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TABLE OF CONTENTS
INDEX TO FINANCIAL STATEMENTS

As filed with the Securities and Exchange Commission on June 19, 2015

Registration No. 333-

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

FORM S-1
REGISTRATION STATEMENT
UNDER
THE SECURITIES ACT OF 1933

BOWIE RESOURCE PARTNERS LP
(Exact Name of Registrant as Specified in Its Charter)


Delaware (State or Other Jurisdiction of Incorporation or Organization)		1220 (Primary Standard Industrial Classification Code Number)		47-2966254 (I.R.S. Employer Identification Number)

6100 Dutchmans Lane, 9th Floor
Louisville, Kentucky 40205
(502) 584-6022
(Address, Including Zip Code, and Telephone Number, Including
Area Code, of Registrant's Principal Executive Offices)

Brian S. Settles
General Counsel
6100 Dutchmans Lane, 9th Floor
Louisville, Kentucky 40205
(502) 584-6022
(Name, Address, Including Zip Code, and Telephone Number, Including Area Code, of Agent for Service)


Copies to:
Shelley Barber Brenda Lenahan Vinson & Elkins L.L.P. 666 Fifth Avenue, 26th Floor New York, New York 10103 Tel: (212) 237-0000 Fax: (212) 237-0100		Joshua Davidson John Geddes Baker Botts L.L.P. One Shell Plaza 910 Louisiana Street Houston, Texas 77002 Tel: (713) 229-1234 Fax: (713) 229-1522

Approximate date of commencement of proposed sale to the public:
As soon as practicable after this Registration Statement becomes effective.

If any of the securities being registered on this Form are to be offered on a delayed or continuous basis pursuant to Rule 415 under the Securities Act of 1933 (the "Securities Act"), check the following box. o

If this Form is filed to register additional securities for an offering pursuant to Rule 462(b) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. o

If this Form is a post-effective amendment filed pursuant to Rule 462(c) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. o

If this Form is a post-effective amendment filed pursuant to Rule 462(d) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. o

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


Large accelerated filer o		Accelerated filer o		Non-accelerated filer ý (Do not check if a smaller reporting company)		Smaller reporting company o

CALCULATION OF REGISTRATION FEE

Title of Each Class of Securities to be Registered	Proposed Maximum Aggregate Offering Price(1)(2)	Amount of Registration Fee




Common units representing limited partner interests	$100,000,000	$11,620

(1): Includes common units issuable upon exercise of the underwriters' option to purchase additional common units.
(2): Estimated solely for the purpose of calculating the registration fee pursuant to Rule 457(o).

The registrant hereby amends this registration statement on such date or dates as may be necessary to delay its effective date until the registrant shall file a further amendment which specifically states that this registration statement shall thereafter become effective in accordance with Section 8(a) of the Securities Act or until the registration statement shall become effective on such date as the Securities and Exchange Commission, acting pursuant to said Section 8(a), may determine.

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The information in this preliminary prospectus is not complete and may be changed. We may not sell these securities until the registration statement filed with the Securities and Exchange Commission becomes effective. This preliminary prospectus is not an offer to sell these securities, and we are not soliciting an offer to buy these securities in any jurisdiction where the offer or sale is not permitted.

SUBJECT TO COMPLETION, DATED , 2015

PROSPECTUS

BOWIE RESOURCE PARTNERS LP

Common Units
Representing Limited Partner Interests

This is the initial public offering of our common units representing limited partner interests. Prior to this offering, there has been no public market for our common units. We are offering common units in this offering. We currently expect the initial public offering price to be between $ and $ per common unit. We intend to apply to list our common units on the New York Stock Exchange under the symbol "BRLP."

The underwriters have the option to purchase up to additional common units from us at the initial public offering price, less the underwriting discounts, within 30 days from the date of this prospectus to cover over-allotments, if any.

Investing in our common units involves risks. Please read "Risk Factors" beginning on page 22.

These risks include the following:

•: We may not have sufficient cash from operations to pay the minimum quarterly distribution on our common and subordinated units following establishment of cash reserves and payment of costs and expenses, including reimbursement of expenses to our general partner. On a pro forma basis, we would not have had sufficient cash available for distribution to pay the full minimum quarterly distribution on all of our units for the year ended December 31, 2014 or the twelve months ended March 31, 2015.
•: A substantial or extended decline in coal prices or increase in the costs of mining or transporting coal could have a material adverse effect on our results of operations and our ability to pay distributions to our unitholders.
•: Competition within the coal industry may adversely affect our ability to sell coal, and excess production capacity in the industry could put downward pressure on coal prices.
•: Our mining operations, including our transportation infrastructure, are extensively regulated, which imposes significant costs on us, and changes to existing and potential future regulations or violations of regulations could increase those costs or limit our ability to produce and sell coal.
•: Our level of indebtedness and the terms of our borrowings could adversely affect our ability to grow our business, our ability to make cash distributions to our unitholders and our credit ratings and profile.
•: Our general partner and its affiliates, including our sponsor, have conflicts of interest with us and limited duties, and they may favor their own interests to the detriment of us and our unitholders.
•: All of our revenue and cash flow will be derived from our coal supply agreements, and we will receive substantially all of our revenue and cash flow from our new coal supply agreement with our sponsor. Therefore, we will be subject to the business risks of our sponsor.
•: Holders of our common units have limited voting rights and are not entitled to elect our general partner or its directors, which could reduce the price at which our common units will trade.
•: Even if holders of our common units are dissatisfied, they cannot initially remove our general partner without its consent.
•: Unitholders who are not "Eligible Holders" will not be entitled to receive distributions on or allocations of income or loss on their common units, and their common units will be subject to redemption.
•: If the Internal Revenue Service were to treat us as a corporation for federal income tax purposes or we were to become subject to material additional amounts of entity-level taxation for state tax purposes, then our cash available for distribution to our unitholders would be substantially reduced.
•: Our unitholders will be required to pay taxes on their share of our taxable income even if they do not receive any cash distributions from us.

In addition, we qualify as an "emerging growth company" as defined in the Jumpstart Our Business Startups Act of 2012, and as such, are allowed to provide in this prospectus more limited disclosures than an issuer that would not so qualify. Furthermore, for so long as we remain an emerging growth company, we will qualify for certain limited exceptions from investor protection laws such as the Sarbanes-Oxley Act of 2002 and the Investor Protection and Securities Reform Act of 2010. Please read "Prospectus Summary—Our Emerging Growth Company Status."

In order to comply with certain U.S. laws relating to the ownership of interests in mineral leases on federal lands, we require an owner of our common units to be an "Eligible Holder." If you are not an Eligible Holder, you will not be entitled to receive distributions on or allocations of income or loss on your common units and your common units will be subject to redemption.

	Per Common Unit	Total

Public Offering Price	$	$
Underwriting Discount	$	$
Proceeds to Bowie Resource Partners LP (before expenses)	$	$

Neither the Securities and Exchange Commission nor any state securities commission has approved or disapproved of these securities or determined if this prospectus is truthful or complete. Any representation to the contrary is a criminal offense.

The underwriters expect to deliver the common units to purchasers on or about , 2015.

Joint Book-Running Managers


Citigroup	Morgan Stanley	Deutsche Bank Securities
UBS Investment Bank	Credit Suisse	Stifel

Co-Managers


Brean Capital

, 2015

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TABLE OF CONTENTS


PROSPECTUS SUMMARY		1
RISK FACTORS		22
USE OF PROCEEDS		64
DILUTION		65
CAPITALIZATION		67
CASH DISTRIBUTION POLICY AND RESTRICTIONS ON DISTRIBUTIONS		69
HOW WE MAKE DISTRIBUTIONS TO OUR PARTNERS		84
SELECTED HISTORICAL AND PRO FORMA FINANCIAL AND OTHER DATA		99
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS		102
BUSINESS		124
THE COAL INDUSTRY		155
ENVIRONMENTAL AND OTHER REGULATORY MATTERS		175
MANAGEMENT		186
EXECUTIVE COMPENSATION		191
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT		197
CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS		198
CONFLICTS OF INTEREST AND FIDUCIARY DUTIES		203
DESCRIPTION OF THE COMMON UNITS		211
THE PARTNERSHIP AGREEMENT		213
UNITS ELIGIBLE FOR FUTURE SALE		228
MATERIAL U.S. FEDERAL INCOME TAX CONSEQUENCES		230
INVESTMENT IN BOWIE RESOURCE PARTNERS LP BY EMPLOYEE BENEFIT PLANS		247
UNDERWRITING		248
LEGAL MATTERS		251
EXPERTS		251
WHERE YOU CAN FIND MORE INFORMATION		251
FORWARD-LOOKING STATEMENTS		253
INDEX TO FINANCIAL STATEMENTS		F-1
APPENDIX A FORM OF FIRST AMENDED AND RESTATED AGREEMENT OF LIMITED PARTNERSHIP		A-1
APPENDIX B GLOSSARY OF DEFINED TERMS		B-1

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You should rely only on the information contained in this prospectus. We have not authorized anyone to provide you with different information. If anyone provides you with different or inconsistent information, you should not rely on it. We and the underwriters take no responsibility for, and can provide no assurance as to the reliability of, any other information that others may give you. We are not, and the underwriters are not, making an offer to sell these securities in any jurisdiction where the offer or sale is not permitted. You should not assume that the information contained in this prospectus is accurate as of any date other than the date on the front of this prospectus.

Coal Reserve Information

"Reserves" are defined by the SEC Industry Guide 7 as that part of a mineral deposit that could be economically and legally recovered or produced at the time of the reserve determination. Industry Guide 7 divides reserves between "proven (measured) reserves" and "probable (indicated) reserves" which are defined as follows:

•: "Proven (measured) reserves." Reserves for which (a) quantity is computed from dimensions revealed in outcrops, trenches, workings or drill holes; grade and/or quality are computed from the results of detailed sampling and (b) the sites for inspection, sampling and measurement are spaced so closely and the geologic character is so well defined that size, shape, depth and mineral content of reserves are well-established.
•: "Probable (indicated) reserves." Reserves for which quantity and grade and/or quality are computed from information similar to that used for proven (measured) reserves, but the sites for inspection, sampling, and measurement are farther apart or are otherwise less adequately spaced. The degree of assurance, although lower than that for proven (measured) reserves, is high enough to assume continuity between points of observation.

Our coal reserve estimates include both assigned and unassigned reserves.

Our coal reserve estimates include reserves that can be economically and legally recovered or produced at the time of their determination. In determining whether our reserves meet this standard, we take into account, among other things, the possible necessity of revising a mining plan, changes in estimated future costs, changes in future cash flows caused by changes in costs required to be incurred to meet regulatory requirements and obtain mining permits, variations in quantity and quality of coal, and varying levels of demand and their effects on selling prices. Further, the economics of our reserves are based on market conditions, including contracted pricing, market pricing and overall demand for our coal. Thus, the actual value at which we no longer consider our reserves to be economic varies depending on the length of time in which the specific market conditions are expected to last. We consider our reserves to be economic at a price in excess of our cash costs to mine the coal and our ongoing replacement capital. Because we do not regularly wash our coal, our reserve estimates do not include potential losses from the washing process.

The information appearing in this prospectus concerning estimates of our proven and probable coal reserves (including the proven and probable coal reserves for Fossil Rock and the Flat Canyon tract, each as defined in this prospectus) was prepared by Norwest Corporation ("Norwest") as of December 31, 2014. Unless otherwise noted, all estimates regarding our proven and probable coal reserves discussed in this prospectus are based on the reserve report prepared by Norwest as of December 31, 2014. Statements of non-reserve coal deposits for the Greens Hollow tract (as defined in this prospectus) rely solely on the estimates of management and have not been prepared or audited by Norwest. All Btus per pound are expressed on an as-received basis, including total moisture. Please read "Business—Coal Reserves and Non-Reserve Coal Deposits."

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Market and Industry Data and Forecasts

In this prospectus, we rely on and refer to information regarding the coal industry, future coal production and consumption and future electricity generation in the United States and internationally from the U.S. Energy Information Administration ("EIA"), World Coal Association, U.S. Mine Safety and Health Administration ("MSHA"), National Mining Association, BP Statistical Review, Baker Hughes, Argus Media, globalCOAL and Wood Mackenzie, none of which are affiliated with us. We have commissioned Wood Mackenzie to provide certain market and industry data and forecasts contained in this prospectus.

When we make statements in this prospectus about our position in our industry or any sector of our industry or about our market share, we are making statements of our belief. This belief is based on data from various sources (including government data, industry publications, surveys and forecasts), on estimates and assumptions that we have made based on that data and other sources and our knowledge of the markets for our products.

We do not have any knowledge that the market and industry data and forecasts provided to us from third-party sources are inaccurate in any material respect. However, we have been advised that certain information provided to us from third-party sources is derived from estimates or subjective judgments, and while such third-party sources have assured us that they have taken reasonable care in the compilation of such information and believe it to be accurate and correct, data compilation is subject to limited audit and validation procedures. We believe that, notwithstanding such qualification by such third-party sources, the market and industry data provided in this prospectus is accurate in all material respects.

Our estimates, in particular as they relate to market share and our general expectations, involve risks and uncertainties and are subject to change based on various factors, including those discussed under the section entitled "Risk Factors."

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PROSPECTUS SUMMARY

This summary highlights information contained elsewhere in this prospectus. This summary does not contain all of the information you should consider before investing in our common units. You should read the entire prospectus carefully, including the section describing the risks of investing in our common units under "Risk Factors" and the financial statements contained elsewhere in this prospectus before making an investment decision. Some of the statements in this summary constitute forward-looking statements. Please read "Forward-Looking Statements." The information presented in this prospectus assumes an initial public offering price of $ per common unit (the mid-point of the price range set forth on the cover page of this prospectus) and, unless otherwise indicated, that the underwriters' option to purchase additional common units to cover over-allotments is not exercised.

References in this prospectus to the "partnership," "we," "our," "us" or like terms when used in a historical context refer to the business of Canyon Fuel Company, LLC and its subsidiaries, which will be our wholly-owned subsidiaries following this offering, or Bowie Resource Partners LP and its subsidiaries thereafter, as the context requires. When used in the present tense or prospectively, "the partnership," "we," "our," "us" or like terms refer to Bowie Resource Partners LP and its subsidiaries and "our operating company" refers to BRP Holdings LLC, a wholly-owned subsidiary of ours, in each case after giving effect to the transactions described in "—IPO Reorganization and Partnership Structure." Except where expressly noted, references in this prospectus to "our sponsor" refer to Bowie Resource Partners, LLC, together with its wholly-owned subsidiaries, including Bowie Resource Holdings, LLC, but excluding the partnership. References in this prospectus to "our general partner" refer to Bowie GP, LLC, a wholly-owned subsidiary of our sponsor, and references to "our executive officers" and "our directors" refer to the executive officers and directors of our general partner. Our coal sales were historically made under coal supply agreements between our sponsor and our end customers. In connection with the closing of this offering, we expect to enter into a coal supply agreement with our sponsor, pursuant to which it will purchase substantially all of our coal on substantially the same terms as our sponsor's agreements with our end customers. References in this prospectus to "our coal supply agreements" refer to (i) coal supply agreements between us and our customers, (ii) coal supply agreements between us and our sponsor and (iii) coal supply agreements between our sponsor and the end customers of our coal. References in this prospectus to "our customers" refer to customers purchasing coal directly from us and customers purchasing our coal through our sponsor. For the definitions of certain other terms used in this prospectus, please read "Appendix B: Glossary of Defined Terms."

Bowie Resource Partners LP

Overview

We were recently formed by our sponsor as a growth-oriented master limited partnership focused on:

•: operating safe, low-cost, strategically-located underground coal mines that produce high quality (high Btu, low sulfur) thermal coal;
•: providing the lowest delivered cost fuel option (coal or natural gas) to our key regional customers, capitalizing on our high productivity, high quality coal and geographic proximity to these customers;
•: fulfilling and extending our long-term, high-volume, fixed-price coal supply agreements;
•: growing our cash flows through prudent acquisitions of strategically-positioned assets; and
•: capitalizing on our differentiated transportation and logistics network that positions us as the only U.S. coal producer with contracted U.S. West Coast export capacity.

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We operate three underground coal mines in Utah with a productive capacity of approximately 12.6 million tons per year: (i) the Sufco mine, near Salina, Utah, which is a longwall operation with a productive capacity of approximately 7.0 million tons per year, (ii) the Skyline mine, near Scofield, Utah, which is a longwall operation with a productive capacity of approximately 4.5 million tons per year, and (iii) the Dugout Canyon mine, near Price, Utah, which has been a longwall operation but is currently a multi-continuous miner operation with a productive capacity of approximately 1.1 million tons per year. Our mines are located in the Uinta Basin in Utah within the Western Bituminous region where a significant percentage of the coal qualifies as "compliance coal" under the Clean Air Act. Our operations were among the most productive underground coal mines in the United States for the year ended December 31, 2014 on a clean tons produced per man hour basis based on MSHA data and, according to Wood Mackenzie, we are one of the largest producers of low-cost, high margin thermal coal in the Western Bituminous region.

The high productivity of our strategically-located mines, together with our sponsor's transportation and logistics network, enables us to deliver our coal to our key regional customers at a lower cost per Btu compared to coal from other producers in the Western Bituminous region, coal from other basins and natural gas, even when adjusted for different heat rate efficiencies between coal and natural gas-fired power plants.

The majority of our coal sales for the year ended December 31, 2014 and the three months ended March 31, 2015 were made to domestic customers pursuant to long-term, high-volume coal supply agreements with fixed pricing, subject to certain price escalators and adjustments. On a pro forma basis, after giving effect to the closing of the Utah Transaction, we expect coal sales under our existing coal supply agreements for each of the next four years to surpass 80% of our production for the twelve months ended March 31, 2015, which should provide significant sustainable revenue and allow us to generate stable and reliable cash flows. Please read "—Recent Developments" for a description of the Utah Transaction and "Business—Customers—Coal Supply Agreements with Key Customers."

As part of our domestic sales portfolio, we have multi-year coal supply agreements with PacifiCorp and Intermountain Power Agency ("IPA"), two investment-grade regional utilities that operate power plants located in close proximity to our mines. These plants were designed to burn high Btu, low sulfur Utah coal. Our coal supply agreements with PacifiCorp and IPA provide for aggregate sales of (i) a minimum of 7.0 million tons and a maximum of 10.5 million tons per year through December 31, 2020, (ii) a minimum of 4.5 million tons and a maximum of 6.0 million tons per year through December 31, 2024 and (iii) a minimum of 2.0 million tons and a maximum of 3.0 million tons per year through December 31, 2029. We believe that our contracts with PacifiCorp and IPA that are set to expire in 2020 and 2024 have the potential to be extended in the future, should we choose to do so. All of our coal supply agreements with PacifiCorp and IPA include price escalators, as well as provisions that allow us to pass through (by means of a price increase) certain increases in mining and transportation costs. Please read "Business—Customers."

We have significantly enhanced the performance of our mines since they were acquired by our sponsor in August 2013. Coal production at our mines increased from 9.7 million tons for the year ended December 31, 2013 to 11.4 million tons for the year ended December 31, 2014. During the year ended December 31, 2014, we realized net loss, operating income and Adjusted EBITDA of $4.9 million, $31.4 million and $125.3 million, respectively, as compared to net income, operating income and Adjusted EBITDA of $8.1 million, $22.1 million and $75.5 million, respectively, for the year ended December 31, 2013. Please read "—Summary Historical and Pro Forma Financial and Other Data—Non-GAAP Financial Measures" for the definition of Adjusted EBITDA and a reconciliation of Adjusted EBITDA to our most directly comparable financial measure calculated and presented in accordance with GAAP.

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We plan to seek acquisition targets similar to our current operations, utilizing our sales contract position, our strategic export capacity and our proven ability to maximize productivity in order to facilitate future accretive transactions. Pursuant to the omnibus agreement that we expect to enter into in connection with this offering, our sponsor will grant us a right of first refusal with respect to certain coal and terminal properties. In addition, we expect to enter into an agreement with Bowie Refined Coal, LLC, an affiliate of our sponsor, providing us with a right of first refusal to acquire certain refined coal projects that it owns. Please read "Certain Relationships and Related Party Transactions." Additionally, we will pursue three organic development projects in the next decade; specifically, the addition of a third continuous miner to our Dugout Canyon mine, the development of the Fossil Rock reserves and the development of reserves in the Lower Hiawatha seam of our Sufco mine. Finally, we expect to benefit from increasing demand and prices for our coal in the export markets of the Pacific Rim. Please read "—Recent Developments" for a description of the Fossil Rock reserves.

We benefit from a differentiated transportation and logistics network established by our sponsor, including its access to port terminals in California through which we export our coal to a variety of growing economies on the Pacific Rim. According to Wood Mackenzie, overall demand for thermal coal imports into the Pacific market is expected to increase from 757 million metric tons in 2014 to 910 million metric tons in 2020 and 1.3 billion metric tons in 2030. Through our sponsor, we are the only coal producer with contracted U.S. West Coast export capacity, with access to terminals with an aggregate throughput capacity of approximately 5.7 million tons per year. For the year ended December 31, 2014, our sponsor exported approximately 3.3 million tons through these terminals, and we expect our sponsor to export approximately 1.0 million tons through these terminals for the year ending December 31, 2015. Prior to our sponsor leasing these terminals, no significant amount of thermal coal had been shipped through these terminals for over 10 years.

Trafigura AG ("Trafigura AG") is the exclusive marketer of our uncommitted coal, and its parent company, Trafigura Beheer B.V. ("Trafigura BV"), indirectly owns a minority interest in our sponsor. Trafigura AG and its affiliates directly or indirectly market approximately 50 million tons of coal per year in the international market. By leveraging Trafigura AG's and its affiliates' significant expertise in the coal export market and existing commodities trading infrastructure, we are able to sell our coal internationally to a variety of intermediary and end users in the power generation business.

Business Strategies

Our principal business objective is to consistently generate stable cash flows that enable us to pay quarterly cash distributions to our unitholders and, over time, sustainably increase our quarterly distributions. We expect to achieve this objective through the following business strategies:

•: Maintaining industry-leading safety standards. Safety is a top priority for us, and we incorporate and emphasize safety in all aspects of our operations, including mine operations and processes and equipment selection. Our mines have been industry leaders in the United States, with each having completed at least one calendar year without an MSHA recordable injury and each having received the National Mining Association's prestigious Sentinel of Safety award. We plan to continue working with equipment manufacturers in an effort to ensure our mining equipment and processes remain safe, and to continue implementing safety measures to maintain the high quality of our underground infrastructure.
•: Growing production and operating cash flows. We expect our coal production and cash flows to increase as a result of the Utah Transaction, and we have a pipeline of potential organic development projects to further develop our reserve base with minimal additional surface infrastructure required. Additionally, we expect to pursue acquisitions from our sponsor through its portfolio of assets and contractual rights, as well as third-party opportunities for which we are uniquely positioned. Pursuant to the omnibus agreement that we expect to enter into in

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connection with this offering, our sponsor will grant us a right of first refusal with respect to certain coal and terminal properties. In addition, we expect to enter into an agreement with Bowie Refined Coal, LLC, an affiliate of our sponsor, providing us with a right of first refusal to acquire certain refined coal projects that it owns. Please read "Certain Relationships and Related Party Transactions."

•: Further strengthening our established relationships with our customers. We are continuously evaluating opportunities to further strengthen our commercial relationships with our long-term customers. For example, in connection with the Utah Transaction, our sponsor entered into a new 15-year coal supply agreement with PacifiCorp, one of our principal customers, providing for additional sales to PacifiCorp of a minimum 2.0 million tons and a maximum of 3.0 million tons of coal per year through 2029. Please read "Business—Customers."
•: Maintaining our delivered cost advantage with our key regional customers. Our mines have a track record of stable production and low direct mining costs per ton. For the year ended December 31, 2014 and the three months ended March 31, 2015, our operations had direct mining costs per ton of $20.31 and $22.90, respectively. Direct mining costs per ton is defined as cost of coal sales, exclusive of items shown separately (as defined in Appendix B), divided by tons sold. We intend to continue building upon and expanding our position as one of the lowest cost Western Bituminous coal producers. Low operating costs, driven by high-quality longwall reserves, a skilled and experienced non-union workforce and a consistent safety track record, combined with our geographical advantage and cost competitive transportation contracts, should allow us to maintain our overall competitive advantage on a delivered cost basis and continue to drive favorable margins in nearly any coal price environment, further differentiating us from our peers.
•: Utilizing our sponsor's export capacity to expand the size and diversity of our coal sales portfolio. While we view sales to local utility customers as our principal generator of cash flows, we expect to benefit from our sponsor's plan to further expand sales into international coal markets, which we expect to provide additional cash flows and diversification from our primary domestic market. We expect export coal markets to have the potential to provide significant growth opportunities relative to the domestic coal market. Although the largest domestic coal producers have attempted to secure export capacity to access the Pacific market, we are the only coal producer with contracted U.S. West Coast export capacity. This provides us with unique competitive advantages, including the option of selling any uncommitted coal we produce into international markets.
•: Continuing to develop and grow our reserve base. We believe our Dugout Canyon mine can support an additional continuous miner unit without any additional surface infrastructure, which would increase its productive capacity from approximately 1.1 million tons per year to approximately 1.5 million tons per year. The Fossil Rock reserves increase our proven and probable reserves by an estimated 11.2 million tons and 32.5 million tons, respectively, and at full production, we expect to produce approximately 4.0 million tons of coal per year from the Fossil Rock reserves from 2017 through 2034. Additionally, we expect to obtain a lease from the BLM through the lease by application process for the Greens Hollow tract, which contains approximately 50.5 million tons of non-reserve coal deposits, including those in the Lower Hiawatha seam, accessible through our Sufco mine.

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Competitive Strengths

We believe we are well-positioned to execute our business strategies because of the following competitive strengths:

•: Portfolio of multi-year, fixed-price coal supply agreements providing stable long-term cash flows. We believe our long-term coal supply agreements provide significant sustainable revenue and should generate stable and reliable cash flows. On a pro forma basis, after giving effect to the closing of the Utah Transaction, we expect coal sales under our existing coal supply agreements of approximately 11.2 million tons in 2015, 9.0 million tons in 2016, 9.5 million tons in 2017 and 9.3 million tons in 2018, which represent approximately 100%, 82%, 86% and 84%, respectively, of our production for the twelve months ended March 31, 2015. Included in our sales portfolio are our coal supply agreements with PacifiCorp and IPA providing for aggregate sales of (i) a minimum of 7.0 million tons and a maximum of 10.5 million tons per year through December 31, 2020, (ii) a minimum of 4.5 million tons and a maximum of 6.0 million tons per year through December 31, 2024 and (iii) a minimum of 2.0 million tons and a maximum of 3.0 million tons per year through December 31, 2029, all of which have fixed pricing, subject to certain price escalators and adjustments as described in further detail under "Business—Customers."
•: Lowest delivered cost to key regional customers maintained by geographic advantage and productivity. Our mines are strategically located in close proximity to our principal customers, and we have in place cost competitive options for both trucking and rail transportation of our coal to these customers. According to Wood Mackenzie, we can deliver our coal to PacifiCorp and IPA at a lower cost per Btu compared to coal from other producers in the Western Bituminous region, coal from other basins and natural gas, even when adjusted for different heat rate efficiencies between coal and natural gas-fired power plants. Our two longwall mines were among the 15 most productive underground coal mines in the United States for the year ended December 31, 2014, on a clean tons produced per man hour basis based on MSHA data. Our industry-leading productivity and resulting low direct mining costs per ton are driven by favorable geology and a highly motivated and skilled non-union workforce.
•: Strategically positioned to take advantage of synergistic and value-added acquisition opportunities in the Western Bituminous region. We are the largest producer of coal in the Uinta Basin, producing 84% more coal than the next largest Western Bituminous coal producer in the Uinta Basin in 2014, according to MSHA production data. In executing our acquisition strategy, we plan to seek acquisition targets similar to our current operations, utilizing our sales contract position, our strategic export capacity and our proven ability to maximize productivity in order to facilitate future accretive transactions. Retaining the largest footprint in the Uinta Basin provides us with a strong foundation for growth within both the Uinta Basin and the broader Western Bituminous region. Our contracted position and ability to sell coal into the international market should allow us to evaluate acquisition opportunities with potential for value creation by expanding production at operations that would otherwise be market constrained.
•: Differentiated transportation and logistics network providing profitable access to growing markets for our coal on the Pacific Rim. We are the only coal producer with contracted U.S. West Coast export capacity. According to Wood Mackenzie, overall demand for thermal coal imports into the Pacific market is expected to increase from 757 million metric tons in 2014 to 910 million metric tons in 2020 and 1.3 billion metric tons in 2030. We have access to export terminals in California with an aggregate throughput capacity of approximately 5.7 million tons per year. Our cost structure and the location of our mines allow us to profitably export coal when the applicable seaborne thermal benchmark price prevents our competitors from doing so. Our export capacity is enhanced by market reach through our relationship with Trafigura AG, one of

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the largest global commodity trading houses. Trafigura AG is the exclusive marketer of our uncommitted coal and its parent company, Trafigura BV, indirectly owns a minority interest in our sponsor. Trafigura AG and its affiliates directly or indirectly market approximately 50 million tons of coal per year in the international market.

•: Proven management capabilities and industry leading safety standards. Our mine management team is comprised of long-tenured coal mining professionals, highly skilled in the planning and execution of Western Bituminous coal mining operations. Our senior operations personnel have, on average, more than 30 years of experience in the coal industry. They are hands-on operators with substantial experience in operating safe mines, increasing productivity and reducing costs. In addition, our senior executives have a proven track-record of successfully identifying, acquiring, financing and integrating assets that enhance the value of our business. Our operations have exemplary safety records, and we strongly believe that safety is the most important factor in productivity. Safety is a focus and value in all aspects of our business. According to MSHA data, we have consistently outperformed national average rates in historical safety violations as well as lost-time safety incident rates.

Recent Developments

Utah Transaction

On June 5, 2015, we acquired certain undeveloped, high Btu, low sulfur coal reserves in Utah (the "Fossil Rock reserves") from an affiliate of PacifiCorp (the "Utah Transaction"). As part of the Utah Transaction, our sponsor entered into an agreement with PacifiCorp to supply all of the coal requirements of PacifiCorp's Huntington Power Plant in Utah through 2029. The Fossil Rock reserves increase our proven and probable reserves by an estimated 11.2 million tons and 32.5 million tons, respectively. At full production, we expect to produce approximately 4.0 million tons of coal per year from the Fossil Rock reserves from 2017 through 2034. The Fossil Rock reserves are located closer to PacifiCorp's Huntington and Hunter Power Plants than our existing mines, which we believe will significantly reduce our transportation costs to this principal customer.

Flat Canyon Lease

Senior Secured Notes Offering and Revolving Credit Facility

Prior to this offering Bowie Finance Corp. ("Finance Corp."), our wholly owned subsidiary, closed a private placement of $ million aggregate principal amount of % senior secured notes due (the "New Notes"). In connection with the closing of the offering of New Notes, Finance Corp. deposited into an escrow account the gross proceeds from the New Notes offering, plus an amount sufficient to pay certain accrued interest and accreted yield. The release of the escrowed funds will be subject to the satisfaction of certain conditions, including the consummation of this offering (the

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"Escrow Release Conditions"). From and after the satisfaction of the Escrow Release Conditions, which we expect to occur concurrently with the closing of this offering, the partnership will become a co-issuer of the New Notes and a party to the indenture governing the New Notes, and will receive $ million of net proceeds (after payment of underwriting discounts) from the offering of the New Notes. The New Notes will be guaranteed on a senior secured basis, jointly and severally, by all of the partnership's direct and indirect wholly owned domestic subsidiaries that will guarantee our indebtedness under a new $ million revolving credit facility that we expect to enter into concurrently with the closing of this offering. This prospectus is not an offer to sell any of the New Notes.

Coal Market Overview

Domestic demand for Western Bituminous coal is growing. According to Wood Mackenzie, coal production from the Western Bituminous region increased between 2013 and 2014, despite lower sales to traditional buyers of Colorado coal such as the Tennessee Valley Authority. There has been growth in the Utah coal market, a subregion of the Western Bituminous region, which is insular in nature due to its low delivered cost, its high Btu value and its low sulfur content. In 2014, coal production in Utah increased by 9% over 2013 levels, according to MSHA data. Coal produced in Utah is an ideal base load fuel source for the regional power plants, including those that do not have scrubbers. Over the last few years, largely as a result of our sponsor's activities, increasing amounts of Western Bituminous coal have been exported through terminals on the U.S. West Coast. Wood Mackenzie projects production of Utah coal to grow to 20.7 million tons in 2020, representing a compound annual growth rate of 3.4% from 2013 production.

Coal remains an in-demand, cost-competitive energy source in the United States. Coal has historically been a low-cost, stable and reliable source of energy relative to alternative fuel sources. Conventional coal-powered generation plants also have a lower level of capital cost relative to alternative energy sources, such as nuclear, hydroelectric, wind and solar power. Despite recent reductions in coal-fired electrical demand, coal is expected to continue to account for the largest share of the electricity generation mix in the United States, representing an average 41.0% share of domestic electricity generation from 2014 to 2020 according to the EIA. According to Wood Mackenzie, total U.S. electricity generation is expected to grow by a total of 20.3% from 2014 to 2025.

Global coal demand continues to grow. According to the World Coal Association, in 2013, coal serviced 30.1% of global primary energy needs (the highest since 1970) and generated over 40% of the world's electricity. The World Coal Association estimates that total world coal production reached a record level of 7.8 billion metric tons in 2013, or 0.4% more than in 2012. The World Coal Association reports that coal has accounted for nearly half of the increase in global energy use over the past decade, with coal's global contribution in the 21^st century alone being comparable to the contribution of nuclear, oil, natural gas and renewables combined. In 2013, global coal consumption grew by 2.8% compared to 2012, making coal the world's fastest growing fossil fuel during the period.

Long-term growth in demand for seaborne thermal coal supply focused in the Pacific Rim. Although prices for seaborne thermal coal declined in 2014, we believe that over the long-term, Pacific Rim demand for global seaborne thermal coal will increase. According to Wood Mackenzie, the industrialization and development of China, India and the wider Asia Pacific region should support the long-term future of coal in the global energy mix, with China accounting for 39% of global thermal coal demand growth between 2014 and 2030. By 2030, Chinese thermal coal demand is expected to represent 47% of world thermal coal demand according to Wood Mackenzie. The graph below illustrates this increase in demand for coal in Asia. Wood Mackenzie projects that Pacific market thermal coal demand will increase at a compound annual growth rate of 3.6% through 2035. Western Bituminous coal is well situated to take advantage of this growing Asian seaborne demand with Utah

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coal being the lowest cost bituminous U.S. coal supplied into an ocean vessel FOB on the U.S. West Coast.

Thermal Seaborne Import Coal Demand

Million Metric Tons

Source: Wood Mackenzie, May 2015

Sponsor

One of our principal strengths is our relationship with our sponsor. Our sponsor is owned by Cedars Energy, LLC ("Cedars") and Galena US Holdings, Inc. ("Galena"). Cedars is a coal sector investor with a track record of acquiring, integrating and developing coal and coal-related assets. Galena is wholly owned by Galena Private Equity Resource Fund, which is managed by Galena Asset Management S.A. ("Galena Asset Management"), a wholly-owned subsidiary of Trafigura BV. Trafigura AG, a wholly-owned subsidiary of Trafigura BV, is our exclusive marketing agent. Trafigura BV has 45 offices in 36 countries around the world and generated revenues of approximately $127.6 billion in 2014. By leveraging Trafigura AG's and its affiliates' significant expertise in the coal export market and existing commodities trading infrastructure, we are able to sell our coal internationally to a variety of intermediary and end users in the power generation business. Our sponsor has extensive experience in identifying, acquiring, financing and integrating assets that enhance the value of our business. Our sponsor successfully executed a business plan that increased the post-acquisition profitability of our operations, resulting in a 66% increase in Adjusted EBITDA from the year ended December 31, 2013 to the year ended December 31, 2014. We believe that our sponsor's experience and expertise in mergers and acquisitions of strategic assets will enhance our ability to achieve our growth objectives. Please read "Business—Our Sponsor."

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Risk Factors

An investment in our common units involves risks. Please read carefully the risks described under the caption "Risk Factors" beginning on page 21 of this prospectus.

