S-1 1 d896459ds1.htm FORM S-1 FORM S-1
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As filed with the Securities and Exchange Commission on April 1, 2015

Registration No. 333-            

 

 

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

 

Form S-1

REGISTRATION STATEMENT

UNDER

THE SECURITIES ACT OF 1933

 

 

CNX Coal Resources LP

(Exact Name of Registrant as Specified in Its Charter)

 

 

 

Delaware

(State or Other Jurisdiction of

Incorporation or Organization)

1220

(Primary Standard Industrial

Classification Code Number)

47-3445032

(I.R.S. Employer

Identification Number)

1000 CONSOL Energy Drive

Canonsburg, Pennsylvania 15317

(724) 485-4000

(Address, Including Zip Code, and Telephone Number, including Area Code, of Registrant’s Principal Executive Offices)

 

 

Lorraine L. Ritter

Chief Financial Officer and Chief Accounting Officer

1000 CONSOL Energy Drive

Canonsburg, Pennsylvania 15317

(724) 485-4000

(Name, Address, Including Zip Code, and Telephone Number, Including Area Code, of Agent for Service)

 

 

Copies to:

 

Brett E. Braden

Latham & Watkins LLP

811 Main Street, Suite 3700

Houston, Texas 77002

(713) 546-5400

David P. Oelman

Douglas E. McWilliams

Vinson & Elkins L.L.P.

1001 Fannin, Suite 2500

Houston, Texas 77002

(713) 758-2222

 

 

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, check the following box.   ¨

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.   ¨

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.   ¨

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.   ¨

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 the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

 

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

 

 

CALCULATION OF REGISTRATION FEE

 

 

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

Common units representing limited partner interests

$250,000,000 $29,050

 

 

(1) Includes common units issuable upon the exercise of the underwriters’ option to purchase additional common units.
(2) Estimated solely for the purpose of calculating the amount of the registration fee in accordance with Rule 457(o) under the Securities Act of 1933, as amended.

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 of 1933 or until the Registration Statement shall become effective on such date as the Securities and Exchange Commission, acting pursuant to said Section 8(a), may determine.

 

 

 


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The information in this 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 is effective. This prospectus is not an offer to sell these securities and it is not soliciting an offer to buy these securities in any jurisdiction where the offer or sale is not permitted.

 

Subject to Completion

Preliminary Prospectus dated                     , 2015

PROSPECTUS

[LOGO]

             Common Units

Representing Limited Partner Interests

CNX Coal Resources LP

 

 

This is the initial public offering of common units representing limited partner interests in CNX Coal Resources LP. We were recently formed by CONSOL Energy Inc. (“CONSOL Energy” or our “sponsor”). We are offering          common units in this offering. We expect that the initial public offering price will be between $         and $         per common unit.

Prior to this offering, there has been no public market for our common units. We intend to apply to list our common units on the New York Stock Exchange under the symbol “CNXC.” We are an “emerging growth company” as that term is used in the Jumpstart Our Business Startups Act.

Investing in our common units involves a high degree of risk. Please read “Risk Factors” beginning on page 20. These risks include the following:

 

    We may not generate sufficient distributable cash flow to support the payment of the minimum quarterly distribution to our unitholders.

 

    The assumptions and estimates underlying the forecast of adjusted EBITDA and distributable cash flow that we include 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 our actual adjusted EBITDA and distributable cash flow to differ materially from our forecast.

 

    Our growth strategy primarily depends on us acquiring additional undivided interests in the Pennsylvania mining complex from our sponsor.

 

    Our general partner and its affiliates, including our sponsor, have conflicts of interest with us and limited fiduciary duties to us and our unitholders, and they may favor their own interests to our detriment and that of our unitholders. Additionally, we have no control over the business decisions and operations of our sponsor, and our sponsor is under no obligation to adopt a business strategy that favors us.

 

    Our partnership agreement replaces our general partner’s fiduciary duties to holders of our common units with contractual standards governing its duties.

 

    Unitholders have very limited voting rights and, even if they are dissatisfied, they will have limited ability to remove our general partner.

 

    Our tax treatment depends on our status as a partnership for U.S. federal income tax purposes. If the Internal Revenue Service were to treat us as a corporation for U.S. federal income tax purposes, which would subject us to entity-level taxation, or if we were otherwise subjected to a material amount of additional entity-level taxation, then our distributable cash flow to our unitholders would be substantially reduced.

 

    Our unitholders’ allocated share of our income will be taxable to them for federal income tax purposes even if they do not receive any cash distributions from us.

 

 

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.

 

    

Per Common Unit

      

Total

 

Public offering price

   $           $     

Underwriting discount

   $           $     

Proceeds, before expenses, to CNX Coal Resources LP

   $           $     

We have granted the underwriters a 30-day option to purchase up to an additional             common units from us at the initial public offering price, less the underwriting discount, if the underwriters sell more than             common units in this offering.

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

 

 

 

BofA Merrill Lynch   Wells Fargo Securities

 

 

The date of this prospectus is                     , 2015.


Table of Contents

[Inside Cover Art]


Table of Contents

TABLE OF CONTENTS

 

    

Page

 

PROSPECTUS SUMMARY

     1   

Overview

     1   

Our Initial Assets

     3   

Competitive Strengths

     4   

Business Strategies

     6   

Our Relationship with CONSOL Energy

     7   

Our Emerging Growth Company Status

     8   

Risk Factors

     9   

The Transactions

     9   

Ownership and Organizational Structure

     10   

Management of CNX Coal Resources LP

     11   

Principal Executive Offices and Internet Address

     12   

Summary of Conflicts of Interest and Duties

     12   

The Offering

     13   

Summary Historical and Pro Forma Financial and Operating Data

     18   

RISK FACTORS

     20   

Risks Related to Our Business

     20   

Risks Related to Environmental, Health, Safety and Other Regulations

     35   

Risks Inherent in an Investment in Us

     38   

Tax Risks

     48   

USE OF PROCEEDS

     54   

CAPITALIZATION

     55   

DILUTION

     56   

CASH DISTRIBUTION POLICY AND RESTRICTIONS ON DISTRIBUTIONS

     58   

General

     58   

Our Minimum Quarterly Distribution

     60   

Unaudited Pro Forma Adjusted EBITDA and Distributable Cash Flow for the Year Ended December 31, 2014

     62   

Estimated Adjusted EBITDA and Distributable Cash Flow for the Twelve Months Ending June 30, 2016

     65   

Significant Forecast Assumptions

     67   

PROVISIONS OF OUR PARTNERSHIP AGREEMENT RELATING TO CASH DISTRIBUTIONS

     72   

Distributions of Available Cash

     72   

Operating Surplus and Capital Surplus

     73   

Capital Expenditures

     75   

Subordinated Units and Subordination Period

     77   

Distributions of Available Cash from Operating Surplus During the Subordination Period

     79   

Distributions of Available Cash from Operating Surplus After the Subordination Period

     80   

General Partner Interest and Incentive Distribution Rights

     80   

Percentage Allocations of Available Cash from Operating Surplus

     81   

General Partner’s Right to Reset Incentive Distribution Levels

     81   

Distributions from Capital Surplus

     84   

Adjustment to the Minimum Quarterly Distribution and Target Distribution Levels

     85   

Distributions of Cash Upon Liquidation

     85   

SELECTED HISTORICAL AND PRO FORMA FINANCIAL AND OPERATING DATA

     89   

Non-GAAP Financial Measure

     91   

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

     92   

Overview

     92   

 

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Page

 

How We Evaluate Our Operations

     92   

Factors That Affect Our Results

     94   

Results of Operations

     97   

Capital Resources and Liquidity

     99   

Off-Balance Sheet Arrangements

     101   

Critical Accounting Policies

     101   

Contingencies and Significant Contractual Obligations

     103   

Quantitative and Qualitative Disclosure about Market Risk

     104   

INDUSTRY

     105   

Overview

     105   

Coal Mining Methods

     106   

Coal Quality Characteristics

     107   

Transportation

     107   

Coal Consumption and Demand

     108   

Coal Industry Trends

     112   

Coal Production and Supply

     115   

BUSINESS

     117   

Overview

     117   

Our Initial Assets

     118   

Competitive Strengths

     120   

Business Strategies

     122   

Our Relationship with CONSOL Energy

     124   

Our Operations

     125   

Transportation Logistics and Infrastructure

     127   

Our Operating Agreement with CONSOL Energy

     128   

Our Employee Services Agreement with CONSOL Energy

     129   

Our Contract Agency Agreement with CONSOL Energy

     130   

Our Terminal and Throughput Agreement with CONSOL Energy

     130   

Coal Reserves

     131   

Our Customers and Contracts

     134   

Seasonality

     136   

Competition

     136   

Our Safety and Environmental Programs and Procedures

     136   

Laws and Regulations

     137   

Health and Safety Laws

     142   

Permit Requirements

     142   

Employees

     143   

Insurance

     143   

Title to Our Properties

     143   

Legal Proceedings

     144   

MANAGEMENT

     145   

Management of CNX Coal Resources LP

     145   

Director Independence

     145   

Committees of the Board of Directors

     146   

Directors and Executive Officers of CNX Coal Resources GP LLC

     146   

Board Leadership Structure

     148   

Board Role in Risk Oversight

     148   

Reimbursement of Expenses

     148   

Compensation of Our Officers and Directors

     149   

Our Long-Term Incentive Plan

     149   

SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

     153   

 

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CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

     155   

Distributions and Payments to Our General Partner and Its Affiliates

     155   

Agreements Governing the Transactions

     157   

Procedures for Review, Approval and Ratification of Related Person Transactions

     161   

CONFLICTS OF INTEREST AND DUTIES

     162   

Conflicts of Interest

     162   

Duties of Our General Partner

     169   

DESCRIPTION OF OUR COMMON UNITS

     172   

Our Common Units

     172   

Transfer Agent and Registrar

     172   

Transfer of Common Units

     172   

Exchange Listing

     173   

OUR PARTNERSHIP AGREEMENT

     174   

Organization and Duration

     174   

Purpose

     174   

Capital Contributions

     174   

Voting Rights

     175   

Limited Liability

     176   

Issuance of Additional Partnership Interests

     177   

Amendment of Our Partnership Agreement

     178   

Merger, Consolidation, Conversion, Sale or Other Disposition of Assets

     180   

Termination and Dissolution

     181   

Liquidation and Distribution of Proceeds

     181   

Withdrawal or Removal of Our General Partner

     181   

Transfer of General Partner Interest

     182   

Transfer of Ownership Interests in Our General Partner

     183   

Transfer of Incentive Distribution Rights

     183   

Change of Management Provisions

     183   

Limited Call Right

     183   

Possible Redemption of Ineligible Holders

     184   

Meetings; Voting

     185   

Status as Limited Partner

     186   

Indemnification

     186   

Reimbursement of Expenses

     186   

Books and Reports

     187   

Right to Inspect Our Books and Records

     187   

Registration Rights

     187   

Applicable Law; Exclusive Forum

     188   

UNITS ELIGIBLE FOR FUTURE SALE

     189   

Rule 144

     189   

Our Partnership Agreement and Registration Rights

     189   

Lock-Up Agreements

     190   

Registration Statement on Form S-8

     190   

MATERIAL FEDERAL INCOME TAX CONSEQUENCES

     191   

Partnership Status

     192   

Limited Partner Status

     193   

Tax Consequences of Unit Ownership

     193   

Tax Treatment of Operations

     199   

Disposition of Common Units

     203   

Uniformity of Units

     205   

Tax-Exempt Organizations and Other Investors

     206   

 

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Administrative Matters

     207   

Recent Legislative Developments

     210   

State, Local, Foreign and Other Tax Considerations

     211   

INVESTMENT IN CNX COAL RESOURCES LP BY EMPLOYEE BENEFIT PLANS

     212   

UNDERWRITING

     214   

Commissions and Discounts

     214   

Option to Purchase Additional Common Units

     215   

No Sales of Similar Securities

     215   

New York Stock Exchange Listing

     215   

Price Stabilization, Short Positions and Penalty Bids

     216   

Electronic Distribution

     217   

Directed Unit Program

     217   

Other Relationships

     217   

Notice to Prospective Investors in Australia

     217   

Notice to Prospective Investors in Hong Kong

     218   

VALIDITY OF THE COMMON UNITS

     219   

EXPERTS

     219   

WHERE YOU CAN FIND ADDITIONAL INFORMATION

     220   

FORWARD-LOOKING STATEMENTS

     221   

INDEX TO FINANCIAL STATEMENTS

     F-1   

FORM OF FIRST AMENDED AND RESTATED AGREEMENT OF LIMITED PARTNERSHIP OF CNX COAL RESOURCES LP

     A-1   

GLOSSARY OF TERMS

     B-1   

You should rely only on the information contained in this prospectus or in any free writing prospectus prepared by us or on behalf of us or to which we have referred you. We have not, and the underwriters have not, authorized any other person to provide you with information different from that contained in this prospectus and any free writing prospectus. If anyone provides you with different or inconsistent information, you should not rely on it. We are not, and the underwriters are not, making an offer to sell these securities in any jurisdiction where an offer or sale is not permitted. The information in this prospectus is accurate only as of the date of this prospectus, regardless of the time of delivery of this prospectus or any sale of our common units. Our business, financial condition, results of operations and prospects may have changed since that date.

Through and including                     , 2015 (the 25th day after the date of this prospectus), federal securities laws may require all dealers that effect transactions in these securities, whether or not participating in this offering, to deliver a prospectus. This requirement is in addition to a dealer’s obligation to deliver a prospectus when acting as an underwriter and with respect to an unsold allotment or subscription.

This prospectus contains forward-looking statements that are subject to a number of risks and uncertainties, many of which are beyond our control. Please read “Risk Factors” and “Forward-Looking Statements.”

 

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Coal Reserve Information

The estimates of our proven and probable reserves are derived from estimates calculated by CONSOL Energy’s geologists and mining engineers, which estimates were audited by Golder Associates Inc., an independent mining and geological consulting firm, in 2014 and subsequently updated in 2015 using the face positions of the Pennsylvania mining complex’s longwall mines as of December 31, 2014. These estimates are based on geologic data, coal ownership information and current and proposed mine plans. Our proven and probable coal reserves are reported as “recoverable coal reserves,” which is the portion of the coal that could be economically and legally extracted or produced at the time of the reserve determination, taking into account mining recovery and preparation plant yield. These estimates are periodically updated to reflect past coal production, new drilling information and other geologic or mining data. Acquisitions or dispositions 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 changes in preparation plant processes.

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

 

    Proven (Measured) Reserves. Reserves for which (a) quantity is computed from dimensions revealed in outcrops, trenches, workings or drill holes; and grade and/or quality are computed from the results of detailed sampling and (b) the sites for inspection, sampling and measurement are spaced so closely and the geologic character is so well defined that size, shape, depth and mineral content of reserves are well-established.

 

    Probable (Indicated) Reserves.” Reserves for which quantity and grade and/or quality are computed from information similar to that used for proven (measured) reserves, but the sites for inspection, sampling, and measurement are farther apart or are otherwise less adequately spaced. The degree of assurance, although lower than that for proven (measured) reserves, is high enough to assume continuity between points of observation.

Please read “Business—Coal Reserves” for additional information regarding our reserves.

Industry and Market Data

The data included in this prospectus regarding the coal industry, including descriptions of trends in the market, as well as our position within the industry, is based on a variety of sources, including independent industry publications, government publications and other published independent sources, information obtained from customers, distributors, suppliers, trade and business organizations and publicly available information, as well as our good faith estimates, which have been derived from management’s knowledge and experience in our industry. Although we have not independently verified the accuracy or completeness of the third-party information included in this prospectus, based on management’s knowledge and experience, we believe that the third-party sources are reliable and that the third-party information included in this prospectus or in our estimates is accurate and complete. Please read “Industry” for additional information regarding the coal industry.

 

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Certain Terms Used in This Prospectus

Unless the context otherwise requires, references in this prospectus to the following terms have the meanings set forth below:

 

    “Conrhein” refers to Conrhein Coal Company, a Pennsylvania general partnership and a wholly owned subsidiary of CONSOL Energy;

 

    “CNX Coal Resources LP,” “our partnership,” “we,” “our,” “us” and similar terms, when used in a historical context, refer to our predecessor for accounting purposes as described in the final bullet below. When used in the present tense or future tense, these terms refer to CNX Coal Resources LP, a Delaware limited partnership, and its subsidiaries;

 

    “CONSOL Energy” and our “sponsor” refer to CONSOL Energy Inc., a Delaware corporation and the parent of our general partner, and its subsidiaries other than our general partner, us and our subsidiaries;

 

    “CPCC” refers to CONSOL Pennsylvania Coal Company LLC, a Delaware limited liability company and a wholly owned subsidiary of CONSOL Energy;

 

    our “general partner” refers to CNX Coal Resources GP LLC, a Delaware limited liability company and our general partner;

 

    the “Pennsylvania mining complex” refers to CONSOL Energy’s mining complex, including coal mines, coal reserves and related assets and operations, located primarily in southwestern Pennsylvania that are currently owned and operated by CPCC and Conrhein and in which CONSOL Energy will contribute to us a 20% undivided interest in the assets, liabilities, revenues and expenses in connection with the completion of this offering; and

 

    our “Predecessor” refers to our predecessor for accounting purposes, which reflects a 20% undivided interest in the assets, liabilities, revenues and expenses comprising the Pennsylvania mining complex that are currently held by CPCC and Conrhein.

In addition, we have provided definitions for some of the terms we use to describe our business and industry and other terms used in this prospectus in the “Glossary of Terms” beginning on page B-1 of this prospectus.

 

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PROSPECTUS SUMMARY

This summary highlights selected information contained elsewhere in this prospectus. You should carefully read the entire prospectus, including “Risk Factors” and the historical audited annual and unaudited pro forma combined financial statements and related notes included elsewhere in this prospectus before making an investment decision. Unless otherwise indicated, the information in this prospectus assumes (i) 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 (ii) that the underwriters do not exercise their option to purchase additional common units. You should read “Risk Factors” beginning on page 20 for more information about important factors that you should consider before purchasing our common units.

Unless otherwise indicated, the operational and reserve information set forth in this prospectus reflect the Pennsylvania mining complex on a 100% basis. In connection with the completion of this offering, CONSOL Energy will contribute to us a 20% undivided interest in the assets, liabilities, revenues and expenses comprising the Pennsylvania mining complex. Please read “—The Transactions.”

CNX Coal Resources LP

Overview

We are a growth-oriented master limited partnership recently formed by CONSOL Energy to manage and further develop all of its active thermal coal operations in Pennsylvania. Our initial assets include a 20% undivided interest in, and operational control over, CONSOL Energy’s Pennsylvania mining complex, which consists of three underground mines and related infrastructure that produce high-Btu bituminous thermal coal that is sold primarily to electric utilities in the eastern United States, our core market. We believe that our ability to efficiently produce and deliver large volumes of high-quality coal at competitive prices, the strategic location of our mines, the industry experience of our management team and our relationship with CONSOL Energy position us as a leading producer of high-Btu thermal coal in the Northern Appalachian Basin and the eastern United States.

The Pennsylvania mining complex, which includes the Bailey mine, the Enlow Fork mine and the newly opened Harvey mine, has extensive high-quality coal reserves. We mine our reserves from the Pittsburgh No. 8 Coal Seam, which is a large contiguous formation of uniform, high-Btu thermal coal that is ideal for high productivity, low-cost longwall operations. As of December 31, 2014, the Pennsylvania mining complex included 785.6 million tons (157.1 million tons net to our 20% interest on a pro forma basis) of proven and probable coal reserves with an average gross heat content of approximately 13,000 Btus per pound and an average sulfur content of 2.38%. Based on our current production capacity, these reserves are sufficient to support over 27 years of production. In addition, all of our reserves exhibit thermoplastic behavior suitable for cokemaking and contain an average of approximately 39% volatile matter (on a dry basis), which enables us, if market dynamics are favorable, to capture greater margins from selling our coal in the metallurgical market to cokemakers and steel manufacturers who utilize modern cokemaking technologies.

The design of the Pennsylvania mining complex is optimized to produce large quantities of coal on a cost efficient basis. We are able to sustain high production volumes at comparatively low operating costs due to, among other things, CONSOL Energy’s significant investments in technologically advanced longwall mining systems, logistics infrastructure and safety. We currently operate five longwalls and 18 continuous mining sections at the Pennsylvania mining complex. The current production capacity of the Pennsylvania mining complex’s five longwalls is 28.5 million tons of coal per year, and it produced approximately 26.1 million tons (5.2 million tons net to our 20% interest on a pro forma basis) of coal for the year ended December 31, 2014. We also recently upgraded our preparation plant, which is connected via conveyor belts to each of our mines, to clean

 

 

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and process up to 8,200 tons of coal per hour. Our onsite logistics infrastructure at the preparation plant includes a new dual-batch train loadout facility capable of loading up to 9,000 tons of coal per hour and 19.3 miles of track linked to separate Class I rail lines owned by Norfolk Southern and CSX, which enables us to simultaneously accommodate multiple unit trains and significantly increases our efficiency in meeting our customers’ transportation needs.

We believe that we are favorably positioned to compete with coal producers in all four primary coal producing basins in the United States primarily because of: (i) our significant transportation cost advantage compared to producers in the Illinois Basin and the Powder River Basin that incur higher rail transportation rates to deliver coal to our core market in the eastern United States, (ii) our favorable operating environment compared to producers in the Central Appalachian Basin, where production has been declining and is expected to continue to decline primarily due to the basin’s high cost production profile, reserve degradation and difficult permitting environment and (iii) the high-quality characteristics of our coal, which enables us to compete for demand from a broader range of coal-fired power plants compared to mining operations in basins that typically produce coal with a comparatively lower heat content, such as the Illinois Basin and Powder River Basin, mining operations in basins that typically produce coal with a comparatively higher sulfur content, such as the Illinois Basin and most areas in the Northern Appalachian Basin, and mining operations in basins that typically produce coal with a comparatively higher chlorine content, such as the Illinois Basin. For example, our recoverable coal reserves have an average gross heat content of approximately 13,000 Btus per pound and an average sulfur content of 2.38% compared to an average gross heat content of 11,619 Btus per pound and an average sulfur content of 2.74% for other coal master limited partnerships, based on publicly available data. In addition, our logistics infrastructure and proximity to coal-fired power plants in the eastern United States provide us with operational and marketing flexibility, reduce the cost to deliver coal to our core market and allow us to realize higher netback prices. These advantages, combined with our ability to maintain low operating costs, allow us to generate favorable margins in relation to our peers.

We also have favorable access to international coal markets through our long-standing commercial relationship with a leading coal trading and brokering company that maintains a broad market presence with foreign coal consumers and through CONSOL Energy’s Baltimore Marine Terminal. The Baltimore Marine Terminal provides coal transshipments directly from rail cars to ocean-going vessels and is the only coal marine terminal on the East Coast served by two rail lines (Norfolk Southern and CSX). For the years ended December 31, 2013 and 2014, the Pennsylvania mining complex sold (on a 100% basis) approximately 4.2 million tons and 3.3 million tons of coal (or 20% and 13% of total sales), respectively, into international coal markets. Both the thermal coal and metallurgical coal international markets provide us with valuable options for delivering our coal and allow us to optimize our sales portfolio and take advantage of pricing opportunities in the international market as they arise. We believe that projected global growth in both the thermal and metallurgical coal markets will support growing international demand for our coal as well as improved margins for our international sales.

We have a well-established and diverse, blue chip customer base, the majority of which is comprised of domestic utility companies located in the eastern United States. As of March 25, 2015, the Pennsylvania mining complex’s committed and priced contract portfolio, on a 100% basis, comprised 22.3 million tons, 11.8 million tons and 6.7 million tons for the years ending December 31, 2015, 2016 and 2017, respectively, which represents approximately 85.5%, 45.1% and 25.6%, respectively, of total production for the year ended December 31, 2014.

 

 

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Our Initial Assets

Overview

In connection with the completion of this offering, CONSOL Energy will contribute to us a 20% undivided interest in the Pennsylvania mining complex and will enter into an operating agreement with us under which we will manage and operate the Pennsylvania mining complex. Based on our current production capacity utilizing five longwall mining systems, our recoverable reserves are sufficient to support over 27 years of production without the need to spend significant capital to develop new slopes and shafts for initial access to the coal seam.

The following table provides selected information for the Pennsylvania mining complex, on a 100% basis, as of and for the year ended December 31, 2014 (tons in millions):

 

Mine

  

Total Recoverable
Reserves
(tons) (1)(2)

    

Average Gross
Heat Content
(Btu/lb) (3)

    

Average
Sulfur
Content (3)

   

Annual
Production
Capacity (tons) (4)

    

Production
for the Year
Ended
December 31,
2014 (tons) (5)

 

Bailey

     254.5         12,926         2.68     11.5         12.3   

Enlow Fork

     322.8         12,939         2.21     11.5         10.6   

Harvey (6)

     208.3         13,068         2.28     5.5         3.2   
  

 

 

    

 

 

    

 

 

   

 

 

    

 

 

 

Total

  785.6      12,968      2.38   28.5      26.1   
  

 

 

    

 

 

    

 

 

   

 

 

    

 

 

 

 

(1) Recoverable reserves include both proved and probable reserves. Recoverable reserves are calculated based on proposed mine plans in the area in which mineable coal exists, coal seam thickness and average density determined by laboratory testing of drill core samples. This calculation is adjusted to account for coal that will not be recovered during mining and for losses that occur if the coal is processed after mining. Reserve calculations do not include adjustments for moisture that may be added during mining or processing, nor do the calculations include adjustments for dilution from rock lying above or below the coal seam. Reserves are reported only for those coal seams that are controlled by ownership or leases. Please read “Business—Coal Reserves.”
(2) All of our reserves exhibit thermoplastic behavior suitable for cokemaking and contain an average of approximately 39% volatile matter (on a dry basis), which enables us, if market dynamics are favorable, to capture greater margins from selling our coal in the metallurgical market to cokemakers and steel manufacturers who utilize modern cokemaking technologies. For the years ended December 31, 2013 and 2014, the Pennsylvania mining complex sold approximately 2.4 million tons and 1.3 million tons of coal, respectively, in the metallurgical market on a 100% basis.
(3) Average gross heat content and average sulfur content are reported on an as-received basis at the typical moisture content of the coal shipped from the Pennsylvania mining complex.
(4) Annual production capacity is an estimate of the design capacity at the Pennsylvania mining complex and is based on us operating five days per week and running two longwall mining systems at the Bailey mine, two longwall mining systems at the Enlow Fork mine and one longwall mining system at the Harvey mine. We determine the number of longwall mining systems based on the size of the reserves for each mine, access to those reserves and the associated surface infrastructure in place (including the capacity of the preparation plant). In addition, to the extent sales exceed the production capacity of five longwall mining systems, we may, from time to time, (i) run weekend shifts at one or more of our mines and/or (ii) temporarily run an additional longwall mining system at the Bailey mine and/or the Enlow Fork mine to increase our production to meet our forecasted sales commitments. The achievement and timing of full production capacity are subject to multiple risks and uncertainties. Please read “Risk Factors.”
(5)

Due to sales temporarily exceeding the production capacity of running five longwall mining systems, the Bailey mine and/or the Enlow Fork mine ran three longwall mining systems for approximately 14 weeks

 

 

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  during the year ended December 31, 2014 to enable us to increase our production beyond our stated production capacity.
(6) The Harvey mine commenced longwall mining operations in March 2014.

Through our operating agreement with CONSOL Energy, we will manage the operation and further development of the Pennsylvania mining complex. Following the completion of this offering, CONSOL Energy will continue to own an 80% undivided interest in the Pennsylvania mining complex, as well as 100% of our general partner and, indirectly through our general partner, our 2% general partner interest and incentive distribution rights. In addition, CONSOL Energy will own a     % limited partner interest in us (or a     % limited partner interest in us if the underwriters exercise in full their option to purchase additional common units). We believe these retained ownership interests in us and the Pennsylvania mining complex will incentivize CONSOL Energy to promote and support the successful execution of our business strategies and our ability to increase cash distributions per unit over time.

Our Right of First Offer

In connection with the completion of this offering, CONSOL Energy will grant to us a right of first offer to acquire its retained 80% undivided interest in the Pennsylvania mining complex. As a result of our right of first offer, we believe that we possess significant growth potential that will be generated through accretive acquisitions of additional undivided interests in the Pennsylvania mining complex. However, CONSOL Energy is under no obligation to present us the opportunity to purchase additional assets from it (including its retained undivided interest, unless and until it otherwise intends to divest such undivided interest), and we are under no obligation to purchase any assets from CONSOL Energy. While we believe that our right of first offer is a significant positive attribute, it is also a source of potential conflicts of interest. Following the completion of this offering, CONSOL Energy will own our general partner, and there will be substantial overlap between the officers and directors of our general partner and the officers and directors of CONSOL Energy. Please read “Risk Factors—Risks Inherent in an Investment in Us,” “Business—Our Initial Assets—Our Right of First Offer” and “Conflicts of Interest and Duties.”

Competitive Strengths

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

 

    Extensive, high-quality reserve base. The Pennsylvania mining complex has extensive high-quality reserves of high-Btu bituminous coal. As of December 31, 2014, the Pennsylvania mining complex included 785.6 million tons (157.1 million tons net to our 20% interest on a pro forma basis) of proven and probable coal reserves that are sufficient to support over 27 years of production. The advantageous qualities of our coal enables us to compete for demand from a broader range of coal-fired power plants compared to mining operations in basins that typically produce coal with a comparatively lower heat content (the Illinois Basin and Powder River Basin), higher sulfur content (the Illinois Basin and most areas in the Northern Appalachian Basin) and higher chlorine content (the Illinois Basin).

 

   

Strategically located mining operations with advanced distribution capabilities and substantial access to key logistics infrastructure. Our logistics infrastructure and proximity to coal-fired power plants in the eastern United States provide us with operational and marketing flexibility, reduce the cost to deliver coal to our core market and allow us to realize higher netback prices. We believe that we have a significant transportation cost advantage compared to many of our competitors, particularly producers in the Illinois Basin and Powder River Basin, for deliveries to customers in

 

 

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our core market and to East Coast ports for international shipping. For example, based on publicly available data and internal estimates, we believe that the transportation cost from our mines compared to Illinois Basin mines is approximately $13 to $15 per ton lower for coal delivered to the mid-Atlantic region, $9 to $10 per ton lower for coal delivered to the southeastern United States and $16 to $17 per ton lower for coal delivered to East Coast ports for shipping to foreign consumers.

 

    Substantial capital investment in new and existing mines. Since 2006, CONSOL Energy has invested over $2.0 billion at the Pennsylvania mining complex to develop technologically advanced, large-scale longwall mining operations and related production and logistics infrastructure. We believe this recent substantial capital investment in the Pennsylvania mining complex will help us maintain high production volumes, low operating costs and a strong safety and environmental compliance record, which we believe are key to supporting stable financial performance and cash flows throughout business and commodity price cycles.

 

    Strong, well-established customer base. We have a well-established and diverse, blue chip customer base, the majority of which is comprised of domestic utility companies located in the eastern United States. We have had success entering into multi-year coal sales agreements with our customers due to our longstanding relationships, reliability of production, deliverability, competitive pricing and coal quality. In addition, to reduce our exposure to retirements of coal-fired power plants, we have strategically developed our customer base to include power plants that are positioned to continue operating for the foreseeable future and that are equipped with environmental controls for mercury and sulfur abatement. For the year ended December 31, 2014, we sold approximately 19.4 million tons of coal (including more than 16.0 million tons of coal to customers in our core market states of Massachusetts, New Hampshire, New York, New Jersey, Pennsylvania, Maryland, Delaware, West Virginia, North Carolina and South Carolina) to domestic power plants and industrial consumers that have not announced any plans to retire generating capacity prior to 2020 and that have scrubber systems in place or under construction to comply with emissions regulations. We also have favorable access to international coal markets through our long-standing commercial relationship with a leading coal trading and brokering company that maintains a broad market presence with foreign coal consumers.

 

    Our relationship with our sponsor, CONSOL Energy. Through our relationship with CONSOL Energy, we will have access to a significant pool of management talent, deep industry knowledge, strong commercial relationships throughout the coal industry and innovative research and development capability, including CONSOL Energy’s dedicated in-house coal laboratory and extensive expertise with coal-fired boilers. By virtue of CONSOL Energy’s retained 80% undivided interest in the Pennsylvania mining complex, direct ownership of an aggregate     % limited partner interest in us (or an aggregate     % limited partner interest in us if the underwriters exercise in full their option to purchase additional common units) and indirect ownership of our 2% general partner interest and all of our incentive distribution rights, we believe that CONSOL Energy has a vested interest in our success. CONSOL Energy intends for us to manage and further develop the Pennsylvania mining complex, and we believe that it will be incentivized to promote and support the successful execution of our business strategies and our ability to increase cash distributions per unit over time.

 

   

Experienced management and operating teams. Our chief executive officer has over 34 years of experience in various capacities within the coal industry. Moreover, our management team has (i) significant expertise owning, developing and managing complex coal mining operations, (ii) valuable relationships with customers, railroads and other participants across the coal industry and

 

 

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(iii) a proven track record of successfully building, enhancing and managing coal assets in a reliable and cost-effective manner. We intend to leverage these qualities to continue to successfully develop our coal mining assets and efficiently manage our operations. In addition, through our employee services agreement with CONSOL Energy, we will employ engineering, development and operations teams that have significant experience in designing, developing and operating large-scale coal complexes. Our operational management team has an average of 27 years of experience operating assets of our scale and complexity and has expertise in mining under various adverse geologic conditions.

Business Strategies

Our primary business objective is to increase the quarterly cash distribution that we pay to our unitholders over time while supporting the ongoing stability of our cash flows and maximization of our margins. We intend to accomplish this objective by executing the following business strategies:

 

    Strategically target compliant coal-fired power plants and continue operational excellence. To reduce our exposure to retirements of coal-fired power plants, we have strategically developed our customer base to include power plants that are positioned to continue operating for the foreseeable future and that are equipped with environmental controls for recent EPA measures. The Mercury Air and Toxics Standards (“MATS”) rules, in combination with other environmental regulations and economic factors, resulted in the retirement of more than 20 GW of domestic coal-fired generating capacity prior to 2015 and has led to the announcement of more than 40 GW of additional domestic coal-fired generating capacity retirements for the period from 2015 through 2019. However, for the year ended December 31, 2014, we only sold approximately 1.5 million tons of coal, representing 5.7% percent of our total 2014 coal sales, to power plants in our core market states that have announced plans to retire prior to 2020. We believe that coal will continue to be a primary source for the generation of electric power, and that coal-fired power plants able to operate into the future will have a substantial cost advantage compared to other power plants that utilize more expensive fuel sources. Our strategy is to continue to serve these customers under multi-year contracts and operate low-cost longwall mining operations with advanced distribution capabilities and access to key logistics infrastructure. We believe this strategy will position us for long-term success.

 

    Complete accretive acquisitions from our sponsor. We expect to make accretive acquisitions of additional undivided interests in the Pennsylvania mining complex from CONSOL Energy over time to increase our distributable cash flow per unit. In connection with the completion of this offering, CONSOL Energy will grant to us a right of first offer to acquire its retained 80% undivided interest in the Pennsylvania mining complex. Although we believe that CONSOL Energy’s significant ownership interest in us will incentivize it to provide us with accretive transaction opportunities, CONSOL Energy is under no obligation to present us the opportunity to purchase additional assets from it (including its retained undivided interest, unless and until it otherwise intends to divest such undivided interest), and we are under no obligation to purchase any assets from CONSOL Energy.

