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

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)

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):

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.

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.

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.

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.

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.

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.

"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:

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."

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."

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.

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 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.

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

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.

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

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

"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

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."

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

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

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.

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


		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;


		• 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


		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.


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


		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."

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.

	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;

•: 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		$	$

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.

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:

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

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

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

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:

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.

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

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

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:

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

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

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:

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

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

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.

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.

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

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

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:

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

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.

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

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

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.

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:

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

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.

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:

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

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,

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.

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."

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:

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."

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

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:

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:

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.

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

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

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

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:

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

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:

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

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.

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.

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

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.

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.

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.

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.

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.

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:

(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:

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	$

(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."

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.

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.

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:

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.

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.

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:

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

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.

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:

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

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.

	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)	$	$

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

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)		$

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.

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 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:

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.

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.

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.

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.

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.

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.

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:

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

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."

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:

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

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	$	$	$	$

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.

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."

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.

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:

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"):

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.

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."

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

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.

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.

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 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.

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:

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.

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 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:

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.

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:

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:

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 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.

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:

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.

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.

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:

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 $ .

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.

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 $ .

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

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

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:

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

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.

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.

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:

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.

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:

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.

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.

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.

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.

	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		$	$

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		$	$

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.

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:

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.

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.

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.

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.

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.

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 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.

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.

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.

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

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.

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.

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

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

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.

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.

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.

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 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

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.

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 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.

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:

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.

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.

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

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:

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."

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.

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.

	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

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.

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

Coal sales for the three months ended March 31, 2015 were $103.9 million compared to coal sales of $112.3 million for the three months ended March 31, 2014. The decrease in coal sales was due to a 0.5 million ton decrease in sales volumes reflecting lower export shipments for the period, partially offset by a 9% increase in coal sales realized per ton as compared to the three months ended March 31, 2014, which was primarily driven by contractual price escalators and lower export shipments. The export sales mix decreased to 8% of tons sold during the three months ended March 31, 2015 versus 21% during the three months ended March 31, 2014.

Other revenues, net remained consistent at $0.1 million for both the three months ended March 31, 2015 and 2014.

The following table summarizes cost of coal sales, exclusive of items shown separately, for the three months ended March 31, 2015 and 2014:

Cost of coal sales, exclusive of items shown separately, for the three months ended March 31, 2015 decreased to $61.6 million compared to $63.1 million for the three months ended March 31, 2014. 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. Both changes were primarily driven by the scheduled longwall move at our Sufco mine, which reduced tons produced and in turn impacted our cost per ton.

Transportation expenses remained relatively consistent at $12.8 million for the three months ended March 31, 2015 and 2014, as decreased sales at our Sufco mine due to the scheduled longwall move were fully offset by increased coal sales under the new 15-year coal supply agreement with PacifiCorp for delivery to the Huntington Power Plant that was supplied via truck from our Skyline mine.

Depreciation, depletion and amortization expenses for the year ended March 31, 2015 were $21.3 million compared to $18.6 million for the three months ended March 31, 2014. This increase is primarily driven by amortization of capitalized longwall costs of $2.8 million for the three months ended March 31, 2015 as compared to none for the three months ended March 31, 2014.

Amortization of acquired sales contracts for the three months ended March 31, 2015 were $(0.1) million compared to $3.1 million for the three months ended March 31, 2014. This decrease reflects the declining balance of the intangible asset being amortized as the acquired contracts reach the end of their terms.

Selling, general and administrative expenses for the three months ended March 31, 2015 were $4.2 million compared to $3.2 million for the three months ended March 31, 2014. This increase is primarily driven by increased personnel and legal costs associated with this offering.

Interest expense, net for the three months ended March 31, 2015 was $8.0 million compared to $9.1 million for the three months ended March 31, 2014. Interest expense decreased primarily due to principal debt payments.

We realized a net loss of $4.1 million for the three months ended March 31, 2015 compared to net income of $2.3 million for the three months ended March 31, 2014. This decrease was primarily due to the following: (i) decreased coal sales of $8.4 million, (ii) increased depreciation, depletion and amortization of $2.7 million, and (iii) increased selling, general and administrative expenses of $1.0 million, partially offset by (i) decreased amortization of acquired sales contracts of $3.2 million, (ii) decreased cost of coal sales, exclusive of items shown separately, of $1.5 million, and (iii) decreased interest expense of $1.1 million.

We realized Adjusted EBITDA of $25.4 million for the three months ended March 31, 2015 compared to $33.3 million for the three months ended March 31, 2014. This decrease was primarily due to decreased coal sales of $8.4 million and increased selling, general and administrative expenses of $1.0 million, offset in part by decreased cost of coal sales of $1.5 million.

Our mines sold 11.5 million tons of coal during the year ended December 31, 2014 compared to 5.6 million tons and 4.4 million tons in the 2013 Predecessor Period and the 2013 Successor Period, respectively. Our coal sales realized per ton during 2014 decreased 6.2%, or $2.41 per ton, when compared to the 2013 Predecessor Period and increased 2.4%, or $0.86 per ton, when compared to the 2013 Successor Period. The decrease from the 2013 Predecessor Period is primarily due to (i) pricing declines, as favorably priced coal supply agreements expired and were replaced with new coal supply agreements, (ii) an increase in the percentage of sales at lower export prices and (iii) spot sales at lower market prices. Our direct mining costs per ton during 2014 decreased 19.0%, or $4.77 per ton, when compared to the 2013 Predecessor Period and decreased 6.2%, or $1.35 per ton, when compared to the 2013 Successor Period. 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.

Coal sales for the year ended December 31, 2014 were $419.8 million compared to coal sales of $219.1 million and $158.8 million for the 2013 Predecessor Period and 2013 Successor Period, respectively. The increase in coal sales was due to a 1.4 million ton increase in sales volumes reflecting higher export shipments for the period, partially offset by a decrease in coal sales realized per ton as compared to the 2013 Predecessor Period, which was primarily driven by higher export shipments. The export sales mix increased to 21% of tons sold during 2014 versus only 9% during 2013.

Other revenues, net was $0.4 million during 2014 compared to $0.8 million and $1.4 million for the 2013 Predecessor Period and the 2013 Successor Period, respectively. The decrease in other revenues is due primarily to a payment in the 2013 Successor Period (that did not recur in 2014) by one of our customers in respect of certain governmental impositions that increased our mining costs.

Cost of coal sales, exclusive of items shown separately, for the year ended December 31, 2014 was $232.8 million compared to $140.8 million and $96.2 million for the 2013 Predecessor Period and the 2013 Successor Period, respectively. The decrease is primarily due to decreases in our direct mining costs per ton, partially offset by the increase in tons sold. The decrease in direct mining costs per ton resulted from improved operating efficiencies achieved through higher production levels primarily at our Skyline mine and to a lesser extent at our Sufco mine in the year ended December 31, 2014 compared to the 2013 Predecessor Period and the 2013 Successor Period.

Transportation expenses for the year ended December 31, 2014 were $44.4 million compared to $30.5 million and $19.7 million for the 2013 Predecessor Period and the 2013 Successor Period, respectively. This decrease is due to transportation benefits gained by the Quitchupah Road project (please read "—Liquidity and Capital Resources—Long-Term Debt—Quitchupah Road Debt") as well as increased sales from our Skyline mine, which has direct mine to rail capabilities, partially offset by increased export shipments.

Depreciation, depletion and amortization expenses for the year ended December 31, 2014 were $81.1 million compared to $22.0 million and $27.3 million for the 2013 Predecessor Period and the 2013 Successor Period, respectively. This increase reflects our stepped up basis in equipment and reserves as a result of the acquisition of CFC by our sponsor versus the lower carrying cost held by the Predecessor. Because a new asset basis can inhibit meaningful comparison of historical results before and after the change of control, depreciation, depletion and amortization for 2014 and the 2013 Successor Period are not comparable to depreciation, depletion and amortization for the 2013 Predecessor Period.

Amortization of acquired sales contracts for the year ended December 31, 2014 were $12.1 million compared to $3.7 million for the 2013 Successor Period. This increase reflects a greater amortization period (since acquisition, essentially 4.5 months in 2013 versus 12 months of 2014) over which the intangible asset is amortized. There was no amortization of acquired sales contracts during the 2013 Predecessor Period.

Selling, general and administrative expenses remained relatively consistent at $17.6 million for the year ended December 31, 2014 compared to $8.0 million and $9.6 million for the 2013 Predecessor Period and the 2013 Successor Period, respectively.

Interest expense, net for the year ended December 31, 2014 was $36.2 million compared to $13.6 million (representing 135 days) for the 2013 Successor Period. Interest expense increased as a result of the acquisition debt secured to acquire CFC in August 2013. There was no interest expense for the 2013 Predecessor Period as the Predecessor allocated no corporate or parent company debt to CFC but did allocate interest income on the intercompany cash balance.

We realized a net loss of $4.9 million for the year ended December 31, 2014 compared to net income of $17.9 million for the 2013 Predecessor Period and net loss of $9.8 million for the 2013 Successor Period. This change was primarily due to the following: (i) increased depreciation, depletion and amortization expenses, (ii) increased interest expense, (iii) increased amortization of acquired sales contracts, and (iv) decreased other revenues, partially offset by (i) increased coal sales, (ii) decreased transportation expense, and (iii) decreased cost of coal sales.

We realized Adjusted EBITDA of $125.3 million for the year ended December 31, 2014 compared to $40.7 million and $34.7 million for the 2013 Predecessor Period and the 2013 Successor Period, respectively. This change was primarily due to increased coal sales, decreased transportation expense, and decreased cost of coal sales, offset in part by decreased other revenues.

We expect that our cash flow from operations, available capacity under our new revolving credit facility and issuances of equity and debt securities (including the New Notes) will be sufficient to meet our short-term working capital requirements and long-term capital expenditure requirements.

Following the completion of this offering, we intend to pay a minimum quarterly distribution of $ per common unit and subordinated unit per quarter, which equates to $ million per quarter, or $ million per year, based on the number of common and subordinated units to be outstanding immediately after completion of this offering, to the extent we have sufficient cash from our operations after establishment of cash reserves and payment of fees and expenses, including payments to our general partner and its affiliates. We do not have a legal obligation to pay this distribution. Please read "Cash Distribution Policy and Restrictions on Distributions."

Our other primary uses of cash include, but are not limited to, the cash costs of coal production, capital expenditures, coal reserve lease and royalty payments, production taxes, debt service costs (interest and principal), lease obligations, transportation and throughput agreements and member distributions. We have made significant capital expenditures to develop our existing mines and related transportation infrastructure. Future longwall development and the associated capital expenditures will continue to be implemented sequentially and will be dependent on our operating cash flow and our access to the capital markets. We estimate that it could cost approximately $100.0 million (based on our experience developing our existing operations and the projected mine plans) to develop the Fossil Rock reserves. In the event that the capital markets are unavailable, we are not obligated or committed to use cash for expansion capital expenditures and would adjust the timing and pace of our growth accordingly.

Historically, we did not make a distinction between maintenance capital expenditures and expansion capital expenditures. For the year ended December 31, 2014 and the three months ended March 31, 2015, we incurred capital expenditures of $28.5 million and $6.0 million, respectively. We expect to spend $ million and $ million on maintenance capital expenditures for the year ending December 31, 2015 and for the twelve months ending June 30, 2016, respectively, and $ million and $ million on expansion capital expenditures for the year ending December 31, 2015 and for the twelve months ending June 30, 2016, respectively. Please read "Cash Distribution Policy and Restrictions on Distributions."

The following is a summary of net cash provided by or used in each of the indicated types of activities during the periods indicated:

Net cash provided by operating activities was $5.5 million for the three months ended March 31, 2015 compared to $12.9 million provided by operating activities for the three months ended March 31, 2014. The decrease in net cash provided by operating activities was largely due to decreased net (loss) income as adjusted for noncash items of $7.0 million in addition to a decrease in working capital of $0.5 million. The decrease in net (loss) income as adjusted for noncash items is due primarily to decreased coal sales and increased selling, general and administrative expenses, offset in part by decreased cost of coal sales and decreased interest expense.

Net cash used in investing activities was $6.0 million for the three months ended March 31, 2015 compared to $1.1 million for the three months ended March 31, 2014. The increase in cash used in investing activities related entirely to timing of investments in property, plant and equipment.

Net cash provided by financing activities was $0.5 million for the three months ended March 31, 2015 compared to $11.8 million used in financing activities for the three months ended March 31, 2014.

Both periods include substantial member distributions and proceeds/payments on long-term debt and notes payable as illustrated in the table below:

The following is a summary of net cash provided by or used in each of the indicated types of activities during the periods indicated:

Net cash provided by operating activities was $84.5 million for the year ended December 31, 2014 compared to $46.0 million and $14.9 million provided by operating activities for the 2013 Predecessor Period and the 2013 Successor Period, respectively. The increase in net cash provided by operating activities was largely due to increased net income as adjusted for noncash items of $30.6 million, partially offset by a decrease in working capital of $6.9 million. The increase in net income as adjusted for noncash items is due primarily to increased coal sales, decreased transportation costs and decreased cost of coal sales, offset in part by increased interest expense. The decrease in working capital is primarily driven by increased inventory, offset partially by decreased accounts receivable.

Net cash used in investing activities was $27.0 million for the year ended December 31, 2014 compared to $5.2 million and $8.4 million used in investing activities for the 2013 Predecessor Period and the 2013 Successor Period, respectively. The primary use of cash during the periods related to investments in property, plant and equipment of $28.5 million for the year ended December 31, 2014 compared to $5.7 million and $3.8 million for the 2013 Predecessor Period and the 2013 Successor Period, respectively. During the year ended December 31, 2014, our surety company returned $1.5 million of the $4.6 million of cash previously retained as collateral for our reclamation bonds during the 2013 Successor Period.

Net cash used in financing activities was $57.5 million for the year ended December 31, 2014, compared to $40.8 million and $6.5 million used in financing activities for the 2013 Predecessor Period and the 2013 Successor Period, respectively. Both periods include substantial member distributions and non-related party note proceeds/payments as illustrated in the table below:

On August 16, 2013, our sponsor entered into loan documentation (collectively, the "Senior Secured Credit Facilities") to finance the purchase of CFC. The Senior Secured Credit Facilities provided for a $35.0 million senior secured asset-backed revolving credit facility, a $335.0 million senior secured first lien term loan and a $100.0 million senior secured second lien term loan.

Under the Senior Secured Credit Facilities, the maximum senior secured leverage ratio of our sponsor must not exceed 3.5x as of March 31, 2015 or December 31, 2014. Our sponsor was in compliance with this covenant as of March 31, 2015 and December 31, 2014.

Certain of our subsidiaries guarantee, and the equity interests and substantially all of the assets of certain of these subsidiaries secure, the Senior Secured Credit Facilities. Following the closing of this offering, we expect that neither we nor our subsidiaries will have ongoing liabilities and obligations under the Senior Secured Credit Facilities and that the liens on the assets of certain of our subsidiaries securing borrowings under these facilities will be released. Please read Note 8 to the historical financial statements for the years ended December 31, 2014 and 2013 included elsewhere in this prospectus for information on the Senior Secured Credit Facilities.

In 2012, CFC entered into an agreement with the State of Utah for the construction of a paved county road (the "Quitchupah Road") to shorten its transportation routes from the Sufco mine to PacifiCorp's Hunter Power Plant. The Quitchupah Road project was funded by CFC through the issuance of County Municipal Financing Bonds with Sevier County, Utah ("Sevier").

CFC agreed to repay Sevier for the cost of the road with repayments to begin once construction was complete. The original principal amounts owed to Sevier are comprised of a $29.9 million repayment agreement for construction of the Quitchupah Road and a $1.4 million promissory note for reimbursement of road improvement costs incurred prior to the start of the Quitchupah Road project. The promissory note matures on March 1, 2018 and incurs interest at 2.5% annually and is payable in arrears. Principal and interest payments for the promissory note commenced on March 1, 2014 and are payable in five equal annual installments of $293,000. The repayment agreement matures on March 1, 2027 and incurs interest at 2.4% annually. Principal and interest payments for the repayment agreement

commenced on March 1, 2014 and are payable in 14 annual installments of varying amounts as specified in the repayment agreement.

CFC had outstanding equipment notes totaling $10.8 million and $12.5 million with Prudential Insurance Company of America as of March 31, 2015 and December 31, 2014, respectively. These 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 notes are secured by liens on the related equipment and are guaranteed by subsidiaries of our sponsor. CFC recorded $312,000 of capitalized deferred financing costs related to these notes during 2013, which are being amortized over the term of the notes. Unamortized deferred financing costs approximated $165,000 and $191,000 as of March 31, 2015 and December 31, 2014, respectively. We expect to repay the outstanding Prudential Notes in full with proceeds from this offering. Please read "Use of Proceeds."

In June 2015, two of our wholly owned subsidiaries issued notes in connection with the Utah Transaction. Hunter Prep Plant, LLC issued a $10 million note in favor of PacifiCorp, which bears interest at 7% and matures on December 31, 2019. Fossil Rock Resources, LLC issued a $30 million note in favor of Fossil Rock Fuels LLC, an affiliate of PacifiCorp, which bears interest at 7% and matures on the earlier of August 31, 2015 or the refinancing of the Senior Secured Credit Facilities.

The notes are guaranteed by our sponsor and are subordinated to the Senior Secured Credit Facilities. We expect to repay the outstanding PacifiCorp Notes in full with net proceeds from this offering and the offering of the New Notes. Please read "Use of Proceeds."

In February 2015, our sponsor financed annual insurance premiums for its insurance policies in the amount of $13.3 million with Imperial Premium Financing Specialists ("IPFS"). The note bears interest at 3.9% with monthly payments of $1.2 million. Amounts owed by our sponsor to IPFS for financed insurance premiums totaled $9.5 million as of March 31, 2015, of which $7.2 million was allocated to CFC. No amounts were outstanding with IPFS as of December 31, 2014.

In connection with the closing of this offering, we expect to enter into a -year, $ million revolving credit facility. The credit facility will be available to fund working capital, for the issuance of letters of credit, to finance capital expenditures and other permitted payments and for other lawful corporate purposes. Borrowings under the credit facility will bear interest at .

The credit facility will contain representations and warranties and affirmative and negative covenants customary for transactions of this nature.

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 "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.

Interest payments will be due semi-annually on and . Subject to certain limitations, we will be able to redeem some or all of the New Notes by paying specified redemption prices in excess of the principal amount, plus accrued and unpaid interest, if any, prior to , 20 or by paying their principal amount thereafter, plus accrued and unpaid interest, if any.

The New Notes will be jointly and severally guaranteed by all of our existing and future restricted subsidiaries that guarantee our debt under our new revolving credit facility, and will be secured by substantially all of our assets.

The indenture governing the New Notes, among other things, will limit our ability and the ability of our restricted subsidiaries to incur additional indebtedness and issue preferred equity; pay dividends or distributions; repurchase equity or repay subordinated indebtedness; make investments or certain other restricted payments; create liens; sell assets; enter into agreements that restrict dividends, distributions, or other payments from restricted subsidiaries; enter into transactions with affiliates; and consolidate, merge, or transfer all or substantially all of their assets and the assets of their restricted subsidiaries on a combined basis.

Upon the occurrence of certain transactions constituting a "change in control" as defined in the indenture, holders of our New Notes could require us to repurchase all outstanding New Notes at % of the principal amount thereof, plus accrued and unpaid interest, if any, to the date of repurchase.

In the normal course of business, we are party to certain off-balance sheet arrangements, including operating leases, coal reserve leases, take-or-pay transportation obligations, bank letters of credit and surety bonds. Liabilities related to these arrangements are generally not reflected in our consolidated balance sheet and except for coal reserve leases, take-or-pay transportation obligations and operating leases, we do not expect any material impact on our cash flows, results from operations or financial condition to result from these off-balance sheet arrangements.

We use surety bonds to secure reclamation and other miscellaneous obligations. As of March 31, 2015 and December 31, 2014, outstanding surety bonds with third parties for post-mining reclamation totaled approximately $24.4 million and $23.8 million, respectively. We had restricted cash totaling $3.1 million as of both March 31, 2015 and December 31, 2014, to secure bonding obligations.

We define market risk as the risk of economic loss as a consequence of the adverse movement of market rates and prices. We believe our principal market risks include commodity price risk, interest rate risk and credit risk, which are disclosed below.

We have commodity price risk as a result of changes in the market value of our coal. We try to minimize this risk by entering into long-term fixed-price coal supply agreements that provide for price escalators, and we may from time to time enter into commodity hedge agreements. As of March 31, 2015 and December 31, 2014, we had 11.2 million tons committed and priced (subject to price escalators) for 2015 and 9.9 million tons expected and priced (subject to price escalators) for 2016. Currently, we have 9.0 million tons expected and priced for 2016. We did not have any hedges in place as of March 31, 2015 or December 31, 2014.

We are exposed to market risk associated with interest rates due to our existing level of indebtedness. At the closing of this offering, we expect to have total borrowings outstanding of $ million. The impact of a 1% increase in the interest rate on this amount of debt would result in an increase in interest expense, and a corresponding decrease in our results of operations, of approximately $ million annually, assuming that our indebtedness remained constant throughout the year. We may use certain derivative instruments to hedge our exposure to variable interest rates in the future, but we currently do not have any hedges in place.

We have credit risk associated with our customers and counterparties in our coal supply agreements. We have procedures in place to assist in determining the creditworthiness for such customers and counterparties. Generally our customers pay for individual train or vessel shipments. In other cases, several of our electric utility customers pay multiple times within a month to limit our exposure. At both March 31, 2015 and December 31, 2014, no allowance was recorded for uncollectible accounts receivable as all amounts were deemed collectible.

The following is a summary of our significant contractual obligations as of March 31, 2015:

(1): Includes $343.3 million attributable to our sponsor's Senior Secured Credit Facilities, $25.8 million attributable to the Quitchupah Road debt, $10.8 million attributable to the Prudential Notes, and $7.2 million attributable to the IPFS notes. Excludes interest payments due to uncertainty about their timing and/or amounts as well as $8.6 million of unamortized discounts. 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 the liens on the assets contributed to us and securing borrowings under these facilities will be released. As a result, neither we nor the subsidiaries that will be contributed to us will have ongoing liabilities and obligations under the Senior Secured Credit Facilities. We expect to repay the outstanding Prudential Notes in full with proceeds from this offering. In connection with the closing of this offering, we expect to enter into a -year, $ million revolving credit facility under which we expect to have $ million of borrowings upon completion of this offering, and issue $ million aggregate principal amount of our % senior secured notes due .
(2): Represents future minimum cash payments due under our various coal reserve lease and royalty obligations.
(3): Represents future minimum cash payments due under our various operating leases.
(4): The contractual obligation table does not include asset retirement obligations. Asset retirement obligations result primarily from statutory, rather than contractual, obligations and the ultimate timing and amount of the obligations are an estimate. As of March 31, 2015 and December 31, 2014, we had $9.4 million and $9.2 million, respectively, recorded to our balance sheet for asset retirement obligations.

A substantial amount our coal is produced from mineral reserves 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 through the process described under "Business—Coal Reserves and Non-Reserve Coal Deposits—Reserve Acquisition Process." These leases are generally for an initial term of ten years but may be extended by diligent development and mining of the reserves until all economically recoverable reserves are depleted. We have met the diligent development requirements for substantially all of these federal leases either directly through production, by including the lease as a part of a logical mining unit with other leases upon which development has occurred, or by paying an advance royalty in lieu of continued operations. Annual production on these federal leases must total at least 1% of the original amount of coal in the entire logical mining unit. In addition, royalties are generally payable monthly at a rate of 8% of the gross realization for coal produced using underground mining methods. Many BLM leases also require payment of a lease rental or minimum royalty, payable either at the time of execution of the lease or in periodic installments. The remainder of our leased coal is generally leased from state governments, land holding companies and various individuals. The duration of these leases varies. Typically, the lease terms are automatically extended as long as active mining continues. Royalty payments are generally based upon a specified rate per ton or a percentage of the gross realization from the sale of the coal.

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

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, (ii) the Skyline mine, near Scofield, Utah, which is a longwall operation, and (iii) the Dugout Canyon mine, near Price, Utah, which has been a longwall operation but is currently a multi-continuous miner operation. 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. According to Wood Mackenzie, we are one of the largest producers of low-cost, high margin thermal coal in the Western Bituminous region. Our operations are some of the safest underground coal mines in the United States. Since 2011, we have reduced our total reportable injury rate by approximately 67%, to 0.5, and have been recognized for our outstanding performance in environment, health and safety management through our receipt of numerous environmental and safety awards.

Our high Btu, low sulfur coal reserves, highly skilled and experienced, non-union workforce and industry leading safety track record have made us one of the most productive underground bituminous coal producers in the United States. As shown in the chart below, 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.

Clean coal production tons per employee man hour. Darker shading denotes mines operated by us.

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 high productivity of our mines and our focus on cost control has enabled us to achieve low direct mining costs per ton. During 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.

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 (described below), 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, which should provide significant sustainable revenue and allow us to generate stable and reliable cash flows. These estimates are based on our historical relationship with our customers and management's knowledge of the customers' coal requirements and the customers' other coal supply arrangements.

As part of our domestic sales portfolio, we have multi-year coal supply agreements with PacifiCorp and 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 "—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 "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.

These international markets provide us with alternatives to our core domestic market, diversification of our customer base and an important economic outlet for our coal. Since the acquisition of our mines by our sponsor in August 2013, our coal has been successfully exported to customers in Mexico, Japan, China, Guatemala, Chile and Hawaii. Through our sponsor, we are the only coal producer with contracted U.S. West Coast export capacity, with access to an aggregate throughput capacity of approximately 5.7 million tons per year (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). Prior to our sponsor leasing these terminals, no significant amount of thermal coal had been shipped through these terminals for over 10 years.

For the year ended December 31, 2014, our sponsor exported approximately 3.3 million tons through the Port of Stockton, California and the Levin-Richmond Terminal, and we expect our sponsor to export approximately 1.0 million tons through these terminals for the year ending December 31, 2015. In addition, we export through the Port of Long Beach, California. For the year ended December 31, 2014, we exported approximately 500,000 tons of our coal through the Port of Long Beach, California. We do not expect that a material portion of our coal will be exported through this port for the year ending December 31, 2015.

Trafigura AG is the exclusive marketer of our uncommitted coal, and its parent company, Trafigura BV, indirectly owns a minority interest in our sponsor through Galena. 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.

Utah Transaction. On June 5, 2015, we acquired (through our wholly-owned subsidiary, Fossil Rock Resources, LLC) 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 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. We plan to begin development of the Fossil Rock reserves in 2017, begin production from the Fossil Rock reserves with continuous miner units in 2018 and spend approximately $100.0 million ratably between 2017 and 2021 to move the Sufco mine longwall system to Fossil Rock for operation in 2021. 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. As part of the Utah Transaction, we also acquired (through our subsidiary, Hunter Prep Plant, LLC) certain real property near PacifiCorp's Hunter Power Plant, which we believe will enhance our coal blending capabilities for deliveries to the Hunter Power Plant.

Flat Canyon Lease. 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, which contains approximately 14.2 million tons and 15.2 million tons of proven and probable reserves, respectively. The issuance by the BLM of the lease of the Flat Canyon tract remains subject to a 30-day antitrust review of 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 "—Coal Reserves and Non-Reserve Coal Deposits—Reserve Acquisition Process."

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

One of our principal strengths is our relationship with our sponsor. Our sponsor is owned by Cedars and 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, 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. Over the last four years, our sponsor has permitted, developed and/or operated four separate coal mining operations in the Western Bituminous region. In addition to acquiring CFC in 2013, our sponsor owns the Bowie #2 mine, located in Paonia, Colorado, which produced 2.4 million tons and 3.3 million tons of coal in 2014 and 2013, respectively. Our sponsor will retain the Bowie #2 mine and any related assets after the IPO Reorganization. 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.

Upon consummation of this offering, we will be 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.

In connection with the closing of this offering, we expect to enter into the following agreements with our sponsor and its affiliates:

For more information, please read "Certain Relationships and Related Party Transactions—Agreements with Affiliates in Connection with the Transactions."

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 has one longwall system and three continuous miner units with a productive capacity of approximately 7.0 million tons per year, (ii) the Skyline mine, near Scofield, Utah, which has one longwall system and two continuous miner units 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. We operate as one 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.

The Sufco mine has longwall and continuous miner reserves in the Upper Hiawatha and Lower Hiawatha seams, which have an average seam thickness of 10 feet. The Skyline mine has longwall and continuous miner reserves in the Lower O'Connor A, Lower O'Connor B and Flat Canyon seams, which have an average seam thickness of 10 feet. Please read "Prospectus Summary—Recent Developments—Flat Canyon Lease" for a description of the status of the Flat Canyon tract. The Dugout Canyon mine has longwall and continuous miner reserves in the Gilson and Rock Canyon seams in the Book Cliffs coalfield, which have an average seam thickness of 7 feet. The Dugout Canyon mine also has potential access to coal deposits in the adjacent Gilson seam northwest of current operations for which we are evaluating for future expansion. We produced 11.4 million tons and 9.7 million tons of high Btu coal for the years ended December 31, 2014 and 2013, respectively.

On June 5, 2015, we acquired the Fossil Rock reserves from an affiliate of PacifiCorp, which 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 plan to begin development of the Fossil Rock reserves in 2017, begin production from the Fossil Rock reserves with continuous miner units in 2018 and spend approximately $100.0 million ratably between 2017 and 2021 to move the Sufco mine longwall system to Fossil Rock for operation in 2021. 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. In addition, we expect to obtain a lease from the BLM through the lease by application process, described in further detail under "—Coal Reserves and Non-Reserve Coal Deposits—Reserve Acquisition Process," for the Greens Hollow tract, which contains approximately 50.5 million tons of non-reserve coal deposits accessible through our Sufco mine. Assuming our acquisition of the Greens Hollow tract, and subject to suitable demand in either domestic or international markets, we will have the ability to add a new longwall system to the Sufco mine to enable it to produce up to 7.0 million tons per year from the Lower Hiawatha seam. This production from the Sufco mine's Lower Hiawatha seam would replace the production from the Sufco mine's Upper Hiawatha seam and would be in addition to the 4.0 million tons of coal produced per year from the Fossil Rock reserves.

On a pro forma basis, after giving effect to the closing of the Utah Transaction and the BLM's issuance of the Flat Canyon lease to us, the following table summarizes our assets and operations as of December 31, 2014:

	Sufco		Skyline			Dugout Canyon(1)		Fossil Rock(2)		Total

Location		Sevier County, UT		Carbon County, UT			Carbon County, UT		Emery County, UT
Type of mining		Longwall, Continuous miner		Longwall, Continuous miner			Continuous miner		Longwall Continuous miner
Reserves: (million tons)(3)
Proven reserves		33.0		33.4	(4)		10.7		11.2		88.3	(4)
Probable reserves		28.2		21.4	(4)		1.6		32.5		83.7	(4)
Total proven and probable		61.2		54.8	(4)		12.3		43.7		172.0	(4)
Annual capacity (million tons)		7.0		4.5			1.1		—		12.6
Production: (million tons)(5)
2014		6.5		4.2			0.7		—		11.4
2013		6.0		3.1			0.6		—		9.7
Coal sales realized per ton(6)
2014	$	39.14	$	32.74		$	35.66	$	—	$	36.62
2013	$	37.63	$	36.87		$	39.73	$	—	$	37.59
Btu per pound(7)		10,916		11,540			11,844		11,550		—
Sulfur (%)		0.43		0.44			0.80		0.57		—
Loadouts		Levan & Salina		Skyline			Savage Energy Terminal		Fossil Rock		—
Transportation		Rail, Truck		Rail, Truck			Rail, Truck		Truck		—
Preparation plant		Castle Valley		Castle Valley			Castle Valley		—		—

(1): Subject to suitable demand in either domestic or international markets, we have the ability to add a third continuous miner unit to the Dugout Canyon mine without any additional surface infrastructure, and increase its productive capacity from approximately 1.1 million tons per year to approximately 1.5 million tons per year.
(2): We acquired the Fossil Rock reserves from an affiliate of PacifiCorp on June 5, 2015. 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. Please read "—Overview—Recent Developments—Utah Transaction."
(3): Includes both assigned and unassigned reserves.
(4): 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, which contains approximately 14.2 million tons and 15.2 million tons of proven and probable reserves, respectively. The issuance by the BLM of the lease of the Flat Canyon tract remains subject to a 30-day antitrust review of 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 "—Coal Reserves and Non-Reserve Coal Deposits—Reserve Acquisition Process."
(5): Production is based upon our system of record.
(6): Coal sales realized per ton is defined as coal sales divided by tons sold.
(7): All Btus per pound are expressed on an as-received basis, including total moisture.

With over 88 million tons and 84 million tons of proven and probable coal reserves, respectively, including the Fossil Rock reserves and the Flat Canyon tract, we believe we are among the largest holders of coal reserves in the Western Bituminous region. Our reserves have thick coal seams and are characterized by roof and floor geology favorable for longwall mining.

The Sufco mine is located on 27,550 acres in Sevier County, Utah approximately 30 miles northeast of Salina, Utah and 125 miles south of Salt Lake City, Utah. The Skyline mine is located on 12,290 acres in Carbon County, Utah approximately five miles southwest of Scofield, Utah and approximately 30 miles northwest of Price, Utah. The Dugout Canyon mine is located on 9,691 acres in Carbon County, Utah approximately 12 miles northeast of Price, Utah. The Sufco and Skyline mines are in the Wasatch Plateau coalfield and the Dugout Canyon mine is in the Book Cliffs coalfield, all of which are part of the Uinta Basin.

The Wasatch Plateau coalfield extends southwest about 90 miles from western Carbon County, Utah through western Emery County and into eastern Sanpete and Sevier Counties. The Wasatch coalfield is 13 to 22 miles wide. The eastern edge is bounded by the outcrop of the coal-bearing Blackhawk Formation and the western edge is bounded by a series of faults near the western edge of the Wasatch Plateau. Carbon and Emery Counties contain the northern and central Wasatch Plateau coalfield areas. Most of the coal in the Wasatch Plateau is in the lower third of the Blackhawk Formation. Eight coal beds have been identified that contain coal seams more than seven feet thick.

The northern part of the Wasatch Plateau coalfield is directly served by rail transportation. One spur leaves the main line of the Union Pacific railroad at the town of Colton and extends 15 miles southwest to serve the mines near Scofield, Utah, including the Skyline mine. Three other spurs branch

off at the town of Helper, with two running five miles west, one to the Savage Energy Terminal and the other one to our Levan rail loadout.

The Book Cliffs coalfield extends 70 miles across northern Carbon and eastern Emery Counties, with an average width of four miles. The field parallels the path of a Union Pacific railroad line, which offers operators in this field a transportation cost advantage, facilitating shorter truck hauls to the rail line. The coal beds in the Book Cliffs coalfield occur in the Upper Cretaceous Blackhawk Formation.

The Sufco mine has longwall and continuous miner reserves in the Upper Hiawatha and Lower Hiawatha seams, which have an average seam thickness of 10 feet. Sufco is currently mining the Upper Hiawatha seam. We plan to continue production from the Upper Hiawatha seam through the third quarter of 2021, after which time we plan to move the Sufco longwall system to Fossil Rock, which contains approximately 11.2 million tons and 32.5 million tons of high Btu, low sulfur proven and probable reserves, respectively, providing a natural replacement for the low sulfur coal currently produced from the Sufco mine's Upper Hiawatha seam. In addition, we expect to obtain a lease from the BLM through the lease by application process, described in further detail under "—Coal Reserves and Non-Reserve Coal Deposits—Reserve Acquisition Process," for the Greens Hollow tract, which contains approximately 50.5 million tons of non-reserve coal deposits accessible through our Sufco mine. Assuming our acquisition of the Greens Hollow tract, and subject to suitable demand in either domestic or international markets, we will have the ability to add a new longwall system to the Sufco mine to enable it to produce up to 7.0 million tons per year from the Lower Hiawatha seam. This production from the Sufco mine's Lower Hiawatha seam would replace the production from the Sufco mine's Upper Hiawatha seam and would be in addition to the 4.0 million tons of coal produced per year from the Fossil Rock reserves.

The expected life of mine sequence for the Sufco mine and Greens Hollow tract is set forth below:

The Sufco mine consists of a longwall, three continuous miner sections and a loadout facility located in Levan, Utah approximately 82 miles from the mine. The longwall panels are typically 1,100 feet wide and vary in length from 2,400 to 12,000 feet. The Sufco mine is producing coal with one longwall system and three continuous miner units, with a productive capacity of approximately 7.0 million tons per year.

Access at the Sufco mine is by drift portal entry from the coal seam outcrop at approximately 7,550 feet of elevation. Handling and surface facilities, including coal stockpiles, truck loading facilities, mine operations, materials supplies, warehouse and offices are all located near the mine portal. Raw coal is hauled from the mine by truck either directly to customers or to the Levan rail loadout where it is transloaded and shipped by the Union Pacific railroad. The truck-loading facility is adjacent to the mine and allows for loading approximately 8.0 million tons per year of coal via truck. The facility is equipped with a truck scale and sampling station, with coal sampled automatically as trucks exit the loadout. The facility is capable of loading two 43-ton trucks per minute and loading 800 to 900 trucks per 24-hour period. As necessary to meet customer requirements, we selectively wash a portion of the

coal produced from the Sufco mine at our 400 ton-per-hour Castle Valley preparation plant ("Castle Valley Prep Plant"), which is located at the Savage Energy Terminal. In 2006, we invested approximately $5.6 million to upgrade the Castle Valley Prep Plant, which has been leased to us through 2016 and will automatically renew for additional one year periods unless either party provides notice of termination not less than three months prior to a renewal period. Lease payments consist of a fixed fee plus a variable fee based on throughput.

We have a coal storage and blending facility located approximately 11 miles from the Sufco mine. The facility provides approximately 1.4 million tons of stockpile capacity. Its location allows for surge storage capacity should market conditions warrant increased production at the Sufco mine and facilitates additional coal blending flexibility to meet customer requirements.

The Levan rail loadout, which is located 82 miles from the Sufco mine, maintains 1.2 million tons of stockpile capacity in three separate stockpiles with blending capabilities to meet customer specifications. The Levan rail loadout is capable of railcar loading at 4,000 tons per hour and has sufficient rail loop siding capacity to accommodate unit trains of 104 railcars. For the years ended December 31, 2014 and 2013, we shipped 2.7 million tons and 2.8 million tons, respectively, through the Levan rail loadout. The Salina yard is a truck loadout and surge yard for truck direct customers. The loadout has two piles, one with 0.2 million tons of stockpile capacity and one with 0.5 million tons of stockpile capacity. The truck loading capacity is approximately 20 trucks per hour.

In 2012, we entered into an agreement with State of Utah for the construction of the Quitchupah Road. The Quitchupah Road reduced the truck haul distance from the Sufco mine to PacifiCorp's Hunter Power Plant, the largest customer of Sufco mine coal, by 23 miles, resulting in estimated savings of $2.32 per ton delivered. Our coal storage and blending facility is also located near the Quitchupah Road, which further enhances the transportation, blending and coal storage flexibility of our Sufco mine. The Quitchupah Road was completed in 2013.

Distances (via truck) from the Sufco mine to key customers and transloading facilities are set forth in the table below:

The Savage Energy Terminal, which is owned and operated by Savage, transloads coal from all three of our mines on a price-per-ton basis. Our transloading agreement with Savage extends into 2017 and will be automatically renewed annually unless either party provides notice of termination to the other party. The Savage Energy Terminal has an annual throughput capacity of approximately 8.0 million tons, and is capable of loading 10,000-ton unit trains at 6,500 tons per hour. The storage capacity at the facility is approximately 2.0 million tons. The Savage Energy Terminal is located on the Castle Valley spur of the Union Pacific rail line, which connects to the Union Pacific railroad mainline near Wellington, Utah. As of December 31, 2014, we ship approximately 500,000 tons of Sufco mine coal through the Savage Energy Terminal per year.

The Skyline mine includes longwall mineable underground reserves in the Lower O'Connor A, Lower O'Connor B and Flat Canyon seams, which have an average seam thickness of 10 feet. Skyline is currently mining the Lower O'Connor A seam in the Wasatch Plateau coalfield. We plan to continue production of the Lower O'Connor A seam through 2017. After completion of this area, we plan to

move into the Flat Canyon tract, which contains approximately 14.2 million tons and 15.2 million tons of proven and probable reserves, respectively, and which we expect to mine through 2029.

The Skyline mine consists of a longwall, two continuous miner sections and a loadout facility. The longwall panels are typically 850 feet wide and vary in length from 1,800 feet to 6,800 feet, depending upon prevailing geological conditions and factors. Gate roads are developed on a two-entry system utilizing a yield pillar design. The Skyline mine is producing coal with one longwall system and two continuous miner units, with a productive capacity of approximately 4.5 million tons per year.

Access to the Skyline mine is by drift portal entry at approximately 8,500 feet of elevation, making Skyline the highest elevation active coal mine portal in the United States. Surface and handling facilities, including coal stockpiles, mine operations, materials supplies, warehouse and mine offices, are located at the mine portal. Rail-loading facilities are located on the Union Pacific railroad spur near the mine, supplied through a 2.2-mile long overland tubular conveyor. Skyline's surface facilities include raw coal storage capacity of 300,000 tons and a run of mine silo with an additional 8,000 tons of storage capacity. At the rail loadout, a 40,000-ton capacity stockpile is flanked with two 15,000-ton capacity silos facilitating efficient loading of railcars.

Raw coal from the Skyline mine is transported directly by an overland conveyor belt system to the Skyline truck and rail loadout facility and then shipped to customers by truck or the Union Pacific railroad. We selectively wash a portion of the coal produced from the Skyline mine at the Castle Valley Prep Plant. The Skyline loadout facility is located on the Scofield spur of the Union Pacific railroad 2.2 miles from the mine. It receives coal through an enclosed tubular overland conveyor system that transports coal at rates up to 1,400 tons per hour. The Skyline mine is the only operating underground coal mine in Utah that can load directly into a train without the use of trucks. The loadout facility is capable of loading railcars at the rate of 5,000 tons per hour and is served by the Union Pacific railroad. The Skyline mine's conveyor belt system is a single flight conveyor that is 2.2 miles long and drops 600 feet in elevation from the tail pulley to the head pulley. The belt travels in a west-to-east direction from the Skyline mine crusher building to the existing rail loadout. The pipe conveyor includes elevated sections that allow for animal migration. The truck loading capacity for the Skyline mine is approximately 230 trucks per day.

Distances (via truck) from the Skyline mine to key customers and transloading facilities are set forth in the table below:

In the year ended December 31, 2014, we did not ship Skyline mine coal through the Savage Energy Terminal.

The Dugout Canyon mine includes both longwall and continuous miner reserves in the Gilson and Rock Canyon seams in the Book Cliffs coalfield, which have an average seam thickness of 7.2 and 7.5 feet, respectively. Dugout Canyon also has potential reserves in the adjacent Gilson Northwest seam. Future expansion opportunities in the Gilson Northwest seam are being evaluated.

The Dugout Canyon mine recently completed mining the last longwall panel in the Gilson seam in the south section of the mine and began retreating from this area in the first quarter of 2013. As of January 2015, two continuous miner units were mining a reserve block in the Rock Canyon seam. Subject to suitable demand in either domestic or international markets, we have the ability to add a third continuous miner unit to the Dugout Canyon mine without any additional surface infrastructure, and increase its productive capacity from approximately 1.1 million tons per year to approximately 1.5 million tons per year. We plan to continue production from the Rock Canyon seam through December 2020. After completion of this area, we plan to move into Gilson North 4, which we expect to mine through July 2026.

The expected life of mine sequence for the Dugout Canyon mine is set forth below:

The Dugout Canyon mine consists of one continuous miner section and a truck loadout facility. Access to the Dugout Canyon mine is by drift portal entry at approximately 7,100 feet of elevation. Coal handling and surface facilities, including stockpiles, truck loadouts, mine operations, materials supplies, warehouse and offices, are located near the mine portal. Dugout Canyon's surface facilities include raw coal storage capacity of 130,000 tons and a raw coal stockpile area with live reclaim to the truck loadout. Dugout Canyon's truck loadout is adjacent to mine operations. The facility allows for the loading of 11 to 12 million tons per year of coal via truck. The facility is equipped with truck scales and a sampling station, with coal sampled automatically as trucks exit the loadout. The facility typically loads 150 to 200, 43-ton trucks per day.

Raw coal from the Dugout Canyon mine is trucked to local markets and to the Savage Energy Terminal, which is approximately 20 miles from the mine, where it can be shipped via the Union Pacific and Burlington Northern Santa Fe railroads. We selectively wash a portion of the coal produced from the Dugout Canyon mine at the Castle Valley Prep Plant, and as of December 31, 2014, we ship approximately 600,000 tons of Dugout Canyon mine coal through the Savage Energy Terminal per year.

On June 5, 2015, we acquired the Fossil Rock reserves from an affiliate of PacifiCorp, which increase our proven and probable reserves by an estimated 11.2 million tons and 32.5 million tons, respectively. We plan to begin development of the Fossil Rock reserves in 2017, begin production from the Fossil Rock reserves with continuous miner units in 2018 and spend approximately $100.0 million ratably between 2017 and 2021 to move the Sufco mine longwall system to Fossil Rock for operation in 2021. 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.

Distances (via truck) from the Fossil Rock reserves to key customers and transloading facilities are set forth in the table below:

Our coal is transported to domestic customers and export terminal facilities by truck and rail. For the years ended December 31, 2014 and 2013, approximately 4.1 million tons and 3.8 million tons, respectively, of our production was shipped via truck to customers, and approximately 7.4 million tons and 6.3 million tons, respectively, of our production was shipped via rail (either to our domestic customers or to U.S. West Coast export terminals). Our sponsor recently entered into a three-year contract for the transportation of our coal via truck from the Sufco and Skyline mines to PacifiCorp, IPA and various loadout facilities. Under a coal haulage agreement entered into in 2004 with Savage, we are required to utilize Savage to transport all of our coal via truck from the Dugout Canyon mine.

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

gas-fired power plants. According to Wood Mackenzie, our coal is cost competitive relative to other sources when delivered to Utah, as illustrated in the chart below:

According to Wood Mackenzie, our coal is cost competitive to our key customers relative to other sources, as illustrated in the charts below:

We are the only coal producer with contracted U.S. West Coast export capacity, with aggregate throughput capacity of approximately 5.7 million tons through the Port of Stockton, California and the Levin-Richmond Terminal. There are currently only three U.S. West Coast terminals that export coal: the Port of Stockton, California and the Levin-Richmond Terminal, each of which is leased by our sponsor, as well as the Port of Long Beach, which is controlled by an affiliate of Oxbow Carbon, LLC, a company that no longer produces coal. Our sponsor's terminal contract with Metropolitan Stevedore Company with respect to the Port of Stockton expires on December 31, 2019, and our sponsor's terminal contract with Levin-Richmond Terminal Corp. expires on December 31, 2015. In addition, our coal has been exported through a brokerage arrangement through the Port of Long Beach, California. This capacity, coupled with our railway access, enables us to transport coal at highly competitive rates. 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.

Pursuant to a Coal Services Agreement, Trafigura AG is the exclusive provider of certain sales, marketing, administrative and other services to us and our sponsor for the production life of our reserves. We and our sponsor pay Trafigura AG a sales fee equal to a percentage of the price paid per ton (FOB mine) delivered under the Coal Services Agreement, provided that the sales fee may be increased for export sales of coal above certain price per ton thresholds. Trafigura AG has the right to terminate the Coal Services Agreement upon 180 days' notice. We and our sponsor have a right to terminate the Coal Services Agreement with respect to any mine only upon a sale of such mine to a third party. For the year ended December 31, 2014, our sponsor paid Trafigura AG approximately $3.6 million pursuant to the Coal Services Agreement.

Upon the closing of this offering, we expect to terminate our existing Coal Services Agreement among CFC, our sponsor and Trafigura AG and to enter into a new Coal Services Agreement among

our operating company and its subsidiaries, our sponsor and Trafigura AG, with substantially the same terms and conditions as the existing Coal Services Agreement.