Management

We are managed and operated by the board of directors and executive officers of our general partner, Bowie GP, LLC, a wholly-owned subsidiary of our sponsor. Some of our directors and all of our executive officers also serve as directors and executive officers of our sponsor. Following this offering, % of our outstanding common units and all of our outstanding subordinated units and incentive distribution rights will be owned, directly or indirectly, by our sponsor. As a result of controlling our general partner, our sponsor will have the right to appoint all members of the board of directors of our general partner, including the independent directors. Our unitholders will not be entitled to elect our general partner or its directors or otherwise directly participate in our management or operations. Certain executive officers of our general partner hold a profits interest in our sponsor. For more information about the executive officers and directors of our general partner, please read "Management."

Following the consummation of this offering, neither our general partner nor our sponsor will receive any management fee, but we will reimburse our general partner and its affiliates for all expenses they incur and payments they make on our behalf. Our partnership agreement provides that our general partner will determine the expenses that are allocable to us. In addition, pursuant to an omnibus agreement, we will reimburse our sponsor on a cost-of-services basis for certain services performed on our behalf. Please read "Certain Relationships and Related Party Transactions."

Our operations will be conducted through, and our operating assets will be owned by, our operating company, BRP Holdings LLC. All of the employees that conduct our business will be employed by our general partner, its affiliates or our subsidiaries.

Conflicts of Interest and Fiduciary Duties

Our general partner has a contractual duty to manage us in a manner that it believes is not adverse to our interest. However, the officers and directors of our general partner also have duties to manage our general partner in a manner beneficial to our sponsor, the owner of our general partner. Our sponsor and its affiliates are not prohibited from engaging in other business activities, including those that might be in direct competition with us. In addition, our sponsor may compete with us for investment opportunities and may own an interest in entities that compete with us. As a result, conflicts of interest may arise in the future between us or our unitholders, on the one hand, and our sponsor and our general partner, on the other hand.

Our partnership agreement limits the liability of and replaces the fiduciary duties that would otherwise be owed by our general partner to our unitholders. Our partnership agreement also restricts the remedies available to our unitholders for actions that might otherwise constitute a breach of duties by our general partner or its directors or officers. Our partnership agreement also provides that affiliates of our general partner, including our sponsor, are not restricted from competing with us and have no obligation to present business opportunities to us. By purchasing a common unit, the purchaser agrees to be bound by the terms of our partnership agreement, and each unitholder is treated as having consented to various actions and potential conflicts of interest contemplated in the partnership agreement that might otherwise be considered a breach of fiduciary or other duties under Delaware law.

For a more detailed description of the conflicts of interest and duties of our general partner and its directors and officers, please read "Conflicts of Interest and Fiduciary Duties." For a description of

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other relationships with our affiliates, please read "Certain Relationships and Related Party Transactions."

IPO Reorganization and Partnership Structure

We are a Delaware limited partnership formed in January 2015 by our general partner and our sponsor. In connection with the closing of this offering, we expect that the following transactions will occur (the "IPO Reorganization"):

•: Canyon Fuel Company, LLC ("CFC") will distribute all cash and cash equivalents, including accounts receivable, to our sponsor.
•: Our sponsor will transfer or cause to be transferred 100% of the equity interests in (i) CFC, including CFC's subsidiary, Fossil Rock Resources, LLC, and (ii) Hunter Prep Plant, LLC to us in exchange for (a) common units ( common units if the underwriters exercise their option to purchase additional common units in full) and subordinated units and (b) a right to receive a cash distribution of up to $ million from us as reimbursement for capital expenditures.
•: We will issue incentive distribution rights ("IDRs") to our general partner.
•: After satisfaction of the Escrow Release Conditions, we will become a co-issuer of the New Notes and a party to the indenture governing the New Notes, and will receive $ million of net proceeds (after payment of underwriting discounts) from the offering of New Notes.
•: We will enter into a new $ million revolving credit facility under which $ million will be drawn as of the closing of this offering.
•: CFC will be released as a guarantor under our sponsor's Senior Secured Credit Facilities (defined herein), and the liens on the assets contributed to us and securing borrowings under these facilities will be released.
•: We will enter into a coal supply agreement with our sponsor pursuant to which it will purchase substantially all of our coal on substantially the same terms as our sponsor's agreements with our end customers. Please read "Certain Relationships and Related Party Transactions—Agreements with Affiliates in Connection with the Transactions—Coal Supply Agreement with Our Sponsor."
•: CFC, our sponsor and Trafigura AG will terminate the existing Coal Services Agreement and our operating company and its subsidiaries will enter into a new Coal Services Agreement with our sponsor and Trafigura AG. Please read "Certain Relationships and Related Party Transactions—Agreements with Affiliates in Connection with the Transactions—Coal Services Agreement."
•: We will enter into an omnibus agreement and certain other agreements with our sponsor and its affiliates, as described in "Certain Relationships and Related Party Transactions—Agreements with Affiliates in Connection with the Transactions."
•: We will issue and sell common units to the public and will use the net proceeds therefrom, together with the net proceeds from our offering of New Notes, as described under "Use of Proceeds."

We have granted the underwriters a 30-day option to purchase up to an aggregate of additional common units to cover over-allotments. Any net proceeds received from the exercise of this option will be used to make a distribution to our sponsor as reimbursement for capital expenditures. If the underwriters do not exercise this option in full or at all, the common units that would have been sold to the underwriters had they exercised the option in full will be issued to our sponsor for no

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additional consideration at the expiration of the option period. Accordingly, the exercise of the underwriters' option will not affect the total number of common units outstanding.

The following chart summarizes our structure after giving effect to the IPO Reorganization, including this offering and the use of proceeds therefrom:

(1): Prior to the IPO Reorganization and in connection with the closing of the Utah Transaction, Fossil Rock Resources, LLC acquired the Fossil Rock reserves from an affiliate of PacifiCorp and Hunter Prep Plant, LLC acquired certain real property from PacifiCorp. Neither entity had a history of operations, nor did they own any assets until the closing of the Utah Transaction.

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Our Emerging Growth Company Status

We are an "emerging growth company" as defined in the Jumpstart Our Business Startups Act of 2012 ("JOBS Act"). For as long as we are an emerging growth company, unlike other public companies, we will not be required to:

•: provide an auditor's attestation report on management's assessment of the effectiveness of our system of internal control over financial reporting pursuant to Section 404(b) of the Sarbanes-Oxley Act of 2002;
•: comply with any new requirements adopted by the Public Company Accounting Oversight Board ("PCAOB") requiring mandatory audit firm rotation or a supplement to the auditor's report in which the auditor would be required to provide additional information about the audit and the financial statements of the issuer;
•: comply with any new audit rules adopted by the PCAOB after April 5, 2012, unless the SEC determines otherwise;
•: provide certain disclosure regarding executive compensation required of larger public companies; or
•: submit for unitholder approval golden parachute payments not previously approved.

We will cease to be an "emerging growth company" upon the earliest of:

•: when we have $1.0 billion or more in annual revenues;
•: when we have at least $700 million in market value of our common units held by non-affiliates;
•: when we issue more than $1.0 billion of non-convertible debt over a three-year period; or
•: the last day of the fiscal year following the fifth anniversary of our initial public offering.

In addition, Section 107 of the JOBS Act also provides that an emerging growth company can take advantage of the extended transition period provided in Section 7(a)(2)(B) of the Securities Act for complying with new or revised accounting standards. In other words, an emerging growth company can delay the adoption of certain accounting standards until those standards would otherwise apply to private companies. However, we are choosing to "opt out" of such extended transition period, and as a result, we will comply with new or revised accounting standards on the relevant dates on which adoption of such standards is required for non-emerging growth companies. Section 107 of the JOBS Act provides that our decision to opt out of the extended transition period for complying with new or revised accounting standards is irrevocable.

Please read "Risk Factors—Risks Inherent in an Investment in Us—For as long as we are an emerging growth company, we will not be required to comply with certain reporting requirements that apply to other public companies, including those relating to auditing standards and disclosure about our executive compensation."

Partnership Information

Our principal executive offices are located at 6100 Dutchmans Lane, 9th Floor, Louisville, Kentucky 40205. Our phone number is (502) 584-6022. Our website address is . We intend to make our periodic reports and other information filed with or furnished to the SEC available, free of charge, through our website, as soon as reasonably practicable after those reports and other information are electronically filed with or furnished to the SEC. Information on our website or any other website is not incorporated by reference into this prospectus and does not constitute a part of this prospectus.

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The Offering


Common units offered to the public		common units.
		common units if the underwriters exercise in full their option to purchase additional common units to cover over-allotments.
Units outstanding after this offering		common units and subordinated units. The exercise of the underwriters' option will not affect the total number of common units outstanding. Please read "—IPO Reorganization and Partnership Structure."
Use of proceeds		We expect to receive approximately $ million of net proceeds from the sale of common units by us in this offering (based on an assumed initial offering price of $ per common unit, the mid-point of the price range set forth on the cover page of this prospectus), after deducting the estimated underwriting discounts and offering expenses. Assuming the Escrow Release Conditions have been satisfied, concurrently with the closing of this offering, we expect to receive approximately $ million of net proceeds from our offering of $ million aggregate principal amount of New Notes. We intend to use the net proceeds of this offering and our offering of the New Notes as follows: (i) $ million to make a cash distribution to our sponsor, in part as reimbursement for capital expenditures, (ii) $ million to repay a $30 million promissory note and a $10 million promissory note, each issued to PacifiCorp or its affiliate in connection with the Utah Transaction (the "PacifiCorp Notes"), (iii) $ million to repay CFC's outstanding equipment notes with Prudential Insurance Company of America (collectively, the "Prudential Notes") and (iv) $ million for general partnership purposes. Please read "Use of Proceeds" and "Management's Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Long-Term Debt—Prudential Notes."
		If the underwriters exercise their option to purchase additional common units in full, the additional net proceeds to us would be approximately $ million (based on an assumed initial offering price of $ per common unit, the mid-point of the price range set forth on the cover page of this prospectus). The net proceeds from any exercise of such option will be used to make a cash distribution to our sponsor, in part as reimbursement for capital expenditures. If the underwriters do not exercise their option, we will issue such additional common units to our sponsor upon the expiration of the option.
		We expect that a portion of the net proceeds distributed to our sponsor will be used by our sponsor to repay outstanding indebtedness under our sponsor's Senior Secured Credit Facilities (defined herein). Please read "Use of Proceeds." We

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		expect that Cedars, which is directly or indirectly owned or controlled by certain of our directors and director nominees, will receive $ million (or $ million if the underwriters exercise their option to purchase additional units) of the net proceeds from this offering as a result of the distribution by our sponsor of a portion of the proceeds it receives from us, and that our executive officers will receive an aggregate of $ million (or $ million if the underwriters exercise their option to purchase additional units) in connection with this offering from the cash distribution made to our sponsor pursuant to a sponsor-level bonus arrangement. Please read "Certain Relationships and Related Party Transactions—Agreements with Affiliates in Connection with the Transactions—Ownership Interests in our Sponsor and Arrangements with Management."
		Affiliates of certain of the underwriters are lenders under our sponsor's Senior Secured Credit Facilities and, accordingly, may ultimately receive a portion of the net proceeds from the offering of our New Notes. Certain of the underwriters are also initial purchasers in connection with the New Notes offering. Please read "Underwriting."
Cash distributions		Within 60 days after the end of each quarter, we expect to make a cash distribution to holders of our common units and subordinated units. We expect to make a minimum quarterly distribution of $ per common unit and subordinated unit ($ per common unit and subordinated unit on an annualized basis) to the extent we have sufficient cash after the establishment of cash reserves and the payment of fees and expenses, including payments to our general partner and its affiliates. For the first quarter that we are publicly traded, we will pay a prorated distribution covering the period after the consummation of this offering through , 2015, based on the actual length of that period.
		The board of directors of our general partner will adopt a policy pursuant to which distributions for each quarter will be paid to the extent we have sufficient cash after establishment of cash reserves and payment of fees and expenses, including payments to our general partner and its affiliates. Our ability to pay the minimum quarterly distribution is subject to various restrictions and other factors described in more detail in "Cash Distribution Policy and Restrictions on Distributions."
		Our partnership agreement generally provides that we will distribute cash each quarter during the subordination period in the following manner:
		• first, to the holders of common units, until each common unit has received the minimum quarterly distribution of $ plus any arrearages from prior quarters;

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		• second, to the holders of subordinated units, until each subordinated unit has received the minimum quarterly distribution of $ ; and
		• third, to the holders of common units and subordinated units, pro rata, until each has received a distribution of $ .
		If cash distributions to our unitholders exceed $ per unit on all common and subordinated units in any quarter, our unitholders and our general partner, as the holder of our IDRs, will receive distributions according to the following percentage allocations:

	Marginal Percentage Interest in Distributions

Total Quarterly Distribution Target Amount	Unitholders			General Partner (as holder of IDRs)
above $ up to $		85.0	%		15.0	%
above $ up to $		75.0	%		25.0	%
above $		50.0	%		50.0	%


		We refer to the additional increasing distributions to our general partner as "incentive distributions." Please read "How We Make Distributions To Our Partners—Incentive Distribution Rights."
		Pro forma cash available for distribution for the year ended December 31, 2014 and the twelve months ended March 31,
		2015 were approximately $ and $ , respectively. The amount of cash available for distribution for the year ended December 31, 2014 and the twelve months ended March 31, 2015 on a pro forma basis would not have been sufficient to allow us to pay the full minimum quarterly distribution on all of our common units and subordinated units during those periods. For a calculation of our ability to make distributions to our unitholders based on our pro forma results of operations for the year ended December 31, 2014 and the twelve months ended March 31, 2015, please read "Cash Distribution Policy and Restrictions on Distributions—Unaudited Pro Forma Cash Available for Distribution."
		We believe, based on our financial forecast and related assumptions included in "Cash Distribution Policy and Restrictions on Distributions," that we will have sufficient cash available for distribution to pay the minimum quarterly distribution of $ on all of our common units and subordinated units for the twelve months ending June 30, 2016. However, we do not have a legal or contractual obligation to pay distributions quarterly or on any other basis or at the minimum quarterly distribution rate or at any other rate, and there is no guarantee that we will pay distributions to our unitholders in any quarter. Our actual results of operations, cash flows and financial condition during the forecast period may vary from the forecast, and there is no guarantee that we will make quarterly cash distributions to our

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		unitholders. Please read "Cash Distribution Policy and Restrictions on Distributions."
Eligible Holders and redemption		To comply with certain U.S. laws relating to the ownership of interests in mineral leases on federal lands, transferees may be required to fill out a properly completed transfer application certifying, and our general partner, acting on our behalf, may at any time require each unitholder to re-certify, that the unitholder is an Eligible Holder. As used herein, an Eligible Holder means a person or entity qualified to hold an interest in mineral leases on federal lands. If a transferee or a common unitholder, as the case may be, is not an Eligible Holder, the transferee or common unitholder may not have any right to receive any distributions or allocations of income or loss on its common units or to vote its common units on any matter, and we have the right to redeem such common units at a price which is equal to the then-current market price of such common units. The redemption price will be paid in cash or by delivery of a promissory note, as determined by our general partner. Please read "The Partnership Agreement—Non-Eligible Holders; Redemption."
Subordinated units		Our sponsor will initially own all of our subordinated units. The principal difference between our common units and subordinated units is that for any quarter during the subordination period, holders of the subordinated units will not be entitled to receive any distribution from operating surplus until the common units have received the minimum quarterly distribution from operating surplus for such quarter plus any arrearages in the payment of the minimum quarterly distribution from prior quarters. Subordinated units will not accrue arrearages.
Conversion of subordinated units		The subordination period will end on the first business day after we have earned and paid an aggregate amount of at least $ (the minimum quarterly distribution on an annualized basis) multiplied by the total number of outstanding common and subordinated units for each of three consecutive, non-overlapping four-quarter periods ending on or after , 2018 and there are no outstanding arrearages on our common units.
		Notwithstanding the foregoing, the subordination period will end on the first business day after we have paid an aggregate amount of at least $ (150.0% of the minimum quarterly distribution on an annualized basis) multiplied by the total number of outstanding common and subordinated units and we have earned that amount plus the related distribution on the incentive distribution rights, for any four-quarter period ending on or after , 2016 and there are no outstanding arrearages on our common units.
		When the subordination period ends, all subordinated units will convert into common units on a one-for-one basis, and all common units will thereafter no longer be entitled to arrearages.

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General partner's right to reset the target distribution levels		Our general partner, as the initial holder of our incentive distribution rights, will have the right, at any time when there are no subordinated units outstanding and we have made distributions in excess of the highest then-applicable target distribution for the prior four consecutive fiscal quarters, to reset the initial target distribution levels at higher levels based on our cash distributions at the time of the exercise of the reset election. If our general partner transfers all or a portion of our incentive distribution rights in the future, then the holder or holders of a majority of our incentive distribution rights will be entitled to exercise this right. Following a reset election, the minimum quarterly distribution will be adjusted to equal the distribution for the quarter immediately preceding the reset, and the target distribution levels will be reset to correspondingly higher levels based on the same percentage increases above the reset minimum quarterly distribution as the initial target distribution levels were above the minimum quarterly distribution.
		If the target distribution levels are reset, the holders of our incentive distribution rights will be entitled to receive common units. The number of common units to be issued will equal the number of common units that would have entitled the holders of our incentive distribution rights to an aggregate quarterly cash distribution for the quarter prior to the reset election equal to the distribution on the incentive distribution rights for the quarter prior to the reset election. Please read "How We Make Distributions To Our Partners—Incentive Distribution Rights—Incentive Distribution Right Holders' Right to Reset Incentive Distribution Levels."
Issuance of additional units		Our partnership agreement authorizes us to issue an unlimited number of additional units without the approval of our unitholders. Please read "Units Eligible for Future Sale" and "The Partnership Agreement—Issuance of Additional Interests."
Limited voting rights		Our general partner will manage and operate us. Unlike the holders of common stock in a corporation, our unitholders will have only limited voting rights on matters affecting our business. Our unitholders will have no right to elect our general partner or its directors on an annual or other continuing basis. Our general partner may not be removed except by a vote of the holders of at least 66²/3% of the outstanding units, including any units owned by our general partner and its affiliates, voting together as a single class. Upon consummation of this offering, our sponsor will own an aggregate of % of our outstanding units (or % of our outstanding units, if the underwriters exercise their option to purchase additional common units in full). This will give our sponsor the ability to prevent the removal of our general partner. In addition, any vote to remove our general partner during the subordination period must provide for the

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		majority of the common units and a majority of the subordinated units, voting as separate classes. This will provide our sponsor the ability to prevent the removal of our general partner. Please read "The Partnership Agreement—Voting Rights."
Limited call right		If at any time our general partner and its affiliates own more than 80% of the outstanding common units, our general partner may purchase all of the remaining common units at a price equal to the greater of (1) the average of the daily closing price of the common units over the 20 trading days preceding the date three days before notice of exercise of the call right is first mailed and (2) the highest per-unit price paid by our general partner or any of its affiliates for common units during the 90-day period preceding the date such notice is first mailed. Please read "The Partnership Agreement—Limited Call Right."
Estimated ratio of taxable income to distributions		We estimate that if you own the common units you purchase in this offering through the record date for distributions for the period ending December 31, , you will be allocated, on a cumulative basis, an amount of federal taxable income for that period that will be less than % of the cash distributed to you with respect to that period. For example, if you receive an annual distribution of $ per unit, we estimate that your average allocable federal taxable income per year will be no more than approximately $ per unit. Thereafter, the ratio of allocable taxable income to cash distributions to you could substantially increase. Please read "Material U.S. Federal Income Tax Consequences—Tax Consequences of Unit Ownership" for the basis of this estimate.
Material federal income tax consequences		For a discussion of the material federal income tax consequences that may be relevant to prospective unitholders who are individual citizens or residents of the United States, please read "Material U.S. Federal Income Tax Consequences."
Exchange listing		We intend to apply to list our common units on the New York Stock Exchange ("NYSE") under the symbol "BRLP."

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Summary Historical and Pro Forma Financial and Other Data

The following table sets forth our summary historical and pro forma financial and other data, as of the dates and for the periods indicated. The summary historical financial data presented as of August 16, 2013 and for the period from January 1, 2013 to August 16, 2013 have been derived from the audited financial statements of CFC prior to the acquisition of CFC by our sponsor on August 16, 2013 (the "Predecessor"), included elsewhere in this prospectus. The summary historical financial data presented as of December 31, 2013, for the period from August 16, 2013 to December 31, 2013 and as of and for the year ended December 31, 2014 have been derived from the audited financial statements of CFC after the acquisition of CFC by our sponsor (the "Successor"), included elsewhere in this prospectus.

The summary historical financial data presented as of and for the three months ended March 31, 2014 and 2015 have been derived from the unaudited interim financial statements of the Successor included elsewhere in this prospectus. The unaudited interim financial statements have been prepared on the same basis as the Successor's audited financial statements and, in the opinion of our management, include all material adjustments, consisting of normal and recurring adjustments, necessary for a fair presentation of the information set forth herein. The summary historical interim balance sheet data as of March 31, 2014 have been derived from unaudited interim financial statements of the Successor, which are not included in this prospectus. Operating results for the three months ended March 31, 2015 are not necessarily indicative of the results that may be expected for the year ended December 31, 2015 or for any future period.

The summary unaudited pro forma financial data presented as of and for the year ended December 31, 2014 and the three months ended March 31, 2015 have been derived from the unaudited pro forma condensed consolidated financial statements of Bowie Resource Partners LP, included elsewhere in this prospectus. The unaudited pro forma condensed consolidated financial statements of Bowie Resource Partners LP give pro forma effect to the IPO Reorganization described under "—IPO Reorganization and Partnership Structure." The unaudited pro forma condensed consolidated balance sheet as of March 31, 2015 reflects the IPO Reorganization as if it occurred on March 31, 2015. The pro forma condensed consolidated statement of (loss) income for the year ended December 31, 2014 and the three months ended March 31, 2015 reflect the IPO Reorganization as if it occurred on January 1, 2014.

We have not given pro forma effect to incremental selling, general and administrative expenses of approximately $ that we expect to incur annually as a result of operating as a publicly traded partnership.

The summary historical and pro forma financial and other data presented below should be read in conjunction with the information presented under "Selected Historical and Pro Forma Financial and Other Data," "Management's Discussion and Analysis of Financial Condition and Results of Operations" and the financial statements and related notes thereto appearing in this prospectus.

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	Predecessor			Successor

	Year Ended December 31, 2013															Bowie Resource Partners LP Pro Forma
	Year Ended December 31, 2013

	Period from January 1, 2013 to August 16, 2013			Period from August 16, 2013 to December 31, 2013			Year Ended December 31, 2014			Three Months Ended March 31, 2014			Three Months Ended March 31, 2015			Year Ended December 31, 2014	Three Months Ended March 31, 2015
				(in thousands, except per ton data)
Statements of Operations Data
Coal sales	$	219,140		$	158,756		$	419,804		$	112,265		$	103,924		$	$
Other revenues, net(1)		813			1,410			358			89			91
Costs and expenses:
Cost of coal sales, exclusive of items shown separately below		140,781			96,165			232,819			63,115			61,629
Transportation		30,477			19,690			44,439			12,758			12,808
Depreciation, depletion and amortization		21,955			27,251			81,057			18,592			21,334
Accretion on asset retirement obligations		462			—			785			196			206
Selling, general and administrative expenses		7,970			9,586			17,590			3,159			4,173
Amortization of acquired sales contracts, net		—			3,708			12,098			3,181			(54	)

Operating income		18,308			3,766			31,374			11,353			3,919
Other expenses (income):
Interest expense and related financing costs		—			13,604			36,245			9,093			8,021
Gain on sale of assets		(389	)		—			—			—			—
Other		769			—			—			—			—

Net income (loss)	$	17,928		$	(9,838	)	$	(4,871	)	$	2,260		$	(4,102	)	$	$



Cash Flow Data
Net cash provided by operating activities	$	45,964		$	14,858		$	84,524		$	12,941		$	5,454
Net cash used in investing activities	$	(5,217	)	$	(8,373	)	$	(27,044	)	$	(1,119	)	$	(5,960	)
Net cash (used in) provided by financing activities	$	(40,807	)	$	(6,485	)	$	(57,480	)	$	(11,822	)	$	506
Balance Sheet Data (at period end)
Total current assets	$	51,857		$	82,093		$	84,655		$	80,907		$	93,375			$
Property, plant and equipment, net	$	285,934		$	400,945		$	357,110		$	385,612		$	344,557			$
Other assets	$	5,192		$	36,615		$	17,659		$	36,701		$	16,203			$
Total liabilities	$	51,430		$	495,027		$	440,104		$	480,497		$	446,069			$
Member's equity	$	291,553		$	24,626		$	19,320		$	22,723		$	8,066			$
Total liabilities and member's equity	$	342,983		$	519,653		$	459,424		$	503,220		$	454,135			$
Other Data
EBITDA(2)	$	39,883		$	34,725		$	124,529		$	33,126		$	25,199		$	$
Adjusted EBITDA(2)	$	40,725		$	34,725		$	125,314		$	33,322		$	25,405		$	$
Tons produced		5,793			3,863			11,386			2,935			2,518
Tons sold		5,614			4,440			11,463			3,175			2,691
Coal sales realized per ton(3)	$	39.03		$	35.76		$	36.62		$	35.36		$	38.62		$	$
Direct mining costs per ton(4)	$	25.08		$	21.66		$	20.31		$	19.88		$	22.90		$	$

(1): Primarily includes net revenues from contract terminations (bookouts), restructuring payments, royalties related to coal lease agreements and revenues from property and facility rentals.
(2): Please read "—Non-GAAP Financial Measures" below for the definitions of EBITDA and Adjusted EBITDA and a reconciliation of EBITDA and Adjusted EBITDA to our most directly comparable financial measure, calculated and presented in accordance with GAAP.
(3): Coal sales realized per ton is defined as coal sales divided by tons sold.
(4): Direct mining costs per ton is defined as cost of coal sales, exclusive of items shown separately, divided by tons sold.

Non-GAAP Financial Measures

EBITDA and Adjusted EBITDA are non-GAAP financial measures used by our management and by external users of our financial statements such as investors, commercial banks, research analysts and others to assess:

•: our ability to make distributions to our unitholders;
•: the financial performance of our assets without regard to financing methods, capital structure or historical cost basis;

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•: the ability of our assets to generate sufficient cash to pay interest costs and support our indebtedness;
•: our operating performance and return on capital as compared to those of other companies and partnerships in our industry, without regard to financing or capital structure; and
•: the feasibility of acquisitions and other capital expenditures and the overall rates of return on investment opportunities.

We define EBITDA as net income (loss) before interest expense, income tax, depreciation, depletion and amortization. We define Adjusted EBITDA as EBITDA further adjusted for accretion of asset retirement obligations, gain or loss on sale of assets, casualty losses and other taxes.

EBITDA and Adjusted EBITDA should not be considered alternatives to, or more meaningful than, net income (loss), income from operations, cash flows from operating activities or any other measure of financial performance or liquidity presented in accordance with GAAP as measures of our operating performance or liquidity. EBITDA and Adjusted EBITDA do not include changes in working capital, capital expenditures and other items that are set forth in cash flow statement presentation of our operating, investing and financing activities. Any measures that exclude these elements have material limitations. Our computations of EBITDA and Adjusted EBITDA may differ from computations of similarly titled measures of other companies.

The following table presents a reconciliation of EBITDA and Adjusted EBITDA to the most directly comparable GAAP financial measure for the periods indicated.

	Predecessor			Successor

	Year Ended December 31, 2013														Bowie Resource Partners LP Pro Forma
	Year Ended December 31, 2013

	Period from January 1, 2013 to August 16, 2013			Period from August 16, 2013 to December 31, 2013			Year Ended December 31, 2014			Three Months Ended March 31, 2014		Three Months Ended March 31, 2015			Year Ended December 31, 2014	Three Months Ended March 31, 2015
				(in thousands)
Reconciliation of EBITDA and Adjusted EBITDA to Net income (loss) :
Net income (loss)	$	17,928		$	(9,838	)	$	(4,871	)	$	2,260	$	(4,102	)	$	$
Add:
Depreciation, depletion and amortization		21,955			27,251			81,057			18,592		21,334
Amortization of acquired sales contracts, net		—			3,708			12,098			3,181		(54	)
Interest expense and related financing costs		—			13,604			36,245			9,093		8,021

EBITDA		39,883			34,725			124,529			33,126		25,199
Add:
Accretion on asset retirement obligations		462			—			785			196		206
Gain on sale of assets		(389	)		—			—			—		—
Other		769			—			—			—		—

Adjusted EBITDA	$	40,725		$	34,725		$	125,314		$	33,322	$	25,405		$	$

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RISK FACTORS

An investment in our common units involves risks. Limited partner interests are inherently different from the capital stock of a corporation, although many of the business risks to which we are subject are similar to those that would be faced by a corporation engaged in a similar business. You should carefully consider the following risk factors, together with all of the other information included in this prospectus, in evaluating an investment in our common units.

If any of the following risks were to occur, our business, financial condition, results of operations and cash available for distribution could be materially adversely affected. In that case, we might not be able to make distributions on our common units, the trading price of our common units could decline, and you could lose all or part of your investment.

Risks Related to Our Business

We may not have sufficient cash from operations to pay the minimum quarterly distribution on our common and subordinated units following establishment of cash reserves and payment of costs and expenses, including reimbursement of expenses to our general partner. On a pro forma basis, we would not have had sufficient cash available for distribution to pay the full minimum quarterly distribution on all of our units for the year ended December 31, 2014 or the twelve months ended March 31, 2015.

We may not have sufficient cash each quarter to pay the full amount of our minimum quarterly distribution of $ per unit, or $ per unit per year, which will require us to have cash available for distribution of approximately $ per quarter, or $ per year, based on the number of common and subordinated units that will be outstanding immediately after the completion of this offering. The amount of cash we can distribute to holders of our units principally depends upon the amount of cash we generate from our operations, which will fluctuate from quarter to quarter based on, among other things:

•: the amount of coal we are able to produce from our properties, which could be adversely affected by, among other things, operating difficulties and unfavorable geologic conditions;
•: the market price of coal;
•: the level of our operating costs, including reimbursement of expenses to our general partner;
•: the supply of and demand for domestic and foreign coal;
•: the timing of shipment of our contractual coal sales which are based on annual, not quarterly, minimum purchases;
•: the impact of delays in the receipt of, failure to maintain, or revocation of necessary governmental permits;
•: the impact of delays in the receipt of, failure to maintain, or termination of necessary coal mining leases;
•: the price and availability of other fuels;
•: the impact of existing and future environmental and climate change regulations, including those impacting coal-fired power plants;
•: the loss of, or significant reduction in, purchases by our largest customers;
•: the cost of compliance with new environmental laws;
•: the cost of power needed to run our mines;
•: worker stoppages or other labor difficulties;

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•: prevailing economic and market conditions;
•: difficulties in collecting our receivables because of credit or financial problems of customers;
•: the effects of new or expanded health and safety regulations;
•: air emission, wastewater discharge and other environmental standards for coal-fired power plants or coal mines and technologies developed to help meet these standards;
•: domestic and foreign governmental regulation, including changes in governmental regulation of the mining industry or the electric utility industry;
•: the proximity to and capacity of transportation facilities;
•: the availability of transportation infrastructure, including flooding and railroad derailments;
•: competition from other coal suppliers;
•: advances in power technologies;
•: the efficiency of our mines;
•: the pricing terms contained in our long-term contracts;
•: cancellation or renegotiation of contracts;
•: legislative, regulatory and judicial developments, including those related to the release of GHGs;
•: inclement or hazardous weather conditions and natural disasters, such as heavy rain, high winds and flooding;
•: transportation costs and availability of transportation;
•: the availability of skilled employees;
•: changes in tax laws; and
•: force majeure events.

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

•: the level and timing of capital expenditures we make;
•: our debt service requirements and other liabilities;
•: fluctuations in our working capital needs;
•: our ability to borrow funds and access capital markets;
•: restrictions contained in debt agreements to which we are a party;
•: the amount of cash reserves established by our general partner and the amount of reimbursements to our general partner; and
•: the cost of acquisitions.

The amount of cash we need to pay the minimum quarterly distribution for four quarters on all of our units to be outstanding immediately after this offering is approximately $ million. The amount of cash available for distribution that we generated during the year ended December 31, 2014 and the twelve months ended March 31, 2015 on a pro forma basis would not have been sufficient to allow us to pay the full minimum quarterly distribution on all of our common units and subordinated units during that period. Please read "Cash Distribution Policy and Restrictions on Distributions" for

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the calculations of our cash available for distribution for those periods and for a description of additional restrictions and factors that may affect our ability to pay cash distributions.

We are a holding company with no independent operations or assets. Distributions to our unitholders are dependent on cash flow generated by our subsidiaries.

We are a holding company. All of our operations are conducted, and all of our assets are owned, by our direct and indirect subsidiaries. Consequently, our cash flow and our ability to meet our obligations or to pay cash distributions to our unitholders will depend upon the cash flows of our subsidiaries and the payment of funds by our subsidiaries to us in the form of dividends or otherwise. The ability of our subsidiaries to make any payments to us will depend on their earnings, the terms of their indebtedness and legal restrictions applicable to them. In particular, the terms of certain indebtedness of our subsidiaries may place significant limitations on the ability of our subsidiaries to pay dividends to us, and thus on our ability to pay distributions to our unitholders. Please read "Management's Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources." In the event that we do not receive distributions or dividends from our subsidiaries, we may be unable to make cash distributions to our unitholders.

The assumptions underlying our forecast of cash available for distribution included in "Cash Distribution Policy and Restrictions on Distributions" are inherently uncertain and subject to significant business, economic, financial, regulatory and competitive risks and uncertainties that could cause cash available for distribution to differ materially from our estimates.

Our forecast of cash available for distribution set forth in "Cash Distribution Policy and Restrictions on Distributions" has been prepared by management and we have not received an opinion or report on it from any independent registered public accountants. The assumptions underlying our forecast of cash available for distribution are inherently uncertain and are subject to significant business, economic, financial, regulatory and competitive risks and uncertainties that could cause cash available for distribution to differ materially from our estimates. If we do not achieve our forecasted results, we may not be able to pay the minimum quarterly distribution or any amount on our common units or subordinated units, in which event the market price of our common units may decline materially.

The amount of cash we have available for distribution to our unitholders depends primarily on our cash flow and not solely on profitability, which may prevent us from making cash distributions during periods when we report net income.

The amount of cash we have available for distribution depends primarily upon our cash flow, including cash flow from reserves and working capital or other borrowings, and not solely on profitability, which will be affected by non-cash items. As a result, we may pay cash distributions during periods when we report net losses for financial accounting purposes and may not pay cash distributions during periods when we report net income.

Our level of indebtedness and the terms of our borrowings could adversely affect our ability to grow our business, our ability to make cash distributions to our unitholders and our credit ratings and profile.

From and after the satisfaction of the Escrow Release Conditions, which we expect to occur concurrently with the closing of this offering, the partnership will become a co-issuer of $ million in aggregate principal amount of New Notes and a party to the indenture governing the New Notes. In connection with the closing of this offering we also expect to enter into a new $ million revolving credit facility. We expect to have $ million of borrowings outstanding under the revolving credit facility at the closing of this offering. In the future, we may also incur additional indebtedness. The operating and financial restrictions and covenants in our New Notes and our new

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revolving credit facility and any future financing agreements could restrict our ability to finance future operations or capital needs or to expand our operations or otherwise pursue our business activities. Our level of debt has important consequences to us, including the following:

•: we need a portion of our cash flow to service our indebtedness, reducing the funds that would otherwise be available for operations, future business opportunities and cash distributions;
•: the restrictions and covenants contained in the agreements governing our indebtedness may limit our ability to grant liens, borrow additional funds, engage in a merger, consolidation or dissolution, sell or otherwise dispose of assets, businesses and operations, make distributions to our unitholders, make acquisitions, investments and capital expenditures, enter into transactions with affiliates or materially alter the character of our business as conducted at the closing of this offering;
•: our debt covenants may also affect our flexibility in planning for, and reacting to, changes in the economy and in our industry;
•: a high level of debt may place us at a competitive disadvantage compared to our competitors that are less leveraged and therefore may be able to take advantage of opportunities that our indebtedness would prevent us from pursuing; and
•: a high level of debt may impair our ability to obtain additional financing, if necessary, for operating working capital, capital expenditures, acquisitions or other purposes, or such financing may not be available on favorable terms.

Our ability to comply with the covenants and restrictions contained in our New Notes and our new revolving credit facility and any future financing agreements may be affected by events beyond our control, including prevailing economic, financial and industry conditions. If market or other economic conditions deteriorate, our ability to comply with these covenants may be impaired. If our operating results are not sufficient to service our current or future indebtedness, we will be forced to take actions such as reducing distributions, reducing or delaying our business activities, acquisitions, investments or capital expenditures, selling assets, restructuring or refinancing our debt, or seeking additional equity capital. We may be unable to effect any of these actions on satisfactory terms, or at all.