 

    Capitalize on industry leading margins and scale. We intend to focus on maintaining high margins by optimizing production from our high-quality reserves and leveraging our extensive logistics infrastructure. The Pennsylvania mining complex generates cash margins among the highest of our peers and produces more tons of thermal coal annually than any other mining complex in the eastern United States. For the year ended December 31, 2014, the Pennsylvania mining complex generated an average cash margin per ton of $25.27 compared to the average cash margin per ton of $14.41 generated by other coal master limited partnerships.

 

 

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    Focus on safety, compliance and continuous improvement. We intend to continue focusing on our core values of safety, compliance and continuous improvement. We operate some of the industry’s safest underground mines based on data from the Mine Safety Health Administration (“MSHA”). Over the last five years, our MSHA reportable incident rate was, on average, approximately 60% lower than the national underground bituminous coal mine incident rate. Furthermore, our MSHA Significant and Substantial (“MSHA S&S”) citation rate per 100 inspection hours was approximately 48% lower than the industry’s average MSHA S&S citation rate over the twelve-month period ended December 31, 2014. In addition, at the Harvey mine, CONSOL Energy recently constructed the first underground training academy in the United States dedicated to training miners and improving their safety performance and regulatory compliance. We believe that our focus on safety, compliance and continuous improvement promotes greater reliability in our operations, which fosters long-term customer relationships and lower operating costs, which support higher margins.

 

    Maintain stable cash flows supported by multi-year, committed and priced sales contracts. We will seek to minimize our direct commodity price exposure and maintain stable cash flows by generating a substantial portion of our revenues from multi-year, committed and priced sales contracts with well-established, creditworthy customers. We intend to further enhance our already strong contract portfolio by focusing on our existing high-quality customer base and extending the duration of our multi-year sales contracts. As of March 25, 2015, the Pennsylvania mining complex’s committed and priced contract portfolio, on a 100% basis, comprised 22.3 million tons, 11.8 million tons and 6.7 million tons for the years ending December 31, 2015, 2016 and 2017, respectively, which represents approximately 85.5%, 45.1% and 25.6%, respectively, of total production for the year ended December 31, 2014.

 

    Opportunistically pursue strategic acquisitions from third parties. We intend to evaluate opportunities to acquire strategic and economically attractive coal reserves and mining operations from third parties in order to extend the life of our coal reserves and grow our distributable cash flow. We intend to prudently and selectively pursue undeveloped reserves that are adjacent to the Pennsylvania mining complex, as well as active mining operations that are complementary to our existing operations.

 

    Opportunistically increase our production capacity. We intend to evaluate increasing the production capacity of the Pennsylvania mining complex if market dynamics for thermal coal are favorable and we are able to secure complimentary sales contracts with attractive margins. The Harvey mine’s existing infrastructure, including its bottom development, slope belt and material handling system, is able to support an additional permanent longwall mining system with moderate additional capital investment in mining equipment.

Our Relationship with CONSOL Energy

One of our principal strengths is our relationship with CONSOL Energy. CONSOL Energy is a Fortune 500 producer of coal and natural gas headquartered in Canonsburg, Pennsylvania. CONSOL Energy and its predecessors have been mining coal, primarily in the Appalachian Basin, since 1864. CONSOL Energy deploys an organic growth strategy focused on efficiently developing its resource base. CONSOL Energy’s premium coal grades are sold to electricity generators, steel makers, coke producers and industrial consumers, both domestically and internationally. In addition, CONSOL Energy is one of the largest independent natural gas exploration, development and production companies with operations focused on the major shale formations of the Appalachian Basin, including the Marcellus Shale. CONSOL Energy is listed on the New York Stock Exchange (“NYSE”) under the symbol “CNX” and had a market capitalization of approximately $6.4 billion as of March 31, 2015.

 

 

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In connection with the completion of this offering (assuming the underwriters do not exercise their option to purchase additional common units), we will (i) issue          common units and          subordinated units to CONSOL Energy, representing an aggregate     % limited partner interest in us, (ii) issue a 2% general partner interest in us and all of our incentive distribution rights to our general partner and (iii) use the net proceeds from this offering and net borrowings under our new revolving credit facility to make a distribution of approximately $         million to CONSOL Energy. Based on the initial public offering price of $         per common unit, the aggregate value of the common units and subordinated units that will be issued to CONSOL Energy in connection with the completion of this offering is approximately $         million. Please read “—The Offering,” “Use of Proceeds,” “Security Ownership of Certain Beneficial Owners and Management” and “Certain Relationships and Related Party Transactions—Distributions and Payments to Our General Partner and Its Affiliates.”

In connection with the completion of this offering, CONSOL Energy will grant to us a right of first offer to acquire its retained 80% undivided interest in the Pennsylvania mining complex. As a result of our right of first offer, we believe that we possess significant growth potential that will be generated through accretive acquisitions of additional undivided interests in the Pennsylvania mining complex. However, CONSOL Energy is under no obligation to present us the opportunity to purchase additional assets from it (including its retained undivided interest, unless and until it otherwise intends to divest such undivided interest), and we are under no obligation to purchase any assets from CONSOL Energy. Please read “—Our Initial Assets— Our Right of First Offer.”

Given CONSOL Energy’s significant ownership interests in us following this offering and its intent to utilize us to own, manage and further develop its active Pennsylvania thermal coal operations, we believe that CONSOL Energy will be incentivized to promote and support the successful execution of our business strategies and our ability to increase cash distributions per unit over time; however, we can provide no assurances that we will benefit from our relationship with CONSOL Energy. While our relationship with CONSOL Energy is a significant strength, it is also a source of potential risks and conflicts. Please read “Risk Factors—Risks Inherent in an Investment in Us” and “Conflicts of Interest and Duties.”

Our Emerging Growth Company Status

As a company with less than $1.0 billion in revenue during its last fiscal year, we qualify as an “emerging growth company” as defined in the Jumpstart Our Business Startups Act of 2012 (the “JOBS Act”). As an emerging growth company, we may, for up to five years, take advantage of specified exemptions from reporting and other regulatory requirements that are otherwise applicable generally to public companies. These exemptions include:

 

    the presentation of only two years of audited financial statements and only two years of related Management’s Discussion and Analysis of Financial Condition and Results of Operations in this prospectus;

 

    deferral of the auditor attestation requirement on the effectiveness of our system of internal control over financial reporting;

 

    exemption from the adoption of new or revised financial accounting standards until they would apply to private companies;

 

    exemption from compliance with any new requirements adopted by the Public Company Accounting Oversight Board 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; and

 

    reduced disclosure about executive compensation arrangements.

 

 

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We may take advantage of these provisions until we are no longer an emerging growth company, which will occur on the earliest of (i) the last day of the fiscal year following the fifth anniversary of this offering, (ii) the last day of the fiscal year in which we have more than $1.0 billion in annual revenue, (iii) the date on which we issue more than $1.0 billion of non-convertible debt over a three-year period and (iv) the date on which we are deemed to be a “large accelerated filer,” as defined in Rule 12b-2 promulgated under the Securities Exchange Act of 1934, as amended (the “Exchange Act”).

We have elected to take advantage of all of the applicable JOBS Act provisions, except that we will elect to opt out of the exemption that allows emerging growth companies to extend the transition period for complying with new or revised financial accounting standards (this election is irrevocable).

Accordingly, the information that we provide you may be different than what you may receive from other public companies in which you hold equity interests.

Risk Factors

An investment in our common units involves risks associated with our business, environmental, health, safety and other regulations, our partnership structure and the tax characteristics of our common units. You should carefully consider the risks described in “Risk Factors” and the other information in this prospectus before deciding whether to invest in our common units.

The Transactions

We were formed on March 16, 2015 by CONSOL Energy and our general partner. In connection with this offering, CONSOL Energy will contribute to us a 20% undivided interest in, and management and operational control over, the Pennsylvania mining complex.

In addition, in connection with this offering, we will:

 

    issue          common units and          subordinated units to CONSOL Energy, representing a     % limited partner interest in us, and issue a 2% general partner interest in us and all of our incentive distribution rights to our general partner;

 

    issue          common units to the public, representing a     % limited partner interest in us, and will apply the net proceeds as described in “Use of Proceeds”;

 

    enter into a new $         million revolving credit facility and make an initial draw of $             million that will be distributed to CONSOL Energy at the closing of this offering; and

 

    enter into an operating agreement, employee services agreement, contract agency agreement, terminal and throughput agreement, management services agreement, cooperation and safety agreement, water supply and services agreement, omnibus agreement, asset contribution agreement and equity contribution agreement with CONSOL Energy as described in “Certain Relationships and Related Party Transactions—Agreements Governing the Transactions.”

The number of common units to be issued to CONSOL Energy includes          common units that will be issued at the expiration of the underwriters’ option to purchase additional common units, assuming that the underwriters do not exercise the option. Any exercise of the underwriters’ option would reduce the common units shown as held by CONSOL Energy by the number to be purchased by the underwriters in connection with such exercise. If and to the extent the underwriters exercise their option, the number of common units purchased by

 

 

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the underwriters pursuant to any exercise will be sold to the public, and any remaining common units not purchased by the underwriters pursuant to any exercise of the option will be issued to CONSOL Energy at the expiration of the option period for no additional consideration. We will use any net proceeds from the exercise of the underwriters’ option to make a cash distribution to CONSOL Energy.

Ownership and Organizational Structure

After giving effect to the transactions described above, assuming the underwriters’ option to purchase additional common units from us is not exercised, our partnership interests will be held as follows:

 

Common units held by the public

  %  (1) 

Common units held by our sponsor

  %  (1) 

Subordinated units held by our sponsor

  %  (1) 

General partner interest held by our general partner

  2.0%  (1) 

Incentive distribution rights held by our general partner

  —%  (2) 
  

 

 

 

Total

  100.0%   
  

 

 

 

 

(1) If the underwriters exercise in full their option to purchase additional common units, the public common units will represent a     % limited partner interest in us, and the common units and subordinated units held by our sponsor will represent     % and     % limited partner interests, respectively, in us.
(2) Incentive distribution rights represent a variable interest in distributions and thus are not expressed as a fixed percentage. Please read “Provisions of Our Partnership Agreement Relating to Cash Distributions—General Partner Interest and Incentive Distribution Rights.” Distributions with respect to the incentive distribution rights will be classified as distributions with respect to equity interests. All of our incentive distribution rights will be issued to our general partner.

 

 

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The following simplified diagram depicts our organizational structure after giving effect to the transactions described above.

 

LOGO

Management of CNX Coal Resources LP

We are managed and operated by the board of directors and executive officers of CNX Coal Resources GP LLC, our general partner. CONSOL Energy is the sole owner of our general partner and has the right to appoint the entire board of directors of our general partner, including the independent directors appointed in accordance with the listing standards of the NYSE. Unlike shareholders in a publicly traded corporation, our unitholders will not be entitled to elect our general partner or the board of directors of our general partner. Many of the executive officers and directors of our general partner also currently serve as executive officers of CONSOL Energy. Please read “Management—Directors and Executive Officers of CNX Coal Resources GP LLC.”

Neither we nor our subsidiaries will have any employees. The officers of our general partner will manage our operations and activities. Under our employee services agreement, CONSOL Energy’s employees

 

 

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will continue to mine and process coal from the Pennsylvania mining complex, subject to our direction and control under the operating agreement. All of the field-level employees required to conduct and support our operations will be employed by CONSOL Energy and will be subject to the employee services agreement. Please read “Business—Our Operating Agreement with CONSOL Energy” and “Business—Our Employee Services Agreement with CONSOL Energy.”

Principal Executive Offices and Internet Address

Our principal executive offices are located at 1000 CONSOL Energy Drive, Canonsburg, Pennsylvania, 15317, and our telephone number is (724) 485-4000. Following the completion of this offering, our website will be located at         . We expect to make our periodic reports and other information filed with or furnished to the U.S. Securities and Exchange Commission (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.

Summary of Conflicts of Interest and Duties

Under our partnership agreement, our general partner has a duty to manage us in a manner it believes is in the best interests of our partnership. However, because our general partner is a wholly owned subsidiary of CONSOL Energy, the officers and directors of our general partner have a duty to manage the business of our general partner in a manner that is also in the best interests of CONSOL Energy. As a result of this relationship, conflicts of interest may arise in the future between us and our unitholders, on the one hand, and our general partner and its affiliates, including CONSOL Energy, on the other hand. For example, our general partner will be entitled to make determinations that affect the amount of cash distributions we make to the holders of common units, which in turn has an effect on whether our general partner receives incentive cash distributions. In addition, our general partner may cause us to borrow funds in order to permit the payment of cash distributions, even if the purpose or effect of the borrowing is to make a distribution on the subordinated units, to make incentive distributions or to accelerate expiration of the subordination period. All of these actions are permitted under our partnership agreement and will not be a breach of any duty (fiduciary or otherwise) of our general partner. Please read “Conflicts of Interest and Duties.”

Delaware law provides that a Delaware limited partnership may, in its partnership agreement, expand, restrict or eliminate the fiduciary duties otherwise owed by the general partner to limited partners and the partnership. As permitted by Delaware law, our partnership agreement contains various provisions replacing the fiduciary duties that would otherwise be owed by our general partner with contractual standards governing the duties of the general partner and contractual methods of resolving conflicts of interest. The effect of these provisions is to restrict the remedies available to unitholders for actions that might otherwise constitute breaches of our general partner’s fiduciary duties. Our partnership agreement also provides that affiliates of our general partner, including CONSOL Energy and its affiliates, are not restricted from competing with us, and neither our general partner nor its affiliates have any obligation to present business opportunities to us except with respect to rights of first offer contained in our omnibus agreement. By purchasing a common unit, the purchaser agrees to be bound by the terms of our partnership agreement, and, pursuant to the terms of our partnership agreement, each holder of common units consents to various actions and potential conflicts of interest contemplated in our partnership agreement that might otherwise be considered a breach of fiduciary or other duties under Delaware law. Please read “Conflicts of Interest and Duties—Duties of Our General Partner” and “Certain Relationships and Related Party Transactions.”

 

 

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The Offering

 

Common units offered to the public

         common units.

 

           common units if the underwriters exercise in full their option to purchase additional common units from us.

 

Units outstanding after this offering

         common units, representing a 49% limited partner interest in us, and          subordinated units, representing a 49% limited partner interest in us.

 

  In addition, we will issue a 2% general partner interest to our general partner.

 

  The number of common units outstanding after this offering includes          common units that are available to be issued to the underwriters pursuant to their option to purchase additional common units from us. The number of common units purchased by the underwriters pursuant to any exercise of the option will be sold to the public. If the underwriters do not exercise their option to purchase additional common units, in whole or in part, any remaining common units not purchased by the underwriters pursuant to the option will be issued to CONSOL Energy at the expiration of the option period for no additional consideration. Accordingly, any exercise of the underwriters’ option, in whole or in part, will not affect the total number of common units outstanding or the amount of cash needed to pay the minimum quarterly distribution on all units.

 

Use of proceeds

We expect to receive net proceeds of approximately $         million from the sale of          common units offered by this prospectus, based on an 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), after deducting the underwriting discount and estimated offering expenses. Our estimate assumes the underwriters’ option to purchase additional common units is not exercised. We intend to use the net proceeds from this offering to (i) make a distribution of approximately $         million to CONSOL Energy and (ii) pay approximately $         million of origination fees related to our new revolving credit facility. Please read “Use of Proceeds.”

 

  If the underwriters exercise in full their option to purchase additional common units, we expect to receive net proceeds of approximately $         million, after deducting the underwriting discount and estimated offering expenses. We will use any net proceeds from the exercise of the underwriters’ option to make a cash distribution to CONSOL Energy.

 

Cash distributions

We intend to make a minimum quarterly distribution of $         per unit to the extent we have sufficient cash at the end of each quarter after establishment of cash reserves and payment of fees and expenses, including payments to our general partner. We refer to this

 

 

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cash as “available cash.” Our ability to pay the minimum quarterly distribution is subject to various restrictions and other factors described in more detail under the caption “Cash Distribution Policy and Restrictions on Distributions.”

 

  We do not expect to make distributions for the period that began on                     , 2015 and ends on the day prior to the closing of this offering. We will adjust the amount of our first distribution for the period from the closing of this offering through                     , 2015 based on the number of days in that period.

 

  In general, we will pay any cash distributions we make each quarter in the following manner:

 

    first, 98% to the holders of common units and 2% to our general partner, until each common unit has received a minimum quarterly distribution of $         plus any arrearages from prior quarters;

 

    second, 98% to the holders of subordinated units and 2% to our general partner, until each subordinated unit has received a minimum quarterly distribution of $        ; and

 

    third, 98% to all unitholders, pro rata, and 2% to our general partner, until each unit has received a distribution of $        .

 

  If cash distributions to our unitholders exceed $         per unit in any quarter, our general partner will receive, in addition to distributions on its 2% general partner interest, increasing percentages, up to 48%, of the cash we distribute in excess of that amount. We refer to these distributions as “incentive distributions.” In certain circumstances, our general partner, as the initial holder of our incentive distribution rights, has the right to reset the target distribution levels described above to higher levels based on our cash distributions at the time of the exercise of this reset election. Please read “Provisions of Our Partnership Agreement Relating to Cash Distributions.”

 

  If we do not have sufficient available cash at the end of each quarter, we may, but are under no obligation to, borrow funds to pay the minimum quarterly distribution to our unitholders.

 

 

Pro forma distributable cash flow that was generated during the year ended December 31, 2014 was approximately $86.7 million. The amount of distributable cash flow we must generate to support the payment of the minimum quarterly distribution for four quarters on our common units and subordinated units to be outstanding immediately after this offering and the corresponding distributions on our general partner’s 2% general partner interest is approximately $         million (or an average of approximately $         million per quarter). As a result, for the year ended December 31, 2014, on a pro forma basis, we would have generated sufficient distributable cash flow to support the payment of the aggregate annualized minimum

 

 

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quarterly distribution on all of our common units and subordinated units and the corresponding distributions on our general partner’s 2% general partner interest. Please read “Cash Distribution Policy and Restrictions on Distributions—Unaudited Pro Forma Adjusted EBITDA and Distributable Cash Flow for the Year Ended December 31, 2014.”

 

  We believe, based on our financial forecast and related assumptions included in “Cash Distribution Policy and Restrictions on Distributions—Estimated Adjusted EBITDA and Distributable Cash Flow for the Twelve Months Ending June 30, 2016,” that we will generate sufficient distributable cash flow to support the payment of the aggregate minimum quarterly distributions of $         million on all of our common units and subordinated units and the corresponding distributions on our general partner’s 2% general partner interest for the twelve months ending June 30, 2016. However, we do not have a legal obligation to pay distributions at our minimum quarterly distribution rate or at any other rate except as provided in our partnership agreement, and there is no guarantee that we will make quarterly cash distributions to our unitholders. Please read “Cash Distribution Policy and Restrictions on Distributions.”

 

Subordinated units

Following the completion of this offering, CONSOL Energy will 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, the subordinated units will not be entitled to receive any distribution until the common units have received the minimum quarterly distribution for such quarter plus any arrearages in the payment of the minimum quarterly distribution from prior quarters during the subordination period. Subordinated units will not accrue arrearages.

 

Conversion of subordinated units

The subordination period will end on the first business day after the date that we have earned and paid distributions of at least (i) $         (the annualized minimum quarterly distribution) on each of the outstanding common units and subordinated units and the corresponding distributions on our general partner’s 2% general partner interest for each of three consecutive, non-overlapping four quarter periods ending on or after                     , 2018 or (ii) $         (150% of the annualized minimum quarterly distribution) on each of the outstanding common units and subordinated units and the corresponding distributions on our general partner’s 2% general partner interest and the related distributions on the incentive distribution rights for any four-quarter period ending on or after                     , 2016, in each case provided there are no arrearages in payment of the minimum quarterly distributions on our common units at that time.

 

 

When the subordination period ends, each outstanding subordinated unit will convert into one common unit, and common units will no

 

 

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longer be entitled to arrearages. Please read “Provisions of Our Partnership Agreement Relating to Cash Distributions—Subordinated Units and Subordination Period.”

 

Issuance of additional partnership interests

Our partnership agreement authorizes us to issue an unlimited number of additional partnership interests and options, rights, warrants and appreciation rights relating to the partnership interests for any partnership purpose at any time and from time to time to such persons for such consideration and on such terms and conditions as our general partner shall determine in its sole discretion, all without the approval of any partners. Our unitholders will not have preemptive or participation rights to purchase their pro rata share of any additional units issued. Please read “Units Eligible for Future Sale” and “Our Partnership Agreement—Issuance of Additional Partnership 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 unless such removal is both (i) for cause and (ii) approved by a vote of the holders of at least 66 23% of the outstanding units, including any units owned by our general partner and its affiliates, voting together as a single class. Following the completion of this offering, CONSOL Energy will own     % of our total outstanding common units and subordinated units on an aggregate basis (or     % of our total outstanding common units and subordinated units on an aggregate basis if the underwriters exercise in full their option to purchase additional common units). As a result, our public unitholders will have limited ability to remove our general partner. Please read “Our 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 has the right, but not the obligation, to purchase all of the remaining common units at a price equal to the greater of (i) the average of the daily closing price of our common units over the 20 trading days preceding the date that is three business days before notice of exercise of the call right is first mailed and (ii) 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. Following the completion of this offering and assuming the underwriters’ option to purchase additional common units from us is not exercised, our general partner and its affiliates will own approximately     % of our common units (excluding any common units purchased by the directors, director nominee and executive officers of our general partner, directors of CONSOL Energy and certain other individuals as selected by CONSOL Energy under our directed unit program). At the end of the subordination period (which could occur as early as

 

 

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within the quarter ending                     , 2016), assuming no additional issuances of common units by us (other than upon the conversion of the subordinated units) and the underwriters’ option to purchase additional common units from us is not exercised, our general partner and its affiliates will own     % of our outstanding common units (excluding any common units purchased by the directors, director nominee and executive officers of our general partner, directors of CONSOL Energy and certain other individuals as selected by CONSOL Energy under our directed unit program) and therefore would not be able to exercise the call right at that time. Please read “Our 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, 2018, you will be allocated, on a cumulative basis, an amount of federal taxable income for that period that will be     % or less 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 Federal Income Tax Consequences—Tax Consequences of Unit Ownership—Ratio of Taxable Income to Distributions.”

 

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 Federal Income Tax Consequences.”

 

Directed unit program

At our request, the underwriters have reserved for sale, at the initial public offering price, up to     % of the common units being offered by this prospectus for sale to the directors, director nominee and executive officers of our general partner, directors of CONSOL Energy and certain other individuals as selected by CONSOL Energy. We do not know if these persons will choose to purchase all or any portion of these reserved common units, but any purchases they do make will reduce the number of common units available to the general public. Please read “Underwriting—Directed Unit Program.”

 

Exchange listing

We intend to apply to list our common units on the NYSE under the symbol “CNXC.”

 

 

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Summary Historical and Pro Forma Financial and Operating Data

The following table presents summary historical financial data of our Predecessor and summary unaudited pro forma financial data of CNX Coal Resources LP for the periods and as of the dates indicated. The following summary historical financial data of our Predecessor reflects a 20% undivided interest in CPCC and Conrhein’s combined assets, liabilities, revenues and expenses that CONSOL Energy will contribute to us at the closing of this offering.

The summary historical financial data of our Predecessor as of and for the years ended December 31, 2014 and 2013 are derived from the audited financial statements of our Predecessor appearing elsewhere in this prospectus. The following table should be read together with, and is qualified in its entirety by reference to, the historical and unaudited pro forma combined financial statements and the accompanying notes included elsewhere in this prospectus. The table should also be read together with “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

The summary unaudited pro forma financial data presented in the following table for the year ended December 31, 2014 is derived from the unaudited pro forma combined financial statements included elsewhere in this prospectus. The unaudited pro forma combined balance sheet assumes the offering and the related transactions occurred as of December 31, 2014, and the unaudited pro forma combined statement of operations for the year ended December 31, 2014, assume the offering and the related transactions occurred as of January 1, 2014. These transactions include, and the unaudited pro forma combined financial statements give effect to, the following:

 

    CONSOL Energy’s contribution to us of a 20% undivided interest in the assets, liabilities, revenues and expenses comprising the Pennsylvania mining complex that are currently held by CPCC and Conrhein;

 

    our entry into a new $         million revolving credit facility and initial draw of $         million that will be distributed to CONSOL Energy at the closing of this offering;

 

    our entry into an operating agreement, employee services agreement, contract agency agreement, terminal and throughput agreement, management services agreement, cooperation and safety agreement, water supply and services agreement, omnibus agreement, asset contribution agreement and equity contribution agreement with CONSOL Energy as described in “Certain Relationships and Related Party Transactions—Agreements Governing the Transactions;”

 

    the consummation of this offering and our issuance of (i)          common units to the public, (ii)          a 2% general partner interest and the incentive distribution rights to our general partner and (iii)          common units and          subordinated units to CONSOL Energy; and

 

    the application of the net proceeds of this offering as described in “Use of Proceeds.”

The unaudited pro forma combined statement of operations does not give effect to an estimated $2.4 million in incremental general and administrative expenses that we expect to incur annually as a result of being a publicly traded partnership.

 

 

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CNX Coal Resources LP
Predecessor

Historical

   

CNX Coal
Resources LP
Pro Forma

 
    

Year Ended

December 31,

   

Year Ended
December 31,

 
    

2014

   

2013

   

2014

 
     (in thousands, except per ton data)  

Statement of Operations Data:

      

Coal revenue

   $ 323,398      $ 271,467      $ 323,398   

Freight revenue

     3,353        3,556        3,353   

Other income

     7,580        1,336        7,371   

Gain (loss) on sale of assets

     148        (124     153   
  

 

 

   

 

 

   

 

 

 

Total revenue and other income

  334,479      276,235      334,275   

Operating and other costs

  172,863      152,054      172,327   

Royalties and production costs

  14,169      11,046      14,169   

Selling and direct administrative expenses

  6,444      5,687      4,710   

Depreciation, depletion and amortization

  33,949      25,306      33,786   

Freight expense

  3,353      3,556      3,353   

General and administrative expenses—related party (1)

  5,198      4,521      5,264   

Other corporate expenses

  7,658      7,680      7,658   

Interest expense

  6,946      2,093      8,631   
  

 

 

   

 

 

   

 

 

 

Total costs

  250,580      211,943      249,898   
  

 

 

   

 

 

   

 

 

 

Net income

$ 83,899    $ 64,292    $ 84,377   
  

 

 

   

 

 

   

 

 

 

Balance Sheet Data (at period end):

Property, plant and equipment, net

$ 398,886    $ 374,284    $ 379,439   

Total assets

  418,811      392,760      415,869   

Total invested equity / partners’ capital

  170,626      119,817      137,230   

Cash Flow Statement Data:

Net cash provided by operating activities

$ 114,109    $ 94,416   

Net cash used in investing activities

  (52,824   (67,628

Net cash used in financing activities

  (61,285   (26,789

Coal Reserves, Production and Sales Data:

Recoverable reserves (at period end)

  157,127      125,066      157,127   

Coal tons produced

  5,213      4,287      5,213   

Coal tons sold

  5,227      4,246      5,227   

Average sales price per ton

$ 61.88    $ 63.93    $ 61.88   

Average costs per ton sold

$ 42.74    $ 44.53    $ 42.44   

Average cash margin per ton (2)

$ 25.27    $ 24.98    $ 25.57   

Other Data:

Capital expenditures

$ 68,061    $ 82,182   

Adjusted EBITDA (3)

$ 125,150    $ 96,435    $ 127,150   

 

(1) General and administrative expenses—related party for the pro forma year ended December 31, 2014 does not give effect to annual incremental general and administrative expenses of approximately $2,418 that we expect to incur as a result of being a publicly traded partnership.
(2) For our calculation of average cash margin per ton, please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Results of Operations—Coal Operations.”
(3) For our definition of the non-GAAP financial measure of adjusted EBITDA and a reconciliation of adjusted EBITDA to our most directly comparable financial measure calculated and presented in accordance with GAAP, please read “Selected Historical and Pro Forma Financial and Operating Data—Non-GAAP Financial Measure.”

 

 

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RISK FACTORS

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, including the matters addressed under “Forward-Looking Statements,” in evaluating an investment in our common units.

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

Risks Related to Our Business

We may not generate sufficient distributable cash flow to support the payment of the minimum quarterly distribution to our unitholders.

In order to support the payment of the minimum quarterly distribution of $         per unit per quarter, or $         per unit on an annualized basis, we must generate distributable cash flow of approximately $         million per quarter, or approximately $         million per year, based on the number of common units and subordinated units and the general partner interest to be outstanding immediately following the completion of this offering. We may not generate sufficient distributable cash flow to support the payment of the minimum quarterly distribution to our unitholders.

The amount of cash we can distribute on our units principally depends upon the amount of cash we generate from our operations, which will fluctuate from quarter to quarter based on, among other things:

 

    the amount of coal we are able to produce from our mines and the efficiency of our mining, preparation and transportation of coal, which could be adversely affected by, among other things, operating difficulties, unfavorable geologic conditions, inclement or hazardous weather conditions and natural disasters or other force majeure events;

 

    the levels of our operating expenses, general and administrative expenses and capital expenditures;

 

    the fees and expenses of our general partner and its affiliates (including our sponsor) that we are required to reimburse;

 

    the amount of cash reserves established by our general partner;

 

    restrictions on distributions contained in our debt agreements;

 

    our ability to borrow under our debt agreements and/or to access the capital markets to fund our capital expenditures and operating expenditures and to pay distributions;

 

    our debt service requirements and other liabilities;

 

    the loss of, or significant reduction in, purchases by our largest customers;

 

    the level and timing of our capital expenditures;

 

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    fluctuations in our working capital needs;

 

    the cost of acquisitions, if any; and

 

    other business risks affecting our cash levels.

In addition, the actual amount of distributable cash flow that we generate will also depend on other factors, some of which are beyond our control, including:

 

    overall domestic and global economic and industry conditions, including the market price of, supply of and demand for domestic and foreign coal;

 

    the consumption pattern of industrial consumers, electricity generators and residential users;

 

    the price and availability of alternative fuels for electricity generation, especially natural gas;

 

    competition from other coal suppliers;

 

    the impact of domestic and foreign governmental laws and regulations, including environmental and climate change regulations and regulations affecting the coal mining industry and coal-fired power plants, and delays in the receipt of, failure to receive, failure to maintain or revocation of necessary governmental permits;

 

    the costs associated with our compliance with domestic and foreign governmental laws and regulations, including environmental and climate change regulations;

 

    technological advances affecting energy consumption;

 

    the costs, availability and capacity of transportation infrastructure;

 

    the cost and availability of skilled labor (including miners), the effects of new or expanded health and safety regulations and work stoppages and other labor difficulties; and

 

    changes in tax laws.

For a description of additional restrictions and factors that may affect our ability to pay cash distributions, please read “Cash Distribution Policy and Restrictions on Distributions.”

The assumptions and estimates underlying the forecast of adjusted EBITDA and distributable cash flow that we include 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 our actual adjusted EBITDA and distributable cash flow to differ materially from our forecast.

The forecast of adjusted EBITDA and distributable cash flow set forth in “Cash Distribution Policy and Restrictions on Distributions” includes our forecast of adjusted EBITDA and distributable cash flow for the twelve months ending June 30, 2016. Our ability to pay the full minimum quarterly distribution in the forecast period is based on a number of assumptions and estimates that may not prove to be correct and that are discussed in “Cash Distribution Policy and Restrictions on Distributions.” Our management has prepared the financial forecast and has neither requested nor received an opinion or report on it from our or any other independent auditor. Although we consider the assumptions and estimates underlying our forecast of adjusted EBITDA and distributable cash flow to be reasonable as of the date of this prospectus, those assumptions and estimates are inherently uncertain and subject to significant business, economic, financial, regulatory and competitive risks and

 

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uncertainties that could cause our actual adjusted EBITDA and distributable cash flow to differ materially from our forecast. If we do not achieve the forecasted results, we may not be able to pay the full minimum quarterly distribution or any amount on our common units, in which event the trading price of our common units could materially decline and you could lose all or part of your investment.

Our growth strategy primarily depends on us acquiring additional undivided interests in the Pennsylvania mining complex from our sponsor.

Our primary strategy for growing our business and increasing distributions to our unitholders is to make acquisitions that increase our distributable cash flow. The primary component of our growth strategy is based upon our expectation of future divestitures by our sponsor to us of portions of its retained 80% undivided interest in the Pennsylvania mining complex. We have only a right of first offer pursuant to our omnibus agreement to purchase the retained undivided interest in the Pennsylvania mining complex retained by our sponsor following the completion of this offering and that our sponsor subsequently elects to sell. However, our sponsor is under no obligation to present us the opportunity to purchase additional assets from it (including its retained undivided interest, unless and until it otherwise intends to divest such undivided interest), and we are under no obligation to purchase any assets from our sponsor. We may never purchase all or a portion of the retained undivided interest in the Pennsylvania mining complex for several reasons, including the following:

 

    our sponsor may choose not to sell all or any portion of its retained undivided interest;

 

    we may not make offers for the retained undivided interest owned by our sponsor;

 

    we and our sponsor may be unable to agree to terms acceptable to both parties;

 

    we may be unable to obtain financing to purchase the retained undivided interest on acceptable terms or at all; or

 

    we may be prohibited by the terms of our debt agreements (including our new revolving credit facility) or other contracts from purchasing all or any portion of the retained undivided interest, and our sponsor may be prohibited by the terms of its debt agreements or other contracts from selling all or any portion of such retained undivided interest. If we or our sponsor must seek waivers of such provisions or refinance debt governed by such provisions in order to consummate a sale of all or a portion of the retained undivided interest, we or our sponsor may be unable to do so in a timely manner or at all.

We do not know when or if our sponsor will determine to sell all or any portion of such retained undivided interest, and we can provide no assurance that we will be able to successfully consummate any future acquisition of all or any portion of such retained undivided interest in the Pennsylvania mining complex. Furthermore, if our sponsor reduces its ownership interest in us, it may be less willing to sell to us all or a portion of its retained undivided interest in the Pennsylvania mining complex. In addition, except for our right of first offer, there are no restrictions on our sponsor’s ability to transfer its retained undivided interest in the Pennsylvania mining complex to a third party. If we do not acquire all or a significant portion of the retained undivided interest in the Pennsylvania mining complex held by our sponsor, our ability to grow our business and increase our cash distributions to our unitholders may be significantly limited.

We face uncertainties in estimating our economically recoverable coal reserves, and inaccuracies in our estimates could result in lower than expected revenues, higher than expected costs and decreased profitability.

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 geologic data, coal ownership

 

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information and current and proposed mine plans. These estimates are periodically updated to reflect past coal production, new drilling information and other geologic or mining data. There are numerous uncertainties inherent in estimating quantities and qualities of coal and costs to mine recoverable reserves, including many factors beyond our control. As a result, estimates of economically recoverable coal reserves are by their nature uncertain. Some of the factors and assumptions which impact economically recoverable coal reserve estimates include:

 

    geological and mining conditions;

 

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

 

    the assumed effects of regulations and taxes by governmental agencies;

 

    our ability to obtain, maintain and renew all required permits;

 

    future improvements in mining technology;

 

    assumptions related to future prices; and

 

    future operating costs, including the cost of materials, and capital expenditures.

