiative to identify, evaluate, and implement collective and cooperative methods of reducing GHG in the region to 15% below 2005 levels by 2020. These states were joined by two additional states and four Canadian provinces and became collectively known as the Western Climate Initiative Partners. However, in November 2011, six states withdrew, leaving California and the four Canadian provinces as members. At a January 2012 stakeholder meeting, this group confirmed a commitment and timetable to create the largest carbon market in North America and provide a model to guide future efforts to establish national approaches in both Canada and the U.S. to reduce GHG emissions. It is likely that these regional efforts will continue.

It is possible that future international, federal and state initiatives to control GHG emissions could result in increased costs associated with coal production and consumption, such as costs to install additional controls to reduce carbon dioxide emissions or costs to purchase emissions reduction credits to comply with future emissions trading programs. Such increased costs for coal consumption could result in some customers switching to alternative sources of fuel, or otherwise adversely affect the ARLP Partnership's operations and demand for its products, which could have a material adverse effect on its business, financial condition and results of operations.

Water Discharge

The Federal Clean Water Act ("CWA") and similar state and local laws and regulations affect coal mining operations by imposing restrictions on effluent discharge into waters and the discharge of dredged or fill material into the waters of the U.S. Regular monitoring, as well as compliance with reporting requirements and performance standards, is a precondition for the issuance and renewal of permits governing the discharge of pollutants into water. Section 404 of the CWA imposes permitting and mitigation requirements associated with the dredging and filling of wetlands and streams. The CWA and equivalent state legislation, where such equivalent state legislation exists, affect coal mining operations that impact wetlands and streams. Although permitting requirements have been tightened in recent years, the ARLP Partnership believes it has obtained all necessary permits required under CWA Section 404 as it has traditionally been interpreted by the responsible agencies. However, mitigation requirements under existing and possible future "fill" permits may vary considerably. For that reason, the setting of post-mine asset retirement obligation accruals for such mitigation projects is difficult to ascertain with certainty and may increase in the future.

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~~For~~ Water more information about asset retirement obligations, please read "Item 8. Financial Statements and Supplementary Data—Note 16. Asset Retirement Obligations." Although more stringent permitting requirements may be imposed in the future, the ARLP Partnership is not able to accurately predict the impact, if any, of such permitting requirements.Discharge

The U.S. Army Corps of Engineers ("Corps of Engineers") maintains two permitting programs under CWA Section 404 for the discharge of dredged or fill material: one for "individual" permits and a more streamlined program for "general" permits. In June 2010, the Corps of Engineers suspended the use of "general" permits under Nationwide Permit 21 ("NWP 21") in the Appalachian states. In February 2012, the Corps of Engineers reissued the final 2012 NWP 21. The Center for Biological Diversity later filed a notice of intent to sue the Corps of Engineers based on allegations the 2012 NWP 21 program violated the Endangered Species Act ("ESA"). The Corps of Engineers and National Marine Fisheries Service ("NMFS") have completed their programmatic ESA Section 7 consultation process on the Corps of Engineers' 2012 NWP 21 package, and NMFS has issued a revised biological opinion finding that the NWP 21 program does not jeopardize the continued existence of threatened and endangered species and will not result in the destruction or adverse modification of designated critical habitat. However, the opinion contains 12 additional protective measures the Corps of Engineers will implement in certain districts to "enhance the protection of listed species and critical habitat." While these measures will not affect previously verified permit activities where construction has not yet been completed, several Corps of Engineers districts with mining operations will be impacted by the additional protective measures going forward. These measures include additional reporting and notification requirements, potential imposition of new regional conditions and additional actions concerning cumulative effects analyses and mitigation. The ARLP Partnership's coal mining operations typically require Section 404 permits to authorize activities such as the creation of slurry ponds and stream impoundments. The CWA authorizes the EPA to review Section 404 permits issued by the Corps of Engineers, and in 2009, the EPA began reviewing Section 404 permits issued by the Corps of Engineers for coal mining in Appalachia. Currently, significant uncertainty exists regarding the obtaining of permits under the CWA for coal mining operations in Appalachia due to various initiatives launched by the EPA regarding these permits.

For instance, even though the State of West Virginia has been delegated the authority to issue permits for coal mines in that state, the EPA is taking a more active role in its review of National Pollutant Discharge Elimination System ("NPDES") permit applications for coal mining operations in Appalachia. The EPA has stated that it plans to review all applications for NPDES permits. Indeed, final guidance issued by the EPA in July 2011, encouraged the EPA Regions 3, 4 and 5 to object to the issuance of state program NPDES permits where the Region does not believe that the proposed permit satisfies the requirements of the CWA, and with regard to state issued general Section 404 permits, support the previously drafted Enhanced Coordination Procedures ("ECP"). In October 2011, the U.S. District Court for the District of Columbia rejected the ECP on several different legal grounds and later, this same court enjoined the EPA from any further usage of its final guidance. The U.S. Supreme Court denied a request to review this decision. Any future application of procedures similar to ECP, such as may be enacted following notice and comment rulemaking, would have the potential to delay issuance of permits for surface coal mines, or to change the conditions or restrictions imposed in those permits.

The EPA also has statutory "veto" power over a Section 404 permit if the EPA determines, after notice and an opportunity for a public hearing, that the permit will have an "unacceptable adverse effect." In January 2011, the EPA exercised its veto power to withdraw or restrict the use of a previously issued permit for Spruce No. 1 Surface Mine in West Virginia, which is one of the largest surface mining operations ever authorized in Appalachia. This action was the first time that such power was exercised with regard to a previously permitted coal mining project. A challenge to the EPA's exercise of this authority was made in the U.S. District Court for the District of Columbia and in March 2012, that court ruled that the EPA lacked the statutory authority to invalidate an already issued Section 404 permit retroactively. In April 2013, the D.C. Circuit Court of Appeals reversed this decision and authorized the EPA to retroactively veto portions of a Section 404 permit. The U.S. Supreme Court denied a request to review this decision. Any future use of the EPA's Section 404 "veto" power could create uncertainly with regard to the ARLP Partnership's continued use of current permits, as well as impose additional time and cost burdens on future operations, potentially adversely affecting coal revenues. In addition, the EPA initiated a preemptive veto prior to the filing of any actual permit application for a copper and gold mine based on fictitious mine scenario. The implications of this decision could allow the EPA to bypass the state permitting process and engage in watershed and land use planning.

Total Maximum Daily Load ("TMDL") regulations under the CWA establish a process to calculate the maximum amount of a pollutant that an impaired water body can receive and still meet state water quality standards, and to

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allocate pollutant loads among the point and non-point pollutant sources discharging into that water body. Likewise, when water quality in a receiving stream is better than required, states are required to conduct an antidegradation review before approving discharge permits. The adoption of new TMDL-related allocations or any changes to antidegradation policies for streams near ARLP Partnership's coal mines could require more costly water treatment and could adversely affect its coal production.

InConsiderable ~~June 2015,~~legal ~~the~~uncertainty ~~EPA~~exists ~~issued~~surrounding athe ~~new~~standard ~~rule providing~~for awhat ~~definition~~constitutes ofjurisdictional ~~the~~waters ~~WOTUS.~~and ~~This~~wetlands ~~rule is~~subject ~~broadly~~to ~~written and expands~~ the ~~EPA~~protections and ~~Corps~~requirements of ~~Engineers~~the ~~jurisdiction~~Clean Water Act. ~~WOTUS~~A ~~creates~~2015 ~~new~~rulemaking ~~federal~~by ~~authority~~EPA ~~over~~to ~~lands,~~revise the ~~ditches,~~standard ~~and~~was ~~potentially~~stayed ~~on-site~~nationwide ~~mining~~by ~~waters~~the U.S. OfCourt ~~critical~~of ~~concern~~Appeals tofor the ~~ARLP~~Sixth ~~Partnership's~~Circuit ~~industry~~and isstayed ~~the~~for ~~possibility~~certain ~~that~~primarily ~~many~~western ~~water~~states ~~features~~by ~~commonly~~a ~~found~~United onStates ~~mine~~District ~~sites~~Court ~~which~~in ~~are~~North ~~currently~~Dakota. ~~not~~In ~~considered~~January ~~jurisdictional~~2018, ~~could~~the ~~nevertheless~~Supreme ~~fall~~Court determined ~~within~~that the ~~definition~~circuit ofcourts ~~WOTUS~~do ~~under~~not ~~the~~have ~~proposed~~jurisdiction ~~rule. Ditches,~~to ~~closed~~hear ~~loop~~challenges ~~systems,~~to ~~on-site~~the ~~ponds,~~2015 ~~impoundments~~rule, ~~and~~removing ~~other~~the ~~water~~basis ~~management~~for ~~features~~the ~~are~~Sixth ~~integral~~Circuit to ~~mining~~continue ~~operations,~~its ~~and~~nationwide ~~are~~stay. ~~used~~Additionally, toEPA ~~manage~~has ~~on-site~~promulgated ~~waters~~a infinal anrule ~~environmentally~~that ~~sound~~extends ~~and~~the ~~frequently~~applicability ~~statutorily~~date ~~mandated~~of ~~manner. The~~the 2015 rule ~~could~~ ~~lead~~for toanother ~~substantially~~two ~~increased~~years ~~permitting~~in ~~requirements~~order ~~with~~to ~~more~~allow ~~costs,~~EPA ~~delays,~~to ~~and~~undertake ~~increased~~a ~~risk~~rulemaking on the question of ~~litigation. Industry~~what ~~groups~~constitutes ~~have~~a ~~challenged~~water of the ~~final~~United ~~rule~~States. ~~Multiple~~ ~~suits~~In ~~were~~the ~~filed~~meantime, ~~across~~judicial challenges to the ~~country~~2015 byrulemaking ~~states,~~are ~~industry,~~likely ~~and~~to ~~outside~~continue ~~parties~~to –work ~~The~~their ~~Coal~~way ~~Industry~~through isthe ~~currently~~courts ~~active~~along inwith ~~suits~~challenges into the ~~Texas~~recent ~~District~~rulemaking ~~Court~~that ~~and~~extends ~~6th~~the ~~Circuit~~applicability ~~Court~~date of ~~Appeals, though~~ the ~~coalition~~2015 ~~has~~rule. ~~moved~~For tonow, ~~intervene~~EPA inand ~~several~~the ~~suits~~Corps ~~(to~~of ~~both~~Engineers ~~defend~~will ~~certain~~continue ~~provisions~~to inapply the ~~rule important~~existing tostandard ~~industry~~for ~~and~~what ~~contest~~constitutes ~~overly-broad~~a ~~provisions). The~~water ~~6th~~of ~~Circuit~~the ~~ordered~~United aStates ~~nationwide~~as ~~stay~~determined ofby the ~~rule that~~Supreme ~~will~~Court ~~remain~~ in ~~effect~~the atRapanos ~~least~~case ~~until~~and itpost-Rapanos ~~issues~~guidance. ~~its~~Should ~~jurisdictional~~the ~~determination~~2015 ~~(expected~~rule intake ~~the~~effect, ~~near~~or ~~future). At~~should ~~present,~~a itdifferent isrule ~~not~~expanding ~~clear~~the ~~whether~~definition anof ~~appellate~~what ~~court~~constitutes ora ~~multiple~~water ~~district~~of ~~courts~~the ~~will~~United ~~exercise~~States ~~jurisdiction~~be ~~over~~promulgated ~~the~~as ~~claims. In~~a ~~January~~result ~~2016,~~of ~~the~~EPA ~~U.S.~~and ~~Supreme~~the ~~Court~~Corps ~~agreed~~of toEngineers' ~~resolve~~rulemaking process, the ~~jurisdictional~~ARLP ~~questions~~Partnership ~~and~~could ~~decide~~face ~~the~~increased ~~proper~~costs ~~court~~and ordelays ~~courts~~due to ~~hear~~additional ~~the~~permitting and regulatory requirements and possible challenges to ~~the~~permitting ~~WOTUS rule~~decisions.

Hazardous Substances and Wastes

The Federal Comprehensive Environmental Response, Compensation and Liability Act ("CERCLA"), otherwise known as the "Superfund" law, and analogous state laws, impose liability, without regard to fault or the legality of the original conduct on certain classes of persons that are considered to have contributed to the release of a "hazardous substance" into the environment. These persons include the owner or operator of the site where the release occurred and companies that disposed or arranged for the disposal of the hazardous substances found at the site. Persons who are or were responsible for the release of hazardous substances may be subject to joint and several liability under CERCLA for the costs of cleaning up releases of hazardous substances and natural resource damages. Some products used in coal mining operations generate waste containing hazardous substances. The ARLP Partnership is currently unaware of any material liability associated with the release or disposal of hazardous substances from its past or present mine sites.

The Federal Resource Conservation and Recovery Act ("RCRA") and corresponding state laws regulating hazardous waste affect coal mining operations by imposing requirements for the generation, transportation, treatment, storage, disposal, and cleanup of hazardous wastes. Many mining wastes are excluded from the regulatory definition of hazardous wastes, and coal mining operations covered by SMCRA permits are by statute exempted from RCRA permitting. RCRA also allows the EPA to require corrective action at sites where there is a release of hazardous substances. In addition, each state has its own laws regarding the proper management and disposal of waste material. While these laws impose ongoing compliance obligations, such costs are not believed to have a material impact on the ARLP Partnership's operations.

In June 2010, the EPA released a proposed rule to regulate the disposal of certain coal combustion by-products ("CCB"). The proposed rule set forth two very different options for regulating CCB under RCRA. The first option called for regulation of CCB as a hazardous waste under Subtitle C, which creates a comprehensive program of federally enforceable requirements for waste management and disposal. The second option utilized Subtitle D, which would give the EPA authority to set performance standards for waste management facilities and would be enforced primarily through citizen suits. The proposal leaves intact the Bevill exemption for beneficial uses of CCB. In April 2012, several environmental organizations filed suit against the EPA to compel the EPA to take action on the proposed rule. Several companies and industry groups intervened. A consent decree was entered on January 29, 2014.

The EPA finalized the CCB rule on December 19, 2014, setting nationwide solid nonhazardous waste standards for CCB disposal. On April 17, 2015, the EPA finalized regulations under the solid waste provisions ("of Subtitle D") of RCRA and not the hazardous waste provisions of Subtitle C which became effective on October 19, 2015. EPA

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~~of RCRA and not the hazardous waste provisions ("Subtitle C") which became effective on October 19, 2015. EPA~~ affirms in the preamble to the final rule that "this rule does not apply to CCR placed in active or abandoned underground or surface mines." Instead, "the U.S. Department of Interior ("DOI") and EPA will address the management of CCR in mine fills in a separate regulatory action(s)." While classification of CCB as a hazardous waste would have led to more stringent restrictions and higher costs, this regulation may still increase the operating costs of the ARLP Partnership's customers and potentially reduce those customers' ability to purchase coal.

On November 3, 2015, EPA published the final rule Effluent Limitations Guidelines and Standards ("ELG"), revising the regulations for the Steam Electric Power Generating category which became effective on January 4, 2016. The rule sets the first federal limits on the levels of toxic metals in wastewater that can be discharged from power plants, based on technology improvements in the steam electric power industry over the last three decades. The combined effect of the CCR and ELG regulations has forced power generating companies to close existing ash ponds and will likely force the closure of certain older existing coal burning power plants that cannot comply with the new standards. These regulations add costs to the operation of coal burning power plants on top of other regulations like the 2014 regulations issued under Section 316(b) of the CWA that affects the cooling water intake structures at power plants in order to reduce fish impingement and entrainment. Individually and collectively, these regulations could, in turn, impact the market for the ARLP Partnership's products. In April 2017, EPA granted petitions for reconsideration and an administrative stay of all future compliance deadlines for the ELG rule. In August 2017, EPA granted petitions for reconsideration of the CCR rule.

Endangered Species Act

The federal ESA and counterpart state legislation protect species threatened with possible extinction. The U.S. Fish and Wildlife Service (the "USFWS") works closely with the OSM and state regulatory agencies to ensure that species subject to the ESA are protected from mining-related impacts. If the USFWS were to designate species indigenous to the areas in which the ARLP Partnership operates as threatened or endangered, the ARLP Partnership could be subject to additional regulatory and permitting requirements.

Other Environmental, Health and Safety Regulations

In addition to the laws and regulations described above, the ARLP Partnership is subject to regulations regarding underground and above ground storage tanks in which it may store petroleum or other substances. Some monitoring equipment that it uses is subject to licensing under the Federal Atomic Energy Act. Water supply wells located on the ARLP Partnership's properties are subject to federal, state, and local regulation. In addition, the ARLP Partnership's use of explosives is subject to the Federal Safe Explosives Act. The ARLP Partnership is also required to comply with the Federal Safe Drinking Water Act, the Toxic Substance Control Act, and the Emergency Planning and Community Right-to-Know Act. The costs of compliance with these regulations should not have a material adverse effect on the ARLP Partnership's business, financial condition or results of operations.

Employees

To conduct its operations, the ARLP Partnership, as of ~~February 1~~January 25, ~~2017~~2018, employed 3,~~324~~321 full-time employees, including 2,~~945~~931 employees involved in active mining operations, ~~178~~180 employees in other operations, and ~~182~~179 corporate employees. The ARLP Partnership's work force is entirely union-free. ~~The ARLP Partnership's total workforce shrank by nearly 22% during 2016 as it reduced production and shifted production to lower-cost operations in response to market conditions.~~

Administrative Services

On April 1, 2010, effective January 1, 2010, we entered into an amended and restated administrative services agreement ("Administrative Services Agreement") with ARLP, MGP, the Intermediate Partnership, our general partner AGP, and Alliance Resource Holdings II, Inc. ("ARH II"), the indirect parent of SGP. The Administrative Services Agreement superseded the administrative services agreement signed in connection with our IPO in 2006. Under the Administrative Services Agreement, certain employees of ARLP, including some executive officers, provide administrative services to AHGP, AGP and ARH II and their respective affiliates. We reimburse the ARLP Partnership for services rendered for us by those employees as provided under the Administrative Services Agreement. We paid the ARLP Partnership $0.4 million under this agreement for the year ended December 31, ~~2016~~2017. ~~The~~ Please ~~ARLP~~read ~~Partnership~~"Item ~~also~~13—Certain ~~billed~~Relationships and ~~recognized~~Related ~~administrative~~Transactions, ~~service~~and ~~revenue~~Director ~~under~~Independence—Administrative ~~this agreement of $0~~Services.~~1 million for the year~~ "

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ended December 31, 2016 from ARH II. Please read "Item 13—Certain Relationships and Related Transactions, and Director Independence—Administrative Services."

ITEM 1A. RISK FACTORS

Risks Inherent in an Investment in Us

In the future, we may not have sufficient cash to pay distributions at our current quarterly distribution level or to increase distributions.

Currently, our earnings and cash flow consist solely of cash distributions from ARLP. Therefore, the amount of distributions we are able to make to our unitholders may fluctuate based on the level of distributions ARLP makes to its partners. We cannot assure you that ARLP will continue to make quarterly distributions at its current level or increase its quarterly distributions in the future. In addition, while we would expect to increase or decrease distributions to our unitholders if ARLP increases or decreases distributions to us, the timing and amount of such increased or decreased distributions, if any, will not necessarily be comparable to the timing and amount of the increase or decrease in distributions made by ARLP to us.

Our ability to distribute cash received from ARLP to our unitholders could be limited by a number of factors, including:

interest expense and principal payments on indebtedness;

restrictions on distributions contained in any current or future debt agreements;

our general and administrative expenses;

expenses of our subsidiaries other than ARLP, including tax liabilities of our corporate subsidiaries, if any;

· reserves necessary for us to make capital contributions to maintain our 1.980011% general partner interest in the ARLP Partnership as required by the partnership agreement of ARLP upon the issuance of additional partnership securities by ARLP; and

reserves our general partner believes prudent for us to maintain for the proper conduct of our business or to provide for future distributions.

We cannot guarantee that in the future we will be able to pay distributions or that any distributions we do make will be at or above our current quarterly distribution level. The actual amount of cash that is available for distribution to our unitholders will depend on numerous factors, many of which are beyond our control or the control of our general partner.

ARLP's cash distributions are not guaranteed and may fluctuate with its performance and other external factors.

The amount of cash that ARLP can distribute to holders of its common units or other partnership securities, including us, each quarter principally depends on the amount of cash it generates from its operations, which will fluctuate from quarter to quarter based on, among other things:

the amount of coal the ARLP Partnership is able to produce from its properties;

the price at which it is able to sell coal, which is affected by the supply of and demand for domestic and foreign coal;

the level of its operating costs;

weather conditions and patterns;

the proximity to and capacity of transportation facilities;

domestic and foreign governmental regulations and taxes;

regulatory, administrative, and judicial decisions;

competition within the coal industry;

the price and availability of alternative fuels;

the effect of worldwide energy consumption; and

prevailing economic conditions.

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In addition, the actual amount of cash that ARLP will have available for distribution will depend on other factors, including:

the level of its capital expenditures;

· the cost of acquisitions, ifand ~~any~~investments;

its debt service requirements and restrictions on distributions contained in its current or future debt agreements;

fluctuations in its working capital needs;

unavailability of financing resulting in unanticipated liquidity constraints;

the ability of ARLP to borrow under its credit agreement to make distributions to its unitholders; and

the amount, if any, of cash reserves established by MGP, in its discretion, for the proper conduct of ARLP's business.

Because of these and other factors, ARLP may not have sufficient available cash to pay a specific level of cash distributions to its unitholders. Furthermore, the amount of cash that ARLP has available for distribution depends primarily upon its cash flow, including cash flow from financial reserves and working capital borrowing, and is not solely a function of profitability, which will be affected by non-cash items. As a result, ARLP may be able to make cash distributions during periods when it records net losses and may be unable to make cash distributions during periods when it records net income. Please read "—Risks Related to ARLP's Business" for a discussion of further risks affecting ARLP's ability to generate available cash and "Item 8. Financial Statements and Supplementary Data—Note 10 – Variable Interest Entities for further discussion of restrictions on the cash available for distribution.

ARLP's managing general partner, with our consent, may limit or modify the incentive distributions we are entitled to receive in order to facilitate ARLP's growth strategy. Our general partner's board of directors can give this consent without a vote of our unitholders.

We own ARLP's managing general partner, which owns the IDRs in ARLP that entitle us to receive increasing percentages, up to a maximum of 48%, of any cash distributed by ARLP, as certain target distribution levels are reached in excess of $0.1375 per ARLP unit in any quarter. The IDRs currently participate at the maximum 48% target cash distribution level at current ARLP distribution levels. A substantial portion of the cash flow we receive from ARLP is provided by these IDRs. The board of directors of MGP ("MGP Board of Directors") may reduce the distributions related to the IDRs payable to us with our consent, which we may provide without the approval of our unitholders.

A reduction in ARLP's distributions will disproportionately affect the amount of cash distributions to which we are currently entitled.

MGP's ownership of the IDRs in ARLP entitles us to receive specified percentages of total cash distributions made by ARLP with respect to any particular quarter only in the event that ARLP distributes more than $0.1375 per unit for such quarter. As a result, the holders of ARLP's common units have a priority over the holders of ARLP's IDRs to the extent of cash distributions by ARLP up to and including $0.1375 per unit for any quarter.

MGP's ownership of the IDRs in ARLP entitles us to receive up to 48% of all cash distributed by ARLP. Because the IDRs participate at the maximum 48% target cash distribution level at current ARLP distribution levels, future growth in distributions we receive from ARLP will not result from an increase in the target cash distribution level associated with the IDRs.

Furthermore, a decrease in the amount of distributions by ARLP to less than $0.1875 per common unit per quarter would reduce MGP's percentage of the incremental cash distributions above to 23% of the amount above $0.15625 per common unit per quarter, a decrease in the ARLP distribution to less than $0.15625 would reduce MGP's percentage to 13% of the amount above $0.1375, and a decrease below that level would reduce the percentage of incremental cash distributions to zero. As a result, any such reduction in quarterly cash distributions from ARLP would disproportionately reduce the amount of all distributions that we receive from ARLP as compared to the impact on the holders of ARLP common units.