If we violate any of the restrictions, covenants, ratios or tests in our New Notes or our new revolving credit facility, a significant portion of our indebtedness may become immediately due and payable, our lenders' commitment to make further loans to us may terminate, and we might not have, or be able to obtain, sufficient funds to make these accelerated payments. Any such violation could also prohibit us from making distributions to our unitholders. Any subsequent replacement of our revolving credit facility or any new indebtedness could have similar or greater restrictions. For more information regarding our New Notes or new revolving credit facility, please read "Management's Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Long-Term Debt."

Our access to credit and capital markets depends on the credit ratings assigned to our debt by independent credit rating agencies. A decrease in our credit ratings, for any reason including those discussed above, would increase our borrowing costs and adversely affect our ability to raise capital. In addition, we may not be able to obtain favorable credit terms from our suppliers, or they may require us to provide collateral, letters of credit, or other forms of security, which would increase our operating costs. As a result, a downgrade in our credit ratings could have a material adverse impact on our financial position, results of operations, and liquidity.

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Our sponsor's level of indebtedness and the terms of its borrowings could adversely affect our ability to grow our business, our ability to make cash distributions to our unitholders and our credit ratings and profile. Our ability to obtain credit in the future and our future credit rating may also be affected by our sponsor's level of indebtedness.

Our sponsor has a significant amount of debt. As of March 31, 2015, our sponsor had total debt of $439.0 million, substantially all of which is secured. In addition to its outstanding debt, as of March 31, 2015, our sponsor could have incurred an additional $16.0 million of senior secured indebtedness under its existing debt agreements. We expect that a portion of the net proceeds distributed to our sponsor in connection with this offering and our offering of the New Notes will be used by our sponsor to repay outstanding senior secured indebtedness under our sponsor's Senior Secured Credit Facilities (defined herein). Our sponsor's level of debt could increase its and our vulnerability to general adverse economic and industry conditions and require our sponsor to dedicate a substantial portion of its cash flow from operations to service its debt and lease obligations, thereby reducing the availability of its cash flow to fund its growth strategy, including capital expenditures, acquisitions and other business opportunities. Furthermore, a higher level of indebtedness at our sponsor increases the risk that it may default on its obligations, including under our new coal supply agreement with our sponsor. The covenants contained in the agreements governing our sponsor's outstanding and future indebtedness may limit its ability to borrow additional funds for development and make certain investments and may directly or indirectly impact our operations in a similar manner.

Our credit rating may be adversely affected by the leverage and credit profile of our sponsor, as credit rating agencies such as Standard & Poor's Ratings Services and Moody's Investors Service, Inc. may consider the leverage and credit profile of our sponsor and its affiliates because of their ownership interest in and control of us and because our new coal supply agreement with our sponsor will account for substantially all of our revenues. Any adverse effect on our credit rating would increase our cost of borrowing or hinder our ability to raise financing in the capital markets, which would impair our ability to grow our business and make cash distributions to our unitholders.

In the event our sponsor were to default under certain of its debt obligations, we could be materially adversely affected. We have no control over whether our sponsor remains in compliance with the provisions of its debt obligations, except as such provisions may otherwise directly pertain to us. Further, any debt instruments that our sponsor or any of its affiliates enter into in the future, including any amendments to existing credit facilities, may include additional or more restrictive limitations on our sponsor that may impact our ability to conduct our business. These additional restrictions could adversely affect our ability to finance our future operations or capital needs or engage in, expand or pursue our business activities.

A significant increase in interest rates could adversely affect our ability to service our indebtedness.

In connection with the closing of this offering, we expect to enter into a new revolving credit facility. We anticipate that borrowings under the revolving credit facility will bear interest at a variable rate per annum. Therefore, we expect to have exposure to movements in interest rates. A significant increase in interest rates could adversely affect our ability to service our indebtedness. The increased cost could make the financing of our business activities more expensive. These added expenses could have an adverse effect on our results of operations, financial condition and our ability to pay distributions to our unitholders.

Our ability to generate the significant amount of cash needed to service our debt and financial obligations and our ability to refinance all or a portion of our indebtedness or obtain additional financing depends on many factors beyond our control.

Our ability to make scheduled payments on or to refinance our debt obligations depends on our financial condition and operating performance, which is subject to prevailing economic and competitive conditions and to certain financial, business and other factors beyond our control. We may not be able to maintain a level of cash flows from operating activities sufficient to permit us to make payments on

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our indebtedness. If we are unable to fund our debt service obligations, it will have an adverse effect on our results of operations, business and financial condition, as well as our ability to pay distributions to our unitholders.

If our cash flows and capital resources are insufficient to fund our debt service obligations, we may be forced to reduce or delay investments and capital expenditures, or to sell assets, seek additional capital or restructure or refinance our indebtedness. Our ability to restructure or refinance our debt will depend on the condition of the capital markets and our financial condition at such time. Any refinancing of our debt could be at higher interest rates and may require us to comply with more onerous covenants, which could further restrict our business operations. The terms of our existing or future debt instruments may restrict us from adopting some of these alternatives. These alternative measures may not be successful and may not permit us to meet our scheduled debt service obligations.

Penalties, fines or sanctions for violations of environmental or mine safety laws could have a material adverse effect on our business, results of operations and cash available for distribution.

MSHA and state regulators continuously inspect underground mines like ours and those of our competitors, which often leads to the issuance of notices of violation. Recently, regulators have been conducting more frequent and more comprehensive inspections of all coal mines, including ours. These enforcement practices create a risk that our operations will be cited for violations, including violations that may lead to material fines, penalties or sanctions. Our mines are at risk of a temporary or extended shut down as a result of an alleged violation. None of our violations to date has had a material impact on our operations or financial condition, but future violations may have a material adverse impact on our business, result of operations or financial condition.

Because most of the coal in the vicinity of our mines is owned by the U.S. federal government, our future success and growth would be affected if we are unable to acquire or are significantly delayed in the acquisition of additional reserves through the federal competitive leasing process.

The U.S. federal government owns most of the coal in the vicinity of our mines. Accordingly, the federal competitive leasing process, which is administered by the BLM, is our primary means of acquiring additional reserves. In order to win a lease and acquire additional coal, our bid for a coal tract must meet or exceed the fair market value of the coal based on the internal estimates of the BLM, which are not published, and must also exceed any third-party bids. The BLM, however, is not required to grant a lease even if it determines that a bid meets or exceeds the fair market value estimate. Furthermore, there is no requirement that the BLM must give preference to any lease by application ("LBA") applicant which means our bids for federal coal leases may compete with other coal producers' bids. Over time, federal coal leases have become increasingly more competitive and expensive to obtain, and the review process to act on a lease for bid continues to lengthen. We expect this trend to continue. The increasing size of potential LBA tracts may make it easier for new mining operators to enter the market on economically viable terms and may, therefore, increase competition for federal coal leases.

In addition, increased opposition from non-governmental organizations and other third parties may also lengthen, delay or complicate the leasing process. Any failure or delay in acquiring a coal lease, or the inability to do so on economically viable terms, could cause our production to decline, and may adversely affect our business, cash flows and results of operations, perhaps materially. For example, in November 2014, two non-governmental organizations brought suit against the Secretary of the Interior and the BLM alleging that the BLM's coal leasing program is in violation of NEPA. Although the plaintiffs acknowledge that the BLM has generally complied with the requirements of NEPA with respect to individual coal leases, they assert that that the agency's failure to update its 1979 analysis of environmental impacts associated with the broader BLM federal coal management program to include the impacts of GHGs constitutes a violation of NEPA. The plaintiffs are seeking a variety of relief, including an injunction that would, if their efforts are successful, prevent the issuance of new coal leases or modifications until the BLM has satisfied the requirements of NEPA. Please read "—Risks

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Related to Environmental, Health, Safety and Other Regulations" for more details regarding risks associated with our compliance with NEPA during the BLM federal leasing process. Further, certain non-governmental organizations have filed comments with the BLM and U.S. Forest Service regarding the BLM's decision to offer the Greens Hollow tract for lease, and have further filed an objection with the U.S. Forest Service objecting to that agency's Draft Record of Decision proposing to consent to the BLM's issuance of the Greens Hollow lease. Further, the leasing action related to the Flat Canyon tract by the BLM could also be challenged in the Department of Interior's Board of Land Appeals or in federal district court. The May 15, 2015 Notice of Lease Sale of the Flat Canyon tract prompted letters by several non-governmental organizations objecting to the lease sale on, among other things, environmental grounds. Such third-party challenges filed against the BLM and the U.S. Forest Service by environmental groups with respect to the LBA process generally, or in the Uinta Basin more specifically, may result in delays and other adverse impacts on the LBA process. Please read "Business—Coal Reserves and Non-Reserve Coal Deposits—Reserve Acquisition Process."

The leasing process also requires us to acquire rights to mine from certain surface owners overlying the coal before the federal government will agree to lease the coal. Surface rights are becoming increasingly more difficult and costly to acquire. Certain federal regulations provide a specific class of surface owners, also known as qualified surface owners ("QSOs"), with the ability to prohibit the BLM from leasing its coal. If a QSO owns the land overlying a coal tract, federal laws prohibit us from leasing the coal tract without first securing surface rights to the land, or purchasing the surface rights from the QSO. This right of QSOs allows them to exercise significant influence over negotiations to acquire surface rights and can delay the leasing process or ultimately prevent the acquisition of coal underlying their surface rights. If we are unable to successfully negotiate access rights with QSOs at a price and on terms acceptable to us, we may be unable to acquire federal coal leases on land owned by the QSO. Our profitability could be adversely affected, perhaps materially, if the prices to acquire land owned by QSOs increase.

Our future success depends upon our ability to obtain and maintain permits, rights and approvals necessary to mine all of our coal reserves.

In order to economically develop our reserves, we must obtain, maintain or renew various governmental permits, rights and approvals, including, as applicable, water rights. We make no assurances that we will be able to obtain, maintain or renew any of the governmental permits, rights or approvals that we need to continue developing our proven and probable coal reserves. The inability to conduct mining operations or obtain, maintain or renew permits, rights or approvals may have a material adverse effect on our results of operations, business and financial position, as well as the ability to pay distributions to our unitholders.

A substantial or extended decline in coal prices or increase in the costs of mining or transporting coal could have a material adverse effect on our results of operations and our ability to pay distributions to our unitholders.

Our results of operations depend, in part, on the margins that we receive on sales of our coal. Our margins reflect the price we receive for our coal over our cost of producing and transporting our coal and are impacted by many factors, including:

•: the market price for coal;
•: the amount of coal we are able to produce from our properties, which could be adversely affected by, among other things, operating difficulties and unfavorable geologic conditions;
•: the supply of, and demand for, domestic and foreign coal;
•: competition from other coal suppliers;
•: advances in power technologies;
•: the efficiency of our mines;

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•: the pricing terms contained in our long-term contracts;
•: cancellation or renegotiation of contracts;
•: legislative, regulatory and judicial developments, including those related to the release of GHGs;
•: the cost of using, and the availability of, other fuels, including the effects of technological developments;
•: air emission, wastewater discharge and other environmental standards for coal-fired power plants and technologies developed to help meet these standards;
•: delays in the receipt of, or failure to maintain, or revocation of necessary government permits;
•: delays in the receipt of, or failure to maintain, or termination of necessary coal mining leases;
•: inclement or hazardous weather conditions and natural disasters, such as heavy rain, high winds and flooding;
•: the availability and cost or interruption of fuel, equipment and other supplies;
•: transportation costs and availability of transportation;
•: the availability of transportation infrastructure, including flooding and railroad derailments;
•: the availability of skilled employees; and
•: work stoppages or other labor difficulties.

Substantial or extended declines in the price that we receive for our coal or increases in the costs of mining or transporting our coal could have a material adverse effect on our results of operations and our ability to generate the cash flows we require to invest in our operations, satisfy our obligations and pay distributions to our unitholders.

We may not be able to obtain equipment, parts and raw materials in a timely manner, in sufficient quantities or at reasonable costs to support our coal mining and transportation operations.

We use equipment in our coal mining and transportation operations such as continuous miners, conveyors, shuttle cars, rail cars, locomotives, roof bolters, shearers and shields. We procure this equipment from a concentrated group of suppliers, and obtaining this equipment often involves long lead times. Occasionally, demand for such equipment by mining companies can be high and some types of equipment may be in short supply. Delays in receiving or shortages of this equipment, as well as the raw materials used in the manufacturing of supplies and mining equipment, which, in some cases, do not have ready substitutes, or the cancellation of our supply contracts under which we obtain equipment and other consumables, could limit our ability to obtain these supplies or equipment. In addition, if any of our suppliers experiences an adverse event, or decides to no longer do business with us, we may be unable to obtain sufficient equipment and raw materials in a timely manner or at a reasonable price to allow us to meet our production goals and our revenues may be adversely impacted. We use considerable quantities of steel, diesel fuel, explosives and other raw materials in the mining process. If the price of steel, diesel fuel, explosives or other raw materials increases substantially or if the value of the U.S. dollar declines relative to foreign currencies with respect to certain imported supplies or other products, our operating expenses could increase. Any of the foregoing events could materially adversely impact our results of operations, business and financial condition as well as our profitability and our ability to pay distributions to our unitholders.

Our business requires substantial capital expenditures, and we may not have access to the capital required to maintain full productive capacity at our mines.

Maintaining and expanding mines and infrastructure is capital intensive. Specifically, the exploration, permitting and development of coal reserves, mining costs, the maintenance of machinery and equipment and compliance with applicable laws and regulations require substantial capital expenditures. While a significant amount of the capital expenditures required to build-out our mines has been spent, we must continue to invest capital to maintain or to increase our production. Decisions

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to increase our production levels could also affect our capital needs. We cannot assure you that we will be able to maintain our production levels or generate sufficient cash flow, or that we will have access to sufficient financing to continue our production, exploration, permitting and development activities at or above our present levels, and we may be required to defer all or a portion of our capital expenditures. Our results of operations, business and financial condition, as well as our ability to pay distributions to our unitholders may be materially adversely affected if we cannot make such capital expenditures.

Major equipment and plant failures could reduce our ability to produce and ship coal and materially adversely affect our results of operations.

We depend on several major pieces of mining equipment and preparation plants to produce and ship our coal, including longwall mining systems, preparation plants, and transloading and loadout facilities. If any of these pieces of equipment or facilities suffered major damage or were destroyed by fire, abnormal wear, flooding, incorrect operation, or otherwise, we may be unable to replace or repair them in a timely manner or at a reasonable cost which would impact our ability to produce and ship coal and materially adversely affect our results of operations, business and financial condition and our ability to pay distributions to our unitholders.

The amount of estimated maintenance capital expenditures our general partner is required to deduct from operating surplus each quarter could increase in the future, resulting in a decrease in available cash from operating surplus that could be distributed to our unitholders.

Our partnership agreement requires our general partner to deduct from operating surplus each quarter estimated maintenance capital expenditures as opposed to actual maintenance capital expenditures in order to reduce disparities in operating surplus caused by fluctuating maintenance capital expenditures, such as reserve replacement costs or refurbishment or replacement of mine equipment. Our initial annual estimated maintenance capital expenditures for purposes of calculating operating surplus will be approximately $ million for the twelve months ending June 30, 2016. This amount is based on our current estimates of the amounts of cash expenditures we will be required to make in the future to maintain our long-term operating capacity or net income, which we believe to be reasonable. Our partnership agreement does not cap the amount of maintenance capital expenditures that our general partner may estimate. This amount has been taken into consideration in calculating our forecasted cash available for distribution in "Cash Distribution Policy and Restrictions on Distributions." The initial amount of our estimated maintenance capital expenditures may be more than our initial actual maintenance capital expenditures, which will reduce the amount of available cash from operating surplus that we would otherwise have available for distribution to our unitholders. The amount of estimated maintenance capital expenditures deducted from operating surplus is subject to review and change by the board of directors of our general partner at least once a year, with any change approved by the conflicts committee. In addition to estimated maintenance capital expenditures, reimbursement of expenses incurred by our general partner and its affiliates will reduce the amount of available cash from operating surplus that we would otherwise have available for distribution to our unitholders. Please read "—We may not have sufficient cash from operations to pay the minimum quarterly distribution on our common and subordinated units following establishment of cash reserves and payment of costs and expenses, including reimbursement of expenses to our general partner."

We face numerous uncertainties in estimating our economically recoverable coal reserves.

Coal is economically recoverable when the price at which coal can be sold exceeds the costs and expenses of mining and selling the coal. Forecasts of our future performance are based on, among other things, estimates of our recoverable coal reserves. We base our reserve information on engineering, economic and geological data assembled and analyzed by third parties and our staff, which includes various engineers and geologists. The reserve estimates as to both quantity and quality are updated from time to time to reflect production of coal from the reserves and new drilling or other data received. There are numerous uncertainties inherent in estimating quantities and qualities of coal

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and costs to mine recoverable reserves, including many factors beyond our control. Estimates of economically recoverable coal reserves necessarily depend upon a number of variable factors and assumptions, any one of which may, if inaccurate, result in an estimate that varies considerably from actual results. These factors and assumptions include:

•: the possible necessity of revising a mining plan;
•: geologic and mining conditions, which may not be fully identified by available exploration data and may differ from our experience in areas we currently mine;
•: market conditions, including contracted pricing, market pricing and overall demand for our coal;
•: future coal prices, operating costs and capital expenditures;
•: severance and excise taxes, royalties and development and reclamation costs;
•: future mining technology improvements;
•: the effects of regulation by governmental agencies;
•: ability to obtain, maintain and renew all required permits and coal mining leases;
•: employee health and safety needs; and
•: historical production from the area compared with production from other producing areas.

As a result, actual coal tonnage recovered from identified reserve areas or properties and revenues and expenditures with respect to our production from reserves may vary materially from estimates. These estimates thus may not accurately reflect our actual reserves. Any material inaccuracy in our estimates related to our reserves could result in lower than expected revenues, higher than expected costs or decreased profitability which could materially adversely affect our results of operations, business and financial condition as well as our ability to pay distributions to our unitholders.

Failure to meet certain provisions in our coal supply agreements could result in economic penalties.

Most of our coal supply agreements contain provisions requiring delivery of coal within certain ranges for specified coal characteristics such as heat content, sulfur, ash, grindability, chlorine and ash fusion temperature. Failure to meet these conditions could result in economic penalties, purchasing replacement coal in a higher priced open market, rejection of deliveries or termination of the agreements, at the election of the customer. If we are subject to economic penalties under the terms of our coal supply agreements, or if we are required to purchase replacement coal in the open market, our results of operations may be adversely affected, which could adversely affect our ability to make distributions to our unitholders.

Our coal supply agreements include price reset and other provisions that could result in lower contract prices.

Price adjustment, "price reset" and other similar provisions in our coal supply agreements may reduce the protection from short-term coal price volatility traditionally provided by such agreements. Price reset provisions are present in our coal supply agreements with IPA and PacifiCorp's Hunter Power Plant. Price reset provisions typically require the parties to agree on a new price. Failure of the parties to agree on a price under a price reset provision can lead to termination of the agreement or an automatic resetting of the price based on an agreed-upon formula. Certain of our price reset provisions are based on the applicable inflation rate, while others are based on a weighted average formula that takes into account a base price, the price of coal sold by us in prior periods and certain index pricing. If the rate of inflation is lower than expected, or if market prices are lower than the existing contract price, as applicable, pricing for these agreements could reset to lower levels.

Most of our coal supply agreements also contain provisions that permit the parties to adjust the contract price upward or downward for specific events, including changes in the laws or changes in the interpretation of laws that affect our costs related to performance of the agreements. These agreements also typically contain force majeure provisions allowing for the suspension of performance by the parties for the duration of specified events beyond the control of the affected party. Additionally, some

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agreements may terminate upon continuance of an event of force majeure for an extended period. Any adjustment or renegotiations following such a termination and leading to a significantly lower contract price could adversely affect our results of operations and cash available for distribution to our unitholders.

Substantially all of our coal supply agreements are forward sales agreements. If the production costs underlying these agreements increase, our results of operations could be materially adversely affected.

Substantially all of our coal supply agreements are forward sales agreements under which customers agree to pay a specified price for coal to be delivered in future years. The profitability of these agreements depends on our ability to adequately control the costs of the coal production underlying the agreements. These production costs are subject to variability due to a number of factors, including increases in the cost of labor, supplies or other raw materials. To the extent our costs increase but pricing under these coal supply agreements remains fixed, we will be unable to pass increasing costs on to our customers. If we are unable to control our costs, our profitability under our forward sales agreements may be impaired and our results of operations, business and financial condition, and our ability to make distributions to our unitholders could be materially adversely affected.

A decrease in the use of coal by electric utilities could affect our ability to sell the coal we produce.

According to the World Coal Association, in 2013 coal was used to generate over 40% of the world's electricity needs. According to the EIA, in the United States, the domestic electricity generation industry accounts for approximately 93% of domestic thermal coal consumption. The use of coal as a fuel source, represented as a percentage of total U.S. electricity production, has declined to 38.7% in 2014 from 44.8% in 2010. The amount of coal consumed by the electric generation industry is affected primarily by the overall demand for electricity, environmental and other governmental regulations, as well as the price and availability of renewable energy sources, including biomass, hydroelectric, wind and solar power and other non-renewable fuel sources, including natural gas and nuclear power. For example, the relatively recent low price of natural gas has resulted, in some instances, in domestic generators increasing natural gas consumption while decreasing coal consumption. Moreover, on June 2, 2014, the EPA proposed new regulations limiting carbon dioxide emissions from existing power generation facilities. This or other future environmental regulation of GHG emissions could accelerate the use by utilities of fuels other than coal. Domestically, state and federal mandates for increased use of electricity derived from renewable energy sources could affect demand for our coal. A number of states have enacted mandates that require electricity suppliers to rely on renewable energy sources to generate a certain percentage of their 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. Moreover, a wide range of recent regulatory developments, such as the MATS and CWA cooling water intake regulations, may make coal burning more expensive or less attractive for electric utilities and may lead to the closure of a number of coal-fired power plants. Other similar initiatives, such as potential revisions to the ozone NAAQSs or the EPA's proposed carbon pollution standard for new power plants, are still pending, but may have similar effects in the future. A decrease in coal consumption by the electric generation industry could adversely affect the price of coal, which could negatively affect our results of operations, business and financial condition, as well as our ability to pay distributions to our unitholders.

All of our revenue and cash flow will be derived from our coal supply agreements, and we will receive substantially all of our revenue and cash flow from our new coal supply agreement with our sponsor. As we expect to derive substantially all of our revenues through our sponsor for the foreseeable future, we will be subject to the risk of nonpayment or nonperformance by our sponsor under our coal supply agreement. Any event, whether related to our operations or otherwise, that

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materially adversely affects our sponsor's financial condition, results of operations or cash flows may adversely affect our ability to sustain or increase cash distributions to our unitholders. Please read "—Our sponsor's level of indebtedness and the terms of its borrowings could adversely affect our ability to grow our business, our ability to make cash distributions to our unitholders and our credit ratings and profile. Our ability to obtain credit in the future and our future credit rating may also be affected by our sponsor's level of indebtedness."

Our sponsor is a privately owned company that does not disclose financial or operating results to the public, limiting the ability of our unitholders to assess the performance or financial outlook of our primary coal sales counterparty.

Our sponsor is a privately owned company and has no obligations to disclose publicly financial or operating information. Accordingly, our unitholders will have little to no insight into our sponsor's ability to meet its obligations to us and to our customers, including its coal purchase commitments under our new coal supply agreement with our sponsor. Our ability to make minimum quarterly distributions on all outstanding units will be adversely affected if: (i) our sponsor does not fulfill its obligations to us or our customers; or (ii) our sponsor's obligations under our new coal supply agreement are suspended, reduced or terminated and we are unable to generate additional revenues from third parties.

Our commercial agreements with our sponsor and Trafigura AG contain provisions that allow the counterparty to such agreement to suspend, reduce or terminate its obligations in certain circumstances including force majeure, which would have a material adverse effect on our results of operations, business, financial condition, and our ability to pay distributions to our unitholders.

We market and sell substantially all of our coal through our sponsor and Trafigura AG. A significant portion of our coal is sold under long-term coal supply agreements with our sponsor, which it sells to PacifiCorp and IPA. In addition, we sell coal to our sponsor that it exports through the U.S. West Coast terminals it leases. Our access to international markets is dependent on our relationship with our sponsor, as the lessee of the U.S. West Coast terminals, and Trafigura AG, as the exclusive marketer of our uncommitted coal. Each of our commercial agreements with our sponsor and Trafigura AG provides that our sponsor or Trafigura AG, as applicable, may suspend, reduce or terminate its obligations to us, if certain events occur. Additionally, Trafigura AG has the right to terminate its marketing arrangements with us at any time upon 180 days' notice. Any reduction, suspension or termination of any of our commercial agreements with our sponsor or Trafigura AG would have a material adverse effect on our results of operations, business and financial condition and our ability to pay distributions to our unitholders.

If Galena sells its interest in our sponsor, Trafigura AG will no longer be our affiliate, which could jeopardize our relationship with Trafigura AG.

Trafigura BV owns Galena Asset Management, which manages Galena, and also owns Trafigura AG, which is the exclusive marketer of our uncommitted coal. Galena owns a 46% interest in our sponsor. If Galena sells its interest in our sponsor, Trafigura AG will no longer be an affiliate of us or our sponsor, and Trafigura AG may decide to terminate its agreements with us. Any termination of our commercial agreements with Trafigura AG could have a material adverse effect on our results of operations, business condition and our ability to pay distributions to our unitholders.

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Certain of our customers may seek to defer contracted shipments of coal pursuant to the terms of our coal supply agreements or otherwise refuse to accept shipments of our coal, which could affect our results of operations and liquidity.

Our long-term coal supply agreements typically permit the parties to vary the timing of delivery within specified limits. From time to time, certain customers have sought and others may seek to delay shipments or request deferrals under existing agreements. There is no assurance that we will be able to resolve existing and potential deferrals on favorable terms, or at all. In addition, if our customers refuse to accept shipments of our coal for which they have an existing contractual obligation, our revenues may decrease until our customers' contractual obligations are honored. Any such delays, deferrals or refusals may have an adverse effect on our business, results of operations and financial condition, as well as our ability to pay distributions to our unitholders.

Our coal supply agreements do not provide for minimum coal sales on a quarterly basis and our coal sales may fluctuate from quarter to quarter.

Substantially all of our coal supply agreements have minimum annual purchase requirements, rather than minimum quarterly purchase requirements. Although the volume to be delivered under our coal supply agreements is stipulated, the parties may vary the timing of delivery within specified limits. Therefore, our revenues could be lower than projected on a quarterly basis, which could affect our ability to pay distributions to our unitholders.

Our ability to collect payments from our customers could be impaired if their creditworthiness deteriorates.

Our ability to receive payment for coal sold and delivered depends on the continued creditworthiness of our customers. Many utilities have sold their power plants to non-regulated affiliates or third parties that may be less creditworthy, thereby increasing the risk we bear on payment default. These new power plant owners may have credit ratings that are below investment grade. In addition, some of our customers have been adversely affected by the current economic downturn, which may impact their ability to fulfill their contractual obligations. Competition with other coal suppliers could force us to extend credit to customers and on terms that could increase the risk we bear on payment default. An inability to collect payment from these counterparties may materially adversely affect our results of operations, business and financial condition, as well as our ability to pay distributions to our unitholders.

The loss of, or significant reduction in, purchases by our largest customers could adversely affect our results of operations.

For the years ended December 31, 2014 and 2013, we derived approximately 24% and 26%, respectively, of our total coal revenues from sales of coal to PacifiCorp. For the years ended December 31, 2014 and 2013, we derived approximately 29% of our total coal revenues from sales of coal to IPA. If any of our top customers, especially PacifiCorp or IPA, were to significantly reduce their purchases of our coal, or if we were unable to sell coal to such customers on terms as favorable to us as the terms under our current coal supply agreements, our results of operations, business and financial condition, as well as our ability to pay distributions to our unitholders may be materially adversely affected. Additionally, our long-term contract for PacifiCorp's Hunter Power Plant is set to expire in 2020. Should we be unable to successfully renew such contract or any other contract with PacifiCorp or IPA upon its expiration, the reduction in the sale of our coal would adversely affect our results of operations, business and financial condition.

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Our operations are subject to risks, some of which are not insurable, and we cannot assure you that our existing insurance would be adequate in the event of a loss.

Insurance against certain risks, including certain liabilities for environmental pollution or hazards, may not be generally available to us or other companies within the mining industry. We cannot assure you that insurance coverage will be available in the future at commercially reasonable costs, or at all, or that the amounts for which we are insured or that we may receive, or the timing of any such receipt, will be adequate to cover all of our losses. Uninsured events may adversely affect our results of operations, business and financial condition, as well as our ability to pay distributions to our unitholders.

The geographic concentration of our mines creates a significant exposure to the risk of the local economy and other local adverse conditions.

All of our mining operations are located in the Uinta Basin in Utah and are therefore vulnerable to economic downturns in that region, as well as other factors, including adverse weather conditions. These mines are located within a relatively limited geographic area and 74% of our tons sold for the year ended December 31, 2014 were marketed in Utah, Nevada and California. As a result, we are more susceptible to regional conditions than the operations of more geographically diversified competitors and any unforeseen events or circumstances that affect the area could also materially adversely affect our results of operations. These factors include, among other things, changes in the economy, damages to infrastructure, weather conditions, demographics and population.

We have future mine closure and reclamation obligations, the timing of and amount for which are uncertain. In addition, our failure to maintain required financial assurances could affect our ability to secure reclamation and coal lease obligations, which could adversely affect our ability to mine or lease coal.

In view of the uncertainties concerning future mine closure and reclamation costs on our properties, the ultimate timing and future costs of these obligations could differ materially from our current estimates. We estimate our asset retirement liabilities for final reclamation and mine closure based upon detailed engineering calculations of the amount and timing of the future cash for a third party to perform the required work. Spending estimates are escalated for inflation and market risk premium, and then discounted at the credit-adjusted, risk-free rate. As of March 31, 2015, we had recorded total asset retirement obligations on our consolidated balance sheet of approximately $9.4 million. Our estimates for this future liability are subject to change based on new or amendments to existing applicable laws and regulation, the nature of ongoing operations and technological innovations. Although we accrue for future costs on our consolidated balance sheet, we do not reserve cash in respect of these obligations or otherwise fund these obligations in advance. As a result, we will have significant cash costs when we are required to close and restore mine sites that may, among other things, affect our ability to satisfy our obligations under our indebtedness and other contractual commitments and pay distributions to our unitholders. We cannot assure you that we will be able to obtain financing on satisfactory terms to fund these costs, or at all.

In addition, regulatory authorities require us to provide financial assurance to secure, in whole or in part, our future reclamation projects. The amount and nature of the financial assurances are dependent upon a number of factors, including our financial condition and reclamation cost estimates. Changes to these amounts, as well as the nature of the collateral to be provided, could significantly increase our costs, making the maintenance and development of existing and new mines less economically feasible. Currently, the security we provide consists of surety bonds. The premium rates and terms of the surety bonds are subject to annual renewals. Our failure to maintain, or inability to acquire, surety bonds or other forms of financial assurance that are required by applicable law, contract or permit could adversely affect our ability to operate. That failure could result from a variety of factors including the lack of availability, higher expense or unfavorable market terms of new surety

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bonds or other forms of financial assurance. There can be no guarantee that we will be able to maintain or add to our current level of financial assurance. Additionally, any capital resources that we do utilize for this purpose will reduce our resources available for our operations and commitments as well as our ability to pay distributions to our unitholders.

Defects in title or loss of any leasehold interests in our properties could limit our ability to conduct mining operations on these properties or result in significant unanticipated costs.

Substantially all of our coal reserves are leased from various landowners. Our main lessor is the U.S. government, from which we lease coal under terms set by Congress and administered by the BLM. The remainder of our coal reserves are leased from the State of Utah, land holding companies and various individuals. A title defect or the loss of any lease upon expiration of its term, upon a default or otherwise, could adversely affect our ability to mine the associated reserves or process the coal that we mine. Title to our owned or leased properties and mineral rights is not usually verified unless we are required by our lenders to obtain title policies or title opinions. In some cases, we rely on title information or representations and warranties provided by our lessors or grantors. Our right to mine certain of our reserves has in the past been, and may again in the future be, adversely affected if defects in title, boundaries or other rights necessary for mining exist or if a lease expires. Any challenge to our title or leasehold interests could delay the mining of the property and could ultimately result in the loss of some or all of our interest in the property. From time to time we also may be in default with respect to leases for properties on which we have mining operations. In such events, we may have to close down or significantly alter the sequence of such mining operations which may adversely affect our future coal production and future revenues. If we mine on property that we do not own or lease, we could incur liability for such mining and be subject to regulatory sanction and penalties.

In order to obtain, maintain or renew leases to conduct our mining operations on property where these defects exist, we may in the future have to incur unanticipated costs. Some leases have minimum production requirements. In addition, we may not be able to successfully negotiate new leases for properties containing additional reserves, or maintain our leasehold interests in properties where we have not commenced mining operations during the term of the lease. If any of our leases are terminated, for lack of diligent development or otherwise, we would be unable to mine the affected coal. As a result, our results of operations, business and financial condition, as well as our ability to pay distributions to our unitholders may be materially adversely affected.

The imposition of new taxes on the coal we produce could materially adversely affect our results of operations.

All of our operations are in Utah. Utah's state severance tax does not currently apply to coal production. If Utah were to impose its state severance tax on coal, or if Utah were to impose any other new tax on coal or otherwise on our Utah operations, we may be significantly impacted and our results of operations, business and financial condition, as well as the ability to pay distributions to our unitholders could be materially adversely affected. Any such imposition of a Utah state severance tax or any other tax could disproportionately impact us relative to our competitors that are more geographically diverse.

A shortage of skilled mining labor in the United States could decrease our labor productivity and increase our labor costs, which would adversely affect our profitability.

Efficient coal mining using complex and sophisticated techniques and equipment requires skilled laborers proficient in multiple mining tasks, including mining equipment maintenance. Any shortage of skilled mining labor reduces the productivity of experienced employees who must assist in training unskilled employees. If a shortage of experienced labor occurs, it could have an adverse impact on our labor productivity and costs and on our ability to expand production in the event there is an increase in

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the demand for our coal, which could adversely affect our results of operations, business and financial condition, as well as our ability to pay distributions to our unitholders.

Our work force could become unionized in the future, which could negatively impact the stability of our production, materially reduce our profitability and increase the risk of work stoppages.

All of our mines are operated by non-union employees. Our employees have the right at any time under the National Labor Relations Act to form or affiliate with a union, and unions may conduct organizing activities in this regard. If our employees choose to form or affiliate with a union and the terms of a union collective bargaining agreement are significantly different from our current compensation and job assignment arrangements with our employees, these arrangements could negatively impact the stability of our production, materially reduce our profitability and increase the risk of work stoppages. In addition, even if our managed operations remain non-union, our business may still be adversely affected by work stoppages at our unionized transportation and service providers. For example, the recent labor dispute between the Pacific Maritime Association and the International Longshore and Warehouse Union disrupted vessel loadings at one of the U.S. West Coast export terminals leased by our sponsor.

Our ability to operate our business effectively could be impaired if we fail to attract and retain key personnel.

Our ability to operate our business and implement our strategies depends, in part, on the continued contributions of our executive officers and other key employees. The loss of any of our key senior executives could have a material adverse effect on our business unless and until we find a replacement. A limited number of persons exist with the requisite experience and skills to serve in our senior management positions. We may not be able to locate or employ qualified executives on acceptable terms. In addition, we believe that our future success will depend on our continued ability to attract and retain highly skilled personnel with coal industry experience. Competition for these persons in the coal industry is intense and we may not be able to successfully recruit, train or retain qualified managerial personnel. As a public company, our future success also will depend on our ability to hire and retain management with public company experience. We may not be able to continue to employ key personnel or attract and retain qualified personnel in the future. Our failure to retain or attract key personnel could have a material adverse effect on our ability to effectively operate our business.

Coal mining operations are subject to inherent risks and are dependent on many factors and conditions beyond our control, any of which may adversely affect our productivity and our financial condition.