Each of the factors that impacts reserve estimation may vary considerably from the assumptions used in estimating the reserves. For these reasons, estimates of coal reserves may vary substantially. Actual production, revenues and expenditures with respect to our coal reserves will likely vary from estimates, and these variances may be material. As a result, our estimates may not accurately reflect our actual coal reserves.

Our inability to acquire additional coal reserves that are economically recoverable may have a material adverse effect on our future profitability.

Our profitability depends substantially on our ability to mine, in a cost-effective manner, coal reserves that possess the quality characteristics our customers desire. Because our reserves decline as we mine our coal, our future profitability depends upon our ability to acquire additional coal reserves that are economically recoverable to replace the reserves we produce. If we fail to acquire or develop sufficient additional reserves over the long term to replace the reserves depleted by our production, our existing reserves will eventually be depleted. Please read “Business—Coal Reserves.”

Deterioration in the global economic conditions in any of the industries in which our customers operate, a worldwide financial downturn, such as the 2008—2009 financial crisis, or negative credit market conditions could have a material adverse effect on our business, financial condition, results of operations, cash flows and ability to make cash distributions.

Economic conditions in a number of industries in which our customers operate, such as electric power generation and steelmaking, substantially deteriorated in recent years and reduced the demand for coal. Although global industrial activity recovered from 2009 levels, the general economic challenges for some of our customers continued in 2014 and the outlook is uncertain. Renewed or continued weakness in the economic conditions of any of the industries served by our customers could have a material adverse effect on our business, financial condition, results of operations, cash flows and ability to make cash distributions. For example:

 

    demand for electricity in the United States is impacted by levels of industrial activity, which if weakened would negatively impact our revenues, margins and profitability;

 

    demand for metallurgical coal depends on domestic and foreign steel demand, which if weakened would negatively impact our ability to sell thermal coal as higher-priced metallurgical coal;

 

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    the tightening of credit or lack of credit availability to our customers could adversely affect our ability to collect our trade receivables; and

 

    our ability to access the capital markets may be restricted at a time when we intend to raise capital for our business, including for exploration and/or development of coal reserves.

Decreases in demand for electricity and changes in coal consumption patterns of U.S. electric power generators could adversely affect our business.

Our business is closely linked to domestic demand for electricity, and any changes in coal consumption by U.S. electric power generators would likely impact our business over the long term. According to the EIA, the domestic electric power sector accounts for more than 93% of total U.S. coal consumption. In 2014, the Pennsylvania mining complex sold approximately 88% of its coal to U.S. electric power generators, and we have multi-year contracts in place with these electric power generators for a significant portion of our future production. The amount of coal consumed by the electric power generation industry is affected by, among other things:

 

    general economic conditions, particularly those affecting industrial electric power demand, such as a downturn in the U.S. economy and financial markets;

 

    overall demand for electricity;

 

    indirect competition from alternative fuel sources for power generation, such as natural gas, fuel oil, nuclear, hydroelectric, wind and solar power, and the location, availability, quality and price of those alternative fuel sources;

 

    environmental and other governmental regulations, including those impacting coal-fired power plants; and

 

    energy conservation efforts and related governmental policies.

For example, the relatively recent low price of natural gas has resulted, in some instances, in domestic electric generators increasing natural gas consumption while decreasing coal consumption. Federal and state mandates for increased use of electricity derived from renewable energy sources could affect demand for our coal. Please read “Risk Factors—Risks Related to Environmental, Health, Safety and Other Regulations.” Such mandates, combined with other incentives to use renewable energy sources, such as tax credits, could make alternative fuel sources more competitive with coal. A decrease in coal consumption by the electric power generation industry could adversely affect the price of coal, which could have a material adverse effect on our business, financial condition, results of operations, cash flows and ability to make cash distributions.

According to the EIA, although electricity demand fell in only three years between 1950 and 2007, it declined in four of the five years between 2008 and 2012. The largest drop in electricity demand occurred in 2009, primarily as the result of the steep economic downturn from late 2007 through 2009, which led to a large drop in electricity sales in the industrial sector. Other factors, such as efficiency improvements associated with new appliance standards in the buildings sectors and overall improvement in the efficiency of technologies powered by electricity, have slowed electricity demand growth and may contribute to slower growth in the future, even as the U.S. economy continues its recovery. Further decreases in the demand for electricity, such as decreases that could be caused by a worsening of current economic conditions, a prolonged economic recession or other similar events, could have a material adverse effect on the demand for coal and on our business over the long term.

Changes in the coal industry that affect our customers, such as those caused by decreased electricity demand and increased competition, could also adversely affect our business. Indirect competition from natural

 

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gas-fired plants that are relatively less expensive to construct and less difficult to permit has the most potential to displace a significant amount of coal-fired electric power generation in the near term, particularly older, less efficient coal-fired powered generators. In addition, uncertainty caused by federal and state regulations could cause coal customers to be uncertain of their coal requirements in future years, which could adversely affect our ability to sell coal to our customers under multi-year sales contracts.

Prices for coal are volatile and can fluctuate widely based upon a number of factors beyond our control, including oversupply relative to the demand available for our coal, weather and the price and availability of alternative fuels. A substantial or extended decline in the prices we receive for our coal could adversely affect our business, results of operations, financial condition, cash flows and ability to make cash distributions to our unitholders.

Our financial results are significantly affected by the prices we receive for our coal and 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. Prices and quantities under our multi-year sales contracts are generally based on expectations of future coal prices at the time the contract is entered into, renewed, extended or re-opened. The expectation of future prices for coal depends upon many factors beyond our control, including the following:

 

    the market price for coal;

 

    overall domestic and global economic conditions, including the supply of and demand for domestic and foreign coal;

 

    the consumption pattern of industrial consumers, electricity generators and residential users;

 

    weather conditions in our markets that affect the demand for thermal coal;

 

    competition from other coal suppliers;

 

    the price and availability of alternative fuels for electricity generation, especially natural gas;

 

    technological advances affecting energy consumption;

 

    the costs, availability and capacity of transportation infrastructure;

 

    the impact of domestic and foreign governmental laws and regulations, including environmental and climate change regulations and regulations affecting the coal mining industry and coal-fired power plants, and delays in the receipt of, failure to receive, failure to maintain or revocation of necessary governmental permits; and

 

    increased utilization by the steel industry of electric arc furnaces or pulverized coal injection processes, which reduce or eliminate the use of furnace coke, an intermediate product produced from metallurgical coal, and generally decrease the demand for metallurgical coal.

The coal industry also faces concerns with respect to oversupply from time to time. For example, the unusually warm 2011/2012 winter left utilities with large coal stockpiles and depressed the demand for thermal coal. A substantial or extended decline in the prices we receive for our coal could adversely affect our business, results of operations, financial condition, cash flows and ability to make cash distributions to our unitholders.

 

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Competition within the coal industry may adversely affect our ability to sell coal. Increased competition or a loss of our competitive position could adversely affect our sales of, or our prices for, our coal, which could impair our profitability. In addition, foreign currency fluctuations could adversely affect the competitiveness of our coal abroad.

We compete with other producers primarily on the basis of price, coal quality, transportation costs and reliability of delivery. We compete with coal producers in various regions of the United States and with some foreign coal producers for domestic sales primarily to electric power generators. We also compete with both domestic and foreign coal producers for sales in international markets. Demand for our coal by our principal customers is affected by the delivered price of competing coals, other fuel supplies and alternative generating sources, including nuclear, natural gas, oil and renewable energy sources, such as hydroelectric and wind power. We sell coal to foreign electricity generators and to the more specialized metallurgical coal market, both of which are significantly affected by international demand and competition.

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 coal industry will not adversely affect us. In addition, increases in coal prices could encourage existing producers to expand capacity or could encourage new producers to enter the market. If overcapacity results, the prices of and demand for our coal could significantly decline, which could have a material adverse effect on our business, financial condition, results of operations, cash flows and ability to make cash distributions.

In addition, we face competition from foreign producers that sell their coal in the export market. 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. 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 foreign trade policies or other arrangements. 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 our foreign competitors 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 to our customers. 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. Consequently, currency fluctuations could adversely affect the competitiveness of our coal in international markets, which could have a material adverse effect on our business, financial condition, results of operations, cash flows and ability to make cash distributions. Please read “Business—Competition.”

Our business involves many hazards and operating risks, some of which may not be fully covered by insurance. The occurrence of a significant accident or other event that is not fully insured could curtail our operations and have a material adverse effect on our ability to distribute cash and, accordingly, the market price for our common units.

Our mining operations, including our transportation infrastructure, are subject to many hazards and operating risks. In particular, underground mining and related processing activities present inherent risks of injury to persons and damage to property and equipment. Our mines are subject to a number of operating risks that could disrupt operations, decrease production and increase the cost of mining for varying lengths of time, thereby adversely affecting our operating results. In addition, if coal production declines, we may not be able to produce sufficient amounts of coal to deliver under our multi-year sales contracts. Our inability to satisfy contractual obligations could result in our customers initiating claims against us. The operating risks that may have a significant impact on our coal operations include:

 

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

 

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    adverse geologic conditions, including amounts of rock and other natural materials intruding into the coal seam, that could affect the stability of the roof and the side walls of the mine;

 

    environmental hazards;

 

    mining and processing equipment failures and unexpected maintenance problems;

 

    fires or explosions, including as a result of methane, coal, coal dust or other explosive materials, and/or other accidents;

 

    inclement or hazardous weather conditions and natural disasters or other force majeure events;

 

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

 

    delays in moving our longwall equipment;

 

    railroad derailments;

 

    security breaches or terroristic acts; and

 

    other hazards that could also result in personal injury and loss of life, pollution and suspension of operations.

Any of these risks could adversely affect our ability to conduct operations or result in substantial loss to us as a result of claims for:

 

    personal injury or loss of life;

 

    damage to and destruction of property, natural resources and equipment, including our coal properties and our coal production or transportation facilities;

 

    pollution and other environmental damage to our properties or the properties of others;

 

    potential legal liability and monetary losses;

 

    regulatory investigations and penalties;

 

    suspension of our operations; and

 

    repair and remediation costs.

In addition, the total cost of coal sold and overall coal production may be adversely affected by various factors. For example, unit costs were negatively impacted in 2014 due to adverse geological conditions at the Enlow Fork mine, primarily related to sandstone intrusions, along with adverse geological conditions and equipment issues at the Harvey mine, primarily related to sandstone intrusions, which resulted in reduced coal production at both the Enlow Fork and Harvey mines. Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Results of Operations—Cost of Coal Sales.”

Although we maintain insurance for a number of risks and hazards, we may not be insured or fully insured against the losses or liabilities that could arise from a significant accident in our coal operations. We may elect not to obtain insurance for any or all of these risks if we believe that the cost of available insurance is excessive relative to the risks presented. In addition, pollution and environmental risks generally are not fully

 

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insurable. Moreover, a significant mine accident could potentially cause a mine shutdown. The occurrence of an event that is not fully covered by insurance could have a material adverse effect on our business, financial condition, results of operations, cash flows and ability to make cash distributions.

In addition, if any of the foregoing changes, conditions or events occurs and is not excusable as a force majeure event, any resulting failure on our part to deliver coal to the purchaser under our contracts could result in economic penalties, suspension or cancellation of shipments or ultimately termination of the agreement, any of which could have a material adverse effect on our business, financial condition, results of operations, cash flows and ability to make cash distributions.

All of our mines are part of a single mining complex and are exclusively located in the Northern Appalachian Basin, making us vulnerable to risks associated with operating in a single geographic area.

All of our operations are conducted at a single mining complex located in the Northern Appalachian Basin in southwestern Pennsylvania. The geographic concentration of our operations at the Pennsylvania mining complex may disproportionately expose us to disruptions in our operations if the region experiences severe weather, transportation capacity constraints, constraints on the availability of required equipment, facilities, personnel or services, significant governmental regulation or natural disasters. If any of these factors were to impact the Northern Appalachian Basin more than other coal producing regions, our business, financial condition, results of operations and ability to make cash distributions will be adversely affected relative to other mining companies that have a more geographically diversified asset portfolio.

The availability and reliability of transportation facilities and fluctuations in transportation costs could affect the demand for our coal or impair our ability to supply coal to our customers.

Transportation logistics play an important role in allowing us to supply coal to our customers. Any significant delays, interruptions or other limitations on the ability to transport our coal could negatively affect our operations. Currently, all of our coal is transported from the Pennsylvania mining complex by rail. Delays and interruptions of rail services because of accidents, infrastructure damage, lack of rail or port capacity, weather-related problems, governmental regulation, terrorism, strikes, lock-outs, third-party actions or other events could temporarily impair our ability to supply coal to customers and adversely affect our profitability. In addition, transportation costs represent a significant portion of the delivered cost of coal and, as a result, the cost of delivery is a critical factor in a customer’s purchasing decision. Increases in transportation costs, including increases resulting from emission control requirements and fluctuations in the price of locomotive diesel fuel and demurrage, could make our coal less competitive, which could have a material adverse effect on our business, financial condition, results of operations, cash flows and ability to make cash distributions.

Any significant downtime of our major pieces of mining equipment, including our preparation plant, could impair our ability to supply coal to our customers and materially and adversely affect our results of operations.

We depend on several major pieces of mining equipment to produce and transport our coal, including, but not limited to, longwall mining systems, continuous mining units, our preparation plant and related facilities, conveyors and transloading 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 transport coal and materially and adversely affect our business, results of operations, financial condition, cash flows and ability to make cash distributions to our unitholders.

All of the coal from our mines is processed at a single preparation plant and loaded on to rail cars using a single train loadout facility. If either of our preparation plant or train loadout facility suffers extended downtime, including from major damage, or is destroyed, our ability to process and deliver coal to our customers would be materially impacted, which would materially adversely affect our business, results of operations, financial condition, cash flows and ability to make cash distributions to our unitholders.

 

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If our customers do not extend existing contracts, do not enter into new multi-year sales contracts or do not honor their existing contracts, our profitability could be adversely affected.

During the year ended December 31, 2014, approximately 59% of the coal we produced was sold under multi-year sales contracts. If a substantial portion of our multi-year sales contracts are modified or terminated (or if force majeure is exercised) and we are unable to replace the contracts (or if new contracts are priced at lower levels), our profitability could be adversely affected. In addition, if customers refuse to accept shipments of our coal for which they have an existing contractual obligation, our revenues will decrease and we may have to reduce production at our mines until our customer’s contractual obligations are honored.

The profitability of our multi-year sales contracts depends on a variety of factors, which vary from contract to contract and fluctuate during the contract term, including our production costs and other factors. Price changes, if any, provided in multi-year sales contracts may not reflect our cost increases and, therefore, increases in our costs may reduce our profit margins. In addition, during periods of declining market prices, provisions in our multi-year sales contracts for adjustment or renegotiation of prices and other provisions may increase our exposure to short-term coal price volatility. As a result, we may not be able to obtain multi-year agreements at favorable prices compared to either market conditions, as they may change from time to time, or our cost structure, which may reduce our profitability.

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

For the year ended December 31, 2014, we derived over 10% of our total revenues from sales to two customers individually. As of December 31, 2014, we had approximately 12 sales agreements with these customers that expire at various times from 2015 to 2018. We are currently discussing the extension of existing agreements or entering into new multi-year sales agreements with these customers, but these negotiations may not be successful and these customers may not continue to purchase coal from us under multi-year sales agreements. If either of these customers were to significantly reduce their purchases of coal from us, or if we were unable to sell coal to them on terms as favorable to us as the terms under our current agreements, our profitability could be adversely affected. Please read “Business—Our Customers and Contracts” for additional information.

Certain provisions in our multi-year sales contracts may provide limited protection during adverse economic conditions, may result in economic penalties to us or permit the customer to terminate the contract.

Price adjustment, “price reopener” and other similar provisions in our multi-year sales contracts may reduce the protection from short-term coal price volatility traditionally provided by such contracts. Price reopener provisions are present in several of our multi-year sales contracts. These price reopener provisions may automatically set a new price based on prevailing market price or, in some instances, require the parties to agree on a new price, sometimes within a specified range of prices. In a limited number of agreements, failure of the parties to agree on a price under a price reopener provision can lead to termination of the contract. Any adjustment or renegotiations leading to a significantly lower contract price could adversely affect our profitability.

Most of our sales agreements contain provisions requiring us to deliver coal within certain ranges for specific coal characteristics such as heat content, sulfur, ash, moisture, volatile matter, grindability, chlorine and ash fusion temperature. Failure to meet these conditions could result in penalties or rejection of the coal at the election of the customer. Our sales contracts also typically contain force majeure provisions allowing for the suspension of performance by either party for the duration of specified events. Force majeure events include, but are not limited to, floods, earthquakes, storms, fire, faults in the coal seam or other geologic conditions, other natural catastrophes, wars, terrorist acts, civil disturbances or disobedience, strikes, railroad transportation delays caused by a force majeure event and actions or restraints by court order and governmental authority or arbitration award. Depending on the language of the contract, some contracts may terminate upon continuance of an event of force majeure that extends for a period greater than three to twelve months.

 

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Our ability to collect payments from our customers could be impaired if their creditworthiness declines or if they fail to honor their contracts with us.

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 with respect to 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 with respect to payment default. We also have a contract to supply coal to an energy trading and brokering customer under which that customer sells coal to end users. If the creditworthiness of our energy trading and brokering customer declines, we may not be able to collect payment for all coal sold and delivered to or on behalf of this customer. In addition, if customers refuse to accept shipments of our coal for which they have an existing contractual obligation, our revenues will decrease and we may have to reduce production at our mines until our customers’ contractual obligations are honored. Our inability to collect payment from counterparties to our sales contracts may materially adversely affect our business, financial condition, results of operations, cash flows and ability to make cash distributions.

To maintain and grow our business, we will be required to make substantial capital expenditures. If we are unable to obtain needed capital or financing on satisfactory terms, our ability to make cash distributions may be diminished or our financial leverage could increase.

In order to maintain and grow our business, we will need to make substantial capital expenditures to fund our share of capital expenditures associated with 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 mining infrastructure 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.

If we do not make sufficient or effective capital expenditures, we will be unable to maintain and grow our business and, as a result, we may be unable to maintain or raise the level of our future cash distributions over the long term. To fund our capital expenditures, we will be required to use cash from our operations, incur debt or sell additional common units or other equity securities. Using cash from our operations will reduce cash available for distribution to our unitholders. Our ability to obtain bank financing or our ability to access the capital markets for future equity or debt offerings may be limited by our financial condition at the time of any such financing or offering and the covenants in our existing debt agreements, as well as by general economic conditions, contingencies and uncertainties that are beyond our control.

In addition, incurring additional debt may significantly increase our interest expense and financial leverage, and issuing additional limited partner interests may result in significant unitholder dilution and would increase the aggregate amount of cash required to maintain the then current distribution rate, which could materially decrease our ability to pay distributions at the then prevailing distribution rate. While we have historically received funding from our sponsor, none of our sponsor, our general partner or any of their respective affiliates is committed to providing any direct or indirect financial support to fund our growth.

 

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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.

Coal mining consumes large quantities of commodities including steel, copper, rubber products and liquid fuels and requires the use of capital equipment. Some commodities, such as steel, are needed to comply with roof control plans required by regulation. The prices we pay for commodities and capital equipment are strongly impacted by the global market. A rapid or significant increase in the costs of commodities or capital equipment we use in our operations could impact our mining operations costs because we may have a limited ability to negotiate lower prices and, in some cases, may not have a ready substitute.

We use equipment in our coal mining and transportation operations such as continuous mining units, 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 in the mining process. If the price of steel or other 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 and adversely impact our business, financial condition, results of operations, cash flows and ability to make cash distributions.

Restrictions in our new revolving credit facility could adversely affect our business, financial condition, results of operations and ability to make quarterly cash distributions to our unitholders.

We expect to enter into a new revolving credit facility prior to or in connection with the closing of this offering. Our new revolving credit facility will limit our ability to, among other things:

 

    incur or guarantee additional debt;

 

    redeem or repurchase units or make distributions under certain circumstances;

 

    make certain investments and acquisitions;

 

    incur certain liens or permit them to exist;

 

    enter into certain types of transactions with affiliates;

 

    merge or consolidate with another company; and

 

    transfer, sell or otherwise dispose of assets.

Our new revolving credit facility will also contain covenants requiring us to maintain certain financial ratios. For example, we may not permit the ratio of (i) consolidated total funded debt (as defined in the agreement governing our revolving credit facility) as of the last day of each fiscal quarter to (ii) consolidated EBITDA (as defined in the agreement governing our revolving credit facility) for the four consecutive fiscal quarters ending on the last day of such fiscal quarter to exceed         to 1.00. In addition, we may not permit the ratio of (i) consolidated EBITDA for the four consecutive fiscal quarters ending on the last day of each fiscal

 

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quarter to (ii) consolidated interest expense (as defined in the agreement governing our revolving credit facility) for such four consecutive fiscal quarters to be less than         to 1.00. Our ability to meet those financial ratios and tests can be affected by events beyond our control, and we cannot assure you that we will meet any such ratios and tests.

The provisions of our new revolving credit facility may affect our ability to obtain future financing and pursue attractive business opportunities and our flexibility in planning for, and reacting to, changes in business conditions. In addition, a failure to comply with the provisions of our new revolving credit facility could result in a default or an event of default that could enable our lenders to declare the outstanding principal of that debt, together with accrued and unpaid interest, to be immediately due and payable. If the payment of our debt is accelerated, our assets may be insufficient to repay such debt in full, and our unitholders could experience a partial or total loss of their investment. Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Capital Resources and Liquidity.”

Debt we incur in the future may limit our flexibility to obtain financing and to pursue other business opportunities.

Our future level of debt could have important consequences to us, including the following:

 

    our ability to obtain additional financing, if necessary, for working capital, capital expenditures or other purposes may be impaired or such financing may not be available on favorable terms;

 

    our funds available for operations, future business opportunities and distributions to unitholders will be reduced by that portion of our cash flow required to make interest payments on our debt;

 

    we may be more vulnerable to competitive pressures or a downturn in our business or the economy generally; and

 

    our flexibility in responding to changing business and economic conditions may be limited.

Our ability to service our debt will depend upon, among other things, our future financial and operating performance, which will be affected by prevailing economic conditions and financial, business, regulatory and other factors, some of which are beyond our control. If our operating results are not sufficient to service any future indebtedness, we will be forced to take actions such as reducing distributions, reducing or delaying our business activities, investments or capital expenditures, selling assets or issuing equity. We may not be able to effect any of these actions on satisfactory terms or at all.

Increases in interest rates could adversely affect our business.

We will have exposure to increases in interest rates. In connection with the completion of this offering, we expect to enter into a new revolving credit facility. Assuming our average debt level of $         million, comprised of funds drawn on our new revolving credit facility, an increase of one percentage point in the interest rates will result in an increase in annual interest expense of $         million. As a result, our results of operations, cash flows and financial condition and, as a result, our ability to make cash distributions to our unitholders, could be materially adversely affected by significant increases in interest rates.

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

The amount of distributable cash flow that we have available for distribution depends primarily upon our cash flow and not solely on our profitability, which will be affected by non-cash items. As a result, we may

 

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make cash distributions during periods when we record a net loss for financial accounting purposes; and conversely, we might determine not to make cash distributions during periods when we record net income for financial accounting purposes.

Our mines are located in areas containing oil and natural gas shale plays, which may require us to coordinate our operations with oil and natural gas drillers.

All of our coal reserves are in areas containing shale oil and natural gas plays, including the Marcellus Shale, which are currently the subject of substantial exploration for oil and natural gas, particularly by horizontal drilling. If we have received a permit for our mining activities, then while we will have to coordinate our mining with such oil and natural gas drillers, our mining activities will have priority over any oil and natural gas drillers with respect to the land covered by our permit. For reserves outside of our permits, we engage in discussions with drilling companies on potential areas on which they can drill that may have a minimal effect on our mine plan.

If a well is in the path of our mining for coal on land that has not yet been permitted for our mining activities, we may not be able to mine through the well unless we purchase it. Although in the past we have purchased vertical wells, the cost of purchasing a producing horizontal well could be substantially greater than that of a vertical well. Horizontal wells with multiple laterals extending from the well pad may access larger oil and natural gas reserves than a vertical well, which would typically result in a higher cost to acquire. The cost associated with purchasing oil and natural gas wells that are in the path of our coal mining activities may make mining through those wells uneconomical, thereby effectively causing a loss of significant portions of our coal reserves, which could materially and adversely affect our business, financial condition, results of operations, cash flows and ability to make cash distributions.

We may incur additional costs and delays to produce coal because we have to acquire additional property rights to perfect our title to coal rights. If we fail to acquire additional property rights to perfect our title to coal rights, we may have to reduce our estimated reserves.

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. While chain of title for our coal estate generally has been established, there may be defects in it that we do not realize until we have committed to developing those coal reserves. As such, the title to the coal estate that we intend to mine may contain defects. 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. In order to conduct our mining operations on properties where these defects exist, we may incur unanticipated costs perfecting title. If we cannot cure these defects, we may have to reduce our coal reserves and, as a result, our business, financial condition, results of operations, cash flows and ability to make cash distributions may be materially adversely affected.

We do not have any officers or employees and rely on officers of our general partner and employees of our sponsor.

We are managed and operated by the board of directors and executive officers of our general partner. Our general partner has no field-level employees that conduct mining operations and relies on the employees of our sponsor to conduct mining activities.

Our sponsor conducts businesses and activities of its own in which we have no economic interest. As a result, there could be material competition for the time and effort of the officers and employees who provide services to both our general partner and to our sponsor. If our general partner and the officers and employees of our sponsor do not devote sufficient attention to the management and operation of our business and activities, our business, financial condition, results of operations, cash flows and ability to make cash distributions could be materially adversely affected.

 

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We operate our mines with a work force that is employed exclusively by our sponsor. While none of our sponsor’s employees who conduct mining operations at the Pennsylvania mining complex are currently members of unions, our business could be adversely affected by union activities.

None of our sponsor’s employees who conduct mining operations at the Pennsylvania mining complex are represented by a labor union or covered under a collective bargaining agreement, although many employers in our industry have employees who belong to a union. It is possible that our sponsor’s employees who conduct mining operations at the Pennsylvania mining complex may join or seek recognition to form a labor union, or our sponsor may be required to become a labor agreement signatory. If some or all of the employees who conduct mining operations at the Pennsylvania mining complex were to become unionized, it could adversely affect productivity, increase labor costs and increase the risk of work stoppages at our mines. If a work stoppage were to occur, it could interfere with operations at the Pennsylvania mining complex and have a material adverse effect on our business, financial condition, results of operations, cash flows and ability to make cash distributions. In addition, the mere fact that a portion of our sponsor’s labor force could be unionized may harm our reputation in the eyes of some investors and thereby negatively affect our common unit price.

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 have a holding company structure, meaning the sole source of our earnings and cash flow consists exclusively of the earnings of and cash distributions from our direct and indirect subsidiaries. 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 distributions 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 our new revolving credit facility will place limitations on the ability of our subsidiaries to pay distributions to us, and thus on our ability to pay distributions to our unitholders. In the event that we do not receive distributions from our subsidiaries, we may be unable to make cash distributions to our unitholders.

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

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

 

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Risks Related to Environmental, Health, Safety and Other Regulations

Regulation of greenhouse gas emissions as well as uncertainty concerning such regulation could adversely impact the market for coal, increase our operating costs, and reduce the value of our coal assets.

Climate change continues to attract considerable public and scientific attention with widespread concern about the impacts of human activity on such changes, especially the emission of greenhouse gases (“GHGs”). The mining and combustion of fossil fuels, like the coal that we produce, results in the emission of GHGs, including from end-users like coal-fired power plants. As a result, numerous proposals have been made and are likely to continue to be made at the international, national, regional and state levels of government to monitor and limit emissions of GHGs. For example, while federal climate change legislation is unlikely in the next several years, several states have already adopted measures requiring GHG emissions to be reduced within state boundaries, including cap-and-trade programs and the imposition of renewable energy portfolio standards. Internationally, the Kyoto Protocol, which set binding emission targets for developed countries (but was never ratified by the United States) was nominally extended past its expiration date of December 2012 with a requirement for a new legal construct to be put into place by 2015. In addition, in November 2014, President Obama announced that the United States would seek to cut net greenhouse gas emissions 26-28 percent below 2005 levels by 2025 in return for China’s commitment to seek to peak emissions around 2030, with concurrent increases in renewable energy.

Following a Supreme Court decision effectively mandating that the EPA regulate GHGs from cars and trucks under the Clean Air Act (“CAA”), the EPA has begun to regulate GHG emissions from power plants under the CAA. For example, on January 8, 2014, the EPA re-proposed New Source Performance Standards (“NSPS”) for carbon dioxide (“CO2”) for new fossil fuel fired power plants and rescinded the rules that were proposed on April 12, 2012. These proposed rules will also require carbon capture and sequestration (“CCS”) for new coal-fired power plants. In addition, on June 2, 2014, the EPA announced the Clean Power Plan, which proposes to limit CO2 emissions from existing power plants.

Adoption of comprehensive legislation or regulation focusing on GHG emission reductions for the United States or other countries where we sell coal, or the inability of utilities to obtain financing in connection with coal-fired plants, may make it more costly to operate coal-fired electric power generation plants and make coal less attractive for electric utility power plants in the future. Apart from actual regulation, uncertainty over the extent of regulation of GHG emissions may inhibit utilities from investing in the building of new coal-fired plants to replace older plants or investing in the upgrading of existing coal-fired plants. Any reduction in the amount of coal consumed by electric power generators as a result of actual or potential regulation of greenhouse gas emissions could decrease demand for our coal, thereby reducing our revenues and materially and adversely affecting our business and results of operations. We or our customers may also have to invest in carbon dioxide capture and storage technologies in order to burn coal and comply with future GHG emission standards.

Apart from governmental regulation, on February 4, 2008, three of Wall Street’s largest investment banks announced that they had adopted climate change guidelines for lenders. The guidelines require the evaluation of carbon risks in the financing of electric power generation plants which may make it more difficult for utilities to obtain financing for coal-fired plants.

In addition, coalbed methane must be expelled from our underground coal mines for mining safety reasons. Coalbed methane has a greater GHG effect than carbon dioxide. CNX Gas Corporation’s (“CNX Gas”) gas operations capture coalbed methane from our underground coal mines, although some coalbed methane is vented into the atmosphere when the coal is mined. In June 2010, Earth Justice petitioned the EPA to make a finding that emissions from coal mines endangered public health and welfare, and to list them as a stationary source subject to further regulation of emissions. On April 30, 2013, the EPA denied the petition. Judicial challenges seeking to force EPA to list coal mines as a stationary source have likewise been unsuccessful to-date.

 

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If in the future the agency were to make an endangerment finding, we may have to further reduce our methane emissions, install additional air pollution controls, pay higher taxes, incur costs to purchase credits that permit us to continue operations as they now exist at our underground coal mines or perhaps curtail coal production.

The characteristics of coal may make it costly for electric power generators and other coal users to comply with various environmental standards regarding the emissions of impurities released when coal is burned, which could cause utilities to replace coal-fired power plants with plants utilizing alternative fuels. In addition, various incentives have been proposed to encourage the generation of electricity from renewable energy sources. A reduction in the use of coal for electric power generation could decrease the volume of our coal sales and adversely affect our results of operations.

Coal contains impurities, including sulfur, mercury, chlorine and other elements or compounds, many of which are released into the air when coal is burned. Complying with regulations to address these emissions can be costly for electric power generators. For example, in order to meet the CAA limits for sulfur dioxide emissions from electric power plants, coal users need to install costly pollution control devices, use sulfur dioxide emission allowances (some of which they may purchase), or switch to other fuels.

Recent EPA rulemakings requiring additional reductions in permissible emission levels of impurities by coal-fired plants will likely make it more costly to operate coal-fired electric power plants and may make coal a less attractive fuel alternative for electric power generation in the future. Examples include the adoption of the Cross-State Air Pollution Rule (“CSAPR”) and the MATS rules. Indeed, a number of coal-fired power plants, particularly smaller and older plants, have retired or announced that they will retire rather than retrofit to meet the obligations of the MATS rules. The MATS rules, in combination with other environmental regulations and economic factors, resulted in the retirement of more than 20 GW of domestic coal-fired generating capacity prior to 2015 and has led to the announcement of more than 40 GW of additional domestic coal-fired generating capacity for the period from 2015 through 2019. For the year ended December 31, 2014, we sold approximately 1.5 million tons of coal to power plants in our core market states (Massachusetts, New Hampshire, New York, New Jersey, Pennsylvania, Maryland, Delaware, West Virginia, North Carolina and South Carolina) that have announced plans to retire prior to 2020 and represent approximately 2 GW of generating capacity. Additional retirements of coal-fired power plants by our customers could further decrease demand for thermal coal and reduce our revenues and adversely affect our business and results of operations.

Apart from actual and potential regulation of emissions and solid wastes from coal-fired plants, state and federal mandates for increased use of electricity from renewable energy sources could have an impact on the market for our coal. Several states have enacted legislative mandates requiring electricity suppliers to use renewable energy sources to generate a certain percentage of power. There have been numerous proposals to establish a similar uniform, national standard although none of these proposals have been enacted to date. Possible advances in technologies and incentives, such as tax credits, to enhance the economics of renewable energy sources could make these sources more competitive with coal. Any reductions in the amount of coal consumed by electric power generators as a result of current or new standards for the emission of impurities or incentives to switch to alternative fuels or renewable energy sources could reduce the demand for our coal, thereby reducing our revenues and adversely affecting our business and results of operations.

Existing and future government laws, regulations and other legal requirements relating to protection of the environment, and others that govern our business may increase our costs of doing business and may restrict our coal operations.

We are subject to laws, regulations and other legal requirements enacted by federal, state and local authorities relating to protection of the environment. These include those legal requirements that govern discharges of substances into the air and water, the management and disposal of hazardous substances and wastes, the cleanup of contaminated sites, threatened and endangered plant and wildlife protection, reclamation and restoration of mining properties after mining is completed, the installation of various safety equipment in our

 

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mines, remediation of impacts of surface subsidence from underground mining, and work practices related to employee health and safety. Complying with these requirements, including the terms of our permits, has had, and will continue to have, a significant effect on our costs of operations. In addition, there is the possibility that we could incur substantial costs as a result of violations under environmental laws, or in connection with the investigation and remediation of environmental contamination. Any additional laws, regulations and other legal requirements enacted or adopted by federal, state and local authorities, or new interpretations of existing legal requirements by regulatory bodies relating to the protection of the environment could further affect our costs of operations. Please read “Business—Laws and Regulations.”

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

Our operations currently use hazardous materials and generate limited quantities of hazardous wastes from time to time. Drainage flowing from or caused by mining activities can be acidic with elevated levels of dissolved metals, a condition referred to as “acid mine drainage.” We could become subject to claims for toxic torts, natural resource damages and other damages as well as for the investigation and clean-up of soil, surface water, groundwater, and other media. Such claims may arise, for example, out of conditions at sites that we currently own or operate, as well as at sites that we previously owned or operated, or may acquire. Our liability for such claims may be joint and several, so that we may be held responsible for more than our share of the contamination or other damages, or for the entire share.