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Restrictions in future financing agreements could limit ARLP's ability to make distributions to its unitholders, borrow additional funds or capitalize on business opportunities.

Any future credit facility could include such provisions and the ARLP Partnership's ability to comply with them may be affected by events beyond its control, including prevailing economic, financial and industry conditions. Failure to comply with any such restrictions or covenants could have significant consequences, such as causing a significant portion of the indebtedness under such a facility to become immediately due and payable or the ARLP Partnership's lenders' commitment to make further loans to it under such facility to terminate. The ARLP Partnership might not have, or be able to obtain, sufficient funds to make such payments.

The ARLP Partnership's payment of principal and interest on any future indebtedness will reduce its cash available for distribution on its units. In addition, any future levels of indebtedness may:

adversely affect the ARLP Partnership's ability to obtain additional financing for future operations or capital needs;

limit its ability to pursue acquisitions and other business opportunities; or

make its results of operations more susceptible to adverse economic or operating conditions.

Our unitholders do not elect our general partner or vote on our general partner's officers or directors. Units held by the Management Group (some of whom are current or former members of management) and their affiliates currently own 70.2% of our units, a sufficient number of our common units to block any attempt to remove our general partner.

Unlike the holders of common stock in a corporation, our unitholders have only limited voting rights on matters affecting our business and, therefore, limited ability to influence management's decisions regarding our business. Our unitholders do not have the ability to elect our general partner or the officers or directors of our general partner. The Board of Directors, including our independent directors, is chosen by the members of our general partner.

Furthermore, if our unitholders are dissatisfied with the performance of our general partner, they will have little ability to remove our general partner. Our general partner may not be removed except upon the vote of the holders of at least ~~2/3rds~~two thirds of our outstanding units. Because the Management Group (some of whom are current or former members of management) and their affiliates currently own 70.2% of our outstanding common units, it is not currently possible for our general partner to be removed without their consent. As a result, the price at which our units trade may be lower because of the absence or reduction of a takeover premium in the trading price.

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possible for our general partner to be removed without their consent. As a result, the price at which our units trade may be lower because of the absence or reduction of a takeover premium in the trading price.

We may issue an unlimited number of limited partner interests, on terms and conditions established by our general partner, without the consent of our unitholders, which will dilute your ownership interest in us and may increase the risk that we will not have sufficient available cash to maintain or increase our per unit distribution level.

The issuance by us of additional common units or other equity securities of equal or senior rank will have the following effects:

our unitholders' proportionate ownership interest in us will decrease;

the amount of cash available for distribution on each unit may decrease;

the relative voting strength of each previously outstanding unit may be diminished;

the ratio of taxable income to distributions may increase; and

the market price of our common units may decline.

The market price of our common units could be adversely affected by sales of substantial amounts of our common units in the public markets, including sales by our existing unitholders.

The Management Group and their affiliates currently own 70.2% of our units. Sales by any of our existing unitholders of a substantial number of our common units in the public markets could have a material adverse effect on the price of our common units or could impair our ability to obtain capital through an offering of equity securities. We do not know whether any such sales would be made in the public market or in private placements, nor do we know what impact such potential or actual sales would have on our unit price in the future.

26Control of our general partner may be transferred to a third party without unitholder consent.

~~Table~~Our general partner may transfer its general partner interest in us to a third party in a merger or in a sale of ~~Contents~~its equity securities without the consent of our unitholders. Furthermore, there is no restriction in our partnership agreement on the ability of the owner of our general partner to sell or transfer all or part of its ownership interest in our general partner to a third-party. The new owner or owners of our general partner would then be in a position to replace the directors and officers of our general partner and control the decisions made and actions taken by its board of directors and officers. In addition, the owner of our general partner controls MGP. Control of MGP can likewise be transferred to a third party without unitholder consent.

We do not know whether any such sales would be made in the public market or in private placements, nor do we know what impact such potential or actual sales would have on our unit price in the future.

Control of our general partner and the IDRs in ARLP may be transferred to a third party without unitholder consent.

Our general partner may transfer its general partner interest in us to a third party in a merger or in a sale of its equity securities without the consent of our unitholders. Furthermore, there is no restriction in our partnership agreement on the ability of the owner of our general partner to sell or transfer all or part of its ownership interest in our general partner to a third-party. The new owner or owners of our general partner would then be in a position to replace the directors and officers of our general partner and control the decisions made and actions taken by its board of directors and officers. In addition, the owner of our general partner controls MGP, the owner of the IDRs in ARLP. Control of MGP can likewise be transferred to a third party without unitholder consent.

Our ability to sell our partnership interests in ARLP may be limited by securities law restrictions and liquidity constraints.

Of the 3187,~~088~~188,338 common units of ARLP that we own, 1268,~~845~~945,062 common units are unregistered, restricted securities within the meaning of Rule 144 under the Securities Act. Unless we exercise our registration rights with respect to these common units, we are limited to selling into the market in any three-month period an amount of ARLP common units that does not exceed the greater of 1% of the total number of common units outstanding or the average weekly reported trading volume of the common units for the four calendar weeks prior to the sale. We face contractual limitations on our ability to sell our general partner interest ~~and IDRs~~, and the market for such interests is illiquid.

We depend on the leadership and involvement of Joseph W. Craft III and other key personnel for the success of our and ARLP's business.

We depend on the leadership and involvement of Mr. Craft, the Chairman, President and Chief Executive Officer of our general partner and a Director and President and Chief Executive Officer of ARLP's ~~managing~~ general partner. Mr. Craft has been integral to the success of ARLP and us, due in part to his ability to identify and develop internal growth projects and accretive acquisitions, make strategic decisions and attract and retain key personnel. The loss of his leadership and involvement or the services of any members of our or ARLP's senior management team could have a material adverse effect on our business, financial condition and results of operations and those of ARLP.

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Your liability as a limited partner may not be limited, and our unitholders may have to repay distributions or make additional contributions to us under certain circumstances.

As a limited partner in a partnership organized under Delaware law, you could be held liable for our obligations to the same extent as a general partner if you participate in the "control" of our business. Our general partner generally has unlimited liability for the obligations of the partnership, except for those contractual obligations of the partnership that are expressly made without recourse to our general partner. Additionally, the limitations on the liability of holders of limited partner interests for the obligations of a limited partnership have not been clearly established in many jurisdictions.

Under certain circumstances, our unitholders may have to repay amounts wrongfully distributed to them. Under Delaware law, neither we nor ARLP may make a distribution to our unitholders if the distribution would cause our or ARLP's respective liabilities to exceed the fair value of our respective assets. Delaware law provides that for a period of three years from the date of the impermissible distribution, partners who received the distribution and who knew at the time of the distribution that it violated Delaware law will be liable to the partnership for the distribution amount. Liabilities to partners on account of their partnership interest and liabilities that are non-recourse to the partnership are not counted for purposes of determining whether a distribution is permitted.

An increase in interest rates may cause the market price of our common units to decline.

Like all equity investments, an investment in our common units is subject to certain risks. In exchange for accepting these risks, investors may expect to receive a higher rate of return than would otherwise be obtainable from lower-risk investments. Accordingly, as interest rates rise, the ability of investors to obtain higher risk-adjusted rates of return by purchasing government-backed debt securities may cause a corresponding decline in demand for riskier investments generally, including yield-based equity investments such as publicly traded limited partnership interests. Reduced demand for our common units resulting from investors seeking other more favorable investment opportunities may cause the trading price of our common units to decline.

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lower-risk investments. Accordingly, as interest rates rise, the ability of investors to obtain higher risk-adjusted rates of return by purchasing government-backed debt securities may cause a corresponding decline in demand for riskier investments generally, including yield-based equity investments such as publicly traded limited partnership interests. Reduced demand for our common units resulting from investors seeking other more favorable investment opportunities may cause the trading price of our common units to decline.

If in the future we cease to manage and control ARLP, we may be deemed to be an investment company under the Investment Company Act of 1940.

If we cease to manage and control ARLP and are deemed to be an investment company under the Investment Company Act of 1940 because of our ownership of ARLP partnership interests, we would either have to register as an investment company under the Investment Company Act, obtain exemptive relief from the SEC or modify our organizational structure or our contract rights to fall outside the definition of an investment company. Registering as an investment company could, among other things, materially limit our ability to engage in transactions with affiliates, including the purchase and sale of certain securities or other property to or from our affiliates, restrict our ability to borrow funds or engage in other transactions involving leverage and require us to add additional directors who are independent of us or our affiliates.

The price of our common units may be volatile, and the trading market for our common units may not provide you with adequate liquidity.

The market price of our common units could be subject to significant fluctuations. Factors that could affect our common unit price include:

ARLP's operating and financial performance and prospects;

quarterly variations in the rate of growth of our financial indicators, such as net income and revenues;

changes in revenue or earnings estimates or publication of research reports by analysts;

the current economic downturn;

the price of coal and expectations for the future of the coal industry;

speculation by the press or investment community;

sales of our common units by our unitholders;

actions by our existing unitholders prior to their disposition of our common units;

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announcements by ARLP or its competitors of significant contracts, acquisitions, strategic partnerships, joint ventures, securities offerings or capital commitments;

general market conditions; and

domestic and international economic, legal and regulatory factors related to ARLP's performance.

The equity markets in general are subject to volatility that may be unrelated to the operating performance of particular companies. These broad market fluctuations may adversely affect the trading price of our common units. In addition, potential investors may be deterred from investing in our common units for various reasons, including the very limited number of publicly traded entities whose assets consist almost exclusively of partnership interests in a publicly traded partnership. The lack of liquidity may also contribute to significant fluctuations in the market price of our common units and limit the number of investors who are able to buy our common units.

Our common units and ARLP's common units may not trade in simple relation or proportion to one another. Instead, the trading prices may diverge because, among other things:, we may enter into other businesses separate and apart from ARLP or any of its affiliates.

· ARLP's cash distributions to its common unitholders have a priority over distributions on its IDRs;

· we participate in the IDRs in ARLP, while ARLP's common unitholders do not; and

· we may enter into other businesses separate and apart from ARLP or any of its affiliates.

Our partnership agreement restricts the rights of unitholders owning 20% or more of our units.

Our unitholders' voting rights are restricted by the provision in our partnership agreement generally providing that any units held by a person that owns 20% or more of any class of units then outstanding, other than our general partner, its affiliates, their transferees and persons who acquired such units with the prior approval of the Board of Directors, cannot be voted on any matter. In addition, our partnership agreement contains provisions limiting the ability of our unitholders to call meetings or to acquire information about our operations, as well as other provisions limiting our unitholders' ability to influence the manner or direction of our management. As a result, the price at which our common units will trade may be lower because of the absence or reduction of a takeover premium in the trading price.

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partner, its affiliates, their transferees and persons who acquired such units with the prior approval of the Board of Directors, cannot be voted on any matter. In addition, our partnership agreement contains provisions limiting the ability of our unitholders to call meetings or to acquire information about our operations, as well as other provisions limiting our unitholders' ability to influence the manner or direction of our management. As a result, the price at which our common units will trade may be lower because of the absence or reduction of a takeover premium in the trading price.

ARLP may issue additional units, which may increase the risk that ARLP will not have sufficient available cash to maintain or increase its per unit distribution level.

ARLP has wide latitude to issue additional units on terms and conditions established by MGP, including units that rank senior to the ARLP common units ~~and the IDRs~~ as to quarterly cash distributions. The payment of distributions on those additional units may increase the risk that ARLP may not have sufficient cash available to maintain or increase its per unit distribution level, which in turn may impact the available cash that we have to distribute to our unitholders. To the extent these units are senior to the common units ~~or the IDRs~~, there is an increased risk that we will not receive the same level or increased distributions on the common units ~~and IDRs~~. ~~Neither~~The ~~the~~ common units ~~nor the IDRs~~ are not entitled to any arrearages from prior quarters.

Risks Related to Conflicts of Interest

Conflicts of interest exist and may arise in the future among us, ARLP and our respective general partners and affiliates. Future conflicts of interest may arise among us and the entities affiliated with any general partner interests we acquire or among ARLP and such entities. For a further discussion of conflicts of interest that may arise, please read "Item 13. Certain Relationships and Related-Party Transactions, and Director Independence."

Although we control ARLP through our ownership of ARLP's ~~managing~~ general partner, ARLP's ~~managing~~ general partner owes fiduciary duties to ARLP and ARLP's unitholders, which may conflict with our interests.

Conflicts of interest exist and may arise in the future as a result of the relationships between us and our affiliates, including ARLP's ~~managing~~ general partner, on the one hand, and ARLP and its limited partners, on the other hand. The directors and officers of ARLP's ~~managing~~ general partner have fiduciary duties to manage ARLP in a manner beneficial to us, its owner. At the same time, ARLP's ~~managing~~ general partner has a fiduciary duty to manage ARLP in a manner beneficial to ARLP and its limited partners. The MGP Board of Directors will resolve any such conflict and has broad latitude to consider the interests of all parties to the conflict. The resolution of these conflicts may not always be in our best interest or that of our unitholders.

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For example, conflicts of interest may arise in the following situations:

the allocation of shared overhead expenses to ARLP and us;

the interpretation and enforcement of contractual obligations between us and our affiliates, on the one hand, and ARLP, on the other hand;

the determination and timing of the amount of cash to be distributed to ARLP's partners and the amount of cash to be reserved for the future conduct of ARLP's business;

the decision as to whether ARLP should make acquisitions, and on what terms;

the determination of whether ARLP should use cash on hand, borrow or issue equity to raise cash to finance acquisition or expansion capital projects, repay indebtedness, meet working capital needs, pay distributions to ARLP's partners or otherwise; and

any decision we make in the future to engage in business activities independent of, or in competition with, ARLP.

The fiduciary duties of our general partner's officers and directors may conflict with those of ARLP's general partner's officers and directors.

Our general partner's officers and directors have fiduciary duties to manage our business in a manner beneficial to us and our partners. However, all of our general partner's executive officers also serve as executive officers of MGP. In addition, our general partner's non-independent director and one of our independent directors also serve as directors of MGP. As a result, these executive officers and directors have fiduciary duties to manage the business of ARLP in a manner beneficial to ARLP and its partners. Consequently, these directors and officers may encounter situations in which their fiduciary obligations to ARLP, on one hand, and us, on the other hand, are in conflict. The resolution of these conflicts may not always be in our best interest or that of our unitholders.

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MGP. In addition, our general partner's non-independent director and one of our independent directors also serve as directors of MGP. As a result, these executive officers and directors have fiduciary duties to manage the business of ARLP in a manner beneficial to ARLP and its partners. Consequently, these directors and officers may encounter situations in which their fiduciary obligations to ARLP, on one hand, and us, on the other hand, are in conflict. The resolution of these conflicts may not always be in our best interest or that of our unitholders.

If we are presented with certain business opportunities, ARLP will have the first right to pursue such opportunities.

Pursuant to an agreement among ARLP, SGP, MGP, MGP II, ARH, ARH II, our general partner and us, among others, (referred to as the omnibus agreement), we have agreed to certain business opportunity arrangements to address potential conflicts that may arise between us and ARLP. If a business opportunity in respect of any coal mining, marketing and transportation assets is presented to us, our general partner, ARLP or its general ~~partners~~partner, then ARLP will have the first right to acquire such assets. The omnibus agreement provides, among other things, that ARLP will be presumed to desire to acquire the assets until such time as it advises us that it has abandoned the pursuit of such business opportunity, and we may not pursue the acquisition of such assets prior to that time.

ARLP and affiliates of our general partner are not limited in their ability to compete with us, which could cause conflicts of interest and limit our ability to acquire additional assets or businesses which in turn could adversely affect our results of operations and cash available for distribution to our unitholders.

Neither our partnership agreement nor the omnibus agreement prohibits ARLP or affiliates of our general partner from owning assets or engaging in businesses that compete directly or indirectly with us or one another. In addition, ARLP and its affiliates or affiliates of our general partner, may acquire, construct or dispose of additional assets related to the mining, marketing and transportation of coal or other assets in the future, without any obligation to offer us the opportunity to purchase or construct any of those assets. As a result, competition among these entities could adversely impact ARLP's or our results of operations and cash available for distribution.

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Potential conflicts of interest may arise among our general partner, its affiliates and us. Our general partner and its affiliates have limited fiduciary duties to us and our unitholders, which may permit them to favor their own interests to the detriment of us and our unitholders.

Conflicts of interest may arise among our general partner and its affiliates, on the one hand, and us and our unitholders, on the other hand. As a result of these conflicts, our general partner may favor its own interests and the interests of its affiliates over the interests of our unitholders. These conflicts include, among others, the following:

Our general partner is allowed to take into account the interests of parties other than us, including ARLP and its affiliates and any other businesses acquired in the future, in resolving conflicts of interest, which has the effect of limiting its fiduciary duty to our unitholders.

Our general partner has limited its liability and reduced its fiduciary duties under the terms of our partnership agreement, while also restricting the remedies available to our unitholders for actions that, without these limitations, might constitute breaches of fiduciary duties. As a result of purchasing our units, unitholders consent to various actions and conflicts of interest that might otherwise constitute a breach of fiduciary or other duties under applicable state law.

Our general partner determines the amount and timing of our investment transactions, borrowings, issuances of additional partnership securities and reserves, each of which can affect the amount of cash that is available for distribution to our unitholders.

Our general partner determines which costs incurred by it and its affiliates are reimbursable by us.

Our partnership agreement does not restrict our general partner from causing us to pay it or its affiliates for any services rendered, or from entering into additional contractual arrangements with any of these entities on our behalf, so long as the terms of any such payments or additional contractual arrangements are fair and reasonable to us.

Our general partner controls the enforcement of obligations owed to us by it and its affiliates.

Our general partner decides whether to retain separate counsel, accountants or others to perform services for us.

30The president and chief executive officer of both our general partner and ARLP's general partner effectively controls us and ARLP through his control of our general partner and ARLP's general partner.

~~Table~~Mr. Craft, the president and chief executive officer of ~~Contents~~both our general partner and ARLP's general partner, controls ARLP's general partner, indirectly jointly owns SGP and owns or controls 66.7% of ARLP's common units. Mr. Craft also currently holds, directly or indirectly or may be deemed to be the beneficial owner of, 68.7% of our common units. These interests give Mr. Craft substantial control over our and ARLP's business and operations and the ability to control the outcome of many matters that require unitholder approval. Mr. Craft is not restricted from disposing of all or a part of his equity interests in our general partner, in ARLP's general partner or in ARLP's special general partner.

The president and chief executive officer of both our general partner and ARLP's managing general partner effectively controls us and ARLP through his control of our general partner and ARLP's managing general partner.

Mr. Craft, the president and chief executive officer of both our general partner and ARLP's managing general partner, controls ARLP's managing general partner, indirectly jointly owns SGP and owns or controls 42.2% of ARLP's common units. Mr. Craft also currently holds, directly or indirectly or may be deemed to be the beneficial owner of, 68.7% of our common units. These interests give Mr. Craft substantial control over our and ARLP's business and operations and the ability to control the outcome of many matters that require unitholder approval. Mr. Craft is not restricted from disposing of all or a part of his equity interests in our general partner, in ARLP's managing general partner or in ARLP's special general partner.

Our partnership agreement limits our general partner's fiduciary duties to us and our unitholders and restricts the remedies available to our unitholders for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty.

Our partnership agreement contains provisions that reduce the standards to which our general partner would otherwise be held by state fiduciary duty law. For example, our partnership agreement:

permits our general partner to make a number of decisions in its individual capacity, as opposed to in its capacity as our general partner. This entitles our general partner to consider only the interests and factors that it desires, and it has no duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates or any limited partner. Examples include the exercise of its limited call right, its voting rights with respect to the units it owns, its registration rights and its determination whether or not to consent to any merger or consolidation of our partnership or amendment to our partnership agreement;

provides that our general partner will not have any liability to us or our unitholders for decisions made in its capacity as a general partner so long as it acted in good faith, meaning it believed the decisions were in the best interests of our partnership;

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generally provides that affiliated transactions and resolutions of conflicts of interest not approved by the audit and conflicts committee of the Board of Directors and not involving a vote of unitholders must be on terms no less favorable to us than those generally being provided to or available from unrelated third-parties or be "fair and reasonable" to us and that, in determining whether a transaction or resolution is "fair and reasonable," our general partner may consider the totality of the relationships among the parties involved, including other transactions that may be particularly advantageous or beneficial to us;

provides that in resolving conflicts of interest, it will be presumed that in making its decision our general partner acted in good faith, and in any proceeding brought by or on behalf of any limited partner or us, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption; and

provides that our general partner and its officers and directors will not be liable for monetary damages to us, our limited partners or assignees for any acts or omissions unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that the general partner or those other persons acted in bad faith or engaged in fraud or willful misconduct or, in the case of a criminal matter, acted with knowledge that such person's conduct was criminal.

In becoming a limited partner of our partnership, a common unitholder is bound by the provisions in the partnership agreement, including the provisions discussed above.

Our general partner has a limited call right that may require you to sell your units at an undesirable time or price.

If at any time our general partner and its affiliates own more than 85% of our outstanding units, our general partner will have the right, but not the obligation, which it may assign to any of its affiliates or to us, to acquire all, but not less than all, of the units held by unaffiliated persons at a price not less than their then-current market price. As a result, you may be required to sell your units at an undesirable time or price and may not receive any return on your investment. You may also incur a tax liability upon a sale of your units.

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Risks Related to ARLP's Business

Because our cash flow consists exclusively of distributions from ARLP, risks to the ARLP Partnership's business are also risks to us. We have set forth below many of the risks to ARLP's business or results of operations, the occurrence of which could negatively impact the ARLP Partnership's financial performance and decrease the amount of cash it is able to distribute to us, thereby decreasing the amount of cash we have available for distribution to our unitholders.

Global economic conditions or economic conditions in any of the industries in which the ARLP Partnership customers operate as well as sustained uncertainty in financial markets may have material adverse impacts on its business and financial condition that it currently cannot predict.

Weakness in global economic conditions or economic conditions in any of the industries the ARLP Partnership serves or in the financial markets could materially adversely affect the ARLP Partnership's business and financial condition. For example:

· the demand for electricity in the U.S. and globally may decline if economic conditions deteriorate, which may negatively impact the revenues, margins and profitability of the ARLP Partnership's business;

any inability of the ARLP Partnership's customers to raise capital could adversely affect its ability to honor its obligations to us; and

ARLP Partnership's future ability to access the capital markets may be restricted as a result of future economic conditions, which could materially impact the ARLP Partnership's ability to grow its business, including development of its coal reserves.

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A substantial or extended decline in coal prices could negatively impact the ARLP Partnership's results of operations.

The ARLP Partnership's results of operations are primarily dependent upon the prices it receives for its coal, as well as its ability to improve productivity and control costs. The prices the ARLP Partnership receives for its production depends upon factors beyond the ARLP Partnership's control, including:

the supply of and demand for domestic and foreign coal;

weather conditions and patterns that affect demand for, or ability to produce, coal;

the proximity to and capacity of transportation facilities;

competition from other coal suppliers;

domestic and foreign governmental regulations and taxes;

the price and availability of alternative fuels;

the effect of worldwide energy consumption including the impact of technological advances on energy consumption; and

prevailing economic conditions.

Any adverse change in these factors could result in weaker demand and lower prices for the ARLP Partnership's products. A substantial or extended decline in coal prices could materially and adversely affect the ARLP Partnership by decreasing its revenues to the extent that it is not protected by the terms of existing coal supply agreements.

Competition within the coal industry may adversely affect the ARLP Partnership's ability to sell coal, and excess production capacity in the industry could put downward pressure on coal prices.