Our mining operations, including our transportation infrastructure, are influenced by changing conditions that can affect the safety of our workforce, production levels, delivery of our coal and costs for varying lengths of time and, as a result, can diminish our revenues and profitability. In particular, underground mining and related processing activities present inherent risks of injury to persons and damage to property and equipment. A shutdown of any of our mines or prolonged disruption of production at any of our mines or transportation of our coal to customers would result in a decrease in our revenues and profitability, which could be material. Certain factors affecting the production and sale of our coal that could result in decreases in our revenues and profitability include:

•: adverse geologic conditions including floor and roof conditions, variations in seam height, washouts and faults;
•: fire or explosions from methane, coal or coal dust or explosive materials;
•: industrial accidents;
•: seismic activities, ground failures, rock bursts or structural cave-ins or slides;
•: delays in the receipt of, or failure to maintain, or revocation of necessary government permits;

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•: delays in the receipt of, or failure to maintain, or termination of necessary coal mining leases;
•: changes in the manner of enforcement of existing laws and regulations;
•: changes in laws or regulations, including permitting requirements and the imposition of additional regulations, taxes or fees;
•: accidental or unexpected mine water inflows;
•: delays in moving our longwall equipment;
•: railroad derailments;
•: inclement or hazardous weather conditions and natural disasters, such as heavy rain or snow, high winds and flooding;
•: environmental hazards;
•: interruption or loss of power, fuel, or parts;
•: increased or unexpected reclamation costs;
•: equipment availability, replacement or repair costs; and
•: mining and processing equipment failures and unexpected maintenance problems.

These risks, conditions and events (1) could result in: (a) damage to, or destruction of value of, our coal properties, our coal production or transportation facilities, (b) personal injury or death, (c) environmental damage to our properties or the properties of others, (d) delays or prohibitions on mining our coal or in the transportation of coal, (e) monetary losses and (f) potential legal liability; and (2) could have a material adverse effect on our results of operations and our ability to generate the cash flows we require to invest in our operations and satisfy our debt obligations. Our insurance policies only provide limited coverage for some of these risks and will not fully cover these risks. A significant mine accident could potentially cause a mine shutdown, and could have a substantial adverse impact on our results of operations, financial condition or cash flows. These risks, conditions or events have had, and can be expected in the future to have, a significant adverse impact on our business and results of operations, as well as our ability to pay distributions to our unitholders.

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

We compete with other producers primarily on the basis of price, coal quality, transportation cost and reliability of supply. We cannot assure you that competition from other producers will not adversely affect us in the future. The coal industry has experienced consolidation in recent years, including consolidation among some of our major competitors. As a result, a substantial portion of coal production is from companies that have significantly greater resources than we do. We cannot assure you that the result of current or further consolidation in the industry will not adversely affect us.

In addition, potential changes to international trade agreements, trade concessions or other political and economic arrangements may benefit coal producers operating in countries other than the United States, where our mining operations are currently located. We cannot assure you that we will be able to compete on the basis of price or other factors with companies that in the future may benefit from favorable trading or other arrangements. We compete directly for U.S. and international coal sales with numerous other coal producers located in the United States and internationally, in countries such as Mexico, Japan, China, Australia, Canada, India, South Africa, Indonesia, Russia and Colombia. The price of coal in the markets into which we sell our coal is also influenced by the price of coal in the markets in which we do not sell our coal because significant oversupply of coal from other markets could materially reduce the prices we receive for our coal. Increases in coal prices could encourage the

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development of expanded capacity by new or existing coal producers, which could result in lower coal prices. In addition, coal is sold internationally in U.S. dollars and, as a result, general economic conditions in foreign markets and changes in foreign currency exchange rates may provide foreign producers of coal with a competitive advantage. If our competitors' currencies decline against the U.S. dollar or against our foreign customers' local currencies, those competitors may be able to offer lower prices for coal. Furthermore, if the currencies of our overseas customers were to significantly decline in value in comparison to the U.S. dollar, those customers may seek decreased prices for the coal we sell to them. As a result, our results of operations, business and financial condition, as well as our ability to pay distributions to our unitholders may be materially adversely affected.

The availability or reliability of current transportation facilities or disruptions in transportation services could affect the demand for our coal or temporarily impair our ability to supply coal to our customers. In addition, our inability to expand our transportation capabilities and options could further impair our ability to deliver coal efficiently to our customers.

We depend upon rail, truck, ocean-going vessels and port facilities to deliver coal to customers. Disruption of these transportation services because of weather-related problems, infrastructure damage, strikes, lock-outs, lack of fuel or maintenance items, transportation delays, lack of rail or port capacity or other events could temporarily impair our ability to supply coal to customers and thus could adversely affect our results of operations, cash flows and financial condition, as well as our ability to pay distributions to our unitholders.

Currently, we are required to utilize Savage Services Corporation ("Savage") to transport all of our coal from our Dugout Canyon mine. If there are significant disruptions in the services provided by Savage, or if we are unable to renew our agreement with Savage at favorable rates, then costs of transportation for coal produced at our Dugout Canyon mine could increase substantially until we arrange alternative transportation services for our Dugout Canyon mine. Additionally, we utilize the Union Pacific railroad for all of our rail shipments, and utilize the Port of Stockton, California, the Levin-Richmond Terminal in Richmond, California (the "Levin-Richmond Terminal"), and the Port of Long Beach, California for all of our exports. If there are disruptions of the transportation or transloading services provided by the relevant trucking company, railroad or port and we are unable to find alternative providers to enable us to deliver coal to our customers, our business and profitability could be adversely affected. While we currently have contracts in place for transportation and transloading of our coal and have continued to develop alternative options, there is no assurance that we will be able to renew these contracts or to develop these alternative options on terms that remain favorable to us. Any failure to do so could have a material adverse impact on our financial position and results of operations as well as our ability to pay distributions to our unitholders.

If our terminal agreements expire or are terminated, it may adversely affect our international coal sales and profitability.

Through our sponsor, we have access to throughput capacity of approximately 4.0 million tons per year at the Port of Stockton, California and approximately 1.7 million tons per year at the Levin-Richmond Terminal. The terminal contract between our sponsor and Metropolitan Stevedore Company with respect to the Port of Stockton expires on December 31, 2019, and the terminal contract between our sponsor and Levin-Richmond Terminal Corp. expires on December 31, 2015. Each agreement may also be terminated by either party upon the occurrence of certain customary events of default. If either one or both of these agreements expire and are not renewed or are otherwise terminated, it may adversely affect our international coal sales and profitability.

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Significant increases in transportation costs could make our coal less competitive when compared to other fuels or coal produced from other regions.

Transportation costs represent a significant portion of the total cost of coal for our customers and the cost of transportation is an important factor in a customer's purchasing decision. Increases in transportation costs, including increases resulting from emission control requirements and fluctuations in the price of diesel fuel and demurrage, could make coal a less competitive source of energy when compared to other fuels such as natural gas or could make our coal less competitive than coal produced in other regions of the United States or abroad. We depend upon the Union Pacific railroad to transport our coal to domestic customers and export terminal facilities. Reductions in service by the Union Pacific railroad or increases in railroad rates would increase our operating costs. Significant decreases in transportation costs, including lower rail rates, could result in increased competition from coal producers in other parts of the country and from abroad, including coal imported into the United States. Increased competition due to changing transportation costs, or alternatively higher rail rates, could have an adverse effect on our results of operations, business and financial condition, as well as our ability to pay distributions to our unitholders.

Our ability to mine and ship coal may be affected by adverse weather conditions, which could have an adverse effect on our revenues.

Adverse weather conditions can impact our ability to mine and ship our coal and our customers' ability to take delivery of our coal. Lower than expected shipments by us during any period could have an adverse effect on our revenues. In addition, severe weather may affect our ability to conduct our mining operations and severe rain, ice or snowfall may affect our ability to load and transport coal. If we are unable to conduct our operations due to severe weather, it could have an adverse effect on our results of operations, business and financial condition, as well as our ability to pay distributions to our unitholders.

Our revenues and operating profits could be negatively impacted if we are unable to extend existing coal supply agreements at favorable pricing or enter into new coal supply agreements due to competition, environmental regulations affecting our customers' changing coal purchasing patterns or other variables.

We compete with other coal suppliers when renewing expiring coal supply agreements or entering into new coal supply agreements. If we cannot renew these coal supply agreements or find alternate customers willing to purchase our coal, our revenue and operating profits could suffer. Our customers may decide not to extend our existing coal supply agreements or enter into new long-term agreements or, in the absence of long-term agreements, may decide to purchase fewer tons of coal than in the past or on different terms, including under different pricing terms or decide not to purchase at all. Any decrease in demand may cause customers to delay negotiations for new agreements or request lower pricing terms or seek coal from other sources. Furthermore, uncertainty caused by laws and regulations affecting electric utilities could deter customers from entering into long-term coal supply agreements with us. Some long-term agreements, including our coal supply agreements with PacifiCorp and IPA, contain provisions for termination or reduction in deliveries due to environmental changes if such changes prohibit or negatively impact those utilities' ability to burn the contracted coal.

We sell uncommitted tons in the spot market, which is subject to volatility.

We derive a portion of our revenue from coal sales in the spot market, typically defined as contracts with terms of less than one year. Trafigura AG, an affiliate of our sponsor, is the exclusive marketer of our uncommitted coal. The pricing in spot contracts is significantly more volatile than pricing through long-term coal supply agreements because it is subject to short-term demand swings. If spot market pricing for coal is unfavorable, this volatility could materially adversely affect our results of

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operations, business and financial condition, as well as our ability to pay distributions to our unitholders.

Demand for export coal and export coal prices are closely linked to consumption patterns of the electric industry in China. Any changes in consumption patterns could affect our operations and profitability.

Demand for export coal and the prices we can obtain for our export coal are linked to coal consumption patterns of the electric generation industry in China, which has accounted for approximately 53% of overall thermal coal consumption in China in recent years. These coal consumption patterns are influenced by factors beyond our control, including the demand for electricity (which is dependent to a significant extent on summer and winter temperatures and the strength of the economy); government regulation; technological developments and the location, availability, quality and price of competing sources of coal; other fuels such as natural gas, oil and nuclear; and alternative energy sources such as hydroelectric power. Any reduction in the demand for export coal by the electric generation industry in China may cause a decline in export coal prices and our profitability.

In November 2014, the U.S. and Chinese governments issued a joint announcement on climate change. In the announcement, the Chinese government stated that it "intends to achieve the peaking of CO₂ emissions around 2030 and to make best efforts to peak early and intends to increase the share of non-fossil fuels in primary energy consumption to around 20% by 2030." Moreover, the countries stated that they would work together to seek the adoption of an international protocol with legal force to address climate change during the United Nations Climate Conference in Paris in 2015. While the announcement has not led to the enactment of any new statutes or the promulgation of any new rules, any new governmental regulation relating to GHG emissions in China could affect our customers' ability to use coal. Any switching of fuel sources in China away from coal, closure of existing coal-fired power plants, or reduced construction of new plants could adversely affect demand for and prices received for coal, perhaps materially.

The current challenging economic environment, along with difficult and volatile conditions in the capital and credit markets, could materially adversely affect our financial position, results of operations or cash flows, and we are unsure whether these conditions will improve in the future.

The U.S. economy and global credit markets remain volatile. Worsening economic conditions or factors that negatively affect the economic health of the United States, Europe and Asia could reduce our revenues and thus adversely affect our results of operations. These markets have historically experienced disruptions, including, among other things, volatility in security prices, diminished liquidity and credit availability, rating downgrades of certain investments and declining valuations of others, failure and potential failures of major financial institutions, unprecedented government support of financial institutions, high unemployment rates and increasing interest rates. Furthermore, if these developments continue or worsen it may adversely affect the ability of our customers and suppliers to obtain financing to perform their obligations to us. We believe that further deterioration or a prolonged period of economic weakness will have an adverse impact on our results of operations, business and financial condition, as well as our ability to pay distributions to our unitholders.

Terrorist attacks and threats, escalation of military activity in response to such attacks or acts of war may negatively affect our business, financial condition and results of operations.

Terrorist attacks and threats, escalation of military activity in response to such attacks or acts of war may negatively affect our business, financial condition and results of operations. Our business is affected by general economic conditions, fluctuations in consumer confidence and spending, and market liquidity, which can decline as a result of numerous factors outside of our control, such as terrorist attacks and acts of war. Future terrorist attacks against U.S. targets, rumors or threats of war, actual conflicts involving the United States or its allies, or military or trade disruptions affecting our

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customers could cause delays or losses in transportation and deliveries of coal to our customers, decreased sales of our coal and extension of time for payment of accounts receivable from our customers. Strategic targets such as energy-related assets may be at greater risk of future terrorist attacks than other targets in the United States. It is possible that any, or a combination, of these occurrences could have a material adverse effect on our business, financial condition and results of operations, as well as our ability to pay distributions to our unitholders.

The amount of our customers' coal inventories may have a negative impact on our business.

Our customers may experience increases or decreases in their respective coal inventories from time to time. If we are unable to meet customers' increased demand due to decreases in their respective coal inventories, we may experience a loss of customers which could have a negative impact on our results of operations. In addition, if customers experience an increase in coal inventory, it is possible that their demand for additional coal from us may decrease, which could have a negative impact on our results of operations.

If our seaborne coal sales are reduced, we may be obligated to pay liquidated damages under our terminal and rail agreements.

If demand for coal in the international market weakens, it may not be economical for us to sell our coal into the seaborne market. If we reduce our seaborne coal sales, we may be obligated to pay liquidated damages or stockpile maintenance fees, or we may forfeit guaranteed stockpile space, under the terms of our terminal agreements. If we reduce our seaborne coal sales, we may also be obligated to pay liquidated damages under the terms of our agreements with the Union Pacific.

Risks Related to Environmental, Health, Safety and Other Regulations

Our mining operations, including our transportation infrastructure, are extensively regulated, which imposes significant costs on us, and changes to existing and potential future regulations or violations of regulations could increase those costs or limit our ability to produce and sell coal.

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

•: permits and other licensing requirements including, as applicable, NEPA;
•: surface subsidence from underground mining;
•: miner health and safety;
•: remediation of contaminated soil, surface water and groundwater;
•: air emissions;
•: water quality standards;
•: the discharge of materials into the environment, including waste water;
•: storage, treatment and disposal of petroleum products and substances which are regarded as hazardous under applicable laws or which, if spilled, could reach waterways or wetlands;
•: storage and disposal of coal wastes, including coal slurry, under applicable laws;
•: protection of human health, plant life and wildlife, including endangered and threatened species;
•: reclamation and restoration of mining properties after mining is completed;
•: wetlands protection;

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•: dam permitting; and
•: the effects, if any, that mining has on groundwater quality and availability.

Because of the extensive and detailed nature of these regulatory requirements, it is extremely difficult for us and other underground coal mining companies in particular, as well as the coal industry in general, to comply with all requirements at all times. We have been cited for violations of regulatory requirements in the past and we expect to be cited for violations in the future. None of our violations to date has had a material impact on our operations or financial condition, but future violations may have a material adverse impact on our business, results of operations or financial condition. While it is not possible to quantify 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, and delays in the receipt of, or failure to receive or revocation of necessary government permits, could substantially increase the cost of coal mining or have a material adverse effect on our results of operations, cash flows and financial condition, as well as our ability to pay distributions to our unitholders. Because we engage in longwall mining at our Sufco and Skyline mines, subsidence issues are particularly important to our operations. Failure to timely secure subsidence rights or any associated mitigation agreements, or any related regulatory action, could materially affect our results by causing delays or changes in our mining plan through stoppages or increased costs because of the necessity of obtaining such rights.

In addition, the utility industry is subject to extensive regulation regarding the environmental impact of its power generation activities, which could affect demand for our coal. It is possible that new environmental 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 our mining operations or our customers' ability to use coal. Any switching of fuel sources away from coal, closure of existing coal-fired power plants, or reduced construction of new plants could have adverse effects on demand for and prices received for our coal.

We may be unable to obtain, maintain or renew permits necessary for our operations, which would materially adversely affect our production, cash flow and profitability.

Mining companies must regularly obtain, maintain or renew a number of permits that impose strict requirements on various environmental and operational matters in connection with coal mining. These include permits issued by various federal, state and local agencies and regulatory bodies. The permitting rules, and the interpretations of these rules, are complex, change frequently, and are often subject to discretionary interpretations by the regulators, all of which may make compliance more difficult or impractical, and may possibly preclude the continuance of ongoing mine development or operations or the development of future mining operations. The public, including non-governmental organizations, anti-mining groups and individuals, have certain statutory rights to comment upon and submit objections to requested permits and environmental impact statements prepared in connection with applicable regulatory processes, and otherwise engage in the permitting process, including bringing citizens' claims to challenge the issuance or renewal of permits, the validity of environmental impact statements or performance of mining activities. Accordingly, required permits may not be issued or renewed in a timely fashion or issued or renewed at all, or permits issued or renewed may not be maintained, may be challenged or may be conditioned in a manner that may restrict our ability to efficiently and economically conduct our mining activities, any of which would materially reduce our production, cash flow, and profitability as well as our ability to pay distributions to our unitholders.

New legislation or administrative regulations or new judicial interpretations or administrative enforcement of existing laws and regulations, including proposals related to the protection of the environment and to human health and safety that would further regulate and tax the coal industry may also require us to change operations significantly or incur increased costs. For example, the EPA

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recently released its finalized revisions to its definition of "waters of the United States," which could result in new or expanded permitting requirements and may delay and add costs to the process for obtaining these permits. Such changes could have a material adverse effect on our financial condition and results of operations as well as our ability to pay distributions to our unitholders. Please read "Environmental and Other Regulatory Matters."

Review of BLM leasing decisions under NEPA may extend the time and/or increase the costs for obtaining necessary governmental approvals associated with our lease applications, which could materially adversely affect our production, cash flow and profitability.

Substantially all of our current and planned activities and operations rely on mineral leases administered by the BLM. The BLM administers competitive coal leases both on a regional basis, where the BLM selects tracts within a region for competitive sale, and through the LBA process, where the public nominates a particular tract of coal for competitive sale. All current BLM leasing is done through the LBA process. Because both regional leases and LBA tracts require one or more governmental approvals, both leasing processes may trigger the requirements of NEPA, which requires federal agencies, including the Department of the Interior, to evaluate major agency actions that have the potential to significantly impact the environment.

Compliance with NEPA can be time-consuming and may result in the imposition of mitigation measures that could affect the amount of coal that we are able to produce from mines on federal lands, and may require public comment. Whether the BLM has complied with NEPA is also subject to protest, appeal or litigation, which can delay or halt projects. For example, in June 2014, a federal court in Colorado rejected a NEPA analysis performed by the U.S. Forest Service and the BLM for various coal mine-related matters, including various lease modifications, specifically holding that the manner in which certain impacts associated with GHG emissions were analyzed was insufficient. This decision adds to the uncertainty surrounding the nature and extent of disclosure required by NEPA for climate change impacts associated with governmental actions. Recently, the Council on Environmental Quality published an updated Draft Guidance for federal agencies on "when and how" to consider and discuss the effects of GHG emissions in any analysis undertaken pursuant to NEPA, but it remains to be seen whether this guidance will provide meaningful certainty about the nature of the disclosures required under NEPA for climate change impacts associated with governmental actions. Recently, non-governmental organizations have filed objections with the BLM and U.S. Forest Service regarding the BLM's decision to offer the Greens Hollow tract for lease. These objections allege that the supplemental environmental impact statement prepared in connection with the issuance of the Greens Hollow lease fails to comply with NEPA for many reasons, including the failure to adequately address impacts associated with GHG emissions. Further, the leasing action related to the Flat Canyon tract by the BLM could also be challenged in the Department of Interior's Board of Land Appeals or in federal district court. The May 15, 2015 Notice of Lease Sale of the Flat Canyon tract prompted letters by several non-governmental organizations objecting to the lease sale on, among other things, environmental grounds. In another recent case, WildEarth Guardians v. United States Office of Surface Mining, Reclamation and Enforcement, the United States District Court for the District of Colorado identified several deficiencies in the NEPA compliance processes relating to approvals of two separate mining plan modifications for Colorado coal mines that had been issued in 2007 and 2009, respectively. The court gave the Office of Surface Mining 120 days to address these deficiencies before the previously-approved mining plans would be vacated. This decision demonstrates courts' willingness to assess NEPA compliance even where relevant approvals have been granted long ago and mining operations are underway. We cannot assure you that there will not be delays in our development plans or operations because of the NEPA review process. For these reasons, NEPA reviews may extend the time and/or increase the costs for obtaining necessary governmental approvals, which could negatively affect our production, cash flow and profitability.

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A change or disruption in our water supply, loss of water rights or interference with water rights owned by others in Utah could adversely affect our results of operations.

Our operations in Utah are heavily dependent upon our access to adequate supplies of water made available under water rights administered by the Utah Division of Water Rights (the "Division"). If we have difficulties obtaining adequate supplies of water due to availability, environmental, legal or other restrictions, or if our operations interfere with existing water rights owned by others, our operations and business may be adversely affected. The Division administers water rights by priority established by the date of application for the water right or the date of first use of the water whereby the water right with the earliest priority date in a source may divert and use its full supply before later priority water rights may divert and use any water. The water in the vicinity of the mines being operated in Utah is fully allocated to existing water rights, and no new water rights are being issued by the Division. Limited water rights are available for acquisition by purchase or lease and administrative change permitting a new use at the mines. There can be no assurance that applicable laws and regulations will not change in a manner that could have an adverse effect on our water rights and operations, or that we will not lose all or a portion of our water rights by abandonment or forfeiture. The physical supply of water needed to fully satisfy our water rights may vary from season to season and year to year and is dependent upon a number of factors including climatic conditions, upstream appropriators of water or other groundwater appropriators in the vicinity of the mines. Any failure of access to adequate water supplies provided under our water rights to support our current operations and any potential expansion would have a material adverse effect on our financial condition and results of operations.

Extensive governmental regulation pertaining to employee safety and health imposes significant costs on our mining operations and could materially adversely affect our results of operations.

Federal and state safety and health regulations in the coal mining industry are among the most comprehensive and pervasive systems for protection of employee safety and health affecting any U.S. industry. Compliance with these requirements imposes significant costs on us and can result in reduced productivity.

The possibility exists that new health and safety legislation, regulations and orders may be adopted that may materially adversely affect our mining operations. For example, in response to underground mine accidents of our competitors in the last decade, state and federal legislatures and regulatory authorities have increased scrutiny of mine safety matters and adopted more stringent requirements governing all forms of mining, including increased sanctions for and disclosure regarding non-compliance. In 2006, Congress enacted the MINER Act, which imposed additional obligations on all coal operators, including, among other matters:

•: the development of new emergency response plans;
•: ensuring the availability of mine rescue teams;
•: prompt notification to federal authorities of incidents that pose a reasonable risk of death; and
•: increased penalties for violations of the applicable federal laws and regulations.

Various states also have enacted new laws and regulations addressing many of these same subjects.

Federal and state health and safety authorities inspect our operations, and we anticipate a significant increase in the frequency and scope of these inspections. In recent years, federal authorities have also conducted special inspections of coal mines for, among other safety concerns, the accumulation of coal dust and the proper ventilation of gases such as methane. In addition, the federal government has announced that it is considering changes to mine safety rules and regulations. For example, MSHA recently finalized a new rule limiting miners' exposure to respirable coal dust. The first phase of the rule went into effect as of August 1, 2014, and requires, among other things, single shift sampling to determine noncompliance and corrective action to remedy any excessive levels of dust. The next phase of the rule takes effect February 1, 2016, and requires increased sampling frequency

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and the use of continuous personal dust monitors. This and other future mine safety rules could potentially result in or require significant expenditures, as well as additional safety training and planning, enhanced safety equipment, more frequent mine inspections, stricter enforcement practices and enhanced reporting requirements.

We must compensate employees for work-related injuries. If we do not make adequate provisions for our workers' compensation liabilities, we may be forced to pay higher amounts for these liabilities in the future, which may add to our compliance costs and adversely affect our operating results. Under the Black Lung Benefits Revenue Act of 1977 and Black Lung Benefits Reform Act of 1977, as amended in 1981, each coal mine operator must secure payment of federal black lung benefits to claimants who are current and former employees and contribute to a trust fund for the payment of benefits and medical expenses to claimants who last worked in the coal industry before July 1973. The trust fund is funded by an excise tax on coal production of up to $1.10 per ton for underground coal sold domestically, not to exceed 4.4% of the gross sales price. For the years ended December 31, 2014 and 2013, we recognized approximately $9.5 million and $10.0 million, respectively, of expense related to this tax. If this tax increases, or if we could no longer pass it on to the purchasers of our coal under our coal supply agreements, our operating costs could be increased and our results could be materially adversely effected. If new laws or regulations increase the number and award size of claims, it could materially adversely harm our business. Please read "Environmental and Other Regulatory Matters." In addition, the erosion through tort liability of the protections we are currently provided by workers' compensation laws could increase our liability for work-related injuries and have a material adverse effect on our results of operations, cash flows and financial condition as well as our ability to pay distributions to our unitholders.

Finally, as a public company, we will be subject to the Dodd-Frank Wall Street Reform and Consumer Protection Act provisions requiring disclosure in our periodic and other reports filed with the SEC regarding specified health and safety violations, orders and citations, related assessments and legal actions and mining-related fatalities.

Federal or state regulatory agencies have the authority to order certain of our mines to be temporarily or permanently closed under certain circumstances, which could materially adversely affect our ability to meet our customers' demands.

Federal or state regulatory agencies, including MSHA and the Utah Department of Natural Resources Division of Oil, Gas, and Mining, have the authority under certain circumstances following significant health, safety or environmental incidents or pursuant to permitting authority to temporarily or permanently close one or more of our mines. If this occurred, we may be required to incur capital expenditures to re-open the mine. In the event that these agencies cause us to close one or more of our mines, our coal supply agreements generally permit us to issue force majeure notices which suspend our obligations to deliver coal under such agreements. However, our customers may challenge our issuances of force majeure notices in connection with these closures. If these challenges are successful, we may have to purchase coal from third-party sources, if available, to fulfill these obligations, incur capital expenditures to re-open the mine or negotiate settlements with the customers, which may include price reductions, the reduction of commitments or the extension of time for delivery or termination of such customers' agreements. Any of these actions could have a material adverse effect on our results of operations, cash flows and financial condition as well as our ability to pay distributions to our unitholders.

Our operations may impact the environment or cause exposure to hazardous substances, and our properties may have environmental contamination, which could result in material liabilities to us.

Certain of our current and historical coal mining operations may use or may have used hazardous and other regulated materials and may have generated hazardous wastes. We may be subject to claims under federal and state statutes or common law doctrines for penalties, toxic torts and other damages,

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as well as for natural resource damages and for the investigation and remediation of soil, surface water, groundwater, and other media under laws such as the CERCLA, commonly known as Superfund, or the CWA. Such claims may arise, for example, out of current, former or threatened conditions at sites that we currently own or operate as well as at sites that we and companies we acquired owned or operated in the past, or sent waste to for treatment or disposal, and at contaminated sites that have always been owned or operated by third parties. Liability may be strict, joint and several, so that we, regardless of whether we caused contamination, may be held responsible for more than our share of the contamination or other damages, or even for the entire share. These and other similar unforeseen impacts that our operations may have on the environment, as well as exposures to regulated materials or wastes associated with our operations, could result in costs and liabilities that could have a material adverse effect on our results of operations, cash flows and financial condition as well as our ability to pay distributions to our unitholders.

New developments in the regulation of GHG emissions and coal ash could materially adversely affect our customers' demand for coal and our results of operations, cash flows and financial condition.

Coal-fired power plants produce carbon dioxide and other GHGs as a by-product of their operations. GHG emissions have received increasing scrutiny from local, state, federal and international government bodies. Future regulation of GHGs could occur pursuant to U.S. treaty obligations or statutory or regulatory change. The EPA and other regulators are using existing laws, including the federal Clean Air Act, to limit emissions of carbon dioxide and other GHGs from major sources, including coal-fired power plants that may require the use of "best available control technology." For example, the EPA has issued regulations restricting GHG emissions from any new U.S. power plants, and from any existing U.S. power plants that undergo major modifications that increase their GHG emissions. The EPA also recently proposed new source performance standards for GHG emissions for new coal and oil-fired power plants, which could require partial carbon capture and sequestration. In addition, in June 2013, President Obama announced additional initiatives intended to reduce GHG emissions globally, including curtailing U.S. government support for public financing of new coal-fired power plants overseas and promoting fuel switching from coal to natural gas or renewable energy sources. Global treaties are also being considered that place restrictions on carbon dioxide and other GHG emissions, though the United States has not assumed any mandatory reduction requirements to date. On June 2, 2014, the EPA further proposed new regulations limiting carbon dioxide emissions from existing power generation facilities. Under this proposal, nationwide carbon dioxide emissions would be reduced by 30% from 2005 levels by 2030 with a flexible interim goal. The current schedule calls for the final rule to be issued by mid-summer 2015, with the emission reductions scheduled to commence in 2020. The permitting of new coal-fired power plants has recently been contested by state regulators and environmental organizations over concerns related to GHG emissions from the new plants. In addition, state and regional climate change initiatives to regulate GHG emissions, such as the Regional Greenhouse Gas Initiative of certain northeastern and mid-Atlantic states, the Western Climate Initiative, the Midwestern Greenhouse Gas Reduction Accord and the California Global Warming Solutions Act, either have already taken effect or may take effect before federal action. Further, governmental agencies have been providing grants or other financial incentives to entities developing or selling alternative energy sources with lower levels of GHG emissions, which may lead to more competition from those entities. There have also been several public nuisance lawsuits brought against power, coal, oil and natural gas companies alleging that their operations are contributing to climate change. The plaintiffs are seeking various remedies, including punitive and compensatory damages and injunctive relief. While the U.S. Supreme Court recently determined that such claims cannot be pursued under federal law, plaintiffs may seek to proceed under state common law.

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A well-publicized failure in December 2008 of a coal ash slurry impoundment maintained by the Tennessee Valley Authority used to store ash from its coal burning power plants has led to new legislative and regulatory scrutiny and proposals that, if enacted, may impose significant obligations on us or our customers. For example, in December 2014, the EPA finalized regulations to address the management of coal ash as a solid waste under RCRA. These new regulatory obligations may result in costs and potential liability for handling coal ash for our utility customers and for us if we were to use coal ash for reclamation, or store or dispose of coal ash for any of our utility customers. Please read "Environmental and Other Regulatory Matters" for additional details.

Extensive environmental regulations, including existing and potential future regulatory requirements relating to air emissions, affect our customers and could reduce the demand for coal as a fuel source and cause coal prices and sales of our coal to materially decline.

The operations of our customers are subject to extensive environmental regulation particularly with respect to air emissions. For example, the federal Clean Air Act and similar state and local laws extensively regulate the amount of sulfur dioxide, particulate matter, nitrogen oxides, mercury, and other compounds emitted into the air from electric power plants, which are the largest end-users of our coal. A series of more stringent requirements relating to particulate matter, ozone, haze, mercury, sulfur dioxide, nitrogen oxide and other air pollutants will, or are expected to become effective in coming years. In addition, concerted conservation efforts that result in reduced electricity consumption could cause coal prices and sales of our coal to materially decline.

More stringent air emissions limitations may require significant emissions control expenditures for many coal-fired power plants and could have the effect of making coal-fired power plants less profitable. As a result, some power plants may switch to other fuels that generate less of these emissions or they may close. Any switching of fuel sources away from coal, closure of existing coal-fired power plants, or reduced construction of new plants could have a material adverse effect on demand for and prices received for our coal. Please read "Environmental and Other Regulatory Matters."

Risks Inherent in an Investment in Us

Our sponsor owns and controls our general partner, which has sole responsibility for conducting our business and managing our operations. Our general partner and its affiliates, including our sponsor, have conflicts of interest with us and limited duties, and they may favor their own interests to the detriment of us and our unitholders.

Following this offering, our sponsor will own and control our general partner and will appoint all of the directors of our general partner. Although our general partner has a duty to manage us in a manner that it believes is not adverse to our interest, the executive officers and directors of our general partner have a fiduciary duty to manage our general partner in a manner beneficial to our sponsor. Therefore, conflicts of interest may arise between our sponsor or any of its affiliates, including our general partner, on the one hand, and us or any of our unitholders, on the other hand. In resolving these conflicts of interest, our general partner may favor its own interests and the interests of its affiliates over the interests of our common unitholders. These conflicts include the following situations, among others:

•: our general partner is allowed to take into account the interests of parties other than us, such as our sponsor, in exercising certain rights under our partnership agreement;
•: neither our partnership agreement nor any other agreement requires our sponsor to pursue a business strategy that favors us;
•: our partnership agreement replaces the fiduciary duties that would otherwise be owed by our general partner with contractual standards governing its duties, limits our general partner's

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liabilities and restricts the remedies available to our unitholders for actions that, without such limitations, might constitute breaches of fiduciary duty;

•: except in limited circumstances, our general partner has the power and authority to conduct our business without unitholder approval;
•: our general partner determines the amount and timing of asset purchases and sales, borrowings, issuances of additional partnership securities and the level of cash reserves, each of which can affect the amount of cash that is distributed to our unitholders;
•: our general partner determines the amount and timing of any cash expenditure and whether an expenditure is classified as a maintenance capital expenditure, which reduces operating surplus, or an expansion capital expenditure, which does not reduce operating surplus. Please read "How We Make Distributions To Our Partners—Operating Surplus and Capital Surplus—Capital Expenditures" for a discussion on when a capital expenditure constitutes a maintenance capital expenditure or an expansion capital expenditure. This determination can affect the amount of cash from operating surplus that is distributed to our unitholders which, in turn, may affect the ability of the subordinated units to convert. Please read "How We Make Distributions To Our Partners—Subordination Period";
•: our general partner may cause us to borrow funds in order to permit the payment of cash distributions, even if the purpose or effect of the borrowing is to make a distribution on the subordinated units, to make incentive distributions or to accelerate the expiration of the subordination period;
•: our partnership agreement permits us to distribute up to $ million as operating surplus, even if it is generated from asset sales, non-working capital borrowings or other sources that would otherwise constitute capital surplus. This cash may be used to fund distributions on our subordinated units or the incentive distribution rights;
•: 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 to us or entering into additional contractual arrangements with its affiliates on our behalf;
•: our general partner intends to limit its liability regarding our contractual and other obligations;
•: our general partner may exercise its right to call and purchase common units if it and its affiliates own more than 80% of the common units;
•: our general partner controls the enforcement of obligations that it and its affiliates owe to us;
•: our general partner decides whether to retain separate counsel, accountants or others to perform services for us; and
•: our general partner may elect to cause us to issue common units to it in connection with a resetting of the target distribution levels related to our general partner's incentive distribution rights without the approval of the conflicts committee of the board of directors of our general partner or the unitholders. This election may result in lower distributions to the common unitholders in certain situations.

In addition, we may compete directly with our sponsor and entities in which it has an interest for acquisition opportunities and potentially will compete with these entities for new business or extensions of the existing services provided by us. Please read "—Our sponsor and other affiliates of our general partner may compete with us" and "Conflicts of Interest and Fiduciary Duties."

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The board of directors of our general partner may modify or revoke our cash distribution policy at any time at its discretion. Our partnership agreement does not require us to pay any distributions at all.

The board of directors of our general partner will adopt a cash distribution policy pursuant to which we intend to distribute quarterly at least $ per unit on all of our units to the extent we have sufficient cash after the establishment of cash reserves and the payment of our expenses, including payments to our general partner and its affiliates. However, the board of directors of our general partner may change such policy at any time at its discretion and could elect not to pay distributions for one or more quarters. Please read "Cash Distribution Policy and Restrictions on Distributions."

In addition, our partnership agreement does not require us to pay any distributions at all. Accordingly, investors are cautioned not to place undue reliance on the permanence of such a policy in making an investment decision. Any modification or revocation of our cash distribution policy could substantially reduce or eliminate the amount of distributions to our unitholders. The amount of distributions we make, if any, and the decision to make any distribution at all will be determined by the board of directors of our general partner, whose interests may differ from those of our common unitholders. Our general partner has limited duties to our unitholders, which may permit it to favor its own interests or the interests of our sponsor to the detriment of our common unitholders.

Our general partner intends to limit its liability regarding our obligations.

Our general partner intends to limit its liability under contractual arrangements between us and third parties so that the counterparties to such arrangements have recourse only against our assets, and not against our general partner or its assets. Our general partner may therefore cause us to incur indebtedness or other obligations that are nonrecourse to our general partner. Our partnership agreement provides that any action taken by our general partner to limit its liability is not a breach of our general partner's duties, even if we could have obtained more favorable terms without the limitation on liability. In addition, we are obligated to reimburse or indemnify our general partner to the extent that it incurs obligations on our behalf. Any such reimbursement or indemnification payments would reduce the amount of cash otherwise available for distribution to our unitholders.