We maintain coal refuse areas and slurry impoundments at the Pennsylvania mining complex. Such areas and impoundments are subject to extensive regulation. Structural failure of a slurry impoundment or coal refuse area could result in extensive damage to the environment and natural resources, such as bodies of water that the coal slurry reaches, as well as liability for related personal injuries and property damages, and injuries to wildlife. Some of our impoundments overlie mined out areas, which can pose a heightened risk of failure and of damages arising out of failure. If one of our impoundments were to fail, we could be subject to claims for the resulting environmental contamination and associated liability, as well as for fines and penalties. Our coal refuse areas and slurry impoundments are designed, constructed, and inspected by our company and by regulatory authorities according to stringent environmental and safety standards.

We must obtain, maintain, and renew governmental permits and approvals which if we cannot obtain in a timely manner could reduce our production, cash flow and results of operations.

Our coal production is dependent on our ability to obtain various federal and state permits and approvals to mine our coal reserves. The permitting rules, and the interpretations of these rules, are complex, change frequently, and are often subject to discretionary interpretations by regulators. The EPA also has the authority to veto permits issued by the U.S. Army Corps of Engineers under the Clean Water Act’s Section 404 program that prohibits the discharge of dredged or fill material into regulated waters without a permit. In addition, the public, including non-governmental organizations and individuals, have certain statutory rights to comment upon and otherwise impact the permitting process, including through court intervention. The pace with which the government issues permits needed for new operations and for on-going operations to continue mining has negatively impacted expected production. These delays or denials of mining permits could reduce our production, cash flow and results of operations.

In 2005, the Pennsylvania Department of Environmental Protection (“PADEP”) issued a technical guidance document that imposes standards in the material mining permits that we hold, including potentially costly stream mitigation and monitoring requirements and alterations to our longwall mining plans. We have filed permit appeals challenging the PADEP’s use and application of the technical guidance document to our mines, which we expect to be resolved by later this year. If these challenges are unsuccessful, we could incur material costs to comply with the technical guidance document requirements, including costs to avoid streams and other water bodies of concern. In addition, we may be required to alter our mine plans, which could result in a reduction in our accessible reserves in the affected mines.

 

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Our mines are subject to stringent federal and state safety regulations that increase our cost of doing business at active operations and may place restrictions on our methods of operation. In addition, government inspectors under certain circumstances, have the ability to order our operations to be shutdown based on safety considerations.

The Coal Mine Safety and Health Act and Mine Improvement and New Emergency Response Act impose stringent health and safety standards on mining operations. Regulations that have been adopted under the Act are comprehensive and affect numerous aspects of mining operations, including training of mine personnel, mining procedures, the equipment used in emergency procedures, and other matters. Pennsylvania has a similar program for mine safety and health regulation and enforcement. The various requirements mandated by law or regulation can place restrictions on our methods of operations, and potentially lead to fees and civil penalties for the violation of such requirements, creating a significant effect on operating costs and productivity. In addition, government inspectors under certain circumstances, have the ability to order our operation to be shutdown based on safety considerations. If an incident were to occur at one of our mines, it could be shut down for an extended period of time and our reputation with our customers could be materially damaged.

We have reclamation and mine closing obligations. If the assumptions underlying our accruals are inaccurate, we could be required to expend greater amounts than anticipated.

The Surface Mining Control and Reclamation Act establishes operational, reclamation and closure standards for our mining operations. We accrue for the costs of current mine disturbance and of final mine closure, including the cost of treating mine water discharge where necessary. The amounts recorded are dependent upon a number of variables, including the estimated future closure costs, estimated proven reserves, assumptions involving profit margins, inflation rates, and the assumed credit-adjusted risk-free interest rates. If these accruals are insufficient or our liability in a particular year is greater than currently anticipated, our future operating results could be adversely affected. We are also required to post bonds for the cost of coal mine reclamation, which is being expanded in Pennsylvania to cover all coal mine bonding, further increasing the amount of surety bonds we must seek in order to permit our mining activities.

Risks Inherent in an Investment in Us

Our general partner and its affiliates, including our sponsor, have conflicts of interest with us and limited fiduciary duties to us and our unitholders, and they may favor their own interests to our detriment and that of our unitholders. Additionally, we have no control over the business decisions and operations of our sponsor, and our sponsor is under no obligation to adopt a business strategy that favors us.

Following the completion of this offering, our sponsor will own and control our general partner and will appoint all of the directors of our general partner. In addition, our sponsor will directly own an aggregate     % limited partner interest in us (or an aggregate     % limited partner interest in us if the underwriters exercise in full their option to purchase additional common units), as well as, through its ownership of our general partner, all of our incentive distribution rights. Our sponsor will also continue to own an 80% undivided interest in the Pennsylvania mining complex following the completion of this offering. Although our general partner has a duty to manage us in a manner that is in the best interests of our partnership and our unitholders, the directors and officers of our general partner also have a duty to manage our general partner in a manner that is in the best interests of our sponsor. Conflicts of interest may arise between our sponsor and its affiliates, including our general partner, on the one hand, and us and our unitholders, on the other hand. In resolving these conflicts of interests, our general partner may favor its own interests and the interests of its affiliates, including our sponsor, over the interests of our common unitholders. These conflicts include, among others, the following situations:

 

    neither our partnership agreement nor any other agreement requires our sponsor to pursue a business strategy that favors us or utilizes our assets, which could involve decisions by our sponsor to pursue and grow particular markets or undertake acquisition opportunities for itself. Our sponsor’s directors and officers have a fiduciary duty to make these decisions in the best interests of our sponsor;

 

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    our general partner is allowed to take into account the interests of parties other than us, such as our sponsor, in resolving conflicts of interest;

 

    our sponsor may be constrained by the terms of its debt instruments from taking actions, or refraining from taking actions, that may be in our best interests;

 

    our partnership agreement replaces the fiduciary duties that would otherwise be owed by our general partner with contractual standards governing its duties, limiting our general partner’s liabilities and restricting the remedies available to our unitholders for actions that, without such limitations, might constitute breaches of fiduciary duty under Delaware law;

 

    except in limited circumstances, our general partner has the power and authority to conduct our business without unitholder approval;

 

    our general partner will determine the amount and timing of, among other things, cash expenditures, borrowings and repayments of indebtedness, the issuance of additional partnership interests, the creation, increase or reduction in cash reserves in any quarter and asset purchases and sales, each of which can affect the amount of cash that is available for distribution to unitholders;

 

    our general partner will determine the amount and timing of any capital expenditures and whether a capital expenditure is classified as a maintenance capital expenditure, which reduces operating surplus, or an expansion capital expenditure, which does not reduce operating surplus. This determination can affect the amount of available cash from operating surplus that is distributed to our unitholders and to our general partner, the amount of adjusted operating surplus generated in any given period and the ability of the subordinated units to convert into common units;

 

    our general partner will determine which costs and expenses incurred by it are reimbursable by us;

 

    our general partner may cause us to borrow funds in order to permit the payment of cash distributions, even if the purpose or effect of the borrowing is to make a distribution on the subordinated units, to make incentive distributions or to accelerate the expiration of the subordination period;

 

    our partnership agreement permits us to distribute up to $         million as operating surplus, even if it is generated from asset sales, non-working capital borrowings or other sources that would otherwise constitute capital surplus. This cash may be used to fund distributions on our subordinated units or to our general partner in respect of the general partner interest or the incentive distribution rights;

 

    our partnership agreement does not restrict our general partner from causing us to pay it or its affiliates for any services rendered to us or entering into additional contractual arrangements with any of these entities on our behalf;

 

    our general partner intends to limit its liability regarding our contractual and other obligations;

 

    our general partner may exercise its right to call and purchase all of the common units not owned by it and its affiliates at a price not less than the then-current market price if it and its affiliates own more than 80% of our common units;

 

    our general partner controls the enforcement of obligations owed to us by our general partner and its affiliates, including obligations under our operating agreement and employee services agreement;

 

    our general partner decides whether to retain separate counsel, accountants or others to perform services for us; and

 

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    our general partner, or any transferee holding incentive distribution rights, may elect to cause us to issue common units and general partner interests to it in connection with a resetting of the target distribution levels related to its incentive distribution rights, without the approval of the conflicts committee of the board of directors of our general partner, which we refer to as our conflicts committee, or our common unitholders. This election could result in lower distributions to our common unitholders in certain situations.

Neither our partnership agreement nor our omnibus agreement will prohibit our sponsor or any other affiliates of our general partner from owning assets or engaging in businesses that compete directly or indirectly with us. Under the terms of our partnership agreement, the doctrine of corporate opportunity, or any analogous doctrine, will not apply to our general partner or any of its affiliates, including 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. Consequently, our sponsor and other affiliates of our general partner may acquire, construct or dispose of additional coal assets in the future without any obligation to offer us the opportunity to purchase any of those assets. As a result, competition from our sponsor and other affiliates of our general partner could materially and adversely impact our results of operations and distributable cash flow. 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 “Certain Relationships and Related Party Transactions—Agreements Governing the Transactions—Omnibus Agreement” and “Conflicts of Interest and Duties.”

Our partnership agreement requires that we distribute all of our available cash, which could limit our ability to grow and make acquisitions.

Our partnership agreement requires that we distribute all of our available cash to our unitholders. As a result, we expect to rely primarily upon external financing sources, including commercial bank borrowings and the issuance of debt and equity securities, to fund our acquisitions and expansion capital expenditures. Therefore, to the extent we are unable to finance our growth externally, our cash distribution policy will significantly impair our ability to grow. In addition, because we will distribute all of our available cash, our growth may not be as fast as that of businesses that reinvest their available cash to expand ongoing operations. To the extent we issue additional partnership interests in connection with any acquisitions or expansion capital expenditures, the payment of distributions on those additional partnership interests 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 partnership interests, including partnership interests ranking senior to our common units as to distributions or in liquidation or that have special voting rights and other rights, and our common unitholders will have no preemptive or other rights (solely as a result of their status as common unitholders) to purchase any such additional partnership interests. The incurrence of additional commercial bank borrowings or other debt to finance our growth strategy would result in increased interest expense, which, in turn, may reduce the amount of cash that we have available to distribute to our unitholders.

While our partnership agreement requires us to distribute all of our available cash, our partnership agreement, including the provisions requiring us to make cash distributions, may be amended.

While our partnership agreement requires us to distribute all of our available cash, our partnership agreement, including the provisions requiring us to make cash distributions, may be amended. During the subordination period, our partnership agreement may not be amended without the approval of our public common unitholders, except in a limited number of circumstances when our general partner can amend our partnership agreement without any unitholder approval. For a description of these limited circumstances, please read “Our Partnership Agreement—Amendment of Our Partnership Agreement—No Unitholder Approval.”

 

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However, after the subordination period has ended, our partnership agreement may be amended with the consent of our general partner and the approval of a majority of the outstanding common units, including common units owned by our general partner and its affiliates. At the completion of this offering, our sponsor will own an aggregate of approximately     % of our outstanding common units (assuming the underwriters do not exercise their option to purchase additional common units) and all of our subordinated units.

Our partnership agreement replaces our general partner’s fiduciary duties to holders of our common units with contractual standards governing its duties.

Delaware law provides that a Delaware limited partnership may, in its partnership agreement, expand, restrict or eliminate the fiduciary duties otherwise owed by the general partner to limited partners and the partnership, provided that the partnership agreement may not eliminate the implied contractual covenant of good faith and fair dealing. This implied covenant is a judicial doctrine utilized by Delaware courts in connection with interpreting ambiguities in partnership agreements and other contracts, and does not form the basis of any separate or independent fiduciary duty in addition to the express contractual duties set forth in our partnership agreement. Under the implied contractual covenant of good faith and fair dealing, a court will enforce the reasonable expectations of the partners where the language in the partnership agreement does not provide for a clear course of action.

As permitted by Delaware law, our partnership agreement contains provisions that eliminate the fiduciary standards to which our general partner would otherwise be held by state fiduciary duty law and replaces those duties with several different contractual standards. 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, free of any duties to us and our unitholders. This provision entitles our general partner to consider only the interests and factors that it desires and relieves it of any duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates or our limited partners. Examples of decisions that our general partner may make in its individual capacity include:

 

    how to allocate business opportunities among us and affiliates of our general partner;

 

    whether to exercise its limited call right;

 

    how to exercise its voting rights with respect to any units it owns;

 

    whether to exercise its registration rights;

 

    whether to sell or otherwise dispose of units or other partnership interests that it owns;

 

    whether to elect to reset target distribution levels;

 

    whether to consent to any merger, consolidation or conversion of the partnership or amendment to our partnership agreement; and

 

    whether to refer or not to refer any potential conflict of interest to the conflicts committee for special approval or to seek or not to seek unitholder approval.

By purchasing a common unit, a unitholder is treated as having consented to the provisions in our partnership agreement, including the provisions discussed above. Please read “Conflicts of Interest and Duties—Duties of Our General Partner.”

 

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

Our general partner intends to limit its liability under contractual arrangements so that counterparties to such agreements have recourse only against our assets and not against our general partner or its assets or any affiliate of 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 terms that are more favorable 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.

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

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

 

    whenever our general partner makes a determination or takes, or declines to take, any other action in its capacity as our general partner, our general partner is required to make such determination, or take or decline to take such other action, in good faith, meaning that it subjectively believed that the determination or the decision to take or decline to take such action was in the best interests of our partnership, and will not be subject to any other or different standard imposed by our partnership agreement, Delaware law, or any other law, rule or regulation, or at equity;

 

    our general partner will not have any liability to us or our unitholders for decisions made in its capacity as a general partner so long as it acted in good faith;

 

    our general partner and its officers and directors will not be liable for monetary damages to us or our limited partners resulting from any act or omission unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that our general partner or its officers and directors, as the case may be, acted in bad faith or engaged in actual fraud or willful misconduct or, in the case of a criminal matter, acted with knowledge that the conduct was criminal; and

 

    our general partner will not be in breach of its obligations under our partnership agreement or its duties to us or our limited partners if a transaction with an affiliate or the resolution of a conflict of interest is approved in accordance with, or otherwise meets the standards set forth in, our partnership agreement.

In connection with a situation involving a transaction with an affiliate or a conflict of interest, our partnership agreement provides that any determination by our general partner must be made in good faith, and that our conflicts committee and the board of directors of our general partner are entitled to a presumption that they acted in good faith. 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 Duties.”

Cost and expense reimbursements, which will be determined by our general partner in its sole discretion, and fees due to our general partner and its affiliates for services provided will be substantial and will reduce our distributable cash flow.

Under our partnership agreement, we are required to reimburse our general partner and its affiliates for all direct and indirect expenses it incurs or payments it makes on our behalf and all other expenses allocable to us

 

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or otherwise incurred by our general partner and its affiliates in connection with managing and operating our business and affairs (including expenses allocated to our general partner by its affiliates). Except to the extent specified under our omnibus agreement and the other agreements described under “Certain Relationships and Related Party Transactions—Agreements Governing the Transactions,” our general partner determines the amount of these expenses. Under the terms of the omnibus agreement we will be required to reimburse our sponsor for the provision of certain administrative support services to us. Under our employee services agreement, we will be required to reimburse our sponsor for all direct third-party and allocated costs and expenses actually incurred by our sponsor in providing operational services. Our general partner and its affiliates also may provide us other services for which we will be charged fees as determined by our general partner. The costs and expenses for which we will reimburse our general partner and its affiliates may 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. The costs and expenses for which we are required to reimburse our general partner and its affiliates are not subject to any caps or other limits under our partnership agreement. We estimate that the total amount of such reimbursed expenses will be approximately $         million for the twelve months ending June 30, 2016. Please read “Cash Distribution Policy and Restrictions on Distributions—Estimated Adjusted EBITDA and Distributable Cash Flow for the Twelve Months Ending June 30, 2016.” Payments to our general partner and its affiliates will be substantial and will reduce the amount of cash we have available to distribute to unitholders.

Unitholders have very limited voting rights and, even if they are dissatisfied, they will have limited ability to remove our general partner.

Unlike the holders of common stock in a corporation, unitholders have only limited voting rights on matters affecting our business and, therefore, limited ability to influence management’s decisions regarding our business. For example, unlike holders of stock in a public corporation, unitholders will not have “say-on-pay” advisory voting rights. Unitholders did not elect our general partner or the board of directors of our general partner and will have no right to elect our general partner or the board of directors of our general partner on an annual or other continuing basis. Through its direct ownership of our general partner, our sponsor has the right to appoint the entire board of directors of our general partner, including our independent directors. Furthermore, if the unitholders are dissatisfied with the performance of our general partner, they will have little ability to remove our general partner. As a result of these limitations, the price at which our common units will trade could be diminished because of the absence or reduction of a takeover premium in the trading price.

Our general partner may not be removed unless such removal is both (i) for cause and (ii) approved by a vote of the holders of at least 66 23% of the outstanding units, including any units owned by our general partner and its affiliates, voting together as a single class. “Cause” is narrowly defined under our partnership agreement to mean that a court of competent jurisdiction has entered a final, non-appealable judgment finding our general partner liable to us or any limited partner for actual fraud or willful misconduct in its capacity as our general partner. Cause does not include most cases of charges of poor management of the business. Following the completion of this offering, our sponsor will own     % of our total outstanding common units and subordinated units on an aggregate basis (or     % of our total outstanding common units and subordinated units on an aggregate basis if the underwriters exercise in full their option to purchase additional common units). This will give our sponsor the ability to prevent the removal of our general partner.

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

Our partnership agreement also contains provisions limiting the ability of unitholders to call meetings or to acquire information about our operations, as well as other provisions limiting the unitholders’ ability to influence the manner or direction of management.

 

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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 in us to a third party in a merger or in a sale of all or substantially all of its assets without the consent of the unitholders. Furthermore, there is no restriction in our partnership agreement on the ability of our sponsor to transfer its membership interest 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 officers of our general partner with its own choices.

The incentive distribution rights of our general partner may be transferred to a third party without unitholder consent.

Our general partner may transfer its incentive distribution rights to a third party at any time without the consent of our unitholders. If our general partner transfers its incentive distribution rights to a third party but retains its general partner interest, our general partner may not have the same incentive to grow our partnership and increase quarterly distributions to unitholders over time as it would if it had retained ownership of its incentive distribution rights. For example, a transfer of incentive distribution rights by our general partner could reduce the likelihood that our sponsor, which owns our general partner, will sell or contribute additional assets to us, as our sponsor would have less of an economic incentive to grow our business, which in turn would impact our ability to grow our asset base.

We may issue an unlimited number of additional partnership interests without unitholder approval, which would dilute our then-existing unitholders’ proportionate ownership interests in us.

At any time, we may issue an unlimited number of general partner interests or limited partner interests of any type without the approval of our unitholders and our unitholders will have no preemptive or other rights (solely as a result of their status as unitholders) to purchase any such general partner interests or limited partner interests. Further, there are no limitations in our partnership agreement on our ability to issue equity securities that rank equal or senior to our common units as to distributions or in liquidation or that have special voting rights and other rights. The issuance by us of additional common units or other equity securities of equal or senior rank will have the following effects:

 

    our then-existing unitholders’ proportionate ownership interests in us will decrease;

 

    the amount of cash we have available to distribute on each unit may decrease;

 

    because a lower percentage of total outstanding units will be subordinated units, the risk that a shortfall in the payment of the minimum quarterly distribution will be borne by our common unitholders will increase;

 

    the ratio of taxable income to distributions may increase;

 

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

 

    the market price of our common units may decline.

The issuance by us of additional general partner interests may have the following effects, among others, if such general partner interests are issued to a person who is not an affiliate of our sponsor:

 

    management of our business may no longer reside solely with our current general partner; and

 

    affiliates of the newly admitted general partner may compete with us, and neither that general partner nor such affiliates will have any obligation to present business opportunities to us except with respect to rights of first offer contained in our omnibus agreement.

 

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Our sponsor may sell units in the public or private markets, and such sales could have an adverse impact on the trading price of the common units.

After the completion of this offering, assuming that the underwriters do not exercise their option to purchase additional common units, our sponsor will hold         common units and         subordinated units. All of the subordinated units will convert into common units at the end of the subordination period. Additionally, we have agreed to provide our sponsor with certain registration rights under applicable securities laws. Please read “Units Eligible for Future Sale.” The sale of these units in the public or private markets could have an adverse impact on the price of the common units or on any trading market that may develop.

Our general partner’s discretion in establishing cash reserves may reduce the amount of cash we have available to distribute to unitholders.

Our partnership agreement requires our general partner to deduct from operating surplus the cash reserves that it determines are necessary to fund our future operating expenditures. In addition, the partnership agreement permits the general partner to reduce available cash by establishing cash reserves for the proper conduct of our business, to comply with applicable law or agreements to which we are a party, or to provide funds for future distributions to partners. These cash reserves will affect the amount of cash we have available to distribute to unitholders.

Affiliates of our general partner, including, but not limited to, our sponsor, may compete with us, and neither our general partner nor its affiliates have any obligation to present business opportunities to us except with respect to rights of first offer contained in our omnibus agreement.

Neither our partnership agreement nor our omnibus agreement will prohibit our sponsor or any other affiliates of our general partner from owning assets or engaging in businesses that compete directly or indirectly with us. Under the terms of our partnership agreement, the doctrine of corporate opportunity, or any analogous doctrine, will not apply to our general partner or any of its affiliates, including 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. Consequently, our sponsor and other affiliates of our general partner may acquire, construct or dispose of additional coal assets in the future without any obligation to offer us the opportunity to purchase any of those assets. Moreover, except for the obligations set forth in the omnibus agreement, neither our sponsor nor any of its affiliates have a contractual obligation to present us the opportunity to purchase additional assets from it, and we are unable to predict whether or when such an opportunity may be presented to us. As a result, competition from our sponsor and other affiliates of our general partner could materially and adversely impact our results of operations and distributable cash flow.

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

If at any time our general partner and its affiliates own more than 80% of our then-outstanding common units, our general partner will have the right, but not the obligation, which it may assign to any of its affiliates or to us, to acquire all, but not less than all, of the common units held by unaffiliated persons at a price not less than their then-current market price. As a result, you may be required to sell your common units at an undesirable time or price and may not receive any return on your investment. You may also incur a tax liability upon a sale of your units. Following the completion of this offering and assuming the underwriters’ option to purchase additional common units from us is not exercised, our general partner and its affiliates will own approximately     % of our common units (excluding any common units purchased by the directors, director

 

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nominee and executive officers of our general partner, directors of our sponsor and certain other individuals as selected by our sponsor under our directed unit program). At the end of the subordination period (which could occur as early as within the quarter ending                     , 2016), assuming no additional issuances of common units by us (other than upon the conversion of the subordinated units) and the underwriters’ option to purchase additional common units from us is not exercised, our general partner and its affiliates will own approximately     % of our outstanding common units (excluding any common units purchased by the directors, director nominee and executive officers of our general partner, directors of our sponsor and certain other individuals as selected by our sponsor under our directed unit program) and therefore would not be able to exercise the call right at that time. Please read “Our Partnership Agreement—Limited Call Right.”

Unitholders may have to repay distributions that were wrongfully distributed to them.

Under certain circumstances, unitholders may have to repay amounts wrongfully 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 you 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. Transferees of common units are liable for the obligations of the transferor to make contributions to the partnership that are known to the transferee at the time of the transfer and for unknown obligations if the liabilities could be determined from our partnership agreement. Liabilities to partners on account of their partnership interest and liabilities that are non-recourse to the partnership are not counted for purposes of determining whether a distribution is permitted.

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 you could lose all or part of your investment.

Prior to this offering, there has been no public market for our common units. After this offering, there will be only         publicly traded common units, assuming the underwriters’ option to purchase additional common units from us is not exercised. In addition, following the completion of this offering, our sponsor will own         common units and         subordinated units, representing an aggregate     % limited partner interest in us (or         common units and         subordinated units, representing an aggregate     % limited partner interest in us, if the underwriters exercise in full their option to purchase additional common units). We do not know the extent to which investor interest will lead to the development of an active trading market or how liquid that market might be. You may not be able to resell your 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 the common units offered hereby 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.

Our general partner, or any transferee holding incentive distribution rights, may elect to cause us to issue common units and general partner interests to it in connection with a resetting of the target distribution levels related to its incentive distribution rights, without the approval of our conflicts committee or our common unitholders. The exercise of this election could result in lower distributions to our common unitholders in certain situations.

Our general partner has the right, at any time when there are no subordinated units outstanding and it has received distributions on its incentive distribution rights at the highest level to which it is entitled (48%, in addition to distributions paid on its 2% general partner interest) for each of the prior four consecutive fiscal

 

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quarters and the amount of such distribution did not exceed the adjusted operating surplus for such quarter, to reset the initial target distribution levels at higher levels based on our distributions at the time of the exercise of the reset election. Following a reset election, the minimum quarterly distribution will be adjusted to equal 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 and a general partner interest. The number of common units to be issued to our general partner will be equal to that number of common units that would have entitled their holder to an average aggregate quarterly cash distribution in the prior two quarters equal to the average of the distributions to our general partner on the incentive distribution rights in such two quarters. Our general partner will also be issued an additional general partner interest necessary to maintain our general partner’s interest in us at the level that existed immediately 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 common unit without such conversion. It is possible, however, that our general partner could exercise this reset election at a time when it is experiencing, or expects to experience, declines in the cash distributions it receives related to its incentive distribution rights and may, therefore, desire to be issued common units rather than retain the right to receive distributions based on the initial target distribution levels. This risk could be elevated if our incentive distribution rights have been transferred to a third party. 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 and general partner interests in connection with resetting the target distribution levels. Additionally, our general partner has the right to transfer all or any portion of our incentive distribution rights at any time, and such transferee shall have the same rights as the general partner relative to resetting target distributions if our general partner concurs that the tests for resetting target distributions have been fulfilled. Please read “Provisions of Our Partnership Agreement Relating to Cash Distributions—General Partner’s Right to Reset Incentive Distribution Levels.”

You will experience immediate and substantial dilution in net tangible book value of $         per common unit.

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

Units held by persons who our general partner determines are not “eligible holders” at the time of any requested certification in the future may be subject to redemption.

As a result of certain laws and regulations to which we are or may in the future become subject, we may require owners of our common units to certify that they are both U.S. citizens and subject to U.S. federal income taxation on our income. Units held by persons who our general partner determines are not “eligible holders” at the time of any requested certification in the future may be subject to redemption. “Eligible holders” are limited partners whose (or whose owners’) (i) U.S. federal income tax status or lack of proof of U.S. federal income tax status does not have and is not reasonably likely to have, as determined by our general partner, a material adverse effect on the maximum applicable rates that can be charged to customers by us or our subsidiaries and (ii) nationality, citizenship or other related status does not create and is not reasonably likely to create, as determined by our general partner, a substantial risk of cancellation or forfeiture of any property in which we have an interest. The aggregate redemption price for redeemable interests will be an amount equal to the current market price (the date of determination of which will be the date fixed for redemption) of limited partner interests of the class to be so redeemed multiplied by the number of limited partner interests of each such class included among the redeemable interests. For these purposes, the “current market price” means, as of any date for any

 

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class of limited partner interests, the average of the daily closing prices per limited partner interest of such class for the 20 consecutive trading days immediately prior to such date. The redemption price will be paid in cash or by delivery of a promissory note, as determined by our general partner. The units held by any person the general partner determines is not an eligible holder will not be entitled to voting rights. Please read “Our Partnership Agreement—Possible Redemption of Ineligible Holders.”

Our partnership agreement will designate the Court of Chancery of the State of Delaware as the exclusive forum for certain types of actions and proceedings that may be initiated by our unitholders, which would limit our unitholders’ ability to choose the judicial forum for disputes with us or our general partner’s directors, officers or other employees.

Our partnership agreement will provide that, with certain limited exceptions, 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) shall be the exclusive forum for any claims, suits, actions or proceedings (i) arising out of or relating in any way to our partnership agreement (including any claims, suits or actions to interpret, apply or enforce the provisions of our partnership agreement or the duties, obligations or liabilities among our partners, or obligations or liabilities of our partners to us, or the rights or powers of, or restrictions on, our partners or us), (ii) brought in a derivative manner on our behalf, (iii) asserting a claim of breach of a duty owed by any of our, or our general partner’s, directors, officers, or other employees, or owed by our general partner, to us or our partners, (iv) asserting a claim against us arising pursuant to any provision of the Delaware Act or (v) asserting a claim against us governed by the internal affairs doctrine. In addition, our partnership agreement provides that each limited partner irrevocably waives the right to trial by jury in any such claim, suit, action or proceeding. 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. These provisions may have the effect of discouraging lawsuits against us and our general partner’s directors and officers. Please read “Our Partnership Agreement—Applicable Law; Exclusive Forum.”

The NYSE does not require a publicly traded limited 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 limited 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. Additionally, any future issuance of additional common units or other securities, including to affiliates, will not be subject to the NYSE’s shareholder approval rules that apply to a corporation. Accordingly, unitholders will not have the same protections afforded to certain corporations that are subject to all of the NYSE corporate governance requirements. Please read “Management—Management of CNX Coal Resources LP.”

Tax Risks

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

 

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Our tax treatment depends on our status as a partnership for U.S. federal income tax purposes. If the Internal Revenue Service (the “IRS”) were to treat us as a corporation for U.S. federal income tax purposes, which would subject us to entity-level taxation, or if we were otherwise subjected to a material amount of additional entity-level taxation, then our distributable cash flow to our unitholders would 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 U.S. federal income tax purposes. We have not requested a ruling from the IRS on this or any other tax matter affecting us.

Despite the fact that we are 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 U.S. federal income tax purposes. A change in our business or a change in current law could cause us to be treated as a corporation for U.S. federal income tax purposes or otherwise subject us to taxation as an entity.

If we were treated as a corporation for U.S. federal income tax purposes, we would pay U.S. federal income tax on our taxable income at the corporate tax rate, which is currently a maximum of 35%, and would likely pay state and local income tax at varying rates. Distributions would generally be taxed again as corporate dividends (to the extent of our current and accumulated earnings and profits), and no income, gains, losses, deductions, or credits would flow through to you. In addition, changes in current state law may subject us to additional entity-level taxation by individual states. Because of state budget deficits and other reasons, several states are evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise and other forms of taxation. For example, Pennsylvania may assess a partnership level tax if the partnership is found to have underreported income by more than $1,000,000 in any tax year. Imposition of any such taxes may substantially reduce our distributable cash flow. Therefore, if we were treated as a corporation for U.S. federal income tax purposes, or otherwise subjected to a material amount of entity-level taxation, there would be a material reduction in the anticipated cash flow and after-tax return to our 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 levels 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 U.S. federal income tax treatment of publicly traded partnerships, including us, or an investment in our common units may be modified by administrative, legislative or judicial interpretation at any time. For example, from time to time, members of Congress and the President propose and consider substantive changes to the existing U.S. federal income tax laws that affect publicly traded partnerships, including the elimination of the qualifying income exception upon which we rely for our treatment as a partnership for U.S. federal income tax purposes. For example, the Obama administration’s budget proposal for fiscal year 2016 recommends that certain publicly traded partnerships earning income from activities related to fossil fuels be taxed as corporations beginning in 2021. Any modification to the U.S. federal income tax laws and interpretations thereof may or may not be retroactively applied and could make it more difficult or impossible to meet the exception for us to be treated as a partnership for U.S. federal income tax purposes. Please read “Material Federal Income Tax Consequences—Partnership Status.” We are unable to predict whether any of these changes or other proposals will ultimately be enacted. However, it is possible that a change in law could affect us, and any such changes could negatively impact the value of an investment in our common units.

 

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Our unitholders’ allocated share of our income will be taxable to them for federal income tax purposes even if they do not receive any cash distributions from us.

Because a unitholder will be treated as a partner to whom we will allocate taxable income that could be different in amount than the cash we distribute, a unitholder’s allocable share of our taxable income will be taxable to it, which may require the payment of federal income taxes and, in some cases, state and local income taxes, on its share of our taxable income even if it receives no cash distributions from us. Our unitholders may not receive cash distributions from us equal to their share of our taxable income or even equal to the actual tax liability that results from that income.

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 distributable cash flow to our unitholders.

We have not requested a ruling from the IRS with respect to our treatment as a partnership for federal income tax purposes or any other matter affecting us. We intend to furnish to each unitholder, within 90 days after the close of each calendar year, specific tax information, including a Schedule K-1, which describes his or her share of our income, gains, losses, and deductions for our preceding taxable year. In preparing this information, we will take various accounting and reporting positions. The IRS may adopt positions that differ from the conclusions of our counsel expressed in this prospectus or from the positions we take, and the IRS’s positions may ultimately be sustained in an audit of our U.S. federal income tax information returns. It may be necessary to resort to administrative or court proceedings to sustain some or all of our counsel’s conclusions or the positions we take and such positions may not ultimately be sustained. A court may not agree with some or all of our counsel’s conclusions or the positions we take. Any contest with the IRS, and the outcome of any IRS contest, may have a materially adverse impact on the market for our common units and the price at which they 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 distributable cash flow. Adjustments resulting from an IRS audit may require each unitholder to adjust a prior year’s tax liability, and possibly may result in an audit of his or her return. Any audit to a unitholder’s return could result in adjustments not related to our returns, as well as those related to our returns.

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

If our unitholders sell common units, they will recognize a gain or loss for U.S. federal income tax purposes equal to the difference between the amount realized and their tax basis in those common units. Because distributions in excess of their allocable share of our net taxable income decrease their tax basis in their common units, the amount, if any, of such prior excess distributions with respect to the common units a unitholder sells will, in effect, become taxable income to the unitholder if it sells such common units at a price greater than its tax basis in those common units, even if the price received is less than its original cost. Furthermore, a substantial portion of the amount realized on any sale of your common units, whether or not representing gain, may be taxed as ordinary income due to potential recapture items, including depreciation and depletion recapture. In addition, because the amount realized includes a unitholder’s share of our nonrecourse liabilities, a unitholder that sells common units may incur a tax liability in excess of the amount of cash received from the sale. Please read “Material Federal Income Tax Consequences—Disposition of Common Units—Recognition of Gain or Loss.”

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

Investment in our common units by tax-exempt entities, such as employee benefit plans and individual retirement accounts (known as IRAs), and non-U.S. persons raises issues unique to them. For example, virtually all of our income allocated to organizations that are exempt from U.S. federal income tax, including IRAs and other retirement plans, will be unrelated business taxable income and will be taxable to them. Distributions to non-U.S. persons will be reduced by withholding taxes at the highest applicable effective tax rate, and each non-

 

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U.S. person will be required to file U.S. federal income tax returns and pay tax on its share of our taxable income. If you are a tax-exempt entity or a non-U.S. person, you should consult a tax advisor before investing in our common units.

We will treat each purchaser of 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 our common units.

Because we cannot match transferors and transferees of common units and because of other reasons, we will adopt depreciation and amortization positions that may not conform to all aspects of existing Treasury Regulations, promulgated under the Internal Revenue Code of 1986 (the “Internal Revenue Code”) referred to as “Treasury Regulations.” A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to you. Latham & Watkins LLP is unable to opine as to the validity of such filing positions. 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 Federal Income Tax Consequences—Tax Consequences of Unit Ownership—Section 754 Election.”