The ARLP Partnership competes with other coal producers in various regions of the U.S. for domestic coal sales. In addition, we face competition from foreign and domestic producers that sell their coal in the international coal markets. The most important factors on which the ARLP Partnership competes are delivered price (i.e., the cost of coal delivered to the customer, including transportation costs, which are generally paid by customers either directly or indirectly), coal quality characteristics, contract flexibility (e.g., volume optionality and multiple supply sources) and reliability of supply. Some competitors may have, among other things, larger financial and operating resources, lower per ton cost of production, or relationships with specific transportation providers. The competition among coal producers may impact the ARLP Partnership's ability to retain or attract customers and could adversely impact revenues and cash available for distribution. In addition, declining prices from an oversupply of coal in the market could reduce revenues and cash available for distribution.

Changes in consumption patterns by utilities regarding the use of coal have affected the ARLP Partnership's ability to sell the coal it produces.

According to the most recent information from the Energy Information Administration, since 2000, coal's share of U.S. electricity production has fallen from 53% to 30%, while natural gas' share has increased from 16% to 33%.

The domestic electric utility industry accounts for over 93.0% of domestic coal consumption. The amount of coal consumed by the domestic electric utility industry is affected primarily by the overall demand for electricity, environmental and other governmental regulations, and the price and availability of competing fuels for power plants such as nuclear, natural gas and fuel oil as well as alternative sources of energy. Gas-fueled generation has the potential to displace coal-fueled generation, particularly from older, less efficient coal-powered generators. The ARLP Partnership expects that many of the new power plants needed in the U.S. to meet increasing demand for electricity generation will be fueled by natural gas because gas-fired plants are cheaper to construct and permits to construct these plants are easier to obtain.

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~~revenues~~rely ~~and~~on ~~cash~~renewable ~~available~~energy ~~for~~sources ~~distribution~~in generating a certain percentage of power. InSuch ~~addition~~mandates, ~~declining~~combined ~~prices~~with ~~from~~other anincentives ~~oversupply~~to ofuse renewable energy sources, such as tax credits, could make alternative fuel sources more competitive with coal. A decrease in coal consumption by the ~~market~~domestic electric utility industry could ~~reduce~~adversely ~~revenues~~affect the price of coal, which could negatively impact the ARLP Partnership's results of operations and reduce its cash available for distribution to us.

Changes in consumption patterns by utilities regarding the use of coal have affected the ARLP Partnership's ability to sell the coal it produces. Since 2000, coal's share of U.S. electricity production has fallen from 53% to 30%, while natural gas' share has increased from 16% to 34%.

The domestic electric utility industry accounts for over 92.0% of domestic coal consumption. The amount of coal consumed by the domestic electric utility industry is affected primarily by the overall demand for electricity, environmental and other governmental regulations, and the price and availability of competing fuels for power plants such as nuclear, natural gas and fuel oil as well as alternative sources of energy. Gas-fueled generation has the potential to displace coal-fueled generation, particularly from older, less efficient coal-powered generators. The ARLP Partnership expects that many of the new power plants needed in the U.S. to meet increasing demand for electricity generation will be fueled by natural gas because gas-fired plants are cheaper to construct and permits to construct these plants are easier to obtain.

Future environmental regulation of GHG emissions also could accelerate the use by utilities of fuels other than coal. In addition, state and federal mandates for increased use of electricity derived from renewable energy sources could affect demand for coal. For example, the EPA's CPP could likely incentivize additional electric generation from natural gas and renewable sources, and Congress has extended tax credits for renewables. In addition, a number of states have enacted mandates that require electricity suppliers to rely on renewable energy sources in generating a certain percentage of power. Such mandates, combined with other incentives to use renewable energy sources, such as tax credits, could make alternative fuel sources more competitive with coal. A decrease in coal consumption by the domestic electric utility industry could adversely affect the price of coal, which could negatively impact the ARLP Partnership's results of operations and reduce its cash available for distribution to us.

Extensive environmental laws and regulations affect coal consumers, and have corresponding effects on the demand for coal as a fuel source.

Federal, state and local laws and regulations extensively regulate the amount of sulfur dioxide, particulate matter, nitrogen oxides, mercury and other compounds emitted into the air from coal-fired electric power plants, which are the ultimate consumers of much of the ARLP Partnership's coal. These laws and regulations can require significant emission control expenditures for many coal-fired power plants, and various new and proposed laws and regulations may require further emission reductions and associated emission control expenditures. These laws and regulations may affect demand and prices for coal. There is also continuing pressure on state and federal regulators to impose limits on carbon dioxide emissions from electric power plants, particularly coal-fired power plants. Further, far-reaching federal regulations promulgated by the EPA in the last several years, such as CSAPR and MATS, have led to the premature retirement of coal-fired generating units and a significant reduction in the amount of coal-fired generating capacity in the U.S. At former President Obama's direction the EPA proposed CO2 emissions requirements, known as the CPP, for existing and modified power plants and published such rules on October 23, 2015. As a result of these current and proposed laws, regulations and regulatory initiatives, electricity generators may elect to switch to other fuels that generate less of these emissions or by-products, further reducing demand for coal. Please read "Item 1. Business—Regulation and Laws—Air Emissions," "—Carbon Dioxide Emissions" and "—Hazardous Substances and Wastes."

Increased regulation of GHG emissions could result in increased operating costs and reduced demand for coal as a fuel source, which could reduce demand for the ARLP Partnership's products, decrease its revenues and reduce its profitability.

Combustion of fossil fuels, such as the coal the ARLP Partnership produces, results in the emission of carbon dioxide into the atmosphere. On December 15, 2009, the EPA published the Endangerment Finding asserting that emissions of carbon dioxide and other GHGs present an endangerment to public health and the environment, and the EPA has begun to regulate GHG emissions pursuant to the CAA. The EPA ~~has~~previously finalized aan ~~rule~~ NSPS to regulate GHG emissions from new power plants, however, the EPA published notice in the federal register in April 2017 that the agency has initiated a review of the NSPS for new and modified fossil fuel fired power plants and that, following the review, the EPA will initiate reconsideration proceedings to suspend, revise or rescind this NSPS. The finalized standard requires CCS, a technology that is not yet commercially feasible without government subsidies and that has not been demonstrated in the marketplace. This requirement, to the extent implemented as originally finalized, effectively prevents construction of new coal fired power plants. In August 2015, the EPA ~~finalized~~issued its final CPP rules that establish carbon pollution standards for existing power plants, called CO2 emission performance rates. Judicial challenges led the U.S. Supreme Court to grant a stay in February 2016 of the implementation of the CPP before the Circuit Court even issued a decision. By its terms, this stay will remain in effect throughout the pendency of the appeals process including at the Circuit Court and the Supreme Court through any certiorari petition that may be granted. The Supreme Court's stay applies only to EPA's regulations for CO2 emissions from existing power plants and will not affect EPA's standards for new power plants. It is not yet clear how either the Circuit Court or the Supreme Court will rule on the legality of the CPP. Additionally, in October 2017 EPA proposed to repeal the CPP, although the final outcome of this action and the pending litigation regarding the CPP is uncertain at this time. In connection with this proposed repeal, EPA issued an ANPRM in December 2017 regarding emission guidelines to limit GHG emissions from existing electricity utility generating units. The ANPRM seeks comment regarding what the EPA should include in a potential new, existing-source regulation under the Clean Air Act of GHG emissions from electric utility generating units that it may propose. If the effort to repeal the rules is unsuccessful and the rules were upheld at the conclusion of this appellate process and were implemented in their current form, or if the ANPRM results in a different proposal to control GHG emissions from electric utility generating units, demand for coal would likely be further decreased, potentially significantly, and our business would be adversely impacted. Please read "Item 1. Business—Regulation and Laws—Air Emissions" and "—Carbon Dioxide Emissions."

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regulations for modified and existing power plants. The rule for modified sources requires reducing GHG emissions from any modified or reconstructed source and could limit the ability of generators to upgrade coal-fired power plants thereby reducing the demand for coal. The rule for existing sources proposes to establish different target emission rates (lbs per megawatt hour) for each state and has an overall goal to achieve a 32% reduction of carbon dioxide emissions from 2005 levels by 2030. If upheld by courts, the regulation could lead to premature retirements of coal-fired electric generating units and significantly reduce the demand for coal. In addition, many states and regions have adopted GHG initiatives. Also, there have been numerous protests of, and challenges to, the permitting of new coal-fired power plants by environmental organizations and state regulators due to concerns related to GHG emissions. Please read "Item 1. Business—Regulation and Laws—Air Emissions" and "—Carbon Dioxide Emissions."

Numerous political and regulatory authorities and governmental bodies, as well as environmental activist groups, are devoting substantial resources to anti-coal activities to minimize or eliminate the use of coal as a source of electricity generation, domestically and internationally, thereby further reducing the demand and pricing for coal and potentially materially and adversely impacting the ARLP Partnership's future financial results, liquidity and growth prospects.

Concerns about the environmental impacts of coal combustion, including perceived impacts on global climate issues, are resulting in increased regulation of coal combustion in many jurisdictions, unfavorable lending policies by lending institutions and divestment efforts affecting the investment community, which could significantly affect demand for the ARLP Partnership's products or its securities. Global climate issues continue to attract public and scientific attention. Some scientists have concluded that increasing concentrations of GHGs in the Earth's atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts and floods and other climatic events. Numerous reports, such as the Fourth and Fifth Assessment Report of the Intergovernmental Panel on Climate Change, have also engendered concern about the impacts of human activity, especially fossil fuel combustion, on global climate issues. In turn, increasing government attention is being paid to global climate issues and to emissions of GHGs, including emissions of carbon dioxide from coal combustion by power plants.

Federal, state and local governments may pass laws mandating the use of alternative energy sources, such as wind power and solar energy, which may decrease demand for the ARLP Partnership's coal products. The CPP is one of a number of recent developments aimed at limiting GHG emissions which could limit the market for some of the ARLP Partnership's products by encouraging electric generation from sources that do not generate the same amount of GHG emissions. Enactment of laws or passage of regulations regarding emissions from the combustion of coal by the U.S., states, or other countries, could also result in electricity generators further switching from coal to other fuel sources or additional coal-fueled power plant closures. For example, the agreement resulting from the 2015 U.N. Framework Convention on Climate Change contains voluntary commitments by numerous countries to reduce their GHG emissions, and could result in additional firm commitments by various nations with respect to future GHG emissions. These commitments could further disfavor coal-fired generation, particularly in the medium- to long-term.

Congress has extended certain tax credits for renewable sources of electric generation, which will increase the ability of these sources to compete with the ARLP Partnership's coal products in the market. In addition, the DOI recently announced a moratorium on issuing certain new coal leases on federal land while the Bureau of Land Management undertakes a programmatic review of the federal coal program. While none of the ARLP Partnership's operations are located on federal lands impacted by this moratorium, it does signal increased attention at the federal level to coal mining practices and the GHG emissions resulting from coal combustion.

There have also been efforts in recent years affecting the investment community, including investment advisors, sovereign wealth funds, public pension funds, universities and other groups, promoting the divestment of fossil fuel equities and also pressuring lenders to limit funding to companies engaged in the extraction of fossil fuel reserves. In California, for example, legislation was signed into law in October 2015 that requires California's state pension funds to divest investments in companies that generate 50% or more of their revenue from coal mining by July 2017. Other activist campaigns have urged banks to cease financing coal-driven businesses. As a result, several major banks have enacted such policies. The impact of such efforts may adversely affect the demand for and price of securities issued by the ARLP Partnership, and impact its access to the capital and financial markets.

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In addition, several well-funded non-governmental organizations have explicitly undertaken campaigns to minimize or eliminate the use of coal as a source of electricity generation. Collectively, these actions and campaigns could adversely impact the ARLP Partnership's future financial results, liquidity and growth prospects.

Government regulations have resulted and could continue to result in significant retirements of coal-fired electric generating units. Retirements of coal-fired electric generating units decrease the overall capacity to burn coal and negatively impact coal demand.

Since 2010, utilities have formally announced the retirement or conversion of ~~558~~more than 600 coal-fired electric generating units through 2030. These retirements and conversions amount to ~~over~~nearly 93111,000 megawatts ("MW") or almost 3035% of the 2010 total coal electric generating capacity. At the end of ~~2016~~2017 retirement and conversions affecting 6069,000 MW, or approximately 1922% of the 2010 total coal electric generating capacity, are estimated to have occurred. Most of these announced and completed retirements and conversions have been attributed to the EPA regulations, although other factors such as an aging coal fleet and low natural gas prices have also played a role. The reduction in coal electric capacity negatively impacts overall coal demand. Additional regulations and other factors could lead to additional retirements and conversions and, thereby, additional reductions in the demand for coal.

~~Plaintiffs in federal court litigation have attempted to pursue tort claims based on the alleged effects of climate change.~~34

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We or our customers could be subject to tort claims based on the alleged effects of climate change.

In 2004, eight states and New York City sued five electric utility companies in Connecticut v. American Electric Power Co. Invoking the federal and state common law of public nuisance, plaintiffs sought an injunction requiring defendants to abate their contribution to the nuisance of climate change by capping carbon dioxide emissions and then reducing them. In June 2011, the U.S. Supreme Court issued a unanimous decision holding that the plaintiffs' federal common law claims were displaced by federal legislation and regulations. The U.S. Supreme Court did not address the plaintiffs' state law tort claims and remanded the issue of preemption for the district court to consider. While the U.S. Supreme Court held that federal common law provides no basis for public nuisance claims against utilities due to their carbon dioxide emissions, tort-type liabilities remain a possibility and a source of concern. Proliferation of successful climate change litigation could adversely impact demand for coal and ultimately have a material adverse effect on our business, financial condition and results of operations.

The stability and profitability of the ARLP Partnership's operations could be adversely affected if its customers do not honor existing contracts or do not extend existing or enter into new long-term contracts for coal.

In ~~2016~~2017, the ARLP Partnership sold approximately 8771.7% of its sales tonnage under contracts having a term greater than one year, which the ARLP Partnership refers to as long-term contracts. Long-term sales contracts have historically provided a relatively secure market for the amount of production committed under the terms of the contracts. From time to time industry conditions may make it more difficult for the ARLP Partnership to enter into long-term contracts with its electric utility customers, and if supply exceeds demand in the coal industry, electric utilities may become less willing to lock in price or quantity commitments for an extended period of time. Accordingly, the ARLP Partnership may not be able to continue to obtain long-term sales contracts with reliable customers as existing contracts expire, which could subject a portion of the ARLP Partnership's revenue stream to the increased volatility of the spot market.

The ARLP Partnership's business can be negatively impacted by customers refusing to honor existing contracts. For example, the ARLP Partnership initiated litigation on January 15, 2015 alleging that a customer anticipatorily breached a coal supply contract when it notified the ARLP Partnership that it would not accept coal shipments under the contract after April 15, 2015. See "Item 3. Legal Proceedings."

Some of the ARLP Partnership's long-term coal sales contracts contain provisions allowing for the renegotiation of prices and, in some instances, the termination of the contract or the suspension of purchases by customers.

Some of the ARLP Partnership's long-term contracts contain provisions that allow for the purchase price to be renegotiated at periodic intervals. These price reopener provisions may automatically set a new price based on the prevailing market price or, in some instances, require the parties to the contract to agree on a new price. Any adjustment or renegotiation leading to a significantly lower contract price could adversely affect the ARLP Partnership's operating profit margins. Accordingly, long-term contracts may provide only limited protection during adverse market conditions. In some circumstances, failure of the parties to agree on a price under a reopener provision can also lead to early termination of a contract.

Several of the ARLP Partnership's long-term contracts also contain provisions that allow the customer to suspend or terminate performance under the contract upon the occurrence or continuation of certain events that are beyond the customer's reasonable control. Such events may include labor disputes, mechanical malfunctions and changes in government regulations, including changes in environmental regulations rendering use of the ARLP Partnership's coal inconsistent with the customer's environmental compliance strategies. Additionally, most of the ARLP Partnership's long-term contracts contain provisions requiring it to deliver coal within stated ranges for specific coal characteristics. Failure to meet these specifications can result in economic penalties, rejection or suspension of shipments or termination of the contracts. In the event of early termination of any of the ARLP Partnership's long-term contracts, if it is unable to enter into new contracts on similar terms, its business, financial condition and results of operations could be adversely affected.

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Partnership's operating profit margins. Accordingly, long-term contracts may provide only limited protection during adverse market conditions. In some circumstances, failure of the parties to agree on a price under a reopener provision can also lead to early termination of a contract.

The ARLP Partnership depends on a few customers for a significant portion of its revenues, and the loss of one or more significant customers could affect its ability to maintain the sales volume and price of the coal it produces.

~~During~~While ~~2016,~~ the ARLP Partnership ~~derived~~did ~~approximately~~not ~~39.4%~~have ofcustomers ~~its total revenues~~ from ~~three~~which ~~customers~~they ~~and~~derived ~~at least~~ 10.0% ofor ~~its~~more ~~2016~~of ~~total~~their ~~revenues~~revenue ~~from~~in ~~each~~2017, ofif the ~~three. If the~~ ARLP Partnership were to lose any of ~~these~~its significant customers without finding replacement customers willing to purchase an equivalent amount of coal on similar terms, or if these customers were to decrease the amounts of coal purchased or the terms, including pricing terms, on which they buy coal from the ARLP Partnership, it could have a material adverse effect on the ARLP Partnership's business, financial condition and results of operations.

Litigation resulting from disputes with the ARLP Partnership's customers may result in substantial costs, liabilities and loss of revenues.

From time to time the ARLP Partnership has disputes with its customers over the provisions of long-term coal supply contracts relating to, among other things, coal pricing, quality, quantity and the existence of specified conditions beyond the ARLP Partnership or its customers control that suspend performance obligations under the particular contract. Disputes may occur in the future and the ARLP Partnership may not be able to resolve those disputes in a satisfactory manner, which could have a material adverse effect on the ARLP Partnership's business, financial condition and results of operations. See "Item 3. Legal Proceedings."

The ARLP Partnership's ability to collect payments from its customers could be impaired if their creditworthiness declines or if they fail to honor their contracts with the ARLP Partnership.

The ARLP Partnership's ability to receive payment for coal sold and delivered depends on the continued creditworthiness of its customers. If the creditworthiness of its customers declines significantly, its business could be adversely affected. In addition, if a customer refuses to accept shipments of the ARLP Partnership's coal for which they have an existing contractual obligation, the ARLP Partnership's revenues will decrease and it may have to reduce production at its mines until its customer's contractual obligations are honored. See "Item 3. Legal Proceedings."

The ARLP Partnership's profitability may decline due to unanticipated mine operating conditions and other events that are not within its control and that may not be fully covered under its insurance policies.

The ARLP Partnership's mining operations are influenced by changing conditions or events that can affect production levels and costs at particular mines for varying lengths of time and, as a result, can diminish its profitability.

These conditions and events include, among others:

mining and processing equipment failures and unexpected maintenance problems;

unavailability of required equipment;

prices for fuel, steel, explosives and other supplies;

fines and penalties incurred as a result of alleged violations of environmental and safety laws and regulations;

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variations in thickness of the layer, or seam, of coal;

amounts of overburden, partings, rock and other natural materials;

weather conditions, such as heavy rains, flooding, ice and other natural events affecting operations, transportation or customers;

accidental mine water discharges and other geological conditions;

fires;

seismic activities, ground failures, rock bursts or structural cave-ins or slides;

employee injuries or fatalities;

labor-related interruptions;

increased reclamation costs;

inability to acquire, maintain or renew mining rights or permits in a timely manner, if at all;

fluctuations in transportation costs and the availability or reliability of transportation; and

unexpected operational interruptions due to other factors.

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These conditions have the potential to significantly impact the ARLP Partnership's operating results. Prolonged disruption of production at any of the ARLP Partnership's mines would result in a decrease in its revenues and profitability, which could materially adversely impact its quarterly or annual results.

Effective October 1, ~~2016~~2017, the ARLP Partnership renewed its annual property and casualty insurance program. The ARLP Partnership's property insurance was procured from its wholly owned captive insurance company, Wildcat Insurance, LLC ("Wildcat Insurance").

Wildcat Insurance charged certain of the ARLP Partnership's subsidiaries for the premiums on this program and in return purchased reinsurance for the program in the standard market at a reduced cost. 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 a $10.0 million overall aggregate deductible. The ARLP Partnership can make no assurances that it will not experience significant insurance claims in the future that could have a material adverse effect on its business, financial condition, results of operations and ability to purchase property insurance in the future.

Although none of the ARLP Partnership's employees are members of unions, its work force may not remain union-free in the future.

None of the ARLP Partnership's employees are represented under collective bargaining agreements. However, all of its work force may not remain union-free in the future, and legislative, regulatory or other governmental action could make it more difficult to remain union-free. If some or all of the ARLP Partnership's currently union-free operations were to become unionized, it could adversely affect its productivity and increase the risk of work stoppages at its mining complexes. In addition, even if the ARLP Partnership remains union-free, its operations may still be adversely affected by work stoppages at unionized companies, particularly if union workers were to orchestrate boycotts against the ARLP Partnership's operations.

The ARLP Partnership's mining operations are subject to extensive and costly laws and regulations, and such current and future laws and regulations could increase current operating costs or limit the ARLP Partnership's ability to produce coal.

The ARLP Partnership is subject to numerous federal, state and local laws and regulations affecting the coal mining industry, including laws and regulations pertaining to employee health and safety, permitting and licensing requirements, air and water quality standards, plant and wildlife protection, reclamation and restoration of mining properties after mining is completed, the discharge or release of materials into the environment, surface subsidence from underground mining and the effects that mining has on groundwater quality and availability. Certain of these laws and regulations may impose strict liability without regard to fault or legality of the original conduct. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, the imposition of remedial liabilities, and the issuance of injunctions limiting or prohibiting the performance of operations. Complying with these laws and regulations may be costly and time consuming and may delay commencement or continuation of exploration or production operations. The possibility exists that new laws or regulations may be adopted, or that judicial interpretations or more stringent enforcement of existing laws and regulations may occur, which could materially affect the ARLP Partnership's mining operations, cash flow, and profitability, either through direct impacts on the ARLP Partnership's mining operations, or indirect impacts that discourage or limit the ARLP Partnership's customers' use of coal. Please read "Item 1. Business—Regulations and Laws."

State and federal laws addressing mine safety practices impose stringent reporting requirements and civil and criminal penalties for violations. Federal and state regulatory agencies continue to interpret and implement these laws and propose new regulations and standards. Implementing and complying with these laws and regulations has increased and will continue to increase the ARLP Partnership's operational expense and to have an adverse effect on its results of operation and financial position. For more information, please read "Item 1. Business—Regulation and Laws—Mine Health and Safety Laws."

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regulations may be adopted, or that judicial interpretations or more stringent enforcement of existing laws and regulations may occur, which could materially affect the ARLP Partnership's mining operations, cash flow, and profitability, either through direct impacts on the ARLP Partnership's existing mining operations, or indirect impacts that discourage or limit the ARLP Partnership's customers' use of coal. Please read "Item 1. Business—Regulations and Laws."

The ARLP Partnership may be unable to obtain and renew permits necessary for its operations, which could reduce its production, cash flow and profitability.

Mining companies must obtain numerous governmental permits or approvals that impose strict conditions and obligations relating to various environmental and safety matters in connection with coal mining. The permitting rules are complex and can change over time. Regulatory authorities exercise considerable discretion in the timing and scope of permit issuance. The public has the right to comment on permit applications and otherwise participate in the permitting process, including through court intervention. Accordingly, permits required to conduct the ARLP Partnership's operations may not be issued, maintained or renewed, or may not be issued or renewed in a timely fashion, or may involve requirements that restrict the ARLP Partnership's ability to economically conduct its mining operations. Limitations on the ARLP Partnership's ability to conduct its mining operations due to the inability to obtain or renew necessary permits or similar approvals could reduce the ARLP Partnership's production, cash flow and profitability. Please read "Item 1. Business—Regulations and Laws—Mining Permits and Approvals."