We expect to distribute a significant portion of our cash available for distribution to our partners, which could limit our ability to grow and make acquisitions.

We plan to distribute most of our cash available for distribution, which may cause our growth to proceed at a slower pace than that of businesses that reinvest their cash to expand ongoing operations. To the extent we issue additional units in connection with any acquisitions or expansion capital expenditures, the payment of distributions on those additional units may increase the risk that we will be unable to maintain or increase our per unit distribution level. There are no limitations in our partnership agreement on our ability to issue additional units, including units ranking senior to the common units. The incurrence of additional commercial borrowings or other debt to finance our growth strategy would result in increased interest expense, which in turn, may impact the cash that we have available to distribute to our unitholders.

Our right of first refusal to acquire certain of our sponsor's assets is subject to risks and uncertainties, and ultimately we may not acquire any of those assets.

Our omnibus agreement will provide us with a right of first refusal to acquire certain of our sponsor's coal and terminal properties and our agreement with Bowie Refined Coal, LLC, an affiliate of our sponsor, will provide us with a right of first refusal to acquire certain refined coal projects. The consummation and timing of any future acquisitions of such assets will depend upon, among other things, our sponsor's or its affiliate's willingness to offer such assets for sale, our ability to negotiate acceptable customer contracts and other agreements with respect to such assets and our ability to

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obtain financing on acceptable terms. We can offer no assurance that we will be able to successfully consummate any future acquisitions pursuant to our rights under these agreements and neither our sponsor nor its affiliate is under any obligation to sell any assets that would be subject to our right of first refusal. For these or a variety of other reasons, we may decide not to exercise our right of first refusal when any assets are offered for sale, and our decision will not be subject to unitholder approval. Please read "Certain Relationships and Related Party Transactions—Agreements with Affiliates in Connection with the Transactions."

Our partnership agreement replaces our general partner's fiduciary duties to unitholders.

Our partnership agreement contains provisions that eliminate and replace the fiduciary 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, or otherwise free of fiduciary duties to us and our unitholders. This entitles our general partner to consider only the interests and factors that it desires and relieves it of any duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates or our limited partners. Examples of decisions that our general partner may make in its individual capacity include:

•: how to allocate business opportunities among us and its affiliates;
•: whether to exercise its call right;
•: whether to seek approval of the resolution of a conflict of interest by the conflicts committee of the board of directors of our general partner;
•: how to exercise its voting rights with respect to the units it owns;
•: whether to exercise its registration rights;
•: whether to elect to reset target distribution levels; and
•: whether or not to consent to any merger or consolidation of the partnership or amendment to the partnership agreement.

By purchasing a common unit, a unitholder is treated as having consented to the provisions in the partnership agreement, including the provisions discussed above. Please read "Conflicts of Interest and Fiduciary Duties—Fiduciary Duties."

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

Our partnership agreement contains provisions that restrict the remedies available to unitholders for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty under state fiduciary duty law. For example, our partnership agreement provides that:

•: whenever our general partner makes a determination or takes, or declines to take, any other action in its capacity as our general partner, our general partner is generally required to make such determination, or take or decline to take such other action, in good faith, and will not be subject to any higher standard imposed by our partnership agreement, Delaware law, or any other law, rule or regulation, or at equity;
•: our general partner and its officers and directors will not be liable for monetary damages or otherwise to us or our limited partners resulting from any act or omission unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that such losses or liabilities were the result of conduct in which our general partner or its officers or directors engaged in bad faith, meaning that they believed that the decision was

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adverse to the interest of the partnership or, with respect to any criminal conduct, with knowledge that such conduct was unlawful; and

•

our general partner will not be in breach of its obligations under the partnership agreement or its duties to us or our limited partners if a transaction with an affiliate or the resolution of a conflict of interest is:

(1): approved by the conflicts committee of the board of directors of our general partner, although our general partner is not obligated to seek such approval; or
(2): approved by the vote of a majority of the outstanding common units, excluding any common units owned by our general partner and its affiliates.

In connection with a situation involving a transaction with an affiliate or a conflict of interest, other than one where our general partner is permitted to act in its sole discretion, any determination by our general partner must be made in good faith. If an affiliate transaction or the resolution of a conflict of interest is not approved by our common unitholders or the conflicts committee then it will be presumed that, in making its decision, taking any action or failing to act, the board of directors acted in good faith, and in any proceeding brought by or on behalf of any limited partner or the partnership, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption. Please read "Conflicts of Interest and Fiduciary Duties."

Our sponsor and other affiliates of our general partner may compete with us.

Our partnership agreement provides that our general partner will be restricted from engaging in any business activities other than acting as our general partner, engaging in activities incidental to its ownership interest in us and providing management, advisory, and administrative services to its affiliates or to other persons. However, affiliates of our general partner, including our sponsor, are not prohibited from engaging in other businesses or activities, including those that might be in direct competition with us. In addition, our sponsor may compete with us for investment opportunities and may own an interest in entities that compete with us.

Pursuant to the terms of our partnership agreement, the doctrine of corporate opportunity, or any analogous doctrine, does not apply to our general partner or any of its affiliates, including its executive officers and directors and our sponsor. Any such person or entity that becomes aware of a potential transaction, agreement, arrangement or other matter that may be an opportunity for us will not have any duty to communicate or offer such opportunity to us. Any such person or entity will not be liable to us or to any limited partner for breach of any fiduciary duty or other duty by reason of the fact that such person or entity pursues or acquires such opportunity for itself, directs such opportunity to another person or entity or does not communicate such opportunity or information to us. This may create actual and potential conflicts of interest between us and affiliates of our general partner and result in less than favorable treatment of us and our unitholders. Please read "Conflicts of Interest and Fiduciary Duties."

The holder or holders of our incentive distribution rights may elect to cause us to issue common units to it in connection with a resetting of the target distribution levels related to the incentive distribution rights, without the approval of the conflicts committee of our general partner's board of directors or the holders of our common units. This could result in lower distributions to holders of our common units.

The holder or holders of a majority of our incentive distribution rights (initially our general partner) have the right, at any time when there are no subordinated units outstanding and we have made cash distributions in excess of the highest then-applicable target distribution for each of the prior four consecutive fiscal quarters, to reset the initial target distribution levels at higher levels based on our cash distribution levels at the time of the exercise of the reset election. Following a reset election

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by our general partner, the minimum quarterly distribution will be calculated equal to an amount equal to the prior cash distribution per common unit for the fiscal quarter immediately preceding the reset election (which amount we refer to as the "reset minimum quarterly distribution") and the target distribution levels will be reset to correspondingly higher levels based on percentage increases above the reset minimum quarterly distribution. If our general partner elects to reset the target distribution levels, it will be entitled to receive a number of common units equal to the number of common units that would have entitled the holder to an aggregate quarterly cash distribution for the quarter prior to the reset election equal to the distribution on the incentive distribution rights for the quarter prior to the reset election.

We anticipate that our general partner would exercise this reset right in order to facilitate acquisitions or internal growth projects that would not be sufficiently accretive to cash distributions per unit without such conversion. However, our general partner may transfer the incentive distribution rights at any time. It is possible that our general partner or a transferee could exercise this reset election at a time when we are experiencing declines in our aggregate cash distributions or at a time when the holders of the incentive distribution rights expect that we will experience declines in our aggregate cash distributions in the foreseeable future. In such situations, the holders of the incentive distribution rights may be experiencing, or may expect to experience, declines in the cash distributions it receives related to the incentive distribution rights and may therefore desire to be issued our common units rather than retain the right to receive incentive distributions based on the initial target distribution levels. As a result, a reset election may cause our common unitholders to experience reduction in the amount of cash distributions that they would have otherwise received had we not issued new common units to the holders of the incentive distribution rights in connection with resetting the target distribution levels. Please read "How We Make Distributions To Our Partners—Incentive Distribution Rights—Incentive Distribution Right Holders' Right to Reset Incentive Distribution Levels."

Cost and expense reimbursements, which will be determined by our general partner in its sole discretion, and fees due to our general partner and our sponsor for services provided will reduce the amount of cash available to pay distributions to our unitholders.

Under our partnership agreement, we are required to reimburse our general partner for all expenses it incurs and payments it makes on our behalf. Our partnership agreement does not set a limit on the amount of expenses for which our general partner may be reimbursed. These expenses include salary, bonus, incentive compensation and other amounts paid to persons who perform services for us or on our behalf and expenses allocated to our general partner by its affiliates. Our general partner is entitled to determine the expenses that are allocable to us. We also expect to enter into an omnibus agreement with our sponsor, pursuant to which we will reimburse our sponsor on a cost-of-services basis for certain services performed on our behalf. The reimbursement of expenses and payment of fees, if any, to our general partner and our sponsor will reduce the amount of cash available to pay distributions to our unitholders. We expect that we will reimburse our sponsor and our general partner approximately $15.7 million in total for services performed under the partnership agreement and the omnibus agreement during the twelve months ending June 30, 2016.

Our partnership agreement includes exclusive forum, venue and jurisdiction provisions. By purchasing a common unit, a limited partner is irrevocably consenting to these provisions regarding claims, suits, actions or proceedings and submitting to the exclusive jurisdiction of Delaware courts.

Our partnership agreement is governed by Delaware law. Our partnership agreement includes exclusive forum, venue and jurisdiction provisions designating Delaware courts as the exclusive venue for most claims, suits, actions and proceedings involving us or our officers, directors and employees. Please read "The Partnership Agreement—Applicable Law; Forum, Venue and Jurisdiction." If a

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dispute were to arise between a limited partner and us or our officers, directors or employees, the limited partner may be required to pursue its legal remedies in Delaware which may be an inconvenient or distant location and which is considered to be a more corporate-friendly environment.

Holders of our common units have limited voting rights and are not entitled to elect our general partner or its directors, which could reduce the price at which our common units will trade.

Compared to the holders of common stock in a corporation, unitholders have limited voting rights and, therefore, limited ability to influence management's decisions regarding our business. Unitholders will have no right on an annual or ongoing basis to elect our general partner or its board of directors. The board of directors of our general partner, including the independent directors, is chosen entirely by our sponsor, as a result of it owning our general partner, and not by our unitholders. Please read "Management—Management of Bowie Resource Partners LP" and "Certain Relationships and Related Party Transactions." Unlike publicly traded corporations, we will not conduct annual meetings of our unitholders to elect directors or conduct other matters routinely conducted at annual meetings of stockholders of corporations. As a result of these limitations, the price at which the common units will trade could be diminished because of the absence or reduction of a takeover premium in the trading price.

Even if holders of our common units are dissatisfied, they cannot initially remove our general partner without its consent.

If our unitholders are dissatisfied with the performance of our general partner, they will have limited ability to remove our general partner. Unitholders initially will be unable to remove our general partner without its consent because our general partner and its affiliates will own sufficient units upon the completion of this offering to be able to prevent its removal. The vote of the holders of at least 66²/3% of all outstanding common and subordinated units voting together as a single class is required to remove our general partner. Following the closing of this offering, our sponsor will own an aggregate of % of our common and subordinated units (or % of our common and subordinated units, if the underwriters exercise their option to purchase additional common units in full).

In addition, any vote to remove our general partner during the subordination period must provide for the election of a successor general partner by the holders of a majority of the common units and a majority of the subordinated units, voting as separate classes. This will provide our sponsor the ability to prevent the removal of our general partner.

Unitholders will experience immediate and substantial dilution of $ per common unit.

The assumed initial public offering price of $ per common unit (the mid-point of the price range set forth on the cover page of this prospectus) exceeds our pro forma net tangible book value of $ per common unit. Based on the assumed initial public offering price of $ per common unit, unitholders will incur immediate and substantial dilution of $ per common unit. This dilution results primarily because the assets contributed to us by affiliates of our general partner are recorded at their historical cost in accordance with GAAP, and not their fair value. Please read "Dilution."

Our general partner interest or the control of our general partner may be transferred to a third party without unitholder consent.

Our general partner may transfer its general partner interest to a third party without the consent of our unitholders. Furthermore, our partnership agreement does not restrict the ability of the owner of our general partner to transfer its membership interests in our general partner to a third party. The new owner of our general partner would then be in a position to replace the board of directors and

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executive officers of our general partner with its own designees and thereby exert significant control over the decisions taken by the board of directors and executive officers of our general partner. This effectively permits a "change of control" without the vote or consent of the unitholders.

The incentive distribution rights may be transferred to a third party without unitholder consent.

Our general partner may transfer the incentive distribution rights to a third party at any time without the consent of our unitholders. If our general partner transfers the incentive distribution rights to a third party, our general partner would not have the same incentive to grow our partnership and increase quarterly distributions to our unitholders over time. For example, a transfer of incentive distribution rights by our general partner could reduce the likelihood of our sponsor accepting offers made by us relating to assets owned by our sponsor, as it would have less of an economic incentive to grow our business, which in turn would impact our ability to grow our asset base.

Our general partner has a call right that may require unitholders to sell their common units at an undesirable time or price.

If at any time our general partner and its affiliates own more than 80% of the common units, our general partner will have the right, which it may assign to any of its affiliates or to us, but not the obligation, to acquire all, but not less than all, of the common units held by unaffiliated persons at a price equal to the greater of (1) the average of the daily closing price of the common units over the 20 trading days preceding the date three days before notice of exercise of the call right is first mailed and (2) the highest per-unit price paid by our general partner or any of its affiliates for common units during the 90-day period preceding the date such notice is first mailed. As a result, unitholders may be required to sell their common units at an undesirable time or price and may not receive any return or a negative return on their investment. Unitholders may also incur a tax liability upon a sale of their units. Our general partner is not obligated to obtain a fairness opinion regarding the value of the common units to be repurchased by it upon exercise of the limited call right. There is no restriction in our partnership agreement that prevents our general partner from causing us to issue additional common units and then exercising its call right. If our general partner exercised its limited call right, the effect would be to take us private and, if the units were subsequently deregistered, we would no longer be subject to the reporting requirements of the Securities Exchange Act of 1934 (the "Exchange Act"). Upon consummation of this offering, and assuming no exercise of the underwriters' option to purchase additional common units, our sponsor will own an aggregate of % of our common and subordinated units. At the end of the subordination period, assuming no additional issuances of units (other than upon the conversion of the subordinated units), our sponsor will own % of our common units. For additional information about the limited call right, please read "The Partnership Agreement—Limited Call Right."

We may issue an unlimited number of additional partnership interests without unitholder approval, which would dilute existing unitholder ownership interests.

Our partnership agreement does not limit the number of additional limited partner interests we may issue at any time without the approval of our unitholders. The issuance of additional common units or other equity interests of equal or senior rank will have the following effects:

•: our existing unitholders' proportionate ownership interest in us will decrease;
•: the amount of cash available for distribution on each unit may decrease;
•: because a lower percentage of total outstanding units will be subordinated units, the risk that a shortfall in the payment of the minimum quarterly distribution will be borne by our common unitholders will increase;

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•: the ratio of taxable income to distributions may increase;
•: the relative voting strength of each previously outstanding unit may be diminished; and
•: the market price of the common units may decline.

There are no limitations in our partnership agreement on our ability to issue units ranking senior to the common units.

In accordance with Delaware law and the provisions of our partnership agreement, we may issue additional partnership interests that are senior to the common units in right of distribution, liquidation and voting. The issuance by us of units of senior rank may (1) reduce or eliminate the amount of cash available for distribution to our common unitholders; (2) diminish the relative voting strength of the total common units outstanding as a class; or (3) subordinate the claims of the common unitholders to our assets in the event of our liquidation.

The market price of our common units could be adversely affected by sales of substantial amounts of our common units in the public or private markets, including sales by our sponsor or other large holders.

After this offering, we will have common units and subordinated units outstanding, which includes the common units we are selling in this offering that may be resold in the public market immediately. All of the subordinated units will convert into common units on a one-for-one basis at the end of the subordination period. The common units ( if the underwriters do not exercise their option to purchase additional common units) that are issued to our sponsor will be subject to resale restrictions under a 180-day lock-up agreement with the underwriters. Each of the lock-up agreements with the underwriters may be waived in the discretion of certain of the underwriters. Sales by our sponsor or other large holders of a substantial number of our common units in the public markets following this offering, or the perception that such sales might occur, 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. In addition, we have agreed to provide registration rights to our sponsor. Under our partnership agreement, our general partner and its affiliates have registration rights relating to the offer and sale of any units that they hold. Alternatively, we may be required to undertake a future public or private offering of common units and use the net proceeds from such offering to redeem an equal number of common units held by our sponsor. Please read "Units Eligible for Future Sale."

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

Our partnership agreement restricts unitholders' voting rights by providing that any units held by a person or group that owns 20% or more of any class of units then outstanding, other than our general partner and its affiliates, their transferees and persons who acquired such units with the prior approval of the board of directors of our general partner, cannot vote on any matter.

There is no existing market for our common units and a trading market that will provide you with adequate liquidity may not develop. The price of our common units may fluctuate significantly, and unitholders could lose all or part of their investment.

Prior to this offering, there has been no public market for the common units. After this offering, there will be only publicly traded common units. We do not know the extent to which investor interest will lead to the development of a trading market or how liquid that market might be. Unitholders may not be able to resell their common units at or above the initial public offering price. Additionally, the lack of liquidity may result in wide bid-ask spreads, contribute to significant

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fluctuations in the market price of the common units and limit the number of investors who are able to buy the common units.

The initial public offering price for our common units will be determined by negotiations between us and the representatives of the underwriters and may not be indicative of the market price of the common units that will prevail in the trading market. The market price of our common units may decline below the initial public offering price. The market price of our common units may also be influenced by many factors, some of which are beyond our control, including:

•: our quarterly distributions;
•: our quarterly or annual earnings or those of other companies in our industry;
•: announcements by us or our competitors of significant contracts or acquisitions;
•: changes in accounting standards, policies, guidance, interpretations or principles;
•: general economic conditions;
•: the failure of securities analysts to cover our common units after this offering or changes in financial estimates by analysts;
•: future sales of our common units; and
•: the other factors described in these "Risk Factors."

Unitholders may have liability to repay distributions.

Under certain circumstances, unitholders may have to repay amounts wrongfully returned or distributed to them. Under Section 17-607 of the Delaware Revised Uniform Limited Partnership Act (the "Delaware Act"), we may not make a distribution to our unitholders if the distribution would cause our liabilities to exceed the fair value of our assets. Delaware law provides that for a period of three years from the date of the impermissible distribution, limited partners who received the distribution and who knew at the time of the distribution that it violated Delaware law will be liable to the limited partnership for the distribution amount. Liabilities to partners on account of their partnership interests and liabilities that are non-recourse to the partnership are not counted for purposes of determining whether a distribution is permitted.

For as long as we are an emerging growth company, we will not be required to comply with certain reporting requirements that apply to other public companies, including those relating to auditing standards and disclosure about our executive compensation.

The JOBS Act contains provisions that, among other things, relax certain reporting requirements for "emerging growth companies," including certain requirements relating to auditing standards and compensation disclosure. We are classified as an emerging growth company. For as long as we are an emerging growth company, which may be up to five full fiscal years, unlike other public companies, we will not be required to, among other things, (1) provide an auditor's attestation report on management's assessment of the effectiveness of our system of internal control over financial reporting pursuant to Section 404(b) of the Sarbanes-Oxley Act of 2002, (2) comply with any new requirements adopted by the PCAOB requiring mandatory audit firm rotation or a supplement to the auditor's report in which the auditor would be required to provide additional information about the audit and the financial statements of the issuer, (3) comply with any new audit rules adopted by the PCAOB after April 5, 2012 unless the SEC determines otherwise or (4) provide certain disclosure regarding executive compensation required of larger public companies.

If we fail to develop or maintain an effective system of internal controls, we may not be able to accurately report our financial results or prevent fraud. As a result, current and potential unitholders

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could lose confidence in our financial reporting, which would harm our business and the trading price of our units.

Effective internal controls are necessary for us to provide reliable financial reports, prevent fraud and operate successfully as a public company. If we cannot provide reliable financial reports or prevent fraud, our reputation and operating results would be harmed. We cannot be certain that our efforts to develop and maintain our internal controls will be successful, that we will be able to maintain adequate controls over our financial processes and reporting in the future or that we will be able to comply with our obligations under Section 404 of the Sarbanes-Oxley Act of 2002. Any failure to develop or maintain effective internal controls, or difficulties encountered in implementing or improving our internal controls, could harm our operating results or cause us to fail to meet our reporting obligations. Ineffective internal controls could also cause investors to lose confidence in our reported financial information, which would likely have a negative effect on the trading price of our units.

The NYSE does not require a publicly traded partnership like us to comply with certain of its corporate governance requirements.

We intend to apply to list our common units on the NYSE. Because we will be a publicly traded partnership, the NYSE does not require us to have a majority of independent directors on our general partner's board of directors or to establish a compensation committee or a nominating and corporate governance committee. Accordingly, unitholders will not have the same protections afforded to stockholders of certain corporations that are subject to all of the NYSE's corporate governance requirements. Please read "Management—Management of Bowie Resource Partners LP."

We will incur increased costs as a result of being a publicly traded partnership.

We have no history operating as a publicly traded partnership. As a publicly traded partnership, we will incur significant legal, accounting and other expenses that we did not incur prior to this offering. In addition, the Sarbanes-Oxley Act of 2002, as well as rules implemented by the SEC and the NYSE, require publicly traded entities to adopt various corporate governance practices that will further increase our costs. The amount of our expenses or reserves for expenses, including the costs of being a publicly traded partnership, will reduce the amount of cash we have for distribution to our unitholders. As a result, the amount of cash we have available for distribution to our unitholders will be affected by the costs associated with being a public company.

Prior to this offering, we have not filed reports with the SEC. Following this offering, we will become subject to the public reporting requirements of the Exchange Act. We expect these rules and regulations to increase certain of our legal and financial compliance costs and to make activities more time-consuming and costly. For example, as a result of becoming a publicly traded company, we are required to have at least three independent directors, create an audit committee and adopt policies regarding internal controls and disclosure controls and procedures, including the preparation of reports on internal controls over financial reporting. In addition, we will incur additional costs associated with our SEC reporting requirements.

We also expect to incur significant expense in order to obtain director and officer liability insurance. Because of the limitations in coverage for directors, it may be more difficult for us to attract and retain qualified persons to serve on the board of directors of our general partner or as executive officers.

We estimate that we will incur approximately $ million of incremental costs per year associated with being a publicly traded partnership; however, it is possible that our actual incremental costs of being a publicly traded partnership will be higher than we currently estimate.

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Unitholders who are not "Eligible Holders" will not be entitled to receive distributions on or allocations of income or loss on their common units, and their common units will be subject to redemption.

In order to comply with U.S. laws with respect to the ownership of interests in mineral leases on federal lands, we will adopt certain requirements regarding those investors who may own our common units. As used herein, an Eligible Holder means a person or entity qualified to hold an interest in mineral leases on federal lands. As of the date hereof, Eligible Holder means: (1) a citizen of the United States; (2) a corporation organized under the laws of the United States or of any state thereof; or (3) an association of United States citizens, such as a partnership or limited liability company, organized under the laws of the United States or of any state thereof, but only if this association does not have any direct or indirect foreign ownership, other than foreign ownership of stock in a parent corporation organized under the laws of the United States or of any state thereof. For the avoidance of doubt, onshore mineral leases or any direct or indirect interest therein may be acquired and held by aliens only through stock ownership, holding or control in a corporation organized under the laws of the United States or of any state thereof and only for so long as the alien is not from a country that the United States federal government regards as denying similar privileges to citizens or corporations of the United States. Common unitholders who are not persons or entities who meet the requirements to be an Eligible Holder will not be entitled to receive distributions or allocations of income and loss on their units and they run the risk of having their units redeemed by us at the lower of their purchase price cost or the then-current market price. The redemption price will be paid in cash or by delivery of a promissory note, as determined by our general partner.

Tax Risks to Common Unitholders

In addition to reading the following risk factors, please read "Material U.S. Federal Income Tax Consequences" for a more complete discussion of the expected material federal income tax consequences of owning and disposing of common units.

Our tax treatment depends on our status as a partnership for federal income tax purposes, as well as our not being subject to a material amount of entity-level taxation by individual states. If the IRS were to treat us as a corporation for federal income tax purposes or we were to become subject to material additional amounts of entity-level taxation for state tax purposes, then our cash available for distribution could be substantially reduced.

The anticipated after-tax economic benefit of an investment in our common units depends largely on our being treated as a partnership for federal income tax purposes. We have not requested, and do not plan to request, a ruling from the IRS on this or any other tax matter affecting us. Despite the fact that we are organized as a limited partnership under Delaware law, it is possible in certain circumstances for a partnership such as ours to be treated as a corporation for federal income tax purposes. Although we do not believe, based upon our current operations, that we will be so treated, a change in our business, a change in current law or a change in the interpretation of current law could cause us to be treated as a corporation for federal income tax purposes or otherwise subject us to taxation as an entity.

If we were treated as a corporation for federal income tax purposes, we would pay federal income tax on our taxable income at the corporate tax rate, which is currently a maximum of 35%, and would likely pay state income tax at varying rates. Distributions to you would generally be taxed again as corporate distributions, and no income, gains, losses, deductions or credits would flow through to you. Because a tax would be imposed upon us as a corporation, our cash available for distribution to you would be substantially reduced. Therefore, treatment of us as a corporation would result in a material reduction in the anticipated cash flow and after-tax return to the unitholders, likely causing a substantial reduction in the value of our common units. Our partnership agreement provides that if a law is enacted or existing law is modified or interpreted in a manner that subjects us to taxation as a

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corporation or otherwise subjects us to entity-level taxation for 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 us.

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

The present federal income tax treatment of publicly traded partnerships, including us, or an investment in our common units may be modified by administrative, legislative or judicial changes or differing interpretations at any time. From time to time, members of Congress propose and consider substantive changes to the existing federal income tax laws that affect publicly traded partnerships. For example, President Obama's proposed fiscal year 2015 budget (the "2015 Budget Proposal") would eliminate the qualifying income exception to the treatment of publicly traded partnerships as corporations, upon which we rely for our treatment as a partnership for U.S. federal income tax purposes, for partnerships with qualifying income or gains from fossil fuels, including coal, beginning in 2021. Any modification to the federal income tax laws may be applied retroactively and could make it more difficult or impossible to meet the exception for certain publicly traded partnerships to be treated as partnerships for federal income tax purposes. Please read "Material U.S. Federal Income Tax Consequences—Taxation of the Partnership—Partnership Status." We are unable to predict whether these changes, or other proposals will ultimately be enacted. Any such changes could negatively impact the value of an investment in our common units.

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

Because our unitholders will be treated as partners to whom we will allocate taxable income that could be different in amount than the cash we distribute, 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. You may not receive cash distributions from us equal to your share of our taxable income or even equal to the actual tax liability that results from that income.

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

We will be considered to have constructively 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. Immediately following this offering, our sponsor will own, directly or indirectly, more than 50% of the total interests in our capital and profits. Therefore, a transfer by our sponsor of all or a portion of its interests in us could result in a termination of us as a partnership for federal income tax purposes. Our termination would, among other things, result in the closing of our taxable year for all unitholders and could result in a deferral of depreciation deductions allowable in computing our taxable income. In the case of a unitholder reporting on a taxable year other than the 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 his taxable income for the year of termination. Our termination currently would not affect our classification as a partnership for federal income tax purposes, but instead, after our termination we would be treated as a new partnership for federal income tax purposes. If treated as a new partnership, we must make new tax elections and could be subject to penalties if we are unable to determine that a termination occurred. Please read "Material U.S. Federal Income Tax Consequences—Disposition of Units—Constructive Termination" for a discussion of the consequences of our termination for federal income tax purposes.

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

If you sell your common units, you will recognize a gain or loss equal to the difference between the amount realized and your tax basis in those common units. Because distributions in excess of your allocable share of our net taxable income result in a decrease in your tax basis in your common 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 in those units, even if the price you receive is less than your original cost. Furthermore, a substantial portion of the amount realized, whether or not representing gain, may be taxed as ordinary income due to potential recapture of depreciation and amortization deductions and certain other items. In addition, because the amount realized includes a unitholder's share of our nonrecourse liabilities, if you sell your units, you may incur a tax liability in excess of the amount of cash you receive from the sale. Please read "Material U.S. Federal Income Tax Consequences—Disposition of Units—Recognition of Gain or Loss" for a further discussion of the foregoing.

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

Investments in common units by tax-exempt entities, such as employee benefit plans and IRAs, and non-U.S. persons raise issues unique to them. For example, virtually all of our income allocated to organizations that are exempt from federal income tax, including IRAs and other retirement plans, will be unrelated business taxable income and will be taxable to them. Distributions to non-U.S. persons will be reduced by withholding taxes at the highest applicable effective tax rate, and non-U.S. persons will be required to file U.S. federal income tax returns and pay tax on their share of our taxable income. If you are a tax-exempt entity or a non-U.S. person, you should consult your tax advisor before investing in our common units.

If the IRS contests the federal income tax positions we take, the market for our common units may be adversely impacted and the cost of any IRS contest will reduce our cash available for distribution to you.

The IRS may adopt positions that differ from the positions we take. It may be necessary to resort to administrative or court proceedings to sustain some or all of the positions we take. A court may not agree with some or all of the positions we take. Any contest by the IRS, and the outcome of any IRS contest, may materially adversely impact the market for our common units and the price at which they trade. Our costs of any contest by the IRS will be borne indirectly by our unitholders and our general partner because the costs will reduce our cash available for distribution.

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

Because we cannot match transferors and transferees of common units, we will adopt depreciation, amortization and depletion 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. Our counsel is unable to opine as to the validity of this approach. It also could affect the timing of these tax benefits or the amount of gain from your sale of common units and could have a negative impact on the value of our common units or result in audit adjustments to your tax returns. Please read "Material U.S. Federal Income Tax Consequences—Tax Consequences of Unit Ownership—Section 754 Election" for a further discussion of the effect of the depreciation and amortization positions we will adopt.

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We will 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 common units each month based upon the ownership of our common units on the first day of each month, instead of on the basis of the date a particular common unit is transferred. Nonetheless, we will allocate certain deductions for depreciation of capital additions based upon the date the underlying property is placed in service. The use of this proration method may not be permitted under existing Treasury Regulations, and although the U.S. Treasury Department issued proposed Treasury Regulations allowing a similar monthly simplifying convention, such regulations are not final and do not specifically authorize the use of the proration method we will adopt. Accordingly, our counsel is unable to opine as to the validity of this method. If the IRS were to successfully challenge our proration method, we may be required to change the allocation of items of income, gain, loss, and deduction among our unitholders. Please read "Material U.S. Federal Income Tax Consequences—Disposition of Units—Allocations Between Transferors and Transferees."

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

Because there are no specific rules governing the federal income tax consequences of loaning a partnership interest, a unitholder whose common 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 federal income tax purposes as a partner with respect to those common 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 common units may not be reportable by the unitholder and any cash distributions received by the unitholder as to those common units could be fully taxable as ordinary income. Our counsel has not rendered an opinion regarding the treatment of a unitholder whose common units are the subject of a securities loan. Unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a loan to a short seller are urged to consult a tax advisor to discuss whether it is advisable to modify any applicable brokerage account agreements to prohibit their brokers from borrowing their common units.

Certain U.S. federal income tax preferences currently available with respect to coal exploration and development may be eliminated as a result of future legislation.

The 2015 Budget Proposal recommends elimination of certain key U.S. federal income tax preferences related to coal exploration and development. The 2015 Budget Proposal would (1) repeal expensing of exploration and development costs relating to coal, (2) repeal the percentage depletion allowance with respect to coal properties, (3) repeal capital gains treatment of coal royalties and (4) repeal the domestic manufacturing deduction for the production of coal. The passage of any legislation as a result of the 2015 Budget Proposal or any other similar changes in U.S. federal income tax laws could eliminate or defer certain tax deductions that are currently available with respect to coal exploration and development, and any such change could increase the taxable income allocable to our unitholders and negatively impact the value of an investment in our units.

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

In addition to federal income taxes, you will likely be subject to other taxes, including foreign, state and local taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we conduct business or own property now or in the future, even if you do not live in any of those jurisdictions. We will initially own assets and conduct business in Utah, Kentucky and Colorado, each of which currently imposes a personal income tax and also imposes income taxes on corporations and other entities. You may be required to file state and local income tax returns and pay state and local income taxes in these states. Further, you may be subject to penalties for failure to comply with those requirements. As we make acquisitions or expand our business, we may own assets or conduct business in additional states or foreign jurisdictions that impose a personal income tax. It is your responsibility to file all U.S. federal, foreign, state and local tax returns. Our counsel has not rendered an opinion on the foreign, state or local tax consequences of an investment in our common units.

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USE OF PROCEEDS

We expect to receive approximately $ million of net proceeds from the sale of common units by us in this offering (based on an assumed initial offering price of $ per common unit, the mid-point of the price range set forth on the cover page of this prospectus), after deducting the estimated underwriting discounts and offering expenses. Assuming the Escrow Release Conditions have been satisfied, concurrently with the closing of this offering, we expect to receive approximately $ million of net proceeds from our offering of $ million aggregate principal amount of New Notes. We intend to use the net proceeds of this offering and our offering of the New Notes as follows: (i) $ million to make a cash distribution to our sponsor, in part as reimbursement for capital expenditures, (ii) $ million to repay the PacifiCorp Notes, (iii) $ million to repay the Prudential Notes and (iv) $ million for general partnership purposes.

If the underwriters exercise their option to purchase additional common units in full, the additional net proceeds to us would be approximately $ million (based on an assumed initial offering price of $ per common unit, the mid-point of the price range set forth on the cover page of this prospectus). The net proceeds from any exercise of such option will be used to make a cash distribution to our sponsor, in part as reimbursement for capital expenditures. If the underwriters do not exercise their option, we will issue such additional common units to our sponsor upon the expiration of the option for no additional consideration.

The Prudential Notes bear interest at LIBOR (subject to a floor of 1%) plus a margin of 5.1% and are due in various monthly installments through 2016. CFC may prepay the Prudential Notes, in whole but not in part, by paying a 2% prepayment fee, which steps down to 1% after October 11, 2015, and certain out-of-pocket expenses incurred by the lenders. The Prudential Notes will mature in October 2016.

The PacifiCorps Notes bear interest at 7% and mature on (i) December 31, 2019, with respect to the $10 million note issued by Hunter Prep Plant, LLC and (ii) the earlier of August 31, 2015 or the refinancing of the Senior Secured Credit Facilities, with respect to the $30 million note issued by Fossil Rock Resources, LLC.

We expect that a portion of the net proceeds distributed to our sponsor will be used by our sponsor to repay outstanding indebtedness under our sponsor's Senior Secured Credit Facilities (defined herein). We expect that Cedars, which is directly or indirectly owned or controlled by certain of our directors and director nominees, will receive $ million (or $ million if the underwriters exercise their option to purchase additional units) of the net proceeds from this offering as a result of the distribution by our sponsor of a portion of the proceeds it receives from us, and that our executive officers will receive an aggregate of $ million (or $ million if the underwriters exercise their option to purchase additional units) in connection with this offering from the cash distribution made to our sponsor pursuant to a sponsor-level bonus arrangement. Please read "Certain Relationships and Related Party Transactions—Agreements with Affiliates in Connection with the Transactions—Ownership Interests in our Sponsor and Arrangements with Management."

Affiliates of certain of the underwriters are lenders under our sponsor's Senior Secured Credit Facilities and, accordingly, may ultimately receive a portion of the net proceeds from the offering of our New Notes. Certain of the underwriters are also initial purchasers in connection with the New Notes offering. Please read "Underwriting."

An increase or decrease in the initial public offering price of $1.00 per common unit would cause the net proceeds that we will receive from the offering, after deducting the estimated underwriting discounts and offering expenses, to increase or decrease by approximately $ million.