We will prorate our items of income, gain, loss and deduction for U.S. federal income tax purposes between transferors and transferees of our common units each month based upon the ownership of our common units on the first business day of each month, instead of on the basis of the date a particular common 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 will prorate our items of income, gain, loss and deduction for U.S. federal income tax purposes 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. The use of this proration method may not be permitted under existing Treasury Regulations, and, accordingly, our counsel is unable to opine as to the validity of this method. The U.S. Treasury Department has issued proposed regulations that provide a safe harbor pursuant to which publicly traded partnerships may use a similar monthly simplifying convention to allocate tax items among transferor and transferee unitholders. Nonetheless, the proposed regulations do not specifically authorize the use of the proration method we will adopt. If the IRS were to challenge this method or new Treasury Regulations were issued, we may be required to change the allocation of items of income, gain, loss and deduction among our unitholders. Latham & Watkins LLP has not rendered an opinion with respect to whether our monthly convention for allocating taxable income and losses is permitted by existing Treasury Regulations. Please read “Material Federal Income Tax Consequences—Disposition of Common Units—Allocations Between Transferors and Transferees.”

A unitholder whose common units are loaned to a “short seller” to effect a short sale of common units may be considered as having disposed of those common units. If so, he would no longer be treated for U.S. federal income 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 a unitholder whose common units are loaned to a “short seller” to effect a short sale of common units may be considered as having disposed of the loaned common units, he 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 to the short seller, any of our income, gains, losses or deductions 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. Latham & Watkins LLP has not rendered an opinion regarding the treatment of a unitholder where common units are loaned to a short seller to effect a short sale of common units. Unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a loan to a

 

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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 loaning their common units.

We will adopt certain valuation methodologies in determining a unitholder’s allocations of income, gain, loss and deduction. The IRS may challenge these methodologies or the resulting allocations, and such a challenge could adversely affect the value of our common units.

In determining the items of income, gain, loss and deduction allocable to our unitholders, in certain circumstances, including when we issue additional units, we must determine the fair market value of our assets. Although we may from time to time consult with professional appraisers regarding valuation matters, we make many fair market value estimates using a methodology based on the market value of our common units as a means to measure the fair market value of our assets. The IRS may challenge these valuation methods and the resulting allocations of income, gain, loss and deduction.

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

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 U.S. federal income tax purposes.

We will be considered to have technically terminated as a partnership for federal income tax purposes if there is a sale or exchange of 50% or more of the total interests in our capital and profits within a twelve-month period. For purposes of determining whether the 50% threshold has been met, multiple sales of the same common unit will be counted only once. Following the completion of this offering, our sponsor and our general partner will collectively own an aggregate         interest in our capital and profits (assuming that the underwriters do not exercise their option to purchase additional common units from us). Therefore, a transfer by our sponsor and our general partner of all or a portion of their interests in us could result in a termination of us as a partnership for U.S. federal income tax purposes. Our technical termination would, among other things, result in the closing of our taxable year for all unitholders, which would result in us filing two tax returns (and our unitholders could receive two Schedules K-1 if relief was not available, as described below) for one fiscal year 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 a fiscal year ending December 31, 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 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, including a new election under Section 754 of the Internal Revenue Code, and we could be subject to penalties if we are unable to determine that a termination occurred. The IRS has announced a publicly traded partnership technical termination relief program whereby, if a publicly traded partnership that technically terminated requests publicly traded partnership technical termination relief and such relief is granted by the IRS, among other things, the partnership will only have to provide one Schedule K-1 to unitholders for the year notwithstanding two partnership tax years. Please read “Material Federal Income Tax Consequences—Disposition of Common Units—Constructive Termination.”

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.

President Obama’s Proposed Fiscal Year 2016 budget (the “Budget Proposal”) recommends elimination of certain key U.S. federal income tax preferences related to coal exploration and development. The 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

 

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royalties, and (4) repeal the domestic manufacturing deduction for the production of coal. The passage of any legislation as a result of the 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.

As a result of investing in our common units, you may become subject to state and local taxes and return filing requirements in jurisdictions where we operate or own or acquire properties.

In addition to U.S. federal income taxes, our unitholders will likely be subject to other taxes, including 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 control property now or in the future, even if they do not live in any of those jurisdictions. Our unitholders will likely be required to file state and local income tax returns and pay state and local income taxes in some or all of these various jurisdictions. Further, our unitholders may be subject to penalties for failure to comply with those requirements. We initially expect to conduct business in Pennsylvania and West Virginia, which currently impose a personal income tax on individuals. As we make acquisitions or expand our business, we may control assets or conduct business in additional states that impose a personal income tax. It is your responsibility to file all federal, state and local tax returns. Our counsel has not rendered an opinion on the state or local tax consequences of an investment in our common units. Please consult your tax advisor.

 

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USE OF PROCEEDS

We expect to receive net proceeds of approximately $         million from the sale of          common units offered by this prospectus, based on an 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), after deducting the underwriting discount and estimated offering expenses. Our estimate assumes the underwriters’ option to purchase additional common units is not exercised. We intend to use the net proceeds from this offering to (i) make a distribution of approximately $         million to CONSOL Energy and (ii) pay approximately $         million of origination fees related to our new revolving credit facility.

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 public and the remainder of the          additional common units, if any, will be issued to CONSOL Energy at the expiration of the option period. Any such common units issued to CONSOL Energy will be issued for no additional consideration. If the underwriters exercise in full their option to purchase additional common units, we expect to receive net proceeds of approximately $         million, after deducting the underwriting discount and estimated offering expenses. We will use any net proceeds from the exercise of the underwriters’ option to make a cash distribution to CONSOL Energy.

A $1.00 increase (decrease) in the assumed initial public offering price of $         per common unit would increase (decrease) the net proceeds to us from this offering by approximately $         million, assuming the number of common units offered by us, as set forth on the cover page of this prospectus, remains the same and assuming the underwriters do not exercise their option to purchase additional common units, and after deducting the underwriting discount and estimated offering expenses. The actual initial public offering price is subject to market conditions and negotiations between us and the underwriters. To the extent there is a change in the net proceeds we receive from this offering, we will make a corresponding change to the size of the cash distribution to CONSOL Energy.

Depending on market conditions at the time of pricing of this offering and other considerations, we may sell fewer or more common units than the number set forth on the cover page of this prospectus.

 

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CAPITALIZATION

The following table sets forth:

 

    the historical cash and cash equivalents and capitalization of our Predecessor as of December 31, 2014; and

 

    our pro forma capitalization as of December 31, 2014, giving effect to the pro forma adjustments described in our unaudited pro forma combined financial statements included elsewhere in this prospectus, including this offering and the application of the net proceeds of this offering in the manner described under “Use of Proceeds” and the other transactions described under “Prospectus Summary—The Transactions.”

The following table assumes that the underwriters do not exercise their option to purchase additional common units. 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 public and the remainder of the additional          common units, if any, will be issued to CONSOL Energy at the expiration of the option period. Any such common units issued to CONSOL Energy will be issued for no additional consideration.

This table is derived from, should be read together with and is qualified in its entirety by reference to the historical financial statements and the accompanying notes and the unaudited pro forma combined financial statements and the accompanying notes included elsewhere in this prospectus. You should also read this table in conjunction with “Prospectus Summary—The Transactions,” “Use of Proceeds” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

 

    

As of December 31, 2014

 
    

Historical

    

Pro Forma

 
     (in thousands)  

Cash

   $ 3       $                
  

 

 

    

 

 

 

Long-term debt:

Revolving credit facility (1)

    

Long-term notes payable—related party (2)

  178,762        

Advanced royalty commitments (3)

  578      578   

Capital lease obligations (4)

  81      81   
  

 

 

    

 

 

 

Total long-term debt (including current maturities)

  179,421   

Invested equity:

Parent net investment

  139,259      —     

Accumulated other comprehensive income

  31,367      —     

Partners’ capital:

Common units—public

  —     

Common units—sponsor

  —     

Subordinated units—sponsor

  —     

General partner interest

  —     

Accumulated other comprehensive income

  —        31,367   
  

 

 

    

 

 

 

Total invested equity / partners’ capital

  170,626   
  

 

 

    

 

 

 

Total capitalization

$ 350,047    $                
  

 

 

    

 

 

 

 

(1) In connection with the completion of this offering, we expect to enter into a new $         million revolving credit facility and make an initial draw of $             million that will be distributed to CONSOL Energy at the closing of this offering. Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Capital Resources and Liquidity—Revolving Credit Facility.”
(2) Includes current portion of $17,931 as of December 31, 2014. Related party long-term notes payable will not be assumed by us at the closing of this offering.
(3) Includes current portion of $300 as of December 31, 2014.
(4) Includes current portion of $30 as of December 31, 2014.

 

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DILUTION

Dilution is the amount by which the offering price per common unit in this offering will exceed the pro forma net tangible book value per unit after the offering. On a pro forma basis as of December 31, 2014, after giving effect to the offering of common units and the related transactions, our net tangible book value was approximately $         million, or $         per unit. Purchasers of common units in this offering will experience substantial and immediate dilution in pro forma net tangible book value per common unit for financial accounting purposes, as illustrated in the following table.

 

Assumed initial public offering price per common unit (1)

$                

Pro forma net tangible book value per unit before this offering (2)

$                

Less: Distribution to CONSOL Energy (3)

Add: Increase in net tangible book value per unit attributable to purchasers in this offering

  

 

 

    

Less: Pro forma net tangible book value per unit after this offering (4)

     

 

 

 

Immediate dilution in net tangible book value per common unit to purchasers in this offering (4)(5)(6)

$     
     

 

 

 

 

(1) Represents the mid-point of the price range set forth on the cover page of this prospectus.
(2) Determined by dividing the number of units (         common units,          subordinated units and the corresponding value for the 2% general partner interest) to be issued to the general partner and its affiliates for their contribution of assets and liabilities to us into the pro forma net tangible book value of the contributed assets and liabilities of $         million.
(3) Determined by dividing the number of units (         common units,          subordinated units and the corresponding value for the 2% general partner interest) to be issued to CONSOL Energy for its contribution of assets and liabilities to us. At the closing of this offering, we intend to make a distribution of $         million to CONSOL Energy from the net proceeds from this offering and net borrowings under our new revolving credit facility.
(4) Determined by dividing the number of units to be outstanding after this offering (         common units,              subordinated units and the corresponding value for the 2% general partner interest) and the application of the related net proceeds into our pro forma net tangible book value, after giving effect to the application of the net proceeds from this offering, of $         million.
(5) 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.
(6) Because the total number of units outstanding following this offering will not be impacted by any exercise of the underwriters’ option to purchase additional common units and any net proceeds from such exercise will not be retained by us, there will be no change to the dilution in net tangible book value per common unit to purchasers in this offering due to any such exercise of the option.

The following table sets forth the partnership interests that we will issue and the total consideration contributed to us by our general partner and its affiliates in respect of their partnership interests and by the purchasers of common units in this offering upon consummation of the transactions contemplated by this prospectus.

 

    

Units Acquired

   

Total Consideration

 
    

Number

  

%

   

Amount
(in millions)

    

%

 

General partner and its affiliates (1)(2)(3)

               $                          

Purchasers in this offering

                        
  

 

  

 

 

   

 

 

    

 

 

 

Total

       $            
  

 

  

 

 

   

 

 

    

 

 

 

 

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(1) Upon the completion of this offering, our general partner and its affiliates will own          common units,          subordinated units and a 2% general partner interest (represented by          hypothetical limited partner units).
(2) Assumes the underwriters’ option to purchase additional common units is not exercised.
(3) The assets contributed by our general partner and its affiliates were recorded at historical cost in accordance with accounting principles generally accepted in the United States. Book value of the consideration provided by our general partner and its affiliates, as of December 31, 2014, was $         million. At the closing of this offering, we intend to make a distribution of $         million to CONSOL Energy from the net proceeds from this offering and net borrowings under our new revolving credit facility.

 

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CASH DISTRIBUTION POLICY AND RESTRICTIONS ON DISTRIBUTIONS

The following discussion of our cash distribution policy should be read 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 results of operations, please refer to our historical financial statements and the accompanying notes and the unaudited pro forma combined financial statements and the accompanying notes included elsewhere in this prospectus.

General

Rationale for Our Cash Distribution Policy

Our partnership agreement requires that we distribute all of our available cash quarterly. This requirement forms the basis of our cash distribution policy and reflects a basic judgment that our unitholders will be better served by distributing our available cash rather than retaining it because, among other reasons, we believe we will generally finance any expansion capital expenditures from external financing sources. Under our current cash distribution policy, we intend to make a minimum quarterly distribution to the holders of our common units and subordinated units of $         per unit, or $         per unit on an annualized basis, to the extent we have sufficient available cash after the establishment of cash reserves and the payment of costs and expenses, including the payment of expenses to our general partner. However, other than the requirement in our partnership agreement to distribute all of our available cash each quarter, we have no legal obligation to make quarterly cash distributions in this or any other amount, and the board of directors of our general partner has considerable discretion to determine the amount of our available cash each quarter. In addition, the board of directors of our general partner may change our cash distribution policy at any time, subject to the requirement in our partnership agreement to distribute all of our available cash quarterly. Generally, our available cash is the sum of (i) all cash on hand at the end of a quarter after the payment of our expenses and the establishment of cash reserves and (ii) if the board of directors of our general partner so determines, all or any portion of additional cash on hand resulting from working capital borrowings made after the end of the quarter. Because we are not subject to an entity-level federal income tax, we expect to have more cash to distribute than would be the case if we were subject to federal income tax. If we do not generate sufficient available cash from our operations, we may, but are under no obligation to, borrow funds to pay the minimum quarterly distribution to our unitholders.

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

Although our partnership agreement requires that we distribute all of our available cash quarterly, there is no guarantee that we will make quarterly cash distributions to our unitholders at our minimum quarterly distribution rate or at any other rate, and we have no legal obligation to do so. Our current cash distribution policy is subject to certain restrictions, as well as the considerable discretion of the board of directors of our general partner in determining the amount of our available cash each quarter. The following factors will affect our ability to make cash distributions, as well as the amount of any cash distributions we make:

 

    We expect that our cash distribution policy will be subject to restrictions on cash distributions under our new revolving credit facility. We expect that one such restriction would prohibit us from making cash distributions while an event of default has occurred and is continuing under our new revolving credit facility, notwithstanding our cash distribution policy. Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Capital Resources and Liquidity—Revolving Credit Facility.”

 

   

The amount of cash that we distribute and the decision to make any distribution is determined by the board of directors of our general partner, taking into consideration the terms of our partnership

 

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agreement. Specifically, the board of directors of our general partner will have the authority to establish cash reserves to provide for the proper conduct of our business, comply with applicable law or any agreement to which we are a party or by which we are bound or our assets are subject and provide funds for future cash distributions to our unitholders, and the establishment of or increase in those reserves could result in a reduction in cash distributions from levels we currently anticipate pursuant to our stated cash distribution policy. Any decision to establish cash reserves made by the board of directors of our general partner in good faith will be binding on our unitholders.

 

    While our partnership agreement requires us to distribute all of our available cash, our partnership agreement, including the provisions requiring us to make cash distributions, may be amended. During the subordination period, our partnership agreement may not be amended without the approval of our public common unitholders, except in a limited number of circumstances when our general partner can amend our partnership agreement without any unitholder approval. Please read “Our Partnership Agreement—Amendment of Our Partnership Agreement—No Unitholder Approval.” However, after the subordination period has ended, our partnership agreement may be amended with the consent of our general partner and the approval of a majority of the outstanding common units, including common units owned by our general partner and its affiliates. Following the completion of this offering, our sponsor will own our general partner and will own          common units and          subordinated units, representing a     % limited partner interest (or          common units and          subordinated units, representing a     % limited partner interest, if the underwriters exercise in full their option to purchase additional common units).

 

    Under Section 17-607 of the Delaware Act, we may not make a distribution if the distribution would cause our liabilities to exceed the fair value of our assets.

 

    We may lack sufficient cash to pay distributions to our unitholders due to cash flow shortfalls attributable to a number of operational, commercial or other factors as well as increases in our operating or general and administrative expenses, principal and interest payments on our debt, tax expenses, working capital requirements and anticipated cash needs. Our available cash is directly impacted by the cash expenses necessary to run our business and will be reduced dollar-for-dollar to the extent such uses of cash increase. Please read “Provisions of Our Partnership Agreement Relating to Cash Distributions—Distributions of Available Cash.”

 

    Our ability to make cash distributions to our unitholders depends on the performance of our operating subsidiaries and their ability to distribute cash to us.

 

    If and to the extent our available cash materially declines from quarter to quarter, we may elect to change our current cash distribution policy and reduce the amount of our quarterly distributions in order to service or repay our debt or fund expansion capital expenditures.

To the extent that our general partner determines not to distribute the full minimum quarterly distribution on our common units with respect to any quarter during the subordination period, the common units will accrue an arrearage equal to the difference between the minimum quarterly distribution and the amount of the distribution actually paid on the common units with respect to that quarter. The aggregate amount of any such arrearages must be paid on the common units before any distributions of available cash from operating surplus may be made on the subordinated units and before any subordinated units may convert into common units. The subordinated units will not accrue any arrearages. Please read “Provisions of Our Partnership Agreement Relating to Cash Distributions—Subordinated Units and Subordination Period.”

 

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Our Ability to Grow Is Dependent on Our Ability to Access External Expansion Capital

Our partnership agreement requires us to distribute all of our available cash to our unitholders on a quarterly basis. As a result, we expect that we will rely primarily upon our cash reserves and external financing sources, including borrowings under our new revolving credit facility and the issuance of debt and equity securities, to fund future acquisitions and other expansion capital expenditures. While we have historically received funding from our sponsor, we do not have any commitment from our sponsor, our general partner or any of their respective affiliates to fund our cash flow deficits or provide other direct or indirect financial assistance to us following the closing of this offering. Following the completion of this offering, our sponsor will directly own a     % limited partner interest in us (or a     % limited partner interest in us if the underwriters exercise in full their option to purchase additional common units). In addition, our sponsor will retain a significant interest in us through its ownership of a 100% interest in our general partner and all of our incentive distribution rights. Given our sponsor’s significant ownership interests in us following the closing of this offering, we believe our sponsor will be incentivized to promote and support the successful execution of our business strategies, including by providing us with direct or indirect financial assistance; however, we can provide no assurances that our sponsor will provide such direct or indirect financial assistance.

To the extent we are unable to finance growth with external sources of capital, the requirement in our partnership agreement to distribute all of our available cash and our current cash distribution policy may significantly impair our ability to grow. In addition, because we will distribute all of our available cash, our growth may not be as fast as businesses that reinvest all of their available cash to expand ongoing operations. We expect that our new revolving credit facility will restrict our ability to incur additional debt, including through the issuance of debt securities. Please read “Risk Factors—Risks Related to Our Business—Restrictions in our new revolving credit facility could adversely affect our business, financial condition, results of operations and ability to make quarterly cash distributions to our unitholders.” To the extent we issue additional partnership interests, the payment of distributions on those additional partnership interests may increase the risk that we will be unable to maintain or increase our cash distributions per common unit. There are no limitations in our partnership agreement on our ability to issue additional partnership interests, including partnership interests ranking senior to our common units, and our common unitholders will have no preemptive or other rights (solely as a result of their status as unitholders) to purchase any such additional partnership interests. If we incur additional debt (under our new revolving credit facility or otherwise) to finance our growth strategy, we will have increased interest expense, which in turn will reduce the available cash that we have to distribute to our unitholders. Please read “Risk Factors—Risks Related to Our Business—Debt we incur in the future may limit our flexibility to obtain financing and to pursue other business opportunities.”

Our Minimum Quarterly Distribution

Upon the consummation 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. 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.” Quarterly distributions, if any, will be made within 45 days after the end of each calendar quarter to holders of record on or about the first day of each such month in which such distributions are made. We do not expect to make distributions for the period that began on                     , 2015 and ends on the day prior to the closing of this offering. We will adjust the amount of our first distribution for the period from the closing of this offering through                     , 2015 based on the number of days in that period.

 

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The amount of available cash needed to pay the minimum quarterly distribution on all of our common units, subordinated units and the 2% general partner interest to be outstanding immediately after this offering for one quarter and on an annualized basis (assuming no exercise and full exercise of the underwriters’ option to purchase additional common units) is summarized in the table below:

 

    

No Exercise of Option to Purchase
Additional Common Units

    

Full Exercise of 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)

 
          ($ in millions)           ($ in millions)  

Publicly held common units

      $                    $                       $                    $                

Common units held by our sponsor

                 

Subordinated units held by our sponsor

                 

2% general partner interest

                 
  

 

  

 

 

    

 

 

    

 

  

 

 

    

 

 

 

Total

$                 $                 $                 $                
  

 

  

 

 

    

 

 

    

 

  

 

 

    

 

 

 

Initially, our general partner will be entitled to 2% of all distributions that we make prior to our liquidation. Our general partner’s initial 2% general partner interest in these distributions may be reduced if we issue additional partnership interests in the future and our general partner does not contribute a proportionate amount of capital to us in order to maintain its initial 2% general partner interest. Our general partner will also initially hold all of the incentive distribution rights, which entitle the holder to increasing percentages, up to a maximum of 48%, of the cash we distribute in excess of $         per unit per quarter.

During the subordination period, before we make any quarterly distributions to our subordinated unitholders, our common unitholders are entitled to receive payment of the full minimum quarterly distribution for such quarter plus any arrearages in distributions of the minimum quarterly distribution from prior quarters. Please read “Provisions of Our Partnership Agreement Relating to Cash Distributions—Subordinated Units and Subordination Period.” We cannot guarantee, however, that we will pay distributions on our common units at our minimum quarterly distribution rate or at any other rate in any quarter.

Although holders of our common units may pursue judicial action to enforce provisions of our partnership agreement, including those related to requirements to make cash distributions as described above, our partnership agreement provides that any determination made by our general partner in its capacity as our general partner must be made in good faith and that any such determination will not be subject to any other standard imposed by the Delaware Act or any other law, rule or regulation or at equity. Our partnership agreement provides that, in order for a determination by our general partner to be made in “good faith,” our general partner must subjectively believe that the determination is in the best interests of our partnership. In making such determination, our general partner may take into account the totality of the circumstances or the totality of the relationships between the parties involved, including other relationships or transactions that may be particularly favorable or advantageous to us. Please read “Conflicts of Interest and Duties.”

The provision in our partnership agreement requiring us to distribute all of our available cash quarterly may not be modified without amending our partnership agreement; however, as described above, the actual amount of our cash distributions for any quarter is subject to fluctuations based on the amount of cash we generate from our business, the amount of reserves the board of directors of our general partner establishes in accordance with our partnership agreement and the amount of available cash from working capital borrowings.

Additionally, the board of directors of our general partner may reduce the minimum quarterly distribution and the target distribution levels if legislation is enacted or modified that results in our partnership becoming taxable as a corporation or otherwise subject to taxation as an entity for federal, state or local income

 

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tax purposes. In such an event, the minimum quarterly distribution and the target distribution levels may be reduced proportionately by the percentage decrease in our available cash resulting from the estimated tax liability we would incur in the quarter in which such legislation is effective. The minimum quarterly distribution will also be proportionately adjusted in the event of any distribution, combination or subdivision of common units in accordance with the partnership agreement, or in the event of a distribution of available cash from capital surplus. Please read “Provisions of Our Partnership Agreement Relating to Cash Distributions—Adjustment to the Minimum Quarterly Distribution and Target Distribution Levels.” The minimum quarterly distribution is also subject to adjustment if the holder(s) of the incentive distribution rights (initially only our general partner) elect to reset the target distribution levels related to the incentive distribution rights. In connection with any such reset, the minimum quarterly distribution will be reset to an amount equal to the average cash distribution amount per common unit for the two quarters immediately preceding the reset. Please read “Provisions of Our Partnership Agreement Relating to Cash Distributions—General Partner’s Right to Reset Incentive Distribution Levels.”

In the sections that follow, we present in detail the basis for our belief that we will be able to fully fund our annualized minimum quarterly distribution of $         per unit for the twelve months ending June 30, 2016. In those sections, we present two tables, consisting of:

 

    “Unaudited Pro Forma Adjusted EBITDA and Distributable Cash Flow for the Year Ended December 31, 2014,” in which we present the amount of adjusted EBITDA and distributable cash flow we would have generated on a pro forma basis for the year ended December 31, 2014, derived from our unaudited pro forma combined financial statements that are included in this prospectus, as adjusted to give pro forma effect to this offering and the related formation transactions; and

 

    “Estimated Adjusted EBITDA and Distributable Cash Flow for the Twelve Months Ending June 30, 2016,” in which we provide our estimated forecast of our ability to generate sufficient adjusted EBITDA and distributable cash flow to support the payment of the minimum quarterly distribution on all common units and subordinated units and the corresponding distributions on our general partner’s 2% general partner interest for the twelve months ending June 30, 2016.

The amounts set forth in the following sections reflect the pro forma historical and forecasted results attributable to 20% of the assets, liabilities, revenues and expenses comprising the Pennsylvania mining complex. In connection with the completion of this offering, our sponsor will contribute to us a 20% undivided interest in the Pennsylvania mining complex. Please read “Prospectus Summary—The Transactions.”

Unaudited Pro Forma Adjusted EBITDA and Distributable Cash Flow for the Year Ended December 31, 2014

If we had completed the transactions contemplated in this prospectus on January 1, 2014, pro forma adjusted EBITDA generated for the year ended December 31, 2014 would have been approximately $124.7 million, and pro forma distributable cash flow generated for the period would have been approximately $86.7 million. These amounts would have been sufficient to support the payment of the minimum quarterly distribution of $         per unit per quarter ($         per unit on an annualized basis) on all of our common units and subordinated units and the corresponding distributions on our general partner’s 2% general partner interest for the year ended December 31, 2014.

Our unaudited pro forma distributable cash flow for the pro forma year ended December 31, 2014 includes $2.4 million of estimated incremental general and administrative expenses that we expect to incur as a result of becoming a publicly traded partnership. Incremental general and administrative expenses related to being a publicly traded partnership include expenses associated with our annual and quarterly SEC reporting, tax return and Schedule K-1 preparation and distribution expenses, expenses associated with listing on the NYSE, fees of our independent registered public accounting firm, legal fees, investor relations expenses, transfer agent and registrar fees, director and officer liability insurance expenses and director compensation. Our incremental general and administrative expenses are not reflected in our Predecessor’s historical combined financial statements or our unaudited pro forma combined statement of operations included elsewhere in this prospectus.

 

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We based the pro forma adjustments upon currently available information and specific estimates and assumptions. The pro forma amounts below do not purport to present our results of operations had the transactions contemplated in this prospectus actually been completed as of the dates indicated. In addition, adjusted EBITDA and distributable cash flow are primarily cash accounting concepts, while our unaudited pro forma combined financial statements have been prepared on an accrual basis. As a result, you should view the amounts of pro forma adjusted EBITDA and distributable cash flow only as general indications of the amounts of adjusted EBITDA and distributable cash flow that we might have generated had we been formed on January 1, 2014.

The following table illustrates, on a pro forma basis, for the year ended December 31, 2014, the amounts of adjusted EBITDA and distributable cash flow that would have been generated, assuming in each case that this offering and the other transactions contemplated in this prospectus had been consummated on January 1, 2014.

 

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CNX Coal Resources LP

Unaudited Pro Forma Adjusted EBITDA and Distributable Cash Flow

 

    

Year Ended
December 31, 2014

 
     ($ thousands,
except per unit amounts)
 

Coal revenue

   $ 323,398   

Freight revenue

     3,353   

Other income

     7,371   

Gain on sale of assets

     153   
  

 

 

 

Total revenue and other income

     334,275   

Operating and other costs (related party of $10,694)

     172,327   

Royalties and production taxes

     14,169   

Selling and direct administrative expenses (related party of $4,710)

     4,710   

Depreciation, depletion and amortization

     33,786   

Freight expense

     3,353   

General and administrative expenses (related party of $5,264) (1)

     7,682   

Other corporate expenses (related party of $7,944) (2)

     7,658   

Interest expense (3)

     8,631   
  

 

 

 

Total costs

     252,316   
  

 

 

 

Pro Forma Net Income Attributable to Unitholders

   $ 81,959   
  

 

 

 

Add:

  

Interest expense

     8,631   

Depreciation, depletion and amortization

     33,786   

Coal contract buyout

     (6,000

Other postretirement benefit plan transition payment, net

     3,299   

Litigation settlement

     (855

Bailey belt repairs

     551   

Stock based compensation

     3,361   
  

 

 

 

Pro Forma Adjusted EBITDA

   $ 124,732   
  

 

 

 

Less:

  

Cash interest expense (4)

   $ 8,031   

Estimated maintenance capital expenditures (5)

     30,042   

Expansion capital expenditures (6)

     39,653   

Add:

  

Borrowings to fund expansion capital expenditures

     39,653   
  

 

 

 

Pro Forma Distributable Cash Flow

   $ 86,659   
  

 

 

 

Pro Forma Cash Distributions:

  

Annualized minimum quarterly distribution per unit

  

Pro forma aggregate annualized quarterly distributions to public common unitholders

  

Pro forma aggregate annualized quarterly distributions to sponsor:

  

Common units held by sponsor

  

Subordinated units held by sponsor

  

General partner interest held by sponsor

  

Total distributions to sponsor

  

Pro Forma Aggregate Annualized Quarterly Distributions

  

Excess / (Shortfall) of Pro Forma Distributable Cash Flow Over Pro Forma Aggregate Annualized Minimum Quarterly Distributions

  

Percent of Pro Forma Aggregate Annualized Minimum Quarterly Distributions Payable to Common Unitholders

  

Percent of Pro Forma Aggregate Annualized Minimum Quarterly Distributions Payable to Subordinated Unitholders

  

 

(1) Includes approximately $2,418 of estimated annual incremental general and administrative expenses that we expect to incur as a result of being a publicly traded partnership.
(2) Includes a $286 favorable adjustment to a previously established franchise tax accrual.
(3) Represents the pro forma adjustment to interest expense associated with the drawn and undrawn portion of the new revolving credit facility comprising interest expense and commitment fees and amortization of origination fees over the five-year expected term of the facility.

 

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(4) Represents cash interest expense paid related to the new revolving credit facility comprising interest expense and commitment fees.
(5) Represents estimated maintenance capital expenditures. Includes (i) approximately $27,429 related to the rebuild, replacement, repair and maintenance of mining equipment associated with our continuous mining units and longwall systems, belts and conveyors, preparation plant maintenance, and refuse disposal areas and (ii) approximately $2,613 of cash reserves related to the replacement of coal reserves based on our production forecast. Historically, we did not make a distinction between maintenance capital expenditures and expansion capital expenditures. For purposes of comparability, we are presenting estimated maintenance capital expenditures for the pro forma year ended December 31, 2014 that are calculated using the same methodology that we will use following the completion of this offering. We estimate that our actual cash maintenance capital expenditures for the pro forma year ended December 31, 2014 were $28,408. The difference between our $30,042 in estimated maintenance capital expenditures for the pro forma year ended December 31, 2014 and the $28,408 in estimated actual cash maintenance capital expenditures represents our proportionate share of the additional amount of maintenance capital expenditures accrued based on our long-term expectations of the ongoing average level of maintenance capital expenditures necessary to maintain the ongoing operations of the Pennsylvania mining complex. Please read “—Significant Forecast Assumptions—Capital Expenditures.”
(6) Primarily relates to expansion capital expenditures associated with the Harvey mine, which commenced longwall operations in March 2014.

Estimated Adjusted EBITDA and Distributable Cash Flow for the Twelve Months Ending June 30, 2016

We forecast our estimated adjusted EBITDA and distributable cash flow for the twelve months ending June 30, 2016 will be approximately $         million and $         million, respectively. In order to pay the aggregate annualized minimum quarterly distribution to all of our unitholders and the corresponding distribution on our general partner’s 2% general partner interest for the twelve months ending June 30, 2016, we must generate adjusted EBITDA and distributable cash flow of at least $         million and $         million, respectively.

We have not historically made public projections as to future operations, earnings or other results. However, management has prepared the forecast of estimated adjusted EBITDA and distributable cash flow for the twelve months ending June 30, 2016, and related assumptions set forth below, to substantiate our belief that we will have sufficient adjusted EBITDA and distributable cash flow to pay the aggregate annualized minimum quarterly distribution to all our unitholders and the corresponding distributions on our general partner’s 2% general partner interest for the twelve months ending June 30, 2016. Please read “—Significant Forecast Assumptions.” This forecast is a forward-looking statement and should be read together with our historical and unaudited pro forma combined financial statements and the accompanying notes included elsewhere in this prospectus and “Management’s Discussion and Analysis of Financial Condition and Results of Operations.” This forecast was not prepared with a view toward complying with the published guidelines of the SEC or guidelines established by the American Institute of Certified Public Accountants with respect to prospective financial information, but, in the view of our management, 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 assumptions on which we base our belief that we can generate sufficient adjusted EBITDA and distributable cash flow to pay the minimum quarterly distribution to all unitholders and our general partner for the forecasted period. However, this information is not fact and should not be relied upon as being necessarily indicative of our future results, and readers of this prospectus are cautioned not to place undue reliance on the prospective financial information.

The prospective financial information included in this prospectus has been prepared by, and is the responsibility of, our management. Ernst & Young LLP has neither compiled nor performed any procedures with respect to the accompanying prospective financial information and, accordingly, Ernst & Young LLP does not express an opinion or any other form of assurance with respect thereto. The Ernst & Young LLP report included in this prospectus relates to our historical financial information. It does not extend to the prospective financial information and should not be read to do so.

When considering our financial forecast, you should keep in mind the risk factors and other cautionary statements under “Risk Factors.” Any of the risks discussed in this prospectus, to the extent they are realized, could cause our actual results of operations to vary significantly from those that would enable us to generate our estimated adjusted EBITDA and distributable cash flow.

 

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We do not undertake any obligation to release publicly the results of any future revisions we may make to the forecast or to update this forecast to reflect events or circumstances after the date of this prospectus. Therefore, you are cautioned not to place undue reliance on this prospective financial information.

CNX Coal Resources LP

Estimated Adjusted EBITDA and Distributable Cash Flow

 

    

Twelve Months Ending

June 30, 2016

 
     ($ millions, except per unit
amounts)
 

Coal revenue

   $                

Freight revenue

  
  

 

 

 

Total revenue and other income

  

Operating and other costs

  

Royalties and production taxes

  

Selling and direct administrative expenses

  

Depreciation, depletion and amortization

  

Freight expense

  

General and administrative expenses (related party of $            ) (1)

  

Other corporate expenses

  

Interest expense (2)

  
  

 

 

 

Total costs

  
  

 

 

 

Estimated Net Income Attributable to Unitholders

   $     
  

 

 

 

Add:

  

Interest expense

  

Depreciation, depletion and amortization

  

Unit based compensation

  
  

 

 

 

Estimated Adjusted EBITDA

   $     
  

 

 

 

Less:

  

Cash interest expense (3)

   $     

Estimated maintenance capital expenditures (4)

  

Expansion capital expenditures

  
  

 

 

 

Estimated Distributable Cash Flow

   $                
  

 

 

 

Estimated Cash Distributions:

  

Annualized minimum quarterly distribution per unit

  

Estimated aggregate annualized quarterly distributions to public common unitholders

  

Estimated aggregate annualized quarterly distributions to sponsor:

  

Common units held by sponsor

  

Subordinated units held by sponsor

  

General partner interest held by sponsor

  

Total distributions to sponsor

  

Estimated Aggregate Annualized Quarterly Distributions

  

Excess / (Shortfall) of Estimated Distributable Cash Flow Over Estimated Aggregate Annualized Minimum Quarterly Distributions

  

 

(1) We expect to incur approximately $2.4 million of estimated annual incremental general and administrative expenses as a result of being a publicly traded partnership.
(2) Forecasted interest expense includes (i) interest on amounts outstanding under our new revolving credit facility; (ii) amortization of origination fees and (iii) commitment fees on the unused portion of our new revolving credit facility.
(3) Forecasted cash interest expense includes (i) interest on amounts outstanding under our new revolving credit facility and (ii) commitment fees on the unused portion of our new revolving credit facility.
(4) Represents estimated maintenance capital expenditures. Includes (i) approximately $             million of estimated maintenance capital expenditures related to the rebuild, replacement, repair and maintenance of mining equipment associated with our continuous mining units and longwall systems, belts and conveyors, preparation plant maintenance, and refuse disposal areas and (ii) approximately $             million of cash reserves related to the replacement of coal reserves based on our production forecast. We estimate that our actual cash maintenance capital expenditures for the twelve months ending June 30, 2016 will be $             million. Please read “—Significant Forecast Assumptions—Capital Expenditures.”

