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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.

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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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		Page
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 25^th 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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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:

 

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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;

 

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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;

 

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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;

 

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

 

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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;

 

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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;

 

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

 

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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;

 

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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;

 

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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;

 

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

 

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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;

 

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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;

 

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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:

 

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

 

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whether to exercise its limited call right;

 

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

 

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whether to exercise its registration rights;

 

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

 

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whether to elect to reset target distribution levels;

 

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

 

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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:

 

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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;

 

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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;

 

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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

 

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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 ²⁄₃% 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:

 

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

 

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

 

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

 

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the ratio of taxable income to distributions may increase;

 

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

 

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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:

 

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

 

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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)

 

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.

 

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)

 

Product Type		2004				2005				2006				2007				2008				2009				2010				2011				2012				2013				2014
Thermal Coal			21				21				22				27				39				22				26				38				56				52				34
Metallurgical Coal			27				29				27				32				43				37				56				70				70				66				63
Total U.S. Coal Exports			48				50				49				59				82				59				82				108				126				118				97

Source: EIA

 

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Coal Industry Trends

Several short-term and long-term factors presently impact coal consumption and production both in the United States and in the seaborne market. These market dynamics include the following:

United States

 

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Coal continues to be a low-cost and abundant resource. The power generation infrastructure in the United States is largely coal-fired. According to the EIA, coal had an average market share of electrical generation in the United States of 48% from 2000 to 2013, principally because it is a relatively low-cost, reliable and abundant fuel source. While lower levels of electrical demand, low natural gas prices, together with other cost factors such as fuel transportation and emission control costs displaced some coal-fired generation in 2012, the trend began to reverse in 2013 as a result of rising gas prices and a lower number of coal supply sources. In its February Short Term Energy Outlook for 2015, the EIA projected the average cost of coal delivered to electric generating plants to be $2.31 on a dollars per MMBtu basis versus $3.98 per MMBtu for natural gas, making the estimated price of natural gas substantially more than the price of coal for 2015. According to the EIA, the 2011 to 2015 average fuel prices per million Btu to electricity generators, using coal and competing fossil fuel power generation alternatives, are as follows:

Average Cost of United States Electricity Generation by Fossil Fuel (dollars per million Btu)

 

Electric Generation Type		2011A				2012A				2013A				2014A				2015E
Distillate Fuel Oil		$	22.43			$	23.51			$	23.08			$	22.33			$	15.74
Residual Fuel Oil		$	18.30			$	21.05			$	19.33			$	19.26			$	11.67
Natural Gas		$	4.73			$	3.42			$	4.33			$	4.98			$	3.98
Coal		$	2.39			$	2.38			$	2.35			$	2.36			$	2.31

Source: EIA

Coal (NAPP Benchmark) vs Natural Gas (Henry Hub) Prices (dollars per million Btu)

 

Source: Bloomberg L.P., as of December 31, 2014

 

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Note: CoalPenn Index = Pennsylvania FOB Railcar, Pittsburgh coal seam, 12,500-13,000 Btu, 2%-3% sulfur and 7%-9% ash content. Converted to MMBtu using 13,000 Btu, which is the average gross heat content of the CONSOL Energy Pennsylvania mining complex coal.

 

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Favorable long-term outlook for U.S. coal market. 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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Stable demand for coal produced in the Northern Appalachian Basin. According to Wood Mackenzie, thermal coal production in the Northern Appalachian Basin is expected to stay relatively constant, with 116 million tons per year expected to be produced by 2035. Wood Mackenzie believes, in the near-term, this stable production forecast will be driven by a combination of the continued decline in coal production in the Central Appalachian Basin, the proximity to demand centers and high-Btu content of coal reserves. Also, coal produced in the Northern Appalachian Basin is a cost competitive fuel resource on a delivered cost, heat content and sulfur content adjusted basis to a large percentage of baseload coal fired power plants in the eastern United States. Long-term, Wood Mackenzie anticipates that an increasingly greater amount of Northern Appalachian thermal coal will be demanded by the international markets as a low-cost high-Btu source of coal supply.

 

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Decline in coal production in the Central Appalachian Basin. Coal production in the Central Appalachian Basin, which has historically been the second largest coal basin in the United States (based on production), has been declining. Increased environmental scrutiny and permitting constraints have significantly increased costs and lowered production from mountain-top mining, a mining method prevalent in Central Appalachia. We believe that this has led to a significant increase in cash costs of produced thermal coal in Central Appalachia and will continue to put cost pressures on producers, disadvantaging Central Appalachia coal on a delivered cost basis relative to other basins. Wood Mackenzie projects that thermal coal production in Central Appalachia will decline 52% from an estimated 66 million tons in 2014 to 32 million tons by 2035. In addition, over the last several years, certain producers in Central Appalachia have shifted production from thermal coal to higher priced metallurgical coal, further decreasing coal available for sale to domestic utilities. We expect declining Central Appalachia production to be offset by production from other U.S. coal basins.

 

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Reduced focus by utility coal buyers on sulfur content. Since 1990, the Clean Air Act’s restrictions on utility sulfur emissions made sulfur content an important part of a coal buyer’s selection of coal. However, the increased adoption of scrubbers by utilities has partially reduced the importance of sulfur content in a coal buyer’s decision making process for environmental purposes, as most scrubbers can remove over 90% of sulfur-related gases prior to emission and achieve compliance with applicable environmental regulations even for higher-sulfur coals. However, there is still a preference for coal with 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 throughout much of the rest of the Northern Appalachian Basin and the Illinois Basin. Other key determinants include heat content (a measurement of how much energy could be created by burning the coal), delivered price (a function of transportation distance, modality and rates) and other secondary coal characteristics.

Aside from sulfur content, chlorine is an important characteristic for coal utility buyers. A higher level of chlorine 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

 

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flue gas desulfurization scrubbers. In general, the Illinois Basin has chlorine content ranging from 0.06% to 0.50% compared to the Northern Appalachian Basin ranging from 0.10% to 0.17%. The moderate chlorine concentrations found in most Northern Appalachian coals, including coal from the Pennsylvania mining complex, are not generally considered to be problematic, and they can actually provide a benefit by helping to promote mercury emissions control.

 

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Increasingly stringent air quality legislation will continue to impact the demand for coal. A series of more stringent environmental requirements related to particulate matter, ozone, mercury, sulfur dioxide, nitrogen oxides, carbon dioxide and other air emissions have been proposed or enacted by federal or state regulatory authorities in recent years including the MATS regulation, which is expected to take effect in April 2015. In addition, environmental regulators are currently considering implementing new proposed changes to greenhouse gas emission limits. We believe that additional air quality regulations may ultimately be adopted and may adversely impact future coal demand.

Seaborne Market

 

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Growth in seaborne thermal coal demand. Wood Mackenzie projects consumption of seaborne thermal coal to increase from 936 million metric tons in 2014 to approximately 1.9 billion metric tons by 2035, a compounded annual growth rate of 3.3%. Growth in international coal import demand has resulted primarily from increased demand for thermal coal for electricity generation by emerging global economies, particularly by countries in the Pacific market where coal is the primary fuel source for new power generation. According to Wood Mackenzie, seaborne imports to China are expected to grow from 198 million metric tons in 2014 to 592 million metric tons in 2035, a compounded annual growth rate of 5.4%. In 2014, China’s imports accounted for 21% of total seaborne demand. Between 2014 and 2035, India’s seaborne thermal coal imports are estimated to rise from 142 million metric tons in 2014 to 462 million metric tons in 2035, a compounded annual growth rate of 5.8%. India’s share of the seaborne thermal coal market is estimated to increase from 15% in 2014 to 25% in 2035.

 

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Increased demand in seaborne metallurgical coal. Wood Mackenzie expects consumption of seaborne metallurgical coal to increase from 286 million metric tons in 2014 to approximately 409 million metric tons in 2035, a compounded annual growth rate of 1.7%. According to Wood Mackenzie, seaborne imports to China are expected to grow from 59 million metric tons in 2014 to 93 million metric tons in 2035, a compounded annual growth rate of 2.2%. Between 2014 and 2035, India’s seaborne metallurgical coal imports are estimated to rise from 42 million metric tons in 2014 to 93 million metric tons in 2035, a compounded annual growth rate of 3.9%. India’s share of the seaborne metallurgical coal market is estimated to increase from 15% in 2014 to 23% in 2035. Metallurgical coal is expected to be in demand in the long-term as emerging economies experience industrialization and urbanization, specifically China and India.

 

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Intermittent supply constraints from traditional thermal and metallurgical coal exporting countries. At times historically, some traditional export supply countries have faced supply constraints limiting their ability to keep up with the pace of seaborne coal demand. Many of these countries have experienced adverse impacts to their export supply capabilities as a result of labor shortages, limited port capacity, rail transportation capacity, reliability, distance, power generation shortages limiting coal processing, increased domestic consumption, unexpected weather impacts, new regulatory and environmental measures, political instability and declining coal qualities. In addition, rising operating cost pressures and increased capital intensity have combined with the near-term decline in thermal and metallurgical coal export prices to force shutdowns of some existing production and delays in new projects coming online. Some producers have decreased output, lowered costs and agreed to sell at lower prices to maintain market share. While some of

 

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these constraints have eased in recent years, we believe that many significant coal importing countries in the Pacific market will continue their attempt to diversify their supply sources to guarantee security of supply by importing coal from producers who had traditionally primarily serviced the Atlantic market, including the United States.

Coal Production and Supply

China is the world’s largest producer of coal with approximately 47% of the world’s coal production, according to the BP Statistical Review. In 2013, China was followed by the United States (approximately 13%), Australia (approximately 7%), Indonesia (approximately 7%), India (approximately 6%), Russia (approximately 4%) and South Africa (approximately 4%).

United States Coal Production

According to the BP Statistical Review, the United States is the largest holder of coal reserves in the world, with over 250 years of supply at current production rates. U.S. coal production was approximately 980 million tons in 2013 according to the EIA. Although total annual domestic coal production has been relatively stable at approximately 1.0 billion tons since 1990, the basins contributing to the industry have experienced significant changes. Wood Mackenzie forecasts that thermal coal production in the United States will increase 19% from 2013 to 2035, and will primarily support scrubbed domestic coal-fired generating units together with increasing demand from the seaborne markets. The following table sets forth historical and forecasted production statistics in each of the major U.S. coal producing regions for the periods indicated based on Wood Mackenzie data:

United States Forecasted Coal Production by Region

 

		2014A				2015E				2016E				2020E				2025E				2035E				2014-2035 Forecasted CAGR
		(tons in millions)
Power River Basin			418				417				414				457				493				518				1.0	%
Central Appalachia Thermal			66				63				46				24				21				32				(3.4	%)
Northern Appalachia Thermal			120				103				98				107				103				116				(0.1	%)
Illinois Basin			137				129				131				139				131				228				2.5	%
Metallurgical			79				77				75				79				77				74				(0.3	%)
Other			180				196				181				164				180				196				0.4	%
Total U.S. Coal Production			1,000				985				945				970				1,005				1,164				0.7	%

Source: Wood Mackenzie

Coal Producing Regions

Coal is mined in over half of the states in the United States, but domestic coal production is primarily attributed to three coal producing regions: the Appalachian region, the Interior region and the Western region. Within those three regions, the major producing centers are the Northern Appalachian Basin and the Central Appalachian Basin, the Powder River Basin in the Western region and the Illinois Basin in the Interior region. The type, quality and characteristics of coal vary within each region.

Northern Appalachian Basin

The Northern Appalachian Basin includes Ohio, Pennsylvania, Maryland and northern West Virginia. The area includes reserves of bituminous coal with heat content generally ranging from 11,100 to 13,900 Btu/lb and sulfur content typically ranging from 1.0% to 5.0%. Thermal coal produced in Northern Appalachia is

 

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marketed primarily to electric utilities, industrial customers and the export market while metallurgical coal production is marketed to domestic and international steelmakers. According to Wood Mackenzie, estimated thermal coal production in Northern Appalachia for 2014 was 120 million tons, an increase of 11.0% from 2013, and is expected to remain stable, with an estimated 116 million tons per year produced by 2035.

Central Appalachian Basin

The Central Appalachian Basin includes eastern Kentucky, southern West Virginia, Virginia and northern Tennessee. The area includes reserves of bituminous coal with a heat content typically ranging from 11,500 to 14,200 Btu/lb and sulfur content typically ranging from 0.5% to 4.0%. Thermal coal produced in Central Appalachia is marketed primarily to electric utilities, industrial customers and the export market, while metallurgical coal production is marketed to domestic and international steelmakers. Compared to the Northern Appalachian basin, the Central Appalachian basin has comparatively higher reserve depletion, increased regulatory standards, higher mining costs and increased geologic complexity. According to Wood Mackenzie, estimated thermal coal production in Central Appalachia for 2014 was 66 million tons, a decrease of 12.7% from 2013, and is expected to decline to 32 million tons in 2035.

Illinois Basin

The Illinois Basin includes western Kentucky, Illinois and Indiana. The area includes reserves of bituminous coal with a heat content typically ranging from 9,700 to 12,800 Btu/lb and sulfur content ranging from 1.0% to 6.0%. Most of the coal produced in the Illinois Basin is used to produce electricity, with small amounts used in industrial applications. Compared to the Northern Appalachian basin, the Illinois Basin has a lower heat content, higher chlorine content and higher transportation cost. According to Wood Mackenzie, estimated coal production in the Illinois Basin was 137 million tons in 2014, an increase of 4.0% from 2013, and is expected to increase to 228 million tons in 2035.

Powder River Basin

The Powder River Basin, or PRB, is located in Wyoming and Montana. The PRB produces sub-bituminous coal with sulfur content typically ranging from 0.2% to 0.8% and heat content typically ranging from 7,800 to 9,700 Btu/lb. After strong growth in production over the past 20 years, growth in domestic demand for PRB coal is expected to moderate in the future due to the slowing demand for low Btu coal as scrubbers proliferate, rail transportation rates increase and operating costs grow as a result of higher strip ratios, but is expected to be offset by increasing demand in Asia. According to Wood Mackenzie, estimated coal production in the PRB was 418 million tons for 2014, an increase of 2.5% from 2013, and is expected to grow to 518 million tons in 2035.

 

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BUSINESS

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. Since 2006, CONSOL Energy has invested over $2.0 billion at the Pennsylvania mining complex to develop technologically advanced, large-scale longwall mining operations that enable us to efficiently mine large volumes of coal with low operating costs, high reliability and strong safety and environmental compliance. 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. Many of our customers’ power plants are optimized to burn coal with our particular heat and sulfur characteristics, which we believe further enhances our position as a leading supplier of coal to power plants in the eastern United States. 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. All of our mines utilize longwall mining, which is a highly automated underground mining technique that produces large volumes of coal at lower costs compared to other underground mining methods. 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 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. Our ability to accommodate multiple unit trains allows for the seamless transition of locomotives from empty inbound trains to fully loaded outbound trains at our facility. 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 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

 

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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. 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. These advantages, combined with our ability to maintain low operating costs, allow us to generate favorable margins in relation to our peers. For example, 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 for coal master limited partnerships.

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.

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.

 

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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 “—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 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.

 

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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” 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:

 

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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. 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 longwall operations. 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). We believe that our access to a broader range of coal-fired power plants will enable us to focus our marketing efforts to achieve maximum netback prices for our coal, which will facilitate us maximizing our margins and better position us to maintain profitability throughout commodity price cycles. 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.

 

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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. Our customers primarily purchase coal based on the delivered cost adjusted for heat content and sulfur content. As a result, transportation costs are a significant factor in determining our customers’ fully realized cost. 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 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. In addition, we believe that our advantageous access to international markets through CONSOL Energy’s Baltimore Marine Terminal provides us with valuable options for delivering our coal and optimizing our sales portfolio.

 

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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, including (i) completion of a new longwall mining system at the Harvey mine, (ii) completion of a new slope and overland conveyor system at the Bailey mine, (iii) construction of two raw coal storage silos and one clean coal storage silo, (iv) construction of a new dual-batch train loadout facility capable of loading up to 9,000 tons of coal per hour, (v) expansion of our cleaning plant capacity, (vi) construction of a new overland belt conveyor system at the Enlow Fork mine that eliminated seven miles of underground conveyors, (vii) sealing off 28.3 square miles of underground workings and eliminating 11 airshafts at the Enlow Fork mine and (viii) construction of a new underground training academy at the Harvey mine. This recent capital investment program represents approximately two-thirds of CONSOL Energy’s total capital investment of over $3.0 billion at the Pennsylvania mining complex since its initial development in 1982. 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.

 

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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.

 

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Our relationship with our sponsor, CONSOL Energy. CONSOL Energy and its predecessors have been mining coal, primarily in the Appalachian Basin, since 1864. 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.

 

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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 (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:

 

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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 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.

 

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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.

 

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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

 

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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. The Pennsylvania mining complex’s favorable location in our core market and access to dual rail transportation options contributes to reducing the delivered cost of our coal, which allows us to secure higher netback prices and maintain favorable margins. Through our recent capital investment program, we have further optimized our mining operations and logistics infrastructure to drive down our cash operating costs. We believe that these factors will contribute to us maintaining higher margins per ton than our competitors and better position us to maintain profitability throughout commodity price cycles. Furthermore, we believe that we will be able to sustain high margins in varied commodity price environments through our significant portfolio of multi-year, committed and priced contracts with our longstanding domestic customer base.

 

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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 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 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.

 

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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. 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. 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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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. Through our relationship with CONSOL Energy, we expect that we will have access to its significant pool of management talent and industry relationships, which we believe will provide us a competitive advantage in pursuing potential third-party acquisition opportunities. We may have the opportunity to work jointly with CONSOL Energy to pursue certain acquisitions of coal properties that may not otherwise be attractive acquisition candidates for either of us individually.

 

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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. The potential future production capacity of the Pennsylvania mining complex consistently running six longwall mining systems would be 33 million tons per year (with our current recoverable reserves sufficient to support over 23 years of production) compared to its current production capacity of 28.5 million tons per year running five longwall mining systems under normal operations (with our current recoverable reserves sufficient to support over 27 years of production). We have already made significant investment in large scale infrastructure, and we believe that we will be able to capitalize on this infrastructure to grow on a materially more cost-effective basis than investing in greenfield development, which should enable us to generate a higher return on additional invested capital.

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 NYSE under the symbol “CNX” and had a market capitalization of approximately $6.4 billion as of March 31, 2015.

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 “Prospectus Summary—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.”

In addition, CONSOL Energy has experience successfully forming and sponsoring a master limited partnership. In 2014, CONSOL Energy, along with its joint venture partner, sponsored the $442.8 million initial public offering of CONE Midstream Partners LP, a master limited partnership that owns and operates natural gas gathering and other midstream energy assets in the Marcellus Shale in Pennsylvania and West Virginia.

 

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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 Operations

Our operations and related reserves are located primarily in Greene County and Washington County in southwestern Pennsylvania, with limited operations and related reserves located in northeastern West Virginia. 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%. Each of the three mines comprising the Pennsylvania mining complex mines coal from the Pittsburgh No. 8 Coal Seam with recoverable reserves that are sufficient to support over 27 years of mining based on our current production capacity.

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 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 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.

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 the coal, 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 whose primary function is to prepare an area of the mine for longwall operations.

The Pennsylvania mining complex has a large-scale, modernized preparation plant that washes and processes up to 8,200 tons of coal per hour, nine raw coal silos with an aggregate storage capacity of 153,000 tons, six clean coal silos with an aggregate storage capacity of 132,500 tons and a new dual-batch train loadout facility capable of loading up to 9,000 tons of coal per hour. We are also currently expanding our life of mine refuse capability, including slurry impoundments, located onsite at the Pennsylvania mining complex by developing a new refuse area that is expected to commence construction in 2016. Depending on customer requirements, blending coal with different qualities may be required from time to time to meet their specifications.

 

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The following map shows the locations of our operations:

 

Bailey Mine

The Bailey mine is the first mine that CONSOL Energy developed at the Pennsylvania mining complex. As of December 31, 2014, the Bailey mine’s assigned and accessible reserve base contained an aggregate of 254.5 million tons (50.9 million tons net to our 20% interest on a pro forma basis) of clean recoverable proven and probable coal with an average gross heat content of approximately 12,900 Btus per pound and an average sulfur content of 2.68%. While operating two longwalls, the production capacity of the Bailey mine is 11.5 million tons of coal per year.

Construction of the slope and initial air shaft began in 1982. The slope development reached the coal seam at a depth of approximately 600 feet and, following development of the slope bottom, commercial coal production began in 1984. Longwall mining production commenced in 1985, and the second longwall was placed into operation in 1987. In 2010, a new slope and overland belt system was commissioned, which allowed a large percentage of the Bailey mine to be sealed off. For the years ended December 31, 2013 and 2014, the Bailey mine produced 10.8 million tons (2.2 million tons net to our 20% interest on a pro forma basis) and 12.3 million tons (2.5 million tons net to our 20% interest on a pro forma basis) of coal, respectively.

The Bailey mine uses seven continuous mining units to develop the mains and gate roads for its longwall panels. The longwalls have a panel width (or face length) of approximately 1,500 feet, a panel length of approximately 12,000 feet and a seam height of approximately 7.6 feet.

 

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Enlow Fork Mine

The Enlow Fork mine is located directly north of the Bailey mine. As of December 31, 2014, the Enlow Fork mine’s assigned and accessible reserve base contained an aggregate of 322.8 million tons (64.6 million tons net to our 20% interest on a pro forma basis) of clean recoverable proven and probable coal with an average gross heat content of approximately 13,000 Btus per pound and an average sulfur content of 2.21%. While operating two longwalls, the production capacity of the Enlow Fork mine is 11.5 million tons of coal per year.

Initial underground development was started from the Bailey mine while the Enlow Fork slope was being constructed. Once the slope bottom was developed and the slope belt became operational, seals were constructed to separate the two mines. Following development of the slope bottom, commercial coal production began in 1989. Longwall mining production commenced in 1991 with the second longwall coming online in 1992. In 2014, a new slope and overland belt system was commissioned and a substantial portion of the Enlow Fork mine was sealed. For the years ended December 31, 2013 and 2014, the Enlow Fork mine produced 10.1 million tons (2.0 million tons net to our 20% interest on a pro forma basis) and 10.6 million tons (2.1 million tons net to our 20% interest on a pro forma basis) of coal, respectively.

The Enlow Fork mine uses seven continuous mining units to develop the mains and gate roads for its longwall panels. The longwalls have a panel width (or face length) of approximately 1,500 feet, a panel length of approximately 12,000 feet and a seam height of approximately 7.8 feet.

Harvey Mine

The Harvey mine is located directly east of the Bailey and Enlow Fork mines. As of December 31, 2014, the Harvey mine’s assigned and accessible reserve base contained an aggregate of 208.3 million tons (41.7 million tons net to our 20% interest on a pro forma basis) of clean recoverable proven and probable coal with an average gross heat content of approximately 13,000 Btus per pound and an average sulfur content of 2.28%. While operating one longwall, the production capacity of the Harvey mine is 5.5 million tons of coal per year.

Similar to the Enlow Fork mine, the Harvey mine was developed off of the Bailey mine’s slope bottom. Once the new slope at the Bailey mine was placed into operation, seals were built to separate the two mines, and the original slope was dedicated solely to the Harvey mine, which eliminated the need to make significant capital expenditures to develop, among other things, a new slope, air shaft and portal facility. Development of the Harvey mine began in 2009, and construction of the supporting surface facilities commenced in 2011. Longwall mining production commenced in March 2014. The Harvey mine was designed for an annual production capacity of approximately five million tons per year. For the year ended December 31, 2014, the Harvey mine produced 3.2 million tons (0.6 million tons net to our 20% interest on a pro forma basis) of coal.

The Harvey mine uses four continuous mining units to develop the mains and gate roads for its longwall panels. The longwall has a panel width (or face length) of approximately 1,500 feet, a panel length of approximately 15,000 feet and a seam height of approximately 6.6 feet. The Harvey mine’s existing infrastructure, including its bottom development, slope belt and material handling system, has the capacity to add one incremental permanent longwall mining system with additional mine development and capital investment.

Transportation Logistics and Infrastructure

We have developed a transportation and logistics network with dual rail transportation options that we believe provides us with operational and marketing flexibility, reduces the cost to deliver coal to our core market and allows us to realize higher netback prices. Substantially all of our coal is sold free on board (“FOB”) at the Pennsylvania mining complex, which means that our customers bear the transportation costs from the mining complex, and all of our coal transported to our domestic customers or export terminal facility by rail. We believe our proximity to our core market, dual rail transportation options and customized on-site logistics infrastructure

 

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contribute to lower overall delivered costs for power plants in the eastern United States as a result of shorter transportation distances, access to diversified rail route options, higher rail car utilization, more efficient use of locomotive power and more predictable movement of product between mine and destination. In addition, we have favorable access to international coal markets through CONSOL Energy’s Baltimore Marine Terminal.

The logistics capabilities of coal producers are important to customers, who focus on the cost, reliability and flexibility of product delivery. We have direct and indirect rail access to domestic customers and the Baltimore Marine Terminal through Norfolk Southern and CSX rail lines. We also have rail-to-barge access to multiple third-party barge-loading terminals on the Monongahela River and the Ohio River if we determine in the future to transport our coal by barge. Because our customers desire to minimize excess coal inventory levels, they seek to arrange for product to be delivered as needed, which requires predictable and efficient loading and transporting of the product. The integrated nature of our logistics operations minimizes the time required to successfully load shipments, even at times of peak activity, lowers product handling costs and facilitates optimal train staging and exiting. Our onsite rail infrastructure includes our new dual-batch train loadout facility and 19.3 miles of track, including two sidings, in a single loop configuration that is 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. Our ability to accommodate multiple unit trains allows for the seamless transition of locomotives from empty inbound trains to fully loaded outbound trains at our facility, which, combined with our high-capacity train loadout facility, minimizes locomotive staging time.

Our new, dual-batch, high-volume train loadout facility commenced operations in 2013 and is able to load up to 9,000 tons of coal per hour and has the ability to load up to ten unit trains per day. Our advanced loading system enables us to load rail cars at a target weight on a consistent, repeatable car-to-car basis. Our online quality monitoring systems analyze coal specifications as a rail car is loaded with a high degree of precision, which allows for more predictable loads of coal and allows us to tailor coal qualities to each customer’s requirements.

CONSOL Energy’s Baltimore Marine Terminal is located on 200 acres along the north shore of the Patapsco River in the Port of Baltimore. The Baltimore Marine Terminal is the only East Coast marine terminal served by two rail lines (Norfolk Southern and CSX). The terminal features high-speed, high-capacity equipment that provides coal transshipments directly from rail cars to ocean-going vessels. The terminal’s throughput capacity is 15 million tons of coal per year, with tandem rotary dumpers able to dump coal at a rate of 5,000 tons per hour and a shiploader that can load vessels at a rate of 7,000 tons per hour. The terminal’s pier is approximately 1,253 feet long and is capable of accommodating vessels with a beam of 174 feet and an air draft of 55 feet. The terminal has storage capacity for more than 1.1 million tons of coal and exported 9.6 million tons in 2014, making the Baltimore Marine Terminal one of the largest coal terminals on the East Coast. In connection with the completion of this offering, we will enter into a contract with CONSOL Energy for the right to ship coal through the terminal for a fixed fee per ton of coal. Please read “—Our Terminal and Throughput Agreement with CONSOL Energy.”

Our Operating Agreement with CONSOL Energy

In connection with the completion of this offering, we will enter into an operating agreement with CPCC and Conrhein pursuant to which we will be named as operator and assume management and control over the day-to-day operations, business and affairs of the Pennsylvania mining complex for the life of the mines. As operator under the operating agreement, we will be responsible for managing and conducting all operations with respect to the Pennsylvania mining complex, including providing the following services, which we refer to as the “operational services”:

 

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maintaining and periodically rehabilitating mine sites;

 

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mining the Pennsylvania mining complex;

 

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operating the beltlines transporting raw coal into the Pennsylvania mining complex’s preparation plant and loading facility;

 

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storing, preparing, treating, managing and loading coal at the preparation plant and, if applicable, blending coal;

 

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disposing, stockpiling, handling, treating and/or storing all coal refuse; and

 

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marketing and selling coal produced from the Pennsylvania mining complex.

We will have the right to enter into contracts relating to the operation and management of, and the marketing and sale of the coal produced from, the Pennsylvania mining complex and to file any reports required to be filed with governmental authorities, in each case, relating to the operation of the Pennsylvania mining complex on behalf of ourselves and CONSOL Energy.

Pursuant to the operating agreement, we and CONSOL Energy will each appoint one representative to an operating committee. The operating committee will meet quarterly to review the annual budget for the Pennsylvania mining complex and the reports provided by us and to discuss the management and development of the Pennsylvania mining complex. While we will be delegated the authority and responsibility to manage and further develop the Pennsylvania mining complex, certain material actions, including the approval of the annual plan and budget and any permanent or extended temporary decommissioning of any of the mines at the Pennsylvania mining complex, will require the unanimous consent of the operating committee.

Any liabilities arising from the operation of the Pennsylvania mining complex that are not a result of our gross negligence or willful misconduct will be borne by us and CONSOL Energy pro rata in relation to ownership percentage of the Pennsylvania mining complex. We will invoice CONSOL Energy on a monthly basis for its pro rata share of costs associated with the operation of the Pennsylvania mining complex, including any costs incurred under the employee services agreement, the contract agency agreement, the terminal and throughput agreement and the water supply and services agreement.

Under the operating agreement, we may be removed as operator of the Pennsylvania mining complex only in the event of our gross negligence or willful misconduct.

Our Employee Services Agreement with CONSOL Energy

In connection with the completion of this offering, we will enter into an employee services agreement with a wholly owned subsidiary of CONSOL Energy pursuant to which, subject to our management, direction and control, CONSOL Energy will provide personnel to mine and process coal from the Pennsylvania mining complex and to perform the operational services that we are charged with providing under the operating agreement.

Pursuant to the employee services agreement, we will reimburse CONSOL Energy monthly for (i) all direct third-party costs and expenses actually incurred by CONSOL Energy in providing operational services, including royalties required to be paid on the coal mined, certain taxes applicable to the coal and coal workers, per-ton reclamation fees or taxes and penalties imposed by any governmental authority for violation of any law or regulation arising out of CONSOL Energy’s performance of the operational services, except to the extent such penalties were as a result of CONSOL Energy’s gross negligence or willful misconduct and (ii) salary, benefits and other compensation cost of CONSOL Energy’s employees performing the operational services to the extent such employees are performing the operational services.

The employee services agreement will have an initial term of 20 years and will continue in full force and effect thereafter unless terminated by either party at the end of the initial term or any time thereafter by

 

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giving not less than 180 days’ prior notice. CONSOL Energy may terminate the employee services agreement sooner if (i) we become insolvent, declare bankruptcy or take any action in furtherance of, or indicating our consent to, approval of, or acquiescence in, a similar proceeding or (ii) CONSOL Energy provides notice not less than 180 days prior to the date of such proposed termination. We may terminate the employee services agreement sooner (i) if CONSOL Energy becomes insolvent, declares bankruptcy or takes any action in furtherance of, or indicating its consent to, approval of, or acquiescence in, a similar proceeding or (ii) upon a finding of CONSOL Energy’s willful misconduct or gross negligence.

The employees of CONSOL Energy are not our employees, and CONSOL Energy has the sole and exclusive responsibility to pay and provide benefits for such employees. We will reimburse CONSOL Energy for our proportionate share of the costs of providing such compensation and benefits to those employees under the employee services agreement and the omnibus agreement.

Our executive management team has broad and extensive coal industry experience and will oversee our relationship with CONSOL Energy. Our executive management team’s responsibilities will include, among other things, periodic review of CONSOL Energy’s compliance with safety and environmental laws and regulations at the federal, state and local enforcement levels. In addition, our executive management team will review and monitor CONSOL Energy’s production levels, mine plans, operating budgets and material capital expenditures. CONSOL Energy’s performance will be monitored through periodic reports addressing key management performance indicators relating to safety, regulatory compliance, production and costs, each of which will be compared to budgeted operating parameters.

Our Contract Agency Agreement with CONSOL Energy

In connection with the completion of this offering, we will enter into a contract agency agreement with a wholly owned subsidiary of CONSOL Energy pursuant to which, at our direction and subject to our control, CONSOL Energy will act as our agent to market and sell the coal produced from the Pennsylvania mining complex and will administer our existing coal purchase and sale contracts, including any extensions or renewals thereof, and any new coal purchase and sale contracts for the sale of coal produced from the Pennsylvania mining complex that we direct CONSOL Energy to enter into as part of the operational services provided by CONSOL Energy under the employee services agreement.

The administration of these coal purchase and sale contracts, which we refer to as our contracts, will include CONSOL Energy’s making elections, enforcing rights, executing coal sale confirmations and invoicing, in each case at our direction and with respect to the coal reserves attributable to our interests and CONSOL Energy’s interest in the Pennsylvania mining complex. We will receive all payments under these coal purchase and sale contracts into our account and periodically will remit to CONSOL Energy its proportionate share of revenues collected to the extent such revenues have not been used in furtherance of our operational services under the operating agreement. We will reimburse CONSOL Energy for our proportionate share of any costs, expenses or liabilities incurred by CONSOL Energy under these coal purchase and sale contracts. For additional information about our contracts, please read “—Our Customers and Contracts.”

Our Terminal and Throughput Agreement with CONSOL Energy

In connection with the completion of this offering, we will enter into a terminal and throughput agreement with a wholly owned subsidiary of CONSOL Energy pursuant to which we will have the option, but not the obligation, to transport or to cause to be transported through CONSOL Energy’s Baltimore Marine Terminal up to 5 million tons of coal each calendar year (prorated for the year in which this offering is completed) for a fee of $4 per ton of coal transported through the Baltimore Marine Terminal. The per ton fee will be escalated annually for inflation and will be subject to a one time price renegotiation based on changes in market conditions and operating costs after the final anniversary of the execution date. The terminal and throughput agreement will have an initial term of seven years.

 

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Coal Reserves

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. The ability to update or modify the estimates of our coal reserves is restricted to the engineering group and all modifications are documented.

“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.

Spacing of points of observation for confidence levels in our reserve calculations is based on guidelines in U.S. Geological Survey Circular 891 (Coal Resource Classification System of the U.S. Geological Survey). Our estimates for proven reserves have the highest degree of geologic assurance. Because of the well-known continuity of the Pittsburgh No. 8 Coal Seam, estimates for proven reserves are based on points of observation that are equal to or less than 3,000 feet, and estimates for probable reserves are computed from points of observation that are between 3,000 feet and 8,000 feet apart.

Our estimates of proven and probable reserves do not rely on isolated points of observation. Small pods of reserves based on a single observation point are not considered; continuity between observation points over a large area is necessary for proven or probable reserves.

Our proven and probable coal reserves fall within the range of commercially marketed coal grades in the United States. The marketability of coal depends on its value-in-use for a particular application, and this is affected by coal quality, including sulfur content, ash content and heating value. Modern power plant boiler design aspects can compensate for coal quality differences that occur. As a result, all of our coal can be marketed for the electric power generation industry. 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 addition of this cross-over market adds additional assurance that our proven and probable coal reserves are commercially marketable.

 

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The amount of coal we assign to a mining complex generally is sufficient to support mining through the duration of the applicable current mining permit. Under federal law, we must renew our mining permits every five years. All assigned reserves have their required permits or governmental approvals, or there is a high probability that these approvals will be secured.

In addition, mines may have access to additional reserves that have not yet been assigned. We refer to these reserves as accessible. Accessible reserves are proven and probable reserves that can be accessed by an existing mine, utilizing the existing infrastructure of the complex to mine and to process the coal in this area. Mining an accessible reserve does not require additional capital spending beyond that required to extend or to continue the normal progression of the mine, such as the sinking of airshafts or the construction of portal facilities.

Some reserves may be accessible by more than one mine because of the proximity of our mines to one another. In the table below, the accessible reserves indicated for a mine are based on our review of current mining plans and reflect our best judgment as to which mine is most likely to utilize the reserve.

Assigned and accessible coal reserves are proven and probable reserves which are either owned or leased. The leases have terms extending up to 30 years and generally provide for renewal through the anticipated life of the associated mine. These renewals are exercisable by the payment of minimum royalties. Under current mining plans, assigned reserves reported will be mined out within the period of existing leases or within the time period of probable lease renewal periods.

The following table sets forth the proven and probable coal reserves at the Pennsylvania mining complex, on a 100% basis, as of December 31, 2014 (tons in millions):

 

Mine		Proven Reserves (tons)				Probable Reserves (tons)				Total Recoverable Reserves (tons)
Bailey			148.7				105.8				254.5
Enlow Fork			253.0				69.8				322.8
Harvey			130.2				78.1				208.3
Total			531.9				253.7				785.6

The following table sets forth additional information regarding the recoverable coal reserves at the Pennsylvania mining complex, on a 100% basis, as of December 31, 2014 (tons in millions):

 

										Gross Heat Content (1)(2) (Btu/lb)												Recoverable Reserves (3)(4)
Mine		Reserve Class				Average Seam Thickness (feet)				Average				Range				Average Sulfur Content (2)				Owned (%)				Leased (%)				Total (tons)
Bailey:			Assigned				7.6				12,928				12,800 – 13,050				2.68	%			53	%			47	%			84.0
			Accessible				7.5				12,940				12,720 – 13,190				2.68	%			78	%			22	%			170.5
Enlow Fork:			Assigned				7.8				12,891				12,800 – 13,000				2.21	%			99	%			1	%			21.6
			Accessible				7.6				12,946				12,720 – 13,120				2.21	%			76	%			24	%			301.2
Harvey:			Assigned				6.6				13,182				12,940 – 13,230				2.28	%			89	%			11	%			27.1
			Accessible				7.6				13,065				12,870 – 13,160				2.28	%			99	%			1	%			181.2
Total:											12,968								2.38	%											785.6

 

(1)	The heat value shown for assigned reserves is based on the quality of coal mined and processed during the year ended December 31, 2014.

 

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(2)	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.

(3)

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.

(4)

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.

 

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Our Customers and Contracts

We sell coal to an established customer base through opportunities as a result of strong business relationships or through a formalized bidding process. The following map shows the extensive reach of our market in the eastern United States.

 

We refer to the contracts under which coal produced from the Pennsylvania mining complex is sold and which a wholly owned subsidiary of CONSOL Energy administers under the contract agency agreement at our direction as our contracts, even though none of these contracts will be transferred to us in connection with this offering. For additional information on our contract agency agreement, please read “—Our Contract Agency Agreement with CONSOL Energy.” The following table describes the contracted position (in millions of tons) of the Pennsylvania mining complex, on a 100% basis, for the years ended 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 primarily 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.

 

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The terms of our sales contracts vary significantly by customer, including price adjustment features, price reopener terms, coal quality requirements, quantity adjustment mechanisms, permitted sources of supply, future regulatory changes, extension options, force majeure provisions and termination and assignment provisions. Contract volumes range from a single shipment to multi-year agreements for millions of tons of coal. The average term of our sales agreements is between one to three years. As a normal course of business, efforts are made to renew or extend contracts scheduled to expire. We generally have been successful in renewing or extending contracts in the past; however, there is no guarantee that our efforts in renewing or extending contracts will be successful in the future. For the year ended December 31, 2014, approximately 70% of all the coal produced from the Pennsylvania mining complex was sold under contracts with terms of one year or more.

Substantially all of our multi-year sales contain fixed prices, subject only to pre-established price adjustments based primarily 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. 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. Under some of our contracts, we have the right to match lower prices offered to our customers by other suppliers.