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DILUTION

Dilution is the amount by which the offering price paid by the purchasers of common units sold in this offering will exceed the pro forma net tangible book value per common unit after the offering. On a pro forma basis as of March 31, 2015, after giving effect to the offering of common units and the application of the related net proceeds, our net tangible book value was $ million, or $ per common unit. Purchasers of common units in this offering will experience immediate and substantial dilution in net tangible book value per common unit for financial accounting purposes, as illustrated in the following table:


Initial public offering price per common unit		$
Net tangible book value per common unit before the offering(1)
Increase in net tangible book value per common unit attributable to purchasers in the offering
Less: Pro forma net tangible book value per common unit after the offering(2)
Immediate dilution in tangible net book value per common unit to purchasers in the offering(3)(4)		$

(1): Determined by dividing the number of units ( common units and subordinated units) to be issued to our general partner and its affiliates, including our sponsor, for the contribution of assets and liabilities to us) into the net tangible book value of the contributed assets and liabilities.
(2): Determined by dividing the total number of units to be outstanding after the offering ( common units and subordinated units) into our pro forma net tangible book value, after giving effect to the application of the expected net proceeds of the offering.
(3): If the initial public offering price were to increase or decrease by $1.00 per common unit, then dilution in net tangible book value per common unit would equal $ and $ , respectively.
(4): Assumes the underwriters' option to purchase additional common units from us is not exercised. If the underwriters' option to purchase additional common units from us is exercised in full, the immediate dilution in net tangible book value per common unit to purchasers in this offering will be $ .

The following table sets forth the number of units that we will issue and the total consideration contributed to us by our general partner and its affiliates and by the purchasers of common units in this offering upon consummation of the transactions contemplated by this prospectus, assuming the underwriters' option to purchase additional common units is not exercised:

	Unit Acquired			Total Consideration

	Number	Percent		Amount	Percent
	(in thousands)
General partner and affiliates(a)(b)			%	$		%
Purchasers in the offering			%			%
Total			%	$		%

(a): The units issued to our general partner and its affiliates, including our sponsor, consist of common units and subordinated units.
(b): The assets contributed by our general partner and its affiliates were recorded at historical cost in accordance with GAAP. Book value of the consideration provided by our general partner and its

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affiliates, as of March 31, 2015, after giving effect to the application of the net proceeds of the offering, is as follows:

		(in thousands)

Book value of net assets contributed		$
Less: Reimbursement and distribution to our sponsor from net proceeds of the offering
Total consideration		$

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CAPITALIZATION

The following table sets forth our cash and cash equivalents and our capitalization as of March 31, 2015:

•: on an actual basis;
•: on an as adjusted basis, after giving effect to the Utah Transaction; and
•: on an as further adjusted basis, after giving effect to the IPO Reorganization, including this offering, the offering of the New Notes and the use of proceeds therefrom as described in "Use of Proceeds."

You should read this table together with "Prospectus Summary—IPO Reorganization and Partnership Structure," "Use of Proceeds," "Selected Historical and Pro Forma Financial and Other Data" and "Management's Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources" and our financial statements, along with the notes thereto, included elsewhere in this prospectus.

	As of March 31, 2015

	Actual		As Adjusted for the Utah Transaction		As Further Adjusted for the IPO Reorganization
	(in thousands)
Cash and cash equivalents	$	—	$	—	$



Long-term debt(1):
New Notes(2)	$	—	$	—	$
Revolving credit facility(3)		—		—
Senior Secured Credit Facilities(4)		334,705		334,705		—
Quitchupah Road debt(5)		25,816		25,816
Prudential Notes		10,767		10,767
PacifiCorp Notes		—		40,000		—
IPFS notes(6)		7,190		7,190

Total long-term debt	$	378,478	$	418,478	$

Partners' capital:
Limited partners:
Common unitholders—public		—		—
Common unitholders—sponsor		—		—
Subordinated unitholders—sponsor		—		—
General partner interest		—		—		—

Total partners' capital		—		—

Member's equity:
Total member's equity	$	8,066	$	8,066	$	—

Total capitalization	$	386,544	$	426,544	$

(1): Includes current portion of long-term debt.
(2): Prior to this offering, Finance Corp. issued $ million aggregate principal amount of % senior secured notes due . From and after the satisfaction of the Escrow Release Conditions, which we expect to occur concurrently with the closing of this offering, the partnership will become a co-issuer of the New Notes and a party to the indenture governing the New Notes. Please read "Management's Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Long-Term Debt—Senior Secured Notes."

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(3): In connection with the closing of this offering, we expect to enter into a $ million revolving credit facility. Please read "Management's Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Long-Term Debt—Revolving Credit Facility."
(4): In connection with the closing of this offering, CFC will be released as a guarantor under our sponsor's Senior Secured Credit Facilities (defined herein), and the liens on the assets contributed to us and securing borrowings under these facilities will be released. Please read "Management's Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Long-Term Debt—Senior Secured Credit Facilities."
(5): In 2012, CFC financed the construction of a paved country road through County Municipal Financing Bonds with Sevier County, Utah. Please read "Management's Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Long-Term Debt—Quitchupah Road Debt."
(6): In February 2015, our sponsor financed annual insurance premiums for its insurance policies through notes payable to Imperial Premium Financing Specialists ("IPFS"). Please read "Management's Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Long-Term Debt—Notes Payable to Imperial Premium Financing Specialists."

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CASH DISTRIBUTION POLICY AND RESTRICTIONS ON DISTRIBUTIONS

You should read the following discussion of our cash distribution policy in conjunction with the specific assumptions included in this section. In addition, you should read "Forward-Looking Statements" and "Risk Factors" for information regarding statements that do not relate strictly to historical or current facts and certain risks inherent in our business.

For additional information regarding our historical and pro forma combined results of operations, you should refer to the historical financial statements as well as our pro forma financial statements, included elsewhere in this prospectus.

General

Our Cash Distribution Policy

The board of directors of our general partner will adopt a cash distribution policy pursuant to which we intend to distribute at least the minimum quarterly distribution of $ per unit ($ per unit on an annualized basis) on all of our units to the extent we have sufficient cash after the establishment of cash reserves and the payment of our expenses, including payments to our general partner and its affiliates. We expect that if we are successful in executing our business strategy, we will grow our business in a steady and sustainable manner and distribute to our unitholders a portion of any increase in our cash available for distribution resulting from such growth. Our general partner has not caused us to establish any cash reserves, and does not have any specific types of expenses for which it intends to establish reserves. We expect our general partner may cause us to establish reserves for specific purposes, such as major capital expenditures or debt service payments, or may choose to generally reserve cash in the form of excess distribution coverage from time to time for the purpose of maintaining stability or growth in our quarterly distributions. In addition, our general partner may cause us to borrow amounts to fund distributions in quarters when we generate less cash than is necessary to sustain or grow our cash distributions per unit. Our cash distribution policy reflects a judgment that our unitholders will be better served by us distributing rather than retaining our cash available for distribution.

The board of directors of our general partner may change our distribution policy at any time and from time to time. Our partnership agreement does not require us to pay cash distributions on a quarterly or on any other basis.

Limitations on Cash Distributions and Our Ability to Change Our Cash Distribution Policy

There is no guarantee that we will make cash distributions to our unitholders. We do not have a legal or contractual obligation to pay distributions quarterly or on any other basis or at our minimum quarterly distribution rate or at any other rate. Our cash distribution policy is subject to certain restrictions and may be changed at any time. The reasons for such uncertainties in our stated cash distribution policy include the following factors:

•: Our cash distribution policy will be subject to restrictions on distributions under our revolving credit facility and the indenture governing our New Notes, which contain financial tests and covenants that we must satisfy. These financial tests and covenants are described in "Management's Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources." Should we be unable to satisfy these restrictions or if we are otherwise in default under our revolving credit facility or the indenture governing our New Notes, we will be prohibited from making cash distributions notwithstanding our stated cash distribution policy.
•: Our general partner will have the authority to cause us to establish cash reserves for the prudent conduct of our business, including for future cash distributions to our unitholders, and the

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establishment of or increase in those cash reserves could result in a reduction in cash distributions from levels we currently anticipate pursuant to our stated cash distribution policy. Our partnership agreement and our cash distribution policy do not set a limit on the amount of cash reserves that our general partner may cause us to establish.

•: We are obligated under our partnership agreement to reimburse our general partner for all expenses it incurs and payments it makes on our behalf. Our partnership agreement does not set a limit on the amount of expenses for which our general partner may be reimbursed. These expenses include salary, bonus, incentive compensation and other amounts paid to persons who perform services for us or on our behalf and expenses allocated to our general partner by its affiliates. Our partnership agreement provides that our general partner will determine the expenses that are allocable to us. We also expect to enter into an omnibus agreement with our sponsor, pursuant to which we will reimburse our sponsor on a cost-of-services basis for certain services performed on our behalf. The reimbursement of expenses and payment of fees, if any, to our general partner and our sponsor will reduce the amount of cash available to pay distributions to our unitholders. We expect that we will reimburse our sponsor and our general partner approximately $15.7 million in total for services performed under the partnership agreement and the omnibus agreement during the twelve months ending June 30, 2016.
•: Even if our cash distribution policy is not modified or revoked, the amount of distributions we pay under our cash distribution policy and the decision to make any distribution is determined by our general partner.
•: Under Section 17-607 of the Delaware Act, we may not make a distribution if the distribution would cause our liabilities to exceed the fair value of our assets.
•: We may lack sufficient cash to pay distributions to our unitholders due to cash flow shortfalls attributable to a number of operational, commercial or other factors as well as increases in our operating or general and administrative expenses, principal and interest payments on our outstanding debt, tax expenses, working capital requirements and anticipated cash needs.
•: If we make distributions out of capital surplus, as opposed to operating surplus, any such distributions would constitute a return of capital and would result in a reduction in the minimum quarterly distribution and the target distribution levels. Please read "How We Make Distributions To Our Partners—Adjustment to the Minimum Quarterly Distribution and Target Distribution Levels." We do not anticipate that we will make any distributions from capital surplus.
•: Our ability to make distributions to our unitholders depends on the performance of our subsidiaries and their ability to distribute cash to us. The ability of our subsidiaries to make distributions to us may be restricted by, among other things, the provisions of present and future indebtedness, applicable state limited liability company laws and other laws and regulations.

Our Ability to Grow May Be Dependent on Our Ability to Access External Expansion Capital

We expect to generally distribute a significant percentage of our cash from operations to our unitholders on a quarterly basis, after the establishment of cash reserves and payment of our expenses. Therefore, our growth may not be as fast as businesses that reinvest most or all of their cash to expand ongoing operations. We expect that we will rely primarily upon external financing sources, including bank borrowings and issuances of debt and equity interests, to fund our expansion capital expenditures. To the extent we are unable to finance growth externally, our cash distribution policy will significantly impair our ability to grow.

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Relationship with Our Sponsor

All of our revenue and cash flow will be derived from our coal supply agreements and we will receive substantially all of our revenue and cash flow from our new coal supply agreement with our sponsor. As we expect to derive substantially all of our revenues through our sponsor for the foreseeable future, we will be subject to the risk of nonpayment or nonperformance by our sponsor under the coal supply agreement between us and our sponsor. Any event, whether related to our operations or otherwise, that materially adversely affects our sponsor's financial condition, results of operations or cash flows may adversely affect our ability to sustain or increase cash distributions to our unitholders.

Our sponsor is a privately owned company and has no obligations to disclose publicly financial or operating information. Accordingly, our unitholders will have little to no insight into our sponsor's ability to meet its obligations to us and to our customers, including its minimum coal purchase commitments under the coal supply agreement between us and our sponsor. Our ability to make minimum quarterly distributions on all outstanding units will be adversely affected if: (i) our sponsor does not fulfill its obligations to us or our customers; or (ii) our sponsor's obligations under our coal supply agreement are suspended, reduced or terminated and we are unable to generate additional revenues from third parties.

Our Minimum Quarterly Distribution

Upon completion of this offering, our partnership agreement will provide for a minimum quarterly distribution of $ per unit for each whole quarter, or $ per unit on an annualized basis. The payment of the full minimum quarterly distribution on all of the common units and subordinated units to be outstanding after completion of this offering would require us to have cash available for distribution of approximately $ million per quarter, or $ million per year. Our ability to make cash distributions at the minimum quarterly distribution rate will be subject to the factors described above under "—General—Limitations on Cash Distributions and Our Ability to Change Our Cash Distribution Policy."

The table below sets forth the amount of common units and subordinated units that will be outstanding immediately after this offering, assuming the underwriters do not exercise their option to purchase additional common units, and the cash available for distribution needed to pay the aggregate minimum quarterly distribution on all of such units for a single fiscal quarter and a four quarter period:

	No Exercise of Underwriters' Option to Purchase Additional Common Units			Full Exercise of Underwriters' Option to Purchase Additional Common Units

	Aggregate Minimum Quarterly Distributions			Aggregate Minimum Quarterly Distributions
	Number of Units	One Quarter	Annualized (Four Quarters)	Number of Units	One Quarter	Annualized (Four Quarters)
Publicly held common units		$	$		$	$
Common units held by our sponsor
Subordinated units held by our sponsor

Total		$	$		$	$

If the underwriters do not exercise their option to purchase additional common units, we will issue common units to our sponsor at the expiration of the option period. If and to the extent the underwriters exercise their option to purchase additional common units, the number of common units purchased by the underwriters pursuant to such exercise will be issued to the underwriters and the remainder, if any, will be issued to our sponsor. Any such units issued to our sponsor will be issued for no additional consideration. Accordingly, the exercise of the underwriters' option will not affect the

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total number of units outstanding or the amount of cash needed to pay the minimum quarterly distribution on all units. Please read "Underwriting."

Our general partner will initially hold the incentive distribution rights, which entitle the holder to increasing percentages, up to a maximum of 50.0%, of the cash we distribute in excess of $ per unit per quarter.

We expect to pay our distributions on or about the last day of each of February, May, August and November to holders of record on or about the 15th day of each such month. We will adjust the quarterly distribution for the period after the closing of this offering through , 2015 based on the actual length of the period.

Subordinated Units

Our sponsor will initially own all of our subordinated units. The principal difference between our common units and subordinated units is that for any quarter during the subordination period, holders of the subordinated units are not entitled to receive any distribution from operating surplus until the common units have received the minimum quarterly distribution from operating surplus for such quarter plus any arrearages in the payment of the minimum quarterly distribution from prior quarters. Subordinated units will not accrue arrearages. When the subordination period ends, all of the subordinated units will convert into an equal number of common units.

To the extent we do not pay the minimum quarterly distribution from operating surplus on our common units, our common unitholders will not be entitled to receive such payments in the future except during the subordination period. To the extent we have cash available for distribution from operating surplus in any future quarter during the subordination period in excess of the amount necessary to pay the minimum quarterly distribution to holders of our common units, we will use this excess cash to pay any distribution arrearages on common units related to prior quarters before any cash distribution is made to holders of subordinated units. Please read "How We Make Distributions To Our Partners—Subordination Period."

In the sections that follow, we present in detail the basis for our belief that we will be able to fully fund our minimum quarterly distribution of $ per common and subordinated unit each quarter for the twelve months ending June 30, 2016. In those sections, we present the following three tables:

•: "Unaudited Pro Forma Cash Available for Distribution," in which we present our estimate of the amount of cash we would have had available for distribution for the year ended December 31, 2014 and the twelve months ended March 31, 2015, based on our historical financial statements, as adjusted to reflect incremental general and administrative expenses we expect we will incur as a publicly traded partnership.
•: "Estimated Cash Available for Distribution," in which we demonstrate our anticipated ability to generate the cash available for distribution necessary for us to pay the minimum quarterly distribution on all units for the twelve months ending June 30, 2016.
•: "Quarterly Forecast Information," in which we present our estimated cash available for distribution for the twelve months ending June 30, 2016 on a quarter-by-quarter basis for the forecast period.

Unaudited Pro Forma Cash Available for Distribution

As set forth in the table below, we believe that our pro forma cash available for distribution for the year ended December 31, 2014 and the twelve months ended March 31, 2015, if we had completed this offering and the IPO Reorganization described under "Prospectus Summary—IPO Reorganization

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and Partnership Structure" on January 1, 2014, in each case, would not have been sufficient to pay the full minimum quarterly distribution on all of our common and subordinated units during that period.

Unaudited pro forma cash available for distribution includes incremental general and administrative expenses that we expect we will incur as a publicly traded partnership, including costs associated with SEC and Sarbanes-Oxley reporting requirements, annual and quarterly reports to unitholders, tax return and Schedule K-1 preparation and distribution, independent auditor fees, investor relations activities, registrar and transfer agent fees, incremental director and officer liability insurance costs and director compensation.

Our unaudited pro forma condensed consolidated financial statements, upon which our unaudited pro forma cash available for distribution is based, do not purport to present our results of operations had the IPO Reorganization actually been completed as of the date indicated. Furthermore, cash available for distribution is a cash accounting concept, while our combined financial statements have been prepared on an accrual basis. We derived the amounts of pro forma cash available for distribution stated above in the manner described in the table below. As a result, the amount of pro forma cash available for distribution should only be viewed as a general indication of the amount of cash available for distribution that we might have generated had we been formed and completed the transactions contemplated in this prospectus in earlier periods.

Our pro forma condensed consolidated financial statements are derived from the historical financial statements of CFC, included elsewhere in this prospectus. Our pro forma condensed consolidated financial statements should be read together with "Selected Historical and Pro Forma Financial and Other Data," "Management's Discussion and Analysis of Financial Condition and Results of Operations" and the historical financial statements of CFC included elsewhere in this prospectus.

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	Year Ended December 31, 2014	Twelve Months Ended March 31, 2015

	(in thousands, except per unit and per ton data)
Operating Data:
Tons produced
Tons sold
Coal sales realized per ton(1)	$	$
Direct mining costs per ton(2)	$	$
Financial Data:
Coal sales	$	$
Other revenues, net
Costs and expenses:
Cost of coal sales, exclusive of items shown separately below
Transportation
Depreciation, depletion and amortization
Accretion on asset retirement obligations
Selling, general and administrative
Amortization of acquired sales contracts, net

Operating income	$	$
Other expenses:
Interest expense and related financing costs
Loss (gain) on sale of assets
Other

Pro forma net income	$	$
Adjustments to reconcile to pro forma EBITDA:
Add:
Depreciation, depletion and amortization
Amortization of acquired sales contracts, net
Interest expense and related financing costs

Pro forma EBITDA(3)	$	$
Adjustments to reconcile to pro forma Adjusted EBITDA:
Add:
Accretion on asset retirement obligations
Loss (gain) on sale of assets
Other

Pro forma Adjusted EBITDA(3)	$	$
Adjustments to reconcile to pro forma cash available for distribution:
Add:
Net proceeds from this offering or borrowings to fund capital expenditures(4)
Less:
Incremental general and administrative expense(5)
Cash interest expense
Expansion capital expenditures
Actual maintenance expenditures

Pro forma cash available for distribution	$	$
Minimum quarterly distribution per unit (annualized)	$	$
Distributions (annualized):
Distributions to common unitholders—public	$	$
Distributions to common unitholders—sponsor
Distributions to subordinated unitholders—sponsor

Total distributions	$	$

Excess (shortfall)	$	$

(1): Coal sales realized per ton is defined as coal sales divided by tons sold.

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(2): Direct mining costs per ton is defined as cost of coal sales, exclusive of items shown separately, divided by tons sold.
(3): For more information, please read "Prospectus Summary—Summary Historical and Pro Forma Financial and Other Data."
(4): We expect to retain approximately $ million of the net proceeds from this offering and borrow $ million under our new revolving credit facility to fund capital expenditures.
(5): Reflects incremental general and administrative expenses that we expect to incur as a result of operating as a publicly traded partnership that are not reflected in our pro forma financial statements.

Estimated Cash Available for Distribution

The following table sets forth our calculation of forecasted cash available for distribution to our unitholders and general partner for the twelve months ending June 30, 2016. We forecast that our cash available for distribution generated during the twelve months ending June 30, 2016 will be approximately $ million. This amount in the aggregate would be sufficient to pay the minimum quarterly distribution of $ per unit on all of our common and subordinated units for each quarter during this period. Since our revenue and cash available for distribution will likely fluctuate over time as a result of changes in coal prices as well as other factors, the board of directors of our general partner expects to reserve all or a portion of any cash generated in excess of the amount sufficient to pay the full minimum quarterly distribution on all units, as a whole, to allow us to maintain and to gradually increase our quarterly cash distributions.

We are providing the financial forecast to supplement our historical consolidated financial statements in support of our belief that we will have sufficient cash available to allow us to pay distributions on all of our common and subordinated units for each quarter in the twelve months ending June 30, 2016 at the minimum quarterly distribution rate. Please read "—Significant Assumptions and Considerations" for further information as to the assumptions we have made for the financial forecast. Please read "Management's Discussion and Analysis of Financial Condition and Results of Operations—Critical Accounting Policies and Estimates" for information as to the accounting policies we have followed for the financial forecast.

Our forecast reflects our judgment as of the date of this prospectus of conditions we expect to exist and the course of action we expect to take during the twelve months ending June 30, 2016. We believe that our actual results of operations will approximate those reflected in our forecast, but we can give no assurance that our forecasted results will be achieved. If our estimates are not achieved, we may not be able to pay distributions on our common and subordinated units at the minimum quarterly distribution rate of $ per unit each quarter (or $ per unit on an annualized basis) or any other rate. The assumptions and estimates underlying the forecast are inherently uncertain and, though we consider them reasonable as of the date of this prospectus, are subject to a wide variety of significant business, economic, and competitive risks and uncertainties that could cause actual results to differ materially from those contained in the forecast, including, among others, risks and uncertainties contained in "Risk Factors." Accordingly, there can be no assurance that the forecast is indicative of our future performance or that actual results will not differ materially from those presented in the forecast. Inclusion of the forecast in this prospectus should not be regarded as a representation by any person that the results contained in the forecast will be achieved.

We do not, as a matter of course, make public forecasts as to future sales, earnings or other results. However, we have prepared the following forecast to present the forecasted cash available for distribution to our unitholders and general partner during the forecasted period. The accompanying forecast was not prepared with a view toward complying with the guidelines established by the American Institute of Certified Public Accountants with respect to prospective financial information, but, in our view, was prepared on a reasonable basis, reflects the best currently available estimates and judgments, and presents, to the best of management's knowledge and belief, the expected course of

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action and our expected future financial performance. However, this information is not necessarily indicative of future results.

Neither our independent auditors, nor any other independent accountants, have compiled, examined or performed any procedures with respect to the forecast contained herein, nor have they expressed any opinion or any other form of assurance on such information or its achievability, and assume no responsibility for, and disclaim any association with, the forecast. We do not undertake to release publicly after this offering any revisions or updates to the financial forecast or the assumptions on which our forecasted results of operations are based.

		Twelve Months Ending June 30, 2016

		(in thousands, except per unit and per ton data)
Operating Data:
Tons produced
Tons sold
Coal sales realized per ton(1)		$
Direct mining costs per ton(2)		$
Financial Data:
Coal sales		$
Other revenues, net
Costs and expenses:
Cost of coal sales, exclusive of items shown separately below
Transportation
Depreciation, depletion and amortization
Accretion on asset retirement obligations
Selling, general and administrative
Amortization of acquired sales contracts, net

Operating income		$
Other expenses:
Interest expense and related financing costs

Net income		$
Adjustments to reconcile to EBITDA:
Add:
Depreciation, depletion and amortization
Amortization of acquired sales contracts, net
Interest expense and related financing costs

EBITDA(3)		$
Adjustments to reconcile to Adjusted EBITDA:
Add:
Accretion on asset retirement obligations

Adjusted EBITDA(3)		$
Adjustments to reconcile to estimated cash available for distribution:
Add:
Net proceeds from this offering or borrowings to fund capital expenditures(4)
Less:
Cash interest expense
Expansion capital expenditures
Accrual for maintenance capital expenditures(5)

Estimated cash available for distribution		$
Minimum quarterly distribution per unit (annualized)		$

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		Twelve Months Ending June 30, 2016

		(in thousands, except per unit and per ton data)
Distributions (annualized):
Estimated distributions to common unitholders—public		$
Estimated distributions to common unitholders—sponsor
Estimated distributions to subordinated unitholders—sponsor

Total distributions		$

Excess		$

(1): Coal sales realized per ton is defined as coal sales divided by tons sold.
(2): Direct mining costs per ton is defined as cost of coal sales, exclusive of items shown separately, divided by tons sold.
(3): For more information, please read "Prospectus Summary—Summary Historical and Pro Forma Financial and Other Data."
(4): We expect to retain approximately $ million of the net proceeds from this offering and borrow $ million under our new revolving credit facility to fund capital expenditures.
(5): Reflects the annual accrual necessary to fund the estimated cost to maintain our long-term operating capacity or net income. Please read "How We Make Distributions To Our Partners—Operating Surplus and Capital Surplus—Capital Expenditures."

Significant Assumptions and Considerations

The forecast has been prepared by and is the responsibility of our management. Our forecast reflects our judgment as of the date of this prospectus of conditions we expect to exist and the course of action we expect to take during the twelve months ending June 30, 2016. While the assumptions disclosed in this prospectus are not all-inclusive, the assumptions listed are those that we believe are significant to our forecasted results of operations. We believe we have a reasonable objective basis for these assumptions. We believe our actual results of operations will approximate those reflected in our forecast, but we can give no assurance that our forecasted results will be achieved. There will likely be differences between our forecast and the actual results, and those differences could be material. If the forecast is not achieved, we may not be able to pay cash distributions on our common units at the minimum distribution rate or at all.

Coal Sales

We estimate that our coal sales for the twelve months ending June 30, 2016 will be approximately $ million, as compared to approximately $ million for the year ended December 31, 2014 and $ million for the twelve months ended March 31, 2015. Our forecast is based on the following assumptions:

•: We estimate that we will produce million tons of coal for the twelve months ending June 30, 2016, as compared to million tons produced for the year ended December 31, 2014 and million tons produced for the twelve months ended March 31, 2015. Production from our coal operations for the forecast period is expected to increase from the year ended December 31, 2014 and the twelve months ended March 31, 2015 based on increased production at all three of our mines.
•: We estimate that we will sell million tons of coal for the twelve months ending June 30, 2016 as compared to million tons sold for the year ended December 31, 2014 and million tons for the twelve months ended March 31, 2015. Tons sold for the forecast period is expected to increase from the year ended December 31, 2014 and the twelve months ended March 31, 2015 due to increased sales from our Sufco mine.

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•: We estimate that our coal sales realized per ton (defined as coal sales per ton sold) will be $ for the twelve months ending June 30, 2016, as compared to $ for the year ended December 31, 2014 and $ for the twelve months ended March 31, 2015. The increase in realization from both periods is driven primarily by scheduled contractual price increases under our coal supply agreements.

Cost of Coal Sales, Exclusive of Items Shown Separately

We estimate that our cost of coal sales, exclusive of items shown separately (as defined in Appendix B), for the twelve months ending June 30, 2016 will be approximately $ million, as compared to approximately $ million for the year ended December 31, 2014 and $ million for the twelve months ended March 31, 2015. Our forecast is based on the following assumptions:

•: We estimate that we will increase production during the forecast period by % and %, compared to the year ended December 31, 2014 and the twelve months ended March 31, 2015, respectively.
•: We forecast that our direct mining costs per ton (defined as cost of coal sales, exclusive of items shown separately, divided by tons sold) will be $ for the twelve months ending June 30, 2016 as compared to $ for the year ended December 31, 2014 and $ for the twelve months ended March 31, 2015. The increase in direct mining costs per ton versus the year ended December 31, 2014 and the twelve months ended March 31, 2015 is primarily driven by increased coal preparation costs for deliveries to the Hunter Power Plant.

Our forecast cost of coal sales, exclusive of items shown separately, could vary significantly because of a large number of variables, many of which are beyond our control.

Transportation

We estimate that transportation expense for the twelve months ending June 30, 2016 will be approximately $ million, as compared to approximately $ million for the year ended December 31, 2014 and $ million for the twelve months ended March 31, 2015. The increase in transportation expense for the forecast period is due to additional coal sales under our new 15-year coal supply agreement with PacifiCorp for delivery to the Huntington Power Plant that will be supplied via truck from our Skyline mine. These costs are primarily passed through to the customer.

Depreciation, Depletion and Amortization

We estimate that depreciation, depletion and amortization for the twelve months ending June 30, 2016 will be approximately $ million, as compared to approximately $ million for the year ended December 31, 2014 and $ million for the twelve months ended March 31, 2015. The decrease in depreciation, depletion and amortization is primarily attributable to our expectation that, during the forecast period, we will obtain control of reserves previously identified as non-reserve coal deposits, which will increase the lives of our mines.

Selling, General and Administrative

We estimate that selling, general and administrative expenses for the twelve months ending June 30, 2016 will be approximately $ million, as compared to approximately $ million for the year ended December 31, 2014 and $ million for the twelve months ended March 31, 2015. The decrease in selling, general and administrative expenses during the forecast period as compared to the year ended December 31, 2014 and the twelve months ended March 31, 2015 is primarily due to lower professional fees related to acquisitions.

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Amortization of Acquired Sales Contracts

We estimate that amortization of acquired sales contracts for the twelve months ending June 30, 2016 will be approximately $ million, as compared to approximately $ million for the year ended December 31, 2014 and $ million for the twelve months ended March 31, 2015. The decrease during the forecast period from the year ended December 31, 2014 and the twelve months ended March 31, 2015 is due to the amortization period of the acquired sales contracts ending on December 31, 2015.

Interest Expense, Net

We estimate that interest expense for the twelve months ending June 30, 2016 will be approximately $ million, as compared to approximately $ million for the year ended December 31, 2014 and $ million for the twelve months ended March 31, 2015. The decrease in interest expense during the forecast period as compared to the year ended December 31, 2014 and the twelve months ended March 31, 2015 is due to principal payments on long-term debt.

Capital Expenditures

Our partnership agreement will distinguish between maintenance capital expenditures (which are cash expenditures made to maintain our long-term operating capacity or net income) and expansion capital expenditures (which are cash expenditures, including transaction expenses, made to increase our operating capacity or net income over the long term). We forecast capital expenditures for the twelve months ending June 30, 2016 based on the following assumptions:

•: We estimate that our maintenance capital expenditures for the twelve months ending June 30, 2016 will be approximately $ million, as compared to approximately $ million for the year ended December 31, 2014 and $ million for the twelve months ended March 31, 2015. The increase in capital expenditures as compared to the year ended December 31, 2014 and the twelve months ended March 31, 2015 is primarily due to rebuilding equipment at, and the extension of existing mine development of, the Sufco and Skyline mines.
•: We do not currently expect to have any expansion capital expenditures for the twelve months ending June 30, 2016. For purposes of this presentation, we have assumed that all expansion capital expenditures will be funded with borrowings or cash on hand.

Estimated maintenance capital expenditures reduce operating surplus, but expansion capital expenditures, actual maintenance capital expenditures and investment capital expenditures do not. Maintenance capital expenditures are those expenditures made to maintain our long-term operating capacity or net income. Examples of maintenance capital expenditures include expenditures associated with the replacement of equipment and coal reserves, whether through the extension of an existing mine or the acquisition or development of new reserves, to the extent such expenditures are made to maintain, over the long term, our operating capacity or net income as they exist at such time as the capital expenditures are made. Maintenance capital expenditures will also include interest (and related fees) on debt incurred and distributions on equity issued (including incremental distributions on incentive distribution rights) to finance all or any portion of the construction or development of a replacement asset that is paid in respect of the period that begins when we enter into a binding obligation to commence constructing or developing a replacement asset and ending on the earlier to occur of the date that any such replacement asset commences commercial service and the date that it is abandoned or disposed of. Our general partner will review all capital expenditures on an annual basis in connection with the budget process and on a quarterly basis at the time expenditures are made to determine which expenditures increase current operating capacity or net income over the long term. Factors our general partner will consider include an assessment of current operating capacity or net income of the mine at the time of the expenditure and an evaluation of whether the expenditure will increase the mine's capacity or net income or whether the expenditure will replace current operating

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capacity or net income. To the extent the capital expenditure increases operating capacity or net income in a sustainable way, it will be classified as an expansion capital expenditure in the period in which the expenditure was made. Otherwise, it will be considered a maintenance capital expenditure. As an example, the capital expenditure related to the development of a new mine would be considered an expansion capital expenditure since it increases the current operating capacity or net income over the long term. In contrast, the rebuild of a pre-existing continuous miner unit would be considered a maintenance capital expenditure as it would not result in a sustainable, long-term increase to our operating capacity or net income but rather will maintain our current operating capacity. Cash expenditures made solely for investment purposes will not be considered maintenance capital expenditures.

On June 17, 2015, we were notified by the BLM, as part of the lease by application process, that we submitted the only bid in the competitive lease sale of the Flat Canyon tract held on June 17, 2015. On June 19, 2015, we were notified by the BLM, as part of the lease by application process, that our bid met or exceeded the BLM's estimate of the fair market value of the tract. The Flat Canyon tract contains proven and probable reserves that are contiguous to the coal reserves we are mining at our Skyline mine, and as such, our development and mining of the proven and probable reserves in the Flat Canyon tract will not require capital expenditures for additional surface infrastructure. The Flat Canyon tract is expected to extend the useful life of our Skyline mine, and we do not currently expect that, at the time capital expenditures are made to develop the Flat Canyon tract, such expenditures will increase, over the long term, our operating capacity or net income in place at such time. We currently expect that the capital expenditures we incur in developing the Flat Canyon tract will be categorized as maintenance capital expenditures. The issuance by the BLM of the lease of the Flat Canyon tract remains subject to a 30-day antitrust review by the U.S. Department of Justice. The leasing action could also be challenged in the Department of Interior's Board of Land Appeals or in federal district court. The May 15, 2015 Notice of Lease Sale of the Flat Canyon tract prompted letters by several non-governmental organizations objecting to the lease sale on, among other things, environmental grounds. Please read "Business—Coal Reserves and Non-Reserve Coal Deposits—Reserve Acquisition Process."

On June 5, 2015, we acquired the Fossil Rock reserves from an affiliate of PacifiCorp. We believe the Fossil Rock reserves will provide a natural replacement for the low sulfur coal currently produced by our Sufco mine from the Upper Hiawatha seam, which we expect to be exhausted in the third quarter of 2021. We currently expect that the capital expenditures we incur in building the necessary surface infrastructure at and developing the Fossil Rock reserves will be categorized as maintenance capital expenditures. However, depending on market conditions and our ability to produce and sell coal from the Sufco mine's Lower Hiawatha seam (assuming our receipt of the Greens Hollow tract from the BLM through the lease by application process), it is possible that we may make capital expenditures with respect to the Fossil Rock reserves that could be viewed as increasing our operating capacity or net income, and thus such capital expenditures could be categorized as expansion capital expenditures. For more information regarding the lease by application process, please see "Business—Coal Reserves and Non-Reserve Coal Deposits—Reserve Acquisition Process."

Regulatory, Industry and Economic Factors

We forecast our results of operations for the twelve months ending June 30, 2016 based on the following assumptions related to regulatory, industry and economic factors:

•: no material nonperformance or credit-related defaults by suppliers, customers or vendors, or shortage of skilled labor;
•: all supplies and commodities necessary for production and sufficient transportation will be readily available;

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•: no new federal, state or local regulation of the portions of the mining industry in which we operate or any interpretation of existing regulation that in either case will be materially adverse to our business;
•: no material unforeseen geological conditions or equipment problems at our mining locations; and
•: no material accidents, releases, weather-related incidents, unscheduled downtime or similar unanticipated events.

Quarterly Forecast Information

The following table sets forth our calculation of forecasted cash available for distribution to our unitholders and general partner on a quarter-by-quarter basis for the forecast period. The following forecast reflects our judgment as of the date of this prospectus of conditions we expect to exist and the course of action we expect to take for the twelve months ending June 30, 2016. Please see "—Significant Assumptions and Considerations." The assumptions and considerations underlying the forecast for the twelve months ending June 30, 2016 are inherently uncertain, and estimating the precise quarter in which each revenue and expense will be recognized increases the level of uncertainty

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of the quarterly forecast information. Accordingly, actual quarter-by-quarter results may differ materially from the quarter-by-quarter forecast information presented below.