The EPA has begun reviewing permits required for the discharge of overburden from mining operations under Section 404 of the CWA. Various initiatives by the EPA regarding these permits have increased the time required to obtain and the costs of complying with such permits. In addition, the EPA previously exercised its "veto" power to withdraw or restrict the use of previously issued permits in connection with one of the largest surface mining operations in Appalachia. The EPA's action was ultimately upheld by a federal court. As a result of these developments, the ARLP Partnership may be unable to obtain or experience delays in securing, utilizing or renewing Section 404 permits required for its operations, which could have an adverse effect on its results of operation and financial position. Please read "Item 1. Business—Regulations and Laws—Water Discharge."

In addition, some of the ARLP Partnership's permits could be subject to challenges from the public, which could result in additional costs or delays in the permitting process, or even an inability to obtain permits, permit modifications, or permit renewals necessary for the ARLP Partnership's operations.

Fluctuations in transportation costs and the availability or reliability of transportation could reduce revenues by causing the ARLP Partnership to reduce its production or by impairing its ability to supply coal to its customers.

Transportation costs represent a significant portion of the total cost of coal for the ARLP Partnership's customers and, as a result, the cost of transportation is a critical factor in a customer's purchasing decision. Increases in transportation costs could make coal a less competitive source of energy or could make the ARLP Partnership's coal production less competitive than coal produced from other sources. Disruption of transportation services due to weather-related problems, flooding, drought, accidents, mechanical difficulties, strikes, lockouts, bottlenecks or other events could temporarily impair the ARLP Partnership's ability to supply coal to its customers. The ARLP Partnership's transportation providers may face difficulties in the future that may impair its ability to supply coal to its customers, resulting in decreased revenues. If there are disruptions of the transportation services provided by the ARLP Partnership's primary rail or barge carriers that transport its coal and the ARLP Partnership is unable to find alternative transportation providers to ship its coal, its business could be adversely affected.

Conversely, significant decreases in transportation costs could result in increased competition from coal producers in other parts of the country. For instance, difficulty in coordinating the many eastern coal loading facilities, the large number of small shipments, the steeper average grades of the terrain and a more unionized workforce are all issues that combine to make coal shipments originating in the eastern U.S. inherently more expensive on a per-mile basis than coal shipments originating in the western U.S. Historically, high coal transportation rates from the western coal producing areas into certain eastern markets limited the use of western coal in those markets. Lower rail rates from the western coal producing areas to markets served by eastern U.S. coal producers have created major competitive challenges for eastern coal producers. In the event of further reductions in transportation costs from western coal producing areas, the increased competition with certain eastern coal markets could have a material adverse effect on the ARLP Partnership's business, financial condition and results of operations.

It is possible that states in which the ARLP Partnership's coal is transported by truck may modify or increase enforcement of their laws regarding weight limits or coal trucks on public roads. Such legislation and enforcement efforts could result in shipment delays and increased costs. An increase in transportation costs could have an adverse effect on the ARLP Partnership's ability to increase or to maintain production and could adversely affect revenues.

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number of small shipments, the steeper average grades of the terrain and a more unionized workforce are all issues that combine to make coal shipments originating in the eastern U.S. inherently more expensive on a per-mile basis than coal shipments originating in the western U.S. Historically, high coal transportation rates from the western coal producing areas into certain eastern markets limited the use of western coal in those markets. Lower rail rates from the western coal producing areas to markets served by eastern U.S. coal producers have created major competitive challenges for eastern coal producers. In the event of further reductions in transportation costs from western coal producing areas, the increased competition with certain eastern coal markets could have a material adverse effect on the ARLP Partnership's business, financial condition and results of operations.

The ARLP Partnership may not be able to successfully grow through future acquisitions.

Since ARLP's formation and the acquisition of its predecessor in August 1999, the ARLP Partnership has expanded its operations by adding and developing mines and coal reserves in existing, adjacent and neighboring properties. The ARLP Partnership continually seeks to expand its operations and coal reserves. The ARLP Partnership's future growth could be limited if it is unable to continue to make acquisitions, or if it is unable to successfully integrate the companies, businesses or properties it acquires. The ARLP Partnership may not be successful in consummating any acquisitions and the consequences of undertaking these acquisitions are unknown. Moreover, any acquisition could be dilutive to earnings and distributions to unitholders and any additional debt incurred to finance an acquisition could affect the ARLP Partnership's ability to make distributions to unitholders. The ARLP Partnership's ability to make acquisitions in the future could require significant amounts of financing that may not be available to the ARLP Partnership under acceptable terms and may be limited by restrictions under its existing or future debt agreements, competition from other coal companies for attractive properties or the lack of suitable acquisition candidates.

Expansions and acquisitions involve a number of risks, any of which could cause the ARLP Partnership not to realize the anticipated benefits.

If the ARLP Partnership is unable to successfully integrate the companies, businesses or properties it acquires, its profitability may decline and it could experience a material adverse effect on its business, financial condition, or results of operations. Expansion and acquisition transactions involve various inherent risks, including:

uncertainties in assessing the value, strengths, and potential profitability of, and identifying the extent of all weaknesses, risks, contingent and other liabilities (including environmental or mine safety liabilities) of, expansion and acquisition opportunities;

the ability to achieve identified operating and financial synergies anticipated to result from an expansion or an acquisition;

problems that could arise from the integration of the new operations; and

unanticipated changes in business, industry or general economic conditions that affect the assumptions underlying the ARLP Partnership's rationale for pursuing the expansion or acquisition opportunity.

Any one or more of these factors could cause the ARLP Partnership not to realize the benefits anticipated to result from an expansion or acquisition. Any expansion or acquisition opportunities the ARLP Partnership pursues could materially affect its liquidity and capital resources and may require it to incur indebtedness, seek equity capital or both. In addition, future expansions or acquisitions could result in the ARLP Partnership assuming more long-term liabilities relative to the value of the acquired assets than it has assumed in its previous expansions and/or acquisitions.

Completion of growth projects and future expansion could require significant amounts of financing that may not be available to the ARLP Partnership on acceptable terms, or at all.

The ARLP Partnership plans to fund capital expenditures for its current growth projects with existing cash balances, future cash flows from operations, borrowings under revolving credit and securitization facilities and cash provided from the issuance of debt or equity. Weakness in the energy sector in general and coal in particular has significantly impacted access to the debt and equity capital markets. Accordingly, the ARLP Partnership's funding plans may be negatively impacted by this constrained environment as well as numerous other factors, including higher than anticipated capital expenditures or lower than expected cash flow from operations. In addition, the ARLP Partnership may be unable to refinance its current revolving credit and securitization facilities when they expire or obtain adequate funding prior to expiry because its lending counterparties may be unwilling or unable to meet their funding obligations. Furthermore, additional growth projects and expansion opportunities may develop in the future that could also require significant amounts of financing that may not be available to the ARLP Partnership on acceptable terms or in the amounts it expects, or at all.

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~~provided from~~ the ~~issuance of debt or equity. Weakness in the energy sector in general and coal in particular has significantly impacted access to the debt and equity capital markets. Accordingly, the~~ ARLP Partnership's ~~funding~~is plans may be negatively impacted by this constrained environment as well as numerous other factors, including higher than anticipated capital expenditures or lower than expected cash flow from operations. In addition, the ARLP Partnership may be unable to ~~refinance~~finance its ~~current~~growth ~~revolving credit~~ and ~~securitization~~future ~~facilities~~expansions ~~when~~as ~~they~~expected, ~~expire~~it orcould ~~obtain adequate funding prior to expiry because its lending counterparties may~~ be ~~unwilling~~required ~~or unable~~ to ~~meet~~seek ~~their~~alternative ~~funding obligations. Furthermore~~financing, ~~additional growth projects and expansion opportunities may develop in~~ the ~~future~~terms ~~that could also require significant amounts~~ of ~~financing~~which ~~that~~ may not be ~~available~~attractive to ~~the~~it, ~~ARLP Partnership on acceptable terms~~ or into ~~the~~revise ~~amounts it expects,~~ or atcancel ~~all~~its plans.

Various factors could adversely impact the debt and equity capital markets as well as the ARLP Partnership's credit ratings or its ability to remain in compliance with the financial covenants under its then current debt agreements, which in turn could have a material adverse effect on its financial condition, results of operations and cash flows. If the ARLP Partnership is unable to finance its growth and future expansions as expected, it could be required to seek alternative financing, the terms of which may not be attractive to it, or to revise or cancel its plans.

The unavailability of an adequate supply of coal reserves that can be mined at competitive costs could cause the ARLP Partnership's profitability to decline.

The ARLP Partnership's profitability depends substantially on its ability to mine coal reserves that have the geological characteristics that enable them to be mined at competitive costs and to meet the quality needed by the ARLP Partnership's customers. Because the ARLP Partnership depletes its reserves as it mines coal, its future success and growth depend, in part, upon its ability to acquire additional coal reserves that are economically recoverable. Replacement reserves may not be available when required or, if available, may not be mineable at costs comparable to those of the depleting mines. The ARLP Partnership may not be able to accurately assess the geological characteristics of any reserves that it acquires, which may adversely affect its profitability and financial condition. Exhaustion of reserves at particular mines also may have an adverse effect on the ARLP Partnership's operating results that is disproportionate to the percentage of overall production represented by such mines. The ARLP Partnership's ability to obtain other reserves in the future could be limited by restrictions under its existing or future debt agreements, competition from other coal companies for attractive properties, the lack of suitable acquisition candidates or the inability to acquire coal properties on commercially reasonable terms.

The estimates of the ARLP Partnership's coal reserves may prove inaccurate and could result in decreased profitability.

The estimates of the ARLP Partnership's coal reserves may vary substantially from actual amounts of coal it is able to economically recover. The reserve data set forth in "Item 2. Properties" represent the ARLP Partnership's engineering estimates. All of the reserves presented in this Annual Report on Form 10-K constitute proven and probable reserves. There are numerous uncertainties inherent in estimating quantities of reserves, including many factors beyond the ARLP Partnership's control. Estimates of coal reserves necessarily depend upon a number of variables and assumptions, any one of which may vary considerably from actual results. These factors and assumptions relate to:

geological and mining conditions, which may not be fully identified by available exploration data and/or differ from the ARLP Partnership's experiences in areas where it currently mines;

the percentage of coal in the ground ultimately recoverable;

historical production from the area compared with production from other producing areas;

the assumed effects of regulation and taxes by governmental agencies;

future improvements in mining technology; and

assumptions concerning future coal prices, operating costs, capital expenditures, severance and excise taxes and development and reclamation costs.

For these reasons, estimates of the recoverable quantities of coal attributable to any particular group of properties, classifications of reserves based on risk of recovery and estimates of future net cash flows expected from these properties as prepared by different engineers, or by the same engineers at different times, may vary substantially. Actual production, revenue and expenditures with respect to the ARLP Partnership's reserves will likely vary from estimates, and these variations may be material. Any inaccuracy in the estimates of the ARLP Partnership's reserves could result in higher than expected costs and decreased profitability.

Mining in certain areas in which the ARLP Partnership operates is more difficult and involves more regulatory constraints than mining in other areas of the U.S., which could affect the mining operations and cost structures of these areas.

The geological characteristics of some of the ARLP Partnership's coal reserves, such as depth of overburden and coal seam thickness, make them difficult and costly to mine. As mines become depleted, replacement reserves may not be available when required or, if available, may not be mineable at costs comparable to those characteristic of the depleting mines. In addition, permitting, licensing and other environmental and regulatory requirements associated with certain of the ARLP Partnership's mining operations are more costly and time-consuming to satisfy. These

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~~Actual~~factors ~~production,~~could ~~revenue~~materially ~~and~~adversely ~~expenditures~~affect ~~with respect to~~ the ~~ARLP~~mining ~~Partnership's~~operations ~~reserves~~and ~~will~~cost ~~likely~~structures ~~vary from estimates~~of, and ~~these~~the ~~variations~~ARLP ~~may~~Partnership's becustomers' ~~material. Any~~ability ~~inaccuracy~~to inuse ~~the~~coal ~~estimates~~produced ofby, the ARLP Partnership's ~~reserves could result in higher than expected costs and decreased profitability~~mines.

Some of the ARLP Partnership's operating subsidiaries lease a portion of the surface properties upon which their mining facilities are located.

The ARLP Partnership's operating subsidiaries do not, in all instances, own all of the surface properties upon which their mining facilities have been constructed. Certain of the operating companies have constructed and now operate all or some portion of their facilities on properties owned by unrelated third parties with whom the subsidiary has entered into a long-term lease. The ARLP Partnership has no reason to believe that there exists any risk of loss of these leasehold rights given the terms and provisions of the subject leases and the nature and identity of the third-party lessors; however, in the unlikely event of any loss of these leasehold rights, operations could be disrupted or otherwise adversely impacted as a result of increased costs associated with retaining the necessary land use.

Unexpected increases in raw material costs could significantly impair the ARLP Partnership's operating profitability.

The ARLP Partnership's coal mining operations are affected by commodity prices. The ARLP Partnership uses significant amounts of steel, petroleum products and other raw materials in various pieces of mining equipment, supplies and materials, including the roof bolts required by the room-and-pillar method of mining. Steel prices and the prices of scrap steel, natural gas and coking coal consumed in the production of iron and steel fluctuate significantly and may change unexpectedly. There may be acts of nature or terrorist attacks or threats that could also impact the future costs of raw materials. Future volatility in the price of steel, petroleum products or other raw materials will impact the ARLP Partnership's operational expenses and could result in significant fluctuations in its profitability.

The ARLP Partnership's indebtedness may limit its ability to borrow additional funds, make distributions to unitholders or capitalize on business opportunities.

The ARLP Partnership has long-term indebtedness, consisting of its outstanding senior unsecured notes, revolving credit facility and its term loan agreement. At December 31, ~~2016~~2017, the ARLP Partnership's total long-term indebtedness outstanding was $~~550~~502.04 million. The ARLP Partnership's leverage may:

adversely affect its ability to finance future operations and capital needs;

limit its ability to pursue acquisitions and other business opportunities;

make its results of operations more susceptible to adverse economic or operating conditions; and

make it more difficult to self-insure for the ARLP Partnership's workers' compensation obligations.

In addition, the ARLP Partnership has unused borrowing capacity under its revolving credit facility. Future borrowings, under credit facilities or otherwise, could result in an increase in the ARLP Partnership's leverage.

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The ARLP Partnership's payments of principal and interest on any indebtedness will reduce the cash available for distribution on its units. The ARLP Partnership will be prohibited from making cash distributions:

during an event of default under any of its indebtedness; or

if after such distribution, it fails to meet a coverage test based on the ratio of its consolidated cash flow to its consolidated fixed charges.

Various limitations in the ARLP Partnership's debt agreements may reduce its ability to incur additional indebtedness, to engage in some transactions and to capitalize on business opportunities. Any subsequent refinancing of the ARLP Partnership's current indebtedness or any new indebtedness could have similar or greater restrictions. Please see "Item 8. Financial Statements and Supplementary Data – Note 7. Long-Term Debt" for further discussion.

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Federal and state laws require bonds to secure the ARLP Partnership's obligations related to statutory reclamation requirements and workers' compensation and black lung benefits. The ARLP Partnership's inability to acquire or failure to maintain surety bonds that are required by state and federal law would have a material adverse effect on it.

Federal and state laws require the ARLP Partnership to place and maintain bonds to secure its obligations to repair and return property to its approximate original state after it has been mined (often referred to as "reclaim" or "reclamation"), to pay federal and state workers' compensation and pneumoconiosis, or black lung, benefits and to satisfy other miscellaneous obligations. These bonds provide assurance that the ARLP Partnership will perform its statutorily required obligations and are referred to as "surety" bonds. These bonds are typically renewable on a yearly basis. The failure to maintain or the inability to acquire sufficient surety bonds, as required by state and federal laws, could subject the ARLP Partnership to fines and penalties and result in the loss of its mining permits. Such failure could result from a variety of factors, including:

lack of availability, higher expense or unreasonable terms of new surety bonds;

the ability of current and future surety bond issuers to increase required collateral, or limitations on availability of collateral for surety bond issuers due to the terms of the ARLP Partnership's credit agreements; and

the exercise by third-party surety bond holders of their rights to refuse to renew the surety.

The ARLP Partnership has outstanding surety bonds with governmental agencies for reclamation, federal and state workers′' compensation and other obligations. At December 31, ~~2016~~2017, the ARLP Partnership's total of such bonds was $~~269~~268.47 million. The ARLP Partnership may have difficulty maintaining its surety bonds for mine reclamation as well as workers′' compensation and black lung benefits. In addition, those governmental agencies may increase the amount of bonding required. The ARLP Partnership's inability to acquire or failure to maintain these bonds, or a substantial increase in the bonding requirements, would have a material adverse effect on it.

The ARLP Partnership and its subsidiaries are subject to various legal proceedings, which may have a material effect on its business.

The ARLP Partnership is party to a number of legal proceedings incident to its normal business activities. There is the potential that an individual matter or the aggregation of multiple matters could have an adverse effect on the ARLP Partnership's cash flows, results of operations or financial position. Please see "Item 8. Financial Statements and Supplementary Data—Note 19. Commitments and Contingencies" for further discussion.

Fluctuations in the oil and natural gas industry could affect the ARLP Partnership's profitability.

The ARLP Partnership has investments in oil and gas mineral interests and gas compression services in the continental U.S. Consequently, the value of the ~~investment~~investments as well as any resulting cash flows, may fluctuate with changes in the market and prices for oil and natural gas. Since the ARLP Partnership began these investments in late 2014, the oil and natural gas industry has experienced a significant ~~decrease~~fluctuations in commodity prices driven by a global supply/demand imbalance for oil and an oversupply of natural gas in the U.S. If commodity prices ~~remain~~decline atto lower levels ~~or decline further~~, the ARLP Partnership could see a decrease in the value of these investments or in the cash flows they generate. For more information on the ARLP Partnership's involvement with AllDale Partnerships and Kodiak, please read "Item 8. Financial Statements and Supplementary Data—Note 12. Investments."

Terrorist attacks or cyber-incidents could result in information theft, data corruption, operational disruption and/or financial loss.

Like most companies, the ARLP Partnership has become increasingly dependent upon digital technologies, including information systems, infrastructure and cloud applications and services, to operate its businesses, to process and record financial and operating data, communicate with our business partners, analyze mine and mining information, estimate quantities of coal reserves, as well as other activities related to its businesses. Strategic targets, such as energy-related assets, may be at greater risk of future terrorist or cyber-attacks than other targets in the U.S. Deliberate attacks on, or security breaches in, the ARLP Partnership's systems or infrastructure, or the systems or infrastructure of third parties, or cloud-based applications could lead to corruption or loss of our proprietary data and

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~~information~~potentially sensitive data, delays in production or delivery, difficulty in completing and settling transactions, challenges in maintaining its books and records, environmental damage, communication interruptions, other operational disruptions and third-party liability. The ARLP Partnership's insurance may not protect it against such occurrences. Consequently, it is possible that any of these occurrences, or a combination of them, could have a material adverse effect on the ARLP Partnership's ~~involvement~~business, ~~with~~financial ~~AllDale Minerals~~condition, ~~please~~results ~~read~~of ~~"Item~~operations 8and cash flows. ~~Financial~~Further, ~~Statements~~as cyber incidents continue to evolve, the ARLP Partnership may be required to expend additional resources to continue to modify or enhance its protective measures or to investigate and ~~Supplementary~~remediate ~~Data—Note~~any ~~12.~~vulnerability ~~Equity~~to ~~Investments~~cyber incidents."

~~Terrorist~~Risks ~~attacks~~Related orto ~~cyber-incidents~~Our ~~could~~Proposed ~~result~~Simplification ~~in information theft, data corruption, operational disruption and/or financial loss.~~Transactions

~~Like~~The ~~most~~completion companies, the ARLP Partnership has become increasingly dependent upon digital technologies, including information systems, infrastructure and cloud applications and services, to operate its businesses, to process and record financial and operating data, communicate with our business partners, analyze mine and mining information, estimate quantities of coal reserves, as well as other activities related to its businesses. Strategic targets, such as energy-related assets, may be at greater risk of future terrorist or cyber-attacks than other targets in the ~~U.S.~~Simplification ~~Deliberate~~Transactions attacks on, or security breaches in, the ARLP Partnership's systems or infrastructure, or the systems or infrastructure of third parties, or cloud-based applications could lead to corruption or loss of our proprietary data and potentially sensitive data, delays in production or delivery, difficulty in completing and settling transactions, challenges in maintaining its books and records, environmental damage, communication interruptions, other operational disruptions and third-party liability. The ARLP Partnership's insurance may not protect it against such occurrences. Consequently, it is ~~possible~~subject that any of these occurrences, or a combination of them, could have a material adverse effect on the ARLP Partnership's business, financial condition, results of operations and cash flows. Further, as cyber incidents continue to evolve, the ARLP Partnership may be required to expend additional resources to continue to modify or enhance its protective measures or to investigate and remediate any vulnerability to cyber incidentsconditions.

The Simplification Agreement contains conditions, some of which are beyond the parties' control, that, if not satisfied or waived, may delay the closing of the Simplification Transactions or result in the Simplification Transactions not occurring. We cannot predict with certainty when and whether any of the conditions to the completion of the Simplification Transactions will be satisfied. Any delay in completing the Simplification Transactions could increase our cost or cause us not to realize, or delay realization of, some or all of the benefits that we expect to achieve from the Simplification Transactions. If the Simplification Transactions are not completed, we and ARLP will have incurred substantial expenses for which no ultimate benefit will have been received by either company. In addition, if the Simplification Agreement is terminated under specified circumstances, either we or ARLP will be required to pay certain expenses of the other party.

Tax Risks to Our Common Unitholders

Our tax treatment depends on our status as a partnership for federal tax purposes, as well as our not being subject to a material amount of entity-level taxation by individual states. If the Internal Revenue Service ("IRS") were ~~treats~~to treat us as a corporation for federal income tax purposes, or we or ARLP become subject to entity-level taxation for state tax purposes, our cash available for distribution to you would be substantially reduced.

The anticipated after-tax benefit of an investment in our units depends largely on AHGP being treated as a partnership for U.S. federal income tax purposes. The value of our investment in ARLP depends largely on ARLP being treated as a partnership for federal income tax purposes.

Despite the fact that we and ARLP are organized as limited partnerships under Delaware law, we and ARLP would be treated as corporations for U.S. federal income tax purposes unless we and ARLP satisfy a "qualifying income" requirement. Based upon ARLP's current operations, we believe we and ARLP satisfy the qualifying income requirement. However, neither we nor ARLP have requested, and do not plan to request, a ruling from the IRS on this or any other matter affecting us or ARLP. Failing to meet the qualifying income requirement or a change in current law could cause us or ARLP to be treated as a corporation for U.S. federal income tax purposes or otherwise subject us or ARLP to taxation as an entity.

If we or ARLP were treated as a corporation for U.S. federal income tax purposes, we would pay U.S. federal income tax on our taxable income at the corporate tax rate, and would likely be liable for state income tax at varying rates. Distributions to our unitholders would generally be taxed again as corporate distributions, and no income, gains, losses, deductions or credits would flow through to our unitholders. Because taxes would be imposed upon us as a corporation, our cash available for distribution to our unitholders would be substantially reduced. Therefore, our treatment as a corporation would result in a material reduction in the anticipated cash flow and after-tax return to our unitholders, likely causing a substantial reduction in the value of the units.