The volume of coal to be delivered is specified in each of our sales contracts. Although the volume to be delivered under the coal contracts is stipulated, the parties may vary the timing of the deliveries within specified limits. 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.

Approximately          million tons (or     %) of our expected coal production for the twelve months ending June 30, 2016 has been committed under contracts. Our primary domestic customers are electric utility companies in the eastern United States. For the year ended December 31, 2014, the Pennsylvania mining complex derived greater than 10% of its total coal sales revenues from each of Duke Energy Corporation (“Duke Energy”) and GenOn Energy, Inc. (“GenOn Energy”). For the year ended December 31, 2013, the Pennsylvania mining complex derived greater than 10% of its total coal sales revenues from each of Duke Energy, GenOn Energy, Xcoal Energy & Resources and the South Carolina Public Service Commission. We believe the advantageous qualities of our coal, our significant transportation cost advantage compared to many of our competitors, our ability to produce large volumes of coal with low operating costs and the diversification of our customer base helps to mitigate our exposure to the loss of any one customer. However, if any of our largest customers were to significantly reduce their purchases of coal from us, or if we were unable to sell coal to our largest customers on terms as favorable to us as the terms under our current contracts, our results of operations may be adversely affected until such time as we generate replacement sales either under multi-year sales contracts or in the spot market.

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 MATS rule compliance. 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

 

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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. 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 retirements 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.

Coal produced from the Pennsylvania mining complex is exported into the thermal and metallurgical coal international markets, primarily to Asia, Canada, Europe, India and South America. For the years ended December 31, 2013 and 2014, the Pennsylvania mining complex sold approximately 20% and 13%, respectively, of its total coal production into international markets, substantially all of which was through a coal trading and brokering company.

Seasonality

Our business has historically experienced only limited variability in its results due to the effect of seasonal changes. Demand for coal-fired power can increase due to unusually hot or cold weather as power consumers use more air conditioning or heating, respectively. Conversely, mild weather can result in weaker demand for our coal. Adverse weather conditions, such as blizzards or floods, can impact our ability to transport coal over our overland conveyor systems and to transport our coal by rail.

Competition

The coal industry is highly competitive, with numerous producers selling into all markets that use coal. There are numerous large and small producers in all coal producing basins of the United States, and we compete with many of these producers. Our main competitors include Alliance Resource Partners, L.P., Alpha Natural Resources, Inc., Arch Coal, Inc., Foresight Energy LP, Murray Energy Corporation, Patriot Coal Corp. and White Oak Resources LLC.

The most important factors on which we compete are coal price, coal quality and characteristics, transportation costs and reliability of supply. Demand for coal and the prices that we will be able to obtain for our coal are closely linked to coal consumption patterns of the domestic electric generation industry and foreign coal consumers. These coal consumption patterns are influenced by many factors that are beyond our control, including demand for electricity, which is significantly dependent upon economic activity and summer and winter temperatures in the United States, government regulation, technological developments and the location, quality, price and availability of competing sources of fuel.

Our Safety and Environmental Programs and Procedures

As part of our core values of safety, compliance and continuous improvement, we are committed to the ongoing safety of our mining operations. For example, 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 have developed and implemented an environmental, health and safety management program to control and reduce the environmental impacts of our operations and to ensure the safe operation of our mines. We have mature safety and environmental management systems that are compliant with OHSAS 18001 and ISO 14001, respectfully. We utilize an electronic data management system, Enviance, to track key performance indicators and manage our permit compliance data. In

 

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addition, our environmental controls include, among others, CONSOL Energy employing 89 full-time environmental compliance professionals and utilizing experienced in-house personnel and contractors to conduct extensive pre-mining sampling and studies to comply with environmental regulations. Our safety program includes, among other things, (i) CONSOL Energy employing 69 full-time safety professionals, (ii) implementing policies and procedures to protect employees and visitors at our mines, (iii) requiring a certified mine foreman to be in charge of the activities at each mine and (iv) ensuring that each employee undergoes the required safety, hazard and task training.

We operate some of the industry’s safest underground mines based on data from the 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. We have been awarded numerous awards for our strong safety, compliance and environmental record. For example, the Bailey mine received the Keystone Mine Safety Award from the Pennsylvania Coal Alliance for our safety record in 2013. In addition, our preparation plant received a Joseph A. Holmes Safety Award in 2011 and 2012, and the Enlow Fork mine received a Joseph A. Holmes Safety Award in 2010 and 2012.

Laws and Regulations

Overview

Our coal mining operations are subject to various federal, state and local environmental, health and safety regulations. Regulations relating to our operations require us to obtain permits and other licenses; reclaim and restore our properties after mining operations have been completed; store, transport and dispose of materials used or generated by our operations; manage surface subsidence from underground mining; control water and air emissions; protect wetlands and endangered plant and wildlife; and to ensure employee health and safety. Furthermore, the electric power generation industry is subject to extensive regulation regarding the environmental impact of its power generation activities, which could affect demand for our coal. Compliance with these laws has substantially increased the cost of coal mining, and the possibility exists that new legislation or regulations may be adopted which would have a significant impact on our coal mining operations or our customers’ ability to use our coal and may require us or our customers to change their operations significantly or incur substantial costs.

The following is a summary of the more significant existing environmental and worker health and safety laws and regulations to which we and our customers’ business operations are subject and for which compliance may have a material adverse impact on our capital expenditures, results of operations and financial position.

Environmental Laws

Air Emissions. The Clean Air Act (“CAA”) and corresponding state and local laws and regulations affect all aspects of coal mining operations, both directly and indirectly. The CAA directly impacts our coal mining and processing operations by requiring us to obtain pre-approval for the construction or modification of certain facilities or to use specific equipment, technologies or best management practices to control emissions.

The CAA also indirectly and more significantly affects the U.S. coal industry by extensively regulating the air emissions of the coal-fired electric power generating plants operated by our customers. Coal contains impurities, such as sulfur, mercury and other constituents, many of which are released into the air when coal is burned. Carbon dioxide, a greenhouse gas, is also emitted when coal is burned. Please read “—Climate Change.” There have been a series of recent federal rulemakings that are focused on emissions from coal-fired electric generating facilities. Installation of emissions control technologies and other required measures will make it more costly to build and operate coal-fired power plants and may make coal a less attractive fuel alternative in the planning and building of power plants in the future. Such measures also may force our customers to retire coal-fired electric power plants, rather than retrofit with the necessary emission control technologies. Any reduction in coal’s share of power generating capacity could negatively impact our ability to sell coal, which could have a material adverse effect on our business, financial condition, results of operations and cash flows.

 

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The air emissions programs that may directly or indirectly affect our operations include, but are not limited to:

 

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Cross-State Air Pollution Rule (“CSAPR”), which requires certain Midwestern and Eastern states to reduce power plant emissions that cross state lines and contribute to ozone and/or fine particle pollution in other states beginning in 2015. Judicial challenges to the rule remain pending.

 

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Mercury and Air Toxics Standards (“MATS”) Rule, which requires coal-fired power plants to reduce air toxics emissions beginning in April 2015.

 

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National Ambient Air Quality Standards (“NAAQS”), which impose air quality standards for carbon monoxide, nitrogen dioxide, ozone, particulate matter, sulfur dioxide and lead. Over the past several years, the EPA has revised its NAAQS for nitrogen dioxide, sulfur dioxide and particulate matter, and, in November 2014, proposed a revised standard for ozone, in each case making the standards more stringent. The EPA expects to finalize the revised ozone NAAQS by October 2015.

 

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Acid Rain Program, which regulates emissions of sulfur dioxide and nitrogen oxides from electric generating facilities. These requirements would not be supplanted by CSAPR.

 

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NOx SIP Call program, which was established to reduce the transport of nitrogen oxides and ozone in 22 Eastern states and the District of Columbia.

 

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Regional Haze Program, which seeks to protect and improve visibility at and around national parks, national wilderness areas and international parks.

 

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New Source Review Program, which requires existing coal-fired power plants to install more stringent air emissions control equipment when modifications to those plants significantly change emissions.

Climate Change. 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. 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 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. The plan proposes a national carbon pollution standard that would, by 2030, cut emissions produced by U.S. power plants by 30% from 2005 levels. The final rule is expected to be issued in mid-summer 2015 and the emission reductions are scheduled to commence in 2020. A legal challenge to the proposed rulemaking has already been filed. Moreover, other legal challenges to the EPA’s authority to regulate GHG emissions under the CAA are likely.

 

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Additionally, the U.S. Supreme Court, in a decision issued in June 2014, addressed whether the EPA’s regulation of GHG emissions from new motor vehicles properly triggered GHG permitting requirements for stationary sources under the CAA’s Prevention of Significant Deterioration (“PSD”) and Title V permitting programs. The court ultimately held that the EPA could require certain large stationary sources that are already subject to the PSD program, due to the source’s emission of conventional pollutants, to limit GHG emissions by employing the “best available control technology.”

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. Furthermore, the low-priced natural gas environment within which we operate also impacts the amount of coal that may be purchased by utilities. Please read “Risk Factors—Risks Related to Our Business—Decreases in demand for electricity and changes in coal consumption patterns of U.S. electric power generators could adversely affect our business.” 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, financial condition, results of operations and cash flows. 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.

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’ 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 the EPA to list coal mines as a stationary source have likewise been unsuccessful to-date. 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.

Water Discharges. The Clean Water Act (“CWA”) and corresponding state laws affect our coal operations by regulating the discharge of pollutants into regulated waters, including wetlands. The CWA and corresponding state laws include requirements for: improvement of designated “impaired waters” (not meeting state water quality standards) through the use of effluent limitations; anti-degradation regulations which protect state designated “high quality/exceptional use” streams by restricting or prohibiting discharges; requirements to treat discharges from coal mining properties for non-traditional pollutants, such as chlorides, selenium and dissolved solids; and minimizing impacts and compensating for unavoidable impacts resulting from discharges of fill materials to regulated streams and wetlands. Continued compliance with such existing permit conditions are not expected to have a material adverse effect on our business, financial condition or results of operations. However, in April 2014, the EPA and the U.S. Army Corps of Engineers (“ACOE”) released a proposed rule to update the definition of “waters of the United States” subject to the CWA. Any expansion of this definition to include previously unregulated waters could have a material adverse impact on our operations if it requires us to obtain additional permits or otherwise limits construction activities.

The EPA issues permits for the discharge of pollutants into surface waters, and the ACOE issues permits for the discharge of dredge and fill material into regulated wetlands. ACOE maintains two permitting programs under Section 404 of the CWA for the discharge of dredge and fill material: one for “individual permits” and a more streamlined program for “general” permits. However, the CWA authorizes the EPA to review and veto permits issued by the ACOE. The EPA has exercised its veto power to retroactively rescind a permit issued by

 

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the ACOE, which has been upheld by the courts. Any future use of this authority could create uncertainty with regard to our current permits, as well as impose additional time and cost burdens on future operations, potentially adversely affecting our business, financial condition, results of operations and cash flows.

In order to obtain a permit for surface coal mining activities, including valley fills associated with steep slope mining, an operator must obtain a permit for the discharge of fill material from the ACOE and a discharge permit from the state regulatory authority under the state counterpart to the CWA. Beginning in early 2009, the EPA took a number of initiatives that have resulted in delays and obstruction of the issuance of such permits for surface mining operations in the Appalachian states, including Pennsylvania where the Pennsylvania mining complex is located. Increased oversight of delegated state programmatic authority, coupled with individual permit review and additional requirements imposed by the EPA, has resulted in delays in the review and issuance of permits for surface coal mining operations, including applications for surface facilities for underground mines, such as applications for coal refuse disposal areas.

In addition, on June 7, 2013, the EPA published proposed standards for steam electric power generating plants to strengthen existing controls on discharges from these plants. For the first time, the proposed standards include limits for toxic metals. Depending on emissions control technology in operation at a power plant, along with waste water management and ash handling, some coal-fired units could be disadvantaged with regards to upgrading wastewater treatment. A final rule is expected in September 2015.

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 later this year. If these challenges are ultimately unsuccessful, we would not be relieved of the costs to comply with the technical guidance document requirements.

The EPA began a water quality investigation in 2011 and we received a request for information pursuant to Section 308 of the CWA regarding our permitted discharge outlets at the Bailey and Enlow Fork mines. We have since responded to the information request and submitted the requested data. We have met with the U.S. Department of Justice, the EPA and the PADEP to negotiate a resolution to this matter. We expect the agencies to assess civil penalties, potentially in excess of $100,000, as part of any negotiated resolution, but do not yet have an estimate of any such penalties.

In May 2014, we notified the PADEP of a discoloration in our water discharges. We implemented a pump-back system to prevent any additional discharges of discolored water. We entered into a consent order to conduct an assessment of the hydrologic conditions of the impoundment and liner system in the coal refuse disposal area in order to determine the cause of the discoloration. We completed the assessment and submitted the final report pursuant to the terms of the consent order on January 30, 2015. We believe that we have satisfied the conditions of the consent order, but this matter has not yet been resolved with PADEP.

Safe Drinking Water Act. The Safe Drinking Water Act (“SDWA”) and its state equivalents affect coal mining operations by imposing requirements on the underground injection of fine coal slurries, fly ash and flue gas scrubber sludge, and by requiring permits to conduct such underground injection activities. In addition to establishing the underground injection control program, the SDWA also imposes regulatory requirements on owners and operators of “public water systems.” This regulatory program could impact our lessees’ reclamation operations where subsidence or other mining-related problems require the provision of drinking water to affected adjacent homeowners.

Hazardous Substances and Waste Materials. We are subject to the requirements of environmental laws and regulations related to the release of hazardous substances and other waste materials into the environment. These laws and regulations generally regulate the generation, storage, treatment, transportation and disposal of

 

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hazardous substances and waste materials and may require investigatory and remedial actions at sites where such material has been released or disposed. For example, the Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”) and comparable state laws, impose joint and several liability without regard to fault or the legality of the original conduct on certain classes of persons that contributed to a release of a “hazardous substance” into the environment. These persons include the owner and operator of the site where a release occurred and persons that disposed or arranged for the disposal of the hazardous substance that has been released into the environment. These persons may be liable for, among other things, the costs of investigating and remediating the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies. CERCLA and comparable state laws also authorize the EPA, its state counterparts, and, in some instances, third parties to take actions in response to threats to the public health or the environment and to seek to recover from the responsible classes of persons the costs they incur. It is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by hazardous substances or other pollutants released into the environment.

We also generate both hazardous and nonhazardous wastes that are subject to the requirements of the Resource Conservation and Recovery Act (“RCRA”) and comparable state laws. Certain mining wastes are currently excluded from the definition of hazardous wastes. However, changes in applicable laws and regulations, including waste characterization, may result in a material increase in our capital expenditures or plant operating and maintenance expense.

Endangered Species Act. The Endangered Species Act and comparable state laws protect species threatened with possible extinction. Protection of threatened and endangered species may have the effect of prohibiting or delaying us from obtaining mining permits and may include restrictions on timber harvesting, road building and other mining or agricultural activities in areas containing the affected species or their habitats. Based on the species that have been identified to date and the current application of applicable laws and regulations, we do not believe there are any species protected under the Endangered Species Act that would materially and adversely affect our mining operations at this time. We have a conservation habitat plan in place at the Bailey mine that covers the Indiana Bat. The U.S. Fish and Wildlife Service has allowed us to use this existing conservation habitat plan to cover the Northern Long-Eared Bat, which is expected to be listed in April 2015.

Surface Mining Control and Reclamation Act. The Surface Mining Control and Reclamation Act (“SMCRA”) and similar state laws establish minimum operational, reclamation and closure standards for surface mining and deep mining. SMCRA requires that comprehensive environmental protection and reclamation standards be met during the course of and following the completion of mining activities. These requirements typically are implemented through mining permits issued at the state level. It is not uncommon for a SMCRA mine permit application to take over two years to prepare and review, depending on the size and complexity of the mine, and another two or more years for the permit to be issued, depending primarily on the regulatory authority’s approach to handling comments and objections received from the general public and other agencies. Also, it is not uncommon for a permit to be delayed as a result of litigation related to the specific permit or another related company’s permit. SMCRA also imposes on mine operators the responsibility of restoring the land to its original state and compensating the landowner for types of damages occurring as a result of mining operations, and requires mine operators to post performance bonds to ensure compliance with any reclamation obligations. Additionally, the Abandoned Mine Lands Program, which is part of SMCRA, imposes a tax on all current mining operations, the proceeds of which are used to restore mines closed before 1977. The current tax is 28 cents per ton on surface-mined coal and 12 cents per ton on underground-mined coal. States from time to time have increased and may continue to increase their fees and taxes to fund reclamation of orphaned mine sites and abandoned mine drainage control on a statewide basis. These fees are currently scheduled to be in effect until September 30, 2021.

Federal and state laws require bonds to secure our obligations to reclaim lands used for mining and to satisfy other miscellaneous obligations. These bonds are typically renewable on a yearly basis. Surety bond costs

 

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have increased while the market terms of surety bonds have generally become less favorable. It is possible that surety-bond issuers may refuse to renew bonds or may demand additional collateral upon those renewals. Any failure to maintain, or inability to acquire, surety bonds that are required by state and federal laws would have a material adverse effect on our ability to produce coal, which could adversely affect our business, financial condition, results of operations and cash flows.

Health and Safety Laws

Mine Safety. Our operations are subject to stringent health and safety standards that have been imposed by federal and state laws since the adoption of the federal Mine Health and Safety Act, which imposes comprehensive health and safety standards on all mining operations. As part of the Mine Health and Safety Act, the Black Lung Acts require payments of benefits by all businesses conducting current mining operations to coal miners with black lung or pneumoconiosis and to some beneficiaries of miners who have died from this disease.

In addition, in 2006, the Mine Improvement and New Emergency Response Act (“Miner Act”) was enacted which imposed obligations related to improvements in mine safety practices, increased civil and criminal penalties for non-compliance, created additional mine rescue teams and expanded the scope of federal oversight, inspection and enforcement activities. Pursuant to the Miner Act, the Mine Safety Health Administration (“MSHA”) has promulgated new emergency rules on mine safety and revised its civil penalty assessment regulations, which resulted in an across-the-board increase in penalties from the existing regulations. Since passage of the Miner Act, enforcement scrutiny has also increased, including more inspection hours at mine sites, increased numbers of inspections and increased issuance of the number and the severity of enforcement actions and related penalties. MSHA continues to interpret and implement various provisions of the Miner Act, along with introducing new proposed regulations and standards. Our compliance with these or any new mine health and safety regulations could increase our mining costs. Additionally, the Dodd Frank Bill that was enacted by Congress in 2010 now requires mining companies, including coal companies, to include various safety statistics regarding citations, penalties, notices of violation and pending legal actions in periodic reports that are required by the securities laws. These disclosures may lead to the enactment of yet further legislation regarding mine safety.

Black Lung Legislation. Under federal black lung benefits legislation, each coal mine operator is required to make payments of black lung benefits or contributions to (1) current and former coal miners totally disabled from black lung disease; (2) certain survivors of miners who have died from black lung disease; and (3) a trust fund for the payment of benefits and medical expenses to certain claimants.

The Patient Protection and Affordable Care Act (“PPACA”) made two changes to the Federal Black Lung Benefits Act. First, it provided changes to the legal criteria used to assess and award claims by creating a legal presumption that miners are entitled to benefits if they have worked at least 15 years in underground coal mines, or in similar conditions, and suffer from a totally disabling lung disease. To rebut this presumption, a coal company would have to prove that a miner did not have black lung or that the disease was not caused by the miner’s work. Second, it changed the law so that black lung benefits will continue to be paid to dependent survivors when the miner passes away, regardless of the cause of the miner’s death. In addition to the federal legislation, we are also liable under various state statutes for black lung claims.

Permit Requirements

Numerous governmental permits or approvals are required for mining operations. When we apply for these permits and approvals, we may be required to prepare and present data to federal, state or local authorities pertaining to the effect or impact that any proposed production or processing of coal may have upon the environment. The authorization, permitting and implementation requirements imposed by federal, state and local authorities may be costly and time consuming and may limit or delay commencement or continuation of mining operations. Under some circumstances, substantial fines and penalties, including revocation or suspension of mining permits, may be imposed under the laws described above. Monetary sanctions and, in severe circumstances, criminal sanctions may be imposed for failure to comply with these laws.

 

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Employees

Pursuant to our operating agreement with CONSOL Energy, we will assume, upon the closing of this offering, management and control over the day-to-day operations, business and affairs of the Pennsylvania mining complex. The officers of our general partner will manage our operations and activities. Under our employee services agreement with CONSOL Energy, CONSOL Energy employees will continue to mine, process and market 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 that we will enter into with CONSOL Energy. As of December 31, 2014, CONSOL Energy employed over 1,850 people who will provide direct support to our operations pursuant to the employee services agreement. None of the employees who will provide direct support to our operations is represented by a labor union or collective bargaining agreement. CONSOL Energy considers its relations with its employees to be satisfactory. Please read “—Our Operating Agreement with CONSOL Energy” and “—Our Employee Services Agreement with CONSOL Energy.”

Insurance

We share insurance coverage with CONSOL Energy, for which we will reimburse CONSOL Energy pursuant to the terms of our omnibus agreement, in amounts and with coverage and deductibles that we, with the advice of insurance advisors and brokers, believe are reasonable and prudent. To the extent CONSOL Energy experiences covered losses under the insurance policies, the limit of our coverage for potential losses may be decreased. We cannot assure you that our insurance coverage will be adequate to protect us from all material expenses related to potential future claims for personal and property damage and third-party liability or that these levels of insurance will be available in the future at economical prices.

Title to Our Properties

Our real property interests are made up of coal minerals and mining rights, including the right to subside, that we have acquired pursuant to a deed and own in fee or have leased from third parties (collectively, “coal rights”), as well as surface rights that allow us to use the associated surface land for our operations that we have acquired pursuant to easements, rights-of-way, permits, surface use agreements, deeds or licenses from landowners, lessors, easement holders, governmental authorities or other parties controlling surface estate (collectively, “surface rights”). We have acquired these coal rights and surface rights without any material challenge known to us relating to the title to such coal rights and surface rights, and we believe that we have satisfactory rights and interests to conduct our operations on lands covered by such rights.

Prior to commencing development operations on coal properties, we conduct a thorough title examination and perform curative work with respect to significant defects. Title to coal properties and the boundaries of these properties are verified by law firms retained by us at the time such properties are leased or acquired. We generally will not commence operations on a property until we have cured any material title defects on such property. We may be responsible for the cost of curing any title defects. In addition, the acquisition of the necessary rights may not be feasible in some cases. We have completed title work on substantially all of our coal producing properties located within the current ten-year mine plans at each of our coal mines and believe that we have satisfactory title to our coal producing properties in accordance with standards generally accepted in the industry. Consistent with industry practice, abstracts and title reports are reviewed and updated approximately five years prior to planned development or mining of the property. If defects in title or boundaries of undeveloped reserves are discovered in the future, control of and the right to mine reserves could be adversely affected.

The transfer of an undivided 20% interest in some of the coal rights and surface rights from CONSOL Energy to us required the consent of certain grantors or other holders of such rights. CONSOL Energy will obtain

 

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sufficient third-party consents and authorizations and will provide notices required for the transfer of the coal rights and surfaces rights as necessary to enable us to operate our business in all material respects. With respect to any remaining consents, authorizations or notices that have not been obtained or provided, we have determined these will not have a material adverse effect on the operation of our business should we fail (or CONSOL Energy have failed) to obtain or provide such consents, authorizations or notices in a reasonable time frame. Some of our surface agreements may continue to be held by affiliates of CONSOL Energy until we have made the appropriate filings in the jurisdictions in which such assets are located and obtained any consents, approvals and notices that are not obtained or provided prior to transfer. We will make these filings and notices and seek to obtain these consents upon completion of this offering.

Legal Proceedings

Our operations are subject to a variety of risks and disputes normally incident to our business. As a result, we may, at any given time, be a defendant in various legal proceedings and litigation arising in the ordinary course of business. However, we are not currently subject to any material litigation.

 

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MANAGEMENT

Management of CNX Coal Resources LP

We are managed by the directors and executive officers of our general partner, CNX Coal Resources GP LLC. Our general partner is not elected by our unitholders and will not be subject to re-election by our unitholders in the future. CONSOL Energy owns all of the membership interests in our general partner and has the right to appoint the entire board of directors of our general partner, including our independent directors. Our unitholders are not entitled to elect the directors of our general partner’s board of directors or to directly or indirectly participate in our management or operations. Our general partner will be liable, as general partner, for all of our debts (to the extent not paid from our assets), except for indebtedness or other obligations that are made specifically nonrecourse to it. Whenever possible, we intend to incur indebtedness that is nonrecourse to our general partner.

At the completion of this offering, we expect that our general partner will have five directors, including one director nominee who will become a member of our board of directors prior to or in connection with the listing of our common units on the NYSE. In accordance with the NYSE’s phase-in rules, we will have at least three independent directors within one year following the effective date of the registration statement of which this prospectus forms a part. We expect that our board will determine that                     , our director nominee who will become a member of our board of directors prior to or in connection with the listing of our common units on the NYSE, is independent under the independence standards of the NYSE.

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

Neither we nor our subsidiaries have any employees. Our general partner has the sole responsibility for providing the employees and other personnel necessary to conduct our operations. All of the employees that conduct our business are employed by our general partner or its affiliates (including CONSOL Energy), but we sometimes refer to these individuals in this prospectus as our employees.

Director Independence

As a publicly traded partnership, we qualify for, and are relying on, certain exemptions from the NYSE’s corporate governance requirements, including:

 

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the requirement that a majority of the board of directors of our general partner consist of independent directors;

 

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the requirement that the board of directors of our general partner have a nominating/corporate governance committee that is composed entirely of independent directors; and

 

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the requirement that the board of directors of our general partner have a compensation committee that is composed entirely of independent directors.

As a result of these exemptions, we do not expect that our general partner’s board of directors will be comprised of a majority of independent directors. Our board of directors does not currently intend to establish a nominating/corporate governance committee or a compensation committee. Accordingly, unitholders will not have the same protections afforded to equity holders of companies that are subject to all of the corporate governance requirements of the NYSE.

We are, however, required to have an audit committee of at least three members, and all of its members are required to meet the independence and experience standards established by the NYSE and the Exchange Act, subject to certain transitional relief during the one-year period following the effective date of the registration

 

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statement of which this prospectus forms a part. In accordance with the NYSE’s corporate governance standards, we must have at least one independent member on our audit committee who satisfies the independence and experience requirements by the date our common units are listed on the NYSE, at least a majority of independent members within 90 days of the effective date of the registration statement of which this prospectus forms a part and a fully independent audit committee within one year of such effective date.

Committees of the Board of Directors

The board of directors of our general partner will have an audit committee, and may have such other committees (including a conflicts committee) as the board of directors shall determine from time to time.

Audit Committee

We are required to have an audit committee of at least three members, and all of its members are required to meet the independence and experience standards established by the NYSE and the Exchange Act, subject to certain transitional relief during the one-year period following the effective date of the registration statement of which this prospectus forms a part. The audit committee of the board of directors of our general partner will assist the board of directors in its oversight of the integrity of our financial statements and our compliance with legal and regulatory requirements and partnership policies and controls. The audit committee will have the sole authority to (i) retain and terminate our independent registered public accounting firm, (ii) approve all auditing services and related fees and the terms thereof performed by our independent registered public accounting firm and (iii) pre-approve any non-audit services and tax services to be rendered by our independent registered public accounting firm. The audit committee will also be responsible for confirming the independence and objectivity of our independent registered public accounting firm. Our independent registered public accounting firm will be given unrestricted access to the audit committee and our management, as necessary. We expect that             will serve as the initial member of the audit committee. We expect that             will satisfy the definition of audit committee financial expert for purposes of the SEC’s rules. CONSOL Energy will appoint a second member to the audit committee within 90 days of the effective date of the registration statement of which this prospectus forms a part and appoint a third member to the audit committee within one year following such effective date.

Conflicts Committee

The board of directors of our general partner has the ability to establish a conflicts committee under our partnership agreement. If established, at least two members of the board of directors of our general partner will serve on the conflicts committee to review specific matters that may involve conflicts of interest in accordance with the terms of our partnership agreement. The board of directors of our general partner will determine whether to refer a matter to the conflicts committee on a case-by-case basis. The members of our conflicts committee may not be officers or employees of our general partner or directors, officers or employees of its affiliates (including CONSOL Energy), and must meet the independence and experience standards established by the NYSE and the Exchange Act to serve on an audit committee of a board of directors. In addition, the members of our conflicts committee may not own any interest in our general partner or any interest in us or our subsidiaries other than common units or awards under our long-term incentive plan. If our general partner seeks approval from the conflicts committee, then it will be presumed that, in making its decision, the conflicts committee acted in good faith, and in any proceeding brought by or on behalf of any limited partner or the partnership challenging such determination, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption. Please read “Conflicts of Interest and Duties.”

Directors and Executive Officers of CNX Coal Resources GP LLC

Directors are appointed by CONSOL Energy, the sole member of our general partner, and hold office until their successors have been appointed or qualified or until their earlier death, resignation, removal or disqualification. Executive officers are appointed by, and serve at the discretion of, the board of directors. The

 

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following table presents information for the directors, director nominee and executive officers of CNX Coal Resources GP LLC as of December 31, 2014. Our director nominee will become a member of the board of directors of our general partner prior to or in connection with the listing of our common units on the NYSE.

 

Name		Age				Position with Our General Partner
James A. Brock			58			Chief Executive Officer and Director
Lorraine L. Ritter			49			Chief Financial Officer and Chief Accounting Officer
Martha A. Wiegand			44			General Counsel and Secretary
Nicholas J. DeIuliis			46			Chairman of the Board
Stephen W. Johnson			55			Director
David M. Khani			51			Director

James A. Brock was appointed Chief Executive Officer and a director of our general partner effective March 16, 2015. Mr. Brock has been Chief Operating Officer—Coal of CONSOL Energy since December 10, 2010. Prior to this appointment, he served as Senior Vice President—Northern Appalachia—West Virginia Operations of CONSOL Energy from 2007 to 2010. From 2006 to 2007, Mr. Brock served as Vice President—Operations. Mr. Brock began his career with CONSOL Energy in 1979 at the Matthews Mine and since then has served at various locations in many positions including Section Foreman, Mine Longwall Coordinator, General Mine Foreman and Superintendent. We believe Mr. Brock’s extensive knowledge of our industry and our operations gained during his years of service with CONSOL Energy in positions of increasing responsibility in its coal operations provide the board of directors of our general partner with valuable experience.

Lorraine L. Ritter was appointed Chief Financial Officer and Chief Accounting Officer of our general partner effective March 16, 2015. Ms. Ritter joined CONSOL Energy’s Accounting Department in November 1989, where she served in positions of increasing responsibility, was promoted to Vice President and Controller of CONSOL Energy effective April 2005 and appointed Principal Accounting Officer of CONSOL Energy in March 2013. Prior to joining CONSOL Energy, Ms. Ritter began her professional career at Ernst & Young LLP. She is also a member of the American Institute of Certified Public Accountants.

Martha A. Wiegand was appointed General Counsel and Secretary of our general partner effective March 16, 2015. Ms. Wiegand joined CONSOL Energy’s Legal Department in December 2008 as Senior Counsel and was promoted to Associate General Counsel of CONSOL Energy effective in 2012, where she is responsible for a variety of legal matters, including coal and natural gas marketing and transportation, labor and employment, financing arrangements and certain corporate transactions. Prior to joining CONSOL Energy, Ms. Wiegand worked for approximately 10 years for several large Pittsburgh-based law firms, where she handled financing and corporate transactions for clients in the banking and energy industries, among others. She is licensed to practice law in Pennsylvania and New Jersey and a member of the American Bar Association, the Pennsylvania Bar Association and the Energy & Mineral Law Foundation.

Nicholas J. DeIuliis was appointed a director and elected Chairman of the Board of our general partner effective March 16, 2015. Mr. DeIuliis has been President of CONSOL Energy since February 23, 2011, and on May 7, 2014 he was named CONSOL Energy’s Chief Executive Officer. Mr. DeIuliis previously served in various positions at CNX Gas Corporation, a subsidiary of CONSOL Energy, including President, Chief Executive Officer and Chief Operating Officer. He is currently Chairman of the Board at CNX Gas Corporation. He was Executive Vice President and Chief Operating Officer of CONSOL Energy from January 2009 until February 2011. Prior to that time, he held the following positions at CONSOL Energy: Senior Vice President—Strategic Planning from 2004 to 2005; Vice President Strategic Planning from 2002 to 2004; Director—Corporate Strategy from 2001 to 2002; Manager—Strategic Planning in 2001; and Supervisor—Process Engineering from 1999 to 2001. We believe that Mr. DeIuliis’ unique and in-depth understanding of our business from his over 20 years of experience with CONSOL Energy, including his current roles as President, Chief Executive Officer and director, provide the board of directors of our general partner with valuable experience.

 

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Stephen W. Johnson was appointed a director of our general partner effective March 16, 2015. Mr. Johnson has served as Executive Vice President and Chief Legal and Corporate Affairs Officer of CONSOL Energy and CNX Gas Corporation since January 1, 2013. Prior to that time, Mr. Johnson served as Senior Vice President and General Counsel of CONSOL Energy and CNX Gas Corporation from 2009 through 2012. He served as Executive Vice President and General Counsel for CNX Gas Corporation from 2007 to 2009 and as Senior Vice President and General Counsel for CNX Gas Corporation from 2005 to 2007. Effective May 30, 2014, Mr. Johnson became a director of the general partner of CONE Midstream Partners LP, a publicly traded master limited partnership and affiliate of CONSOL Energy. Prior to joining CONSOL Energy, Mr. Johnson was a partner with Reed Smith LLP and a shareholder with Buchanan Ingersoll & Rooney PC. We believe Mr. Johnson’s extensive knowledge of our industry and our operations gained during his years of service with CONSOL Energy in positions of increasing responsibility, as well as his legal knowledge and experience, provide the board of directors of our general partner with valuable experience.

David M. Khani was appointed a director of our general partner effective March 16, 2015. Mr. Khani joined CONSOL Energy on September 1, 2011 as its Vice President—Finance, and was promoted to Executive Vice President and Chief Financial Officer effective March 1, 2013. Prior to joining CONSOL Energy, Mr. Khani was with FBR Capital Markets & Co. (“FBR”), an investment banking and advisory firm and held the following positions: Director of Research from February 2007 through October 2010, and then Co-Director of Research from November 2010 through August 2011. Prior to that time he served as the Managing Director and Co-Head of FBR’s Energy and Natural Resources Group. Effective May 30, 2014, Mr. Khani became a director and the Chief Financial Officer of the general partner of CONE Midstream Partners LP. We believe Mr. Khani’s energy industry and financial experience provides the board of directors of our general partner with valuable experience in our financial and investor relations matters.

Board Leadership Structure

The board of directors of our general partner has no policy with respect to the separation of the offices of chairman of the board of directors and chief executive officer. Instead, that relationship is defined and governed by the amended and restated limited liability company agreement of our general partner, which permits the same person to hold both offices. Directors of the board of directors of our general partner are designated or appointed by CONSOL Energy. Accordingly, unlike holders of common stock in a corporation, our unitholders will have only limited voting rights on matters affecting our business or governance, subject in all cases to any specific unitholder rights contained in our partnership agreement.

Board Role in Risk Oversight

Our corporate governance guidelines will provide that the board of directors of our general partner is responsible for reviewing the process for assessing the major risks facing us and the options for their mitigation. This responsibility will be largely satisfied by our audit committee, which is responsible for reviewing and discussing with management and our independent registered public accounting firm our major risk exposures and the policies management has implemented to monitor such exposures, including our financial risk exposures and risk management policies.

Reimbursement of Expenses

Our partnership agreement requires us to reimburse our general partner for (i) direct and indirect expenses it incurs or payments it makes on our behalf (including salary, bonus, incentive compensation and other amounts paid to any person, including affiliates of our general partner, to perform services for us or our subsidiaries or for our general partner in the discharge of its duties to us and our subsidiaries) and (ii) all other expenses reasonably allocable to us or our subsidiaries or otherwise incurred by our general partner in connection with operating our business (including expenses allocated to our general partner by its affiliates). Our general partner is entitled to determine the expenses that are allocable to us and our subsidiaries. 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

 

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allocated to our general partner by its affiliates. 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.” 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. Please read “Certain Relationships and Related Party Transactions—Distributions and Payments to Our General Partner and Its Affiliates.”

Compensation of Our Officers and Directors

Executive Compensation

We and our general partner were formed in March 2015 and will have no material assets or operations until the closing of this offering. Accordingly, our general partner has not accrued and will not accrue any compensation obligations for executive officers and directors for any periods prior to the closing of this offering. Because the executive officers of our general partner are employed by CONSOL Energy or its affiliates, compensation of the executive officers, other than any awards granted under the long-term incentive plan we intend to adopt prior to the completion of this offering, will be set by CONSOL Energy and its affiliates. The executive officers of our general partner will continue to participate in employee benefit plans and arrangements sponsored by CONSOL Energy and its affiliates, including plans that may be established in the future.

Compensation of Our Directors

The officers or employees of our general partner or of our sponsor who also serve as directors of our general partner will not receive additional compensation for their service as a director of our general partner. In connection with this offering, directors of our general partner who are not officers or employees of our general partner or of our sponsor, or “non-employee directors,” will receive cash and equity-based compensation for their services as directors. The non-employee director compensation program will consist of the following:

 

•

an annual retainer of $        ;

 

•

an additional annual retainer of $         for service as the lead director (if established) or chair of the audit committee; and

 

•

an annual equity-based award granted under the LTIP, having a value as of the grant date of approximately $        .

Non-employee directors will also receive reimbursement for out-of-pocket expenses they incur in connection with attending meetings of the board of directors or its committees. Each director will be indemnified for his or her actions associated with being a director to the fullest extent permitted under Delaware law.

Our Long-Term Incentive Plan

Our general partner intends to adopt the CNX Coal Resources LP 2015 Long-Term Incentive Plan (our “LTIP”) under which our general partner may issue long-term equity based awards to directors, officers and employees of our general partner or its affiliates, or to any consultants, affiliates of our general partner or other individuals who perform services for us. These awards will be intended to compensate the recipients thereof based on the performance of our common units and their continued service during the vesting period, as well as to align their long-term interests with those of our unitholders. All determinations with respect to awards to be made under our LTIP will be made by the board of directors of our general partner or any committee thereof that may be established for such purpose or by any delegate of the board of directors or such committee, subject to applicable law, which we refer to as the plan administrator. We currently expect that the board of directors of our

 

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general partner or a committee thereof will be designated as the plan administrator. The following description reflects the terms that are currently expected to be included in the LTIP.

General

The LTIP will provide for the grant, from time to time at the discretion of the board of directors of our general partner or any delegate thereof, subject to applicable law, of unit awards, restricted units, phantom units, unit options, unit appreciation rights, distribution equivalent rights, profits interest units and other unit-based awards. The purpose of awards under the LTIP is to provide additional incentive compensation to individuals providing services to us, and to align the economic interests of such individuals with the interests of our unitholders. The LTIP will limit the number of units that may be delivered pursuant to vested awards to                      common units, subject to proportionate adjustment in the event of unit splits and similar events. Common units subject to awards that are cancelled, forfeited, withheld to satisfy exercise prices or tax withholding obligations or otherwise terminated without delivery of the common units will be available for delivery pursuant to other awards.