We base our coal reserve estimates on engineering, economic and geological data assembled and analyzed by our staff. These estimates are also based on the expected cost of production and projected sale prices and assumptions concerning the permitability and advances in mining technology. The estimates of coal reserves and non-reserve coal deposits as to both quantity and quality are periodically updated to reflect the production of coal from the reserves, updated geologic models and mining recovery data, coal reserves recently acquired and estimated costs of production and sales prices. Acquisitions or sales of coal properties will also change these estimates. Changes in mining methods may increase or decrease the recovery basis for a coal seam, as will plant processing efficiency tests. We maintain reserve and non-reserve coal deposit information in secure computerized databases, as well as in hard copy. The ability to update and/or modify the estimates of our coal reserves and non-reserve coal deposits is restricted to a few individuals and the modifications are documented.

All of our reserves are considered high Btu coal, with Btu content ranging between 10,916 and 11,844 per pound and low sulfur, with sulfur content ranging between 0.43% and 0.80%. On a pro forma basis, after giving effect to the closing of the Utah Transaction and the BLM's issuance of the Flat Canyon lease to us, the following table presents our estimated coal reserves as of December 31, 2014:

(1): All of our proven and probable reserves are thermal (or steam) coal. We own 0.7 million tons of proven and probable reserves at each of the Sufco and Skyline mines. Our other reserves are held by lease. On a weighted-average basis, all our coal is compliance coal.
(2): All Btus per pound are expressed on an as-received basis, including total moisture.
(3): 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, which contains approximately 14.2 million tons and 15.2 million tons of proven and probable reserves, respectively. The issuance by the BLM of the lease of the Flat Canyon tract remains subject to a 30-day antitrust review of 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 "—Reserve Acquisition Process."
(4): We acquired the Fossil Rock reserves from an affiliate of PacifiCorp on June 5, 2015. Please read "—Overview."

On a pro forma basis, after giving effect to our anticipated lease of the Greens Hollow tract from the BLM, the following table presents our estimated non-reserve coal deposits as of December 31, 2014:

Non-reserve coal deposits are coal-bearing bodies that have been sufficiently sampled and analyzed in trenches, outcrops, drilling and underground workings to assume continuity between sample points, and therefore warrant further exploration stage work. However, this coal does not qualify as a commercially viable coal reserve as prescribed by standards of the SEC until a final comprehensive evaluation based on unit cost per ton, recoverability and other material factors concludes legal and economic feasibility. Non-reserve coal deposits may be classified as such by either limited property control or geological limitations, or both.

Periodically, we retain outside experts to independently verify our coal reserve and non-reserve coal deposit estimates. The most recent audit by an independent engineering firm of our coal reserve estimates was completed by Norwest, as of December 31, 2014 and covered all of the coal reserves that we controlled as of such date, together with the Fossil Rock reserves and the proven and probable reserves associated with the Flat Canyon tract. As of December 31, 2014, on a pro forma basis giving effect to the Utah Transaction and our anticipated lease of the Flat Canyon tract and the Greens Hollow tract from the BLM, we would have controlled over 88 million tons and 84 million tons of proven and probable coal reserves, respectively, with an average heat content range of 10,916 to 11,844 Btu per pound and an estimated 50.5 million tons of non-reserve coal deposits with an average heat content range of 10,900 to 11,200 Btu per pound. Statements of non-reserve coal deposits for the Greens Hollow tract rely solely on the estimates of management and have not been prepared or audited by Norwest.

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.

A substantial amount of our coal is produced from mineral reserves leased from various land owners. Our main lessor is the U.S. government, from which we lease coal under terms set by Congress and administered by the BLM through the process described below under "—Reserve Acquisition Process." These leases are generally for an initial term of ten years but may be extended by diligent development and mining of the reserves until all economically recoverable reserves are depleted. We have met the diligent development requirements for substantially all of our federal leases either directly through production, by including the lease as a part of a logical mining unit with other leases upon which development has occurred, or by paying an advance royalty in lieu of continued operations. Annual production on these federal leases must total at least 1% of the original amount of coal in the entire logical mining unit. In addition, royalties are generally payable monthly at a rate of 8% of the gross realization for coal produced using underground mining methods. Many BLM leases also require payment of a lease rental or minimum royalty, payable either at the time of execution of the lease or in periodic installments.

The remainder of our coal is generally leased from the State of Utah, land holding companies and various individuals. The duration of these leases varies. Typically, the lease terms are automatically extended as long as active mining continues. Royalty payments are generally based upon a specified rate per ton or a percentage of the gross realization from the sale of the coal.

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 August 2013, in connection with the execution of our sponsor's Senior Secured Credit Facilities, title polices and title opinions were obtained by our sponsor on certain of our owned and leased surface and mineral rights. We have not obtained any title policies or title opinions with respect to the Fossil Rock reserves but will be required to do so in connection with the offering of the New Notes.

We own 0.7 million tons of proven and probable reserves at each of the Sufco and Skyline mines. Our other reserves are held by lease. Set forth below is a description and summary of the leased mineral reserves for the life of mine sequence for each mine:

	Sufco Mine Leases

Lessor	Effective Date	Expiration Date	Royalty Rate	Total Lease Acres
BLM	9/11/1941	9/10/2021	8% and $0.35/ton after 6.93 million tons removed	3,079.83
BLM	1/1/1979	12/31/2019	11.68%	716.51
BLM	3/1/1962	2/28/2022	8%	480.00
BLM	10/1/1981	9/30/2021	8% and $0.35/ton after 6.93 million tons removed	1,953.73
BLM	7/1/1989	6/30/2019	8% and $0.35/ton after 6.93 million tons removed	8,826.34
BLM	6/1/1966	4/30/2016	8%	240.00
BLM	10/1/1999	9/30/2019	8%	5,694.66
State of Utah School and Institutional Trust Lands Administration(1)	10/1/2004	9/30/2024	8%	2,134.19
BLM(2)	TBD	TBD	8% estimated	TBD

	Skyline Mine Leases

Lessor	Effective Date	Expiration Date	Royalty Rate	Total Lease Acres
BLM	5/1/1966	5/1/2016	8%	1,532.70
BLM	3/1/1962	2/28/2022	8%	279.40
BLM	10/1/1964	10/1/2024	8%	520.00
BLM	9/1/1965	8/31/2015	8%	2,489.32
BLM	2/1/1964	1/31/2024	8%	557.22
BLM	9/1/1996	8/30/2016	8% and $0.40/ton in tract 2	4,061.52
Carbon County	5/1/2004	4/30/2024	8%	80.00
James O. Tracy, Jr. & Linda D. Tracy	5/22/1998	5/21/2018	2% or $0.30/ton whichever is greater	346.68
David G. & Rene L. Cunningham	5/22/1998	5/21/2018	2% or $0.30/ton whichever is greater	346.68
Collard Family Trust	5/30/1998	5/29/2018	4% or $0.60/ton whichever is greater for owned; $0.05/ton or $2,010/year whichever is greater for not owned	1,003.67
Carbon County	10/5/1977	7/31/2022	8%	1,200.00
BLM(1)	TBD	TBD	8%	2,692.16

	Dugout Canyon Mine Leases

Lessor	Effective Date	Expiration Date	Royalty Rate	Total Lease Acres
BLM	10/1/1995	9/30/2015	8%	2,117.52
BLM	1/1/1957	12/31/2016	8%	2,881.15
BLM	1/4/1935	1/3/2015	8%	1,548.31
BLM	9/1/1982	8/30/2022	8%	440.00
State of Utah School and Institutional Trust Lands Administration	10/11/1985	10/31/2015	8%	3,640.00
State of Utah School and Institutional Trust Lands Administration	10/11/1985	10/31/2015	8%	2,212.00
State of Utah School and Institutional Trust Lands Administration	4/3/1989	10/31/2015	8%	557.20
State of Utah School and Institutional Trust Lands Administration	9/1/2000	10/31/2015	8%	2,560.00
State of Utah School and Institutional Trust Lands Administration	2/1/2007	10/31/2015	8%	320.00

A substantial amount of our coal is produced from mineral reserves leased from various land owners. Most of our leases are with the U.S. government with lease terms set by Congress and administered by the BLM. Accordingly, the federal competitive leasing process is our principal means of acquiring additional reserves. We acquire a large portion of our coal through the LBA process. Under this process, before a mining company can obtain a new federal coal lease, the company must nominate a coal tract for lease and then win the lease through a competitive bidding process. The LBA process can last anywhere from two to five years or more from the time the coal tract is nominated to the time a final bid is accepted by the BLM. After the LBA is awarded, the company then conducts the necessary testing to determine what amount can be classified as reserves and begins the process to

permit the coal for mining, which generally takes another two to five years. Third-party legal challenges, such as legal challenges filed against the BLM and the Secretary of the Interior 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.

To initiate the LBA process, coal producers file an application with the BLM's state office indicating interest in a specific coal tract. The BLM reviews the initial application to determine whether the application conforms to existing land-use plans for that particular tract of land and whether the application would provide for maximum coal recovery. The application is further reviewed by a regional coal team at a public meeting. Based on a review of the available information and public comment, the regional coal team will make a recommendation to the BLM whether to continue, modify or reject the application.

The BLM also allows for small tracts of coal to be acquired through the lease by modification process. A lease by modification is a non-competitive leasing process and is used in circumstances where a lessee is seeking to modify an existing federal coal lease by adding less than 960 acres in a configuration that is deemed non-competitive to other coal producers.

If the BLM determines to continue the application, a BLM-directed study under NEPA consisting of either an environmental assessment ("EA") or an Environmental Impact Statement ("EIS") is conducted at the cost of the applicant. This analysis or impact statement is subject to publication and public comment. The BLM may consult with other government agencies during this process, including state and federal agencies, surface management agencies, Native American tribes or bands, the U.S. Department of Justice or others as needed. The public comment period for an analysis or impact statement typically occurs over a 60-day period.

After the EA or EIS has been issued and a recommendation has been published that supports the lease sale of the LBA tract, the BLM schedules a public competitive lease sale. The BLM prepares an internal estimate of the fair market value of the coal that is based on its economic analysis and comparable sales analysis. Prior to the lease sale, companies interested in acquiring the lease must send sealed bids to the BLM. The bid amounts for the lease are payable in five annual installments, with the first 20% installment due when the mining operator submits its initial bid for an LBA. Before the lease is approved by the BLM, the company must first furnish to the BLM an initial rental payment for the first year of rent along with either a bond for the next 20% annual installment payment for the bid amount, or an application for history of timely payment, in which case the BLM may waive the bond requirement if the company successfully meets all the qualifications of a timely payor. The bids are opened at the lease sale. If the BLM decides to grant a lease, the lease is awarded to the company that submitted the highest total bid meeting or exceeding the BLM's fair market value estimate, which is not published. The BLM, however, is not required to grant a lease even if it determines that a bid meeting or exceeding the fair market value of the coal has been submitted. The winning bidder must also submit a report setting forth the nature and extent of its coal holdings to the U.S. Department of Justice for a 30-day antitrust review of the lease. If the successful bidder was not the initial applicant, the BLM will refund the initial applicant certain fees it paid in connection with the application process, for example the fees associated with the EA or EIS, and the winning bidder will bear those costs. Coal leases awarded through the LBA process and subject to federal leases are administered by the U.S. Department of Interior under the Federal Coal Leasing Amendment Act of 1976. Once the BLM has issued a lease, the company must next complete the permitting process before it can mine the coal. Please read "Environmental and Other Regulatory Matters—Permits."

The federal coal leasing process is designed to be a public process, giving stakeholders and other interested parties opportunities to comment on the BLM's proposed and final actions and allow third-party comments. Because of this, third parties, including non-governmental organizations, can challenge the BLM's actions, which may delay the leasing process. If these challenges prove successful or are

litigated for a prolonged period of time, a coal company's ability to bid on or acquire a new coal lease could be significantly delayed, or could cause the BLM to not offer a lease for bid at all. 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 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. These types of challenges create some uncertainty with respect to the timing of future LBA bids and lease acquisitions and may ultimately delay the leasing process or prevent mining operations. Even after a lease has been issued and a successful bidder has paid installment money to the BLM, legal challenges may still seek to delay or prevent mining operations. It is possible that subsequent EISs for other mines in the Uinta Basin currently underway but not yet final could be similarly challenged. There also exists the possibility of similar challenges to the permitting and licensing process, which is also a public process designed to allow public comments.

Each of our federal coal leases have an initial term of 10 or more years, renewable for subsequent 10-year periods and for so long thereafter as coal is produced in commercial quantities. The leases require diligent development within the initial term of the lease award, requiring coal extraction in commercial quantities during the initial term, as specified in each lease. At the end of an initial development period, the lessee is required to maintain continuous operations, as defined in the applicable leasing regulations. In certain cases, a lessee may combine contiguous leases into a logical mining unit. This allows the production of coal from any of the leases within the logical mining unit to be used to meet the continuous operation requirements for the entire logical mining unit. We pay to the federal government an annual rent of $3.00 per acre and production royalties (generally) of 8% of gross revenue on underground mined coal. The federal government remits approximately 50% of the production royalty payments to the state after deducting administrative expenses. Some of our mines are also subject to coal leases with the State of Utah and have different terms and conditions that we must adhere to in a similar way to our federal leases. Under these federal and state leases, if the leased coal is not diligently developed during the initial development period or if certain other terms of the leases are not complied with, including the requirement to produce a minimum quantity of coal or pay a minimum production royalty, if applicable, the BLM or the applicable state regulatory agency can terminate the lease prior to the expiration of its term.

Some of the coal we lease from the U.S. federal government comes from "split estate" lands in which one party, such as the federal government, owns the coal and a private party owns the surface. In order to mine the coal we acquire, we must acquire rights to mine from certain owners of the surface lands overlying the coal. Certain federal regulations provide QSOs with the ability to prohibit the BLM from leasing its coal. If the land overlying a coal tract is owned by a QSO, 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, which would allow us to conduct our mining operations. Furthermore, the state permitting process requires us to demonstrate surface owner consent for split estate lands before the state will issue a permit to mine coal. This consent is separate from the QSO consent required before leasing federal coal. The right of QSOs and certain other surface owners allows them to exercise significant influence over negotiations and prices to acquire surface rights and can delay the federal coal lease or permitting processes or ultimately prevent the acquisition of the federal coal lease or permit over that land entirely. QSOs may own land adjacent to or near our existing mines that may be attractive acquisition candidates for us.

Most of the coal we have acquired from private third parties is in the form of coal leases obtained through private negotiations with one or more third parties. These leases generally include, among

other terms and conditions, a set term of years with the right to renew the lease for a stated period and royalties to be paid to the lessor as a percentage of the sales price. These leases may require payment of a lease bonus or minimum royalty, payable either at the time of execution of the lease or in periodic installments, and a minimum production of coal from the leased areas in order to hold the leases by active production. We believe that the term of years will allow the recoverable reserve to be fully extracted in accordance with our projected mine plan. Consistent with industry practice, we conduct only limited investigations of title to our coal properties prior to leasing. Title to properties leased from private third parties is not usually verified unless we are required by our lenders to obtain title policies or title opinions.

We sell coal directly through coal supply agreements with our customers and indirectly to customers through our sponsor. 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.

A large portion of our coal is sold to PacifiCorp and IPA, two large regional utilities located in close proximity to our mines. For the years ended December 31, 2014 and 2013, we derived approximately 52% and 55%, respectively, of our total coal revenues from sales of coal to PacifiCorp and IPA. For the year ending December 31, 2015, we expect to derive approximately 71% of our total coal revenues from sales of coal to PacifiCorp and IPA. If these two customers were to significantly reduce their purchases of coal from us, or if we were unable to sell coal to these customers on terms as favorable to us as the terms under our current coal supply agreements, our results of operations may be materially adversely affected.

In addition to our sales to PacifiCorp and IPA, we expect to sell approximately 2.0 million tons each year to our domestic industrial customers. While our coal supply agreements with these industrial customers are typically short-term in nature (12 to 18 months in duration), most of these customers have been purchasing our coal for over 25 years and, as such, we expect these customers to continue to renew their coal supply agreements with us in the future.

The coal supply agreements with our end customers often result from competitive bidding and extensive negotiations. Consequently, the terms of these agreements may vary significantly by customer, including with respect to price adjustment features, coal quality requirements, quantity adjustment mechanisms, permitted sources of supply, future regulatory changes, extension options, force majeure provisions and termination and assignment provisions.

Most of our coal supply agreements contain provisions requiring delivery of coal within certain ranges for specific 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. Although the volume to be delivered under a long-term agreement is stipulated, the parties may vary the timing of delivery within specified limits. Our coal supply 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. Some agreements may terminate upon continuance of an event of force majeure for an extended period.

The international thermal coal market has also been a substantial part of our business with sales to end users in Mexico, Japan, China, Guatemala, Chile and Hawaii. For the years ended December 31, 2014 and 2013, we exported approximately 21% and 9%, respectively, of our coal production into these international markets. Trafigura AG is the exclusive marketer of our uncommitted coal. Almost all of our export sales are made under contracts with a duration of less than one year.

On a pro forma basis, after giving effect to the closing of the Utah Transaction, the following table describes our contracted position (in millions of tons) for certain key customers for 2015, 2016, 2017 and 2018 as of December 31, 2014. In addition to the contracts described below, we also sell coal domestically to other industrial companies and internationally, through Trafigura AG, to a variety of intermediary and end-users in the power generation business.

(1): References in this prospectus to "our coal supply agreements" includes (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. These coal supply agreements include the PacifiCorp: Hunter, PacifiCorp: Huntington, IPA Contract No. 1 and IPA Contract No. 2 coal supply agreements. Our sponsor is the direct counterparty to these agreements.
(2): Except for IPA Contract No. 1, our coal supply agreements with key customers provide for sales of a minimum amount of coal per year and a maximum amount of coal per year.
(3): Reflects our anticipated coal sales based on our historical relationship with the customer and management's knowledge of the customer's coal requirements and the customer's other coal supply arrangements.
(4): Pursuant to the terms of the Huntington coal supply agreement, PacifiCorp has the right through 2020 to purchase coal under certain legacy contracts with other coal producers. PacifiCorp currently has the right to purchase up to 0.6 million tons in 2016 and 0.3 million tons of coal in 2017 under such legacy contracts. In the event that PacifiCorp purchases coal under such legacy contracts, the annual minimum quantity may fall below 2.0 million tons of coal to the extent of such purchases.
(5): For 2015, we expect 0.44 million tons of sales for IPA Contract No. 2 to be sourced from the Bowie #2 mine, which is owned by our sponsor. Our sponsor will retain the Bowie #2 mine and any related assets after the IPO Reorganization.

We have two long-term coal supply agreements with PacifiCorp, one for PacifiCorp's Hunter Power Plant and one for PacifiCorp's Huntington Power Plant, each of which includes fixed pricing, subject to price escalators and adjustments as described below. The PacifiCorp agreements provide for aggregate sales of a minimum of 4.5 million tons per year and a maximum of 7.5 million tons per year. The PacifiCorp coal supply agreements include provisions that require the customer to compensate us (either in the form of a shortfall fee or by purchasing any shortfall tonnage during the following contract year) in the event the customer does not take delivery of the minimum annual volume of coal specified in the applicable coal supply agreement. The PacifiCorp coal supply agreements 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. A minimum of 2.5 million tons, and a maximum of 4.5 million tons, of the coal to be delivered to PacifiCorp is subject to a price reset effective January 1, 2016 based on a weighted average formula that takes into account a base price, the price of coal sold by us in 2015 (adjusted for delivery FOB the railcar) and certain index pricing. Based on this formula, and upon a previously determined "ceiling" price for the 2016 calendar year, we expect this price reset for the 2016 calendar year to result in a price slightly below that for the 2015 calendar year.

The Hunter Power Plant coal supply agreement requires PacifiCorp to purchase a minimum of 2.5 million tons and a maximum of 4.5 million tons of our coal per year through December 31, 2020. The Huntington Power Plant coal supply agreement, which was executed on December 12, 2014 as part of the Utah Transaction and became effective upon the closing of the same, requires PacifiCorp to purchase all of its coal requirements for the Huntington Power Plant from us through December 31, 2029, with a minimum of 2.0 million tons of coal per year and maximum of 3.0 million tons of coal per year, subject to certain exceptions to the minimum tonnage requirements through 2020. From December 12, 2014 until the closing of the Utah Transaction, we sold coal to PacifiCorp for the Huntington Power Plant under an interim coal supply agreement (the terms of which, other than its duration, were substantially the same as those in the coal supply agreement that became effective upon the closing of the Utah Transaction).

The PacifiCorp coal supply agreements permit the customer (or, in the case of the Huntington Power Plant, the customer and us) to terminate the agreement in the event changes in regulations affecting the coal industry increase the price of coal beyond a specified amount, subject to the non-terminating party's right to elect to continue the agreement by bearing such additional costs above the specified amount. In addition, PacifiCorp may terminate if certain regulations or other governmental actions affect, in the case of the Huntington Power Plant, PacifiCorp's ability to use the minimum tonnage, or increase, in the case of the Hunter Power Plant, PacifiCorp's cost of handling and consuming coal above a specified threshold, subject to our right to continue each agreement for a specified period and to supply coal under such agreement with certain price adjustments. The PacifiCorp coal supply agreements contain force majeure provisions allowing for the suspension of performance by either party for the duration of specified events to the extent made necessary by any such force majeure event.

We have two long-term coal supply agreements with IPA, each for IPA's Delta Power Plant and each of which includes fixed pricing, subject to price escalators and adjustments as described below. The IPA coal supply agreements provide for aggregate sales of a minimum of 2.5 million tons per year and a maximum of 3.2 million tons in 2015 and a maximum of 3.0 million tons per year thereafter. Under each IPA coal supply agreement, in the event the customer does not take delivery of the annual volume or minimum annual volume of coal, as applicable, we may reschedule delivery of all or part of such shortfall tonnage or sell such shortfall tonnage to an alternate buyer, in which case the customer will compensate us for a specified percentage of administrative fees and for any deficiency in the per

ton price received. One agreement requires IPA to purchase 2.0 million tons of coal (Sufco mine quality) per year through December 31, 2024, with an option for the 2015 calendar year only for IPA to purchase an additional 0.2 million tons. The other agreement requires IPA to purchase a minimum of 500,000 tons and a maximum of 1.0 million tons of coal (Skyline mine quality) per year through December 31, 2024.

The coal supply agreements with 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. The IPA coal supply agreements permit either the customer or us to terminate the agreement in the event changes in regulations affecting the coal industry increase the price of coal beyond a specified amount, subject to the non-terminating party's right to elect to continue the agreement by bearing such additional costs above the specified amount. In addition, the IPA coal supply agreements contain force majeure provisions allowing for the suspension of performance by either party for the duration of specified events to the extent made necessary by any such force majeure event. If a force majeure event prevents us from delivering or IPA from accepting more than 30% of each month's coal during any fiscal year, and if such force majeure event continues and cannot be eliminated for a six month period, then the party not claiming force majeure may terminate the applicable coal supply agreement.

The U.S. coal industry is highly competitive, both regionally and nationally. In the Western Bituminous region, we compete primarily with coal producers such as Peabody Energy Corporation, Arch Coal, Inc., UtahAmerican Energy, Inc., a subsidiary of Murray Energy Corporation, and Rhino Resource Partners LP. Outside of our region, we compete broadly with other U.S.-based producers of thermal coal and internationally with numerous global coal producers.

A number of factors beyond our control affect the markets in which we sell our coal. Continued demand for our coal and the prices obtained by us depend primarily on: the coal consumption patterns of the electricity industry in the United States and elsewhere around the world; the availability, location, cost of transportation and price of competing coal; and other electricity generation and fuel supply sources such as natural gas, oil, nuclear, hydroelectric and renewable energy. Coal consumption patterns are affected primarily by the demand for electricity, environmental and other governmental regulations and technological developments. The most important factors on which we compete are price, coal quality characteristics and reliability of supply.

As part of our omnibus agreement, our sponsor has agreed to grant us a royalty-free license to use the name "Bowie" and related marks. Additionally, our sponsor has agreed to grant us a non-exclusive right to use all of our sponsor's current and future technology to operate our business.

As of December 31, 2014, we employed 810 non-union workers. Of this total, 214 were salaried employees, including management and administrative personnel. Hourly employees include mine technicians, equipment operators, equipment maintenance engineers and loadout/plant operations maintenance workers. We emphasize safety across all operations.

We are highly focused on the safety of our coal operations and work diligently to meet or exceed all safety and environmental regulations required by state and federal laws. Safety performance at our mines continues to be significantly better than the national average. Our non-fatal days lost incidence rate was 16% of the industry average for the year ended December 31, 2014. Non-fatal days lost incidence rate is an industry standard used to describe occupational injuries that result in loss of one or more days from an employee's scheduled work. Our non-fatal days lost time incidence rate for all

operations for the year ended December 31, 2014 was 0.51 as compared to the national average of 3.16 for the same period, as reported by MSHA. This data is consistent with that of prior years and reflects a trend of excellence that we intend to maintain through our safety programs and policies. We also intend to continue to implement responsible, effective environmental practices throughout our operations and reclamation activities.

From time to time, we are involved in lawsuits, claims or other proceedings with respect to matters such as personal injury, permitting, wrongful death, damage to property, environmental remediation, employment and contract disputes and other claims and actions arising in the ordinary course of business. We cannot estimate with certainty our ultimate legal and financial liability with respect to such pending litigation matters. However, we believe, based on our examination of such matters, that our ultimate liability will not have a material adverse effect on our financial position, results of operations or cash flows.

Except as otherwise indicated, the statistical information and industry and market data contained in this section is based on or derived from statistical information and industry and market data collated and prepared by Wood Mackenzie. The data is based on Wood Mackenzie's review of such statistical information and market data available at the time (including internal surveys and sources, independent financial information, independent external industry publications, reports or other publicly available information). Due to the incomplete nature of the statistical information and market data available, Wood Mackenzie has had to make some estimates where necessary when preparing the data. The data is subject to change and may differ from similar assessments obtained from other analysts of coal and energy markets. While Wood Mackenzie has taken reasonable care in the preparation of the data and believes it to be accurate and correct, data collection is subject to limited audit and validation procedures.

Coal is an abundant and inexpensive natural resource and major contributor to the world's energy supply. Coal is primarily used as a fuel for electric power generation. According to the BP Statistical Review, global proven coal reserves totaled approximately 892 billion metric tons by the end of 2014 and represented approximately 30% of the world's primary energy consumption in 2014. According to Wood Mackenzie, the industrialization and development of China, India and the wider Asia Pacific region will ensure the long-term future of coal in the global energy mix.

The chart below demonstrates the importance of coal as global energy source over time according to the BP Statistical Review:

Coal is generally categorized as either thermal coal or metallurgical coal and often ranked by heat content, with anthracite, bituminous, sub-bituminous and lignite coal representing the highest to lowest heat ranking, respectively. Thermal coal's main use is electricity generation by utilities and independent

power producers. Metallurgical coal is used by steel producers to create metallurgical coke for use in the steel making process.

The United States has the largest proven reserve base of coal in the world with approximately 237 billion metric tons, or approximately 27% of global coal proven reserves. According to the EIA, U.S. coal reserves would sustain 294 years of domestic supply based on 2012 consumption rates. Coal represents the largest domestic fossil fuel source, accounting for approximately 92% of domestic fossil energy reserves on a Btu basis, according to the National Mining Association. According to Wood Mackenzie, total U.S. electricity generation is expected to grow by 20.3% from 2014 to 2025. 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.

Our industry segment. We produce high heat value, low sulfur thermal coal from our three underground mines in the Uinta Basin (Utah), part of the Western Bituminous region. In 2014, coal production in Utah increased by 7% over 2013 levels, according to MSHA data. Through 2020, Wood Mackenzie projects that total demand for Utah thermal coal will increase at a compound annual growth rate of 3.4% from 2013 levels compared to a projected compound annual decline of 1.9% for overall U.S. thermal coal demand. Our domestic customers are western utilities and industrial companies to which we sell coal mostly under long-term coal supply agreements. We also sell our coal internationally to a variety of intermediary and end-users in the power generation business. Our coal competes with all producers of thermal coal that supply coal to domestic or international consumers.

Global coal market. Coal will remain a fundamental component of the global energy system. Wood Mackenzie predicts coal will overtake oil as the world's most consumed fuel in 2018, primarily a consequence of power demand growth in developing markets such as China and India. This trend is expected to continue, with aggregate demand substantially exceeding that of oil by 2030. Non-hydro renewables are expected to grow rapidly during this period, averaging 6.1% annually, faster than any other energy source. However, this growth in renewables is from a low base, and by 2030, renewables are estimated to contribute only 2% of global energy supply.

In 2014, global thermal coal demand was dominated by China. According to Wood Mackenzie, China's demand for thermal coal will account 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. Coal's use as a power generation fuel will persist in the developed world, with coal accounting for an average of 20% of European and 30% of North American electricity generation from 2014 through 2030.

Demand growth for seaborne thermal coal. According to Wood Mackenzie, coal consumption in the seaborne thermal coal market grew at a compound annual growth rate of 7.7% from the period 2008–2014, increasing from approximately 614 million metric tons to approximately 959 million metric tons. Wood Mackenzie projects consumption of seaborne thermal coal to increase further to approximately 1.6 billion metric tons by 2035, a compound annual growth rate of 2.6% from 2014. Thermal coal demand has been growing in emerging economies, particularly in the Pacific Rim. According to Wood Mackenzie, countries outside of the developed economies of Europe, Japan and the United States imported 68% of the world's seaborne export thermal coal in 2014 and their share of the total seaborne thermal coal market is projected to increase to 80% by 2025.

Increased seaborne thermal coal import demand by China and India. China, which has traditionally been a net exporter of thermal coal, underwent a 175.8 million metric ton increase in imports from 2008 to 2014, a compound annual growth rate of 33%. Imports are expected to grow an additional 108% to 419.1 million metric tons by 2035, according to Wood Mackenzie. The chart below shows

seaborne thermal coal import demand and seaborne thermal coal export supply for China from 2008 through 2035:

The largest driver of the demand growth for seaborne coal in China over the next few decades will be the power sector. As shown in the chart below, from 2008–2035, coal demand from the power generation sector is expected to increase at a compound annual growth rate of 3.0%, doubling over that time period. Over the same period, coal demand from the cement sector will decline at a compound annual growth rate of –0.6%, and demand growth for all other sectors in China will grow at 1.0% per annum.

By 2035, seaborne thermal imports are expected to account for 8.6% of Chinese coal supply, compared with 6.0% in 2014. Per Wood Mackenzie, in 2014, the United States supplied 0.2 million metric tons of seaborne thermal coal to China, comprising less than 1% of its total thermal imports. According to Wood Mackenzie, by 2035, the United States will supply 39.3 million metric tons of seaborne thermal coal to China, comprising 9.4% of its total thermal imports.

Coal demand has also increased significantly in India, with seaborne imports rising from 28 million metric tons in 2008 to 157.5 million metric tons in 2014, a 33% compound annual growth rate. India's demand for imported thermal coal is expected to increase in both the near- and long-term, as the country has made clear its intent to increase coal-fired power generation as a share of its overall generation portfolio. Wood Mackenzie estimates that India had 182 gigawatts of coal-fired generation capacity in 2014 and expects this to increase by 176% to 449.8 gigawatts by 2035. Per Wood Mackenzie, between the period from 2014–2035, India's thermal coal imports are projected to increase by 213% to 404 million metric tons, and India's share of the seaborne thermal coal market is estimated to increase from 16% to 25% over the same period.

Countries that are large net exporters of thermal coal experience sporadic supply constraints. Occasionally, countries that export significant amounts of thermal coal have experienced supply constraints impacting the global seaborne thermal market balance. A variety of these countries have had their thermal coal exporting ability affected by various circumstances, including labor shortages, limited port capacity, limited rail transportation capacity, reliability and distance constraints, power generation shortages that limited coal processing capabilities, increased domestic consumption, unexpected weather patterns, increasingly stringent regulatory and environmental measures, political instability and diminishing coal qualities. Additionally, an intensifying operating cost environment and increased capital constraints, in conjunction with recent depressed thermal coal export prices, have forced shutdowns of some existing production and delays in new project development. We believe that

many countries with significant thermal coal import needs in the Pacific Rim will continue to diversify the sources from which they procure thermal coal.

Seaborne thermal coal markets will experience a period of over-supply in the near-term. Despite recent growth trends in seaborne coal markets and robust long-term fundamentals as forecast by Wood Mackenzie, a fluctuating global economy has led to lower near-term demand and lower global spot prices for seaborne thermal coal. 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, $61.94 per metric ton at January 2, 2015 and to $59.60 per metric ton at March 27, 2015. We believe that the current sustained low price environment will continue to cause high cost coal suppliers across the globe to shut down mine operations, which will result in lower global supply, and consequently, improved global pricing.

Coal remains a widely available and cost-competitive resource. Coal-fired power plants comprise a significant portion of the nation's power generation infrastructure. The EIA states that coal had a 47% average market share of electrical power generation in the United States over 2000–2013, predominantly due to its low cost and abundance. Depressed levels of electrical demand and low natural gas prices, in conjunction with other factors such as fuel freight costs and emission control costs, displaced some coal-fired generation in 2012. However, this trend began to reverse in 2013 as a result of rising natural gas prices and decline in the supply of coal. In its April Short Term Energy Outlook for 2015, the EIA projected the average cost of coal delivered to electric generating plants to be $2.34 on a dollars per million Btu basis versus $4.54 per million Btu for natural gas, implying an estimated price of natural gas that is 94% higher than coal for 2015. The below table details the average fuel prices per million Btu to electricity generators for a mix of fossil fuels:

Average Cost of Electricity Generation by Fossil Fuel
(Real 2013 Dollars per million Btu)

Recent trends in U.S. coal demand and production. Over the last ten years, the U.S. coal industry supplied an average of 966 million tons per year of coal production. The challenging economic conditions and relatively mild winter climate during 2012 in the United States decreased demand for electricity, and in turn, demand for thermal coal. In addition, U.S. natural gas prices reached record lows, creating an oversupply of U.S. thermal coal and high inventory stockpiles at utilities. These factors contributed to falling coal prices and led to a domestic supply and demand imbalance. Certain U.S. coal producers were forced to reduce workforces, idle or close high cost operations and defer capital expenditures across all U.S. coal basins. As a result, total U.S. coal production decreased by approximately 2.0% from 1,016 million tons in 2012 to 996 million tons in 2013, according to the EIA.

During 2013 and 2014, natural gas prices increased in the United States and provided the domestic coal market an opportunity to balance. Per the Henry Hub Index, natural gas spot prices increased

136% from their 10-year monthly low of $2.00 per million Btu at the end of March 2012 to $3.14 per million Btu at the end of December 2014. However, natural gas prices fell again at the beginning of the 2015 due to oversupply and the decline in oil prices. The U.S. coal market is expected to face similar challenges this year to those faced in 2012. Wood Mackenzie projects that thermal coal production in the United States will decline by 88 million tons over last year, with 2015 U.S. thermal production totalling 832.1 million tons. Despite these conditions, the Utah coal market is expected to be somewhat insulated from the natural gas competition faced by the eastern markets. According to Wood Mackenzie, Utah coal demand is anticipated to increase by 2.6% this year over 2014 to 18.4 million tons.

Increasing demand for Utah coal. Wood Mackenzie projects total production of Utah coal to grow from 17.9 million tons in 2014 to 20.7 million tons in 2020, representing a compound annual growth rate of 2.4%. Demand for coal produced in Utah is expected to grow at a faster rate than overall U.S. coal demand. Utah coal generally has low sulfur content and demand for low sulfur coal has increased in the United States as utilities have had to comply with new environmental regulations such as the Clean Air Act. As many electric utilities have opted to forego retrofitting with scrubbers in the 25 years since the Clean Air Act passed, coal of the low-sulfur variety produced in the Western Bituminous region continues to have access to a market that cannot be supplied by high-sulfur coal from other regions. In addition, coal with low-sulfur content such as that produced in the Western Bituminous region is burned by utilities in both the Atlantic and Pacific seaborne markets.

Impact of natural gas demand on thermal coal demand. Traditionally, coal has been the primary source of fuel for electricity generation in the United States, accounting for approximately one-half of the market, while natural gas supplied approximately 15% to 30% of the fuel used to generate electricity. Over the period from 2000 to 2007, the price of natural gas per the Henry Hub Index averaged $5.70 per million Btu; however, natural gas prices began to decrease substantially beginning in 2008 and reached a 10-year low at the end of March 2012 of $2.00 per million Btu.

As a result, from 2011 to 2012, the natural gas electricity generation market share increased from 24.7% to 30.3%, while coal-supplied generation fell from 42.3% to 37.4%, according to the EIA. In 2013, natural gas prices increased from 2012 levels to an average of $3.72 per million Btu and reached a high of $5.01 per million Btu at the end of January 2014. As a result of the increasing natural gas price environment, coal-fired generation regained some of its market share, attaining 39.1% in 2013.

Given the low price environment for natural gas, it is expected that production of natural gas may decline at some point in the future. Baker Hughes has reported that the number of active natural gas drilling rigs dropped by 46%, from 811 rigs at the beginning of 2012 to 439 rigs at the beginning of 2013, and then fell an additional 25%, to 328 rigs as of October 24, 2014. We expect the lower rig count will lead to stabilized natural gas production.

Developments in U.S. regional coal markets. Historically, Central Appalachia has been the second largest coal basin by production (behind the Powder River Basin). Recently, production in Central Appalachia has declined and is expected to remain on this trajectory given its high production cost profile, its depleting reserves and recent regulations which have increased the difficulty in obtaining the necessary mining permits, particularly with regards to mountain-top mining, a method common across Central Appalachia. Given the difficult environment, thermal coal production in Central Appalachia has declined 69% from 219 million tons in 2002 to 67 million tons in 2014, per Wood Mackenzie. Thermal coal production in Central Appalachia is expected to continue to decline, with a 63% decrease expected from 2014–2035 and only 25.0 million tons of production expected in 2035. Diminished production from this region should be offset in part by increased production from other U.S. coal basins.

Powder River Basin experiencing higher coal transportation costs. Following the enactment of the Clean Air Act Amendments of 1990, many unscrubbed utilities began to comply with reduced sulfur dioxide emissions regulations by purchasing emission credits or switching to lower sulfur fuels. A result of these actions was increasing demand for low sulfur coal, such as that produced in the Western Bituminous region and the Powder River Basin. After a slight decline in production in 2012 and 2013 due to low natural gas prices, Western Bituminous coal production grew in 2014 to an estimated 85.8 million tons, a 2.4% increase from 2013 levels.

Another cost component that impacts Powder River Basin competitiveness is transportation. Most utilities consuming Powder River Basin coal negotiate long-term rail contracts with one of the two western railroads (Union Pacific and Burlington Northern Santa Fe) to control their transportation costs. Over the period from 1994–2004, reported average revenue per carload for these carriers increased 10.1%. Since the original transportation contracts began to expire in 2004, the reported average revenue per carload for these carriers has increased by 86.3% through December 31, 2013. The increased average cost of transportation for Powder River Basin coal is expected to result in higher delivered coal costs in the future.

The charts below compare the delivered cost of coal (including transportation cost) from our mines when delivered to Utah and to our key customers against the delivered cost of coal from the Powder River Basin and other regions.

Expected increases in international demand for U.S. coal exports over the long-term. Recently, U.S. coal exports have increased, 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. Per Wood Mackenzie, U.S. coal exports rose from 59 million tons in 2009 to 102 million tons in 2014, a compound annual growth rate of 11.6%. 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 believe that potential supply shortfalls in the Pacific Rim will reverse this trend and lead to higher demand and improved pricing for U.S. thermal seaborne coal in the long term. We expect the Western Bituminous region to entrench itself as a key supplier of coal to the seaborne thermal market.

Coal demand will continue to be affected by increasingly restrictive environmental legislation. A series of more rigorous environmental requirements related to air emissions have limited the amount of carbon dioxide, nitrogen oxides, mercury, ozone and other emissions that can be produced by utilities across the United States. These regulations have been enacted by both federal and state regulatory agencies over the last few years. Additionally, environmental regulators are currently considering implementing further proposed limitations to GHG emissions. While past air quality legislation reducing sulfur emissions has resulted in an increase in demand for low sulfur coals such as those produced in the Western Bituminous region, we believe that additional air quality regulations will be adopted over time, which have the ability to adversely impact future demand for coal in the United States.

Per the World Coal Association, world anthracite and bituminous coal consumption was estimated at 6.6 billion metric tons in 2013, approximately 1.1 billion metric tons of which were sold internationally, primarily in the seaborne coal market. The seaborne market consists of all coal shipped

between countries via ocean-going vessels apart from shipments between Canada and the United States via the Great Lakes.

Trends in thermal coal consumption are impacted by electricity demand, global power generation infrastructure, cost of transportation, governmental and environmental regulations, developments in technology, and the ease of procurement and cost advantage of other fuels including nuclear power, natural gas, and hydroelectric power. Seaborne metallurgical coal demand is influenced predominantly by global steel demand.

U.S. coal market. Thermal coal's predominant use is electricity generation, but it also supports industrial uses, and in the aggregate, thermal coal accounts for 98% of coal consumed in the United States. Metallurgical coal is predominantly consumed in the production of metallurgical coke used in steelmaking blast furnaces. Power generation from coal-fired power plants accounted for 38.7% of all power generated in the United States in 2014 compared to 27.4% from natural gas and 19.4% from nuclear power.

According to the EIA, between 1975 and 2010, thermal coal consumption in the United States more than doubled, reaching over 1.0 billion tons in 2010. As a result of the recent global economic downturn, the decreasing cost of natural gas and increasingly stringent regulatory and environmental constraints, domestic thermal coal consumption for electricity generation decreased to approximately 824 million tons in 2012, per the EIA. However, due primarily to recent increased gas prices, thermal coal consumption for electricity generation rose by 28 million tons in 2014 to 851 million tons, a 3% increase over 2012 levels.

The following table sets forth the consumption of coal in the United States by consuming sector as actual or forecasted, as applicable, by the EIA for the periods indicated:

In the United States, the reliance on coal-fired generation is attributable to the abundance and low cost of coal. In 2012 and 2013, coal was the least expensive and most readily available fuel source in the United States. Coal was approximately 47% and 55% cheaper in 2013 and 2014, respectively, on a dollar per million Btu basis than natural gas, the next least expensive and readily available fuel source.

U.S. regulatory environment. Utilities are increasingly purchasing coal on a sulfur content basis, as opposed to a heat content basis (measured in dollars per million Btu), as the transition to sulfur mitigation systems, or scrubbers, continues to be required by more stringent environmental regulations such as the Clean Air Act. The Western Bituminous region is characterized by low cost, low sulfur coal, and is competitive with other coal basins across the nation due to its low cost, access to widespread

transportation outlets and its low sulfur content. The Clean Air Act Amendments of 1990 implemented restrictions on sulfur emissions by electric utilities, which caused most of these entities to comply with the new regulations by using lower sulfur coal or by purchasing sulfur emission credits. As the emission regulations continue to evolve, these compliance strategies will result in utilities increasingly turning to low sulfur coal products in an effort to comply with the new air emission limitation requirements in the most economic manner.

We believe that the Clean Air Act Amendments of 1990 will continue to drive demand for the low sulfur coal produced in regions such as Utah. According to Wood Mackenzie, total Utah coal demand including exports is expected to grow by 16%, from 17.9 million tons in 2014 to upwards of 20.7 million tons in 2020, in part due to the low sulfur content of coal from this region and transportation cost advantages over regions such as the Powder River Basin.

The following map shows certain coal-fired power plants, Western Bituminous mines and transportation infrastructure:

Seaborne coal market. Wood Mackenzie estimates that total seaborne thermal coal demand in 2014 was approximately 959 million metric tons. The seaborne coal markets for thermal coal consist of the Atlantic market and the Pacific market. The Atlantic market largely consists of countries in Europe, the Mediterranean region, North America, South America and Central America. Within the Atlantic market, the countries with the largest consumption of seaborne thermal coal are the United Kingdom, Germany, Turkey, Italy and France, based on 2013 figures per Wood Mackenzie. The Pacific market largely consists of countries in Asia and Oceania. The Pacific market's largest consuming countries for imported seaborne thermal coal are China, Japan, India, South Korea, Taiwan and Malaysia. The table below highlights the historical and forecasted growth in the seaborne thermal coal market, per Wood Mackenzie:

According to Wood Mackenzie, Atlantic market and Pacific market thermal coal demand was 262.0 million and 756.5 million metric tons, respectively, for 2014. The vast majority of significant coal-consuming countries in Asia are expected to experience substantial demand growth with China and India accounting for the largest portion of the increase. Wood Mackenzie projects total demand for seaborne thermal coal to increase from 958.6 million metric tons in 2014 to 1.3 billion metric tons by 2025.

China is the world's largest producer of coal with approximately 47% of the world's coal production, according to the 2015 BP Statistical Review. In 2014, China was followed by the United States (13%), Indonesia (7%), Australia (7%), India (6%), Russia (4%) and South Africa (4%).

U.S. coal production. According to the 2015 BP Statistical Review, the United States is not only the second largest coal producer in the world, but is also the largest holder of coal reserves in the world, with approximately 294 years of supply at 2012 production rates according to the EIA. U.S.

thermal coal production was 920.5 million tons in 2014 according to Wood Mackenzie. While total annual domestic coal production has been relatively stable at approximately 1.0 billion tons since the mid-1990s, the production mix across basins has not remained constant over that period. Low-cost production from regions such as the Western Bituminous region, Powder River Basin and Illinois Basin has replaced high cost production from Central and Northern Appalachia. Wood Mackenzie forecasts that thermal coal production in the United States will decrease 12.9% from 2014 to 2025, and will primarily supply domestic coal-fired generating units together with increasing demand from the seaborne markets. The table below contains historical production information for a selection of U.S. coal producing regions for the periods, per Wood Mackenzie:

Region	1990

	(tons in millions)
Utah		22.0	25.5	27.1	24.5	19.3	16.4	17.9	(9.2	)
Western Bituminous (including Utah)		96.1	106.2	111.5	116.9	86.9	83.8	85.8	(25.7	)
Powder River Basin		197.1	285.2	361.3	430.2	472.8	416.2	418.2	56.9
Central Appalachia		202.2	197.0	215.3	199.0	136.4	70.0	67.4	(147.9	)
Northern Appalachia		158.9	132.9	136.1	135.2	115.0	110.6	117.9	(18.2	)
Illinois Basin		141.2	108.9	88.1	95.0	106.7	132.2	137.2	49.1
Other		120.0	114.3	104.0	105.1	91.1	86.3	94.0	(10.0	)

Total U.S. Coal Production		915.5	944.4	1,016.4	1,081.3	1,008.9	899.2	920.5	(95.9	)

Wood Mackenzie forecasts that the Utah area will experience the largest coal production growth rate among coal producing regions in the United States. We believe this is largely a result of increasingly stringent environmental and permitting regulations, declining geologic conditions, higher mining costs and greater transportation expenses impacting the Appalachian Basin. The following table sets forth forecasted production statistics for a selection of U.S. coal producing regions for the periods indicated based on Wood Mackenzie data:

Wood Mackenzie estimates that Utah coal production will grow at a compound annual rate of 2.4%, from 17.9 million tons in 2014 to 20.7 million tons in 2020. Thermal coal production from other U.S. regions is estimated to decrease at a compound annual growth rate of 2.7% over the same period.

Note: Due to rounding, recalculations of percentages based upon the numbers disclosed may not produce the same results.

Coal producing regions. Across the United States, more than one half of states produce coal, but domestic production is primarily attributable to three major coal producing regions: the Western, Interior and Appalachia regions. Within those three regions, the major producing centers are the Western Bituminous region and Powder River Basin in the Western region, the Illinois Basin in the Interior region and Northern Appalachia and Central Appalachia in Appalachia. Each region has unique coal types, characteristics and qualities for which it is known.

Western Bituminous Region. The Western Bituminous region is made up of parts of Utah, Colorado, New Mexico, Arizona and Wyoming and includes the Uinta Basin. The Western Bituminous region typically produces bituminous coal with sulfur content ranging from 0.8% to 1.8% and heat content ranging from 11,000 to 12,000 Btu per pound. We believe that recent abnormal weather patterns, combined with rail transportation constraints that can affect the Powder River Basin shipments, will create a sustained opportunity for Western Bituminous producers to provide low-cost, low sulfur coal across the United States.

Per Wood Mackenzie, coal production in the Western Bituminous region was 85.8 million tons in 2014. Wood Mackenzie forecasts that coal production in the Western Bituminous region will decrease by 3.8 million tons to 82.0 million tons in 2020, a decrease of 4.5%. However, Wood Mackenzie estimates that Utah coal production will grow by 15.6%, from 17.9 million tons in 2014 to 20.7 million tons in 2020.