ARLP's partnership agreement provides that if a law is enacted or existing law is modified or interpreted in a manner that subjects ARLP to taxation as a corporation or otherwise subjects ARLP to entity-level taxation for U.S. federal, state or local income tax purposes, the minimum quarterly distribution amount and the target distribution amounts may be adjusted to reflect the impact of that law on ARLP. Likewise, our cash distributions to you will be reduced if we or ARLP is subjected to any form of such entity-level taxation. At the state level, several states have been evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise or other forms of taxation. If any state were to impose a tax upon us or ARLP as an entity, the cash available for distribution to you would be reduced and the value of our common units or ARLP common units could be negatively impacted.

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~~distribution~~ The totax ~~you~~treatment ~~would~~of bepublicly ~~reduced~~traded ~~and~~partnerships ~~the~~or ~~value~~an ofinvestment in our ~~common~~ units could be subject to potential legislative, judicial or ~~ARLP~~administrative ~~common~~changes ~~units~~or ~~could~~differing beinterpretations, ~~negatively~~possibly ~~impacted~~applied on a retroactive basis.

The present U.S. federal income tax treatment of publicly traded partnerships, including us and ARLP, or an investment in our common units ~~could~~may be ~~subject~~modified toby ~~potential~~administrative, legislative, ~~judicial~~ or ~~administrative~~judicial changes or differing interpretations at any time. From time to time, ~~possibly~~members onof Congress have proposed and considered such substantive changes to the existing federal income tax laws that would affect us, ARLP, or all publicly traded partnerships. For example, recently enacted legislation repealed Section 199, which, prior to its repeal, entitled our unitholders to a ~~retroactive~~deduction ~~basis~~equal to a specified percentage of ARLP's qualified production activities income that was allocated to such unitholder. In addition, although there is no current legislative proposal, a prior legislative proposal would have eliminated the qualifying income exception to the treatment of all publicly-traded partnerships as corporations upon which we and ARLP rely for our treatment as a partnership for U.S. federal income tax purposes.

~~The present U.S. federal income tax treatment of publicly traded partnerships~~Further, ~~including~~on usJanuary ~~and ARLP~~24, ~~or an investment in our common units may be modified by administrative~~2017, ~~legislative~~final orregulations ~~judicial~~concerning ~~changes~~which oractivities ~~differing~~give ~~interpretations~~rise atto ~~any~~qualifying ~~time. From~~income ~~time~~within tothe ~~time,~~meaning ~~members~~ of ~~Congress~~Section 7704 ~~propose~~of ~~and~~the ~~consider~~Internal ~~such~~Revenue ~~substantive~~Code ~~changes~~(the to"Final ~~the~~Regulations") ~~existing~~were ~~federal~~published ~~income~~in ~~tax~~the ~~laws~~Federal ~~that~~Register. ~~affect~~The ~~publicly~~Final ~~traded~~Regulations ~~partnerships. Although~~are ~~there~~effective isas noof ~~current~~January ~~legislative~~19, ~~proposal~~2017, aand ~~prior~~apply ~~legislative~~to ~~proposal~~taxable ~~would~~years ~~have~~beginning ~~eliminated~~on ~~the~~or ~~qualifying~~after ~~income~~January ~~exception~~19, to2017. ~~the~~We ~~treatment~~do ofnot ~~all~~believe ~~publicly-traded~~the ~~partnerships~~Final asRegulations ~~corporations~~affect ~~upon~~our ~~which~~ability weor ~~and~~ ARLP's ~~rely~~ability ~~for~~to ~~our~~be ~~treatment~~treated as a partnership for ~~U.S.~~ federal income tax purposes.

~~In addition~~However, onany ~~January~~modification ~~24,~~to ~~2017,~~the ~~final~~U.S. ~~regulations~~federal ~~concerning~~income ~~which~~tax ~~activities~~laws ~~give~~may ~~rise~~be toapplied ~~qualifying~~retroactively ~~income~~and ~~within~~could ~~the~~make ~~meaning~~it ofmore ~~Section 7704~~difficult ofor ~~the~~impossible ~~Internal~~for ~~Revenue~~us ~~Code~~or (ARLP to meet the ~~"Final~~exception ~~Regulations")~~for ~~were~~certain ~~published~~publicly intraded ~~the~~partnerships ~~Federal~~to ~~Register~~be treated as partnerships for U.S. ~~The~~federal ~~Final~~income ~~Regulations~~tax purposes. We are ~~effective~~unable asto predict whether any of ~~January~~these ~~19,~~changes ~~2017,~~or ~~and~~other ~~apply~~proposals towill ~~taxable~~ultimately ~~years~~be ~~beginning~~enacted. onAny similar or ~~after~~future ~~January~~legislative ~~19,~~changes ~~2017.~~could Wenegatively doimpact ~~not~~the ~~believe~~amount of our common unit distributions and the ~~Final~~value ~~Regulations~~of ~~affect~~an investment in our ~~ability~~common units. You are urged to beconsult ~~treated~~with asyour aown ~~partnership~~tax ~~for~~advisor ~~federal~~with ~~income~~respect ~~tax~~to ~~purposes~~the status of regulatory or administrative developments and proposals and their potential effect on your investment in our units.

However, any modification to the U.S. federal income tax laws may be applied retroactively and could make it more difficult or impossible for us or ARLP 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 amount of our common unit distributions and the value of an investment in our common units.

If the IRS were to contest the federal income tax positions we take, it may adversely impact the market for our common units or ARLP common units, and the costs of any such contest would reduce cash available for distribution to ARLP and our unitholders.

We have not requested a ruling from the IRS with respect to our treatment as a partnership for federal income tax purposes. The IRS may adopt positions that differ from the positions that we or ARLP take. It may be necessary to resort to administrative or court proceedings to sustain some or all of the positions we or ARLP take. A court may not agree with some or all of the positions we or ARLP take. Any contest with the IRS may materially and adversely impact the market for our common units or ARLP's common units and the prices at which they trade. In addition, the costs of any contest with the IRS will be borne by ARLP and therefore indirectly by us, as a unitholder and as the owner of the ~~managing~~ general partner of ARLP. Moreover, the costs of any contest between us and the IRS will result in a reduction in cash available for distribution to our unitholders and thus will be borne indirectly by our unitholders.

If the IRS makes audit adjustments to our income tax returns or ARLP's income tax returns for tax years beginning after December 31, 2017, it (and some states) may assess and collect any taxes (including any applicable penalties and interest) resulting from such audit ~~adjustment~~ adjustments directly from us or ARLP, in which case ARLP's cash distribution to us and our cash available for distribution to our unitholders might be substantially reduced. In addition, our current and former unitholders may be required to indemnify us for any taxes (including any applicable penalties and interest) resulting from such audit adjustments that were paid on such unitholders' behalf.

Pursuant to the Bipartisan Budget Act of 2015, for ~~taxable~~tax years beginning after December 31, 2017, if the IRS makes audit adjustments to our income tax returns or ARLP's income tax returns, it (and some states) may assess and collect any taxes (including any applicable penalties and interest) resulting from such audit ~~adjustment~~adjustments directly from us. ~~To the extent possible under the new rules, our general partner may elect to either pay the taxes (including any applicable penalties and interest) directly to the IRS~~ or, ~~if we are eligible, issue a revised Schedule K-1 to each unitholder with respect to an audited and adjusted return~~ARLP. Although our general partner may elect to have our unitholders take such audit adjustment into account in accordance with their interests in us during the tax year under audit, there can be no assurance that such election will be practical, permissible or effective in all circumstances. As a result, our current unitholders may bear some or all of the tax liability resulting from such audit adjustment, even if such unitholders did not own units in us during the tax year under audit. If we are required to pay taxes, penalties and interest as the result of audit adjustments, cash available for distribution to our unitholders may be substantially reduced. In addition, because

To the extent possible under the new rules, our general partner may elect to either pay the taxes (including any applicable penalties and interest) directly to the IRS or, if we are eligible, issue a revised information statement to each unitholder and former unitholder with respect to an audited and adjusted return. Although our general partner may elect to have our unitholders and former unitholders take such audit adjustment into account and pay any resulting

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~~payment~~taxes ~~would~~(including beapplicable ~~due~~penalties ~~for~~or ~~the~~interest) ~~taxable~~in ~~year~~accordance with their interests in ~~which~~us during the tax year under audit, isthere ~~completed~~can be no assurance that such election will be practical, permissible or effective in all circumstances. In addition, ARLP may elect to have us (and its other current and former unitholders) take such audit adjustments into account and pay any resulting taxes (including applicable penalties or interest) in accordance with our interest in ARLP during ~~that~~the ~~taxable~~tax year ~~would~~under audit or require us to indemnify ARLP for any taxes (including applicable penalties or interest) paid by ARLP on our behalf, or ARLP may elect to pay any resulting taxes (including applicable penalties or interest) directly. As a result, our current unitholders may bear ~~the~~some ~~expense~~or all of the tax liability resulting from such audit adjustment, even if ~~they~~such ~~were~~unitholders did not ~~unitholders~~own units in us during the ~~audited~~tax ~~taxable~~ year under audit. If, as a result of any such audit adjustment, we are required to make payments of taxes, penalties and interest, our cash available for distribution to our unitholders might be substantially reduced and our current and former unitholders may be required to indemnify us for any taxes (including any applicable penalties and interest) resulting from such audit adjustments that were paid on such unitholders' behalf.

Even if you do not receive any cash distributions from us, you will be required to pay taxes on your share of our taxable income.

You will be required to pay federal income taxes and, in some cases, state and local income taxes, on your share of our taxable income, whether or not you receive cash distributions from us. For example, if the ARLP Partnership sells assets and uses the proceeds to repay existing debt or fund capital expenditures, you may be allocated taxable income and gain resulting from the sale and our cash available for distribution would not increase. Similarly, taking advantage of opportunities to reduce existing debt, such as debt exchanges, debt repurchases, or modifications of existing debt could result "cancellation of indebtedness income" being allocated to our unitholders as taxable income without any increase in our cash available for distribution. You may not receive cash distributions from us equal to your share of our taxable income or even equal to the actual tax liability which results from your share of our taxable income.

Tax gain or loss on the disposition of our units could be more or less than expected.

If you sell your units, you will recognize gain or loss equal to the difference between the amount realized and your tax basis in those units. Because distributions in excess of your allocable share of our net taxable income result in a decrease in your tax basis in your units, the amount, if any, of such prior excess distributions with respect to the units you sell will, in effect, become taxable income to you if you sell such units at a price greater than your tax basis therein, even if the price you receive is less than your original cost. In addition, because the amount realized includes a unitholder's share of our non-recourse liabilities, if you sell your units, you may incur a tax liability in excess of the amount of cash you receive from the sale.

A substantial portion of the amount realized from the sale of your units, whether or not representing gain, may be taxed as ordinary income to you due to potential recapture items, including depreciation recapture. Thus, you may recognize both ordinary income and capital loss from the sale of your units if the amount realized on a sale of your units is less than your adjusted basis in the units. Net capital loss may only offset capital gains and, in the case of individuals, up to $3,000 of ordinary income per year. In the taxable period in which you sell your units, you may recognize ordinary income from our allocations of income and gain to you prior to the sale and from recapture items that generally cannot be offset by any capital loss recognized upon the sale of units.

Tax-exempt entities ~~and~~face ~~non-U.S.~~unique ~~persons~~tax issues from owning our units ~~face unique tax issues~~ that may result in adverse tax consequences to them.

Investment in our units by tax-exempt entities, such as employee benefit plans, and individual retirement accounts ("known as IRAs") ~~and non-U.S. persons,~~ raises issues unique to them. For example, virtually all of our income allocated to organizations that are exempt from U.S. federal income tax, including IRAs and other retirement plans, will be unrelated business taxable income and will be taxable to them. ~~Allocations~~ ~~and/or~~Further, ~~distributions~~with respect to ~~non~~taxable years beginning after December 31, 2017, a tax-~~U.S.~~exempt ~~persons~~entity ~~will~~with bemore ~~reduced~~than one unrelated trade or business (including by ~~withholding~~attribution ~~taxes~~from atinvestment ~~the~~in ~~highest~~a ~~applicable~~partnership ~~effective~~such ~~tax~~as ~~rate,~~ours ~~and~~that ~~non-U.S.~~is ~~persons~~engaged ~~will~~in beone or more unrelated trade or business) is required to ~~file~~compute ~~U.S.~~the ~~federal~~unrelated business taxable income of such tax-exempt ~~returns~~entity ~~and~~separately ~~pay~~with ~~tax~~respect onto ~~their~~each ~~share~~such trade or business (including for purposes of ~~our~~determining ~~taxable~~any ~~income. If~~net ~~you~~operating ~~are~~loss deduction). As a ~~tax~~result, for years beginning after December 31, 2017, it may not be possible for tax-exempt ~~entity~~entities to utilize losses from an investment in our partnership to offset unrelated business taxable income from another unrelated trade or abusiness ~~non-U~~and vice versa.S. ~~person,~~Tax-exempt ~~you~~entities should consult ~~your~~a tax advisor before investing in our ~~common~~ units.

We treat each purchaser of our units as having the same tax benefits without regard to the units purchased. The IRS may challenge this treatment, which could adversely affect the value of our units.

Because we cannot match transferors and transferees of units, we adopt depreciation and amortization positions that may not conform to all aspects of existing Treasury Regulations. A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to you. It also could affect the timing of these tax benefits or the amount of gain from your sale of units and could have a negative impact on the value of our units or result in audit adjustments to your tax returns.

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Non-U.S. Unitholders will be subject to U.S. taxes and withholding with respect to their income and gain from owning our units.

Non-U.S. unitholders are generally taxed and subject to income tax filing requirements by the United States on income effectively connected with a U.S. trade or business ("effectively connected income"). Income allocated to our unitholders and any gain from the sale of our units will generally be considered to be "effectively connected" with a U.S. trade or business. As a result, distributions to a Non-U.S. unitholder will be subject to withholding at the highest applicable effective tax rate and a Non-U.S. unitholder who sells or otherwise disposes of a unit will also be subject to U.S. federal income tax on the gain realized from the sale or disposition of that unit.

The Tax Cuts and Jobs Act imposes a withholding obligation of 10% of the amount realized upon a Non-U.S. unitholder's sale or exchange of an interest in a partnership that is engaged in a U.S. trade or business. However, due to challenges of administering a withholding obligation applicable to open market trading and other complications, the IRS has temporarily suspended the application of this withholding rule to open market transfers of interests in publicly traded partnerships pending promulgation of regulations or other guidance that resolves the challenges. It is not clear if or when such regulations or other guidance will be issued. Non-U.S. unitholders should consult a tax advisor before investing in our units.

We treat each purchaser of our units as having the same tax benefits without regard to the units actually purchased. The IRS may challenge this treatment, which could adversely affect the value of our units.

We generally prorate our items of income, gain, loss and deduction between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred. The IRS may challenge this treatment, which could change the allocation of items of income, gain, loss and deduction among our unitholders.

We generally prorate our items of income, gain, loss and deduction between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month (the "Allocation Date"), instead of on the basis of the date a particular unit is transferred. Similarly, we generally allocate certain deductions for depreciation of capital additions, gain or loss realized on a sale or other disposition of our assets and, in the discretion of the general partner, any other extraordinary item of income, gain, loss or deduction based upon ownership on the Allocation Date. Treasury Regulations allow a similar monthly simplifying convention, but such regulations do not specifically authorize all aspects of our proration method thereafter. If the IRS were to challenge our proration method, we may be required to change the allocation of items of income, gain, loss and deduction among our unitholders.

A unitholder whose units are the subject of a securities loan (e.g., a loan to a "short seller" to cover a short sale of units) may be considered as having disposed of those units. If so, he would no longer be treated for tax purposes as a partner with respect to those units during the period of the loan and may recognize gain or loss from the disposition.

Because there isare no specific rules governing the U.S. federal income tax ~~concept~~consequence of loaning a partnership interest, a unitholder whose units are the subject of a securities loan may be considered as having disposed of the loaned units. In that case, the unitholder may no longer be treated for tax purposes as a partner with respect to those units during the period of the loan to the short seller and the unitholder may recognize gain or loss from such disposition. Moreover, during the period of the loan, any of our income, gain, loss or deduction with respect to those units may not be reportable by the unitholder and any cash distributions received by the unitholder as to those units could be fully taxable as ordinary income. Unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a securities loan are urged to consult a tax advisor to determine whether it is advisable to modify any applicable brokerage account agreements to prohibit their brokers from borrowing their units.

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ARLP has adopted certain valuation methodologies in determining unitholder's allocations of income, gain, loss and deduction. The IRS may challenge these methods or the resulting allocations, and such a challenge could adversely affect the value of the common units.

In determining the items of income, gain, loss and deduction allocable to our unitholders, ARLP must routinely determine the fair market value of its respective assets. Although ARLP may from time to time consult with professional appraisers regarding valuation matters, ARLP makes many fair market value estimates using a methodology based on the market value of its common units as a means to measure the fair market value of its respective assets. The IRS may challenge these valuation methods and the resulting allocations or character of income, gain, loss and deduction.

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

Certain federal income tax deductions currently available with respect to coal mining and production may be eliminated as a result of future legislation.

In past years, members of Congress have indicated a desire to eliminate certain key U.S. federal income tax provisions currently applicable to coal companies, including the percentage depletion allowance with respect to coal properties. No legislation with that effect has been proposed and elimination of those provisions would not impact the ARLP Partnership's financial statements or results of operations. However, elimination of the provisions could result in unfavorable tax consequences for its unitholders and, as a result, could negatively impact its unit price as well as our unitholders and unit price.

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The sale or exchange of 50% or more of our capital and profits interests within a twelve-month period will result in the termination of us as a partnership for federal income tax purposes.

We will be considered to have terminated as a partnership for federal income tax purposes if there is a sale or exchange of 50% or more of the total interests in our capital and profits within a twelve-month period. For purposes of determining whether the 50% threshold has been met, multiple sales of the same interest will be counted only once. Our termination would, among other things, result in the closing of our taxable year for all unitholders, which would result in us filing two tax returns for one calendar year and could result in a significant deferral of depreciation deductions allowable in computing our taxable income. In the case of a unitholder reporting on a taxable year other than a calendar year, the closing of our taxable year may also result in more than twelve months of our taxable income or loss being includable in taxable income for the unitholder's taxable year that includes our termination. A termination would not affect our classification as a partnership for federal income tax purposes, but it would result in our being treated as a new partnership for U.S. federal income tax purposes following the termination. If we were treated as a new partnership, we would be required to make new tax elections and could be subject to penalties if we were unable to determine that a termination occurred. The IRS has implemented relief procedures whereby if a publicly traded partnership that has technically terminated, requests and the IRS grants special relief, among other things, the partnership may be permitted to provide only a single Schedule K-1 to unitholders for the two short tax periods included in the year in which the termination occurs.

You will likely be subject to state and local taxes and income tax return filing requirements in jurisdictions where you do not live as a result of investing in our units.

In addition to U.S. federal income taxes, you will likely be subject to other taxes, such as state and local income taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we or ARLP do business or own property now or in the future, even if you do not live in any of those jurisdictions. You will likely be required to file state and local income tax returns and pay state and local income taxes in some or all of these various jurisdictions. Further, you may be subject to penalties for failure to comply with those requirements.

WeARLP currently ~~own~~owns assets and ~~conduct~~conducts business in a variety of states which currently impose a personal income tax on individuals, corporations and other entities. As we or ARLP make acquisitions or expand our business, we or ARLP may own assets or conduct business in additional states that impose a personal income tax. It is your responsibility to file all U.S. federal, state and local tax returns.

ITEM 1B. UNRESOLVED STAFF COMMENTS

None.

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ITEM 2. PROPERTIES

Coal Reserves

The ARLP Partnership must obtain permits from applicable regulatory authorities before beginning to mine particular reserves. For more information on this permitting process, and matters that could hinder or delay the process, please read "Item 1. Business—Regulation and Laws—Mining Permits and Approvals."

The ARLP Partnership's reported coal reserves are those it believes can be economically and legally extracted or produced at the time of the filing of this Annual Report on Form 10-K. In determining whether its reserves meet this economic and legal standard, the ARLP Partnership takes into account, among other things, its potential ability or inability to obtain mining permits, the possible necessity of revising mining plans changes in future cash flows caused by changes in estimated future costs, changes in mining permits, variations in quantity and quality of coal, and varying levels of demand and their effects on selling prices.

At December 31, ~~2016~~2017, the ARLP Partnership had approximately 1.7667 billion tons of coal reserves. All of the estimates of reserves which are presented in this Annual Report on Form 10-K are of proven and probable reserves (as defined below) and closely adhere to the standards described in U.S. Geological Survey ("USGS") Circular 831 and USGS Bulletin 1450-B. For information on the locations of the ARLP Partnership's mines, please read "Mining Operations" under "Item 1. Business."