	Three Months Ending September 30, 2015	Three Months Ending December 31, 2015	Three Months Ending March 31, 2016	Three Months Ending June 30, 2016

	(in thousands, except per unit and per ton data)
Operating Data:
Tons produced
Tons sold
Coal sales realized per ton(1)	$	$	$	$
Direct mining costs per ton(2)	$	$	$	$
Financial Data:
Coal sales	$	$	$	$
Other revenues, net
Costs and expenses:
Cost of coal sales, exclusive of items shown separately below
Transportation
Depreciation, depletion and amortization
Accretion on asset retirement obligations
Selling, general and administrative
Amortization of acquired sales contracts, net

Operating income	$	$	$	$
Other expenses:
Interest expense and related financing costs

Net income	$	$	$	$
Adjustments to reconcile to EBITDA:
Add:
Depreciation, depletion and amortization
Amortization of acquired sales contracts, net
Interest expense and related financing costs

EBITDA(3)	$	$	$	$
Adjustments to reconcile to Adjusted EBITDA:
Add:
Accretion on asset retirement obligations

Adjusted EBITDA(3)	$	$	$	$
Adjustments to reconcile to estimated cash available for distribution:
Add:
Net proceeds from this offering or borrowings to fund capital expenditures(4)
Less:
Cash interest expense
Expansion capital expenditures
Accrual for maintenance capital expenditures(5)

Estimated cash available for distribution	$	$	$	$
Minimum quarterly distribution per unit	$	$	$	$

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	Three Months Ending September 30, 2015	Three Months Ending December 31, 2015	Three Months Ending March 31, 2016	Three Months Ending June 30, 2016

	(in thousands, except per unit and per ton data)
Distributions:
Estimated distributions to common unitholders—public	$	$	$	$
Estimated distributions to common unitholders—sponsor
Estimated distributions to subordinated unitholders—sponsor

Total distributions	$	$	$	$

Excess	$	$	$	$

(1): Coal sales realized per ton is defined as coal sales divided by tons sold.
(2): Direct mining costs per ton is defined as cost of coal sales, exclusive of items shown separately, divided by tons sold.
(3): For more information, please read "Prospectus Summary—Summary Historical and Pro Forma Financial and Other Data."
(4): We expect to retain approximately $ million of the net proceeds from this offering and borrow $ million under our new revolving credit facility to fund capital expenditures.
(5): Reflects the annual accrual necessary to fund the estimated cost to maintain our long-term operating capacity or net income. Please read "How We Make Distributions To Our Partners—Operating Surplus and Capital Surplus—Capital Expenditures."

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HOW WE MAKE DISTRIBUTIONS TO OUR PARTNERS

General

Our partnership agreement provides that our general partner will make a determination as to whether to make a distribution, but our partnership agreement does not require us to pay distributions at any time or in any amount. Instead, the board of directors of our general partner will adopt a cash distribution policy to be effective as of the closing of this offering that will set forth our general partner's intention with respect to the distributions to be made to unitholders. Pursuant to our cash distribution policy, within 60 days after the end of each quarter, beginning with the quarter ending , 2015, we intend to distribute to the holders of common and subordinated units on a quarterly basis at least the minimum quarterly distribution of $ per unit, or $ on an annualized basis, to the extent we have sufficient cash after establishment of cash reserves and payment of fees and expenses, including payments to our general partner and its affiliates. We will prorate the quarterly distribution for the period after the closing of this offering through , 2015.

The board of directors of our general partner may change the foregoing distribution policy at any time and from time to time, and even if our cash distribution policy is not modified or revoked, the amount of distributions paid under our policy and the decision to make any distribution is determined by our general partner. Our partnership agreement does not contain a requirement for us to pay distributions to our unitholders, and there is no guarantee that we will pay the minimum quarterly distribution, or any distribution, on the units in any quarter. However, our partnership agreement does contain provisions intended to motivate our general partner to make steady, increasing and sustainable distributions over time.

Set forth below is a summary of the significant provisions of our partnership agreement that relate to cash distributions.

Operating Surplus and Capital Surplus

General

Any distributions we make will be characterized as made from "operating surplus" or "capital surplus." Distributions from operating surplus are made differently than cash distributions that we would make from capital surplus. Operating surplus distributions will be made to our unitholders and, if we make quarterly distributions above the first target distribution level described below, to the holder of our incentive distribution rights. We do not anticipate that we will make any distributions from capital surplus. In such an event, however, any capital surplus distribution would be made pro rata to all unitholders, but the incentive distribution rights would generally not participate in any capital surplus distributions. Any distribution from capital surplus would result in a reduction of the minimum quarterly distribution and target distribution levels and, if we reduce the minimum quarterly distribution to zero and eliminate any unpaid arrearages, thereafter capital surplus would be distributed as if it were operating surplus and the incentive distribution rights would thereafter be entitled to participate in such distributions. Please read "—Distributions From Capital Surplus."

Operating Surplus

We define operating surplus as:

•: $ million (as described below); plus
•: all of our cash receipts after the closing of this offering, excluding cash from interim capital transactions (as defined below) and provided that cash receipts from the termination of any hedge contract prior to its stipulated settlement or termination date will be included in equal quarterly installments over the remaining scheduled life of such hedge contract had it not been terminated; plus

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•: cash distributions paid in respect of equity issued (including incremental distributions on incentive distribution rights), other than equity issued in this offering, to finance all or a portion of expansion capital expenditures in respect of the period that commences when we enter into a binding obligation for the acquisition, construction, development or expansion and ending on the earlier to occur of the date any acquisition, construction, development or expansion commences commercial service and the date that it is disposed of or abandoned; plus
•: cash distributions paid in respect of equity issued (including incremental distributions on incentive distribution rights) to pay the construction period interest on debt incurred, or to pay construction period distributions on equity issued, to finance the expansion capital expenditures referred to above, in each case, in respect of the period that commences when we enter into a binding obligation for the acquisition, construction, development or expansion and ending on the earlier to occur of the date any acquisition, construction, development or expansion commences commercial service and the date that it is disposed of or abandoned; plus
•: an amount equal to the net proceeds from this offering that are retained for general partnership purposes, up to the amount of accounts receivable distributed to our sponsor prior to the closing of this offering; less
•: all of our operating expenditures (as defined below) after the closing of this offering; less
•: the amount of cash reserves established by our general partner to provide funds for future operating expenditures; less
•: all working capital borrowings not repaid within twelve months after having been incurred or repaid within such twelve month period with the proceeds of additional working capital borrowings; less
•: any cash loss realized on disposition of an investment capital expenditure.

Disbursements made, cash received (including working capital borrowings) or cash reserves established, increased or reduced after the end of a period but on or before the date on which cash or cash equivalents will be distributed with respect to such period shall be deemed to have been made, received, established, increased or reduced, for purposes of determining operating surplus, within such period if our general partner so determines. Furthermore, cash received from an interest in an entity for which we account using the equity method will not be included to the extent it exceeds our proportionate share of that entity's operating surplus (calculated as if the definition of operating surplus applied to such entity from the date of our acquisition of such an interest without any basket similar to that described in the first bullet above). Operating surplus does not reflect cash generated by our operations. For example, it includes a basket of $ million that will enable us, if we choose, to distribute as operating surplus cash we receive in the future from non-operating sources such as asset sales, issuances of securities and long-term borrowings that would otherwise be distributed as capital surplus. In addition, the effect of including, as described above, certain cash distributions on equity interests in operating surplus will be to increase operating surplus by the amount of any such cash distributions. As a result, we may also distribute as operating surplus up to the amount of any such cash that we receive from non-operating sources.

The proceeds of working capital borrowings increase operating surplus and repayments of working capital borrowings are generally operating expenditures, as described below, and thus reduce operating surplus when made. However, if a working capital borrowing is not repaid during the twelve-month period following the borrowing, it will be deducted from operating surplus at the end of such period, thus decreasing operating surplus at such time. When such working capital borrowing is in fact repaid, it will be excluded from operating expenditures because operating surplus will have been previously reduced by the deduction.

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We define operating expenditures in our partnership agreement, and it generally means all of our cash expenditures, including taxes, reimbursement of expenses to our general partner or its affiliates, payments made under hedge contracts (provided that (1) with respect to amounts paid in connection with the initial purchase of a hedge contract, such amounts will be amortized over the life of the applicable hedge contract and (2) payments made in connection with the termination of any hedge contract prior to the expiration of its stipulated settlement or termination date will be included in operating expenditures in equal quarterly installments over the remaining scheduled life of such hedge contract), officer compensation, repayment of working capital borrowings, interest on indebtedness and estimated maintenance capital expenditures (as discussed in further detail below), provided that operating expenditures will not include:

•: repayment of working capital borrowings deducted from operating surplus pursuant to the penultimate bullet point of the definition of operating surplus above when such repayment actually occurs;
•: payments (including prepayments and prepayment penalties and the purchase price of indebtedness that is repurchased and cancelled) of principal of and premium on indebtedness, other than working capital borrowings;
•: expansion capital expenditures;
•: actual maintenance capital expenditures;
•: investment capital expenditures;
•: payment of transaction expenses relating to interim capital transactions;
•: distributions to our partners (including distributions in respect of our incentive distribution rights);
•: repurchases of equity interests except to fund obligations under employee benefit plans; or
•: any other expenditures or payments using the proceeds of this offering that are described in "Use of Proceeds."

Capital Surplus

Capital surplus is defined in our partnership agreement as any cash distributed in excess of our operating surplus. Accordingly, capital surplus would generally be generated only by the following (which we refer to as "interim capital transactions"):

•: borrowings other than working capital borrowings;
•: sales of our equity interests; and
•: sales or other dispositions of assets for cash, other than inventory, accounts receivable and other assets sold in the ordinary course of business or as part of normal retirement or replacement of assets.

Characterization of Cash Distributions

Our partnership agreement provides that we treat all cash distributed as coming from operating surplus until the sum of all cash distributed since the closing of this offering (other than any distributions of proceeds of this offering) equals the operating surplus from the closing of this offering. Our partnership agreement provides that we treat any amount distributed in excess of operating surplus, regardless of its source, as distributions of capital surplus. We do not anticipate that we will make any distributions from capital surplus.

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Capital Expenditures

Our partnership agreement will distinguish between maintenance capital expenditures (which are cash expenditures made to maintain our long-term operating capacity or net income), expansion capital expenditures (which are cash expenditures, including transaction expenses, made to increase our operating capacity or net income over the long-term) and investment capital expenditures (capital expenditures that are neither maintenance capital expenditures nor expansion capital expenditures). Our general partner will determine the amount of expenditures made to maintain or increase our long-term operating capacity or net income.

Estimated maintenance capital expenditures reduce operating surplus, but expansion capital expenditures, actual maintenance capital expenditures and investment capital expenditures do not. Examples of maintenance capital expenditures include expenditures associated with the replacement of equipment and coal reserves, whether at an existing mine or the acquisition or development of new reserves, to the extent such expenditures are made to maintain our then current operating capacity or net income as they exist at such time as the capital expenditures are made. Maintenance capital expenditures will also include interest (and related fees) on debt incurred and distributions on equity issued (including incremental distributions on incentive distribution rights) to finance all or any portion of the construction or development of a replacement asset that is paid in respect of the period that begins when we enter into a binding obligation to commence constructing or developing a replacement asset and ending on the earlier to occur of the date that any such replacement asset commences commercial service and the date that it is abandoned or disposed of. Our general partner will review all capital expenditures on an annual basis in connection with the budget process and on a quarterly basis at the time expenditures are made to determine which expenditures increase current operating capacity or net income over the long term. Factors our general partner will consider include an assessment of current operating capacity or net income of the mine at the time of the expenditure and an evaluation of whether the expenditure will increase the mine's capacity or net income or whether the expenditure will replace current operating capacity or net income. To the extent the capital expenditure increases operating capacity or net income over the long term, it will be classified as an expansion capital expenditure in the period in which the expenditure was made. Otherwise, it will be considered a maintenance capital expenditure. Cash expenditures made solely for investment purposes will not be considered maintenance capital expenditures.

Because our maintenance capital expenditures can be irregular, the amount of our actual maintenance capital expenditures may differ substantially from period to period, which could cause similar fluctuations in the amounts of operating surplus if we subtracted actual maintenance capital expenditures from operating surplus.

To eliminate these fluctuations, our partnership agreement will require that an estimate of the average quarterly maintenance capital expenditures necessary to maintain our operating capacity over the long-term be subtracted from operating surplus each quarter as opposed to the actual amounts spent. The amount of estimated maintenance capital expenditures deducted from operating surplus for those periods will be subject to review and change by our general partner at least once a year, provided that any change is approved by our conflicts committee. The estimate will be made at least annually and whenever an event occurs that is likely to result in a material adjustment to the amount of our maintenance capital expenditures, including a major acquisition or expansion or the introduction of new governmental regulations that will impact our business. For purposes of calculating operating surplus, any adjustment to this estimate will be prospective only. For a discussion of the amounts we have allocated toward estimated maintenance capital expenditures, please read "Cash Distribution Policy and Restrictions on Distributions."

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The use of estimated maintenance capital expenditures in calculating operating surplus will have the following effects:

•: the amount of actual maintenance capital expenditures in any quarter will not directly reduce operating surplus but will instead be factored into the estimate of the average quarterly maintenance capital expenditures. This may result in the subordinated units converting into common units when the use of actual maintenance capital expenditures would result in lower operating surplus during the subordination period and potentially result in the tests for conversion of the subordinated units not being satisfied;
•: it may increase our ability to distribute as operating surplus cash we receive from non-operating sources; and
•: it may be more difficult for us to raise our distribution above the minimum quarterly distribution and pay incentive distributions on the incentive distribution rights held by our general partner.

Expansion capital expenditures are those cash expenditures, including transaction expenses, made to increase our operating capacity or net income over the long term. Examples of expansion capital expenditures include the acquisition of reserves, equipment or a new mine or the expansion of an existing mine, in each case to the extent such expenditures are expected to expand our long-term operating capacity or increase our net income. Expansion capital expenditures will also include interest (and related fees) on debt incurred and distributions on equity issued (including incremental distributions on incentive distribution rights) to finance all or any portion of such acquisition or expansion in respect of the period that commences when we enter into a binding obligation for the acquisition, construction, development or expansion and ending on the earlier to occur of the date any acquisition construction, development or expansion commences commercial service and the date that it is disposed of or abandoned. Expenditures made solely for investment purposes will not be considered expansion capital expenditures.

Investment capital expenditures are those capital expenditures, including transaction expenses, that are neither maintenance capital expenditures nor expansion capital expenditures. Investment capital expenditures largely will consist of capital expenditures made for investment purposes. Examples of investment capital expenditures include traditional capital expenditures for investment purposes, such as purchases of securities, as well as other capital expenditures that might be made in lieu of such traditional investment capital expenditures, such as the acquisition of an asset for investment purposes or development of assets that are in excess of the maintenance of our existing operating capacity or net income, but which are not expected to expand, for more than the short term, our operating capacity or net income.

As described above, neither investment capital expenditures nor expansion capital expenditures are operating expenditures, and thus will not reduce operating surplus. Because expansion capital expenditures include interest payments (and related fees) on debt incurred to finance all or a portion of an acquisition, development or expansion in respect of a period that begins when we enter into a binding obligation for an acquisition construction, development or expansion and ending on the earlier to occur of the date on which such acquisition, construction, development or expansion commences commercial service and the date that it is abandoned or disposed of, such interest payments also do not reduce operating surplus. Losses on disposition of an investment capital expenditure will reduce operating surplus when realized and cash receipts from an investment capital expenditure will be treated as a cash receipt for purposes of calculating operating surplus only to the extent the cash receipt is a return on principal.

Cash expenditures that are made in part for maintenance capital purposes, investment capital purposes or expansion capital purposes will be allocated as maintenance capital expenditures, investment capital expenditures or expansion capital expenditures by our general partner.

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Subordination Period

General

Our partnership agreement provides that, during the subordination period (which we describe below), the common units will have the right to receive distributions from operating surplus each quarter in an amount equal to $ per common unit, which amount is defined in our partnership agreement as the minimum quarterly distribution, plus any arrearages in the payment of the minimum quarterly distribution on the common units from prior quarters, before any distributions from operating surplus may be made on the subordinated units. These units are deemed "subordinated" because for a period of time, referred to as the subordination period, the subordinated units will not be entitled to receive any distribution from operating surplus for any quarter until the common units have received the minimum quarterly distribution from operating surplus for such quarter plus any arrearages in the payment of the minimum quarterly distribution from prior quarters. Furthermore, no arrearages will be paid on the subordinated units. The practical effect of the subordinated units is to increase the likelihood that during the subordination period there will be sufficient cash from operating surplus to pay the minimum quarterly distribution on the common units.

Determination of Subordination Period

Except as described below, the subordination period will begin on the closing date of this offering and expire on the first business day after the distribution to unitholders in respect of any quarter, beginning with the quarter ending , 2018, if each of the following has occurred:

•: for each of the three consecutive, non-overlapping four-quarter periods immediately preceding that date, aggregate distributions from operating surplus equaled or exceeded the sum of the minimum quarterly distribution multiplied by the total number of common and subordinated units outstanding in each quarter in each period;
•: for the same three consecutive, non-overlapping four-quarter periods, the "adjusted operating surplus" (as described below) equaled or exceeded the sum of the minimum quarterly distribution multiplied by the total number of common and subordinated units outstanding during each quarter on a fully diluted weighted average basis; and
•: there are no arrearages in payment of the minimum quarterly distribution on the common units.

For the period after the closing of this offering through , 2015, our partnership agreement will prorate the minimum quarterly distribution based on the actual length of the period, and use such prorated distribution for all purposes, including in determining whether the test described above has been satisfied.

Early Termination of Subordination Period

Notwithstanding the foregoing, the subordination period will automatically terminate, and all of the subordinated units will convert into common units on a one-for-one basis, on the first business day after the distribution to unitholders in respect of any quarter, beginning with the quarter ending , 2016, if each of the following has occurred:

•: for one four-quarter period immediately preceding that date, aggregate distributions from operating surplus exceeded the sum of 150.0% of the minimum quarterly distribution multiplied by the total number of common units and subordinated units outstanding in each quarter in the period;
•: for the same four-quarter period, the "adjusted operating surplus" (as described below) equaled or exceeded the sum of 150.0% of the minimum quarterly distribution multiplied by the total

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number of common and subordinated units outstanding during each quarter on a fully diluted weighted average basis, plus the related distribution on the incentive distribution rights; and

•: there are no arrearages in payment of the minimum quarterly distributions on the common units.

Conversion Upon Removal of the General Partner

In addition, if the unitholders remove our general partner other than for cause, the subordinated units held by any person will immediately and automatically convert into common units on a one-for-one basis, provided (1) neither such person nor any of its affiliates voted any of its units in favor of the removal and (2) such person is not an affiliate of the successor general partner.

Expiration of the Subordination Period

When the subordination period ends, each outstanding subordinated unit will convert into one common unit and will then participate pro rata with the other common units in distributions.

Adjusted Operating Surplus

Adjusted operating surplus is intended to generally reflect the cash generated from operations during a particular period and therefore excludes net increases in working capital borrowings and net drawdowns of reserves of cash generated in prior periods if not utilized to pay expenses during that period. Adjusted operating surplus for any period consists of:

•: operating surplus generated with respect to that period (excluding any amounts attributable to the items described in the first bullet point under "—Operating Surplus and Capital Surplus—Operating Surplus" above); less
•: any net increase during that period in working capital borrowings; less
•: any net decrease during that period in cash reserves for operating expenditures not relating to an operating expenditure made during that period; less
•: any expenditures that are not operating expenditures solely because of the provision described in the last bullet point describing operating expenditures above; plus
•: any net decrease during that period in working capital borrowings; plus
•: any net increase during that period in cash reserves for operating expenditures required by any debt instrument for the repayment of principal, interest or premium; plus
•: any net decrease made in subsequent periods in cash reserves for operating expenditures initially established during such period to the extent such decrease results in a reduction of adjusted operating surplus in subsequent periods pursuant to the third bullet point above.

Any disbursements received, cash received (including working capital borrowings) or cash reserves established, increased or reduced after the end of a period that the general partner determines to include in operating surplus for such period shall also be deemed to have been made, received or established, increased or reduced in such period for purposes of determining adjusted operating surplus for such period.

Distributions From Operating Surplus During the Subordination Period

If we make a distribution from operating surplus for any quarter ending before the end of the subordination period, our partnership agreement requires that we make the distribution in the following manner:

•: first, to the common unitholders, pro rata, until we distribute for each common unit an amount equal to the minimum quarterly distribution for that quarter and any arrearages in payment of the minimum quarterly distribution on the common units for any prior quarters;

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•: second, to the subordinated unitholders, pro rata, until we distribute for each subordinated unit an amount equal to the minimum quarterly distribution for that quarter; and
•: thereafter, in the manner described in "—General Partner Interest—Incentive Distribution Rights" below.

Distributions From Operating Surplus After the Subordination Period

If we make distributions of cash from operating surplus for any quarter ending after the subordination period, our partnership agreement requires that we make the distribution in the following manner:

•: first, to all common unitholders, pro rata, until we distribute for each common unit an amount equal to the minimum quarterly distribution for that quarter; and
•: thereafter, in the manner described in "—Incentive Distribution Rights" below.

General Partner Interest

Our general partner owns a non-economic general partner interest in us, which does not entitle it to receive cash distributions. However, our general partner owns the incentive distribution rights and may in the future own common units or other equity interests in us and will be entitled to receive distributions on any such interests.

Incentive Distribution Rights

Incentive distribution rights represent the right to receive increasing percentages (15.0%, 25.0% and 50.0%) of quarterly distributions from operating surplus after the minimum quarterly distribution and the target distribution levels have been achieved. Our general partner currently holds the incentive distribution rights, but may transfer these rights separately from its general partner interest.

If for any quarter:

•: we have distributed cash from operating surplus to the common and subordinated unitholders in an amount equal to the minimum quarterly distribution; and
•: we have distributed cash from operating surplus to the common unitholders in an amount necessary to eliminate any cumulative arrearages in payment of the minimum quarterly distribution;

then, we will make additional distributions from operating surplus for that quarter among the unitholders and the holders of the incentive distribution rights in the following manner:

•: first, to all unitholders, pro rata, until each unitholder receives a total of $ per unit for that quarter (the "first target distribution");
•: second, 85.0% to all common unitholders and subordinated unitholders, pro rata, and 15.0% to the holders of our incentive distribution rights, until each unitholder receives a total of $ per unit for that quarter (the "second target distribution");
•: third, 75.0% to all common unitholders and subordinated unitholders, pro rata, and 25.0% to the holders of our incentive distribution rights, until each unitholder receives a total of $ per unit for that quarter (the "third target distribution"); and
•: thereafter, 50.0% to all common unitholders and subordinated unitholders, pro rata, and 50.0% to the holders of our incentive distribution rights.

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Percentage Allocations of Distributions From Operating Surplus

The following table illustrates the percentage allocations of distributions from operating surplus between the unitholders and the holders of our incentive distribution rights based on the specified target distribution levels. The amounts set forth under the column heading "Marginal Percentage Interest in Distributions" are the percentage interests of the holders of our incentive distribution rights and the unitholders in any distributions from operating surplus we distribute up to and including the corresponding amount in the column heading "Total Quarterly Distribution Per Unit." The percentage interests shown for our unitholders and the holders of our incentive distribution rights for the minimum quarterly distribution are also applicable to quarterly distribution amounts that are less than the minimum quarterly distribution. The percentage interests set forth below assume there are no arrearages on common units.

		Marginal Percentage Interest in Distributions

	Total Quarterly Distribution Per Unit	Unitholders			IDR Holders
Minimum Quarterly Distribution	up to $		100.0	%		0	%
First Target Distribution	above $ up to $		100.0	%		0	%
Second Target Distribution	above $ up to $		85.0	%		15.0	%
Third Target Distribution	above $ up to $		75.0	%		25.0	%
Thereafter	above $		50.0	%		50.0	%

Incentive Distribution Right Holders' Right to Reset Incentive Distribution Levels

Our general partner, as the initial holder of our incentive distribution rights, has the right under our partnership agreement to elect to relinquish the right to receive incentive distribution payments based on the initial target distribution levels and to reset, at higher levels, the target distribution levels upon which the incentive distribution payments would be set. If our general partner transfers all or a portion of the incentive distribution rights in the future, then the holder or holders of a majority of our incentive distribution rights will be entitled to exercise this right. The following discussion assumes that our general partner holds all of the incentive distribution rights at the time that a reset election is made.

The right to reset the target distribution levels upon which the incentive distributions are based may be exercised, without approval of our unitholders or the conflicts committee of our general partner at any time when there are no subordinated units outstanding and we have made cash distributions in excess of the highest then-applicable target distribution for the prior four consecutive fiscal quarters. The reset target distribution levels will be higher than the most recent per unit distribution level prior to the reset election and higher than the target distribution levels prior to the reset such that there will be no incentive distributions paid under the reset target distribution levels until cash distributions per unit following the reset event increase as described below. Because the reset target distribution levels will be higher than the most recent per unit distribution level prior to the reset, if we were to issue additional common units after the reset and maintain the per unit distribution level, no additional incentive distributions would be payable. By contrast, if there were no such reset and we were to issue additional common units and maintain the per unit distribution level, additional incentive distributions would have to be paid based on the additional number of outstanding common units and the percentage interest of the incentive distribution rights above the target distribution levels. Thus, the exercise of the reset right would lower our cost of equity capital. We anticipate that our general partner would exercise this reset right in order to facilitate acquisitions or internal growth projects that would otherwise not be sufficiently accretive to cash distributions per common unit, taking into account the existing levels of incentive distribution payments being made.

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In connection with the resetting of the target distribution levels and the corresponding relinquishment by our general partner of incentive distribution payments based on the target cash distributions prior to the reset, our general partner will be entitled to receive a number of newly issued common units based on the formula described below that takes into account the "cash parity" value of the cash distributions related to the incentive distribution rights for the quarter prior to the reset event as compared to the cash distribution per common unit in such quarter.

The number of common units to be issued in connection with a resetting of the minimum quarterly distribution amount and the target distribution levels would equal the quotient determined by dividing (x) the amount of cash distributions received in respect of the incentive distribution rights for the fiscal quarter ended immediately prior to the date of such reset election by (y) the amount of cash distributed per common unit with respect to such quarter.

Following a reset election, the reset minimum quarterly distribution will be calculated and the target distribution levels will be reset to be correspondingly higher such that we would make distributions from operating surplus for each quarter thereafter as follows:

•: first, to all common unitholders, pro rata, until each unitholder receives an amount per unit for that quarter equal to 115.0% of the reset minimum quarterly distribution;
•: second, 85.0% to all common unitholders, pro rata, and 15.0% to the holders of our incentive distribution rights, until each unitholder receives an amount per unit for that quarter equal to 125.0% of the reset minimum quarterly distribution;
•: third, 75.0% to all common unitholders, pro rata, and 25.0% to the holders of our incentive distribution rights, until each unitholder receives an amount per unit for that quarter equal to 150.0% of the reset minimum quarterly distribution; and
•: thereafter, 50.0% to all common unitholders, pro rata, and 50.0% to the holders of our incentive distribution rights.

Because a reset election can only occur after the subordination period expires, the reset minimum quarterly distribution will have no significance except as a baseline for the target distribution levels.

The following table illustrates the percentage allocation of distributions from operating surplus between the unitholders and the holders of our incentive distribution rights at various distribution levels (1) pursuant to the distribution provisions of our partnership agreement in effect at the closing of this offering, as well as (2) following a hypothetical reset of the target distribution levels based on the assumption that the quarterly distribution amount per common unit during the fiscal quarter immediately preceding the reset election was $ .

	Quarterly Distribution Per Unit Prior to Reset					Quarterly Distribution Per Unit Following Hypothetical Reset

Minimum Quarterly Distribution	up to $	100.0	%	0.0	%	up to $ (1)
First Target Distribution	above $ up to $	100.0	%	0.0	%	above $ up to $ (2)
Second Target Distribution	above $ up to $	85.0	%	15.0	%	above $ up to $ (3)
Third Target Distribution	above $ up to $	75.0	%	25.0	%	above $ up to $ (4)
Thereafter	above $	50.0	%	50.0	%	above $

(1): This amount is equal to the hypothetical reset minimum quarterly distribution.
(2): This amount is 115.0% of the hypothetical reset minimum quarterly distribution.
(3): This amount is 125.0% of the hypothetical reset minimum quarterly distribution.

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(4): This amount is 150.0% of the hypothetical reset minimum quarterly distribution.

The following table illustrates the total amount of distributions from operating surplus that would be distributed to the unitholders and the holders of incentive distribution rights, based on the amount distributed for the quarter immediately prior to the reset. The table assumes that immediately prior to the reset there would be common units outstanding and the distribution to each common unit would be $ for the quarter prior to the reset.

	Quarterly Distribution per Unit Prior to Reset	Cash Distributions to Common Unitholders Prior to Reset	Cash Distributions to Holders of Incentive Distribution Rights Prior to Reset	Total Distributions

Minimum Quarterly Distribution	up to $	$	$	$
First Target Distribution	above $ up to $
Second Target Distribution	above $ up to $
Third Target Distribution	above $ up to $
Thereafter	above $

		$	$	$

The following table illustrates the total amount of distributions from operating surplus that would be distributed to the unitholders and the holders of our incentive distribution rights, with respect to the quarter in which the reset occurs. The table reflects that as a result of the reset there would be common units outstanding and the distribution to each common unit would be $ . The number of common units to be issued upon the reset was calculated by dividing (1) the amount received in respect of the incentive distribution rights for the quarter prior to the reset as shown in the table above, or $ , by (2) the amount of cash distributed on each common unit for the quarter prior to the reset as shown in the table above, or $ .

			Cash Distributions to Holders of Incentive Distribution Rights After Reset

		Cash Distributions to Common Unitholders Prior to Reset
	Quarterly Distribution per Unit Prior to Reset
	Quarterly Distribution per Unit Prior to Reset		Common Units(1)	Incentive Distribution Rights	Total	Total Distributions
Minimum Quarterly Distribution	up to $	$	$	$	$	$
First Target Distribution	above $ up to $
Second Target Distribution	above $ up to $
Third Target Distribution	above $ up to $
Thereafter	above $

		$	$	$	$	$

(1): Represents distributions in respect of the common units issued upon the reset.

The holders of incentive distribution rights will be entitled to cause the target distribution levels to be reset on more than one occasion.

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Distributions From Capital Surplus

How Distributions From Capital Surplus Will Be Made

Our partnership agreement requires that we make distributions from capital surplus, if any, in the following manner:

•: first, to all common unitholders and subordinated unitholders, pro rata, until the minimum quarterly distribution is reduced to zero, as described below;
•: second, to the common unitholders, pro rata, until we distribute for each common unit an amount from capital surplus equal to any unpaid arrearages in payment of the minimum quarterly distribution on the common units; and
•: thereafter, we will make all distributions from capital surplus as if they were from operating surplus.

Effect of a Distribution From Capital Surplus

Our partnership agreement treats a distribution from capital surplus as the repayment of the initial unit price from this initial public offering, which is a return of capital. Each time a distribution from capital surplus is made, the minimum quarterly distribution and the target distribution levels will be reduced in the same proportion as the distribution from capital surplus to the fair market value of the common units prior to the announcement of the distribution. Because distributions of capital surplus will reduce the minimum quarterly distribution and target distribution levels after any of these distributions are made, it may be easier for our general partner to receive incentive distributions and for the subordinated units to convert into common units. However, any distribution from capital surplus before the minimum quarterly distribution is reduced to zero cannot be applied to the payment of the minimum quarterly distribution or any arrearages.

Once we reduce the minimum quarterly distribution and target distribution levels to zero, all future distributions will be made such that 50.0% is paid to all unitholders, pro rata, and 50.0% is paid to the holder or holders of incentive distribution rights.

Adjustment to the Minimum Quarterly Distribution and Target Distribution Levels

In addition to adjusting the minimum quarterly distribution and target distribution levels to reflect a distribution from capital surplus, if we combine our common units into fewer common units or subdivide our common units into a greater number of common units, our partnership agreement specifies that the following items will be proportionately adjusted:

•: the minimum quarterly distribution;
•: the target distribution levels;
•: the initial unit price, as described below under "—Distributions of Cash Upon Liquidation";
•: the per unit amount of any outstanding arrearages in payment of the minimum quarterly distribution on the common units; and
•: the number of subordinated units.

For example, if a two-for-one split of the common units should occur, the minimum quarterly distribution, the target distribution levels and the initial unit price would each be reduced to 50.0% of its initial level. If we combine our common units into a lesser number of units or subdivide our common units into a greater number of units, we will combine or subdivide our subordinated units

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using the same ratio applied to the common units. We will not make any adjustment by reason of the issuance of additional units for cash or property.

In addition, if as a result of a change in law or interpretation thereof, we or any of our subsidiaries is treated as an association taxable as a corporation or is otherwise subject to additional taxation as an entity for U.S. federal, state, local or non-U.S. income or withholding tax purposes, our general partner may, in its sole discretion, reduce the minimum quarterly distribution and the target distribution levels for each quarter by multiplying each distribution level by a fraction, the numerator of which is cash for that quarter (after deducting our general partner's estimate of our additional aggregate liability for the quarter for such income and withholding taxes payable by reason of such change in law or interpretation) and the denominator of which is the sum of (1) cash for that quarter, plus (2) our general partner's estimate of our additional aggregate liability for the quarter for such income and withholding taxes payable by reason of such change in law or interpretation thereof. To the extent that the actual tax liability differs from the estimated tax liability for any quarter, the difference will be accounted for in distributions with respect to subsequent quarters.

Distributions of Cash Upon Liquidation

General

If we dissolve in accordance with the partnership agreement, we will sell or otherwise dispose of our assets in a process called liquidation. We will first apply the proceeds of liquidation to the payment of our creditors. We will distribute any remaining proceeds to the unitholders and the holders of the incentive distribution rights, in accordance with their capital account balances, as adjusted to reflect any gain or loss upon the sale or other disposition of our assets in liquidation.

The allocations of gain and loss upon liquidation are intended, to the extent possible, to entitle the holders of units to a repayment of the initial value contributed by unitholders for their units in this offering, which we refer to as the "initial unit price" for each unit. The allocations of gain and loss upon liquidation are also intended, to the extent possible, to entitle the holders of common units to a preference over the holders of subordinated units upon our liquidation, to the extent required to permit common unitholders to receive their initial unit price plus the minimum quarterly distribution for the quarter during which liquidation occurs plus any unpaid arrearages in payment of the minimum quarterly distribution on the common units. However, there may not be sufficient gain upon our liquidation to enable the common unitholders to fully recover all of these amounts, even though there may be cash available for distribution to the holders of subordinated units. Any further net gain recognized upon liquidation will be allocated in a manner that takes into account the incentive distribution rights.

Manner of Adjustments for Gain

The manner of the adjustment for gain is set forth in the partnership agreement. If our liquidation occurs before the end of the subordination period, we will generally allocate any gain to the partners in the following manner:

•: first, to our general partner to the extent of certain prior losses specially allocated to our general partner;
•: second, to the common unitholders, pro rata, until the capital account for each common unit is equal to the sum of: (1) the initial unit price; (2) the amount of the minimum quarterly distribution for the quarter during which our liquidation occurs; and (3) any unpaid arrearages in payment of the minimum quarterly distribution;

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•: third, to the subordinated unitholders, pro rata, until the capital account for each subordinated unit is equal to the sum of: (1) the initial unit price; and (2) the amount of the minimum quarterly distribution for the quarter during which our liquidation occurs;
•: fourth, to all unitholders, pro rata, until we allocate under this bullet an amount per unit equal to: (1) the sum of the excess of the first target distribution per unit over the minimum quarterly distribution per unit for each quarter of our existence; less (2) the cumulative amount per unit of any distributions from operating surplus in excess of the minimum quarterly distribution per unit that we distributed to the unitholders, pro rata, for each quarter of our existence;
•: fifth, 85.0% to all unitholders, pro rata, and 15.0% to the holders of our incentive distribution rights, until we allocate under this bullet an amount per unit equal to: (1) the sum of the excess of the second target distribution per unit over the first target distribution per unit for each quarter of our existence; less (2) the cumulative amount per unit of any distributions from operating surplus in excess of the first target distribution per unit that we distributed 85.0% to the unitholders, pro rata, and 15.0% to the holders of our incentive distribution rights for each quarter of our existence;
•: sixth, 75.0% to all unitholders, pro rata, and 25.0% to the holders of our incentive distribution rights, until we allocate under this bullet an amount per unit equal to: (1) the sum of the excess of the third target distribution per unit over the second target distribution per unit for each quarter of our existence; less (2) the cumulative amount per unit of any distributions from operating surplus in excess of the second target distribution per unit that we distributed 75.0% to the unitholders, pro rata, and 25.0% to the holders of our incentive distribution rights for each quarter of our existence; and
•: thereafter, 50.0% to all unitholders, pro rata, and 50.0% to holders of our incentive distribution rights.

If the liquidation occurs after the end of the subordination period, the distinction between common units and subordinated units will disappear, so that clause (3) of the second bullet point above and all of the third bullet point above will no longer be applicable.

We may make special allocations of gain among the partners in a manner to create economic uniformity among the common units into which the subordinated units convert and the common units held by public unitholders.

Manner of Adjustments for Loss

If our liquidation occurs before the end of the subordination period, we will generally allocate any loss to our general partner and the unitholders in the following manner:

•: first, to holders of subordinated units in proportion to the positive balances in their capital accounts until the capital accounts of the subordinated unitholders have been reduced to zero;
•: second, to the holders of common units in proportion to the positive balances in their capital accounts, until the capital accounts of the common unitholders have been reduced to zero; and
•: thereafter, 100.0% to our general partner.