Restricted Units and Phantom Units

A restricted unit is a common unit that is subject to forfeiture. Upon vesting, the forfeiture restrictions lapse and the recipient holds a common unit that is not subject to forfeiture. A phantom unit is a notional unit that entitles the grantee to receive a common unit upon the vesting of the phantom unit or on a deferred basis upon specified future dates or events or, in the discretion of the plan administrator, cash equal to the fair market value of a common unit. The plan administrator of the LTIP may make grants of restricted units and phantom units under the LTIP that contain such terms, consistent with the LTIP, as the plan administrator may determine are appropriate, including the period over which restricted units or phantom units will vest. The plan administrator of the LTIP may, in its discretion, base vesting on the grantee’s completion of a period of service or upon the achievement of specified financial objectives or other criteria or upon a change of control (as defined in the LTIP) or as otherwise described in an award agreement.

Distributions made by us with respect to awards of restricted units may be subject to the same vesting requirements as the restricted units.

Distribution Equivalent Rights

The plan administrator of the LTIP, in its discretion, may also grant distribution equivalent rights, either as standalone awards or in tandem with other awards. Distribution equivalent rights are rights to receive an amount in cash, restricted units or phantom units equal to all or a portion of the cash distributions made on units during the period an award remains outstanding.

Unit Options and Unit Appreciation Rights

The LTIP may also permit the grant of options covering common units. Unit options represent the right to purchase a number of common units at a specified exercise price. Unit appreciation rights represent the right to receive the appreciation in the value of a number of common units over a specified exercise price, either in cash or in common units. Unit options and unit appreciation rights may be granted to such eligible individuals and with such terms as the plan administrator of the LTIP may determine, consistent with the LTIP; however, a unit option or unit appreciation right must have an exercise price equal to at least the fair market value of a common unit on the date of grant.

Unit Awards

Awards covering common units may be granted under the LTIP with such terms and conditions, including restrictions on transferability, as the plan administrator of the LTIP may establish.

 

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Profits Interest Units

Awards granted to grantees who are partners, or granted to grantees in anticipation of the grantee becoming a partner or granted as otherwise determined by the plan administrator, may consist of profits interest units. The plan administrator will determine the applicable vesting dates, conditions to vesting and restrictions on transferability and any other restrictions for profits interest awards.

Other Unit-Based Awards

The LTIP may also permit the grant of “other unit-based awards,” which are awards that, in whole or in part, are valued or based on or related to the value of a common unit. The vesting of another unit-based award may be based on a participant’s continued service, the achievement of performance criteria or other measures. On vesting or on a deferred basis upon specified future dates or events, another unit-based award may be paid in cash and/or in units (including restricted units) or any combination thereof as the plan administrator of the LTIP may determine.

Source of Common Units

Common units to be delivered with respect to awards may be newly-issued units, common units acquired by us or our general partner in the open market, common units already owned by our general partner or us, common units acquired by our general partner directly from us or any other person or any combination of the foregoing.

Anti-Dilution Adjustments and Change in Control

If an “equity restructuring” event occurs that could result in an additional compensation expense under applicable accounting standards if adjustments to awards under the LTIP with respect to such event were discretionary, the plan administrator of the LTIP will equitably adjust the number and type of units covered by each outstanding award and the terms and conditions of such award to equitably reflect the restructuring event, and the plan administrator will adjust the number and type of units with respect to which future awards may be granted under the LTIP. With respect to other similar events, including, for example, a combination or exchange of units, a merger or consolidation or an extraordinary distribution of our assets to unitholders, that would not result in an accounting charge if adjustment to awards were discretionary, the plan administrator of the LTIP shall have discretion to adjust awards in the manner it deems appropriate and to make equitable adjustments, if any, with respect to the number of units available under the LTIP and the kind of units or other securities available for grant under the LTIP. Furthermore, upon any such event, including a change in control of us or our general partner, or a change in any law or regulation affecting the LTIP or outstanding awards or any relevant change in accounting principles, the plan administrator of the LTIP will generally have discretion to (i) accelerate the time of exercisability or vesting or payment of an award, (ii) require awards to be surrendered in exchange for a cash payment or substitute other rights or property for the award, (iii) provide for the award to assumed by a successor or one of its affiliates, with appropriate adjustments thereto, (iv) cancel unvested awards without payment or (v) make other adjustments to awards as the plan administrator deems appropriate to reflect the applicable transaction or event.

Termination of Service

The consequences of the termination of a grantee’s membership on the board of directors of our general partner or other service arrangement will generally be determined by the plan administrator in the terms of the relevant award agreement.

 

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Amendment or Termination of Long-Term Incentive Plan

The plan administrator of the LTIP, at its discretion, may terminate the LTIP at any time with respect to the common units for which a grant has not previously been made. The plan administrator of the LTIP also has the right to alter or amend the LTIP or any part of it from time to time or to amend any outstanding award made under the LTIP, provided that no change in any outstanding award may be made that would materially impair the vested rights of the participant without the consent of the affected participant or result in taxation to the participant under Section 409A of the Internal Revenue Code.

 

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SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

The following table sets forth the beneficial ownership of common units and subordinated units of CNX Coal Resources LP that will be issued upon the completion of this offering and the related transactions and held by:

 

•

each unitholder known by us to beneficially hold 5% or more of our outstanding units;

 

•

each director or director nominee of our general partner;

 

•

each named executive officer of our general partner; and

 

•

all of the directors, director nominee and named executive officers of our general partner as a group.

In addition, in connection with the completion of this offering, we will issue a 2% general partner interest and all of our incentive distribution rights to our general partner.

Beneficial ownership is determined under the rules of the SEC and generally includes voting or investment power with respect to securities. Unless indicated below, to our knowledge, the persons and entities named in the following table have sole voting and sole investment power with respect to all units beneficially owned by them, subject to community property laws where applicable.

The following table assumes that the underwriters’ option to purchase additional common units is not exercised. The percentage of units beneficially owned is based on a total of             common units and             subordinated units outstanding immediately following this offering. The following table does not include any common units that the directors, director nominee and named executive officers of our general partner may purchase in this offering through the directed unit program described under “Underwriting.”

 

Name of Beneficial Owner (1)		Common Units To Be Beneficially Owned				Percentage of Common Units To Be Beneficially Owned				Subordinated Units To Be Beneficially Owned				Percentage of Subordinated Units To Be Beneficially Owned				Percentage of Total Common Units and Subordinated Units To Be Beneficially Owned
CONSOL Energy Inc. (2)								%							100	%				%
Directors/Director Nominee/Named Executive Officers
James A. Brock			—				—				—				—				—
Lorraine L. Ritter			—				—				—				—				—
Martha A. Wiegand			—				—				—				—				—
Nicholas J. DeIuliis			—				—				—				—				—
Stephen W. Johnson			—				—				—				—				—
David M. Khani			—				—				—				—				—
			—				—				—				—				—
All Directors, Director Nominee and Executive Officers as a group (7 persons)			—				—				—				—				—

 

*	Less than 1%.

(1)	Unless otherwise indicated, the address for all beneficial owners in this table is c/o CNX Coal Resources GP LLC, 1000 CONSOL Energy Drive, Canonsburg, Pennsylvania 15317.

(2)	CONSOL Energy is the sole owner of the membership interests in our general partner. We will issue             common units and             subordinated units to CONSOL Energy in connection with the completion of this offering.

 

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The following table sets forth, as of                 , 2014, the number of shares of CONSOL Energy common stock beneficially owned by each of the directors, director nominee and named executive officers of our general partner and all of the directors, director nominee and named executive officers of our general partner as a group. The percentage of total shares is based on              shares outstanding as of                 , 2014. Amounts shown below include options that are currently exercisable or that may become exercisable within 60 days of                 , 2014 and the shares underlying deferred stock units and the shares underlying restricted stock units that will be settled within 60 days of                 , 2014. Unless otherwise indicated, the named person has the sole voting and dispositive powers with respect to the shares of CONSOL Energy common stock set forth opposite such person’s name.

 

Name of Beneficial Owner		Total Common Stock Beneficially Owned		Percent of Total Outstanding
Directors/Director Nominee/Named Executive Officers
James A. Brock					*
Lorraine L. Ritter					*
Martha A. Wiegand					*
Nicholas J. DeIuliis					*
Stephen W. Johnson					*
David M. Khani					*
All Directors, Director Nominee and Executive Officers as a group (7 persons)					*

 

*	Less than 1%.

 

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CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

Following the completion of this offering, our sponsor 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). In addition, our general partner will own a 2% general partner interest in us and all of our incentive distribution rights.

Distributions and Payments to Our General Partner and Its Affiliates

The following table summarizes the distributions and payments to be made by us to our general partner and its affiliates in connection with the formation, ongoing operation and liquidation of us. These distributions and payments were determined by and among affiliated entities and, consequently, are not the result of arm’s-length negotiations.

Formation Stage

 

The consideration received by our general partner and its affiliates for our formation.

•

2% general partner interest; and

•

98% limited partner interest.

Offering Stage

 

The consideration received by our general partner and its affiliates prior to or in connection with this offering for the contribution to us of a 20% undivided interest in the Pennsylvania mining complex

•

common units (or             common units if the underwriters exercise in full their option to purchase additional common units);

•

subordinated units;

•

a 2% general partner interest in us;

•

the incentive distribution rights; and

•

a distribution of approximately $         million from the net proceeds of this offering (or $         million if the underwriters exercise in full their option to purchase additional common units).

Post-IPO Operational Stage

 

Distributions of available cash to our general partner and its affiliates

We will generally make cash distributions of 98% to the unitholders pro rata, including our sponsor, as the holder of             common units and             subordinated units, and 2% to our general partner, assuming it makes any capital contributions necessary to maintain its 2% general partner interest in us. In addition, if distributions exceed the minimum quarterly distribution and target distribution levels, the incentive distribution rights held by our general partner will entitle our general partner to increasing percentages of the distributions, up to 48% of the distributions above the highest target distribution level.

 

Assuming we generate sufficient distributable cash flow to support the payment of the full minimum quarterly distribution on all of our outstanding units for four quarters, our general partner would receive

 

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an annual distribution of approximately $         million on the 2% general partner interest, and our sponsor would receive an annual distribution of approximately $         million on its common units and subordinated units (or $         million if the underwriters exercise in full their option to purchase additional common units).

 

Payments to our general partner and its affiliates

Under our partnership agreement, we are required to reimburse our general partner and its affiliates for all costs and expenses that they incur on our behalf for managing and controlling our business and operations. Except to the extent specified under our omnibus agreement and the other agreements described under “—Agreements Governing the Transactions,” our general partner determines the amount of these expenses and such determinations must be made in good faith under the terms of our partnership agreement. Under our omnibus agreement, we will reimburse our sponsor for expenses incurred by our sponsor and its affiliates in providing certain general and administrative services to us, including the provision of executive management services by certain officers of our general partner. The expenses of other employees will be allocated to us based on the amount of time actually spent by those employees on our business. These reimbursable expenses also include an allocable portion of the compensation and benefits of employees and executive officers of other affiliates of our general partner who provide services to us and are exclusive of any expenses incurred under the employee services agreement. We will also reimburse our sponsor for any additional out-of-pocket costs and expenses incurred by our sponsor and its affiliates in providing general and administrative services to us. 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.

 

Pursuant to the employee services agreement, we will reimburse CONSOL Energy monthly for (i) all direct third-party costs and expenses actually incurred by CONSOL Energy in providing operational services and (ii) salary, benefits and other compensation cost of CONSOL Energy’s employees performing the operational services to the extent such employees are performing the operational services. Please read “—Agreements Governing the Transactions” below.

 

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.”

 

Withdrawal or removal of our general partner

If our general partner withdraws or is removed, its general partner interest and its incentive distribution rights will either be sold to the new general partner for cash or converted into common units, in each

 

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case for an amount equal to the fair market value of those interests. Please read “Our Partnership Agreement—Withdrawal or Removal of Our General Partner.”

Liquidation Stage

 

Liquidation

Upon our liquidation, the partners, including our general partner, will be entitled to receive liquidating distributions according to their respective capital account balances.

Agreements Governing the Transactions

We and other parties will enter into the various agreements that will effect the transactions contemplated by this offering, including the vesting of assets in, and the assumption of liabilities by, us and our subsidiaries, and the application of the proceeds from this offering. While not the result of arm’s-length negotiations, we believe the terms of all of our initial agreements with our sponsor and its affiliates will be, and specifically intend the rates to be, generally no less favorable to either party than those that could have been negotiated with unaffiliated parties with respect to similar services. All of the transaction expenses incurred in connection with these transactions, including the expenses associated with transferring assets into our subsidiaries, will be paid for with the proceeds from this offering.

Operating Agreement

At the closing of this offering, we will enter into an operating agreement with CPCC and Conrhein. For more information about our operating agreement, please read “Business—Our Operating Agreement with CONSOL Energy.”

Employee Services Agreement

At the closing of this offering, we will enter into an employee services agreement with a subsidiary of CONSOL Energy. For more information about our employee services agreement, please read “Business—Our Employee Services Agreement with CONSOL Energy.”

Contract Agency Agreement

At the closing of this offering, we will enter into a contract agency agreement with a subsidiary of CONSOL Energy. For more information about our contract agency agreement, please read “Business—Our Contract Agency Agreement with CONSOL Energy.”

Terminal and Throughput Agreement

At the closing of this offering, we will enter into a terminal and throughput agreement with a subsidiary of CONSOL Energy. For more information about our terminal and throughput agreement, please read “Business—Our Terminal and Throughput Agreement with CONSOL Energy.”

Management Services Agreement

At the closing of this offering, we will enter into a management services agreement with a wholly owned subsidiary of CONSOL Energy, under which we will provide certain management services to assist in the management of CONSOL Energy’s retained interest in the Pennsylvania mining complex. Under the management services agreement, CONSOL Energy’s subsidiary will reimburse us monthly for (i) all direct third-party costs and expenses actually incurred by us in providing the management services and (ii) salary, benefits and other compensation costs of the employees performing the management services to the extent such

 

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employees are performing the management services. This management fee is fixed until December 31, 2015 and thereafter will be adjusted annually based on changes in the scope of the services performed. The management services that we provide to CONSOL Energy under our management services agreement include the management of coal land-related matters and coal operations and engineering support. The management services agreement has an initial term of five years and will automatically renew for additional one-year terms unless terminated by either party on not less than 180 days’ prior notice.

If a force majeure event prevents us from performing required management services, CONSOL Energy may subcontract the affected management services and any fees owed by CONSOL Energy will be reduced dollar-for-dollar by any amounts paid to such subcontractors.

Cooperation and Safety Agreement

At the closing of this offering, we, on behalf of ourselves and CPCC and Conrhein, will enter into a cooperation and safety agreement with a wholly owned subsidiary of CONSOL Energy pursuant to which we, in our capacity as operator of the Pennsylvania mining complex, will coordinate mining activities relating to the Pennsylvania mining complex with the drilling and development activities of those subsidiaries of CONSOL Energy that own oil and natural gas interests in and around the Pennsylvania mining complex.

The cooperation and safety agreement will contain provisions related to the safe and economical operation of our coal business and CONSOL Energy’s natural gas business where joint interests exist, including with respect to surface rights and use, water rights and use and subsidence issues.

Water Supply and Services Agreement

In connection with the completion of this offering, we will enter into a water supply and services agreement with a wholly owned subsidiary of CONSOL Energy pursuant to which we will have the option, but not the obligation, to (i) acquire water from CONSOL Energy for a fee of $3.50 per thousand gallons of water, which we refer to as the supply fee, in an amount up to 600 gallons per minute and (ii) cause CONSOL Energy to treat and dispose of water produced from the Pennsylvania mining complex for a fee of $1.91 per thousand gallons of water, which we refer to as the disposal fee. The supply fee will be subject to a renegotiation based on market conditions at the end of the initial term, and the disposal fee will be subject to annual renegotiation based on market conditions and operating costs of the water treatment facility. The water supply and services agreement will have an initial term of five years and will automatically renew for additional one-year terms unless terminated by either party on not less than 30 days’ prior notice.

Omnibus Agreement

At the closing of this offering, we will enter into an omnibus agreement with CONSOL Energy, CPCC, Conrhein and our general partner that will address the following matters:

 

•

our payment of an annual administrative support fee, initially in the amount of $9.4 million (prorated for the first year of service), for the provision of certain administrative support services by CONSOL Energy and its affiliates;

 

•

our payment of an annual executive support fee, initially in the amount of approximately $0.7 million (pro rated for the first year of service), for the provision of certain executive support services by CONSOL Energy and its affiliates;

 

•

our obligation to reimburse CONSOL Energy for all other direct or allocated costs and expenses incurred by CONSOL Energy in providing general and administrative services (which reimbursement is in addition to certain expenses of our general partner and its affiliates that are reimbursed under our partnership agreement);

 

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•

our right of first offer to acquire CONSOL Energy’s retained 80% undivided interest in the Pennsylvania mining complex; and

 

•

certain indemnities, as described in below, from CONSOL Energy and us.

So long as CONSOL Energy controls our general partner, the omnibus agreement will remain in full force and effect. If CONSOL Energy ceases to control our general partner, either party may terminate the omnibus agreement, provided that the indemnification obligations will survive any such termination in accordance with their terms.

Payment of administrative support fee, executive support fee and reimbursement of expenses. We will pay CONSOL Energy an administrative support fee, initially in the amount of $9.4 million (payable in equal monthly installments and pro rated for the first year of service), for the provision of certain administrative support services for our benefit, including: financial and administrative services (including treasury and accounting); information technology; legal services; corporate health, safety and environmental services; facility services; human resources services; procurement services; corporate engineering services, including asset integrity and regulatory services; logistical services; asset oversight, such as operational management and supervision; business development services; investor relations; tax matters; and public company reporting services. These allocated portions are based on our proportionate share of CONSOL Energy’s property, plant and equipment and equity-method investments associated with the operations overseen by the applicable officer. We will also pay CONSOL Energy an executive support fee, initially in the amount of approximately $0.7 million (payable in equal monthly installments and pro rated for the first year of service), for the provision of certain executive support services for our benefit. CONSOL Energy administrative support fee may change each calendar year, as determined in good faith, to accurately reflect the degree and extent of the general and administrative services provided to us and may be adjusted to reflect, among other things, the contribution, acquisition or disposition of assets to or by us or to reflect any change in the cost of providing general and administrative services to us due to changes in any law, rule or regulation applicable to CONSOL Energy and its affiliates or to us, including any interpretation of such laws, rules or regulations.

Under the omnibus agreement, we will also reimburse CONSOL Energy for all other direct and allocated costs and expenses incurred by CONSOL Energy in providing these services to us, including salaries, bonuses and benefits costs, for certain officers of CONSOL Energy, including those who also serve as officers and directors of our general partner. This reimbursement will be in addition to our reimbursement of our general partner and its affiliates for certain costs and expenses incurred on our behalf for managing and controlling our business and operations as required by our partnership agreement.

Right of first offer. Under the omnibus agreement, until the date that CONSOL Energy no longer controls our general partner, if CONSOL Energy decides to sell, transfer or otherwise dispose of all or part of its retained 80% undivided interest in the Pennsylvania mining complex, CONSOL Energy will provide us by written notice with the opportunity to make the first offer to acquire such interests and assets. Following the receipt of such notice, we will have 60 days to propose a transaction with CONSOL Energy. We and CONSOL Energy will then have 60 days to negotiate in good faith to reach an agreement on such transaction. If we and CONSOL Energy are unable to agree on such terms during such 60-day period, then CONSOL Energy may divest of such retained undivided interest to any third party during a 180-day period following the expiration of such 60-day period on terms generally no less favorable to the third party than those included in the written notice.

The consummation and timing of any acquisition by us of all or part of the interest covered by our right of first offer will depend upon, among other things, CONSOL Energy’s decision to sell any of the interest covered by the right of first offer and our ability to reach an agreement with CONSOL Energy on price and other terms. Accordingly, we can provide no assurance whether, when or on what terms we will be able to successfully consummate any future acquisitions pursuant to our right of first offer, and CONSOL Energy is under no

 

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obligation to accept any offer that we may choose to make. Please read “Risk Factors—Risks Related to Our Business—Our growth strategy primarily depends on us acquiring additional undivided interests in the Pennsylvania mining complex from our sponsor.”

Indemnification. CONSOL Energy will indemnify us for certain liabilities, including those relating to:

 

•

the consummation of the transactions contemplated by our asset contribution agreement and the equity contribution agreement;

 

•

certain liabilities retained by CONSOL Energy pursuant to the asset contribution agreement;

 

•

certain title matters, including the failure to have (i) the ability to operate under any governmental license, permit or approval or (ii) such valid title to the contributed assets, in each case, that is necessary for us to own or operate the contributed assets in substantially the same manner as owned or operated by CONSOL Energy prior to this offering;

 

•

except to the extent resulting from our breach of the operating standard in the operating agreement, CONSOL Energy’s ownership of its retained 80% interest in and to the Pennsylvania mining complex; and

 

•

a breach by CONSOL Energy of the services standard in the employee services agreement.

We will indemnify CONSOL Energy for certain liabilities, including those relating to:

 

•

the use, ownership or operation of our assets, including certain environmental liabilities;

 

•

our breach of the operating standard in the operating agreement;

 

•

any liabilities incurred by CONSOL Energy under the contract agency agreement; and

 

•

our breach of the operating standard in the management services agreement.

Under the omnibus agreement, certain indemnification by CONSOL Energy will be limited to liabilities identified prior to the             anniversary of the closing of this offering. Certain of our and CONSOL Energy’s indemnification obligations will be subject to a deductible of $             million per claim. For purposes of calculating the deductible, a “claim” will include all liabilities that arise from a discrete act or event. There is no limit on the amount for which CONSOL Energy or we will indemnify under the omnibus agreement once the deductible is met.

Asset Contribution Agreement

We have entered into a contribution agreement, which we refer to as our asset contribution agreement, with CPCC and Conrhein under which, prior to the effective date of the registration statement of which this prospectus forms a part, CPCC and Conrhein contributed to CNX Thermal Holdings LLC, a Delaware limited liability company (“CNX Thermal Holdings”), a 20% undivided interest in the Pennsylvania mining complex.

Equity Contribution Agreement

At the closing of this offering, we will enter into a contribution, conveyance and assumption agreement, which we refer to as our equity contribution agreement, with CONSOL Energy, CPCC, Conrhein and our general partner under which CONSOL Energy and our general partner will contribute to us all of the limited liability company interests in CNX Operating LLC, a Delaware limited liability company and sole member of CNX Thermal Holdings.

 

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Procedures for Review, Approval and Ratification of Related Person Transactions

The board of directors of our general partner will adopt a code of business conduct and ethics in connection with the completion of this offering that will provide that the board of directors of our general partner or its authorized committee will review on at least a quarterly basis all transactions with related persons that are required to be disclosed under SEC rules and, when appropriate, initially authorize or ratify all such transactions. In the event that the board of directors of our general partner or its authorized committee considers ratification of a transaction with a related person and determines not to so ratify, the code of business conduct and ethics will provide that our management will make all reasonable efforts to cancel or annul the transaction.

The code of business conduct and ethics will provide that, in determining whether or not to recommend the initial approval or ratification of a transaction with a related person, the board of directors of our general partner or its authorized committee should consider all of the relevant facts and circumstances available, including (if applicable) but not limited to: (i) whether there is an appropriate business justification for the transaction; (ii) the benefits that accrue to us as a result of the transaction; (iii) the terms available to unrelated third parties entering into similar transactions; (iv) the impact of the transaction on a director’s independence (in the event the related person is a director, an immediate family member of a director or an entity in which a director or an immediate family member of a director is a partner, shareholder, member or executive officer); (v) the availability of other sources for comparable products or services; (vi) whether it is a single transaction or a series of ongoing, related transactions; and (vii) whether entering into the transaction would be consistent with the code of business conduct and ethics.

The code of business conduct and ethics described above will be adopted in connection with the completion of this offering and, therefore, the transactions described above were not reviewed under such policy.

 

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CONFLICTS OF INTEREST AND DUTIES

Conflicts of Interest

Conflicts of interest exist and may arise in the future as a result of the relationships between our general partner and its affiliates, including our sponsor, on the one hand, and us and our unaffiliated limited partners, on the other hand. The directors and executive officers of our general partner have duties to manage our general partner in a manner that is in the best interests of its owners. At the same time, our general partner has a duty to manage us in a manner that it believes is in the best interests of our partnership.

Whenever a conflict of interest arises between our general partner or its affiliates, on the one hand, and us or any other partner, on the other hand, our general partner will resolve that conflict. Our general partner may seek the approval of such resolution from the conflicts committee of the board of directors of our general partner (“special approval”) or from our unitholders (“unitholder approval”), but our general partner is not required to do so. There is no requirement under our partnership agreement that our general partner seek special approval or unitholder approval for the resolution of any conflict of interest, and, under our partnership agreement, our general partner may decide to seek such approval or resolve a conflict of interest in any other way permitted by our partnership agreement, as described below, in its sole discretion. The board of directors of our general partner will decide whether to refer a matter to the conflicts committee or to our unitholders on a case-by-case basis. In determining whether to refer a matter to the conflicts committee or to our unitholders for approval, the board of directors of our general partner will consider a variety of factors, including the nature of the conflict of interest, the size of the transaction and dollar amount involved, the identity of the parties involved and any other factors the board of directors deems relevant in determining whether it will seek special approval or unitholder approval. Whenever our general partner makes a determination to seek special approval, to seek unitholder approval or to adopt a resolution or course of action that has not received special approval or unitholder approval, then our general partner will be entitled, to the fullest extent permitted by law, to make such determination free of any duty or obligation whatsoever to our partnership or any limited partner, and our general partner will not, to the fullest extent permitted by law, be required to act in good faith or pursuant to any other standard or duty imposed by our partnership agreement or under the Delaware Act or any other law, rule or regulation or at equity, and our general partner in making such determination will be permitted to do so in its sole and absolute discretion. For a more detailed discussion of the duties applicable to our general partner, please read “—Duties of Our General Partner.”

Whenever a potential conflict of interest exists or arises, any resolution or course of action by our general partner or its affiliates in respect of such conflict of interest will be permitted and deemed approved by all partners, and will not constitute a breach of our partnership agreement or of any duty stated or implied by law or equity, if the resolution or course of action in respect of such conflict of interest is:

 

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approved by special approval, which our partnership agreement defines as approval by a majority of the members of the conflicts committee; or

 

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approved by unitholder approval, which our partnership agreement defines as the vote of a majority of the outstanding common units, excluding any common units owned by our general partner or any of its affiliates.

If our general partner seeks special approval from the conflicts committee, then it will be presumed that, in making its decision, the conflicts committee acted in good faith, and in any proceeding brought by or on behalf of any limited partner or the partnership challenging such determination, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption. If our general partner does not seek special approval or unitholder approval, then our general partner, the board of directors of our general partner or any committee of the board of directors of our general partner (including the conflicts committee), as applicable, will make such determination or take or decline to take any action in good faith, and none of our general partner, the

 

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board of directors of our general partner or any committee of the board of directors of our general partner (including the conflicts committee), as applicable, will be subject to any fiduciary duty or other duty or obligation, or any other, different or higher standard under our partnership agreement or under the Delaware Act or any other law, rule or regulation or at equity. Under our partnership agreement, it will be presumed that, in making its decision, our general partner, the board of directors of our general partner or any committee of the board of directors of our general partner (including the conflicts committee), as applicable, acted in good faith, and in any proceeding brought by or on behalf of any limited partner or the partnership challenging such determination, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption. Unless the resolution of a conflict of interest is specifically provided for in our partnership agreement, our general partner or the conflicts committee of our general partner’s board of directors may consider any factors it determines in good faith to consider when resolving a conflict. In order for a determination or the taking or declining to take an action to be in “good faith” for purposes of our partnership agreement, the person or persons making such determination or taking or declining to take such action must subjectively believe that the determination or other action is in the best interests of the partnership. In taking such action, such person 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. If that person has the required subjective belief, then the decision or action will be conclusively deemed to be in good faith for all purposes under our partnership agreement.

It is possible, but we believe it is unlikely, that our general partner would approve a matter that the conflicts committee has previously declined to approve or declined to recommend that the full board of directors approve. If the conflicts committee does not approve or does not recommend that the full board of directors approve a matter that has been presented to it, then, unless the board of directors of our general partner has delegated exclusive authority to the conflicts committee, the board of directors of our general partner may subsequently approve the matter. In such a case, although the matter will not have received “special approval” under our partnership agreement, the board of directors of our general partner could still determine to resolve the conflict of interest solely under the good faith standard. In making any such determination, the board of directors of our general partner may take into account the totality of the relationships between the parties involved, including other transactions that may be particularly favorable or advantageous to us. Please read “Management—Committees of the Board of Directors—Conflicts Committee” for information about the conflicts committee of our general partner’s board of directors.

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

Affiliates of our general partner, including 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.

Our partnership agreement provides that our general partner will be restricted from engaging in any business activities other than acting as our general partner (or as general partner or managing member of another entity of which we are a partner or member) or those activities incidental to its ownership of interests in us. However, affiliates of our general partner, including our sponsor, are not prohibited from engaging in other businesses or activities, including those that might compete with us.

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 and executive officers and directors of our general partner. 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

 

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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 reserves, mining operations and related 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.

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 partnership agreement contains provisions that reduce and modify the standards to which our general partner would otherwise be held by state fiduciary duty law. For example, our partnership agreement permits our general partner to make a number of decisions in its individual capacity, as opposed to in its capacity as our general partner, free of any duty or obligation to us and our unitholders. When acting in its individual capacity, our general partner is entitled 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 or any limited partner. Examples of decisions that our general partner may make in its individual capacity include:

 

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

 

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whether to exercise its limited call right;

 

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

 

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whether to exercise its registration rights;

 

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

 

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whether to elect to reset target distribution levels;

 

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

 

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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.

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

In addition to the provisions described above, our partnership agreement contains provisions that restrict the remedies available to our limited partners for actions that might constitute breaches of fiduciary duty under applicable Delaware law. For example, our partnership agreement:

 

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permits our general partner to make a number of decisions in its individual capacity, as opposed to in its capacity as our general partner. When acting in its individual capacity, our general partner is entitled to consider only the interests and factors that it desires, and it has no duty or obligation to give any consideration to any interest of, or factors affecting, us or any limited partner;

 

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provides that the general partner will have no liability to us or our limited partners for decisions made in its capacity as a general partner so long as such decisions are made in good faith reliance on the provisions of our partnership agreement;

 

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•

generally provides that in a situation involving a transaction with an affiliate or other conflict of interest, any determination by our general partner must be made in good faith. If an affiliate transaction or the resolution of another conflict of interest does not receive special approval or unitholder approval, then our general partner will make such determination or take or decline to take any action in good faith, and neither our general partner nor the board of directors of our general partner will be subject to any fiduciary duty or other duty or obligation, or any other, different or higher standard under our partnership agreement or under the Delaware Act or any other law, rule or regulation or at equity. Under our partnership agreement, it will be presumed that in making its decision, our general partner (including the board of directors of our general partner) acted in good faith, and in any proceeding brought by or on behalf of any limited partner or us challenging such decision, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption; and

 

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provides that 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 or directors, as the cases 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 unlawful.

By purchasing a common unit, a common unitholder will be deemed to have agreed to become bound by the provisions in our partnership agreement, including the provisions discussed above.

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

Under our partnership agreement, our general partner has full power and authority to do all things, other than those items that require unitholder approval, on such terms as it determines to be necessary or appropriate to conduct our business, including, but not limited to, the following:

 

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the making of any expenditures, the lending or borrowing of money, the assumption or guarantee of or other contracting for, indebtedness and other liabilities, the issuance of evidences of indebtedness, including indebtedness that is convertible into our securities, and the incurring of any other obligations;

 

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the purchase, sale or other acquisition or disposition of our securities, or the issuance of additional options, rights, warrants and appreciation rights relating to our securities;

 

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the acquisition, disposition, mortgage, pledge, encumbrance, hypothecation or exchange of any or all of our assets (though subject to any prior approval required under our partnership agreement);

 

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the negotiation, execution and performance of any contracts, conveyances or other instruments;

 

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the distribution of our cash;

 

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the selection and dismissal of employees (including officers) and agents, outside attorneys, accountants, consultants and contractors and the determination of their compensation and other terms of employment or hiring;

 

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the maintenance of insurance for our benefit and the benefit of our partners;

 

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the formation of, or acquisition of an interest in, the contribution of property to, and the making of loans to, any limited or general partnership, joint venture, corporation, limited liability company or other entity;

 

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the control of any matters affecting our rights and obligations, including the bringing and defending of actions at law or in equity, otherwise engaging in the conduct of litigation, arbitration or mediation and the incurring of legal expense, the settlement of claims and litigation;

 

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the indemnification of any person against liabilities and contingencies to the extent permitted by law;

 

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the making of tax, regulatory and other filings, or the rendering of periodic or other reports to governmental or other agencies having jurisdiction over our business or assets; and

 

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the entering into of agreements with any of its affiliates to render services to us or to itself in the discharge of its duties as our general partner.

Our partnership agreement provides that our general partner must act in good faith when making decisions on our behalf in its capacity as our general partner, and our partnership agreement further provides that in order for a determination 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. When our general partner is acting in its individual capacity, as opposed to in its capacity as our general partner, it may act free of any duty or obligation to us or our limited partners. Please read “Our Partnership Agreement—Voting Rights” for information regarding matters that require unitholder approval.

Actions taken by our general partner may affect the amount of our distributable cash flow or accelerate the right to convert subordinated units.

The amount of our distributable cash flow is affected by decisions of our general partner regarding matters such as the amount and timing of:

 

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cash expenditures;

 

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borrowings and repayments of indebtedness;

 

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the issuance of additional partnership interests;

 

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the creation, increase or reduction in cash reserves in any quarter; and

 

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asset purchases and sales.

Our general partner determines 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 cash 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.

In addition, our general partner may use an amount, initially equal to $         million, which would not otherwise constitute available cash from operating surplus, in order to permit the payment of cash distributions on its general partner interest and incentive distribution rights. All of these actions may affect the amount of cash distributed to our unitholders and our general partner and may facilitate the conversion of subordinated units into common units. Please read “Provisions of Our Partnership Agreement Relating to Cash Distributions.”

 

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

 

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enabling our general partner or its affiliates to receive distributions on any subordinated units held by them or the incentive distribution rights; or

 

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accelerating the expiration of the subordination period.

For example, in the event we have not generated sufficient cash from our operations to pay the minimum quarterly distribution on our common units and our subordinated units, our partnership agreement permits us to borrow working capital funds, which would enable us to make this distribution on all outstanding units. Please read “Provisions of Our Partnership Agreement Relating to Cash Distributions—Subordinated Units and Subordination Period.”

Our partnership agreement provides that we and our subsidiaries may borrow funds from our general partner and its affiliates. Our general partner and its affiliates may not borrow funds from us or our operating subsidiaries.

We will reimburse our general partner and its affiliates for costs and expenses incurred on our behalf.

We will reimburse our general partner and its affiliates, including our sponsor, for costs and expenses incurred on our behalf. Our partnership agreement requires us 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 or otherwise incurred by our general partner or its affiliates in connection with managing and operating our business and affairs. Our partnership agreement provides that our general partner will determine the expenses that are allocable to us in good faith, and it will charge on a fully allocated cost basis for services provided to us. The expenses for which we are required to reimburse our general partner are not subject to any caps or other limits under our partnership agreement. Our omnibus agreement and employee services agreement will also address our payment of amounts to, and our reimbursement of, our general partner and its affiliates for certain costs and services. Please read “Certain Relationships and Related Party Transactions—Agreements Governing the Transactions.”

Contracts between us, on the one hand, and our general partner and its affiliates, on the other hand, will not be the result of arm’s-length negotiations.

Our partnership agreement allows our general partner to determine, in good faith, any amounts to pay itself or its affiliates for any services rendered to us. Our general partner may also enter into additional contractual arrangements with any of its affiliates on our behalf. Our general partner will determine, in good faith, the terms of any arrangements or transactions entered into after the completion of this offering. While neither our partnership agreement nor any of the other agreements, contracts and arrangements between us and our general partner and its affiliates are or will be the result of arm’s-length negotiations, we believe the terms of all of our initial agreements with our general partner and its affiliates will be, and specifically intend the fees to be, generally no less favorable to either party than those that could have been negotiated with unaffiliated parties with respect to similar services. Similarly, agreements, contracts or arrangements between us and our general partner and its affiliates that are entered into following the completion of this offering will not be required to be negotiated on an arm’s-length basis, although, in some circumstances, our general partner may determine that the conflicts committee may make a determination on our behalf with respect to such arrangements.

Our general partner and its affiliates will have no obligation to permit us to use any facilities or assets of our general partner and its affiliates, except as may be provided in contracts entered into specifically for such use. There is no obligation of our general partner and its affiliates to enter into any contracts of this kind.

 

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

Our general partner intends to limit its liability under contractual arrangements and other obligations 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 partnership agreement provides that any action taken by our general partner to limit its liability is not a breach of our general partner’s fiduciary duties, even if we could have obtained terms that are more favorable without the limitation on liability.

Common units are subject to our general partner’s limited call right.

Our general partner may exercise its right to call and purchase common units, as provided in our partnership agreement, or may assign this right to one of its affiliates or to us. Our general partner may use its own discretion, free of any duty or liability to us or our unitholders, in determining whether to exercise this right. As a result, a common unitholder may have to sell its common units at an undesirable time or at a price that is less than the market price on the date of purchase. Please read “Our Partnership Agreement—Limited Call Right.”

Common unitholders will have no right to enforce obligations of our general partner and its affiliates under agreements with us.

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

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

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

Our general partner 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 our general partner’s incentive distribution rights without the approval of our conflicts committee or our unitholders. This election may 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 incentive distributions at the highest level to which it is entitled (48%) for each of the prior four consecutive calendar quarters and the amount of each 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 cash distributions at the time of the exercise of the reset election. Furthermore, our general partner has the right to transfer all or any portion of the incentive distribution rights at any time, and such transferee shall have the same rights as our general partner relative to resetting target distributions if our general partner concurs that the tests for resetting target distributions have been fulfilled. Following a reset election by our general partner, the minimum quarterly distribution will be reset to an amount equal to the average cash distribution per unit for the two calendar quarters immediately preceding the reset election (such amount is referred to as the “reset minimum quarterly distribution”), and the target distribution levels will be reset to correspondingly higher levels based on percentage increases above the reset minimum quarterly distribution.

 

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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; however, it is possible that our general partner could exercise this reset election at a time when we are experiencing declines in our aggregate cash distributions or at a time when our general partner expects that we will experience declines in our aggregate cash distributions in the foreseeable future. In such situations, our general partner may be experiencing, or may expect to experience, declines in the cash distributions it receives related to its incentive distribution rights and may therefore desire to be issued common units, which are entitled to specified priorities with respect to our distributions and which therefore may be more advantageous for the general partner to own in lieu of the right to receive incentive distribution payments based on target distribution levels that are less certain to be achieved in the then current business environment. As a result, a reset election may cause our common unitholders to experience dilution in the amount of cash distributions that they would have otherwise received had we not issued common units to our general partner in connection with resetting the target distribution levels related to our general partner’s incentive distribution rights. Please read “Provisions of Our Partnership Agreement Relating to Cash Distributions—General Partner Interest and Incentive Distribution Rights.”