47The following table sets forth reserve information at December 31, 2017 about the ARLP Partnership's coal operations:

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	Mine	Heat
	Type	Content (BTUs	Pounds S02 per MMBTU				Classification		Reserve Assignment		Reserve Control
Operations	(1)	per pound)	<1.2	1.2-2.5	>2.5	Total	Proven	Probable	Assigned	Unassigned	Owned	Leased
			(tons in millions)
Illinois Basin Operations
Dotiki (KY)	U	12,200	—	—	80.6	80.6	52.5	28.1	36.8	43.8	28.8	51.8
Warrior (KY)	U	12,500	—	—	96.4	96.4	72.9	23.5	76.1	20.3	23.8	72.6
Hopkins (KY)	U	12,000	—	—	13.9	13.9	9.7	4.2	—	13.9	2.9	11.0
	S	11,500	—	—	7.8	7.8	7.8	—	7.8	—	7.8	—
River View (KY)	U	11,500	—	—	166.4	166.4	108.4	58.0	166.4	—	37.3	129.1
Henderson/Union (KY)	U	11,400	—	5.7	495.3	501.0	168.2	332.8	—	501.0	90.8	410.2
Onton (KY)	U	11,750	—	—	40.3	40.3	22.6	17.7	40.3	—	0.2	40.1
Sebree (KY)	U	11,400	—	—	8.6	8.6	3.1	5.5	—	8.6	3.9	4.7
Hamilton County (IL)	U	11,650	—	—	559.3	559.3	243.0	316.3	147.1	412.2	53.3	506.0
Gibson (North) (IN, IL)	U	11,500	0.1	8.0	14.5	22.6	17.5	5.1	22.6	—	0.3	22.3
Gibson (South) (IN)	U	11,500	0.9	19.5	45.2	65.6	56.3	9.3	65.6	—	18.0	47.6
Region Total			1.0	33.2	1,528.3	1,562.5	762.0	800.5	562.7	999.8	267.1	1,295.4

Appalachia Operations
MC Mining (KY)	U	12,900	2.9	0.5	1.7	5.1	4.4	0.7	2.9	2.2	0.1	5.0
Mettiki (MD)	U	13,200	—	1.6	3.8	5.4	5.2	0.2	5.4	—	—	5.4
Mettiki (WV)	U	13,200	—	8.2	8.2	16.4	11.0	5.4	10.5	5.9	2.4	14.0
Tunnel Ridge (WV)	U	12,600	—	—	83.6	83.6	33.8	49.8	83.6	—	—	83.6
Region Total			2.9	10.3	97.3	110.5	54.4	56.1	102.4	8.1	2.5	108.0

Total			3.9	43.5	1,625.6	1,673.0	816.4	856.6	665.1	1,007.9	269.6	1,403.4

% of Total			0.2%	2.6%	97.2%	100.0%	48.8%	51.2%	39.8%	60.2%	16.1%	83.9%

~~and~~(1) ~~USGS~~U ~~Bulletin~~= ~~1450-B. For~~Underground ~~information~~and onS ~~the~~= ~~locations of the ARLP Partnership's mines, please read "Mining Operations" under "Item 1. Business."~~ Surface

The ~~following~~ARLP ~~table~~Partnership's ~~sets~~reserve ~~forth~~estimates ~~reserve~~are ~~information~~prepared atfrom ~~December 31,~~geological ~~2016~~data ~~about~~assembled and analyzed by its staff of geologists and engineers. This data is obtained through the ARLP Partnership's extensive, ongoing exploration drilling and in-mine channel sampling programs. The ARLP Partnership's drill spacing criteria adhere to standards as defined by the USGS. The maximum acceptable distance from seam data points varies with the geologic nature of the coal ~~operations:~~ seam being studied, but generally the standard for (a) proven reserves is that points of observation are no greater than ½ mile apart and are projected to extend as a ¼ mile wide belt around each point of measurement and

	Mine	Heat
	Type	Content (BTUs	Pounds S02 per MMBTU				Classification		Reserve Assignment		Reserve Control
Operations	(1)	per pound)	<1.2	1.2-2.5	>2.5	Total	Proven	Probable	Assigned	Unassigned	Owned	Leased
			(tons in millions)
Illinois Basin Operations
Dotiki (KY)	U	12,200	—	—	81.2	81.2	56.2	25.0	38.8	42.4	27.7	53.5
Warrior (KY)	U	12,500	—	—	100.0	100.0	75.9	24.1	78.5	21.5	24.4	75.6
Hopkins (KY)	U	12,000	—	—	13.9	13.9	9.7	4.2	—	13.9	2.9	11.0
	S	11,500	—	—	7.8	7.8	7.8	—	7.8	—	7.8	—
River View (KY)	U	11,500	—	—	171.0	171.0	107.4	63.6	171.0	—	37.5	133.5
Henderson/Union (KY)	U	11,400	—	5.7	497.6	503.3	169.3	334.0	—	503.3	90.2	413.1
Onton (KY)	U	11,750	—	—	40.3	40.3	22.6	17.7	40.3	—	0.2	40.1
Sebree (KY)	U	11,400	—	—	13.6	13.6	5.8	7.8	—	13.6	3.9	9.7
Hamilton County (IL)	U	11,650	—	—	563.9	563.9	247.6	316.3	152.5	411.4	53.7	510.2
Pattiki (IL)	U	11,650	—	—	52.4	52.4	43.2	9.2	10.0	42.4	0.1	52.3
Gibson (North) (IN)	U	11,500	0.1	8.0	14.5	22.6	17.5	5.1	22.6	—	0.3	22.3
Gibson (South) (IN)	U	11,500	0.7	23.5	46.2	70.4	60.4	10.0	70.4	—	18.3	52.1
Region Total			0.8	37.2	1,602.4	1,640.4	823.4	817.0	591.9	1,048.5	267.0	1,373.4
Appalachia Operations
MC Mining (KY)	U	12,900	3.7	0.5	1.6	5.8	5.0	0.8	3.7	2.1	0.3	5.5
Mettiki (MD)	U	13,200	—	1.6	3.8	5.4	5.2	0.2	5.4	—	—	5.4
Mountain View (WV)	U	13,200	—	10.2	8.2	18.4	13.1	5.3	12.5	5.9	3.7	14.7
Tunnel Ridge (WV)	U	12,600	—	—	91.4	91.4	37.4	54.0	91.4	—	—	91.4
Region Total			3.7	12.3	105.0	121.0	60.7	60.3	113.0	8.0	4.0	117.0
Total			4.5	49.5	1,707.4	1,761.4	884.1	877.3	704.9	1,056.5	271.0	1,490.4
% of Total			0.3%	2.8%	96.9%	100.0%	50.2%	49.8%	40.0%	60.0%	15.4%	84.6%

(1)U = Underground and S = Surface

The ARLP Partnership's reserve estimates are prepared from geological data assembled and analyzed by its staff of geologists and engineers. This data is obtained through the ARLP Partnership's extensive, ongoing exploration drilling and in-mine channel sampling programs. The ARLP Partnership's drill spacing criteria adhere to standards as defined by the USGS. The maximum acceptable distance from seam data points varies with the geologic nature of the coal seam being studied, but generally the standard for (a) proven reserves is that points of observation are no greater than ½ mile apart and are projected to extend as a ¼ mile wide belt around each point of measurement and (b) probable reserves is that points of observation are between ½ and 1 ½ miles apart and are projected to extend as a ½ mile wide belt that lies ¼ mile from the points of measurement.

Reserve estimates will change from time to time to reflect mining activities, additional analysis, new engineering and geological data, acquisition or divestment of reserve holdings, modification of mining plans or mining methods, and other factors. The ARLP Partnership has historically obtained an outside audit of its reserve estimates and calculation methods every five years with the most recent audit being performed by Weir International Mining Consultants in July 2015.

Reserves represent that part of a mineral deposit that can be economically and legally extracted or produced, and reflect estimated losses involved in producing a saleable product. All of the ARLP Partnership's reserves are steam coal, except for reserves at Mettiki that can be delivered to the steam or metallurgical markets. The 3.7 million tons of reserves listed at MC Mining as <1.2 pounds of SO2 per million British thermal units ("MMBTU") are marketable as compliance coal under Phase II of CAA.

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(~~"BTU"~~b) probable ~~values~~reserves ~~are~~is ~~reported~~that onpoints anof asobservation ~~shipped,~~are ~~fully~~between ~~washed~~½ ~~basis.~~and ~~Shipments~~1 ~~that~~½ ~~are~~miles ~~either~~apart ~~fully~~and orare ~~partially~~projected ~~raw~~to ~~will~~extend ~~have~~as a ~~lower~~½ ~~BTU~~mile ~~value~~wide belt that lies ¼ mile from the points of measurement.

~~The~~Reserve ~~ARLP~~estimates ~~Partnership~~will ~~owns~~change orfrom ~~controls~~time ~~certain~~to ~~leases~~time ~~for coal deposits that do not currently meet the criteria~~ to bereflect ~~reflected~~mining as reserves but may be reclassified as reserves in the future. These tons are classified as non-reserve coal deposits and are not included in the ARLP Partnership's reported reserves. These non-reserve coal deposits include the following: Mettiki––2.9 million tonsactivities, ~~Tunnel~~additional ~~Ridge––16.6 million tons~~analysis, ~~Hamilton~~new ~~County––33.3~~engineering ~~million~~and ~~tons,~~geological ~~Warrior––7.7 million tons~~data, ~~Dotiki—2.2~~acquisition ~~million~~or ~~tons,~~divestment ~~Onton—4.6~~of ~~million~~reserve ~~tons~~holdings, ~~River~~modification ~~View––0.01~~of ~~million~~mining ~~tons,~~plans ~~Gibson~~or ~~(North)––0.4~~mining ~~million tons~~methods, ~~Gibson (South)––1.3 million tons, Elk Creek––5.2 million tons~~ and ~~Pattiki––14.7~~other ~~million tons~~factors. The ~~Henderson/Union~~ARLP ~~County~~Partnership ~~Undeveloped~~has ~~Reserves~~historically ~~account~~obtained ~~for~~an ~~the~~outside ~~majority~~audit of ~~the~~its ~~ARLP Partnership's non-~~reserve ~~coal~~estimates ~~deposits~~and ~~with~~calculation ~~200.5~~methods ~~million~~every ~~tons. In~~five ~~addition,~~years ~~there~~with ~~are 47.8 million tons located near~~ the ~~Dotiki~~most ~~complex~~recent ~~for~~audit ~~total~~being ~~non-reserve~~performed ~~coal~~by ~~deposits~~Weir ofInternational ~~337.2~~Mining ~~million~~Consultants ~~tons. For~~in ~~more information on reserve acquisitions see "Item 8~~July 2015. ~~Financial Statements and Supplementary Data––Note 3. Acquisitions."~~

Reserves represent that part of a mineral deposit that can be economically and legally extracted or produced, and reflect estimated losses involved in producing a saleable product. All of the ARLP Partnership's reserves are steam coal, except for reserves at Mettiki that can be delivered to the steam or metallurgical markets. The 2.9 million tons of reserves listed at MC Mining as <1.2 pounds of SO2 per million British thermal units ("MMBTU") are marketable as compliance coal under Phase II of CAA.

Assigned reserves are those reserves that have been designated for mining by a specific operation. Unassigned reserves are those reserves that have not yet been designated for mining by a specific operation. British thermal units ("BTU") values are reported on an as shipped, fully washed basis. Shipments that are either fully or partially raw will have a lower BTU value.

The ARLP Partnership owns or controls certain leases for coal deposits that do not currently meet the criteria to be reflected as reserves but may be reclassified as reserves in the future. These tons are classified as non-reserve coal deposits and are not included in the ARLP Partnership's reported reserves. These non-reserve coal deposits include the following: Mettiki––2.9 million tons, Tunnel Ridge––17.4 million tons, Hamilton––33.3 million tons, Warrior––4.8 million tons, Dotiki—0.6 million tons, Onton—4.6 million tons, Gibson (North)––0.4 million tons, Gibson (South)––1.2 million tons, Elk Creek––4.9 million tons and Pattiki––53.5 million tons. The Henderson/Union Reserves account for the majority of the ARLP Partnership's non-reserve coal deposits with 199.9 million tons. In addition, there are 17.3 million tons located near the Dotiki complex for total non-reserve coal deposits of 340.8 million tons.

The ARLP Partnership leases most of its reserves and generally has the right to maintain leases in force until the exhaustion of mineable and merchantable coal located within the leased premises or a larger coal reserve area. These leases provide for royalties to be paid to the lessor at a fixed amount per ton or as a percentage of the sales price. Many leases require payment of minimum royalties, payable either at the time of the execution of the lease or in periodic installments, even if no mining activities have begun. These minimum royalties are normally credited against the production royalties owed to a lessor once coal production has commenced.

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Mining Operations

The following table sets forth production and other data about the ARLP Partnership's mining operations:

Tons Produced

Operations

Location

~~2016~~2017

~~2015~~2016

~~2014~~2015

Transportation

Equipment

(in millions)

Illinois Basin Operations

Dotiki

Kentucky

32.76

43.07

34.90

CSX, PAL, truck, barge

Warrior

Kentucky

3.86

43.08

54.10

CSX, PAL, truck, barge

Hopkins

Kentucky

~~0.4~~—

20.94

32.09

CSX, PAL, truck, barge

CM, TS

River View

Kentucky

89.60

98.16

9.31

Barge

Onton

Kentucky

—

~~1.8~~—

21.48

Barge, truck

Hamilton

Illinois

36.01

23.70

—2.7

CSX, EVWR, NS, truck, barge

LW, CM

Pattiki

Illinois

~~1.9~~—

21.49

2.64

CSX, EVWR, barge

Gibson (North)

Indiana

—

~~2.2~~—

32.82

CSX, NS, truck, barge

Gibson (South)

Indiana

46.0

24.90

02.89

CSX, NS, truck, barge

Region Total

2527.43

3225.04

3032.90

Appalachia Operations

MC Mining

Kentucky

1.24

1.52

1.65

CSX, truck, barge

Mountain View

West Virginia

2.0

2.1

1.9

CSX, truck

LW, CM

Mettiki

WV/MD

2.1

2.0

2.1

CSX, truck

LW, CM

Tunnel Ridge

West Virginia

6.68

56.6

65.36

Barge, WLE, NS

LW, CM

Region Total

910.83

9.28

9.82

TOTAL

3537.26

4135.2

4041.72


CSX	-	CSX Railroad
EVWR	-	Evansville Western Railroad
NS	-	Norfolk Southern Railroad
PAL	-	Paducah & Louisville Railroad
WLE	-	Wheeling & Lake Erie Railroad
CM	-	Continuous Miner
LW	-	Longwall
TS	-	Truck, Shovel, Front End Loader or Dozer

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ITEM 3. LEGAL PROCEEDINGS

We are not engaged in any material litigation. From time to time the ARLP Partnership is a party to litigation matters incidental to the conduct of its business. The ARLP Partnership initiated litigation on January 15, 2015 alleging that a customer anticipatorily breached a coal supply contract when it notified the ARLP Partnership that it would not accept coal shipments under the contract after April 15, 2015. The contract ~~obligates~~obligated the customer to purchase more than 5.0 million tons during the period between April 16, 2015 and the end of the contract term on December 31, 2021. On February 18, 2018, the ARLP Partnership reached agreement with the customer and certain of its affiliates to settle the litigation. The agreement includes a $93.0 million payment to the ARLP Partnership isand ~~seeking~~certain tofuture ~~recover~~coal ~~damages~~supply ~~resulting~~commitments. In addition, the ARLP Partnership will acquire certain coal reserves for $2.0 million from an affiliate of the customer's. As ~~alleged~~a ~~breach~~result of ~~contract~~certain costs related to this settlement, the ARLP Partnership expects to realize approximately $80 million from the recovery.

It is the opinion of management that the ultimate resolution of the ARLP Partnership's pending litigation matters will not have a material adverse effect on our financial condition, results of operation or liquidity. However, we cannot assure you that disputes or litigation will not arise or that the ARLP Partnership will be able to resolve any such future disputes or litigation in a satisfactory manner. The information under "General Litigation" and "Other" in "Item 8. Financial Statements and Supplementary Data—Note 19. Commitments and Contingencies" is incorporated herein by this reference.

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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 Annual Report on Form 10-K.

5051

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PART II

ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED UNITHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

The common units representing limited partners' interests are listed on the NASDAQ Global Select Market under the symbol "AHGP." The common units began trading on May 10, 2006. On February 8, ~~2017~~2018, the closing market price for the common units was $3026.9082 per unit and there were 59,863,000 common units outstanding. There were approximately 118,~~460~~891 record holders of common units at December 31, ~~2016~~2017.

The following table sets forth the range of high and low sales prices per common unit and the amount of cash distributions declared and paid with respect to the units, for the two most recent fiscal years:

	High		Low		Distributions Per Unit
1st Quarter 2015	$	62.59	$	48.25	$	0.9375 (paid May 20, 2015)
2nd Quarter 2015	$	52.78	$	38.36	$	0.96 (paid August 19, 2015)
3rd Quarter 2015	$	40.15	$	29.81	$	0.96 (paid November 19, 2015)
4th Quarter 2015	$	35.76	$	15.71	$	0.96 (paid February 19, 2016)
1st Quarter 2016	$	21.05	$	12.05	$	0.55 (paid May 20, 2016)
2nd Quarter 2016	$	21.30	$	13.76	$	0.55 (paid August 19, 2016)
3rd Quarter 2016	$	28.00	$	20.29	$	0.55 (paid November 18, 2016)
4th Quarter 2016	$	32.70	$	26.00	$	0.55 (paid February 17, 2017)
1st Quarter 2017	$	32.31	$	25.44	$	0.55 (paid May 19, 2017)
2nd Quarter 2017	$	30.48	$	22.71	$	0.73 (paid August 18, 2017)
3rd Quarter 2017	$	29.43	$	23.79	$	0.735 (paid November 17, 2017)
4th Quarter 2017	$	28.77	$	23.83	$	0.7425 (paid February 20, 2018)

We will distribute 100% of our available cash (including any held by MGP) within 50 days after the end of each quarter to unitholders of record. Available cash is generally defined as all cash and cash equivalents on hand at the end of each quarter less reserves established by AGP in its reasonable discretion for future cash requirements. These reserves are retained to provide for the conduct of our business, the payment of debt principal and interest and to provide funds for future distributions.

Equity Compensation Plans

The information relating to our equity compensation plans required by Item 5 is incorporated by reference to such information as set forth in "Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters" contained herein.

ITEM 6. SELECTED FINANCIAL DATA

Since we own MGP, our financial statements reflect the consolidated results of the ARLP Partnership. The amount of earnings of the ARLP Partnership allocated to its limited partners' interests not owned by us is reflected as a noncontrolling interest in our consolidated income statement and balance sheet. Our consolidated financial statements do not differ materially from those of the ARLP Partnership. The differences between our financial statements and those of the ARLP Partnership are primarily attributable to (a) amounts reported as noncontrolling interests and (b) additional general and administrative costs and taxes attributable to us. The additional general and administrative costs principally consist of costs incurred by us as a result of being a publicly traded partnership and amounts paid to Alliance Coal under an Administrative Services Agreement in addition to amounts paid to AGP under our partnership agreement.

51 Our historical financial data below were derived from the AHGP Partnership's audited consolidated financial statements as of and for the years ended December 31, 2017, 2016, 2015, 2014 and 2013. Prior years results presented have been recast to reflect a reclassification of depreciation and depletion capitalized into coal inventory as

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~~Our~~adjustments ~~historical~~to ~~financial~~Depreciation, ~~data~~depletion ~~below were derived from the AHGP Partnership's audited consolidated financial statements as of~~ and ~~for~~amortization ~~the~~rather ~~years~~than ~~ended~~Operating ~~December 31,~~expenses ~~2016,~~(excluding ~~2015~~depreciation, ~~2014,~~depletion ~~2013~~ and ~~2012~~amortization).

(in millions, except unit, per unit and per ton data)	Year Ended December 31,
	2016		2015		2014		2013		2012
	2017		2016		2015		2014		2013
Statements of Income
Sales and operating revenues:
Coal sales	$	1,~~861~~711.81	$	21,~~158~~861.08	$	2,~~208~~158.60	$	2,~~137~~208.46	$	12,~~979~~137.4
Transportation revenues		3041.17		3330.61		2633.06		3226.60		2232.06
Other sales and operating revenues		3943.10		8139.71		6581.87		3565.28		3235.52
Total revenues		1,~~931~~795.08		21,~~273~~931.30		2,~~300~~273.43		2,~~205~~300.24		2,~~033~~205.92
Expenses:
Operating expenses (excluding depreciation, depletion and amortization)		1,~~138~~095.82		1,~~377~~124.18		1,~~383~~386.48		1,~~398~~383.84		1,~~303~~398.38
Transportation expenses		3041.17		3330.61		2633.06		3226.60		2232.06
Outside coal purchases		~~1.5~~—		01.35		—0.3		~~2.0~~—		382.60
General and administrative		7563.13		6975.1		7669.71		6576.37		6265.83
Depreciation, depletion and amortization		~~322~~269.50		~~333~~336.75		~~274~~324.60		~~264~~274.96		~~218~~264.19
Asset impairment		—		~~100.1~~—		—100.1		—		~~19.0~~—
Total operating expenses		1,~~568~~469.02		1,~~913~~568.90		1,~~760~~913.79		1,~~763~~760.67		1,~~663~~763.86
Income from operations		~~363~~326.06		~~359~~363.40		~~539~~359.74		~~441~~539.67		~~370~~441.16
Interest expense (net of interest capitalized)		(3039.74)		(3130.27)		(3331.62)		(2733.06)		(2827.70)
Interest income		—0.1		~~1.5~~—		1.75		1.07		01.20
Equity in income (loss) of affiliates		3.5		(49.0)		(16.7)		(24.4)		(14.7)
Equity investment income (loss)		13.9		3.5		(49.0)		(16.7)		(24.4)
Acquisition gain, net		—		22.5		—		—		—
Cost investment income		6.4		—		—		—		—
Other income		0.7		1.0		1.6		1.8		3.2
Acquisition gain, net		—		—		22.5		—		—
Income before income taxes		336.5		304.2		492.7		393.0		330.1
Debt extinguishment loss		(8.1)		—		—		—		—
Income tax expense (benefit)		—		—		—		1.4		(1.1)
Other income		3.0		0.7		1.0		1.6		1.8
Net income		336.5		304.2		492.7		391.6		331.2
Income before income taxes		302.5		336.5		304.2		492.7		393.0
Income attributable to noncontrolling interests		(150.6)		(92.9)		(208.3)		(157.7)		(135.1)
Income tax expense		0.2		—		—		—		1.4
Net income attributable to Alliance Holdings GP, L.P. (“AHGP”)	$	185.9	$	211.3	$	284.4	$	233.9	$	196.1
Net income		302.3		336.5		304.2		492.7		391.6
Basic and diluted net income of AHGP per limited partner unit	$	3.11	$	3.53	$	4.75	$	3.91	$	3.28
Less: Net income attributable to noncontrolling interests		(116.3)		(150.6)		(92.9)		(208.3)		(157.7)
Distributions paid per limited partner unit	$	2.6100	$	3.7725	$	3.4375	$	3.095	$	2.7225
Net income attributable to Alliance Holdings GP, L.P. ("AHGP")	$	186.0	$	185.9	$	211.3	$	284.4	$	233.9
Basic and diluted net income of AHGP per limited partner unit	$	3.11	$	3.11	$	3.53	$	4.75	$	3.91
Distributions paid per limited partner unit	$	2.5650	$	2.6100	$	3.7725	$	3.4375	$	3.095
Weighted average number of units outstanding-basic and diluted		59,863,000		59,863,000		59,863,000		59,863,000		59,863,000
Balance Sheet Data:
Working capital (1)	$	(466.07)	$	(~~103~~46.50)	$	(76103.85)	$	~~113~~(76.78)	$	75113.37
Total assets		2,~~197~~221.73		2,~~366~~197.57		2,~~288~~366.85		2,~~126~~288.78		12,~~958~~126.87
Long-term obligations (2)		~~485~~473.0		~~658~~485.60		~~606~~658.96		~~848~~606.49		~~791~~848.64
Total liabilities		1,~~100~~068.04		1,~~372~~100.40		1,~~270~~372.54		1,~~271~~270.15		1,~~251~~271.01
Partners’ capital	$	1,097.6	$	994.1	$	1,018.3	$	855.6	$	707.8
Partners' capital	$	1,152.9	$	1,097.6	$	994.1	$	1,018.3	$	855.6
Other Operating Data:
Tons sold		3637.78		4036.27		3940.72		3839.87		3538.28
Tons produced		3537.26		4135.2		4041.72		3840.87		3438.8
Coal sales per ton sold (3)	$	5045.7624	$	5350.6276	$	5553.5962	$	55.0459	$	5655.2804
Cost per ton sold (4)	$	3128.0995	$	3430.2271	$	34.8246	$	3634.0782	$	3836.1507
Other Financial Data:
Net cash provided by operating activities	$	~~700~~554.71	$	~~714~~700.47	$	~~734~~714.84	$	~~702~~734.98	$	~~546~~702.29
Net cash used in investing activities		(~~191~~244.8)		(~~355~~191.98)		(~~441~~355.29)		(~~426~~441.02)		(~~623~~426.40)
Net cash used in financing activities		(~~503~~345.12)		(~~348~~503.1)		(~~363~~348.71)		(~~209~~363.7)		(~~173~~209.27)
EBITDA (5)		~~689~~610.7		~~667~~703.67		~~799~~657.19		~~684~~799.01		~~576~~684.70
Adjusted EBITDA (5)		~~689~~618.79		~~745~~703.27		~~799~~735.14		~~684~~799.01		~~595~~684.70
Maintenance capital expenditures (6)	$	93140.30	$	~~236~~93.3	$	236.3	$	~~222~~236.43	$	~~282~~222.64

(1)

Working capital is impacted by current maturities of long-term debt. For information regarding long-term debt, please read "Item 8. Financial Statements and Supplementary Data—Note 7. Long-Term Debt."

(2)

Long-term obligations include long-term portions of debt and capital lease obligations.

(3)

Coal sales per ton sold are based on total coal sales divided by tons sold.

~~(4) Cost per ton sold is based on the total of operating expenses and outside coal purchases divided by tons sold.~~ 53

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(54) ~~EBITDA~~Cost ~~and~~per ~~Adjusted~~ton ~~EBITDA~~sold ~~are financial measures not calculated in accordance with generally accepted accounting principles ("GAAP"). EBITDA~~ is ~~defined~~based ason ~~net income (prior to~~ the ~~allocation~~total of ~~noncontrolling~~operating ~~interest)~~expenses ~~before net interest expense, income taxes~~ and ~~depreciation,~~outside ~~depletion~~coal ~~and~~purchases ~~amortization)~~divided ~~and~~by ~~Adjusted~~tons ~~EBITDA is EBITDA modified for certain items that may not reflect the trend of future results, such as asset impairments and gains and losses on acquisition related accounting~~sold.