Powder River Basin. The Powder River Basin is located in Wyoming and Montana. The Powder River Basin region typically produces sub-bituminous coal with sulfur content ranging from 0.2% to 0.8% and heat content ranging from 7,800 to 9,700 Btu per pound. After strong growth in production over the past 20 years, growth in domestic demand for Powder River Basin coal is expected to

moderate in the future due to transportation rate increases and growing operating costs as a result of higher strip ratios.

Per Wood Mackenzie, coal production in the Powder River Basin was 418.2 million tons for 2014. Wood Mackenzie forecasts that coal production in the Powder River Basin will decrease by 19.3 million to 398.9 million tons in 2020, an decrease of 4.6%.

Illinois Basin. The Illinois Basin spans western Kentucky, Illinois and Indiana. Reserves in this area are comprised of bituminous coal with typical heat content ranging from 9,700 to 12,800 Btu per pound and sulfur content ranging from 1.0% to 6.0%. Coal produced in the Illinois Basin is predominantly used for the generation of electricity, with minimal amounts used in industrial applications.

The Illinois Basin is divided into several regions which include northern Illinois, central Illinois, southern Illinois, West Kentucky and Indiana, each of which is known for distinct coal quality characteristics, transportation methods and mining logistics. Given its high sulfur content, coal from the Illinois Basin is typically suitable for electric power generation facilities that have installed pollution control devices, such as scrubbers, to reduce emissions.

According to Wood Mackenzie, coal production in the Illinois Basin was 137.2 million tons in 2014. Wood Mackenzie forecasts that coal production in the Illinois Basin will increase by 0.8 million to 138 million tons in 2020, a 0.6% increase.

Northern Appalachia. Northern Appalachia includes Ohio, Pennsylvania, Maryland and northern West Virginia. The region contains reserves of bituminous coal with heat content generally ranging from 11,100 to 13,900 Btu per pound and sulfur content typically ranging from 1.0% to 5.0%. Thermal coal produced in Northern Appalachia is predominantly marketed to electric utilities, industrial customers and the export market, while metallurgical coal production from the region is marketed to domestic and international steelmakers. Exports from Northern Appalachia predominantly serve customers in the Atlantic Basin.

According to Wood Mackenzie, total Northern Appalachia thermal coal production was 117.9 million tons in 2014. Wood Mackenzie forecasts that thermal production in Northern Appalachia will fall by 27.2 million to 90.7 million tons in 2020, a 23.1% decrease.

Central Appalachia. Central Appalachia includes eastern Kentucky, southern West Virginia, Virginia and northern Tennessee. The region contains reserves of bituminous coal with a heat content typically ranging from 11,500 to 14,200 Btu per pound and sulfur content typically ranging from 0.5% to 4.0%. Central Appalachian thermal coal is marketed primarily to electric utilities, industrial customers and the export market, while metallurgical coal production is marketed to domestic and international steelmakers. Reserve depletion, increasingly stringent regulatory standards and challenging geology in the region is expected to lead to significant decreases in production over the long-term.

According to Wood Mackenzie, total Central Appalachia thermal coal production was 67.4 million tons in 2014. Wood Mackenzie forecasts that thermal coal production in Central Appalachia will decline by 43.8 million to 23.6 million tons in 2020, a 65% decline.

U.S. coal exports. Historically, comparatively high transportation costs associated with moving coal from mine to Atlantic ports, coupled with a lack of available ports on the U.S. West Coast, has impeded the amount of coal that the United States could supply to the seaborne market, limiting its global competitiveness. Coal export volumes have fluctuated over the last decade, with a low of 48 million tons in 2004 and a high of 126 million tons in 2012. Of the 118 million tons of coal exported in 2013, 52 million tons were thermal coal with the balance being metallurgical coal. As demonstrated in the table below, over the period from 2004–2013, exported thermal and metallurgical coal from the United States increased 145%.

Seaborne coal supply. Seaborne thermal coal is supplied to both the Atlantic market and the Pacific market. Colombia, Russia, South Africa, the United States and Indonesia continue to be the principal suppliers to the Atlantic seaborne thermal coal market. Wood Mackenzie estimates that in 2014, the Atlantic market accounted for 262.0 million metric tons of thermal coal imports, just under 26% of the global thermal seaborne market. Indonesia, Australia, Columbia, South Africa and Russia are the principal suppliers of the Pacific seaborne thermal coal market. Wood Mackenzie estimates that in 2014, the Pacific market accounted for 756.5 million metric tons of thermal coal, just over 74% of the global thermal seaborne market.

One of the key trends in seaborne thermal coal is the growing demand in the Pacific Rim, with countries in the region unable to produce enough coal domestically to satisfy their power generation requirements. In countries that have historically been key suppliers to Asia, coal producers have recently been experiencing many challenges, among them infrastructure constraints, rising tax burdens, increasing government regulations, port capacity limitations, increasing domestic demand and restrictions on export quantities. While the Pacific market is currently experiencing a surplus of thermal coal, we believe that over the long-term, there will be an opportunity for low-cost U.S. producers to supply coal to the Pacific markets. The table below, per Wood Mackenzie data, highlights the projected supply of thermal coal exports:

	Supply to Seaborne Market

	Supply to Seaborne Market												2012–2030 Compound Annual Growth Rate Forecast
Country of Origin	2012 Actual		2013 Actual		2014 Actual		2015 Forecast		2025 Forecast		2030 Forecast		2012–2030 Compound Annual Growth Rate Forecast
Australia		173		186		205		210		294		423		5.1	%
Colombia		81		80		77		82		132		132		2.8	%
Russia		102		100		102		109		104		92		(0.5	)%
South Africa		71		70		75		82		90		100		1.9	%
Indonesia		358		396		380		400		517		523		2.1	%
United States		53		52		39		33		94		134		5.3	%
of which supply to Pacific market		16		18		11		15		48		50		6.5	%
of which Western Bituminous		2		4		5		2		4		4		4.7	%
Other Supply		61		73		59		41		55		62		0.1	%

Total Supply		897		957		938		969		1,348		1,616		3.3	%

Transportation of coal. The coal industry in the United States relies upon the operation of a consistent, reliable transportation infrastructure to deliver its coal to its point of use both domestically and internationally. The primary methods of transportation for coal within the United States are railroads and barges, which account for approximately three-quarters of all coal shipments. When coal is only traveling a short distance from mine to point of use, trucks and conveyors are used as well.

Transportation has a large impact on the delivered price of coal at the point of use. The cost to transport coal from the mine to the customer can have a significant impact on the value of coal as it relates to the energy content that it delivers. Coal produced in the United States for domestic consumption is generally sold FOB at the mine or terminal and it is customary for the purchaser to take on the transportation costs as part of the price paid for the product. However, seaborne coal is generally sold FOB at the loading port. Depending upon the requirements of individual customers, producers may provide transportation and logistics services for the customer, often in turn for a higher negotiated price. The countries that import coal in both the Atlantic and Pacific seaborne markets have an established coal import terminal infrastructure.

Upon the enactment of the Clean Air Act Amendments of 1990, many utilities that did not have scrubbers chose to comply with reduced sulfur dioxide emissions mandates by purchasing emission credits and / or switching to lower sulfur fuels. As a result, Powder River Basin production increased from 197.1 million tons in 1990 to an estimated 418.2 million tons in 2014. In conjunction, some utilities that burn Powder River Basin coal decided to enter into long-term rail contracts with one of the two western U.S. railroads to minimize their spending on transportation costs. From 1994 to 2004, reported revenue per carload for these carriers was essentially unchanged, rising 10.1%. As many of the original long-term, fixed price contracts expired, unit rail charges increased significantly. From 2004 to December 31, 2013, average revenue per carload for these carriers increased by 86.3%.

On the U.S. West Coast, major export terminals for coal include the Port of Stockton, in Stockton, California; the Levin-Richmond Terminal and the Port of Long Beach, California. Multiple terminal development projects are ongoing, including the Morrow Pacific Project in Boardman, Oregon; Longview Terminal in Longview, Washington and the Gateway Pacific Terminal in Cherry Point, Washington. These projects have encountered significant resistance from local communities and environmental groups.

In the eastern United States, major export terminals for coal include the Port of New Orleans in New Orleans, Louisiana; Alabama State Docks in Mobile, Alabama; Port of Houston in Houston, Texas; Shipyard River Terminal in Charleston, South Carolina; Hampton Roads in Norfolk, Virginia; and Port of Baltimore in Baltimore, Maryland.

Prices for coal vary widely based on many factors, which include supply and demand balance, production and transportation costs, availability of alternate fuels, macroeconomic conditions, coal quality, governmental regulation and weather patterns. The two primary components of the delivered price of coal are the price of coal at the mine and the transportation costs required to get the coal to the point of use. Spot and forward prices for coal are generally based upon various published indices traditionally accepted by both buyers and sellers. Typically, coal prices for a given region are based on a benchmark price, and the price of coal is modified from this benchmark based on certain physical characteristics.

U.S. thermal coal market pricing. From 2002 through 2013, annual average thermal coal spot prices in Central Appalachia, Northern Appalachia, the Illinois Basin, the Powder River Basin and the Western Bituminous region increased in real 2014 terms by 69%, 61%, 40%, 32% and 60%, respectively. Over the course of this period, coal prices fluctuated along with short to medium-term supply/demand instabilities. Thermal coal prices increased substantially in 2008 predominantly due to

strong demand from both the domestic and export markets, paired with declines in inventory levels. This trend reversed in 2009 as a result of the U.S. recession and global economic downturn.

The following chart sets forth representative per ton thermal coal prices in various U.S. markets reported on an annualized basis for the period from January 1, 2002 to December 31, 2013, as reported by Wood Mackenzie. Historical prices for the Uinta Basin are reported by Argus Media and extend to December 31, 2014.

Seaborne thermal coal market pricing. Thermal coal qualities sold on the international market vary widely, with premiums or discounts to benchmark prices based on a comparison of specific quality characteristics to the quality of the benchmark index. No single producer has sufficient market share to control pricing on the seaborne thermal coal market, thus all producers are price takers. Accordingly, the sales prices for seaborne thermal coal in a given market will typically fluctuate with changes in the balance of supply and demand, currency exchange rates, prices of transportation and other fuels and government regulations.

From the period 2008–2011, the seaborne thermal coal market experienced an upward trend in prices. Throughout this period, coal price fluctuations were based predominantly on short to medium-term supply and demand imbalances and inventory levels that were higher or lower than normal. The Pacific market seaborne coal prices rallied in 2010 and 2011 resulting from strong global demand from China and India which outweighed available supply. The following chart sets forth average historical coal prices from pricing surveys and forward projections (as of November 2014) for

the FOB Newcastle thermal market price and FOB Richards Bay thermal market price, as reported and forecast by Wood Mackenzie.

Our operations are subject to a variety of U.S. federal, state and local laws and regulations, such as those relating to employee health and safety; water discharges; air emissions; plant and wildlife protection; the restoration of mining properties; the storage, treatment and disposal of wastes; remediation of contaminants; surface subsidence from underground mining and the effects of mining on surface water and groundwater conditions. In addition, we may become subject to additional costs for benefits for current and retired coal miners.

We believe that we are in material compliance with all applicable environmental, health, safety and related requirements, including all required permits and approvals. From time to time, our mines have received citations or violations, but to date they have not resulted in material liabilities for us. However, there can be no assurance that violations will not occur in the future, that we will be able to always obtain, maintain or renew required permits or that changes in these requirements or their enforcement or the discovery of new conditions will not cause us to incur significant costs and liabilities in the future. Certain of our current and historical mining operations use or have used or store regulated materials which, if released into the environment, may require investigation and remediation. Under certain permits, we are required to monitor groundwater quality on and adjacent to our sites and to develop and implement plans to minimize and correct land subsidence, as well as impacts on waterways and wetlands, caused by our mining operations. While we cannot currently estimate our costs with any certainty, we do not expect these or other costs of compliance with existing environmental, health and safety requirements to be material during 2015. Moreover, under the terms of the omnibus agreement, our sponsor will indemnify us for certain environmental remediation costs. Please read "Certain Relationships and Related Party Transactions—Agreements with Affiliates in Connection with the Transactions—Omnibus Agreement." Major regulatory requirements are briefly described below.

In the United States, the Coal Mine Health and Safety Act of 1969, the Federal Mine Safety and Health Act of 1977 (the "1977 Act") and the Mine Improvement and New Emergency Response Act of 2006 impose stringent mine safety and health standards on all aspects of mining operations. In 1978, the MSHA was created to carry out the mandates of the 1977 Act and was granted enforcement authority. The MSHA is authorized to inspect all underground mining operations at least four times a year and issue citations with civil penalties for the violation of a mandatory health and safety standard. MSHA review and approval is required for a number of miner safety and welfare plans including ventilation, roof controls/bolting, safety training and ground control, refuse disposal and impoundments and respirable dust. For example, MSHA recently finalized a new rule limiting miners' exposure to respirable coal dust. The first phase of the rule went into effect 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 and the use of continuous personal dust monitors. Also, the State of Utah has its own programs for mine safety and health regulation and enforcement. These 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.

The costs of implementing these safety and health regulations at the federal and state level have been, and will continue to be, substantial. Moreover, in response to the April 2010 explosion at Massey Energy Company's Upper Big Branch Mine, we have seen an increase in enforcement scrutiny, including increased numbers of inspections, more inspection hours at mine sites, and increases in the number and severity of enforcement actions, including increased penalties for violations.

Under the U.S. Black Lung Benefits Revenue Act of 1977 and the 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 have been diagnosed with pneumoconiosis and are current and former employees. Companies must also contribute to a trust fund for the payment of benefits and medical expenses to claimants who last worked in the coal industry prior to July 1, 1973 via an excise tax on production sold domestically of up to $1.10 per ton for deep-mined coal and up to $0.55 per ton for surface-mined coal, neither amount to exceed 4.4% of the gross sales price. This tax is passed on to the purchaser under many of our coal supply agreements.

More recently, the Patient Protection and Affordable Care Act added an automatic survivor benefit paid upon the death of a miner with an awarded black lung claim and established a rebuttable presumption with regard to pneumoconiosis among miners with 15 or more years of coal mine employment that are totally disabled by a respiratory condition. These changes could make it more difficult for operators to defend against black lung claims.

We are subject to various U.S. federal, state and local environmental laws. Some of these laws, as described below, impose stringent requirements on our coal mining operations. U.S. federal and state regulations require regular monitoring of our mines and other facilities to ensure compliance. U.S. federal and state inspectors are required to inspect our mining facilities on a frequent schedule. Future laws, regulations or orders, as well as future interpretations or more rigorous enforcement of existing laws, regulations or orders, may require increases in capital and operating costs the extent of which we cannot predict.

The SMCRA, which is administered by the OSM, establishes mining, environmental protection and reclamation standards for all aspects of surface mining as well as many aspects of deep mining. Mine operators must obtain SMCRA permits and permit renewals from the OSM or the applicable state agency. Where state regulatory agencies have adopted federal mining programs under SMCRA, the state becomes the regulatory authority. The Utah Division of Oil, Gas and Mining administers Utah's approved SMCRA program and therefore has achieved primary control of SMCRA enforcement in the State through federal authorization.

SMCRA permit provisions include a complex set of requirements which include: coal prospecting; mine plan development; topsoil removal, storage and replacement; selective handling of overburden materials; mine pit backfilling and grading; protection of the hydrologic balance; subsidence control for underground mines; surface drainage control; mine drainage and mine discharge control and treatment; restoration to the approximate original contour; and re-vegetation. The disposal of coal refuse is also permitted under the SMCRA.

The mining permit application process is initiated by collecting baseline data to adequately characterize the pre-mine environmental condition of the permit area. This work includes surveys of cultural and historical resources, soils, vegetation, wildlife, assessment of surface and ground water hydrology, climatology and wetlands. In conducting this work, we collect geologic data to define and model the soil and rock structures and coal that we will mine. We develop mining and reclamation plans by utilizing this geologic data and incorporating elements of the environmental data. The mining and reclamation plan incorporates the provisions of the SMCRA, state programs and other complementary environmental programs that affect coal mining. Also included in the permit application are documents defining ownership and agreements pertaining to coal, minerals, oil and natural gas, water rights, rights of

way and surface land, and documents required of the OSM's Applicant Violator System, including the mining and compliance history of officers, directors and principal owners of the entity.

Once a permit application is prepared and submitted to the regulatory agency, it goes through a completeness review and technical review. Public notice of the proposed permit is given that also provides for a comment period before a permit can be issued. Some SMCRA mine permits take over a year to prepare, depending on the size and complexity of the mine and may take months or years to be reviewed and issued. Regulatory authorities have considerable discretion in the timing of the permit issuance and the public and other agencies have rights to comment on and otherwise engage in the permitting process, including through intervention in the courts. Before a SMCRA permit is issued, a mine operator must submit a bond or otherwise secure the performance of reclamation obligations.

The Abandoned Mine Land Fund, which is part of the SMCRA, requires a fee on all coal produced. The proceeds are used to reclaim mine lands closed or abandoned prior to the SMCRA's adoption in 1977. Prior to October 1, 2012, the fee was $0.315 per ton on surface-mined coal and $0.135 per ton on deep-mined coal. Effective October 1, 2012, the fee on surface-mined coal was lowered to $0.28 per ton and the fee on deep-mined coal was lowered to $0.12 per ton.

The SMCRA stipulates compliance with many other major environmental statutes, including: the Clean Air Act; the Endangered Species Act; the CWA; RCRA and CERCLA.

Various federal and state laws, including the SMCRA, require us to obtain surety bonds or other forms of financial security to secure payment of certain long-term obligations, including mine closure or reclamation costs. As of December 31, 2014, we had outstanding surety bonds of $23.8 million related to these matters. Changes in these laws or regulations could require us to obtain additional surety bonds or other forms of financial security.

The Clean Air Act and comparable state laws that regulate air emissions affect coal mining operations both directly and indirectly. Direct impacts on coal mining operations may occur through Clean Air Act permitting requirements or emission control requirements relating to particulate matter, such as fugitive dust, including future regulation of fine particulate matter measuring 2.5 micrometers in diameter or smaller. The Clean Air Act indirectly affects coal mining operations by extensively regulating the air emissions of sulfur dioxide, nitrogen oxides, mercury and other compounds emitted by coal-fired electricity generating plants.

Clean Air Act requirements that may directly or indirectly affect our operations include the following:

Title IV of the Clean Air Act required a two-phase reduction of sulfur dioxide emissions by electric utilities and applies to all coal-fired power plants generating greater than 25 Megawatts of power. The affected electricity generators have sought to meet these requirements by, among other compliance methods, switching to lower sulfur fuels, installing pollution control devices, reducing electricity generating levels or purchasing sulfur dioxide emission allowances. We cannot accurately predict the effect of these provisions of the Clean Air Act on us in future years. At this time, we believe that implementation has resulted in an upward pressure on the price of lower sulfur coals, such as ours, and could therefore have an adverse effect on demand for our coal.

The Clean Air Act requires the EPA to set standards, referred to as NAAQS, for certain pollutants. Areas that are not in compliance (referred to as "non-attainment areas") with these

standards must take steps to reduce emissions levels. The EPA has promulgated NAAQS for six common pollutants, including sulfur dioxide, nitrogen oxide, ozone, particulate matter with an aerodynamic diameter less than or equal to 10 microns ("PM10"), and for fine particulate matter with an aerodynamic diameter less than or equal to 2.5 microns ("PM2.5"). The EPA revised the PM2.5 NAAQS on December 14, 2012, making it more stringent. Pursuant to the 2012 revision, states were required to make recommendations on nonattainment designations for the new NAAQS in late 2013, and the EPA finalized its designations in December 2014, although the EPA deferred making designations for several areas due to data validity issues. Individual states must now identify the sources of PM2.5 emissions and develop emission reduction plans, which may be state-specific or regional in scope. Nonattainment areas must meet the revised standard no later than 2021. Future regulation and enforcement of the new PM2.5 standard will affect many power plants and coke plants, especially coal-fired power plants and all plants in non-attainment areas. Continuing non-compliance with NAAQS standards could prevent issuance of permits to facilities within the non-attainment areas. Meeting current or potentially more stringent NAAQS may require reductions of nitrogen oxide and sulfur dioxide emissions.

In November 2014, the EPA proposed a revision of the existing NAAQS for ozone. Specifically, the EPA proposed updating both its primary ozone standard and the secondary standard to 8-hour standards set within a range of 65 to 70 parts per billion (ppb). Significant additional emissions control expenditures will likely be required at coal-fired power plants and coke plants to meet the new standards, which are expected to be finalized in 2015. Nitrogen oxides, which are a by-product of coal combustion, can lead to the creation of ozone. Accordingly, emissions control requirements for new and expanded coal-fired power plants and industrial boilers and coke plants would continue to become more demanding in the years ahead. In March 2015, eleven states wrote a letter to the EPA asking the agency to drop its proposed revision and instead leave in place the current standard. More stringent NAAQS in the future for ozone could increase the costs of operating coal-fired power plants.

The CSAPR, which was intended to replace the previously developed CAIR, requires states to reduce power plant emissions that contribute to ozone or fine particle pollution in other states. Under the CSAPR, emissions reductions were to have started January 1, 2012, for sulfur dioxide and annual nitrogen oxides reductions, and May 1, 2012, for ozone season nitrogen oxides reductions. Several states and other parties filed suits in the U.S. Court of Appeals for the D.C. Circuit in 2011 challenging the CSAPR. On August 21, 2012, the D.C. Circuit vacated the CSAPR and ordered the EPA to continue administering CAIR, pending the promulgation of a replacement rule. It is unclear what effect, if any, CAIR will have on our operations or results. On April 29, 2014, the U.S. Supreme Court found that the EPA was complying with statutory requirements when it issued CSAPR and reversed the D.C. Circuit's vacation of CSAPR. The case was remanded to the D.C. Circuit for further proceedings consistent with the Court's opinion. On June 26, 2014, the United States filed a motion asking the D.C. Circuit to lift its stay of CSAPR. On October 23, 2014, the court granted the EPA's request to lift the stay, and on November 21, 2014, the EPA issued an interim final rule reconciling the CSAPR rule with the court's order, which calls for Phase 1 implementation in 2015 and Phase 2 implementation in 2017. However, other legal challenges to CSAPR remain in the D.C. Circuit litigation. Arguments were heard in the remanded D.C. Circuit litigation in February 2015, and a ruling is expected later this year. Because U.S. utilities have continued to take steps to comply with CAIR, which requires similar power plant emissions reductions, and because utilities are preparing to comply with the Mercury and Air Toxics Standards regulations which require overlapping power plant emissions reductions, the practical impact of CSAPR is expected to be limited.

On December 16, 2011, the EPA issued the MATS to reduce emissions of toxic air pollutants, including mercury, other metals and acid gases, from new and existing coal and oil fired power plants. Under the final rule, existing power plants will have up to four years to comply with the MATS by installing or upgrading pollution controls, fuel switching, or using existing emissions controls as necessary to meet the compliance deadline. The D.C. Circuit upheld various portions of the rulemaking in two separate decisions issued in March and April 2014, respectively. In November 2014, the U.S. Supreme Court granted certiorari to review the D.C. Circuit decision. The Supreme Court heard oral arguments in the case in March 2015. The MATS requirements could significantly increase our customers' costs and cause them to reduce their demand for coal, which may materially impact our results or operations.

Some utilities have been moving forward with installation of equipment necessary to comply with MATS, and the EPA and states have been granting additional time beyond the 2015 deadline (but no more than one extra year) for facilities that need more time to upgrade and complete those installations. The rule could result in the retirement of certain older coal plants.

Concerns about GHG, including carbon dioxide, emitted from burning coal at electric generation plants has led to efforts at all levels of government to reduce their emissions, which could require utilities to burn less or eliminate coal in the production of electricity. Congress has considered federal legislation to reduce GHG emissions which, among other things, could establish a cap and trade system for GHG, including carbon dioxide emitted by coal burning power plants, and requirements for electric utilities to increase their use of renewable energy such as solar and wind power. Also, the EPA has taken several recent actions under the Clean Air Act to regulate GHG emissions. These include, among others, the EPA's finding of "endangerment" to public health and welfare from GHG and its issuance in 2009 of the Final Mandatory Reporting of Greenhouse Gases Rule, which requires large sources, including coal-fired power plants, to monitor and report GHG emissions to the EPA annually starting in 2011. The EPA also recently proposed new source performance standards for GHG for new coal and oil-fired power plants, which could require partial carbon capture and sequestration to comply. 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 final rule is expected to be issued by mid-summer 2015 and the emission reductions are scheduled to commence in 2020. A legal challenge to the proposed rulemaking was already filed by a coal company, and twelve states joined the suit. However, the D.C. Circuit Court of Appeals denied the petitions for review, holding that the court did not have authority to review agency rules that are not yet final. Although this suit was unsuccessful, similar judicial challenges are likely to be filed in the future once these regulations are finalized. We expect that the EPA's proposed regulations for both new and existing power plants, if promulgated along the lines proposed, would negatively affect the viability of coal-fired power generation, which could ultimately reduce demand for our coal. Although the EPA's actions are subject to procedural delays and legal challenges, and efforts are underway in Congress to limit or remove the EPA's authority to regulate GHG emissions, they will proceed as proposed unless revised by the EPA or altered by the courts or Congress.

The U.S. Supreme Court, in a decision issued on June 23, 2014, addressed whether the EPA's regulation of GHG emissions from new motor vehicles properly triggered GHG permitting requirements for stationary sources under the Clean Air Act. Through its Prevention of Significant Deterioration ("PSD") and Title V Greenhouse Gas Tailoring Rule, the EPA sought to require large industrial facilities, including coal-fired power plants, to obtain permits to emit, and to use best available control technology to curb, GHG emissions. The decision reversed, in part, and affirmed, in part, a 2012 D.C. Circuit

decision that upheld the EPA's GHG-related regulations. Specifically, the court held that the EPA exceeded its statutory authority when it interpreted the Clean Air Act to require Prevention of Significant Deterioration and Title V permitting for stationary sources based on their potential GHG emissions. However, the Court also held that the EPA's determination that a source already subject to the PSD program due to its emission of conventional pollutants may be required to limit its GHG emissions by employing the "best available control technology" was permissible.

Non-government organizations have also petitioned the EPA to regulate coal mines as stationary sources under the Clean Air Act. On May 13, 2014, the D.C. Circuit in WildEarth Guardians v. United States Environmental Protection Agency upheld the EPA's denial of one such petition. On July 18, 2014, the D.C. Circuit denied a petition to rehear that case en banc.

Nine Northeast and Mid-Atlantic states have cooperatively developed a regional cap and trade program, the Regional Greenhouse Gas Initiative, intended to reduce carbon dioxide emissions from power plants in the region. There can be no assurance at this time that this, or similar state or regional carbon dioxide cap and trade programs, in the states where our customers operate, will not adversely affect the future market for coal in the region.

The EPA has initiated a regional haze program designed to protect and to improve visibility at and around national parks, national wilderness areas and international parks. This program restricts the construction of new coal-fired power plants whose operation may impair visibility at and around federally protected areas. Moreover, this program may require certain existing coal-fired power plants to install additional control measures designed to limit haze-causing emissions, such as sulfur dioxide, nitrogen oxides, volatile organic chemicals and particulate matter. In March 2015, the Utah Air Quality Board released a revised proposed State Implementation Plan to address regional haze. In the meantime, a non-governmental organization has filed a lawsuit in federal court seeking, among other relief, an injunction compelling EPA to promulgate a Federal Implementation Plan to address regional haze in Utah. As of June 5, 2015, this litigation has been stayed for 60 days pending settlement negotiations. These limitations could adversely affect the future market for coal.

A number of pending regulatory changes and court actions are affecting the scope of the EPA's new source review and PSD programs, which under certain circumstances require existing coal-fueled power plants to install the more stringent air emissions control equipment required of new plants. The new source review and PSD programs are continually revised and such revisions may impact demand for coal nationally, but we are unable to predict the magnitude of the impact.

The RCRA affects coal mining operations by establishing requirements for the treatment, storage, and disposal of hazardous wastes. Certain coal mine wastes, such as overburden and coal cleaning wastes, are exempted from hazardous waste management.

Subtitle C of the RCRA exempted fossil fuel combustion wastes from hazardous waste regulation until the EPA completed a report to Congress and made a determination on whether the wastes should be regulated as hazardous. In 2000, the EPA concluded that coal combustion wastes do not warrant regulation as hazardous under the RCRA. Following a large spill of coal ash waste at a coal burning power plant in Tennessee in June 2010, the EPA proposed two alternative sets of regulations governing the management and storage of coal ash: one would regulate coal ash and related ash impoundments at

coal-fired power plants under federal regulations governing hazardous solid waste under Subtitle C of the RCRA and the other would regulate coal ash as a non-hazardous solid waste under Subtitle D. In December 2014, the EPA finalized regulations that address the management of coal ash as a non-hazardous solid waste under Subtitle D. The rules impose engineering, structural and siting standards on surface impoundments and landfills that hold coal combustion wastes and mandate regular inspections. The rule also requires fugitive dust controls and imposes various monitoring, cleanup, and closure requirements.

In addition, environmental groups filed a notice of intent to sue the EPA for failing to update effluent limitation guidelines under the CWA for coal-fired power plants to limit discharges of toxic metals from handling of coal combustion waste. In April 2013, the EPA released its proposed revised effluent limitation guidelines to address toxic pollutants discharged from power plants, including discharges from coal ash ponds. Pursuant to a consent decree, the EPA is required to sign a final action on the rule by September 30, 2015. If the EPA adopts new CWA requirements, compliance obligations for handling, transporting, storing and disposing of the material would likely increase. Potential changes to all of these rules could make coal burning more expensive or less attractive for electric utilities.

Most state hazardous waste laws exempt coal combustion waste and instead treat it as either a solid waste or a special waste. These laws may also be revised. Any costs associated with handling or disposal of coal ash as hazardous wastes would increase our customers' operating costs and potentially reduce their ability to purchase coal. In addition, potential liability for contamination caused by the past or future use, storage or disposal of ash could substantially increase.

The CWA established in-stream water quality standards and treatment standards for waste water discharge through the NPDES. Regular monitoring, reporting requirements and performance standards are requirements of NPDES permits that govern the discharge of pollutants, including selenium, sulfate and specific conductance, into water. Discharges that exceed the limits specified under NPDES permits can lead to the imposition of penalties, and persistent non-compliance could lead to significant penalties, compliance costs and delays in coal production. In addition, the imposition of future restrictions on the discharge of certain pollutants into "waters of the United States" could increase the difficulty of obtaining and complying with NPDES permits, which could impose additional time and cost burdens on our operations. Moreover, in May 2015, the EPA released a finalized rule that sets forth changes to its definition of "waters of the United States." Although EPA has stated that the rule does not create any new permitting requirements and maintains all previous exemptions and exclusions, we are currently evaluating the effects, if any, the finalized rule may have on our operations or permitting obligations. Any expansion to CWA jurisdiction could impose additional permitting obligations on our operations, which may adversely impact our coal production or results of operations.

TMDL regulations establish a process by which states may designate stream segments as "impaired" (not meeting present water quality standards). Industrial dischargers, including coal mines and plants, will be required to meet new TMDL effluent standards for these stream segments. The adoption of new TMDL regulations in receiving streams could hamper or delay the issuance of discharge and Section 404 permits, and if issued, could require new effluent limitations for our coal mines and could require more costly water treatment, which could adversely affect our coal production or results of operations. States are also adopting anti-degradation regulations in which a state designates certain water bodies or streams as "high quality." These regulations would prohibit the diminution of water quality in these streams. Waters discharged from coal mines to high quality streams will be required to meet or exceed new "high quality" standards. The designation of high quality streams at or in the vicinity of our coal mines could require more costly water treatment and could adversely affect our coal production or results of operations.

In the case of both the TMDL and anti-degradation review, the limits in our NPDES discharge permits could become more stringent, thereby potentially increasing our treatment costs or making it more difficult to obtain new permits. Other requirements may result in obligations to treat discharges from coal mining properties for non-traditional pollutants, such as chlorides, selenium and dissolved solids and/or require us to take measures intended to protect streams, wetlands, other regulated water sources and associated riparian lands from mining impacts. Individually and collectively, these requirements may cause us to incur significant additional costs that could adversely affect our operating results, financial condition and cash flows.

On May 19, 2014, the EPA issued a new final rule pursuant to Section 316(b) of the CWA that affects the cooling water intake structures at power plants in order to reduce fish impingement and entrainment. The rule is expected to affect over 500 power plants. These requirements could increase our customers' costs and cause them to reduce their demand for coal, which may materially impact our results or operations.

CERCLA and similar state laws affect coal mining by creating liability for the investigation and remediation of releases of regulated materials into the environment and for damages to natural resources. Under these laws, joint and several liability may be imposed on waste generators, current and former site owners or operators and others regardless of fault, for all related site investigation and remediation costs. Although the EPA excludes most wastes generated by coal mining and processing operations from the hazardous waste laws, such wastes can, in certain circumstances, constitute hazardous substances for the purposes of CERCLA. In addition, the disposal, release or spilling of some products used by coal companies in operations, such as chemicals, could trigger the liability provisions of the statute. Thus, coal mines that we currently own or have previously owned or operated, and sites to which we sent waste materials, may be subject to liability under CERCLA and similar state laws.

Substantially all of our planned activities and operations include acreage located on federal land and, thus, require one or more governmental approvals that may trigger the requirements of NEPA. NEPA requires federal agencies, including the Department of the Interior, to evaluate major agency actions such as issuing an approval, that have the potential to significantly impact the environment. In the course of such evaluations, an agency will typically prepare an environmental assessment to assess the potential direct, indirect and cumulative impacts of a proposed project. Where the activities in question have significant impacts to the environment, the agency, in this instance, must prepare an environmental impact statement, or EIS. 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 agencies have complied with NEPA is subject to protest, appeal or litigation, which can delay or halt projects. For example, in June 2014, the U.S. District Court for the District of Colorado, in High Country Conservation Advocates v. United States Forest Service, found that the U.S. Forest Service and the BLM failed to comply with the requirements of NEPA when ruling on various coal mine-related matters, including various lease modifications. The court found that two separate EIS reports prepared by the agencies were insufficient because they failed to include certain data and analysis relating to the impacts of carbon emissions. Accordingly, in September 2014, the court vacated the agencies' approvals, including those related to the lease modifications. 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. 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.

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. Although we do not expect any delays in our development plans or operations because of the NEPA review process, NEPA reviews may extend the time and/or increase the costs for obtaining necessary governmental approvals.

Protection of threatened, endangered and other special status species may have the effect of prohibiting or delaying us from obtaining mining permits. Based on the species that have been identified to date and the current application of applicable laws and regulations, however, we do not believe there are any species protected under the Endangered Species Act that would materially adversely affect our ability to mine coal from our properties in accordance with current mining plans. Should more stringent protective measures be applied to threatened, endangered or other special status species or to their critical habitat, then we could experience increased operating costs or difficulty in obtaining future mining permits.

The U.S. Fish and Wildlife Service ("USFWS") is currently subject to an agreement that requires it to determine by September 2015 whether the greater sage-grouse will be listed as a threatened species. Pursuant to this agreement, the USFWS has initiated its formal status review of the greater sage-grouse under the Endangered Species Act. However, in December 2014, a coalition of mining and ranching groups filed a lawsuit in federal court challenging earlier settlements between USFWS and various non-governmental organizations pursuant to which USFWS must make listing determinations for several species, including the greater sage-grouse, by various dates certain. In March 2015, several counties and industry associations filed challenges against the BLM, USFWS, and U.S. Geological Survey pursuant to the Federal Information Quality Act challenging a number of key reports upon which USFWS is expected to rely in making its listing decision. Moreover, in an effort to delay any potential action on the greater sage-grouse by the September 2015 deadline, Congress has passed a spending bill preventing USFWS from spending money in 2015 on rules that would protect the greater sage-grouse. Meanwhile, in May 2015, the BLM and the U.S. Forest Service issued a series of final Environmental Impact Statements ("EISs") for proposed land use plan amendments incorporating conservation measures for the greater sage-grouse in ten western states. The USFWS has stated that it will utilize these land use plans in its formal review of the greater sage-grouse listing status. BLM has stated that the EISs focus on conserving Priority Habitat areas that have been identified as having the highest value to maintaining the species and its habitat and contain land use measures designed to minimize or avoid habitat disturbance. BLM has also stated that the plans honor all valid, existing rights, including those for oil and gas development, rights-of-way, locatable minerals, and other

permitting projects. At a state level, Utah published a Conservation Plan for Greater Sage-grouse in Utah in 2013. The Utah Conservation Plan seeks to eliminate the threats facing sage-grouse populations while balancing the economic and social needs of the residents of Utah. Pursuant to the Utah Conservation Plan, extractive mineral activities in designated Sage Grouse Management Areas would be subject to management protocols designed to avoid or minimize disturbances to the sage-grouse population. Utah has submitted its Conservation Plan to the USFWS for its opinion on the sufficiency of the conservation provisions. USFWS began its review of the Plan in February 2013, and in February 2015, Governor Gary Herbert signed an Executive Order implementing the Plan. Certain of our mines may be located on or near lands designated as Priority Areas of Conservation for the greater sage-grouse as determined by USFWS and/or Sage Grouse Management Areas as determined by Utah's Public Lands Policy Coordination Office. However, we have not yet determined whether the Utah Conservation Plan or the addition of the greater sage-grouse to the list of threatened species would impact our operations. If a USFWS listing determination results, it could lead to new land use restrictions to protect the greater sage-grouse. Should more stringent protective measures be applied to protect the greater sage-grouse, this could result in increased operating costs, heightened difficulty in obtaining future mining permits, or the need to implement additional mitigation measures, thereby impacting our mining operations and costs.

We are required to comply with numerous other federal, state and local environmental laws in addition to those previously discussed. These additional laws include, for example, the Safe Drinking Water Act, the Toxic Substance Control Act and the Emergency Planning and Community Right-to-Know Act.

Mining companies must obtain numerous permits that impose strict regulations on various environmental and safety matters. These provisions include requirements for building dams; coal prospecting; mine plan development; topsoil removal, storage and replacement; protection of the hydrologic balance; subsidence control for underground mines; subsidence and surface drainage control; mine drainage and mine discharge control and treatment; and re-vegetation.

The mining permit application process is initiated by collecting baseline data to adequately characterize the pre-mine environmental condition of the permit area. This work includes surveys of cultural resources, soils, vegetation, wildlife, assessment of surface and ground water hydrology, climatology and wetlands. In conducting this work, we collect geologic data to define and model the soil and rock structures and coal that we will mine. We develop mine and reclamation plans by utilizing this geologic data and incorporating elements of the environmental data. The mine and reclamation plan incorporates the provisions of the SMCRA, the state programs and the complementary environmental programs that affect coal mining, including the CWA.

Required permits include mining and reclamation permits under the SMCRA, issued by the Utah Department of Natural Resources Division of Oil, Gas and Mining, and wastewater discharge, or NPDES, permits under the CWA, issued by the Utah Department of Environmental Quality Division of Water Quality. In addition to the required permits, for surface operations, mining companies may also need to obtain air quality permits from Utah Department of Environmental Quality Division of Air Quality. In addition, MSHA approval for ventilation, roof control and numerous specific surface and underground operations must be obtained and maintained. The authorization and permitting requirements imposed by these and other governmental agencies are costly and may delay development or continuation of mining operations. Due to the fact that the application review process may take years to complete and permit applications are increasingly being challenged by environmental and other

advocacy groups, we may experience difficulty or delays in obtaining mining permits or other necessary approvals, or even face denials of permits altogether.

Once a permit application is prepared and submitted to the regulatory agency, it goes through a completeness review, technical review and public notice and comment period before it can be approved. Some SMCRA and CWA permits can take over a year to prepare, depending on the size and complexity of the mine and often take six months or years to receive approval. Regulatory authorities have considerable discretion in the timing of the permit issuance and the public has rights to comment on and otherwise engage in the permitting process, including through intervention in the courts.

Currently, we have the necessary permits for mining operations at each of our three mines. Continued and expanded operations will require additional or renewed permits. These additional permits may include significant permit revisions to the SMCRA mining permit and fill and dredge permits for mining of additional coal panels; new NPDES, new SMCRA, new impounding, and possible CWA permits for additional refuse areas; and revisions to the SMCRA permit and a NPDES construction permit for additional bleeder shafts. Due to various and, sometimes, interrelated requirements from different agencies, it is not possible to predict an average or approximate time frame required to obtain all permits and approvals to operate new or expanded mines. In addition, expanded permitting activity and/or challenges from environmental groups may increase the various agencies' permit and approval review time in the future, and may create uncertainty about our ability to utilize permits that may be the subject of any appeal.

Our customers may face similar permitting challenges. In addition to the regulatory requirements applicable to electric generators described above, export terminals are also subject to permit requirements, as well as challenges from environmental organizations which may make it complicated or expensive to expand existing terminal capacity or open new export terminals in a timely and cost-effective manner. Demand for our coal could be constrained by export terminal capacity, which may materially impact our results or operations.

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. As a result of owning our general partner, our sponsor will have the right to appoint all members of the board of directors of our general partner, including at least three directors meeting the independence standards established by the NYSE. At least one of our independent directors will be appointed prior to the date our common units are listed for trading on the NYSE. Our unitholders will not be entitled to elect our general partner or its directors or otherwise directly participate in our management or operations. Our general partner owes certain contractual duties to our unitholders as well as a fiduciary duty to its owners.

Upon the closing of this offering, we expect that our general partner will have seven directors, at least one of whom will be independent as defined under the standards established by the NYSE and the Exchange Act. The NYSE does not require a listed publicly traded partnership, such as ours, to have a majority of independent directors on the board of directors of our general partner or to establish a compensation committee or a nominating committee. However, our general partner is required to have an audit committee of at least three members, and all its members are required to meet the independence and experience standards established by the NYSE and the Exchange Act, subject to certain transitional relief during the one-year period following consummation of this offering. Our sponsor will appoint at least one member of the audit committee to the board of directors of our general partner by the date our common units first trade on the NYSE.

In evaluating director candidates, our sponsor will assess whether a candidate possesses the integrity, judgment, knowledge, experience, skill and expertise that are likely to enhance the board's ability to manage and direct our affairs and business, including, when applicable, to enhance the ability of committees of the board to fulfill their duties.

All of the executive officers of our general partner listed below will allocate their time between managing our business and affairs and the business and affairs of our sponsor. The amount of time that our executive officers will devote to our business and the business of our sponsor will vary in any given year based on a variety of factors. Our executive officers intend, however, to devote as much time to the management of our business and affairs as is necessary for the proper conduct of our business and affairs. Following the consummation of this offering and after giving effect to the closing of the Utah Transaction, we expect that our executive officers, on average, will devote at least 50% of their time to our operations. However, the amount of time that our executive officers actually devote to our operations may fluctuate and cannot be predicted with certainty and will also be dependent on future acquisition activities and other operational requirements of our sponsor.

Following the consummation of this offering, neither our general partner nor our sponsor will receive any management fee or other compensation in connection with our general partner's management of our business, but we will reimburse our general partner and its affiliates, including our sponsor, for all expenses they incur and payments they make on our behalf. Our partnership agreement does not set a limit on the amount of expenses for which our general partner and its affiliates 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. Please read "Certain Relationships and Related Party Transactions."

Certain executive officers of our general partner hold a profits interest in our sponsor.

The following table shows information for the executive officers and directors of our general partner upon the consummation of this offering. Directors hold office until their successors have been

elected or qualified or until the earlier of their death, resignation, removal or disqualification. Executive officers serve at the discretion of the board. There are no family relationships among any of our directors or executive officers. Some of our directors and all of our executive officers also serve as directors and executive officers of our sponsor.

Name		Position With Our General Partner

John J. Siegel	65	Chairman of the Board of Directors
Johannes ("Manie") H. Dreyer	44	Chief Executive Officer, Director
Eugene ("Gene") E. DiClaudio	62	Chief Operating Officer
James J. Wolff	57	Chief Financial Officer
Grant S. Quasha	35	Chief Commercial Officer
Brian S. Settles	35	Senior Vice President, Secretary and General Counsel
John DeRosa	54	Director Nominee
Jesus Fernandez	38	Director Nominee
Carlos Pons	33	Director Nominee
Steve Rickmeier	67	Director Nominee

John J. Siegel has over 30 years of experience as a founder and operator of vertically-integrated coal companies. Among individual holders, he owns the largest equity share of our sponsor. Mr. Siegel is also the co-owner and operator of Bowie Refined Coal, LLC and ClearStack Power LLC. Previously, he was the founder and operator of each of Green Bay Fuels, Inc., Jader Coal, LLC, Northwestern Synfuels, LLC and Sentinel Energy, Inc. Mr. Siegel holds a Bachelor of Arts degree from St. Joseph's College in Rensselaer, Indiana. He attended law school at the University of Louisville.

We believe Mr. Siegel's extensive knowledge of the coal industry and his wealth of management experience within the industry make him a valuable asset to the board of directors of our general partner.

Johannes ("Manie") H. Dreyer has over 20 years of experience in the mining and minerals industry. His career spans a broad range of commodities, having spent the majority of his time in leadership roles within the coal industry. Throughout his career, Mr. Dreyer has worked in operational and engineering projects, business development, as well as marketing and sales across three continents. He most recently served as President of BHP Billiton Energy Coal South Africa from 2009 to 2014. Prior to that, Mr. Dreyer held a number of executive, operating and commercial positions within BHP Billiton's business divisions in the United States, South Africa, and Singapore. Mr. Dreyer serves as a director and executive committee member of the World Coal Association, whilst he previously served as a director of the Richards Bay Coal Terminal in South Africa as well as a director and council member for the South African Chamber of Mines. He holds a bachelor's degree in electrical engineering from the Rand Afrikaans University (South Africa) as well as a master's degree in business leadership from the University of South Africa.

We believe Mr. Dreyer's extensive professional and leadership experience within the mining and minerals industry, including his tenure at BHP Billiton, make him well-qualified to serve as a member of the board of directors of our general partner.

Eugene ("Gene") E. DiClaudio has 40 years of experience in the coal industry. Prior to joining our sponsor, he was the President of the Arch Western Bituminous Group since 2005, where he oversaw the operations of the Sufco, Skyline, Dugout Canyon and West Elk mines and was responsible for all operational results, including Health & Safety, Environmental Compliance, Engineering, Purchasing, Process Improvement and Human Resources. Previously, Mr. DiClaudio was president of Mountain Coal and held senior executive positions at ARCO Coal and BP Coal. He holds a Bachelor of Science

degree in Mining Engineering from Pennsylvania State University and holds the Pennsylvania Mine Foreman Certificate.

James J. Wolff has been the chief financial officer of our sponsor since 2011. He has over 30 years of experience in the energy and transportation industries, with a diverse background in finance, operations and business development. Mr. Wolff possesses substantial IPO, M&A and divestitures experience with companies generating revenues between $300 million and $8 billion. Prior to joining our sponsor, he was CFO of U.S. Coal Corporation and has held senior executive positions with Energy Coal Resources, American Commercial Lines and CSX Corporation. Mr. Wolff holds a Bachelor of Arts degree in Economics from the University of Texas and attended South Texas College of Law.

Grant S. Quasha joined our sponsor in 2013 as Senior VP, Business Development. He was promoted to Chief Commercial Officer in 2014 and is responsible for Business Development, Strategy, Sales and Marketing. Mr. Quasha has over 10 years of experience in the commodity and finance industries. Prior to joining our sponsor, he was the North American Manager of Corporate and Structured Finance at Trafigura and an Associate at JPMorgan Chase & Co., focused on the mining industry. Mr. Quasha began his career as an oil tanker broker at Poten & Partners. He holds a Bachelor of Arts degree, cum laude, from Harvard College and a Master of Business Administration degree with Distinction from Harvard Business School.

Brian S. Settles joined our sponsor in August 2013 and has served as Senior Vice President, Secretary and General Counsel since that time. Prior to joining our sponsor, Mr. Settles practiced law with Fultz Maddox Hovious & Dickens, PLC, Greenebaum Doll & McDonald PLLC and Taft Stettinius & Hollister LLP, specializing in mergers and acquisitions, corporate law and natural resources law. Mr. Settles holds a Bachelor of Arts degree in Finance from Miami University, magna cum laude, and a Juris Doctor degree from the University of Kentucky College of Law, summa cum laude.