Duties of Our General Partner

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 the Delaware Act, our partnership agreement contains various provisions replacing the fiduciary duties that might otherwise be owed by our general partner with contractual standards governing the duties of our general partner and contractual methods of resolving conflicts of interest. We have adopted these provisions to allow our general partner or its affiliates to engage in transactions with us that would otherwise be prohibited by state-law fiduciary standards and to take into account the interests of other parties in addition to our interests when resolving conflicts of interest. We believe this is appropriate and necessary because the board of directors of our general partner has duties to manage our general partner in a manner that is in the best interests of its owners in addition to the best interests of our partnership. Without these provisions, our general partner’s ability to make decisions involving conflicts of interest would be restricted. These provisions enable our general partner to take into consideration the interests of all parties involved in the proposed action. These provisions also strengthen the ability of our general partner to attract and retain experienced and capable directors. These provisions disadvantage the common unitholders because they restrict the rights and remedies that would otherwise be available to such unitholders for actions that, without those limitations, might constitute breaches of fiduciary duty, as described below, and permit our general partner to take into account the interests of third parties in addition to our interests when resolving conflicts of interest. The following is a summary of the fiduciary duties imposed on general partners of a limited partnership by the Delaware Act in the absence of partnership agreement provisions to the contrary, the contractual duties of our general partner contained in our partnership agreement that replace the fiduciary duties that would otherwise be imposed by Delaware laws on our general partner and the rights and remedies of our unitholders with respect to these contractual duties:

 

State law fiduciary duty standards

Fiduciary duties are generally considered to include an obligation to act in good faith and with due care and loyalty. The duty of care, in the absence of a provision in a partnership agreement providing otherwise, would generally require a general partner to act for the

 

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partnership in the same manner as a prudent person would act on his own behalf. The duty of loyalty, in the absence of a provision in a partnership agreement providing otherwise, would generally prohibit a general partner of a Delaware limited partnership from taking any action or engaging in any transaction where a conflict of interest is present unless such transactions were entirely fair to the partnership.

 

Partnership agreement modified standards

Our partnership agreement contains provisions that waive or consent to conduct by our general partner and its affiliates that might otherwise raise issues as to compliance with fiduciary duties or applicable law. For example, our partnership agreement provides that when our general partner is acting in its capacity as our general partner, as opposed to in its individual capacity, it must act in good faith, meaning that it subjectively believed that the decision was in the best interests of our partnership, and our general partner will not be subject to any other standard under our partnership agreement or applicable law, other than the implied contractual covenant of good faith and fair dealing. If our general partner has the required subjective belief, then the decision or action will be conclusively deemed to be in good faith for all purposes under our partnership agreement. In taking such action, 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. In addition, when our general partner is acting in its individual capacity, as opposed to in its capacity as our general partner, it may act free of any duty or obligation to us or our limited partners. These standards reduce the obligations to which our general partner would otherwise be held. If our general partner seeks special approval from the conflicts committee, then it will be presumed that, in making its decision, the conflicts committee acted in good faith, and in any proceeding brought by or on behalf of any limited partner or the partnership challenging such determination, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption. If our general partner does not seek special approval from our conflicts committee or unitholder approval, then our general partner will make such determination or take or decline to take any action in good faith, and neither our general partner nor the board of directors of our general partner will be subject to any fiduciary duty or other duty or obligation, or any other, different or higher standard under our partnership agreement or under the Delaware Act or any other law, rule or regulation or at equity. Under our partnership agreement, it will be presumed that, in making its decision, our general partner (including the board of directors of our general partner) acted in good faith, and in any proceeding brought by or on behalf of any limited partner or us challenging such approval, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption. These standards reduce the obligations to which our general partner would otherwise be held.

 

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In addition to the other more specific provisions limiting the obligations of our general partner, our partnership agreement further provides that our general partner and its officers and directors will not be liable for monetary damages to us or our limited partners for errors of judgment or for any acts or omissions unless there has been a final and non-appealable judgment by a court of competent jurisdiction determining that our general partner or its officers and directors 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 unlawful.

 

Rights and remedies of unitholders

The Delaware Act generally provides that a limited partner may institute legal action on behalf of the partnership to recover damages from a third party where a general partner has refused to institute the action or where an effort to cause a general partner to do so is not likely to succeed. These actions include actions against a general partner for breach of its fiduciary duties, if any, or of the partnership agreement.

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

Under our partnership agreement, we must indemnify our general partner and its officers, directors and managers, to the fullest extent permitted by law, against liabilities, costs and expenses incurred by our general partner or these other persons. We must provide this indemnification unless there has been a final and non-appealable judgment by a court of competent jurisdiction determining that these persons 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 unlawful. We also must provide this indemnification for criminal proceedings when our general partner or these other persons acted with no knowledge that their conduct was unlawful. Thus, our general partner could be indemnified for its negligent acts if it met the requirements set forth above. To the extent that these provisions purport to include indemnification for liabilities arising under the Securities Act of 1933, as amended (the “Securities Act”), in the opinion of the SEC, such indemnification is contrary to public policy and therefore unenforceable. Please read “Our Partnership Agreement—Indemnification.”

 

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DESCRIPTION OF OUR COMMON UNITS

Our Common Units

Our common units represent limited partner interests in us. The holders of common units, along with the holders of subordinated units, are entitled to participate in partnership distributions and to exercise the rights and privileges provided to limited partners under our partnership agreement. Please read “Cash Distribution Policy and Restrictions on Distributions” and “Provisions of Our Partnership Agreement Relating to Cash Distributions.” For a description of the rights and privileges of limited partners under our partnership agreement, including voting rights, please read “Our Partnership Agreement.”

Transfer Agent and Registrar

Duties

Computershare Trust Company, N.A. will serve as the transfer agent and registrar for our common units. We will pay all fees charged by the transfer agent for transfers of common units, except for the following that must be paid by our unitholders:

 

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surety bond premiums to replace lost or stolen certificates, or to cover taxes and other governmental charges in connection therewith;

 

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special charges for services requested by a holder of a common unit; and

 

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other similar fees or charges.

Unless our general partner determines otherwise in respect of some or all of any classes of our partnership interests, our partnership interests will be evidenced by book-entry notation on our partnership register and not by physical certificates.

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

Resignation or Removal

The transfer agent may resign, by notice to us, or be removed by us. The resignation or removal of the transfer agent will become effective upon our appointment of a successor transfer agent and registrar and its acceptance of the appointment. If a successor has not been appointed or has not accepted its appointment within 30 days after notice of the resignation or removal, our general partner may act as the transfer agent and registrar until a successor is appointed.

Transfer of Common Units

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

 

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represents that the transferee has the capacity, power and authority to become bound by our partnership agreement;

 

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automatically agrees to be bound by the terms and conditions of, and is deemed to have executed, our partnership agreement; and

 

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gives the consents and approvals contained in our partnership agreement, such as the approval of all transactions and agreements entered into in connection with our formation and this offering.

A transferee will become a substituted limited partner of our partnership for the transferred common units automatically upon the recording of the transfer on our books and records. Our general partner will cause any transfers to be recorded on our books and records from time to time as necessary to accurately reflect the transfers but no less frequently than quarterly.

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

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

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

Exchange Listing

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

 

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OUR PARTNERSHIP AGREEMENT

The following is a summary of the material provisions of our partnership agreement. The form of our partnership agreement is included in this prospectus as Appendix A. We will provide prospective investors with a copy of our partnership agreement upon request at no charge.

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

 

•

with regard to distributions of available cash, please read “Provisions of Our Partnership Agreement Relating to Cash Distributions”;

 

•

with regard to the duties of our general partner, please read “Conflicts of Interest and Duties”;

 

•

with regard to the authority of our general partner to manage our business and activities, please read “Management—Management of CNX Coal Resources LP”;

 

•

with regard to the transfer of common units, please read “Description of Our Common Units—Transfer of Common Units”; and

 

•

with regard to allocations of taxable income and taxable loss, please read “Material Federal Income Tax Consequences.”

Organization and Duration

Our partnership was organized on March 16, 2015 under the Delaware Act and will have a perpetual existence unless terminated pursuant to the terms of our partnership agreement.

Purpose

Under our partnership agreement, the purpose and nature of the business to be conducted by us shall be to engage directly or indirectly in any business activity that is approved by our general partner, in its sole discretion, and that lawfully may be conducted by a limited partnership organized pursuant to the Delaware Act; provided, however, that our general partner shall not cause us to engage, directly or indirectly, in any business activity that our general partner determines would be reasonably likely to cause us to be treated as an association taxable as a corporation or otherwise taxable as an entity for U.S. federal income tax purposes.

Although our general partner has the ability to cause us and our subsidiaries to engage in activities other than those related to the coal business, our general partner currently has no plans to do so and may decline to do so free of any duty or obligation whatsoever to us or the limited partners, including any duty to act in the best interests of us or our limited partners, other than the implied contractual covenant of good faith and fair dealing. In general, our general partner is authorized to perform all acts it determines to be necessary or appropriate to carry out our purposes and to conduct our business.

Capital Contributions

Unitholders are not obligated to make additional capital contributions, except as described below under “—Limited Liability.” For a discussion of our general partner’s right to contribute capital to maintain its 2% general partner interest if we issue additional partnership interests, please read “—Issuance of Additional Partnership Interests.”

 

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Voting Rights

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

 

•

during the subordination period, the approval of a majority of the outstanding common units, excluding those common units held by our general partner and its affiliates, and a majority of the outstanding subordinated units, voting as separate classes; and

 

•

after the subordination period, the approval of a majority of the outstanding common units.

Following the completion of this offering, our sponsor will have the ability to ensure passage of, as well as the ability to ensure the defeat of, any amendment that requires a unit majority by virtue of its ownership of              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).

In voting their common units and subordinated units, our general partner and its affiliates will have no duty or obligation whatsoever to us or the limited partners, including any duty to act in the best interests of us or the limited partners, other than the implied contractual covenant of good faith and fair dealing.

 

Issuance of additional partnership interests

No approval rights.

 

Amendment of our partnership agreement

Certain amendments may be made by the general partner without the approval of the unitholders. Other amendments generally require the approval of a unit majority. Please read “—Amendment of Our Partnership Agreement.”

 

Merger of our partnership or the sale of all or substantially all of our assets

Unit majority. Please read “—Merger, Consolidation, Conversion, Sale or Other Disposition of Assets.”

 

Dissolution of our partnership

Unit majority. Please read “—Termination and Dissolution.”

 

Continuation of our business upon dissolution

Unit majority. Please read “—Termination and Dissolution.”

 

Withdrawal of the general partner

Under most circumstances, the approval of unitholders holding at least a majority of the outstanding common units, excluding common units held by our general partner and its affiliates, is required for the withdrawal of the general partner prior to                     , 2025, in a manner which would cause a dissolution of our partnership. Please read “—Withdrawal or Removal of Our General Partner.”

 

Removal of the general partner

Not less than 66 2⁄3% of the outstanding units, voting as a single class, including units held by our general partner and its affiliates, for cause. Please read “—Withdrawal or Removal of Our General Partner.”

 

Transfer of the general partner interest

Our general partner may transfer all, but not less than all, of its general partner interest in us without a vote of our unitholders to an

 

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affiliate or another person in connection with its merger or consolidation with or into, or sale of all or substantially all of its assets to, such person. The approval of a majority of the outstanding common units, excluding common units held by our general partner and its affiliates, is required in other circumstances for a transfer of the general partner interest to a third party prior to                     , 2025. Please read “—Transfer of General Partner Interest.”

 

Transfer of incentive distribution rights

Our general partner may transfer any or all of its incentive distribution rights to an affiliate or another person without a vote of our unitholders. Please read “—Transfer of Incentive Distribution Rights.”

 

Reset of incentive distribution levels

No approval right.

 

Transfer of ownership interests in our general partner

No approval right. Please read “—Transfer of Ownership Interests in Our General Partner.”

Limited Liability

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

 

•

remove or replace our general partner for cause;

 

•

approve some amendments to our partnership agreement; or

 

•

take other action under our partnership agreement;

constituted “participation in the control” of our business for the purposes of the Delaware Act, then the limited partners could be held personally liable for our obligations under the laws of Delaware, to the same extent as our general partner. This liability would extend to persons who transact business with us who reasonably believe that a limited partner is a general partner. Neither our partnership agreement nor the Delaware Act specifically provides for legal recourse against our general partner if a limited partner were to lose limited liability through any fault of our general partner. While this does not mean that a limited partner could not seek legal recourse, we know of no precedent for this type of a claim in Delaware case law.

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

 

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distribution was in violation of the Delaware Act shall be liable to the limited partnership for the amount of the distribution for three years. Under the Delaware Act, a substituted limited partner of a limited partnership is liable for the obligations of its assignor to make contributions to the partnership, except that such person is not obligated for liabilities unknown to it at the time it became a limited partner and that could not be ascertained from the partnership agreement.

Our operating subsidiaries conduct business in Pennsylvania and West Virginia. We may have subsidiaries that conduct business in other states in the future. Maintenance of our limited liability as a partner or member of our subsidiaries may require compliance with legal requirements in the jurisdictions in which such subsidiaries conduct business, including qualifying such entities to do business there.

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

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.

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

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

Upon issuance of additional limited partner interests (other than the issuance of common units upon any exercise by the underwriters of their option to purchase additional common units, the issuance of common units in connection with a reset of the incentive distribution target levels or the issuance of common units upon conversion of outstanding partnership interests), our general partner will be entitled, but not required, to make additional capital contributions to the extent necessary to maintain its 2% general partner interest in us. Our general partner’s 2% general partner interest in us will 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 to maintain its 2% general partner interest. Moreover, our general partner will have the right, which it may from time to time assign in whole or in part to any of its affiliates, to purchase common units, subordinated units or other partnership interests whenever, and on the same terms that, we issue those interests to persons other than our general partner and its affiliates, to the extent necessary to maintain the percentage interest of the general partner and its affiliates

 

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represented by common units, subordinated units and other partnership interests that existed immediately prior to each issuance. The other holders of common units will not have preemptive rights to acquire additional common units or other partnership interests.

Amendment of Our Partnership Agreement

General

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

Prohibited Amendments

No amendment may be made that would, among other actions:

 

•

enlarge the obligations of any limited partner without its consent, unless such is deemed to have occurred as a result of an amendment approved by at least a majority of the type or class of limited partner interests so affected; or

 

•

enlarge the obligations of, restrict in any way any action by or rights of, or reduce in any way the amounts distributable, reimbursable or otherwise payable by us to our general partner or any of its affiliates without its consent, which consent may be given or withheld at its option.

The provisions of our partnership agreement preventing the amendments having the effects described in any of the clauses above can be amended upon the approval of the holders of at least 90% of the outstanding units voting together as a single class (including units owned by our general partner and its affiliates). Following the completion of this offering, our sponsor 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).

No Unitholder Approval

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

 

•

a change in our name, the location of our principal office, our registered agent or our registered office;

 

•

the admission, substitution, withdrawal or removal of partners in accordance with our partnership agreement;

 

•

a change that our general partner determines to be necessary or appropriate to qualify or continue our qualification as a limited partnership or a partnership in which the limited partners have limited liability under the laws of any state or to ensure that neither we nor any of our subsidiaries will be treated as an association taxable as a corporation or otherwise taxed as an entity for federal income tax purposes;

 

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•

an amendment that is necessary, in the opinion of our counsel, to prevent us or our general partner or its directors, officers, agents or trustees, from in any manner, being subjected to the provisions of the Investment Company Act of 1940, the Investment Advisors Act of 1940, or “plan asset” regulations adopted under the Employee Retirement Income Security Act of 1974 (“ERISA”), each as amended, whether or not substantially similar to plan asset regulations currently applied or proposed by the U.S. Department of Labor;

 

•

an amendment that (i) sets forth the designations, preferences, rights, powers and duties of any class or series of partnership interests or (ii) our general partner determines to be necessary, appropriate or advisable in connection with the authorization or issuance of additional partnership interests;

 

•

any amendment expressly permitted in our partnership agreement to be made by our general partner acting alone;

 

•

an amendment effected, necessitated or contemplated by a merger agreement or plan of conversion that has been approved under the terms of our partnership agreement;

 

•

any amendment that our general partner determines to be necessary or appropriate to reflect and account for the formation by us of, or our investment in, any corporation, partnership or other entity, in connection with our conduct of activities permitted by our partnership agreement;

 

•

a change in our fiscal year or taxable year and any other changes that our general partner determines to be necessary or appropriate as a result of such change;

 

•

mergers with, conveyances to or conversions into another limited liability entity that is newly formed and has no assets, liabilities or operations at the time of the merger, conveyance or conversion other than those it receives by way of the merger, conveyance or conversion; or

 

•

any other amendments substantially similar to any of the matters described in the clauses above.

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

 

•

do not adversely affect in any material respect the limited partners considered as a whole or any particular class of partnership interests as compared to other classes of partnership interests;

 

•

are necessary or appropriate to satisfy any requirements, conditions or guidelines contained in any opinion, directive, order, ruling or regulation of any federal or state agency or judicial authority or contained in any federal or state statute;

 

•

are necessary or appropriate to facilitate the trading of limited partner interests or to comply with any rule, regulation, guideline or requirement of any securities exchange on which the limited partner interests are or will be listed or admitted to trading;

 

•

are necessary or appropriate for any action taken by our general partner relating to splits or combinations of units under the provisions of our partnership agreement; or

 

•

are required to effect the intent expressed in this prospectus or the intent of the provisions of our partnership agreement or are otherwise contemplated by our partnership agreement.

 

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Opinion of Counsel and Unitholder Approval

For amendments that do not require unitholder approval, our general partner will not be required to obtain an opinion of counsel to the effect that an amendment will not affect the limited liability of any limited partner under Delaware law. No other amendments to our partnership agreement will become effective without the approval of holders of at least 90% of the outstanding units voting as a single class unless we first obtain such an opinion of counsel.

In addition to the above restrictions, any amendment that would have a material adverse effect on the rights or preferences of any type or class of partnership interests in relation to other classes of partnership interests will require the approval of at least a majority of the type or class of partnership interests so affected. Any amendment that would reduce the percentage of units required to take any action, other than to remove our general partner for cause or call a meeting of unitholders, must be approved by the written consent or the affirmative vote of limited partners whose aggregate outstanding units constitute not less than the percentage sought to be reduced. Any amendment that would increase the percentage of units required to remove our general partner for cause must be approved by the written consent or the affirmative vote of limited partners whose aggregate outstanding units constitute not less than 90% of outstanding units. Any amendment that would increase the percentage of units required to call a meeting of unitholders must be approved by the written consent or the affirmative vote of limited partners whose aggregate outstanding units constitute at least a majority of the outstanding units.

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

A merger, consolidation or conversion of our partnership requires the prior consent of our general partner. However, our general partner will have no duty or obligation to consent to any merger, consolidation or conversion and may decline to do so free of any duty or obligation whatsoever to us or the limited partners, including any duty to act in the best interest of us or the limited partners, other than the implied contractual covenant of good faith and fair dealing.

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

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

 

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Termination and Dissolution

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

 

•

the withdrawal or removal of our general partner or any other event that results in its ceasing to be our general partner other than by reason of a transfer of its general partner interest in accordance with our partnership agreement or withdrawal or removal followed by approval and admission of a successor;

 

•

the election of our general partner to dissolve us, if approved by the holders of units representing a unit majority;

 

•

the entry of a decree of judicial dissolution of our partnership; or

 

•

there being no limited partners, unless we are continued without dissolution in accordance with the Delaware Act.

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

 

•

the action would not result in the loss of limited liability of any limited partner; and

 

•

neither our partnership nor any of our subsidiaries would be treated as an association taxable as a corporation or otherwise be taxable as an entity for federal income tax purposes upon the exercise of that right to continue (to the extent not already so treated or taxed).

Liquidation and Distribution of Proceeds

Upon our dissolution, unless we are continued as a new limited partnership, the liquidator authorized to wind up our affairs will, acting with all of the powers of our general partner that are necessary or appropriate to, liquidate our assets and apply the proceeds of the liquidation as described in “Provisions of Our Partnership Agreement Relating to Cash Distributions—Distributions of Cash Upon Liquidation.” The liquidator may defer liquidation or distribution of our assets for a reasonable period of time or distribute assets to partners in kind if it determines that a sale would be impractical or would cause undue loss to our partners.

Withdrawal or Removal of Our General Partner

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

 

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Upon voluntary withdrawal of our general partner by giving notice to the other partners, the holders of a unit majority may select a successor to that withdrawing general partner. If a successor is not elected, or is elected but an opinion of counsel regarding limited liability and tax matters cannot be obtained, we will be dissolved, wound up and liquidated, unless within a specified period after that withdrawal, the holders of a unit majority agree to continue our business by appointing a successor general partner. Please read “—Termination and Dissolution.”

Our general partner may not be removed unless that removal is both (i) for cause and (ii) approved by the vote of the holders of not less than 66 ²⁄₃% of our outstanding units, voting together as a single class, including units held by our general partner and its affiliates, and we receive an opinion of counsel regarding limited liability and tax matters. Any removal of our general partner is also subject to the approval of a successor general partner by the vote of the holders of a majority of the outstanding common units, voting as a separate class, and subordinated units, voting as a separate 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 the general partner liable to our partnership 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. The ownership of more than 33 ¹⁄₃% of the outstanding units by our general partner and its affiliates would give them the practical ability to prevent our general partner’s removal. Following the completion of this offering, our sponsor 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).

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

If the option described above is not exercised by either the departing general partner or the successor general partner, the departing general partner will become a limited partner and its general partner interest and its incentive distribution rights will automatically convert into common units pursuant to a valuation of those interests as determined by an investment banking firm or other independent expert selected in the manner described in the preceding paragraph.

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

Transfer of General Partner Interest

Except for transfer by our general partner of all, but not less than all, of its general partner interest to (i) an affiliate of our general partner (other than an individual), or (ii) another entity as part of the merger or consolidation of our general partner with or into such entity or the transfer by our general partner of all or substantially all of its assets to such entity, our general partner may not transfer all or any part of its general

 

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partner interest to another person prior to                     , 2025, without the approval of the holders of at least a majority of the outstanding common units, excluding common units held by our general partner and its affiliates. As a condition of this transfer, the transferee must assume, among other things, the rights and duties of our general partner, agree to be bound by the provisions of our partnership agreement, and furnish an opinion of counsel regarding limited liability and tax matters.

Our general partner and its affiliates may at any time transfer units to one or more persons, without unitholder approval, except that they may not transfer subordinated units to us.

Transfer of Ownership Interests in Our General Partner

At any time, our sponsor and its affiliates may sell or transfer all or part of their membership interest in our general partner, to an affiliate or third party without the approval of our unitholders.

Transfer of Incentive Distribution Rights

At any time, our general partner may sell or transfer its incentive distribution rights to an affiliate or third party without the approval of the unitholders.

Change of Management Provisions

Our partnership agreement contains specific provisions that are intended to discourage a person or group from attempting to remove CNX Coal Resources GP LLC as our general partner or otherwise change our management. If any person or group other than our general partner and its affiliates acquires beneficial ownership of 20% or more of any class of units, that person or group loses voting rights on all of its units. This loss of voting rights does not apply to any person or group that acquires the units from our general partner or its affiliates and any transferees of that person or group who are notified by our general partner that they will not lose their voting rights or to any person or group who acquires the units with the prior approval of the board of directors of our general partner. Please read “—Withdrawal or Removal of Our General Partner.”

Limited Call Right

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

The purchase price in the event of this purchase is the greater of:

 

•

the highest cash price paid by either our general partner or any of its affiliates for any limited partner interests of the class purchased within the 90 days preceding the date on which our general partner first mails notice of its election to purchase those limited partner interests; and

 

•

the current market price calculated in accordance with our partnership agreement as of the date three business days before the date the notice is mailed.

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

 

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Possible Redemption of Ineligible Holders

If at any time our general partner determines, with the advice of counsel, that:

(i) the U.S. federal income tax status (or lack of proof of the U.S. federal income tax status) of one or more limited partners or their owners has or is reasonably likely to have a material adverse effect on the maximum applicable rates that can be charged to customers by us or our subsidiaries (a “rate eligibility trigger”), or

(ii) we or our subsidiaries are subject to any federal, state or local law or regulation that would create a substantial risk of cancellation or forfeiture of any property in which we have an interest based on the nationality, citizenship or other related status of one or more limited partners or their owners (a “citizenship eligibility trigger”),

then our general partner may adopt such amendments to our partnership agreement as it determines to be necessary or appropriate to:

(a) in the case of a rate eligibility trigger, obtain such proof of the U.S. federal income tax status of such limited partners and, to the extent relevant, their owners, as our general partner determines to be necessary or appropriate to reduce the risk of occurrence of a material adverse effect on the rates that can be charged to customers by us or our subsidiaries, or

(b) in the case of a citizenship eligibility trigger, obtain such proof of the nationality, citizenship or other related status of such limited partners and, to the extent relevant, their owners, as our general partner determines to be necessary or appropriate to eliminate or mitigate the risk of cancellation or forfeiture of any properties or interests therein.

Amendments adopted by our general partner may include provisions requiring all limited partners to certify as to their (and their owners’) status as eligible holders upon demand and on a regular basis, as determined by our general partner, and may require transferees of units to so certify prior to being admitted to our partnership as limited partners.

“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.

Amendments adopted by our general partner may provide that (i) any limited partner who fails to furnish, within a reasonable period, requested proof of its (and its owners’) status as an eligible holder or (ii) if upon receipt of such eligibility certificate or other requested information our general partner determines that a limited partner (or its owner) is not an eligible holder, the limited partner interests owned by such limited partner will be subject to redemption. In addition, our general partner will be substituted and treated as the owner of all limited partner interests owned by an ineligible holder.

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 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

 

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delivery of a promissory note, as determined by our general partner. Any such promissory note will bear interest at the rate of 5% annually and be payable in three equal annual installments of principal and accrued interest, commencing one year after the redemption date. Further, the units will not be entitled to any allocations of income or loss, distributions or voting rights while held by such unitholder.

Meetings; Voting

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

Our general partner does not anticipate that any meeting of unitholders will be called in the foreseeable future. Any action that is required or permitted to be taken by the unitholders may be taken either at a meeting of the unitholders or, if authorized by our general partner, without a meeting if consents in writing describing the action so taken are signed by holders of the number of units that would be necessary to authorize or take that action at a meeting where all limited partners were present and voted. Meetings of the unitholders may be called by our general partner or by unitholders owning at least 20% of the outstanding units of the class for which a meeting is proposed. Unitholders may vote either in person or by proxy at meetings. The holders of a majority in voting power of the outstanding units of the class or classes for which a meeting has been called, represented in person or by proxy, will constitute a quorum unless any action by the unitholders requires approval by holders of a greater percentage of the units, in which case the quorum will be the greater percentage. For all matters presented to the limited partners at a meeting at which a quorum is present for which no minimum or other vote of the limited partners is specifically required pursuant to our partnership agreement, the rules and regulations of any national securities exchange on which the common units are admitted to trading, or applicable law or pursuant to any regulation applicable to us or our partnership interests, a majority of the votes cast by the limited partners holding outstanding units will be deemed to constitute the act of all limited partners (with abstentions and broker non-votes being deemed to not have been cast with respect to such matter). On any matter where a minimum or other vote of limited partners is provided by any provision of our partnership agreement or required by the rules or regulations of any national securities exchange on which the common units are admitted to trading, or applicable law or pursuant to any regulation applicable to us or our partners interests, such minimum or other vote will be the vote of the limited partners required to approve such matter (with the effect of abstentions and broker non-votes to be determined based on the vote of the limited partners required to approve such matter, provided that if the effect of abstentions and broker non-votes is not specified by the applicable rule, regulation or law, and there is no prevailing interpretation of such effect, then abstentions and broker non-votes will be deemed not to have been cast with respect to such matter). The general partner interest does not entitle our general partner to any vote other than its rights as general partner under our partnership agreement, will not be entitled to vote on any action required or permitted to be taken by the unitholders and will not count toward or be considered outstanding when calculating required votes, determining the presence of a quorum, or for similar purposes.

Each record holder of a unit has a vote according to its percentage interest in us, although additional limited partner interests having special voting rights could be issued. Please read “—Issuance of Additional Partnership Interests.” However, if at any time any person or group, other than our general partner and its affiliates, a direct transferee of our general partner and its affiliates or a transferee of such direct transferee, who is notified by our general partner that it will not lose its voting rights, acquires, in the aggregate, beneficial ownership of 20% or more of any class of units then outstanding, that person or group will lose voting rights on all of its units and the units may not be voted on any matter and will not be considered to be outstanding when sending notices of a meeting of unitholders, calculating required votes, determining the presence of a quorum, or for other similar purposes. Common units held in nominee or street name account will be voted by the broker or other nominee in accordance with the instruction of the beneficial owner unless the arrangement between the beneficial owner and its nominee provides otherwise. Except as our partnership agreement otherwise provides, subordinated units will vote together with common units as a single class. Any notice, demand, request, report or

 

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proxy material required or permitted to be given or made to record holders of common units under our partnership agreement will be delivered to the record holder by us or by the transfer agent.

Status as Limited Partner

By transfer of common units in accordance with our partnership agreement, each transferee of common units shall be admitted as a limited partner with respect to the common units transferred when such transfer and admission is reflected in our register. Except as described under “—Limited Liability,” the common units will be fully paid, and unitholders will not be required to make additional contributions.

Indemnification

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

 

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our general partner;

 

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any departing general partner;

 

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any person who is or was an affiliate of our general partner or any departing general partner;

 

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any person who is or was a director, officer, managing member, manager, general partner, fiduciary or trustee of us or our subsidiaries, an affiliate of us or our subsidiaries or any entity set forth in the preceding three bullet points;

 

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any person who is or was serving as director, officer, managing member, manager, general partner, fiduciary or trustee of another person owing a fiduciary duty to us or any of our subsidiaries at the request of our general partner or any departing general partner or any of their affiliates, excluding any such person providing, on a fee-for-service basis, trustee, fiduciary of custodial services; and

 

•

any person designated by our general partner because such person’s status, service or relationship expose such person to potential claims or suits relating to our or our subsidiaries’ business and affairs.

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

Any expenses incurred by an indemnified person in connection with any indemnification will be advanced by us.

Reimbursement of Expenses

Our partnership agreement requires us 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 or otherwise incurred by our general partner and its affiliates in connection with managing and operating our business and affairs. These expenses include salary, bonus, incentive compensation and other amounts paid to persons who perform services for us or on our behalf and expenses allocated to our general partner by its affiliates. Our general partner is entitled to determine in good faith the expenses that are allocable to us. The expenses for which we are required to reimburse our general partner are not subject to any caps or other limits. Please read “Certain Relationships and Related Party Transactions—Agreements Governing the Transactions—Omnibus Agreement.”

 

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Books and Reports

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

We will mail or make available to record holders of common units, within 90 days after the close of each fiscal year, an annual report containing audited financial statements and a report on those financial statements by our independent registered public accounting firm. Except for our fourth quarter, we will also mail or make available summary financial information within 45 days after the close of each quarter (or such shorter period as required by the SEC).

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

Right to Inspect Our Books and Records

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

 

•

a current list of the name and last known address of each record holder;

 

•

copies of our partnership agreement and our certificate of limited partnership and all amendments thereto; and

 

•

certain information regarding the status of our business and financial condition.

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

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

Registration Rights

Under our partnership agreement, we have agreed to register for resale under the Securities Act and applicable state securities laws any common units, subordinated units or other partnership interests proposed to be sold by our general partner or any of its affiliates, other than individuals, or their assignees if an exemption from the registration requirements is not otherwise available. We are obligated to pay all expenses incidental to the registration, excluding underwriting discounts and commissions. Please read “Units Eligible for Future Sale.”

 

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Applicable Law; Exclusive Forum

Our partnership agreement is governed by Delaware law.

Our partnership agreement will provide that 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. Although we believe this provision benefits us by providing increased consistency in the application of Delaware law in the types of lawsuits to which it applies, the provision may have the effect of discouraging lawsuits against our directors and officers. The enforceability of similar choice of forum provisions in other companies’ certificates of incorporation or similar governing documents have been challenged in legal proceedings, and it is possible that, in connection with any action, a court could find the choice of forum provisions contained in our partnership agreement to be inapplicable or unenforceable in such action. 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, if such court does not have subject matter jurisdiction thereof, any other court located in the State of Delaware with subject matter jurisdiction) in connection with any such claims, suits, actions or proceedings.

 

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UNITS ELIGIBLE FOR FUTURE SALE

Following the completion of this offering and 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. All of the common units and subordinated units held by our sponsor are subject to lock-up restrictions described below. The sale of these units could have an adverse impact on the price of our common units or on any trading market that may develop.

Rule 144

The common units sold in this offering will generally be freely transferable without restriction or further registration under the Securities Act, other than any units purchased in this offering 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 the directed unit program, which will be subject to the lock-up restrictions described below. None of the directors or officers of our general partner own any common units prior to this offering; however, they may purchase common units through the directed unit program or otherwise. Additionally, any common units owned by an “affiliate” of ours may not be resold publicly except in compliance with the registration requirements of the Securities Act or under an exemption from the registration requirements pursuant to Rule 144 or otherwise. Rule 144 permits securities acquired by an affiliate to be sold into the market in an amount that does not exceed, during any three-month period, the greater of:

 

•

1.0% of the total number of our common units outstanding; or

 

•

the average weekly reported trading volume of our common units for the four weeks prior to the sale.

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

Our Partnership Agreement and Registration Rights

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. Any issuance of additional common units or other limited partner interests would result in a corresponding decrease in the proportionate ownership interest in us represented by, and could adversely affect the cash distributions to and market price of, common units then outstanding. Please read “Our Partnership Agreement—Issuance of Additional Partnership Interests.”

Under our partnership agreement, our general partner and its affiliates, other than individuals, have the right to cause us to register under the Securities Act and applicable state securities laws the offer and sale of any units that they hold. Subject to the terms and conditions of our partnership agreement, these registration rights allow our general partner and its affiliates or their assignees holding any common units or other limited partner interests to require registration of any of these common units or other limited partner interests and to include any

 

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of these common units or other limited partner interests in a registration by us of other partnership interests, including common units offered by us or by any unitholder. Our general partner and its affiliates will continue to have these registration rights for two years after CNX Coal Resources GP LLC ceases to be our general partner. In connection with any registration of this kind, we will indemnify each unitholder participating in the registration and its officers, directors and controlling persons from and against any liabilities under the Securities Act or any applicable state securities laws arising from the registration statement or prospectus. We will bear all costs and expenses incidental to any registration, excluding any underwriting discounts and commissions. Except as described below, our general partner and its affiliates may sell their common units or other limited partner interests in private transactions at any time, subject to compliance with applicable laws.

Lock-Up Agreements

Our general partner’s executive officers and directors, our general partner and our sponsor have agreed that for a period of 180 days from the date of this prospectus they will not, without the prior written consent of Merrill Lynch, Pierce, Fenner & Smith Incorporated dispose of any common units or any securities convertible into or exchangeable for our common units. Participants in our directed unit program who purchase $100,000 or more of common units under the program will be subject to similar restrictions for a period of 25 days from the date of this prospectus. Please read “Underwriting” for a description of these lock-up provisions.

Registration Statement on Form S-8

We intend to file a registration statement on Form S-8 under the Securities Act following this offering to register all common units issued or reserved for issuance under our LTIP. We expect to file this registration statement as soon as practicable. Common units covered by the registration statement on Form S-8 will be eligible for sale in the public market, subject to applicable vesting requirements and the terms of applicable lock-up agreements described above.

 

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MATERIAL FEDERAL INCOME TAX CONSEQUENCES

This section is a summary of the material tax considerations that may be relevant to prospective unitholders who are individual citizens or residents of the U.S. and, unless otherwise noted in the following discussion, is the opinion of Latham & Watkins LLP, counsel to our general partner and us, insofar as it relates to legal conclusions with respect to matters of U.S. federal income tax law. This section is based upon current provisions of the Internal Revenue Code of 1986, as amended (the “Internal Revenue Code”), existing and proposed Treasury regulations promulgated under the Internal Revenue Code (the “Treasury Regulations”) and current administrative rulings and court decisions, all of which are subject to change. Later changes in these authorities may cause the tax consequences to vary substantially from the consequences described below. Unless the context otherwise requires, references in this section to “us” or “we” are references to CNX Coal Resources LP and our operating subsidiaries.

The following discussion does not comment on all federal income tax matters affecting us or our unitholders and does not describe the application of the alternative minimum tax that may be applicable to certain unitholders. Moreover, the discussion focuses on unitholders who are individual citizens or residents of the U.S. and has only limited application to corporations, estates, entities treated as partnerships for U.S. federal income tax purposes, trusts, nonresident aliens, U.S. expatriates and former citizens or long-term residents of the United States or other unitholders subject to specialized tax treatment, such as banks, insurance companies and other financial institutions, tax-exempt institutions, foreign persons (including, without limitation, controlled foreign corporations, passive foreign investment companies and non-U.S. persons eligible for the benefits of an applicable income tax treaty with the United States), individual retirement accounts (IRAs), real estate investment trusts (REITs) or mutual funds, dealers in securities or currencies, traders in securities, U.S. persons whose “functional currency” is not the U.S. dollar, persons holding their units as part of a “straddle,” “hedge,” “conversion transaction” or other risk reduction transaction, and persons deemed to sell their units under the constructive sale provisions of the Internal Revenue Code. In addition, the discussion only comments to a limited extent on state, local and foreign tax consequences. Accordingly, we encourage each prospective unitholder to consult its own tax advisor in analyzing the state, local and foreign tax consequences particular to such unitholder of the ownership or disposition of common units and potential changes in applicable tax laws.

No ruling has been requested from the IRS regarding our characterization as a partnership for tax purposes. Instead, we will rely on opinions of Latham & Watkins LLP. Unlike a ruling, an opinion of counsel represents only that counsel’s best legal judgment and does not bind the Internal Revenue Service (the “IRS”) or the courts. Accordingly, the opinions and statements made herein may not be sustained by a court if contested by the IRS. Any contest of this sort with the IRS may materially and adversely impact the market for the common units and the prices at which common units trade. In addition, the costs of any contest with the IRS, principally legal, accounting and related fees, will result in a reduction in our distributable cash flow to our unitholders and our general partner and thus will be borne indirectly by our unitholders and our general partner. Furthermore, the tax treatment of us, or of an investment in us, may be significantly modified by future legislative or administrative changes or court decisions. Any modifications may or may not be retroactively applied.

All statements as to matters of federal income tax law and legal conclusions with respect thereto, but not as to factual matters, contained in this section, unless otherwise noted, are the opinion of Latham & Watkins LLP and are based on the accuracy of the representations made by us.

For the reasons described below, Latham & Watkins LLP has not rendered an opinion with respect to the following specific federal income tax issues: (i) the treatment of a unitholder whose common units are loaned to a short seller to cover a short sale of common units (please read “—Tax Consequences of Unit Ownership—Treatment of Short Sales”); (ii) whether our monthly convention for allocating taxable income and losses is permitted by existing Treasury Regulations (please read “—Disposition of Common Units—Allocations Between Transferors and Transferees”); and (iii) whether our method for taking into account Section 743 adjustments is sustainable in certain cases (please read “—Tax Consequences of Unit Ownership—Section 754 Election” and “—Uniformity of Units”).