(5)

EBITDA and Adjusted EBITDA are financial measures not calculated in accordance with generally accepted accounting principles ("GAAP"). EBITDA is defined as net income (prior to the allocation of noncontrolling interest) before net interest expense, income taxes and depreciation, depletion and amortization. Adjusted EBITDA is EBITDA modified for certain items that may not reflect the trend of future results, such as asset impairments and gains and losses from acquisition valuation-related accounting and debt extinguishment losses.

EBITDA 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. We believe that the presentation of EBITDA provides useful information to investors regarding our performance and results of operations because EBITDA, when used in conjunction with related GAAP financial measures, (i) provides additional information about our core operating performance and ability to generate and distribute cash flow, (ii) provides investors with the financial analytical framework upon which we base financial, operational, compensation and planning decisions and (iii) presents a measurement that investors, rating agencies and debt holders have indicated is useful in assessing us and our results of operations.

We believe Adjusted EBITDA is a useful measure for investors because it further demonstrates the performance of assets without regard to items that may not reflect the trend of future results.

EBITDA and Adjusted EBITDA should not be considered as alternatives to net income attributable to AHGP, net income, income from operations, cash flows from operating activities or any other measure of financial performance presented in accordance with GAAP. EBITDA and Adjusted EBITDA are not intended to represent cash flow and do not represent the measure of cash available for distribution. Our method of computing EBITDA and Adjusted EBITDA may not be the same method used to compute similar measures reported by other companies, or EBITDA and Adjusted EBITDA may be computed differently by us in different contexts (e.g. public reporting versus computation under financing agreements).

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The following table presents a reconciliation of (a) GAAP "Cash Flows Provided by Operating Activities" to non-GAAP Adjusted EBITDA and EBITDA and (b) non-GAAP Adjusted EBITDA and EBITDA to GAAP "Net income attributable to AHGP":

	Year Ended December 31,
	2016		2015		2014		2013		2012
	2017		2016		2015		2014		2013
	(in thousands)
Cash flows provided by operating activities	$	~~700~~554,~~725~~082	$	~~714~~700,~~408~~725	$	~~734~~714,~~830~~408	$	~~702~~734,~~919~~830	$	~~546~~702,~~224~~919
Non-cash compensation expense		(1412,~~229~~279)		(1214,~~854~~229)		(1112,~~560~~854)		(911,~~193~~560)		(79,~~607~~193)
Settlement of deferred directors compensation		~~218~~26		~~177~~218		~~218~~177		—218		~~459~~—
Asset retirement obligations		(3,~~769~~793)		(3,~~192~~769)		(23,~~730~~192)		(32,~~004~~730)		(23,~~853~~004)
Coal inventory adjustment to market		—(449)		~~(1,952)~~—		(~~377~~1,952)		(~~2,811~~377)		(2,~~978~~811)
Equity in loss of affiliates		3,543		(49,046)		(16,648)		(24,441)		(14,650)
Equity investment income (loss)		13,860		3,543		(49,046)		(16,648)		(24,441)
Net gain (loss) on sale of property, plant and equipment		76		1		4,409		(3,475)		(147)
Distributions received from investments		(13,939)		(2,719)		—		—		—
Valuation allowance of deferred tax assets		1,365		(1,557)		(1,636)		(3,483)		—
Paid-in-kind distributions received from cost investment		6,398		—		—		—		—
Other		(3,300)		(6,388)		5,151		6,251		3,815
Net gain (loss) on sale of property, plant and equipment		696		76		1		4,409		(3,475)
Net effect of working capital changes		(25,567)		75,856		55,578		(6,258)		46,116
Valuation allowance of deferred tax assets		3,339		1,365		(1,557)		(1,636)		(3,483)
Interest expense, net		30,655		29,693		31,913		26,081		28,453
Other		(6,212)		(3,300)		(6,388)		5,151		6,251
Income tax expense (benefit)		14		21		—		1,397		(1,082)
Net effect of working capital changes		37,658		(8,848)		66,126		55,578		(6,258)
Adjusted EBITDA		689,731		745,167		799,148		683,983		595,750
Interest expense, net		39,283		30,655		29,693		31,913		26,081
Asset impairment		—		(100,130)		—		—		(19,031)
Income tax expense		211		14		21		—		1,397
Acquisition gain, net		—		22,548		—		—		—
Adjusted EBITDA		618,881		703,731		735,437		799,148		683,983
EBITDA		689,731		667,585		799,148		683,983		576,719
Asset impairment		—		—		(100,130)		—		—
Depreciation, depletion and amortization		(322,509)		(333,713)		(274,566)		(264,911)		(218,122)
Acquisition gain, net		—		—		22,548		—		—
Interest expense, net		(30,655)		(29,693)		(31,913)		(26,081)		(28,453)
Debt extinguishment loss		(8,148)		—		—		—		—
Income tax (expense) benefit		(14)		(21)		—		(1,397)		1,082
EBITDA		610,733		703,731		657,855		799,148		683,983
Net income		336,553		304,158		492,669		391,594		331,226
Depreciation, depletion and amortization		(268,981)		(336,509)		(323,983)		(274,566)		(264,911)
Net income attributable to noncontrolling interest		(150,619)		(92,846)		(208,318)		(157,721)		(135,158)
Interest expense, net		(39,283)		(30,655)		(29,693)		(31,913)		(26,081)
Net income attributable to AHGP	$	185,934	$	211,312	$	284,351	$	233,873	$	196,068
Income tax expense		(211)		(14)		(21)		—		(1,397)
Net income		302,258		336,553		304,158		492,669		391,594
Net income attributable to noncontrolling interest		(116,270)		(150,619)		(92,846)		(208,318)		(157,721)
Net income attributable to AHGP	$	185,988	$	185,934	$	211,312	$	284,351	$	233,873

(6)

The ARLP Partnership's maintenance capital expenditures, as defined under the terms of its partnership agreement, are those capital expenditures required to maintain, over the long-term, the operating capacity of its capital assets.

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ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

General

The following discussion of our financial condition and results of operations should be read in conjunction with the historical financial statements and notes thereto included ~~elsewhere~~ in ~~this~~Item ~~Annual Report on Form 10-K~~8. ~~For~~ ~~more~~Financial ~~detailed~~Statements ~~information~~and ~~regarding~~Supplementary ~~the~~Data ~~basis~~where ofyou ~~presentation~~can ~~for~~find ~~the~~more ~~following~~detailed ~~financial~~ information, ~~please~~in ~~see~~ "~~Item 8. Financial Statements and Supplementary Data—~~Note 1. Organization and Presentation" and "Note 2. Summary of Significant Accounting Policies." regarding the basis of presentation supporting the following financial information.

Executive Overview

The AHGP Partnership

Our cash flows currently consist of distributions from ARLP on our ARLP partnership interests~~, including the IDRs that we own~~. We reflect our ownership interest in the ARLP Partnership on a consolidated basis, which means that our financial results are combined with the ARLP Partnership's financial results and the results of our other subsidiaries. The earnings of the ARLP Partnership allocated to its limited partners' interests not owned by us and, prior to the Exchange Transaction, the ARLP Partnership earnings allocated to SGP's general partner interest in the ARLP Partnership and the Intermediate Partnership are reflected as a noncontrolling interest in our consolidated income statement and balance sheet. ~~Accordingly, the noncontrolling partners' interest in the ARLP Partnership's net income is reflected as reduction of consolidated net income in our results of operations.~~ In addition to the ARLP Partnership, our ~~historical consolidated~~ results of operations include the results of operations of MGP II and MGP, our direct and indirect wholly owned ~~subsidiary~~subsidiaries.

The AHGP Partnership's results of operations principally reflect the results of operations of the ARLP Partnership adjusted for noncontrolling partners' interest in the ARLP Partnership's net income. Accordingly, the discussion of our financial position and results of operations in this "Management's Discussion and Analysis of Financial Condition and Results of Operations" reflects the operating activities and results of operations of the ARLP Partnership.

expanding its operations by adding and developing mines and coal reserves in existing, adjacent or neighboring properties;

extending the lives of its current mining operations through acquisition and development of coal reserves using its existing infrastructure;

continuing to make productivity improvements to remain a low-cost producer in each region in which it operates;

strengthening its position with existing and future customers by offering a broad range of coal qualities, transportation alternatives and customized services;

developing strategic relationships to take advantage of opportunities within the coal industry and MLP sector; and

· ~~making~~continuing ~~equity~~to make accretive investments ~~for~~in ~~the~~oil ~~purchase~~and ofgas related activities, such as oil and gas mineral interests and gas compression services in various geographic locations within producing basins in the continental U.S.

The ARLP Partnership

The ARLP Partnership is a diversified producer and marketer of coal primarily to major U.S. utilities and industrial users and was the first such producer and marketer in the nation to be a publicly traded master limited partnership. The ARLP Partnership is currently the second-largest coal producer in the eastern U. S. In ~~2016~~2017, the ARLP Partnership produced and sold 3537.26 million and 3637.78 million tons of coal, respectively. The coal it ~~produced~~sold in ~~2016~~2017 was approximately 1525.24% low-sulfur coal, 6339.89% medium-sulfur coal and 2134.07% high-sulfur coal. Based on market ~~conditions~~expectations, the ARLP Partnership classifies low-sulfur coal as coal with a sulfur content of less than 1.5%, medium-sulfur coal as coal with a sulfur content of 1.5% to 3%, and high-sulfur coal as coal with a sulfur content of greater than 3%. The BTU content of the ARLP Partnership's coal ranges from 11,400 to 13,200.

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~~medium-sulfur~~ The ~~coal~~ARLP asPartnership ~~coal~~operates ~~with~~eight aunderground ~~sulfur~~mining ~~content~~complexes ofin ~~1.5%~~Illinois, toIndiana, 3%Kentucky, Maryland, and ~~high-sulfur~~West ~~coal~~Virginia, as ~~coal~~well ~~with~~as a ~~sulfur~~coal-loading ~~content~~terminal ofon ~~greater~~the ~~than~~Ohio 3%River at Mt. Vernon, Indiana. ~~The~~In ~~BTU~~addition, ~~content~~the ofARLP Partnership owns equity interests in various oil and gas mineral interests and gas compression services in various geographic locations within producing basins in the continental U.S. At December 31, 2017, the ARLP Partnership's had approximately 1.67 billion tons of proven and probable coal ~~ranges~~reserves ~~from 11~~in Illinois,~~400~~ Indiana, toKentucky, 13Maryland,~~200~~ Pennsylvania and West Virginia. We believe the ARLP Partnership controls adequate reserves to implement its currently contemplated mining plans. Please see "Item 1. Business—Mining Operations" for further discussion of the ARLP Partnership's mines.

~~The~~On ~~ARLP~~July ~~Partnership~~19, ~~operates~~2017, ~~eight~~Alliance ~~underground~~Minerals ~~mining~~purchased ~~complexes~~$100 million of Series A-1 Preferred Interests from Kodiak, ~~including~~a ~~the~~privately-held ~~Hamilton~~company ~~longwall~~providing ~~mining~~large-scale, ~~complex~~high-utilization ingas ~~southern~~compression ~~Illinois~~assets ~~which~~to ~~the~~customers ~~ARLP~~operating ~~Partnership~~primarily ~~acquired~~in onthe Permian Basin. On July 31, 2015, byHamilton ~~purchasing~~acquired the remaining equity ~~ownership~~interests inof White Oak, ~~and~~from ~~operate~~White aOak ~~coal-loading~~Finance ~~terminal~~Inc. onand ~~the~~other ~~Ohio River at Mt~~parties. ~~Vernon, Indiana.~~ Prior to ~~July~~the ~~31,~~acquisition ~~2015,~~ the ARLP Partnership ~~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. ~~The~~ ~~ARLP~~For ~~Partnership~~more ~~also~~information ~~owns~~on the ~~idled~~White ~~Onton~~Oak ~~mine and idled Gibson North mine. In addition~~Acquisition, ~~the~~please ~~ARLP~~read ~~Partnership~~"Item owns through its consolidated affiliate, Cavalier Minerals, an equity interest in AllDale Minerals for the purchase of oil and gas mineral interests in various geographic locations within producing basins in the continental U8.S. ~~and~~Financial ~~plans~~Statements ~~to make similar additional equity investments. At December 31, 2016, the ARLP Partnership had approximately 1.76 billion tons of proven~~ and ~~probable~~Supplementary ~~coal~~Data—Note ~~reserves in Illinois, Indiana, Kentucky, Maryland, Pennsylvania and West Virginia~~3. We ~~believe the ARLP Partnership controls adequate reserves to implement its currently contemplated mining plans~~Acquisitions. ~~Please see~~ "~~Item~~ ~~1. Business—Mining Operations" for further discussion of the ARLP Partnership's mines.~~

In ~~2016~~2017, approximately 9080.30% of the ARLP Partnership's sales tonnage was purchased by U.S. electric utilities, with the balance sold to third-party resellers and industrial consumers. Although many utility customers recently have appeared to favor a shorter-term contracting strategy, in ~~2016~~2017, approximately 8771.7% of the ARLP Partnership's sales tonnage was sold under long-term contracts. The ARLP Partnership's long-term contracts contribute to its stability and profitability by providing greater predictability of sales volumes and sales prices. In ~~2016~~2017, approximately 9385.09% of the medium- and high-sulfur coal was sold to utility plants with installed pollution control devices. These devices, also known as scrubbers, eliminate substantially all emissions of sulfur dioxide.

As discussed in more detail in "Item 1A. Risk Factors," the ARLP Partnership's results of operations could be impacted by prices for items that are used in coal production such as steel, electricity and other supplies, unforeseen geologic conditions or mining and processing equipment failures and unexpected maintenance problems, and by the availability or reliability of transportation for coal shipments. Moreover, the regulatory environment in which we operate has grown increasingly stringent as a result of legislation and initiatives pursued during the years prior to the current Trump administration. Additionally, the ARLP Partnership's results of operations could be impacted by its ability to obtain and renew permits necessary for its operations, secure or acquire coal reserves, or find replacement buyers for coal under contracts with comparable terms to existing contracts. ~~Moreover, the regulatory environment has grown increasingly stringent in recent years.~~ As outlined in "Item 1. Business—Regulation and Laws," a variety of measures taken by regulatory agencies in the U.S. and abroad in response to the perceived threat from climate change attributed to GHG emissions could substantially increase compliance costs for the ARLP Partnership and its customers and reduce demand for coal, which could materially and adversely impact its results of operations. For additional information regarding some of the risks and uncertainties that affect the ARLP Partnership's business and the industry in which it operates, see "Item 1A. Risk Factors."

As discussed above, on February 22, 2018, our Board of Directors and the board of directors of ARLP's general partner approved the Simplification Agreement, pursuant to which we would become a wholly owned subsidiary of ARLP. For more information regarding the Simplification Agreement, please see 'Item 1. Business – Simplification Transactions.'

The ARLP Partnership's principal expenses related to the production of coal are labor and benefits, equipment, materials and supplies, maintenance, royalties and excise taxes. The ARLP Partnership employs a totally union-free workforce. Many of the benefits of the ARLP Partnership's union-free workforce are related to higher productivity and are not necessarily reflected in its direct costs. In addition, transportation costs may be substantial and are often the determining factor in a coal consumer's contracting decision.

The ARLP Partnership's mining operations are located near many of the major eastern utility generating plants and on major coal hauling railroads in the eastern U.S. The River View and Tunnel Ridge mines and Mt. Vernon transloading facility are located on the Ohio River and the idled Onton mine is located on the Green River in western Kentucky.

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.57

· Illinois Basin reportable segment is comprised of multiple operating segments, including the following current operating mining complexes: a) Webster County Coal's Dotiki mining complex, b) Gibson County

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~~Coal's~~ We ~~mining~~have ~~complex,~~two ~~which~~reportable ~~includes~~segments: ~~the~~Illinois ~~Gibson~~Basin ~~North~~and ~~mine~~Appalachia ~~(currently~~and ~~idled)~~an ~~and~~"all ~~Gibson~~other" ~~South~~category ~~mine,~~referred c)to ~~Warrior's~~as ~~mining~~Other ~~complex,~~and d)Corporate. Our ~~River~~reportable ~~View's~~segments ~~mining~~correspond ~~complex~~to ~~and~~major e)coal ~~the~~producing ~~Hamilton~~regions ~~mining~~in ~~complex~~the eastern U.S. Factors Insimilarly ~~April~~affecting ~~2014,~~financial ~~initial~~performance ~~production~~of ~~began~~our atoperating ~~the~~segments ~~Gibson~~within ~~South~~each ~~mine.~~of ~~The~~these ~~Gibson~~two ~~North~~reportable ~~mine~~segments ~~has~~generally ~~been~~include ~~idled~~coal ~~since~~quality, ~~the~~geology, ~~fourth~~coal ~~quarter~~marketing ofopportunities, ~~2015~~mining inand ~~response~~transportation tomethods ~~market~~and ~~conditions~~regulatory issues.

~~The~~· Illinois Basin reportable segment ~~also~~is ~~includes~~comprised ~~White~~of ~~County~~multiple ~~Coal's~~operating ~~Pattiki~~segments, including currently operating mining ~~complex,~~complexes ~~Hopkins~~(a) Webster County Coal's Dotiki mining complex, ~~which~~(b) ~~includes~~Gibson ~~the~~County ~~Elk Creek mine, the Pleasant View surface mineable reserves and the Fies underground project, Sebree~~Coal's mining complex, which includes the ~~Onton~~Gibson ~~mine,~~North ~~Steamport~~ and ~~certain~~Gibson ~~Sebree~~South ~~reserves~~mines, ~~CR Services, LLC, CR Machine Shop, LLC, certain properties and equipment of Alliance Resource Properties, ARP Sebree, LLC~~ (~~"ARP Sebree"~~c), ~~ARP~~Warrior's ~~Sebree~~mining ~~South~~complex, ~~LLC, UC Coal, LLC~~ (~~"UC Coal"~~d) ~~and~~River ~~its~~View's ~~subsidiaries,~~mining UCcomplex ~~Mining, LLC,~~ and UC(e) ~~Processing,~~the ~~LLC. The~~Hamilton ~~Pattiki~~mining ~~mine ceased production in December 2016~~complex. The ~~Elk~~Gibson ~~Creek~~North mine ~~depleted~~has ~~its~~been ~~reserves~~idled insince ~~March 2016 and ceased production on April 1, 2016. The Sebree properties,~~ the ~~Pleasant View surface mineable reserves and the Fies underground project are held by the ARLP Partnership for future mine development. During the~~ fourth quarter of 2015, ~~the ARLP Partnership idled its Onton mine~~ in response to market conditions~~. In~~ ~~the~~but ~~fourth~~is ~~quarter~~expected ofto ~~2014~~resume ~~and February 2015, Alliance Resource Properties acquired reserves that would allow increased~~ production from the River View mine, add three new potential development projects for the ARLP Partnership's organic growth strategy and may significantly extend the life of the Dotiki mine. UC Coal equipment assets acquired in ~~2015 continue being deployed as needed at various Illinois Basin operating mines~~2018. For information regarding the permitting process and matters that could hinder or delay the process, please read "Item 1. Business—Regulation and Laws—Mining Permits and Approvals". For information regarding Alliance Resource Properties' acquisition of reserves in December 2014 and February 2015 and the ARLP Partnership's assumption of control at the Hamilton mine in July 2015, please read "Item 8. Financial Statements and Supplementary Data—Note 3. Acquisitions."

· The ~~Appalachia~~Illinois Basin reportable segment isalso ~~comprised~~includes ofWhite ~~multiple~~County ~~operating~~Coal's ~~segments~~Pattiki mining complex, ~~including~~Hopkins ~~the~~County ~~Mettiki~~Coal's mining complex, which includes the ~~Tunnel~~Elk ~~Ridge~~Creek ~~mining~~mine, ~~complex~~the Pleasant View surface mineable reserves and the MCFies ~~Mining~~underground project, Sebree's mining complex., ~~The~~which ~~Mettiki~~includes ~~mining~~the ~~complex~~Onton ~~includes~~mine, ~~Mettiki~~Steamport ~~Coal~~and ~~(WV)~~certain 'sreserves, ~~Mountain~~CR ~~View~~Services, ~~mine~~LLC, CR Machine Shop, LLC, certain properties and ~~Mettiki~~equipment ~~Coal's~~of ~~preparation~~Alliance ~~plant.~~Resource ~~During~~Properties, ~~the~~ARP ~~fourth~~Sebree, ~~quarter~~LLC, ~~2015~~ARP Sebree South, ~~the~~LLC, ~~ARLP~~and ~~Partnership~~UC ~~surrendered~~Coal, ~~the~~LLC ~~Penn~~and ~~Ridge~~its ~~lease~~subsidiaries, asUC ~~those~~Mining, ~~reserves~~LLC, ~~were~~and noUC ~~longer~~Processing, aLLC. The ~~core~~Pattiki ~~part~~mine ofceased ~~its~~production ~~foreseeable~~in ~~development~~December ~~plans~~2016. The ~~Please~~Elk ~~read~~Creek ~~"Item~~mine 8.depleted ~~Financial~~its ~~Statements~~reserves in March 2016 and ~~Supplementary~~ceased ~~Data—Note~~production 4on April 1, 2016. The ~~Long-Lived~~ARLP ~~Asset~~Partnership's ~~Impairment"~~Onton ~~for~~mine ~~further~~has ~~discussion~~been idled since the fourth quarter of ~~this~~2015 ~~surrender~~in response to market conditions. UC Coal, LLC equipment assets acquired in 2015 continue to be deployed as needed at various Illinois Basin operating mines.

· ~~Other~~Appalachia ~~and~~reportable ~~Corporate~~segment ~~includes~~is ~~marketing~~comprised ~~and administrative expenses, ASI and its subsidiaries included in the Matrix Group, ASI's ownership~~ of ~~aircraft,~~multiple ~~Mt.~~operating ~~Vernon's dock activities; coal brokerage activity~~segments, ~~MAC's~~including ~~manufacturing and sales (primarily to~~ the ~~ARLP~~Mettiki ~~Partnership's~~mining ~~mines) of rock dust~~complex, ~~certain~~the ~~activities~~Tunnel ofRidge ~~Alliance~~mining ~~Resource~~complex ~~Properties, throughput receivables~~ and ~~prior~~the ~~workers'~~MC ~~compensation~~Mining ~~and~~mining ~~pneumoconiosis~~complex. ~~liabilities~~The ~~from~~Mettiki ~~Pontiki~~mining ~~Coal,~~complex ~~LLC~~includes Mettiki (~~"Pontiki"~~WV),'s ~~which~~Mountain ~~sold~~View ~~most~~mine ~~of its assets in May 2014, Wildcat Insurance, which was established in September 2014 to assist the ARLP Partnership with its insurance requirements, Alliance Minerals~~ and ~~its~~Mettiki ~~affiliate, Cavalier Minerals, which holds equity investments in AllDale Minerals and AROP Funding, LLC~~ (~~"AROP Funding"~~MD).'s ~~Please~~preparation ~~read "Item 8~~plant. Financial Statements and Supplementary Data—Note 7. Long-Term Debt", "—Note 10. Variable Interest Entities" and "—Note 12. Equity Investments" for more information on AROP Funding, Alliance Minerals, Cavalier Minerals and AllDale Minerals.

Other and Corporate includes marketing and administrative activities, ASI and its subsidiaries included in the Matrix Group, ASI's ownership of aircraft, the Alliance Partnership's Mt. Vernon dock activities; Alliance Coal's coal brokerage activity, MAC's manufacturing and sales (primarily to the ARLP Partnership's mines) of rock dust, certain of Alliance Resource Properties' land and mineral interest activities, Pontiki Coal, LLC's ("Pontiki") legacy workers' compensation and pneumoconiosis liabilities, Wildcat Insurance, which assists the ARLP Partnership with its insurance requirements, Alliance Minerals, and its affiliate, Cavalier Minerals, both of which hold equity investments in various AllDale Partnerships, Alliance Mineral's investment in Kodiak, AROP Funding, LLC ("AROP Funding"), and our new subsidiary formed March 30, 2017, Alliance Resource Finance Corporation ("Alliance Finance"). Please read "Item 8. Financial Statements and Supplementary Data—Note 7. Long-Term Debt", "—Note 10. Variable Interest Entities" and "—Note 12. Investments" for more information on AROP Funding, Alliance Finance, Alliance Minerals, Cavalier Minerals, the AllDale Partnerships and Kodiak.