John DeRosa is a nominee for the board of directors of our general partner. Mr. DeRosa is a member of the board of directors of our sponsor. He has over 25 years of experience in the financial services industry and is currently the Head of Tax for the Americas for Deutsche Bank. In his role, he is responsible for all tax matters for Deutsche Bank's operations in the U.S., Latin America and Canada. Deutsche Bank Securities Inc. is acting as an underwriter in connection with this offering. Prior to joining Deutsche Bank, Mr. DeRosa was the Global Head of Tax for Lehman Brothers, the Head of Tax for The Bank of New York, a Director in the Structured Transactions Group at Morgan Stanley and a tax partner in the Financial Services group of Ernst & Young. Mr. DeRosa is a CPA. He earned his B.A. in Political Science from Haverford College and his M.B.A in accounting from Rutgers University.

We believe Mr. DeRosa's wealth of experience and expertise in the financial services industry will provide him with unique insight that we expect will be valuable to the board of directors of our general partner.

Jesus Fernandez is a nominee for the board of directors of our general partner. Mr. Fernandez is a member of the board of directors of our sponsor. Mr. Fernandez has over 15 years of experience in mining investments and commodities financing. He established the Trafigura Group's mining investment arm in 2005, and he currently heads the mining investment team at Galena. Mr. Fernandez is a board member of a number of companies including Trafigura Group's mining division, Cadillac Ventures and Mawson West. Prior to joining the Trafigura Group, he worked in the project finance team at International Power plc in London. Mr. Fernandez has a Master of Science degree (Finance and Investment) from the University of Exeter and a Licenciatura (Economics degree) from the Universidad de Cantabria, Spain.

We believe Mr. Fernandez's substantial industry experience, including at the Trafigura Group and Galena, will enable him to provide essential guidance to the board of directors of our general partner.

Carlos Pons is a nominee for the board of directors of our general partner. Mr. Pons is a member of the board of directors of our sponsor. Mr. Pons has over ten years of experience in M&A, investments and financing in mining and natural resources. He started his career at Goldman Sachs and worked in its London and Moscow offices where he was involved in numerous merger, acquisition and capital markets transactions. Most recently, Mr. Pons worked for Ural Invest as Vice President for investments and executed mining and infrastructure investments in Russia and Africa. Mr. Pons joined Galena in 2013 from Glencore's oil department, where his main focus was M&A. He has a B.A. in Business Administration from ICADE Madrid, Spain.

Based upon his strong background in various aspects of the mining and natural resources industry, we believe Mr. Pons has the requisite set of skills to serve as a director of our general partner.

Steve Rickmeier is a nominee for the board of directors of our general partner. Mr. Rickmeier is a member of the board of directors of our sponsor and has over 30 years of experience in the tax-related finance industry, including as Managing Director of the Energy Finance Group of GE Capital Corporation from 1992 to 1997 and as Managing Director of The Deerpath Group LLC from 1979 to 1991. Previously, Mr. Rickmeier served as Vice President-Director of Lease Financing for ITT Industrial Credit from 1977 to 1979 and as Manager-Industrial Leasing at the Leasing and Industrial Loans Group of GE Capital Corporation from 1972 to 1977. Mr. Rickmeier is one of the principal equity owners of our sponsor. He is also an owner of Bowie Refined Coal, LLC and Clearstack Power, LLC, as well as the co-founder of Northwestern Synfuels, Sentinel Energy and Loyola Synfuels. Mr. Rickmeier received a B.A. from Northwestern University in 1969 and an M.B.A. from Loyola University of Chicago in 1972.

We believe Mr. Rickmeier's extensive experience in the financial sector and the coal industry make him well-qualified to serve as a member of the board of directors of our general partner.

In accordance with the rules of the NYSE, our general partner must have at least one independent director prior to the listing of our common units on the NYSE, one additional member within three months of the effectiveness of the registration statement of which this prospectus forms a part, and one additional independent member within 12 months of that date.

The board of directors of our general partner will have an audit committee and a conflicts committee. We do not expect that we will have a compensation committee, but rather that the board of directors of our general partner will approve equity grants to directors and employees.

We are required to have an audit committee of at least three members, and all its members are required to meet the independence and experience standards established by the NYSE and the Exchange Act, subject to certain transitional relief during the one-year period following consummation of this offering as described above. The audit committee will assist the board of directors in its oversight of the integrity of our financial statements and our compliance with legal and regulatory requirements and partnership policies and controls. The audit committee will have the sole authority to (1) retain and terminate our independent registered public accounting firm, (2) approve all auditing services and related fees and the terms thereof performed by our independent registered public accounting firm, and (3) pre-approve any non-audit services and tax services to be rendered by our

independent registered public accounting firm. The audit committee will also be responsible for confirming the independence and objectivity of our independent registered public accounting firm. Our independent registered public accounting firm will be given unrestricted access to the audit committee and our management.

At least one independent member of the board of directors of our general partner will serve on a conflicts committee to review specific matters that the board believes may involve conflicts of interest and determines to submit to the conflicts committee for review. The conflicts committee will determine if the resolution of the conflict of interest is adverse to the interest of the partnership. The members of the conflicts committee may not be officers or employees of our general partner or directors, officers or employees of its affiliates, including our sponsor, and must meet the independence standards established by the NYSE and the Exchange Act to serve on an audit committee of a board of directors. In addition, the members of our conflicts committee may not own any interest in our general partner or its affiliates (other than common units or awards under our long-term incentive plan) that is determined by the board of directors of our general partner to have an adverse impact on the ability of such director to act in an independent manner with respect to the matter submitted to the conflicts committee. Any matters approved by the conflicts committee will be conclusively deemed to be approved by us and all of our partners and not a breach by our general partner of any duties it may owe us or our unitholders.

We and our general partner were formed in January 2015 and had no material assets or operations until immediately prior to the closing of this offering. Accordingly, neither we nor our general partner has accrued or will accrue any cost or liability with respect to management compensation or retirement benefits for directors or executive officers for any periods prior to our formation date or the date of this offering. As a result, we have no historical compensation information present. We currently do not have a compensation committee.

All of the executive officers of our general partner will be employed by our sponsor, and will allocate their time between managing our business and managing the business of our sponsor. Since all of our executive officers will be employed by our sponsor, the responsibility and authority for compensation-related decisions for our executive officers generally will reside with our sponsor. Any such compensation decisions will not be subject to any approvals by the board of directors of our general partner or any committees thereof. However, any and all determinations with respect to awards that may be made to our executive officers, key employees or directors under any long-term incentive plan we adopt will be made by the board of directors of our general partner or a committee thereof that may be established for such purpose. Please read the description of the long-term incentive plan we intend to adopt prior to the completion of this offering ("LTIP") below under the heading "—Long-Term Incentive Plan."

The executive officers of our general partner may participate in employee benefit plans and other compensation arrangements maintained by our sponsor, including plans that may be established in the future. Our executive officers currently have employment agreements with our sponsor that we anticipate will continue in effect following this offering, the material terms of which are described below. Except with respect to any awards that may be granted under the LTIP, we do not anticipate that our executive officers will receive separate amounts of compensation in relation to the services they provide to us. In accordance with the terms of our partnership agreement and omnibus agreement, we will reimburse our sponsor for compensation-related expenses attributable to the portion of the executive's time dedicated to providing services to us. Please read "The Partnership Agreement—Reimbursement of Expenses" and "Certain Relationships and Related Party Transactions—Agreements with Affiliates in Connection with the Transactions—Omnibus Agreement." Although we will bear an allocated portion of our sponsor's costs of providing compensation and benefits to employees who serve as executive officers of our general partner, we will have no control over such costs and will not establish or direct the compensation policies or practices of our sponsor.

The employment agreements between our executive officers and our sponsor were entered into in 2013 (in the case of Mr. Dreyer, 2014) and each has a three year term, which may be extended by mutual written agreement. The employment agreements provide the executive officers with (i) an annual base salary, which is subject to annual review and may be modified by the board of directors of our sponsor in its discretion; (ii) an annual bonus opportunity (A) in the case of Mr. DiClaudio, in an amount up to 125% of base salary based on the attainment of certain financial, safety and other performance criteria, and (B) in the case of our other executive officers, in an amount up to 50% of base salary (125% of base salary, in the case of Mr. Dreyer) in the discretion of the board of directors of our sponsor; (iii) a profits interest in our sponsor, as described below under "Certain Relationships and Related Party Transactions—Agreements with Affiliates in Connection with the Transactions—Ownership Interests in our Sponsor and Arrangements with Management"; and (iv) the right to participate in all benefit plans, programs and policies offered to salaried employees subject to applicable eligibility requirements. Specifically, the employment agreements established the following annual base salary rates for the executive officers: (a) Mr. Dreyer—$650,000, (b) Mr. DiClaudio—$500,000, (c) Mr. Wolff—$350,000, (d) Mr. Quasha—$330,000, and (e) Mr. Settles—$250,000. The

employment agreements also provide that the executive officers will be reimbursed for reasonable business and other expenses incurred in furtherance of their duties.

If the employment one of our executive officers with the sponsor is terminated without "cause" or for "good reason," then the executive officer will receive, subject to the execution of a general release of claims, (i) a lump sum payment equal to (A) 1.5 times annual base salary, plus (B) the bonus amount received for the prior calendar year (for Mr. Dreyer, the lump sum payment is equal to two times annual base salary), and (ii) reimbursement for premiums for continued medical coverage if elected under COBRA for up to one year (up to 18 months, in the case of Mr. Dreyer). For these purposes, (a) "cause" generally means (1) breach of the employment agreement by executive that is not cured within 30 days of written notice from our sponsor, (2) dishonest, fraudulent or unlawful conduct or gross negligence or willful misconduct involving the sponsor's business or affairs that results in economic harm to the sponsor, or (3) a plea of nolo contendere to or conviction for a felony involving moral turpitude (or, in the case of Mr. Dreyer, being charged with any crime that is related to his employment or that is punishable other than only by a fine or other non-custodial penalty); and (b) "good reason" generally means (1) a material diminution of the executive's duties, responsibilities or authority, (2) a geographic relocation of the executive's primary office location, (3) a reduction in the executive's base salary, or (4) breach of the employment agreement by our sponsor that is not cured within 30 days of written notice from the executive. The employment agreements contain certain indemnification rights, confidentiality and non-disparagement covenants, which are perpetual in duration, and certain non-solicitation and non-competition covenants, which extend for one to two years following the executive's termination of employment.

We do not have any liabilities or obligations under the employment agreements, other than by virtue of our reimbursement obligations under our partnership agreement and omnibus agreement.

In order to incentivize our management and directors following the completion of this offering to continue to grow our business, the board of directors of our general partner intends to adopt a long-term incentive plan, or the LTIP, for employees, officers, consultants and directors of our general partner and any of its affiliates, including our sponsor, who perform services for us. Our general partner intends to implement the LTIP prior to the completion of this offering to provide maximum flexibility with respect to the design of compensatory arrangements for individuals providing services to us; however, at this time, neither we nor our general partner has made any decisions regarding any specific grants under the LTIP in conjunction with this offering or in the near term.

The description of the LTIP set forth below is a summary of the material features of the LTIP that our general partner intends to adopt. This summary, however, does not purport to be a complete description of all the provisions of the LTIP that will be adopted and represents only the general partner's current expectations regarding the LTIP. This summary is qualified in its entirety by reference to the LTIP, the form of which is filed as an exhibit to this registration statement. The purpose of the LTIP is to provide a means to attract and retain individuals who are essential to our growth and profitability and to encourage them to devote their best efforts to advancing our business by affording such individuals a means to acquire and maintain ownership of awards, the value of which is tied to the performance of our common units. We expect that the LTIP will provide for the grant of unit options, unit appreciation rights, restricted units, unit awards, phantom units, distribution equivalent rights, cash awards, performance awards, other unit-based awards and substitute awards (collectively, "awards"). These awards are intended to align the interests of employees, officers, consultants and directors with those of our unitholders and to give such individuals the opportunity to share in our long-term performance. Any awards that are made under the LTIP will be approved by the board of directors of our general partner or a committee thereof that may be established for such purpose. We will be responsible for the cost of awards granted under the LTIP.

The LTIP will be administered by the board of directors of our general partner or an alternative committee appointed by the board of directors of our general partner, which we refer to together as the "committee" for purposes of this summary. The committee will administer the LTIP pursuant to its terms and all applicable state, federal, or other rules or laws. The committee will have the power to determine to whom and when awards will be granted, determine the amount of awards (measured in cash or in shares of our common units), proscribe and interpret the terms and provisions of each award agreement (the terms of which may vary), accelerate the vesting provisions associated with an award, delegate duties under the LTIP and execute all other responsibilities permitted or required under the LTIP. In the event that the committee is not comprised of "nonemployee directors" within the meaning of Rule 16b-3 under the Exchange Act, the full board of directors or a subcommittee of two or more nonemployee directors will administer all awards granted to individuals that are subject to Section 16 of the Exchange Act.

The maximum aggregate number of common units that may be issued pursuant to any and all awards under the LTIP will not exceed common units, subject to adjustment due to recapitalization or reorganization, as provided under the LTIP. In addition, if any common units subject to any award are not issued or transferred, or cease to be issuable or transferable for any reason, including (but not exclusively) because units are withheld or surrendered in payment of taxes or any exercise or purchase price relating to an award or because an award is forfeited, terminated, expires unexercised, is settled in cash in lieu of common units, or is otherwise terminated without a delivery of units, those common units will again be available for issue, transfer, or exercise pursuant to awards under the LTIP, to the extent allowable by law. Common units to be delivered pursuant to awards under our LTIP may be common units acquired by our general partner in the open market, from any other person, directly from us, or any combination of the foregoing.

We may grant unit options to eligible persons. Unit options are rights to acquire common units at a specified price. The exercise price of each unit option granted under the LTIP will be stated in the unit option agreement and may vary; provided, however, that, the exercise price for an unit option must not be less than 100% of the fair market value per common unit as of the date of grant of the unit option unless that unit option is intended to otherwise comply with the requirements of Section 409A of the Code. Unit options may be exercised in the manner and at such times as the committee determines for each unit option, unless that unit option is determined to be subject to Section 409A of the Code, in which case the unit option will be subject to any necessary timing restrictions imposed by the Code or federal regulations. The committee will determine the methods and form of payment for the exercise price of a unit option and the methods and forms in which common units will be delivered to a participant.

A unit appreciation right is the right to receive, in cash or in common units, as determined by the committee, an amount equal to the excess of the fair market value of one common unit on the date of exercise over the grant price of the unit appreciation right. The committee will be able to make grants of unit appreciation rights and will determine the time or times at which a unit appreciation right may be exercised in whole or in part. The exercise price of each unit appreciation right granted under the LTIP will be stated in the unit appreciation right agreement and may vary; provided, however, that, the

exercise price must not be less than 100% of the fair market value per common unit as of the date of grant of the unit appreciation right, unless that unit appreciation right is intended to otherwise comply with the requirements of Section 409A of the Code.

A restricted unit is a grant of a common unit subject to a risk of forfeiture, performance conditions, restrictions on transferability and any other restrictions imposed by the committee in its discretion. Restrictions may lapse at such times and under such circumstances as determined by the committee. The committee shall provide, in the restricted unit agreement, whether the restricted unit will be forfeited upon certain terminations of employment. Unless otherwise determined by the committee, a common unit distributed in connection with a unit split or unit dividend, and other property distributed as a dividend, will generally be subject to restrictions and a risk of forfeiture to the same extent as the restricted unit with respect to which such common unit or other property has been distributed.

The committee will be authorized to grant common units that are not subject to restrictions. The committee may grant unit awards to any eligible person in such amounts as the committee, in its sole discretion, may select.

Phantom units are rights to receive common units, cash or a combination of both at the end of a specified period. The committee may subject phantom units to restrictions (which may include a risk of forfeiture) to be specified in the phantom unit agreement that may lapse at such times determined by the committee. Phantom units may be satisfied by delivery of common units, cash equal to the fair market value of the specified number of common units covered by the phantom unit or any combination thereof determined by the committee. Except as otherwise provided by the committee in the phantom unit agreement or otherwise, phantom units subject to forfeiture restrictions may be forfeited upon termination of a participant's employment prior to the end of the specified period. Cash distribution equivalents may be paid during or after the vesting period with respect to a phantom unit, as determined by the committee.

The committee will be able to grant distribution equivalent rights in tandem with awards under the LTIP (other than unit awards or an award of restricted units), or distribution equivalent rights may be granted alone. Distribution equivalent rights entitle the participant to receive cash equal to the amount of any cash distributions made by us during the period the distribution equivalent right is outstanding. Payment of cash distributions pursuant to a distribution equivalent right issued in connection with another award may be subject to the same vesting terms as the award to which it relates or different vesting terms, in the discretion of the committee.

The LTIP will permit the grant of awards denominated in and settled in cash. Cash awards may be based, in whole or in part, on the value or performance of a common unit.

The committee may condition the right to exercise or receive an award under the LTIP, or may increase or decrease the amount payable with respect to an award, based on the attainment of one or more performance conditions deemed appropriate by the committee.

The LTIP will permit the grant of other unit-based awards, which are awards that may be based, in whole or in part, on the value or performance of a common unit or are denominated or payable in common units. Upon settlement, these other unit-based awards may be paid in common units, cash or a combination thereof, as provided in the award agreement.

The LTIP will permit the grant of awards in substitution for similar awards held by individuals who become employees, consultants or directors as a result of a merger, consolidation, or acquisition, by us or an affiliate, of another entity or the assets of another entity. Such substitute awards that are unit options or unit appreciation rights may have exercise prices less than 100% of the fair market value per common unit on the date of the substitution if such substitution complies with Section 409A of the Code and its regulations and other applicable laws and exchange rules.

At our discretion, and subject to conditions that the committee may impose, a participant's minimum statutory tax withholding with respect to an award may be satisfied by withholding from any payment related to an award or by the withholding of common units issuable pursuant to the award based on the fair market value of the common units.

If any "equity restructuring" event occurs that could result in an additional compensation expense under the applicable accounting guidance for stock-based compensation if adjustments to awards with respect to such event were discretionary, the committee will equitably adjust the number and type of units covered by each outstanding award and the terms and conditions of each such award to equitably reflect the restructuring event. With respect to a similar event that would not result in an accounting charge if adjustment to awards were discretionary, the committee shall have complete discretion to adjust awards in the manner it deems appropriate. In the event the committee makes any adjustment in accordance with the foregoing provisions, a corresponding and proportionate adjustment shall be made with respect to the maximum number of units available under the LTIP and the kind of units or other securities available for grant under the LTIP. Furthermore, in the case of (i) a subdivision or consolidation of the common units (by reclassification, split or reverse split or otherwise), (ii) a recapitalization, reclassification, or other change in our capital structure or (iii) any other reorganization, merger, combination, exchange, or other relevant change in capitalization of our equity, then a corresponding and proportionate adjustment shall be made in accordance with the terms of the LTIP, as appropriate, with respect to the maximum number of units available under the LTIP, the number of units that may be acquired with respect to an award, and, if applicable, the exercise price of an award, in order to prevent dilution or enlargement of awards as a result of such events.

Upon a "change in control" (as defined in the LTIP), the committee may, in its discretion, (i) remove any forfeiture restrictions applicable to an award, (ii) accelerate the time of exercisability or vesting of an award, (iii) require awards to be surrendered in exchange for a cash payment, (iv) cancel unvested awards without payment or (v) make adjustments to awards as the committee deems appropriate to reflect the change in control.

The consequences of the termination of a participant's employment, consulting arrangement or membership on the board of directors will be determined by the committee in the terms of the relevant award agreement.

We and our general partner were formed in January 2015 and, as such, have not accrued or paid any obligations with respect to compensation for directors for any periods prior to our formation date or the date of this offering.

The executive officers or employees of our sponsor who also serve as directors of our general partner will not receive additional compensation for their service as a director of our general partner. Directors of our general partner who are not executive officers or employees of our sponsor will receive compensation as "non-employee directors" as set by our general partner's board of directors.

Effective as of the closing of this offering, each non-employee director will receive a compensation package that will consist of an annual cash retainer of $ . In addition, our directors will be reimbursed for out-of-pocket expenses in connection with attending meetings of the board of directors or its committees. Each non-employee director may receive grants of equity-based awards under the LTIP we intend to adopt prior to the completion of this offering from time to time for so long as he or she serves as a director.

Each member of the board of directors of our general partner will be indemnified for his actions associated with being a director to the fullest extent permitted under Delaware law.

The following table sets forth the beneficial ownership of common units and subordinated units of Bowie Resource Partners LP that will be issued and outstanding upon the consummation of this offering and the related transactions and held by:

Unless otherwise noted, the address for each beneficial owner listed below is 6100 Dutchmans Lane, 9th Floor, Louisville, Kentucky 40205.

Name of Beneficial Owner

Bowie GP, LLC	—	—		—	—		—
Bowie Resource Holdings, LLC(1)(2)			%		100	%		%
John J. Siegel			%	—	—			%
Johannes H. Dreyer			%	—	—			%
Eugene E. DiClaudio			%	—	—			%
James J. Wolff			%	—	—			%
Grant S. Quasha			%	—	—			%
Brian S. Settles			%	—	—			%
John DeRosa			%	—	—			%
Jesus Fernandez			%	—	—			%
Carlos Pons			%	—	—			%
Steve Rickmeier			%	—	—			%
			%	—	—			%
All directors and executive officers as a group ( persons)			%	—	—			%

After this offering, assuming that the underwriters do not exercise their option to purchase additional common units, our sponsor will own, directly or indirectly, common units and subordinated units, representing an aggregate of approximately % limited partner interest in us (excluding the incentive distribution rights, which cannot be expressed as a fixed percentage), and will own and control our general partner. Our sponsor will also appoint all of the directors of our general partner, which will own a non-economic general partner interest in us and will own the incentive distribution rights.

The terms of the transactions and agreements disclosed in this section were determined by and among affiliated entities and, consequently, are not the result of arm's-length negotiations. These terms are not necessarily at least as favorable to the parties to these transactions and agreements as the terms that could have been obtained from unaffiliated third parties.

The following table summarizes the distributions and payments to be made by us to our general partner and its affiliates in connection with the formation, ongoing operation and any liquidation of Bowie Resource Partners LP.


The aggregate consideration received by our general partner and its affiliates for the contribution of their interests		common units, subordinated units and all of our incentive distribution rights; and
		$ million of net proceeds from this offering and our offering of the New Notes to our sponsor, in part as reimbursement for capital expenditures.
		Any net proceeds received from the exercise of the underwriters' option to purchase additional common units will be used to make a distribution to our sponsor, in part 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 additional consideration at the expiration of the option period.
*Operational Stage*
Distributions of cash available for distribution to our general partner and its affiliates		We will generally make cash distributions 100% to our unitholders, including affiliates of our general partner. In addition, if distributions exceed the minimum quarterly distribution and other higher target distribution levels, our general partner will be entitled to increasing percentages of the distributions, up to 50.0% of the distributions above the highest target distribution level.
		Assuming we have sufficient cash available for distribution to pay the full minimum quarterly distribution on all of our outstanding common units and subordinated units for four quarters, our general partner and its affiliates would receive an annual distribution of approximately $ million on their units.


Payments to our general partner and its affiliates		Our general partner will not receive a management fee or other compensation for its management of our partnership, but we will reimburse our general partner and its affiliates for all direct and indirect expenses they incur and payments they make on our behalf. Our partnership agreement does not set a limit on the amount of expenses for which our general partner and its affiliates 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. Additionally, in connection with this offering, we 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. 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.
Withdrawal or removal of our general partner		If our general partner withdraws or is removed, its non-economic general partner interest and its incentive distribution rights will either be sold to the new general partner for cash or converted into common units, in each case for an amount equal to the fair market value of those interests. Please read "The Partnership Agreement—Withdrawal or Removal of Our General Partner."
*Liquidation Stage*
Liquidation		Upon our liquidation, the partners, including our general partner, will be entitled to receive liquidating distributions according to their respective capital account balances.

In connection with the closing of this offering, we expect to enter into certain agreements with our sponsor, as described in more detail below.

We expect to enter into a contribution agreement that will effect the contribution by our sponsor of the ownership interests in our operating company and its subsidiaries, including CFC, to us, and the use of the net proceeds of this offering and our offering of the New Notes. Please read "—Distributions and Payments to Our General Partner and Its Affiliate—Formation Stage" for the aggregate consideration to be received by our sponsor for the contribution of its interests. While we believe this agreement is on terms no less favorable to any party than those that could have been negotiated with an unaffiliated third party, it will not be the result of arm's-length negotiations. All of the transaction expenses incurred in connection with these transactions will be paid from the proceeds of this offering and our offering of the New Notes.

We expect to enter into a registration rights agreement with our sponsor pursuant to which we may be required to register the sale of the (i) common units issued (or issuable) to our sponsor pursuant to the contribution agreement, (ii) subordinated units and (iii) common units issuable upon conversion of

the subordinated units pursuant to the terms of the partnership agreement (together, the "Registrable Securities") it holds. Under the registration rights agreement, our sponsor will have the right to request that we register the sale of Registrable Securities held by it, and our sponsor will have the right to require us to make available shelf registration statements permitting sales of Registrable Securities into the market from time to time over an extended period, subject to certain limitations. 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. In addition, the registration rights agreement gives our sponsor piggyback registration rights under certain circumstances. The registration rights agreement also includes provisions dealing with indemnification and contribution and allocation of expenses. All of the Registrable Securities held by our sponsor and any permitted transferee will be entitled to these registration rights.

In connection with the closing of this offering, we will enter into an omnibus agreement with our sponsor and our general partner that will address certain aspects of our relationship with them, including:

The omnibus agreement can be amended by written agreement of all parties to the agreement. However, the partnership may not agree to any amendment or modification that would, in the reasonable discretion of our general partner, be adverse in any material respect to the holders of our common units without prior approval of the conflicts committee. So long as our sponsor controls our general partner, the omnibus agreement will remain in full force and effect unless mutually terminated by the parties. If our sponsor ceases to control our general partner, the omnibus agreement will terminate, provided (i) the indemnification obligations described above and (ii) our non-exclusive right to use all of our sponsor's technology will remain in full force and effect in accordance with their terms.

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. Pursuant to the coal supply agreement, our sponsor will purchase our coal, in the quantities and of the quality and from the mines specified in our sponsor's agreements with our end customers, and will sell our coal to the end customers under each such agreement between our sponsor and our end customers. Our sponsor will pay us the contracted price it receives from end customers of our coal, less certain fees and expenses.

Pursuant to the coal supply agreement, we will deliver coal to our sponsor FOB mine. To the extent that our sponsor has discretion in determining the source, quantity and delivery timing under any agreement with an end customer, we will have the right to direct our sponsor's exercise of such discretion. Our sponsor will agree to satisfy its obligations to supply coal to end customers first using coal purchased from us pursuant to the coal supply agreement, to the extent our coal meets the quality, quantity and location specifications under our sponsor's agreements with end customers.

The coal supply agreement will become effective upon the closing of this offering and will terminate upon the first to occur of (i) mutual agreement of the parties to terminate the agreement, (ii) the date on which all of the applicable coal supply agreements between our sponsor and end customers have been assigned to us, (iii) the date on which all of our sponsor's obligations under the applicable coal supply agreements between our sponsor and end customers have terminated, (iv) our acquisition from our sponsor of our sponsor's wholly owned subsidiary, Bowie Coal Sales, LLC or (v) termination by us or our sponsor in the event of a breach of a material provision of the agreement by our sponsor or us, respectively.

Trafigura BV owns Galena Asset Management, which manages Galena. Galena owns a 46% interest in our sponsor. Trafigura BV also owns Trafigura AG, which is the exclusive marketer of our uncommitted coal pursuant to a Coal Services Agreement. Pursuant to the Coal Services Agreement, Trafigura AG is the exclusive provider of certain sales, marketing, administrative and other services to us and our sponsor for the production life of our reserves. We and our sponsor pay Trafigura AG a sales fee equal to a percentage of the price paid per ton (FOB mine) delivered under the Coal Services Agreement, provided that the sales fee may be increased for export sales of coal above certain price per ton thresholds. Trafigura AG has the right to terminate the Coal Services Agreement upon 180 days' notice. We and our sponsor have a right to terminate the Coal Services Agreement with respect to any mine only upon a sale of such mine to a third party. For the year ended December 31, 2014, our sponsor paid Trafigura AG approximately $3.6 million pursuant to the Coal Services Agreement.

Upon the closing of this offering, we expect to terminate the existing Coal Services Agreement among CFC, our sponsor and Trafigura AG and to enter into a new Coal Services Agreement among

our operating company and its subsidiaries, our sponsor and Trafigura AG, with substantially the same terms and conditions as the existing Coal Services Agreement.

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. The agreement can be amended by written agreement of all parties to the agreement. However, the partnership may not agree to any amendment or modification that would, in the reasonable discretion of our general partner, be adverse in any material respect to the holders of our common units without prior approval of the conflicts committee. So long as our sponsor controls our general partner, the agreement will remain in full force and effect unless mutually terminated by the parties. If our sponsor ceases to control our general partner, the agreement will terminate.

Messrs. Siegel and Rickmeier directly or indirectly own or control Cedars, which has a 54% ownership interest in our sponsor. We expect that Cedars 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. In addition, certain executive officers of our general partner hold non-voting profits interests in our sponsor that entitle them to share in distributions by our sponsor above specified levels. It is not anticipated that the specified ceiling amount with respect to such interests will be attained in connection with this offering. However, pursuant to sponsor-level bonus arrangements, we expect Messrs. Dreyer, DiClaudio, Wolff, Quasha and Settles will receive an aggregate of $ million (or $ million if the underwriters exercise their option to purchase additional units) in connection with the cash distribution by our sponsor of a portion of the net proceeds from this offering.

Procedures for Review, Approval and Ratification of Transactions with Related Persons

We expect that the board of directors of our general partner will adopt policies for the review, approval and ratification of transactions with related persons. We anticipate the board will adopt a written code of business conduct and ethics, under which a director would be expected to bring to the attention of the chief executive officer or the board any conflict or potential conflict of interest that may arise between the director or any affiliate of the director, on the one hand, and us or our general partner on the other. The resolution of any such conflict or potential conflict should, at the discretion of the board in light of the circumstances, be determined by a majority of the disinterested directors.

If a conflict or potential conflict of interest arises between our general partner or its affiliates, on the one hand, and us or our unitholders, on the other hand, the resolution of any such conflict or potential conflict should be addressed by the board of directors of our general partner in accordance with the provisions of our partnership agreement. At the discretion of the board in light of the circumstances, the resolution may be determined by the board in its entirety or by a conflicts committee meeting the definitional requirements for such a committee under our partnership agreement.

Upon our adoption of our code of business conduct, we would expect that any executive officer will be required to avoid conflicts of interest unless approved by the board of directors of our general partner.

Please read "Conflicts of Interest and Fiduciary Duties—Conflicts of Interest" for additional information regarding the relevant provisions of our partnership agreement.

The code of business conduct and ethics described above will be adopted in connection with the closing of this offering, and as a result, the transactions described above were not reviewed according to such procedures.

The Delaware Revised Uniform Limited Partnership Act, which we refer to as the Delaware Act, provides that Delaware limited partnerships may, in their partnership agreements, expand, restrict or eliminate the fiduciary duties otherwise owed by the general partner to the limited partners and the partnership. 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. Our partnership agreement also specifically defines the remedies available to unitholders for actions taken that, without these defined liability standards, might constitute breaches of fiduciary duty under applicable Delaware law.

When our general partner is acting in its capacity as our general partner, as opposed to in its individual capacity, it must act in "good faith," meaning it must act in a manner that it believes is not adverse to our interest. This duty to act in good faith is the default standard set forth under our partnership agreement and our general partner will not be subject to any higher standard.

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

When the directors and officers of our general partner cause our general partner to manage and operate our business, the directors and officers must cause our general partner to act in a manner consistent with our general partner's applicable duties. However, the directors and officers of our general partner have fiduciary duties to manage our general partner, including when it is acting in its capacity as our general partner, in a manner beneficial to our sponsor.

Conflicts may arise as a result of the duties of our general partner and its directors and officers to act for the benefit of its owners, which may conflict with our interests and the interests of our public unitholders. Where the directors and officers of our general partner are causing our general partner to act in its capacity as our general partner, the directors and officers must cause the general partner to act in good faith, meaning they cannot cause the general partner to take an action that they believe is adverse to our interest. However, where a decision by our general partner in its capacity as our general partner is not clearly not adverse to our interest, the directors of our general partner may determine to submit the determination to the conflicts committee for review or to seek approval by the unitholders, as described below.

Conflicts of interest exist and may arise in the future as a result of the relationships between our general partner and its directors, officers and owners (including our sponsor) on the one hand, and us and our limited partners, on the other hand.

Whenever a conflict arises between our general partner or its owners, on the one hand, and us or our limited partners, on the other hand, the resolution, course of action or transaction in respect of such conflict of interest shall be conclusively deemed approved by us and all our limited partners and shall not constitute a breach of our partnership agreement, of any agreement contemplated thereby or of any duty, if the resolution, course of action or transaction in respect of such conflict of interest is:

Our general partner may, but is not required to, seek the approval of such resolutions or courses of action from the conflicts committee of its board of directors or from the holders of a majority of the outstanding common units as described above. If our general partner does not seek approval from the conflicts committee or from holders of common units as described above and the board of directors of our general partner approves the resolution or course of action taken with respect to the conflict of interest, then it will be presumed that, in making its decision, the board of directors of our general partner acted in good faith, and in any proceeding brought by or on behalf of us or any of our unitholders, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption and proving that such decision was not in good faith. Unless the resolution of a conflict is specifically provided for in our partnership agreement, the board of directors of our general partner or the conflicts committee of the board of directors of our general partner may consider any factors they determine in good faith to consider when resolving a conflict. An independent third party is not required to evaluate the resolution. Under our partnership agreement, all determinations, other actions or failures to act by our general partner, the board of directors of our general partner or any committee thereof (including the conflicts committee) will be presumed to be "in good faith" and in any proceeding brought by or on behalf of us or any of our unitholders, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption and proving that such decision was not in good faith. Please read "Management—Committees of the Board of Directors—Conflicts Committee" for information about the conflicts committee of our general partner's board of directors.

Conflicts of interest could arise in the situations described below, among others:

The amount of cash that is available for distribution to unitholders is affected by decisions of our general partner regarding such matters as:

In addition, borrowings by us and our affiliates do not constitute a breach of any duty owed by our general partner to our unitholders, including borrowings that have the purpose or effect of:

In addition, our general partner may use an amount, initially equal to $ million, which would not otherwise constitute operating surplus, in order to permit the payment of distributions on subordinated units and the incentive distribution rights. All of these actions may affect the amount of cash distributed to our unitholders and our general partner and may facilitate the conversion of subordinated units into common units. Please read "How We Make Distributions To Our Partners."

For example, in the event we have not generated sufficient cash from our operations to pay the minimum quarterly distribution on our common units and our subordinated units, our partnership agreement permits us to borrow funds, which would enable us to make such distribution on all outstanding units. Please read "How We Make Distributions To Our Partners—Operating Surplus and Capital Surplus—Operating Surplus."

The officers and certain directors of our general partner have fiduciary duties to our sponsor that may cause them to pursue business strategies that disproportionately benefit our sponsor or which otherwise are not in our best interests.

Our partnership agreement contains provisions that replace the standards to which our general partner would otherwise be held by state fiduciary duty law. For example, our partnership agreement permits our general partner to make a number of decisions in its individual capacity, as opposed to in its capacity as our general partner. This entitles our general partner to consider only the interests and factors that it desires, and it has no duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates or any limited partner. Examples include the exercise of its call right, its voting rights with respect to any units it owns, its registration rights and its determination whether or not to consent to any merger or consolidation or amendment of the partnership agreement.

In addition to the provisions described above, our partnership agreement contains provisions that restrict the remedies available to our unitholders for actions that might otherwise constitute breaches of fiduciary duty. For example, our partnership agreement provides that:

By purchasing a common unit, the purchaser agrees to be bound by the provisions in our partnership agreement, including the provisions discussed above. Please read "—Fiduciary Duties."

Any agreements between us, on the one hand, and our general partner and its affiliates, on the other, will not grant to the unitholders, separate and apart from us, the right to enforce the obligations of our general partner and its affiliates in our favor.

Neither our partnership agreement nor any of the other agreements, contracts and arrangements between us and our general partner and its affiliates are or will be the result of arm's-length negotiations. Our general partner will determine, in good faith, the terms of any of such future transactions.

Under our partnership agreement, our general partner has full power and authority to do all things, other than those items that require unitholder approval, necessary or appropriate to conduct our business, including the following actions:

Please read "The Partnership Agreement—Voting Rights" for information regarding the voting rights of unitholders.

The attorneys, independent accountants and others who perform services for us have been retained by our general partner. Attorneys, independent accountants and others who perform services for us are selected by our general partner or the conflicts committee of the board of directors of our general partner and may perform services for our general partner and its affiliates. We may retain separate counsel for ourselves or the conflict committee in the event of a conflict of interest between our general partner and its affiliates, on the one hand, and us or the holders of common units, on the other, depending on the nature of the conflict, although we may choose not to do so.

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.

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, the reset minimum quarterly distribution will be calculated and the target distribution levels will be reset to correspondingly higher levels based on percentage increases above the reset minimum quarterly distribution.

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 a 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."

Duties owed to unitholders by our general partner are prescribed by law and in our partnership agreement. The Delaware Act provides that Delaware limited partnerships may, in their partnership agreements, expand, restrict or eliminate the fiduciary duties otherwise owed by the general partner to limited partners and the partnership.

Our partnership agreement contains various provisions that eliminate and replace the fiduciary duties that might otherwise be owed by our general partner. We have adopted these provisions to allow our general partner or its affiliates to engage in transactions with us that otherwise might be prohibited by state law fiduciary standards and to take into account the interests of other parties in addition to our interests when resolving conflicts of interest. We believe this is appropriate and necessary because the board of directors of our general partner has a duty to manage our partnership in good faith and a duty to manage our general partner in a manner beneficial to its owner. Without these modifications, our general partner's ability to make decisions involving conflicts of interest would be restricted. Replacing the fiduciary duty standards in this manner benefits our general partner by enabling it to take into consideration all parties involved in the proposed action. Replacing the fiduciary duty standards also strengthens the ability of our general partner to attract and retain experienced and capable directors. Replacing the fiduciary duty standards represents a detriment to our public unitholders because it restricts the remedies available to our public unitholders for actions that, without those limitations, might constitute breaches of fiduciary duty, as described below, and permits our general partner to take into account the interests of third parties in addition to our interests when resolving conflicts of interests.

The following is a summary of the fiduciary duties imposed on general partners of a limited partnership by the Delaware Act in the absence of partnership agreement provisions to the contrary, the contractual duties of our general partner contained in our partnership agreement that replace the

fiduciary duties that would otherwise be imposed by Delaware laws on our general partner and the rights and remedies of our unitholders with respect to these contractual duties:


State law fiduciary duty standards		Fiduciary duties are generally considered to include an obligation to act in good faith and with due care and loyalty. The duty of care, in the absence of a provision in a partnership agreement providing otherwise, would generally require a general partner to act for the partnership in the same manner as a prudent person would act on his own behalf. The duty of loyalty, in the absence of a provision in a partnership agreement providing otherwise, would generally require that any action taken or transaction engaged in be entirely fair to the partnership.
Partnership agreement modified standards		Our partnership agreement contains provisions that waive or consent to conduct by our general partner and its affiliates that might otherwise raise issues as to compliance with fiduciary duties or applicable law. For example, our partnership agreement provides that when our general partner is acting in its capacity as our general partner, as opposed to in its individual capacity, it must act in "good faith" meaning that it believed its actions or omissions were not adverse to the interest of the partnership, and will not be subject to any higher standard under applicable law. In addition, when our general partner is acting in its individual capacity, as opposed to in its capacity as our general partner, it may act without any fiduciary obligation to us or the unitholders whatsoever. These contractual standards replace the obligations to which our general partner would otherwise be held.
		In making decisions, other than one where our general partner is permitted to act in its sole discretion, it will be presumed that in making its decision our general partner, the board of directors of our general partner or the conflicts committee of the board of directors of our general partner acted in good faith, and in any proceeding brought by or on behalf of any limited partner or us, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption and proving that such decision was not in good faith.

By purchasing our common units, the purchaser agrees to be bound by the provisions in our partnership agreement, including the provisions discussed above. This is in accordance with the policy of the Delaware Act favoring the principle of freedom of contract and the enforceability of partnership agreements. The failure of a limited partner to sign a partnership agreement does not render the partnership agreement unenforceable against that person.

Under our partnership agreement, we must indemnify our general partner and its officers, directors, managers and certain other specified persons, to the fullest extent permitted by law, against liabilities, costs and expenses incurred by our general partner or these other persons. We must provide this indemnification unless there has been a final and non-appealable judgment by a court of competent jurisdiction determining that such losses or liabilities were the result of the conduct of our general partner or such officer or director engaged in by it in bad faith or, with respect to any criminal conduct, with the knowledge that its conduct was unlawful. Thus, our general partner could be indemnified for its negligent acts if it meets the requirements set forth above. To the extent these provisions purport to include indemnification for liabilities arising under the Securities Act in the opinion of the SEC, such indemnification is contrary to public policy and, therefore, unenforceable. Please read "The Partnership Agreement—Indemnification."

The common units and the subordinated units are separate classes of limited partner interests in us. The holders of units are entitled to participate in partnership distributions and exercise the rights or privileges available to limited partners under our partnership agreement. For a description of the relative rights and preferences of holders of common units and subordinated units in and to partnership distributions, please read this section and "How We Make Distributions To Our Partners." For a description of other rights and privileges of limited partners under our partnership agreement, including voting rights, please read "The Partnership Agreement."

In order to comply with certain U.S. laws relating to the ownership of interests in mineral leases on federal lands, we have adopted requirements regarding our owners. Our partnership agreement requires that a transferee of common units properly complete and deliver to us a transfer application containing a certification as to a number of matters, including the status of the transferee, or all its owners, as being an Eligible Holder (as defined below under "—Transfer of Common Units"). 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 that 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 "—Transfer of Common Units" below and "The Partnership Agreement—Non-Eligible Holders; Redemption."

American Stock Transfer & Trust Company, LLC will serve as the registrar and transfer agent for the common units. We will pay all fees charged by the transfer agent for transfers of common units except the following, which must be paid by our unitholders:

There will be no charge to our unitholders for disbursements of our cash distributions. We will indemnify the transfer agent, its agents and each of their stockholders, directors, officers and employees against all claims and losses that may arise out of acts performed or omitted for its activities in that capacity, except for any liability due to any gross negligence or intentional misconduct of the indemnified person or entity.

The transfer agent may resign, by notice to us, or be removed by us. The resignation or removal of the transfer agent will become effective upon our appointment of a successor transfer agent and registrar and its acceptance of the appointment. If no successor is appointed or has not accepted its appointment within 30 days of the resignation or removal, our general partner may act as the transfer agent and registrar until a successor is appointed.

Upon the transfer of a common unit in accordance with our partnership agreement, the transferee of the common unit shall be admitted as a limited partner with respect to the common units transferred when such transfer and admission are reflected in our books and records. Each transferee:

As used in this prospectus, an Eligible Holder means a person or entity qualified to hold an interest in mineral leases on federal lands. As of the date hereof, an 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 U.S. 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 such 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 U.S. federal government regards as denying similar privileges to citizens or corporations of the United States.

Our general partner will cause any transfers to be recorded on our books and records from time to time (or shall cause the transfer agent to do so, as applicable).

We may, at our discretion, treat the nominee holder of a common unit as the absolute owner. In that case, the beneficial holder's rights are limited solely to those that it has against the nominee holder as a result of any agreement between the beneficial owner and the nominee holder.

Common units are securities and any transfers are subject to the laws governing the transfer of securities. In addition to other rights acquired upon transfer, the transferor gives the transferee the right to become a substituted limited partner in our partnership for the transferred common units.

Until a common unit has been transferred on our books, we and the transfer agent may treat the record holder of the common unit as the absolute owner for all purposes, except as otherwise required by law or stock exchange regulations.

We intend to apply to list our common units on the NYSE under the symbol "BRLP."

The following is a summary of the material provisions of our partnership agreement, which we will adopt in connection with the closing of this offering. The form of our partnership agreement is included in this prospectus as Appendix A. We will provide investors and prospective investors with a copy of our partnership agreement, when available, upon request at no charge.

We summarize the following provisions of our partnership agreement elsewhere in this prospectus:

We were organized in January 2015 and will have a perpetual existence unless terminated pursuant to the terms of our partnership agreement.

Our purpose, as set forth in our partnership agreement, is limited to any business activity that is approved by our general partner and that lawfully may be conducted by a limited partnership organized under Delaware law; provided that our general partner shall not cause us to take any action that the general partner determines would be reasonably likely to cause us to be treated as an association taxable as a corporation or otherwise taxable as an entity for federal income tax purposes.

Although our general partner has the ability to cause us and our subsidiaries to engage in activities other than the business of mining and transporting coal, our general partner may decline to do so in its sole discretion. Our general partner is generally authorized to perform all acts it determines to be necessary or appropriate to carry out our purposes and to conduct our business.

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.

Our partnership agreement specifies the manner in which we will make cash distributions to holders of our common units and other partnership securities, as well as to our general partner in respect of its incentive distribution rights. For a description of these cash distribution provisions, please read "How We Make Distributions To Our Partners."

Unitholders are not obligated to make additional capital contributions, except as described below under "—Limited Liability."

The following is a summary of the unitholder vote required for approval of the matters specified below. Matters that call for the approval of a "unit majority" require:

In voting their common and subordinated units, our general partner and its affiliates will have no duty or obligation whatsoever to us or the limited partners, including any duty to act in the best interests of us or the limited partners.

The incentive distribution rights may be entitled to vote in certain circumstances.


Issuance of additional units		No approval right.
Amendment of the partnership agreement		Certain amendments may be made by our general partner without the approval of the unitholders. Other amendments generally require the approval of a unit majority. Please read "—Amendment of the Partnership Agreement."
Merger of our partnership or the sale of all or substantially all of our assets		Unit majority in certain circumstances. Please read "—Merger, Consolidation, Conversion, Sale or Other Disposition of Assets."
Dissolution of our partnership		Unit majority. Please read "—Dissolution."
Continuation of our business upon dissolution		Unit majority. Please read "—Dissolution."
Withdrawal of our general partner		Under most circumstances, the approval of a majority of the common units, excluding common units held by our general partner and its affiliates, is required for the withdrawal of our general partner prior to , 2025 in a manner that would cause a dissolution of our partnership. Please read "—Withdrawal or Removal of Our General Partner."
Removal of our general partner		Not less than 66²/3% of the outstanding units, voting as a single class, including units held by our general partner and its affiliates. 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. Please read "—Withdrawal or Removal of Our General Partner."
Transfer of our general partner interest		No approval right. Please read "—Transfer of General Partner Interest."

If any person or group other than our general partner and its affiliates acquires beneficial ownership of 20% or more of any class of units, that person or group loses voting rights on all of its units. This loss of voting rights does not apply to any person or group that acquires the units from our general partner or its affiliates and any transferees of that person or group approved by our general partner or to any person or group who acquires the units with the specific prior approval of our general partner.

Our partnership agreement is governed by Delaware law. Our partnership agreement requires that any claims, suits, actions or proceedings:

shall be exclusively brought in the Court of Chancery of the State of Delaware, (or, if such court does not have subject matter jurisdiction thereof, any other court located in the State of Delaware with subject matter jurisdiction), regardless of whether such claims, suits, actions or proceedings sound in contract, tort, fraud or otherwise, are based on common law, statutory, equitable, legal or other grounds, or are derivative or direct claims. By purchasing a common unit, a limited partner is irrevocably consenting to these limitations and provisions regarding claims, suits, actions or proceedings and submitting to the exclusive jurisdiction of the Court of Chancery of the State of Delaware (or such other court) in connection with any such claims, suits, actions or proceedings.

Assuming that a limited partner does not participate in the control of our business within the meaning of the Delaware Act and that he otherwise acts in conformity with the provisions of the partnership agreement, his liability under the Delaware Act will be limited, subject to possible exceptions, to the amount of capital he is obligated to contribute to us for his common units plus his share of any undistributed profits and assets. However, if it were determined that the right, or exercise of the right, by the limited partners as a group:

constituted "participation in the control" of our business for the purposes of the Delaware Act, then the limited partners could be held personally liable for our obligations under the laws of Delaware, to

the same extent as our general partner. This liability would extend to persons who transact business with us under the reasonable belief that the limited partner is a general partner. Neither our partnership agreement nor the Delaware Act specifically provides for legal recourse against our general partner if a limited partner were to lose limited liability through any fault of our general partner. While this does not mean that a limited partner could not seek legal recourse, we know of no precedent for this type of a claim in Delaware case law.