 

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Significant Forecast Assumptions

The forecast has been prepared by and is the responsibility of management. The 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 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 our actual results, and those differences could be material. If the forecasted results are not achieved, we may not be able to make cash distributions on our common units at the minimum quarterly distribution rate or at all.

General Considerations

In connection with the completion of this offering, our sponsor will contribute to us a 20% undivided interest in the Pennsylvania mining complex. As a result, the forecasted financial and operating results reflect 20% of the total forecasted financial and operating results of the Pennsylvania mining complex as a whole.

Production and Revenues

We forecast that our coal revenues for the twelve months ending June 30, 2016 will be approximately $         million compared to approximately $323.4 million for the pro forma year ended December 31, 2014. Our forecast is based primarily on the following assumptions:

 

    We estimate that we will produce approximately          million tons of coal for the twelve months ending June 30, 2016 compared to the 5.2 million tons of coal that we produced for the pro forma year ended December 31, 2014. Our estimated increase in production volumes is primarily due to a full twelve months of longwall production from the Harvey mine being reflected in the forecast period. The Harvey mine commenced longwall operations in March 2014. We expect that the Harvey mine will produce          million tons of coal during the forecast period compared to the 0.6 million tons of coal the Harvey mine produced for the pro forma year ended December 31, 2014. This increase is partially offset by lower production at the Bailey and Enlow Fork mines during the forecast period. During the year ended December 31, 2014, we ran an additional longwall at the Bailey mine and/or the Enlow Fork mine for approximately 14 weeks to meet our sales commitments. Our coal production could vary significantly from the foregoing assumption based on numerous factors, many of which are beyond our control. Please read “Risk Factors.”

 

    We estimate that we will sell approximately          million tons of coal for the twelve months ending June 30, 2016 compared to the 5.2 million tons we sold for the pro forma year ended December 31, 2014. Our estimated increase in tons of coal sold is primarily due to a full twelve months of production from the Harvey mine being reflected in the forecast period. This increase is partially offset by lower production at the Bailey and Enlow Fork mines during the forecast period. During the year ended December 31, 2014, we ran an additional longwall at the Bailey mine and/or the Enlow Fork mine for approximately 14 weeks to meet our sales commitments. We estimate that we will sell approximately          millions tons of coal in the thermal coal market compared to the 4.95 million tons we sold in the thermal coal market for the pro forma year ended December 31, 2014. We estimate that we will sell approximately          millions tons of coal in the metallurgical coal market compared to the 0.25 million tons we sold in the metallurgical coal market for the pro forma year ended December 31, 2014.

 

   

We estimate that our average coal sales price per ton will be approximately $         for the twelve months ending June 30, 2016 compared to our average coal sales price per ton of $61.88 for the pro forma year ended December 31, 2014. We estimate that our average coal sales price per ton sold in the thermal coal market will be approximately $         for the twelve months ending June 30, 2016 compared to our average coal sales price per ton sold in the thermal coal market of $61.99 for the

 

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pro forma year ended December 31, 2014. We estimate that our average coal sales price per ton sold in the metallurgical coal market will be approximately $         for the twelve months ending June 30, 2016 compared to our average coal sales price per ton sold in the metallurgical coal market of $59.67 for the pro forma year ended December 31, 2014. Actual results could vary significantly from our assumptions if we are unable to deliver coal pursuant to our contracts, if a number of our customers are unable to satisfy their contractual obligations or if we are materially incorrect in our pricing or volume assumptions for uncommitted sales.

 

    Our estimate includes sales under committed and priced sales contracts to sell approximately          million tons, or approximately         % of our forecasted sales volume, at a weighted average price of $         per ton during the forecast period. We had          million tons of coal contracted under committed and priced sales contracts as of                     , 2014 (or         % of total 2014 tons sold).

 

    We estimate that we will sell approximately          million tons, or approximately         % of our forecasted sales during the forecast period, to customers for which we do not currently have committed and priced sales contracts in place for a weighted average price per ton of $        . Our estimated weighted average sales price for our uncommitted tons assumes that we will be successful in selling these tons at prices that reflect management’s current estimates of market conditions and pricing trends. Management’s estimates are based on published indices, a review of recently completed transactions and conversations with customers and sales prospects.

 

    We estimate that our freight revenue will be approximately $         for the twelve months ending June 30, 2016 compared to freight revenue of $3.4 million for the pro forma year ended December 31, 2014. Freight revenue, and offsetting freight expense, is incurred when we maintain the shipping agreements and the shipping and handling costs are invoiced to coal customers and are paid to third-party carriers. The forecasted freight revenue is based upon our forecast of coal sales by customer and our understanding of historic shipping and handling arrangements specific to our customer base. Actual results could vary if our assumptions of customer mix or shipping and handling arrangements vary versus actual arrangements entered into by our customers.

Operating and Other Costs

We forecast our operating and other costs will be approximately $         million for the twelve months ending June 30, 2016 compared to approximately $172.3 million for the pro forma year ended December 31, 2014. Operating and other costs primarily include the cost of labor, maintenance, power, lease expense, inventory changes (both volume and price) and all other costs that are directly related to our mining operations other than direct administrative, selling, royalties and production taxes and depreciation, depletion and amortization. The increase in operating costs for the forecast period compared to the pro forma year ended December 31, 2014 is primarily attributable to increased longwall production as a result of the Harvey mine operating for a full twelve months as well as a forecasted increase in cash operating costs per ton.

We estimate that our average cash margin per ton for the twelve months ending June 30, 2016 will be $         compared to $25.57 for the pro forma year ended December 31, 2014. The forecasted decrease in average cash margin per ton is primarily due to our slightly lower average realized price. Our forecasted average cash margin per ton could vary significantly because of a large number of variables, many of which are beyond our control.

Royalties and Production Taxes

We estimate that our royalties and production taxes for the twelve months ending June 30, 2016 will be $         million compared to $14.2 million for the pro forma year ended December 31, 2014. The forecasted decrease in royalties and production taxes is primarily due to less production in West Virginia (which levies a severance tax on coal) compared to the pro forma year ended December 31, 2014.

 

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Selling, Administrative and Corporate Expenses

Our selling, administrative and corporate expenses consist of (i) selling and direct administrative expenses, (ii) general and administrative expenses and (iii) other corporate expenses.

Selling and direct administrative expenses include corporate and administrative expenses that are directly attributable to the production of coal or to selling coal, including mine engineering services, land, direct administrative costs and selling expenses.

General and administrative expenses include salaries and related employee benefit costs of the directors and officers of our general partner, corporate general and administrative expenses proportionately charged to us from our sponsor (inclusive of employee and non-employee costs) and expenses incurred as a result of being a publicly traded company, such as accounting, audit and legal fees.

Other corporate expenses include cash based incentive compensation expenses and equity-based incentive compensation expenses proportionately charged to us from our sponsor and equity-based incentive compensation expenses directly incurred by us under our long-term incentive plan.

We expect total selling, administrative and corporate expenses for the twelve months ending June 30, 2016 will be approximately $         million compared to approximately $20.1 million for the pro forma year ended December 31, 2014. These amounts include the approximate $2.4 million of annual incremental publicly traded partnership expenses that we expect to incur after the completion of this offering.

Depreciation, Depletion and Amortization

We estimate that depreciation, depletion and amortization expense will be approximately $         million for the twelve months ending June 30, 2016 compared to approximately $33.8 million for the pro forma year ended December 31, 2014. The increase in depreciation, depletion and amortization expense compared to the pro forma year ended December 31, 2014 is due to an increase in depreciation related additional depreciation of equipment as a result of the Harvey mine operating for a full twelve months.

Interest Expense

We estimate that interest expense will be approximately $         million for the twelve months ending June 30, 2016. Our interest expense for the twelve months ending June 30, 2016 includes (i) approximately $         million of interest under our new revolving credit facility based on an assumed interest rate of             , (ii) approximately $         million of non-cash amortization of assumed origination fees for our new revolving credit facility and (iii) approximately $         million of commitment fees on the unused portion of our new revolving credit facility based on an assumed $         million in average borrowings outstanding under our new revolving credit facility during the twelve months ending June 30, 2016.

Our new revolving credit facility will bear interest at either a base rate or LIBOR rate, in each case plus a margin. We calculated our interest rate based on the LIBOR rate, which generally will be LIBOR plus         % to         %, depending on our most recent consolidated leverage ratio or our credit rating, as the case may be. For purposes of our estimate, we assumed LIBOR of         % plus the top end of the margin applicable to the LIBOR rate. We estimated that we will incur approximately $         million of non-cash amortization of origination fees. We calculated the approximate $         million of commitment fees based on an assumed         % commitment fee on the estimated $         million average undrawn portion of the new revolving credit facility. Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Capital Resources and Liquidity—Revolving Credit Facility” for a description of our new revolving credit facility.

 

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Capital Expenditures

We distinguish between maintenance capital expenditures and expansion capital expenditures. In general, maintenance capital expenditures are cash expenditures made to maintain, over the long term, our operating capacity or capital asset base, and expansion capital expenditures are cash expenditures made to increase, over the long term, our operating capacity or capital asset base. 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 distributable cash flow, operating surplus and adjusted operating surplus if we were to subtract actual maintenance capital expenditures. To help mitigate these fluctuations, our partnership agreement will require that each quarter we subtract from operating surplus an estimate of the average quarterly maintenance capital expenditures necessary to maintain our operating capacity or capital asset base over the long term, as opposed to subtracting the actual amount we spend on maintenance capital expenditures in that quarter. In addition, our maintenance capital expenditures include expenditures associated with the replacement of coal reserves, whether through the expansion of an existing mine or the acquisition or development of new reserves to maintain, over the long term, our operating capacity or capital asset base. Estimated maintenance capital expenditures will reduce operating surplus and distributable cash flow, but expansion capital expenditures and actual maintenance capital expenditures will not reduce operating surplus and distributable cash flow. Please read “Provisions of Our Partnership Agreement Relating to Cash Distributions—Capital Expenditures.”

We forecast capital expenditures for the twelve months ending June 30, 2016 based on the following assumptions:

 

    Our estimated maintenance capital expenditures are $         million for the twelve months ending June 30, 2016 compared to estimated maintenance capital expenditures of approximately $30.0 million for the pro forma year ended December 31, 2014. The increase in maintenance capital expenditures compared to the pro forma year ended December 31, 2014 is primarily due to higher production volumes in the forecast period. We estimate that our actual cash maintenance capital expenditures for the twelve months ending June 30, 2016 will be $             million. The difference between our $             million in estimated maintenance capital expenditures for the twelve months ending June 30, 2016 and the $             million in estimated actual cash maintenance capital expenditures represents our proportionate share of the additional amount of maintenance capital expenditures that we will accrue based on our long-term expectations of the ongoing average level of maintenance capital expenditures necessary to maintain the ongoing operations of the Pennsylvania mining complex. Our estimate of maintenance capital expenditures are those capital expenditures required to maintain, over the long-term, our operating capacity or capital asset base. Maintenance capital expenditures include the rebuild, replacement, repair and maintenance of mining equipment associated with our continuous mining units and longwall systems, belts and conveyors, preparation plant maintenance, and refuse disposal areas. The forecasted levels of maintenance capital expenditures are based on actual cost experienced operating the Pennsylvania mining complex and budgeted capital expenditures by our mine operation teams based on recent purchase orders and discussions with vendors regarding pricing. Our forecasted maintenance capital expenditures also include approximately $         million for the replacement of our coal reserves to maintain, over the long term, our operating capacity or capital asset base. We expect to fund actual maintenance capital expenditures from cash generated by our operations.

 

    We estimate that our expansion capital expenditures will be approximately $         million for the twelve months ending June 30, 2016 compared to approximately $39.7 million for the pro forma year ended December 31, 2014. Substantially all of the expansion capital expenditures for the pro forma year ended December 31, 2014 relates to the Harvey mine, which commenced longwall operations in March 2014.

 

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Regulatory, Industry and Economic Factors

Our forecast of adjusted EBITDA and distributable cash flow for the twelve months ending June 30, 2016 is also based on the following significant assumptions related to regulatory, industry and economic factors:

 

    there will be no material nonperformance or credit-related defaults by suppliers, customers or vendors nor will any events occur that would be deemed a force majeure event under our coal sales contracts;

 

    there will not be any new federal, state or local regulation, or any interpretation of existing regulation, of the portions of the coal industry in which we operate that will be materially adverse to our business;

 

    there will not be any material accidents, weather-related incidents, unscheduled downtime or similar unanticipated events with respect to our assets or operations;

 

    there will be no unforeseen geologic conditions or equipment failures at our mines that would have a material effect on our operations;

 

    there will not be a shortage of skilled labor; and

 

    there will not be any material adverse changes in the coal industry, commodity prices, capital markets or overall economic conditions.

 

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PROVISIONS OF OUR PARTNERSHIP AGREEMENT RELATING TO CASH DISTRIBUTIONS

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

Distributions of Available Cash

General

Our partnership agreement requires that, within 45 days after the end of each quarter, beginning with the quarter ending                     , 2015, we distribute all of our available cash to unitholders of record on the applicable record date. We will adjust the amount of our distribution for the period from the closing of this offering through                     , 2015, based on the actual length of the period.

Definition of Available Cash

Available cash generally means, for any quarter, all cash and cash equivalents on hand at the end of that quarter:

 

    less, the amount of any cash reserves established by our general partner to:

 

    provide for the proper conduct of our business (including cash reserves for our future capital expenditures, future acquisitions and anticipated future debt service requirements);

 

    comply with applicable law or any loan agreement, security agreement, mortgage, debt instrument or other agreement or obligation to which we or any of our subsidiaries is a party or by which we or such subsidiary is bound or we or such subsidiary’s assets are subject; or

 

    provide funds for distributions to our unitholders and to our general partner for any one or more of the next four quarters (provided that our general partner may not establish cash reserves for distributions pursuant to this bullet point if the effect of such reserves will prevent us from distributing the minimum quarterly distribution on all common units and any cumulative arrearages on such common units for the current quarter);

 

    plus, if our general partner so determines, all or any portion of the additional cash and cash equivalents (i) on hand on the date of determination of available cash with respect to such quarter resulting from working capital borrowings made subsequent to the end of such quarter or (ii) available to be borrowed as a working capital borrowing as of the date of determination of available cash with respect to such quarter.

The purpose and effect of the last bullet point above is to allow our general partner, if it so decides, to use cash from working capital borrowings made after the end of the quarter to pay distributions to unitholders. Under our partnership agreement, working capital borrowings are generally borrowings incurred under a credit facility, commercial paper facility or similar financing arrangement that are used solely for working capital purposes or to pay distributions to our partners and with the intent of the borrower to repay such borrowings within twelve months with funds other than from additional working capital borrowings.

Intent to Distribute the Minimum Quarterly Distribution

Under our current cash distribution policy, we intend to make a minimum quarterly distribution to the holders of our common units and subordinated units of $         per unit, or $         per unit on an annualized basis, to the extent we have sufficient available cash after the establishment of cash reserves and the payment of costs

 

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and expenses, including reimbursements of costs and expenses to our general partner and its affiliates incurred on our behalf. However, there is no guarantee that we will pay the minimum quarterly distribution on our units in any quarter. The amount of distributions paid under our cash distribution policy and the decision to make any distribution will be determined by our general partner, taking into consideration the terms of our partnership agreement. Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Capital Resources and Liquidity—Revolving Credit Facility.”

General Partner Interest and Incentive Distribution Rights

Initially, our general partner will be entitled to 2% of all quarterly distributions from inception that we make prior to our liquidation. Our general partner has the right, but not the obligation, to contribute a proportionate amount of capital to us to maintain its current general partner interest. The general partner’s initial 2% general partner interest in these distributions will be reduced if we issue additional limited partner interests in the future and our general partner does not contribute a proportionate amount of capital to us to maintain its 2% general partner interest (other than the issuance of common units upon any exercise by the underwriters of their option to purchase additional common units in this offering).

Our general partner also currently holds incentive distribution rights that entitle it to receive increasing percentages, up to a maximum of 48%, of the available cash we distribute from operating surplus (as defined below) in excess of $         per unit per quarter. The maximum distribution of 48% does not include any distributions that our general partner or its affiliates may receive on common units, subordinated units or the general partner interest that they own.

Operating Surplus and Capital Surplus

General

All cash distributed to unitholders will be characterized as either being paid from “operating surplus” or “capital surplus.” We treat distributions of available cash from operating surplus differently than distributions of available cash from capital surplus.

Operating Surplus

We define operating surplus as:

 

    $         million (as described below); plus

 

    all of our cash receipts after the closing of this offering, excluding cash from interim capital transactions (as defined below) and the termination of hedge contracts, provided that cash receipts from the termination of a hedge contract prior to its scheduled settlement or termination date shall be included in operating surplus in equal quarterly installments over the remaining scheduled life of such hedge contract; plus

 

    working capital borrowings made after the end of a quarter but on or before the date of determination of operating surplus for that quarter; plus

 

    cash distributions (including incremental distributions on incentive distribution rights) paid in respect of equity issued, other than equity issued in this offering, to finance all or a portion of expansion capital expenditures in respect of the period from the date that we enter into a binding obligation to commence the construction, replacement, improvement or expansion of a capital asset and ending on the earlier to occur of the date the capital asset commences commercial service and the date that it is abandoned or disposed of; less

 

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    all of our operating expenditures (as defined below) after the closing of this offering; less

 

    the amount of cash reserves established by our general partner to provide funds for future operating expenditures; less

 

    all working capital borrowings not repaid within twelve months after having been incurred, or repaid within such twelve-month period with the proceeds of additional working capital borrowings.

As described above, operating surplus does not reflect actual cash on hand that is available for distribution to our unitholders and is not limited to cash generated by operations. For example, our definition of operating surplus includes a provision that will enable us, if we choose, to distribute as operating surplus up to $         million of 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 repayments are made. However, if working capital borrowings, which increase operating surplus, are not repaid during the twelve-month period following the borrowing, they will be deemed repaid at the end of such period, thus decreasing operating surplus at such time. When such working capital borrowings are in fact repaid, they will not be treated as a further reduction in operating surplus because operating surplus will have been previously reduced by the deemed repayment.

Interim Capital Transactions

We define interim capital transactions as (i) borrowings, refinancings or refundings of indebtedness (other than working capital borrowings and items purchased on open account or for a deferred purchase price in the ordinary course of business) and sales of debt securities, (ii) issuances of equity interests, (iii) sales or other dispositions of assets, other than sales or other dispositions of inventory, accounts receivable and other assets in the ordinary course of business and sales or other dispositions of assets as part of normal asset retirements or replacements and (iv) capital contributions received by us and our subsidiaries.

Operating Expenditures

We define operating expenditures as all of our cash expenditures, including, but not limited to, taxes, compensation of employees, officers and directors of our general partner, reimbursements of expenses of our general partner and its affiliates, debt service payments, estimated maintenance capital expenditures (as discussed in further detail below), repayment of working capital borrowings and payments made in the ordinary course of business under any hedge contracts, subject to the following:

 

    repayments of working capital borrowings where such borrowings have previously been deemed to have been repaid (as described above) will not constitute operating expenditures when actually repaid;

 

    payments (including prepayments and prepayment penalties) of principal of and premium on indebtedness other than working capital borrowings will not constitute operating expenditures;

 

   

operating expenditures will not include (i) expansion capital expenditures, (ii) actual maintenance capital expenditures, (iii) payment of transaction expenses (including taxes) relating to interim

 

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capital transactions, (iv) distributions to our partners, (v) repurchases of partnership interests (excluding repurchases we make to satisfy obligations under employee benefit plans) or (vi) any other expenditures or payments using the proceeds from this offering that are described in “Use of Proceeds;” and

 

    (i) amounts paid in connection with the initial purchase of a hedge contract will be amortized over the life of such hedge contract and (ii) payments made in connection with the termination of any hedge contract prior to the expiration of its scheduled settlement or termination date will be included in equal quarterly installments over the remaining scheduled life of such hedge contract.

Capital Surplus

Capital surplus is defined in our partnership agreement as any distribution of available cash in excess of our cumulative operating surplus. Accordingly, except as described above, capital surplus would generally be generated by:

 

    borrowings other than working capital borrowings;

 

    sales of our equity and debt securities;

 

    sales or other dispositions of assets, other than inventory, accounts receivable and other assets sold in the ordinary course of business or as part of ordinary course retirement or replacement of assets; and

 

    capital contributions received.

Characterization of Cash Distributions

All available cash distributed by us on any date from any source will be treated as distributed from operating surplus until the sum of all available cash distributed by us since the closing of this offering equals the operating surplus from the closing of this offering through the end of the quarter immediately preceding that distribution. We anticipate that distributions from operating surplus generally will not represent a return of capital. However, operating surplus, as defined in our partnership agreement, includes certain components, including a $         million cash basket, that represent non-operating sources of cash. Consequently, it is possible that all or a portion of specific distributions from operating surplus may represent a return of capital. Any available cash distributed by us in excess of our cumulative operating surplus will be deemed to be capital surplus under our partnership agreement. Our partnership agreement treats a distribution of capital surplus as the repayment of the initial unit price from this initial public offering and as a return of capital. We do not anticipate that we will make any distributions from capital surplus.

Capital Expenditures

We distinguish between maintenance capital expenditures and expansion capital expenditures. In general, maintenance capital expenditures are cash expenditures made to maintain, over the long term, our operating capacity or capital asset base, and expansion capital expenditures are cash expenditures made to increase, over the long term, our operating capacity or capital asset base. 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 distributable cash flow, operating surplus and adjusted operating surplus if we were to subtract actual maintenance capital expenditures. To help mitigate these fluctuations, our partnership agreement will require that each quarter we subtract from operating surplus an estimate of the average quarterly maintenance capital expenditures necessary to maintain our operating capacity or capital asset base over the long term, as opposed to subtracting the actual amount we spend

 

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on maintenance capital expenditures in that quarter. As a result, estimated maintenance capital expenditures will reduce operating surplus and distributable cash flow, but expansion capital expenditures and actual maintenance capital expenditures will not reduce operating surplus and distributable cash flow.

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 capital asset base over the long term. Factors our general partner will consider include an assessment of current operating capacity or capital asset base of a mine at the time of the expenditure and an evaluation of whether the expenditure will increase such mine’s operating capacity or capital asset base or whether the expenditure will replace or maintain such mine’s current operating capacity or capital asset base. To the extent a capital expenditure increases operating capacity or capital asset base in a sustainable way, it will be classified as an expansion capital expenditure in the period in which the capital expenditure was made. Otherwise, it will be considered a maintenance capital expenditure. Capital expenditures that are made in part for maintenance capital purposes and in part for expansion capital purposes will be allocated as maintenance capital expenditures or expansion capital expenditures by our general partner.

Maintenance Capital Expenditures

Under our partnership agreement, maintenance capital expenditures are cash expenditures (including expenditures for the construction of new capital assets or the replacement, improvement or expansion of existing capital assets) made to maintain, over the long term, our operating capacity or capital asset base. Maintenance capital expenditures include interest payments (and related fees) on debt incurred and distributions on equity issued (including incremental distributions on incentive distribution rights) to finance all or a portion of maintenance capital expenditures in respect of the period from the date that we enter into a binding obligation to commence the construction, replacement, improvement or expansion of a capital asset and ending on the earlier to occur of the date that such capital improvement commences commercial service and the date that such capital improvement is abandoned or disposed of. Examples of maintenance capital expenditures include expenditures associated with the replacement of equipment and coal reserves, whether through the expansion 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 capital asset base as they exist at such time as the capital expenditures are made. In addition, the rebuild of a continuous mining unit would be considered a maintenance capital expenditure as it would not result in a sustainable, long-term increase to a mine’s operating capacity or capital asset base but rather will maintain such mine’s current operating capacity or capital asset base.

Our partnership agreement will require that each quarter we subtract from operating surplus an estimate of the average quarterly maintenance capital expenditures necessary to maintain our operating capacity or capital asset base over the long term, as opposed to subtracting the actual amount we spend on maintenance capital expenditures in that quarter. The amount of estimated maintenance capital expenditures deducted from operating surplus for those periods will be subject to review and revision by our general partner at least once a year. 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, such as a major acquisition or the introduction of new governmental regulations that will impact our business. Our partnership agreement does not set a limit on the amount of maintenance capital expenditures that our general partner may estimate. 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:

 

   

the amount of actual maintenance capital expenditures in any quarter will not directly reduce operating surplus but will instead be factored into the estimate of the average quarterly maintenance

 

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capital expenditures. This may result in the subordinated units converting into common units when the use of actual maintenance capital expenditures would result in lower operating surplus during the subordination period and potentially result in the tests for conversion of the subordinated units not being satisfied;

 

    it may increase our ability to distribute as operating surplus cash we receive from non-operating sources; and

 

    it may be more difficult for us to raise our distribution above the minimum quarterly distribution and pay incentive distributions on the incentive distribution rights held by our general partner.

We forecast that our estimated maintenance capital expenditures will total $         million during the twelve months ending June 30, 2016. We expect to fund actual cash maintenance capital expenditures with cash generated by our operations.

Expansion Capital Expenditures

Under our partnership agreement, expansion capital expenditures are cash expenditures for acquisitions, the construction of new capital assets or the replacement, improvement or expansion of existing capital assets that are made to increase, over the long term, our operating capacity or capital asset base. Expansion capital expenditures include interest payments (and related fees) on debt incurred and distributions on equity issued (including incremental distributions on incentive distribution rights) to finance all or a portion of expansion capital expenditures in respect of the period from the date that we enter into a binding obligation to commence the construction, replacement, improvement or expansion of a capital asset and ending on the earlier to occur of the date that such capital improvement commences commercial service and the date that such capital improvement is abandoned or disposed of. Examples of expansion capital expenditures include the acquisition or the construction, development or expansion of additional mines, longwall mining systems, processing facilities, transload facilities or storage capacity, to the extent such capital expenditures are expected to expand our long-term operating capacity or capital asset base. For example, should we determine to develop an additional longwall mining system at the Harvey mine, the capital expenditures related to the development of the second longwall mining system would be considered expansion capital expenditures since they would increase the current operating capacity or capital asset base of the Harvey mine over the long term. Because expansion capital expenditures include interest payments (and related fees) on debt incurred to finance all or a portion of the construction of a capital asset in respect of a period that (i) begins when we enter into a binding obligation to commence construction of a capital improvement and (ii) ends on the earlier to occur of the date any such capital asset commences commercial service and the date that it is abandoned or disposed of, such interest payments also do not reduce operating surplus.

We estimate that our expansion capital expenditures will be approximately $         million for the twelve months ending June 30, 2016.

Subordinated Units and Subordination Period

General

Our partnership agreement provides that, during the subordination period (which we define below), the common units will have the right to receive distributions of available cash from operating surplus each quarter in an amount equal to $         per 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 of available cash from operating surplus may be made on the subordinated units. Subordinated 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 distributions from operating

 

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surplus until the common units have received the minimum quarterly distribution from operating surplus plus any arrearages in the payment of the minimum quarterly distribution from operating surplus on the common units from prior quarters. Furthermore, no arrearages will accrue or be payable on the subordinated units. The practical effect of the subordinated units is to increase the likelihood that, during the subordination period, there will be available cash to be distributed on the common units.

Subordination Period

Except as described below, the subordination period will begin on the closing date of this offering and will extend until the first business day following the distribution of available cash in respect of any quarter beginning after                     , 2018, that each of the following tests are met:

 

    distributions of available cash from operating surplus on each of the outstanding common units and subordinated units and the corresponding distributions on the 2% general partner interest equaled or exceeded $         (the annualized minimum quarterly distribution), for each of the three consecutive, non-overlapping four-quarter periods immediately preceding that date;

 

    the adjusted operating surplus (as defined below) generated during each of the three consecutive, non-overlapping four-quarter periods immediately preceding that date equaled or exceeded the sum of $         (the annualized minimum quarterly distribution) on all of the outstanding common units and subordinated units and the corresponding distributions on the 2% general partner interest during those periods on a fully diluted basis; and

 

    there are no arrearages in payment of the minimum quarterly distribution on the common units.

Early Termination of the Subordination Period

Notwithstanding the foregoing, the subordination period will automatically terminate on the first business day following the distribution of available cash in respect of any quarter, beginning with the quarter ending                     , 2016, that each of the following tests are met:

 

    distributions of available cash from operating surplus on each of the outstanding common units and subordinated units and the corresponding distributions on the 2% general partner interest equaled or exceeded $         (150% of the annualized minimum quarterly distribution), plus the related distributions on the incentive distribution rights, for the four-quarter period immediately preceding that date;

 

    the adjusted operating surplus (as defined below) generated during the four-quarter period immediately preceding that date equaled or exceeded the sum of (i) $         (150% of the annualized minimum quarterly distribution) on all of the outstanding common units and subordinated units and the corresponding distributions on the 2% general partner interest during that period on a fully diluted basis and (ii) the corresponding distributions on the incentive distribution rights; and

 

    there are no arrearages in payment of the minimum quarterly distribution on the common units.

Expiration of the Subordination Period

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

 

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Adjusted Operating Surplus

Adjusted operating surplus is intended to 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 established in prior periods. Adjusted operating surplus for a period consists of:

 

    operating surplus generated with respect to that period (excluding any amounts attributable to the item described in the first bullet under the caption “—Operating Surplus and Capital Surplus—Operating Surplus” above); less

 

    any net increase in working capital borrowings with respect to that period; less

 

    any expenditures that are not operating expenditures solely because of the provision described in clause (vi) of the third bullet under the caption “—Operating Surplus and Capital Surplus—Operating Expenditures” above; less

 

    any net decrease in cash reserves for operating expenditures with respect to that period not relating to an operating expenditure made with respect to that period; plus

 

    any net decrease in working capital borrowings with respect to that period; plus

 

    any net decrease made in subsequent periods to cash reserves for operating expenditures initially established with respect to that period to the extent such decrease results in a reduction in adjusted operating surplus in subsequent periods; plus

 

    any net increase in cash reserves for operating expenditures with respect to that period required by any debt instrument for the repayment of principal, interest or premium.

Distributions of Available Cash from Operating Surplus During the Subordination Period

We will make distributions of available cash from operating surplus for any quarter during the subordination period in the following manner:

 

    first, 98% to the common unitholders, pro rata, and 2% to our general partner, until we distribute for each outstanding common unit an amount equal to the minimum quarterly distribution for that quarter;

 

    second, 98% to the common unitholders, pro rata, and 2% to our general partner, until we distribute for each outstanding common unit an amount equal to any arrearages in payment of the minimum quarterly distribution on the common units for any prior quarters during the subordination period;

 

    third, 98% to the subordinated unitholders, pro rata, and 2% to our general partner, until we distribute for each outstanding subordinated unit an amount equal to the minimum quarterly distribution for that quarter; and

 

    thereafter, in the manner described in “—General Partner Interest and Incentive Distribution Rights” below.

The preceding discussion is based on the assumptions that our general partner maintains its 2% general partner interest and that we do not issue additional classes of equity securities.

 

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Distributions of Available Cash from Operating Surplus After the Subordination Period

We will make distributions of available cash from operating surplus for any quarter after the subordination period in the following manner:

 

    first, 98% to all common unitholders, pro rata, and 2% to our general partner, until we distribute for each outstanding common unit an amount equal to the minimum quarterly distribution for that quarter; and

 

    thereafter, in the manner described in “—General Partner Interest and Incentive Distribution Rights” below.

The preceding discussion is based on the assumptions that our general partner maintains its 2% general partner interest and that we do not issue additional classes of equity securities.

General Partner Interest and Incentive Distribution Rights

Our partnership agreement provides that our general partner initially will be entitled to 2% of all distributions that we make prior to our liquidation. Our general partner has the right, but not the obligation, to contribute a proportionate amount of capital to us in order to maintain its 2% general partner interest if we issue additional limited partner interests. Our general partner’s 2% general partner interest, and the percentage of our cash distributions to which it is entitled from such 2% general partner interest, will be proportionately reduced if we issue additional limited partner interests in the future (other than the issuance of common units upon any exercise by the underwriters of their option to purchase additional common units in this offering, the issuance of common units upon conversion of outstanding subordinated units or the issuance of common units upon a reset of the incentive distribution rights) and our general partner does not contribute a proportionate amount of capital to us in order to maintain its 2% general partner interest. Our partnership agreement does not require that our general partner fund its capital contribution with cash. Our general partner may instead fund its capital contribution by the contribution to us of common units or other property.

Incentive distribution rights represent the right to receive an increasing percentage (13%, 23% and 48%) of quarterly distributions of available cash 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.

The following discussion assumes that our general partner maintains its 2% general partner interest, our general partner continues to own the incentive distribution rights and we do not issue any additional classes of equity securities.

If for any quarter:

 

    we have distributed available cash from operating surplus to the common unitholders and subordinated unitholders in an amount equal to the minimum quarterly distribution; and

 

    we have distributed available cash from operating surplus on outstanding common units in an amount necessary to eliminate any cumulative arrearages in payment of the minimum quarterly distribution;

then, we will distribute any additional available cash from operating surplus for that quarter among the unitholders and our general partner in the following manner:

 

    first, 98% to all unitholders, pro rata, and 2% to our general partner, until each unitholder receives a total of $         per unit for that quarter (the “first target distribution”);

 

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    second, 85% to all unitholders, pro rata, and 15% to our general partner, until each unitholder receives a total of $         per unit for that quarter (the “second target distribution”);

 

    third, 75% to all unitholders, pro rata, and 25% to our general partner, until each unitholder receives a total of $         per unit for that quarter (the “third target distribution”); and

 

    thereafter, 50% to all unitholders, pro rata, and 50% to our general partner.

Percentage Allocations of Available Cash from Operating Surplus

The following table illustrates the percentage allocations of available cash from operating surplus between the unitholders and our general partner, as the initial holder of our incentive distribution rights, based on the specified target distribution levels. The amounts set forth under “Marginal percentage interest in distributions” are the percentage interests of our unitholders and our general partner in any available cash from operating surplus we distribute up to and including the corresponding amount in the column “Total quarterly distribution per unit target amount” until available cash we distribute reaches the next target distribution level, if any. The percentage interests shown for our unitholders and our general partner 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 for our general partner include its 2% general partner interest and assume that our general partner has contributed any additional capital necessary to maintain its 2% general partner interest, our general partner has not transferred its incentive distribution rights and that there are no arrearages on common units.