 

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Partnership Status

A partnership is not a taxable entity and incurs no federal income tax liability. Instead, each partner of a partnership is required to take into account its share of items of income, gain, loss and deduction of the partnership in computing its federal income tax liability, regardless of whether cash distributions are made to the unitholder by the partnership. Distributions by a partnership to a partner are generally not taxable to the partnership or the partner unless the amount of cash distributed to the partner is in excess of the partner’s adjusted basis in its partnership interest. Section 7704 of the Internal Revenue Code provides that publicly traded partnerships will, as a general rule, be taxed as corporations. However, an exception, referred to as the “Qualifying Income Exception,” exists with respect to publicly traded partnerships of which 90% or more of the gross income for every taxable year consists of “qualifying income.” Qualifying income includes income and gains derived from the mining or production, processing, transportation, and marketing of any mineral or natural resource, including coal. Other types of qualifying income include interest (other than from a financial business), dividends, gains from the sale or other disposition of real property and gains from the sale or other disposition of capital assets held for the production of income that otherwise constitutes qualifying income. We estimate that less than     % of our current gross income is not qualifying income; however, this estimate could change from time to time. Based upon and subject to this estimate, the factual representations made by us and our general partner and a review of the applicable legal authorities, Latham & Watkins LLP is of the opinion that at least 90% of our current gross income constitutes qualifying income. The portion of our income that is qualifying income may change from time to time.

The IRS has made no determination as to our status or the status of our operating subsidiaries for federal income tax purposes or whether our operations generate “qualifying income” under Section 7704 of the Internal Revenue Code. Instead, we will rely on the opinion of Latham & Watkins LLP on such matters. It is the opinion of Latham & Watkins LLP that, based upon the Internal Revenue Code, its regulations, published revenue rulings and court decisions and the representations described below that:

 

•

We will be classified as a partnership for federal income tax purposes; and

 

•

Each of our operating subsidiaries will be treated as a partnership or will be disregarded as an entity separate from us for federal income tax purposes.

In rendering its opinion, Latham & Watkins LLP has relied on factual representations made by us and our general partner. The representations made by us and our general partner upon which Latham & Watkins LLP has relied include:

 

•

Neither we nor any of the operating subsidiaries has elected or will elect to be treated as a corporation; and

 

•

For each taxable year, more than 90% of our gross income has been and will be income of the type that Latham & Watkins LLP has opined or will opine is “qualifying income” within the meaning of Section 7704(d) of the Internal Revenue Code.

We believe that these representations have been true in the past and expect that these representations will continue to be true in the future.

If we fail to meet the Qualifying Income Exception, other than a failure that is determined by the IRS to be inadvertent and that is cured within a reasonable time after discovery (in which case the IRS may also require us to make adjustments with respect to our unitholders or pay other amounts), we will be treated as if we had transferred all of our assets, subject to liabilities, to a newly formed corporation, on the first day of the year in which we fail to meet the Qualifying Income Exception, in return for stock in that corporation, and then distributed that stock to the unitholders in liquidation of their interests in us. This deemed contribution and

 

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liquidation should be tax-free to unitholders and us so long as we, at that time, do not have liabilities in excess of the tax basis of our assets. Thereafter, we would be treated as a corporation for federal income tax purposes.

If we were treated as an association taxable as a corporation in any taxable year, either as a result of a failure to meet the Qualifying Income Exception or otherwise, our items of income, gain, loss and deduction would be reflected only on our tax return rather than being passed through to our unitholders, and our net income would be taxed to us at corporate rates. In addition, any distribution made to a unitholder would be treated as taxable dividend income, to the extent of our current and accumulated earnings and profits, or, in the absence of earnings and profits, a nontaxable return of capital, to the extent of the unitholder’s tax basis in its common units, or taxable capital gain, after the unitholder’s tax basis in its common units is reduced to zero. Accordingly, taxation as a corporation would result in a material reduction in a unitholder’s cash flow and after-tax return and thus would likely result in a substantial reduction of the value of the units.

The discussion below is based on Latham & Watkins LLP’s opinion that we will be classified as a partnership for federal income tax purposes.

Limited Partner Status

Unitholders of CNX Coal Resources LP will be treated as partners of CNX Coal Resources LP for federal income tax purposes. Also, unitholders whose common units are held in street name or by a nominee and who have the right to direct the nominee in the exercise of all substantive rights attendant to the ownership of their common units will be treated as partners of CNX Coal Resources LP for federal income tax purposes.

A beneficial owner of common units whose units have been transferred to a short seller to complete a short sale would appear to lose its status as a partner with respect to those units for federal income tax purposes. Please read “—Tax Consequences of Unit Ownership—Treatment of Short Sales.”

Income, gains, losses or deductions would not appear to be reportable by a unitholder who is not a partner for federal income tax purposes, and any cash distributions received by a unitholder who is not a partner for federal income tax purposes would therefore appear to be fully taxable as ordinary income. These holders are urged to consult their tax advisors with respect to the tax consequences to them of holding common units in CNX Coal Resources LP. The references to “unitholders” in the discussion that follows are to persons who are treated as partners in CNX Coal Resources LP for federal income tax purposes.

Tax Consequences of Unit Ownership

Flow-Through of Taxable Income

Subject to the discussion below under “—Tax Consequences of Unit Ownership—Entity-Level Collections” we will not pay any federal income tax. Instead, each unitholder will be required to report on its income tax return its share of our income, gains, losses and deductions without regard to whether we make cash distributions to such unitholder. Consequently, we may allocate income to a unitholder even if such unitholder has not received a cash distribution. Each unitholder will be required to include in income its allocable share of our income, gains, losses and deductions for our taxable year ending with or within its taxable year. Our taxable year ends on December 31.

Treatment of Distributions

Distributions by us to a unitholder generally will not be taxable to the unitholder for federal income tax purposes, except to the extent the amount of any such cash distribution exceeds its tax basis in its common units immediately before the distribution. Our cash distributions in excess of a unitholder’s tax basis generally will be considered to be gain from the sale or exchange of the common units, taxable in accordance with the rules

 

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described under “—Disposition of Common Units.” Any reduction in a unitholder’s share of our liabilities for which no partner, including the general partner, bears the economic risk of loss, known as “nonrecourse liabilities,” will be treated as a distribution by us of cash to that unitholder. To the extent our distributions cause a unitholder’s “at risk” amount to be less than zero at the end of any taxable year, it must recapture any losses deducted in previous years. Please read “—Tax Consequences of Unit Ownership—Limitations on Deductibility of Losses.”

A decrease in a unitholder’s percentage interest in us because of our issuance of additional common units will decrease its share of our nonrecourse liabilities, and thus will result in a corresponding deemed distribution of cash. This deemed distribution may constitute a non-pro rata distribution. A non-pro rata distribution of money or property may result in ordinary income to a unitholder, regardless of its tax basis in its common units, if the distribution reduces the unitholder’s share of our “unrealized receivables,” including depreciation recapture and/or substantially appreciated “inventory items,” each as defined in the Internal Revenue Code, and collectively, “Section 751 Assets.” To that extent, the unitholder will be treated as having been distributed its proportionate share of the Section 751 Assets and then having exchanged those assets with us in return for the non-pro rata portion of the actual distribution made to such unitholder. This latter deemed exchange will generally result in the unitholder’s realization of ordinary income, which will equal the excess of (1) the non-pro rata portion of that distribution over (2) the unitholder’s tax basis (often zero) for the share of Section 751 Assets deemed relinquished in the exchange.

Ratio of Taxable Income to Distributions

We estimate that a purchaser of common units in this offering who owns those common units from the date of closing of this offering through the record date for distributions for the period ending December 31, 2018, 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 with respect to that period. Thereafter, we anticipate that the ratio of allocable taxable income to cash distributions to the unitholders will increase. Our estimate is based upon many assumptions regarding our business operations, including assumptions as to our revenues, capital expenditures, cash flow, net working capital and anticipated cash distributions. These estimates and assumptions are subject to, among other things, numerous business, economic, regulatory, legislative, competitive and political uncertainties beyond our control. Further, the estimates are based on current tax law and tax reporting positions that we will adopt and with which the IRS could disagree. Accordingly, we cannot assure you that these estimates will prove to be correct.

The actual percentage of distributions that will constitute taxable income could be higher or lower than expected, and any differences could be material and could materially affect the value of the common units. For example, the ratio of allocable taxable income to cash distributions to a purchaser of common units in this offering will be greater, and perhaps substantially greater, than our estimate with respect to the period described above if:

 

•

gross income from operations exceeds the amount required to make minimum quarterly distributions on all units, yet we only distribute the minimum quarterly distributions on all units;

 

•

we make a future offering of common units and use the proceeds of the offering in a manner that does not produce substantial additional deductions during the period described above, such as to repay indebtedness outstanding at the time of this offering or to acquire property that is not eligible for depreciation or amortization for federal income tax purposes or that is depreciable or amortizable at a rate significantly slower than the rate applicable to our assets at the time of this offering; or

 

•

legislation is passed that would limit or repeal certain federal income tax preferences currently available with respect to coal exploration and development.

 

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Basis of Common Units

A unitholder’s initial tax basis for its common units will be the amount it paid for the common units plus its share of our nonrecourse liabilities. That basis will be increased by its share of our income and by any increases in its share of our nonrecourse liabilities. That basis will be decreased, but not below zero, by distributions from us, by the unitholder’s share of our losses, by any decreases in its share of our nonrecourse liabilities and by its share of our expenditures that are not deductible in computing taxable income and are not required to be capitalized. A unitholder will have no share of our debt that is recourse to our general partner to the extent of the general partner’s “net value” as defined in Treasury Regulations under Section 752 of the Internal Revenue Code, but will have a share, generally based on its share of profits, of our nonrecourse liabilities. Please read “—Disposition of Common Units—Recognition of Gain or Loss.”

Limitations on Deductibility of Losses

The deduction by a unitholder of its share of our losses will be limited to the tax basis in its units and, in the case of an individual unitholder, estate, trust, or corporate unitholder (if more than 50% of the value of the corporate unitholder’s stock is owned directly or indirectly by or for five or fewer individuals or some tax-exempt organizations) to the amount for which the unitholder is considered to be “at risk” with respect to our activities, if that is less than its tax basis. A common unitholder subject to these limitations must recapture losses deducted in previous years to the extent that distributions cause its at risk amount to be less than zero at the end of any taxable year. Losses disallowed to a unitholder or recaptured as a result of these limitations will carry forward and will be allowable as a deduction to the extent that its at risk amount is subsequently increased, provided such losses do not exceed such common unitholder’s tax basis in its common units. Upon the taxable disposition of a unit, any gain recognized by a unitholder can be offset by losses that were previously suspended by the at risk limitation but may not be offset by losses suspended by the basis limitation. Any loss previously suspended by the at risk limitation in excess of that gain would no longer be utilizable.

In general, a unitholder will be at risk to the extent of the tax basis of its units, excluding any portion of that basis attributable to its share of our nonrecourse liabilities, reduced by (1) any portion of that basis representing amounts otherwise protected against loss because of a guarantee, stop loss agreement or other similar arrangement and (2) any amount of money it borrows to acquire or hold its units, if the lender of those borrowed funds owns an interest in us, is related to the unitholder or can look only to the units for repayment. A unitholder’s at risk amount will increase or decrease as the tax basis of the unitholder’s units increases or decreases, other than tax basis increases or decreases attributable to increases or decreases in its share of our nonrecourse liabilities.

In addition to the basis and at risk limitations on the deductibility of losses, the passive loss limitations generally provide that individuals, estates, trusts and some closely-held corporations and personal service corporations can deduct losses from passive activities, which are generally trade or business activities in which the taxpayer does not materially participate, only to the extent of the taxpayer’s income from those passive activities. The passive loss limitations are applied separately with respect to each publicly traded partnership. Consequently, any passive losses we generate will only be available to offset our passive income generated in the future and will not be available to offset income from other passive activities or investments, including our investments or a unitholder’s investments in other publicly traded partnerships, or the unitholder’s salary, active business or other income. Passive losses that are not deductible because they exceed a unitholder’s share of income we generate may be deducted in full when it disposes of its entire investment in us in a fully taxable transaction with an unrelated party. The passive loss limitations are applied after other applicable limitations on deductions, including the at risk rules and the basis limitation.

A unitholder’s share of our net income may be offset by any of our suspended passive losses, but it may not be offset by any other current or carryover losses from other passive activities, including those attributable to other publicly traded partnerships.

 

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Limitations on Interest Deductions

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

 

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interest on indebtedness properly allocable to property held for investment;

 

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our interest expense attributed to portfolio income; and

 

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the portion of interest expense incurred to purchase or carry an interest in a passive activity to the extent attributable to portfolio income.

The computation of a unitholder’s investment interest expense will take into account interest on any margin account borrowing or other loan incurred to purchase or carry a unit. Net investment income includes gross income from property held for investment and amounts treated as portfolio income under the passive loss rules, less deductible expenses, other than interest, directly connected with the production of investment income, but generally does not include gains attributable to the disposition of property held for investment or (if applicable) qualified dividend income. The IRS has indicated that the net passive income earned by a publicly traded partnership will be treated as investment income to its unitholders. In addition, the unitholder’s share of our portfolio income will be treated as investment income.

Entity-Level Collections

If we are required or elect under applicable law to pay any federal, state, local or foreign income tax on behalf of any unitholder or our general partner or any former unitholder, we are authorized to pay those taxes from our funds. That payment, if made, will be treated as a distribution of cash to the unitholder on whose behalf the payment was made. If the payment is made on behalf of a person whose identity cannot be determined, we are authorized to treat the payment as a distribution to all current unitholders. We are authorized to amend our partnership agreement in the manner necessary to maintain uniformity of intrinsic tax characteristics of units and to adjust later distributions, so that after giving effect to these distributions, the priority and characterization of distributions otherwise applicable under our partnership agreement is maintained as nearly as is practicable. Payments by us as described above could give rise to an overpayment of tax on behalf of an individual unitholder in which event the unitholder would be required to file a claim in order to obtain a credit or refund.

Allocation of Income, Gain, Loss and Deduction

In general, if we have a net profit, our items of income, gain, loss and deduction will be allocated among our general partner and the unitholders in accordance with their percentage interests in us. At any time that distributions are made to the common units in excess of distributions to the subordinated units, or incentive distributions are made to our general partner, gross income will be allocated to the recipients to the extent of these distributions. If we have a net loss, that loss will be allocated first to our general partner and the unitholders in accordance with their percentage interests in us to the extent of their positive capital accounts, as adjusted to take into account the unitholders’ share of nonrecourse debt, and, second, to our general partner.

Specified items of our income, gain, loss and deduction will be allocated to account for (1) any difference between the tax basis and fair market value of our assets at the time of this offering and (2) any difference between the tax basis and fair market value of any property contributed to us by our general partner and its affiliates (or by a third party) that exists at the time of such contribution, together referred to in this discussion as the “Contributed Property.” The effect of these allocations, referred to as “Section 704(c) Allocations,” to a unitholder purchasing common units from us in this offering will be essentially the same as if the tax bases of our assets were equal to their fair market values at the time of this offering. In the event we issue additional common units or engage in certain other transactions in the future, “reverse Section 704(c)

 

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Allocations,” similar to the Section 704(c) Allocations described above, will be made to the general partner and all of our unitholders immediately prior to such issuance or other transactions to account for the difference between the “book” basis for purposes of maintaining capital accounts and the fair market value of all property held by us at the time of such issuance or future transaction. In addition, items of recapture income will be allocated to the extent possible to the unitholder who was allocated the deduction giving rise to the treatment of that gain as recapture income in order to minimize the recognition of ordinary income by some unitholders. Finally, although we do not expect that our operations will result in the creation of negative capital accounts, if negative capital accounts nevertheless result, items of our income and gain will be allocated in an amount and manner sufficient to eliminate the negative balance as quickly as possible.

An allocation of items of our income, gain, loss or deduction, other than an allocation required by the Internal Revenue Code to eliminate the difference between a partner’s “book” capital account, credited with the fair market value of Contributed Property, and “tax” capital account, credited with the tax basis of Contributed Property, referred to in this discussion as the “Book-Tax Disparity,” will generally be given effect for federal income tax purposes in determining a partner’s share of an item of income, gain, loss or deduction only if the allocation has “substantial economic effect.” In any other case, a partner’s share of an item will be determined on the basis of its interest in us, which will be determined by taking into account all the facts and circumstances, including:

 

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its relative contributions to us;

 

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the interests of all the partners in profits and losses;

 

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the interest of all the partners in cash flow; and

 

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the rights of all the partners to distributions of capital upon liquidation.

Latham & Watkins LLP is of the opinion that, with the exception of the issues described in “—Tax Consequences of Unit Ownership—Section 754 Election” and “—Disposition of Common Units—Allocations Between Transferors and Transferees,” allocations under our partnership agreement will be given effect for federal income tax purposes in determining a partner’s share of an item of income, gain, loss or deduction.

Treatment of Short Sales

A unitholder whose units are loaned to a “short seller” to cover a short sale of units may be considered as having disposed of those units. If so, it would no longer be treated for tax purposes as a partner with respect to those units during the period of the loan and may recognize gain or loss from the disposition. As a result, during this period:

 

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any of our income, gain, loss or deduction with respect to those units would not be reportable by the unitholder;

 

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any cash distributions received by the unitholder as to those units would be fully taxable; and

 

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while not entirely free from doubt, all of these distributions would appear to be ordinary income.

Because there is no direct or indirect controlling authority on the issue relating to partnership interests, Latham & Watkins LLP has not rendered an opinion regarding the tax treatment of a unitholder whose common units are loaned to a short seller to cover a short sale of common units; therefore, unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a loan to a short seller are urged to consult a tax advisor to discuss whether it is advisable to modify any applicable brokerage account agreements to prohibit their brokers from borrowing and loaning their units. The IRS has previously announced that it is studying issues relating to the tax treatment of short sales of partnership interests. Please also read “—Disposition of Common Units—Recognition of Gain or Loss.”

 

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Tax Rates

Under current law, the highest marginal U.S. federal income tax rate applicable to ordinary income of individuals is 39.6% and the highest marginal U.S. federal income tax rate applicable to long-term capital gains (generally, capital gains on certain assets held for more than twelve months) of individuals is 20%. Such rates are subject to change by new legislation at any time.

In addition, a 3.8% Medicare tax, or NIIT, is imposed on certain net investment income earned by individuals, estates and trusts. For these purposes, net investment income generally includes a unitholder’s allocable share of our income and gain realized by a unitholder from a sale of units. In the case of an individual, the tax will be imposed on the lesser of (1) the unitholder’s net investment income and (2) the amount by which the unitholder’s modified adjusted gross income exceeds $250,000 (if the unitholder is married and filing jointly or a surviving spouse), $125,000 (if the unitholder is married and filing separately) or $200,000 (in any other case). In the case of an estate or trust, the tax will be imposed on the lesser of (1) undistributed net investment income and (2) the excess adjusted gross income over the dollar amount at which the highest income tax bracket applicable to an estate or trust begins. The U.S. Department of the Treasury and the IRS have issued Treasury Regulations that provide guidance regarding the NIIT. Prospective unitholders are urged to consult with their tax advisors as to the impact of the NIIT on an investment in our common units.

Section 754 Election

We will make the election permitted by Section 754 of the Internal Revenue Code. That election is irrevocable without the consent of the IRS unless there is a constructive termination of the partnership. Please read “—Disposition of Common Units—Constructive Termination.” The election will generally permit us to adjust a common unit purchaser’s tax basis in our assets (“inside basis”) under Section 743(b) of the Internal Revenue Code to reflect its purchase price. This election does not apply with respect to a person who purchases common units directly from us. The Section 743(b) adjustment belongs to the purchaser and not to other unitholders. For purposes of this discussion, the inside basis in our assets with respect to a unitholder will be considered to have two components: (1) its share of our tax basis in our assets (“common basis”) and (2) its Section 743(b) adjustment to that basis.

We will adopt the remedial allocation method as to all our properties. Where the remedial allocation method is adopted, the Treasury Regulations under Section 743 of the Internal Revenue Code require a portion of the Section 743(b) adjustment that is attributable to recovery property that is subject to depreciation under Section 168 of the Internal Revenue Code and whose book basis is in excess of its tax basis to be depreciated over the remaining cost recovery period for the property’s unamortized Book-Tax Disparity. Under Treasury Regulation Section 1.167(c)-1(a)(6), a Section 743(b) adjustment attributable to property subject to depreciation under Section 167 of the Internal Revenue Code, rather than cost recovery deductions under Section 168, is generally required to be depreciated using either the straight-line method or the 150% declining balance method. Under our partnership agreement, our general partner is authorized to take a position to preserve the uniformity of units even if that position is not consistent with these and any other Treasury Regulations. Please read “—Uniformity of Units.”

We intend to depreciate the portion of a Section 743(b) adjustment attributable to unrealized appreciation in the value of Contributed Property, to the extent of any unamortized Book-Tax Disparity, using a rate of depreciation or amortization derived from the depreciation or amortization method and useful life applied to the property’s unamortized Book-Tax Disparity, or treat that portion as non-amortizable to the extent attributable to property which is not amortizable. This method is consistent with the methods employed by other publicly traded partnerships but is arguably inconsistent with Treasury Regulation Section 1.167(c)-1(a)(6), which is not expected to directly apply to a material portion of our assets. To the extent this Section 743(b) adjustment is attributable to appreciation in value in excess of the unamortized Book-Tax Disparity, we will apply the rules described in the Treasury Regulations and legislative history. If we determine that this position

 

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cannot reasonably be taken, we may take a depreciation or amortization position under which all purchasers acquiring units in the same month would receive depreciation or amortization, whether attributable to common basis or a Section 743(b) adjustment, based upon the same applicable rate as if they had purchased a direct interest in our assets. This kind of aggregate approach may result in lower annual depreciation or amortization deductions than would otherwise be allowable to some unitholders. Please read “—Uniformity of Units.” A unitholder’s tax basis for its common units is reduced by its share of our deductions (whether or not such deductions were claimed on an individual’s income tax return) so that any position we take that understates deductions will overstate the common unitholder’s basis in its common units, which may cause the unitholder to understate gain or overstate loss on any sale of such units. Please read “—Disposition of Common Units—Recognition of Gain or Loss.” Latham & Watkins LLP is unable to opine as to whether our method for taking into account Section 743 adjustments is sustainable for property subject to depreciation under Section 167 of the Internal Revenue Code or if we use an aggregate approach as described above, as there is no direct or indirect controlling authority addressing the validity of these positions. Moreover, the IRS may challenge our position with respect to depreciating or amortizing the Section 743(b) adjustment we take to preserve the uniformity of the units. If such a challenge were sustained, the gain from the sale of units might be increased without the benefit of additional deductions.

A Section 754 election is advantageous if the transferee’s tax basis in its units is higher than the units’ share of the aggregate tax basis of our assets immediately prior to the transfer. In that case, as a result of the election, the transferee would have, among other items, a greater amount of depreciation deductions and its share of any gain or loss on a sale of our assets would be less. Conversely, a Section 754 election is disadvantageous if the transferee’s tax basis in its units is lower than those units’ share of the aggregate tax basis of our assets immediately prior to the transfer. Thus, the fair market value of the units may be affected either favorably or unfavorably by the election. A basis adjustment is required regardless of whether a Section 754 election is made in the case of a transfer of an interest in us if we have a substantial built-in loss immediately after the transfer, or if we distribute property and have a substantial basis reduction. Generally, a built-in loss or a basis reduction is substantial if it exceeds $250,000.

The calculations involved in the Section 754 election are complex and will be made on the basis of assumptions as to the value of our assets and other matters. For example, the allocation of the Section 743(b) adjustment among our assets must be made in accordance with the Internal Revenue Code. The IRS could seek to reallocate some or all of any Section 743(b) adjustment allocated by us to our tangible assets to goodwill instead. Goodwill, as an intangible asset, is generally nonamortizable or amortizable over a longer period of time or under a less accelerated method than our tangible assets. We cannot assure you that the determinations we make will not be successfully challenged by the IRS and that the deductions resulting from them will not be reduced or disallowed altogether. Should the IRS require a different basis adjustment to be made, and should, in our opinion, the expense of compliance exceed the benefit of the election, we may seek permission from the IRS to revoke our Section 754 election. If permission is granted, a subsequent purchaser of units may be allocated more income than it would have been allocated had the election not been revoked.

Tax Treatment of Operations

Accounting Method and Taxable Year

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

 

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Initial Tax Basis, Depreciation and Amortization

The tax basis of our assets will be used for purposes of computing depreciation and cost recovery deductions and, ultimately, gain or loss on the disposition of these assets. The federal income tax burden associated with the difference between the fair market value of our assets and their tax basis immediately prior to (1) this offering will be borne by our general partner and its affiliates, and (2) any other offering will be borne by our general partner and all of our unitholders as of that time. Please read “—Tax Consequences of Unit Ownership—Allocation of Income, Gain, Loss and Deduction.”

To the extent allowable, we may elect to use the depreciation and cost recovery methods, including bonus depreciation to the extent available, that will result in the largest deductions being taken in the early years after assets subject to these allowances are placed in service. Please read “—Uniformity of Units.” Property we subsequently acquire or construct may be depreciated using accelerated methods permitted by the Internal Revenue Code.

If we dispose of depreciable property by sale, foreclosure or otherwise, all or a portion of any gain, determined by reference to the amount of depreciation previously deducted and the nature of the property, may be subject to the recapture rules and taxed as ordinary income rather than capital gain. Similarly, a unitholder who has taken cost recovery or depreciation deductions with respect to property we own will likely be required to recapture some or all of those deductions as ordinary income upon a sale of its interest in us. Please read “—Tax Consequences of Unit Ownership—Allocation of Income, Gain, Loss and Deduction” and “—Disposition of Common Units—Recognition of Gain or Loss.”

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

Valuation and Tax Basis of Our Properties

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

Coal Depletion

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

Depletion deductions we claim generally will reduce the tax basis of the underlying mineral property. Depletion deductions can, however, exceed the total tax basis of the mineral property. The excess of our percentage depletion deductions over the adjusted tax basis of the property at the end of the taxable year is subject to tax preference treatment in computing the alternative minimum tax. Upon the disposition of the mineral property, a portion of the gain, if any, equal to the lesser of the deductions for depletion which reduce the adjusted tax basis of the mineral property plus deductible development and mining exploration expenses (discussed below), or the amount of gain recognized upon the disposition, will be treated as ordinary income to

 

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us. In addition, a corporate unitholder’s allocable share of the amount allowable as a percentage depletion deduction for any property will be reduced by 20% of the excess, if any, of that partner’s allocable share of the amount of the percentage depletion deductions for the taxable year over the adjusted tax basis of the mineral property as of the close of the taxable year.

Mining Exploration and Development Expenditures

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

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

We generally elect to defer mine development expenses, consisting of expenditures incurred in making coal accessible for extraction, after the exploration process has disclosed the existence of coal in commercially marketable quantities, and deduct them on a ratable basis as the coal benefited by the expenses is sold.

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

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

Sales of Coal Reserves

If any coal reserves are sold or otherwise disposed of in a taxable transaction, we will recognize gain or loss measured by the difference between the amount realized (including the amount of any indebtedness assumed by the purchaser upon such disposition or to which such property is subject) and the adjusted tax basis of the property sold. Generally, the character of any gain or loss recognized upon that disposition will depend upon whether our coal reserves or the mined coal sold are held by us:

 

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for sale to customers in the ordinary course of business (i.e., we are a “dealer” with respect to that property);

 

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for use in a trade or business within the meaning of Section 1231 of the Internal Revenue Code; or

 

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as a capital asset within the meaning of Section 1221 of the Internal Revenue Code.

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

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

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

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

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

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

Deduction for U.S. Production Activities

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

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receipts, and a share of other deductions, expenses and losses that are not directly allocable to those receipts or another class of income. The products produced must be manufactured, produced, grown or extracted in whole or in significant part by the taxpayer in the United States.

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

The amount of a unitholder’s Section 199 deduction for each year is limited to 50% of the IRS Form W-2 wages actually or deemed paid by the unitholder during the calendar year that are deducted in arriving at qualified production activities income. Each unitholder is treated as having been allocated IRS Form W-2 wages from us equal to the unitholder’s allocable share of our wages that are deducted in arriving at qualified production activities income for that taxable year.

It is not anticipated that we or our subsidiaries will pay material wages that will be allocated to our unitholders, and thus a unitholder’s ability to claim the Section 199 deduction may be limited.

Disposition of Common Units

Recognition of Gain or Loss

Gain or loss will be recognized on a sale of units equal to the difference between the amount realized and the unitholder’s tax basis for the units sold. A unitholder’s amount realized will be measured by the sum of the cash or the fair market value of other property received by such unitholder plus its share of our nonrecourse liabilities. Because the amount realized includes a unitholder’s share of our nonrecourse liabilities, the gain recognized on the sale of units could result in a tax liability in excess of any cash received from the sale.

Prior distributions from us that in the aggregate were in excess of cumulative net taxable income for a common unit and, therefore, decreased a unitholder’s tax basis in that common unit will, in effect, become taxable income if the common unit is sold at a price greater than the unitholder’s tax basis in that common unit, even if the price received is less than its original cost.

Except as noted below, gain or loss recognized by a unitholder, other than a “dealer” in units, on the sale or exchange of a unit will generally be taxable as capital gain or loss. Capital gain recognized by an individual on the sale of units held for more than twelve months will generally be taxed at the U.S. federal income tax rate applicable to long-term capital gains. However, a portion of this gain or loss, which will likely be substantial, will be separately computed and taxed as ordinary income or loss under Section 751 of the Internal Revenue Code to the extent attributable to assets giving rise to depreciation recapture or other “unrealized receivables” or to “inventory items” we own. The term “unrealized receivables” includes potential recapture items, including depreciation and depletion recapture. Ordinary income attributable to unrealized receivables, inventory items, depreciation and depletion recapture may exceed net taxable gain realized upon the sale of a unit and may be recognized even if there is a net taxable loss realized on the sale of a unit. Thus, a unitholder may recognize both ordinary income and a capital loss upon a sale of units. Capital losses may offset capital gains and no more than $3,000 of ordinary income, in the case of individuals, and may only be used to offset capital gains in the case of corporations. Both ordinary income and capital gain recognized on a sale of units may be subject to the NIIT in certain circumstances. Please read “—Tax Consequences of Unit Ownership—Tax Rates.”

 

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The IRS has ruled that a partner who acquires interests in a partnership in separate transactions must combine those interests and maintain a single adjusted tax basis for all those interests. Upon a sale or other disposition of less than all of those interests, a portion of that tax basis must be allocated to the interests sold using an “equitable apportionment” method, which generally means that the tax basis allocated to the interest sold equals an amount that bears the same relation to the partner’s tax basis in its entire interest in the partnership as the value of the interest sold bears to the value of the partner’s entire interest in the partnership. Treasury Regulations under Section 1223 of the Internal Revenue Code allow a selling unitholder who can identify common units transferred with an ascertainable holding period to elect to use the actual holding period of the common units transferred. Thus, according to the ruling discussed above, a common unitholder will be unable to select high or low basis common units to sell as would be the case with corporate stock, but, according to the Treasury Regulations, it may designate specific common units sold for purposes of determining the holding period of units transferred. A unitholder electing to use the actual holding period of common units transferred must consistently use that identification method for all subsequent sales or exchanges of common units. A unitholder considering the purchase of additional units or a sale of common units purchased in separate transactions is urged to consult its tax advisor as to the possible consequences of this ruling and application of the Treasury Regulations.

Specific provisions of the Internal Revenue Code affect the taxation of some financial products and securities, including partnership interests, by treating a taxpayer as having sold an “appreciated” partnership interest, one in which gain would be recognized if it were sold, assigned or terminated at its fair market value, if the taxpayer or related persons enter(s) into:

 

•

a short sale;

 

•

an offsetting notional principal contract; or

 

•

a futures or forward contract;

in each case, with respect to the partnership interest or substantially identical property.

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

Allocations Between Transferors and Transferees

In general, our taxable income and losses will be determined annually, will be prorated on a monthly basis and will be subsequently apportioned among the unitholders in proportion to the number of units owned by each of them as of the opening of the applicable exchange on the first business day of the month, which we refer to in this prospectus as the “Allocation Date.” However, gain or loss realized on a sale or other disposition of our assets other than in the ordinary course of business will be allocated among the unitholders on the Allocation Date in the month in which that gain or loss is recognized. As a result, a unitholder transferring units may be allocated income, gain, loss and deduction realized after the date of transfer.

Although simplifying conventions are contemplated by the Internal Revenue Code and most publicly traded partnerships use similar simplifying conventions, the use of this method may not be permitted under existing Treasury Regulations as there is no direct or indirect controlling authority on this issue. The U.S. Treasury Department has issued proposed Treasury Regulations that provide a safe harbor pursuant to which a publicly traded partnership may use a similar monthly simplifying convention to allocate tax items among

 

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transferor and transferee unitholders, although such tax items must be prorated on a daily basis. Existing publicly traded partnerships are entitled to rely on these proposed Treasury Regulations; however, they are not binding on the IRS and are subject to change until final Treasury Regulations are issued. Accordingly, Latham & Watkins LLP is unable to opine on the validity of this method of allocating income and deductions between transferor and transferee unitholders because the issue has not been finally resolved by the IRS or the courts. If this method is not allowed under the Treasury Regulations, or only applies to transfers of less than all of the unitholder’s interest, our taxable income or losses might be reallocated among the unitholders. We are authorized to revise our method of allocation between transferor and transferee unitholders, as well as unitholders whose interests vary during a taxable year, to conform to a method permitted under future Treasury Regulations. A unitholder who owns units at any time during a quarter and who disposes of them prior to the record date set for a cash distribution for that quarter will be allocated items of our income, gain, loss and deductions attributable to that quarter through the month of disposition but will not be entitled to receive that cash distribution.

Notification Requirements

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

Constructive Termination

We will be considered to have technically terminated our partnership for federal income tax purposes if there is a sale or exchange of 50% or more of the total interests in our capital and profits within a twelve-month period. For purposes of determining whether the 50% threshold has been met, multiple sales of the same interest will be counted only once. Immediately after this initial public offering our sponsor and our general partner will collectively own     % of the total interests 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 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 its 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 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.

Uniformity of Units

Because we cannot match transferors and transferees of units, we must maintain uniformity of the economic and tax characteristics of the units to a purchaser of these units. In the absence of uniformity, we may

 

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be unable to completely comply with a number of federal income tax requirements, both statutory and regulatory. A lack of uniformity can result from a literal application of Treasury Regulation Section 1.167(c)-1(a)(6). Any non-uniformity could have a negative impact on the value of the units. Please read “—Tax Consequences of Unit Ownership—Section 754 Election.” We intend to depreciate the portion of a Section 743(b) adjustment attributable to unrealized appreciation in the value of Contributed Property, to the extent of any unamortized Book-Tax Disparity, using a rate of depreciation or amortization derived from the depreciation or amortization method and useful life applied to the property’s unamortized Book-Tax Disparity, or treat that portion as nonamortizable, to the extent attributable to property the common basis of which is not amortizable, consistent with the regulations under Section 743 of the Internal Revenue Code, even though that position may be inconsistent with Treasury Regulation Section 1.167(c)-1(a)(6), which is not expected to directly apply to a material portion of our assets.

Please read “—Tax Consequences of Unit Ownership—Section 754 Election.” To the extent that the Section 743(b) adjustment is attributable to appreciation in value in excess of the unamortized Book-Tax Disparity, we will apply the rules described in the Treasury Regulations and legislative history. If we determine that this position cannot reasonably be taken, we may adopt a depreciation and amortization position under which all purchasers acquiring units in the same month would receive depreciation and amortization deductions, whether attributable to common basis or a Section 743(b) adjustment, based upon the same applicable rate as if they had purchased a direct interest in our assets. If this position is adopted, it may result in lower annual depreciation and amortization deductions than would otherwise be allowable to some unitholders and risk the loss of depreciation and amortization deductions not taken in the year that these deductions are otherwise allowable. This position will not be adopted if we determine that the loss of depreciation and amortization deductions will have a material adverse effect on the unitholders. If we choose not to utilize this aggregate method, we may use any other reasonable depreciation and amortization method to preserve the uniformity of the intrinsic tax characteristics of any units that would not have a material adverse effect on the unitholders. In either case, and as stated above under “—Tax Consequences of Unit Ownership—Section 754 Election,” Latham & Watkins LLP has not rendered an opinion with respect to these methods. Moreover, the IRS may challenge any method of depreciating the Section 743(b) adjustment described in this paragraph. If this challenge were sustained, the uniformity of units might be affected, and the gain from the sale of units might be increased without the benefit of additional deductions. Please read “—Disposition of Common Units—Recognition of Gain or Loss.”

Tax-Exempt Organizations and Other Investors

Ownership of units by employee benefit plans, other tax-exempt organizations, non-resident aliens, foreign corporations and other foreign persons raises issues unique to those investors and, as described below to a limited extent, may have substantially adverse tax consequences to them. If you are a tax-exempt entity or a non-U.S. person, you should consult your tax advisor before investing in our common units. Employee benefit plans and most other organizations exempt from federal income tax, including individual retirement accounts and other retirement plans, are subject to federal income tax on unrelated business taxable income. Virtually all of our income allocated to a unitholder that is a tax-exempt organization will be unrelated business taxable income and will be taxable to it.

Non-resident aliens and foreign corporations, trusts or estates that own units will be considered to be engaged in business in the U.S. because of the ownership of units. As a consequence, they will be required to file federal tax returns to report their share of our income, gain, loss or deduction and pay federal income tax at regular rates on their share of our net income or gain. Moreover, under rules applicable to publicly traded partnerships, our quarterly distribution to foreign unitholders will be subject to withholding at the highest applicable effective tax rate. Each foreign unitholder must obtain a taxpayer identification number from the IRS and submit that number to our transfer agent on a Form W-8BEN, W-8BEN-E or applicable substitute form in order to obtain credit for these withholding taxes. A change in applicable law may require us to change these procedures.

 

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

A foreign unitholder who sells or otherwise disposes of a common unit will be subject to U.S. federal income tax on gain realized from the sale or disposition of that unit to the extent the gain is effectively connected with a U.S. trade or business of the foreign unitholder. Under a ruling published by the IRS, interpreting the scope of “effectively connected income,” a foreign unitholder would be considered to be engaged in a trade or business in the U.S. by virtue of the U.S. activities of the partnership, and part or all of that unitholder’s gain would be effectively connected with that unitholder’s indirect U.S. trade or business. Moreover, under the Foreign Investment in Real Property Tax Act, a foreign common unitholder generally will be subject to U.S. federal income tax upon the sale or disposition of a common unit if (1) it owned (directly or constructively applying certain attribution rules) more than 5% of our common units at any time during the five-year period ending on the date of such disposition and (2) 50% or more of the fair market value of all of our assets consisted of U.S. real property interests at any time during the shorter of the period during which such unitholder held the common units or the five-year period ending on the date of disposition. Currently, more than 50% of our assets consist of U.S. real property interests and we do not expect that to change in the foreseeable future. Therefore, foreign unitholders may be subject to federal income tax on gain from the sale or disposition of their units.

Administrative Matters

Information Returns and Audit Procedures

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 its share of our income, gain, loss and deduction for our preceding taxable year. In preparing this information, which will not be reviewed by counsel, we will take various accounting and reporting positions, some of which have been mentioned earlier, to determine each unitholder’s share of income, gain, loss and deduction. We cannot assure you that those positions will yield a result that conforms to the requirements of the Internal Revenue Code, Treasury Regulations or administrative interpretations of the IRS. Neither we nor Latham & Watkins LLP can assure prospective unitholders that the IRS will not successfully contend in court that those positions are impermissible. Any challenge by the IRS could negatively affect the value of the units.

The IRS may audit our federal income tax information returns. 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 its return. Any audit of a unitholder’s return could result in adjustments not related to our returns as well as those related to our returns.