Under the Delaware Act, a limited partnership may not make a distribution to a partner if, after the distribution, all liabilities of the limited partnership, other than liabilities to partners on account of their partnership interests and liabilities for which the recourse of creditors is limited to specific property of the partnership, would exceed the fair value of the assets of the limited partnership. For the purpose of determining the fair value of the assets of a limited partnership, the Delaware Act provides that the fair value of property subject to liability for which recourse of creditors is limited shall be included in the assets of the limited partnership only to the extent that the fair value of that property exceeds the nonrecourse liability. The Delaware Act provides that a limited partner who receives a distribution and knew at the time of the distribution that the distribution was in violation of the Delaware Act shall be liable to the limited partnership for the amount of the distribution for three years.

Following the completion of this offering, we expect that our subsidiaries will conduct business in Utah, Kentucky and Colorado and we may have subsidiaries that conduct business in other states or countries in the future. Maintenance of our limited liability as owner of our operating subsidiaries may require compliance with legal requirements in the jurisdictions in which the operating subsidiaries conduct business, including qualifying our subsidiaries to do business there.

Limitations on the liability of members or limited partners for the obligations of a limited liability company or limited partnership have not been clearly established in many jurisdictions. If, by virtue of our ownership interest in our subsidiaries or otherwise, it were determined that we were conducting business in any jurisdiction without compliance with the applicable limited partnership or limited liability company statute, or that the right or exercise of the right by the limited partners as a group to remove or replace our general partner, to approve some amendments to our partnership agreement, or to take other action under our partnership agreement constituted "participation in the control" of our business for purposes of the statutes of any relevant jurisdiction, then the limited partners could be held personally liable for our obligations under the law of that jurisdiction to the same extent as our general partner under the circumstances. We will operate in a manner that our general partner considers reasonable and necessary or appropriate to preserve the limited liability of the limited partners.

Our partnership agreement authorizes us to issue an unlimited number of additional partnership interests for the consideration and on the terms and conditions determined by our general partner without the approval of the unitholders.

It is possible that we will fund acquisitions through the issuance of additional common units, subordinated units or other partnership interests. Holders of any additional common units we issue will be entitled to share equally with the then-existing common unitholders in our distributions. In addition, the issuance of additional common units or other partnership interests may dilute the value of the interests of the then-existing common unitholders in our net assets.

In accordance with Delaware law and the provisions of our partnership agreement, we may also issue additional partnership interests that, as determined by our general partner, may have rights to distributions or special voting rights to which the common units are not entitled. In addition, our partnership agreement does not prohibit our subsidiaries from issuing equity interests, which may effectively rank senior to the common units.

Our general partner will have the right, which it may from time to time assign in whole or in part to any of its affiliates, to purchase common units, subordinated units or other partnership interests whenever, and on the same terms that, we issue partnership interests to persons other than our general partner and its affiliates, to the extent necessary to maintain the percentage interest of our general partner and its affiliates, including such interest represented by common and subordinated units, that existed immediately prior to each issuance. The common unitholders will not have preemptive rights under our partnership agreement to acquire additional common units or other partnership interests.

Amendments to our partnership agreement may be proposed only by our general partner. However, our general partner will have no duty or obligation to propose any amendment and may decline to do so free of any duty or obligation whatsoever to us or the limited partners, including any duty to act in the best interests of us or the limited partners. In order to adopt a proposed amendment, other than the amendments described below, our general partner is required to seek written approval of the holders of the number of units required to approve the amendment or to call a meeting of the limited partners to consider and vote upon the proposed amendment. Except as described below, an amendment must be approved by a unit majority.

The provision of our partnership agreement preventing the amendments having the effects described in the clauses above can be amended upon the approval of the holders of at least 90.0% of the outstanding units, voting as a single class (including units owned by our general partner and its affiliates). Upon completion of the offering, an affiliate of our general partner will own approximately % of our outstanding common and subordinated units.

Our general partner may generally make amendments to our partnership agreement without the approval of any limited partner to reflect:

In addition, our general partner may make amendments to our partnership agreement, without the approval of any limited partner, if our general partner determines that those amendments:

Any amendment that our general partner determines adversely affects in any material respect one or more particular classes of limited partners, and is not permitted to be adopted by our general partner without limited partner approval, will require the approval of at least a majority of the class or classes so affected, but no vote will be required by any class or classes of limited partners that our general partner determines are not adversely affected in any material respect. Any such amendment that would have a material adverse effect on the rights or preferences of any type or class of outstanding units in relation to other classes of units will require the approval of at least a majority of the type or class of units so affected. Any such amendment that would reduce the voting percentage required to take any action other than to remove the general partner or call a meeting of unitholders is required to be approved by the affirmative vote of limited partners whose aggregate outstanding units constitute not less than the voting requirement sought to be reduced. Any such amendment that would increase the percentage of units required to remove the general partner or call a meeting of unitholders must be approved by the affirmative vote of limited partners whose aggregate outstanding units constitute not less than the percentage sought to be increased.

For amendments of the type not requiring unitholder approval, our general partner will not be required to obtain an opinion of counsel that an amendment will neither result in a loss of limited liability to the limited partners nor result in our being treated as a taxable entity for federal income tax purposes in connection with any of the amendments. No other amendments to our partnership agreement will become effective without the approval of holders of at least 90% of the outstanding units, voting as a single class, unless we first obtain an opinion of counsel to the effect that the amendment will not affect the limited liability under applicable law of any of our limited partners.

A merger, consolidation or conversion of us requires the prior consent of our general partner. However, our general partner will have no duty or obligation to consent to any merger, consolidation or conversion and may decline to do so free of any duty or obligation whatsoever to us or the limited partners, including any duty to act in the best interest of us or the limited partners.

In addition, our partnership agreement generally prohibits our general partner, without the prior approval of the holders of a unit majority, from causing us to sell, exchange or otherwise dispose of all or substantially all of our assets in a single transaction or a series of related transactions, including by way of merger, consolidation or other combination. Our general partner may, however, mortgage, pledge, hypothecate or grant a security interest in all or substantially all of our assets without such approval. Our general partner may also sell all or substantially all of our assets under a foreclosure or other realization upon those encumbrances without such approval. Finally, our general partner may consummate any merger without the prior approval of our unitholders if we are the surviving entity in the transaction, our general partner has received an opinion of counsel regarding limited liability and tax matters, the transaction would not result in a material amendment to the partnership agreement (other than an amendment that the general partner could adopt without the consent of other partners), each of our units will be an identical unit of our partnership following the transaction and the partnership interests to be issued do not exceed 20% of our outstanding partnership interests (other than incentive distribution rights) immediately prior to the transaction.

If the conditions specified in our partnership agreement are satisfied, our general partner may convert us or any of our subsidiaries into a new limited liability entity or merge us or any of our subsidiaries into, or convey all of our assets to, a newly formed entity, if the sole purpose of that conversion, merger or conveyance is to effect a mere change in our legal form into another limited liability entity, we have received an opinion of counsel regarding limited liability and tax matters and the governing instruments of the new entity provide the limited partners and our general partner with the same rights and obligations as contained in our partnership agreement. Our unitholders are not entitled to dissenters' rights of appraisal under our partnership agreement or applicable Delaware law in the event of a conversion, merger or consolidation, a sale of substantially all of our assets or any other similar transaction or event.

We will continue as a limited partnership until dissolved under our partnership agreement. We will dissolve upon:

Upon a dissolution under the last clause above, the holders of a unit majority may also elect, within specific time limitations, to continue our business on the same terms and conditions described in our partnership agreement by appointing as a successor general partner an entity approved by the holders of units representing a unit majority, subject to our receipt of an opinion of counsel to the effect that:

Upon our dissolution, unless our business is continued, the liquidator authorized to wind up our affairs will, acting with all of the powers of our general partner that are necessary or appropriate, liquidate our assets and apply the proceeds of the liquidation as described in "How We Make Distributions To Our Partners—Distributions of Cash Upon Liquidation." The liquidator may defer liquidation or distribution of our assets for a reasonable period of time or distribute assets to partners in kind if it determines that a sale would be impractical or would cause undue loss to our partners.

Except as described below, our general partner has agreed not to withdraw voluntarily as our general partner prior to , 2025 without obtaining the approval of the holders of at least a majority of the outstanding common units, excluding common units held by our general partner and its affiliates, and furnishing an opinion of counsel regarding limited liability and tax matters. On or after , 2025, our general partner may withdraw as general partner without first obtaining approval of any unitholder by giving 90 days' written notice, and that withdrawal will not constitute a violation of our partnership agreement. Notwithstanding the information above, our general partner may withdraw without unitholder approval upon 90 days' notice to the limited partners if at least 50% of the outstanding common units are held or controlled by one person and its affiliates, other than our general partner and its affiliates. In addition, our partnership agreement permits our general partner, in some instances, to sell or otherwise transfer all of its general partner interest in us without the approval of the unitholders. Please read "—Transfer of General Partner Interest."

Upon withdrawal of our general partner under any circumstances, other than as a result of a transfer by our general partner of all or a part of its general partner interest in us, the holders of a unit majority may select a successor to that withdrawing general partner. If a successor is not elected, or is elected but an opinion of counsel regarding limited liability and tax matters cannot be obtained, we will be dissolved, wound up and liquidated, unless within a specified period after that withdrawal, the holders of a unit majority agree in writing to continue our business and to appoint a successor general partner. Please read "—Dissolution."

Our general partner may not be removed unless that removal is approved by the vote of the holders of not less than 66²/3% of the outstanding units, voting together as a single class, including units held by our general partner and its affiliates, and we receive an opinion of counsel regarding limited liability and tax matters. Any removal of our general partner is also subject to the approval of a

successor general partner by the vote of the holders of a majority of the outstanding common units, voting as a class, and the outstanding subordinated units, voting as a class. The ownership of more than 33¹/3% of the outstanding units by our general partner and its affiliates gives them the ability to prevent our general partner's removal. At the closing of this offering, an affiliate of our general partner will own % of our outstanding limited partner units, including all of our subordinated units.

Our partnership agreement also provides that if our general partner is removed as our general partner under circumstances where cause does not exist:

In the event of the removal of our general partner under circumstances where cause exists or withdrawal of our general partner where that withdrawal violates our partnership agreement, a successor general partner will have the option to purchase the general partner interest and incentive distribution rights of the departing general partner and its affiliates for a cash payment equal to the fair market value of those interests. Under all other circumstances where our general partner withdraws or is removed by the limited partners, the departing general partner will have the option to require the successor general partner to purchase the general partner interest and the incentive distribution rights of the departing general partner and its affiliates for fair market value. In each case, this fair market value will be determined by agreement between the departing general partner and the successor general partner. If no agreement is reached, an independent investment banking firm or other independent expert selected by the departing general partner and the successor general partner will determine the fair market value. Or, if the departing general partner and the successor general partner cannot agree upon an expert, then an expert chosen by agreement of the experts selected by each of them will determine the fair market value.

If the option described above is not exercised by either the departing general partner or the successor general partner, the departing general partner's general partner interest and all its and its affiliates' incentive distribution rights will automatically convert into common units equal to the fair market value of those interests as determined by an investment banking firm or other independent expert selected in the manner described in the preceding paragraph.

In addition, we will be required to reimburse the departing general partner for all amounts due the departing general partner, including, without limitation, all employee-related liabilities, including severance liabilities, incurred as a result of the termination of any employees employed for our benefit by the departing general partner or its affiliates.

At any time, our general partner may transfer all or any of its general partner interest to another person without the approval of our common unitholders. As a condition of this transfer, the transferee must, among other things, assume the rights and duties of our general partner, agree to be bound by the provisions of our partnership agreement and furnish an opinion of counsel regarding limited liability and tax matters.

At any time, the owner of our general partner may sell or transfer all or part of its ownership interests in our general partner to an affiliate or third party without the approval of our unitholders.

By transfer of subordinated units or incentive distribution rights in accordance with our partnership agreement, each transferee of subordinated units or incentive distribution rights will be admitted as a limited partner with respect to the subordinated units or incentive distribution rights transferred when such transfer and admission is reflected in our books and records. Each transferee:

Our general partner will cause any transfers to be recorded on our books and records no less frequently than quarterly.

We may, at our discretion, treat the nominee holder of subordinated units or incentive distribution rights as the absolute owner. In that case, the beneficial holder's rights are limited solely to those that it has against the nominee holder as a result of any agreement between the beneficial owner and the nominee holder.

Subordinated units and incentive distribution rights are securities and any transfers are subject to the laws governing transfer of securities. In addition to other rights acquired upon transfer, the transferor gives the transferee the right to become a limited partner for the transferred subordinated units or incentive distribution rights.

Until a subordinated unit or incentive distribution right has been transferred on our books, we and the transfer agent may treat the record holder of the unit or right as the absolute owner for all purposes, except as otherwise required by law or stock exchange regulations.

Our partnership agreement contains specific provisions that are intended to discourage a person or group from attempting to remove Bowie GP, LLC as our general partner or from otherwise changing our management. Please read "—Withdrawal or Removal of Our General Partner" for a discussion of certain consequences of the removal of our general partner. If any person or group, other than our general partner and its affiliates, acquires beneficial ownership of 20% or more of any class of units, that person or group loses voting rights on all of its units. This loss of voting rights does not apply in certain circumstances. Please read "—Meetings; Voting."

If at any time our general partner and its affiliates own more than 80% of the then-issued and outstanding limited partner interests of any class, our general partner will have the right, which it may assign in whole or in part to any of its affiliates or to us, to acquire all, but not less than all, of the limited partner interests of the class held by unaffiliated persons, as of a record date to be selected by our general partner, on at least 10, but not more than 60, days' notice. The purchase price in the event of this purchase is the greater of:

As a result of our general partner's right to purchase outstanding limited partner interests, a holder of limited partner interests may have his limited partner interests purchased at an undesirable time or at a price that may be lower than market prices at various times prior to such purchase or lower than a unitholder may anticipate the market price to be in the future. The tax consequences to a unitholder of the exercise of this call right are the same as a sale by that unitholder of his common units in the market. Please read "Material U.S. Federal Income Tax Consequences—Disposition of Units."

To avoid any adverse effect on the maximum applicable rates chargeable to customers by us or any of our future subsidiaries, or in order to reverse an adverse determination that has occurred regarding such maximum rate, our partnership agreement provides our general partner the power to amend our partnership agreement. If our general partner, with the advice of counsel, determines that our not being treated as an association taxable as a corporation or otherwise taxable as an entity for federal income tax purposes, coupled with the tax status (or lack of proof thereof) of one or more of our limited partners (or their owners, to the extent relevant), has, or is reasonably likely to have, a material adverse effect on the maximum applicable rates chargeable to customers by our subsidiaries, then our general partner may adopt such amendments to our partnership agreement as it determines necessary or advisable to:

If our general partner, with the advice of counsel, determines we are subject to federal, state or local laws or regulations that, in the reasonable determination of our general partner, create a substantial risk of cancellation or forfeiture of any property that we have an interest in because of the nationality, citizenship or other related status of any limited partner (or its owners, to the extent relevant), then our general partner may adopt such amendments to our partnership agreement as it determines necessary or advisable to:

To comply with certain U.S. laws relating to the ownership of interests in mineral leases on federal lands, common unit 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 common unitholder to re-certify that the common 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. 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 such 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. This certification can be changed in any manner our general partner determines is necessary or appropriate to implement its original purpose.

then, as the case may be, such transfer will, to the fullest extent permitted by law, be void or we will have the right to redeem the units held by the common unitholder. Further, the common units held by the common unitholder may not be entitled to any allocations of income or loss, distributions, or voting rights.

The purchase price will be paid in cash or delivery of a promissory note, as determined by our general partner. Any such promissory note will bear interest at the rate of 8% annually and be payable in three equal annual installments of principal and accrued interest, commencing one year after the redemption date.

Except as described below regarding a person or group owning 20% or more of any class of units then outstanding, record holders of units on the record date will be entitled to notice of, and to vote at, meetings of our limited partners and to act upon matters for which approvals may be solicited.

Our general partner does not anticipate that any meeting of our unitholders will be called in the foreseeable future. Any action that is required or permitted to be taken by the unitholders may be taken either at a meeting of the unitholders or without a meeting if consents in writing describing the action so taken are signed by holders of the number of units necessary to authorize or take that action at a meeting. Meetings of the unitholders may be called by our general partner or by unitholders owning at least 20% of the outstanding units of the class for which a meeting is proposed. Unitholders may vote either in person or by proxy at meetings. The holders of a majority of the outstanding units of the class or classes for which a meeting has been called, represented in person or by proxy, will constitute a quorum, unless any action by the unitholders requires approval by holders of a greater percentage of the units, in which case the quorum will be the greater percentage. Our general partner

may postpone any meeting of unitholders one or more times for any reason by giving notice to the unitholders entitled to vote at such meeting. Our general partner may also adjourn any meeting of unitholders one or more times for any reason, including the absence of a quorum, without a vote of the unitholders.

Each record holder of a unit has a vote according to his percentage interest in us, although additional limited partner interests having special voting rights could be issued. Please read "—Issuance of Additional Interests." However, if at any time any person or group, other than our general partner and its affiliates, or a direct or subsequently approved transferee of our general partner or its affiliates and purchasers specifically approved by our general partner, acquires, in the aggregate, beneficial ownership of 20% or more of any class of units then outstanding, that person or group will lose voting rights on all of its units and the units may not be voted on any matter and will not be considered to be outstanding when sending notices of a meeting of unitholders, calculating required votes, determining the presence of a quorum or for other similar purposes. Common units held in nominee or street name account will be voted by the broker or other nominee in accordance with the instruction of the beneficial owner unless the arrangement between the beneficial owner and his nominee provides otherwise. Except as our partnership agreement otherwise provides, subordinated units will vote together with common units, as a single class. Units that are owned by Non-Eligible Holders will be voted by our general partner and our general partner will distribute the votes on those units in the same ratios as the votes of limited partners on other units are cast.

Any notice, demand, request, report or proxy material required or permitted to be given or made to record common unitholders under our partnership agreement will be delivered to the record holder by us or by the transfer agent.

If a majority of the incentive distribution rights are held by our general partner and its affiliates, the holders of the incentive distribution rights will have no right to vote in respect of such rights on any matter, unless otherwise required by law, and the holders of the incentive distribution rights, shall be deemed to have approved any matter approved by our general partner.

If less than a majority of the incentive distribution rights are held by our general partner and its affiliates, the incentive distribution rights will be entitled to vote on all matters submitted to a vote of unitholders, other than amendments and other matters that our general partner determines do not adversely affect the holders of the incentive distribution rights in any material respect. On any matter in which the holders of incentive distribution rights are entitled to vote, such holders will vote together with the subordinated units, prior to the end of the subordination period, or together with the common units, thereafter, in either case as a single class, and such incentive distribution rights shall be treated in all respects as subordinated units or common units, as applicable, when sending notices of a meeting of our limited partners to vote on any matter (unless otherwise required by law), calculating required votes, determining the presence of a quorum or for other similar purposes under our partnership agreement. The relative voting power of the holders of the incentive distribution rights and the subordinated units or common units, depending on which class the holders of incentive distribution rights are voting with, will be set in the same proportion as cumulative cash distributions, if any, in respect of the incentive distribution rights for the four consecutive quarters prior to the record date for the vote bears to the cumulative cash distributions in respect of such class of units for such four quarters.

By transfer of common units in accordance with our partnership agreement, each transferee of common units shall be admitted as a limited partner with respect to the common units transferred

when such transfer and admission are reflected in our books and records. Except as described under "—Limited Liability," the common units will be fully paid, and unitholders will not be required to make additional contributions.

Under our partnership agreement, in most circumstances, we will indemnify the following persons, to the fullest extent permitted by law, from and against all losses, claims, damages or similar events:

Any indemnification under these provisions will only be out of our assets. Unless our general partner otherwise agrees, it will not be personally liable for, or have any obligation to contribute or lend funds or assets to us to enable us to effectuate, indemnification. We may purchase insurance against liabilities asserted against and expenses incurred by persons for our activities, regardless of whether we would have the power to indemnify the person against liabilities under our partnership agreement.

Our partnership agreement requires us to reimburse our general partner for all direct and indirect expenses it incurs or payments it makes on our behalf and all other expenses allocable to us or otherwise incurred by our general partner in connection with operating our business. 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.

Our general partner is required to keep appropriate books of our business at our principal offices. These books will be maintained for both tax and financial reporting purposes on an accrual basis. For tax and fiscal reporting purposes, our fiscal year is the calendar year.

We will furnish or make available to record holders of our common units, within 105 days after the close of each fiscal year, an annual report containing audited consolidated financial statements and a report on those consolidated financial statements by our independent public accountants. Except for our fourth quarter, we will also furnish or make available summary financial information within 50 days after the close of each quarter. We will be deemed to have made any such report available if we file such report with the SEC on EDGAR or make the report available on a publicly available website that we maintain.

We will furnish each record holder with information reasonably required for federal and state tax reporting purposes within 90 days after the close of each calendar year. This information is expected to be furnished in summary form so that some complex calculations normally required of partners can be avoided. Our ability to furnish this summary information to our unitholders will depend on their cooperation in supplying us with specific information. Every unitholder will receive information to assist him in determining his federal and state tax liability and in filing his federal and state income tax returns, regardless of whether he supplies us with the necessary information.

Our partnership agreement provides that a limited partner can, for a purpose reasonably related to his interest as a limited partner, upon reasonable written demand stating the purpose of such demand and at his own expense, have furnished to him:

Under our partnership agreement, however, each of our limited partners and other persons who acquire interests in our partnership interests, do not have rights to receive information from us or any of the persons we indemnify as described above under "—Indemnification" for the purpose of determining whether to pursue litigation or assist in pending litigation against us or those indemnified persons relating to our affairs, except pursuant to the applicable rules of discovery relating to the litigation commenced by the person seeking information.

Our general partner may, and intends to, keep confidential from the limited partners trade secrets or other information the disclosure of which our general partner determines is not in our best interests or that we are required by law or by agreements with third parties to keep confidential. Our partnership agreement limits the rights to information that a limited partner would otherwise have under Delaware law.

Under our partnership agreement, we have agreed to register for resale under the Securities Act and applicable state securities laws any common units, subordinated units or other limited partner interests proposed to be sold by our general partner or any of its affiliates or their assignees if an exemption from the registration requirements is not otherwise available. These registration rights continue for two years following any withdrawal or removal of our general partner. We are obligated to pay all expenses incidental to the registration, excluding underwriting discounts.

In addition, in connection with this offering, we expect to enter into a registration rights agreement with our sponsor. Please read "Certain Relationships and Related Party Transactions—Agreements with Affiliates in Connection with the Transactions—Registration Rights Agreement."

After the sale of the common units offered by this prospectus, our sponsor will hold an aggregate of common units and subordinated units. All of the subordinated units will convert into common units at the end of the subordination period and some may convert earlier. The sale of these common and subordinated units could have an adverse impact on the price of the common units or on any trading market that may develop.

Our common units sold in this offering will generally be freely transferable without restriction or further registration under the Securities Act, except that any common units held by an "affiliate" of ours may not be resold publicly except in compliance with the registration requirements of the Securities Act or under an exemption under Rule 144 or otherwise. Rule 144 permits securities acquired by an affiliate of the issuer to be sold into the market in an amount that does not exceed, during any three-month period, the greater of:

Sales under Rule 144 are also subject to specific manner of sale provisions, holding period requirements, notice requirements and the availability of current public information about us. A person who is not deemed to have been an affiliate of ours at any time during the three months preceding a sale, and who has beneficially owned our common units for at least six months (provided we are in compliance with the current public information requirement), or one year (regardless of whether we are in compliance with the current public information requirement), would be entitled to sell those common units under Rule 144, subject only to the current public information requirement. After beneficially owning Rule 144 restricted units for at least one year, a person who is not deemed to have been an affiliate of ours at any time during the 90 days preceding a sale would be entitled to freely sell those common units without regard to the public information requirements, volume limitations, manner of sale provisions and notice requirements of Rule 144.

Our partnership agreement provides that we may issue an unlimited number of limited partner interests of any type at any time without a vote of the unitholders. Any issuance of additional common units or other limited partner interests would result in a corresponding decrease in the proportionate ownership interest in us represented by, and could adversely affect the cash distributions to and market price of, common units then outstanding. Please read "The Partnership Agreement—Issuance of Additional Interests."

Under our partnership agreement and the registration rights agreement that we expect to enter into, our sponsor will have the right to cause us to register under the Securities Act and applicable state securities laws the offer and sale of any units that it holds. Subject to the terms and conditions of the partnership agreement and the registration rights agreement, these registration rights allow our sponsor or its assignees holding any units to require registration of any of these units and to include any of these units in a registration by us of other units, including units offered by us or by any unitholder. 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. Our sponsor will continue to have these registration rights for two years following the withdrawal or removal of Bowie GP, LLC as our general partner. In connection with any registration of this kind, we will indemnify each unitholder participating in the registration and its officers, directors, and controlling persons from and against any liabilities under the Securities Act or any applicable state securities laws arising from the registration statement or prospectus. We will bear all costs and expenses incidental to any registration, excluding any underwriting discount. Except as

described below, our sponsor may sell its units in private transactions at any time, subject to compliance with applicable laws.

The executive officers and directors of our general partner and our sponsor have agreed not to sell any common units they beneficially own for a period of 180 days from the date of this prospectus. Please read "Underwriting" for a description of these lock-up provisions.

Prior to the completion of this offering, we expect to adopt a new LTIP. If adopted, we intend to file a registration statement on Form S-8 under the Securities Act to register common units issuable under the LTIP. This registration statement on Form S-8 is expected to be filed following the effective date of the registration statement of which this prospectus is a part and will be effective upon filing. Accordingly, common units issued under the LTIP will be eligible for resale in the public market without restriction after the effective date of the Form S-8 registration statement, subject to applicable vesting requirements, Rule 144 limitations applicable to affiliates and the lock-up restrictions described above.

This section summarizes the material federal income tax consequences that may be relevant to prospective unitholders and is based upon current provisions of the Internal Revenue Code of 1986, as amended (the "Code"), existing and proposed Treasury regulations thereunder (the "Treasury Regulations"), and current administrative rulings and court decisions, all of which are subject to change. Changes in these authorities may cause the federal income tax consequences to a prospective unitholder to vary substantially from those described below. Unless the context otherwise requires, references in this section to "we" or "us" are references to the partnership and its subsidiaries on and after the closing of this offering.

Legal conclusions contained in this section, unless otherwise noted, are the opinion of Vinson & Elkins L.L.P. and are based on the accuracy of representations made by us to them for this purpose. However, this section does not address all federal income tax matters that affect us or our unitholders and does not describe the application of the alternative minimum tax that may be applicable to certain unitholders. Furthermore, this section focuses on unitholders who are individual citizens or residents of the United States (for federal income tax purposes), who have the U.S. dollar as their functional currency and who hold units as capital assets (generally, property that is held for investment). This section has limited applicability to corporations, partnerships, (including entities treated as partnerships for federal income tax purposes), estates, trusts, non-resident aliens or other unitholders subject to specialized tax treatment, such as tax-exempt institutions, non-U.S. persons, IRAs, employee benefit plans, real estate investment trusts or mutual funds. Accordingly, we encourage each unitholder to consult the unitholder's own tax advisor in analyzing the federal, state, local and non-U.S. tax consequences particular to that unitholder resulting from ownership or disposition of units and potential changes in applicable tax laws.

We are relying on opinions and advice of Vinson & Elkins L.L.P. with respect to the matters described herein. An opinion of counsel represents only that counsel's best legal judgment and does not bind the IRS or a court. Accordingly, the opinions and statements made herein may not be sustained by a court if contested by the IRS. Any such contest of the matters described herein may materially adversely impact the market for units and the prices at which our units trade. In addition, our costs of any contest with the IRS will be borne indirectly by our unitholders and our general partner because the costs will reduce our cash available for distribution. Furthermore, the tax consequences of an investment in us may be significantly modified by future legislative or administrative changes or court decisions, which may be retroactively applied.

For the reasons described below, Vinson & Elkins L.L.P. has not rendered an opinion with respect to the following federal income tax issues: (1) the treatment of a unitholder whose units are the subject of a securities loan (e.g., a loan to a short seller to cover a short sale of units) (please read "—Tax Consequences of Unit Ownership—Treatment of Securities Loans"); (2) whether our monthly convention for allocating taxable income and losses is permitted by existing Treasury Regulations (please read "—Disposition of Units—Allocations Between Transferors and Transferees"); and (3) whether our method for allocating excess depletion deductions and taking into account Section 743 adjustments is sustainable in certain cases (please read "—Tax Consequences of Unit Ownership—Section 754 Election" and "—Disposition of Units—Uniformity of Units").

We expect to be treated as a partnership for U.S. federal income tax purposes and, therefore, generally will not be liable for entity-level federal income taxes. Instead, as described below, each of our unitholders will take into account its respective share of our items of income, gain, loss and deduction in computing its federal income tax liability as if the unitholder had earned such income directly, even if we make no cash distributions to the unitholder. Distributions we make to a unitholder

generally will not give rise to income or gain taxable to such unitholder, unless the amount of cash distributed exceeds the unitholder's adjusted tax basis in its units.

Section 7704 of the Code generally provides that publicly traded partnerships will be treated as corporations for federal income tax purposes. However, if 90% or more of a partnership's gross income for every taxable year it is publicly traded consists of "qualifying income," the partnership may continue to be treated as a partnership for federal income tax purposes (the "Qualifying Income Exception"). Qualifying income includes income and gains derived from the mining, transportation and marketing of minerals and natural resources, such as coal. Other types of qualifying income include interest (other than from a financial business), dividends, gains from the sale of real property and gains from the sale or other disposition of capital assets held for the production of income that otherwise constitutes qualifying income. We estimate that less than 2.0% of our current gross income is not qualifying income; however, this estimate could change from time to time.

Based upon factual representations made by us and our general partner, Vinson & Elkins L.L.P. is of the opinion that we will be treated as a partnership and each of our limited liability company subsidiaries will be disregarded as entities separate from us for federal income tax purposes. The representations made by us and by our general partner upon which Vinson & Elkins L.L.P. has relied in rendering its opinion include, without limitation:

If we fail to meet the Qualifying Income Exception, other than a failure that is determined by the IRS to be inadvertent and that is cured within a reasonable time after discovery (in which case the IRS may also require us to make adjustments with respect to our unitholders or pay other amounts), we will be treated as transferring all of our assets, subject to liabilities, to a newly formed corporation, on the first day of the year in which we fail to meet the Qualifying Income Exception, in return for stock in that corporation and then as distributing that stock to our unitholders in liquidation. This deemed contribution and liquidation should not result in the recognition of taxable income by our unitholders or us so long as our liabilities do not exceed the tax basis of our assets. Thereafter, we would be treated as an association taxable as a corporation for federal income tax purposes.

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 interpretation 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, the 2015 Budget Proposal would eliminate the Qualifying Income Exception upon which we rely for our treatment as a partnership for U.S. federal income tax purposes for partnerships with qualifying income from fossil fuels, including coal beginning in 2021. Further, the Treasury Department and the IRS issued proposed Regulations interpreting the scope of the Qualifying Income Exception on May 5, 2015 (the "Proposed Regulations"). We believe the income that we treat as qualifying income satisfies the requirements for qualifying income under the Proposed Regulations. However, the Proposed Regulations could be changed before they are finalized and could take a position that is contrary to our interpretation of Section 7704 of the Code. We are unable to predict whether these changes, or other proposals, will ultimately be enacted. However, it is possible that a change in law could affect us and may be applied retroactively. Any such changes could negatively impact the value of an investment in our units.

If for any reason we are taxable as a corporation in any taxable year, our items of income, gain, loss and deduction would be taken into account by us in determining the amount of our liability for

federal income tax, rather than being passed through to our unitholders. Our taxation as a corporation would materially reduce the cash available for distribution to unitholders and thus would likely substantially reduce the value of our units. Any distribution made to a unitholder at a time we are treated as a corporation would be (i) a taxable dividend to the extent of our current or accumulated earnings and profits, then (ii) a nontaxable return of capital to the extent of the unitholder's tax basis in its units, and thereafter (iii) taxable capital gain.

The remainder of this discussion is based on the opinion of Vinson & Elkins L.L.P. that we will be treated as a partnership for federal income tax purposes.

Unitholders who are admitted as limited partners of the partnership, as well as unitholders whose units are held in street name or by a nominee and who have the right to direct the nominee in the exercise of all substantive rights attendant to the ownership of units, will be treated as partners of the partnership for federal income tax purposes. For a discussion related to the risks of losing partner status as a result of securities loans, please read "—Treatment of Securities Loans." Unitholders who are not treated as partners in us as described above are urged to consult their own tax advisors with respect to the tax consequences applicable to them under the circumstances.

Subject to the discussion below under "—Entity-Level Collections of Unitholder Taxes" with respect to payments we may be required to make on behalf of our unitholders, we will not pay any federal income tax. Rather, each unitholder will be required to report on its federal income tax return each year its share of our income, gains, losses and deductions for our taxable year or years ending with or within its taxable year. Consequently, we may allocate income to a unitholder even if that unitholder has not received a cash distribution.

We estimate that a purchaser of common units in this offering who owns those common units from the date of closing of this offering through the record date for distributions for the period ending December 31, , 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 with respect to that period. Thereafter, we anticipate that the ratio of taxable income to cash distributions to the common unitholders will increase. These estimates are based upon the assumption that earnings from operations will approximate the amount required to make the minimum quarterly distribution on all units and other assumptions with respect to capital expenditures, cash flow, net working capital and anticipated cash distributions. These estimates and assumptions are subject to, among other things, numerous business, economic, regulatory, legislative, competitive and political uncertainties beyond our control. Further, the estimates are based on current tax law and tax reporting positions that we will adopt and with which the IRS could disagree. Accordingly, we cannot assure you that these estimates will prove to be correct. The actual ratio of taxable income to cash distributions could be higher or lower than expected, and any differences could be material and could materially affect the value of the common units. For example, the ratio of taxable income to cash distributions to a purchaser of common units in this offering will be higher, and perhaps substantially higher, than our estimate with respect to the period described above if:

A unitholder's tax basis in its units initially will be the amount paid for those units plus the unitholder's share of our liabilities. That basis generally will be (i) increased by the unitholder's share of our income and any increases in such unitholder's share of our liabilities, and (ii) decreased, but not below zero, by the amount of all distributions, the unitholder's share of our losses, and any decreases in its share of our liabilities. The IRS has ruled that a partner who acquires interests in a partnership in separate transactions must combine those interests and maintain a single adjusted tax basis for all of those interests.

Distributions made by us to a unitholder generally will not be taxable to the unitholder, unless such distributions exceed the unitholder's tax basis in its units, in which case the unitholder generally will recognize gain taxable in the manner described below under "—Disposition of Units."

Any reduction in a unitholder's share of our "liabilities" will be treated as a distribution by us of cash to that unitholder. A decrease in a unitholder's percentage interest in us because of our issuance of additional units may decrease the unitholder's share of our liabilities. For purposes of the foregoing, a unitholder's share of our nonrecourse liabilities (liabilities for which no partner bears the economic risk of loss) generally will be based upon that unitholder's share of the unrealized appreciation (or depreciation) in our assets, to the extent thereof, with any excess liabilities allocated based on the unitholder's share of our profits. Please read "—Disposition of Units."

A non-pro rata distribution of money or property (including a deemed distribution as a result of the reallocation of our liabilities described above) may cause a unitholder to recognize ordinary income, if the distribution reduces the unitholder's share of our "unrealized receivables," including depreciation and depletion recapture and substantially appreciated "inventory items," both as defined in Section 751 of the Code ("Section 751 Assets"). To the extent of such reduction, the unitholder would be deemed to receive its proportionate share of the Section 751 Assets and exchange such assets with us in return for a portion of the non-pro rata distribution. This deemed exchange generally will result in the unitholder's recognition of ordinary income in an amount equal to the excess of (1) the non-pro rata portion of that distribution over (2) the unitholder's tax basis (generally zero) in the Section 751 Assets deemed to be relinquished in the exchange.

A unitholder may not be entitled to deduct the full amount of loss we allocate to it because its share of our losses will be limited to the lesser of (i) the unitholder's tax basis in its units, and (ii) in the case of a unitholder that is an individual, estate, trust or certain types of closely-held corporations, the amount for which the unitholder is considered to be "at risk" with respect to our activities. In general, a unitholder will be at risk to the extent of its tax basis in its units, reduced by (1) any portion of that basis attributable to the unitholder's share of our liabilities, (2) any portion of that basis representing amounts otherwise protected against loss because of a guarantee, stop loss agreement or

similar arrangement and (3) any amount of money the unitholder borrows to acquire or hold its units, if the lender of those borrowed funds owns an interest in us, is related to another unitholder or can look only to the units for repayment. A unitholder subject to the at risk limitation must recapture losses deducted in previous years to the extent that distributions (including distributions deemed to result from a reduction in a unitholder's share of nonrecourse liabilities) cause the unitholder's at risk amount to be less than zero at the end of any taxable year.

Losses disallowed to a unitholder or recaptured as a result of the basis or at risk limitations will carry forward and will be allowable as a deduction in a later year to the extent that the unitholder's tax basis or at risk amount, whichever is the limiting factor, is subsequently increased. Upon a taxable disposition of units, any gain recognized by a unitholder can be offset by losses that were previously suspended by the at risk limitation but not losses suspended by the basis limitation. Any loss previously suspended by the at risk limitation in excess of that gain can no longer be used, and will not be available to offset a unitholder's salary or active business income.

In addition to the basis and at risk limitations, a passive activity loss limitation generally limits the deductibility of losses incurred by individuals, estates, trusts, some closely-held corporations and personal service corporations from "passive activities" (generally, trade or business activities in which the taxpayer does not materially participate). The passive loss limitations are applied separately with respect to each publicly traded partnership. Consequently, any passive losses we generate will be available to offset only passive income generated by us. Passive losses that exceed a unitholder's share of passive income we generate may be deducted in full when the unitholder disposes of all of its units in a fully taxable transaction with an unrelated party. The passive loss rules generally are applied after other applicable limitations on deductions, including the at risk and basis limitations.

The deductibility of a non-corporate taxpayer's "investment interest expense" generally is limited to the amount of that taxpayer's "net investment income." Investment interest expense includes:

The computation of a unitholder's investment interest expense will take into account interest on any margin account borrowing or other loan incurred to purchase or carry a unit. Net investment income includes gross income from property held for investment and amounts treated as portfolio income under the passive loss rules, less deductible expenses other than interest directly connected with the production of investment income. Net investment income generally does not include qualified dividend income or gains attributable to the disposition of property held for investment. A unitholder's share of a publicly traded partnership's portfolio income and, according to the IRS, net passive income will be treated as investment income for purposes of the investment interest expense limitation.

If we are required or elect under applicable law to pay any federal, state, local or non-U.S. tax on behalf of any current or former unitholder or our general partner, we are authorized to treat the payment as a distribution of cash to the relevant unitholder or general partner. Where the tax is payable on behalf of all unitholders or we cannot determine the specific unitholder on whose behalf the tax is payable, we are authorized to treat the payment as a distribution to all current unitholders. Payments by us as described above could give rise to an overpayment of tax on behalf of a unitholder, in which event the unitholder may be entitled to claim a refund of the overpayment amount.

Unitholders are urged to consult their tax advisors to determine the consequences to them of any tax payment we make on their behalf.

Our items of income, gain, loss and deduction generally will be allocated among our unitholders in accordance with their percentage interests in us. At any time that we make incentive distributions, gross income will be allocated to the recipients to the extent of these distributions.

Specified items of our income, gain, loss and deduction will be allocated under Section 704(c) of the Code (or the principles of Section 704(c) of the Code) to account for any difference between the tax basis and fair market value of our assets at the time such assets are contributed to us and at the time of any subsequent offering of our units (a "Book-Tax Disparity"). As a result, the federal income tax burden associated with any Book-Tax Disparity immediately prior to an offering generally will be borne by our partners holding interests in us prior to such offering. In addition, items of recapture income will be specially allocated to the extent possible to the unitholder who was allocated the deduction giving rise to that recapture income in order to minimize the recognition of ordinary income by other unitholders.

An allocation of items of our income, gain, loss or deduction, other than an allocation required by the Code to eliminate a Book-Tax Disparity, will generally be given effect for federal income tax purposes in determining a partner's share of an item of income, gain, loss or deduction only if the allocation has "substantial economic effect." In any other case, a partner's share of an item will be determined on the basis of the partner's interest in us, which will be determined by taking into account all the facts and circumstances, including (i) the partner's relative contributions to us, (ii) the interests of all the partners in profits and losses , (iii) the interest of all the partners in cash flow and (iv) the rights of all the partners to distributions of capital upon liquidation. Vinson & Elkins L.L.P. is of the opinion that, with the exception of the issues described in "—Section 754 Election" and "—Disposition of Units—Allocations Between Transferors and Transferees," allocations of income, gain, loss or deduction under our partnership agreement will be given effect for federal income tax purposes.

A unitholder whose units are loaned (for example, a loan to "short seller" to cover a short sale of units) may be treated as having disposed of those units. If so, such unitholder would no longer be treated for tax purposes as a partner with respect to those units during the period of the loan and may recognize gain or loss from the disposition. As a result, during this period (i) any of our income, gain, loss or deduction allocated to those units would not be reportable by the lending unitholder, and (ii) any cash distributions received by the unitholder as to those units may be treated as ordinary taxable income.

Due to a lack of controlling authority, Vinson & Elkins L.L.P. has not rendered an opinion regarding the tax treatment of a unitholder that enters into a securities loan with respect to its units. Unitholders desiring to assure their status as partners and avoid the risk of income recognition from a loan of their units are urged to modify any applicable brokerage account agreements to prohibit their brokers from borrowing and lending their units. The IRS has announced that it is studying issues relating to the tax treatment of short sales of partnership interests. Please read "—Disposition of Units—Recognition of Gain or Loss."

Under current law, the highest marginal federal income tax rates for individuals applicable to ordinary income and long-term capital gains (generally, gains from the sale or exchange of certain investment assets held for more than one year) are 39.6% and 20%, respectively. These rates are subject to change by new legislation at any time.

In addition, a 3.8% net investment income tax applies to certain net investment income earned by individuals, estates, and trusts. For these purposes, net investment income generally includes a unitholder's allocable share of our income and gain realized by a unitholder from a sale of units. In the case of an individual, the tax will be imposed on the lesser of (i) the unitholder's net investment income from all investments, or (ii) the amount by which the unitholder's modified adjusted gross income exceeds $250,000 (if the unitholder is married and filing jointly or a surviving spouse), $125,000 (if married filing separately) or $200,000 (if the unitholder is unmarried or in any other case). In the case of an estate or trust, the tax will be imposed on the lesser of (i) undistributed net investment income, or (ii) the excess adjusted gross income over the dollar amount at which the highest income tax bracket applicable to an estate or trust begins.

We will make the election permitted by Section 754 of the Code that permits us to adjust the tax bases in our assets as to specific purchasers of our units under Section 743(b) of the Code. That election is irrevocable without the consent of the IRS. The Section 743(b) adjustment separately applies to each purchaser of units based upon the values and bases of our assets at the time of the relevant purchase, and the adjustment will reflect the purchase price paid. The Section 743(b) adjustment does not apply to a person who purchases units directly from us.

Under our partnership agreement, we are authorized to take a position to preserve the uniformity of units even if that position is not consistent with applicable Treasury Regulations. A literal application of Treasury Regulations governing a 743(b) adjustment attributable to properties depreciable under Section 167 of the Code may give rise to differences in the taxation of unitholders purchasing units from us and unitholders purchasing from other unitholders. If we have any such properties, we intend to adopt methods employed by other publicly traded partnerships to preserve the uniformity of units, even if inconsistent with existing Treasury Regulations, and Vinson & Elkins L.L.P. has not opined on the validity of this approach. Moreover, we plan to adopt an allocation methodology with respect our coal properties that generate excess percentage depletion which may be inconsistent with the Treasury Regulations under Sections 704(b) and 743(b), but which is necessary in order to retain the uniformity of our units and provide appropriate tax consequences to each unitholder. Vinson & Elkins L.L.P. has not opined on whether our method under Sections 704(b) and 743(b) as it relates to excess percentage depletion is sustainable under the Treasury Regulations. Please read "—Disposition of Units—Uniformity of Units."

The IRS may challenge the positions we adopt with respect to depreciating or amortizing the Section 743(b) adjustment we take to preserve the uniformity of units due to lack of controlling authority. Because a unitholder's tax basis for its units is reduced by its share of our items of deduction or loss, any position we take that understates deductions will overstate a unitholder's basis in its units, and may cause the unitholder to understate gain or overstate loss on any sale of such units. Please read "—Disposition of Units—Recognition of Gain or Loss." If a challenge to such treatment were sustained, the gain from the sale of units may be increased without the benefit of additional deductions.

The calculations involved in the Section 754 election are complex and will be made on the basis of assumptions as to the value of our assets and other matters. The IRS could seek to reallocate some or all of any Section 743(b) adjustment we allocated to our assets subject to depreciation to goodwill or nondepreciable assets. Goodwill, as an intangible asset, is generally nonamortizable or amortizable over a longer period of time or under a less accelerated method than our tangible assets. We cannot assure any unitholder that the determinations we make will not be successfully challenged by the IRS or that the resulting deductions will not be reduced or disallowed altogether. Should the IRS require a different tax basis adjustment to be made, and should, in our opinion, the expense of compliance exceed the benefit of the election, we may seek permission from the IRS to revoke our Section 754

election. If permission is granted, a subsequent purchaser of units may be allocated more income than it would have been allocated had the election not been revoked.

We will use the year ending December 31 as our taxable year and the accrual method of accounting for federal income tax purposes. Each unitholder will be required to include in income its share of our income, gain, loss and deduction for each taxable year ending within or with its taxable year. In addition, a unitholder who has a taxable year ending on a date other than December 31 and who disposes of all of its units following the close of our taxable year but before the close of its taxable year must include its share of our income, gain, loss and deduction in income for its taxable year, with the result that it will be required to include in income for its taxable year its share of more than one year of our income, gain, loss and deduction. Please read "—Disposition of Units—Allocations Between Transferors and Transferees."

The tax bases of our assets will be used for purposes of computing depreciation and cost recovery deductions and, ultimately, gain or loss on the disposition of these assets. If we dispose of depreciable property by sale, foreclosure or otherwise, all or a portion of any gain, determined by reference to the amount of depreciation and depletion deductions previously taken, may be subject to the recapture rules and taxed as ordinary income rather than capital gain. Similarly, a unitholder who has taken cost recovery or depreciation deductions with respect to property we own will likely be required to recapture some or all of those deductions as ordinary income upon a sale of its interest in us. Please read "—Tax Consequences of Unit Ownership—Allocation of Income, Gain, Loss and Deduction."

The costs we incur in offering and selling our common units (called "syndication expenses") must be capitalized and cannot be deducted currently, ratably or upon our termination. While there are uncertainties regarding the classification of costs as organization expenses, which may be amortized by us, and as syndication expenses, which may not be amortized by us, the underwriting discounts we incur will be treated as syndication expenses.

The federal income tax consequences of the ownership and disposition of units will depend in part on our estimates of the relative fair market values and the initial tax bases of our assets. Although we may from time to time consult with professional appraisers regarding valuation matters, we will make many of the relative fair market value estimates ourselves. These estimates and determinations of tax basis are subject to challenge and will not be binding on the IRS or the courts. If the estimates of fair market value or basis are later found to be incorrect, the character and amount of items of income, gain, loss or deduction previously reported by unitholders could change, and unitholders could be required to adjust their tax liability for prior years and incur interest and penalties with respect to those adjustments.

In general, we are entitled to depletion deductions with respect to coal mined from the underlying mineral property. We generally are entitled to the greater of cost depletion limited to the basis of the property or percentage depletion. The percentage depletion rate for coal is 10%.