 

                  

Marginal Percentage
Interest in Distributions

 
    

Total Quarterly Distribution Per Unit
Target Amount

    

Unitholders

   

General
Partner

 

Minimum Quarterly Distribution

        $                     98     2

First Target Distribution

   above $                      up to $                     98     2

Second Target Distribution

   above $                      up to $                     85     15

Third Target Distribution

   above $                      up to $                     75     25

Thereafter

        above $                     50     50

General Partner’s Right to Reset Incentive Distribution Levels

Our general partner, as the initial holder of our incentive distribution rights, has the right under our partnership agreement, subject to certain conditions, 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 minimum quarterly distribution amount and target distribution levels upon which the incentive distribution payments to our general partner 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. Our general partner’s right to reset the minimum quarterly distribution amount and the target distribution levels upon which the incentive distributions payable to our general partner are based may be exercised, without approval of our unitholders or the conflicts committee, at any time when there are no subordinated units outstanding, we have made cash distributions to the holders of the incentive distribution rights at the highest level of incentive distributions for each of the four consecutive fiscal quarters immediately preceding such time and the amount of each such distribution did not exceed adjusted operating surplus for such quarter. If our general partner and its affiliates are not the holders of a majority of the incentive distribution rights at the time an election is made to reset the minimum quarterly distribution amount and the target distribution levels, then the proposed reset will be subject to the prior written concurrence of the general partner that the conditions described above have been satisfied. The reset minimum quarterly distribution amount and target distribution levels will be higher than the minimum quarterly distribution amount and the target

 

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distribution levels prior to the reset such that the holder of the incentive distribution rights will not receive any incentive distributions under the reset target distribution levels until cash distributions per unit following this event increase as described below. 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 to our general partner.

In connection with the resetting of the minimum quarterly distribution amount and the target distribution levels and the corresponding relinquishment by our general partner of incentive distribution payments based on the target distributions prior to the reset, our general partner will be entitled to receive a number of newly issued common units based on a predetermined formula described below that takes into account the “cash parity” value of the average cash distributions related to the incentive distribution rights received by our general partner for the two quarters immediately preceding the reset event as compared to the average cash distributions per common unit during that two-quarter period. In addition, our general partner will be issued a general partner interest necessary to maintain our general partner’s interest in us immediately prior to the reset election.

The number of common units that our general partner (or the then-holder of the incentive distribution rights, if other than our general partner) would be entitled to receive from us in connection with a resetting of the minimum quarterly distribution amount and the target distribution levels then in effect would be equal to the quotient determined by dividing (x) the average aggregate amount of cash distributions received by our general partner in respect of its incentive distribution rights during the two consecutive fiscal quarters ended immediately prior to the date of such reset election by (y) the average of the aggregate amount of cash distributed per common unit during each of these two quarters.

Following a reset election, the minimum quarterly distribution amount will be reset to an amount equal to the average cash distribution amount per common unit for the two fiscal quarters 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 be correspondingly higher such that we would distribute all of our available cash from operating surplus for each quarter thereafter as follows:

 

    first, 98% to all unitholders, pro rata, and 2% to our general partner, until each unitholder receives an amount equal to 115% of the reset minimum quarterly distribution for that quarter;

 

    second, 85% to all unitholders, pro rata, and 15% to our general partner, until each unitholder receives an amount per unit equal to 125% of the reset minimum quarterly distribution for the quarter;

 

    third, 75% to all unitholders, pro rata, and 25% to our general partner, until each unitholder receives an amount per unit equal to 150% of the reset minimum quarterly distribution for the quarter; and

 

    thereafter, 50% to all unitholders, pro rata, and 50% to our general partner.

 

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The following table illustrates the percentage allocations of available cash from operating surplus between the unitholders and our general partner at various cash distribution levels (i) pursuant to the cash distribution provisions of our partnership agreement in effect at the completion of this offering, as well as (ii) following a hypothetical reset of the minimum quarterly distribution and target distribution levels based on the assumption that the average quarterly cash distribution amount per common unit during the two fiscal quarters immediately preceding the reset election was $        .

 

         

Marginal Percentage Interest in
Distributions

   

Quarterly Distribution Per
Unit Following
Hypothetical Reset

 
   

Quarterly Distribution Per
Unit Prior to Reset

   

Common
Unitholders

   

General
Partner
Interest

   

Incentive
Distribution
Rights

   

Minimum Quarterly Distribution

      $                    98%        2%        —          $                   

First Target Distribution

    above $                   up to $                    98%        2%        —          above $             up to $             (a)   

Second Target Distribution

    above $                   up to $                    85%        2%        13%        above $             up to $             (b)   

Third Target Distribution

    above $                   up to $                    75%        2%        23%        above $             up to $             (c)   

Thereafter

      above $                    50%        2%        48%        above $             (c)   

 

(a) This amount is 115% of the hypothetical reset minimum quarterly distribution.
(b) This amount is 125% of the hypothetical reset minimum quarterly distribution.
(c) This amount is 150% of the hypothetical reset minimum quarterly distribution.

The following table illustrates the total amount of available cash from operating surplus that would be distributed to the unitholders and our general partner, including in respect of incentive distribution rights, based on an average of the amounts distributed for the two quarters immediately prior to the reset. The table assumes that immediately prior to the reset there would be          common units outstanding, our general partner’s 2% general partner interest has been maintained and the average distribution to each common unit would be $         per quarter for the two consecutive, non-overlapping quarters prior to the reset.

 

                     

Cash Distribution to General
Partner Prior to Reset

 
   

Quarterly
Distribution Per
Unit Prior to Reset

   

Cash
Distributions to
Common
Unitholders
Prior to Reset

   

Common
Units

   

2%
General
Partner
Interest

   

Incentive
Distribution
Rights

   

Total

   

Total
Distributions

 

Minimum Quarterly Distribution

      $             $                   $ —        $                   $ —        $        $     

First Target Distribution

    above $               up to $                 —            —         

Second Target Distribution

    above $               up to $                 —             

Third Target Distribution

    above $               up to $                 —             

Thereafter

      above $                 —             
     

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 
      $        $ —        $        $        $                   $                
     

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

 

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The following table illustrates the total amount of available cash from operating surplus that would be distributed to the unitholders and the general partner, including in respect of incentive distribution rights, with respect to the quarter after the reset occurs. The table reflects that, as a result of the reset, there would be              common units outstanding, our general partner has maintained its 2% general partner interest and that the average distribution to each common unit would be $        . The number of common units issued as a result of the reset was calculated by dividing (x) $        , the average of the amounts received by the general partner in respect of its incentive distribution rights for the two consecutive, non-overlapping quarters prior to the reset as shown in the table above, by (y) $        , the average of the cash distributions made on each common unit per quarter for the two consecutive, non-overlapping quarters prior to the reset as shown in the table above.

 

     

Cash Distribution to General
Partner After Reset

 
   

Quarterly
Distribution Per
Unit After Reset

   

Cash
Distributions
to Common
Unitholders
After Reset

   

Common
Units

   

2%
General
Partner
Interest

   

Incentive
Distribution
Rights

   

Total

   

Total
Distributions

 

Minimum Quarterly Distribution

    $             $        $        $        $ —        $        $     

First Target Distribution

    above $         up to $               —          —          —          —          —          —     

Second Target Distribution

    above $         up to $               —          —          —          —          —          —     

Third Target Distribution

    above $         up to $               —          —          —          —          —          —     

Thereafter

    above $               —          —          —          —          —          —     
   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 
    $                   $                   $                   $ —        $                   $                
   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Our general partner will be entitled to cause the minimum quarterly distribution amount and the target distribution levels to be reset on more than one occasion, provided that it may not make a reset election except at a time when it has received incentive distributions for the immediately preceding four consecutive fiscal quarters based on the highest level of incentive distributions that it is entitled to receive under our partnership agreement.

Distributions from Capital Surplus

How Distributions from Capital Surplus Will Be Made

We will make distributions of available cash from capital surplus, if any, in the following manner:

 

    first, 98% to all unitholders, pro rata, and 2% to our general partner, until we distribute for each common unit that was issued in this offering, an amount of available cash from capital surplus equal to the initial public offering price in this offering;

 

    second, 98% to all unitholders, pro rata, and 2% to our general partner, until we distribute for each common unit, an amount of available cash from capital surplus equal to any unpaid arrearages in payment of the minimum quarterly distribution on the outstanding common units; and

 

    thereafter, as if they were from operating surplus.

The preceding discussion is based on the assumptions that our general partner maintains its 2% general partner interest and that we do not issue additional classes of equity securities.

Effect of a Distribution from Capital Surplus

Our partnership agreement treats a distribution of capital surplus as the repayment of the initial unit price from this initial public offering, which is a return of capital. The initial public offering price less any distributions of capital surplus per unit is referred to as the “unrecovered initial unit price.” Each time a distribution of capital surplus is made, the minimum quarterly distribution and the target distribution levels will

 

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be reduced in the same proportion as the corresponding reduction in the unrecovered initial unit price. Because distributions of capital surplus will reduce the minimum quarterly distribution after any of these distributions are made, the effects of distributions of capital surplus may make it easier for our general partner to receive incentive distributions and for the subordinated units to convert into common units. However, any distribution of capital surplus before the unrecovered initial unit price is reduced to zero cannot be applied to the payment of the minimum quarterly distribution or any arrearages.

Once we distribute capital surplus on a unit issued in this offering in an amount equal to the initial unit price, we will reduce the minimum quarterly distribution and the target distribution levels to zero. Then, after distributing an amount of capital surplus for each common unit equal to any unpaid arrearages of the minimum quarterly distributions on outstanding common units, we will then make all future distributions from operating surplus, with 50% being paid to the unitholders, pro rata, and 2% to our general partner and 48% to the holder of our 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 of capital surplus, if we combine our units into fewer units or subdivide our units into a greater number of units, we will proportionately adjust:

 

    the minimum quarterly distribution;

 

    target distribution levels;

 

    the unrecovered initial unit price; and

 

    the arrearages per common unit in payment of the minimum quarterly distribution on the common units.

For example, if a two-for-one split of the common units should occur, the minimum quarterly distribution, the target distribution levels and the unrecovered initial unit price would each be reduced to 50% of its initial level, and each subordinated unit would be split into two subordinated units. We will not make any adjustment by reason of the issuance of additional units for cash or property (including additional common units issued under any compensation or benefit plans).

In addition, if legislation is enacted or if the official interpretation of existing law is modified by a governmental authority, so that we become taxable as a corporation or otherwise subject to taxation as an entity for federal, state or local income tax purposes, our partnership agreement specifies that the minimum quarterly distribution and the target distribution levels for each quarter may be reduced by multiplying each distribution level by a fraction, the numerator of which is available cash for that quarter (reduced by the amount of the estimated tax liability for such quarter payable by reason of such legislation or interpretation) and the denominator of which is the sum of available cash for that quarter (reduced by the amount of the estimated tax liability for such quarter payable by reason of such legislation or interpretation) plus our general partner’s estimate of our aggregate liability for the quarter for such income taxes payable by reason of such legislation or interpretation. To the extent that the actual tax liability differs from the estimated tax liability for any quarter, the difference may be accounted for in subsequent quarters.

Distributions of Cash Upon Liquidation

General

If we dissolve in accordance with our 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

 

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creditors. We will distribute any remaining proceeds to the unitholders and our general partner, 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 outstanding common units to a preference over the holders of outstanding subordinated units upon our liquidation, to the extent required to permit common unitholders to receive their unrecovered 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 holders of common units to fully recover all of these amounts, even though there may be cash distributed 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 of our general partner.

Manner of Adjustments for Gain

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

 

    first, to our general partner to the extent of any negative balance in its capital account;

 

    second, 98% to the common unitholders, pro rata, and 2% to our general partner, until the capital account for each common unit is equal to the sum of:

 

  (1) the unrecovered initial unit price;

 

  (2) the amount of the minimum quarterly distribution for the quarter during which our liquidation occurs; and

 

  (3) any unpaid arrearages in payment of the minimum quarterly distribution;

 

    third, 98% to the subordinated unitholders, pro rata, and 2% to our general partner, until the capital account for each subordinated unit is equal to the sum of:

 

  (1) the unrecovered initial unit price; and

 

  (2) the amount of the minimum quarterly distribution for the quarter during which our liquidation occurs;

 

    fourth, 98% to all unitholders, pro rata, and 2% to our general partner, until we allocate under this paragraph an amount per unit equal to:

 

  (1) the sum of the excess of the first target distribution per unit over the minimum quarterly distribution per unit for each quarter of our existence; less

 

  (2) the cumulative amount per unit of any distributions of available cash from operating surplus in excess of the minimum quarterly distribution per unit that we distributed 98% to the unitholders, pro rata, and 2% to our general partner, for each quarter of our existence;

 

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    fifth, 85% to all unitholders, pro rata, and 15% to our general partner, until we allocate under this paragraph an amount per unit equal to:

 

  (1) the sum of the excess of the second target distribution per unit over the first target distribution per unit for each quarter of our existence; less

 

  (2) the cumulative amount per unit of any distributions of available cash from operating surplus in excess of the first target distribution per unit that we distributed 85% to the unitholders, pro rata, and 15% to our general partner for each quarter of our existence;

 

    sixth, 75% to all unitholders, pro rata, and 25% to our general partner, until we allocate under this paragraph an amount per unit equal to:

 

  (1) the sum of the excess of the third target distribution per unit over the second target distribution per unit for each quarter of our existence; less

 

  (2) the cumulative amount per unit of any distributions of available cash from operating surplus in excess of the second target distribution per unit that we distributed 75% to the unitholders, pro rata, and 25% to our general partner for each quarter of our existence; and

 

    thereafter, 50% to all unitholders, pro rata, and 50% to our general partner.

The percentages set forth above are based on the assumption that our general partner maintains its 2% general partner interest and has not transferred its incentive distribution rights and that we do not issue additional classes of equity securities.

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 fourth bullet point above will no longer be applicable.

Manner of Adjustments for Losses

If our liquidation occurs before the end of the subordination period, after making allocations of loss to the general partner and the unitholders in a manner intended to offset in reverse order the allocations of gains that have previously been allocated, we will generally allocate any loss to our general partner and unitholders in the following manner:

 

    first, 98% to the holders of subordinated units in proportion to the positive balances in their capital accounts and 2% to our general partner, until the capital accounts of the subordinated unitholders have been reduced to zero;

 

    second, 98% to the holders of common units in proportion to the positive balances in their capital accounts and 2% to our general partner, until the capital accounts of the common unitholders have been reduced to zero; and

 

    thereafter, 100% to our general partner.

The percentages set forth above are based on the assumption that our general partner maintains its 2% general partner interest and has not transferred its incentive distribution rights and that we do not issue additional classes of equity securities.

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

 

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Adjustments to Capital Accounts

Our partnership agreement requires that we make adjustments to capital accounts upon the issuance of additional units. In this regard, our partnership agreement specifies that we allocate any unrealized and, for tax purposes, unrecognized gain resulting from the adjustments to the unitholders and the general partner 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 our general partner 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 units and subordinated units. If we make negative adjustments to the capital accounts as a result of such loss, future positive adjustments resulting from the issuance of additional units will be allocated in a manner designed to reverse the prior negative adjustments, and special allocations will be made upon liquidation in a manner that results, to the extent possible, in our unitholders’ capital account balances equaling the amounts they would have been if no earlier adjustments for loss had been made.

 

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SELECTED HISTORICAL AND PRO FORMA FINANCIAL AND OPERATING DATA

The following table presents selected historical financial data of our Predecessor and selected unaudited pro forma financial data of CNX Coal Resources LP for the periods and as of the dates indicated. The following selected historical financial data of our Predecessor reflects a 20% undivided interest in CPCC and Conrhein’s combined assets, liabilities, revenues and expenses that CONSOL Energy will contribute to us at the closing of this offering.

The selected historical financial data of our Predecessor as of and for the years ended December 31, 2014 and 2013 are derived from the audited financial statements of our Predecessor appearing elsewhere in this prospectus. The following table should be read together with, and is qualified in its entirety by reference to, the historical and unaudited pro forma combined financial statements and the accompanying notes included elsewhere in this prospectus. The table should also be read together with “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

The selected unaudited pro forma financial data presented in the following table for the year ended December 31, 2014 is derived from the unaudited pro forma combined financial statements included elsewhere in this prospectus. The unaudited pro forma combined balance sheet assumes the offering and the related transactions occurred as of December 31, 2014, and the unaudited pro forma combined statement of operations for the year ended December 31, 2014, assume the offering and the related transactions occurred as of January 1, 2014. These transactions include, and the unaudited pro forma combined financial statements give effect to, the following:

 

    CONSOL Energy’s contribution to us of a 20% undivided interest in the assets, liabilities, revenues and expenses comprising the Pennsylvania mining complex that are currently held by CPCC and Conrhein;

 

    our entry into a new $         million revolving credit facility and initial draw of $             million that will be distributed to CONSOL Energy at the closing of this offering;

 

    our entry into an operating agreement, employee services agreement, contract agency agreement, terminal and throughput agreement, management services agreement, cooperation and safety agreement, water supply and services agreement, omnibus agreement, asset contribution agreement and equity contribution agreement with CONSOL Energy as described in “Certain Relationships and Related Party Transactions—Agreements Governing the Transactions;”

 

    the consummation of this offering and our issuance of (i)          common units to the public, (ii)          a 2% general partner interest and the incentive distribution rights to our general partner and (iii)          common units and          subordinated units to CONSOL Energy; and

 

    the application of the net proceeds of this offering as described in “Use of Proceeds.”

The unaudited pro forma combined statement of operations does not give effect to an estimated $2.4 million in incremental general and administrative expenses that we expect to incur annually as a result of being a publicly traded partnership.

 

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CNX Coal Resources LP
Predecessor
Historical

   

CNX Coal
Resources LP
Pro Forma

 
    

Year Ended
December 31,

   

Year Ended
December 31,

 
    

2014

   

2013

   

2014

 
     (in thousands, except per ton data)  

Statement of Operations Data:

      

Coal revenue

   $ 323,398      $ 271,467      $ 323,398   

Freight revenue

     3,353        3,556        3,353   

Other income

     7,580        1,336        7,371   

Gain (loss) on sale of assets

     148        (124     153   
  

 

 

   

 

 

   

 

 

 

Total revenue and other income

  334,479      276,235      334,275   

Operating and other costs

  172,863      152,054      172,327   

Royalties and production taxes

  14,169      11,046      14,169   

Selling and direct administrative expenses

  6,444      5,687      4,710   

Depreciation, depletion and amortization

  33,949      25,306      33,786   

Freight expense

  3,353      3,556      3,353   

General and administrative expenses—related party (1)

  5,198      4,521      5,264   

Other corporate expenses

  7,658      7,680      7,658   

Interest expense

  6,946      2,093      8,631   
  

 

 

   

 

 

   

 

 

 

Total costs

  250,580      211,943      249,898   
  

 

 

   

 

 

   

 

 

 

Net income

$ 83,899    $ 64,292    $ 84,377   
  

 

 

   

 

 

   

 

 

 

Balance Sheet Data (at period end):

Property, plant and equipment, net

$ 398,886    $ 374,284    $ 379,439   

Total assets

  418,811      392,760      415,869   

Total invested equity / partners’ capital

  170,626      119,817      137,230   

Cash Flow Statement Data:

Net cash provided by operating activities

$ 114,109    $ 94,416   

Net cash used in investing activities

  (52,824   (67,628

Net cash used in financing activities

  (61,285   (26,789

Coal Reserves, Production and Sales Data:

Recoverable reserves (at period end)

  157,127      125,066      157,127   

Coal tons produced

  5,213      4,287      5,213   

Coal tons sold

  5,227      4,246      5,227   

Average sales price per ton

$ 61.88    $ 63.93    $ 61.88   

Average costs per ton sold

$ 42.74    $ 44.53    $ 42.44   

Average cash margin per ton (2)

$ 25.27    $ 24.98    $ 25.57   

Other Data:

Capital expenditures

$ 68,061    $ 82,182   

Adjusted EBITDA (3)

$ 125,150    $ 96,435    $ 127,150   

 

(1) General and administrative expenses—related party for the pro forma year ended December 31, 2014 does not give effect to annual incremental general and administrative expenses of approximately $2,418 that we expect to incur as a result of being a publicly traded partnership.
(2) For our calculation of average cash margin per ton, please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Results of Operations—Coal Operations.”
(3) For our definition of the non-GAAP financial measure of adjusted EBITDA and a reconciliation of adjusted EBITDA to our most directly comparable financial measure calculated and presented in accordance with GAAP, please read “—Non-GAAP Financial Measure.”

 

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Non-GAAP Financial Measure

We define adjusted EBITDA as (i) net income (loss) before net interest expense, depreciation, depletion and amortization, as adjusted for (ii) material nonrecurring and other items which may not reflect the trend of our future results. Adjusted EBITDA is used as a supplemental financial measure by management and by external users of our financial statements, such as investors, industry analysts, lenders and ratings agencies, to assess:

 

    our operating performance as compared to the operating performance of other companies in the coal industry, without regard to financing methods, historical cost basis or capital structure;

 

    the ability of our assets to generate sufficient cash flow to make distributions to our partners;

 

    our ability to incur and service debt and fund capital expenditures; and

 

    the viability of acquisitions and other capital expenditure projects and the returns on investment of various investment opportunities.

We believe that the presentation of adjusted EBITDA in this prospectus provides information useful to investors in assessing our financial condition and results of operations. The GAAP measure most directly comparable to adjusted EBITDA is net income. Adjusted EBITDA should not be considered an alternative to net income or any other measure of financial performance or liquidity presented in accordance with GAAP. Adjusted EBITDA excludes some, but not all, items that affect net income or net cash, and these measures may vary from those of other companies. As a result, adjusted EBITDA as presented below may not be comparable to similarly titled measures of other companies.

The following table presents a reconciliation of adjusted EBITDA to net income, the most directly comparable GAAP financial measure, on a historical basis and pro forma basis, as applicable, for each of the periods indicated.

 

    

CNX Coal Resources LP

Predecessor

Historical

   

CNX Coal
Resources LP
Pro Forma

 
     Year Ended
December 31,
   

Year Ended
December 31,

 
    

2014

   

2013

   

2014

 
     (in thousands)  

Net income attributable to unitholders

   $ 83,899      $ 64,292      $ 84,377   

Interest expense

     6,946        2,093        8,631   

Depreciation, depletion and amortization

     33,949        25,306        33,786   

Coal contract buyout

     (6,000     —          (6,000

Other postretirement benefit plan transition payment, net

     3,299        —          3,299   

Litigation settlement

     (855     —          (855

Business interruption proceeds

     —          (1,089     —     

Bailey belt repairs

     551        1,662        551   

Stock based compensation

     3,361        4,171        3,361   
  

 

 

   

 

 

   

 

 

 

Adjusted EBITDA

$ 125,150    $ 96,435    $ 127,150   
  

 

 

   

 

 

   

 

 

 

 

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

You should read the following discussion of the financial condition and results of operations of our Predecessor in conjunction with the historical financial statements and notes of our Predecessor and the unaudited pro forma combined financial statements for CNX Coal Resources LP included elsewhere in this prospectus. Among other things, those historical and unaudited pro forma combined financial statements include more detailed information regarding the basis of presentation for the following information. This discussion contains forward-looking statements that involve risks and uncertainties. Our actual results could differ materially from those described in such forward-looking statements. Factors that could cause or contribute to such differences include, but are not limited to, those identified below and those discussed in the sections entitled “Risk Factors” and “Forward-Looking Statements” included elsewhere in this prospectus.

Unless otherwise indicated, the following discussion of the financial condition and results of operations of our Predecessor reflect a 20% undivided interest in the assets, liabilities and results of operations of the Pennsylvania mining complex, presented on a proportionate basis, as of December 31, 2014 and 2013, and for the years then ended. As used in the following discussion of the financial condition and results of operations of our Predecessor, the terms “we,” “our,” “us,” or like terms refer to our Predecessor with respect to its 20% undivided interest in the Pennsylvania mining complex’s combined assets, liabilities, revenues and costs.

Overview

We are a growth-oriented master limited partnership recently formed by CONSOL Energy to manage and further develop all of its active thermal coal operations in Pennsylvania. Our initial assets include a 20% undivided interest in, and operational control over, CONSOL Energy’s Pennsylvania mining complex, which consists of three underground mines and related infrastructure that produce high-Btu bituminous thermal coal that is sold primarily to electric utilities in the eastern United States, our core market. We believe that our ability to efficiently produce and deliver large volumes of high-quality coal at competitive prices, the strategic location of our mines, the industry experience of our management team and our relationship with CONSOL Energy position us as a leading producer of high-Btu thermal coal in the Northern Appalachian Basin and the eastern United States.

How We Evaluate Our Operations

Our management intends to use a variety of financial and operating metrics to analyze our performance. These metrics are significant factors in assessing our operating results and profitability and include: (i) coal production, sales volumes and average sales price, which drive coal sales revenue; (ii) cost of coal sales; (iii) adjusted EBITDA, a non-GAAP financial measure; and (iv) distributable cash flow, a non-GAAP financial measure.

Coal Production, Sales Volumes and Average Sales Price

We evaluate our operations based on the volume of coal we can safely produce in compliance with regulatory standards, the volume of coal we sell and the prices we receive for our coal. Our coal production, sales volume and sales prices are largely dependent upon the terms of our multi-year coal sales contracts. The volume of coal we sell is also a function of the pricing environment in the domestic and international thermal and metallurgical coal markets.

 

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We evaluate the price we receive for our coal on an average sales price per ton basis. Our average sales price per ton represents our coal sales revenue divided by total tons of coal sold. The following table provides operational data with respect to our coal sales volume and average prices per ton for the Pennsylvania mining complex on both a 100% basis and our 20% undivided interest for the periods indicated:

 

   

100% Basis for the Years Ended
December 31,

   

20% Undivided Interest for the
Years Ended December 31,

 
   

2014

   

2013

   

2014

   

2013

 
   

(tons in millions)

 

Tons of coal produced

    26.1        21.4        5.2        4.3   

Tons of coal sold

    26.1        21.2        5.2        4.2   

Tons sold under multi-year sales contracts (1)

    15.3        15.5        3.1        3.1   

Average sales price per ton

  $ 61.88      $ 63.93      $ 61.88      $ 63.93   

 

(1) Contracts over one year in duration

We will seek to minimize our direct commodity price exposure and maintain stable cash flows by generating a substantial portion of our revenues from multi-year, committed and priced sales contracts with well-established, creditworthy customers. We intend to further enhance our already strong contract portfolio by focusing on our existing high-quality customer base and extending the duration of our multi-year sales contracts. We believe our multi-year sales contracts provide significant revenue visibility and facilitate our ability to generate stable and consistent cash flows. The average term of our sales contracts is between one to three years, and we have several multi-year sales contracts with terms over four years. Please read “—Factors That Affect Our Results—Contract Position” for more information about the contract position of the Pennsylvania mining complex under our multi-year sales contracts as of March 25, 2015.

Cost of Coal Sales

We evaluate our cost of coal sales on a cost per ton basis. Our cost of coal sales per ton represents our costs divided by the tons of coal we sell. Our costs include labor, supplies, utilities, operating lease expenses, repairs and maintenance, direct administrative expenses, selling expenses, royalties, production taxes and depreciation, depletion and amortization costs, as well as coal inventory fluctuations, both volume and price. Our costs exclude any indirect costs such as general and administrative costs and other costs not directly attributable to the production of coal. Please read “—Results of Operations” for more information about the cost of coal sold per ton.

Adjusted EBITDA

We define adjusted EBITDA as (i) net income (loss) before net interest expense, depreciation, depletion and amortization, as adjusted for (ii) material nonrecurring and other items which may not reflect the trend of our future results. Adjusted EBITDA is used as a supplemental financial measure by management and by external users of our financial statements, such as investors, industry analysts, lenders and ratings agencies, to assess:

 

    our operating performance as compared to the operating performance of other companies in the coal industry, without regard to financing methods, historical cost basis or capital structure;

 

    the ability of our assets to generate sufficient cash flow to make distributions to our partners;

 

    our ability to incur and service debt and fund capital expenditures; and

 

    the viability of acquisitions and other capital expenditure projects and the returns on investment of various investment opportunities.

 

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We believe that the presentation of adjusted EBITDA in this prospectus provides information useful to investors in assessing our financial condition and results of operations. The GAAP measure most directly comparable to adjusted EBITDA is net income. Adjusted EBITDA should not be considered an alternative to net income or any other measure of financial performance or liquidity presented in accordance with GAAP. Adjusted EBITDA excludes some, but not all, items that affect net income and our presentation of adjusted EBITDA may vary from that presented by other companies. As a result, adjusted EBITDA as presented below may not be comparable to similarly titled measures of other companies.

For a reconciliation of adjusted EBITDA to net income, the most directly comparable GAAP financial measure, on a historical basis and pro forma basis, please read “Selected Historical and Pro Forma Financial and Operating Data—Non-GAAP Financial Measure.”

Distributable Cash Flow

Although we have not quantified distributable cash flow on a historical basis, after the completion of this offering, we intend to use distributable cash flow, which we define as adjusted EBITDA less net cash interest paid and estimated maintenance capital expenditures, to analyze our performance. Distributable cash flow will not reflect changes in working capital balances.

Distributable cash flow is used as a supplemental financial measure by management and by external users of our financial statements, such as investors, industry analysts, lenders and ratings agencies, to assess:

 

    the ability of our assets to generate cash sufficient to support our indebtedness and make future cash distributions to our unitholders; and

 

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

We believe that the presentation of distributable cash flow in this prospectus provides information useful to investors in assessing our financial condition and results of operations. The GAAP measures most directly comparable to distributable cash flow are net income and net cash provided by operating activities. Distributable cash flow should not be considered an alternative to net income, net cash provided by (used in) operating activities or any other measure of financial performance or liquidity presented in accordance with GAAP. Distributable cash flow excludes some, but not all, items that affect net income or net cash, and these measures may vary from those of other companies. As a result, our distributable cash flow may not be comparable to similarly titled measures of other companies.

Factors That Affect Our Results

Coal Prices. We attempt to mitigate price fluctuations by executing multi-year sales contracts. Domestic coal prices have weakened due to reduced demand from coal-fired power plants. International prices have also declined as a result of excess supply in the marketplace. We expect this low-price environment to continue in the near term.

Coal Demand. Demand for coal can increase due to unusually hot or cold weather as coal-fired electricity generation rises with greater use of air conditioning or heating. Conversely, mild weather can result in weaker demand for our coal. Adverse weather conditions, such as blizzards or floods, can affect our ability to transport our coal and our customers’ ability to take delivery of coal.

 

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Despite the current weakness in international prices, we believe that long-term international demand for thermal and metallurgical coal will continue to increase due primarily to demand from China, India, South Korea, and other Asian countries. As a result of growing international demand, coal prices for thermal coal in the international market have, from time to time, been higher relative to domestic prices and, based on forward price curves, are expected to continue to increase over time. Given our low cost of production and transportation optionality, we believe that we are competitively well positioned to sell and deliver our coal into the international market.

Contract Position. We sell a significant portion of our coal under multi-year sales contracts. Historically, we have marketed our coal principally to electric utilities in the eastern United States. We also export coal into the thermal and metallurgical coal international markets, primarily to Asia, Canada, Europe, India and South America. For the years ended December 31, 2014 and 2013, we sold approximately 13% and 20%, respectively, of total coal production into international markets. The following table describes the contracted position (in millions of tons) of the Pennsylvania mining complex, on a 100% basis, for the years ending December 31, 2015, 2016 and 2017 as of March 25, 2015:

 

     2015      2016      2017  
    

Tons

   

Price

    

Tons

   

Price

    

Tons

   

Price

 

Committed and priced (1)

     22.3      $ 60.84         11.8      $ 60.01         6.7      $ 62.38   

As a percentage of total production for the year ended December 31, 2014

     85.5     N/A         45.1     N/A         25.6     N/A   

Committed and unpriced

     0.1        N/A         1.5        N/A         1.0        N/A   

As a percentage of total production for the year ended December 31, 2014

     0.4     N/A         5.9     N/A         3.8     N/A   

 

(1) Our committed and priced contracts include only those contracts that contain fixed prices with pre-established price adjustments based solely on (i) variances in the quality characteristics of coal delivered to the customer beyond threshold quality characteristics specified in the applicable sales contract, (ii) the actual calorific value of coal delivered to the customer, and/or (iii) certain proprietary price adjustment formulas.

Our sales strategy is generally to enter into multi-year sales contracts for the majority of our production. Our average coal sales revenue per ton in the near term may decrease as we replace expiring favorably priced sales contracts with new sales contracts at contractually negotiated market prices. However, we believe that our low-cost operating structure positions us to successfully contract our coal sales at a profitable margin in any price environment in which our competitors also operate.

Coal Production Rates. The table below presents total tons produced from the Pennsylvania mining complex on both a 100% basis and our 20% undivided interest for the periods indicated (in thousands of tons):

 

     100% Basis for the Years Ended
December 31,
     20% Undivided Interest for the Years
Ended December 31,
 

Mine

  

        2014        

    

        2013        

    

        2014        

    

        2013        

 

Bailey

     12,325         10,754         2,465         2,151   

Enlow Fork

     10,557         10,112         2,111         2,022   

Harvey (1)

     3,184         567         637         114   
  

 

 

    

 

 

    

 

 

    

 

 

 

Total

  26,066      21,433      5,213      4,287   
  

 

 

    

 

 

    

 

 

    

 

 

 

 

(1) The Harvey mine commenced longwall mining operations in March 2014. The tons produced in 2013 were a result of development of the mine.

 

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Current operations at the Pennsylvania mining complex include two longwall mining systems at the Bailey mine, two longwall mining systems at the Enlow Fork mine and one longwall mining system at the Harvey mine. Unless we determine to add an additional permanent longwall mining system at the Harvey mine in the future in order to expand the production capacity of the Pennsylvania mining complex, we generally expect to run five longwall mining systems five days per week under normal operations. We also have the flexibility and spare equipment to run an additional longwall mining system at both the Bailey mine and the Enlow Fork mine. Therefore, to the extent sales exceed our normal operating capacity, we may, from time to time, temporarily run an additional longwall mining system at the Bailey mine and/or the Enlow Fork mine to increase our production to meet our forecasted sales commitments. In addition, we may, from time to time to meet our forecasted sales commitments, (i) run weekend shifts at one or more of our mines to increase our production or (ii) reduce work schedules or idle one or more of our mines to decrease our production.

Cost of Coal Sales. We evaluate our cost of coal sales on a cost per ton basis which represents our operating costs, direct administrative and selling expenses, royalties and production taxes, and depreciation, depletion and amortization costs divided by our tons sold. Operating costs include labor, maintenance, power, lease expense, inventory changes (both volume and price) and all other costs that are directly related to our mining operations other than direct administrative, selling, royalties, production taxes and depreciation, depletion and amortization. Our cost of coal sold excludes any indirect costs, such as general and administrative costs, transportation costs and corporate expenses.

Cost of coal sales varies based on many factors such as sales volumes and commodity prices for the supplies used in the mining process. Geological conditions encountered in the mining process also impact costs of sales due to the impact these conditions have on the volume of coal available for sale and maintenance expenses incurred as a result of geological conditions.

 

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Results of Operations

Year Ended December 31, 2014 Compared with the Year Ended December 31, 2013

Total net income was $84 million for the year ended December 31, 2014 compared to $64 million for the year ended December 31, 2013. Our results of operations for each of these years are presented in the table below. Variances are discussed following the table.