How the ARLP Partnership Evaluates its Performance

The ARLP Partnership's management uses a variety of financial and operational measurements to analyze its performance. Primary measurements include the following: (1) raw and saleable tons produced per unit shift; (2) coal sales price per ton; (3) Segment Adjusted EBITDA Expense per ton; (4) EBITDA; and (5) Segment Adjusted EBITDA.

Raw and Saleable Tons Produced per Unit Shift. The ARLP Partnership reviews raw and saleable tons produced per unit shift as part of its operational analysis to measure the productivity of its operating segments, which is significantly influenced by mining conditions and the efficiency of its preparation plants. A discussion of mining conditions and preparation plant costs are found below under "—Analysis of Historical Results of Operations" and therefore provides implicit analysis of raw and saleable tons produced per unit shift.

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Coal Sales Price per Ton. The ARLP Partnership defines coal sales price per ton as total coal sales divided by tons sold. The ARLP Partnership reviews coal sales price per ton to evaluate marketing efforts and for market demand and trend analysis.

Segment Adjusted EBITDA Expense per Ton. The ARLP Partnership defines Segment Adjusted EBITDA Expense per ton (a non-GAAP financial measure) as the sum of operating expenses, outside coal purchases and other income divided by total tons sold. The ARLP Partnership reviews segment adjusted EBITDA expense per ton for cost trends.58

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Segment Adjusted EBITDA Expense per Ton. The ARLP Partnership defines Segment Adjusted EBITDA Expense per ton (a non-GAAP financial measure) as the sum of operating expenses, coal purchases and other income divided by total tons sold. The ARLP Partnership reviews Segment Adjusted EBITDA Expense per ton for cost trends.

EBITDA. The ARLP Partnership defines EBITDA (a non-GAAP financial measure) as net income (prior to the allocation of noncontrolling interest) before net interest expense, income taxes and depreciation, depletion and amortization. EBITDA is used as a supplemental financial measure by the ARLP Partnership's management and by external users of its financial statements such as investors, commercial banks, research analysts and others. The ARLP Partnership believes that the presentation of EBITDA provides useful information to investors regarding its performance and results of operations because EBITDA, when used in conjunction with related GAAP financial measures, (i) provides additional information about our core operating performance and ability to generate and distribute cash flow, (ii) provides investors with the financial analytical framework upon which the ARLP Partnership bases financial, operational, compensation and planning decisions and (iii) presents a measurement that investors, rating agencies and debt holders have indicated is useful in assessing that ARLP Partnership and its results of operations.

Segment Adjusted EBITDA. The ARLP Partnership defines Segment Adjusted EBITDA (a non-GAAP financial measure) as net income (prior to the allocation of noncontrolling interest) before net interest expense, income taxes, depreciation, depletion and amortization, asset impairment, acquisition gain, net, debt extinguishment loss and general and administrative expenses. Management therefore is able to focus solely on the evaluation of segment operating profitability as it relates to our revenues and operating expenses, which are primarily controlled by our segments.

Analysis of Historical Results of Operations

2017 Compared with 2016

We reported net income of $302.3 million for 2017 compared to $336.6 million for 2016. The decrease of $34.3 million was due to lower coal sales price realizations offset in part by increased sales volumes, decreased operating expenses, reduced depreciation, depletion and amortization and increased income from the oil and gas investments. Total revenues decreased to $1.80 billion in 2017 compared to $1.93 billion in 2016 as the anticipated reduction in coal sales prices more than offset increased sales volumes and other sales and operating revenues. Even though sales and production volumes increased for 2017, operating expenses were lower compared to 2016, reflecting initiatives to shift production to lower-cost operations. The favorable production cost mix and lower selling expenses in 2017 significantly lowered operating expenses per ton sold compared to 2016. Results presented for 2016 have been recast to reflect a reclassification of depreciation and depletion capitalized into coal inventory as an adjustment to depreciation, depletion and amortization rather than operating expenses.


	December 31,				December 31,
	2017		2016		2017		2016
	(in thousands)				(per ton sold)
Tons sold		37,824		36,680		N/A		N/A
Tons produced		37,609		35,244		N/A		N/A
Coal sales	$	1,711,114	$	1,861,788	$	45.24	$	50.76
Operating expenses and outside coal purchases	$	1,095,167	$	1,126,362	$	28.95	$	30.71

Coal sales. Coal sales decreased $150.7 million or 8.1% to $1.71 billion for 2017 from $1.86 billion for 2016. The decrease was attributable to lower average coal sales prices, which reduced coal sales by $208.7 million, partially offset by the benefit of increased tons sold, which contributed $58.0 million in additional coal sales. Average coal sales prices decreased $5.52 per ton sold in 2017 to $45.24 compared to $50.76 per ton sold in 2016, primarily due to the expiration of higher-priced legacy contracts, partially offset by higher price realizations at the Mettiki mine from its participation in the metallurgical coal markets in 2017 and improved prices at the MC Mining mine. Sales and production volumes rose to 37.8 million tons sold and 37.6 million tons produced in 2017 compared to 36.7 million

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tons sold and 35.2 million tons produced in 2016, primarily due to strong performances at the Hamilton, Gibson South, Mettiki, MC Mining and Tunnel Ridge mines.

Operating expenses and outside coal purchases. Operating expenses and outside coal purchases decreased 2.8% to $1.10 billion for 2017 from $1.13 billion for 2016 primarily as a result of the previously discussed favorable production cost mix. On a per ton basis, operating expenses and outside coal purchases decreased 5.7% to $28.95 per ton sold from $30.71 per ton sold in 2016, due primarily to increased sales and production volumes and the previously discussed initiatives to shift production to lower-cost operations. The most significant operating expense variances by category are discussed below:

Labor and benefit expenses per ton produced, excluding workers' compensation, decreased 13.2% to $9.24 per ton in 2017 from $10.65 per ton in 2016. This decrease of $1.41 per ton was primarily attributable to lower labor and benefit costs per ton due to fewer employees resulting in part from the increased mix of lower-cost production as well as lower health care benefit expenses; and

Production taxes and royalty expenses decreased $0.49 per produced ton sold in 2017 compared to 2016 primarily as a result of lower excise taxes per ton resulting from a favorable state production mix, increased export sales and lower average coal sales prices.

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

Material and supplies expenses per ton produced increased 1.9% to $9.76 per ton in 2017 from $9.58 per ton in 2016. The increase of $0.18 per ton produced resulted primarily from increases of $0.27 per ton for contract labor used in the mining process and $0.12 per ton for roof support, partially offset by the increased mix of lower-cost production and a related decrease of $0.10 per ton for power and fuel used in the mining process; and

Maintenance expenses per ton produced increased 7.7% to $3.34 per ton in 2017 from $3.10 per ton in 2016. The increase of $0.24 per ton produced was primarily due to increased maintenance expenses at several mines in both reportable segments due in part to the use of surplus equipment from the ARLP Partnership's idled mines.

Other sales and operating revenues. Other sales and operating revenues were principally comprised of Mt. Vernon transloading revenues, Matrix Design sales and other outside services. Other sales and operating revenues increased to $43.0 million in 2017 from $39.1 million in 2016. The increase of $3.9 million was primarily due to increased mining technology product sales by Matrix Design and increased transloading revenues from Mt. Vernon, partially offset in comparison to 2016 by proceeds of coal supply contract buy-outs received in 2016.

General and administrative. General and administrative expenses for 2017 decreased to $63.3 million compared to $75.1 million in 2016. The decrease of $11.8 million was primarily due to lower incentive compensation expenses.

Depreciation, depletion and amortization. Depreciation, depletion and amortization expense decreased to $269.0 million for 2017 compared to $336.5 million for 2016 primarily as a result of the depletion of reserves at the Elk Creek mine in the first quarter of 2016, closure of the Pattiki mine in the fourth quarter of 2016, volume reductions at the Dotiki and Warrior mines, the use of surplus equipment from idled mines and ongoing capital reduction initiatives at all of the ARLP Partnerships' operations.

Interest expense. Interest expense, net of capitalized interest, increased to $39.4 million in 2017 from $30.7 million in 2016 primarily due to interest incurred under the ARLP Senior Notes issued in April 2017, offset in part by reduced borrowings under the ARLP revolving credit facility and the payment of the ARLP Term Loan and ARLP Series B Senior Notes. Interest payable under the ARLP Partnership's Senior Notes, revolving credit facility, Term Loan and Series B Senior Notes is discussed below under "–Debt Obligations."

Equity investment income. Equity investment income increased to $13.9 million in 2017 from $3.5 million in 2016 due to increased income from the ARLP Partnership's investments in the AllDale Partnerships.

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Cost investment income. Distributions of additional preferred interests received from the ARLP Partnership's new Kodiak investment contributed $6.4 million of cost investment income to 2017.

Debt extinguishment loss. The ARLP Partnership recognized a debt extinguishment loss of $8.1 million in 2017 to reflect a make-whole payment incurred to repay the ARLP Partnership's Series B Senior Notes in May 2017.

Transportation revenues and expenses. Transportation revenues and expenses were $41.7 million and $30.1 million for 2017 and 2016, respectively. The increase of $11.6 million was primarily attributable to increased tonnage for which the ARLP Partnership arranges third-party transportation at certain mines and an increase in average third-party transportation rates in 2017. The cost of third-party transportation services are passed through to the ARLP Partnership's customers.

Net income attributable to noncontrolling interests. The net income attributable to noncontrolling interest was $116.3 million and $150.6 million in 2017 and 2016, respectively. The decrease in net income attributable to noncontrolling interests is due to an increased percentage allocation of the ARLP Partnership's net income to AHGP due to increased cash distributions to AHGP as a result of the Exchange Transaction in addition to a decrease in the consolidated net income of the ARLP Partnership due to the changes in revenues and expenses described above.

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Segment Information. Our 2017 Segment Adjusted EBITDA decreased 12.4% to $682.2 million from 2016 Segment Adjusted EBITDA of $778.8 million. Segment Adjusted EBITDA, tons sold, coal sales, other sales and operating revenues and Segment Adjusted EBITDA Expense by segment are as follows:



	Year Ended December 31,
	2017		2016		Increase (Decrease)
	(in thousands)
Segment Adjusted EBITDA
Illinois Basin	$	391,426	$	552,284	$	(160,858)	(29.1)	%
Appalachia		234,124		191,487		42,637	22.3	%
Other and Corporate		65,431		45,909		19,522	42.5	%
Elimination		(8,769)		(10,862)		2,093	19.3	%
Total Segment Adjusted EBITDA (1)	$	682,212	$	778,818	$	(96,606)	(12.4)	%

Tons sold
Illinois Basin		27,026		26,912		114	0.4	%
Appalachia		10,783		9,734		1,049	10.8	%
Other and Corporate		1,636		1,865		(229)	(12.3)	%
Elimination		(1,621)		(1,831)		210	11.5	%
Total tons sold		37,824		36,680		1,144	3.1	%

Coal sales
Illinois Basin	$	1,078,255	$	1,306,241	$	(227,986)	(17.5)	%
Appalachia		616,305		534,796		81,509	15.2	%
Other and Corporate		74,973		86,174		(11,201)	(13.0)	%
Elimination		(58,419)		(65,423)		7,004	10.7	%
Total coal sales	$	1,711,114	$	1,861,788	$	(150,674)	(8.1)	%

Other sales and operating revenues
Illinois Basin	$	1,638	$	7,686	$	(6,048)	(78.7)	%
Appalachia		3,622		3,404		218	6.4	%
Other and Corporate		53,691		45,786		7,905	17.3	%
Elimination		(15,924)		(17,752)		1,828	10.3	%
Total other sales and operating revenues	$	43,027	$	39,124	$	3,903	10.0	%

Segment Adjusted EBITDA Expense
Illinois Basin	$	688,468	$	761,644	$	(73,176)	(9.6)	%
Appalachia		385,802		346,712		39,090	11.3	%
Other and Corporate		83,490		89,594		(6,104)	(6.8)	%
Elimination		(65,573)		(72,313)		6,740	9.3	%
Total Segment Adjusted EBITDA Expense (1)	$	1,092,187	$	1,125,637	$	(33,450)	(3.0)	%

(1)

For a definition of Segment Adjusted EBITDA and Segment Adjusted EBITDA Expense and related reconciliations to comparable GAAP financial measures, please see below under "—Reconciliation of non-GAAP "Segment Adjusted EBITDA" to GAAP "net income" and reconciliation of non-GAAP "Segment Adjusted EBITDA Expense" to GAAP "Operating Expenses." Results presented for Segment Adjusted EBITDA and Segment Adjusted EBITDA Expense for 2016 have been recast to reflect a reclassification of depreciation and depletion capitalized into coal inventory as adjustments to depreciation, depletion and amortization rather than operating expenses.

Illinois Basin – Segment Adjusted EBITDA decreased 29.1% to $391.4 million in 2017 from $552.3 million in 2016. The decrease of $160.9 million was primarily attributable to lower coal sales, which decreased 17.5% to $1.08 billion in 2017 from $1.31 billion in 2016, partially offset by decreased expenses resulting from a favorable production mix. The coal sales decrease of $228.0 million primarily reflects lower average coal sales prices of $39.90 per ton in

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2017 compared to $48.54 per ton in 2016, primarily resulting from the expiration of higher-priced legacy contracts. Lower sales prices were partially offset by increased tons sold, which increased slightly to 27.0 million tons in 2017 from 26.9 million tons in 2016. Higher sales volumes resulted from strong performances at the Gibson South and Hamilton mines, offset in part by the previously mentioned depletion of reserves at the Elk Creek mine in the 2016 first quarter, the closure of the Pattiki mine in the 2016 fourth quarter and reduced sales at the Dotiki mine. Segment Adjusted EBITDA Expense decreased 9.6% to $688.5 million in 2017 from $761.6 million in 2016 and Segment Adjusted EBITDA Expense per ton decreased $2.83 per ton sold to $25.47 compared to $28.30 per ton sold in 2016, primarily due to a significant increase in low-cost longwall production from the Hamilton mine, increased production at the Gibson South operation and a related reduced mix of sales volumes from higher cost mines, as well as reduced selling expenses, lower health care benefit expenses and certain cost decreases described above under "–Operating expenses and outside coal purchases."

Appalachia – Segment Adjusted EBITDA increased 22.3% to $234.1 million for 2017 from $191.5 million in 2016. The increase of $42.6 million was primarily attributable to increased coal sales, which rose 15.2% to $616.3 million in 2017 compared to $534.8 million in 2016, partially offset by higher Segment Adjusted EBITDA Expense. The increase of $81.5 million in coal sales resulted from higher sales volumes across the region, which increased 10.8% to 10.8 million tons sold in 2017 compared to 9.7 million tons sold in 2016, and higher average coal sales prices of $57.16 per ton in 2017 compared to $54.94 per ton in 2016. Higher price realizations in 2017 were a result of sales from the ARLP Partnership's Mettiki mine into the metallurgic coal export market and improved prices at the MC Mining mine. Segment Adjusted EBITDA Expense increased 11.3% to $385.8 million in 2017 from $346.7 million in 2016 due to increased sales volumes. Segment Adjusted EBITDA Expense per ton increased slightly to $35.78 per ton compared to $35.62 per ton sold in 2016, primarily due to an increased sales mix of higher-cost Mettiki production in 2017 and reduced recoveries from the Tunnel Ridge mine.

Other and Corporate – Segment Adjusted EBITDA increased by $19.5 million to $65.4 million in 2017 compared to $45.9 million in 2016. The increase was primarily attributable to higher equity investment income from the AllDale Partnerships, distributions of additional preferred interests received from Kodiak and increased mining technology product sales by Matrix Design. In 2017, Segment Adjusted EBITDA Expense decreased to $83.5 million for 2017 compared to $89.6 million for 2016 primarily as a result of decreased coal brokerage activity.

Elimination – Segment Adjusted EBITDA Expense eliminations decreased in 2017 to $65.6 million from $72.3 million in 2016 and coal sales eliminations decreased to $58.4 million from $65.4 million in 2016, reflecting decreased intercompany coal sales brokerage activity.

2016 Compared with 2015

We reported net income of $336.6 million for 2016 compared to $304.2 million for 2015, an increase of $32.4 million. Comparative results between the years reflect in part the negative net impact in 2015 of $77.6 million of certain large non-cash items ("Non-Cash Items") described below and $48.5 million of equity ininvestment loss ~~of affiliates~~ related to White Oak also in 2015. Net income in 2016 was negatively impacted by reduced revenues compared to 2015 resulting from planned reductions in coal sales and production volumes, lower coal sales prices, lower other sales and operating revenues due to the absence of coal royalty and surface facilities revenues from White Oak in 2016, offset in part by reduced operating expenses in 2016. Lower operating expenses during 2016 primarily reflect decreased sales volumes and a favorable production cost mix resulting from the initiative to shift production to lower-cost per ton operations. Lower volumes in 2016 resulted from idling the Onton and Gibson North mines in the fourth quarter of 2015 and the planned depletion of reserves at the Elk Creek mine in the first quarter of 2016, partially offset by additional volumes from the Tunnel Ridge and Gibson South operations and the Hamilton mine acquired in the White Oak Acquisition. The Non-Cash Items in 2015 included asset impairments of $100.1 million offset in part by a net gain of $22.5 million related to final business combination accounting for the White Oak Acquisition. For more information on the White Oak Acquisition, please read "Item 8. Financial Statements and Supplementary Data—Note 3. Acquisitions." For more information on the 2015 non-cash asset impairments, please read "Item 8. Financial Statements and Supplementary Data—Note 4. Long-Lived Asset Impairments." Results presented for 2016 and 2015

	December 31,				December 31,
	2016		2015		2016		2015
	(in thousands)				(per ton sold)
Tons sold		36,680		40,247		N/A		N/A
Tons produced		35,244		41,178		N/A		N/A
Coal sales	$	1,861,788	$	2,158,006	$	50.76	$	53.62
Operating expenses and outside coal purchases	$	1,140,362	$	1,377,380	$	31.09	$	34.22

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have been recast to reflect a reclassification of depreciation and depletion capitalized into coal inventory as an adjustment to depreciation, depletion and amortization rather than operating expenses.


	December 31,				December 31,
	2016		2015		2016		2015
	(in thousands)				(per ton sold)
Tons sold		36,680		40,247		N/A		N/A
Tons produced		35,244		41,178		N/A		N/A
Coal sales	$	1,861,788	$	2,158,006	$	50.76	$	53.62
Operating expenses and outside coal purchases	$	1,126,362	$	1,387,110	$	30.71	$	34.46

Coal sales. Coal sales decreased $296.2 million or 13.7% to $1.86 billion for 2016 from $2.16 billion for 2015. The decrease was attributable to a volume variance of $191.2 million resulting from reduced tons sold as discussed above and a price variance of $105.0 million due to lower average coal sales prices. Average coal sales prices decreased $2.86 per ton sold in 2016 to $50.76 compared to $53.62 per ton sold in 2015, primarily due to lower-priced legacy contracts at the Hamilton mine inherited in the White Oak Acquisition and lower average prices at certain mines, particularly at the Gibson South, Dotiki, Tunnel Ridge and MC Mining operations, as a result of challenging market conditions.

Operating expenses and outside coal purchases. Operating expenses and outside coal purchases decreased 1718.28% to $1.1413 billion for 2016 from $1.3839 billion for 2015 primarily as a result of the previously discussed reductions to coal production volumes and a favorable production cost mix. On a per ton basis, operating expenses and outside coal purchases decreased 910.19% to $3130.0971 per ton sold from $34.2246 per ton sold in 2015, due primarily to the lower-cost production mix and higher productivity from the Tunnel Ridge and Gibson South mines. 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 7.8% to $10.65 per ton in 2016 from $11.55 per ton in 2015. This decrease of $0.90 per ton was primarily attributable to the increased mix of lower-cost production discussed above and reduced overtime in response to market conditions;

Material and supplies expenses per ton produced decreased 14.8% to $9.58 per ton in 2016 from $11.25 per ton in 2015. The decrease of $1.67 per ton produced resulted primarily from the increased mix of lower-cost production discussed above and related decreases of $0.77 per ton for roof support, $0.47 per ton for contract labor used in the mining process and $0.24 per ton for certain ventilation expenses partially offset by increases of $0.22 per ton for equipment rentals primarily due to equipment leases assumed in the White Oak Acquisition and $0.15 per ton for environmental and reclamation expenses;

Maintenance expenses per ton produced decreased 21.1% to $3.10 per ton in 2016 from $3.93 per ton in 2015. The decrease of $0.83 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 $0.39 per produced ton sold in 2016 compared to 2015 primarily as a result of lower excise taxes per ton resulting from a favorable state production mix and lower average coal sales prices discussed above;

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

Operating expenses were increased by a 1.4 million ton inventory reduction and related inventory cost adjustments in 2016 as compared to a 1.0 million ton inventory increase and related inventory cost adjustments in 2015.

Other sales and operating revenues. Other sales and operating revenues were principally comprised of Mt. Vernon transloading revenues, Matrix Design sales, other outside services and in 2015, surface facility services and coal royalty revenues received from White Oak prior to the White Oak Acquisition in July 2015. Other sales and operating revenues decreased to $39.1 million in 2016 from $81.7 million in 2015. The decrease of $42.6 million was primarily due to the absence of coal royalty and surface facilities revenues from White Oak in 2016.

General and administrative. General and administrative expenses for 2016 increased to $75.1 million compared to $69.1 million in 2015. The increase of $6.0 million was primarily due to higher incentive compensation expenses.64

Depreciation, depletion and amortization. Depreciation, depletion and amortization expense for 2016 decreased to $322.5 million compared to $333.7 million in 2015. The decrease of $11.2 million was primarily due to previously discussed volume reductions at the Onton, Gibson North and Elk Creek mines, partially offset by increases in depreciation, depletion and amortization associated with the acquisition of the Hamilton mine in July 2015 and at the Pattiki mine, which ceased production in December 2016 .

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coal royalty revenues received from White Oak prior to the White Oak Acquisition in July 2015. Other sales and operating revenues decreased to $39.1 million in 2016 from $81.7 million in 2015. The decrease of $42.6 million was primarily due to the absence of coal royalty and surface facilities revenues from White Oak in 2016.

Depreciation, depletion and amortization. Depreciation, depletion and amortization ("DD&A") expense for 2016 increased to $336.5 million compared to $324.0 million in 2015. The increase of $12.5 million was primarily due to increases in DD&A associated with the Pattiki mine, which ceased production in December 2016 and the acquisition of the Hamilton mine in July 2015, partially offset by the previously discussed volume reductions at the Onton, Gibson North, and Elk Creek mines. .

Asset impairment. In 2015, the ARLP Partnership recorded $100.1 million of impairment charges comprised of a $66.9 million impairment related to the idling of the Onton mine, a $19.5 million impairment at the MC Mining complex, primarily due to lower coal sales prices, and a $13.7 million impairment due to the surrender in 2015 of leases of undeveloped coal reserves and related property. No asset impairments were recorded in 2016.

Interest expense. Interest expense, net of capitalized interest, decreased slightly to $30.7 million in 2016 from $31.2 million in 2015 primarily due to the repayment of the ARLP Series A senior notes in June 2015 offset in part by additional interest incurred under capital lease obligations. Interest payable under the ARLP senior notes, ARLP term loan, ARLP revolving credit facility and capital lease financings is discussed below under "–Debt Obligations."

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Filing Compare · Alliance Holdings GP, L.P.