Partnerships generally are treated as separate entities for purposes of federal tax audits, judicial review of administrative adjustments by the IRS and tax settlement proceedings. The tax treatment of partnership items of income, gain, loss and deduction are determined in a partnership proceeding rather than in separate proceedings with the partners. The Internal Revenue Code requires that one partner be designated as the “Tax Matters Partner” for these purposes. Our partnership agreement names our general partner as our Tax Matters Partner.

The Tax Matters Partner will make some elections on our behalf and on behalf of unitholders. In addition, the Tax Matters Partner can extend the statute of limitations for assessment of tax deficiencies against unitholders for items in our returns. The Tax Matters Partner may bind a unitholder with less than a 1% profits

 

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

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

Additional Withholding Requirements

Withholding taxes may apply to certain types of payments made to “foreign financial institutions” (as specially defined in the Internal Revenue Code) and certain other non-U.S. entities. Specifically, a 30% withholding tax may be imposed on interest, dividends and other fixed or determinable annual or periodical gains, profits and income from sources within the United States (“FDAP Income”), or gross proceeds from the sale or other disposition of any property of a type which can produce interest or dividends from sources within the United States (“Gross Proceeds”) paid to a foreign financial institution or to a “non-financial foreign entity” (as specially defined in the Internal Revenue Code), unless (1) the foreign financial institution undertakes certain diligence and reporting, (2) the non-financial foreign entity either certifies it does not have any substantial U.S. owners or furnishes identifying information regarding each substantial U.S. owner or (3) the foreign financial institution or non-financial foreign entity otherwise qualifies for an exemption from these rules. If the payee is a foreign financial institution and is subject to the diligence and reporting requirements in clause (1) above, it must enter into an agreement with the U.S. Treasury requiring, among other things, that it undertake to identify accounts held by certain U.S. persons or U.S.-owned foreign entities, annually report certain information about such accounts, and withhold 30% on payments to noncompliant foreign financial institutions and certain other account holders.

These rules generally will apply to payments of FDAP Income and will apply to payments of relevant Gross Proceeds made on or after January 1, 2017. Thus, to the extent we have FDAP Income or Gross Proceeds that are not treated as effectively connected with a U.S. trade or business (please read “—Tax-Exempt Organizations and Other Investors”), unitholders who are foreign financial institutions or certain other non-U.S. entities may be subject to withholding on distributions they receive from us, or their distributive share of our income, pursuant to the rules described above.

Prospective investors should consult their own tax advisors regarding the potential application of these withholding provisions to their investment in our common units.

Nominee Reporting

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

 

•

the name, address and taxpayer identification number of the beneficial owner and the nominee;

 

•

whether the beneficial owner is:

 

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a person that is not a U.S. person;

 

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a foreign government, an international organization or any wholly owned agency or instrumentality of either of the foregoing; or

 

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a tax-exempt entity;

 

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•

the amount and description of units held, acquired or transferred for the beneficial owner; and

 

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specific information including the dates of acquisitions and transfers, means of acquisitions and transfers, and acquisition cost for purchases, as well as the amount of net proceeds from dispositions.

Brokers and financial institutions are required to furnish additional information, including whether they are U.S. persons and specific information on units they acquire, hold or transfer for their own account. A penalty of $100 per failure, up to a maximum of $1,500,000 per calendar year, is imposed by the Internal Revenue Code for failure to report that information to us. The nominee is required to supply the beneficial owner of the units with the information furnished to us.

Accuracy-Related Penalties

An additional tax equal to 20% of the amount of any portion of an underpayment of tax that is attributable to one or more specified causes, including negligence or disregard of rules or regulations, substantial understatements of income tax and substantial valuation misstatements, is imposed by the Internal Revenue Code. No penalty will be imposed, however, for any portion of an underpayment if it is shown that there was a reasonable cause for that portion and that the taxpayer acted in good faith regarding that portion.

For individuals, a substantial understatement of income tax in any taxable year exists if the amount of the understatement exceeds the greater of 10% of the tax required to be shown on the return for the taxable year or $5,000 ($10,000 for most corporations). The amount of any understatement subject to penalty generally is reduced if any portion is attributable to a position adopted on the return:

 

•

for which there is, or was, “substantial authority”; or

 

•

as to which there is a reasonable basis and the pertinent facts of that position are disclosed on the return.

If any item of income, gain, loss or deduction included in the distributive shares of unitholders might result in that kind of an “understatement” of income for which no “substantial authority” exists, we must disclose the pertinent facts on our return. In addition, we will make a reasonable effort to furnish sufficient information for unitholders to make adequate disclosure on their returns and to take other actions as may be appropriate to permit unitholders to avoid liability for this penalty. More stringent rules apply to “tax shelters,” which we do not believe includes us, or any of our investments, plans or arrangements.

A substantial valuation misstatement exists if (a) the value of any property, or the adjusted basis of any property, claimed on a tax return is 150% or more of the amount determined to be the correct amount of the valuation or adjusted basis, (b) the price for any property or services (or for the use of property) claimed on any such return with respect to any transaction between persons described in Internal Revenue Code Section 482 is 200% or more (or 50% or less) of the amount determined under Section 482 to be the correct amount of such price, or (c) the net Internal Revenue Code Section 482 transfer price adjustment for the taxable year exceeds the lesser of $5 million or 10% of the taxpayer’s gross receipts. No penalty is imposed unless the portion of the underpayment attributable to a substantial valuation misstatement exceeds $5,000 ($10,000 for most corporations). If the valuation claimed on a return is 200% or more than the correct valuation or certain other thresholds are met, the penalty imposed increases to 40%. We do not anticipate making any valuation misstatements.

In addition, the 20% accuracy-related penalty also applies to any portion of an underpayment of tax that is attributable to transactions lacking economic substance. To the extent that such transactions are not disclosed, the penalty imposed is increased to 40%. Additionally, there is no reasonable cause defense to the imposition of this penalty to such transactions.

 

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Reportable Transactions

If we were to engage in a “reportable transaction,” we (and possibly you and others) would be required to make a detailed disclosure of the transaction to the IRS. A transaction may be a reportable transaction based upon any of several factors, including the fact that it is a type of tax avoidance transaction publicly identified by the IRS as a “listed transaction” or that it produces certain kinds of losses for partnerships, individuals, S corporations, and trusts in excess of $2 million in any single year, or $4 million in any combination of six successive tax years. Our participation in a reportable transaction could increase the likelihood that our federal income tax information return (and possibly your tax return) would be audited by the IRS. Please read “—Administrative Matters—Information Returns and Audit Procedures.”

Moreover, if we were to participate in a reportable transaction with a significant purpose to avoid or evade tax, or in any listed transaction, you may be subject to the following additional consequences:

 

•

accuracy-related penalties with a broader scope, significantly narrower exceptions, and potentially greater amounts than described above at “—Administrative Matters—Accuracy-Related Penalties”;

 

•

for those persons otherwise entitled to deduct interest on federal tax deficiencies, nondeductibility of interest on any resulting tax liability; and

 

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in the case of a listed transaction, an extended statute of limitations.

We do not expect to engage in any “reportable transactions.”

Recent Legislative Developments

The present federal income tax treatment of publicly traded partnerships, including us, or an investment in our common units may be modified by administrative, legislative or judicial interpretation at any time. For example, from time to time, members of Congress and the President propose and consider substantive changes to the existing 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. Any modification to the 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 federal income tax purposes. Please read “—Partnership Status.” We are unable to predict whether any such changes 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.

The White House has recommended various legislative changes affecting the U.S. federal income tax preferences relating to coal exploration and development in President Obama’s Proposed Fiscal Year 2016 budget (the “Budget Proposal”). Among the changes recommended in the Budget Proposal is the elimination of certain key U.S. federal income tax preferences relating to coal exploration and development discussed above. The Budget Proposal would (1) repeal the expensing of exploration and development costs relating to coal, (2) repeal the percentage depletion allowance with respect to coal properties, (3) repeal capital gains treatment for coal royalties and (4) repeal the domestic manufacturing deduction for the production of coal. The passage of any legislation as a result of the Budget Proposal or any other similar changes in U.S. federal income tax laws could eliminate certain tax deductions that are currently available with respect to coal exploration and development, and any such change could increase the taxable income allocable to our unitholders and negatively impact the value of an investment in our units.

 

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State, Local, Foreign and Other Tax Considerations

In addition to federal income taxes, you likely will be subject to other taxes, such as state, local and foreign income taxes, unincorporated business taxes, and estate, inheritance or intangible taxes that may be imposed by the various jurisdictions in which we do business or own property or in which you are a resident. Although an analysis of those various taxes is not presented here, each prospective unitholder should consider their potential impact on its investment in us. We will initially own property or do business in Pennsylvania and West Virginia. Both Pennsylvania and West Virginia impose an income tax on individuals, corporations and other entities. We may also own property or do business in other jurisdictions in the future. Although you may not be required to file a return and pay taxes in some jurisdictions because your income from that jurisdiction falls below the filing and payment requirement, you will be required to file income tax returns and to pay income taxes in many of these jurisdictions in which we do business or own property and may be subject to penalties for failure to comply with those requirements. In some jurisdictions, tax losses may not produce a tax benefit in the year incurred and may not be available to offset income in subsequent taxable years. Some of the jurisdictions, including West Virginia, may require us, or we may elect, to withhold a percentage of income from amounts to be distributed to a unitholder who is not a resident of the jurisdiction. Withholding, the amount of which may be greater or less than a particular unitholder’s income tax liability to the jurisdiction, generally does not relieve a nonresident unitholder from the obligation to file an income tax return. Amounts withheld will be treated as if distributed to unitholders for purposes of determining the amounts distributed by us. Please read “—Tax Consequences of Unit Ownership—Entity-Level Collections.” Based on current law and our estimate of our future operations, our general partner anticipates that any amounts required to be withheld will not be material.

It is the responsibility of each unitholder to investigate the legal and tax consequences, under the laws of pertinent states, localities and foreign jurisdictions, of its investment in us. Accordingly, each prospective unitholder is urged to consult its own tax counsel or other advisor with regard to those matters. Further, it is the responsibility of each unitholder to file all state, local and foreign, as well as U.S. federal tax returns, that may be required of it. Latham & Watkins LLP has not rendered an opinion on the state, local, alternative minimum or foreign tax consequences of an investment in us.

 

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INVESTMENT IN CNX COAL RESOURCES LP BY EMPLOYEE BENEFIT PLANS

An investment in us by an employee benefit plan is subject to additional considerations because the investments of these plans are subject to the fiduciary responsibility and prohibited transaction provisions of ERISA and the restrictions imposed by Section 4975 of the Internal Revenue Code and provisions under any federal, state, local, non-U.S. or other laws or regulations that are similar to such provisions of the Internal Revenue Code or ERISA, collectively, “Similar Laws.” For these purposes the term “employee benefit plan” includes, but is not limited to, qualified pension, profit-sharing and stock bonus plans, Keogh plans, simplified employee pension plans and tax deferred annuities or IRAs or annuities established or maintained by an employer or employee organization, and entities whose underlying assets are considered to include “plan assets” of such plans, accounts and arrangements, collectively, “Employee Benefit Plans.” Among other things, consideration should be given to:

 

•

whether the investment is prudent under Section 404(a)(1)(B) of ERISA and any other applicable Similar Laws;

 

•

whether in making the investment, the plan will satisfy the diversification requirements of Section 404(a)(1)(C) of ERISA and any other applicable Similar Laws;

 

•

whether the investment will result in recognition of unrelated business taxable income by the plan and, if so, the potential after-tax investment return. Please read “Material Federal Income Tax Consequences—Tax-Exempt Organizations and Other Investors”; and

 

•

whether making such an investment will comply with the delegation of control and prohibited transaction provisions of ERISA, the Internal Revenue Code and any other applicable Similar Laws.

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

Section 406 of ERISA and Section 4975 of the Internal Revenue Code prohibit Employee Benefit Plans from engaging, either directly or indirectly, in specified transactions involving “plan assets” with parties that, with respect to the Employee Benefit Plan, are “parties in interest” under ERISA or “disqualified persons” under the Internal Revenue Code unless an exemption is available. A party in interest or disqualified person who engages in a non-exempt prohibited transaction may be subject to excise taxes and other penalties and liabilities under ERISA and the Internal Revenue Code. In addition, the fiduciary of the ERISA plan that engaged in such a non-exempt prohibited transaction may be subject to penalties and liabilities under ERISA and the Internal Revenue Code.

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

The U.S. Department of Labor regulations and Section 3(42) of ERISA provide guidance with respect to whether, in certain circumstances, the assets of an entity in which Employee Benefit Plans acquire equity interests would be deemed “plan assets.” Under these rules, an entity’s assets would not be considered to be “plan assets” if, among other things:

 

(a)

the equity interests acquired by the Employee Benefit Plan are publicly offered securities—i.e., the equity interests are widely held by 100 or more investors independent of the issuer and each other, are freely transferable and are registered under certain provisions of the federal securities laws;

 

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(b)

the entity is an “operating company,”—i.e., it is primarily engaged in the production or sale of a product or service, other than the investment of capital, either directly or through a majority-owned subsidiary or subsidiaries; or

 

(c)

there is no significant investment by “benefit plan investors,” which is defined to mean that less than 25% of the value of each class of equity interest, disregarding any such interests held by our general partner, its affiliates and certain other persons, is held generally by Employee Benefit Plans.

Our assets should not be considered “plan assets” under these regulations because it is expected that the investment will satisfy the requirements in (a) and (b) above. The foregoing discussion of issues arising for employee benefit plan investments under ERISA and the Internal Revenue Code is general in nature and is not intended to be all inclusive, nor should it be construed as legal advice. In light of the serious penalties imposed on persons who engage in prohibited transactions or other violations, plan fiduciaries contemplating a purchase of common units should consult with their own counsel regarding the consequences under ERISA, the Internal Revenue Code and other Similar Laws.

 

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UNDERWRITING

Merrill Lynch, Pierce, Fenner & Smith Incorporated and Wells Fargo Securities, LLC are acting as representatives of the underwriters and book-running managers of this offering. Subject to the terms and conditions set forth in an underwriting agreement among us and the underwriters, we have agreed to sell to the underwriters, and each of the underwriters has agreed, severally and not jointly, to purchase from us, the number of common units set forth opposite its name below.

 

Underwriter		Number of Common Units
Merrill Lynch, Pierce, Fenner & Smith Incorporated
Wells Fargo Securities, LLC
Total

Subject to the terms and conditions set forth in the underwriting agreement, the underwriters have agreed, severally and not jointly, to purchase all of the common units sold under the underwriting agreement if any of these common units are purchased. If an underwriter defaults, the underwriting agreement provides that the purchase commitments of the nondefaulting underwriters may be increased or the underwriting agreement may be terminated.

We have agreed to indemnify the underwriters against certain liabilities, including liabilities under the Securities Act, or to contribute to payments the underwriters may be required to make in respect of those liabilities.

The underwriters are offering the common units, subject to prior sale, when, as and if issued to and accepted by them, subject to approval of legal matters by their counsel, including the validity of the common units, and other conditions contained in the underwriting agreement, such as the receipt by the underwriters of officer’s certificates and legal opinions. The underwriters reserve the right to withdraw, cancel or modify offers to the public and to reject orders in whole or in part.

Commissions and Discounts

The representatives have advised us that the underwriters propose initially to offer the common units to the public at the public offering price set forth on the cover page of this prospectus and to dealers at that price less a concession not in excess of $         per common unit. After the initial offering, the public offering price, concession or any other term of the offering may be changed.

The following table shows the public offering price, underwriting discount and proceeds before expenses to us. The information assumes either no exercise or full exercise by the underwriters of their option to purchase additional common units.

 

Per Common Unit

Without Option

With Option

Public offering price

$

$

$

Underwriting discount

$

$

$

Proceeds, before expenses, to CNX Coal Resources LP

$

$

$

The expenses of the offering, not including the underwriting discount, are estimated at $             and are payable by us.

 

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We also have agreed to reimburse the underwriters for up to $             of reasonable fees and expenses of counsel related to the review by the Financial Industry Regulatory Authority, Inc., or FINRA, of the terms of sale of the common units offered hereby, and the underwriters have agreed to reimburse us for certain expenses in connection with this offering.

Option to Purchase Additional Common Units

We have granted an option to the underwriters, exercisable for 30 days after the date of this prospectus, to purchase up to              additional common units at the public offering price, less the underwriting discount. If the underwriters exercise this option, each will be obligated, subject to conditions contained in the underwriting agreement, to purchase a number of additional common units proportionate to that underwriter’s initial amount reflected in the above table.

No Sales of Similar Securities

We, our executive officers and directors and our other existing security holders have agreed not to sell or transfer any common units or securities convertible into, exchangeable for, exercisable for, or repayable with common units, for 180 days after the date of this prospectus without first obtaining the written consent of the representatives. Specifically, we and these other persons have agreed, with certain limited exceptions, not to directly or indirectly:

 

•

offer, pledge, sell or contract to sell any common units,

 

•

sell any option or contract to purchase any common units,

 

•

purchase any option or contract to sell any common units,

 

•

grant any option, right or warrant for the sale of any common units,

 

•

lend or otherwise dispose of or transfer any common units,

 

•

request or demand that we file a registration statement related to the common units, or

 

•

enter into any swap or other agreement that transfers, in whole or in part, the economic consequence of ownership of any common units whether any such swap or transaction is to be settled by delivery of common units or other securities, in cash or otherwise.

This lock-up provision applies to common units and to securities convertible into or exchangeable or exercisable for or repayable with common units. It also applies to common units owned now or acquired later by the person executing the agreement or for which the person executing the agreement later acquires the power of disposition.

New York Stock Exchange Listing

We intend to apply to list our common units on the NYSE under the symbol “CNXC.” In order to meet the requirements for listing on that exchange, the underwriters have undertaken to sell a minimum number of common units to a minimum number of beneficial owners as required by that exchange.

Before this offering, there has been no public market for our common units. The initial public offering price will be determined through negotiations among us and the representatives. In addition to prevailing market conditions, the factors to be considered in determining the initial public offering price are:

 

•

the valuation multiples of publicly traded companies that the representatives believe to be comparable to us,

 

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•

our financial information,

 

•

the history of, and the prospects for, our company and the industry in which we compete,

 

•

an assessment of our management, its past and present operations, and the prospects for, and timing of, our future revenues,

 

•

the present state of our development, and

 

•

the above factors in relation to market values and various valuation measures of other companies engaged in activities similar to ours.

An active trading market for the common units may not develop. It is also possible that after the offering the common units will not trade in the public market at or above the initial public offering price.

The underwriters do not expect to sell more than 5% of the common units in the aggregate to accounts over which they exercise discretionary authority.

Price Stabilization, Short Positions and Penalty Bids

Until the distribution of the common units is completed, SEC rules may limit underwriters and selling group members from bidding for and purchasing our common units. However, the representatives may engage in transactions that stabilize the price of the common units, such as bids or purchases to peg, fix or maintain that price.

In connection with the offering, the underwriters may purchase and sell our common units in the open market. These transactions may include short sales, purchases on the open market to cover positions created by short sales and stabilizing transactions. Short sales involve the sale by the underwriters of a greater number of common units than they are required to purchase in the offering. “Covered” short sales are sales made in an amount not greater than the underwriters’ option to purchase additional common units described above. The underwriters may close out any covered short position by either exercising their option to purchase additional common units or purchasing common units in the open market. In determining the source of common units to close out the covered short position, the underwriters will consider, among other things, the price of common units available for purchase in the open market as compared to the price at which they may purchase common units through the option granted to them. “Naked” short sales are sales in excess of such option. The underwriters must close out any naked short position by purchasing common units in the open market. A naked short position is more likely to be created if the underwriters are concerned that there may be downward pressure on the price of our common units in the open market after pricing that could adversely affect investors who purchase in the offering. Stabilizing transactions consist of various bids for or purchases of common units made by the underwriters in the open market prior to the completion of the offering.

The underwriters may also impose a penalty bid. This occurs when a particular underwriter repays to the underwriters a portion of the underwriting discount received by it because the representatives have repurchased common units sold by or for the account of such underwriter in stabilizing or short covering transactions.

Similar to other purchase transactions, the underwriters’ purchases to cover the syndicate short sales may have the effect of raising or maintaining the market price of our common units or preventing or retarding a decline in the market price of our common units. As a result, the price of our common units may be higher than the price that might otherwise exist in the open market. The underwriters may conduct these transactions on the NYSE, in the over-the-counter market or otherwise.

 

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Neither we nor any of the underwriters make any representation or prediction as to the direction or magnitude of any effect that the transactions described above may have on the price of our common units. In addition, neither we nor any of the underwriters make any representation that the representatives will engage in these transactions or that these transactions, once commenced, will not be discontinued without notice.

Electronic Distribution

In connection with the offering, certain of the underwriters or securities dealers may distribute prospectuses by electronic means, such as e-mail.

Directed Unit Program

At our request, the underwriters have reserved up to     % of the common units being offered by this prospectus (excluding the common units that may be issued upon the underwriters’ exercise of their option to purchase additional common units) for sale at the initial public offering price 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. The sales will be made by Merrill Lynch, Pierce, Fenner & Smith Incorporated through a directed unit program. The number of units available for sale to the general public will be reduced to the extent that these individuals purchase all or a portion of the reserved units. Any reserved units not so purchased will be offered by the underwriters to the general public on the same basis as the other units offered by this prospectus.

We have agreed to indemnify Merrill Lynch, Pierce, Fenner & Smith Incorporated and the underwriters in connection with the directed unit program, including for the failure of any participant to pay for its units. Participants in the directed unit program who purchase $100,000 or more of common units under the program will be subject to a 25-day lock-up period with respect to any common units sold to them under the program. This lock-up will have similar restrictions to the lock-up agreements described above under “—No Sales of Similar Securities.” Any common units sold through the directed unit program to the directors, director nominee and executive officers of our general partner will be subject to the 180-day lock-up agreements described above under “—No Sales of Similar Securities.”

Other Relationships

Some of the underwriters and their affiliates have engaged in, and may in the future engage in, investment banking and other commercial dealings in the ordinary course of business with us or our affiliates. They have received, or may in the future receive, customary fees and commissions for these transactions.

In addition, in the ordinary course of their business activities, the underwriters and their affiliates may make or hold a broad array of investments and actively trade debt and equity securities (or related derivative securities) and financial instruments (including bank loans) for their own account and for the accounts of their customers. Such investments and securities activities may involve securities and/or instruments of ours or our affiliates. The underwriters and their affiliates may also make investment recommendations and/or publish or express independent research views in respect of such securities or financial instruments and may hold, or recommend to clients that they acquire, long and/or short positions in such securities and instruments.

Notice to Prospective Investors in Australia

No placement document, prospectus, product disclosure statement or other disclosure document has been lodged with the Australian Securities and Investments Commission in relation to the offering. This registration statement does not constitute a prospectus, product disclosure statement or other disclosure document under the Corporations Act 2001 (the “Corporations Act”), and does not purport to include the information required for a prospectus, product disclosure statement or other disclosure document under the Corporations Act.

 

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Any offer in Australia of the common units may only be made to persons (the “Exempt Investors”), who are:

(a) “sophisticated investors” (within the meaning of section 708(8) of the Corporations Act), “professional investors” (within the meaning of section 708(11) of the Corporations Act) or otherwise pursuant to one or more exemptions contained in section 708 of the Corporations Act; and

(b) “wholesale clients” (within the meaning of section 761G of the Corporations Act),

so that it is lawful to offer the common units without disclosure to investors under Chapters 6D and 7 of the Corporations Act.

The common units applied for by Exempt Investors in Australia must not be offered for sale in Australia in the period of 12 months after the date of allotment under the offering, except in circumstances where disclosure to investors under Chapters 6D and 7 of the Corporations Act would not be required pursuant to an exemption under both section 708 and Subdivision B of Division 2 of Part 7.9 of the Corporations Act or otherwise or where the offer is pursuant to a disclosure document which complies with Chapters 6D and 7 of the Corporations Act. Any person acquiring common units must observe such Australian on-sale restrictions.

This registration statement contains general information only and does not take account of the investment objectives, financial situation or particular needs of any particular person. It does not contain any securities recommendations or financial product advice. Before making an investment decision, investors need to consider whether the information in this registration statement is appropriate to their needs, objectives and circumstances, and, if necessary, seek expert advice on those matters.

Notice to Prospective Investors in Hong Kong

No advertisement, invitation or document relating to the common units has been or may be issued or has been or may be in the possession of any person for the purposes of issue, whether in Hong Kong or elsewhere, which is directed at, or the contents of which are likely to be accessed or read by, the public of Hong Kong (except if permitted to do so under the securities laws of Hong Kong) other than with respect to common units which are or are intended to be disposed of only to persons outside Hong Kong or only to “professional investors” as defined in the Securities and Futures Ordinance and any rules made under that Ordinance.

 

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VALIDITY OF THE COMMON UNITS

The validity of the common units and certain tax and other legal matters will be passed upon for us by Latham & Watkins LLP, Houston, Texas. Certain legal matters in connection with our common units offered hereby will be passed upon for the underwriters by Vinson & Elkins L.L.P., Houston, Texas.

EXPERTS

The financial statements of CNX Coal Resources LP Predecessor at December 31, 2014 and 2013, and for the years then ended, appearing in this prospectus and registration statement have been audited by Ernst & Young LLP, independent registered public accounting firm, as set forth in their report thereon appearing elsewhere herein, and are included in reliance upon such report given on the authority of such firm as experts in accounting and auditing.

The balance sheet of CNX Coal Resources LP at March 27, 2015, appearing in this prospectus and registration statement has been audited by Ernst & Young LLP, independent registered public accounting firm, as set forth in their report thereon appearing elsewhere herein, and is included in reliance upon such report given on the authority of such firm as experts in accounting and auditing.

The information included in this prospectus relating to the estimates of our proven and probable reserves associated with the mining operations at the Pennsylvania mining complex is derived from CONSOL Energy’s internal estimates, 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 and is included in this prospectus upon the authority of said firm as an expert.

 

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WHERE YOU CAN FIND ADDITIONAL INFORMATION

We have filed with the SEC a registration statement on Form S-1 relating to the common units offered by this prospectus. This prospectus, which constitutes a part of the registration statement, does not contain all of the information set forth in the registration statement. For further information regarding us and the common units offered by this prospectus, we refer you to the full registration statement, including its exhibits and schedules, filed under the Securities Act. The registration statement, of which this prospectus constitutes a part, including its exhibits and schedules, may be inspected and copied at the SEC’s Public Reference Room at 100 F Street, N.E., Washington, D.C. 20549. Copies of the materials may also be obtained from the SEC at prescribed rates by writing to the Public Reference Room. You may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330.

The SEC maintains a website at http://www.sec.gov that contains reports, information statements and other information regarding issuers that file electronically with the SEC. Our registration statement, of which this prospectus constitutes a part, can be downloaded from the SEC’s website.

After the completion of this offering, we will file with or furnish to the SEC periodic reports and other information. These reports and other information may be inspected and copied at the Public Reference Room maintained by the SEC or obtained from the SEC’s website as provided above. Following the completion of this offering, our website will be located at                     . We intend to make our periodic reports and other information filed with or furnished to the SEC available, free of charge, through our website, as soon as reasonably practicable after those reports and other information are electronically filed with or furnished to the SEC. Information on our website or any other website is not incorporated by reference into this prospectus and does not constitute a part of this prospectus.

We intend to furnish or make available to our unitholders annual reports containing our audited financial statements prepared in accordance with GAAP. We also intend to furnish or make available to our unitholders quarterly reports containing our unaudited interim financial information, including the information required by Form 10-Q, for the first three fiscal quarters of each fiscal year.

CONSOL Energy is subject to the information requirements of the Exchange Act and, in accordance therewith, files reports and other information with the SEC. You may read CONSOL Energy’s filings on the SEC’s website and at the Public Reference Room described above or CONSOL Energy’s website at www.consolenergy.com. CONSOL Energy’s common stock trades on the NYSE under the symbol “CNX.” Information on CONSOL Energy’s website is not incorporated by reference into this prospectus and does not constitute a part of this prospectus.

 

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FORWARD-LOOKING STATEMENTS

This prospectus contains forward-looking statements. Statements that are predictive in nature, that depend upon or refer to future events or conditions or that include the words “believe,” “expect,” “anticipate,” “intend,” “estimate” and other expressions that are predictions of or indicate future events and trends and that do not relate to historical matters identify forward-looking statements. Our forward-looking statements include statements about our business strategy, our industry, our future profitability, our expected capital expenditures and the impact of such expenditures on our performance, the costs of being a publicly traded partnership and our capital programs. All statements in this prospectus about our forecast of distributable cash flow and our forecasted results for the twelve months ending June 30, 2016 constitute forward-looking statements.

A forward-looking statement may include a statement of the assumptions or bases underlying the forward-looking statement. We believe that we have chosen these assumptions or bases in good faith and that they are reasonable. You are cautioned not to place undue reliance on any forward-looking statements. You should also understand that it is not possible to predict or identify all such factors and should not consider the following list to be a complete statement of all potential risks and uncertainties. Factors that could cause our actual results to differ materially from the results contemplated by such forward-looking statements include:

 

•

changes in coal prices or the costs of mining or transporting coal;

 

•

uncertainty in estimating economically recoverable coal reserves and replacement of reserves;

 

•

our ability to develop our existing coal reserves and successfully execute our mining plans;

 

•

changes in general economic conditions, both domestically and globally;

 

•

competitive conditions within the coal industry;

 

•

changes in the consumption patterns of coal-fired power plants and steelmakers and other factors affecting the demand for coal by coal-fired power plants and steelmakers;

 

•

the availability and price of coal to the consumer compared to the price of alternative and competing fuels;

 

•

competition from the same and alternative energy sources;

 

•

energy efficiency and technology trends;

 

•

our ability to successfully implement our business plan;

 

•

the price and availability of debt and equity financing;

 

•

operating hazards and other risks incidental to coal mining;

 

•

major equipment failures and difficulties in obtaining equipment, parts and raw materials;

 

•

availability, reliability and costs of transporting coal;

 

•

adverse or abnormal geologic conditions, which may be unforeseen;

 

•

natural disasters, weather-related delays, casualty losses and other matters beyond our control;

 

•

interest rates;

 

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•

labor availability, relations and other workforce factors;

 

•

defaults by our sponsor under our operating agreement and employee services agreement;

 

•

changes in availability and cost of capital;

 

•

changes in our tax status;

 

•

delays in the receipt of, failure to receive or revocation of necessary governmental permits;

 

•

defects in title or loss of any leasehold interests with respect to our properties;

 

•

the effect of existing and future laws and government regulations, including the enforcement and interpretation thereof;

 

•

the effects of litigation; and

 

•

certain factors discussed elsewhere in this prospectus.

You should not place undue reliance on our forward-looking statements. Although forward-looking statements reflect our good faith beliefs at the time they are made, forward-looking statements involve known and unknown risks, uncertainties and other factors, including the factors described under “Risk Factors,” which may cause our actual results, performance or achievements to differ materially from anticipated future results, performance or achievements expressed or implied by such forward-looking statements. We undertake no obligation to publicly update or revise any forward-looking statement, whether as a result of new information, future events, changed circumstances or otherwise, unless required by law.

 

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INDEX TO FINANCIAL STATEMENTS

CNX Coal Resources LP

Unaudited Pro Forma Combined Financial Statements

 

Introduction			F-2
Unaudited Pro Forma Combined Statement of Operations for the Year Ended December 31, 2014			F-4
Unaudited Pro Forma Combined Balance Sheet as of December 31, 2014			F-5
Notes to the Unaudited Pro Forma Combined Financial Statements			F-6

CNX Coal Resources LP Predecessor

Historical Financial Statements

 

Report of Independent Registered Public Accounting Firm			F-9
Combined Statements of Operations for the Years Ended December 31, 2014 and December 31, 2013			F-10
Combined Statements of Comprehensive Income for the Years Ended December 31, 2014 and December 31, 2013			F-11
Combined Balance Sheets at December 31, 2014 and December 31, 2013			F-12
Combined Statements of Net Investment for the Years Ended December 31, 2014 and December 31, 2013			F-13
Combined Statements of Cash Flows for the Years Ended December 31, 2014 and December 31, 2013			F-14
Notes to the Audited Combined Financial Statements			F-15

CNX Coal Resources LP

Historical Balance Sheet

 

Report of Independent Registered Public Accounting Firm			F-34
Balance Sheet as of March 27, 2015			F-35
Notes to Balance Sheet			F-36

 

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CNX COAL RESOURCES LP

UNAUDITED PRO FORMA COMBINED FINANCIAL STATEMENTS

INTRODUCTION

Set forth below are the unaudited pro forma combined balance sheet of CNX Coal Resources LP (“we,” “us,” “our” or the “Partnership”) as of December 31, 2014 and the unaudited pro forma combined statement of operations for the Partnership for the year ended December 31, 2014. The unaudited pro forma combined financial statements for the Partnership have been derived by adjusting the historical combined financial statements of CONSOL Pennsylvania Coal Company LLC, a Delaware limited liability company (“CPCC”), and Conrhein Coal Company, a Pennsylvania general partnership (“Conrhein”), each a wholly owned subsidiary of CONSOL Energy Inc. (“CONSOL Energy”). The Partnership’s predecessor for accounting purposes (the “Predecessor”) consists of a 20% undivided interest in the combined assets, liabilities, revenues and expenses of CPCC and Conrhein.

CPCC and Conrhein’s assets include the Pennsylvania mining complex located primarily in southwestern Pennsylvania, comprised of the Bailey Mine, Enlow Fork Mine and Harvey Mine, coal reserves and properties associated with the Pennsylvania mining complex and preparation plant, facilities, equipment and other infrastructure associated with the Pennsylvania mining complex. All of CPCC and Conrhein’s assets are located in Pennsylvania and West Virginia. In connection with the completion of our initial public offering (this “offering”), CONSOL Energy will contribute to us a 20% undivided interest in the assets, liabilities, revenues and expenses comprising the Pennsylvania mining complex that are currently held by CPCC and Conrhein. We will record the contribution of the 20% undivided interest at historical cost, as the contribution will be considered a reorganization of entities under common control.

The historical combined financial statements of the Predecessor are set forth elsewhere in this prospectus, and the unaudited pro forma combined financial statements for the Partnership should be read in conjunction with, and are qualified in their entirety by reference to, such historical combined financial statements and the related notes contained therein. The pro forma adjustments are based upon currently available information and certain estimates and assumptions, and actual results may differ from the pro forma adjustments. However, management believes that these estimates and assumptions provide a reasonable basis for presenting the significant effects of the contemplated transactions and that the pro forma adjustments are factually supportable and give appropriate effect to those estimates and assumptions and are properly applied in the unaudited pro forma combined financial statements.

The pro forma adjustments have been prepared as if the transactions to be effected at the closing of this offering had taken place on December 31, 2014, in the case of the pro forma combined balance sheet, and as of January 1, 2014, in the case of the pro forma combined statement of operations for the year ended December 31, 2014. The unaudited pro forma combined financial statements have been prepared on the assumption that we will be treated as a partnership for U.S. federal income tax purposes.

The unaudited pro forma combined financial statements give pro forma effect to the matters described in the notes hereto, including:

 

•

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 $400 million revolving credit facility and initial draw of $225 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

 

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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. As a result, the unaudited pro forma combined financial statements may not be indicative of the results that actually would have occurred if the matters described above had occurred on the dates indicated or that would be obtained in the future.

 

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CNX COAL RESOURCES LP

UNAUDITED PRO FORMA COMBINED STATEMENT OF OPERATIONS YEAR ENDED DECEMBER 31, 2014

(in thousands)

 

		Historical				Pro Forma Adjustments				Pro Forma
Coal Revenue		$	323,398			$	—			$	323,398
Freight Revenue			3,353								3,353
Other Income			7,580				(209	)(a)			7,371
Gain on Sale of Assets			148				5	(a)			153
Total Revenue and Other Income			334,479				(204	)			334,275
Operating and Other Costs (Related Party of $10,694 and $10,694, respectively)			172,863				(299	)(b)			172,327
							(237	)(a)
Royalties and Production Taxes			14,169				—				14,169
Selling and Direct Administrative Expenses (Related Party of $5,791 and $4,710, respectively)			6,444				(6,444	)(c)			4,710
							4,710	(c)
Depreciation, Depletion and Amortization			33,949				(163	)(a)			33,786
Freight Expense			3,353								3,353
General and Administrative Expenses—Related Party			5,198				(5,198	)(c)			5,264
							5,264	(c)
Other Corporate Expenses (Related Party of $7,944 and $7,944, respectively)(1)			7,658				—				7,658
Interest Expense (Related Party of $9,534 and $0, respectively)			6,946				(6,945	)(d)			8,631
							8,630	(e)
Total Costs			250,580				(682	)			249,898
Net Income		$	83,899			$	478			$	84,377
Pro forma general partner interest in net income
Pro form limited partners’ interest in net income
Common units
Subordinated units
Pro forma net income per limited partner unit (basic and diluted)
Common units
Subordinated units
Pro forma weighted average number of limited partner units outstanding (basic and diluted)
Common units
Subordinated units

 

(1)	Includes a $286 favorable adjustment to a previously established franchise tax accrual.

The accompanying notes are an integral part of these unaudited pro forma combined financial statements.

 

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CNX COAL RESOURCES LP

UNAUDITED PRO FORMA COMBINED BALANCE SHEET

AS OF DECEMBER 31, 2014

(in thousands)

 

		Historical				Pro Forma Adjustments				Pro Forma
ASSETS
Current Assets:
Cash		$	3			$	7,000	(f)		$	7,003
Other Receivables			384								384
Inventories			10,639								10,639
Prepaid Expenses			3,922								3,922
Total Current Assets			14,948				7,000				21,948
Property and Equipment
Property, Plant and Equipment			686,593				(29,987	)(g)			664,880
							8,274	(h)
Less—Accumulated Depreciation, Depletion and Amortization			287,707				(4,612	)(g)			285,441
							2,346	(h)
Total Property and Equipment—Net			398,886				(19,447	)			379,439
Other Assets:
Other			4,977				3,000	(e)			14,482
							6,505	(i)
Total Other Assets			4,977				9,505				14,482
TOTAL ASSETS		$	418,811			$	(2,942	)		$	415,869
LIABILITIES AND EQUITY
Current Liabilities:
Accounts Payable		$	15,782			$	(15,782	)(j)		$	—
Current Portion of Long-Term Notes—Related Party			17,931				(17,931	)(d)			—
Current Portion of Long-Term Debt—Other			330								330
Other Accrued Liabilities			35,502				(2	)(d)			35,500
Total Current Liabilities			69,545				(33,715	)			35,830
Long-Term Debt:
Long-Term Notes Payable—Related Party			160,831				(160,831	)(d)			—
Revolving Credit Facility			—				225,000	(e)			225,000
Advanced Royalty Commitments			278								278
Capital Lease Obligations			51								51
Total Long-Term Debt			161,160				64,169				225,329
Deferred Credits and Other Liabilities:
Postretirement Benefits Other Than Pensions			5,279								5,279
Pneumoconiosis Benefits			1,250								1,250
Asset Retirement Obligations			7,961								7,961
Workers’ Compensation			2,381								2,381
Other			609								609
Total Deferred Credits and Other Liabilities			17,480				—				17,480
TOTAL LIABILITIES			248,185				30,454				278,639
Invested Equity:
Parent Net Investment			139,259				181,604	(k)			—
							(320,863	)(k)
Accumulated Other Comprehensive Income			31,367				(31,367	)(n)			—
Partners’ Capital
Common Units—Public			—				250,000	(l)			250,000
Common Units—CONSOL Energy			—				314,446	(k)			(150,554	)
							(465,000	)(m)
Subordinated Units—CONSOL Energy			—								—
General Partner			—				6,417	(k)			6,417
Accumulated Other Comprehensive Income			—				31,367	(n)			31,367
Total Invested Equity / Partners’ Capital			170,626				(33,396	)			137,230
TOTAL LIABILITIES AND INVESTED EQUITY / PARTNERS’ CAPITAL		$	418,811			$	(2,942	)		$	415,869

The accompanying notes are an integral part of these unaudited pro forma combined financial statements.