 

    

For the Years Ended
December 31,

        
    

2014

    

2013

    

Difference

 
     (in millions)  

Total coal revenues

   $ 323       $ 271       $ 52   

Freight revenue

     3         4         (1

Miscellaneous other income

     8         1         7   
  

 

 

    

 

 

    

 

 

 

Total revenue and other income

  334      276      58   

Cost of coal sold:

Operating costs

  171      148      23   

Direct administrative and selling

  6      5      1   

Total royalty/production taxes

  14      11      3   

Depreciation, depletion and amortization

  32      25      7   
  

 

 

    

 

 

    

 

 

 

Total cost of coal sold

  223      189      34   

Other costs and expenses:

Other costs

  2      4      (2

Depreciation, depletion and amortization

  2      —        2   
  

 

 

    

 

 

    

 

 

 

Total other costs and expenses

  4      4      —     

General and administrative expense

  5      5      —     

Other corporate expenses

  8      8      —     

Freight expense

  3      4      (1

Interest expense

  7      2      5   
  

 

 

    

 

 

    

 

 

 

Total costs

  250      212      38   
  

 

 

    

 

 

    

 

 

 

Net income

$ 84    $ 64    $ 20   
  

 

 

    

 

 

    

 

 

 

Coal Operations

Coal revenue and cost components on a per unit basis for the years ended December 31, 2014 and December 31, 2013 were as indicated in the table below. Our operations also include various costs such as general and administrative, corporate, freight and other costs not included in our unit cost analysis because these costs are not associated with coal production.

 

    

For the Years Ended
December 31,

              
    

2014

    

2013

    

Variance

   

Percent

Change

 

Company produced tons sold (in millions)

     5.2         4.2         1.0        23.1

Average sales price per ton sold

   $ 61.88       $ 63.93       $ (2.05     (3.2 )% 

Total operating costs per ton sold

   $ 32.69       $ 35.11       $ (2.42     (6.9 )% 

Total direct administration and selling costs per ton sold

     1.20         1.26         (0.06     (4.8 )% 

Total royalty/production taxes per ton sold

     2.72         2.58         0.14        5.4

Total depreciation, depletion and amortization costs per ton sold

     6.13         5.58         0.55        9.9
  

 

 

    

 

 

    

 

 

   

 

 

 

Total costs per ton sold

$ 42.74    $ 44.53    $ (1.79   (4.0 )% 
  

 

 

    

 

 

    

 

 

   

 

 

 

Average margin per ton sold

$ 19.14    $ 19.40    $ (0.26   (1.3 )% 
  

 

 

    

 

 

    

 

 

   

 

 

 

Add: Total depreciation, depletion and amortization costs per ton sold

  6.13      5.58      0.55      9.9
  

 

 

    

 

 

    

 

 

   

 

 

 

Average cash margin per ton sold

$ 25.27    $ 24.98    $ 0.29      1.16
  

 

 

    

 

 

    

 

 

   

 

 

 

 

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Coal Revenue

Coal revenue was $323 million for the year ended December 31, 2014 compared to $271 million for the year ended December 31, 2013. The $52 million increase was attributable to 1.0 million additional tons sold during 2014 partially offset by a $2.05 per ton lower average sales price. The lower average coal sales price in the 2014 period was the result of the roll-off of some higher-priced legacy sales contracts. Revenue was also impacted by 0.7 million tons of coal being priced in the export market for the year ended December 31, 2014, which was 0.2 million tons lower than the tons priced in the export market for the year ended December 31, 2013. Higher sales volumes were the result of market demand and the commissioning of the Harvey mine in March 2014.

Freight Revenue

Freight revenue is the amount billed to customers for transportation costs incurred. This revenue is based on weight of coal shipped and negotiated freight rates for rail transportation to customers for which we contractually provide transportation services. Freight revenue is completely offset in freight expense. Freight revenue was $3 million for the year ended December 31, 2014 compared to $4 million for the year ended December 31, 2013. The $1 million decrease in freight revenue was due to decreased shipments where we were contractually obligated to provide transportation services.

Miscellaneous Other Income

Miscellaneous other income was $8 million for the year ended December 31, 2014 compared to $1 million for the year ended December 31, 2013. The $7 million increase was due to a $6 million coal customer contract buyout and $1 million in other miscellaneous other income, none of which were individually material.

Cost of Coal Sales

Cost of coal sales is comprised of operating and other production costs related to produced tons sold, along with changes in coal inventory, both in volumes and carrying values. The costs of coal sold per ton include items such as direct operating costs, royalty and production taxes, direct administration and selling expenses, and depreciation, depletion, and amortization costs. Total operating costs and expenses were $223 million for the year ended December 31, 2014, or $34 million higher than the $189 million for the year ended December 31, 2013. Total costs per ton sold was $42.74 per ton for the year ended December 31, 2014 compared to $44.53 per ton for the year ended December 31, 2013. The increase in total dollars and decrease in unit costs was primarily due to the 23.1% increase in tons sold. Fixed costs were allocated over more tons sold during 2014, resulting in lower unit costs. These improvements were offset, in part, by various maintenance projects at the Bailey mine and the Enlow Fork mine related to additional longwall overhauls and 22,000 additional feet of coal mined with continuous mining units at the Bailey and the Enlow Fork mines during 2014. The additional footage mined with continuous mining units resulted in additional roof support, haulage, and mine maintenance costs. Unit costs were also negatively impacted during 2014 due to adverse geological conditions at the Enlow Fork mine, primarily relating to sandstone intrusions, along with adverse geological conditions and equipment issues at the Harvey mine, primarily relating to sandstone intrusions, which resulted in reduced coal production at both the Enlow Fork and Harvey mines.

Other Costs

Other costs is comprised of various costs and expenses that are not allocated to each individual mine and therefore not included in unit costs. Other costs were $2 million for the year ended December 31, 2014 compared to $4 million for the year ended December 31, 2013. Supplies expense decreased $1 million for the year ended December 31, 2014 compared to the year ended December 31, 2013 primarily due to additional purchases of supplies in 2013 that related to the preparation plant belt collapse that occurred in July 2012, which were not included in active mining costs.

 

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Other Costs and Expenses—Depreciation, Depletion and Amortization

Depreciation, depletion, and amortization increased $2 million primarily due to additional assets placed in service during 2014 compared to 2013.

General and Administrative Expense

CONSOL Energy allocates general and administrative costs based upon the level of operating activity of its underlying business units. The amount of general and administrative costs allocated to us from CONSOL Energy remained consistent from 2013 to 2014.

Other Corporate Expenses

Other corporate expense is comprised of expenses for CONSOL Energy’s stock based compensation and short-term incentive compensation program. These expenses include costs that are directly related to our operations along with a portion of costs that are allocated to us based on a percent of total labor costs. For the years ended December 31, 2014 and December 31, 2013, other corporate expenses remained consistent.

Freight Expense

Freight expense is based on weight of coal shipped and the negotiated freight rates for rail transportation for customers to which we contractually provide transportation services. Freight revenue is the amount billed to customers for transportation costs incurred. Freight expense is offset by freight revenue. The $1 million decrease in freight expense was due to decreased shipments under contracts for which CONSOL Energy was contractually obligated to provide transportation services.

Interest Expense

Interest expense increased $5 million in 2014 primarily due to less capitalized interest reclassified out of interest expense in 2014 compared to 2013. Capitalized interest decreased during 2014 compared to 2013 due to the Harvey mine coming on line in 2014.

Capital Resources and Liquidity

Liquidity and Financing Arrangements

Historically, our principal sources of liquidity have been cash from operations and funding from CONSOL Energy. While we have historically received funding from CONSOL Energy, we do not have any commitment from CONSOL Energy, our general partner or any of their respective affiliates to fund our cash flow deficits or provide other direct or indirect financial assistance to us following the closing of this offering. We expect our ongoing sources of liquidity following this offering to include cash generated from operations, borrowings under our new revolving credit facility and, if necessary, the issuance of additional equity or debt securities. We believe that cash generated from these sources will be sufficient to meet our short-term working capital requirements and our long-term capital expenditure requirements and to make quarterly cash distributions at our minimum quarterly distribution level.

Our partnership agreement requires that we distribute all of our available cash to our unitholders. As a result, we expect to rely primarily upon external financing sources, including commercial bank borrowings and the issuance of debt and equity securities, to fund our acquisitions and expansion capital expenditures, if any.

 

 

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We intend to pay a minimum quarterly distribution of $         per unit per quarter, which equates to an aggregate distribution of approximately $         million per quarter, or approximately $         million per year, based on the number of common units, subordinated units and the general partner interest to be outstanding immediately after the completion of this offering. We do not have a legal or contractual obligation to pay distributions quarterly (or on any other basis) at our minimum quarterly distribution rate (or at any other rate). Please read “Cash Distribution Policy and Restrictions on Distributions.”

Revolving Credit Facility

Prior to or in connection with the completion of this offering, we intend to enter into a new $         million revolving credit facility. Our new revolving credit facility will be available to fund working capital and to finance acquisitions and other capital expenditures. Borrowings under our revolving credit facility are expected to bear interest at LIBOR plus an applicable spread. LIBOR and the applicable spread will be defined in the credit agreement that evidences our new revolving credit facility. We expect the unused portion of the revolving credit facility will be subject to a commitment fee.

We expect our revolving credit facility to contain covenants and conditions that, among other things, limit our ability to incur or guarantee additional debt, make cash distributions, incur certain liens or permit them to exist, make certain investments and acquisitions, enter into certain types of transactions with affiliates, merge or consolidate with another company, and transfer, sell or otherwise dispose of assets. We also expect to be subject to covenants that require us to maintain certain financial ratios.

Cash Flows

 

    

For the Years Ended
December 31,

        
    

  2014  

    

  2013  

    

  Change  

 
     (in millions)  

Net cash provided by operating activities

   $ 114       $ 94       $ 20   

Net cash used in investing activities

     (53      (68      15   

Net cash used in financing activities

     (61      (27      (34

Cash flows provided by operating activities increased $20 million for the year ended December 31, 2014 compared to the year ended December 31, 2013 primarily due to the following items:

 

    Net income increased $20 million in the period-to-period comparison;

 

    Other adjustments to reconcile net income to cash flow provided by operating activities increased due to $9 million of additional depreciation, depletion, and amortization for the year ended December 31, 2014;

 

    A net decrease of $8 million due to changes in operating assets, operating liabilities, other assets and other liabilities, which occurred throughout both periods; and

 

    The remaining change is due to various other transactions that occurred throughout both periods, none of which were individually material.

Net cash used in investing activities decreased $15 million for the year ended December 31, 2014 compared to the year ended December 31, 2013 primarily due to the following items:

 

    Capital expenditures decreased $14 million due to a $11 million decrease in various projects at the Enlow Fork mine and a decrease of $4 million in capitalized interest due to the completion of the Harvey mine in the first quarter 2014. This decrease was partially offset by various capital expenditures; and

 

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    Proceeds from sale of assets were consistent period-to-period from the sale-leaseback agreements for longwall shields at both the Bailey and Harvey mines.

Net cash used in financing activities increased $34 million for the year ended December 31, 2014 compared to the year ended December 31, 2013 primarily due to the following items:

 

    Net parent advances increased $35 million for the year ended December 31, 2014; and

 

    The remaining change is due to various other transactions that occurred throughout both periods, none of which were individually material.

Capital Expenditures

Our mining operations require investments to expand, upgrade or enhance existing operations and to comply with environmental regulations. Our capital requirements consist of maintenance capital expenditures and expansion capital expenditures. Maintenance capital expenditures are those capital expenditures required to maintain or replace, including over the long term, our operating capacity or capital asset base. Expansion capital expenditures are those capital expenditures made to increase our long-term operating capacity or capital asset base. Examples of maintenance capital expenditures include the replacement of equipment and coal reserves, whether through the expansion of an existing mine or the acquisition (by lease or otherwise) of new reserves, to the extent such expenditures are incurred to maintain or replace our operating capacity or capital asset base. Examples of expansion capital expenditures include the acquisition (by lease or otherwise) of reserves, equipment or a new mine or the expansion of an existing mine, to the extent such expenditures are incurred to increase our long-term operating capacity or capital asset base.

For the year ended December 31, 2014, the total capital expenditures of our Predecessor were $68 million compared to capital expenditures of $82 million for the year ended December 31, 2013. The 2014 capital expenditures included $6 million for the Bailey mine, $11 million for the Enlow Fork mine, $39 million for the Harvey mine, $8 million related to the preparation plant and $4 million related to land and other projects. The Bailey mine and Enlow Fork mine expenditures were for equipment and infrastructure. The Harvey mine expenditures were primarily for new mine development. The preparation plant projects were related to water treatment and refuse disposal areas. The 2013 capital expenditures included $11 million for the Bailey mine, $23 million for the Enlow Fork mine, $39 million for the Harvey mine, $4 million related to the preparation plant and $5 million related to land and other projects. The Bailey mine and Enlow Fork mine expenditures for 2013 were for equipment and infrastructure. The Harvey mine expenditures for 2013 primarily related to new mine development. The preparation plant projects were related to water treatment infrastructure and refuse disposal areas.

Off-Balance Sheet Arrangements

In the normal course of business, we are a party to certain off-balance sheet arrangements. These arrangements include guarantees and financial instruments with off-balance sheet risk, such as bank letters of credit and surety bonds. No liabilities related to these arrangements are reflected in our combined balance sheet, and we do not expect any material adverse effects on our financial condition, results of operations or cash flows to result from these off-balance sheet arrangements.

Critical Accounting Policies

Critical accounting policies are those that are important to our financial condition and require management’s most difficult, subjective or complex judgments. Different amounts would be reported under different operating conditions or under alternative assumptions. We have evaluated the accounting policies used in the preparation of the accompanying financial statements of our Predecessor and related notes thereto and believe those policies are reasonable and appropriate.

 

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We apply those accounting policies that we believe best reflect the underlying business and economic events, consistent with GAAP. Our more critical accounting policies include those related to the following items, but refer to Note 1 (Description of Business and Basis of Presentation) of the audited combined financial statements of our Predecessor included elsewhere in this prospectus for a complete listing of our accounting policies.

Other Post-Employment Benefits, Worker’s Compensation and Coal Workers’ Pneumoconiosis

Liabilities and expenses for other post-employment benefits (“OPEB”), worker’s compensation and coal workers’ pneumoconiosis (“CWP”) are determined using actuarial methodologies and incorporate significant assumptions, including the interest rate used to discount the future estimated liability, health care cost trend rates and mortality rates.

The interest rate used to discount future estimated liabilities is determined using a company-specific yield curve model (above median) developed with the assistance of an external actuary. The company-specific yield curve uses a subset of the expanded bond universe to determine the company-specific discount rate. Bonds used in the yield curves are rated AA by Moody’s or Standard & Poor’s as of the measurement date. The yield curve model parallels the plans’ projected cash flows.

The estimated liabilities recognized at December 31, 2014 and the benefit payments made for the year end December 31, 2014 were as follows (in thousands):

 

Plan

  

Estimated Liability as of
December 31, 2014

    

Benefit Payments for the year
ended December 31, 2014

 

OPEB

   $ 6,819       $ 1,530   

Workers’ Compensation

     3,303         1,038   

CWP

     1,274         68   

Asset Retirement Obligations

The Surface Mining Control and Reclamation Act established operational, reclamation and closure standards for all aspects of surface mining as well as most aspects of deep mining. We accrue for the costs of current mine disturbance and final mine and gas well closure, including the cost of treating mine water discharge where necessary. Estimates of our total reclamation, mine-closing and gas well closing liabilities, which are based upon permit requirements and our engineering expertise related to these requirements, including the current portion, were approximately $9 million at December 31, 2014. This liability is reviewed annually, or when events and circumstances indicate an adjustment is necessary, by management and engineers. The estimated liability can significantly change if actual costs vary from assumptions or if governmental regulations change significantly.

Accounting for asset retirement obligations requires that the fair value of an asset retirement obligation be recognized in the period in which it is incurred if a reasonable estimate of fair value can be made. The present value of the estimated asset retirement costs is capitalized as part of the carrying amount of the long-lived asset. Asset retirement obligations are primarily related to the closure of the mines and gas wells and the reclamation of land upon exhaustion of coal reserves. Changes in the variables used to calculate the liabilities can have a significant effect on the mine closing and reclamation liabilities.

Coal Reserve Values

There are numerous uncertainties inherent in estimating quantities and values of economically recoverable coal reserves, including many factors beyond our control. As a result, estimates of economically recoverable coal reserves are by their nature uncertain. Information about our reserves consists of estimates based

 

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on engineering, economic and geological data assembled and analyzed by our staff. Our coal reserves have been audited by an independent third party. Some of the factors and assumptions which impact economically recoverable reserve estimates include:

 

    geological conditions;

 

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

 

    the assumed effects of regulations and taxes by governmental agencies;

 

    assumptions governing future prices; and

 

    future operating costs.

Each of these factors may in fact vary considerably from the assumptions used in estimating reserves. For these reasons, estimates of the economically recoverable quantities of coal attributable to a particular group of properties, and classifications of these reserves based on risk of recovery and estimates of future net cash flows, may vary substantially. Actual production, revenues and expenditures with respect to our reserves will likely vary from estimates, and these variances may be material.

Contingencies and Significant Contractual Obligations

We are currently involved in certain legal proceedings. We have accrued our estimate of the probable costs for the resolution of these proceedings. This estimate has been developed in consultation with legal counsel involved in the defense of these matters and is based upon the nature of the lawsuit, progress of the case in court, view of legal counsel, prior experience in similar matters, and management’s intended response. Future results of operations for any particular quarter or annual period could be materially affected by changes in our assumptions or the outcome of these proceedings. Legal fees associated with defending these various lawsuits and claims are expensed when incurred. Please read Note 17 (Commitments and Contingent Liabilities) of the notes to the audited combined financial statements of our Predecessor included elsewhere in this prospectus for further discussion.

The following is a summary of our significant contractual obligations at December 31, 2014 (in thousands):

 

    

Payments due by Year

 
    

Less Than

1 Year

    

1-3 Years

    

3-5 Years

    

More Than

5 Years

    

Total

 

Purchase order firm commitments

   $ 2,464       $ —         $ —         $ —         $ 2,464   

Long-term note payable (a)

     18,231         75,005         29,483         56,621         179,340   

Interest on long-term note payable (a)

     2         —           —           —           2   

Capital (finance) lease obligations

     30         36         15         —           81   

Interest on capital (finance) lease obligations

     1         2         1         —           4   

Operating lease obligations

     9,271         17,975         10,259         3,576         41,081   

Long-term liabilities—employee related (b)

     2,608         4,969         4,712         5,147         17,436   

Other long-term liabilities (c)

     30,624         1,415         901         17,380         50,320   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total contractual obligations

$ 63,231    $ 99,402    $ 45,371    $ 82,724    $ 290,728   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

 

(a) Long-term debt of $178,762 and interest on long-term debt of $2 will not be assumed by CNX Coal Resources LP and are included in the pro forma adjustments. Please read our unaudited pro forma combined financial statements included elsewhere in this prospectus.

 

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(b) Long-term liabilities—employee related include liabilities for other post-employment benefits, work-related injuries and illnesses. Estimated salaried retirement contributions required to meet minimum funding standards under ERISA are excluded from the pay-out table due to the uncertainty regarding amounts to be contributed. We do not expect to contribute to the pension in 2015.
(c) Other long-term liabilities include mine reclamation and closure and other long-term liability costs.

Quantitative and Qualitative Disclosure about Market Risk

In addition to the risks inherent in operations, we are exposed to financial, market, political and economic risks. The following discussion provides additional detail regarding our exposure to the risks related to changes in commodity prices, interest rates and foreign exchange rates.

Commodity Price Risk

We are exposed to market price fluctuations in the normal course of selling coal. We sell coal under both short-term and multi-year contracts with fixed prices and/or indexed prices that reflect market value at the time we enter into those contracts. Our risk management policy prohibits the use of derivatives for speculative purposes. Please read “—Factors That Affect Our Results—Contract Position” and “Business—Our Customers and Contracts.”

Interest Rate Risk

In connection with the completion of this offering we expect to enter into a new revolving credit facility. Assuming our average debt level of $         million, comprised of funds drawn on our new revolving credit facility, an increase of one percentage point in the interest rate will result in an increase in annual interest expense of $         million. As a result, our results of operations, cash flows and financial condition and our ability to make cash distributions to our unitholders could be materially adversely affected by significant increases in interest rates.

Foreign Exchange Rate Risk

All of our transactions are denominated in U.S. dollars. As a result, we do not have material direct exposure to fluctuations in foreign currency exchange rates from the sale of our coal under sales contracts. However, because coal is sold internationally in U.S. dollars, general economic conditions in foreign markets and changes in foreign currency exchange rates may provide our foreign competitors 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 to our customers. 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. Consequently, currency fluctuations could adversely affect the competitiveness of our coal in international markets.

 

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INDUSTRY

Overview

Coal is an abundant and relatively inexpensive natural resource that is a primary source for the generation of electric power and an essential component for certain types of steel manufacturing. Coal is also the most abundant domestic fossil fuel, accounting for approximately 92% of U.S. fossil energy reserves on a Btu basis, according to the National Mining Association. According to the BP Statistical Review, worldwide proven coal reserves totaled approximately 892 billion metric tons at 2013 year end. The United States has the largest proven reserve base in the world with approximately 237 billion metric tons, or 26.6% of total world proven coal reserves. According to the BP Statistical Review, U.S. coal reserves represent over 250 years of domestic supply based on 2013 production rates.

Coal is a major contributor to the world’s energy supply. According to the BP Statistical Review, coal represented approximately 30% of the world’s primary energy consumption in 2013, its highest share since 1970. Global coal consumption grew 3% from 2012 to 2013, making coal the world’s fastest growing fossil fuel, according to the BP Statistical Review. According to Wood Mackenzie, coal’s use in global electricity generation is forecasted to rise 75% from 2014 to 2035. The chart below demonstrates the increasing importance of coal for global energy consumption over time according to the BP Statistical Review:

World Energy Consumption by Fuel Type

(million metric tons of oil equivalents)

 

LOGO

Source: BP Statistical Review June 2014

Coal quality is largely driven by heat content, with anthracite, bituminous, sub-bituminous and lignite coal representing the highest to lowest heat ranking, respectively, and is also categorized as either thermal coal or metallurgical coal. Thermal coal, which is sometimes referred to as “steam” coal, is used by electric utilities and independent power producers to generate electricity, and metallurgical coal is used by steel companies to produce metallurgical coke for use in the steel making process. In 2013, thermal coal accounted for 928 million tons or approximately 92% of total U.S. coal demand, and 7,101 million metric tons or approximately 86% of total global coal demand, according to Wood Mackenzie. Metallurgical coal accounted for approximately 85 million tons or approximately 8% of total U.S. coal demand, and 1,117 metric million metric tons or approximately 14% of total global coal demand, according to Wood Mackenzie.

 

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Thermal coal consumption patterns are influenced by the demand for electricity, power generation infrastructure, transportation costs, governmental and environmental regulations, technological developments and the location, availability and cost of other sources of energy such as heating oil, natural gas, nuclear power, hydroelectric power and renewable sources of electricity generation, such as solar and wind. Demand for metallurgical coal is influenced primarily by the worldwide demand for steel. Thermal coal produced in the Northern Appalachian basin, where the Pennsylvania mining complex is located, is marketed primarily to electric utilities in the eastern United States, which prefer to source coal with higher heat content at the lowest all-in cost.

Coal Mining Methods

Coal is mined using two primary methods, underground mining and surface mining.

Underground Mining

Underground mines in the United States are typically operated using one of two different methods: longwall mining and continuous mining (or room and pillar mining).

Longwall mining is a highly automated underground mining technique that produces large volumes of coal at lower costs compared to other underground mining methods. A longwall mining system uses a shearer to cut across a panel of coal about 1,500 feet in width and up to 15,000 feet in length, self-advancing roof supports to protect the miners working at the longwall face and an armored face conveyor to transport the coal. The longwall mining system is highly productive due to the continuous nature of the coal production and the large volume of coal produced relative to the number of miners required to operate the longwall mining system. A longwall mining system is supported by one or more continuous mining units. While the continuous mining units contribute to coal production, their primary function is to prepare an area of the mine for longwall operations. Longwall mining accounts for approximately 55% of underground coal production, according to the EIA Annual Coal Report 2013.

The other underground mining technique commonly used in the United States is the continuous mining method. In continuous mining, rooms are cut into the coal bed leaving a series of pillars, or columns of coal, to help support the mine roof and control the flow of air. Continuous mining equipment is used to cut the coal from the mining face, and shuttle cars are generally used to transport coal to a conveyor belt for subsequent delivery to the surface. Once mining has advanced to the end of a panel, retreat mining may begin to mine as much coal as can be safely and feasibly be mined from each of the pillars created. Continuous mining accounts for approximately 43% of underground coal production, according to the EIA Annual Coal Report 2013.

Underground mining accounts for approximately 35% of U.S. production, according to the EIA Annual Coal Report 2013.

Surface mining

Surface mining, including strip mining and mountaintop removal mining, is generally used when coal is found relatively close to the surface, when multiple seams in close vertical proximity are being mined or when conditions otherwise warrant. Surface mining involves removing the overburden with heavy earth moving equipment and explosives, loading out the coal, replacing the overburden and topsoil after the coal has been excavated and reestablishing vegetation and plant life. Surface mining methods include area, contour, auger and highwall mining.

Surface mining produces the majority of U.S. coal output, accounting for approximately 65% of U.S. production, according to the EIA Annual Coal Report 2013. We do not engage in any surface mining.

 

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Coal Quality Characteristics

Coal quality is differentiated primarily by its heat content as measured in British thermal units per pound (Btu/lb). In general, coal with low moisture and ash content has high heat content. Coal with higher heat content generally commands higher prices because less coal is needed to generate a given quantity of electric power.

Coal quality is also differentiated by sulfur content. When coal is burned, sulfur dioxide and other air emissions are released. Sub-bituminous coal typically has lower sulfur content than bituminous coal. Sulfur concentration has major influences on the use of coal to generate electricity. Sulfur concentration affects the type and capacity of pollution control equipment required (thus, capital cost, and even the ability of a given boiler to fire a given coal); operating costs (such as the amount of lime or limestone required in a flue gas desulfurization (“FGD”) system and the amount of FGD waste that must be disposed of); slagging tendency (related to the iron disulfide content, which is generally desirable for wet-bottom boilers and undesirable for dry-bottom boilers); and the number of emission allowances or credits (for example, Cross-State Air Pollution Rule allowances) that must be used. Thus, sulfur content can determine the absolute acceptability of a specific coal to be used in a given boiler and will usually have some impact on the operating cost of using a coal. As a general rule, lower sulfur content is desirable.

Plants that will burn mid- and high-sulfur coals going forward generally have installed or are in the process of installing flue gas desulfurization scrubbers, which can reduce sulfur dioxide emissions by more than 90%, in order to comply with environmental regulations such as MATS and CSAPR. Plants that will burn lower-sulfur coals, such as sub-bituminous coal from the Powder River Basin, may elect to use dry sorbent injection (“DSI”) instead of a scrubber to control sulfur dioxide emissions. DSI systems have lower capital costs than scrubbers but achieve lower sulfur dioxide removal efficiencies and use higher-cost re-agents than most scrubbers.

Coal ash and chlorine content also can influence the marketability of a particular coal. Ash is the inorganic residue remaining after the combustion of coal. As with sulfur content, ash content varies from seam to seam. Ash content is also an important characteristic of coal because electric generating plants must handle and dispose of ash following combustion. The chlorine content of coal is important to generating station operators since high levels can adversely impact boiler performance by causing fireside corrosion, boiler tube wastage and fouling (stemming from the alkali metals associated with the chlorine), and it can potentially require increased water use and wastewater disposal costs in units equipped with wet flue gas desulfurization scrubbers. For the most part, in the United States, coals with potentially problematic chlorine contents (greater than approximately 0.2%) are limited to the Illinois Basin.

Coal-fired power plants in the United States are also required to reduce their air emissions of hydrogen chloride, formed from the chlorine in coal, and of mercury under the MATS, which are scheduled to take effect in April 2015. Hydrogen chloride emissions are effectively controlled using either a FGD scrubber or DSI. A moderate concentration of chlorine actually promotes mercury emissions control in power plants; the chlorine content of many Northern Appalachian coals (including coal produced from the Pennsylvania mining complex) is sufficiently high to be beneficial in this regard.

More specific to metallurgical coal, volatile matter, which refers to the components of coal that are driven off when heated to approximately 1,742 degrees Fahrenheit in the absence of air, is another important characteristic. Volatile matter contains the compounds that are used to produce certain by-products and generally needs to be within a certain percentage range in order to be better suited for coking purposes.

Transportation

The U.S. coal industry is dependent on a consistent and reliable transportation network connecting the various supply regions to the domestic and international markets. Railroads and barges comprise the foundation of the domestic coal distribution system, collectively handling approximately 75% of all coal shipments, according to Wood Mackenzie. Truck and conveyor systems typically move coal over shorter distances.

 

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Transportation is a significant component of the total cost of coal at a customer’s point of usage. The cost to transport coal from the mine to the customer can be large relative to the value of the coal as an energy source. Coal produced in the United States for domestic consumption is generally sold FOB by the coal producer at the mine or terminal, and the purchaser normally bears the transportation costs from the FOB point. Seaborne coal, however, is generally sold FOB at the loading port by the coal producer or marketer. Based upon individual coal customer needs, a coal producer or marketer may agree to provide transportation and transportation services for the delivery of the coal to the customer in exchange for a higher price.

While coal can sometimes be moved by one transportation method to market, it is common for two or more modes to be used to ship coal (i.e., inter-modal movements). The method of transportation and the delivery distance greatly impact the total cost of coal delivered to the consumer.

In the 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, which is the location of CONSOL’s Baltimore Marine Terminal. To receive these exports, countries importing coal in both the Atlantic and Pacific seaborne markets have an established import terminal infrastructure.

Coal Consumption and Demand

According to Wood Mackenzie, world coal consumption in 2013 was estimated at 8.2 billion metric tons, of which approximately 1.3 billion metric tons were sold internationally, primarily in the seaborne coal market.

United States Coal Market

Thermal coal is used to generate electricity and supports industrial uses. In 2013, it accounted for approximately 92% of coal consumed in the United States, according to Wood Mackenzie. Metallurgical coal is predominantly consumed in the production of metallurgical coke used in steelmaking blast furnaces. According to the EIA, power generation from coal-fired units accounted for 40.1% of all power generated in the United States in 2013 compared to 27.5% from natural gas and 18.6% 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 conditions, which reduced demand for electricity generation, as well as from increasing natural gas switching and regulatory and environmental pressures, total domestic thermal coal consumption decreased to approximately 870 million tons in 2012, according to the EIA. From 2012 to 2015, total domestic thermal coal consumption is expected to increase approximately 70 million tons primarily from an increasing demand from utilities, according to the EIA. Despite the retirement of coal-fired generation capacity and increased share of natural gas and other fuel sources in electric generation, the EIA forecasts that the U.S. coal industry will retain its position as the predominant supplier of fuel to the domestic utility industry through 2030. According to the EIA’s Annual Energy Outlook 2014, domestic thermal coal consumption is expected to increase to approximately 970 million tons by 2025 and coal’s share of domestic power generation is projected to average 38% throughout the forecast period.

 

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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:

U.S. Coal Consumption (tons in millions)

 

    

2011A

    

2012A

    

2013A

    

2014E

    

2015E

    

2020E

    

2025E

 

Electric Power

     932         825         874         896         893         892         919   

Industrial

     46         43         45         46         47         49         49   

Steel Production

     21         21         21         21         22         22         22   

Commercial/Institutional

     3         2         2         2         2         2         2   

Coal-to-Liquids

     0         0         0         0         0         0         0   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total U.S. Coal Consumption

  1,002      891      942      965      964      965      992   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Source: EIA Annual Energy Outlook 2014

U.S. Scrubber Market

Utilities in the United States are increasingly purchasing coal on a heat content basis (measured in dollars per million Btus) and less on a sulfur content basis as sulfur mitigation systems, or scrubbers, are installed by utilities to comply with increasingly stringent emissions requirements required of the Clean Air Act and other state and federal air regulations. The Northern Appalachian basin is characterized by high-Btu coal. Coal produced in the Northern Appalachian basin competes favorably against other coal basins due to its low delivered cost, high heat content, and access to a vast network of transportation outlets for broad consumption across the eastern United States. The CAA Amendments restricted emissions of sulfur dioxide by electric utilities, which caused most utilities to comply with the new regulations by using lower sulfur coal or by purchasing sulfur emission credits. However, as the emission regulations have continued to evolve to include the CSAPR (in effect January 2015), MATS (expected to take effect in April 2015) and other recent EPA and state regulations, these compliance strategies have become less effective and, as a result, most utilities in our core market have elected to install scrubbers at their coal-fired baseload electric generating facilities to meet air emission requirements.

 

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While coal-fired baseload electric generating facilities that have elected to install scrubbers are able to utilize higher-sulfur coal, there is a preference for lower sulfur content due to additional cost to remove the sulfur. Coal produced at the Pennsylvania mining complex has lower sulfur relative to coal produced at many competing mines in the Northern Appalachian Basin and the Illinois Basin.

 

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Source: Ventyx Enterprise Software, The Velocity Suite

Seaborne Thermal Coal Market

The seaborne coal markets for thermal coal, which consists of coal shipped between countries via ocean going vessels, excluding shipments between Canada and the United States via the Great Lakes, 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. The Atlantic market’s largest consuming countries for seaborne thermal coal are the United Kingdom, Germany, Italy, Turkey, Spain and France. The Pacific market largely consists of countries in Asia and Oceania, including Australia. The Pacific market’s largest consuming countries for imported seaborne thermal coal are China, Japan, Korea, Taiwan and India. According to Wood Mackenzie, coal consumption in the seaborne thermal coal market increased from approximately 615 million metric tons in 2008 to 936 million metric tons in 2014, a compounded annual growth rate of 7.3%. Countries outside of the developed economies of Europe and Japan 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 88% in 2035, according to Wood Mackenzie.

Seaborne Metallurgical Coal Market

The seaborne metallurgical coal market consists of two markets, the Atlantic and Pacific. As with the seaborne thermal coal market, the metallurgical coal market consists of coal shipped on ocean going vessels between countries and excludes shipments between Canada and the United States through the Great Lakes. The Atlantic market largely consists of countries in Europe, the Mediterranean region, North America, and South America. The Atlantic market’s largest consuming countries for seaborne metallurgical coal are Brazil, Italy,

 

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Ukraine, Turkey, Belgium, Germany, the United Kingdom and France. The Pacific market largely consists of countries in Asia and Oceania. The Pacific market’s largest consuming countries for imported seaborne metallurgical coal are Japan, India, South Korea, Taiwan and China. According to Wood Mackenzie, coal consumption in the seaborne metallurgical coal market increased from approximately 216 million metric tons in 2008 to 286 million metric tons in 2014, a compounded annual growth rate of 4.8%. Countries outside of the developed economies of Europe and Japan imported 79% of the world’s seaborne export metallurgical coal in 2014 and their share of the total seaborne metallurgical coal market is projected to increase to 82% in 2035, according to Wood Mackenzie.

Historical coal export volumes from the United States have fluctuated over the last decade ranging between 48 million tons in 2004 and 97 million tons in 2014, according to the EIA. Of the 97 million tons of coal exported in 2014, 34 million tons was thermal coal with the balance being metallurgical coal. As shown in the table below, between 2004 and 2014 export thermal and metallurgical coal from the United States both increased 103% over the same time period.

United States Coal Exports (tons in millions)