Depletion deductions we claim generally will reduce the tax basis of the underlying mineral property. Percentage depletion deductions can, however, exceed the total tax basis of the mineral property. The excess of our percentage depletion deductions over the adjusted tax basis of the property

at the end of the taxable year is subject to tax preference treatment in computing the alternative minimum tax. Upon the disposition of the mineral property, a portion of the gain, if any, equal to the lesser of the deductions for depletion which reduce the adjusted tax basis of the mineral property plus deductible development and mining exploration expenses, or the amount of gain recognized on the disposition, will be treated as ordinary income to us. In addition, a corporate unitholder's allocable share of the amount allowable as a percentage depletion deduction for any property will be reduced by 20% of the excess, if any, of that partner's allocable share of the amount of the percentage depletion deductions for the taxable year over the adjusted tax basis of the mineral property as of the close of the taxable year.

We will elect to currently deduct mining exploration expenditures that we pay or incur to determine the existence, location, extent or quality of coal deposits prior to the time the existence of coal in commercially marketable quantities has been disclosed.

Amounts we deduct for mine exploration expenditures must be recaptured and included in our taxable income at the time a mine reaches the production stage, unless we elect to reduce future depletion deductions by the amount of the recapture. A mine reaches the producing stage when the major part of the coal production is obtained from working mines other than those opened for the purpose of development or the principal activity of the mine is the production of developed coal rather than the development of additional coal for mining. This recapture is accomplished through the disallowance of both cost and percentage depletion deductions on the particular mine reaching the production stage. This disallowance of depletion deductions continues until the amount of adjusted exploration expenditures with respect to the mine have been fully recaptured. This recapture is not applied to the full amount of the previously deducted exploration expenditures. Instead, these expenditures are reduced by the amount of percentage depletion, if any, that was lost as a result of deducting these exploration expenditures.

Mine development costs incurred during the development phase are capitalized and revenue from the incidental sale of coal while a mine is in the development phase is recorded as a reduction of the related mine development costs.

Mine exploration and development expenditures are subject to recapture as ordinary income to the extent of any gain upon a sale or other disposition of our property or of your common units. Please read "—Disposition of Units." Corporate unitholders are subject to an additional rule that requires them to capitalize a portion of their otherwise deductible mine exploration and development expenditures. Corporate unitholders, other than some S corporations, are required to reduce their otherwise deductible exploration expenditures by 30%. These capitalized mine exploration and development expenditures must be amortized over a 60-month period, beginning in the month paid or incurred, using a straight-line method and may not be treated as part of the basis of the property for the purposes of computing depletion.

When computing the alternative minimum tax, mine exploration and development expenditures are capitalized and deducted over a ten year period. Unitholders may avoid this alternative minimum tax adjustment of their mine exploration and development expenditures by electing to capitalize all or part of the expenditures and deducting them over ten years for regular income tax purposes. You may select the specific amount of these expenditures for which you wish to make this election.

If any coal reserves are sold or otherwise disposed of in a taxable transaction, we will recognize gain or loss measured by the difference between the amount realized (including the amount of any indebtedness assumed by purchaser upon such disposition or to which such property is subject) and the

adjusted tax basis of the property sold. Generally, the character of any gain or loss recognized upon that disposition will depend upon whether our coal reserves or the mined coal sold are held by us:

In determining dealer status with respect to coal reserves and other types of real estate, the courts have identified a number of factors for distinguishing between a particular property held for sale in the ordinary course of business and one held for investment. Any determination must be based on all the facts and circumstances surrounding the particular property for sale in question.

We intend to hold our coal reserves for use in a trade or business, achieving long-term capital appreciation. Although our general partner may consider strategic sales of coal reserves consistent with achieving long-term capital appreciation, our general partner does not anticipate frequent sales of coal reserves. Thus, the general partner does not believe we will be viewed as a dealer. In light of the factual nature of this question, however, there is no assurance that our purposes for holding our properties will not change and that our future activities will not cause us to be a "dealer" in coal reserves.

If we are not a dealer with respect to our coal reserves and we have held the disposed property for more than a one-year period primarily for use in our trade or business, the character of any gain or loss realized from a disposition of the property will be determined under Section 1231 of the Code. If we have not held the property for more than one year at the time of the sale, gain or loss from the sale will be taxable as ordinary income.

A unitholder's distributive share of any Section 1231 gain or loss generated by us will be aggregated with any other gains and losses realized by that unitholder from the disposition of property used in the trade or business, as defined in Section 1231(b) of the Code, and from the involuntary conversion of such properties and of capital assets held in connection with a trade or business or a transaction entered into for profit for the requisite holding period. If a net gain results, all such gains and losses will be long-term capital gains and losses; if a net loss results, all such gains and losses will be ordinary income and losses. Net Section 1231 gains will be treated as ordinary income to the extent of prior net Section 1231 losses of the taxpayer or predecessor taxpayer for the five most recent prior taxable years to the extent such losses have not previously been offset against Section 1231 gains. Losses are deemed recaptured in the chronological order in which they arose.

If we are not a dealer with respect to our coal reserves and that property is not used in a trade or business, the property will be a "capital asset" within the meaning of Section 1221 of the Code. Gain or loss recognized from the disposition of that property will be taxable as capital gain or loss, and the character of such capital gain or loss as long-term or short-term will be based upon our holding period of such property at the time of its sale. The requisite holding period for long-term capital gain is more than one year.

Upon a disposition of coal reserves, a portion of the gain, if any, equal to the lesser of (1) the depletion deductions that reduced the tax basis of the disposed mineral property plus deductible development and mining exploration expenses or (2) the amount of gain recognized on the disposition, will be treated as ordinary income to us.

Subject to the limitations on the deductibility of losses discussed above and the limitation described below, unitholders will be entitled to a deduction, herein referred to as the Section 199 deduction, equal to a specified percentage of our qualified production activities income that is allocated to such unitholder. The percentage is currently 9% for qualified production activities income.

Qualified production activities income is generally equal to gross receipts from domestic production activities reduced by cost of goods sold allocable to those receipts, other expenses directly associated with those receipts, and a share of other deductions, expenses and losses that are not directly allocable to those receipts or another class of income. The products produced must be manufactured, produced, grown or extracted in whole or in significant part by the taxpayer in the United States.

For a partnership, the Section 199 deduction is determined at the partner level. To determine its Section 199 deduction, each unitholder will aggregate its share of the qualified production activities income allocated to him from us with the unitholder's qualified production activities income from other sources. Each unitholder must take into account its distributive share of the expenses allocated to him from our qualified production activities regardless of whether we otherwise have taxable income. However, our expenses that otherwise would be taken into account for purposes of computing the Section 199 deduction are only taken into account if and to the extent the unitholder's share of losses and deductions from all of our activities is not disallowed by the basis rules, the at-risk rules or the passive activity loss rules. Please read "—Tax Consequences of Unit Ownership—Limitations on Deductibility of Losses."

The amount of a unitholder's Section 199 deduction for each year is limited to 50% of the IRS Form W-2 wages actually or deemed paid by the unitholder during the calendar year that are deducted in arriving at qualified production activities income. Each unitholder is treated as having been allocated IRS Form W-2 wages from us equal to the unitholder's allocable share of our wages that are deducted in arriving at qualified production activities income for that taxable year. It is not anticipated that we or our subsidiaries will pay material wages that will be allocated to our unitholders, and thus a unitholder's ability to claim the Section 199 deduction may be limited.

The White House has recommended various legislative changes affecting the U.S. federal income tax preferences relating to coal exploration and development in the 2015 Budget Proposal. Among the changes recommended in the 2015 Budget Proposal is the elimination of certain key U.S. federal income tax preferences relating to coal exploration and development discussed above. The 2015 Budget Proposal would (1) repeal the 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 for 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 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.

A unitholder will be required to recognize gain or loss on a sale of units equal to the difference between the unitholder's amount realized and tax basis in the units sold. A unitholder's amount

realized generally will equal the sum of the cash or the fair market value of other property it receives plus its share of our liabilities with respect to such units. Because the amount realized includes a unitholder's share of our liabilities, the gain recognized on the sale of units could result in a tax liability in excess of any cash received from the sale.

Except as noted below, gain or loss recognized by a unitholder on the sale or exchange of a unit held for more than one year generally will be taxable as long-term capital gain or loss. However, gain or loss recognized on the disposition of units will be separately computed and taxed as ordinary income or loss under Section 751 of the Code to the extent attributable to Section 751 Assets, such as depreciation or depletion recapture. Ordinary income attributable to Section 751 Assets may exceed net taxable gain realized on the sale of a unit and may be recognized even if there is a net taxable loss realized on the sale of a unit. Thus, a unitholder may recognize both ordinary income and capital gain or loss upon a sale of units. Net capital loss may offset capital gains and, in the case of individuals, up to $3,000 of ordinary income per year.

For purposes of calculating gain or loss on the sale of units, the unitholder's tax basis will be adjusted by its allocable share of our income or loss in respect of its units for the year of the sale. Furthermore, as described above, the IRS has ruled that a partner who acquires interests in a partnership in separate transactions must combine those interests and maintain a single adjusted tax basis for all those interests. Upon a sale or other disposition of less than all of those interests, a portion of that tax basis must be allocated to the interests sold using an "equitable apportionment" method, which generally means that the tax basis allocated to the interest sold equals an amount that bears the same relation to the partner's tax basis in its entire interest in the partnership as the value of the interest sold bears to the value of the partner's entire interest in the partnership.

Treasury Regulations under Section 1223 of the Code allow a selling unitholder who can identify units transferred with an ascertainable holding period to elect to use the actual holding period of the units transferred. Thus, according to the ruling discussed in the paragraph above, a unitholder will be unable to select high or low basis units to sell as would be the case with corporate stock, but, according to the Treasury Regulations, it may designate specific units sold for purposes of determining the holding period of units transferred. A unitholder electing to use the actual holding period of units transferred must consistently use that identification method for all subsequent sales or exchanges of our units. A unitholder considering the purchase of additional units or a sale of units purchased in separate transactions is urged to consult its tax advisor as to the possible consequences of this ruling and application of the Treasury Regulations.

Specific provisions of the Code affect the taxation of some financial products and securities, including partnership interests, by treating a taxpayer as having sold an "appreciated" financial position, including a partnership interest with respect to which gain would be recognized if it were sold, assigned or terminated at its fair market value, in the event the taxpayer or a related person enters into:

Moreover, if a taxpayer has previously entered into a short sale, an offsetting notional principal contract or a futures or forward contract with respect to the partnership interest, the taxpayer will be treated as having sold that position if the taxpayer or a related person then acquires the partnership interest or substantially identical property. The Secretary of the Treasury is authorized to issue regulations that treat a taxpayer that enters into transactions or positions that have substantially the same effect as the preceding transactions as having constructively sold the financial position.

In general, our taxable income or loss will be determined annually, will be prorated on a monthly basis and will be subsequently apportioned among the unitholders in proportion to the number of units owned by each of them as of the opening of the applicable exchange on the first business day of the month (the "Allocation Date"). However, gain or loss realized on a sale or other disposition of our assets or, in the discretion of the general partner, any other extraordinary item of income, gain, loss or deduction will be allocated among the unitholders on the Allocation Date in the month in which such income, gain, loss or deduction is recognized. As a result, a unitholder transferring units may be allocated income, gain, loss and deduction realized after the date of transfer.

Although simplifying conventions are contemplated by the Code and most publicly traded partnerships use similar simplifying conventions, the use of this method may not be permitted under existing Treasury Regulations. Recently, however, the Department of the Treasury and the IRS issued proposed Treasury Regulations that provide a safe harbor pursuant to which a publicly traded partnership may use a similar monthly simplifying convention to allocate tax items among transferor and transferee unitholders, although such tax items must be prorated on a daily basis. Nonetheless, the proposed regulations do not specifically authorize the use of the proration method we have adopted. Accordingly, Vinson & Elkins L.L.P. is unable to opine on the validity of this method of allocating income and deductions between transferee and transferor unitholders. If this method is not allowed under the final Treasury Regulations, or only applies to transfers of less than all of the unitholder's interest, our taxable income or losses could be reallocated among our unitholders. We are authorized to revise our method of allocation between transferee and transferor unitholders, as well as among unitholders whose interests vary during a taxable year, to conform to a method permitted under future Treasury Regulations.

A unitholder who disposes of units prior to the record date set for a cash distribution for that quarter will be allocated items of our income, gain, loss and deduction attributable to the month of disposition but will not be entitled to receive a cash distribution for that period.

A unitholder who sells or purchases any of its units is generally required to notify us in writing of that transaction within 30 days after the transaction (or, if earlier, January 15 of the year following the transaction in the case of a seller). Upon receiving such notifications, we are required to notify the IRS of that transaction and to furnish specified information to the transferor and transferee. Failure to notify us of a transfer of units may, in some cases, lead to the imposition of penalties. However, these reporting requirements do not apply to a sale by an individual who is a citizen of the United States and who effects the sale through a broker who will satisfy such requirements.

We will be considered to have "constructively" terminated as a partnership for federal income tax purposes upon the 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 and 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. For such purposes, multiple sales of the same unit are counted only once. A constructive termination results in the closing of our taxable year for all unitholders. In the case of a unitholder reporting on a taxable year other than the calendar year, the closing of our taxable year may result in more than twelve months of our taxable income or loss being includable in such unitholder's taxable income for the year of termination.

A constructive termination occurring on a date other than December 31 generally would require that we file two tax returns for one fiscal year and the cost of the preparation of these returns will be borne by all unitholders. However, pursuant to an IRS relief procedure the IRS may allow a constructively terminated partnership to provide a single Schedule K-1 for the calendar year in which a termination occurs. Following a constructive termination, we would be required to make new tax elections, including a new election under Section 754 of the Code, and the termination would result in a deferral of our deductions for depreciation. A termination could also result in penalties if we were unable to determine that the termination had occurred. Moreover, a termination may either accelerate the application of, or subject us to, any tax legislation enacted before the termination that would not otherwise have been applied to us as a continuing as opposed to a terminating partnership.

Because we cannot match transferors and transferees of units and other reasons, we must maintain uniformity of the economic and tax characteristics of the units to a purchaser of these units. In the absence of uniformity, we may be unable to completely comply with a number of federal income tax requirements. Any non-uniformity could have a negative impact on the value of the units. Please read "—Tax Consequences of Unit Ownership—Section 754 Election."

Our partnership agreement permits our general partner to take positions in filing our tax returns that preserve the uniformity of our units. These positions may include reducing the depreciation, amortization or loss deductions to which a unitholder would otherwise be entitled or reporting a slower amortization of Section 743(b) adjustments for some unitholders than that to which they would otherwise be entitled. Vinson & Elkins L.L.P. is unable to opine as to validity of such filing positions.

A unitholder's basis in units is reduced by its share of our deductions (whether or not such deductions were claimed on an individual income tax return) so that any position that we take that understates deductions will overstate the unitholder's basis in its units, and may cause the unitholder to understate gain or overstate loss on any sale of such units. Please read "—Recognition of Gain or Loss" above and "—Tax Consequences of Unit Ownership—Section 754 Election" above. The IRS may challenge one or more of any positions we take to preserve the uniformity of units. If such a challenge were sustained, the uniformity of units might be affected, and, under some circumstances, the gain from the sale of units might be increased without the benefit of additional deductions.

Ownership of units by employee benefit plans and other tax-exempt organizations, as well as by non-resident alien individuals, non-U.S. corporations and other non-U.S. persons raises issues unique to those investors and, as described below, may have substantially adverse tax consequences to them. Prospective unitholders that are tax-exempt entities or non-U.S. persons should consult their tax advisors before investing in our units. Employee benefit plans and most other tax-exempt organizations, including IRAs and other retirement plans, are subject to federal income tax on unrelated business taxable income. Virtually all of our income will be unrelated business taxable income and will be taxable to a tax-exempt unitholder. Moreover, under our partnership agreement, non-U.S. persons are not Eligible Holders of our units and units held by non-U.S. persons may be subject to redemption. Please read "The Partnership Agreement—Non-Eligible Holders; Redemption."

Non-U.S. unitholders are taxed by the United States on income effectively connected with a U.S. trade or business ("effectively connected income") and on certain types of U.S.-source non-effectively connected income (such as dividends), and will be treated as engaged in business in the United States because of their ownership of our units. Furthermore, it is probable that they will be deemed to conduct such activities through a permanent establishment in the United States within the meaning of any applicable tax treaty. Consequently, they will be required to file federal tax returns to report their

share of our income, gain, loss or deduction and pay federal income tax at regular rates on their share of our net income or gain. Moreover, under rules applicable to publicly traded partnerships, distributions to non-U.S. unitholders are subject to withholding at the highest applicable effective tax rate. Each non-U.S. unitholder must obtain a taxpayer identification number from the IRS and submit that number to our transfer agent on a Form W-8BEN or applicable substitute form in order to obtain credit for these withholding taxes.

In addition, because a foreign corporation that owns units will be treated as engaged in a U.S. trade or business, that corporation may be subject to the U.S. branch profits tax at a rate of 30%, in addition to regular federal income tax, on its share of our income and gain to the extent reflected in earnings and profits, and as adjusted for changes in the foreign corporation's "U.S. net equity." That tax may be reduced or eliminated by an income tax treaty between the United States and the country in which the foreign corporate unitholder is a "qualified resident." In addition, this type of unitholder is subject to special information reporting requirements under Section 6038C of the Code.

A non-U.S. unitholder who sells or otherwise disposes of a unit will be subject to federal income tax on gain realized from the sale or disposition of that unit to the extent the gain is effectively connected with a U.S. trade or business of the non-U.S. unitholder. Under a ruling published by the IRS interpreting the scope of "effectively connected income," part or all of a non-U.S. unitholder's gain from the sale or disposition of units may be treated as effectively connected with that unitholder's indirect U.S. trade or business constituted by its investment in us. Moreover, under the Foreign Investment in Real Property Tax Act, a non-U.S. unitholder generally will be subject to federal income tax upon the sale or disposition of a unit if (i) it owned (directly or constructively applying certain attribution rules) more than 5% of our units at any time during the five-year period ending on the date of such disposition and (ii) 50% or more of the fair market value of all of our assets consisted of U.S. real property interests at any time during the shorter of the period during which such unitholder held the units or the 5-year period ending on the date of disposition. Currently, more than 50% of our assets consist of U.S. real property interests and we do not expect that to change in the foreseeable future. Therefore, non-U.S. unitholders may be subject to federal income tax on gain from the sale or disposition of their units.

We intend to furnish to each unitholder, within 90 days after the close of each taxable year, specific tax information, including a Schedule K-1, which describes its share of our income, gain, loss and deduction for our preceding taxable year. In preparing this information, which will not be reviewed by counsel, we will take various accounting and reporting positions, some of which have been mentioned earlier, to determine each unitholder's share of income, gain, loss and deduction. We cannot assure our unitholders that those positions will yield a result that conforms to all of the requirements of the Code, Treasury Regulations or administrative interpretations of the IRS.

The IRS may audit our federal income tax information returns. Neither we nor Vinson & Elkins L.L.P. can assure prospective unitholders that the IRS will not successfully challenge the positions we adopt, and such a challenge could adversely affect the value of the units. Adjustments resulting from an IRS audit may require each unitholder to adjust a prior year's tax liability and may result in an audit of the unitholder's own return. Any audit of a unitholder's return could result in adjustments unrelated to our returns.

Publicly traded partnerships generally are treated as entities separate from their owners for purposes of federal income tax audits, judicial review of administrative adjustments by the IRS and tax settlement proceedings. The tax treatment of partnership items of income, gain, loss and deduction are determined in a partnership proceeding rather than in separate proceedings of the partners. The Code

requires that one partner be designated as the "Tax Matters Partner" for these purposes, and our partnership agreement designates our general partner.

The Tax Matters Partner can extend the statute of limitations for assessment of tax deficiencies against unitholders for items in our returns. The Tax Matters Partner may bind a unitholder with less than a 1% profits interest in us to a settlement with the IRS unless that unitholder elects, by filing a statement with the IRS, not to give that authority to the Tax Matters Partner. The Tax Matters Partner may seek judicial review, by which all the unitholders are bound, of a final partnership administrative adjustment and, if the Tax Matters Partner fails to seek judicial review, judicial review may be sought by any unitholder having at least a 1% interest in profits or by any group of unitholders having in the aggregate at least a 5% interest in profits. However, only one action for judicial review may go forward, and each unitholder with an interest in the outcome may participate in that action.

A unitholder must file a statement with the IRS identifying the treatment of any item on its federal income tax return that is not consistent with the treatment of the item on our return. Intentional or negligent disregard of this consistency requirement may subject a unitholder to substantial penalties.

Persons who hold an interest in us as a nominee for another person are required to furnish to us:

Brokers and financial institutions are required to furnish additional information, including whether they are U.S. persons and specific information on units they acquire, hold or transfer for their own account. A penalty of $100 per failure, up to a maximum of $1.5 million per calendar year, is imposed by the Code for failure to report that information to us. The nominee is required to supply the beneficial owner of the units with the information furnished to us.

Certain penalties may be imposed as a result of an underpayment of tax that is attributable to one or more specified causes, including negligence or disregard of rules or regulations, substantial understatements of income tax and substantial valuation misstatements. No penalty will be imposed, however, for any portion of an underpayment if it is shown that there was a reasonable cause for the underpayment of that portion and that the taxpayer acted in good faith regarding the underpayment of that portion. We do not anticipate that any accuracy-related penalties will be assessed against us.

In addition to federal income taxes, unitholders may be subject to other taxes, including state and local income taxes, unincorporated business taxes, and estate, inheritance or intangibles taxes that may be 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 those jurisdictions. We will initially own assets and conduct business in various states (including Utah, Kentucky and Colorado), each of which imposes a personal income tax on individuals and an income tax on corporations and other entities. We may also own property or do business in other states in the future that impose income or similar taxes on nonresident individuals. Although an analysis of those various taxes is not presented here, each prospective unitholder should consider their potential impact on its investment in us.

Although you may not be required to file a return and pay taxes in some jurisdictions because your income from that jurisdiction falls below the filing and payment requirement, you will be required to file income tax returns and to pay income taxes in many of these jurisdictions in which we do business or own property and may be subject to penalties for failure to comply with those requirements. 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.

It is the responsibility of each unitholder to investigate the legal and tax consequences, under the laws of pertinent jurisdictions, of its investment in us. We strongly recommend that each prospective unitholder consult, and depend upon, its own tax counsel or other advisor with regard to those matters. Further, it is the responsibility of each unitholder to file all state, local and non-U.S., as well as U.S. federal tax returns that may be required of it. Vinson & Elkins L.L.P. has not rendered an opinion on the state, local, alternative minimum tax or non-U.S. tax consequences of an investment in us.

An investment in us by an employee benefit plan is subject to additional considerations because the investments of these plans are subject to the fiduciary responsibility and prohibited transaction provisions of ERISA, restrictions imposed by Section 4975 of the Code, and/or provisions under any federal, state, local, non-U.S. or other laws or regulations that are similar to such provisions of the Code or ERISA (collectively, "Similar Laws"). For these purposes, the term "employee benefit plan" includes qualified pension, profit-sharing and unit bonus plans, Keogh plans, simplified employee pension plans and tax deferred annuities or IRAs or annuities and entities whose underlying assets are considered to include "plan assets" of such plans, accounts or arrangements. Among other things, consideration should be given to:

The person with investment discretion with respect to the assets of an employee benefit plan, often called a fiduciary, should determine whether an investment in us is authorized by the appropriate governing instrument and is a proper investment for the plan.

Section 406 of ERISA and Section 4975 of the Code prohibit employee benefit plans from engaging in specified transactions involving "plan assets" with parties that are "parties in interest" under ERISA or "disqualified persons" under the Code with respect to the plan.

In addition to considering whether the purchase of common units is a prohibited transaction, a fiduciary of an employee benefit plan should consider whether the plan will, by investing in us, be deemed to own an undivided interest in our assets, with the result that our operations would be subject to the regulatory restrictions of ERISA, including its prohibited transaction rules, as well as the prohibited transaction rules of the Code and any other applicable Similar Laws.

The Department of Labor regulations provide guidance with respect to whether the assets of an entity in which employee benefit plans acquire equity interests would be deemed "plan assets" under some circumstances. Under these regulations, an entity's assets would not be considered to be "plan assets" if, among other things:

Plan fiduciaries contemplating a purchase of common units should consult with their own counsel regarding the consequences under ERISA, the Code and any other applicable Similar Laws in light of the serious penalties imposed on persons who engage in prohibited transactions or other violations.

Citigroup Global Markets Inc., Morgan Stanley & Co. LLC, Deutsche Bank Securities Inc., UBS Securities LLC, Credit Suisse Securities (USA) LLC and Stifel, Nicolaus & Company, Incorporated are acting as joint book-running managers of this offering, and Citigroup Global Markets Inc., Morgan Stanley & Co. LLC and Deutsche Bank Securities Inc. are acting as representatives of the underwriters. Subject to the terms and conditions stated in the underwriting agreement dated the date of this prospectus, each underwriter named below has severally agreed to purchase, and we have agreed to sell to that underwriter, the number of common units set forth opposite the underwriter's name below:

The underwriting agreement provides that the obligations of the underwriters to purchase the common units included in this offering are subject to approval of legal matters by counsel and to other conditions. The underwriters are obligated to purchase all the common units (other than those covered by the underwriters' over-allotment option described below) if they purchase any of the common units.

Common units sold by the underwriters to the public will initially be offered at the initial public offering price set forth on the cover of this prospectus. Any common units sold by the underwriters to securities dealers may be sold at a discount from the initial public offering price not to exceed $ per common unit. After the common units are released for sale to the public, if all the common units are not sold at the initial offering price, the underwriters may change the offering price and the other selling terms. The representatives have advised us that the underwriters do not intend to confirm sales to discretionary accounts that exceed % of the total number of common units offered by them.

If the underwriters sell more common units than the total number set forth in the table above, we have granted to the underwriters an option, exercisable for 30 days from the date of this prospectus, to purchase up to additional common units at the public offering price less the underwriting discount. To the extent the option is exercised, each underwriter must purchase a number of additional common units approximately proportionate to that underwriter's initial purchase commitment. Any common units issued or sold under the option will be issued and sold on the same terms and conditions as the other common units that are the subject of this offering.

We, our sponsor, our general partner and certain officers and directors of our sponsor and our general partner have agreed that, for a period of 180 days from the date of this prospectus, we and they will not, without the prior written consent of , dispose of or hedge any common units or any securities convertible into or exchangeable for our common units, with certain exceptions.

Notwithstanding the foregoing, if (i) during the last 17 days of the 180-day restricted period, we issue an earnings release or material news or a material event relating to our company occurs; or (ii) prior to the expiration of the 180-day restricted period, we announce that we will release earnings results during the 16-day period beginning on the last day of the 180-day restricted period, the restrictions described above shall continue to apply until the expiration of the 18-day period beginning

on the issuance of the earnings release or the occurrence of the material news or material event. , in their sole discretion, may release any of the securities subject to these lock-up agreements at any time and without notice.

Prior to this offering, there has been no public market for our common units. Consequently, the initial public offering price for the common units was determined by negotiations among us and the representatives. Among the factors considered in determining the initial public offering price were our results of operations, our current financial condition, our future prospects, our markets, the economic conditions in and future prospects for the industry in which we compete, our management, and currently prevailing general conditions in the equity securities markets, including current market valuations of publicly traded companies considered comparable to our company. We cannot assure you, however, that the price at which the common units will sell in the public market after this offering will not be lower than the initial public offering price or that an active trading market in our common units will develop and continue after this offering.

We will apply to have our common units listed on the NYSE under the symbol "BRLP."

The following table shows the underwriting discounts that we will pay to the underwriters in connection with this offering. These amounts are shown assuming both no exercise and full exercise of the underwriters' over-allotment option.

We estimate that the expenses of the offering, not including the underwriting discount, will be approximately $ million, all of which will be paid by us.

In connection with the offering, the underwriters may purchase and sell common units in the open market. Purchases and sales in the open market may include short sales, purchases to cover short positions, which may include purchases pursuant to the underwriters' over-allotment option and stabilizing purchases. The underwriters also may impose penalty bids.

Purchases to cover short positions and stabilizing purchases, as well as other purchases by the underwriters for their own accounts, may have the effect of preventing or retarding a decline in the market price of the common units. They may also cause the price of the common units to be higher than the price that would otherwise exist in the open market in the absence of these transactions. The underwriters may conduct these transactions on the New York Stock Exchange, in the over-the-counter market or otherwise. If the underwriters commence any of these transactions, they may discontinue them at any time.

A prospectus in electronic format may be available on the websites or through other online services maintained by one or more of the underwriters participating in this offering, or by their affiliates. The underwriters may agree to allocate a specific number of common units for sale to online brokerage account holders. Any such allocation for online distributions will be made by the underwriters on the same basis as other allocations.

Other than the prospectus in electronic format, the information on any underwriter's or selling group member's website and any information contained in any other website maintained by an underwriter or selling group member is not part of this prospectus or the registration statement of which this prospectus forms a part, has not been approved or endorsed by us or any underwriter or selling group member in its capacity as underwriter or selling group member and should not be relied upon by investors.

Certain of the underwriters and their affiliates have engaged, and may in the future engage, in commercial banking, investment banking and advisory services for us, our sponsor or our respective affiliates from time to time in the ordinary course of their business for which they have received customary fees and reimbursement of expenses. Affiliates of certain of the underwriters are lenders under our new revolving credit facility. In addition, Mr. John DeRosa, who is expected to become a member of the board of directors of our general partner in connection with the closing of this offering, is currently the Head of Tax for the Americas for Deutsche Bank.

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, as well as related fees and expenses. Affiliates of Morgan Stanley & Co. LLC and Deutsche Bank Securities Inc. 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. Citigroup Global Markets Inc., Morgan Stanley & Co. LLC and Deutsche Bank Securities Inc. are also initial purchasers in connection with the New Notes offering. Other than the participation as lenders under the such credit facilities or as described in this prospectus, none of the underwriters has provided or will provide financing, investment or advisory services to us during the 180-day period prior to or the 90-day period following the date of this prospectus.

The underwriters are full service financial institutions engaged in various activities, which may include securities trading, commercial and investment banking, financial advisory, investment management, principal investment, hedging, financing and brokerage activities. In the ordinary course of their various business activities, the underwriters and their respective affiliates may make or hold a broad array of investments and actively trade debt and equity securities (or related derivative securities)

and financial instruments (which may include bank loans and/or credit default swaps) for their own account and for the accounts of their customers and may at any time hold long and short positions in such securities and instruments. Such investment and securities activities may involve our securities and instruments.

Because the Financial Industry Regulatory Authority, Inc. ("FINRA") views the common units offered hereby as interests in a direct participation program, this offering is being made in compliance with FINRA Rule 2310. Investor suitability with respect to the common units should be judged similarly to the suitability with respect to other securities that are listed for trading on a national securities exchange.

We, our sponsor, our general partner and certain of our affiliates have agreed to indemnify the underwriters against certain liabilities, including liabilities under the Securities Act, or to contribute to payments the underwriters may be required to make because of any of those liabilities.

The validity of our common units and certain other legal matters will be passed upon for us by Vinson & Elkins L.L.P., New York, New York. Certain legal matters in connection with this offering will be passed upon for the underwriters by Baker Botts L.L.P., Houston, Texas.

The consolidated balance sheet of Bowie Resource Partners LP as of March 31, 2015 and the financial statements of Canyon Fuel Company, LLC as of December 31, 2014 and for the year then ended appearing in this prospectus and registration statement have been audited by Ernst & Young LLP, independent registered public accounting firm, as set forth in their report thereon appearing elsewhere herein, and are included in reliance upon such report given on the authority of such firm as experts in accounting and auditing.

The financial statements of Canyon Fuel Company, LLC as of December 31, 2013 and for the period from August 16, 2013 to December 31, 2013 appearing in this prospectus and registration statement have been audited by Coulter & Justus, PC, independent registered public accounting firm, as set forth in their report thereon appearing elsewhere herein, and is included in reliance upon such report given on the authority of such firm as experts in accounting and auditing.

The financial statements of Canyon Fuel Company, LLC for the period from January 1, 2013 to August 16, 2013 appearing in this prospectus and registration statement have been audited by Ernst & Young LLP, independent registered public accounting firm, as set forth in their report thereon appearing elsewhere herein, and are included in reliance upon such report given on the authority of such firm as experts in accounting and auditing.

The coal reserves are based on SEC compliant reserve statements prepared by Norwest Corporation, an independent international mining consultancy. Those statements have been included with their expert's qualification to perform such studies and prepare requisite documents.

We have filed with the SEC a registration statement on Form S-1 (including the exhibits, schedules and amendments thereto) under the Securities Act with respect to the common units being offered hereunder. This prospectus does not contain all of the information set forth in the registration statement and the exhibits and schedules to the registration statement. For further information with respect to us and our common units, we refer you to the registration statement and the exhibits filed as a part of the registration statement. Statements contained in this prospectus concerning the contents of any contract or any other documents are not necessarily complete. If a contract or document has been

filed as an exhibit to the registration statement, we refer you to the copy of the contract or document that has been filed as an exhibit and reference thereto is qualified in all respects by the terms of the filed exhibit.

As a result of this offering, we will become subject to the full informational requirements of the Exchange Act. We will fulfill our obligations with respect to such requirements by filing period reports and other information with the SEC. Our SEC filings, including the registration statement and any exhibits and schedules thereto, may be inspected without charge at the Public Reference Room of the SEC at 100 F Street, N.E., Washington, D.C. 20549, and copies of these materials may be obtained from that office after payment of fees prescribed by the SEC. Information on the operation of the Public Reference Room may be obtained by calling the SEC at 1-800-SEC-0330. The SEC maintains a web site that contains reports, proxy and information statements and other information regarding registrants that file electronically with the SEC at http://www.sec.gov. After this offering, documents filed by us can also be inspected at the offices of the New York Stock Exchange Inc., 20 Broad Street, New York, New York 10002.

This prospectus 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. You can identify these forward-looking statements by the use of forward-looking words such as "outlook," "intends," "plans," "estimates," "believes," "expects," "potential," "continues," "may," "will," "should," "seeks," "approximately," "predicts," "anticipates," "foresees," or the negative version of these words or other comparable words and phrases. Any forward-looking statements contained in this prospectus speak only as of the date on which we make it and are based upon our historical performance and on current plans, estimates and expectations. Our future results and financial condition may differ materially from those we currently anticipate as a result of the various factors. Among those factors that could cause actual results to differ materially are:

Before you invest in our common units, you should be aware that the occurrence of the events described above and elsewhere in this prospectus could have a material adverse effect on our business, results of operations and financial position. We undertake no obligation to update or revise publicly any forward-looking statements, whether as a result of new information, future events or otherwise, except as required by law.

Set forth below are the unaudited pro forma condensed consolidated interim balance sheet of Bowie Resource Partners LP as of March 31, 2015 and the unaudited pro forma condensed consolidated interim statement of comprehensive (loss) income of Bowie Resource Partners LP for the three months ended March 31, 2015 and the year ended December 31, 2014. Such pro forma condensed consolidated financial statements are based on the historical financial statements of Canyon Fuel Company, LLC ("CFC"), the predecessor to our partnership for accounting purposes.

Our unaudited pro forma condensed consolidated financial statements present the pro forma effects of the Utah Transaction and the transactions that will occur in conjunction with our initial public offering (the "Offering Transactions"), each, as described below and of the adjustments set forth under the notes hereto. The unaudited pro forma condensed consolidated interim balance sheet as of March 31, 2015 reflects the effects of the Utah Transaction and the Offering Transactions as if they occurred on March 31, 2015 and the unaudited pro forma condensed consolidated statement of comprehensive (loss) income for the three months ended March 31, 2015 and the year ended December 31, 2014 reflects the effects of the Utah Transaction and Offering Transactions as if they occurred on January 1, 2014. We have not made adjustments to give effect to the incremental selling, general and administrative expenses of approximately $ million that we expect to incur as a result of being a publicly traded partnership. The unaudited pro forma condensed consolidated financial statements should be read in conjunction with the historical financial statements included elsewhere in this prospectus.

Our unaudited pro forma condensed consolidated financial statements are based on certain assumptions and do not purport to be indicative of the results that actually would have been achieved if the Utah Transaction and the Offering Transactions had been completed on the dates set forth above. These assumptions are subject to change and the effect of any such change could be material. Moreover, they do not project our financial position or results of operations as of any future date or for any future period.

Please read "Note 1. Pro Forma Condensed Consolidated Interim Balance Sheet Adjustments."

Neither Fossil Rock Resources, LLC nor Hunter Prep Plant, LLC had a history of operations, nor did they own any assets, until the closing of the Utah Transaction.

BOWIE RESOURCE PARTNERS LP

Unaudited Pro Forma Condensed Consolidated Interim Balance Sheet as of March 31, 2015

	Canyon Fuel Company, LLC		Adjustments for Utah Transaction (Note 1)		Adjustments for Offering Transactions (Note 1)		Bowie Resource Partners LP Pro Forma

	(in thousands)
Assets
Current assets:
Cash	$	—	$		$	(b)(c)	$
Accounts receivable		15,746				(c)
Inventories, net		48,588				(e)
Prepaid expenses and other current assets		16,618				(b)
Current portion of above market sales contracts		12,423

Total current assets		93,375
Property, plant and equipment, including mineral reserves and mine development costs, net		344,557		(a)		(e)
Restricted cash		3,100
Above market sales contracts, less current portion		—
Deferred financing costs, net		9,457				(d)
Other noncurrent assets		3,646				(a)(e)

Total Assets	$	454,135	$		$		$



Liabilities and member's equity
Current liabilities:
Accounts payable	$	28,037	$		$		$
Accrued expenses		21,728
Current portion of debt and short-term borrowings		50,502				(b)
Current portion of below market sales contracts		5,538

Total current liabilities		105,805
Debt, less current portion		327,976		(a)		(b)(e)
Asset retirement obligations		9,381		(a)		(e)
Other noncurrent liabilities		2,907

Total liabilities		446,069
Member's equity		8,066		(a)		(c)(d)(e)

Total liabilities and member's equity	$	454,135	$		$		$

See accompanying notes to unaudited pro forma condensed consolidated financial statements

BOWIE RESOURCE PARTNERS LP

Unaudited Pro Forma Condensed Consolidated Interim Statement of Comprehensive (Loss) Income
for the Three Months Ended March 31, 2015

	Canyon Fuel Company, LLC			Adjustments for Offering Transactions (Note 2)		Bowie Resource Partners LP Pro Forma

Revenues:
Coal sales to non-related parties	$	45,697		$		$
Coal sales to related parties		58,227
Other revenues, net		91

Total revenues		104,015
Cost of coal sales, exclusive of items shown separately below		74,587
Purchased coal from related parties		56
Depreciation, depletion and amortization		21,334
Amortization of acquired sales contracts, net		(54	)
Selling, general and administrative expenses		4,173			(f)

Operating income		3,919
Other expense:
Interest expense and related financing costs		(8,021	)		(g)

Net (loss) income and comprehensive (loss) income	$	(4,102	)	$		$

See accompanying notes to unaudited pro forma condensed consolidated financial statements

BOWIE RESOURCE PARTNERS LP

Unaudited Pro Forma Condensed Consolidated Statement of Comprehensive (Loss) Income
for the Year Ended December 31, 2014

	Canyon Fuel Company, LLC			Adjustments for Offering Transactions (Note 2)		Bowie Resource Partners LP Pro Forma

	(in thousands)
Revenues:
Coal sales to non-related parties	$	316,944		$		$
Coal sales to related parties		102,860
Other revenues, net of settlement expenses		358

Total revenues		420,162
Cost of coal sales, exclusive of items shown separately below		262,907
Purchased coal from related parties		15,136
Depreciation, depletion and amortization		81,057
Amortization of acquired sales contracts, net		12,098
Selling, general and administrative expenses		17,590			(f)

Operating income		31,374
Other expenses:
Interest expense and related financing costs		(36,245	)		(g)

Net other expense		(36,245	)
Net (loss) income and comprehensive (loss) income	$	(4,871	)	$		$

See accompanying notes to unaudited pro forma condensed consolidated financial statements

BOWIE RESOURCE PARTNERS LP

NOTES TO UNAUDITED PRO FORMA CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

NOTE 2. Pro Forma Condensed Consolidated Interim Statement of Comprehensive (Loss) Income Adjustments

BOWIE RESOURCE PARTNERS LP

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We have audited the accompanying consolidated balance sheet of Bowie Resource Partners LP and subsidiary (the Partnership) as of March 31, 2015. The consolidated balance sheet is the responsibility of the Partnership's management. Our responsibility is to express an opinion on this consolidated balance sheet based on our audit.

We conducted our audit in accordance with the standards of the Public Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. We were not engaged to perform an audit of the Partnership's internal control over financial reporting. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Partnership's internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.

In our opinion, the consolidated balance sheet referred to above presents fairly, in all material respects, the financial position of Bowie Resource Partners LP and subsidiary at March 31, 2015, in conformity with U.S. generally accepted accounting principles.

Bowie Resource Partners LP (the "Partnership") is a Delaware limited partnership formed in January 2015. Bowie GP, LLC (the "General Partner") is a limited liability company formed in January 2015 as the general partner of the Partnership. In January 2015, the Partnership formed its wholly-owned subsidiary BRP Holdings LLC (the "Operating Company").

In January 2015, Bowie Resource Holdings, LLC ("BRH"), a Delaware limited liability company, agreed to contribute $100 to the Partnership in exchange for a 100% limited partner interest. The agreement to contribute has been recorded as a contribution receivable and is reflected in the accompanying balance sheet as a reduction to partners' capital.

There have been no other transactions involving the Partnership or the Operating Company as of May 28, 2015.

The Partnership, pursuant to an initial public offering, intends to sell common units representing limited partnership interests in the Partnership. In connection with the closing of the public offering, BRH will contribute its ownership interests in Canyon Fuel Company, LLC, Fossil Rock Resources, LLC and Hunter Prep Plant, LLC (the "Contributed Assets") to the Partnership, which will then contribute the Contributed Assets to the Operating Company. The Partnership will then issue common units and subordinated units to BRH in exchange for the Contributed Assets and will offer common units to the public by way of a public offering. The General Partner will have a non-economic general partner interest in the Partnership. In addition, the Partnership will issue to the General Partner incentive distribution rights, which entitle the holder to increasing percentages, up to a maximum of 50%, of the distributions the Partnership makes above the highest target level.

The Partnership and the Operating Company, upon transfer of the Contributed Assets and the closing of the initial public offering, will be engaged in substantially the same business and revenue generating activities as the companies forming the Contributed Assets.

This balance sheet has been prepared in accordance with accounting principles generally accepted in the United States. Since the Partnership and the Operating Company have had no activity since their inception, separate statements of comprehensive income, changes in partners' equity and cash flows have not been presented.

The Partnership and the Operating Company evaluated subsequent events occurring through May 28, 2015, which is the date the accompanying financial statements were issued, and has determined that there are no material events that require recognition or disclosure.

We have audited the accompanying balance sheet of Canyon Fuel Company, LLC (the Company) as of December 31, 2014, and the related statements of operations and comprehensive (loss) income, members' equity and cash flows for the year ended December 31, 2014. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audit.

We conducted our audit in accordance with auditing standards generally accepted in the United States and in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. We were not engaged to perform an audit of the Company's internal control over financial reporting. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Canyon Fuel Company, LLC at December 31, 2014, and the results of its operations and its cash flows for the year ended December 31, 2014, in conformity with U.S. generally accepted accounting principles.

The accompanying financial statements have been prepared assuming that the Company will continue as a going concern. As discussed in Note 8 to the financial statements, the Company intends to refinance its Senior Secured Credit Facility. If such refinancing does not occur by the end of the third quarter of 2015, a violation of the financial covenant of the Senior Secured Credit Facility is expected that raises substantial doubt about the Company's ability to continue as a going concern. Management's plans in regard to these matters are also described in Note 8. The financial statements do not include any adjustments that might result from the outcome of this uncertainty.

We have audited the accompanying balance sheet of Canyon Fuel Company, LLC (the Company) as of December 31, 2013, and the related statements of operations and comprehensive loss, member's equity and cash flows for the period from August 16, 2013 to December 31, 2013. The Company's management is responsible for these financial statements. Our responsibility is to express an opinion on these financial statements based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Canyon Fuel Company, LLC at December 31, 2013, and the results of its operations and its cash flows for the period from August 16, 2013 to December 31, 2013, in conformity with accounting principles generally accepted in the United States.

We have audited the accompanying statements of income and comprehensive income, changes in members' equity, and cash flows for the period from January 1, 2013 to August 16, 2013 of Canyon Fuel Company, LLC (the "Predecessor"). These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. We were not engaged to perform an audit of the Predecessor's internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Predecessor's internal control over financial reporting. Accordingly we express no such opinion. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the results of the Predecessor's operations and its cash flows for the period from January 1, 2013 to August 16, 2013, in conformity with U.S. generally accepted accounting principles.

As described in Note 2 to the financial statements, the accompanying financial statements for the period from January 1, 2013 to August 16, 2013 have been derived from the accounting records of Arch Coal, Inc. These financial statements include expense allocations for certain corporate functions historically provided by Arch Coal, Inc. These allocations may not be reflective of the actual expense which would have been incurred had the Predecessor operated as a separate entity apart from Arch Coal, Inc.

	December 31,

	2014		2013
Assets
Current assets:
Accounts receivable from non-related parties	$	10,412	$	19,849
Accounts receivable from related party		—		414
Inventories, net		52,375		33,768
Prepaid expenses and other current assets		6,992		6,149
Current portion of above market sales contracts		14,876		21,913

Total current assets		84,655		82,093
Property, plant and equipment, including mineral reserves and mine development costs, net		357,110		400,945
Restricted cash		3,100		4,600
Above market sales contracts, less current portion		867		15,570
Deferred financing costs, net		10,024		12,636
Other noncurrent assets		3,668		3,809

Total assets	$	459,424	$	519,653



Liabilities and member's equity
Current liabilities:
Accounts payable	$	27,655	$	19,911
Accrued expenses		21,149		19,982
Current portion of debt and short-term borrowings		33,151		41,374
Current portion of below market sales contracts		8,912		9,357

Total current liabilities		90,867		90,624
Debt, less current portion		337,179		383,691
Below market sales contracts, less current portion		—		9,197
Asset retirement obligation		9,175		8,720
Other noncurrent liabilities		2,883		2,795

Total liabilities		440,104		495,027
Commitments and contingencies (Note 13)
Member's equity		19,320		24,626

Total liabilities and member's equity	$	459,424	$	519,653

The accompanying Notes to the Audited Financial Statements are an integral
part of these Audited Financial Statements.

Canyon Fuel Company, LLC

Statements of Operations and Comprehensive (Loss) Income

(in thousands)

				Year Ended December 31, 2013

	Year Ended December 31, 2014			Post-Acquisition Period from August 16, 2013 to December 31, 2013			Pre-Acquisition Period from January 1, 2013 to August 16, 2013
Revenues:
Coal sales to non-related parties	$	316,944		$	134,626		$	219,140
Coal sales to related parties		102,860			24,130			—
Other revenues, net		358			1,410			813

Total revenues		420,162			160,166			219,953
Cost of coal sales, exclusive of items shown separately below		262,907			115,855			171,720
Purchased coal from related parties		15,136			—			—
Depreciation, depletion and amortization		81,057			27,251			21,955
Amortization of acquired sales contracts, net		12,098			3,708			—
Selling, general and administrative expenses		17,590			9,586			7,970

Operating income		31,374			3,766			18,308
Other income (expense):
Interest expense and related financing costs		(36,245	)		(13,604	)		—
Gain on sale of assets		—			—			389
Other		—			—			(769	)

Net other expense		(36,245	)		(13,604	)		(380	)

Net (loss) income and comprehensive (loss) income	$	(4,871	)	$	(9,838	)	$	17,928

The accompanying Notes to the Audited Financial Statements are an integral
part of these Audited Financial Statements.

	Member's Equity

Pre-Acquisition Period from January 1, 2013 to August 16, 2013
Balance at January 1, 2013	$	312,438
Net income		17,928
Asset contributed by Arch to be included in sale		1,994
Distribution to parent		(40,807	)

Balance at August 16, 2013		291,553




Post-Acquisition
Balance at August 16, 2013		62,437
Net loss		(9,838	)
Net distribution to parent		(27,973	)

Balance at December 31, 2013		24,626
Net loss		(4,871	)
Net distribution to parent		(435	)

Balance at December 31, 2014	$	19,320

The accompanying Notes to the Audited Financial Statements are an integral
part of these Audited Financial Statements.