 

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CNX COAL RESOURCES LP

NOTES TO UNAUDITED PRO FORMA COMBINED FINANCIAL STATEMENTS

(Dollars in thousands)

1. Pro Forma Adjustments and Assumptions

The adjustments are based on currently available information and certain estimates and assumptions and, therefore, the actual effects of these transactions will differ from the pro forma adjustments. A general description of these transactions and adjustments is provided as follows:

 

(a)	Represents the adjustment to remove rental income, loss on sale of assets, operating costs and depreciation expense related to certain rental properties included in the Predecessor’s financial statements that will not be contributed to the Partnership (refer to footnote (g) below).

 

(b)

Represents the adjustment to Operating and Other Costs to (i) eliminate property taxes for certain surface land leases which were included in the Predecessor financial statements that will not be contributed to the Partnership of $1,402 (refer to footnote (g) below); and (ii) record property taxes for certain mineral leases which were not included in the Predecessor financial statements that will be contributed to the Partnership of $1,103 (refer to footnote (h) below).

 

(c)	Represents the adjustment to remove historical selling and direct administrative expenses and general and administrative expenses and to record the new fixed fee expense for services provided to the Partnership by CONSOL Energy under the omnibus agreement and employee services agreement.

 

(d)

Represents the adjustments related to the elimination of the Predecessor’s historical related party long-term note payable of $178,762, comprising a current portion of $17,931, non-current portion of $160,831 and accrued interest of $2, as the Partnership will not be assuming this note payable. Related party interest expense of $6,945 associated with the long-term note payable was eliminated for the year ended December 31, 2014. The remaining related party interest expense of $1 is for capital leases, which will be contributed to the Partnership.

 

(e)

Represents the adjustments related to the Partnership’s new revolving credit facility, including the payment of an estimated $3,000 of origination fees, which will be amortized over the life of the facility. Incremental expense of $8,630 is comprised of $7,155 associated with expected borrowings on the credit facility of $225,000, commitment fees of $875 and amortization of origination costs of $600 for the year ended December 31, 2014. Assuming $225,000 is initially drawn under the new revolving credit facility at the closing of this offering, each 0.125% change in the assumed interest rate for the new revolving credit facility would change pro forma interest expense by approximately $281 for the year ended December 31, 2014.

 

(f)	Represents the following adjustments to cash:

 

Sources						Uses
Gross proceeds from sale of common units		$	250,000			Distribution to CONSOL Energy		$	465,000
Gross borrowings under revolving credit facility			225,000			Underwriting discount
						Other offering expenses
						Revolving credit facility origination fees			3,000
						Cash on hand*			7,000
Total Sources		$	475,000			Total Uses		$	475,000

 

*	The Partnership plans to retain $7,000 of cash on hand for the Partnership’s working capital purposes.

 

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(g)

Represents the pro forma adjustment to reflect the net adjustment to property, plant and equipment for (i) certain surface land leases which were included in the Predecessor financial statements that will not be contributed to the Partnership (refer to footnote (b) above); and (ii) removal of rental properties included in the Predecessor financial statements that will not be contributed to the Partnership (refer to footnote (a) above). These surface land leases and rental properties are not critical to the mining operations of the Pennsylvania mining complex and thus will not be contributed to the Partnership.

 

		As of December 31, 2014
Surface land leases not being contributed—Gross		$	(21,772	)
Rental properties not being contributed—Gross			(8,215	)
Property, plant and equipment—gross adjustment			(29,987	)
Surface land leases not being contributed—Accumulated depreciation, depletion and amortization			(1,863	)
Rental properties not being contributed—Accumulated depreciation, depletion and amortization			(2,749	)
Accumulated depreciation, depletion and amortization adjustment			(4,612	)
Property, plant and equipment, net adjustment		$	(25,375	)

 

(h)	Represents the pro forma adjustment to reflect the net adjustment to property, plant and equipment primarily related to certain mineral leases which were not included in the Predecessor financial statements that will be contributed to the Partnership (refer to footnote (b) above).

 

		As of December 31, 2014
Mineral leases being contributed—Gross		$	8,274
Less: Mineral leases being contributed—Accumulated depreciation, depletion and amortization			2,346
Property, plant and equipment—net adjustment		$	5,928

 

(i)

Represents the adjustment related to tradable stream credits of $6,505 which were not included in the financial statements of the Predecessor that will be contributed to the Partnership. A stream credit or stream offset is a generic term for any tradable certificate or permit representing the right to drain, fill, or dredge a stream.

 

(j)	Represents the adjustment to remove historical accounts payable as these payables will not be assumed by the Partnership.

 

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(k)

The table below summarizes the pro forma adjustments to Parent Net Investment and Partners’ Capital based on our expected partnership capital allocated in connection with this offering. The allocation of pro forma capitalization to CONSOL Energy’s units is based on CONSOL Energy’s expected ownership percentage in us at the closing of this offering.

 

Invested Equity:
Parent Net Investment		$	139,259
Surface land and rental properties not being contributed (refer to footnote (g) above)			(25,375	)
Mineral leases being contributed (refer to footnote (h) above)			5,928
Stream credits being contributed (refer to footnote (i) above)			6,505
Accounts Payable not being contributed (refer to footnote (j) above)			15,782
Long-Term Note Payable (refer to footnote (d) above)			178,764
Net adjustment to Parent Net Investment			181,604
Subtotal of historical Parent Net Investment		$	320,863
Partners’ Capital:
98% allocation of historical Parent Net Investment to Common Units—CONSOL Energy		$	314,446
2% allocation of historical Parent Net Investment to General Partner			6,417
Accumulated Other Comprehensive Income			31,367
Offering proceeds (refer to footnote (f) above)			250,000
Distribution to CONSOL Energy (refer to footnote (m) below)			(465,000	)
Pro Forma Capitalization		$	137,230
Allocation of Pro Forma Capitalization:
Common Units—Public		$	250,000
Common Units—CONSOL Energy			(150,554	)
Subordinated Units—CONSOL Energy
General Partner			6,417
Accumulated Other Comprehensive Income			31,367
Pro Forma Capitalization		$	137,230

 

(l)	Represents the net adjustment to the public common unitholders’ partners’ capital, as follows:

 

		December 31, 2014
Gross proceeds from initial public offering (refer to footnote (f) above)		$	250,000
Underwriting discount (refer to footnote (f) above)
Expenses and costs of initial public offering (refer to footnote (f) above)
		$	250,000

 

(m)	Represents the distribution of the remaining initial public offering proceeds and borrowings under the new revolving credit facility of $465,000 to CONSOL Energy.

 

(n)	Represents the reclassification of historical accumulated other comprehensive income from Invested Equity to Partners’ Capital.

 

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors of CNX Coal Resources GP LLC

We have audited the accompanying combined balance sheets of the CNX Coal Resources LP Predecessor (the Predecessor) as of December 31, 2014 and 2013, and the related combined statements of operations, statements of comprehensive income, statement of net investment, and statements of cash flows for the years then ended. These financial statements are the responsibility of the Predecessor’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

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

In our opinion, the financial statements referred to above present fairly, in all material respects, the combined financial position of the CNX Coal Resources LP Predecessor at December 31, 2014 and 2013, and the results of its combined operations and its cash flows for each of the years then ended, in conformity with U.S. generally accepted accounting principles.

/s/ Ernst & Young LLP

Pittsburgh, Pennsylvania

April 1, 2015

 

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CNX COAL RESOURCES LP PREDECESSOR

COMBINED STATEMENTS OF OPERATIONS

(Dollars in thousands)

 

		For the Years Ended December 31,
		2014				2013
Coal Revenue		$	323,398			$	271,467
Freight Revenue			3,353				3,556
Other Income			7,580				1,336
Gain (Loss) on Sale of Assets			148				(124	)
Total Revenue and Other Income			334,479				276,235
Operating and Other Costs (Related Party of $10,694 and $11,219, respectively)			172,863				152,054
Royalties and Production Taxes			14,169				11,046
Selling and Direct Administrative Expenses (Related Party of $5,791 and $5,537, respectively)			6,444				5,687
Depreciation, Depletion and Amortization			33,949				25,306
Freight Expense			3,353				3,556
General and Administrative Expenses—Related Party			5,198				4,521
Other Corporate Expenses (Related Party $7,944 and $7,516, respectively)			7,658				7,680
Interest Expense (Related Party of $9,534 and $9,310, respectively)			6,946				2,093
Total Costs			250,580				211,943
Net Income		$	83,899			$	64,292

The accompanying notes are an integral part of these combined financial statements.

 

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CNX COAL RESOURCES LP PREDECESSOR

COMBINED STATEMENTS OF COMPREHENSIVE INCOME

(Dollars in thousands)

 

		For the Years Ended December 31,
		2014				2013
Net Income		$	83,899			$	64,292
Other Comprehensive Income:
Actuarially Determined Long-Term Liability Adjustments			33,439				8,419
Other Comprehensive Income			33,439				8,419
Comprehensive Income		$	117,338			$	72,711

The accompanying notes are an integral part of these combined financial statements.

 

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CNX COAL RESOURCES LP PREDECESSOR

COMBINED BALANCE SHEETS

(Dollars in thousands)

 

		Supplemental Pro Forma (Unaudited) December 31, 2014				December 31, 2014				December 31, 2013
ASSETS
Current Assets:
Cash		$	3			$	3			$	3
Other Receivables			384				384				119
Inventories			10,639				10,639				10,932
Prepaid Expenses			3,922				3,922				3,719
Total Current Assets			14,948				14,948				14,773
Property, Plant and Equipment:
Property, Plant and Equipment			686,593				686,593				631,208
Less—Accumulated Depreciation, Depletion and Amortization			287,707				287,707				256,924
Total Property, Plant and Equipment—Net			398,886				398,886				374,284
Other Assets:
Other			4,977				4,977				3,703
Total Other Assets			4,977				4,977				3,703
TOTAL ASSETS		$	418,811			$	418,811			$	392,760
LIABILITIES AND EQUITY
Current Liabilities:
Accounts Payable		$	15,782			$	15,782			$	17,988
Current Portion of Long Term Notes—Related Party			17,931				17,931				1,849
Current Portion of Long Term Debt—Other			330				330				240
Other Accrued Liabilities			35,502				35,502				34,577
Distribution Payable to CONSOL Energy			465,000				—				—
Total Current Liabilities			534,545				69,545				54,654
Long-Term Debt:
Long-Term Notes Payable—Related Party			160,831				160,831				167,391
Advanced Royalty Commitments			278				278				386
Capital Lease Obligations			51				51				32
Total Long-Term Debt			161,160				161,160				167,809
Deferred Credits and Other Liabilities:
Postretirement Benefits Other Than Pensions			5,279				5,279				36,663
Pneumoconiosis Benefits			1,250				1,250				3,677
Asset Retirement Obligations			7,961				7,961				6,861
Workers’ Compensation			2,381				2,381				2,479
Other			609				609				800
Total Deferred Credits and Other Liabilities			17,480				17,480				50,480
TOTAL LIABILITIES			713,185				248,185				272,943
Invested Equity:
Parent Net Investment			(325,741	)			139,259				121,889
Accumulated Other Comprehensive Income (Loss)			31,367				31,367				(2,072	)
Total Invested Equity			(294,374	)			170,626				119,817
TOTAL LIABILITIES AND INVESTED EQUITY		$	418,811			$	418,811			$	392,760

The accompanying notes are an integral part of these combined financial statements.

 

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CNX COAL RESOURCES LP PREDECESSOR

COMBINED STATEMENT OF NET INVESTMENT

(Dollars in thousands)

 

		Parent Net Investment				Accumulated Other Comprehensive Income (Loss)				Total Invested Equity
December 31, 2012		$	97,533			$	(10,491	)		$	87,042
Net Income			64,292				—				64,292
Actuarially Determined Long-Term Liability Adjustments			—				8,419				8,419
Comprehensive Income			64,292				8,419				72,711
Net Change in Parent Advances			(39,936	)			—				(39,936	)
December 31, 2013			121,889				(2,072	)			119,817
Net Income			83,899				—				83,899
Actuarially Determined Long-Term Liability Adjustments			—				33,439				33,439
Comprehensive Income			83,899				33,439				117,338
Net Change in Parent Advances			(66,529	)			—				(66,529	)
December 31, 2014		$	139,259			$	31,367			$	170,626

The accompanying notes are an integral part of these combined financial statements.

 

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CNX COAL RESOURCES LP PREDECESSOR

COMBINED STATEMENTS OF CASH FLOWS

(Dollars in thousands)

 

		For the Years Ended December 31,
		2014				2013
Cash Flows from Operating Activities:
Net Income		$	83,899			$	64,292
Adjustments to Reconcile Net Income to Net Cash Provided By Operating Activities:
Depreciation, Depletion and Amortization			33,949				25,306
Gain/(Loss) on Sale of Assets			(148	)			124
Amortization of Mineral Leases			229				305
Changes in Operating Assets:
Other Receivables			(265	)			214
Inventories			293				(3,537	)
Prepaid Expenses			(203	)			(1,134	)
Changes in Other Assets			(1,274	)			(513	)
Changes in Operating Liabilities:
Accounts Payable			(1,751	)			(1,816	)
Other Operating Liabilities			925				8,342
Changes in Other Liabilities			(1,115	)			2,674
Other			(430	)			159
Net Cash Provided by Operating Activities			114,109				94,416
Cash Flows from Investing Activities:
Capital Expenditures			(68,061	)			(82,182	)
Proceeds from Sales of Assets			15,237				14,554
Net Cash Used in Investing Activities			(52,824	)			(67,628	)
Cash Flows from Financing Activities:
Payments on Miscellaneous Borrowings			(19	)			(13	)
Payments on Related Party Long-Term Notes			(1,849	)			(9,591	)
Proceeds from Related Party Long-Term Notes			11,371				18,893
Net Distributions to CONSOL Energy			(70,788	)			(36,078	)
Net Cash Used In Financing Activities			(61,285	)			(26,789	)
Net Change in Cash			—				(1	)
Cash at Beginning of Period			3				4
Cash at End of Period		$	3			$	3

The accompanying notes are an integral part of these combined financial statements.

 

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CNX COAL RESOURCES LP PREDECESSOR

NOTES TO COMBINED FINANCIAL STATEMENTS

(Dollars in thousands)

NOTE 1—DESCRIPTION OF BUSINESS AND BASIS OF PRESENTATION:

CNX Coal Resources LP (the “Partnership”) was formed by CONSOL Energy Inc. (“CONSOL Energy”) in March 2015 as a Delaware limited partnership. Upon completion of the Partnership’s proposed initial public offering (“IPO”), CONSOL Energy will contribute to the Partnership a 20% undivided interest in the combined assets, liabilities, revenues and expenses of CONSOL Pennsylvania Coal Company LLC (“CPCC”) and Conrhein Coal Company (“Conrhein”). CPCC and Conrhein’s assets and associated liabilities consist of the (i) Pennsylvania mining complex located in southwestern Pennsylvania, comprised of the Bailey mine, Enlow Fork mine and Harvey mine; (ii) coal reserves and properties associated with the Pennsylvania mining complex and (iii) preparation plant, facilities, equipment and other infrastructure associated with the Pennsylvania mining complex. The 20% undivided interest in the historical combined assets, liabilities, revenues and expenses of CPCC and Conrhein represents the Partnership’s predecessor for accounting purposes (the “Predecessor”). The accompanying financial statements and related notes include a 20% undivided interest in the assets, liabilities and results of operations of CPCC and Conrhein, presented on a proportionate basis, as of December 31, 2014 and 2013, and for the years then ended. As used in these financial statements, the terms “we,” “our,” “us,” or like terms refer to the Predecessor with respect to its 20% undivided interest in CPCC and Conrhein’s combined assets, liabilities, revenues and expenses. References in these financial statements to “CONSOL Energy” refer collectively to CONSOL Energy Inc. and its consolidated subsidiaries, other than the Predecessor.

The financial statements were prepared from separate records maintained by CONSOL Energy, CPCC and Conrhein and may not necessarily be indicative of the conditions that would have existed, or the results of operations, if CPCC and Conrhein had been operated as unaffiliated entities. As these combined financial statements represent the combination of two separate legal entities wholly owned by CONSOL Energy, the net assets of the Predecessor have been presented as a Parent Net Investment. Parent Net Investment is primarily comprised of the Predecessor’s undivided interest in (i) CONSOL Energy’s initial investment in CPCC and Conrhein (and any subsequent adjustments thereto); (ii) the accumulated net earnings; (iii) net transfers to or from CONSOL Energy, including those related to cash management functions performed by CONSOL Energy; (iv) non-cash changes in financing arrangements, including the conversion of certain related party liabilities into Parent Net Investment; and (v) corporate cost allocations. Transactions between the Predecessor and CONSOL Energy or CONSOL Energy’s other subsidiaries have been identified in the financial statements as transactions between related parties.

Supplemental Pro Forma Information (Unaudited):

Staff Accounting Bulletin 1.B.3 requires that certain distributions to owners prior to or concurrent with an initial public offering be considered as distributions in contemplation of that offering. Upon completion of CNX Coal Resources LP’s proposed initial public offering, CNX Coal Resources LP estimates that it will distribute approximately $465 million to CONSOL Energy Inc. The supplemental pro forma balance sheet as of December 31, 2014 gives pro forma effect to this assumed distribution as though it had been declared and was payable as of that date.

Use of Estimates:

The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, as well as various disclosures. Actual results could differ from those estimates. The most significant estimates included in the preparation of the combined financial statements are related to other postretirement benefits, coal workers’ pneumoconiosis, workers’ compensation, asset retirement obligations, contingencies, and coal reserve values.

 

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Cash:

The Predecessor participates in CONSOL Energy’s centralized cash management system. The centralized cash management system entitles the Predecessor to issue checks against the central bank account for ongoing operations. The presented checks against the central bank account are reflected as contributions of CONSOL Energy’s equity investment. The remaining amount recorded as cash includes petty cash on hand and on deposit at banking institutions not included in the centralized cash management system.

Trade Accounts Receivable:

The Predecessor’s trade accounts receivables are sold to CONSOL Energy, without recourse, when the revenue is recognized. CONSOL Energy is responsible for collecting and servicing the trade accounts receivables. The sold receivables are reflected as a distribution of CONSOL Energy’s equity investment.

Inventories:

Inventories are stated at the lower of cost or market. The cost of coal inventories is determined by the first-in, first-out (FIFO) method. Coal inventory costs include labor, supplies, equipment costs, depreciation, depletion and amortization, operating overhead and other related costs. The cost of supplies inventory is determined by the average cost method and includes operating and maintenance supplies to be used in our coal operations.

Property, Plant and Equipment:

Property, plant and equipment is recorded at cost upon acquisition. Expenditures which extend the useful lives of existing plant and equipment are capitalized. Interest costs applicable to major asset additions are capitalized during the construction period. Costs of additional mine facilities required to maintain production after a mine reaches the production stage, generally referred to as “receding face costs,” are expensed as incurred; however, the costs of additional airshafts and new portals are capitalized. Planned major maintenance costs which do not extend the useful lives of existing plant and equipment are expensed as incurred.

Coal exploration costs are expensed as incurred. Coal exploration costs include those incurred to ascertain existence, location, extent or quality of ore or minerals before beginning the development stage of the mine.

Costs of developing new underground mines and certain underground expansion projects are capitalized. Underground development costs, which are costs incurred to make the mineral physically accessible, include costs to prepare property for shafts, driving main entries for ventilation, haulage, personnel, construction of airshafts, roof protection and other facilities.

Airshafts and capitalized mine development associated with a coal reserve are amortized on a units-of-production basis as the coal is produced so that each ton of coal is assigned a portion of the unamortized costs. We employ this method to match costs with the related revenues realized in a particular period. Rates are updated when revisions to coal reserve estimates are made. Coal reserve estimates are reviewed when information becomes available that indicates a reserve change is needed, or at a minimum once a year. Any material effect from changes in estimates is disclosed in the period the change occurs. Amortization of development cost begins when the development phase is complete and the production phase begins. At an underground mine, the end of the development phase and the beginning of the production phase takes place when construction of the mine for economic extraction is substantially complete. Coal extracted during the development phase is incidental to the mine’s production capacity and is not considered to shift the mine into the production phase.

Advance mining royalties are advance payments made to lessors under terms of mineral lease agreements that are recoupable against future production using the units-of-production method. Depletion of leased coal interests is computed using the units-of-production method over proven and probable coal reserves.

 

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Advance mining royalties and leased coal interests are evaluated periodically, or at a minimum once a year, for impairment issues or whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. Any revisions are accounted for prospectively as changes in accounting estimates.

When properties are retired or otherwise disposed, the related cost and accumulated depreciation are removed from the respective accounts and any profit or loss on disposition is recognized in Gain (Loss) on Sale of Assets in the Combined Statement of Operations.

Depreciation of plant and equipment is calculated on the straight-line method over their estimated useful lives or lease terms generally as follows:

 

		Years
Buildings and improvements		10 to 45
Machinery and equipment		3 to 25
Leasehold improvements		Life of Lease

Costs to obtain coal lands are capitalized based on the cost at acquisition and are amortized using the units-of-production method over all estimated proven and probable reserve tons assigned and accessible to the mine. Proven and probable coal reserves exclude non-recoverable coal reserves and anticipated processing losses. Rates are updated when revisions to coal reserve estimates are made. Coal reserve estimates are reviewed when events and circumstances indicate a reserve change is needed, or at a minimum once a year. Amortization of coal interests begins when the coal reserve is produced. At an underground mine, a ton is considered produced once it reaches the surface area of the mine. Any material effect from changes in estimates is disclosed in the period the change occurs.

Impairment of Long-lived Assets:

Impairment of long-lived assets is recorded when indicators of impairment are present and the undiscounted cash flows estimated to be generated by those assets are less than the assets’ carrying value. The carrying value of the assets is then reduced to its estimated fair value which is usually measured based on an estimate of future discounted cash flows. There were no impairment losses recognized during the years ended December 31, 2014 and 2013.

Pension:

The personnel who operate CPCC and Conrhein’s assets are employees of CONSOL Energy and participate in certain defined benefit retirement plans administered by CONSOL Energy. CONSOL Energy directly charges the Predecessor for the service costs associated with these employees that participate in the salary retirement pension plans. CONSOL Energy reflects the obligations for the salary pension plan and the related pension trust in its financial statements. The Predecessor is charged a portion of the service costs of CONSOL Energy’s defined benefit pension plan for the retirees of CPCC based on an actuarial assessment of those costs. The Predecessor’s share of those costs is reflected in Operating and Other costs in the accompanying Combined Statements of Operations. Conrhein has no current or former employees.

Postretirement Benefits Other Than Pensions:

Postretirement benefits other than pensions are accounted for in accordance with the Retirement Benefits Compensation and Non-retirement Postemployment Benefits Compensation Topics of the Financial Accounting Standards Board (FASB) Accounting Standards Codification which requires employers to accrue the cost of such retirement benefits for the employees’ active service periods. Such liabilities are determined on an actuarial basis for the Predecessor’s dedicated contract labor provided under a service agreement with CONSOL Energy.

 

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Pneumoconiosis Benefits and Workers’ Compensation:

The Predecessor is required by federal and state statutes to provide benefits to certain current and former totally disabled employees or their dependents for awards related to coal workers’ pneumoconiosis. The Predecessor is also required by various state statutes to provide workers’ compensation benefits for employees who sustain employment related physical injuries or some types of occupational disease. Workers’ compensation benefits include compensation for their disability, medical costs, and on some occasions, the cost of rehabilitation. The provisions for estimated benefits are determined on an actuarial basis for the Predecessor’s dedicated contract labor provided under a service agreement with CONSOL Energy.

Asset Retirement Obligations:

Mine closing costs, perpetual water care costs and costs associated with dismantling and removing gas related facilities are accrued using the accounting treatment prescribed by the Asset Retirement and Environmental Obligations Topic of the FASB Accounting Standards Codification. This topic requires 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. Depreciation of the capitalized asset retirement cost is generally determined on a units-of-production basis. Accretion of the asset retirement obligation is recognized over time and generally will escalate over the life of the producing asset, typically as production declines. Accretion is included in Operating and Other Costs on the Combined Statements of Operations. Asset retirement obligations primarily relate to the closure of mines which includes treatment of water and the reclamation of land upon exhaustion of coal reserves.

Accrued mine closing costs, perpetual care costs and reclamation costs and costs of dismantling and removing gas-related facilities are regularly reviewed by management and are revised for changes in future estimated costs and regulatory requirements.

Subsidence:

Subsidence occurs when there is sinking of surface lands due to the removal of underlying coal. The affected areas related to subsidence include stream, property, roads, pipelines and other land and surface structures. Total estimated subsidence claims are recognized in the period when the related coal has been extracted and are included in Operating and Other Costs on the Combined Statements of Operations. Due to the timing of the actual expenditures for subsidence occurring before or after the associated tonnage is mined, a related prepaid subsidence asset, long-term subsidence asset or accrued subsidence liability is recognized in Prepaid Expenses, Other Assets or Other Accrued Liabilities, respectively, on the Combined Balance Sheets.

Income Taxes:

The Predecessor is comprised of a 20% undivided interest in assets and liabilities of CPCC and Conrhein and does not share in the separate income tax consequences attributable to the owners of CPCC and Conrhein. Accordingly, no provision for federal or state income taxes has been recorded. As of December 31, 2014 and 2013, the Predecessor had no liability reported for unrecognized tax benefits and had not incurred interest and penalties related to income taxes. Following the initial public offering of the Partnership, the Partnership’s operations will be treated as a partnership for federal and state income tax purposes, with each partner being separately taxed on its share of taxable income. Therefore, the Predecessor has excluded income taxes from these financial statements.

Revenue Recognition:

Revenues are recognized when title passes to the customers. For domestic coal sales, this generally occurs when coal is loaded at the mine preparation facility. For export coal sales, revenue recognition occurs when coal is loaded onto marine vessels at terminal locations.

 

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Freight Revenue and Expense:

Shipping and handling costs invoiced to coal customers and paid to third-party carriers are recorded as Freight Revenue and Freight Expense, respectively.

Royalty Recognition:

Royalty expenses for coal rights are included in Royalties and Production Taxes on the Combined Statements of Operations when the related revenue for the coal sale is recognized.

Contingencies:

The Predecessor, from time to time, is subject to various lawsuits and claims with respect to such matters as personal injury, wrongful death, damage to property, exposure to hazardous substances, governmental regulations (including environmental remediation), employment and contract disputes, and other claims and actions, arising out of the normal course of business. Liabilities are recorded when it is probable that obligations have been incurred and the amounts can be reasonably estimated. Estimates are developed through consultation with legal counsel involved in the defense and are based upon an analysis of potential results, assuming a combination of litigation and settlement strategies. Legal fees associated with defending these various lawsuits and claims are expensed when incurred.

Other Comprehensive Income (Loss):

Changes in Accumulated Other Comprehensive Income / (Loss) by component were as follows:

 

		Postretirement Benefits
Balance at December 31, 2013			(2,072	)
Other comprehensive income before reclassifications			36,909
Amounts reclassified from accumulated other comprehensive income			(3,470	)
Other comprehensive income			33,439
Balance at December 31, 2014		$	31,367

The following table shows the reclassification of adjustments out of Accumulated Other Comprehensive Loss:

 

		For the Years Ended December 31,
		2014				2013
Actuarially Determined Long-Term Liability Adjustments* (Note 11 and Note 12)
Amortization of prior service costs		$	(1,865	)		$	(624	)
Recognized net actuarial loss			437				779
Curtailment gains			(2,042	)			—
Total		$	(3,470	)		$	155

Recent Accounting Pronouncements:

In May 2014, the Financial Accounting Standards Board issued Update 2014-09—Revenue from Contracts with Customers (Topic 606). The objective of the amendments in this update is to improve financial reporting by creating common revenue recognition guidance for accounting principles generally accepted in the

 

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United States (U.S. GAAP) and International Financial Reporting Standards (IFRS). The guidance in this update supersedes the revenue recognition requirements in Topic 605, Revenue Recognition, and most industry-specific guidance throughout the Industry Topics of the Codification. The core principle of the guidance is that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. An entity should disclose sufficient information, both qualitative and quantitative, to enable users of financial statements to understand the nature, amount, timing, and uncertainty of revenue and cash flows arising from contracts with customers. The amendments in this update are effective for annual reporting periods beginning after December 15, 2016, including interim periods within that reporting period. Early application is not permitted. Management believes adoption of this new guidance will not have a material impact on the Predecessor’s financial statements.

Parent Net Investment:

Parent Net Investment represents a net balance reflecting CONSOL Energy’s initial investment in the Predecessor, subsequent adjustments resulting from the operations of the Predecessor and various transactions between the Predecessor and CONSOL Energy. The balance also includes the results of the Predecessor’s participation in CONSOL Energy’s centralized cash management program and other allocated costs.

Subsequent Events:

Events and transactions subsequent to the balance sheet date have been evaluated through April 1, 2015, the date these financial statements were issued, for potential recognition or disclosure in the financial statements.

NOTE 2—ACQUISITIONS AND DISPOSITIONS:

In March 2014, the Predecessor completed a sale-leaseback of longwall shields for the Harvey mine. Cash proceeds for the sale offset the basis of $15,071; therefore, no gain or loss was recognized on the sale. The five-year lease has been accounted for as an operating lease.

In January 2013, the Predecessor completed a sale-leaseback of longwall shields for the Bailey mine. Cash proceeds for the sale were $14,233. The Predecessor recognized a loss of $72 due to transaction fees and was included in Gain (Loss) on Sale of Assets in the Combined Statements of Operations. The five-year lease has been accounted for as an operating lease.

NOTE 3—OTHER INCOME:

 

		For the Years Ended December 31,
		2014				2013
Coal Contract Buyout		$	6,000			$	—
Litigation Settlement			855				—
Business Interruption Proceeds			—				1,089
Other			725				247
Total Other Income		$	7,580			$	1,336

The $1,089 of Business Interruption Proceeds included in Other Income in the Combined Statements of Operations is related to the preparation plant belt collapse that occurred in 2012. On July 27, 2012, a structural failure occurred at the above-ground conveyor system at the preparation plant. The belt system conveys coal from the Bailey and Enlow Fork mines to the preparation plant. This incident caused a total of four longwalls to be idled for approximately three weeks, at which point one rebuilt conveyor belt was re-started.

 

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NOTE 4—INTEREST EXPENSE:

 

		For the Years Ended December 31,
		2014				2013
Interest on Notes—Related Party		$	9,534			$	9,310
Interest on Other Payables, Net			1				(8	)
Interest Capitalized			(2,589	)			(7,209	)
Total Interest Expense		$	6,946			$	2,093

NOTE 5—ASSET RETIREMENT OBLIGATIONS:

The reconciliation of changes in the Asset Retirement Obligations at December 31, 2014 and December 31, 2013 is as follows:

 

		Year Ended December 31,
		2014				2013
Balance at beginning of period		$	7,662			$	5,730
Accretion expense			723				540
Payments			(801	)			(7	)
Revisions in estimated cash flows			1,527				1,399
Balance at end of period		$	9,111			$	7,662

NOTE 6—INVENTORIES:

Inventories consist of the following at December 31, 2014 and 2013:

 

		December 31, 2014				December 31, 2013
Coal		$	1,718			$	2,320
Supplies			8,921				8,612
Total Inventories		$	10,639			$	10,932

NOTE 7—PROPERTY, PLANT AND EQUIPMENT:

 

		December 31, 2014				December 31, 2013
Coal and other plant and equipment		$	441,933			$	413,745
Coal properties and surface lands			107,158				103,123
Airshafts			68,855				57,476
Mine development			65,340				53,974
Coal advance mining royalties			3,307				2,890
Total property, plant and equipment			686,593				631,208
Less: Accumulated depreciation, depletion and amortization			287,707				256,924
Total Net Property, Plant and Equipment		$	398,886			$	374,284

Coal reserves are controlled either through fee ownership or by lease. The duration of the leases vary; however, the lease terms generally are extended automatically to the exhaustion of economically recoverable reserves, as long as active mining continues. Coal interests held by lease provide the same rights as fee ownership for mineral extraction and are legally considered real property interests.

 

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As of December 31, 2014 and 2013, plant and equipment includes gross assets under capital lease of $333 and $287, respectively. Accumulated amortization for capital leases was $252 and $239 at December 31, 2014 and 2013, respectively. Amortization expense for assets under capital leases approximated $19 and $10 for the years ended December 31, 2014 and 2013, respectively, and is included in Depreciation, Depletion and Amortization in the accompanying Combined Statements of Operations. See Note 10—Leases for further discussion of capital leases.

NOTE 8—OTHER ACCRUED LIABILITIES:

 

		December 31, 2014				December 31, 2013
Subsidence liability		$	20,854			$	19,660
Accrued payroll and benefits			3,253				3,170
Litigation			2,346				986
Equipment lease rental			1,948				1,329
Short-term incentive compensation			1,103				1,137
Deferred revenue			286				2,736
Other			1,955				1,748
Current portion of long-term liabilities:
Postretirement benefits other than pensions			1,540				1,738
Asset retirement obligations			1,150				801
Workers’ compensation			922				1,032
Long-term disability			121				167
Pneumoconiosis benefits			24				73
Total Other Accrued Liabilities		$	35,502			$	34,577

NOTE 9—LONG-TERM DEBT:

 

		December 31, 2014				December 31, 2013
CONSOL Financial Inc. Loan (5.46% and 5.48% weighted average interest rate at December 31, 2014 and 2013, respectively)		$	178,762			$	169,240
Advance royalty commitments (7.91% and 7.93% weighted average interest rate for December 31, 2014 and 2013, respectively)			578				611
			179,340				169,851
Less amounts due in one year *			18,231				2,074
Long-Term Debt		$	161,109			$	167,777

 

*	Excludes current portion of Capital Lease Obligations of $30 and $15 at December 31, 2014 and December 31, 2013, respectively.

The CONSOL Financial Inc. Loan represents multiple 10-year term notes at the applicable federal rates upon execution, which are due at various future dates.

 

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Annual undiscounted maturities on long-term debt are as follows for the years ended December 31:

 

2015		$	18,231
2016			49,412
2017			25,593
2018			18,268
2019			11,215
Thereafter			56,621
Total Long-Term Debt Maturities		$	179,340

NOTE 10—LEASES:

The Predecessor uses various leased facilities and equipment in its operations. Future minimum lease payments under capital and operating leases, together with the present value of the net minimum capital lease payments December 31, 2014, are as follows:

 

		Capital Leases				Operating Leases
2015		$	30			$	9,271
2016			21				9,108
2017			17				8,867
2018			13				7,139
2019			4				3,120
Thereafter			—				3,576
Total minimum lease payments		$	85			$	41,081
Less amount representing interest (0.63%—1.88%)			4
Present value of minimum lease payments			81
Less amount due in one year			30
Total Long-Term Capital Lease Obligation		$	51

Rental expense related to operating leases approximated $10,006 and $7,153 during the years ended December 31, 2014 and 2013, respectively.

NOTE 11—OTHER POSTRETIREMENT BENEFIT PLANS:

Other Postretirement Benefit Plans:

The Predecessor is contractually obligated for a portion of the medical and life insurance benefits to retired employees of CONSOL Pennsylvania Coal Company LLC (the “OPEB Plans”). The medical plans contain certain cost sharing and containment features, such as deductibles, coinsurance, health care networks and coordination with Medicare. Also, salaried employees and retirees contribute a target of 20% of the medical plan operating costs. Contributions may be higher, depending on either years of service or a combination of age and years of service at retirement. Prospective annual cost increases of up to 6% will be shared by the Predecessor and the participants based on their age and years of service at retirement. Annual cost increases in excess of 6% will be the responsibility of the participants. The eligibility requirements to participate in the plans are as follows:

 

•

For salaried or non-represented hourly retirees hired before January 1, 2007 who did not work in a corporate or operational support position, the eligibility requirement is either age 55 with 20 years of service or age 62 with 15 years of service for traditional retiree health coverage.

 

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•

Salaried or non-represented hourly retirees hired or re-hired on or after January 1, 2007 who did not work in a corporate or operational support position receive a retiree medical spending allowance of $2,250 per year for each year of service at retirement.

 

•

Retirees who worked in corporate or operational support positions at retirement receive a fixed annual retiree medical contribution into a Health Reimbursement Account. The amount of the contribution is dependent on several factors, and the money in the account can be used to help pay for a commercial medical plan, Medicare Part B or Part D premiums, and other qualified medical expenses

On September 30, 2014, the plans were amended to reduce future benefits as of October 1, 2014. Salaried and non-represented hourly retirees as of September 30, 2014 will continue in the aforementioned OPEB Plans, which are currently anticipated to remain unchanged, until December 31, 2019, and coverage thereafter will be eliminated. Further, effective September 30, 2014, retiree medical, prescription drug and life insurance benefits are no longer provided to active employees. The Predecessor elected to make cash transition payments totaling approximately $5,341 to the active employees whose retiree medical, prescription drug, and life insurance benefits were eliminated by the changes to the OPEB Plans. These cash payments are not considered to be post-retirement benefits, and as such, they are not reflected in the actuarial calculations related to the OPEB Plans. The cash payment is reflected as expense in the Operating and Other Costs line of the Combined Statement of Operations. The amendment to the OPEB Plans resulted in a $28,375 reduction in the OPEB liability with a corresponding adjustment in Other Comprehensive Income. A curtailment gain of $2,042 was recognized in September 2014 with a corresponding adjustment in Other Comprehensive Income. The amendment also resulted in a remeasurement of the OPEB Plans at September 30, 2014.

The reconciliation of changes in the benefit obligation, plan assets and funded status of these plans at December 31, 2014 and December 31, 2013, is as follows:

 

		Other Postretirement Benefits
		At December 31, 2014				At December 31, 2013
Change in benefit obligation:
Benefit obligation at beginning of period		$	38,401			$	44,278
Service cost			741				1,236
Interest cost			1,408				1,753
Actuarial gain			(3,905	)			(7,201	)
Plan amendments			(28,375	)			—
Participant contributions			79				199
Benefits and other payments			(1,530	)			(1,864	)
Benefit obligation at end of period		$	6,819			$	38,401
Funded status:
Current liabilities		$	(1,540	)		$	(1,738	)
Noncurrent liabilities			(5,279	)			(36,663	)
Net obligation recognized		$	(6,819	)		$	(38,401	)
Amounts recognized in accumulated other comprehensive income consist of:
Net actuarial loss		$	(3,796	)		$	(8,119	)
Prior service credit			26,264				1,572
Net amount recognized		$	22,468			$	(6,547	)

 

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The components of net periodic benefit costs are as follows:

 

		Other Postretirement Benefits
		For the Years Ended December 31,
		2014				2013
Components of net periodic benefit cost:
Service cost		$	741			$	1,236
Interest cost			1,408				1,753
Amortization of prior service credits			(1,865	)			(624	)
Recognized net actuarial loss			640				1,146
Curtailment gain recognized			(2,042	)			—
Net periodic benefit cost (credit)		$	(1,118	)		$	3,511

Amounts included in accumulated other comprehensive income, expected to be recognized in 2015 net periodic benefit costs:

 

Prior service credit recognition		$	5,253
Actuarial loss recognition		$	(1,297	)

Assumptions:

The weighted-average assumptions used to determine benefit obligations are as follows:

 

		At December 31, 2014				At December 31, 2013
Discount rate			1.84	%			4.88	%

The discount rates are determined using a Predecessor-specific yield curve model (above-mean) developed with the assistance of an external actuary. The Predecessor-specific yield curve models (above-mean) use a subset of the expanded bond universe to determine the Predecessor-specific discount rate. Bonds used in the yield curve are rated AA by Moody’s or Standard & Poor’s as of the measurement date. The yield curve models parallel the plans’ projected cash flows, and the underlying cash flows of the bonds included in the models exceed the cash flows needed to satisfy the Predecessor’s plans.