If the liquidation occurs after the end of the subordination period, the distinction between common units and subordinated units will disappear, so that all of the first bullet point above will no longer be applicable.

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We may make special allocations of loss among the partners in a manner to create economic uniformity among the common units into which the subordinated units convert and the common units held by public unitholders.

Adjustments to Capital Accounts

Our partnership agreement requires that we make adjustments to capital accounts upon the issuance of additional units. In this regard, our partnership agreement specifies that we allocate any unrealized and, for federal income tax purposes, unrecognized gain resulting from the adjustments to the unitholders and the holders of our incentive distribution rights in the same manner as we allocate gain upon liquidation. In the event that we make positive adjustments to the capital accounts upon the issuance of additional units, our partnership agreement requires that we generally allocate any later negative adjustments to the capital accounts resulting from the issuance of additional units or upon our liquidation in a manner that results, to the extent possible, in the partners' capital account balances equaling the amount that they would have been if no earlier positive adjustments to the capital accounts had been made. In contrast to the allocations of gain, and except as provided above, we generally will allocate any unrealized and unrecognized loss resulting from the adjustments to capital accounts upon the issuance of additional units to the unitholders and the holders of our incentive distribution rights based on their respective percentage ownership of us. In this manner, prior to the end of the subordination period, we generally will allocate any such loss equally with respect to our common and subordinated units. If we make negative adjustments to the capital accounts as a result of such loss, future positive adjustments resulting from the issuance of additional units will be allocated in a manner designed to reverse the prior negative adjustments, and special allocations will be made upon liquidation in a manner that results, to the extent possible, in our unitholders' capital account balances equaling the amounts they would have been if no earlier adjustments for loss had been made.

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SELECTED HISTORICAL AND PRO FORMA FINANCIAL AND OTHER DATA

The following table sets forth our selected historical and pro forma financial and other data, as of the dates and for the periods indicated. The selected historical financial data presented as of August 16, 2013 and for the period from January 1, 2013 to August 16, 2013 have been derived from the audited financial statements of the Predecessor, included elsewhere in this prospectus. The selected historical financial data presented as of December 31, 2013, for the period from August 16, 2013 to December 31, 2013 and as of and for the year ended December 31, 2014 have been derived from the audited financial statements of the Successor, included elsewhere in this prospectus.

The selected historical financial data presented as of and for the three months ended March 31, 2014 and 2015 have been derived from the unaudited interim financial statements of the Successor included elsewhere in this prospectus. The unaudited interim financial statements have been prepared on the same basis as the Successor's audited financial statements and, in the opinion of our management, include all material adjustments, consisting of normal and recurring adjustments, necessary for a fair presentation of the information set forth herein. The selected historical interim balance sheet data as of March 31, 2014 is derived from unaudited interim financial statements of the Successor, which are not included in this prospectus. Operating results for the three months ended March 31, 2015 are not necessarily indicative of the results that may be expected for the year ended December 31, 2015 or for any future period.

The selected unaudited pro forma financial data presented as of and for the year ended December 31, 2014 and the three months ended March 31, 2015 are derived from the unaudited pro forma condensed consolidated financial statements of Bowie Resource Partners LP, included elsewhere in this prospectus. The unaudited pro forma condensed consolidated financial statements of Bowie Resource Partners LP give pro forma effect to the IPO Reorganization described under "Prospectus Summary—IPO Reorganization and Partnership Structure." The unaudited pro forma condensed consolidated balance sheet as of March 31, 2015 reflects the IPO Reorganization as if it occurred on March 31, 2015. The pro forma condensed consolidated statement of (loss) income for the year ended December 31, 2014 and the three months ended March 31, 2015 reflect the IPO Reorganization as if it occurred on January 1, 2014.

The selected historical and pro forma financial and other data presented below should be read in conjunction with the information presented under "Management's Discussion and Analysis of Financial Condition and Results of Operations" and the financial statements and related notes thereto appearing in this prospectus.

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	Predecessor			Successor												Bowie Resource Partners LP Pro Forma

	Year Ended December 31, 2013
	Period from January 1, 2013 to August 16, 2013			Period from August 16, 2013 to December 31, 2013			Year Ended December 31, 2014			Three Months Ended March 31, 2014			Three Months Ended March 31, 2015			Year Ended December 31, 2014	Three Months Ended March 31, 2015
				(in thousands, except per ton data)
Statements of Operations Data
Coal sales	$	219,140		$	158,756		$	419,804		$	112,265		$	103,924		$	$
Other revenues, net(1)		813			1,410			358			89			91
Costs and expenses:
Cost of coal sales, exclusive of items shown separately below		140,781			96,165			232,819			63,115			61,629
Transportation		30,477			19,690			44,439			12,758			12,808
Depreciation, depletion and amortization		21,955			27,251			81,057			18,592			21,334
Accretion on asset retirement obligations		462			—			785			196			206
Selling, general and administrative expenses		7,970			9,586			17,590			3,159			4,173
Amortization of acquired sales contracts, net		—			3,708			12,098			3,181			(54	)

Operating income		18,308			3,766			31,374			11,353			3,919
Other expenses (income):
Interest expense and related financing costs		—			13,604			36,245			9,093			8,021
Gain on sale of assets		(389	)		—			—			—			—
Other		769			—			—			—			—

Net income (loss)	$	17,928		$	(9,838	)	$	(4,871	)	$	2,260		$	(4,102	)	$	$



Cash Flow Data
Net cash provided by operating activities	$	45,964		$	14,858		$	84,524		$	12,941		$	5,454
Net cash used in investing activities	$	(5,217	)	$	(8,373	)	$	(27,044	)	$	(1,119	)	$	(5,960	)
Net cash (used in) provided by financing activities	$	(40,807	)	$	(6,485	)	$	(57,480	)	$	(11,822	)	$	506
Balance Sheet Data (at period end)
Total current assets	$	51,857		$	82,093		$	84,655		$	80,907		$	93,375			$
Property, plant and equipment, net	$	285,934		$	400,945		$	357,110		$	385,612		$	344,557			$
Other assets	$	5,192		$	36,615		$	17,659		$	36,701		$	16,203			$
Total liabilities	$	51,430		$	495,027		$	440,104		$	480,497		$	446,069			$
Member's equity	$	291,553		$	24,626		$	19,320		$	22,723		$	8,066			$
Total liabilities and member's equity	$	342,983		$	519,653		$	459,424		$	503,220		$	454,135			$
Other Data
EBITDA(2)	$	39,883		$	34,725		$	124,529		$	33,126		$	25,199		$	$
Adjusted EBITDA(2)	$	40,725		$	34,725		$	125,314		$	33,322		$	25,405		$	$
Tons produced		5,793			3,863			11,386			2,935			2,518
Tons sold		5,614			4,440			11,463			3,175			2,691
Coal sales realized per ton(3)	$	39.03		$	35.76		$	36.62		$	35.36		$	38.62		$	$
Direct mining costs per ton(4)	$	25.08		$	21.66		$	20.31		$	19.88		$	22.90		$	$

(1): Primarily includes net revenues from contract terminations (bookouts), restructuring payments, royalties related to coal lease agreements and revenues from property and facility rentals.
(2): Please read "—Non-GAAP Financial Measures" below for the definitions of EBITDA and Adjusted EBITDA and a reconciliation of EBITDA and Adjusted EBITDA to our most directly comparable financial measure, calculated and presented in accordance with GAAP.
(3): Coal sales realized per ton is defined as coal sales divided by tons sold.
(4): Direct mining costs per ton is defined as cost of coal sales, exclusive of items shown separately, divided by tons sold.

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Non-GAAP Financial Measures

•: our ability to make distributions to our unitholders;
•: the financial performance of our assets without regard to financing methods, capital structure or historical cost basis;
•: the ability of our assets to generate sufficient cash to pay interest costs and support our indebtedness;
•: our operating performance and return on capital as compared to those of other companies and partnerships in our industry, without regard to financing or capital structure; and
•: the feasibility of acquisitions and other capital expenditures and the overall rates of return on investment opportunities.

The following table presents a reconciliation of EBITDA and Adjusted EBITDA to the most directly comparable GAAP financial measure for the periods indicated.

	Predecessor			Successor											Bowie Resource Partners LP Pro Forma

	Year Ended December 31, 2013
	Period from January 1, 2013 to August 16, 2013			Period from August 16, 2013 to December 31, 2013			Year Ended December 31, 2014			Three Months Ended March 31, 2014		Three Months Ended March 31, 2015			Year Ended December 31, 2014	Three Months Ended March 31, 2015
				(in thousands)
Reconciliation of EBITDA and Adjusted EBITDA to Net income (loss):
Net income (loss)	$	17,928		$	(9,838	)	$	(4,871	)	$	2,260	$	(4,102	)	$	$
Add:
Depreciation, depletion and amortization		21,955			27,251			81,057			18,592		21,334
Amortization of acquired sales contracts, net		—			3,708			12,098			3,181		(54	)
Interest expense and related financing costs		—			13,604			36,245			9,093		8,021

EBITDA		39,883			34,725			124,529			33,126		25,199
Add:
Accretion on asset retirement obligations		462			—			785			196		206
Gain on sale of assets		(389	)		—			—			—		—
Other		769			—			—			—		—

Adjusted EBITDA	$	40,725		$	34,725		$	125,314		$	33,322	$	25,405		$	$

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

You should read the following discussion and analysis together with "Selected Historical and Pro Forma Financial and Other Data" and the financial statements and related notes included elsewhere in this prospectus.

The following discussion and analysis of our historical financial condition and results of operations as of August 16, 2013 and for the period from January 1, 2013 to August 16, 2013 (the "2013 Predecessor Period") has been derived from the audited financial statements of Canyon Fuel Company, LLC ("CFC") prior to the acquisition of CFC by our sponsor on August 16, 2013 (the "Predecessor"), included elsewhere in this prospectus. The discussion and analysis of our historical financial condition and results of operations as of December 31, 2013, for the period from August 16, 2013 to December 31, 2013 (the "2013 Successor Period") and as of and for the year ended December 31, 2014 has been derived from the audited financial statements of CFC after the acquisition of CFC by our sponsor (the "Successor"), included elsewhere in this prospectus.

The discussion and analysis of our historical financial condition and results of operations as of and for the three months ended March 31, 2014 and 2015 have been derived from the unaudited interim financial statements of the Successor included elsewhere in this prospectus. The unaudited interim financial statements have been prepared on the same basis as the Successor's audited financial statements and, in the opinion of our management, include all material adjustments, consisting of normal and recurring adjustments, necessary for a fair presentation of the information set forth herein. The historical interim balance sheet data as of March 31, 2014 have been derived from unaudited interim financial statements of the Successor, which are not included in this prospectus. Operating results for the three months ended March 31, 2015 are not necessarily indicative of the results that may be expected for the year ended December 31, 2015 or for any future period.

Unless otherwise indicated, references in "Management's Discussion and Analysis of Financial Condition and Results of Operations" to "the partnership," "we," "our," "us" or like terms when used in a historical context refer to the business and financial condition and results of operations of CFC and its subsidiaries, and when used in the present tense or prospectively, refer to Bowie Resource Partners LP and its subsidiaries giving effect to the transactions described in "Prospectus Summary—IPO Reorganization and Partnership Structure."

This discussion contains forward-looking statements about our business, operations and industry that involve risks and uncertainties, such as statements regarding our plans, objectives, expectations and intentions. Our future results and financial condition may differ materially from those we currently anticipate as a result of the factors we describe under "Forward-Looking Statements," "Risk Factors" and elsewhere in this prospectus. All references to tons produced, tons sold, coal sales realized per ton or direct mining costs per ton refer to clean tons of coal.

Overview

We operate three low-cost, underground coal mines in the Uinta Basin that produce high Btu, low sulfur coal that is sold both domestically and internationally. Our mines consist of:

•: Sufco: A longwall mine in southern Utah, producing coal with one longwall mining system and three continuous miner units, with a productive capacity of approximately 7.0 million tons per year.
•: Skyline: A longwall mine in central Utah, producing coal with one longwall mining system and two continuous miner units, with a productive capacity of approximately 4.5 million tons per year.

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•: Dugout Canyon: A continuous miner operation in central Utah, which as of January 2015 is producing coal with two continuous miners, with a productive capacity of approximately 1.1 million tons per year. We believe our Dugout Canyon mine can support an additional continuous miner unit without any additional surface infrastructure, which would increase its productive capacity to approximately 1.5 million tons per year.

We have significantly enhanced the performance of our mines since they were acquired by our sponsor in August 2013. Coal production at our mines increased from 5.8 million tons and 3.9 million tons for the 2013 Predecessor Period and 2013 Successor Period, respectively, to 11.4 million tons for the year ended December 31, 2014. During the year ended December 31, 2014, we realized net loss, operating income and Adjusted EBITDA of $4.9 million, $31.4 million and $125.3 million, respectively, as compared to net income, operating income and Adjusted EBITDA of $17.9 million, $18.3 million and $40.7 million, respectively, for the 2013 Predecessor Period and net loss, operating income and Adjusted EBITDA of $9.8 million, $3.8 million and $34.7 million, respectively, for the 2013 Successor Period. Please read "Prospectus Summary—Summary Historical and Pro Forma Financial and Other Data—Non-GAAP Financial Measures" for the definition of Adjusted EBITDA and a reconciliation of Adjusted EBITDA to our most directly comparable financial measure calculated and presented in accordance with GAAP.

Our results for the three months ended March 31, 2015 as compared to the three months ended March 31, 2014 were affected by a scheduled 20-day longwall move at our Sufco mine during 2015 that did not occur in 2014, partially offset by increased coal sales realized per ton. As a result of this scheduled longwall move, coal production decreased from 2.9 million tons for the three months ended March 31, 2014 to 2.5 million tons for the three months ended March 31, 2015. In addition, coal sales realized per ton increased 9% from $35.36 for the three months ended March 31, 2014 to $38.62 for the three months ended March 31, 2015, primarily driven by price escalators in our existing coal supply agreements and a change in sales mix reflecting lower export sales that are generally sold at a lower realized price FOB the mine.

On June 5, 2015, we acquired from PacifiCorp and its affiliate (a) certain undeveloped, high Btu, low sulfur coal reserves in Utah (the "Fossil Rock reserves") through our wholly-owned subsidiary, Fossil Rock Resources, LLC and (b) certain real property near PacifiCorp's Hunter Power Plant through our wholly-owned subsidiary Hunter Prep Plant, LLC (the "Utah Transaction") for a purchase price of $40.0 million (including (i) a $30 million promissory note from Fossil Rock Resources, LLC and (ii) a $10 million promissory note from Hunter Prep Plant, LLC, each of which we expect to repay using net proceeds from this offering and the offering of New Notes). As part of the Utah Transaction, our sponsor entered into an agreement with PacifiCorp to supply all of the coal requirements of PacifiCorp's Huntington Power Plant in Utah through 2029. The volume for the new coal supply agreement with PacifiCorp will be supplied predominantly with our coal. The Fossil Rock reserves increase our proven and probable reserves by an estimated 11.2 million tons and 32.5 million tons, respectively, and provide a natural replacement for the low sulfur coal currently produced by our Sufco mine from the Upper Hiawatha seam, which we expect to be exhausted in the third quarter of 2021.

We believe we are uniquely positioned with our low-cost coal, long-term domestic coal supply agreements and terminal agreements to provide attractive returns and grow our business both organically and through acquisitions. The timing of additional development and/or acquisitions is dependent on several factors, including permitting, market demand, access to capital, equipment availability and the committed sales position at our existing mining operations.

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Factors That Affect Our Results, Trends and Uncertainties

Contract Position

We sell a significant portion of our coal under coal supply agreements with terms that range from one to fifteen years. On a pro forma basis, after giving effect to the closing of the Utah Transaction, we expect coal sales under our existing coal supply agreements of approximately 11.2 million tons in 2015, 9.0 million tons in 2016, 9.5 million tons in 2017 and 9.3 million tons in 2018, which represent approximately 100%, 82%, 86% and 84%, respectively, of our production for the twelve months ended March 31, 2015. We have sold coal to 68 domestic power plants, industrial users and international customers. However, the three primary power plants that purchase our coal are located in Utah and are a short truck or rail haul from our mines. Export tons are sold to customers in multiple countries throughout the Pacific Rim, principally by Trafigura AG, the exclusive marketer of our uncommitted coal. Trafigura AG, along with its affiliates, has 45 offices in 36 countries around the world and is a leading independent commodity trader. To date, we absorb no foreign credit risk as all tons are sold FOB the U.S. port.

Our primary sales strategy is to enter into long-term domestic coal supply agreements for the majority of our production with fixed pricing, subject to certain price escalators and adjustments. Please read "Business—Customers." Our coal sales realized per ton in the near term may decrease as we replace expiring favorably priced coal supply agreements with new coal supply agreements at contractually negotiated market prices.

Coal Prices

Generally, domestic coal prices have weakened since 2011 due to reduced demand from coal-fired power plants. International coal prices have also declined as a result of excess supply in the marketplace. According to globalCOAL, the Newcastle spot price of coal FOB Australia declined from $114.30 per metric ton at January 6, 2012, to $94.16 per metric ton at January 4, 2013, to $85.41 per metric ton at January 3, 2014, to $61.94 per metric ton at January 2, 2015 and to $59.60 per metric ton at March 27, 2015. We expect this low-price environment to continue into the second half of 2015. Price trends thereafter are likely to be influenced by supply and demand balance, production and transportation costs, availability of alternate fuels, macroeconomic conditions, coal quality, governmental regulation and weather patterns. We attempt to mitigate coal price fluctuations by executing long-term coal supply agreements and may hedge a portion of our unpriced export position. We have four long-term coal supply agreements (two with PacifiCorp and two with IPA) that provide both volume and pricing visibility through calendar year 2020, accounting for approximately 9.0 million tons per year of coal sales, or about 71% of our productive capacity as of December 31, 2014. Beyond 2020, these same agreements provide volume and pricing certainty through 2024 for approximately 4.5 million tons per year, or approximately 36% of our productive capacity as of December 31, 2014. Please read "The Coal Industry—Coal Pricing" for further discussion of pricing trends and expectations.

Coal Demand

Demand for coal can increase due to unusually hot or cold weather as electricity consumers use more air conditioning or heating and, as a result, power producers burn more coal. Conversely, mild weather can result in lower demand for our coal. Adverse weather conditions, such as blizzards or floods, can affect our ability to mine and ship our coal and our customers' ability to take delivery of coal. Coal demand in the western United States is also impacted by rain and the winter snow pack since coal fired power generation competes with hydro-electric power production. Generally, our customers take deliveries ratably throughout the year building or depleting their inventory.

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While global coal prices have declined in recent years, and we expect U.S. coal export demand to be slightly weaker in the near term, we expect long-term international demand for thermal coal to increase, supported by emerging economies across the globe and sustained growth in electric power generation and steel production capacity in Asia, most noticeably in China and India. Imports by China are expected to grow by 108% to 419.1 million metric tons from 2014 to 2035, according to Wood Mackenzie. As a result of growing international demand, coal prices for seaborne thermal coal have, from time to time, been higher relative to domestic prices. Based on forward price curves, we expect seaborne thermal coal prices to continue to increase over time. Given our low cost of production, attractive coal qualities, transportation optionality, and unique access to U.S. West Coast terminals, we believe we will be competitive selling our coal into the seaborne market in the future. Please read "The Coal Industry—Coal Demand" for further discussion of coal demand trends and expectations.

Coal Tons Produced

The table below represents total tons produced from our mines:

	Predecessor		Successor

	Year Ended December 31, 2013
	Period from January 1, 2013 to August 16, 2013		Period from August 16, 2013 to December 31, 2013		Year Ended December 31, 2014		Three Months Ended March 31, 2014		Three Months Ended March 31, 2015
			(in thousands)
Tons produced		5,793		3,863		11,386		2,935		2,518

Our production may be influenced by geological conditions, delays in obtaining permits or leases, labor shortages, unforeseen equipment problems and unexpected shortages of critical materials, such as steel, diesel fuel and explosives, that may result in adverse cost increases and limit our ability to produce at our forecasted levels. Please read "Risk Factors" for further discussion of risks and uncertainties that may affect our production.

Longwall Moves

Longwall mines have periods of interrupted production as mining is completed in a particular panel and the longwall mining equipment is disassembled, moved and reassembled at the next panel. During these periods, the mine continues to ship coal to customers from continuous miner production and/or inventory as available. We attempt to minimize this production interruption by designing long and wide panels that limit moves to approximately twice per year. Production interruptions of 20 days or less occur with a frequency of six to nine months. There are no guarantees that future longwall moves at our longwall mines will have similar results.

Cost of Coal Sales, Exclusive of Items Shown Separately

Our cost of coal sales, exclusive of items shown separately, includes labor and benefits, supplies, repairs, utilities, insurance, equipment rental, mine lease costs, property and land subsidence costs, sales-related costs, belting, coal preparation, royalties and direct mine overhead. Each of these cost components has its own drivers, which can include the cost and availability of labor, changes in health care and insurance regulations, the cost of consumable items or inputs in our supplies, changes in regulation, and/or our staffing levels. In particular, our royalties can depend directly upon the price at which we sell our coal and the underlying terms of our coal leases.

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Transportation

We sell a majority of our coal to customers at delivery points other than our mines, including power plants, industrial facilities and ports along the U.S. West Coast. As such, we often bear the transportation costs and any transloading costs. Where possible, we enter into long-term transportation and throughput agreements. Because we are responsible for the cost of transporting our coal to these various delivery points, we often, but not always, bear the risk that our transportation expense will increase over time. Our transportation costs, in part, correlate to the distance required to transport our coal to the buyer. As a result, the transportation of our coal to domestic buyers has lower associated costs than the transportation of our coal to international buyers. International sales require us to transport coal first by rail to a seaborne export terminal and then load the coal onto the buyers' ships. In certain circumstances, the cost of transporting our coal to international buyers can be as much as ten times the cost of transporting our coal to domestic buyers.

Depreciation, Depletion and Amortization

Costs of mineral rights and developing new mines or significantly expanding the capacity of existing mines are capitalized and amortized using the units of production method, based on estimated proven and probable reserves. Property, plant and equipment are recorded at cost and are generally expensed on a straight-line basis over the useful life of the asset. Costs that extend the useful life or increase the productivity of the assets are capitalized, while normal repairs and maintenance are expensed as incurred. Interest costs applicable to major additions are capitalized during the construction period.

Accretion on Asset Retirement Obligations

Accretion expense represents the increase in the carrying amount of our asset retirement obligations due to the passage of time.

Selling, General and Administrative

Selling, general and administrative expense consists of our general corporate overhead expenses, including management and administrative labor, corporate occupancy expenses, office expenses, and professional fees.

Regulatory Environment

A variety of actions taken by regulatory agencies, including climate change regulation, challenges to the issuance or renewal of our permits to operate, and challenges to the issuance of BLM leases, could substantially increase compliance costs for us and our customers, reduce general demand for coal, or interrupt operations at one or more of our mines.

Critical Accounting Policies and Estimates

Our discussion and analysis of our financial condition, results of operations, liquidity and capital resources is based on our financial statements, which have been prepared in accordance with GAAP. GAAP requires that we make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses, and the related disclosure of contingent assets and liabilities. We base these estimates on historical experience and on various other assumptions that we consider reasonable under the circumstances. On an ongoing basis we evaluate our estimates. Actual results may differ from

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these estimates. Of these significant accounting policies, we believe the following may involve a higher degree of judgment or complexity:

Revenue Recognition

Our revenues are generated primarily under long-term coal supply agreements with electric utilities, industrial companies and coal brokers that in turn sell coal domestically or internationally. Revenue is recognized when title or risk of loss passes to the customer. Title passes generally when the coal is loaded on the rail, ocean vessel or other transportation source that delivers the coal to its destination.

Other revenues primarily include net revenues from contract termination (bookouts) or restructuring payments incurred during the period. Also included are revenues from royalties related to coal lease agreements and revenues from property and facility rentals.

Segment Information

We operate as a single reportable segment, as our Chief Executive Officer, serving as our Chief Operating Decision Maker (CODM), reviews financial information on the basis of our consolidated financial results for purposes of making decisions. Generally, the CODM evaluates performance and allocates resources based on Adjusted EBITDA. Discrete financial information sufficient to allow the CODM to make decisions is only available on a consolidated basis.

Acquired Sales Contracts

Coal supply agreements (sales contracts) acquired in business combinations are capitalized at their fair value and amortized over the tons of coal shipped during the contract. The fair value of a sales contract is determined by discounting the cash flows attributable to the difference between the contract price and the prevailing forward prices for the tons remaining under the contract at the date of acquisition. Contracts where the expected contract price is above market at the acquisition date have a positive value and are classified as assets, whereas contracts where the expected contract price is below market at the acquisition date have a negative value and are classified as liabilities. If a contract is terminated before it has been fully amortized, the remaining fair value of the acquired contract is written off and recognized as a gain (below market contracts) or loss (above market contracts) on contract termination.

Inventory

Coal, parts and supply inventories are valued at the lower of average cost or market. Coal inventory costs include labor, parts and supplies used, equipment costs, transportation costs prior to title transfer to customers, depreciation, depletion, amortization and operating overhead. Coal is classified as inventory at the time the coal is extracted and transported to the mine surface.

Property, Plant and Equipment

Property, plant and equipment are stated at cost, except for assets acquired using purchase accounting, which are recorded at fair value at the date of acquisition. Additions and improvements that significantly add to productive capacity or extend the useful life of assets are capitalized. Interest costs applicable to major asset additions are capitalized during the construction period. Maintenance and repair costs are expensed as incurred. Depreciation is recorded using the straight-line method over the estimated useful lives of the assets. The useful lives of our equipment, plant and facilities generally range from 5 to 10 years with the exception of buildings which have a 20 year useful life.

Mineral rights and mine development costs, which are included with property, plant and equipment, are recorded at cost, except for assets acquired using purchase accounting, which are

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recorded at fair value at the date of acquisition. Depletion of reserves and amortization of mine development costs are computed using the units of production method, based on estimated proven and probable reserves. If coal is extracted during the mine development process, the amount of revenue from the sale of that coal is included in other income in the period earned.

Long-lived assets, such as property, equipment, mine development costs, owned and leased mineral rights and purchased intangibles subject to amortization, are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset or asset groups may not be recoverable. Recoverability of assets or asset groups to be held and used is measured by a comparison of the carrying amount of an asset or asset group to the estimated undiscounted future cash flows expected to be generated by the asset or asset group. If the carrying amount of an asset or asset group exceeds its estimated future cash flows, an impairment charge is recognized equal to the amount by which the carrying amount of the asset or asset group exceeds the fair value of the asset or asset group.

Assets are grouped at the lowest level for which there are identifiable cash flows that are largely independent of the cash flows of other groups of assets. For our active mining operations, we generally group such assets at the mine level, with the exception of impairment evaluations triggered by mine closures. In those cases involving mine closures, the related assets are evaluated at the individual asset level for remaining economic life based on transferability to our other ongoing operations and for use in reclamation activities, or for expected salvage value. For our development properties and portfolio of surface land and coal reserve holdings, we consider several factors to determine whether to evaluate those assets individually or on a grouped basis for purposes of impairment testing. Such factors include geographic proximity to one another, the expectation of shared infrastructure upon development based on future mining plans and whether it would be most advantageous to bundle such assets in the event of sale to a third party.

Asset Retirement Obligations

Our asset retirement obligations ("ARO") liabilities consist of cost estimates for reclamation and support facilities at our mines in accordance with interpretations of applicable federal and state reclamation laws, as defined by each mining permit. These cost estimates relate to reclaiming support acreage, sealing portals at deep mines and other costs related to reclaiming refuse areas.

We estimate our ARO liabilities for final reclamation and mine closure based upon detailed engineering calculations of the amount and timing of the future cash spending for a third party to perform the required work. Cost estimates are escalated for inflation and then discounted at the credit-adjusted, risk-free rate (9% at December 31, 2014 and 2013). Accretion on the ARO begins at the time the liability is incurred. Upon initial recognition of a liability, a corresponding amount is capitalized as part of the carrying amount of the related long-lived asset. The ARO asset is amortized over its expected life on a units-of-production basis. The ARO liability is then accreted to the projected spending date. As changes in estimates occur (such as mine plan revisions, changes in estimated costs, or changes in timing of the performance of reclamation activities), the revisions to the obligation and asset are recognized at the appropriate credit-adjusted, risk-free rate. We review our ARO at least annually and make necessary adjustments for permit changes as granted by state authorities and for revisions of estimates of the amount and timing of costs. Any difference between the recorded obligation and the actual cost of reclamation is recorded in profit or loss in the period the obligation is settled.

Fair Value Measurements

Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. Valuation techniques used must maximize the use of observable inputs and minimize the use of unobservable inputs.

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A three level hierarchy has been established for valuing assets and liabilities based on how transparent (observable) the inputs are that are used to determine fair value, with the inputs considered most observable categorized as Level 1 and those that are least observable categorized as Level 3. Hierarchy levels are defined below:

•: Level 1: Quoted prices in active markets for identical assets and liabilities;
•: Level 2: Quoted prices for similar assets and liabilities in active markets; quoted prices for identical or similar instruments in markets that are not active; and
•: Level 3: Unobservable inputs that are supported by little or no market data which require the reporting entity to develop its own assumptions.

Financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of assets and liabilities and their placement within fair value hierarchy levels.

Our accounts receivable, restricted cash, accounts payable and accrued expenses are considered financial instruments. These assets and liabilities are reflected at fair value or at carrying amounts that approximate their fair value due to the short-term nature or the terms of the instruments. The estimated carrying value of our debt approximates its fair value because the effective interest rates are not significantly different from current market rates. We do not have any nonfinancial assets or nonfinancial liabilities measured at fair value on a recurring basis, other than ARO. The inputs and techniques used to derive ARO fair value are described in the ARO section above. This fair value determination is classified as Level 3 in the hierarchy.

We measure the fair value of certain assets on a non-recurring basis, generally when events or changes in circumstances indicate that the carrying amount of the assets may not be recoverable. Our policy is further described in the property, plant and equipment policies above.

Key Metrics

We assess the performance of our business using certain key metrics. These key metrics include tons produced, tons sold, coal sales realized per ton, direct mining costs per ton and Adjusted EBITDA.

Tons produced is defined as clean tons produced.

Tons sold is defined as produced and purchased tons sold (as applicable).

Coal sales realized per ton is defined as coal sales divided by tons sold.

Direct mining costs per ton is defined as cost of coal sales, exclusive of items shown separately, divided by tons sold.

•: our ability to make distributions to our unitholders;
•: the financial performance of our assets without regard to financing methods, capital structure or historical cost basis;
•: the ability of our assets to generate sufficient cash to pay interest costs and support our indebtedness;
•: our operating performance and return on capital as compared to those of other companies and partnerships in our industry, without regard to financing or capital structure; and

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•: the feasibility of acquisitions and other capital expenditures and the overall rates of return on investment opportunities.

Factors Affecting Comparability of Financial Results

Our historical results of operations and cash flows are not indicative of results of operations and cash flows to be expected in the future principally for the following reasons:

Long-Term Debt

In connection with the closing of this offering, we expect that CFC will be released as a guarantor under our sponsor's Senior Secured Credit Facilities, and that the liens on the assets being contributed to us and securing borrowings under these facilities will be released. Prior to this offering, Finance Corp. issued $ million aggregate principal amount of % senior secured notes due . From and after the satisfaction of the Escrow Release Conditions, which we expect to occur concurrently with the closing of this offering, the partnership will become a co-issuer of the New Notes and a party to the indenture governing the New Notes. In connection with the closing of this offering we also expect to enter into a new $ million revolving credit facility. We expect to use net proceeds from this offering and our offering of the New Notes to repay the outstanding Prudential Notes and the PacifiCorp Notes. Please read "—Liquidity and Capital Resources—Long-Term Debt."

Public Company Expenses

We estimate that we will incur approximately $ million of incremental selling, general and administrative expenses per year associated with being a publicly traded partnership, consisting of expenses associated with SEC reporting requirements, including annual and quarterly reports to unitholders, tax return and Schedule K-1 preparation and distribution, Sarbanes-Oxley Act compliance, listing fees, independent auditor fees, legal fees, investor relations activities, registrar and transfer agent fees, director and officer insurance and director compensation.

CFC Acquisition

Our sponsor acquired CFC on August 16, 2013. The 2013 Successor Period includes the effect of fair value purchase accounting adjustments resulting from the acquisition of CFC by our sponsor. Due to the change in the basis of accounting resulting from the application of purchase accounting, the Predecessor's historical financial data and the Successor's historical financial data are not necessarily comparable.

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Results of Operations

The table below displays our results of operations for the periods indicated.

	Predecessor

	Year Ended December 31, 2013
	Period from January 1, 2013 to August 16, 2013			Period from August 16, 2013 to December 31, 2013			Year Ended December 31, 2014			Three Months Ended March 31, 2014		Three Months Ended March 31, 2015

	(in thousands, except per ton data)
Statements of Operations Data
Coal sales	$	219,140		$	158,756		$	419,804		$	112,265	$	103,924
Other revenues, net		813			1,410			358			89		91
Costs and expenses:
Cost of coal sales, exclusive of items shown separately below		140,781			96,165			232,819			63,115		61,629
Transportation		30,477			19,690			44,439			12,758		12,808
Depreciation, depletion and amortization(1)		21,955			27,251			81,057			18,592		21,334
Accretion on asset retirement obligations		462			—			785			196		206
Selling, general and administrative expenses		7,970			9,586			17,590			3,159		4,173
Amortization of acquired sales contracts, net		—			3,708			12,098			3,181		(54	)

Operating income		18,308			3,766			31,374			11,353		3,919
Other expenses (income):
Interest expense and related financing costs(2)		—			13,604			36,245			9,093		8,021
Gain on sale of assets		(389	)		—			—			—		—
Other		769			—			—			—		—

Net income (loss)	$	17,928		$	(9,838	)	$	(4,871	)	$	2,260	$	(4,102	)



Other Data
EBITDA(3)	$	39,883		$	34,725		$	124,529		$	33,126	$	25,199
Adjusted EBITDA(3)	$	40,725		$	34,725		$	125,314		$	33,322	$	25,405
Tons produced		5,793			3,863			11,386			2,935		2,518
Tons sold		5,614			4,440			11,463			3,175		2,691
Coal sales realized per ton(4)	$	39.03		$	35.76		$	36.62		$	35.36	$	38.62
Direct mining costs per ton(5)	$	25.08		$	21.66		$	20.31		$	19.88	$	22.90

(1): The increase in depreciation, depletion and amortization is primarily the result of the step-up in basis of our coal properties and supporting mine infrastructure upon the acquisition of CFC by our sponsor.
(2): Interest expense increased as the result of our sponsor borrowing $435 million to acquire CFC.
(3): Please read "Selected Historical and Pro Forma Financial and Other Data—Non-GAAP Financial Measures" for the definitions of EBITDA and Adjusted EBITDA and a reconciliation of EBITDA and Adjusted EBITDA to our most directly comparable financial measure, calculated and presented in accordance with GAAP.
(4): Coal sales realized per ton is defined as coal sales divided by tons sold.
(5): Direct mining costs per ton is defined as cost of coal sales, exclusive of items shown separately, divided by tons sold.

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Comparison of Three Months Ended March 31, 2015 to Three Months Ended March 31, 2014

Overview

Our results for the three months ended March 31, 2015 as compared to the three months ended March 31, 2014 were affected by a scheduled 20-day longwall move at our Sufco mine during 2015 that did not occur in 2014, partially offset by increased coal sales realized per ton. As a result of the scheduled longwall move, coal production decreased from 2.9 million tons for the three months ended March 31, 2014 to 2.5 million tons for the three months ended March 31, 2015. In addition, coal sales realized per ton increased 9% from $35.36 for the three months ended March 31, 2014 to $38.62 for the three months ended March 31, 2015. The increase in realization is primarily due to price escalators in our existing coal supply agreements and a change in sales mix reflecting lower export sales that are generally sold at a lower realized price FOB the mine. Our direct mining costs per ton increased from $19.88 for the three months ended March 31, 2014 to $22.90 for the three months ended March 31, 2015 due primarily to the scheduled longwall move at our Sufco mine.

Coal Sales

The following table summarizes coal sales information for the three months ended March 31, 2015 and 2014:

		Successor

		Three Months Ended March 31, 2014			Three Months Ended March 31, 2015			Increase/ (Decrease) $			Increase/ (Decr

Bowie Resource Partners LP S-1