				Year Ended December 31, 2013

	Year Ended December 31, 2014			Post-Acquisition Period from August 16, 2013 to December 31, 2013			Pre-Acquisition Period from January 1, 2013 to August 16, 2013
Operating activities
Net (loss) income	$	(4,871	)	$	(9,838	)	$	17,928
Adjustments to reconcile net (loss) income to net cash provided by operating activities:
Depreciation, depletion and amortization		81,057			27,251			21,955
Amortization of acquired sales contracts, net		12,098			3,708			—
Amortization of discounts on notes payable		2,310			690			—
Accretion of asset retirement obligation		785			—			462
Amortization of deferred financing costs		2,612			862			—
Prepaid royalties expensed		—			—			759
Gain on sale of assets		—			—			(389	)
Changes in operating asset and liabilities:
Accounts receivable from non-related parties		9,437			(19,849	)		463
Accounts receivable from related party		414			(414	)		—
Inventories		(18,607	)		17,019			9,681
Prepaid expenses and other current assets		(7,711	)		(5,547	)		1,677
Other noncurrent assets		141			(144	)		142
Accounts payable		5,604			12,319			4,996
Accrued expenses		1,167			(11,252	)		(11,710	)
Other noncurrent liabilities		88			53			—

Net cash provided by operating activities		84,524			14,858			45,964
Investing activities
Purchases of property, plant and equipment		(28,544	)		(3,793	)		(5,653	)
Proceeds from the sale of equipment		—			20			639
Additions to prepaid royalties		—			—			(203	)
Change in restricted cash		1,500			(4,600	)		—

Net cash used in investing activities		(27,044	)		(8,373	)		(5,217	)
Financing activities
Proceeds from long-term debt and notes payable		27,449			44,950			—
Payments on long-term debt and notes payable		(84,494	)		(23,079	)		—
Payments for deferred financing costs		—			(383	)		—
Net distributions to parent		(435	)		(27,973	)		(40,807	)

Net cash used in financing activities		(57,480	)		(6,485	)		(40,807	)

Net decrease in cash		—			—			(60	)
Cash at beginning of period		—			—			82

Cash at end of period	$	—		$	—		$	22



Supplemental disclosure of cash flow information
Cash paid for interest	$	35,108		$	7,156		$	—
Supplemental disclosure of noncash activities
Property, plant and equipment financed	$	—		$	30,264		$	—
Property, plant and equipment purchases in accounts payable		2,142			—			—

The accompanying Notes to the Audited Financial Statements are an integral
part of these Audited Financial Statements.

Canyon Fuel Company, LLC

Notes to Audited Financial Statements

Years Ended December 31, 2014 and 2013

Canyon Fuel Company, LLC (the Company) operates three underground coal mines in Utah (two longwall operations and one room-and-pillar operation) and is wholly-owned by Bowie Resource Holdings, LLC (BRH), an entity that is wholly-owned by Bowie Resource Partners, LLC (BRP).

The Company engages in the extraction, cleaning and marketing of steam coal for sale primarily to major power plants in Utah, Nevada and California, as well as to cement, lime and gypsum plants and other industrial users in the western United States. In addition, the Company has access to port terminals in the State of California through which its coal is exported to a variety of growing international markets.

On August 16, 2013 (Acquisition Date), the Company was acquired (the Acquisition) by BRH from Arch Coal, Inc. and Arch Western Resources, LLC, an entity controlled by Arch Coal (Arch) (Note 3).

The accompanying Financial Statements include the accounts of the Company, as a controlled entity of BRP, for the post-acquisition periods as of December 31, 2014 and December 31, 2013 and the results of operations and cash flows for the year end December 31, 2014 and the period from August 16, 2013 through December 31, 2013. Also included are the accounts of the Company, as a controlled entity of Arch, for the pre-acquisition period from January 1, 2013 to August 16, 2013.

The Financial Statements of the Company have been prepared on the accrual basis of accounting in accordance with accounting principles generally accepted in the United States of America (GAAP) and Staff Accounting Bulletin Topic 1.B, Allocation of Expenses and Related Disclosure in Financial Statements of Subsidiaries, Divisions or Lesser Business Components of Another Entity. The Accounting Standards Codification (ASC), as produced by the Financial Accounting Standards Board, is the sole source of authoritative GAAP for non-governmental entities.

The Company has applied push-down accounting effective as of the Acquisition Date. Push-down accounting refers to the establishment of a new accounting and reporting basis for an acquiree (consistent with the purchase accounting basis used by the acquirer) in its separate standalone financial statements. This is based on an acquisition that results in the acquiree's outstanding equity interest becoming substantially wholly-owned. When push-down accounting has been applied, the acquiree's accounting should be substantially similar to that appropriate for a new entity. Accordingly, the Company's accounts were adjusted as of the Acquisition Date to reflect the new equity position of the Company, and the results of operations and cash flows for the year ended December 31, 2013 have been segregated in the accompanying Financial Statements to reflect pre- and post-acquisition activity.

These Financial Statements include allocations of assets, liabilities and expenses related to BRP's and BRH's corporate functions (post-acquisition) and Arch's corporate functions (pre-acquisition), including senior management, operations support, marketing, legal, human resources, finance and information technology. Allocations are based on proportional costs or incremental costs, whichever management has assessed is more representative of the amounts incurred by BRP, BRH or Arch, as applicable, on behalf of the Company. These amounts are allocated on the basis of the number of

locations or such other basis as deemed reasonably reflective of the Company's usage of the services provided by these related companies.

Post-acquisition, BRH allocated to the Company long term debt and related deferred financing costs and interest expense. BRH also allocated to the Company certain assets and liabilities attributable to or being utilized by the Company. These accounts include accounts receivable; prepaid expenses and other current assets; capitalized computer hardware and software included in property, plant and equipment, including mineral reserves and mine development costs, net; other noncurrent assets; accounts payable and accrued expenses. Within the Statements of Operations and Comprehensive (Loss) Income, allocations to the Company include amortization of capitalized computer hardware and software costs, reflected in depreciation, depletion and amortization; with all other cost allocations included in selling, general and administrative expenses.

Post-acquisition, the Company secured insurance coverage and bonding under programs maintained by BRH. As a result, the Company's costs under these programs may not reflect the costs it would otherwise incur if it operated as a stand-alone business.

Pre-acquisition, the Financial Statements include an allocation of expenses related to Arch's corporate functions, including senior management, operations support, marketing, legal human resources, finance and information technology. Expenses were allocated on a basis of proportional or incremental costs, whichever management had assessed was more representative of the costs incurred by Arch on behalf of the Company. These costs were allocated on the basis of revenues, headcount, number of locations, or such other basis as deemed reasonably reflective of the Company's usage of the services provided by Arch. These costs are reflected in selling, general and administrative expenses in the statements of operations and comprehensive (loss) income. The Financial Statements also include an allocation of expenses related to Arch Western Bituminous Group's office in Grand Junction, Colorado, including management oversight, engineering, human resources, finance, purchasing and information technology. These costs are reflected in cost of sales in the statements of operations and comprehensive (loss) income. All of the Company's employees are compensated under Arch's incentive and bonus plans, including stock-based awards. The costs, determined under GAAP, directly relating to the employees of the Company's mining complexes are reflected in the Company's cost of coal sales. The costs allocated to the Company are not necessarily indicative of the costs that would have been incurred if the Company were operated as a stand-alone business. See Note 11, Related Party Transactions for a discussion of the Company's various transactions with Arch.

Amounts, except per ton data, presented throughout these Financial Statements are in thousands (000s) of U.S. Dollars, unless otherwise indicated.

The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect certain reported amounts and disclosures. Accordingly, actual results could differ from those estimates.

The Company, in the course of its business activities, is exposed to a number of risks including fluctuating market conditions for coal, transportation and fuel costs, changing government regulations, unexpected maintenance and equipment failure, employee benefits cost control, changes in estimates of proven and probable coal reserves, the availability and timing of necessary mining permits and control of adequate recoverable mineral reserves. In addition, adverse weather and geological conditions may increase operating costs, sometimes substantially.

For the post-acquisition period covered by these Financial Statements, the Company's treasury activities were centralized at BRH's corporate office in Louisville, Kentucky. The Company's excess cash is remitted to BRH and the Company's disbursement accounts are funded by BRH as amounts are presented for payment. Accordingly, the amounts due to or from BRH and its subsidiaries are primarily settled as a net distribution to parent, and accounts receivable and accounts payable related to these transactions are not recorded. Only minimal cash balances are maintained at the Company level.

The Company's revenues are generated primarily under long-term coal sales contracts 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.

The Company sells a majority of its coal to customers at delivery points other than its mines, including power plants, industrial facilities and ports along the U.S. West Coast. As such, the Company often bears the transportation costs and any transloading costs. The Company records shipping and handling costs as a component of cost of coal sales.

Cash consists of cash held with reputable depository institutions and is stated at cost, which approximates fair value. Restricted cash consists of amounts held on deposit with bonding agencies to secure bonding obligations.

The Company evaluates accounts receivable based upon the estimated collectability, as determined by such variables as customer creditworthiness, the age of the receivables and historical loss experience. Receivables are considered past due if the full payment is not received by the contractual due date. Account balances are charged off after all means of collection have been exhausted and the potential for recovery is considered remote. It is the Company's policy not to require collateral on accounts receivable. Based upon the Company's evaluation, there was no allowance for doubtful accounts at December 31, 2014 or 2013. The Company does not have a history of credit losses with its customers.

Coal, parts and supplies 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.

Longwall mining is a form of underground mining that employs a shearer with two rotating drums pulled mechanically back and forth across an exposed coal face. The roof of the mine is supported by a hydraulic system while the drums are mining the coal. Conveyors move the loosened coal to an underground mine conveyor which transports the coal to the mine surface. The process to move the longwall shearer to a new coal panel within the mine occurs over the course of several months. Costs of relocating a longwall shearer to a new coal panel are capitalized and amortized using the straight-line method over the estimated life of the new coal panel. Costs capitalized include labor, parts and supplies used, and other equipment costs incurred to reposition a longwall shearer. Capitalized longwall costs are included in prepaid expenses and other current assets in the accompanying Balance Sheets. The Company had $4,083 recorded as capitalized longwall costs as of December 31, 2014. Capitalized longwall costs were not significant as of December 31, 2013. Amortization of capitalized longwall costs was $6,868 for the year ended December 31, 2014. Amortization of capitalized longwall costs was not significant during the post-acquisition period from August 16, 2013 to December 31, 2013 or the pre-acquisition period from January 1, 2013 to August 16, 2013.

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 the Company's 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 recorded at fair value at the date of acquisition. If coal is extracted during the mine development process, the amount of revenue from the sale of that coal is credited against the costs of development. Depletion of reserves and amortization of mine development costs are computed using the units of production method, based on estimated proven and probable reserves.

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 are classified as assets, whereas contracts where the expected contract price is below market at the acquisition date 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.

In conjunction with the Acquisition (Note 3), the Company recorded above market sales contracts with a fair value of $49,138 and below market sales contracts with a fair value of $26,501 in the opening balance sheet. The contracts are amortized over a weighted average amortization period of approximately 3 years.

Net amortization expense of the Company's acquired contracts was $12,098 and $3,708 for the year ended December 31, 2014 and for the post-acquisition period from August 16, 2013 to December 31, 2013, respectively. The Company did not have acquired sales contracts during the pre-acquisition period from January 1, 2013 to August 16, 2013.

Based on expected remaining shipments under these contracts, the Company estimates the following net amortization for the years ended December 31:

The Company is a single member limited liability company that is treated as a disregarded entity for federal and state income tax purposes. The Company's parent has elected to be treated as a partnership for federal and state income tax purposes. A partnership is not a tax paying entity for federal and state income tax purposes. Income, loss, deductions and credits of the Company pass through to its member and are taxed at the member's income tax rate. Accordingly, no provision for income taxes is provided in these Financial Statements. The Company reports any tax-related interest and penalties as a component of other expense. The Company makes distributions to its member to cover the member's estimated state and federal income taxes payable as a result of the operations of the Company.

The Company does not believe there are any material uncertain tax positions and, accordingly, it did not recognize a liability for unrecognized benefits in the Balance Sheets at December 31, 2014 and 2013. The Company does not anticipate any significant change in unrecognized tax benefits during the next twelve months.

The Company remains open to state examinations for tax years ended December 31, 2013 to December 31, 2014. The Company is not currently under examination by the Internal Revenue Service, state or local tax authorities.

The Company is required, under certain royalty lease agreements, to make minimum royalty payments whether or not mining activity is performed on the leased property. These minimum payments may be recoupable once mining begins on the leased property. The Company capitalizes the recoupable minimum royalty payments and amortizes these deferred costs, once the mining activities begin, on the units of production method. If the Company has ceased mining or has made a decision not to mine such property, these deferred costs are expensed.

Deferred financing costs represent capitalized amounts paid in connection with the issuance of debt. These costs are amortized using the effective interest method over the term of the associated debt.

The Company's asset retirement obligation (ARO) liabilities consist of cost estimates for reclamation and support facilities at mines in accordance with interpretations of applicable state and federal 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.

The Company estimates its 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 a credit-adjusted risk-free rate (9.00% 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. The Company reviews its asset retirement obligation at least annually and makes 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.

Costs to acquire permits for exploration activities are capitalized. Drilling and other costs related to locating coal deposits and evaluating the economic viability of such deposits are expensed as incurred.

The Company is subject to federal and state laws to provide workers' compensation and coal workers' black lung benefits to eligible employees, former employees and their dependents. The Company utilizes an insurance program to secure its on-going obligations associated with claims for work-related injuries and occupational disease, including black lung claims, with the exception of black lung claims filed under the Federal Coal Mine Health and Safety Act by former employees of the Company having dates of loss (i.e. the last date of exposure) prior to the Acquisition Date (Note 10), for which the Company is self-insured.

It is the intent of the Company to maintain insurance policies for workers' compensation and black lung related to active employees in order to mitigate its exposure to such claims both now and in the future. Premium expense for workers' compensation benefits is recognized in the period in which the related insurance coverage is provided.

The Company's black lung benefits liability for active employees with dates of loss subsequent to the Acquisition Date is calculated using the service cost method that considers the calculation of the actuarial present value of the estimated black lung obligation. The actuarial calculations using the service cost method for the black lung benefits liability are based on numerous assumptions, including disability incidence, medical costs, mortality, death benefits, dependents and interest rates.

The Company's black lung self-insured liability for black lung claims of employees with dates of loss prior to the Acquisition Date is calculated on an event driven basis that considers actuarial estimates of the aggregate liability for claims incurred. The actuarial calculations are based on numerous assumptions, including disability incidence, medical costs, mortality, death benefits, dependents and interest rates.

The Company's 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 the Company's debt approximates its fair value because the effective interest rates are not significantly different from current market rates. The Company does 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 Asset Retirement Obligations section of this note. This fair value determination is classified as Level 3 in the hierarchy.

The Company measures 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. The Company's policy is further described in the property, plant and equipment policies above.

In May 2014, the Financial Accounting Standards Board issued Accounting Standards Update No. 2014-09: Revenue from Contracts with Customers. The standard outlines a five-step model for revenue recognition with the core principle being that a company should recognize revenue when it transfers control of goods or services to customers at an amount that reflects the consideration to which it expects to be entitled in exchange for those goods or services. Companies can choose to apply the standard using the full retrospective approach or a modified retrospective approach. Under the modified approach, financial statements will be prepared for the year of adoption using the new

standard and prior periods presented will not be adjusted. Companies will recognize a cumulative catch-up adjustment to the opening balance of retained earnings. For public entities, this new guidance is effective for annual reporting periods beginning after December 15, 2016, including interim periods within that reporting period. For nonpublic entities, this new guidance is effective for annual reporting periods beginning after December 15, 2017, and interim reporting periods within annual reporting periods beginning after December 15, 2018. Early adoption is permitted for nonpublic entities. The Company has not yet made a determination as to whether it will early adopt the provisions of this new standard nor has any determination been made as to the method of application (full retrospective or modified retrospective). It is too early to assess whether the impact of the adoption of this new guidance will have a material impact on the Company's results of operations, financial position or cash flows.

The Company does not expect the adoption of any other recently issued accounting pronouncements to have a material impact on its Financial Statements.

In preparation of the accompanying Financial Statements, management has evaluated events that have occurred subsequent to the balance sheet date through March 26, 2015, the date the Financial Statements were issued.

Subsequent to the issuance of the Company's Financial Statements as of December 31, 2013 and the post-acquisition period from August 16, 2013 to December 31, 2013, a determination was made that the Company's black lung benefits liability was not calculated and reported using the service cost method that considers the calculation of the actuarial present value of the estimated black lung obligation, as required. The Company had accounted for its black lung benefits liability using an event driven approach under ASC 450, Contingencies. It was determined the Company should have accounted for its black lung benefits liability using a service cost approach under ASC 710, Compensation—General, because this approach matches black lung costs over the service lives of the miners who ultimately receive black lung benefits. The Company also determined that mineral reserves were not recorded at fair value. As of the Acquisition Date, these corrections resulted in an increase in property, plant and equipment, including mineral reserves and mine development costs, net and an increase in other noncurrent liabilities of $1,489, all of which the Company deemed immaterial.

Subsequent to the issuance of the Company's Financial Statements as of December 31, 2013 and the post-acquisition period from August 16, 2013 to December 31, 2013, a determination was made that the calculation of depletion included uncontrolled resources within the depletion base. The uncontrolled resources did not meet the definition of proven and probable reserves in accordance with SEC Industry Guide 7 and should not have been included in the depletion base.

All prior period information has been revised for these items. As of December 31, 2013, the corrections resulted in a net increase in property, plant and equipment, including mineral reserves and mine development costs, net of $502, an increase in other noncurrent liabilities of $1,542 and an

increase to accumulated deficit of $1,040. For the post-acquisition period from August 16, 2013 to December 31, 2013, the corrections resulted in an increase to depletion expense on mineral reserves of $987; an increase in cost of coal sales of $53, and an increase to net loss of $1,040.

The Company has determined these misstatements were not material to the Company's previously issued Financial Statements and has corrected these items by revising the amounts previously reported in the 2013 Financial Statements.

On August 16, 2013, BRH acquired 100% of the membership interests in the Company from Arch for $435,000. The Acquisition was funded using proceeds from a cash equity investment in BRH and borrowings under new debt issued by Morgan Stanley Senior Funding Inc. and Deutsche Bank Securities, Inc. (Note 8). The purchase price of the Company consisted of the following items:

The Unit Purchase Agreement (Purchase Agreement) specified a base purchase price of $435,000 which was the agreed upon sales price for 100% of the membership interests in the Company. Provisions of the Purchase Agreement allowed for various adjustments to the base purchase price, including a cash adjustment, a debt adjustment, a working capital adjustment and an accounts payable adjustment, which are customary in transactions of this nature. The Company's cash, debt, working capital and accounts payable positions as of the Acquisition Date resulted in a $12,015 reduction in the purchase price. Additionally, per the terms of the Purchase Agreement, the purchase price was reduced by the value of certain coal inventory being retained by Arch. As a result, consideration transferred was reduced by an additional $312 on the Acquisition Date. Consideration transferred was further reduced due to the inability of Arch to transfer certain software licenses following the change in ownership of the Company. BRH had to establish new licenses post acquisition directly with the software vendor. As a result, Arch agreed to an additional $300 reduction in consideration transferred to compensate for the license purchases. Net consideration transferred to Arch on the Acquisition Date was $422,373.

The following table summarizes the fair values of the assets acquired and liabilities assumed (prior to the allocations) as of August 16, 2013:

	As Revised(1)

Inventories, net	$	50,787
Prepaid expenses and other current assets		602
Property, plant and equipment, including mineral reserves and mine development costs		394,159
Above market sales contracts		49,138
Other noncurrent assets		5,017
Accounts payable		(7,592	)
Accrued expenses		(30,398	)
Long-term debt		(1,377	)
Below market sales contracts		(26,501	)
Asset retirement obligations		(8,720	)
Other noncurrent liabilities		(2,742	)

Net consideration transferred	$	422,373

Fair values for prepaid expenses and other current assets, other noncurrent assets, accounts payable, accrued expenses, long-term debt and other noncurrent liabilities were assumed to approximate their carrying value as stated on the closing trial balance received from Arch as of the Acquisition Date due to the short-term nature of these items or because the effective interest rates were not significantly different from current market rates.

The Company had approximately 1.8 million tons of extracted coal on the Acquisition Date as determined via independent third party surveys performed near the Acquisition Date. The fair value of this acquired coal inventory was determined by the Company using the comparative sales method. Fair value of acquired inventories were estimated to be $40,156 on the Acquisition Date. The Company also had parts and supplies inventories with a fair value of $10,631, net of a reserve for slow-moving and obsolete parts and supplies of $760. The fair value was determined based on the short-term nature of the inventories and a review of the parts and supplies inventories expected to be used in production.

The fair values of acquired property, plant and equipment (PP&E), including mine development costs, were estimated using a combination of the cost and market approaches, depending on the component. The Company engaged independent, third party valuation specialists familiar with the industry to aid in determining the acquisition date fair values of the acquired PP&E. Total PP&E, excluding mineral reserves, was estimated to have a fair value of $345,971 as of the Acquisition Date. Additionally, the Company reconsidered the remaining useful lives of the acquired PP&E and assigned new remaining useful lives, for purposes of calculating depreciation expense, based on a weighted

average of the remaining policy life (based on the Company's fixed asset policy) for each PP&E category. Useful lives assigned range from 3 to 20 years, depending on the asset category. The fair value of acquired mineral reserves, which is included in PP&E, including mineral reserves and mine development costs, was estimated considering both the cash flows for a mining asset's potential reserves beyond proven and probable reserves and estimates of future market price changes. A third party valuation specialist was also engaged by the Company to assist in these fair value estimates. Mineral reserves were estimated to have an Acquisition Date fair value of $46,699. In 2014, a revision (Note 2) of $1,489 to other noncurrent liabilities resulted in an increase in the mineral rights balance to $48,188 within the opening balance sheet and within the December 31, 2013 Balance Sheet.

The Company recognized a liability for ARO associated with the Company's underground mines and coal handling facilities. The Company engaged a third party valuation specialist to estimate the "minimum," "most likely," and "maximum" reclamation costs to be incurred. The Company recorded ARO of $8,720 based on the "most likely" ARO scenario. Because the estimated costs are based on probabilities, the actual liability may be above or below the "most likely" costs recorded.

A third party actuary was also engaged by the Company to assist in determining the fair value associated with the Company's assumed liability for future black lung claims filed under the Federal Coal Mine Health and Safety Act. Initially, the actuary was engaged to calculate a liability in relation to claims filed by Company employees prior to the Acquisition Date. The liability was estimated on an event driven approach, using various actuarial assumptions, including interest rate, for the amount of $1,253 as of the Acquisition Date. Additionally, it was determined that the Company also has a liability for future black lung claims related to active employees with dates of loss subsequent to the Acquisition Date and, therefore, the Company needed to increase its estimate for black lung benefits liability (Note 10). The black lung benefits liability for active employees with dates of loss subsequent to the Acquisition Date was calculated using the service cost method in consideration of the calculation of actuarial present value of the estimated black lung obligation. The revision (Note 2) resulted in a $1,489 reclassification from mineral reserves to increase the fair value estimate for black lung benefits liability (Note 10) to $2,742, included in other noncurrent liabilities within the opening balance sheet on August 16, 2013.

The Company evaluated identified intangible assets and identified the following: (a) the assembled workforce; and (b) customer contracts. The Company used the cost approach to estimate fair values for the assembled workforce. Amounts estimated for the assembled workforce were deemed insignificant for recognition.

Acquired customer contracts were evaluated for favorable and unfavorable terms in accordance with the off-market valuation approach. Terms of the acquired customer contracts were compared with current market terms. As a result, the Company determined acquired contracts contained both favorable and unfavorable terms compared to current market conditions. The Company recognized an intangible asset acquired (for favorable contracts) of $49,138. The Company also assumed a liability for unfavorable contracts which had an estimated fair value of $26,501 as of the Acquisition Date. The useful lives assigned to the acquired contracts were determined in accordance with the duration of the underlying contracts.

Parts and supplies inventories are stated net of an allowance for slow-moving and obsolete inventories of $853 and $821 at December 31, 2014 and 2013, respectively.

Prepaid expenses and other current assets consist of the following as of December 31:

Property, plant and equipment, including mineral reserves and mine development costs, consist of the following as of December 31:

Depreciation expense for the Company was $62,746 for the year ended December 31, 2014, $23,469 for the post-acquisition period from August 16, 2013 to December 31, 2013 and $19,236 for the pre-acquisition period from January 1, 2013 to August 16, 2013. Depletion and amortization expense on mineral reserves, mine development costs and capitalized asset retirement costs was $11,443 for the year ended December 31, 2014, $3,782 for the post-acquisition period from August 16, 2013 to December 31, 2013 and $2,719 for the pre-acquisition period from January 1, 2013 to August 16, 2013. Depreciation, depletion and amortization commences upon in service date. Capitalized revenues from coal sold during the mine development process were not significant for the pre-acquisition period from January 1, 2013 to August 16, 2013.

The carrying amount of the 2013 Senior Secured Credit Facility is presented above net of the respective unamortized original issue discount (including amounts allocated from BRH) of $9,047 and $11,358 at December 31, 2014 and 2013, respectively.

On August 16, 2013, BRH entered into loan agreements (collectively, the 2013 Senior Secured Credit Facility) among BRH and its subsidiaries (including the Company), Morgan Stanley Senior Funding Inc. (Morgan Stanley), Deutsche Bank Securities, Inc. (Deutsche Bank), and other lenders thereto. The 2013 Senior Secured Credit Facility provides for a $35,000 senior secured asset-backed revolving credit facility (the 2013 ABL), a $335,000 senior secured first lien term loan (the 2013 First Lien Term Loan), and a $100,000 senior secured second lien term loan (the 2013 Second Lien Term Loan). The 2013 ABL also has provisions for swingline loans up to an additional $5,000. The 2013 First Lien Term Loan and 2013 Second Lien Term Loan (collectively, the 2013 Term Loans) are net of original issue discounts of $10,050 and $4,000, respectively. These discounts are amortized over the lives of the respective term loans. The 2013 ABL has a term of 5 years and will mature on August 16, 2018. The 2013 First Lien Term Loan matures on August 16, 2020 and the 2013 Second Lien Term Loan matures on August 16, 2021. BRH recorded capitalized deferred financing costs of $15,294 related to the 2013 Senior Secured Credit Facility which are being amortized over the weighted average term of

the 2013 Senior Secured Credit Facility, or 6.5 years. Unamortized deferred financing costs allocated to the Company were $9,833 and $12,341 as of December 31, 2014 and 2013, respectively.

Proceeds from the 2013 Senior Secured Credit Facility were used to finance the Acquisition (Note 3) and to pay for Acquisition related expenses.

The obligations under the 2013 Senior Secured Credit Facility are guaranteed by the subsidiaries of BRH, including the Company. The obligations are also secured by all of the membership units of BRH and substantially all of the assets of the Company.

All borrowings under the 2013 Senior Secured Credit Facility bear interest, at the option of BRH, at either a base rate (subject to a floor of 2.00% for borrowings under the 2013 Term Loans) or a LIBOR rate (subject to a floor of 1.00% for borrowings under the 2013 Term Loans), each as defined in the 2013 Senior Secured Credit Facility, plus: (1) in the case of the 2013 First Lien Term Loan, a margin of 4.75% and 5.75% per year for borrowings bearing interest at the base rate and LIBOR rate, respectively; (2) in the case of the 2013 Second Lien Term Loan, a margin of 9.75% and 10.75% per year for borrowings bearing interest at the base rate and LIBOR rate, respectively; or (3) in the case of the 2013 ABL, a margin dependent on the average historical excess availability, as defined in the 2013 ABL, ranging from 0.75% to 1.00% and 1.75% to 2.00% per year for borrowings bearing interest at the base rate and LIBOR rate, respectively.

BRH had $304,483 and $321,361 outstanding under the 2013 First Lien Term Loan as of December 31, 2014 and 2013, respectively (net of unamortized original discounts of $7,486 and $9,452, as of December 31, 2014 and 2013 respectively). Additionally, BRH had $74,935 and $96,206 outstanding under the 2013 Second Lien Term Loan as of December 31, 2014 and 2013, respectively (net of an unamortized original issue discount of $3,065 and $3,794 as of December 31, 2014 and 2013, respectively). Amounts allocated to the Company by BRH for the 2013 First Lien were $261,094 and $275,567 as of December 31, 2014 and 2013, respectively (net of allocated, unamortized original issue discounts of $6,419 and $8,105 as of December 31, 2014 and 2013, respectively). BRH allocated $64,257 and $82,497 to the Company for the 2013 Second Lien Term Loan as of December 31, 2014 and 2013, respectively (net of allocated, unamortized original issue discounts of $2,628 and $3,253, as of December 31, 2014 and 2013, respectively). Interest rates payable as of December 31, 2014 and 2013 were LIBOR (with a floor of 1.00%) plus: (1) in the case of the 2013 First Lien Term Loan 5.75%, or 6.75% in total; and (2) in the case of the 2013 Second Lien Term Loan 10.75%, or 11.75% in total. The 2013 First Lien Term Loan is also subject to quarterly amortization of escalating rates ranging from 1.25% to 2.50% which commenced on August 16, 2013. Annual principal repayment by BRH for the year ending December 31, 2015 is expected to be $25,125.

The 2013 Term Loans are subject to mandatory prepayment requirements to prepay the term loan borrowings thereunder with proceeds from asset dispositions or property loss events, other debt issuances, and excess cash flow after the end of each fiscal year. These prepayment requirements are subject to various thresholds as defined in the 2013 Senior Secured Credit Facility. The 2013 Term Loans are also subject to various prepayment penalties for voluntary prepayments of principal, in part or in whole, as defined in the 2013 Senior Secured Credit Facility. During 2014, BRH paid $22,000 towards the 2013 Second Lien Term Loan as a result of these provisions.

In 2015, BRH intends to refinance its obligations under the 2013 Senior Secured Credit Facility. If such refinancing does not occur by the end of the third quarter of 2015, BRH does not expect to be in compliance with the maximum senior secured leverage ratio, in which case BRH intends to exercise its ability to Cure, as defined in the 2013 Senior Secured Credit Facility. BRH may not be successful in its refinancing efforts or may not be able to Cure the maximum senior secured leverage ratio breach, which would result in an event of default as defined in the 2013 Senior Secured Credit Facility. These Financial Statements are prepared assuming the Company will continue as a going concern and do not include any adjustments that might result from the outcome of this uncertainty.

BRH is permitted to make distributions, within certain thresholds as defined in the documentation and to buy and sell assets when in compliance with its financial covenants. The 2013 Senior Secured Credit Facility also imposes certain restrictions on the ability of BRH and its subsidiaries to incur liens, incur debt, make investments (including acquisitions), engage in organizational changes such as mergers and dissolutions, dispose of assets, change the nature of its business, enter into transactions with affiliates, and make restricted payments within defined thresholds. It also contains customary events of default. The documentation generally does not restrict BRH's ability to provide for loans and advances between BRH and its subsidiaries that secure or guarantee related indebtedness, provided that certain of such loans and advances are subordinated to BRH's obligations under the 2013 Senior Secured Credit Facility.

The 2013 ABL requires compliance with an additional financial covenant, the fixed charge coverage ratio, upon the occurrence and during the continuation of a covenant trigger period, as defined in the 2013 ABL. BRH was not in a covenant trigger period at any point during 2014. In addition, the agreement requires submission of a monthly borrowing base calculation and certificate to determine net availability under the 2013 ABL. As of December 31, 2014 and 2013, respectively, BRH had $5,500 and $17,000 in outstanding borrowings under the 2013 ABL and the remaining availability was $29,500 and $18,000, as of December 31, 2014 and 2013, respectively. The Company's allocated potions of outstanding borrowings under the 2013 ABL were $4,125 and $12,750 as of December 31, 2014 and 2013, respectively. The interest rates payable on the ABL at December 31, 2014 were LIBOR plus 2.00%, or 2.16% for the first $5,000 and the base rate of 3.25% plus 1.00%, or 4.25%, on the remaining $500. The interest rate payable at December 31, 2013 was LIBOR plus 1.75%, or 1.92%.

In 2012, the Company entered into an agreement with the State of Utah for the construction of a paved county road (the Quitchupah Road) to shorten its transportation routes from the Sufco mine (Sufco) to one of Sufco's largest customers. The Quitchupah Road project was funded by the Company through the issuance of County Municipal Financing Bonds (the Bonds) with Sevier County, Utah (Sevier Special Service District #1 or Sevier). The Company agreed to repay Sevier for the cost of the

road with repayments to begin once construction was complete. Construction on the Quitchupah Road project was ongoing at the time of the Acquisition (Note 3), thus the liability to Sevier and the rights to the Quitchupah Road were acquired by BRH. The amounts owed to Sevier Special Service District #1 are comprised of a $29,935 Repayment Agreement for construction of the Quitchupah Road and a $1,352 Promissory Note for reimbursement of road improvement costs incurred prior to the start of the Quitchupah Road project. The Promissory Note matures on March 1, 2018 and incurs interest at 2.50% annually and is payable in arrears. Principal and interest on the Promissory Note are payable in five equal annual installments of $293 beginning on March 1, 2014. The Repayment Agreement matures on March 1, 2027 and incurs interest at 2.40% annually. Principal and interest payments for the Repayment Agreement commenced on March 1, 2014 and are payable in 14 annual installments of varying amounts as specified in the Repayment Agreement.

The Quitchupah Road project had a total estimated construction cost of $29,935 including costs incurred to obtain funding such as legal fees, cost of all engineering and design work, and costs incurred for permitting, materials, labor and construction required to complete the project. Provisions of the Repayment Agreement allowed for adjustment of the principal amount following submission of a completion report stating actual Quitchupah Road construction costs. The Quitchupah Road was completed in October 2013 and the Company received the final completion report from Sevier Special Service District #1 in February 2014. Actual costs to complete the project were $28,912, $1,023 lower than the estimated cost. In accordance with the Repayment Agreement, the difference between the amount funded and actual project costs incurred was applied as credit against the annual payments due, starting in reverse order with the final annual payment. As such, the Company reduced the principal amount owed to Sevier by $1,023 to $28,912 in December 2013. As of December 31, 2014 and 2013, respectively, the Company had $28,387 and $30,264 outstanding under the notes payable to Sevier Special Service District #1.

The Company had outstanding equipment notes totaling $12,467 and $19,267 with Prudential Insurance Company of America as of December 31, 2014 and 2013, respectively. The notes bear interest at a fixed annual rate of 6.10% and are due in various monthly installments through 2016. The notes are secured by liens on the related equipment. The Company recorded $312 of capitalized deferred financing costs related to these notes during 2013 which are being amortized over the term of the notes. Unamortized deferred financing costs approximated $191 and $295 as of December 31, 2014 and 2013, respectively.

In February 2014, BRH financed a new insurance premium for its workers' compensation insurance policy that had a cost of $7,614. The note incurred interest at 3.97% with monthly payments of $645. As of December 31, 2013, BRH had financed $7,262 of its insurance premiums with Imperial Premium Financing Specialists; $4,720 was allocated to the Company. The note incurred interest at an annual rate of 3.97% with monthly payments of approximately $739 through October 31, 2014, at which time the note was repaid.

Aggregate maturities of the Company's allocated indebtedness are as follows as of December 31, 2014:

Interest and related financing costs attributable to the Company's notes payable and long-term debt are comprised of the following for the periods described:

Amounts presented above include parent allocations for interest expense of $29,608 and $10,531 and for other related financing costs of $4,819 and $1,535, for the year ended December 31, 2014 and the post-acquisition period from August 16, 2013 to December 31, 2013, respectively. There were no interest or related financing costs for the pre-acquisition period from January 1, 2013 to August 16, 2013.

The Company's asset retirement obligations as of December 31, 2013 were comprised of $8,720 for liabilities incurred from the Acquisition (Note 3). There was no significant change to the liability during the post-acquisition period from August 16, 2013 to December 31, 2013.

Changes in the Company's ARO liabilities are summarized below for the year ended December 31, 2014:

Accretion expense was $462 for the pre-acquisition period from January 1, 2013 to August 16, 2013.

The Company's insurance program for employee group health insurance is funded by the Company up to certain retention levels. A reserve is recorded for those claims incurred but not paid prior to year-end based on prior experience and claims reported subsequent to year-end. Changes in estimates for claims incurred but not reported are recorded in the year the estimates are revised. The Company limits its risk by maintaining outside insurance for any individual claim exceeding $400. The Company has reserves of $1,607 and $706 as of December 31, 2014 and 2013, respectively, in accrued expenses. The Company recognized expenses for the employee group health plan of $9,073 for the year ended December 31, 2014 and $1,999 for the period from August 16, 2013 to December 31, 2013. Health insurance plan expenses for the pre-acquisition period from January 1, 2013 to August 16, 2013 are included in the allocations made by Arch (Note 11).

The Company is fully insured against claims by its active workforce for work-related injuries, including black lung claims, with the exception of claims by former employees with dates of loss prior to the Acquisition Date. In conjunction with the Acquisition (Note 3) the Company assumed a liability for black lung claims of former employees with dates of loss prior to the Acquisition Date, for which the Company is self-insured.

Losses arising from the Company's black lung benefits liability for active miners were accrued under the service cost method, based upon actuarial estimates of the aggregate liability for future claims. Losses arising from the Company's self-insured black lung benefits liability were accrued on an event driven approach, based upon actuarial estimates of the aggregate liability for claims incurred.

As of December 31, 2014 and 2013, the black lung benefits liability was $2,883 and $2,795, respectively, and was recorded in other noncurrent liabilities. The discount rate and healthcare inflation assumption used to estimate present value of future obligations for black lung was 4% in both 2014 and 2013. The health care inflation assumption was 5% in both 2014 and 2013.

Workers' compensation and black lung insurance plan expenses allocated to the Company for the pre-acquisition period from January 1, 2013 to August 16, 2013 are included in the allocations made by Arch (Note 11).

BRH sponsors a defined contribution retirement plan for substantially all employees, including employees of the Company since the Acquisition Date. The Company makes voluntary matching contributions to participants based upon a percentage of the participant's salary. The Company may also make additional contributions at its discretion. The Company's contributions totaled $4,370 for the year ended December 31, 2014 and $1,222 for the period from August 16, 2013 to December 31, 2013.

During the pre-acquisition period from January 1, 2013 to August 16, 2013, substantially all of the Company's employees were covered by Arch's non-contributory defined-benefit pension plan. The benefits were based on the employee's age and compensation. Arch funded the plans in an amount not less than the minimum statutory funding requirements or more than the maximum amount that can be deducted for federal income tax purposes.

The Company's eligible employees also received certain post-retirement medical and life insurance benefits under Arch's plans. Generally, covered employees who terminated employment after meeting eligibility requirements were eligible for post-retirement coverage for themselves and their dependents. The employee post-retirement medical/life plans were contributory, with retiree contributions adjusted periodically, and contained other cost-sharing features such as deductibles and coinsurance.

The Company's employees were also able to participate in Arch's savings plans that were established to assist eligible employees in providing for their future retirement needs.

The Company's allocated contributions related to Arch's employee benefit plans were approximately $5,800 for the pre-acquisition period from January 1, 2013 to August 16, 2013. Since the employees of the Company represent only a portion of Arch's (during Arch's period of ownership) benefit plan participants, the net obligation, plan assets, and funded status of these plans are the obligation of Arch (pre-acquisition) and, as such, are not reflected in these Financial Statements.

Transactions between the Company and other affiliated companies not disclosed elsewhere are described below.

The Company has various coal sales agreements, for which revenue recognized from coal sales to related parties was comprised of the following for the periods indicated:

There were no coal sales to related parties for the pre-acquisition period from January 1, 2013 to August 16, 2013.

Purchased coal from Bowie Coal Sales, LLC (BCS), a related party and wholly-owned subsidiary of BRH, totaled $15,136 for the year ended December 31, 2014. The Company did not purchase coal from related parties during 2013. BCS functions as the coal sales entity for BRH and often purchases coal from the Company and sells such coal to its end customer. With respect to export sales, coal purchased by BCS from the Company is transported to one of the California port terminals leased by BCS and loaded onto a vessel for delivery to the end customer. The sales price paid by BCS to the Company for these export sales is based on a calculation of the net profit (net back) to the mine from which the coal originated. Net back refers to the sales price to the end customer net of commissions, rail transportation costs, stevedoring, demurrage, other applicable port charges and any coal quality adjustments. BCS also sells the Company's coal domestically. For domestic sales, the sales price paid by BCS to the Company is equivalent to BCS' ultimate sales price to the end customer, net of transportation costs where the ultimate sales price is a delivered price. Collectively, the intent of coal sales to BCS is primarily administrative and pricing is intended such that BCS not recognize a profit on the sales but instead that profit will be returned to the coal mine that ultimately produced the coal.

Bowie Refined Coal, LLC (BRC) operates ten §45 Qualified Refined Coal Facilities in the United States. BRC's facilities refine coal waste into a reusable salable product with short prox analyses comparable to that of the native coal. From time to time, the Company sells its high ash waste coal to BRC to be washed at one of its refined coal facilities, where the sales price is determined based upon the Company's cost to deliver the coal to BRC. The Company may then repurchase the cleaned coal from BRC and sell it to its end customer, where the sales price for such cleaned coal is determined based upon BRC's original cost to purchase the coal plus costs incurred by BRC in the washing process and a yield loss adjustment. A member of Cedars Energy, LLC (the controlling partner of BRP referred to as Cedars) also owns a controlling interest in BRC. Since the member has a controlling interest in both the Company and BRC, BRC is deemed a related party. Amounts receivable from BRC totaled none and $414 as of December 31, 2014 and 2013, respectively, and pertain to high ash waste coal sold to BRC during the periods.

During August 2013, the Company entered into a coal services agreement with Trafigura AG (Trafigura), a multinational commodities trading corporation formed under the laws of the Country of

Switzerland, which is a wholly-owned subsidiary of Trafigura Beheer B.V. Trafigura Beheer B.V. also owns Galena Asset Management S.A., which manages Galena Private Equity Resource Fund, which owns Galena US Holdings, Inc., a Delaware corporation (Galena). Cedars and Galena formed BRP in June 2013 to facilitate a joint venture to acquire the Company. Galena holds a 46% minority ownership interest in BRP. Since Galena is owned by Trafigura Beheer B.V. and Galena has an ownership stake in the Company's ultimate parent, BRP, Trafigura is deemed a related party.

Trafigura also serves as the Company's exclusive marketing agent for which marketing fees paid by the Company to Trafigura totaled $1,354 for the year ended December 31, 2014. The Company did not pay marketing fees to related parties during 2013.

Additionally, the following amounts were allocated to the Company by BRH as of and for the periods indicated:

	Year Ended December 31, 2014		Period from August 16, 2013 to December 31, 2013

Balance Sheet
Accounts receivable	$	—	$	13
Prepaid expenses and other current assets		936		4,773
Property, plant and equipment, including mineral reserves and mine development costs, net		281		150
Deferred financing costs, net		9,833		12,341
Accounts payable		493		1,166
Accrued expenses		3,095		5,152
Current maturities of long-term debt and notes payable (net of unamortized original issue discount)		23,728		31,442
Long-term debt, less current portion (net of unamortized original issue discount)		305,748		344,092
Statements of Comprehensive (Loss) Income
Other revenues, net of settlement expenses	$	29	$	64
Depreciation, depletion and amortization		94		14
Selling, general and administrative expenses		17,543		8,561
Interest expense and related financing costs		34,427		12,065

Amounts presented above were allocated in accordance with the methodology outlined in Note 2.

Related party transactions during the pre-acquisition period from January 1, 2013 to August 16, 2013 primarily relate to transactions between the Company and Arch. The Company was party to an accounts receivable securitization program with Arch whereby the Company sold its receivables to Arch without recourse at a discount based on the prime rate and day's sales outstanding. The discount on receivables sold to Arch totaled $380 for the pre-acquisition period from January 1, 2013 to August 16, 2013. Arch contributed certain reserves and other assets totaling $1,994 to the Company for inclusion in its sale in August 2013. Amounts allocated to the Company by Arch for selling, general and administrative services were approximately $8,000 and amounts allocated to the Company for Arch Western Bituminous Group's Grand Junction office were approximately $800.

The Company's two largest customers accounted for 29% and 24% of revenues for the year ended December 31, 2014, 21% and 19% of revenues for the period from August 16, 2013 to December 31, 2013, and 31% and 28% of revenues for the period from January 1, 2013 to August 16, 2013.

The Company routinely has cash on deposit with financial institutions which exceed Federal Deposit Insurance Corporation (FDIC) limits. Balances in excess of FDIC limits are subject to the risk that the financial institution will not pay upon demand. At December 31, 2014 and 2013, the Company's cash balances with financial institutions exceed the FDIC coverage by approximately $3,845 and $4,900, respectively.

Two customers accounted for 49% and 21% of accounts receivable as of December 31, 2014 and 18% and 11% of accounts receivable as of December 31, 2013.

The Company leases equipment, buildings, coal reserves and various other properties under non-cancelable, long-term leases, expiring at various dates. The Company incurred rental expense for operating leases of $4,158, $1,461 and $1,178 for the year end December 31, 2014, the post-acquisition period from August 16, 2013 to December 31, 2013 and the pre-acquisition period from January 1, 2013 to August 16, 2013, respectively. Coal reserves lease agreements require royalties to be paid as the coal is mined. The Company incurred coal lease and royalty expenses of $28,326 for the year ended December 31, 2014, $11,545 for the period from August 16, 2013 to December 31, 2013, and $17,174 for the period from January 1, 2013 to August 16, 2013. Certain agreements require minimum annual royalties to be paid regardless of the amount of coal mined during the year. Certain agreements may also be cancelable at the Company's discretion.

A substantial amount of the coal mined by the Company is produced from mineral reserves leased from various land owners. One of the major lessors is the U.S. government, from which the Company leases substantially all of the coal it mines in Utah under terms set by Congress and administered by the U.S. Bureau of Land Management. These leases are generally for an initial term of ten years but may be extended by diligent development and mining of the reserves until all economically recoverable reserves are depleted. The Company has met the diligent development requirements for substantially all of these federal leases either directly through production, by including the lease as a part of a logical mining unit with other leases upon which development has occurred, or by paying an advance royalty in lieu of continued operations. Annual production on these federal leases must total at least 1% of the original amount of coal in the entire logical mining unit. In addition, royalties are payable monthly at a rate of 8% of the gross realization for coal produced using underground mining methods. The remainder of the leased coal is generally leased from state governments, land holding companies and various individuals. The duration of these leases varies greatly. Typically, the lease terms are

automatically extended as long as active mining continues. Royalty payments are generally based upon a specified rate per ton or a percentage of the gross realization from the sale of the coal.

Future noncancelable minimum royalty and lease payments under these agreements are as follows as of December 31, 2014:

The Company believes it is in substantial compliance with federal, state and local environmental laws and regulations as currently promulgated. However, the exact nature of environmental control matters, if any, that the Company may encounter in the future cannot be predicted, primarily because of the increasing number, complexity and changing characteristics of environmental requirements that may be enacted by federal, state and local authorities. The Company's policy is to accrue for environmental expenses when the costs are probable and can be reasonably estimated.

The Company is contesting several enforcement actions issued by the Federal Mine Safety and Health Administration. The matters are pending before an administrative law judge of the Federal Mine Safety and Health Review Commission. Discovery is ongoing. Management believes that the ultimate resolution of such matters will not have a material adverse effect on the financial position of the Company.

In the ordinary course of business, the Company is a party to certain off-balance sheet arrangements. These arrangements include financial instruments with off-balance sheet risk, such as performance on surety bonds. No liabilities related to these arrangements are reflected in the accompanying Balance Sheets, and management does not expect any material adverse effects on the Company's financial position, results of operations or cash flows as a result of these off-balance sheet arrangements.

The Company is required by authoritative agencies to provide collateral in the form of reclamation bonds to ensure the completion of future reclamation. As of December 31, 2014 and 2013, outstanding

surety bonds with third parties for post-mining reclamation totaled approximately $23,754 and $23,908, respectively. The Company had restricted cash totaling $3,100 and $4,600 as of December 31, 2014 and 2013, respectively, to secure bonding obligations.