The weighted-average assumptions used to determine net periodic benefit costs are as follows:

 

		At December 31, 2014				At December 31, 2013
Discount rate			4.88	%			4.05	%

The assumed health care cost trend rates are as follows:

 

		At December 31, 2014				At December 31, 2013
Health care cost trend rate for next year			6.03	%			6.17	%
Rate to which the cost trend is assumed to decline (ultimate trend rate)			4.50	%			4.50	%
Year that the rate reaches ultimate trend rate			2026				2026

 

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Assumed health care cost trend rates have a significant effect on the amounts reported for the medical plans. A one-percentage point change in assumed health care cost trend rates would have the following effects:

 

		1-Percentage Point Increase				1-Percentage Point Decrease
Effect on total of service and interest cost components		$	284			$	(230	)
Effect on accumulated postretirement benefit obligation		$	187			$	(194	)

Assumed discount rates also have a significant effect on the amounts reported for the other postemployment benefit costs. A one-quarter percentage point change in assumed discount rate would have the following effect on benefit costs:

 

		0.25 Percentage Point Increase				0.25 Percentage Point Decrease
Other postemployment benefits costs (decrease) increase		$	(149	)		$	158

Plan Assets:

There are no assets in the other postretirement benefit plans at December 31, 2014 or December 31, 2013.

Cash Flows:

The Predecessor does not expect to contribute to the other postemployment benefit plan in 2015. We intend to pay benefit claims as they are due.

The following benefit payments, reflecting expected future service, are expected to be paid:

 

		Other Postretirement Benefits
2015		$	1,540
2016			1,477
2017			1,421
2018			1,373
2019			1,312
Year 2020-2024			—

NOTE 12—COAL WORKERS’ PNEUMOCONIOSIS (CWP) AND WORKERS’ COMPENSATION:

The Predecessor is contractually obligated for medical and disability benefits to CPCC employees and their dependents resulting from occurrences of coal workers’ pneumoconiosis disease (“CWP”). Conrhein has no current or former employees. The Predecessor is also responsible under various state statutes for pneumoconiosis benefits. The calculation of the actuarial present value of the estimated pneumoconiosis obligation is based on an annual actuarial study by external actuaries and uses assumptions regarding disability incidence, medical costs, indemnity levels, mortality, death benefits, dependents and interest rates which are derived from actual Predecessor experience and outside sources. Although recent CWP legislation has not had a significant impact on the liability, the Predecessor has noticed an increase in claims. Actuarial gains or losses can result from differences in incident rates and severity of claims filed as compared to original assumptions.

The Predecessor is also contractually responsible to compensate individuals who sustain employment related physical injuries or some types of occupational diseases and, on some occasions, for costs of their rehabilitation. Workers’ compensation laws will also compensate survivors of workers who suffer employment

 

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related deaths. Workers’ compensation laws are administered by state agencies with each state having its own set of rules and regulations regarding compensation that is owed to an employee that is injured in the course of employment. The Predecessor primarily provides for these claims through a self-insurance program. The Predecessor recognizes an actuarial present value of the estimated workers’ compensation obligation calculated by independent actuaries. The calculation is based on claims filed and an estimate of claims incurred but not yet reported as well as various assumptions. The assumptions include discount rate, future healthcare trend rate, benefit duration and recurrence of injuries. Actuarial gains associated with workers’ compensation have resulted from discount rate changes, several years of favorable claims experience, various favorable state legislation changes and overall lower incident rates than our assumptions.

 

		CWP								Workers’ Compensation
		December 31,								December 31,
		2014				2013				2014				2013
Change in benefit obligation:
Benefit obligation at beginning of period		$	3,750			$	3,805			$	3,511			$	2,871
State administrative fees and insurance bond premiums			—				—				493				493
Service, legal and administrative cost			698				501				1,440				1,478
Expenses paid			(24	)			—				—				—
Interest cost			171				149				148				111
Actuarial gain			(3,253	)			(632	)			(1,251	)			(258	)
Benefits paid			(68	)			(73	)			(1,038	)			(1,184	)
Benefit obligation at end of period		$	1,274			$	3,750			$	3,303			$	3,511
Current liabilities		$	(24	)		$	(73	)		$	(922	)		$	(1,032	)
Noncurrent liabilities			(1,250	)			(3,677	)			(2,381	)			(2,479	)
Net obligation recognized		$	(1,274	)		$	(3,750	)		$	(3,303	)		$	(3,511	)
Amounts recognized in accumulated other comprehensive income consist of:
Net actuarial gain		$	6,137			$	3,077			$	2,675			$	1,440
Net amount recognized		$	6,137			$	3,077			$	2,675			$	1,440

The components of the net periodic cost are as follows:

 

		CWP								Workers’ Compensation
		For the Years Ended December 31,								For the Years Ended December 31,
		2014				2013				2014				2013
Service cost		$	698			$	501			$	1,440			$	1,478
Interest cost			171				149				148				111
Recognized net actuarial gain			(192	)			(348	)			(16	)			(44	)
State administrative fees and insurance bond premiums			—				—				493				493
Net periodic cost		$	677			$	302			$	2,065			$	2,038

Amounts included in accumulated other comprehensive income, expected to be recognized in 2015 net periodic benefit costs:

 

		CWP Benefits				Workers’ Compensation Benefits
Actuarial gain recognition		$	56			$	1

 

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Assumptions:

The weighted-average discount rate used to determine benefit obligations and net periodic costs are as follows:

 

		CWP								Workers’ Compensation
		At December 31,				At December 31,				At December 31,				At December 31,
		2014				2013				2014				2013
Benefit obligations			4.21	%			4.75	%			3.84	%			4.57	%
Net periodic costs			4.75	%			4.03	%			4.57	%			3.95	%

Assumed discount rates have a significant effect on the amounts reported for both CWP benefits and Workers’ Compensation costs. A one-quarter percentage point change in assumed discount rate would have the following effect on benefit costs:

 

		0.25 Percentage Point Increase				0.25 Percentage Point Decrease
CWP costs (decrease) increase		$	(18	)		$	19
Workers’ Compensation costs (decrease) increase		$	(12	)		$	13

Cash Flows:

The Predecessor does not intend to make contributions to the CWP or Workers’ Compensation plans in 2015. We intend to pay benefit claims as they become due.

The following benefit payments, which reflect expected future claims as appropriate, are expected to be paid:

 

						Workers’ Compensation
		CWP Benefits				Total Benefits				Actuarial Benefits				Other Benefits
2015		$	24			$	1,043			$	922			$	121
2016			20				1,036				912				124
2017			20				1,040				912				127
2018			22				1,048				917				131
2019			24				1,056				922				134
Year 2020-2024			165				5,504				4,783				721

NOTE 13—OTHER BENEFIT PLANS:

Salaried Pension:

The Predecessor is contractually obligated to fund 20% of the service costs for CONSOL Pennsylvania Coal Company LLC employees, which provide mining services to the Predecessor, that participate in the CONSOL Energy Salaried Pension Plan. CONSOL Energy has non-contributory defined benefit retirement plans covering substantially all salaried employees. The benefits for these plans are based primarily on years of service and employees’ salaries near retirement. On September 30, 2014, the qualified pension plan was amended to reduce future accruals of pension benefits as of December 31, 2014. The plan amendment called for a hard freeze of the defined benefit pension plan on December 31, 2014 for employees who were under age 40 or had less than 10 years of service as of September 30, 2014. In addition, employees hired or rehired on or after October 1, 2014 are not eligible to participate in the plan; however, beginning January 1, 2015, the Predecessor will contribute an additional 3% of eligible compensation into the 401(k) plan accounts for these affected employees. Employees who were age 40 or over and had at least 10 years of service as of September 30, 2014 will continue in the defined benefit pension plan unchanged. The Predecessor costs of these benefits during the years ended December 31, 2014 and 2013 were $1,402 and $1,464, respectively. These amounts are funded to CONSOL

 

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Energy as a component of parent advances. The Predecessor expects to fund comparable amounts in future periods. These costs are reflected in Other Corporate Expenses in the Combined Statements of Operations.

Investment Plan:

The Predecessor is contractually obligated to fund 20% of CONSOL Pennsylvania Coal Company LLC’s portion of CONSOL Energy’s investment plan. CONSOL Energy’s investment plan is available to all domestic, non-represented employees. CONSOL Energy’s plan includes company matching of 6% of eligible compensation contributed for all non-represented employees of CONSOL Pennsylvania Coal Company LLC. Total payments and costs were $612 and $584 for the years ended December 31, 2014 and 2013, respectively.

Long-Term Disability:

The Predecessor is contractually obligated for a Long-Term Disability Plan available to all eligible full-time salaried employees of CONSOL Pennsylvania Coal Company LLC. The benefits for this plan are based on a percentage of monthly earnings, offset by all other income benefits available to the disabled.

 

		For the Years Ended
		December 31, 2014				December 31, 2013
Benefit costs		$	126			$	198
Discount rate assumption used to determine net periodic benefit costs			3.53	%			3.04	%

Long-Term Disability related liabilities are included in Deferred Credits and Other Liabilities–Other and Other Accrued Liabilities on the Combined Balance Sheets and amounted to $527 and $664 at December 31, 2014 and 2013, respectively.

NOTE 14—SUPPLEMENTAL CASH FLOW INFORMATION:

For the years ended December 31, 2014 and 2013, the Predecessor paid interest expense, net of capitalized interest, of $6,949 and $2,090, respectively.

The following are non-cash transactions that impact the investing and financing activities of the Predecessor. For non-cash transactions that relate to acquisitions and dispositions, refer to Note 2.

As of December 31, 2014 and 2013, the Predecessor purchased goods and services related to capital projects in the amount of $454 and $1,226, respectively, that are included in accounts payable.

The Predecessor obtains capital lease arrangements for company-used vehicles. For the years ended December 31, 2014 and 2013, the Predecessor entered into non-cash capital lease arrangements of $52 and $34, respectively.

As of December 31, 2014 and 2013, there were capital equipment transfers of $4,259 and $3,858, respectively, between the Predecessor and CONSOL Energy that are included in Parent Net Investment.

NOTE 15—CONCENTRATION OF CREDIT RISK AND MAJOR CUSTOMERS:

The Predecessor markets thermal coal and metallurgical coal principally to electric utilities in the eastern United States.

For the years ended December 31, 2014 and 2013, sales to our coal customers, Duke Energy and GenOn Energy Management, each exceeded 10% of our revenues, and for the year ended December 31, 2013 sales to XCoal Energy & Resources and South Carolina Public Service Commission each exceeded 10% of our revenues.

 

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NOTE 16—FAIR VALUE OF FINANCIAL INSTRUMENTS:

The Predecessor determines the fair value of assets and liabilities based on the exchange price that would be received for an asset or paid to transfer a liability (an exit price) in the principal or most advantageous market for the asset or liability in an orderly transaction between market participants. The fair values are based on assumptions that market participants would use when pricing an asset or liability, including assumptions about risk and the risks inherent in valuation techniques and the inputs to valuations. The fair value hierarchy is based on whether the inputs to valuation techniques are observable or unobservable. Observable inputs reflect market data obtained from independent sources (including LIBOR-based discount rates), while unobservable inputs reflect the Predecessor’s own assumptions of what market participants would use.

The fair value hierarchy includes three levels of inputs that may be used to measure fair value as described below.

Level One—Quoted prices for identical instruments in active markets.

Level Two—The fair value of the assets and liabilities included in Level 2 are based on standard industry income approach models that use significant observable inputs, including LIBOR-based discount rates.

Level Three—Unobservable inputs significant to the fair value measurement supported by little or no market activity. The significant unobservable inputs used in the fair value measurement of the Predecessor’s third party guarantees are the credit risk of the third party and the third party surety bond markets.

In those cases when the inputs used to measure fair value meet the definition of more than one level of the fair value hierarchy, the lowest level input that is significant to the fair value measurement in its totality determines the applicable level in the fair value hierarchy.

The following methods and assumptions were used to estimate the fair value for which the fair value option was not elected:

Long-term debt: The fair value of long-term debt is measured using unadjusted quoted market prices or estimated using discounted cash flow analyses. The discounted cash flow analyses are based on current market rates for instruments with similar cash flows.

The carrying amounts and fair values of financial instruments for which the fair value option was not elected are as follows:

 

		December 31, 2014								December 31, 2013
		Carrying Amount				Fair Value				Carrying Amount				Fair Value
Long-term debt		$	178,762			$	159,109			$	169,240			$	149,915

The Predecessor’s debt obligations are valued through reference to the applicable underlying benchmark rate and, as a result, constitute Level 2 fair value measurements.

NOTE 17—COMMITMENTS AND CONTINGENT LIABILITIES:

The Predecessor is subject to various lawsuits and claims with respect to such matters as personal injury, wrongful death, damage to property, exposure to hazardous substances, governmental regulations (including environmental remediation), employment and contract disputes and other claims and actions arising out of the normal course of business. We accrue the estimated loss for these lawsuits and claims when the loss is probable

 

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and can be estimated. Our current estimated accruals related to these pending claims, individually and in the aggregate, are immaterial to the financial position, results of operations or cash flows of the Predecessor, and there are no material pending claims that would require disclosure in the financial statements individually or in the aggregate. It is possible that the aggregate loss in the future with respect to these lawsuits and claims could ultimately be material to the financial position, results of operations or cash flows of the Predecessor; however, such amount cannot be reasonably estimated.

At December 31, 2014, the Predecessor is contractually obligated to CONSOL Energy for the following financial guarantees, unconditional purchase obligations and letters of credit to certain third parties, as described by major category in the following table. Letters of credit to third parties, reflected below, were issued by CONSOL Energy on behalf of the Predecessor under the centralized treasury function. These amounts represent the maximum potential total of future payments that we could be required to make under these instruments. These amounts have not been reduced for potential recoveries under recourse or collateralization provisions. Generally, recoveries under reclamation bonds would be limited to the extent of the work performed at the time of the default. No amounts related to these financial guarantees and letters of credit are recorded as liabilities on the financial statements. The Predecessor’s management believes that these guarantees will expire without being funded, and therefore the commitments will not have a material adverse effect on the financial condition of the Predecessor.

 

		Amount of Commitment Expiration Per Period
		Total Amounts Committed				Less Than 1 Year				1-3 Years				3-5 Years				Beyond 5 Years
Letters of Credit:
Employee-related		$	3,845			$	3,845			$	—			$	—			$	—
Environmental			241				101				140				—				—
Total Letters of Credit			4,086				3,946				140				—				—
Surety Bonds:
Employee-related			7,960				7,960				—				—				—
Environmental			46,285				46,285				—				—				—
Other			1,208				1,208				—				—				—
Total Surety Bonds			55,453				55,453				—				—				—
Total Commitments		$	59,539			$	59,399			$	140			$	—			$	—

Employee-related financial guarantees have primarily been provided to support various state workers’ compensation self-insurance programs. Environmental financial guarantees have primarily been provided to support various performance bonds related to reclamation and other environmental issues. Other guarantees have been extended to support insurance policies, legal matters, full and timely payments of mining equipment leases, and various other items necessary in the normal course of business.

The Predecessor enters into long-term unconditional purchase obligations. These purchase obligations are not recorded on the Combined Balance Sheet. As of December 31, 2014, the purchase obligations for each of the next five years and beyond were as follows:

 

Obligations Due		Amount
Less than 1 year		$	2,464
1—3 years			—
3—5 years			—
More than 5 years			—
Total Purchase Obligations		$	2,464

 

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NOTE 18—RELATED PARTY:

The Combined Statements of Operations include expense allocations for certain corporate functions historically performed by CONSOL Energy, including allocations of general corporate expenses related to stock based compensation, legal, treasury, human resources, information technology, engineering, and other administrative services. Those allocations were based primarily on specific identification, head counts and coal tons produced. Also, centralized cash management activities for CONSOL Energy were utilized for collections and payments related to normal course of business accounts receivable and payments for goods and services. The balance of receivable/payable from CONSOL Energy and other affiliates are presented as contributions/distributions in these combined financial statements. Management believes the assumptions underlying the Combined Financial Statements, including the assumptions regarding allocating general corporate expenses from CONSOL Energy are reasonable. Nevertheless, the Combined Financial Statements may not include all of the actual expenses that would have been incurred by the Predecessor and may not reflect our Combined Statement of Operations, Balance Sheet and Cash Flows had we been a stand-alone company during the periods presented. Actual costs that would have been incurred if the Predecessor had been a stand-alone company would depend on multiple factors, including organizational structure and strategic decisions made in various areas, including information technology and infrastructure.

We believe that transactions with related parties, other than certain transactions with CONSOL Energy related to administrative services, were conducted on terms comparable to those with unrelated parties.

Purchases of supply inventory from Fairmont Supply Company, formerly a wholly owned subsidiary of CONSOL Energy, were approximately $8,680 and $9,171 for the years ended December 31, 2014 and 2013, respectively, and are included in Operating and Other Costs in the accompanying Combined Statements of Operations.

Charges for services from CONSOL Energy include the following:

 

		Year Ended December 31,
		2014				2013
Operating and Other Costs		$	2,014			$	2,048
Selling and Direct Administrative Expenses			5,791				5,537
General and Administrative Expenses—Related Party			5,198				4,521
Other Corporate Expenses			7,944				7,516
Total Service from CONSOL Energy		$	20,947			$	19,622

The Predecessor has several related party long-term loans with CONSOL Financial Inc., a wholly owned subsidiary of CONSOL Energy, that are disclosed within Note 9. Payments on the loans for the years ended December 31, 2014 and 2013 were $1,849 and $9,591, respectively. Proceeds from additional loans for the years ended December 31, 2014 and 2013 were $11,371 and $18,893, respectively. Interest Expense was $9,534 and $9,310 for the years ended December 31, 2014 and 2013, respectively, and is included in Interest Expense in the accompanying Combined Statements of Operations.

 

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SUPPLEMENTAL COAL DATA (UNAUDITED)

The table below represents our 20% undivided interest in the proved and probable reserves as of December 31, 2014 and December 31, 2013.

 

		For the Year Ended December 31,
		2014				2013
		(Thousands of Tons)
Proved and probable reserves at beginning of period			125,066				131,437
Purchased reserves			1				1
Reserves sold in place			—				(2,037	)
Production			(5,213	)			(4,287	)
Revisions and other changes			37,273				(48	)
Consolidated proved and probable reserves at end of period*			157,127				125,066

 

*	Proved and probable coal reserves are the equivalent of “demonstrated reserves” under the coal resource classification system of the U.S. Geological Survey. Generally, these reserves would be commercially mineable at year-end prices and cost levels, using current technology and mining practices.

Our coal reserves are located in southwestern Pennsylvania and the northern panhandle of West Virginia. At December 31, 2014, 157,127 tons of proven and probable reserves were assigned and/or accessible to our three active mines (Bailey, Enlow Fork and Harvey mines). Of the 2014 total reserves, Enlow Fork mine equates to 64,568 tons, Bailey Mine to 50,900 tons and Harvey Mine to 41,659 tons. On average, 100 percent of the reserves have a sulfur content equivalent to greater than 2.5 pounds sulfur dioxide per million British Thermal Units (Btu). Of the 2014 reserve average of 3.6 pounds sulfur dioxide per million Btu, Enlow Fork mine equates to 3.4, Bailey mine to 3.4 and Harvey mine to 4.1.

Our estimate of proven and probable coal reserves has been determined by CONSOL Energy’s geologists and mining engineers. CONSOL Energy geologists and mining engineers completed an extensive re-evaluation of the longwall mineable Pittsburgh seam during 2014. The re-evaluations included the use of mine specific assumptions and mine plans versus general mine recovery factors and general parameters. To date, approximately 98% of our operations have been re-evaluated using mine specific parameters as opposed to an assumed average mining recovery factor. The 2014 re-evaluations resulted in an increase of 37,273 tons, or 29.8%, over the 2013 reserve estimates. Approximately 98% of our reserves were audited by Golder Associates Inc. in 2014.

 

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM 

To the Partners of CNX Coal Resources LP

We have audited the accompanying balance sheet of CNX Coal Resources LP (the Partnership) as of March 27, 2015. This balance sheet is the responsibility of the Partnership’s management. Our responsibility is to express an opinion on this balance sheet based on our audit.

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

In our opinion, the balance sheet referred to above presents fairly, in all material respects, the financial position of CNX Coal Resources LP at March 27, 2015 in conformity with U.S. generally accepted accounting principles.

/s/ Ernst & Young LLP

Pittsburgh, Pennsylvania

April 1, 2015

 

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CNX COAL RESOURCES LP

BALANCE SHEET

MARCH 27, 2015

 

Assets
Total Assets		$	—
Partners’ Capital
Limited Partner		$	980
General Partner			20
Less: Notes Receivable from Limited Partner			(980	)
Less: Note Receivable from General Partner			(20	)
Total Partners’ Capital		$	—

 

 

The accompanying notes are an integral part of this balance sheet.

 

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CNX COAL RESOURCES LP

NOTES TO BALANCE SHEET

1. Description of the Business

CNX Coal Resources LP (the “Partnership”) is a Delaware limited partnership formed on March 16, 2015. CNX Coal Resources GP LLC (the “General Partner”) is a Delaware limited liability company formed on March 16, 2015 and is the general partner of the Partnership. CONSOL Energy Inc., a Delaware Corporation (the “Limited Partner”), is the limited partner and is the parent of the General Partner.

On March 26, 2015, the Limited Partner contributed $980 in the form of a note receivable to the Partnership in exchange for a 98% limited partner interest. The General Partner contributed $20 in the form of a note receivable to the Partnership in exchange for a 2% general partner interest. There have been no other transactions involving the Partnership as of March 27, 2015.

2. Subsequent Events

Events and transactions subsequent to the balance sheet date have been evaluated through April 1, 2015, the date the balance sheet was issued, for potential recognition or disclosure.

 

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Appendix A

FORM OF FIRST AMENDED AND RESTATED AGREEMENT OF LIMITED PARTNERSHIP OF

CNX COAL RESOURCES LP

[To be filed by amendment]

 

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Appendix B

GLOSSARY OF TERMS

Accessible reserves. Accessible reserves are proven and probable reserves that can be accessed by an existing mine, utilizing the existing infrastructure of the complex to mine and to process the coal in this area. Accessible reserves do not have their required permits or governmental approvals.

Ash. Inorganic material consisting of silica, alumina, iron, calcium, sodium and other incombustible matter that is contained in coal. The composition of the ash can affect the burning characteristics of coal.

Assigned reserves. Coal that has been committed to be mined at an identified mine. All assigned reserves have their required permits or governmental approvals, or there is a high probability that these approvals will be secured.

Average cash margin per ton. Average cash margin per ton sold is the average sales price per ton sold less the total costs of coal sold per ton (excluding depreciation, depletion and amortization costs of coal sold per ton).

Bituminous coal. The most common type of coal that is between sub-bituminous and anthracite rank. Bituminous coals produced from central and eastern U.S. coal fields typically have moisture content less than 20% by weight and heating value of 10,500 to 14,000 Btu/lb.

British thermal unit or “Btu.” A measure of the thermal energy required to raise the temperature of one pound of pure liquid water one degree Fahrenheit at the temperature at which water has its greatest density (39 degrees Fahrenheit).

Central Appalachian Basin. Coal producing area in eastern Kentucky, Virginia and southern West Virginia and northern Tennessee.

Coal seam. Coal deposits occur in layers typically separated by layers of rock. Each layer of coal is called a “seam.” A seam can vary in thickness from inches to a hundred feet or more.

Coke. A hard, dry carbon substance produced by heating coal to a very high temperature in the absence of air. Coke is used in the manufacture of iron and steel.

Continuous mining unit. A machine which constantly extracts coal while loading. This is to be distinguished from a conventional mining unit which must stop the extraction process in order for loading to commence.

CSX. CSX Corporation.

EIA. Energy Information Administration.

EPA. Environmental Protection Agency.

GW. Gigawatts.

Illinois Basin. Coal producing area in Illinois, Indiana and western Kentucky.

Lignite. The lowest rank of coal. It is brownish-black with a high moisture content commonly above 35% by weight and heating value commonly less than 8,000 Btu/lb.

Longwall 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 the coal, self-advancing roof supports to protect the miners working at the longwall face and

 

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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.

MATS. Mercury and Air Toxics Standards.

Metallurgical coal. The various grades of coal suitable for carbonization to make coke for steel manufacture. Also known as “met” coal, it exhibits thermoplastic or “caking” properties, meaning that it has the ability to become plastic and resolidify when heated in the absence of oxygen. Other important characteristics include its volatile matter content and levels of impurities such as ash and sulfur.

Mineable coal. That portion of the coal reserve base which is commercially mineable and excludes all coal that will be left, such as in pillars, fenders or property barriers.

MMBtus. One million Btus.

MSHA. Mine Safety and Health Administration.

Netback price. The netback price of coal is the net realized sales price for the Pennsylvania mining complex, measured as the delivered price of the coal to its customer less all costs involved in transporting the coal to its destination.

Norfolk Southern. Norfolk Southern Corporation.

Northern Appalachian Basin. Coal producing area in western Maryland, eastern Ohio, southwestern Pennsylvania and northern West Virginia.

Overburden. Layers of earth and rock covering a coal seam. In surface mining operations, overburden is removed prior to coal extraction.

Powder River Basin. Coal producing area in northeastern Wyoming and southeastern Montana.

Preparation plant. A facility for crushing, sizing and washing coal to prepare it for use by customers. The washing process separates ash from the coal and may also remove some of the coal’s sulfur content. Usually located on a mine site, although one plant may serve several mines.

Productivity. As used in this prospectus, refers to clean tons of coal produced per underground man hour worked, as published by the MSHA.

Reclamation. The process of restoring land to its prior condition, productive use or other permitted condition following mining activities. The process commonly includes reshaping the land to its approximate original contour, restoring topsoil and planting native grass and shrubs. Reclamation operations are typically conducted concurrently with mining operations. Reclamation is closely regulated by both state and federal laws.

Reserve. That part of a mineral deposit that could be economically and legally extracted or produced at the time of the reserve determination.

Roof. The stratum of rock or other mineral above a coal seam; the overhead surface of a coal working place.

Roof supports. Longwall equipment, including chocks or shields equipped with hydraulic cylinders which are placed in a long line, side by side, to support the roof of the coalface.

 

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Scrubber (flue gas desulfurization system). Any of several forms of chemical/physical devices which operate to remove sulfur compounds formed during coal combustion from the flue gas. These devices combine the sulfur in gaseous emissions with other chemicals to form inert compounds, such as gypsum, that must then be removed for disposal or beneficial reuse.

SEC. The Securities and Exchange Commission.

Slope. Underground mine access shaft which travels downward towards the coal seam.

Sub-bituminous coal. Black coal that ranks between lignite and bituminous coal. Sub-bituminous coal produced from the Powder River Basin has a moisture content between 20% to over 30% by weight, and its heat content ranges from 8,000 to 9,500 Btu/lb of coal.

Subsidence. Lateral or vertical movement of surface land that occurs when the roof of an underground mine collapses. Longwall mining causes planned subsidence by the mining out of coal that supports the overlying strata.

Sulfur. One of the elements present in varying quantities in coal that contributes to environmental degradation when coal is burned. Sulfur dioxide (SO₂) is produced as a gaseous by-product of coal combustion.

Thermal coal. Coal used by power plants and industrial steam boilers to produce electricity or process steam. Also commonly referred to as “steam coal.”

Thermoplastic. As used in this prospectus, the property of some bituminous coals to undergo a physical phase transition at elevated temperatures and in the absence of oxygen, in which partial melting occurs and the coal becomes a viscous molten plastic mass. Devolatilization, which occurs simultaneously, eventually leads to a frothy coke structure.

Tons. The short ton is the unit of measure referred to in this prospectus, unless otherwise noted. A “short” or net ton is equal to 2,000 pounds. A “long” or British ton is 2,240 pounds. A “metric” tonne is approximately 2,205 pounds.

Unassigned reserves. Coal at suspended locations and coal that has not been committed to be mined at existing operating facilities or potential future operations.

Underground mine. Also known as a “deep” mine. Usually located several hundred feet below the earth’s surface and accessed by a slope, drift portal or shaft. Most underground mines are located east of the Mississippi River and underground mines account for about 40% of annual U.S. coal production.

Wood Mackenzie. Wood Mackenzie Inc.

 

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Common Units

CNX Coal Resources LP

Representing Limited Partner Interests

 

 

PROSPECTUS

 

BofA Merrill Lynch

Wells Fargo Securities

                    , 2015

Through and including                 , 2015, (the 25th day after the date of this prospectus), all dealers effecting transactions in the Common Units, whether or not participating in this offering, may be required to deliver a prospectus. This delivery 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.

 

 

 

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Part II

Information Not Required in Prospectus

 

Item 13.

Other Expenses of Issuance and Distribution

Set forth below are the expenses (other than the underwriting discount) expected to be incurred in connection with the issuance and distribution of the securities registered hereby. With the exception of the SEC registration fee, the FINRA filing fee and the NYSE listing fee, the amounts set forth below are estimates.

 

SEC registration fee		$	29,050
FINRA filing fee			38,000
NYSE listing fee			*
Printing and engraving expenses			*
Fees and expenses of legal counsel			*
Accounting fees and expenses			*
Transfer agent and registrar fees			*
Miscellaneous			*
Total		$	*

 

*	To be filed by amendment.

 

Item 14.

Indemnification of Directors and Officers

The section of the prospectus entitled “Our Partnership Agreement—Indemnification” discloses that we will generally indemnify officers, directors and affiliates of the general partner to the fullest extent permitted by the law against all losses, claims, damages or similar events and is incorporated herein by this reference. Reference is also made to the underwriting agreement to be filed as an exhibit to this registration statement in which CNX Coal Resources LP and certain of its affiliates will agree to indemnify the underwriters against certain liabilities, including liabilities under the Securities Act, and to contribute to payments that may be required to be made in respect of these liabilities. Subject to any terms, conditions or restrictions set forth in the partnership agreement, Section 17-108 of the Delaware Act empowers a Delaware limited partnership to indemnify and hold harmless any partner or other persons from and against all claims and demands whatsoever.

 

Item 15.

Recent Sales of Unregistered Securities

On March 16, 2015, in connection with the formation of the partnership, CNX Coal Resources LP issued to (i) CNX Coal Resources GP LLC a 2% general partner interest in the partnership for $20.00 and (ii) CONSOL Energy Inc. a 98% limited partner interest in the partnership for $980.00 in an offering exempt from registration under Section 4(a)(2) of the Securities Act. There have been no other sales of unregistered securities within the past three years.

 

Item 16.

Exhibits

See the Exhibit Index immediately following the signature page hereto, which is incorporated by reference as if fully set forth herein.

 

Item 17.

Undertakings

The undersigned registrant hereby undertakes to provide to the underwriters at the closing specified in the underwriting agreement certificates in such denominations and registered in such names as required by the underwriters to permit prompt delivery to each purchaser.

 

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Insofar as indemnification for liabilities arising under the Securities Act may be permitted to directors, officers and controlling persons of the registrant pursuant to the foregoing provisions, or otherwise, the registrant has been advised that in the opinion of the Securities and Exchange Commission such indemnification is against public policy as expressed in the Securities Act and is, therefore, unenforceable. In the event that a claim for indemnification against such liabilities (other than the payment by the registrant of expenses incurred or paid by a director, officer or controlling person of the registrant in the successful defense of any action, suit or proceeding) is asserted by such director, officer or controlling person in connection with the securities being registered, the registrant will, unless in the opinion of its counsel the matter has been settled by controlling precedent, submit to a court of appropriate jurisdiction the question whether such indemnification by it is against public policy as expressed in the Securities Act and will be governed by the final adjudication of such issue.

The undersigned registrant hereby undertakes that,

 

(1)

For purposes of determining any liability under the Securities Act, the information omitted from the form of prospectus filed as part of this registration statement in reliance upon Rule 430A and contained in a form of prospectus filed by the registrant pursuant to Rule 424(b)(1) or (4) or 497(h) under the Securities Act shall be deemed to be part of this registration statement as of the time it was declared effective.

 

(2)

For the purpose of determining any liability under the Securities Act, each post-effective amendment that contains a form of prospectus shall be deemed to be a new registration statement relating to the securities offered therein, and the offering of such securities at that time shall be deemed to be the initial bona fide offering thereof.

 

(3)

That, for the purpose of determining liability under the Securities Act of 1933 to any purchaser, each prospectus filed pursuant to Rule 424(b) as part of a registration statement relating to an offering, other than registration statements relying on Rule 430B or other than prospectuses filed in reliance on Rule 430A, shall be deemed to be part of and included in the registration statement as of the date it is first used after effectiveness. Provided, however, that no statement made in a registration statement or prospectus that is part of the registration statement or made in a document incorporated or deemed incorporated by reference into the registration statement or prospectus that is part of the registration statement will, as to a purchaser with a time of contract of sale prior to such first use, supersede or modify any statement that was made in the registration statement or prospectus that was part of the registration statement or made in any such document immediately prior to such date of first use.

 

(4)

That, for the purpose of determining liability of the registrant under the Securities Act of 1933 to any purchaser in the initial distribution of the securities, the undersigned registrant undertakes that in a primary offering of securities of the undersigned registrant pursuant to this registration statement, regardless of the underwriting method used to sell the securities to the purchaser, if the securities are offered or sold to such purchaser by means of any of the following communications, the undersigned registrant will be a seller to the purchaser and will be considered to offer or sell such securities to such purchaser:

 

(a)

Any preliminary prospectus or prospectus of the undersigned registrant relating to the offering required to be filed pursuant to Rule 424;

 

(b)

If the registrant is subject to Rule 430C, each prospectus filed pursuant to Rule 424(b) as part of a registration statement relating to an offering, other than registration statements relying on Rule 430B or other than prospectuses filed in reliance on Rule 430A, shall be deemed to be part of and included in the registration statement as of the date it is first used after effectiveness. Provided, however, that no statement made in a registration statement or

 

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prospectus that is part of the registration statement or made in a document incorporated or deemed incorporated by reference into the registration statement or prospectus that is part of the registration statement will, as to a purchaser with a time of contract of sale prior to such first use, supersede or modify any statement that was made in the registration statement or prospectus that was part of the registration statement or made in any such document immediately prior to such date of first use;

 

(c)

Any free writing prospectus relating to the offering prepared by or on behalf of the undersigned registrant or used or referred to by the undersigned registrant;

 

(d)

The portion of any other free writing prospectus relating to the offering containing material information about the undersigned registrant or its securities provided by or on behalf of the undersigned registrant; and

 

(e)

Any other communication that is an offer in the offering made by the undersigned registrant to the purchaser.

The undersigned registrant undertakes to send to each common unitholder, at least on an annual basis, a detailed statement of any transactions with CNX Coal Resources GP LLC, our general partner, or its affiliates and of fees, commissions, compensation and other benefits paid, or accrued to CNX Coal Resources GP LLC or its affiliates for the fiscal year completed, showing the amount paid or accrued to each recipient and the services performed.

The registrant undertakes to provide to the common unitholders the financial statements required by Form 10-K for the first full fiscal year of operations of the registrant.

 

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Signatures

Pursuant to the requirements of the Securities Act of 1933, as amended, the registrant has duly caused this Registration Statement to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Canonsburg, Commonwealth of Pennsylvania, on April 1, 2015.

 

Each person whose signature appears below appoints James A. Brock, Lorraine L. Ritter and Martha A. Wiegand, and each of them, any of whom may act without the joinder of the other, as his true and lawful attorneys-in-fact and agents, with full power of substitution and re-substitution, for him and in his name, place and stead, in any and all capacities, to sign any and all amendments (including post-effective amendments) to this Registration Statement and any Registration Statement (including any amendment thereto) for this offering that is to be effective upon filing pursuant to Rule 462(b) under the Securities Act of 1933, as amended, and to file the same, with all exhibits thereto, and all other documents in connection therewith, with the Securities and Exchange Commission, granting unto said attorneys-in-fact and agents, and each of them, full power and authority to do and perform each and every act and thing requisite and necessary to be done in connection therewith, as fully to all intents and purposes as he might or could do in person, hereby ratifying and confirming all that said attorneys-in-fact and agents, or any of them, or their or his substitute and substitutes, may lawfully do or cause to be done by virtue hereof. Pursuant to the requirements of the Securities Act of 1933, as amended, this Registration Statement has been signed below by the following persons in the capacities indicated on April 1, 2015.

 

Signature		Title
/s/    James A. Brock         James A. Brock		Chief Executive Officer and Director (Principal Executive Officer)
/s/    Lorraine L. Ritter         Lorraine L. Ritter		Chief Financial Officer and Chief Accounting Officer (Principal Financial Officer and Principal Accounting Officer)
/s/    Nicholas J. DeIuliis         Nicholas J. DeIuliis		Director (Chairman of the Board)
/s/    Stephen W. Johnson         Stephen W. Johnson		Director
/s/    David M. Khani         David M. Khani		Director

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Exhibit Index

 

Exhibit number		Description
1.1*		Form of Underwriting Agreement (including form of Lock-Up Agreement)
3.1A		Certificate of Limited Partnership of CNX Coal Resources LP
3.1B		Certificate of Amendment to the Certificate of Limited Partnership of CNX Coal Resources LP
3.2*		Form of First Amended and Restated Agreement of Limited Partnership of CNX Coal Resources LP (included as Appendix A to the Prospectus)
5.1*		Form of Opinion of Latham & Watkins LLP as to the legality of the securities being registered
8.1*		Form of Opinion of Latham & Watkins LLP relating to tax matters
10.1*		Form of Operating Agreement
10.2*		Form of Employee Services Agreement
10.3*		Form of Contract Agency Agreement
10.4*		Form of Terminal and Throughput Agreement
10.5*		Form of Management Services Agreement
10.6*		Form of Cooperation and Safety Agreement
10.7*		Form of Water Supply and Services Agreement
10.8*		Form of Omnibus Agreement
10.9*		Form of Asset Contribution Agreement
10.10*		Form of Equity Contribution Agreement
10.11*#		Form of CNX Coal Resources LP 2014 Long-Term Incentive Plan
10.12*		Form of Credit Agreement
21.1*		List of Subsidiaries of CNX Coal Resources LP
23.1		Consent of Ernst & Young LLP
23.2*		Consent of Latham & Watkins LLP (contained in Exhibit 5.1)
23.3*		Consent of Latham & Watkins LLP (contained in Exhibit 8.1)
23.4		Consent of Golder Associates Inc.
23.5		Consent of Wood Mackenzie Inc.
23.6*		Consent of Director Nominee
24.1		Powers of Attorney (contained on the signature page to this Registration Statement)

 

*	To be filed by amendment.

#	Compensatory plan, contract or arrangement.

 

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