On December 12, 2014, the Company (through its wholly-owned subsidiary, Fossil Rock Resources, LLC) entered into an agreement with an affiliate of PacifiCorp to acquire certain undeveloped, high Btu, low sulfur coal reserves in Utah (the Fossil Rock reserves), and BCS entered into a coal supply agreement with PacifiCorp to supply all of the coal requirements of PacifiCorp's Huntington Power Plant in Utah through 2029 (collectively, the Utah Transaction). The new coal supply agreement with PacifiCorp provides for sales to PacifiCorp of a minimum of 2.0 million tons and a maximum of 3.0 million tons of coal per year through 2029. As part of the Utah Transaction, BRH also entered into an agreement with PacifiCorp (through its wholly-owned subsidiary, Hunter Prep Plant, LLC) to acquire certain real property near the Hunter Power Plant, which will enhance coal blending capabilities for deliveries to the Hunter Power Plant. The Utah Transaction, subject to customary closing conditions, is expected to close in the first half of 2015 for a purchase price of $40,000, to be paid via the delivery by Fossil Rock Resources, LLC of $30,000 in cash at closing and the delivery by Hunter Prep Plant, LLC of a $10,000 promissory note to PacifiCorp, pending certain customary purchase price adjustments to be determined upon closing.

The Company is subject to various lawsuits, claims and other legal proceedings arising in the ordinary course of business. The Company records costs relating to these matters when a loss is probable and the amount can be reasonably estimated; amounts are generally recorded in other accrued liabilities. Legal expenses incurred related to such lawsuits and claims are also accrued.

Unaudited quarterly selected financial data for the years ended December 31, 2014 and for the post-acquisition period from August 16, 2013 to December 31, 2013 and the pre-acquisition period from January 1, 2013 to August 16, 2013 is summarized below:

	First Quarter		Second Quarter			Third Quarter			Fourth Quarter

*2014*
Coal sales	$	112,265	$	97,514		$	115,727		$	94,298
Operating income		11,353		8,929			7,336			3,756
Net income (loss)		2,260		(246	)		(1,871	)		(5,014	)
*Post-acquisition period from August 16, 2013 to December 31, 2013*
Coal sales	$	—	$	—		$	52,279		$	106,477
Operating (loss) income		—		—			(2,291	)		6,057
Net loss		—		—			(5,979	)		(3,859	)

*Pre-acquisition period from January 1, 2013 to August 16, 2013*
Coal sales	$	91,122	$	90,328		$	37,690		$	—
Operating income		18,346		10,948			(10,986	)		—
Net income (loss)		18,504		10,426			(11,002	)		—

In the third quarter of 2013, the Company was acquired by BRH from Arch (Note 3).

	March 31, 2015		December 31, 2014

	(Unaudited)
Assets
Current assets:
Accounts receivable	$	15,746	$	10,412
Inventories, net		48,588		52,375
Prepaid expenses and other current assets		16,618		6,992
Current portion of above market sales contracts		12,423		14,876

Total current assets		93,375		84,655
Property, plant and equipment, including mineral reserves and mine development costs, net		344,557		357,110
Restricted cash		3,100		3,100
Above market sales contracts, less current portion		—		867
Deferred financing costs, net		9,457		10,024
Other noncurrent assets		3,646		3,668

Total assets	$	454,135	$	459,424



Liabilities and member's equity
Current liabilities:
Accounts payable	$	28,037	$	27,655
Accrued expenses		21,728		21,149
Current portion of debt and short-term borrowings		50,502		33,151
Current portion of below market sales contracts		5,538		8,912

Total current liabilities		105,805		90,867
Debt, less current portion		327,976		337,179
Asset retirement obligation		9,381		9,175
Other noncurrent liabilities		2,907		2,883

Total liabilities		446,069		440,104
Commitments and contingencies (Note 11)
Member's equity		8,066		19,320

Total liabilities and member's equity	$	454,135	$	459,424

The accompanying Notes are an integral part of these Condensed Interim Financial Statements.

Canyon Fuel Company, LLC

Condensed Interim Statements of Operations and Comprehensive (Loss) Income

(in thousands)
(Unaudited)

	Three Months Ended March 31,

	2015			2014
Revenues:
Coal sales to non-related parties	$	45,697		$	92,485
Coal sales to related parties		58,227			19,780
Other revenues, net		91			89

Total revenues		104,015			112,354
Cost of coal sales, exclusive of items shown separately below		74,587			72,682
Purchased coal from related parties		56			3,387
Depreciation, depletion and amortization		21,334			18,592
Amortization of acquired sales contracts, net		(54	)		3,181
Selling, general and administrative expenses		4,173			3,159

Operating income		3,919			11,353
Other expense:
Interest expense and related financing costs		(8,021	)		(9,093	)

Net (loss) income and comprehensive (loss) income	$	(4,102	)	$	2,260

The accompanying Notes are an integral part of these Condensed Interim Financial Statements.

Canyon Fuel Company, LLC

Condensed Interim Statements of Cash Flows

(in thousands)
(Unaudited)

	Three Months Ended March 31,

	2015			2014
Operating activities
Net (loss) income	$	(4,102	)	$	2,260
Adjustments to reconcile net (loss) income to net cash provided by operating activities:
Depreciation, depletion and amortization		21,334			18,592
Amortization of acquired sales contracts, net		(54	)		3,181
Amortization of discounts on notes payable		490			581
Accretion of asset retirement obligation		206			196
Amortization of deferred financing costs		567			653
Changes in operating assets and liabilities:
Accounts receivable from non-related parties		(5,334	)		(2,917	)
Accounts receivable from related parties		—			414
Inventories		3,787			1,290
Prepaid expenses and other current assets		(12,447	)		(4,525	)
Other noncurrent assets		22			143
Accounts payable		382			(5,463	)
Accrued expenses		579			(1,479	)
Other noncurrent liabilities		24			15

Net cash provided by operating activities		5,454			12,941
Investing activities
Purchases of property, plant and equipment		(5,960	)		(1,119	)

Net cash used in investing activities		(5,960	)		(1,119	)
Financing activities
Proceeds from long-term debt and notes payable		20,257			5,025
Payments on long-term debt and notes payable		(12,599	)		(12,684	)
Net distributions to parent		(7,152	)		(4,163	)

Net cash provided by (used in) financing activities		506			(11,822	)
Net change in cash		—			—
Cash at beginning of period		—			—

Cash at end of period	$	—		$	—



Supplemental disclosure of cash flow information
Cash paid for interest	$	9,292		$	7,633
Supplemental disclosure of noncash activities
Property, plant and equipment transferred from affiliate	$	—		$	2,142

The accompanying Notes are an integral part of these Condensed Interim Financial Statements.

Canyon Fuel Company, LLC

Notes to Condensed Interim Financial Statements

Three Months Ended March 31, 2015 and 2014

(Unaudited)

The accompanying Condensed Interim Financial Statements include the accounts of the Company, as a controlled entity of BRP, for the periods as of March 31, 2015 and December 31, 2014 and the results of operations and cash flows for the three months ended March 31, 2015 and 2014.

The Condensed Interim Financial Statements of the Company have been prepared on the accrual basis of accounting in accordance with accounting principles generally accepted in the United States of America (GAAP) for interim financial statements and pursuant to the rules and regulations of the Securities and Exchange Commission. Accordingly, they do not include all of the information and footnotes required by GAAP for complete financial statements. These Condensed Interim Financial Statements have also been prepared in accordance with Staff Accounting Bulletin Topic 1.B, Allocation of Expenses and Related Disclosure in Financial Statements of Subsidiaries, Divisions or Lesser Business Components of Another Entity. In the opinion of management, all adjustments (consisting of normal recurring accruals) considered necessary for a fair presentation have been included. 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. These Condensed Interim Financial Statements should be read in conjunction with the audited financial statements of the Company for the year ended December 31, 2014.

The Condensed Interim Balance Sheet at December 31, 2014 has been derived from the audited financial statements at that date but does not include all of the information and footnotes required by GAAP for complete financial statements.

These Condensed Interim Financial Statements include allocations of assets, liabilities and expenses related to BRP's and BRH's corporate functions, including senior management, operations support, marketing, legal, human resources, finance and information technology. Allocations are based on proportional costs or incremental costs, whichever management has assessed is more representative of the amounts incurred by BRP or BRH, on behalf of the Company. These amounts are allocated on the basis of the number of locations or such other basis as deemed reasonably reflective of the Company's usage of the services provided by these related companies.

BRH allocates to the Company long term debt and related deferred financing costs and interest expense. BRH also allocates to the Company certain assets and liabilities attributable to or being

utilized by the Company. These accounts include accounts receivable; prepaid expenses and other current assets; capitalized computer hardware and software included in property, plant and equipment, including mineral reserves and mine development costs, net; other noncurrent assets; accounts payable and accrued expenses. Within the Condensed Interim Statements of Operations and Comprehensive (Loss) Income, allocations to the Company include amortization of capitalized computer hardware and software costs, reflected in depreciation, depletion and amortization; with all other cost allocations included in selling, general and administrative expenses.

The Company secures insurance coverage and bonding under programs maintained by BRH. As a result, the Company's costs under these programs may not reflect the costs it would otherwise incur if it operated as a stand-alone business.

Amounts, except per ton data, presented throughout these Condensed Interim Financial Statements are in thousands (000s) of U.S. Dollars, unless otherwise indicated.

The Company's treasury activities are centralized at BRH's corporate office in Louisville, Kentucky. The Company's excess cash is remitted to BRH and the Company's disbursement accounts are funded by BRH as amounts are presented for payment. Accordingly, the amounts due to or from BRH and its subsidiaries are primarily settled as a net distribution to parent, and are recorded in members' equity. Only minimal cash balances are maintained at the Company level.

The Company operates as a single reportable segment, as the Company's Chief Executive Officer, serving as the Chief Operating Decision Maker (CODM), reviews financial information on the basis of the Company's consolidated financial results for purposes of making decisions. Generally, the CODM evaluates performance and allocates resources based on Adjusted EBITDA. EBITDA is defined as net

income (loss) before interest expense, income tax, depreciation, depletion and amortization. Adjusted EBITDA is defined as EBITDA further adjusted for accretion of asset retirement obligations, gain or loss on sale of assets, casualty losses and other taxes. Discrete financial information sufficient to allow the CODM to make decisions is only available on a consolidated basis.

The Company is a single member limited liability company that is treated as a disregarded entity for federal and state income tax purposes. The Company's parent has elected to be treated as a partnership for federal and state income tax purposes. A partnership is not a tax paying entity for federal and state income tax purposes. Income, loss, deductions and credits of the Company pass through to its member and are taxed at the member's income tax rate. Accordingly, no provision for income taxes is provided in these Condensed Interim Financial Statements. The Company reports any tax-related interest and penalties as a component of other expense. The Company makes distributions to its member to cover the member's estimated state and federal income taxes payable as a result of the operations of the Company.

The Company does not believe there are any material uncertain tax positions and, accordingly, it did not recognize a liability for unrecognized benefits in the Condensed Interim Balance Sheets at March 31, 2015 or December 31, 2014. The Company does not anticipate any significant change in unrecognized tax benefits during the next twelve months.

The Company's 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 the Company's debt approximates its fair value because the effective interest rates are not significantly different from current market rates. The Company does 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 Asset Retirement Obligations section of Note 2 to the audited financial statements. This fair value determination is classified as Level 3 in the hierarchy.

In May 2014, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) No. 2014-09: Revenue from Contracts with Customers. The standard outlines a five-step model for revenue recognition with the core principle being that a company should recognize revenue when it transfers control of goods or services to customers at an amount that reflects the consideration to which it expects to be entitled in exchange for those goods or services. Companies can either apply a full retrospective approach or a modified retrospective approach. For public business entities, the amendment is effective for annual reporting periods beginning after December 15, 2016, including interim periods within that reporting period. For nonpublic entities, the amendment is effective for annual reporting periods beginning after December 15, 2017, and interim reporting periods within annual reporting periods beginning after December 15, 2018. Early adoption is permitted for nonpublic entities. The Company has not yet made a determination as to whether it will early adopt the provisions of this new standard nor has any determination been made as to the method of application. It is too early to assess whether the impact of the adoption of this new guidance will have a material impact on the Company's results of operations, financial position or cash flows.

In April 2015, the FASB issued ASU No. 2015-03 Interest—Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs. The amendments in this ASU require that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of the debt liability, consistent with debt discounts. For public business entities, the amendments are effective for financial statements issued for fiscal years beginning after December 31, 2015, and interim periods within those fiscal years. For nonpublic entities, the

amendments are effective for financial statements issued for fiscal years beginning after December 15, 2015, and interim periods within fiscal years beginning after December 15, 2016. We do not expect the adoption of this amendment to have a material impact on the Company's results of operations, financial position or cash flows, as there are no changes to the recognition and measurement guidance for debt issuance costs.

The Company does not expect the adoption of any other recently issued accounting pronouncements to have a material impact on its Financial Statements.

In preparation of the accompanying Condensed Interim Financial Statements, management has evaluated events that have occurred subsequent to the balance sheet date through May 5, 2015, the date the Condensed Interim Financial Statements were issued.

Parts and supplies inventories are stated net of an allowance for slow-moving and obsolete inventories of $796 and $853 at March 31, 2015 and December 31, 2014, respectively.

Property, plant and equipment, including mineral reserves and mine development costs, consist of the following as of:

Depreciation expense for the Company was $15,992 and $15,728 for the three months ended March 31, 2015 and 2014, respectively. Depletion and amortization expense on mineral reserves, mine development costs and capitalized asset retirement costs was $2,521 and $2,864 for the three months ended March 31, 2015 and 2014, respectively. Depreciation, depletion and amortization commences upon in service date.

The carrying amount of the 2013 Senior Secured Credit Facility is presented above net of the respective unamortized original issue discount (including amounts allocated from BRH) of $8,557 and $9,047 at March 31, 2015 and December 31, 2014, respectively.

BRH had $298,639 and $304,483 outstanding under the 2013 First Lien Term Loan as of March 31, 2015 and December 31, 2014, respectively (net of an unamortized original issue discount of $7,049 and $7,486, as of March 31, 2015 and December 31, 2014, respectively). Additionally, BRH had $75,069 and $74,935 outstanding under the 2013 Second Lien Term Loan as of March 31, 2015 and December 31, 2014, respectively (net of an unamortized original issue discount of $2,931 and $3,065, as of March 31, 2015 and December 31, 2014, respectively). Amounts allocated to the Company by BRH for the 2013 First Lien Term Loan were $256,083 and $261,094 as of March 31, 2015 and December 31, 2014, respectively (net of allocated, unamortized original issue discounts of $6,044 and $6,419, as of March 31, 2015 and December 31, 2014, respectively). BRH allocated $64,372 and $64,257 to the Company for the 2013 Second Lien Term Loan as of March 31, 2015 and December 31, 2014, respectively (net of allocated, unamortized original issue discounts of $2,513 and $2,628, as of March 31, 2015 and December 31, 2014, respectively). Interest rates payable at March 31, 2015 and December 31, 2014 were LIBOR (with a floor of 1.00%) plus: (1) in the case of the 2013 First Lien Term Loan 5.75%, or 6.75% in total; and (2) in the case of the 2013 Second Lien Term Loan 10.75%, or 11.75% in total. The 2013 First Lien Term Loan is also subject to quarterly amortization of escalating rates ranging from 1.25% to 2.50% which commenced on August 16, 2013.

As of March 31, 2015 and December 31, 2014, respectively, BRH had $19,000 and $5,500 in borrowings outstanding under the 2013 ABL and the remaining availability was $16,000 and $29,500, respectively. Amounts allocated to the Company for the 2013 ABL were $14,250 and $4,125 as of March 31, 2015 and December 31, 2014, respectively. The interest rates payable on the ABL at March 31, 2015 were LIBOR plus 2.00%, or 2.17% for the first $12,500 and the base rate of 3.25% plus 1.00%, or 4.25%, on the remaining $6,500. The interest rates payable at December 31, 2014 were LIBOR plus 2.00%, or 2.16% for the first $5,000 and the base rate of 3.25% plus 1.00%, or 4.25%, on the balances in excess of $5,000.

Under the 2013 Senior Secured Credit Facility, BRH must comply with one financial covenant on a quarterly basis, which is the maximum senior secured leverage ratio for which the maximum ratio could not exceed 3.5 to 1 as of March 31, 2015 or December 31, 2014. BRH was in compliance with this covenant at March 31, 2015 and December 31, 2014. The 2013 ABL requires compliance with an additional financial covenant, the fixed charge coverage ratio, upon the occurrence and during the continuation of a covenant trigger period, as defined in the 2013 ABL. BRH was not in a covenant trigger period at any point during the three months ended March 31, 2015 or the year ended December 31, 2014. In addition, the 2013 ABL requires submission of a monthly borrowing base calculation and certificate to determine net availability under the 2013 ABL.

In 2015, BRH intends to refinance its obligations under the 2013 Senior Secured Credit Facility. If such refinancing does not occur by the end of the third quarter of 2015, BRH does not expect to be in compliance with the maximum senior secured leverage ratio, in which case BRH intends to exercise its ability to Cure, as defined in the 2013 Senior Secured Credit Facility. BRH may not be successful in its refinancing efforts or may not be able to Cure the maximum senior secured leverage ratio breach, which would result in an event of default as defined in the 2013 Senior Secured Credit Facility. These Condensed Interim Financial Statements are prepared assuming the Company will continue as a going concern and do not include any adjustments that might result from the outcome of this uncertainty.

In February 2015, BRH financed annual insurance premiums for its insurance policies in the amount of $13,332 with Imperial Premium Financing Specialists (IPFS). The note bears interest at 3.97% with monthly payments of $1,202. Amounts owed by BRH to IPFS for financed insurance premiums totaled $9,477 as of March 31, 2015 of which $7,190 was allocated to the Company. No amounts were outstanding with IPFS as of December 31, 2014.

Interest and related financing costs attributable to the Company's notes payable and long-term debt are comprised of the following for the three months ended March 31:

Amounts presented above include parent allocations for interest expense of $6,606 and $7,376 and for other related financing costs of $1,031 and $1,209, for the three months ended March 31, 2015 and 2014, respectively.

Transactions between the Company and other affiliated companies not disclosed elsewhere are described below.

The Company has various coal sales agreements, for which revenue recognized from coal sales to related parties was comprised of the following for the three months ended March 31:

Purchased coal from Bowie Coal Sales, LLC (BCS), a related party and wholly-owned subsidiary of BRH, totaled $56 and $3,387 for the three months ended March 31, 2015 and 2014, respectively. BCS functions as the coal sales entity for BRH and often purchases coal from the Company and sells such coal to its end customer. With respect to export sales, coal purchased by BCS from the Company is transported to one of the California port terminals leased by BCS and loaded onto a vessel for delivery to the end customer. The sales price paid by BCS to the Company for these export sales is based on a calculation of the net profit (net back) to the mine from which the coal originated. Net back refers to the sales price to the end customer net of commissions, rail transportation costs, stevedoring, demurrage, other applicable port charges and any coal quality adjustments. BCS also sells the Company's coal domestically. For domestic sales, the sales price paid by BCS to the Company is equivalent to BCS' ultimate sales price to the end customer, net of transportation costs where the ultimate sales price is a delivered price. Collectively, the intent of coal sales to BCS is primarily administrative and pricing is intended such that BCS not recognize a profit on the sales but instead that profit will be returned to the coal mine that ultimately produced the coal.

BRC to be washed at one of its refined coal facilities, where the sales price is determined based upon the Company's cost to deliver the coal to BRC. The Company, through its affiliate, BCS, may then repurchase the cleaned coal from BRC and sell it to its end customer, where the sales price for such cleaned coal is determined based upon BRC's original cost to purchase the coal plus costs incurred by BRC in the washing process and a yield loss adjustment. A member of Cedars Energy, LLC (the controlling partner of BRP referred to as Cedars) also owns a controlling interest in BRC. Since the member has a controlling interest in both the Company and BRC, BRC is deemed a related party.

During August 2013, the Company entered into a coal services agreement with Trafigura AG (Trafigura), a multinational commodities trading corporation formed under the laws of the Country of Switzerland, which is a wholly-owned subsidiary of Trafigura Beheer B.V. Trafigura Beheer B.V. also owns Galena Asset Management S.A., which manages Galena Private Equity Resource Fund, which owns Galena US Holdings, Inc., a Delaware corporation (Galena). Cedars and Galena formed BRP in June 2013 to facilitate a joint venture to acquire the Company. Galena holds a 46% minority ownership interest in BRP. Since Galena is owned by Trafigura Beheer B.V. and Galena has an ownership stake in the Company's ultimate parent, BRP, Trafigura is deemed a related party.

Trafigura also serves as the Company's exclusive marketing agent for which marketing fees paid by the Company to Trafigura totaled $990 and $213 for the three months ended March 31, 2015 and 2014, respectively.

Additionally, the following amounts were allocated to the Company by BRH as of and for the periods indicated:

Amounts presented above were allocated in accordance with the methodology outlined in Note 2.

Two customers accounted for 56% and 36% of revenues for the three months ended March 31, 2015 and three customers accounted for 27%, 25% and 15% of revenues for three months ended March 31, 2014.

The Company routinely has cash on deposit with financial institutions which exceed Federal Deposit Insurance Corporation (FDIC) limits. Balances in excess of FDIC limits are subject to the risk that the financial institution will not pay upon demand. At March 31, 2015, the Company's cash balances with financial institutions exceeded the FDIC coverage by approximately $3,084.

One customer accounted for 83% of accounts receivable as of March 31, 2015 and two customers accounted for 49% and 21% of accounts receivable as of December 31, 2014.

The Company leases equipment, buildings, coal reserves and various other properties under non-cancelable, long-term leases, expiring at various dates. The Company incurred rental expense for operating leases of $443 and $1,396 for the three months ended March 31, 2015 and 2014, respectively. Coal reserves lease agreements require royalties to be paid as the coal is mined. The Company incurred coal lease and royalty expenses of $7,463 and $8,319 for three months ended March 31, 2015 and 2014, respectively. Certain agreements require minimum annual royalties to be paid regardless of the amount of coal mined during the year. Certain agreements may also be cancelable at the Company's discretion.

A substantial amount of the coal mined by the Company is produced from mineral reserves leased from various land owners. One of the major lessors is the U.S. government, from which the Company

leases substantially all of the coal it mines in Utah under terms set by Congress and administered by the U.S. Bureau of Land Management. These leases are generally for an initial term of ten years but may be extended by diligent development and mining of the reserves until all economically recoverable reserves are depleted. The Company has met the diligent development requirements for substantially all of these federal leases either directly through production, by including the lease as a part of a logical mining unit with other leases upon which development has occurred, or by paying an advance royalty in lieu of continued operations. Annual production on these federal leases must total at least 1% of the original amount of coal in the entire logical mining unit. In addition, royalties are payable monthly at a rate of 8% of the gross realization for coal produced using underground mining methods. The remainder of the leased coal is generally leased from state governments, land holding companies and various individuals. The duration of these leases varies greatly. Typically, the lease terms are automatically extended as long as active mining continues. Royalty payments are generally based upon a specified rate per ton or a percentage of the gross realization from the sale of the coal.

The Company is required by authoritative agencies to provide collateral in the form of reclamation bonds to ensure the completion of future reclamation. As of March 31, 2015 and December 31, 2014, outstanding surety bonds with third parties for post-mining reclamation totaled approximately $24,416

and $23,754, respectively. The Company had restricted cash totaling $3,100 as of March 31, 2015 and December 31, 2014, respectively, to secure bonding obligations.

ash: Inorganic material consisting of iron, alumina, sodium and other incombustible matter that are contained in coal. The composition of the ash can affect the burning characteristics of coal.

Atlantic market: A term used to describe a geographic region of the world where goods are traded and shipped primarily on the Atlantic Ocean.

bituminous coal: A soft black coal with a heat content that ranges from 10,500 to 14,000 Btu per pound, as received. This coal is located primarily in Appalachia, Arizona, the Midwest, Colorado and Utah, and is the type most commonly used for electricity generation in the United States. Bituminous coal is also used for industrial steam purposes and as metallurgical coal used in steel production.

Btu: British thermal units, or Btu, is the amount of heat required to raise the temperature of one pound of water one degree Fahrenheit.

Central Appalachia: Coal producing area in eastern Kentucky, Virginia and southern West Virginia and northern Tennessee.

CERCLA: The Comprehensive Environmental Response, Compensation, and Liability Act of 1980.

Clean Air Act: The federal law enacted to regulate air emissions, as amended to date.

coal seam: Coal deposits occur in layers typically separated by layers of rock. Each layer is called a "seam." A seam can vary in thickness from inches to a hundred feet or more.

coke: A hard, dry carbon substance produced by heating coal to a very high temperature in the absence of air. Coke is used in the manufacture of iron and steel. Its production results in a number of useful by-products.

compliance coal: Any coal that emits less than 1.2 pounds of sulfur dioxide per million Btu when burned without blending other coals or using sulfur dioxide reduction technologies in order to comply with the requirements of the Clean Air Act.

continuous mining: A form of underground room and pillar mining, which involves the excavation of a series of "rooms" into the coal seam leaving "pillars" or columns of coal to help support the mine roof. A specialized cutting machine, the continuous miner, mechanizes the extraction procedure. Continuous miners tear the coal from the seam and load it onto conveyors or into shuttle cars in a continuous operation. This is to be distinguished from a conventional mining unit which must stop the extraction process in order for loading to commence.

Cost of coal sales, exclusive of items shown separately: When referenced in this prospectus, means cost of coal sales, exclusive of transportation, depreciation, depletion and amortization, and accretion on asset retirement obligations; when referenced in the financial statements, means cost of coal sales, exclusive of depreciation, depletion and amortization.

FOB: Free on board. The term generally specifies the location at which title, and hence risk of loss, transfers from a seller to a buyer.

Four Corners: A region of the United States consisting of the southwestern corner of Colorado, northwestern corner of New Mexico, northeastern corner of Arizona and southeastern corner of Utah.

fossil fuel: A hydrocarbon such as coal, petroleum or natural gas that may be used as a fuel.

Illinois Basin: Coal producing area in Illinois, Indiana and western Kentucky.

lignite: The lowest rank of coal. It is brownish-black with a high moisture content commonly above 35% by weight and heating value commonly less than 8,000 Btu.

longwall mining: A productive underground mining method in the United States. A shearer with two rotating cutting drums trams across the longwall face, cutting the coal and transferring it to an armored chain conveyor. Hydraulic supports hold the roof as the longwall system advances through the coal.

medium sulfur coal: Coal with a sulfur content greater than or equal to 1.0% but less than or equal to 1.5%.

metallurgical coal: The various grades of coal suitable for carbonization to make coke for steel manufacture. Its quality depends on four important criteria: volatility, which affects coke yield; the level of impurities including sulfur and ash, which affects coke quality; composition, which affects coke strength; and basic characteristics, which affect coke oven safety. Metallurgical coal typically has a particularly high Btu but low ash and sulfur content.

natural gas: Hydrocarbon gas found in the earth, composed of methane, ethane, butane, propane and other gasses.

nitrogen oxide: A gas formed in high temperature environments such as coal combustion. It is reported to contribute to ground level ozone and visibility degradation.

non-reserve coal deposits: Non-reserve coal deposits are coal-bearing bodies that have been sufficiently sampled and analyzed in trenches, outcrops, drilling and underground workings to assume continuity between sample points, and therefore warrant further exploration stage work. However, this coal does not qualify as a commercially viable coal reserve as prescribed by standards of the SEC until a final comprehensive evaluation based on unit cost per ton, recoverability and other material factors concludes legal and economic feasibility. Non-reserve coal deposits may be classified as such by either limited property control or geological limitations, or both.

Northern Appalachia: Coal producing area in Ohio, Pennsylvania, Maryland and northern West Virginia.

overburden: Layers of earth and rock covering a coal seam. In surface mining operations, overburden is removed prior to coal extraction.

Pacific market: A term used to described a geographic region of the world where goods are traded and shipped primarily on the Pacific and Indian Oceans.

Pacific Rim: Geographic area surrounding the edges of the Pacific Ocean, including the western shores of North America and South America, Australia, eastern Asia and the islands of the Pacific.

preparation plant: Usually located on a mine site, although one plant may serve several mines. A preparation plant is a facility for crushing, sizing and washing coal to prepare it for use by a particular customer. The washing process separates higher ash coal and may also remove some of the coal's sulfur content.

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.

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.

reclamation: The process of restoring land to its prior condition, productive use or other permitted condition following mining activities. The process commonly includes "recontouring" or reshaping the land to its approximate original appearance, restoring topsoil and planting native grass and shrubs. Reclamation operations are typically conducted concurrently with mining operations. Reclamation is closely regulated by both state and federal laws.

reserve: That part of a mineral deposit that could be economically and legally recovered or produced at the time of the reserve determination.

room and pillar mining: A system of coal mining commonly used in the U.S. in which rooms are driven off the entries with pillars of coal left standing between them for temporary or permanent roof support.

Severance tax: A tax imposed on the removal of a natural resource, such as crude oil or coal.

SMCRA: The Surface Mining Control and Reclamation Act of 1977, as amended.

subsidence: Lateral or vertical movement of surface land that occurs when the roof of an underground mine collapses. Longwall mining causes planned subsidence by the mining out of coal that supports the overlying strata.

sulfur: One of the elements present in varying quantities in coal that contributes to environmental degradation when coal is burned. Sulfur dioxide is produced as a gaseous by-product of coal combustion.

surface mine: A mine in which the coal lies near the surface and can be extracted by removing the covering layer of soil overburden. Surface mines are also known as open-pit mines.

thermal coal: Coal used by power plants and industrial steam boilers to produce electricity or process steam. It generally is lower in Btu heat content and higher in volatile matter than metallurgical coal. It is also commonly referred to as "steam coal."

tons: A "short" or net ton is equal to 2,000 pounds. A "long" or British ton is 2,240 pounds. A "metric" ton is approximately 2,205 pounds. The short ton is the unit of measure referred to in this

prospectus, unless otherwise stated. A "clean" ton is a produced ton that has undergone requisite cleaning and preparation processes.

Treasury Regulations: The existing and proposed regulations promulgated by the U.S. Treasury Department under the Code.

Uinta Basin: Coal producing area located in western Colorado and eastern Utah.

volatile matter: Combustible matter which is vaporized in the combustion process. Power plant boilers are designed to burn coal containing specific amounts of volatile matter.

Western Bituminous region: Coal producing area located in western Colorado and eastern Utah.

Western United States: Coal producing area that includes the Powder River Basin, the Western Bituminous region, the Four Corners area and the Uinta Basin.

Until , 2015 (25 days after the commencement of this offering), all dealers that effect transactions in these securities, whether or not participating in this offering, may be required to deliver a prospectus. This is in addition to the dealer's obligation to deliver a prospectus when acting as an underwriter and with respect to unsold allotments or subscriptions.

Set forth below are the expenses (other than underwriting discounts) expected to be incurred in connection with the issuance and distribution of the securities registered hereby. With the exception of the SEC registration fee, the FINRA filing fee and the NYSE listing fee the amounts set forth below are estimates.

ITEM 14. INDEMNIFICATION OF OFFICERS AND THE DIRECTORS OF THE BOARD OF DIRECTORS OF OUR GENERAL PARTNER.

The section of the prospectus entitled "The Partnership Agreement—Indemnification" is incorporated herein by reference and discloses that we will generally indemnify the directors and officers of our general partner to the fullest extent permitted by law against all losses, claims, damages or similar events. Subject to any terms, conditions or restrictions set forth in the amended and restated agreement of limited partnership, Section 17-108 of the Delaware Revised Uniform Limited Partnership Act empowers a Delaware limited partnership to indemnify and hold harmless any partner or other person from and against all claims and demands whatsoever.

Section 18-108 of the Delaware Limited Liability Company Act provides that a Delaware limited liability company may indemnify and hold harmless any member or manager or other person from and against any and all claims and demands whatsoever. The limited liability company agreement of Bowie GP, LLC, our general partner, provides for the indemnification of its directors and officers against liabilities they incur in their capacities as such. We may enter into indemnity agreements with each of the current directors and officers of our general partner to give these directors and officers additional contractual assurances regarding the scope of the indemnification set forth in our general partner's limited liability company agreement and to provide additional procedural protections.

The underwriting agreement that we expect to enter into with the underwriters, to be filed as Exhibit 1.1 to this registration statement, will contain indemnification and contribution provisions that will indemnify and hold harmless the director and officers of our general partner.

In connection with our formation in January 2015, we issued (i) the non-economic general partner interest in us to Bowie GP, LLC and (ii) the 100.0% limited partner interest in us to Bowie Resource Holdings, LLC for $100.00. These issuances were exempt from registration under Section 4(2) of the Securities Act. There have been no other sales of unregistered securities within the past three years.

See the Exhibit Index on the page immediately preceding the exhibits for a list of exhibits filed as part of this registration statement on Form S-1, which Exhibit Index is incorporated herein by reference.

The undersigned Registrant hereby undertakes to provide to the underwriters at the closing specified in the underwriting agreement certificates in such denominations and registered in such names as required by the underwriters to permit prompt delivery to each purchaser.

Insofar as indemnification for liabilities arising under the Securities Act may be permitted to directors, officers and controlling persons of the Registrant pursuant to the provisions described in Item 14 above, or otherwise, the Registrant has been advised that in the opinion of the Securities and Exchange Commission such indemnification is against public policy as expressed in the Securities Act and is, therefore, unenforceable. In the event that a claim for indemnification against such liabilities (other than the payment by the Registrant of expenses incurred or paid by a director, officer or controlling person of the Registrant in the successful defense of any action, suit or proceeding) is asserted by such director, officer or controlling person in connection with the securities being registered, the Registrant will, unless in the opinion of its counsel the matter has been settled by controlling precedent, submit to a court of appropriate jurisdiction the question whether such indemnification by it is against public policy as expressed in the Securities Act and will be governed by the final adjudication of such issue.

The undersigned registrant hereby undertakes that, for the purpose of determining liability of the registrant under the Securities Act to any purchaser in the initial distribution of the securities, in a primary offering of securities of the undersigned registrant pursuant to this registration statement, regardless of the underwriting method used to sell the securities to the purchaser, if the securities are offered or sold to such purchaser by means of any of the following communications, the undersigned registrant will be a seller to the purchaser and will be considered to offer or sell such securities to such purchaser:

(1) Any preliminary prospectus or prospectus of the undersigned registrant relating to the offering required to be filed pursuant to Rule 424;

(2) Any free writing prospectus relating to the offering prepared by or on behalf of the undersigned registrant or used or referred to by the undersigned registrant;

(3) The portion of any other free writing prospectus relating to the offering containing material information about the undersigned registrant or its securities provided by or on behalf of the undersigned registrant; and

(4) Any other communication that is an offer in the offering made by the undersigned registrant to the purchaser.

(1) For purposes of determining any liability under the Securities Act, the information omitted from the form of prospectus filed as part of this Registration Statement in reliance upon Rule 430A and contained in a form of prospectus filed by the Registrant pursuant to Rule 424(b)(1) or (4) or 497(h) under the Securities Act shall be deemed to be part of this Registration Statement as of the time it was declared effective;

(2) For the purpose of determining any liability under the Securities Act, each post-effective amendment that contains a form of prospectus shall be deemed to be a new registration statement relating to the securities offered therein, and the offering of such securities at the time shall be deemed to be the initial bona fide offering thereof; and

(3) For purposes of determining any liability under the Securities Act, each prospectus filed pursuant to Rule 424(b) as part of a registration statement relating to an offering, other than registration statements relying on Rule 430B or other than prospectuses filed in reliance on Rule 430A, shall be deemed to be part of and included in the registration statement as of the date it is first used after effectiveness. Provided, however, that no statement made in a registration statement or prospectus that is part of the registration statement or made in a document incorporated or deemed incorporated

by reference into the registration statement or prospectus that is part of the registration statement will, as to a purchaser with a time of contract of sale prior to such first use, supersede or modify any statement that was made in the registration statement or prospectus that was part of the registration statement or made in any such document immediately prior to such date of first use.

The Registrant undertakes to send to each limited partner at least on an annual basis a detailed statement of any transactions with Bowie GP, LLC, our general partner, or any of its affiliates, and of fees, commissions, compensation and other benefits paid, or accrued to, Bowie Resource Partners LP or its affiliates for the fiscal year completed, showing the amount paid or accrued to each recipient and the services performed.

The Registrant undertakes to provide to the limited partners the financial statements required by Form 10-K for the first full fiscal year of operations of the Partnership.

Pursuant to the requirements of the Securities Act of 1933, as amended, the registrant has duly caused this Registration Statement to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Louisville, State of Kentucky, on June 19, 2015.

Each person whose signature appears below appoints Johannes H. Dreyer, James J. Wolff, and Brian S. Settles, and each of them, any of whom may act without the joinder of the other, as his or her true and lawful attorneys-in-fact and agents, with full power of substitution and re-substitution, for him or her and in his or her name, place and stead, in any and all capacities, to sign any and all amendments (including post-effective amendments) to this Registration Statement and any Registration Statement (including any amendment thereto) for this offering that is to be effective upon filing pursuant to Rule 462(b) under the Securities Act of 1933, as amended, and to file the same, with all exhibits thereto, and all other documents in connection therewith, with the Securities and Exchange Commission, granting unto said attorneys-in-fact and agents full power and authority to do and perform each and every act and thing requisite and necessary to be done, as fully to all intents and purposes as he might or would do in person, hereby ratifying and confirming all that said attorneys-in-fact and agents or any of them of their or his or her substitute and substitutes, may lawfully do or cause to be done by virtue hereof.

Pursuant to the requirements of the Securities Act of 1933, as amended, this Registration Statement has been signed below by the following persons in the capacities and the dates indicated.

		Description

1.1	*	Form of Underwriting Agreement
2.1	†	Asset Purchase and Sale Agreement by and between Fossil Rock Fuels, LLC and Fossil Rock Resources, LLC, dated as of December 12, 2014
2.2		Amendment No. 1 to Asset Purchase and Sale Agreement by and between Fossil Rock Fuels, LLC and Fossil Rock Resources, LLC, dated as of June 5, 2015
3.1		Certificate of Limited Partnership of Bowie Resource Partners LP
3.2	*	Form of Amended and Restated Limited Partnership Agreement of Bowie Resource Partners LP (included as Appendix A in the prospectus included in this Registration Statement)
4.1	*	Form of Registration Rights Agreement
4.2	*	Form of Indenture, by and among the Issuers, the Guarantors and , as Trustee
5.1		Form of Opinion of Vinson & Elkins L.L.P. as to the legality of the securities being registered
8.1		Form of Opinion of Vinson & Elkins L.L.P. relating to tax matters
10.1	*	Form of Contribution Agreement
10.2		Form of Bowie Resource Partners LP Long-Term Incentive Plan
10.3	*	Form of Credit Agreement, by and among Bowie Resource Partners, LP, , as administrative agent and the Lenders party thereto
10.4		Form of Omnibus Agreement
10.5		Form of Coal Supply Agreement by and among BRP Holdings LLC, Canyon Fuel Company, LLC, Fossil Rock Resources, LLC and Bowie Coal Sales, LLC
10.6	*	Form of Coal Services Agreement by and among Trafigura AG, BRP Holdings LLC, Canyon Fuel Company, LLC, Fossil Rock Resources, LLC and Bowie Coal Sales, LLC
10.7		Form of Bowie Refined Coal Agreement
10.8		Repayment Agreement (Quitchupah Road), dated as of April 12, 2012 by and between the Sevier Special Service Districts and Canyon Fuel Company, LLC
21.1		List of Subsidiaries of Bowie Resource Partners LP
23.1		Consent of Norwest Corporation
23.2		Consent of Wood Mackenzie Inc.
23.3		Consent of Coulter & Justus, PC
23.4		Consents of Ernst & Young LLP
23.5		Consent of Vinson & Elkins L.L.P. (contained in Exhibit 5.1)
23.6		Consent of Vinson & Elkins L.L.P. (contained in Exhibit 8.1)
24.1		Powers of Attorney (included on page II-4)
99.1		Consent of Director Nominee, John DeRosa
99.2		Consent of Director Nominee, Jesus Fernandez
99.3		Consent of Director Nominee, Carlos Pons
99.4		Consent of Director Nominee, Steve Rickmeier


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

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

	Per Common Unit	Total

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


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


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


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


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


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)		$

	Unit Acquired			Total Consideration

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

		(in thousands)

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

	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		$	$		$	$

		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		$

	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	$	$	$	$

		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	%

			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 $

		$	$	$	$	$


Brean Capital

	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

	Successor

	Three Months Ended March 31, 2014		Three Months Ended March 31, 2015		Increase/ (Decrease) $			Increase/ (Decrease) %
	(in thousands, except per ton data)
Coal sales	$	112,265	$	103,924	$	(8,341	)		(7	)%
Tons sold		3,175		2,691		(484	)		(15	)%
Coal sales realized per ton(4)	$	35.36	$	38.62	$	3.26			9	%

	Total		Less than 1 Year		1 - 3 Years		4 - 5 Years		More than 5 Years

	(in thousands)
Long-term debt(1)	$	387,035	$	52,418	$	45,809	$	60,237	$	228,571
Coal leases and royalties(2)		4,034		642		928		797		1,667
Other leases(3)		573		573		—		—		—

Total(4)	$	391,642	$	53,633	$	46,737	$	61,034	$	230,238

Area	Start Date	Finish Date	Coal Seam

West Lease	February 2015	September 2017	Upper Hiawatha
Quitchupah	February 2017	September 2021	Upper Hiawatha
Greens Hollow(1)	December 2020	August 2033	Lower Hiawatha

Origination	Destination

Sufco	Hunter Power Plant	39
Sufco	Huntington Power Plant	62
Sufco	IPA Power Plant	120
Sufco	Savage Energy Terminal	71

Area	Start Date	Finish Date	Coal Seam

North of Graben 1	January 2010	April 2017	Lower O'Connor A
South of Graben 2	October 2016	May 2018	Lower O'Connor A
Flat Canyon tract(1)	July 2017	January 2029	Lower O'Connor A
			Lower O'Connor B
			Flat Canyon

Area	Start Date	Finish Date	Coal Seam

Rock Canyon	February 2013	December 2020	Rock Canyon
Gilson North 4	June 2020	July 2026	Gilson
North West 8	February 2024	March 2034	Gilson

	Proven Reserves				Probable Reserves

	Proven Reserves				Probable Reserves						Btu per pound(2)
Mine	Assigned		Unassigned		Assigned		Unassigned		Total(1)		Btu per pound(2)		Sulfur (%)
	(in millions of tons)
Sufco		18.7		14.3		16.8		11.4		61.2		10,916		0.43
Skyline(3)		32.5		0.9		21.1		0.3		54.8		11,542		0.44
Dugout Canyon		9.2		1.5		1.2		0.4		12.3		11,844		0.80
Fossil Rock(4)		11.2		—		29.1		3.4		43.7		11,550		0.57

		Total all mines								172.0

	Contracted Position Minimum/Maximum(2)								Projected Coal Sales(3)

	Contracted Position Minimum/Maximum(2)								Projected Coal Sales(3)								Contract Expiration
Customer(1)	2015		2016		2017		2018		2015(3)		2016		2017		2018		Contract Expiration
	(million tons)								(million tons)
PacifiCorp: Hunter		2.5–4.5		2.5–4.5		2.5–4.5		2.5–4.5		3.8		3.5		4.1		4.0		2020
PacifiCorp: Huntington(4)		2.0–3.0		2.0–3.0		2.0–3.0		2.0–3.0		1.8		2.1		2.5		2.5		2029
IPA Contract No 1		2.0–2.2		2.0		2.0		2.0		2.0		2.0		2.0		2.0		2024
IPA Contract No 2(5)		0.5–1.0		0.5–1.0		0.5–1.0		0.5–1.0		0.31		0.75		0.75		0.75		2024

Total		7.0–10.7		7.0–10.5		7.0–10.5		7.0–10.5		7.91		8.35		9.35		9.25

Electric Generation Type	2012		2013		2014		2015 (Est.)

Distillate Fuel Oil	$	23.76	$	24.04	$	23.56	$	17.19
Residual Fuel Oil	$	20.52	$	18.89	$	20.32	$	11.87
Natural Gas	$	3.47	$	4.40	$	5.12	$	4.54
Coal	$	2.37	$	2.34	$	2.31	$	2.34

End of Use Market

Mountain Region	12.6	11.8	10.7	12.2	11.3	(0.9	)%
Export	1.7	4.0	4.4	5.0	4.7	8.8	%
Industrial	1.3	1.3	1.3	1.3	1.3	0.0	%
Other Domestic	0.8	0.8	2.0	2.2	0.4	(5.1	)%

Total Utah Demand	16.4	17.9	18.4	20.7	17.8	0.7	%



Electric Power	824	935	921	919
Other Industrial / Buildings	45	50	50	52
Steel Production	21	21	19	18

Total U.S. Coal Consumption	889	1,005	990	988

Region	2015E

	(tons in millions)
Utah(1)		18.4	18.4	20.7	2.4	%
Western Bituminous (including Utah)(1)		77.0	78.2	82.0	1.3	%
Powder River Basin(1)		410.0	399.6	398.9	(0.5	)%
Central Appalachia(1)		52.2	33.9	23.6	(14.7	)%
Northern Appalachia(1)		103.0	95.0	90.7	(2.5	)%
Illinois Basin(1)		118.9	120.1	138.0	3.0	%
Other		71.0	60.4	55.4	(4.9	)%

Total U.S. Coal Production		832.1	787.1	788.5	(1.1	)%


2014–2016 Compound Annual Production Growth		2014–2020 Compound Annual Production Growth

Product Type

Thermal Coal	21	21	22	27	39	22	26	38	56	52
Metallurgical Coal	27	29	28	32	43	37	56	69	70	66

Total U.S. Coal Exports	48	50	50	59	82	59	82	107	126	118


Rights and remedies of unitholders		The Delaware Act generally provides that a limited partner may institute legal action on behalf of the partnership to recover damages from a third party where a general partner has refused to institute the action or where an effort to cause a general partner to do so is not likely to succeed. These actions include actions against a general partner for breach of its duties or of the partnership agreement. In addition, the statutory or case law of some jurisdictions may permit a limited partner to institute legal action on behalf of himself and all other similarly situated limited partners to recover damages from a general partner for violations of its fiduciary duties to the limited partners.


Transfer of incentive distribution rights		No approval right. Please read "—Transfer of Subordinated Units and Incentive Distribution Rights."
Transfer of ownership interests in our general partner		No approval right. Please read "—Transfer of Ownership Interests in the General Partner."

Underwriters		Number of Common Units

Citigroup Global Markets Inc.
Morgan Stanley & Co. LLC
Deutsche Bank Securities Inc.
UBS Securities LLC
Credit Suisse Securities (USA) LLC
Stifel, Nicolaus & Company, Incorporated
Brean Capital, LLC

Total


BOWIE RESOURCE PARTNERS LP
Unaudited Pro Forma Condensed Consolidated Financial Statements
Introduction		F-2
Unaudited Pro Forma Condensed Consolidated Interim Balance Sheet as of March 31, 2015		F-4
Unaudited Pro Forma Condensed Consolidated Interim Statement of Comprehensive (Loss) Income for the Three Months Ended March 31, 2015		F-5
Unaudited Pro Forma Condensed Consolidated Statement of Comprehensive (Loss) Income for the Year Ended December 31, 2014		F-6
Notes to Unaudited Pro Forma Condensed Consolidated Financial Statements		F-7
Consolidated Balance Sheet
Report of Independent Registered Public Accounting Firm		F-8
Consolidated Balance Sheet as of March 31, 2015		F-9
Notes to Consolidated Balance Sheet		F-10
CANYON FUEL COMPANY, LLC (PREDECESSOR)
Historical Audited Financial Statements for the Years Ended December 31, 2014 and 2013
Reports of Independent Registered Public Accounting Firms		F-11
Balance Sheets		F-14
Statements of Operations and Comprehensive (Loss) Income		F-15
Statements of Member's Equity		F-16
Statements of Cash Flows		F-17
Notes to Audited Financial Statements		F-18
Unaudited Historical Condensed Interim Financial Statements for the Three Months Ended March 31, 2015 and 2014
Balance Sheets		F-44
Statements of Operations and Comprehensive (Loss) Income		F-45
Statements of Cash Flows		F-46
Notes to Condensed Interim Financial Statements		F-47

	March 31, 2015

Assets	$	—



Liabilities and partners' capital
Total liabilities		—
Partners' capital:
Limited partners		100
General partner		—
Less: contribution receivable from partners		(100	)

Total partners' capital		—

Total liabilities and partners' capital	$	—